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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS
Table of Contents
As filed with the Securities and Exchange Commission on January 19, 2017
Registration No. 333-
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
Centennial Resource Development, Inc.
(Exact Name of Registrant as Specified in its Charter)
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Delaware
(State or other jurisdiction
of incorporation)
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1311
(Primary Standard Industrial
Classification Code Number)
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47-5381253
(I.R.S. Employer
Identification No.)
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1401 Seventeenth Street, Suite 1000
Denver, Colorado 80202
(720) 441-5515
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)
Copies to:
William N. Finnegan IV
Debbie P. Yee
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
(713) 546-5400
Approximate date of commencement of proposed sale to the public:
From time to time after the effective date of this Registration Statement.
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box.
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If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list
the Securities Act registration statement number of the earlier effective registration statement for the same offering.
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If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement for the same offering.
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If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement for the same offering.
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the
definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer
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Accelerated filer
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Non-accelerated filer
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(Do not check if a
smaller reporting company)
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Smaller reporting company
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CALCULATION OF REGISTRATION FEE
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Title of each class of securities
to be registered
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Amount to be
registered(1)
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Proposed maximum
offering price per
share
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Proposed maximum
aggregate offering
price
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Amount of
registration fee
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Class A Common Stock, par value $0.0001 per share
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26,100,000(2)
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$18.39(4)
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$479,979,000
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$55,630
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Class A Common Stock, par value $0.0001 per share
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36,485,970(3)
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$18.39(4)
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$670,976,989
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$77,766
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Total
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62,585,970
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$1,150,955,989
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$133,396
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(1)
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Pursuant
to Rule 416(a) under the Securities Act of 1933, as amended (the "Securities Act"), there are also being registered such indeterminable additional
shares of Class A Common Stock, par value $0.0001 per share, of the Registrant (the "Class A Common Stock") as may be issued to prevent dilution as a result of stock splits, stock
dividends or similar transactions.
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(2)
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Represents
the resale of 26,100,000 shares of Class A Common Stock that are issuable upon the conversion of 104,400 shares of Series B Preferred Stock,
par value $0.0001 per share, of the Registrant, which the Registrant issued to an affiliate of SB RS Holdings, LLC in a private placement in connection with the Registrant's acquisition of
leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC and that are convertible into shares of
Class A Common Stock on a 250-to-1 basis (subject to certain adjustments) in accordance with the Certificate of Designation of Series B Preferred Stock of Centennial Resource
Development, Inc. filed with the Secretary of State of the State of Delaware on December 28, 2016.
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(3)
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Represents
the resale of 36,485,970 shares of Class A Common Stock issued to certain investors in private placements in connection with the Registrant's
acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC.
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(4)
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Estimated
at $18.39 per share, the average of the high and low prices of the Class A Common Stock as reported on The NASDAQ Capital Market on
January 13, 2017, solely for the purpose of calculating the registration fee in accordance with Rule 457(f)(1) under the Securities Act.
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall
file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act, or until the
Registration Statement shall become effective on such date as the Securities and Exchange Commission acting pursuant to said Section 8(a), may determine.
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The information contained in this prospectus is not complete and may be changed. No securities may be sold until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any state where the offer or
sale is not permitted.
Subject to Completion, dated January 19, 2017
Preliminary Prospectus
CENTENNIAL RESOURCE DEVELOPMENT, INC.
62,585,970 Shares of Class A Common Stock
This prospectus relates to the resale of 62,585,970 shares of Class A Common Stock, par value $0.0001 per share (the "Class A Common
Stock"), of Centennial Resource Development, Inc. (the "Company," "we," "our" or "us") by the selling stockholders named in this prospectus or their permitted transferees. The shares of
Class A Common Stock being offered by the selling stockholders consist of (i) 26,100,000 shares of Class A Common Stock (the "Conversion Shares") that are issuable upon the
conversion of 104,400 shares of our Series B Preferred Stock, par value $0.0001 per share (the "Series B Preferred Stock"), and (ii) 36,485,970 shares of Class A Common
Stock (the "Private Placement Shares"). We sold the shares of Series B Preferred Stock and the Private Placement Shares in private placements that closed simultaneously with the consummation of
our acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and Silverback Operating, LLC on December 28, 2016.
The
selling stockholders may offer, sell or distribute all or a portion of their shares of Class A Common Stock publicly or through private transactions at prevailing market
prices or at negotiated prices. We will not receive any of the proceeds from the sale of the shares of Class A Common Stock owned by the selling stockholders. We will bear all costs, expenses
and fees in connection with the registration of these shares of Class A Common Stock, including with regard to compliance with state securities or "blue sky" laws. The selling stockholders will
bear all commissions and discounts, if any, attributable to their sale of shares of Class A Common Stock. See "Plan of Distribution" beginning on page 131 of this prospectus.
Our
Class A Common Stock is quoted on The NASDAQ Capital Market ("NASDAQ") under the symbol "CDEV". On January 18, 2017, the closing price of our Class A Common
Stock was $18.87. As of January 18, 2017, we had 200,835,049 shares of Class A Common Stock issued and outstanding.
We
are an "emerging growth company" as defined in Section 2(a) of the Securities Act of 1933, as amended (the "Securities Act"), as modified by the Jumpstart Our Business Startups
Act of 2012 (the
"JOBS Act") and are subject to reduced public company reporting requirements. This prospectus complies with the requirements that apply to an issuer that is an emerging growth company.
INVESTING IN THESE SECURITIES INVOLVES CERTAIN RISKS. SEE "RISK FACTORS" ON PAGE 8.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these
securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
The date of this prospectus is , 2017
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TABLE OF CONTENTS
You
should rely only on the information contained in this prospectus, any prospectus supplement or in any free writing prospectus we may authorize to be delivered or made available to
you. We have not, and the selling stockholders have not, authorized anyone to provide you with different information. We and the selling stockholders are not offering to sell, or seeking offers to
buy, shares of our Class A Common Stock in jurisdictions where offers and sales are not permitted. The information contained in this prospectus is accurate only as of the date of this
prospectus, regardless of the time of delivery of this prospectus or any sale of shares of our Class A Common Stock.
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INDUSTRY AND MARKET DATA
The market data and certain other statistical information used throughout this prospectus are based on independent industry publications,
government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the selling stockholders have
independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of
uncertainty and risk due to a variety of factors, including those described in the section entitled "Risk Factors." These and other factors could cause results to differ materially from those
expressed in these publications.
TRADEMARKS AND TRADE NAMES
We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This
prospectus may also contain trademarks, service marks and trade names of third parties, that are the property of their respective owners. Our use or display of third parties' trademarks, service
marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks,
service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not
assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.
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GLOSSARY
Unless the context otherwise requires, references in this prospectus to:
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"AMI" are to the area of mutual interest pursuant to which certain parties can elect to purchase up to 80.75% of 11,694 net acres acquired in
the Silverback Acquisition.
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"Business Combination" are to our acquisition of approximately 89% of the outstanding membership interests in CRP from the Centennial
Contributors, which closed on October 11, 2016, and the other transactions contemplated by the Contribution Agreement;
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"Business Combination Private Placements" are to the issuance and sale in private placements of (i) 81,005,000 shares of Class A
Common Stock to Riverstone Centennial Holdings, L.P. and (ii) 20,000,000 shares of Class A Common Stock to certain other investors, which closed simultaneously with the
consummation of the Business Combination;
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"Celero" are to Celero Energy Company, LP, a Delaware limited partnership;
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"Centennial Contributors" are to CRD, NGP Follow-On and Celero, collectively;
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The "Company," "we," "our" or "us" are to (a) Centennial Resource Development, Inc. and its subsidiaries, including CRP,
following the closing of the Business Combination and (b) Silver Run Acquisition Corporation prior to the closing of the Business Combination;
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"Class A Common Stock" are to our Class A Common Stock, par value $0.0001 per share;
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"Class B Common Stock" are to our Class B Common Stock, par value $0.0001 per share;
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"Class C Common Stock" are to our Class C Common Stock, par value $0.0001 per share, which were issued to the Centennial
Contributors in connection with the Business Combination;
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"Contribution Agreement" are to the Contribution Agreement, dated as of July 6, 2016, among the Centennial Contributors, CRP and NewCo,
as amended by Amendment No. 1 thereto, dated as of July 29, 2016, and the Joinder Agreement, dated as of October 7, 2016, by the Company;
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"CRD" are to Centennial Resource Development, LLC, a Delaware limited liability company;
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"CRP" are to Centennial Resource Production, LLC, a Delaware limited liability company;
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"CRP Common Units" are to units representing common membership interests in CRP;
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"founder shares" are to shares of our Class B Common Stock purchased by our Sponsor in a private placement prior to our IPO, which were
converted into shares of Class A Common Stock on a one-for-one basis in connection with the closing of the Business Combination;
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"initial stockholders" are to holders of our founder shares prior to our IPO, including our Sponsor and our independent directors prior to the
Business Combination;
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"IPO" are to our initial public offering of units, which closed on February 29, 2016;
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"NewCo" are to New Centennial, LLC, a Delaware limited liability company controlled by affiliates of Riverstone;
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"NGP Follow-On" are to NGP Centennial Follow-On LLC, a Delaware limited liability company;
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"Private Placement Warrants" are to our 8,000,000 outstanding warrants, which were purchased by our Sponsor in a private placement
simultaneously with the closing of our IPO;
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"Public Warrants" are to our 16,666,643 outstanding warrants, which were sold as part of the Units in our IPO;
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"Riverstone" are to Riverstone Investment Group LLC and its affiliates, including our Sponsor, collectively;
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"Riverstone Purchasers" are to Riverstone VI Centennial QB Holdings, L.P., Riverstone Non-ECI USRPI AIV, L.P. and REL US
Centennial Holdings, LLC, which are affiliates of Riverstone;
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"Series B Preferred Stock" are to our Series B Preferred Stock, par value $0.0001 per share;
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"Series B Preferred Units" are to Series B Preferred Units of CRP which, by their terms, convert to CRP Common Units upon the
conversion of the Series B Preferred Stock;
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"Silverback Acquisition" are to our acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback
Exploration, LLC and Silverback Operating, LLC, which closed on December 28, 2016;
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"Silverback Acquisition Private Placements" are to the issuance and sale in private placements of (i) 3,473,590 shares of Class A
Common Stock and 104,400 shares of Series B Preferred Stock to the Riverstone Purchasers and (ii) 33,012,380 shares of our Class A Common Stock to certain other investors, which
closed simultaneously with the consummation of the Silverback Acquisition;
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"Sponsor" are to our sponsor, Silver Run Sponsor, LLC, a Delaware limited liability company and an affiliate of Riverstone;
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"Units" are to our units sold in our IPO, each of which consisted of one share of Class A Common Stock and one-third of one Public
Warrant; and
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"voting common stock" are to our Class A Common Stock and Class C Common Stock.
For
additional defined terms commonly used in the oil and natural gas industry and used in this prospectus, please see "Glossary of Oil and Natural Gas Terms" set forth in
Annex A.
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PROSPECTUS SUMMARY
This summary highlights certain information appearing elsewhere in this prospectus. For a more complete understanding of this offering, you
should read the entire prospectus
carefully, including the risk factors and the financial statements. Unless otherwise specified herein, the information set forth in this prospectus describes the Company and its operations as of and
for the periods preceding September 30, 2016, and does not reflect the completion of the Silverback Acquisition.
Our Company
Corporate History
We were originally formed in November 2015 as a special purpose acquisition company under the name Silver Run Acquisition Corporation for the
purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving us and one or more businesses. Until the consummation
of the Business Combination, our shares of Class A Common Stock, Public Warrants and Units were traded on The NASDAQ Capital Market ("NASDAQ") under the ticker symbols "SRAQ," "SRAQW" and
"SRAQU," respectively.
On
October 11, 2016 (the "Business Combination Closing Date"), we consummated the acquisition of approximately 89% of the outstanding membership interests in Centennial Resource
Production, LLC, a Delaware limited liability company ("CRP"), pursuant to (i) that certain Contribution Agreement, dated as of July 6, 2016 (as amended by Amendment No. 1
thereto, dated as of July 29, 2016, the "Contribution Agreement"), among Centennial Resource Development, LLC, a Delaware limited liability company ("CRD"), NGP Centennial
Follow-On LLC, a Delaware limited liability company ("NGP Follow-On"), Celero Energy Company, LP, a Delaware limited partnership (together with CRD and NGP Follow-On, the "Centennial
Contributors"), CRP and New Centennial, LLC, a Delaware limited liability company ("NewCo"), (ii) that certain Assignment Agreement, dated as of October 7, 2016, between NewCo and
the Company and (iii) that certain Joinder Agreement, dated as of October 7, 2016, by the Company (such acquisition, together with the other transactions contemplated by the Contribution
Agreement, the "Business Combination").
At
the closing of the Business Combination, we contributed to CRP approximately $1.49 billion in cash and CRP then distributed to the Centennial Contributors cash in the amount of
approximately $1.18 billion in partial redemption of the Centennial Contributors' membership interests in CRP. At the closing of the Business Combination, we and the Centennial Contributors
effected a recapitalization of CRP pursuant to which (1) all of the remaining outstanding membership interests in CRP of the Centennial Contributors were converted into 20,000,000 units
representing common membership
interests in CRP (the "CRP Common Units") and (2) we were admitted as a member of CRP and issued 163,505,000 CRP Common Units.
Following
the Business Combination, we changed our name from "Silver Run Acquisition Corporation" to "Centennial Resource Development, Inc." and continued the listing of our
Class A Common Stock and Public Warrants on NASDAQ under the symbols "CDEV" and "CDEVW," respectively.
Business Overview
Our only significant asset is our ownership of an approximate 92% membership interest in CRP. We are an independent oil and natural gas company
focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin
of the Permian Basin, and our properties consist of large, contiguous acreage blocks in Reeves, Ward and Pecos counties in West Texas.
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As
of September 30, 2016, our portfolio included 63 operated producing horizontal wells. The horizontal wells span an area approximately 45 miles long by 20 miles wide where we
have established commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. As a result, we have broadly
appraised this acreage across various geographic areas and stratigraphic zones, which we expect will allow us to efficiently develop our drilling inventory with a focus on maximizing returns to our
stockholders. In addition, we believe this acreage may be prospective for the 2nd and 3rd Bone Spring shales and Avalon Shale, where other operators have experienced drilling success
near our acreage.
As
of September 30, 2016, we have leased or acquired approximately 42,300 net acres, approximately 80% of which we operate. Our acreage is predominantly located in the southern
portion of the Delaware Basin, where production and reserves typically contain a higher percentage of oil and natural gas liquids and a correspondingly lower percentage of natural gas compared to the
northern portion of the Delaware Basin. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, we added one horizontal rig in June 2016, a second horizontal rig
in September 2016 and a third horizontal rig in October 2016. During 2016, we placed 11 horizontal wells on production. Our development drilling plan is comprised exclusively of horizontal drilling
with an ongoing focus on optimizing completions, reducing drilling times and reducing costs.
Our
goal is to build a premier development and acquisition company focused on horizontal drilling in the Delaware Basin.
Recent Developments
Silverback Acquisition
On December 28, 2016, we completed the acquisition of leasehold interests and related upstream assets in Reeves County, Texas from
Silverback Exploration, LLC and Silverback Operating, LLC (collectively, "Silverback") for a cash purchase price of approximately $855,000,000, subject to customary purchase price
adjustments. The assets acquired from Silverback include 30 operated producing horizontal wells and approximately 35,000 net acres in Reeves County, Texas that directly offset our existing acreage. We
operate approximately 95% of, and have an approximate 88% working interest in, this acreage and believe that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale
formations.
The
acreage acquired in the Silverback Acquisition includes 11,694 net acres, with an allocated value of approximately $300 million, subject to an area of mutual interest (the
"AMI") among various parties. Pursuant to the AMI, one or more of three separate counterparties may elect to acquire up to an aggregate of 80.75% of the acreage subject to the AMI by paying to us, on
or before January 30, 2017, such counterparty's share of the cost and expense of acquiring the acreage. The failure of a counterparty to make such payment on or before January 30, 2017
will be deemed to be an election not to acquire the AMI acreage.
Issuance of Class A Common Stock and Preferred Stock in Private Placements
In connection with the Silverback Acquisition, we issued and sold in private placements (i) 3,473,590 shares of Class A Common
Stock and 104,400 shares of Series B Preferred Stock to the Riverstone Purchasers and (ii) 33,012,380 shares of our Class A Common Stock to certain other investors, resulting in
gross proceeds of approximately $910 million. We used the proceeds from the private placements to fund the cash consideration for the Silverback Acquisition and expect to use any remaining
proceeds for general corporate purposes.
The
shares of Series B Preferred Stock are automatically convertible into shares of our Class A Common Stock on a 250-to-1 basis (subject to certain adjustments) at such
time as we receive
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stockholder
approval for the issuance of such shares of Class A Common Stock in compliance with NASDAQ listing rules ("Stockholder Approval"). We intend to call a special meeting of our
stockholders in order to receive such approval. For a more detailed description of the Series B Preferred Stock, please see "Description of Capital StockSeries B Preferred
Stock."
Credit Agreement Amendment
On December 28, 2016, in connection with the closing of the Silverback Acquisition, CRP entered into an amendment to its credit agreement
to, among other things, increase the borrowing base thereunder from $200.0 million to $250.0 million.
Organizational Structure
The following diagram illustrates the current ownership structure of the Company, after giving effect to the conversion of our Series B
Preferred Stock.
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(1)
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Includes
the 33,012,380 shares of Class A Common Stock of the selling stockholders (other than the Riverstone Purchasers) registered under this prospectus for
resale.
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(2)
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Gives
effect to the issuance of the 26,100,000 Conversion Shares, which are registered under this prospectus for resale (and not accounting for the outstanding
Public Warrants and Private Placement Warrants).
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(3)
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CRD,
one of the Centennial Contributors, also owns one share of our Series A Preferred Stock, par value $0.0001 per share (the "Series A Preferred
Stock"), which does not have any voting rights (other than the right to nominate and elect one director to our board of directors) or rights with respect to dividends but is entitled to preferred
distributions in liquidation in the amount of $0.0001 per share.
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(4)
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The
economic and voting interests set forth in the diagram do not account for the outstanding Public Warrants and Private Placement Warrants.
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Additional Information
Our principal executive offices are located at 1401 Seventeenth Street, Suite 1000, Denver, Colorado 80202, and our telephone number is
(720) 441-5515. Our website is www.cdevinc.com. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.
Our Emerging Growth Company Status
As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an "emerging growth company" as defined in
the JOBS Act. As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable
generally to public companies. These exemptions include:
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the presentation of only two years of audited financial statements and only two years of related Management's Discussion and Analysis of
Financial Condition and Results of Operations;
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deferral of the auditor attestation requirement on the effectiveness of our system of internal control over financial reporting;
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exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;
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exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm
rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and
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reduced disclosure about executive compensation arrangements.
We
may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following
February 29, 2021, the fifth anniversary of our IPO, (ii) the last day of the fiscal year in which we have more than $1.0 billion in annual revenue, (iii) the date on which
we issue more than $1.0 billion of non-convertible debt over a three-year period and (iv) the date on which we are deemed to be a "large accelerated filer," as defined in
Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). We have elected to take advantage of each of the exemptions for emerging growth companies,
other than the presentation of only two years of audited financial statements and related Management's Discussion and Analysis of Financial Conditions and Results of Operations.
Accordingly,
the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.
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The Offering
We are registering the resale of 62,585,970 shares of Class A Common Stock by the selling stockholders named in this prospectus, or their
permitted transferees.
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Shares Offered by the Selling Stockholders
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We are registering 62,585,970 shares of Class A Common Stock to be offered by the selling stockholders named herein, which includes (i) 26,100,000 Conversion Shares and (ii) 36,485,970
Private Placement Shares.
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Terms of the Offering
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The selling stockholders will determine when and how they will dispose of the shares of Class A Common Stock registered
under this prospectus for resale.
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Shares Outstanding Prior to This Offering (Prior to the Conversion of the Series B Preferred Stock)(1)(2)
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As of January 18, 2017, we had issued and outstanding (i) 200,835,049 shares of Class A Common Stock,
(ii) 19,155,921 shares of Class C Common Stock, (iii) 1 share of Series A Preferred Stock and (iv) 104,400 shares of Series B Preferred Stock.
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Shares Outstanding After This Offering (Assuming Conversion of the Series B Preferred Stock)(1)
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(i) 226,935,049 shares of Class A Common Stock (ii) 19,155,921 shares of Class C Common Stock and
(iii) 1 share of Series A Preferred Stock.
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Use of Proceeds
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We will not receive any of the proceeds from the sale of shares of Class A Common Stock by the selling
stockholders.
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Trading Market and Ticker Symbol
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Our Class A Common Stock is listed on NASDAQ under the symbol "CDEV".
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(1)
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The
number of shares of Class A Common Stock does not include (i) the 16,500,000 shares of Class A Common Stock available for future issuance
under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan or (ii) the 24,666,643 shares of Class A Common Stock issuable upon the exercise of the Public
Warrants and the Private Placement Warrants.
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(2)
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The
number of shares of Class A Common Stock does not include the 26,100,000 Conversion Shares, which are issuable upon the conversion of our Series B
Preferred Stock at such time as we receive Stockholder Approval.
For
additional information concerning the offering, see "Plan of Distribution" beginning on page 131.
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Risk Factors
Before investing in our securities, you should carefully read and consider the information set forth in "Risk Factors" beginning on
page 8.
Summary Historical Reserve and Operating Data
The following tables present, for the periods and as of the dates indicated, summary data with respect to our estimated net proved oil and
natural gas reserves and operating data.
The
reserve estimates attributable to our properties as of December 31, 2015 presented in the table below are based on a reserve report prepared by Netherland, Sewell &
Associates, Inc., our independent petroleum engineer. A copy of the reserve report is included as Exhibit 99.2 to the registration statement of which this prospectus forms a part.
All of these reserve estimates were prepared in accordance with the SEC's rules regarding oil and natural gas reserve reporting that are currently in effect. The following tables also contain summary
unaudited information regarding production and sales of oil, natural gas and NGLs with respect to such properties.
Please
see the sections of this prospectus entitled "Description of BusinessOil and Natural Gas DataProved Reserves" and "Management's Discussion and Analysis
of Financial Condition and Results of Operations" in evaluating the information presented below.
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As of
December 31,
2015(1)
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Proved Reserves:
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Oil (MBbls)
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23,199
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Natural gas (MMcf)
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32,442
|
|
NGLs (MBbls)
|
|
|
3,851
|
|
|
|
|
|
|
Total proved reserves (MBoe)
|
|
|
32,457
|
|
Proved Developed Reserves:
|
|
|
|
|
Oil (MBbls)
|
|
|
9,347
|
|
Natural gas (MMcf)
|
|
|
12,711
|
|
NGLs (MBbls)
|
|
|
1,603
|
|
|
|
|
|
|
Total proved developed reserves (MBoe)
|
|
|
13,068
|
|
Proved developed reserves as a percentage of total proved reserves
|
|
|
40
|
%
|
Proved Undeveloped Reserves:
|
|
|
|
|
Oil (MBbls)
|
|
|
13,852
|
|
Natural gas (MMcf)
|
|
|
19,731
|
|
NGLs (MBbls)
|
|
|
2,248
|
|
|
|
|
|
|
Total proved undeveloped reserves (MBoe)
|
|
|
19,389
|
|
Oil and Natural Gas Prices:
|
|
|
|
|
OilWTI posted price per Bbl
|
|
$
|
46.79
|
|
Natural gasHenry Hub spot price per MMBtu
|
|
$
|
2.59
|
|
-
(1)
-
Our
estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil
and NGL volumes, the average West Texas Intermediate posted price of $46.79 per barrel as of December 31, 2015 was adjusted for quality, transportation fees and a regional price differential.
For gas volumes, the average Henry Hub spot price of $2.59 per MMBtu as of December 31, 2015 was adjusted for energy content, transportation fees and a regional price differential. All prices
are held constant throughout the lives of the properties. The average adjusted product prices weighted by production
6
Table of Contents
over
the remaining lives of the properties are $41.85 per barrel of oil, $13.94 per barrel of NGL and $1.71 per Mcf of gas as of December 31, 2015.
|
|
|
|
|
|
|
|
|
|
Nine Months
Ended
September 30,
2016
|
|
Year Ended
December 31,
2015
|
|
Production and Operating Data:
|
|
|
|
|
|
|
|
Net Production Volumes(1):
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,520
|
|
|
1,830
|
|
Natural gas (MMcf)
|
|
|
2,551
|
|
|
3,058
|
|
NGLs (MBbls)
|
|
|
242
|
|
|
331
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
2,187
|
|
|
2,671
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average net daily production (Boe/d)
|
|
|
7,982
|
|
|
7,317
|
|
Average Sales Prices:
|
|
|
|
|
|
|
|
Oil (per Bbl) (excluding impact of cash settled derivatives)
|
|
$
|
37.48
|
|
$
|
42.43
|
|
Oil (per Bbl) (after impact of cash settled derivatives)
|
|
|
48.42
|
|
|
61.61
|
|
Natural gas (per Mcf) (excluding impact of cash settled derivatives)
|
|
|
2.24
|
|
|
2.60
|
|
Natural gas (per Mcf) (after impact of cash settled derivatives)
|
|
|
2.24
|
|
|
3.04
|
|
NGLs (per Bbl)
|
|
|
12.80
|
|
|
14.66
|
|
|
|
|
|
|
|
|
|
Total (per Boe) (excluding impact of cash settled derivatives)
|
|
|
30.08
|
|
|
33.87
|
|
Total (per Boe) (after impact of cash settled derivatives)
|
|
|
37.68
|
|
|
47.51
|
|
Average Unit Costs per Boe:
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
4.71
|
|
$
|
7.93
|
|
Severance and ad valorem taxes
|
|
|
1.61
|
|
|
1.88
|
|
Transportation, processing, gathering and other operating expenses
|
|
|
2.00
|
|
|
2.15
|
|
Depreciation, depletion, amortization, and accretion of asset retirement obligations
|
|
|
27.86
|
|
|
33.73
|
|
Abandonment expense and impairment of unproved properties
|
|
|
1.16
|
|
|
2.85
|
|
Exploration
|
|
|
|
|
|
0.03
|
|
Contract termination and rig stacking
|
|
|
|
|
|
0.89
|
|
General and administrative expenses
|
|
|
4.87
|
|
|
5.32
|
|
-
(1)
-
Totals
may not sum or recalculate due to rounding.
7
Table of Contents
RISK FACTORS
Investing in our securities involves a high degree of risk. You should consider carefully the risks and uncertainties
described below, together with all of the other information in this prospectus, including our consolidated financial statements and related notes, before deciding whether to purchase any of our
securities. Any of these risks may have a material adverse effect on our business, financial condition, results of operations and cash flows and our prospects could be harmed. In that event, the price
of our securities could decline and you could lose part or all of your investment. Unless otherwise specified, operational data is as of September 30, 2016 and does not reflect the completion
of the Silverback Acquisition.
Risks Related to Our Business
Our only significant asset is our ownership of an approximate 92% membership interest in CRP. Distributions
from CRP may not be sufficient to allow us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations.
We have no direct operations and no significant assets other than the ownership of an approximate 92% membership interest in CRP. We will depend
on CRP for distributions, loans and other payments to generate the funds necessary to meet our financial obligations or to pay any dividends with respect to our Class A Common Stock. Subject to
certain restrictions, CRP generally will be required to (i) make pro rata distributions to its members, including us, in an amount at least sufficient to allow us to pay our taxes and
(ii) reimburse us for certain corporate and other overhead expenses. However, legal and contractual restrictions in agreements governing future indebtedness of CRP, as well as the financial
condition and operating requirements of CRP may limit our ability to obtain cash from CRP. The earnings from, or other available assets of, CRP may not be sufficient to pay dividends or make
distributions or loans to enable us to pay any dividends on our Class A Common Stock or satisfy our other financial obligations.
Oil, natural gas and NGL prices are volatile. A sustained decline in oil, natural gas and NGL prices could
adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The prices we receive for our oil, natural gas and NGLs production heavily influence our revenue, profitability, access to capital, future rate
of growth and carrying value of our properties. Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to relatively minor changes in the supply of and demand for
oil, natural gas and NGLs and market uncertainty. Historically, oil, natural gas and NGL prices have been volatile. For example, during the period from January 1, 2014 through
November 1, 2016, the WTI spot price for oil has declined from a high of $107.62 per Bbl on July 23, 2014 to $26.21 per Bbl on February 11, 2016, and the Henry Hub spot price for
natural gas has declined from a high of $7.92 per MMBtu on March 4, 2014 to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane,
isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices. The prices we
receive for our production, and the levels of our production, depend on numerous factors beyond our control, which include the following:
-
-
worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGLs;
-
-
the price and quantity of foreign imports of oil, natural gas and NGLs;
-
-
political and economic conditions in or affecting other producing regions or countries, including the Middle East, Africa, South America and
Russia;
8
Table of Contents
-
-
actions of the Organization of the Petroleum Exporting Countries ("OPEC"), its members and other state-controlled oil companies relating to oil
price and production controls;
-
-
the level of global exploration, development and production;
-
-
the level of global inventories;
-
-
prevailing prices on local price indexes in the area in which we operate;
-
-
the proximity, capacity, cost and availability of gathering and transportation facilities;
-
-
localized and global supply and demand fundamentals and transportation availability;
-
-
the cost of exploring for, developing, producing and transporting reserves;
-
-
weather conditions and other natural disasters;
-
-
technological advances affecting energy consumption;
-
-
the price and availability of alternative fuels;
-
-
expectations about future commodity prices; and
-
-
U.S. federal, state and local and non-U.S. governmental regulation and taxes.
In
the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015 and 2016, the global oil supply has continued
to outpace demand, resulting in continuing lower realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United
States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest
demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the
industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begin to decline, prices are expected to remain
under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally
correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting
projects that produce NGLs in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and in 2016. The declines in
natural gas prices are primarily due to an imbalance between supply and demand across North America. The duration and magnitude of the commodity price declines cannot be accurately predicted. Compared
to 2014, our realized oil price for 2015 fell 47.3% to $42.43 per barrel, and our realized oil price for the nine months ended September 30, 2016 has further decreased to $37.48 per barrel.
Similarly, our realized natural gas price for 2015 dropped 43.2% to $2.60 per Mcf and our realized price for NGLs declined 52.2% to $14.66 per barrel. For the nine months ended
September 30, 2016, our realized price for natural gas was $2.24 per Mcf and our realized price for NGLs was $12.80 per barrel.
In
addition, other governmental actions, including initiatives by OPEC, may continue to impact oil prices. Furthermore, it is uncertain what impact the election of Donald Trump as
President of the United States will have on the exploration for and production of domestic oil, natural gas and NGLs. Decisions by OPEC to reduce production or increased domestic oil and natural gas
production in a changing regulatory environment could impact the price of oil.
Lower
commodity prices may reduce our cash flows and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future
reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in
9
Table of Contents
proved
reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current WTI or Henry Hub strip prices and the resultant effect such
prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some
of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which
may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations,
liquidity and ability to finance planned capital expenditures.
Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain
required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.
The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to
development and acquisition projects. We have funded, and we expect that we will continue to fund, our capital expenditures with cash generated by operations and borrowings under CRP's revolving
credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance
of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash
flow from operations to fund working capital, capital expenditures and acquisitions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a
result of, among other things, oil, natural gas and NGL prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and
competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.
Our
cash flow from operations and access to capital are subject to a number of variables, including:
-
-
the prices at which our production is sold;
-
-
our proved reserves;
-
-
the level of hydrocarbons we are able to produce from existing wells;
-
-
our ability to acquire, locate and produce new reserves;
-
-
the levels of our operating expenses; and
-
-
CRP's ability to borrow under its revolving credit facility and the ability to access the capital markets.
If
our revenues or the borrowing base under CRP's revolving credit facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or
for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or
equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under CRP's revolving credit facility are not sufficient to meet our capital
requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties. This, in turn, could lead to a decline in our
reserves and production, and could materially and adversely affect our business, financial condition and results of operations.
10
Table of Contents
Part of our strategy involves using some of the latest available horizontal drilling and completion
techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that
we face while drilling horizontal wells include the following:
-
-
landing a wellbore in the desired drilling zone;
-
-
staying in the desired drilling zone while drilling horizontally through the formation;
-
-
running our casing the entire length of the wellbore; and
-
-
being able to run tools and other equipment consistently through the horizontal wellbore.
Risks
that we face while completing wells include the following:
-
-
the ability to fracture stimulate the planned number of stages;
-
-
the ability to run tools the entire length of the wellbore during completion operations; and
-
-
the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
In
addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and
complete multiple wells before any such wells begin producing. Furthermore, the results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that
are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing
future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as anticipated, and we could
incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could
adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities,
which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.
Our
decisions to develop or purchase prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and
engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see "Reserve
estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present
value of our reserves." In addition, our cost of drilling, completing and operating wells is often uncertain.
Further,
many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
-
-
delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from wastewater disposal, emission
of greenhouse gases ("GHGs") and limitations on hydraulic fracturing;
-
-
pressure or irregularities in geological formations;
11
Table of Contents
-
-
shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;
-
-
equipment failures, accidents or other unexpected operational events;
-
-
lack of available gathering facilities or delays in construction of gathering facilities;
-
-
lack of available capacity on interconnecting transmission pipelines;
-
-
adverse weather conditions;
-
-
issues related to compliance with environmental regulations;
-
-
environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well
stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
-
-
declines in oil and natural gas prices;
-
-
limited availability of financing at acceptable terms;
-
-
title problems; and
-
-
limitations in the market for oil and natural gas.
The Silverback Acquisition involves risks associated with acquisitions and integrating acquired properties,
including the potential exposure to significant liabilities, and the intended benefits of the Silverback Acquisition may not be realized.
The Silverback Acquisition involves risks associated with acquisitions and integrating acquired properties into existing operations, including
that:
-
-
our senior management's attention may be diverted from the management of daily operations to the integration of the properties acquired in the
Silverback Acquisition;
-
-
we could incur significant unknown and contingent liabilities for which we have limited or no contractual remedies or insurance coverage;
-
-
the properties acquired in the Silverback Acquisition may not perform as well as we anticipate;
-
-
one or more parties may elect to exercise its rights under the AMI, resulting in us owning less acreage and having more cash on hand than we
currently anticipate;
-
-
unexpected costs, delays and challenges may arise in integrating the properties acquired in the Silverback Acquisition into our existing
operations; and
-
-
we may need to hire additional staff, devote additional resources and contract additional rigs to integrate the properties acquired in the the
Silverback Acquisition.
Even
if we successfully integrate the properties acquired in the Silverback Acquisition into our operations, it may not be possible to realize the full benefits we anticipate or we may
not realize these benefits within the expected timeframe. If we fail to realize the benefits we anticipate from the Silverback Acquisition, our business, results of operations and financial condition
may be adversely affected.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take
other actions to satisfy our obligations under applicable debt instruments, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness depends on our financial condition and operating performance, which
are subject to prevailing economic and
12
Table of Contents
competitive
conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to
pay the principal, premium, if any, and interest on our indebtedness.
If
our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek
additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at
such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of
existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a
timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we
could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. CRP's credit agreement currently restricts our
ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to
meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
Restrictions in CRP's existing and future debt agreements could limit our growth and ability to engage in
certain activities.
CRP's credit agreement contains a number of significant covenants, including restrictive covenants that may limit our ability to, among other
things:
-
-
incur additional indebtedness;
-
-
make loans to others;
-
-
make investments;
-
-
merge or consolidate with another entity;
-
-
make certain payments;
-
-
hedge future production or interest rates;
-
-
incur liens;
-
-
sell assets; and
-
-
engage in certain other transactions without the prior consent of the lenders.
In
addition, CRP's credit agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. As of September 30,
2016, we were in full compliance with such financial ratios and covenants.
The
restrictions in CRP's credit agreement may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to
otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants impose
on us.
A
breach of any covenant in CRP's credit agreement would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived, could result in
acceleration of the indebtedness outstanding under CRP's credit agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The
accelerated
13
Table of Contents
indebtedness
would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new
financing were available at that time, it may not be on terms that are acceptable to us.
Any significant reduction in the borrowing base under CRP's revolving credit facility as a result of the
periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
CRP's revolving credit facility limits the amounts CRP can borrow up to a borrowing base amount, which the lenders, in their sole discretion,
determine semiannually on April 1 and October 1. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties
securing the loan. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is
waived by the lenders. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under CRP's revolving credit facility. Any increase in the borrowing base
requires the consent of the lenders holding 100% of the commitments. In connection with the Silverback Acquisition, CRP entered into an amendment to its credit agreement to, among other things,
increase the borrowing base from $200 million to $250 million. The next scheduled borrowing base redetermination is expected in the spring of 2017.
In
the future, we may not be able to access adequate funding under CRP's revolving credit facility (or a replacement facility) as a result of a decrease in the borrowing base due to the
issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and
the inability of other lenders to provide additional funding to cover the defaulting lender's portion. Declines in commodity prices could result in a determination to lower the borrowing base in the
future and, in such a case, CRP could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and
development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to
service CRP's indebtedness.
Our derivative activities could result in financial losses or could reduce our earnings.
We enter into derivative instrument contracts for a portion of our oil and natural gas production. As of September 30, 2016, we had
entered into hedging contracts through December 2018 covering a total of 905 MBbls of our projected oil production and 1,460 BBtu of our projected natural gas production. In addition, as of
September 30, 2016, we had entered into basis swaps covering a total of 448 MBbls of our projected oil production. Accordingly, our earnings may fluctuate significantly as a result of
changes in fair value of our derivative instruments.
Derivative
instruments also expose us to the risk of financial loss in some circumstances, including when:
-
-
production is less than the volume covered by the derivative instruments;
-
-
the counterparty to the derivative instrument defaults on its contractual obligations;
-
-
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
-
-
there are issues with regard to legal enforceability of such instruments.
The
use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity
prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our
14
Table of Contents
operations
would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of CRP's borrowing base.
Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates. In addition, derivative arrangements could limit the
benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.
Our
commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden
decreases in a counterparty's liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are
unable to predict sudden changes in a counterparty's creditworthiness or ability to perform. Even if we accurately predict sudden changes, our ability to negate the risk may be limited depending upon
market conditions.
During
periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness
of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in
reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions,
including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the
estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available
geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and
natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual
future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary
from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than
expected, and production declines may be greater than our estimates and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to
reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities
and present value of our reserves.
You
should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted
future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example,
our estimated proved reserves as of December 31, 2015 and related standardized measure were calculated under rules of the SEC using twelve-month trailing average benchmark prices of
$46.79 per barrel of oil (WTI) and $2.59 per MMBtu (Henry Hub spot), which, for certain periods in 2016, were substantially higher than the available spot prices. If spot prices are below such
calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.
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We will not be the operator on all of our acreage or drilling locations, and, therefore, we will not be able
to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.
As of September 30, 2016, we have leased or acquired approximately 42,300 net acres, approximately 80% of which we operate. As of
September 30, 2016, we were the operator on 673 of our 1,388 identified gross horizontal drilling locations. We acquired approximately 35,000 net acres in the Silverback Acquisition,
approximately 95% of which we operate. We will have limited ability to exercise influence over the operations of the drilling locations operated by our partners, and there is the risk that our
partners may at any time have economic, business or legal interests or goals that are inconsistent with ours. Furthermore, the success and timing of development activities operated by our partners
will depend on a number of factors that will be largely outside of our control, including:
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the timing and amount of capital expenditures;
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the operator's expertise and financial resources;
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the approval of other participants in drilling wells;
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the selection of technology; and
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the rate of production of reserves, if any.
This
limited ability to exercise control over the operations and associated costs of some of our drilling locations could prevent the realization of targeted returns on capital in
drilling or acquisition activities.
Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties
that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the amount of capital that would be necessary to drill such locations.
We have specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our
existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and
natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and
pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know
if the numerous identified drilling locations will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is
established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling
activities may materially differ from those presently identified.
As
of September 30, 2016, we had identified 1,388 horizontal drilling locations on our acreage based on approximately 880-foot spacing with five to six wells per 640-acre section
in the Wolfcamp zones and approximately 1,320-foot spacing with four wells per 640-acre section in the 3rd Bone Spring Sandstone, in each case, consisting of laterals ranging from 4,500 feet up
to 9,500 feet. As a result of the limitations described above, we may be unable to drill many of our identified locations. In addition, we will require significant additional capital over a prolonged
period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See "Our development and acquisition projects
require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and
reserves." Any drilling activities we are able to conduct on these locations may not be successful or enable us to add additional proved reserves to our overall
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proved
reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. Additionally, if we
curtail our drilling program, we may lose a portion of our acreage through lease expirations.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several
years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.
As of September 30, 2016, approximately 60% of our total net acreage (approximately 79% of our operated net acreage in Reeves and Ward
counties) was either held by production or under continuous drilling provisions. Of the net acreage acquired in the Silverback Acquisition, approximately 37% was either held by production or under
continuous drilling provisions at the time of acquisition. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying
quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. If our leases expire and we are
unable to renew the leases, we will lose the right to develop the related properties. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural
gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline
transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.
Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling
activities.
Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power
failures, temporary shut-in of production and difficulties in the transportation of our oil, natural gas and NGLs. Any decreases in production due to poor weather conditions will have an adverse
effect on our revenues, which will in turn negatively affect our cash flow from operations.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to
obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes.
Drought conditions have persisted in Texas in past years. These drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing
to protect local water supplies. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect
on our financial condition, results of operations and cash flows.
Our producing properties are located in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas,
making us vulnerable to risks associated with operating in a single geographic area.
All of our producing properties are geographically concentrated in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas. At
December 31, 2015, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to
the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints,
market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.
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The marketability of our production is dependent upon transportation and other facilities, certain of which
we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation
facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a
transportation facility. Our natural gas production is generally transported by third-party gathering lines from the wellhead to a gas processing facility. We do not control these trucks and other
third-party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a
significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and
natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements
or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut-in or curtailment, or an inability to obtain favorable terms for
delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.
We may incur losses as a result of title defects in the properties in which we invest.
The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial
condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which
case we may lose the lease and the right to produce all or a portion of the minerals under the property.
The development of our estimated PUDs may take longer and may require higher levels of capital expenditures
than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.
As of December 31, 2015, 60% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved
undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop
such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In
addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Further, we may be required to write-down our PUDs if we do not drill those wells
within five years after their respective dates of booking.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are
less than their carrying value, we may be required to take write-downs of the carrying values of our properties.
Accounting rules that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices
and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be
required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. Recently, commodity prices have declined significantly. On September 30,
2016, the WTI spot price for crude oil was $47.72 per barrel and the Henry Hub spot price for natural gas was $2.84 per MMBtu, representing decreases of 55% and 63%, respectively, from the high of
$107.62 per barrel of oil and $7.92 per MMBtu for natural gas during 2014. Likewise, NGLs have suffered significant recent declines
in realized prices. NGLs are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which
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have
different uses and different pricing characteristics. Lower commodity prices in the future could result in impairments of our properties, which could have a material adverse effect on our results
of operations for the periods in which such charges are taken.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will
decline, which would adversely affect our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir
characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will
decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing
our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and
future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be
materially and adversely affected.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological
advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our
business, financial condition, results of operations and cash flows.
We depend upon a significant purchaser for the sale of most of our oil, natural gas and NGL production.
We normally sell our production to a relatively small number of customers, as is customary in our business. For the years ended
December 31, 2015 and 2014, Plains Marketing, L.P. accounted for 64% and 78%, respectively, of our total revenue. During such years, no other purchaser accounted for 10% or more of our
revenue. In the third quarter of 2016, we started selling the majority of our oil production to Shell Trading (US) Company ("Shell") under a new marketing contract. The loss of Shell as a purchaser
could materially and adversely affect our revenues in the short-term.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and
occupational health and safety requirements applicable to our business activities.
Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the
environment, health and safety aspects of our operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations,
including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the
environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria
addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection
Agency ("EPA") and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking
difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal
penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may
experience
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delays
in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.
Certain
environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes
have been stored
or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of
whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In
connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for
damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and
costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years.
The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and
consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling,
disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations.
Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely
affect our business, financial condition or results of operations.
Our
development activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility
of:
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environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the
environment, including groundwater, air and shoreline contamination;
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abnormally pressured formations;
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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse; fire, explosions and ruptures of pipelines;
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personal injuries and death;
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natural disasters; and
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terrorist attacks targeting oil and natural gas related facilities and infrastructure.
Any
of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties; and
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repair and remediation costs.
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We
may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution
and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition
and results of operations.
Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of
operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover
drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know
conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies
we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed
or canceled as a result of numerous factors, including:
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unexpected drilling conditions;
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title problems;
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pressure or lost circulation in formations;
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equipment failure or accidents;
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adverse weather conditions;
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compliance with environmental and other governmental or contractual requirements; and
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increases in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment
and services.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any
inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we
will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on
commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.
The
success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired
businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for
purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate
acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses
and assets into our existing operations
successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In
addition, CRP's credit agreement imposes certain limitations on our ability to enter into mergers or combination transactions. CRP's credit agreement also limits our ability to incur
certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.
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Certain of our properties are subject to land use restrictions, which could limit the manner in which we
conduct our business.
Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our
business. Although none of our drilling locations associated with proved undeveloped reserves as of December 31, 2015 or September 30, 2016 are on properties currently subject to such
land use restrictions, such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and
may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of
development activities and perhaps even be precluded from the drilling of wells.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield
services could adversely affect our ability to execute our development plans within our budget and on a timely basis.
The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and
conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas
prices, causing periodic shortages. Our operations are concentrated in areas in which industry had increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well
as access to transportation, processing and refining facilities in these areas, had increased, as did the costs for those items. However, beginning in the second half of 2014, commodity prices began
to decline and the demand for goods and services has subsided due to reduced activity. To the extent that commodity prices improve in the future, any delay or inability to secure the personnel,
equipment, power, services, resources and facilities access necessary
for us to resume or increase our development activities could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or
significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable
costs, we may not be able to drill all of our acreage before our leases expire.
We could experience periods of higher costs if commodity prices rise. These increases could reduce our
profitability, cash flow and ability to complete development activities as planned.
Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases
result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services
and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to declining costs of some drilling
equipment, materials and supplies. However, such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to
complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative
activities.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we
could be subject to substantial penalties and fines.
Under the Domenici-Barton Energy Policy Act of 2005 ("EP Act of 2005"), the Federal Energy Regulatory Commission ("FERC") has civil penalty
authority under the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act ("NGPA") to impose penalties for current violations of up to $1 million per day for each violation and
disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has
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adopted
regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market
manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other
matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.
Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs
and reduced demand for the oil and natural gas that we produce, while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for
or responding to those effects.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment,
the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required
to obtain preconstruction permits for their GHG emissions are also required to meet "best available control technology" standards that are being established by the states or, in some cases, by the EPA
on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA
has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which
include certain of our operations. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and
natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes
across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose methane emission standards for existing sources
as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments
to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require additional personnel time to support these activities or
the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.
While
Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG
emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG
emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In
addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most
recently, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which requires member countries to review and "represent a progression" in their
intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The Paris Agreement entered into force in November 2016. The United States is
one of over 70 nations that has ratified or otherwise consented to be bound by the agreement. Although it is not possible at this time to predict how legislation or new regulations that may be adopted
to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions
of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect
demand for the oil and natural gas we produce. Finally, many scientists have concluded
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that
increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and
other climatic events; if any such effects were to occur, they could have a material adverse effect on our operations.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as
governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our
production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface
rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and
stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted
federal regulatory authority pursuant to the federal Safe Drinking Water Act ("SDWA") over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance
in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards,
including standards for the capture of air emissions released during hydraulic fracturing, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to
disclose information regarding the chemicals used in hydraulic fracturing, and also finalized rules in 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly
owned wastewater treatment plants. In addition, the Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal
and American Indian lands. The U.S. District Court of Wyoming struck down the rule in June 2016. The BLM appealed the ruling to the Tenth Circuit. This appeals remains pending. In addition, Congress
has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing
process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.
Certain
governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality
is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in December
2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to
widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to
impact drinking water resources. Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of
hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.
At
the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on
hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a "well integrity rule," which updates the requirements for drilling, putting pipe down and cementing
wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is
later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek
to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in
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particular.
We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more
stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply
with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and
production activities, as well as our ability to dispose of saltwater gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the
increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015,
the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction.
In addition, a number of lawsuits have been filed in other states, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated
state and federal rules regulating waste disposal. In
response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of saltwater disposal wells or otherwise to assess any
relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texas published a new rule governing permitting or re-permitting of disposal wells
that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and
structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the
disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the
permit application or existing operating permit for that well.
We
dispose of large volumes of saltwater gathered from our drilling and production operations pursuant to permits issued to us by governmental authorities overseeing such disposal
activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating
constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption
and implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of saltwater gathered from our drilling and production activities by limiting
volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of
operations.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire
properties, market oil or natural gas and secure trained personnel.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select
suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is
substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially
greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number
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of
properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel
than we are able to offer. The cost to attract and retain qualified personnel has increased over the past
three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing
hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
Our business is difficult to evaluate because we have a limited operating history, and we are susceptible to
the potential difficulties associated with rapid growth and expansion.
CRP was formed in 2012 and, as a result, there is only limited historical financial and operating information available upon which to base your
evaluation of our performance.
In
addition, we have grown rapidly over the last several years. We believe that our future success depends on our ability to manage the rapid growth that we have experienced and the
demands from increased responsibility on management personnel. The following factors could present difficulties:
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increased responsibilities for our executive level personnel;
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increased administrative burden;
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increased capital requirements; and
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increased organizational challenges common to large, expansive operations.
Our
operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information of CRP included elsewhere in this
prospectus is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not
necessarily indicative of success from our future drilling operations.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates
or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place
us at a competitive disadvantage. For example, as of September 30, 2016, outstanding borrowings subject to variable interest rates were approximately $189 million, and a 1.0% increase in
interest rates would result in an increase in annual interest expense of approximately $1.9 million, assuming the $189 million of debt was outstanding for the full year. Recent and
continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance operations. We require continued access to
capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
We may be subject to risks in connection with acquisitions of properties.
The successful acquisition of producing properties requires an assessment of several factors,
including:
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recoverable reserves;
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future oil and natural gas prices and their applicable differentials;
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operating costs; and
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potential environmental and other liabilities.
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The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to
be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess
their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an
inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not
entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.
As a result of future legislation, certain U.S. federal income tax deductions currently available with
respect to oil and gas exploration and development may be eliminated and our production may be subject to the imposition of new U.S. federal taxes.
The U.S. President's Fiscal Year 2017 Budget Proposal and legislation introduced in a prior session of Congress includes proposals that, if
enacted into law, would eliminate certain key U.S. federal income tax provisions currently available to oil and gas exploration and production companies or potentially make our operations subject to
the imposition of new U.S. federal taxes. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the
elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, (iv) an extension of
the amortization period for certain geological and geophysical expenditures and (v) imposition of a $10.25 per barrel fee on oil, to be paid by oil companies (but the budget does not describe
where and how such a fee would be collected). It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any
legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil
and gas exploration and development, and any such change, as well as any changes to or the imposition of new U.S. federal, state or local taxes (including the imposition of, or increase in production,
severance or similar taxes), could increase the cost of exploration and development of oil and gas resources, which would negatively affect our financial condition and results of operations.
Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and
natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying
subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, our drilling activities may not
be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and we could
incur losses as a result of such expenditures.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our
ability to conduct drilling activities in areas where we operate.
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities
designed to protect various wildlife. Seasonal
restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to
periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent
restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of
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expensive
mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species
protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative
instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and
entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission ("CFTC") and the SEC to promulgate rules and regulations implementing the
Dodd-Frank Act. In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic
equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules
that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging
transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
The
CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including
physical commodity swaps, for mandatory clearing. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps.
Although we expect to qualify for the end-user exception from such margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market
participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of
collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow.
The
full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives
contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the
availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result
of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund
capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives
and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity
prices. Any of these consequences could have a material and adverse effect on us and our financial condition.
In
addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in
foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.
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The standardized measure of our estimated reserves is not an accurate estimate of the current fair value of
our estimated oil and natural gas reserves.
Standardized measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and
regulations of the SEC. Standardized measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation.
Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs
that will be required to produce or develop the oil and natural gas properties. As a result, estimates included herein of future net cash flow may be materially different from the future net cash
flows that are ultimately received, and the standardized measure of our estimated reserves included in this prospectus should not be construed as accurate estimates of the current fair value of our
proved reserves.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and
services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies
at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in
the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable
cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
Changes in laws or regulations, or a failure to comply with any laws and regulations, may adversely affect
our business, investments and results of operations.
We are subject to laws, regulations and rules enacted by national, regional and local governments and NASDAQ. In particular, we are required to
comply with certain SEC, NASDAQ and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly.
Those laws, regulations and rules and their interpretation and application may also change from time to time and those changes could have a material adverse effect on our business, investments and
results of operations. In addition, a failure to comply with applicable laws, regulations and rules, as interpreted and applied, could have a material adverse effect on our business and results of
operations.
Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or
other tax returns could adversely affect our financial condition and results of operations.
We are subject to income taxes in the United States, and our domestic tax liabilities are subject to the allocation of expenses in differing
jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:
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changes in the valuation of our deferred tax assets and liabilities;
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expected timing and amount of the release of any tax valuation allowances;
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tax effects of stock-based compensation;
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costs related to intercompany restructurings;
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changes in tax laws, regulations or interpretations thereof; or
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lower than anticipated future earnings in jurisdictions where we have lower statutory tax rates and higher than anticipated future earnings in
jurisdictions where we have higher statutory tax rates.
In
addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect
on our financial condition and results of operations.
Risks Related to Our Securities and Capital Structure
The market price of our securities may decline.
Fluctuations in the price of our securities could contribute to the loss of all or part of your investment. Prior to the closing of the Business
Combination, trading in our Class A Common Stock and Public Warrants had been limited. If an active market for our securities develops and continues, the trading price of our securities could
be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of the factors listed below could have a material adverse effect on your
investment and our securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of our securities may not recover and may experience a
further decline.
Factors
affecting the trading price of our securities may include:
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actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar
to us;
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changes in the market's expectations about our operating results;
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success of competitors;
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our operating results failing to meet the expectation of securities analysts or investors in a particular period;
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changes in financial estimates and recommendations by securities analysts concerning us or its markets in general;
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operating and stock price performance of other companies that investors deem comparable to us;
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our ability to market new and enhanced products on a timely basis;
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changes in laws and regulations affecting our business;
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commencement of, or involvement in, litigation involving us;
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changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;
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the volume of securities available for public sale;
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any major change in our board or management;
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sales of substantial amounts of our securities by our directors, executive officers or significant stockholders or the perception that such
sales could occur; and
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general economic and political conditions such as recession; interest rate, fuel price, and international currency fluctuations; and acts of
war or terrorism.
Many
of the factors listed above are beyond our control. In addition, broad market and industry factors may materially harm the market price of our securities irrespective of our
operating
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performance.
The stock market in general, and NASDAQ have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular
companies affected. The trading prices and valuations of these stocks, and of our Class A Common Stock and Public Warrants which trade on NASDAQ, may not be predictable. A loss of investor
confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to the Company could depress the price of our securities regardless of our business,
prospects, financial conditions or results of operations. A decline in the market price of our securities also could adversely affect our ability to issue additional securities and our ability to
obtain additional financing in the future.
If securities or industry analysts do not publish or cease publishing research or reports about us, our
business, or our market, or if they change their recommendations regarding our securities adversely, the price and trading volume of our securities could decline.
The trading market for our securities will be influenced by the research and reports that industry or securities analysts may publish about us,
our business, our market, or our competitors. Securities and industry analysts do not currently, and may never, publish research on us. If no securities or industry analysts commence coverage of us,
our stock price and trading volume would likely be negatively impacted. If any of the analysts who may cover us change their recommendation regarding our securities adversely, or provide more
favorable relative recommendations about our competitors, the price of our securities would likely decline. If any analyst who may cover us were to cease coverage of us or fail to regularly publish
reports on it, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.
Riverstone and its affiliates own a significant percentage of our outstanding voting common stock.
Riverstone and its affiliates, including our Sponsor, beneficially own approximately 44.0% of our voting common stock and, upon the conversion
of our Series B Preferred Stock, will beneficially own approximately 49.96% of our voting common stock. As long as Riverstone and its affiliates, including our Sponsor, own or control a
significant percentage of outstanding voting power, they will have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of
directors and the size of our board of directors, any amendment of our charter or bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially
all of our assets.
The
interests of Riverstone and its affiliates, including our Sponsor, may not align with the interests of our other stockholders. Our Sponsor is in the business of making investments in
companies and may acquire and hold interests in businesses that compete directly or indirectly with us. Riverstone and its affiliates, including our Sponsor, may also pursue acquisition opportunities
that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, our second amended and restated certificate of incorporation (the
"Charter") provides that we renounce any interest or expectancy in the business opportunities of our officers and directors and their respective affiliates and each such party shall not have any
obligation to offer us those opportunities unless presented to one of our directors or officers in his or her capacity as a director or officer.
We are no longer a "controlled company" within the meaning of the NASDAQ listing rules, and will not be able
to take advantage of exemptions from certain corporate governance requirements.
Riverstone and its affiliates, including our Sponsor, no longer control a majority of our outstanding voting common stock. After the conversion
of our Series B Preferred Stock, Riverstone will not own over 50.0% of our voting common stock. As a result, we are no longer a "controlled company" within the meaning of the NASDAQ listing
rules, and will not be able to take advantage of exemptions from
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certain
corporate governance requirements. Under the NASDAQ listing rules, a company of which more than 50% of the voting power is held by an individual, group or another company is a "controlled
company" and is exempt from certain corporate governance requirements, including, among others, the following:
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a majority of its board of directors consist of independent directors (as defined under the NASDAQ corporate governance standards);
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its nominating and corporate governance committee consists entirely of independent directors; and
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the compensation of its executive officers be determined, or recommended to the board for determination, by a majority of independent directors
in a vote by independent directors, or by a compensation committee comprised solely of independent directors.
Pursuant
to the requirements of the NASDAQ listing rules, a majority of our board of directors must consist of independent directors within one year after we cease to be a controlled
company. In addition, we must comply with the independent board committee requirements as they relate to the
nominating and corporate governance and compensation committees on the following phase-in schedule: (1) one independent committee member at the time we cease to be a controlled company,
(2) a majority of independent committee members within 90 days of the date we cease to be a controlled company and (3) all independent committee members within one year of the
date we cease to be a controlled company. Our board of directors is not currently comprised of a majority of independent directors, and neither our corporate governance and nominating committee nor
our compensation committee is currently comprised solely of independent directors. Accordingly, during the applicable phase-in periods provided for under the NASDAQ listing rules, you may not have the
same protections afforded to stockholders of companies that are subject to all of the NASDAQ corporate governance standards.
Anti-takeover provisions contained in our Charter and amended and restated bylaws (the "Bylaws"), as well as
provisions of Delaware law, could impair a takeover attempt.
Our Charter and Bylaws contain provisions that could have the effect of delaying or preventing changes in control or changes in our management
without the consent of our board of directors. These provisions include:
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no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;
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the exclusive right of our board of directors to elect a director to fill a vacancy created by the expansion of the board of directors or the
resignation, death, or removal of a director, which prevents stockholders from being able to fill vacancies on our board of directors;
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the ability of our board of directors to determine whether to issue shares of our preferred stock and to determine the price and other terms of
those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer;
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a prohibition on stockholder action by written consent, which forces stockholder action to be taken at an annual or special meeting of our
stockholders;
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the requirement that an annual meeting of stockholders may be called only by the chairman of the board of directors, the chief executive
officer, or the board of directors, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors;
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limiting the liability of, and providing indemnification to, our directors and officers;
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controlling the procedures for the conduct and scheduling of stockholder meetings;
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providing that directors may be removed prior to the expiration of their terms by stockholders only for cause; and
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advance notice procedures that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to
be acted upon at a stockholders' meeting, which may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer's own slate of directors or otherwise
attempting to obtain control of the Company.
These
provisions, alone or together, could delay hostile takeovers and changes in control of the Company or changes in our board of directors and management.
As
a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law (the "DGCL"), which
prevents some stockholders holding more than 15% of our outstanding voting common stock from engaging in certain business combinations without approval of the holders of substantially all of our
outstanding voting common stock. Any provision of our Charter or Bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our
stockholders to receive a premium for their securities and could also affect the price that some investors are willing to pay for our securities.
The JOBS Act permits "emerging growth companies" like us to take advantage of certain exemptions from various
reporting requirements applicable to other public companies that are not emerging growth companies.
We qualify as an "emerging growth company" as defined in the JOBS Act. As such, we take advantage of certain exemptions from various reporting
requirements applicable to other public companies that are not emerging growth companies for as long as we continue to be an emerging growth company, including (i) the exemption from the
auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (ii) the exemptions from say-on-pay,
say-on-frequency and say-on-golden parachute voting requirements and (iii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. As a
result, our stockholders may not have access to certain information they deem important. We will remain an emerging growth company until the earliest of (i) the last day of the fiscal year
(a) following February 28, 2021, the fifth anniversary of our IPO, (b) in which we have total annual gross revenue of at least $1.0 billion or (c) in which we are
deemed to be a large accelerated filer, which means the market value of our Class A Common Stock that is held by non-affiliates exceeds $700 million as of the last business day of our
prior second fiscal quarter, and (ii) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three-year period.
In
addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the exemption from complying with new or revised accounting standards
provided in Section 7(a)(2)(B) of the Securities Act as long as we are an emerging growth company. An emerging growth company can therefore delay the adoption of certain accounting standards
until those standards would otherwise apply to private companies. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that
apply to non-emerging growth companies, but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period, which means that when a standard is issued
or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new
or revised standard. This may make comparison of our financial statements with another public company which is neither
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an
emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accountant
standards used.
We
cannot predict if investors will find our Class A Common Stock less attractive because we will rely on these exemptions. If some investors find our Class A Common Stock
less attractive as a result, there may be a less active trading market for our Class A Common Stock and our stock price may be more volatile.
Non-U.S. holders may be subject to U.S. income tax with respect to gain on disposition of their
Class A Common Stock.
We believe that we are a United States real property holding corporation (a "USRPHC"). As a result, Non-U.S. holders (defined below in the
section entitled "Material U.S. Federal Income Tax Considerations") that own (or are treated as owning under constructive ownership rules) more than a specified amount of our Class A Common
Stock during a specified time period may be subject to U.S. federal income tax on a sale, exchange, or other disposition of such Class A Common Stock and may be required to file a U.S.
federal income tax return. If you are a Non-U.S. holder, we urge you to consult your tax advisors regarding the tax consequences of such treatment.
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this prospectus constitute "forward-looking statements." All statements, other than statements of historical fact included
in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking
statements. When used in this prospectus, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "project" and similar expressions are intended to identify forward-looking
statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management's current expectations and assumptions about future
events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other
cautionary statements described under the heading "Risk Factors."
Forward-looking
statements may include statements about:
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our business strategy;
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our reserves;
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our drilling prospects, inventories, projects and programs;
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our ability to replace the reserves we produce through drilling and property acquisitions;
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our financial strategy, liquidity and capital required for our development program;
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our realized oil, natural gas and natural gas liquids ("NGL") prices;
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the timing and amount of our future production of oil, natural gas and NGLs;
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our hedging strategy and results;
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our future drilling plans;
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our competition and government regulations;
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our ability to obtain permits and governmental approvals;
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our pending legal or environmental matters;
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our marketing of oil, natural gas and NGLs;
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our leasehold or business acquisitions;
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our costs of developing our properties;
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general economic conditions;
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credit markets;
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uncertainty regarding our future operating results; and
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our plans, objectives, expectations and intentions contained in this prospectus that are not historical.
We
caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control,
incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling
and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of
production, cash flow and
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access
to capital, the timing of development expenditures and the other risks described under the heading "Risk Factors."
Reserve
engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on
the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may
justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates
may differ significantly from the quantities of oil and natural gas that are ultimately recovered.
Should
one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ
materially from those expressed in any forward-looking statements.
All
forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should
also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except
as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to
reflect events or circumstances after the date of this prospectus.
36
Table of Contents
USE OF PROCEEDS
We will not receive any of the proceeds from the sale of Class A Common Stock by the selling stockholders named herein.
DETERMINATION OF OFFERING PRICE
Our Class A Common Stock is listed on NASDAQ under the symbol "CDEV." The actual offering price by the selling stockholders of the shares
of Class A Common Stock covered by this prospectus will be determined by prevailing market prices at the time of sale, by private transactions negotiated by the selling stockholders or as
otherwise described in the section entitled "Plan of Distribution."
PRICE RANGE OF SECURITIES AND DIVIDENDS
Our Class A Common Stock is currently listed on NASDAQ under the symbol "CDEV". Through October 11, 2016, our Class A
Common Stock was listed under the symbol "SRAQ". The following table sets forth for the periods indicated, the reported high and low bid quotations per share for our Class A Common Stock.
|
|
|
|
|
|
|
|
|
|
Class A Common
Stock (CDEV)
|
|
|
|
High
|
|
Low
|
|
2017:
|
|
|
|
|
|
|
|
First Quarter(1)
|
|
$
|
20.08
|
|
$
|
18.19
|
|
2016:
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$
|
16.96
|
|
$
|
14.09
|
|
Third Quarter
|
|
$
|
16.10
|
|
$
|
9.65
|
|
Second Quarter(2)
|
|
$
|
10.70
|
|
$
|
9.80
|
|
First Quarter(3)
|
|
|
N/A
|
|
|
N/A
|
|
-
(1)
-
Through
January 18, 2017.
-
(2)
-
Beginning
on April 15, 2016.
-
(3)
-
Since
the Class A Common Stock commenced separate trading on April 15, 2016, there is no information presented for the Class A Common Stock for
the first quarter of 2016.
On
January 18, 2017, the closing price of our Class A Common Stock was $18.87. As of January 18, 2017, there were 200,835,049 shares of Class A Common Stock
outstanding, held of record by 215 holders. In addition, 24,666,643 shares of Class A Common Stock are issuable upon exercise of the 24,666,643 Warrants, held of record by two holders.
The number of record holders of our Class A Common Stock does not include DTC participants or beneficial owners holding shares through nominee names.
Dividend Policy
We have not paid any cash dividends on our Class A Common Stock or Class C Common Stock to date. Our board of directors may from
time to time consider whether or not to institute a dividend policy. It is our present intention to retain any earnings for use in our business operations and, accordingly, the we do not anticipate
the board of directors declaring any dividends in the foreseeable future.
37
Table of Contents
SELECTED HISTORICAL FINANCIAL INFORMATION
The following table shows selected historical financial information of CRP for the periods and as of the dates indicated. For all periods ending
on or prior to and all dates as of or prior to October 15, 2014, the date on which Celero conveyed all of its oil and natural gas properties to CRP,
the following table reflects the combined results of CRP and Celero, and for all periods and dates subsequent to October 15, 2014, reflects the results of CRP.
The
selected historical consolidated and combined financial information of CRP as of and for the years ended December 31, 2015, 2014 and 2013 was derived from the audited
historical consolidated and combined financial statements of CRP included elsewhere in this prospectus. The selected historical interim consolidated financial information of CRP as of
September 30, 2016 and for the nine months ended September 30, 2016 and 2015 was derived from the unaudited interim condensed consolidated financial statements of CRP included elsewhere
in this prospectus.
CRP's
historical results are not necessarily indicative of future operating results. The selected consolidated and combined financial information should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical
38
Table of Contents
consolidated
and combined financial statements of CRP and accompanying notes included elsewhere in this prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
Year Ended December 31,
|
|
|
|
2016
|
|
2015
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
56,975
|
|
$
|
59,068
|
|
$
|
77,643
|
|
$
|
114,955
|
|
$
|
65,863
|
|
Natural gas sales
|
|
|
5,717
|
|
|
6,082
|
|
|
7,965
|
|
|
9,670
|
|
|
3,024
|
|
NGL sales
|
|
|
3,097
|
|
|
3,590
|
|
|
4,852
|
|
|
7,200
|
|
|
3,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
65,789
|
|
|
68,740
|
|
|
90,460
|
|
|
131,825
|
|
|
71,974
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
10,295
|
|
|
17,317
|
|
|
21,173
|
|
|
17,690
|
|
|
19,106
|
|
Severance and ad valorem taxes
|
|
|
3,523
|
|
|
3,833
|
|
|
5,021
|
|
|
6,875
|
|
|
4,153
|
|
Transportation, processing, gathering and other operating expenses
|
|
|
4,375
|
|
|
4,352
|
|
|
5,732
|
|
|
4,772
|
|
|
1,291
|
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
60,939
|
|
|
64,003
|
|
|
90,084
|
|
|
69,110
|
|
|
29,285
|
|
Abandonment expense and impairment of unproved properties
|
|
|
2,546
|
|
|
3,851
|
|
|
7,619
|
|
|
20,025
|
|
|
8,561
|
|
Exploration
|
|
|
|
|
|
|
|
|
84
|
|
|
|
|
|
|
|
Contract termination and rig stacking
|
|
|
|
|
|
2,388
|
|
|
2,387
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
|
10,655
|
|
|
8,538
|
|
|
14,206
|
|
|
31,694
|
|
|
16,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
92,333
|
|
|
104,282
|
|
|
146,306
|
|
|
150,166
|
|
|
79,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss (gain) on sale of oil and natural gas properties
|
|
|
(11
|
)
|
|
(2,688
|
)
|
|
(2,439
|
)
|
|
2,096
|
|
|
(16,756
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating (loss) income
|
|
|
(26,533
|
)
|
|
(32,854
|
)
|
|
(53,407
|
)
|
|
(20,437
|
)
|
|
9,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(5,422
|
)
|
|
(4,743
|
)
|
|
(6,266
|
)
|
|
(2,475
|
)
|
|
(513
|
)
|
(Loss) gain on derivatives instruments
|
|
|
(4,184
|
)
|
|
12,320
|
|
|
20,756
|
|
|
41,943
|
|
|
(4,410
|
)
|
Other income
|
|
|
6
|
|
|
(5
|
)
|
|
20
|
|
|
281
|
|
|
122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other (expense) income
|
|
|
(9,600
|
)
|
|
7,572
|
|
|
14,510
|
|
|
39,749
|
|
|
(4,801
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before taxes
|
|
|
(36,133
|
)
|
|
(25,282
|
)
|
|
(38,897
|
)
|
|
19,312
|
|
|
4,691
|
|
Income tax benefit (expense)(2)
|
|
|
406
|
|
|
|
|
|
572
|
|
|
(1,524
|
)
|
|
(1,079
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
(35,727
|
)
|
|
(25,282
|
)
|
|
(38,325
|
)
|
|
17,788
|
|
|
3,612
|
|
Less: Net loss attributable to noncontrolling interest
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(35,727
|
)
|
$
|
(25,282
|
)
|
$
|
(38,325
|
)
|
$
|
17,790
|
|
$
|
3,618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
51,511
|
|
$
|
48,474
|
|
$
|
68,882
|
|
$
|
97,248
|
|
$
|
13,416
|
|
Net cash used in investing activities
|
|
|
(100,975
|
)
|
|
(171,316
|
)
|
|
(198,635
|
)
|
|
(163,380
|
)
|
|
(136,517
|
)
|
Net cash provided by financing activities
|
|
|
48,106
|
|
|
110,219
|
|
|
118,504
|
|
|
36,966
|
|
|
118,742
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX(1)
|
|
$
|
53,570
|
|
$
|
60,667
|
|
$
|
82,279
|
|
$
|
88,108
|
|
$
|
18,059
|
|
39
Table of Contents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
September 30,
2016
|
|
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
410
|
|
$
|
1,768
|
|
$
|
13,017
|
|
$
|
42,183
|
|
Cash held in escrow
|
|
|
|
|
|
|
|
|
|
|
|
5,000
|
|
Other current assets
|
|
|
12,840
|
|
|
32,377
|
|
|
54,329
|
|
|
19,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
13,250
|
|
|
34,145
|
|
|
67,346
|
|
|
66,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
619,375
|
|
|
578,787
|
|
|
540,624
|
|
|
357,541
|
|
Other long-term assets
|
|
|
1,287
|
|
|
3,363
|
|
|
7,799
|
|
|
48,229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
633,912
|
|
$
|
616,295
|
|
$
|
615,769
|
|
$
|
472,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
24,822
|
|
$
|
22,133
|
|
$
|
103,512
|
|
$
|
46,169
|
|
Revolving credit facility
|
|
|
124,000
|
|
|
74,000
|
|
|
65,000
|
|
|
29,000
|
|
Term loan, net of unamortized deferred financing costs
|
|
|
64,762
|
|
|
64,649
|
|
|
64,568
|
|
|
|
|
Other long-term liabilities
|
|
|
5,191
|
|
|
4,649
|
|
|
4,757
|
|
|
6,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
218,775
|
|
|
165,431
|
|
|
237,837
|
|
|
81,538
|
|
Owners' equity
|
|
|
415,137
|
|
|
450,864
|
|
|
377,932
|
|
|
389,859
|
|
Noncontrolling interest in unconsolidated subsidiary
|
|
|
|
|
|
|
|
|
|
|
|
688
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and owners' equity
|
|
$
|
633,912
|
|
$
|
616,295
|
|
$
|
615,769
|
|
$
|
472,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Adjusted
EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income, see
"Non-GAAP Financial Measure" below.
-
(2)
-
The
Company is a C-corp under the Internal Revenue Code of 1986, as amended, and, as a result, is subject to U.S. federal, state and local income taxes. Although CRP
is subject to franchise tax in the State of Texas (at less than 1% of modified pre-tax earnings), as a partnership, it generally passes through its taxable income to its owners for other income tax
purposes and is not subject to U.S. federal income taxes or other state or local income taxes.
Non-GAAP Financial Measure
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by our management and external users of our financial statements,
such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization and
accretion of asset retirement obligations, abandonment expense and impairment of unproved properties, (gains) losses on derivatives excluding net cash receipts (payments) on settled derivatives,
non-cash equity based compensation, gains and losses from the sale of assets and other non-cash and non-recurring operating items. Adjusted EBITDAX is not a measure of net income as determined by
United States generally accepted accounting principles ("GAAP").
Our
management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to
period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can
vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as
40
Table of Contents
determined
in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing
a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our
presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be
comparable to other similarly titled measures of other companies.
The
following table presents a reconciliation of Adjusted EBITDAX to net income, the most directly comparable financial measure calculated and presented in accordance with GAAP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
Year Ended December 31,
|
|
|
|
2016
|
|
2015
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Adjusted EBITDAX reconciliation to net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(35,727
|
)
|
$
|
(25,282
|
)
|
$
|
(38,325
|
)
|
$
|
17,790
|
|
$
|
3,618
|
|
Interest expense
|
|
|
5,422
|
|
|
4,743
|
|
|
6,266
|
|
|
2,475
|
|
|
513
|
|
Income tax (benefit) expense
|
|
|
(406
|
)
|
|
|
|
|
(572
|
)
|
|
1,524
|
|
|
1,079
|
|
Depreciation, depletion and amortization and accretion of asset retirement obligations
|
|
|
60,939
|
|
|
64,003
|
|
|
90,084
|
|
|
69,110
|
|
|
29,285
|
|
Abandonment expense and impairment of unproved properties
|
|
|
2,546
|
|
|
3,851
|
|
|
7,619
|
|
|
20,025
|
|
|
8,561
|
|
Loss (gain) on derivatives
|
|
|
4,184
|
|
|
(12,320
|
)
|
|
(20,756
|
)
|
|
(41,943
|
)
|
|
4,410
|
|
Net cash received for derivative settlements
|
|
|
16,623
|
|
|
25,972
|
|
|
36,430
|
|
|
4,611
|
|
|
(12,651
|
)
|
Noncash incentive compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
12,420
|
|
|
|
|
Contract termination and rig stacking
|
|
|
|
|
|
2,388
|
|
|
2,387
|
|
|
|
|
|
|
|
Write-off of deferred offering costs(1)
|
|
|
|
|
|
|
|
|
1,585
|
|
|
|
|
|
|
|
Loss (gain) on sale of oil and natural gas properties
|
|
|
(11
|
)
|
|
(2,688
|
)
|
|
(2,439
|
)
|
|
2,096
|
|
|
(16,756
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
|
|
$
|
53,570
|
|
$
|
60,667
|
|
$
|
82,279
|
|
$
|
88,108
|
|
$
|
18,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
During
the year ended December 31, 2015, CRP delayed the timing of its initial public offering and, as a result, deferred offering costs of
$1.6 million were charged against earnings.
41
Table of Contents
DESCRIPTION OF BUSINESS
Corporate History
We were originally incorporated in Delaware on November 4, 2015 as a blank check company under the name Silver Run Acquisition
Corporation for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving us and one or more businesses (an
"initial business combination").
On
February 29, 2016, we consummated our IPO of 50,000,000 Units (including 5,000,000 Units sold pursuant to the underwriters' partial exercise of their over-allotment option) at
$10.00 per Unit, with each Unit consisting of one share of Class A Common Stock and one-third of one Public Warrant. Our IPO generated total gross proceeds of $500,000,000. Prior to the
consummation of our IPO, in November 2015, Silver Run Sponsor, LLC (our "Sponsor") purchased 11,500,000 shares of Class B Common Stock (the "founder shares"), for an aggregate purchase
price of $25,000, or approximately $0.002 per share. On February 23, 2016, we effected a stock dividend of approximately 0.125 shares for each outstanding share of Class B Common Stock,
resulting in the initial stockholders holding an aggregate of 12,937,500 founder shares. Also, in February 2016, our Sponsor transferred 40,000 of its founder shares to each of William D. Gutermuth,
Jeffery H. Tepper and Diana J. Walters, our independent directors at the time of the transfer. On April 8, 2016, following the expiration of the underwriters' remaining over-allotment option in
connection with our IPO, our Sponsor forfeited 437,500 founder shares.
Simultaneously
with the closing of our IPO on February 29, 2016, we completed the private sale of 8,000,000 warrants (the "Private Placement Warrants") to our Sponsor at a
purchase price of $1.50 per Private Placement Warrant, generating gross proceeds to us of $12,000,000. The Private Placement Warrants are identical to the Public Warrants, except that our Sponsor
agreed not to transfer, assign or sell any of the Private Placement Warrants (except to certain permitted transferees) until 30 days after the closing of the initial business combination. The
Private Placement Warrants are also not redeemable by us so long as they are held by our Sponsor or its permitted transferees.
A
total of $500,000,000, comprised of $490,000,000 of the proceeds from our IPO, including approximately $17,500,000 in deferred underwriting commissions to the underwriters of our IPO,
and the proceeds of the sale of the Private Placement Warrants were placed in a trust account maintained by Continental Stock Transfer & Trust Company, acting as trustee.
On
April 14, 2016, we announced that the holders of our Units could elect to separately trade the Class A Common Stock and Public Warrants included in the Units commencing
on April 15, 2016. The Units not separated continued to trade on NASDAQ under the symbol "SRAQU" until October 11, 2016, when the Units were separated into their component securities in
connection with the consummation of the Business Combination (as defined below).
From
the consummation of our IPO through the end of June 2016, we were searching for a suitable target business to effect an initial business combination. On July 6, 2016, New
Centennial, LLC, a Delaware limited liability company and affiliate of our Sponsor ("NewCo"), entered into a Contribution Agreement (as amended by Amendment No. 1 thereto, dated as of
July 29, 2016, the "Contribution Agreement"), with Centennial Resource Development, LLC, a Delaware limited liability company ("CRD"), NGP Centennial Follow-On LLC, a Delaware
limited liability company ("NGP Follow-On"), Celero Energy Company, LP, a Delaware limited partnership ("Celero" and, together with CRD and NGP Follow-On, the "Centennial Contributors"),
Centennial Resource Production, LLC, a Delaware limited liability company ("CRP"), to acquire approximately 89% of the outstanding membership interests in CRP, and on October 7, 2016,
NewCo assigned its rights to acquire such membership interests to us (the acquisition and the other transactions contemplated by the Contribution Agreement, the "Business Combination").
42
Table of Contents
Upon
the terms and conditions contained in the Contribution Agreement, at the closing of the Business Combination, we contributed to CRP approximately $1.49 billion in cash and
CRP then distributed to the Centennial Contributors cash in the amount of approximately $1.19 billion in partial redemption of the Centennial Contributors' membership interests in CRP. We and
the Centennial Contributors effected a recapitalization of CRP (the "Recapitalization"), pursuant to which (1) all of the remaining outstanding membership interests of the Centennial
Contributors were converted into 20,000,000 units representing common membership interests in CRP (the "CRP Common Units") and (2) we were admitted as a member of CRP and issued the remaining
163,505,000 CRP Common Units. We also issued 20,000,000 shares of our Class C Common Stock, par value $0.0001 per share (the "Class C Common Stock"), to the Centennial Contributors.
Pursuant to the terms of the limited liability company agreement of CRP, the Centennial Contributors and their permitted transferees generally have the right to cause CRP to redeem all or a portion of
their CRP Common Units in exchange for shares of our Class A Common Stock or, at CRP's option, an equivalent amount of cash; provided that we may, at our option, effect a direct exchange of
such cash or Class A Common Stock for such CRP Common Units in lieu of a redemption by CRP. Upon the future redemption or exchange of CRP Common Units held by a Centennial Contributor, a
corresponding number of shares of Class C Common Stock will be canceled.
In
connection with the closing of the Business Combination, we also issued one share of our Series A Preferred Stock, par value $0.0001 per share (the "Series A Preferred
Stock"), to CRD. CRD, as the holder of the Series A Preferred Stock, is not entitled to any dividends from us, but will be entitled to preferred distributions in liquidation in the amount of
$0.0001 per share of Series A Preferred Stock. In addition, for so long as the Series A Preferred Stock remains outstanding, CRD will be entitled to nominate one director for election to
our board of directors in connection with any vote of our stockholders for the election of directors, and the vote of CRD will be the only vote required to elect such nominee to our board. The
Series A Preferred Stock is redeemable by us (a) at such time as CRD and its affiliates cease to own, in the aggregate, at least 5,000,000 CRP Common Units and/or shares of
Class A Common Stock (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions), (b) at any time at CRD's option or
(c) upon a breach of the transfer restrictions relating to the Series A Preferred Stock.
Upon
the closing of the Business Combination, we changed our name from "Silver Run Acquisition Corporation" to "Centennial Resource Development, Inc.," and continued the listing
of our Class A Common Stock and Public Warrants under the symbols "CDEV" and "CDEVW," respectively. The Units automatically separated into their component securities upon closing of the
Business Combination and, as a result, no longer trade as a separate security.
CRP History
CRP was formed in August 2012 by an affiliate of Natural Gas Partners, a family of energy-focused private equity investment funds, in connection
with the acquisition of all of the oil and natural gas properties and certain other assets of Celero, which was formed in 2006 to focus on the development and acquisition of oil and natural gas
properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. Until the closing of the Business Combination, CRP operated as a privately-held independent oil and natural gas
company.
CRP
is considered our accounting predecessor and hence the historical financial statements of CRP for the three years ended December 31, 2015 and the interim period ended
September 30, 2016 (unaudited) are included elsewhere in this prospectus. The historical financial statements of Silver Run Acquisition Corporation (a development stage company) for the period
from November 4, 2015 (inception) to December 31, 2015 and for the nine months ended September 30, 2016 (unaudited) are not included in this prospectus, but were included in our
definitive proxy statement filed with the Securities and Exchange Commission on September 23, 2016 and our Quarterly Report on Form 10-Q
43
Table of Contents
for
the quarter ended September 30, 2016, respectively. Unless otherwise specified herein, the information set forth in this prospectus does not reflect the completion of the Silverback
Acquisition.
Our Business
Our only significant asset is our ownership of an approximate 92% membership interest in CRP. We are an independent oil and natural gas company
focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin
of the Permian Basin, and our properties consist of large, contiguous acreage blocks in Reeves, Ward and Pecos counties in West Texas.
As
of September 30, 2016, our portfolio included 63 operated producing horizontal wells. The horizontal wells span an area approximately 45 miles long by 20 miles
wide where we have established commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and
Wolfcamp C. As a result, we have broadly appraised our acreage across various geographic areas and stratigraphic zones, which we expect will allow us to efficiently develop our drilling
inventory with a focus on maximizing returns to our stockholders. In addition, we believe our acreage may be prospective for the 2nd and 3rd Bone Spring shales and Avalon Shale, where
other operators have experienced drilling success near our acreage.
As
of September 30, 2016, we have leased or acquired approximately 42,300 net acres, approximately 80% of which we operate. Our acreage is predominantly located in the southern
portion of the Delaware Basin, where production and reserves typically contain a higher percentage of oil and natural gas liquids and a correspondingly lower percentage of natural gas compared to the
northern portion of the Delaware Basin. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, we added one horizontal rig in June 2016, a second horizontal rig
in September 2016 and a third horizontal rig in October 2016. During 2016, we placed 11 horizontal wells on production. Our development drilling plan is comprised exclusively of horizontal drilling
with an ongoing focus on reducing drilling times, optimizing completions and reducing costs.
The
Permian Basin is an attractive operating area due to its extensive original oil-in-place, favorable operating environment, multiple horizontal zones, high oil and liquids-rich
natural gas content, well-developed network of oilfield service providers, long-lived reserves with relatively consistent reservoir quality and historically high drilling success rates. According to
the U.S. Energy Information Administration (the "EIA"), the Permian Basin is the most prolific oil producing area in the United States, accounting for 46% and 36% of total crude oil production from
the seven most prolific U.S. producing regions (Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian and Utica) during the month ended December 31, 2016 and December 31, 2015,
respectively.
On
December 28, 2016, we completed the acquisition of leasehold interests and related upstream assets in Reeves County, Texas from Silverback Exploration, LLC and
Silverback Operating, LLC for a cash purchase price of approximately $855,000,000, subject to customary purchase price adjustments. The assets acquired from Silverback include 30 operated
producing horizontal wells and approximately 35,000 net acres that directly offset our existing acreage in Reeves County, Texas. We operate approximately 95% of, and have an approximate 88% working
interest in, this acreage and believe that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale formations.
The
acreage acquired in the Silverback Acquisition includes 11,694 net acres, with an allocated value of approximately $300 million, subject to the AMI. Pursuant to the AMI, one
or more of three separate counterparties may elect to acquire up to an aggregate of 80.75% of the acreage subject to the AMI by paying to us, on or before January 30, 2017, such counterparty's
share of the cost and expense of acquiring the acreage. The failure of a counterparty to make such payment on or before January 30, 2017 will be deemed to be an election not to acquire the AMI
acreage.
44
Table of Contents
Our
goal is to build a premier development and acquisition company focused on horizontal drilling in the Delaware Basin. We have assembled a multi-year inventory of horizontal drilling
projects. As of September 30, 2016, we had identified 1,388 gross horizontal drilling locations in the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and
Wolfcamp C zones across our Delaware Basin acreage based on spacing of four wells per 640-acre section in the 3rd Bone Spring Sandstone and five to six wells per 640-acre section in the
Wolfcamp zones. Our drilling inventory includes 381 extended lateral locations of either 9,500 or 7,500 lateral feet. Our near-term drilling program is focused on both the Upper and Lower Wolfcamp A
zones, but we also intend to drill locations in the 3rd Bone Spring Sandstone, Wolfcamp B and Wolfcamp C zones. Based on our and other operators' well results and our analysis of geologic and
engineering data, we believe the 2nd and 3rd Bone Spring shales and Avalon Shale may also be prospective across our acreage, and we may integrate these zones into our future drilling
program as they become further delineated. The following table provides a summary of our gross horizontal drilling locations by zone as of September 30, 2016.
Gross Identified Horizontal Drilling Locations(1)(2)
|
|
|
|
|
|
|
Total
|
|
Zones:
|
|
|
|
|
3rd Bone Spring Sandstone
|
|
|
64
|
|
Upper Wolfcamp A
|
|
|
403
|
|
Lower Wolfcamp A
|
|
|
335
|
|
Wolfcamp B
|
|
|
311
|
|
Wolfcamp C
|
|
|
275
|
|
|
|
|
|
|
Total Horizontal Locations(3)(4)
|
|
|
1,388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Our
total identified horizontal drilling locations include 48 locations associated with proved undeveloped reserves as of September 30, 2016. We have
estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area, combined with our interpretation
of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the drilling of vertical wells that have
penetrated our horizontal zones. In addition, to evaluate the prospectivity of our horizontal acreage, we have performed open-hole and mud log evaluations, core analysis and drill cuttings analysis.
See "Our Properties." The drilling locations that we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and
other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our ability to add additional proved reserves to our existing
proved reserves. See "Risk FactorsRisks Related to Our BusinessDrilling for and producing oil and natural gas are high risk activities with many uncertainties that could
adversely affect our business, financial condition or results of operations." Further, to the extent the drilling locations are associated with acreage that expires, we would lose our right to develop
the related locations. See "Risk FactorsRisks Related to Our BusinessOur identified drilling locations are scheduled out over many years, making them susceptible to
uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such
locations."
-
(2)
-
Our
horizontal drilling location count implies 880-foot spacing with five to six wells per 640-acre section in the Wolfcamp zones and 1,320-foot spacing with four
wells per
45
Table of Contents
640-acre
section in the 3rd Bone Spring Sandstone, in each case, consisting primarily of single-section (i.e., approximately 4,500-foot) laterals.
-
(3)
-
673
of our 1,388 horizontal drilling locations are on acreage that we operate. We have an approximate 84% average working interest in our operated acreage.
-
(4)
-
We
have included undeveloped horizontal locations only on our leasehold in Reeves and Ward counties.
We
believe that development drilling of our 1,388 gross horizontal locations, with an increasing focus on drilling extended lateral wells as well as potential downspacing, will allow us
to grow our production and reserves. In addition, we believe our large acreage blocks allow us to optimize our horizontal development program to maximize our resource recovery and our returns. We also
intend to grow our production and reserves through acquisitions that meet our strategic and financial objectives. Furthermore, we believe our operational efficiency is enhanced by a third-party gas
gathering system and cryogenic processing plant, which were built specifically for the area where the majority of our acreage is located, and our operated saltwater disposal system. In addition, a
third-party crude gathering system, which became operational in the third quarter of 2016 and will transport the majority of our crude oil to market at a lower cost than we have experienced
historically, will provide additional efficiencies.
We
experienced a significant decrease in our drilling and completion costs during 2015, which continued into 2016. This trend has been driven by efficiency improvements in the field,
including reduced drilling days, the modification of well designs and reduction or elimination of unnecessary costs. Additionally, overall service costs have declined as a result of reduced industry
demand. For the nine months ended September 30, 2016, the spud-to-rig release for our three single-section horizontal wells was approximately 21 days compared to 28 days and
46 days for all single-section horizontal wells we drilled in 2015 and 2014, respectively. We expect that further optimization in the field (including the increased drilling of longer laterals,
pad drilling, the use of shared facilities and zipper fracs), reduced rig rates and lower service costs will improve our well economics.
Our
2016 capital budget for drilling, completion and recompletion activities and facilities costs was approximately $92 million, excluding leasing and other acquisitions. We
allocated approximately $80 million of our 2016 capital budget for the drilling and completion of operated wells and $6 million for our participation in the drilling and completion of
non-operated wells. For 2016, we budgeted $25 million for leasing. In the nine months ended September 30, 2016, we incurred capital costs of approximately $48.9 million, excluding
leasing and acquisition costs.
Because
we operate approximately 80% of our net acreage (as of September 30, 2016), the amount and timing of our capital expenditures are largely subject to our discretion. We
believe our approximate 84% average working interest in our operated acreage provides us with flexibility to manage our drilling program and optimize our returns and profitability. We could choose to
defer a portion of our planned capital expenditures depending on a variety of factors, including the success of our drilling activities; prevailing and anticipated prices for oil, natural gas and
NGLs; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; drilling, completion and acquisition costs; and the
level of participation by other working interest owners. We have an approximate 17% working interest in our non-operated acreage.
For
the nine months ended September 30, 2016, our average net daily production was 7,982 Boe/d (approximately 69% oil, 20% natural gas and 11% NGLs). The following table provides
summary information regarding our proved reserves as of December 31, 2015, based on a reserve report prepared by Netherland, Sewell & Associates, Inc., our independent petroleum
engineer ("NSAI"). Of
46
Table of Contents
our
proved reserves, approximately 40% were classified as PDP. PUDs included in this estimate are from 52 horizontal well locations across three zones.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Total Proved Reserves
|
|
Oil
(MMBbls)
|
|
NGLs
(MMBbls)
|
|
Natural Gas
(Bcf)
|
|
Total
(MMBoe)
|
|
% Oil
|
|
% Liquids(1)
|
|
% Developed
|
|
|
23.2
|
|
|
3.9
|
|
|
32.4
|
|
|
32.5
|
|
|
71
|
|
|
83
|
|
|
40
|
|
-
(1)
-
Includes
oil and NGLs.
Based
on the reserve estimates of NSAI, the average PUD horizontal EUR as of December 31, 2015 is approximately 610 MBoe (approximately 71% oil, 12% NGLs and 17% natural gas) for
our Wolfcamp wells, which have an average lateral length of approximately 4,500 feet.
Our properties include working interests in approximately 90,800 gross (42,300 net) surface acres, substantially all of which are located in the
oil-rich core of the Southern Delaware Basin, a sub-basin of the Permian Basin, in the Texas counties of Reeves, Ward and Pecos. The following table summarizes our surface acreage by county as of
September 30, 2016.
|
|
|
|
|
|
|
|
|
|
Gross
|
|
Net
|
|
County:
|
|
|
|
|
|
|
|
Reeves
|
|
|
76,600
|
|
|
36,400
|
|
Ward
|
|
|
2,400
|
|
|
1,900
|
|
Pecos
|
|
|
11,800
|
|
|
4,000
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
90,800
|
|
|
42,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In
addition to the acreage described in the table above, we acquired approximately 35,000 net acres in Reeves County in the Silverback Acquisition.
Permian Basin.
The Permian Basin consists of mature, legacy onshore oil and liquids-rich natural gas reservoirs that span approximately
86,000 square
miles in West Texas and New Mexico. The Basin is composed of five sub regions: the Delaware Basin, the Central Basin Platform, the Midland Basin, the Northwest Shelf and the Eastern Shelf. The Permian
Basin is an attractive operating area due to its multiple horizontal and vertical target zones, favorable operating environment, high oil and liquids-rich natural gas content, mature infrastructure,
well-developed network of oilfield service providers, long-lived reserves with consistent reservoir quality and historically high drilling success rates. According to the EIA, the Permian Basin is the
most prolific oil producing area in the U.S., accounting for 23% and 20% of total U.S. crude oil production during the twelve-month periods ended April 30, 2016 and April 30, 2015,
respectively. Six key producing formations within the Permian Basin (Spraberry, Wolfcamp, Bone Spring, Glorieta, Yeso and Delaware) have provided the bulk of the Basin's 122% increase in oil
production since 2007. Approximately 62% of the increase came from the Wolfcamp, Bone Spring and Spraberry formations.
Delaware Basin.
The present structural form of the Delaware Basin, a sub-basin of the Permian Basin, began to take shape in the early
Pennsylvanian
period at which time the area slowly downwarped relative to the adjacent Central Basin Platform and Northwest Shelf. This period was characterized by relatively stable marine shale and limestone
deposition with periodic influxes of siliciclastics during sea-level lowstands. Stratigraphic records indicate a rapid deepening of the Delaware Basin during early Permian time. High total organic
carbon marine shales, carbonate debris flows and turbidite sandstones were the predominant deposits in the Delaware Basin during this period. Subsequent burial and
47
Table of Contents
thermal
maturation of this thick Permian succession of highly organic source and reservoir rock resulted in what we believe is evolving into a prolific oil field.
The
Delaware Basin encompasses an estimated 10,039 square miles and contained over 25,000 producing wells at the end of 2015, with production from certain wells dating back to 1924. Over
the past decade, horizontal drilling activity has been more prevalent within the Delaware Basin relative to other areas of the Permian Basin. According to Baker Hughes, three of the top six Permian
Basin counties by horizontal rig count are located in the Delaware Basin. Reeves County, where the majority of our acreage is located, had the second most horizontal rigs of any U.S. county in
June 17, 2016, with 21 rigs as of such date.
We
believe that our properties are prospective for oil and liquids-rich natural gas from multiple producing stratigraphic horizons, which we refer to as "stacked pay zones." For the nine
months ended September 30, 2016, our net daily production averaged 69% oil, 20% natural gas and 11% NGLs and had a greater liquids-content than other areas of the Delaware Basin.
Oil
and gas production was first established in the area of our leasehold from vertical wells in the Wolfbone interval, a blend of stacked pay zones in the Permian (Wolfcampian) Wolfcamp
and overlying (Leonardian) Bone Spring formations. Operators were initially drawn to this area for the thick pay section, superior rock quality and oil-rich production. The Barilla Draw field,
partially coincident with our leasehold, is the source of substantial petrophysical data acquired during this vertical phase of development. This data, including 17 of our wells with advanced
petrophysical logs and two of our wells with whole core, is being utilized to guide our horizontal development of the area. The vertical development has resulted in a better understanding of our
leasehold's geology relative to other parts of the Basin and has not caused significant depletion. Depth to the top of the Wolfcamp from a representative well central to our leasehold is approximately
10,600 feet. The gross thickness of the potential pay section from the top of the Bone Spring formation through the base of the Wolfcamp C is approximately 3,500 feet, an attractive thickness for
development with multiple horizontal landing zones. We believe that the combination of these conditions will allow us to achieve superior results during the development of our leasehold.
Our
horizontal drilling, including 63 operated wells as of September 30, 2016, has been widespread with locations across the majority of our leasehold. We have established
commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C, across an area
approximately 45 miles long by 20 miles wide. As a result, we have broadly appraised our acreage across various geographic areas and stratigraphic zones. Also, as of September 30,
2016, approximately 60% of our total net acreage (approximately 79% of our operated net acreage in Reeves and Ward counties) was either held by production or under continuous drilling provisions. This
has put us in a position to strategically develop our acreage with a near-term focus on high-return projects. Our previous activity, such as horizontal drilling in the Wolfcamp B and C zones, has been
a catalyst for activity from offset operators. We will closely monitor this offset activity and adjust our future development plans with information and best practices learned from our peers.
As
of September 30, 2016, we operated approximately 80% of our net acreage and had an approximate 84% average working interest in our operated acreage. This operational control
gives us flexibility in development strategy and pace. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, which suspension had no effect on our proved
undeveloped reserves as of December 31, 2015, we added one horizontal drilling rig in June 2016, a second horizontal rig in September 2016 and a third horizontal rig in October 2016. During
2016, we placed 11 horizontal wells on production. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on reducing drilling times, optimizing
completions and reducing costs without compromising worker health, safety and environmental protection. For the nine months ended
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Table of Contents
September 30,
2016, the spud-to-rig release for our three single-section horizontal wells was approximately 21 days compared to 28 days and 46 days for all single-section
horizontal wells we drilled in 2015 and 2014, respectively. We expect that further optimization in the field (including the increased drilling of longer laterals, pad drilling, the use of shared
facilities and zipper fracs), reduced rig rates and lower service costs will improve our well economics. In March 2016, we drilled and completed our first 9,500-foot lateral well, which had an initial
90-day oil production rate of approximately 900 barrels of oil per day.
Completion
design and its effective execution are the predominant factors that dictate relative well performance in an area or zone. We have an evolving completion strategy that includes
methodical adjustments of parameters, experimentation of different designs on adjacent locations with similar rock characteristics, constant monitoring and re-evaluation of results and ultimately
tailoring completions to the conditions specific to an area or zone. Our current base completion design is a slickwater fracture stimulation, targeting 160 feet stage length, approximately 6 clusters
per stage and 2,000 pounds or greater of proppant per foot of lateral length. Field-level rate of return is most influenced by incremental improvements in well performance and cost savings. Our
philosophy is to focus on both parameters, with an emphasis on performance enhancement.
Our
current drilling program is focused primarily on the Upper and Lower Wolfcamp A intervals. However, based on existing well results and our analysis of geologic and engineering data,
we believe the 3rd Bone Spring Sandstone, Wolfcamp B and Wolfcamp C intervals are prospective across our acreage and we plan to target those zones in our future drilling program. As of
September 30, 2016, our location count for the Wolfcamp is based on locations spaced approximately 880 feet from each other within a zone and staggered vertically in adjacent zones, and for the
3rd Bone Spring Sandstone, the current location count is based on locations spaced approximately 1,320 feet from each other (as illustrated in the figure below). If future downspacing pilots
are successful, we may be able to add additional locations to our multi-year inventory. In addition, we believe our acreage may be prospective for the 2nd and 3rd Bone Spring shales and
Avalon Shale, where other operators have experienced drilling success near our acreage. We also anticipate that our recently completed Silverback Acquisition will impact our existing drilling program
as we integrate these new assets.
NSAI,
our independent petroleum engineer, has estimated that as of December 31, 2015, proved reserves net to our interest in our properties were approximately 32,457 MBoe, of
which 40% were
classified as PDP. The proved reserves are generally characterized as long-lived, with predictable production profiles.
Production Status.
For the nine months ended September 30, 2016, our average net daily production was 7,982 Boe/d (approximately
69% oil, 20%
natural gas and 11% NGLs). During 2015, our average net daily production was 7,317 Boe/d (approximately 69% oil, 19% natural gas and 12%
49
Table of Contents
NGLs).
As of September 30, 2016, we produced from 77 horizontal and 70 vertical wells, in each case, operated and non-operated.
Facilities.
We strive to develop the necessary infrastructure to lower our costs and support our drilling schedule and production
growth. We
accomplish this goal primarily through contractual arrangements with third-party service providers. Our facilities located on our properties are generally in close proximity to our well locations and
include storage tank batteries, oil/gas/water separation equipment and artificial lift equipment. A crude gathering system, which became operational in the third quarter of 2016 will transport the
majority of our crude oil to market at a lower cost than we have experienced historically. For gas gathering and processing, we have infrastructure in place that spans the heart of our leasehold. The
majority of our gas is processed at a cryogenic plant that is centrally located in our area of operations. We have a long-term agreement with a third-party gas gatherer and processor and benefit from
priority producer status as the anchor tenant.
Recent and Future Activity.
During the nine months ended September 30, 2016, 8.0 gross (5.1 net) wells were placed on production
on our
acreage. All of these wells were horizontal wells. After temporarily suspending drilling activity at the end of March 2016 to preserve capital, we added one horizontal rig in June 2016, a second
horizontal rig in September 2016 and a third horizontal rig in October 2016. During the remainder of 2016, 3 operated horizontal wells were placed on production.
As
of September 30, 2016, we had identified 1,388 gross horizontal drilling locations in the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and
Wolfcamp C horizontal zones across our Delaware Basin acreage based on approximately 880-foot spacing for the Wolfcamp zones and 1,320-foot spacing for the 3rd Bone Spring Sandstone. Our
drilling inventory includes 381 horizontal extended lateral locations of either 9,500 or 7,500 feet. Gross drilling locations are defined
as locations on operated and non-operated leaseholds specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and
engineering data. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators in our area,
combined with our interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the
drilling of vertical wells that have penetrated our horizontal zones. In addition, to evaluate the prospectivity of our horizontal acreage, we have performed open-hole and mud log evaluations, core
analysis and drill cuttings analysis. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant, such as easement restrictions and state and
local regulations, are considered in determining such locations. The drilling locations for which we will actually drill wells will ultimately depend upon the availability of capital, regulatory
approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.
50
Table of Contents
Oil and Natural Gas Data
Proved Reserves
Evaluation and Review of Proved Reserves.
Our proved reserve estimates as of December 31, 2015 and 2014 were prepared by NSAI, our
independent
petroleum engineer. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set
forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI does not own an interest in any of our
properties, nor is it employed by us on a contingent basis. Copies of our independent petroleum engineer's proved reserve reports as of December 31, 2015 and December 31, 2014 are
included as Exhibit 99.2 and Exhibit 99.1, respectively, of the registration statement of which this prospectus forms a part. Our reserve report as of December 31, 2013 was
prepared internally by our in-house petroleum engineers in accordance with (i) the same methodology utilized by NSAI in preparing its reports and (ii) the rules and regulations of the
SEC.
We
maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent petroleum engineer to ensure the integrity, accuracy and
timeliness of the data used to calculate the proved reserves relating to our assets in the Permian Basin. Our internal technical team members meet with our independent petroleum engineer periodically
during the period covered by NSAI's proved reserve reports to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI for our
properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Terry Sherban, our Vice President, Reservoir Engineering,
is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Sherban is a petroleum engineer with 37 years of reservoir and operations experience, and our
geoscience staff has an average of approximately 24 years of energy industry experience.
The
preparation of our proved reserve estimates was completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve
estimations, include the following:
-
-
review and verification of historical production data, which data is based on actual production as reported by us;
-
-
review of reserve estimates by Mr. Sherban or under his direct supervision;
-
-
review by our Vice President, Development and Chief Executive Officer of all of our reported proved reserves, including the review of all
significant reserve changes and all new PUDs additions;
-
-
direct reporting responsibilities by our Vice President, Reservoir Engineering to our Chief Executive Officer; and
-
-
verification of property ownership by our land department.
Estimation of Proved Reserves.
Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of
geoscience and
engineering data, can be estimated with reasonable certainty to be economically produciblefrom a given date forward, from known reservoirs and under existing economic conditions,
operating methods and government regulationsprior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high
degree of confidence that the quantities will be recovered." All of our proved reserves as of December 31, 2015, 2014 and 2013 were estimated using a deterministic method. The
51
Table of Contents
estimation
of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results
in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable
oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production
performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the
reserve evaluator in the process of estimating the quantities of reserves. Reserves for PDP wells were estimated using production performance methods for the vast majority of properties. Certain new
producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a
reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of
accuracy for predicting proved developed non-producing ("PDNP") and PUD for our properties, due to the abundance of analog data.
To
estimate economically recoverable proved reserves and related future net cash flows, NSAI considered many factors and assumptions, including the use of reservoir parameters derived
from geological and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.
Under
SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous
reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that
have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish
reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with
consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and
historical well cost and operating expense data.
Summary of Oil and Natural Gas Reserves.
The following table presents our estimated net proved oil and natural gas reserves as of
December 31,
2015, 2014 and 2013, based on the proved reserve report as of December 31, 2015 and 2014 by NSAI, our independent petroleum engineer, and based on our internally prepared reserve report as of
December 31, 2013, in each case, prepared in accordance with the rules and regulations of the SEC. Copies of the proved reserve reports as of December 31, 2015 and December 31,
2014 prepared by NSAI with respect to our properties are included as
52
Table of Contents
Exhibit 99.2
and Exhibit 99.1, respectively, to the registration statement of which this prospectus forms a part. All of our proved reserves are located in the United States.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2015(1)
|
|
2014(2)
|
|
2013(3)
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
9,347
|
|
|
8,026
|
|
|
6,021
|
|
Natural gas (MMcf)
|
|
|
12,711
|
|
|
11,959
|
|
|
4,837
|
|
NGLs (MBbls)
|
|
|
1,603
|
|
|
766
|
|
|
382
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
13,068
|
|
|
10,786
|
|
|
7,210
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
13,852
|
|
|
11,823
|
|
|
12,489
|
|
Natural gas (MMcf)
|
|
|
19,731
|
|
|
15,455
|
|
|
2,131
|
|
NGLs (MBbls)
|
|
|
2,248
|
|
|
785
|
|
|
143
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
19,389
|
|
|
15,184
|
|
|
12,987
|
|
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
23,199
|
|
|
19,850
|
|
|
18,510
|
|
Natural gas (MMcf)
|
|
|
32,442
|
|
|
27,414
|
|
|
6,968
|
|
NGLs (MBbls)
|
|
|
3,851
|
|
|
1,551
|
|
|
525
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
32,457
|
|
|
25,970
|
|
|
20,197
|
|
Oil and Natural Gas Prices:
|
|
|
|
|
|
|
|
|
|
|
OilWTI posted price per Bbl
|
|
$
|
46.79
|
|
$
|
91.48
|
|
$
|
95.96
|
|
Natural gasHenry Hub spot price per MMBtu
|
|
$
|
2.59
|
|
$
|
4.35
|
|
$
|
3.67
|
|
-
(1)
-
Our
estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil
and NGL volumes, the average West Texas Intermediate posted price of $46.79 per barrel as of December 31, 2015 was adjusted for quality, transportation fees and a regional price differential.
For gas volumes, the average Henry Hub spot price of $2.59 per MMBtu as of December 31, 2015 was adjusted for energy content, transportation fees and a regional price differential. All prices
are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $41.85 per barrel of oil, $13.94 per
barrel of NGL and $1.71 per Mcf of gas as of December 31, 2015.
-
(2)
-
Our
estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil
and NGL volumes, the average West Texas Intermediate posted price of $91.48 per barrel as of December 31, 2014 was adjusted for quality, transportation fees and a regional price differential.
For gas volumes, the average Henry Hub spot price of $4.35 per MMBtu as of December 31, 2014 was adjusted for energy content, transportation fees and a regional price differential. All prices
are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $84.94 per barrel of oil, $22.70 per
barrel of NGL and $4.70 per Mcf of gas as of December 31, 2014.
-
(3)
-
Our
estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil
and NGL volumes, the average West Texas Intermediate posted price of $95.96 per barrel as of December 31, 2013 was adjusted for quality, transportation fees and a regional price differential.
For gas volumes, the average Henry Hub spot price of $3.67 per MMBtu as
53
Table of Contents
of
December 31, 2013 was adjusted for energy content, transportation fees and a regional price differential. All prices are held constant throughout the lives of the properties. The average
adjusted product prices weighted by production over the remaining lives of the properties are $92.05 per barrel of oil, $26.05 per barrel of NGL and $3.76 per Mcf of gas as of December 31,
2013.
The
changes from December 31, 2014 estimated proved reserves to December 31, 2015 estimated proved reserves reflect the addition of 12,864 MBoe of proved reserves through
extensions and 1,275 MBoe of acquired proved reserves, offset by net negative revisions of 4,981 MBoe primarily due to the decline in commodity prices.
The
changes from December 31, 2013 estimated proved reserves to December 31, 2014 estimated proved reserves reflect production during this period of approximately 2,015
MBoe and additions of approximately 21,012 MBoe attributable to new locations resulting from the strategic drilling of wells to delineate our acreage position and the sale of 13,706 MBoe of reserves
in the CO2 Project Disposition and the Marston Disposition.
Reserve
engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner.
The
accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In
addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are
ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual
results, including geologic interpretation, prices and future production rates and costs. Please read the section entitled "Risk FactorsRisks Related to Our Business."
Additional
information regarding our proved reserves can be found in the notes to our financial statements included elsewhere in the registration statement of which this prospectus
forms a part and the proved reserve reports as of December 31, 2015 and December 31, 2014, which are included as Exhibit 99.2 and Exhibit 99.1, respectively, to the
registration statement of which this prospectus forms a part.
PUDs
Year Ended December 31, 2015
As of December 31, 2015, our PUDs totaled 13,852 MBbls of oil, 19,731 MMcf of natural gas and 2,248 MBbls of NGLs, for a total of 19,389
MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
Changes
in PUDs that occurred during 2015 were primarily due to (i) negative revisions of 4,648 MBoe primarily related to the conversion of PUDs to unproved reserves of
approximately 6,794 MBoe due to the decline in commodity prices, partially offset by a positive revision in performance; (ii) an increase of approximately 9,605 MBoe attributable to
extensions resulting from strategic drilling of wells by us to delineate our acreage position; (iii) the conversion of approximately 1,020 MBoe attributable to PUDs into proved developed
reserves; and (iv) the acquisition of 268 MBoe of PUDs.
During
the twelve months ended December 31, 2015, we spent $17.7 million to convert PUDs to proved developed reserves.
All
of our PUD drilling locations are scheduled to be drilled within five years of their initial booking. As of December 31, 2015, none of our total proved reserves were
classified as PDNP
54
Table of Contents
Year Ended December 31, 2014
As of December 31, 2014, our PUDs totaled 11,823 MBbls of oil, 15,455 MMcf of natural gas and 785 MBbls of NGLs, for a total of 15,184
MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
Changes
in PUDs that occurred during 2014 were primarily due to (i) a decrease of approximately 10,806 MBoe related to the CO2 Project Disposition in May 2014 and 296 MBoe related
to the Marston Disposition in December 2014; (ii) additions of approximately 13,618 MBoe attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage
position; and (iii) the conversion of approximately 318 MBoe attributable to PUDs into proved developed reserves.
During
the twelve months ended December 31, 2014, we spent $10.6 million to convert PUDs to proved developed reserves.
All
of our PUD drilling locations are scheduled to be drilled within five years of their initial booking. As of December 31, 2014, 0.2% of our total proved reserves were
classified as PDNP.
Year Ended December 31, 2013
As of December 31, 2013, our PUDs totaled 12,489 MBbls of oil, 2,131 MMcf of natural gas and 143 MBbls of NGLs, for a total of 12,987
MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
Changes
in PUDs that occurred during 2013 were primarily due to (i) additions of approximately 5,430 MBoe attributable to improved recovery resulting from the application of
tertiary recovery methods utilizing CO2 injection on properties in Chaves County, New Mexico that we sold in May 2014; (ii) a decrease of approximately 6,707 MBoe related to the Wolfbone
Disposition in October 2013, the sale of our interest in 320 gross (187 net) acres in Glasscock and Midland Counties, Texas, including two wells, in June 2013, and the sale of our interest in 1,951
gross (1,617 net) acres in Midland County, Texas, including ten wells, in August 2013; (iii) additions of approximately 4,038 MBoe attributable to extensions resulting from strategic
drilling of wells by us to delineate our acreage position and (iv) the conversion of approximately 402 MBoe attributable to PUDs into proved developed reserves.
During
the twelve months ended December 31, 2013, we spent $7.5 million to convert PUDs to proved developed reserves and $144.0 million to convert non-proved
reserves to proved developed reserves.
All
of our PUD drilling locations are scheduled to be drilled within five years of their initial booking. As of December 31, 2013, 2% of our total proved reserves were classified
as PDNP.
55
Table of Contents
Oil and Natural Gas Production Prices and Costs
Production and Price History
The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for
each of the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
Ended
September 30,
|
|
Year Ended December 31,
|
|
|
|
2016
|
|
2015
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(In thousands)
|
|
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,520
|
|
|
1,329
|
|
|
1,830
|
|
|
1,428
|
|
|
713
|
|
Natural gas (MMcf)
|
|
|
2,551
|
|
|
2,205
|
|
|
3,058
|
|
|
2,112
|
|
|
797
|
|
NGLs (MBbls)
|
|
|
242
|
|
|
242
|
|
|
331
|
|
|
235
|
|
|
98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)(1)
|
|
|
2,187
|
|
|
1,939
|
|
|
2,671
|
|
|
2,015
|
|
|
944
|
|
Average realized prices before effects of hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
37.48
|
|
$
|
44.45
|
|
$
|
42.43
|
|
$
|
80.50
|
|
$
|
92.37
|
|
Natural gas (per Mcf)
|
|
|
2.24
|
|
|
2.76
|
|
|
2.60
|
|
|
4.58
|
|
|
3.79
|
|
NGLs (per Bbl)
|
|
|
12.80
|
|
|
14.83
|
|
|
14.66
|
|
|
30.64
|
|
|
31.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (per Boe)
|
|
$
|
30.08
|
|
$
|
35.45
|
|
$
|
33.87
|
|
$
|
65.42
|
|
$
|
76.24
|
|
Average realized prices after effects of hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
48.42
|
|
$
|
63.30
|
|
$
|
61.61
|
|
$
|
83.73
|
|
$
|
74.68
|
|
Natural gas (per Mcf)
|
|
|
2.24
|
|
|
3.18
|
|
|
3.04
|
|
|
4.58
|
|
|
3.79
|
|
NGLs (per Bbl)
|
|
|
12.80
|
|
|
14.83
|
|
|
14.66
|
|
|
30.64
|
|
|
31.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (per Boe)
|
|
$
|
37.68
|
|
$
|
48.85
|
|
$
|
47.51
|
|
$
|
67.71
|
|
$
|
62.84
|
|
Average costs (per Boe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
4.71
|
|
$
|
8.93
|
|
$
|
7.93
|
|
$
|
8.78
|
|
$
|
20.24
|
|
Severance and ad valorem taxes
|
|
|
1.61
|
|
|
1.98
|
|
|
1.88
|
|
|
3.41
|
|
|
4.40
|
|
Transportation, processing, gathering and other operating expenses
|
|
|
2.00
|
|
|
2.24
|
|
|
2.15
|
|
|
2.37
|
|
|
1.37
|
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
27.86
|
|
|
33.01
|
|
|
33.73
|
|
|
34.30
|
|
|
31.02
|
|
Abandonment expense and impairment of unproved properties
|
|
|
1.16
|
|
|
1.99
|
|
|
2.85
|
|
|
9.94
|
|
|
9.07
|
|
Exploration
|
|
|
|
|
|
|
|
|
0.03
|
|
|
|
|
|
|
|
Contract termination and rig stacking
|
|
|
|
|
|
1.23
|
|
|
0.89
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
|
4.87
|
|
|
4.40
|
|
|
5.32
|
|
|
15.73
|
|
|
17.84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
42.21
|
|
$
|
53.78
|
|
$
|
54.78
|
|
$
|
74.53
|
|
$
|
83.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
May
not sum or recalculate due to rounding.
Productive Wells
As of September 30, 2016, we owned an approximate 61% average working interest in 147 gross (89 net) productive wells. Our wells are oil
wells that produce associated liquids-rich natural gas. Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities. Gross wells are
the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.
56
Table of Contents
Developed and Undeveloped Acreage
The following table sets forth information as of September 30, 2016 relating to our leasehold acreage. Developed acreage consists of
acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not
been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
|
Gross(1)
|
|
Net(2)
|
|
Gross(1)
|
|
Net(2)
|
|
Gross(1)
|
|
Net(2)
|
|
|
8,200
|
|
|
6,500
|
|
|
82,600
|
|
|
35,800
|
|
|
90,800
|
|
|
42,300
|
|
-
(1)
-
A
gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
-
(2)
-
A
net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the
fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Many
of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage
has been established prior to such date, in which event the lease will remain in effect until the cessation of production. Substantially all of the leases governing our acreage have continuous
development clauses that permit us to continue to hold the acreage under such leases after the expiration of the primary term if we initiate additional development within 60 to 180 days after
the completion of the last well drilled on such lease, without the requirement of a lease extension payment. Thereafter, the lease is held with additional development every 60 to 180 days until
the entire lease is held by production. None of our horizontal drilling locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term that is not accounted
for with a continuous development schedule. The following table sets forth the gross and net undeveloped acreage, as of September 30, 2016, that will expire over the next five years unless
production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining 2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
|
5,900
|
|
|
2,700
|
|
|
8,200
|
|
|
3,800
|
|
|
15,700
|
|
|
7,300
|
|
|
6,600
|
|
|
3,100
|
|
|
|
|
|
|
|
Drilling Results
The following table sets forth the results of our drilling activity, as defined by wells having been placed on production, for the periods
indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled,
quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of
57
Table of Contents
whether
they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months
Ended September 30,
|
|
For the Year Ended December 31,
|
|
|
|
2016
|
|
2015
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Exploratory Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Exploratory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(1)
|
|
|
8.0
|
|
|
5.1
|
|
|
9.0
|
|
|
8.1
|
|
|
16.0
|
|
|
12.4
|
|
|
36.0
|
|
|
26.8
|
|
|
26.0
|
|
|
10.9
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Development
|
|
|
8.0
|
|
|
5.1
|
|
|
9.0
|
|
|
8.1
|
|
|
16.0
|
|
|
12.4
|
|
|
36.0
|
|
|
26.8
|
|
|
26.0
|
|
|
10.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(1)
|
|
|
8.0
|
|
|
5.1
|
|
|
9.0
|
|
|
8.1
|
|
|
16.0
|
|
|
12.4
|
|
|
36.0
|
|
|
26.8
|
|
|
26.0
|
|
|
10.9
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
8.0
|
|
|
5.1
|
|
|
9.0
|
|
|
8.1
|
|
|
16.0
|
|
|
12.4
|
|
|
36.0
|
|
|
26.8
|
|
|
26.0
|
|
|
10.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Although
a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well
becoming uneconomical, particularly exploratory wells where there is no production history.
Operations
General
As of September 30, 2016, we were the operator of approximately 80% of our net acreage. As operator, we design and manage the development
of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We
employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.
Marketing and Customers
We market the majority of our production from properties we operate for both our account and the account of the other working interest owners in
these properties. We sell our oil, natural gas and NGL production to purchasers at market prices. We sell all of our natural gas and NGLs under contracts with terms of greater than twelve months and
all of our oil under contracts with terms of twelve months or less.
We
normally sell production to a relatively small number of customers, as is customary in our business. For the years ended December 31, 2015, 2014 and 2013, Plains
Marketing, L.P. accounted for 64%, 78% and 72%, respectively, of our total revenue. During such years, no other purchaser accounted for 10% or more of our revenue. In the third quarter of 2016,
we started selling the majority of our oil production to Shell Trading (US) Company ("Shell") under a new marketing contract. The loss of Shell as a purchaser could materially and adversely affect our
revenues in the short-term. However, based on
the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of Shell as a purchaser would not have a material adverse effect on our
58
Table of Contents
financial
condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
Transportation
During the initial development of our fields, we consider all gathering and delivery infrastructure options in the areas of our production. With
the completion of a third-party crude gathering system in the third quarter of 2016, the majority of our oil production is currently transported by pipe at a lower cost than we have experienced
historically with trucking. Our natural gas is generally transported by our gathering lines from the wellhead to a Central Delivery Point ("CDP") and then is gathered by third-party lines from these
CDPs to a gas processing facility. At a small number of our wells, we own natural gas pipeline facilities that connect our wells to third-party natural gas gathering systems located in the vicinity of
those wells.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these
companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis.
These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market
prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would
adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable
properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a
disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
There
is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by
various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the
nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil
and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state
and local laws and regulations more easily than we can, which would adversely affect our competitive position.
Seasonality of Business
Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth
and first quarters resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on
an annual basis.
Title to Properties
As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection
with acquisition of leasehold acreage. At such time as we
59
Table of Contents
determine
to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling
operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will
not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and we
believe that we
have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.
Prior
to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we
may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other
interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.
We
believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests
generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to
environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas
industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or
materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public
authorities and private parties for us to operate our business in all material respects as described in this prospectus.
Oil and Natural Gas Leases
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil
and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties as of September 30, 2016 generally range from 20% to
25%, resulting in a net revenue interest to us generally ranging from 75% to 80%.
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related
operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties
have statutory provisions regulating the development and production of oil and natural gas, including provisions related to permits for the
drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are
drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These
include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas
wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields
and individual wells.
60
Table of Contents
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing
business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted.
Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress,
the states, FERC and the courts. We cannot predict when or whether any such proposals may become effective.
We
believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material
adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past
non-compliance with environmental laws or regulations may be discovered.
Regulation of Production of Oil and Natural Gas
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and
regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in
Texas, which regulates drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and
regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The
laws of Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of
production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural
gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well
spacing or density. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
The
failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory
requirements and restrictions that affect our operations.
Regulation of Sales and Transportation of Oil
Sales of oil, condensate and NGLs from our producing wells are not currently regulated and are made at negotiated prices. Nevertheless, Congress
could enact price controls in the future.
Our
sales of oil are affected by the availability, terms and conditions and cost of transportation services. The transportation of oil in common carrier pipelines is also subject to rate
and access regulation. FERC regulates the transportation in interstate commerce of crude oil, petroleum products, NGLs and other forms of liquid fuel under the Interstate Commerce Act.
Intrastate
oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory
oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We rely on third-party pipelines systems
to transport the majority of crude oil produced by ours wells. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers,
we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
61
Table of Contents
Changes
in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and
intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that
materially differs from the way they will affect other oil producers and marketers with which we compete.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal
government, primarily FERC. In the past, the federal government regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled
market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA, and culminated in adoption of the Natural Gas
Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is
regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may
also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.
The
EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that
affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in
prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provided FERC with the power to assess civil penalties of up to
$1,000,000 per day for violations of the NGA and increased FERC's civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. On June 29, 2016,
FERC issued an order (Order No. 826) increasing the maximum civil penalty amounts under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of
$1,193,970 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for
resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied
rehearing. The rules make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services
subject to the jurisdiction of FERC, for any entity, directly or indirectly, use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to
make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market
manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that
provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC
jurisdiction, which now includes the annual reporting requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of
FERC's NGA enforcement authority.
We
are required to observe such anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act ("CEA"), and
regulations promulgated thereunder by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such
commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to
affect the price of
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commodity. Should we violate the anti-market manipulation laws and regulations, it could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing
authorities.
On
December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order
704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now
required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or
may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704.
Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC's policy statement on price reporting.
Natural
gas gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA
exempts companies that provide natural gas gathering services from regulation by FERC as a "natural gas company" under the NGA.
Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC's determinations as to the
classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering
facilities, or vice versa, and depending on the scope of that decision, our costs of getting gas to point-of-sale locations may increase. We believe that the natural gas pipelines in our gathering
systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated
transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on
future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances,
nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the
future.
Intrastate
natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of
regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all
intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and
ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates,
the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Changes
in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and
intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that
materially differs from the way they will affect other natural gas producers and marketers with which we compete.
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Regulation of Environmental and Occupational Safety and Health Matters
Our oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations
governing occupational safety and health, the
discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These
laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be
released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit
or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of remedial action to prevent or mitigate
pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial
liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.
The
following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business
operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 ("CERCLA"), also known as the "Superfund" law, and comparable
state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for
the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which
we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in
certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may
be held responsible that would materially and adversely affect us.
The
Resource Conservation and Recovery Act ("RCRA") and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous
and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy
from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies
under RCRA's less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas development and production wastes
now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA's exemption of
certain oil and gas wastes from RCRA. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated
wastes, which could have a material adverse effect on our results of operations and financial
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position.
In addition, in the course of our operations, we may generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils
that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this
regard are materially more burdensome than those for similarly situated companies.
We
currently own, lease or operate numerous properties that have been used for oil and natural gas development and production activities for many years. Although we believe that we have
utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the
properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our
properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control.
These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or
corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent
future contamination.
Water Discharges
The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced
waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by
the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers
(the "Corps"). In September 2015, the EPA and the Corps issued new rules defining the scope of the EPA's and the Corps' jurisdiction under the Clean
Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands. To the extent the rule expands the scope of the Clean Water Act's jurisdiction, we could
face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the
reach of the Clean Water Act, and implementation of the rule has been stayed pending resolution of the court challenge. Obtaining permits has the potential to delay the development of oil and natural
gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities
and may impose substantial potential liability for the costs of removal, remediation and damages.
Pursuant
to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and
implement spill prevention, control and countermeasure plans, also referred to as "SPCC plans," in connection with on-site storage of significant quantities of oil. We believe that we maintain all
required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof. We are currently undertaking a review of recently acquired
oil properties to determine the need for new or updated SPCC plans and developing or updating such plans where necessary, the costs of which are not expected to be material.
The
primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 ("OPA"), which amends and augments the oil spill provisions of the Clean Water Act
and imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States
or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain
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facility
response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source
of an oil discharge or that poses the substantial threat of discharge is one type of "responsible party" who is liable. The OPA applies joint and several liability, without regard to fault, to each
liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our
operations.
Air Emissions
The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor
stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain
pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit
requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, we may be required to incur certain capital expenditures for air
pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard ("NAAQS") for ozone from 75 to 70 parts per
billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for
pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound
emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known
as "green completions." These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers
and storage vessels. More recently, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes
applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and
requirements. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of
development, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.
Regulation of GHG Emissions
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment,
the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required
to obtain preconstruction permits for their GHG emissions are also required to meet "best available control technology" standards that are being established by the states or, in some cases, by the EPA
on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA
has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which
include certain of our operations. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and
natural gas source category, including
production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including
hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose
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methane
emission standards for existing sources as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new
equipment such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring
additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance
costs on our operations.
While
Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG
emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG
emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In
addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most
recently, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, which requires member countries to review and "represent a progression" in their
intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The agreement was signed in April 2016, and entered into force in November
2016. The United States is one of over 70 nations having ratified or otherwise consented to be bound by the agreement. Although it is not possible at this time to predict how legislation or new
regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our
equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil
and natural gas we produce. Finally, many scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects,
such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our operations.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface
rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and
stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted
federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the
performance of such activities using diesel fuels. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of
air emissions released during hydraulic fracturing, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the
chemicals used in hydraulic fracturing, and also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment
plants. In addition, the Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands.
The U.S. District Court of Wyoming struck down this rule. The BLM has appealed this decision. The appeal remains pending. In addition, Congress has from time to time considered legislation to provide
for federal regulation of hydraulic fracturing under the SDWA and to require
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disclosure
of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.
At
the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on
hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a "well integrity rule," which updates the requirements for drilling, putting pipe down and cementing
wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is
later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek
to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow
applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal
restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements,
experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.
ESA and Migratory Birds
The Endangered Species Act ("ESA") and (in some cases) comparable state laws were established to protect endangered and threatened species.
Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species' habitat. Similar protections are offered to
migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to
exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service may designate critical
habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further
material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District
Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the
ESA by no later than completion of the agency's 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government recently issued
indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification
or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species
protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our
leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
OSHA
We are subject to the requirements of the Occupational Safety and Health Act ("OSHA") and comparable state statutes whose purpose is to protect
the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing
regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local
governmental authorities and citizens. We believe
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that
we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain
drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are
generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.
We
have not experienced any material adverse effect from compliance with environmental requirements; however, there is no assurance that this will continue. We have not incurred any
material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2016, nor do we expect to incur any such expenditures
in 2017.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development
activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will
be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our
financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.
Employees
As of January 18, 2017, we had 64 full-time employees. We hire independent contractors on an as needed basis, and have no collective
bargaining agreements with our employees. We believe that our employee relationships are satisfactory.
Legal Proceedings
We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but
management believes it is remote that pending or threatened legal matters will have a material adverse impact on our financial condition.
Due
to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers'
compensation claims and employment related disputes. In the opinion of our management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material
adverse effect on our financial condition, cash flows or results of operations.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the accompanying financial statements and
related notes of CRP included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The
forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking
statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves,
capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in "Risk
Factors" and "Cautionary Note Regarding Forward-Looking Statements," all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed
may not occur. Financial information included in this prospectus does not reflect the properties acquired in the Silverback Acquisition.
Prior Company Operations
We have no direct operations and no significant assets other than the ownership of an approximate 92% membership interest in CRP. CRP is
considered our accounting predecessor and, accordingly, the following financial results and discussion and analysis reflect the results of CRP prior to the closing of the Business Combination.
For
all periods ending on or before October 15, 2014 and for all dates on or before October 15, 2014, the historical financial results contained herein reflect the combined
results of (i) CRP and (ii) Celero Energy Company, LP, a Delaware limited partnership ("Celero"), which was formed in 2006 to focus on the development and acquisition of oil and
natural gas properties in Texas and New Mexico, primarily in the Permian Basin in West Texas. On October 15, 2014, Celero conveyed substantially all of its oil and natural gas properties and
other assets to CRP in exchange for membership interests in CRP, and as a result, subsequent to October 15, 2014, the historical financial results contained herein reflect the results of CRP.
Except as the context otherwise requires, references in the following discussion to the "Company," "we," "our" or "us" with respect to periods prior to the closing of the Business Combination are to
CRP and its operations prior to the closing of the Business Combination.
Overview
We are an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich
natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. Our horizontal wells span an area approximately 45 miles long by 20
miles wide where we have established commercial production in five distinct zones: the 3rd Bone Spring Sandstone, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C.
On December 28, 2016, we completed the acquisition of leasehold interests and related upstream assets in Reeves County, Texas from
Silverback Exploration, LLC and Silverback Operating, LLC for a cash purchase price of approximately $855,000,000, subject to customary purchase price adjustments. The assets acquired
from Silverback include 30 operated producing horizontal wells
and approximately 35,000 net acres that directly offset our existing acreage in Reeves County, Texas. We operate approximately 95% of, and have an approximate 88% working interest in, this acreage and
believe that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale formations.
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The
acreage acquired in the Silverback Acquisition includes 11,694 net acres, with an allocated value of approximately $300 million, subject to the AMI. Pursuant to the AMI, one
or more of three separate counterparties may elect to acquire up to an aggregate of 80.75% of the acreage subject to the AMI by paying to us, on or before January 30, 2017, such counterparty's
share of the cost and expense of acquiring the acreage. The failure of a counterparty to make such payment on or before January 30, 2017 will be deemed to be an election not to acquire the AMI
acreage. As of the date of this prospectus, we have not received notice that any party intends to exercise its rights under the AMI.
The oil and gas industry is cyclical and commodity prices are highly volatile. In the second half of 2014, oil prices began a rapid and
significant decline as the global oil supply began to outpace demand. During 2015 and 2016, the global oil supply has continued to outpace demand, resulting in a sustained decline in realized prices
for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases
by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand
in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at
historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices are expected to remain under pressure. In addition, the lifting of economic
sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally correlate to the price of oil. Also adversely affecting the
price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting projects that produce NGLs in recent years. Prices for
domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and 2016. The declines in natural gas prices are primarily due to an imbalance
between supply and demand across North America. The duration and magnitude of the commodity price declines cannot be accurately predicted.
Our
revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production, as well as NGLs that are extracted from our natural gas
during processing. Compared to 2014, our realized oil price for 2015 fell 47.3% to $42.43 per barrel, and our realized oil price for the nine months ended September 30, 2016 has further
decreased to $37.48 per barrel. Similarly, our realized natural gas price for 2015 dropped 43.2% to $2.60 per Mcf and our realized price for NGLs declined 52.2% to $14.66 per barrel compared to 2014.
For the nine months ended September 30, 2016, our realized price for natural gas was $2.24 per Mcf and our realized price for NGLs was $12.80 per barrel. Lower oil, natural gas and NGL prices
not only may decrease our revenues, but also may reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore potentially lower our oil, natural gas and NGL reserves.
Lower commodity prices in the future could result in impairments of our properties and may materially and adversely affect our future business, financial condition, results of operations, operating
cash flows, liquidity or ability to finance planned capital expenditures. Lower oil, natural gas and NGL prices may also reduce the borrowing base under CRP's credit agreement, which is determined at
the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher oil and natural gas prices may result in
significant non-cash fair value losses being incurred on our derivatives, which could cause us to experience net losses when oil and natural gas prices rise.
In
addition, other governmental actions, including initiatives by OPEC, may continue to impact oil prices. Decisions by OPEC to reduce production or increased domestic oil and natural
gas production in a changing regulatory environment could impact the price of oil.
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We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations,
including:
-
-
realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts on our oil production;
-
-
production results;
-
-
lease operating expenses; and
-
-
Adjusted EBITDAX.
See
"Sources of Our Revenues," "Production Results," "Operating Costs and Expenses" and "Adjusted EBITDAX" below for a discussion of
these metrics.
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural
gas during processing. Oil sales contributed 87% of our total revenues for the nine months ended September 30, 2016. Natural gas sales contributed 8% and NGL sales contributed 5% of our total
revenues for the nine months ended September 30, 2016. Our oil, natural gas and NGL revenues do not include the effects of derivatives.
Increases
or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Oil, natural gas and NGL prices are market
driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality and geopolitical and economic factors. See
"Market Conditions" for information regarding the current commodity price environment. A $1.00 per barrel change in our realized oil price would have resulted in a $1.5 million
change in oil revenues for the nine months ended September 30, 2016. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.3 million change in our gas
revenues for the nine months ended September 30, 2016. A $1.00 per barrel change in our realized NGL price would have changed revenue by $0.2 million for the nine months ended
September 30, 2016.
The
following table presents our average realized commodity prices, as well as the effects of derivative settlements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
Ended
September 30,
|
|
Year Ended December 31,
|
|
|
|
2016
|
|
2015
|
|
2015
|
|
2014
|
|
2013
|
|
Crude Oil (per Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX price
|
|
$
|
41.53
|
|
$
|
51.02
|
|
$
|
48.76
|
|
$
|
92.91
|
|
$
|
97.98
|
|
Average realized price, before the effects of derivative settlements
|
|
|
37.48
|
|
|
44.45
|
|
|
42.43
|
|
|
80.50
|
|
|
92.37
|
|
Effects of derivative settlements
|
|
|
10.94
|
|
|
18.85
|
|
|
19.18
|
|
|
3.23
|
|
|
(17.74
|
)
|
Natural Gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX price (per MMBtu)
|
|
$
|
2.35
|
|
$
|
2.76
|
|
$
|
2.63
|
|
$
|
4.26
|
|
$
|
3.73
|
|
Average realized price, before the effects of derivative settlements (per Mcf)
|
|
|
2.24
|
|
|
2.76
|
|
|
2.60
|
|
|
4.58
|
|
|
3.79
|
|
Effects of derivative settlements (per Mcf)
|
|
|
|
|
|
0.42
|
|
|
0.43
|
|
|
|
|
|
|
|
NGLs (per Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price
|
|
$
|
12.80
|
|
$
|
14.83
|
|
$
|
14.66
|
|
$
|
30.64
|
|
$
|
31.50
|
|
72
Table of Contents
While
quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location
and transportation differentials for these products.
See
"Results of Operations" below for an analysis of the impact changes in realized prices had on our revenues.
The following table presents historical production volumes for our properties for the nine months ended September 30, 2016 and 2015 and
the years ended December 31, 2015, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
Ended
September 30,
|
|
Year Ended December 31,
|
|
|
|
2016
|
|
2015
|
|
2015
|
|
2014
|
|
2013
|
|
Oil (MBbls)
|
|
|
1,520
|
|
|
1,329
|
|
|
1,830
|
|
|
1,428
|
|
|
713
|
|
Natural gas (MMcf)
|
|
|
2,551
|
|
|
2,205
|
|
|
3,058
|
|
|
2,112
|
|
|
797
|
|
NGLs (MBbls)
|
|
|
242
|
|
|
242
|
|
|
331
|
|
|
235
|
|
|
98
|
|
Total (MBoe)(1)
|
|
|
2,187
|
|
|
1,939
|
|
|
2,671
|
|
|
2,015
|
|
|
944
|
|
Average net daily production (Boe/d)(1)
|
|
|
7,982
|
|
|
7,101
|
|
|
7,317
|
|
|
5,521
|
|
|
2,586
|
|
-
(1)
-
May
not sum or recalculate due to rounding.
As
reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add proved
reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through drilling as well as acquisitions. Our ability to add reserves through development projects
and acquisitions is dependent on many factors, including our ability to borrow or raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and
consummate acquisitions. Please read "Risk FactorsRisks Related to Our Business" for a discussion of these and other risks affecting our proved reserves and production.
Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in
the future. Due to this volatility, we have historically used commodity derivative instruments, such as collars, swaps and basis swaps, to hedge price risk associated with a portion of our anticipated
production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and
provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices
and may partially limit our potential gains from future increases in prices. See "Quantitative and Qualitative Disclosure About Market RiskCommodity Price Risk" for
information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.
We
expect to continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our
discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our production. CRP's credit agreement allows us to hedge up
to 80% of our reasonably anticipated production from proved reserves for up to 24 months in the future and up to 65% of our reasonably anticipated production from proved reserves for 25 to
60 months in the future, provided that no hedges may have a tenor beyond five years.
73
Table of Contents
Costs associated with producing oil, natural gas and NGLs are substantial. Some of these costs vary with commodity prices, some trend with the
type and volume of production, and others are a function of the number of wells we own. As of September 30, 2016 and December 31, 2015, we owned interests in 147 and 138 gross wells,
respectively.
Lease Operating Expenses.
Lease operating expenses ("LOE") are the costs incurred in the operation of producing properties and workover
costs.
Expenses for utilities, direct labor, water injection and disposal, materials and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor and materials and
supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping
equipment or surface facilities result in increased LOE in periods during which they are performed. Certain of our operating cost components are variable and increase or decrease as the level of
produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production-related activities, such as pumping to recover oil and natural gas and
separation and treatment of water produced in connection with our oil and natural gas production.
We
monitor our operations to ensure that we are incurring LOE at an acceptable level. For example, we monitor our LOE per Boe to determine if any wells or properties should be shut in,
recompleted or sold. This unit rate also allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers. Although we strive to
reduce our LOE, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate
our properties or make acquisitions and dispositions of properties. For example, we may increase field level expenditures to optimize our operations, incurring higher expenses in one quarter relative
to another, or we may acquire or dispose of properties that have different LOE per Boe. These initiatives would influence our overall operating cost and could cause fluctuations when comparing LOE on
a period to period basis.
Severance and Ad Valorem Taxes.
Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from
production sold at
fixed rates established by federal, state or local taxing authorities. In general, the severance taxes we pay correlate to the changes in oil, natural gas and NGLs revenues. We are also subject to ad
valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas
prices.
Transportation, Processing, Gathering and Other Operating Expenses.
Transportation, processing, gathering and other operating expenses
principally
consist of expenditures to prepare and transport production from the wellhead to a specified sales point and gas processing costs. These costs will fluctuate with increases or decreases in production
volumes, contractual fees and changes in fuel and compression costs.
Depreciation, Depletion, Amortization, and Accretion of Asset Retirement Obligations.
Depreciation, depletion, amortization, and
accretion of asset
retirement obligations ("DD&A") is the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. We use the successful efforts method of accounting
for oil and natural gas activities and, as such, we capitalize all costs associated with our development and acquisition efforts and all successful exploration efforts, which are then allocated to
each unit of production using the unit of production method. Please read "Critical Accounting Policies and EstimatesSuccessful Efforts Method of Accounting for Oil and
Natural Gas Activities" for further discussion.
Impairment Expense.
We review our proved properties and unproved leasehold costs for impairment whenever events and changes in
circumstances indicate
that a decline in the recoverability
74
Table of Contents
of
their carrying value may have occurred. Please read "Critical Accounting Policies and EstimatesImpairment of Oil and Natural Gas Properties" for further discussion.
General and Administrative Expenses.
General and administrative ("G&A") expenses are costs incurred for overhead, including payroll
and benefits for
our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other fees for professional services and legal compliance.
Derivative Gain (Loss).
Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair
value. We have
not elected to apply cash flow hedge accounting, and consequently, recognize gains and losses in earnings rather than deferring such amounts in other comprehensive income as allowed under cash flow
hedge accounting. Fair value gains or losses, as well as cash receipts or payments on settled derivative contracts, are recognized in our results of operations. Cash flows from derivatives are
reported as cash flows from operating activities.
Interest Expense.
A portion of our working capital requirements and capital expenditures are financed with borrowings under CRP's
revolving credit
facility and term loan. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under CRP's
revolving credit facility and term loan in interest expense.
We define Adjusted EBITDAX as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization and accretion of
asset retirement obligations, abandonment expense and impairment of unproved properties, (gains) losses on derivatives excluding net cash receipts (payments) on settled derivatives, noncash incentive
compensation expense (gains) losses on sale of oil and natural gas properties and other non-cash and non-recurring operating items.
Our
management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to
period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from
company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be
considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from
Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of
depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. For further
discussion, please read "Selected Historical Financial InformationNon-GAAP Financial Measure."
Factors Affecting the Comparability of Our Future Financial Data Attributable to CRP to the Historical
Financial Results of CRP's Operations
Our future results of operations attributable to CRP may not be comparable to the historical results of operations of CRP for the periods
presented due to the following reasons:
Marston Disposition.
In December 2014, CRP conveyed approximately 1,845 net acres in Ward County, Texas, including 18 wells that
produced 122 net
Boe/d for the year ended December 31, 2014, for cash proceeds of approximately $12.5 million (the "Marston Disposition"). The Marston Disposition was accounted for as a transaction
between entities under common control.
75
Table of Contents
CO2 Project Disposition.
In May 2014, CRP conveyed certain oil and natural gas properties in Chaves County, New Mexico pursuant to
which it had
pursued a tertiary recovery project utilizing CO2 to increase production on such properties, including wells that produced 378 net Boe/d in the first half of 2014, for net cash proceeds of
approximately $59.3 million (the "CO2 Project Disposition").
Wolfbone Disposition.
In October 2013, CRP conveyed approximately 1,000 net acres in the Delaware Basin, including 187 non-operated
wells that
produced approximately 200 net Boe/d in the first half of 2013, for net cash proceeds of approximately $28.7 million (the "Wolfbone Disposition").
Income Taxes.
We are a C-corp under the Code and, as a result, are subject to U.S. federal, state and local income taxes. Although CRP
is subject to
franchise tax in the State of Texas (at less than 1% of modified pre-tax earnings), as a partnership, it generally passes through its taxable income to its owners for other income tax purposes and is
not subject to U.S. federal income taxes or other state or local income taxes. Accordingly, the historical financial data attributable to CRP contains no provision for U.S. federal income taxes or
income taxes in any state or locality other than franchise tax in the State of Texas. Following the closing of the Business Combination and going forward, the financial data attributable to CRP may be
affected because we are subject to additional tax as a C-Corp. We estimate that we will be subject to U.S. federal, state and local taxes at a blended statutory rate of 36% of pre-tax earnings
allocable to us. Subject to certain restrictions, CRP generally will be required to make pro rata distributions to its members, including us, in an amount at least sufficient to allow us to pay our
taxes. Such distributions will reduce the cash available to be used in CRP's business.
Public Company Expenses.
We incur direct, incremental G&A expense as a result of being a publicly traded company, including, but not
limited to,
costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, tax return
preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director
compensation. These direct, incremental G&A expenses are not included in CRP's historical financial results of operations.
76
Table of Contents
Results of Operations
Nine Months Ended September 30, 2016 Compared to September 30, 2015
Oil, Natural Gas and NGL Sales Revenues.
The following table provides the components of our revenues for the periods indicated, as well
as each
period's average prices and production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
|
|
% Change
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
56,975
|
|
$
|
59,068
|
|
$
|
(2,093
|
)
|
|
(4
|
)%
|
Natural gas sales
|
|
|
5,717
|
|
|
6,082
|
|
|
(365
|
)
|
|
(6
|
)%
|
NGL sales
|
|
|
3,097
|
|
|
3,590
|
|
|
(493
|
)
|
|
(14
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
65,789
|
|
$
|
68,740
|
|
$
|
(2,951
|
)
|
|
(4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
37.48
|
|
$
|
44.45
|
|
$
|
(6.97
|
)
|
|
(16
|
)%
|
Natural gas (per Mcf)
|
|
|
2.24
|
|
|
2.76
|
|
|
(0.52
|
)
|
|
(19
|
)%
|
NGL (per Bbl)
|
|
|
12.80
|
|
|
14.83
|
|
|
(2.03
|
)
|
|
(14
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (per Boe)
|
|
$
|
30.08
|
|
$
|
35.45
|
|
$
|
(5.37
|
)
|
|
(15
|
)%
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,520
|
|
|
1,329
|
|
|
191
|
|
|
14
|
%
|
Natural gas (MMcf)
|
|
|
2,551
|
|
|
2,205
|
|
|
346
|
|
|
16
|
%
|
NGLs (MBbls)
|
|
|
242
|
|
|
242
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)(2)
|
|
|
2,187
|
|
|
1,939
|
|
|
248
|
|
|
13
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volume:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls/d)
|
|
|
5,547
|
|
|
4,868
|
|
|
679
|
|
|
14
|
%
|
Natural gas (Mcf/d)
|
|
|
9,310
|
|
|
8,077
|
|
|
1,233
|
|
|
15
|
%
|
NGLs (Bbls/d)
|
|
|
883
|
|
|
886
|
|
|
(3
|
)
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Boe/d)(2)
|
|
|
7,982
|
|
|
7,101
|
|
|
881
|
|
|
12
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Average
prices shown in the table reflect prices before the effects of our realized commodity derivative transactions.
-
(2)
-
Total
may not sum or recalculate due to rounding.
As
reflected in the table above, our total revenues for the first nine months of 2016 were 4%, or $3.0 million, lower than total revenues for the first nine months of 2015. The
decrease was primarily due to a decrease in commodity prices, resulting in a 15% decrease in average sales price per Boe, which was partially offset by a 13% increase in production sold in the first
nine months of 2016 compared to the prior year.
Oil
sales decreased 4%, or $2.1 million, for the first nine months of 2016 compared to the prior year period primarily due to a 16% decrease in the average sales price for oil,
partially offset by a 14% increase in oil volumes sold. Natural gas sales decreased 6%, or $0.4 million, for the first nine months of 2016 compared to the prior year period primarily due to a
19% decrease in the average sales price for natural gas, partially offset by a 16% increase in natural gas volumes sold. NGL sales decreased 14%, or $0.5 million, for the first nine months of
2016 compared to the prior year period primarily due to a 14% decrease in the average sales price for NGLs.
77
Table of Contents
Operating Expenses.
We present per Boe information because we use this information to evaluate our performance relative to our peers and
to identify
and measure trends we believe may require additional analysis.
The
following table summarizes our operating expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
|
|
% Change
|
|
Operating Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
10,295
|
|
$
|
17,317
|
|
$
|
(7,022
|
)
|
|
(41
|
)%
|
Severance and ad valorem taxes
|
|
|
3,523
|
|
|
3,833
|
|
|
(310
|
)
|
|
(8
|
)%
|
Transportation, processing, gathering and other operating expense
|
|
|
4,375
|
|
|
4,352
|
|
|
23
|
|
|
1
|
%
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
60,939
|
|
|
64,003
|
|
|
(3,064
|
)
|
|
(5
|
)%
|
Abandonment expense and impairment of unproved properties
|
|
|
2,546
|
|
|
3,851
|
|
|
(1,305
|
)
|
|
(34
|
)%
|
Contract termination and rig stacking
|
|
|
|
|
|
2,388
|
|
|
(2,388
|
)
|
|
(100
|
)%
|
General and administrative expenses
|
|
|
10,655
|
|
|
8,538
|
|
|
2,117
|
|
|
25
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses before gain on oil and natural gas properties
|
|
|
92,333
|
|
|
104,282
|
|
|
(11,949
|
)
|
|
(11
|
)%
|
Gain on sale of oil and natural gas properties
|
|
|
(11
|
)
|
|
(2,688
|
)
|
|
2,677
|
|
|
(100
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses after gain on oil and natural gas properties
|
|
$
|
92,322
|
|
$
|
101,594
|
|
$
|
(9,272
|
)
|
|
(9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
4.71
|
|
$
|
8.93
|
|
$
|
(4.22
|
)
|
|
(47
|
)%
|
Severance and ad valorem taxes
|
|
|
1.61
|
|
|
1.98
|
|
|
(0.37
|
)
|
|
(19
|
)%
|
Transportation, processing, gathering and other operating expense
|
|
|
2.00
|
|
|
2.24
|
|
|
(0.24
|
)
|
|
(11
|
)%
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
27.86
|
|
|
33.01
|
|
|
(5.15
|
)
|
|
(16
|
)%
|
Abandonment expense and impairment of unproved properties
|
|
|
1.16
|
|
|
1.99
|
|
|
(0.83
|
)
|
|
(42
|
)%
|
Contract termination and rig stacking
|
|
|
|
|
|
1.23
|
|
|
(1.23
|
)
|
|
(100
|
)%
|
General and administrative expenses
|
|
|
4.87
|
|
|
4.40
|
|
|
0.47
|
|
|
11
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses per Boe
|
|
$
|
42.21
|
|
$
|
53.78
|
|
$
|
(11.57
|
)
|
|
(22
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease Operating Expenses.
We experience volatility in our LOE as a result of the impact industry activity has on service provider costs
and
seasonality in workover expense. LOE decreased 41%, or $7.0 million, in the first nine months of 2016 compared to the first nine months of 2015, due in part to service providers lowering costs
in light of the weak commodity price environment. Additionally, we shut in several non-economic wells at the beginning of 2016, which decreased LOE approximately $1.0 million. Workover expense
decreased $2.1 million and we converted several rental units to permanent pumping units decreasing the amounts of rental expense by approximately $1.0 million in the first nine months of
2016 compared to the prior year period. Lastly, we decreased the use of contract labor and expenses related to repairs and maintenance by $1.3 million and $1.6 million, respectively, in
the first nine months of 2016 compared to the first nine months of 2015.
78
Table of Contents
Severance and Ad Valorem Taxes.
Severance taxes are primarily based on the market value of our production at the wellhead and ad
valorem taxes are
generally based on the valuation of our oil and natural gas properties and vary across the different counties in which we operate. Severance and ad valorem taxes decreased 8%, or $0.3 million,
in the first nine months of 2016 compared to the first nine months of 2015, primarily due to lower production revenues, which were primarily a result of lower realized commodity prices. Severance and
ad valorem taxes as a percentage of our revenue were 5.4% for the first nine months of 2016 compared to 5.6% for the prior year period.
Transportation, Processing, Gathering and Other Operating Expenses.
Transportation, processing, gathering and other operating expenses
were
relatively flat in the first nine months of 2016 compared to the first nine months of 2015.
Depreciation, Depletion, Amortization and Accretion of Asset Retirement Obligations.
Our DD&A rate can fluctuate as a result of
impairments,
dispositions, finding and development costs and proved reserve volumes. DD&A decreased 5%, or $3.1 million, in the first nine months of 2016 compared to the first nine months of 2015, primarily
due to a decrease in the DD&A rate, partially offset by an increase in average production volumes. The decrease in the DD&A rate was primarily due to lower drilling costs, in conjunction with lower
LOE that extends the economic lives of our wells. DD&A per Boe was $27.86 for the first nine months of 2016 compared to $33.01 for the prior year period.
Abandonment Expense and Impairment of Unproved Properties.
In the nine months ended September 30, 2016 and 2015, we recorded
$2.5 million and $3.9 million, respectively, of abandonment expense attributable to leases that expired during the period or that we expect to expire in the future.
Contract Termination and Rig Stacking.
In the first nine months of 2016, we did not incur any drilling and rig termination fees, as
compared to
$2.4 million in the first nine months of 2015. In light of the low commodity price environment, we curtailed drilling activity beginning in the first quarter of 2015, and as a result, incurred
drilling and rig termination fees of $2.4 million in the first nine months of 2015.
General and Administrative Expenses.
G&A expenses increased 25%, or $2.1 million, primarily due to an increase in transaction
costs and
miscellaneous expenses of $1.1 million each in the first nine months of 2016 compared to the first nine months of 2015. G&A per Boe was $4.87 for the first nine months of 2016 compared to $4.40
for the prior year period. The increase in G&A per Boe was primarily due to an increase in expenses, partially offset by an increase in production during the first nine months of 2016 compared to the
first nine months of 2015.
Gain on Sale of Oil and Natural Gas Properties.
In the first nine months of 2016, we recorded an immaterial net gain on the sale of oil
and natural
gas properties as compared to a net gain of $2.7 million in the prior year period, which was primarily attributable to a gain associated with the sale of non-core unproved property to an
unrelated third party.
79
Table of Contents
Other Income and Expenses.
The following table summarizes our other income and expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Change
|
|
% Change
|
|
Other (expense) income (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
(5,422
|
)
|
$
|
(4,743
|
)
|
$
|
(679
|
)
|
|
14
|
%
|
Gain (loss) on derivative instruments
|
|
|
(4,184
|
)
|
|
12,320
|
|
|
(16,504
|
)
|
|
(134
|
)%
|
Other (expense) income
|
|
|
6
|
|
|
(5
|
)
|
|
11
|
|
|
(220
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other (expense) income
|
|
$
|
(9,600
|
)
|
$
|
7,572
|
|
$
|
(17,172
|
)
|
|
(227
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax (expense) benefit
|
|
$
|
406
|
|
$
|
|
|
$
|
406
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense.
Interest expense increased 14%, or $0.7 million, primarily due to an increase in the average borrowings under
CRP's
revolving credit facility during the first nine months of 2016 compared to the first nine months of 2015.
Gain on Derivative Instruments.
In the first nine months of 2016, we recognized a $4.2 million derivative loss as compared to a
$12.3 million derivative gain in the first nine months of 2015. Net losses and gains on its derivatives are a function of fluctuations in the underlying commodity prices and the monthly
settlement of the instruments.
80
Table of Contents
Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014
Oil and Natural Gas Revenues.
The following table provides the components of our revenues for the years indicated, as well as each
year's respective
average prices and production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
|
|
|
|
2015
|
|
2014
|
|
Change
|
|
% Change
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
77,643
|
|
$
|
114,955
|
|
$
|
(37,312
|
)
|
|
(32
|
)%
|
Natural gas sales
|
|
|
7,965
|
|
|
9,670
|
|
|
(1,705
|
)
|
|
(18
|
)%
|
NGL sales
|
|
|
4,852
|
|
|
7,200
|
|
|
(2,348
|
)
|
|
(33
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
90,460
|
|
$
|
131,825
|
|
$
|
(41,365
|
)
|
|
(31
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
42.43
|
|
$
|
80.50
|
|
$
|
(38.07
|
)
|
|
(47
|
)%
|
Natural gas (per Mcf)
|
|
|
2.60
|
|
|
4.58
|
|
|
(1.98
|
)
|
|
(43
|
)%
|
NGLs (per Bbl)
|
|
|
14.66
|
|
|
30.64
|
|
|
(15.98
|
)
|
|
(52
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (per Boe)
|
|
$
|
33.87
|
|
$
|
65.42
|
|
$
|
(31.55
|
)
|
|
(48
|
)%
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,830
|
|
|
1,428
|
|
|
402
|
|
|
28
|
%
|
Natural gas (MMcf)
|
|
|
3,058
|
|
|
2,112
|
|
|
946
|
|
|
45
|
%
|
NGLs (MBbls)
|
|
|
331
|
|
|
235
|
|
|
96
|
|
|
41
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)(2)
|
|
|
2,671
|
|
|
2,015
|
|
|
656
|
|
|
33
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls/d)
|
|
|
5,014
|
|
|
3,912
|
|
|
1,102
|
|
|
28
|
%
|
Natural gas (Mcf/d)
|
|
|
8,378
|
|
|
5,786
|
|
|
2,592
|
|
|
45
|
%
|
NGLs (Bbls/d)
|
|
|
907
|
|
|
644
|
|
|
263
|
|
|
41
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Boe/d)(2)
|
|
|
7,317
|
|
|
5,521
|
|
|
1,796
|
|
|
33
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Average
prices shown in the table reflect prices before the effects of CRP's realized commodity derivative transactions.
-
(2)
-
Totals
may not sum or recalculate due to rounding.
As
reflected in the table above, our total revenues for 2015 was 31%, or $41.4 million, lower than in 2014. The decrease was primarily due to a significant decrease in commodity
prices, resulting in a 48% decrease in the average sales price per Boe. The decrease was offset in part by a 33% increase in average daily production sold in 2015 compared to 2014. The increase in
average daily production in 2015 was negatively impacted by property divestitures that occurred in 2014. In 2014, average daily production attributable to the property dispositions approximated 310
Boe/d.
Oil
sales decreased 32%, or $37.3 million, primarily as result of a 47% decrease in average sales price for oil, offset by a 28% increase in oil volumes sold. Natural gas sales
decreased 18%, or $1.7 million, primarily as a result of 43% decrease in the average sales price for natural gas, offset by a 45% increase in natural gas volumes sold. NGL sales decreased 33%,
or $2.3 million, primarily as a result of a 52% decrease in the average price for NGLs, offset by a 41% increase in NGL volumes sold.
81
Table of Contents
Operating Expenses.
The following table summarizes our expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
|
|
|
|
2015
|
|
2014
|
|
Change
|
|
% Change
|
|
Operating expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
21,173
|
|
$
|
17,690
|
|
$
|
3,483
|
|
|
20
|
%
|
Severance and ad valorem taxes
|
|
|
5,021
|
|
|
6,875
|
|
|
(1,854
|
)
|
|
(27
|
)%
|
Transportation, processing, gathering and other operating expenses
|
|
|
5,732
|
|
|
4,772
|
|
|
960
|
|
|
20
|
%
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
90,084
|
|
|
69,110
|
|
|
20,974
|
|
|
30
|
%
|
Abandonment expense and impairment of unproved properties
|
|
|
7,619
|
|
|
20,025
|
|
|
(12,406
|
)
|
|
(62
|
)%
|
Exploration
|
|
|
84
|
|
|
|
|
|
84
|
|
|
100
|
%
|
Contract termination and rig stacking
|
|
|
2,387
|
|
|
|
|
|
2,387
|
|
|
100
|
%
|
General and administrative expenses
|
|
|
14,206
|
|
|
31,694
|
|
|
(17,488
|
)
|
|
(55
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
$
|
146,306
|
|
$
|
150,166
|
|
$
|
(3,860
|
)
|
|
(3
|
)%
|
(Gain) loss on sale of oil and natural gas properties
|
|
|
(2,439
|
)
|
|
2,096
|
|
|
NM
|
|
|
NM
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses after (gain) loss on sale of oil and natural gas properties
|
|
$
|
143,867
|
|
$
|
152,262
|
|
$
|
(8,395
|
)
|
|
(6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average unit costs per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
7.93
|
|
$
|
8.78
|
|
$
|
(0.85
|
)
|
|
(10
|
)%
|
Severance and ad valorem taxes
|
|
|
1.88
|
|
|
3.41
|
|
|
(1.53
|
)
|
|
(45
|
)%
|
Transportation, processing, gathering and other operating expenses
|
|
|
2.15
|
|
|
2.37
|
|
|
(0.22
|
)
|
|
(9
|
)%
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
33.73
|
|
|
34.30
|
|
|
(0.57
|
)
|
|
(2
|
)%
|
Abandonment expense and impairment of unproved properties
|
|
|
2.85
|
|
|
9.94
|
|
|
(7.09
|
)
|
|
(71
|
)%
|
Exploration
|
|
|
0.03
|
|
|
|
|
|
0.03
|
|
|
100
|
%
|
Contract termination and rig stacking
|
|
|
0.89
|
|
|
|
|
|
0.89
|
|
|
100
|
%
|
General and administrative expenses
|
|
|
5.32
|
|
|
15.73
|
|
|
(10.41
|
)
|
|
(66
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses per Boe
|
|
$
|
54.78
|
|
$
|
74.53
|
|
$
|
(19.75
|
)
|
|
(26
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease Operating Expenses.
We experience volatility in our LOE as a result of the impact industry activity has on service provider costs
and
seasonality in workover expense. LOE increased 20%, or $3.5 million, in 2015 as compared to 2014, as we continued to put new wells on production, resulting in increased needs for compression,
rental equipment, fuel, saltwater disposal and chemicals. We also had a year-over-year increase in workover expense.
Severance and Ad Valorem Taxes.
Severance taxes are primarily based on the market value of our production at the wellhead and ad valorem
taxes are
generally based on the valuation of our oil and natural gas properties and vary across the different counties in which we operate. Severance and ad valorem taxes decreased 27%, primarily due to lower
production revenues primarily as a result of lower realized commodity prices. Severance and ad valorem taxes as a percentage of our revenue was 5.6% for 2015 compared to 5.2% for 2014.
Transportation, Processing, Gathering and Other Operating Expenses.
Transportation, processing, gathering and other operating expenses
increased 20%,
or $1.0 million. In 2015, lower prices for
82
Table of Contents
natural
gas and NGLs resulted in lower costs associated with fuel and processing fees, which were partially offset by higher processing volumes.
Depreciation, Depletion, Amortization and Accretion of Asset Retirement Obligations.
Our DD&A rate can fluctuate as a result of
impairments,
dispositions, finding and development costs and proved reserve volumes. DD&A expense increased 30%, or $21.0 million, primarily due to an increase in production volumes. DD&A per Boe was $33.73
for 2015, a slight decrease as compared to $34.30 in 2014.
Abandonment Expense and Impairment of Unproved Properties.
In 2015, we recorded $7.6 million attributable to leases that expired
during the
year or were expected to expire in the future. In 2014, we recorded impairment expense of $20.0 million, of which $13.8 million was attributable to an impairment of unproved properties
and $6.2 million was attributable to leases that expired during the year or were expected to expire in the future.
Contract Termination and Rig Stacking.
In light of the low commodity price environment, we curtailed drilling activity in 2015. As a
result, we
incurred drilling and rig termination fees of $2.4 million in 2015 as compared to no drilling and rig termination fees in 2014.
General and Administrative Expenses.
G&A expenses decreased 55%, or $17.5 million, primarily due to $12.4 million of
incentive
compensation recorded in 2014 due to the achievement of certain performance criteria associated with CRP's incentive units. Additionally, the decrease is the result of no longer having two distinct
management teams and employees associated with each of CRP and Celero along with our growing capital program and oil production levels.
Gain (Loss) on Sale of Oil and Natural Gas Properties.
In 2015, we recorded a net gain of $2.4 million, primarily attributable to
the sale of
non-core unproved property to an unrelated third party. In 2014, we recorded a net loss of $2.1 million, primarily attributable to the CO2 Project Disposition.
Other Income and Expenses.
The following table summarizes our other income and expenses for the years indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
|
|
|
|
2015
|
|
2014
|
|
Change
|
|
% Change
|
|
Other income (expense) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
(6,266
|
)
|
$
|
(2,475
|
)
|
$
|
(3,791
|
)
|
|
153
|
%
|
Gain on derivative instruments
|
|
|
20,756
|
|
|
41,943
|
|
|
(21,187
|
)
|
|
(51
|
)%
|
Other income
|
|
|
20
|
|
|
281
|
|
|
(261
|
)
|
|
NM
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
|
|
$
|
14,510
|
|
$
|
39,749
|
|
$
|
(25,239
|
)
|
|
(63
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense)
|
|
$
|
572
|
|
$
|
(1,524
|
)
|
|
NM
|
|
|
NM
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense.
Interest expense increased $3.8 million, or 153%, primarily due to an increase in the average amounts
outstanding under our
term loan and revolving credit facility in 2015 compared to 2014.
Gain on Derivative Instruments.
In 2015, we recognized a $20.8 million gain on derivative instruments compared to a
$41.9 million gain
on derivative instruments in 2014. Net gains on our derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.
83
Table of Contents
Income Tax Benefit (Expense).
We are treated as a flow-through entity for U.S. federal income tax purposes and the purposes of certain
state and
local income taxes and, accordingly, are not subject to such income taxes. We are subject to the Texas franchise tax, at a statutory rate of 0.75% of income. For the year ended December 31,
2015, we recognized a tax benefit of $0.6 million associated with our Texas franchise tax obligation. For the year ended December 31, 2014, we recognized income tax expense of
$1.5 million. The decrease was primarily due to a decrease in the Texas franchise tax rate and a decrease in our estimated income attributable to Texas franchise tax year-over-year.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Oil and Natural Gas Revenues.
The following table provides the components of our revenues for the years indicated, as well as each
year's respective
average prices and production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
|
|
|
|
2014
|
|
2013
|
|
Change
|
|
% Change
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
114,955
|
|
$
|
65,863
|
|
$
|
49,092
|
|
|
75
|
%
|
Natural gas sales
|
|
|
9,670
|
|
|
3,024
|
|
|
6,646
|
|
|
220
|
%
|
NGL sales
|
|
|
7,200
|
|
|
3,087
|
|
|
4,113
|
|
|
133
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
131,825
|
|
$
|
71,974
|
|
$
|
59,851
|
|
|
83
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
80.50
|
|
$
|
92.37
|
|
$
|
(11.87
|
)
|
|
(13
|
)%
|
Natural gas (per Mcf)
|
|
|
4.58
|
|
|
3.79
|
|
|
0.79
|
|
|
21
|
%
|
NGLs (per Bbl)
|
|
|
30.64
|
|
|
31.50
|
|
|
(0.86
|
)
|
|
(3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (per Boe)
|
|
$
|
65.42
|
|
$
|
76.24
|
|
$
|
(10.82
|
)
|
|
(14
|
)%
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
1,428
|
|
|
713
|
|
|
715
|
|
|
100
|
%
|
Natural gas (MMcf)
|
|
|
2,112
|
|
|
797
|
|
|
1,315
|
|
|
165
|
%
|
NGLs (MBbls)
|
|
|
235
|
|
|
98
|
|
|
137
|
|
|
140
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)(1)
|
|
|
2,015
|
|
|
944
|
|
|
1,071
|
|
|
113
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls/d)
|
|
|
3,912
|
|
|
1,953
|
|
|
1,959
|
|
|
100
|
%
|
Natural gas (Mcf/d)
|
|
|
5,786
|
|
|
2,184
|
|
|
3,602
|
|
|
165
|
%
|
NGLs (Bbls/d)
|
|
|
644
|
|
|
268
|
|
|
376
|
|
|
140
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Boe/d)(1)
|
|
|
5,521
|
|
|
2,586
|
|
|
2,935
|
|
|
114
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Totals
may not sum or recalculate due to rounding.
Oil
sales increased 75%, or $49.1 million, primarily as result of a 100% increase in oil volumes sold, partially offset by a 13% decrease in the average realized price in 2014
compared to 2013. Excluding the CO2 Project Disposition and the Wolfbone Disposition, oil production increased 180%, or 876 MBbls, to 1,363 MBbls in 2014 from 487 MBbls in 2013. The increase in
production was partially offset by a decrease of 161 MBbls attributable to these dispositions.
Natural
gas sales increased 220%, or $6.6 million, primarily as a result of a 165% increase in natural gas volumes sold and a 21% increase in the average realized price in 2014
compared to 2013. Excluding the CO2 Project Disposition and the Wolfbone Disposition, natural gas production increased 201%, or 1,394 MMcf, to 2,089 MMcf in 2014 from 695 MMcf in 2013. The increase in
production was partially offset by a decrease of 79 MMcf attributable to these dispositions.
84
Table of Contents
NGL
sales increased 133%, or $4.1 million, primarily as a result of a 140% increase in NGL volumes sold, partially offset by a 3% decrease in the average realized price in 2014
compared to 2013. Excluding the CO2 Project Disposition and the Wolfbone Disposition, natural gas production and ultimately the NGLs extracted during processing increased 153%, or 142 MBbls, to 235
MBbls in 2014
from 93 MBbls in 2013. The increase in NGL volumes extracted was partially offset by a decrease of 5 MBbls attributable to the Wolfbone Disposition and the CO2 Project Disposition.
Operating Expenses.
The following table summarizes our expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
|
|
|
|
2014
|
|
2013
|
|
Change
|
|
% Change
|
|
Operating expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
17,690
|
|
$
|
19,106
|
|
$
|
(1,416
|
)
|
|
(7
|
)%
|
Severance and ad valorem taxes
|
|
|
6,875
|
|
|
4,153
|
|
|
2,722
|
|
|
66
|
%
|
Transportation, processing, gathering and other operating expenses
|
|
|
4,772
|
|
|
1,291
|
|
|
3,481
|
|
|
270
|
%
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
69,110
|
|
|
29,285
|
|
|
39,825
|
|
|
136
|
%
|
Abandonment expense and impairment of unproved properties
|
|
|
20,025
|
|
|
8,561
|
|
|
11,464
|
|
|
134
|
%
|
General and administrative expenses
|
|
|
31,694
|
|
|
16,842
|
|
|
14,852
|
|
|
88
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
$
|
150,166
|
|
$
|
79,238
|
|
$
|
70,928
|
|
|
90
|
%
|
Loss (gain) on sale of oil and natural gas properties
|
|
|
2,096
|
|
|
(16,756
|
)
|
|
18,852
|
|
|
NM
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses after loss (gain) on sale of oil and natural gas properties
|
|
$
|
152,262
|
|
$
|
62,482
|
|
$
|
89,780
|
|
|
144
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average unit costs per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
8.78
|
|
$
|
20.24
|
|
$
|
(11.46
|
)
|
|
(57
|
)%
|
Severance and ad valorem taxes
|
|
|
3.41
|
|
|
4.40
|
|
|
(0.99
|
)
|
|
(23
|
)%
|
Transportation, processing, gathering and other operating expenses
|
|
|
2.37
|
|
|
1.37
|
|
|
1.00
|
|
|
73
|
%
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
34.30
|
|
|
31.02
|
|
|
3.28
|
|
|
11
|
%
|
Abandonment expense and impairment of unproved properties
|
|
|
9.94
|
|
|
9.07
|
|
|
0.87
|
|
|
10
|
%
|
General and administrative expenses
|
|
|
15.73
|
|
|
17.84
|
|
|
(2.11
|
)
|
|
(12
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses per Boe
|
|
$
|
74.53
|
|
$
|
83.94
|
|
$
|
(9.41
|
)
|
|
(11
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease Operating Expenses.
LOE decreased 7%, or $1.4 million, primarily due to the Wolfbone Disposition and the CO2 Project
Disposition, which
accounted for $12.5 million of CRP's LOE in 2013 compared to $4.4 million in 2014. The decrease was offset by an increase in costs for compression, rental equipment, fuel and overhead
associated with bringing additional wells on production during 2014. LOE per Boe, excluding the Wolfbone Disposition and the CO2 Project Disposition, was $6.84 for the year ended December 31,
2014 compared to $8.22 for the year ended December 31, 2013. The decrease per Boe was primarily related to a 113% increase in production volumes in 2014 compared to 2013.
Severance and Ad Valorem Taxes.
Severance taxes are primarily based on the market value of our production at the wellhead and ad
valorem taxes are
generally based on the valuation of our oil and natural gas properties and vary across the different counties in which we operate. Severance and ad
85
Table of Contents
valorem
taxes increased 66%, primarily as a result of an 83% increase in revenues. The increase was partially offset by the Wolfbone Disposition and the CO2 Project Disposition, which accounted for
$1.6 million of our severance taxes in 2013 compared to $0.5 million in 2014. Severance and ad valorem taxes as a percentage of our revenue was 5.2% for 2014 compared to 5.8% for 2013.
Transportation, Processing, Gathering and Other Operating Expenses.
Transportation, processing, gathering and other operating expenses
increased
270%, or $3.5 million, primarily due to an increase in sales and processing volumes. In 2014, our natural gas and NGL volumes increased 162% compared to 2013. Transportation, processing,
gathering and other operating expenses per Boe, excluding the Wolfbone Disposition and the CO2 Project Disposition, was $2.45 for 2014 compared to $1.85 for the year ended December 31, 2013.
The increase per Boe was primarily related to an increase in gathering expense in 2014 compared to 2013.
Depreciation, Depletion, Amortization and Accretion of Asset Retirement Obligations.
Our DD&A rate can fluctuate as a result of
impairments,
dispositions and changes in the mix of our production and the underlying proved reserve volumes. DD&A expense increased 136%, or $39.8 million, primarily due to a 113% increase in production
volumes. DD&A, excluding the Wolfbone Disposition and the CO2 Project Disposition, was $67.6 million, or $34.75 per Boe, in 2014 compared to $21.7 million, or $31.17 Boe, in 2013. DD&A
per Boe primarily increased as we continued to shift toward drilling more horizontal wells, which are comparatively more expensive than vertical wells. DD&A expense, excluding our dispositions,
increased due to the aforementioned increase in production on our properties.
General and Administrative Expenses.
G&A expenses increased 88%, primarily due to $12.4 million of incentive compensation
recorded in 2014 due
to the achievement of certain performance criteria associated with our incentive units. Additionally, the increase was the result of having two distinct management teams and employees associated with
CRP's predecessors along with its growing capital program and oil production levels.
Loss (Gain) on Sale of Oil and Natural Gas Properties.
We recorded a loss on sale of assets of $2.1 million in 2014 and a gain on
sale of
assets of $16.8 million in 2013. The loss in 2014 and gains in 2013 were primarily attributable to the following:
-
-
In May 2014, we completed the CO2 Project Disposition for net cash proceeds of approximately $60 million and realized a loss on sale of
$1.8 million.
-
-
In October 2013, we completed the Wolfbone Disposition for total proceeds of approximately $28.7 million and realized a gain on sale of
$7.7 million.
-
-
In August 2013, we sold oil and natural gas properties in the Midland Basin for total proceeds of $17.1 million and realized a
$7.9 million gain on sale.
Other Income and Expenses.
The following table summarizes our other income and expenses for the years indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
|
|
|
|
2014
|
|
2013
|
|
Change
|
|
% Change
|
|
Other income (expense) (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
(2,475
|
)
|
$
|
(513
|
)
|
$
|
(1,962
|
)
|
|
382
|
%
|
Gain (loss) on derivative instruments
|
|
|
41,943
|
|
|
(4,410
|
)
|
|
46,353
|
|
|
NM
|
|
Other expense
|
|
|
281
|
|
|
122
|
|
|
159
|
|
|
130
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
$
|
39,749
|
|
$
|
(4,801
|
)
|
$
|
44,550
|
|
|
NM
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
(1,524
|
)
|
$
|
(1,079
|
)
|
$
|
(445
|
)
|
|
41
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86
Table of Contents
Interest Expense.
Interest expense increased $2.0 million, or 382%, primarily due to an increase in the borrowings under CRP's
revolving
credit facility during 2014 as compared to 2013 as well as due to the interest associated with CRP's term loan, which was entered into in the fourth quarter of 2014.
Gain (Loss) on Derivative Instruments.
During 2014, we recognized a $41.9 million gain on derivative instruments compared to a
$4.4 million loss on derivative instruments in 2013, primarily as a result of the impact of changing commodity prices on increased hedging activities.
Income Tax Expense.
During the year ended December 31, 2014, we recognized $1.5 million of expense associated with our Texas
franchise
tax obligation, an increase of $0.4 million, or 41%, as compared to the $1.1 million we recognized during the year ended December 31, 2013. The increase was based on an increase
in our estimated taxable income subject to Texas franchise tax year-over-year.
Capital Requirements and Sources of Liquidity
Our development and acquisition activities require us to make significant operating and capital expenditures. Historically, our primary sources
of liquidity have been capital contributions from CRP's equity sponsors, borrowings under CRP's revolving credit facility and term loan, proceeds from asset dispositions and cash flows from
operations. CRD and NGP Follow-On, CRP's equity sponsors, agreed to make capital contributions to CRP of up to $321.9 million and $184.5 million, respectively, and as of
September 30, 2016, CRD and NGP Follow-On have made total capital contributions of $289.4 million and $84.2 million, respectively. To date, our primary use of capital has been for
the development and acquisition of oil and natural gas properties.
We
plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we expect
to maintain an active hedging program that seeks to reduce our exposure to commodity prices and protect our cash flow.
The
amount and allocation of future capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating,
investing and financing activities, and our ability to assimilate acquisitions and execute our drilling program. We periodically review our capital expenditure budget to assess changes in current and
projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete
acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.
Our
2016 capital budget for drilling, completion and recompletion activities and facilities costs was approximately $92 million, excluding leasing and other acquisitions. In the
nine months ended September 30, 2016, we incurred capital costs of approximately $48.9 million, excluding leasing and acquisition costs.
Because
we are the operator of a high percentage of our acreage, the amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to
defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for
oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and
acquisition costs and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could
result in a reduction in anticipated production and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations. See
"BusinessOil and Natural Gas Production Prices and CostsDeveloped and Undeveloped Acreage." In addition, we may be required to reclassify some portion of
87
Table of Contents
our
reserves currently booked as proved undeveloped reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial
booking.
As
of September 30, 2016, there was $124.0 million outstanding under CRP's revolving credit facility and $0.5 million of letters of credit outstanding, and CRP was
able to incur approximately $15.5 million of
additional indebtedness under its revolving credit facility. The borrowing base under CRP's revolving credit facility was $140.0 million as of September 30, 2016. In connection with the
closing of the Business Combination, CRP repaid all amounts outstanding under its revolving credit facility and term loan and entered into an amendment to its credit agreement to, among other things,
increase the borrowing base from $140 million to $200 million. In connection with the Silverback Acquisition, CRP entered into an amendment to its credit agreement to, among other
things, increase the borrowing base from $200 million to $250 million.
Based
upon current oil and natural gas price expectations for 2017, we believe that our cash flow from operations and additional borrowings under CRP's revolving credit facility will
provide us with sufficient liquidity to execute our current capital program. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and
prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot ensure that operations and other needed capital will be available on acceptable
terms or at all. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to
reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base
borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot ensure that needed capital will be available on
acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage
through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our
reserves.
We define working capital as current assets minus current liabilities. At September 30, 2016, we had a working capital deficit of
$11.6 million. At December 31, 2015, we had working capital of $12.0 million, and at December 31, 2014, we had a working capital deficit of $36.2 million. We may
continue to incur working capital deficits in the future due to the amounts that accrue related to our drilling program. Our collection of receivables has historically been timely, and losses
associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents balance totaled $0.4 million, $1.8 million and $13.0 million at
September 30, 2016, December 31, 2015 and December 31, 2014, respectively. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX
prices for our oil and natural gas production will be the largest variables affecting our working capital.
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Table of Contents
The following table summarizes our cash flows for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
Year Ended December 31,
|
|
|
|
2016
|
|
2015
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Net cash provided by operating activities
|
|
$
|
51,511
|
|
$
|
48,474
|
|
$
|
68,882
|
|
$
|
97,248
|
|
$
|
13,416
|
|
Net cash used in investing activities
|
|
|
(100,975
|
)
|
|
(171,316
|
)
|
|
(198,635
|
)
|
|
(163,380
|
)
|
|
(136,517
|
)
|
Net cash provided by financing activities
|
|
|
48,106
|
|
|
110,219
|
|
|
118,504
|
|
|
36,966
|
|
|
118,742
|
|
Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2016 and
September 30, 2015
Operating Activities.
Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs,
production volumes
and changes in working capital. The increase in net cash provided by operating activities for the first nine months of 2016 compared to the first nine months of 2015 was primarily due to a
$11.9 million reduction in operating expenses and a positive cash flow impact from working capital of $8.4 million, partially offset by a $3.0 million decrease in total revenues
and a $9.3 million decrease in derivatives settlements.
Investing Activities.
Net cash used in investing activities is primarily comprised of acquisition and development of oil and natural
gas properties,
net of dispositions. In the first nine months of 2016, net cash used for investing activities included $100.8 million attributable to the acquisition and development of oil and natural gas
properties. In the first nine months of 2015, net cash used for investing activities included $171.9 million attributable to the acquisition and development of oil and natural gas properties.
Financing Activities.
Net cash provided by financing activities in the first nine months of 2016 included $55.0 million of
borrowings under
CRP's revolving credit facility, offset by repayments of $5.0 million. Net cash provided by financing activities in the first nine months of 2015 included $110.7 million of capital
contributions, which were primarily used to repay a portion of CRP's revolving credit facility.
Analysis of Cash Flow Changes Between the Year Ended December 31, 2015 and 2014
Operating Activities.
Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs,
production volumes
and changes in working capital. The decrease in net cash provided by operating activities for the year ended December 31, 2015 as compared to the prior year is primarily due to a
$41.4 million decrease in total revenues and a decrease in changes in current assets and current liabilities, which decreased cash proceeds provided by operating activities by
$16.4 million. The decreases are primarily offset by an increase in net cash received for derivative settlements of $30.9 million.
Investing Activities.
Net cash used in investing activities is primarily comprised of acquisition and development of oil and natural
gas properties
net of dispositions. In 2015, net cash used for investing activities included $201.3 million attributable to the acquisition and development of oil and natural gas properties, offset by
proceeds from asset sales of $2.7 million. In 2014, net cash used for investing activities included $298.3 million attributable to the acquisition and development of oil and natural gas
properties, offset by net proceeds from asset sales of $129.9 million.
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Table of Contents
Financing Activities.
Net cash provided by financing activities in 2015 included $92.0 million of borrowings under CRP's revolving
credit
facility, offset by repayments of $83.0 million, capital contributions of $111.4 million, $1.6 million of payments associated with our financing obligation and debt issuance costs
of $0.3 million. Net cash provided by financing activities in 2014 included $196.0 million of borrowing under CRP's revolving credit facility, offset by $160.0 million of
repayments, $65.0 million of proceeds from CRP's term loan, and capital contributions of $59.8 million, offset by $119.3 million attributable to the repurchase of equity interests
and $1.6 million of debt issuance costs.
Analysis of Cash Flow Changes Between the Year Ended December 31, 2014 and 2013
Operating Activities.
Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs,
production volumes
and changes in working capital. The increase in net cash provided by operating activities for the year ended December 31, 2014 as compared to the prior year was primarily due to a
$59.9 million increase in total revenues and an increase in changes in current assets and current liabilities which increased cash proceeds by operating activities by $16.5 million.
Investing Activities.
Net cash used in investing activities is primarily comprised of acquisition and development of oil and natural
gas properties
net of dispositions. The increase in cash used in investing activities for the year ended December 31, 2014 as compared to the prior year was primarily due to a $129.0 million increase
in capital expenditures attributable to the acquisition and development of oil and natural gas properties, offset by cash proceeds of $71.8 million attributable to the disposition of CRP's
midstream assets in 2014.
Financing Activities.
Net cash provided by financing activities in 2014 included $196.0 million of borrowing under CRP's revolving
credit
facility, offset by $160.0 million of repayments, $65.0 million of proceeds from CRP's term loan, and capital contributions of $59.8 million, offset by $119.3 million
attributable to the repurchase of equity interests. Net cash provided by financing activities in 2013 including $57.0 million of borrowing under CRP's revolving credit facility offset by
repayment of $28.0 million, capital contributions of $114.8 million, offset by $21.1 million of capital distributions.
On October 15, 2014, CRP entered into an amended and restated credit agreement (as amended, the "credit agreement") with JPMorgan Chase
Bank, N.A., as administrative agent, and a syndicate of lenders, that includes both a term loan commitment of $65.0 million (the "term loan"), which was fully funded as of September 30,
2016, and a revolving credit facility (the "revolving credit facility") with commitments of $500.0 million (subject to the borrowing base), with a sublimit for letters of credit of
$15.0 million. As of September 30, 2016, CRP had $124.0 million outstanding under its revolving credit facility and $0.5 million of letters of credit outstanding, and CRP
was able to incur approximately $15.5 million of additional indebtedness under its revolving credit facility. CRP's term loan matures on April 15, 2018, and its revolving credit facility
matures on October 15, 2019.
On
October 11, 2016, CRP entered into an amendment to the credit agreement to, among other things, (i) permit the Business Combination, (ii) reflect the repayment in
full of all term loans thereunder,
(iii) increase the borrowing base from $140.0 million to $200.0 million, (iv) increase the interest rate to LIBOR plus 2.25%-3.25%, and (v) require CRP to have
sufficient liquidity and satisfy a maximum leverage ratio in order to make dividends. On December 28, 2016, in connection with the closing of the Silverback Acquisition, CRP entered into an
amendment to the credit agreement to, among other things, further increase the borrowing base from $200.0 million to $250.0 million.
The
amount available to be borrowed under CRP's revolving credit facility is subject to a borrowing base that will be redetermined semiannually each April 1 and October 1
by the lenders in
90
Table of Contents
their
sole discretion. CRP's credit agreement also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the
volumes of CRP's proved oil and natural gas reserves and estimated cash flows from these reserves and its commodity hedge positions. The borrowing base will automatically be decreased by an amount
equal to 25% of the aggregate notional amount of issued permitted senior unsecured notes unless such decrease is waived by the lenders. Upon a redetermination of the borrowing base, if borrowings in
excess of the revised borrowing capacity are outstanding, CRP could be required to immediately repay a portion of its debt outstanding under its credit agreement. The next regular redetermination date
is scheduled for the spring of 2017.
Principal
amounts borrowed are payable on the term loan maturity date and the revolving credit maturity date, as applicable. Interest on the term loan is LIBOR plus 5.25%. At
September 30, 2016, the weighted average interest rate on CRP's term loan was 5.78%. Loans under its revolving credit facility may be base rate loans or LIBOR loans. Interest is payable
quarterly for base rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for statutory reserve requirements) plus an applicable
margin ranging from 150 to 250 basis points, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the
agent bank's prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points, plus
an applicable margin ranging from 50 to 150 basis points, depending on the percentage of the borrowing base utilized. At September 30, 2016, the weighted average interest rate on borrowings
under CRP's revolving credit facility was approximately 2.78%. CRP also pays a commitment fee on unused amounts of its revolving credit facility ranging from 37.5 basis points to 50 basis
points, depending on the percentage of the borrowing base utilized. CRP may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage
costs.
CRP's
credit agreement contains restrictive covenants that limit its ability to, among other things:
-
-
incur additional indebtedness;
-
-
make investments and loans;
-
-
enter into mergers;
-
-
make or declare dividends;
-
-
enter into commodity hedges exceeding a specified percentage of its expected production;
-
-
enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness;
-
-
incur liens;
-
-
sell assets; and
-
-
engage in transactions with affiliates.
CRP's
credit agreement also requires it to maintain compliance with the following financial ratios:
-
-
a current ratio, which is the ratio of CRP's consolidated current assets (including unused commitments under CRP's revolving credit facility
and excluding non-cash assets under Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 815,
Derivatives and
Hedging
and certain restricted cash) to consolidated current liabilities (excluding the current portion of long-term debt under its credit agreement and non-cash liabilities
under ASC 815), of not less than 1.0 to 1.0; and
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Table of Contents
-
-
a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP's credit agreement) to consolidated EBITDAX (as defined in CRP's
credit agreement) for the rolling four fiscal quarter period ending on such day, of not greater than 4.0 to 1.0.
As
of September 30, 2016, CRP was in compliance with such covenants and the financial ratios described above.
Contractual Obligations
A summary of our contractual obligations as of December 31, 2015 is provided in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period For the Year Ending December 31,
|
|
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
Thereafter
|
|
Total
|
|
|
|
(in thousands)
|
|
Revolving credit facility(1)
|
|
$
|
|
|
$
|
|
|
$
|
|
|
$
|
74,000
|
|
$
|
|
|
$
|
|
|
$
|
74,000
|
|
Term loan
|
|
|
|
|
|
|
|
|
65,000
|
|
|
|
|
|
|
|
|
|
|
|
65,000
|
|
Drilling rig commitments
|
|
|
422
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
422
|
|
Office and equipment leases
|
|
|
539
|
|
|
477
|
|
|
485
|
|
|
419
|
|
|
|
|
|
|
|
|
1,920
|
|
Pipeline financing obligation(2)
|
|
|
2,137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,137
|
|
Asset retirement obligations(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,288
|
|
|
2,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,098
|
|
$
|
477
|
|
$
|
65,485
|
|
$
|
74,419
|
|
$
|
|
|
$
|
2,288
|
|
$
|
145,767
|
|
-
(1)
-
This
table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on CRP's revolving credit facility
because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. As of
September 30, 2016, CRP had $124.0 million outstanding under its revolving credit facility and $0.5 million of letters of credit outstanding, and it was able to incur
approximately $15.5 million of additional indebtedness under its revolving credit facility.
-
(2)
-
A
subsidiary of EagleClaw Midstream Ventures, LLC has constructed an expansion of a gas gathering system for which we have agreed to repay all construction
costs, which totaled approximately $4.0 million. Each month, we pay a minimum fee of $7,000 per day until all construction costs are paid.
-
(3)
-
Amounts
represent estimates of our future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future
costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and
regulatory environment.
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary
objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising
from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible
losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
92
Table of Contents
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGLs production. Pricing for oil, natural gas and
NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. During the period from January 1, 2014 through November 1, 2016, the
WTI spot price has declined from a high of $107.62 per Bbl on July 23, 2014 to $26.21 per Bbl on February 11, 2016. NGL prices generally correlate to the price of oil, and accordingly
prices for these products have likewise declined and are likely to continue following that market. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued
to be weak throughout 2015 and 2016. During the period from January 1, 2014 through November 1, 2016, natural gas prices have declined from a high of $7.92 per MMBtu on March 4,
2014 to a low of $1.49 per MMBtu on March 4, 2016.
A
$1.00 per barrel change in our realized oil price would have resulted in a $1.5 million change in oil revenues for the first nine months of 2016. A $0.10 per Mcf change in our
realized natural gas price would have resulted in a $0.3 million change in natural gas revenues for the first nine months of 2016. A $1.00 per barrel change in our realized NGL prices would
have resulted in a $0.2 million change in NGL revenues for the first nine months of 2016. Oil sales contributed 87% of our total revenues for the first nine months of 2016. Natural gas sales
contributed 9% and NGL sales contributed 5% of our total revenues for the first nine months of 2016. Our oil, natural gas and NGL revenues do not include the effects of derivatives.
Due
to this volatility, we have historically used, and we expect to continue to use, commodity derivative instruments, such as collars, swaps and basis swaps, to hedge price risk
associated with a portion of its anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to
fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection
against declines in oil and natural gas prices and may partially limit our potential gains from future increases in prices. CRP's credit agreement limits its ability to enter into commodity hedges
covering greater than 80% of its reasonably anticipated projected production volume.
Our
open positions as of September 30, 2016:
|
|
|
|
|
|
|
|
Description & Production Period
|
|
Volume (Bbl)
|
|
Weighted
Average Swap
Price ($/Bbl)(1)
|
|
Crude Oil Swaps:
|
|
|
|
|
|
|
|
October 2016 - December 2016
|
|
|
11,500
|
|
$
|
76.25
|
|
October 2016 - December 2016
|
|
|
23,000
|
|
|
62.42
|
|
October 2016 - December 2016
|
|
|
11,500
|
|
|
77.32
|
|
October 2016 - December 2016
|
|
|
23,000
|
|
|
65.58
|
|
October 2016 - December 2016
|
|
|
9,200
|
|
|
54.00
|
|
October 2016 - December 2016
|
|
|
9,200
|
|
|
53.23
|
|
October 2016 - December 2016
|
|
|
9,200
|
|
|
51.80
|
|
October 2016 - December 2016
|
|
|
32,200
|
|
|
52.10
|
|
October 2016 - December 2016
|
|
|
9,200
|
|
|
50.20
|
|
October 2016 - December 2016
|
|
|
9,200
|
|
|
40.87
|
|
October 2016 - December 2016
|
|
|
18,400
|
|
|
43.35
|
|
October 2016 - December 2016
|
|
|
27,600
|
|
|
42.75
|
|
January 2017 - December 2017
|
|
|
91,250
|
|
|
64.05
|
|
January 2017 - December 2017
|
|
|
36,500
|
|
|
54.65
|
|
January 2017 - December 2017
|
|
|
36,500
|
|
|
43.50
|
|
93
Table of Contents
|
|
|
|
|
|
|
|
Description & Production Period
|
|
Volume (Bbl)
|
|
Weighted
Average Swap
Price ($/Bbl)(1)
|
|
January 2017 - December 2017
|
|
|
36,500
|
|
|
44.85
|
|
January 2017 - December 2017
|
|
|
36,500
|
|
|
45.10
|
|
January 2017 - December 2017
|
|
|
109,500
|
|
|
44.80
|
|
January 2017 - December 2017
|
|
|
36,500
|
|
|
47.27
|
|
January 2017 - December 2017
|
|
|
36,500
|
|
|
49.00
|
|
January 2017 - December 2017
|
|
|
182,500
|
|
|
49.80
|
|
January 2017 - December 2017
|
|
|
73,000
|
|
|
52.35
|
|
January 2018 - December 2018
|
|
|
36,500
|
|
|
55.95
|
|
Crude Oil Basis Swaps:
|
|
|
|
|
|
|
|
August 2016 - November 2016
|
|
|
23,000
|
|
$
|
(1.65
|
)
|
August 2016 - November 2016
|
|
|
23,000
|
|
|
(1.05
|
)
|
August 2016 - November 2016
|
|
|
23,000
|
|
|
(1.40
|
)
|
August 2016 - November 2016
|
|
|
30,500
|
|
|
(0.55
|
)
|
August 2016 - November 2016
|
|
|
27,600
|
|
|
0.25
|
|
August 2016 - November 2016
|
|
|
18,400
|
|
|
(0.16
|
)
|
August 2016 - November 2016
|
|
|
9,200
|
|
|
(0.50
|
)
|
August 2016 - November 2016
|
|
|
9,200
|
|
|
(0.40
|
)
|
August 2016 - November 2016
|
|
|
27,600
|
|
|
(0.25
|
)
|
August 2016 - November 2016
|
|
|
46,000
|
|
|
(0.25
|
)
|
August 2016 - November 2016
|
|
|
46,000
|
|
|
(0.20
|
)
|
August 2016 - November 2016
|
|
|
18,400
|
|
|
(0.10
|
)
|
August 2016 - November 2016
|
|
|
18,400
|
|
|
0.10
|
|
November 2016 - November 2017
|
|
|
91,250
|
|
|
(0.20
|
)
|
November 2016 - November 2017
|
|
|
36,500
|
|
|
(0.20
|
)
|
-
(1)
-
The
oil swap contracts are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude. The oil basis derivative contracts
are settled based on the month's average daily implied principal components of our cost structure.
|
|
|
|
|
|
|
|
Description & Production Period
|
|
Volume (MMBtu)
|
|
Weighted
Average Swap
Price ($/MMbtu)(1)
|
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|
January 2017 - December 2017
|
|
|
1,460,000
|
|
$
|
2.94
|
|
-
(1)
-
The
natural gas derivative contracts are settled based on the month's average daily NYMEX price of Henry Hub Natural Gas.
Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to
our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. The counterparties to our derivative contracts currently in place have
investment grade ratings.
Our
principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the
concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or
liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high.
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Joint
operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their
ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.
At September 30, 2016, CRP had $189.0 million of debt outstanding, with an assumed weighted average interest rate of 3.81%.
Interest is calculated under the terms of CRP's credit agreement based on a LIBOR spread. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in
the assumed weighted average interest rate would be approximately $1.9 million per year. CRP does not currently have or intend to enter into any derivative arrangements to protect against
fluctuations in interest rates applicable to its outstanding indebtedness.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon consolidated and combined financial statements,
which have been prepared in accordance with GAAP. The preparation of the financial statements requires it to make estimates and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses and related disclosure of contingent assets and liabilities. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may
differ from these estimates.
Our oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts
method, we capitalize lease acquisition costs, all development costs and successful exploration costs.
Proved Oil and Natural Gas Properties.
Costs incurred to obtain access to proved reserves and to provide facilities for extracting,
treating,
gathering and storing oil, natural gas and NGLs are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells and
service wells, including unsuccessful development wells, are capitalized.
Unproved Properties.
Acquisition costs associated with the acquisition of non-producing leaseholds are recorded as unproved leasehold
costs and
capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other
similar costs related to acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural
gas properties.
Exploration Costs.
Exploration costs, other than exploration drilling costs, are charged to expense as incurred. These costs include
seismic
expenditures, other geological and geophysical costs, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending
determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.
Our proved oil and natural gas properties are recorded at cost. We evaluate our proved properties for impairment when events or changes in
circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and natural gas properties and compare
these undiscounted cash flows to the carrying
amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount
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exceeds
the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but
are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future operating and capital expenditures, and discount rates.
Unproved
properties costs consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. We evaluate significant unproved properties for impairment based
on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.
Our estimated proved reserve quantities and future net cash flows are critical to the understanding of the value of our business. They are used
in comparative financial ratios and are the basis for significant accounting estimates in our financial statements, including the calculations of depletion and impairment of proved oil and natural gas
properties. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials and basis differentials,
applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate
discount rate. For example, the standardized measure calculations require a 10% discount rate to be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and
undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We engage Netherland, Sewell &
Associates, Inc., our independent petroleum engineer ("NSAI"), to prepare our total calculated proved reserve PV-10. We expect proved reserve estimates will change as additional information
becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year-end. For purposes of depletion and impairment, reserve
quantities are adjusted in accordance with GAAP for the impact of additions and dispositions.
Our revenue recognition policy is significant because revenue is a key component of our results of operations and our forward-looking statements
contained in the above analysis of liquidity and capital resources. We derive our revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when our production is
delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has
transferred to a purchaser. At the end of each month, we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties,
contractual arrangements, NYMEX and local spot market prices and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the
month payment is received.
We utilize commodity derivative instruments, including swaps, collars and basis swaps, to manage the price risk associated with the forecasted
sale of our oil and natural gas production. Our derivative instruments are not designated as hedges for accounting purposes. Accordingly, changes in fair value are recognized in our consolidated and
combined statements of operations in the period of change. Gains and losses on derivatives and premiums paid for put options are included in cash flows from operating activities.
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Our asset retirement obligation represents the estimated present value of the amount we will incur to retire long-lived assets at the end of
their productive lives, in accordance with applicable state laws. Our asset retirement obligation is determined by calculating the present value of estimated cash flows related to the liability. The
retirement obligation is recorded as a liability at its
estimated present value as of inception with an offsetting increase in the carrying amount of the related long-lived asset. Periodic accretion of discount of the estimated liability is recorded as an
expense in the income statement. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset.
Asset
retirement liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive
lives of assets and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the subjectivity
of assumptions, the costs to ultimately retire our wells may vary significantly from prior estimates.
Recently Issued Accounting Pronouncements
In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-15, Classification
of Certain Cash Receipts and Cash Payments, which clarifies how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update addresses eight
specific cash flow issues with the objective of reducing the existing diversity in practice. The new standard becomes effective for us on January 1, 2018, with early adoption is permitted. We
are evaluating the impact, if any, that the adoption of this update will have on our condensed consolidated financial statements and related disclosures.
In
February 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-02,
Leases,
which requires all leasing arrangements
to be presented in the balance sheet as liabilities along with a corresponding asset. The ASU will replace most existing leases guidance in GAAP when it becomes effective. The new standard becomes
effective for us on January 1, 2019. Although early application is permitted, we do not plan to early adopt the ASU. The standard requires the use of the modified retrospective transition
method. We are evaluating the impact, if any, that the adoption of this update will have on our condensed consolidated financial statements and related disclosures.
In
March 2016, the FASB issued ASU No. 2016-09,
Improvements to Employee Share-Based Payment Accounting,
which includes provisions
intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in financial statements. This amendment will be effected prospectively for
reporting periods beginning on or after December 15, 2016, and early adoption is permitted. We are evaluating the impact, if any, that the adoption of this update will have on our condensed
consolidated financial statements and related disclosures.
In
May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers.
This guidance is to be applied using a full retrospective
method or a modified retrospective method, as outlined in the guidance. In August 2015, the FASB deferred the effective date of the new revenue recognition
standard by one year. The revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is
permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. We are evaluating the impact, if any, that the adoption of this update
will have on our consolidated and combined financial statements and related disclosures.
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Internal Controls and Procedures
We qualify as an "emerging growth company" as defined in the JOBS Act and, as such, we qualify for an exception to the SEC's rules implementing
Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the
years ended December 31, 2015, 2014 or 2013. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience
inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.
Off-Balance Sheet Arrangements
We do not currently have any off-balance sheet arrangements.
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MANAGEMENT
Directors and Executive Officers
Set forth below are the names, ages and positions of each of each of our directors and executive officers:
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Name
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Age
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Position
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Class(1)
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Mark G. Papa
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70
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President, Chief Executive Officer and Chairman of the Board
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III
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George S. Glyphis
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46
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Chief Financial Officer
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Sean R. Smith
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44
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Chief Operating Officer
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Maire A. Baldwin
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51
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Director
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I
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Robert M. Tichio
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39
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Director
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I
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Karl E. Bandtel
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50
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Director
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II
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Jeffrey H. Tepper
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51
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Director
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II
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David M. Leuschen
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65
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Director
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III
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Pierre F. Lapeyre, Jr.
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54
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Director
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III
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Tony R. Weber
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54
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Director
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(2)
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(1)
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The
term of office of the Class I directors expires at the annual meeting of stockholders in 2017, the term of office of the Class II directors expires
at the annual meeting of stockholders in 2018, and the term of office of the Class III directors expires at the annual meeting of stockholders in 2019.
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(2)
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Tony
Weber has been nominated and elected to the board of directors by CRD as the holder of our Series A Preferred Stock. The term of office of
Mr. Weber expires at the annual meeting of stockholders in 2017.
Mark G. Papa
has been our Chief Executive Officer and a director since November 2015. Since the closing of the Business Combination,
Mr. Papa also serves as our President. Mr. Papa is a Houston-based advisor to Riverstone. We currently anticipate that Mr. Papa will spend approximately 60% of his working time
providing services to us as our President and Chief Executive Officer and approximately 40% of his working time providing services to Riverstone on matters unrelated to the Company. Prior
to joining Riverstone in February 2015, Mr. Papa was Chairman and CEO of EOG Resources, Inc. (NYSE: EOG), an independent U.S. oil and gas company, from August 1999 to December 2013.
Mr. Papa served as a member of EOG Resources' board of directors from August 1999 until December 2014. Mr. Papa worked at EOG Resources for 32 years in various management
positions. Mr. Papa was retired from December 2013 through February 2015. Prior to joining EOG Resources, Mr. Papa worked at Conoco Inc. for 13 years in various engineering
and management positions. Mr. Papa has also served on the board of Oil States Industries (NYSE: OIS), a multinational oil and gas company, since February 2001 and Casa de Esperanza, a
non-profit organization serving immigrants, since November 2006. In February 2010 and 2013, the Harvard Business Review cited Mr. Papa as one of the 100 Best Performing CEOs in the World; both
times Mr. Papa was the highest ranked Global Energy CEO. Additionally, Institutional Investor magazine repeatedly ranked him as the Top Independent E&P CEO. He received his B.S. in petroleum
engineering from the University of Pittsburgh and an MBA from the University of Houston. We believe Mr. Papa's significant experience in the energy industry make him well qualified to serve as
a member of the board of directors.
George S. Glyphis
has been our Chief Financial Officer since the closing of the Business Combination. He has served as Vice President and
Chief Financial Officer of Centennial Resource Management, LLC (the "Management Company") since July 2014. Prior to joining the Management Company, Mr. Glyphis served as a Managing
Director in the Oil & Gas Investment Banking practice at
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J.P.
Morgan where his client base comprised primarily upstream and integrated oil and gas companies. In his 21 years at J.P. Morgan, Mr. Glyphis led the origination and execution of
transactions including initial public offerings, equity follow-on offerings, high yield and investment grade bond offerings, corporate mergers and acquisitions, asset acquisition and divestitures, and
reserve-based and corporate lending. Mr. Glyphis earned his B.A. in History from the University of Virginia.
Sean R. Smith
has been our Chief Operating Officer since the closing of the Business Combination. Mr. Smith has served as the Vice
President, Geosciences of CRP since May 2014. Prior to joining CRP, from February 2013 to May 2014, Mr. Smith worked at QEP Resources, where he served in several roles, including as a General
Manager, leading the geoscience, regulatory and reservoir engineering departments for the Williston, Powder River, and Denver Julesburg Basins. Prior to QEP Resources, from 2005 to February 2013,
Mr. Smith worked at Resolute Energy Corporation as a Manager and Geologist. He has also worked in various geotechnical roles at Kerr-McGee and Sanchez Oil & Gas. Mr. Smith earned
his B.A. in Geology from Lawrence University. He is licensed with the Texas Board of Professional Geoscientists and is a member of the American Association of Petroleum Geologists.
Maire A. Baldwin
has served as a director since the closing of the Business Combination. Ms. Baldwin was employed as an Advisor to
EOG from March 2015 until April 2016. Prior to that, she was employed at EOG as Vice President Investor Relations from 1996-2014. Ms. Baldwin has served as a director of the Houston Parks Board
since 2011, a non-profit dedicated to developing parks and green
space to the greater Houston area where she serves on several committees. She is co-founder of Pursuit, a non-profit dedicated to raising funds and awareness of adults with intellectual and
developmental disabilities. Ms. Baldwin has an MBA from the University of Texas at Austin and a B.A. in Economics from the University of Texas at Austin. Ms. Baldwin was selected
to serve on the board of directors due to her extensive experience in the energy industry.
Robert M. Tichio
has served as a director since the closing of the Business Combination. Mr. Tichio is a Partner of Riverstone and
joined Riverstone in 2006. Prior to joining Riverstone, Mr. Tichio was in the Principal Investment Area of Goldman Sachs which manages the firm's private corporate equity investments.
Mr. Tichio began his career at J.P. Morgan in the Mergers & Acquisitions group where he concentrated on assignments that included public company combinations, asset sales, takeover
defenses and leveraged buyouts. In addition to serving on the boards of a number of Riverstone portfolio companies and their affiliates, Mr. Tichio has been a director of Northern Blizzard
Resources Inc. since June 2011 and a director EP Energy Corporation since September 2013. Mr. Tichio previously served as a member of the board of directors of Gibson Energy (TSE:GEI)
from 2008 to 2013 and Midstates Petroleum Company, Inc. from 2012 to 2015. He holds an MBA from Harvard Business School and a bachelor's degree from Dartmouth College. Mr. Tichio was
selected to serve on the board of directors due to his extensive private equity and mergers and acquisitions experience.
Karl E. Bandtel
has served as a director since the closing of the Business Combination. Mr. Bandtel was a Partner at Wellington
Management Company, where he managed energy portfolios, from 1997 until June 30, 2016 when he retired. He holds a Master's degree in business from the University of
WisconsinMadison and a bachelor's degree from University of WisconsinMadison. Mr. Bandtel was selected to serve on the board of directors due to his extensive
experience in investing in energy companies, both public and private.
Jeffrey H. Tepper
has served as a director since the completion of our IPO in February 2016. Mr. Tepper is Founder of JHT
Advisors LLC, an M&A advisory and investment firm. From 1990 to 2013, Mr. Tepper served in a variety of senior management and operating roles at the investment bank Gleacher &
Company, Inc. and its predecessors and affiliates. Mr. Tepper was Head of Investment Banking and a member of the Firm's Management Committee. Mr. Tepper is experienced in
mergers &
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acquisitions,
corporate finance, leveraged finance and asset management. Mr. Tepper is also the former Chief Operating Officer overseeing operations, compliance, technology and financial
reporting. In 2001, Mr. Tepper co-founded Gleacher's asset management activities and served as President. Gleacher managed over $1 billion of institutional capital in the mezzanine
capital and fund of hedge fund areas. Mr. Tepper served on the Investment Committees of Gleacher Mezzanine and Gleacher Fund Advisors. Between 1987 and 1990, Mr. Tepper was employed by
Morgan Stanley & Co. as a financial analyst in the mergers & acquisitions and merchant banking departments. Mr. Tepper received an MBA from Columbia Business School and a
BS in Economics from The Wharton School of the University of
Pennsylvania with concentrations in finance and accounting. Mr. Tepper was selected to serve on the board of directors due to his significant investment and financial experience.
David M. Leuschen
has served as a director since the closing of the Business Combination. Mr. Leuschen is a Founder of Riverstone
and has been a Senior Managing Director since 2000. Prior to founding Riverstone, Mr. Leuschen was a Partner and Managing Director at Goldman Sachs and founder and head of the Goldman Sachs
Global Energy and Power Group. Mr. Leuschen joined Goldman Sachs in 1977, became head of the Global Energy and Power Group in 1985, became a Partner of that firm in 1986 and remained with
Goldman Sachs until leaving to found Riverstone in 2000. Mr. Leuschen also served as Chairman of the Goldman Sachs Energy Investment Committee, where he was responsible for screening potential
capital commitments by Goldman Sachs in the energy and power industry and was responsible for establishing and managing the firm's relationships with senior executives from leading companies in all
segments of the energy and power industry. Mr. Leuschen serves as a non-executive board member of Riverstone Energy Limited (LSE: REL) since May 2013 and serves on the boards of directors or
equivalent bodies of a number of private Riverstone portfolio companies and their affiliates. In 2007, Mr. Leuschen, along with Riverstone and The Carlyle Group ("Carlyle"), became the subject
of an industry-wide inquiry by the Office of the Attorney General of the State of New York (the "Attorney General") relating to the use of placement agents in connection with investments by the New
York State Common Retirement Fund ("NYCRF") in certain funds, including funds that were jointly developed by Riverstone and Carlyle. In June 2009, Riverstone entered into an Assurance of
Discontinuance with the Attorney General to resolve the matter and agreed to make a restitution payment of $30 million to the New York State Office of the Attorney General for the benefit of
NYCRF. Mr. Leuschen also entered into an Assurance of Discontinuance with the Attorney General in December 2009 and agreed that Riverstone and/or Mr. Leuschen would make a restitution
payment of $20 million to the New York State Office of the Attorney General for the benefit of NYCRF. Mr. Leuschen has received an MBA from Dartmouth's Amos Tuck School of Business and
an A.B. degree from Dartmouth College. Mr. Leushen was selected to serve on the board of directors due to his extensive mergers and acquisitions, financing and investing experience in the
energy and power industry.
Pierre F. Lapeyre,
Jr. has served as a director since the closing of the Business Combination. Mr. Lapeyre is a Founder of
Riverstone and has been a Senior Managing Director since 2000. Prior to founding Riverstone, Mr. Lapeyre was a Managing Director of Goldman Sachs in its Global Energy and Power Group.
Mr. Lapeyre joined Goldman Sachs in 1986 and spent his 14-year investment banking career focused on energy and power, particularly the midstream, upstream and energy service sectors.
Mr. Lapeyre serves as a non-executive board member of Riverstone Energy Limited (LSE: REL) since May 2013 and serves on the boards of directors or equivalent bodies of a number of
private Riverstone portfolio companies and their affiliates. He has an MBA from the University of North Carolina at Chapel Hill and a B.S. in Finance and Economics from the University of Kentucky.
Mr. Lapeyre was selected to serve on the board of directors due to his extensive mergers and acquisitions, financing and investing experience in the energy and power industry.
Tony R. Weber
has served as a director since the closing of the Business Combination. Mr. Weber joined Natural Gas Partners in
December 2003 and has served as a Managing Partner since November
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2013.
He previously served Natural Gas Partners in other capacities, including Managing Director from 2007 to November 2013. Prior to joining Natural Gas Partners, Mr. Weber was the Chief
Financial Officer of Merit Energy Company from April 1998 to December 2003. Prior to that, he was Senior Vice President and Manager of Union Bank of California's Energy Division in Dallas, Texas from
1987 to 1998. From September 2011 to September 2016, Mr. Weber served as the Chairman of the Board for Memorial Resource Development, Inc., and from September 2011 to March 2016, he
served as a director of the general partner of Memorial Production Partners LP. Mr. Weber received a B.B.A. in Finance in 1984 from Texas A&M University. Mr. Weber was selected to
serve on the board of directors due to his extensive corporate finance, banking and private equity experience. Mr. Weber was nominated and elected to the board of directors by CRD which, as the
holder of our Series A Preferred Stock, is entitled to nominate and elect one director to the board of directors for so long as the Centennial Contributors hold at least 5,000,000 CRP Common
Units and/or shares of Class A Common Stock (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions).
Board of Directors and Terms of Office of Officers and Directors
We are managed under the direction of our board of directors. Our board of directors is divided into three classes of directors with only one
class of directors being elected in each year and each class (except those directors appointed prior to our first annual meeting of stockholders) serving a three-year term. The term of office of the
first class of directors, consisting of Maire A. Baldwin and Robert M. Tichio, will expire at our first annual meeting of stockholders. The term of office of the second class of directors, Jeffrey H.
Tepper and Karl E. Bandtel, will expire at the second annual meeting of stockholders. The term of office of the third class of directors, consisting of Mark G. Papa, David M. Leuschen and Pierre F.
Lapeyre, Jr., will expire at the third annual meeting of stockholders. In addition, one director, initially Tony R. Weber, will be nominated and elected by CRD as the holder of our Series A
Preferred Stock. The term of office of Mr. Weber will expire at our first annual meeting of stockholders.
Our
board of directors has determined that Ms. Maire A. Baldwin and Messrs. Karl E. Bandtel, Jeffrey H. Tepper and Tony R. Weber are independent within the meaning of
NASDAQ Rule 5605(a)(2).
Officers
are appointed by the board of directors and serve at discretion of the board, rather than for specific terms of office.
Controlled Company Status
Riverstone and its affiliates, including our Sponsor, no longer control a majority of our outstanding voting common stock. As a result, we are
no longer a "controlled company" within the meaning of the NASDAQ listing rules, and will no longer be able to take advantage of exemptions from certain corporate governance requirements.
Specifically, pursuant to the requirements of the NASDAQ listing rules, a majority of our board of directors must consist of independent directors within one year after we cease to be a controlled
company, and we must comply with the independent board committee requirements as they relate to the nominating and corporate governance and compensation committees on the following phase-in schedule:
(1) one independent committee member at the time we cease to be a controlled company, (2) a majority of independent committee members within 90 days of the date we cease to be a
controlled company and (3) all independent committee members within one year of the date we cease to be a controlled company. Our board of directors is not currently comprised of a majority of
independent directors, and neither our corporate governance and nominating committee nor our compensation committee is currently comprised solely of independent directors.
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Board Committees
The standing committees of our board of directors currently consists of an audit committee (the "Audit Committee"), a compensation committee
(the "Compensation Committee") and a corporate governance and nominating committee (the "Corporate Governance and Nominating Committee"). Each of the committees report to the board of directors as
they deem appropriate and as the board may request. The composition, duties and responsibilities of these committees are set forth below.
Audit Committee
The principal functions of our Audit Committee are detailed in the Audit Committee charter, which is available on our website, and
include:
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the appointment, compensation, retention, replacement, and oversight of the work of the independent auditors and any other independent
registered public accounting firm engaged by us;
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pre-approving all audit and permitted non-audit services to be provided by the independent auditors or any other registered public accounting
firm engaged us, and establishing pre-approval policies and procedures;
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reviewing and discussing with the independent auditors all relationships the auditors have with us in order to evaluate their continued
independence;
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setting clear hiring policies for employees or former employees of the independent auditors;
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setting clear policies for audit partner rotation in compliance with applicable laws and regulations;
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obtaining and reviewing a report, at least annually, from the independent auditors describing (i) the independent auditor's internal
quality-control procedures and (ii) any material issues raised by the most recent internal quality-control review, or peer review, of the audit firm, or by any inquiry or investigation by
governmental or professional authorities within the preceding five years respecting one or more independent audits carried out by the firm and any steps taken to deal with such issues;
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reviewing and approving any related party transaction required to be disclosed pursuant to Item 404 of Regulation S-K promulgated
by the SEC prior to us entering into such transaction; and
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reviewing with management, the independent auditors and our legal advisors, as appropriate, any legal, regulatory or compliance matters,
including any correspondence with regulators or government agencies and any employee complaints or published reports that raise material issues regarding our financial statements or accounting
policies and any significant changes in accounting standards or rules promulgated by the Financial Accounting Standards Board, the SEC or other regulatory authorities.
Our
Audit Committee consists of Messrs. Jeffrey H. Tepper and Karl E. Bandtel and Ms. Maire A. Baldwin, with Mr. Tepper serving as the Chair. We believe that
Messrs. Tepper and Bandtel and Ms. Baldwin qualify as independent directors according to the rules and regulations of the SEC with respect to audit committee membership. We also believe
that Mr. Tepper qualifies as our "audit committee financial expert," as such term is defined in Item 401(h) of Regulation S-K.
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Compensation Committee
The principal functions of our Compensation Committee are detailed in the Compensation Committee charter, which is available on our website, and
include:
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reviewing and approving on an annual basis the corporate goals and objectives relevant to our Chief Executive Officer's compensation,
evaluating our Chief Executive Officer's performance in light of such goals and objectives and determining and approving the remuneration (if any) of our Chief Executive Officer based on such
evaluation;
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reviewing and approving on an annual basis the compensation of all of our other officers;
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reviewing on an annual basis our executive compensation policies and plans;
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implementing and administering our incentive compensation equity-based remuneration plans;
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assisting management in complying with our proxy statement and annual report disclosure requirements;
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approving all special perquisites, special cash payments and other special compensation and benefit arrangements for our officers and
employees;
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if required, producing a report on executive compensation to be included in our annual proxy statement;
and
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reviewing, evaluating and recommending changes, if appropriate, to the remuneration for directors.
Our
Compensation Committee consists of Ms. Maire A. Baldwin and Messrs. Pierre F. Lapeyre, Jr., Jeffrey H. Tepper and Robert M. Tichio, with Mr. Lapeyre
serving as the Chair.
The
Compensation Committee may delegate the approval of certain transactions to a subcommittee consisting solely of two or more members of the Compensation Committee who are
"non-employee directors" for the purposes of Rule 16b-3 under the Exchange Act and "outside directors" for the purposes of Section 162(m) of the U.S. Internal Revenue Code of 1986, as
amended (the "Code"). On October 27, 2016, the Compensation Committee created a subcommittee (the "Section 162(m) Plan Subcommittee") consisting of Ms. Baldwin and
Mr. Tepper to administer and make determinations from time to time with respect to awards granted or compensation to be provided under the Centennial Resource Development, Inc. 2016 Long
Term Incentive Plan (the "LTIP") or any successor plan, including compensation that is intended to qualify as "performance-based compensation" under Section 162(m) of the Code, and the
regulations promulgated thereunder. The Compensation Committee has determined that Ms. Baldwin and Mr. Tepper are both "non-employee directors" for the purposes of Rule 16b-3
under the Exchange Act and "outside directors" for the purposes of Section 162(m) of the Code. The charter of the Section 162(m) Plan Subcommittee is available on our website.
Corporate Governance and Nominating Committee
The principal functions of our Corporate Governance and Nominating Committee are detailed in the Corporate Governance and Nominating Committee
charter, which is available on our website, and include:
-
-
assisting the board of directors in identifying individuals qualified to become members of the board of directors, consistent with criteria
approved by the board of directors;
-
-
recommending director nominees for election or for appointment to fill vacancies;
-
-
recommending the election of officer candidates;
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-
-
monitoring the independence of board of director members;
-
-
ensuring the availability of director education programs; and
-
-
advising the board of directors about appropriate composition of the board of directors and its committees.
The
Corporate Governance and Nominating Committee also develops and recommends to the board of directors corporate governance principles and practices and assists in implementing them,
including conducting a regular review of our corporate governance principles and practices. The Corporate Governance and Nominating Committee oversees the annual performance evaluation of the board of
directors and the committees of the board of directors and makes a report to the board of directors on succession planning.
Our
Corporate Governance and Nominating Committee consists of Messrs. David M. Leuschen, Tony R. Weber and Robert M. Tichio, with Mr. Leuschen serving as the Chair.
Compensation Committee Interlocks and Insider Participation
During 2016, no officer or employee served as a member of our Compensation Committee. None of our executive officers serve as a member of the
board of directors or compensation committee of any entity that has one or more executive officers serving on our board of directors or Compensation Committee.
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EXECUTIVE AND DIRECTOR COMPENSATION
Executive Compensation
The following disclosure describes the material elements of the compensation of the Company's named executive officers for 2016 and is presented
based on the reduced disclosure rules applicable to the Company as an "emerging growth company" within the meaning of the Securities Act. For 2016, our named executive officers
were:
-
-
Mark G. Papa, President and Chief Executive Officer;
-
-
George S. Glyphis, Chief Financial Officer; and
-
-
Sean R. Smith, Chief Operating Officer.
Mr. Papa
has been our Chief Executive Officer and a director since November 2015 and has served as our President since the closing of the Business Combination. Prior to the
closing of the Business Combination, we did not pay Mr. Papa any compensation for services rendered to us. During 2016 and through the closing of the Business Combination,
Messrs. Glyphis and Smith were employees of CRD or one of its affiliates. Since the closing of the Business Combination, Mr. Glyphis has served as our Chief Financial Officer and
Mr. Smith has served as our Chief Operating Officer.
2016 Summary Compensation Table
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name and Principal Position
|
|
Year
|
|
Salary
($)
|
|
Bonus
($)(2)
|
|
Option
Awards
($)(3)
|
|
All Other
Compensation
($)(4)
|
|
Total
($)
|
|
Mark G. Papa, President and Chief Executive Officer(1)
|
|
2016
|
|
|
148,485
|
|
|
|
|
|
5,860,000
|
|
|
|
|
|
6,008,485
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
George S. Glyphis, Chief Financial Officer
|
|
2016
|
|
|
293,087
|
|
|
|
|
|
1,465,000
|
|
|
13,583
|
|
|
1,771,670
|
|
|
|
2015
|
|
|
275,000
|
|
|
68,750
|
|
|
|
|
|
25,077
|
|
|
368,827
|
|
Sean R. Smith, Chief Operating Officer
|
|
2016
|
|
|
308,469
|
|
|
|
|
|
1,758,000
|
|
|
13,708
|
|
|
2,080,177
|
|
-
(1)
-
Although
Mr. Papa has been our Chief Executive Officer and a director since November 2015, he did not receive any compensation from us until after the closing
of the Business Combination.
-
(2)
-
The
amount of any bonus payments to be made to our named executive officers for services performed in 2016 has not yet been determined. We expect that the these
amounts will be determined in the first quarter of 2017.
-
(3)
-
Amounts
in this column reflect the aggregate grant date fair value of stock options granted during 2016 computed in accordance with ASC Topic 718, excluding the
effect of estimated forfeitures. All of the stock options have an exercise price of $14.52, which was the closing price of our Class A Common Stock on the date of grant. We calculated the grant
date fair value of the stock options using a Black-Scholes option pricing model and the following assumptions: a volatility of 40%, an option term of six years, a risk-free interest rate of 1.47%, a
dividend yield of zero and a grant date fair value of our Class A Common Stock of $14.52.
-
(4)
-
Amounts
in this column reflect, for all named executive officers, matching contributions to the 401(k) Plan made on their behalf for 2016. See
"Narrative DisclosuresRetirement Benefits" for more information on matching contributions to the 401(k) Plan.
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Outstanding Equity Awards at 2016 Fiscal Year-End
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|
|
|
|
|
|
|
|
|
|
|
Option Awards
|
Name
|
|
Grant Date
|
|
Number of
Securities
Underlying
Unexercised
Options,
Exercisable
(#)
|
|
Number of
Securities
Underlying
Unexercised
Options,
Unexercisable
(#)(1)
|
|
Option
Exercise
Price
($)
|
|
Option
Expiration
Date
|
Mark G. Papa
|
|
10/27/16
|
|
|
|
|
|
1,000,000
|
|
|
14.52
|
|
10/26/26
|
George S. Glyphis
|
|
10/27/16
|
|
|
|
|
|
250,000
|
|
|
14.52
|
|
10/26/26
|
Sean R. Smith
|
|
10/27/16
|
|
|
|
|
|
300,000
|
|
|
14.52
|
|
10/26/26
|
-
(1)
-
All
options vest in three substantially equal annual installments on each of the first three anniversaries of the grant date, subject to the holder's continued
employment with us through the applicable vesting date.
Narrative Disclosures
Although Mr. Papa has been our Chief Executive Officer and a director since November 2015, he did not receive any compensation from us
until after the closing of the Business Combination. During 2016 and through the closing of the Business Combination, Messrs. Glyphis and Smith had annual base salaries of $275,000 and $283,250
respectively. Effective as of the closing of the Business Combination, the Compensation Committee approved an annual base salary for Mr. Papa and annual base salaries and annual target bonuses
(expressed as a percentage of annual base salary) for Messrs. Glyphis and Smith, as set forth in the following table:
|
|
|
|
|
|
|
|
Named Executive Officer
|
|
Annual Base
Salary
($)
|
|
Target
Bonus
(%)
|
|
Mark G. Papa
|
|
|
800,000
|
|
|
|
|
George S. Glyphis
|
|
|
350,000
|
|
|
100
|
|
Sean R. Smith
|
|
|
385,000
|
|
|
100
|
|
The
amount of any bonus payments to be made to our named executive officers for services performed in 2016 has not yet been determined. Our board of directors or the Compensation
Committee will determine the 2016 annual bonus amounts for our named executive officers in its discretion based on performance and other factors that our board of directors or the Compensation
Committee determines are appropriate. We expect that the bonuses will be determined in the first quarter of 2017.
In connection with the closing of the Business Combination, our board of directors adopted and our stockholders approved the LTIP, which is
described below under "2016 Long Term Incentive Plan." On October 27, 2016, our Section 162(m) Plan Subcommittee granted Messrs. Papa, Glyphis and Smith options to
purchase 1,000,000, 250,000 and 300,000 shares of our Class A Common Stock, respectively, under the LTIP at an exercise price per share of $14.52, which was the closing price of our
Class A Common Stock on the date of grant. The options will vest and become exercisable in three substantially equal annual installments on each of the first three anniversaries of the date of
grant, subject to the executive officer's continued service with us.
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Table of Contents
Mr. Papa is an advisor to Riverstone. We currently anticipate Mr. Papa will spend approximately 60% of his working time providing
services for us as our President and Chief Executive Officer and approximately 40% of his working time providing services to Riverstone on matters unrelated to the Company. Since the closing of the
Business Combination, this has been the approximate allocation of Mr. Papa's working time. The Compensation Committee and the Section 162(m) Plan Subcommittee were aware of
Mr. Papa's continued service to Riverstone and considered it when determining an appropriate level of compensation for services as our President and Chief Executive Officer.
Employment, Severance or Change in Control Agreements
The Company has not entered into any employment, severance or change in control agreements with its named executive officers. In addition, the
Company's named executive officers are not entitled to any payments or other benefits in connection with a termination of employment or a change in control.
Our named executive officers are eligible to participate in our employee benefit plans and programs, including medical and dental benefits and
life insurance, to the same extent as our other full-time employees, subject to the terms and eligibility requirements of those plans. We also sponsor a 401(k) defined contribution plan (the
"401(k) Plan") in which our named executive officers may participate, subject to limits imposed by the Code, to the same extent as our other full-time employees. The 401(k) Plan provides for matching
contributions equal to 100% of the first 6% of employees' eligible compensation contributed to the 401(k) Plan. Employees are immediately 100% vested in the matching contributions. We do not typically
provide any perquisites or special personal benefits to our named executive officers, but have from time to time reimbursed relocation expenses for our named executive officers.
Compensation of Directors
Prior to the closing of the Business Combination, our directors received no compensation for their service on our board of directors. Since the
closing of the Business Combination, directors employed by us or affiliated with Riverstone or Natural Gas Partners have continued to receive no compensation for serving on our board of directors or
its committees. Effective October 11, 2016, our board of directors approved for each of Maire A. Baldwin, Karl E. Bandtel and Jeffrey H. Tepper an annual retainer of $87,500 per year in cash
for service on our board of directors and its committees, payable quarterly in arrears and subject to proration for any partial year of service. In addition, our board of directors granted each of
Ms. Baldwin and Messrs. Bandtel and Tepper 11,218 restricted shares of our Class A Common Stock under the LTIP, which will vest in a single installment on October 11, 2017.
The board of directors anticipates that it will consider additional annual awards of restricted shares under our LTIP in the future that are intended to result in a total annual value of cash and
equity-based compensation of approximately $250,000 being paid to Ms. Baldwin and Messrs. Bandtel and Tepper for service on our board of directors.
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|
|
|
|
|
|
|
|
|
|
|
Name
|
|
Fees earned or
paid in cash
($)
|
|
Stock awards
($)(1)
|
|
Total
($)
|
|
Maire A. Baldwin
|
|
|
19,658
|
|
|
224,677
|
|
|
244,335
|
|
Karl E. Bandtel
|
|
|
19,658
|
|
|
224,677
|
|
|
244,335
|
|
Jeffrey H. Tepper
|
|
|
19,658
|
|
|
224,677
|
|
|
244,335
|
|
Robert M. Tichio
|
|
|
|
|
|
|
|
|
|
|
David M. Leuschen
|
|
|
|
|
|
|
|
|
|
|
Pierre F. Lapeyre, Jr.
|
|
|
|
|
|
|
|
|
|
|
Tony R. Weber
|
|
|
|
|
|
|
|
|
|
|
William D. Gutermuth(2)
|
|
|
|
|
|
|
|
|
|
|
Diana J. Walters(2)
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Amounts
in this column reflect the aggregate grant date fair value of restricted shares computed in accordance with ASC Topic 718. Each of Ms. Baldwin and
Messrs. Bandtel and Tepper held 11,218 unvested shares of our restricted stock as of December 31, 2016. None of our non-employee directors held any of our stock options or other equity
awards as of such date.
-
(2)
-
Mr. Gutermuth
and Ms. Walters resigned from our board of directors effective as of the closing of the Business Combination.
2016 Long Term Incentive Plan
In connection with the closing of the Business Combination, our board of directors adopted and our stockholders approved the LTIP, under which
we may grant cash and equity-based incentive awards to eligible service providers in order to attract, retain and motivate the persons who make important contributions to our company. The material
terms of the LTIP are summarized below.
Our employees, consultants and directors, and employees and consultants of our subsidiaries, are eligible to receive awards under the LTIP. The
LTIP is administered by our board of directors, which may delegate its duties and responsibilities to one or more committees of our directors and/or officers (referred to collectively as the "plan
administrator"), subject to the limitations imposed under the LTIP, Section 16 of the Exchange Act, stock exchange rules and other applicable laws. The plan administrator has the authority to
take all actions and make all determinations under the LTIP, to interpret the LTIP and award agreements and to adopt, amend and repeal rules for the administration of the LTIP as it deems advisable.
The plan administrator also has the authority to determine which eligible service providers receive awards, grant awards and set the terms and conditions of all awards under the LTIP, including any
vesting and vesting acceleration provisions, subject to the conditions and limitations in the LTIP. Our board of directors has delegated certain limited authority to our Chief Executive Officer to
grant options and awards of restricted stock under the LTIP and created the 162(m) Plan Subcommittee to administer and make determinations from time to time with respect to awards granted or
compensation to be provided under the LTIP.
An aggregate of 16,500,000 shares of Class A Common Stock have been reserved for issuance under the LTIP, all of which may be issued upon
the exercise of incentive stock options. Shares issued under the LTIP may be authorized but unissued shares, shares purchased on the open market or
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treasury
shares. As of January 18, 2017, a total of 2,829,000 stock options and 320,805 shares of restricted stock were outstanding under the LTIP.
If
an award under the LTIP expires, lapses or is terminated, exchanged for cash, surrendered, repurchased, canceled without having been fully exercised or forfeited, any unused shares
subject to the award will again be available for new grants under the LTIP. Further, shares delivered to satisfy the purchase price or tax withholding obligation for any award other than an option or
stock appreciation right will again be available for new grants under the LTIP. However, the LTIP does not allow the
shares available for grant under the LTIP to be recharged or replenished with shares that:
-
-
are tendered or withheld to satisfy the exercise price of an option;
-
-
are tendered or withheld to satisfy tax withholding obligations for any award that is an option or stock appreciation right;
-
-
are subject to a stock appreciation right but are not issued in connection with the stock settlement of the stock appreciation right;
or
-
-
are purchased on the open market with cash proceeds from the exercise of options.
Awards
granted under the LTIP in substitution for any options or other stock or stock-based awards granted by an entity before the entity's merger or consolidation with us (or any of our
subsidiaries) or our (or any of our subsidiary's) acquisition of the entity's property or stock will not reduce the shares available for grant under the LTIP, but will count against the maximum number
of shares that may be issued upon the exercise of incentive stock options.
The maximum aggregate number of shares of Class A Common Stock with respect to which one or more awards of options or stock appreciation
rights may be granted under the LTIP to any one person during any fiscal year is 1,000,000 shares of Class A Common Stock; and the maximum aggregate number of shares of Class A Common
Stock with respect to which one or more awards of restricted stock, restricted stock units, or other stock or cash based awards that are denominated in
shares intended to qualify as performance-based compensation under Section 162(m) of the Code (as described below) may be granted under the LTIP to any one person during any fiscal year is
1,000,000 shares of Class A Common Stock. However, these numbers may be adjusted to take into account equity restructurings and certain other corporate transactions as described below. The
maximum amount of cash that may be paid to any one person during any fiscal year with respect to one or more awards payable in cash and not denominated in shares is $5,000,000.
The LTIP provides for the grant of stock options, including incentive stock options ("ISOs") and nonqualified stock options ("NSOs"), stock
appreciation rights ("SARs"), restricted stock, dividend equivalents, restricted stock units ("RSUs") and other stock or cash based awards. Certain awards under the LTIP may constitute or provide for
payment of "nonqualified deferred compensation" under Section 409A of the Code. All awards under the LTIP will be set forth in award agreements, which will detail the terms and conditions of
awards, including any applicable vesting and payment terms and post-termination exercise limitations. A brief description of each award type follows.
-
-
Stock Options and SARs.
Stock options provide for the purchase of shares of
Class A Common Stock in the future at an exercise price set on the grant date. ISOs, in contrast to NSOs, may provide tax deferral beyond exercise and favorable capital gains tax treatment to
their holders if certain holding period and other requirements of the Code are satisfied. SARs entitle their holder, upon exercise, to receive from us an amount equal to the appreciation of the shares
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subject
to the award between the grant date and the exercise date. The plan administrator will determine the number of shares covered by each option and SAR, the exercise price of each option and SAR
and the conditions and limitations applicable to the exercise of each option and SAR. The exercise price of a stock option or SAR will not be less than 100% of the fair market value of the underlying
share on the grant date (or 110% in the case of ISOs granted to certain significant stockholders), except with respect to certain substitute awards granted in connection with a corporate transaction.
The term of a stock option or SAR may not be longer than ten years (or five years in the case of ISOs granted to certain significant stockholders).
-
-
Restricted Stock.
Restricted stock is an award of nontransferable shares of
Class A Common Stock that remain forfeitable unless and until specified conditions are met and which may be subject to a purchase price. Upon issuance of restricted stock, recipients generally
have the rights of a stockholder with respect to such shares, which generally include the right to receive dividends and other distributions in relation to the award; however, dividends may be paid
with respect to restricted stock with performance-based vesting only to the extent the performance conditions have been satisfied and the restricted stock vests. The terms and conditions applicable to
restricted stock will be determined by the plan administrator, subject to the conditions and limitations contained in the LTIP.
-
-
RSUs.
RSUs are contractual promises to deliver shares of Class A
Common Stock in the future, which may also remain forfeitable unless and until specified conditions are met and may be accompanied by the right to receive the equivalent value of dividends paid on
shares of Class A Common Stock prior to the delivery of the underlying shares (i.e., dividend equivalent rights); however, dividend equivalents with respect to an award with
performance-based vesting that are based on dividends paid prior to the vesting of such award will only be paid out to the holder to the extent that the performance-based vesting conditions are
subsequently satisfied and the award vests. The plan administrator may provide that the delivery of the shares underlying RSUs will be deferred on a mandatory basis or at the election of the
participant. The terms and conditions applicable to RSUs will be determined by the plan administrator, subject to the conditions and limitations contained in the LTIP.
-
-
Other Stock or Cash Based Awards.
Other stock or cash based awards are
awards of cash, fully vested shares of Class A Common Stock and other awards valued wholly or partially by referring to, or otherwise based on, shares of Class A Common Stock or other
property. Other stock or cash based awards may be granted to participants and may also be available as a payment form in the settlement of other awards, as standalone payments and as payment in lieu
of compensation to which a participant is otherwise entitled. The plan administrator will determine the terms and conditions of other stock or cash based awards, which may include any purchase price,
performance goal, transfer restrictions and vesting conditions.
The plan administrator will determine whether specific performance awards are intended to constitute "qualified performance-based compensation"
within the meaning of Section 162(m) of the Code and will have discretion to pay compensation that is not qualified performance-based compensation and that is not tax deductible. Under
Section 162(m), a "covered
employee" is our Chief Executive Officer and certain of our other most highly compensated executive officers. Section 162(m) imposes a $1 million cap on the compensation deduction that
we may take in respect of compensation paid to covered employees; however, compensation that qualifies as qualified performance-based compensation is excluded from the calculation of the
$1 million cap.
In
order to constitute qualified performance-based compensation under Section 162(m), in addition to certain other requirements, the relevant amounts must be payable only upon the
attainment
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of
pre-established, objective performance goals set by the plan administrator and based on stockholder-approved performance criteria. Our stockholders have approved the below performance criteria.
For
purposes of the LTIP, one or more of the following performance criteria will be used in setting performance goals applicable to qualified performance-based compensation, either for
the entire company or a subsidiary, division, business unit or an individual, and may be used in setting performance goals applicable to other stock or cash based awards: net earnings or losses
(either before or after one or more of interest, taxes, depreciation, amortization, and non-cash equity-based compensation expense); gross or net sales or revenue or sales or revenue growth; net
income (either before or after taxes) or adjusted net income; profits (including but not limited to gross profits, net profits, profit growth, net operation profit or economic profit), profit return
ratios or operating margin; budget or operating earnings (either before or after taxes or before or after allocation of corporate overhead and bonus); cash flow (including operating cash flow and free
cash flow or cash flow return on capital); return on assets; return on capital or invested capital; cost of capital; return on stockholders' equity; total stockholder return; return on sales; costs,
reductions in costs and cost control measures; expenses; working capital; earnings or loss per share; adjusted earnings or loss per share; price per share or dividends per share (or appreciation in or
maintenance of such price or dividends); regulatory achievements or compliance; implementation, completion or attainment of objectives relating to research, development, regulatory, commercial, or
strategic milestones or developments; market share; economic value or economic value added models; division, group or corporate financial goals; individual business objectives; production or growth in
production; reserves or added reserves; growth in reserves per share; inventory growth; environmental, health and/or safety performance; effectiveness of hedging programs; improvements in internal
controls and policies and procedures; customer satisfaction/growth; customer service; employee satisfaction; recruitment and maintenance of personnel; human resources management; supervision of
litigation and other legal matters; strategic partnerships and transactions; financial ratios (including those measuring liquidity, activity, profitability or leverage); debt levels or reductions;
sales-related goals; financing and other capital raising transactions; cash on hand; acquisition activity; investment sourcing activity; and marketing initiatives, any of which may be measured in
absolute terms or as compared to any incremental increase or decrease. Such performance goals also may be based solely by reference to the company's performance or the performance of a subsidiary,
division, business segment or business unit of the company or a subsidiary, or based upon performance relative to performance of other companies or upon comparisons of any of the indicators of
performance relative to performance of other companies. When determining performance goals, the
plan administrator may provide for exclusion of the impact of an event or occurrence which the plan administrator determines should appropriately be excluded, including, without limitation,
non-recurring charges or events, acquisitions or divestitures, changes in the corporate or capital structure, events unrelated to the business or outside of the control of management, foreign exchange
considerations, and legal, regulatory, tax or accounting changes.
Under the LTIP, the plan administrator may not except in connection with equity restructurings and certain other corporate transactions as
described below, without the approval of our stockholders, authorize the repricing of any outstanding option or SAR to reduce its price per share, or cancel any option or SAR in exchange for cash or
another award when the price per share exceeds the Fair Market Value (as that term is defined in the LTIP) of the underlying shares.
In connection with certain corporate transactions and events affecting our Class A Common Stock, including a change in control, or change
in any applicable laws or accounting principles, the plan administrator has broad discretion to take action under the LTIP to prevent the dilution or
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enlargement
of intended benefits, facilitate the transaction or event or give effect to the change in applicable laws or accounting principles. This includes canceling awards for cash or property,
accelerating the vesting of awards, providing for the assumption or substitution of awards by a successor entity, adjusting the number and type of shares subject to outstanding awards and/or with
respect to which awards may be granted under the LTIP and replacing or terminating awards under the LTIP. In addition, in the event of certain non-reciprocal transactions with our stockholders, the
plan administrator will make equitable adjustments to the LTIP and outstanding awards as it deems appropriate to reflect the transaction.
The LTIP provides that the plan administrator may establish compensation for non-employee directors from time to time subject to the LTIP's
limitations. The plan administrator will from time to time determine the terms, conditions and amounts of all non-employee director compensation in its discretion and pursuant to the exercise of its
business judgment, taking into account such factors, circumstances and considerations as it shall deem relevant from time to time, provided that the sum of any cash compensation or other compensation
and the grant date fair value of any equity awards granted under the LTIP as compensation for services as a non-employee director during any fiscal year may not exceed $500,000. The plan administrator
may make exceptions to this limit for individual non-employee directors in extraordinary circumstances, as the plan administrator may determine in its discretion, subject to the limitations in the
LTIP.
Our board of directors may amend or terminate the LTIP at any time; however, no amendment, other than an amendment that increases the number of
shares available under the LTIP, may materially and adversely affect an award outstanding under the LTIP without the consent of the affected participant and stockholder approval will be obtained for
any amendment to the extent necessary to comply with applicable laws. The LTIP will remain in effect until the tenth anniversary of the date our board of directors adopted the LTIP, unless earlier
terminated by our board of directors. No awards may be granted under the LTIP after its termination.
Foreign Participants, Claw-back Provisions, Transferability and Participant Payments
The plan administrator may modify awards granted to participants who are foreign nationals or employed outside the United States or establish
subplans or procedures to address differences in laws, rules, regulations or customs of such foreign jurisdictions. All awards will be subject to any company claw-back policy as set forth in such
claw-back policy or the applicable award agreement. Except as the plan administrator may determine or provide in an award agreement, awards under the LTIP are generally non-transferrable, except by
will or the laws of descent and distribution, or, subject to the plan administrator's consent, pursuant to a domestic relations order, and are generally exercisable only by the participant. With
regard to tax withholding obligations arising in connection with awards under the LTIP, and exercise price obligations arising in connection with the exercise of stock options under the LTIP, the plan
administrator may, in its discretion, accept cash, wire
transfer or check, shares of Class A Common Stock that meet specified conditions, a promissory note, a "market sell order," such other consideration as the plan administrator deems suitable or
any combination of the foregoing.
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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Founder Shares
On November 6, 2015, our Sponsor purchased 11,500,000 shares of Class B Common Stock, the founder shares, from us, for an
aggregate purchase price of $25,000, or approximately $0.002 per share. In February 2016, our Sponsor transferred 40,000 founder shares to each of our then independent directors (together with our
Sponsor, the "initial stockholders") at their original purchase price. On February 24, 2016, we effected a stock dividend of approximately 0.125
shares for each outstanding share of Class B Common Stock, resulting in the initial stockholders holding an aggregate of 12,937,500 founder shares. On April 8, 2016, following the
expiration of the underwriters' remaining over-allotment option in connection with our IPO, our Sponsor forfeited 437,500 founder shares, so that the remaining 12,500,000 founder shares held by the
initial stockholders would represent 20% of our then issued and outstanding shares of common stock. On October 11, 2016, all of the outstanding founder shares were automatically converted into
shares of Class A Common Stock on a one-for-one basis in connection with the closing of the Business Combination.
The
initial stockholders have agreed, subject to limited exceptions, not to transfer, assign or sell any of their shares of Class A Common Stock received upon conversion of their
founder shares until the earlier to occur of: (A) one year after the closing of the Business Combination or (B) subsequent to the Business Combination, (x) if the last sale price
of the Class A Common Stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and the like) for any 20 trading days within
any 30 trading day period commencing at least 150 days after the closing of the Business Combination, or (y) the date on which we complete a liquidation, merger, stock exchange or other
similar transaction that results in all of our stockholders having the right to exchange their shares of common stock for cash, securities or other property.
Administrative Support Agreement
On February 23, 2016, we entered into an administrative support agreement pursuant to which we agreed to pay an affiliate of our Sponsor
a total of $10,000 per month for office space, utilities and secretarial and administrative support. We paid the affiliate of our Sponsor $30,000 and $40,000 for such services for the three and six
months ended June 30, 2016, respectively. Following the closing of the Business Combination, we no longer pay these monthly fees.
Private Placement Warrants
On February 29, 2016, our Sponsor purchased from us 8,000,000 Private Placement Warrants at a price of $1.50 per whole warrant
($12,000,000 in the aggregate) in a private placement that occurred simultaneously with the closing of our IPO. Each whole Private Placement Warrant is exercisable for one whole share of
Class A Common Stock at a price of $11.50 per share. A portion of the purchase price of the Private Placement Warrants was placed in our trust account along with the proceeds from our IPO. The
Private Placement Warrants are non-redeemable and exercisable on a cashless basis so long as they are held by our Sponsor or its permitted transferees.
Related Party Loans
On November 6, 2015, our Sponsor agreed to loan us an aggregate of up to $300,000 to cover expenses related to our IPO pursuant to a
promissory note (the "2015 Note"). The 2015 Note was non-interest bearing and payable on the earlier of March 31, 2016 or the completion of our IPO. On November 10, 2015, we borrowed
$150,000 under the 2015 Note, and we borrowed the remaining $150,000 under the 2015 Note in February 2016. On February 29, 2016, the full $300,000 balance of the 2015 Note was repaid to our
Sponsor.
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Table of Contents
On
August 2, 2016, we issued an unsecured, non-interest bearing promissory note to our Sponsor (the "2016 Note"). We borrowed $300,000 under the 2016 Note, and repaid the full
$300,000 balance upon the closing of the Business Combination on October 11, 2016.
Agreements Relating to Our Business Combination
Subscription Agreements
In connection with the Business Combination, on July 21, 2016, we entered into subscription agreements with certain investors pursuant to
which such investors purchased, in the aggregate, 20,000,000 shares of Class A Common Stock at the closing of the Business Combination for an aggregate purchase price of $200 million. On
the same date, the Company entered into a separate subscription agreement with Riverstone Centennial, pursuant to which Riverstone Centennial purchased 81,005,000 shares of Class A Common Stock
at the closing of the Business Combination for an aggregate purchase price of approximately $810 million.
Amended and Restated Limited Liability Company Agreement of CRP
In connection with the closing of the Business Combination, on October 11, 2016, we and the Centennial Contributors entered into CRP's
fifth amended and restated limited liability company agreement (the "A&R LLC Agreement"). The operations of CRP, and the rights and obligations of the holders of CRP Common Units, are set forth
in the A&R LLC Agreement.
Appointment as Manager.
Under the A&R LLC Agreement, we are a member and the sole manager of CRP. As the sole manager,
we are able to control
all of the day-to-day business affairs and decision-making of CRP without the approval of any other member, unless otherwise stated in the A&R LLC Agreement. As such, we, through our officers
and directors, are responsible for all operational and administrative decisions of CRP and the day-to-day management of CRP's business. Pursuant to the terms of the A&R LLC Agreement, we
cannot, under any circumstances, be removed as the sole manager of CRP except by our election.
Compensation.
We are not entitled to compensation for our services as manager. We are entitled to reimbursement by CRP for any
reasonable
out-of-pocket expenses incurred on behalf of CRP, including all of our fees, expenses and costs of being a public company (including public reporting obligations, proxy statements, stockholder
meetings, stock exchange fees, transfer agent fees, SEC and FINRA filing fees and offering expenses) and maintaining our corporate existence.
Recapitalization.
The A&R LLC Agreement provides for the exchange of all outstanding membership interests of CRP held by
the Centennial
Contributors prior to the closing of the Business Combination for newly issued CRP Common Units at the closing. Each CRP Common Unit entitles the holder to a pro rata share of the net profits and net
losses and distributions of CRP.
Distributions.
The A&R LLC Agreement allows for distributions to be made by CRP to its members on a pro rata basis out
of "distributable cash"
(as defined in the A&R LLC Agreement). We expect CRP may make distributions out of distributable cash periodically to the extent permitted by the debt agreements of CRP and necessary to enable
us to cover our operating expenses and other obligations, as well as to make dividend payments, if any, to the holders of our Class A Common Stock. In addition,
the A&R LLC Agreement generally requires CRP to make pro rata distributions to its members, including us, in an amount at least sufficient to allow us to pay our taxes.
CRP Common Unit Redemption Right.
The A&R LLC Agreement provides a redemption right to the Centennial Contributors
which entitles them to
cause CRP to redeem, from time to time, all or a portion of their CRP Common Units for, at CRP's option, newly-issued shares of our Class A Common Stock on a one-for-one basis or a cash payment
equal to the average of the volume-weighted closing
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Table of Contents
price
of one share of Class A Common Stock for the five trading days prior to the date the Centennial Contributors deliver a notice of redemption for each CRP Common Unit redeemed (subject to
customary adjustments, including for stock splits, stock dividends and reclassifications). In the event of a "reclassification event" (as defined in the A&R LLC Agreement), the manager is to
ensure that each CRP Common Unit is redeemable for the same amount and type of property, securities or cash that a share of Class A Common Stock becomes exchangeable for or converted into as a
result of such "reclassification event." Upon the exercise of the redemption right, the Centennial Contributor will surrender its CRP Common Units to CRP for cancellation. The A&R LLC Agreement
requires that we contribute cash or shares of our Class A Common Stock to CRP in exchange for a number of CRP Common Units in CRP equal to the number of CRP Common Units to be redeemed from the
Centennial Contributor. CRP will then distribute such cash or shares of our Class A Common Stock to such Centennial Contributor to complete the redemption. Upon the exercise of the redemption
right, we may, at our option, effect a direct exchange of cash or our Class A Common Stock for such CRP Common Units in lieu of such a redemption. Upon the redemption or exchange of CRP Common
Units held by a Centennial Contributor, a corresponding number of shares of Class C Common Stock will be canceled.
Change of Control.
In connection with the occurrence of a "manager change of control" (as defined below), we have the right to
require each member of
CRP (other than us) to cause CRP to redeem some or all of such member's CRP Common Units and a corresponding number of shares of Class C Common Stock, in each case, effective immediately prior
to the consummation of the manager change of control. From and after the date of such redemption, the CRP Common Units and shares of Class C Common Stock subject to such redemption will be
deemed to be transferred to us and each such member will cease to have any rights with respect to the CRP Common Units and shares of Class C Common Stock subject to such redemption (other than
the right to receive shares of Class A Common Stock pursuant to such redemption). A "manager change of control" will be deemed to have occurred if or upon: (i) the consummation of a
sale, lease or transfer of all or substantially all of our assets (determined on a consolidated basis) to any person or "group" (as such term is used in Section 13(d)(3)) that has been approved
by our stockholders and board of directors, (ii) a merger or consolidation of the Company with any other person (other than a transaction in which our voting
securities outstanding immediately prior to the transaction continue to represent at least 50.01% of our or the surviving entity's total voting securities following the transaction) that has been
approved by our stockholders and board of directors or (iii) subject to certain exceptions, the acquisition by any person or "group" (as such term is used in Section 13(d)(3)) of
beneficial ownership of at least 50.01% of our voting securities, if recommended or approved by our board of directors or determined by our board of directors to be in our and our stockholders' best
interests.
Maintenance of One-to-One Ratios.
The A&R LLC Agreement includes provisions intended to ensure that we at all times
maintain a one-to-one
ratio between (a) the number of outstanding shares of Class A Common Stock and the number of CRP Common Units owned by us (subject to certain exceptions for certain rights to purchase
our equity securities under a "poison pill" or similar shareholder rights plan, if any, certain convertible or exchangeable securities issued under our equity compensation plans and certain equity
securities issued pursuant to our equity compensation plans (other than a stock option plan) that are restricted or have not vested thereunder) and (b) the number of outstanding shares of our
Class C Common Stock and the number of CRP Common Units owned by the Centennial Contributors. This construct is intended to result in the Centennial Contributors having a voting interest in the
Company that is identical to the Centennial Contributors' economic interest in CRP.
Transfer Restrictions.
The A&R LLC Agreement generally does not permit transfers of CRP Common Units by members, subject
to limited
exceptions. Any transferee of CRP Common Units must
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Table of Contents
assume,
by operation of law or written agreement, all of the obligations of a transferring member with respect to the transferred units, even if the transferee is not admitted as a member of CRP.
Dissolution.
The A&R LLC Agreement provides that the unanimous consent of all members will be required to voluntarily
dissolve CRP. In
addition to a voluntary dissolution, CRP will be dissolved upon a change of control transaction under certain circumstances, as well as upon the entry of a decree of judicial dissolution or other
circumstances in accordance with Delaware law. Upon a dissolution event, the proceeds of a liquidation will be distributed in the following order: (i) first, to pay the expenses of winding up
CRP; (ii) second, to pay debts and liabilities owed to creditors of CRP; and (iii) third, to the members pro-rata in accordance with their respective percentage ownership interests in
CRP (as determined based on the number of CRP Common Units held by a member relative to the aggregate number of all outstanding CRP Common Units).
Confidentiality.
Each member has agreed to maintain the confidentiality of CRP's confidential information. This obligation
excludes information
independently obtained or developed by the members, information that is in the public domain or otherwise disclosed to a member, in either such case not in violation of a confidentiality obligation or
disclosures required by law or judicial process or approved by our chief executive officer.
Indemnification and Exculpation.
The A&R LLC Agreement provides for indemnification of the manager, members and officers
of CRP and their
respective subsidiaries or affiliates and provides that, except as otherwise provided therein, we, as the managing member of CRP, have the same fiduciary duties to CRP and its members as are owed to a
corporation organized under Delaware law and its stockholders by its directors.
Amended and Restated Registration Rights Agreement
In connection with the closing of the Business Combination, on October 11, 2016, the Company entered into an amended and restated
registration rights agreement (the "Registration Rights Agreement") with our Sponsor, certain of our former and current directors, Riverstone Centennial Holdings, L.P. ("Riverstone Centennial")
and the Centennial Contributors, pursuant to which such parties are entitled to certain registration rights relating to (i) shares of our Class A Common Stock issued to our Sponsor and
such former and current directors upon the conversion of their founder shares at the closing of the Business Combination, (ii) the Private Placement Warrants and warrants that may be issued
upon conversion of working capital loans (and any shares of Class A Common Stock issuable upon the exercise of such warrants), (iii) the shares of Class A Common Stock that have
been or may be issued from time to time to certain members of CRP who own CRP Common Units upon the redemption or exchange by such members of CRP Common Units for shares of Class A Common Stock
(the "Centennial Holder Shares") and (iv) the shares of Class A Common Stock issued to Riverstone Centennial in the Business Combination Private Placement (collectively, the "Registrable
Securities").
The
holders of a majority of the Registrable Securities (other than the securities identified in clauses (iii) and (iv) of the preceding paragraph) are entitled to make up
to three demands, excluding short form demands, that we register the resale of such securities, while holders of a majority of the Registrable Securities owned by Riverstone Centennial and its
permitted transferees are entitled to five demands, excluding short form demands, that we register the resale of such securities. Additionally, the holders of a majority of the Centennial Holder
Shares are entitled to demand one underwritten offering if the offering is reasonably expected to result in gross proceeds of more than $50 million. In connection with this Amended and Restated
Registration Rights Agreement, we filed a Registration Statement on Form S-1 that was declared effective on November 21, 2016.
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Table of Contents
The
holders also have certain "piggy-back" registration rights with respect to registration statements and rights to require us to register for resale such securities pursuant to
Rule 415 under the Securities Act. However, the Registration Rights Agreement provides that we will not permit any registration statement filed under the Securities Act with respect to the
founder shares and the Private Placement Warrants and the shares of Class A Common Stock underlying such Private Placement Warrants to become effective until termination of the applicable
lock-up period, which occurs (i) in the case of the founder shares, on the earlier of (A) October 11, 2017, (B) if the last sale price of our Class A Common Stock
equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and other similar transactions) for any 20 trading days within any 30-trading day
period commencing at least 150 days after the Business Combination Closing Date, or (C) the date on which we complete a liquidation, merger, capital stock exchange, reorganization or
other similar transaction that results in all of our stockholders having the right to exchange their shares of common stock for cash, securities or other property and (ii) in the case of the
Private Placement Warrants and the shares of Class A Common Stock underlying such Private Placement Warrants, November 11, 2016. We will bear the expenses incurred in connection with the
filing of any such registration statements.
Silverback Acquisition Subscription Agreements
In connection with the Silverback Acquisition, on November 27, 2016 (as amended on December 22, 2016), we entered into a
subscription agreement with the Riverstone Purchasers, pursuant to which the Riverstone Purchasers agreed to purchase an aggregate of 3,473,590 shares of Class A Common Stock and 104,400 shares
of Series B Preferred Stock at the closing for an aggregate purchase price of approximately $430 million. For a more detailed description of the Series B Preferred Stock, please
see "Description of Capital StockSeries B Preferred Stock." In addition, on December 2, 2016, we entered into subscription agreements with the other selling stockholders,
pursuant to which such selling stockholders agreed to purchase an aggregate of 33,012,380 shares of Class A Common Stock at the closing for an aggregate purchase price of approximately
$480 million. We refer to the subscription agreements entered into by the selling stockholders, including the Riverstone Purchasers, as the "Subscription Agreements."
The
shares of Class A Common Stock and Series B Preferred Stock issued pursuant to the Subscription Agreements were not registered under the Securities Act in reliance upon
the exemption provided in Section 4(a)(2) of the Securities Act. The Subscription Agreements provide that the Company must register the resale of the shares of Class A Common Stock
issued thereunder pursuant to a registration statement that must be filed within 75 calendar days after consummation of the Silverback Acquisition. The Subscription Agreements provide further
that the Company must use its commercially reasonable
efforts to have the registration statement declared effective as soon as practicable after the filing thereof, but no later than the earlier of (i) the 90th calendar day following the
filing thereof and (ii) the 10th business day after the date the Company is notified (orally or in writing, whichever is earlier) by the SEC that such registration statement will not be
"reviewed" or will not be subject to further review.
Amendment to A&R LLC Agreement
On December 28, 2016, in connection with the Silverback Acquisition, the A&R LLC Agreement was amended by Amendment No. 1
to Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC (the "First CRP Amendment"). Pursuant to the First CRP Amendment, the Series B
Preferred Units were created, with 104,400 of such Series B Preferred Units issued to the Company, in connection with the contribution of proceeds from the Silverback Acquisition Private
Placements. Pursuant to the First CRP Amendment, the Series B Preferred Units have limited voting rights and are entitled to participate with the CRP Common Units
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Table of Contents
in
any distributions declared in accordance with the A&R LLC Agreement. The Series B Preferred Units will automatically convert to CRP Common Units upon the conversion of the Company's
Series B Preferred Stock. For additional information related to the conversion of the Class B Preferred Stock see "Description of Capital StockSeries B Preferred
Stock."
Related Party Policy
Prior to the closing of our IPO, we did not have a formal policy for the review, approval or ratification of related party transactions.
Accordingly, certain of the transactions discussed above were not reviewed, approved or ratified in accordance with any such policy.
We
have adopted a code of ethics requiring us to avoid, wherever possible, all conflicts of interests, except under guidelines or resolutions approved by our board of directors (or the
appropriate committee of our board) or as disclosed in our public filings with the SEC. Under our code of ethics, conflict of interest situations include any financial transaction, arrangement or
relationship (including
any indebtedness or guarantee of indebtedness) involving the company. A copy of our code of ethics is available on our website.
In
addition, our Audit Committee, pursuant to its charter, is responsible for reviewing and approving related party transactions to the extent that we enter into such transactions. An
affirmative vote of a majority of the members of the Audit Committee present at a meeting at which a quorum is present is required in order to approve a related party transaction. A majority of the
members of the entire Audit Committee will constitute a quorum. Without a meeting, the unanimous written consent of all of the members of the Audit Committee will be required to approve a related
party transaction. A copy of the Audit Committee charter is available on our website. We also require each of our directors and executive officers to complete a directors' and officers' questionnaire
that elicits information about related party transactions.
These
procedures are intended to determine whether any such related party transaction impairs the independence of a director or presents a conflict of interest on the part of a director,
employee or officer.
Our
Audit Committee will review on a quarterly basis any payments that are made to our Sponsor, officers or directors, or our or their affiliates.
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Table of Contents
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information known to us regarding ownership of shares of our voting common stock as of January 17,
2017:
-
-
each person who is the beneficial owner of more than 5% of the outstanding shares of our voting common stock;
-
-
each of our named executive officers and directors; and
-
-
all of our current executive officers and directors, as a group.
Beneficial
ownership is determined according to the rules of the SEC, which generally provide that a person has beneficial ownership of a security if he, she or it possesses sole or
shared voting or investment power over that security, including options and warrants that are currently exercisable or exercisable within 60 days.
The
beneficial ownership of our voting Common Stock as of the record date and prior to the conversion of the shares of Series B Preferred Stock is based on 200,835,049 shares of
Class A Common Stock, 19,155,921 shares of Class C Common Stock and Warrants to purchase 24,666,643 shares of Class A Common Stock issued and outstanding in the aggregate as of
January 17, 2017.
The
expected beneficial ownership of our voting Common Stock following the conversion of the shares of Series B Preferred Stock is based on 226,935,049 shares of Class A
Common Stock, 19,155,921 shares of Class C Common Stock and Warrants to purchase 24,666,643 shares of Class A Common Stock expected to be issued and outstanding.
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Table of Contents
Unless
otherwise indicated, we believe that all persons named in the table below have sole voting and investment power with respect to all shares of voting common stock beneficially
owned by them.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of Common Stock
Owned Prior to
Conversion of Series B
Preferred Stock
|
|
Shares of
Series B
Preferred
Stock
|
|
Number of Shares of
Common Stock Owned
After Conversion of
Series B Preferred Stock
|
|
Name of Beneficial Owner
|
|
Number
|
|
Percentage
|
|
Number
|
|
Number
|
|
Percentage
|
|
5% or Greater Stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funds affiliated with Riverstone Holdings(1)
|
|
|
104,858,590
|
|
|
50.2
|
%
|
|
104,400
|
|
|
130,958,590
|
|
|
55.7
|
%
|
Centennial Resource Development, LLC(2)
|
|
|
12,227,062
|
|
|
5.7
|
%
|
|
|
|
|
12,227,062
|
|
|
5.1
|
%
|
Celero Energy Company, LP(3)
|
|
|
4,246,898
|
|
|
2.1
|
%
|
|
|
|
|
4,246,898
|
|
|
1.8
|
%
|
NGP Centennial Follow-On LLC(4)
|
|
|
2,681,961
|
|
|
1.3
|
%
|
|
|
|
|
2,681,961
|
|
|
1.2
|
%
|
Funds advised by Capital Research and Management Company(5)
|
|
|
16,255,129
|
|
|
8.1
|
%
|
|
|
|
|
16,255,129
|
|
|
7.2
|
%
|
Fidelity Contrafund: Fidelity Advisor Series Opportunistic Insights Fund(6)(7)
|
|
|
59,000
|
|
|
*
|
|
|
|
|
|
59,000
|
|
|
*
|
|
Fidelity Contrafund: Fidelity Contrafund(6)(7)
|
|
|
7,528,926
|
|
|
3.7
|
%
|
|
|
|
|
7,528,926
|
|
|
3.3
|
%
|
Fidelity Contrafund Commingled Pool(6)
|
|
|
774,600
|
|
|
*
|
|
|
|
|
|
774,600
|
|
|
*
|
|
Fidelity Contrafund: Fidelity Advisor New Insights Fund(6)(7)
|
|
|
1,779,900
|
|
|
*
|
|
|
|
|
|
1,779,900
|
|
|
*
|
|
Fidelity Contrafund: Fidelity Series Opportunistic Insights Fund(6)(7)
|
|
|
408,700
|
|
|
*
|
|
|
|
|
|
408,700
|
|
|
*
|
|
Variable Insurance Products Fund III: Balanced Portfolio(6)(7)
|
|
|
187,300
|
|
|
*
|
|
|
|
|
|
187,300
|
|
|
*
|
|
Fidelity Puritan Trust: Fidelity Balanced Fund(6)(7)
|
|
|
1,735,600
|
|
|
*
|
|
|
|
|
|
1,735,600
|
|
|
*
|
|
Variable Insurance Products Fund II: Contrafund Portfolio(6)(7)
|
|
|
1,049,900
|
|
|
*
|
|
|
|
|
|
1,049,900
|
|
|
*
|
|
Fidelity Advisor Series I: Fidelity Advisor Balanced Fund(6)(7)
|
|
|
139,200
|
|
|
*
|
|
|
|
|
|
139,200
|
|
|
*
|
|
Fidelity Select Portfolios: Energy Portfolio(6)(7)
|
|
|
115,200
|
|
|
*
|
|
|
|
|
|
115,200
|
|
|
*
|
|
Variable Insurance Products Fund IV: Energy Portfolio(6)(7)
|
|
|
14,400
|
|
|
*
|
|
|
|
|
|
14,400
|
|
|
*
|
|
Fidelity Central Investment Portfolios LLC: Fidelity Energy Central Fund(6)(7)
|
|
|
45,400
|
|
|
*
|
|
|
|
|
|
45,400
|
|
|
*
|
|
Fidelity Advisor Series VII: Fidelity Advisor Energy Fund(6)(7)
|
|
|
45,200
|
|
|
*
|
|
|
|
|
|
45,200
|
|
|
*
|
|
Fidelity Select Portfolios: Natural Resources Portfolio(6)(7)
|
|
|
38,300
|
|
|
*
|
|
|
|
|
|
38,300
|
|
|
*
|
|
Directors and Named Executive Officers
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark G. Papa
|
|
|
10,000
|
|
|
*
|
|
|
|
|
|
10,000
|
|
|
*
|
|
George S. Glyphis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sean R. Smith
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jeffrey H. Tepper
|
|
|
40,000
|
|
|
*
|
|
|
|
|
|
40,000
|
|
|
*
|
|
Tony R. Weber
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Robert M. Tichio
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
David M. Leuschen(1)
|
|
|
104,858,590
|
|
|
50.2
|
%
|
|
104,400
|
|
|
130,958,590
|
|
|
55.7
|
%
|
Pierre F. Lapeyre Jr.(1)
|
|
|
104,858,590
|
|
|
50.2
|
%
|
|
104,400
|
|
|
130,958,590
|
|
|
55.7
|
%
|
Maire A. Baldwin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Karl E. Bandtel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All directors and executive officers, as a group (10 individuals)
|
|
|
104,908,590
|
|
|
50.2
|
%
|
|
104,400
|
|
|
131,008,590
|
|
|
55.7
|
%
|
-
*
-
Less
than one percent.
-
(1)
-
Includes
61,743,780 shares of Class A Common Stock and 76,304 shares of Series B Preferred Stock held of record by Riverstone VI Centennial QB
Holdings, L.P. ("Riverstone QB Holdings), 18,250,421 shares of Class A Common Stock and 22,554 shares of Series B Preferred Stock held of record by REL US Centennial
Holdings, LLC ("REL US"), 4,484,389 shares of Class A Common Stock and 5,542 shares of Series B Preferred Stock held of record by Riverstone Non-ECI USRPI AIV, L.P.
("Riverstone Non-ECI") and
121
Table of Contents
12,380,000
shares of Class A Common Stock and warrants to purchase an additional 8,000,000 shares of Class A Common Stock held of record by Silver Run Sponsor, LLC ("Silver Run
Sponsor"). David Leuschen and Pierre F.
Lapeyre, Jr. are the managing directors of Riverstone Holdings LLC. Riverstone Holdings, LLC is the sole shareholder of Riverstone Energy GP VI Corp., which is the managing member
of Riverstone Energy GP VI, LLC, which is the general partner of Riverstone Energy Partners VI, L.P., which is the general partner of Riverstone QB Holdings. Riverstone
Energy Partners GP VI, LLC is managed by a six person managing committee consisting of Pierre F. Lapeyre, Jr., David M. Leuschen, James T. Hackett, Michael B. Hoffman, N.
John Lancaster and, on a rotating basis, one of E. Bartow Jones, Baran Tekkora and Robert M. Tichio. As such, each of Riverstone Energy Partners GP VI, LLC, Riverstone
Energy Partners VI, L.P., Riverstone Energy GP VI Corp., Riverstone Holdings LLC, Mr.Leuschen and Mr. Lapeyre may be deemed to share beneficial ownership of the
securities held directly by Riverstone QB Holdings. Riverstone Holdings II (Cayman) Ltd. is the general partner of Riverstone Energy Limited Investment Holdings, LP, which is the sole
shareholder of REL IP General Partner Limited, which is the general partner of REL IP General Partner LP, which is the managing member of REL US. Mr. Leuschen and Mr. Lapeyre are
the sole shareholders of Riverstone Holdings II (Cayman) Ltd. and have or share voting and investment discretion with respect to the securities held of record by REL US Centennial
Holdings, LLC. As such, each of REL IP General Partner LP, REL IP General Partner Limited, Riverstone Energy Limited Investment Holdings, LP, Riverstone Holdings II
(Cayman) Ltd., Mr. Leuschen and Mr. Lapeyre may be deemed to have or share beneficial ownership of the securities held directly by REL US. Riverstone Non-ECI GP Ltd.
is the sole member of Riverstone Non-ECI Partners GP Cayman LLC, which is the general partner of Riverstone Non-ECI Partners GP (Cayman), L.P., which is the sole member of
Riverstone Non-ECI USRPI AIV GP, L.L.C., which is the general partner of Riverstone Non-ECI. Riverstone Non-ECI GP Ltd. is managed by Mr. Leuschen and Mr. Lapeyre,
who have or share voting and investment discretion with respect to the securities held of record by Riverstone Non-ECI. As such, each of Riverstone Non-ECI USRPI AIV GP, L.L.C., Riverstone
Non-ECI Partners GP (Cayman), L.P., Riverstone Non-ECI Partners GP Cayman LLC, Riverstone Non-ECI GP Ltd., Mr. Leuschen and Mr. Lapeyre may be
deemed to have or share beneficial ownership of the securities held directly by Riverstone Non-ECI. Silver Run Sponsor Manager, LLC is the managing member of Silver Run Sponsor. Riverstone
Holdings LLC is the managing member of Silver Run Sponsor Manager, LLC. As such, each of Silver Run Sponsor Manager, LLC, Riverstone Holdings LLC, Mr. Leuschen and
Mr. Lapeyre may be deemed to share beneficial ownership of the common stock held directly by Silver Run Sponsor, LLC. Each such entity or person disclaims any such beneficial ownership
of such securities. The business address for Silver Run Sponsor and Silver Run Sponsor Manager, LLC is 1000 Louisiana Street, Suite 1450, Houston, Texas 77002. The business
address for each other person named in this footnote is c/o Riverstone Holdings, 712 Fifth Avenue, 36th Floor, New York, NY 10019.
-
(2)
-
The
board of managers of CRD has voting and dispositive power over these shares. The board of managers of CRD consists of Ward Polzin, Bret Siepman, Chris Carter,
David Hayes, Martin Sumner, Christopher Ray and Tony R. Weber. None of such persons individually have voting and dispositive power over these shares, and the board of managers of CRD acts by majority
vote and thus each such person is not deemed to beneficially own the shares held by CRD. NGP X US Holdings, L.P. ("NGP X US Holdings") owns approximately 86% of CRD, and certain members of
CRD's management team own approximately 14%. Certain members of CRD's management team and certain of CRD's employees also own incentive units in CRD. Please see the section of the registration
statement entitled "Executive CompensationNarrative DisclosuresIncentive Units" for more information on the incentive units. As a result, NGP X US Holdings may be deemed to
indirectly beneficially own the shares held by CRD. NGP X US Holdings disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. NGP X Holdings GP,
L.L.C. (the sole general partner of NGP X US Holdings), NGP Natural Resources X, L.P. (the sole member of NGP X Holdings GP, L.L.C.), G.F.W. Energy X, L.P. (the sole general
partner of NGP Natural Resources X, L.P.) and GFW X, L.L.C. (the sole general partner of G.F.W. Energy X, L.P.) may each be deemed to share voting and dispositive power over the reported
shares and therefore may also be deemed to be the beneficial owner of these shares. GFW X, L.L.C. has delegated full power and authority to manage NGP X US Holdings to NGP Energy Capital Management,
L.L.C. and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these
shares. Chris Carter and Tony R. Weber, both of whom are members of CRD's board of directors, are managing partners of NGP Energy Capital Management, L.L.C. In addition, Craig Glick and Christopher
Ray are members of the executive committee of NGP Energy Capital Management, L.L.C. Although none of Messrs. Carter, Weber, Glick or Ray individually have voting or dispositive power over these
shares, such individuals may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Each of
Messrs. Carter, Weber, Glick and Ray disclaim beneficial ownership of these shares except to the extent of their respective pecuniary interest therein.
122
Table of Contents
-
(3)
-
Celero
Energy Management, LLC, the general partner of Celero ("Celero GP"), has voting and dispositive power over these shares. The board of managers
of Celero GP consists of David Hayes, Bruce Selkirk and Christopher Ray. None of such persons individually have voting and dispositive power over these shares, and the board of managers of
Celero GP acts by majority vote and thus each such person is not deemed to beneficially own the shares held by Celero GP. Natural Gas Partners VIII, L.P. ("NGP VIII") owns 94.7%
of the membership interests of Celero GP, and the remaining 5.3% is held by certain members of Celero's management team and other minority owners. As a result, NGP VIII may be deemed to
indirectly beneficially own these shares. NGP VIII disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. G.F.W. Energy VIII, L.P. (the sole
general partner of NGP VIII) and GFW VIII, L.L.C. (the sole general partner of G.F.W. Energy VIII, L.P.) may each be deemed to share voting and dispositive power over these shares and
therefore may also be deemed to be the beneficial owner of these shares. GFW VIII, L.L.C. has delegated full power and authority to manage NGP VIII to NGP Energy Capital Management, L.L.C. and
accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares.
Chris Carter and Tony R. Weber (one of our directors) are managing partners of NGP Energy Capital Management, L.L.C. In addition, Craig Glick and Christopher Ray are members of the executive committee
of NGP Energy Capital Management, L.L.C. Although none of Messrs. Carter, Weber, Glick or Ray individually have voting or dispositive power over these shares, such individuals may be deemed to
share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Each of Messrs. Carter, Weber, Glick and Ray disclaim
beneficial ownership of these shares except to the extent of their respective pecuniary interest therein.
-
(4)
-
NGP
Centennial Follow-On LLC is managed by its managing member, NGP X US Holdings. As such, NGP X US Holdings has voting and dispositive power over
these shares. NGP X US Holdings disclaims beneficial ownership of these shares except to the extent of its pecuniary interest therein. NGP X Holdings GP, L.L.C. (the sole general
partner of NGP X US Holdings), NGP Natural Resources X, L.P. (the sole member of NGP X Holdings GP, L.L.C.), G.F.W. Energy X, L.P. (the sole general partner of NGP
Natural Resources X, L.P.) and GFW X, L.L.C. (the sole general partner of G.F.W. Energy X, L.P.) may each be deemed to share voting and dispositive power over the reported shares and
therefore may also be deemed to be the beneficial owner of these shares. G.F.W. Energy X, L.P. has delegated full power and authority to manage NGP Natural Resources X, L.P. to NGP
Energy Capital Management, L.L.C. and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be
the beneficial owner of these shares. Chris Carter and Tony R. Weber (one of our directors) are managing partners of NGP Energy Capital Management, L.L.C. In addition, Craig Glick and Christopher Ray
are members of the executive committee of NGP Energy Capital Management, L.L.C. Although none of Messrs. Carter, Weber, Glick or Ray individually have voting or dispositive power over these
shares, such individuals may be deemed to share voting and dispositive power over these shares and therefore may also be deemed to be the beneficial owner of these shares. Each of
Messrs. Carter, Weber, Glick and Ray disclaim beneficial ownership of these shares except to the extent of their respective pecuniary interest therein.
-
(5)
-
Includes
7,542,654 shares of Class A Common Stock and warrants exercisable for 17,233 shares of Class A Common Stock held by SMALLCAP World
Fund, Inc. ("SCWF"), 8,209,667 shares of Class A Common Stock and warrants exercisable for 29,433 shares of Class A Common Stock held by The Growth Fund of America ("GFA") and
456,142 shares of Class A Common Stock held by Capital Group Global Equity Fund (Canada) ("CGGEF," and, together with SCWF and GFA, the "CRMC Stockholders"). Capital Research and Management
Company ("CRMC") is the investment adviser to each of the CRMC Stockholders. CRMC and/or Capital World Investors ("CWI") may be deemed to be the beneficial owner of all of the securities held by the
CRMC Stockholders; however, each of CRMC and CWI expressly disclaim that it is the beneficial owner of such securities. Julian N. Abdey, Mark E. Denning, Peter Eliot, Brady L. Enright, J. Blair
Frank, Bradford F. Freer, Leo Hee, Claudia P. Huntington, Jonathan Knowles, Lawrence Kymisis, Harold H. La, Aidan O'Connell, Andraz Razen and Gregory W. Wendt, as portfolio managers, have voting and
investment power over the securities held by SCWF. Christopher D. Buchbinder, Barry S. Crosthwaite, J. Blair Frank, Joanna F. Jonsson, Carl M. Kawaja, Michael T. Kerr, Ronald B. Morrow, Donald
D. O'Neal, Martin Romo, Lawrence R. Solomon, James Terrile and Alan J. Wilson, as portfolio managers, have voting and investment power over the securities held by GFA. Leo Hee, Carl M. Kawaja
and Dina N. Perry, as portfolio managers, have voting and investment power over the securities held by CGGEF. The address for each of the CRMC Stockholders is c/o Capital Research and Management
Company, 333 South Hope Street, 55th Floor, Los Angeles, CA 90071. The CRMC Stockholders may be affiliates of a broker-dealer. Each of the CRMC Stockholders acquired the shares being registered
hereby in the ordinary course of its business.
123
Table of Contents
-
(6)
-
These
accounts are managed by direct or indirect subsidiaries of FMR LLC. Abigail P. Johnson is a Director, the Vice Chairman, the Chief Executive Officer and
the President of FMR LLC. Members of the Johnson family, including Abigail P. Johnson, are the predominant owners, directly or through trusts, of Series B voting common shares of
FMR LLC, representing 49% of the voting power of FMR LLC. The Johnson family group and all other Series B shareholders have entered into a shareholders' voting agreement under
which all Series B voting common shares will be voted in accordance with the majority vote of Series B voting common shares. Accordingly, through their ownership of voting common shares
and the execution of the shareholders' voting agreement, members of the Johnson family may be deemed, under the Investment Company Act of 1940, to form a controlling group with respect to
FMR LLC. The address is 245 Summer Street, Boston, MA 02210.
-
(7)
-
Neither
FMR LLC nor Abigail P. Johnson has the sole power to vote or direct the voting of the shares owned directly by the various investment companies
registered under the Investment Company Act ("Fidelity Funds") advised by Fidelity Management & Research Company ("FMR Co"), a wholly owned subsidiary of FMR LLC, which power resides
with the Fidelity Funds' Boards of Trustees. FMR Co carries out the voting of the shares under written guidelines established by the Fidelity Funds' Boards of Trustees.
124
Table of Contents
SELLING STOCKHOLDERS
The selling stockholders may offer and sell, from time to time, any or all of the shares of Class A Common Stock being offered for resale
by this prospectus, which includes (i) 26,100,000 Conversion Shares and (ii) 36,485,970 Private Placement Shares. The term "selling stockholders" includes the stockholders listed in the
table below and their permitted transferees. The Conversion Shares and the Private Placement Shares are being registered by the registration statement of which this prospectus forms a part
pursuant to the Subscription Agreements entered into in connection with the Silverback Acquisition.
The
following table provides, as of January 17, 2017, information regarding the beneficial ownership of our Class A Common Stock and Series B Preferred Stock held by
each selling stockholder, the number of shares of Class A Common Stock that may be sold by each selling stockholder under this prospectus and that each selling stockholder will beneficially own
after this offering.
Because
each selling stockholder may dispose of all, none or some portion of their securities, no estimate can be given as to the number of securities that will be beneficially owned by
a selling stockholder upon termination of this offering. For purposes of the table below, however, we have assumed that after termination of this offering none of the securities covered by this
prospectus will be beneficially owned by the selling stockholders and further assumed that the selling stockholders will not acquire beneficial ownership of any additional securities during the
offering. In addition, the selling stockholders may have sold, transferred or otherwise disposed of, or may sell, transfer or otherwise dispose of, at any time and from time to time, our securities in
transactions exempt from the registration requirements of the Securities Act after the date on which the information in the table is presented.
We
may amend or supplement this prospectus from time to time in the future to update or change this selling stockholders list and the securities that may be resold.
Please
see the section entitled "Plan of Distribution" for further information regarding the stockholders' method of distributing these shares.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name of Beneficial Owner
|
|
Shares of
Class A
Common
Stock
Owned Prior
to Offering
|
|
Shares of
Series B
Preferred
Stock
Owned
Prior to
Offering(1)
|
|
Maximum
Number of
Shares of Class A
Common Stock
to be Sold
Pursuant to this
Prospectus After
Conversion of
Series B
Preferred Stock
|
|
Shares of
Class A
Common Stock
Owned After
Offering(2)
|
|
Selling Stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Riverstone VI Centennial QB Holdings, L.P.
|
|
|
61,743,780
|
|
|
76,304
|
|
|
21,614,780
|
|
|
59,205,000
|
|
REL US Centennial Holdings, LLC
|
|
|
18,250,421
|
|
|
22,554
|
|
|
6,388,921
|
|
|
17,500,000
|
|
Riverstone Non-ECI USRPI AIV, L.P.
|
|
|
4,484,389
|
|
|
5,542
|
|
|
1,569,889
|
|
|
4,300,000
|
|
Funds advised by Capital Research and Management Company
|
|
|
16,208,463
|
|
|
|
|
|
5,502,063
|
|
|
10,706,400
|
|
Fidelity Contrafund: Fidelity Advisor Series Opportunistic Insights Fund
|
|
|
59,000
|
|
|
|
|
|
18,800
|
|
|
40,200
|
|
Fidelity Contrafund: Fidelity Contrafund
|
|
|
7,528,926
|
|
|
|
|
|
2,340,926
|
|
|
5,188,000
|
|
Fidelity Contrafund Commingled Pool
|
|
|
774,600
|
|
|
|
|
|
261,700
|
|
|
512,900
|
|
Fidelity Contrafund: Fidelity Advisor New Insights Fund
|
|
|
1,779,900
|
|
|
|
|
|
555,400
|
|
|
1,224,500
|
|
125
Table of Contents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name of Beneficial Owner
|
|
Shares of
Class A
Common
Stock
Owned Prior
to Offering
|
|
Shares of
Series B
Preferred
Stock
Owned
Prior to
Offering(1)
|
|
Maximum
Number of
Shares of Class A
Common Stock
to be Sold
Pursuant to this
Prospectus After
Conversion of
Series B
Preferred Stock
|
|
Shares of
Class A
Common Stock
Owned After
Offering(2)
|
|
Fidelity Contrafund: Fidelity Series Opportunistic Insights Fund
|
|
|
408,700
|
|
|
|
|
|
129,800
|
|
|
278,900
|
|
Variable Insurance Products Fund III: Balanced Portfolio
|
|
|
187,300
|
|
|
|
|
|
72,000
|
|
|
115,300
|
|
Fidelity Puritan Trust: Fidelity Balanced Fund
|
|
|
1,735,600
|
|
|
|
|
|
639,500
|
|
|
1,096,100
|
|
Variable Insurance Products Fund II: Contrafund Portfolio
|
|
|
1,049,900
|
|
|
|
|
|
400,000
|
|
|
649,900
|
|
Fidelity Advisor Series I: Fidelity Advisor Balanced Fund
|
|
|
139,200
|
|
|
|
|
|
52,300
|
|
|
86,900
|
|
Anchor Series Capital Appreciation Portfolio(3)
|
|
|
122,303
|
|
|
|
|
|
122,303
|
|
|
|
|
Barclays Bank UK Retirement Fund(3)
|
|
|
22,514
|
|
|
|
|
|
22,514
|
|
|
|
|
Charles Stewart Mott Foundation(3)
|
|
|
47,333
|
|
|
|
|
|
16,004
|
|
|
31,329
|
|
Commonwealth Specialist Fund 36(3)
|
|
|
24,139
|
|
|
|
|
|
7,281
|
|
|
16,858
|
|
ConocoPhillips Retirement Plan(3)
|
|
|
12,553
|
|
|
|
|
|
9,331
|
|
|
3,222
|
|
Desjardins American Equity Growth Fund(3)
|
|
|
25,786
|
|
|
|
|
|
19,586
|
|
|
6,200
|
|
FIRST INVESTORS HEDGED U.S. EQUITY OPPORTUNITIES FUND(3)
|
|
|
1,470
|
|
|
|
|
|
1,470
|
|
|
|
|
Global Multi-Strategy Fund(3)
|
|
|
15,994
|
|
|
|
|
|
15,994
|
|
|
|
|
Harbor Mid Cap Growth Fund(3)
|
|
|
36,197
|
|
|
|
|
|
36,197
|
|
|
|
|
Hartford Capital Appreciation HLS Fund
|
|
|
49,942
|
|
|
|
|
|
49,942
|
|
|
|
|
Hartford Global Capital Appreciation Fund(3)
|
|
|
18,052
|
|
|
|
|
|
18,052
|
|
|
|
|
Hartford Growth Opportunities HLS Fund(3)
|
|
|
53,299
|
|
|
|
|
|
53,299
|
|
|
|
|
Hartford Real Total Return Fund(3)
|
|
|
11,624
|
|
|
|
|
|
4,145
|
|
|
7,479
|
|
Hartford Small Company HLS Fund(3)
|
|
|
343,780
|
|
|
|
|
|
44,489
|
|
|
299,291
|
|
High Haith Master Investors (Cayman) L.P.(3)
|
|
|
41,015
|
|
|
|
|
|
21,469
|
|
|
19,546
|
|
Highland Public Inflation Hedges Collective Fund(3)
|
|
|
15,307
|
|
|
|
|
|
6,599
|
|
|
8,708
|
|
Highland Public Inflation Hedges Fund(3)
|
|
|
27,589
|
|
|
|
|
|
11,909
|
|
|
15,680
|
|
International Monetary Fund Retired Staff Benefits Investment Account(3)
|
|
|
1,174
|
|
|
|
|
|
1,174
|
|
|
|
|
International Monetary Fund Staff Retirement Plan(3)
|
|
|
7,827
|
|
|
|
|
|
7,827
|
|
|
|
|
John Hancock Funds II Small Cap Growth Fund(3)
|
|
|
85,903
|
|
|
|
|
|
7,474
|
|
|
78,429
|
|
John Hancock Pension Plan(3)
|
|
|
21,948
|
|
|
|
|
|
1,845
|
|
|
20,103
|
|
John Hancock Variable Insurance Trust Small Cap Growth Trust(3)
|
|
|
157,266
|
|
|
|
|
|
13,559
|
|
|
143,707
|
|
MassMutual Select Small Cap Growth Equity Fund(3)
|
|
|
55,916
|
|
|
|
|
|
5,688
|
|
|
50,228
|
|
Mid Cap Growth Portfolio(3)
|
|
|
6,776
|
|
|
|
|
|
6,776
|
|
|
|
|
MML Small Cap Growth Equity Fund(3)
|
|
|
40,760
|
|
|
|
|
|
4,111
|
|
|
36,649
|
|
Molson Coors (UK) Pension Plan(3)
|
|
|
39,240
|
|
|
|
|
|
39,240
|
|
|
|
|
Northwestern Memorial HealthCare(3)
|
|
|
108,218
|
|
|
|
|
|
32,642
|
|
|
75,576
|
|
126
Table of Contents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name of Beneficial Owner
|
|
Shares of
Class A
Common
Stock
Owned Prior
to Offering
|
|
Shares of
Series B
Preferred
Stock
Owned
Prior to
Offering(1)
|
|
Maximum
Number of
Shares of Class A
Common Stock
to be Sold
Pursuant to this
Prospectus After
Conversion of
Series B
Preferred Stock
|
|
Shares of
Class A
Common Stock
Owned After
Offering(2)
|
|
Retirement Income Plan for Employees of Armstrong World Industries, Inc.(3)
|
|
|
4,914
|
|
|
|
|
|
4,914
|
|
|
|
|
RIFL Global Equity Plus Fund(3)
|
|
|
3,961
|
|
|
|
|
|
3,961
|
|
|
|
|
Russell Global Equity Fund(3)
|
|
|
13,263
|
|
|
|
|
|
13,263
|
|
|
|
|
Russell Global Equity Pool(3)
|
|
|
5,336
|
|
|
|
|
|
5,336
|
|
|
|
|
Russell Global Opportunities Fund(3)
|
|
|
25,648
|
|
|
|
|
|
25,648
|
|
|
|
|
Russell Institutional Funds, LLCRussell Multi-Asset Core Plus Fund(3)
|
|
|
12,257
|
|
|
|
|
|
12,257
|
|
|
|
|
Russell Investment CompanyRussell Global Equity Fund(3)
|
|
|
52,823
|
|
|
|
|
|
52,823
|
|
|
|
|
Russell Trust CompanyMulti-Asset Core Fund(3)
|
|
|
11,931
|
|
|
|
|
|
11,931
|
|
|
|
|
Russell Trust Company Russell World Equity Fund(3)
|
|
|
17,009
|
|
|
|
|
|
17,009
|
|
|
|
|
Smithfield Foods Master Trust(3)
|
|
|
3,253
|
|
|
|
|
|
3,253
|
|
|
|
|
Spindrift Investors (Bermuda) L.P.(3)
|
|
|
159,003
|
|
|
|
|
|
29,487
|
|
|
129,516
|
|
Spindrift Partners, L.P.(3)
|
|
|
188,402
|
|
|
|
|
|
32,040
|
|
|
156,362
|
|
The Hartford Capital Appreciation Fund(3)
|
|
|
73,662
|
|
|
|
|
|
73,662
|
|
|
|
|
The Hartford Global Real Asset Fund(3)
|
|
|
27,400
|
|
|
|
|
|
7,228
|
|
|
20,172
|
|
The Hartford Growth Opportunities Fund(3)
|
|
|
83,948
|
|
|
|
|
|
83,948
|
|
|
|
|
The Hartford Small Company Fund(3)
|
|
|
185,874
|
|
|
|
|
|
23,358
|
|
|
162,516
|
|
Treasurer of the State of North Carolina(3)
|
|
|
41,229
|
|
|
|
|
|
29,729
|
|
|
11,500
|
|
Trustees of Hamilton College(3)
|
|
|
14,097
|
|
|
|
|
|
10,097
|
|
|
4,000
|
|
UNC Investment Fund, LLC(3)
|
|
|
47,298
|
|
|
|
|
|
14,288
|
|
|
33,010
|
|
US Research Equity Extended Master Fund (Cayman) L.P.(3)
|
|
|
23,008
|
|
|
|
|
|
5,670
|
|
|
17,338
|
|
Vanguard Energy Fund(3)
|
|
|
2,014,206
|
|
|
|
|
|
2,014,206
|
|
|
|
|
Wellington ALTA Fund(3)
|
|
|
924
|
|
|
|
|
|
924
|
|
|
|
|
Wellington Diversified Inflation Hedges Fund(3)
|
|
|
47,142
|
|
|
|
|
|
22,228
|
|
|
24,914
|
|
Wellington Hedged Alpha Opportunities Fund, L.P.(3)
|
|
|
3,702
|
|
|
|
|
|
3,702
|
|
|
|
|
Wellington Trust Company, National Association Multiple Collective Investment Funds Trust II Real Total Return II Portfolio(3)
|
|
|
36,141
|
|
|
|
|
|
10,901
|
|
|
25,240
|
|
Wellington Trust Company, National Association Multiple Collective Investment Funds Trust II, Global Equities Portfolio(3)
|
|
|
4,970
|
|
|
|
|
|
4,970
|
|
|
|
|
Wellington Trust Company, National Association Multiple Collective Investment Funds Trust II, Real Total Return Portfolio(3)
|
|
|
45,022
|
|
|
|
|
|
13,580
|
|
|
31,442
|
|
127
Table of Contents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name of Beneficial Owner
|
|
Shares of
Class A
Common
Stock
Owned Prior
to Offering
|
|
Shares of
Series B
Preferred
Stock
Owned
Prior to
Offering(1)
|
|
Maximum
Number of
Shares of Class A
Common Stock
to be Sold
Pursuant to this
Prospectus After
Conversion of
Series B
Preferred Stock
|
|
Shares of
Class A
Common Stock
Owned After
Offering(2)
|
|
Wellington Trust Company, National Association Multiple Collective Investment Funds Trust II, Wells Fargo Select Small Cap Growth Portfolio(3)
|
|
|
63,637
|
|
|
|
|
|
45,937
|
|
|
17,700
|
|
Wellington Trust Company, National Association Multiple Collective Investment Funds Trust, Capital Appreciation Equity Portfolio(3)
|
|
|
7,850
|
|
|
|
|
|
7,850
|
|
|
|
|
Wellington Trust Company, National Association Multiple Collective Investment Funds Trust, Energy Portfolio(3)
|
|
|
44,011
|
|
|
|
|
|
20,944
|
|
|
23,067
|
|
Wellington Trust Company, National Association Multiple Collective Investment Funds Trust, Opportunistic Growth Portfolio(3)
|
|
|
3,522
|
|
|
|
|
|
2,022
|
|
|
1,500
|
|
Wellington Trust Company, National Association Multiple Collective Investment Funds Trust, Small Cap Growth Portfolio(3)
|
|
|
6,506
|
|
|
|
|
|
173
|
|
|
6,333
|
|
Wellington Trust Company, National Association Multiple Common Trust Funds Trust Select Energy Opportunities I Portfolio(3)
|
|
|
150,959
|
|
|
|
|
|
45,520
|
|
|
105,439
|
|
Wellington Trust Company, National Association Multiple Common Trust Funds Trust Select Energy Opportunities Portfolio(3)
|
|
|
320,894
|
|
|
|
|
|
87,866
|
|
|
233,028
|
|
Wellington Trust Company, National Association Multiple Common Trust Funds Trust, Capital Appreciation Equity Portfolio(3)
|
|
|
6,892
|
|
|
|
|
|
6,892
|
|
|
|
|
Wellington Trust Company, National Association Multiple Common Trust Funds Trust, Dynamic Growth Portfolio(3)
|
|
|
12,271
|
|
|
|
|
|
12,271
|
|
|
|
|
Wellington Trust Company, National Association Multiple Common Trust Funds Trust, Energy II Portfolio(3)
|
|
|
129,052
|
|
|
|
|
|
129,052
|
|
|
|
|
Wellington Trust Company, National Association Multiple Common Trust Funds Trust, Energy Portfolio(3)
|
|
|
402,960
|
|
|
|
|
|
192,256
|
|
|
210,704
|
|
Wellington Trust Company, National Association Multiple Common Trust Funds Trust, Global Select Capital Appreciation Portfolio(3)
|
|
|
115,616
|
|
|
|
|
|
115,616
|
|
|
|
|
128
Table of Contents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name of Beneficial Owner
|
|
Shares of
Class A
Common
Stock
Owned Prior
to Offering
|
|
Shares of
Series B
Preferred
Stock
Owned
Prior to
Offering(1)
|
|
Maximum
Number of
Shares of Class A
Common Stock
to be Sold
Pursuant to this
Prospectus After
Conversion of
Series B
Preferred Stock
|
|
Shares of
Class A
Common Stock
Owned After
Offering(2)
|
|
Wellington Trust Company, National Association Multiple Common Trust Funds Trust, Opportunistic Growth Portfolio(3)
|
|
|
3,880
|
|
|
|
|
|
3,880
|
|
|
|
|
Wellington Trust Company, National Association Multiple Common Trust Funds Trust, Real Total Return Portfolio(3)
|
|
|
2,802
|
|
|
|
|
|
1,056
|
|
|
1,746
|
|
Funds and accounts advised by T. Rowe Price Associates, Inc.(4).
|
|
|
9,679,344
|
|
|
|
|
|
4,470,426
|
|
|
5,208,918
|
|
Funds advised by SailingStone Capital Partners LLC
|
|
|
3,094,911
|
|
|
|
|
|
3,094,911
|
|
|
|
|
Hartree Partners, LP
|
|
|
2,104,941
|
|
|
|
|
|
687,758
|
|
|
1,417,183
|
|
MTP Energy Fund LTD (Magnetar)
|
|
|
1,719,395
|
|
|
|
|
|
1,719,395
|
|
|
|
|
MMF Moore ET Investments, LP
|
|
|
2,751,032
|
|
|
|
|
|
2,751,032
|
|
|
|
|
Funds advised by Discovery Capital Management, LLC
|
|
|
687,758
|
|
|
|
|
|
687,758
|
|
|
|
|
Tortoise Energy Independence Fund, Inc.
|
|
|
117,239
|
|
|
|
|
|
117,239
|
|
|
|
|
Tortoise North American Energy Independence Fund
|
|
|
2,610
|
|
|
|
|
|
2,610
|
|
|
|
|
Tortoise Select Opportunity Fund
|
|
|
24,348
|
|
|
|
|
|
24,348
|
|
|
|
|
Tortoise Direct Opportunities Fund, LP
|
|
|
543,561
|
|
|
|
|
|
543,561
|
|
|
|
|
The Baupost Group, L.L.C(5).
|
|
|
2,407,153
|
|
|
|
|
|
2,407,153
|
|
|
|
|
BlackRock, Inc.(6)
|
|
|
1,703,573
|
|
|
|
|
|
1,031,637
|
(7)
|
|
671,936
|
|
Funds advised by Tide Point Capital Management LP
|
|
|
3,314,224
|
|
|
|
|
|
687,758
|
|
|
2,626,466
|
|
Funds advised by Kensico Capital Management Corp
|
|
|
2,687,758
|
|
|
|
|
|
687,758
|
|
|
2,000,000
|
|
Encompass Capital E&P Master Fund LP
|
|
|
343,879
|
|
|
|
|
|
343,879
|
|
|
|
|
-
(1)
-
Shares
of Series B Preferred Stock are automatically convertible into shares of Class A Common Stock on a 250-to-1 basis (subject to certain
adjustments) at such time as we receive Stockholder Approval. For a more detailed description of the Series B Preferred Stock, please see "Description of Capital
StockSeries B Preferred Stock."
-
(2)
-
Assumes
each selling stockholder sells the maximum number of shares of Class A Common Stock that may be sold by such selling stockholder under this
prospectus.
-
(3)
-
Wellington
Management Company LLP is the investment adviser to these entities. Wellington Management Company LLP is an investment adviser registered
under the Investment Advisers Act of 1940, as amended, and is an indirect subsidiary of Wellington Management Group LLP. Wellington Management Company LLP and Wellington Management
Group LLP may each be deemed to share beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of the shares indicated in the table, all of which are
held of record by the entities named in the table or a nominee on its behalf. The business address of the entities named in the table is c/o Wellington Management Company LLP, 280 Congress
Street, Boston,
129
Table of Contents
Massachusetts 02210.
The business address of Wellington Management Company LLP and Wellington Management Group LLP is 280 Congress Street, Boston, Massachusetts 02210.
-
(4)
-
T.
Rowe Price Associates, Inc., is a registered investment adviser ("Fund Manager" or "TRPA"). Fund Manager is affiliated with a registered broker-dealer, T.
Rowe Price Investment Services, Inc. ("TRPIS"). TRPIS is a subsidiary of the Fund Manager and was formed primarily for the limited purpose of acting as the principal underwriter and distributor
of shares of funds in the T. Rowe Price fund family. T. Rowe Price Associates, Inc. serves as investment adviser with power to direct investments and/or sole power to vote the securities owned
by the funds and accounts that hold shares of the Company. For purposes of reporting requirements of the Securities Exchange Act of 1934, TRPA may be deemed to be the beneficial owner of all of the
shares listed in this table; however, TRPA expressly disclaims that it is, in fact, the beneficial owner of such securities. TRPA is the wholly owned subsidiary of T. Rowe Price Group, Inc.,
which is a publicly traded financial services holding company.
-
(5)
-
The
Baupost Group, L.L.C. is a registered investment adviser and acts as the investment adviser to certain private investment limited partnerships on whose behalf
these securities were indirectly purchased.
-
(6)
-
The
registered holders of the referenced shares are funds and accounts managed by investment adviser subsidiaries of BlackRock, Inc. BlackRock, Inc. is
the ultimate parent holding company of such investment adviser entities. On behalf of such investment adviser entities, the applicable portfolio managers, respectively as a managing directors of such
entities, have voting and investment power over the shares held by the foregoing funds and accounts which are the registered holders of the referenced shares and units. Such applicable portfolio
managers expressly disclaim beneficial ownership of all shares and units held by such funds and accounts. The address of such funds and accounts, such investment adviser subsidiaries and such
applicable portfolio managers is 55 East 52nd Street, New York, NY 10055.
-
(7)
-
The
registered holders of the referenced shares to be registered are funds and accounts under management by investment adviser subsidiaries of BlackRock, Inc.
BlackRock, Inc. is the ultimate parent holding company of such investment adviser entities. On behalf of such investment adviser entities, David Trucano, as a managing director of such
entities, has voting and investment power over the shares held by the funds and accounts which are the registered holders of the referenced shares. David Trucano expressly disclaims beneficial
ownership of all shares held by such funds and accounts. The address of such funds and accounts, such investment adviser subsidiaries and David Trucano is 55 East 52nd Street, New York, NY
10055. Shares being registered for resale may not incorporate all shares deemed to be beneficially held by BlackRock, Inc.
Material Relationships with Selling Stockholders
Please see "Certain Relationships and Related Transactions" appearing elsewhere in this prospectus for information regarding material
relationships with our selling stockholders within the past three years.
130
Table of Contents
PLAN OF DISTRIBUTION
We are registering the resale of shares of Class A Common Stock by the selling stockholders named herein. The selling stockholders, which
as used herein includes their permitted transferees, may, from time to time, sell, transfer or otherwise dispose of any or all of their shares on NASDAQ or any other stock exchange, market or trading
facility on which such shares are traded or in private transactions. These dispositions may be at fixed prices, at prevailing market prices at the time of sale, at prices related to the prevailing
market price, at varying prices determined at the time of sale or at negotiated prices.
The
selling stockholders may use any one or more of the following methods when disposing of their shares of Class A Common Stock:
-
-
ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;
-
-
block trades in which the broker-dealer will attempt to sell the shares as agent, but may position and resell a portion of the block as
principal to facilitate the transaction;
-
-
purchases by a broker-dealer as principal and resale by the broker-dealer for its account;
-
-
an exchange distribution in accordance with the rules of the applicable exchange;
-
-
privately negotiated transactions;
-
-
in underwriting transactions;
-
-
short sales;
-
-
through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise;
-
-
broker-dealers may agree with the selling stockholders to sell a specified number of such shares at a stipulated price;
-
-
distribution to members, limited partners or stockholders of selling stockholders;
-
-
a combination of any such methods of sale; and
-
-
any other method permitted pursuant to applicable law.
The
selling stockholders may, from time to time, pledge or grant a security interest in some or all of the shares of Class A Common Stock owned by them and, if they default in the
performance of their secured obligations, the pledgees or secured parties may offer and sell their shares, from time to time, under this prospectus, or under an amendment to this prospectus under
Rule 424(b)(3) or other applicable provision of the Securities Act amending the list of selling stockholders to include the pledgee, transferee or other successors in interest as selling
stockholders under this prospectus. The selling stockholders also may transfer their shares in other circumstances, in which case the transferees, pledgees or other successors in interest will be the
selling beneficial owners for purposes of this prospectus.
In
connection with the sale of our Class A Common Stock or interests therein, the selling stockholders may enter into hedging transactions with broker-dealers or other financial
institutions, which may in turn engage in short sales of our securities in the course of hedging the positions they assume. The selling stockholders may also sell their securities short and deliver
these securities to close out their short positions, or loan or pledge such securities to broker-dealers that in turn may sell these securities. The selling stockholders may also enter into option or
other transactions with broker-dealers or other financial institutions or the creation of one or more derivative securities which require the delivery to such broker-dealer or other financial
institution of the shares offered by this prospectus,
131
Table of Contents
which
shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).
The
aggregate proceeds to the selling stockholders from the sale of the shares offered by them will be the purchase price of the share less discounts or commissions, if any. Each of the
selling stockholders reserves the right to accept and, together with their agents from time to time, to reject, in whole or in part, any proposed purchase of their shares to be made directly or
through agents. We will not receive any of the proceeds from the resale of shares of Class A Common Stock being offered by the selling stockholders named herein.
The
selling stockholders also may resell all or a portion of their shares in open market transactions in reliance upon Rule 144 under the Securities Act, provided that they meet
the criteria and conform to the requirements of that rule.
In
connection with an underwritten offering, underwriters or agents may receive compensation in the form of discounts, concessions or commissions from the selling stockholders or from
purchasers of the offered shares for whom they may act as agents. In addition, underwriters may sell the shares to or through dealers, and those dealers may receive compensation in the form of
discounts, concessions or commissions from the underwriters and/or commissions from the purchasers for whom they may act as agents. The selling stockholders and any underwriters, dealers or agents
participating in a distribution of the shares may be deemed to be "underwriters" within the meaning of the Securities Act, and any profit on the sale of the shares by the selling stockholders and any
commissions received by broker-dealers may be deemed to be underwriting commissions under the Securities Act.
To
the extent required, the shares of Class A Common Stock to be sold, the names of the selling stockholders, the respective purchase prices and public offering prices, the names
of any agent, dealer or underwriter, and any applicable commissions or discounts with respect to a particular offer will be set forth in an accompanying prospectus supplement or, if appropriate, a
post-effective amendment to the registration statement that includes this prospectus.
Blue Sky Restrictions on Resale
In order to comply with the securities laws of some states, if applicable, our shares of Class A Common Stock may be sold in these
jurisdictions only through registered or licensed brokers or dealers. In addition, in some states our shares of Class A Common Stock may not be sold unless they have been registered or
qualified for sale or an exemption from registration or qualification requirements is available and is complied with.
If
a selling stockholder wants to sell its shares of Class A Common Stock under this prospectus in the United States, the selling stockholders will also need to comply with state
securities laws, also known as "Blue Sky laws," with regard to secondary sales. All states offer a variety of exemption from registration for secondary sales. Many states, for example, have an
exemption for secondary trading of securities registered under Section 12(g) of the Exchange Act or for securities of issuers that publish continuous disclosure of financial and non-financial
information in a recognized securities manual, such as Standard & Poor's. The broker for a selling stockholder will be able to advise a selling stockholder in which states shares of
Class A Common Stock are exempt from registration for secondary sales.
Any
person who purchases shares of Class A Common Stock from a selling stockholder offered by this prospectus who then wants to sell such shares will also have to comply with Blue
Sky laws regarding secondary sales.
When
the registration statement that includes this prospectus becomes effective, and a selling stockholder indicates in which state(s) he desires to sell his shares of Class A
Common Stock we will be able to identify whether it will need to register or will rely on an exemption there from.
132
Table of Contents
We
have advised the selling stockholders that the anti-manipulation rules of Regulation M under the Exchange Act may apply to sales of securities in the market and to the
activities of the selling stockholders and their affiliates. In addition, we will make copies of this prospectus (as it may be supplemented or amended from time to time) available to the selling
stockholders for the purpose of satisfying the prospectus delivery requirements of the Securities Act. The selling stockholders may indemnify any broker-dealer that participates in transactions
involving the sale of their shares against certain liabilities, including liabilities arising under the Securities Act.
We
have agreed to indemnify, to the extent permitted by law, the selling stockholders (and each selling stockholder's officers and directors and each person who controls such selling
stockholder) against liabilities caused by any untrue or alleged untrue statement of material fact contained in this prospectus or the registration statement of which this prospectus forms a
part (including any amendment or supplement thereof) or any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein not misleading,
except insofar as the same are caused by or contained in any information furnished in writing to the Company by such selling stockholder expressly for use herein.
We
are required to pay all fees and expenses incident to the registration of the shares of Class A Common Stock covered by this prospectus, including with regard to compliance
with state securities or Blue Sky laws. Otherwise, all discounts, commissions or fees incurred in connection with the sale of shares of Class A Common Stock offered hereby will be paid by the
selling stockholders.
133
Table of Contents
DESCRIPTION OF CAPITAL STOCK
The Company has authorized 620,000,000 shares of capital stock, consisting of (a) 640,000,000 shares of common stock, including
(i) 600,000,000 shares of Class A Common Stock, and (ii) 20,000,000 shares of Class C Common Stock and (b) 1,000,000 shares of preferred stock, including one share
of Series A Preferred Stock and 104,400 shares of Series B Preferred Stock.
As
of January 18, 2017, there were: 215 holders of record of Class A Common Stock and 200,835,049 shares of Class A Common Stock outstanding; (b) three
holders of record of Class C Common Stock and 19,155,921 shares of Class C Common Stock outstanding; (c) one holder of record of Series A Preferred Stock and one share of
Series A Preferred Stock outstanding; (d) three holders of record of Series B Preferred Stock and 104,400 shares of Series B Preferred Stock outstanding; (e) one
holder of the Public Warrants and 16,666,643 Public Warrants outstanding; and (f) one holder of the Private Placement Warrants and 8,000,000 Private Placement Warrants outstanding.
Class A Common Stock
Holders of the Company's Class A Common Stock are entitled to one vote for each share held on all matters to be voted on by the Company's
stockholders. Holders of the Class A Common Stock and holders of the Class C Common Stock will vote together as a single class on all matters submitted to a vote of the Company's
stockholders, except as required by law. Unless specified in the Charter (including any certificate of designation of preferred stock) or Bylaws, or as required by applicable provisions of the
Delaware General Corporation Law or applicable stock exchange rules, the affirmative vote of a majority of the Company's shares of common stock that are voted is required to approve any such matter
voted on by the Company's stockholders. There is no cumulative voting with respect to the election of directors, with the result that the holders of more than 50% of the shares voted for the election
of directors can elect all of the directors (subject to the right of the holder of our Series A Preferred Stock to nominate and elect one director). Subject to the rights of the holders of any
outstanding series of preferred stock, the Company's stockholders are entitled to receive ratable dividends when, as and if declared by the board of directors out of funds legally available therefor.
In
the event of a liquidation, dissolution or winding up of the Company, the holders of the Class A Common Stock are entitled to share ratably in all assets remaining available
for distribution to them after payment of liabilities and after provision is made for each class of stock, if any, having preference over the Class A Common Stock. The Company's stockholders
have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the Class A Common Stock.
Class C Common Stock
In connection with the Business Combination, we issued 20,000,000 shares of Class C Common Stock to the Centennial Contributors. Holders
of Class C Common Stock, together with holders of Class A Common Stock voting as a single class, will have the right to vote on all matters properly submitted to a vote of the
stockholders. In addition, the holders of Class C Common Stock, voting as a separate class, will be entitled to approve any amendment, alteration or repeal of any provision of our Charter that
would alter or change the powers, preferences or relative, participating, optional or other or special rights of the Class C Common Stock. Holders of Class C Common Stock will not be
entitled to any dividends from the Company and will not be entitled to receive any of our assets in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.
Shares
of Class C Common Stock may be issued only to the Centennial Contributors, their respective successors and assigns, as well as any permitted transferees of the Centennial
Contributors. A holder of Class C Common Stock may transfer shares of Class C Common Stock to any transferee (other than the
Company) only if such holder also simultaneously transfers an equal number of such holder's CRP Common Units to such transferee in compliance with the amended and restated limited
134
Table of Contents
liability
company agreement of CRP. The Centennial Contributors generally have the right to cause CRP to redeem all or a portion of their CRP Common Units in exchange for shares of the Company's
Class A Common Stock or, at CRP's option, an equivalent amount of cash. The Company may, however, at its option, effect a direct exchange of cash or Class A Common Stock for such CRP
Common Units in lieu of such a redemption by CRP. Upon the future redemption or exchange of CRP Common Units held by a Centennial Contributor, a corresponding number of shares of Class C Common
Stock will be canceled.
Series A Preferred Stock
In connection with the Business Combination, we also issued one share of Series A Preferred Stock to CRD. CRD, as the holder of the
Series A Preferred Stock, will not be entitled to any dividends from the Company, but will be entitled to preferred distributions in liquidation in the amount of $0.0001 per share of
Series A Preferred Stock and will have a limited voting right as described below. The Series A Preferred Stock will be redeemable by us (a) at such time as CRD and its affiliates
cease to own, in the aggregate, at least 5,000,000 CRP Common Units and/or shares of Class A Common Stock (as adjusted for stock splits, stock dividends, reorganizations, recapitalizations and
other similar transactions), (b) at any time at CRD's option or (c) upon a breach by CRD of the transfer restrictions relating to the Series A Preferred Stock. In addition, for so
long as the Series A Preferred Stock remains outstanding, CRD will be entitled to nominate one director for election to our board of directors in connection with any vote of our stockholders
for the election of directors, and the vote of CRD will be the only vote required to elect such nominee to our board.
Series B Preferred Stock
In connection with the Silverback Acquisition, we issued 104,400 shares of Series B Preferred Stock to the Riverstone Purchasers. The
shares of Series B Preferred Stock are automatically convertible into shares of Class A Common Stock on a 250-to-1 basis (subject to adjustments for stock splits, stock dividends,
reorganization, recapitalizations and the like) at such time as we receive
Stockholder Approval. Holders of the Series B Preferred Stock are not entitled to dividends, except that such holders will be entitled to pro rata participation in any dividends paid on shares
of the Class A Common Stock on an as-converted basis whether or not the shares of Series B Preferred Stock are then entitled to conversion. Prior to the date of the special meeting of
the Company's stockholders held to seek Stockholder Approval, no holder of Series B Preferred Stock may sell, contract to sell, pledge or otherwise dispose of any shares of Series B
Preferred Stock without the prior written consent of the Company, except to an affiliate of such holder or the Company or a subsidiary thereof.
Holders
of Series B Preferred Stock generally will not have any voting rights, except as required by law. Notwithstanding the foregoing, the affirmative vote of holders of a
majority of the Series B Preferred Stock then outstanding, voting as a separate class, is required to (a) approve any amendment, alteration or repeal of any provision of the Certificate
of Designation relating to the Series B Preferred Stock or the Charter that adversely affects the rights, preferences, privileges or voting powers of the Series B Preferred Stock or
(b) authorize the issuance of any senior securities or parity securities. With respect to any matter on which the holders of Series B Preferred Stock are entitled to vote, each share of
Series B Preferred Stock will be entitled to one vote on such matter.
Beginning
on the third anniversary of the closing date of the Silverback Acquisition, the Company will have the right, but not the obligation, to redeem all (but not less than all) of
each holder's shares of Series B Preferred Stock for a redemption price per share, determined on an as-converted basis, equal to the average of the last reported sale price for a share of
Class A Common Stock on NASDAQ for each of the last 10 consecutive trading days prior to the redemption date or, if such shares are no longer traded, at the fair market value of the
Class A Common Stock, as determined in good faith by the Board of Directors of the Company.
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In
the event of a voluntary or involuntary liquidation, dissolution or winding up of the Company (each a "Liquidation Event"), holders of the Series B Preferred Stock will first
be entitled to receive the liquidation preference per share of $0.0001 (the "Liquidation Preference") before any distribution of assets is made to holders of any junior securities. If, in the event of
a Liquidation Event, after payment of any amounts to be paid in respect of any senior securities, the Company's assets available for distribution are insufficient to fully pay the liquidation payments
owing to the holders of the Series B Preferred Stock and the holders of any parity securities, the holders of the Series B Preferred Stock and such parity securities will share ratably
in the distribution of the Company's assets in proportion to the full liquidating distributions to which they would otherwise have been respectively entitled. After the payment of the Liquidation
Preference to the holders of the Series B Preferred Stock (and payment of any amount to be paid in respect of any senior securities and any parity securities), the remaining assets of the
Company will be distributed ratably to the holders of the Class A Common Stock and the Series B Preferred Stock on an as-converted basis whether or not the shares of Series B
Preferred Stock are then entitled to conversion (and any other participating equity securities of the Company). A Liquidation Event will not include (i) the merger or consolidation of the
Company with any other entity, including a merger or consolidation in which the holders of the Series B Preferred Stock receive cash,
securities or property for their shares, the sale, lease or exchange of all or substantially all of the Company's assets for cash, securities or other property, (ii) the conversion of the
Company into another legal entity or (iii) the sale of all or substantially all of the assets of the Company to an affiliate in connection with a reorganization or liquidation.
Prior
to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of shares of Class A Common
Stock are to receive cash, securities or property for their shares (a "Corporate Event"), the Company will make appropriate provision to ensure that the holders of the Series B Preferred Stock
receive in such Corporate Event a preferred security, issued by the entity surviving or resulting from such Corporate Event and containing provisions substantially equivalent to the provisions set
forth in the Certificate of Designation relating to the Series B Preferred Stock without abridgement, including, without limitation, the same rights, preferences, privileges or voting powers
that shares of the Series B Preferred Stock had immediately prior to such Corporate Event (the "Survivor Preferred Security").
If
the Company desires to enter into a Corporate Event that will result in holders of shares of Class A Common Stock receiving exclusively cash consideration as a result thereof
(a "Cash Event"), the Company will use its commercially reasonable efforts to ensure that the parties to such Cash Event enter into documentation that provides that upon conversion of a share of
Survivor Preferred Security, the holder thereof shall be entitled to receive, in lieu of such cash, a share or shares of common equity of the entity surviving or resulting from the Cash Event. Each
such Survivor Preferred Security will initially (that is, immediately after the effective time of the Cash Event) entitle the holder to convert such Survivor Preferred Security into a number of shares
of common equity of the entity surviving or resulting from the Cash Event that are equivalent in fair market value to the cash amount that would otherwise have been received by the holder had such
holder's shares of Series B Preferred Stock been converted into shares of Class A Common Stock immediately prior to the Cash Event.
Warrants
Each whole Public Warrant issued in our IPO entitles the registered holder to purchase one whole share of our Class A Common Stock at a
price of $11.50 per share, subject to adjustment as discussed below, at any time commencing 12 months from the closing of our IPO. Pursuant to the warrant agreement, a warrant holder may
exercise its Public Warrants only for a whole
number of shares of Class A Common Stock. No fractional Public Warrants have been issued and only whole Public
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Warrants
trade. The Public Warrants will expire five years after the Business Combination Closing Date, at 5:00 p.m., New York City time, or earlier upon redemption or liquidation.
The
Company will not be obligated to deliver any shares of Class A Common Stock pursuant to the exercise of a Public Warrant and will have no obligation to settle exercise unless
the registration statement of which this prospectus forms a part is then effective and a prospectus relating thereto is current, subject to the Company satisfying its obligations described
below with respect to registration. No Public Warrant will be exercisable and the Company will not be obligated to issue shares of Class A Common Stock upon exercise of a Public Warrant unless
Class A Common Stock issuable upon such exercise has been registered, qualified or deemed to be exempt under the securities laws of the state of residence of the registered holder of the Public
Warrants. In the event that the conditions in the two immediately preceding sentences are not satisfied with respect to a Public Warrant, the holder of such Public Warrant will not be entitled to
exercise such Public Warrant and such Public Warrant may have no value and expire worthless.
Pursuant
to the warrant agreement, we have filed with the SEC a registration statement on Form S-1 for the registration under the Securities Act of the shares of Class A
Common Stock issuable upon exercise of the Public Warrants. We have agreed to use our best efforts to maintain the effectiveness of such registration statement, and a current prospectus relating
thereto, until the expiration of the Public Warrants in accordance with the provisions of the warrant agreement. Notwithstanding the above, if the Class A Common Stock is at the time of any
exercise of a Public Warrant not listed on a national securities exchange such that it satisfies the definition of a "covered security" under Section 18 (b)(1) of the Securities Act, the
Company may, at its option, require holders of Public Warrants who exercise their Public Warrants to do so on a "cashless basis" in accordance with Section 3(a)(9) of the Securities Act and, in
the event the Company so elects, it will not be required to file or maintain in effect a registration statement, but the Company will be required to use its best efforts to register or qualify the
shares under applicable blue sky laws to the extent an exemption is not available.
Once
the Public Warrants become exercisable, the Company may call the Public Warrants for redemption:
-
(a)
-
in
whole and not in part;
-
(b)
-
at
a price of $0.01 per Public Warrant;
-
(c)
-
upon
not less than 30 days' prior written notice of redemption (the "30-day redemption period") to each Public Warrant holder; and
-
(d)
-
if,
and only if, the reported last sale price of the Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within a 30-trading day
period ending three business days before the Company sends the notice of redemption to the Public Warrant holders.
If
and when the Public Warrants become redeemable by the Company, the Company may exercise its redemption right even if it is unable to register or qualify the underlying securities for
sale under all applicable state securities laws.
The
Company has established the redemption criterion described in clause (d) above to allow a redemption call only if the Class A Common Stock is trading at the time of the
call at a significant premium to the Public Warrant exercise price. If the foregoing conditions are satisfied and the Company issues a notice of redemption of the Public Warrants, each Public Warrant
holder will be entitled to exercise its Public Warrant prior to the scheduled redemption date. However, the price of the Class A Common Stock may fall below the $18.00 redemption trigger price
as well as the $11.50 Public Warrant exercise price after the redemption notice is issued.
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If
the Company calls the Public Warrants for redemption as described above, the Company's management will have the option to require any holder that wishes to exercise its Public Warrant
to do so on a "cashless basis." In determining whether to require all holders to exercise their Public Warrants on a "cashless basis," the Company's management will consider, among other factors, its
cash position, the number of Public Warrants that are outstanding and the dilutive effect on its stockholders of issuing the maximum number of shares of Class A Common Stock issuable upon the
exercise of its Public Warrants. If the Company's management takes advantage of this option, all holders of Public Warrants would pay the exercise price by surrendering their Public Warrants for that
number of shares of Class A Common Stock equal to the quotient obtained by dividing (x) the product of the number of shares of Class A Common Stock underlying the Public Warrants,
multiplied by the difference between the exercise price of the Public Warrants and the "fair market value" (defined below) by (y) the fair market
value. The "fair market value" shall mean the average reported last sale price of the Class A Common Stock for the 10 trading days ending on the third trading day prior to the date on which the
notice of redemption is sent to the holders of Public Warrants. If the Company's management takes advantage of this option, the notice of redemption will contain the information necessary to calculate
the number of shares of Class A Common Stock to be received upon exercise of the Public Warrants, including the "fair market value" in such case. Requiring a cashless exercise in this manner
will reduce the number of shares to be issued and thereby lessen the dilutive effect of a Public Warrant redemption. The Company believes this feature is an attractive option to the Company if it does
not need the cash from the exercise of the Public Warrants. If the Company calls its Public Warrants for redemption and its management does not take advantage of this option, our Sponsor and its
permitted transferees would still be entitled to exercise their Private Placement Warrants for cash or on a cashless basis using the same formula described above that other Public Warrant holders
would have been required to use had all Public Warrant holders been required to exercise their Public Warrants on a cashless basis, as described in more detail below.
A
holder of a Public Warrant may notify the Company in writing in the event it elects to be subject to a requirement that such holder will not have the right to exercise such Public
Warrant, to the extent that after giving effect to such exercise, such person (together with such person's affiliates), to the warrant agent's actual knowledge, would beneficially own in excess of
9.8% (or such other amount as a holder may specify) of the shares of Class A Common Stock outstanding immediately after giving effect to such exercise.
If
the number of outstanding shares of Class A Common Stock is increased by a stock dividend payable in shares of Class A Common Stock, or by a split-up of shares of
Class A Common Stock or other similar event, then, on the effective date of such stock dividend, split-up or similar event, the number of shares of Class A Common Stock issuable on
exercise of each Public Warrant will be increased in proportion to such increase in the outstanding shares of Class A Common Stock. A rights offering to holders of Class A Common Stock
entitling holders to purchase shares of Class A Common Stock at a price less than the fair market value will be deemed a stock dividend of a number of shares of Class A Common Stock
equal to the product of (i) the number of shares of Class A Common Stock actually sold in such rights offering (or issuable under any other equity securities sold in such rights offering
that are convertible into or exercisable for Class A Common Stock) multiplied by (ii) one (1) minus the quotient of (x) the price per share of Class A Common
Stock paid in such rights offering divided by (y) the fair market value. For these purposes (i) if the rights offering is for securities convertible into or exercisable for
Class A Common Stock, in determining the price payable for Class A Common Stock, there will be taken into account any consideration received for such rights, as well as any additional
amount payable upon exercise or conversion and (ii) fair market value means the volume weighted average price of Class A Common Stock as reported during the 10 trading day period ending
on the trading day prior to the first date on which the shares of Class A Common Stock trade on the applicable exchange or in the applicable market, regular way, without the right to receive
such rights.
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In
addition, if the Company, at any time while the Public Warrants are outstanding and unexpired, pays a dividend or makes a distribution in cash, securities or other assets to the
holders of Class A Common Stock on account of such shares of Class A Common Stock (or other shares of the Company's capital stock into which the Public Warrants are convertible), other
than (a) as described above or (b) certain ordinary cash dividends, then the Public Warrant exercise price will be decreased, effective immediately after the effective date of such
event, by the amount of cash and/or the fair market value of any securities or other assets paid on each share of Class A Common Stock in respect of such event.
If
the number of outstanding shares of Class A Common Stock is decreased by a consolidation, combination, reverse stock split or reclassification of shares of Class A
Common Stock or other similar event, then, on the effective date of such consolidation, combination, reverse stock split, reclassification or similar event, the number of shares of Class A
Common Stock issuable on exercise of each Public Warrant will be decreased in proportion to such decrease in outstanding shares of Class A Common Stock.
Whenever
the number of shares of Class A Common Stock purchasable upon the exercise of the Public Warrants is adjusted, as described above, the Public Warrant exercise price will
be adjusted by multiplying the exercise price immediately prior to such adjustment by a fraction (x) the numerator of which will be the number of shares of Class A Common Stock
purchasable upon the exercise of the Public Warrants immediately prior to such adjustment, and (y) the denominator of which will be the number of shares of Class A Common Stock so
purchasable immediately thereafter.
In
case of any reclassification or reorganization of the outstanding shares of Class A Common Stock (other than those described above or that solely affects the par value of such
shares of Class A Common Stock), or in the case of any merger or consolidation of the Company with or into another corporation (other than a consolidation or merger in which the Company is the
continuing corporation and that does not result in any reclassification or reorganization of the Company's outstanding shares of Class A Common Stock), or in the case of any sale or conveyance
to another corporation or entity of the assets or other property of the Company as an entirety or substantially as an entirety in connection with which the Company is dissolved, the holders of the
Public Warrants will thereafter have the right to purchase and receive, upon the basis and upon the terms and conditions specified in the Public Warrants and in lieu of the shares of Class A
Common Stock immediately theretofore purchasable and receivable upon the exercise of the rights represented thereby, the kind and amount of shares of stock or other securities or property (including
cash) receivable upon such reclassification, reorganization, merger or consolidation, or upon a dissolution following any such sale or transfer, that the holder of the Public Warrants would have
received if such holder had exercised their Public Warrants immediately prior to such event. If less than 70% of the consideration receivable by the holders of Class A Common Stock in such a
transaction is payable in the form of Class A Common Stock in the successor entity that is listed for trading on a national securities exchange or is quoted in an established over-the-counter
market, or is to be so listed for trading or quoted immediately following such event, and if the registered holder of the Public Warrant properly exercises the Public Warrant within 30 days
following public disclosure of such transaction, the Public Warrant exercise price will be reduced as specified in the warrant agreement based on the Black-Scholes value (as defined in the warrant
agreement) of the Public Warrant.
The
Public Warrants may be exercised upon surrender of the warrant certificate on or prior to the expiration date at the offices of the warrant agent, with the exercise form on the
reverse side of the warrant certificate completed and executed as indicated, accompanied by full payment of the exercise price (or on a cashless basis, if applicable), by certified or official bank
check payable to the Company, for the number of Public Warrants being exercised. The Public Warrant holders do not have the rights or privileges of holders of Class A Common Stock and any
voting rights until they exercise their Public Warrants and receive shares of Class A Common Stock. After the issuance of shares of Class A
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Common
Stock upon exercise of the Public Warrants, each holder will be entitled to one vote for each share held of record on all matters to be voted on by stockholders.
No
fractional shares will be issued upon exercise of the Public Warrants. If, upon exercise of the Public Warrants, a holder would be entitled to receive a fractional interest in a
share, the Company will, upon exercise, round down to the nearest whole number of shares of Class A Common Stock to be issued to the Public Warrant holder.
The
Public Warrants have been issued in registered form under a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and the Company. The
warrant agreement provides that the terms of the Public Warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by
the holders of at least 50% of the then outstanding Public Warrants to make any change that adversely affects the interests of the registered holders of Public Warrants.
The Private Placement Warrants (including the Class A Common Stock issuable upon exercise of the Private Placement Warrants) will not be
transferable, assignable or saleable until 30 days after the closing of the Business Combination (except, among other limited exceptions, to the Company's officers and directors and other
persons or entities affiliated with our Sponsor) and they will not be redeemable by the Company so long as they are held by our Sponsor or its permitted transferees. Otherwise, the Private Placement
Warrants have terms and provisions that are identical to those of the Public Warrants, including as to exercise price, exercisability and exercise period. If the Private Placement Warrants are held by
holders other than our Sponsor or its permitted transferees, the Private Placement Warrants will be redeemable by the Company and exercisable by the holders on the same basis as the Public Warrants.
If
holders of the Private Placement Warrants elect to exercise them on a cashless basis, they would pay the exercise price in the same manner as holders of Public Warrants as described
above under "Public Warrants." The reason that the Company has agreed that the Private Placement Warrants will be exercisable on a cashless basis so long as they are held by our Sponsor
or its permitted transferees is because it was not known at the time of issuance whether our Sponsor would be affiliated with the Company following an initial business combination. If our Sponsor
remains affiliated with the Company, its ability to sell the Company's securities in the open market will be significantly limited. The Company has policies in place that prohibit insiders from
selling the Company's securities except during specific periods of time. Even during such periods of time when insiders will be permitted to sell the Company's securities, an insider cannot trade in
the Company's securities if he or she is in possession of material non-public information. Accordingly, unlike public stockholders who could sell the shares of Class A Common Stock issuable
upon exercise of the Public Warrants freely in the open market, the insiders could be significantly restricted from doing so. As a result, the Company believes that allowing the holders to exercise
the Private Placement Warrants on a cashless basis is appropriate.
Our
Sponsor has agreed not to transfer, assign or sell any of the Private Placement Warrants (including the Class A Common Stock issuable upon exercise of any of the Private
Placement Warrants) until the date that is 30 days after the Business Combination Closing Date, except to, among other limited exceptions, the Company's officers and directors and other persons
or entities affiliated with our Sponsor.
The
Private Placement Warrants were sold in a private placement pursuant to a purchase agreement between us and our Sponsor and have the terms set forth in a warrant agreement between
Continental Stock Transfer & Trust Company, as warrant agent, and the Company.
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Our Transfer Agent and Warrant Agent
The transfer agent for our Class A Common Stock, Class C Common Stock and Series B Preferred Stock and warrant agent for
the Public Warrants and Private Placement Warrants is Continental Stock Transfer & Trust Company. We have agreed to indemnify Continental Stock Transfer & Trust Company in its roles as
transfer agent and warrant agent, its agents and each of its stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its
activities in that capacity, except for any liability due to any gross negligence, willful misconduct or bad faith of the indemnified person or entity.
Certain Anti-Takeover Provisions of Delaware Law and our Charter and Bylaws
We are subject to the provisions of Section 203 of the DGCL regulating corporate takeovers. This statute prevents certain Delaware
corporations, under certain circumstances, from engaging in a "business combination" with:
-
-
a stockholder who owns 15% or more of our outstanding voting stock (otherwise known as an "interested stockholder");
-
-
an affiliate of an interested stockholder; or
-
-
an associate of an interested stockholder, for three years following the date that the stockholder became an interested stockholder.
A
"business combination" includes a merger or sale of more than 10% of our assets. However, the above provisions of Section 203 do not apply
if:
-
-
our board of directors approves the transaction that made the stockholder an "interested stockholder," prior to the date of the transaction;
-
-
after the completion of the transaction that resulted in the stockholder becoming an interested stockholder, that stockholder owned at least
85% of our voting stock outstanding at the time the transaction commenced, other than statutorily excluded shares of common stock; or
-
-
on or subsequent to the date of the transaction, the business combination is approved by our board of directors and authorized at a meeting of
our stockholders, and not by written consent, by an affirmative vote of at least two-thirds of the outstanding voting stock not owned by the interested stockholder.
Under
our Charter, our board of directors is classified into three classes of directors. As a result, in most circumstances, a person can gain control of our board only by successfully
engaging in a proxy contest at two or more annual meetings.
Our
authorized but unissued common stock and preferred stock are available for future issuances without stockholder approval (including a specified future issuance) and could be utilized
for a variety of corporate purposes, including future offerings to raise additional capital, acquisitions and employee benefit plans. The existence of authorized but unissued and unreserved common
stock and preferred stock could render more difficult or discourage an attempt to obtain control of us by means of a proxy contest, tender offer, merger or otherwise.
Our Bylaws provide that special meetings of our stockholders may be called only by a majority vote of our board of directors, by our Chief
Executive Officer or by our Chairman.
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Our Bylaws provide that stockholders seeking to bring business before our annual meeting of stockholders, or to nominate candidates for election
as directors at our annual meeting of stockholders, must provide timely notice of their intent in writing. To be timely, a stockholder's notice will need to be received by the company secretary at our
principal executive offices not later than the close of business on the 90th day nor earlier than the close of business on the 120th day prior to the anniversary date of the immediately
preceding annual meeting of stockholders. Pursuant to Rule 14a-8 of the Exchange Act, proposals seeking inclusion in our annual proxy statement must comply with the notice periods contained
therein. Our Bylaws also specify certain requirements as to the form and content of a stockholders' meeting. These provisions may preclude our stockholders from bringing matters before our annual
meeting of stockholders or from making nominations for directors at our annual meeting of stockholders.
Rule 144
Pursuant to Rule 144, a person who has beneficially owned restricted shares of our Class A Common Stock or Private Placement
Warrants for at least six months would be entitled to sell their securities provided that (i) such person is not deemed to have been one of our affiliates at the time of, or at any time during
the three months preceding, a sale and (ii) we are subject to the Exchange Act periodic reporting requirements for at least three months before the sale and have filed all required reports
under Section 13 or 15(d) of the Exchange Act during the 12 months (or such shorter period as we were required to file reports) preceding the sale.
Persons
who have beneficially owned restricted shares of our Class A Common Stock or Private Placement Warrants for at least six months but who are our affiliates at the time of,
or at any time during the three months preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three-month period only a number of
securities that does not exceed the greater of:
-
-
1% of the total number of shares of Class A Common Stock then outstanding; or
-
-
the average weekly reported trading volume of the Class A Common Stock during the four calendar weeks preceding the filing of a notice
on Form 144 with respect to the sale.
Sales
by our affiliates under Rule 144 are also limited by manner of sale provisions and notice requirements and to the availability of current public information about us.
Rule 144 is not available for the resale of securities initially issued by shell companies (other than business combination related shell
companies) or issuers that have been at any time previously a shell company. However, Rule 144 also includes an important exception to this prohibition if the following conditions are
met:
-
-
the issuer of the securities that was formerly a shell company has ceased to be a shell company;
-
-
the issuer of the securities is subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act;
-
-
the issuer of the securities has filed all Exchange Act reports and materials required to be filed, as applicable, during the preceding
12 months (or such shorter period that the issuer was required to file such reports and materials), other than Current Reports on Form 8-K; and
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-
-
at least one year has elapsed from the time that the issuer filed current Form 10 type information with the Securities and Exchange
Commission reflecting its status as an entity that is not a shell company.
As
a result, if we have filed all Exchange Act reports and materials as set forth in the third bullet of the preceding paragraph, then any holder of restricted shares of our
Class A Common Stock or Private Placement Warrants (including our initial stockholders with respect to their founder shares and Private Placement Warrants) will be able to sell such shares or
Private Placement Warrants, as applicable, pursuant to Rule 144 without registration one year following the closing of the Business Combination.
Listing of Securities
The Company's Class A Common Stock and Public Warrants are currently quoted on NASDAQ under the symbols "CDEV" and "CDEVW," respectively.
Through October 11, 2016, our Class A Common Stock, Public Warrants and Units were quoted under the symbols "SRAQ," "SRAQW," and "SRAQU," respectively. Upon the consummation of the
Business Combination, we separated our Units into their component securities of one share of Class A Common Stock and one-third of one Public Warrant, and the Units ceased public trading.
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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS
The following discussion is a summary of the material U.S. federal income tax consequences to Non-U.S. Holders (as defined below) of the
purchase, ownership and disposition of our Class A Common Stock issued pursuant to this offering, but does not purport to be a complete analysis of all potential tax effects. The effects of
other U.S. federal tax laws, such as estate and gift tax laws, and any applicable state, local or non-U.S. tax laws are not discussed. This discussion is based on the Code, Treasury regulations
promulgated thereunder ("Treasury Regulations"), judicial decisions, and published rulings and administrative pronouncements of the U.S. Internal Revenue Service (the "IRS"), in each case as in effect
as of the date hereof. These authorities may change or be subject to differing interpretations. Any such change or differing interpretation may be applied retroactively in a manner that could
adversely affect a Non-U.S. Holder of our Class A Common Stock. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance
the IRS or a court will not take a contrary position to that discussed below regarding the tax consequences of the purchase, ownership and disposition of our Class A Common Stock.
This
discussion is limited to Non-U.S. Holders that hold our Class A Common Stock as a "capital asset" within the meaning of Section 1221 of the Code (generally, property
held for investment). This discussion does not address all U.S. federal income tax consequences relevant to a Non-U.S. Holder's particular circumstances, including the impact of the Medicare
contribution tax on net investment income. In addition, it does not address consequences relevant to Non-U.S. Holders subject to special rules, including, without
limitation:
-
-
U.S. expatriates and former citizens or long-term residents of the United States;
-
-
persons subject to the alternative minimum tax;
-
-
persons holding our Class A Common Stock as part of a hedge, straddle or other risk reduction strategy or as part of a conversion
transaction or other integrated investment;
-
-
banks, insurance companies, and other financial institutions;
-
-
brokers, dealers or traders in securities;
-
-
"controlled foreign corporations," "passive foreign investment companies," and corporations that accumulate earnings to avoid U.S. federal
income tax;
-
-
partnerships, or other entities or arrangements treated as partnerships for U.S. federal income tax purposes;
-
-
tax-exempt organizations or governmental organizations;
-
-
persons deemed to sell our Class A Common Stock under the constructive sale provisions of the Code;
-
-
persons who hold or receive our Class A Common Stock pursuant to the exercise of any employee stock option or otherwise as compensation;
-
-
"qualified foreign pension funds" as defined in Section 897(l)(2) of the Code and entities all of the interests of which are held by
qualified foreign pension funds; and
-
-
tax-qualified retirement plans.
If
an entity treated as a partnership for U.S. federal income tax purposes holds our Class A Common Stock, the tax treatment of a partner in the partnership will depend on the
status of the partner, the activities of the partnership and certain determinations made at the partner level. Accordingly, partnerships holding our Class A Common Stock and partners in such
partnerships should consult their tax advisors regarding the U.S. federal income tax consequences to them.
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THIS DISCUSSION IS FOR INFORMATIONAL PURPOSES ONLY AND IS NOT TAX ADVICE. INVESTORS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME
TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR
UNDER THE LAWS OF ANY STATE, LOCAL OR NON-U.S. TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.
Definition of a Non-U.S. Holder
For purposes of this discussion, a "Non-U.S. Holder" is any beneficial owner of our Class A Common Stock that is neither a "U.S. person"
nor an entity treated as a partnership for U.S. federal income tax purposes. A U.S. person is any person that, for U.S. federal income tax purposes, is or is treated as any of the
following:
-
-
an individual who is a citizen or resident of the United States;
-
-
a corporation created or organized under the laws of the United States, any state thereof, or the District of Columbia;
-
-
an estate, the income of which is subject to U.S. federal income tax regardless of its source; or
-
-
a trust that (1) is subject to the primary supervision of a U.S. court and the control of one or more "United States persons" (within
the meaning of Section 7701(a)(30) of the Code), or (2) has a valid election in effect to be treated as a United States person for U.S. federal income tax purposes.
Distributions
As described in the section entitled "Dividend Policy" we do not anticipate declaring or paying dividends to holders of our Class A
Common Stock in the foreseeable future. However, if we do make distributions of cash or property on our Class A Common Stock, such distributions will constitute dividends for U.S. federal
income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Amounts not treated as dividends for U.S. federal
income tax purposes will constitute a return of capital and first be applied against and reduce a Non-U.S. Holder's adjusted tax basis in its Class A Common Stock, but not below zero. Any
excess will be treated as capital gain and will be treated as described below under "Sale or Other Taxable Disposition."
Subject
to the discussion below on effectively connected income, dividends paid to a Non-U.S. Holder of our Class A Common Stock will be subject to U.S. federal withholding tax at
a rate of 30% of the gross amount of the dividends (or such lower rate specified by an applicable income tax treaty, provided the Non-U.S. Holder furnishes a valid IRS Form W-8BEN or W-8BEN-E
(or other applicable documentation) certifying qualification for the lower treaty rate). A Non-U.S. Holder that does not timely furnish the required documentation, but that qualifies for a reduced
treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. Holders should consult their tax advisors regarding their
entitlement to benefits under any applicable income tax treaty.
If
dividends paid to a Non-U.S. Holder are effectively connected with the Non-U.S. Holder's conduct of a trade or business within the United States (and, if required by an applicable
income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such dividends are attributable), the Non-U.S. Holder will be exempt from the U.S. federal
withholding tax described above. To claim the exemption, the Non-U.S. Holder must furnish to the applicable
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withholding
agent a valid IRS Form W-8ECI, certifying that the dividends are effectively connected with the Non-U.S. Holder's conduct of a trade or business within the United States.
Any
such effectively connected dividends will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. A Non-U.S. Holder that is a corporation also may
be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items),
which will include such effectively connected dividends. Non-U.S. Holders should consult their tax advisors regarding any applicable tax treaties that may provide for different rules.
Sale or Other Taxable Disposition
A Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of our
Class A Common Stock unless:
-
-
the gain is effectively connected with the Non-U.S. Holder's conduct of a trade or business within the United States (and, if required by an
applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such gain is attributable);
-
-
the Non-U.S. Holder is a nonresident alien individual present in the United States for 183 days or more during the taxable year of the
disposition and certain other requirements are met; or
-
-
our Class A Common Stock constitutes a United States real property interest ("USRPI") by reason of our status as a United States real
property holding corporation ("USRPHC") for U.S. federal income tax purposes. Generally, a domestic corporation is a USRPHC if the fair market value of its USRPIs equals or exceeds 50% of the sum of
the fair market value of its worldwide real property interests plus its other assets used or held for use in its trade or business.
Gain
described in the first bullet point above generally will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. A Non-U.S. Holder that is a
corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on its effectively connected earnings and profits (adjusted
for certain items), which will include such effectively connected gain.
A
Non-U.S. Holder described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty)
on any gain derived from the disposition, which may be offset by U.S. source capital losses of the Non-U.S. Holder (even though the individual is not considered a resident of the United States),
provided the Non-U.S. Holder has timely filed U.S. federal income tax returns with respect to such losses.
With
respect to the third bullet point above, we believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, a
Non-U.S. Holder of our Class A Common Stock generally will not be subject to U.S. net federal income tax as a result of our being a USRPHC if our Class A Common Stock is "regularly
traded," as defined by applicable Treasury Regulations, on an established securities market, and such Non-U.S. Holder owned, actually or constructively, 5% or less of our Class A Common Stock
throughout the shorter of the five-year period ending on the date of the sale or other taxable disposition or the Non-U.S. Holder's holding period. If our Class A Common Stock is not considered
to be so traded, a Non-U.S. Holder generally would be subject to net U.S. federal income tax on the gain realized on a disposition of our Class A Common Stock as a result of our being a USRPHC
and generally would be required to file a U.S. federal income tax return. Additionally, a 15% withholding tax would apply to the gross proceeds from such disposition.
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Non-U.S.
Holders should also consult their tax advisors regarding potentially applicable income tax treaties that may provide for different rules.
Information Reporting and Backup Withholding
Payments of dividends on our Class A Common Stock will not be subject to backup withholding, provided the applicable withholding agent
does not have actual knowledge or reason to know the Non-U.S. Holder is a United States person and the Non-U.S. Holder either
certifies its non-U.S. status, such as by furnishing a valid IRS Form W-8BEN, W-8BEN-E or W-8ECI, or otherwise establishes an exemption. However, information returns are required to be filed
with the IRS in connection with any dividends on our Class A Common Stock paid to the Non-U.S. Holder, regardless of whether any tax was actually withheld. In addition, proceeds of the sale or
other taxable disposition of our Class A Common Stock within the United States or conducted through certain U.S.-related brokers generally will not be subject to backup withholding or
information reporting if the applicable withholding agent receives the certification described above and does not have actual knowledge or reason to know that such Non-U.S. Holder is a United States
person, or the Non-U.S. Holder otherwise establishes an exemption. Proceeds of a disposition of our Class A Common Stock conducted through a non-U.S. office of a non-U.S. broker generally will
not be subject to backup withholding or information reporting.
Copies
of information returns that are filed with the IRS may also be made available under the provisions of an applicable treaty or agreement to the tax authorities of the country in
which the Non-U.S. Holder resides or is established.
Backup
withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a Non-U.S. Holder's U.S. federal
income tax liability, provided the required information is timely furnished to the IRS.
Additional Withholding Tax on Payments Made to Foreign Accounts
Withholding taxes may be imposed under Sections 1471 to 1474 of the Code (such Sections commonly referred to as the Foreign Account Tax
Compliance Act, or "FATCA") on certain types of payments made to non-U.S. financial institutions and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends
on, or gross proceeds from the sale or other disposition of, our Class A Common Stock paid to a "foreign financial institution" or a "non-financial foreign entity" (each as defined in the Code)
(including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (1) the foreign financial institution undertakes certain
diligence and reporting obligations, (2) the non-financial foreign entity either certifies it does not have any "substantial United States owners" (as defined in the Code) or furnishes
identifying information regarding each direct and indirect substantial United States owner, or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an
exemption from these rules and provides appropriate documentation (such as IRS Form W-8BEN-E). If the payee is a foreign financial institution and is subject to the diligence and reporting
requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain
"specified United States persons" or "United States-owned foreign entities" (each as defined in the Code), annually report certain information about such accounts, and withhold 30% on certain payments
to non-compliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United
States governing FATCA may be subject to different rules.
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Under
the applicable Treasury Regulations and administrative guidance, withholding under FATCA generally applies to payments of dividends on our Class A Common Stock, and will
apply to payments of gross proceeds from the sale or other disposition of such stock on or after January 1, 2019.
Prospective
investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our Class A Common Stock.
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LEGAL MATTERS
The validity of the securities offered hereby will be passed upon for us by Latham & Watkins LLP of Houston, Texas. Any
underwriters or agents will be advised about other issues relating to the offering by counsel to be named in the applicable prospectus supplement.
EXPERTS
The consolidated and combined financial statements of Centennial Resource Production, LLC and Celero Energy Company, LP
(Predecessor) as of December 31, 2015 and 2014, and each of the years in the three-year period ended December 31, 2015, have been included herein and in the registration statement in
reliance upon the reports of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
Estimates
of our oil and natural gas reserves and related future net cash flows related to our properties as of December 31, 2015 and December 31, 2014 included herein and
elsewhere in the registration statement were based upon a reserve report prepared by our independent petroleum engineer, Netherland, Sewell & Associates, Inc. We have included these
estimates in reliance on the authority of such firm as an expert in such matters.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the shares of Class A
Common Stock offered by this prospectus. This prospectus does not contain all of the information included in the registration statement. For further information pertaining to us and our Class A
Common Stock you should refer to the registration statement and its exhibits. Statements contained in this prospectus concerning any of our contracts, agreements or other documents are not necessarily
complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed. Each statement in this
prospectus relating to a contract or document filed as an exhibit is qualified in all respects by the filed exhibit.
We
are subject to the informational requirements of the Exchange Act and file annual, quarterly and current reports and other information with the SEC. Our filings with the SEC are
available to the public on the SEC's website at http://www.sec.gov. Those filings are also available to the public on, or accessible through, our website under the heading "Investors" at
www.cdevinc.com. The information we file with the SEC or contained on or accessible through our corporate website or any other website that we may maintain is not part of this prospectus or the
registration statement of which this prospectus is a part. You may also read and copy, at SEC prescribed rates, any document we file with the SEC, including the registration statement (and its
exhibits) of which this prospectus is a part, at the SEC's Public Reference Room located at 100 F Street, N.E., Washington D.C. 20549. You can call the SEC at 1-800-SEC-0330 to obtain
information on the operation of the Public Reference Room.
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INDEX TO FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Page
|
|
CENTENNIAL RESOURCE PRODUCTION, LLC (PREDECESSOR)UNAUDITED FINANCIAL STATEMENTS
|
|
|
|
|
Condensed Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015
|
|
|
F-2
|
|
Condensed Consolidated Statements of Operations For the Three and Nine Months Ended September 30, 2016 and
2015
|
|
|
F-3
|
|
Condensed Consolidated Statement of Changes in Owners' Equity For the Nine Months Ended September 30,
2016
|
|
|
F-4
|
|
Condensed Consolidated Statements of Cash Flows For the Nine Months Ended September 30, 2016 and
2015
|
|
|
F-5
|
|
Notes to Condensed Consolidated Financial Statements
|
|
|
F-6
|
|
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP (PREDECESSOR)AUDITED FINANCIAL
STATEMENTS
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
F-17
|
|
Consolidated and Combined Balance Sheets as of December 31, 2015 and 2014
|
|
|
F-18
|
|
Consolidated and Combined Statements of Operations For the Years Ended December 31, 2015, 2014 and 2013
|
|
|
F-19
|
|
Consolidated and Combined Statements of Changes in Owners' Equity For the Years ended December 31, 2015, 2014 and
2013
|
|
|
F-20
|
|
Consolidated and Combined Statements of Cash Flows For the Years ended December 31, 2015, 2014 and 2013
|
|
|
F-21
|
|
Notes to Consolidated and Combined Financial Statements
|
|
|
F-22
|
|
SILVER RUN ACQUISITION CORPORATIONUNAUDITED PRO FORMA FINANCIAL STATEMENTS
|
|
|
|
|
Unaudited pro forma condensed consolidated combined financial information of
Silver Run Acquisition Corporation for the three years ended December 31, 2015 and the nine months ended September 30, 2016.
|
|
|
F-47
|
|
F-1
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(Predecessor)
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In Thousands)
|
|
|
|
|
|
|
|
|
|
September 30,
2016
|
|
December 31,
2015
|
|
ASSETS
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
410
|
|
$
|
1,768
|
|
Accounts receivable, net
|
|
|
10,358
|
|
|
13,012
|
|
Derivative instruments, net
|
|
|
1,618
|
|
|
19,043
|
|
Prepaid and other current assets
|
|
|
864
|
|
|
322
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
13,250
|
|
|
34,145
|
|
Oil and natural gas properties, other property and equipment
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
|
|
718,999
|
|
|
651,596
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(241,017
|
)
|
|
(180,946
|
)
|
Unproved oil and natural gas properties
|
|
|
139,690
|
|
|
105,897
|
|
Other property and equipment, net of accumulated depreciation of $1,665 and $868, respectively
|
|
|
1,703
|
|
|
2,240
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
619,375
|
|
|
578,787
|
|
Noncurrent assets
|
|
|
|
|
|
|
|
Derivative instruments, net
|
|
|
245
|
|
|
2,070
|
|
Other noncurrent assets
|
|
|
1,042
|
|
|
1,293
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
633,912
|
|
$
|
616,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND OWNERS' EQUITY
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
23,579
|
|
$
|
19,985
|
|
Derivative instruments, net
|
|
|
1,000
|
|
|
|
|
Other current liabilities
|
|
|
243
|
|
|
2,148
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
24,822
|
|
|
22,133
|
|
Noncurrent liabilities
|
|
|
|
|
|
|
|
Revolving credit facility
|
|
|
124,000
|
|
|
74,000
|
|
Term loan, net of unamortized deferred financing costs
|
|
|
64,762
|
|
|
64,649
|
|
Asset retirement obligations
|
|
|
2,680
|
|
|
2,288
|
|
Deferred tax liability
|
|
|
1,954
|
|
|
2,361
|
|
Derivative instruments, net
|
|
|
557
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
218,775
|
|
|
165,431
|
|
Owners' equity
|
|
|
415,137
|
|
|
450,864
|
|
|
|
|
|
|
|
|
|
Total liabilities and owners' equity
|
|
$
|
633,912
|
|
$
|
616,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
F-2
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(Predecessor)
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three
Months Ended
September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
23,388
|
|
$
|
18,913
|
|
$
|
56,975
|
|
$
|
59,068
|
|
Natural gas sales
|
|
|
2,629
|
|
|
2,054
|
|
|
5,717
|
|
|
6,082
|
|
NGL sales
|
|
|
1,304
|
|
|
926
|
|
|
3,097
|
|
|
3,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
27,321
|
|
|
21,893
|
|
|
65,789
|
|
|
68,740
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
3,656
|
|
|
4,355
|
|
|
10,295
|
|
|
17,317
|
|
Severance and ad valorem taxes
|
|
|
1,432
|
|
|
1,555
|
|
|
3,523
|
|
|
3,833
|
|
Transportation, processing, gathering and other operating expenses
|
|
|
1,787
|
|
|
1,424
|
|
|
4,375
|
|
|
4,352
|
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
18,454
|
|
|
19,880
|
|
|
60,939
|
|
|
64,003
|
|
Abandonment expense and impairment of unproved properties
|
|
|
1,649
|
|
|
|
|
|
2,546
|
|
|
3,851
|
|
Contract termination and rig stacking
|
|
|
|
|
|
221
|
|
|
|
|
|
2,388
|
|
General and administrative expenses
|
|
|
5,250
|
|
|
3,007
|
|
|
10,655
|
|
|
8,538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
32,228
|
|
|
30,442
|
|
|
92,333
|
|
|
104,282
|
|
Gain on sale of oil and natural gas properties
|
|
|
(15
|
)
|
|
(9
|
)
|
|
(11
|
)
|
|
(2,688
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating loss
|
|
|
(4,892
|
)
|
|
(8,540
|
)
|
|
(26,533
|
)
|
|
(32,854
|
)
|
Other (expense) income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(1,983
|
)
|
|
(1,469
|
)
|
|
(5,422
|
)
|
|
(4,743
|
)
|
Gain (loss) on derivative instruments
|
|
|
1,741
|
|
|
13,344
|
|
|
(4,184
|
)
|
|
12,320
|
|
Other (expense) income
|
|
|
|
|
|
(9
|
)
|
|
6
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other (expense) income
|
|
|
(242
|
)
|
|
11,866
|
|
|
(9,600
|
)
|
|
7,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(5,134
|
)
|
|
3,326
|
|
|
(36,133
|
)
|
|
(25,282
|
)
|
Income tax benefit
|
|
|
|
|
|
|
|
|
406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(5,134
|
)
|
$
|
3,326
|
|
$
|
(35,727
|
)
|
$
|
(25,282
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
F-3
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(Predecessor)
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN OWNER'S EQUITY
(Unaudited)
(In Thousands)
|
|
|
|
|
|
|
Total
Owners' Equity
|
|
Balance at December 31, 2015
|
|
$
|
450,864
|
|
Contributions
|
|
|
|
|
Net loss
|
|
|
(35,727
|
)
|
|
|
|
|
|
Balance at September 30, 2016
|
|
$
|
415,137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
F-4
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(Predecessor)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In Thousands)
|
|
|
|
|
|
|
|
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2016
|
|
2015
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(35,727
|
)
|
$
|
(25,282
|
)
|
Adjustments to reconcile net loss to net cash provided by operating activities:
|
|
|
|
|
|
|
|
Accretion of asset retirement obligations
|
|
|
129
|
|
|
101
|
|
Depreciation, depletion and amortization
|
|
|
60,810
|
|
|
63,902
|
|
Abandonment expense and impairment of unproved properties
|
|
|
2,546
|
|
|
3,851
|
|
Deferred tax expense
|
|
|
(406
|
)
|
|
|
|
Gain on sale of oil and natural gas properties
|
|
|
(11
|
)
|
|
(2,688
|
)
|
Loss (gain) on derivative instruments
|
|
|
4,184
|
|
|
(12,320
|
)
|
Net cash received for derivative settlements
|
|
|
16,623
|
|
|
25,972
|
|
Amortization of debt issuance costs
|
|
|
363
|
|
|
360
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
Decrease in accounts receivable
|
|
|
3,021
|
|
|
4,956
|
|
Increase in prepaid and other assets
|
|
|
(165
|
)
|
|
(656
|
)
|
Increase (decrease) in accounts payable and other liabilities
|
|
|
144
|
|
|
(9,722
|
)
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
51,511
|
|
|
48,474
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
Acquisition of oil and natural gas properties
|
|
|
(55,566
|
)
|
|
(38,315
|
)
|
Development of oil and natural gas properties
|
|
|
(45,203
|
)
|
|
(133,595
|
)
|
Purchases of other property and equipment
|
|
|
(206
|
)
|
|
(2,097
|
)
|
Development of assets held for sale
|
|
|
|
|
|
|
|
Proceeds from sales of oil and natural gas properties and other assets
|
|
|
|
|
|
2,691
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(100,975
|
)
|
|
(171,316
|
)
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
Proceeds from revolving credit facility
|
|
|
55,000
|
|
|
84,000
|
|
Repayment of revolving credit facility
|
|
|
(5,000
|
)
|
|
(83,000
|
)
|
Capital contributions
|
|
|
|
|
|
110,656
|
|
Financing obligation
|
|
|
(1,894
|
)
|
|
(1,238
|
)
|
Debt issuance costs
|
|
|
|
|
|
(199
|
)
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
48,106
|
|
|
110,219
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(1,358
|
)
|
|
(12,623
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
1,768
|
|
|
13,017
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
410
|
|
$
|
394
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
4,993
|
|
$
|
4,340
|
|
Supplemental noncash activity
|
|
|
|
|
|
|
|
Accrued capital expenditures included in accounts payable and accrued expenses
|
|
$
|
16,339
|
|
$
|
14,946
|
|
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
F-5
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1Organization and Nature of Operations
Centennial Resource Production, LLC, a Delaware limited liability company formerly named Atlantic Energy Holdings, LLC ("Centennial OpCo" or the "Predecessor"), was formed
on August 30, 2012 by its management members, third-party investors and NGP Natural Resources X, LP ("NGP X"), an affiliate of Natural Gas Partners, a family of energy-focused
private equity investment funds ("NGP"). Centennial OpCo is engaged in the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves, primarily in the Delaware
Basin of West Texas.
For
additional information regarding the organization and formation of the Predecessor please refer to
Note 1
Organization and Nature of Operations
in the Predecessor's audited
consolidated and combined financial statements for the year ended December 31, 2015, included in the Proxy
Statement of Silver Run Acquisition Corporation filed with the Securities and Exchange Commission on September 23, 2016 (the "Audited Financial Statements").
Note 2Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally
accepted in the United States of America ("U.S. GAAP"). The condensed consolidated financial statements do not include all information and notes required by U.S. GAAP for complete
financial statements. However, except as disclosed herein, there has been no material change in the information disclosed in the notes to the Audited Financial Statements. In the opinion of
management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation of interim financial information, have been included. Operating results for the
periods presented are not necessarily indicative of expected results for the full year. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying
condensed consolidated financial statements.
Assumptions, Judgments and Estimates
The preparation of the Predecessor's condensed consolidated financial statements requires the Predecessor's management to make various
assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these
assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously
established.
The
more significant areas requiring the use of assumptions, judgments and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment
tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) determining fair value and allocating purchase price in connection
with business combinations; (6) valuation of derivative instruments; and (7) accrued revenue and related receivables.
F-6
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 2Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)
Significant Accounting Policies
The significant accounting policies followed by the Predecessor are set forth in
Note 2
Basis of
Presentation
,
Summary of Significant
Accounting Policies, and Recently Issued Accounting Standards
in the Audited Financial Statements.
Recently Issued Accounting Standards
In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-15,
Classification of Certain Cash
Receipts and Cash Payments
, which clarifies how certain cash receipts and cash payments are presented and classified in
the statement of cash flows. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The new standard becomes effective for the
Predecessor on January 1, 2018, with early adoption is permitted. The Predecessor is evaluating the impact, if any, that the adoption of this update will have on the Predecessor's condensed
consolidated financial statements and related disclosures.
In
March 2016, the FASB issued ASU No. 2016-09,
Improvements to Employee Share-Based Payment Accounting
, which includes provisions
intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment will be effective prospectively for
reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Predecessor is evaluating the impact, if any, that the adoption of this update will have on the
Predecessor's condensed consolidated financial statements and related disclosures.
In
February 2016, the FASB issued ASU No. 2016-02,
Leases
, which requires all leasing arrangements to be presented in the balance
sheet as liabilities along with a corresponding asset. This ASU will replace most existing leases guidance in U.S. GAAP when it becomes effective. The new standard becomes effective for the
Predecessor on January 1, 2019. Although early adoption is permitted, the Predecessor does not plan to early adopt the ASU. The standard requires the use of the modified retrospective
transition method. The Predecessor is evaluating the impact, if any, that the adoption of this update will have on the Predecessor's condensed consolidated financial statements and related
disclosures.
In
May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers
. This guidance is to be applied using a full retrospective
method or a modified retrospective method, as outlined in the guidance. In August 2015, the FASB deferred the effective date of the new revenue recognition standard by one year. The revenue
recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual
periods, and interim periods within those annual periods, beginning after December 15, 2016. The Predecessor is evaluating the impact, if any, that the adoption of this update will have on our
consolidated and combined financial statements and related disclosures.
Other
than as disclosed above or set forth in
Note
2
Basis of Presentation
,
Summary of Significant Accounting Policies, and Recently
Issued Accounting Standards
in the Predecessor's Audited Financial
F-7
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 2Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)
Statements,
there are no other new accounting standards that would have a material impact on the Predecessor's condensed consolidated financial statements and disclosures.
Note 3Accounts Receivable, Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
|
|
|
|
|
|
|
|
|
|
September 30,
2016
|
|
December 31,
2015
|
|
|
|
(in thousands)
|
|
Oil and natural gas
|
|
$
|
8,372
|
|
$
|
5,789
|
|
Joint interest billings
|
|
|
892
|
|
|
1,514
|
|
Hedge settlements
|
|
|
751
|
|
|
3,956
|
|
Other
|
|
|
434
|
|
|
1,844
|
|
Allowance for doubtful accounts
|
|
|
(91
|
)
|
|
(91
|
)
|
|
|
|
|
|
|
|
|
Accounts receivable, net
|
|
$
|
10,358
|
|
$
|
13,012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable and accrued expenses are comprised of the following:
|
|
|
|
|
|
|
|
|
|
September 30,
2016
|
|
December 31,
2015
|
|
|
|
(in thousands)
|
|
Accounts payable
|
|
$
|
7,365
|
|
$
|
1,827
|
|
Accrued capital expenditures
|
|
|
11,110
|
|
|
11,700
|
|
Revenues payable
|
|
|
2,698
|
|
|
3,439
|
|
Other
|
|
|
2,406
|
|
|
3,019
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
23,579
|
|
$
|
19,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 4Acquisitions
In June 2016, the Predecessor completed the acquisition of unproved and proved properties in the Delaware Basin. Total cash consideration paid by the Predecessor was
$33.0 million, including usual and customary post-closing adjustments. The Predecessor determined that the acquisition met the criteria for a business combination under FASB Accounting Standard
Codification ("ASC") Topic 805,
Business Combinations
. The Predecessor allocated the final purchase price to the acquired assets and liabilities based
on fair value as of the respective acquisition dates, as summarized in the table below.
F-8
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 4Acquisitions (Continued)
Refer
to
Note 7Fair Value Measurements
for additional discussion on the valuation techniques used in determining the fair value of
the acquired properties.
|
|
|
|
|
|
|
September 30,
2016
|
|
|
|
(in thousands)
|
|
Cash consideration
|
|
$
|
32,979
|
|
|
|
|
|
|
Fair value of assets and liabilities acquired:
|
|
|
|
|
Proved oil and natural gas properties
|
|
|
15,374
|
|
Unproved oil and natural gas properties
|
|
|
18,071
|
|
|
|
|
|
|
Total fair value of oil and natural gas properties acquired
|
|
|
33,445
|
|
Revenue Suspense
|
|
|
(400
|
)
|
Asset retirement obligation
|
|
|
(66
|
)
|
|
|
|
|
|
Total fair value of net assets acquired
|
|
$
|
32,979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 5Asset Retirement Obligations
The following table summarizes the changes in the Predecessor's asset retirement obligations for the nine months ended September 30, 2016:
|
|
|
|
|
|
|
Nine Months
Ended
September 30,
2016
|
|
|
|
(in thousands)
|
|
Asset retirement obligations, beginning of period
|
|
$
|
2,288
|
|
Liabilities assumed
|
|
|
66
|
|
Liabilities incurred
|
|
|
174
|
|
Liabilities settled
|
|
|
(9
|
)
|
Accretion expense
|
|
|
129
|
|
Revision of estimated liabilities
|
|
|
32
|
|
|
|
|
|
|
Asset retirement obligations, end of period
|
|
$
|
2,680
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 6Derivative Instruments
The Predecessor periodically uses derivative instruments to mitigate its exposure to a decline in commodity prices and the corresponding negative impact on cash flow available for
reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. Depending on changes in oil
and natural gas futures markets and the Predecessor's view of underlying supply and demand trends, it may increase or decrease its hedging positions.
F-9
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 6Derivative Instruments (Continued)
The
following table summarizes the approximate volumes and average contract prices of swap and collar contracts the Predecessor had in place as of September 30, 2016:
|
|
|
|
|
|
|
|
|
|
2016
|
|
2017
|
|
Crude Oil Swaps:
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
|
193,200
|
|
|
675,250
|
|
Weighted average floor price ($/Bbl)
|
|
$
|
55.21
|
|
$
|
50.41
|
|
Crude Oil Basis Swaps:
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
|
320,300
|
|
|
127,750
|
|
Weighted average floor price ($/Bbl)
|
|
$
|
(0.45
|
)
|
$
|
(0.20
|
)
|
Natural Gas Swaps:
|
|
|
|
|
|
|
|
Notional volume (MMBtu)
|
|
|
|
|
|
1,460,000
|
|
Weighted average floor price ($/MMBtu)
|
|
$
|
|
|
$
|
2.94
|
|
In
a typical commodity swap agreement, if the agreed upon published third-party index price ("index price") is lower than the swap fixed price, the Predecessor receives the difference
between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Predecessor pays the difference. In addition, the Predecessor has entered into
basis swap contracts in order to hedge the difference between the NYMEX index price and a local index price. When the actual differential exceeds the fixed price provided by the basis swap contract,
the Predecessor receives the difference from the counterparty; when the differential is less than the fixed price provided by the basis swap contract, the Predecessor pays the difference to the
counterparty.
The
Predecessor's commodity derivatives are measured at fair value and are included in the accompanying condensed consolidated balance sheets as derivative assets and liabilities. The
fair value of the commodity contracts was a net asset of $0.3 million and $21.1 million as of September 30, 2016 and December 31, 2015, respectively.
F-10
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 6Derivative Instruments (Continued)
The
following tables below summarize the gross fair value of derivative assets and liabilities and the effect of netting on the condensed consolidated balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2016
|
|
|
|
Balance Sheet
Classification
|
|
Gross
Amounts
|
|
Netting
Adjustments
|
|
Net Amounts
Presented on the
Condensed
Consolidated
Balance Sheets
|
|
|
|
(in thousands)
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
Current assets
|
|
$
|
2,642
|
|
$
|
(1,024
|
)
|
$
|
1,618
|
|
Derivative instruments
|
|
Noncurrent assets
|
|
|
277
|
|
|
(32
|
)
|
|
245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
$
|
2,919
|
|
$
|
(1,056
|
)
|
$
|
1,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
Current liabilities
|
|
$
|
1,011
|
|
$
|
(11
|
)
|
$
|
1,000
|
|
Derivative instruments
|
|
Noncurrent Liabilities
|
|
|
659
|
|
|
(102
|
)
|
|
557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
|
$
|
1,670
|
|
$
|
(113
|
)
|
$
|
1,557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
Balance Sheet
Classification
|
|
Gross
Amounts
|
|
Netting
Adjustments
|
|
Net Amounts
Presented on the
Condensed
Consolidated
Balance Sheets
|
|
|
|
(in thousands)
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
Current assets
|
|
$
|
19,469
|
|
$
|
(426
|
)
|
$
|
19,043
|
|
Derivative instruments
|
|
Noncurrent assets
|
|
|
2,071
|
|
|
(1
|
)
|
|
2,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
$
|
21,540
|
|
$
|
(427
|
)
|
$
|
21,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
Predecessor's oil and natural gas derivative instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the
Predecessor's condensed consolidated statements of operations. The derivative instruments are recorded at fair value on the condensed consolidated balance sheets and any gains and losses are
recognized in current period earnings.
The
following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
(in thousands)
|
|
Loss (gain) on derivative instruments
|
|
$
|
(1,741
|
)
|
$
|
(13,344
|
)
|
$
|
4,184
|
|
$
|
(12,320
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-11
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 6Derivative Instruments (Continued)
The Predecessor is exposed to financial risks associated with its derivative contracts from non-performance by its counterparties. The Predecessor mitigates its exposure to any single
counterparty by contracting with a number of financial institutions, each of which have a high credit rating and is a member of its bank credit facility. The Predecessor's member banks do not require
it to post collateral for its hedge liability positions. Because some of the member banks have discontinued hedging activities, in the future the Predecessor may hedge with counterparties outside its
bank group to obtain competitive terms and to spread counterparty risk.
The
Predecessor did not incur any losses due to counterparty non-performance during the three and nine months ended September 30, 2016 or the year ended December 31, 2015.
Note 7Fair Value Measurements
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Predecessor has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique,
into a three-level fair value hierarchy. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2
are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.
The
following table is a listing of the Predecessor's assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of
September 30, 2016 and December 31, 2015 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
(in thousands)
|
|
Commodity derivative asset, net(1)
|
|
|
|
|
|
|
|
|
|
|
September 30, 2016
|
|
$
|
|
|
$
|
306
|
|
$
|
|
|
December 31, 2015
|
|
$
|
|
|
$
|
21,113
|
|
$
|
|
|
-
(1)
-
This
represents a financial asset that is measured at fair value on a recurring basis.
Both
financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value
measurement. The following is a description of the valuation methodologies used by the Predecessor as well as the general classification of such instruments pursuant to the above fair value hierarchy.
There were no transfers between Level 1, Level 2 or Level 3 during any period presented.
Derivatives
The Predecessor uses Level 2 inputs to measure the fair value of oil and natural gas commodity derivatives. The Predecessor uses
industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk,
as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The
Predecessor utilizes its counterparties' valuations to assess the reasonableness of its own valuations.
F-12
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 7Fair Value Measurements (Continued)
Nonrecurring Fair Value Measurements
The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an
income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties
include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials;
(v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Predecessor's management
at the time of the valuation. Refer to
Note 4
Acquisitions and Divestitures
for
additional information on the fair value of assets acquired during 2016.
Other Financial Instruments
The carrying amounts of the Predecessor's cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate
fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying values of the amounts outstanding under the Predecessor's credit agreement
approximate fair value because the variable interest rates are reflective of current market conditions.
Note 8Long-Term Debt
Credit Agreement
The Predecessor's amended and restated credit agreement ("credit agreement"), dated October 15, 2014, includes both a term loan
commitment of $65.0 million (the "term loan") and a revolving credit facility (the "revolving credit facility") with commitments of $500.0 million (subject to the borrowing base), with a
sublimit for letters of credit of $15.0 million. The revolving credit facility matures on October 15, 2019 and the term loan matures on April 15, 2018.
The
borrowing base under the revolving credit facility is determined at the discretion of the lenders and depends on, among other things, the volumes of the Predecessor's proved oil and
natural gas reserves and estimated cash flows from these reserves and the Predecessor's commodity hedge positions. In April 2016, the borrowing base was reaffirmed at $140.0 million. The next
regular redetermination date is scheduled for October 2016.
As
of September 30, 2016, borrowings under the revolving credit facility were $124.0 million and $0.5 million of outstanding letters of credit, leaving
$15.5 million in borrowing capacity under the revolving credit facility.
F-13
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 8Long-Term Debt (Continued)
The
term loan, net of unamortized deferred financing costs on the accompanying condensed consolidated balance sheets as of September 30, 2016 and December 31, 2015,
consisted of the following:
|
|
|
|
|
|
|
|
|
|
September 30,
2016
|
|
December 31,
2015
|
|
|
|
(in thousands)
|
|
Term loan
|
|
$
|
65,000
|
|
$
|
65,000
|
|
Unamortized deferred financing costs
|
|
|
(238
|
)
|
|
(351
|
)
|
|
|
|
|
|
|
|
|
Term loan, net of unamortized deferred financing costs
|
|
$
|
64,762
|
|
$
|
64,649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
credit agreement also has customary covenants with which the Predecessor was in compliance as of September 30, 2016.
Note 9Incentive Unit Compensation
There have been no material changes in issued, forfeited or vested incentive units during the nine months ended September 30, 2016. Please refer to
Note 9
Incentive Unit Compensation
in the Audited Financial Statements.
Incentive
units are accounted for as liability awards under FASB ASC Topic 718,
CompensationStock Compensation,
with
compensation expense based on period-end fair value. The achievement of payout conditions is a performance condition that requires the Predecessor to assess, at each reporting period, the probability
that an event of payout will occur. Compensation cost is required to be recognized at such time that the payout terms are probable of being met. At the grant dates and subsequent reporting periods,
the Predecessor did not deem as probable that such payouts would be achieved.
Note 10Transactions with Related Parties
In May 2016, the Predecessor acquired acreage in close proximity to its operating area in Reeves County, Texas and wellbore only rights in an uncompleted horizontal wellbore for
approximately $9.8 million from Caird DB, LLC, an affiliate of NGP.
The
Predecessor is party to a 15-year gas gathering agreement with PennTex Permian, LLC ("PennTex"), an NGP affiliated company, which terminates on April 1, 2029 and is
subject to one-year extensions at either party's election. Under the agreement, PennTex gathers and processes the Predecessor's gas. PennTex purchases the extracted natural gas liquids from the
Predecessor, net of gathering fees and an agreed percentage of the actual proceeds from the sale of the residue natural gas and natural gas liquids. Net payments received from PennTex for the three
months ended September 30, 2016 and 2015 were $0.5 million and $0.2 million, respectively. Net payments received from PennTex for the nine months ended September 30, 2016
and 2015 were $0.9 million and $0.9 million, respectively. As of September 30, 2016, the Predecessor recorded a receivable of $0.3 million from PennTex.
F-14
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 10Transactions with Related Parties (Continued)
In
October 2014, the gas gathering agreement with PennTex was amended to construct an expansion of the gathering system and a receipt point. Please refer to
Note 11Commitments and Contingencies
.
From
time to time, the Predecessor obtains services related to its drilling and completion activities from affiliates of NGP. In particular, the Predecessor has paid the following
amounts to the following affiliates of NGP for such services: (i) approximately $0.3 million during the nine months ended September 30, 2016 to Cretic Energy Services, LLC;
and (ii) approximately $3.3 million during the nine
months ended September 30, 2016 to RockPile Energy Services, LLC. On September 8, 2016, Rockpile Energy Services, LLC, was purchased from NGP by a third party and is no
longer a related party with the Predecessor.
Note 11Commitments and Contingencies
Commitments
In October 2014, the Predecessor's gas gathering agreement with PennTex was amended to provide for the construction of an expansion of the
gathering system and a receipt point. The Predecessor will reimburse PennTex for the total cost of the expansion project. The Predecessor will pay a minimum fee of $7,000 per day until PennTex recoups
the capital outlay for the expansion project. At September 30, 2016 a short-term liability of $0.3 million was in included in
Other current
liabilities
on the condensed consolidated balance sheets. For the three and nine months ended September 30, 2016, the Predecessor made payments, including interest, of
$0.2 million and $1.0 million, respectively.
In
December 2015, the Predecessor entered into a transportation and gathering services agreement by which a transporter agreed to construct a crude oil gathering and transportation
system capable of transporting crude oil from certain Company wells in Reeves and Ward Counties, Texas to destination points in Crane and Midland, Texas (the "Transportation System"), and the
Predecessor agreed to dedicate and ship on the Transportation System all crude oil owned or controlled by the Predecessor from oil and gas leases covering approximately 28,000 gross acres located
within a designated area of mutual interest in Reeves and Ward Counties. The agreement has a primary term of 12 years from October 1, 2016, the date the Transportation System was first
put into service, and may be extended at the Company's option for two successive two-year terms and, thereafter, is automatically extended for
successive one-year terms unless terminated by the Predecessor or the transporter upon 60 days' prior notice.
In
July 2016, the Predecessor entered into a crude oil purchase agreement by which the Predecessor agreed to sell all of its crude oil production that is produced at receipt points
identified in the agreement commencing on the October 1, 2016 in-service date of the Transportation System. The purchaser is obligated to purchase the crude oil at the receipt points identified
in the agreement and transport it on the Transportation System. The agreement has an initial term of nine months from October 1, 2016, the date the Transportation System entered commercial
service, and evergreen 30-day renewal terms unless terminated by the Predecessor or the purchaser on 30 days' prior notice. The price received by the Predecessor for the crude oil it sells
under the agreement is based generally on NYMEX pricing subject to marketing and other adjustments, and varies depending on whether the oil is transported to Crane or Midland, Texas and on whether the
oil is transported before or after the Transportation System is connected to a pipeline in Crane, Texas or a terminal in Midland, Texas.
F-15
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC
(PREDECESSOR)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Note 11Commitments and Contingencies (Continued)
There
have been no other material changes in commitments during the nine months ended September 30, 2016. Please refer to
Note 11
Commitment and
Contingencies
in the Audited Financial Statements.
Contract Termination and Rig Stacking
In light of the low commodity price environment, the Predecessor curtailed its drilling activity during 2015. For the three and nine months
ended September 30, 2015, the Predecessor incurred drilling rig termination fees of $0.2 million and $2.4 million, respectively, which are recorded in the
Contract termination and rig stacking
line item in the accompanying condensed consolidated statements of operations.
Contingencies
In the ordinary course of business, the Predecessor may at times be subject to claims and legal actions. Management believes it is remote that
the impact of such matters will have a material adverse effect on the Predecessor's financial position, results of operations or cash flows. Management is unaware of any pending litigation brought
against the Predecessor requiring the reserve of a contingent liability as of the date of these condensed consolidated financial statements.
Note 12Subsequent Events
On October 11, 2016, Centennial Resource Development, Inc. (formerly known as Silver Run Acquisition Corporation) (CDEV) consummated the previously announced acquisition of
approximately 89% of the outstanding membership interests in the Predecessor (the "Business Combination"), pursuant to (i) the certain Contribution Agreement, dated as of July 6, 2016
(as amended by Amendment No. 1 thereto, dated as of July 29, 2016, the "Contribution Agreement"), among Centennial Resource Development, LLC, a Delaware limited liability company
("CRD"), NGP Centennial Follow-On LLC, a Delaware limited liability company ("NGP Follow-On"), Celero Energy Company, LP, a Delaware limited partnership (together with CRD and NGP
Follow-On, the "Centennial Contributors"), the Predecessor and New Centennial, LLC, a Delaware limited liability company ("NewCo"), (ii) that certain Assignment Agreement, dated as of
October 7, 2016, between NewCo and Silver Run Acquisition Corporation and (iii) that certain Joinder Agreement, dated as of October 7, 2016, by Silver Run Acquisition Corporation.
In
connection with the Business Combination CDEV paid the Centennial Contributors $1,186,744,348 in aggregate cash consideration and the Centennial Contributors retained 20,000,000
common membership interests in the Predecessor, representing approximately 11% of the outstanding membership interests in the Predecessor.
On
October 11, 2016, the Predecessor also entered into an amendment to the credit agreement to, among other things (i) permit the transaction, (ii) reflect the
repayment in full of all term loans thereunder, (iii) increase the borrowing base from $140.0 million to $200.0 million, (iv) increase the interest rate to LIBOR plus
2.25% - 3.25%, and (v) require the Predecessor to have sufficient liquidity and satisfy a maximum leverage ratio in order to make dividends. As of the closing date of the Business
Combination, the Predecessor has no outstanding debt and approximately $100.0 million of cash on hand.
F-16
Table of Contents
Report of Independent Registered Public Accounting Firm
The
Board of Directors
Centennial Resource Development, Inc.:
We
have audited the accompanying consolidated and combined balance sheets of Centennial Resource Production, LLC and Celero Energy Company, LP (Predecessor, the Company) as
of December 31, 2015 and 2014, and the related consolidated and combined statements of operations, changes in owners' equity, and cash flows for each of the years in the three-year period ended
December 31, 2015. These
consolidated and combined financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated and combined financial statements
based on our audits.
We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In
our opinion, the consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of Centennial Resource
Production, LLC and Celero Energy Company, LP (Predecessor) as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
As
discussed in Note 2 to the consolidated and combined financial statements, the balance sheets, and the related statements of operations, changes in equity, and cash flows have
been prepared on a consolidated and combined basis of accounting as a result of the reorganization of interests under common control.
Denver,
Colorado
April 5, 2016, except as to Note 14, which is as of May 17, 2016
F-17
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
CONSOLIDATED AND COMBINED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2015
|
|
2014
|
|
|
|
(In thousands)
|
|
ASSETS
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,768
|
|
$
|
13,017
|
|
Accounts receivable, net
|
|
|
13,012
|
|
|
23,117
|
|
Derivative instruments, net
|
|
|
19,043
|
|
|
30,422
|
|
Prepaid and other current assets
|
|
|
322
|
|
|
790
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
34,145
|
|
|
67,346
|
|
Oil and natural gas properties, other property and equipment
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
|
|
651,596
|
|
|
541,119
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(180,946
|
)
|
|
(91,735
|
)
|
Unproved oil and natural gas properties
|
|
|
105,897
|
|
|
90,645
|
|
Other property and equipment, net of accumulated depreciation of $868 and $139, respectively
|
|
|
2,240
|
|
|
595
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
578,787
|
|
|
540,624
|
|
Noncurrent assets
|
|
|
|
|
|
|
|
Derivative instruments, net
|
|
|
2,070
|
|
|
6,365
|
|
Other noncurrent assets
|
|
|
1,293
|
|
|
1,434
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
616,295
|
|
$
|
615,769
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND OWNERS' EQUITY
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
19,985
|
|
$
|
101,295
|
|
Other current liabilities
|
|
|
2,148
|
|
|
2,217
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
22,133
|
|
|
103,512
|
|
Noncurrent liabilities
|
|
|
|
|
|
|
|
Revolving credit facility
|
|
|
74,000
|
|
|
65,000
|
|
Term loan, net of unamortized deferred financing costs
|
|
|
64,649
|
|
|
64,568
|
|
Asset retirement obligations
|
|
|
2,288
|
|
|
1,824
|
|
Deferred tax liability
|
|
|
2,361
|
|
|
2,933
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
165,431
|
|
|
237,837
|
|
Owners' equity
|
|
|
450,864
|
|
|
377,932
|
|
|
|
|
|
|
|
|
|
Total liabilities and owners' equity
|
|
$
|
616,295
|
|
$
|
615,769
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated and combined financial statements.
F-18
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(in thousands)
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
77,643
|
|
$
|
114,955
|
|
$
|
65,863
|
|
Natural gas sales
|
|
|
7,965
|
|
|
9,670
|
|
|
3,024
|
|
NGL sales
|
|
|
4,852
|
|
|
7,200
|
|
|
3,087
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
90,460
|
|
|
131,825
|
|
|
71,974
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
21,173
|
|
|
17,690
|
|
|
19,106
|
|
Severance and ad valorem taxes
|
|
|
5,021
|
|
|
6,875
|
|
|
4,153
|
|
Transportation, processing, gathering and other operating expenses
|
|
|
5,732
|
|
|
4,772
|
|
|
1,291
|
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
90,084
|
|
|
69,110
|
|
|
29,285
|
|
Abandonment expense and impairment of unproved properties
|
|
|
7,619
|
|
|
20,025
|
|
|
8,561
|
|
Exploration
|
|
|
84
|
|
|
|
|
|
|
|
Contract termination and rig stacking
|
|
|
2,387
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
|
14,206
|
|
|
31,694
|
|
|
16,842
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
146,306
|
|
|
150,166
|
|
|
79,238
|
|
(Gain) loss on sale of oil and natural gas properties
|
|
|
(2,439
|
)
|
|
2,096
|
|
|
(16,756
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total operating (loss) income
|
|
|
(53,407
|
)
|
|
(20,437
|
)
|
|
9,492
|
|
Other (expense) income
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(6,266
|
)
|
|
(2,475
|
)
|
|
(513
|
)
|
Gain (loss) on derivative instruments
|
|
|
20,756
|
|
|
41,943
|
|
|
(4,410
|
)
|
Other income
|
|
|
20
|
|
|
281
|
|
|
122
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other (expense) income
|
|
|
14,510
|
|
|
39,749
|
|
|
(4,801
|
)
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
(38,897
|
)
|
|
19,312
|
|
|
4,691
|
|
Income tax benefit (expense)
|
|
|
572
|
|
|
(1,524
|
)
|
|
(1,079
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
(38,325
|
)
|
|
17,788
|
|
|
3,612
|
|
Less net loss attributable to noncontrolling interest
|
|
|
|
|
|
(2
|
)
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to the predecessor
|
|
$
|
(38,325
|
)
|
$
|
17,790
|
|
$
|
3,618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated and combined financial statements.
F-19
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN OWNERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Owners'
Equity
|
|
Noncontrolling
Interest in
Subsidiary
|
|
Total Equity
|
|
|
|
(in thousands)
|
|
Balance at December 31, 2012
|
|
$
|
296,980
|
|
$
|
|
|
$
|
296,980
|
|
Contributions
|
|
|
118,000
|
|
|
694
|
|
|
118,694
|
|
Distributions
|
|
|
(25,340
|
)
|
|
|
|
|
(25,340
|
)
|
Owners' promissory note receivable
|
|
|
(3,399
|
)
|
|
|
|
|
(3,399
|
)
|
Net income (loss)
|
|
|
3,618
|
|
|
(6
|
)
|
|
3,612
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2013
|
|
|
389,859
|
|
|
688
|
|
|
390,547
|
|
Contributions
|
|
|
59,776
|
|
|
150
|
|
|
59,926
|
|
Repurchase of equity interests
|
|
|
(119,272
|
)
|
|
|
|
|
(119,272
|
)
|
Deemed contribution from sale of assets
|
|
|
21,489
|
|
|
(836
|
)
|
|
20,653
|
|
Deemed contribution from parent for payment of incentive units
|
|
|
12,420
|
|
|
|
|
|
12,420
|
|
Deemed distribution in connection with common control acquisition
|
|
|
(4,130
|
)
|
|
|
|
|
(4,130
|
)
|
Net income (loss)
|
|
|
17,790
|
|
|
(2
|
)
|
|
17,788
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2014
|
|
|
377,932
|
|
|
|
|
|
377,932
|
|
Contributions
|
|
|
111,396
|
|
|
|
|
|
111,396
|
|
Deemed distribution from sale of assets
|
|
|
(139
|
)
|
|
|
|
|
(139
|
)
|
Net loss
|
|
|
(38,325
|
)
|
|
|
|
|
(38,325
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2015
|
|
$
|
450,864
|
|
$
|
|
|
$
|
450,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated and combined financial statements.
F-20
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(in thousands)
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(38,325
|
)
|
$
|
17,788
|
|
$
|
3,612
|
|
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
Accretion of asset retirement obligations
|
|
|
139
|
|
|
156
|
|
|
358
|
|
Depreciation, depletion and amortization
|
|
|
89,945
|
|
|
68,954
|
|
|
28,927
|
|
Noncash incentive compensation expense
|
|
|
|
|
|
12,420
|
|
|
|
|
Abandonment expense and impairment of unproved properties
|
|
|
7,619
|
|
|
20,025
|
|
|
8,524
|
|
Write-off of deferred S-1 related expense
|
|
|
1,585
|
|
|
|
|
|
|
|
Deferred tax (benefit) expense
|
|
|
(572
|
)
|
|
1,524
|
|
|
1,079
|
|
(Gain) loss on sale of oil and natural gas properties
|
|
|
(2,439
|
)
|
|
2,096
|
|
|
(16,756
|
)
|
(Gain) loss on derivative instruments
|
|
|
(20,756
|
)
|
|
(41,943
|
)
|
|
4,410
|
|
Net cash received for derivative settlements
|
|
|
35,493
|
|
|
4,611
|
|
|
(12,651
|
)
|
Payment of derivative contract premiums
|
|
|
|
|
|
|
|
|
(994
|
)
|
Recovery of bad debt
|
|
|
|
|
|
(777
|
)
|
|
1,128
|
|
Amortization of debt issuance costs
|
|
|
482
|
|
|
316
|
|
|
210
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in accounts receivable
|
|
|
5,244
|
|
|
(6,322
|
)
|
|
(1,016
|
)
|
Increase in prepaid and other assets
|
|
|
(864
|
)
|
|
(79
|
)
|
|
(2,054
|
)
|
(Decrease) increase in accounts payable and other liabilities
|
|
|
(8,669
|
)
|
|
18,479
|
|
|
(1,361
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
68,882
|
|
|
97,248
|
|
|
13,416
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
Acquisition of oil and natural gas properties
|
|
|
(43,223
|
)
|
|
(22,167
|
)
|
|
(27,412
|
)
|
Development of oil and natural gas properties
|
|
|
(156,006
|
)
|
|
(275,683
|
)
|
|
(146,463
|
)
|
Purchases of other property and equipment
|
|
|
(2,097
|
)
|
|
(453
|
)
|
|
(543
|
)
|
Proceeds from sales of oil and natural gas properties and other assets
|
|
|
2,691
|
|
|
72,382
|
|
|
46,316
|
|
Development of assets held for sale
|
|
|
|
|
|
(14,240
|
)
|
|
(37,915
|
)
|
Proceeds from sale of Atlantic Midstream, net of cash sold
|
|
|
|
|
|
71,781
|
|
|
|
|
Change in cash held in escrow
|
|
|
|
|
|
5,000
|
|
|
29,500
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(198,635
|
)
|
|
(163,380
|
)
|
|
(136,517
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
Proceeds from revolving credit facility
|
|
|
92,000
|
|
|
196,000
|
|
|
57,000
|
|
Repayment of revolving credit facility
|
|
|
(83,000
|
)
|
|
(160,000
|
)
|
|
(28,000
|
)
|
Financing obligation
|
|
|
(1,633
|
)
|
|
|
|
|
|
|
Capital contributions
|
|
|
111,396
|
|
|
59,776
|
|
|
114,859
|
|
Debt issuance costs
|
|
|
(259
|
)
|
|
(1,637
|
)
|
|
(471
|
)
|
Repurchase of equity
|
|
|
|
|
|
(119,272
|
)
|
|
(21,102
|
)
|
Capital distribution
|
|
|
|
|
|
|
|
|
(4,238
|
)
|
Proceeds from term loan
|
|
|
|
|
|
65,000
|
|
|
|
|
Distribution in connection with common control acquisition
|
|
|
|
|
|
(3,051
|
)
|
|
|
|
Contributions received from noncontrolling interest
|
|
|
|
|
|
150
|
|
|
694
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
118,504
|
|
|
36,966
|
|
|
118,742
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(11,249
|
)
|
|
(29,166
|
)
|
|
(4,359
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
13,017
|
|
|
42,183
|
|
|
46,542
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
1,768
|
|
$
|
13,017
|
|
$
|
42,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
5,782
|
|
$
|
1,935
|
|
$
|
232
|
|
Supplemental noncash activity
|
|
|
|
|
|
|
|
|
|
|
Accrued capital expenditures included in accounts payable and accrued expenses
|
|
$
|
13,124
|
|
$
|
81,510
|
|
$
|
5,099
|
|
Owners' promissory note receivable
|
|
|
|
|
|
|
|
|
3,399
|
|
Financing obligation
|
|
|
3,770
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated and combined financial statements.
F-21
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Note 1Organization and Nature of Operations
Centennial Resource Production, LLC, a Delaware limited liability company formerly named Atlantic Energy Holdings, LLC ("Centennial OpCo"), was formed on August 30,
2012 by its management members, third-party investors and NGP Natural Resources X, LP ("NGP X"), an affiliate of Natural Gas Partners ("NGP"), a family of energy-focused private equity
investment funds. Centennial OpCo is engaged in the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves, primarily in the Delaware Basin of West Texas.
Atlantic
Midstream was formed on May 21, 2013, as a Delaware limited liability company and is constructing assets to gather and process natural gas in the Delaware Basin of West
Texas. Centennial OpCo sold its interests in Atlantic Midstream on February 12, 2014 (refer to
Note 4Acquisitions and
Divestitures
).
On
March 31, 2014, all of Centennial OpCo's employee members sold their membership interests to Centennial OpCo. Contemporaneously, Centennial Resource Development, LLC, a
Delaware limited liability company formed by NGP X and certain management members ("Centennial HoldCo"), agreed to purchase the entirety of Centennial OpCo's issued and outstanding incentive units. On
April 30, 2014, NGP X contributed and conveyed its membership interests in Centennial OpCo to Centennial HoldCo. On May 9, 2014, Centennial OpCo's remaining members sold their membership
interests to Centennial OpCo. As a result of these transactions, Centennial OpCo became a wholly-owned subsidiary of Centennial HoldCo. Centennial HoldCo is a holding company with no independent
operations apart from its ownership interests in Centennial OpCo. NGP X controls Centennial HoldCo through ownership of 99.0% of its membership interests.
Celero
Energy Company, LP, a Delaware limited partnership ("Celero"), was formed on September 22, 2006, by its general partner, Celero Energy Management, LLC
("Celero GP"), its management team and Natural Gas Partners VIII, L.P. ("NGP VIII"), also an affiliate of NGP. Celero is engaged in the development and acquisition of oil and natural gas
properties in Texas and New Mexico, primarily in the Permian Basin in West Texas.
On
October 15, 2014, Celero conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo
(the "Combination"). As a result of the transaction, Centennial HoldCo owned approximately 72% of Centennial OpCo, and Celero owned the remaining 28%.
In
2015, NGP Centennial Follow-On LLC ("Follow-On"), a Delaware limited liability company controlled by NGP but the economic interests in which are owned by unaffiliated third
party investors and management, contributed $84.2 million to Centennial OpCo in exchange for membership interests in Centennial OpCo. In addition, Centennial HoldCo contributed approximately
$27.2 million to Centennial OpCo in exchange for additional membership interests in Centennial OpCo. Accordingly, Centennial HoldCo, Celero and Follow-On own an approximate 61.2%, 21.2% and
17.6% membership interest in Centennial OpCo, respectively.
F-22
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 2Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards
Basis of Presentation
Through the delegation of authority of the general partners of NGP X and NGP VIII to NGP Energy Capital Management, L.L.C. ("NGP ECM"), all
power and authority of the respective fund limited partnership in effectuating its core investment, management and divestment function is controlled by NGP ECM. As all power and authority to control
the core functions of Centennial OpCo and Celero (collectively, the "Predecessor") are controlled by NGP X and NGP VIII, respectively, the Combination has been accounted for as a reorganization of
entities under common control in a manner similar to a pooling of interests. The results of Centennial OpCo and Celero have been combined for all periods in which common control existed for financial
reporting purposes. All significant intercompany and intra-company balances and transactions have been eliminated.
Certain
prior period amounts have been reclassified to conform to the current presentation on the accompanying consolidated and combined financial statements.
Under
certain contracts, when NGLs are extracted from the gas stream, processors receive a portion of the sales value from both the residue gas and the NGLs as a processing fee and remit
the contractual proceeds to us. Prior to 2015, revenue was recognized net of these processing fees for residue gas and NGLs sold under these contracts as allowed under Financial Accounting Standards
Board ("FASB") Accounting Standards Codification ("ASC") Topic 605,
Revenue Recognition
. Increasing NGL production has resulted in processing costs
becoming more significant. Accordingly, the Predecessor changed its policy to record these processing costs with operating costs as allowed under ASC 605.
Beginning in 2015, the Predecessor's realized prices for sales under these contracts reflect the value of 100% of the residue gas and NGLs yielded by processing, rather than the value associated with
the contractual proceeds it received. The related processing fees now are included in
Transportation, processing, gathering, and other operating
expenses
. Financial statements for periods prior to 2015 have been reclassified to reflect this change in accounting treatment. There was no impact on operating income.
Assumptions, Judgments and Estimates
In the course of preparing the Predecessor's consolidated and combined financial statements, the Predecessor's management makes various
assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these
assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously
established.
The
more significant areas requiring the use of assumptions, judgments and estimates include: (1) oil and natural gas reserves; (2) cash flow estimates used in impairment
tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) determining fair value and allocating purchase price in connection
with business combinations; (6) valuation of derivative instruments; and (7) accrued revenue and related receivables.
The
accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP").
F-23
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 2Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)
Significant Accounting Policies
Cash and Cash Equivalents
The Predecessor considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash
equivalents.
Accounts Receivable
Accounts receivable consists mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the
Predecessor operates. For receivables from joint interest owners, the Predecessor typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings.
Generally, oil and natural gas receivables are collected within two months and the Predecessor has had minimal bad debts. The Predecessor establishes an allowance for doubtful accounts equal to the
estimable portions of accounts receivable for which failure to collect is probable. The Predecessor's allowance for doubtful accounts totaled $0.1 million and $0.3 million as of
December 31, 2015 and 2014, respectively.
Credit Risk and Other Concentrations
The Predecessor sells oil and natural gas to various third party purchasers. The future availability of a ready market for oil and natural gas
depends on numerous factors outside the Predecessor's control, none of which can be predicted with certainty. For the years ended December 31, 2015, 2014 and 2013, the Predecessor had one major
customer, Plains Marketing, LP, which accounted for 64%, 78% and 72%, respectively, of total revenue for those years. The Predecessor does not require collateral and does not believe the loss
of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
By
using derivative instruments to economically hedge exposures to changes in commodity prices, the Predecessor exposes itself to credit risk and market risk. Credit risk is the failure
of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Predecessor, which creates credit risk.
As of December 31, 2015, and through the filing date of this report, all of the Predecessor's derivative counterparties were members of the Predecessor's credit facility lender group. The
credit facility is secured by the Predecessor's
proved oil and natural gas properties and therefore, the Predecessor is not required to post any collateral. The Predecessor does not receive collateral from its counterparties. The maximum amount of
loss due to credit risk that the Predecessor would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial
instruments, was approximately $21.5 million at December 31, 2015. The Predecessor minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single
counterparty; and (ii) monitoring the creditworthiness of the Predecessor's counterparties on an ongoing basis. In accordance with the Predecessor's standard practice, its commodity derivatives
are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
F-24
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 2Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)
The
Predecessor places its temporary cash investments with high-quality financial institutions and does not limit the amount of credit exposure to any one financial institution. For the
years ended December 31, 2015, 2014 and 2013, the Predecessor has not incurred losses related to these investments.
Oil and Natural Gas Properties
The Predecessor follows the successful efforts method of accounting for its oil and natural gas properties. Under the successful efforts method,
the costs incurred to acquire, drill, and complete productive wells and development wells are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including
personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as
incurred. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. As of December 31, 2015 and 2014, no costs were
capitalized in connection with exploratory wells in progress. Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged
or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is
recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized in income.
Unproved
properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. The Predecessor evaluates significant unproved properties for impairment
based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. Unproved properties and the related costs are transferred to proved
properties when reserves are discovered on or otherwise attributed to the property. For the year ended December 31, 2015, the
Predecessor recorded abandonment expense and impairment of unproved properties of $7.6 million for leases which had expired, or were expected to expire. For the year ended December 31,
2014, the Predecessor recorded abandonment expense and impairment of unproved properties of $20.0 million, of which $13.8 million was attributable to an impairment of unproved properties
and $6.2 million was attributable to leases which had expired, or were expected to expire. For the year ended December 31, 2013, the Predecessor recorded an impairment of
$7.4 million attributable to lease expirations.
The
Predecessor reviews its proved oil and natural gas properties for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of
such property. The Predecessor estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural
gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Predecessor will write down the carrying amount of
the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates,
estimated future capital expenditures and discount rates commensurate with the risk associated with realizing the projected cash flows. There were no impairments of proved oil and natural gas
properties during the years ended December 31, 2015, 2014 and 2013.
F-25
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 2Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)
Other Property and Equipment
Other property and equipment such as office furniture and equipment, buildings, vehicles, and computer hardware and software is recorded at
cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets ranging from three to twenty years. Major renewals and improvements are capitalized while
expenditures for maintenance and repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the
accounts.
Deferred Loan Costs
Deferred loan costs related to the Predecessor's revolving credit facility are included in the line item
Other
noncurrent assets
in the consolidated and combined balance sheets and are stated at cost, net of amortization, and are amortized to interest expense on a straight line basis
over the borrowing term. Please refer to Recently Issued Accounting Standards, for additional discussion of deferred loan costs related to the Predecessor's term loan.
Derivative Financial Instruments
In order to manage its exposure to oil and natural gas price volatility, the Predecessor enters into derivative transactions from time to time,
including commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements relating to the price risk associated with a portion of its production. To the extent legal
right of offset exists with a counterparty, the Predecessor reports derivative assets and liabilities on a net basis.
The
Predecessor records derivative instruments on the consolidated and combined balance sheets as either an asset or liability measured at fair value and records changes in the fair
value of derivatives in current earnings as they occur. The Predecessor's derivatives have not been designated as hedges for accounting purposes. For additional discussion on derivatives, please refer
to
Note 5Derivative Financial Instruments
.
Asset Retirement Obligations
The Predecessor recognizes an estimated liability for future costs associated with the abandonment of its oil and natural gas properties. A
liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired.
The increase in carrying value is included in proved oil and natural gas properties in the accompanying consolidated and combined balance sheets. The Predecessor depletes the amount added to proved
oil and natural gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and natural gas
properties. For additional discussion, please refer to
Note 10Asset Retirement Obligations
.
F-26
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 2Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)
Revenue Recognition
The Predecessor derives revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when the Predecessor's
production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to
the product has transferred to the purchaser. At the end of each month, the Predecessor estimates the amount of production delivered to the purchaser and the price it will receive. The Predecessor
follows the sales method of accounting for its oil and natural gas revenue, whereby revenue is recorded based on the Predecessor's share of volume sold, regardless of whether the Predecessor has taken
its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Predecessor has an imbalance on a specific property greater than the expected remaining
proved reserves.
Incentive Units
Incentive units are accounted for as liability awards under FASB ASC Topic 718,
CompensationStock
Compensation
, with compensation expense based on period-end fair value. For additional discussion, please refer to
Note 9Incentive
Unit Compensation
.
Segment Reporting
The Predecessor operates in only one industry segment, which is the exploration and production of oil and natural gas. All of its operations are
conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
Income Taxes
Centennial OpCo is organized as a Delaware limited liability company, and Celero is organized as a Delaware limited partnership. As such, the
Predecessor is treated as a flow-through entity for U.S. federal income tax purposes and for purposes of certain state and local income taxes. For such purposes, the net taxable income of the
Predecessor and any related tax credits are passed through to the owners and are included in their tax returns, even though such net taxable income or tax credits may not have actually been
distributed. Accordingly, no provision has been made in the consolidated and combined financial statements of the Predecessor for such income taxes paid at the owner level.
The
Predecessor is subject to the Texas franchise tax, at a statutory rate of 0.75% of taxable margin. Deferred tax assets and liabilities are recognized for future Texas franchise tax
consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective Texas franchise tax bases. As of December 31,
2015 and 2014, the Predecessor's long-term deferred tax liability was $2.4 million and $2.9 million, respectively.
The
Predecessor evaluates the tax positions taken or expected to be taken in the course of preparing its tax returns and disallows the recognition of tax positions not deemed to meet a
"more-likely-than-not" threshold of being sustained by the applicable tax authority. The Predecessor's management does not believe that any tax positions included in its tax returns would not meet
this
F-27
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 2Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)
threshold.
The Predecessor's policy is to reflect interest and penalties related to uncertain tax positions as part of its income tax expense, when and if they become applicable.
As
of December 31, 2015 the Predecessor has no current tax years under audit. The Predecessor remains subject to examination for federal income taxes and state income taxes for
tax years 2012-2015.
Recently Issued Accounting Standards
In May 2014, In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09,
Revenue from Contracts with
Customers
. This guidance is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance. In August 2015, the FASB deferred
the effective date of the new revenue recognition standard by one year. The revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning
after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Predecessor is
currently evaluating the impact, if any, that the adoption of this update will have on its consolidated and combined financial statements or disclosures.
In
August 2014, the FASB issued ASU No. 2014-15,
Disclosure of Uncertainties about an Entity's Ability to Continue as a Going
Concern
. This update requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity's ability to continue as a going
concern within one year after the date that the entity's financial statements are issued, or within one year after the date the entity's financial statements are available to be issued, and to provide
disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early
application is permitted. The Predecessor is currently evaluating the impact, if any, that the adoption of this update will have on its consolidated and combined financial statements or disclosures.
Effective
November 1, 2015, the Predecessor early adopted, on a retrospective basis, ASU No. 2015-03,
Simplifying the Presentation of Debt Issuance
Costs
("ASU 2015-03"). ASU 2015-03 requires deferred financing costs to be presented on the accompanying consolidated and combined balance sheets as a direct
deduction from the carrying value of the related debt liability. In accordance, the Predecessor has reclassified $0.4 million of deferred financing costs related to its term loan, from the
Other noncurrent
assets
line item to the
Term loan, net of unamortized deferred financing costs
line
item.
F-28
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 2Basis of Presentation, Significant Accounting Policies, and Recently Issued Accounting Standards (Continued)
The
December 31, 2014 accompanying balance sheet line items that were adjusted as a result of the adoption of ASU No. 2015-03 are presented in the following table:
|
|
|
|
|
|
|
|
|
|
As of December 31, 2014
|
|
|
|
As Reported
|
|
As Adjusted
|
|
|
|
(in thousands)
|
|
Other noncurrent assets
|
|
$
|
1,866
|
|
$
|
1,434
|
|
Total assets
|
|
|
616,201
|
|
|
615,769
|
|
Term loan
|
|
|
65,000
|
|
|
|
|
Term loan, net of unamortized deferred financing costs
|
|
|
|
|
|
64,568
|
|
Total liabilities
|
|
|
238,269
|
|
|
237,837
|
|
Total liabilities and owners' equity
|
|
|
616,201
|
|
|
615,769
|
|
ASU
2015-03 does not specifically address the accounting for deferred financing costs related to line-of-credit arrangements. In August 2015, the FASB issued ASU No. 2015-15,
Presentation and Subsequent Measurement of Debt
Issuance Costs Associated with Line-of-Credit Arrangements
("ASU 2015-15") allowing for deferred
financing costs associated with line-of-credit arrangements to continue to be presented as assets. ASU 2015-15 is consistent with how the Predecessor currently accounts for deferred financing
costs related to the Predecessor's revolving credit facility.
Effective
January 1, 2015, the Predecessor early adopted, on a prospective basis, ASU No. 2015-01,
Income StatementExtraordinary and
Unusual Items
. This ASU simplifies income statement presentation by eliminating the concept of extraordinary items. There was no impact to the
Predecessor's consolidated and combined financial statements or disclosures from the adoption of this standard.
Effective
December 1, 2015, the Predecessor early adopted, on a prospective basis, ASU No. 2015-17,
Balance Sheet Classification of Deferred
Taxes
("ASU 2015-17"). This ASU requires that deferred tax liabilities and assets, along with any related valuation allowance, be classified as noncurrent on the balance
sheet. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments in
ASU 2015-17. As ASU 2015-17 was adopted on a prospective basis, the Predecessor did not retrospectively adjust prior periods.
F-29
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 3Accounts Receivable and Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
|
|
|
|
|
|
|
|
|
|
December 31,
2015
|
|
December 31,
2014
|
|
|
|
(in thousands)
|
|
Oil and natural gas
|
|
$
|
5,789
|
|
$
|
9,116
|
|
Joint interest billings
|
|
|
1,514
|
|
|
11,116
|
|
Hedge settlements
|
|
|
3,956
|
|
|
3,141
|
|
Other
|
|
|
1,844
|
|
|
|
|
Allowance for doubtful accounts
|
|
|
(91
|
)
|
|
(256
|
)
|
|
|
|
|
|
|
|
|
Accounts receivable, net
|
|
$
|
13,012
|
|
$
|
23,117
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable and accrued expenses are comprised of the following:
|
|
|
|
|
|
|
|
|
|
December 31,
2015
|
|
December 31,
2014
|
|
|
|
(in thousands)
|
|
Accounts payable
|
|
$
|
1,827
|
|
$
|
30,224
|
|
Accrued capital expenditures
|
|
|
11,700
|
|
|
59,675
|
|
Revenues payable
|
|
|
3,439
|
|
|
7,566
|
|
Other
|
|
|
3,019
|
|
|
3,830
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
19,985
|
|
$
|
101,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 4Acquisitions and Divestitures
2015 Acquisitions
On September 1, 2015, the Predecessor acquired additional interests in proved and unproved oil and natural gas properties in the Delaware
Basin. Total cash consideration paid by the Predecessor was $16.0 million, net of closing adjustments.
On
September 3, 2015, the Predecessor acquired a non-operated interest in 1,804 net acres in the Delaware Basin from an unrelated third party. Total cash consideration paid by the
Predecessor was $6.4 million, net of closing adjustments.
The
Predecessor determined that both of these acquisitions met the criteria for business combinations under FASB ASC Topic 805,
Business
Combinations
. The Predecessor allocated the final purchase prices to the acquired assets and liabilities based on fair value as of the respective acquisition
F-30
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 4Acquisitions and Divestitures (Continued)
dates,
as summarized in the table below. Refer to
Note 6Fair Value Measurements
for additional discussion on the valuation
techniques used in determining the fair value of the acquired properties.
|
|
|
|
|
|
|
|
|
|
Acquisition #1
|
|
Acquisition #2
|
|
|
|
September 1,
2015
|
|
September 3,
2015
|
|
|
|
(in thousands)
|
|
Cash consideration
|
|
$
|
16,006
|
|
$
|
6,369
|
|
|
|
|
|
|
|
|
|
Fair value of assets and liabilities acquired:
|
|
|
|
|
|
|
|
Proved oil and natural gas properties
|
|
|
7,731
|
|
|
6,491
|
|
Unproved oil and natural gas properties
|
|
|
8,312
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fair value of oil and natural gas properties acquired
|
|
|
16,043
|
|
|
6,491
|
|
Asset retirement obligation
|
|
|
(37
|
)
|
|
(122
|
)
|
|
|
|
|
|
|
|
|
Total fair value of net assets acquired
|
|
$
|
16,006
|
|
$
|
6,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 Acquisitions
In June 2014, Centennial OpCo acquired 2,400 net acres in the Delaware Basin from an unrelated third party, for approximately
$11.0 million, net of customary closing adjustments.
2014 Dispositions
In December 2014, Centennial OpCo sold its interest in approximately 1,845 net acres in Ward County, Texas, including 18 vertical wells, to an
NGP-controlled entity for proceeds of $12.5 million, which resulted in a gain of $1.5 million and was recorded as an equity contribution due to the entities being under common control.
In
May 2014, Celero sold its Caprock field to an unrelated third party for $59.3 million, net of customary closing adjustments. A net loss of $2.2 million was recognized on
the sale during the second quarter of 2014.
In
February 2014, Centennial OpCo sold its 98.5% interest in Atlantic Midstream to PennTex Permian, an NGP-controlled entity for net proceeds of $71.8 million, which resulted in a
gain of $20.0 million and was recorded as an equity contribution due to the entities being under common control.
2013 Acquisitions
During the year ended December 31, 2013, the Predecessor acquired, from third-parties, a combination of new leases and additional working
interest in wells it operates through a number of separate, individually insignificant transactions for aggregate consideration of $20.4 million. The Predecessor reflected the total
consideration paid as $4.9 million of proved oil and natural gas properties and $15.5 million of unproved oil and natural gas properties.
F-31
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 4Acquisitions and Divestitures (Continued)
2013 Divestitures
In October 2013, the Predecessor sold non-operated oil and natural gas properties in its Wolfbone prospect for total proceeds of approximately
$28.7 million, and realized a $7.7 million gain on sale.
In
August 2013, the Predecessor sold its interest in certain oil and natural gas properties, which covered 1,951 gross (1,617 net) acres in Midland County, Texas, including ten wells,
for total proceeds of $17.1 million and realized a $7.9 million gain on sale.
In
June 2013, the Predecessor sold its interest in certain oil and natural gas properties, which covered 320 gross (187 net) acres in Glasscock and Midland Counties, Texas, including two
wells, for total proceeds of $0.3 million, and realized a $0.3 million loss on sale.
Note 5Derivative Financial Instruments
The Predecessor has entered into various commodity derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the
associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Predecessor's derivative contracts include swap arrangements for oil.
In
a typical commodity swap agreement, if the agreed upon published third-party index price ("index price") is lower than the swap fixed price, the Predecessor receives the difference
between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Predecessor pays the difference. In addition, the Predecessor has entered into
basis swap contracts in order to hedge the difference between the NYMEX index price and a local index price. When the actual differential exceeds the fixed price provided by the basis swap contract,
the Predecessor receives the difference from the counterparty; when the differential is less than the fixed price provided by the basis swap contract, the Predecessor pays the difference to the
counterparty.
The
Predecessor's derivative instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the Predecessor's consolidated and
combined statements of operations. The Predecessor's commodity derivatives are measured at fair value and are included in the accompanying consolidated and combined balance sheets as derivative
assets. The fair value of the commodity contracts was a net asset of $21.1 million and $36.8 million as of December 31, 2015 and 2014, respectively.
As
of December 31, 2015, the Predecessor had open crude oil derivative positions with respect to future production as set forth in the table below. When aggregating multiple
contracts, the weighted average contract price is disclosed.
|
|
|
|
|
|
|
|
|
|
2016
|
|
2017
|
|
Crude Oil Swaps:
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
|
729,000
|
|
|
127,750
|
|
Weighted average floor price ($/Bbl)
|
|
$
|
67.82
|
|
$
|
61.36
|
|
Crude Oil Basis Swaps:
|
|
|
|
|
|
|
|
Notional volume (Bbl)
|
|
|
622,200
|
|
|
91,250
|
|
Weighted average floor price ($/Bbl)
|
|
$
|
(0.71
|
)
|
$
|
(0.20
|
)
|
F-32
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 5Derivative Financial Instruments (Continued)
The
following table below summarizes the gross fair value of derivative assets and liabilities and the effect of netting on the consolidated and combined balance sheets (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet
Classification
|
|
Gross
Amounts
|
|
Netting
Adjustments
|
|
Net Amounts
Presented on the
Balance Sheet
|
|
December 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
Current assets
|
|
$
|
19,469
|
|
$
|
(426
|
)
|
$
|
19,043
|
|
Derivative instruments
|
|
Noncurrent assets
|
|
|
2,071
|
|
|
(1
|
)
|
|
2,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
$
|
21,540
|
|
$
|
(427
|
)
|
$
|
21,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
Current assets
|
|
$
|
30,444
|
|
$
|
(22
|
)
|
$
|
30,422
|
|
Derivative instruments
|
|
Noncurrent assets
|
|
|
6,365
|
|
|
|
|
|
6,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
$
|
36,809
|
|
$
|
(22
|
)
|
$
|
36,787
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following table presents gains and losses for derivative instruments not designated as hedges for accounting purposes for the periods presented (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2015
|
|
2014
|
|
2013
|
|
Gain (loss) on derivative instruments
|
|
$
|
20,756
|
|
$
|
41,943
|
|
$
|
(4,410
|
)
|
Note 6Fair Value Measurements
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Predecessor has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique,
into a three-level fair value hierarchy. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2
are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.
The
following table is a listing of the Predecessor's assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of
December 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments, net(1)
|
|
$
|
|
|
$
|
21,113
|
|
$
|
|
|
-
(1)
-
This
represents financial assets or liabilities that are measured at fair value on a recurring basis.
F-33
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 6Fair Value Measurements (Continued)
The following table is a listing of the Predecessor's assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of
December 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments, net(1)
|
|
$
|
|
|
$
|
36,787
|
|
$
|
|
|
Unproved oil and gas properties(2)
|
|
$
|
|
|
$
|
|
|
$
|
5,705
|
|
-
(1)
-
This
represents a financial asset or liability that is measured at fair value on a recurring basis.
-
(2)
-
This
represents a non-financial asset that is measured at fair value on a nonrecurring basis.
Both
financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value
measurement. The following is a description of the valuation methodologies used by the Predecessor as well as the general classification of such instruments pursuant to the above fair value hierarchy.
There were no transfers between Level 1, Level 2 or Level 3 during any period presented.
Derivatives
The Predecessor uses Level 2 inputs to measure the fair value of its derivative instruments. The fair value of all derivative instruments
is estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices
for the underlying instruments, as well as other relevant economic measures. The fair value of all derivative instruments is estimated using a combined income and market valuation methodology based
upon forward commodity price and volatility curves. The curves are obtained from independent pricing services, and the Predecessor has made no adjustments to the obtained prices. The independent
pricing services publish observable market information from multiple brokers and exchanges. All valuations were compared against counterparty valuations to verify the reasonableness of prices. The
Predecessor also considers counterparty credit risk and its own credit risk in its determination of all estimated fair values. The Predecessor has consistently applied these valuation techniques in
all periods presented and believes it has obtained the most accurate information available for the types of derivative contracts it holds. The Predecessor recognizes transfers between levels at the
end of the reporting period for which the transfer has occurred.
Nonrecurring Fair Value Measurements
Unproved oil and natural gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying
costs may not be recoverable. To measure the fair value of the unproved properties, the Predecessor uses a market approach, which takes into account further development plans, risk weighted potential
resource recovery, and estimated reserve values (if any). The Predecessor recorded a $13.8 million impairment related to certain unproved oil and natural gas properties for the year ended
December 31, 2014.
F-34
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 6Fair Value Measurements (Continued)
The
fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs
that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and natural gas properties include estimates of:
(i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash
flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Predecessor's management at the time of the
valuation. Refer to
Note 4Acquisitions and Divestitures
for additional information on the fair value of assets acquired.
Other Financial Instruments
The carrying amounts of the Predecessor's cash, cash equivalents, accounts receivable, accounts payable, and accrued expenses approximate fair
value due to the short-term maturities and/or liquid nature of these assets and liabilities. The carrying values of the amounts outstanding under the credit agreement approximate fair value because
the variable interest rates are reflective of current market conditions.
Note 7Long-Term Debt
Credit Agreement
In May 2015, the Predecessor entered into an amendment to its amended and restated credit agreement ("credit agreement") dated as of
October 15, 2014. The amendment extends the term loan maturity from April 15, 2017 to April 15, 2018. The credit agreement includes both a term loan commitment of
$65.0 million (the "term loan") and a revolving credit facility (the "revolving credit facility") with commitments of $500.0 million (subject to the borrowing base), with a sublimit for
letters of credit of $15.0 million. The borrowing base is subject to regular semi-annual redeterminations.
The
borrowing base of the revolving credit facility under the credit agreement is determined at the discretion of the lenders, and is subject to regular redeterminations in each quarter
of 2015 and on April 1 and October 1 in subsequent years. The borrowing base depends on, among other things, the volumes of the Predecessor's proved oil and natural gas reserves and
estimated cash flows from these reserves and the Predecessor's commodity hedge positions. In August 2015, the Predecessor's borrowing base was reaffirmed at $140.0 million. The next
redetermination date is scheduled for April 1, 2016. Upon a redetermination of the borrowing base, if borrowings in excess of the revised borrowing capacity were outstanding, the Predecessor
could be forced to immediately repay a portion of its debt outstanding under the credit agreement.
At
December 31, 2015, outstanding borrowings under the revolving credit facility were $74.0 million and $0.6 million of outstanding letters of credit, leaving
$65.4 million in borrowing capacity under the revolving credit facility.
Interest
on the term loan is LIBOR plus 5.25%. Borrowings under the credit agreement bear interest at either (i) LIBOR plus a margin between 1.50% and 2.50% or (ii) the
prime rate plus a margin between 0.50% and 1.50%, in each case, based on the amount utilized. The annual commitment
F-35
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 7Long-Term Debt (Continued)
fee
on the unused portion of the credit facility ranges between 0.375% and 0.50% based on the amount utilized.
The
Term loan, net of unamortized deferred financing costs
line item on the accompanying consolidated and combined balance sheets as of
December 31, 2015 and 2014, consisted of the following:
|
|
|
|
|
|
|
|
|
|
December 31,
2015
|
|
December 31,
2014
|
|
|
|
(in thousands)
|
|
Term loan
|
|
$
|
65,000
|
|
$
|
65,000
|
|
Unamortized deferred financing costs
|
|
|
(351
|
)
|
|
(432
|
)
|
|
|
|
|
|
|
|
|
Term loan, net of unamortized deferred financing costs
|
|
$
|
64,649
|
|
$
|
64,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
Predecessor must comply with certain financial and non-financial covenants under the terms of its credit agreement, including limitations on distribution payments, disposition of
assets and requirements to maintain certain financial ratios, which include:
-
-
a requirement that the Predecessor's current assetsincluding amounts available to be drawn under the credit
agreementmust exceed current liabilities;
-
-
a requirement that the Predecessor maintain a ratio of consolidated funded debt to consolidated EBITDAX of not more than 4.0 to 1.0.
At
December 31, 2015 the Predecessor was in compliance with its financial covenants.
Note 8Owners' Equity
Centennial OpCo
Centennial OpCo's operations are governed by the provisions of the Fourth Amended and Restated Limited Liability Company Agreement
("Agreement"), effective April 15, 2015. As of December 31, 2015, members included Centennial HoldCo, Celero and Follow-On, owning an approximate 61.2%, 21.2% and 17.6% membership
interest in Centennial OpCo, respectively.
In
2015 Follow-On contributed $84.2 million to Centennial OpCo in exchange for membership interests in Centennial OpCo. In addition, Centennial HoldCo contributed approximately
$27.2 million to Centennial OpCo in exchange for additional membership interests in Centennial OpCo.
At
December 31, 2015, Centennial OpCo has two classes of membership interests outstanding: Class A, which consist of membership interests held by Centennial HoldCo and
Follow-On; and Class B, which consist of membership interests held by Celero. As of December 31, 2015, Centennial HoldCo had contributed $289.4 million and had a remaining capital
commitment of $32.5 million, Follow-On had contributed $84.2 million and had a remaining capital commitment of $100.3 million, and Celero had contributed $125.4 million in
conjunction with the Combination and does not have a remaining capital commitment. Under the terms of the Agreement, Centennial OpCo will dissolve upon the earlier of July 1, 2022; the sale,
disposition or termination of all or substantially all of the property owned by Centennial OpCo; or consent in writing of Centennial HoldCo. Pursuant to the
F-36
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 8Owners' Equity (Continued)
Agreement
(and as is customary for limited liability companies), the liability of the members is limited to their contributed capital.
In
December 2014, the Predecessor sold its interest in approximately 1,845 net acres in Ward County, Texas, including 18 vertical wells, to an NGP-controlled entity for proceeds of
$12.5 million. Because the Predecessor and purchaser are considered entities under common control, the gain of $1.5 million was recorded as a deemed contribution from sale of assets.
On
October 15, 2014, Celero conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in Centennial OpCo.
In connection with the transaction Centennial HoldCo made cash tender offers to Celero's limited partners to purchase their
interest in the Partnership for their respective share of the transaction value of $157.6 million. A total of 20.4% of the partners accepted the cash tender offer for a total of
$32.2 million. Celero subsequently redeemed Celero limited partnership interests from Centennial HoldCo for $17.1 million in cash and $15.1 million in Centennial OpCo's membership
interest. Celero's contribution in Centennial OpCo after the conveyance was $125.4 million. Furthermore, the Combination was accounted for as a reorganization of entities under common control
in a manner similar to a pooling of interest which resulted in a deemed distribution of $4.1 million.
On
April 30, 2014 NGP X contributed and conveyed its membership interest in Centennial OpCo to Centennial HoldCo. On May 9, 2014, Centennial OpCo's remaining members sold
their membership interests to Centennial OpCo for $75.7 million.
On
March 31, 2014 all of Centennial OpCo's employee members sold their membership interests in Centennial OpCo. Centennial OpCo paid $11.4 million, net of promissory notes
from certain employee members, to acquire the membership interests. Contemporaneously, Centennial HoldCo, agreed to purchase the entirety of Centennial OpCo's issued and outstanding incentive units.
The total consideration paid by Centennial HoldCo to acquire the issued and outstanding incentive units was $12.4 million and is included in General and administration expense on the
consolidated and combined statement of operations. Additionally, the Predecessor recorded a deemed contribution from parent for payment of incentive units from Centennial HoldCo of
$12.4 million for funding the incentive unit purchase. All of the incentive unit purchases were fully settled and terminated as of August 31, 2014.
In
February 2014, the Predecessor sold its 98.5% interest in Atlantic Midstream to PennTex Permian, an NGP-controlled entity for net proceeds of $71.8 million. Because the
Predecessor and purchaser are considered entities under common control, the gain of $20.0 million was recorded as a deemed contribution from sale of assets.
In
2013, Centennial OpCo accepted $3.4 million of capital contributions from certain employee members in exchange for full recourse promissory notes, which were recorded as a
reduction of owners' equity.
Celero
In 2014, a portion of limited partners of the partnership elected to exit the partnership for total consideration of $32.2 million. In
2013, Celero made a $21.1 million tax distribution.
F-37
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 9Incentive Unit Compensation
Follow-On Incentive Units
Under the Amended and Restated NGP Centennial Follow-On LLC Agreement ("Follow-On LLC Agreement"), Follow-On grants certain
incentive units to certain employees of Centennial Resource Management, LLC ("Centennial Management"), a wholly-owned subsidiary of Centennial HoldCo. Employees of Centennial Management provide
substantially all of their services to the Predecessor and in substance the incentive unit holders are employees of the Predecessor; therefore, Follow-On's incentive units have been treated as
obligations of the Predecessor for accounting purposes.
In
April 2015, Tier I, Tier II, Tier III, Tier IV and Tier V incentive units were issued.
The
following table summarizes Follow-On's incentive unit activity for the year ended December 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tier I
|
|
Tier II
|
|
Tier III
|
|
Tier IV
|
|
Tier V
|
|
Incentive units at December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(5,000
|
)
|
|
(5,000
|
)
|
|
(5,000
|
)
|
|
(5,000
|
)
|
|
(5,000
|
)
|
Granted
|
|
|
919,000
|
|
|
919,000
|
|
|
919,000
|
|
|
919,000
|
|
|
919,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive units at December 31, 2015
|
|
|
914,000
|
|
|
914,000
|
|
|
914,000
|
|
|
914,000
|
|
|
914,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at December 31, 2015
|
|
|
121,197
|
|
|
121,197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All
of the incentive units are non-voting and subject to certain vesting and performance conditions. The terms of the incentive units are as follows: Tier I and Tier II
incentive units vest ratably over five years, but are subject to forfeiture if payout is not achieved. In addition, all unvested Tier I and Tier II incentive units vest immediately upon
Tier I and Tier II payout, respectively. Tier III, IV and V incentive units vest only upon the achievement of certain payout thresholds for each such tier and each tier of
incentive units is subject to forfeiture if the applicable required payouts are not achieved. In addition, vested and unvested incentive units are forfeited if an incentive unit holder's employment is
terminated for any reason or if the incentive unit holder voluntarily terminates their employment. Payouts for each Tier I through V are based upon achievement of specified rates of return on
Follow-On's invested capital.
The
incentive units are issued to employees in return for services provided and cash payout is based, in part, on the value of Follow-On's equity; therefore, the incentive units are
accounted for as liability awards under FASB ASC Topic 718,
CompensationStock Compensation
, with compensation expense based on period-end
fair value. The achievement of payout conditions is a performance condition that requires the Predecessor to assess, at each reporting period, the probability that an event of payout will occur.
Compensation cost is required to be recognized at such time that the payout terms are probable of being met. No incentive compensation expense was recorded at December 31, 2015 or 2014, because
it was not probable that the performance criterion would be met.
Centennial HoldCo Incentive Units
As of December 31, 2015 and 2014, Tier I, Tier II, Tier III, Tier IV and Tier V incentive units had
been issued to certain employees of Centennial Management. Employees of Centennial Management provide substantially all of their services to the Predecessor and in substance the incentive unit holders
F-38
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 9Incentive Unit Compensation (Continued)
are
employees of the Predecessor. Therefore, Centennial HoldCo's incentive units have been treated as obligations of the Predecessor for accounting purposes.
The
following table summarizes Centennial HoldCo's incentive unit activity for the years ended December 31, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tier I
|
|
Tier II
|
|
Tier III
|
|
Tier IV
|
|
Tier V
|
|
Incentive units at December 31, 2013
|
|
|
655,000
|
|
|
655,000
|
|
|
655,000
|
|
|
655,000
|
|
|
655,000
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
254,000
|
|
|
254,000
|
|
|
254,000
|
|
|
254,000
|
|
|
254,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive units at December 31, 2014
|
|
|
909,000
|
|
|
909,000
|
|
|
909,000
|
|
|
909,000
|
|
|
909,000
|
|
Forfeited
|
|
|
(6,000
|
)
|
|
(6,000
|
)
|
|
(6,000
|
)
|
|
(6,000
|
)
|
|
(6,000
|
)
|
Granted
|
|
|
11,000
|
|
|
11,000
|
|
|
11,000
|
|
|
11,000
|
|
|
11,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive units at December 31, 2015
|
|
|
914,000
|
|
|
914,000
|
|
|
914,000
|
|
|
914,000
|
|
|
914,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at December 31, 2015
|
|
|
370,517
|
|
|
370,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All
of the incentive units are non-voting and subject to certain vesting and performance conditions. The terms of the incentive units are as follows: Tier I and Tier II
incentive units vest ratably over five years, but are subject to forfeiture if payout is not achieved. In addition, all unvested Tier I and Tier II incentive units vest immediately upon
Tier I and Tier II payout, respectively. Tier III, IV and V incentive units vest only upon the achievement of certain payout thresholds for each such tier and each tier of
incentive units is subject to forfeiture if the applicable required payouts are not achieved. In addition, vested and unvested incentive units are forfeited if an incentive unit holder's employment is
terminated for any reason or if the incentive unit holder voluntarily terminates their employment. Payouts for each Tier I through Tier V are based upon achievement of specified rates of
return on Centennial HoldCo's invested capital.
The
incentive units are issued to employees in return for services provided and cash payout is based, in part, on the value of Centennial HoldCo's equity; therefore, the incentive units
are accounted for as liability awards under FASB ASC Topic 718,
CompensationStock Compensation
, with compensation expense based on
period-end fair value. The achievement of payout conditions is a performance condition that requires the Predecessor to assess, at each reporting period, the probability that an event of payout will
occur. Compensation cost is required to be recognized at such time that
the payout terms are probable of being met. No incentive compensation expense was recorded at December 31, 2015 or 2014, because it was not probable that the performance criterion would be met.
Centennial OpCo Incentive Units
Under Centennial OpCo's Second Amended and Restated Limited Liability Company Agreement, Centennial OpCo issued certain incentive units to its
management and employees. All of the incentive units were non-voting and subject to certain vesting and performance conditions. The incentive units were accounted for as liability awards and
compensation expense is based on period-end fair value.
On
March 31, 2014, Centennial HoldCo agreed to purchase the entirety of Centennial OpCo's issued and outstanding incentive units for total consideration of $12.4 million
(the "Incentive Unit
F-39
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 9Incentive Unit Compensation (Continued)
Purchase").
The closing and funding of the Incentive Unit Purchase occurred separately for each employee in accordance with each individual Membership Interest Purchase Agreement during the second and
third quarters of 2014 and is included within the
General and administrative expense
line item in the consolidated and combined statements of operations
for the year ended December 31, 2014. Additionally, the Predecessor recorded a capital contribution from Centennial HoldCo of $12.4 million for funding of the Incentive Unit Purchase
during the year ended December 31, 2014. As a result of the Incentive Unit Purchase, all of Centennial OpCo's incentive units were fully settled and terminated as of August 31, 2014.
The
following table summarizes Centennial OpCo's incentive unit activity for the years ended December 31, 2014 and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tier I
|
|
Tier II
|
|
Tier III
|
|
Tier IV
|
|
Tier V
|
|
Incentive units at December 31, 2012
|
|
|
941,252
|
|
|
|
|
|
935,004
|
|
|
939,137
|
|
|
939,137
|
|
Forfeited
|
|
|
(4,557
|
)
|
|
(1,519
|
)
|
|
(4,557
|
)
|
|
|
|
|
|
|
Settled
|
|
|
(132,322
|
)
|
|
(132,322
|
)
|
|
(132,322
|
)
|
|
(136,681
|
)
|
|
(136,681
|
)
|
Granted
|
|
|
45,877
|
|
|
984,091
|
|
|
45,865
|
|
|
45,893
|
|
|
45,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive units at December 31, 2013
|
|
|
850,250
|
|
|
850,250
|
|
|
843,990
|
|
|
848,349
|
|
|
848,349
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settled
|
|
|
(866,159
|
)
|
|
(866,159
|
)
|
|
(843,990
|
)
|
|
(848,349
|
)
|
|
(848,349
|
)
|
Granted
|
|
|
15,909
|
|
|
15,909
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive units at December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 10Asset Retirement Obligations
The Predecessor recognizes an estimated liability for future costs associated with the plugging and abandonment of its oil and natural gas properties. A liability for the fair value of
an asset retirement obligation ("ARO") and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired. The increase in
carrying value is included in proved oil and natural gas properties in the accompanying consolidated and combined balance sheets. The Predecessor depletes the amount added to proved oil and gas
property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties. Cash
paid to settle asset retirement obligations is included in the operating section of the Predecessor's accompanying consolidated and combined statements of cash flows.
The
Predecessor's estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and
abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In
periods subsequent to the initial measurement of the ARO, the Predecessor must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing
or the amount of the original estimate of undiscounted cash flows.
F-40
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 10Asset Retirement Obligations (Continued)
The following table summarizes the changes in the Predecessor's asset retirement obligations for the periods indicated (in thousands):
|
|
|
|
|
|
|
|
|
|
For the Year Ended
December 31,
|
|
|
|
2015
|
|
2014
|
|
Asset retirement obligations, beginning of year
|
|
$
|
1,824
|
|
$
|
3,557
|
|
Additional liabilities incurred
|
|
|
133
|
|
|
670
|
|
Liabilities acquired
|
|
|
178
|
|
|
|
|
Liabilities disposed(1)
|
|
|
|
|
|
(2,820
|
)
|
Accretion expense
|
|
|
139
|
|
|
156
|
|
Revision of estimated liabilities
|
|
|
14
|
|
|
261
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of year
|
|
$
|
2,288
|
|
$
|
1,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Refer
to
Note 4Acquisitions and Divestitures
.
Note 11Commitments and Contingencies
Commitments
The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess
of one year as of December 31, 2015:
|
|
|
|
|
Years Ending December 31,
|
|
Amount
|
|
|
|
(in thousands)
|
|
2016
|
|
$
|
2,676
|
|
2017
|
|
|
477
|
|
2018
|
|
|
485
|
|
2019
|
|
|
419
|
|
2020
|
|
|
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,057
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling Rig Contracts
As of December 31, 2015, the Predecessor is not party to any long-term drilling rig contracts.
In
light of the low commodity price environment, the Predecessor curtailed its drilling activity during 2015. For the year ended December 31, 2015, the Predecessor incurred
drilling rig termination fees of $2.4 million, which are recorded in the
Contract termination and rig stacking
line item in the accompanying
consolidated and combined statement of operations.
F-41
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 11Commitments and Contingencies (Continued)
Office Leases
The Predecessor leases office space in Denver, Colorado and Midland, Texas. Rent expense for the years ended December 31, 2015, 2014 and
2013 was $0.4 million, $0.5 million and $0.8 million, respectively.
Financing Obligation
The Predecessor is party to a contract with PennTex Permian, LLC ("PennTex"), an NGP-controlled entity, to construct an expansion of the
gathering system and a receipt point. The Predecessor will reimburse the gas gatherer for the total cost of the expansion project. The Predecessor shall pay a minimum fee of $7,000 per day until the
gas gatherer recoups the capital outlay for the expansion project. The Predecessor determined that the agreement contains an embedded lease and the transaction was accounted for as a financing
obligation. The Predecessor recorded an asset and a liability of $3.8 million attributable to this agreement. The asset is being depreciated over its estimated remaining life. At
December 31, 2015, a short-term liability of $2.1 million was included in
Other current
liabilities
on the consolidated and combined balance sheets. The Predecessor has made payments of $1.7 million as of December 31, 2015, including interest.
Contingencies
The Predecessor is subject to litigation and claims arising in the ordinary course of business. The Predecessor accrues for such items when a
liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such pending litigation and claims will not have a material effect on the results of
operations, the financial position, or the cash flows of the Predecessor.
Note 12Transactions with Related Parties
In December 2014, the Predecessor sold its interest in approximately 1,845 net acres in Ward County, Texas, including 18 vertical wells, to an NGP-controlled entity for proceeds of
$12.5 million. For additional discussion, please refer to
Note 4Acquisitions and Divestitures
.
In
October 2014, Celero, an NGP-controlled entity, conveyed substantially all of its oil and gas properties and other assets to Centennial OpCo in exchange for membership interests in
Centennial OpCo. As a result of the transaction, Centennial HoldCo owned approximately 72% of Centennial OpCo, and Celero owned the remaining 28%. For additional discussion, please refer to
Note 2Basis of
Presentation
.
Effective
October 14, 2014, the Predecessor entered into a Management Services Agreement with Centennial Management, a wholly-owned subsidiary of Centennial HoldCo. Employees of
Centennial Management provide substantially all of their services to the Predecessor.
In
October 2014, the gas gathering agreement with PennTex Permian was amended to construct an expansion of the gathering system and a receipt point. The Predecessor will reimburse
PennTex Permian for the total cost of the expansion project. The Predecessor shall pay a minimum fee of $7,000 per day until PennTex Permian recoups the capital outlay for the expansion project. At
December 31, 2015, a short-term liability of $2.1 million was included in
Other current liabilities
on the consolidated
F-42
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 12Transactions with Related Parties (Continued)
and
combined balance sheets. As of December 31, 2015, the Predecessor has made payments of $1.7 million, including interest.
In
February 2014, the Predecessor entered into a gas gathering agreement with Atlantic Midstream. At the time this agreement was entered into, the Predecessor had a 98.5% interest in
Atlantic Midstream. In February 2014, subsequent to entry into this gas gathering agreement, the Predecessor sold its 98.5% interest in Atlantic Midstream to PennTex Permian, LLC, an
NGP-controlled entity for net proceeds of $71.8 million. PennTex paid the Predecessor $1.2 million and $2.2 million for purchases of residue gas and NGLs (net of gathering,
processing and other fees) for the years ended December 31, 2015 and 2014.
From
time to time, the Predecessor obtains services related to its drilling and completion activities from affiliates of NGP. In particular, since 2014, the Predecessor has paid the
following amounts to the following affiliates of NGP for such services: (i) approximately $1.2 million during the year ended December 31, 2015 to RockPile Energy
Services, LLC; and (ii) approximately $1.7 million during the year ended December 31, 2014 to MS Energy Services.
Note 13Subsequent Events
The Predecessor has evaluated all subsequent events through the date the financial statements were filed with the SEC and has nothing additional to disclose.
Note 14Supplemental Oil and Gas Information (unaudited)
Costs Incurred For Oil and Natural Gas Producing Activities
The following table sets forth the capitalized costs incurred in the Predecessor's oil and natural gas production, exploration, and development
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(in thousands)
|
|
Acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
14,268
|
|
$
|
5,758
|
|
$
|
10,208
|
|
Unproved properties
|
|
|
28,955
|
|
|
16,409
|
|
|
17,204
|
|
Development costs
|
|
|
87,452
|
|
|
324,802
|
|
|
151,562
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
130,675
|
|
$
|
346,969
|
|
$
|
178,974
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Reserve Quantities
The reserve estimates presented below were made in accordance with U.S. GAAP requirements for disclosures about oil and natural gas
producing activities and Securities and Exchange Commission ("SEC") rules for oil and natural gas reporting reserves estimation and disclosure.
Estimates
of the Predecessor's proved oil and natural gas reserves at December 31, 2015 and 2014 were prepared by Netherland, Sewell & Associates, Inc. Estimates of
the Predecessor's proved oil and
F-43
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 14Supplemental Oil and Gas Information (unaudited) (Continued)
natural
gas reserves at December 31, 2013 were prepared internally by management and not by independent third-party petroleum engineers.
There
are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are
often different from the quantities of oil and natural gas that are ultimately recovered.
The
following table summarizes the trailing 12-month index prices used in the reserve estimates for the years ended December 31, 2015, 2014 and 2013. The following prices, as
adjusted for transportation, quality, and basis differentials, were used in the calculation of the standardized measure of discounted future net cash flows ("standardized measure"):
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended
December 31,
|
|
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(in thousands)
|
|
Oil (per Bbl)
|
|
$
|
41.85
|
|
$
|
84.94
|
|
$
|
92.05
|
|
Gas (per Mcf)
|
|
$
|
1.71
|
|
$
|
4.70
|
|
$
|
3.76
|
|
NGLs (per Bbl)
|
|
$
|
13.94
|
|
$
|
22.70
|
|
$
|
26.05
|
|
The
table below presents a summary of changes in the Predecessor's estimated proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
Crude
Oil
(MBbls)
|
|
Natural
Gas
(MMcf)
|
|
Natural
Gas
Liquids
(MBbls)
|
|
Crude
Oil
(MBbls)
|
|
Natural
Gas
(MMcf)
|
|
Natural
Gas
Liquids
(MBbls)
|
|
Crude
Oil
(MBbls)
|
|
Natural
Gas
(MMcf)
|
|
Natural
Gas
Liquids
(MBbls)
|
|
Total Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of the year
|
|
|
19,850
|
|
|
27,414
|
|
|
1,551
|
|
|
18,510
|
|
|
6,968
|
|
|
525
|
|
|
11,422
|
|
|
10,032
|
|
|
967
|
|
Extensions and discoveries
|
|
|
9,444
|
|
|
11,927
|
|
|
1,432
|
|
|
16,122
|
|
|
22,575
|
|
|
1,127
|
|
|
12,459
|
|
|
5,189
|
|
|
300
|
|
Revisions of previous estimates
|
|
|
(5,109
|
)
|
|
(5,204
|
)
|
|
995
|
|
|
56
|
|
|
178
|
|
|
180
|
|
|
426
|
|
|
837
|
|
|
80
|
|
Purchases of reserves in place
|
|
|
844
|
|
|
1,363
|
|
|
204
|
|
|
162
|
|
|
192
|
|
|
23
|
|
|
109
|
|
|
94
|
|
|
8
|
|
Divestitures of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
(13,572
|
)
|
|
(387
|
)
|
|
(69
|
)
|
|
(5,193
|
)
|
|
(8,387
|
)
|
|
(732
|
)
|
Production
|
|
|
(1,830
|
)
|
|
(3,058
|
)
|
|
(331
|
)
|
|
(1,428
|
)
|
|
(2,112
|
)
|
|
(235
|
)
|
|
(713
|
)
|
|
(797
|
)
|
|
(98
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of the year
|
|
|
23,199
|
|
|
32,442
|
|
|
3,851
|
|
|
19,850
|
|
|
27,414
|
|
|
1,551
|
|
|
18,510
|
|
|
6,968
|
|
|
525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of the year
|
|
|
8,026
|
|
|
11,959
|
|
|
766
|
|
|
6,021
|
|
|
4,837
|
|
|
382
|
|
|
2,978
|
|
|
2,078
|
|
|
285
|
|
End of the year
|
|
|
9,347
|
|
|
12,711
|
|
|
1,603
|
|
|
8,026
|
|
|
11,959
|
|
|
766
|
|
|
6,021
|
|
|
4,837
|
|
|
382
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of the year
|
|
|
11,823
|
|
|
15,455
|
|
|
785
|
|
|
12,489
|
|
|
2,131
|
|
|
143
|
|
|
8,444
|
|
|
7,954
|
|
|
682
|
|
End of the year
|
|
|
13,852
|
|
|
19,731
|
|
|
2,248
|
|
|
11,823
|
|
|
15,455
|
|
|
785
|
|
|
12,489
|
|
|
2,131
|
|
|
143
|
|
F-44
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 14Supplemental Oil and Gas Information (unaudited) (Continued)
Proved
reserves at December 31, 2015 increased 25% to 32,457 MBoe, compared to 25,970 MBoe at December 31, 2014.
During
2015, the Predecessor added 12,864 MBoe of proved reserves through extensions, primarily due to its drilling activity.
During
2015, the Predecessor had net negative revisions of 4,981 MBoe. The significant decrease in commodity prices seen in 2015 resulted in negative revisions related to the conversion
of approximately 6,794 MBoe from PUDs to unproved reserves, partially offset by a positive revision in performance.
During
2015, the Predecessor acquired 1,275 MBoe of proved reserves. Refer to
Note 4Acquisitions and Divestitures
.
During
2014, the Predecessor added 21,012 MBoe of proved reserves through extensions and discoveries, primarily due to its continued development drilling program and 265 MBoe of proved
reserves, due to better than expected performance of its proved developed reserves.
During
2014, the Predecessor divested of 13,706 MBoe of proved reserves. Refer to
Note 4Acquisitions and Divestitures
.
During
2013, the Predecessor added 6,934 MBoe of proved reserves through extension and discoveries, primarily from the drilling of new wells and from new proved undeveloped locations
added during the year. Additionally, the Predecessor added 6,799 MBoe through improved recovery. Improved recovery reflects reserve additions that result from the application of tertiary recovery
methods such as CO
2
injection at the Predecessor's Caprock field. The Caprock field was sold in May 2014.
During
2013, the Predecessor had revisions of 646 MBoe due to better than expected performance attributable to its proved developed reserves.
During
2013, the Predecessor divested of 7,323 MBoe for certain properties sold. Refer to
Note 4Acquisitions and
Divestitures
.
Standardized Measure of Discounted Future Net Cash Flows
The Predecessor computes a standardized measure of discounted future net cash flows and changes therein relating to estimated proved reserves in
accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis
differentials, to the year-end estimated future reserve quantities. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
Future
operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end
costs and assuming continuation of existing economic conditions.
The
assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Predecessor's expectations of
actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the
F-45
Table of Contents
CENTENNIAL RESOURCE PRODUCTION, LLC AND CELERO ENERGY COMPANY, LP
(PREDECESSOR)
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 14Supplemental Oil and Gas Information (unaudited) (Continued)
reserve
quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation
process.
The
following table presents the Predecessor's standardized measure of discounted future net cash flows for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(in thousands)
|
|
Future cash inflows
|
|
$
|
1,079,962
|
|
$
|
1,850,205
|
|
$
|
1,743,612
|
|
Future development costs
|
|
|
(277,837
|
)
|
|
(440,366
|
)
|
|
(223,227
|
)
|
Future production costs
|
|
|
(450,058
|
)
|
|
(457,236
|
)
|
|
(601,614
|
)
|
Future income tax expenses
|
|
|
(6,643
|
)
|
|
(10,834
|
)
|
|
(3,540
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
345,424
|
|
|
941,769
|
|
|
915,231
|
|
10% discount to reflect timing of cash flows
|
|
|
(210,355
|
)
|
|
(575,886
|
)
|
|
(543,924
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
135,069
|
|
$
|
365,883
|
|
$
|
371,307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A
summary of changes in the standardized measure of discounted future net cash flows is as follows for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2015
|
|
2014
|
|
2013
|
|
|
|
(in thousands)
|
|
Standardized measure of discounted future net cash flows, beginning of the period
|
|
$
|
365,883
|
|
$
|
371,307
|
|
$
|
257,083
|
|
Sales of oil, natural gas and NGLs, net of production costs
|
|
|
(58,534
|
)
|
|
(102,488
|
)
|
|
(47,424
|
)
|
Purchase of minerals in place
|
|
|
14,416
|
|
|
5,650
|
|
|
4,410
|
|
Divestiture of minerals in place
|
|
|
|
|
|
(242,344
|
)
|
|
(73,174
|
)
|
Extensions and discoveries, net of future development costs
|
|
|
57,894
|
|
|
312,532
|
|
|
99,107
|
|
Change in estimated development costs
|
|
|
16,100
|
|
|
10,386
|
|
|
7,520
|
|
Net change in prices and production costs
|
|
|
(494,734
|
)
|
|
(3,027
|
)
|
|
21,601
|
|
Change in estimated future development costs
|
|
|
247,642
|
|
|
2,935
|
|
|
(40,783
|
)
|
Revisions of previous quantity estimates
|
|
|
(51,342
|
)
|
|
924
|
|
|
135,759
|
|
Accretion of discount
|
|
|
37,517
|
|
|
13,561
|
|
|
19,000
|
|
Net change in income taxes
|
|
|
1,601
|
|
|
(2,762
|
)
|
|
(35
|
)
|
Net change in timing of production and other
|
|
|
(1,374
|
)
|
|
(791
|
)
|
|
(11,757
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows, end of the period
|
|
$
|
135,069
|
|
$
|
365,883
|
|
$
|
371,307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-46
Table of Contents
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED
FINANCIAL INFORMATION
The unaudited pro forma condensed consolidated combined statements of operations for the nine months ended September 30, 2016 and for the
year ended December 31, 2015 combine the historical consolidated statements of operations of Silver Run Acquisition Corporation ("Silver Run") and the historical consolidated statements of
operations of Centennial Resource Production, LLC, a Delaware limited liability company ("CRP"), giving effect to the Transactions (as defined below) as if they had been consummated on
January 1, 2015, the beginning of the earliest period presented. The unaudited pro forma condensed consolidated combined balance sheet as of September 30, 2016 combines the historical
consolidated balance sheet of Silver Run and the historical condensed consolidated balance sheet of CRP, giving effect to the following transactions (for purposes of this section, collectively, the
"Transactions") as if they had been consummated on September 30, 2016:
-
-
the acquisition by Silver Run of approximately 89% of the outstanding membership interests in CRP pursuant to that certain Contribution
Agreement, dated as of July 6, 2016 (as amended by Amendment No. 1 thereto, dated as of July 29, 2016, the "Contribution Agreement"), among Centennial Resource
Development, LLC, a Delaware limited liability company ("CRD"), NGP Centennial Follow-On LLC, a Delaware limited liability company ("NGP Follow-On"), Celero Energy Company, LP, a
Delaware limited partnership (together with CRD and NGP Follow-On, the "Centennial Contributors"), CRP and New Centennial, LLC, a Delaware limited liability company controlled by Riverstone
Investment Group LLC and its affiliates (collectively, "Riverstone"), to which we expect to become a party following the approval and adoption of the same by Silver Run's stockholders (the
"business combination");
-
-
the conversion of 12,500,000 shares of Silver Run's Class B Common Stock, par value $0.0001 per share, into 12,500,000 shares of Silver
Run's Class A Common Stock, par value $0.0001 per share (the "Class A Common Stock"), in connection with the business combination;
-
-
the issuance by Silver Run of 20,000,000 shares of a new class of capital stock designated as Class C Common Stock, par value $0.0001
per share (the "Class C Common Stock"), to the Centennial Contributors in connection with the business combination;
-
-
the issuance by Silver Run of 1 share of a new class of preferred stock designated as Series A Preferred Stock, par value $0.0001 per
share (the "Series A Preferred Stock"), to CRD in connection with the business combination;
-
-
the issuance and sale by Silver Run of (a) up to 81,005,000 shares of Class A Common Stock to Riverstone Centennial
Holdings, L.P., an accredited investor affiliated with Riverstone (together with any person to whom it assigns the right to purchase such shares, the "Riverstone private investors" and such
issuance, together with any issuance of additional shares of Class A Common Stock to the Riverstone private investors to facilitate the Transactions, the "Riverstone Private Placement"), and
(b) 20,000,000 shares of Class A Common Stock to certain other investors in a private placement (together with the Riverstone Private Placement, the "Private Placements"), the proceeds
of which will be used to fund a portion of the cash consideration in the business combination;
-
-
the contribution of cash by Silver Run to CRP necessary for CRP to repay any of its or its subsidiaries' outstanding debt that becomes due and
payable as a result of the consummation of the business combination, which as of September 30, 2016, was approximately $189.0 million (the "Additional Debt Repayment Contribution"); and
-
-
the redemption by Silver Run of shares of Class A Common Stock held by any public stockholders in connection with the business
combination and the issuance by Silver Run of
F-47
Table of Contents
The
historical consolidated financial statements have been adjusted in the unaudited pro forma condensed consolidated combined financial statements to give pro forma effect to events
that are: (1) directly attributable to the business combination; (2) factually supportable; and (3) with respect to the statement of operations, expected to have a continuing
impact on Silver Run's results following the completion of the Transactions.
The
unaudited pro forma condensed consolidated combined financial statements have been developed from and should be read in conjunction with:
-
-
the accompanying notes to the unaudited pro forma condensed consolidated combined financial statements;
-
-
the historical audited financial statements of Silver Run as of December 31, 2015 and for the period from November 4, 2015 (date
of inception) to December 31, 2015, which are included in Silver Run's definitive proxy statement filed with the Securities and Exchange Commission (the "SEC") on September 23, 2016 (the
"Proxy Statement");
-
-
the historical unaudited financial statements of Silver Run as of and for the three and nine months ended September 30, 2016, which are
included in Silver Run's Form 10-Q for the quarter ended September 30, 2016 filed with the SEC on November 10, 2016 (the "Silver Run 10-Q");
-
-
the historical consolidated audited financial statements of CRP as of and for the year ended December 31, 2015, which are included in
the Proxy Statement;
-
-
the historical condensed consolidated unaudited financial statements of CRP as of and for the nine months ended September 30, 2016,
which are included within this registration statement; and
-
-
other information relating to Silver Run and CRP contained in the Proxy Statement.
Under
Silver Run's amended and restated certificate of incorporation, public stockholders have the right to redeem, upon the closing of the business combination, shares of Class A
Common Stock then held by them for cash equal to their pro rata share of the aggregate amount on deposit (as of two business days prior to the closing of the business combination) in the Trust
Account. For illustrative purposes, based on the fair value of marketable securities held in the Trust Account as of September 30, 2016 of approximately $500,549,792, the estimated per share
redemption price would have been approximately $10.00. To the extent that any shares of Class A Common Stock are redeemed from the public stockholders, the Riverstone private investors have
agreed to be ready, willing and able to purchase additional shares of Class A Common Stock from us at $10.00 per share to offset such redemptions on a share-for-share basis. As a result, if we
assume as an illustrative redemption scenario that approximately 47.9 million shares of Class A Common Stock are redeemed from the public stockholders, resulting in an aggregate payment
of $478.8 million from the Trust Account, the reduction in the Trust Account of $478.8 million is assumed to result in Silver Run issuing approximately an additional 47.9 million
shares of Class A Common Stock to the Riverstone private investors as part of
the Riverstone Private Placement, and the illustrative redemption scenario does not result in any pro forma adjustments to the unaudited pro forma condensed consolidated combined balance sheet or the
cash and cash equivalents, common stock, additional paid in capital, pro forma shares outstanding or earnings per share line items.
The
unaudited pro forma condensed consolidated combined financial statements have been prepared using the acquisition method of accounting in accordance with U.S. GAAP with Silver
Run as
F-48
Table of Contents
the
acquirer. Under the acquisition method of accounting, the purchase price is allocated to the underlying CRP assets acquired and liabilities assumed based on their respective fair market values.
Silver
Run has not completed the detailed valuation studies necessary to arrive at the required estimates of the fair value of the assets acquired, the liabilities assumed and the
related allocations of the purchase price in the business combination. As a result, the unaudited pro forma adjustments are preliminary and are subject to change as additional information becomes
available and as additional analyses are performed. The unaudited pro forma adjustments have been made solely for the purpose of providing the unaudited pro forma condensed consolidated combined
financial statements presented below.
Silver
Run has estimated the fair value of assets acquired and liabilities assumed based on discussions with members of CRP's management, preliminary valuation studies, due diligence and
information presented in the financial statements and accounting records of CRP. The valuation will be finalized as soon as practicable within the required measurement period, but in no event later
than twelve months following completion of the business combination. Any increases or decreases in the fair value of these assets and liabilities upon completion of the final valuations will result in
adjustments to the balance sheet and/or statement of operations. In addition, the final purchase price of the business combination is subject to the final determination of the Additional Debt
Repayment Contribution. The final purchase price and the final purchase price allocation may be different than that reflected in the preliminary purchase price allocation presented herein, and this
difference may be material.
Assumptions
and estimates underlying the unaudited pro forma adjustments set forth in the unaudited pro forma condensed consolidated combined financial statements are described in the
accompanying notes. The unaudited pro forma condensed consolidated combined financial statements have been presented for illustrative purposes only and are not necessarily indicative of the operating
results and financial position that would have been achieved had the business combination and the other related Transactions occurred on the dates indicated. Further, the unaudited pro forma condensed
consolidated combined financial statements do not purport to project the future operating results or financial position of Silver Run following the completion of the business combination and the other
related
Transactions. The unaudited pro forma adjustments represent management's estimates based on information available as of the date of these unaudited pro forma condensed consolidated combined financial
statements and are subject to change as additional information becomes available and analyses are performed.
F-49
Table of Contents
Silver Run Acquisition Corporation
Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations
Year Ended December 31, 2015
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Silver Run
|
|
(b)
CRP
|
|
Pro forma
Adjustments
|
|
|
|
Pro forma
Combined
(Assuming No
Redemptions
and Assuming
Illustrative
Redemptions)
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
|
|
$
|
77,643
|
|
$
|
|
|
|
|
$
|
77,643
|
|
|
Natural gas sales
|
|
|
|
|
|
7,965
|
|
|
|
|
|
|
|
7,965
|
|
|
NGL sales
|
|
|
|
|
|
4,852
|
|
|
|
|
|
|
|
4,852
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
|
|
|
90,460
|
|
|
|
|
|
|
|
90,460
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
|
|
|
21,173
|
|
|
|
|
|
|
|
21,173
|
|
|
Severance and ad valorem taxes
|
|
|
|
|
|
5,021
|
|
|
|
|
|
|
|
5,021
|
|
|
Transportation, processing, gathering and other operating expenses
|
|
|
|
|
|
5,732
|
|
|
|
|
|
|
|
5,732
|
|
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
|
|
|
90,084
|
|
|
(24,338
|
)
|
(c)
|
|
|
65,746
|
|
|
Abandonment expense and impairment of unproved properties
|
|
|
|
|
|
7,619
|
|
|
|
|
|
|
|
7,619
|
|
|
Exploration
|
|
|
|
|
|
84
|
|
|
|
|
|
|
|
84
|
|
|
Contract termination and rig stacking
|
|
|
|
|
|
2,387
|
|
|
|
|
|
|
|
2,387
|
|
|
General and administrative expenses
|
|
|
2
|
|
|
14,206
|
|
|
|
|
|
|
|
14,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
2
|
|
|
146,306
|
|
|
(24,338
|
)
|
|
|
|
121,970
|
|
|
Gain on sale of oil and natural gas properties
|
|
|
|
|
|
(2,439
|
)
|
|
|
|
|
|
|
(2,439
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating loss
|
|
|
(2
|
)
|
|
(53,407
|
)
|
|
24,338
|
|
|
|
|
(29,071
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (expense) income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
|
|
|
(6,266
|
)
|
|
5,089
|
|
(e)
|
|
|
(1,177
|
)
|
|
Other income
|
|
|
|
|
|
20
|
|
|
|
|
|
|
|
20
|
|
|
Gain on derivative instruments
|
|
|
|
|
|
20,756
|
|
|
|
|
|
|
|
20,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
|
|
|
|
|
|
14,510
|
|
|
5,089
|
|
|
|
|
19,599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
(2
|
)
|
|
(38,897
|
)
|
|
29,427
|
|
|
|
|
(9,472
|
)
|
|
Income tax benefit
|
|
|
|
|
|
572
|
|
|
2,459
|
|
(f)
|
|
|
3,031
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
(2
|
)
|
|
(38,325
|
)
|
|
31,886
|
|
|
|
|
(6,441
|
)
|
|
Less: Net loss attributable to non-controlling interests
|
|
|
|
|
|
|
|
|
(1,032
|
)
|
(g)
|
|
|
(1,032
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to the combined entity
|
|
$
|
(2
|
)
|
$
|
(38,325
|
)
|
$
|
32,918
|
|
|
|
$
|
(5,409
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.00
|
|
|
|
|
|
|
|
|
|
$
|
(0.03
|
)
|
(h)
|
Diluted
|
|
$
|
0.00
|
|
|
|
|
|
|
|
|
|
$
|
(0.03
|
)
|
(h)
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
12,938
|
|
|
|
|
|
|
|
|
|
|
163,500
|
|
(h)
|
Diluted
|
|
|
12,938
|
|
|
|
|
|
|
|
|
|
|
183,500
|
|
(h)
|
F-50
Table of Contents
Silver Run Acquisition Corporation
Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations
Nine Months Ended September 30, 2016
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Silver Run
|
|
(b)
CRP
|
|
Pro forma
Adjustments
|
|
|
|
Pro forma
Combined
(Assuming No
Redemptions
and Assuming
Illustrative
Redemptions)
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
|
|
$
|
56,975
|
|
$
|
|
|
|
|
$
|
56,975
|
|
|
Natural gas sales
|
|
|
|
|
|
5,717
|
|
|
|
|
|
|
|
5,717
|
|
|
NGL sales
|
|
|
|
|
|
3,097
|
|
|
|
|
|
|
|
3,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
|
|
|
65,789
|
|
|
|
|
|
|
|
65,789
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
|
|
|
10,295
|
|
|
|
|
|
|
|
10,295
|
|
|
Severance and ad valorem taxes
|
|
|
|
|
|
3,523
|
|
|
|
|
|
|
|
3,523
|
|
|
Transportation, processing, gathering and other operating expenses
|
|
|
|
|
|
4,375
|
|
|
|
|
|
|
|
4,375
|
|
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
|
|
|
|
|
60,939
|
|
|
(26,440
|
)
|
(c)
|
|
|
34,499
|
|
|
Abandonment expense and impairment of unproved properties
|
|
|
|
|
|
2,546
|
|
|
|
|
|
|
|
2,546
|
|
|
General and administrative expenses
|
|
|
1,009
|
|
|
10,655
|
|
|
|
|
|
|
|
11,664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
1,009
|
|
|
92,333
|
|
|
(26,440
|
)
|
|
|
|
66,902
|
|
|
Gain on sale of oil and natural gas properties
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating loss
|
|
|
(1,009
|
)
|
|
(26,533
|
)
|
|
26,440
|
|
|
|
|
(1,102
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (expense) income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
|
|
|
(5,422
|
)
|
|
4,587
|
|
(e)
|
|
|
(835
|
)
|
|
Other incomeinvestment income on Trust Account
|
|
|
550
|
|
|
|
|
|
(550
|
)
|
(d)
|
|
|
|
|
|
Other income
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
6
|
|
|
Loss on derivative instruments
|
|
|
|
|
|
(4,184
|
)
|
|
|
|
|
|
|
(4,184
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
550
|
|
|
(9,600
|
)
|
|
4,037
|
|
|
|
|
(5,013
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
(459
|
)
|
|
(36,133
|
)
|
|
30,477
|
|
|
|
|
(6,115
|
)
|
|
Income tax benefit
|
|
|
|
|
|
406
|
|
|
1,522
|
|
|
|
|
1,928
|
|
(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
(459
|
)
|
|
(35,727
|
)
|
|
31,999
|
|
|
|
|
(4,187
|
)
|
|
Less: Net loss attributable to non-controlling interests
|
|
|
|
|
|
|
|
|
(657
|
)
|
|
|
|
(657
|
)
|
(g)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to the combined entity
|
|
$
|
(459
|
)
|
$
|
(35,727
|
)
|
$
|
32,656
|
|
|
|
$
|
(3,530
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.03
|
)
|
|
|
|
|
|
|
|
|
$
|
(0.02
|
)
|
(h)
|
Diluted
|
|
$
|
(0.03
|
)
|
|
|
|
|
|
|
|
|
$
|
(0.02
|
)
|
(h)
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
14,328
|
|
|
|
|
|
|
|
|
|
|
163,500
|
|
(h)
|
Diluted
|
|
|
14,328
|
|
|
|
|
|
|
|
|
|
|
183,500
|
|
(h)
|
F-51
Table of Contents
Silver Run Acquisition Corporation
Unaudited Pro Forma Condensed Consolidated Combined Balance Sheet
At September 30, 2016
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Silver Run
|
|
(b)
CRP
|
|
Pro forma
Adjustments
|
|
|
|
Pro forma
Combined
(Assuming No
Redemptions
and
Assuming
Illustrative
Redemptions)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
138
|
|
$
|
410
|
|
$
|
99,806
|
|
(c)
|
|
$
|
100,354
|
|
Accounts receivable, net
|
|
|
197
|
|
|
10,358
|
|
|
|
|
|
|
|
10,555
|
|
Derivative instruments
|
|
|
|
|
|
1,618
|
|
|
|
|
|
|
|
1,618
|
|
Prepaid and other current assets
|
|
|
165
|
|
|
864
|
|
|
|
|
|
|
|
1,029
|
|
Investment held in Trust Account
|
|
|
500,550
|
|
|
|
|
|
(500,550
|
)
|
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
501,050
|
|
|
13,250
|
|
|
(400,744
|
)
|
|
|
|
113,556
|
|
Oil and natural gas properties, other property and equipment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
|
|
|
|
|
718,999
|
|
|
(283,919
|
)
|
(e)
|
|
|
435,080
|
|
Accumulated depreciation, depletion and amortization
|
|
|
|
|
|
(241,017
|
)
|
|
241,017
|
|
(e)
|
|
|
|
|
Unproved oil and natural gas properties
|
|
|
|
|
|
139,690
|
|
|
998,545
|
|
(e)
|
|
|
1,138,235
|
|
Other property and equipment, net
|
|
|
|
|
|
1,703
|
|
|
|
|
|
|
|
1,703
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property and equipment, net
|
|
|
|
|
|
619,375
|
|
|
955,643
|
|
|
|
|
1,575,018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
|
|
|
|
245
|
|
|
|
|
|
|
|
245
|
|
Other noncurrent assets
|
|
|
|
|
|
1,042
|
|
|
(1,042
|
)
|
(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
501,050
|
|
$
|
633,912
|
|
$
|
553,857
|
|
|
|
$
|
1,688,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
2
|
|
$
|
23,579
|
|
$
|
|
|
|
|
$
|
23,581
|
|
Derivative instruments
|
|
|
|
|
|
1,000
|
|
|
|
|
|
|
|
1,000
|
|
Other current liabilities
|
|
|
300
|
|
|
243
|
|
|
|
|
|
|
|
543
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
302
|
|
|
24,822
|
|
|
|
|
|
|
|
25,124
|
|
Noncurrent liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit facility
|
|
|
|
|
|
124,000
|
|
|
(124,000
|
)
|
(f)
|
|
|
|
|
Term loan, net of unamortized deferred financing costs
|
|
|
|
|
|
64,762
|
|
|
(64,762
|
)
|
(f)
|
|
|
|
|
Asset retirement obligations
|
|
|
|
|
|
2,680
|
|
|
|
|
|
|
|
2,680
|
|
Deferred underwriting compensation
|
|
|
17,500
|
|
|
|
|
|
(17,500
|
)
|
(g)
|
|
|
|
|
Deferred tax liability
|
|
|
|
|
|
1,954
|
|
|
(1,954
|
)
|
|
|
|
|
|
Derivative instruments
|
|
|
|
|
|
557
|
|
|
|
|
|
|
|
557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
17,802
|
|
|
218,775
|
|
|
(208,216
|
)
|
|
|
|
28,361
|
|
Class A common stock subject to possible redemption; 47,877,199 shares (at redemption value of approximately $10.00 per share)
|
|
|
478,248
|
|
|
|
|
|
(478,248
|
)
|
(h)
|
|
|
|
|
OWNERS' EQUITY/ STOCKHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Owners' equity
|
|
|
|
|
|
415,137
|
|
|
(415,137
|
)
|
(j)
|
|
|
|
|
Preferred shares, $0.0001 par value; 1,000,000 shares authorized; none issued and outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Class A common stock, $0.0001 par value 200,000,000 shares authorized; 2,122,801 shares issued and outstanding at September 30, 2016 (excluding
47,877,199 shares subject to possible redemption)
|
|
|
1
|
|
|
|
|
|
1
|
|
(k)
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
5
|
|
(h)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
(m)
|
|
|
|
|
Class B common stock, $0.0001 par value 20,000,000 shares authorized, 12,500,000 shares issued and outstanding at September 30, 2016
|
|
|
1
|
|
|
|
|
|
(1
|
)
|
(k)
|
|
|
|
|
Class C common stock, $0.0001 par value; 20,000,000 shares authorized; 20,000,000 shares issued and outstanding at September 30, 2016
|
|
|
|
|
|
|
|
|
2
|
|
(l)
|
|
|
2
|
|
Additional paid-in capital
|
|
|
5,460
|
|
|
|
|
|
1,004,038
|
|
(m)
|
|
|
1,487,741
|
|
|
|
|
|
|
|
|
|
|
478,243
|
|
(h)
|
|
|
|
|
Retained Earnings (accumulated deficit)
|
|
|
(462
|
)
|
|
|
|
|
(11,550
|
)
|
(g)
|
|
|
(12,012
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
5,000
|
|
|
415,137
|
|
|
1,055,611
|
|
|
|
|
1,475,748
|
|
Non-controlling interests
|
|
|
|
|
|
|
|
|
184,710
|
|
(i)
|
|
|
184,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Equity
|
|
|
5,000
|
|
|
415,137
|
|
|
1,240,321
|
|
|
|
|
1,660,458
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Equity
|
|
$
|
501,050
|
|
$
|
633,912
|
|
$
|
553,857
|
|
|
|
$
|
1,688,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-52
Table of Contents
1. Basis of Pro Forma Presentation
Overview
The unaudited pro forma condensed consolidated combined financial statements have been prepared assuming the business combination is accounted
for using the acquisition method of accounting with Silver Run as the acquiring entity. Under the acquisition method of accounting, Silver Run's assets and liabilities will retain their carrying
values and CRP's assets and liabilities will be recorded at their fair values measured as of the acquisition date. The excess of the purchase price over the estimated fair values of CRP's net assets
acquired, if applicable, will be recorded as goodwill. The pro forma adjustments have been prepared as if the business combination and the other related Transactions had taken place on
September 30, 2016 in the case of the unaudited pro forma condensed consolidated combined balance sheet and on January 1, 2015 in the case of the unaudited pro forma condensed
consolidated combined statements of operations.
The
acquisition method of accounting is based on Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") 805, Business combination ("ASC 805"), and uses
the fair value concepts defined in FASB ASC 820, Fair Value Measurements ('ASC 820"). ASC 805 requires, among other things, that most assets acquired and liabilities assumed be recognized at their
fair values as of the acquisition date by Silver Run, who was determined to be the accounting acquirer.
ASC
820 defines the term "fair value," sets forth the valuation requirements for any asset or liability measured at fair value, expands related disclosure requirements and specifies a
hierarchy of valuation techniques based on the nature of the inputs used to develop the fair value measures. Fair value is defined in ASC 820 as "the price that would be received to sell an asset or
paid to transfer a liability in an orderly transaction between market participants at the measurement date." This is an exit price concept for the valuation of the asset or liability. In addition,
market participants are assumed to be buyers and sellers in the principal (or the most advantageous) market for the asset or liability. Fair value measurements for an asset assume the highest and best
use by these market participants. Many of these fair value measurements can be highly subjective, and it is possible that other professionals, applying reasonable judgment to the same facts and
circumstances, could develop and support a range of alternative estimated amounts.
Under
ASC 805, acquisition-related transaction costs are not included as a component of consideration transferred but are accounted for as expenses in the periods in which such costs are
incurred, or if related to the issuance of debt, capitalized as debt issuance costs. Acquisition-related transaction costs expected to be incurred as part of the business combination, include
estimated fees related to the issuance of long-term debt, as well as advisory, legal and accounting fees.
The
unaudited pro forma condensed consolidated combined financial statements should be read in conjunction with (i) Silver Run's historical financial statements and related notes
for the period from November 4, 2015 (date of inception) to December 31, 2015, as well as "Management's Discussion and Analysis of Financial Condition and Results of Operations of Silver
Run," which are included in the Proxy Statement, (ii) Silver Run's historical financial statements and related notes for the nine months
ended September 30, 2016, as well as "Management's Discussion and Analysis of Financial Condition and Results of Operations," which are included in the Silver Run 10-Q, (iii) CRP's
historical consolidated financial statements and related notes for the year ended December 31, 2015, as well as "Management's Discussion and Analysis of Financial Condition and Results of
Operations of CRP," which are included in the Proxy Statement, and (iv) CRP's historical consolidated financial statements and related notes for the nine months ended September 30, 2016,
as well as "Management's Discussion and Analysis of Financial Condition and Results of Operations" which are included within this registration statement.
F-53
Table of Contents
1. Basis of Pro Forma Presentation (Continued)
The
pro forma adjustments represent management's estimates based on information available as of the date of this filing and are subject to change as additional information becomes
available and additional analyses are performed. The unaudited pro forma condensed consolidated combined financial statements do not reflect possible adjustments related to restructuring or
integration activities that have yet to be determined or transaction or other costs following the business combination that are not expected to have a continuing impact. Further, one-time
transaction-related expenses anticipated to be incurred prior to, or concurrent with, closing the business combination and the other related Transactions are not included in the unaudited pro forma
condensed consolidated combined statements of operations. However, the impact of such transaction-related expenses is reflected in the unaudited pro forma condensed consolidated combined balance sheet
as a decrease to retained earnings and a decrease to cash.
Preliminary Estimated Purchase Price
The purchase consideration was preliminarily estimated as follows (in thousands):
|
|
|
|
|
|
|
At September 30,
2016
|
|
Preliminary Purchase Consideration:
|
|
|
|
|
Cash
|
|
$
|
1,186,744
|
|
Repayment of CRP long-term debt(1)
|
|
|
189,000
|
|
|
|
|
|
|
Total Purchase Price Consideration
|
|
|
1,375,744
|
|
|
|
|
|
|
Fair value of non-controlling interest(2)
|
|
|
184,710
|
|
|
|
|
|
|
Total Purchase Price Consideration and Fair Value of Non-Controlling Interest
|
|
$
|
1,560,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Represents
the additional contribution that is expected to be made by Silver Run to CRP in exchange for units representing common membership interest in CRP ("CRP
Common Units"), to repay CRP's outstanding indebtedness at the Closing (the "Additional Debt Repayment Contribution"). Prior to the consummation of the business combination, Silver Run and CRP intend
to amend CRP's credit agreement to permit the business combination and to increase the aggregate commitments thereunder and Silver Run expects to repay all of CRP's outstanding indebtedness at the
Closing. Pursuant to the Contribution Agreement, Silver Run will contribute to CRP cash in an amount equal to the net cash proceeds received by Silver Run pursuant to the Transactions, which amount
includes the contribution of the cash consideration and the Additional Debt Repayment Contribution, in exchange for a number of CRP Common Units equal to the number of shares of Class A Common
Stock outstanding following the completion of the Transactions. As a result, following the completion of the Transactions, Silver Run will own 163.5 million CRP Common Units, representing an
approximate 89% interest in CRP.
-
(2)
-
Represents
the fair value of the non-controlling interest (NCI) attributable to the Centennial Contributors. NCI is the portion of equity (net assets) in a
subsidiary not attributable, directly or indirectly to Silver Run. In a business combination the NCI is recognized at its acquisition date fair value in accordance with ASC 805. The fair value of the
NCI represents a 10.9% membership interest in CRP.
F-54
Table of Contents
1. Basis of Pro Forma Presentation (Continued)
Preliminary Estimated Purchase Price Allocation
The following table summarizes the allocation of the preliminary estimate of the purchase consideration to the assets acquired and liabilities
assumed (in thousands):
|
|
|
|
|
|
|
At September 30,
2016
|
|
Estimated Fair Value of Assets Acquired
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
410
|
|
Other current assets
|
|
|
11,222
|
|
Derivative instruments
|
|
|
1,863
|
|
Oil and Gas Properties(1):
|
|
|
|
|
Proved Properties
|
|
|
435,080
|
|
Unproved Properties
|
|
|
1,138,235
|
|
Other property, plant and equipment
|
|
|
1,703
|
|
Goodwill
|
|
|
|
|
|
|
|
|
|
Total Assets Acquired
|
|
|
1,588,513
|
|
Estimated Fair Value of Liabilities Assumed
|
|
|
|
|
Accounts payable and accrued expenses
|
|
|
23,579
|
|
Other current liabilities
|
|
|
243
|
|
Revolving credit facility
|
|
|
|
|
Derivative instruments
|
|
|
1,557
|
|
Asset retirement obligation
|
|
|
2,680
|
|
|
|
|
|
|
Total consideration and fair value
|
|
$
|
1,560,454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
The
fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and
therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to
a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates;(iii) future
operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by
management at the time of the valuation and are the most sensitive and may be subject to change. The reduction in the carrying cost of the proved properties was impacted by all of these factors, but
most notably, the assumptions with respect to future commodity prices as of the valuation date.
2. Pro Forma Adjustments and Assumptions
Pro Forma Adjustments to the Statement of Operations:
-
a.
-
Represents
the Silver Run historical statement of operations for the nine months ended September 30, 2016 and for the period from November 4, 2015 (date
of inception) to December 31, 2015, respectively.
-
b.
-
Represents
the CRP historical statement of operations for the nine months ended September 30, 2016 and year ended December 31, 2015.
-
c.
-
Represents
the adjustments to depreciation, depletion, and amortization based on the purchase price allocation.
F-55
Table of Contents
2. Pro Forma Adjustments and Assumptions (Continued)
-
d.
-
Represents
an adjustment to eliminate historical interest income of Silver Run associated with the funds that were previously held in the Trust Account, which will be
used to fund a portion of the cash consideration in the business combination.
-
e.
-
Represents
the following adjustments to interest expense:
-
(1)
-
an
adjustment to decrease interest expense related to the historical debt of CRP that is to be repaid as part of or just prior to the closing of the business
combination (the "Closing").
-
(2)
-
an
adjustment to increase interest expense by the undrawn commitment fee to be assessed on CRP's revolver in the event that it does not have any amounts drawn on
that revolver.
-
f.
-
Represents
an adjustment to record the tax expense based on total pro forma combined income (loss) before income taxes as if Silver Run had been subject to U.S.
federal income tax as a corporation using an estimated effective entity-level income tax rate of 32%, inclusive of all applicable U.S. federal, state and local income taxes.
-
g.
-
Represents
net income (loss) attributable to the non-controlling interest on total pro forma combined net income (loss).
-
h.
-
Pro
forma basic earnings per share was computed by dividing pro forma net income attributable to Silver Run by the weighted average shares of Class A Common
Stock, as if such shares were issued and outstanding as of January 1, 2015. Pro forma dilutive earnings per share was computed using the "if-converted" method to determine the potential
dilutive effect of its Class C Common Stock.
Pro Forma Adjustments to the Balance Sheet:
-
a.
-
Represents
the Silver Run unaudited historical balance sheet as of September 30, 2016.
-
b.
-
Represents
the CRP unaudited historical balance sheet as of September 30, 2016.
-
c.
-
Represents
the net adjustment to cash associated with Silver Run's payment of cash consideration in the business combination:
Pro
forma net adjustment to cash associated with purchase adjustments (in thousands):
|
|
|
|
|
|
|
At
September 30,
2016
|
|
Silver Run cash previously held in Trust Account
|
|
$
|
500,550
|
(1)
|
Cash consideration
|
|
|
(1,186,744)
|
(2)
|
Proceeds from Private Placements
|
|
|
1,010,050
|
(3)
|
Payment of transaction costs
|
|
|
(35,050)
|
(4)
|
Payment of CRP's long-term debt
|
|
|
(189,000)
|
(5)
|
|
|
|
|
|
Net adjustments to cash associated with purchase accounting
|
|
$
|
99,806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Represents
the adjustment related to the reclassification of the cash equivalents held in the Trust Account in the form of investments to cash and cash equivalents
to reflect the fact that these investments are available for use in connection with the business combination and the payment of a portion of the cash consideration.
-
(2)
-
Represents
the cash consideration portion of the total consideration that is expected to be paid to effectuate the business combination.
F-56
Table of Contents
2. Pro Forma Adjustments and Assumptions (Continued)
-
(3)
-
Represents
the issuance of 101,005,000 shares of Class A Common Stock at a price of $10.00 per share in the Private Placements, which will result in aggregate
proceeds of $1,010,050,000.
-
(4)
-
Reflects
the impact of estimated transaction costs of $35.1 million, including
-
(i)
-
$17.5 million
of deferred underwriting compensation attributable to Silver Run's IPO
-
(ii)
-
$6.0 million
of estimated fees and expenses attributable to the Private Placements and
-
(iii)
-
$11.6 million
of banking, legal and accounting fees that are not capitalizable as part of the transaction. In accordance with ASC 805, acquisition-related
transaction costs and related charges are not included as a component of consideration to be transferred but are required to be expensed as incurred. The unaudited pro forma condensed consolidated
combined balance sheet reflects these costs as a reduction of cash with a corresponding decrease in retained earnings. These costs are not included in the unaudited pro forma condensed consolidated
combined statement of operations as they are directly related to the business combination and will be nonrecurring.
-
(5)
-
Represents
the additional contribution that is expected to be made by Silver Run to CRP, in exchange for CRP Common Units to repay CRP's outstanding indebtedness at
the Closing.
-
d.
-
Represents
the adjustment related to the reclassification of the cash equivalents held in the Trust Account in the form of investments to cash and cash equivalents to
reflect the fact that these investments are available for use in connection with the business combination and the payment of a portion of the cash consideration.
-
e.
-
The
allocation of the estimated fair value of consideration transferred to the estimated fair value of CRP's oil and natural gas properties resulted in the following
purchase price allocation adjustments:
-
(1)
-
Represents
a $714.6 million increase in gross book basis of oil and gas properties to reflect them at fair value. The fair value measurements of oil and
natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas
properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and
natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices;
and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and
may be subject to change. The reduction in the carrying cost of the proved properties was impacted by all of these factors, but most notably, the assumptions with respect to future commodity prices as
of the valuation date.
-
(2)
-
Represents
the elimination of CRP's historical accumulated depletion and amortization ("DD&A") balances.
-
f.
-
Represents
an adjustment related to the repayment of CRP's long-term debt in conjunction with the consummation of the business combination. Prior to the consummation
of the business combination, Silver Run and CRP intend to amend CRP's credit agreement to permit the business combination and to increase the aggregate commitments thereunder. In either case, Silver
Run expects to repay all of CRP's outstanding indebtedness at the Closing. Debt issuance costs totaling $1.3 million were derecognized as part of the purchase consideration allocation.
F-57
Table of Contents
2. Pro Forma Adjustments and Assumptions (Continued)
-
g.
-
Represents
the payment of deferred underwriting costs of $17.5 million as well as an adjustment to retained earnings (accumulated deficit) of
$11.6 million of banking, legal and accounting fees that are not capitalizable as part of the transaction. The $11.6 million represents an estimate of transaction-related costs provided
by our various service providers. The $11.6 million of transaction-related costs are not included in the unaudited pro forma condensed consolidated combined statement of operations as they are
directly related to the business combination and will be nonrecurring.
-
h.
-
Represents
an adjustment to reflect that at the time of issuance, certain of Silver Run's Class A Common Stock was subject to a possible redemption and, as
such, an amount of $478.2 million was classified as redeemable equity in Silver Run's historical consolidated balance sheet as of September 30, 2016. Under the assumption that none of
the public stockholders elect to have Silver Run redeem these shares in connection with the business combination, the shares are no longer redeemable and have been reclassified from redeemable equity
to additional paid in capital and Class A Common Stock, $0.0001 par value.
-
i.
-
Represents
the fair value of the non-controlling interest (NCI) attributable to the Centennial Contributors. NCI is the portion of equity (net assets) in a subsidiary
not attributable, directly or indirectly, to Silver Run. In a business combination, the NCI is recognized at its acquisition-date fair value in accordance with ASC 805.
-
j.
-
Represents
an adjustment to eliminate CRP historical members' equity in conjunction with the completion of the business combination.
-
k.
-
Represents
the automatic conversion of Class B Common Stock to Class A Common Stock on a one-for-one basis in accordance with Silver Run's amended and
restated certificate of incorporation upon the Closing.
-
l.
-
Represents
the 20,000,000 shares of Class C Common Stock issued to the Centennial Contributors. Holders of Class C Common Stock will have the right to
vote on all matters properly submitted to a vote of the Silver Run stockholders, but will not be entitled to any dividends or any distributions in liquidation from Silver Run. The Centennial
Contributors will generally have the right to cause CRP to redeem all or a portion of their CRP Common Units in exchange for shares of Class A Common Stock, or at CRP's option, an equivalent
amount of cash. Upon redemption or exchange of CRP Common Units held by a Centennial Contributor, a corresponding number of shares of Class C Common Stock will be canceled.
-
m.
-
Reflects
an adjustment for the additional paid in capital associated with the issuance of 101,005,000 shares of Class A Common Stock at a price of $10.00 per
share in the Private Placements, which will result in an aggregate of $1,004,038,000, net of estimated fees and expenses, which is reflected as an adjustment to additional paid in capital. Also
includes an adjustment of $10,000 for the par value of the Class A Common Stock associated with the issuance of new shares attributable to the Private Placements.
F-58
Table of Contents
ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this prospectus, which are commonly used in the oil and natural gas
industry:
3-D seismic.
Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more
detailed and accurate
interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
Analogous reservoir.
Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir
conditions (depth,
temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation
of more limited data and estimation of recovery. When used to support proved reserves, an analogous reservoir refers to a reservoir that shares the following characteristics with the reservoir of
interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar
geological structure; and (iv) same drive mechanism. For a complete definition of analogous reservoir, refer to the SEC's Regulation S-X, Rule 4-10(a)(2).
Basin.
A large natural depression on the earth's surface in which sediments generally brought by water accumulate.
Bbl.
One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.
Bcf.
One billion cubic feet of natural gas.
Boe.
One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of
natural gas to one Bbl of
oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
Boe/d.
One Boe per day.
British thermal unit or Btu.
The quantity of heat required to raise the temperature of a one-pound mass of water from 58.5 to
59.5 degrees
Fahrenheit.
Completion.
Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the
appropriate
authority that the well has been abandoned.
Condensate.
A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that,
when produced, is in
the liquid phase at surface pressure and temperature.
Delineation.
The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production
characteristics.
Developed acreage.
The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development costs.
Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating,
gathering and storing the
oil and natural gas. For a complete definition of development costs refer to the SEC's Regulation S-X, Rule 4-10(a)(7).
Development project.
The means by which petroleum resources are brought to the status of economically producible. As examples,
the development of a
single reservoir or field, an incremental
A-1
Table of Contents
development
in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Development well.
A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic
horizon known to be
productive.
Differential.
An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in
the quality and/or
location of oil or natural gas.
Downspacing.
Additional wells drilled between known producing wells to better develop the reservoir.
Dry well.
A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of
such production exceed
production expenses and taxes.
Economically producible.
The term economically producible, as it relates to a resource, means a resource which generates revenue
that exceeds, or is
reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC's Regulation S-X, Rule 4-10(a)(10).
Estimated ultimate recovery or EUR.
The sum of reserves remaining as of a given date and cumulative production as of that date.
Exploration costs.
Costs incurred in identifying areas that may warrant examination and in examining specific areas that are
considered to have
prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. For a complete definition of exploration costs, refer
to the SEC's Regulation S-X, Rule 4-10(a)(12).
Exploratory well.
A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of
oil or natural gas in
another reservoir.
Field.
An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual
geological structural
feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field,
refer to the SEC's Regulation S-X, Rule 4-10(a)(15).
Formation.
A layer of rock which has distinct characteristics that differs from nearby rock.
Gross acres or gross wells.
The total acres or wells, as the case may be, in which a working interest is owned.
Held by production.
Acreage covered by a mineral lease that perpetuates a company's right to operate a property as long as the
property produces a
minimum paying quantity of oil or gas.
Horizontal drilling.
A drilling technique used in certain formations where a well is drilled vertically to a certain depth and
then drilled at a
right angle within a specified interval.
MBbl.
One thousand barrels of crude oil, condensate or NGLs.
MBoe.
One thousand Boe.
Mcf.
One thousand cubic feet of natural gas.
Mcf/d.
One Mcf per day.
MMBbl.
One million barrels of crude oil, condensate or NGLs.
A-2
Table of Contents
MMBoe.
One million Boe.
MMBtu.
One million British thermal units.
MMcf.
One million cubic feet of natural gas.
Net acres.
The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who
has 50% interest in 100
acres owns 50 net acres.
Net production.
Production that is owned less royalties and production due to others.
Net revenue interest.
A working interest owner's gross working interest in production less the royalty, overriding royalty,
production payment and
net profits interests.
NGLs.
Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural
gasoline.
NYMEX.
The New York Mercantile Exchange.
Offset operator.
Any entity that has an active lease on an adjoining property for oil, natural gas or NGLs purposes.
Operator.
The individual or company responsible for the development and/or production of an oil or natural gas well or lease.
Play.
A geographic area with hydrocarbon potential.
Present value of future net revenues or PV-10.
The estimated future gross revenue to be generated from the production of proved
reserves, net of
estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related
expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.
Production costs.
Costs incurred to operate and maintain wells and related equipment and facilities,
including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete
definition of production costs, refer to the SEC's Regulation S-X, Rule 4-10(a)(20).
Productive well.
A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from
the sale of the
production exceed production expenses and taxes.
Prospect.
A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary
economic analysis using
reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves.
Reserves that can be expected to be recovered through (i) existing wells with existing equipment
and operating
methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at
the time of the reserves estimate if the extraction is by means not involving a well.
Proved properties.
Properties with proved reserves.
Proved reserves.
Those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be
estimated with
reasonable certainty to be economically produciblefrom a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government
regulationsprior to the time at which contracts providing the right to
A-3
Table of Contents
operate
expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the
hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas
reserves, refer to the SEC's Regulation S-X, Rule 4-10(a)(22).
Proved undeveloped reserves or PUDs.
Proved reserves that are expected to be recovered from new wells on undrilled acreage or
from existing wells
where a relatively major expenditure is required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating
that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time.
Realized price.
The cash market price less all expected quality, transportation and demand adjustments.
Reasonable certainty.
A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC's
Regulation S-X,
Rule 4-10(a)(24).
Recompletion.
The completion for production of an existing wellbore in another formation from that which the well has been
previously completed
Reliable technology.
Reliable technology is a grouping of one or more technologies (including computational methods) that has
been field tested and
has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Reserves.
Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible,
as of a given date,
by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue
interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be
assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas
that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain
prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir.
A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas
that is confined by
impermeable rock or water barriers and is individual and separate from other reservoirs.
Resources.
Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources
may be estimated to
be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
Royalty.
An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from
the leased acreage
(or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner's
royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a
transfer to a subsequent owner.
A-4
Table of Contents
Service well.
A well drilled or completed for the purpose of supporting production in an existing field.
Spacing.
The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g.,
40-acre spacing,
and is often established by regulatory agencies.
Spot market price.
The cash market price without reduction for expected quality, transportation and demand adjustments.
Spud.
Commenced drilling operations on an identified location.
Standardized measure.
Discounted future net cash flows estimated by applying year-end prices to the estimated future production
of year-end proved
reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are
computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted
using a 10% annual discount rate.
Stratigraphic test well.
A drilling effort, geologically directed, to obtain information pertaining to a specific geologic
condition. Such wells
customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to
hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.
Success rate.
The percentage of wells drilled which produce hydrocarbons in commercial quantities.
Undeveloped acreage.
Lease acreage on which wells have not been drilled or completed to a point that would permit the production
of commercial
quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Unit.
The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for
development and operation
without regard to separate property interests. Also, the area covered by a unitization agreement.
Unproved properties.
Properties with no proved reserves.
Wellbore.
The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or
borehole.
Working interest.
The right granted to the lessee of a property to develop and produce and own natural gas or other minerals.
The working interest
owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
Workover.
Operations on a producing well to restore or increase production.
WTI.
West Texas Intermediate.
A-5
Table of Contents
PART IIINFORMATION NOT REQUIRED IN PROSPECTUS
Item 13. Other Expenses of Issuance and Distribution
The following table sets forth the costs and expenses payable by the registrant in connection with this offering. All of the amounts shown are
estimates except the Securities and Exchange Commission (the "SEC") registration fee.
|
|
|
|
|
SEC Registration Fee
|
|
$
|
133,396
|
|
Legal Fees and Expenses
|
|
|
75,000
|
|
Accounting Fees and Expenses
|
|
|
30,000
|
|
Other
|
|
|
10,000
|
|
|
|
|
|
|
Total
|
|
$
|
248,396
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We
will bear all costs, expenses and fees in connection with the registration of the shares of Class A Common Stock, including with regard to compliance with state securities or
"blue sky" laws. The selling stockholders, however, will bear all commissions and discounts, if any, attributable to their sale of shares of Class A Common Stock.
Item 14. Indemnification of Directors and Officers
Reference is made to Section 102(b)(7) of the Delaware General Corporation Law (the "DGCL"), which enables a corporation
in its original certificate of incorporation or an amendment thereto to eliminate or limit the personal liability of a director for violations of the director's fiduciary duty, except (1) for
any breach of the director's duty of loyalty to the corporation or its stockholders; (2) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation
of law; (3) pursuant to Section 174 of the DGCL, which provides for liability of directors for unlawful payments of dividends or unlawful stock purchases or redemptions or;
(4) for any transaction from which a director derived an improper personal benefit.
Reference
is also made to Section 145 of the DGCL, which provides that a corporation may indemnify any person, including an officer or director, who was or is, or is threatened to
be made, party to any threatened, pending or completed legal action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of such
corporation) by reason of the fact that such person is or was an officer, director, employee or agent of such corporation or is or was serving at the request of such corporation as a director,
officer, employee or agent of another corporation or enterprise. The indemnity may include expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably
incurred by such person in connection with such action, suit or proceeding, provided such officer, director, employee or agent acted in good faith and in a manner he reasonably believed to be in, or
not opposed to, the corporation's best interest and, for criminal proceedings, had no reasonable cause to believe that his conduct was unlawful. A Delaware corporation may indemnify any officer or
director in an action by or in the right of the corporation under the same conditions, except that no indemnification is permitted without judicial approval if the officer or director is adjudged to
be liable to the corporation. Where an officer or director is successful on the merits or otherwise in the defense of any action referred to above, the corporation must indemnify him against the
expenses that such officer or director actually and reasonably incurred in connection therewith.
In
accordance with Section 102(b)(7) of the DGCL, our second amended and restated certificate of incorporation (our "Charter") provides that no director shall be personally liable
to us or any of our stockholders for monetary damages resulting from breaches of its fiduciary duty as a director, except to the extent such limitation on or exemption from liability is not permitted
under the DGCL unless he or she violated their duty of loyalty to the Registrant or its stockholders, acted in bad faith, knowingly or
II-1
Table of Contents
intentionally
violated the law, authorized unlawful payments of dividends, unlawful stock purchases or unlawful redemptions, or derived improper personal benefit from their actions as directors. The
effect
of this provision of Charter is to eliminate our rights and those of our stockholders (through stockholders' derivative suits on our behalf) to recover monetary damages against a director for breach
of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by Section 102(b)(7) of the DGCL. However, this
provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director's duty of
care.
If
the DGCL is amended to authorize corporate action further eliminating or limiting the liability of directors, then, in accordance with our Charter, the liability of our directors to
us or our stockholders will be eliminated or limited to the fullest extent authorized by the DGCL, as so amended. Any repeal or amendment of provisions of our Charter limiting or eliminating the
liability of directors, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only,
except to the extent such amendment or change in law permits us to further limit or eliminate the liability of directors on a retroactive basis.
Our
Charter also provides that we will, to the fullest extent authorized or permitted by applicable law, indemnify our current and former officers and directors, as well as those persons
who, while directors or officers of our corporation, are or were serving as directors, officers, employees or agents of another entity, trust or other enterprise, including service with respect to an
employee benefit plan, in connection with any threatened, pending or completed proceeding, whether civil, criminal, administrative or investigative, against all expense, liability and loss (including,
without limitation, attorney's fees, judgments, fines, ERISA excise taxes and penalties and amounts paid in settlement) reasonably incurred or suffered by any such person in connection with any such
proceeding. Notwithstanding the foregoing, a person eligible for indemnification pursuant to our Charter will be indemnified by us in connection with a proceeding initiated by such person only if such
proceeding was authorized by our board of directors, except for proceedings to enforce rights to indemnification.
The
right to indemnification conferred by our Charter is a contract right that includes the right to be paid by us the expenses incurred in defending or otherwise participating in any
proceeding referenced above in advance of its final disposition, provided, however, that if the DGCL requires, an advancement of expenses incurred by our officer or director (solely in the capacity as
an officer or director of our corporation) will be made only upon delivery to us of an undertaking, by or on behalf of such officer or director, to repay all amounts so advanced if it is ultimately
determined that such person is not entitled to be indemnified for such expenses under our Charter or otherwise.
The
rights to indemnification and advancement of expenses will not be deemed exclusive of any other rights which any person covered by our Charter may have or hereafter acquire under
law, our Charter, our amended and restated bylaws (our "Bylaws"), an agreement, vote of stockholders or disinterested directors, or otherwise.
Any
repeal or amendment of provisions of our Charter affecting indemnification rights, whether by our stockholders or by changes in law, or the adoption of any other provisions
inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a
retroactive basis, and will not in any
way diminish or adversely affect any right or protection existing at the time of such repeal or amendment or adoption of such inconsistent provision with respect to any act or omission occurring prior
to such repeal or amendment or adoption of such inconsistent provision. Our Charter will also permit us, to the extent and in the manner authorized or permitted by law, to indemnify and to advance
expenses to persons other that those specifically covered by our Charter.
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Table of Contents
Our
Bylaws include the provisions relating to advancement of expenses and indemnification rights consistent with those set forth in our Charter. In addition, our Bylaws provide for a
right of indemnity to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full by us within a specified period of time. Our Bylaws also permit us to
purchase and maintain insurance, at our expense, to protect us and/or any director, officer, employee or agent of our corporation or another entity, trust or other enterprise against any expense,
liability or loss, whether or not we would have the power to indemnify such person against such expense, liability or loss under the DGCL.
Any
repeal or amendment of provisions of our Bylaws affecting indemnification rights, whether by our board of directors, stockholders or by changes in applicable law, or the adoption of
any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader
indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing thereunder with respect to any act or omission occurring prior to
such repeal or amendment or adoption of such inconsistent provision.
We
have entered into indemnity agreements with each of our officers and directors. These agreements will require us to indemnify these individuals to the fullest extent permitted under
Delaware law and to advance expenses incurred as a result of any proceeding against them to which they could be indemnified.
Item 15. Recent Sales of Unregistered Securities
Since our formation, we have sold the following securities without registration under the Securities Act:
Founder Shares
On November 6, 2015, our Sponsor purchased the founder shares for $25,000, or approximately $0.002 per share. On February 5, 2016,
our Sponsor transferred 40,000 founder shares to each of the Company's then independent directors at their original purchase price. Immediately prior to the pricing of our IPO, the Company effected a
stock dividend with respect to its Class B Common Stock of 1,437,500 shares, resulting in the initial stockholders holding an aggregate of 12,937,500 founder shares. On April 8,
2016, following the expiration of the underwriters' remaining over-allotment option, our Sponsor forfeited 437,500 founder shares, so that the remaining founder shares held by the initial stockholders
would represent 20% of the outstanding shares of common stock. The founder shares were issued in connection with our organization pursuant to the exemption from registration contained in
Section 4(a)(2) of the Securities Act.
Private Placement Warrants
Simultaneously with the consummation of our IPO, our Sponsor purchased from the Company an aggregate of 8,000,000 Private Placement Warrants at
a price of $1.50 per Private Placement Warrant (for a purchase price of $12,000,000). Each Private Placement Warrant entitles the holder thereof to purchase one share of Class A Common Stock at
an exercise price of $11.50 per share. The sale of the Private Placement Warrants was made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.
Business Combination Private Placements
On the October 11, 2016, we completed the Business Combination Private Placements for approximately $1.01 billion in aggregate
proceeds, which were used to fund a portion of the cash consideration in the Business Combination. The shares of Class A Common Stock sold in the Business
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Table of Contents
Combination
Private Placements were issued pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.
Class C Common Stock and Series A Preferred Stock Issuance
On the Business Combination Closing Date, the Company issued 20,00,000 shares of Class C Common Stock to the Centennial Contributors and
one share of Series A Preferred Stock to CRD in connection with the Business Combination. These issuances were made pursuant to the exemption from registration contained in
Section 4(a)(2) of the Securities Act.
CRP Common Unit Exchange
On the Business Combination Closing Date, following the closing of the Business Combination, the Company issued 844,079 shares of Class A
Common Stock to an accredited investor at the direction of members of CRP affiliated with such investor (the "CRP Members"), in exchange for 844,079 CRP Common Units held by such CRP Members. Upon the
exchange of the CRP Common Units, the Company canceled 844,079 shares of Class C Common Stock held by the CRP Members. The issuance of the shares of Class A Common Stock was made
pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.
Silverback Acquisition Private Placements
On December 28, 2016, we completed the Silverback Acquisition Private Placements for approximately $910 million in aggregate
proceeds, which were used to fund the cash consideration for the Silverback Acquisition. The shares of Class A Common Stock and Series B Preferred Stock sold in the Silverback
Acquisition Private Placements were issued pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.
Item 16. Exhibits
See the Exhibit Index, which follows the signature page and which is incorporated by reference herein.
Item 17. Undertakings
The undersigned registrant hereby undertakes:
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To file, during any period in which offers or sales are being made, a post-effective amendment to this registration
statement:
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To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;
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To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most
recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the
foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high
end of the estimated maximum offering range may be reflected in the form of prospectus filed with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent
no more than 20 percent change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement; and
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Table of Contents
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To include any material information with respect to the plan of distribution not previously disclosed in the registration
statement or any material change to such information in the registration statement.
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That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed a new
registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
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To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the
termination of the offering.
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That, for purposes of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to
Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on
Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness, provided, however, that no statement made in a
registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus
that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration
statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.
Insofar
as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the
foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore,
unenforceable. In the event
that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the
opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as
expressed in the Securities Act and will be governed by the final adjudication of such issue.
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Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant certifies that it has reasonable grounds to believe that
it meets all of the requirements for filing on Form S-1 and has duly caused this Registration Statement on Form S-1 to be signed on its behalf by the undersigned, thereunto duly
authorized, in the City of Denver, State of Colorado on January 19, 2017.
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CENTENNIAL RESOURCE DEVELOPMENT, INC.
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By:
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/s/ GEORGE S. GLYPHIS
George S. Glyphis
Chief Financial Officer, Treasurer and Assistant Secretary
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POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints George S. Glyphis and Davis O'Connor, and each of them, with full power to
act without the other, as attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign
any and all amendments (including post-effective amendments) to this registration statement, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the
Commission, granting unto each said attorney-in-fact and agent full power and authority to do and perform each and every act in person, hereby ratifying and confirming all that said attorneys-in-fact
and agents or either of them or their or his substitute or substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant
to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.
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SIGNATURE
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TITLE
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DATE
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/s/ MARK G. PAPA
Mark G. Papa
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Chairman, President and Chief Executive Officer (Principal Executive Officer)
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January 19, 2017
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/s/ GEORGE S. GLYPHIS
George S. Glyphis
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Chief Financial Officer, Treasurer and Assistant Secretary (Principal Financial Officer)
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January 19, 2017
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/s/ JAMIE L. WHEAT
Jamie L. Wheat
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Vice President and Chief Accounting Officer (Principal Accounting Officer)
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January 19, 2017
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/s/ MAIRE A. BALDWIN
Maire A. Baldwin
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Director
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January 19, 2017
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/s/ KARL E. BANDTEL
Karl E. Bandtel
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Director
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January 19, 2017
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Table of Contents
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SIGNATURE
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TITLE
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DATE
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/s/ PIERRE F. LAPEYRE, JR.
Pierre F. Lapeyre, Jr.
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Director
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January 19, 2017
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/s/ DAVID M. LEUSCHEN
David M. Leuschen
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Director
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January 19, 2017
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/s/ JEFFREY H. TEPPER
Jeffrey H. Tepper
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Director
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January 19, 2017
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/s/ ROBERT M. TICHIO
Robert M. Tichio
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Director
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January 19, 2017
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/s/ TONY R. WEBER
Tony R. Weber
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Director
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January 19, 2017
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Table of Contents
EXHIBIT INDEX
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Exhibit
Number
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Description of Exhibits
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2.1
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Contribution Agreement, dated as of July 6, 2016, as amended by Amendment No. 1 thereto, dated as of July 29, 2016, among Centennial Resource Development, LLC, NGP Centennial Follow-On LLC, Celero
Energy Company, LP, Centennial Resource Production, LLC and New Centennial, LLC (incorporated by reference to Annex A of the Registrant's definitive proxy statement filed with the SEC on September 23, 2016).
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2.2
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Purchase and Sale Agreement, dated as of November 21, 2016, by and among SB RS Holdings, LLC, Silverback Exploration, LLC and Silverback Operating, LLC.
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3.1
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Second Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed with the SEC on October 11, 2016).
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3.2
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Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed with the SEC on October 7, 2016).
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3.3
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Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of October 11, 2016 (incorporated by reference to Exhibit 10.5 to the Registrant's Current
Report on Form 8-K filed with the SEC on October 11, 2016).
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3.4
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Amendment No. 1 to Fifth Amended and Restated Limited Liability Company Agreement of Centennial Resource Production, LLC dated as of December 28, 2016 (incorporated by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed with the SEC on December 28, 2016).
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4.1
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Specimen Class A Common Stock Certificate (incorporated by reference to Exhibit 4.2 to the Registrant's Registration Statement on Form S-1 (Registration No. 333-209140) filed with the SEC on
January 27, 2016).
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4.2
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Specimen Warrant Certificate (incorporated by reference to Exhibit 4.3 to the Registrant's Registration Statement on Form S-1 (Registration No. 333-209140) filed with the SEC on January 27,
2016).
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4.3
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Warrant Agreement between Continental Stock Transfer & Trust Company and the Registrant (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed with the SEC on
February 29, 2016).
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4.4
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Certificate of Designation of Series A Preferred Stock (incorporated by reference to Exhibit 3.2 to the Registrant's Current Report on Form 8-K filed with the SEC on October 11, 2016).
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4.5
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Certificate of Designation of Series B Preferred Stock (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed with the SEC on December 29, 2016).
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5.1
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Opinion of Latham & Watkins LLP.
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10.1
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Amended and Restated Registration Rights Agreement among the Registrant and certain stockholders (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed with the SEC on
October 11, 2016).
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10.2
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Sponsor Warrants Purchase Agreement, dated February 23, 2016, between the Registrant and Silver Run Sponsor, LLC (incorporated by reference to Exhibit 10.5 to the Registrant's Current Report on
Form 8-K filed with the SEC on February 29, 2016).
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Table of Contents
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Exhibit
Number
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Description of Exhibits
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10.3
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Form of Indemnity Agreement (incorporated by reference to Exhibit 10.7 to the Registrant's Registration Statement on Form S-1 (Registration No. 333-209140) filed with the SEC on January 27,
2016).
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10.4
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Amended and Restated Credit Agreement, dated as of October 15, 2014, among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-1 of Centennial Resource Development, Inc. (Registration No. 333-212185) filed with the SEC on June 22, 2016).
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10.5
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First Amendment to Amended and Restated Credit Agreement, dated as of May 6, 2015, among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders
and guarantors party thereto (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-1 of Centennial Resource Development, Inc. (Registration No. 333-212185) filed with the SEC on June 22,
2016).
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10.6
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Second Amendment to Amended and Restated Credit Agreement, dated as of October 11, 2016, by and among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and
the lenders and guarantors party thereto (incorporated by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed with the SEC on October 11, 2016).
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10.7
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Third Amendment to Amended and Restated Credit Agreement, dated as of December 28, 2016, by and among Centennial Resource Production, LLC, as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, and
the lenders and guarantors party thereto (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed with the SEC on January 4, 2017).
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10.8
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Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Registrant's Current Report on Form 8-K filed with the Commission on October 11,
2016).
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10.9
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Form of Stock Option Agreement under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Registrant's Current Report on Form 8-K filed
with the Commission on October 11, 2016).
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10.10
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Form of Restricted Stock Unit Agreement under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on
Form 8-K filed with the Commission on October 11, 2016).
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10.11
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Form of Restricted Stock Agreement under the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (incorporated by reference to Exhibit 10.9 to the Registrant's Current Report on Form 8-K
filed with the Commission on October 11, 2016).
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21.1
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Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 to the Registration Statement on Form S-1 of Centennial Resource Development, Inc. (Registration No. 333-214355) filed with the
SEC on October 31, 2016).
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23.1
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Consent of KPMG LLP.
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23.2
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Consent of Netherland, Sewell & Associates, Inc.
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23.3
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Consent of Latham & Watkins LLP (included in Exhibit 5.1).
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24.1
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Power of Attorney (included on signature pages of this Registration Statement).
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Table of Contents
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Exhibit
Number
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Description of Exhibits
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99.1
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Netherland, Sewell & Associates, Inc., Summary of Reserves at December 31, 2014 (incorporated by reference to Exhibit 99.1 to the Registration Statement on Form S-1 of Centennial Resource
Development, Inc. (Registration No. 333-214355) filed with the SEC on October 31, 2016).
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99.2
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Netherland, Sewell & Associates, Inc., Summary of Reserves at December 31, 2015 (incorporated by reference to Exhibit 99.2 to the Registration Statement on Form S-1 of Centennial Resource
Development, Inc. (Registration No. 333-214355) filed with the SEC on October 31, 2016).
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#101.INS
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XBRL Instance Document.
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#101.SCH
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XBRL Taxonomy Extension Schema Document.
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#101.CAL
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XBRL Taxonomy Extension Calculation Linkbase Document.
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#101.DEF
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XBRL Taxonomy Extension Definition Linkbase Document.
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#101.LAB
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XBRL Taxonomy Extension Label Linkbase Document.
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#101.PRE
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XBRL Taxonomy Extension Presentation Linkbase Document.
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#
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Pursuant
to Rule 406T of Regulation S-T, this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of
Sections 11 or 12 of the Securities Act, is deemed not filed for purposes of Section 18 of the Exchange Act and otherwise is not subject to liability under these sections.
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Filed
herewith.
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