ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated and combined financial statements and related notes in “Part II, Item 8. Financial Statements and Supplementary Data.” The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Please see “Cautionary Statement Concerning Forward-Looking Statements” and “Part I, Item 1A. Risk Factors” in this Report.
Overview
We are an independent oil and natural gas company focused on the development 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.
We have no direct operations and no significant assets other than our current 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.
Silver Run Business Combination
Centennial Resource Development, Inc. (the “Company,” “Centennial,” “we,” “us,” or “our”) was originally incorporated in Delaware on November 4, 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.
On February 29, 2016, we consummated our initial public offering of Units each consisting of one share of Class A Common Stock and one-third of one Public Warrant. On October 11, 2016, we consummated the acquisition of approximately
89%
of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company (“CRP” and such acquisition, the “Business Combination”).
The application of acquisition accounting for the Business Combination significantly affected certain assets, liabilities, and expenses. As a result, financial information as of December 31, 2016 and in the period October 11, 2016 through December 31, 2016 is not necessarily comparable to CRP’s predecessor financial information.
Presentation of Financial and Operating Data
As a result of the Business Combination, we are the acquirer for accounting purposes, and CRP is the acquiree and accounting Predecessor. Our financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. We are the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination on October 11, 2016.
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.
Recent Developments
Silverback Acquisition
On December 28, 2016, we completed the acquisition (the “Silverback 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 $855.0 million, subject to customary purchase price adjustments. The assets acquired from Silverback include 31 operated producing horizontal wells and approximately
35,500
net acres that directly offset our existing acreage in Reeves County, Texas. We operate approximately
90%
of, and have an approximate
90%
working interest in this acreage. Of the net acres acquired,
1,250
net acres are subject to consents to assign, which are expected to be
assigned in the first quarter of 2017. The Wolfcamp A and B are producing horizons on this acreage and we believe that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale formations.
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 $910.0 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 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, refer to
Note 7—Shareholders' and Owners' Equity
to the Consolidated and Combined Financial Statements in Part II, Item 8. Financial Statements and Supplementary Data in this annual report.
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.
Redemption of Public Warrants
On March 1, 2017, the Company delivered a notice of redemption of the Public Warrants, announcing its intention to redeem any unexercised and outstanding Public Warrants on March 31, 2017 for
$0.01
per Public Warrant. As permitted under the warrant agreement that provides the terms of the Public Warrants, the notice of redemption requires all holders exercising their Public Warrants prior to March 31, 2017 to do so on a “cashless basis” and surrender their Public Warrants for a number of shares of Class A Common Stock equal to the product of the quotient equal to (i) the difference between
$11.50
and
$18.44
(the average last sale price of the Class A Common Stock for the ten trading days ending on February 24, 2017) divided by (ii)
$18.44
, or approximately
0.376
, multiplied by the number of Public Warrants held by such holder, rounded down to the nearest whole share. Assuming all warrants are exercised by holders, Centennial will issue approximately
6.27 million
shares of Class A Common Stock to the Public Warrant holders, resulting in a share count of approximately
253 million
shares outstanding, which includes Class A Common Stock shares, the shares of Series B Preferred Stock held by Riverstone (assuming conversion to Class A Common Stock on a 250-to-one basis), and the shares of Class C Common Stock held by the Centennial Contributors. The Private Placement Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees.
Market Conditions
The oil and gas industry is cyclical and commodity prices can be volatile. In the second half of 2014, oil prices began a rapid and significant decline as global and domestic supply began to outpace demand. During 2015 and 2016, global and domestic oil supply continued to outpace demand resulting in further deterioration in realized oil prices. In 2016, oil prices were volatile, and it is likely that oil prices will continue to fluctuate due to the ongoing global supply and demand imbalance, high inventories and geopolitical factors.
Our revenue, profitability and future growth are highly dependent on the prices we receives 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%
to
$42.43
per barrel, and our realized oil price for
2016
further decreased to
$39.91
per barrel. Similarly, our realized natural gas price for 2015 dropped
43%
to
$2.60
per Mcf and our realized price for NGLs declined
52%
to
$14.66
per barrel. For
2016
, our realized price for natural gas was
$2.52
per Mcf and our realized price for NGLs was
$15.01
per barrel. Lower oil, natural gas and NGL prices may not only 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 our 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.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
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•
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realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts on its oil and natural gas production;
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•
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lease operating expenses; and
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(1)
|
Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States (“GAAP”). Please see "Non-GAAP Financial Measure" below for a reconciliation.
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Sources of our Revenues
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. For the period from
October 11, 2016, through December 31, 2016 (Successor)
, oil sales, natural gas sales and NGL sales contributed
82%
,
12%
, and
7%
, respectively, of our total revenues. For the period from
January 1, 2016, through October 10, 2016 (Predecessor)
, oil sales, natural gas sales and NGL sales contributed
87%
,
9%
and
5%
, respectively of our total revenues. Our oil, natural gas and NGL revenues do not include the effects of derivatives for either period.
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
$0.5 million
and a
$1.6 million
change in oil revenues for the periods from
October 11, 2016, through December 31, 2016 (Successor)
and
January 1, 2016, through October 10, 2016 (Predecessor)
, respectively. A $0.10 per Mcf change in our realized natural gas price would have resulted in a
$0.1 million
and a
$0.3 million
change in our natural gas revenues for the periods from
October 11, 2016, through December 31, 2016 (Successor)
and
January 1, 2016, through October 10, 2016 (Predecessor)
, respectively. A $1.00 per barrel change in our realized NGL prices would have resulted in a
$0.1 million
and a
$0.3 million
change in NGL revenues for the periods from
October 11, 2016, through December 31, 2016 (Successor)
and
January 1, 2016, through October 10, 2016 (Predecessor)
, respectively.
The following table presents our average realized commodity prices, as well as the effects of derivative settlements.
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Successor
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Predecessor
|
|
October 11, 2016
through
December 31, 2016
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January 1, 2016
through
October 10, 2016
|
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Year Ended December 31,
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|
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2015
|
|
2014
|
Crude Oil (per Bbl):
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|
|
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|
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Average NYMEX price
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$
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49.21
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|
|
|
$
|
41.75
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|
|
$
|
48.76
|
|
|
$
|
92.86
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|
Average realized price, before the effects of derivative settlements
|
46.49
|
|
|
|
37.74
|
|
|
42.43
|
|
|
80.50
|
|
Effects of derivative settlements
|
2.02
|
|
|
|
10.49
|
|
|
19.18
|
|
|
3.23
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|
Natural Gas:
|
|
|
|
|
|
|
|
|
Average NYMEX price (per MMBtu)
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$
|
3.18
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|
|
|
$
|
2.37
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|
|
$
|
2.63
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|
|
$
|
4.26
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|
Average realized price, before the effects of derivative settlements (per Mcf)
|
3.10
|
|
|
|
2.27
|
|
|
2.60
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|
|
4.58
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|
Effects of derivative settlements (per Mcf)
|
—
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|
|
|
—
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|
|
0.43
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|
|
—
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NGLs (per Bbl):
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|
|
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|
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Average realized price
|
$
|
20.36
|
|
|
|
$
|
12.98
|
|
|
$
|
14.66
|
|
|
$
|
30.64
|
|
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.
Operating Costs and Expenses
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
December 31, 2016
(Successor)
and
December 31, 2015
(Predecessor)
, CRP owned interests in
208
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 makes 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 trends 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 Estimates—Successful 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 of their carrying value may have occurred. Please read “—Critical Accounting Policies and Estimates—Impairment 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 to development operations, audit and other fees for professional services and legal compliance.
Interest Expense.
We finance a portion of our working capital requirements and capital expenditures with borrowings under our revolving credit facility. 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 our revolving credit facility in interest expense.
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 consolidated and combined statements of operations. Cash flows from derivatives are reported as cash flows from operating activities.
A discussion of changes in operating costs and expenses is included in Results of Operations, below.
Results of Operations
For the Periods From October 11, 2016, Through December 31, 2016 (Successor) and January 1, 2016, Through October 10, 2016 (Predecessor) Compared to Year Ended
December 31, 2015
(Predecessor)
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 respective average prices and production volumes:
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Successor
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|
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Predecessor
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Combined
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|
Predecessor
|
|
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|
|
|
October 11, 2016
through
December 31, 2016
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|
January 1, 2016
through
October 10, 2016
|
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Year Ended December 31, 2016
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|
Year Ended December 31, 2015
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Increase/(Decrease)
|
|
|
|
|
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$
|
|
%
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
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Oil sales
|
$
|
24,313
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|
|
|
$
|
59,787
|
|
|
$
|
84,100
|
|
|
$
|
77,643
|
|
|
$
|
6,457
|
|
|
8
|
%
|
Natural gas sales
|
3,449
|
|
|
|
6,045
|
|
|
9,494
|
|
|
7,965
|
|
|
1,529
|
|
|
19
|
%
|
NGL sales
|
1,955
|
|
|
|
3,284
|
|
|
5,239
|
|
|
4,852
|
|
|
387
|
|
|
8
|
%
|
Total Revenues
|
$
|
29,717
|
|
|
|
$
|
69,116
|
|
|
$
|
98,833
|
|
|
$
|
90,460
|
|
|
$
|
8,373
|
|
|
9
|
%
|
Average sales price (1):
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|
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Oil (per Bbl)
|
$
|
46.49
|
|
|
|
$
|
37.74
|
|
|
$
|
39.91
|
|
|
$
|
42.43
|
|
|
$
|
(2.52
|
)
|
|
(6
|
)%
|
Natural gas (per Mcf)
|
3.10
|
|
|
|
2.27
|
|
|
2.52
|
|
|
2.60
|
|
|
(0.08
|
)
|
|
(3
|
)%
|
NGL (per Bbl)
|
20.36
|
|
|
|
12.98
|
|
|
15.01
|
|
|
14.66
|
|
|
0.35
|
|
|
2
|
%
|
Total (per Boe)
|
$
|
36.92
|
|
|
|
$
|
30.31
|
|
|
$
|
32.04
|
|
|
$
|
33.87
|
|
|
$
|
(1.83
|
)
|
|
(5
|
)%
|
Production:
|
|
|
|
|
|
|
|
|
|
|
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|
Oil (MBbls)
|
523
|
|
|
|
1,584
|
|
|
2,107
|
|
|
1,830
|
|
|
277
|
|
|
15
|
%
|
Natural gas (MMcf)
|
1,113
|
|
|
|
2,660
|
|
|
3,773
|
|
|
3,058
|
|
|
715
|
|
|
23
|
%
|
NGLs (MBbls)
|
96
|
|
|
|
253
|
|
|
349
|
|
|
331
|
|
|
18
|
|
|
5
|
%
|
Total (MBoe)(2)
|
805
|
|
|
|
2,280
|
|
|
3,085
|
|
|
2,671
|
|
|
414
|
|
|
15
|
%
|
Average daily production volume:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls/d)
|
6,378
|
|
|
|
5,577
|
|
|
5,757
|
|
|
5,014
|
|
|
743
|
|
|
15
|
%
|
Natural gas (Mcf/d)
|
13,573
|
|
|
|
9,366
|
|
|
10,309
|
|
|
8,378
|
|
|
1,931
|
|
|
23
|
%
|
NGLs (Bbls/d)
|
1,171
|
|
|
|
891
|
|
|
954
|
|
|
907
|
|
|
47
|
|
|
5
|
%
|
Total (Boe/d)(2)
|
9,811
|
|
|
|
8,029
|
|
|
8,429
|
|
|
7,317
|
|
|
1,112
|
|
|
15
|
%
|
|
|
(1)
|
Average prices shown in the table reflect prices before the effects of our realized commodity derivative transactions.
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(2)
|
Total may not sum or recalculate due to rounding.
|
As reflected in the table above, our combined revenues for
2016
were
9%
, or
$8.4 million
,
higher
than total revenues for
2015
. The
increase
was primarily due to a
15%
increase in production sold in
2016
, which was partially offset by a
5%
decrease in average sales price per Boe, compared to the prior year.
Combined oil sales
increased
8%
, or
$6.5 million
, for
2016
compared to the prior year period primarily due to a
15%
increase in oil volumes sold, partially offset by an
6%
decrease in the average sales price for oil. Combined natural gas sales
increased
19%
, or
$1.5 million
, for
2016
compared to the prior year period primarily due to a
23%
increase in natural gas volumes sold, partially offset by a
3%
decrease in the average sales price for natural gas. Combined NGL sales
increased
8%
, or
$0.4 million
, for
2016
compared to the prior year period primarily due to a
5%
increase
in the NGL volumes sold.
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 sets forth selected operating data for the periods indicated:
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|
|
Successor
|
|
|
Predecessor
|
|
Combined
|
|
Predecessor
|
|
|
|
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
|
Increase/(Decrease)
|
|
|
|
|
|
$
|
|
%
|
Operating Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
$
|
3,541
|
|
|
|
$
|
11,036
|
|
|
$
|
14,577
|
|
|
$
|
21,173
|
|
|
$
|
(6,596
|
)
|
|
(31
|
)%
|
Severance and ad valorem taxes
|
1,636
|
|
|
|
3,696
|
|
|
5,332
|
|
|
5,021
|
|
|
311
|
|
|
6
|
%
|
Transportation, processing, gathering and other operating expense
|
2,187
|
|
|
|
4,583
|
|
|
6,770
|
|
|
5,732
|
|
|
1,038
|
|
|
18
|
%
|
Production costs per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
$
|
4.40
|
|
|
|
$
|
4.84
|
|
|
$
|
4.73
|
|
|
$
|
7.93
|
|
|
$
|
(3.20
|
)
|
|
(40
|
)%
|
Severance and ad valorem taxes
|
2.03
|
|
|
|
1.62
|
|
|
1.73
|
|
|
1.88
|
|
|
(0.15
|
)
|
|
(8
|
)%
|
Transportation, processing, gathering and other operating expense
|
2.72
|
|
|
|
2.01
|
|
|
2.19
|
|
|
2.15
|
|
|
0.04
|
|
|
2
|
%
|
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. Combined LOE
decreased
31%
, or
$6.6 million
, in
2016
compared to
2015
, due in part to service providers lowering costs in light of the weak commodity price environment. Additionally, the number of wells placed on production in
2016
decreased 29% compared to
2015
. Workover expense decreased $2.0 million and we converted several rental units to permanent pumping units decreasing the amounts of rental expense by approximately $1.6 million in
2016
compared to the prior year period. Lastly, we decreased the use of contract labor and expenses related to repairs and maintenance by $1.2 million and $1.9 million, respectively, in
2016
compared to
2015
.
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. Combined severance and ad valorem taxes
increased
6%
, or
$0.3 million
, in
2016
compared to
2015
, primarily due to higher sales volumes, partially offset by lower realized commodity prices. Combined severance and ad valorem taxes as a percentage of our revenue were
5.4%
for
2016
compared to
5.6%
for the prior year period.
Transportation, Processing, Gathering and Other Operating Expenses.
Combined transportation, processing, gathering and other operating expenses in
2016
increased
18%
, or
$1.0 million
, compared to
2015
, primarily due to an increase in natural gas production of
23%
year over year, partially offset by lower realized commodity prices
Depreciation, Depletion, Amortization and Accretion of Asset Retirement Obligations.
The following table summarizes our DD&A for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2015
|
(in thousands)
|
|
|
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
$
|
14,877
|
|
|
|
$
|
62,964
|
|
|
$
|
90,084
|
|
Depreciation, depletion, amortization and accretion of asset retirement obligations per Boe
|
18.48
|
|
|
|
27.62
|
|
|
33.73
|
|
Our DD&A rate can fluctuate as a result of impairments, dispositions, finding and development costs and proved reserve volumes. For the period from
October 11, 2016, through December 31, 2016 (Successor)
, DD&A expense for the period was
$14.9 million
or
$18.48
per Boe.
For the period from
January 1, 2016, through October 10, 2016 (Predecessor)
, DD&A expense was
$63.0 million
or
$27.62
per Boe. In
2015
, DD&A expense was
$90.1 million
or
$33.73
per Boe. The decrease in DD&A rate is primarily due to lower development costs and reserve additions.
Abandonment Expense and Impairment of Unproved Properties.
The following table summarizes our abandonment expense and impairment of unproved properties for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2015
|
(in thousands)
|
|
|
|
Abandonment expense and impairment of unproved properties
|
$
|
—
|
|
|
|
$
|
2,545
|
|
|
$
|
7,619
|
|
For the period from
October 11, 2016, through December 31, 2016 (Successor)
, we did not have any abandonment expense and impairment of unproved property. For the period from
January 1, 2016, through October 10, 2016 (Predecessor)
and in
2015
, we recorded
$2.5 million
and
$7.6 million
, respectively, of leasehold expirations attributable to leases that expired during the period or that we expect to expire in the future.
Exploration.
The following table summarizes our exploration expense for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2015
|
|
|
|
|
Exploration
|
$
|
844
|
|
|
|
$
|
—
|
|
|
$
|
84
|
|
For the period from
October 11, 2016, through December 31, 2016 (Successor)
, we recorded
$0.8 million
of exploration expense related to seismic data that will be used for exploration. For the period from
January 1, 2016, through October 10, 2016 (Predecessor)
, we did not incur any exploration expense. For 2015, we recorded
$0.1 million
of exploration expense for logging analyses.
Contract Termination and Rig Stacking.
The following table summarizes our contract termination and rig stacking expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2015
|
(in thousands)
|
|
|
|
Contract termination and rig stacking
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
2,387
|
|
For the periods from
October 11, 2016, through December 31, 2016 (Successor)
and
January 1, 2016, through October 10, 2016 (Predecessor)
, we did not incur any drilling and rig termination fees, as compared to
$2.4 million
in
2015
. In light of the low commodity price environment, we curtailed drilling activity beginning in the first quarter of 2015, and as a result, we incurred drilling and rig termination fees of
$2.4 million
in
2015
.
General and Administrative Expenses.
The following table summarizes our G&A expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2015
|
(in thousands)
|
|
|
|
General and administrative expenses
|
$
|
13,715
|
|
|
|
$
|
25,581
|
|
|
$
|
14,206
|
|
General and administrative expenses per Boe
|
17.04
|
|
|
|
11.22
|
|
|
5.32
|
|
For the period from
October 11, 2016, through December 31, 2016 (Successor)
, G&A expenses were
$13.7 million
or
$17.04
per Boe. G&A expenses for the Successor period included
$4.1 million
of transactional expenses primarily attributable to the consummation of the Business Combination. Additionally, G&A expenses for the Successor period included $1.0 million of non-cash charges resulting from the issuance of restricted stock and stock option awards. We have recognized non-cash equity based compensation cost as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2015
|
(in thousands)
|
|
|
|
Restricted stock awards
|
$
|
405
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Stock option awards
|
928
|
|
|
|
—
|
|
|
—
|
|
Total equity based compensation expense
|
$
|
1,333
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Expense associated with stock compensation will fluctuate based on the grant-date market value of the award and the number of shares granted. Refer to
Note 8—Equity Based Compensation
to the Consolidated and Combined Financial Statements in Part II, Item 8. Financial Statements and Supplementary Data in this annual report for further discussion regarding our equity based compensation.
For the period from
January 1, 2016, through October 10, 2016 (Predecessor)
, G&A expenses were
$25.6 million
or
$11.22
per Boe. In
2015
, G&A expenses were
$14.2 million
or
$5.32
per Boe. G&A expenses
increased
80%
, or
$11.4 million
, between these two periods primarily due to
$15.8 million
of transaction expenses incurred in connection with the Business Combination during the period from January 1, 2016, through October 10, 2016.
Incentive Compensation.
The following table summarizes our incentive compensation for the period indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2015
|
|
|
|
|
Incentive unit compensation
|
$
|
—
|
|
|
|
$
|
165,394
|
|
|
$
|
—
|
|
For the period from
January 1, 2016, through October 10, 2016 (Predecessor)
, we recorded non-cash incentive compensation of
$165.4 million
related to the consummation of the Business Combination.
Gain on Sale of Oil and Natural Gas Properties.
The following table summarizes our gain on sale of oil and natural gas properties for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2015
|
|
|
|
|
Gain on sale of oil and natural gas properties
|
$
|
24
|
|
|
|
$
|
11
|
|
|
$
|
2,439
|
|
For the periods from
October 11, 2016, through December 31, 2016 (Successor)
and
January 1, 2016, through October 10, 2016 (Predecessor)
we recorded immaterial net gains on the sale of oil and natural gas properties. In
2015
(Predecessor)
, we recorded a net
gain
of
$2.4 million
, which was primarily attributable to a gain associated with the sale of non-core unproved property to an unrelated third party.
Other Income and Expenses.
The following table summarizes our other income and expenses for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2015
|
|
|
|
|
Other (expense) income (in thousands):
|
|
|
|
|
|
|
Interest expense
|
$
|
(378
|
)
|
|
|
$
|
(5,626
|
)
|
|
$
|
(6,266
|
)
|
Loss on derivative instruments
|
(1,548
|
)
|
|
|
(6,838
|
)
|
|
20,756
|
|
Other income
|
—
|
|
|
|
6
|
|
|
20
|
|
Total other expense
|
$
|
(1,926
|
)
|
|
|
$
|
(12,458
|
)
|
|
$
|
14,510
|
|
Income tax benefit
|
$
|
—
|
|
|
|
$
|
406
|
|
|
$
|
572
|
|
Interest Expense.
For the period from
October 11, 2016, through December 31, 2016 (Successor)
we incurred interest expense of
$0.4 million
primarily related to the commitment fee we pay for unused amounts on our revolving credit facility. For the period from
January 1, 2016, through October 10, 2016 (Predecessor)
, we incurred interest expense of
$5.6 million
related to borrowings under our revolving credit facility and interest on our term loan. In
2015
(Predecessor)
, we incurred interest expense of
$6.3 million
related to borrowings under our revolving credit facility and interest on our term loan.
Gain on Derivative Instruments.
For the periods from
October 11, 2016, through December 31, 2016 (Successor)
and
January 1, 2016, through October 10, 2016 (Predecessor)
, we recognized derivatives losses of
$1.5 million
and
$6.8 million
, respectively. In
2015
(Predecessor)
, we recognized a
$20.8 million
derivative
gain
. Net losses and gains on our derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.
Year Ended
December 31, 2015
(Predecessor) Compared to Year Ended
December 31, 2014
(Predecessor)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
|
Year Ended December 31,
|
|
Increase/(Decrease)
|
|
2015
|
|
2014
|
|
$
|
|
%
|
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 realized prices (excluding effect of hedges):
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
42.43
|
|
|
$
|
80.50
|
|
|
$
|
(38.07
|
)
|
|
(47
|
)%
|
Natural gas (per Mcf)
|
2.60
|
|
|
4.58
|
|
|
(1.98
|
)
|
|
(43
|
)%
|
NGL (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 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
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.
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
|
Year Ended December 31,
|
|
Increase/(Decrease)
|
|
2015
|
|
2014
|
|
$
|
|
%
|
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 expense
|
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 before gain on oil and natural gas properties
|
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 oil and natural gas properties
|
$
|
143,867
|
|
|
$
|
152,262
|
|
|
$
|
(8,395
|
)
|
|
(6
|
)%
|
Production 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 expense
|
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 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
|
|
|
Year Ended December 31,
|
|
Increase/(Decrease)
|
|
2015
|
|
2014
|
|
$
|
|
%
|
Other (expense) income (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.
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.
Liquidity and Capital Resources
Overview
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.
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.
Based upon current oil and natural gas price expectations for 2017, we believe that our cash on hand, cash flow from operations and 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 plan to monitor crude oil and natural gas markets and macroeconomic events impacting their prices. Under this strategy we will opportunistically enter into hedging arrangements to reduce our exposure to commodity prices and the resulting impact of this volatility on our cash flow from operations.
Capital Budget
The following table summarizes our fiscal year 2017 capital expenditure guidance range:
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Capital expenditure program
|
$
|
500
|
|
—
|
$
|
585
|
|
Drilling and completion capital expenditure
|
440
|
|
—
|
500
|
|
Land
|
50
|
|
—
|
70
|
|
Facilities, seismic and other
|
10
|
|
—
|
15
|
|
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. In addition, we may be required to reclassify some portion of 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.
Working Capital Analysis
Our working capital, which we define as current assets minus current liabilities, was a surplus of
$59.9 million
and
$12.0 million
at
December 31, 2016
(Successor)
and
December 31, 2015
(Predecessor)
, respectively. Our cash balances totaled
$134.1 million
and
$1.8 million
at
December 31, 2016
(Successor)
and
December 31, 2015
(Predecessor)
, respectively. Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our credit agreement will be sufficient to fund our working capital needs. 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.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
(in thousands)
|
|
|
|
2015
|
|
2014
|
Net cash provided by operating activities
|
$
|
9,410
|
|
|
|
$
|
51,740
|
|
|
$
|
68,882
|
|
|
$
|
97,248
|
|
Net cash used in investing activities
|
(1,749,733
|
)
|
|
|
(101,434
|
)
|
|
(198,635
|
)
|
|
(163,380
|
)
|
Net cash provided by financing activities
|
1,874,268
|
|
|
|
47,926
|
|
|
118,504
|
|
|
36,966
|
|
Operating Activities
For the period from
October 11, 2016, through December 31, 2016 (Successor)
, net cash provided by operating activities was approximately
$9.4 million
. Cash provided by operating activities for the period from
January 1, 2016, through October 10, 2016 (Predecessor)
, was approximately
$51.7 million
, compared to approximately
$68.9 million
for the year ended
December 31, 2015
(Predecessor)
. The decrease in net cash provided by operating activities was primarily due to a
$21.3 million
decrease in total revenues and a decrease in net cash received for derivative settlements of
$18.9 million
. These decreases were offset by an
increase in changes in current assets and current liabilities.
Cash provided by operating activities for the year ended
December 31, 2015
(Predecessor)
was approximately
$68.9 million
, compared to approximately
$97.2 million
for the year ended
December 31, 2014
(Predecessor)
. The decrease in net cash provided by operating activities was 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
The following table provides a comparative summary of cash flow from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
(in thousands)
|
|
|
|
2015
|
|
2014
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Proceeds withdrawn from trust account
|
$
|
500,561
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Acquisition of Centennial Resource Production, LLC
|
(1,375,744
|
)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Acquisition of oil and natural gas properties
|
(849,642
|
)
|
|
|
(55,564
|
)
|
|
(43,223
|
)
|
|
(22,167
|
)
|
Development of oil and natural gas properties
|
(24,107
|
)
|
|
|
(45,605
|
)
|
|
(156,006
|
)
|
|
(275,683
|
)
|
Purchases of other property and equipment
|
(801
|
)
|
|
|
(265
|
)
|
|
(2,097
|
)
|
|
(453
|
)
|
Development of assets held for sale
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(14,240
|
)
|
Proceeds from sales of oil and natural gas properties and other assets
|
—
|
|
|
|
—
|
|
|
2,691
|
|
|
72,382
|
|
Proceeds from sale of Atlantic Midstream, net of cash sold
|
—
|
|
|
|
—
|
|
|
—
|
|
|
71,781
|
|
Cash held in escrow
|
—
|
|
|
|
—
|
|
|
—
|
|
|
5,000
|
|
Net cash used by investing activities
|
$
|
(1,749,733
|
)
|
|
|
$
|
(101,434
|
)
|
|
$
|
(198,635
|
)
|
|
$
|
(163,380
|
)
|
Net cash used by investing activities is primarily comprised of acquisition and development of oil and natural gas properties, net of dispositions.
Net cash used by investing activities for the period from
October 11, 2016, through December 31, 2016 (Successor)
was approximately
$1.7 billion
and included
$1.4 billion
attributable to the Business Combination,
$849.6 million
attributable to the Silverback Acquisition and
$24.1 million
attributable to the development of oil and natural gas properties. Cash used by investing activities during the period was offset by
$500.6 million
of proceeds withdrawn from the trust account used to purchase CRP.
Net cash used by investing activities for the period from
January 1, 2016, through October 10, 2016 (Predecessor)
included
$101.2 million
attributable to the acquisition and development of oil and natural gas properties.
Net cash used by investing activities for the year ended December 31, 2015
(Predecessor)
included
$199.2 million
attributable to the acquisition and development of oil and natural gas properties, offset by proceeds from asset sales of
$2.7 million
.
Net cash used by investing activities for the year ended December 31, 2014
(Predecessor)
included
$297.9 million
attributable to the acquisition and development of oil and natural gas properties, offset by net proceeds from asset sales of
$144.2 million
.
Financing Activities.
Net cash provided by financing activities for the period from
October 11, 2016, through December 31, 2016 (Successor)
, included proceeds of
$1.5 billion
from the issuance and sale of shares of our Class A Common Stock and
$379.5 million
from the issuance and sale of shares of our Series B Preferred Stock, offset by
$27.1 million
attributable to the payment of underwriting fees and
$17.5 million
repayment of deferred underwriting fees attributable to our IPO.
Net cash provided by financing activities for the period from
January 1, 2016, through October 10, 2016 (Predecessor)
, 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 for the year ended December 31, 2015
(Predecessor)
included
$92.0 million
of borrowing under CRP's revolving credit facility, offset by
$83.0 million
of repayments and capital contributions of
$111.4 million
.
Net cash provided by financing activities for the year ended December 31, 2014
(Predecessor)
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.
Credit Agreement
In connection with the consummation of the Business Combination, all indebtedness under CRP’s term loan and revolving credit facility was repaid in full. On October 11, 2016, CRP entered into a second amendment to the amended and restated credit agreement (the “second amendment”), which amends the amended and restated credit agreement, dated as of October 15, 2014, among CRP, each of the lenders from time to time party thereto and JPMorgan Chase Bank, N.A. as administrative agent (the “credit agreement”). CRP entered into the second amendment 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
225
to
325
basis points, 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 a third amendment to amended and restated credit agreement (the “third amendment”), which further amends the credit agreement. CRP entered into this amendment to, among other things, increase the borrowing base thereunder from
$200.0 million
to
$250.0 million
.
As of
December 31, 2016
, there were
no
borrowings under the revolving credit facility. Outstanding letters of credit were
$0.4 million
, leaving
$249.6 million
in borrowing capacity under the revolving credit facility.
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 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.
Borrowings 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
225
to
325
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
125
to
225
basis points, depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee on unused amounts of its revolving credit facility of
50
basis points. 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 our ability to, among other things:
|
|
•
|
incur additional indebtedness;
|
|
|
•
|
make investments and loans;
|
|
|
•
|
make or declare dividends;
|
|
|
•
|
enter into commodity hedges exceeding a specified percentage of our expected production;
|
|
|
•
|
enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness;
|
|
|
•
|
engage in transactions with affiliates.
|
Our credit agreement also requires us 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
(“ASC 815”) and certain restricted cash) to consolidated current liabilities (excluding the current portion of long-term debt under CRP’s credit agreement and non-cash liabilities under ASC 815), of not less than 1.0 to 1.0; and
|
|
|
•
|
a leverage ratio, which is the ratio of Total Funded Debt (as defined in our credit agreement) to consolidated EBITDAX (as defined in our credit agreement) for the rolling four fiscal quarter period ending on such day, of not greater than 4.0 to 1.0.
|
As of
December 31, 2016
, we were in compliance with such covenants and the financial ratios described above.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of
December 31, 2016
, we had no off-balance sheet arrangements.
Contractual Obligations
A summary of our contractual obligations as of
December 31, 2016
is provided in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
Drilling rig commitments
|
|
$
|
7,316
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7,316
|
|
Office and equipment leases
|
|
831
|
|
|
814
|
|
|
573
|
|
|
134
|
|
|
79
|
|
|
—
|
|
|
2,431
|
|
Asset retirement obligations(1)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,226
|
|
|
7,226
|
|
Total
|
|
$
|
8,147
|
|
|
$
|
814
|
|
|
$
|
573
|
|
|
$
|
134
|
|
|
$
|
79
|
|
|
$
|
7,226
|
|
|
$
|
16,973
|
|
|
|
(1)
|
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.
|
Recently Issued Accounting Standards
Please refer to
Note 1—Basis of Presentation and Summary of Significant Accounting Policies
, in Part II, Item 8. Financial Statements and Supplementary Data in this annual report for a discussion of recently issued accounting standards and their anticipated effect on our business.
Critical Accounting Policies and Estimate
The discussion and analysis of our financial condition and results of operations are based upon our consolidated and combined financial statements, which have been prepared in accordance with GAAP. The preparation of these statements requires us to make certain assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies is detailed in
Note 1—Basis of Presentation and Summary of Significant Accounting Policies
, in Part II, Item 8. Financial Statements and Supplementary Data in this annual report.
We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.
Successful Efforts Method of Accounting for Oil and Natural Gas Activities
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.
Impairment of Oil and Natural Gas Properties
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 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.
Oil and Natural Gas Reserve Quantities
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 consolidated and combined 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 percent 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, 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.
Revenue Recognition
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.
Derivative Instruments
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.
Asset Retirement Obligations
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.
Our 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.
Non-GAAP Financial Measure
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated and combined 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, exploration costs, 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, transaction costs and other non-cash and non-recurring operating items. Adjusted EBITDAX is not a measure of net income as determined by GAAP.
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 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, our most directly comparable financial measure calculated and presented in accordance with GAAP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
(in thousands)
|
|
|
|
2015
|
|
2014
|
Adjusted EBITDAX reconciliation to net income:
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to Centennial Resource Development, Inc.
|
$
|
(8,081
|
)
|
|
|
$
|
(218,724
|
)
|
|
$
|
(38,325
|
)
|
|
$
|
17,790
|
|
Less net loss attributable to noncontrolling interest
|
904
|
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Interest expense
|
378
|
|
|
|
5,626
|
|
|
6,266
|
|
|
2,475
|
|
Income tax (benefit) expense
|
—
|
|
|
|
(406
|
)
|
|
(572
|
)
|
|
1,524
|
|
Depreciation, depletion and amortization and accretion of asset retirement obligations
|
14,877
|
|
|
|
62,964
|
|
|
90,084
|
|
|
69,110
|
|
Abandonment expense and impairment of unproved properties
|
—
|
|
|
|
2,545
|
|
|
7,619
|
|
|
20,025
|
|
Exploration
|
844
|
|
|
|
—
|
|
|
84
|
|
|
—
|
|
Loss (gain) on derivatives
|
1,548
|
|
|
|
6,838
|
|
|
(20,756
|
)
|
|
(41,943
|
)
|
Net cash receipts on settled derivatives
|
1,054
|
|
|
|
16,623
|
|
|
36,430
|
|
|
4,611
|
|
Incentive unit compensation
|
—
|
|
|
|
165,394
|
|
|
—
|
|
|
—
|
|
Equity based compensation expense
|
1,333
|
|
|
|
—
|
|
|
—
|
|
|
12,420
|
|
Contract termination and rig stacking
|
—
|
|
|
|
—
|
|
|
2,387
|
|
|
—
|
|
Write-off of IPO related offering costs
|
—
|
|
|
|
1,181
|
|
|
1,585
|
|
|
—
|
|
Transaction costs
|
4,097
|
|
|
|
15,792
|
|
|
3
|
|
|
670
|
|
Gain (loss) on sale of assets
|
(24
|
)
|
|
|
(11
|
)
|
|
(2,439
|
)
|
|
2,096
|
|
Adjusted EBITDAX
|
$
|
16,930
|
|
|
|
$
|
57,822
|
|
|
$
|
82,366
|
|
|
$
|
88,780
|
|
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CENTENNIAL RESOURCE DEVELOPMENT, INC.
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
|
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Information to Consolidate and Combined Financial Statements
|
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Centennial Resource Development, Inc.:
We have audited the accompanying consolidated balance sheets of Centennial Resource Development, Inc. and its subsidiaries (the Company) as of December 31, 2016 (Successor Company balance sheet) and 2015 (Predecessor Company balance sheet), and the related consolidated statements of operations, shareholders’ equity, and cash flows for the period from October 11, 2016 through December 31, 2016 (Successor Company operations) and the period from January 1, 2016 through October 10, 2016 and for each of the two years in the period ended December 31, 2015 (Predecessor Company operations). These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 Successor Company consolidated financial statements referred to above present fairly, in all material respects, the financial position of Centennial Resource Development, Inc. and its subsidiaries as of December 31, 2016, and the results of their operations and their cash flows for the period from October 11, 2016 through December 31, 2016, in conformity with U.S. generally accepted accounting principles.
Further, in our opinion, the Predecessor Company consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of the predecessor to Centennial Resource Development, Inc. and its subsidiaries as of December 31, 2015, and the results of their operations and their cash flows for the period from January 1, 2016 through October 10, 2016, and for each of the two years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Denver, Colorado
March 23, 2017
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
December 31, 2016
|
|
|
December 31, 2015
|
ASSETS
|
|
|
|
|
Current assets
|
|
|
|
|
Cash and cash equivalents
|
$
|
134,083
|
|
|
|
$
|
1,768
|
|
Accounts receivable, net
|
14,734
|
|
|
|
13,012
|
|
Derivative instruments, net
|
431
|
|
|
|
19,043
|
|
Prepaid and other current assets
|
2,078
|
|
|
|
322
|
|
Total current assets
|
151,326
|
|
|
|
34,145
|
|
Oil and natural gas properties, other property and equipment
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
605,853
|
|
|
|
651,596
|
|
Accumulated depreciation, depletion and amortization
|
(14,436
|
)
|
|
|
(180,946)
|
|
Unproved oil and natural gas properties
|
1,905,661
|
|
|
|
105,897
|
|
Other property and equipment, net of accumulated depreciation of $391 and $868, respectively
|
2,193
|
|
|
|
2,240
|
|
Total property and equipment, net
|
2,499,271
|
|
|
|
578,787
|
|
Noncurrent assets
|
|
|
|
|
Derivative instruments, net
|
—
|
|
|
|
2,070
|
|
Other noncurrent assets
|
1,045
|
|
|
|
1,293
|
|
Total assets
|
$
|
2,651,642
|
|
|
|
$
|
616,295
|
|
LIABILITIES AND SHAREHOLDERS’/OWNERS’ EQUITY
|
|
|
|
|
Current liabilities
|
|
|
|
|
Accounts payable and accrued expenses
|
$
|
86,100
|
|
|
|
$
|
19,985
|
|
Derivative instruments, net
|
5,361
|
|
|
|
—
|
|
Other current liabilities
|
—
|
|
|
|
2,148
|
|
Total current liabilities
|
91,461
|
|
|
|
22,133
|
|
Noncurrent liabilities
|
|
|
|
|
Revolving credit facility
|
—
|
|
|
|
74,000
|
|
Term loan, net of unamortized deferred financing costs
|
—
|
|
|
|
64,649
|
|
Asset retirement obligations
|
7,226
|
|
|
|
2,288
|
|
Deferred tax liability
|
—
|
|
|
|
2,361
|
|
Derivative instruments, net
|
20
|
|
|
|
—
|
|
Total liabilities
|
98,707
|
|
|
|
165,431
|
|
Shareholders’/Owners’ Equity
|
|
|
|
|
Owners' equity
|
—
|
|
|
|
450,864
|
|
Preferred stock, $.0001 par value, 1,000,000 shares authorized:
|
|
|
|
|
Series A: 1 share issued and outstanding at December 31, 2016
|
—
|
|
|
|
—
|
|
Series B: 104,400 shares issued and outstanding at December 31, 2016
|
—
|
|
|
|
—
|
|
Common stock, $0.0001 par value, 620,000,000 shares authorized:
|
|
|
|
|
Class A: 201,091,646 shares issued and outstanding at December 31, 2016
|
20
|
|
|
|
—
|
|
Class C: 19,155,921 shares issued and outstanding at December 31, 2016
|
2
|
|
|
|
—
|
|
Additional paid-in capital
|
2,364,049
|
|
|
|
—
|
|
Accumulated deficit
|
(8,929
|
)
|
|
|
—
|
|
Total shareholders’/owners’ equity
|
2,355,142
|
|
|
|
450,864
|
|
Noncontrolling interest
|
197,793
|
|
|
|
—
|
|
Total equity
|
2,552,935
|
|
|
|
450,864
|
|
Total liabilities and shareholders’/owners’ equity
|
$
|
2,651,642
|
|
|
|
$
|
616,295
|
|
The accompanying notes are an integral part of these consolidated and combined financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
2014
|
Revenues
|
|
|
|
|
|
|
|
|
Oil sales
|
$
|
24,313
|
|
|
|
$
|
59,787
|
|
|
$
|
77,643
|
|
|
$
|
114,955
|
|
Natural gas sales
|
3,449
|
|
|
|
6,045
|
|
|
7,965
|
|
|
9,670
|
|
NGL sales
|
1,955
|
|
|
|
3,284
|
|
|
4,852
|
|
|
7,200
|
|
Total revenues
|
29,717
|
|
|
|
69,116
|
|
|
90,460
|
|
|
131,825
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
3,541
|
|
|
|
11,036
|
|
|
21,173
|
|
|
17,690
|
|
Severance and ad valorem taxes
|
1,636
|
|
|
|
3,696
|
|
|
5,021
|
|
|
6,875
|
|
Transportation, processing, gathering and other operating expense
|
2,187
|
|
|
|
4,583
|
|
|
5,732
|
|
|
4,772
|
|
Depreciation, depletion, amortization and accretion of asset retirement obligations
|
14,877
|
|
|
|
62,964
|
|
|
90,084
|
|
|
69,110
|
|
Abandonment expense and impairment of unproved properties
|
—
|
|
|
|
2,545
|
|
|
7,619
|
|
|
20,025
|
|
Exploration
|
844
|
|
|
|
—
|
|
|
84
|
|
|
—
|
|
Contract termination and rig stacking
|
—
|
|
|
|
—
|
|
|
2,387
|
|
|
—
|
|
General and administrative expenses
|
13,715
|
|
|
|
25,581
|
|
|
14,206
|
|
|
31,694
|
|
Incentive unit compensation
|
—
|
|
|
|
165,394
|
|
|
—
|
|
|
—
|
|
Total operating expenses
|
36,800
|
|
|
|
275,799
|
|
|
146,306
|
|
|
150,166
|
|
Gain (loss) on sale of oil and natural gas properties
|
24
|
|
|
|
11
|
|
|
2,439
|
|
|
(2,096
|
)
|
Total operating loss
|
(7,059
|
)
|
|
|
(206,672
|
)
|
|
(53,407
|
)
|
|
(20,437
|
)
|
Other (expense) income
|
|
|
|
|
|
|
|
|
Interest expense
|
(378
|
)
|
|
|
(5,626
|
)
|
|
(6,266
|
)
|
|
(2,475
|
)
|
Gain (loss) on derivative instruments
|
(1,548
|
)
|
|
|
(6,838
|
)
|
|
20,756
|
|
|
41,943
|
|
Other (expense) income
|
—
|
|
|
|
6
|
|
|
20
|
|
|
281
|
|
Total other (expense) income
|
(1,926
|
)
|
|
|
(12,458
|
)
|
|
14,510
|
|
|
39,749
|
|
(Loss) income before income taxes
|
(8,985
|
)
|
|
|
(219,130
|
)
|
|
(38,897
|
)
|
|
19,312
|
|
Income tax benefit (expense)
|
—
|
|
|
|
406
|
|
|
572
|
|
|
(1,524
|
)
|
Net (loss) income
|
(8,985
|
)
|
|
|
(218,724
|
)
|
|
(38,325
|
)
|
|
17,788
|
|
Less net loss attributable to noncontrolling interest
|
(904
|
)
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
Net (loss) income attributable to Centennial Resource Development, Inc.
|
$
|
(8,081
|
)
|
|
|
$
|
(218,724
|
)
|
|
$
|
(38,325
|
)
|
|
$
|
17,790
|
|
Loss per share:
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.05
|
)
|
|
|
|
|
|
|
|
Diluted
|
$
|
(0.05
|
)
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated and combined financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN OWNERS’ EQUITY (Predecessor)
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
owners’ equity
|
|
Noncontrolling interest in subsidiary
|
|
Total equity
|
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
|
|
Deemed contributions
|
179,442
|
|
|
—
|
|
|
179,442
|
|
Net loss
|
(218,724
|
)
|
|
—
|
|
|
(218,724
|
)
|
Balance at October 10, 2016
|
$
|
411,582
|
|
|
$
|
—
|
|
|
$
|
411,582
|
|
The accompanying notes are an integral part of these consolidated and combined financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (Successor)
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
|
Class A
|
|
Class B
|
|
Class C
|
|
Series A
|
|
Series B
|
|
Paid-In Capital
|
|
Accumulated Deficit
|
|
Total Equity
|
|
Noncontrolling Interest
|
|
Total Equity
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
|
|
Balance at October 10, 2016
|
2,175
|
|
|
$
|
—
|
|
|
12,500
|
|
|
$
|
1
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
5,460
|
|
|
(461
|
)
|
|
5,000
|
|
|
—
|
|
|
5,000
|
|
Conversion of common shares from Class B to Class A at transaction
|
12,500
|
|
|
1
|
|
|
(12,500
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Class A common shares released from possible redemption
|
47,825
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
478,243
|
|
|
—
|
|
|
478,248
|
|
|
—
|
|
|
478,248
|
|
Class C common shares issued
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20,000
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Conversion of common shares from Class C to Class A
|
844
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(844
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,798
|
|
|
—
|
|
|
7,798
|
|
|
(7,798
|
)
|
|
—
|
|
Sale of unregistered Class A common shares
|
101,005
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,010,040
|
|
|
—
|
|
|
1,010,050
|
|
|
—
|
|
|
1,010,050
|
|
Underwriters’ discount and offering expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,713
|
)
|
|
—
|
|
|
(6,713
|
)
|
|
—
|
|
|
(6,713
|
)
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(387
|
)
|
|
(387
|
)
|
|
—
|
|
|
(387
|
)
|
Noncontrolling interest in Centennial Resource Production, LLC
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
184,779
|
|
|
184,779
|
|
Balance at October 11, 2016
|
164,349
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
19,156
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,494,826
|
|
|
(848
|
)
|
|
1,493,996
|
|
|
176,981
|
|
|
1,670,977
|
|
Restricted stock issued
|
257
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sale of unregistered Class A common shares
|
36,486
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
530,503
|
|
|
—
|
|
|
530,507
|
|
|
—
|
|
|
530,507
|
|
Sale of unregistered Class B preferred shares
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
104
|
|
|
—
|
|
|
379,494
|
|
|
—
|
|
|
379,494
|
|
|
—
|
|
|
379,494
|
|
Underwriters’ discount and offering expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(20,391
|
)
|
|
—
|
|
|
(20,391
|
)
|
|
—
|
|
|
(20,391
|
)
|
Change in equity due to issuance of shares by Centennial Resource Production, LLC
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21,716
|
)
|
|
—
|
|
|
(21,716
|
)
|
|
21,716
|
|
|
—
|
|
Equity based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,333
|
|
|
—
|
|
|
1,333
|
|
|
—
|
|
|
1,333
|
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,081
|
)
|
|
(8,081
|
)
|
|
(904
|
)
|
|
(8,985
|
)
|
Balance at December 31, 2016
|
201,092
|
|
|
$
|
20
|
|
|
—
|
|
|
$
|
—
|
|
|
19,156
|
|
|
$
|
2
|
|
|
—
|
|
|
$
|
—
|
|
|
104
|
|
|
$
|
—
|
|
|
$
|
2,364,049
|
|
|
$
|
(8,929
|
)
|
|
$
|
2,355,142
|
|
|
$
|
197,793
|
|
|
$
|
2,552,935
|
|
The accompanying notes are an integral part of these consolidated and combined financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
2014
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net (loss) income
|
$
|
(8,985
|
)
|
|
|
$
|
(218,724
|
)
|
|
$
|
(38,325
|
)
|
|
$
|
17,788
|
|
Adjustments to reconcile net loss to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
Accretion of asset retirement obligations
|
49
|
|
|
|
134
|
|
|
139
|
|
|
156
|
|
Depreciation, depletion and amortization
|
14,828
|
|
|
|
62,830
|
|
|
89,945
|
|
|
68,954
|
|
Incentive unit compensation
|
—
|
|
|
|
165,394
|
|
|
—
|
|
|
—
|
|
Equity based compensation expense
|
1,333
|
|
|
|
—
|
|
|
—
|
|
|
12,420
|
|
Noncash transaction costs
|
—
|
|
|
|
14,049
|
|
|
—
|
|
|
—
|
|
Abandonment expense and impairment of unproved properties
|
—
|
|
|
|
2,545
|
|
|
7,619
|
|
|
20,025
|
|
Write-off of deferred S-1 related expense
|
—
|
|
|
|
—
|
|
|
1,585
|
|
|
—
|
|
Deferred tax (benefit) expense
|
—
|
|
|
|
(406
|
)
|
|
(572
|
)
|
|
1,524
|
|
(Gain) loss on sale of oil and natural gas properties
|
(24
|
)
|
|
|
(11
|
)
|
|
(2,439
|
)
|
|
2,096
|
|
Loss (gain) on derivative instruments
|
1,548
|
|
|
|
6,838
|
|
|
(20,756
|
)
|
|
(41,943
|
)
|
Net cash received for derivative settlements
|
1,054
|
|
|
|
16,623
|
|
|
35,493
|
|
|
4,611
|
|
Recovery of bad debt
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(777
|
)
|
Amortization of debt issuance costs
|
70
|
|
|
|
376
|
|
|
482
|
|
|
316
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Decrease (increase) in accounts receivable
|
(983
|
)
|
|
|
969
|
|
|
5,244
|
|
|
(6,322
|
)
|
Increase in prepaid and other assets
|
(1,092
|
)
|
|
|
(170
|
)
|
|
(864
|
)
|
|
(79
|
)
|
Increase (decrease) in accounts payable and other liabilities
|
1,612
|
|
|
|
1,293
|
|
|
(8,669
|
)
|
|
18,479
|
|
Net cash provided by operating activities
|
9,410
|
|
|
|
51,740
|
|
|
68,882
|
|
|
97,248
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Proceeds withdrawn from trust account
|
500,561
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Acquisition of Centennial Resource Production, LLC
|
(1,375,744
|
)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Acquisition of oil and natural gas properties
|
(849,642
|
)
|
|
|
(55,564
|
)
|
|
(43,223
|
)
|
|
(22,167
|
)
|
Development of oil and natural gas properties
|
(24,107
|
)
|
|
|
(45,605
|
)
|
|
(156,006
|
)
|
|
(275,683
|
)
|
Purchases of other property and equipment
|
(801
|
)
|
|
|
(265
|
)
|
|
(2,097
|
)
|
|
(453
|
)
|
Development of assets held for sale
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(14,240
|
)
|
Proceeds from sales of oil and natural gas properties and other assets
|
—
|
|
|
|
—
|
|
|
2,691
|
|
|
72,382
|
|
Proceeds from sale of Atlantic Midstream, net of cash sold
|
—
|
|
|
|
—
|
|
|
—
|
|
|
71,781
|
|
Cash held in escrow
|
—
|
|
|
|
—
|
|
|
—
|
|
|
5,000
|
|
Net cash used by investing activities
|
(1,749,733
|
)
|
|
|
(101,434
|
)
|
|
(198,635
|
)
|
|
(163,380
|
)
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Issuance of Class A common shares
|
1,540,556
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Issuance of Preferred Series B shares
|
379,494
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Payment of underwriting fees
|
(27,104
|
)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Payment of deferred underwriting compensation
|
(17,500
|
)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Proceeds from revolving credit facility
|
—
|
|
|
|
55,000
|
|
|
92,000
|
|
|
196,000
|
|
Repayment of revolving credit facility
|
—
|
|
|
|
(5,000
|
)
|
|
(83,000
|
)
|
|
(160,000
|
)
|
Capital contributions
|
—
|
|
|
|
—
|
|
|
111,396
|
|
|
59,776
|
|
Financing obligation
|
(63
|
)
|
|
|
(2,074
|
)
|
|
(1,633
|
)
|
|
—
|
|
Debt issuance costs
|
(1,115
|
)
|
|
|
—
|
|
|
(259
|
)
|
|
(1,637
|
)
|
Repurchase of equity
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(119,272
|
)
|
Proceeds from term loan
|
—
|
|
|
|
—
|
|
|
—
|
|
|
65,000
|
|
Distribution in connection with common control acquisition
|
—
|
|
|
|
—
|
|
|
—
|
|
|
(3,051
|
)
|
Contributions received from noncontrolling interest
|
—
|
|
|
|
—
|
|
|
—
|
|
|
150
|
|
Net cash provided by financing activities
|
1,874,268
|
|
|
|
47,926
|
|
|
118,504
|
|
|
36,966
|
|
Net increase (decrease) in cash and cash equivalents
|
133,945
|
|
|
|
(1,768
|
)
|
|
(11,249
|
)
|
|
(29,166
|
)
|
Cash and cash equivalents, beginning of period
|
138
|
|
|
|
1,768
|
|
|
13,017
|
|
|
42,183
|
|
Cash and cash equivalents, end of period
|
$
|
134,083
|
|
|
|
$
|
—
|
|
|
$
|
1,768
|
|
|
$
|
13,017
|
|
The accompanying notes are an integral part of these consolidated and combined financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS (Continued)
(in thousands)
Supplemental cash flow information and noncash activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
2014
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
$
|
234
|
|
|
|
$
|
5,092
|
|
|
$
|
5,782
|
|
|
$
|
1,935
|
|
Supplemental noncash activity
|
|
|
|
|
|
|
|
|
Accrued capital expenditures included in accounts payable and accrued expenses
|
$
|
65,217
|
|
|
|
$
|
21,025
|
|
|
$
|
13,124
|
|
|
$
|
81,510
|
|
Financing obligation
|
—
|
|
|
|
—
|
|
|
3,770
|
|
|
—
|
|
The accompanying notes are an integral part of these consolidated and combined financial statements.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Note 1—Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Centennial Resource Development, Inc. (the “Company”) was originally incorporated in Delaware on November 4, 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 the Company and one or more businesses.
On February 29, 2016, the Company consummated its initial public offering of Units each consisting of
one
share of Class A Common Stock and one-third of one Public Warrant. On October 11, 2016, the Company consummated the acquisition of approximately
89%
of the outstanding membership interests in Centennial Resource Production, LLC, a Delaware limited liability company (“CRP” and such acquisition, the “Business Combination”). In connection with the closing of the Business Combination, the Company changed its name from "Silver Run Acquisition Corporation" to "Centennial Resource Development, Inc." and continued the listing of its Class A Common Stock and Public Warrants on NASDAQ under the symbols "CDEV" and "CDEVW," respectively. Refer to
Note 2—Business Combination
for further discussion of the Business Combination.
CRP was formed in August 2012 by an affiliate of NGP Energy Capital Management, 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.
The Company’s Class A Common Stock and Public Warrants trade on The NASDAQ Capital Market (“NASDAQ”) under the ticker symbols “CDEV” and “CDEVW,” respectively. The Units automatically separated into their component securities prior to or upon closing of the Business Combination and, as a result, no longer trade as a separate security. The consolidated financial statements include the accounts of the Company and CRP and its wholly-owned subsidiaries.
Basis of Presentation
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying consolidated and combined financial statements. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of
December 31, 2016
, through the filing date of this report.
As a result of the Business Combination, the Company is the acquirer for accounting purposes, and CRP is the acquiree and accounting Predecessor. The Company’s financial statement presentation distinguishes a “Predecessor” for CRP for periods prior to the Business Combination. The Company is the “Successor” for periods after the Business Combination, which includes consolidation of CRP subsequent to the Business Combination on October 11, 2016. The Merger was accounted for as a business combination using the acquisition method of accounting, and the Successor financial statements reflect a new basis of accounting that is based on the fair value of the net assets acquired. Refer to
Note 2—Business Combination
for further discussion of the Business Combination. As a result of the application of the acquisition method of accounting as of the Business Combination, the financial statements for the Predecessor period and for the Successor period are presented on a different basis of accounting and are therefore, not comparable.
Principles of Consolidation
The consolidated financial statements included herein have been prepared in accordance with GAAP and the rules and regulations of Securities and Exchange Commission (“SEC”). The consolidated financial statements include the accounts of the Company and its majority owned subsidiary CRP, and its wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of the Company’s consolidated and combined financial statements requires the Company’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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
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.
Cash and Cash Equivalents
The Company considers all highly liquid instruments with an original maturity of
three
months or less at the time of issuance to be cash equivalents. The Company's cash management process provides for the daily funding of checks as they are presented to the bank.
Accounts Receivable
Accounts receivable consists mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company 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 Company has had minimal bad debts.
Although diversified among many companies, collectibility is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. The Company establishes an allowance for doubtful accounts equal to the estimable portions of accounts receivable for which failure to collect is probable. The Company had
no
allowance for doubtful accounts at
December 31, 2016
(Successor)
. The allowance for doubtful accounts at
December 31, 2015
(Predecessor)
was
$0.1 million
.
Credit Risk and Other Concentrations
The Company normally sell production to a relatively small number of customers, as is customary in its business. For the year ended
December 31, 2016
, sales to Plains Marketing, LP (“Plains”), Shell Trading (US) Company, and Permian Transport and Trading accounted for
48%
,
22%
, and
11%
, respectively, of the total revenue. For the years ended
December 31, 2015
and
December 31, 2014
, the Company only had one major customer, Plains, which accounted for
64%
and
78%
, respectively, of total revenue. The loss of any of the Company’s major purchasers could materially and adversely affect its revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, the Company believes that the loss of any major purchaser would not have a material adverse effect on its financial condition and results of operations because 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 Company 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 Company, which creates credit risk.
As of
December 31, 2016
, and through the filing date of this report, all of the Company’s derivative counterparties were members of the Company’s credit facility lender group. The credit facility is secured by the Company’s proved oil and natural gas properties and therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company 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
$0.7 million
at
December 31, 2016
(Successor)
. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; and (ii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’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.
The Company 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, 2016
(Successor)
and
December 31, 2015
(Predecessor)
, the Company has not incurred losses related to these investments.
Oil and Natural Gas Properties
The Company 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, 2016
(Successor)
and
December 31, 2015
(Predecessor)
, 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,
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
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 to income.
Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. The Company 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. There was
no
abandonment and impairment expense
for the period from October 11, 2016, through December 31, 2016
(Successor)
.
For the period from January 1, 2016, through October 10, 2016
(Predecessor)
, the Company recorded abandonment and impairment expense of
$2.5 million
for leases which have expired, or are expected to expire. For the year ended
December 31, 2015
(Predecessor)
, the Company recorded abandonment and impairment expense of
$7.6 million
for leases which have expired, or are expected to expire. For the year ended
December 31, 2014
(Predecessor)
, the Company 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 which had expired, or were expected to expire.
The Company reviews it 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 Company 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 Company 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 for the periods
October 11, 2016, through December 31, 2016 (Successor)
and
January 1, 2016, through October 10, 2016 (Predecessor)
and for the years ended
December 31, 2015
(Predecessor)
and
December 31, 2014
(Predecessor)
.
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 Company’s revolving credit facility are included in the line item
Other
noncurrent assets
in the consolidated balance sheets and are stated at cost, net of amortization. These costs are amortized to interest expense on a straight line basis over the borrowing term.
Derivative Financial Instruments
In order to manage its exposure to oil and natural gas price volatility, the Company 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 Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative position.
The Company records derivative instruments on the consolidated 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 Company’s derivatives have not been designated as hedges for accounting purposes. For additional discussion on derivatives, please refer to
Note 9—Derivative Instruments
.
Asset Retirement Obligations
The Company 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 balance sheets. The Company 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
the remaining estimated economic lives of the respective oil and natural gas properties. For additional discussion, please refer to
Note 11—Asset Retirement Obligations
.
Revenue Recognition
The Company derives revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when the Company’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 Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company follows the sales method of accounting for its oil and natural gas revenue, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. The Company had no significant imbalances as of
December 31, 2016
or
2015
.
Income Taxes
Income taxes and uncertain tax positions are accounted for in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 740,
Accounting for Income Taxes
(“ASC 740”). Deferred income taxes are provided for the differences between the bases of assets and liabilities for financial reporting and income tax purposes. Tax positions meeting the more-likely-than-not recognition threshold are measured pursuant to the guidance set forth in ASC 740. A valuation allowance is established when necessary to reduce deferred tax assets to the amount expected to be realized.
Equity Based Compensation (Successor)
The Company recognizes compensation related to all stock-based awards, including stock options, in the financial statements based on their estimated grant-date fair value. The Company grants various types of stock-based awards including stock options and restricted stock. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock are valued using the market price of the Company’s common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period. See
Note 8—Equity Based Compensation
for additional information regarding the Company’s equity based compensation (successor).
Equity Based Compensation (Predecessor)
Pursuant to the LLC Agreement of CRP (prior to the Business Combination), certain incentive units were available to be issued to the Company’s management and employees, consisting of Tier I, Tier I A, Tier II, Tier III and Tier IV units. The incentive units were intended to be compensation for services rendered to CRP. Tier Incentive units are accounted for as liability awards under FASB ASC Topic 718,
Compensation: Stock Compensation
(“ASC 718”)
,
with compensation expense based on period-end fair value. Refer to
Note 8—Equity Based Compensation
for additional information regarding the CRP’s equity based compensation (Predecessor).
Earnings (Loss) Per Share
The two-class method of computing earnings per share is required for entities that have participating securities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Basic earnings (loss) per share is calculated by dividing earnings (loss) available to common shareholders by the weighted average shares-basic during each period.
The Company’s preferred series B shares have a non-forfeitable right to participate in distributions with common stockholders on a pro rata, as-converted basis and as such are considered participating securities. Shares of the Company’s unvested restricted stock are eligible to receive dividends; however, dividend rights will be forfeited if the award does not vest. Accordingly, these shares are not considered participating securities. Shares of the Company’s class C common stock and warrants do not share in the earnings or losses and are therefore not participating securities.
The Company uses the "if-converted" method to determine the potential dilutive effect of exchanges of outstanding CRP Common Units and corresponding shares of its outstanding Class C common stock, and the treasury stock method to determine the potential dilutive effect of its outstanding restricted stock and stock options.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
The following table reflects the allocation of net income to common stockholders and EPS computations for the periods indicated based on a weighted average number of common stock outstanding for the period:
|
|
|
|
|
|
Successor
|
|
October 11, 2016
through
December 31, 2016
|
(in thousands, except per share data)
|
Net income (loss)
|
$
|
(8,081
|
)
|
Less: Loss allocable to participating securities
|
(46
|
)
|
Net loss available for common shareholders
|
$
|
(8,035
|
)
|
|
|
Basic net loss per share
|
$
|
(0.05
|
)
|
Diluted net loss per share
|
$
|
(0.05
|
)
|
|
|
Basic weighted average share outstanding
|
165,684
|
|
Add: Dilutive effects of stock options and RSUs
|
—
|
|
Diluted weighted average shares outstanding
|
165,684
|
|
Options and restricted shares of
2.7 million
and
0.3 million
, respectively, were not included in the weighted average shares-dilutive calculation for the period from
October 11, 2016, through December 31, 2016
because their effect would have been anti-dilutive.
Segment Reporting
The Company 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.
Recently Issued Accounting Standards
In August 2016, the FASB issued ASU 2016-15,
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments
. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update should be applied using the retrospective transition method. Adoption of this standard will only affect the presentation of the Company’s cash flows and will not have a material impact on its consolidated financial statements.
In April 2016, the FASB issued ASU 2016-10,
Revenue from Contracts with Customers: Identifying Performance Obligations and Licensing
. This update clarifies two principles of ASC Topic 606,
Revenue from Contracts with Customers
: identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as ASU 2016-08,
Revenue from Contracts with Customers: Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net)
, the revenue recognition standard discussed below. The adoption of this standard is not expected to have a material impact on the Company’s financial position, results of operations and liquidity.
March 2016, the FASB issued ASU 2016-09,
Compensation-Stock Compensation
. This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. The Company elected to early adopt this guidance in October 2016 in conjunction with the issuance of its equity awards.
In March 2016, the FASB issued ASU 2016-08,
Revenue from Contracts with Customers: Principal Versus Agent Considerations (Reporting Revenue Gross Versus Net)
. Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning this update is applied only to the most current period presented. The Company is currently evaluating the impact, if any, that the adoption of this update will have on its financial position, results of operations and liquidity.
In February 2016, the FASB issued ASU 2016-02,
Leases
. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on its balance sheet for current operating leases.
In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers
. This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application permitted for annual reporting period beginning after December 31, 2016. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is currently evaluating the impact of this standard on its consolidated financial statements.
Subsequent Events
On March 1, 2017, the Company delivered a notice of redemption of the Public Warrants, announcing its intention to redeem any unexercised and outstanding Public Warrants on March 31, 2017 for
$0.01
per Public Warrant. As permitted under the warrant agreement that provides the terms of the Public Warrants, the notice of redemption requires all holders exercising their Public Warrants prior to March 31, 2017 to do so on a “cashless basis” and surrender their Public Warrants for a number of shares of Class A Common Stock equal to the product of the quotient equal to (i) the difference between
$11.50
and
$18.44
(the average last sale price of the Class A Common Stock for the ten trading days ending on February 24, 2017) divided by (ii)
$18.44
, or approximately
0.376
, multiplied by the number of Public Warrants held by such holder, rounded down to the nearest whole share. Assuming all warrants are exercised by holders, Centennial will issue approximately
6.27 million
shares of Class A Common Stock to the Public Warrant holders, resulting in a share count of approximately
253 million
shares outstanding, which includes Class A Common Stock shares, the shares of Series B Preferred Stock held by Riverstone (assuming conversion to Class A Common Stock on a 250-to-one basis), and the shares of Class C Common Stock held by the Centennial Contributors. The Private Placement Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees. Refer to
Note 7—Shareholders' and Owners' Equity
for additional information regarding the Company’s warrants.
Note 2—Business Combination
On October 11, 2016 (the "Closing Date"), the Company 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 (the "Closing"), Silver Run 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. At the Closing, Silver Run 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
"CRP Common Units") and (2) the Company was admitted as a member of CRP and issued
163,505,000
CRP Common Units, representing an approximate
89%
interest in CRP.
The Business Combination has been accounted using the acquisition method. The acquisition method of accounting is based on FASB 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.
The purchase consideration for the Business Combination was as follows:
|
|
|
|
|
(in thousands)
|
October 11, 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)
|
184,779
|
|
Total purchase price consideration and fair value of non-controlling interest
|
$
|
1,560,523
|
|
|
|
(1)
|
Represents the additional contribution 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 Date.
|
|
|
(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
11%
membership interest in CRP.
|
The following table summarizes the allocation of the purchase consideration to the assets acquired and liabilities assumed:
|
|
|
|
|
(in thousands)
|
October 11, 2016
|
Fair value of assets acquired:
|
|
Other current assets
|
$
|
13,341
|
|
Derivative instruments
|
1,052
|
|
Oil and gas properties(1):
|
|
Proved properties
|
444,551
|
|
Unproved properties
|
1,138,423
|
|
Other property, plant and equipment
|
1,764
|
|
Goodwill
|
—
|
|
Total fair value of assets acquired
|
1,599,131
|
|
Fair value of liabilities assumed:
|
|
Accounts payable and accrued expenses
|
30,156
|
|
Other current liabilities
|
63
|
|
Derivative instruments(2)
|
3,400
|
|
Asset retirement obligation
|
4,989
|
|
Fair value of net assets acquired
|
$
|
1,560,523
|
|
|
|
(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)
|
The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the merger and represent Level 2 inputs. Derivative instruments in an asset position include a measure of counterparty
|
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s own nonperformance risk, each based on the current published credit default swap rates.
Unaudited Pro Forma Operating Results
The following unaudited pro forma combined financial information has been prepared as if the Business Combination and other related transactions had taken place on January 1, 2015. The unaudited pro forma consolidated financial information has been prepared using the acquisition method of accounting in accordance with GAAP.
The information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including depletion of CRP’s fair-valued proved oil and gas properties, and the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2016, were adjusted to exclude
$18.7 million
of transaction-related costs and
$165.4 million
of incentive unit compensation incurred by CRP.
The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Business Combination taken place on January 1, 2015; furthermore, the financial information is not intended to be a projection of future results.
|
|
|
|
|
|
|
|
|
|
(Unaudited Pro Forma)
|
|
Year Ended December 31,
|
(in thousands)
|
2016
|
|
2015
|
Total revenues
|
$
|
98,833
|
|
|
$
|
90,460
|
|
Total operating expenses
|
86,490
|
|
|
123,702
|
|
Net income (loss) attributable to common shareholders of Centennial Resource Development, Inc.
|
1,666
|
|
|
(6,397
|
)
|
Basic and diluted net loss per share
|
0.01
|
|
|
(0.04
|
)
|
Note 3—Property Acquisitions and Dispositions
2016 Acquisitions
In December 2016, the Company acquired undeveloped acreage and oil and gas producing properties located in Reeves County, Texas from Silverback Exploration, LLC. for an aggregate price of approximately
$855.0 million
, subject to customary purchase price adjustments. Approximately
$116.7 million
was recorded as proved oil and natural gas properties with the remaining recorded to unproved oil and natural gas properties. Approximately
$32.3 million
of the purchase price is included in accounts payable on the consolidated balance sheet as of December 31, 2016. This remaining amount will be paid when all the title issues related to the acquisition have been satisfied. The assets include
31
operated producing horizontal wells and approximately
35,500
net acres that directly offset the Company’s existing acreage in Reeves County, Texas. Of the net acres acquired,
1,250
net acres are subject to consents to assign, which are expected to be assigned in the first quarter of 2017. The Company operates approximately
90%
of, and has an approximate
90%
working interest in, this acreage. The Wolfcamp A and Wolfcamp C are producing horizons on this acreage and the Company believes that this acreage may be prospective for the Wolfcamp C and Avalon and Bone Spring shale formations.
In June 2016, the Company acquired undeveloped acreage and oil and gas producing properties located in Reeves County, Texas. Total cash consideration paid by the Company was
$33.0 million
, including usual and customary post-closing adjustments. Approximately
$15.4 million
was recorded as proved oil and natural gas properties. The assets include
four
operated producing horizontal wells and approximately
1,580
net acres that directly offset the Company’s existing acreage in Reeves County, Texas.
|
|
|
|
|
|
Predecessor
|
(in thousands)
|
June 3, 2016
|
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
|
|
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
In May 2016, the Company acquired unproved 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. The assets included approximately
875
net acres that directly offset the Company’s existing acreage.
2015 Acquisitions
On September 1, 2015, the Company acquired additional interests in proved and unproved oil and natural gas properties in the Delaware Basin. Total cash consideration paid by the Company was
$16.0 million
, net of closing adjustments.
On September 3, 2015, the Company 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 Company was
$6.4 million
, net of closing adjustments.
The Company allocated the final purchase prices to the acquired assets and liabilities based on fair value as of the respective acquisition dates, as summarized in the table below.
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
Acquisition #1
|
|
Acquisition #2
|
(in thousands)
|
September 1, 2015
|
|
September 3, 2015
|
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, the Company 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, the Company 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, the Company 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, the Company 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.
Note 4—Accounts Receivable, Accounts Payable and Accrued Expenses
Accounts receivable are comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
December 31, 2016
|
|
|
December 31, 2015
|
Oil and natural gas
|
$
|
11,596
|
|
|
|
$
|
5,789
|
|
Joint interest billings
|
2,942
|
|
|
|
1,514
|
|
Hedge settlements
|
194
|
|
|
|
3,956
|
|
Other
|
2
|
|
|
|
1,844
|
|
Allowance for doubtful accounts
|
—
|
|
|
|
(91)
|
|
Accounts receivable, net
|
$
|
14,734
|
|
|
|
$
|
13,012
|
|
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Accounts payable and accrued expenses are comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
December 31, 2016
|
|
|
December 31, 2015
|
Accounts payable
|
$
|
11,210
|
|
|
|
$
|
1,827
|
|
Accrued capital expenditures
|
24,038
|
|
|
|
11,700
|
|
Revenues payable
|
3,815
|
|
|
|
3,439
|
|
Payable to Silverback
|
32,293
|
|
|
|
—
|
|
Accrued underwriting fees
|
7,719
|
|
|
|
—
|
|
Other
|
7,025
|
|
|
|
3,019
|
|
Accounts payable and accrued expenses
|
$
|
86,100
|
|
|
|
$
|
19,985
|
|
Note 5—Long-Term Debt
Credit Agreement (Successor)
In connection with the consummation of the Business Combination, all indebtedness under CRP’s term loan and revolving credit facility was repaid in full. On October 11, 2016, CRP entered into a second amendment to the amended and restated credit agreement (the “second amendment”), which amends the amended and restated credit agreement, dated as of October 15, 2014, among CRP, each of the lenders from time to time party thereto and JPMorgan Chase Bank, N.A. as administrative agent (the “credit agreement”). CRP entered into the second amendment 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
225
to
325
basis points, 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 a third amendment to the amended and restated credit agreement (the “third amendment”), which further amends the credit agreement. CRP entered into this amendment to, among other things, increase the borrowing base thereunder 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 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.
Borrowings 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
225
to
325
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
125
to
225
basis points, depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee on unused amounts of its revolving credit facility of
50
basis points. 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: (1) incur additional indebtedness; (2) make investments and loans; (3) enter into mergers; (4) make or declare dividends; (5) enter into commodity hedges exceeding a specified percentage of its expected production; (6) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (7) incur liens; (8) sell assets; and (9) engage in transactions with affiliates.
CRP's credit agreement also requires it to maintain compliance with the following financial ratios: (1) 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 FASB ASC Topic 815,
Derivatives and Hedging
(“ASC 815”) 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 (2) a leverage ratio, which is the ratio of Total Funded Debt (as defined in CRP's
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
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
.
At
December 31, 2016
, there were
no
borrowings under the revolving credit facility. Outstanding letters of credit were
$0.4 million
, leaving
$249.6 million
in borrowing capacity under the revolving credit facility.
At
December 31, 2016
, the Company was in compliance with all required covenants.
Term Loan and Revolving Credit Facility (Predecessor)
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
October 10, 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
. Prior to the Business Combination, the borrowing base was
$140.0 million
.
On
October 10, 2016
, CRP had
$124.0 million
outstanding under its revolving credit facility and
$0.4 million
of letters of credit outstanding, leaving
$15.6 million
in borrowing capacity under the revolving credit facility.
The credit agreement also has customary covenants with which CRP was in compliance on
October 10, 2016
, prior to the Business Combination.
The term loan, net of unamortized deferred financing costs on the accompanying consolidated balance sheets as of
December 31, 2015
, consisted of the following:
|
|
|
|
|
|
Predecessor
|
(in thousands)
|
December 31, 2015
|
Term loan
|
$
|
65,000
|
|
Unamortized deferred financing costs
|
(351)
|
|
Term loan, net of unamortized deferred financing costs
|
$
|
64,649
|
|
Note 6—Income Taxes
As a result of the Business Combination, the Company became the sole managing member of CRP, and as a result, began consolidating the financial results of CRP. CRP is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, CRP is not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by CRP is passed through to and included in the taxable income or loss of its members, including the Company, on a pro rata basis. The Company is subject to U.S. federal income taxes, in addition to state and local income taxes with respect to its allocable share of any taxable income or loss of CRP, as well as any stand-alone income or loss generated by the Company.
Income tax benefit (expense) are included in the consolidated statements of operations are detailed below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
(in thousands)
|
|
|
|
2015
|
|
2014
|
Current taxes
|
|
|
|
|
|
|
|
|
Federal
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Deferred taxes
|
|
|
|
|
|
|
|
|
Federal
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
State
|
—
|
|
|
|
406
|
|
|
572
|
|
|
(1,524
|
)
|
|
—
|
|
|
|
406
|
|
|
572
|
|
|
(1,524
|
)
|
Income tax benefit (expense)
|
$
|
—
|
|
|
|
$
|
406
|
|
|
$
|
572
|
|
|
$
|
(1,524
|
)
|
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
A reconciliation of the statutory federal income tax expense to the income tax expense from continuing operations provided at December 31, 2016, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
(in thousands)
|
|
|
2015
|
|
2014
|
Income tax (benefit) expense at the federal statutory rate
|
$
|
(3,145
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State income taxes - net of federal income tax benefits
|
—
|
|
|
406
|
|
|
572
|
|
|
(1,524
|
)
|
Excess depletion
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Noncontrolling interest in partnership
|
273
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Nondeductible expenses
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Change in valuation allowance
|
2,868
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Income tax benefit (expense)
|
$
|
—
|
|
|
$
|
406
|
|
|
$
|
572
|
|
|
$
|
(1,524
|
)
|
The tax effects of temporary differences that give rise to significant positions of the deferred income tax assets and liabilities are presented below:
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
December 31, 2016
|
|
|
December 31, 2015
|
Deferred tax assets:
|
|
|
|
|
Net operating loss carryforwards
|
$
|
2,590
|
|
|
|
$
|
—
|
|
Capitalized intangible drilling cost
|
10,314
|
|
|
|
—
|
|
Equity-based compensation
|
467
|
|
|
|
—
|
|
Other assets
|
291
|
|
|
|
—
|
|
Total deferred tax assets
|
13,662
|
|
|
|
—
|
|
Deferred tax liabilities:
|
|
|
|
|
Investment in Centennial Resource Production, LLC
|
(8,514
|
)
|
|
|
—
|
|
Other liabilities
|
—
|
|
|
|
(2,361
|
)
|
Total deferred tax liabilities
|
(8,514
|
)
|
|
|
(2,361
|
)
|
|
|
|
|
|
Valuation allowance
|
(5,148
|
)
|
|
|
—
|
|
|
|
|
|
|
Net deferred tax asset (liabilities)
|
$
|
—
|
|
|
|
$
|
(2,361
|
)
|
For the period from
October 11, 2016, through December 31, 2016 (Successor)
, equity was debited
$5.6 million
in connection with the issuance of shares to a noncontrolling interest owner. No tax benefit was recorded in equity as a
$2.0 million
valuation allowance fully offset the attendant tax benefit.
As of
December 31, 2016
, the Company had approximately
$7.3 million
of federal net operating loss carryovers that commence expiry in 2035.
The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. It is currently estimated that the Company’s net deferred tax assets will not be utilized. Accordingly, a valuation allowance against the net deferred tax assets has been recorded at
December 31, 2016
.
The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon the examination by the Internal Revenue Service or other governmental agency. As of
December 31, 2016
, the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
uncertain tax positions during the next 12 months. Interest and penalties related to uncertain tax positions are reported in income tax expense.
The Company is subject to the following material taxing jurisdictions: U.S., Colorado and Texas. As of
December 31, 2016
, the Company has no current tax years under audit. The Company remains subject to examination for federal income taxes and state income taxes for tax years 2015 and 2016.
Note 7—Shareholders' and Owners' Equity
Shareholders’ Equity (Successor)
At
December 31, 2016
, the Company had authorized
621,000,000
shares of capital stock, consisting of (a)
620,000,000
shares of common stock, including (i)
600,000,000
shares of Class A Common Stock, (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.
On October 11, 2016, in connection with Business combination the Company issued and sold in private placements (i)
81,005,000
shares of Class A Common Stock to Riverstone Centennial Holdings, L.P. and (ii) the issuance and sale of
20,000,000
shares of Class A Common Stock to certain other accredited investors in a private placement, resulting in net cash proceeds of approximately
$1.0 billion
. The outstanding shares of Class B Common Stock, par value
$0.0001
per share, converted into shares of Class A Common Stock on a
one
-for-
one
basis in connection with the Business Combination. Additionally, the Company issued
20,000,000
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. Holders of Class C Common Stock, 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.
On December 28, 2016, in connection with the Silverback Acquisition, the Company 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 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 Investment Group LLC and (ii)
33,012,380
shares of the Company’s Class A Common Stock to certain other investors, resulting in net cash proceeds of approximately
$889.6 million
. The Company 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 the Company’s Class A Common Stock on a
250
-to-
one
basis (subject to certain adjustments for stock splits, stock dividends, reorganization, recapitalizations and the like) at such time as the Company receives stockholder approval for the issuance of such shares of Class A Common Stock in compliance with NASDAQ listing rules.
Class A Common Stock
The Company had
201,091,646
shares of Class A Common Stock outstanding as of December 31, 2016, consisting of (i)
50,000,000
shares of Class A Common Stock issued as part of Units in connection with the IPO, (ii)
12,500,000
shares of Class A Common Stock issued upon conversion of the Company’s Class B Common Stock, par value
$0.0001
per share, in connection with the Business Combination (iii)
101,005,000
shares of Class A Common Stock issued in private placements in connection with the Business Combination, (iv)
844,079
shares of Class A Common Stock issued upon the redemption of CRP Common Units and cancellation of shares of Class C Common Stock, (v)
36,485,970
shares of Class A Common Stock issued in private placements in connection with the Silverback Acquisition and (vi)
256,597
restricted shares of Class A Common Stock issued to the Company’s directors and executive officers. Additional shares of Class A Common Stock may be issued by the Company upon the exchange of CRP Common Units and cancellation of shares of Class C Common Stock pursuant to the A&R LLC Agreement (as defined below), the conversion of the Series B Preferred Stock and the exercise of the Company’s outstanding Warrants.
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 the
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Company’s 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
The Company had
19,155,921
shares of Class C Common Stock outstanding as of December 31, 2016, which represent the portion of the
20,000,000
shares of Class C Common Stock issued to the Centennial Contributors in connection with the Business Combination that had not been redeemed or exchanged as of such date.
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 the Company’s 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 its assets in the event of any voluntary or involuntary liquidation, dissolution or winding up of its 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 A&R LLC Agreement (as defined below). Holders of Class C Common Stock 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.
Preferred Stock
As of December 31, 2016, the Company had outstanding
one
share of Series A Preferred Stock, issued to CRD in connection with the Business Combination, and
104,400
shares of Series B Preferred Stock, issued and sold to certain affiliates of Riverstone in connection with the Silverback Acquisition.
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 the Company (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 the Company’s board of directors in connection with any vote of the Company’s stockholders for the election of directors, and the vote of CRD will be the only vote required to elect such nominee to the Company’s board of directors.
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 December 28, 2019, 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
ten
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 Company’s
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
board of directors. In the event of a voluntary or involuntary liquidation, dissolution or winding up of the Company, holders of the Series B Preferred Stock will first be entitled to receive the liquidation preference per share of
$0.0001
before any distribution of assets is made to holders of any junior securities.
The shares of Series B Preferred Stock are automatically convertible into shares of the Company’s Class A Common Stock on a
250
-to-
one
basis (subject to certain adjustments) at such time as the Company receives stockholder approval for the issuance of such shares of Class A Common Stock in compliance with NASDAQ listing rules.
Warrants
As of December 31, 2016, the Company had
24,666,643
warrants outstanding, consisting of
16,666,643
public warrants originally sold as part of the Units in the IPO and
8,000,000
Private Placement Warrants sold to the Company’s Sponsor in a private placement. Each whole warrant entitles the holder to purchase
one
whole share of Class A Common Stock for
$11.50
per share. The warrants became exercisable on March 1, 2017 and will expire
five
years after the completion of the Business Combination or earlier upon redemption or liquidation.
On March 1, 2017, the Company delivered a notice of redemption of the Public Warrants, announcing its intention to redeem any unexercised and outstanding Public Warrants on March 31, 2017 for
$0.01
per Public Warrant. As permitted under the warrant agreement that provides the terms of the Public Warrants, the notice of redemption requires all holders exercising their Public Warrants prior to March 31, 2017 to do so on a “cashless basis” and surrender their Public Warrants for a number of shares of Class A Common Stock equal to the product of the quotient equal to (i) the difference between
$11.50
and
$18.44
(the average last sale price of the Class A Common Stock for the ten trading days ending on February 24, 2017) divided by (ii)
$18.44
, or approximately
0.376
, multiplied by the number of Public Warrants held by such holder, rounded down to the nearest whole share. Assuming all warrants are exercised by holders, Centennial will issue approximately
6.27 million
shares of Class A Common Stock to the Public Warrant holders, resulting in a share count of approximately
253 million
shares outstanding, which includes Class A Common Stock shares, the shares of Series B Preferred Stock held by Riverstone (assuming conversion to Class A Common Stock on a
250
-to-
one
basis), and the shares of Class C Common Stock held by the Centennial Contributors. The Private Placement Warrants are non-redeemable so long as they are held by our Sponsor or its permitted transferees.
Noncontrolling Interest
As a result of the exchange of CRP Common Units (and corresponding shares of Class C Common Stock) for Class A Common Stock (discussed in
Note 12—Transactions with Related Parties
) on October 11, 2016, the Company’s ownership in CRP increased from
89.1%
to
89.6%
and the ownership of the other holders of CRP Common Units in CRP decreased from
10.9%
to
10.4%
. Because the increase in the Company’s ownership interest in CRP did not result in a change of control, the transaction was accounted for as an equity transaction under ASC Topic 810,
Consolidations
, which requires that any differences between the amount by which the carrying value of the Company’s basis in CRP and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest.
As a result of the December 28, 2016 private placements and the issuance of shares of Class A Common Stock and Series B Preferred Stock to the investors therein (discussed in
Note 12—Transactions with Related Parties
), the net proceeds of which were contributed by the Company to CRP, the Company’s ownership of CRP increased from
89.6%
to
92.2%
and the other holders of CRP Common Units decreased from
10.4%
to
7.8%
.
The Company has consolidated the financial position and results of operations of CRP and reflected that portion retained by the other holders of CRP Common Units as a noncontrolling interest.
The following table summarizes the noncontrolling interest income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
2014
|
Net loss attributable to noncontrolling interest
|
$
|
(904
|
)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
Owners’ Equity (Predecessor)
At October 10, 2016 (prior to the Business Combination), members included Centennial HoldCo, Celero and Follow-On, owning an approximate
61.2%
,
21.2%
and
17.6%
membership interest in Centennial OpCo, respectively. CRP has
two
classes of membership interests outstanding: Class A, which consist of membership interests held by CRD and Follow-On; and Class B, which consist of membership interests held by Celero. On October 10, 2016 CRP recorded a deemed contribution attributable to the consummation of the Business Combination, which resulted in a Fundamental Change with respect to the incentive units and
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
CRP recorded
$165.4 million
of compensation expense. Refer to
Note 7—Shareholders' and Owners' Equity
. Additionally, CRP recorded a deemed contribution of
$14.0 million
attributable to certain transaction costs related to the Business Combination paid by the Centennial Contributors. Refer to
Note 2—Business Combination
.
As of December 31, 2015, CRD 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
and has
no
remaining capital commitment.
In 2015 Follow-On contributed
$84.2 million
to Centennial OpCo in exchange for membership interests in Centennial CRP. In addition, CRD contributed approximately
$27.2 million
to CRP in exchange for additional membership interests in CRP.
Note 8—Equity Based Compensation
Equity based compensation (Successor)
The Company has recognized non-cash stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.
|
|
|
|
|
|
Successor
|
|
October 11, 2016
through
December 31, 2016
|
(in thousands)
|
Restricted stock awards
|
$
|
405
|
|
Stock option awards
|
928
|
|
Total equity based compensation expense
|
$
|
1,333
|
|
Equity Incentive Plan
On October 7, 2016, the stockholders of the Company approved the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”). An aggregate of
16,500,000
shares of Class A common stock will be available for issuance under the LTIP. The LTIP provides for 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.
Restricted Stock
The following table provides information about restricted stock awards granted in
2016
:
|
|
|
|
|
|
|
|
|
Successor
|
|
Awards
|
|
Weighted Average Grant-Date Fair Value
|
Service-based stock awards:
|
|
|
|
Outstanding as of October 11, 2016
|
—
|
|
|
$
|
—
|
|
Vested
|
—
|
|
|
$
|
—
|
|
Granted
|
256,597
|
|
|
$
|
20.03
|
|
Canceled
|
—
|
|
|
$
|
—
|
|
Outstanding as of December 31, 2016
|
256,597
|
|
|
$
|
20.03
|
|
Compensation cost for the service-based vesting restricted shares is based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period. Unrecognized compensation cost related to unvested restricted shares at December 31, 2016 was
$4.7 million
. The Company expects to recognize that cost over a weighted average period of
2.6
years.
Stock Options
Options that have been granted under the LTIP expire
ten
years from the grant date and have service-based vesting schedules of
three
years. The exercise price for an option under the LTIP is the closing price of the Company’s common stock as reported by NASDAQ on the date of grant.
Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
volatilities are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.
The following summarizes the options granted and related information, and the assumptions used to determine the fair value of those options.
|
|
|
|
|
|
Successor
|
|
October 11, 2016
through
December 31, 2016
|
Options granted
|
2,760,500
|
|
Weighted average grant-date fair value
|
$
|
5.93
|
|
Weighted average exercise price
|
$
|
14.67
|
|
Total fair value (in thousands)
|
$
|
16,375
|
|
Expected term
|
6
|
|
Expected stock volatility
|
40.0
|
%
|
Dividend yield
|
—
|
%
|
Risk-free interest rate
|
1.5
|
%
|
Information about outstanding stock options is summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
|
|
Weighted Average Exercise Price
|
|
Weighted Average Remaining Term
(in years)
|
|
Aggregate Intrinsic Value
(in thousands)
|
Outstanding as of October 11, 2016
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
—
|
|
Exercised
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
—
|
|
Granted
|
2,760,500
|
|
|
$
|
14.67
|
|
|
5.8
|
|
|
$
|
13,934
|
|
Forfeited
|
(25,000
|
)
|
|
$
|
14.52
|
|
|
5.8
|
|
|
$
|
130
|
|
Outstanding as of December 31, 2016
|
2,735,500
|
|
|
$
|
14.67
|
|
|
5.8
|
|
|
$
|
13,804
|
|
Exercisable as of December 31, 2016
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
The following summary reflects the status of non-vested stock options as of
December 31, 2016
and changes since the Business Combination on
October 11, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
|
|
Weighted Average Grant-Date Fair Value
|
|
Weighted Average Exercise Price
|
Non-vested as of October 11, 2016
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Vested
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Granted
|
2,760,500
|
|
|
$
|
5.93
|
|
|
$
|
14.67
|
|
Forfeited
|
(25,000
|
)
|
|
$
|
5.86
|
|
|
$
|
14.52
|
|
Non-vested as of December 31, 2016
|
2,735,500
|
|
|
$
|
5.93
|
|
|
$
|
14.67
|
|
As of
December 31, 2016
, there was
$15.3 million
of unrecognized compensation cost related to non-vested stock options. The Company expects to recognize that cost on a pro rata basis over a weighted average period of
2.8
years.
Equity based compensation (Predecessor)
Incentive Units
Certain employees of Centennial Resource Management, LLC, a wholly owned subsidiary of CRD at the time of grant, received an award of CRD and NGP Follow-On incentive units, or profits interests. 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
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 CRD and NGP Follow-Ons 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 equity; therefore, the incentive units are accounted for as liability awards under ASC 718, with compensation expense based on period-end fair value. The achievement of payout conditions is a performance condition that requires CRP 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. The consummation of the Business Combination resulted in a Fundamental Change with respect to the incentive units and CRP recorded
$165.4 million
of compensation expense. No incentive compensation expense was recorded at December 31, 2015 or 2014, because it was not probable that the performance criterion would be met.
Note 9—Derivative Instruments
The Company periodically uses derivative instruments to mitigate its exposure to a decline in commodity prices and the corresponding negative impact on cash flow available for reinvestment. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. Depending on changes in oil and natural gas futures markets and the Company’s view of underlying supply and demand trends, it may increase or decrease its hedging positions.
The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
2017
|
|
2018
|
Crude Oil Swaps:
|
|
|
|
Notional volume (Bbl)
|
675,250
|
|
|
36,500
|
|
Weighted average fixed price ($/Bbl)
|
$
|
50.41
|
|
|
$
|
55.95
|
|
Crude Oil Basis Swaps:
|
|
|
|
Notional volume (Bbl)
|
127,750
|
|
|
—
|
|
Weighted average fixed price ($/Bbl)
|
$
|
(0.20
|
)
|
|
$
|
—
|
|
Natural Gas Swaps:
|
|
|
|
Notional volume (MMBtu)
|
1,460,000
|
|
|
—
|
|
Weighted average fixed 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 Company 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 Company pays the difference. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the NYMEX index price and a local index price. The oil basis derivative contracts are settled based on the difference between the arithmetic average of WTI MIDLAND ARGUS and WTI ARGUS during the relevant calculation period. When the actual differential exceeds the fixed price provided by the basis swap contract, the Company receives the difference from the counterparty; when the differential is less than the fixed price provided by the basis swap contract, the Company pays the difference to the counterparty.
The Company’s commodity derivatives are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. The fair value of the commodity contracts was a net
liability
of
$5.0 million
and a net
asset
of
$21.1 million
as of
December 31, 2016
and
December 31, 2015
, respectively.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
The following tables below summarize the gross fair value of derivative assets and liabilities and the effect of netting on the consolidated balance sheets (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
December 31, 2016
|
|
Balance Sheet Classification
|
|
Gross Amounts
|
|
Netting Adjustments
|
|
Net Amounts Presented on the Consolidated Balance Sheets
|
Assets
|
|
|
|
|
|
|
|
Derivative instruments
|
Current assets
|
|
$
|
739
|
|
|
$
|
(308
|
)
|
|
$
|
431
|
|
Derivative instruments
|
Noncurrent assets
|
|
—
|
|
|
—
|
|
|
—
|
|
Total assets
|
|
|
$
|
739
|
|
|
$
|
(308
|
)
|
|
$
|
431
|
|
Liabilities
|
|
|
|
|
|
|
|
Derivative instruments
|
Current liabilities
|
|
$
|
5,669
|
|
|
$
|
(308
|
)
|
|
$
|
5,361
|
|
Derivative instruments
|
Noncurrent Liabilities
|
|
20
|
|
|
—
|
|
|
20
|
|
Total liabilities
|
|
|
$
|
5,689
|
|
|
$
|
(308
|
)
|
|
$
|
5,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
December 31, 2015
|
|
Balance Sheet Classification
|
|
Gross Amounts
|
|
Netting Adjustments
|
|
Net Amounts Presented on the Consolidated Balance Sheets
|
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 Company’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 Company’s consolidated and combined statements of operations. The derivative instruments are recorded at fair value on the 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
2014
|
(Loss) gain on derivative instruments
|
$
|
(1,548
|
)
|
|
|
$
|
(6,838
|
)
|
|
$
|
20,756
|
|
|
$
|
41,943
|
|
The Company is exposed to financial risks associated with its derivative contracts from non-performance by its counterparties. The Company 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 Company’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 Company may hedge with counterparties outside its bank group to obtain competitive terms and to spread counterparty risk.
Note 10—Fair Value Measurements
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Company 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
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 Company’s assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of
December 31, 2016
and
December 31, 2015
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
December 31, 2016
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
Commodity derivative liability, net(1)
|
$
|
—
|
|
|
$
|
4,950
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Predecessor
|
|
December 31, 2015
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
Commodity derivative asset, net(1)
|
$
|
—
|
|
|
$
|
21,113
|
|
|
$
|
—
|
|
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 Company 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 Company uses Level 2 inputs to measure the fair value of oil and natural gas commodity derivatives. The Company 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 Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
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 Company’s management at the time of the valuation. Refer to
Note 2—Business Combination
and
Note 3—Property Acquisitions and Dispositions
for additional information on the fair value of assets acquired during
2016
.
Other Financial Instruments
The carrying amounts of the Company’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 credit agreement approximate fair value because the variable interest rates are reflective of current market conditions.
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Note 11—Asset Retirement Obligations
The following table summarizes the changes in the Company’s asset retirement obligations for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31, 2015
|
(in thousands)
|
|
|
|
Asset retirement obligations, beginning of period
|
$
|
4,989
|
|
|
|
$
|
2,288
|
|
|
$
|
1,824
|
|
Liabilities incurred
|
187
|
|
|
|
174
|
|
|
133
|
|
Liabilities acquired
|
2,002
|
|
|
|
66
|
|
|
178
|
|
Liabilities settled
|
(1
|
)
|
|
|
(42
|
)
|
|
—
|
|
Accretion expense
|
49
|
|
|
|
134
|
|
|
139
|
|
Revision of estimated liabilities
|
—
|
|
|
|
32
|
|
|
14
|
|
Asset retirement obligations, end of period
|
$
|
7,226
|
|
|
|
$
|
2,652
|
|
|
$
|
2,288
|
|
AROs reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with the Company's oil and natural gas properties. Inherent in the fair value calculation of the ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance.
Note 12—Transactions with Related Parties
Founder Shares
On November 6, 2015, the Company’s Sponsor purchased
11,500,000
shares of Class B Common Stock, the founder shares, from the Company, for an aggregate purchase price of
$25,000
, or approximately
$0.002
per share. In February 2016, the Company’s Sponsor transferred
40,000
founder shares to each of the Company’s then independent directors (together with the Company’s Sponsor, the "initial stockholders") at their original purchase price. On February 24, 2016, the Company 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
12,937,000
founder shares. On April 8, 2016, following the expiration of the underwriters' remaining over-allotment option in connection with the Company’s IPO, the Company’s Sponsor forfeited
437,500
founder shares, so that the remaining
12,500,000
founder shares held by the initial stockholders would represent
20%
of the Company’s 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 the Company completes a liquidation, merger, stock exchange or other similar transaction that results in all of its stockholders having the right to exchange their shares of common stock for cash, securities or other property.
Administrative Support Agreement
On February 23, 2016, the Company entered into an administrative support agreement pursuant to which it agreed to pay an affiliate of its Sponsor a total of
$10,000
per month for office space, utilities and secretarial and administrative support. The Company paid the affiliate of the Sponsor
$70,000
for such services for the nine months ended September 30, 2016. Following the closing of the Business Combination, the Company no longer pays these monthly fees.
Private Placement Warrants
On February 29, 2016, the Company’s Sponsor purchased
8,000,000
Private Placement Warrants from the Company at a price of
$1.50
per whole warrant (
$12.0 million
in the aggregate) in a private placement that occurred simultaneously with the closing of the Company’s 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 the
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Company’s trust account along with the proceeds from its IPO. The Private Placement Warrants are non-redeemable and exercisable on a cashless basis so long as they are held by the Company’s Sponsor or its permitted transferees.
Related Party Loans
On November 6, 2015, the Company’s Sponsor agreed to loan it an aggregate of up to
$300,000
to cover expenses related to its 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 the Company’s IPO. On November 10, 2015, the Company borrowed
$150,000
under the 2015 Note, and it 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 the Company’s Sponsor.
On August 2, 2016, the Company issued an unsecured, non-interest bearing promissory note to its Sponsor (the “2016 Note”). The Company 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.
Exchange Right
On October 11, 2016, following the closing of the Business Combination, the Company issued
844,079
shares of its Class A Common Stock, par value
$0.0001
per share, to an accredited investor at the direction of members of CRP affiliated with such investor (the “CRP Members”), in exchange for
844,079
common membership interests in CRP (the “CRP Common Units”) held by certain Centennial Contributors. The exchange was effected in accordance with the Fifth Amended and Restated Limited Liability Company Agreement of CRP, which permits Centennial Contributors of CRP Common Units to exchange their CRP Common Units on a
one
-for-
one
basis for shares of Class A Common Stock. Upon the exchange of the CRP Common Units described above, the Company canceled
844,079
shares of its Class C Common Stock, par value
$0.0001
per share, held by the Centennial Contributors.
Amended and Restated Limited Liability Company Agreement of CRP
In connection with the closing of the Business Combination, on October 11, 2016, the Company 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.
On December 28, 2016 and March 20, 2017, in connection with the Silverback Acquisition, the A&R LLC Agreement was amended by Amendment No. 1 to the A&R LLC Agreement and Amendment No. 2 to the A&R LLC Agreement, respectively (the “CRP Amendments”). Pursuant to the CRP Amendments, 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 CRP Amendments, the Series B Preferred Units have limited voting rights and are entitled to participate with the CRP Common Units 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.
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 its Sponsor, certain of its 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 the Company’s 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 the Company 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 the Company 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Amended and Restated Registration Rights Agreement, the Company filed a Registration Statement on Form S-1 that was declared effective on November 21, 2016.
The holders also have certain “piggy-back” registration rights with respect to registration statements and rights to require the Company to register for resale such securities pursuant to Rule 415 under the Securities Act. However, the Registration Rights Agreement provides that the Company 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 the Company’s 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, or (C) the date on which the Company completes a liquidation, merger, capital stock exchange, reorganization or other similar transaction that results in all of its 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. The Company will bear the expenses incurred in connection with the filing of any such registration statements.
Subscription Agreements
In connection with the Business Combination, on July 21, 2016, the Company 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
$200.0 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
$810.0 million
.
In connection with the Silverback Acquisition, on November 27, 2016 (as amended on December 22, 2016), the Company 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
$430.0 million
. In addition, on December 2, 2016, the Company 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
$480.0 million
. The Company refers 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.
Customer and Supplier Relationships
NGP Affiliated Companies
In May 2016, the Company 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.
From time to time, the Company obtains services related to its drilling and completion activities from affiliates of NGP. In particular, the Company has paid the following amounts to the following affiliates of NGP for such services: (i) approximately
$0.5 million
during the year ended
December 31, 2016
to Cretic Energy Services, LLC (“Cretic”); and (ii) approximately
$3.3 million
during the year ended
December 31, 2016
to RockPile Energy Services, LLC. On September 8, 2016, Rockpile Energy Services, LLC, was purchased from NGP by an unrelated third party. At
December 31, 2016
, included in
Accounts payable and accrued expenses
was
$0.2 million
due to Cretic.
The Company is party to a
15
-year gas gathering agreement with PennTex Permian, LLC (“PennTex”), 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 Company’s gas. PennTex purchases the extracted natural gas liquids from the Company, net of gathering fees and an agreed
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
percentage of the actual proceeds from the sale of the residue natural gas and natural gas liquids. Net payments received from PennTex for the periods from
October 11, 2016, through December 31, 2016 (Successor)
and
January 1, 2016, through October 10, 2016 (Predecessor)
and the years ended
December 31, 2015
and
2014
were
$0.2 million
,
$1.0 million
,
$1.2 million
and
$2.2 million
, respectively. In the third quarter of 2016, PennTex sold its assets related to this agreement to an unrelated third party
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 13—Commitments and Contingencies
.
Riverstone Affiliated Companies
From time to time, the Successor obtains services related to its drilling and completion activities from affiliates of Riverstone. In particular, the Successor has paid the following amounts to the following affiliates of Riverstone for such services: (i) approximately $
8.2 million
during the year ended
December 31, 2016
to Liberty Oilfield Services, LLC (“Liberty”); and (ii) approximately $
1.4 million
during the year ended
December 31, 2016
to Permian Tank and Manufacturing, Inc. (“Permian”). At
December 31, 2016
, included in
Accounts payable and accrued expenses
was
$3.1 million
and
$0.4 million
due to Liberty and Permian, respectively.
Other Affiliated Companies
Mark G. Papa, our President, Chief Executive Officer and Chairman of the Board, serves as a director and Chairman of the Board of Oil States International, Inc., an energy services company publicly traded on the New York Stock Exchange (“Oil States”). From time to time, the Successor obtains services related to drilling and completion activities from Oil States. In particular, during the fiscal year ended
December 31, 2016
, the Successor paid approximately
$1.2 million
to Oil States. At
December 31, 2016
, included in
Accounts payable and accrued expenses
was
$0.2 million
due to Oil States.
Note 13—Commitments and Contingencies
Operating Leases and Other Commitments
The following is a schedule of the Company’s future minimum lease payments with commitments that have initial or remaining non-cancelable lease terms in excess of
one
year as of
December 31, 2016
:
|
|
|
|
|
|
|
|
Amount
|
Years ending December 31,
|
|
(in thousands)
|
2017
|
|
$
|
8,147
|
|
2018
|
|
814
|
|
2019
|
|
573
|
|
2020
|
|
134
|
|
2021
|
|
79
|
|
Thereafter
|
|
7,226
|
|
Total
|
|
$
|
16,973
|
|
Financing Obligation
In October 2014, the Company’s gas gathering agreement with PennTex was amended to construct an expansion of the gathering system and a receipt point. The Company reimbursed PennTex for the total cost of the expansion project. The Company paid a minimum fee of
$7,000
per day until PennTex recouped the capital outlay for the expansion project. At
December 31, 2016
, the financing obligation was paid in full. At
December 31, 2015
, a short-term liability of
$2.1 million
was in included in
Other current liabilities
on the consolidated balance sheets. For the periods from
October 11, 2016, through December 31, 2016 (Successor)
and
January 1, 2016, through October 10, 2016 (Predecessor)
and for the year ended
December 31, 2015
, the Company made payments, including interest, of
$0.1 million
,
$2.1 million
and
$1.7 million
, respectively.
Transportation and Gathering Agreement
In December 2015, the Company 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 Company agreed to dedicate and ship on the Transportation System all crude oil owned or controlled by the Company 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
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
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 Company or the transporter upon
60
days’ prior notice.
Purchase Agreement
In July 2016, the Company entered into a crude oil purchase agreement by which the Company 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 Company or the purchaser on
30
days’ prior notice. The price received by the Company 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.
Drilling Rig Contracts
As of
December 31, 2016
, the Company has
four
drilling rigs under contract. All of these contracts expire in 2017.
In light of the low commodity price environment, the Company curtailed its drilling activity during 2015. For the year-ended
December 31, 2015
, the Company 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 statements of operations.
Office Leases
The Company leases office space in Denver, Colorado, Midland, Texas, Sugar Land, Texas, and Pecos, Texas. The Company recognized rent expense of
$0.1 million
,
$0.4 million
,
$0.4 million
and
$0.5 million
for the periods from
October 11, 2016, through December 31, 2016
,
January 1, 2016, through October 10, 2016
, and for the years ended
December 31, 2015
and
December 31, 2014
, respectively.
Contingencies
In the ordinary course of business, the Company 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 Company’s financial position, results of operations or cash flows. Management is unaware of any pending litigation brought against the Company requiring the reserve of a contingent liability as of the date of these consolidated financial statements.
Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited)
Costs Incurred For Oil and Natural Gas Producing Activities
The following table sets forth the capitalized costs incurred in the Company’s oil and gas production, exploration, and development activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
(in thousands)
|
|
|
|
2015
|
|
2014
|
Acquisition costs:
|
|
|
|
|
|
|
|
|
Proved properties
|
$
|
561,251
|
|
|
|
$
|
16,386
|
|
|
$
|
14,268
|
|
|
$
|
5,758
|
|
Unproved properties
|
1,905,660
|
|
|
|
39,399
|
|
|
28,955
|
|
|
16,409
|
|
Development costs
|
44,602
|
|
|
|
53,512
|
|
|
87,452
|
|
|
324,802
|
|
Exploration costs
|
844
|
|
|
|
—
|
|
|
84
|
|
|
—
|
|
Total
|
$
|
2,512,357
|
|
|
|
$
|
109,297
|
|
|
$
|
130,759
|
|
|
$
|
346,969
|
|
Results of Oil and Natural Gas Producing Activities
The results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
(in thousands)
|
|
|
|
2015
|
|
2014
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil, natural gas and NGL sales
|
$
|
29,717
|
|
|
|
$
|
69,116
|
|
|
$
|
90,460
|
|
|
$
|
131,825
|
|
Costs:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
3,541
|
|
|
|
11,036
|
|
|
21,173
|
|
|
17,690
|
|
Severance and ad valorem taxes
|
1,636
|
|
|
|
3,696
|
|
|
5,021
|
|
|
6,875
|
|
Transportation, processing, gathering and other operating expenses
|
2,187
|
|
|
|
4,583
|
|
|
5,732
|
|
|
4,772
|
|
Depletion, amortization and accretion of asset retirement obligations
|
14,486
|
|
|
|
62,228
|
|
|
89,350
|
|
|
68,981
|
|
Abandonment expense and impairment of unproved properties
|
—
|
|
|
|
2,545
|
|
|
7,619
|
|
|
20,025
|
|
Exploration
|
844
|
|
|
|
—
|
|
|
84
|
|
|
—
|
|
Contract termination and rig stacking
|
—
|
|
|
|
—
|
|
|
2,387
|
|
|
—
|
|
Income tax expense (benefit)
|
—
|
|
|
|
(406
|
)
|
|
(572
|
)
|
|
1,524
|
|
Results of operations
|
$
|
7,023
|
|
|
|
$
|
(14,566
|
)
|
|
$
|
(40,334
|
)
|
|
$
|
11,958
|
|
Oil and Gas Reserve Quantities
The reserve estimates presented below were made in accordance with 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 Company’s proved oil and natural gas reserves at
December 31, 2016
,
2015
and
2014
were prepared by Netherland, Sewell & Associates, Inc. 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 average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month for the periods from
October 11, 2016, through December 31, 2016 (Successor)
and
January 1, 2016, through October 10, 2016 (Predecessor)
and for the years ended
December 31, 2015
and
2014
. 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”):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
|
|
|
|
2015
|
|
2014
|
Oil (per Bbl)
|
$
|
38.49
|
|
|
|
$
|
36.98
|
|
|
$
|
41.85
|
|
|
$
|
84.94
|
|
Gas (per Mcf)
|
0.98
|
|
|
|
1.24
|
|
|
1.71
|
|
|
4.70
|
|
NGLs (per Bbl)
|
14.59
|
|
|
|
13.28
|
|
|
13.94
|
|
|
22.70
|
|
The table below presents a summary of changes in the Company’s estimated proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016, through December 31, 2016
|
|
|
January 1, 2016, through October 10, 2016
|
|
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 period
|
30,091
|
|
|
36,801
|
|
|
4,506
|
|
|
|
23,199
|
|
|
32,442
|
|
|
3,851
|
|
Extensions and discoveries
|
7,063
|
|
|
12,219
|
|
|
1,225
|
|
|
|
5,851
|
|
|
6,410
|
|
|
773
|
|
Revisions of previous estimates
|
184
|
|
|
16,445
|
|
|
983
|
|
|
|
1,025
|
|
|
(1,521
|
)
|
|
(110
|
)
|
Purchases of reserves in place
|
9,651
|
|
|
83,992
|
|
|
5,152
|
|
|
|
1,600
|
|
|
2,130
|
|
|
245
|
|
Divestitures of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(523
|
)
|
|
(1,113
|
)
|
|
(96
|
)
|
|
|
(1,584
|
)
|
|
(2,660
|
)
|
|
(253
|
)
|
End of period
|
46,466
|
|
|
148,344
|
|
|
11,770
|
|
|
|
30,091
|
|
|
36,801
|
|
|
4,506
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
11,346
|
|
|
14,973
|
|
|
1,927
|
|
|
|
9,347
|
|
|
12,711
|
|
|
1,603
|
|
End of period
|
14,551
|
|
|
42,190
|
|
|
3,618
|
|
|
|
11,346
|
|
|
14,973
|
|
|
1,927
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
18,745
|
|
|
21,828
|
|
|
2,579
|
|
|
|
13,852
|
|
|
19,731
|
|
|
2,248
|
|
End of period
|
31,914
|
|
|
106,154
|
|
|
8,152
|
|
|
|
18,745
|
|
|
21,828
|
|
|
2,579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31, 2015
|
|
|
Year Ended December 31, 2014
|
|
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 period
|
19,850
|
|
|
27,414
|
|
|
1,551
|
|
|
|
18,510
|
|
|
6,968
|
|
|
525
|
|
Extensions and discoveries
|
9,444
|
|
|
11,927
|
|
|
1,432
|
|
|
|
16,122
|
|
|
22,575
|
|
|
1,127
|
|
Revisions of previous estimates
|
(5,109
|
)
|
|
(5,204
|
)
|
|
995
|
|
|
|
56
|
|
|
178
|
|
|
180
|
|
Purchases of reserves in place
|
844
|
|
|
1,363
|
|
|
204
|
|
|
|
162
|
|
|
192
|
|
|
23
|
|
Divestitures of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(13,572
|
)
|
|
(387
|
)
|
|
(69
|
)
|
Production
|
(1,830
|
)
|
|
(3,058
|
)
|
|
(331
|
)
|
|
|
(1,428
|
)
|
|
(2,112
|
)
|
|
(235
|
)
|
End of period
|
23,199
|
|
|
32,442
|
|
|
3,851
|
|
|
|
19,850
|
|
|
27,414
|
|
|
1,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
8,026
|
|
|
11,959
|
|
|
766
|
|
|
|
6,021
|
|
|
4,837
|
|
|
382
|
|
End of period
|
9,347
|
|
|
12,711
|
|
|
1,603
|
|
|
|
8,026
|
|
|
11,959
|
|
|
766
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period
|
11,823
|
|
|
15,455
|
|
|
785
|
|
|
|
12,489
|
|
|
2,131
|
|
|
143
|
|
End of period
|
13,852
|
|
|
19,731
|
|
|
2,248
|
|
|
|
11,823
|
|
|
15,455
|
|
|
785
|
|
Proved reserves at December 31, 2016 increased
104%
to
82,959
MBoe, compared to
40,730
MBoe at October 10, 2016.
During the period from
October 11, 2016, through December 31, 2016 (Successor)
, the Company acquired
28,801
MBoe of proved reserves. Refer to
Note 3—Property Acquisitions and Dispositions
. Additionally, the Company added
10,324
MBoe of proved reserves through extensions, primarily due to its drilling activity, as well as,
3,908
MBoe of revisions due to improved results in completion techniques and adjustments of natural gas and NGL treatment through the gas plants slightly offset by
805
MBoe of production.
Proved reserves at October 10, 2016 increased
25%
to
40,730
MBoe, compared to
32,457
MBoe at December 31, 2015.
During the period from
January 1, 2016, through October 10, 2016 (Predecessor)
, the Company acquired
2,200
MBoe of proved reserves. Refer to
Note 3—Property Acquisitions and Dispositions
. Additionally, the Company added
7,692
MBoe of
proved reserves through extensions, primarily due to its drilling activity, as well as
660
MBoe due to positive performance revisions, slightly offset by
2,280
MBoe of production.
Proved reserves at December 31, 2015 increased
25%
to
32,457
MBoe, compared to
25,970
MBoe at December 31, 2014.
During 2015, the Company added
12,864
MBoe of proved reserves through extensions, primarily due to its drilling activity.
During 2015, the Company 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 Company acquired
1,275
MBoe of proved reserves. Refer to
Note 3—Property Acquisitions and Dispositions
.
During 2014, the Company 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 Company divested of
13,706
MBoe of proved reserves. Refer to
Note 3—Property Acquisitions and Dispositions
.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. The estimated future net cash flows are then discounted at a rate of 10%.
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of its’ Predecessor’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations and no value may be assigned to probable or possible reserves.
The following table presents the Company’s standardized measure of discounted future net cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
|
Year Ended December 31,
|
(in thousands)
|
|
|
|
2015
|
|
2014
|
Future cash inflows
|
$
|
2,105,585
|
|
|
|
$
|
1,217,641
|
|
|
$
|
1,079,962
|
|
|
$
|
1,850,205
|
|
Future development costs
|
(482,162
|
)
|
|
|
(297,559
|
)
|
|
(277,837
|
)
|
|
(440,366
|
)
|
Future production costs
|
(640,306
|
)
|
|
|
(413,410
|
)
|
|
(450,058
|
)
|
|
(457,236
|
)
|
Future income tax expenses
|
(136,587
|
)
|
|
|
(5,614
|
)
|
|
(6,643
|
)
|
|
(10,834
|
)
|
Future net cash flows
|
846,530
|
|
|
|
501,058
|
|
|
345,424
|
|
|
941,769
|
|
10% discount to reflect timing of cash flows
|
(471,438
|
)
|
|
|
(291,345
|
)
|
|
(210,355
|
)
|
|
(575,886
|
)
|
Standardized measure of discounted future net cash flows
|
$
|
375,092
|
|
|
|
$
|
209,713
|
|
|
$
|
135,069
|
|
|
$
|
365,883
|
|
The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
(in thousands)
|
October 11, 2016
through
December 31, 2016
|
|
|
January 1, 2016
through
October 10, 2016
|
Standardized measure of discounted future net cash flows, beginning of period
|
$
|
209,713
|
|
|
|
$
|
135,069
|
|
Sales of oil, natural gas and NGLs, net of production costs
|
(22,354
|
)
|
|
|
(49,801
|
)
|
Purchase of minerals in place
|
127,842
|
|
|
|
10,145
|
|
Divestiture of minerals in place
|
—
|
|
|
|
—
|
|
Extensions and discoveries, net of future development costs
|
55,825
|
|
|
|
46,438
|
|
Change in estimated development costs
|
10,891
|
|
|
|
11,743
|
|
Net change in prices and production costs
|
(978
|
)
|
|
|
6,661
|
|
Change in estimated future development costs
|
571
|
|
|
|
28,998
|
|
Revisions of previous quantity estimates
|
20,190
|
|
|
|
3,673
|
|
Accretion of discount
|
4,753
|
|
|
|
11,319
|
|
Net change in income taxes
|
(47,990
|
)
|
|
|
(1,568
|
)
|
Net change in timing of production and other
|
16,629
|
|
|
|
7,036
|
|
Standardized measure of discounted future net cash flows, end of period
|
$
|
375,092
|
|
|
|
$
|
209,713
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
Year Ended December 31,
|
(in thousands)
|
2015
|
|
|
2014
|
Standardized measure of discounted future net cash flows, beginning of period
|
$
|
365,883
|
|
|
|
$
|
371,307
|
|
Sales of oil, natural gas and NGLs, net of production costs
|
(58,534
|
)
|
|
|
(102,488
|
)
|
Purchase of minerals in place
|
14,416
|
|
|
|
5,650
|
|
Divestiture of minerals in place
|
—
|
|
|
|
(242,344
|
)
|
Extensions and discoveries, net of future development costs
|
57,894
|
|
|
|
312,532
|
|
Change in estimated development costs
|
16,100
|
|
|
|
10,386
|
|
Net change in prices and production costs
|
(494,734
|
)
|
|
|
(3,027
|
)
|
Change in estimated future development costs
|
247,642
|
|
|
|
2,935
|
|
Revisions of previous quantity estimates
|
(51,342
|
)
|
|
|
924
|
|
Accretion of discount
|
37,517
|
|
|
|
13,561
|
|
Net change in income taxes
|
1,601
|
|
|
|
(2,762
|
)
|
Net change in timing of production and other
|
(1,374
|
)
|
|
|
(791
|
)
|
Standardized measure of discounted future net cash flows, end of period
|
$
|
135,069
|
|
|
|
$
|
365,883
|
|
Selected Quarterly Financial Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Successor
|
|
Periods Ended
|
|
|
Period Ended
|
(in thousands)
|
March 31
|
|
June 30
|
|
September 30
|
|
October 1, 2016
through
October 10, 2016
|
|
|
October 11, 2016
through
December 31, 2016
|
2016
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
15,121
|
|
|
$
|
23,347
|
|
|
$
|
27,321
|
|
|
$
|
3,327
|
|
|
|
$
|
29,717
|
|
Operating expenses
|
29,855
|
|
|
30,251
|
|
|
32,228
|
|
|
183,465
|
|
|
|
36,800
|
|
Gain (loss) on sale of oil and natural gas properties
|
(4
|
)
|
|
—
|
|
|
15
|
|
|
—
|
|
|
|
24
|
|
Operating loss
|
(14,738
|
)
|
|
(6,904
|
)
|
|
(4,892
|
)
|
|
(180,138
|
)
|
|
|
(7,059
|
)
|
Other income (expense)
|
277
|
|
|
(9,635
|
)
|
|
(242
|
)
|
|
(2,858
|
)
|
|
|
(1,926
|
)
|
Income tax expense (benefit)
|
—
|
|
|
406
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
Net loss
|
(14,461
|
)
|
|
(16,133
|
)
|
|
(5,134
|
)
|
|
(182,996
|
)
|
|
|
(8,081
|
)
|
Loss per share:
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
$
|
(0.05
|
)
|
Diluted
|
|
|
|
|
|
|
|
|
|
$
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
Quarters Ended
|
(in thousands)
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
2015
|
|
|
|
|
|
|
|
Revenues
|
$
|
24,416
|
|
|
$
|
22,431
|
|
|
$
|
21,893
|
|
|
$
|
21,720
|
|
Operating expenses
|
36,656
|
|
|
37,184
|
|
|
30,442
|
|
|
42,024
|
|
Gain (loss) on sale of oil and natural gas properties
|
2,675
|
|
|
4
|
|
|
9
|
|
|
(249
|
)
|
Operating loss
|
(9,565
|
)
|
|
(14,749
|
)
|
|
(8,540
|
)
|
|
(20,553
|
)
|
Other income (expense)
|
3,628
|
|
|
(7,922
|
)
|
|
11,866
|
|
|
6,938
|
|
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|
572
|
|
Net (loss) income
|
(5,937
|
)
|
|
(22,671
|
)
|
|
3,326
|
|
|
(13,043
|
)
|