SRC ENERGY INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited; in thousands, except share data)
|
|
|
|
|
|
|
|
|
ASSETS
|
September 30, 2018
|
|
December 31, 2017
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
19,236
|
|
|
$
|
48,772
|
|
Accounts receivable:
|
|
|
|
Oil, natural gas, and NGL sales
|
110,912
|
|
|
86,013
|
|
Trade
|
29,559
|
|
|
18,134
|
|
Other current assets
|
11,996
|
|
|
7,116
|
|
Total current assets
|
171,703
|
|
|
160,035
|
|
|
|
|
|
Property and equipment:
|
|
|
|
Oil and gas properties, full cost method:
|
|
|
|
Proved properties, net of accumulated depletion
|
1,364,116
|
|
|
970,584
|
|
Wells in progress
|
244,206
|
|
|
106,269
|
|
Unproved properties and land, not subject to depletion
|
748,695
|
|
|
793,669
|
|
Oil and gas properties, net
|
2,357,017
|
|
|
1,870,522
|
|
Other property and equipment, net
|
5,902
|
|
|
6,054
|
|
Total property and equipment, net
|
2,362,919
|
|
|
1,876,576
|
|
Goodwill
|
40,711
|
|
|
40,711
|
|
Other assets
|
3,599
|
|
|
2,242
|
|
Total assets
|
$
|
2,578,932
|
|
|
$
|
2,079,564
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS' EQUITY
|
|
|
|
Current liabilities:
|
|
|
|
Accounts payable and accrued expenses
|
$
|
171,951
|
|
|
$
|
74,672
|
|
Revenue payable
|
82,670
|
|
|
64,111
|
|
Production taxes payable
|
77,115
|
|
|
52,413
|
|
Asset retirement obligations
|
2,771
|
|
|
3,246
|
|
Commodity derivative liabilities
|
18,570
|
|
|
7,865
|
|
Total current liabilities
|
353,077
|
|
|
202,307
|
|
|
|
|
|
Revolving credit facility
|
115,000
|
|
|
—
|
|
Notes payable, net of issuance costs
|
539,050
|
|
|
538,186
|
|
Commodity derivative liabilities
|
1,671
|
|
|
—
|
|
Asset retirement obligations
|
48,951
|
|
|
28,376
|
|
Deferred taxes
|
18,076
|
|
|
—
|
|
Other liabilities
|
2,308
|
|
|
2,261
|
|
Total liabilities
|
1,078,133
|
|
|
771,130
|
|
|
|
|
|
Commitments and contingencies (See Note 15)
|
|
|
|
|
|
|
|
|
|
Shareholders' equity:
|
|
|
|
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding
|
—
|
|
|
—
|
|
Common stock - $0.001 par value, 400,000,000 and 300,000,000 shares authorized: 242,572,199 and 241,365,522 shares issued and outstanding as of September 30, 2018 and December 31, 2017, respectively
|
243
|
|
|
241
|
|
Additional paid-in capital
|
1,488,588
|
|
|
1,474,273
|
|
Retained earnings (deficit)
|
11,968
|
|
|
(166,080
|
)
|
Total shareholders' equity
|
1,500,799
|
|
|
1,308,434
|
|
|
|
|
|
Total liabilities and shareholders' equity
|
$
|
2,578,932
|
|
|
$
|
2,079,564
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements
SRC ENERGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; in thousands, except share and per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Oil, natural gas, and NGL revenues
|
$
|
160,978
|
|
|
$
|
103,593
|
|
|
$
|
455,298
|
|
|
$
|
222,419
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
Lease operating expenses
|
10,360
|
|
|
4,316
|
|
|
29,868
|
|
|
13,008
|
|
Transportation and gathering
|
1,994
|
|
|
838
|
|
|
5,729
|
|
|
1,136
|
|
Production taxes
|
12,824
|
|
|
10,083
|
|
|
41,325
|
|
|
21,013
|
|
Depreciation, depletion, and accretion
|
45,188
|
|
|
33,740
|
|
|
124,146
|
|
|
73,396
|
|
Unused commitment charge
|
—
|
|
|
—
|
|
|
—
|
|
|
669
|
|
General and administrative
|
10,685
|
|
|
8,484
|
|
|
29,691
|
|
|
24,289
|
|
Total expenses
|
81,051
|
|
|
57,461
|
|
|
230,759
|
|
|
133,511
|
|
|
|
|
|
|
|
|
|
Operating income
|
79,927
|
|
|
46,132
|
|
|
224,539
|
|
|
88,908
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
Commodity derivatives gain (loss)
|
(8,529
|
)
|
|
(2,383
|
)
|
|
(28,604
|
)
|
|
2,324
|
|
Interest expense, net of amounts capitalized
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Interest income
|
23
|
|
|
16
|
|
|
37
|
|
|
47
|
|
Other income
|
125
|
|
|
83
|
|
|
152
|
|
|
385
|
|
Total other income (expense)
|
(8,381
|
)
|
|
(2,284
|
)
|
|
(28,415
|
)
|
|
2,756
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
71,546
|
|
|
43,848
|
|
|
196,124
|
|
|
91,664
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
8,918
|
|
|
—
|
|
|
18,076
|
|
|
—
|
|
Net income
|
$
|
62,628
|
|
|
$
|
43,848
|
|
|
$
|
178,048
|
|
|
$
|
91,664
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
Basic
|
$
|
0.26
|
|
|
$
|
0.22
|
|
|
$
|
0.74
|
|
|
$
|
0.46
|
|
Diluted
|
$
|
0.26
|
|
|
$
|
0.22
|
|
|
$
|
0.73
|
|
|
$
|
0.46
|
|
|
|
|
|
|
|
|
|
Weighted-average shares outstanding:
|
|
|
|
|
|
|
|
Basic
|
242,536,781
|
|
|
200,881,447
|
|
|
242,184,348
|
|
|
200,807,436
|
|
Diluted
|
243,560,046
|
|
|
201,460,915
|
|
|
243,207,058
|
|
|
201,326,129
|
|
The accompanying notes are an integral part of these condensed consolidated financial statements
SRC ENERGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited; in thousands)
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
Cash flows from operating activities:
|
|
|
|
Net income
|
$
|
178,048
|
|
|
$
|
91,664
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
Depletion, depreciation, and accretion
|
124,146
|
|
|
73,396
|
|
Settlement of asset retirement obligation
|
(5,234
|
)
|
|
(4,077
|
)
|
Provision for deferred taxes
|
18,076
|
|
|
—
|
|
Stock-based compensation expense
|
9,347
|
|
|
8,390
|
|
Mark-to-market of commodity derivative contracts:
|
|
|
|
Total loss (gain) on commodity derivatives contracts
|
28,604
|
|
|
(2,324
|
)
|
Cash settlements on commodity derivative contracts
|
(13,263
|
)
|
|
778
|
|
Changes in operating assets and liabilities
|
3,830
|
|
|
(25,010
|
)
|
Net cash provided by operating activities
|
343,554
|
|
|
142,817
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
Acquisition of oil and gas properties and leaseholds
|
(129,069
|
)
|
|
(62,562
|
)
|
Capital expenditures for drilling and completion activities
|
(331,702
|
)
|
|
(305,636
|
)
|
Other capital expenditures
|
(26,439
|
)
|
|
(11,198
|
)
|
Acquisition of land and other property and equipment
|
(2,914
|
)
|
|
(4,058
|
)
|
Proceeds from sales of oil and gas properties and other
|
1,233
|
|
|
77,017
|
|
Net cash used in investing activities
|
(488,891
|
)
|
|
(306,437
|
)
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
Proceeds from the employee exercise of stock options
|
4,302
|
|
|
114
|
|
Payment of employee payroll taxes in connection with shares withheld
|
(1,106
|
)
|
|
(631
|
)
|
Proceeds from the revolving credit facility
|
115,000
|
|
|
170,000
|
|
Principal repayments on the revolving credit facility
|
—
|
|
|
(20,000
|
)
|
Fees on debt and equity issuances and revolving credit facility amendments
|
(2,173
|
)
|
|
(1,372
|
)
|
Capital lease payments
|
(222
|
)
|
|
—
|
|
Net cash provided by financing activities
|
115,801
|
|
|
148,111
|
|
|
|
|
|
Net decrease in cash, cash equivalents, and restricted cash
|
(29,536
|
)
|
|
(15,509
|
)
|
|
|
|
|
Cash, cash equivalents, and restricted cash at beginning of period
|
48,772
|
|
|
36,834
|
|
|
|
|
|
Cash, cash equivalents, and restricted cash at end of period
|
$
|
19,236
|
|
|
$
|
21,325
|
|
Supplemental Cash Flow Information (See Note
16
)
The accompanying notes are an integral part of these condensed consolidated financial statements
SRC ENERGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
|
|
1
.
|
Organization and Summary of Significant Accounting Policies
|
Organization
:
SRC Energy Inc.
is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural gas liquids ("NGLs"), primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado. The Company’s common stock is listed and traded on the NYSE American under the symbol "SRCI."
Basis of Presentation:
The Company operates in
one
business segment, and all of its operations are located in the United States of America.
At the directive of the Securities and Exchange Commission ("SEC") to use "plain English" in public filings, the Company will use such terms as "we," "our," "us," or the "Company" in place of
SRC Energy Inc
. When such terms are used in this manner throughout this document, they are in reference only to the corporation,
SRC Energy Inc.,
and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.
The condensed consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The Company prepares its condensed consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”).
Interim Financial Information:
The unaudited condensed consolidated interim financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the SEC as promulgated in Rule 10-01 of Regulation S-X. The condensed consolidated balance sheet as of
December 31, 2017
was derived from the Company's annual consolidated financial statements included within its Annual Report on Form 10-K for the year ended
December 31, 2017
as filed with the SEC on February 21, 2018. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been condensed or omitted pursuant to such SEC rules and regulations. The Company believes that the disclosures included are adequate to make the information presented not misleading and recommends that these condensed financial statements be read in conjunction with the audited financial statements and notes thereto for the year ended
December 31, 2017
.
In our opinion, the unaudited condensed consolidated financial statements contained herein reflect all adjustments, consisting solely of normal recurring items, which are necessary for the fair presentation of the Company's financial position, results of operations, and cash flows on a basis consistent with that of its prior audited financial statements. However, the results of operations for interim periods may not be indicative of results to be expected for the full fiscal year.
Major Customers:
The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of our oil, natural gas, and NGL revenues (“major customers”) for each of the periods presented are shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
Major Customers
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Company A
|
|
23%
|
|
30%
|
|
13%
|
|
27%
|
Company B
|
|
21%
|
|
27%
|
|
19%
|
|
26%
|
Company C
|
|
14%
|
|
13%
|
|
28%
|
|
15%
|
Company D
|
|
14%
|
|
*
|
|
11%
|
|
*
|
Company E
|
|
14%
|
|
*
|
|
16%
|
|
*
|
* less than 10%
Based on the current demand for oil and natural gas, the availability of other buyers, the multiple contracts for sales of our products, and the Company having the option to sell to other buyers if conditions warrant, the Company believes
that the loss of our existing customers or individual contracts would not have a material adverse effect on us. Our oil and natural gas production is a commodity with a readily available market, and we sell our products under many distinct contracts. In addition, there are several oil and natural gas purchasers and processors within our area of operations to whom our production could be sold.
Accounts receivable consist primarily of receivables from oil, natural gas, and NGL sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.
Customers with balances greater than
10%
of total receivable balances as of each of the periods presented are shown in the following table (these companies do not necessarily correspond to those presented above):
|
|
|
|
|
|
|
|
As of
|
|
As of
|
Major Customers
|
|
September 30, 2018
|
|
December 31, 2017
|
Company A
|
|
23%
|
|
26%
|
Company B
|
|
16%
|
|
16%
|
Company C
|
|
14%
|
|
23%
|
Company D
|
|
14%
|
|
*
|
Company E
|
|
*
|
|
11%
|
* less than 10%
The Company operates exclusively within the United States of America, and except for cash and cash equivalents, all of the Company’s assets are utilized in, and all of our revenues are derived from, the oil and gas industry.
Recently Adopted Accounting Pronouncements:
In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 (collectively with ASU 2014-09, the "Revenue ASUs") to clarify principal versus agent considerations. The Revenue ASUs allow for the use of either the full or modified retrospective transition method, and the standard became effective for annual reporting periods beginning after December 15, 2017 including interim periods within that period. The Company adopted the guidance using the modified retrospective method with the effective date of January 1, 2018. The Company did not record a cumulative-effect adjustment to the opening balance of retained earnings as no adjustment was necessary. The adoption of the Revenue ASUs did not impact net income or cash flows. See Note
14
for the new disclosures required by the Revenue ASUs.
Recently Issued Accounting Pronouncements:
We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us.
In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" ("ASU 2016-02"), which establishes a comprehensive new lease standard designed to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous US GAAP. ASU 2016-02 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We are currently evaluating the impact of the adoption of this standard on our financial statements.
There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.
|
|
2
.
|
Property and Equipment
|
The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
As of
|
|
As of
|
|
September 30, 2018
|
|
December 31, 2017
|
Oil and gas properties, full cost method:
|
|
|
|
Costs of proved properties:
|
|
|
|
Producing and non-producing
|
$
|
2,148,278
|
|
|
$
|
1,629,789
|
|
Less, accumulated depletion and full cost ceiling impairments
|
(784,162
|
)
|
|
(659,205
|
)
|
Subtotal, proved properties, net
|
1,364,116
|
|
|
970,584
|
|
|
|
|
|
Costs of wells in progress
|
244,206
|
|
|
106,269
|
|
|
|
|
|
Costs of unproved properties and land, not subject to depletion:
|
|
|
|
Lease acquisition and other costs
|
739,303
|
|
|
786,469
|
|
Land
|
9,392
|
|
|
7,200
|
|
Subtotal, unproved properties and land
|
748,695
|
|
|
793,669
|
|
|
|
|
|
Costs of other property and equipment:
|
|
|
|
Other property and equipment
|
9,462
|
|
|
8,134
|
|
Less, accumulated depreciation
|
(3,560
|
)
|
|
(2,080
|
)
|
Subtotal, other property and equipment, net
|
5,902
|
|
|
6,054
|
|
|
|
|
|
Total property and equipment, net
|
$
|
2,362,919
|
|
|
$
|
1,876,576
|
|
The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. At
September 30, 2018
and
2017
, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and
no
impairments were necessary.
Capitalized Overhead:
A portion of the Company’s overhead expenditures are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenditures, in the amounts shown in the table below, were capitalized in the full cost pool (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Capitalized overhead
|
$
|
3,129
|
|
|
$
|
2,518
|
|
|
$
|
9,522
|
|
|
$
|
7,729
|
|
3
. Acquisitions
September 2018 Acquisition and Swap
In September 2018, the Company completed the purchase of vertical and horizontal wells in the Greeley-Crescent development area in Weld County, Colorado for
$64.1 million
in cash and the assumption of certain liabilities for a total purchase price of
$96.8 million
. This purchase was contemplated as part of the GCII Acquisition discussed below in "‑December 2017 Acquisition." The effective date of this part of the transaction was September 1, 2018. The transaction was accounted for as an asset acquisition under ASC 805,
Business Combinations
, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date of September 27, 2018.
In September 2018, we completed a trade with another party of approximately
2,500
net acres. This transaction further enhances the contiguous nature of the Company's acreage position.
August 2018 Acquisition
In August 2018, the Company completed the purchase of leasehold acreage and associated non-operated production for
$37.6 million
in cash and the assumption of certain liabilities for a total purchase price of
$38.0 million
. The acreage increased our working interest in existing operations and planned wells. The transaction was accounted for as an asset acquisition under ASC 805,
Business Combinations
, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date of August 3, 2018.
December 2017 Acquisition
In December 2017, the Company completed the purchase of approximately
30,200
net acres and the associated non-operated production in the Greeley-Crescent development area in Weld County, Colorado for
$576.4 million
in cash and the assumption of certain liabilities for a total purchase price of
$577.5 million
("GCII Acquisition"). The purchase price has been allocated as
$60.8 million
to proved oil and gas properties and
$516.7 million
to unproved oil and gas properties. The effective date of this part of the transaction was November 1, 2017. The transaction was accounted for as an asset acquisition under ASC 805,
Business Combinations
, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date of December 15, 2017.
|
|
4
.
|
Depletion, depreciation, and accretion ("DD&A")
|
DD&A consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Depletion of oil and gas properties
|
$
|
44,230
|
|
|
$
|
32,944
|
|
|
$
|
121,259
|
|
|
$
|
71,389
|
|
Depreciation and accretion
|
958
|
|
|
796
|
|
|
2,887
|
|
|
2,007
|
|
Total DD&A Expense
|
$
|
45,188
|
|
|
$
|
33,740
|
|
|
$
|
124,146
|
|
|
$
|
73,396
|
|
Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter.
|
|
5
.
|
Asset Retirement Obligations
|
Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, remediate the well, and reclaim the drilling site to its original use. The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in regulations. Changes in estimates are reflected in the obligations as they occur. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost. The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands):
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
Asset retirement obligations, December 31, 2017
|
$
|
31,622
|
|
Obligations incurred with development activities
|
1,488
|
|
Obligations assumed with acquisitions
|
26,150
|
|
Accretion expense
|
1,406
|
|
Obligations discharged with asset retirements and divestitures
|
(8,944
|
)
|
Asset retirement obligation, September 30, 2018
|
$
|
51,722
|
|
Less, current portion
|
(2,771
|
)
|
Long-term portion
|
$
|
48,951
|
|
|
|
6
.
|
Revolving Credit Facility
|
On April 2, 2018, the Company entered into a second amended and restated credit agreement (the “Restated Credit Agreement”) with certain banks and other lenders. The Restated Credit Agreement provides a revolving credit facility (sometimes referred to as the "Revolver") and a
$25 million
swingline facility with a maturity date of
April 2, 2023
. The Revolver is available for working capital for exploration and production operations, acquisitions of oil and gas properties, and general corporate purposes and to support letters of credit. At
September 30, 2018
, the terms of the Revolver provided for up to
$1.5 billion
in borrowings, an aggregate elected commitment of
$450 million
, and a borrowing base limitation of
$550 million
. As of
September 30, 2018
and
December 31, 2017
, the outstanding principal balance was
$115.0 million
and
nil
, respectively. At
September 30, 2018
, the Company had
no
letters of credit issued.
In October 2018, the lenders under the Revolver completed their semi-annual redetermination of our borrowing base. The borrowing base was increased from
$550 million
to
$650 million
, and we increased our aggregate elected commitment from
$450 million
to
$500 million
.
Interest under the Revolver accrues monthly at a variable rate. For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or LIBOR plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the
nine months ended September 30, 2018
and
2017
was
4.0%
and
3.3%
, respectively.
Certain of the Company’s assets, including substantially all of its producing wells and developed oil and gas leases, have been designated as collateral under the Restated Credit Agreement. The amount available to be borrowed is subject to scheduled redeterminations on a semi-annual basis. If certain events occur or if the bank syndicate or the Company so elects in certain circumstances, an unscheduled redetermination could be undertaken.
The Restated Credit Agreement contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of the projected production from proved developed producing or total proved reserves as reflected in the most recently completed reserve report.
Furthermore, the Restated Credit Agreement requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to
4.0
to 1.0 as of the last day of any fiscal quarter or (b) permit its ratio of current assets to current liabilities, each as defined in the agreement, to be less than
1.0
to 1.0 as of the last day of any fiscal quarter. As of
September 30, 2018
, the most recent compliance date, the Company was in compliance with these loan covenants and expects to remain in compliance throughout the next 12-month period.
2025 Senior Notes
In November 2017, the Company issued
$550 million
aggregate principal amount of
6.25%
Senior Notes due 2025 (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at
6.25%
and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017. The net proceeds from the sale of the 2025 Senior Notes were
$538.1 million
after deductions of
$11.9 million
for expenses and underwriting discounts and commissions.
The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of
6.6%
.
The net proceeds were used to fund the GCII Acquisition as discussed further in Note
3
, to repay our previously outstanding senior notes due 2021, and to pay off the outstanding Revolver balance
.
At any time prior to December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to
100%
of the principal amount plus an Applicable Premium (as defined in the Indenture) and accrued and unpai
d interest. On and after December 1, 2020, the Company may redeem all or a part of the 2025 Senior Notes at a redemption price equal to a specified percentage of the principal amount of the redeemed notes
(
104.688%
for 2020,
103.125%
for 2021,
101.563%
for 2022,
and
100%
for 2023 and thereafter,
during the twelve-month period beginning on December 1 of each applicable year), plus accrued and unpaid interest. Additionally, prior to December 1, 2020, the Company can, on one or more occasions, redeem up to
35%
of the principal amount of the 2025 Senior Notes with all or a portion of the net cash proceeds of one or more Equity Offerings (as defined in the Indenture) at a redemption price equal to
106.25%
of the principal amount of the redeemed notes, plus accrued and unpaid interest, subject to certain conditions.
The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.
The indenture governing the 2025 Senior Notes provides that, in certain circumstances, the notes will be guaranteed by one or more subsidiaries of the Company, in which case such guarantee would be made on a full and unconditional and joint and several senior unsecured basis.
A
s of
September 30, 2018
, the most recent compliance date, the C
ompany was in compliance with these covenants and expects to remain in compliance throughout the next 12-month period.
|
|
8
.
|
Commodity Derivative Instruments
|
The Company has entered into commodity derivative instruments as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver.
The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with
seven
counterparties.
Five
of the counterparties are lenders in the Restated Credit Agreement. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.
The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying condensed consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses are recorded in the condensed consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in it making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s condensed consolidated statements of cash flows.
The Company’s commodity derivative contracts as of
September 30, 2018
are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement Period
|
|
Derivative
Instrument
|
|
Volumes
(Bbls per day)
|
|
Weighted-Average
Floor Price
|
|
Weighted-Average Ceiling Price
|
Crude Oil - NYMEX WTI
|
|
|
|
|
|
|
|
|
Oct 1, 2018 - Dec 31, 2018
|
|
Collar
|
|
10,000
|
|
|
$
|
43.63
|
|
|
$
|
61.29
|
|
Jan 1, 2019 - Dec 31, 2019
|
|
Collar
|
|
6,000
|
|
|
$
|
55.00
|
|
|
$
|
74.31
|
|
|
|
|
|
|
|
|
|
|
Settlement Period
|
|
Derivative
Instrument
|
|
Volumes
(MMBtu per day)
|
|
Weighted-Average
Floor Price
|
|
Weighted-Average Ceiling Price
|
Natural Gas - CIG Rocky Mountain
|
|
|
|
|
|
|
|
|
Oct 1, 2018 - Dec 31, 2018
|
|
Collar
|
|
15,000
|
|
|
$
|
2.25
|
|
|
$
|
2.82
|
|
|
|
|
|
|
|
|
|
|
Settlement Period
|
|
Derivative
Instrument
|
|
Volumes
(MMBtu per day)
|
|
Fixed Basis Difference
|
|
|
Natural Gas - CIG Rocky Mountain
|
|
|
|
|
|
|
|
|
Jan 1, 2019 - Dec 31, 2019
|
|
Swap
|
|
10,000
|
|
|
$
|
(0.79
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Settlement Period
|
|
Derivative
Instrument
|
|
Volumes
(Bbls per day)
|
|
Weighted-Average Fixed Price
|
|
|
Propane - Mont Belvieu
|
|
|
|
|
|
|
|
|
Oct 1, 2018 - Dec 31, 2018
|
|
Swap
|
|
1,000
|
|
|
$
|
33.60
|
|
|
|
Jan 1, 2019 - Dec 31, 2019
|
|
Swap
|
|
2,000
|
|
|
$
|
37.52
|
|
|
|
Subsequent to
September 30, 2018
, the Company added the following positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement Period
|
|
Derivative
Instrument
|
|
Volumes
(MMBtu per day)
|
|
Weighted-Average Fixed Basis Difference
|
|
|
Natural Gas - CIG Rocky Mountain
|
|
|
|
|
|
|
|
|
Nov 1, 2018 - Dec 31, 2018
|
|
Swap
|
|
50,000
|
|
|
$
|
(0.21
|
)
|
|
|
Jan 1, 2019 - Dec 31, 2019
|
|
Swap
|
|
20,000
|
|
|
$
|
(0.74
|
)
|
|
|
Offsetting of Derivative Assets and Liabilities
As of
September 30, 2018
and
December 31, 2017
, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its condensed consolidated balance sheets.
The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying condensed consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 30, 2018
|
Underlying
|
|
Balance Sheet
Location
|
|
Gross Amounts of Recognized Assets and Liabilities
|
|
Gross Amounts Offset in the
Balance Sheet
|
|
Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
|
Commodity derivative contracts
|
|
Current assets
|
|
$
|
1,740
|
|
|
$
|
(1,740
|
)
|
|
$
|
—
|
|
Commodity derivative contracts
|
|
Noncurrent assets
|
|
1,078
|
|
|
(1,078
|
)
|
|
—
|
|
Commodity derivative contracts
|
|
Current liabilities
|
|
20,310
|
|
|
(1,740
|
)
|
|
18,570
|
|
Commodity derivative contracts
|
|
Noncurrent liabilities
|
|
$
|
2,749
|
|
|
$
|
(1,078
|
)
|
|
$
|
1,671
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
Underlying
|
|
Balance Sheet
Location
|
|
Gross Amounts of Recognized Assets and Liabilities
|
|
Gross Amounts Offset in the
Balance Sheet
|
|
Net Amounts of Assets and Liabilities Presented in the
Balance Sheet
|
Commodity derivative contracts
|
|
Current assets
|
|
$
|
1,960
|
|
|
$
|
(1,960
|
)
|
|
$
|
—
|
|
Commodity derivative contracts
|
|
Noncurrent assets
|
|
—
|
|
|
—
|
|
|
—
|
|
Commodity derivative contracts
|
|
Current liabilities
|
|
9,825
|
|
|
(1,960
|
)
|
|
7,865
|
|
Commodity derivative contracts
|
|
Noncurrent liabilities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
The amount of gain (loss) recognized in the condensed consolidated statements of operations related to derivative financial instruments was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Realized gain (loss) on commodity derivatives
|
$
|
(8,273
|
)
|
|
$
|
116
|
|
|
$
|
(16,228
|
)
|
|
$
|
(26
|
)
|
Unrealized gain (loss) on commodity derivatives
|
(256
|
)
|
|
(2,499
|
)
|
|
(12,376
|
)
|
|
2,350
|
|
Total gain (loss)
|
$
|
(8,529
|
)
|
|
$
|
(2,383
|
)
|
|
$
|
(28,604
|
)
|
|
$
|
2,324
|
|
Realized gains and losses represent the monthly settlement of derivative contracts at their scheduled maturity date, net of the previously incurred premiums attributable to settled commodity contracts. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Monthly settlement
|
$
|
(8,273
|
)
|
|
$
|
376
|
|
|
$
|
(16,228
|
)
|
|
$
|
927
|
|
Previously incurred premiums attributable to settled commodity contracts
|
—
|
|
|
(260
|
)
|
|
—
|
|
|
(953
|
)
|
Total realized loss
|
$
|
(8,273
|
)
|
|
$
|
116
|
|
|
$
|
(16,228
|
)
|
|
$
|
(26
|
)
|
Credit Related Contingent Features
As of
September 30, 2018
,
five
of the
seven
counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the sixth and seventh counterparties, which are not lenders under the credit facility, is unsecured and does not require the posting of collateral.
|
|
9
.
|
Fair Value Measurements
|
ASC 820,
Fair Value Measurements and Disclosure
, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
|
|
•
|
Level 1: Quoted prices available in active markets for identical assets or liabilities;
|
|
|
•
|
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and
|
|
|
•
|
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.
|
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The Company’s non-recurring fair value measurements include unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through certain asset acquisitions. Please refer to Notes
2
,
3
, and
5
for further discussion of unproved properties, asset acquisitions, and asset retirement obligations, respectively.
The acquisition of a group of assets in certain asset acquisitions requires fair value estimates for assets acquired and liabilities assumed. The fair value of assets and liabilities acquired is calculated using a net discounted cash flow approach for the proved producing, proved undeveloped, probable, and possible properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and natural gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, the fair value is determined using market comparables.
The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rates, and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Notes
3
and
5
for additional information.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at September 30, 2018
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Financial assets and liabilities:
|
|
|
|
|
|
|
|
Commodity derivative asset
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Commodity derivative liability
|
$
|
—
|
|
|
$
|
20,241
|
|
|
$
|
—
|
|
|
$
|
20,241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2017
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Financial assets and liabilities:
|
|
|
|
|
|
|
|
Commodity derivative asset
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Commodity derivative liability
|
$
|
—
|
|
|
$
|
7,865
|
|
|
$
|
—
|
|
|
$
|
7,865
|
|
Commodity Derivative Instruments
The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At
September 30, 2018
, derivative instruments utilized by the Company consist of swaps and collars. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued based on several factors including public indices, the instruments themselves are traded with third-party counterparties. As such, the Company has classified these instruments as Level 2.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, accounts receivable, and accounts payable are representative of their fair values due to their short-
term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.
The fair value of the notes payable is estimated to be
$514.3 million
at
September 30, 2018
. The Company determined the fair value of its notes payable at
September 30, 2018
by using observable market-based information for these debt instruments. The Company has classified the notes payable as Level 1.
The components of interest expense are (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Revolving bank credit facility
|
$
|
376
|
|
|
$
|
1,016
|
|
|
$
|
461
|
|
|
$
|
1,286
|
|
Notes payable
|
8,593
|
|
|
1,800
|
|
|
25,781
|
|
|
5,400
|
|
Amortization of issuance costs and other
|
905
|
|
|
1,090
|
|
|
2,905
|
|
|
2,267
|
|
Less: interest capitalized
|
(9,874
|
)
|
|
(3,906
|
)
|
|
(29,147
|
)
|
|
(8,953
|
)
|
Interest expense, net of amounts capitalized
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
11
.
|
Equity and Stock-Based Compensation
|
Equity
At the 2018 annual meeting of shareholders of the Company held on May 18, 2018, the shareholders approved the Third Amended and Restated Articles of Incorporation of the Company to increase the number of authorized shares of common stock of the Company from
300,000,000
to
400,000,000
.
Stock-Based Compensation
In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant-date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting period"). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's condensed consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool. As of
September 30, 2018
, there were
10,500,000
common shares authorized for grant under the 2015 Equity Incentive Plan, of which
4,251,410
shares were available for future grant. The shares available for future grant exclude
1,555,263
shares which have been reserved for future vesting of performance-vested stock units in the event that these awards meet the criteria to vest at their maximum multiplier.
The amount of stock-based compensation was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Stock options
|
$
|
1,072
|
|
|
$
|
1,277
|
|
|
$
|
3,470
|
|
|
$
|
3,825
|
|
Performance-vested stock units
|
1,187
|
|
|
807
|
|
|
3,216
|
|
|
2,130
|
|
Restricted stock units and stock bonus shares
|
1,771
|
|
|
1,386
|
|
|
4,507
|
|
|
3,779
|
|
Total stock-based compensation
|
$
|
4,030
|
|
|
$
|
3,470
|
|
|
$
|
11,193
|
|
|
$
|
9,734
|
|
Less: stock-based compensation capitalized
|
(625
|
)
|
|
(440
|
)
|
|
(1,846
|
)
|
|
(1,344
|
)
|
Total stock-based compensation expensed
|
$
|
3,405
|
|
|
$
|
3,030
|
|
|
$
|
9,347
|
|
|
$
|
8,390
|
|
Stock options
No stock options were granted during the
three and nine months ended
September 30, 2018
or
2017
. The following table summarizes activity for stock options for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Remaining Contractual Life
|
|
Aggregate Intrinsic Value (thousands)
|
Outstanding, December 31, 2017
|
5,636,834
|
|
|
$
|
9.38
|
|
|
7.0 years
|
|
$
|
4,806
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|
|
Exercised
|
(823,883
|
)
|
|
5.36
|
|
|
|
|
4,611
|
|
Expired
|
(23,400
|
)
|
|
11.27
|
|
|
|
|
|
Forfeited
|
(104,917
|
)
|
|
9.57
|
|
|
|
|
|
Outstanding, September 30, 2018
|
4,684,634
|
|
|
$
|
10.07
|
|
|
6.6 years
|
|
$
|
2,505
|
|
Outstanding, Exercisable at September 30, 2018
|
3,142,430
|
|
|
$
|
10.25
|
|
|
6.4 years
|
|
$
|
1,452
|
|
The following table summarizes information about issued and outstanding stock options as of
September 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Options
|
|
Exercisable Options
|
Range of Exercise Prices
|
|
Options
|
|
Weighted-Average Exercise Price per Share
|
|
Weighted-Average Remaining Contractual Life
|
|
Options
|
|
Weighted-Average Exercise Price per Share
|
|
Weighted-Average Remaining Contractual Life
|
Under $5.00
|
|
35,000
|
|
|
$
|
3.31
|
|
|
3.8 years
|
|
35,000
|
|
|
$
|
3.31
|
|
|
3.8 years
|
$5.00 - $6.99
|
|
723,800
|
|
|
6.30
|
|
|
6.7 years
|
|
389,200
|
|
|
6.27
|
|
|
5.9 years
|
$7.00 - $10.99
|
|
1,362,334
|
|
|
9.42
|
|
|
6.7 years
|
|
864,830
|
|
|
9.49
|
|
|
6.4 years
|
$11.00 - $13.46
|
|
2,563,500
|
|
|
11.58
|
|
|
6.7 years
|
|
1,853,400
|
|
|
11.57
|
|
|
6.6 years
|
Total
|
|
4,684,634
|
|
|
$
|
10.07
|
|
|
6.6 years
|
|
3,142,430
|
|
|
$
|
10.25
|
|
|
6.4 years
|
The estimated unrecognized compensation cost from stock options not vested as of
September 30, 2018
, which will be recognized ratably over the remaining vesting phase, is as follows:
|
|
|
|
|
Unrecognized compensation cost (in thousands)
|
$
|
5,685
|
|
Remaining vesting phase
|
1.8 years
|
|
Restricted stock units and stock bonus awards
The Company grants restricted stock units and stock bonus awards to directors, eligible employees, and officers under its equity incentive plan. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each restricted stock unit or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over
three
to
five years
. Restricted stock units and stock bonus awards are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award.
The following table summarizes activity for restricted stock units and stock bonus awards for the
nine months ended September 30, 2018
:
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted-Average Grant-Date Fair Value
|
Not vested, December 31, 2017
|
1,087,386
|
|
|
$
|
8.89
|
|
Granted
|
747,168
|
|
|
9.35
|
|
Vested
|
(439,945
|
)
|
|
8.77
|
|
Forfeited
|
(54,111
|
)
|
|
9.56
|
|
Not vested, September 30, 2018
|
1,340,498
|
|
|
$
|
9.16
|
|
The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of
September 30, 2018
, which will be recognized ratably over the remaining vesting phase, is as follows:
|
|
|
|
|
Unrecognized compensation cost (in thousands)
|
$
|
9,075
|
|
Remaining vesting phase
|
2.0 years
|
|
Performance-vested stock units
The Company grants
two
types of performance-vested stock units ("PSUs") to certain executives under its long-term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from
zero
to
two
times the number of PSUs awarded. The shares issued for PSUs are determined based on the Company’s performance over a
three
-year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the
three
-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited.
Goal-Based PSUs -
These PSUs are earned and vested after 2020 based on a discretionary assessment by the Compensation Committee. This assessment is anticipated to measure the performance of the Company and the executives over the defined vesting period. As vesting is based on the discretion of the Compensation Committee, we have not yet met the requirements of establishing an accounting grant date for them. This will occur when the Compensation Committee determines and communicates the vesting percentage to the award recipients, which will then trigger the service inception date, the fair value of the awards, and the associated expense recognition period.
As of
September 30, 2018
,
281,872
Goal-Based PSUs had been awarded to certain executives.
Total Shareholder Return ("TSR") PSUs -
The vesting criterion for the TSR PSUs is based on a comparison of the Company’s TSR for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.
The assumptions used in valuing the TSR PSUs granted were as follows:
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
Weighted-average expected term
|
2.8 years
|
|
|
2.9 years
|
|
Weighted-average expected volatility
|
52
|
%
|
|
59
|
%
|
Weighted-average risk-free rate
|
2.41
|
%
|
|
1.34
|
%
|
The fair value of the TSR PSUs granted during the
nine months ended September 30, 2018
and
2017
was
$4.2 million
and
$5.1 million
, respectively. As of
September 30, 2018
, unrecognized compensation cost for TSR PSUs was
$6.0 million
and will be amortized through 2020. A summary of the status and activity of TSR PSUs is presented in the following table:
|
|
|
|
|
|
|
|
|
Number of Units
1
|
|
Weighted-Average Grant-Date Fair Value
|
Not vested, December 31, 2017
|
951,884
|
|
|
$
|
9.44
|
|
Granted
|
321,507
|
|
|
13.11
|
|
Vested
|
—
|
|
|
—
|
|
Forfeited
|
—
|
|
|
—
|
|
Not vested, September 30, 2018
|
1,273,391
|
|
|
$
|
10.36
|
|
1
The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from
zero
to
two
, depending on the level of satisfaction of the vesting condition.
|
|
12
.
|
Weighted-Average Shares Outstanding
|
The following table sets forth the Company's outstanding equity grants which have a dilutive effect on earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Weighted-average shares outstanding — basic
|
242,536,781
|
|
|
200,881,447
|
|
|
242,184,348
|
|
|
200,807,436
|
|
Potentially dilutive common shares from:
|
|
|
|
|
|
|
|
Stock options
|
230,067
|
|
|
415,524
|
|
|
332,953
|
|
|
412,902
|
|
TSR PSUs
1
|
411,738
|
|
|
—
|
|
|
336,882
|
|
|
—
|
|
Restricted stock units and stock bonus shares
|
381,460
|
|
|
163,944
|
|
|
352,875
|
|
|
105,791
|
|
Weighted-average shares outstanding — diluted
|
243,560,046
|
|
|
201,460,915
|
|
|
243,207,058
|
|
|
201,326,129
|
|
1
The number of awards assumes that the associated vesting condition is met at the respective period end based on market prices as of the respective period end. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from
zero
to
two
, depending on the level of satisfaction of the vesting condition.
The following potentially dilutive securities outstanding for the periods presented were not included in the respective weighted-average shares outstanding-diluted calculation above:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Potentially dilutive common shares from:
|
|
|
|
|
|
|
|
Stock options
1
|
3,456,300
|
|
|
4,726,500
|
|
|
3,438,167
|
|
|
4,756,500
|
|
TSR PSUs
1,2
|
160,754
|
|
|
951,884
|
|
|
160,754
|
|
|
951,884
|
|
Goal-Based PSUs
2,3
|
281,872
|
|
|
—
|
|
|
281,872
|
|
|
—
|
|
Restricted stock units and stock bonus shares
1
|
13,907
|
|
|
308,094
|
|
|
13,907
|
|
|
497,806
|
|
Total
|
3,912,833
|
|
|
5,986,478
|
|
|
3,894,700
|
|
|
6,206,190
|
|
1
Potential common shares excluded from the weighted-average shares outstanding-diluted calculation as the securities had an anti-dilutive effect on earnings per share.
2
The number of awards reflects the target amount of shares granted. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from
zero
to
two
, depending on the level of satisfaction of the vesting condition.
3
Potential common shares excluded from the weighted-average shares outstanding-diluted calculation as the securities are considered contingently issuable, and the performance criteria are not considered met as of period end.
We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision
is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.
During the three months ended March 31, 2018, the Company concluded it is more likely than not it will realize the benefits of its net deferred tax assets by the end of 2018 as a result of current year ordinary income. This conclusion was based upon the Company’s projection of cumulative positive net income for the three-year period ended December 31, 2018. The release of the valuation allowance is reflected in the Company’s estimated annual effective tax rate since the realization of the Company’s deferred tax assets is supported by current year ordinary income. The Company is projecting a net deferred tax liability with a full release of its beginning valuation allowance by the end of 2018.
The effective tax rates for the
three and nine months ended
September 30, 2018
were
12%
and
9%
, respectively. For the
three and nine months ended
September 30, 2017
, the effective tax rates were
nil
.
The effective tax rates for the
three and nine months ended
September 30, 2018
and
2017
differed from the statutory rates due primarily to the release of valuation allowances previously recorded against deferred tax assets.
As of
September 30, 2018
, we had no liability for unrecognized tax benefits. The Company believes that there are no new items or changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards and would not result in significant interest expense or penalties. Most of the Company's tax returns filed since August 31, 2011 are still subject to examination by tax authorities. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions, and we are not currently under any state income tax examinations.
No significant uncertain tax positions were identified as of any date on or before
September 30, 2018
. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of
September 30, 2018
, the Company has not recognized any interest or penalties related to uncertain tax benefits.
Each period, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. As of
September 30, 2018
, the Company believes it will be able to generate sufficient future taxable income within the carryforward periods and, accordingly, believes that it is more likely than not that its net deferred income tax assets will be fully realized.
14
. Revenue from Contracts with Customers
Sales of oil, natural gas, and NGLs are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. All of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
Revenues (in thousands):
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Oil
|
$
|
123,540
|
|
|
$
|
73,144
|
|
|
$
|
354,601
|
|
|
$
|
154,232
|
|
Natural Gas and NGLs
|
37,438
|
|
|
30,449
|
|
|
100,697
|
|
|
68,187
|
|
|
$
|
160,978
|
|
|
$
|
103,593
|
|
|
$
|
455,298
|
|
|
$
|
222,419
|
|
Natural Gas and NGLs Sales
Under our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. For these contracts, we have concluded that the midstream processing entity is our customer. We recognize natural gas and NGL revenues based on the net amount of the proceeds received from the midstream processing.
Oil Sales
Our oil sales contracts are generally structured in one of the following ways:
|
|
•
|
We sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received.
|
|
|
•
|
We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third party costs are recorded as transportation and gathering in our condensed consolidated statements of operations.
|
Transaction Price Allocated to Remaining Performance Obligations
A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Contract Balances
Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606. As of
September 30, 2018
, we had contract assets recorded within other current assets of
$1.6 million
representing cash advances to customers which are expected to be realized within a year.
Prior-Period Performance Obligations
We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales when that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the
three and nine months ended
September 30, 2018
, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
|
|
15
.
|
Other Commitments and Contingencies
|
Oil Commitments
The Company entered into firm sales agreements for its oil production with
four
counterparties. Deliveries under
three
of the sales agreements have commenced. Deliveries under the fourth agreement are expected to commence in the first quarter of 2019. Pursuant to these agreements, we must deliver specific amounts of oil either from our own production or from oil that we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. Our commitments over the next five years, excluding the contingent commitment described below, are as follows:
|
|
|
|
|
Year ending December 31,
|
|
Oil
|
|
(MBbls)
|
Remainder of 2018
|
|
1,072
|
|
2019
|
|
5,167
|
|
2020
|
|
4,003
|
|
2021
|
|
1,672
|
|
2022
|
|
—
|
|
Thereafter
|
|
—
|
|
Total
|
|
11,914
|
|
During the
third
quarter of
2018
, we were able to meet all of our delivery obligations, and we anticipate that our current gross operated production will continue to meet our future delivery obligations; although, this cannot be guaranteed.
Natural Gas Commitments
In collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we have agreed to participate in the expansion of natural gas gathering and processing capacity in the D-J Basin.
|
|
•
|
The first agreement includes a new
200
MMcf per day processing plant ("Mewbourn 3") as well as the expansion of a related gathering system. Starting in August 2018, Mewbourn 3 was complete and in service. Our share of the commitment requires
46.4
MMcf per day to be delivered after the plant in-service date for a period of
7
years.
|
|
|
•
|
The second agreement includes an additional
300
MMcf per day processing plant ("O'Connor 2"), including up to
100
MMcf per day of bypass, as well as the expansion of a related gathering system. Construction of the plant is underway and is expected to be placed into service in the second quarter of 2019. Our share of the commitment will require an additional
43.8
MMcf per day to be delivered after the plant in-service date for a period of
7
years.
|
These contractual obligations can be reduced by the collective volumes delivered to the plants by other producers in the D-J Basin that are in excess of such producers' total commitment. If we are unable to fulfill all of our contractual obligations and our obligations are not sufficiently reduced by the collective volumes delivered by other producers, we may be required to pay penalties or damages pursuant to these agreements. During the
third
quarter of
2018
, we were able to meet all of our delivery obligations, and we anticipate that our current gross operated production will continue to meet our future delivery obligations; although, this cannot be guaranteed.
Litigation
From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current proceedings are reasonably likely to have a material adverse impact on the Company's business, financial position, results of operations, or cash flows.
Office leases
The Company’s principal office space located in Denver is under lease through July 2022. Current rent under the lease is approximately
$66,000
per month. The Company also has a field office lease in Greeley which requires monthly payments of
$7,500
through October 2021.
Rent expense for offices leases was
$0.3 million
and
$0.2 million
for the
three months ended September 30, 2018
and
2017
, respectively. For the
nine months ended September 30, 2018
and
2017
, rent expense for office leases was
$0.7 million
and
$0.9 million
, respectively.
Vehicle Leases
The Company has entered into a leasing arrangement for its vehicles used in our operations. These leases terminate after four years and are classified as capital leases. The assets associated with these capital leases are recorded within "Other property and equipment, net."
A schedule of the minimum lease payments under non-cancellable capital and operating leases as of
September 30, 2018
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
Year ending December 31:
|
|
Vehicles Leases
|
|
Office Leases
|
Remainder of 2018
|
|
$
|
41
|
|
|
$
|
222
|
|
2019
|
|
163
|
|
|
896
|
|
2020
|
|
163
|
|
|
916
|
|
2021
|
|
189
|
|
|
913
|
|
2022
|
|
136
|
|
|
500
|
|
Thereafter
|
|
—
|
|
|
—
|
|
Total minimum lease payments
|
|
$
|
692
|
|
|
$
|
3,447
|
|
Less: Amount representing estimated executory cost
|
|
(57
|
)
|
|
|
Net minimum lease payments
|
|
635
|
|
|
|
Less: Amount representing interest
|
|
(92
|
)
|
|
|
Present value of net minimum lease payments
*
|
|
$
|
543
|
|
|
|
*
Reflected in the balance sheet as current and non-current obligations of
$111 thousand
and
$432 thousand
, respectively, within "Accounts payable and accrued expenses" and "Other liabilities," respectively.
|
|
16
.
|
Supplemental Schedule of Information to the Condensed Consolidated Statements of Cash Flows
|
The following table supplements the cash flow information presented in the condensed consolidated financial statements for the periods presented (in thousands):
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
Supplemental cash flow information:
|
2018
|
|
2017
|
Interest paid
|
$
|
17,701
|
|
|
$
|
4,796
|
|
|
|
|
|
Non-cash investing and financing activities:
|
|
|
|
Accrued well costs as of period end
|
$
|
143,015
|
|
|
$
|
122,387
|
|
Asset retirement obligations incurred with development activities
|
1,488
|
|
|
2,782
|
|
Asset retirement obligations assumed with acquisitions
|
26,150
|
|
|
23,521
|
|
Obligations discharged with asset retirements and divestitures
|
$
|
(8,944
|
)
|
|
$
|
(7,023
|
)
|
|
|
|
|
Net changes in operating assets and liabilities:
|
|
|
|
Accounts receivable
|
$
|
(31,170
|
)
|
|
$
|
(85,027
|
)
|
Accounts payable and accrued expenses
|
(842
|
)
|
|
1,413
|
|
Revenue payable
|
15,858
|
|
|
41,997
|
|
Production taxes payable
|
20,504
|
|
|
17,548
|
|
Other
|
(520
|
)
|
|
(941
|
)
|
Changes in operating assets and liabilities
|
$
|
3,830
|
|
|
$
|
(25,010
|
)
|
|
|
ITEM
2
.
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
Introduction
The following discussion and analysis was prepared to supplement information contained in the accompanying condensed consolidated financial statements and is intended to explain certain items regarding the Company's financial condition as of
September 30, 2018
and its results of operations for the
three and nine months ended
September 30, 2018
and
2017
. It should be read in conjunction with the “Selected Financial Data” and the accompanying audited consolidated financial statements and related notes thereto contained in the Annual Report on Form 10-K for the year ended
December 31, 2017
filed with the SEC on February 21, 2018. Unless the context otherwise requires, references to "SRC Energy," "we," "us," "our," or the "Company" in this report refer to the registrant, SRC Energy Inc., and its subsidiaries.
This section and other parts of this Quarterly Report on Form 10-Q contain forward-looking statements that involve risks and uncertainties. See the “Cautionary Statement Concerning Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q. Forward-looking statements are not guarantees of future performance, and our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed and referenced in “Risk Factors.” We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.
Proposition 112
As discussed in the "Risk Factors" section of this report, certain groups opposed to oil and natural gas hydraulic fracturing operations have proposed Proposition 112, which is included on Colorado’s November 6, 2018 ballot. Proposition 112 would impose a minimum setback distance of 2,500 feet between any new oil and gas development and any occupied structures or defined "vulnerable areas." If this proposition is enacted, it would apply prospectively to oil and gas development permitted on or after the effective date of the law, which is expected to be December 2018. Although there is significant uncertainty about how this law would be interpreted and implemented, if approved by the voters, it could have significant adverse effects on the Company’s long-term operations, reserves, and financial condition.
See “Risk Factors - Proposition 112, if approved, would have a material adverse effect on our future drilling inventory and other aspects of our business.”
If Proposition 112 is enacted, we will consider all available courses of action, including potential legal challenges, legislative reformation, and regulatory modifications, but the outcome of any such efforts and the effect that they might have on the Company is unknown. We do not believe that Proposition 112 would impact existing wells, current drilling or completion activities, or future wells that have been approved by the state. We currently have state-approved and permitted drilling locations that we believe would be grandfathered under Proposition 112 and would provide approximately two years of drilling inventory.
Overview
SRC Energy
is an independent oil and gas company engaged in the acquisition, development, and production of oil, natural gas, and NGLs in the D-J Basin, which we believe to be one of the premier, liquids-rich oil and natural gas resource plays in the United States. It contains hydrocarbon-bearing deposits in several formations, including the Niobrara, Codell, Greenhorn, Shannon, Sussex, J-Sand, and D-Sand. The area has produced oil and natural gas for over fifty years and benefits from established infrastructure, long reserve life, and multiple service providers.
Our oil and natural gas activities are focused in the Wattenberg Field, predominantly in Weld County, Colorado, an area that covers the western flank of the D-J Basin.
Currently, we are focused on the horizontal development of the Codell formation as well as the three benches of the Niobrara formation, which are all characterized by relatively high liquids content.
In order to maintain operational focus while preserving developmental flexibility, we strive to attain operational control of a majority of the wells in which we have a working interest. We currently operate approximately
85%
of our proved developed reserves and anticipate operating a majority of our future net drilling locations. Additionally, our current development plan anticipates that all of our future activities will be concentrated in the Wattenberg Field.
Market Conditions
Market prices for our products significantly impact our revenues, net income, and cash flow. The market prices for oil, natural gas, and NGLs are inherently volatile. To provide historical perspective, the following table presents the average annual NYMEX prices for oil and natural gas for each of the last five fiscal years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Year Ended August 31,
|
|
2017
|
|
2016
|
|
2015
|
|
2015
|
|
2014
|
|
2013
|
Average NYMEX prices
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
$
|
50.93
|
|
|
$
|
43.20
|
|
|
$
|
48.73
|
|
|
$
|
60.65
|
|
|
$
|
100.39
|
|
|
$
|
94.58
|
|
Natural gas (per Mcf)
|
$
|
3.00
|
|
|
$
|
2.52
|
|
|
$
|
2.58
|
|
|
$
|
3.12
|
|
|
$
|
4.38
|
|
|
$
|
3.55
|
|
For the periods presented in this report, the following table presents the Reference Price (derived from average NYMEX prices) as well as the differential between the Reference Price and the prices realized by us.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Oil (NYMEX-WTI)
|
|
|
|
|
|
|
|
Average NYMEX Price
|
$
|
69.76
|
|
|
$
|
48.18
|
|
|
$
|
66.89
|
|
|
$
|
49.44
|
|
Realized Price *
|
63.48
|
|
|
41.89
|
|
|
60.13
|
|
|
41.73
|
|
Differential *
|
$
|
(6.28
|
)
|
|
$
|
(6.29
|
)
|
|
$
|
(6.76
|
)
|
|
$
|
(7.71
|
)
|
|
|
|
|
|
|
|
|
Natural Gas (NYMEX-Henry Hub)
|
|
|
|
|
|
|
|
Average NYMEX Price
|
$
|
2.90
|
|
|
$
|
2.99
|
|
|
$
|
2.90
|
|
|
$
|
3.03
|
|
Realized Price
|
1.79
|
|
|
2.35
|
|
|
1.84
|
|
|
2.39
|
|
Differential
|
$
|
(1.11
|
)
|
|
$
|
(0.64
|
)
|
|
$
|
(1.06
|
)
|
|
$
|
(0.64
|
)
|
|
|
|
|
|
|
|
|
NGL Realized Price
|
$
|
19.93
|
|
|
$
|
17.32
|
|
|
$
|
18.91
|
|
|
$
|
15.49
|
|
* Adjusted to include the effect of transportation and gathering expenses.
Market conditions in the Wattenberg Field require us to sell oil at prices less than the prices posted by the NYMEX. The differential between the prices actually received by us at the wellhead and the published indices reflects deductions imposed upon us by the purchasers for location and quality adjustments. With regard to the sale of oil, substantially all of the Company's first quarter 2017 oil production was sold to the counterparties of its firm sales commitments. Beginning in the second quarter of 2017 and continuing through the current period, the Company's oil production exceeded its firm sales commitments, and the surplus oil production was sold at a reduced differential as compared to our committed volumes.
Our revenues, results of operations, profitability, future growth, and carrying value of our oil and gas properties depend primarily on the prices that we receive for our oil, natural gas, and NGL production. There has been significant volatility in the price of oil and natural gas since mid-2014. During the
nine months ended September 30, 2018
, the NYMEX-WTI oil price ranged from a high of
$77.41
per Bbl on
June 27, 2018
to a low of
$59.20
per Bbl on
February 9, 2018
, and the NYMEX-Henry Hub natural gas price ranged from a low of
$2.55
per MMBtu on
February 12, 2018
to a high of
$3.63
per MMBtu on
January 29, 2018
. As reflected in published data, the price for WTI oil settled at
$60.46
per Bbl on
December 29, 2017
. Comparably, the price of oil settled at
$73.16
per Bbl on
Friday, September 28, 2018
,
an increase
of
21%
from
December 29, 2017
. NYMEX-Henry Hub natural gas traded at
$2.95
per Mcf on
December 29, 2017
, but
increased
approximately
2%
as of
September 28, 2018
to
$3.01
. While we use NYMEX-Henry Hub to calculate our natural gas differentials, our natural gas sales tend to trend more closely with Colorado Interstate Gas – Rocky Mountains as published in Inside FERC’s Gas Market Report, published by Platts ("CIG"). Average CIG prices for the
third
quarter of
2018
increased
to
$2.18
from
$1.83
in the
second
quarter of
2018
, and the basis difference for CIG to NYMEX-Henry Hub
decreased
from
$0.97
to
$0.72
.
A decline in oil and natural gas prices will adversely affect our financial condition and results of operations. Furthermore, low oil and natural gas prices can result in an impairment of the value of our properties and impact the calculation of the “ceiling test” required under the accounting principles for companies following the “full cost” method of accounting. At
September 30, 2018
, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairment was necessary.
Core Operations
The following
table p
rovides details about our ownership interests with respect to vertical and horizontal producing wells as of
September 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vertical Wells
|
Operated Wells
|
|
Non-Operated Wells
|
|
Totals
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
628
|
|
|
602
|
|
|
146
|
|
|
44
|
|
|
774
|
|
|
646
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Horizontal Wells
|
Operated Wells
|
|
Non-Operated Wells
|
|
Totals
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
364
|
|
|
338
|
|
|
310
|
|
|
59
|
|
|
674
|
|
|
397
|
|
In addition to the producing wells summarized in the preceding table, as of
September 30, 2018
, we were the operator of
77
gross (
66
net) horizontal wells in progress, which excludes
30
gross (
23
net) wells for which we have only set surface casings. As of
September 30, 2018
, we are participating in
29
gross (
9
net) non-operated horizontal wells in progress.
As we develop our acreage through horizontal drilling, we have an active program for the remediation and reclamation of the
vast majority of the operated
vertical wellbores. During the
nine months ended September 30, 2018
, we plugged
146
wells and returned the associated acreage to the property owners.
Production
For the three months ended
September 30, 2018
, our average daily production
increased
to
49,165
BOED as compared to
40,378
BOED for the three months ended
September 30, 2017
. During the first
nine
months of
2018
, our average net daily production was
47,416
BOED. By comparison, during the
nine months ended September 30, 2017
, our average production rate was
30,331
BOED. As of
September 30, 2018
, over
99%
o
f
our daily production was from horizontal wells.
Strategy
Our primary objective is to enhance shareholder value by increasing our net asset value, net reserves, and cash flow through development, exploitation, and acquisitions of oil and gas properties. We intend to follow a balanced risk strategy by allocating capital expenditures to lower risk development and exploitation activities. Key elements of our business strategy include the following:
|
|
•
|
Concentrate on our existing core area in the D-J Basin, where we have significant operating experience.
All of our current wells and our proved undeveloped acreage are located either in or adjacent to the Wattenberg Field, and we seek to acquire developed and undeveloped oil and gas properties in the same area. Focusing our operations in this area leverages our management, technical, and operational experience in the basin.
|
|
|
•
|
Develop and exploit existing oil and gas properties.
Our principal growth strategy has been to develop and exploit our properties to add reserves. In the Wattenberg Field, we target three benches of the Niobrara formation as well as the Codell formation for horizontal drilling and production. We believe horizontal drilling is the most efficient and safest way to recover the potential hydrocarbons and consider the Wattenberg Field to be relatively low-risk because information gained from the large number of existing wells can be applied to potential future wells. There is enough similarity between wells in the Wattenberg Field that the exploitation process is generally repeatable.
|
|
|
•
|
Use the latest technology to maximize returns and improve hydrocarbon recovery.
Our development objective for individual well optimization is to drill and complete wells with lateral lengths of mostly 7,000' to 10,000'. Utilizing petrophysical and seismic data, a 3-D model is developed for each leasehold section to assist in determining optimal wellbore placement, well spacing, and stimulation design. This process is augmented with formation-specific drilling and completion execution designs and coupled with localized production results to implement a continuous improvement philosophy in optimizing the value per acre of our leasehold throughout our development program.
|
|
|
•
|
Operate in a safe manner
and work in partnership with our surrounding stakeholders.
While our scale of operations has increased significantly, we continue to focus on maintaining a safe workplace for our employees and contractors. Further, as technology for resource development has advanced, we seek to utilize best industry practices to meet or exceed regulatory requirements while reducing our impacts on neighboring communities. Such practices include building our infrastructure out ahead of operations to minimize traffic, working with our service providers to minimize dust and lighting issues, and constructing sound walls to minimize noise. We value our positive relationship with local governing entities and the communities in which we operate and seek to continually achieve a status of operator of choice.
|
|
|
•
|
Retain control over the operation of a substantial portion of our production.
As operator of a majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled. This allows us to modify our capital spending as our financial resources and underlying lease terms allow and market conditions permit.
|
|
|
•
|
Maintain financial flexibility while focusing on operational cost control.
We strive to be a cost-efficient operator and to maintain a relatively low utilization of debt, which enhances our financial flexibility. Our high degree of operational control, as well as our focus on operating efficiencies and short return on investment cycle times, is central to our operating strategy.
|
|
|
•
|
Acquire and develop assets near established infrastructure
. We have made acquisitions of contiguous acreage and aligned our development plans where technically-capable, financially-stable midstream companies have existing assets and plans for additional investment. We work collaboratively with these companies to proactively identify expansion opportunities that complement our development plans while reducing truck traffic.
|
|
|
•
|
Control and reduce emissions from our production facilities
. We place high importance on achieving compliance with all applicable air quality rules and regulations
and r
educing
emissions continues to be a top environmental priority. To minimize these emissions, we employ best management practices such as using available direct pipeline take-away access and pneumatic actuated instrument devices and working with suppliers to deploy diesel engines that meet the U.S. Environmental Protection Agency Tier 4 standand. We also control emissions and minimize flaring of gas by recovering natural gas and actively pursuing sufficient take-away capacity for associated produced gas
and the
use of vapor recovery equipment
.
We continue to evolve the design of our production facilities to produce oil and natural gas with fewer air emissions
,
including those emissions for which there are public health standards (e.g. ozone and particulate matter)
.
|
Significant Developments
Acquisitions and Trade
In September 2018, the Company completed the purchase of vertical and horizontal wells in the Greeley-Crescent development area in Weld County, Colorado for
$64.1 million
in cash and the assumption of certain liabilities for a total purchase price of
$96.8 million
. The effective date of this purchase was September 1, 2018.
In September 2018, we completed a trade with another party of approximately
2,500
net acres. This transaction further enhances the contiguous nature of the Company's acreage position.
In August 2018, the Company completed the purchase of leasehold acreage and associated non-operated production for
$37.6 million
in cash and the assumption of certain liabilities for a total purchase price of
$38.0 million
. The acreage increased our working interest in existing operations and planned wells.
Revolving Credit Facility
In October 2018, the lenders under the Revolver completed their semi-annual redetermination of our borrowing base. The borrowing base was increased from $550 million to $650 million, and we increased our aggregate elected commitment from $450 million to $500 million.
Drilling and Completion Operations
Our drilling and completion schedule drives our production forecast and our expected future cash flows. We believe that at current drilling and completion cost levels and with currently prevailing commodity prices, we can achieve attractive well-level rates of return. Should commodity prices weaken or our costs escalate significantly, our operational flexibility will allow us to adjust our drilling and completion schedule, if prudent. If the well-level internal rate of return is at or below our weighted-average cost of capital, we may choose to delay completions and/or forego drilling altogether. Conversely, if commodity prices move
higher, we may choose to accelerate drilling and completion activities.
During the
nine months ended September 30, 2018
, we drilled
89
operated horizontal wells and turned
54
operated horizontal wells to sales. As of
September 30, 2018
, the Company had
9
gross (
8
net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the fourth quarter. As of
September 30, 2018
, we are the operator of
77
gross (
66
net) horizontal wells in progress, whic
h excludes
30
gross (
23
net) horizontal wells for whi
ch we have only set surface casings. The majority of this activity was funded through cash flows from operations. For 2018 as a whole, we expect to drill 118 gross (101 net) operated horizontal wells and complete approximately 127 gross (112 net) operated horizontal wells with mid-length and long laterals targeting the Codell and Niobrara formations.
For the
nine months ended September 30, 2018
, we participated in the co
mpletion of
32
gross (
6
net) non-operated horizontal wells. As of
September 30, 2018
, we are participating in
29
gross (
9
net) non-operated ho
rizontal wells in progress.
Trends and Outlook
NYMEX-WTI oil traded at
$60.46
per Bbl on
December 29, 2017
, but has since
increased
approximately
21%
as of
September 28, 2018
to
$73.16
. NYMEX-Henry Hub natural gas traded at
$2.95
per Mcf on
December 29, 2017
, but
increased
approximately
2%
as of
September 28, 2018
to
$3.01
. Although NYMEX-WTI oil prices have increased in 2018, they continue to be volatile and are out of our control. If oil prices decrease, this could
(i) reduce our cash flow which could, in turn, reduce the funds available for exploring and replacing oil and natural gas reserves, (ii) reduce our Revolver borrowing base capacity and increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) reduce the number of oil and gas prospects which have reasonable economic returns, (iv) cause us to allow leases to expire based upon the value of potential oil and natural gas reserves in relation to the costs of exploration, (v) result in marginally productive oil and natural gas wells being abandoned as non-commercial, and (vi) cause ceiling test impairments.
We continually focus on managing drilling and completion costs through a combination of well design optimization, reductions in the average days to drill, and employment of current technological advancements. This focus on cost management helps support well-level economics under varying oil and natural gas pricing environments.
Midstream companies that operate the natural gas processing facilities and gathering pipelines in the Wattenberg Field continue to make significant capital investments to increase the capacity of their systems. From time to time, our production has been and may continue to be adversely impacted by the lack of processing capacity, resulting in high natural gas gathering line pressures. Second and third quarter 2018 results were impacted by this lack of spare gas processing capacity, which resulted in persistently high line pressures and the inability to maintain consistent production flows. Further exacerbating the midstream constraints were above average temperatures in Colorado in June and continuing into July as well as unplanned shutdowns of natural gas processing facilities. As a result, many of the Company's wells could not be produced consistently, and the Company was unable to turn recently completed wells to sales as desired.
To address the growing volumes of natural gas production in the D-J Basin, DCP Midstream is developing multiple projects including new processing plants, low pressure gathering systems, additional compression, and plant bypass infrastructure. Most notably, in collaboration with DCP Midstream, we and several other producers have agreed to support the expansion of natural gas gathering and processing capacity through agreements that impose baseline and incremental volume commitments, which we are currently exceeding. The initial plans included a new 200 MMcf per day processing plant ("Mewbourn 3"), and the expansion of a related gathering system, which became operational in August 2018. Through the same framework, all of the parties agreed to a development plan to add another 300 MMcf per day plant ("O'Connor 2"), including up to 100 MMcf per day of bypass, that is expected to be in service in the second quarter of 2019. In addition, DCP Midstream has announced the development of a third plant ("Bighorn"), which could have capacity up to 1 Bcf per day, including bypass, with an in-service date after 2019.
We have extended the use of oil and water gathering lines to certain production locations. These gathering systems are owned and operated by independent third parties, and we commit specific leases or areas to these systems. We believe these gathering lines have several benefits, including a) reduced need to use trucks, thereby reducing truck traffic and noise in and around our production locations, b) potentially lower gathering costs as pipeline gathering tends to be more efficient, c) reduced on-site storage capacity, resulting in lower production location facility costs, and d) generally improved community relations. As these gathering lines are currently being expanded, we have experienced and expect to continue to experience some delays in placing our pads on production.
Oil transportation and takeaway capacity has increased with the expansion of certain interstate pipelines servicing the Wattenberg Field. We strive to reduce the negative differential that we have historically realized on our oil production depending
on transportation commitments, local refinery demand, and our production volumes. Further details regarding posted prices and average realized prices are discussed in "-Market Conditions."
For
2018
, we expect to drill 118 gross operated horizontal wells
(
89
of which were drilled through
September 30, 2018
)
with mostly mid-length and long laterals targeting the Codell and Niobrara zones. We anticipate this drilling and completion program will cost approximately $580 million
(
$408.3 million
of which was incurred through
September 30, 2018
)
and that it should lead to a significant increase in production and associated proved developed producing reserves. We currently estimate that full-year 2018 production will average approximately 50,000 BOED with the
oil mix being approximately 45%
of production.
Other than the foregoing and the aforementioned Proposition 112, we do not know of any trends, events, or uncertainties that have had, during the periods covered by this report, or are reasonably expected to have, a material impact on our sales, revenues, expenses, liquidity, or capital resources.
Results of Operations
Material changes to certain items in our condensed consolidated statements of operations included in our condensed consolidated financial statements for the periods presented are discussed below.
For the
three months ended September 30, 2018
compared to the
three months ended September 30, 2017
For the
three months ended September 30, 2018
, we reported net
income
of
$62.6 million
compared to net
income
of
$43.8 million
during the
three months ended September 30, 2017
. Net
income
per basic and diluted share was
$0.26
for the
three months ended September 30, 2018
compared to net
income
per basic and diluted share of
$0.22
for the
three months ended September 30, 2017
.
Oil, Natural Gas, and NGL Production and Revenues
- For the
three months ended September 30, 2018
, we recorded total oil, natural gas, and NGL revenues of
$161.0 million
compared to
$103.6 million
for the
three months ended September 30, 2017
,
an increase
of
$57.4 million
or
55%
. The following table summarizes key production and revenue statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Percentage
|
|
2018
|
|
2017
|
|
Change
|
Production:
|
|
|
|
|
|
Oil (MBbls)
1
|
1,915
|
|
|
1,726
|
|
|
11
|
%
|
Natural Gas (MMcf)
2
|
9,471
|
|
|
7,412
|
|
|
28
|
%
|
NGLs (MBbls)
1
|
1,030
|
|
|
753
|
|
|
37
|
%
|
MBOE
3
|
4,523
|
|
|
3,714
|
|
|
22
|
%
|
BOED
4
|
49,165
|
|
|
40,378
|
|
|
22
|
%
|
|
|
|
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
Oil
|
$
|
123,540
|
|
|
$
|
73,144
|
|
|
69
|
%
|
Natural Gas
|
16,908
|
|
|
17,402
|
|
|
(3
|
)%
|
NGLs
|
20,530
|
|
|
13,047
|
|
|
57
|
%
|
|
$
|
160,978
|
|
|
$
|
103,593
|
|
|
55
|
%
|
Average sales price:
|
|
|
|
|
|
Oil
5
|
$
|
63.48
|
|
|
$
|
41.89
|
|
|
52
|
%
|
Natural Gas
|
1.79
|
|
|
2.35
|
|
|
(24
|
)%
|
NGLs
|
19.93
|
|
|
17.32
|
|
|
15
|
%
|
BOE
5
|
$
|
35.15
|
|
|
$
|
27.66
|
|
|
27
|
%
|
1
"MBbl" refers to one thousand stock tank barrels, or 42,000 U.S. gallons liquid volume in reference to crude oil or other liquid hydrocarbons.
2
"MMcf" refers to one million cubic feet of natural gas.
3
"MBOE" refers to one thousand barrels of oil equivalent, which combines MBbls of oil and MMcf of natural gas by converting each six MMcf of natural gas to one MBbl of oil.
4
"BOED" refers to the average number of barrels of oil equivalent produced in a day for the period.
5
Adjusted to include the effect of transportation and gathering expenses.
Net oil, natural gas, and NGL production for the
three months ended September 30, 2018
averaged
49,165
BOED,
an increase
of
22%
over average production of
40,378
BOED in the
three months ended September 30, 2017
. From
September 30, 2017
to
September 30, 2018
, our well count increased by
170
net horizontal wells, growing our reserves and daily production totals. The
22%
increase in production and the
27%
increase in average sales prices resulted in a significant increase in revenues.
LOE
- Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
2018
|
|
2017
|
Production costs
|
$
|
10,181
|
|
|
$
|
4,223
|
|
Workover
|
179
|
|
|
93
|
|
Total LOE
|
$
|
10,360
|
|
|
$
|
4,316
|
|
|
|
|
|
Per BOE:
|
|
|
|
Production costs
|
$
|
2.25
|
|
|
$
|
1.14
|
|
Workover
|
0.04
|
|
|
0.03
|
|
Total LOE
|
$
|
2.29
|
|
|
$
|
1.17
|
|
Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells
and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas.
During the
three months ended September 30, 2018
, we experienced
increased
production expense compared to the
three months ended September 30, 2017
due to a
45%
increase in net operated wells. In addition,
elevated line pressures temporarily drove operating costs on a per unit basis higher
in the third quarter of 2018
as the Company incurred incremental costs without the typical benefit of flush production from its new wells.
Transportation and gathering -
Transportation and gathering was
$2.0 million
, or
$0.44
per BOE, for the
three months ended September 30, 2018
, compared to
$0.8 million
, or
$0.23
per BOE, for the
three months ended September 30, 2017
. Coinciding with the increasing production in 2018, the Company has increased the volume of its production that is sold and delivered at the downstream interconnect. This has the effect of increasing both the net price received for the production and transportation and gathering costs. While costs attributable to volumes sold at the interconnect of the pipeline are reported as an expense, the Company analyzes these charges on a net basis within revenue for comparability with wellhead sales.
Production taxes
- Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. Production taxes were
$12.8 million
, or
$2.83
per BOE, for the
three months ended September 30, 2018
, compared to
$10.1 million
, or
$2.71
per BOE, during the
three months ended September 30, 2017
. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were
8.0%
and
9.7%
for the
three months ended September 30, 2018
and
2017
, respectively.
DD&A
- The following table summarizes the components of DD&A:
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
(in thousands)
|
2018
|
|
2017
|
Depletion of oil and gas properties
|
$
|
44,230
|
|
|
$
|
32,944
|
|
Depreciation and accretion
|
958
|
|
|
796
|
|
Total DD&A
|
$
|
45,188
|
|
|
$
|
33,740
|
|
|
|
|
|
DD&A expense per BOE
|
$
|
9.99
|
|
|
$
|
9.08
|
|
For the
three months ended September 30, 2018
, DD&A was
$9.99
per BOE compared to
$9.08
per BOE for the
three months ended September 30, 2017
. The increase in the DD&A rate was the result of rece
nt drilling and completion activities which increased the amortization base. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, whereby the ratio of production volumes for the quarter to the beginning of quarter estimated total reserves determines the depletion rate.
General and Administrative ("G&A")
- The following table summarizes G&A expenses incurred and capitalized during the periods presented:
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
(in thousands)
|
2018
|
|
2017
|
G&A costs incurred
|
$
|
13,836
|
|
|
$
|
11,002
|
|
Capitalized costs
|
(3,151
|
)
|
|
(2,518
|
)
|
Total G&A
|
$
|
10,685
|
|
|
$
|
8,484
|
|
|
|
|
|
Non-Cash G&A
|
$
|
3,405
|
|
|
$
|
3,030
|
|
Cash G&A
|
7,280
|
|
|
5,454
|
|
Total G&A
|
$
|
10,685
|
|
|
$
|
8,484
|
|
|
|
|
|
Non-Cash G&A per BOE
|
$
|
0.75
|
|
|
$
|
0.82
|
|
Cash G&A per BOE
|
1.61
|
|
|
1.47
|
|
G&A Expense per BOE
|
$
|
2.36
|
|
|
$
|
2.29
|
|
G&A includes overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees, and regulatory costs, among others. Total G&A costs of
$10.7 million
for the
third
quarter of
2018
were
26%
higher
than G&A for the same period of
2017
. This increase is primarily due to
a
25%
increase in employee headcount from
117
at
September 30, 2017
to
146
at
September 30, 2018
. Additionally, G&A for the
three months ended September 30, 2018
was elevated by expenses incurred in support of Colorado oil and gas legislative activities.
Our G&A expense for the
three months ended September 30, 2018
includes stock-based compensation of
$3.4 million
compared to
$3.0 million
for the
three months ended September 30, 2017
.
Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the
three months ended September 30, 2017
to the
three months ended September 30, 2018
reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.
Commodity derivative gains (losses)
- As more fully described in Item 1. Financial Statements – Note
8
,
Commodity Derivative Instruments
, we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the
three months ended September 30, 2018
, we realized a settlement
loss
of
$8.3 million
.
For the prior comparable period, we realized a settlement
gain
of
$0.1 million
, net of previously incurred premiums attributable to the settled commodity contracts.
In addition, for the
three months ended September 30, 2018
, we recorded an unrealized
loss
of
$0.3 million
to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the
three months ended September 30, 2017
, we reported an unrealized
loss
of
$2.5 million
. Unrealized
losses
are non-cash items.
Income taxes
- As more fully described in Item 1. Financial Statements – Note
13
,
Income Taxes
, we reported income tax
expense
of
$8.9 million
for the
three months ended September 30, 2018
as compared to no income tax expense for the comparable prior year period.
The effective tax rates for the
three and nine months ended
September 30, 2018
and
2017
differed from the statutory rates due primarily to the release of valuation allowances previously recorded against deferred tax assets.
For the
nine months ended September 30, 2018
compared to the
nine months ended September 30, 2017
For the
nine months ended September 30, 2018
, we reported net
income
of
$178.0 million
compared to net
income
of
$91.7 million
during the
nine months ended September 30, 2017
. Net
income
per basic and diluted share was
$0.74
and
$0.73
, respectively, for the
nine months ended September 30, 2018
compared to net
income
per basic and diluted share of
$0.46
for the
nine months ended September 30, 2017
.
Oil, Natural Gas, and NGL Production and Revenues
- For the
nine months ended September 30, 2018
, we recorded total oil, natural gas, and NGL revenues of
$455.3 million
compared to
$222.4 million
for the
nine months ended September 30, 2017
,
an increase
of
$232.9 million
or
105%
. The following table summarizes key production and revenue statistics:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
Percentage
|
|
2018
|
|
2017
|
|
Change
|
Production:
|
|
|
|
|
|
Oil (MBbls)
|
5,802
|
|
|
3,668
|
|
|
58
|
%
|
Natural Gas (MMcf)
|
26,177
|
|
|
17,122
|
|
|
53
|
%
|
NGLs (MBbls)
|
2,780
|
|
|
1,758
|
|
|
58
|
%
|
MBOE
|
12,945
|
|
|
8,280
|
|
|
56
|
%
|
BOED
|
47,416
|
|
|
30,331
|
|
|
56
|
%
|
|
|
|
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
Oil
|
$
|
354,601
|
|
|
$
|
154,232
|
|
|
130
|
%
|
Natural Gas
|
48,139
|
|
|
40,945
|
|
|
18
|
%
|
NGLs
|
52,558
|
|
|
27,242
|
|
|
93
|
%
|
|
$
|
455,298
|
|
|
$
|
222,419
|
|
|
105
|
%
|
Average sales price:
|
|
|
|
|
|
Oil
|
$
|
60.13
|
|
|
$
|
41.73
|
|
|
44
|
%
|
Natural Gas
|
1.84
|
|
|
2.39
|
|
|
(23
|
)%
|
NGLs
|
18.91
|
|
|
15.49
|
|
|
22
|
%
|
BOE
|
$
|
34.73
|
|
|
$
|
26.72
|
|
|
30
|
%
|
Net oil, natural gas, and NGL production for the
nine months ended September 30, 2018
averaged
47,416
BOED, an increase of
56%
over average production of
30,331
BOED in the
nine months ended September 30, 2017
. From
September 30, 2017
to
September 30, 2018
, our well count increased by
170
ne
t
horizontal wells, growing our reserves and daily production totals. The
56%
increase in production and
30%
increase in average sales prices resulted in a significant increase in revenues.
LOE
- Direct operating costs of producing oil and natural gas are reported as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
Production costs
|
$
|
29,328
|
|
|
$
|
12,511
|
|
Workover
|
540
|
|
|
497
|
|
Total LOE
|
$
|
29,868
|
|
|
$
|
13,008
|
|
|
|
|
|
Per BOE:
|
|
|
|
Production costs
|
$
|
2.27
|
|
|
$
|
1.51
|
|
Workover
|
0.04
|
|
|
0.06
|
|
Total LOE
|
$
|
2.31
|
|
|
$
|
1.57
|
|
Lease operating and workover costs tend to increase or decrease primarily in relation to the number and type of wells
and, to a lesser extent, on fluctuations in oil field service costs and changes in the production mix of oil and natural gas.
During the
nine months ended September 30, 2018
, we experienced
increased
production expense compared to the
nine months ended September 30, 2017
primarily
due to a
45%
increase in net operated wells. In addition, elevated line pressures temporarily drove operating costs on a unit basis higher in the second and third quarter of 2018 as the Company incurred incremental costs without the typical benefit of flush production from its new wells.
Transportation and gathering -
Transportation and gathering was
$5.7 million
, or
$0.44
per BOE, for the
nine months ended September 30, 2018
, compared to
$1.1 million
, or
$0.14
per BOE, for the
nine months ended September 30, 2017
. In the first half of 2017, a majority of the Company's production was delivered to the purchaser at the wellhead whereas, in 2018, the
Company has increased the proportion of its production that is sold and delivered at the downstream interconnect. This has the effect of increasing both the net price received for the production and transportation and gathering costs. While costs attributable to volumes sold at the interconnect of the pipeline are reported as an expense, the Company analyzes these charges on a net basis within revenue for comparability with wellhead sales.
Production taxes
- Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. Production taxes were
$41.3 million
, or
$3.19
per BOE, for the
nine months ended September 30, 2018
, compared to
$21.0 million
, or
$2.54
per BOE, for the
nine months ended September 30, 2017
. Taxes tend to increase or decrease primarily based on the value of production sold. As a percentage of revenues, production taxes were
9.1%
and
9.4%
for the
nine months ended September 30, 2018
and
2017
, respectively.
DD&A
- The following table summarizes the components of DD&A:
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
(in thousands)
|
2018
|
|
2017
|
Depletion of oil and gas properties
|
$
|
121,259
|
|
|
$
|
71,389
|
|
Depreciation and accretion
|
2,887
|
|
|
2,007
|
|
Total DD&A
|
$
|
124,146
|
|
|
$
|
73,396
|
|
|
|
|
|
DD&A expense per BOE
|
$
|
9.59
|
|
|
$
|
8.86
|
|
For the
nine months ended September 30, 2018
, DD&A was
$9.59
per BOE compared to
$8.86
per BOE for the
nine months ended September 30, 2017
.
The increase in the DD&A rate was the result of rece
nt drilling and completion activities which increased the amortization base. Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on estimated reserves, whereby the ratio of production volumes for the quarter to the beginning of the quarter estimated total reserves determines the depletion rate.
G&A
- The following table summarizes G&A expenses incurred and capitalized during the periods presented:
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
(in thousands)
|
2018
|
|
2017
|
G&A costs incurred
|
$
|
39,298
|
|
|
$
|
32,018
|
|
Capitalized costs
|
(9,607
|
)
|
|
(7,729
|
)
|
Total G&A
|
$
|
29,691
|
|
|
$
|
24,289
|
|
|
|
|
|
Non-Cash G&A
|
$
|
9,347
|
|
|
$
|
8,390
|
|
Cash G&A
|
20,344
|
|
|
15,899
|
|
Total G&A
|
$
|
29,691
|
|
|
$
|
24,289
|
|
|
|
|
|
Non-Cash G&A per BOE
|
$
|
0.72
|
|
|
$
|
1.01
|
|
Cash G&A per BOE
|
1.57
|
|
|
1.92
|
|
G&A Expense per BOE
|
$
|
2.29
|
|
|
$
|
2.93
|
|
G&A includes all overhead costs associated with employee compensation and benefits, insurance, facilities, professional fees and regulatory costs, among others. Total G&A costs of
$29.7 million
for the
nine months ended September 30, 2018
were
22%
higher than G&A for the same period of 2017. This increase is primarily due to a
25%
increase in employee headcount from
117
at
September 30, 2017
to
146
at
September 30, 2018
. Additionally, G&A for the
nine months ended September 30, 2018
was elevated by expenses incurred in support of Colorado oil and gas legislative activities during the third quarter of 2018.
Our G&A expense for the
nine months ended September 30, 2018
includes stock-based compensation of
$9.3 million
compared to
$8.4 million
for the
nine months ended September 30, 2017
.
Pursuant to the requirements under the full cost accounting method for oil and gas properties, we identify all general and administrative costs that relate directly to the acquisition of undeveloped mineral leases and the exploration and development of
properties. Those costs are reclassified from G&A expenses and capitalized into the full cost pool. The increase in capitalized costs from the
nine months ended September 30, 2017
to the
nine months ended September 30, 2018
reflects our increased headcount of individuals performing activities to maintain and acquire leases and develop our properties.
Commodity derivatives
- As more fully described in Item 1. Financial Statements – Note
8
,
Commodity Derivative Instruments,
we use commodity contracts to help mitigate the risks inherent in the price volatility of oil and natural gas. For the
nine months ended September 30, 2018
, we realized a settlement
loss
of
$16.2 million
. For the prior comparable period, we realized a settlement
loss
of
$26.0 thousand
, net of previously incurred premiums attributable to the settled commodity contracts.
In addition, for the
nine months ended September 30, 2018
, we recorded an unrealized
loss
of
$12.4 million
to recognize the mark-to-market change in fair value of our commodity contracts. In comparison, in the
nine months ended September 30, 2017
, we reported an unrealized
gain
of
$2.4 million
. Unrealized
gains and losses
are non-cash items.
Income taxes
- We reported income tax
expense
of
$18.1 million
for the
nine months ended September 30, 2018
as compared to no income tax expense for the comparable prior year period. During the
nine months ended September 30, 2018
and
2017
, the effective tax rate differed from the statutory rate
due primarily to the release of valuation allowances previously recorded against deferred tax assets.
Liquidity and Capital Resources
Historically, our primary sources of capital have been net cash provided by cash flow from operations, the sale of equity and debt securities, borrowings under bank credit facilities, and proceeds from the sale of properties. Our primary use of capital has been for the exploration, development, and acquisition of oil and gas properties. Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us.
We believe that our current capital resources, including cash flows from operating activities, cash on hand, and amounts available under our revolving credit facility will be sufficient to fund our planned capital expenditures and operating expenses for the next twelve months. During the
nine months ended
September 30, 2018
, our drilling and completions expenditures were primarily covered by cash flows from operating activities. To the extent actual operating results differ from our anticipated results, available borrowings under our credit facility are reduced, or we experience other unfavorable events, our liquidity could be adversely impacted. Our liquidity would also be affected if we increase our capital expenditures or complete one or more additional acquisitions. Terms of future financings may be unfavorable, and we cannot assure investors that funding will be available on acceptable terms.
As operator of the majority of our wells and undeveloped acreage, we control the timing and selection of new wells to be drilled. This allows us to modify our capital spending as our financial resources allow and market conditions support. Additionally, our relatively low utilization of debt enhances our financial flexibility as it provides a potential source of future liquidity while currently not overly burdening us with restrictive financial covenants and mandatory repayment schedules.
Sources and Uses
Our sources and uses of capital are heavily influenced by the prices that we receive for our production. Oil and gas markets will likely continue to be volatile in the future. To deal with the volatility in commodity prices, we maintain a flexible capital investment program and seek to maintain a high operating interest in our leaseholds with limited long-term capital commitments. This enables us to accelerate or decelerate our activities quickly in response to changing industry environments.
At
September 30, 2018
, we had cash, cash equivalents, and restricted cash of
$19.2 million
,
$550.0 million
outstanding on our Senior 2025 Notes, and a
$115.0 million
balance outstanding under our revolving credit facility. Our sources and (uses) of funds for the
nine months ended
September 30, 2018
and
2017
are summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
Net cash provided by operations
|
$
|
343,554
|
|
|
$
|
142,817
|
|
Capital expenditures
|
(490,124
|
)
|
|
(383,454
|
)
|
Net cash provided by other investing activities
|
1,233
|
|
|
77,017
|
|
Net cash provided by (used in) equity financing activities
|
3,039
|
|
|
(517
|
)
|
Net cash provided by debt financing activities
|
112,762
|
|
|
148,628
|
|
Net increase in cash, cash equivalents, and restricted cash
|
$
|
(29,536
|
)
|
|
$
|
(15,509
|
)
|
Net cash provided by operating activities was
$343.6 million
and
$142.8 million
for the
nine months ended
September 30, 2018
and
2017
, re
spectively. The increase in cash from operating activities reflects the increase in realized commodity prices and production.
N
et cash provided by other investing activities was
$1.2 million
and
$77.0 million
for the
nine months ended
September 30, 2018
and
2017
, respectively, which were primarily comprised of proceeds from the sale of oil and gas properties and other.
Credit Facility
The Revolver has a maturity date of
April 2, 2023
. The Revolver has a maximum loan commitment of $1.5 billion; however, the maximum amount available to be borrowed at any one time is subject to a borrowing base limitation, which stipulates that we may borrow up to the least of the aggregate maximum credit amount, the aggregate elected commitment, or the borrowing base. The borrowing base can increase or decrease based upon the value of the collateral, which secures any amounts borrowed under the Revolver. The value of the collateral will generally be derived with reference to the estimated discounted future net cash flows from our proved oil and natural gas reserves. The collateral includes substantially all of our producing wells and developed oil and gas leases.
In October 2018, t
he borrow
ing base was increased from
$550 million
to
$650 million
; however, our
elected commitment amount was $500 million
. As of
October 31, 2018
, there was a
$145.0 million
principal balance outstanding
and
no
letters of credit outstanding, leaving
$355.0 million
available to us for future borrowings. The next semi-annual redetermination is scheduled for
April 2019
. Interest on the Revolver accrues at a variable rate. The interest rate pricing grid provides for an
escalation in applicable margin based on increased utilization of the Revolver.
The Revolver requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to
4.0
to 1.0 as of the last day of any fiscal quarter or (b)
permit its ratio of current assets to current liabilities, each as defined in the agreement, to be less than
1.0
to 1.0
as of the last day o
f any fiscal quarter.
2025 Senior Notes
In November 2017, the Company issued $550 million aggregate principal amount of 6.25% Senior Notes due 2025 (the 2025 Senior Notes) in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018.
The Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to, among other restrictions and limitations: (i) incur additional indebtedness; (ii) incur liens; (iii) pay dividends; (iv) consolidate, merge, or transfer all or substantially all of its or their assets; (v) engage in transactions with affiliates; or (vi) engage in certain restricted business activities. These covenants are subject to a number of exceptions and qualifications.
Capital Expenditures
Capital expenditures for drilling and completion activities totaled
$408.3 million
and
$383.0 million
for the
nine months ended September 30, 2018
and
2017
, respectively. The following table summarizes our capital expenditures for oil and gas properties (in thousands):
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
Capital expenditures for drilling and completion activities
|
$
|
408,334
|
|
|
$
|
383,028
|
|
Acquisitions of oil and gas properties and leasehold*
|
162,081
|
|
|
89,677
|
|
Capitalized interest, capitalized G&A, and other
|
40,037
|
|
|
17,514
|
|
Accrual basis capital expenditures**
|
$
|
610,452
|
|
|
$
|
490,219
|
|
*Acquisitions of oil and gas properties and leasehold reflects the full purchase price of our various acquisitions which includes non-cash additions for liabilities assumed in the transaction such as asset retirement obligations.
**Capital expenditures reported in the condensed consolidated statement of cash flows are calculated on a cash basis, which differs from the accrual basis used to calculate the capital expenditures.
During the
nine months ended September 30, 2018
, we drilled
89
operated horizontal wells and turned
54
operated horizontal wells to sales. As of
September 30, 2018
, the Company had
9
gross (
8
net) wells that were drilled and completed, but not producing. These wells are expected to be turned to sales during the fourth quarter. As of
September 30, 2018
, we are the operator of
77
gross (
66
net) horizontal wells in progress, which excludes
30
gross (
23
net) wells for which we have only set surface casings. All of the wells in progress at
September 30, 2018
are scheduled to commence production before
December 31, 2019
. The majority of this activity was funded through cash flows from operations.
For the
nine months ended September 30, 2018
, we participated in
61
gross (
14
net) non-operated horizontal wells.
Capital Requirements
Our level of exploration, development, and acreage expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows, development results, acquisitions and divestitures, and downstream infrastructure and commitments, among other factors. Our primary need for capital will be to fund our anticipated drilling and completion activities and any other acquisitions that we may complete during
2018
.
We anticipate that our full-year
2018
drilling and completion capital expenditures for operated wells will be approximately $580 million (
$408.3 million
of which was incurred through
September 30, 2018
). However, should commodity prices and/or economic conditions change, we can reduce or accelerate our drilling and completion activities, which could have a material impact on our anticipated capital requirements.
For the near term, we believe that we have sufficient liquidity to fund our
needs through cash on hand, cash flow from operations, and additional borrowings available under our revolving credit facility. However, should this not
meet all of our long-term needs, we may need to raise additional funds to drill new wells through the sale of our securities, from third parties willing to pay our share of drilling and completing wells, or from other sources. We may not be successful in raising the capital needed to drill or acquire oil or natural gas wells. We may seek to raise funds in capital markets transactions from time to time if we believe market conditions to be favorable.
Oil and Natural Gas Commodity Contracts
We use derivative contracts to help protect against the variability in cash flows created by short-term price fluctuations associated with the sale of future oil and natural gas production. At
October 23, 2018
, we had open p
ositions covering
3.1 million
barrels of oil and
15,380
M
Mcf of natural gas. We do not use derivative instruments for speculative purposes.
Our commodity derivative instruments may include but are not limited to “collars,” “swaps,” and “put” positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in our credit facility.
During the
nine months ended September 30, 2018
, we reported an unrealized commodity activity
loss
of
$12.4 million
. Unrealized
losses
are non-cash items. We also reported a realized
loss
of
$16.2 million
, representing the settlement of commodity contracts settled during the period.
At
September 30, 2018
, we estimated that the fair value of our various commodity derivative contracts was a net
liability
of
$20.2 million
. See Item 1. Financial Statements – Note
9
,
Fair Value Measurements
, for a description of the methods we use to estimate the fair values of commodity derivative instruments.
Non-GAAP Financial Measures
In addition to financial measures presented on the basis of accounting principles generally accepted in the United States of America ("US GAAP"), we present certain financial measures which are not prescribed by US GAAP ("non-GAAP"). The following is a summary of the measure that we currently report.
Adjusted EBITDA
We use "adjusted EBITDA," a non-GAAP financial measure, for internal managerial purposes because it allows us to evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed in the table below from net income in arriving at adjusted EBITDA. We exclude those items because they 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 EBITDA is not a measure of financial performance under US GAAP and should be considered in addition to, not as a substitute for, net income. We believe that adjusted EBITDA is widely used in our industry as a measure of operating performance and may also be used by investors to measure our ability to meet debt covenant requirements. However, our definition of adjusted EBITDA may not be fully comparable to measures with similar titles reported by other companies. We define adjusted EBITDA as net income adjusted to exclude the impact of the items set forth in the table below (amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Adjusted EBITDA:
|
|
|
|
|
|
|
|
Net income
|
$
|
62,628
|
|
|
$
|
43,848
|
|
|
$
|
178,048
|
|
|
$
|
91,664
|
|
Depreciation, depletion, and accretion
|
45,188
|
|
|
33,740
|
|
|
124,146
|
|
|
73,396
|
|
Stock-based compensation expense
|
3,405
|
|
|
3,030
|
|
|
9,347
|
|
|
8,390
|
|
Mark-to-market of commodity derivative contracts:
|
|
|
|
|
|
|
|
Total loss (gain) on commodity derivatives contracts
|
8,529
|
|
|
2,383
|
|
|
28,604
|
|
|
(2,324
|
)
|
Cash settlements on commodity derivative contracts
|
(7,142
|
)
|
|
544
|
|
|
(13,263
|
)
|
|
778
|
|
Interest income
|
(23
|
)
|
|
(16
|
)
|
|
(37
|
)
|
|
(47
|
)
|
Income tax expense
|
8,918
|
|
|
—
|
|
|
18,076
|
|
|
—
|
|
Adjusted EBITDA
|
$
|
121,503
|
|
|
$
|
83,529
|
|
|
$
|
344,921
|
|
|
$
|
171,857
|
|
Critical Accounting Policies
We prepare our condensed consolidated financial statements and the accompanying notes in conformity with US GAAP, which requires management to make estimates and assumptions about future events that affect the reported amounts in the condensed consolidated financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management discusses the development, selection, and disclosure of each of the critical accounting policies.
There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used from those disclosed in the "Management’s Discussion and Analysis of Financial Condition and Results of Operations" section of the Annual Report on Form 10-K filed with the SEC on February 21, 2018 and in the financial
statements and accompanying notes contained in that report. Item 1. Financial Statements – Note
1
,
Organization and Summary of Significant Accounting Policies,
to the accompanying condensed consolidated financial statements included elsewhere in this report provides information regarding recently issued accounting pronouncements.
Cautionary Statement Concerning Forward-Looking Statements
This report contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as "believes," "expects," "anticipates," "intends," "plans," "estimates," "should," "likely," or similar expressions indicate forward-looking statements. Forward-looking statements included in this report include statements relating to future production, future capital expenditures and projects, the adequacy and nature of future sources of financing, possible future impairment charges, midstream capacity issues and the construction and effect of additional midstream infrastructure, future differentials, future production relative to volume commitments, and the potential implementation and effects of Proposition 112 and our responses thereto.
The identification in this report of factors that may affect our future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.
See "
Risk Factors"
in this report and in Item 1A of our Annual Report on Form 10-K for the
year ended December 31, 2017
filed with the SEC on February 21, 2018 for a discussion of risk factors that affect our business, financial condition, and results of operations. These risks include, among others, those associated with the following:
|
|
•
|
declines in oil and natural
gas
prices;
|
|
|
•
|
operating hazards that adversely affect our ability to conduct business;
|
|
|
•
|
uncertainties in the estimates of proved reserves;
|
|
|
•
|
the effect of seasonal weather conditions and wildlife and plant species restrictions on our operations;
|
|
|
•
|
our ability to fund, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable;
|
|
|
•
|
our ability to obtain adequate financing;
|
|
|
•
|
the effect of local and regional factors on oil and natural gas prices;
|
|
|
•
|
incurrence of ceiling test write-downs;
|
|
|
•
|
our inability to control operations on properties that we do not operate;
|
|
|
•
|
the availability and capacity of gathering systems, pipelines, and other midstream infrastructure for our production;
|
|
|
•
|
the strength and financial resources of our competitors;
|
|
|
•
|
our ability to successfully identify, execute, and effectively integrate acquisitions;
|
|
|
•
|
the effect of federal, state, and local laws and regulations;
|
|
|
•
|
the effects of, including costs to comply with, environmental legislation or regulatory initiatives, including those related to hydraulic fracturing and Proposition 112;
|
|
|
•
|
our ability to market our production;
|
|
|
•
|
the effects of local moratoria or bans on our business;
|
|
|
•
|
the effect of environmental liabilities;
|
|
|
•
|
the effect of the adoption and implementation of statutory and regulatory requirements for derivative transactions;
|
|
|
•
|
changes in U.S. tax laws;
|
|
|
•
|
our ability to satisfy our contractual obligations and commitments;
|
|
|
•
|
the amount of our indebtedness and our ability to maintain compliance with debt covenants;
|
|
|
•
|
the effectiveness of our disclosure controls and our internal controls over financial reporting;
|
|
|
•
|
the geographic concentration of our principal properties;
|
|
|
•
|
our ability to protect critical data and technology systems;
|
|
|
•
|
the availability of water for use in our operations; and
|
|
|
•
|
the risks and uncertainties described and referenced in "Risk Factors."
|