Document
false0000077877 0000077877 2020-06-04 2020-06-05


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): June 5, 2020
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PDC Energy, Inc.
(Exact name of registrant as specified in its charter)
Delaware
 
001-37419
 
95-2636730
(State or other jurisdiction of
 
(Commission
 
(I.R.S. Employer
incorporation or organization)
 
File Number)
 
Identification Number)

1775 Sherman Street, Suite 3000
Denver, Colorado 80203
(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (303) 860-5800


Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
Securities registered pursuant to Section 12(b) of the Act
Title of each class
 
Ticker Symbol
 
Name of each exchange on which registered
Common stock, par value $0.01 per share
 
PDCE
 
Nasdaq Global Select Market

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨







Item 8.01. Other Events.
As previously disclosed, PDC Energy, Inc. (“PDC”) merged with SRC Energy Inc., a Colorado corporation (“SRC”) on January 14, 2020. Pursuant to the Agreement and Plan of Merger, dated as of August 25, 2019, by and between PDC and SRC, SRC merged with and into PDC, with PDC continuing as the surviving corporation (the “Merger”). PDC’s Current Report on Form 8-K filed on January 14, 2020 contained the historical financial statements of SRC and the pro forma financial information giving effect to the Merger, and the related notes thereto, required to be filed pursuant to Item 9.01 of Form 8-K as a result of the Merger.

This Current Report on Form 8-K provides (i) the consolidated financial statements of SRC and its subsidiaries as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019 and (ii) the unaudited pro forma combined consolidated statement of operations of PDC for the year ended December 31, 2019, presented as if the Merger had occurred on January 1, 2019. This information is being provided to satisfy the requirements of Article 11 of Regulation S-X that may arise from time to time as a result of the Merger.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits


 






SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Date: June 5, 2020
PDC ENERGY, INC.

By:
/s/ Nicole Martinet
 
Nicole Martinet
 
General Counsel, Senior Vice President and Corporate Secretary



Exhibit
 

Exhibit 99.1    






SRC Energy Inc. and Subsidiaries
Financial Statements as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019



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SRC ENERGY INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Index to Consolidated Financial Statements as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019
 
 
Independent Auditors' Report
 
 
Consolidated Balance Sheets
 
 
Consolidated Statements of Operations
 
 
Consolidated Statements of Changes in Shareholders’ Equity
 
 
Consolidated Statements of Cash Flows
 
 
Notes to Consolidated Financial Statements

1



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INDEPENDENT AUDITORS’ REPORT

To SRC Energy Inc.

We have audited the accompanying consolidated financial statements of SRC Energy Inc. and its subsidiaries (the "Company"), which comprise the consolidated balance sheets as of December 31, 2019 and 2018, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes to the consolidated financial statements.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of SRC Energy Inc. and its subsidiaries as of December 31, 2019 and 2018, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2019 in accordance with accounting principles generally accepted in the United States of America.









2



Disclaimer of Opinion on Supplementary Information

Our audits were conducted for the purpose of forming an opinion on the financial statements as a whole. The supplementary oil and natural gas producing information in Note 18 to the consolidated financial statements is presented for the purpose of additional analysis and is not a required part of the financial statements. This supplementary information is the responsibility of the Company’s management. Such information has not been subjected to the auditing procedures applied in our audits of the financial statements and, accordingly it is inappropriate to and we do not express an opinion on the supplementary information referred to above.

/s/ DELOITTE & TOUCHE LLP

February 26, 2020


3

SRC ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data) 


ASSETS
December 31, 2019
 
December 31, 2018
Current assets:
 
 
 
Cash and cash equivalents
$
65,641

 
$
49,609

Accounts receivable:
 
 
 
Oil, natural gas, and NGL sales
76,807

 
100,973

Trade
23,826

 
39,415

Commodity derivative assets

 
34,906

Other current assets
14,993

 
7,537

Total current assets
181,267

 
232,440

 
 
 
 
Property and equipment:
 
 
 
Oil and gas properties, full cost method:
 
 
 
Proved properties, net of accumulated depletion
1,829,880

 
1,545,445

Wells in progress
224,052

 
227,262

Unproved properties and land, not subject to depletion
673,615

 
740,453

Oil and gas properties, net
2,727,547

 
2,513,160

Other property and equipment, net
3,903

 
5,540

Total property and equipment, net
2,731,450

 
2,518,700

Other assets
9,046

 
3,574

Total assets
$
2,921,763

 
$
2,754,714

 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued expenses
$
98,126

 
$
150,010

Revenue payable
98,780

 
97,030

Production taxes payable
100,346

 
95,099

Asset retirement obligations
8,394

 
11,694

Commodity derivative liabilities
11,789

 

Total current liabilities
317,435

 
353,833

 
 
 
 
Revolving credit facility
165,000

 
195,000

Notes payable, net of issuance costs
540,615

 
539,360

Deferred taxes
94,613

 
37,967

Asset retirement obligations
46,288

 
40,052

Other liabilities
2,986

 
2,210

Total liabilities
1,166,937

 
1,168,422

 
 
 
 
Commitments and contingencies (See Note 16)
 
 
 
 
 
 
 
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 shares authorized: 243,684,103 and 242,608,284 shares issued and outstanding as of December 31, 2019 and 2018, respectively
244

 
243

Additional paid-in capital
1,507,256

 
1,492,107

Retained earnings
247,326

 
93,942

Total shareholders' equity
1,754,826

 
1,586,292

 
 
 
 
Total liabilities and shareholders' equity
$
2,921,763

 
$
2,754,714

The accompanying notes are an integral part of these consolidated financial statements

4

SRC ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)

 
Year Ended December 31,
 
2019
 
2018
 
2017
Oil, natural gas, and NGL revenues
$
635,502

 
$
645,641

 
$
362,516

 
 
 
 
 
 
Expenses:
 
 
 
 
 
Lease operating expenses
58,384

 
43,291

 
19,496

Transportation and gathering
16,794

 
9,135

 
3,226

Production taxes
34,112

 
59,830

 
36,266

Depreciation, depletion, and accretion
240,157

 
179,773

 
112,309

Goodwill impairment

 
40,711

 

Unused commitment charge

 

 
669

General and administrative
46,292

 
38,618

 
32,965

Total expenses
395,739

 
371,358

 
204,931

 
 
 
 
 
 
Operating income
239,763

 
274,283

 
157,585

 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Commodity derivative gain (loss)
(30,227
)
 
23,413

 
(4,226
)
Interest expense, net of amounts capitalized

 

 
(11,842
)
Interest income
314

 
99

 
363

Other income
180

 
194

 
503

Total other income (expense)
(29,733
)
 
23,706

 
(15,202
)
 
 
 
 
 
 
Income before income taxes
210,030

 
297,989

 
142,383

 
 
 
 
 
 
Income tax expense (benefit)
56,646

 
37,967

 
(99
)
Net income
$
153,384

 
$
260,022

 
$
142,482


The accompanying notes are an integral part of these consolidated financial statements

5

SRC ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(in thousands, except share data)

 
Number of Common
Shares
 
Par Value
Common Stock
 
Additional
Paid-In Capital
 
Retained
Earnings
(Deficit)
 
Total Shareholders'
Equity
Balance, January 1, 2017
200,647,572

 
$
201

 
$
1,148,998

 
$
(308,460
)
 
$
840,739

Shares issued in equity offering
40,250,000

 
40

 
312,131

 

 
312,171

Shares issued under stock bonus and equity incentive plans
280,284

 

 
4,976

 

 
4,976

Shares issued for exercise of stock options
187,666

 

 
740

 

 
740

Stock-based compensation for options

 

 
5,076

 

 
5,076

Stock-based compensation for performance-vested stock units

 

 
2,938

 

 
2,938

Payment of tax withholdings using withheld shares

 

 
(688
)
 

 
(688
)
Other activity

 

 
102

 
(102
)
 

Net income

 

 

 
142,482

 
142,482

Balance, December 31, 2017
241,365,522

 
241

 
1,474,273

 
(166,080
)
 
1,308,434

Shares issued under stock bonus and equity incentive plans
432,700

 
1

 
5,972

 

 
5,973

Shares issued for exercise of stock options
810,062

 
1

 
4,301

 

 
4,302

Stock-based compensation for options

 

 
4,543

 

 
4,543

Stock-based compensation for performance-vested stock units

 

 
4,212

 

 
4,212

Payment of tax withholdings using withheld shares

 

 
(1,121
)
 

 
(1,121
)
Other activity
 
 

 
(73
)
 

 
(73
)
Net income

 

 

 
260,022

 
260,022

Balance, December 31, 2018
242,608,284

 
243

 
1,492,107

 
93,942

 
1,586,292

Shares issued under stock bonus and equity incentive plans
1,075,819

 
1

 
8,524

 

 
8,525

Stock-based compensation for options

 

 
2,949

 

 
2,949

Stock-based compensation for performance-vested stock units

 

 
4,873

 

 
4,873

Payment of tax withholdings using withheld shares

 

 
(1,197
)
 

 
(1,197
)
Net income

 

 

 
153,384

 
153,384

Balance, December 31, 2019
243,684,103

 
$
244

 
$
1,507,256

 
$
247,326

 
$
1,754,826


The accompanying notes are an integral part of these consolidated financial statements

6

SRC ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

 
Year Ended December 31,
 
2019
 
2018
 
2017
Cash flows from operating activities:
 
 
 
 
 
Net income
$
153,384

 
$
260,022

 
$
142,482

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depletion, depreciation, and accretion
240,157

 
179,773

 
112,309

Goodwill impairment

 
40,711

 

Settlements of asset retirement obligations
(10,938
)
 
(6,388
)
 
(4,541
)
Loss on extinguishment of debt

 

 
11,842

Provision for deferred taxes
56,646

 
37,967

 

Stock-based compensation expense
13,043

 
12,287

 
11,225

Mark-to-market of commodity derivative contracts:
 
 
 
 
 
Total loss (gain) on commodity derivative contracts
30,227

 
(23,413
)
 
4,226

Cash settlements on commodity derivative contracts
17,402

 
(19,359
)
 
942

Cash premiums paid for commodity derivative contracts
(1,971
)
 

 

Changes in operating assets and liabilities
40,722

 
39,543

 
12,830

Net cash provided by operating activities
538,672

 
521,143

 
291,315

 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
Acquisitions of oil and gas properties and leaseholds
(5,255
)
 
(149,658
)
 
(661,468
)
Capital expenditures for drilling and completion activities
(441,934
)
 
(516,480
)
 
(450,384
)
Other capital expenditures
(56,380
)
 
(47,916
)
 
(17,841
)
Acquisition of land and other property and equipment
(368
)
 
(3,039
)
 
(4,186
)
Proceeds from sales of oil and gas properties and other
13,071

 
1,627

 
93,573

Net cash used in investing activities
(490,866
)
 
(715,466
)
 
(1,040,306
)
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
Proceeds from the sale of stock

 

 
322,000

Offering costs

 
(157
)
 
(9,745
)
Proceeds from the employee exercise of stock options

 
4,302

 
741

Payment of employee payroll taxes in connection with shares withheld
(1,197
)
 
(1,121
)
 
(688
)
Proceeds from revolving credit facility

 
195,000

 
250,000

Principal repayments on revolving credit facility
(30,000
)
 

 
(250,000
)
Proceeds from issuance of notes payable

 

 
550,000

Repayment of notes payable

 

 
(88,234
)
Financing fees on issuance of notes payable and amendments to revolving credit facility
(379
)
 
(2,588
)
 
(13,145
)
Finance lease payments
(198
)
 
(276
)
 

Net cash provided by (used in) financing activities
(31,774
)
 
195,160

 
760,929

 
 
 
 
 
 
Net increase in cash, cash equivalents, and restricted cash
16,032

 
837

 
11,938

 
 
 
 
 
 
Cash, cash equivalents, and restricted cash at beginning of period
49,609

 
48,772

 
36,834

 
 
 
 
 
 
Cash, cash equivalents, and restricted cash at end of period
$
65,641

 
$
49,609

 
$
48,772

Supplemental Cash Flow Information (See Note 17)

The accompanying notes are an integral part of these consolidated financial statements

7



SRC ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2019, 2018, and 2017

1.
Organization and Summary of Significant Accounting Policies

Organization:  SRC Energy Inc. (the "Company" or "SRC") is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and NGLs, primarily in the D-J Basin of Colorado.

Basis of Presentation:  The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.  The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("US GAAP").

Merger: On August 25, 2019, the Company entered into an Agreement and Plan of Merger ("PDC Merger Agreement") with PDC Energy, Inc., a Delaware corporation ("PDC"). On January 14, 2020, SRC merged with and into PDC, with PDC continuing as the surviving corporation (the “PDC Merger”). Pursuant to the PDC Merger Agreement, at the effective time of the PDC Merger, the Company's shareholders received 0.158 of a share of PDC common stock for each outstanding share of the Company's common stock, plus cash in lieu of any fractional PDC shares that otherwise would have been issued (the "Merger Consideration"). The PDC Merger Agreement also addresses the treatment of SRC equity awards in the PDC Merger. PDC’s common stock is listed and traded on the NASDAQ Global Select Market under the symbol PDCE. For the year ended December 31, 2019, the Company has incurred $8.7 million of merger transaction costs recognized in general and administrative expense of the consolidated statements of operations.

Use of Estimates:     The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and natural gas reserves, production tax expenses, derivatives, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the consolidated financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates.

Cash and Cash Equivalents:  The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include lease acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or retirement of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves.

Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved oil and natural gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is the impairment test prescribed by regulations of the Securities and Exchange Commission ("SEC").  The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and natural gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties.  The present value of estimated future net revenues is computed by applying prices of oil and natural gas reserves to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be

8



incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued in the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During the years ended December 31, 2019, 2018, and 2017, the Company did not recognize any ceiling test impairments.

The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials and are held constant for the productive life of each well.

Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and natural gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

The determination of depletion expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

Capitalized Interest: The Company capitalizes interest on expenditures made in connection with acquisitions of mineral interests that are currently not subject to depletion and exploration and development projects that are in progress.  Interest is capitalized during the period that activities are in progress to bring the projects to their intended use.  See Note 10 for additional information.

Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information.

Other Property and Equipment: Support equipment (including such items as vehicles, computer equipment, and software), office leasehold improvements, office furniture and equipment, and buildings are stated at historical cost. Expenditures for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment, office leasehold improvements, and office furniture and equipment are depreciated under the straight-line method using estimated useful lives ranging from three to five years. Buildings are also depreciated under the straight-line method using estimated useful lives of thirty-nine years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its other property and equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. 


9



Accounts Payable and Accrued Expenses: Accounts payable and accrued expenses consist of the following (in thousands):
 
As of December 31,
 
2019
 
2018
Trade accounts payable
$
2,829

 
$
2,029

Accrued well costs
72,121

 
130,784

Accrued G&A
5,647

 
4,913

Accrued LOE
8,380

 
8,366

Accrued interest
3,822

 
3,574

Operating lease liability
4,881

 

Accrued other
446

 
344

 
$
98,126

 
$
150,010


Revenue Payable: Revenue payable represents amounts collected from purchasers for oil and natural gas sales which are revenues due to other working or royalty interest owners. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received unless we are waiting for the other owners to confirm their ownership.

Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently retired.  Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to retire the asset, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit-adjusted risk-free rate.  Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the related asset.  Asset retirement costs ("ARCs") related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value, while the net capitalized cost decreases over the useful life of the asset as depletion expense is recognized.  In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment.

Goodwill: Goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination.  Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. Historically, we performed the annual impairment assessment as of October 1.

When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must calculate the estimated fair value of the reporting unit.  If the carrying value of the reporting unit exceeds the estimated fair value, the Company should recognize an impairment charge.  The amount of impairment for goodwill is measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill.  For purposes of assessing goodwill, the Company only has one reporting unit.

In the prior year, the Company performed its annual goodwill impairment test as of October 1, 2018 and determined that no impairment had occurred. However, as a result of a sustained decrease in the price of our common stock during the fourth quarter of 2018 caused by a significant decline in oil prices over the same period, the Company performed another goodwill impairment test as of December 31, 2018. The impairment test performed by the Company indicated that the carrying value of its reporting unit exceeded its fair value and that an impairment loss should be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to the reporting unit. Based on these results, the Company recorded a non-cash impairment charge of $40.7 million, reducing the carrying value of goodwill to zero. The Company utilized a market approach

10



in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time and contain considerable management judgments.

Oil, Natural Gas, and NGL Revenues: The Company derives revenue primarily from the sale of oil, natural gas, and NGLs produced on its properties.  Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests.  Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the product is transferred to the purchaser.  Payment is generally received between thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Major Customers:    The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil, natural gas, and NGL revenue ("major customers") for each of the periods presented are shown in the following table:
 
Year Ended December 31,
 
2019
 
2018
 
2017
Company A
28%
 
17%
 
*
Company B
19%
 
20%
 
24%
Company C
16%
 
22%
 
33%
Company D
11%
 
13%
 
17%
Company E
*
 
13%
 
*
* 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 December 31,
 
2019
 
2018
Company A
20%
 
12%
Company B
18%
 
15%
Company C
11%
 
12%
Company D
*
 
13%
* 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 employed in, and all of its revenues are derived from, the oil and gas industry.

Lease Operating Expenses:  Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred.  Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, fuel consumed, supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities.
 
Stock-Based Compensation:  The Company recognizes all equity-based compensation as stock-based compensation

11



expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model.  For stock bonus awards and restricted stock units, fair value is the closing stock price for the Company's common stock on the grant date. For performance-vested stock units, fair value is calculated using a Monte Carlo simulation.  Once a grant date has been established, the compensation is recognized over the remaining vesting period of the grant.  See Note 11 for additional information.
 
Income Tax:  Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.
 
No significant uncertain tax positions were identified as of any date on or before December 31, 2019.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of December 31, 2019, the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 13 for further information.

Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars to reduce the effect of price changes on a portion of its future oil and natural gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative gain (loss) line in the consolidated statement of operations. The Company values its derivative instruments by obtaining independent market quotes as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, refer to Note 8.

Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of oil to a third-party marketer and/or other counterparties that transport oil via pipelines. See Note 16 for additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil that we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the consolidated statement of operations.

Recently Adopted Accounting Pronouncements:

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") No. 2016-02, Leases (Topic 842), followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASC 842”). ASC 842 requires lessees to recognize right-of-use (“ROU”) assets and lease payment liabilities in the balance sheet for leases representing the Company’s right to use the underlying assets over the lease term. Each lease that is recognized in the balance sheet will be classified as either finance or operating, with such classification affecting the pattern and classification of expense recognition in the consolidated statements of operations and presentation within the statements of cash flows.

The Company adopted ASC 842 on January 1, 2019 using the modified retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby previously reported periods continue to be reported in accordance with historical accounting guidance for leases that were in effect for those prior periods. Policy elections and practical expedients that the Company has implemented as part of adopting ASC 842 include (a) excluding from the balance sheet leases with terms that are less than or equal to one year, (b) for all existing asset classes that contain both lease and non-lease components, combining these components together and accounting for them as a single lease component, (c) the package of practical expedients, which among other things allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements, which were not accounted for under the previous leasing guidance, that existed or expired before adoption of ASC 842. ASC 842 does not apply to leases used in the exploration or use of minerals, oil, and natural gas.

The Company's adoption of ASC 842 resulted in an increase in other assets, accounts payable and accrued expenses, and other liabilities line items in the January 1, 2019 consolidated balance sheet as a result of the additional ROU assets and related

12



lease liabilities. Upon adoption on January 1, 2019, the Company recognized approximately $2.4 million in ROU assets and $4.3 million in liabilities for its operating leases. There was no cumulative effect to retained earnings upon the adoption of this guidance. See Note 15 for the new disclosures required by ASC 842.

Recently Issued Accounting Pronouncements: 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.

Change in estimate: Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. During the year ended December 31, 2019, the Company reduced its estimate for 2018 severance taxes. When preparing the 2018 severance tax return, the credit for ad valorem taxes was greater than originally estimated, resulting in a reduction of 2018 severance taxes. Based on this analysis, the Company's prior year accrual was reduced, resulting in an approximate $7.9 million reduction to our production taxes, which increased our operating income for the year ended December 31, 2019 by a corresponding amount.

2.
Property and Equipment

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
 
As of December 31,
 
2019
 
2018
Oil and gas properties, full cost method:
 
 
 
Costs of proved properties:
 
 
 
Producing and non-producing
$
2,905,625

 
$
2,385,958

Less, accumulated depletion and full cost ceiling impairments
(1,075,745
)
 
(840,513
)
Subtotal, proved properties, net
1,829,880

 
1,545,445

 
 
 
 
Costs of wells in progress
224,052

 
227,262

 
 
 
 
Costs of unproved properties and land, not subject to depletion:
 
 
 
Lease acquisition and other costs
664,220

 
731,058

Land
9,395

 
9,395

Subtotal, unproved properties and land
673,615

 
740,453

 
 
 
 
Costs of other property and equipment:
 
 
 
Other property and equipment
10,102

 
9,642

Less, accumulated depreciation
(6,199
)
 
(4,102
)
Subtotal, other property and equipment, net
3,903

 
5,540

 
 
 
 
Total property and equipment, net
$
2,731,450

 
$
2,518,700


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. During the years ended December 31, 2019, 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.

The costs of unproved properties are withheld from the depletion base until such time as the properties are either developed or impaired. Unproved properties are reviewed on an annual basis, or more frequently if necessary, for impairment and, if impaired, are reclassified to proved properties and included in the depletion base. During the years ended December 31, 2019 and 2017, these reviews indicated that the carrying values had not been impaired. Therefore, no impairment was necessary for the years end December 31, 2019 or 2017. However, during the year ended December 31, 2018, the Company recorded an impairment of $1.2 million to the carrying value of its unproved properties.


13



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):
 
Year Ended December 31,
 
2019
 
2018
 
2017
Capitalized overhead
$
14,481

 
$
12,775

 
$
10,293


Costs Incurred:  Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands):
 
Year Ended December 31,
 
2019
 
2018
 
2017
Acquisition of property:
 
 
 
 
 
Unproved
$
2,428

 
$
46,039

 
$
538,489

Proved
3,512

 
136,652

 
139,154

Exploration costs

 

 

Development costs
384,008

 
583,660

 
460,875

Other property and equipment and land
592

 
3,039

 
4,397

Capitalized interest, capitalized G&A, and other
72,713

 
57,039

 
26,677

Total costs incurred
$
463,253

 
$
826,429

 
$
1,169,592


Capitalized Costs Excluded from Depletion:  The following table summarizes costs related to unproved properties and development costs that have been excluded from amounts subject to depletion at December 31, 2019 (in thousands):
 
Period Incurred
 
 
 
Year Ended December 31,
 
Prior to January 1, 2017
 
Total as of December 31, 2019
 
2019
 
2018
 
2017
 
 
Unproved leasehold acquisition costs
$
8,791

 
$
74,184

 
$
387,866

 
$
193,379

 
$
664,220

Unproved development costs
62,845

 
7,486

 

 

 
70,331

Total unevaluated costs
$
71,636

 
$
81,670

 
$
387,866

 
$
193,379

 
$
734,551


There were no individually significant properties or significant development projects included in the Company’s unproved property balance.  The Company regularly evaluates these costs to determine whether impairment has occurred or proved reserves have been established.  The majority of these costs are expected to be evaluated and included in the depletion base within four years.

3.
Acquisitions

The Company seeks to acquire developed and undeveloped oil and gas properties in the core Wattenberg Field to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons.

In September 2018, the Company completed the purchase of operated vertical and horizontal wells in the Greeley-Crescent development area. This purchase was contemplated in November 2017 when we entered into a purchase and sale agreement pursuant to which we agreed to acquire a total of approximately 30,200 net acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field ("GCII Acquisition"). The first closing for this agreement occurred in December 2017. The effective date for this second closing was September 1, 2018. The total purchase price for the second closing was $96.9 million, composed of cash of $64.2 million and assumed liabilities of $32.7 million. The assumed liabilities included $25.8 million for asset retirement obligations. The entire purchase price has been allocated to proved oil and gas properties.


14



In August 2018, the Company completed the purchase of leasehold acreage and associated non-operated production for $37.2 million in cash and the assumption of certain liabilities for a total purchase price of $37.5 million. The acreage increased our working interest in existing operations and planned wells. The purchase price for the acquisition was allocated as $23.9 million to proved oil and gas properties and $13.6 million to unproved oil and gas properties.

All of these transactions were accounted for as asset acquisitions, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date.

4.
Depletion, depreciation, and accretion ("DD&A")

DD&A consisted of the following (in thousands):
 
Year Ended December 31,
 
2019
 
2018
 
2017
Depletion of oil and gas properties
$
234,459

 
$
175,441

 
$
109,287

Depreciation and accretion
5,698

 
4,332

 
3,022

Total DD&A Expense
$
240,157

 
$
179,773

 
$
112,309


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 proved reserves at the beginning of the quarter. For the year ended December 31, 2019, production of 22,584 thousand barrels of oil equivalent ("MBOE") represented 7.1% of estimated total proved reverses. For the year ended December 31, 2018, production of 18,448 MBOE represented 5.7% of estimated total proved reserves. For the year ended December 31, 2017, production of 12,481 MBOE represented 5.2% of estimated total proved reserves. DD&A expense was $10.63 per barrel of oil equivalent ("BOE"), $9.74 per BOE, and $9.00 per BOE for the years ended December 31, 2019, 2018, and 2017, respectively.

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, plug and reclaim the wells, and restore 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):
 
Year Ended December 31,
 
2019
 
2018
 
 
 
 
Beginning asset retirement obligation
$
51,746

 
$
31,622

Obligations incurred with development activities
2,311

 
4,174

Obligations assumed with acquisitions

 
26,150

Accretion expense
3,472

 
2,310

Obligations discharged with asset retirements and divestitures
(11,712
)
 
(12,267
)
Revisions in previous estimates
8,865

 
(243
)
Ending asset retirement obligation
$
54,682

 
$
51,746

Less, current portion
(8,394
)
 
(11,694
)
Non-current portion
$
46,288

 
$
40,052


During the year ended December 31, 2019, the Company increased its asset retirement obligation by $8.9 million due primarily to a revision to the expected timing of the future cash flows.


15



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 December 31, 2019, the terms of the Revolver provided for up to $1.5 billion in borrowings, an aggregate elected commitment of $550 million, and a borrowing base limitation of $650 million. As of December 31, 2019 and December 31, 2018, the outstanding principal balance was $165.0 million and $195.0 million, respectively. At December 31, 2019, the Company had $11.6 million letters of credit issued.

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 year ended December 31, 2019 and 2018 was 4.3% and 4.2%, 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 lenders consented to a postponement of the redetermination scheduled for November 2019.

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 December 31, 2019, the most recent compliance date, the Company was in compliance with these loan covenants.

In connection with the completion of the PDC Merger on January 14, 2020, PDC terminated all commitments and repaid all amounts outstanding under the Restated Credit Agreement.

7.
Notes Payable

In November 2017, the Company issued $550 million aggregate principal amount of 6.25% Senior Notes (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 "Indenture") and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. As of December 31, 2019, none of the Company's subsidiaries met the criteria outlined within the Indenture to be considered a guarantor of the 2025 Senior Notes. As of December 31, 2019, the most recent compliance date, the Company was in compliance with its loan covenants.

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 then-outstanding Revolver balance.

In connection with the completion of the PDC Merger on January 14, 2020, PDC assumed all of the Company’s obligations under the 2025 Senior Notes. On January 17, 2020, PDC made an offer to repurchase the 2025 Senior Notes from the holders at 101% of the principal amount of the 2025 Senior Notes, together with any accrued and unpaid interest to the date of repurchase. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding 2025 Senior Notes accepted the redemption offer for a total redemption price of approximately $452.2 million, plus accrued and unpaid interest of $6.2 million. The repurchase was funded by proceeds from PDC's revolving credit facility.


16



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.

A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may at times purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase.

A "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create "collars." We regularly utilize "no premium" (a.k.a. zero cost) collars where the cost of the put is offset by the proceeds of the call. At settlement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price.

Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price or price differential over a specified term.

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.

In conjunction with certain derivative contracts, the Company deferred the payment of certain put premiums. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company amortizes the deferred put premium liabilities as they become payable. As of December 31, 2019, the Company had no outstanding put premium liabilities.

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 five counterparties. Each of the counterparties are lenders in the Revolver. 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 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 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 consolidated statements of cash flows.

The Company’s commodity derivative contracts as of December 31, 2019 are summarized below:
Settlement Period
 
Derivative
Instrument
 
Volumes
(Bbls per day)
 
Weighted-Average Fixed Price
Crude Oil - NYMEX WTI
 
 
 
 
 
 
Jan 1, 2020 - Dec 31, 2020
 
Swap
 
10,700

 
$
55.42


17




Offsetting of Derivative Assets and Liabilities

As of December 31, 2019 and 2018, 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 consolidated balance sheets.

The following table provides a reconciliation between the net assets and liabilities reflected in the accompanying 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 December 31, 2019
Underlying Commodity
 
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
 
$

 
$

 
$

Commodity derivative contracts
 
Non-current assets
 
$

 
$

 
$

Commodity derivative contracts
 
Current liabilities
 
$
11,789

 
$

 
$
11,789

Commodity derivative contracts
 
Non-current liabilities
 
$

 
$

 
$

 
 
 
 
As of December 31, 2018
Underlying Commodity
 
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
 
$
39,485

 
$
(4,579
)
 
$
34,906

Commodity derivative contracts
 
Non-current assets
 
$

 
$

 
$

Commodity derivative contracts
 
Current liabilities
 
$
4,579

 
$
(4,579
)
 
$

Commodity derivative contracts
 
Non-current liabilities
 
$

 
$

 
$


The amount of gain (loss) recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands):
 
Year Ended December 31,
 
2019
 
2018
 
2017
Realized gain (loss) on commodity derivatives
$
16,468

 
$
(19,359
)
 
$
39

Unrealized gain (loss) on commodity derivatives
(46,695
)
 
42,772

 
(4,265
)
Total gain (loss)
$
(30,227
)
 
$
23,413

 
$
(4,226
)

Realized gains and losses represent the monthly settlement of derivative contracts at their scheduled maturity date, net of the premiums attributable to settled commodity contracts. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):
 
Year Ended December 31,
 
2019
 
2018
 
2017
Monthly settlements
$
18,439

 
$
(19,359
)
 
$
1,062

Premiums attributable to settled commodity contracts
(1,971
)
 

 
(1,023
)
Total realized gain (loss)
$
16,468

 
$
(19,359
)
 
$
39



18



Credit Related Contingent Features

As of December 31, 2019, all 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.

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 goodwill, unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations and certain asset acquisitions. Refer to Notes 1, 3, and 5 for further discussion of goodwill, business combinations and asset acquisitions, and asset retirement obligations, respectively.

The Company determines the estimated fair value of its goodwill using a quoted market price for the Company as adjusted for a control premium. As the control premium is an unobservable pricing input, this input is deemed to be a Level 3 input. See Note 1 for additional information.

The acquisition of a group of assets in a business combination transaction and 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 reclamation 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 rate, and estimated dates of retirement. 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 December 31, 2019
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial assets and liabilities:
 
 
 
 
 
 
 
Commodity derivative asset
$

 
$

 
$

 
$

Commodity derivative liability
$

 
$
11,789

 
$

 
$
11,789


19



 
Fair Value Measurements at December 31, 2018
 
Level 1
 
Level 2
 
Level 3
 
Total
Financial assets and liabilities:
 
 
 
 
 
 
 
Commodity derivative asset
$

 
$
34,906

 
$

 
$
34,906

Commodity derivative liability
$

 
$

 
$

 
$


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 December 31, 2019, derivative instruments utilized by the Company consist of swaps. The oil, natural gas, and propane derivative markets are highly active. Although the Company’s derivative instruments are 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, cash held in escrow, 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 $555.8 million at December 31, 2019. The Company determined the fair value of its notes payable at December 31, 2019 by using observable market-based information for quoted prices of the debt instruments. The Company has classified the notes payable as Level 1.

10.
Interest Expense

The components of interest expense are (in thousands):
 
Year Ended December 31,
 
2019
 
2018
 
2017
Revolving credit facility
$
7,744

 
$
2,209

 
$
2,004

Notes payable
34,375

 
34,375

 
10,036

Amortization of debt issuance costs and other
3,534

 
3,926

 
3,084

Debt extinguishment costs

 

 
11,842

Less: interest capitalized
(45,653
)
 
(40,510
)
 
(15,124
)
Interest expense, net
$

 
$

 
$
11,842


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.

On August 25, 2019, the Company entered into the PDC Merger Agreement with PDC. On January 14, 2020, the PDC Merger was completed. Pursuant to the PDC Merger Agreement, at the effective time of the PDC Merger, the Company's

20



shareholders received 0.158 of a share of PDC common stock for each outstanding share of the Company's common stock, plus cash in lieu of any fractional PDC shares that otherwise would have been issued.

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 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 December 31, 2019, there were 10,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which 1,039,966 shares were available for future grants. The shares available for future grant exclude 1,508,273 shares which have been reserved for future vesting of performance-vested stock units in the event that these awards met the criterion to vest at their maximum multiplier.

At the effective time of the PDC Merger, (1) each outstanding SRC restricted stock unit and stock bonus award became fully vested and was cancelled in exchange for the Merger Consideration in respect of each share of SRC common stock underlying the applicable award, (2) each SRC performance stock unit that was outstanding became vested and was cancelled in exchange for the Merger Consideration in respect of each share of SRC common stock underlying the applicable award (with such number of shares of SRC common stock determined based on target performance and any remaining shares of SRC common stock subject to the award forfeited), less applicable tax withholdings, (3) each SRC performance stock unit granted following the execution of the PDC Merger Agreement as required by the terms of the PDC Merger Agreement (see below for further discussion) was assumed and converted into a PDC performance stock unit that remains subject to the same terms and conditions (including performance-vesting terms) that applied immediately prior to the effective time, except that the number of shares of PDC common stock subject to each PDC performance stock unit was determined by multiplying the number of shares subject to the SRC performance stock unit by 0.158 (rounded to the nearest whole share), (4) each outstanding in-the-money SRC stock option was cancelled in exchange for the Merger Consideration in respect of each “Net Share Option” subject to the applicable option and (5) each outstanding, out-of-the-money SRC stock option was cancelled for no consideration.

The amount of stock-based compensation was as follows (in thousands):
 
Year Ended December 31,
 
2019
 
2018
 
2017
Stock options
$
2,949

 
$
4,543

 
$
5,076

Performance-vested stock units
4,873

 
4,212

 
2,938

Restricted stock units and stock bonus shares
8,524

 
5,972

 
4,977

Total stock-based compensation
16,346

 
14,727

 
12,991

Less: stock-based compensation capitalized
(3,303
)
 
(2,440
)
 
(1,766
)
Total stock-based compensation expense
$
13,043

 
$
12,287

 
$
11,225


Stock options

No stock options were granted during the years ended December 31, 2019, 2018, and 2017.


21



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, 2016
6,001,500

 
$
9.27

 
8.0 years
 
$
6,515

Granted

 

 
 
 

Exercised
(187,666
)
 
3.95

 
 
 
976

Expired
(41,000
)
 
11.98

 
 
 
 
Forfeited
(136,000
)
 
10.97

 

 


Outstanding, December 31, 2017
5,636,834

 
9.38

 
7.0 years
 
4,806

Granted

 

 
 
 
 
Exercised
(823,883
)
 
5.36

 
 
 
4,611

Expired
(37,400
)
 
11.22

 
 
 
 
Forfeited
(122,917
)
 
9.93

 
 
 
 
Outstanding, December 31, 2018
4,652,634

 
10.06

 
6.4 years
 
49

Granted

 

 
 
 
 
Exercised

 

 
 
 

Expired
(85,000
)
 
9.90

 
 
 
 
Forfeited
(58,800
)
 
8.28

 
 
 
 
Outstanding, December 31, 2019
4,508,834

 
$
10.09

 
5.1 years
 
$
28

Outstanding, Exercisable at December 31, 2019
4,110,834

 
$
10.23

 
5.0 years
 
$
28


The following table summarizes information about issued and outstanding stock options as of December 31, 2019:
 
 
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

 
2.5 years
 
35,000

 
$
3.31

 
2.5 years
$5.00 - $6.99
 
671,000

 
6.29

 
4.2 years
 
530,600

 
6.30

 
3.6 years
$7.00 - $10.99
 
1,323,334

 
9.42

 
5.1 years
 
1,146,134

 
9.44

 
4.9 years
$11.00 - $13.46
 
2,479,500

 
11.57

 
5.4 years
 
2,399,100

 
11.57

 
5.4 years
Total
 
4,508,834

 
$
10.09

 
5.1 years
 
4,110,834

 
$
10.23

 
5.0 years

The estimated unrecognized compensation cost from stock options not vested as of December 31, 2019, which will be recognized ratably over the remaining vesting period, is as follows:
Unrecognized compensation (in thousands)
$
1,297

Remaining vesting period
1.0 years


At the effective time of the PDC Merger, 10,000 stock options were cancelled in exchange for the Merger Consideration and 4,473,834 stock options were cancelled for no consideration.

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

22



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 periods presented:
 
Number of
Shares
 
Weighted-Average
Grant-Date Fair Value
Not vested, December 31, 2016
890,336

 
$
9.55

Granted
681,568

 
8.29

Vested
(455,772
)
 
9.21

Forfeited
(28,746
)
 
9.74

Not vested, December 31, 2017
1,087,386

 
8.89

Granted
1,130,388

 
7.76

Vested
(478,517
)
 
8.96

Forfeited
(99,339
)
 
9.28

Not vested, December 31, 2018
1,639,918

 
8.07

Granted
1,733,634

 
4.88

Vested
(876,142
)
 
8.01

Forfeited
(89,980
)
 
6.25

Not vested, December 31, 2019
2,407,430

 
$
5.86


The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2019, which will be recognized ratably over the remaining vesting period, is as follows:
Unrecognized compensation (in thousands)
$
8,365

Remaining vesting period
1.8 years


At the effective time of the PDC Merger, 1,701,568 restricted stock units and stock bonus awards became fully vested and were cancelled in exchange for the Merger Consideration.

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 December 31, 2019, 274,898 Goal-Based PSUs remained outstanding.

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 fair value of the TSR PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be

23



obtained for those iterations. In the case of the Company’s TSR PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the TSR PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period, and the volatilities for each of the Company’s peers.

The assumptions used in valuing the TSR PSUs granted were as follows:
 
Year Ended December 31,
 
2019
 
2018
 
2017
Weighted-average expected term
2.9 years

 
2.8 years

 
2.9 years

Weighted-average expected volatility
48
%
 
52
%
 
59
%
Weighted-average risk-free rate
2.49
%
 
2.41
%
 
1.34
%

As of December 31, 2019, unrecognized compensation for TSR PSUs was $5.1 million and will be amortized through 2021. A summary of the status and activity of TSR PSUs is presented in the following table:
 
Number of Units1
 
Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016
478,510

 
$
8.09

Granted
473,374

 
10.79

Vested

 

Forfeited

 

Not vested, December 31, 2017
951,884

 
9.44

Granted
321,507

 
13.11

Vested
(465,188
)
 
8.09

Forfeited
(28,175
)
 
10.15

Not vested, December 31, 2018
780,028

 
11.73

Granted
918,842

 
5.74

Vested
(465,495
)
 
10.79

Forfeited

 

Not vested, December 31, 2019
1,233,375

 
$
7.62

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.

On January 13, 2020, SRC granted 986,885 new TSR PSUs (“New PSU”) in respect of shares of SRC common stock, on the terms specified in the PDC Merger Agreement. The New PSU awards will be assumed or substituted by PDC and converted automatically into new performance stock unit awards of PDC, subject to the same terms and conditions as were applicable to the New PSU awards immediately prior to the effective time. The number of shares of PDC common stock covered by such assumed awards will be based on the target number of SRC shares covered by such awards multiplied by 0.158, the exchange ratio in the PDC Merger. The range of shares of PDC common stock that may be earned in respect of the New PSUs is 0% to 200% of the applicable target.

At the effective time of the PDC Merger, 1,508,273 performance stock units became vested and were cancelled in exchange for the Merger Consideration with such number of shares of common stock determined based on target performance and any remaining shares of common stock subject to the award forfeited. An additional 465,495 performance stock units that were vested in 2019 but were unsettled at the effective time of the PDC Merger were cancelled in exchange for the Merger Consideration with such number of shares of common stock determined based on target performance and any remaining shares of common stock subject to the award forfeited.


24



12.
Defined Contribution Plan

The Company sponsors a 401(k) defined contribution plan (the "plan") for eligible employees. Effective January 1, 2017, the Company modified the plan to include a discretionary matching contribution equal to 100% of compensation deferrals not to exceed 6% of eligible compensation. The Company contributed approximately $1.0 million, $0.9 million, and $0.7 million for the years ended December 31, 2019, 2018, and 2017, respectively, to the plan.

13.
Income Taxes

The income tax provision is comprised of the following (in thousands):
 
Year Ended December 31,
 
2019
 
2018
 
2017
Current:
 
 
 
 
 
Federal
$

 
$

 
$
(99
)
State

 

 

Total current income tax expense (benefit)

 

 
(99
)
 
 
 
 
 
 
Deferred:
 
 
 
 
 
Federal
48,243

 
72,898

 
48,631

State
8,403

 
12,697

 
4,371

Total deferred income tax (benefit) expense
56,646

 
85,595

 
53,002

 
 
 
 
 
 
Change in valuation allowance

 
(47,628
)
 
(53,002
)
Income tax expense (benefit)
$
56,646

 
$
37,967

 
$
(99
)

A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands):
 
Year Ended December 31,
 
2019
 
2018
 
2017
 
 
 
 
 
 
Federal income tax at statutory rate
$
44,106

 
$
62,578

 
$
48,410

State income taxes, net of federal tax
8,403

 
12,697

 
4,371

Impact of tax reform, net of valuation allowance

 

 
(99
)
Valuation allowance

 
(47,628
)
 
(53,002
)
Goodwill impairment

 
8,549

 

Other
4,137

 
1,771

 
221

Income tax expense (benefit)
$
56,646

 
$
37,967

 
$
(99
)
Effective rate expressed as a percentage
27
%
 
13
%
 
 %

The change in the Federal tax rate in 2017 was due to the passage of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act ("TCJA"). The passage of this legislation resulted in the change in the U.S. statutory rate from 35% to 21%. Based on the Company's current interpretation and subject to the release of the related regulations and any future interpretive guidance, the effects of the change in tax law have been incorporated herein, and no substantial changes were identified compared to December 31, 2017.

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other deferred tax assets will be utilized prior to

25



their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands):
 
As of December 31,
 
2019
 
2018
Deferred tax assets (liabilities):
 
 
 
Net operating loss carryforward
$
71,921

 
$
111,587

Stock-based compensation
7,327

 
6,984

Basis of oil and gas properties
(179,831
)
 
(150,080
)
Statutory depletion
2,262

 
2,434

Unrealized loss on commodity derivative
2,907

 
(8,607
)
Other
801

 
(285
)
 
(94,613
)
 
(37,967
)
Valuation allowance on tax assets

 

Deferred tax liability, net
$
(94,613
)
 
$
(37,967
)

During the year ended December 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 cumulative positive net income for the three-year period ended December 31, 2018. In addition to the cumulative positive net income, the temporary deferred tax liabilities exceed the deferred tax assets resulting in the ability to utilize all deferred tax assets to offset future taxable income resulting from the reversal of the deferred tax liabilities.     

At December 31, 2019, the Company has U.S. Federal and state net operating loss carryforward of approximately $291.7 million that could be utilized to offset taxable income of future years. These net operating loss carryforwards will expire in various years beginning in 2025 with substantially all of the carryforwards expiring beginning in 2031.

As of December 31, 2019, the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor 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. The Company's federal and state tax returns filed since December 31, 2016 and December 31, 2015, respectively, remain subject to examination by tax authorities.

14.    Revenue from Contracts with Customers

Under FASB Topic 606, Revenue from Contracts with Customers ("ASC 606"), 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.
 
Year Ended December 31,
Revenues (in thousands):
2019
 
2018
 
2017
Oil
$
506,303

 
$
494,052

 
$
261,505

Natural Gas and NGLs
129,199

 
151,589

 
101,011

 
$
635,502

 
$
645,641

 
$
362,516


Natural Gas and NGLs Sales

Under the majority of 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

26



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 entity.

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 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 December 31, 2019, we had no contract assets recorded. As of December 31, 2018, we had contract assets recorded within other current assets of $1.4 million representing cash advances to customers.

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 years ended December 31, 2019 and 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

15.    Leases

The Company evaluates contractual arrangements at inception to determine if the agreement is a lease or contains an identifiable lease component as defined by ASC 842. When evaluating contracts to determine appropriate classification and recognition under ASC 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, whether renewal or termination options are reasonably certain to be exercised, and future lease payments to be included in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating contracts that meet the definition of a lease under ASC 842 include:


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Discount Rate - Unless implicitly defined, the Company will determine the present value of future lease payments using an estimated incremental secured borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease commencement.
Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain these options will be exercised. There are no available options to extend that the Company is reasonably certain to exercise.

Currently, the Company has operating leases for asset classes that include office space, drilling rigs, and equipment rentals primarily used in development and field operations. The Company has financing leases for vehicles. We have provided a residual value guarantee for our vehicle leases. Certain leases also contain optional extension periods that allow for lease terms to be extended for up to an additional 5 years.

Costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying asset is utilized. For example, costs associated with drilling rigs are capitalized as part of the development of the Company’s oil and gas properties. Refer to Note 1 for additional information on its accounting policies for oil and gas development and production activities. When calculating the Company’s ROU asset and liability, the Company considers all the necessary payments made or that are expected to be made upon commencement of the lease. Excluded from the initial measurement are certain variable lease payments.

The Company’s total lease costs were as follows (in thousands):
 
 
Year Ended December 31, 2019
Finance lease cost:
 
 
Amortization of ROU assets
 
$
256

Interest on lease liabilities
 
31

 
 
 
Operating lease cost
 
3,799

Variable lease cost
 
729

Short-term lease cost 1
 
116,697

Total Lease Cost
 
$
121,512

1 Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than or equal to one year. These costs primarily include drilling activities and field equipment rentals, and approximately 90% of these costs are capitalized to the consolidated balance sheet. It is expected that this amount will fluctuate primarily with the number of drilling rigs that the Company is operating under short-term agreements.

Other information related to the Company’s leases is as follows (in thousands, except lease terms and discount rates):
 
 
December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
 
 
       Operating cash flows from operating leases
 
$
4,244

       Financing cash flows from finance leases
 
198

 
 
 
ROU assets obtained in exchange for new finance lease liabilities
 
186

ROU assets obtained in exchange for new operating lease liabilities
 
9,792

 
As of
December 31, 2019
Weighted-average remaining lease term - finance leases
2.6 years

Weighted-average remaining lease term - operating leases
1.7 years

Weighted-average discount rate - finance leases
4.75
%
Weighted-average discount rate - operating leases
4.75
%


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As of December 31, 2019 and through the date of issuance of these financial statements, the Company has no material lease arrangements which are scheduled to commence in the future. Maturities for the Company’s operating and finance lease liabilities included in the accompanying consolidated balance sheets as of December 31, 2019 were as follows (in thousands):
Year
 
Finance Leases
 
Operating Leases
2020
 
$
197

 
$
5,106

2021
 
224

 
2,113

2022
 
194

 
500

2023
 
38

 

2024
 

 

Thereafter
 

 

Total lease payments
 
$
653

 
$
7,719

Less imputed interest
 
(46
)
 
(287
)
Total lease liability
 
$
607

 
$
7,432


As of December 31, 2018, minimum future contractual payments were as follows (in thousands):
Year
 
Rig Contracts
 
Capital Leases
 
Operating Leases
2019
 
$
11,102

 
$
183

 
$
896

2020
 

 
186

 
916

2021
 

 
204

 
913

2022
 

 
167

 
500

2023
 

 

 

Thereafter
 

 

 


Amounts recorded in the Company’s accompanying consolidated balance sheets were as follows (in thousands):
As of December 31, 2019
 
Financing Leases
 
Operating Leases
Other property and equipment, net
 
$
670

 
$

Other assets
 

 
6,037

 
 
 
 
 
Accounts payable and accrued expenses
 
173