PDC ENERGY, INC. - Quarter Report: 2021 June (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2021

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to _________

Commission File Number 001-37419

PDC ENERGY, INC.

(Exact name of registrant as specified in its charter)


Delaware			95-2636730
(State of incorporation)			(I.R.S. Employer Identification No.)

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

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 (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large Accelerated Filer	x	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		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. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 98,659,588 shares of the Company's Common Stock ($0.01 par value) were outstanding as of July 27, 2021.

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PDC ENERGY, INC.

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	PART I – FINANCIAL INFORMATION	Page

Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Cash Flows	3
	Condensed Consolidated Statements of Stockholders’ Equity	4
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	45

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults Upon Senior Securities	46
Item 4.	Mine Safety Disclosures	46
Item 5.	Other Information	46
Item 6.	Exhibits	47

	Signatures	48

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) and the United States (“U.S.”) Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are “forward-looking statements”. Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; impacts of Colorado political matters, including recent rulemaking initiatives influencing our ability to continue to obtain permits; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; cash flows from operations relative to future capital investments; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; adequacy of midstream infrastructure; the potential return of capital to shareholders through buybacks of shares and/or payments of dividends; ongoing compliance with our consent decree; risk of our counterparties non-performance on derivative instruments; and our ability to fund planned activities.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

•market and commodity price volatility, widening price differentials, and related impacts to the Company, including decreased revenue, income and cash flow, write-downs and impairments and availability of capital;

•future cash flows, liquidity and financial condition;

•changes in, and interpretations and enforcement of, environmental and other laws and other political and regulatory development, including in particular additional permit scrutiny in Colorado;

•the coronavirus 2019 (“COVID-19”) pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters;

•declines in the value of our crude oil, natural gas and natural gas liquids (“NGLs”) properties resulting in impairments;

•changes in, and inaccuracy of, reserve estimates and expected production and decline rates;

•timing and extent of our success in discovering, acquiring, developing and producing reserves;

•reductions in the borrowing base under our revolving credit facility;

•availability and cost of capital;

•risks inherent in the drilling and operation of crude oil and natural gas wells;

•timing and costs of wells and facilities;

•availability, cost, and timing of sufficient pipeline, gathering and transportation facilities and related infrastructure;

•potential losses of acreage or other impacts due to lease expirations, other title defects, or otherwise;

•risks inherent in marketing crude oil, natural gas and NGLs;

•effect of crude oil and natural gas derivative activities;

•impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events;

•cost of pending or future litigation;

•impact to our operations, personnel retention, strategy, stock price and expenses caused by the actions of activist shareholders;

•uncertainties associated with future dividends to our shareholders;

•our ability to retain or attract senior management and key technical employees;

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•civil unrest, terrorist attacks and cyber threats; and

•success of strategic plans, expectations and objectives for our future operations.

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors made in our Annual Report on Form 10-K for the year ended December 31, 2020 (“2020 Form 10-K”) filed with the U.S. Securities and Exchange Commission (“SEC”) for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

REFERENCES

Unless the context otherwise requires, references in this report to “PDC Energy”, “PDC”, “the Company”, “we”, “us”, “our” or “ours” refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements.

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PDC ENERGY, INC.

Condensed Consolidated Balance Sheets

(in thousands, except share and per share data)

(Unaudited)


	June 30, 2021		December 31, 2020
Assets
Current assets:
Cash and cash equivalents	$	109,749	$	2,623
Accounts receivable, net	307,201		244,251
Fair value of derivatives	5,146		48,869
Prepaid expenses and other current assets	7,717		12,505
Total current assets	429,813		308,248
Properties and equipment, net	4,846,682		4,859,199
Fair value of derivatives	8,909		9,565
Other assets	48,585		60,961
Total Assets	$	5,333,989	$	5,237,973

Liabilities and Stockholders’ Equity
Liabilities
Current liabilities:
Accounts payable	$	177,099	$	90,635
Production tax liability	75,719		124,475
Fair value of derivatives	393,180		98,152
Funds held for distribution	225,134		177,132
Accrued interest payable	15,354		14,734
Other accrued expenses	77,559		81,715
Current portion of long-term debt	197,919		193,014
Total current liabilities	1,161,964		779,857
Long-term debt	1,242,676		1,409,548

Asset retirement obligations	121,628		132,637
Fair value of derivatives	100,675		36,359
Other liabilities	242,140		264,034
Total liabilities	2,869,083		2,622,435

Commitments and contingent liabilities

Stockholders’ equity
Common shares - par value $0.01 per share, 150,000,000 authorized, 98,906,605 and 99,758,720 issued as of June 30, 2021 and December 31, 2020, respectively	989		998
Additional paid-in capital	3,333,168		3,387,754
Accumulated deficit	(868,338)		(772,265)
Treasury shares - at cost, 20,000 and 37,510 as of June 30, 2021 and December 31, 2020, respectively	(913)		(949)
Total stockholders’ equity	2,464,906		2,615,538
Total Liabilities and Stockholders’ Equity	$	5,333,989	$	5,237,973

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenues
Crude oil, natural gas and NGLs sales	$	533,141	$	173,921	$	1,001,260	$	494,236
Commodity price risk management gain (loss), net	(308,253)		(120,786)		(489,509)		313,912
Other income	3,981		1,281		3,154		3,298
Total revenues	228,869		54,416		514,905		811,446
Costs, expenses and other
Lease operating expense	42,395		35,808		84,199		85,342
Production taxes	26,968		7,846		56,460		26,316
Transportation, gathering and processing expense	25,989		16,949		47,721		30,445
Exploration, geologic and geophysical expense	286		728		640		864
General and administrative expense	32,843		35,352		65,520		97,517
Depreciation, depletion and amortization	162,210		149,491		308,973		325,648
Accretion of asset retirement obligations	3,232		2,358		6,360		4,978
Impairment of properties and equipment	62		32		252		881,106
Loss (gain) on sale of properties and equipment	(129)		(174)		(341)		(353)
Other	2,145		2,003		2,193		4,147
Total costs, expenses and other	296,001		250,393		571,977		1,456,010
Loss from operations	(67,132)		(195,977)		(57,072)		(644,564)
Interest expense, net	(20,060)		(21,782)		(39,101)		(45,955)
Loss before income taxes	(87,192)		(217,759)		(96,173)		(690,519)
Income tax benefit (expense)	155		(4,073)		100		3,672
Net loss	$	(87,037)	$	(221,832)	$	(96,073)	$	(686,847)

Loss per share:
Basic	$	(0.88)	$	(2.23)	$	(0.97)	$	(7.09)
Diluted	$	(0.88)	$	(2.23)	$	(0.97)	$	(7.09)

Weighted-average common shares outstanding:
Basic	99,187		99,566		99,445		96,821
Diluted	99,187		99,566		99,445		96,821

Dividends declared per share	$	0.12	$	—	$	0.12	$	—

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)


	Six Months Ended June 30,
	2021		2020
Cash flows from operating activities:
Net loss	$	(96,073)	$	(686,847)
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives	403,723		(153,294)
Depreciation, depletion and amortization	308,973		325,648
Impairment of properties and equipment	252		881,106
Accretion of asset retirement obligations	6,360		4,978
Non-cash stock-based compensation	11,515		12,036
Gain on sale of properties and equipment	(341)		(353)
Amortization and write-off of debt discount, premium and issuance costs	7,714		8,941
Deferred income taxes	—		(2,430)
Other	875		1,657
Changes in assets and liabilities	(65,632)		(22,180)
Net cash from operating activities	577,366		369,262
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(240,266)		(387,930)
Capital expenditures for other properties and equipment	(274)		(1,935)
Acquisition of crude oil and natural gas properties	—		(139,812)
Proceeds from sale of properties and equipment	4,414		1,384
Proceeds from divestitures	—		62
Net cash from investing activities	(236,126)		(528,231)
Cash flows from financing activities:
Proceeds from revolving credit facility and other borrowings	429,800		1,318,000
Repayment of revolving credit facility and other borrowings	(597,800)		(669,000)
Redemption of senior notes	—		(452,153)
Payment of debt issuance costs	—		(4,666)
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	(5,656)		(8,180)
Purchase of treasury shares under stock repurchase program	(47,694)		(23,819)
Dividends paid	(11,885)		—
Principal payments under financing lease obligations	(879)		(985)
Net cash from financing activities	(234,114)		159,197
Net change in cash, cash equivalents and restricted cash	107,126		228
Cash and cash equivalents, beginning of period	2,623		963
Cash and cash equivalents, end of period	$	109,749	$	1,191

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Stockholders’ Equity

(in thousands)

(Unaudited)


	Six Months Ended June 30, 2021
	Common Stock					Treasury Stock
	Shares	Amount		Additional Paid-in Capital		Shares	Amount		Accumulated Deficit		Total Stockholders’ Equity
Balance, January 1, 2021	99,759	$	998	$	3,387,754	(38)	$	(949)	$	(772,265)	$	2,615,538
Net loss	—	—		—		—	—		(9,036)		(9,036)
Stock-based compensation	209	2		3,670		—	1,348		—		5,020
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—		(81)	(2,356)		—		(2,356)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(33)	—		(1,091)		33	1,091		—		—
Retirement of treasury shares	(568)	(6)		(21,061)		568	21,067		—		—
Issuance of treasury shares	—	—		—		65	—		—		—
Purchase of treasury shares under stock repurchase program	—	—		—		(598)	(22,098)		—		(22,098)
Balance, March 31, 2021	99,367	$	994	$	3,369,272	(51)	$	(1,897)	$	(781,301)	$	2,587,068
Net loss	—	—		—		—	—		(87,037)		(87,037)
Stock-based compensation	295	3		5,742		—	750		—		6,495
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—		(92)	(3,300)		—		(3,300)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(78)	(1)		(2,807)		78	2,808		—		—
Retirement of treasury shares	(677)	(7)		(26,922)		684	27,235		—		306
Issuance of treasury shares	—	—		—		22	—		—		—
Purchase of treasury shares under stock repurchase program	—	—		—		(661)	(26,509)		—		(26,509)
Dividends declared ($0.12 per share)	—	—		(12,117)		—	—		—		(12,117)
Balance, June 30, 2021	98,907	989		3,333,168		(20)	(913)		(868,338)		2,464,906

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Stockholders’ Equity - continued

(in thousands)

(Unaudited)


	Six Months Ended June 30, 2020
	Common Stock					Treasury Stock
	Shares	Amount		Additional Paid-in Capital		Shares	Amount		Accumulated Deficit		Total Stockholders’ Equity
Balance, January 1, 2020	61,652	$	617	$	2,384,309	(35)	$	(1,474)	$	(47,945)	$	2,335,507
Net loss	—	—		—		—	—		(465,015)		(465,015)
Issuance pursuant to acquisition	39,182	391		1,014,921		—	—		—		1,015,312
Stock-based compensation	121	1		3,713		—	1,958		—		5,672
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—		(306)	(7,693)		—		(7,693)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(251)	(3)		(6,425)		251	6,428		—		—
Retirement of treasury shares	(1,266)	(12)		(23,807)		1,266	23,819		—		—
Issuance of treasury shares	—	—		—		69	—		—		—
Purchase of treasury shares under stock repurchase program	—	—		—		(1,266)	(23,819)		—		(23,819)
Balance, March 31, 2020	99,438	$	994	$	3,372,711	(21)	$	(781)	$	(512,960)	$	2,859,964


Net income	—	—		—		—	—		(221,832)		(221,832)
Stock-based compensation	213	2		6,164		—	198		—		6,364
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—		(64)	(487)		—		(487)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(39)	—		(322)		39	322		—		—


Issuance of treasury shares	—	—		—		13	—				—


Balance, June 30, 2020	99,612	$	996	$	3,378,553	(33)	$	(748)	$	(734,792)	$	2,644,009

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION

PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones. As of June 30, 2021, we owned an interest in approximately 3,600 gross productive wells.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. All material intercompany accounts and transactions have been eliminated in consolidation. In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments necessary for a fair statement of the results of interim periods presented in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 2020 condensed consolidated balance sheet data was derived from audited statements, but does not include all disclosures required by U.S. GAAP. The information presented in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2020 Form 10-K. Our results of operations and cash flows for the six months ended June 30, 2021 are not necessarily indicative of the results to be expected for the full year or any other future period.

NOTE 2 - BUSINESS COMBINATION

In January 2020, we merged with SRC Energy Inc. (“SRC”) in a transaction valued at $1.7 billion, inclusive of SRC’s net debt (the “SRC Acquisition”). SRC was an independent oil and natural gas company engaged in the exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in Weld County, Colorado. The acquisition added approximately 83,000 net acres which are located on large, contiguous acreage blocks in the core of the Wattenberg Field.

Upon closing, we issued approximately 38.9 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the terms of the merger agreement that we entered into with SRC. We finalized the purchase price allocation on December 31, 2020, and we recognized total transaction costs of $19.9 million for the year ended December 31, 2020.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

The following table details our final purchase price, valuation and allocation of the purchase price to the assets acquired and liabilities assumed as a result of the SRC Acquisition:


	(in thousands)
Consideration:
Cash	$	40
Retirement of seller's credit facility	166,238
Total cash consideration	166,278
Common stock issued	1,009,015
Shares withheld in lieu of taxes	6,299

Total consideration	$	1,181,592

Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current assets	$	145,792
Properties and equipment, net - proved	1,613,674
Properties and equipment, net - unproved	109,615
Properties and equipment, net - other	16,242
Deferred tax asset	189,311
Other assets	11,810
Total assets acquired	2,086,444
Liabilities assumed:
Current liabilities	(253,967)
Senior notes	(555,500)
Asset retirement obligations	(42,417)
Other liabilities	(52,968)
Total liabilities assumed	(904,852)
Total identifiable net assets acquired	$	1,181,592

This acquisition was accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved and unproved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices, lease terms and expirations and a market-based weighted-average cost of capital rate of 10 percent. These inputs require significant judgments and estimates by management at the time of the valuation.

The results of operations for the SRC Acquisition since the closing date have been included on our condensed consolidated financial statements for the three and six months ended June 30, 2020 and include approximately $48.3 million and $151.8 million, respectively, of total revenue, and $14.5 million and $1.4 million loss from operations, respectively.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

Pro Forma Information. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the six months ended June 30, 2020, assuming the acquisition had been completed as of January 1, 2020. The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on available information and certain assumptions that we believe are reasonable, including (i) the Company's common stock issued to convert SRC’s outstanding shares of common stock and the cancellation of equity awards, (ii) the depletion of SRC’s fair-valued proved oil and gas properties using the successful efforts method of accounting and (iii) the estimated tax impacts of the proforma adjustments, if any. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company and SRC totaling approximately $38.0 million for the six months ended June 30, 2020. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results.


	Six Months Ended June 30, 2020
Total revenue	$	832,786
Net income (loss)	(647,435)

Earnings (loss) per share:
Basic	$	(6.49)
Diluted	(6.49)

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

NOTE 3 - REVENUE RECOGNITION

Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the periods presented:


	Three Months Ended June 30,						Six Months Ended June 30,
Revenue by Commodity and Operating Region	2021		2020		Percent Change		2021		2020		Percent Change
	(in thousands)
Crude oil
Wattenberg Field	$	291,551	$	93,540	212	%	$	527,514	$	300,189	76	%
Delaware Basin	59,148		22,231		166	%	96,836		64,756		50	%
Total	$	350,699	$	115,771	203	%	$	624,350	$	364,945	71	%
Natural gas
Wattenberg Field	$	74,664	$	29,443	154	%	$	171,686	$	69,520	147	%
Delaware Basin	11,139		1,605		*		19,763		1,042		*
Total	$	85,803	$	31,048	176	%	$	191,449	$	70,562	171	%
NGLs
Wattenberg Field	$	83,505	$	22,762	267	%	$	161,282	$	48,004	236	%
Delaware Basin	13,134		4,340		203	%	24,179		10,725		125	%
Total	$	96,639	$	27,102	257	%	$	185,461	$	58,729	216	%
Crude oil, natural gas and NGLs
Wattenberg Field	$	449,720	$	145,745	209	%	$	860,482	$	417,713	106	%
Delaware Basin	83,421		28,176		196	%	140,778		76,523		84	%
Total	$	533,141	$	173,921	207	%	$	1,001,260	$	494,236	103	%

_____________

* Percent change is not meaningful.

Contract Assets. Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with midstream service providers that are our customers. The intent of the payments is primarily to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are included in other assets on the condensed consolidated balance sheets. The contract assets are amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer.

The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for the six months ended June 30, 2021:


	(in thousands)
Beginning balance	$	25,872
Reduction to additions previously recognized	(819)
Amortized as a reduction to crude oil, natural gas and NGLs sales	(1,488)
Ending balance	$	23,565

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

NOTE 4 - FAIR VALUE MEASUREMENTS

Recurring Fair Value Measurements

Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default exchange rates and the duration of each outstanding derivative position. We validate our fair value measurement by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions and reviewing counterparty statements and other supporting documentation.

Our crude oil and natural gas fixed-price exchanges are included in Level 2. Our collars are included in Level 3. Our basis exchanges are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of the dates indicated:


		June 30, 2021						December 31, 2020
	Condensed Consolidated Balance Sheet Line Item	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
		(in thousands)
Derivative assets
Current	Fair value of derivatives	$	579	$	4,567	$	5,146	$	36,580	$	12,289	$	48,869
Non-current	Fair value of derivatives	2,330		6,579		8,909		315		9,250		9,565
Total		$	2,909	$	11,146	$	14,055	$	36,895	$	21,539	$	58,434

Derivative liabilities
Current	Fair value of derivatives	$	284,799	$	108,381	$	393,180	$	76,420	$	21,732	$	98,152
Non-current	Fair value of derivatives	79,925		20,750		100,675		28,125		8,234		36,359
Total		$	364,724	$	129,131	$	493,855	$	104,545	$	29,966	$	134,511

The following table presents a reconciliation of our Level 3 assets and liabilities measured at fair value:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period	$	(36,234)	$	67,240	$	(8,427)	$	8,414
Changes in fair value included on condensed consolidated statements of operations line item:
Commodity price risk management gain (loss), net	(94,131)		(13,169)		(127,520)		54,361
Settlements included on condensed consolidated statement of operations line items:
Commodity price risk management gain (loss), net	12,380		(27,113)		17,962		(35,817)
Fair value of Level 3 instruments, net asset (liability) end of period	$	(117,985)	$	26,958	$	(117,985)	$	26,958

Net change in fair value of Level 3 unsettled derivatives included on condensed consolidated statements of operations line item:
Commodity price risk management gain (loss), net	$	(81,417)	$	(13,675)	$	(93,867)	$	21,989

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements.

Nonrecurring Fair Value Measurement

Acquisitions and Impairment of Long-lived Assets. We measure fair value using inputs that are not observable in the market, and are therefore designated as Level 3 within the valuation hierarchy, on a nonrecurring basis for any acquired assets or businesses and to review our proved and unproved crude oil and natural gas properties for possible impairment.

Asset Retirement Obligations. We measure the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy.

Other Financial Instruments

The carrying value of the financial instruments included in current assets and current liabilities approximates fair value due to the short-term maturities of these instruments.

Long-term Debt. The portion of our long-term debt related to our revolving credit facility approximates fair value, as the applicable interest rates are variable and reflective of market rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker or dealer quotes, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of the dates indicated:


			June 30, 2021				December 31, 2020
	Nominal Interest		Estimated Fair Value		Percent of Par		Estimated Fair Value		Percent of Par
			(in millions)				(in millions)
Senior Notes:
2021 Convertible Notes	1.125	%	$	198.2	99.1	%	$	196.2	98.1	%
2024 Senior Notes	6.125	%	409.2		102.3	%	410.8		102.7	%
2025 Senior Notes	6.25	%	105.9		103.5	%	102.8		100.5	%
2026 Senior Notes	5.75	%	783.8		104.5	%	775.5		103.4	%

NOTE 5 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

Objective and Strategy. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts such as collars, fixed-price exchanges and basis protection exchanges, to protect against price declines in future periods. We do not enter into derivative contracts for speculative or trading purposes.

We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. Depending on changes in oil and gas futures markets and management's view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. As of June 30, 2021, we had derivative instruments in place for a portion of our anticipated production in 2021 through 2023. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

Commodity Derivative Contracts. As of June 30, 2021, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted-average contract price is presented:


	Collars					Fixed-Price Swaps
Commodity/ Index/ Maturity Period	Quantity (Crude oil - MBbls Natural Gas - BBtu)	Weighted-Average Contract Price				Quantity (Crude Oil - MBbls Gas and Basis- BBtu)	Weighted- Average Contract Price		Fair Value June 30, 2021 (in thousands)
		Floors		Ceilings
Crude Oil
NYMEX
2021	2,502	$	38.01	$	49.29	4,976	$	41.89	$	(200,961)
2022	3,552	49.49		60.96		6,744	44.42		(169,559)
2023	—	—		—		4,602	56.23		(21,386)
Total Crude Oil	6,054					16,322			$	(391,906)

Natural Gas
NYMEX
2021	36,600	2.51		2.92		15,900	2.40		(47,880)
2022	17,400	2.50		2.89		33,600	2.70		(22,607)
2023	—	—		—		20,400	2.57		(4,761)




Total Natural Gas	54,000					69,900			(75,248)





Basis Protection - Natural Gas
CIG
2021						52,500	(0.44)		(12,885)
2022						51,000	(0.26)		(1,130)
2023						20,400	(0.23)		1,369




Total Basis Protection - Natural Gas						123,900			(12,646)

Commodity Derivatives Fair Value									$	(479,800)

Effect of Derivative Instruments on the Condensed Consolidated Balance Sheet. The balance sheet line items and fair value amounts of our derivative instruments are disclosed in Note 4 - Fair Value Measurements.

Our financial derivative agreements contain master netting provisions that provide for the net settlement of contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets.

The following table reflects the impact of netting agreements on gross derivative assets and liabilities as of the dates indicated:


As of June 30, 2021	Total Gross Amount Presented on the Balance Sheet		Effect of Master Netting Agreements		Total Net Amount
	(in thousands)
Derivative assets:
Derivative instruments, at fair value	$	14,055	$	(14,055)	$	—

Derivative liabilities:
Derivative instruments, at fair value	$	493,855	$	(14,055)	$	479,800

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

Effect of Derivative Instruments on the Condensed Consolidated Statements of Operations. The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:


	Three Months Ended June 30,				Six Months Ended June 30,
Condensed Consolidated Statement of Operations Line Item	2021		2020		2021		2020
	(in thousands)
Commodity price risk management gain (loss), net
Net settlements	$	(55,135)	$	114,795	$	(85,786)	$	160,618
Net change in fair value of unsettled derivatives	(253,118)		(235,581)		(403,723)		153,294
Total commodity price risk management gain (loss), net	$	(308,253)	$	(120,786)	$	(489,509)	$	313,912

Derivative Counterparties. Our commodity derivative instruments expose us to credit risk of non-performance by our counterparties. We use financial institutions who are also lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at June 30, 2021; however, this determination may change.

NOTE 6 - PROPERTIES AND EQUIPMENT, NET

The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization (“DD&A”) as of the dates indicated:


	June 30, 2021		December 31, 2020
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	7,875,257	$	7,523,639
Unproved	351,626		350,677
Total crude oil and natural gas properties	8,226,883		7,874,316
Equipment and other	63,861		65,027
Land and buildings	17,664		24,299
Construction in progress	470,021		523,550
Properties and equipment, at cost	8,778,429		8,487,192
Accumulated DD&A	(3,931,747)		(3,627,993)
Properties and equipment, net	$	4,846,682	$	4,859,199

Impairment of Oil and Gas Properties. There were no significant impairment charges recognized related to our proved and unproved properties during the three and six months ended June 30, 2021. In the first quarter of 2020, the significant decline in crude oil prices in addition to the ongoing effects of the COVID-19 pandemic was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded impairment expense of $881.1 million to our proved and unproved properties.

Proved Properties. Of the total impairment expense recognized in the first quarter of 2020, approximately $753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. We estimated the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount, a level 3 input. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a discount rate of 17 percent, which was based on a weighted-average cost of capital for the area where the assets are located.

Unproved Properties. We recognized approximately $127.3 million of impairment charges for our unproved properties in the Delaware Basin during the three months ended March 31, 2020. These impairment charges were recognized based on the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

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fair value of the properties, a Level 3 input. The fair value is estimated based on a review of our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we have no development plans.

Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment for the periods presented:


	Six Months Ended June 30,		Year Ended December 31, 2020
	(in thousands, except for number of wells)
Beginning balance	$	7,459	$	16,078
Additions to capitalized exploratory well costs pending the determination of proved reserves	5,521		11,770
Reclassifications to proved properties	—		(20,389)
Ending balance	$	12,980	$	7,459

Number of wells pending determination at period-end	2		2

Our net capitalized exploratory well costs that have been capitalized for a period greater than one year were $7.5 million as of June 30, 2021 and December 31, 2020. We expect to complete our two gross suspended wells associated with two projects prior to the end of 2021.

NOTE 7 - ACCOUNTS RECEIVABLE, OTHER ACCRUED EXPENSES AND OTHER LIABILITIES

Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts as of the dates indicated:


	June 30, 2021		December 31, 2020
	(in thousands)
Crude oil, natural gas and NGLs sales	$	281,207	$	178,147
Joint interest billings	22,476		35,396
Other	9,252		37,471
Allowance for doubtful accounts	(5,734)		(6,763)
Accounts receivable, net	$	307,201	$	244,251

Other Accrued Expenses. The following table presents the components of other accrued expenses as of the dates indicated:


	June 30, 2021		December 31, 2020
	(in thousands)
Employee benefits	$	19,311	$	23,304
Asset retirement obligations	33,792		33,933
Environmental expenses	10,365		10,139
Operating and finance leases	7,803		7,986
Other	6,288		6,353
Other accrued expenses	$	77,559	$	81,715

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

Other Liabilities. The following table presents the components of other liabilities as of the dates indicated:


	June 30, 2021		December 31, 2020
	(in thousands)
Deferred midstream gathering credits	$	164,637	$	168,478
Deferred oil gathering credits	17,085		18,090
Production taxes	50,806		65,592
Operating and finance leases	8,873		10,763
Other	739		1,111
Other liabilities	$	242,140	$	264,034

Deferred Midstream Gathering Credits. In the second quarter of 2019, concurrent with the sale of our Delaware Basin midstream assets, we entered into an agreement with each of the purchasers pursuant to which we dedicated the gathering of certain of our production and all water gathering and disposal volumes in the Delaware Basin. The terms of these agreements range from 15 to 22 years. The acreage dedication agreements resulted in initial cash receipts and are being amortized on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production.

Deferred Oil Gathering Credits. In 2018, we entered into an agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider’s gathering lines and extends the term of the agreement through December 2029. The acreage dedication agreement resulted in an initial cash receipt and is being amortized on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production.

The following table presents the amortization charges recognized on the condensed consolidated statements of operations for the periods indicated:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(in thousands)
Crude oil, natural gas and NGL sales	$	—	$	222	$	—	$	373
Transportation, gathering and processing expense	1,779		1,308		3,300		2,477
Lease operating expense	647		449		1,085		772

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

NOTE 8 - LONG-TERM DEBT

Long-term debt consisted of the following as of the dates indicated:


	June 30, 2021		December 31, 2020
	(in thousands)
Senior Notes:
1.125% Convertible Notes due September 2021:
Principal amount	$	200,000	$	200,000
Unamortized discount and debt issuance costs	(2,081)		(6,986)
Net of unamortized discount and debt issuance costs	197,919		193,014

6.125% Senior Notes due September 2024:
Principal amount	400,000		400,000
Unamortized debt issuance costs	(3,142)		(3,632)
Net of unamortized debt issuance costs	396,858		396,368

6.25% Senior Notes due December 2025:
Principal amount	102,324		102,324
Unamortized premium	801		880
Net of unamortized premium	103,125		103,204

5.75% Senior Notes due May 2026:
Principal amount	750,000		750,000
Unamortized discount and debt issuance costs	(7,307)		(8,024)
Net of unamortized discount and debt issuance costs	742,693		741,976

Total senior notes	1,440,595		1,434,562

Revolving Credit Facility:
Revolving credit facility due May 2023	—		168,000
Total debt, net of unamortized discount, premium and debt issuance costs	1,440,595		1,602,562
Less current portion of long-term debt	197,919		193,014
Total long-term debt	$	1,242,676	$	1,409,548

Senior Notes

2021 Convertible Notes. In September 2016, we issued $200 million of 1.125% convertible notes due September 15, 2021 (the “2021 Convertible Notes”). Interest is payable semi-annually in arrears on March 15 and September 15.

The 2021 Convertible Notes are convertible after March 15, 2021 at a conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to a conversion price of $85.39 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash or a combination thereof. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares.

2024 Senior Notes. In September 2016, we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”). Interest is payable semi-annually on March 15 and September 15. The principal amount of the 2024 Senior Notes are redeemable after September 15, 2020 at fixed redemption prices, currently at 103.063 percent plus accrued and unpaid interest.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

2025 Senior Notes. Upon completion of the SRC Acquisition in January 2020, we assumed $550 million aggregate principal amount of 6.25% senior notes due December 1, 2025 (the “2025 Senior Notes”). The 2025 Senior Notes were recorded at their approximate fair value of $555.5 million. The difference between the acquisition date fair value and the principal amount of the 2025 Senior Notes will be recognized as a reduction to interest expense over the remaining life of the notes. Interest is payable semi-annually on June 1 and December 1. On January 17, 2020, we commenced an offer to repurchase the 2025 Senior Notes from the holders at 101 percent of the principal amount of the 2025 Senior Notes, together with any accrued and unpaid interest. 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 $452.2 million, plus accrued and unpaid interest of $6.2 million. The fair value of the 2025 Senior Notes approximated the repurchase offer price, resulting in recognition of an immaterial loss on extinguishment of the repurchased notes. The repurchase was funded by proceeds from our revolving credit facility. An aggregate principal amount of $102.3 million remains outstanding.

On and after December 1, 2020, the Company may redeem the remaining 2025 Senior Notes at a redemption price equal to a specified percentage of the principal amount of the redeemed notes, currently at 103.125%, plus accrued and unpaid interest.

2026 Senior Notes. In November 2017, we issued $600 million aggregate principal amount of 5.75% senior notes due May 15, 2026 (the “2026 Senior Notes”). Interest is payable semi-annually on May 15 and November 15.

In September 2020, we issued an additional $150 million aggregate principal amount of the 2026 Senior Notes at a price equal to 99 percent of par, which resulted in net proceeds of $146.7 million, after deducting the original issuance discount of $1.5 million and debt issuance costs of $1.8 million. The additional 2026 Senior Notes issued have the same terms and conditions as the existing 2026 Senior Notes.

The 2026 Senior Notes are redeemable after May 15, 2021 at fixed redemption prices, currently at 104.313% plus accrued and unpaid interest.

Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2024 Senior Notes, the 2025 Senior Notes and the 2026 Senior Notes (collectively, the “Senior Notes”) and our 2021 Convertible Notes.

The Senior Notes and 2021 Convertible Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.

Upon the occurrence of a “change of control”, as defined in the indentures for the Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase.

The indentures governing the Senior Notes contain covenants and restricted payment provisions that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. As of June 30, 2021, we were in compliance with all covenants and all restricted payment provisions related to our Senior Notes.

Revolving Credit Facility

In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”), which provides for a maximum credit amount of $2.5 billion. The amount we may borrow under the Restated Credit Agreement is subject to certain limitations. The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other

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June 30, 2021

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things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility.

As of June 30, 2021, we had a borrowing base of $1.8 billion, an elected commitment of $1.6 billion and availability under our revolving credit facility of $1.6 billion, which was net of $18.7 million of letters of credit outstanding.

The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month, plus a premium) or, at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of June 30, 2021, the applicable interest margin is 0.75 percent for the alternate base rate option or 1.75 percent for the LIBOR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the revolving credit facility expires in May 2023, unless the borrowing base falls below the outstanding balance.

The revolving credit facility contains various restrictive covenants and compliance requirements, which include, among other things: (i) maintenance of certain financial ratios, as defined per the revolving credit facility, including a minimum current ratio of 1.0:1.0 and a maximum leverage ratio of 4.0:1.0; (ii) restrictions on the payment of cash dividends; (iii) limits on the incurrence of additional indebtedness; (iv) prohibition on the entry into commodity hedges exceeding a specified percentage of our expected production; and (v) restrictions on mergers and dispositions of assets. As of June 30, 2021, we were in compliance with all covenants related to our revolving credit facility.

As of June 30, 2021 and December 31, 2020, debt issuance costs related to our revolving credit facility were $6.4 million and $8.1 million, respectively, and are included in other assets on our condensed consolidated balance sheets.

NOTE 9 - LEASES

We have operating leases for office space and well equipment and finance leases for vehicles. There were no significant changes in our operating and finance leases in the first half of 2021. We had short-term lease costs of $71.4 million and $110.2 million for the three and six months ended June 30, 2021, respectively, and $35.9 million and $132.0 million for the three and six months ended June 30, 2020, respectively. Our short-term lease costs include amounts that are capitalized as part of the cost of assets and are recorded as properties and equipment or recognized as expense.

The following table presents the balance sheet classification of our leases as of the dates indicated:


Leases	Condensed Consolidated Balance Sheet Line Item	June 30, 2021		December 31, 2020
		(in thousands)
Operating Leases:
Operating lease right-of-use assets	Other assets	$	9,849	$	11,722

Operating lease obligation - short-term	Other accrued expenses	6,426		6,520
Operating lease obligation - long-term	Other liabilities	6,485		9,061
Total operating lease liabilities		$	12,911	$	15,581

Finance Leases:
Finance lease right-of-use assets	Properties and equipment, net	$	3,767	$	3,189

Finance lease obligation - short-term	Other accrued expenses	1,377		1,466
Finance lease obligation - long-term	Other liabilities	2,388		1,702
Total finance lease liabilities		$	3,765	$	3,168

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

NOTE 10 - ASSET RETIREMENT OBLIGATIONS

The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties for the six months ended June 30, 2021:


	(in thousands)
Asset retirement obligations at beginning of period	$	166,570
Obligations incurred with development activities and other	2,897

Accretion expense	6,360
Revisions in estimated cash flows	(780)
Obligations discharged with asset retirements and divestitures	(19,627)
Asset retirement obligations at end of period	155,420

Current portion (1)	(33,792)
Long-term portion	$	121,628

_____________

(1) The current portion of the asset retirement obligation is included in other accrued expenses on our condensed consolidated balance sheets.

Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and surface reclamation costs considering federal and state regulatory requirements in effect at that time. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense.

NOTE 11 - COMMITMENTS AND CONTINGENCIES

Commitments. We routinely enter into, extend or amend operating agreements in the ordinary course of business. We have long-term transportation, sales, processing and facility expansion agreements for pipeline capacity and water delivery and disposal commitments. There were no significant commitments entered into during the three and six months ended June 30, 2021. For details of our commitments, refer to Note 12 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data included in our Form 10-K for the year ended December 31, 2020.

Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying condensed consolidated balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.

Environmental. Due to the nature of the oil and gas industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of June 30, 2021 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on our condensed consolidated balance sheets.

In recent years, we have been executing a program to plug and abandon certain of our older vertical wells in the Wattenberg Field. A self-audit of final reclamation activities associated with site retirements, which we concluded in 2019, identified certain deficiencies, including incomplete documentation and agency submittals, inadequate plant growth and incomplete earthwork. In December 2019, we formally disclosed these deficiencies to the Colorado Oil and Gas Conservation Commission (“COGCC”) and are working to close this backlog of site reclamation work. In August 2020, the COGCC issued a Notice of Alleged Violation (“NOAV”) citing a failure to comply with reclamation requirements at multiple locations. During 2020, we assessed and identified deficiencies in reclamation activities at sites acquired through the January 2020 SRC

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

Acquisition. In January 2021, we formally disclosed to the COGCC the deficiencies at sites acquired in the SRC Acquisition. To resolve the alleged violations, the COGCC and PDC jointly agreed to an Administrative Order by Consent (“AOC”) which assessed penalties in the amount of approximately $491,000, with approximately $333,000 suspended pending PDC meeting certain conditions of the AOC. The COGCC approved the AOC in July 2021. We are implementing programs to meet the requirements of the AOC and correct any identified deficiencies.

As part of our integration activities over the facilities acquired through the SRC Acquisition, we conducted a comprehensive air quality compliance audit. Through the audit process, we identified certain deficiencies and disclosed them to the Colorado Department of Public Health and Environment (“CDPHE”) and the U.S. Environmental Protection Agency (“EPA”) in July 2021. We do not believe potential penalties and other expenditures associated with the deficiencies identified will have a material effect on our financial condition or results of operations, but they may exceed $300,000.

Clean Air Act Agreement and Related Consent Decree. We continue to implement the requirements of a consent decree entered into with the CDPHE in 2017, as well as a revised compliance order on consent, the latter of which was modified by the CDPHE after the SRC Acquisition was completed. Over the course of this execution, we have identified certain immaterial deficiencies in our implementation of the programs. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $300,000.

Further, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations.

NOTE 12 - COMMON STOCK

Stock-Based Compensation Plans

2018 Equity Incentive Plan. In May 2020, our stockholders approved an amendment to increase the number of shares of our common stock reserved for issuance pursuant to our long-term equity compensation plan for employees and non-employee directors (the “2018 Plan”) from 1,800,000 to 7,050,000 shares. As of June 30, 2021, there were 4,143,921 shares available for grant under the 2018 Plan.

2010 Long-Term Equity Compensation Plan. Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was approved by stockholders in 2013 (the “2010 Plan”), remains outstanding and we may continue to use the 2010 Plan to grant awards. No awards may be granted under the 2010 Plan on or after June 5, 2023. As of June 30, 2021, there were 305,395 shares available for grant under the 2010 Plan.

2015 SRC Equity Incentive Plan. SRC PSUs were granted in connection with the closing of the SRC Acquisition. For the six months ended and as of June 30, 2021, there were no changes to the 2015 SRC Equity Incentive Plan and there were no shares available for grant.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(in thousands)
General and administrative expense	$	6,113	$	6,053	$	10,941	$	11,461
Lease operating expense	382		311		574		575
Total stock-based compensation expense	$	6,495	$	6,364	$	11,515	$	12,036

Restricted Stock Units

The following table presents the changes in non-vested time-based RSUs to all employees, including executive officers, for the six months ended June 30, 2021:


	Shares	Weighted-Average Grant Date Fair Value per Share
Non-vested at beginning of period	1,150,970	$	20.14
Granted	639,196	33.32
Vested	(520,585)	24.75
Forfeited	(43,228)	22.79
Non-vested at end of period	1,226,353	24.96

The weighted-average grant date fair value of restricted stock units was $33.32 and $11.69 for the six months ended June 30, 2021 and 2020, respectively. Total compensation cost related to non-vested time-based awards and not yet recognized on our condensed consolidated statements of operations as of June 30, 2021 was $25.7 million. This cost is expected to be recognized over a weighted-average period of 2.08 years.

Performance Stock Units

The Compensation Committee awarded a total of 207,655 market-based PSUs to our executive officers during the six months ended June 30, 2021. In addition to continuous employment, the vesting of these PSUs is contingent on a combination of absolute stock performance and our total stockholder return (“TSR”), which is essentially our stock price change, including any dividends, over a three-year period ending on December 31, 2023, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between zero and 250 percent of the target PSUs awarded.

The grant-date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our common stock historical volatility.

The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the periods presented:


	Six Months Ended June 30,
	2021	2020
Expected term of award (in years)	3	3
Risk-free interest rate	0.2%	1.4%
Expected volatility	84.6%	46.6%
Weighted-average grant date fair value per share	$54.01	$33.52

SRC Performance Stock Units. The terms of the SRC PSUs are substantially the same as those of the PDC PSUs, except that the SRC PSUs do not require continuous employment and the performance period associated with the awards of

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

January 1, 2019 through December 31, 2021 predates the grant date. The fair value of the SRC PSU awards was determined on the grant date of January 13, 2020 using the Monte Carlo pricing model using the following assumptions:


			Six Months Ended June 30, 2020
Expected term of awards (in years)			2
Risk-free interest rate			1.6%
Expected volatility			56.9%
Weighted-average grant date fair value per share			$33.35

The expected term of the awards is based on the number of years from the grant date through the end of the performance period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant, extrapolated to approximate the life of the awards. The expected volatility was based on our common stock historical volatility, as well as that of our peer group.

The following table presents the change in non-vested market-based awards, including SRC PSUs, during the six months ended June 30, 2021:


	Shares	Weighted-Average Grant Date Fair Value per Share
Non-vested at beginning of period	499,547	$	38.66
Granted	207,655	54.01
Non-vested at end of period	707,202	43.17

Total compensation cost related to non-vested market-based awards not yet recognized on our condensed consolidated statements of operations as of June 30, 2021 was $15.0 million. This cost is expected to be recognized over a weighted-average period of 1.67 years.

Stock Appreciation Rights

All outstanding SARs as of June 30, 2021 have vested and the related compensation cost has been fully recognized. During the six months ended June 30, 2021 there were 9,766 SARs exercised at a weighted-average exercise price of $30.19 and 34,551 SARs expired with a weighted-average exercise price of $52.15. As of June 30, 2021, there were 166,358 SARs outstanding and exercisable which have a weighted-average exercise price of $50.02 and an average remaining contractual term of 3.62 years. Outstanding and exercisable SARs have $0.6 million intrinsic value as of June 30, 2021.

Preferred Stock

We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our board of directors from time to time. Through June 30, 2021, no shares of preferred stock have been issued.

Stock Repurchase Program

In April 2019, the board of directors approved the repurchase of up to $200 million of our outstanding common stock (the “Stock Repurchase Program”). Effective upon the closing of the SRC Acquisition, our board of directors approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million. Repurchases under the Stock Repurchase Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Stock Repurchase Program does not require any specific number of shares to be acquired, is subject to market conditions and can be modified or discontinued by our board of directors at any time. Pursuant to the Stock Repurchase Program, we repurchased 1.3 million and 1.3 million shares of outstanding common stock at a cost of $48.6 million and $23.8 million during the six months ended June 30, 2021 and 2020, respectively. We suspended the program in March 2020 due to adverse market conditions but reinstated it in February 2021. Repurchases may extend until December 31, 2023. As of June 30, 2021, $298.2 million of our outstanding common stock remained available for repurchase under the program.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

Dividends

In May 2021, our board of directors declared a cash dividend of $0.12 per share of common stock. The dividend was paid on June 24, 2021 to stockholders of record on June 10, 2021. All RSUs and PSUs receive a dividend equivalent per unit, recognized as a liability included in other liabilities on our condensed consolidated balance sheets, until the recipients receive the equivalents upon vesting. Dividends declared were recorded as a reduction of additional paid-in capital as there were no retained earnings as of the date of declaration. Future divided payments must be approved by our board of directors and will depend on our liquidity, financial requirements, and other factors considered relevant by our board.

NOTE 13 - INCOME TAXES

We compute our quarterly tax provision using the effective tax rate method by applying the anticipated annual effective rate to our year-to-date income or loss, except for discrete items. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs.

We consider whether a portion, or all, of the deferred tax assets (“DTAs”) will be realized based on a more likely than not standard of judgment. The ultimate realization of DTAs is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. As of December 31, 2020, we had a full valuation allowance totaling $165.6 million against our DTAs resulting from prior year cumulative financial losses, oil and gas impairments, and significant net operating losses for U.S. federal and state income tax. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. As of June 30, 2021, there was no change in our assessment of the realizability of our DTAs. Future events or new evidence which may lead us to conclude that it is more likely than not that our net DTAs will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions.

As long as we conclude that we will continue to provide for a valuation allowance against our net DTA, we will likely not have any additional income tax expense or benefit other than for state income taxes. The effective income tax rates for the three and six months ended June 30, 2021 were 0.2 percent and 0.1 percent benefit on loss, respectively, and 1.9 percent benefit on loss and 0.5 percent provision on loss for the three and six months ended June 30, 2020, respectively.

As of June 30, 2021, there is no liability for unrecognized income tax benefits. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. The IRS has accepted our 2019 federal income tax return with no tax adjustments. We continue to voluntarily participate in the IRS CAP program for the review of our 2020 and 2021 tax years. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings.

NOTE 14 - EARNINGS PER SHARE

Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested equity-based employee awards, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

The following table presents our weighted-average basic and diluted shares outstanding for the periods presented:


	Three Months Ended June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
	(in thousands)
Weighted-average common shares outstanding - basic	99,187	99,566	99,445	96,821




Weighted-average common shares and equivalents outstanding - diluted	99,187	99,566	99,445	96,821

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2021

(Unaudited)

We reported a net loss for the three and six months ended June 30, 2021 and 2020. As a result, our basic and diluted weighted-average common shares outstanding were the same for those periods because the effect of the common share equivalents was anti-dilutive.

The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect for the periods presented:


	Three Months Ended June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
	(in thousands)
RSUs and PSUs	2,818	1,914	2,642	1,600

Other equity-based awards	172	244	185	236
Total anti-dilutive common share equivalents	2,990	2,158	2,827	1,836

The 2021 Convertible Notes give the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes were not included in the diluted earnings per share calculation using the treasury stock method for any periods presented as the average market price of our common stock did not exceed the conversion price.

NOTE 15 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION


	Six Months Ended June 30,
	2021		2020
	(in thousands)
Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest	$	30,855	$	39,168
Income taxes	(1,125)		(204)

Non-cash investing and financing activities:
Change in accounts payable related to capital expenditures	$	61,310	$	(7,223)
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals	(1,729)		44,082
Issuance of common stock for the acquisition of crude oil and natural gas properties, net	—		1,009,015

Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	4,054	$	4,421
Operating cash flows from finance leases	65		109


Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	1,066	$	4,217
Finance leases	1,466		703

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our condensed consolidated financial statements and related notes included in Item 1. Financial Statements of this report. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements.

EXECUTIVE SUMMARY

June 30, 2021 Financial Overview of Operations and Liquidity

COVID-19 Impact

In 2020, the COVID-19 pandemic led to a significant decline in commodity prices, negatively impacting the world economy, including oil and natural gas producers, such as PDC. To date in 2021, the effects of COVID-19 mitigation efforts, including the distribution of vaccines, has aided in the recovery of global commodity prices. The commodity price environment may remain volatile for an extended period through the progression of the COVID-19 pandemic, including outbreaks caused by coronavirus variants.

Financial Matters

Production volumes were 17.4 and 33.2 MMboe for the three and six months ended June 30, 2021, respectively, representing an increase of one percent compared to the three months ended June 30, 2020 and a decrease of three percent as compared to the six months ended June 30, 2020. The year-to-date decrease was primarily driven by (i) reduced capital expenditures in the second half of 2020 resulting from the COVID-19 related decrease in demand for oil and natural gas and (ii) a loss of approximately 0.5 MMBoe from temporary shut-ins of our wells driven by severe weather during the first quarter of 2021. For the month ended June 30, 2021, we maintained an average daily production rate of approximately 193,000 Boe per day, down by approximately 2 percent compared to 197,000 Boe per day for the month ended June 30, 2020.

On a sequential quarterly basis, total production for the three months ended June 30, 2021 increased 11 percent to 17.4 MMboe as compared to 15.7 MMboe for the three months ended March 31, 2021 due to temporary shut-ins driven by severe weather in the first quarter of 2021 and timing of capital investments between 2020 and 2021.

Crude oil, natural gas and NGLs sales increased to $533.1 million and $1.0 billion for the three and six months ended June 30, 2021, respectively, compared to $173.9 million and $494.2 million for the three and six months ended June 30, 2020, respectively. The increase in revenues for the three months ended June 30, 2021 compared to prior period was primarily due to

the 204 percent increase in weighted-average realized commodity prices between periods. The increase in revenues for the six months ended June 30, 2021 compared to the same period in 2020 was primarily due to the 108 percent increase in weighted-average realized commodity prices, which was partially offset by the 3 percent decrease in production between periods.

We had negative net settlements from our commodity derivative contracts of $55.1 million and $85.8 million for the three and six months ended June 30, 2021, as compared to positive net settlements of $114.8 million and $160.6 million for the three and six months ended June 30, 2020.

The combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 66 percent and 40 percent to $478.0 million and $915.5 million for the three and six months ended June 30, 2021, respectively, from $288.7 million and $654.8 million for the three and six months ended June 30, 2020.

For the three months ended June 30, 2021, we generated a net loss of $87.0 million, or $0.88 per diluted share, compared to a net loss of $221.8 million, or $2.23 per diluted share, for the comparable period in 2020. The decrease in net loss between periods was primarily due to an increase in crude oil, natural gas and NGLs sales of $359.2 million partially offset by an increase in commodity price risk management loss of $187.5 million. For the six months ended June 30, 2021, we generated a net loss of $96.1 million, or $0.97 per diluted share, compared to a net loss of $686.8 million, or $7.09 per diluted share, for the comparable period in 2020. The decrease in net loss for the first half of 2021 as compared to the same period in 2020 was most significantly impacted by an increase in crude oil, natural gas and NGLs sales of $507.0 million, a decrease in general and administrative expense of $32.0 million realized in the first half of 2021 and an $881.1 million impairment charge recognized in

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the first quarter of 2020. These positive factors impacting the decrease in our net loss between periods were partially offset by a $489.5 million commodity price risk management loss in the first half of 2021 compared to $313.9 million in commodity price risk management gains in 2020.

For the three and six months ended June 30, 2021, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $358.3 million and $674.1 million, respectively, compared to $198.5 million and $426.4 million for the comparable periods in 2020. The increases for the three and six months ended June 30, 2021 were primarily due to an increase in sales, offset by net derivative settlements, of $189.3 million and $260.7 million, respectively.

Cash flows from operations were $577.4 million and $369.3 million for the six months ended June 30, 2021 and 2020, respectively, and our adjusted cash flows from operations, a non-U.S. GAAP financial measure, were $643.0 million and $391.5 million, respectively. Adjusted free cash flows, a non-U.S. GAAP financial measure, were $341.4 million for the six months ended June 30, 2021 and $10.8 million for the comparable period of the prior year.

See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.

Drilling and Completion Overview

During the six months ended June 30, 2021, we operated one full-time drilling rig, one spudder rig and one full-time completion crew in the Wattenberg Field. In addition, we operated one full-time drilling rig and one part-time completion crew, which started in March and ended in June, in the Delaware Basin. Our total capital investments in crude oil and natural gas properties for the six months ended June 30, 2021 were $301.6 million.

The following tables summarize our drilling and completion activities for the six months ended June 30, 2021:


	Operated Wells
	Wattenberg Field		Delaware Basin		Total
	Gross	Net	Gross	Net	Gross	Net
In-process as of December 31, 2020	214	201.8	20	19.0	234	220.8
Wells spud	43	39.8	10	10.0	53	49.8
Wells turned-in-line	(56)	(53.5)	(18)	(17.4)	(74)	(70.9)

In-process as of June 30, 2021	201	188.1	12	11.6	213	199.7

Our in-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our in-process wells are generally completed and turned-in-line within two years of drilling.

Capital Return

Debt Reduction. During the six months ended June 30, 2021, we had net debt repayments of $168.0 million on our revolving credit facility, resulting in no outstanding balance at the period end.

Stock Repurchase Program. In February 2021, we reinstated our Stock Repurchase Program. During the three and six months ended June 30, 2021, we repurchased 0.7 million and 1.3 million shares of our outstanding common stock at a cost of $26.5 million and $48.6 million, respectively. As of June 30, 2021, $298.2 million of our outstanding common stock remained available for repurchases under the program.

Dividends. In May 2021, our board of directors declared our first cash dividend of $0.12 per share of common stock. For the three and six months ended June 30, 2021, our dividends paid totaled $11.9 million.

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2021 Operational and Financial Outlook

We anticipate that our production in 2021 will range between 190,000 Boe to 195,000 Boe per day, approximately 64,000 Bbls to 66,000 Bbls of which are expected to be crude oil. Our planned 2021 capital investments in crude

oil and natural gas properties, which we expect to be between $550 million and $600 million, are focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin.

We have operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining inventory in order to best meet our short- and long-term corporate strategy. We may revise our 2021 capital investment program for the remainder of the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds, and acquisition and divestiture opportunities. During the second quarter of 2021, we experienced minor increases in capital and operating costs which were partially offset by our completion cost efficiencies. We anticipate further modest increases in costs if oil and gas pricing remains near or exceeds current levels.

Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between the Kersey, Prairie, Plains, and Summit development areas. Our 2021 capital investment program for the Wattenberg Field is approximately 75 percent of our expected total capital investments in crude oil and natural gas properties, of which approximately 90 percent is expected to be invested in operated drilling and completion activity. We plan to drill standard-reach lateral (“SRL”), mid-reach lateral (“MRL”) and extended-reach lateral (“XRL”) wells in the Wattenberg Field. In 2021, we anticipate spudding approximately 75 to 85 operated wells and turning-in-line approximately 150 to 175 operated wells. In 2021, we expect to operate with one full-time horizontal drilling rig crew and one full-time completion crew along with a part-time spudder rig. The remainder of the Wattenberg Field capital investment program is expected to be used for land, capital workovers, facilities projects and non-operated drilling.

Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2021 are expected to be approximately 25 percent of our total capital investments, of which approximately 85 percent is expected to be invested in operated drilling and completion activity. In June 2021, we concluded our operated completion program for the year by completing and turning-in-line 18 wells. We will continue to operate with one drilling rig for the remainder of 2021. The majority of the remaining wells we plan to drill in 2021 in the Delaware Basin are MRL and XRL wells.

We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2021, we expect 2021 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. We expect that any excess cash flows from operations will be used to reduce our indebtedness, to return capital to our shareholders, and for general corporate purposes.

Regulatory and Political Update

In Colorado, certain interest groups opposed to oil and natural gas have proposed ballot initiatives that could hinder or eliminate the ability to develop resources in the state. In 2019, the Colorado legislature passed Senate Bill 19-181 (“SB 19-181”) to address concerns underlying the ballot initiatives.

As part of SB 19-181, a series of rulemaking hearings have been conducted which focused on issues such as permitting requirements, setbacks and siting requirements, resulting in the adoption of new regulatory requirements. Rulemakings focused on financial assurance and permit fees have not been completed. The financial assurance rulemaking could result in increased bonding requirements, though the final language and impact will not be known until early 2022.

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A key component of SB 19-181 was the change in the COGCC mission from “fostering” the industry to “regulating” the industry. As a result, changes were made to the permitting process in Colorado. Permits are now designed as Oil and Gas Development Plans (“OGDP”), which streamlines single pad locations or proximate multi-pad locations into a single permitting package. Operators also have an option to pursue a Comprehensive Area Plan (“CAP”). A CAP is designed to represent a landscape-level look at oil and gas development in a larger area over a longer period of time, and to include multiple OGDPs within its boundaries. As both CAPs and OGDPs are new processes and the COGCC staff is working to develop the appropriate materials and adjusting to their new operating plan, the time needed to obtain a permit has been prolonged. COGCC rules provide that the permitting process could range between six to twelve months or more from submission to approval.

We cannot predict whether future ballot initiatives or other legislation or regulation will be proposed that would dramatically limit the areas of the state in which drilling is permitted to occur.

The SEC and other regulatory bodies are proposing a number of climate change-focused and broader environmental, social and governance (“ESG”) disclosures and reporting requirements in SEC filings for public companies. If adopted, we will modify and accommodate our disclosures accordingly.

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Results of Operations

Summary of Operating Results

The following table presents selected information regarding our operating results:


	Three Months Ended June 30,						Six Months Ended June 30,
	2021		2020		Percent Change		2021		2020		Percent Change
	(dollars in millions, except per unit data)
Production:
Crude oil (MBbls)	5,391		6,215		(13)	%	10,248		12,103		(15)	%
Natural gas (MMcf)	43,360		40,708		7	%	83,512		82,055		2	%
NGLs (MBbls)	4,805		4,249		13	%	8,997		8,314		8	%
Crude oil equivalent (MBoe)	17,424		17,248		1	%	33,164		34,093		(3)	%
Average Boe per day (Boe)	191,473		189,538		1	%	183,227		187,324		(2)	%

Crude Oil, Natural Gas and NGLs Sales:
Crude oil	$	350.6	$	115.8	203	%	$	624.3	$	364.9	71	%
Natural gas	85.8		31.0		177	%	191.4		70.6		171	%
NGLs	96.7		27.1		257	%	185.6		58.7		216	%
Total crude oil, natural gas and NGLs sales	$	533.1	$	173.9	207	%	$	1,001.3	$	494.2	103	%

Net Settlements on Commodity Derivatives
Crude oil	$	(47.9)	$	115.0	(142)	%	$	(68.4)	$	161.9	(142)	%
Natural gas	(7.2)		(0.2)		*		(17.4)		(1.3)		*
Total net settlements on derivatives	$	(55.1)	$	114.8	(148)	%	$	(85.8)	$	160.6	(153)	%

Average Sales Price (excluding net settlements on derivatives):
Crude oil (per Bbl)	$	65.05	$	18.63	249	%	$	60.92	$	30.15	102	%
Natural gas (per Mcf)	1.98		0.76		161	%	2.29		0.86		166	%
NGLs (per Bbl)	20.11		6.38		215	%	20.61		7.06		192	%
Crude oil equivalent (per Boe)	30.60		10.08		204	%	30.19		14.50		108	%

Average Costs and Expenses (per Boe):
Lease operating expense	$	2.43	$	2.08	17	%	$	2.54	$	2.50	2	%
Production taxes	1.55		0.45		244	%	1.70		0.77		121	%
Transportation, gathering and processing expense	1.49		0.98		52	%	1.44		0.89		62	%
General and administrative expense	1.88		2.05		(8)	%	1.98		2.86		(31)	%
Depreciation, depletion and amortization	9.31		8.67		7	%	9.32		9.55		(2)	%

Lease Operating Expense by Operating Region (per Boe)
Wattenberg Field	$	2.15	$	1.88	14	%	$	2.23	$	2.31	(3)	%
Delaware Basin	4.35		3.19		36	%	4.77		3.53		35	%

____________

* Percent change is not meaningful.

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PDC ENERGY, INC.

Crude Oil, Natural Gas and NGLs Sales

Crude oil, natural gas and NGLs sales for the three and six months ended June 30, 2021 increased compared to the three and six months ended June 30, 2020 due to the following:


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	(in millions)
Change in:
Production	$	(9.7)	$	(49.8)

Average crude oil price	250.3		315.3
Average natural gas price	52.7		119.7
Average NGLs price	65.9		121.9
Total change in crude oil, natural gas and NGLs sales revenue	$	359.2	$	507.1

Crude Oil, Natural Gas and NGLs Production

The following table presents crude oil, natural gas and NGLs production for the periods presented:


	Three Months Ended June 30,				Six Months Ended June 30,
Production by Operating Region	2021	2020	Percent Change		2021	2020	Percent Change
Crude oil (MBbls)
Wattenberg Field	4,497	5,170	(13)	%	8,670	10,095	(14)	%
Delaware Basin	894	1,045	(14)	%	1,578	2,008	(21)	%
Total	5,391	6,215	(13)	%	10,248	12,103	(15)	%
Natural gas (MMcf)
Wattenberg Field	38,181	34,779	10	%	73,742	69,836	6	%
Delaware Basin	5,179	5,929	(13)	%	9,770	12,219	(20)	%
Total	43,360	40,708	7	%	83,512	82,055	2	%
NGLs (MBbls)
Wattenberg Field	4,353	3,685	18	%	8,153	7,031	16	%
Delaware Basin	452	564	(20)	%	844	1,283	(34)	%
Total	4,805	4,249	13	%	8,997	8,314	8	%
Crude oil equivalent (MBoe)
Wattenberg Field	15,213	14,651	4	%	29,113	28,766	1	%
Delaware Basin	2,211	2,597	(15)	%	4,051	5,327	(24)	%
Total	17,424	17,248	1	%	33,164	34,093	(3)	%
Average crude oil equivalent per day (Boe)
Wattenberg Field	167,176	161,000	4	%	160,846	158,055	2	%
Delaware Basin	24,297	28,538	(15)	%	22,381	29,269	(24)	%
Total	191,473	189,538	1	%	183,227	187,324	(2)	%

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PDC ENERGY, INC.

Net production volumes for oil, natural gas and NGLs increased 1 percent and decreased 3 percent during the three and six months ended June 30, 2021 compared to the three and six months ended June 30, 2020. The increase in production volume for the three months ended June 30, 2021 compared to the same period in 2020 was due to wells turned in line in the second quarter of 2021 and the temporary shut-ins of some wells resulting from the COVID-19 related decrease in demand for crude oil and natural gas in the second quarter of 2020. The decrease in production for the six months ended June 30, 2021 compared to the same period in 2020 was driven by (i) reduced capital expenditures in the second half of 2020 resulting from the COVID-19 related decrease in demand for oil and gas and (ii) a loss of approximately 0.5 MMBoe from temporary shut-ins of a significant portion of our wells driven by severe weather during the first quarter of 2021.

The following table presents our crude oil, natural gas and NGLs production ratio by operating region for the periods presented:


	Three Months Ended June 30, 2021
	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	30%	42%	28%	100%
Delaware Basin	40%	39%	21%	100%

	Three Months Ended June 30, 2020
	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	35%	40%	25%	100%
Delaware Basin	40%	38%	22%	100%


	Six Months Ended June 30, 2021
	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	30%	42%	28%	100%
Delaware Basin	39%	40%	21%	100%

	Six Months Ended June 30, 2020
	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	35%	41%	24%	100%
Delaware Basin	38%	38%	24%	100%

The change in production mix in the Wattenberg Field during the three and six months ended June 30, 2021 compared to the same periods in 2020 was driven by our 2021 developmental plans being focused on areas that have a higher gas/oil ratio as well as the variability of our quarterly capital spend.

Midstream Capacity

Our ability to market our production depends substantially on the availability, proximity and capacity of in-field gathering systems, compression and processing facilities, as well as transportation pipelines out of the basin, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available on a timely basis and at acceptable costs, our production and results of operations could be adversely affected.

The ultimate timing and availability of adequate infrastructure remains out of our control. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure. Like other producers, from time to time, we enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to sufficiently meet our projected volume growth from our areas of operation. If our production falls below the level required under these agreements, we could be subject to transportation charges or aid in construction payments for commitment shortfalls.

Our production from the Wattenberg Field and Delaware Basin was not materially affected by midstream or downstream capacity constraints during the six months ended June 30, 2021.

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PDC ENERGY, INC.

Crude Oil, Natural Gas and NGLs Pricing

Our results of operations depend upon many factors. Key factors include market prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices have a high degree of volatility and our realizations can change substantially. Our weighted-average realized commodity prices increased 204 percent and 108 percent during the three and six months ended June 30, 2021 compared to the three and six months ended June 30, 2020. The NYMEX average daily crude oil and NYMEX first-of-the-month natural gas prices increased by 137 percent and 67 percent for the three months ended June 30, 2021, as compared to the same period in 2020, respectively. For the six months ended June 30, 2021, prices increased by 65 percent and 51 percent, as compared to the same period in 2020, respectively.

The following table presents weighted-average sales prices of crude oil, natural gas and NGLs for the periods presented:


	Three Months Ended June 30,						Six Months Ended June 30,
Weighted-Average Realized Sales Price by Operating Region					Percent Change						Percent Change
(excluding net settlements on derivatives)	2021		2020				2021		2020
Crude oil (per Bbl)
Wattenberg Field	$	64.84	$	18.09	258	%	$	60.84	$	29.73	105	%
Delaware Basin	66.10		21.28		211	%	61.35		32.25		90	%
Weighted-average price	65.05		18.63		249	%	60.92		30.15		102	%
Natural gas (per Mcf)
Wattenberg Field	$	1.96	$	0.85	131	%	$	2.33	$	1.00	133	%
Delaware Basin	2.15		0.27		*		2.02		0.09		*
Weighted-average price	1.98		0.76		161	%	2.29		0.86		166	%
NGLs (per Bbl)
Wattenberg Field	$	19.18	$	6.18	210	%	$	19.78	$	6.83	190	%
Delaware Basin	29.01		7.70		277	%	28.65		8.36		243	%
Weighted-average price	20.11		6.38		215	%	20.61		7.06		192	%
Crude oil equivalent (per Boe)
Wattenberg Field	$	29.56	$	9.95	197	%	$	29.56	$	14.52	104	%
Delaware Basin	37.74		10.85		248	%	34.75		14.36		142	%
Weighted-average price	30.60		10.08		204	%	30.19		14.50		108	%

____________

* Percent change is not meaningful.

Crude oil, natural gas and NGLs revenues are recognized when we transfer control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to occur when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from the crude oil, natural gas or NGLs production.

Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or “gross” method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us based on a percent of proceeds or a sales price fixed at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index on which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transportation and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing (“TGP”) expense.

Information related to the components and classifications of TGP expense on the condensed consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based on average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based on first-of-the-month index prices, as in each case this is the method used to sell the majority of these commodities pursuant to terms of the relevant sales agreements. For

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NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after transportation, gathering and processing expense shown in the table below represents our approximate composite per barrel price for NGLs.


Three Months Ended June 30, 2021	Average NYMEX Price		Average Realized Price Before TGP Expense		Average Realization Percentage Before TGP Expense		Average TGP Expense (1)		Average Realized Price After TGP Expense		Average Realization Percentage After TGP Expense
Crude oil (per Bbl)	$	66.07	$	65.05	98	%	$	3.33	$	61.72	93	%
Natural gas (per MMBtu)	2.83		1.98		70	%	0.12		1.86		66	%
NGLs (per Bbl)	66.07		20.11		30	%	—		20.11		30	%
Crude oil equivalent (per Boe)	45.71		30.60		67	%	1.32		29.28		64	%

Three Months Ended June 30, 2020	Average NYMEX Price		Average Realized Price Before TGP Expense		Average Realization Percentage Before TGP Expense		Average TGP Expense (1)		Average Realized Price After TGP Expense		Average Realization Percentage After TGP Expense
Crude oil (per Bbl)	$	27.85	$	18.63	67	%	$	1.87	$	16.76	60	%
Natural gas (per MMBtu)	1.72		0.76		44	%	0.12		0.64		37	%
NGLs (per Bbl)	27.85		6.38		23	%	—		6.38		23	%
Crude oil equivalent (per Boe)	20.94		10.08		48	%	0.96		9.12		44	%


Six Months Ended June 30, 2021	Average NYMEX Price		Average Realized Price Before TGP Expense		Average Realization Percentage Before TGP Expense		Average TGP Expense (1)		Average Realized Price After TGP Expense		Average Realization Percentage After TGP Expense
Crude oil (per Bbl)	$	61.96	$	60.92	98	%	$	3.32	$	57.60	93	%
Natural gas (per MMBtu)	2.76		2.29		83	%	0.11		2.18		79	%
NGLs (per Bbl)	61.96		20.61		33	%	—		20.61		33	%
Crude oil equivalent (per Boe)	42.91		30.19		70	%	1.32		28.87		67	%

Six Months Ended June 30, 2020	Average NYMEX Price		Average Realized Price Before TGP Expense		Average Realization Percentage Before TGP Expense		Average TGP Expense (1)		Average Realized Price After TGP Expense		Average Realization Percentage After TGP Expense
Crude oil (per Bbl)	$	37.01	$	30.15	81	%	$	1.67	$	28.48	77	%
Natural gas (per MMBtu)	1.83		0.86		47	%	0.12		0.74		40	%
NGLs (per Bbl)	37.01		7.06		19	%	—		7.06		19	%
Crude oil equivalent (per Boe)	26.58		14.50		55	%	0.87		13.63		51	%

____________

(1)Average TGP expense excludes unutilized firm transportation fees of $0.17 per Boe and $0.02 per Boe for the three months ended June 30, 2021 and 2020, respectively, and $0.12 per BOE and $0.02 per BOE for the six months ended June 30, 2021 and 2020.

Our average realization percentages for crude oil, natural gas and NGLs increased in the three and six months ended June 30, 2021 as compared to the same period in 2020 due to the improvement in oil and gas product demand that occurred as countries relaxed COVID-19 restrictions throughout 2020 and 2021. During the six months ended June 30, 2021, our natural gas realizations were notably higher due to strong February 2021 pricing that resulted from the severe weather conditions.

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Commodity Price Risk Management

We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices, including collars, fixed-price exchanges and basis protection exchanges on a portion of our estimated crude oil and natural gas production. For our commodity exchanges, we ultimately realize the fixed price value related to the swaps. See Note 5 - Commodity Derivative Financial Instruments in Item 1. Financial Statements included elsewhere in this report for a summary of our derivative positions as of June 30, 2021.

Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, and the change in fair value of unsettled commodity derivatives related to our crude oil and natural gas production.

Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas forward price curves and changes in certain differentials.

The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil collars and fixed price exchanges	$	(47.9)	$	115.0	$	(68.4)	$	162.0
Natural gas collars and fixed price exchanges	(4.7)		3.3		(7.5)		3.6
Natural gas basis protection exchanges	(2.5)		(3.5)		(9.9)		(5.0)
Total net settlements of commodity derivative instruments	(55.1)		114.8		(85.8)		160.6
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments	29.5		(125.9)		(5.4)		(2.4)
Crude oil collars and fixed price exchanges	(224.6)		(95.8)		(329.5)		177.1
Natural gas collars and fixed price exchanges	(66.1)		(3.0)		(67.7)		(7.0)
Natural gas basis protection exchanges	8.0		(10.9)		(1.1)		(14.4)
Net change in fair value of unsettled commodity derivative instruments	(253.2)		(235.6)		(403.7)		153.3
Total commodity price risk management gain (loss), net	$	(308.3)	$	(120.8)	$	(489.5)	$	313.9

Lease Operating Expense

Lease operating expense (“LOE”) increased by 18 percent to $42.4 million for the three months ended June 30, 2021 compared to $35.8 million for the three months ended June 30, 2020. The period-over-period increase in LOE was primarily

attributable to increased payroll costs and activities at our well locations since the shut-ins from the COVID-19 induced downturn in 2020. Additionally, we experienced fewer vendor concessions as the price of commodities has improved since the second quarter of 2020. LOE per Boe increased 17 percent to $2.43 for the three months ended June 30, 2021 from $2.08 for the three months ended June 30, 2020.

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LOE decreased by 1 percent to $84.2 million for the six months ended June 30, 2021 compared to $85.3 million for the six months ended June 30, 2020. The period-over-period decrease in LOE was primarily attributable to operational efficiencies realized from the SRC Acquisition in the Wattenberg Field for approximately $4.2 million. The decrease was partially offset by increased payroll costs and activities at our well locations in the first half of 2021 as compared to same period in 2020, as discussed above. LOE per Boe increased 2 percent to $2.54 for the six months ended June 30, 2021 from $2.50 for the six months ended June 30, 2020, primarily due to a 3 percent decrease in production volumes between periods.

Production Taxes

Production taxes are comprised mainly of severance tax and ad valorem tax, and are directly related to crude oil, natural gas and NGLs sales and are generally assessed as a percentage of net revenues. From time to time, there are adjustments to the statutory rates for these taxes based upon certain credits that are determined based upon activity levels and relative commodity prices from year-to-year.

Production taxes increased 244 percent to $27.0 million for the three months ended June 30, 2021 compared to $7.8 million for the three months ended June 30, 2020. Production taxes per Boe increased 244 percent to $1.55 for the three months ended June 30, 2021 compared to $0.45 for the three months ended June 30, 2020. The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs prices between periods.

Production taxes increased 115 percent to $56.5 million for the six months ended June 30, 2021 compared to $26.3 million for the six months ended June 30, 2020. Production taxes per Boe increased 121 percent to $1.70 for the six months ended June 30, 2021 compared to $0.77 for the six months ended June 30, 2020. The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs prices between periods.

Transportation, Gathering and Processing Expense

TGP expense increased 53 percent to $26.0 million for the three months ended June 30, 2021 compared to $16.9 million for the three months ended June 30, 2020. TGP expense per Boe increased 52 percent to $1.49 for the three months ended June 30, 2021 compared to $0.98 for the three months ended June 30, 2020. The increase in TGP expense was primarily due to (i) a $6.1 million increase relating to an increase in transportation rates of our crude oil volumes delivered, (ii) $2.5 million in costs relating to new contracts and amendments to existing crude oil sales contracts, which resulted in a change in recognition from a net-back to a gross presentation of TGP expense, and (iii) $2.5 million of shortfall fees relating to our delivery commitment in the Delaware Basin. These increases were offset by $3.0 million relating to a net decrease of production volumes for crude oil and natural gas between periods.

TGP expense increased 57 percent to $47.7 million for the six months ended June 30, 2021 compared to $30.4 million for the six months ended June 30, 2020. TGP expense per Boe increased 62 percent to $1.44 for the six months ended June 30, 2021 compared to $0.89 for the six months ended June 30, 2020. The increase in TGP expense was primarily due to (i) a $13.6 million increase relating to an increase in transportation rates of our crude oil volumes delivered, (ii) $5.0 million in costs relating to new contracts and amendments to existing crude oil sales contracts, which resulted in a change in recognition from a net-back to a gross presentation of TGP expense, and (iii) $2.9 million of shortfall fees relating to our delivery commitment in the Delaware Basin. These increases were offset by $6.5 million relating to a net decrease of production volumes for crude oil and natural gas between periods.

Impairment of Properties and Equipment

There were no significant impairment charges recognized related to our proved and unproved oil and gas properties during the three and six months ended June 30, 2021. If crude oil prices decline, or we change other estimates impacting future net cash flows (e.g. reserves, price differentials, future operating and/or development costs), our proved and unproved oil and gas properties could be subject to additional impairments in future periods.

During the three months ended March 31, 2020, we recorded impairment charges of $881.1 million. The impairment charges during the three months ended March 31, 2020 were due to a significant decline in crude oil prices, which was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment.

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General and Administrative Expense

General and administrative expense decreased 7 percent to $32.8 million for the three months ended June 30, 2021 compared to $35.4 million for the three months ended June 30, 2020 primarily due to $4.0 million in transition costs incurred in the second quarter of 2020 related to the SRC Acquisition, partially offset by a $2.0 million receivable allowance recognized in the second quarter of 2021.

General and administrative expense decreased 33 percent to $65.5 million for the six months ended June 30, 2021 compared to $97.5 million for the six months ended June 30, 2020 primarily due to $30.0 million in transaction and transition costs incurred in the first half of 2020 related to the SRC Acquisition, and consultant fees related to our ERP implementation of $5.2 million.

Depreciation, Depletion and Amortization Expense

DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $160.3 million and $305.0 million for the three and six months ended June 30, 2021, respectively, compared to $147.3 million and $321.1 million for the three and six months ended June 30, 2020, respectively. The increase in DD&A expense for the three months ended June 30, 2021 compared to the same period in 2020 was primarily due to the capitalized costs of wells turned in line during the second quarter of 2021 and an increase in production volumes between periods. The decrease in total DD&A expense for the six months ended June 30, 2021 compared to the same period in 2021 was primarily due to the decrease in production volumes between periods and the proved property impairment recognized in the first quarter of 2020 in the Delaware Basin, which lowered the carrying value of our depletion base.

The period-over-period change in DD&A expense related to crude oil and natural gas properties was primarily due to the following:


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	(in millions)
Increase (decrease) in production	$	6.0	$	(11.8)
Increase (decrease) in weighted-average depreciation, depletion and amortization rates	7.0		(4.3)
Total increase (decrease) in DD&A expense related to crude oil and natural gas properties	$	13.0	$	(16.1)

The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties for the periods presented:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(per Boe)
Operating Region/Area
Wattenberg Field	$	8.99	$	8.92	$	9.10	$	9.04
Delaware Basin	10.63		6.74		9.89		11.80
Total weighted-average	9.20		8.67		9.20		9.55

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Interest Expense, net

Interest expense, net decreased $1.7 million to $20.1 million for the three months ended June 30, 2021 compared to $21.8 million for the three months ended June 30, 2020. The decrease was primarily related to a $4.8 million decrease in interest as a result of reduced borrowings under our revolving credit facility between periods which was partially offset by a $2.2 million increase in interest expense related to the issuance of an additional $150 million aggregate principal amount of the 2026 Senior Notes in September 2020.

Interest expense, net decreased $6.9 million to $39.1 million for the six months ended June 30, 2021 compared to $46.0 million for the six months ended June 30, 2020. The decrease was primarily related to a $8.9 million decrease in interest as a result of reduced borrowings under our revolving credit facility between periods and a $1.7 million decrease in interest related to the partial redemption in February 2020 of the 2025 Senior Notes we assumed from the SRC Acquisition. These decreases were partially offset by a $4.4 million increase in interest expense related to the issuance of an additional $150 million aggregate principal amount of the 2026 Senior Notes in September 2020.

Provision for Income Taxes

We recorded a full valuation allowance against our net deferred tax assets for the six months ended June 30, 2021 and 2020 resulting in an effective income tax rate of 0.2 percent and 0.1 percent benefit on loss for the three and six months ended June 30, 2021, respectively, and a 1.9 percent benefit on loss and a 0.5 percent provision on loss for the three and six months ended June 30, 2020, respectively. The effective tax rate differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to pre-tax income due to the valuation allowance in effect for both periods.

At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. As of June 30, 2021, there was no change in our assessment of the realizability of our DTAs. Future events or new evidence which may lead us to conclude that it is more likely than not that our net DTAs will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions.

As long as we conclude that we will continue to provide for a valuation allowance against our net deferred tax assets, we will likely not have any additional income tax expense or benefit other than for state income taxes.

Net Income (Loss)/Adjusted Net Income (Loss)

The factors impacting net loss of $87.0 million and $96.1 million for the three and six months ended June 30, 2021, respectively, and net loss of $221.8 million and $686.8 million for the three and six months ended June 30, 2020, respectively, are discussed above.

Adjusted net income, a non-U.S. GAAP financial measure, was $166.2 million and $307.6 million for the three and six months ended June 30, 2021, respectively. We recognized an adjusted net income of $13.8 million for the three months ended June 30, 2021 and an adjusted net loss of $840.1 million for the six months ended June 30, 2020. With the exception of the tax-affected (when applicable) net change in fair value of unsettled commodity derivatives, the same factors impacted adjusted net income (loss). See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.

Financial Condition, Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows from operating activities, borrowings from our revolving credit facility, asset sales and proceeds raised in debt and equity capital market transactions. For the six months ended June 30, 2021, our net cash flows from operating activities were $577.4 million.

Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity

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PDC ENERGY, INC.

prices have historically been volatile and we manage a portion of this volatility through our use of commodity derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production.

We may use our available liquidity for operating activities, capital investments, working capital requirements, acquisitions and for general corporate purposes. We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells. From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as of June 30, 2021 is an indication of a lack of liquidity. We had working capital deficits of $732.2 million as of June 30, 2021 and $471.6 million as of December 31, 2020. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time.

Liquidity

Our cash and cash equivalents were $109.7 million at June 30, 2021 and availability under our revolving credit facility was $1.6 billion, providing for a total liquidity position of $1.7 billion as of June 30, 2021. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. Based on our current production forecast for 2021, we expect 2021 cash flows from operations to exceed our capital investments in crude oil and natural gas properties.

Based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to repay our 2021 Convertible Notes, which mature in September 2021 and to fund our planned activities through the 12-month period following the filing of this report. We also believe that we have sufficient expected cash flows from operations to repurchase additional shares pursuant to the Stock Repurchase Program and to pay potential future dividends. In addition, we may from time to time seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise.

Our revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to maintain: (a) a minimum current ratio of 1.0:1.0 and (b) a leverage ratio of not greater than 4.0:1.0. For purposes of the current ratio covenant, the revolving credit facility’s definition of total current assets, in addition to current assets as presented under U.S. GAAP, includes, among other things, unused commitments under the revolving credit facility. Additionally, the current ratio covenant calculation allows us to exclude the current portion of our long-term debt and other short-term loans from the U.S. GAAP total current liabilities amount. Accordingly, the existence of a working capital deficit under U.S. GAAP is not necessarily indicative of a violation of the current ratio covenant. At June 30, 2021, we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.6:1.0 and a leverage ratio of 1.2:1.0. We expect to remain in compliance throughout the 12-month period following the filing of this report.

Cash Flows

Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs and general and administrative expense. Cash flows from operating activities increased $208.1 million for the six months ended June 30, 2021 compared to the six months ended June 30, 2020. The increase between periods was primarily due to a $507.0 million increase in revenue from crude oil, natural gas and NGLs sales, a $32.0 million decrease in general and administrative expense, and the timing of vendor payments. These decreases were partially offset by $85.8 million in cash settlement losses on commodity derivatives in the first half of 2021 compared to a $160.6 million in cash receipts from derivative settlements in the comparable period in 2020, and a $17.3 million increase in TGP expense and the timing of receivable collections between periods.

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Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $251.5 million during the six months ended June 30, 2021 to $643.0 million from $391.5 million during the six months ended June 30, 2020. The increase was primarily due to the factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of assets and liabilities. Adjusted free cash flow, a non-U.S. GAAP financial measure, increased by $330.6 million during the six months ended June 30, 2021 to $341.4 million compared to $10.8 million during the six months ended June 30, 2020. The increase between periods was primarily due to the increase in cash flows from operating activities, as discussed above, and a decrease in capital investments in crude oil and natural gas properties.

See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.

Investing Activities. As crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments.

Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $236.1 million during the six months ended June 30, 2021 was primarily related to our drilling and completion activities of $240.3 million, partially offset by $4.4 million in proceeds from the sale of certain properties and equipment. Net cash used in investing activities of $528.2 million during the six months ended June 30, 2020 was primarily related to our drilling and completion activities of $387.9 million and $139.8 million related to the closing of the SRC Acquisition.

Financing Activities. Net cash used in financing activities of $234.1 million during the six months ended June 30, 2021 was primarily due to net repayments to our credit facility of $168.0 million, the repurchase and retirement of 1.3 million shares of our common stock totaling to $47.7 million pursuant to our Stock Repurchase Program and dividend payments totaling $11.9 million. Repurchases of our common stock may extend into 2023 based on current market conditions, although the board of directors could elect to suspend or terminate the program at any time, including if certain share price parameters are not achieved. As of June 30, 2021, $298.2 million out of the approved $525 million remained available for repurchases under the program. Further, during the second quarter of 2021, our board of directors declared and paid our first cash dividend of $0.12 per common share. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and depend on our level of earnings, financial requirements, and other factors considered relevant by our board.

Net cash used in financing activities of $159.2 million during the six months ended June 30, 2020 was primarily due to net borrowings from our credit facility of $649.0 million, partially offset by the redemption of a portion of the 2025 Senior Notes totaling $452.2 million and the repurchase and retirement of 1.3 million shares of our common stock totaling $23.8 million pursuant to our Stock Repurchase Program.

Subsidiary Guarantor

PDC Permian, Inc., a Delaware corporation (the “Guarantor”), our wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes, 2025 Senior Notes and 2026 Senior Notes (collectively, the “Senior Notes”) and our 2021 Convertible Notes. The Guarantor holds our assets located in the Delaware Basin. The Senior Notes and 2021 Convertible Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantees are subject to release in limited circumstances only upon the occurrence of certain customary conditions.

The indentures governing the Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (i) incur additional debt including under our revolving credit facility, (ii) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (ii) sell assets, including capital stock of our restricted subsidiaries, (iv) restrict the payment of dividends or other payments by restricted subsidiaries to us, (v) create liens that secure debt, (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company.

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PDC ENERGY, INC.

The following summarized subsidiary guarantor financial information has been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method.


	As of/Six Months Ended				As of/Year Ended
	June 30, 2021				December 31, 2020
	Issuer		Guarantor		Issuer		Guarantor
	(in millions)
Assets
Current assets	$	385.5	$	(0.3)	$	271.4	$	(57.8)
Intercompany accounts receivable, guarantor subsidiary	57.4		—		107.3		—
Investment in guarantor subsidiary	1,767.2		—		1,767.2		—
Properties and equipment, net	3,917.2		929.5		3,982.1		877.1
Other non-current assets	44.0		4.6		56.6		4.3

Liabilities
Current liabilities	$	1,077.0	$	85.2	$	751.3	$	28.5
Intercompany accounts payable	—		44.0		—		94.2
Long-term debt	1,242.7		—		1,409.5		—
Other non-current liabilities	289.0		175.4		254.9		178.1

Statement of Operations
Crude oil, natural gas and NGLs sales	$	860.5	$	140.8	$	968.8	$	183.7
Commodity price risk management gain (loss), net	(489.5)		—		180.3		—
Total revenues	372.5		142.4		1,151.5		182.5
Production costs	147.4		41.0		227.0		71.6
Gross profit	713.1		99.8		741.8		112.1
Impairment of properties and equipment	0.3		—		2.0		880.4
Net income (loss)	(152.4)		56.3		(49.2)		(670.0)

Off-Balance Sheet Arrangements

At June 30, 2021, we had no off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital investments or capital resources.

Contractual Obligations

Since December 31, 2020, there have not been any significant, non-routine changes in our contractual obligations. See Note 11 - Commitments and Contingencies to the accompanying condensed consolidated financial statements included elsewhere in this report.

Recent Accounting Standards

There were no significant new accounting standards adopted or new accounting pronouncements that would have potential effect on us as of June 30, 2021.

Critical Accounting Policies and Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with U.S. GAAP required management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenue and expenses.

There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the consolidated financial statements and accompanying notes contained in our 2020 Form 10-K filed with the SEC on February 25, 2021.

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Reconciliation of Non-U.S. GAAP Financial Measures

We use “adjusted cash flows from operations”, “adjusted free cash flow (deficit)”, “adjusted net income (loss)” and “adjusted EBITDAX”, non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure.

Adjusted cash flows from operations and adjusted free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe adjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities and to return capital to stockholders in the period in which the related transactions occurred. We exclude from this measure cash receipts and expenditures related to acquisitions and divestitures of oil and gas properties and capital expenditures for other properties and equipment, which are not reflective of the cash generated or used by ongoing activities on our existing producing properties and, in the case of acquisitions and divestitures, may be evaluated separately in terms of their impact on our performance and liquidity. Adjusted free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from the adjusted free cash flow measure.

We are unable to present a reconciliation of forward-looking adjusted cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of adjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations.

Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance.

Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development and acquisitions and to service our debt obligations.

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PDC ENERGY, INC.

The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(in millions)
Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow:
Net cash from operating activities	$	224.3	$	103.0	$	577.4	$	369.3
Changes in assets and liabilities	118.7		78.7		65.6		22.2
Adjusted cash flows from operations	343.0		181.7		643.0		391.5
Capital expenditures for development of crude oil and natural gas properties	(131.2)		(197.1)		(240.3)		(387.9)
Change in accounts payable related to capital expenditures for oil and gas development activities	(45.9)		77.2		(61.3)		7.2
Adjusted free cash flow	$	165.9	$	61.8	$	341.4	$	10.8

Net income (loss) to adjusted net income (loss):
Net income (loss)	$	(87.0)	$	(221.8)	$	(96.1)	$	(686.8)
Loss (gain) on commodity derivative instruments	308.3		120.8		489.5		(313.9)
Net settlements on commodity derivative instruments	(55.1)		114.8		(85.8)		160.6
Tax effect of above adjustments (1)	—		—		—		—
Adjusted net income (loss)	$	166.2	$	13.8	$	307.6	$	(840.1)

Net income (loss) to adjusted EBITDAX:
Net income (loss)	$	(87.0)	$	(221.8)	$	(96.1)	$	(686.8)
Loss (gain) on commodity derivative instruments	308.3		120.8		489.5		(313.9)
Net settlements on commodity derivative instruments	(55.1)		114.8		(85.8)		160.6
Non-cash stock-based compensation	6.5		6.4		11.5		12.0
Interest expense, net	20.1		21.8		39.1		46.0
Income tax expense (benefit)	(0.2)		4.1		(0.1)		(3.7)
Impairment of properties and equipment	0.1		—		0.3		881.1
Exploration, geologic and geophysical expense	0.3		0.7		0.6		0.9
Depreciation, depletion and amortization	162.2		149.5		309.0		325.6
Accretion of asset retirement obligations	3.2		2.4		6.4		5.0
Loss (gain) on sale of properties and equipment	(0.1)		(0.2)		(0.3)		(0.4)
Adjusted EBITDAX	$	358.3	$	198.5	$	674.1	$	426.4

Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities	$	224.3	$	103.0	$	577.4	$	369.3
Interest expense, net	20.1		21.8		39.1		46.0
Amortization and write-off of debt discount, premium and issuance costs	(3.9)		(5.3)		(7.7)		(8.9)
Exploration, geologic and geophysical expense	0.3		0.7		0.6		0.9
Other	(1.2)		(0.4)		(0.9)		(3.1)
Changes in assets and liabilities	118.7		78.7		65.6		22.2
Adjusted EBITDAX	$	358.3	$	198.5	$	674.1	$	426.4

_____________

(1)Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the three and six months ended June 30, 2021 and 2020.

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PDC ENERGY, INC.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market-Sensitive Instruments and Risk Management

We are exposed to market risks associated with interest rates, commodity price and credit risks. We have established risk management processes to monitor and manage these market risks.

Interest Rate Risk

Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes and Senior Notes have fixed rates, and therefore near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.

As of June 30, 2021, we had no outstanding balance on our revolving credit facility.

Commodity Price Risk

We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, natural gas basis and NGLs. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives.

Based on a sensitivity analysis as of June 30, 2021, we estimate that a ten percent increase in natural gas, crude oil prices and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives in place, would have resulted in an increase in the fair value of our net derivative liabilities of $84.1 million, whereas a ten percent decrease in prices would have resulted in a decrease in fair value of our net derivative liabilities of $82.3 million. The potential increase in the fair value of our net derivative liabilities would be recorded in statements of operations as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.

Credit Risk

Credit risk represents the loss that we would incur if a counterparty fails to perform its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure. When exposed to significant credit risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties.

We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments.

Our crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

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PDC ENERGY, INC.

Disclosure of Limitations

Because the information above included only those exposures that existed at June 30, 2021, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time.

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PDC ENERGY, INC.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of June 30, 2021, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2021.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

Information regarding our legal proceedings can be found in Note 11 - Commitments and Contingencies to our condensed consolidated financial statements included elsewhere in this report.

RISK FACTORS

We face many risks. Each of these risk factors could adversely affect our business, operating results and financial condition as well as the value of an investment in our common stock are described under Item 1A, Risk Factors, of our 2020 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

There have been no material changes from the risk factors previously disclosed in our 2020 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table presents information about our purchases of our common stock during the three months ended June 30, 2021:


Period	Total Number of Shares Purchased (1) (2)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions)
April	345,614	$	35.36	255,268	$	315.7
May	211,555	40.14		210,310	307.3
June	201,576	46.39		196,070	298.2
Total second quarter 2021 purchases	758,745	40.09		661,648	298.2

_____________

(1)In April 2019, our board of directors approved a program to acquire up to $200 million of our outstanding common stock and in August 2019, effective with the closing of the SRC Acquisition, increased such amount to $525 million (the “Stock Repurchase Program”). The Stock Repurchase Program does not require any specific number of shares to be acquired and can be modified or discontinued by our board of directors at any time. We reinstated our Stock Repurchase Program in late February 2021. Repurchases may extend until December 31, 2023.

(2)Purchases outside of the Stock Repurchase Program represent shares withheld from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. The withheld shares are not considered common stock repurchased under the Stock Repurchase Program.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES - None.

ITEM 4. MINE SAFETY DISCLOSURES - Not applicable.

ITEM 5. OTHER INFORMATION - None.

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PDC ENERGY, INC.

ITEM 6. EXHIBITS

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Securities guaranteed by PDC Permian, Inc., a subsidiary guarantor of PDC Energy, Inc.

31.1

Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*

Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

104

Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

* Furnished herewith.

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PDC ENERGY, INC.

SIGNATURES

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, thereunto duly authorized.


			PDC Energy, Inc.
			(Registrant)




Date: August 4, 2021			/s/ Barton Brookman
			Barton Brookman
			President and Chief Executive Officer
			(principal executive officer)

			/s/ R. Scott Meyers
			R. Scott Meyers
			Senior Vice President and Chief Financial Officer
			(principal financial officer)