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 ~~March 31,~~June 30, 2022

☐ 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

Trading Symbol(s)

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 ☒ No ☐

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 ☒ No ☐

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	☒	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 ☒

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: ~~95,429,367~~96,307,108 shares of the Company's Common Stock ($0.01 par value) were outstanding as of ~~April~~July 26, 2022.

~~Table of contents~~

PDC ENERGY, INC.

TABLE OF CONTENTS


	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	56
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2123
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4143
Item 4.	Controls and Procedures	4345

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	4446
Item 1A.	Risk Factors	4447
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4547
Item 3.	Defaults Upon Senior Securities	4547
Item 4.	Mine Safety Disclosures	4547
Item 5.	Other Information	4547
Item 6.	Exhibits	4648

	Signatures	4749

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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, the pending acquisition of Great Western Petroleum, LLC (“Great Western”) and the effects thereof, including but not limited to, an anticipated increase in our capital investment budget and the redemption of Great Western’s 12% Senior Notes due September 2025; the expected timing of the acquisition of Great Western~~and the possibility that the acquisition will not close;~~ statements regarding future production, costs and cash flows; impacts from the acquisition and integration of Great Western, including changes in results of operations, production volumes and costs per Boe, DD&A per Boe, general and administrative expenses, and interest expense in the second half of 2022; 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 return of capital to shareholders through buybacks of shares and/or payments of dividends; ongoing compliance with our legacy PDC consent ~~decree;~~decree and Great Western’s compliance order on consent; expected impact from emission reduction initiatives; risk of our ~~counterparties~~counterparties’ non-performance on derivative instruments; tax matters; 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 decreased availability of capital;

•difficulties in integrating our operations as a result of any significant acquisitions, including the ~~pending~~ acquisition of Great Western Petroleum, LLC (“Great Western”), or acreage exchanges;

•adverse changes to our future cash flows, liquidity and financial condition;

•changes in, and interpretations and enforcement of, environmental and other laws and other political and regulatory developments, 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;

•limitations in the availability of supplies, materials, contractors and services that may delay the drilling or

completion of our wells;

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

~~Table of contents~~

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

•effect of crude oil and natural gas derivative activities;

Table of contents

•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 or share buybacks;

•timing and amounts of federal and state income taxes;

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

•~~a failure to complete the acquisition of Great Western or~~ an unanticipated assumption of liabilities or other problems with the ~~acquisition;~~Great Western acquisition or other acquisitions we may pursue;

•civil unrest, terrorist attacks and cyber threats;

•risks associated with recent inflationary trends and the potential for a recession; 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, 2021 (“2021 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)


		March 31, 2022		December 31, 2021			June 30, 2022		December 31, 2021
Assets	Assets					Assets
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	171,157	$	33,829	Cash and cash equivalents	$	38,528	$	33,829
Accounts receivable, net	Accounts receivable, net	537,056		398,605		Accounts receivable, net	723,415		398,605
Fair value of derivatives	Fair value of derivatives	13,158		17,909		Fair value of derivatives	14,643		17,909
Prepaid expenses and other current assets	Prepaid expenses and other current assets	12,191		8,230		Prepaid expenses and other current assets	11,726		8,230
Total current assets	Total current assets	733,562		458,573		Total current assets	788,312		458,573
Properties and equipment, net	Properties and equipment, net	4,886,264		4,814,865		Properties and equipment, net	7,087,772		4,814,865
Fair value of derivatives	Fair value of derivatives	19,956		15,177		Fair value of derivatives	26,967		15,177
Other assets	Other assets	91,582		48,051		Other assets	73,190		48,051
Total Assets	Total Assets	$	5,731,364	$	5,336,666	Total Assets	$	7,976,241	$	5,336,666

Liabilities and Stockholders’ Equity	Liabilities and Stockholders’ Equity					Liabilities and Stockholders’ Equity
Liabilities	Liabilities					Liabilities
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	192,268	$	127,891	Accounts payable	$	285,414	$	127,891
Production tax liability	Production tax liability	112,348		99,583		Production tax liability	242,653		99,583
Fair value of derivatives	Fair value of derivatives	572,636		304,870		Fair value of derivatives	702,329		304,870
Funds held for distribution	Funds held for distribution	302,649		285,861		Funds held for distribution	548,185		285,861
Accrued interest payable	Accrued interest payable	18,251		10,482		Accrued interest payable	14,683		10,482
Other accrued expenses	Other accrued expenses	77,130		91,409		Other accrued expenses	85,021		91,409
Total current liabilities	Total current liabilities	1,275,282		920,096		Total current liabilities	1,878,285		920,096
Long-term debt	Long-term debt	942,565		942,084		Long-term debt	1,698,047		942,084
Asset retirement obligations	Asset retirement obligations	123,856		127,526		Asset retirement obligations	146,020		127,526
Fair value of derivatives	Fair value of derivatives	234,284		95,561		Fair value of derivatives	235,630		95,561
Deferred income taxes	Deferred income taxes	29,983		26,383		Deferred income taxes	186,383		26,383
Other liabilities	Other liabilities	360,643		314,769		Other liabilities	361,155		314,769
Total liabilities	Total liabilities	2,966,613		2,426,419		Total liabilities	4,505,520		2,426,419

Commitments and contingent liabilities	Commitments and contingent liabilities					Commitments and contingent liabilities

Stockholders’ equity	Stockholders’ equity					Stockholders’ equity
Common shares - par value $0.01 per share, 150,000,000 authorized, 95,749,823 and 96,468,071 issued as of March 31, 2022 and December 31, 2021, respectively		957		965
Common shares - par value $0.01 per share, 150,000,000 authorized, 97,047,329 and 96,468,071 issued as of June 30, 2022 and December 31, 2021, respectively						Common shares - par value $0.01 per share, 150,000,000 authorized, 97,047,329 and 96,468,071 issued as of June 30, 2022 and December 31, 2021, respectively	970		965
Additional paid-in capital	Additional paid-in capital	3,052,741		3,161,941		Additional paid-in capital	3,096,523		3,161,941
Accumulated deficit		(281,914)		(249,954)
Treasury shares - at cost, 105,002 and 54,960 as of March 31, 2022 and December 31, 2021, respectively		(7,033)		(2,705)
Retained earnings (accumulated deficit)						Retained earnings (accumulated deficit)	380,467		(249,954)
Treasury shares - at cost, 120,143 and 54,960 as of June 30, 2022 and December 31, 2021, respectively						Treasury shares - at cost, 120,143 and 54,960 as of June 30, 2022 and December 31, 2021, respectively	(7,239)		(2,705)
Total stockholders’ equity	Total stockholders’ equity	2,764,751		2,910,247		Total stockholders’ equity	3,470,721		2,910,247
Total Liabilities and Stockholders’ Equity	Total Liabilities and Stockholders’ Equity	$	5,731,364	$	5,336,666	Total Liabilities and Stockholders’ Equity	$	7,976,241	$	5,336,666

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 March 31,					Three Months Ended June 30,				Six Months Ended June 30,
			2022		2021				2022		2021		2022		2021
Revenues	Revenues							Revenues
Crude oil, natural gas and NGLs sales	Crude oil, natural gas and NGLs sales		$	882,378	$	468,119		Crude oil, natural gas and NGLs sales	$	1,237,680	$	533,141	$	2,120,058	$	1,001,260
Commodity price risk management gain (loss), net	Commodity price risk management gain (loss), net		(568,055)		(181,256)			Commodity price risk management gain (loss), net	(101,976)		(308,253)		(670,031)		(489,509)
Other income	Other income		2,125		(827)			Other income	2,787		3,981		4,912		3,154
Total revenues	Total revenues		316,448		286,036			Total revenues	1,138,491		228,869		1,454,939		514,905
Costs, expenses and other	Costs, expenses and other							Costs, expenses and other
Lease operating expense	Lease operating expense		54,156		41,804			Lease operating expense	70,611		42,395		124,767		84,199
Production taxes	Production taxes		62,916		29,492			Production taxes	89,251		26,968		152,167		56,460
Transportation, gathering and processing expense	Transportation, gathering and processing expense		27,971		21,732			Transportation, gathering and processing expense	29,584		25,989		57,555		47,721
Exploration, geologic and geophysical expense	Exploration, geologic and geophysical expense		253		354			Exploration, geologic and geophysical expense	320		286		573		640
General and administrative expense	General and administrative expense		34,107		32,677			General and administrative expense	45,649		32,843		79,756		65,520
Depreciation, depletion and amortization	Depreciation, depletion and amortization		151,055		146,763			Depreciation, depletion and amortization	191,061		162,210		342,116		308,973
Accretion of asset retirement obligations	Accretion of asset retirement obligations		2,987		3,128			Accretion of asset retirement obligations	3,352		3,232		6,339		6,360
Impairment of properties and equipment	Impairment of properties and equipment		943		190			Impairment of properties and equipment	510		62		1,453		252
Loss (gain) on sale of properties and equipment	Loss (gain) on sale of properties and equipment		(125)		(212)			Loss (gain) on sale of properties and equipment	498		(129)		373		(341)
Other expense	Other expense		—		48			Other expense	—		2,145		—		2,193
Total costs, expenses and other	Total costs, expenses and other		334,263		275,976			Total costs, expenses and other	430,836		296,001		765,099		571,977
Income (loss) from operations	Income (loss) from operations		(17,815)		10,060			Income (loss) from operations	707,655		(67,132)		689,840		(57,072)
Interest expense, net	Interest expense, net		(12,945)		(19,041)			Interest expense, net	(17,565)		(20,060)		(30,510)		(39,101)
Gain on bargain purchase								Gain on bargain purchase	100,273		—		100,273		—
Income (loss) before income taxes	Income (loss) before income taxes		(30,760)		(8,981)			Income (loss) before income taxes	790,363		(87,192)		759,603		(96,173)
Income tax benefit (expense)	Income tax benefit (expense)		(1,200)		(55)			Income tax benefit (expense)	(127,982)		155		(129,182)		100
Net income (loss)	Net income (loss)		$	(31,960)	$	(9,036)		Net income (loss)	$	662,381	$	(87,037)	$	630,421	$	(96,073)

Earnings (loss) per share:	Earnings (loss) per share:							Earnings (loss) per share:
Basic	Basic		$	(0.33)	$	(0.09)		Basic	$	6.83	$	(0.88)	$	6.52	$	(0.97)
Diluted	Diluted		$	(0.33)	$	(0.09)		Diluted	$	6.74	$	(0.88)	$	6.42	$	(0.97)

Weighted average common shares outstanding:	Weighted average common shares outstanding:							Weighted average common shares outstanding:
Basic	Basic		96,279		99,702			Basic	96,982		99,187		96,632		99,445
Diluted	Diluted		96,279		99,702			Diluted	98,246		99,187		98,150		99,445

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)


		Three Months Ended March 31,					Six Months Ended June 30,
		2022		2021			2022		2021
Cash flows from operating activities:	Cash flows from operating activities:					Cash flows from operating activities:
Net income (loss)	Net income (loss)	$	(31,960)	$	(9,036)	Net income (loss)	$	630,421	$	(96,073)
Adjustments to net income (loss) to reconcile to net cash from operating activities:	Adjustments to net income (loss) to reconcile to net cash from operating activities:					Adjustments to net income (loss) to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives	Net change in fair value of unsettled commodity derivatives	406,461		150,606		Net change in fair value of unsettled commodity derivatives	209,777		403,723
Depreciation, depletion and amortization	Depreciation, depletion and amortization	151,055		146,763		Depreciation, depletion and amortization	342,116		308,973
Impairment of properties and equipment	Impairment of properties and equipment	943		190		Impairment of properties and equipment	1,453		252
Accretion of asset retirement obligations	Accretion of asset retirement obligations	2,987		3,128		Accretion of asset retirement obligations	6,339		6,360
Non-cash stock-based compensation	Non-cash stock-based compensation	5,474		5,020		Non-cash stock-based compensation	12,770		11,515
(Gain) loss on sale of properties and equipment	(Gain) loss on sale of properties and equipment	(125)		(212)		(Gain) loss on sale of properties and equipment	373		(341)
Amortization of debt discount, premium and issuance costs	Amortization of debt discount, premium and issuance costs	1,357		3,837		Amortization of debt discount, premium and issuance costs	2,715		7,714
Deferred income taxes	Deferred income taxes	3,600		—		Deferred income taxes	128,481		—
Gain on bargain purchase						Gain on bargain purchase	(100,273)		—
Other	Other	(905)		(305)		Other	(700)		875
Changes in assets and liabilities	Changes in assets and liabilities	(49,839)		53,068		Changes in assets and liabilities	2,909		(65,632)
Net cash from operating activities	Net cash from operating activities	489,048		353,059		Net cash from operating activities	1,236,381		577,366
Cash flows from investing activities:	Cash flows from investing activities:					Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	Capital expenditures for development of crude oil and natural gas properties	(187,021)		(109,048)		Capital expenditures for development of crude oil and natural gas properties	(533,592)		(240,266)
Capital expenditures for midstream assets						Capital expenditures for midstream assets	(3,015)		—
Capital expenditures for other properties and equipment	Capital expenditures for other properties and equipment	(67)		(69)		Capital expenditures for other properties and equipment	(2,537)		(274)

Cash paid for acquisition of an exploration and production business						Cash paid for acquisition of an exploration and production business	(1,068,241)		—
Proceeds from sale of properties and equipment	Proceeds from sale of properties and equipment	89		4,370		Proceeds from sale of properties and equipment	461		4,414
Proceeds from divestitures	Proceeds from divestitures	465		—		Proceeds from divestitures	465		—
Funds held in escrow for acquisition		(50,000)		—

Net cash from investing activities	Net cash from investing activities	(236,534)		(104,747)		Net cash from investing activities	(1,606,459)		(236,126)
Cash flows from financing activities:	Cash flows from financing activities:					Cash flows from financing activities:
Proceeds from revolving credit facility and other borrowings	Proceeds from revolving credit facility and other borrowings	100,500		229,000		Proceeds from revolving credit facility and other borrowings	1,372,000		429,800
Repayment of revolving credit facility and other borrowings	Repayment of revolving credit facility and other borrowings	(100,500)		(397,000)		Repayment of revolving credit facility and other borrowings	(617,000)		(597,800)

Payment of debt issuance costs	Payment of debt issuance costs	(30)		—		Payment of debt issuance costs	(47)		—
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	Purchase of treasury shares for employee stock-based compensation tax withholding obligations	(9,203)		(2,356)		Purchase of treasury shares for employee stock-based compensation tax withholding obligations	(16,860)		(5,656)
Purchase of treasury shares under stock repurchase program	Purchase of treasury shares under stock repurchase program	(80,853)		(21,067)		Purchase of treasury shares under stock repurchase program	(295,005)		(47,694)
Dividends paid	Dividends paid	(24,681)		—		Dividends paid	(59,219)		(11,885)
Principal payments under financing lease obligations	Principal payments under financing lease obligations	(419)		(445)		Principal payments under financing lease obligations	(962)		(879)
Net cash from financing activities	Net cash from financing activities	(115,186)		(191,868)		Net cash from financing activities	382,907		(234,114)
Net change in cash and cash equivalents	Net change in cash and cash equivalents	137,328		56,444		Net change in cash and cash equivalents	12,829		107,126
Cash and cash equivalents, beginning of period		33,829		2,623
Cash and cash equivalents, end of period		$	171,157	$	59,067
Cash, cash equivalents and restricted cash, beginning of period						Cash, cash equivalents and restricted cash, beginning of period	33,829		2,623
Cash, cash equivalents and restricted cash, end of period						Cash, cash equivalents and restricted cash, end of period	$	46,658	$	109,749

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Stockholders’ Equity

(in ~~thousands)~~thousands, except dividends per share)

(Unaudited)


		Three Months Ended March 31, 2022																					Six Months Ended June 30, 2022
		Common Stock			Additional Paid-in Capital				Treasury Stock						Accumulated Deficit					Total Stockholders’ Equity			Common Stock								Additional Paid-in Capital		Treasury Stock				Retained Earnings (Accumulated Deficit)		Total Stockholders’ Equity
		Shares	Amount				Shares			Amount									Shares					Amount					Shares				Amount
Balance, January 1, 2022	Balance, January 1, 2022	96,468	$	965			$	3,161,941		(55)			$	(2,705)			$	(249,954)					$	2,910,247	Balance, January 1, 2022	96,468				$		965	$	3,161,941	(55)		$	(2,705)	$	(249,954)	$	2,910,247
Net loss		—	—		—				—		—				(31,960)					(31,960)
Net income (loss)																						Net income (loss)	—				—				—		—		—		(31,960)		(31,960)
Stock-based compensation	Stock-based compensation	655	7		1,798				—		3,669				—					5,474		Stock-based compensation	655				7				1,798		—		3,669		—		5,474
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—				(164)		(9,203)				—					(9,203)		Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—				—				—		(164)		(9,203)		—		(9,203)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(53)	(2)		(3,022)				53		3,024				—					—		Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(53)				(2)				(3,022)		53		3,024		—		—
Retirement of treasury shares	Retirement of treasury shares	(1,320)	(13)		(83,508)				1,320		83,521				—					—		Retirement of treasury shares	(1,320)				(13)				(83,508)		1,320		83,521		—		—
Issuance of treasury shares	Issuance of treasury shares	—	—		—				67		—				—					—		Issuance of treasury shares	—				—				—		67		—		—		—
Purchase of treasury shares under stock repurchase program	Purchase of treasury shares under stock repurchase program	—	—		—				(1,326)		(85,339)				—					(85,339)		Purchase of treasury shares under stock repurchase program	—				—				—		(1,326)		(85,339)		—		(85,339)
Dividends declared ($0.25 per share)	Dividends declared ($0.25 per share)	—	—		(24,468)				—		—				—					(24,468)		Dividends declared ($0.25 per share)	—				—				(24,468)		—		—		—		(24,468)
Balance, March 31, 2022	Balance, March 31, 2022	95,750	$	957	$	3,052,741			(105)		$	(7,033)			$	(281,914)				$	2,764,751	Balance, March 31, 2022	95,750				957				3,052,741		(105)		(7,033)		(281,914)		2,764,751
Net income (loss)																						Net income (loss)	—				—				—		—		—		662,381		662,381
Issuance of stock pursuant to acquisition																						Issuance of stock pursuant to acquisition	4,007				40				293,274		—		—		—		293,314
Stock-based compensation																						Stock-based compensation	337				3				6,924		—		369		—		7,296
Purchase of treasury shares for employee stock-based compensation tax withholding obligations																						Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—				—				—		(101)		(7,657)		—		(7,657)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations																						Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(101)				(1)				(7,635)		101		7,636		—		—
Retirement of treasury shares																						Retirement of treasury shares	(2,946)				(29)				(214,123)		2,946		214,152		—		—
Issuance of treasury shares																						Issuance of treasury shares	—				—				—		5		—		—		—
Purchase of treasury shares under stock repurchase program																						Purchase of treasury shares under stock repurchase program	—				—				—		(2,966)		(214,706)		—		(214,706)
Dividends declared ($0.35 per share)																						Dividends declared ($0.35 per share)	—				—				(34,658)		—		—		—		(34,658)
Balance, June 30, 2022																						Balance, June 30, 2022	97,047				$	970			$	3,096,523	(120)		$	(7,239)	$	380,467	$	3,470,721

Three Months Ended March 31, 2021
Common Stock Additional Paid-in Capital Treasury Stock Accumulated Deficit Total Stockholders’ Equity
Shares Amount Shares Amount
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

See accompanying Notes to Condensed Consolidated Financial Statements

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	Six Months Ended June 30, 2021
	Common Stock			Additional Paid-in Capital		Treasury Stock			Accumulated Deficit		Total Stockholders’ Equity
	Shares	Amount				Shares	Amount
Balance, January 1, 2021	99,759	$	998	$	3,387,754	(38)	$	(949)	$	(772,265)	$	2,615,538
Net income (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 income (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	—	—		—		(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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~March 31,~~June 30, 2022

(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 ~~March 31,~~June 30, 2022, we owned an interest in approximately ~~3,450~~4,200 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, 2021 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 2021 Form 10-K. Our results of operations and cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2022 are not necessarily indicative of the results to be expected for the full year or any other future period.

NOTE 2 - ~~PENDING ACQUISITION~~

BUSINESS COMBINATION

On ~~February 26,~~May 6, 2022, we ~~entered into a definitive purchase agreement under which we will acquire~~completed the acquisition of Great Western Petroleum, LLC (“Great Western”), for approximately $1.4 billion, inclusive of Great Western’s net debt (the “Great Western Acquisition”). Great Western iswas an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in the Wattenberg Field of Colorado. The ~~purchase~~ consideration ~~for the Great Western Acquisition will be made through the transfer of~~paid was $542.5 million in cash and approximately ~~4.0~~$4.0 million shares of our common stock, valued at $293.3 million on the acquisition date. In addition, we paid off the Great Western secured credit facility totaling $235.8 million and ~~approximately $543~~irrevocably deposited $361.2 million inon Great Western’s behalf to pay and discharge on May 20, 2022 Great Western’s 12 percent senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. The cash ~~pursuant~~portion of the purchase price and the termination of Great Western’s debt were funded through a combination of cash on hand and availability under our revolving credit facility.

Purchase Price Allocation

The Great Western Acquisition has been accounted for using the acquisition method under Accounting Standards Codification (“ASC”) 805, Business Combinations, with PDC being treated as the accounting acquirer. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values, while transaction and integration costs associated with the acquisition were expensed as incurred.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2022

(Unaudited)

The following table presents our preliminary allocation of the total purchase price of Great Western to the ~~Membership Interest Purchase Agreement~~identifiable assets acquired and liabilities assumed based on the fair values as of the acquisition date:


	(in thousands, except share and per share data)
Consideration:
Cash	$	542,500
Retirement of Great Western’s credit facility	235,822
Extinguishment of Great Western’s secured senior notes	361,231
Total cash consideration	1,139,553

Common stock issued	4,007,018
Fair value of PDC common stock on May 6, 2022	$	73.20
Total fair value of common stock issued	293,314

Total consideration	$	1,432,867

Assets acquired:
Cash	$	63,183
Accounts receivable	164,433
Other current assets	3,684
Properties and equipment, net - proved	2,088,927

Properties and equipment, net - other	7,035
Other noncurrent assets	21,888
Total assets acquired	$	2,349,150

Liabilities assumed:
Accounts payable	$	(131,376)
Production tax liability	(110,940)
Funds held for distribution	(162,945)
Other current liabilities	(3,903)
Fair value of derivatives	(319,600)
Asset retirement obligations	(22,926)
Deferred tax liabilities	(31,518)
Other liabilities	(32,802)
Total liabilities assumed	(816,010)

Total identifiable net assets acquired	$	1,533,140
Gain on bargain purchase	100,273
Purchase price consideration	$	1,432,867

Determining the fair values of the assets and liabilities of Great Western requires judgement and certain assumptions to be made, the most significant of these being related to the valuation of crude oil and natural gas properties. The majority of the 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 14.25 percent. These inputs require significant judgments and estimates by management at the time of the valuation. Due to this, the final purchase price allocation is considered an ongoing process and we anticipate the measurement period may extend into the fourth quarter of 2022.

ASC 805, Business Combinations, requires that any excess of purchase price over the fair value of assets acquired, including identifiable intangibles and liabilities assumed, be recognized as goodwill and any excess of fair value of acquired net

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2022

(Unaudited)

assets, including identifiable intangible assets over the acquisition consideration, results in a gain from bargain purchase. Prior to recording a gain, the acquiring entity must reassess whether all assets acquired and assumed liabilities have been identified and recognized and perform re-measurements to verify that the consideration paid, assets acquired and liabilities assumed have been properly valued. The Great Western Acquisition resulted in a gain on bargain purchase due to the estimated fair value of the identifiable net assets acquired exceeding the purchase consideration transferred by $100.3 million and is shown as a gain on bargain purchase on our condensed consolidated statement of operations, net of related income taxes of $31.5 million. Upon completion of our assessment, we concluded that recording a gain on bargain purchase was appropriate and required under ASC 805. The bargain purchase was primarily attributable to the increase in commodity price forecasts from the date we entered into the definitive purchase agreement with Great Western, (“February 26, 2022, to the closing date of the acquisition, May 6, 2022, when the fair value of crude oil and natural gas reserves acquired were determined. Additionally, the majority of the acquisition consideration was fixed and therefore did not fluctuate in the event of market increases or decreases between the date of entry into the agreement through the closing date.

The results of operations for the Great Western Acquisition ~~Agreement”). In February~~since the closing date have been included on our condensed consolidated financial statements for the three and six months ended June 30, 2022 and include approximately $191.0 million of total revenue and $133.3 million of income from operations. During the three and six months ended June 30, 2022, we ~~deposited $50.0~~recognized total transaction costs of $10.6 million, ~~into an escrow account pursuant to the terms of the Acquisition Agreement, recognized as other assets~~which are included in general and administrative expense on the condensed consolidated ~~balance sheet. We anticipate~~statement of operations.

Pro Forma Information. The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for the three and six months ended June 30, 2022, assuming the acquisition had been completed as of January 1, 2021. 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.

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) our common stock issued to the owners of Great Western, ~~Acquisition will be completed~~(ii) the increase in ~~May~~depletion reflecting the relative fair values and production volumes attributable to Great Western’s properties and the revision to the depletion rate reflecting the reserve volumes acquired, (iii) adjustments to interest expense as a result of payoff of Great Western’s credit facility and secured senior notes, (iv) the adjustment to reflect the gain on bargain purchase, and (v) the estimated tax impacts of the pro forma adjustments. In addition, pro forma earnings were adjusted to exclude acquisition-related costs incurred by us and Great Western totaling approximately $25.3 million and $28.5 million for the three and six months ended June 30, 2022, ~~subject to certain customary closing conditions being met.~~respectively, and included the total costs of $28.5 million for the six months ended June 30, 2021.


	Three months ended June 30				Six months ended June 30
	2022		2021		2022		2021
	(in thousands, except per share data)
Total revenue	$	1,154,220	$	254,588	$	1,506,567	$	618,988
Net income (loss)	574,887		(160,895)		491,127		(121,460)

Earnings (loss) per share:
Basic	$	5.83	$	(1.56)	$	4.94	$	(1.17)
Diluted	5.76		(1.56)		4.87		(1.17)

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~March 31,~~June 30, 2022

(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 March 31,					Three Months Ended June 30,						Six Months Ended June 30,
Revenue by Commodity and Operating Region	Revenue by Commodity and Operating Region		2022		2021			Percent Change		Revenue by Commodity and Operating Region	2022		2021		Percent Change		2022		2021		Percent Change
			(in thousands)								(in thousands)
Crude oil	Crude oil									Crude oil
Wattenberg Field	Wattenberg Field		$	451,911	$	235,963		92	%	Wattenberg Field	$	599,162	$	291,551	106	%	$	1,051,073	$	527,514	99	%
Delaware Basin	Delaware Basin		97,838		37,688			160	%	Delaware Basin	141,671		59,148		140	%	239,509		96,836		147	%
Total	Total		549,749		273,651			101	%	Total	$	740,833	$	350,699	111	%	1,290,582		624,350		107	%
Natural gas	Natural gas									Natural gas
Wattenberg Field	Wattenberg Field		143,699		97,022			48	%	Wattenberg Field	$	237,713	$	74,664	218	%	381,412		171,686		122	%
Delaware Basin	Delaware Basin		19,425		8,624			125	%	Delaware Basin	40,004		11,139		259	%	59,429		19,763		201	%
Total	Total		163,124		105,646			54	%	Total	$	277,717	$	85,803	224	%	440,841		191,449		130	%
NGLs	NGLs									NGLs
Wattenberg Field	Wattenberg Field		138,875		77,777			79	%	Wattenberg Field	$	181,552	$	83,505	117	%	320,427		161,282		99	%
Delaware Basin	Delaware Basin		30,630		11,045			177	%	Delaware Basin	37,578		13,134		186	%	68,208		24,179		182	%
Total	Total		169,505		88,822			91	%	Total	$	219,130	$	96,639	127	%	388,635		185,461		110	%
Crude oil, natural gas and NGLs	Crude oil, natural gas and NGLs									Crude oil, natural gas and NGLs
Wattenberg Field	Wattenberg Field		734,485		410,762			79	%	Wattenberg Field	$	1,018,427	$	449,720	126	%	1,752,912		860,482		104	%
Delaware Basin	Delaware Basin		147,893		57,357			158	%	Delaware Basin	219,253		83,421		163	%	367,146		140,778		161	%
Total	Total		$	882,378	$	468,119		88	%	Total	$	1,237,680	$	533,141	132	%	$	2,120,058	$	1,001,260	112	%

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 for the ~~three~~six months ended ~~March 31,~~June 30, 2022:


	(in thousands)
Beginning balance	$	15,472
~~Additions (Net reduction~~Reductions to ~~additions~~assets previously ~~recognized)~~recognized (1)	~~(5,112)~~(12,307)
Amortized as a reduction to crude oil, natural gas and NGLs sales	~~(328)~~(429)
Ending balance	$	~~10,032~~2,736

_____________

(1) The reductions to our contract asset amounts previously recognized is due to the continued improvements in natural gas prices in 2022, which resulted in us receiving reimbursements from our third party gas processor during 2022 as part of our long-term gas processing agreement.

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 use our counterparties’ valuations to assess reasonableness of our fair value measurement.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~March 31,~~June 30, 2022

(Unaudited)

Our crude oil and natural gas fixed-price exchanges and basis exchanges are included in Level 2. Our collars are included in 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:


			March 31, 2022						December 31, 2021								June 30, 2022						December 31, 2021
		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			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)														(in thousands)
Derivative assets	Derivative assets														Derivative assets
Current	Current	Fair value of derivatives	$	6,795	$	6,363	$	13,158	$	—	$	17,909	$	17,909	Current	Fair value of derivatives	$	2,555	$	12,088	$	14,643	$	—	$	17,909	$	17,909
Non-current	Non-current	Fair value of derivatives	4,680		15,276		19,956		605		14,572		15,177		Non-current	Fair value of derivatives	8,378		18,589		26,967		605		14,572		15,177
Total	Total		$	11,475	$	21,639	$	33,114	$	605	$	32,481	$	33,086	Total		$	10,933	$	30,677	$	41,610	$	605	$	32,481	$	33,086

Derivative liabilities	Derivative liabilities														Derivative liabilities
Current	Current	Fair value of derivatives	$	(389,334)	$	(183,302)	$	(572,636)	$	(230,695)	$	(74,175)	$	(304,870)	Current	Fair value of derivatives	$	(526,359)	$	(175,970)	$	(702,329)	$	(230,695)	$	(74,175)	$	(304,870)
Non-current	Non-current	Fair value of derivatives	(169,736)		(64,548)		(234,284)		(74,715)		(20,846)		(95,561)		Non-current	Fair value of derivatives	(175,402)		(60,228)		(235,630)		(74,715)		(20,846)		(95,561)
Total	Total		$	(559,070)	$	(247,850)	$	(806,920)	$	(305,410)	$	(95,021)	$	(400,431)	Total		$	(701,761)	$	(236,198)	$	(937,959)	$	(305,410)	$	(95,021)	$	(400,431)

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

Three Months Ended March 31,
2022 2021
(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period $ (62,540) $ (8,427)
Changes in fair value included on condensed consolidated statements of operations line item:
Commodity price risk management gain (loss), net (209,771) (33,389)
Settlements included on condensed consolidated statement of operations line items:
Commodity price risk management gain (loss), net 46,100 5,582
Fair value of Level 3 instruments, net asset (liability) end of period $ (226,211) $ (36,234)
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 $ (159,118) $ (30,863)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
	(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period	$	(226,211)	$	(36,234)	$	(62,540)	$	(8,427)
Changes in fair value included on condensed consolidated statements of operations line item:
Commodity price risk management gain (loss), net	(63,157)		(94,131)		(272,928)		(127,520)
Settlements included on condensed consolidated statement of operations line items:
Commodity price risk management gain (loss), net	83,848		12,380		129,948		17,962
Fair value of Level 3 instruments, net asset (liability) end of period	$	(205,520)	$	(117,985)	$	(205,520)	$	(117,985)

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	$	(39,192)	$	(81,417)	$	(150,253)	$	(93,867)

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.~~curve. 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2022

(Unaudited)

Nonrecurring Fair Value Measurements

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.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~March 31, 2022~~

~~(Unaudited)~~

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 elected 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 as of the dates indicated:

March 31, 2022 December 31, 2021
Nominal Interest Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par
(in millions) (in millions)
Senior Notes:
2024 Senior Notes 6.125 % $ 202.6 101.3 % $ 202.8 101.4 %
2026 Senior Notes 5.75 % 762.0 101.6 % 775.5 103.4 %


			June 30, 2022			December 31, 2021
	Nominal Interest		Estimated Fair Value	Percent of Par		Estimated Fair Value		Percent of Par
			(in millions)			(in millions)
Senior Notes:
2024 Senior Notes	6.125	%	198,800	99.4	%	$	202.8	101.4	%
2026 Senior Notes	5.75	%	704,250	93.9	%	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 crude oil and natural 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 ~~March 31,~~June 30, 2022, we had derivative instruments in place for a portion of our anticipated production in 2022 through 2025. 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.

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 for the periods presented:


		Three Months Ended March 31,					Three Months Ended June 30,				Six Months Ended June 30,
Condensed Consolidated Statement of Operations Line Item	Condensed Consolidated Statement of Operations Line Item		2022		2021			Condensed Consolidated Statement of Operations Line Item	2022		2021		2022		2021
			(in thousands)						(in thousands)
Commodity price risk management gain (loss), net	Commodity price risk management gain (loss), net							Commodity price risk management gain (loss), net
Net settlements	Net settlements		$	(161,594)	$	(30,650)		Net settlements	$	(298,661)	$	(55,135)	$	(460,254)	$	(85,786)
Net change in fair value of unsettled derivatives	Net change in fair value of unsettled derivatives		(406,461)		(150,606)			Net change in fair value of unsettled derivatives	196,685		(253,118)		(209,777)		(403,723)
Total commodity price risk management gain (loss), net	Total commodity price risk management gain (loss), net		$	(568,055)	$	(181,256)		Total commodity price risk management gain (loss), net	$	(101,976)	$	(308,253)	$	(670,031)	$	(489,509)

811

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~March 31,~~June 30, 2022

(Unaudited)

Commodity Derivative Contracts. As of ~~March 31,~~June 30, 2022, 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
March 31, 2022
(in thousands)
Floors Ceilings
Crude Oil
NYMEX
2022 4,104 $ 53.18 $ 67.33 5,028 $ 46.14 $ (349,549)
2023 4,833 58.13 76.68 6,510 60.13 (206,083)
2024 225 55.00 75.12 6,126 70.59 (39,312)
2025 — — — 1,200 73.00 (398)
Total Crude Oil 9,162 18,864 (595,342)
Natural Gas
NYMEX
2022 26,595 3.14 4.78 25,200 2.70 (117,951)
2023 15,060 3.07 4.36 34,742 3.01 (58,102)
2024 — — — 26,160 3.49 (5,337)
41,655 86,102 (181,390)
CIG
2023 — — — 8,760 3.39 (6,185)
2025 — — — 4,800 3.10 (1,425)
— 13,560 (7,610)
Total Natural Gas 41,655 99,662 (189,000)
Basis Protection - Natural Gas
CIG
2022 51,795 (0.25) 9,540
2023 49,802 (0.30) 1,711
2024 26,160 (0.39) (715)
Total Basis Protection - Natural Gas 127,757 10,536
Commodity Derivatives Fair Value $ (773,806)


	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, 2022 (in thousands)
		Floors		Ceilings
Crude Oil
NYMEX
2022	2,736	$	53.18	$	67.33	6,852	$	58.35	$	(362,341)
2023	5,937	61.27		83.11		9,804	66.42		(258,320)
2024	825	65.91		89.58		6,126	70.59		(46,487)
2025	—	—		—		2,640	75.10		3,851
Total Crude Oil	9,498					25,422			(663,297)

Natural Gas
NYMEX
2022	21,063	3.13		4.65		29,642	2.95		(112,700)
2023	17,227	3.17		4.86		41,825	3.05		(82,080)
2024	—	—		—		26,160	3.54		(20,566)
2025	—	—		—		4,980	4.84		2,420
	38,290					102,607			(212,926)
CIG
2023	—	—		—		8,760	3.39		(9,279)
2025	—	—		—		4,800	3.10		(3,756)
	—					13,560			(13,035)

Total Natural Gas	38,290					116,167			(225,961)





Basis Protection - Natural Gas
CIG
2022						50,430	(0.27)		2,137
2023						57,782	(0.29)		(6,844)
2024						26,160	(0.39)		(2,113)
2025						4,980	(0.37)		(271)




Total Basis Protection - Natural Gas						139,352			(7,091)

Commodity Derivatives Fair Value									$	(896,349)

912

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~March 31,~~June 30, 2022

(Unaudited)

~~Subsequent to March 31, 2022, we entered into the following commodity derivative positions covering our crude oil and natural gas production:~~

Collars Fixed-Price Swaps
Commodity/ Index/
Maturity Period
Quantity
(Crude oil -
MBbls
Natural Gas - BBtu)
Weighted-Average
Contract Price
Quantity
(Crude oil -
MBbls
Natural Gas - BBtu)
Weighted-
Average
Contract
Price
Floors Ceilings
Crude Oil
NYMEX
2023 600 $ 75.00 $ 110.00 804 $ 86.00
Natural Gas
NYMEX
2023 900 5.00 14.40 — —
Basis Protection
CIG
2022 — — — 13,300 (0.31)
2023 — — — 4,800 (0.28)

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.

~~0Our~~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 ~~March 31,~~June 30, 2022:

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 $ 33,114 $ (33,114) $ —
Derivative liabilities:
Derivative instruments, at fair value $ 806,920 $ (33,114) $ 773,806


	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	$	41,610	$	(41,610)	$	—

Derivative liabilities:
Derivative instruments, at fair value	$	937,959	$	(41,610)	$	896,349

Derivative Counterparties. Our commodity derivative instruments expose us to the 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 ~~March 31,~~June 30, 2022; however, this determination may change.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~March 31, 2022~~

~~(Unaudited)~~

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:

March 31, 2022 December 31, 2021
(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved $ 8,511,308 $ 8,310,018
Unproved 306,210 306,181
Total crude oil and natural gas properties 8,817,518 8,616,199
Equipment and other 66,917 63,099
Land and buildings 19,928 19,928
Construction in progress 387,212 371,968
Properties and equipment, at cost 9,291,575 9,071,194
Accumulated DD&A (4,405,311) (4,256,329)
Properties and equipment, net $ 4,886,264 $ 4,814,865


	June 30, 2022		December 31, 2021
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	10,729,089	$	8,310,018
Unproved	285,926		306,181
Total crude oil and natural gas properties	11,015,015		8,616,199
Equipment and other	76,505		63,099
Land and buildings	25,406		19,928
Construction in progress	567,100		371,968
Properties and equipment, at cost	11,684,026		9,071,194
Accumulated DD&A	(4,596,254)		(4,256,329)
Properties and equipment, net	$	7,087,772	$	4,814,865

Impairment of Oil and Gas Properties. There were no significant impairment charges recognized related to our proved and unproved properties during the ~~three~~six months ended ~~March 31,~~June 30, 2022 and 2021.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2022

(Unaudited)

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:

Three Months Ended March 31, 2022 Year Ended December 31, 2021
(in thousands, except for number of wells)
Beginning balance $ — $ 7,459
Additions to capitalized exploratory well costs pending the determination of proved reserves 3,428 5,902
Reclassifications to proved properties — (13,361)
Ending balance $ 3,428 $ —
Number of wells pending determination at period-end 1 —


	Six Months Ended June 30, 2022		Year Ended December 31, 2021
	(in thousands, except for number of wells)
Beginning balance	$	—	$	7,459
Additions to capitalized exploratory well costs pending the determination of proved reserves	9,613		5,902
Reclassifications to proved properties	—		(13,361)
Ending balance	$	9,613	$	—

Number of wells pending determination at period-end	1		—

As of ~~March 31,~~June 30, 2022, there were no exploratory well costs that were capitalized for more than one year.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~March 31, 2022~~

~~(Unaudited)~~

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:

March 31, 2022 December 31, 2021
(in thousands)
Crude oil, natural gas and NGLs sales $ 523,029 $ 368,991
Joint interest billings 16,922 24,860
Other 550 10,809
Allowance for doubtful accounts (3,445) (6,055)
Accounts receivable, net $ 537,056 $ 398,605


	June 30, 2022		December 31, 2021
	(in thousands)
Crude oil, natural gas and NGLs sales	$	683,787	$	368,991
Joint interest billings	30,766		24,860
Other	15,069		10,809
Allowance for doubtful accounts	(6,207)		(6,055)
Accounts receivable, net	$	723,415	$	398,605

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

March 31, 2022 December 31, 2021
(in thousands)
Employee benefits $ 12,935 $ 29,319
Asset retirement obligations 31,914 32,146
Environmental expenses 12,266 11,942
Operating and finance leases 7,574 7,197
Other 12,441 10,805
Other accrued expenses $ 77,130 $ 91,409


	June 30, 2022		December 31, 2021
	(in thousands)
Employee benefits	$	18,801	$	29,319
Asset retirement obligations	31,913		32,146
Environmental expenses	13,342		11,942
Operating and finance leases	7,189		7,197
Other	13,776		10,805
Other accrued expenses	$	85,021	$	91,409

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

March 31, 2022 December 31, 2021
(in thousands)
Deferred midstream gathering credits $ 157,526 $ 159,788
Deferred oil gathering credits 15,578 16,080
Production taxes 178,722 131,865
Operating and finance leases 7,971 6,274
Other 846 762
Other liabilities $ 360,643 $ 314,769


	June 30, 2022		December 31, 2021
	(in thousands)
Deferred midstream gathering credits	$	154,700	$	159,788
Deferred oil gathering credits	15,075		16,080
Production taxes	154,895		131,865
Operating and finance leases	33,602		6,274
Other	2,883		762
Other liabilities	$	361,155	$	314,769

Deferred Midstream Gathering Credits. In 2019, we entered into agreements 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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2022

(Unaudited)

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 related to our deferred credits recognized on the condensed consolidated statements of operations for the periods indicated:


		Three Months Ended March 31,					Three Months Ended June 30,				Six Months Ended June 30,
			2022		2021				2022		2021		2022		2021
			(in thousands)						(in thousands)
Transportation, gathering and processing expense	Transportation, gathering and processing expense		$	1,956	$	1,521		Transportation, gathering and processing expense	$	2,228	$	1,779	$	4,222	$	3,300
Lease operating expense	Lease operating expense		531		438			Lease operating expense	859		647		1,467		1,085

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~March 31, 2022~~

~~(Unaudited)~~

NOTE 8 - LONG-TERM DEBT

Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling ~~$7.4~~$7.0 million and $7.9 million as of ~~March 31,~~June 30, 2022 and December 31, 2021, respectively, consists of the following:


	June 30, 2022		December 31, 2021
	(in thousands)
Revolving credit facility due November 2026	$	755,000	$	—









6.125% Senior Notes due September 2024	198,919		198,674









5.75% Senior Notes due May 2026	744,128		743,410





Total debt, net of unamortized discount, premium and debt issuance costs	$	1,698,047	$	942,084

March 31, 2022 December 31, 2021
(in thousands)
Revolving credit facility due November 2026 $ — $ —
6.125% Senior Notes due September 2024 198,796 198,674
5.75% Senior Notes due May 2026 743,769 743,410
Total debt, net of unamortized discount, premium and debt issuance costs $ 942,565 $ 942,084

Revolving Credit Facility

In November 2021, we entered into a Fifth Amended and Restated Credit Agreement (the “Restated Credit Agreement”), which provides for a maximum credit amount of $2.5 billion, subject to certain limitations, an initial borrowing base of $2.4 billion and an elected commitment of $1.5 billion. The Restated Credit Agreement matures on the earlier to occur of (i) the end of the five-year term on November 2, 2026 or (ii) the date that is 91 days prior to the scheduled maturity of the 2026 Senior Notes if the aggregate outstanding principal amount of those notes exceeds $500 million and our commitment utilization exceeds 50%.

The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general business purposes. The borrowing base is based on, among other 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. The Restated Credit Agreement includes an investment grade period election pursuant to which we have an option to remove our borrowing base limitations and terminate the liens securing the Restated Credit Agreement when certain debt ratings are achieved.

As of ~~March 31,~~June 30, 2022, we had a borrowing base of ~~$2.4~~$3.0 billion, an elected commitment of $1.5 billion and availability under our revolving credit facility of ~~$1.48 billion,~~$724.6 million, net of ~~$19.9~~$20.4 million of letters of credit outstanding. In April 2022, as part of our credit facility 2022 semi-annual redetermination, our borrowing base increased from $2.4 billion to $3.0 billion; however, we maintained our elected commitment amount of $1.5 billion.

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 Secured Overnight Financing Rate (“SOFR”) for one month, plus a premium) or, at our election, a rate equal to SOFR 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 ~~March 31,~~June 30, 2022, the applicable interest

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2022

(Unaudited)

margin is ~~0.75~~1.25 percent for the alternate base rate option or ~~1.75~~2.25 percent for the SOFR option, and the unused commitment fee is ~~0.375~~0.50 percent. Principal payments are generally not required until the maturity date of the revolving credit facility, unless the borrowing base falls below the outstanding balance. The Restated Credit Agreement also includes the ability to add certain sustainability-linked key performance indicators to be agreed upon between us, the administrative agent and a majority of the lenders and that may impact the applicable margin and commitment fee rate.

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 3.5:1.0; (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 ~~March 31,~~June 30, 2022, we were in compliance with all covenants related to our revolving credit facility.

As of ~~March 31,~~June 30, 2022 and December 31, 2021, debt issuance costs related to our revolving credit facility were ~~$16.1~~$15.2 million and $16.9 million, respectively, and are included in other assets on our condensed consolidated balance sheets.

~~Table of contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~March 31, 2022~~

~~(Unaudited)~~

Senior Notes

The following table summarizes the face values, interest rates, maturity dates, semi-annual interest payment dates, and optional redemption periods related to our outstanding senior note obligations as of ~~March 31,~~June 30, 2022:

2024 Senior Notes

2026 Senior Notes

Outstanding principal amounts (in thousands)

200,000

750,000

Interest rate

6.125

5.75

Maturity date

September 15, 2024

May 15, 2026

Interest payment dates

March 15, September 15

May 15, November 15

Redemption periods (1)

September 15, 2022

May 15, 2024

_____________

(1) At any time prior to the indicated dates, we have the option to redeem all or a portion of our senior notes of the applicable series at the redemption amounts specified in the respective senior note indenture plus accrued and unpaid interest to the date of redemption. On or after the indicated dates, we may redeem all or a portion of the senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus accrued and unpaid interest to the date of redemption.

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

The Senior 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 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 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 ~~March 31,~~June 30, 2022, we were in compliance with all covenants and all restricted payment provisions related to our Senior Notes.

Our wholly-owned subsidiaries, PDC Permian, Inc. and Pioneer Water Pipeline LLC (acquired in connection with the Great Western Acquisition), are each a guarantor of our obligations under the 2024 Senior Notes and the 2026 Senior Notes (collectively, the “Senior Notes”) and our credit facility.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2022

(Unaudited)

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~~Our leases ~~for the three months ended March 31, 2022.~~have remaining lease terms ranging from one to eleven years. We had short-term lease costs of ~~$74.7~~$80.8 million and ~~$38.9~~$71.4 million for the three months ended ~~March 31,~~June 30, 2022 and ~~March 31,~~June 30, 2021, respectively, and $155.5 million and $110.2 million for the six months ended June 30, 2022 and June 30, 2021, 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.

~~Table of contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~March 31, 2022~~

~~(Unaudited)~~

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

Leases Condensed Consolidated Balance Sheet Line Item March 31, 2022 December 31, 2021
(in thousands)
Operating lease right-of-use assets Other assets $ 6,824 $ 7,630
Finance lease right-of-use assets Properties and equipment, net 6,721 3,483
Total right-of-use assets $ 13,545 $ 11,113
Operating lease obligation - current Other accrued expenses 5,505 5,937
Operating lease obligation - non-current Other liabilities 3,308 4,044
Finance lease obligation - current Other accrued expenses 2,069 1,260
Finance lease obligation - non-current Other liabilities 4,663 2,230
Total lease liabilities $ 15,545 $ 13,471
Weighted average remaining lease term (years) 3.0 2.8
Weighted average discount rate 4.8 % 4.8 %

~~In January 2022, we entered into a 11-year lease agreement for an office space expected to commence in the second quarter of 2022 with an aggregate lease payments of approximately $32.0 million.~~


Leases	Condensed Consolidated Balance Sheet Line Item	June 30, 2022			December 31, 2021
		(in thousands)
Operating lease right-of-use assets	Other assets	$	16,198		$	7,630
Finance lease right-of-use assets	Properties and equipment, net	6,352			3,483
Total right-of-use assets		$	22,550		$	11,113

Operating lease obligation - current	Other accrued expenses	5,123			5,937
Operating lease obligation - non-current	Other liabilities	29,298			4,044
Finance lease obligation - current	Other accrued expenses	2,066			1,260
Finance lease obligation - non-current	Other liabilities	4,304			2,230
Total lease liabilities		$	40,791		$	13,471

Weighted average remaining lease term (years)		7.6			2.8
Weighted average discount rate		5.0		%	4.8		%

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 ~~three~~six months ended ~~March 31,~~June 30, 2022:


	(in thousands)
Asset retirement obligations at beginning of period	$	159,672
Obligations incurred with development activities and other	~~1,655~~2,744
Obligations incurred with acquisition	22,926
Accretion expense	~~2,987~~6,339
Revisions in estimated cash flows	(284)
Obligations discharged with asset retirements and divestitures	~~(8,260)~~(13,464)
Asset retirement obligations at end of period	~~155,770~~177,933

Current portion (1)	~~(31,914)~~(31,913)
Long-term portion	$	~~123,856~~146,020

_____________

(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 the time that the obligation is incurred. 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~March 31,~~June 30, 2022

(Unaudited)

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~~six months ended ~~March 31, 2022.~~ June 30, 2022, other than the commitments assumed as a result of the Great Western Acquisition, which included certain sales, transportation, gathering and processing contractual obligations. The aggregate committed volume and related amounts acquired as of June 30, 2022 are presented in the table below:


	Period ending June 30,
	2023		2024	2025		2026		2027		Thereafter		Total		Expiration Date for Thereafter
Natural gas (MMcf)	17,086		17,133	17,086		17,086		17,086		38,525		124,002		September 30, 2029
Natural gas (MMBtu)	6,726		6,726	6,744		6,726		6,726		1,695		35,343		September 30, 2027
Crude oil (MBbls)	14,174		13,847	11,111		7,300		1,840		—		48,272		N/A

Dollar commitment (in thousands)	$	77,197	76,447	$	66,815	$	56,545	$	44,492	$	57,362	$	378,858

For details of our existing commitments excluding the Great Western Acquisition, refer to Note 13 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data included in our Form 10-K for the year ended December 31, 2021.

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.

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”) to 7,050,000 shares. As of ~~March 31,~~June 30, 2022, there were ~~3,836,691~~3,829,031 shares available for grant under the 2018 Plan.

2010 Long-Term Equity Compensation Plan. Our Amended and Restated 2010 Long-Term Equity Compensation Plan, approved 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 ~~March 31,~~June 30, 2022, there were ~~465,780~~248,843 shares available for grant under the 2010 Plan.

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 March 31,					Three Months Ended June 30,				Six Months Ended June 30,
			2022		2021				2022		2021		2022		2021
			(in thousands)						(in thousands)
General and administrative expense	General and administrative expense		$	5,182	$	4,828		General and administrative expense	$	6,738	$	6,113	$	11,920	$	10,941
Lease operating expense	Lease operating expense		292		192			Lease operating expense	558		382		850		574
Total stock-based compensation expense	Total stock-based compensation expense		$	5,474	$	5,020		Total stock-based compensation expense	$	7,296	$	6,495	$	12,770	$	11,515

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~March 31,~~June 30, 2022

(Unaudited)

Restricted Stock Units

The following table presents the changes in non-vested time-based RSUs to eligible employees, including executive officers, for the ~~three~~six months ended ~~March 31,~~June 30, 2022:

Shares Weighted Average Grant-Date Fair Value per Share
Non-vested at beginning of period 1,165,187 $ 25.33
Granted 92,411 57.57
Vested (196,336) 28.76
Forfeited (5,730) 26.40
Non-vested at end of period 1,055,532 27.51


	Shares	Weighted Average Grant-Date Fair Value per Share
Non-vested at beginning of period	1,165,187	$	25.33
Granted	344,106	70.58
Vested	(538,750)	25.78
Forfeited	(32,552)	38.87
Non-vested at end of period	937,991	41.21

The weighted average grant-date fair value of restricted stock units was ~~$57.57~~$70.58 and ~~$28.75~~$33.32 for the ~~three~~six months ended ~~March 31,~~June 30, 2022 and 2021, respectively. The total grant-date fair value of restricted stock units that vested for the ~~three~~six months ended ~~March 31,~~June 30, 2022 and 2021 was ~~$5.6~~$13.9 million and ~~$6.1~~$12.9 million, respectively. Total compensation cost related to non-vested time-based awards and not yet recognized on our condensed consolidated statements of operations as of ~~March 31,~~June 30, 2022 was ~~$21.8~~$33.5 million. This cost is expected to be recognized over a weighted average period of ~~1.7~~1.8 years.

Performance Stock Units

The Compensation Committee awarded a total of 102,098 market-based PSUs to our executive officers during the ~~three~~six months ended ~~March 31,~~June 30, 2022. 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, 2024, 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, as well as that of our peer group.

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:

Three Months Ended March 31,
2022 2021
Expected term of award (in years) 2.9 2.9
Risk-free interest rate 1.7% 0.2%
Expected volatility 86.3% 84.6%
Weighted average grant date fair value per share $107.85 $54.01


	Six Months Ended June 30,
	2022	2021
Expected term of award (in years)	2.9	2.9
Risk-free interest rate	1.7%	0.2%
Expected volatility	86.3%	84.6%
Weighted average grant date fair value per share	$107.85	$54.01

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~March 31,~~June 30, 2022

(Unaudited)

The following table presents the change in non-vested market-based awards during the ~~three~~six months ended ~~March 31,~~June 30, 2022:


	Shares	Weighted Average Grant-Date Fair Value per Share
Non-vested at beginning of period	439,229	$	43.21
Granted	102,098	107.85
Granted for performance multiple (1)	241,183	43.10
Released (1)	(241,183)	43.10
Non-vested at end of period	541,327	55.40

_____________

(1) Upon completion of the performance period for the PSUs granted in 2019 and a portion of the PSUs granted in 2020, a performance multiple of 190% was applied to each of the grants resulting in additional grants of PSUs in January 2022.

Total compensation cost related to non-vested market-based awards not yet recognized on our condensed consolidated statements of operations as of ~~March 31,~~June 30, 2022 was ~~$19.5~~$16.9 million. This cost is expected to be recognized over a weighted average period of ~~1.5~~1.3 years.

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 ~~March 31,~~June 30, 2022, no shares of preferred stock have been issued.

Stock Repurchase Program

In 2019, our board of directors approved a program pursuant to which we may acquire shares of our common stock from time to time. At December 31, 2021, $187.3 million of the approved $525.0 million remained available for repurchase under the stock repurchase program. In February 2022, our board of directors approved a new stock repurchase program that reset the total repurchase value to $1.25 billion, which we currently anticipate fully utilizing by December 31, 2023. 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. Repurchases under the program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. Pursuant to the program, we repurchased ~~1.3~~4.3 million and ~~0.6~~1.3 million shares of outstanding common stock at a cost of ~~$85.3~~$300.0 millionand ~~$22.1~~$48.6 million during the ~~three~~six months ended ~~March 31,~~June 30, 2022 and 2021, respectively. As of ~~March 31,~~June 30, 2022, ~~$1.19 billion~~$978.1 million remained available under the program for repurchases of our outstanding common stock.

Dividends

During the first and second quarters of 2022, our board of directors approved the declaration and payment of quarterly cash dividends of $0.25 and $0.35 per share of common stock, respectively. For the ~~three~~six months ended ~~March 31,~~June 30, 2022, our dividends totaled ~~$24.5~~$59.1 million or ~~$0.25~~$0.60 per share of outstanding common stock. 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 dividend 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.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~March 31, 2022~~

~~(Unaudited)~~

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 our 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. At each reporting period, management considers the ~~scheduled reversal of deferred tax liabilities,~~ available taxes in carryback periods, the future reversals of existing taxable temporary differences, tax planning strategies and

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2022

(Unaudited)

projected future taxable income in making this assessment. Our oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to ~~continue to~~ provide a valuation allowance against our DTAs ~~as of December 31, 2021 and March 31, 2022~~beginning January 1, 2020 since we ~~cannot~~previously could not conclude that it is more likely than not that our DTAs will be fully realized in future periods.

~~Future events or new~~During the period ended June 30, 2022, sufficient positive evidence ~~which may lead~~became available that allowed us to ~~conclude~~reach a conclusion that it is more likely than not that our 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. Given recent improvements in oil and gas prices and improvements~~the valuation allowance is no longer be needed. As we previously disclosed in our ~~current earnings,~~2021 Form 10-K, we ~~believe there is~~maintained a ~~reasonable possibility that, if oil~~valuation allowance on our net federal deferred tax assets and ~~natural gas prices remain similar~~would continue to ~~March 31, 2022 pricing levels,~~do so until sufficient positive evidence ~~may become available within~~exists to support a reversal of the ~~next 12 months~~allowance. In the second quarter, continued higher commodity prices have increased our income, resulting in the reversal of objective negative evidence of cumulative loss in recent years, and we determined that we have sufficient positive evidence to ~~allow us to reach~~release the valuation allowance. As a ~~conclusion that all or a significant portion~~result, we released $22.4 million of the valuation allowance ~~will no longer be needed. Release of the valuation allowance would result in the recognition of certain~~against our deferred income tax assets and recognized a corresponding decrease to income tax expense in the period ~~the release is recorded. However, the exact timing and amount~~ended June 30, 2022. The remainder of the valuation allowance ~~release are subject~~of $34.2 million will be recognized as a decrease to ~~change based on~~income tax expense over the ~~level~~second half of ~~profitability that we actually achieve.~~2022.

The effective income tax rates for the three and six months ended ~~March 31,~~June 30, 2022, ~~and 2021~~excluding our discrete gain on bargain purchase of $100.3 million, were ~~3.9~~18.5 percent and ~~0.6~~19.6 percent, respectively, and 0.2 percent and 0.1 percent provision on the respective pre-tax ~~losses.~~losses for the three and six months ended June 30, 2021, respectively. The effective tax rates differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax loss due to the valuation allowance or changes in the valuation allowance against our deferred income tax assets.

As of ~~March 31,~~June 30, 2022, there is 0 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 2020 federal income tax return with no tax adjustments. We continue to voluntarily participate in the IRS CAP program for the review of our 2021 ~~and 2022~~ tax ~~years.~~year. 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 stock-based employee awards 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 March 31,
2022 2021
(in thousands)
Weighted average common shares outstanding - basic 96,279 99,702
Weighted average common shares and equivalents outstanding - diluted 96,279 99,702


	Three Months Ended June 30,		Six Months Ended June 30,
	2022	2021	2022	2021
	(in thousands)
Weighted average common shares outstanding - basic	96,982	99,187	96,632	99,445
Dilutive effect of:
RSUs and PSUs	1,235	—	1,488	—

Other equity-based awards	29	—	30	—
Weighted average common shares and equivalents outstanding - diluted	98,246	99,187	98,150	99,445

We reported a net loss for the three and six months ended ~~March 31, 2022 and~~June 30, 2021. 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~March 31,~~June 30, 2022

(Unaudited)

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 March 31,
2022 2021
(in thousands)
Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
RSUs and PSUs 2,281 1,748
Other stock-based awards 143 212
Total anti-dilutive common share equivalents 2,424 1,960


	Three Months Ended June 30,		Six Months Ended June 30,
	2022	2021	2022	2021
	(in thousands)
Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
RSUs and PSUs	225	2,818	113	2,642

Other stock-based awards	33	172	33	185
Total anti-dilutive common share equivalents	258	2,990	146	2,827

NOTE 15 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION


	Six Months Ended June 30,
	2022		2021
	(in thousands)
Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest	$	23,614	$	30,855
Income taxes	157		(1,125)

Non-cash investing and financing activities:
Change in accounts payable related to capital expenditures	$	(25,671)	$	61,310
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals	1,114		(1,729)
Issuance of common stock for acquisition of an exploration and production business	293,314		—

Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	3,611	$	4,054
Operating cash flows from finance leases	123		65


Right-of-use assets obtained in exchange for lease obligations:
Operating leases (1)	$	11,121	$	1,066
Finance leases	3,846		1,466

_____________

(1) Includes $3.1 million operating lease acquired from Great Western.

Cash, cash equivalents and restricted cash presented in the condensed consolidated statements of cash flow is comprised of the following:


	June 30,
	2022		2021
	(in thousands)
Cash and cash equivalents	$	38,528	$	109,749
Restricted cash (1)	8,130		—
	$	46,658	$	109,749

_____________

(1) Included in Other assets on our condensed consolidated balance sheets.

Three Months Ended March 31,
2022 2021
(in thousands)
Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest $ 3,825 $ 9,043
Income taxes (233) (1,388)
Non-cash investing and financing activities:
Change in accounts payable related to capital expenditures $ 33,135 $ 15,393
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals 767 206
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 1,740 $ 2,224
Operating cash flows from finance leases 49 20
Right-of-use assets obtained in exchange for lease obligations:
Operating leases $ 444 $ —
Finance leases 3,660 917

2022

PDC ENERGY, INC.

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

~~March 31,~~June 30, 2022 Financial Overview of Operations and Liquidity

Market Conditions

The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. Commodity prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment.

Crude Oil Markets

In 2021, the global economy continued to recover due to the partial containment of COVID-19, ~~and related emerging variants,~~ which resulted toin an increase in crude oil demand. Recovery has generally continued in 2022 despite a variety of economic headwinds, including outbreaks of COVID-19 variants. Overall production from OPEC+ has not increased at the same pace ~~of the~~as demand, creating upward pressure on crude oil prices and tightening of global oil inventories. In February 2022, Russia, a major global crude oil exporter, attacked and invaded Ukraine, driving the United States (“U.S.”) and other Western countries to apply sanctions over crude oil imports from Russia. Additionally, many crude oil purchasers are boycotting Russian crude oil in response to the attacks on Ukraine. All of these factors have led to lower global oil supply and significantly higher crude oil prices in the first ~~quarter~~six months of 2022 when compared to 2021.

During 2022, the U.S. has experienced the highest inflation rates since 1981 resulting mainly from the global recovery from COVID-19, supply chain disruptions, higher labor costs and the invasion of Ukraine by Russia. The ~~commodity price environment may remain volatile~~U.S. Federal Reserve has responded to the rise in inflation by increasing the benchmark federal funds interest rate. The magnitude and overall effectiveness of these actions remains uncertain, but such monetary policy changes can increase the risk of economic slowdown or lead to a recession. A slowdown or recession can cause a decrease or shift in short-term or long-term demand for ~~an extended period due to, among other things, the continued invasion~~crude oil, resulting in ~~Ukraine, outbreaks caused by coronavirus variants, the recovery of the economy, unexpected supply disruptions in key producing countries including~~industry oversupply and the potential for higher U.S. crude oil production, historically low storage inventories of petroleum products, geopolitical disputes, weather conditions, and ongoing investor and regulatory pressure to replace fossil fuel consumption with lower ~~carbon emission alternatives.~~commodity prices.

Natural Gas and NGL Markets

In addition to the crude oil market drivers noted above, natural gas and NGL prices are also affected by structural changes in supply and demand, growth in levels of liquified natural gas exports and deviations from seasonally normal weather. Lower inventory levels and lack of reinvestment in supply growth have driven natural gas and NGL prices higher.

Financial Matters

Three months ended ~~March 31,~~June 30, 2022 compared to three months ended ~~December~~March 31, ~~2021~~

2022

•Production volumes ~~decreased~~increased to 21.4 MMboe in the second quarter of 2022, an increase of 19 percent compared to 17.9 MMboe in the first quarter, ~~of 2022, a decrease of 8 percent compared to the fourth quarter of 2021,~~ primarily driven by the ~~timing of our turn-in-line activities and two fewer days in~~production volumes from the ~~first quarter of 2022.~~

Great Western Acquisition.

•Crude oil, natural gas and NGLs sales increased to ~~$882.4~~$1,237.7 million compared to ~~$848.2~~$882.4 million in the ~~fourth~~first quarter of ~~2021~~2022 primarily due to a 1317 percentincrease in weighted average realized commodity prices ~~partially offset by 8~~and a 19 percent ~~decrease~~increase in production volumes between periods.

•Negative net settlements from our commodity derivative contracts ~~decreased~~increased to $298.7 million in the second quarter of 2022 compared to $161.6 million in the first quarter of 2022 ~~compared to $194.8 million in the fourth quarter of 2021~~ due to a ~~lower volume of commodities hedged~~continued increase in ~~the first quarter of 2022.~~

commodity prices between periods and additional commodity derivatives acquired from Great Western.

•Combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 1030 percent to ~~$720.8~~$939.0 million from ~~$653.3~~$720.8 million in the ~~fourth~~first quarter of ~~2021.~~2022.

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•Generated net income of $662.4 million, or $6.74 per diluted share, for the second quarter of 2022 and a net loss of $32.0 million, or $0.33 per diluted share, for the first quarter of 2022 ~~and a net income of $473.1 million, or $4.78 per diluted share for the fourth quarter of 2021~~ primarily due to ~~a $568.1 million commodity price risk management loss incurred in 2022 partially offset by~~(i) an increase in crude oil, natural gas and NGLs sales of ~~$34.2~~$355.3 million, (ii) a $466.1 million decrease in commodity risk management loss between periods, and (iii) a gain on bargain purchase from the Great Western Acquisition of $100.3 million, partially offset by an increase in income tax expense of $128.0 million between periods.

•Adjusted EBITDAX, a non-U.S. GAAP financial measure, ~~was $549.3~~increased to $814.3 million compared to ~~$487.7~~$549.3 million for the ~~fourth~~first quarter of ~~2021,~~2022, primarily due to an increase in sales of ~~$67.5~~$218.2 million, net of negative net derivative settlements, and a $100.3 million gain on bargain purchase recognized in the second quarter of 2022, partially offset by an increase in costs experienced in operations.

•Cash flows from operations ~~decreased~~increased to $747.4 million compared to $489.0 million ~~compared to $520.0 million~~ in the ~~fourth~~first quarter of ~~2021.~~2022. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to ~~$538.8~~$694.7 million compared to ~~$473.1~~$538.8 million in ~~fourth~~the first quarter of 2022. Adjusted free cash flows, a non-U.S. GAAP financial measure, increased to $403.8 million from $318.7 million in the first quarter of 2022.

Six months ended June 30, 2022 compared to six months ended June 30, 2021

•Production volumes increased to 39.3 MMboe in 2022, an increase of 19 percent compared to 33.2 MMboe in 2021, primarily driven by production volumes from Great Western Acquisition and as a result of our turn-in-line activities.

•Crude oil, natural gas and NGLs sales increased to $2.1 billion compared to $1.0 billion in 2021 primarily due to a 79 percent increase in weighted average realized commodity prices and a 19 percent increase in production volumes between periods.

•Negative net settlements from our commodity derivative contracts increased to $460.3 million in 2022 compared to $85.8 million in 2021 due to improvements in commodity pricing year over year and additional commodity derivatives acquired from Great Western.

•Combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 81 percent to $1,659.8 million from $915.5 million in 2021.

•Generated net income of $630.4 million, or $6.42 per diluted share, in the 2022 period and a net loss of $96.1 million, or $0.97 per diluted share, in the 2021 period, primarily due to an increase in crude oil, natural gas and NGLs sales of $1,118.8 million and a gain on bargain purchase from the Great Western Acquisition of $100.3 million, partially offset by a $180.5 million increase in commodity risk management loss and a $129.3 million increase in income tax expense between periods .

•Adjusted EBITDAX, a non-U.S. GAAP financial measure, increased to $1,363.5 million in 2022 compared to $674.1 million in 2021, primarily due to an increase in sales of $744.3 million, net of negative net derivative settlements, and a $100.3 million gain on bargain purchase recognized in 2022, partially offset by an increase in costs experienced in operations between periods.

•Cash flows from operations increased to $1,236.4 million in 2022 compared to $577.4 million in 2021. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to $1,233.5 million in 2022 compared to $643.0 million in 2021. Adjusted free cash flows, a non-U.S. GAAP financial measure, ~~decreased~~increased to ~~$318.7 million from $339.5~~$722.5 million in ~~the fourth quarter of~~2022 from $341.4 million in 2021.

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.

~~Pending Acquisition~~

Great Western Acquisition

On ~~February 26,~~May 6, 2022, we ~~entered into~~completed the ~~Acquisition Agreement to acquire~~acquisition of Great Western, for approximately $1.4 billion, inclusive of Great Western’s net debt. Great Western iswas an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in the Wattenberg Field of Colorado. ~~We anticipate acquiring approximately 54,000 net acres~~The consideration paid was $542.5 million in ~~the Core Wattenberg~~cash and ~~production of approximately 55,000 Boe per day. Under the terms of the Acquisition Agreement, the purchase consideration for the Great Western Acquisition will be made through the transfer of~~ approximately 4.0 million shares of our common stock, valued at $293.3 million on the acquisition date. In addition, we paid off Great Western’s secured credit facility totaling $235.8 million, and ~~approximately $543~~paid $361.2 million ~~in cash.~~to terminate Great Western’s 12% senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. The cash portion of the purchase price ~~is expected to be~~and the termination of Great Western’s debt were funded through a combination of cash on hand and availability under our revolving credit facility. ~~We anticipate that~~As a result of the Great Western Acquisition, ~~will be completed~~we acquired approximately 54,000 net acres in ~~May 2022, subject to certain customary closing conditions being met.~~

the core Wattenberg Field and production of approximately 50,000 Boe per day.

Drilling and Completion Overview

In the Wattenberg Field, we operated one full-time drilling rig ~~one spudder rig~~ and one full-time completion crew during the first ~~quarter~~half of 2022, ~~and~~ added a second full-time drilling rig in mid-March ~~2022.~~2022 and added a third full-time drilling rig upon closing the Great Western Acquisition. In addition, we operated one full-time drilling rig and one completion crew during the first ~~quarter~~half of 2022 in the Delaware Basin. Our total capital investments in crude oil and natural gas properties for the ~~three~~six months ended ~~March 31,~~June 30, 2022 were ~~$220.2~~$508.1 million.

The following table summarize our drilling and completion activities for the ~~three~~six months ended ~~March 31,~~June 30, 2022:


	Operated Wells
	Wattenberg Field		Delaware Basin		Total
	Gross	Net	Gross	Net	Gross	Net
In-process as of December 31, 2021	143	133.0	21	20.6	164	153.6
Wells spud	74	69.5	10	9.9	84	79.4
Wells acquired in-process (1)	48	44.6	—	—	48	44.6
Wells turned-in-line	(73)	(68.9)	(18)	(17.8)	(91)	(86.7)
In-process as of June 30, 2022	192	178.2	13	12.7	205	190.9

_____________

Operated Wells
Wattenberg Field Delaware Basin Total
Gross Net Gross Net Gross Net
In-process as of December 31, 2021 143 133.0 21 20.6 164 153.6
Wells spud 20 17.8 6 5.9 26 23.7
Wells turned-in-line (40) (38.8) (9) (9.0) (49) (47.8)
In-process as of March 31, 2022 123 112.0 18 17.5 141 129.5

(1) Represents in-process wells we obtained as part of the Great Western Acquisition.

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.

~~PDC ENERGY, INC.~~

Capital Returns

Stock Repurchase Program. In February 2022, our board of directors approved a new stock repurchase program that reset the total repurchase value to $1.25 billion, which we currently anticipate fully utilizing by December 31, 2023. We repurchased ~~1.3~~4.3 million shares of outstanding common stock at a cost of ~~$85.3~~$300.0 million for the ~~three~~six months ended ~~March 31,~~June 30, 2022. As of ~~March 31,~~June 30, 2022, ~~$1.19 billion of our outstanding common stock~~$978.1 million remained available for repurchases under the program.

Dividends. ~~For~~Our board of directors approved the ~~three months ended March 31, 2022, our dividends declared amounted to~~declaration and payment of a quarterly cash dividend of $0.25 per share of common stock ~~or $24.5 million~~ in the ~~aggregate.~~first quarter of 2022 and increased our base quarterly dividend to $0.35 per share of common stock in the second quarter of 2022. For the six months ended June 30, 2022, our dividends totaled $59.1 million or $0.60 per share of outstanding common stock.

PDC ENERGY, INC.

2022 Operational and Financial Outlook

~~On a PDC standalone basis (without consideration to~~Upon completion of the Great Western ~~Acquisition),~~Acquisition we ~~anticipate that~~provided updated guidance in late May 2022. Based on our current operating results from the first half of the year, we now expect full-year 2022 production ~~for 2022 will~~to range between ~~195,000~~230,000 Boe to ~~205,000~~240,000 Boe per day, of which approximately ~~62,000~~73,000 Bbls to ~~65,000~~77,000 Bbls ~~of which are~~is expected to be crude oil. Our planned 2022 capital investments in crude oil and natural gas properties ~~which we expect~~are now expected to be between ~~$675 million~~$1.025 and ~~$725 million, are~~$1.075 billion and is focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin. Our capital budget and operating costs for 2022 ~~is likely~~will continue to be impacted by cost inflation if crude oil and natural gas prices remain at current levels or continue to increase. ~~Our 2022 operational and financial projections will be updated after we close the Great Western Acquisition.~~

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 to best meet our short- and long-term corporate strategy. We may revise our 2022 capital investment program during 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,~~matters and acquisition and divestiture opportunities.

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, Summit and ~~Summit~~Range development areas. ~~Upon closing the Great Western Acquisition, we plan to add a fifth development area called Ranger.~~ Our 2022 capital investment program for the Wattenberg Field ~~on a PDC standalone basis,~~ represents approximately 7580 percent of our expected total capital investments in crude oil and natural gas properties. In 2022, the majority of the wells we plan to drill are 1.5 mile and 2.0 mile lateral wells. Our plan includes spudding ~~approximately 130 to 145 operated wells~~ and turning-in-line approximately ~~115~~150 to ~~130~~175 operated wells. ~~We added a full-time drilling rig in March 2022, bringing us to two~~To meet our development plan, we intend on running three full-time horizontal rigs and one full-time plus an intermittent completion crew ~~along with a part-time spudder rig planned~~ for the rest of the year.

Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2022 are expected to be approximately 2520 percent ~~on a PDC standalone basis,~~ of our total capital investments. In 2022, we anticipate spudding 16 operated wells and turning-in-line ~~approximately 15 to~~ 20 operated wells with the majority of the wells being 2.0 mile lateral wells.

We completed our 2022 completion program in late May and are currently running one full-time drilling rig.

We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2022, we expect 2022 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. Our first priority is to pay our quarterly base dividend of ~~$0.25~~$0.35 per share. Then we expect to use approximately 60% or more of our remaining adjusted free cash flows, a non-U.S. GAAP financial measure, for share repurchases and special dividends, as needed. Any remaining adjusted free cash flows will be used for reducing debt, building cash on our consolidated balance sheet or other general corporate purposes.

~~PDC ENERGY, INC.~~

Regulatory and Political Updates

In Colorado, certain interest groups opposed to oil and natural gas development 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. Pursuant to SB 19-181, a series of rulemaking hearings were conducted, which focused on issues such as permitting requirements, setbacks and siting requirements, and financial assurance, resulting in the adoption of new regulatory requirements. We anticipate that future hearings will be conducted by the COGCC on permit fees, ~~worker certification~~the interaction between the state and local governments, and well site reclamation. These proceedings could result in new rules that impose increased costs and regulations on our operations.

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. As of January 2021, 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 an overview of oil and gas development over a larger area over a longer period of time, including a comprehensive cumulative impact analysis, an alternative location analysis, and extensive communication with both local elected officials and communities. A CAP will include multiple OGDPs within its boundaries. As both CAPs and OGDPs are new processes and the COGCC staff is working to develop the appropriate requirements and adjusting to their new operating plan, the time needed to

PDC ENERGY, INC.

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.

In addition to the changes to the permitting process, the COGCC conducted a rulemaking concerning financial assurance to be provided by operators in Colorado. The rulemaking was designed to address and reduce the number of wells that have not been properly plugged by their operators (“orphan wells”) due to financial constraints or bankruptcy. As part of that rulemaking, tiers of operators were established based on identified metrics ~~which results~~with operators in ~~varying~~different tiers being obligated to provide different levels of financial ~~assurance being required.~~assurance. For our tier, a bond of $40 million will be required in the second ~~quarter~~half of 2022 and will be secured through our existing surety bond program. In addition to the financial assurance, operators will be assessed aan annual fixed fee per existing well that will fund the plugging and abandonment of orphan wells identified by the COGCC. We do not anticipate a material effect on our financial condition or results of operations with meeting the outlined financial assurance requirements.

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

Wattenberg Permits Update.In June 2022, the COGCC granted PDC ~~was granted~~ unanimous approval for ~~an 8-well~~a 69-well OGDP ~~located in rural Weld County in October 2021,~~and a 30-well OGDP, our ~~first approval~~second and third approvals under the new permitting ~~process resulting from a company-wide collaborative effort. Additionally, in September 2021, we submitted~~process. Combined, these two approvals provided us approximately 100 additional permits for our ~~application for an OGDP covering an approximate 70-well, multi-pad development~~2024 drilling and completion plan. ~~We anticipate a COGCC determination on approval of this OGDP in the second quarter of 2022.~~

In December 2021, PDC submitted our first CAP. The application proposes approximately 450 wells spread amongst 2522 surface locations, ~~in Weld County,~~ to be developed over several years. We conducted a comprehensive analysis of potential impacts and have committed to transport all water and commodity production via pipeline and to provide electrical infrastructure to all locations. These commitments will lessen the impact of traffic, noise, light and ~~emissions.~~emissions, while also improving our ESG metrics. Additionally, we developed a dashboard to analyze disproportionately impacted communities in the area and developed a robust communication plan designed to encourage communication with and garner feedback from these key stakeholders. We worked with COGCC on comments received on this CAP, submitted updated plans in June 2022 and received the completeness determination on August 2, 2022. We anticipate a COGCC determination on approval of our CAP by year end 2022 or early 2023, recognizing that there may be delays in this new process.

Together, these applications represent our planned Wattenberg Field turn-in-line activity ~~into 2027 on a PDC standalone basis.~~

past 2028.

Environmental, Social and Governance (“ESG”)

We are committed to a meaningful and measurable ESG strategy. Our mission to be a cleaner, safer and more socially responsible company begins with a sound strategy, is supported in the boardroom and is overseen by our Environmental, Social, Governance and Nominating Committee at the board of directors and is considered at every level of our business.

~~PDC ENERGY, INC.~~

~~During the first quarter of~~On March 31, 2022, we completed our initial U.S. Environmental Protection Agency (“EPA”) annual filing for ~~2021. Our results outline that~~2021 and we ~~have achieved a~~reported an approximate 12% reduction in greenhouse gas (“GHG”) emissions and an approximate 17% reduction in methane emissions intensity from 2020 baseline ~~targets, that puts us~~levels (each on a per unit of production basis), putting the Company on track to meet ~~our~~its 60% and 50% GHG and methane reduction ~~levels~~goals by 2025, respectively.

Additionally, in May 2022, our board of directors approved quantitative metrics for GHG and methane emissions reductions for our 2022 short-term incentive program, including 15% GHG and 30% methane emissions reduction targets from 2021 to 2022, respectively. As noted above, this supports the Company’s previously announced sustainability goals. In total, over 25% of our short-term incentive program is tied to ESG and Environmental, Health and Safety initiatives. Additional information on our ESG practices, including sustainability goals, key metrics and progress achieved, can be found in our Sustainability Report available on our website at www.pdce.com and is not incorporated by reference in this report.

The SEC and other regulatory bodies are proposing a number of climate-change focused and broader ESG reporting requirements focused on emission reduction. When adopted, we will modify our disclosures accordingly.

2527

PDC ENERGY, INC.

Results of Operations

In November 2020, the SEC issued Final Rule 33-10890, Management’s Discussion and Analysis, Selected Financial Data and Supplementary Financial Information, which modernizes and simplifies certain disclosure requirements of Regulation S-K. One of the updates to Item 303 of Regulation S-K allows registrants to compare the results of the most recently completed quarter to the results of either the immediately preceding quarter or the corresponding quarter of the preceding year. We adopted presenting the results of operations with this approach effective January 1, 2022, as we believe that comparing current quarter results to those of the immediately preceding quarter is more useful in identifying current business trends and provides a more meaningful comparison. Accordingly, we have compared the results for the three months ended March 31, 2022 and December 31, 2021 below. Additionally, in the first filing after the adoption of this rule change, we are required to disclose a comparison of the results for the current quarter and the corresponding quarter of the preceding fiscal year. Accordingly, the comparison between the results for the three months ended March 31, 2022 and March 31, 2021 is also presented below.

Summary of Operating Results

The following table presents selected information regarding our operating results:

Three Months Ended Percent Change Between
March 31, 2022 December 31, 2021 March 31, 2021
March 31, 2022 -
December 31, 2021
March 31, 2022 - March 31, 2021
(dollars in millions, except per unit data)
Production:
Crude oil (MBbls) 5,853 6,325 4,857 (7) % 21 %
Natural gas (MMcf) 43,119 47,033 40,152 (8) % 7 %
NGLs (MBbls) 4,885 5,241 4,192 (7) % 17 %
Crude oil equivalent (MBoe) 17,924 19,405 15,740 (8) % 14 %
Average Boe per day (Boe) 199,156 210,924 174,889 (6) % 14 %
Crude Oil, Natural Gas and NGLs Sales:
Crude oil $ 549.7 $ 483.9 $ 273.7 14 % 101 %
Natural gas 163.1 192.7 105.6 (15) % 54 %
NGLs 169.6 171.6 88.8 (1) % 91 %
Total crude oil, natural gas and NGLs sales $ 882.4 $ 848.2 $ 468.1 4 % 89 %
Net Settlements on Commodity Derivatives `
Crude oil $ (131.1) $ (122.7) $ (20.5) 7 % *
Natural gas (30.5) (72.1) (10.2) (58) % 199 %
Total net settlements on derivatives $ (161.6) $ (194.8) $ (30.7) (17) % *
Average Sales Price (excluding net settlements on derivatives):
Crude oil (per Bbl) $ 93.93 $ 76.50 $ 56.34 23 % 67 %
Natural gas (per Mcf) 3.78 4.10 2.63 (8) % 44 %
NGLs (per Bbl) 34.70 32.74 21.19 6 % 64 %
Crude oil equivalent (per Boe) 49.23 43.71 29.74 13 % 66 %
Average Costs and Expenses (per Boe):
Lease operating expense $ 3.02 $ 2.62 $ 2.66 15 % 14 %
Production taxes 3.51 3.30 1.87 6 % 88 %
Transportation, gathering and processing expense 1.56 1.34 1.38 16 % 13 %
General and administrative expense 1.90 1.62 2.08 17 % (9) %
Depreciation, depletion and amortization 8.43 8.07 9.32 4 % (10) %


	Three Months Ended						Six Months Ended
	June 30, 2022		March 31, 2022		Percent Change		June 30, 2022		June 30, 2021		Percent Change
	(dollars in millions, except per unit data)
Production:
Crude oil (MBbls)	6,844		5,853		17	%	12,697		10,248		24	%
Natural gas (MMcf)	49,817		43,119		16	%	92,936		83,512		11	%
NGLs (MBbls)	6,263		4,885		28	%	11,148		8,997		24	%
Crude oil equivalent (MBoe)	21,410		17,924		19	%	39,335		33,164		19	%
Average Boe per day (Boe)	235,275		199,156		18	%	217,320		183,227		19	%

Crude Oil, Natural Gas and NGLs Sales:
Crude oil	$	740.9	$	549.7	35	%	$	1,290.6	$	624.3	107	%
Natural gas	277.7		163.1		70	%	440.8		191.4		130	%
NGLs	219.1		169.6		29	%	388.7		185.6		109	%
Total crude oil, natural gas and NGLs sales	$	1,237.7	$	882.4	40	%	$	2,120.1	$	1,001.3	112	%

Net Settlements on Commodity Derivatives									`
Crude oil	$	(231.4)	$	(131.1)	77	%	$	(362.5)	$	(68.4)	*
Natural gas	(67.3)		(30.5)		121	%	(97.8)		(17.4)		*
Total net settlements on derivatives	$	(298.7)	$	(161.6)	85	%	$	(460.3)	$	(85.8)	*

Average Sales Price (excluding net settlements on derivatives):
Crude oil (per Bbl)	$	108.24	$	93.93	15	%	$	101.64	$	60.92	67	%
Natural gas (per Mcf)	5.57		3.78		47	%	4.74		2.29		107	%
NGLs (per Bbl)	34.99		34.70		1	%	34.86		20.61		69	%
Crude oil equivalent (per Boe)	57.81		49.23		17	%	53.90		30.19		79	%

Average Costs and Expenses (per Boe):
Lease operating expense	$	3.30	$	3.02	9	%	$	3.17	$	2.54	25	%
Production taxes	4.17		3.51		19	%	3.87		1.70		128	%
Transportation, gathering and processing expense	1.38		1.56		(12)	%	1.46		1.44		1	%
General and administrative expense	2.13		1.90		12	%	2.03		1.98		3	%
Depreciation, depletion and amortization	8.92		8.43		6	%	8.70		9.32		(7)	%

Lease Operating Expense by Operating Region (per Boe)
Wattenberg Field	$	2.85	$	2.42	18	%	$	2.65	$	2.23	19	%
Delaware Basin	5.98		6.67		(10)	%	6.29		4.77		32	%

____________

~~PDC ENERGY, INC.~~

Three Months Ended Percent Change Between
March 31, 2022 December 31, 2021 March 31, 2021
March 31, 2022 -
December 31, 2021
March 31, 2022 - March 31, 2021
(dollars in millions, except per unit data)
Lease Operating Expense by Operating Region (per Boe)
Wattenberg Field $ 2.42 $ 2.17 $ 2.31 12 % 5 %
Delaware Basin 6.67 5.42 5.27 23 % 27 %

~~____________~~

* Percent change is not meaningful.

PDC ENERGY, INC.

As a result of non-recurring costs incurred during the second quarter of 2022 to acquire Great Western and integrate it into our operations, our results of operations are not indicative of future results of operations for the second half of 2022. Additionally, we anticipate increases in production volumes and production cost per Boe as the integration of Great Western continues. Further, we expect increases in DD&A per Boe due to the fair value of Great Western’s crude oil and natural gas properties and a decrease in general and administrative expenses as acquisition transaction and transition costs wind down after the integration. Lastly, we expect interest expense to increase in the second half of 2022 as a result of our increased level of borrowings under our revolving credit facility resulting from the funding of the Great Western Acquisition and an overall increase in market interest rates.

Crude Oil, Natural Gas and NGLs Sales

The change in crude oil, natural gas and NGLs sales for the three months ended ~~March 31,~~June 30, 2022 compared to the three months ended ~~December~~March 31, ~~2021~~2022 and ~~March 31,~~the six months ended June 30, 2022 compared to the six months ended June 30, 2021 were due to the following:


		Change Between					Change Between
		March 31, 2022 - December 31, 2021		March 31, 2022 - March 31, 2021			March 31, 2022 - June 30, 2022		June 30, 2021 - June 30, 2022
		(in millions)					(in millions)
Change in:	Change in:					Change in:
Production	Production	$	(63.9)	$	78.6	Production	$	166.3	$	215.1

Average crude oil price	Average crude oil price	102.0		220.0		Average crude oil price	97.9		517.1
Average natural gas price	Average natural gas price	(13.5)		49.7		Average natural gas price	89.3		227.8
Average NGLs price	Average NGLs price	9.6		66.0		Average NGLs price	1.8		158.8
Total change in crude oil, natural gas and NGLs sales revenue	Total change in crude oil, natural gas and NGLs sales revenue	$	34.2	$	414.3	Total change in crude oil, natural gas and NGLs sales revenue	$	355.3	$	1,118.8

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			Percent Change Between					Three Months Ended				Six Months Ended
Production by Operating Region	Production by Operating Region	March 31, 2022	December 31, 2021	March 31, 2021	March 31, 2022 - December 31, 2021		March 31, 2022 - March 31, 2021		Production by Operating Region	June 30, 2022	March 31, 2022	Percent Change		June 30, 2022	June 30, 2021	Percent Change
Crude oil (MBbls)	Crude oil (MBbls)								Crude oil (MBbls)
Wattenberg Field	Wattenberg Field	4,832	5,306	4,173	(9)	%	16	%	Wattenberg Field	5,545	4,832	15	%	10,377	8,670	20	%
Delaware Basin	Delaware Basin	1,021	1,019	684	—	%	49	%	Delaware Basin	1,299	1,021	27	%	2,320	1,578	47	%
Total	Total	5,853	6,325	4,857	(7)	%	21	%	Total	6,844	5,853	17	%	12,697	10,248	24	%
Natural gas (MMcf)	Natural gas (MMcf)								Natural gas (MMcf)
Wattenberg Field	Wattenberg Field	37,663	40,870	35,561	(8)	%	6	%	Wattenberg Field	43,244	37,663	15	%	80,907	73,742	10	%
Delaware Basin	Delaware Basin	5,456	6,163	4,591	(11)	%	19	%	Delaware Basin	6,573	5,456	20	%	12,029	9,770	23	%
Total	Total	43,119	47,033	40,152	(8)	%	7	%	Total	49,817	43,119	16	%	92,936	83,512	11	%
NGLs (MBbls)	NGLs (MBbls)								NGLs (MBbls)
Wattenberg Field	Wattenberg Field	4,291	4,615	3,800	(7)	%	13	%	Wattenberg Field	5,575	4,291	30	%	9,866	8,153	21	%
Delaware Basin	Delaware Basin	594	626	392	(5)	%	52	%	Delaware Basin	688	594	16	%	1,282	844	52	%
Total	Total	4,885	5,241	4,192	(7)	%	17	%	Total	6,263	4,885	28	%	11,148	8,997	24	%
Crude oil equivalent (MBoe)	Crude oil equivalent (MBoe)								Crude oil equivalent (MBoe)
Wattenberg Field	Wattenberg Field	15,400	16,732	13,900	(8)	%	11	%	Wattenberg Field	18,328	15,400	19	%	33,728	29,113	16	%
Delaware Basin	Delaware Basin	2,524	2,673	1,840	(6)	%	37	%	Delaware Basin	3,082	2,524	22	%	5,607	4,051	38	%
Total	Total	17,924	19,405	15,740	(8)	%	14	%	Total	21,410	17,924	19	%	39,335	33,164	19	%

Average crude oil equivalent per day (Boe)									Average crude oil equivalent per day (Boe)
Wattenberg Field									Wattenberg Field	201,407	171,111	18	%	186,342	160,846	16	%
Delaware Basin									Delaware Basin	33,868	28,045	21	%	30,978	22,381	38	%
Total									Total	235,275	199,156	18	%	217,320	183,227	19	%

2729

PDC ENERGY, INC.

Three Months Ended Percent Change Between
Production by Operating Region March 31, 2022 December 31, 2021 March 31, 2021 March 31, 2022 -
December 31, 2021 March 31, 2022 - March 31, 2021
Average crude oil equivalent per day (Boe)
Wattenberg Field 171,111 181,870 154,444 (6) % 11 %
Delaware Basin 28,045 29,054 20,445 (3) % 37 %
Total 199,156 210,924 174,889 (6) % 14 %

Net production volumes for oil, natural gas and NGLs decreased 8 percent during the three months ended March 31, 2022 compared to the three months ended December 31, 2021 primarily due to the timing of wells turned-in-line in both basins and two fewer days in the first quarter of 2022 as well as normal decline in production from our existing wells.

Net production volumes for oil, natural gas and NGLs increased 1419 percent during the three months ended June 30, 2022 compared to the three months ended March 31, 2022 primarily due to 3.0 MMboe of additional production volumes from the Great Western Acquisition and the net impact of turn-in-line activities in both basins during the second quarter of 2022.

Net production volumes for oil, natural gas and NGLs increased 19 percent during the six months ended June 30, 2022 compared to the same period in 2021. The increase in production volume between periods was primarily due to ~~a greater number~~3.0 MMboe of ~~wells turned-in-line~~additional production volumes from the Great Western Acquisition and the net impact of turn-in-line activities in both basins since the ~~first~~second quarter of ~~2021 and a loss in production 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 March 31, 2022
Crude Oil Natural Gas NGLs Total
Wattenberg Field 31% 41% 28% 100%
Delaware Basin 40% 36% 24% 100%
Three Months Ended December 31, 2021
Crude Oil Natural Gas NGLs Total
Wattenberg Field 32% 41% 27% 100%
Delaware Basin 38% 38% 24% 100%
Three Months Ended March 31, 2021
Crude Oil Natural Gas NGLs Total
Wattenberg Field 30% 43% 27% 100%
Delaware Basin 37% 42% 21% 100%

~~Our production mix in both operating regions remained relatively consistent between all periods.~~


	Three Months Ended June 30, 2022
	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	30%	39%	31%	100%
Delaware Basin	42%	36%	22%	100%

	Three Months Ended March 31, 2022
	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	31%	41%	28%	100%
Delaware Basin	40%	36%	24%	100%

	Six Months Ended June 30, 2022
	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	31%	40%	29%	100%
Delaware Basin	41%	36%	23%	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%

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, preventative routine maintenance 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 ~~three~~six months ended ~~March 31,~~June 30, 2022. We continuously monitor infrastructure capacities versus producer activity and production volume forecasts. Continued increases in crude oil and natural gas prices

~~PDC ENERGY, INC.~~

through early 2022 have incentivized producers in the Permian Basin to increase the level of drilling and completion activities. The potential increase in production levels may lead to natural gas transportation constraints out of the Permian Basin by the end of 2022 ~~through~~or in 2023, which may result to lower realized ~~WAHA~~Waha natural gas prices. However, a majority of PDC’s gas production in the Delaware Basin is dedicated to Permian Highway Pipeline and is exposed to Houston-based gas pricing.

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.

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

Three Months Ended Percent Change Between
Weighted Average Realized Sales Price by Operating Region March 31, 2022 December 31, 2021 March 31, 2021 March 31, 2022 -
December 31, 2021 March 31, 2022 - March 31, 2021
(excluding net settlements on derivatives)
Crude oil (per Bbl)
Wattenberg Field $ 93.52 $ 76.59 $ 56.54 22 % 65 %
Delaware Basin 95.86 76.05 55.13 26 % 74 %
Weighted-average price 93.93 76.50 56.34 23 % 67 %
Natural gas (per Mcf)
Wattenberg Field $ 3.82 $ 4.18 $ 2.73 (9) % 40 %
Delaware Basin 3.56 3.53 1.88 1 % 89 %
Weighted-average price 3.78 4.10 2.63 (8) % 44 %
NGLs (per Bbl)
Wattenberg Field $ 32.37 $ 31.52 $ 20.47 3 % 58 %
Delaware Basin 51.54 41.74 28.23 23 % 83 %
Weighted-average price 34.70 32.74 21.19 6 % 64 %
Crude oil equivalent (per Boe)
Wattenberg Field $ 47.69 $ 43.19 $ 29.55 10 % 61 %
Delaware Basin 58.59 46.93 31.17 25 % 88 %
Weighted-average price 49.23 43.71 29.74 13 % 66 %


	Three Months Ended						Six Months Ended
Weighted Average Realized Sales Price by Operating Region	June 30, 2022		March 31, 2022		Percent Change		June 30, 2022		June 30, 2021		Percent Change
(excluding net settlements on derivatives)
Crude oil (per Bbl)
Wattenberg Field	$	108.05	$	93.52	16	%	$	101.28	$	60.84	66	%
Delaware Basin	109.06		95.86		14	%	103.25		61.35		68	%
Weighted average price	108.24		93.93		15	%	101.64		60.92		67	%
Natural gas (per Mcf)
Wattenberg Field	$	5.50	$	3.82	44	%	$	4.71	$	2.33	102	%
Delaware Basin	6.09		3.56		71	%	4.94		2.02		145	%
Weighted average price	5.57		3.78		47	%	4.74		2.29		107	%
NGLs (per Bbl)
Wattenberg Field	$	32.56	$	32.37	1	%	$	32.48	$	19.78	64	%
Delaware Basin	54.62		51.54		6	%	53.19		28.65		86	%
Weighted average price	34.99		34.70		1	%	34.86		20.61		69	%
Crude oil equivalent (per Boe)
Wattenberg Field	$	55.57	$	47.69	17	%	$	51.97	$	29.56	76	%
Delaware Basin	71.13		58.59		21	%	65.48		34.75		88	%
Weighted average price	57.81		49.23		17	%	53.90		30.19		79	%

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.

PDC ENERGY, INC.

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

~~PDC ENERGY, INC.~~

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


Three Months Ended June 30, 2022	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)	$	108.41	$	108.24	100	%	$	2.37	$	105.87	98	%
Natural gas (per MMBtu)	7.17		5.58		78	%	0.22		5.36		75	%
NGLs (per Bbl)	108.41		34.99		32	%	—		34.99		32	%
Crude oil equivalent (per Boe)	83.05		57.81		70	%	1.26		56.55		68	%

Three Months Ended March 31, 2022	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)	$	94.29	$	93.93	100	%	$	2.69	$	91.24	97	%
Natural gas (per MMBtu)	4.95		3.78		76	%	0.23		3.55		72	%
NGLs (per Bbl)	94.29		34.70		37	%	—		34.70		37	%
Crude oil equivalent (per Boe)	68.40		49.23		72	%	1.42		47.81		70	%

Six Months Ended June 30, 2022	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)	$	101.35	$	101.65	100	%	$	2.52	$	99.13	98	%
Natural gas (per MMBtu)	6.06		4.74		78	%	0.22		4.52		75	%
NGLs (per Bbl)	101.35		34.86		34	%	—		34.86		34	%
Crude oil equivalent (per Boe)	75.76		53.90		71	%	1.33		52.57		69	%

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	%

____________

Three Months Ended March 31, 2022 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) $ 94.29 $ 93.93 100 % $ 2.69 $ 91.24 97 %
Natural gas (per MMBtu) 4.95 3.78 76 % 0.23 3.55 72 %
NGLs (per Bbl) 94.29 34.70 37 % — 34.70 37 %
Crude oil equivalent (per Boe) 68.40 49.23 72 % 1.42 47.81 70 %
Three Months Ended December 31, 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) $ 77.19 $ 76.50 99 % $ 2.72 $ 73.78 96 %
Natural gas (per MMBtu) 5.50 4.10 75 % 0.13 3.97 72 %
NGLs (per Bbl) 77.19 32.74 42 % — 32.74 42 %
Crude oil equivalent (per Boe) 59.33 43.71 74 % 1.19 42.52 72 %
Three Months Ended March 31, 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) $ 57.84 $ 56.34 97 % $ 3.32 $ 53.02 92 %
Natural gas (per MMBtu) 2.69 2.63 98 % 0.11 2.52 94 %
NGLs (per Bbl) 57.84 21.19 37 % — 21.19 37 %
Crude oil equivalent (per Boe) 40.12 29.74 74 % 1.32 28.42 71 %

~~____________~~

(1)Average TGP expense excludes unutilized firm transportation fees of ~~$0.14 per Boe, $0.15~~$0.12 per Boe and ~~$0.06~~$0.14 per ~~BOE~~Boe for the three months ended June 30, 2022 and March 31, 2022, ~~December 31,~~respectively, and 0.13 and $0.12 per Boe for the six months ended June 30, 2022 and 2021, ~~and March 31, 2021,~~ respectively.

Our average realization percentages for crude oil, natural gas and NGLs were relatively flat for the three months ended ~~March 31,~~June 30, 2022 as compared to the three months ended ~~December~~March 31, ~~2021.~~2022.

Our average realization percentage for crude oil increased for the ~~three~~six months ended ~~March 31,~~June 30, 2022 as compared to the same period in 2021 primarily due to an increased demand for crude oil, ~~due to the containment of COVID-19.~~global supply disruptions and geopolitical issues. In

PDC ENERGY, INC.

addition, we realized improved differentials from our 2022 crude oil sales contracts. Average realization percentage for natural gas decreased for the ~~three~~six months ended ~~March 31,~~June 30, 2022 compared to the ~~three~~six months ended ~~March 31,~~June 30, 2021 due to strong pricing in February 2021 as a result of severe weather conditions.

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 ~~March 31,~~June 30, 2022.

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.

~~PDC ENERGY, INC.~~

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
March 31, 2022 December 31, 2021 March 31, 2021
(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil collars and fixed price exchanges $ (131.1) $ (122.7) $ (20.5)
Natural gas collars and fixed price exchanges (28.1) (80.0) (2.8)
Natural gas basis protection exchanges (2.3) 7.9 (7.4)
Total net settlements of commodity derivative instruments (161.5) (194.8) (30.7)
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments 100.2 198.5 (0.7)
Crude oil collars and fixed price exchanges (373.6) (38.9) (137.8)
Natural gas collars and fixed price exchanges (140.6) 46.7 (2.1)
Natural gas basis protection exchanges 7.4 (5.8) (10.0)
Net change in fair value of unsettled commodity derivative instruments (406.6) 200.5 (150.6)
Total commodity price risk management gain (loss), net $ (568.1) $ 5.7 $ (181.3)


	Three Months Ended				Six Months Ended
	June 30, 2022		March 31, 2022		June 30, 2022		June 30, 2021
	(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil collars and fixed price exchanges	$	(231.4)	$	(131.1)	$	(362.5)	$	(68.4)
Natural gas collars and fixed price exchanges	(75.7)		(28.1)		(103.8)		(7.5)
Natural gas basis protection exchanges	8.4		(2.3)		6.1		(9.9)
Total net settlements of commodity derivative instruments	(298.7)		(161.5)		(460.2)		(85.8)
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments	173.9		100.2		174.9		(5.4)
Crude oil collars and fixed price exchanges	(6.6)		(373.6)		(308.0)		(329.5)
Natural gas collars and fixed price exchanges	41.4		(140.6)		(71.0)		(67.7)
Natural gas basis protection exchanges	(12.0)		7.4		(5.7)		(1.1)
Net change in fair value of unsettled commodity derivative instruments	196.7		(406.6)		(209.8)		(403.7)
Total commodity price risk management gain (loss), net	$	(102.0)	$	(568.1)	$	(670.0)	$	(489.5)

The continued increase in commodity prices during the three months ended June 30, 2022 and March 31, 2022 ~~December 31, 2021~~ and ~~March 31,~~during the six months ended June 30, 2022 and June 30, 2021 had an overall unfavorable impact on the fair value and settlements of our commodity derivatives.

PDC ENERGY, INC.

Lease Operating Expense

Lease operating expense (“LOE”) increased by 730 percent to $70.6 million for the three months ended June 30, 2022 compared to $54.2 million for the three months ended March 31, ~~2022 compared to $50.8 million for the three months ended December 31, 2021.~~2022. The period-over-period increase in LOE was primarily attributable to (i) an approximate $7.0 million increase as a ~~$1.7~~result of the Great Western Acquisition, (ii) a $4.8 million increase in ~~workover expense due to the timing~~water disposal, well and pumper services in both basins as a result of ~~workover activities in the Delaware Basin~~higher commodity prices and ~~$1.5~~inflation and (iii) $1.8 million in additional ~~chemical treatments and power~~environmental costs in ~~both basins.~~the Wattenberg basin. LOE per Boe increased 159 percent to $3.30 for the three months ended June 30, 2022 from $3.02 for the three months ended March 31, ~~2022 from $2.62 for the three months ended December 31, 2021.~~2022. The increase isin LOE per Boe was primarily ~~driven by~~due to the ~~cost increases~~additional costs outlined ~~above as well as a decrease in production of 8 percent period-over-period.~~above.

LOE increased by 3048 percent to ~~$54.2~~$124.8 million for the ~~three~~six months ended ~~March 31,~~June 30, 2022 compared to ~~$41.8~~$84.2 million for the ~~three~~six months ended ~~March 31,~~June 30, 2021. The period-over-period increase in LOE was primarily due to (i) a $7.0 million increase a as a result of the Great Western Acquisition, (ii) increased activities and payroll costs of ~~$4.8~~$12.8 million ~~at our operated and non-operated well locations~~ resulting from an increase in ~~completion~~ activities in both basins, ~~(ii) a $3.2~~(iii) an $11.4 million increase in chemical treatments, water disposal and environmental costs as a result of higher commodity prices and ~~regulatory costs~~inflation and ~~(iii)~~(iv) a ~~$2.4~~$6.2 million increase in workover expense due to the timing of workover activities focused mainly in the Delaware Basin. LOE per Boe increased 1425 percent to ~~$3.02~~$3.17 for the ~~three~~six months ended ~~March 31,~~June 30, 2022 from ~~$2.66~~$2.54 for the ~~three~~six months ended ~~March 31, 2021.~~

June 30, 2021, an increase that was primarily due to the additional costs outlined above.

~~PDC ENERGY, INC.~~

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 ~~decreased 2~~increased 42 percent to $89.3 million for the three months ended June 30, 2022 compared to $62.9 million for the three months ended March 31, ~~2022 compared~~2022. Production taxes per Boe increased 19 percent to ~~$64.1 million~~$4.17 for the three months ended ~~December 31, 2021. Production taxes per Boe increased 6 percent~~June 30, 2022 compared to $3.51 for the three months ended March 31, ~~2022 compared to $3.30 for the three months ended December 31, 2021.~~2022. The increase in production taxes ~~per Boe~~ was primarily due to ~~an increase in~~additional production volumes from the Great Western Acquisition and higher crude oil, natural gas and ~~NGLs~~NGL prices between periods.

Production taxes increased ~~113~~170 percent to ~~$62.9~~$152.2 million for the ~~three~~six months ended ~~March 31,~~June 30, 2022 compared to ~~$29.5~~$56.5 million for the ~~three~~six months ended ~~March 31,~~June 30, 2021. Production taxes per Boe increased 88128 percent to ~~$3.51~~$3.87 for the ~~three~~six months ended ~~March 31,~~June 30, 2022 compared to ~~$1.87~~$1.70 for the ~~three~~six months ended ~~March 31,~~June 30, 2021. The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs prices between ~~periods.~~

periods and additional production from the Great Western Acquisition.

Transportation, Gathering and Processing Expense

TGP expense increased 86 percent to $29.6 million for the three months ended June 30, 2022 compared to $28.0 million for the three months ended March 31, ~~2022 compared~~2022. The increase in TGP expense between periods was primarily due to ~~$26.0~~a $1.7 million increase relating to additional production volumes from the Great Western Acquisition. TGP expense per Boe decreased 12 percent to $1.38 for the three months ended ~~December 31, 2021. TGP expense per Boe increased 16 percent~~June 30, 2022 compared to $1.56 for the three months ended March 31, 2022. The decrease in TGP expense per Boe between periods was primarily due to lower TGP rates on the acquired Great Western production.

TGP expense increased 21 percent to $57.6 million for the six months ended June 30, 2022 compared to ~~$1.34~~$47.7 million for the ~~three~~six months ended ~~December 31,~~June 30, 2021. The increase in TGP expense between periods was primarily due to ana $1.7 million increase relating to additional production volumes from the Great Western Acquisition in 2022 and a $10.5 million increase relating to gas processing ~~costs~~volumes and rates in the Delaware ~~Basin between periods.~~

basin. TGP expense per Boe increased 291 percent to ~~$28.0 million~~$1.46 for the ~~three~~six months ended ~~March 31,~~June 30, 2022 compared to ~~$21.7 million~~$1.44 for the ~~three~~six months ended ~~March 31,~~June 30, 2021. TGP expense per Boe ~~increased 13 percent to $1.56~~ for the ~~three~~six months ended ~~March 31, 2022 compared to $1.38 for the three months ended March 31, 2021. The overall increase in TGP expense for the three months ended March 31,~~June 30, 2022 compared to the same period in 2021 was ~~driven~~relatively flat due to the net impact of lower TGP rates on the acquired Great Western production offset by ~~a $5.6 million increase relating to~~higher gas processing ~~costs and a $1.8 million increase in shortfall fees relating to our delivery commitment, both in the Delaware Basin.~~costs.

PDC ENERGY, INC.

Impairment of Properties and Equipment

There were no significant impairment charges recognized related to our proved and unproved oil and gas properties ~~during~~for the three months ended June 30, 2022 or March 31, 2022 ~~December 31, 2021, and March 31,~~or for the six months ended June 30, 2022 or 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.

General and Administrative Expense

General and administrative expense ~~slightly~~ increased 934 percent to $45.6 million for the three months ended June 30, 2022 compared to $34.1 million for the three months ended March 31, 2022, ~~compared to $31.4 million for the three months ended December 31, 2021,~~ primarily due to ~~an increase~~$13.0 million in ~~charitable contributions~~transaction and ~~an increase~~transition costs recognized in ~~professional fees~~the second quarter of 2022 relating to the Great Western ~~Acquisition in the first quarter of 2022.~~

Acquisition.

General and administrative expense ~~remained relatively flat with an increase of 4~~increased 22 percent to ~~$34.1~~$79.8 million for the ~~three~~six months ended ~~March 31,~~June 30, 2022 compared to ~~$32.7~~$65.5 million for the ~~three~~six months ended ~~March 31, 2021.~~

June 30, 2021, primarily due to $13.0 million in transaction and transition costs recognized in the second quarter of 2022 relating to the Great Western Acquisition.

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 $189.1 million for the three months ended June 30, 2022 compared to $149.3 million for the three months ended March 31, ~~2022 compared to $154.7 million for the three months ended December 31, 2021.~~2022. The ~~decrease~~increase in DD&A expense wasprimarily due to ~~an 8~~(i) a 19 percent ~~decrease~~increase in production volumes between periods, ~~partially offset by~~(ii) an increase in the weighted average DD&A expense rate ~~as a result~~primarily due to the fair value of proved crude oil and natural gas properties acquired from Great Western and (iii) capitalized costs offor wells turned-in-line in the ~~first~~second quarter of 2022.

~~PDC ENERGY, INC.~~

DD&A expense related to crude oil and natural gas properties was ~~$149.3~~$338.4 million for the ~~three~~six months ended ~~March 31,~~June 30, 2022 compared to ~~$144.8~~$305.0 million for the comparable period in 2021. The increase in total DD&A expense was primarily due to a 1419 percent increase in production volumes between periods ~~primarily due to a greater number of~~and capitalized costs for wells turned-in-line since the second quarter of 2021 partially offset bya decrease in ~~the~~ weighted average DD&A expense ~~rate.~~

rate resulting from our improved reserve quantities as of December 31, 2021.

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

Change Between
March 31, 2022 -
December 31, 2021
March 31, 2022 - March 31, 2021
(in millions)
Increase (decrease) in production $ (11.7) $ 20.0
Increase (decrease) in weighted-average depreciation, depletion and amortization rates 6.3 (15.5)
Total increase (decrease) in DD&A expense related to crude oil and natural gas properties $ (5.4) $ 4.5


	Change Between
	March 31, 2022 - June 30, 2022		June 30, 2021 - June 30, 2022
	(in millions)
Increase (decrease) in production	$	29.2	$	57.4
Increase (decrease) in weighted average depreciation, depletion and amortization rates	10.7		(24.0)
Total increase (decrease) in DD&A expense related to crude oil and natural gas properties	$	39.9	$	33.4

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				Three Months Ended						Six Months Ended
		March 31, 2022		December 31, 2021			March 31, 2021			June 30, 2022		March 31, 2022		June 30, 2022		June 30, 2021
		(per Boe)				(per Boe)
Operating Region/Area	Operating Region/Area								Operating Region/Area
Wattenberg Field	Wattenberg Field	$	8.00	$	7.70		$	9.22	Wattenberg Field	$	8.52	$	8.00	$	8.28	$	9.10
Delaware Basin	Delaware Basin	10.33		9.71			9.01		Delaware Basin	10.68		10.33		10.52		9.89
Total weighted average DD&A expense rate	Total weighted average DD&A expense rate	8.33		7.97			9.20		Total weighted average DD&A expense rate	8.83		8.33		8.60		9.20

PDC ENERGY, INC.

Interest Expense, net

Interest expense, net ~~decreased $10.6~~increased$4.6 million to $17.6 million for the three months ended June 30, 2022 compared to $12.9 million for the three months ended March 31, ~~2022 compared to $23.5 million for the three months ended December 31, 2021.~~2022. The ~~decrease~~increase was primarily ~~related~~due to ~~(i) reduced~~a $5.4 million increase relating to increased borrowings under our revolving credit facility ~~between periods, (ii)~~in the second quarter of 2022 to finance the cash portion of the purchase price of the Great Western Acquisition.

Interest expense, net decreased $8.6 million to $30.5 million for the six months ended June 30, 2022 compared to $39.1 million for the six months ended June 30, 2021. The decrease was primarily due to a $6.0 million decrease from the expiration and redemption of our 2021 Convertible Notes in September 2021 and a $9.3 million decrease from the full redemption of our 2025 Senior Notes and a partial redemption of our 2024 Senior Notes in December and November 2021, ~~respectively, and (iii) a $6.9 million loss on extinguishment recognized in the fourth quarter of 2021 as a result of aforementioned redemptions of our Senior Notes.~~

~~Interest expense, net decreased $6.1 million to $12.9 million for the three months ended March 31, 2022 compared to $19.0 million for the three months ended March 31, 2021.~~respectively. The decrease was ~~primarily related~~partially offset by $5.5 million relating to ~~(i) reduced~~increased borrowings under our revolving credit facility ~~between periods, (ii) expiration~~in 2022 to finance the cash portion of the purchase price of the Great Western Acquisition.

Gain on Bargain Purchase

We recognized a $100.3 million gain on the bargain purchase of the Great Western Acquisition, net of related income taxes of $31.5 million, for the three and ~~redemption of~~six months ended June 30, 2022. For additional information, see Note 2 - Business Combination to our ~~2021 Convertible Notes~~condensed consolidated financial statements included elsewhere in ~~September 2021, and (iii) a full redemption of our 2025 Senior Notes and a partial redemption of our 2024 Senior Notes in December and November 2021, respectively.~~

this report.

Provision for Income Taxes

We recorded income tax expense of ~~$1.2~~$128.0 million, ~~$26.5~~excluding our discrete gain on bargain purchase of $100.3 million, and ~~$0.1~~$1.2 million for the three months ended June 30, 2022 and March 31, 2022, ~~December 31, 2021, and March 31, 2021,~~respectively, resulting in an effective income tax rate of 18.5 percent provision on pre-tax income, and 3.9 percent provision on pre-tax losses, ~~5.3~~respectively.

We recorded income tax expense of $129.2 million, excluding our discrete gain on bargain purchase of $100.3 million, and $0.1 million for the six months ended June 30, 2022 and June 30, 2021, respectively, resulting in an effective income tax rate of 19.6 percent provision on pre-tax income, and ~~0.6~~0.2 percent provision on pre-tax losses, respectively. The effective tax rates differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to pre-tax loss due to the effect of athe valuation allowance or changes in the valuation allowance against our deferred income tax assets.

The ultimate realization of deferred tax assets (“DTAs”) is dependent upon the generation of future taxable income during the periods in which those temporary differences ~~become~~became deductible. At each reporting period, management considers

the ~~scheduled reversal of deferred tax liabilities,~~ available taxes in carryback periods, the future reversals of existing taxable temporary differences, tax planning strategies and projected future taxable income in making this assessment. Our oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to continue to provide a valuation allowance against our DTAs ~~as of December 31, 2021 and March 31, 2022~~beginning January 1, 2020, since we ~~cannot~~previously could not conclude that it is more likely than not that our DTAs will be fully realized in future periods.

~~PDC ENERGY, INC.~~

~~Future events or new~~During the period ended June 30, 2022, sufficient positive evidence ~~which may lead~~became available that allowed us to ~~conclude~~reach a conclusion that it is more likely than not that our 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. Given recent improvements in oil and gas prices and improvements~~the valuation allowance is no longer be needed. As we previously disclosed in our ~~current earnings,~~2021 Form 10-K, we ~~believe there is~~maintained a ~~reasonable possibility that, if oil~~valuation allowance on our net federal deferred tax assets and ~~natural gas prices remain similar~~would continue to ~~March 31, 2022 pricing levels,~~do so until sufficient positive evidence ~~may become available within~~exists to support a reversal of the ~~next 12 months~~allowance. In the second quarter, continued higher commodity prices have increased our income, resulting in the reversal of objective negative evidence of cumulative loss in recent years, and we determined that we have sufficient positive evidence to ~~allow us to reach~~release the valuation allowance. As a ~~conclusion that all or a significant portion~~result, we released $22.4 million of the valuation allowance ~~will no longer be needed. Release of the valuation allowance would result in the recognition of certain~~against our deferred income tax assets and recognized a corresponding decrease to income tax expense in the period ~~the release is recorded. However, the exact timing and amount~~ended June 30, 2022. The remainder of the valuation allowance ~~release are subject~~of $34.2 million will be recognized as a decrease to ~~change based on~~income taxes expense over the ~~level~~second half of ~~profitability that we actually achieve.~~

2022.

Given recent improvements in oil and gas prices and assumptions based on our current production forecasts, we

estimate that we will ~~begin to~~ incur significant cash federal and state income taxes ~~again later~~ in ~~2022 and~~ 2023.

PDC ENERGY, INC.

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

The factors impacting a net income of $662.4 million and a net loss of $32.0 million ~~net income of $473.1 million, and net loss of $9.0 million~~ for the three months ended June 30, 2022 and March 31, 2022, ~~December 31, 2021,~~respectively, and ~~March 31,~~a net income of $630.4 million and a net loss of $96.1 million for the six months ended June 30, 2022 and June 30, 2021, respectively, are discussed above.

Adjusted net income, a non-U.S. GAAP financial measure, was ~~$358.6 million, $283.1~~$502.1 million and ~~$141.6~~$358.6 million for the three months ended June 30, 2022 and March 31, 2022, ~~December 31, 2021,~~respectively, and ~~March 31,~~$798.2 million and $307.6 million for the six months ended June 30, 2022, and June 30, 2021, respectively. With the exception of the tax-affected net change in fair value of unsettled commodity derivatives, when applicable, 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 and cash equivalents, cash flows from operating activities, unused borrowing capacity from our revolving credit facility, proceeds raised in debt and equity capital market transactions, and other sources, such as asset sales.

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 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, capital returns 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 ~~March 31,~~June 30, 2022 is an indication of a lack of liquidity. We had working capital deficits of ~~$541.7~~$1,090.0 million as of ~~March 31,~~June 30, 2022 and $461.5 million as of December 31, 2021. The increase in working capital deficit since December 31, 2021 was primarily due to an increase in the fair value of net derivative liabilities of ~~$272.5~~$400.7 million and ~~an increase~~by a net deficit in ~~accounts payable~~working capital items as result of ~~$64.4 million partially offset by an increase in receivables of $138.5 million and an increase in cash and cash equivalents of $137.3 million.~~the Great Western Acquisition. 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.

~~PDC ENERGY, INC.~~

From time to time, we may 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.

Liquidity

Our cash and cash equivalents were ~~$171.2~~$38.5 million at ~~March 31,~~June 30, 2022 and availability under our revolving credit facility was ~~$1.5 billion,~~$724.6 million, providing for a total liquidity position of ~~$1.65 billion~~$763.1 million as of ~~March 31,~~June 30, 2022. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests.

Our material short-term and long-term cash requirements consist primarily of capital expenditures, payments of contractual obligations, dividends, share repurchases and working capital obligations. AsIf commodity prices continue to increase, our working capital requirements may increase due to higher operating costs and negative settlements on our outstanding commodity derivative contracts. Funding for these requirements may be provided by any combination of our capital resources previously outlined.

~~On February 26, 2022, we entered into the Acquisition Agreement to acquire Great Western for approximately $1.4 billion, inclusive~~

PDC ENERGY, INC.

As a result of ~~Great Western’s net debt. Under the terms of the Acquisition Agreement, the purchase consideration for~~ the Great Western Acquisition, ~~will be made through the transfer~~we paid $361.2 million on Great Western’s behalf to pay and discharge Great Western’s 12% senior secured notes due 2025, inclusive of ~~approximately 4.0~~unpaid accrued interest and a premium for early termination. Additionally, we paid off Great Western’s secured credit facility totaling $235.7 million, ~~shares~~inclusive of ~~our common stock and approximately $543 million in cash.~~unpaid accrued interest. The ~~cash portion~~termination of ~~the purchase price is expected to be~~Great Western’s debt was funded through a combination of cash on hand and availability under our revolving credit facility. ~~We anticipate that the Great Western Acquisition will be completed in May 2022, subject to certain customary closing conditions being met.~~

Upon closing the Great Western Acquisition, we will be required to pay off and terminate Great Western’s revolving credit facility, which had an outstanding balance of approximately $227.0 million as of March 31, 2022. At closing, we are also expecting to pay off Great Western’s $311.9 million of 12.0% Senior Notes due September 1, 2025, plus a redemption premium. The payments of the debt balances is expected to be funded through the availability under our revolving credit facility.

Based on our current production forecast for 2022, we expect 2022 cash flows from operations, which are net of expected cash federal and state income taxes, to exceed our capital investments in crude oil and natural gas properties. In addition, 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 fund our planned activities through the 12-month period following the filing of this report. We also believe that we will have sufficient expected cash flows from operations to allow us to execute our capital return plan. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board.

Our material cash requirements greater than twelve months from various contractual and other obligations include debt obligations and interest payments; commodity derivative contract liabilities; production taxes; operating and finance leases; asset retirement obligations; and firm transportation and processing agreements. There are no significant changes to our material cash requirements arising from contractual obligations since December 31, 2021.

In April 2022, as part of our 2022 semi-annual borrowing base redetermination, the borrowing base increased from $2.4 billion to $3.0 billion; however, we maintained our elected commitment amount of $1.5 billion. 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 (a) to maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 3.5:1.0. 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 ~~March 31,~~June 30, 2022, we were in compliance with all covenants in the revolving credit facility with a current ratio of ~~3.1:~~1.3:1.0 and a leverage ratio of ~~0.4:~~0.7:1.0.

~~PDC ENERGY, INC.~~

In April 2022, as part of our credit facility 2022 semi-annual redetermination, our borrowing base increased from $2.4 billion to $3.0 billion; however, we maintained our elected commitment amount of $1.5 billion.

We expect to remain in compliance with the covenants under our credit facility and our Senior Notes throughout the 12-month period following the filing of this report.

Cash Flows

Our cash flows from operating, investing and financing activities are as follows:

Three Months Ended
March 31, 2022 March 31, 2021
(in thousands)
Cash flows from operating activities $ 489,048 $ 353,059
Cash flows from investing activities (236,534) (104,747)
Cash flows from financing activities (115,186) (191,868)
Net increase (decrease) in cash and cash equivalents $ 137,328 $ 56,444


	Six Months Ended
	June 30, 2022		June 30, 2021
	(in thousands)
Cash flows from operating activities	$	1,236,381	$	577,366
Cash flows from investing activities	(1,606,459)		(236,126)
Cash flows from financing activities	382,907		(234,114)
Net increase (decrease) in cash and cash equivalents	$	12,829	$	107,126

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 by ~~$136.0~~$659.0 million to ~~$489.0~~$1,236.4 million during the ~~three~~six months ended ~~March 31,~~June 30, 2022 compared to ~~$353.1~~$577.4 million during the ~~three~~six months ended ~~March 31,~~June 30, 2021. The increase between periods was primarily due to a ~~$414.3~~$1,118.8 million increase in revenue from crude oil, natural gas and NGLs sales and the timing of vendor payments. These increases were partially offset by a ~~$130.9~~$374.5 million increase in derivative settlement losses, a ~~$33.4~~$95.7 million increase in production taxes and the timing of receivable collections between periods.

PDC ENERGY, INC.

Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by ~~$238.8~~$590.5 million to ~~$538.8~~$1,233.5 million during the ~~three~~six months ended ~~March 31,~~June 30, 2022 from ~~$300.0~~$643.0 million during the ~~three~~six months ended ~~March 31,~~June 30, 2021. 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 ~~$143.1~~$381.1 million during the ~~three~~six months ended ~~March 31,~~June 30, 2022 to ~~$318.7~~$722.5 million compared to ~~$175.6~~$341.4 million during the ~~three~~six months ended ~~March 31,~~June 30, 2021. The increase between periods was primarily due to the increase in cash flows from operating activities, as discussed above, partially offset by an increase in capital investments in crude oil and natural gas properties as a result of our 2022 development ~~plan.~~

plan and the Great Western Acquisition.

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 crude oil and natural 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 ~~$236.5~~$1,606.5 million during the ~~three~~six months ended ~~March 31,~~June 30, 2022 was primarily due to $1,068.2 million related to the closing of the Great Western Acquisition as well as our drilling and completion activities of ~~$187.0~~$533.6 million ~~and a $50.0 million deposit in escrow relating to the Great Western Acquisition.~~. Net cash used in investing activities of ~~$104.7~~$236.1 million during the ~~three~~six months ended ~~March 31,~~June 30, 2021 was primarily related to our drilling and completion activities of ~~$109.0~~$240.3 million, partially offset by $4.4 million in proceeds from the sale of certain properties and equipment.

Financing Activities. Net cash used in financing activities of ~~$115.2~~$382.9 million during the ~~three~~six months ended ~~March 31,~~June 30, 2022 was primarily due to (i) net borrowings from our credit facility of $755.0 million to fund the cash portion of the purchase price of the Great Western Acquisition and to terminate Great Western’s debt, (ii) the repurchase of ~~1.3 million~~4.3 shares of our common stock for ~~$80.9~~$295.0 million pursuant to our stock repurchase program and (iii) dividend payments totaling ~~$24.7~~$59.2 million. Repurchases of our common stock may extend through the

~~PDC ENERGY, INC.~~

end of 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 ~~March 31,~~June 30, 2022, ~~$1.19 billion~~$978.1 million out of the approved $1.25 billion remained available for repurchases under the program. 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 ~~$191.9~~$234.1 million during the ~~three~~six months ended ~~March 31,~~June 30, 2021 was primarily due to net repayments to our credit facility of $168.0 million, ~~and~~ the repurchase and retirement of 1.3 million shares of our common stock totaling to ~~$21.1~~$47.7 million pursuant to our stock repurchase ~~program.~~

program and dividend payments totaling $11.9 million.

Subsidiary ~~Guarantor~~

Guarantors

PDC Permian, Inc., a Delaware corporation ~~(the “Guarantor”~~(“Permian”), ~~our~~and Pioneer Water Pipeline LLC, a Delaware limited liability company (“Pioneer” and together with “Permian”, the “Guarantors”), each a wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes and 2026 Senior Notes (collectively, the “Senior Notes”). The ~~Guarantor~~Permian holds our assets located in the Delaware Basin. Pioneer holds certain water midstream assets located in the Wattenberg Basin. The Senior Notes are fully and unconditionally guaranteed on a joint and several basis by the ~~Guarantor.~~Guarantors. 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.

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/Three Months Ended				As of/Year Ended					As of/Six Months Ended				As of/Year Ended
		March 31, 2022				December 31, 2021					June 30, 2022				December 31, 2021
		Issuer		Guarantor		Issuer		Guarantor			Issuer		Guarantors		Issuer		Guarantor
		(in millions)									(in millions)
Assets	Assets									Assets
Current assets	Current assets	$	636.3	$	97.2	$	402.6	$	56.0	Current assets	$	678.2	$	110.1	$	402.6	$	56.0
Intercompany accounts receivable, guarantor subsidiary	Intercompany accounts receivable, guarantor subsidiary	—		74.8		—		40.8		Intercompany accounts receivable, guarantor subsidiary	—		161.8		—		40.8
Investment in guarantor subsidiary	Investment in guarantor subsidiary	1,766.8		—		1,767.2		—		Investment in guarantor subsidiary	1,767.2		—		1,767.2		—
Properties and equipment, net	Properties and equipment, net	3,896.0		990.2		3,875.0		939.9		Properties and equipment, net	6,070.7		1,017.1		3,875.0		939.9
Other non-current assets	Other non-current assets	106.6		4.9		58.5		4.8		Other non-current assets	95.0		5.2		58.5		4.8

Liabilities	Liabilities									Liabilities
Current liabilities	Current liabilities	$	1,173.2	$	102.1	$	862.5	$	57.6	Current liabilities	$	1,786.5	$	91.8	$	862.5	$	57.6
Intercompany accounts payable	Intercompany accounts payable	74.8		—		27.9		—		Intercompany accounts payable	161.8		—		27.9		—
Long-term debt	Long-term debt	942.6		—		942.1		—		Long-term debt	1,698.0		—		942.1		—
Other non-current liabilities	Other non-current liabilities	578.1		170.7		392.3		172.0		Other non-current liabilities	760.9		168.3		392.3		172.0

Statement of Operations	Statement of Operations									Statement of Operations
Crude oil, natural gas and NGLs sales	Crude oil, natural gas and NGLs sales	$	734.5	$	147.9	$	2,163.1	$	389.5	Crude oil, natural gas and NGLs sales	$	1,752.9	$	367.1	$	2,163.1	$	389.5
Commodity price risk management gain (loss), net	Commodity price risk management gain (loss), net	(568.1)		—		(701.5)		—		Commodity price risk management gain (loss), net	(670.0)		—		(701.5)		—
Total revenues	Total revenues	167.6		148.9		1,464.5		391.4		Total revenues	1,085.9		369.1		1,464.5		391.4
Production costs	Production costs	232.1		64.0		892.4		189.0		Production costs	534.5		142.1		892.4		189.0
Gross profit (1)	Gross profit (1)	502.4		83.9		1,270.7		200.4		Gross profit (1)	1,218.4		225.0		1,270.7		200.4
Impairment of properties and equipment	Impairment of properties and equipment	0.1		0.9		0.4		—		Impairment of properties and equipment	0.6		0.9		0.4		—
Net income (loss)	Net income (loss)	(114.4)		82.4		327.7		194.9		Net income (loss)	408.2		222.2		327.7		194.9

____________

(1)Gross profit is calculated as crude oil, natural gas and NGLs sales less production costs.

~~PDC ENERGY, INC.~~

Recent Accounting ~~Standards~~Pronouncements

There were no significant new accounting standards adopted or new accounting pronouncements that would have potential effect on us as of ~~March 31,~~June 30, 2022.

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 2021 Form 10-K filed with the SEC on February 28, 2022.

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PDC ENERGY, INC.

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 for the periods presented:


		Three Months Ended				Three Months Ended						Six Months Ended
		March 31, 2022		December 31, 2021			March 31, 2021			June 30, 2022		March 31, 2022		June 30, 2022		June 30, 2021
		(in millions)				(in millions)
Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow:	Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow:								Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow:
Net cash from operating activities	Net cash from operating activities	$	489.0	$	520.0		$	353.1	Net cash from operating activities	$	747.4	$	489.0	$	1,236.4	$	577.4
Changes in assets and liabilities	Changes in assets and liabilities	49.8		(46.9)			(53.1)		Changes in assets and liabilities	(52.7)		49.8		(2.9)		65.6
Adjusted cash flows from operations	Adjusted cash flows from operations	538.8		473.1			300.0		Adjusted cash flows from operations	694.7		538.8		1,233.5		643.0
Capital expenditures for development of crude oil and natural gas properties	Capital expenditures for development of crude oil and natural gas properties	(187.0)		(154.3)			(109.0)		Capital expenditures for development of crude oil and natural gas properties	(346.7)		(187.0)		(533.7)		(240.3)
Change in accounts payable related to capital expenditures for oil and gas development activities		(33.1)		20.7			(15.4)
Capital expenditures for midstream assets									Capital expenditures for midstream assets	(3.0)		—		(3.0)		—
Change in accounts payable related to capital expenditures for oil and gas development activities and midstream assets									Change in accounts payable related to capital expenditures for oil and gas development activities and midstream assets	58.8		(33.1)		25.7		(61.3)
Adjusted free cash flow	Adjusted free cash flow	$	318.7	$	339.5		$	175.6	Adjusted free cash flow	$	403.8	$	318.7	$	722.5	$	341.4

Net income (loss) to adjusted net income (loss):	Net income (loss) to adjusted net income (loss):								Net income (loss) to adjusted net income (loss):
Net income (loss)	Net income (loss)	$	(32.0)	$	473.1		$	(9.0)	Net income (loss)	$	662.4	$	(32.0)	$	630.4	$	(96.1)
Loss (gain) on commodity derivative instruments	Loss (gain) on commodity derivative instruments	568.1		(5.7)			181.3		Loss (gain) on commodity derivative instruments	102.0		568.1		670.0		489.5
Net settlements on commodity derivative instruments	Net settlements on commodity derivative instruments	(161.6)		(194.8)			(30.7)		Net settlements on commodity derivative instruments	(298.7)		(161.6)		(460.3)		(85.8)
Tax effect of above adjustments (1)	Tax effect of above adjustments (1)	(15.9)		10.5			—		Tax effect of above adjustments (1)	36.4		(15.9)		(41.9)		—
Adjusted net income (loss)	Adjusted net income (loss)	$	358.6	$	283.1		$	141.6	Adjusted net income (loss)	$	502.1	$	358.6	$	798.2	$	307.6

Net income (loss) to adjusted EBITDAX:	Net income (loss) to adjusted EBITDAX:								Net income (loss) to adjusted EBITDAX:
Net income (loss)	Net income (loss)	$	(32.0)	$	473.1		$	(9.0)	Net income (loss)	$	662.4	$	(32.0)	$	630.4	$	(96.1)
Loss (gain) on commodity derivative instruments	Loss (gain) on commodity derivative instruments	568.1		(5.7)			181.3		Loss (gain) on commodity derivative instruments	102.0		568.1		670.0		489.5
Net settlements on commodity derivative instruments	Net settlements on commodity derivative instruments	(161.6)		(194.8)			(30.7)		Net settlements on commodity derivative instruments	(298.7)		(161.6)		(460.3)		(85.8)
Non-cash stock-based compensation	Non-cash stock-based compensation	5.5		5.7			5.0		Non-cash stock-based compensation	7.2		5.5		12.8		11.5
Interest expense, net	Interest expense, net	12.9		23.5			19.0		Interest expense, net	17.6		12.9		30.5		39.1
Income tax expense (benefit)	Income tax expense (benefit)	1.2		26.5			0.1		Income tax expense (benefit)	128.0		1.2		129.2		(0.1)
Impairment of properties and equipment	Impairment of properties and equipment	0.9		0.1			0.2		Impairment of properties and equipment	0.5		0.9		1.5		0.3
Exploration, geologic and geophysical expense	Exploration, geologic and geophysical expense	0.3		0.2			0.4		Exploration, geologic and geophysical expense	0.3		0.3		0.6		0.6
Depreciation, depletion and amortization	Depreciation, depletion and amortization	151.1		156.6			146.8		Depreciation, depletion and amortization	191.1		151.1		342.1		309.0
Accretion of asset retirement obligations	Accretion of asset retirement obligations	3.0		2.9			3.1		Accretion of asset retirement obligations	3.4		3.0		6.3		6.4
Loss (gain) on sale of properties and equipment	Loss (gain) on sale of properties and equipment	(0.1)		(0.4)			(0.2)		Loss (gain) on sale of properties and equipment	0.5		(0.1)		0.4		(0.3)
Adjusted EBITDAX	Adjusted EBITDAX	$	549.3	$	487.7		$	316.0	Adjusted EBITDAX	$	814.3	$	549.3	$	1,363.5	$	674.1

Cash from operating activities to adjusted EBITDAX:	Cash from operating activities to adjusted EBITDAX:								Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities	Net cash from operating activities	$	489.0	$	520.0		$	353.1	Net cash from operating activities	$	747.4	$	489.0	$	1,236.4	$	577.4
Interest expense, net(2)		12.9		16.6			19.0
Gain on bargain purchase									Gain on bargain purchase	100.3		—		100.3		—
Interest expense, net									Interest expense, net	17.6		12.9		30.5		39.1
Amortization and write-off of debt discount, premium and issuance costs	Amortization and write-off of debt discount, premium and issuance costs	(1.4)		(2.3)			(3.8)		Amortization and write-off of debt discount, premium and issuance costs	(1.3)		(1.4)		(2.7)		(7.7)
Exploration, geologic and geophysical expense	Exploration, geologic and geophysical expense	0.3		0.2			0.4		Exploration, geologic and geophysical expense	0.3		0.3		0.6		0.6
Other	Other	(1.3)		0.1			0.4		Other	2.7		(1.3)		1.3		(0.9)
Changes in assets and liabilities	Changes in assets and liabilities	49.8		(46.9)			(53.1)		Changes in assets and liabilities	(52.7)		49.8		(2.9)		65.6
Adjusted EBITDAX	Adjusted EBITDAX	$	549.3	$	487.7		$	316.0	Adjusted EBITDAX	$	814.3	$	549.3	$	1,363.5	$	674.1

_____________

(1)Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the ~~three~~six months ended ~~March 31, 2021.~~

~~(2)Excludes loss on extinguishment from early retirement of our senior notes amounting to $6.9 million for the three months ended December 31,~~June 30, 2021.

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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 rate risks, commodity price risk and credit risk. Recent inflationary trends and the possibility of a recession could impact each of these market 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 2024 Senior Notes and 2026 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 ~~March 31,~~June 30, 2022, we had no$755.0 million outstanding borrowings under our revolving credit facility.

If market interest rates would have increased or decreased one percent, our interest expense for the six months ended June 30, 2022 would have changed by approximately $1.5 million.

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.

As of ~~March 31,~~June 30, 2022, we had a net liability derivative position of ~~$773.8~~$896.3 million related to our commodity price risk derivatives. Based on a sensitivity analysis as of ~~March 31,~~June 30, 2022, we estimate that a 10 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 ~~$114.2~~$222.7 million, whereas a ten percent decrease in prices would have resulted in a decrease in fair value of our net derivative liabilities of ~~$116.5~~$224.5 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 ~~March 31,~~June 30, 2022, 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 ~~March 31,~~June 30, 2022, 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 ~~March 31,~~June 30, 2022.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended ~~March 31,~~June 30, 2022 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~~Additional 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.

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. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. 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 ~~March 31,~~June 30, 2022 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.

Following a self-audit of final reclamation activities associated with site retirements, we formally disclosed identified deficiencies to the Colorado Oil and Gas Conservation Commission (“COGCC”) in December 2019. ~~In August 2020, the COGCC issued a Notice of Alleged Violation (“NOAV”) citing a failure to comply with reclamation requirements at multiple locations.~~ To resolve the ~~alleged violations~~matter, in July of 2021, the COGCC and PDC jointly agreed to an Administrative Order by Consent (“AOC”) which assessed penalties in the amount of approximately $500,000, with approximately $350,000 suspended pending PDC meeting certain conditions of the AOC. We are implementing programs to meet the requirements of the AOC and correct any identified deficiencies.

On August 30, 2021 and November 1, 2021, the COGCC issued us a ~~NOAV~~Notice of Alleged Violation (“NOAV”) related to the timing of wellhead pressure test reporting for certain wells in the Wattenberg Field. Pursuant to the NOAV, we have performed a comprehensive audit of our wellhead pressure testing and reporting processes. We ~~are actively updating~~have updated and will continue to implement and monitor for effectiveness and efficiency in our processes to mitigate against the possibility of the alleged violations occurring in the future. We do not anticipate a material effect on our financial condition or results of operations. However, the potential penalties may exceed $300,000.

Commencing in early 2020, we conducted a comprehensive air quality compliance audit over the facilities acquired in the SRC Acquisition. Through the self-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 such penalties may exceed $300,000.

On July 11, 2022, we received a Notice of Violation/Cease and Desist Order (“NOV”) from the CDPHE, pursuant to a May 2021 Stormwater Permit Audit and subsequent Compliance Advisory, the latter received by Great Western Operating Company on July 25, 2021. Having acquired the subject assets on May 6, 2022, we are working with the CDPHE to ensure ongoing compliance and resolve the NOV. We do not anticipate potential penalties and other expenditures associated with the NOV will have a material effect on our financial condition or results of operations, but such penalties 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 EPA and CDPHE in 2017. Per the terms of the agreement, we applied for termination in February 2022 and anticipate a response later this ~~year.~~year without any further comments or required actions from the EPA. Over the course of ~~this execution,~~executing the consent decree requirements, we have identified certain immaterial deficiencies in our ~~implementation of the programs.~~implementation. 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 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.

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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 2021 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 2021 Form 10-K.

~~Table of contents~~

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 ~~March 31,~~June 30, 2022:

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 (1)
(in millions)
January 592,567 $ 55.54 501,000 $ 159.5
February 71,735 56.73 4,340 1,250.0
March 825,680 69.71 820,555 1,192.8
Total first quarter 2022 purchases 1,489,982 63.45 1,325,895 1,192.8


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 (1) (in millions)
April	/	714,091	$	74.22	613,658	$	1,147.4
May		1,382,199	69.33		1,381,407	1,051.6
June		970,777	75.74		970,777	978.1
Total second quarter 2022 purchases		3,067,067	72.50		2,965,842	978.1

_____________

(1)In 2019, our board of directors approved a program pursuant to which we may acquire shares of our common stock from time to time. At December 31, 2021, $187.3 million out of the approved $525 million remained available for repurchase under the stock repurchase program. In February 2022, our board of directors approved a new stock repurchase program that reset the total repurchase value to $1.25 billion, which we currently anticipate fully utilizing by December 31, 2023. 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.

(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.~~Guarantors.

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.

~~99.1~~

~~Form of 2022 Performance Share Agreement.~~

~~99.2~~

~~Form of 2022 Restricted Stock Unit Agreement (Directors).~~

~~99.3~~

~~Form of 2022 Restricted Stock Unit Agreement (Executives).~~

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: ~~May 4,~~August 3, 2022			/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)

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	Three Months Ended March 31, 2021
	Common Stock			Additional Paid-in Capital		Treasury Stock			Accumulated Deficit		Total Stockholders’ Equity
	Shares	Amount				Shares	Amount
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