PDC ENERGY, INC. - Quarter Report: 2022 March (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 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 shares of the Company's Common Stock ($0.01 par value) were outstanding as of April 26, 2022.

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PDC ENERGY, INC.

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	PART I – FINANCIAL INFORMATION	Page

Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Cash Flows	3
	Condensed Consolidated Statements of Stockholders’ Equity	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	43

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Mine Safety Disclosures	45
Item 5.	Other Information	45
Item 6.	Exhibits	46

	Signatures	47

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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 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 consent decree; expected impact from emission reduction initiatives; risk of our counterparties non-performance on derivative instruments; and our ability to fund planned activities.

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

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

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

•difficulties in integrating our operations as a result of any significant acquisitions, including the pending acquisition of 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;

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

•effect of crude oil and natural gas derivative activities;

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

•cost of pending or future litigation;

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

•uncertainties associated with future dividends to our shareholders 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;

•civil unrest, terrorist attacks and cyber threats; and

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

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors made in our Annual Report on Form 10-K for the year ended December 31, 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
Assets
Current assets:
Cash and cash equivalents	$	171,157	$	33,829
Accounts receivable, net	537,056		398,605
Fair value of derivatives	13,158		17,909
Prepaid expenses and other current assets	12,191		8,230
Total current assets	733,562		458,573
Properties and equipment, net	4,886,264		4,814,865
Fair value of derivatives	19,956		15,177
Other assets	91,582		48,051
Total Assets	$	5,731,364	$	5,336,666

Liabilities and Stockholders’ Equity
Liabilities
Current liabilities:
Accounts payable	$	192,268	$	127,891
Production tax liability	112,348		99,583
Fair value of derivatives	572,636		304,870
Funds held for distribution	302,649		285,861
Accrued interest payable	18,251		10,482
Other accrued expenses	77,130		91,409
Total current liabilities	1,275,282		920,096
Long-term debt	942,565		942,084
Asset retirement obligations	123,856		127,526
Fair value of derivatives	234,284		95,561
Deferred income taxes	29,983		26,383
Other liabilities	360,643		314,769
Total liabilities	2,966,613		2,426,419

Commitments and contingent liabilities

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
Additional paid-in capital	3,052,741		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)
Total stockholders’ equity	2,764,751		2,910,247
Total Liabilities and Stockholders’ Equity	$	5,731,364	$	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,
		2022		2021
Revenues
Crude oil, natural gas and NGLs sales		$	882,378	$	468,119
Commodity price risk management gain (loss), net		(568,055)		(181,256)
Other income		2,125		(827)
Total revenues		316,448		286,036
Costs, expenses and other
Lease operating expense		54,156		41,804
Production taxes		62,916		29,492
Transportation, gathering and processing expense		27,971		21,732
Exploration, geologic and geophysical expense		253		354
General and administrative expense		34,107		32,677
Depreciation, depletion and amortization		151,055		146,763
Accretion of asset retirement obligations		2,987		3,128
Impairment of properties and equipment		943		190
Loss (gain) on sale of properties and equipment		(125)		(212)
Other expense		—		48
Total costs, expenses and other		334,263		275,976
Income (loss) from operations		(17,815)		10,060
Interest expense, net		(12,945)		(19,041)
Income (loss) before income taxes		(30,760)		(8,981)
Income tax benefit (expense)		(1,200)		(55)
Net income (loss)		$	(31,960)	$	(9,036)

Earnings (loss) per share:
Basic		$	(0.33)	$	(0.09)
Diluted		$	(0.33)	$	(0.09)

Weighted average common shares outstanding:
Basic		96,279		99,702
Diluted		96,279		99,702

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,
	2022		2021
Cash flows from operating activities:
Net income (loss)	$	(31,960)	$	(9,036)
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives	406,461		150,606
Depreciation, depletion and amortization	151,055		146,763
Impairment of properties and equipment	943		190
Accretion of asset retirement obligations	2,987		3,128
Non-cash stock-based compensation	5,474		5,020
(Gain) loss on sale of properties and equipment	(125)		(212)
Amortization of debt discount, premium and issuance costs	1,357		3,837
Deferred income taxes	3,600		—
Other	(905)		(305)
Changes in assets and liabilities	(49,839)		53,068
Net cash from operating activities	489,048		353,059
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(187,021)		(109,048)
Capital expenditures for other properties and equipment	(67)		(69)

Proceeds from sale of properties and equipment	89		4,370
Proceeds from divestitures	465		—
Funds held in escrow for acquisition	(50,000)		—
Net cash from investing activities	(236,534)		(104,747)
Cash flows from financing activities:
Proceeds from revolving credit facility and other borrowings	100,500		229,000
Repayment of revolving credit facility and other borrowings	(100,500)		(397,000)



Payment of debt issuance costs	(30)		—
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	(9,203)		(2,356)
Purchase of treasury shares under stock repurchase program	(80,853)		(21,067)
Dividends paid	(24,681)		—
Principal payments under financing lease obligations	(419)		(445)
Net cash from financing activities	(115,186)		(191,868)
Net change in cash and cash equivalents	137,328		56,444
Cash and cash equivalents, beginning of period	33,829		2,623
Cash and cash equivalents, end of period	$	171,157	$	59,067

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Stockholders’ Equity

(in thousands)

(Unaudited)


	Three Months Ended March 31, 2022
	Common Stock			Additional Paid-in Capital		Treasury Stock			Accumulated Deficit		Total Stockholders’ Equity
	Shares	Amount				Shares	Amount
Balance, January 1, 2022	96,468	$	965	$	3,161,941	(55)	$	(2,705)	$	(249,954)	$	2,910,247
Net loss	—	—		—		—	—		(31,960)		(31,960)
Stock-based compensation	655	7		1,798		—	3,669		—		5,474
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	(53)	(2)		(3,022)		53	3,024		—		—
Retirement of treasury shares	(1,320)	(13)		(83,508)		1,320	83,521		—		—
Issuance of treasury shares	—	—		—		67	—		—		—
Purchase of treasury shares under stock repurchase program	—	—		—		(1,326)	(85,339)		—		(85,339)
Dividends declared ($0.25 per share)	—	—		(24,468)		—	—		—		(24,468)
Balance, March 31, 2022	95,750	$	957	$	3,052,741	(105)	$	(7,033)	$	(281,914)	$	2,764,751


	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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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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, 2022, we owned an interest in approximately 3,450 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 months ended March 31, 2022 are not necessarily indicative of the results to be expected for the full year or any other future period.

NOTE 2 - PENDING ACQUISITION

On February 26, 2022, we entered into a definitive purchase agreement under which we will acquire Great Western Petroleum, LLC (“Great Western”) for approximately $1.4 billion, inclusive of Great Western’s net debt (the “Great Western Acquisition”). Great Western is an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in Colorado. The purchase consideration for the Great Western Acquisition will be made through the transfer of approximately 4.0 million shares of our common stock and approximately $543 million in cash, pursuant to the Membership Interest Purchase Agreement that we entered into with Great Western (“Acquisition Agreement”). In February 2022, we deposited $50.0 million into an escrow account pursuant to the terms of the Acquisition Agreement, recognized as other assets on the condensed consolidated balance sheet. We anticipate that the Great Western Acquisition will be completed in May 2022, subject to certain customary closing conditions being met.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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,
Revenue by Commodity and Operating Region		2022		2021		Percent Change
		(in thousands)
Crude oil
Wattenberg Field		$	451,911	$	235,963	92	%
Delaware Basin		97,838		37,688		160	%
Total		549,749		273,651		101	%
Natural gas
Wattenberg Field		143,699		97,022		48	%
Delaware Basin		19,425		8,624		125	%
Total		163,124		105,646		54	%
NGLs
Wattenberg Field		138,875		77,777		79	%
Delaware Basin		30,630		11,045		177	%
Total		169,505		88,822		91	%
Crude oil, natural gas and NGLs
Wattenberg Field		734,485		410,762		79	%
Delaware Basin		147,893		57,357		158	%
Total		$	882,378	$	468,119	88	%

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 months ended March 31, 2022:


	(in thousands)
Beginning balance	$	15,472
Additions (Net reduction to additions previously recognized)	(5,112)
Amortized as a reduction to crude oil, natural gas and NGLs sales	(328)
Ending balance	$	10,032

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, 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
	Condensed Consolidated Balance Sheet Line Item	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
		(in thousands)
Derivative assets
Current	Fair value of derivatives	$	6,795	$	6,363	$	13,158	$	—	$	17,909	$	17,909
Non-current	Fair value of derivatives	4,680		15,276		19,956		605		14,572		15,177
Total		$	11,475	$	21,639	$	33,114	$	605	$	32,481	$	33,086

Derivative liabilities
Current	Fair value of derivatives	$	(389,334)	$	(183,302)	$	(572,636)	$	(230,695)	$	(74,175)	$	(304,870)
Non-current	Fair value of derivatives	(169,736)		(64,548)		(234,284)		(74,715)		(20,846)		(95,561)
Total		$	(559,070)	$	(247,850)	$	(806,920)	$	(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)

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

Nonrecurring Fair Value 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 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	%

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 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, 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,
Condensed Consolidated Statement of Operations Line Item		2022		2021
		(in thousands)
Commodity price risk management gain (loss), net
Net settlements		$	(161,594)	$	(30,650)
Net change in fair value of unsettled derivatives		(406,461)		(150,606)
Total commodity price risk management gain (loss), net		$	(568,055)	$	(181,256)

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2022

(Unaudited)

Commodity Derivative Contracts. As of March 31, 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)

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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.

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, 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

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, 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

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

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		—

As of March 31, 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

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

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

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 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,
		2022		2021
		(in thousands)
Transportation, gathering and processing expense		$	1,956	$	1,521
Lease operating expense		531		438

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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 million and $7.9 million as of March 31, 2022 and December 31, 2021, respectively, consists of the following:


	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, 2022, we had a borrowing base of $2.4 billion, an elected commitment of $1.5 billion and availability under our revolving credit facility of $1.48 billion, net of $19.9 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, 2022, the applicable interest margin is 0.75 percent for the alternate base rate option or 1.75 percent for the SOFR option, and the unused commitment fee is 0.375 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, 2022, we were in compliance with all covenants related to our revolving credit facility.

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

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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, 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, 2022, we were in compliance with all covenants and all restricted payment provisions related to our Senior Notes.

NOTE 9 - LEASES

We have operating leases for office space and well equipment, and finance leases for vehicles. There were no significant changes in our operating and finance leases for the three months ended March 31, 2022. We had short-term lease costs of $74.7 million and $38.9 million for the three months ended March 31, 2022 and March 31, 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.

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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.

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 months ended March 31, 2022:


	(in thousands)
Asset retirement obligations at beginning of period	$	159,672
Obligations incurred with development activities and other	1,655

Accretion expense	2,987
Revisions in estimated cash flows	(284)
Obligations discharged with asset retirements and divestitures	(8,260)
Asset retirement obligations at end of period	155,770

Current portion (1)	(31,914)
Long-term portion	$	123,856

_____________

(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, 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 months ended March 31, 2022. For details of our commitments, 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, 2022, there were 3,836,691 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, 2022, there were 465,780 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,
		2022		2021
		(in thousands)
General and administrative expense		$	5,182	$	4,828
Lease operating expense		292		192
Total stock-based compensation expense		$	5,474	$	5,020

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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 months ended March 31, 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

The weighted average grant-date fair value of restricted stock units was $57.57 and $28.75 for the three months ended March 31, 2022 and 2021, respectively. The total grant-date fair value of restricted stock units that vested for the three months ended March 31, 2022 and 2021 was $5.6 million and $6.1 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, 2022 was $21.8 million. This cost is expected to be recognized over a weighted average period of 1.7 years.

Performance Stock Units

The Compensation Committee awarded a total of 102,098 market-based PSUs to our executive officers during the three months ended March 31, 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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2022

(Unaudited)

The following table presents the change in non-vested market-based awards during the three months ended March 31, 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, 2022 was $19.5 million. This cost is expected to be recognized over a weighted average period of 1.5 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, 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 million and 0.6 million shares of outstanding common stock at a cost of $85.3 million and $22.1 million during the three months ended March 31, 2022 and 2021, respectively. As of March 31, 2022, $1.19 billion remained available under the program for repurchases of our outstanding common stock.

Dividends

For the three months ended March 31, 2022, our dividends totaled $24.5 million or $0.25 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, 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 since we cannot conclude that it is more likely than not that our DTAs will be fully realized in future periods.

Future events or new evidence which may lead us to conclude 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 in our current earnings, we believe there is a reasonable possibility that, if oil and natural gas prices remain similar to March 31, 2022 pricing levels, sufficient positive evidence may become available within the next 12 months to allow us to reach a conclusion that all or a significant portion of the valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense in the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change based on the level of profitability that we actually achieve.

The effective income tax rates for the three months ended March 31, 2022 and 2021 were 3.9 percent and 0.6 percent provision on the respective pre-tax losses. 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 against our deferred income tax assets.

As of March 31, 2022, there is no liability for unrecognized income tax benefits. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. The IRS has accepted our 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. 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

We reported a net loss for the three months ended March 31, 2022 and 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.

Table of contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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

NOTE 15 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION


	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

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, 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 containment of COVID-19 and related emerging variants, which resulted to an increase in crude oil demand. Overall production from OPEC+ has not increased at the same pace of the 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 of 2022 when compared to 2021.

The commodity price environment may remain volatile for an extended period due to, among other things, the continued invasion in Ukraine, outbreaks caused by coronavirus variants, the recovery of the economy, unexpected supply disruptions in key producing countries including 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.

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, 2022 compared to three months ended December 31, 2021

•Production volumes decreased 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 the first quarter of 2022.

•Crude oil, natural gas and NGLs sales increased to $882.4 million compared to $848.2 million in the fourth quarter of 2021 primarily due to a 13 percent increase in weighted average realized commodity prices partially offset by 8 percent decrease in production volumes between periods.

•Negative net settlements from our commodity derivative contracts decreased 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 in the first quarter of 2022.

•Combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 10 percent to $720.8 million from $653.3 million in the fourth quarter of 2021.

PDC ENERGY, INC.

•Generated 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 an increase in crude oil, natural gas and NGLs sales of $34.2 million between periods.

•Adjusted EBITDAX, a non-U.S. GAAP financial measure, was $549.3 million compared to $487.7 million for the fourth quarter of 2021, primarily due to an increase in sales of $67.5 million, net of negative net derivative settlements, partially offset by an increase in costs experienced in operations.

•Cash flows from operations decreased to $489.0 million compared to $520.0 million in the fourth quarter of 2021. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to $538.8 million compared to $473.1 million in fourth quarter of 2021. Adjusted free cash flows, a non-U.S. GAAP financial measure, decreased to $318.7 million from $339.5 million in the fourth quarter of 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

On February 26, 2022, we entered into the Acquisition Agreement to acquire Great Western for approximately $1.4 billion, inclusive of Great Western’s net debt. Great Western is an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in Colorado. We anticipate acquiring approximately 54,000 net acres in the Core Wattenberg 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 and approximately $543 million in cash. The cash portion of the purchase price is expected to be 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.

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 of 2022 and added a second full-time drilling rig in mid-March 2022. In addition, we operated one full-time drilling rig and one completion crew during the first quarter of 2022 in the Delaware Basin. Our total capital investments in crude oil and natural gas properties for the three months ended March 31, 2022 were $220.2 million.

The following table summarize our drilling and completion activities for the three months ended March 31, 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	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

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 million shares of outstanding common stock at a cost of $85.3 million for the three months ended March 31, 2022. As of March 31, 2022, $1.19 billion of our outstanding common stock remained available for repurchases under the program.

Dividends. For the three months ended March 31, 2022, our dividends declared amounted to $0.25 per share of common stock or $24.5 million in the aggregate.

2022 Operational and Financial Outlook

On a PDC standalone basis (without consideration to the Great Western Acquisition), we anticipate that our production for 2022 will range between 195,000 Boe to 205,000 Boe per day, approximately 62,000 Bbls to 65,000 Bbls of which are expected to be crude oil. Our planned 2022 capital investments in crude oil and natural gas properties, which we expect to be between $675 million and $725 million, are focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin. Our capital budget for 2022 is likely 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, 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, and Summit 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 75 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 to 130 operated wells. We added a full-time drilling rig in March 2022, bringing us to two full-time horizontal rigs and one 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 25 percent, on a PDC standalone basis, of our total capital investments. In 2022, we anticipate spudding and turning-in-line approximately 15 to 20 operated wells with the majority of the wells being 2.0 mile lateral wells.

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 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 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 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 in varying levels of financial assurance being required. For our tier, a bond of $40 million will be required in the second quarter of 2022 and will be secured through our existing surety bond program. In addition to the financial assurance, operators will be assessed a 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. PDC was granted unanimous approval for an 8-well OGDP located in rural Weld County in October 2021, our first approval under the new permitting process resulting from a company-wide collaborative effort. Additionally, in September 2021, we submitted our application for an OGDP covering an approximate 70-well, multi-pad development 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 25 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. 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 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.

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 2022, we completed our Environmental Protection Agency annual filing for 2021. Our results outline that we have achieved a reduction in greenhouse gas (“GHG”) and methane emissions intensity from 2020 baseline targets, that puts us on track to meet our 60% and 50% GHG and methane reduction levels by 2025, respectively. 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.

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)	%

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.

Crude Oil, Natural Gas and NGLs Sales

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


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

Average crude oil price	102.0		220.0
Average natural gas price	(13.5)		49.7
Average NGLs price	9.6		66.0
Total change in crude oil, natural gas and NGLs sales revenue	$	34.2	$	414.3

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
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
Crude oil (MBbls)
Wattenberg Field	4,832	5,306	4,173	(9)	%	16	%
Delaware Basin	1,021	1,019	684	—	%	49	%
Total	5,853	6,325	4,857	(7)	%	21	%
Natural gas (MMcf)
Wattenberg Field	37,663	40,870	35,561	(8)	%	6	%
Delaware Basin	5,456	6,163	4,591	(11)	%	19	%
Total	43,119	47,033	40,152	(8)	%	7	%
NGLs (MBbls)
Wattenberg Field	4,291	4,615	3,800	(7)	%	13	%
Delaware Basin	594	626	392	(5)	%	52	%
Total	4,885	5,241	4,192	(7)	%	17	%
Crude oil equivalent (MBoe)
Wattenberg Field	15,400	16,732	13,900	(8)	%	11	%
Delaware Basin	2,524	2,673	1,840	(6)	%	37	%
Total	17,924	19,405	15,740	(8)	%	14	%

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 14 percent during the three months ended March 31, 2022 compared to the same period in 2021. The increase in production volume between periods was primarily due to a greater number of wells turned-in-line since the first 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.

Midstream Capacity

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

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

Our production from the Wattenberg Field and Delaware Basin was not materially affected by midstream or downstream capacity constraints during the three months ended March 31, 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 2023, which may result to lower realized 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.

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	%

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

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

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

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 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 per Boe, and $0.06 per BOE for the three months ended March 31, 2022, December 31, 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, 2022 as compared to the three months ended December 31, 2021.

Our average realization percentage for crude oil increased for the three months ended March 31, 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. In addition, we realized improved differentials from our 2022 crude oil sales contracts. Average realization percentage for natural gas decreased for the three months ended March 31, 2022 compared to the three months ended March 31, 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, 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)

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

Lease Operating Expense

Lease operating expense (“LOE”) increased by 7 percent 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. The period-over-period increase in LOE was primarily attributable to a $1.7 million increase in workover expense due to the timing of workover activities in the Delaware Basin and $1.5 million in additional chemical treatments and power costs in both basins. LOE per Boe increased 15 percent to $3.02 for the three months ended March 31, 2022 from $2.62 for the three months ended December 31, 2021. The increase is primarily driven by the cost increases outlined above as well as a decrease in production of 8 percent period-over-period.

LOE increased by 30 percent to $54.2 million for the three months ended March 31, 2022 compared to $41.8 million for the three months ended March 31, 2021. The period-over-period increase in LOE was primarily due to (i) increased activities and payroll costs of $4.8 million at our operated and non-operated well locations resulting from an increase in completion activities in both basins, (ii) a $3.2 million increase in chemical treatments, environmental and regulatory costs and (iii) a $2.4 million increase in workover expense due to the timing of workover activities focused in the Delaware Basin. LOE per Boe increased 14 percent to $3.02 for the three months ended March 31, 2022 from $2.66 for the three months ended March 31, 2021.

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 percent to $62.9 million for the three months ended March 31, 2022 compared to $64.1 million for the three months ended December 31, 2021. Production taxes per Boe increased 6 percent to $3.51 for the three months ended March 31, 2022 compared to $3.30 for the three months ended December 31, 2021. The increase in production taxes per Boe was primarily due to an increase in crude oil and NGLs prices between periods.

Production taxes increased 113 percent to $62.9 million for the three months ended March 31, 2022 compared to $29.5 million for the three months ended March 31, 2021. Production taxes per Boe increased 88 percent to $3.51 for the three months ended March 31, 2022 compared to $1.87 for the three months ended March 31, 2021. The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs prices between periods.

Transportation, Gathering and Processing Expense

TGP expense increased 8 percent to $28.0 million for the three months ended March 31, 2022 compared to $26.0 million for the three months ended December 31, 2021. TGP expense per Boe increased 16 percent to $1.56 for the three months ended March 31, 2022 compared to $1.34 for the three months ended December 31, 2021. The increase in TGP expense was primarily due to an increase in gas processing costs in the Delaware Basin between periods.

TGP expense increased 29 percent to $28.0 million for the three months ended March 31, 2022 compared to $21.7 million for the three months ended March 31, 2021. TGP expense per Boe increased 13 percent to $1.56 for the three 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, 2022 compared to the same period in 2021 was driven by a $5.6 million increase relating to gas processing costs and a $1.8 million increase in shortfall fees relating to our delivery commitment, both in the Delaware Basin.

Impairment of Properties and Equipment

There were no significant impairment charges recognized related to our proved and unproved oil and gas properties during the three months ended March 31, 2022, December 31, 2021, and March 31, 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 9 percent 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 in charitable contributions and an increase in professional fees relating to the Great Western Acquisition in the first quarter of 2022.

General and administrative expense remained relatively flat with an increase of 4 percent to $34.1 million for the three months ended March 31, 2022 compared to $32.7 million for the three months ended March 31, 2021.

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 $149.3 million for the three months ended March 31, 2022 compared to $154.7 million for the three months ended December 31, 2021. The decrease in DD&A expense was primarily due to an 8 percent decrease in production volumes between periods partially offset by an increase in the weighted average DD&A expense rate as a result of capitalized costs of wells turned-in-line in the first quarter of 2022.

PDC ENERGY, INC.

DD&A expense related to crude oil and natural gas properties was $149.3 million for the three months ended March 31, 2022 compared to $144.8 million for the comparable period in 2021. The increase in total DD&A expense was primarily due to a 14 percent increase in production volumes between periods primarily due to a greater number of wells turned-in-line since the second quarter of 2021 partially offset by a decrease in the weighted average DD&A expense rate.

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

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
	March 31, 2022		December 31, 2021		March 31, 2021
	(per Boe)
Operating Region/Area
Wattenberg Field	$	8.00	$	7.70	$	9.22
Delaware Basin	10.33		9.71		9.01
Total weighted average DD&A expense rate	8.33		7.97		9.20

Interest Expense, net

Interest expense, net decreased $10.6 million 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. The decrease was primarily related to (i) reduced borrowings under our revolving credit facility between periods, (ii) a 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. The decrease was primarily related to (i) reduced borrowings under our revolving credit facility between periods, (ii) expiration and redemption of our 2021 Convertible Notes 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.

Provision for Income Taxes

We recorded income tax expense of $1.2 million, $26.5 million and $0.1 million for the three months ended March 31, 2022, December 31, 2021, and March 31, 2021, resulting in an effective income tax rate of 3.9 percent provision on pre-tax losses, 5.3 percent provision on pre-tax income and 0.6 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 a 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 deductible. At each reporting period, management considers

the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. 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 since we cannot conclude that it is more likely than not that our DTAs will be fully realized in future periods.

PDC ENERGY, INC.

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

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

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

The factors impacting 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 March 31, 2022, December 31, 2021, and March 31, 2021, respectively, are discussed above.

Adjusted net income, a non-U.S. GAAP financial measure, was $358.6 million, $283.1 million, and $141.6 million for the three months ended March 31, 2022, December 31, 2021, and March 31, 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, 2022 is an indication of a lack of liquidity. We had working capital deficits of $541.7 million as of March 31, 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 million and an increase in accounts payable 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. 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 million at March 31, 2022 and availability under our revolving credit facility was $1.5 billion, providing for a total liquidity position of $1.65 billion as of March 31, 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. As 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 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 of approximately 4.0 million shares of our common stock and approximately $543 million in cash. The cash portion of the purchase price is expected to be 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.

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, 2022, we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.1:1.0 and a leverage ratio of 0.4:1.0.

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

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 million to $489.0 million during the three months ended March 31, 2022 compared to $353.1 million during the three months ended March 31, 2021. The increase between periods was primarily due to a $414.3 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 million increase in derivative settlement losses, a $33.4 million increase in production taxes and the timing of receivable collections between periods.

Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $238.8 million to $538.8 million during the three months ended March 31, 2022 from $300.0 million during the three months ended March 31, 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 million during the three months ended March 31, 2022 to $318.7 million compared to $175.6 million during the three months ended March 31, 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.

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 million during the three months ended March 31, 2022 was primarily related to our drilling and completion activities of $187.0 million and a $50.0 million deposit in escrow relating to the Great Western Acquisition. Net cash used in investing activities of $104.7 million during the three months ended March 31, 2021 was primarily related to our drilling and completion activities of $109.0 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 million during the three months ended March 31, 2022 was primarily due to the repurchase of 1.3 million shares of our common stock for $80.9 million pursuant to our stock repurchase program and dividend payments totaling $24.7 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, 2022, $1.19 billion 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 million during the three months ended March 31, 2021 was primarily due to net repayments to our credit facility of $168.0 million and the repurchase and retirement of shares of our common stock totaling to $21.1 million pursuant to our stock repurchase program.

Subsidiary Guarantor

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

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

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
	March 31, 2022				December 31, 2021
	Issuer		Guarantor		Issuer		Guarantor
	(in millions)
Assets
Current assets	$	636.3	$	97.2	$	402.6	$	56.0
Intercompany accounts receivable, guarantor subsidiary	—		74.8		—		40.8
Investment in guarantor subsidiary	1,766.8		—		1,767.2		—
Properties and equipment, net	3,896.0		990.2		3,875.0		939.9
Other non-current assets	106.6		4.9		58.5		4.8

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

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

There were no significant new accounting standards adopted or new accounting pronouncements that would have potential effect on us as of March 31, 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
	March 31, 2022		December 31, 2021		March 31, 2021
	(in millions)
Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow:
Net cash from operating activities	$	489.0	$	520.0	$	353.1
Changes in assets and liabilities	49.8		(46.9)		(53.1)
Adjusted cash flows from operations	538.8		473.1		300.0
Capital expenditures for development of crude oil and natural gas properties	(187.0)		(154.3)		(109.0)
Change in accounts payable related to capital expenditures for oil and gas development activities	(33.1)		20.7		(15.4)
Adjusted free cash flow	$	318.7	$	339.5	$	175.6

Net income (loss) to adjusted net income (loss):
Net income (loss)	$	(32.0)	$	473.1	$	(9.0)
Loss (gain) on commodity derivative instruments	568.1		(5.7)		181.3
Net settlements on commodity derivative instruments	(161.6)		(194.8)		(30.7)
Tax effect of above adjustments (1)	(15.9)		10.5		—
Adjusted net income (loss)	$	358.6	$	283.1	$	141.6

Net income (loss) to adjusted EBITDAX:
Net income (loss)	$	(32.0)	$	473.1	$	(9.0)
Loss (gain) on commodity derivative instruments	568.1		(5.7)		181.3
Net settlements on commodity derivative instruments	(161.6)		(194.8)		(30.7)
Non-cash stock-based compensation	5.5		5.7		5.0
Interest expense, net	12.9		23.5		19.0
Income tax expense (benefit)	1.2		26.5		0.1
Impairment of properties and equipment	0.9		0.1		0.2
Exploration, geologic and geophysical expense	0.3		0.2		0.4
Depreciation, depletion and amortization	151.1		156.6		146.8
Accretion of asset retirement obligations	3.0		2.9		3.1
Loss (gain) on sale of properties and equipment	(0.1)		(0.4)		(0.2)
Adjusted EBITDAX	$	549.3	$	487.7	$	316.0

Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities	$	489.0	$	520.0	$	353.1
Interest expense, net(2)	12.9		16.6		19.0
Amortization and write-off of debt discount, premium and issuance costs	(1.4)		(2.3)		(3.8)
Exploration, geologic and geophysical expense	0.3		0.2		0.4
Other	(1.3)		0.1		0.4
Changes in assets and liabilities	49.8		(46.9)		(53.1)
Adjusted EBITDAX	$	549.3	$	487.7	$	316.0

_____________

(1)Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the three 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, 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. 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, 2022, we had no outstanding borrowings under our revolving credit facility.

Commodity Price Risk

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

As of March 31, 2022, we had a net liability derivative position of $773.8 million related to our commodity price risk derivatives. Based on a sensitivity analysis as of March 31, 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 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 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, 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, 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, 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, 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 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, 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 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 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 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.

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. Over the course of this execution, we have identified certain immaterial deficiencies in our implementation of the programs. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree 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.

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.

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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, 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

_____________

(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.

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, 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)