PDC ENERGY, INC. - Quarter Report: 2020 September (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 September 30, 2020

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

For the transition period from __________ to _________

Commission File Number 001-37419

PDC ENERGY, INC.

(Exact name of registrant as specified in its charter)


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

1775 Sherman Street, Suite 3000

Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

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

Securities registered pursuant to Section 12(b) of the Act.

Title of each class

Ticker Symbol

Name of each exchange on which registered

Common stock, par value $0.01 per share

PDCE

Nasdaq Global Select Market

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

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

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


Large Accelerated Filer	x	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 99,637,673 shares of the Company's Common Stock ($0.01 par value) were outstanding as of October 22, 2020.

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PDC ENERGY, INC.

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	PART I – FINANCIAL INFORMATION	Page

Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Operations	2
	Condensed Consolidated Statements of Cash Flows	3
	Condensed Consolidated Statements of Stockholders' Equity	4
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	53

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 3.	Defaults Upon Senior Securities	56
Item 4.	Mine Safety Disclosures	56
Item 5.	Other Information	56
Item 6.	Exhibits	57

	Signatures	58

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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"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; 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; our currently suspended stock repurchase program; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; timing and adequacy of infrastructure projects of our midstream providers; impacts of Colorado political matters, including recent rulemaking initiatives given our geographic concentration; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; risk of our counterparties non-performance on derivative instruments; and our ability to repay our 2021 Convertible Notes and 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:

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

•changes in global production volumes and demand, including economic conditions that might impact demand and prices for the products we produce;

•geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries;

•impacts of Colorado political matters;

•volatility of commodity prices for crude oil, natural gas and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices, including risks relating to decreased revenue, income and cash flow, write-downs and impairments and availability of capital;

•volatility and widening of differentials;

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

•impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement of those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;

•timing and receipt of necessary regulatory permits;

•impact of regulatory developments in Colorado, particularly with respect to additional permit scrutiny;

•declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments;

•changes in estimates of proved reserves;

•inaccuracy of reserve estimates and expected production rates;

•potential for production decline rates from our wells being greater than expected;

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

•availability and cost of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;

•risks incidental to the drilling and operation of crude oil and natural gas wells;

•difficulties in integrating our operations as a result of any significant acquisitions, including the merger with SRC Energy Inc. ("SRC"), or acreage exchanges;

•increases in costs and expenses;

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

•potential losses of acreage due to lease expirations or otherwise;

•future cash flows, liquidity and financial condition;

•competition within the oil and gas industry;

•availability and cost of capital;

•success in marketing our crude oil, natural gas and NGLs;

•effect of crude oil and natural gas derivative activities;

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

•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;

•effect that acquisitions we may pursue have on our capital requirements;

•our ability to retain or attract senior management and key technical employees; 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 the heading "Risk Factors," made in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2019 filed with the U.S. Securities and Exchange Commission ("SEC") on February 26, 2020 (the "2019 Form 10-K"), our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 filed with the SEC on May 8, 2020 (the "First Quarter 2020 Form 10-Q"), our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the SEC on August 6, 2020 (the "Second Quarter 2020 Form 10-Q") and our other filings with the 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)


	September 30, 2020		December 31, 2019
Assets
Current assets:
Cash and cash equivalents	$	3,818	$	963

Accounts receivable, net	207,151		266,354
Fair value of derivatives	138,652		28,078
Prepaid expenses and other current assets	11,964		8,635
Total current assets	361,585		304,030
Properties and equipment, net	4,885,234		4,095,202

Fair value of derivatives	13,027		3,746

Other assets	72,682		45,702
Total Assets	$	5,332,528	$	4,448,680

Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	103,504	$	98,934
Production tax liability	122,555		76,236
Fair value of derivatives	63,957		2,921
Funds held for distribution	174,084		98,393
Accrued interest payable	21,179		14,284
Other accrued expenses	81,892		70,462
Current portion of long-term debt	190,608		—
Total current liabilities	757,779		361,230
Long-term debt	1,525,999		1,177,226
Deferred income taxes	—		195,841
Asset retirement obligations	133,356		95,051

Fair value of derivatives	46,460		692
Other liabilities	250,535		283,133
Total liabilities	2,714,129		2,113,173

Commitments and contingent liabilities (Note 12)

Stockholders' equity

Common shares - par value $0.01 per share, 150,000,000 authorized, 99,639,727 and 61,652,412 issued as of September 30, 2020 and December 31, 2019, respectively	996		617
Additional paid-in capital	3,383,648		2,384,309
Accumulated Deficit	(765,575)		(47,945)
Treasury shares - at cost, 17,150 and 34,922 as of September 30, 2020 and December 31, 2019, respectively	(670)		(1,474)
Total stockholders' equity	2,618,399		2,335,507
Total Liabilities and Stockholders' Equity	$	5,332,528	$	4,448,680

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenues
Crude oil, natural gas and NGLs sales	$	314,920	$	307,409	$	809,156	$	967,464
Commodity price risk management gain (loss), net	(68,061)		54,867		245,851		(87,858)
Other income	2,358		3,667		5,656		11,495
Total revenues	249,217		365,943		1,060,663		891,101
Costs, expenses and other
Lease operating expenses	37,338		36,498		122,680		106,047
Production taxes	14,621		13,039		40,937		57,849
Transportation, gathering and processing expenses	24,399		10,999		54,844		34,631
Exploration, geologic and geophysical expense	162		209		1,026		3,492

General and administrative expense	32,490		41,091		130,007		123,497
Depreciation, depletion and amortization	144,504		171,839		470,152		491,784
Accretion of asset retirement obligations	2,420		1,356		7,398		4,503
Impairment of properties and equipment	1,221		167		882,327		37,021

Loss (gain) on sale of properties and equipment	(289)		43,872		(642)		9,599

Other expenses	1,936		2,492		6,083		8,882
Total costs, expenses and other	258,802		321,562		1,714,812		877,305
Income (loss) from operations	(9,585)		44,381		(654,149)		13,796
Interest expense, net	(21,022)		(17,811)		(66,977)		(53,679)

Income (loss) before income taxes	(30,607)		26,570		(721,126)		(39,883)
Income tax benefit (expense)	(176)		(10,662)		3,496		4,163
Net income (loss)	$	(30,783)	$	15,908	$	(717,630)	$	(35,720)

Earnings (loss) per share:
Basic	$	(0.31)	$	0.25	$	(7.34)	$	(0.55)
Diluted	$	(0.31)	$	0.25	$	(7.34)	$	(0.55)

Weighted-average common shares outstanding:
Basic	99,617		62,547		97,762		64,835
Diluted	99,617		62,595		97,762		64,835

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)


	Nine Months Ended September 30,
	2020		2019
Cash flows from operating activities:
Net loss	$	(717,630)	$	(35,720)
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives	(18,338)		68,058
Depreciation, depletion and amortization	470,152		491,784
Impairment of properties and equipment	882,327		37,021



Accretion of asset retirement obligations	7,398		4,503
Non-cash stock-based compensation	17,441		18,124
Loss (gain) on sale of properties and equipment	(642)		9,599

Amortization and write-off of debt discount, premium and issuance costs	12,546		10,139
Deferred income taxes	(2,431)		(4,389)
Other	1,950		2,761
Changes in assets and liabilities	(3,461)		49,092
Net cash from operating activities	649,312		650,972
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(445,505)		(755,828)
Capital expenditures for other properties and equipment	(1,940)		(15,522)
Acquisition of crude oil and natural gas properties	(139,812)		(12,445)
Proceeds from sale of properties and equipment	1,539		1,528
Proceeds from divestitures	1,796		202,046

Restricted cash	—		8,001


Net cash from investing activities	(583,922)		(572,220)
Cash flows from financing activities:



Proceeds from revolving credit facility and other borrowings	1,485,600		1,300,000
Repayment of revolving credit facility and other borrowings	(1,204,600)		(1,235,500)

Proceeds from senior notes	148,500		—
Payment of debt issuance costs	(6,197)		(53)
Purchase of treasury shares	(23,819)		(142,665)
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	(8,412)		(3,874)
Redemption of senior notes	(452,153)		—

Principal payments under financing lease obligations	(1,454)		(1,492)

Net cash from financing activities	(62,535)		(83,584)
Net change in cash, cash equivalents and restricted cash	2,855		(4,832)
Cash, cash equivalents and restricted cash, beginning of period	963		9,399
Cash, cash equivalents and restricted cash, end of period	$	3,818	$	4,567

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Stockholders' Equity

(in thousands, except share data)

(Unaudited)


	Nine Months Ended September 30, 2020
	Common Stock					Treasury Stock
	Shares	Amount		Additional Paid-in Capital		Shares	Amount		Accumulated Deficit		Total Stockholders' Equity

Balance, December 31, 2019	61,652,412	$	617	$	2,384,309	(34,922)	$	(1,474)	$	(47,945)	$	2,335,507
Net loss	—	—		—		—	—		(465,015)		(465,015)
Issuance pursuant to acquisition	39,182,045	391		1,014,921		—	—		—		1,015,312
Stock-based compensation	120,952	1		3,713		—	1,958		—		5,672
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—		(306,185)	(7,693)		—		(7,693)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(251,287)	(3)		(6,425)		251,287	6,428		—		—
Purchase of treasury shares	—	—		—		(1,266,000)	(23,819)		—		(23,819)
Retirement of treasury shares	(1,266,000)	(12)		(23,807)		1,266,000	23,819		—		—
Issuance of treasury shares	—	—		—		69,327	—		—		—
Balance, March 31, 2020	99,438,122	994		3,372,711		(20,493)	(781)		(512,960)		2,859,964
Net loss	—	—		—		—	—		(221,832)		(221,832)
Stock-based compensation	212,809	2		6,164		—	198		—		6,364
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—		(64,219)	(487)		—		(487)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(39,374)	—		(322)		39,374	322		—		—


Issuance of treasury shares	—	—		—		12,200	—		—		—
Balance, June 30, 2020	99,611,557	996		3,378,553		(33,138)	(748)		(734,792)		2,644,009
Net loss	—	—		—		—	—		(30,783)		(30,783)
Stock-based compensation	36,826	—		5,216		—	189		—		5,405
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—		(16,642)	(232)		—		(232)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(8,656)	—		(121)		8,656	121		—		—


Issuance of treasury shares	—	—		—		23,974	—		—		—




Balance, September 30, 2020	99,639,727	$	996	$	3,383,648	(17,150)	$	(670)	$	(765,575)	$	2,618,399

See accompanying Notes to Condensed Consolidated Financial Statements

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	Nine Months Ended September 30, 2019
	Common Stock					Treasury Stock
	Shares	Amount		Additional Paid-in Capital		Shares	Amount		Retained Earnings (Accumulated Deficit)		Total Stockholders' Equity

Balance, December 31, 2018	66,148,609	$	661	$	2,519,423	(45,220)	$	(2,103)	$	8,727	$	2,526,708
Net loss	—	—		—		—	—		(120,176)		(120,176)
Stock-based compensation	48,254	1		4,682		—	—		—		4,683
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—		(41,787)	(1,460)		—		(1,460)
Issuance of treasury shares	—	—		(2,547)		64,372	2,547		—		—

Balance, March 31, 2019	66,196,863	662		2,521,558		(22,635)	(1,016)		(111,449)		2,409,755
Net income	—	—		—		—	—		68,548		68,548
Stock-based compensation	148,040	1		7,574		—	—		—		7,575
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—		(54,784)	(2,257)		—		(2,257)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(2,182)	—		(78)		2,182	78		—		—
Purchase of treasury shares	—	—		—		(3,136,406)	(105,215)		—		(105,215)
Retirement of treasury shares	(2,822,259)	(28)		(94,085)		2,822,259	94,113		—		—
Issuance of treasury shares	—	—		(995)		24,604	995				—


Balance, June 30, 2019	63,520,462	$	635	$	2,433,974	(364,780)	$	(13,302)	$	(42,901)	$	2,378,406
Net income	—	—		—		—	—		15,908		15,908
Stock-based compensation	10,808	—		5,866		—	—		—		5,866
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—		(4,750)	(157)		—		(157)
Retirement of treasury shares for employee stock-based compensation tax withholding obligations	(995)	—		(32)		995	32		—		—
Purchase of treasury shares	—	—		—		(1,228,310)	(40,268)		—		(40,268)
Retirement of treasury shares	(1,442,457)	(14)		(48,536)		1,442,457	48,550		—		—
Issuance of treasury shares	—	—		(614)		14,973	614		—		—

Balance, September 30, 2019	62,087,818	$	621	$	2,390,658	(139,415)	$	(4,531)	$	(26,993)	$	2,359,755

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(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 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 Wolfcamp zones. As of September 30, 2020, we owned an interest in approximately 3,800 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 presentation of our financial statements for interim periods 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, 2019 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 2019 Form 10-K. Our results of operations and cash flows for the nine months ended September 30, 2020 are not necessarily indicative of the results to be expected for the full year or any other future period.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Recently Adopted Accounting Pronouncement

In March 2020, the SEC adopted final rules that amend the financial disclosure requirements for subsidiary issuers and guarantors of registered debt securities in Rule 3-10 of Regulation S-X. The amended rules, which can be found under new Rule 13-01 of Regulation S-X, narrow the circumstances that require separate financial statements of subsidiary issuers and guarantors and streamline the alternative disclosures required in lieu of those statements. The amended rules allow registrants, among other things, to disclose summarized financial information of the issuer and guarantors on a combined basis and to present only the most recently completed fiscal year and subsequent year-to-date interim period. The rule replaces the requirement to provide condensed consolidating financial information with a requirement to present summarized financial information of the issuers and guarantors. These disclosures may be provided outside the notes to the condensed consolidated financial statements. The rule is effective in the first quarter of 2021, with earlier adoption permitted. We early adopted the rule in the first quarter of 2020 and have provided these disclosures outside the notes to the condensed consolidated financial statements.

Recently Issued Accounting Pronouncement but Not Yet Adopted

In August 2020, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2020-06, Debt - Debt with conversion and other options and derivatives and hedging on contracts in entity's own equity. Amendments in this ASU simplify accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity's own equity. The amendments remove the separation models for convertible debt instruments with cash conversion features and convertible instruments with beneficial conversion features. Consequently, a convertible debt instrument will be accounted for as a single liability measured at its amortized cost and convertible preferred stock will be accounted for as a single equity instrument measured at its historical cost as long as no other features require bifurcation and recognition as derivatives. The amendments also modify the accounting for certain contracts in an entity's own equity that are currently accounted for as derivatives because of specific settlement provisions. Lastly, the earnings per share ("EPS") calculation is being amended to (i) require entities to use the if-converted method for all convertible instruments and include the effect of potential share settlement; (ii) clarify that the average market price for the period should be used in the computation of the diluted EPS denominator; and (iii) require entities to use the weighted-average share count from each quarter when calculating the year-to-date weighted average share count for all potentially dilutive securities. The amendments in this ASU are effective for fiscal years beginning after December 31, 2021, including interim periods within those fiscal years and early adoption is permitted. We are in the process of evaluating the potential impact of adopting this ASU and we do not expect to adopt the amendments early.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

In August 2020, the SEC issued a final rule that modernizes the disclosure requirements in Regulation S-K relating to the description of the business, legal proceedings, and risk factors, which are required in many SEC filings, including Form 10-K and registration statements. The final rule is effective on November 9, 2020, 30 days after its date of publication in the Federal Register. We will consider the amendments when preparing our annual report for the year ending December 31, 2020.

NOTE 3 - BUSINESS COMBINATION

In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt (the "SRC Acquisition"). Upon closing, we issued approximately 39 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the merger agreement that we entered into with SRC (the "Merger Agreement"). During the nine months ended September 30, 2020, we recorded transaction costs related to the SRC Acquisition of $20.2 million. These expenses were accounted for separately from the assets and liabilities assumed and are included in general and administrative expense in the condensed consolidated statements of operations.

The details of the estimated purchase price and the preliminary allocation of the purchase price are as follows:


	Nine Months Ended September 30, 2020
	(in thousands)
Consideration:
Cash	$	40
Retirement of seller's credit facility	166,238
Total cash consideration	166,278
Common stock issued	1,009,015
Shares withheld in lieu of taxes	6,299

Total consideration	$	1,181,592

Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current assets	$	149,538
Properties and equipment, net - proved	1,607,175
Properties and equipment, net - unproved	109,615
Properties and equipment, net - other	16,242
Deferred tax asset	193,410
Other assets	13,266
Total assets acquired	2,089,246
Liabilities assumed:
Current liabilities	(257,285)
Senior notes	(555,500)
Asset retirement obligations	(41,901)
Other liabilities	(52,968)
Total liabilities assumed	(907,654)
Total identifiable net assets acquired	$	1,181,592

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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

terms and expirations and a market-based weighted-average cost of capital rate of 10 percent. These inputs require significant judgments and estimates by management at the time of the valuation. As of the date of this report, we expect that the measurement period will extend into the fourth quarter of 2020, and the value of the assets and liabilities may be revised as appropriate.

The results of operations for the SRC Acquisition since the closing date have been included in our condensed consolidated financial statements for the three and nine months ended September 30, 2020 and include approximately $82.0 million and $233.8 million of total revenue, respectively, and $20.7 million and $19.3 million of loss from operations for the three and nine months ended September 30, 2020, respectively.

Pro Forma Information. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the nine months ended September 30, 2020 and for the three and nine months ended September 30, 2019, assuming the acquisition had been completed as of January 1, 2019. The financial information for the three months ended September 30, 2020 is included in our condensed consolidated statements of operations and therefore does not require a pro forma disclosure. The pro forma amounts for the nine months ended September 30, 2020 include an immaterial non-recurring adjustment which was not included in our pro forma information disclosed in our six months ended June 30, 2020 and our three months ended March 31, 2020 footnotes. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the business combination. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results.


	Three Months Ended September 30,		Nine Months Ended September 30,
	2019		2020		2019
	(in thousands, except per share data)

Total revenue	$	511,110	$	1,082,003	$	1,373,739
Net income (loss)	63,092		(677,636)		128,337

Earnings (loss) per share:
Basic	$	0.62	$	(6.79)	$	1.23
Diluted	0.62		(6.79)		1.23

NOTE 4 - REVENUE RECOGNITION

Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred 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. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the three and nine months ended September 30, 2020 and 2019:


	Three Months Ended September 30,						Nine Months Ended September 30,
Revenue by Commodity and Operating Region	2020		2019		Percent Change		2020		2019		Percent Change
	(in thousands)
Crude oil
Wattenberg Field	$	183,420	$	185,543	(1.1)	%	$	483,608	$	569,518	(15.1)	%
Delaware Basin	42,591		70,175		(39.3)	%	107,347		191,452		(43.9)	%


Total	$	226,011	$	255,718	(11.6)	%	$	590,955	$	760,970	(22.3)	%
Natural gas
Wattenberg Field	$	39,759	$	23,949	66.0	%	$	109,279	$	100,779	8.4	%
Delaware Basin	2,140		2,613		(18.1)	%	3,183		9,293		(65.7)	%


Total	$	41,899	$	26,562	57.7	%	$	112,462	$	110,072	2.2	%
NGLs
Wattenberg Field	$	38,871	$	16,906	129.9	%	$	86,875	$	67,305	29.1	%
Delaware Basin	8,139		8,223		(1.0)	%	18,864		29,117		(35.2)	%


Total	$	47,010	$	25,129	87.1	%	$	105,739	$	96,422	9.7	%
Crude oil, natural gas and NGLs
Wattenberg Field	$	262,050	$	226,398	15.7	%	$	679,762	$	737,602	(7.8)	%
Delaware Basin	52,870		81,011		(34.7)	%	129,394		229,862		(43.7)	%


Total	$	314,920	$	307,409	2.4	%	$	809,156	$	967,464	(16.4)	%

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 in the condensed consolidated balance sheet. The contract assets are amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer.

The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for the nine months ended September 30, 2020:


	Amount
	(in thousands)

Beginning balance, January 1, 2020	$	11,494
Additions	15,627
Amortized as a reduction to crude oil, natural gas and NGLs sales	(1,588)
Ending balance, September 30, 2020	$	25,533

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Determination of Fair Value

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means.

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity.

Derivative Financial Instruments

We measure the fair value of our 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 such as the LIBOR curve for a similar duration of each outstanding position, 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 swap rates and the duration of each outstanding derivative position. We validate our fair value measurement by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions and through the review of counterparty statements and other supporting documentation.

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


	As of September 30, 2020						As of December 31, 2019
	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)



Total assets	$	130,134	$	21,545	$	151,679	$	22,886	$	8,938	$	31,824



Total liabilities	(79,658)		(30,759)		(110,417)		(3,089)		(524)		(3,613)
Net derivative instruments	$	50,476	$	(9,214)	$	41,262	$	19,797	$	8,414	$	28,211

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands)
Fair value of Level 3 instruments, net asset beginning of period	$	26,958	$	22,504	$	8,414	$	58,329
Changes in fair value included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net	(21,521)		10,846		32,840		(22,077)

Settlements included in condensed consolidated statement of operations line items:
Commodity price risk management loss, net	(14,652)		(2,445)		(50,469)		(5,347)

Fair value of Level 3 instruments, net asset end of period	$	(9,215)	$	30,905	$	(9,215)	$	30,905

Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net	$	(13,171)	$	6,787	$	9,466	$	(11,620)

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.

Non-Derivative Financial Assets and Liabilities

We utilize fair value on a nonrecurring basis to review our proved crude oil and natural gas properties for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. Unobservable inputs include estimated future crude oil and natural gas production, forward strip commodity pricing curves (adjusted for basis differentials), operating and development costs, future development plans and a discount rate of 17 percent, which was based on a weighted-average cost of capital for the area for which the assets are located (all of which were designated as Level 3 inputs within the fair value hierarchy).

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 and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes.


		As of September 30, 2020				As of December 31, 2019
		Estimated Fair Value		Percent of Par		Estimated Fair Value		Percent of Par
		(in millions)
Senior Notes:
	2021 Convertible Notes	$	192.6	96.3	%	$	188.6	94.3	%
	2024 Senior Notes	382.8		95.7	%	409.2		102.3	%
	2025 Senior Notes	96.1		93.9	%	—		—	%
	2026 Senior Notes (1)	696.8		92.9	%	599.4		99.9	%

_____________

(1)Includes additional $150.0 million aggregate principal amount of 2026 Senior Notes issued in September 2020. For further discussion see footnote titled Long-term Debt.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

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

Concentration of Risk

Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily 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 September 30, 2020; however, this determination may change.

Cash and Cash Equivalents. We consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of the FDIC insurance limits at September 30, 2020 and December 31, 2019. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our revolving credit facility.

NOTE 6 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

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 swaps and basis protection swaps, to protect against price declines in future periods. We do not enter into derivative contracts for speculative or trading purposes.

Collars are designed to establish floor and ceiling prices on anticipated future oil or gas production, while swaps establish a fixed price for anticipated future oil or gas production. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases.

We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. As of September 30, 2020, we had derivative instruments in place for a portion of our anticipated 2020, 2021 and 2022 production. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

As of September 30, 2020, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted-average contract price is shown.


	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 September 30, 2020 (1) (in thousands)
	Floors		Ceilings
Crude Oil
NYMEX

2020		900		$	55.00	$	71.68	3,174	$	58.90			$	71,119
2021		996		35.00		46.22		9,180	46.90				40,547
2022		—		—		—		3,984	40.01				(13,433)
Total Crude Oil		1,896						16,338					$	98,233

Natural Gas
NYMEX
2020		17,308		$	2.02	$	2.34	1,000	$	2.30			$	(6,576)
2021		62,625		2.46		2.86		31,800	2.40				(31,070)
2022		8,700		2.50		2.79		8,700	2.62				(21)






Total Natural Gas		88,633						41,500					$	(37,667)






Basis Protection - Natural Gas
CIG
2020		—		$	—	$	—	17,350	$	(0.48)			$	(4,627)
2021		—		—		—		94,425	(0.46)				(13,433)
2022		—		—		—		17,400	(0.36)				(733)
Waha
2020		—		—		—		1,000	(1.40)				(511)


Total Basis Protection - Natural Gas		—						130,175					$	(19,304)












Commodity Derivatives Fair Value											$	41,262

_____________

(1)Approximately 14 percent of the fair value of our commodity derivative assets and 28 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).

Subsequent to September 30, 2020, we entered into the following commodity derivative positions covering our natural gas production:


	Collars					Fixed-Price Swaps
Commodity/ Index/ Maturity Period		Quantity (BBtu)		Weighted-Average Contract Price				Quantity (BBtu)	Weighted- Average Contract Price
	Floors		Ceilings
NYMEX
2022		8,700		$	2.50	$	3.00	—	—
Basis Protection
CIG
2022		—		—		—		8,700	$	(0.31)

We have not elected to designate any of our derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the condensed consolidated statements of operations.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

The following table presents the condensed consolidated balance sheet line item and fair value amounts of our derivative instruments as of September 30, 2020 and December 31, 2019:


			Fair Value
Derivative Instruments:		Condensed Consolidated Balance Sheet Line Item	September 30, 2020		December 31, 2019
			(in thousands)
Derivative assets:	Current
	Commodity derivative contracts	Fair value of derivatives	$	138,652	$	27,766


	Basis protection derivative contracts	Fair value of derivatives	—		312



			138,652		28,078
	Non-current
	Commodity derivative contracts	Fair value of derivatives	13,027		3,746





Total derivative assets			$	151,679	$	31,824

Derivative liabilities:	Current
	Commodity derivative contracts	Fair value of derivatives	$	50,969	$	529


	Basis protection derivative contracts	Fair value of derivatives	12,988		2,392



			63,957		2,921
	Non-current
	Commodity derivative contracts	Fair value of derivatives	40,144		692


	Basis protection derivative contracts	Fair value of derivatives	6,316		—



			46,460		692
Total derivative liabilities			$	110,417	$	3,613

The following table presents the impact of our derivative instruments on our condensed consolidated statements of operations:


	Three Months Ended September 30,				Nine Months Ended September 30,
Condensed Consolidated Statement of Operations Line Item	2020		2019		2020		2019
	(in thousands)
Commodity price risk management gain (loss), net
Net settlements	$	66,895	$	1,845	$	227,513	$	(19,800)
Net change in fair value of unsettled derivatives	(134,956)		53,022		18,338		(68,058)
Total commodity price risk management gain (loss), net	$	(68,061)	$	54,867	$	245,851	$	(87,858)

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 September 30, 2020	Derivative Instruments, Gross		Effect of Master Netting Agreements		Derivative Instruments, Net
	(in thousands)
Derivative assets:
Derivative instruments, at fair value	$	151,679	$	(51,823)	$	99,856

Derivative liabilities:
Derivative instruments, at fair value	$	110,417	$	(51,823)	$	58,594

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)


As of December 31, 2019	Derivative Instruments, Gross		Effect of Master Netting Agreements		Derivative Instruments, Net
	(in thousands)
Derivative assets:
Derivative instruments, at fair value	$	31,824	$	(2,619)	$	29,205

Derivative liabilities:
Derivative instruments, at fair value	$	3,613	$	(2,619)	$	994

NOTE 7 - PROPERTIES AND EQUIPMENT

The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization ("DD&A"):


	September 30, 2020		December 31, 2019
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	7,389,676	$	6,241,780
Unproved	381,428		403,379
Total crude oil and natural gas properties	7,771,104		6,645,159
Equipment and other	65,256		41,888
Land and buildings	24,859		12,312
Construction in progress	505,930		408,428
Properties and equipment, at cost	8,367,149		7,107,787
Accumulated DD&A	(3,481,915)		(3,012,585)
Properties and equipment, net	$	4,885,234	$	4,095,202

Impairment Charges. During the three months ended March 31, 2020, we recorded impairment charges of $881.1 million. The impairment charges during the three months ended March 31, 2020 were due to a significant decline in crude oil prices, which was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded impairment charges of $881.1 million to our proved and unproved properties. Of these impairment charges, approximately $753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and realized prices at which we reasonably expect the crude oil and natural gas will be sold. In addition to our proved property impairment, we also recognized approximately $127.3 million of impairment charges for our unproved properties in the Delaware Basin. These impairment charges were recognized based on a review of our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we have no development plans. There were no triggering events identified as of June 30 and September 30, 2020 and therefore we did not recognize any significant impairment write-downs with respect to our proved and unproved properties for the second and third quarter of 2020.

During the nine months ended September 30, 2019, we recorded impairment charges totaling $10.3 million, including $0.1 million during the three months ended September 30, 2019 related to leaseholds and leasehold expirations within our non-focus areas of the Delaware Basin where we were no longer pursuing plans to develop the properties. During the nine months ended September 30, 2019, we also recorded impairments of $26.7 million related to certain midstream facility infrastructure in the Delaware Basin. We determined the fair value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold.

Midstream Asset Divestitures. During the second quarter of 2019, we completed the sales of our Delaware Basin produced water gathering and disposal, crude oil gathering and natural gas gathering assets (the "Midstream Asset Divestitures") for aggregate proceeds of $345.6 million. The proceeds were received upon closing, with the exception of $82.0 million that we received in June 2020. Concurrent with the Midstream Asset Divestitures, we entered into agreements with the

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

purchasers which provide us with certain gathering, processing, transportation and water disposal services. See footnote titled Other Accrued Expenses and Other Liabilities for further details regarding these agreements. Proceeds were allocated first to the assets sold based upon the fair values of the tangible assets sold, with the remainder of $179.6 million allocated to the acreage dedication agreements. We recorded an aggregate gain on the sale of $34.0 million based on the fair value of the tangible assets sold.

Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the condensed consolidated balance sheets:


	Nine Months Ended September 30,		Year Ended December 31, 2019
	(in thousands, except for number of wells)

Beginning balance	$	16,078	$	12,188
Additions to capitalized exploratory well costs pending the determination of proved reserves	11,540		31,901
Reclassifications to proved properties	(20,392)		(28,011)

Ending balance	$	7,226	$	16,078

Number of wells pending determination at period-end	2		4

During nine months ended September 30, 2020, two wells classified as exploratory at December 31, 2019 were reclassified as productive and no new wells drilled were classified as exploratory.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

NOTE 8 - OTHER ACCRUED EXPENSES AND OTHER LIABILITIES

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


	September 30, 2020		December 31, 2019
	(in thousands)

Employee benefits	$	19,833	$	21,611
Asset retirement obligations	30,348		32,200

Environmental expenses	11,988		2,256
Operating and finance leases	8,809		5,926

Other	10,914		8,469
Other accrued expenses	$	81,892	$	70,462

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


	September 30, 2020		December 31, 2019
	(in thousands)

Production taxes	$	46,500	$	68,020
Deferred oil gathering credits	18,593		20,100
Deferred midstream gathering credits	170,508		175,897
Operating and finance leases	12,494		15,779
Other	2,440		3,337
Other liabilities	$	250,535	$	283,133

Deferred Oil Gathering Credits. In 2018, we entered into an agreement that dedicates crude oil production 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 over the life of the agreement. Amortization charges related to this deferred oil gathering credit totaling approximately $0.5 million for each of the three months ended September 30, 2020 and 2019 and $1.5 million for each of the nine months ended September 30, 2020 and 2019, are included as a reduction to transportation, gathering and processing expenses.

Deferred Midstream Gathering Credits. In the second quarter of 2019, concurrent with the sale of our Delaware Basin midstream assets, we entered into agreements with the purchasers that 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 10 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.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands)
Crude oil, natural gas and NGL sales (1)	$	—	$	201	$	368	$	259
Transportation, gathering and processing expenses	1,535		711		2,991		914
Lease operating expenses	686		373		1,458		557

_____________

(1)In July 2020, we entered into amendments to existing crude oil sales contracts, which resulted in a change in recognition of related deferred credit amortization from a net-back to a gross presentation of transportation, gathering and processing expenses.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

NOTE 9 - LONG-TERM DEBT

Long-term debt consisted of the following as of:


	September 30, 2020		December 31, 2019
	(in thousands)
Senior Notes:
1.125% Convertible Notes due September 2021:
Principal amount	$	200,000	$	200,000
Unamortized discount	(8,458)		(14,763)
Unamortized debt issuance costs	(934)		(1,666)
Net of unamortized discount and debt issuance costs	190,608		183,571

6.125% Senior Notes due September 2024:
Principal amount	400,000		400,000
Unamortized debt issuance costs	(3,876)		(4,611)
Net of unamortized debt issuance costs	396,124		395,389

6.25% Senior Notes due December 2025:
Principal amount	102,324		—
Unamortized premium	914		—
Net of unamortized premium	103,238		—

5.75% Senior Notes due May 2026:
Principal amount	750,000		600,000
Unamortized discount	(1,490)		—
Unamortized debt issuance costs	(6,873)		(5,734)
Net of unamortized discount and debt issuance costs	741,637		594,266

Total senior notes	1,431,607		1,173,226

Revolving Credit Facility:
Revolving credit facility due May 2023	285,000		4,000
Total debt, net of unamortized discount and premium and debt issuance costs	1,716,607		1,177,226
Less current portion of long-term debt	190,608		—
Long-term debt	$	1,525,999	$	1,177,226

Senior Notes

2021 Convertible Notes. In September 2016, we issued $200 million of 1.125% convertible notes due September 15, 2021 (the "2021 Convertible Notes"). Interest is payable semi-annually on March 15 and September 15. The conversion price at maturity is $85.39 per share. We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes.

Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash or a combination thereof. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

2024 Senior Notes. In September 2016, we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”). Interest is payable semi-annually on March 15 and September 15. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes.

2025 Senior Notes. Upon completion of the SRC Acquisition in January 2020, we assumed $550 million aggregate principal amount of 6.25% senior notes due December 1, 2025 (the "2025 Senior Notes"). The 2025 Senior Notes were recorded at $555.5 million, representing the approximate fair value. The difference between the acquisition date fair value and the principal amount of the 2025 Senior Notes will be recognized as a reduction to interest expense over the remaining life of the notes. Interest is payable semi-annually on June 1 and December 1. On January 17, 2020, we commenced an offer to repurchase the 2025 Senior Notes from the holders at 101 percent of the principal amount of the 2025 Senior Notes, together with any accrued and unpaid interest. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding 2025 Senior Notes accepted the redemption offer for a total redemption price of approximately $452.2 million, plus accrued and unpaid interest of $6.2 million. The fair value of the 2025 Senior Notes approximated the repurchase offer price, resulting in recognition of an immaterial loss on extinguishment of the repurchased notes. The repurchase was funded by proceeds from our revolving credit facility. An aggregate principal amount of approximately $102.3 million remains outstanding.

2026 Senior Notes. In November 2017, we issued $600.0 million aggregate principal amount of 5.75% senior notes due May 15, 2026 (the "2026 Senior Notes"). Interest is payable semi-annually on May 15 and November 15. Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes.

In September 2020, we issued an additional $150.0 million aggregate principal amount of the 2026 Senior Notes at a price equal to 99 percent of par, which resulted in net proceeds of $146.7 million, after deducting the original issuance discount of $1.5 million and debt issuance costs of $1.8 million. The additional 2026 Senior Notes issued have the same terms and conditions as the existing 2026 Senior Notes.

Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2021 Convertible Notes, the 2024 Senior Notes, the 2025 Senior Notes and the 2026 Senior Notes (collectively, the "Notes"). As of September 30, 2020, we were in compliance with all covenants related to the Notes.

Revolving Credit Facility

In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”). Among other things, the Restated Credit Agreement provides for a maximum credit amount of $2.5 billion. The amount we may borrow under the Restated Credit Agreement is subject to certain limitations. As a result of closing the SRC Acquisition, the borrowing base on our revolving credit facility increased to $2.1 billion and we elected to increase the aggregate commitment amount under our revolving credit facility to $1.7 billion. On May 5, 2020, we entered into a Second Amendment to the Restated Credit Agreement (the “Second Amendment”) that amended our interest rate and certain other provisions in the Restated Credit Agreement. In October 2020, as part of our fall 2020 semi-annual redetermination, the borrowing base of our credit facility was reduced to $1.6 billion, with a corresponding automatic reduction to our elected commitments of $1.6 billion.

The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other 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 outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month, plus a premium) or, at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of September 30, 2020, the applicable interest margin is 0.75 percent for the alternate base rate option or 1.75 percent for the LIBOR option, and the unused commitment fee

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

is 0.375 percent. Principal payments are generally not required until the revolving credit facility expires in May 2023, unless the borrowing base falls below the outstanding balance.

As of September 30, 2020 and December 31, 2019, debt issuance costs related to our revolving credit facility were $9.4 million and $8.9 million, respectively, and are included in other assets in our condensed consolidated balance sheets. As of September 30, 2020, the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was 2.2 percent.

NOTE 10 - LEASES

We determine if an arrangement is representative of a lease at contract inception. Right-of-use ("ROU") assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the commencement date based on the present value of the expected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms of our leases include options to extend or terminate the lease only when we can ascertain that it is reasonably certain we will exercise that option.

We have operating leases for office space and compressors and finance leases for vehicles. Our leases have remaining lease terms ranging from one to five years. The vehicle leases include options to renew for up to four years. Lease payments associated with vehicle leases also include a contractually stated residual value guarantee.

The following table presents the components of lease costs:


	Three Months Ended September 30,				Nine Months Ended September 30,
Lease Costs	2020		2019		2020		2019
	(in thousands)
Operating lease costs	$	2,030	$	1,093	$	5,842	$	3,824

Finance lease costs:
Amortization of ROU assets	473		506		1,462		1,493
Interest on lease liabilities	44		66		150		195
Total finance lease costs	517		572		1,612		1,688
Short-term lease costs	17,975		35,118		149,960		147,223

Total lease costs	$	20,522	$	36,783	$	157,414	$	152,735

Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense. Our short-term lease costs include amounts that are capitalized as part of the cost of another asset and are recorded as properties and equipment or recognized as expense.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

The following table presents the balance sheet classification and other information regarding our leases as of:


Leases	Condensed Consolidated Balance Sheet Line Item	September 30, 2020			December 31, 2019
		(in thousands)
Operating Leases:
Operating lease ROU assets	Other assets	$	13,484		$	14,926
Operating lease obligation - short-term	Other accrued expenses	7,183			4,159
Operating lease obligation - long-term	Other liabilities	10,496			12,944
Total operating lease liabilities		$	17,679		$	17,103
Finance Leases:
Finance lease ROU assets	Properties and equipment, net	$	3,647		$	4,637
Finance lease obligation - short-term	Other accrued expenses	1,626			1,767
Finance lease obligation - long-term	Other liabilities	1,998			2,835
Total finance lease liabilities		$	3,624		$	4,602
Weighted-average remaining lease term (years)
Operating leases		3.15			4.28
Finance leases		2.72			3.17
Weighted-average discount rate
Operating leases		5.0		%	5.0		%
Finance leases		5.0		%	5.0		%

Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of September 30, 2020 consist of the following:


	Operating Leases		Finance Leases		Total
	(in thousands)
2020 (remaining after September 30, 2020)	$	2,294	$	496	$	2,790
2021	7,055		1,580		8,635
2022	5,516		955		6,471
2023	1,559		669		2,228
2024	950		141		1,091
Thereafter	1,698		9		1,707
Total lease payments	19,072		3,850		22,922
Less interest and discount	(1,393)		(226)		(1,619)
Present value of lease liabilities	$	17,679	$	3,624	$	21,303

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

NOTE 11 - 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:


	Amount
	(in thousands)

Balance at December 31, 2019	$	127,251
Obligations incurred with development activities and other	7,588
Obligations incurred with acquisition	47,158
Accretion expense	7,398

Obligations discharged with asset retirements	(25,545)
Obligations discharged with divestitures	(146)
Balance at September 30, 2020	163,704

Current portion	(30,348)
Long-term portion	$	133,356

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

NOTE 12 - COMMITMENTS AND CONTINGENCIES

Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. Our condensed consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. We may from time to time find ourselves unable to market our commodities at prices acceptable to us, or at all, which could cause us to be unable to meet these obligations. In such cases, we may be subject to penalties, fees, minimum margins or other payments.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity and water delivery and disposal commitments:


	For the Twelve Months Ending September 30,
Area	2021		2022		2023		2024		2025 and Through Expiration		Total		Expiration Date

Natural gas (MMcf)
Wattenberg Field	63,922		63,922		63,922		64,098		86,876		342,740		August 31, 2026
Delaware Basin	32,022		14,510		9,125		9,150		57,075		121,882		March 31, 2031
Gas Marketing	7,117		6,228		—		—		—		13,345		August 31, 2022

Total	103,061		84,660		73,047		73,248		143,951		477,967

Crude oil (MBbls)
Wattenberg Field	17,338		15,500		13,035		9,882		18,900		74,655		August 31, 2026
Delaware Basin	8,214		8,030		8,030		2,024		—		26,298		December 31, 2023
Total	25,552		23,530		21,065		11,906		18,900		100,953

Water (MBbls)
Wattenberg Field	6,207		6,207		6,206		6,224		1,564		26,408		December 31, 2024



Dollar commitment (in thousands)	$	140,186	$	117,235	$	97,036	$	70,981	$	117,736	$	543,174

Wattenberg Field. We entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018 and the second plant was completed in August 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016 to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. In addition, as a result of the SRC Acquisition, we are subject to substantially similar facilities expansion agreements with the same primary midstream provider of 46.4 MMcfd and 43.8 MMcfd, respectively. We may be required to pay shortfall fees for any volumes under the 97.9 MMcfd and 77.3 MMcfd incremental commitments. Any shortfall in these volume commitments may be offset by other producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. The actual shortfall in target profit margin incurred, which we guaranteed to our midstream provider, was included as part of contract assets as part of Other assets in the condensed consolidated balance sheets.

Delaware Basin. In May 2018, we entered into a firm sales agreement that is effective from June 2018 through December 2023 with an integrated marketing company for our crude oil production in the Delaware Basin. Contracted volumes are currently 24,000 barrels of crude oil per day and decrease over time to 22,000 barrels per day. This agreement is expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices.

Crude Oil, Natural Gas and NGLs Sales. For the three months ended September 30, 2020 and 2019, amounts related to long-term transportation volumes in the table above were $4.5 million and $13.7 million, respectively, and were netted against our crude oil and natural gas sales. For the nine months ended September 30, 2020 and 2019, amounts related to long-term transportation volumes in the table above were $17.6 million and $36.8 million, respectively, and were netted against our crude oil and natural gas sales.

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 balance

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.

Environmental. Due to the nature of the natural gas and oil 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 September 30, 2020 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 in the condensed consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual.

In recent years, we have been executing a program to plug and abandon certain of our older vertical wells in the Wattenberg Field. A self-audit of final reclamation activities associated with site retirements, which we concluded in 2019, identified deficiencies, including incomplete documentation and agency submittals, inadequate plant growth and incomplete earthwork. In December 2019, we formally disclosed these deficiencies to the Colorado Oil and Gas Conservation Commission ("COGCC") and are working to close this backlog of site reclamation work. On August 19, 2020, COGCC issued to PDC a Notice of Alleged Violation ("NOAV") citing a failure to comply with reclamation requirements at multiple locations. During 2020, we are similarly assessing reclamation activities at sites acquired through the SRC Acquisition. We do not believe potential penalties and other expenditures associated with the deficiencies disclosed to the COGCC and the resulting NOAV, nor any potential future disclosure of deficiencies associated with reclamation of sites acquired in the SRC Acquisition, will have a material effect on our financial condition or results of operations, but they may exceed $100,000.

In July 2020, a ruling by the U.S. Court of Appeals for the District of Columbia Circuit found that the U.S. Environmental Protection Agency (“EPA”) established the northern boundary of the Denver Metro/Northern Front Range ozone non-attainment area based on erroneous criteria and ordered the EPA to reconsider that boundary, potentially including more land within the designated area. All of our Wattenberg Field operations and leaseholds are within the current non-attainment area. Accordingly, we do not expect the ruling to impact us, regardless of the results of the EPA’s boundary reconsideration.

As part of our integration activities over the facilities acquired through the SRC Acquisition, we are in the process of conducting a comprehensive air quality compliance audit. We do not believe potential penalties and other expenditures associated with deficiencies identified through the audit will have a material effect on our financial condition or results of operations, but they may exceed $100,000.

Clean Air Act Agreement and Related Consent Decree. In June 2017, following our receipt of a 2015 Clean Air Act information request from the EPA and a 2015 compliance advisory from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Pollution Control Division, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law.

In October 2017, we entered into a consent decree to resolve the lawsuit and the compliance advisory. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements, and environmental mitigations and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. While many of those actions are complete, some requirements will continue until the consent decree is terminated.

In addition, as a result of the SRC Acquisition, we are subject to the obligations and requirements of a 2018 Compliance Order on Consent (“COC”) entered into by SRC with CDPHE, applicable to certain SRC oil and gas production facilities. The CDPHE has agreed to revise the COC to make the inspection and monitoring requirements, among others, consistent with those contained in our consent decree.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

Since the consent decree took effect, and more recently was expanded to include the COC, we have timely implemented the various programs that meet its requirements. Over the course of this execution, we have identified certain immaterial deficiencies in our implementation of the programs. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $100,000.

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

NOTE 13 - COMMON STOCK

Stock-Based Compensation Plans

2018 Equity Incentive Plan. In May 2020, our stockholders approved an amendment to increase the number of shares of our common stock reserved for issuance pursuant to our long-term equity compensation plan for employees and non-employee directors (the “2018 Plan”) from 1,800,000 to 7,050,000. The 2018 Plan was approved in May 2018 and expires in March 2028. Shares issued may be authorized but unissued shares, treasury shares or any combination thereof. Additionally, the 2018 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or paid out in the form of cash. However, shares tendered or withheld to satisfy the exercise price of options or tax withholding obligations, and shares covering the portion of exercised stock-settled stock appreciation rights ("SARs") (regardless of the number of shares actually delivered), count against the share limit. Awards may be issued in the form of options, SARs, restricted stock, restricted stock units ("RSUs"), performance stock units ("PSUs") and other stock-based awards. Awards may vest over periods of continued service or upon the satisfaction of performance conditions set at the discretion of the Compensation Committee of the Board (the "Compensation Committee"), with a minimum one-year vesting period applicable to most awards. With regard to SARs and options, awards have a maximum exercisable period of ten years. As of September 30, 2020, there were 5,244,358 shares available for grant under the 2018 Plan.

2010 Long-Term Equity Compensation Plan. Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was approved by stockholders in 2013 (as the same has been amended and restated from time to time, 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 September 30, 2020, there were 159,237 shares available for grant under the 2010 Plan.

2015 SRC Equity Incentive Plan. Pursuant to the closing of the SRC Acquisition, SRC granted 155,928 PSUs to certain SRC executives under the 2015 SRC Equity Incentive Plan (the “2015 SRC Plan”). These PSUs (the “SRC PSUs”) were granted prior to the consummation of the merger, were assumed and converted into PDC PSUs at a rate of 0.158 per share and remain subject to the same terms and conditions (including performance-vesting terms) that applied immediately prior to the closing of the SRC Acquisition. The PSUs will result in a payout between zero and 200 percent of the target PSUs awarded. As of September 30, 2020, there were no shares available for grant under the 2015 SRC Plan.

Stock-based Compensation. The impact of our stock-based compensation plans on our results of operations was $5.4 million and $17.4 million for the three and nine months ended September 30, 2020, respectively, and $5.9 million and $18.1 million for the three and nine months ended September 30, 2019, respectively.

Restricted Stock Units

Time-Based Awards. The fair value of the time-based RSUs is amortized ratably over the requisite service period, primarily three years. The time-based RSUs generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

The following table presents the changes in non-vested time-based RSUs to all employees, including executive officers, for the nine months ended September 30, 2020:


	Shares	Weighted-Average Grant Date Fair Value per Share

Non-vested at December 31, 2019	795,926	$	45.51
Granted	1,151,273	12.00
Vested	(444,611)	41.87
Forfeited	(300,841)	22.87
Non-vested at September 30, 2020	1,201,747	20.42

The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:


	As of/Nine Months Ended September 30,
	2020		2019
	(in thousands, except per share data)

Total intrinsic value of time-based awards vested	$	6,124	$	11,251
Total intrinsic value of time-based awards non-vested	14,896		22,673
Market price per share as of September 30	12.40		27.75
Weighted-average grant date fair value per share	12.00		40.38

Total compensation cost related to non-vested time-based awards and not yet recognized in our condensed consolidated statements of operations as of September 30, 2020 was $15.7 million. This cost is expected to be recognized over a weighted-average period of 2.0 years.

Performance Stock Units

Market-Based Awards. The fair value of the market-based PSUs is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.

The Compensation Committee awarded a total of 368,077 market-based PSUs to our executive officers during the nine months ended September 30, 2020. 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, 2022, 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 weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions:


	Nine Months Ended September 30,
	2020			2019

Expected term of award (in years)	3			3
Risk-free interest rate	1.4		%	2.5		%
Expected volatility	46.6		%	41.4		%
Weighted-average grant date fair value per share	$	33.52		$	56.68

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 historical volatility.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

SRC Performance Stock Units. The terms of the SRC PSUs are substantially the same as those of the PDC PSUs, except that the SRC PSUs do not require continuous employment and the performance period associated with the awards of January 1, 2019 through December 31, 2021 predates the grant date. The fair value of the SRC PSU awards was determined on the grant date of January 13, 2020 using the Monte Carlo pricing model using the following assumptions:


	Nine Months Ended September 30,
	2020

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

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

The following table presents the change in non-vested market-based awards, including SRC PSUs, during the nine months ended September 30, 2020:


	Shares	Weighted-Average Grant Date Fair Value per Share

Non-vested at December 31, 2019	221,142	$	61.61
Granted	524,005	30.29
Vested	(10,196)	12.44
Forfeited	(89,597)	46.43
Non-vested at September 30, 2020	645,354	39.06

The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented:


	As of/Nine Months Ended September 30,
	2020		2019
	(in thousands, except per share data)


Total intrinsic value of market-based awards non-vested	$	7,999	$	6,719
Market price per common share as of September 30,	12.40		27.75
Weighted-average grant date fair value per share	30.29		56.68

Total compensation cost related to non-vested market-based awards not yet recognized in our condensed consolidated statements of operations as of September 30, 2020 was $9.3 million. This cost is expected to be recognized over a weighted-average period of 1.7 years.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

Stock Appreciation Rights

The SARs vest ratably over a three-year period and may generally be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. The following table presents the change in SARs during the nine months ended September 30, 2020:


	Shares	Weighted-Average Grant Date Fair Value per Share

Outstanding at December 31, 2019	290,258	$	46.64
Exercised	(7,807)	24.44
Expired	(71,776)	40.83
Outstanding at September 30, 2020	210,675	49.45

All outstanding SARs as of September 30, 2020 have vested and the related compensation cost has been fully recognized.

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 the Board from time to time. Through September 30, 2020, no shares of preferred stock have been issued.

Stock Repurchase Program

In April 2019, the Board approved the acquisition of up to $200 million of our outstanding common stock, depending on market conditions (the "Stock Repurchase Program"). Effective upon the closing of the SRC Acquisition, our Board approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million. Repurchases under the Stock Repurchase Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board at any time. During the nine months ended September 30, 2020, we repurchased 1.3 million shares of our outstanding common stock at a cost of $23.8 million. We suspended the program in March 2020. Approximately $346.8 million of our outstanding common stock remains available for repurchase under the program. If the program is reactivated, we expect repurchases made pursuant to the Stock Repurchase Program to extend beyond December 31, 2021, given current market conditions.

NOTE 14 - 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.

As previously noted, we recorded impairments totaling $882.3 million for the nine months ended September 30, 2020. These impairments resulted in three years of cumulative historical pre-tax losses and a net deferred tax asset position. We also have estimated net operating loss carryovers (“NOLs”) for federal income tax purposes of $470.0 million. These losses were a key consideration that led us to continue to provide a valuation allowance against our net deferred tax assets as of September 30, 2020 since we cannot conclude that it is more likely than not that our net deferred tax asset will be fully realized in future periods.

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. 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. Future events or new evidence which may lead us to conclude that it is more likely than not that our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings,

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)

sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. We will continue to evaluate whether the valuation allowance is needed in future reporting periods.

As noted in the footnote Business Combinations, the accounting for the SRC Acquisition is still in the measurement period. Additional adjustments during the measurement period for the SRC Acquisition may have an impact on the income tax provision in future periods, although such adjustments are not expected to be material. Other than business combination accounting adjustments during the measurement period, we will likely not have any additional income tax expense or benefit other than for state income taxes as long as we continue to conclude that it is appropriate to maintain a full valuation allowance against our net deferred tax assets.

The effective income tax rate for the three and nine months ended September 30, 2020 was a 0.6 percent provision on loss and a 0.5 percent benefit on loss, respectively, compared to a 40.1 percent provision on income for the three months ended September 30, 2019 and a 10.4 percent benefit on loss for the nine months ended September 30, 2019. The effective tax rate for the three and nine months ended September 30, 2020 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income due to the effect of a full valuation allowance in effect at September 30, 2020. The effective tax rate for the three and nine months ended September 30, 2019 differs from the statutory U.S. federal income tax rate of 21% due to state income taxes, non-deductible lobbying expenses, stock-based compensation and non-deductible officers’ compensation.

As of September 30, 2020, 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 2018 federal income tax return with no tax adjustments. We continue to voluntarily participate in the IRS CAP Program for the review of our 2019 and 2020 tax year. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings.

NOTE 15 - EARNINGS PER SHARE

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

The following table presents our weighted-average basic and diluted shares outstanding:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
	(in thousands)

Weighted-average common shares outstanding - basic	99,617	62,547	97,762	64,835
Dilutive effect of:
RSUs and PSUs	—	32	—	—

Other equity-based awards	—	16	—	—
Weighted-average common shares and equivalents outstanding - diluted	99,617	62,595	97,762	64,835

We reported a net loss for the three and nine months ended September 30, 2020 and the nine months ended September 30, 2019. As a result, our basic and diluted weighted-average common shares outstanding were the same for those periods because the effect of the common share equivalents was anti-dilutive.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(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:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2020	2019	2020	2019
	(in thousands)

Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
RSUs and PSUs	1,831	947	1,715	980

Other equity-based awards	223	267	231	302
Total anti-dilutive common share equivalents	2,054	1,214	1,946	1,282

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

NOTE 16 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION


	Nine Months Ended September 30,
	2020		2019
	(in thousands)
Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest	$	51,556	$	41,483
Income taxes	(204)		261

Non-cash investing and financing activities:
Change in accounts payable related to capital expenditures	$	(31,403)	$	(32,943)
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals	44,339		13,493
Change in accounts payable related to the purchase and retirement of treasury shares	—		2,818
Issuance of common stock for the acquisition of crude oil and natural gas properties, net	1,009,015		—

Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	6,714	$	4,107
Operating cash flows from finance leases	155		193


ROU assets obtained in exchange for lease obligations:
Operating leases	$	4,217	$	1,428
Finance leases	703		2,323

Subsequent to the filing of our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2019, we identified an immaterial error in our condensed consolidated statement of cash flows related to cash paid for capital expenditures for development of crude oil and natural gas properties for the period ended September 30, 2019. Our balance sheet and statement of operations for the relevant period were not impacted. We evaluated the error under the guidance of Accounting Standards Codification 250, Accounting Changes and Error Corrections ("ASC 250"). Based on the guidance in ASC 250, we determined that the error did not have a material impact on our previously-issued financial statements or those of the period of correction.

The error resulted in an overstatement of cash flows from operations of $24.8 million and an overstatement of cash used in investing activities of $24.8 million in each period as follows:

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(unaudited)


	Nine Months Ended
	September 30, 2019
	(dollars in thousands)
Cash flows from operating activities, as reported	$	675,725
Adjustment	(24,753)
Cash flows from operating activities, as adjusted	$	650,972

Cash flows from investing activities, as reported	$	(596,973)
Adjustment	24,753
Cash flows from investing activities, as adjusted	$	(572,220)

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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 elsewhere in this report. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements.

EXECUTIVE SUMMARY

September 30, 2020 Financial Overview of Operations and Liquidity

We have been adversely affected by the ongoing global COVID-19 pandemic, including its effects on commodity demand and pricing, downstream capacity, employee health and safety, business continuity and regulatory matters. We expect those impacts to continue in the near-term and we may experience additional impacts in the future. See Item 1A. Risk Factors for additional information regarding the potential impacts of the COVID-19 pandemic.

Production volumes increased to 17.7 MMboe and 51.8 MMboe for the three and nine months ended September 30, 2020, respectively, representing increases of 39 percent and 43 percent as compared to the three and nine months ended September 30, 2019, respectively. The majority of the increase can be attributed to producing properties received in the SRC Acquisition. Total liquids production of crude oil and NGLs comprised 61 percent and 60 percent of production during the three and nine months ended September 30, 2020, respectively. For the month ended September 30, 2020, we maintained an average daily production rate of approximately 181,000 Boe per day, up from approximately 138,000 Boe per day for the month ended September 30, 2019.

On a sequential quarterly basis, total production for the three months ended September 30, 2020 increased three percent to 17.7 MMboe as compared to 17.2 MMboe for the three months ended June 30, 2020.

Crude oil, natural gas and NGLs sales revenue increased to $314.9 million for the three months ended September 30, 2020 compared to $307.4 million for the three months ended September 30, 2019 and decreased to $809.2 million for the nine months ended September 30, 2020 compared to $967.5 million for the comparable period of 2019. The year to date decrease in revenues between periods was primarily due to the 41 percent decrease in weighted-average realized commodity prices, partially offset by the 42 percent increase in production.

We had positive net settlements from our commodity derivative contracts of $66.9 million and $227.5 million for the three and nine months ended September 30, 2020, respectively, as compared to positive net settlements of $1.8 million for the three months ended September 30, 2019 and negative net settlements of $19.8 million for the nine months ended September 30, 2019.

The combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 23 percent to $381.8 million for the three months ended September 30, 2020 from $309.2 million for the three months ended September 30, 2019 and increased nine percent to $1,036.7 million for the nine months ended September 30, 2020 from $947.7 million for the nine months ended September 30, 2019.

For the three months ended September 30, 2020, we generated a net loss of $30.8 million, or $0.31 per diluted share, compared to net income of $15.9 million, or $0.25 per diluted share, for the comparable period in 2019. Our net loss for the three months ended September 30, 2020 as compared to the net income for the three months ended September 30, 2019 was primarily due to a negative net change in the fair value of commodity derivatives, partially offset by decrease in loss on sale of properties and equipment of $44.2 million between periods. For the nine months ended September 30, 2020, we generated a net loss of $717.6 million, or $7.34 per diluted share, compared to a net loss of $35.7 million, or $0.55 per diluted share, for the comparable period in 2019. Our net loss for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019 was most significantly impacted by the increase in impairment of properties and equipment and the decrease in crude oil, natural gas and NGLs sales, partially offset by the commodity price risk management gain.

During the three and nine months ended September 30, 2020, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $278.8 million and $705.2 million, respectively, compared to $214.7 million and $646.4 million for the comparable periods in 2019. The increases for the three and nine months ended September 30, 2020 were primarily due to the increase in commodity derivative settlements of $65.1 million and $247.3 million, respectively, partially offset by increases in lease operating expenses, transportation, gathering and processing expenses and general and administrative expense between periods.

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PDC ENERGY, INC.

Our cash flows from operations were $649.3 million and $651.0 million and our adjusted cash flows from operations, a non-U.S. GAAP financial measure, were $652.8 million and $601.9 million for the nine months ended September 30, 2020 and September 30, 2019, respectively.

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.

SRC Acquisition

In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt. Upon closing, we issued approximately 39 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the Merger Agreement.

Liquidity

Available liquidity as of September 30, 2020 was $1.4 billion, which was comprised of $3.8 million of cash and cash equivalents and $1.4 billion available for borrowing under our revolving credit facility. In September 2020, we issued an additional $150.0 million principal amount of our 2026 Senior Notes. The net proceeds from the offering were used to repay a portion of the amount outstanding under our revolving credit facility. Total net repayments of revolver borrowings during the third quarter of 2020 were $368.0 million. In October 2020, as part of our fall 2020 semi-annual redetermination, the borrowing base of our credit facility was reduced from $1.7 billion to $1.6 billion, with a corresponding automatic reduction to our elected commitments to $1.6 billion. Looking forward into 2021, based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to repay our 2021 Convertible Notes, which mature in September 2021, and to fund our planned activities through the 12-month period following the filing of this report.

Drilling and Completion Overview

The following tables summarize our drilling and completion activity for the nine months ended September 30, 2020:


	Operated Wells
	Wattenberg Field		Delaware Basin		Total
	Gross	Net	Gross	Net	Gross	Net
In-process as of December 31, 2019	145	134.3	30	29.1	175	163.4
Wells spud	86	77.5	2	2.0	88	79.5
Wells acquired in-process (1)	88	81.9	—	—	88	81.9
Wells turned-in-line	(101)	(93.5)	(13)	(13.0)	(114)	(106.5)

In-process as of September 30, 2020	218	200.2	19	18.1	237	218.3

_____________

(1)Represents in-process wells and wells being completed that we received as part of the SRC Acquisition.


	Non-Operated Wells
	Wattenberg Field		Delaware Basin		Total
	Gross	Net	Gross	Net	Gross	Net
In-process as of December 31, 2019	41	5.3	—	—	41	5.3
Wells spud	68	7.2	—	—	68	7.2
Wells spud and subsequently sold prior to turned-in-line	(39)	(7.7)	—	—	(39)	(7.7)
Wells acquired in-process (now operated by PDC) (1)	(15)	(1.1)	—	—	(15)	(1.1)
Wells turned-in-line	(27)	(0.9)	—	—	(27)	(0.9)
In-process as of September 30, 2020	28	2.8	—	—	28	2.8

_____________

(1)Represents in-process wells and wells being completed that we received as part of the SRC Acquisition.

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

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PDC ENERGY, INC.

2020 Operational and Financial Outlook

In February 2020, the Board approved our initial 2020 development plan. This plan is based upon our February 2020 internal outlook for crude oil and natural gas prices, favorable debt metrics and the strength of our balance sheet, including our hedge position for 2020. Since that time, future commodity prices, and future crude oil prices in particular, have significantly declined. As a result, in April 2020, we finalized a comprehensive revision to our 2020 development plan, which includes estimated service cost savings and further reductions to planned drilling and completion activity. Our 2020 capital investments in crude oil and natural gas properties are now expected to range between $500 million and $550 million. The revised 2020 development plan is based upon our current outlook for the remainder of the year.

We currently anticipate that our total production for 2020 will range between 175,000 Boe to 185,000 Boe per day, approximately 64,000 Bbls to 68,000 Bbls of which are expected to be crude oil. This decrease as compared to our initial 2020 development plan is reflective of, among other things, a curtailment of our second quarter production volumes in response to takeaway capacity or market limitations, decreases in NYMEX pricing and significantly widened differentials, largely due to the global COVID-19 pandemic.

Wattenberg Field. We ran three drilling rigs in the Wattenberg Field through the middle of April 2020, when we dropped to a two-rig pace. We released a second rig at the end of May 2020, and expect to remain at a one-rig pace during the remainder of the year. We also released our only completion crew in the Wattenberg Field in early May 2020 but resumed completion activities in September 2020. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between the Kersey, Prairie, Plains and Summit development areas. Our 2020 capital investment program for the Wattenberg Field is approximately 85 percent of our expected total capital investments in crude oil and natural gas properties, of which approximately 90 percent is expected to be invested in operated drilling and completion activity. The majority of the wells we plan to drill in 2020 in the Wattenberg Field are mid-reach lateral (“MRL”) and extended-reach lateral (“XRL”) wells. In 2020, we anticipate spudding approximately 105 to 115 operated wells and turning-in-line approximately 120 to 130 operated wells. We expect an average development cost per well of between $2.5 million and $4.0 million, depending upon the lateral length of the well. The remainder of the Wattenberg Field capital investment program is expected to be used for land, capital workovers, facilities projects and non-operated drilling.

Delaware Basin. In the Delaware Basin, we ran one drilling rig through early May 2020 and we released our only active completion crew in March 2020. We do not expect material activities in the Delaware Basin for the remainder of 2020. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2020 are expected to be approximately 15 percent of our total capital investments in crude oil and natural gas properties, of which approximately 95 percent is expected to be invested in operated drilling and completion activity. In 2020, we have spud ten operated wells (eight of which were started as part of a batch drilling process prior to the end of 2019) and have turned-in-line 13 operated wells. The wells we drilled in 2020 in the Delaware Basin are MRL and XRL wells.

Financial Guidance. We are committed to our disciplined approach to managing our development plans. Based on our updated production forecast for 2020 and assumed average NYMEX prices of $35.00 per Bbl of crude oil and $2.50 per Mcf of natural gas and an assumed average composite price of $10.00 per Bbl for NGLs for the fourth quarter of 2020, we expect 2020 adjusted cash flows from operations, a non-U.S. GAAP financial measure, to exceed our capital investments in crude oil and natural gas properties by more than $350 million.

The following table sets forth our current financial guidance for the year ended December 31, 2020 for certain expenses:


	Low			High
Operating Expenses
Lease operating expenses (in millions)	$	160		$	165
Transportation, gathering and processing expenses ("TGP") ($/Boe)	$	1.00		$	1.15
Production taxes (% of crude oil, natural gas and NGLs sales)	5		%	6		%
General and administrative expense (in millions)(1)	$	135		$	140

_____________

(1)Excluding transaction costs incurred related to the SRC Acquisition of approximately $20.2 million.

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PDC ENERGY, INC.

Colorado Political Update

Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state. In late July 2020, Governor Polis authored an op-ed stating that both industry and mainstream environmental groups have communicated a willingness to stand down on ballot initiatives in 2020, and to work together to prevent initiatives in 2022, while the regulatory process associated with 2019’s Senate Bill 19-181 ("SB-181") is in progress. As part of that agreement, Governor Polis stated that he would “actively oppose” ballot initiatives around the oil and gas industry and acknowledged the importance of regulatory certainty.

As part of the SB-181 rulemaking process, in September 2020, Colorado Oil and Gas Conservation Commission ("COGCC") held hearings related to certain aspects of SB-181, including but not limited to setbacks and siting requirements. The COGCC commissioners determined that locations with building units within 2,000 feet would be subject to additional siting requirements, but also supported “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from building units in certain circumstances. These would include when a tenant or owner, with informed consent, agrees to drilling closer; when the location is part of a comprehensive area plan that organizes multiple drill sites; when the wells, tanks and compressors are 2,000 feet from a building unit, even if the edge of the drill pad is closer; or when a commission hearing finds substantial protections at the site. A formal vote related to this particular rulemaking series is expected to take place in late November 2020, with all SB-181 rulemaking expected to be finalized in 2021.

Because approximately 81 percent of our proved reserves are located in Colorado, the risks we face with respect to possible future setbacks, siting requirements and other regulatory requirements, implemented through statute, rules or ballot proposals, are greater than those of our competitors with more geographically diverse operations. We cannot predict the outcome of possible future regulatory developments.

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PDC ENERGY, INC.

Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		Percent Change		2020		2019		Percent Change
	(dollars in millions, except per unit data)
Production
Crude oil (MBbls)	6,029		4,853		24.2	%	18,133		14,277		27.0	%
Natural gas (MMcf)	41,747		29,273		42.6	%	123,802		83,916		47.5	%
NGLs (MBbls)	4,714		2,983		58.0	%	13,028		8,091		61.0	%
Crude oil equivalent (MBoe)	17,701		12,714		39.2	%	51,794		36,354		42.5	%
Average Boe per day (Boe)	192,402		138,195		39.2	%	189,029		133,165		42.0	%
Crude Oil, Natural Gas and NGLs Sales
Crude oil	$	226.0	$	255.7	(11.6)	%	$	591.0	$	761.0	(22.3)	%
Natural gas	41.9		26.6		57.5	%	112.5		110.1		2.2	%
NGLs	47.0		25.1		87.3	%	105.7		96.4		9.6	%
Total crude oil, natural gas and NGLs sales	$	314.9	$	307.4	2.4	%	$	809.2	$	967.5	(16.4)	%

Net Settlements on Commodity Derivatives
Crude oil	$	69.7	$	(1.9)	*		$	231.7	$	(19.5)	*
Natural gas	(2.8)		3.7		(175.7)	%	(4.2)		(0.3)		*

Total net settlements on derivatives	$	66.9	$	1.8	*		$	227.5	$	(19.8)	*

Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	37.49	$	52.70	(28.9)	%	$	32.59	$	53.30	(38.9)	%
Natural gas (per Mcf)	1.00		0.91		9.9	%	0.91		1.31		(30.5)	%
NGLs (per Bbl)	9.97		8.43		18.3	%	8.12		11.92		(31.9)	%
Crude oil equivalent (per Boe)	17.79		24.18		(26.4)	%	15.62		26.61		(41.3)	%







Average Costs and Expenses (per Boe)
Lease operating expenses	$	2.11	$	2.87	(26.5)	%	$	2.37	$	2.92	(18.8)	%
Production taxes	0.83		1.03		(19.4)	%	0.79		1.59		(50.3)	%
Transportation, gathering and processing expenses	1.38		0.87		58.6	%	1.06		0.95		11.6	%
General and administrative expense	1.84		3.23		(43.0)	%	2.51		3.40		(26.2)	%
Depreciation, depletion and amortization	8.16		13.52		(39.6)	%	9.08		13.53		(32.9)	%

Lease Operating Expenses by Operating Region (per Boe)
Wattenberg Field	$	1.89	$	2.51	(24.7)	%	$	2.17	$	2.53	(14.2)	%
Delaware Basin	3.21		3.94		(18.5)	%	3.42		4.21		(18.8)	%

_____________

Percent change is not meaningful.

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PDC ENERGY, INC.

Crude Oil, Natural Gas and NGLs Sales

Crude oil, natural gas and NGLs sales revenue for the three months ended September 30, 2020 increased compared to the three months ended September 30, 2019 and decreased for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 due to the following:


	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020
	(in millions)
Change in:
Production	$	87.9	$	316.6

Average crude oil price	(91.7)		(375.5)
Average natural gas price	4.0		(49.9)
Average NGLs price	7.3		(49.5)
Total change in crude oil, natural gas and NGLs sales revenue	$	7.5	$	(158.3)

Crude Oil, Natural Gas and NGLs Production

The following table presents crude oil, natural gas and NGLs production:


	Three Months Ended September 30,				Nine Months Ended September 30,
Production by Operating Region	2020	2019	Percent Change		2020	2019	Percent Change
Crude oil (MBbls)
Wattenberg Field	4,888	3,525	38.7	%	14,984	10,777	39.0	%
Delaware Basin	1,141	1,328	(14.1)	%	3,149	3,500	(10.0)	%


Total	6,029	4,853	24.2	%	18,133	14,277	27.0	%
Natural gas (MMcf)
Wattenberg Field	35,450	22,945	54.5	%	105,286	67,139	56.8	%
Delaware Basin	6,297	6,328	(0.5)	%	18,516	16,777	10.4	%


Total	41,747	29,273	42.6	%	123,802	83,916	47.5	%
NGLs (MBbls)
Wattenberg Field	4,006	2,178	83.9	%	11,037	6,086	81.4	%
Delaware Basin	708	805	(12.0)	%	1,991	2,005	(0.7)	%


Total	4,714	2,983	58.0	%	13,028	8,091	61.0	%
Crude oil equivalent (MBoe)
Wattenberg Field	14,803	9,527	55.4	%	43,569	28,053	55.3	%
Delaware Basin	2,898	3,187	(9.1)	%	8,225	8,301	(0.9)	%


Total	17,701	12,714	39.2	%	51,794	36,354	42.5	%
Average crude oil equivalent per day (Boe)
Wattenberg Field	160,902	103,554	55.4	%	159,011	102,758	54.7	%
Delaware Basin	31,500	34,641	(9.1)	%	30,018	30,407	(1.3)	%

Total	192,402	138,195	39.2	%	189,029	133,165	42.0	%

_____________

Amounts may not recalculate due to rounding.

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


Three Months Ended September 30, 2020

	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	33%	40%	27%	100%
Delaware Basin	40%	36%	24%	100%

Three Months Ended September 30, 2019

	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	37%	40%	23%	100%
Delaware Basin	42%	33%	25%	100%


Nine Months Ended September 30, 2020

	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	34%	41%	25%	100%
Delaware Basin	38%	38%	24%	100%

Nine Months Ended September 30, 2019

	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	38%	40%	22%	100%
Delaware Basin	42%	34%	24%	100%

The overall production increase during the three and nine months ended September 30, 2020 compared to the same periods in 2019 was primarily due to the SRC Acquisition, partially offset by normal field production declines across our existing wells.

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 to use on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. In response to the substantial development drilling in our current areas of operation in recent years, third-party midstream providers have significantly expanded their midstream facilities and services. These third-party midstream facility expansions, in conjunction with the more recent slowdown in producer activity, have provided for improved and more stabilized line pressures which are providing a production environment that is more favorable for producers, both currently and for the near term given anticipated producer activity levels.

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 of construction payments for commitment shortfalls.

Wattenberg Field. Beginning in the mid-fourth quarter of 2019 and continuing through the third quarter of 2020, the combination of DCP Midstream, LP's ("DCP") continued system expansions and the availability of both residue gas and NGL takeaway out of the basin allowed DCP to more meaningfully reduce line pressures in all of our operated areas of the Wattenberg Field. DCP was able to fully utilize its most recent processing and bypass infrastructure expansions during the first three quarters of 2020. In addition, by year-end 2020, DCP is forecasted to complete another processing expansion of up to an incremental 225 MMcfd. Given current and forecasted activity levels in the basin, we anticipate that this expansion will provide ample processing capacity.

Our production in the Wattenberg Field is significantly dependent on DCP's gathering system, and this reliance increased considerably when we closed the SRC Acquisition. We continue to work with our midstream service providers in an

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effort to ensure all of the existing in-basin infrastructure is fully utilized and that all options for system expansion are evaluated and implemented to the extent possible to accommodate projected future volume growth from the field.

As midstream infrastructure development continues, we anticipate having the ability to move additional volumes on DCP’s system in 2020 and beyond. The successful and timely completion of these development projects is dependent on continued capital investment by DCP and other third-party midstream providers, which could be impacted by current market conditions.

Delaware Basin. Our production from the Delaware Basin was not materially affected by midstream or downstream capacity constraints during the nine months ended September 30, 2020. Similar to the Wattenberg Field, our crude oil netback pricing realizations were most negatively impacted by the demand reduction from COVID-19.

Pipeline utilization in the Permian Basin has fallen from the constrained levels experienced during the first quarter of 2020. The COVID-19-induced downturn also forced widespread curtailments in natural gas production, which lowered pipeline utilization and eventually improved pricing differentials in the basin during the second and third quarter of 2020. The completion of Kinder Morgan’s Permian Highway Pipeline anticipated in the first quarter of 2021 is expected to provide additional takeaway capacity out of the Permian Basin.

Crude Oil, Natural Gas and NGLs Pricing

Our results of operations depend upon many factors. Key factors include market prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices have a high degree of volatility and our realizations can change substantially. Our realized sales prices for crude oil, natural gas and NGLs decreased 26 percent and 41 percent during the three and nine months ended September 30, 2020, respectively, compared to the three and nine months ended September 30, 2019. The NYMEX average daily crude oil prices decreased 27 percent and 33 percent for the three and nine months ended September 30, 2020, respectively, as compared to the same period in 2019. The NYMEX average first-of-the-month natural gas price decreased 11 percent and 30 percent for the three and nine months ended September 30, 2020, respectively, as compared to the same period in 2019.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
Weighted-Average Realized Sales Price by Operating Region					Percent Change						Percent Change
(excluding net settlements on derivatives)	2020		2019				2020		2019
Crude oil (per Bbl)
Wattenberg Field	$	37.52	$	52.64	(28.7)	%	$	32.28	$	52.84	(38.9)	%
Delaware Basin	37.33		52.84		(29.4)	%	34.09		54.70		(37.7)	%
Weighted-average price	37.49		52.70		(28.9)	%	32.59		53.30		(38.9)	%
Natural gas (per Mcf)
Wattenberg Field	$	1.12	$	1.04	7.7	%	$	1.04	$	1.50	(30.7)	%
Delaware Basin	0.34		0.41		(17.1)	%	0.17		0.55		(69.1)	%
Weighted-average price	1.00		0.91		9.9	%	0.91		1.31		(30.5)	%
NGLs (per Bbl)
Wattenberg Field	$	9.70	$	7.76	25.0	%	$	7.87	$	11.06	(28.8)	%
Delaware Basin	11.50		10.22		12.5	%	9.48		14.53		(34.8)	%
Weighted-average price	9.97		8.43		18.3	%	8.12		11.92		(31.9)	%
Crude oil equivalent (per Boe)
Wattenberg Field	$	17.70	$	23.76	(25.5)	%	$	15.60	$	26.29	(40.7)	%
Delaware Basin	18.24		25.42		(28.2)	%	15.73		27.69		(43.2)	%
Weighted-average price	17.79		24.18		(26.4)	%	15.62		26.61		(41.3)	%

_____________


Amounts may not recalculate due to rounding.

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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. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received.

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 for 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 expenses.

Beginning in the second quarter of 2020, COVID-19 led to government restrictions on movement and economic activity, triggering a dramatic reduction in crude oil demand. This negatively impacted crude oil netback pricing realizations, which resulted in production curtailments during the second and third quarter. We expect our realized crude oil prices to be volatile for the remainder of the year through next year due to market uncertainties in crude oil demand as a result of COVID-19.

As discussed above, we enter into agreements for the sale and transportation, gathering and processing of our production, the terms of which can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. Information related to the components and classifications in 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 NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after transportation, gathering and processing expenses shown in the table below represents our approximate composite per barrel price for NGLs.

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Three Months Ended September 30, 2020	Average NYMEX Price		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses		Average Realization Percentage After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	40.93	$	37.49	92	%	$	3.00	$	34.49	84	%
Natural gas (per MMBtu)	1.98		1.00		51	%	0.12		0.88		44	%
NGLs (per Bbl)	40.93		9.97		24	%	—		9.97		24	%
Crude oil equivalent (per Boe)	29.50		17.79		60	%	1.30		16.49		56	%

Three Months Ended September 30, 2019	Average NYMEX Price		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses		Average Realization Percentage After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	56.45	$	52.70	93	%	$	1.29	$	51.41	91	%
Natural gas (per MMBtu)	2.23		0.91		41	%	0.15		0.76		34	%
NGLs (per Bbl)	56.45		8.43		15	%	—		8.43		15	%
Crude oil equivalent (per Boe)	39.92		24.18		61	%	0.83		23.35		58	%


Nine Months Ended September 30, 2020	Average NYMEX Price		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses		Average Realization Percentage After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	38.32	$	32.59	85	%	$	2.11	$	30.48	80	%
Natural gas (per MMBtu)	1.88		0.91		48	%	0.12		0.79		42	%
NGLs (per Bbl)	38.32		8.12		21	%	—		8.12		21	%
Crude oil equivalent (per Boe)	27.55		15.62		57	%	1.02		14.60		53	%

Nine Months Ended September 30, 2019	Average NYMEX Price		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses		Average Realization Percentage After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	57.06	$	53.30	93	%	$	1.23	$	52.07	91	%
Natural gas (per MMBtu)	2.67		1.31		49	%	0.17		1.14		43	%
NGLs (per Bbl)	57.06		11.92		21	%	0.14		11.78		21	%
Crude oil equivalent (per Boe)	41.25		26.61		65	%	0.92		25.69		62	%

Our average realization percentages for crude oil decreased materially for the three and nine months ended September 30, 2020 as compared to the same periods in 2019, primarily due to the global deterioration of commodity prices as a result of continued effects from COVID-19, geopolitical conditions and supply disruptions. We expect crude oil realizations for the remainder of 2020 to remain relatively similar to the third quarter of 2020.

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Commodity Price Risk Management

We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices, including collars, fixed-price swaps and basis protection swaps on a portion of our estimated crude oil and natural gas production. For our commodity swaps, we ultimately realize the fixed price value related to the swaps. See the footnote titled Commodity Derivative Financial Instruments to our accompanying condensed consolidated financial statements included elsewhere in this report for a summary of our derivative positions as of September 30, 2020.

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

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil collars and fixed price swaps	$	69.7	$	(1.9)	$	231.7	$	(19.5)

Natural gas collars and fixed price swaps	2.3		5.1		5.9		5.7
Natural gas basis protection swaps	(5.1)		(1.4)		(10.1)		(6.0)

Total net settlements of commodity derivative instruments	66.9		1.8		227.5		(19.8)
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments	(75.9)		2.5		(9.5)		(61.5)
Crude oil collars and fixed price swaps	(25.2)		49.8		83.9		(8.0)
Natural gas collars and fixed price swaps	(24.4)		0.1		(37.5)		3.2
Natural gas basis protection swaps	(9.5)		0.6		(18.5)		(1.8)

Net change in fair value of unsettled commodity derivative instruments	(135.0)		53.0		18.4		(68.1)
Total commodity price risk management gain (loss), net	$	(68.1)	$	54.8	$	245.9	$	(87.9)

Lease Operating Expenses

Lease operating expenses ("LOE") increased slightly by two percent to $37.3 million for the three months ended September 30, 2020 compared to $36.5 million for the three months ended September 30, 2019. The period-over-period increase in LOE is primarily attributable to the wells acquired from our SRC Acquisition in January 2020 offset by vendor price concessions. LOE per Boe decreased 26 percent to $2.11 for the three months ended September 30, 2020 from $2.87 for the three months ended September 30, 2019, primarily due to a 39 percent increase in production volumes and vendor prices concessions between periods.

LOE increased 16 percent to $122.7 million for the nine months ended September 30, 2020 compared to $106.0 million in the nine months ended September 30, 2019. The period-over-period increase in LOE was primarily attributable to the wells acquired from our SRC Acquisition in January 2020 and our drilling activity in the Wattenberg Field. Specifically, the increase was primarily due to $8.0 million in additional well services, an increase of $5.7 million in produced water disposal, and a $3.4 million increase in non-operated well expenses. The increases were partially offset by a $3.0 million decrease related to midstream expenses resulting from the sale of Delaware Basin midstream assets during the second quarter of 2019, vendor

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prices concessions and reduced activity from well shut ins during the three months ended June 30, 2020. Lease operating expense per Boe decreased by 19 percent to $2.37 for the nine months ended September 30, 2020 from $2.92 for the nine months ended September 30, 2019, primarily due to a 42 percent increase in production volumes, vendor price concessions and reduced activity between periods.

Production Taxes

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

Production taxes increased 12 percent to $14.6 million for the three months ended September 30, 2020 compared to $13.0 million for the three months ended September 30, 2019, primarily due to revenue generated from the wells acquired from our SRC Acquisition in January 2020 as the wells operate in areas with higher ad valorem tax rates. Production taxes per Boe decreased 19 percent to $0.83 for the three months ended September 30, 2020 compared to $1.03 for the three months ended September 30, 2019 due to lower realized prices for crude oil and our 39 percent increase in production volumes between periods .

Production taxes decreased 29 percent to $40.9 million for the nine months ended September 30, 2020 compared to $57.8 million for the nine months ended September 30, 2019, primarily due to reductions in revenues, effective severance tax rates in the Wattenberg Field, and lower tax assessments on our oil and gas reserve appraisal values in the Delaware Basin during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. Production taxes per Boe decreased 50 percent to $0.79 for the nine months ended September 30, 2020 compared to $1.59 for the nine months ended September 30, 2019 due to lower realized prices for crude oil, natural gas and NGLs between periods.

Transportation, Gathering and Processing Expenses

Transportation, gathering and processing expenses ("TGP") increased 122 percent to $24.4 million for the three months ended September 30, 2020 compared to $11.0 million for the three months ended September 30, 2019 and increased 58 percent to $54.8 million in the nine months ended September 30, 2020 compared to $34.6 million in the nine months ended September 30, 2019. The increase in TGP was primarily due to increases in transportation rates relating to our crude oil volumes delivered, additional new transportation agreements entered in 2020, higher production volumes between periods as a result of the SRC Acquisition as well as amendments to existing crude oil sales contracts, which resulted in a change in recognition from a net-back to a gross presentation of TGP.

TGP per Boe increased 59 percent to $1.38 for the three months ended September 30, 2020 compared to $0.87 for the three months ended September 30, 2019 and increased 12 percent to $1.06 for the nine months ended September 30, 2020 compared to $0.95 for the nine months ended September 30, 2019. The increase of TGP per Boe between periods was primarily due to an increase in TGP as discussed above, partially offset by an increase in production volume delivered.

Impairment of Properties and Equipment

The following table sets forth the major components of our impairment of properties and equipment:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Impairment of proved and unproved properties	$	0.1	$	0.1	$	881.2	$	10.3

Impairment of infrastructure and other	1.1		—		1.1		26.7
Impairment of properties and equipment	$	1.2	$	0.1	$	882.3	$	37.0

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Impairment Charges. During the three months ended March 31, 2020, we recorded impairment charges of $881.1 million. The impairment charges during the three months ended March 31, 2020 were due to a significant decline in crude oil prices, which was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded impairment charges of $881.1 million to our proved and unproved properties. Of these impairment charges, approximately $753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and realized prices at which we reasonably expect the crude oil and natural gas will be sold. In addition to our proved property impairment, we also recognized approximately $127.3 million of impairment charges for our unproved properties in the Delaware Basin. These impairment charges were recognized based on a review of our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we have no development plans. We did not recognize any significant impairment write-downs with respect to our proved and unproved properties for the second and third quarter of 2020. If future crude oil prices continue to decline to lower levels, or other estimates impacting future net cash flows deteriorate (e.g. reserves, price differentials, future operating and/or development costs), our proved and unproved oil and gas properties could be subject to additional impairments in future periods.

During the nine months ended September 30, 2019, we recorded impairment charges totaling $10.3 million, including

$0.1 million during the three months ended September 30, 2019 related to leaseholds and leasehold expirations within our non-focus areas of the Delaware Basin where we were no longer pursuing plans to develop the properties. During the nine months ended September 30, 2019, we also recorded impairments of $26.7 million related to certain midstream facility infrastructure in the Delaware Basin. We determined the fair value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold.

General and Administrative Expense

General and administrative expense decreased 21 percent to $32.5 million for the three months ended September 30, 2020 compared to $41.1 million for the three months ended September 30, 2019 primarily due to decreases of $4.7 million in professional fees related to the SRC Acquisition costs, $3.3 million in professional fees and $2.1 million in the allowance adjustment for royalty owner payments. The decreases were partially offset by a $2.3 million increase in payroll and related benefits.

General and administrative expense increased 5 percent to $130.0 million for the nine months ended September 30, 2020 compared to $123.5 million for the nine months ended September 30, 2019 primarily due to increases of $20.2 million in transaction costs related to the SRC Acquisition and $2.5 million insurance reimbursement related to legal fees that was received in the second quarter of 2019. The increases were partially offset by decreases of $7.9 million for professional fees, $5.6 million in shareholder activism fees, and $2.1 million in the allowance adjustment for royalty owner payments incurred in the nine months ended September 30, 2019.

Depreciation, Depletion and Amortization Expense

Crude oil and natural gas properties. 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 $142.3 million and $463.5 million for the three and nine months ended September 30, 2020, respectively, compared to $170.5 million and $487.5 million for the three and nine months ended September 30, 2019, respectively.

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


	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020
	(in millions)
Increase in production	$	60.8	$	189.9
Decrease in weighted-average depreciation, depletion and amortization rates	(89.0)		(213.9)
Total increase in DD&A expense related to crude oil and natural gas properties	$	(28.2)	$	(24.0)

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


	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Region/Area	2020		2019		2020		2019
	(per Boe)
Wattenberg Field	$	8.33	$	12.42	$	8.80	$	12.32
Delaware Basin	6.87		16.34		10.06		17.07

Total weighted-average	8.16		13.41		9.08		13.41

The decrease in DD&A expense rate in the Delaware Basin was primarily due to the proved property impairment recognized in the first quarter of 2020, which lowered the carrying value of our depletion base.

Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $2.2 million and $6.7 million for the three and nine months ended September 30, 2020, respectively, compared to $1.4 million and $4.3 million for the three and nine months ended September 30, 2019, respectively.

Loss on sale of properties and equipment

In September 2019, we exchanged acreage located in Reeves County, Texas. As additional consideration for the acreage acquired, we paid $2.7 million in cash and recognized a loss of $45.6 million based on the carrying value of the acreage sold.

Interest Expense, Net

Interest expense, net increased $3.2 million to $21.0 million for the three months ended September 30, 2020 compared to $17.8 million for the three months ended September 30, 2019. The increase was primarily related to a $2.6 million increase related to the assumption of SRC's 2025 Senior Notes and a $1.2 million increase in interest expense related to our revolving credit facility. The increases were partially offset by a $1.1 million increase in capitalized interest.

Interest expense, net increased $13.3 million to $67.0 million for the nine months ended September 30, 2020 compared to $53.7 million for the nine months ended September 30, 2019. The increase was primarily related to a $10.3 million increase in interest expense related to our revolving credit facility as a result of higher borrowings between periods and a $7.4 million increase related to the assumption of SRC's 2025 Senior Notes. The increases were partially offset by a $5.1 million increase in capitalized interest.

Provision for Income Taxes

We recorded a full valuation allowance against our net deferred tax assets for the nine months ended September 30, 2020 resulting in effective income tax rates of a 0.6 percent provision on loss and a 0.5 percent benefit on loss for the three and nine months ended September 30, 2020, respectively, compared to a 40.1 percent provision on income and a 10.4 percent benefit on loss for the three and nine months ended September 30, 2019, respectively. The effective tax rate for the three and nine months ended September 30, 2020 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income due to the effect of a full valuation allowance in effect at September 30, 2020. The effective tax rate for the three and nine months ended September 30, 2019 differs from the statutory U.S. federal income tax rate of 21% due to state income taxes, non-deductible lobbying expenses, stock-based compensation and non-deductible officers’ compensation.

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taxable income in making this assessment. Future events or new evidence which may lead us to conclude that it is more likely than not that our net deferred tax assets 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. We will continue to evaluate whether the valuation allowance is needed in future reporting periods.

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

The factors impacting net losses of $30.8 million and $717.6 million for the three and nine months ended September 30, 2020, respectively, and net income of $15.9 million and a net loss of $35.7 million for the three and nine months ended September 30, 2019, respectively, are discussed above.

Adjusted net income, a non-U.S. GAAP financial measure, was $104.2 million for the three months ended September 30, 2020 and adjusted net loss was $736.0 million for the nine months ended September 30, 2020. For the three months ended September 30, 2019, the adjusted net loss was $24.5 million and for the nine months ended September 30, 2019, the adjusted net income was $16.1 million. With the exception of the tax-affected (when applicable) net change in fair value of unsettled derivatives, the same factors impacted adjusted net income (loss), a non-U.S. GAAP financial measure. 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

Our primary sources of liquidity are cash flows from operating activities, borrowings from our revolving credit facility, asset sales and proceeds raised in debt and equity capital market transactions. For the nine months ended September 30, 2020, our net cash flows from operating activities were $649.3 million.

Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage a portion of this volatility through our use of derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production.

We may use our available liquidity for operating activities, capital investments, working capital requirements, acquisitions and for general corporate purposes. We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells.

Our working deficit increased to $396.2 million at September 30, 2020 from $57.2 million at December 31, 2019. The increase was primarily attributable to our Convertible Notes maturing in September 2021, which resulted in the notes being classified in current liabilities, an increase in the fair value liability of our commodity derivatives and additional current liabilities resulting from the SRC Acquisition. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time.

Our cash and cash equivalents were $3.8 million at September 30, 2020 and availability under our revolving credit facility was $1.4 billion, providing for a total liquidity position of $1.4 billion as of September 30, 2020. In October 2020, as part of our fall 2020 semi-annual redetermination, the borrowing base of our credit facility was reduced from $1.7 billion to $1.6 billion, with a corresponding automatic reduction to our elected commitments to $1.6 billion.

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Based on our updated production forecast for 2020 and assumed average NYMEX prices of $35.00 per Bbl of crude oil and $2.50 per Mcf of natural gas and an assumed average composite price of $10.00 per Bbl for NGLs for the fourth quarter of 2020, we expect 2020 adjusted cash flows from operations, a non-U.S. GAAP financial measure, to exceed our capital investments in crude oil and natural gas properties by more than $350 million.

As a result of merging with SRC, we assumed the SRC Senior Notes and paid off and terminated SRC's revolving credit facility. On January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes at 101 percent of the principal amount. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding SRC Senior Notes accepted our redemption offer for a total redemption price of approximately $452.2 million, plus accrued and unpaid interest of $6.2 million. We funded the repurchase with proceeds from our revolving credit facility. An aggregate principal amount of approximately $102.3 million of the SRC Senior Notes remains outstanding.

In September 2020, we issued an additional $150.0 million principal amount of our 2026 Senior Notes. The net proceeds from the offering were used to repay a portion of the amount outstanding under our revolving credit facility. Total net repayments of revolver borrowings during the third quarter of 2020 were $368.0 million.

In April 2019, the Board approved the Stock Repurchase Program. Effective upon on the closing of the SRC Acquisition, our Board approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million. During the nine months ended September 30, 2020, we repurchased 1.3 million shares of our outstanding common stock at a cost of $23.8 million. We suspended the program in March 2020. Approximately $346.8 million remains available for repurchases under the program. If we reactivate it, we expect to slow the pace of previously planned share repurchases as we continue to prioritize our financial strength and liquidity. In that case, we would expect purchases to extend beyond December 31, 2021.

In addition, we may from time to time seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in our Restated Credit Agreement and other factors.

Based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to repay our convertible bonds maturing in September of 2021 and to fund our planned activities through the 12-month period following the filing of this report.

Our revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests.

The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. For purposes of the current ratio covenant, the revolving credit facility’s definition of total current assets, in addition to current assets as presented under U.S. GAAP, includes, but is not limited to, unused commitments under the revolving credit facility. 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 September 30, 2020, we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.2:1.0 and a leverage ratio of 1.7:1.0. We expect to remain in compliance throughout the 12-month period following the filing of this report.

Cash Flows

Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities slightly decreased for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. The decrease between periods was primarily due to a $158.3 million decrease in revenue from crude oil, natural gas and NGLs sales, a $16.6 million increase in lease operating expenses, a $20.2 million increase in TGP and a decrease of $52.6 million related to the change in working capital, which includes $82.0 million received in June 2020 related to the Midstream Asset Divestitures. The decreases were partially offset by an increase in commodity derivative settlements of $247.3 million and $16.9 million decrease in production taxes between periods.

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Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $50.9 million to $652.8 million during the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. 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 $359.7 million during the nine months ended September 30, 2020 to $238.7 million from an adjusted free cash flow deficit of $121.0 million during the nine months ended September 30, 2019. The increase was primarily due to the decrease in capital investments in crude oil and natural gas properties during the nine months ended September 30, 2020 compared to the same 2019 period.

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

Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $583.9 million during the nine months ended September 30, 2020 was primarily related to our drilling and completion activities of $445.5 million and $139.8 million related to the closing of the SRC Acquisition. Net cash used in investing activities of $572.2 million during the nine months ended September 30, 2019 was primarily related to our drilling and completion activities of $755.8 million and $199.4 million net cash received from the Midstream Asset Divestitures and certain Delaware Basin crude oil and natural gas properties.

Financing Activities. Net cash used in financing activities of $62.5 million during the nine months ended September 30, 2020 was a result of redemption of a portion of the 2025 Senior Notes totaling $452.2 million and the repurchase and retirement of shares of our common stock totaling $23.8 million pursuant to the Stock Repurchase Program which were financed by our net borrowings from our credit facility of $281.0 million, proceeds from the issuance of 2026 Senior Notes of $148.5 million and cash flows from operating activities. Net cash used in financing activities of $83.6 million during the nine months ended September 30, 2019 was primarily due to the repurchase and retirement of shares of our common stock totaling $142.7 million partially offset by net borrowings from our credit facility of $64.5 million.

Subsidiary Guarantor

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

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

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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/Nine Months Ended				As of/Year Ended
	September 30, 2020				December 31, 2019
	Issuer		Guarantor		Issuer		Guarantor
	(in millions)

Assets
Current assets	$	334.5	$	25.3	$	175.8	$	126.0
Intercompany accounts receivable, guarantor subsidiary	110.5		—		348.8		—
Intercompany accounts receivable, non-guarantor subsidiary	—		—		6.3		—
Investment in guarantor subsidiary	1,766.8		—		1,766.8		—
Properties and equipment, net	3,996.5		888.7		2,328.3		1,766.9
Other non-current assets	67.7		4.5		41.8		6.8

Liabilities
Current liabilities	$	726.0	$	30.1	$	306.6	$	52.4
Intercompany accounts payable	—		102.6		—		348.8
Long-term debt	1,526.0		—		1,177.2		—
Other non-current liabilities	248.6		180.3		361.1		211.6

Statement of Operations
Crude oil, natural gas and NGLs sales	$	679.8	$	129.4	$	999.3	$	308.0
Commodity price risk management gain (loss), net	245.9		—		(162.8)		—
Total revenues	927.7		128.2		838.1		308.7
Production costs	165.4		53.0		180.1		89.2
Gross profit	514.4		76.4		819.2		218.8
Impairment of properties and equipment	2.0		880.4		0.3		38.2
Net income (loss)	(34.9)		(681.5)		(24.6)		(30.0)

Off-Balance Sheet Arrangements

At September 30, 2020, we had no off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital investments or capital resources.

Commitments and Contingencies

See the footnote titled Commitments and Contingencies to the accompanying condensed consolidated financial statements included elsewhere in this report.

Recent Accounting Standards

See the footnote titled Summary of Significant Accounting Policies to the accompanying condensed consolidated financial statements included elsewhere in this report.

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 2019 Form 10-K filed with the SEC on February 26, 2020.

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Reconciliation of Non-U.S. GAAP Financial Measures

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

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

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

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

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

Beginning in the third quarter of 2019, we included a reconciling item for gains or losses on the sale of properties and equipment when calculating adjusted EBITDAX, thereby no longer including such gains or losses in our reported adjusted EBITDAX. We believe this methodology for calculating adjusted EBITDAX will enable greater comparability to our peers, as well as consistent treatment of adjustments for impairment and gains or losses on the sale of properties and equipment. For comparability, all prior periods presented have been conformed to the aforementioned methodology.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow (deficit):
Net cash from operating activities	$	280.1	$	233.5	$	649.3	$	651.0
Changes in assets and liabilities	(18.7)		(31.1)		3.5		(49.1)
Adjusted cash flows from operations	261.4		202.4		652.8		601.9
Capital expenditures for development of crude oil and natural gas properties	(57.6)		(237.8)		(445.5)		(755.8)
Change in accounts payable related to capital expenditures for oil and gas development activities	24.2		74.2		31.4		32.9
Adjusted free cash flow (deficit)	$	228.0	$	38.8	$	238.7	$	(121.0)

Net income (loss) to adjusted net income (loss):
Net income (loss)	$	(30.8)	$	15.9	$	(717.6)	$	(35.7)
Loss (gain) on commodity derivative instruments	68.1		(54.9)		(245.9)		87.9
Net settlements on commodity derivative instruments	66.9		1.8		227.5		(19.8)
Tax effect of above adjustments (1)	—		12.7		—		(16.3)
Adjusted net income (loss)	$	104.2	$	(24.5)	$	(736.0)	$	16.1

Net income (loss) to adjusted EBITDAX:
Net income (loss)	$	(30.8)	$	15.9	$	(717.6)	$	(35.7)
Loss (gain) on commodity derivative instruments	68.1		(54.9)		(245.9)		87.9
Net settlements on commodity derivative instruments	66.9		1.8		227.5		(19.8)
Non-cash stock-based compensation	5.4		5.9		17.4		18.1
Interest expense, net	21.0		17.8		67.0		53.7
Income tax expense (benefit)	0.2		10.7		(3.5)		(4.2)
Impairment of properties and equipment	1.2		0.2		882.3		37.0

Exploration, geologic and geophysical expense	0.2		0.2		1.0		3.5
Depreciation, depletion and amortization	144.5		171.8		470.2		491.8
Accretion of asset retirement obligations	2.4		1.4		7.4		4.5
Loss (gain) on sale of properties and equipment	(0.3)		43.9		(0.6)		9.6
Adjusted EBITDAX	$	278.8	$	214.7	$	705.2	$	646.4

Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities	$	280.1	$	233.5	$	649.3	$	651.0
Interest expense, net	21.0		17.8		67.0		53.7
Amortization of debt discount and issuance costs	(3.6)		(3.4)		(12.5)		(10.1)
Exploration, geologic and geophysical expense	0.2		0.2		1.0		3.5

Other	(0.2)		(2.3)		(3.1)		(2.6)
Changes in assets and liabilities	(18.7)		(31.1)		3.5		(49.1)
Adjusted EBITDAX	$	278.8	$	214.7	$	705.2	$	646.4

_____________

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

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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 2021 Convertible Notes, 2024 Senior Notes, 2025 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 September 30, 2020, we had a $285.0 million outstanding balance on our revolving credit facility. If market interest rates would have increased or decreased one percent, our interest expense for the nine months ended September 30, 2020 would have changed by approximately $1.4 million.

Commodity Price Risk

We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, natural gas basis and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives.

Based on a sensitivity analysis as of September 30, 2020, we estimate that a ten percent increase in natural gas and crude oil, inclusive of basis, over the entire period for which we have commodity derivatives in place, would have resulted in a decrease in the fair value of net derivative assets of $75.2 million, whereas a ten percent decrease in prices would have resulted in an increase in fair value of net derivative assets of $74.5 million.

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.

Disclosure of Limitations

Because the information above included only those exposures that existed at September 30, 2020, 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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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of September 30, 2020, 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 September 30, 2020.

Management's Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Management has assessed the effectiveness of our internal control over financial reporting as of September 30, 2020, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO").

Changes in Internal Control over Financial Reporting

As of January 1, 2020, we implemented a new ERP system. In connection with the ERP system implementation, we have updated our internal controls over financial reporting to accommodate modifications to our business processes and accounting procedures.

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PART II

ITEM 1. LEGAL PROCEEDINGS

Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies -

Litigation and Legal Items to our accompanying condensed consolidated financial statements included elsewhere in this report.

RISK FACTORS

We face many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described under Item 1A, Risk Factors, of our 2019 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 2019 Form 10-K, First Quarter 2020 Form 10-Q and Second Quarter 2020 Form 10-Q, except for the following:

Global COVID-19 Pandemic and Crude Oil Market Downturn

Our operations have been adversely affected as a result of the ongoing global COVID-19 pandemic and the precipitous decline in crude oil demand and pricing. We expect those impacts to continue in the near-term and we may experience additional impacts in the future. For example:

•Prolonged depressed crude oil prices may have adverse effects on the financial wellbeing of our business, including with respect to revenue, profitability, cash flows and liquidity; quantity and present value of our reserves; borrowing base under our revolving credit facility; and access to other sources of capital;

•Decreased crude oil prices may require us to shut in production for a significant portion of our producing wells, which will reduce our revenue and require monetary compensation to mineral lessors;

•Domestic oversupply of crude oil may lead to insufficient storage capacity and could impact our midstream providers’ ability to accept and transport our production to market;

•Effects of COVID-19, including demand destruction, reduction in skilled workforce and state and local orders regarding public health and safety, may result in claims of force majeure by us or our counterparties relating to obligations under material agreements;

•Low commodity prices may lead to financial distress and restructuring events affecting working interest partners, vendors, service providers and other counterparties;

•Negative financial impacts to our business partners may cause delays or failure to pay service providers, which could result in liens filed against our real and personal property;

•Our reduced capital spend and projected decline in revenues have led to temporary and permanent reductions in our work force and decreases to our director, executive and employee compensation, which may affect our ability to attract and retain experienced technical and other professional personnel;

•Our reduced drilling program may result in losses of acreage due to lease expirations, which could result in impairment charges and the loss of future drilling opportunities;

•Reported reductions in the work forces of our service providers may result in delays in procuring products and services essential to our operations;

•State and local orders, ordinances and guidance related to COVID-19 have forced a significant portion of our employees to work remotely, which may result in decreased productivity and continuity among the employee base;

•Current market conditions and impacts on our business generally may lead to an increased risk of litigation; and

•The cumulative effects of COVID-19 on the economy may result in a long-term global recession or depression.

Changes in laws and regulations applicable to us could impose additional operating restrictions, increase our costs of compliance or have other adverse effects on us.

The regulatory environment in which we operate changes frequently, often through the imposition of new or more stringent environmental and other requirements. We cannot predict the nature, timing, cost or effect of such additional requirements, but they may have a variety of adverse effects on us. In 2019, Colorado enacted Senate Bill 19-181 (“SB 19-181”), which changes the mission of the COGCC from fostering responsible and balanced development to regulating development to protect public health and the environment and directs the COGCC to undertake rulemaking on various operational matters including environmental protection, wellbore integrity and the relationship between state and local deferral with regards to siting. The rulemaking process is currently underway and some of the matters being addressed are setbacks and

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siting requirements. In the September 2020 hearings, the COGCC commissioners determined that locations with building units within 2,000 feet would be subject to additional siting requirements, but also supported “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from building units in certain circumstances. The implementation of these final rules could have a significant adverse effect on our unpermitted locations and therefore on our future inventory and reserves. We continue to be very active in the rulemaking process but cannot predict its outcome or the impact on our operations.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers


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 (2)	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions)

July 1 - 31, 2020	6,902	$	13.34	—	$	346.8
August 1 - 31, 2020	6,619	14.80		—	346.8
September 1 - 30, 2020	3,121	13.26		—	346.8
Total third quarter 2020 purchases	16,642	13.91		—	346.8

__________

(1)Certain purchases 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 issued or considered common stock repurchased under the Stock Repurchase Program described in the footnote titled Common Stock to our accompanying condensed consolidated financial statements included elsewhere in this report.

(2)In April 2019, the Board approved a program to acquire up to $200 million of our outstanding common stock and in August 2019, effective with the closing of the SRC Acquisition, increased such amount to $525 million. The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board at any time; further repurchases pursuant to the program have been suspended and, if we resume the program, we expect to slow the pace of previously planned share repurchases as we continue to prioritize our financial strength and liquidity. We expect purchases made pursuant to the Stock Repurchase Program to extend beyond December 31, 2021, given current market conditions.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES - None.

ITEM 4. MINE SAFETY DISCLOSURES - Not applicable.

ITEM 5. OTHER INFORMATION - None.

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PDC ENERGY, INC.

ITEM 6. EXHIBITS

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

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

31.1

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

31.2

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

32.1*

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

101.INS

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

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

104

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

* Furnished herewith.

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PDC ENERGY, INC.

SIGNATURES

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


			PDC Energy, Inc.
			(Registrant)




Date: November 4, 2020			/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)