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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, 2019

☐ 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: 61,616,700 shares of the Company's Common Stock ($0.01 par value) were outstanding as of October 21, 2019.

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PDC ENERGY, INC.

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	PART I – FINANCIAL INFORMATION	Page

Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets (unaudited)	1
	Condensed Consolidated Statements of Operations (unaudited)	2
	Condensed Consolidated Statements of Cash Flows (unaudited)	3
	Condensed Consolidated Statements of Equity (unaudited)	4
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 4.	Controls and Procedures	59

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	60
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64
Item 3.	Defaults Upon Senior Securities	64
Item 4.	Mine Safety Disclosures	64
Item 5.	Other Information	64
Item 6.	Exhibits	65

	SIGNATURES	66

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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, the pending acquisition of SRC Energy, Inc. ("SRC") and the effects thereof; the expected timing of the acquisition of SRC; 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 stock repurchase program, which may be modified or discontinued at any time; potential additional payments from the sale of our midstream assets; 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 and the related impact on our midstream capacity and related curtailments; fractionation capacity; impacts of Colorado political matters and expected timing of rulemakings; ability to meet our volume commitments to midstream providers; ability to obtain permits from the Colorado Oil and Gas Conservation Commission ("COGCC") in a timely manner; ongoing compliance with our consent decree and expected timing of certain litigation; and reclassification of the Denver Metro/North Front Range NAA ozone classification to serious.

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:


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


•	volatility of commodity prices for crude oil, natural gas and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices;


•	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;


•	impact of recent regulatory developments in Colorado 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 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;


•	timing and receipt of necessary regulatory permits;


•	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 acquisition of SRC, or acreage exchanges;


•	increases or changes in costs and expenses;


•	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;

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•	increases or changes in costs and expenses;


•	future cash flows, liquidity and financial condition;


•	competition within the oil and gas industry;


•	availability and cost of capital;


•	our success in marketing 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, including litigation related to the acquisition of SRC;


•	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, 2018 filed with the U.S. Securities and Exchange Commission ("SEC") on February 28, 2019 (the "2018 Form 10-K"), 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, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships.

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PDC ENERGY, INC.

Condensed Consolidated Balance Sheets

(unaudited; in thousands, except share and per share data)



	September 30, 2019			December 31, 2018
Assets
Current assets:
Cash and cash equivalents	$	4,567		$	1,398
Accounts receivable, net	253,077			181,434
Fair value of derivatives	75,830			84,492
Prepaid expenses and other current assets	7,938			7,136
Total current assets	341,412			274,460
Properties and equipment, net	4,165,156			4,002,862
Assets held-for-sale, net	—			140,705
Fair value of derivatives	33,185			93,722
Other assets	43,851			32,396
Total Assets	$	4,583,604		$	4,544,145

Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	147,893		$	181,864
Production tax liability	71,569			60,719
Fair value of derivatives	2,953			3,364
Funds held for distribution	88,047			105,784
Accrued interest payable	16,280			14,150
Other accrued expenses	81,049			75,133
Total current liabilities	407,791			441,014
Long-term debt	1,267,471			1,194,876
Deferred income taxes	193,707			198,096
Asset retirement obligations	86,182			85,312
Liabilities held-for-sale	—			4,111
Fair value of derivatives	661			1,364
Other liabilities	268,037			92,664
Total liabilities	2,223,849			2,017,437

Commitments and contingent liabilities

Stockholders' equity
Common shares - par value $0.01 per share, 150,000,000 authorized, 62,087,818 and 66,148,609 issued as of September 30, 2019 and December 31, 2018, respectively	621			661
Additional paid-in capital	2,390,658			2,519,423
Retained earnings (deficit)	(26,993		)	8,727
Treasury shares - at cost, 139,415 and 45,220 as of September 30, 2019 and December 31, 2018, respectively	(4,531		)	(2,103		)
Total stockholders' equity	2,359,755			2,526,708
Total Liabilities and Stockholders' Equity	$	4,583,604		$	4,544,145

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Operations

(unaudited; in thousands, except per share data)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues
Crude oil, natural gas and NGLs sales	$	307,409		$	372,439		$	967,464		$	1,003,597
Commodity price risk management gain (loss), net	54,867			(94,394		)	(87,858		)	(257,760		)
Other income	3,667			2,672			11,495			8,011
Total revenues	365,943			280,717			891,101			753,848
Costs, expenses and other
Lease operating expenses	36,498			33,046			106,047			94,942
Production taxes	13,039			23,984			57,849			66,757
Transportation, gathering and processing expenses	10,999			9,234			34,631			25,511
Exploration, geologic and geophysical expense	209			1,032			3,492			4,553
Impairment of properties and equipment	167			1,488			37,021			194,230
General and administrative expense	41,091			48,240			123,497			121,183
Depreciation, depletion and amortization	171,839			147,540			491,784			409,952
Accretion of asset retirement obligations	1,356			1,200			4,503			3,773
Loss on sale of properties and equipment	43,872			2,118			9,599			3,199
Other expenses	2,492			2,711			8,882			8,187
Total costs, expenses and other	321,562			270,593			877,305			932,287
Income (loss) from operations	44,381			10,124			13,796			(178,439		)
Interest expense	(17,859		)	(17,622		)	(53,742		)	(52,561		)
Interest income	48			188			63			405
Income (loss) before income taxes	26,570			(7,310		)	(39,883		)	(230,595		)
Income tax (expense) benefit	(10,662		)	3,876			4,163			53,765
Net income (loss)	$	15,908		$	(3,434	)	$	(35,720	)	$	(176,830	)

Earnings per share:
Basic	$	0.25		$	(0.05	)	$	(0.55	)	$	(2.68	)
Diluted	$	0.25		$	(0.05	)	$	(0.55	)	$	(2.68	)

Weighted-average common shares outstanding:
Basic	62,547			66,073			64,835			66,032
Diluted	62,595			66,073			64,835			66,032

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(unaudited; in thousands)



	Nine Months Ended September 30,
	2019			2018
Cash flows from operating activities:
Net loss	$	(35,720	)	$	(176,830	)
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives	68,058			167,218
Depreciation, depletion and amortization	491,784			409,952
Impairment of properties and equipment	37,021			194,230
Accretion of asset retirement obligations	4,503			3,773
Non-cash stock-based compensation	18,124			16,357
Loss on sale of properties and equipment	9,599			3,199
Amortization of debt discount and issuance costs	10,139			9,454
Deferred income taxes	(4,389		)	(53,029		)
Other	2,761			1,025
Changes in assets and liabilities	73,845			2,485
Net cash from operating activities	675,725			577,834
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(780,581		)	(685,549		)
Capital expenditures for other properties and equipment	(15,522		)	(3,739		)
Acquisition of crude oil and natural gas properties	(12,445		)	(181,572		)
Proceeds from sale of properties and equipment	1,528			2,443
Proceeds from divestitures	202,046			43,493
Restricted cash	8,001			1,249
Net cash from investing activities	(596,973		)	(823,675		)
Cash flows from financing activities:
Proceeds from revolving credit facility	1,300,000			629,000
Repayment of revolving credit facility	(1,235,500		)	(554,000		)
Payment of debt issuance costs	(53		)	(4,086		)
Purchase of treasury shares	(142,665		)	—
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	(3,874		)	(4,700		)
Principal payments under financing lease obligations	(1,492		)	(873		)
Other	—			(55		)
Net cash from financing activities	(83,584		)	65,286
Net change in cash, cash equivalents and restricted cash	(4,832		)	(180,555		)
Cash, cash equivalents and restricted cash, beginning of period	9,399			189,925
Cash, cash equivalents and restricted cash, end of period	$	4,567		$	9,370

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Equity

(unaudited; in thousands, except share data)



	Nine Months Ended September 30, 2019
	Common Stock								Treasury Stock
	Shares		Amount			Additional Paid-in Capital			Shares		Amount			Retained Earnings (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.

Condensed Consolidated Statements of Equity

(unaudited; in thousands, except share data)



	Nine Months Ended September 30, 2018
	Common Stock						Treasury Stock
	Shares	Amount		Additional Paid-in Capital			Shares		Amount			Retained Earnings (Deficit)			Total Stockholders' Equity

Balance, December 31, 2017	65,955,080	$	659	$	2,503,294		(55,927	)	$	(3,008	)	$	6,704		$	2,507,649
Net loss	—	—		—			—		—			(13,139		)	(13,139		)
Stock-based compensation	43,930	1		5,260			—		—			—			5,261
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—			(41,357	)	(2,255		)	—			(2,255		)
Issuance of treasury shares	—	—		(3,891		)	70,603		3,891			—			—
Non-employee directors' deferred compensation plan	—	—		—			(2,574	)	(142		)	—			(142		)
Balance, March 31, 2018	65,999,010	660		2,504,663			(29,255	)	(1,514		)	(6,435		)	2,497,374
Net loss	—	—		—			—		—			(160,257		)	(160,257		)
Stock-based compensation	134,015	1		5,517			—		—			—			5,518
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—			(45,706	)	(2,239		)	—			(2,239		)
Issuance of treasury shares	—	—		(397		)	7,792		397			—			—
Other	—	—		(90		)	—		—			—			(90		)
Balance, June 30, 2018	66,133,025	661		2,509,693			(67,169	)	(3,356		)	(166,692		)	2,340,306
Net loss	—	—		—			—		—			(3,434		)	(3,434		)
Stock-based compensation	3,402	—		5,578			—		—			—			5,578
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	—	—		—			(3,402	)	(206		)	—			(206		)
Issuance of treasury shares	—	—		(410		)	8,306		410			—			—
Balance, September 30, 2018	66,136,427	$	661	$	2,514,861		(62,265	)	$	(3,152	)	$	(170,126	)	$	2,342,244

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(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. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of September 30, 2019, we owned an interest in approximately 2,700 gross productive wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Our gas marketing segment does not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries and our proportionate share of our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.

In our opinion, the accompanying condensed consolidated financial statements contain all adjustments, consisting of normal recurring adjustments, necessary for a fair statement of 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, 2018 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 2018 Form 10-K. Our results of operations and cash flows for the nine months ended September 30, 2019 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 Standards

In February 2016, the Financial Accounting Standards Board ("FASB") issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. As provided by practical expedients, we made accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset. The FASB issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that, if elected, permits an organization to not evaluate the accounting for existing land easements that are not accounted for under the previous lease accounting standard. We elected this practical expedient, and accordingly, existing land easements at December 31, 2018 were not assessed. All new or modified land easements entered into after January 1, 2019 are evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Adoption of the New Lease Standard resulted in increases to other assets of $20.1 million, other accrued expenses of $4.6 million and other liabilities of $15.5 million at January 1, 2019, with no adjustment to the opening balance of retained earnings.

Recently Issued Accounting Standards

In June 2016, the FASB issued an accounting update and subsequent amendments on the impairment of financial instruments. The update added a new impairment model, known as the current expected credit loss model, which is based upon expected credit losses, rather than incurred losses. Under the new guidance, an allowance will be recognized based upon

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

the entity's estimate of lifetime expected credit losses. The update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years and early adoption is permitted. Based on implementation efforts performed to date, we do not expect adoption of the update to have a material impact on our condensed consolidated financial statements.

NOTE 3 - PENDING ACQUISITION

On August 25, 2019, we and SRC entered into an Agreement and Plan of Merger (the “Merger Agreement”) under which we will acquire SRC in an all-stock transaction (the “SRC Acquisition”). We expect the SRC Acquisition to be completed early in the first quarter of 2020, subject to PDC and SRC shareholder approval and the satisfaction of certain customary closing conditions, including the receipt of federal regulatory approvals. The Merger Agreement may be terminated by us or SRC in certain circumstances. We will account for the SRC Acquisition as a business combination using the acquisition method of accounting.

Upon completion of the SRC Acquisition, SRC shareholders will automatically receive 0.158 of a share of our common stock in exchange for each share of SRC common stock. This exchange ratio is fixed and will not be adjusted for changes in our or SRC’s stock price. The value of the SRC Acquisition, which will include assumption of SRC's net debt, will be dependent upon the market value of our common stock on the date of closing. We estimate that we will issue up to approximately 40 million shares of our common stock in connection with the SRC Acquisition.

During the nine months ended September 30, 2019, we recorded transaction costs related to the SRC Acquisition of $5.0 million, which are included in general and administrative expense in our condensed consolidated statement of operations. The liabilities associated with such amounts are included in other accrued expenses in our condensed consolidated balance sheet as of September 30, 2019.

Subject to closing the SRC Acquisition, the borrowing base on our revolving credit facility will increase from $1.6 billion to $2.1 billion. In addition, we elected to increase the aggregate commitment amount under our revolving credit facility to (i) $1.7 billion upon closing of the SRC Acquisition and (ii) up to $1.9 billion, at our sole discretion, at any time following closing of the SRC Acquisition before April 30, 2020. As described below, if the SRC Acquisition results in a "Change of Control" under the indenture governing SRC’s $550 million 6.25% Senior Notes due December 2025 (the "SRC Senior Notes"), we will be required to offer to purchase those notes. We expect that our decision regarding the expansion of the commitment to $1.9 billion will be based in part on whether we make such an offer and, if so, the amount of SRC Senior Notes tendered in the offer.

Upon closing the SRC Acquisition, we will assume the SRC Senior Notes and be required to pay off and terminate SRC's revolving credit facility. As of September 30, 2019, SRC had $165 million outstanding under its revolving credit facility. The SRC Senior Notes contain a change of control provision pursuant to which, if the consummation of the SRC Acquisition results in a “Change of Control” under the indenture governing the SRC Senior Notes, we will be required to make an offer to repurchase the SRC Senior Notes at a price equal to 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase.

Additionally, in August 2019, contingent on the closing of the SRC Acquisition, our Board of Directors (the "Board") approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million with a target completion date of December 31, 2021.

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, 2019

(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, 2019 and 2018:



	Three Months Ended September 30,						Nine Months Ended September 30,
Revenue by Commodity and Operating Region	2019		2018		Percent Change		2019		2018		Percentage Change
	(in thousands)
Crude oil
Wattenberg Field	$	185,543	$	216,346	(14.2	)%	$	569,518	$	576,645	(1.2	)%
Delaware Basin	70,175		68,341		2.7	%	191,452		184,357		3.8	%
Utica Shale (1)	—		—		*		—		2,696		*
Total	$	255,718	$	284,687	(10.2	)%	$	760,970	$	763,698	(0.4	)%
Natural gas
Wattenberg Field	$	23,949	$	27,762	(13.7	)%	$	100,779	$	80,174	25.7	%
Delaware Basin	2,613		6,994		(62.6	)%	9,293		22,145		(58.0	)%
Utica Shale (1)	—		—		*		—		1,109		*
Total	$	26,562	$	34,756	(23.6	)%	$	110,072	$	103,428	6.4	%
NGLs
Wattenberg Field	$	16,906	$	36,758	(54.0	)%	$	67,305	$	95,799	(29.7	)%
Delaware Basin	8,223		16,238		(49.4	)%	29,117		39,832		(26.9	)%
Utica Shale (1)	—		—		*		—		840		*
Total	$	25,129	$	52,996	(52.6	)%	$	96,422	$	136,471	(29.3	)%
Revenue by Operating Region
Wattenberg Field	$	226,398	$	280,866	(19.4	)%	$	737,602	$	752,618	(2.0	)%
Delaware Basin	81,011		91,573		(11.5	)%	229,862		246,334		(6.7	)%
Utica Shale (1)	—		—		*		—		4,645		*
Total	$	307,409	$	372,439	(17.5	)%	$	967,464	$	1,003,597	(3.6	)%



(1)	In March 2018, we completed the disposition of our Utica Shale properties.

NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Determination of Fair Value

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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

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 through the review of counterparty statements and other supporting documentation, determination that the source of the inputs is valid, corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions.

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:



	September 30, 2019									December 31, 2018
	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	$	77,313		$	31,702		$	109,015		$	118,521		$	59,693		$	178,214
Total liabilities	(2,817		)	(797		)	(3,614		)	(3,364		)	(1,364		)	(4,728		)
Net asset	$	74,496		$	30,905		$	105,401		$	115,157		$	58,329		$	173,486

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,
	2019			2018			2019			2018
	(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period	$	22,504		$	(19,100	)	$	58,329		$	(9,687	)
Changes in fair value included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net	10,846			(16,175		)	(22,077		)	(23,029		)
Settlements included in condensed consolidated statement of operations line items:
Commodity price risk management gain (loss), net	(2,445		)	6,413			(5,347		)	3,854
Fair value of Level 3 instruments, net asset (liability) end of period	$	30,905		$	(28,862	)	$	30,905		$	(28,862	)

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	$	6,787		$	(7,451	)	$	(11,620	)	$	(4,229	)

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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

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.

The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest 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, 2019				December 31, 2018
		Estimated Fair Value		Percent of Par		Estimated Fair Value		Percent of Par
		(in millions)
Senior notes:
	2021 Convertible Notes	$	185.2	92.6	%	$	175.4	87.7	%
	2024 Senior Notes	400.0		100.0	%	370.2		92.5	%
	2026 Senior Notes	589.8		98.3	%	532.4		88.7	%

The carrying value of the financial instruments included in current assets and current liabilities approximate fair value 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, 2019.

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, 2019 and December 31, 2018. 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 to protect against price declines in future periods. 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. As of September 30, 2019, we had derivative instruments, which were comprised of collars, fixed-price swaps and basis protection swaps, in place for a portion of our anticipated 2019, 2020 and 2021 production. Our

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

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.

As of September 30, 2019, 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 - MBls Natural Gas - BBtu)	Weighted-Average Contract Price				Quantity (Crude Oil - MBbls Gas and Basis- BBtu )	Weighted- Average Contract Price			Fair Value September 30, 2019 (1) (in thousands)
Commodity/ Index/ Maturity Period	Quantity (Crude oil - MBls Natural Gas - BBtu)	Floors		Ceilings		Quantity (Crude Oil - MBbls Gas and Basis- BBtu )	Weighted- Average Contract Price			Fair Value September 30, 2019 (1) (in thousands)
Crude Oil
NYMEX
2019	1,450	$	57.07	$	66.82	1,650	$	55.96		$	10,336
2020	3,600	55.00		71.68		6,200	61.28			84,429
2021	—	—		—		1,200	57.99			9,166
Total Crude Oil	5,050					9,050				$	103,931

Natural Gas
NYMEX
2019	—	$	—	$	—	7,582	$	2.91		$	3,699
Dominion South
2019	—	—		—		21	2.54			1
2020	—	—		—		14	2.54			—
Total Natural Gas	—					7,617				$	3,700

Basis Protection - Natural Gas
CIG
2019	—	$	—	$	—	13,861	$	(0.64	)	$	(1,629	)
2020	—	—		—		20,500	(0.62		)	(601		)
Total Basis Protection - Natural Gas	—					34,361				$	(2,230	)

Commodity Derivatives Fair Value										$	105,401

_____________


(1)	Approximately 29.1 percent of the fair value of our commodity derivative assets and 22.1 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).

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, 2019

(unaudited)

The following table presents the balance sheet location and fair value amounts of our derivative instruments on the condensed consolidated balance sheets:



			Fair Value
Derivative Instruments:		Condensed Consolidated Balance Sheet Line Item	September 30, 2019		December 31, 2018
			(in thousands)
Derivative assets:	Current
	Commodity derivative contracts	Fair value of derivatives	$	75,663	$	84,492
	Basis protection derivative contracts	Fair value of derivatives	167		—
			75,830		84,492
	Non-current
	Commodity derivative contracts	Fair value of derivatives	33,185		93,722
Total derivative assets			$	109,015	$	178,214

Derivative liabilities:	Current
	Commodity derivative contracts	Fair value of derivatives	$	990	$	748
	Basis protection derivative contracts	Fair value of derivatives	1,963		2,616
			2,953		3,364
	Non-current
	Commodity derivative contracts	Fair value of derivatives	227		1,364
	Basis protection derivative contracts	Fair value of derivatives	434		—
			661		1,364
Total derivative liabilities			$	3,614	$	4,728

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	2019		2018			2019			2018
	(in thousands)
Commodity price risk management gain (loss), net
Net settlements	$	1,845	$	(48,096	)	$	(19,800	)	$	(90,542	)
Net change in fair value of unsettled derivatives	53,022		(46,298		)	(68,058		)	(167,218		)
Total commodity price risk management gain (loss), net	$	54,867	$	(94,394	)	$	(87,858	)	$	(257,760	)

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, 2019	Derivative Instruments, Gross		Effect of Master Netting Agreements			Derivative Instruments, Net
	(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	109,015	$	(2,843	)	$	106,172

Liability derivatives:
Derivative instruments, at fair value	$	3,614	$	(2,843	)	$	771

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)



As of December 31, 2018	Derivative Instruments, Gross		Effect of Master Netting Agreements			Derivative Instruments, Net
	(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	178,214	$	(3,985	)	$	174,229

Liability derivatives:
Derivative instruments, at fair value	$	4,728	$	(3,985	)	$	743

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, 2019			December 31, 2018
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	6,153,145		$	5,452,613
Unproved	423,056			492,594
Total crude oil and natural gas properties	6,576,201			5,945,207
Equipment and other	41,667			60,612
Land and buildings	12,312			11,243
Construction in progress	399,732			356,095
Properties and equipment, at cost	7,029,912			6,373,157
Accumulated DD&A	(2,864,756		)	(2,370,295		)
Properties and equipment, net	$	4,165,156		$	4,002,862

Acreage Acquisition. 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.

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. Concurrent with the Midstream Asset Divestitures, we entered into agreements with the purchasers which provide us with certain gathering, processing, transportation and water disposal services. 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. See the footnote titled Other Accrued Expenses and Other Liabilities for further details regarding these agreements.

In May 2019, we completed the sale of our produced water gathering and disposal midstream assets in the Delaware Basin for $126.3 million, subject to certain customary post-closing adjustments, plus potential future payments of up to $75.0 million. We recorded a gain on the sale of $25.7 million based on the fair value of the tangible assets sold during the nine months ended September 30, 2019.

In May 2019, we also completed the sale of our crude oil gathering midstream assets in the Delaware Basin for $37.3 million, subject to certain customary post-closing adjustments, plus potential future payments of up to $15.2 million. We recorded a loss on the sale of $0.2 million based on the fair value of the tangible assets sold during the nine months ended September 30, 2019.

In June 2019, we completed the sale of our natural gas gathering midstream assets in the Delaware Basin for $182.0 million ($100.0 million of which was paid upon closing with the remaining $82.0 million to be paid in June 2020), subject to certain customary post-closing adjustments, plus potential future payments of up to $60.5 million. The $82.0 million receivable

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

is included in accounts receivable, net on our condensed consolidated balance sheet at September 30, 2019. We recorded a gain on the sale of $8.5 million based on the fair value of the tangible assets sold during the nine months ended September 30, 2019.

The Midstream Asset Divestitures did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for the divested assets as discontinued operations.

Classification of Assets and Liabilities as Held-for-Sale. Assets held-for-sale at December 31, 2018 included assets sold in the Midstream Asset Divestitures, and certain non-core Delaware Basin crude oil and natural gas properties. The following table presents balance sheet data related to assets and liabilities held-for-sale:



	December 31, 2018
	(in thousands)
Assets
Properties and equipment, net	$	137,448
Other assets	3,257
Total assets	$	140,705

Liabilities
Asset retirement obligations	$	4,111
Total liabilities	$	4,111

During the nine months ended September 30, 2019, we sold certain Delaware Basin crude oil and natural gas properties for net cash proceeds of $33.4 million, which approximated the net book value, resulting in no gain or loss on the sale.

Impairment Charges. The following table presents impairment charges recorded for crude oil and natural gas properties:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)

Impairment of proved and unproved properties	$	146	$	1,488	$	10,250	$	194,146
Amortization of individually insignificant unproved properties	—		—		—		84
Impairment of infrastructure and other	21		—		26,771		—
Impairment of properties and equipment	$	167	$	1,488	$	37,021	$	194,230

During the nine months ended September 30, 2019 and 2018, we recorded impairment charges totaling $10.3 million and $194.2 million respectively, including $0.1 million and $1.5 million during the three months ended September 30, 2019 and 2018, respectively, related to the divestiture of leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin that we determined not to develop. 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. During the nine months ended September 30, 2019, we also recorded impairments of $26.8 million related to certain midstream facility infrastructure in the Delaware Basin. Upon closing of the Midstream Asset Divestitures, it was determined that the net book value of these assets was not recoverable.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

During the nine months ended September 30, 2018, we also corrected an error in our calculation of the unproved properties and goodwill impairment originally reported in the quarter ended September 30, 2017. The correction of the error resulted in an additional impairment charge of $6.3 million, recorded in the three months ended March 31, 2018, which we have included in the impairment of properties and equipment expense line in our condensed consolidated statement of operations. We evaluated the error under 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.

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, 2018
	(in thousands, except for number of wells)

Beginning balance	$	12,188		$	15,448
Additions to capitalized exploratory well costs pending the determination of proved reserves	25,605			35,127
Reclassifications to proved properties	(13,016		)	(38,387		)
Ending balance	$	24,777		$	12,188

Number of wells pending determination at period-end	3			2

During the nine months ended September 30, 2019, one well classified as exploratory at December 31, 2018 was reclassified as productive and two new wells drilled were classified as exploratory.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(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, 2019		December 31, 2018
	(in thousands)

Employee benefits	$	17,712	$	25,811
Asset retirement obligations	30,873		25,598
Purchases of treasury shares	2,818		—
Environmental expenses	1,646		3,038
Operating and finance leases	6,014		—
Other	21,986		20,686
Other accrued expenses	$	81,049	$	75,133

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



	September 30, 2019		December 31, 2018
	(in thousands)

Production taxes	$	49,273	$	61,310
Deferred oil gathering credits	20,603		22,710
Deferred midstream gathering credits	177,398		—
Operating and finance leases	17,331		—
Other	3,432		8,644
Other liabilities	$	268,037	$	92,664

Deferred Oil Gathering Credits. In January 2018, we entered into an agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The payment is being amortized over the life of the agreement. Amortization charges related to this deferred oil gathering credit totaling approximately $0.5 million and $0.4 million for the three months ended September 30, 2019 and 2018, respectively, and $1.5 million and $1.1 million for the nine months ended September 30, 2019 and 2018, respectively, are included as a reduction to transportation, gathering and processing expenses in our condensed consolidated statements of operations.

Deferred Midstream Gathering Credits. In May 2019, concurrent with the sale of our Delaware Basin produced water gathering and disposal midstream assets, we entered into an agreement with the purchaser which dedicates all of our water gathering and disposal volumes in the Delaware Basin via pipeline for a term of 15 years. We recorded a long-term deferred credit of $40.5 million attributable to the value of the dedication, which is being amortized using the units-of-production basis. Amortization charges related to this deferred credit totaling $0.4 million and $0.6 million for the three and nine months ended September 30, 2019, respectively, are included as a reduction to lease operating expenses and capital costs in our condensed consolidated statements of operations and on our condensed consolidated balance sheets, respectively.

In May 2019, concurrent with the sale of our Delaware Basin crude oil gathering midstream assets, we entered into an agreement with the purchaser which provides us with gathering and transport for crude oil from dedicated acreage within an area of mutual interest for a term of 15 years. We recorded a long-term deferred credit of $28.9 million attributable to the value of the dedication, which is being amortized on a units-of-production basis. Amortization charges related to this deferred credit totaling $0.2 million and $0.3 million for the three and nine months ended September 30, 2019, respectively, are included as crude oil sales in our condensed consolidated statements of operations.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

In June 2019, concurrent with the sale of our Delaware Basin natural gas gathering midstream assets, we entered into an agreement with the purchaser which provides us with gathering, processing and transportation of our natural gas from certain dedicated leases for a term of 22 years. We recorded a long-term deferred credit of $110.2 million attributable to the value of the dedication, which is being amortized on a units-of-production basis. Amortization charges related to this deferred credit totaling $0.8 million and $1.1 million, respectively, are included as a reduction to transportation, gathering and processing expenses in our condensed consolidated statements of operations.

NOTE 9 - LONG-TERM DEBT

Long-term debt consisted of the following as of:



	September 30, 2019			December 31, 2018
	(in thousands)
Senior Notes:
1.125% Convertible Notes due September 2021:
Principal amount	$	200,000		$	200,000
Unamortized discount	(16,807		)	(22,766		)
Unamortized debt issuance costs	(1,909		)	(2,640		)
Net of unamortized discount and debt issuance costs	181,284			174,594

6.125% Senior Notes due September 2024:
Principal amount	400,000			400,000
Unamortized debt issuance costs	(4,856		)	(5,590		)
Net of unamortized debt issuance costs	395,144			394,410

5.75% Senior Notes due May 2026:
Principal amount	600,000			600,000
Unamortized debt issuance costs	(5,957		)	(6,628		)
Net of unamortized debt issuance costs	594,043			593,372

Total senior notes	1,170,471			1,162,376

Revolving Credit Facility:
Revolving credit facility due May 2023	97,000			32,500
Total long-term debt, net of unamortized discount and debt issuance costs	$	1,267,471		$	1,194,876

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 in cash 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. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes were capitalized as debt issuance costs. As of September 30, 2019, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using the effective interest method.

Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash or a combination of cash and shares of our common stock. 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 of our common stock, with cash paid in lieu of fractional shares.

2024 Senior Notes. In September 2016, we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”). The 2024 Senior Notes accrue interest from the date of issuance and

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

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 using the effective interest method.

2026 Senior Notes. In November 2017, we issued $600 million aggregate principal amount of 5.75% senior notes due May 15, 2026 (the "2026 Senior Notes"). The 2026 Senior Notes accrue interest from the date of issuance and 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 using the effective interest method.

Our wholly-owned subsidiary PDC Permian, Inc. guarantees our obligations under the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes (collectively, the "Notes"). Accordingly, condensed consolidating financial information for PDC and PDC Permian, Inc. is presented in the footnote titled Subsidiary Guarantor.

As of September 30, 2019, 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 under our Notes. In August 2019, we entered into a First Amendment to the Restated Credit Agreement (the "First Amendment"). The First Amendment primarily provides for certain borrowings in connection with the SRC Acquisition and modifies certain sections of the Restated Credit Agreement to permit the consummation of the SRC Acquisition. See the footnote titled Pending Acquisition for more detail on the expected impact of the SRC Acquisition on our revolving credit facility. In October 2019, as part of our semi-annual redetermination, the borrowing base on our revolving credit facility was reaffirmed at $1.6 billion and we elected to retain our commitment amount at $1.3 billion.

In October 2019, we elected to increase the aggregate commitment amount under our revolving credit facility to (i) $1.7 billion upon consummation of the SRC Acquisition and (ii) up to $1.9 billion, at our sole discretion, at any time following consummation of the SRC Acquisition and before April 30, 2020. If the SRC Acquisition results in a "Change of Control" under the indenture governing the SRC Senior Notes, we will be required to make an offer to purchase those notes. We expect that our decision regarding the expansion of the commitment to $1.9 billion will be based in part on whether we make such an offer and, if so, the amount of notes tendered in the offer.

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, excluding our share of properties held by the limited partnerships that we sponsor, 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, 2019, the applicable interest margin is 0.25 percent for the alternate base rate option or 1.25 percent for the LIBOR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the revolving credit facility expires in May 2023, unless the borrowing base falls below the outstanding balance.

The revolving credit facility contains 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. As of September 30, 2019, we were in compliance with all the revolving credit facility covenants.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

As of September 30, 2019 and December 31, 2018, debt issuance costs related to our revolving credit facility were $9.5 million and $11.5 million, respectively, and are included in other assets on the condensed consolidated balance sheets. As of September 30, 2019, the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was 4.7 percent.

NOTE 10 - LEASES

On January 1, 2019, we adopted the New Lease Standard issued by the FASB. We determine if an arrangement is representative of a lease under the New Lease Standard at contract inception. 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:



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

Finance lease costs:
Amortization of ROU assets	$	506	$	1,493
Interest on lease liabilities	66		195
Total finance lease costs	$	572	$	1,688
Short-term lease costs	35,118		147,223
Total lease costs	$	36,783	$	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 on our condensed consolidated statements of operations. 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 in our condensed consolidated balance sheets or amounts recognized as expense in our condensed consolidated statements of operations.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

The following table presents leases and the balance sheet classification as of:



Leases	Condensed Consolidated Balance Sheet Line Item	September 30, 2019
		(in thousands)
Operating Leases:
Operating lease ROU assets	Other assets	$	15,802
Operating lease obligation - short-term	Other accrued expense	$	4,093
Operating lease obligation - long-term	Other liabilities	13,986
Total operating lease liabilities		$	18,079
Finance Leases:
Finance lease ROU assets	Properties and equipment, net	$	5,307
Finance lease obligation - short-term	Other accrued expense	$	1,921
Finance lease obligation - long-term	Other liabilities	3,344
Total finance lease liabilities		$	5,265
Weighted-average remaining lease term (years)
Operating leases		4.49
Finance leases		3.29
Weighted-average discount rate
Operating leases		5.0		%
Finance leases		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, 2019 consist of the following:



	Operating Leases			Finance Leases			Total
	(in thousands)
2019	$	1,193		$	549		$	1,742
2020	4,847			2,085			6,932
2021	4,923			1,469			6,392
2022	5,016			856			5,872
2023	1,559			637			2,196
Thereafter	2,648			95			2,743
Total lease payments	20,186			5,691			25,877
Less interest and discount	(2,107		)	(426		)	(2,533		)
Present value of lease liabilities	$	18,079		$	5,265		$	23,344

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(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, 2018	$	115,021
Obligations incurred with development activities	4,573
Accretion expense	4,503
Revisions in estimated cash flows	16,648
Obligations discharged with asset retirements	(16,796		)
Obligations discharged with divestitures	(6,894		)
Balance at September 30, 2019	117,055
Current portion	(30,873		)
Long-term portion	$	86,182

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 on the condensed consolidated balance sheets.

The revisions in estimated cash flows during the nine months ended September 30, 2019 were primarily due to increases in the estimated surface reclamation costs to obtain final well pad reclamation approval from the applicable regulatory agencies.

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 our affiliated partnerships and 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(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	2020		2021		2022		2023		2024 and Through Expiration		Total		Expiration Date

Natural gas (MMcf)
Wattenberg Field	29,326		31,025		31,025		31,025		71,813		194,214		June 30, 2026
Delaware Basin	41,530		25,197		5,385		—		—		72,112		December 31, 2021
Gas Marketing	7,136		7,117		6,227		—		—		20,480		August 31, 2022
Total	77,992		63,339		42,637		31,025		71,813		286,806

Crude oil (MBbls)
Wattenberg Field	10,489		14,632		16,242		13,948		39,970		95,281		December 31, 2027
Delaware Basin	8,833		8,214		8,030		8,030		2,024		35,131		December 31, 2023
Total	19,322		22,846		24,272		21,978		41,994		130,412

Water (MBbls)
Wattenberg Field	5,441		6,207		6,207		6,207		7,788		31,850		December 31, 2024

Dollar commitment (in thousands)	$	93,528	$	98,999	$	98,223	$	85,204	$	186,772	$	562,726

Wattenberg Field. We have 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. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. We are currently satisfying the volume commitment.

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 22,200 barrels of crude oil per day and increase over time to 26,400 barrels of crude oil 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, 2019 and 2018, amounts related to long-term transportation volumes in the table above were $13.7 million and $11.0 million, respectively, and were netted against our crude oil and natural gas sales in our condensed consolidated statements of operations. For the nine months ended September 30, 2019 and 2018, amounts related to long-term transportation volumes in the table above were $36.8 million and $16.2 million, respectively, and were netted against our crude oil and natural gas sales in our condensed consolidated statements of operations.

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 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

Action Regarding Partnerships. In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al. (the "Dufresne Case"), filed in the United States District Court for the District of Colorado (the "District Court"). The original complaint stated that it was a derivative action brought by a number of limited partner investors seeking to assert claims on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP (collectively, the "Partnerships"), against PDC and includes claims for breach of fiduciary duty and breach of contract. The plaintiffs also included claims against two of our senior officers and three independent members of the Board for allegedly aiding and abetting PDC's breach of fiduciary duty. We filed a motion to dismiss on July 31, 2018. On February 19, 2019, the District Court granted the motion to dismiss, in part. It dismissed all claims against the individuals named as defendants. It also held that that the plaintiffs were time-barred from using the failure to assign acreage to support their claims for breach of fiduciary duty against PDC. On June 4, 2019, the District Court entered an order holding its opinion on the motion to dismiss in abeyance pending resolution of the Partnerships' bankruptcy cases and staying the litigation. As discussed in more detail below, the District Court in Colorado has dismissed the Dufresne Case.

Partnership Bankruptcy Filings. On October 30, 2018, the Partnerships filed petitions under Chapter 11 of the Bankruptcy Code (the "Chapter 11 Proceedings") in the United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"). Prior to the bankruptcy filings, PDC designated a third-party (the “Responsible Party”) to analyze strategic options for the Partnerships. After designation of the Responsible Party and before filing the Chapter 11 Proceedings, PDC and the Partnerships agreed to enter into a transaction pursuant to which PDC would acquire substantially all of the Partnerships’ assets through a Chapter 11 plan of liquidation and obtain a release of claims from the Partnerships, including the claims asserted in the Dufresne Case. In June 2019, the Responsible Party, PDC and the plaintiffs in the Dufresne Case reached a settlement of the matters raised in the Dufresne Case and the Chapter 11 Proceedings. The settlement, which settles all claims asserted against PDC, whether direct or derivative, including, but not limited to, the claims asserted in the Dufresne Case, was incorporated into an Amended Chapter 11 Plan (the “Amended Chapter 11 Plan”). The Disclosure Statement accompanying the Amended Chapter 11 Plan was approved by the Bankruptcy Court in August 2019 along with procedures for soliciting votes on the Amended Chapter 11 Plan. The Amended Chapter 11 Plan was distributed to the Partnership unit holders for voting. On October 2, 2019, the Bankruptcy Court held a hearing to consider confirmation of the Amended Chapter 11 Plan and, on October 3, 2019, entered an order confirming the Amended Chapter 11 Plan. The requirements for the Amended Chapter 11 Plan to become effective were met on October 21, 2019 (the “Effective Date”). As contemplated by the Amended Chapter 11 Plan, on the Effective Date, PDC funded the settlement payment, purchase price for the Partnership’s oil and gas assets and the administrative reserve. Additionally, the Partnership’s oil and gas assets were conveyed to PDC and PDC and the plaintiffs in the Dufresne Case submitted an agreed order dismissing the Dufresne Case with prejudice to the District Court. The District Court entered the agreed order on October 23, 2019 dismissing the Dufresne Case with prejudice. Distributions of the settlement amount pursuant to the Amended Chapter 11 Plan to the Partnership unit holders is expected to occur in December 2019.

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, 2019 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual.

Clean Air Act Agreement and Related Consent Decree. In June 2017, following our receipt of a 2015 Clean Air Act information request from the Environmental Protection Agency ("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. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

liability. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements.

We are in the process of implementing the consent decree program. Over the course of its execution, we have identified certain immaterial deficiencies in our implementation of the program. 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.

In addition, in December 2018, we were named as a nominal defendant in a derivative action filed in the Delaware chancery court. The complaint, which seeks unspecified monetary damages and various forms of equitable relief, alleges that certain current and former members of the Board violated their fiduciary duties, committed waste and were unjustly enriched by, among other things, failing to implement adequate environmental safeguards in connection with the issues that gave rise to the Department of Justice lawsuit and consent decree. We believe that this lawsuit is without merit but cannot predict its outcome.

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 2018, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the “2018 Plan”). The 2018 Plan provides for a reserve of 1,800,000 shares of our common stock that may be issued pursuant to awards under the 2018 Plan and a term that expires in March 2028. Shares issued may be either authorized but unissued shares, treasury shares or any combination. 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 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. We began issuing shares from the 2018 Plan during the nine months ended September 30, 2019. As of September 30, 2019, there were 1,427,070 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 most recently 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. As of September 30, 2019, there were 125,298 shares available for grant under the 2010 Plan.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands)

Stock-based compensation expense	$	5,866		$	5,578		$	18,124		$	16,357
Income tax benefit	(1,403		)	(1,337		)	(4,335		)	(3,921		)
Stock-based compensation expense, net of tax	$	4,463		$	4,241		$	13,789		$	12,436

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.

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, 2019:



	Shares		Weighted-Average Grant Date Fair Value per Share

Non-vested at December 31, 2018	618,407		$	54.16
Granted	587,250		40.38
Vested	(292,110	)	53.22
Forfeited	(96,519	)	45.98
Non-vested at September 30, 2019	817,028		45.56

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



	Nine Months Ended September 30,
	2019		2018
	(in thousands, except per share data)

Total intrinsic value of time-based awards vested	$	11,251	$	11,178
Total intrinsic value of time-based awards non-vested	22,673		30,987
Market price per share as of September 30	27.75		48.96
Weighted-average grant date fair value per share	40.38		50.85

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, 2019 was $25.9 million. This cost is expected to be recognized over a weighted-average period of 1.9 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

The Compensation Committee awarded a total of 139,197 market-based PSUs to our executive officers during the nine months ended September 30, 2019. In addition to continuous employment, the vesting of these PSUs is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2021, 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 200 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,
	2019		2018

Expected term of award (in years)	3		3
Risk-free interest rate	2.5	%	2.4	%
Expected volatility	41.4	%	42.3	%

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.

The following table presents the change in non-vested market-based awards during the nine months ended September 30, 2019:



	Shares	Weighted-Average Grant Date Fair Value per Share

Non-vested at December 31, 2018	102,914	$	74.88
Granted	139,197	56.68
Non-vested at September 30, 2019	242,111	64.42

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



	Nine Months Ended September 30,
	2019		2018
	(in thousands, except per share data)

Total intrinsic value of market-based awards non-vested	$	6,719	$	6,805
Market price per common share as of September 30,	27.75		48.96
Weighted-average grant date fair value per share	56.68		69.98

Total compensation cost related to non-vested market-based awards not yet recognized in our condensed consolidated statements of operations as of September 30, 2019 was $8.9 million. This cost is expected to be recognized over a weighted-average period of 1.7 years.

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. No SARs were awarded or expired during the three and nine months ended September 30, 2019.

Total compensation cost related to non-vested SARs granted and not yet recognized in our condensed consolidated statements of operations as of September 30, 2019 was $0.1 million. The cost is expected to be recognized over a weighted-average period of 0.3 years.

Table of contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

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, 2019, no shares of preferred stock have been issued.

Stock Repurchase Program

In April 2019, the Board approved a stock repurchase program (the "Stock Repurchase Program") to acquire up to $200 million of our outstanding common stock, depending on market conditions. 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. Our target completion date for the Stock Repurchase Program is December 31, 2020.

During the three and nine months ended September 30, 2019, we repurchased 1.2 million and 4.4 million shares of our outstanding common stock, respectively, at a cost of $40.3 million and $145.5 million, respectively, pursuant to the Stock Repurchase Program. We settled $142.7 million of the repurchases prior to September 30, 2019 and accrued $2.8 million for settlements that occurred subsequent to period-end. During October 2019, we repurchased 0.3 million shares of our outstanding common stock at a cost of $8.9 million. Approximately $45.7 million remains available for repurchases under the Stock Repurchase Program. See the footnote titled Pending Acquisition for more information regarding our Stock Repurchase Plan.

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. The authoritative guidance for accounting for income taxes allows use of the year-to-date effective tax rate (the “discrete method”) when a reliable estimate of the estimated annual effective tax rate cannot be made. During the interim period ended September 30, 2019, we determined that the use of the discrete method is more appropriate than the annual effective tax rate method due to sensitivity to small changes to projected pre-tax earnings for the year, which resulted in significant variations in the customary relationship between income tax expense and pretax income. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs. Consequently, based upon the mix and timing of our actual annual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful.

The effective income tax rates differ from the statutory federal tax rate, primarily due to state taxes, stock-based compensation, nondeductible officers’ compensation and nondeductible lobbying expenses. The effective income tax rates for the three and nine months ended September 30, 2019 includes discrete income tax provision items of $0.1 million and $3.1 million, respectively, relating to the tax detriment on stock-based compensation and change in estimated federal tax credits, which resulted in a 0.2 percent increase and a 7.7 percent decrease to our effective income tax rate for the three and nine months ended September 30, 2019, respectively. We anticipate the potential for increased periodic volatility in future effective tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items.

As of September 30, 2019, 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 partially accepted our 2018 tax return. The 2018 tax return is in the IRS CAP Program post-filing review process, with no significant tax adjustments currently proposed. We are currently participating in the CAP Program for the review of our 2019 tax year. Participation in the CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

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 restricted stock, outstanding SARs, 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,
	2019	2018	2019	2018
	(in thousands)

Weighted-average common shares outstanding - basic	62,547	66,073	64,835	66,032
Dilutive effect of:
Restricted stock and PSU	32	—	—	—
Other equity-based awards	16	—	—	—
Weighted-average common shares and equivalents outstanding - diluted	62,595	66,073	64,835	66,032

We reported a net loss for the nine months ended September 30, 2019 and the three and nine months ended September 30, 2018. As a result, our basic and diluted weighted-average common shares outstanding were the same for those periods because the effect of the common share equivalents was anti-dilutive.

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



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
	(in thousands)

Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
RSUs and PSUs	947	719	980	655
Other equity-based awards	267	314	302	319
Total anti-dilutive common share equivalents	1,214	1,033	1,282	974

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 could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $85.39 conversion price during the periods presented. During the three and nine months ended September 30, 2019 and 2018, the average market price of our common stock did not exceed the conversion price; therefore, shares issuable upon conversion of the 2021 Convertible Notes were not included in the diluted earnings per share calculation.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)

NOTE 16 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION



	Nine Months Ended September 30,
	2019			2018 (1)
	(in thousands)
Supplemental cash flow information:
Cash payments for:
Interest, net of capitalized interest	$	41,483		$	39,470
Income taxes	261			(6,707		)

Non-cash investing and financing activities:
Change in accounts payable related to capital expenditures	$	(57,696	)	$	91,444
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals	13,493			6,720
Change in accounts payable related to the purchase and retirement of treasury shares	2,818			—

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

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

(1) As we have elected the modified retrospective method of adoption for the New Lease Standard, cash flows related to lease liabilities have

not been restated for the nine months ended September 30, 2018.

NOTE 17 - SUBSIDIARY GUARANTOR

PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the condensed consolidating financial information separately for:



(i)	PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries;
(ii)	PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes;
(iii)	Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and
(iv)	Parent and subsidiaries on a consolidated basis ("Consolidated").

The Guarantor is 100 percent owned by the Parent. The senior notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the condensed consolidating financial information follows the same accounting policies as described in the notes to the condensed consolidated financial statements.

The following condensed consolidating financial statements have been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column.

Table of contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)



	Condensed Consolidating Balance Sheets
	September 30, 2019
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Current assets:
Cash and cash equivalents	$	1,968		$	2,599		$	—		$	4,567
Accounts receivable, net	128,245			124,832			—			253,077
Fair value of derivatives	75,830			—			—			75,830
Prepaid expenses and other current assets	7,680			258			—			7,938
Total current assets	213,723			127,689			—			341,412
Properties and equipment, net	2,373,992			1,791,164			—			4,165,156
Intercompany receivable	355,429			—			(355,429		)	—
Investment in subsidiaries	1,288,788			—			(1,288,788		)	—
Fair value of derivatives	33,185			—			—			33,185
Other assets	36,818			7,033			—			43,851
Total Assets	$	4,301,935		$	1,925,886		$	(1,644,217	)	$	4,583,604

Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	104,292		$	43,601		$	—		$	147,893
Production tax liability	65,503			6,066			—			71,569
Fair value of derivatives	2,953			—			—			2,953
Funds held for distribution	71,376			16,671			—			88,047
Accrued interest payable	16,276			4			—			16,280
Other accrued expenses	78,603			2,446			—			81,049
Total current liabilities	339,003			68,788			—			407,791
Intercompany payable	—			355,429			(355,429		)	—
Long-term debt	1,267,471			—			—			1,267,471
Deferred income taxes	166,455			27,252			—			193,707
Asset retirement obligations	80,232			5,950			—			86,182
Fair value of derivatives	661			—			—			661
Other liabilities	88,358			179,679			—			268,037
Total liabilities	1,942,180			637,098			(355,429		)	2,223,849

Commitments and contingent liabilities

Stockholders' Equity
Common shares	621			—			—			621
Additional paid-in capital	2,390,658			1,766,775			(1,766,775		)	2,390,658
Retained deficit	(26,993		)	(477,987		)	477,987			(26,993		)
Treasury shares	(4,531		)	—			—			(4,531		)
Total stockholders' equity	2,359,755			1,288,788			(1,288,788		)	2,359,755
Total Liabilities and Stockholders' Equity	$	4,301,935		$	1,925,886		$	(1,644,217	)	$	4,583,604

Table of contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)



	Condensed Consolidating Balance Sheets
	December 31, 2018
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Current assets:
Cash and cash equivalents	$	1,398		$	—		$	—		$	1,398
Accounts receivable, net	146,529			34,905			—			181,434
Fair value of derivatives	84,492			—			—			84,492
Prepaid expenses and other current assets	6,725			411			—			7,136
Total current assets	239,144			35,316			—			274,460
Properties and equipment, net	2,270,711			1,732,151			—			4,002,862
Assets held-for-sale	—			140,705			—			140,705
Intercompany receivable	451,601			—			(451,601		)	—
Investment in subsidiaries	1,316,945			—			(1,316,945		)	—
Fair value of derivatives	93,722			—			—			93,722
Other assets	30,084			2,312			—			32,396
Total Assets	$	4,402,207		$	1,910,484		$	(1,768,546	)	$	4,544,145

Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	110,847		$	71,017		$	—		$	181,864
Production tax liability	53,309			7,410			—			60,719
Fair value of derivatives	3,364			—			—			3,364
Funds held for distribution	90,183			15,601			—			105,784
Accrued interest payable	14,143			7			—			14,150
Other accrued expenses	73,689			1,444			—			75,133
Total current liabilities	345,535			95,479			—			441,014
Intercompany payable	—			451,601			(451,601		)	—
Long-term debt	1,194,876			—			—			1,194,876
Deferred income taxes	162,368			35,728			—			198,096
Asset retirement obligations	79,904			5,408			—			85,312
Liabilities held-for-sale	—			4,111			—			4,111
Fair value of derivatives	1,364			—			—			1,364
Other liabilities	91,452			1,212			—			92,664
Total liabilities	1,875,499			593,539			(451,601		)	2,017,437

Commitments and contingent liabilities

Stockholders' Equity
Common shares	661			—			—			661
Additional paid-in capital	2,519,423			1,766,775			(1,766,775		)	2,519,423
Retained earnings (deficit)	8,727			(449,830		)	449,830			8,727
Treasury shares	(2,103		)	—			—			(2,103		)
Total stockholders' equity	2,526,708			1,316,945			(1,316,945		)	2,526,708
Total Liabilities and Stockholders' Equity	$	4,402,207		$	1,910,484		$	(1,768,546	)	$	4,544,145

Table of contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)



	Condensed Consolidating Statements of Operations
	Three Months Ended September 30, 2019
	Parent			Guarantor			Eliminations		Consolidated
	(in thousands)

Revenues
Crude oil, natural gas and NGLs sales	$	226,397		$	81,012		$	—	$	307,409
Commodity price risk management gain, net	54,867			—			—		54,867
Other income	3,193			474			—		3,667
Total revenues	284,457			81,486			—		365,943
Costs, expenses and other
Lease operating expenses	23,955			12,543			—		36,498
Production taxes	10,787			2,252			—		13,039
Transportation, gathering and processing expenses	6,252			4,747			—		10,999
Exploration, geologic and geophysical expense	311			(102		)	—		209
Impairment of properties and equipment	117			50			—		167
General and administrative expense	37,936			3,155			—		41,091
Depreciation, depletion and amortization	119,460			52,379			—		171,839
Accretion of asset retirement obligations	1,220			136			—		1,356
(Gain) loss on sale of properties and equipment	(227		)	44,099			—		43,872
Other expenses	2,492			—			—		2,492
Total costs, expenses and other	202,303			119,259			—		321,562
Income (loss) from operations	82,154			(37,773		)	—		44,381
Interest expense	(18,803		)	944			—		(17,859		)
Interest income	48			—			—		48
Income (loss) before income taxes	63,399			(36,829		)	—		26,570
Income tax (expense) benefit	(19,010		)	8,348			—		(10,662		)
Equity in loss of subsidiary	(28,481		)	—			28,481		—
Net income (loss)	$	15,908		$	(28,481	)	$	28,481	$	15,908

Table of contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)



	Condensed Consolidating Statements of Operations
	Three Months Ended September 30, 2018
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Revenues
Crude oil, natural gas and NGLs sales	$	280,866		$	91,573		$	—		$	372,439
Commodity price risk management loss, net	(94,394		)	—			—			(94,394		)
Other income	2,300			372			—			2,672
Total revenues	188,772			91,945			—			280,717
Costs, expenses and other
Lease operating expenses	23,219			9,827			—			33,046
Production taxes	17,852			6,132			—			23,984
Transportation, gathering and processing expenses	4,520			4,714			—			9,234
Exploration, geologic and geophysical expense	279			753			—			1,032
Impairment of properties and equipment	98			1,390			—			1,488
General and administrative expense	43,886			4,354			—			48,240
Depreciation, depletion and amortization	97,370			50,170			—			147,540
Accretion of asset retirement obligations	1,084			116			—			1,200
(Gain) loss on sale of properties and equipment	(141		)	2,259			—			2,118
Other expenses	2,711			—			—			2,711
Total costs, expenses and other	190,878			79,715			—			270,593
Income (loss) from operations	(2,106		)	12,230			—			10,124
Interest expense	(18,232		)	610			—			(17,622		)
Interest income	188			—			—			188
Income (loss) before income taxes	(20,150		)	12,840			—			(7,310		)
Income tax (expense) benefit	5,753			(1,877		)	—			3,876
Equity in income of subsidiary	10,963			—			(10,963		)	—
Net income (loss)	$	(3,434	)	$	10,963		$	(10,963	)	$	(3,434	)

Table of contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)



	Condensed Consolidating Statements of Operations
	Nine Months Ended September 30, 2019
	Parent			Guarantor			Eliminations		Consolidated
	(in thousands)

Revenues
Crude oil, natural gas and NGLs sales	$	737,601		$	229,863		$	—	$	967,464
Commodity price risk management loss, net	(87,858		)	—			—		(87,858		)
Other income	8,381			3,114			—		11,495
Total revenues	658,124			232,977			—		891,101
Costs, expenses and other
Lease operating expenses	71,143			34,904			—		106,047
Production taxes	44,600			13,249			—		57,849
Transportation, gathering and processing expenses	17,561			17,070			—		34,631
Exploration, geologic and geophysical expense	887			2,605			—		3,492
Impairment of properties and equipment	117			36,904			—		37,021
General and administrative expense	109,655			13,842			—		123,497
Depreciation, depletion and amortization	349,055			142,729			—		491,784
Accretion of asset retirement obligations	3,949			554			—		4,503
(Gain) loss on sale of properties and equipment	(675		)	10,274			—		9,599
Other expenses	8,882			—			—		8,882
Total costs, expenses and other	605,174			272,131			—		877,305
Income (loss) from operations	52,950			(39,154		)	—		13,796
Interest expense	(56,488		)	2,746			—		(53,742		)
Interest income	63			—			—		63
Loss before income taxes	(3,475		)	(36,408		)	—		(39,883		)
Income tax (expense) benefit	(4,087		)	8,250			—		4,163
Equity in loss of subsidiary	(28,158		)	—			28,158		—
Net loss	$	(35,720	)	$	(28,158	)	$	28,158	$	(35,720	)

Table of contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)



	Condensed Consolidating Statements of Operations
	Nine Months Ended September 30, 2018
	Parent			Guarantor			Eliminations		Consolidated
	(in thousands)

Revenues
Crude oil, natural gas and NGLs sales	$	757,263		$	246,334		$	—	$	1,003,597
Commodity price risk management loss, net	(257,760		)	—			—		(257,760		)
Other income	7,295			716			—		8,011
Total revenues	506,798			247,050			—		753,848
Costs, expenses and other
Lease operating expenses	68,013			26,929			—		94,942
Production taxes	50,122			16,635			—		66,757
Transportation, gathering and processing expenses	11,361			14,150			—		25,511
Exploration, geologic and geophysical expense	887			3,666			—		4,553
Impairment of properties and equipment	191			194,039			—		194,230
General and administrative expense	108,597			12,586			—		121,183
Depreciation, depletion and amortization	284,963			124,989			—		409,952
Accretion of asset retirement obligations	3,460			313			—		3,773
Loss on sale of properties and equipment	940			2,259			—		3,199
Other expenses	8,187			—			—		8,187
Total costs, expenses and other	536,721			395,566			—		932,287
Loss from operations	(29,923		)	(148,516		)	—		(178,439		)
Interest expense	(54,244		)	1,683			—		(52,561		)
Interest income	405			—			—		405
Loss before income taxes	(83,762		)	(146,833		)	—		(230,595		)
Income tax benefit	19,678			34,087			—		53,765
Equity in loss of subsidiary	(112,746		)	—			112,746		—
Net loss	$	(176,830	)	$	(112,746	)	$	112,746	$	(176,830	)

Table of contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)



	Condensed Consolidating Statements of Cash Flows
	Nine Months Ended September 30, 2019
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Cash flows from operating activities	$	436,397		$	239,328		$	—		$	675,725
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(445,448		)	(335,133		)	—			(780,581		)
Capital expenditures for other properties and equipment	(15,192		)	(330		)	—			(15,522		)
Acquisition of crude oil and natural gas properties	(11,379		)	(1,066		)	—			(12,445		)
Proceeds from sale of properties and equipment	153			1,375			—			1,528
Proceeds from divestitures	5,485			196,561			—			202,046
Restricted cash	8,001			—			—			8,001
Intercompany transfers	97,908			—			(97,908		)	—
Net cash from investing activities	(360,472		)	(138,593		)	(97,908		)	(596,973		)
Cash flows from financing activities:
Proceeds from revolving credit facility	1,300,000			—			—			1,300,000
Repayment of revolving credit facility	(1,235,500		)	—			—			(1,235,500		)
Payment of debt issuance costs	(53		)	—			—			(53		)
Purchase of treasury shares	(142,665		)	—			—			(142,665		)
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	(3,874		)	—			—			(3,874		)
Principal payments under financing lease obligations	(1,264		)	(228		)	—			(1,492		)
Intercompany transfers	—			(97,908		)	97,908			—
Net cash from financing activities	(83,356		)	(98,136		)	97,908			(83,584		)
Net change in cash, cash equivalents and restricted cash	(7,431		)	2,599			—			(4,832		)
Cash, cash equivalents and restricted cash, beginning of period	9,399			—			—			9,399
Cash, cash equivalents and restricted cash, end of period	$	1,968		$	2,599		$	—		$	4,567

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(unaudited)



	Condensed Consolidating Statements of Cash Flows
	Nine Months Ended September 30, 2018
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Cash flows from operating activities	$	405,326		$	172,508		$	—		$	577,834
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(360,457		)	(325,092		)	—			(685,549		)
Capital expenditures for other properties and equipment	(2,834		)	(905		)	—			(3,739		)
Acquisition of crude oil and natural gas properties, including settlement adjustments	(181,501		)	(71		)	—			(181,572		)
Proceeds from sale of properties and equipment	1,918			525			—			2,443
Proceeds from divestitures	43,493			—			—			43,493
Restricted cash	1,249			—			—			1,249
Intercompany transfers	(153,121		)	—			153,121			—
Net cash from investing activities	(651,253		)	(325,543		)	153,121			(823,675		)
Cash flows from financing activities:
Proceeds from revolving credit facility	629,000			—			—			629,000
Repayment of revolving credit facility	(554,000		)	—			—			(554,000		)
Payment of debt issuance costs	(4,086		)	—			—			(4,086		)
Purchase of treasury shares for employee stock-based compensation tax withholding obligations	(4,700		)	—			—			(4,700		)
Principal payments under financing lease obligations	(787		)	(86		)	—			(873		)
Other	(55		)	—			—			(55		)
Intercompany transfers	—			153,121			(153,121		)	—
Net cash from financing activities	65,372			153,035			(153,121		)	65,286
Net change in cash, cash equivalents and restricted cash	(180,555		)	—			—			(180,555		)
Cash, cash equivalents and restricted cash, beginning of period	189,925			—			—			189,925
Cash, cash equivalents and restricted cash, end of period	$	9,370		$	—		$	—		$	9,370

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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

Production and Financial Overview

Production volumes increased to 12.7 MMboe and 36.4 MMboe for the three and nine months ended September 30, 2019, respectively, representing increases of 26 percent and 28 percent as compared to the three and nine months ended September 30, 2018, respectively. Crude oil production increased 13 percent and 19 percent for the three and nine months ended September 30, 2019, respectively, compared to the three and nine months ended September 30, 2018, respectively. Natural gas production increased 35 percent in each of the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018. NGLs production increased 37 percent and 35 percent for the three and nine months ended September 30, 2019, respectively, compared to the three and nine months ended September 30, 2018, respectively. For the month ended September 30, 2019, we maintained an average daily production rate of approximately 138,000 Boe per day, up from approximately 121,000 Boe per day for the month ended September 30, 2018.

On a sequential quarterly basis, total production for the three months ended September 30, 2019 as compared to the three months ended June 30, 2019 increased by two percent and crude oil production decreased by one percent. The increase in total production volumes was primarily related to the timing of wells turned-in-line in both areas of production, partially offset by elevated gathering system line pressures and unplanned facility downtime in the Wattenberg Field. The decrease in crude oil production was primarily related to elevated gathering system line pressures and unplanned facility downtime.

Crude oil, natural gas and NGLs sales revenue decreased to $307.4 million and $967.5 million for the three and nine months ended September 30, 2019, respectively, compared to $372.4 million and $1.0 billion for the three and nine months ended September 30, 2018, respectively. The 18 percent and four percent decreases in sales revenues were driven by the 34 percent and 25 percent decreases in weighted-average realized commodity prices, partially offset by the 26 percent and 28 percent increases in production, as compared to the prior periods.

We had positive net settlements from our commodity derivative contracts of $1.8 million for the three months ended September 30, 2019 and negative net settlements from our commodity derivative contracts of $19.8 million for the nine months ended September 30, 2019, as compared to negative net settlements of $48.1 million and $90.5 million for the three and nine months ended September 30, 2018.

The combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments decreased five percent to $309.2 million for the three months ended September 30, 2019 from $324.3 million for the three months ended September 30, 2018 and increased four percent to $947.7 million for the nine months ended September 30, 2019 from $913.1 million for the nine months ended September 30, 2018.

For the three months ended September 30, 2019, we generated net income of $15.9 million and for the nine months ended September 30, 2019, we generated a net loss of $35.7 million, or $0.25 and $(0.55) per diluted share, respectively, compared to net losses of $3.4 million and $176.8 million, respectively, or $(0.05) and $(2.68) per diluted share, respectively, for the comparable periods in 2018. Our net income for the three months ended September 30, 2019 as compared to the net loss for the three months ended September 30, 2018 was primarily due to the gain in commodity price risk management for the three months ended September 30, 2019 as compared to the loss in the three months ended September 30, 2018, partially offset by the increase in the loss on sale of properties and equipment of $41.8 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. Our net loss for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 was most positively impacted by the decrease in the loss in commodity price risk management, the decrease in impairments of properties and equipment and the $34.0 million gain from the Midstream Asset Divestitures, which were partially offset by the $45.6 million loss from sale of properties and equipment resulting from an acreage acquisition.

During the three and nine months ended September 30, 2019, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $214.7 million and $646.4 million, respectively, compared to $215.3 million and $621.1 million, respectively, for the comparable periods of 2018. The decrease for the three months ended September 30, 2019 was primarily due to the

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decrease in crude oil, natural gas and NGLs sales of $65.0 million. The decrease was partially offset by the increase in commodity derivative settlements of $49.9 million and the decrease in operating costs of $12.9 million for the three months ended September 30, 2019. The increase for the nine months ended September 30, 2019 was primarily due to the decrease in the loss on commodity derivative settlements of $70.7 million, which was partially offset by the decrease in crude oil, natural gas and NGLs sales of $36.1 million and the increase in operating costs of $13.6 million. 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.

Our cash flows from operations were $675.7 million and $577.8 million and our adjusted cash flows from operations, a non-U.S. GAAP financial measure, were $601.9 million and $575.3 million for the nine months ended September 30, 2019 and September 30, 2018, respectively.

Pending Acquisition

On August 25, 2019, we and SRC entered into the Merger Agreement relating to the SRC Acquisition. We expect the SRC Acquisition to be completed early in the first quarter of 2020, subject to PDC and SRC shareholder approval, respectively, and the satisfaction of certain other customary closing conditions. The value of the SRC Acquisition, which will include assumption of SRC's net debt, will be dependent upon the market value of our common stock on the date of closing. We estimate that we will issue up to approximately 40 million shares of our common stock in connection with the SRC Acquisition. See Item 1A. Risk Factors for risk factors related to the SRC Acquisition.

Liquidity

Available liquidity as of September 30, 2019 was $1.2 billion, which was comprised of $4.6 million of cash and cash equivalents and $1.2 billion available for borrowing under our revolving credit facility. In October 2019, as part of our semi-annual redetermination, the borrowing base on our revolving credit facility was reaffirmed at $1.6 billion and we elected to retain our commitment amount at $1.3 billion. Based on our current production forecast for 2019 and assuming a NYMEX crude oil price of $55.00 per barrel, we expect cash flows from operations to approximate our capital investments in crude oil and natural gas properties for the year. Although capital investments in crude oil and natural gas properties exceeded cash flows from operations during the nine months ended September 30, 2019, we expect cash flows from operations to exceed capital investments in crude oil and natural gas properties during the fourth quarter of 2019.

In the second quarter of 2019, we completed the Midstream Asset Divestitures for an aggregate cash purchase price of $345.6 million ($263.6 million of which was paid upon closing with $82.0 million to be paid in June 2020), subject to certain customary post-closing adjustments, plus aggregate conditional payments of up to $150.7 million. We allocated $179.6 million of the proceeds to deferred midstream gathering credits for future gathering, processing, transportation and water disposal services. We have and expect to continue to use the proceeds from these divestitures for our capital investment program.

Subject to closing the SRC Acquisition, the borrowing base on our revolving credit facility will increase to $2.1 billion. In addition, we elected to increase the aggregate commitment amount under our revolving credit facility to (i) $1.7 billion upon closing of the SRC Acquisition and (ii) up to $1.9 billion, at our sole discretion, at any time following closing of the SRC Acquisition before April 30, 2020. As described below, if the SRC Acquisition results in a "Change of Control" under the indenture governing the SRC Senior Notes, we will be required to make an offer to purchase those notes. We expect that our decision regarding the expansion of the commitment to $1.9 billion will be based in part on whether we make such an offer and, if so, the amount of SRC Senior Notes tendered in the offer.

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In April 2019, the Board approved the acquisition of up to $200 million of our outstanding common stock, depending on market conditions. Pursuant to the Stock Repurchase Program, we repurchased 4.4 million shares of outstanding common stock at a cost of $145.5 million from June 2019 through September 2019 and we repurchased 0.3 million shares of outstanding common stock at a cost of $8.9 million during October 2019. Approximately $45.7 million remains available for repurchases under the Stock Repurchase Program as of October 31, 2019. Applicable regulations will prohibit us from repurchasing shares during the period between the distribution of the definitive proxy statement/prospectus relating to the SRC Acquisition and the closing of the acquisition. Additionally, in August 2019, contingent on the closing of the SRC Acquisition, the Board approved an increase and extension to the Stock Repurchase Program. The program now contemplates up to $525 million in repurchases with a target completion date of December 31, 2021.

Operational Overview

We ran three drilling rigs in the Wattenberg Field through mid-September 2019 and then dropped to a two-rig pace, which we expect to maintain during the remainder of 2019. In the Delaware Basin, we ran three rigs through May 2019 and then dropped to a two-rig pace in June 2019. We expect to continue to operate at a two-rig pace in the Delaware Basin throughout the remainder of the year. We were able to reduce the number of rigs in each area primarily due to operational efficiencies, our allocation of our planned expenditures and our inventory of drilled uncompleted wells. The projected activities and results discussed in this section and below in "2019 Operational and Financial Outlook" do not reflect any additional impact of the SRC Acquisition.

The following tables summarize our drilling and completion activity for the nine months ended September 30, 2019:



	Operated Wells
	Wattenberg Field				Delaware Basin				Total
	Gross		Net		Gross		Net		Gross		Net
In-process as of December 31, 2018	133		122.4		18		17.4		151		139.8
Spud	107		102.6		24		23.3		131		125.9
Turned-in-line	(102	)	(93.3	)	(21	)	(20.0	)	(123	)	(113.3	)
In-process as of September 30, 2019	138		131.7		21		20.7		159		152.4



	Non-Operated Wells
	Wattenberg Field				Delaware Basin				Total
	Gross		Net		Gross		Net		Gross		Net
In-process as of December 31, 2018	5		2.0		6		0.9		11		2.9
Spud	46		4.1		3		0.4		49		4.5
Turned-in-line	(19	)	(1.1	)	(9	)	(1.3	)	(28	)	(2.4	)
In-process as of September 30, 2019	32		5.0		—		—		32		5.0

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 drilled uncompleted wells are generally completed and turned-in-line within a year of drilling.

2019 Operational and Financial Outlook

We currently expect our production for 2019 to range between 48 MMBoe to 50 MMBoe, or approximately 132,000 Boe to 137,000 Boe per day. We estimate that approximately 40 percent of our 2019 production will be comprised of crude oil and approximately 22 percent will be NGLs, for total liquids of approximately 62 percent. Our planned 2019 capital investments in crude oil and natural gas properties, which we now expect to be at or near the low end of our $810 million to $840 million range, are focused on continued execution of our development plans in the Wattenberg Field and Delaware Basin.

We believe that our disciplined approach in allocating our planned expenditures allows us to maintain a degree of operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, cost efficiencies, expected rates of return, the political environment and our remaining inventory in order to best meet our short- and long-term corporate strategy. Should commodity pricing or the operating environment deteriorate, we may determine that an adjustment to our development plan is appropriate.

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Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the core Wattenberg Field, which we have delineated between the Kersey, Prairie and Plains development areas. Our 2019 capital investment program for the Wattenberg Field is approximately 60 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. We plan to drill standard-reach lateral (“SRL”), mid-reach lateral (“MRL”) and extended-reach lateral (“XRL”) wells in 2019, the majority of which will be in the Kersey area of the field. In 2019, we anticipate spudding approximately 120 to 130 operated wells and turning-in-line approximately 110 to 125 operated wells. We expect an average development cost of between $3 million and $5 million per well, 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. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2019 are expected to be approximately 40 percent of our total capital investments in crude oil and natural gas properties, of which approximately 85 percent is allocated to spud 33 operated wells and turn-in-line 21 operated wells. We plan to drill MRL and XRL wells in 2019 with an expected average development cost of between $11.5 million and $13 million per well, depending upon the lateral length of the well. We do not plan to drill any SRL wells in the Delaware Basin in 2019. Based on the timing of our operations and requirements to hold acreage, we may elect to drill wells different from or in addition to those currently anticipated as we are continuing to analyze the terms of the relevant leases. We plan to use approximately 15 percent of our budgeted Delaware Basin capital for leasing, non-operated capital, seismic and technical studies and facilities.

Corporate Capital. In 2019, we also expect to spend approximately $20 million for corporate capital, the majority of which is related to the implementation of an Enterprise Resource Planning system to replace our existing operating and financial systems. This long-planned investment is being made to enhance maintenance of our financial records, improve operational functionality and provide timely information to our management team related to the operation of the business.

Financial Guidance.

The following table sets forth our current financial guidance for the year ended December 31, 2019 for certain expenses and the impact of price differentials, exclusive of expected costs related to the SRC Acquisition:



	Low			High
Operating Expenses
Lease operating expenses ($/Boe)	$	2.85		$	3.00
Transportation, gathering and processing expenses ("TGP") ($/Boe)	$	0.90		$	1.00
Production taxes (% of crude oil, natural gas and NGLs sales)	6		%	7		%
General and administrative expense ("G&A") ($/Boe)	$	3.00		$	3.20

Estimated Price Realizations (% of NYMEX, excludes TGP)
Crude oil	90%			95%
Natural gas	40%			45%
NGLs	20%			25%

In June 2019, in response to current market conditions and reductions in development activity in the Wattenberg Field and Delaware Basin, we instituted measures we believe were necessary to reduce our general and administrative expenses. As a result, we reduced corporate headcount by approximately 15 percent to more closely align with our updated operational plans. These measures have resulted in general and administrative expense, exclusive of costs incurred related to the SRC Acquisition, of $2.84 per Boe in the third quarter of 2019. We expect our general and administrative expense, exclusive of costs incurred related to the SRC Acquisition, to be in the range of $2.60 to $2.80 per Boe for the fourth quarter of 2019.

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Regulatory Update

Senate Bill 19-181. In April 2019, Colorado Senate Bill 19-181 (“SB-181”) was signed into law and made a number of changes to oil and gas regulation in Colorado. The bill gives local governments the option to regulate facility siting and surface impacts and increases air quality monitoring and environmental protection. It also changes the mission and makeup of the COGCC, among other things. Rulemakings contemplated by the bill may create new application and operating requirements; however, the rulemaking process is expected to take years to finalize. In October 2019, the CDPHE released a study of potential health risks that modeled certain exposure scenarios at distances up to 2,000 feet, based on data collected at oil and gas development and production sites. The study concluded that modeling results “support increased concern for adverse effects” in a very narrow set of hypothetical circumstances associated with the development phase of oil and gas operations. As a result, the COGCC has determined that it will utilize the objective criteria developed following SB-181 in reviewing proposed permits for locations up to 2,000 feet from building units. The criteria are currently being used in the review of permits up to 1,500 feet from building units. We may experience significant delays in the issuance of permits and necessary approvals as a result, but we have previously been successful in obtaining permits under the objective criteria. We primarily operate in the core Wattenberg Field in Weld County and have approved permits for development into April of 2021; however, significant delays in the issuance of permits could adversely impact the timing of our future development plans in the Wattenberg Field.

Ozone Classification. In 2016, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro North Front Range Ozone Eight-Hour Non-Attainment ("Denver Metro/North Front Range NAA") area from “marginal” to “moderate” under the 2008 national ambient air quality standard (“NAAQS”). This increase in non-attainment status triggered significant additional obligations for the state under the Clean Air Act ("CAA") and resulted in Colorado adopting new and more stringent air quality control requirements in November 2017 that are applicable to our operations. Ozone measurements in the Denver Metro/North Front Range NAA exceeded the NAAQS during 2018, subjecting it to a further reclassification to “serious.” In 2018, the CDPHE requested an extension to the “serious” ozone classification as a result of a year of compliant ozone monitoring in 2017. This extension request was withdrawn by Governor Polis in March 2019. The EPA and CDPHE are currently determining the process for a “serious” designation, which is expected to occur later this year. A “serious” classification will trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements, which may in turn result in significant costs, and delays in obtaining necessary permits applicable to our operations.

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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,
	2019			2018			Percent Change		2019			2018			Percent Change
	(dollars in millions, except per unit data)
Production
Crude oil (MBbls)	4,853			4,296			13.0	%	14,277			12,040			18.6	%
Natural gas (MMcf)	29,273			21,765			34.5	%	83,916			62,040			35.3	%
NGLs (MBbls)	2,983			2,177			37.0	%	8,091			6,010			34.6	%
Crude oil equivalent (MBoe)	12,714			10,100			25.9	%	36,354			28,390			28.1	%
Average Boe per day (Boe)	138,195			109,783			25.9	%	133,165			103,993			28.1	%
Crude Oil, Natural Gas and NGLs Sales
Crude oil	$	255.7		$	284.7		(10.2	)%	$	761.0		$	763.7		(0.4	)%
Natural gas	26.6			34.7			(23.3	)%	110.1			103.4			6.5	%
NGLs	25.1			53.0			(52.6	)%	96.4			136.5			(29.4	)%
Total crude oil, natural gas and NGLs sales	$	307.4		$	372.4		(17.5	)%	$	967.5		$	1,003.6		(3.6	)%

Net Settlements on Commodity Derivatives
Crude oil	$	(1.9	)	$	(51.6	)	(96.3	)%	$	(19.5	)	$	(104.1	)	(81.3	)%
Natural gas	3.7			4.8			(22.9	)%	(0.3		)	18.7			(101.6	)%
NGLs	—			(1.3		)	*		—			(5.1		)	*
Total net settlements on derivatives	$	1.8		$	(48.1	)	(103.7	)%	$	(19.8	)	$	(90.5	)	(78.1	)%

Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	52.70		$	66.27		(20.5	)%	$	53.30		$	63.43		(16.0	)%
Natural gas (per Mcf)	0.91			1.60			(43.1	)%	1.31			1.67			(21.6	)%
NGLs (per Bbl)	8.43			24.35			(65.4	)%	11.92			22.71			(47.5	)%
Crude oil equivalent (per Boe)	24.18			36.88			(34.4	)%	26.61			35.35			(24.7	)%

Average Costs and Expenses (per Boe)
Lease operating expenses	$	2.87		$	3.27		(12.2	)%	$	2.92		$	3.34		(12.6	)%
Production taxes	1.03			2.37			(56.5	)%	1.59			2.35			(32.3	)%
Transportation, gathering and processing expenses	0.87			0.91			(4.4	)%	0.95			0.90			5.6	%
General and administrative expense	3.23			4.78			(32.4	)%	3.40			4.27			(20.4	)%
Depreciation, depletion and amortization	13.52			14.61			(7.5	)%	13.53			14.44			(6.3	)%

Lease Operating Expenses by Operating Region (per Boe)
Wattenberg Field	$	2.51		$	3.01		(16.6	)%	$	2.53		$	3.11		(18.6	)%
Delaware Basin	3.94			4.09			(3.7	)%	4.21			4.13			1.9	%
Utica Shale (1)	—			—			*		—			3.46			*



	Amounts may not recalculate due to rounding.
*	Percent change is not meaningful.
(1)	In March 2018, we completed the disposition of our Utica Shale properties.

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Crude Oil, Natural Gas and NGLs Sales

For the three and nine months ended September 30, 2019, crude oil, natural gas and NGLs sales revenue decreased compared to the three and nine months ended September 30, 2018 due to the following:



	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
	(in millions)
Increase in production	$	68.6		$	225.6
Decrease in average crude oil sales price	(65.9		)	(144.6		)
Decrease in average natural gas sales price	(20.2		)	(29.8		)
Decrease in average NGLs sales price	(47.5		)	(87.3		)
Total decrease in crude oil, natural gas and NGLs sales revenue	$	(65.0	)	$	(36.1	)

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	2019	2018	Percent Change		2019	2018	Percent Change
Crude oil (MBbls)
Wattenberg Field	3,525	3,254	8.3	%	10,777	9,076	18.7	%
Delaware Basin	1,328	1,042	27.4	%	3,500	2,918	19.9	%
Utica Shale (1)	—	—	*		—	46	*
Total	4,853	4,296	13.0	%	14,277	12,040	18.6	%
Natural gas (MMcf)
Wattenberg Field	22,945	16,808	36.5	%	67,139	48,169	39.4	%
Delaware Basin	6,328	4,957	27.7	%	16,777	13,457	24.7	%
Utica Shale (1)	—	—	*		—	414	*
Total	29,273	21,765	34.5	%	83,916	62,040	35.3	%
NGLs (MBbls)
Wattenberg Field	2,178	1,643	32.6	%	6,086	4,616	31.8	%
Delaware Basin	805	534	50.7	%	2,005	1,360	47.4	%
Utica Shale (1)	—	—	*		—	34	*
Total	2,983	2,177	37.0	%	8,091	6,010	34.6	%
Crude oil equivalent (MBoe)
Wattenberg Field	9,527	7,698	23.8	%	28,053	21,721	29.2	%
Delaware Basin	3,187	2,402	32.7	%	8,301	6,520	27.3	%
Utica Shale (1)	—	—	*		—	149	*
Total	12,714	10,100	25.9	%	36,354	28,390	28.1	%
Average crude oil equivalent per day (Boe)
Wattenberg Field	103,554	83,674	23.8	%	102,758	79,564	29.2	%
Delaware Basin	34,641	26,109	32.7	%	30,407	23,883	27.3	%
Utica Shale (1)	—	—	*		—	546	*
Total	138,195	109,783	25.9	%	133,165	103,993	28.1	%



	Amounts may not recalculate due to rounding.
*	Percent change is not meaningful.
(1)	In March 2018, we completed the disposition of our Utica Shale properties.

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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, 2019

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

Three Months Ended September 30, 2018

	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	43%	36%	21%	100%
Delaware Basin	44%	34%	22%	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%

Nine Months Ended September 30, 2018

	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	42%	37%	21%	100%
Delaware Basin	45%	34%	21%	100%

Midstream Capacity

Our ability to market our production depends substantially on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. In recent years, there has been substantial development in our current areas of operation, and this has made it more challenging for providers of midstream infrastructure and services to keep pace with the corresponding increases in field-wide production. The ultimate timing and availability of adequate infrastructure is not within our control and we could experience capacity constraints for extended periods of time that could negatively impact our ability to meet our production targets. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure. Like other producers, we from time to time enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity. If our production falls below the level required under these agreements, we could be subject to transportation charges or aid in construction payments for commitment shortfalls.

Wattenberg Field. From time to time, elevated line pressures on gas gathering facilities have adversely affected production from the Wattenberg Field, including during the third quarter of 2019. While system expansions completed by our primary third-party midstream provider in the Wattenberg Field, DCP Midstream, LP (“DCP”), in late 2018 led to modest line pressure relief in early 2019, pressures remained at relatively elevated levels and have more recently increased to historical highs. DCP placed its O’Connor II plant into service in August 2019; however, through a combination of unplanned downtime on DCP’s system and limited takeaway capacity, our third quarter 2019 production was curtailed more than expected.

We expect increased production volumes in the Wattenberg Field in the fourth quarter of 2019 as a result of NGL takeaway expansion projects and increased firm residue gas space obtained by DCP. We expect this additional takeaway capacity to result in DCP being able to utilize the majority of its recently-commissioned O’Connor II plant.

We currently anticipate having the ability to move additional volumes on DCP’s system with the start-up of the Cheyenne Connector residue pipeline planned for early second quarter of 2020 and the commissioning of the Latham II plant, which is expected in mid-2020.

Our production in the Wattenberg Field is significantly dependent on DCP's gathering system, and this reliance will increase considerably upon closing of 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 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.

NGL fractionation on the Gulf Coast and Conway continues to operate at or near full capacity and this could potentially impact the operation of gas plants in the Wattenberg Field. Our Wattenberg Field operations are not currently being impacted by NGL fractionation capacity constraints; however, limitations on downstream fractionation capacity could limit the ability of our service providers to adjust ethane and propane recoveries to optimize the plant product mix to maximize revenue. Additional fractionation capacity has come online this year, with additional capacity expected to be available in late 2019 and throughout 2020.

Delaware Basin. Our production from the Delaware Basin was not materially affected by midstream or downstream capacity constraints during the first nine months of 2019. However, despite the completion and start-up of a new natural gas residue pipeline, takeaway capacity downstream of in-field gathering and processing facilities in the basin continues to operate close to capacity and near-term production constraints are possible. From time to time, we have experienced increased levels of natural gas flaring due to midstream capacity constraints in the Delaware Basin.

As discussed above, NGL fractionation on the Gulf Coast and at Conway is running at or near full capacity, and this could potentially impact the operation of gas plants in the Delaware Basin. Two new crude oil pipelines out of the Permian Basin were recently completed and are now operational. As a result, we believe the crude oil takeaway constraints that were experienced in 2018 and early 2019 have been alleviated for the time being.

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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 during the three and nine months ended September 30, 2019 compared to the three and nine months ended September 30, 2018. The NYMEX average daily crude oil prices decreased 19 percent and 15 percent for the three and nine months ended September 30, 2019, respectively, as compared to the same periods in 2018 and the NYMEX average first-of-the-month natural gas price decreased 23 percent and eight percent for the three and nine months ended September 30, 2019, respectively, as compared to the same periods in 2018.

The following tables present 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)	2019		2018		Percent Change		2019		2018		Percent Change
Crude oil (per Bbl)
Wattenberg Field	$	52.64	$	66.49	(20.8	)%	$	52.84	$	63.53	(16.8	)%
Delaware Basin	52.84		65.58		(19.4	)%	54.70		63.19		(13.4	)%
Utica Shale (1)	—		—		*		—		58.10		*
Weighted-average price	52.70		66.27		(20.5	)%	53.30		63.43		(16.0	)%
Natural gas (per Mcf)
Wattenberg Field	$	1.04	$	1.65	(37.0	)%	$	1.50	$	1.66	(9.6	)%
Delaware Basin	0.41		1.41		(70.9	)%	0.55		1.65		(66.7	)%
Utica Shale (1)	—		—		*		—		2.68		*
Weighted-average price	0.91		1.60		(43.1	)%	1.31		1.67		(21.6	)%
NGLs (per Bbl)
Wattenberg Field	$	7.76	$	22.38	(65.3	)%	$	11.06	$	20.76	(46.7	)%
Delaware Basin	10.22		30.42		(66.4	)%	14.53		29.29		(50.4	)%
Utica Shale (1)	—		—		*		—		24.29		*
Weighted-average price	8.43		24.35		(65.4	)%	11.92		22.71		(47.5	)%
Crude oil equivalent (per Boe)
Wattenberg Field	$	23.76	$	36.49	(34.9	)%	$	26.29	$	34.65	(24.1	)%
Delaware Basin	25.42		38.12		(33.3	)%	27.69		37.78		(26.7	)%
Utica Shale (1)	—		—		*		—		30.98		*
Weighted-average price	24.18		36.88		(34.4	)%	26.61		35.35		(24.7	)%



	Amounts may not recalculate due to rounding.
*	Percent change not meaningful.
(1)	In March 2018, we completed the disposition of our Utica Shale properties.

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

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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.

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.



For the 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	%

For the Three Months Ended September 30, 2018	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)	$	69.50	$	66.27	95	%	$	1.05	$	65.22	94	%
Natural gas (per MMBtu)	2.90		1.60		55	%	0.20		1.40		48	%
NGLs (per Bbl)	69.50		24.35		35	%	0.18		24.17		35	%
Crude oil equivalent (per Boe)	50.79		36.88		73	%	0.91		35.97		71	%

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For the 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	%

For the Nine Months Ended September 30, 2018	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)	$	66.75	$	63.43	95	%	$	0.89	$	62.54	94	%
Natural gas (per MMBtu)	2.90		1.67		58	%	0.22		1.45		50	%
NGLs (per Bbl)	66.75		22.71		34	%	0.20		22.51		34	%
Crude oil equivalent (per Boe)	48.78		35.35		72	%	0.90		34.45		71	%

Our average realization percentages for crude oil sales for the three and nine months ended September 30, 2019 are comparable to those for the corresponding periods of 2018. The realization percentages for our natural gas sales for the three and nine months ended September 30, 2019 have decreased materially as compared to the same periods in 2018, primarily due to widening of the basis between NYMEX and the indices upon which we sell our natural gas production. In the Delaware Basin, we experienced certain days during the three and nine months ended September 30, 2019 when the transportation, gathering and processing cost to deliver our natural gas to market exceeded the price we received. The realization percentages for our NGLs sales also decreased as compared to 2018, primarily due to reductions in prices for the individual NGLs components for the three and nine months ended September 30, 2019 as compared to the same periods in 2018.

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 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, 2019.

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 curves and changes in certain differentials.

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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,
	2019			2018			2019			2018
	(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil fixed price swaps, collars and rollfactors	$	(1.9	)	$	(53.6	)	$	(19.5	)	$	(117.6	)
Crude oil basis protection swaps	—			2.0			—			13.5
Natural gas fixed price swaps and collars	5.1			0.5			5.7			3.1
Natural gas basis protection swaps	(1.4		)	4.3			(6.0		)	15.6
NGLs fixed price swaps	—			(1.3		)	—			(5.1		)
Total net settlements of commodity derivative instruments	1.8			(48.1		)	(19.8		)	(90.5		)
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments	2.5			56.6			(61.5		)	47.9
Crude oil fixed price swaps, collars and rollfactors	49.8			(101.4		)	(8.0		)	(213.8		)
Natural gas fixed price swaps and collars	0.1			(0.8		)	3.2			(2.1		)
Natural gas basis protection swaps	0.6			0.2			(1.8		)	2.6
NGLs fixed price swaps	—			(0.9		)	—			(1.9		)
Net change in fair value of unsettled commodity derivative instruments	53.0			(46.3		)	(68.1		)	(167.3		)
Total commodity price risk management gain (loss), net	$	54.8		$	(94.4	)	$	(87.9	)	$	(257.8	)

Lease Operating Expenses

Lease operating expenses increased 10 percent to $36.5 million in the three months ended September 30, 2019 compared to $33.0 million in the three months ended September 30, 2018. Significant changes in lease operating expenses included increases of $4.2 million for produced water disposal, $1.4 million in additional compressor and equipment rentals, $0.9 million for oil inventory expense and $0.7 million for non-operated wells. The increases were partially offset by a $2.0 million decrease in workover expense, a $1.5 million decrease related to midstream expense resulting from the sale of Delaware Basin midstream assets during the second quarter of 2019 and a $1.1 million decrease in environmental expenses. Lease operating expense per Boe decreased by 12 percent to $2.87 for the three months ended September 30, 2019 from $3.27 for the three months ended September 30, 2018, primarily due to a 26 percent increase in production volumes.

Lease operating expenses increased 12 percent to $106.0 million in the nine months ended September 30, 2019 compared to $94.9 million in the nine months ended September 30, 2018. Significant changes in lease operating expenses included increases of $7.3 million for produced water disposal, $4.5 million in additional compressor and equipment rentals, $1.8 million for non-operated wells, $1.6 million for payroll and employee benefits and $1.0 million in chemical expenses. The increases were partially offset by a $5.1 million decrease in workover expense, a $2.2 million decrease related to midstream expense resulting from the sale of Delaware Basin midstream assets during the second quarter of 2019 and a $0.7 million decrease to flared gas royalties. Lease operating expense per Boe decreased by 13 percent to $2.92 for the nine months ended September 30, 2019 from $3.34 for the nine months ended September 30, 2018, primarily due to a 28 percent increase in production volumes.

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.

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Production taxes decreased 46 percent to $13.0 million in the three months ended September 30, 2019 compared to $24.0 million in the three months ended September 30, 2018, primarily due to an 18 percent decrease in crude oil, natural gas and NGLs sales, reductions in effective severance tax rates and refunds of severance tax during the three months ended September 30, 2019. Production taxes per Boe decreased by 57 percent to $1.03 for the three months ended September 30, 2019 compared to $2.37 for the three months ended September 30, 2018.

Production taxes decreased 13 percent to $57.8 million in the nine months ended September 30, 2019 compared to $66.8 million in the nine months ended September 30, 2018, primarily due to the four percent decrease in crude oil, natural gas and NGLs sales, reductions in effective severance tax rates and refunds of severance tax during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. Production taxes per Boe decreased by 32 percent to $1.59 for the nine months ended September 30, 2019 compared to $2.35 for the nine months ended September 30, 2018.

Transportation, Gathering and Processing Expenses

Transportation, gathering and processing expenses increased 19 percent to $11.0 million in the three months ended September 30, 2019 compared to $9.2 million in the three months ended September 30, 2018 and 36 percent to $34.6 million in the nine months ended September 30, 2019 compared to $25.5 million in the nine months ended September 30, 2018. Transportation, gathering and processing expenses are primarily impacted by variances in the volumes delivered through pipelines and for natural gas gathering and transportation operations. As discussed in Crude Oil, Natural Gas and NGLs Pricing, whether transportation, gathering and processing costs are presented separately or are reflected as a reduction to net revenue is a function of the terms of the relevant marketing contract. Transportation, gathering and processing expenses per Boe decreased by four percent to $0.87 for the three months ended September 30, 2019 compared to $0.91 for the three months ended September 30, 2018 and increased by six percent to $0.95 for the nine months ended September 30, 2019 compared to $0.90 for the nine months ended September 30, 2018.

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,
	2019		2018		2019		2018
	(in millions)

Impairment of proved and unproved properties	$	0.1	$	1.5	$	10.3	$	194.1
Amortization of individually insignificant unproved properties	—		—		—		0.1
Impairment of infrastructure and other	—		—		26.7		—
Impairment of properties and equipment	$	0.1	$	1.5	$	37.0	$	194.2

During the nine months ended September 30, 2019 and 2018, we recorded impairment charges totaling $10.3 million and $194.2 million, respectively, including $0.1 million and $1.5 million during the three months ended September 30, 2019 and 2018, respectively, related to the divestiture of leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin that we determined not to develop. 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. Upon closing of the Midstream Asset Divestitures, it was determined that the net book value of these assets was not recoverable.

General and Administrative Expense

General and administrative expense decreased 15 percent to $41.1 million in the three months ended September 30, 2019 compared to $48.2 million in the three months ended September 30, 2018. The decrease was primarily attributable to an $8.0 million decrease in legal-related fees, a $5.2 million decrease in government relations costs and a $1.5 million decrease in fines and penalties. The decreases were partially offset by a $5.0 million increase in costs related to the SRC Acquisition and a $2.1 million increase in the allowance adjustment for royalty owner payments.

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General and administrative expense increased two percent to $123.5 million in the nine months ended September 30, 2019 compared to $121.2 million in the nine months ended September 30, 2018. The increase was primarily attributable to a $5.6 million increase related to shareholder activism, $5.0 million increase in costs related to the SRC Acquisition, a $4.4 million increase in payroll and related benefits, a $3.0 million increase in professional service fees and a $2.1 million increase in the allowance adjustment for royalty owner payments. The increases were partially offset by a decrease in government relations costs of $6.7 million and a decrease of $10.9 million in legal-related fees.

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 $170.5 million and $487.5 million for the three and nine months ended September 30, 2019, respectively, compared to $145.4 million and $403.8 million for the three and nine months ended September 30, 2018, 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, 2019			Nine Months Ended September 30, 2019
	(in millions)
Increase in production	$	38.9		$	115.5
Decrease in weighted-average depreciation, depletion and amortization rates	(13.9		)	(31.8		)
Total increase in DD&A expense related to crude oil and natural gas properties	$	25.0		$	83.7

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	2019		2018		2019		2018
	(per Boe)
Wattenberg Field	$	12.42	$	12.51	$	12.32	$	12.98
Delaware Basin	16.34		20.43		17.07		18.70
Total weighted-average	$	13.41	$	14.40	$	13.41	$	14.22

Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $1.4 million and $4.3 million for the three and nine months ended September 30, 2019, respectively, compared to $2.1 million and $6.2 million for the three and nine months ended September 30, 2018, 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

Interest expense increased $0.3 million to $17.9 million for the three months ended September 30, 2019 compared to $17.6 million for the three months ended September 30, 2018. The increase was primarily related to a $1.1 million increase in interest related to our revolving credit facility, partially offset by a $1.0 million increase in capitalized interest.

Interest expense increased $1.1 million to $53.7 million for the nine months ended September 30, 2019 compared to $52.6 million for the nine months ended September 30, 2018. The increase was primarily related to a $4.2 million increase in interest related to our revolving credit facility, partially offset by a $3.3 million increase in capitalized interest.

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Provision for Income Taxes

The effective income tax rate for the three months ended September 30, 2019 was a 40.1 percent expense on income and the effective income tax rate for the nine months ended September 30, 2019 was a 10.4 percent benefit on loss, compared to a 53.0 percent and 23.3 percent benefit on loss for the three and nine months ended September 30, 2018, respectively. The effective income tax rates are based upon a full year forecasted pre-tax income for the year adjusted for permanent differences. The authoritative guidance for accounting for income taxes allows use of the year-to-date effective tax rate (the “discrete method”) when a reliable estimate of the estimated annual effective tax rate cannot be made. During the interim period ended September 30, 2019, we determined that the use of the discrete method is more appropriate than the annual effective tax rate method due to sensitivity to small changes to projected pre-tax earnings for the year, which resulted in significant variations in the customary relationship between income tax expense and pretax income.

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

The factors impacting net income for the three months ended September 30, 2019 of $15.9 million, a net loss of $35.7 million for the nine months ended September 30, 2019 and net losses for the three and nine months ended September 30, 2018 of $3.4 million and $176.8 million, respectively, are discussed above. Adjusted net loss, a non-U.S. GAAP financial measure, was $24.5 million for the three months ended September 30, 2019 and adjusted net income was $16.1 million for the nine months ended September 30, 2019. Adjusted net income was $31.8 million for the three months ended September 30, 2018 and adjusted net loss was $49.6 million for the nine months ended September 30, 2018. With the exception of the tax-affected 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, our revolving credit facility, asset sales and proceeds raised in debt and equity capital market transactions. For the nine months ended September 30, 2019, our net cash flows from operating activities were $675.7 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. Due to a decreasing leverage ratio that we have experienced over the past year, the percentage of our expected future production that we currently have hedged is lower than we have historically maintained and we anticipate that this may remain the case in the near term.

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

From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as of September 30, 2019 is an indication of a lack of liquidity. We had working capital deficits of $66.4 million and $166.6 million at September 30, 2019 and December 31, 2018, respectively. 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 $4.6 million at September 30, 2019 and availability under our revolving credit facility was $1.2 billion, providing for a total liquidity position of $1.2 billion as of September 30, 2019. In October 2019, as part of our semi-annual redetermination, the borrowing base on our revolving credit facility was reaffirmed at $1.6 billion and we elected to retain our commitment amount at $1.3 billion. Based on our current production forecast for 2019 and assuming a NYMEX crude oil price of $55.00 per barrel, we expect cash flows from operations to approximate our capital investments in crude oil and natural gas properties for the year. Although capital investments in crude oil and natural gas

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properties exceeded cash flows from operations during the nine months ended September 30, 2019, we expect cash flows from operations to exceed capital investments in crude oil and natural gas properties during the fourth quarter of 2019 and are taking active steps to ensure that our capital investments in crude oil and natural gas properties remain within our guidance range.

In the second quarter of 2019, we completed the Midstream Asset Divestitures for an aggregate cash purchase price of $345.6 million ($263.6 million of which was paid upon closing with the remaining $82.0 million to be paid in June 2020), subject to certain customary post-closing adjustments, plus aggregate conditional payments of up to $150.7 million. We allocated $179.6 million of the proceeds to deferred midstream gathering credits for future gathering, processing, transportation and water disposal services. We have and expect to continue to use the proceeds from these divestitures for our capital investment program.

On August 25, 2019, we and SRC entered into the Merger Agreement for the SRC Acquisition. We expect the SRC Acquisition to be completed early in the first quarter of 2020, subject to the satisfaction of PDC and SRC shareholder approvals and certain other customary closing conditions.

Upon closing the SRC Acquisition, we will assume the SRC Senior Notes and be required to pay off and terminate SRC's revolving credit facility. If the SRC Acquisition results in a "Change of Control" under the indenture governing the SRC Senior Notes, we will be required to make an offer to purchase those notes. Accordingly, subject to closing the SRC Acquisition, the borrowing base on our revolving credit facility will increase and, in October 2019, we elected to increase the aggregate commitment amount under our revolving credit. See the footnote titled Pending Acquisition to our accompanying condensed consolidated financial statements included elsewhere in this report for more information regarding the impact of the SRC Acquisition on our revolving credit facility.

In April 2019, the Board approved the acquisition of up to $200 million of our outstanding common stock, depending on market conditions. Pursuant to the Stock Repurchase Program, we repurchased 4.4 million shares of outstanding common stock at a cost of $145.5 million from June 2019 through September 2019 and we repurchased 0.3 million shares of outstanding common stock at a cost of $8.9 million during October 2019. Approximately $45.7 million remains available for repurchases under the Stock Repurchase Program as of October 31, 2019. Additionally, in August 2019, contingent on the closing of the SRC Acquisition, the Board approved an increase and extension to the Stock Repurchase Program. The program now contemplates up to $525 million in repurchases with a target completion date of December 31, 2021. See the footnote titled Pending Acquisition to our accompanying condensed consolidated financial statements included elsewhere in this report for more information regarding our Stock Repurchase Plan.

We currently project that we will generate a sufficient level of cash flow through December 2021 to fund the Stock Repurchase Program, while maintaining the ability to pursue additional future return of capital programs, depending on market conditions. 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.

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

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. In August 2019, we entered into a First Amendment to the Restated Credit Agreement. The First Amendment primarily modifies certain sections of the Restated Credit Agreement to permit the consummation of the SRC Acquisition and provides for certain borrowings in connection with the SRC Acquisition.

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. At September 30, 2019, we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.6:1.0 and a leverage ratio of 1.5:1.0. We expect to remain in compliance throughout the 12-month period following the filing of this report.

The indentures governing our 2024 Senior Notes and 2026 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

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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.

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 increased by $97.9 million to $675.7 million for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, due to an increase in changes in assets and liabilities of $71.4 million, primarily attributable to $95.5 million due to deferred midstream gathering credits related to our Midstream Asset Divestitures, as well as an increase in commodity derivative settlements of $70.7 million and a decrease in production taxes of $8.9 million. These changes were partially offset by a decrease in crude oil, natural gas and NGLs sales of $36.1 million and increases in lease operating expenses of $11.1 million, transportation, gathering and processing expense of $9.1 million and general and administrative expenses of $2.3 million.

Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $26.6 million to $601.9 million during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. 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. During the nine months ended September 30, 2019, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $646.4 million compared to $621.1 million for the comparable period in 2018. The four percent increase in our adjusted EBITDAX for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 was primarily due to the decrease in the loss on commodity derivative settlements of $70.7 million, which was partially offset by a decrease in crude oil, natural gas and NGLs sales of $36.1 million and an increase in operating costs of $13.6 million. 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 $597.0 million during the nine months ended September 30, 2019 was primarily related to our drilling and completion activities of $780.6 million. Net cash received from the Midstream Asset Divestitures and certain Delaware Basin crude oil and natural gas properties was $199.4 million. Net cash used in investing activities of $823.7 million during the nine months ended September 30, 2018 was primarily related to cash utilized toward property acquisitions of $181.6 million and our drilling and completion activities of $685.5 million. Partially offsetting these investments was the receipt of approximately $43.5 million, primarily related to the sale of our Utica Shale assets in March 2018.

Financing 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 pursuant to the Stock Repurchase Program, partially offset by net borrowings from our credit facility of $64.5 million.

Off-Balance Sheet Arrangements

At September 30, 2019, 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.

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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 2018 Form 10-K filed with the SEC on February 28, 2019.

Reconciliation of Non-U.S. GAAP Financial Measures

We use "adjusted cash flows from operations," "free cash flow," "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 free cash flow. 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 free cash flow provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities and to return capital to stockholders.

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, 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,
	2019			2018			2019			2018
	(in millions)
Adjusted cash flows from operations and free cash flow (deficit):
Net cash from operating activities	$	233.5		$	197.0		$	675.7		$	577.8
Changes in assets and liabilities	(31.1		)	4.1			(73.8		)	(2.5		)
Adjusted cash flows from operations	202.4			201.1			601.9			575.3
Capital expenditures for development of crude oil and natural gas properties	(237.8		)	(252.9		)	(780.6		)	(685.5		)
Change in accounts payable related to capital expenditures	74.2			(19.1		)	57.7			(91.4		)
Free cash flow (deficit)	$	38.8		$	(70.9	)	$	(121.0	)	$	(201.6	)

Adjusted net income (loss):
Net income (loss)	$	15.9		$	(3.4	)	$	(35.7	)	$	(176.8	)
(Gain) loss on commodity derivative instruments	(54.9		)	94.4			87.9			257.8
Net settlements on commodity derivative instruments	1.8			(48.1		)	(19.8		)	(90.5		)
Tax effect of above adjustments	12.7			(11.1		)	(16.3		)	(40.1		)
Adjusted net income (loss)	$	(24.5	)	$	31.8		$	16.1		$	(49.6	)

Net income (loss) to adjusted EBITDAX:
Net income (loss)	$	15.9		$	(3.4	)	$	(35.7	)	$	(176.8	)
(Gain) loss on commodity derivative instruments	(54.9		)	94.4			87.9			257.8
Net settlements on commodity derivative instruments	1.8			(48.1		)	(19.8		)	(90.5		)
Non-cash stock-based compensation	5.9			5.6			18.1			16.4
Interest expense, net	17.8			17.4			53.7			52.2
Income tax expense (benefit)	10.7			(3.9		)	(4.2		)	(53.8		)
Impairment of properties and equipment	0.2			1.5			37.0			194.2
Exploration, geologic and geophysical expense	0.2			1.0			3.5			4.6
Depreciation, depletion and amortization	171.8			147.5			491.8			410.0
Accretion of asset retirement obligations	1.4			1.2			4.5			3.8
Loss on sale of properties and equipment	43.9			2.1			9.6			3.2
Adjusted EBITDAX	$	214.7		$	215.3		$	646.4		$	621.1

Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities	$	233.5		$	197.0		$	675.7		$	577.8
Interest expense, net	17.8			17.4			53.7			52.2
Amortization of debt discount and issuance costs	(3.4		)	(3.1		)	(10.1		)	(9.5		)
Exploration, geologic and geophysical expense	0.2			1.0			3.5			4.6
Other	(2.3		)	(1.1		)	(2.6		)	(1.5		)
Changes in assets and liabilities	(31.1		)	4.1			(73.8		)	(2.5		)
Adjusted EBITDAX	$	214.7		$	215.3		$	646.4		$	621.1

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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 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, 2019, we had a $97.0 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, 2019 would have changed by approximately $0.2 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, 2019, 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 our derivative positions of $47.1 million, whereas a ten percent decrease in prices would have resulted in an increase in fair value of $49.5 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, 2019, 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, 2019, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the 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 the Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of September 30, 2019 because of the material weaknesses in our internal control over financial reporting described below.

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 CEO and CFO, 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, 2019, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO").

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

We did not maintain a sufficient complement of personnel within the Land Department as a result of increased volume of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of land administrative records associated with unproved leases, which are used in verifying the completeness, accuracy, valuation, rights and obligations over the accounting of properties and equipment, sales and accounts receivable and costs and expenses. These control deficiencies resulted in immaterial adjustments to our unproved properties, impairment of unproved properties, sales, accounts receivable and depletion expense accounts and related disclosures in our consolidated financial statements for the years ended December 31, 2018 and 2017 and the nine months ended September 30, 2019.

Additionally, these control deficiencies could result in misstatements of substantially all accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, our management has determined that these control deficiencies constitute material weaknesses.

Remediation Plan for Material Weaknesses

We are committed to continuing to review, optimize and enhance our internal control over financial reporting. In response to the identified material weaknesses, our management, with the oversight of the Audit Committee of our Board of Directors, has assessed a number of different remediation initiatives to improve our internal control over financial reporting. Building on our efforts during 2017, we continued throughout 2018 and the beginning of 2019 to dedicate significant resources and efforts to improve our internal control over financial reporting and to take steps to remediate the material weaknesses identified above. While certain remediation plans have been implemented, we continue to actively plan for and implement additional remediation measures.

During 2018 and 2019, we have taken steps to strengthen the control activities within the Land Department, which include new leadership, hiring additional personnel with relevant experience, increased layers of supervision, staff training and development and division of responsibilities within the Land Department. We have also designed and implemented control activities to verify the completeness and accuracy of land administrative records associated with unproved leases, including the

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verification of the reliability of underlying data used in the execution of the control activities. As we continue to evaluate and work to improve our internal control over financial reporting, we may take additional measures to address these control deficiencies, or we may modify certain of the remediation measures described above to improve the operating effectiveness of those measures. These material weaknesses will not be considered remediated until the applicable remediated controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.

ITEM 1A. 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 2018 Form 10-K and our Quarterly Report on Form 10-Q for the quarterly period ending March 31, 2019 (the "2019 Q1 Form 10-Q"). 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 2018 Form 10-K and 2019 Q1 Form 10-Q, except for the following:

The transactions contemplated by the Merger Agreement are subject to conditions that may not be satisfied on a timely basis or at all. Failure to complete the transactions contemplated by the Merger Agreement could have material and adverse effects on us.

Completion of the SRC Acquisition is subject to a number of conditions, including, among other things, (i) the adoption and approval by our shareholders of the Merger Agreement and the Merger of PDC and SRC and the issuance of PDC’s common stock in the SRC Acquisition, (ii) the adoption and approval of the Merger Agreement and the Merger of PDC and SRC by SRC’s shareholders, (iii) the absence of any law or order prohibiting the consummation of the SRC Acquisition, (iv) the effectiveness of the registration statement on Form S-4 pursuant to which the shares of our common stock issuable in the SRC Acquisition are registered with the SEC, (v) the authorization for listing of the shares of our common stock issuable in the SRC Acquisition on the NASDAQ exchange, and (vi) delivery of opinions of counsel to us and to SRC to the effect that the SRC Acquisition will qualify as a reorganization within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended. Such conditions, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the completion of the SRC Acquisition uncertain. In addition, the Merger Agreement contains certain termination rights for both SRC and us, which if exercised will also result in the SRC Acquisition not being consummated. Furthermore, the governmental authorities from which the federal regulatory approvals are required may impose conditions on the completion of the SRC Acquisition or require changes to the terms of the SRC Acquisition or Merger Agreement.

If the transactions contemplated by the Merger Agreement are not completed, our business may be adversely affected and, without realizing any of the benefits of having completed the SRC Acquisition, we will be subject to a number of risks, including the following: we will be required to pay our costs relating to the SRC Acquisition, such as legal, accounting, and financial advisory fees; time and resources committed by our management to matters relating to the SRC Acquisition could otherwise have been devoted to pursuing other beneficial opportunities; and the market price of our common stock could be impacted to the extent that the current market price reflects a market assumption that the SRC Acquisition will be completed. In addition, if the Merger Agreement is terminated and the Board seeks another acquisition, we cannot be certain that we will be able to find a party willing to enter into a transaction as attractive to us as the SRC Acquisition.

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We will be subject to business uncertainties while the SRC Acquisition is pending, which could adversely affect our business.

It is possible that certain persons with whom we have a business relationship may delay certain business decisions relating to us, or seek to terminate, change or renegotiate their relationships with us, in connection with the pendency of the SRC Acquisition. This could negatively affect our revenues, earnings and cash flows, as well as the market price of our common stock, regardless of whether the SRC Acquisition is completed. Also, our ability to attract, retain and motivate employees may be impaired until the SRC Acquisition is completed and for a period of time thereafter as current and prospective employees may experience uncertainty about their roles within the combined company following the transaction.

In addition, under the terms of the Merger Agreement, we are subject to certain restrictions on the conduct of our business prior to the completion of the SRC Acquisition, which may adversely affect our ability to execute certain of our business strategies. Such limitations could negatively affect our business and operations prior to the completion of the SRC Acquisition.

Our shareholders will have a reduced ownership in the combined company after the SRC Acquisition and may exercise less influence over the policies of the combined company.

Based on the number of issued and outstanding shares of SRC common stock as of September 30, 2019 and the number of outstanding SRC equity awards currently estimated to be payable in shares of our common stock in connection with the SRC Acquisition, we anticipate issuing up to approximately 40 million shares of our common stock pursuant to the Merger Agreement. The actual number of shares of our common stock to be issued pursuant to the Merger Agreement will be determined at the completion of the SRC Acquisition based on the number of shares of SRC common stock outstanding at such time. The issuance of these new shares could have the effect of depressing the market price of our common stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, our earnings per share could have a depressive effect on the price of our common stock.

The SRC Acquisition will also dilute the current ownership position and voting interest of our shareholders. Immediately after the completion of the SRC Acquisition, it is expected that current PDC shareholders will own approximately 61 percent, and SRC shareholders will own approximately 39 percent, of the combined company’s outstanding common stock. As a result, our current shareholders may have less influence on the policies of the combined company than they currently have.

The market price of shares of our common stock may decline in the future as a result of the sale of shares of our common stock held by former SRC shareholders or our current shareholders.

Following their receipt of shares of our common stock as consideration in the SRC Acquisition, former SRC shareholders may seek to sell the shares of our common stock delivered to them, and the Merger Agreement contains no restriction on the ability of former SRC shareholders to sell such shares of our common stock following completion of the transaction. Other shareholders may also seek to sell shares of our common stock held by them following, or in anticipation of, the completion of the SRC Acquisition. These sales (or the perception that these sales may occur), coupled with the increase in the number of outstanding shares of our common stock, may adversely affect the market for, and the market price of, our common stock.

The Merger Agreement limits our ability to pursue alternatives to the SRC Acquisition.

The Merger Agreement contains certain provisions that restrict our ability to solicit, initiate or knowingly encourage or facilitate, among other things, any inquiries, proposals, offers or requests for information regarding, or the making of a competing proposal, engage in any discussions or negotiations with respect to a competing proposal or furnish any non-public information to any person in connection with a competing proposal. In addition, if the Merger Agreement is terminated under certain specified circumstances we would be required to pay SRC a termination fee of $55.0 million, including if SRC terminates because the Board changes its recommendation with respect to the SRC Acquisition or if we terminate in connection with a superior proposal. Among other things, these provisions may prevent us from entering into an alternative transaction that would be more attractive to us than the SRC Acquisition.

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Even if the SRC Acquisition is completed, we may not achieve the anticipated benefits and the SRC Acquisition may disrupt our current plans or operations.

The success of the SRC Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and SRC’s businesses, and there can be no assurance that we will be able to successfully integrate SRC or otherwise realize the anticipated benefits of the SRC Acquisition. Difficulties in integrating SRC into our company may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:


•	the inability to successfully integrate SRC into our company in a manner that permits us to achieve the full cost savings anticipated from the SRC Acquisition;


•	complexities associated with managing a larger, more complex, integrated business;


•	not realizing anticipated operating synergies;


•	integrating personnel from the two companies and the loss of key employees;


•	potential unknown liabilities and unforeseen expenses, delays or federal regulatory conditions associated with the SRC Acquisition and following completion of the SRC Acquisition;


•	integrating relationships with customers, vendors and business partners;


•	performance shortfalls as a result of the diversion of management’s attention caused by the SRC Acquisition and the integration of SRC’s operations into our company; and


•	the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies.

We are expected to incur significant transaction costs in connection with the SRC Acquisition, which may be in excess of those we currently anticipate.

We have incurred and are expected to continue to incur a number of non-recurring costs associated with negotiating and completing the SRC Acquisition, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial and, in many cases, will be borne by us whether or not the SRC Acquisition is completed. A substantial majority of our non-recurring expenses will consist of transaction costs related to the SRC Acquisition and include, among others, fees paid to financial, legal, accounting and other advisors, and filing and special meeting fees. We will also incur transaction costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and other employment-related costs. We will continue to assess the magnitude of these costs, and we may incur additional unanticipated costs. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not offset integration-related costs and achieve a net benefit in the near term or at all. The costs described above and any unanticipated costs and expenses, many of which will be borne by us even if the SRC Acquisition is not completed, could have an adverse effect on our financial condition and operating results.

Investigations regarding the merger could result in one or more lawsuits against the SRC board, SRC and/or PDC, and other lawsuits may be filed against SRC, PDC and/or their respective boards challenging the merger. An adverse ruling in any such lawsuit may prevent the merger from being completed.

Following the public announcement of the merger, investigations were launched by several law firms generally regarding whether the SRC board failed to satisfy its duties to its shareholders, including whether the board adequately pursued alternatives to the acquisition and whether the board obtained the best price possible for SRC shares of common stock. In addition to the pending state law complaints and federal law complaints discussed below, there is a possibility that one or more of these investigations could result in further lawsuits against the SRC board and/or SRC, seeking, among other things, injunctive relief or other equitable relief, including a request to rescind parts of the merger agreement already implemented, in addition to other fees and costs.

Lawsuits have been filed against SRC, the directors of SRC and PDC regarding the merger, which could result in substantial costs and may delay or prevent the merger from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements.

On October 4, 2019 and October 11, 2019, purported shareholders of SRC filed putative class action lawsuits against the members of the SRC board, SRC, and PDC in Colorado District Courts in Arapahoe County and Denver County, captioned Robert Garfield v. Lynn A. Peterson, et al., Case No. 2019CV32360 and George Korol v. SRC Energy Inc., et al.,

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Case No. 2019CV33933. The plaintiffs in the state law complaints generally claim that (i) SRC and the members of the SRC board breached their fiduciary duties to SRC shareholders by authorizing the merger with PDC for what the plaintiffs assert is inadequate consideration and pursuant to an unfair process and with inadequate disclosures and (ii) PDC aided and abetted the other defendants’ alleged breach of duties.

On October 8, 2019 and October 11, 2019, purported shareholders of SRC filed putative class action lawsuits against SRC, the members of the SRC board, and PDC in the United States District Court, District of Delaware, captioned Patrick Plumley v. SRC Energy Inc., et al., Case No. 1:19-cv-01912, and Juan Aguirre v. SRC Energy Inc., et al., Case No. 1:19-cv-01934. The plaintiffs in the federal law complaints generally claim that the defendants disseminated a false or misleading registration statement regarding the proposed merger in violation of Section 14(a) and Section 20(a) of the Exchange Act and/or Rule 14a-9 promulgated under the Exchange Act.

Even if the lawsuits are without merit, as the defendants believe these lawsuits to be, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on PDC's and SRC's respective liquidity and financial condition. The plaintiffs in the state law complaints seek, among other things, to rescind the transaction or obtain rescissory damages if the merger is consummated, to recover other unspecified damages, including recover attorneys’ fees and costs, and to obtain injunctive relief. The plaintiffs in the federal law complaints seek, among other things, injunctive relief to prevent consummation of the merger until the alleged disclosure violations are cured, damages in the event the merger is consummated, and an award of attorney’s fees. Any other lawsuit that may be filed in the future could also seek, among other things, injunctive relief or other equitable relief, including a request to rescind parts of the merger agreement already implemented and to otherwise enjoin the parties from consummating the merger. If a plaintiff is successful in obtaining an injunction prohibiting completion of the merger in the state law complaints, federal law complaints, or any other similar lawsuits, then that injunction may delay or prevent the merger from being completed, which may adversely affect PDC's and SRC's respective business, financial position and results of operation.

One of the conditions to the closing of the merger is that no injunction by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case that prohibits or makes illegal the closing of the merger. Consequently, if a lawsuit is filed and a plaintiff is successful in obtaining an injunction prohibiting completion of the merger, then that injunction may delay or prevent the merger from being completed within the expected timeframe or at all, which may adversely affect PDC's and SRC's respective business, financial position and results of operations.

After the SRC Acquisition is completed, PDC will be proportionally more exposed to regulatory risks associated with oil and gas operations in Colorado and other risks associated with a more geographically-concentrated asset base.

PDC's principal assets in terms of production and reserves are located in the Wattenberg Field located within the Denver-Julesburg Basin of Colorado, but we also have a significant acreage position in the Delaware Basin in Texas. During the nine months ended September 30, 2019, 75 percent of PDC's production came from its assets in Colorado and 25 percent came from its assets in Texas. Substantially all of SRC's properties, and all of its current production and reserves, are located in Colorado. Various new regulatory requirements applicable to oil and natural gas operations in Colorado have been proposed or adopted in recent years. In particular, Proposition 112, a voter initiative that qualified for the ballot for the general election in November 2018, would have effectively prohibited the vast majority of both PDC's and SRC's planned drilling activity in Colorado by imposing mandatory 2,500 foot setbacks between new oil and gas wells and any occupied structure or designated "vulnerable area." Although Proposition 112 was defeated at the polls, subsequent legislation significantly amended existing state law to, among other things, require the COGCC to prioritize public health and environmental concerns in its decisions, instruct the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and authorize local governmental authorities to impose limitations on oil and gas development activities more stringent than those imposed at the state level. In particular, in October 2019, the CDPHE released a study of potential health risks that modeled certain exposure scenarios at distances up to 2,000 feet, based on data collected at oil and gas development and production sites. The study concluded that modeling results “support increased concern for short-term adverse effects” in a very narrow set of hypothetical circumstances associated with the development phase of oil and gas operations. As a result, the COGCC has determined that it will utilize the objective criteria developed following SB-181 in reviewing proposed permits for locations up to 2,000 feet from building units. We may experience significant delays in the issuance of permits and necessary approvals as a result. If the merger is completed, the percentage of PDC's combined properties, production and reserves located in Colorado will increase and our exposure to the risk of unfavorable regulatory developments in the state will therefore increase as well.

Similarly, the operations of both PDC and SRC have been adversely affected in recent years by limitations in the availability of adequate midstream infrastructure in the Wattenberg Field. In particular, PDC has experienced high line

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pressures as a result of the capacity of the DCP system being unable, at times, to handle the total production from the various producers in the Wattenberg Field. The increased percentage of PDC's combined production located in the Wattenberg Field following the merger will proportionately increase PDC's exposure to this adequate midstream infrastructure risk, as well as other risks associated with operating in a more concentrated geographic area.

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) (3) (4)

July 1 - 31, 2019	574,483	$	34.84	569,733	$	75.0
August 1 - 31, 2019	—	—		—	75.0
September 1 - 30, 2019	658,577	30.99		658,577	54.6
Total third quarter 2019 purchases	1,233,060	$	32.78	1,228,310	$	54.6

__________

(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, 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.


(3)	In October 2019, we repurchased $8.9 million of our outstanding common stock as part of the Stock Repurchase Program. At October 31, 2019, $45.7 million of shares remained available for repurchase that may yet be purchased under the Stock Repurchase Program.


(4)	Applicable regulations will prohibit us from repurchasing shares during the period between the distribution of the proxy statement/prospectus relating to the SRC Acquisition and the closing of the acquisition.

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

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 6, 2019	/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)