Edgar Filing: PDC ENERGY, INC.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 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

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 o
Non-accelerated filer o	Smaller reporting company o
	Emerging growth company o

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 o No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 66,282,650 shares of the Company's Common Stock ($0.01 par value) were outstanding as of April 22, 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 Statement of Equity (unaudited)	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	50

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52
Item 3.	Defaults Upon Senior Securities	52
Item 4.	Mine Safety Disclosures	52
Item 5.	Other Information	52
Item 6.	Exhibits	53

	SIGNATURES	54

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed, and that cash flows from operations will exceed expected capital investments in crude oil and natural gas properties for 2019 and 2020; anticipated stock repurchase program, which may be modified or discontinued at any time, and expected timing and amount of such program; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; anticipated sale of our Delaware Basin midstream assets and the timing of those sales and whether closing will occur timely or at all; 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; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; 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;


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


•	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;


•	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 or acreage exchanges;


•	increases or changes in costs and expenses;


•	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;


•	increases or changes in costs and expenses;

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•	future cash flows, liquidity and financial condition;


•	possibility that one or more sales of our Delaware Basin midstream assets will not close when expected or at all;


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


•	cost of pending or future litigation;


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


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


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

Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in this Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 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)



	March 31, 2019			December 31, 2018
Assets
Current assets:
Cash and cash equivalents	$	1,112		$	1,398
Accounts receivable, net	190,844			181,434
Fair value of derivatives	13,330			84,492
Prepaid expenses and other current assets	7,870			7,136
Total current assets	213,156			274,460
Properties and equipment, net	4,121,649			4,002,862
Assets held-for-sale, net	152,847			140,705
Fair value of derivatives	24,225			93,722
Other assets	52,051			32,396
Total Assets	$	4,563,928		$	4,544,145

Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	215,555		$	181,864
Production tax liability	55,430			60,719
Fair value of derivatives	43,899			3,364
Funds held for distribution	91,615			105,784
Accrued interest payable	15,194			14,150
Other accrued expenses	68,836			75,133
Total current liabilities	490,529			441,014
Long-term debt	1,289,046			1,194,876
Deferred income taxes	160,609			198,096
Asset retirement obligations	82,497			85,312
Liabilities held-for-sale	4,614			4,111
Fair value of derivatives	1,815			1,364
Other liabilities	125,063			92,664
Total liabilities	2,154,173			2,017,437

Commitments and contingent liabilities

Stockholders' equity
Common shares - par value $0.01 per share, 150,000,000 authorized, 66,196,863 and 66,148,609 issued as of March 31, 2019 and December 31, 2018, respectively	662			661
Additional paid-in capital	2,521,558			2,519,423
Retained earnings (deficit)	(111,449		)	8,727
Treasury shares - at cost, 22,635 and 45,220 as of March 31, 2019 and December 31, 2018, respectively	(1,016		)	(2,103		)
Total stockholders' equity	2,409,755			2,526,708
Total Liabilities and Stockholders' Equity	$	4,563,928		$	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 March 31,
	2019			2018
Revenues
Crude oil, natural gas and NGLs sales	$	321,099		$	305,225
Commodity price risk management loss, net	(190,074		)	(47,240		)
Other income	3,475			2,615
Total revenues	134,500			260,600
Costs, expenses and other
Lease operating expenses	35,221			29,636
Production taxes	22,168			20,169
Transportation, gathering and processing expenses	11,424			7,313
Exploration, geologic and geophysical expense	2,643			2,646
Impairment of properties and equipment	7,875			33,188
General and administrative expense	39,598			35,696
Depreciation, depletion and amortization	151,422			126,788
Accretion of asset retirement obligations	1,584			1,288
(Gain) loss on sale of properties and equipment	(369		)	1,432
Other expenses	3,554			2,768
Total costs, expenses and other	275,120			260,924
Loss from operations	(140,620		)	(324		)
Interest expense	(16,978		)	(17,529		)
Interest income	10			148
Loss before income taxes	(157,588		)	(17,705		)
Income tax benefit	37,412			4,566
Net loss	$	(120,176	)	$	(13,139	)

Earnings per share:
Basic	$	(1.82	)	$	(0.20	)
Diluted	$	(1.82	)	$	(0.20	)

Weighted-average common shares outstanding:
Basic	66,182			65,957
Diluted	66,182			65,957

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(unaudited; in thousands)



	Three Months Ended March 31,
	2019			2018
Cash flows from operating activities:
Net loss	$	(120,176	)	$	(13,139	)
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives	181,622			21,202
Depreciation, depletion and amortization	151,422			126,788
Impairment of properties and equipment	7,875			33,188
Accretion of asset retirement obligations	1,584			1,288
Non-cash stock-based compensation	4,683			5,261
(Gain) loss on sale of properties and equipment	(369		)	1,432
Amortization of debt discount and issuance costs	3,349			3,246
Deferred income taxes	(37,487		)	(4,809		)
Other	21			515
Changes in assets and liabilities	(10,671		)	30,177
Net cash from operating activities	181,853			205,149
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(266,940		)	(196,917		)
Capital expenditures for other properties and equipment	(4,826		)	(1,066		)
Acquisition of crude oil and natural gas properties	—			(180,825		)
Proceeds from sale of properties and equipment	102			20
Proceeds from divestiture	—			39,023
Restricted cash	—			1,249
Net cash from investing activities	(271,664		)	(338,516		)
Cash flows from financing activities:
Proceeds from revolving credit facility	432,000			35,000
Repayment of revolving credit facility	(340,500		)	(35,000		)
Purchase of treasury stock	(1,460		)	(2,255		)
Other	(515		)	(379		)
Net cash from financing activities	89,525			(2,634		)
Net change in cash, cash equivalents and restricted cash	(286		)	(136,001		)
Cash, cash equivalents and restricted cash, beginning of period	9,399			189,925
Cash, cash equivalents and restricted cash, end of period	$	9,113		$	53,924

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

Condensed Consolidated Statement of Equity

(unaudited; in thousands, except share data)



	Three Months Ended March 31, 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		)
Purchase of treasury shares	—		—		—			(41,787	)	(1,460		)	—			(1,460		)
Issuance of treasury shares	(64,372	)	1		(1		)	64,372		—			—			—
Non-employee directors' deferred compensation plan	—		—		—			—		—			—			—
Issuance of stock awards, net of forfeitures	112,626		—		(2,547		)	—		2,547			—			—
Stock-based compensation expense	—		—		4,683			—		—			—			4,683
Other	—		—		—			—		—			—			—
Balance, March 31, 2019	66,196,863		$	662	$	2,521,558		(22,635	)	$	(1,016	)	$	(111,449	)	$	2,409,755



	Three Months Ended March 31, 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		)
Purchase of treasury shares	—	—		—			(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		)
Issuance of stock awards, net of forfeitures	43,930	1		(1		)	—		—			—			—
Stock-based compensation expense	—	—		5,261			—		—			—			5,261
Balance, March 31, 2018	65,999,010	$	660	$	2,504,663		(29,255	)	$	(1,514	)	$	(6,435	)	$	2,497,374

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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 rural areas of 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 March 31, 2019, we owned an interest in approximately 2,800 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 three months ended March 31, 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

Cash, cash equivalents and restricted cash. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the condensed consolidated balance sheets at March 31, 2019 and 2018 and December 31, 2018 and 2017, which sum to the total of cash, cash equivalents and restricted cash in the consolidated statements of cash flows:



	March 31, 2019		December 31, 2018		March 31, 2018		December 31, 2017
	(in thousands)
Cash and cash equivalents	$	1,112	$	1,398	$	45,923	$	180,675
Restricted cash	8,001		8,001		8,001		9,250
Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	9,113	$	9,399	$	53,924	$	189,925

Restricted cash is included in other assets on the condensed consolidated balance sheets.

Recently Adopted Accounting Standards

In February 2016, the 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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

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 will be 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.

NOTE 3 - 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.

Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by

commodity and operating region for the three months ended March 31, 2019 and 2018 (in thousands):



	Three Months Ended March 31,
Revenue by Commodity and Operating Region	2019		2018		Percent Change
Crude oil
Wattenberg Field	$	180,426	$	170,306	5.9	%
Delaware Basin	50,657		53,418		(5.2	)%
Utica Shale (1)	—		2,696		(100.0	)%
Total	$	231,083	$	226,420	2.1	%
Natural gas
Wattenberg Field	$	46,701	$	29,772	56.9	%
Delaware Basin	5,770		7,679		(24.9	)%
Utica Shale (1)	—		1,110		(100.0	)%
Total	$	52,471	$	38,561	36.1	%
NGLs
Wattenberg Field	$	27,722	$	28,770	(3.6	)%
Delaware Basin	9,823		10,635		(7.6	)%
Utica Shale (1)	—		839		(100.0	)%
Total	$	37,545	$	40,244	(6.7	)%
Revenue by Operating Region
Wattenberg Field	$	254,849	$	228,848	11.4	%
Delaware Basin	66,250		71,732		(7.6	)%
Utica Shale (1)	—		4,645		(100.0	)%
Total	$	321,099	$	305,225	5.2	%



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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

NOTE 4 - 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.

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:



	March 31, 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	$	21,177		$	16,378		$	37,555		$	118,521		$	59,693		$	178,214
Total liabilities	(42,326		)	(3,388		)	(45,714		)	(3,364		)	(1,364		)	(4,728		)
Net asset (liability)	$	(21,149	)	$	12,990		$	(8,159	)	$	115,157		$	58,329		$	173,486

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

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



	Three Months Ended March 31,
	2019			2018
	(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period	$	58,329		$	(9,687	)
Changes in fair value included in condensed consolidated statement of operations line item:
Commodity price risk management loss, net	(43,520		)	(2,152		)
Settlements included in condensed consolidated statement of operations line items:
Commodity price risk management loss, net	(1,819		)	3,006
Fair value of Level 3 instruments, net liability end of period	$	12,990		$	(8,833	)

Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item:
Commodity price risk management loss, net	$	(38,680	)	$	1,205

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

Non-Derivative Financial Assets and Liabilities

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.

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:



		As of March 31, 2019				As of December 31, 2018
		Estimated Fair Value		Percent of Par		Estimated Fair Value		Percent of Par
		(in millions)
Senior notes:
	2021 Convertible Notes	$	188.1	94.1	%	$	175.4	87.7	%
	2024 Senior Notes	398.9		99.7	%	370.2		92.5	%
	2026 Senior Notes	583.7		97.3	%	532.4		88.7	%

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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at March 31, 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 March 31, 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 5 - 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 March 31, 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 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 March 31, 2019, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.



	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 March 31, 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 March 31, 2019 (1) (in thousands)
Crude Oil
NYMEX
2019	2,050	$	56.22	$	67.77	6,150	$	54.25		$	(35,191	)
2020	3,600	55.00		71.68		5,600	61.55			27,831
2021	—	—		—		600	57.23			350
Total Crude Oil	5,650					12,350				$	(7,010	)

Natural Gas
NYMEX
2019	—	$	—	$	—	22,746	$	2.91		$	2,641
Dominion South
2019	—	—		—		113	2.56			6
2020	—	—		—		14	2.54			—
Total Natural Gas	—					22,873				$	2,647

Basis Protection - Natural Gas
CIG
2019	—	$	—	$	—	22,683	$	(0.76	)	$	(3,796	)
Total Basis Protection - Natural Gas	—					22,683				$	(3,796	)

Commodity Derivatives Fair Value										$	(8,159	)

_____________


(1)	Approximately 43.6 percent of the fair value of our commodity derivative assets and 7.4 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.

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	March 31, 2019		December 31, 2018
			(in thousands)
Derivative assets:	Current
	Commodity derivative contracts	Fair value of derivatives	$	13,330	$	84,492
	Non-current
	Commodity derivative contracts	Fair value of derivatives	24,225		93,722
Total derivative assets			$	37,555	$	178,214

Derivative liabilities:	Current
	Commodity derivative contracts	Fair value of derivatives	$	40,103	$	748
	Basis protection derivative contracts	Fair value of derivatives	3,796		2,616
			43,899		3,364
	Non-current
	Commodity derivative contracts	Fair value of derivatives	1,815		1,364
Total derivative liabilities			$	45,714	$	4,728

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

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



	Three Months Ended March 31,
Condensed Consolidated Statement of Operations Line Item	2019			2018
	(in thousands)
Commodity price risk management loss, net
Net settlements	$	(8,452	)	$	(26,038	)
Net change in fair value of unsettled derivatives	(181,622		)	(21,202		)
Total commodity price risk management loss, net	$	(190,074	)	$	(47,240	)

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

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



As of March 31, 2019	Derivative Instruments, Gross		Effect of Master Netting Agreements			Derivative Instruments, Net
	(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	37,555	$	(27,793	)	$	9,762

Liability derivatives:
Derivative instruments, at fair value	$	45,714	$	(27,793	)	$	17,921



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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

NOTE 6 - PROPERTIES AND EQUIPMENT

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



	March 31, 2019			December 31, 2018
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	5,681,685		$	5,452,613
Unproved	485,571			492,594
Total crude oil and natural gas properties	6,167,256			5,945,207
Infrastructure and other	59,510			60,612
Land and buildings	12,497			11,243
Construction in progress	404,229			356,095
Properties and equipment, at cost	6,643,492			6,373,157
Accumulated DD&A	(2,521,843		)	(2,370,295		)
Properties and equipment, net	$	4,121,649		$	4,002,862

Classification of Assets and Liabilities as Held-for-Sale. During the fourth quarter of 2018, as part of our plans to divest certain of our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets, we began actively marketing the assets for sale; therefore, these assets are classified as held-for-sale as they met the criteria for such classification at March 31, 2019 and December 31, 2018. The planned disposition of our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets does not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we will not account for the disposition as a discontinued operation. Also included in assets held-for-sale are 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:



	March 31, 2019		December 31, 2018
	(in thousands)
Assets
Properties and equipment, net	$	150,360	$	137,448
Other assets	2,487		3,257
Total assets	$	152,847	$	140,705

Liabilities
Asset retirement obligation	$	4,614	$	4,111
Total liabilities	$	4,614	$	4,111

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



	Three Months Ended March 31,
	2019		2018
	(in thousands)

Impairment of proved and unproved properties	$	7,875	$	33,130
Amortization of individually insignificant unproved properties	—		58
Impairment of crude oil and natural gas properties	$	7,875	$	33,188

During the three months ended March 31, 2019 and 2018, we recorded impairment charges totaling $7.9 million and $26.9 million, respectively, related to the divestiture of leaseholds and the then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin and made the determination that we would no longer pursue plans

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

to develop these properties. 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 three months ended March 31, 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 the guidance of Accounting Standards Codification 250, Accounting Changes and Error Corrections ("ASC 250"). Based on the guidance in ASC 250, we determined that the impact of 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:



	March 31, 2019		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	12,853		35,127
Reclassifications to proved properties	—		(38,387		)
Ending balance	$	25,041	$	12,188

Number of wells pending determination at period end	2		2

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

NOTE 7 - OTHER ACCRUED EXPENSES AND OTHER LIABILITIES

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



	March 31, 2019		December 31, 2018
	(in thousands)

Employee benefits	$	10,188	$	25,811
Asset retirement obligations	28,798		25,598
Environmental expenses	3,554		3,038
Operating and finance leases	6,645		—
Other	19,651		20,686
Other accrued expenses	$	68,836	$	75,133

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



	March 31, 2019		December 31, 2018
	(in thousands)

Production taxes	$	78,805	$	61,310
Deferred oil gathering credit	22,207		22,710
Operating and finance leases	20,063		—
Other	3,988		8,644
Other liabilities	$	125,063	$	92,664

Deferred Oil Gathering Credit. In January 2018, we received a payment from a midstream service provider for the execution of an amendment to an existing crude oil PSA signed in December 2017. The amendment was effective contingent upon certain events which occurred in late January 2018. The amendment, among other things, 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 using the straight-line method over the life of the amendment. Amortization charges totaling approximately $0.5 million and $0.4 million for the three months ended March 31, 2019 and 2018, respectively, related to the deferred oil gathering credit are included as a reduction to transportation, gathering and processing expenses in our condensed consolidated statements of operations.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

NOTE 8 - LONG-TERM DEBT

Long-term debt consisted of the following as of:



	March 31, 2019			December 31, 2018
	(in thousands)
Senior Notes:
1.125% Convertible Notes due September 2021:
Principal amount	$	200,000		$	200,000
Unamortized discount	(20,807		)	(22,766		)
Unamortized debt issuance costs	(2,397		)	(2,640		)
Net of unamortized discount and debt issuance costs	176,796			174,594

6.125% Senior Notes due September 2024:
Principal amount	400,000			400,000
Unamortized debt issuance costs	(5,346		)	(5,590		)
Net of unamortized debt issuance costs	394,654			394,410

5.75% Senior Notes due May 2026:
Principal amount	600,000			600,000
Unamortized debt issuance costs	(6,404		)	(6,628		)
Net of unamortized debt issuance costs	593,596			593,372

Total senior notes	1,165,046			1,162,376

Revolving Credit Facility:
Revolving credit facility due May 2023	124,000			32,500
Total long-term debt, net of unamortized discount and debt issuance costs	$	1,289,046		$	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 March 31, 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 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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

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 2026 Senior Notes and the 2024 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 March 31, 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 and, as of March 31, 2019, a borrowing base of $1.3 billion. The amount we may borrow under the Restated Credit Agreement is subject to certain limitations under our Notes.

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 March 31, 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 March 31, 2019, we were in compliance with all the revolving credit facility covenants.

As of March 31, 2019 and December 31, 2018, debt issuance costs related to our revolving credit facility were $10.9 million and $11.5 million, respectively, and are included in other assets on the condensed consolidated balance sheets. As of March 31, 2019, the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was 4.5 percent.

NOTE 9 - 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

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 March 31, 2019
	(in thousands)
Operating lease costs	$	1,348

Finance lease costs:
Amortization of ROU assets	$	483
Interest on lease liabilities	60
Total finance lease costs	543

Short-term lease costs	61,030
Total lease costs	$	62,921

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.

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



Leases	Condensed Consolidated Balance Sheet Line Item	March 31, 2019
		(in thousands)
Operating Leases:
Operating lease ROU assets	Other assets	$	19,535

Operating lease obligation - short-term	Other accrued expense	$	4,958
Operating lease obligation - long-term	Other liabilities	17,055
Total operating lease liabilities		$	22,013

Finance Leases:
Finance lease ROU assets	Properties and equipment, net	$	4,748

Finance lease obligation - short-term	Other accrued expense	$	1,687
Finance lease obligation - long-term	Other liabilities	3,008
Total finance lease liabilities		$	4,695

Weighted-average remaining lease term (years)
Operating leases		3.22
Finance leases		4.53

Weighted-average discount rate
Operating leases		5.0		%
Finance leases		5.0		%

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

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



	Operating Leases			Finance Leases			Total
	(in thousands)
2019	$	4,378		$	1,431		$	5,809
2020	5,910			1,716			7,626
2021	5,782			1,101			6,883
2022	4,851			528			5,379
2023	1,394			321			1,715
Thereafter	2,291			6			2,297
Total lease payments	24,606			5,103			29,709
Less interest and discount	(2,593		)	(408		)	(3,001		)
Present value of lease liabilities	$	22,013		$	4,695		$	26,708

NOTE 10 - ASSET RETIREMENT OBLIGATIONS

The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties:



	Amount
	(in thousands)

Balance at December 31, 2018	$	115,021
Obligations incurred with development activities	2,807
Accretion expense	1,584
Revisions in estimated cash flows	3,200
Obligations discharged with asset retirements and divestiture	(6,703		)
Balance at March 31, 2019	115,909
Liabilities held-for-sale	(4,614		)
Current portion	(28,798		)
Long-term portion	$	82,497

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.

NOTE 11 - 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

March 31, 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 March 31,
Area	2020		2021		2022		2023		2024 and Through Expiration		Total		Expiration Date

Natural gas (MMcf)
Wattenberg Field	26,772		31,025		31,025		31,025		85,290		205,137		April 30, 2026
Delaware Basin	47,150		33,410		16,097		—		—		96,657		December 31, 2021
Gas Marketing	7,136		7,117		6,966		2,830		—		24,049		August 31, 2022
Total	81,058		71,552		54,088		33,855		85,290		325,843

Crude oil (MBbls)
Wattenberg Field	9,740		6,227		5,475		5,475		450		27,367		April 30, 2023
Delaware Basin	8,227		8,580		8,030		8,030		6,050		38,917		December 31, 2023
Total	17,967		14,807		13,505		13,505		6,500		66,284

Water (MBbls)
Wattenberg Field	3,886		6,207		6,207		6,206		10,899		33,405		December 31, 2024
Delaware Basin	3,660		3,650		3,650		3,650		870		15,480		June 26, 2023
Total	7,546		9,857		9,857		9,856		11,769		48,885

Dollar commitment (in thousands)	$	104,504	$	80,633	$	73,851	$	68,882	$	94,836	$	422,706

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. The second plant is currently scheduled to be completed by the end of the second quarter of 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. Any shortfall in these volume commitments may be offset by other producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. Payments made to date for such quantities have not been significant.

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 17,200 barrels of crude oil per day and increase over time to 26,400 barrels of crude oil per day. These agreements are 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 March 31, 2019 and 2018, amounts related to long-term transportation volumes in the table above were $10.9 million and $2.6 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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

material adverse effect on our financial position, results of operations or liquidity.

Action Regarding Partnerships. In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al., filed in the United States District Court for the District of Colorado (the "Dufresne Case"). 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 our Board of Directors for allegedly aiding and abetting PDC's breach of fiduciary duty. The lawsuit accuses PDC, as the managing general partner of the Partnerships, of, among other things, failing to maximize the productivity of the Partnerships’ crude oil and natural gas wells and improperly assigning the Partnerships only interests in the wells, as opposed to leasehold interests in surrounding acreage. In late April 2018, the plaintiffs filed an amendment to their complaint, which alleges additional facts and purports to add direct class action claims in addition to the original derivative claims. We filed a motion to dismiss this amended complaint and the claims against the individuals named as defendants on July 31, 2018. On February 19, 2019, the 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 assignments to support their claims for breach of fiduciary duty against PDC. We filed an answer to the remaining claims on March 5, 2019. We understand that this action is stayed as a result of the partnership bankruptcy proceedings described in Partnership Bankruptcy Filings below. We are currently unable to estimate any potential damages resulting from this lawsuit.

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"). The Partnerships intend to enter into a transaction with us, pursuant to which they will sell substantially all of their assets to us through a Chapter 11 plan of liquidation (the "Chapter 11 Plan") and provide a release of any claims, including those asserted in the Dufresne Case. The Partnerships remain in possession of their assets and continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. In addition, a third-party (the “Responsible Party”) has been designated for the Partnerships. The Responsible Party is expected to oversee all actions for the Partnerships in connection with the Chapter 11 Proceedings, including actions relating to the anticipated transactions with us and seeking approval of the Chapter 11 Plan. In late November and early December 2018, the plaintiffs in the Dufresne Case filed several pleadings in the Bankruptcy Court, including one to dismiss the bankruptcy on grounds that PDC had no authority to hire the Responsible Party, the Responsible Party had no authority to cause the Partnerships to file bankruptcy, and the bankruptcy was filed solely for the purpose of gaining a litigation advantage in the Dufresne Case. The plaintiffs in the Dufresne Case also objected to the retention of the Responsible Party. PDC, the Partnerships and the plaintiffs in the Dufresne Case agreed to mediate their disputes. As a result, on December 17, 2018 the Bankruptcy Court entered an agreed order staying the bankruptcy motions and abating the Dufresne Case to allow the parties to mediate their disputes. The mediation was conducted in late February 2019, but the parties did not reach a settlement. As a result, on March 21, 2019, the Bankruptcy Court entered an agreed scheduling order with respect to the motion to dismiss and objection to the retention of the Responsible Party, with a hearing scheduled for June 2019. We do not believe that the Partnership's Chapter 11 Proceedings will have a material adverse effect on our financial position, results of operations or liquidity, but we cannot predict the outcome of such proceedings.

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 March 31, 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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law.

In October 2017, we entered into a consent decree to resolve the lawsuit and the compliance advisory. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects) of which the cash fines and the full cost of supplemental environmental projects were paid in the first and third quarters of 2018, respectively, (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations and (iii) mitigation with an estimated cost of $1.7 million. We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional 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 degree 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 our Board of Directors 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 12 - 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 our Board of Directors (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 three months ended March 31, 2019. As of March 31, 2019, there were 1,772,088 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 March 31, 2019, there were 37,703 shares available for grant under the 2010 Plan.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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 March 31,
	2019			2018
	(in thousands)

Stock-based compensation expense	$	4,683		$	5,261
Income tax benefit	(1,120		)	(1,261		)
Stock-based compensation expense, net of tax	$	3,563		$	4,000

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 three months ended March 31, 2019:



	Shares		Weighted-Average Grant Date Fair Value per Share

Non-vested at December 31, 2018	618,407		$	54.16
Granted	189,137		38.59
Vested	(93,685	)	54.64
Forfeited	(12,186	)	48.38
Non-vested at March 31, 2019	701,673		50.00

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



	Three Months Ended March 31,
	2019		2018
	(in thousands, except per share data)

Total intrinsic value of time-based awards vested	$	3,311	$	3,530
Total intrinsic value of time-based awards non-vested	28,544		26,297
Market price per share as of March 31	40.68		49.03
Weighted-average grant date fair value per share	38.59		50.94

Total compensation cost related to non-vested time-based awards and not yet recognized in our condensed consolidated statements of operations as of March 31, 2019 was $23.8 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

March 31, 2019

(unaudited)

The Compensation Committee awarded a total of 139,197 market-based PSUs to our executive officers during the three months ended March 31, 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:



	Three Months Ended March 31,
	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 three months ended March 31, 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 March 31, 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:



	Three Months Ended March 31,
	2019		2018
	(in thousands, except per share data)

Total intrinsic value of market-based awards non-vested	$	9,849	$	6,815
Market price per common share as of March 31,	40.68		49.03
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 March 31, 2019 was $11.6 million. This cost is expected to be recognized over a weighted-average period of 2.2 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 months ended March 31, 2019.

Total compensation cost related to non-vested SARs granted and not yet recognized in our condensed consolidated statements of operations as of March 31, 2019 was $0.4 million. The cost is expected to be recognized over a weighted-average period of 0.8 years.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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 our Board of Directors from time to time. Through March 31, 2019, no shares of preferred stock have been issued.

Stock Repurchase Program

In April 2019, our Board of Directors approved a stock repurchase program (the “Program”) to acquire up to $200 million of our outstanding common stock, depending on market conditions. The Program is expected to begin in the third quarter of 2019 with a target completion date of December 31, 2020. Repurchases under the Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board of Directors at any time.

NOTE 13 - INCOME TAXES

We compute our quarterly tax provision using the effective tax rate method by applying the anticipated annual effective rate to our year-to-date income or loss, except for discrete items. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs. 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, nondeductible lobbying expenses, and federal tax credits. The effective income tax rate for the three months ended March 31, 2019 includes discrete income tax provision items of $0.5 million relating to the tax detriment on stock-based compensation, which resulted in a 0.3 percent decrease to our effective income tax rate. 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.

The effective income tax rate for the three months ended March 31, 2019 was a 23.7 percent benefit on loss, compared to a 25.8 percent benefit on loss for the three months ended March 31, 2018.

As of March 31, 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 2017 tax return. The 2017 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 2018 and 2019 tax years. Participation in the CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings.

NOTE 14 - EARNINGS PER SHARE

Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed, except that the denominator includes the effect, using the treasury stock method, of unvested 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 March 31,
	2019	2018
	(in thousands)

Weighted-average common shares outstanding - basic	66,182	65,957
Weighted-average common shares and equivalents outstanding - diluted	66,182	65,957

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)

We reported a net loss for the three months ended March 31, 2019 and 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 March 31,
	2019	2018
	(in thousands)

Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
RSUs and PSUs	895	613
Other equity-based awards	302	76
Total anti-dilutive common share equivalents	1,197	689

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 months ended March 31, 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

March 31, 2019

(unaudited)

NOTE 15 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION



	Three Months Ended March 31,
	2019		2018 (1)

Supplemental cash flow information:
Cash payments for:
Interest, net of capitalized interest	$	12,602	$	12,343
Income taxes	—		193

Non-cash investing and financing activities:
Change in accounts payable related to capital expenditures	$	14,941	$	51,093
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals	2,794		5,354

Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	1,441	$	—
Operating cash flows from finance leases	60		—
Financing cash flows from finance leases	494		—

ROU assets obtained in exchange for lease obligations:
Operating leases	$	481	$	—
Finance leases	624		—

(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 three months ended March 31, 2018.

NOTE 16 - 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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)



	Condensed Consolidating Balance Sheets
	March 31, 2019
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Current assets:
Cash and cash equivalents	$	1,112		$	—		$	—		$	1,112
Accounts receivable, net	157,254			33,590			—			190,844
Fair value of derivatives	13,330			—			—			13,330
Prepaid expenses and other current assets	6,963			907			—			7,870
Total current assets	178,659			34,497			—			213,156
Properties and equipment, net	2,301,379			1,820,270			—			4,121,649
Assets held-for-sale	—			152,847			—			152,847
Intercompany receivable	528,315			—			(528,315		)	—
Investment in subsidiaries	1,309,187			—			(1,309,187		)	—
Fair value of derivatives	24,225			—			—			24,225
Other assets	44,755			7,296			—			52,051
Total Assets	$	4,386,520		$	2,014,910		$	(1,837,502	)	$	4,563,928

Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	110,019		$	105,536		$	—		$	215,555
Production tax liability	51,558			3,872			—			55,430
Fair value of derivatives	43,899			—			—			43,899
Funds held for distribution	75,899			15,716			—			91,615
Accrued interest payable	15,190			4			—			15,194
Other accrued expenses	65,902			2,934			—			68,836
Total current liabilities	362,467			128,062			—			490,529
Intercompany payable	—			528,315			(528,315		)	—
Long-term debt	1,289,046			—			—			1,289,046
Deferred income taxes	127,378			33,231			—			160,609
Asset retirement obligations	75,133			7,364			—			82,497
Liabilities held-for-sale	—			4,614			—			4,614
Fair value of derivatives	1,815			—			—			1,815
Other liabilities	120,926			4,137			—			125,063
Total liabilities	1,976,765			705,723			(528,315		)	2,154,173

Commitments and contingent liabilities

Stockholders' Equity
Common shares	662			—			—			662
Additional paid-in capital	2,521,558			1,766,775			(1,766,775		)	2,521,558
Retained earnings	(111,449		)	(457,588		)	457,588			(111,449		)
Treasury shares	(1,016		)	—			—			(1,016		)
Total stockholders' equity	2,409,755			1,309,187			(1,309,187		)	2,409,755
Total Liabilities and Stockholders' Equity	$	4,386,520		$	2,014,910		$	(1,837,502	)	$	4,563,928

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 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	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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)



	Condensed Consolidating Statements of Operations
	Three Months Ended March 31, 2019
	Parent			Guarantor			Eliminations		Consolidated
	(in thousands)

Revenues
Crude oil, natural gas and NGLs sales	$	254,849		$	66,250		$	—	$	321,099
Commodity price risk management loss, net	(190,074		)	—			—		(190,074		)
Other income	2,633			842			—		3,475
Total revenues	67,408			67,092			—		134,500
Costs, expenses and other
Lease operating expenses	23,634			11,587			—		35,221
Production taxes	15,885			6,283			—		22,168
Transportation, gathering and processing expenses	5,440			5,984			—		11,424
Exploration, geologic and geophysical expense	317			2,326			—		2,643
Impairment of properties and equipment	—			7,875			—		7,875
General and administrative expense	34,434			5,164			—		39,598
Depreciation, depletion and amortization	112,631			38,791			—		151,422
Accretion of asset retirement obligations	1,378			206			—		1,584
(Gain) loss on sale of properties and equipment	(382		)	13			—		(369		)
Other expenses	3,554			—			—		3,554
Total costs, expenses and other	196,891			78,229			—		275,120
Loss from operations	(129,483		)	(11,137		)	—		(140,620		)
Interest expense	(17,935		)	957			—		(16,978		)
Interest income	10			—			—		10
Loss before income taxes	(147,408		)	(10,180		)	—		(157,588		)
Income tax benefit	34,991			2,421			—		37,412
Equity in loss of subsidiary	(7,759		)	—			7,759		—
Net loss	$	(120,176	)	$	(7,759	)	$	7,759	$	(120,176	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)



	Condensed Consolidating Statements of Operations
	Three Months Ended March 31, 2018
	Parent			Guarantor			Eliminations		Consolidated
	(in thousands)

Revenues
Crude oil, natural gas and NGLs sales	$	233,494		$	71,731		$	—	$	305,225
Commodity price risk management loss, net	(47,240		)	—			—		(47,240		)
Other income	2,516			99			—		2,615
Total revenues	188,770			71,830			—		260,600
Costs, expenses and other
Lease operating expenses	21,362			8,274			—		29,636
Production taxes	16,081			4,088			—		20,169
Transportation, gathering and processing expenses	3,231			4,082			—		7,313
Exploration, geologic and geophysical expense	313			2,333			—		2,646
Impairment of properties and equipment	6			33,182			—		33,188
General and administrative expense	31,559			4,137			—		35,696
Depreciation, depletion and amortization	94,376			32,412			—		126,788
Accretion of asset retirement obligations	1,200			88			—		1,288
Gain on sale of properties and equipment	1,432			—			—		1,432
Other expenses	2,768			—			—		2,768
Total costs, expenses and other	172,328			88,596			—		260,924
Income (loss) from operations	16,442			(16,766		)	—		(324		)
Interest expense	(18,097		)	568			—		(17,529		)
Interest income	148			—			—		148
Loss before income taxes	(1,507		)	(16,198		)	—		(17,705		)
Income tax benefit	577			3,989			—		4,566
Equity in loss of subsidiary	(12,209		)	—			12,209		—
Net loss	$	(13,139	)	$	(12,209	)	$	12,209	$	(13,139	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2019

(unaudited)



	Condensed Consolidating Statements of Cash Flows
	Three Months Ended March 31, 2019
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Cash flows from operating activities	$	152,524		$	29,329		$	—		$	181,853
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(161,482		)	(105,458		)	—			(266,940		)
Capital expenditures for other properties and equipment	(4,756		)	(70		)	—			(4,826		)
Proceeds from sale of properties and equipment	102			—			—			102
Intercompany transfers	(76,271		)	—			76,271			—
Net cash from investing activities	(242,407		)	(105,528		)	76,271			(271,664		)
Cash flows from financing activities:
Proceeds from revolving credit facility	432,000			—			—			432,000
Repayment of revolving credit facility	(340,500		)	—			—			(340,500		)
Purchase of treasury stock	(1,460		)	—			—			(1,460		)
Other	(443		)	(72		)	—			(515		)
Intercompany transfers	—			76,271			(76,271		)	—
Net cash from financing activities	89,597			76,199			(76,271		)	89,525
Net change in cash, cash equivalents and restricted cash	(286		)	—			—			(286		)
Cash, cash equivalents and restricted cash, beginning of period	9,399			—			—			9,399
Cash, cash equivalents and restricted cash, end of period	$	9,113		$	—		$	—		$	9,113



	Condensed Consolidating Statements of Cash Flows
	Three Months Ended March 31, 2018
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Cash flows from operating activities	$	149,009		$	56,140		$	—		$	205,149
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(97,286		)	(99,631		)	—			(196,917		)
Capital expenditures for other properties and equipment	(701		)	(365		)	—			(1,066		)
Acquisition of crude oil and natural gas properties	(180,825		)	—			—			(180,825		)
Proceeds from sale of properties and equipment	20			—			—			20
Proceeds from divestiture	39,023			—			—			39,023
Restricted cash	1,249			—			—			1,249
Intercompany transfers	(43,891		)	—			43,891			—
Net cash from investing activities	(282,411		)	(99,996		)	43,891			(338,516		)
Cash flows from financing activities:
Proceeds from revolving credit facility	35,000			—			—			35,000
Repayment of revolving credit facility	(35,000		)	—			—			(35,000		)
Purchase of treasury stock	(2,255		)	—			—			(2,255		)
Other	(344		)	(35		)	—			(379		)
Intercompany transfers	—			43,891			(43,891		)	—
Net cash from financing activities	(2,599		)	43,856			(43,891		)	(2,634		)
Net change in cash, cash equivalents and restricted cash	(136,001		)	—			—			(136,001		)
Cash, cash equivalents and restricted cash, beginning of period	189,925			—			—			189,925
Cash, cash equivalents and restricted cash, end of period	$	53,924		$	—		$	—		$	53,924

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

The following discussion and analysis should be read in conjunction with our condensed consolidated financial statements and related notes included 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 of 11.2 MMboe for the three months ended March 31, 2019 represent an increase of 26 percent as compared to the three months ended March 31, 2018. Crude oil production increased 19 percent for the three months ended March 31, 2019 compared to the three months ended March 31, 2018. Crude oil production comprised approximately 40 percent and 43 percent of total production for the three months ended March 31, 2019 and 2018, respectively. Both natural gas and NGLs production increased 31 percent for the three months ended March 31, 2019 compared to the three months ended March 31, 2018. For the month ended March 31, 2019, we maintained an average daily production rate of approximately 124,000 Boe per day, up from approximately 96,000 Boe per day for the month ended March 31, 2018.

On a sequential quarterly basis, total production and crude oil production volumes for the three months ended March 31, 2019 as compared to the three months ended December 31, 2018 decreased by five percent and eight percent, respectively. The decrease in these production volumes was primarily related to fewer production days in the first quarter of 2019 and the natural decline of wells in the Delaware Basin as we did not turn any wells in-line during the second half of the fourth quarter of 2018.

Crude oil, natural gas and NGLs sales revenue increased to $321.1 million for the three months ended March 31, 2019, compared to $305.2 million for the three months ended March 31, 2018. The five percent increase in sales revenues was driven by the 26 percent increase in production, partially offset by the 16 percent decrease in weighted average realized commodity prices, as compared to the prior period.

We had negative net settlements from our commodity derivative contracts of $8.5 million for the three months ended March 31, 2019 as compared to negative net settlements of $26.0 million for the three months ended March 31, 2018. See Results of Operations - Commodity Price Risk Management for further details of our settlements of derivatives and changes in the fair value of unsettled derivatives.

The combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 12 percent to $312.6 million for the three months ended March 31, 2019 from $279.2 million for the three months ended March 31, 2018.

For the three months ended March 31, 2019, we generated a net loss of $120.2 million or $1.82 per diluted share, compared to a net loss of $13.1 million or $0.20 per diluted share for the comparable period in 2018. Our net loss for the three months ended March 31, 2019 as compared to the three months ended March 31, 2018 was most negatively impacted by unrealized losses on our commodity derivative instruments.

During the three months ended March 31, 2019, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $209.2 million compared to $190.1 million for the comparable period in 2018. The increase was primarily due to the increase in crude oil, natural gas and NGLs sales of $15.9 million and a decrease in the loss on commodity derivative settlements of $17.6 million. The increase was partially offset by an increase in operating costs of $15.6 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 $181.9 million and $205.1 million and our adjusted cash flows from operations, a non-U.S. GAAP financial measure, were $192.6 million and $174.9 million for the three months ended March 31, 2019 and March 31, 2018, respectively.

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Liquidity

Available liquidity as of March 31, 2019 was $1.2 billion, which was comprised of $1.1 million of cash and cash equivalents and $1.2 billion available for borrowing under our revolving credit facility. Based on our current production forecast for 2019 and our average 2019 price assumptions of $55.00 for NYMEX crude oil and $3.00 for NYMEX natural gas, we expect 2019 cash flows from operations to exceed our capital investments in crude oil and natural gas properties by approximately $65.0 million. Assuming a NYMEX crude oil price of $50.00, we expect cash flows from operations to exceed our capital investments in crude oil and natural gas properties by approximately $25.0 million. We anticipate that capital investments will exceed cash flows from operations during the first half of 2019 and expect cash flows from operations to exceed capital investments during the remainder of the year.

Operational Overview

During the three months ended March 31, 2019, we ran three drilling rigs in each of the Wattenberg Field and the Delaware Basin and we expect to maintain a three-rig pace in the Wattenberg Field. In the Delaware Basin, we expect to operate at a three-rig pace through the second quarter of 2019 and at a two-rig pace throughout the remainder of the year.

The following tables summarize our drilling and completion activity for the three months ended March 31, 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	38		36.7		10		9.4		48		46.1
Turned-in-line	(32	)	(28.9	)	(9	)	(8.7	)	(41	)	(37.6	)
In-process as of March 31, 2019	139		130.2		19		18.1		158		148.3



	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	12		1.7		2		0.4		14		2.1
Turned-in-line	(8	)	(0.1	)	(2	)	(0.1	)	(10	)	(0.2	)
In-process as of March 31, 2019	9		3.6		6		1.2		15		4.8

Our in-process wells represent wells that are in the process of being drilled and/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

As previously announced, we expect our production for 2019 to range between 46 MMBoe to 50 MMBoe, or approximately 126,000 Boe to 137,000 Boe per day. We expect that approximately 41 to 45 percent of our 2019 production will be comprised of crude oil and approximately 21 to 23 percent will be NGLs, for total liquids of approximately 62 to 68 percent. Our planned 2019 capital investments in crude oil and natural gas properties, which we expect to be between $810 million and $870 million, are focused on continued execution of our development plans in the Wattenberg Field and Delaware Basin.

In 2019, we also expect to spend approximately $20 million for corporate capital, the majority of which is related to the implementation of an ERP 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.

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

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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.

Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which we have further 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 90 percent is expected to be invested in operated drilling and completion activity. We plan to drill standard-reach lateral (“SRL”), mid-reach lateral (“MRL”) and extended-reach lateral (“XRL”) wells in 2019, the majority of which will be in the Kersey area of the field. In 2019, we anticipate spudding approximately 135 to 150 operated wells and turning-in-line approximately 110 to 125 operated wells. We expect to drill at a three-rig pace in 2019 with an average development cost per well of between $3 million and $5 million, depending upon the lateral length of the well. The remainder of the Wattenberg Field capital investment program is expected to be used for non-operated drilling, land, capital workovers and facilities projects.

Delaware Basin. Our 2019 capital investment program for the Delaware Basin contemplates operating at a three-rig pace through the second quarter of 2019 and a two-rig pace throughout the remainder of the year. 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 80 percent is allocated to spud approximately 25 to 30 operated wells and turn-in-line approximately 20 to 25 operated wells. We plan to drill MRL and XRL wells in 2019 with an expected average development cost per well of between $11.5 million and $13 million, 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 20 percent of our budgeted Delaware Basin capital for midstream assets, leasing, non-operated capital, seismic and technical studies and facilities.

In 2018, we began the process of actively marketing our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets for sale. In the second quarter of 2019, we entered into definitive agreements to divest the natural gas gathering and produced water gathering and disposal assets for an aggregate purchase price of approximately $310 million, subject to post-closing adjustments. These transactions are expected to close in mid-2019. We are also in the final stages of negotiations regarding the sale of our crude oil gathering assets. We expect to use the proceeds from these divestitures to reduce the outstanding borrowings under our revolving credit facility and for our capital investment program.

Financial Guidance.

The following table sets forth our previously-announced financial guidance for the year ended December 31, 2019 for certain expenses and price differentials:



	Low			High
Operating Expenses
Lease operating expenses ($/Boe)	$	2.85		$	3.15
Transportation, gathering and processing expenses ("TGP") ($/Boe)	$	0.80		$	1.00
Production taxes (% of crude oil, natural gas and NGLs sales)	6		%	7		%
General and administrative expense ("G&A") ($/Boe) (1)	$	3.00		$	3.40

Estimated Price Realizations (% of NYMEX, excludes TGP)
Crude oil	90%			95%
Natural gas	50%			55%
NGLs	30%			35%



(1)	The 2019 guidance for G&A does not include expenses associated with shareholder activism. Management is taking steps within its control to target full-year G&A per Boe, including these expenses, to be within range.

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Regulatory Update

Senate Bill 19-181. On April 16, 2019, Colorado Senate Bill 19-181 was signed into law and made a number of changes to oil and gas regulation in Colorado. Among other things, it gives local governments the option to regulate facility siting and surface impacts of oil and natural gas development, and it authorizes local governments to impose requirements that are stricter than state requirements. It changes the mission of the Colorado Oil and Gas Conservation Commission ("COGCC") from “fostering” responsible and balanced development to “regulating” the industry, and it changes the composition and qualifications of the COGCC commissioners. In addition, it changes the standard for environmental regulation to require that such regulation be “reasonable” and to omit references to cost-effectiveness and technical feasibility. Furthermore, it changes requirements for spacing and compulsory pooling. It also calls for rulemaking on several matters that bear on operations, including environmental protection, facility siting, cumulative impacts, flowlines, wells that are inactive, temporarily abandoned or shut-in, financial assurance, wellbore integrity and application fees. These rulemakings may create new application and operating requirements, but they are expected to take years to finalize. We primarily operate in the rural areas of the core Wattenberg Field in Weld County and have approved permits for development into 2020.

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 Colorado Department of Public Health and Environment (“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.

Shareholder Activism

Kimmeridge Energy Management Company, LLC and its affiliates (collectively, “Kimmeridge”), a beneficial holder of approximately 5.1 percent of the outstanding shares of our common stock (based on Kimmeridge's latest Schedule 13D/A filed with the SEC on March 18, 2019), has nominated for election a competing slate of director candidates to our Board of Directors in connection with our 2019 Annual Meeting of Stockholders (the “2019 Annual Meeting”). If elected, this competing slate would replace our three nominees, our Chief Executive Officer, Barton R. Brookman, and independent directors Mark E. Ellis and Larry F. Mazza, who currently comprise three of our eight member Board.

On April 17, 2019, we filed definitive proxy materials with the SEC nominating Messrs. Brookman, Ellis and Mazza to stand for re-election to the Board of Directors at the 2019 Annual Meeting. On April 18, 2019, Kimmeridge filed definitive proxy materials with the SEC regarding the election of Kimmeridge’s competing slate of director candidates.

Engaging in a proxy fight and responding to shareholder activism can be costly and time-consuming, disrupting our operations and diverting the attention of management and our employees. Activist campaigns can create perceived uncertainties as to our future direction, strategy and leadership and may result in the loss of potential business opportunities, harm our ability to pursue certain transactions and cause our stock price to experience periods of volatility.

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Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results:



	Three Months Ended March 31,
	2019			2018			Percent Change
	(dollars in millions, except per unit data)
Production
Crude oil (MBbls)	4,525			3,798			19.1	%
Natural gas (MMcf)	25,651			19,587			31.0	%
NGLs (MBbls)	2,415			1,846			30.8	%
Crude oil equivalent (MBoe)	11,215			8,908			25.9	%
Average Boe per day (Boe)	124,611			98,980			25.9	%
Crude Oil, Natural Gas and NGLs Sales
Crude oil	$	231.1		$	226.4		2.1	%
Natural gas	52.5			38.6			36.0	%
NGLs	37.5			40.2			(6.7	)%
Total crude oil, natural gas and NGLs sales	$	321.1		$	305.2		5.2	%

Net Settlements on Commodity Derivatives
Crude oil	$	(2.9	)	$	(27.0	)	(89.3	)%
Natural gas	(5.6		)	2.7			*
NGLs (propane portion)	—			(1.7		)	(100.0	)%
Total net settlements on derivatives	$	(8.5	)	$	(26.0	)	(67.3	)%

Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	51.06		$	59.62		(14.4	)%
Natural gas (per Mcf)	2.05			1.97			4.1	%
NGLs (per Bbl)	15.55			21.80			(28.7	)%
Crude oil equivalent (per Boe)	28.63			34.26			(16.4	)%

Average Costs and Expenses (per Boe)
Lease operating expenses	$	3.14		$	3.33		(5.7	)%
Production taxes	1.98			2.26			(12.4	)%
Transportation, gathering and processing expenses	1.02			0.82			24.4	%
General and administrative expense	3.53			4.01			(12.0	)%
Depreciation, depletion and amortization	13.50			14.23			(5.1	)%

Lease Operating Expenses by Operating Region (per Boe)
Wattenberg Field	$	2.63		$	3.02		(12.9	)%
Delaware Basin	5.15			4.44			16.0	%
Utica Shale (1)	—			3.46			(100.0	)%



*	Percent change is not meaningful.
	Amounts may not recalculate due to rounding.
	(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 months ended March 31, 2019, crude oil, natural gas and NGLs sales revenue increased compared to the three months ended March 31, 2018 due to the following:



	Three Months Ended March 31, 2019
	(in millions)
Increase in production	$	67.7
Decrease in average crude oil price	(38.7		)
Increase in average natural gas price	2.0
Decrease in average NGLs price	(15.1		)
Total increase in crude oil, natural gas and NGLs sales revenue	$	15.9

Crude Oil, Natural Gas and NGLs Production

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



	Three Months Ended March 31,
Production by Operating Region	2019	2018	Percent Change
Crude oil (MBbls)
Wattenberg Field	3,571	2,881	24.0	%
Delaware Basin	954	871	9.5	%
Utica Shale (1)	—	46	(100.0	)%
Total	4,525	3,798	19.1	%
Natural gas (MMcf)
Wattenberg Field	20,961	15,524	35.0	%
Delaware Basin	4,690	3,649	28.5	%
Utica Shale (1)	—	414	(100.0	)%
Total	25,651	19,587	31.0	%
NGLs (MBbls)
Wattenberg Field	1,901	1,428	33.1	%
Delaware Basin	514	383	34.2	%
Utica Shale (1)	—	35	(100.0	)%
Total	2,415	1,846	30.8	%
Crude oil equivalent (MBoe)
Wattenberg Field	8,965	6,896	30.0	%
Delaware Basin	2,250	1,862	20.8	%
Utica Shale (1)	—	150	(100.0	)%
Total	11,215	8,908	25.9	%
Average crude oil equivalent per day (Boe)
Wattenberg Field	99,611	76,623	30.0	%
Delaware Basin	25,000	20,690	20.8	%
Utica Shale (1)	—	1,667	(100.0	)%
Total	124,611	98,980	25.9	%

Amounts may not recalculate due to rounding.

(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 March 31, 2019

	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	40%	39%	21%	100%
Delaware Basin	42%	35%	23%	100%

Three Months Ended March 31, 2018

	Crude Oil	Natural Gas	NGLs	Total
Wattenberg Field	42%	37%	21%	100%
Delaware Basin	47%	32%	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. Both of our current areas of operation have seen substantial development in recent years, and this has made it more difficult 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 would 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 induce them to provide increased capacity. If our production falls below the level required under these agreements, we could be subject to substantial penalties.

Wattenberg Field. Elevated line pressures on gas gathering facilities have adversely affected production from the Wattenberg Field from time to time, most recently beginning in mid-2017 and continuing into the first quarter of 2019. DCP Midstream, LP (“DCP”) completed its Mewbourn 3 Plant in August of 2018. This project, along with associated new compression, resulted in significant incremental capacity being added to the DCP system. System pressures began to decrease as this plant commenced operations and reached full capacity during the third and fourth quarters of 2018. Concurrently, additional residue pipeline capacity became available as pipeline expansion projects were completed and commissioned in November 2018. As a result, system pressures have been at lower levels than they were prior to the commissioning of the Mewbourn 3 Plant. These lower pressures, along with the system improvements implemented by DCP to prevent line freezes, combined with relatively mild weather in late 2018 and early 2019, resulted in significantly less plant downtime and lower system pressures as compared to the same period a year ago.

DCP continues to make progress on construction of its O’Conner 2 Plant, which we currently expect to be completed by the end of the second quarter of 2019. We anticipate that the start-up of the O’Conner 2 Plant will further reduce line pressures on the system while providing additional processing capacity for incremental production associated with our ongoing drilling program.

Agreements relating to the Mewbourn 3 and O’Conner 2 plants include baseline volume commitments for us and the other operators and guarantee a specified profit margin to DCP for a three-year period beginning on the initial start-up date of the relevant plant. Under our current drilling plans, we expect to continue to satisfy the volume commitments under both agreements. However, in the current commodity pricing environment, we have started making payments toward the profit margin requirements associated with the Mewbourn 3 Plant. Such payments made to date have not been significant; however, they may increase in the future. See the footnote titled Commitments and Contingencies to our condensed consolidated financial statements included elsewhere in this report for additional details regarding these agreements.

We have been engaged with DCP in planning for further incremental increases to the processing capacity in the field and it is currently our expectation that an additional plant will be constructed and commissioned on DCP’s system in mid-2020. We also continue to work with our other midstream service providers in the field in an 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.

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Additional residue and NGLs takeaway pipeline expansions or conversions are expected to be completed in the third and fourth quarters of 2019 to help ensure that all products associated with additional processing capacity will be transported to market. There is a risk that the residue takeaway pipeline expansions or conversions will not be completed in time to accommodate all of the incremental residue volume associated with the O’Conner 2 plant, which could potentially limit the incremental capacity benefits of the plant until the fourth quarter of 2019.

Limits on NGL fractionation capacity in the Gulf Coast can also affect our Wattenberg Field operations. While there has been some improvement in the availability of NGL fractionation on the Gulf Coast, capacity on the Gulf Coast and at Conway continues to run at very high rates. Our Wattenberg Field production is not currently being limited 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 is scheduled to come online later in 2019 and in 2020.

Delaware Basin. In the second quarter of 2018, we entered into firm sales and pipeline agreements for portions of our Delaware Basin crude oil and natural gas production. The crude oil agreement runs through December 2023 and provides for firm physical takeaway for all of our forecasted 2019 Delaware Basin crude oil volumes. This agreement provides us with price diversification through realization of export market pricing that includes access to a Corpus Christi terminal and exposure to Brent-weighted prices.

Our Delaware Basin natural gas sales agreements run through December 2021 and provide for firm physical takeaway of amounts varying between 50,000 MMbtu and 115,000 MMbtu per day of our natural gas volumes from the basin during the term of the agreements. A significant portion of our Delaware Basin natural gas sales are tied to Gulf Coast pricing, and as a result, we were able to somewhat mitigate the impact that the low Waha West Texas natural gas pricing had on our Delaware Basin natural gas sales prices during the first quarter of 2019.

Our production from the Delaware Basin was not materially affected by midstream or downstream capacity constraints during the first quarter of 2019. However, natural gas takeaway capacity downstream of in-field gathering and processing facilities in the basin is operating close to capacity and near-term production constraints are possible.

As discussed above, NGL fractionation on the Gulf Coast and at Conway is running at high utilization rates and this could potentially impact the operation of gas plants in the Delaware Basin. In addition, residue pipeline and downstream crude oil pipelines in the Delaware Basin are also operating at high utilization rates. We expect additional residue gas and crude oil pipelines to be available in early 2020 and additional NGL fractionation infrastructure to be available starting in mid-2019, with more projects scheduled to be completed in 2020.

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Crude Oil, Natural Gas and NGLs Pricing

Our results of operations depend upon many factors. Key factors include the price 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 and NGLs decreased during the three months ended March 31, 2019 compared to the three months ended March 31, 2018. NYMEX average daily crude oil prices decreased 13 percent and NYMEX first-of-the-month natural gas prices increased five percent for the three months ended March 31, 2019 as compared to the respective 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 March 31,
Weighted-Average Realized Sales Price by Operating Region					Percent Change
(excluding net settlements on derivatives)	2019		2018		Percent Change
Crude oil (per Bbl)
Wattenberg Field	$	50.52	$	59.13	(14.6	)%
Delaware Basin	53.11		61.34		(13.4	)%
Utica Shale (1)	—		58.10		(100.0	)%
Weighted-average price	51.06		59.62		(14.4	)%
Natural gas (per Mcf)
Wattenberg Field	$	2.23	$	1.92	16.1	%
Delaware Basin	1.23		2.10		(41.4	)%
Utica Shale (1)	—		2.68		(100.0	)%
Weighted-average price	2.05		1.97		4.1	%
NGLs (per Bbl)
Wattenberg Field	$	14.59	$	20.14	(27.6	)%
Delaware Basin	19.11		27.76		(31.2	)%
Utica Shale (1)	—		24.29		(100.0	)%
Weighted-average price	15.55		21.80		(28.7	)%
Crude oil equivalent (per Boe)
Wattenberg Field	$	28.43	$	33.18	(14.3	)%
Delaware Basin	29.45		38.52		(23.5	)%
Utica Shale (1)	—		30.98		(100.0	)%
Weighted-average price	28.63		34.26		(16.4	)%

Amounts may not recalculate due to rounding.

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

Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us based on a percent of proceeds or a sales price fixed at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid.

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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 transport 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 March 31, 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)	$	54.90	$	51.06	93	%	$	1.21	$	49.85	91	%
Natural gas (per MMBtu)	3.15		2.05		65	%	0.19		1.86		59	%
NGLs (per Bbl)	54.90		15.55		28	%	0.24		15.31		28	%
Crude oil equivalent (per Boe)	41.17		28.63		70	%	0.98		27.65		67	%

For the Three Months Ended March 31, 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)	$	62.87	$	59.62	95	%	$	0.67	$	58.95	94	%
Natural gas (per MMBtu)	3.00		1.97		66	%	0.22		1.75		58	%
NGLs (per Bbl)	62.87		21.80		35	%	0.24		21.56		34	%
Crude oil equivalent (per Boe)	46.43		34.26		74	%	0.82		33.44		72	%

Our average realization percentages for crude oil and natural gas for the three months ended March 31, 2019 are consistent with those for the comparable periods of 2018. The realization percentage for our NGLs sales has decreased as compared to 2018, primarily due to decreases in prices for the individual NGLs components for the three months ended March 31, 2019 as compared to the same period in 2018.

Commodity Price Risk Management

We use commodity derivative instruments to manage fluctuations in crude oil, natural gas and NGLs 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 condensed consolidated financial statements included elsewhere in this report for a detailed presentation of our derivative positions as of March 31, 2019.

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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. Commodity price risk management, net, does not include gains or losses from derivative transactions related to our gas marketing segment, which are included in other income and other expenses.

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 value 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.

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



	Three Months Ended March 31,
	2019			2018
	(in millions)
Commodity price risk management loss, net:
Net settlements of commodity derivative instruments:
Crude oil fixed price swaps, collars and rollfactors	$	(2.9	)	$	(26.8	)
Crude oil basis protection swaps	—			(0.2		)
Natural gas fixed price swaps and collars	(1.6		)	0.1
Natural gas basis protection swaps	(4.0		)	2.6
NGLs (propane portion) fixed price swaps	—			(1.7		)
Total net settlements of commodity derivative instruments	(8.5		)	(26.0		)
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments	(18.5		)	20.3
Crude oil fixed price swaps, collars and rollfactors	(159.4		)	(52.6		)
Natural gas fixed price swaps and collars	(0.3		)	(0.8		)
Natural gas basis protection swaps	(3.4		)	10.6
NGLs (propane portion) fixed price swaps	—			1.3
Net change in fair value of unsettled commodity derivative instruments	(181.6		)	(21.2		)
Total commodity price risk management loss, net	$	(190.1	)	$	(47.2	)

Lease Operating Expenses

Lease operating expenses increased 19 percent to $35.2 million in the three months ended March 31, 2019 compared to $29.6 million in the three months ended March 31, 2018. The increase was primarily due to a 26 percent increase in production volumes. Significant changes in lease operating expenses included increases of $1.4 million for produced water disposal expense, $1.1 million in additional compressor and equipment rentals related to the increase in wells turned-in-line, $0.9 million related to midstream expense, $0.9 million in environmental remediation expense and $0.6 million for payroll and employee benefits primarily related to increases in headcount. Lease operating expense per Boe decreased by six percent to $3.14 for the three months ended March 31, 2019 from $3.33 for the three months ended March 31, 2018.

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 increased 10 percent to $22.2 million in the three months ended March 31, 2019 compared to $20.2 million in the three months ended March 31, 2018, primarily due to the five percent increase in crude oil, natural gas and NGLs sales for the three months ended March 31, 2019 compared to the three months ended March 31, 2018.

Transportation, Gathering and Processing Expenses

Transportation, gathering and processing expenses increased 56 percent to $11.4 million in the three months ended March 31, 2019 compared to the three months ended March 31, 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.

Impairment of Properties and Equipment

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



	Three Months Ended March 31,
	2019		2018
	(in millions)

Impairment of proved and unproved properties	$	7.9	$	33.1
Amortization of individually insignificant unproved properties	—		0.1
Impairment of crude oil and natural gas properties	$	7.9	$	33.2

During the three months ended March 31, 2019 and 2018, we recorded impairment charges primarily related to the divestiture of leaseholds and leasehold expirations within our non-focus areas of the Delaware Basin where we were no longer pursuing plans to develop the properties.

General and Administrative Expense

General and administrative expense increased 11 percent to $39.6 million in the three months ended March 31, 2019 compared to $35.7 million in the three months ended March 31, 2018. The increase was primarily attributable to a $2.2 million increase in legal-related costs, which include costs related to the marketing of our Delaware Basin midstream assets and proxy-related activities, and a $1.6 million increase related to professional services.

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 $149.9 million for the three months ended March 31, 2019 compared to $124.8 million for the three months ended March 31, 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 March 31, 2019
	(in thousands)
Increase in production	$	34,551
Decrease in weighted-average depreciation, depletion and amortization rates	(9,427		)
Total increase in DD&A expense related to crude oil and natural gas properties	$	25,124

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



	Three Months Ended March 31,
Operating Region/Area	2019		2018
	(per Boe)
Wattenberg Field	$	12.44	$	13.53
Delaware Basin	17.08		16.91
Total weighted-average	$	13.37	$	14.01

Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $1.5 million for the three months ended March 31, 2019 compared to $2.0 million for the three months ended March 31, 2018.

Interest Expense

Interest expense decreased $0.6 million to $17.0 million for the three months ended March 31, 2019 compared to $17.5 million for the three months ended March 31, 2018. The decrease was primarily related to a $1.2 million increase in capitalized interest. The decrease was partially offset by a $0.5 million increase in interest related to our revolving credit facility.

Provision for Income Taxes

The effective income tax rates for the three months ended March 31, 2019 were a 23.7 percent benefit on the loss before income taxes compared to a 25.8 percent benefit on the loss before income taxes for the three months ended March 31, 2018. The effective income tax rates are based upon a full year forecasted pre-tax income for the year adjusted for permanent differences. The forecasted full year effective income tax rate has been applied to the quarterly pre-tax loss, resulting in an income tax benefit for the period. The quarterly rates are proportionately impacted by updates to previously-forecasted pre-tax earnings.

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

The factors resulting in net loss in the three months ended March 31, 2019 of $120.2 million and a net loss in the three months ended March 31, 2018 of $13.1 million are discussed above, with the net change in the fair value of unsettled commodity derivatives having the most significant impact. Adjusted net income, a non-U.S. GAAP financial measure, was $18.0 million for the three months ended March 31, 2019 and $3.0 million for the three months ended March 31, 2018. With the exception of the tax-affected net change in fair value of unsettled derivatives of $138.2 million for the three months ended March 31, 2019, and $16.1 million for the three months ended March 31, 2018, these 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 three months ended March 31, 2019, our net cash flows from operating activities were $181.9 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.

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

From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as of March 31, 2019 is an indication of a lack of liquidity. We had working capital deficits of $277.4 million and $166.6 million at March 31, 2019 and December 31, 2018, respectively. The increase in the working capital deficit as of March 31, 2019 of $110.8 million is primarily the result of a decrease in the net fair value of our unsettled commodity derivative instruments of $111.7 million and an increase in accounts payable of $33.7 million related to our increased development activities. The changes were partially offset by the decrease in funds held for distribution of $14.2 million and an increase in accounts receivable of $9.4 million primarily related to our crude oil, natural gas and NGLs sales. 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 $1.1 million at March 31, 2019 and availability under our revolving credit facility was $1.2 billion, providing for a total liquidity position of $1.2 billion as of March 31, 2019. Based on our current production forecast for 2019 and our average 2019 price assumptions of $55.00 for NYMEX crude oil and $3.00 for NYMEX natural gas, we expect 2019 cash flows from operations to exceed our capital investments in crude oil and natural gas properties by approximately $65.0 million.

In April 2019, our Board of Directors approved the Program to acquire up to $200 million of our outstanding common stock, depending on market conditions. The Program is expected to begin in the third quarter of 2019 with a target completion date of December 31, 2020. We currently project that we will generate a sufficient level of free cash flow in this period to fund the Program while maintaining the ability to pursue additional future return of capital programs, depending on market conditions. Repurchases under the Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board of Directors 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 based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests.

The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. At March 31, 2019, we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.1:1.0 and a leverage ratio of 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 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. See the footnote titled Long-Term Debt to the

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accompanying condensed consolidated financial statements included elsewhere in this report for more information regarding our revolving credit facility.

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 decreased by $23.3 million to $181.9 million for the three months ended March 31, 2019 compared to the three months ended March 31, 2018, primarily due to a decrease in changes in assets and liabilities of $40.8 million, as well as increases in lease operating expenses of $5.6 million, transportation, gathering and processing expense of $4.1 million, general and administrative expenses of $3.9 million and production taxes of $2.0 million. These changes were partially offset by increases in commodity derivative settlements of $17.6 million and crude oil, natural gas and NGLs sales of $15.9 million.

Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $17.7 million to $192.6 million during the three months ended March 31, 2019 compared to the three months ended March 31, 2018. The increase was primarily due to the same 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 three months ended March 31, 2019, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $209.2 million compared to $190.1 million for the comparable period in 2018. The 10 percent increase in our adjusted EBITDAX for the three months ended March 31, 2019 as compared to the three months ended March 31, 2018 was primarily due to the increase in crude oil, natural gas and NGLs sales of $15.9 million and a decrease in the loss on commodity derivative settlements of $17.6 million. The increase was partially offset by an increase in operating costs of $15.6 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 $271.7 million during the three months ended March 31, 2019 was primarily related to our drilling and completion activities of $266.9 million. Net cash used in investing activities of $338.5 million during the three months ended March 31, 2018 was primarily related to cash utilized toward the purchase price of the Bayswater Acquisition of $180.8 million and our drilling and completion activities of $196.9 million. Partially offsetting these investments was the receipt of approximately $39.0 million related to the Utica Shale Divestiture.

Financing Activities. Net cash received from financing activities of $89.5 million during the three months ended March 31, 2019 was primarily comprised of net borrowings from our credit facility of $91.5 million.

Off-Balance Sheet Arrangements

At March 31, 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.

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 condensed

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consolidated financial statements and accompanying notes contained in our 2018 Form 10-K filed with the SEC on February 28, 2019.

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Reconciliation of Non-U.S. GAAP Financial Measures

We use "adjusted cash flows from operations," "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, providing public guidance on possible future results. These 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. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help 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 not rely on any single financial measure.

Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has generally been a timing issue from one period to the next as we have not had significant accounts receivable collection problems, nor been unable to purchase assets or pay our obligations.

Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives and net settlements on commodity derivatives, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of unsettled derivatives. Additionally, other items which are not indicative of future results may be excluded to clearly identify operating trends.

Adjusted EBITDAX. We define adjusted EBITDAX as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of properties and equipment, exploration, geologic and geophysical expense, depreciation, depletion and amortization expense, accretion of asset retirement obligations and non-cash stock-based compensation, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDAX is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), and should not be considered an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDAX includes certain non-cash costs incurred by us and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDAX differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDAX is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts and others to analyze such things as:


•	operating performance and return on capital as compared to our peers;


•	financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis;


•	our ability to generate sufficient cash to service our debt obligations; and


•	the viability of acquisition opportunities and capital expenditure projects, including the related rate of return.

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PDC ENERGY, INC.

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



	Three Months Ended March 31,
	2019			2018
	(in millions)
Adjusted cash flows from operations:
Net cash from operating activities	$	181.9		$	205.1
Changes in assets and liabilities	10.7			(30.2		)
Adjusted cash flows from operations	$	192.6		$	174.9

Adjusted net income:
Net loss	$	(120.2	)	$	(13.1	)
Loss on commodity derivative instruments	190.1			47.2
Net settlements on commodity derivative instruments	(8.5		)	(26.0		)
Tax effect of above adjustments	(43.4		)	(5.1		)
Adjusted net income	$	18.0		$	3.0

Net loss to adjusted EBITDAX:
Net loss	$	(120.2	)	$	(13.1	)
Loss on commodity derivative instruments	190.1			47.2
Net settlements on commodity derivative instruments	(8.5		)	(26.0		)
Non-cash stock-based compensation	4.7			5.3
Interest expense, net	17.0			17.4
Income tax benefit	(37.4		)	(4.6		)
Impairment of properties and equipment	7.9			33.2
Exploration, geologic and geophysical expense	2.6			2.6
Depreciation, depletion and amortization	151.4			126.8
Accretion of asset retirement obligations	1.6			1.3
Adjusted EBITDAX	$	209.2		$	190.1

Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities	$	181.9		$	205.1
Interest expense, net	17.0			17.4
Amortization of debt discount and issuance costs	(3.3		)	(3.2		)
Gain (loss) on sale of properties and equipment	0.4			(1.4		)
Exploration, geologic and geophysical expense	2.6			2.6
Other	(0.1		)	(0.2		)
Changes in assets and liabilities	10.7			(30.2		)
Adjusted EBITDAX	$	209.2		$	190.1

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PDC ENERGY, INC.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market-Sensitive Instruments and Risk Management

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

Interest Rate Risk

Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 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 March 31, 2019, our interest-bearing deposit accounts included money market accounts and checking accounts with various banks. The amount of our interest-bearing cash, cash equivalents and restricted cash as of March 31, 2019 was $0.6 million with a weighted-average interest rate of 1.4 percent. Based on a sensitivity analysis of our interest-bearing deposits as of March 31, 2019 and assuming we had $0.6 million outstanding throughout the period, we estimate that a one percent increase in interest rates would not have had a material impact on interest income for the three months ended March 31, 2019.

As of March 31, 2019, we had a $124.0 million outstanding balance on our revolving credit facility. If market interest rates would have increased or decreased one percent, our interest expense for the three months ended March 31, 2019 would have changed by approximately $0.3 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. See the footnote titled Commodity Derivative Financial Instruments to our condensed consolidated financial statements included elsewhere in this report for a description of our open commodity derivative positions at March 31, 2019.

Our realized prices vary regionally based on local market differentials and our transportation agreements. The following table presents average market index prices for crude oil and natural gas for the periods identified, as well as the average sales prices we realized for our crude oil, natural gas and NGLs production:



	Three Months Ended		Year Ended
	March 31, 2019		December 31, 2018
Average NYMEX Index Price:
Crude oil (per Bbl)	$	54.90	$	64.77
Natural gas (per MMBtu)	3.15		3.09

Average Sales Price Realized:
Excluding net settlements on commodity derivatives
Crude oil (per Bbl)	$	51.06	$	61.19
Natural gas (per Mcf)	2.05		1.85
NGLs (per Bbl)	15.55		22.14

Based on a sensitivity analysis as of March 31, 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 $68.6 million, whereas a ten percent decrease in prices would have resulted in an increase in fair value of $68.5 million.

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PDC ENERGY, INC.

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.

Our oil and gas exploration and production business's crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers.

We 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. See the footnote titled Commodity Derivative Financial Instruments to our condensed consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial instruments.

Disclosure of Limitations

Because the information above included only those exposures that existed at March 31, 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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of March 31, 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 March 31, 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 March 31, 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.

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PDC ENERGY, INC.

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 quarter ended March 31, 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 hiring additional personnel with relevant experience, increased layers of supervision, 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 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 March 31, 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 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. 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, except for the following:

Our business could be negatively affected as a result of actions of activist shareholders

Activist shareholders, such as Kimmeridge, may from time to time attempt to effect changes, engage in proxy solicitations or advance shareholder proposals. Activist shareholders may make strategic proposals and seek to effect changes concerning our operations, strategy, management and other matters. Engaging in a proxy fight and responding to shareholder activism can be costly and time-consuming, disrupting our operations and diverting the attention of management and our

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employees. Activist campaigns can create perceived uncertainties as to our future direction, strategy and leadership and may result in the loss of potential business opportunities, harm our ability to pursue certain transactions and cause our stock price to experience periods of volatility.

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)	Average Price Paid per Share

January 1 - 31, 2019	27,069	$	32.83
February 1 - 28, 2019	14,718	38.81
March 1 - 31, 2019	—	—
Total first quarter 2019 purchases	41,787	$	34.94

__________


(1)	Purchases represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans.

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.

99.1

Form of 2019 Performance Share Agreement.

99.2

Form of 2019 Restricted Stock Unit Agreement (Directors).

99.3

Form of 2019 Restricted Stock Unit Agreement (Executives) (Amended and Restated 2010 Long-Term Equity Compensation Plan).

99.4

Form of 2019 Restricted Stock Unit Agreement (Executives) (2018 Equity Incentive Plan).

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

* Furnished herewith.

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PDC ENERGY, INC.

SIGNATURES

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



	PDC Energy, Inc.
	(Registrant)




Date: May 1, 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)