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 ~~September~~June 30, ~~2016~~2017

£ 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 and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 and post 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, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated ~~filer"~~filer," "smaller reporting company," and ~~"smaller reporting~~"emerging growth company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer x	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	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: ~~56,266,147~~65,865,441 shares of the Company's Common Stock ($0.01 par value) were outstanding as of ~~October 17, 2016.~~July 20, 2017.

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PDC ENERGY, INC.

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	PART I – FINANCIAL INFORMATION	Page

Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets (unaudited)	1
	Condensed Consolidated Statements of Operations (unaudited)	2
	Condensed Consolidated Statements of Cash Flows (unaudited)	3
	Condensed Consolidated ~~Statements~~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	2427
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4046
Item 4.	Controls and Procedures	4249

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	4249
Item 1A.	Risk Factors	4250
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4350
Item 3.	Defaults Upon Senior Securities	4350
Item 4.	Mine Safety Disclosures	4350
Item 5.	Other Information	4350
Item 6.	Exhibits	4451

	SIGNATURES	4552

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") ~~and~~, Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"), and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations, and prospects. All statements other than statements of historical ~~facts~~fact included in and incorporated by reference into this report are "forward-looking ~~statements" within the meaning of the safe harbor provisions of the United States ("U.S.~~statements."~~) Private Securities Litigation Reform Act of 1995.~~ Words such as expects, anticipates, intends, plans, believes, seeks, estimates, and similar expressions or variations of such words are intended to identify forward-looking statements herein. ~~These~~Forward-looking statements ~~relate to,~~may include, among other things: the closing of pending transactions and the effects of such transactions, including the fact that the pending Delaware Basin acquisition is subject to continuing diligence between the parties and accordingly, may not occur within the expected timeframe or at all; estimated futurethings, statements regarding future: reserves, production, ~~(including the components of such production), sales, expenses,~~costs, cash flows, ~~liquidity~~ and ~~balance sheet attributes; estimated crude oil, natural gas~~earnings; drilling locations and ~~natural gas liquids (“NGLs”) reserves; the impact of prolonged depressed commodity prices,~~growth opportunities; capital investments and projects, including ~~potentially reduced production and associated cash flow; anticipated capital projects, expenditures and opportunities;~~ expected capital budget allocations; our operational flexibility and ability to revise our development plan, either upward or downward; availability of sufficient funding and liquidity for our capital program and sources of that funding; expected positive net settlements on derivatives for the remainder of 2016; that we expect quarter-over-quarter production growth; future exploration, drilling and development activities, including non-operated activity, the number of drilling rigs we expect to run and lateral lengths of wells, ~~including the~~drill times and number of rigs ~~we expect to run in 2017 in the Delaware Basin; expected 2016 production~~employed; rates of return; operational enhancements and ~~cash flow ranges~~efficiencies; management of lease expiration issues; financial ratios; and ~~timing of turn-in-lines; our evaluation method of our customers'~~midstream capacity and derivative counterparties' credit risk; effectiveness of our derivative program in providing a degree of price stability; potential for future impairments; expected sustained relief of gathering system pressure; compliance with debt covenants; impact of litigation on our results of operations and financial position; that we do not expect to pay dividends in the foreseeable future; and our future strategies, plans and objectives.related curtailments.

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 terms “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 ~~the~~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 worldwide production volumes and demand, including economic conditions that might impact ~~demand;~~demand and prices for the products we produce;

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

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 ~~related to~~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 ~~further~~ 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;

losses from our gas marketing business exceeding our expectations;

difficulties in integrating our operations as a result of any significant acquisitions, including our recent acquisitions in the Delaware Basin;

increases or changes in operating costs, severance and ad valorem taxes, and increases or changes in drilling, completion, and facilities costs;

potential losses of acreage due to lease expirations or otherwise;

increases or adverse changes in construction costs and procurement costs associated with future build out of midstream-related assets;

future cash flows, liquidity, and financial condition;

competition within the oil and gas industry;

availability and cost of capital;

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

effect of crude oil and natural gas derivatives activities;

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

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cost of pending or future litigation, including recent environmental litigation;

effect that acquisitions we may pursue have on our capital ~~expenditures;~~investments;

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, ~~2015~~2016 (the ~~"2015~~"2016 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February ~~22, 2016,~~28, 2017, 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

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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"~~"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. ~~See Note 1,~~ ~~Nature of Operations and Basis of Presentation, to our condensed consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries.~~

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PDC ENERGY, INC.

Condensed Consolidated Balance Sheets

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


	September 30, 2016			December 31, 2015			June 30, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	1,197,692		$	850		$	202,291		$	244,100
Accounts receivable, net	99,895			104,274			135,203			143,392
Fair value of derivatives	65,604			221,659			52,105			8,791
Prepaid expenses and other current assets	4,854			5,266			6,619			3,542
Total current assets	1,368,045			332,049			396,218			399,825
Properties and equipment, net	1,932,274			1,940,552			4,165,572			4,008,266
Fair value of derivatives	8,423			44,387			16,397			2,386
Goodwill							56,331			62,041
Other assets	108,538			53,555			22,410			13,324
Total Assets	$	3,417,280		$	2,370,543		$	4,656,928		$	4,485,842

Liabilities and Shareholders' Equity
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	62,350		$	92,613		$	152,492		$	66,322
Production tax liability	22,141			26,524			35,296			24,767
Fair value of derivatives	22,563			1,595			10,138			53,595
Funds held for distribution	51,107			29,894			86,846			71,339
Current portion of long-term debt	—			112,940
Accrued interest payable	19,364			9,057			15,955			15,930
Other accrued expenses	41,756			28,709			29,939			38,625
Total current liabilities	219,281			301,332			330,666			270,578
Long-term debt	1,041,575			529,437			1,049,004			1,043,954
Deferred income taxes	44,340			143,452			452,028			400,867
Asset retirement obligation	82,509			84,032
Asset retirement obligations							77,867			82,612
Fair value of derivatives	17,885			695			2,311			27,595
Other liabilities	25,630			24,398			30,610			37,482
Total liabilities	1,431,220			1,083,346			1,942,486			1,863,088

Commitments and contingent liabilities

Shareholders' equity
Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued	—			—
Common shares - par value $0.01 per share, 150,000,000 authorized, 56,280,544 and 40,174,776 issued as of September 30, 2016 and December 31, 2015, respectively	563			402
Stockholders' equity
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,927,104 and 65,704,568 issued as of June 30, 2017 and December 31, 2016, respectively							659			657
Additional paid-in capital	1,796,664			907,382			2,495,940			2,489,557
Retained earnings	190,133			380,422			221,604			134,208
Treasury shares - at cost, 25,854 and 20,220 as of September 30, 2016 and December 31, 2015, respectively	(1,300		)	(1,009		)
Total shareholders' equity	1,986,060			1,287,197
Total Liabilities and Shareholders' Equity	$	3,417,280		$	2,370,543
Treasury shares - at cost, 64,024 and 28,763 as of June 30, 2017 and December 31, 2016, respectively							(3,761		)	(1,668		)
Total stockholders' equity							2,714,442			2,622,754
Total Liabilities and Stockholders' Equity							$	4,656,928		$	4,485,842

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PDC ENERGY, INC.

Condensed Consolidated Statements of Operations

(unaudited; in thousands, except per share data)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
Revenues
Crude oil, natural gas and NGLs sales	$	141,805		$	104,483		$	328,013		$	275,520
Sales from natural gas marketing	2,678			2,580			6,728			8,336
Commodity price risk management gain (loss), net	19,397			123,549			(62,348		)	141,170
Well operations, pipeline income and other	10			488			2,425			1,666
Crude oil, natural gas, and NGLs sales													$	213,602		$	110,841		$	403,294		$	186,208
Commodity price risk management gain (loss), net of settlements													57,932			(92,801		)	138,636			(81,745		)
Other income													3,624			2,057			6,935			6,465
Total revenues	163,890			231,100			274,818			426,692			275,158			20,097			548,865			110,928
Costs, expenses and other
Lease operating expenses	14,001			13,825			43,006			42,749			20,028			13,675			39,817			29,005
Production taxes	9,568			5,476			19,682			13,206			15,042			6,043			27,441			10,114
Transportation, gathering and processing expenses	5,048			3,938			13,554			6,584			6,488			4,465			12,390			8,506
Cost of natural gas marketing	3,092			2,781			7,795			8,875
Exploration expense	241			252			688			812
General and administrative expense													29,531			23,579			55,846			46,358
Exploration, geologic, and geophysical expense													1,033			237			1,987			447
Depreciation, depletion and amortization													126,013			107,014			235,329			204,402
Impairment of properties and equipment	933			154,031			6,104			161,207			27,566			4,170			29,759			5,171
General and administrative expense	32,510			20,277			78,868			62,050
Depreciation, depletion and amortization	112,927			80,947			317,329			206,873
Accretion of asset retirement obligations													1,666			1,811			3,434			3,623
(Gain) loss on sale of properties and equipment													(532		)	260			(692		)	176
Provision for uncollectible notes receivable	(700		)	—			44,038			—			(40,203		)	—			(40,203		)	44,738
Accretion of asset retirement obligations	1,777			1,594			5,400			4,742
Gain on sale of properties and equipment	(219		)	(74		)	(43		)	(302		)
Total cost, expenses and other	179,178			283,047			536,421			506,796
Loss from operations	(15,288		)	(51,947		)	(261,603		)	(80,104		)
Other expenses													3,890			2,125			7,418			4,703
Total costs, expenses and other													190,522			163,379			372,526			357,243
Income (loss) from operations													84,636			(143,282		)	176,339			(246,315		)
Interest expense	(20,193		)	(12,092		)	(42,759		)	(35,384		)	(19,617		)	(10,672		)	(39,084		)	(22,566		)
Interest income	140			1,378			1,875			3,626			768			177			1,008			1,735
Loss before income taxes	(35,341		)	(62,661		)	(302,487		)	(111,862		)
Provision for income taxes	12,032			21,167			112,198			40,560
Net loss	$	(23,309	)	$	(41,494	)	$	(190,289	)	$	(71,302	)
Income (loss) before income taxes													65,787			(153,777		)	138,263			(267,146		)
Income tax (expense) benefit													(24,537		)	58,327			(50,867		)	100,166
Net income (loss)													$	41,250		$	(95,450	)	$	87,396		$	(166,980	)

Earnings per share:
Basic	$	(0.48	)	$	(1.04	)	$	(4.16	)	$	(1.84	)	$	0.63		$	(2.04	)	$	1.33		$	(3.78	)
Diluted	$	(0.48	)	$	(1.04	)	$	(4.16	)	$	(1.84	)	$	0.62		$	(2.04	)	$	1.32		$	(3.78	)

Weighted-average common shares outstanding:
Basic	48,839			40,085			45,741			38,837			65,859			46,742			65,804			44,175
Diluted	48,839			40,085			45,741			38,837			66,019			46,742			66,066			44,175

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PDC ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(unaudited; in thousands)


	Nine Months Ended September 30,						Six Months Ended June 30,
	2016			2015			2017			2016
Cash flows from operating activities:
Net loss	$	(190,289	)	$	(71,302	)
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled derivatives	230,177			21,322
Net income (loss)							$	87,396		$	(166,980	)
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives							(126,070		)	201,825
Depreciation, depletion and amortization	317,329			206,873			235,329			204,402
Impairment of properties and equipment							29,759			5,171
Provision for uncollectible notes receivable	44,038			—			(40,203		)	44,738
Impairment of properties and equipment	6,104			161,207
Accretion of asset retirement obligation	5,400			4,742
Stock-based compensation	15,205			14,278
Gain on sale of properties and equipment	(43		)	(302		)
Accretion of asset retirement obligations							3,434			3,623
Non-cash stock-based compensation							9,826			11,126
(Gain) loss on sale of properties and equipment							(692		)	176
Amortization of debt discount and issuance costs	12,951			5,308			6,399			3,077
Deferred income taxes	(114,136		)	(44,770		)	50,767			(102,319		)
Non-cash interest income	(1,194		)	(3,624		)
Other	668			(174		)	670			(1,287		)
Changes in assets and liabilities	34,621			(10,552		)	6,582			(5,754		)
Net cash from operating activities	360,831			283,006			263,197			197,798
Cash flows from investing activities:
Capital expenditures	(353,722		)	(489,036		)
Acquisition of crude oil and natural gas properties	(100,000		)	—
Capital expenditures for development of crude oil and natural gas properties							(334,406		)	(234,677		)
Capital expenditures for other properties and equipment							(2,299		)	(1,030		)
Acquisition of crude oil and natural gas properties, including settlement adjustments							5,372			—
Proceeds from sale of properties and equipment	4,945			319			1,293			4,903
Sale of promissory note							40,203			—
Restricted cash							(9,250		)	—
Sale of short-term investments							49,890			—
Purchase of short-term investments							(49,890		)	—
Net cash from investing activities	(448,777		)	(488,717		)	(299,087		)	(230,804		)
Cash flows from financing activities:
Proceeds from sale of equity, net of issuance cost	855,072			202,851
Proceeds from senior notes	392,250			—
Proceeds from convertible senior notes	193,979			—
Proceeds from issuance of equity, net of issuance cost							—			296,575
Proceeds from revolving credit facility	85,000			325,000			—			85,000
Repayment of revolving credit facility	(122,000		)	(331,000		)	—			(122,000		)
Redemption of convertible notes	(115,000		)	—			—			(115,000		)
Purchase of treasury shares							(5,274		)	(4,055		)
Other	(4,513		)	(3,516		)	(645		)	735
Net cash from financing activities	1,284,788			193,335			(5,919		)	141,255
Net change in cash and cash equivalents	1,196,842			(12,376		)	(41,809		)	108,249
Cash and cash equivalents, beginning of period	850			16,066			244,100			850
Cash and cash equivalents, end of period	$	1,197,692		$	3,690		$	202,291		$	109,099

Supplemental cash flow information:
Cash payments for:
Cash payments (receipts) for:
Interest, net of capitalized interest	$	22,975		$	23,467		$	32,647		$	19,988
Income taxes	167			9,936			(39		)	167
Non-cash investing and financing activities:
Change in accounts payable related to purchases of properties and equipment	$	(31,497	)	$	(68,529	)	$	81,891		$	(28,999	)
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals	1,137			1,642
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals							2,415			843
Purchase of properties and equipment under capital leases	1,231			1,479			2,160			1,074

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PDC ENERGY, INC.

Condensed Consolidated ~~Statements~~Statement of Equity

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

Nine Months Ended September 30, 2016 2015
Common shares, issued:
Shares beginning of period 40,174,776
35,927,985
Shares issued pursuant to sale of equity 15,799,906
4,002,000
Exercise of stock options 46,084
—
Issuance of stock awards, net of forfeitures 259,778
191,623
Shares end of period 56,280,544
40,121,608
Treasury shares:
Shares beginning of period 20,220
21,643
Purchase of treasury shares 90,695
93,898
Issuance of treasury shares (91,895 ) (97,995 )
Non-employee directors' deferred compensation plan 6,834
4,872
Shares end of period 25,854
22,418
Common shares outstanding 56,254,690
40,099,190

Equity:
Shareholders' equity
Preferred shares, par value $0.01 per share:
Balance beginning and end of period $ —
$ —
Common shares, par value $0.01 per share:
Balance beginning of period 402
359
Shares issued pursuant to sale of equity and note conversion 158
40
Issuance of stock awards, net of forfeitures 3
2
Balance end of period 563
401
Additional paid-in capital:
Balance beginning of period 907,383
689,209
Convertible debt discount, net of issuance costs and tax 23,264
—
Proceeds from sale of equity, net of issuance costs 854,932
202,811
Stock-based compensation expense 15,202
14,419
Issuance of treasury shares (5,180 ) (4,633 )
Tax impact of stock-based compensation 1,063
1,232
Balance end of period 1,796,664
903,038
Retained earnings:
Balance beginning of period 380,422
448,702
Net loss (190,289 ) (71,302 )
Balance end of period 190,133
377,400
Treasury shares, at cost:
Balance beginning of period (1,009 ) (911 )
Purchase of treasury shares (5,106 ) (4,575 )
Issuance of treasury shares 5,179
4,632
Non-employee directors' deferred compensation plan (364 ) (249 )
Balance end of period (1,300 ) (1,103 )
Total shareholders' equity $ 1,986,060
$ 1,279,736



	Common Stock							Treasury Stock
	Shares		Amount		Additional Paid-in Capital			Shares		Amount			Retained Earnings			Total Stockholders' Equity

Balance, December 31, 2016	65,704,568		$	657	$	2,489,557		(28,763	)	$	(1,668	)	$	134,208		$	2,622,754
Net income	—		—		—			—		—			87,396		87,396,000	87,396
Issuance pursuant to acquisition	—		—		(82		)	—		—			—			(82		)
Issuance pursuant to sale of equity	—		—		(7		)	—		—			—			(7		)
Convertible debt discount, net of issuance costs and tax	—		—		(2		)	—		—			—			(2		)
Purchase of treasury shares	—		—		—			(79,381	)	(5,274		)	—			(5,274		)
Issuance of treasury shares	(46,822	)	2		(3,350		)	46,822		3,350			—			2
Non-employee directors' deferred compensation plan	—		—		(2		)	(2,702	)	(169		)	—			(171		)
Issuance of stock awards, net of forfeitures	269,358		—		—			—		—			—			—
Stock-based compensation expense	—		—		9,826			—		—			—			9,826
Balance, June 30, 2017	65,927,104		$	659	$	2,495,940		(64,024	)	$	(3,761	)	$	221,604		$	2,714,442

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September~~June 30, ~~2016~~2017

(unaudited)

NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION

PDC Energy, Inc. ~~(the~~("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production company that produces, develops, ~~acquires~~ and explores for crude oil, natural gas, and NGLs, with primary operations in the Wattenberg Field in Colorado and, beginning in December 2016, the Delaware Basin in Reeves and Culberson Counties, Texas. We also have operations in the Utica Shale in ~~southeastern~~Southeastern Ohio. Subsequent to June 30, 2017, as part of plans to divest the Utica Shale properties, we engaged an investment banking group to assist in marketing them for sale; therefore, these properties will be classified as held-for-sale upon meeting the criteria for such classification in the third quarter of 2017. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our ~~Ohio~~Delaware Basin operations are currently focused in the ~~Utica Shale play. In addition, we currently have a pending acquisition in the Delaware Basin in Texas. See Note 6,~~ ~~Pending Acquisition~~.Wolfcamp zones. As of ~~September~~June 30, ~~2016,~~2017, we owned an interest in approximately ~~3,000~~2,900 gross productive wells. We are engaged in two ~~business~~operating segments: ~~Oil~~our oil and ~~Gas Exploration~~gas exploration and ~~Production~~production segment and ~~Gas Marketing.~~our gas marketing segment. Beginning in 2017, 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 ~~subsidiary Riley Natural Gas ("RNG")~~subsidiaries, and our proportionate share of our ~~four~~two 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~~consisting of ~~only~~ normal recurring ~~adjustments)~~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, ~~2015~~2016 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 ~~2015~~2016 Form 10-K. Our results of operations and cash flows for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain immaterial reclassifications have been made to our prior period statement of operations to conform to the current period presentation. The reclassifications had no impact on previously reported cash flows, net earnings, earnings per share or stockholders' equity.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Recently Issued Accounting Standards

In May 2014, the ~~Financial Accounting Standards Board ("FASB")~~FASB and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations, and (5) recognize revenue when ~~(or as)~~or as each performance obligation is satisfied. In March 2016, the FASB issued an update to the standard intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations when recognizing revenue. In December 2016, the FASB issued technical corrections and improvements to the standard. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are ~~currently evaluating~~in the ~~impact these changes may have~~process of assessing potential impacts of the new standard on our ~~condensed consolidated financial statements.~~existing revenue recognition criteria, as well as on related revenue recognition disclosures.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard requires management to assess an entity's ability to continue as a going concern at the end of every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. We expect to adopt this standard in the fourth quarter of 2016. Adoption of this standard is not expected to have a significant impact on our condensed consolidated financial statements.

In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. For leases with terms of more than 12 months, the accounting update requires lessees to recognize ana right-of-use asset and lease liability for its right to use the underlying asset and ~~a lease liability for~~ the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. We are ~~currently evaluating~~in the process of assessing the impact these changes may have on our ~~condensed consolidated financial statements.~~

In March 2016, the FASB issued an accounting update on stock-based compensation intended to simplify several aspects of the accounting for employee share-based payment award transactions. Areas of simplification include income tax consequences, classification of the awards as either equity or liabilities and the classification on the statement of cash flows. The guidance is effective for fiscal years beginning

~~Table of contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2016~~

~~(unaudited)~~

after December 15, 2016, and interim periods within those years, with early adoption permitted. We expect to adopt this standard in the fourth quarter of 2016. Adoption of this standard is not expected to have a significant impact on our condensed consolidated financial statements.

In August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.

In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements.

In January 2017, the FASB issued an accounting update to simplify the subsequent measurement of goodwill. The update eliminates the two-step process that required identification of potential impairment and a separate measure of actual impairment. The annual and/or interim assessments are still required to be completed. The guidance is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the second quarter of 2017 and will implement the new guidance accordingly in performing impairment testing in 2017. Our annual evaluation of goodwill for impairment is expected to occur in the fourth quarter of 2017, at which time we will apply this accounting update and the impact can be determined.

In May 2017, the FASB issued an accounting update clarifying when to account for a change to the terms or conditions of a share-based payment award as a modification. The guidance is effective for fiscal years beginning on or after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Adoption of this standard is not expected to have a significant impact on our condensed consolidated financial statements.

NOTE 3 - ~~FAIR VALUE OF FINANCIAL INSTRUMENTS~~BUSINESS COMBINATION

~~Determination~~Delaware Basin Acquisition. On December 6, 2016, we closed on an acquisition which has been accounted for as a business combination. The transaction was for the purchase of ~~Fair Value~~

~~Our~~approximately 57,900 net acres, approximately 30 completed and producing wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion, after preliminary post-closing adjustments, comprised of approximately $946.0 million in cash, including the payment of $40.0 million of debt of the seller at closing and other purchase price adjustments, and 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed. The estimated fair value ~~measurements~~of assets acquired and liabilities assumed in the acquisition presented below are ~~estimated pursuant~~preliminary and subject to ~~a fair value hierarchy that requires us to maximize~~customary additional post-closing adjustments as more detailed analysis associated with the ~~use~~acquired properties is completed. The final settlement statement has been agreed upon with the sellers; however, we are in the process 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 offinalizing 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 valuationvalues of the assets acquired and liabilities assumed and ~~their placement within~~expect to keep the ~~fair value hierarchy levels.~~transaction open through the third quarter of 2017 to ensure that any final allocation adjustments associated with the period through final settlement are appropriately reflected in the final purchase price allocation. The ~~three levels of inputs that may~~most significant item to 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~~completed is 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~~allocation of the ~~underlying position, current market prices, crude oil~~per acre values across the acquisition. There were a significant number of leases acquired with complex lease terms 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, the determination that the source of the inputs is valid, the 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. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September~~June 30, ~~2016~~2017

(unaudited)

~~Our fixed-price swaps, basis swaps and physical purchases are included~~evaluation of these terms may impact the manner in ~~Level 2 and~~which the purchase price allocation across the acquired acreage is finalized based upon lease expiration timing. We expect that the completion of this process will adjust our ~~collars and physical sales are included in Level 3. The following table presents, for each applicable level within~~final determination of the ~~fair~~ value ~~hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:~~

September 30, 2016 December 31, 2015
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)
Assets:
Commodity-based derivative contracts $ 49,021
$ 24,582
$ 73,603
$ 174,657
    $ 91,288
    $ 265,945
Basis protection derivative contracts 424
—
424
101
—
101
Total assets 49,445
24,582
74,027
174,758
91,288
266,046
Liabilities:
Commodity-based derivative contracts 30,917
8,650
39,567
738
—
    738
Basis protection derivative contracts 881
—
881
1,552
—
    1,552
Total liabilities 31,798
8,650
40,448
2,290
—
2,290
Net asset $ 17,647
$ 15,932
$ 33,579
$ 172,468
$ 91,288
$ 263,756

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

Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
(in thousands)
Fair value, net asset beginning of period $ 27,285
$ 58,256
$ 91,288
$ 62,356
Changes in fair value included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net 4,234
38,085
(16,023 ) 42,525
Sales from natural gas marketing —
51
(20 ) 51
Settlements included in statement of operations line items:
Commodity price risk management gain (loss), net (15,587 ) (12,530 ) (59,243 ) (21,063 )
Sales from natural gas marketing —
—
(70 ) (7 )
Fair value, net asset end of period $ 15,932
$ 83,862
$ 15,932
$ 83,862

Net change in fair value of unsettled derivatives included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net $ (2,240 ) $ 34,564
$ (8,273 ) $ 31,794

goodwill.

The ~~significant unobservable input used in~~details of the ~~fair value measurement~~estimated purchase price and the preliminary allocation of ~~our derivative contracts is~~ the ~~implied volatility curve,~~purchase price for the transaction, 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 this report.reflects certain post-closing adjustments, are presented below (in thousands):

~~Non-Derivative Financial Assets and Liabilities~~



	June 30, 2017
Acquisition costs:
Cash, net of cash acquired	$	905,962
Retirement of seller's debt	40,000
Total cash consideration	945,962
Common stock, 9.4 million shares	690,702
Other purchase price adjustments	1,025
Total acquisition costs	$	1,637,689

Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current assets	$	6,561
Crude oil and natural gas properties - proved	216,000
Crude oil and natural gas properties - unproved	1,721,334
Infrastructure, pipeline, and other	33,695
Construction in progress	12,148
Goodwill	56,331
Total assets acquired	2,046,069
Liabilities assumed:
Current liabilities	(23,844		)
Asset retirement obligations	(4,248		)
Deferred tax liabilities, net	(380,288		)
Total liabilities assumed	(408,380		)
Total identifiable net assets acquired	$	1,637,689

The ~~carrying value of the financial instruments included in current assets and current liabilities approximate~~ fair value ~~due to~~measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the ~~short-term maturities~~market, and therefore represent Level 3 inputs. The fair values of ~~these instruments.~~

~~We utilize fair value on a nonrecurring basis to review our~~ crude oil and natural gas properties ~~for possible impairment when events~~ and ~~circumstances indicate~~asset retirement obligations were measured using valuation techniques that convert future cash flows to a ~~possible decline in~~single discounted amount. Significant inputs to the ~~recoverability~~valuation of the carrying value of such properties. 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 properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, lease terms and expirations, and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are the most sensitive and subject to change.

This acquisition was accounted for under the acquisition method. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred.

Goodwill. Goodwill is calculated as the excess of the purchase price over the fair value of net assets acquired and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired were the acquisition of an element of a workforce and the expected value from operations of the Delaware Basin acquisition to be derived in the future. The amount of goodwill that was recorded on a preliminary basis related to the Delaware Basin acquisition has decreased as compared to the initial estimated amount recorded as of December 31, 2016, due to customary purchase price allocations, primarily related to a refund from the sellers in connection with a revised valuation of certain acquired leases and the retirement of estimated environmental remediation liabilities. Such amounts will be ~~sold.~~

finalized with final purchase accounting, as described above. Any value assigned to goodwill is not expected to be deductible for income tax purposes.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September~~June 30, ~~2016~~2017

(unaudited)

The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. The liability related to this plan, which was included in other liabilities on the condensed consolidated balance sheets, was immaterial as of ~~September 30, 2016~~ ~~and December 31, 2015.~~

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, as of ~~September 30, 2016~~, we estimate the fair value of the portion of our long-term debt related to our 1.125% senior notes due 2021 to be $214.8 million, or 107.4% of par value, 6.125% senior notes due 2024 to be $415.6 million, or 103.9% of par value, and 7.75% senior notes due 2022 to be $530.3 million, or 106.1% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs.

~~The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the related vehicle lease.~~

~~Concentration of Risk~~

~~Derivative Counterparties.~~ Our derivative arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no counterparty default losses relating to our derivative arrangements. 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 counterparties on the fair value of our derivative instruments was not significant at September 30, 2016, taking into account the estimated likelihood of nonperformance.

The following table presents the ~~counterparties that expose us~~changes in goodwill:



	Amount
	(in thousands)

Balance at December 31, 2016	$	62,041
Purchase price adjustments, net of tax	(5,710		)
Balance at June 30, 2017	$	56,331

With the creation of goodwill from this transaction, we will perform our evaluation of goodwill for impairment annually or when a triggering event is deemed to ~~credit risk~~have occurred. We evaluate goodwill for impairment by either performing a qualitative evaluation or a quantitative test, which involves comparing the estimated fair value to the carrying value. In either case, the valuation of goodwill will be a significant estimate as such methods incorporate forward-looking assumptions and estimates.

NOTE 4 - PROPERTIES AND EQUIPMENT

The following table presents the components of ~~September 30, 2016~~ ~~with regard to our derivative assets:~~properties and equipment, net of accumulated depreciation, depletion, and amortization ("DD&A"):

Counterparty Name Fair Value of
Derivative Assets
(in thousands)
Canadian Imperial Bank of Commerce (1) $ 21,343
JP Morgan Chase Bank, N.A (1) 17,929
Bank of Nova Scotia (1) 15,166
Wells Fargo Bank, N.A. (1) 9,891
NATIXIS (1) 7,171
Other lenders in our revolving credit facility 2,491
Various (2) 36
Total $ 74,027

~~__________~~

~~(1)Major lender in our revolving credit facility. See Note 8, Long-Term Debt.~~

~~(2)Represents a total of two counterparties.~~



	June 30, 2017			December 31, 2016
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	3,842,942		$	3,499,718
Unproved	1,841,589			1,874,671
Total crude oil and natural gas properties	5,684,531			5,374,389
Infrastructure, pipeline, and other	94,654			62,093
Land and buildings	15,274			12,165
Construction in progress	171,600			122,591
Properties and equipment, at cost	5,966,059			5,571,238
Accumulated DD&A	(1,800,487		)	(1,562,972		)
Properties and equipment, net	$	4,165,572		$	4,008,266

~~Cash~~The following table presents impairment charges recorded for crude oil and ~~Cash Equivalents.We consider all highly liquid instruments purchased with an original maturity of~~natural gas properties:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
	(in thousands)

Impairment of unproved properties	$	27,463	$	1,084	$	29,565	$	2,053
Amortization of individually insignificant unproved properties	103		54		194		86
Impairment of crude oil and natural gas properties	27,566		1,138		29,759		2,139
Land and buildings	—		3,032		—		3,032
Total impairment of properties and equipment	$	27,566	$	4,170	$	29,759	$	5,171

During the three months ended June 30, 2017, we impaired certain unproved Delaware Basin leasehold positions totaling $27.0 million that expired during the three months ending June 30, 2017, or ~~less~~are projected to ~~be cash equivalents. Cash~~expire between June 30, 2017 and ~~cash equivalents potentially subject us~~December 31, 2017. Subsequent to closing the acquisitions in the Delaware Basin, it was determined that development of certain acreage tracts would not meet our internal expectations for acceptable rates of return due to a ~~concentration~~combination of ~~credit risk as substantially all of our deposits held~~weakening commodity prices; higher per well development and operational costs; and updated technical analysis. As a result, we allowed or expect to allow certain acreage to expire, and in ~~financial institutions~~other circumstances we were in excess of the FDIC insurance limits at September 30, 2016. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy.unable to obtain necessary lease term extensions.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September~~June 30, ~~2016~~2017

(unaudited)

~~Notes Receivable.~~ ~~The following table presents information regarding a note receivable outstanding as of September 30, 2016:~~

Amount
(in thousands)
Note receivable:
Principal outstanding, December 31, 2015 $ 43,069
Paid-in-kind interest 969
Principal outstanding, September 30, 2016 44,038
Allowance for uncollectible notes receivable (44,038 )
Note receivable, net $ —

In October 2014, we sold our entire 50% ownership interest in PDCM to an unrelated third-party. As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39 million, bearing interest at varying rates beginning at 8%, and increasing annually. Pursuant to the Note agreement, interest is payable quarterly, in arrears, commencing in December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. As of ~~September 30, 2016~~, the issuer of the Note had elected the PIK Interest option. The principal and any unpaid interest is due and payable in full in September 2020 and can be prepaid in whole or in part at any time without premium or penalty. If an event of default occurs under the Note agreement, the Note must be repaid prior to maturity. Legally, the Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets; however, we believe that collection of the Note is not reasonably assured.

On a quarterly basis, we examine the Note for evidence of impairment, evaluating factors such as the creditworthiness of the issuer of the Note and the value of the underlying assets that secure the Note. We performed our quarterly evaluation and cash flow analysis as of March 31, 2016 and, based upon the unaudited year-end financial statements and reserve report of the issuer of the Note received by us in late March 2016 and existing market conditions, determined that collection of the Note and PIK Interest was not reasonably assured. As a result, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44 million outstanding balance as of March 31, 2016, which was included in the condensed consolidated balance sheet line item other assets. As of September 30, 2016, there has been no change to our assessment of the collectibility of the note or related interest since March 31, 2016. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Note and are accounting for the Note under the cash basis method.

Under the effective interest method, we recognized $1.2 million of interest income related to the Note for the three months ended March 31, 2016, of which $1 million was PIK Interest, and we recognized $1.1 million and $3.4 million of interest income related to the Note for the three and nine months ended September 30, 2015, respectively, of which $0.8 million and $2.4 million, respectively, was PIK Interest.

Additionally, during the three months ended March 31, 2016, we recorded a $0.7 million provision and allowance for uncollectible notes receivable to impair a promissory note related to a previous divestiture as collection of the promissory note was not reasonably assured based on the analysis we performed as of March 31, 2016. In August 2016, we collected the $0.7 million promissory note and reversed the related provision and allowance for uncollectible notes receivable during the three months ended September 30, 2016.

NOTE 45 - 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 utilize the following economic hedging strategies for each~~and propane, which is an element of our ~~business segments.~~

~~For crude oil and natural gas sales,~~NGLs, 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 ~~changes~~decreases in ~~price associated with the derivative~~ commodity prices, they also limit the benefit we might otherwise ~~have received~~receive from price ~~increases in the physical market; and~~increases.

For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative.

We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of ~~September~~June 30, ~~2016~~,2017, we had derivative instruments, which were comprised of collars, fixed-price swaps, and basis protection swaps, ~~and physical sales and purchases,~~ in place for a portion of our anticipated 2017 and 2018 production ~~through 2018~~ for a total of ~~90,425~~12,896 MBbls of crude oil, 82,030 BBtu of natural gas, and

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2016~~

~~(unaudited)~~

~~8,857~~ 643 MBbls of ~~crude oil. The majority of our~~propane. Our commodity derivative contracts ~~are~~have been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market ~~prices.~~prices, without adjustment for premium or discount.

We have not elected to designate any of our derivative instruments as cash flow hedges, and therefore these instruments do not qualify for ~~use of~~ hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the condensed consolidated statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing.

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


			Fair Value						Fair Value
Derivative instruments:	Derivative instruments:	Condensed Consolidated Balance sheet line item	September 30, 2016		December 31, 2015		Derivative instruments:	Condensed consolidated balance sheet line item	June 30, 2017		December 31, 2016
			(in thousands)						(in thousands)
Derivative assets:	Current						Current
	Commodity contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	$	65,191	$	221,161
	Related to natural gas marketing	Fair value of derivatives	270		441
	Basis protection contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	143		57
			65,604		221,659
	Non-current						Commodity derivative contracts	Fair value of derivatives	$	49,540	$	8,490
	Commodity contracts						Basis protection derivative contracts	Fair value of derivatives	2,565		301
	Related to crude oil and natural gas sales	Fair value of derivatives	8,122		44,292				52,105		8,791
	Related to natural gas marketing	Fair value of derivatives	20		51		Non-current
	Basis protection contracts						Commodity derivative contracts	Fair value of derivatives	15,051		1,123
	Related to crude oil and natural gas sales	Fair value of derivatives	281		44		Basis protection derivative contracts	Fair value of derivatives	1,346		1,263
			8,423		44,387				16,397		2,386
Total derivative assets			$	74,027	$	266,046	Total derivative assets		$	68,502	$	11,177

Derivative liabilities:	Current						Current
	Commodity contracts						Commodity derivative contracts	Fair value of derivatives	$	9,943	$	53,565
	Related to crude oil and natural gas sales	Fair value of derivatives	$	21,639	$	—	Basis protection derivative contracts	Fair value of derivatives	195		30
	Related to natural gas marketing	Fair value of derivatives	221		417				10,138		53,595
	Basis protection contracts						Non-current
	Related to crude oil and natural gas sales	Fair value of derivatives	703		1,178		Commodity derivative contracts	Fair value of derivatives	2,311		27,595
			22,563		1,595				2,311		27,595
	Non-current
	Commodity contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	17,698		275
	Related to natural gas marketing	Fair value of derivatives	9		46
	Basis protection contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	178		374
			17,885		695
Total derivative liabilities			$	40,448	$	2,290	Total derivative liabilities		$	12,449	$	81,190

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September~~June 30, ~~2016~~2017

(unaudited)

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,					Six Months Ended June 30,
Condensed consolidated statement of operations line item	2016			2015			2016			2015			2017		2016			2017		2016
	(in thousands)												(in thousands)
Commodity price risk management gain (loss), net
Commodity price risk management gain, net
Net settlements	$	47,728		$	67,993		$	167,859		$	162,454		$	12,015	$	53,301		$	12,566	$	120,132
Net change in fair value of unsettled derivatives	(28,331		)	55,556			(230,207		)	(21,284		)	45,917		(146,102		)	126,070		(201,877		)
Total commodity price risk management gain (loss), net	$	19,397		$	123,549		$	(62,348	)	$	141,170
Sales from natural gas marketing
Net settlements	$	122		$	165		$	420		$	561
Net change in fair value of unsettled derivatives	255			(5		)	(263		)	(298		)
Total sales from natural gas marketing	$	377		$	160		$	157		$	263
Cost of natural gas marketing
Net settlements	$	(103	)	$	(157	)	$	(380	)	$	(531	)
Net change in fair value of unsettled derivatives	(277		)	(5		)	293			260
Total cost of natural gas marketing	$	(380	)	$	(162	)	$	(87	)	$	(271	)
Total commodity price risk management gain, net													$	57,932	$	(92,801	)	$	138,636	$	(81,745	)

Net settlements of commodity derivatives decreased for the three and six months ended June 30, 2017 as compared to the three and six months ended June 30, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior to commodity prices becoming depressed in late 2014. Substantially all of these higher-value agreements settled by the end of 2016. Net settlements for the three and six months ended June 30, 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices. Based upon the forward strip pricing at June 30, 2017, we expect that settlements will continue to be substantially lower in 2017 on a relative basis as compared to those in 2016.

All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. ~~Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant.~~ We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets.

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


As of September 30, 2016	Derivative instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
As of June 30, 2017								Derivative instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)							(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	74,027	$	(22,520	)	$	51,507	$	68,502	$	(10,974	)	$	57,528

Liability derivatives:
Derivative instruments, at fair value	$	40,448	$	(22,520	)	$	17,928	$	12,449	$	(10,974	)	$	1,475


As of December 31, 2015	Derivative instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
As of December 31, 2016								Derivative instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
	(in thousands)							(in thousands)
Asset derivatives:
Derivative instruments, at fair value	$	266,046	$	(1,921	)	$	264,125	$	11,177	$	(10,930	)	$	247

Liability derivatives:
Derivative instruments, at fair value	$	2,290	$	(1,921	)	$	369	$	81,190	$	(10,930	)	$	70,260

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September~~June 30, ~~2016~~2017

(unaudited)

NOTE 56 - ~~PROPERTIES AND EQUIPMENT~~FAIR VALUE OF FINANCIAL INSTRUMENTS

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

September 30, 2016 December 31, 2015
(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved $ 3,183,772
$ 2,881,189
Unproved 61,838
60,498
Total crude oil and natural gas properties 3,245,610
2,941,687
Equipment and other 31,410
30,098
Land and buildings 10,900
12,667
Construction in progress 107,794
113,115
Properties and equipment, at cost 3,395,714
3,097,567
Accumulated DD&A (1,463,440 ) (1,157,015 )
Properties and equipment, net $ 1,932,274
$ 1,940,552

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:

~~In September 2016, we closed on an acreage exchange transaction with Noble Energy, Inc.~~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 ~~certain~~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 ~~its subsidiaries ("Noble")~~our derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, ~~consolidate certain acreage positions in~~ the ~~core area~~contractual price of the Wattenberg Field. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties.

~~The following table presents impairment charges recorded for~~underlying position, current market prices, crude oil and natural gas ~~properties:~~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. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars, physical sales, and propane fixed-price swaps 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:

Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
(in thousands)

Impairment of proved and unproved properties $ 338
$ 150,840
$ 2,391
$ 152,764
Amortization of individually insignificant unproved properties 595
3,191
681
8,443
Impairment of crude oil and natural gas properties
933
154,031
3,072
161,207
Land and buildings —
—
3,032
—
Impairment of properties and equipment $ 933
$ 154,031
$ 6,104
$ 161,207

~~NOTE 6 - PENDING ACQUISITION~~

In August 2016, we entered into acquisition agreements to purchase Arris Petroleum Corporation (“Arris”) and the assets of 299 Resources, LLC, 299 Production, LLC and 299 Pipeline, LLC (collectively, “299 Sellers”) pursuant to which, and subject to the terms and conditions of those agreements, we have agreed to acquire an aggregate of approximately 57,000 net acres, approximately 30 wells and other related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to Arris and 299 Sellers of approximately $915 million in cash and approximately 9.4 million shares of our common stock (valued at approximately $590 million at the time the acquisition agreements were executed), subject to certain adjustments, and ongoing due diligence (the "Delaware Basin Acquisition"). The acquisition agreements allow the sellers to include a specified amount of additional leases in the transaction, which would increase the purchase price. Upon executing the acquisition agreements, we paid a $100 million deposit toward the cash portion of the purchase price into an escrow account, which is included in other assets in our September 30, 2016 condensed consolidated balance sheet. In some circumstances set forth in the acquisition agreements, we could be required to forfeit the $100 million deposit. The acquisition is expected to close in December 2016; however, there can be no assurance that conditions to closing will be satisfied.

In order to fund the cash portion of the Delaware Basin Acquisition, we completed a public offering of shares of our common stock, a public offering of convertible senior notes and a private offering of senior notes in September 2016. See Note 8, ~~Long-Term Debt, and Note 12,~~ ~~Common Stock~~, for further information. Prior to the September 2016 issuances of common stock, convertible senior notes and senior notes, we entered into a commitment letter with JPMorgan Chase Bank, N.A. (“JPMorgan”), for short-term bridge financing of the Delaware Basin Acquisition. The commitment letter contemplated, among other things, (i) a senior unsecured bridge loan to us in an aggregate principal amount not to exceed $600 million, to be drawn, if at all, at the closing of the Delaware Basin Acquisition, (ii) a $250 million increase in the commitments under our existing revolving credit facility and (iii) certain related proposed amendments and waivers to our existing credit facility agreement. Upon issuance of the common stock, convertible senior notes and senior notes, the bridge loan commitment was terminated. Upon closing of



	June 30, 2017									December 31, 2016
	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)
Assets:
Total assets	$	58,226		$	10,276		$	68,502		$	6,350		$	4,827		$	11,177
Total liabilities	(10,792		)	(1,657		)	(12,449		)	(66,789		)	(14,401		)	(81,190		)
Net asset (liability)	$	47,434		$	8,619		$	56,053		$	(60,439	)	$	(9,574	)	$	(70,013	)

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September~~June 30, ~~2016~~2017

(unaudited)

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period	$	2,316		$	73,195		$	(9,574	)	$	91,288
Changes in fair value included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net	9,262			(26,422		)	22,622			(20,257		)
Settlements included in condensed consolidated statement of operations line items:
Commodity price risk management gain (loss), net	(2,959		)	(19,398		)	(4,429		)	(43,656		)
Fair value of Level 3 instruments, net asset end of period	$	8,619		$	27,375		$	8,619		$	27,375

Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net	$	8,161		$	(18,210	)	$	17,194		$	(13,105	)

The significant unobservable input used in the ~~Delaware Basin Acquisition,~~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 this report.

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 crude oil and natural gas properties and goodwill 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 ~~required to pay approximately $9 million~~sold. The fair value of the goodwill is determined using either a qualitative method or a quantitative method, both of which utilize market data, a Level 2 input, in ~~fees~~the derivation of the value estimation.

The portion of our long-term debt related to ~~the bridge loan commitment, approximately $6 million in fees related to the increase in commitments under the~~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 June 30, 2017.



		Estimated Fair Value		Percent of Par
		(in millions)
Senior notes:
	2021 Convertible Notes	$	180.8	90.4	%
	2022 Senior Notes	520.6		104.1	%
	2024 Senior Notes	406.0		101.5	%

The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the related vehicle lease.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

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 major lenders under our revolving credit facility as counterparties to our commodity derivative contracts. An insignificant portion of our commodity derivative instruments may be with other counterparties. 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 June 30, 2017, taking into account the estimated likelihood of nonperformance.

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 June 30, 2017. 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 major lenders under our revolving credit facility.

Notes Receivable. In October 2014, we sold our entire 50 percent ownership interest in PDC Mountaineer, LLC to an unrelated third-party. As part of the consideration, we received a promissory note (the “Promissory Note”) for a principal sum of $39.0 million, bearing varying interest rates. The interest was to be paid quarterly, in arrears and at the option of the issuer, could be paid-in-kind (“PIK Interest”) and any such PIK Interest would be subject to the then current interest rate.

We regularly analyzed the Promissory Note for evidence of collectability, evaluating factors such as the creditworthiness of the issuer of the Promissory Note and the value of the underlying assets that secure the Promissory Note. Based upon this analysis, during the quarter ended March 31, 2016, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.0 million accumulated outstanding balance, including interest. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Promissory Note and began accounting for the interest on the Promissory Note under the cash basis method.

We performed this analysis as of March 31, 2017 and evaluated preliminary 2016 year-end financial statements of the note issuer which were available at such time, related information about the operations of the issuer, and existing market conditions for natural gas. Based upon this evaluation, it was determined that collection of the Promissory Note and PIK Interest continued to be doubtful and the full valuation allowance on the Promissory Note remained appropriate as of that date. This evaluation assumed repayment of the Promissory Note would be made exclusively from the existing operations of the issuer of the Promissory Note based on the latest available information.

In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately ~~$10~~$40.2 million in ~~other direct acquisition-related costs. During~~cash. The sales agreement transferred all of our legal rights to collect from the issuer of the Promissory Note. Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during the three months ended ~~September~~June 30, 2016, we recorded charges for the bridge loan fees and the other direct acquisition-related costs. The $9 million charge for fees related to the bridge loan commitment is included in interest expense and the $10 million charge for other direct acquisition-related costs is included in general and administrative expenses. The liabilities associated with both amounts are included in other accrued expenses on our condensed consolidated balance sheet as of September 30, 2016.2017.

NOTE 7 - INCOME TAXES

We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. 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. ~~A tax expense or benefit unrelated to the current year income or loss is recognized in its entirety as a discrete item of tax in the period identified.~~ The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective income tax rate, adjusted for the effect of discrete items.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

The effective income tax ~~rate~~rates for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 was ~~a 34.0%~~37.3 percent and ~~37.1% benefit~~36.8 percent expense on ~~loss~~income, respectively, compared to ~~a 33.8%~~37.9 percent and ~~36.3%~~37.5 percent benefit on loss for the three and ~~nine~~six months ended ~~September~~June 30, ~~2015.~~2016. The effective income tax ~~rate~~rates for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016 is~~2017 include discrete income tax benefits of $0.2 million and $1.8 million relating to the excess income tax basis recognized with the vesting of stock awards during the three and six months ended June 30, 2017, which resulted in a 0.3 percent and 1.3 percent reduction to our effective income tax rates.

The effective income tax rates for the three and six months ended June 30, 2017, are based upon a full year forecasted tax ~~benefit~~provision on ~~loss~~income and isare greater than the statutory federal income tax rate, primarily due to state income taxes, nondeductible officers’ compensation and nondeductible lobbying expenses, partially offset by stock-based compensation tax deductions. We anticipate the potential for increased periodic volatility in future effective income tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items. The effective income tax rates for the three and six months ended June 30, 2016, were based upon a full year forecasted income tax benefit on loss and were greater than the statutory federal income tax rate, primarily due to state income taxes and percentage depletion, partially offset by nondeductible officers’ compensation and nondeductible lobbying expenses. The effective tax rate for the three and nine months ended September 30, 2015 differs from the statutory rate primarily due to state taxes and percentage depletion, partially offset by nondeductible officers' compensation. There were no significant discrete income tax items recorded during the three and ~~nine~~six months ended ~~September~~June 30, ~~2016 or September 30, 2015.~~2016.

As of ~~September~~June 30, ~~2016,~~2017, 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. We continue to voluntarily participate in the Internal Revenue Service's ~~("IRS")~~ Compliance Assurance Program ~~("CAP")~~ for the 2016 and 2017 tax years, and received final acceptance of our 2015 ~~and 2016~~federal income tax ~~years. With respect to~~return during the 2014 tax year, we have agreed to a post filing adjustment with the IRS which resulted in an immaterial tax payment for the 2014 tax year. The IRS has fully accepted the 2014 federal return, as adjusted. The IRS has partially accepted our recently filed 2015 return that is now going through the IRS CAP post-filing review process.six months ended June 30, 2017.

~~Table of contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2016~~

~~(unaudited)~~

NOTE 8 - LONG-TERM DEBT

Long-term debt consisted of the following as of:


	September 30, 2016			December 31, 2015			June 30, 2017			December 31, 2016
	(in thousands)						(in thousands)
Senior notes:
1.125% Convertible senior notes due 2021:
1.125% Convertible Notes due 2021:
Principal amount	$	200,000		$	—		$	200,000		$	200,000
Unamortized discount	(39,199		)	—			(33,952		)	(37,475		)
Unamortized debt issuance costs	(4,793		)	—			(4,103		)	(4,584		)
1.125% Convertible senior notes due 2021, net of unamortized discount and debt issuance costs	156,008			—
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs							161,945			157,941

6.125% Senior notes due 2024:
7.75% Senior Notes due 2022:
Principal amount	400,000			—			500,000			500,000
Unamortized debt issuance costs	(7,710		)	—			(5,882		)	(6,443		)
6.125% Senior notes due 2024, net of unamortized debt issuance costs	392,290			—
7.75% Senior Notes due 2022, net of unamortized debt issuance costs							494,118			493,557

7.75% Senior notes due 2022:
6.125% Senior Notes due 2024:
Principal amount	500,000			500,000			400,000			400,000
Unamortized debt issuance costs	(6,723		)	(7,563		)	(7,060		)	(7,544		)
7.75% Senior notes due 2022, net of unamortized debt issuance costs	493,277			492,437
6.125% Senior Notes due 2024, net of unamortized debt issuance costs							392,940			392,456

3.25% Convertible senior notes due 2016:
Principal amount	—			115,000
Unamortized discount	—			(1,852		)
Unamortized debt issuance costs	—			(208		)
3.25% Convertible senior notes due 2016, net of unamortized discount and debt issuance costs	—			112,940
Total senior notes	1,041,575			605,377			1,049,003			1,043,954

Revolving credit facility	—			37,000			—			—
Total debt, net of unamortized discount and debt issuance costs	1,041,575			642,377
Less current portion of long-term debt	—			112,940
Long-term debt	$	1,041,575		$	529,437
Total long-term debt, net of unamortized discount and debt issuance costs							$	1,049,003		$	1,043,954

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

Senior Notes

~~1.125%~~2021 Convertible ~~Senior Notes Due 2021.~~Notes. In September 2016, we issued $200 million of 1.125% convertible senior notes due 2021 (the "2021 Convertible Notes") in a public offering. ~~The 2021 Convertible Notes are governed by an indenture dated September 14, 2016 between us and the U.S. Bank National Association, as trustee.~~ The maturity for the payment of principal is September 15, 2021. Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September ~~15, commencing on March 15, 2017.~~15. The conversion stock price at maturity is $85.39 per share. We allocated the gross proceeds of the 2021 Convertible Notes ~~are senior unsecured obligations~~between the liability and ~~rank senior in right~~equity components of ~~payment to our future indebtedness that is expressly subordinated to~~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; equal~~Notes. Approximately $4.8 million in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. The proceeds fromcosts associated with the issuance of the 2021 Convertible ~~Notes, after deducting offering expenses and underwriting discounts, are expected~~Note have been capitalized as debt issuance costs. As of June 30, 2017, the unamortized debt discount will be amortized over the remaining contractual term to ~~be used to fund a portion of the purchase price of the Delaware Basin Acquisition (see Note 6,~~ ~~Pending Acquisition), to pay related fees and expenses and for general corporate purposes.~~

The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, in each case at an initial conversion rate of 11.7113 per $1,000 principal amountmaturity of the 2021 Convertible Notes ~~which is equal to~~using an ~~initial conversion price~~effective interest rate of ~~approximately $85.39 per share. The conversion rate is subject to adjustment upon certain events. Upon~~5.8 percent.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2016~~

~~(unaudited)~~

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, as well as cash in lieu of fractional shares.

~~We may not redeem the 2021 Convertible Notes prior to their maturity date. If~~2022 Senior Notes. In October 2012, we undergo a fundamental change, as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100% of theissued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”). The 2022 Senior Notes accrue interest from the date of ~~the 2021 Convertible Notes to be repurchased, plus any accrued~~issuance and ~~unpaid~~ interest ~~to, but excluding, the fundamental change repurchase date. The occurrence of a fundamental change will also result~~is payable semi-annually in ~~the 2021 Convertible Notes becoming convertible.~~

~~We allocated the gross proceeds of the 2021 Convertible Notes between the liability~~arrears on April 15 and equity components of the debt. The initial $160.5 million million liability component was determined based on the fair value of similar debt instruments excluding the conversion feature for similar terms and priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes.October 15. Approximately ~~$4.8~~$11.0 million in costs associated with the issuance of the ~~2021 Convertible~~2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. As of September 30, 2016, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using an effective interest rate of 5.8%. Based upon a September 30, 2016 stock price of $67.06 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount.

~~6.125%~~2024 Senior ~~Notes Due 2024.~~Notes. In September 2016, we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”) in a private ~~placement. The proceeds from~~placement to qualified institutional buyers. In May 2017, in accordance with the ~~issuance of~~registration rights agreement that we entered into with the initial purchasers when we issued the 2024 Senior Notes, ~~after deducting offering expenses and underwriting discounts, are expected~~we filed a registration statement with the SEC relating to ~~be used~~an offer to ~~fund a portion of the purchase price of the Delaware Basin Acquisition (see Note 6,~~ ~~Pending Acquisition), to pay related fees and expenses and for general corporate purposes. If the acquisition is not completed on or prior to December 31, 2016 (or in some circumstances by or on January 15, 2017),~~exchange the 2024 Senior Notes ~~will be redeemed in whole at a special mandatory redemption price equal to 100% of the aggregate principal amount of the 2024~~for registered notes ~~plus accrued and unpaid interest.~~

with substantially identical terms. The 2024 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on March 15 and September ~~15, commencing on March 15, 2017.~~15. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. ~~The 2024~~

In January 2017, pursuant to the filing of supplemental indentures for the 2021 Convertible Notes, 2022 Senior Notes, ~~are senior unsecured obligations~~ and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries.

~~In connection with the issuance of~~ the 2024 Senior Notes ~~we entered into~~(collectively, the "Notes"), our wholly-owned subsidiary, PDC Permian, Inc., became a ~~registration rights agreement with~~guarantor of our obligations under the ~~initial purchasers in which we agreed to file a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes~~Notes. Accordingly, condensed consolidating financial information for registered notes with substantially identical terms. In addition, we have agreed, in certain circumstances, to file a shelf registration statement covering the resale of the 2024 Senior Notes by holders.

At any time prior to September 15, 2019, we may redeem up to 35% of the outstanding 2024 Senior Notes with proceeds from certain equity offerings at a redemption price of 106.125% of the principal amount of the notes redeemed, plus accruedPDC and unpaid interest, if at least 65% of the aggregate principal amount of the 2024 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering.

~~Upon the occurrence of a "change of control," as defined~~PDC Permian, Inc. is presented in the indenture for the 2024 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100% of the principal amount, together with any accrued and unpaid interest to the date of purchase.

The indenture governing the 2024 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries.

~~7.75% Senior Notes Due 2022.~~footnote titled In October 2012, we issued $500 million aggregate principal amount of 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”) in a private placement. The 2022 Senior Notes accrue interest from the date of issuance and interest

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2016~~

~~(unaudited)~~

is payable semi-annually in arrears on April 15 and October 15. The indenture governing the 2022 Senior Notes contains customary restrictive incurrence covenants, and customary repurchase and redemption provisions, generally similar to those in the indenture governing the 2024 Senior Notes. Capitalized debt issuance costs are being amortized as interest expense over the life of the 2022 Senior Notes using the effective interest method.

~~3.25% Convertible Senior Notes Due 2016~~Subsidiary Guarantor. In November 2010, we issued $115 million aggregate principal amount of 3.25% convertible senior notes due 2016 (the "2016 Convertible Notes") in a private placement. The maturity for the payment of principal was May 15, 2016. At December 31, 2015, our indebtedness included the 2016 Convertible Notes. Upon settlement in May 2016, we paid the aggregate principal amount of the 2016 Convertible Notes, plus cash for fractional shares, totaling approximately 115 million, utilizing proceeds from our March 2016 equity offering. Additionally, we issued 792,406 shares of common stock for the $47.9 million excess conversion value. See Note 12, ~~Common Stock,~~ ~~for more information.~~

As of ~~September~~June 30, ~~2016,~~2017, we were in compliance with all covenants related to the ~~2021 Convertible Notes, 2024 Senior Notes and 2022 Senior~~ Notes, and expect to remain in compliance throughout the next 12-month period.

Revolving Credit Facility

Revolving Credit Facility. We are party to a Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent, and other lenders party thereto (sometimes referred to as the "revolving credit facility"). The revolving credit facility ~~matures in May 2020 and~~ is available for working capital requirements, capital ~~expenditures,~~investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility matures in May 2020 and provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base ~~which is currently $700 million,~~ and ~~the aggregate commitments, which are currently $450 million.~~certain limitations under our senior notes. 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, excluding proved reserves attributable to our affiliated partnerships.~~interests. The borrowing base is subject to a semi-annual ~~size~~ 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. The revolving credit facility is secured by ~~substantially all~~a pledge of the stock of certain of our ~~assets, including~~subsidiaries, mortgages of certain producing crude oil and natural gas ~~properties.~~properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility.

In ~~September 2016,~~May 2017, we entered into a ~~Third~~Fifth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, amends the revolving credit facility to ~~permit the completion of the Delaware Basin Acquisition (see Note 6,~~ ~~Pending Acquisition~~) and, effective upon closing of the acquisition, adjusts the interest rate payable on amounts borrowed under the facility and increases the aggregate commitments under the facility from $450 million to $700 million (with the borrowing base remaining at $700 million).

In October 2016, we entered into a Fourth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, reaffirmed of our borrowing base at $700 million and made certain other immaterial modifications to the existing agreement, includingreflect an increase in the ~~amount~~borrowing base from $700 million to $950 million. We have elected to maintain a $700 million commitment level as of ~~our future production that we are permitted to hedge.~~ the date of this report. In

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

addition, the Fifth Amendment made changes to certain of the financial and non-financial covenants in the existing agreement, as well as other administrative changes.

As of June 30, 2017 and December 31, 2016, debt issuance costs related to our revolving credit facility were $7.5 million and $8.8 million, respectively, and are included in other assets on the condensed consolidated balance sheets. We had no outstanding balance on our revolving credit facility as of ~~September~~June 30, ~~2016, compared to $37 million outstanding as of~~2017 or December 31, ~~2015.~~2016. The ~~weighted-average interest rate on~~outstanding principal amount under the ~~outstanding balance on our~~ revolving credit facility ~~exclusive~~accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of JPMorgan Chase Bank, N.A.'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, oninterest margin, and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of June 30, 2017, the applicable interest margin is 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment ~~and~~fee is 0.50 percent. No principal payments are generally required until the ~~letter of credit noted below, was 2.6% per annum as of December 31, 2015.~~

As of September 30, 2016, RNG had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit is currently scheduled to expire in September 2017 but is expected to be automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility ~~by an amount equal to~~expires in May 2020, or in the ~~letter of credit. As of September 30, 2016,~~event that the ~~available funds under our revolving credit facility, including~~borrowing base falls below the ~~reduction for the $11.7 million letter of credit, was $438.3 million.~~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, ~~as of September 30, 2016,~~ include requirements to: (a) maintain a minimum current ratio of ~~1.00 to 1.00~~1.0:1.0 and (b) not exceed a maximum leverage ratio of ~~4.25 to 1.00.~~ 4.0:1.0. As of ~~September~~June 30, ~~2016,~~2017, we were in compliance with all of the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. ~~Effective upon closing of~~As defined by the ~~Delaware Basin Acquisition, the maximum permitted~~revolving credit facility, our current ratio was 3.3 and our leverage ratio ~~will be reduced to 4.00 to 1.00.~~

~~Table~~was 1.9 as of ~~contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September~~June 30, ~~2016~~

~~(unaudited)~~

2017.

In May 2017, we replaced our $11.7 million irrevocable standby letter of credit that we held in favor of a third-party transportation service provider for surety of an existing firm transportation obligation with a $9.3 million deposit, which is classified as restricted cash and is included in other assets on the condensed consolidated balance sheet. As of June 30, 2017, available funds under our revolving credit facility were $700 million based on our elected commitment level.

NOTE 9 - OTHER ACCRUED EXPENSES

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



	June 30, 2017		December 31, 2016
	(in thousands)

Employee benefits	$	12,148	$	22,282
Asset retirement obligations	12,938		9,775
Other	4,853		6,568
Other accrued expenses	$	29,939	$	38,625

NOTE 10 - CAPITAL LEASES

We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds ~~90%~~90 percent of the fair value of the leased vehicles at inception of the lease.

The following table presents ~~leased~~ vehicles under capital ~~leases~~lease as ~~of September 30, 2016:~~of:


	Amount			June 30, 2017			December 31, 2016
	(in thousands)			(in thousands)
Vehicles	$	2,801		$	5,097		$	2,975
Accumulated depreciation	(613		)	(1,240		)	(776		)
	$	2,188		$	3,857		$	2,199

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following:


For the Twelve Months Ending September 30,	Amount
For the Twelve Months Ending June 30,				Amount
	(in thousands)			(in thousands)
2017	$	860
2018	1,167			$	1,836
2019	553			1,527
2020				1,195
	2,580			4,558
Less executory cost	(101		)	(189		)
Less amount representing interest	(280		)	(491		)
Present value of minimum lease payments	$	2,199		$	3,878

Short-term capital lease obligations	$	646		$	1,474
Long-term capital lease obligations	1,553			2,404
	$	2,199		$	3,878

Short-term capital lease obligations are included in other accrued expenses on the condensed consolidated balance ~~sheets. Long-term~~sheets and long-term capital lease obligations are included in other liabilities on the condensed consolidated balance sheets.

NOTE 1011 - 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			Amount
	(in thousands)			(in thousands)

Balance at beginning of period, January 1, 2016	$	89,492
Balance at December 31, 2016				$	92,387
Obligations incurred with development activities	1,137			2,415
Accretion expense	5,400			3,434
Obligations discharged with disposal of properties and asset retirements	(6,620		)
Balance end of period, September 30, 2016	89,409
Obligations discharged with asset retirements				(7,431		)
Balance at June 30, 2017				90,805
Less current portion	(6,900		)	(12,938		)
Long-term portion	$	82,509		$	77,867

Our estimated asset retirement ~~obligation~~obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging and abandonment ~~cost~~costs considering federal and state regulatory requirements in effect. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. ~~In 2016,~~As of June 30, 2017, the credit-adjusted risk-free

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2016~~

~~(unaudited)~~

rates used to discount our plugging and abandonment liabilities ranged from ~~7.6%~~6.5 percent to ~~8.0%.~~8.2 percent. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors, and changes to our credit-adjusted risk-free rate as market conditions warrant. Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets.

NOTE 1112 - COMMITMENTS AND CONTINGENCIES

Firm Transportation ~~Processing~~ and ~~Sales~~Processing Agreements. We enter into contracts that provide firm transportation ~~sales~~ and processing ~~agreements~~ 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. We record in our financial~~owners whose volumes we market on their behalf. Our condensed consolidated statements ~~only~~of operations reflect our share of ~~costs based upon our working interest in the wells.~~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. As natural gas prices continue to remain depressed, certain third-party producers under our Gas Marketing segment have begun and continue to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. As

Table of ~~September~~contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2016, we have recorded an allowance for doubtful accounts of approximately $1.1 million. We have initiated several legal actions for breach of contract, collection, and related claims against certain third-party producers that are delinquent in their payment obligations, which have to date resulted in one default judgment.2017

(unaudited)

The following table presents gross volume information related to our long-term firm transportation ~~sales~~ and processing agreements for pipeline capacity:


	For the Twelve Months Ending September 30,													For the Twelve Months Ending June 30,
Area	2017		2018		2019		2020		2021 and Through Expiration		Total		Expiration Date	2018		2019		2020		2021		2022 and Through Expiration		Total		Expiration Date

Natural gas (MMcf)
Gas Marketing segment	7,117		7,117		7,117		7,136		13,344		41,831		August 31, 2022
Wattenberg Field														—		9,734		18,849		18,798		79,979		127,360		March 31, 2026
Delaware Basin														14,600		14,600		14,640		7,360		—		51,200		December 31, 2020
Gas Marketing														7,117		7,117		7,136		7,117		8,021		36,508		August 31, 2022
Utica Shale	2,738		2,738		2,738		2,745		7,754		18,713		July 22, 2023	2,737		2,737		2,745		2,737		5,709		16,665		July 22, 2023
Total	9,855		9,855		9,855		9,881		21,098		60,544			24,454		34,188		43,370		36,012		93,709		231,733

Crude oil (MBbls)
Wattenberg Field	2,413		2,413		2,413		1,813		—		9,052		June 30, 2020	2,413		2,414		2,420		—		—		7,247		June 30, 2020

Dollar commitment (in thousands)	$	17,470	$	16,324	$	16,324	$	13,205	$	8,102	$	71,425		$	18,583	$	28,104	$	36,564	$	22,665	$	81,560	$	187,476

In December 2016, in anticipation of our future drilling activities in the Wattenberg Field, we entered into a facilities expansion agreement with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct a new 200 MMcfd cryogenic plant. We will be bound to the volume requirements in this agreement on the first day of the calendar month after the actual in-service date of the plant, which in the above table is estimated to be in October 2018. The agreement requires a baseline volume commitment, consisting of our gross wellhead volume delivered in November 2016, to this midstream provider and an incremental wellhead volume commitment of 51.5 MMcfd for seven years. We may be required to pay a shortfall fee for any volumes under the 51.5 MMcfd incremental commitment. Any shortfall of this volume commitment may be offset by additional third party 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 contract to guarantee a certain target profit margin to the midstream provider on these incremental volumes. We expect that our development plan will support the utilization of that capacity.

In April 2017, we entered into a transportation service agreement for delivery of 40,000 dekatherms per day of our Delaware Basin natural gas production to the Waha market hub in West Texas.

For each of the three and six months ended June 30, 2017, commitments for long-term transportation volumes, net to our interest, for Wattenberg Field crude oil, Delaware Basin natural gas, and Utica Shale natural gas were $2.6 million and $4.8 million, respectively, and were recorded in transportation, gathering, and processing expense in our condensed consolidated statements of operations. For each of the three and six months ended June 30, 2016, commitments for long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $2.3 million and $4.7 million, respectively.

During the three and six months ended June 30, 2017, long-term firm transportation costs for our gas marketing business associated with the commitments shown above were $0.9 million and $1.7 million, respectively, and were recorded in other expenses in our condensed consolidated statements of operations. During the three and six months ended June 30, 2016, long-term firm transportation costs for our gas marketing business associated with the commitments shown above were $0.9 million and $1.7 million, respectively.

~~Litigation.~~Litigation and Legal Items. ~~We are~~The Company is involved in various legal ~~proceedings that we consider normal to our business. We review~~proceedings. The Company reviews 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~~the best ~~interests. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any,~~interests of the Company. Management has provided the necessary estimated accruals in the ~~remaining~~accompanying balance sheets where deemed appropriate for litigation ~~will~~and legal related items that are ongoing and not yet concluded. However, the liability ultimately incurred with respect to a matter may exceed the ~~amounts reserved.~~related accrual. Although the results cannot be known with certainty, we ~~currently~~ believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations, or liquidity.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

A group of 42 independent West Virginia natural gas producers has filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. (“Dominion”), certain entities affiliated with Dominion, and RNG as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. RNG and Dominion have removed the case to the U.S. District Court for the Northern District of West Virginia and are preparing pre-trial pleadings, including an answer to the complaint and a motion to dismiss the case. At this time, RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses.

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 ~~regular~~periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events ~~that require remediation~~ are probable and the costs can be reasonably estimated. ~~As of September 30, 2016 and December 31, 2015,~~Except as discussed herein, we ~~had accrued environmental liabilities in the amount of $3.2 million and $4.1 million, respectively, included in other accrued expenses on the condensed consolidated balance sheets. We~~ are not aware of any environmental claims existing as of ~~September~~June 30, ~~2016~~2017 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 past non-compliance with environmental laws will not be discovered on our properties. However, the liability ultimately incurred with respect to a matter may exceed the related accrual. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets.

~~Table of contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2016~~

~~(unaudited)~~

In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado. The Information Request ~~focused~~focuses on historical operation and design information for 46 of our production facilities and asks that we conduct sampling and analyses at the identified 46 facilities. We responded to the Information Request with the requested data in January 2016. ~~We continue to meet with the EPA and provide additional information, but cannot predict the outcome of this matter at this time.~~

In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. § 25-7-115(2) from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds ~~to the maximum extent possible~~ at 65 facilities consistent with applicable standards under Colorado law. ~~We are working with the agency to address the allegations, but cannot predict the outcome of this matter at this time.~~

~~Employment Agreements~~For more than a year, we held a series of meetings with ~~Executive Officers. Each~~the EPA, Department of ~~our senior executive officers may be entitled to a severance payment~~Justice (“DOJ”) and ~~certain other benefits upon~~CDPHE on the ~~termination~~above matters. On June 26, 2017, the DOJ on behalf of the ~~officer's employment pursuant~~EPA and the State of Colorado filed a complaint against us based on the above matters. We continue to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followedschedule meetings with these agencies in working toward a ~~change of control~~resolution of the ~~Company.~~matters. The ultimate outcome related to these combined actions is not known at this time.

NOTE 1213 - COMMON STOCK

Sale of Equity Securities

~~In September~~During December 2016, we ~~completed a public offering of 9,085,000~~issued 9.4 million shares of our common stock ~~at a price to us of $61.51 per share. Net proceeds~~as partial consideration for 100 percent of the ~~offering were $558.5 million, after deducting offering expenses~~common stock of Arris Petroleum and ~~underwriting discounts,~~for the acquisition of ~~which $90,850 is included in common shares-par value and $558.4 million is included in additional paid-in capital ("APIC") on~~certain Delaware Basin properties. Pursuant to the ~~September 30, 2016 condensed consolidated balance sheet. The~~terms of previously-disclosed lock-up agreements, these shares were ~~issued pursuant to an effective shelf registration statement~~restricted for sale. The lock-up period ended on ~~Form S-3 filed with~~June 4, 2017. We have registered the ~~SEC in March 2015.~~

~~In March 2016, we completed a public offering of 5,922,500~~9.4 million shares of our common stock at a price to us of $50.11 per share. Net proceeds of the offering were $296.6 million, after deducting offering expenses and underwriting discounts, of which $59,225 is included in common shares-par value and $296.5 million is included in APIC on the September 30, 2016 condensed consolidated balance sheet. The shares were issued pursuant to the effective shelf registration statement on Form S-3 filed with the SEC in March 2015.

In March 2015, we completed a public offering of 4,002,000 shares of our common stock at a price to us of $50.73 per share. Net proceeds of the offering were $202.9 million, after deducting offering expenses and underwriting discounts, of which $40,020 is included in common shares-par value and $202.8 million is included in APIC on the condensed consolidated balance sheets. The shares were issued pursuant to the effective shelf registration statement on Form S-3 filed with the SEC in March 2015.for resale.

Stock-Based Compensation Plans

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
	(in thousands)												(in thousands)

Stock-based compensation expense	$	4,079		$	4,813		$	15,205		$	14,278		$	5,372		$	6,444		$	9,826		$	11,126
Income tax benefit	(1,552		)	(1,828		)	(5,786		)	(5,423		)	(2,010		)	(2,452		)	(3,676		)	(4,233		)
Net stock-based compensation expense	$	2,527		$	2,985		$	9,419		$	8,855		$	3,362		$	3,992		$	6,150		$	6,893

Table of contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

Stock Appreciation Rights ~~("SARs")~~

The ~~SARs~~stock appreciation right ("SARs") vest ratably over a three-year period and may 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.

~~Table of contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2016~~

~~(unaudited)~~

~~In January 2016, the~~The Compensation Committee of our Board of Directors awarded ~~58,709~~ SARs to our executive ~~officers.~~officers during the six months ended June 30, 2017 and 2016. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:


	Nine Months Ended September 30,						Six Months Ended June 30,
	2016			2015			2017			2016

Expected term of award	6.0 years			5.2 years
Expected term of award (in years)							6			6
Risk-free interest rate	1.8		%	1.4		%	2.0		%	1.8		%
Expected volatility	54.5		%	58.0		%	53.3		%	54.5		%
Weighted-average grant date fair value per share	$	26.96		$	22.23		$	38.58		$	26.96

The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future.

The following table presents the changes in our SARs for ~~all periods presented:~~the six months ended June 30, 2017:

Nine Months Ended September 30,
2016 2015
Number of
SARs Weighted-Average
Exercise
Price Average Remaining Contractual
Term (in years)
Aggregate Intrinsic
Value (in thousands)
Number of
SARs Weighted-Average
Exercise
Price
Average Remaining Contractual
Term (in years)

Aggregate Intrinsic
Value (in thousands)
Outstanding beginning of year, January 1, 326,453
$ 38.99
279,011
$ 38.77

Awarded 58,709
51.63
68,274
39.63

Exercised (141,084 ) 40.16
$ 2,770
—
—

Outstanding at September 30, 244,078
41.36
7.1 6,273
347,285
38.94
7.5 $ 4,888
Vested and expected to vest at September 30, 238,671
41.20
7.1 6,171
341,423
38.89
7.5 4,821
Exercisable at September 30, 136,644
36.74
5.9 4,143
191,149
35.68
6.6 3,312



	Number of SARs	Weighted-Average Exercise Price		Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2016	244,078	$	41.36	6.9	$	7,620
Awarded	54,142	74.57		—	—
Outstanding at June 30, 2017	298,220	47.39		7.0	1,158
Exercisable at June 30, 2017	186,248	39.38		5.8	1,093

Total compensation cost related to SARs granted ~~net of estimated forfeitures,~~ and not yet recognized in our condensed consolidated statement of operations as of ~~September~~June 30, ~~2016~~2017 was ~~$1.7~~$2.8 million. The cost is expected to be recognized over a weighted-average period of ~~1.9~~2.1 years.

Restricted Stock Awards

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

~~In January 2016, the Compensation Committee awarded to our executive officers a total~~

Table of ~~61,634 time-based restricted shares that vest ratably over a~~ ~~three-year period ending in January 2019.~~contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~:2017:

Shares Weighted-Average
Grant Date
Fair Value

Non-vested at December 31, 2015 525,081
$ 50.23
Granted 269,709
57.12
Vested (256,976 ) 48.60
Forfeited (14,716 ) 55.70
Non-vested at September 30, 2016 523,098
54.43

~~Table of contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2016~~

~~(unaudited)~~



	Shares		Weighted-Average Grant Date Fair Value

Non-vested at December 31, 2016	479,642		$	56.09
Granted	248,946		67.02
Vested	(202,427	)	56.43
Forfeited	(5,311	)	67.20
Non-vested at June 30, 2017	520,850		61.06

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


	As of/for the Nine Months Ended September 30,				As of/Six Months Ended June 30,
	2016		2015		2017		2016
	(in thousands, except per share data)				(in thousands, except per share data)

Total intrinsic value of time-based awards vested	$	14,675	$	13,061	$	13,103	$	13,314
Total intrinsic value of time-based awards non-vested	35,079		30,959		22,454		31,506
Market price per common share as of September 30,	67.06		53.01
Market price per common share as of June 30,					43.11		57.61
Weighted-average grant date fair value per share	57.12		48.58		67.02		57.11

Total compensation cost related to non-vested time-based awards ~~net of estimated forfeitures,~~ and not yet recognized in our condensed consolidated statements of operations as of ~~September~~June 30, ~~2016~~2017 was ~~$18.7~~$25.7 million. This cost is expected to be recognized over a weighted-average period of ~~1.9~~2.1 years.

Market-Based Awards.The fair value of the market-based restricted shares 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.

~~In January 2016, the~~The Compensation Committee of our Board of Directors awarded a total of ~~24,280~~28,069 market-based restricted shares to our executive ~~officers.~~officers during the six months ended June 30, 2017. In addition to continuous employment, the vesting of these shares is contingent on ~~the Company's~~our total ~~shareholder~~stockholder return ("TSR"), which is essentially ~~the Company’s~~our stock price change including any dividends as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, ~~2018~~2019, and can result in a payout between 0%0 percent and ~~200%~~200 percent of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards was computed using the Monte Carlo pricing model using the following assumptions:


	Nine Months Ended September 30,						Six Months Ended June 30,
	2016			2015			2017			2016

Expected term of award	3 years			3 years
Expected term of award (in years)							3			3
Risk-free interest rate	1.2		%	0.9		%	1.4		%	1.2		%
Expected volatility	52.3		%	53.0		%	51.4		%	52.3		%
Weighted-average grant date fair value per share	$	72.54		$	66.16		$	94.02		$	72.54

The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility.

~~The following table presents the change in non-vested market-based awards during the~~ ~~nine~~ ~~months ended~~ ~~September 30, 2016~~:

Shares
Weighted-Average
Grant Date
Fair Value per Share

Non-vested at December 31, 2015
71,549
$ 63.60
Granted
24,280
72.54
Vested (1)
(11,283 ) 98.50
Non-vested at September 30, 2016
84,546
61.51

~~__________~~

~~(1)Vested shares were issued at 200% based on our relative total shareholder return as ranked among the Company's peer group.~~

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~September~~June 30, ~~2016~~2017

(unaudited)

The following table presents the change in non-vested market-based awards during the six months ended June 30, 2017:



	Shares	Weighted-Average Grant Date Fair Value per Share

Non-vested at December 31, 2016	48,420	$	64.97
Granted	28,069	94.02
Non-vested at June 30, 2017	76,489	75.63

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


	As of/for the Nine Months Ended September 30,				As of /Six Months Ended June 30,
	2016		2015		2017		2016
	(in thousands, except per share data)				(in thousands, except per share data)

Total intrinsic value of market-based awards vested	$	1,174	$	—	$	—	$	1,174
Total intrinsic value of market-based awards non-vested	5,670		5,996		3,297		4,871
Market price per common share as of September 30,	67.06		53.01
Market price per common share as of June 30,					43.11		57.61
Weighted-average grant date fair value per share	72.54		66.16		94.02		72.54

Total compensation cost related to non-vested market-based awards, ~~net of estimated forfeitures, and~~ not yet recognized in our condensed consolidated statements of operations as of ~~September~~June 30, ~~2016~~2017, was ~~$1.9~~$3.4 million. This cost is expected to be recognized over a weighted-average period of ~~1.9~~2.1 years.

Treasury Share Purchases

In June 2010, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). In accordance with the 2010 Plan, as amended in June 2013, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares granted may be either authorized but unissued shares, treasury shares, or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of SARs, paid out in the form of cash. In accordance with our stock-based compensation plans, employees and directors may surrender shares of our common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2010 Plan are reissued for new grants. For shares reissued for new grants under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to additional paid-in capital. As of December 31, 2016, we had 10,397 shares remaining available for reissuance pursuant to our 2010 plan. Additionally, as of December 31, 2016, we had 18,366 of shares of treasury stock related to a rabbi trust. During the six months ended June 30, 2017, we acquired 79,381 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 46,822 shares were reissued and 42,956 shares are available for reissuance pursuant to our 2010 Plan.

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 from time to time. Through June 30, 2017, no preferred shares have been issued.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

NOTE 1314 - 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, stock options, 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 a reconciliation of the weighted-average diluted shares outstanding:


	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015	2017	2016	2017	2016
	(in thousands)				(in thousands)

Weighted-average common shares outstanding - basic	48,839	40,085	45,741	38,837	65,859	46,742	65,804	44,175
Dilutive effect of:
Restricted stock					94	—	176	—
Other equity-based awards					66	—	86	—
Weighted-average common shares and equivalents outstanding - diluted	48,839	40,085	45,741	38,837	66,019	46,742	66,066	44,175

We reported a net loss for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016 and 2015, respectively.~~2016. As a result, our basic and diluted weighted-average common shares outstanding were the same for that period because the effect of the common share equivalents was anti-dilutive.

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


	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015	2017	2016	2017	2016
	(in thousands)				(in thousands)

Weighted-average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
Restricted stock	660	816	705	836	376	768	119	745
Convertible notes	—	468	345	505	—	358	—	478
Other equity-based awards	97	95	103	97	1	103	10	105
Total anti-dilutive common share equivalents	757	1,379	1,153	1,438	377	1,229	129	1,328

In September 2016, we issued the 2021 Convertible Notes, which 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.

~~Table~~ During the three and six months ended June 30, 2017, the average market price of ~~contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~September 30, 2016~~

~~(unaudited)~~

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.

In November 2010, we issued ~~the~~ $115.0 million aggregate principal amount of 3.25% convertible senior notes that were due in 2016 ("2016 Convertible ~~Notes,~~Notes"), which gave the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The 2016 Convertible Notes matured in May 2016. ~~See Note 8,~~ ~~Long-Term Debt,~~ ~~for additional information.~~ Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method ifwhen the average market share price exceeded the $42.40 conversion price during the ~~period~~periods presented.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

Shares issuable upon conversion of the 2021 Convertible Notes and 2016 Convertible Notes were excluded from the diluted earnings per share calculation for the applicable periods as the effect would be anti-dilutive to our earnings per share.

NOTE 1415 - ~~BUSINESS SEGMENTS~~

We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated.SUBSIDIARY GUARANTOR

~~Oil and Gas Exploration and Production.~~ Our ~~Oil and Gas Exploration and Production segment includes all of~~subsidiary PDC Permian, Inc. guarantees our ~~crude oil and natural gas properties.~~obligations under our publicly-registered Notes. The ~~segment represents revenues and expenses from~~following presents the production and sale of crude oil, natural gas and NGLs. Segment revenue includes crude oil, natural gas and NGLs sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of properties and equipment, direct general and administrative expense and depreciation, depletion and amortization expense.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 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;
(iv)	Parent and subsidiaries on a consolidated basis ("Consolidated").

~~Gas Marketing.~~ ~~Our Gas Marketing segment purchases, aggregates~~The Guarantor is 100% owned by the Parent beginning in December 2016. The Notes are fully and ~~resells natural gas produced~~unconditionally guaranteed on a joint and several basis by ~~unrelated third-parties. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income, less costs~~the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of ~~natural gas marketing and direct general and administrative expense.~~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.

~~Unallocated Amounts.~~ Unallocated income includes unallocated other revenue, less corporate general and administrative expense, corporate DD&A expense, interest income and interest expense. Unallocated assets include assets utilized for corporate general and administrative purposes, as well as assets not specifically included in our two business segments.

The following ~~tables present~~condensed consolidating financial statements have been prepared on the same basis of accounting as our ~~segment information:~~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.

Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
(in thousands)
Segment revenues:
Oil and gas exploration and production $ 161,212
$ 228,520
$ 268,090
$ 418,356
Gas marketing 2,678
2,580
6,728
8,336
Total revenues $ 163,890
$ 231,100
$ 274,818
$ 426,692

Segment income (loss) before income taxes:
Oil and gas exploration and production $ 17,809
$ (30,296 ) $ (134,731 ) $ (14,134 )
Gas marketing (414 ) (201 ) (1,067 ) (539 )
Unallocated (52,736 ) (32,164 ) (166,689 ) (97,189 )
Loss before income taxes $ (35,341 ) $ (62,661 ) $ (302,487 ) $ (111,862 )



	Condensed Consolidating Balance Sheets
	June 30, 2017
	Parent		Guarantor		Eliminations			Consolidated
	(in thousands)
Assets
Current assets	$	381,313	$	14,905	$	—		$	396,218
Properties and equipment, net	1,945,252		2,220,320		—			4,165,572
Intercompany receivable	120,106		—		(120,106		)	—
Investment in subsidiaries	1,733,615		—		(1,733,615		)	—
Goodwill	—		56,331		—			56,331
Noncurrent assets	37,966		841		—			38,807
Total Assets	$	4,218,252	$	2,292,397	$	(1,853,721	)	$	4,656,928

Liabilities and Stockholders' Equity
Current liabilities	$	277,443	$	53,223	$	—		$	330,666
Intercompany payable	—		120,106		(120,106		)	—
Long-term debt	1,049,004		—		—			1,049,004
Other noncurrent liabilities	177,363		373,872		11,581			562,816
Stockholders' equity	2,714,442		1,745,196		(1,745,196		)	2,714,442
Total Liabilities and Stockholders' Equity	$	4,218,252	$	2,292,397	$	(1,853,721	)	$	4,656,928

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

September 30, 2016 December 31, 2015
(in thousands)
Segment assets:
Oil and gas exploration and production $ 3,390,005
$ 2,294,288
Gas marketing 3,735
4,217
Unallocated 23,540
72,038
Total assets $ 3,417,280
$ 2,370,543



	Condensed Consolidating Balance Sheets
	December 31, 2016
	Parent		Guarantor		Eliminations			Consolidated
	(in thousands)
Assets
Current assets	$	387,309	$	12,516	$	—		$	399,825
Properties and equipment, net	1,889,419		2,118,847		—			4,008,266
Intercompany receivable	9,415		—		(9,415		)	—
Investment in subsidiaries	1,765,092		—		(1,765,092		)	—
Goodwill	—		62,041		—			62,041
Noncurrent assets	15,539		171		—			15,710
Total Assets	$	4,066,774	$	2,193,575	$	(1,774,507	)	$	4,485,842

Liabilities and Stockholders' Equity
Current liabilities	$	235,121	$	35,457	$	—		$	270,578
Intercompany payable	—		9,415		(9,415		)	—
Long-term debt	1,043,954		—		—			1,043,954
Other noncurrent liabilities	164,945		383,611		—			548,556
Stockholders' equity	2,622,754		1,765,092		(1,765,092		)	2,622,754
Total Liabilities and Stockholders' Equity	$	4,066,774	$	2,193,575	$	(1,774,507	)	$	4,485,842



	Condensed Consolidating Statements of Operations
	Three Months Ended June 30, 2017
	Parent			Guarantor			Eliminations		Consolidated
	(in thousands)

Operating and other revenues	$	252,346		$	22,812		$	—	$	275,158
Operating expenses	39,915			7,700			—		47,615
General and administrative	26,617			2,914			—		29,531
Depreciation depletion and amortization	108,727			17,286			—		126,013
Impairment of properties and equipment	531			27,035			—		27,566
Provision for uncollectible notes receivable	(40,203		)	—			—		(40,203		)
Interest (expense) income	(19,032		)	183			—		(18,849		)
Income (loss) before income taxes	97,727			(31,940		)	—		65,787
Income tax expense	(36,285		)	11,748			—		(24,537		)
Equity in loss of subsidiary	(20,192		)	—			20,192		—
Net income (loss)	$	41,250		$	(20,192	)	$	20,192	$	41,250



	Condensed Consolidating Statements of Operations
	Six Months Ended June 30, 2017
	Parent			Guarantor			Eliminations		Consolidated
	(in thousands)

Operating and other revenues	$	507,087		$	41,778		$	—	$	548,865
Operating expenses	77,415			14,380			—		91,795
General and administrative	50,146			5,700			—		55,846
Depreciation depletion and amortization	210,465			24,864			—		235,329
Impairment of properties and equipment	1,134			28,625			—		29,759
Provision for uncollectible notes receivable	(40,203		)	—			—		(40,203		)
Interest (expense) income	(38,389		)	313			—		(38,076		)
Income (loss) before income taxes	169,741			(31,478		)	—		138,263
Income tax expense	(62,448		)	11,581			—		(50,867		)
Equity in loss of subsidiary	(19,897		)	—			19,897		—
Net income (loss)	$	87,396		$	(19,897	)	$	19,897	$	87,396

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2017

(unaudited)

Net losses of the Guarantor for the three and six months ended June 30, 2017 are primarily the result of the impairment of certain unproved Delaware Basin leasehold positions during the respective periods.



	Condensed Consolidating Statements of Cash Flows
	Six Months Ended June 30, 2017
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Cash flows from operating activities	$	246,128		$	17,069		$	—		$	263,197
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural properties	(198,954		)	(135,452		)	—			(334,406		)
Capital expenditures for other properties and equipment	(1,792		)	(507		)	—			(2,299		)
Acquisition of crude oil and natural gas properties, including settlement adjustments	—			5,372			—			5,372
Proceeds from sale of properties and equipment	1,293			—			—			1,293
Sale of promissory note	40,203			—			—			40,203
Restricted cash	(9,250		)	—			—			(9,250		)
Purchases of short-term investments	(49,890		)	—			—			(49,890		)
Sales of short-term investments	49,890			—			—			49,890
Intercompany transfers	(109,923		)	—			109,923			—
Net cash from investing activities	(278,423		)	(130,587		)	109,923			(299,087		)
Cash flows from financing activities:
Proceeds from issuance of equity, net of issuance costs	—			—			—			—
Purchase of treasury stock	(5,274		)	—			—			(5,274		)
Other	(627		)	(18		)	—			(645		)
Intercompany transfers	—			109,923			(109,923		)	—
Net cash from financing activities	(5,901		)	109,905			(109,923		)	(5,919		)
Net change in cash and cash equivalents	(38,196		)	(3,613		)	—			(41,809		)
Cash and cash equivalents, beginning of period	240,487			3,613			—			244,100
Cash and cash equivalents, end of period	$	202,291		$	—		$	—		$	202,291

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PDC ENERGY, INC.

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

The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this report. Further, we encourage you to ~~revisit~~review the Special Note Regarding Forward-Looking Statements.

EXECUTIVE SUMMARY

Financial Overview

Production volumes increased ~~substantially~~ to ~~6.0~~8.0 MMboe and ~~15.8~~14.7 MMboe for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, respectively, representing increases of ~~39%~~ 54 percentand ~~49%, respectively,~~50 percent as compared to the three and ~~nine~~six months ended ~~September~~June 30, ~~2015.~~2016, respectively. The ~~increase~~increases in production volumes ~~was~~were primarily attributable to the continued success of our ~~successful~~ horizontal Niobrara and Codell drilling program in the Wattenberg ~~Field.~~ Field and our first full six months of production from our recently-acquired Delaware Basin properties.Crude oil production increased ~~17%~~62 percent and ~~27%~~47 percent for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, respectively, compared to the ~~same prior year periods.~~three and six months ended June 30, 2016. Crude oil production comprised approximately ~~39%~~40 percent and ~~40%~~ 39 percentof total production in the three and ~~nine~~six months ended ~~September~~June 30, 2016. Our ratio of crude oil production to total production decreased as compared to 2015 as expected as we shifted our focus to the higher gas to oil ratio inner core area of the Wattenberg Field during the first half of 2016. We expect our ratio of crude oil to total production to increase by the end of 2016 as we move drilling operations back toward the middle core area of the Wattenberg Field. Natural gas2017, respectively. NGL production increased ~~47%~~66 percent and ~~60% in~~70 percent for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, respectively, compared to the three and ~~nine~~six months ended ~~September~~June 30, ~~2015. NGL~~2016. Natural gas production increased ~~80%~~40 percent and ~~83% for~~43 percent in the three and ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, respectively, compared to the ~~same prior year periods. Our inner core wells have shown stronger wet gas~~three and six months ended June 30, 2016.On a combined basis, total liquids production ~~than anticipated, which has contributed to~~comprised 63 percent and 59 percent of our total production during the ~~growth~~three months ended June 30, 2017 and June 30, 2016, respectively, and 62 percent and 60 percent of ~~gas~~total production during the six months ended June 30, 2017 and ~~NGL production. Our~~June 30, 2016, respectively. For the three months ended June 30, 2017, we maintained an average daily production rate of approximately 88,100 Boe per day, up from approximately 57,100 Boe per day for the three months ended ~~September~~June 30, ~~2016 increased approximately 0.8 MMboe, or 16%,~~2016.

On a sequential quarterly basis, total production volumes for the three months ended June 30, 2017, as compared to the three months ended ~~June~~March 31, 2017, increased by 21 percent, while crude oil production increased by 30 ~~2016. We expect a modest~~percent during the same period. The increase in production ~~for~~was primarily related to 84 wells in our Wattenberg Field being turned-in-line during the first six months of 2017 and a 47 percent increase in our average daily production in the Delaware Basin from the first quarter, to approximately 10,000 Boe per day in the quarter ended June 30, 2017. We expect that we will see modest sequential production growth in the third quarter of 2017 and leveling off of production in the fourth quarter of ~~2016 as compared to~~2017, based on the ~~third quarter, as we have approximately 20 fewer wells scheduled to be turned-in-line during~~adjusted timing for our turn-in-lines, and expected capacity considerations associated with gathering system line pressures in the fourth quarter, and we expect all remaining 2016 well completions to be concluded by the middle of the fourth quarter of 2016. For the month ended September 30, 2016, our average production rate was 63 MBoe per day, up from 47 MBoe per day for the month ended September 30, 2015.Wattenberg Field.

~~Crude oil, natural gas and NGLs sales, coupled with the impact of settled derivatives, increased during the three and nine months ended September 30, 2016 relative to the same prior year periods.~~ Crude oil, natural gas, and NGLs sales increased to ~~$141.8~~$213.6 million and ~~$328~~$403.3 million ~~during~~in the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017, respectively, compared to ~~$104.5~~$110.8 million and ~~$275.5~~$186.2 million in the ~~same prior year periods due to 39%~~three and ~~49%~~six months ended June 30, 2016, respectively. These 93 percent and 117 percent increases in sales revenues were driven by the 54 percentand 50 percent increases in production ~~respectively, offset~~and 25 percent and 44 percent increases in ~~part by 2% and 20% decreases, respectively, in the~~ realized price per barrel of crude oil equivalent ("Boe"). The realized prices per Boe were $23.62 and $20.80 for the three and nine months ended September 30, 2016, respectively, compared to $24.15 and $26.02, respectively, for the same prior year periods. Positivecommodity prices.

We had positive net settlements ~~on derivatives decreased to $47.7~~from our commodity derivative contracts of $12.0 million for the three months ended ~~September~~June 30, ~~2016 and increased to $167.9 million during the nine months ended September 30, 2016~~2017 as compared to positive net settlements onof $53.3 million for the three months ended June 30, 2016. We had positive net settlements of $12.6 million for the six months ended June 30, 2017, as compared to positive net settlements of $120.1 million for the six months ended June 30, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior to commodity prices becoming depressed in late 2014. Substantially all of these higher-value derivatives settled by the end of ~~$68 million~~2016. Net settlements for the three and ~~$162.5 million~~six months ended June 30, 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices. Based upon the forward strip pricing at June 30, 2017, we expect that settlements will continue to be substantially lower in 2017 than in 2016. See Results of Operations - Commodity Price Risk Management, Net for further details of our settlements of derivatives and changes in the ~~same prior year periods. As a result~~fair value of ~~these aggregate changes,~~unsettled derivatives.

The combined revenue from crude oil, natural gas, and NGLs sales and the impact of net settled derivatives totaled $189.5 million and $495.9 million during the three and nine months ended September 30, 2016, respectively, compared to $172.5 million and $438 million during the three and nine months ended September 30, 2015, respectively. This represents increases of 10% and 13% during the three and nine months ended September 30, 2016, respectively, compared to the same prior year periods. The realized prices per Boe, including the impact of net settlements received on ~~derivatives, were $31.56 and $31.44 for the three and nine months ended September 30, 2016, respectively, compared to $39.88 and $41.37 for the same prior year periods, respectively.~~

~~Additional significant changes impacting~~ our ~~results of operations for the three months ended September 30, 2016 include the following:~~

Negative net change in the fair value of unsettled derivative positions during the three months ended September 30, 2016 was $28.3 million compared to a positive net change in the fair value of unsettled derivative positions of $55.5 million during the same prior year period. The decrease in fair value of unsettled derivative positions was primarily attributable to a less significant upward shift in the crude oil and natural gas forward curves, offset by the impact of the beginning of period fair value ofcommodity derivative instruments ~~settled in the respective periods, during the current quarter as compared~~increased 37 percent to ~~the three months ended September 30, 2015;~~

~~Impairment of properties and equipment decreased to~~ ~~$0.9~~$225.6 million for the three months ended September 30, 2016 compared to $154 million in the same prior year period, primarily related to the $150.3 million write-down of our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value in the three months ended ~~September~~June 30, ~~2015;~~

~~General and administrative expense increased to $32.5~~2017, from $164.1 million ~~for~~in the three months ended ~~September~~June 30, 2016, ~~compared~~and increased 36 percent to ~~$20.3~~$415.9 million in the ~~same prior year period, primarily due to $11.3 million of fees and expenses related to the pending Delaware Basin Acquisition;~~

~~Depreciation, depletion and amortization expense increased to $112.9 million during the three~~six months ended ~~September~~June 30, ~~2016 compared to $80.9~~2017, from $306.3 million in the ~~same prior year period, primarily due to increased production; and~~

~~Interest expense increased to $20.2 million for the three~~six months ended ~~September~~June 30, ~~2016 compared to $12.1 million in the same prior year period, primarily attributable to a $9 million charge for the bridge loan commitment related to the Delaware Basin Acquisition.~~2016.

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PDC ENERGY, INC.

~~Additional significant changes impacting our results of operations for the nine months ended September 30, 2016 include the following:~~

Negative net change in the fair value of unsettled derivative positions during the nine months ended September 30, 2016 was $230.2 million compared to a negative net change in the fair value of unsettled derivative positions of $21.3 million during the same prior year period. The decrease in fair value of unsettled derivative positions was primarily attributable to an upward shift in the crude oil and natural gas forward curves that occurred during 2016;

Impairment of properties and equipment decreased to $6.1 million for the nine months ended September 30, 2016 compared to $161.2 million in the same prior year period, primarily related to the $150.3 million write-down of our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value in the three months ended September 30, 2015;

General and administrative expense increased to $78.9 million for the nine months ended September 30, 2016 compared to $62.1 million in the same prior year period, primarily due to $11.3 million of fees and expenses related to the Delaware Basin Acquisition;

Depreciation, depletion and amortization expense increased to $317.3 million during the nine months ended September 30, 2016 compared to $206.9 million in the same prior year period, primarily due to increased production and, to a lesser extent, a higher weighted-average depreciation, depletion and amortization rate;

During the first quarter of 2016, we determined that collection of a third-party note receivable arising from the sale of our interest in properties in the Marcellus Shale was not reasonably assured based then current market conditions and new information made available to us. As a result, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44 million outstanding balance as of March 31, 2016. As of September 30, 2016, there has been no change to our assessment of the collectibility of the note. See Note 3, ~~Fair Value of Financial Instruments - Notes Receivable, to our condensed consolidated financial statements included elsewhere in this report for additional information; and~~

Interest expense increased to $42.8 million for the nine months ended September 30, 2016 compared to $35.4 million in the same prior year period, primarily attributable to a $9 million charge for the bridge loan commitment related to the Delaware Basin Acquisition.

In March 2016, we completed a public offering of 5,922,500 shares of our common stock at a price to us of $50.11 per share. Net proceeds of the offering were $296.6 million, after deducting offering expenses and underwriting discounts. We used a portion of the net proceeds of the offering to repay all amounts then outstanding on our revolving credit facility and the principal amount owed upon the maturity of the Convertible Notes in May 2016 and retained the remainder for general corporate purposes.

The 2016 Convertible Notes matured in May 2016. We settled the 2016 Convertible Notes with a combination of cash and stock, paying the aggregate principal amount, plus cash for fractional shares, totaling approximately $115 million, utilizing proceeds from the offering. Additionally, we issued 792,406 shares of common stock for the excess conversion value.

~~In June 2016, we entered into definitive agreements with Noble to consolidate certain acreage positions in the core Wattenberg Field.~~

In September 2016, we closed the acreage exchange transaction. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties. The difference in net acres is primarily due to variances in leasehold net revenue interests and third-party mid-stream contracts. This acreage trade is expected to increase opportunities for longer horizontal laterals with significantly increased working interests, while minimizing potential surface impact.

~~Pending Delaware Basin Acquisition~~

We seek acquisition opportunities as part of our overall growth strategy, and in particular have recently engaged in the process of searching for, and evaluating, a large-scale acquisition in a new U.S. onshore basin capable of creating material long-term value-added growth, focusing on four key criteria: top-tier acreage in core geologic positions, significant drilling inventory with additional expansion through downspacing, portfolio optionality for capital allocation and diversification and the ability to deliver long-term corporate accretion. In August 2016, we identified a potential acquisition, which we refer to as the Delaware Basin Acquisition, that we believe met our four key criteria.

We entered into definitive agreements relating to the Delaware Basin Acquisition in August 2016. The agreements contemplate that we will acquire an aggregate of approximately 57,000 net acres, approximately 30 wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $915 million in cash and approximately 9.4 million shares of our common stock (valued at approximately $590 million at the time the acquisition agreements were executed), subject to certain adjustments and ongoing due diligence. The acquisition agreements allow the sellers to include a specified amount of additional leases in the transaction, which would increase the purchase price. Upon executing the acquisition agreements, we paid a $100 million deposit toward the cash portion of the purchase price into an escrow account. In some circumstances set forth in the acquisition agreements, we could be required to forfeit the $100 million deposit. The Delaware Basin Acquisition is expected to initially increase our daily production by approximately 7,000 Boe per day. The acquisition is expected to close in December 2016; however, there can be no assurance conditions to closing will be satisfied. Upon closing, we currently expect to initially run a two rig drilling program in the Delaware Basin. We are currently completing our budgeting process for 2017, but anticipate running two to three rigs in the Delaware Basin during 2017. Taking into account the anticipated plans for the Delaware Basin Acquisition properties, we expect that pursuit of our development program will require capital in excess of our projected cash flows from operations for some period of time beginning in 2017.

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~~PDC ENERGY, INC.~~

In order to fund the cash portion of the Delaware Basin Acquisition, we completed a public offering of 9,085,000 shares of our common stock, a public offering of the 2021 Convertible Notes and a private offering of the 2024 Senior Notes in September 2016 (collectively, the "Securities Issuances"). The common stock was issued at a price to us of $61.51 per share for net proceeds of approximately $558.5 million, after deducting offering expenses and underwriting discounts. Net proceeds of the issuances of the 2021 Convertible Notes and 2024 Senior Notes were approximately $194 million and $392.3 million, respectively, after deducting offering expenses and underwriting discounts. If the Delaware Basin Acquisition is not completed on or prior to December 31, 2016 (or in some circumstances by or on January 15, 2017), the 2024 Senior Notes will be redeemed in whole at a special mandatory redemption price equal to 100% of the aggregate principal amount of the 2024 Senior Notes, plus accrued and unpaid interest.

Prior to the Securities Issuances, we entered into a commitment letter with JPMorgan regarding certain aspects of the temporary financing of the Delaware Basin Acquisition. The commitment letter contemplated, among other things, (i) a senior unsecured bridge loan to us in an aggregate principal amount not to exceed $600 million, to be drawn, if at all, at the closing of the Delaware Basin Acquisition, (ii) a $250 million increase in the commitments under our existing revolving credit facility and (iii) certain related proposed amendments and waivers to our existing credit facility agreement. We expect to fund the cash consideration payable in the Delaware Basin Acquisition with proceeds from the Securities Issuances. Following the completion of the Securities Issuances, the bridge loan commitment was terminated. Upon closing of the Delaware Basin Acquisition, we will be required to pay approximately $9 million in fees related to the bridge loan commitment, approximately $6 million in fees related to the increase in commitments under the revolving credit facility and approximately $10 million in other direct acquisition-related costs. During the three months ended ~~September~~June 30, 2017, we impaired certain unproved Delaware Basin leasehold positions totaling $27.0 million that expired during the three months ending June 30, 2017, or are projected to expire between June 30, 2017 and December 31, 2017. Subsequent to closing the acquisitions in the Delaware Basin, it was determined that development of certain acreage tracts would not meet our internal expectations for acceptable rates of return due to a combination of weakening commodity prices; higher per well development and operational costs; and updated technical analysis. As a result, we allowed or expect to allow certain acreage to expire, and in other circumstances we were unable to obtain necessary lease term extensions. As of June 30, 2017, our current leasehold position in the Delaware Basin is approximately 60,000 net acres.

In the three and six months ended June 30, 2017, we generated net income of $41.2 million and $87.4 million, respectively, or$0.62 and $1.32 per diluted share, respectively. During the same periods, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $200.4 million and $330.6 million, respectively. Our net income and adjusted EBITDAX were positively impacted by the sale of the $40.2 million Promissory Note and the collection of the related cash proceeds in April 2017, as further described below in Results of Operations - Provision for Uncollectible Notes Receivable. Beginning in 2017, we have included non-cash stock-based compensation and exploration, geologic and geophysical expense in our reconciliation of adjusted EBITDAX. In prior periods, we included adjusted EBITDA, a non-U.S. GAAP financial measure, which did not include these adjustments. All prior periods have been conformed for comparability of this updated presentation. In the three and six months ended June 30, 2016, ~~we recorded charges~~our net loss per diluted share was $2.04 and $3.78, respectively, and our adjusted EBITDAX, a non-GAAP financial measure, was $122.4 million and $180.2 million, respectively. Our cash flow from operations was $263.2 million and our adjusted cash flow from operations, a non-U.S. GAAP financial measure, was $256.6 million in the six months ended June 30, 2017. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for ~~the bridge loan commitment fees~~a more detailed discussion of these non-U.S. GAAP financial measures and ~~the other direct acquisition-related costs. The $9 million charge for fees related~~a reconciliation of these measures to the bridge loan commitment is included in interest expense and the $10 million charge for other direct acquisition-related costs is included in general and administrative expenses. The liabilities associated with both amounts are included in other accrued expenses on our condensed consolidated balance sheet as of September 30, 2016.most comparable U.S. GAAP measures.

~~Liquidity~~

Available liquidity as of ~~September~~June 30, ~~2016~~2017 was ~~$1,636~~$902.3 million, ~~compared to $402.2 million as of December 31, 2015. Available liquidity as of September 30, 2016~~which is comprised of ~~$1,197.7~~$202.3 million of cash and cash equivalents and ~~$438.3~~$700.0 million available for borrowing under our revolving credit ~~facility. These amounts exclude~~facility at our current commitment level. We expect decreases in our cash balance over the course of 2017 as we continue planned development in the core Wattenberg Field and further capital investment in our Delaware Basin assets.

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 attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an ~~additional $250 million available~~active commodity derivative hedging program, potential utilization of our borrowing capacity under our revolving credit facility, ~~that will be available following the closing of the Delaware Basin Acquisition~~ and ~~may be available in other circumstances subject~~when warranted, capital markets transactions from time to certain terms and conditions of the agreement. In October 2016, we completed the semi-annual redetermination of our revolving credit facility by the lenders, which resulted in the reaffirmation of the borrowing base at $700 million. We have elected to maintain the aggregate commitment level at $450 million until the closing of the Delaware Basin Acquisition. Cash and cash equivalents as of September 30, 2016 included approximately $392.3 million of proceeds from the issuance of the 2024 Senior Notes. If, however, the Delaware Basin Acquisition is not completed prior to or on December 31, 2016 (or in some circumstances by or on January 15, 2017), the $400 million principal amount of the 2024 Senior Notes is required to be redeemed with interest. If required, we will redeem the 2024 Senior Notes with available cash. With our current derivative position, available liquidity and expected cash flows from operations, we believe we have sufficient liquidity to allow us to fund our operations and the cash portion of the purchase price for the Delaware Basin Acquisition and execute our expected 2016 development program.

The following table presents our liquidity as of September 30, 2016 pro forma for the closing of the Delaware Basin Acquisition, reflecting cash to be paid and the increase in the aggregate commitments under our revolving credit facility:

As of September 30, 2016 Amount
(in millions)
Cash and cash equivalents $ 1,197.7
Available for borrowing under our credit facility 438.3
Available liquidity 1,636.0
Increase in aggregate commitments under our revolving credit facility 250.0
Cash due upon closing of the Delaware Basin Acquisition (1) (840.0 )
Adjusted liquidity $ 1,046.0

~~__________~~

~~(1)~~Amount includes total cash portion of purchase price due to sellers, less $100 million deposit in escrow and estimated acquisition-related costs. Amount does not reflect potential purchase price adjustments to be determined upon and post closing.

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~~PDC ENERGY, INC.~~

time.

Operational Overview

During the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, we continued to execute our strategic plan to grow production while preserving our financial strength and liquidity. ~~Through July 2016,~~During the second quarter of 2017, we ~~ran~~operated four ~~automated~~ drilling rigs in the Wattenberg ~~Field. In August 2016, we decreased the number of automated~~Field and four drilling rigs ~~running~~in the Delaware Basin. Our drilling efficiency in the Wattenberg Field over the last two quarters has resulted in shorter drill cycle times; therefore, we expect to decrease our rig count to three rigs beginning in ~~anticipation~~the fourth quarter of ~~higher working interests in wells drilled resulting from~~2017. Because of the ~~aforementioned acreage exchange with Noble. During~~shorter drill times, the ~~nine months ended September 30, 2016, we spud 107 horizontal wells and turned-in-line 121 horizontal wells~~impact of the reduced rig count on our expected turn-in-line count in the Wattenberg Field. We also participated in 11 gross, 2.8 net, horizontal non-operated wells that were spud and 24 gross, 5.0 net, horizontal non-operated wells which were turned-in-line. During the nine months ended September 30, 2016, we drilled and completed five wells in the Utica Shale, three of which were turned-in-line during the period. Of these three wells, oneField is an approximately 10,000 foot lateral well located in Guernsey County and two are approximately 6,000 foot lateral wells located in Washington County. We plan to turn-in-line the two remaining wells over the next several months.

~~2016 Operational Outlook~~

~~We expect our production for 2016~~expected to be ~~at the high end or slightly exceed the 21.0 MMBoe to 22.0 MMBoe range disclosed earlier~~minimal in ~~the year and our production rate for December 2016 to exceed 71,000 Boe per day, including the impact of expected production from~~2017. In the Delaware Basin, ~~Acquisition, assuming the acquisition closes~~one rig contract expired in December 2016. Our revised 2016 capital forecast of $400 million to $420 million is focused on continuing to provide value-driven production growth by exploiting our substantial inventory of projects in the Wattenberg Field. Currently, excluding acquisition costs thatAugust 2017, and we expect to ~~incur~~utilize three drilling rigs through the end of 2017. Our active drilling program in ~~2016 related to~~ the Delaware Basin ~~Acquisition, we expect~~in the first half of 2017 provided us with a degree of flexibility with respect to ~~be near or slightly below~~holding acreage in the ~~low end of~~area on a near-term basis and allows us to shift immediate focus to improving drill cycle times and the ~~expected range~~per well costs of our ~~capital expenditures.~~

Delaware Basin wells.

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PDC ENERGY, INC.

~~Colorado Ballot Initiative Update~~

The following tables summarizes our drilling and completion activity for the six months ended June 30, 2017:

During 2016, certain interest groups in Colorado opposed to oil and natural gas development generally, or hydraulic fracturing in particular, advanced various options for ballot initiatives aimed at significantly limiting or effectively preventing oil and natural gas development in the state of Colorado. Proponents of two such initiatives attempted to qualify the initiatives to appear on the ballot for the November 2016 election. On August 29, 2016, the Colorado Secretary of State issued a press release and statements of insufficiency of signatures, stating that the proponents of the proposals had failed to collect enough valid signatures to have the proposals included on the ballot.

One of the initiatives, which we refer to as the “local control” initiative, would have amended the state constitution to give city, town and county governments the right to regulate, or to ban, oil and gas development and production within their boundaries, notwithstanding rules and approvals to the contrary at the state level. This proposal was motivated in part by a decision of the Colorado Supreme Court earlier this year holding that local government restrictions on oil and gas activities are subject to preemption by state rules.

A second initiative, which we refer to as the “setback” initiative, would have amended the state constitution to require all new oil and gas development facilities to be located at least 2,500 feet away from any occupied structure or broadly defined “area of special concern,” including public and community drinking water sources, lakes, rivers, perennial or intermittent streams, creeks, irrigation canals, riparian areas, playgrounds, permanent sports fields, amphitheaters, public parks and public open space.

If implemented, the setback initiative would have effectively prohibited the vast majority of our planned future drilling activities in Colorado and would therefore have made it impossible to pursue our current development plans. The local control proposal would potentially have had a similar effect, depending on the nature and extent of regulations implemented by relevant local governmental authorities. Pursuant to the determination of the Colorado Secretary of State, these proposals will not appear on the November 2016 ballot. However, future proposals of this nature are possible.



	Wells Operated by PDC
	Wattenberg Field				Delaware Basin				Total
	Gross		Net		Gross		Net		Gross		Net
In-process as of December 31, 2016	64		52.7		5		4.8		69		57.5
Wells spud	73		65.7		12		11.0		85		76.7
Wells turned-in-line to sales	(72	)	(59.2	)	(9	)	(8.7	)	(81	)	(67.9	)
In-process as of June 30, 2017	65		59.2		8		7.1		73		66.3

Because substantially all of our current operations and reserves are located in Colorado, the risks we face with respect to such future proposals are greater than those of our competitors with more geographically diverse operations. Although we cannot predict the outcome of future ballot initiatives, statutes or regulatory developments, such developments could materially impact our results of operations, production and reserves.



	Wells Operated by Others
	Wattenberg Field				Delaware Basin		Total
	Gross		Net		Gross	Net	Gross		Net
In-process as of December 31, 2016	18		3.4		—	—	18		3.4
Wells spud	71		9.0		3	0.8	74		9.8
Wells turned-in-line to sales	(12	)	(1.9	)	—	—	(12	)	(1.9	)
In-process as of June 30, 2017	77		10.5		3	0.8	80		11.3

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 but uncompleted wells ("DUCs") are generally completed and turned in-line to sales within three to nine months of drilling. The majority of the in-process wells at each period end are DUCs, as we do not begin the completion process until the entire well pad is drilled. As we continue to monitor our capital investment and due to the efficiencies gained by our operating team in the Wattenberg Field, we expect that we will have an increase of approximately 25 wells in our in-process well count at December 31, 2017, as compared to December 31, 2016, resulting from faster than expected drill cycle times. All appropriate costs incurred through the end of the period have been capitalized, while the capital investment to complete the wells will be incurred in the period in which the wells are completed.

2017 Operational Outlook

Based on our revised timing and the estimated productivity of wells associated with our capital investment program, we currently believe that our 2017 production will be approximately 32 MMBoe. We expect that approximately 40 percent of our 2017 production will be crude oil and approximately 23 percent will be NGLs, for total liquids of approximately 63 percent. The anticipated percentage of production from NGLs has increased due to the success of field recovery efforts and improved yields by our third-party processors in the Wattenberg Field.

We expect our capital expenditures to be approximately $800 million in 2017, an estimate that we have increased to account for higher per well costs in the Delaware Basin and increases in the total expected number of wells to be spud in the Wattenberg Field during the year. We also added a third and fourth rig in the first quarter of 2017 in the Delaware Basin, which was sooner than initially contemplated in our budget, in order to protect certain leasehold positions and to create greater future operational flexibility. This flexibility as it relates to holding acreage in the Delaware Basin is particularly important given the volatility of commodity prices and potential further service cost increases in the Delaware Basin as it should allow us to adjust our drilling program to two rigs in this area if necessary for a period of time without risk of losing significant additional acreage.

Further, some additional capital investment has been included in our forecast for an anticipated Wattenberg Field acreage trade that would, if completed, increase our working interest in certain wells. The trade is expected to close in the second half of 2017.

Wattenberg Field. The 2017 investment forecast has been reduced to approximately $450 million in the Wattenberg Field with three rigs running in the fourth quarter of 2017. Approximately $445 million of our 2017 capital investment program is expected to be allocated to development activities, comprised of approximately $425 million for our operated drilling program and approximately $20 million for wells drilled and operated by others. The remainder of the

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Wattenberg Field capital investment program is expected to be used for miscellaneous well equipment and capital projects. Wells in the Wattenberg Field typically have productive horizons at a depth of approximately 6,500 to 7,500 feet below the surface. In 2017, our revised investment forecast anticipates spudding approximately 155 and turning-in-line approximately 133 horizontal operated wells with lateral lengths of 4,000 to 10,000 feet.

Delaware Basin. Our 2017 investment forecast contemplates the operation of a three-rig program for the remainder of 2017 in the Delaware Basin. Total capital investment in the Delaware Basin has been increased to approximately $345 million, of which approximately $285 million is allocated to spud 24 and turn-in-line an estimated 20 wells. Expected per well drilling costs in the Delaware Basin have increased by approximately 15 to 20 percent during the second quarter of 2017 as compared to the first quarter of 2017, primarily due to higher costs of services and supplies and longer than anticipated drill cycle times. To enhance our understanding of the geology in the Delaware Basin, we initiated various engineering studies on most of our Delaware Basin wells, including expanded depth pilot holes and logging/seismic services. These studies are providing important information to our operating team; however, they have come with additional unexpected costs. Additionally, mechanical issues have resulted in cost overruns for certain wells. Of the 20 planned turn-in-lines during 2017, 9 are expected to have extended laterals of approximately 10,000 horizontal feet with an estimated 70 to 75 completion stages per well. Similarly spaced completion stages are anticipated for the remaining 11 turn-in-lines. Wells in the Delaware Basin typically have productive horizons at a depth of approximately 9,000 to 11,000 feet below the surface. We plan to invest approximately $15 million for leasing, seismic, and technical studies with an additional $35 million for midstream-related projects including gas connections and surface location infrastructure. The remaining $10 million of the Delaware Basin capital investment program is expected to be used for non-operated capital projects.

We expect to incur costs associated with the purchase of seismic data and pilot hole exploratory work in the Delaware Basin, which will be accounted for as exploration, geologic, and geophysical expense. We estimate that this will result in approximately $5 million to $10 million of exploration expense in 2017.

Utica Shale. As a result of our evaluation of our strategic alternatives with respect to our Utica Shale position, we are working toward a divestiture of these properties during 2017. As of June 30, 2017, these assets did not meet the accounting criteria to be classified as held-for-sale; therefore, they continue to be included in properties and equipment on our condensed consolidated balance sheets. Subsequent to June 30, 2017, we engaged an investment banking group to assist in marketing the Utica properties for sale; therefore, these operations are expected to be classified as held-for-sale upon meeting the criteria for such classification in the third quarter of 2017.

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Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results:


	Three Months Ended September 30,								Nine Months Ended September 30,								Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			Percentage Change		2016			2015			Percentage Change		2017		2016		Percentage Change		2017		2016		Percentage Change
	(dollars in millions, except per unit data)																(dollars in millions, except per unit data)
Production ~~(1)~~
Crude oil (MBbls)	2,339.8			2,007.8			16.5	%	6,240.2			4,895.9			27.5	%	3,237		1,993		62.4	%	5,745		3,900		47.3	%
Natural gas (MMcf)	13,417.4			9,148.9			46.7	%	36,768.2			22,997.0			59.9	%	17,783		12,673		40.3	%	33,367		23,351		42.9	%
NGLs (MBbls)	1,428.1			793.0			80.1	%	3,402.8			1,858.5			83.1	%	1,814		1,092		66.1	%	3,357		1,975		70.0	%
Crude oil equivalent (MBoe) ~~(2)~~	6,004.2			4,325.6			38.8	%	15,771.0			10,587.3			49.0	%	8,015		5,197		54.2	%	14,663		9,767		50.1	%
Average MBoe per day	65.3			47.0			38.8	%	57.6			38.8			49.0	%
Average Boe per day (Boe)																	88,078		57,111		54.2	%	81,011		53,664		50.9	%
Crude Oil, Natural Gas and NGLs Sales
Crude oil	$	98.5		$	78.3		25.8	%	$	233.0		$	206.7		12.7	%	$	148.8	$	80.4	85.1	%	$	271.8	$	134.4	102.2	%
Natural gas	27.4			18.8			45.7	%	59.6			49.4			20.6	%	38.3		17.4		120.1	%	75.3		32.3		133.1	%
NGLs	15.9			7.4			114.9	%	35.4			19.4			82.5	%	26.5		13.0		103.8	%	56.2		19.5		188.2	%
Total crude oil, natural gas and NGLs sales	$	141.8		$	104.5		35.7	%	$	328.0		$	275.5		19.1	%
Total crude oil, natural gas, and NGLs sales																	$	213.6	$	110.8	92.8	%	$	403.3	$	186.2	116.6	%

Net Settlements on Derivatives (3)
Net Settlements on Commodity Derivatives
Crude oil	$	39.5		$	60.7		(34.9	)%	$	131.6		$	142.4		(7.6	)%	$	5.1	$	38.7	(86.8	)%	$	1.9	$	92.0	(97.9	)%
Natural gas	8.2			7.3			12.3	%	36.3			20.1			80.6	%	6.8		14.6		(53.4	)%	10.6		28.1		(62.3	)%
NGLs (propane portion)																	0.1		—		*		0.1		—		*
Total net settlements on derivatives	$	47.7		$	68.0		(29.9	)%	$	167.9		$	162.5		3.3	%	$	12.0	$	53.3	(77.5	)%	$	12.6	$	120.1	(89.5	)%

Average Sales Price (excluding net settlements on derivatives)																	Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	42.11		$	38.98		8.0	%	$	37.33		$	42.22		(11.6	)%	$	45.97	$	40.37	13.9	%	$	47.31	$	34.46	37.3	%
Natural gas (per Mcf)	2.04			2.05			(0.5	)%	1.62			2.15			(24.7	)%	2.16		1.37		57.7	%	2.26		1.38		63.8	%
NGLs (per Bbl)	11.12			9.40			18.3	%	10.41			10.45			(0.4	)%	14.59		11.93		22.3	%	16.75		9.89		69.4	%
Crude oil equivalent (per Boe)	23.62			24.15			(2.2	)%	20.80			26.02			(20.1	)%	26.65		21.33		24.9	%	27.50		19.07		44.2	%

Average Lease Operating Expenses (per Boe) (4)
Wattenberg Field	$	2.39		$	3.31		(27.8	)%	$	2.77		$	4.24		(34.7	)%
Utica Shale	1.27			1.74			(27.0	)%	1.87			1.77			5.6	%
Weighted-average	2.33			3.20			(27.2	)%	2.73			4.04			(32.4	)%

Natural Gas Marketing Contribution Margin (5)	$	(0.4	)	$	(0.2	)	100.0	%	$	(1.1	)	$	(0.6	)	(83.3	)%

Other Costs and Expenses
Average Costs and Expenses (per Boe)
Lease operating expenses																	$	2.50	$	2.63	(4.9	)%	$	2.72	$	2.97	(8.4	)%
Production taxes	$	9.6		$	5.5		74.7	%	$	19.7		$	13.2		49.0	%	1.88		1.16		62.1	%	1.87		1.04		79.8	%
Transportation, gathering and processing expenses	5.0			3.9			28.2	%	13.6			6.6			105.9	%	0.81		0.86		(5.8	)%	0.84		0.87		(3.4	)%
Impairment of properties and equipment	0.9			154.0			(99.4	)%	6.1			161.2			(96.2	)%
General and administrative expense	32.5			20.3			60.3	%	78.9			62.1			27.1	%	3.68		4.54		(18.9	)%	3.81		4.75		(19.8	)%
Depreciation, depletion and amortization	112.9			80.9			39.5	%	317.3			206.9			53.4	%	15.72		20.59		(23.7	)%	16.05		20.93		(23.3	)%
Provision for uncollectible notes receivable	(0.7		)	—			*		44.0			—			*

Interest expense	$	20.2		$	12.1		67.0	%	$	42.8		$	35.4		20.8	%
Lease Operating Expenses by Operating Region (per Boe)																	Lease Operating Expenses by Operating Region (per Boe)
Wattenberg Field																	$	2.22	$	2.66	(16.5	)%	$	2.42	$	3.00	(19.3	)%
Delaware Basin																	4.88		—		*		5.53		—		*
Utica Shale																	1.34		2.08		(35.6	)%	1.48		2.28		(35.1	)%


*	Percentage change is not ~~meaningful or equal to or greater than 300%.~~meaningful.

Amounts may not recalculate due to rounding.

~~______________~~


~~(1)~~	~~Production is net and determined by multiplying the gross production volume of properties in which we have an interest by our ownership percentage.~~


~~(2)~~	~~One Bbl of crude oil or NGL equals six Mcf of natural gas.~~


~~(3)~~	~~Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to natural gas marketing.~~


~~(4)~~	~~Represents lease operating expenses, exclusive of production taxes, on a per unit basis.~~


~~(5)~~	Represents sales from natural gas marketing, net of costs of natural gas marketing, including net settlements and net change in fair value of unsettled derivatives related to natural gas marketing activities.

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PDC ENERGY, INC.

Crude Oil, Natural Gas, and NGLs Sales

For the three and six months ended June 30, 2017, crude oil, natural gas, and NGLs sales revenue increased compared to the three and six months ended June 30, 2016 due to the following (in millions):



	June 30, 2017
	Three Months Ended		Six Months Ended
	(in millions)
Increase in production	$	65.9	$	91.1
Increase in average crude oil price	18.2		73.8
Increase in average natural gas price	13.9		29.2
Increase in average NGLs price	4.8		23.0
Total increase in crude oil, natural gas and NGLs sales revenue	$	102.8	$	217.1

Crude Oil, Natural Gas, and NGLs Production

The following tables present crude oil, natural gas, and NGLs production. Our acquisitions of assets in the Delaware Basin closed in December 2016; therefore, there is no comparative data for the three and six months ended June 30, 2016:



	Three Months Ended June 30,				Six Months Ended June 30,
Production by Operating Region	2017	2016	Percentage Change		2017	2016	Percentage Change
Crude oil (MBbls)
Wattenberg Field	2,798	1,894	47.7	%	4,940	3,712	33.1	%
Delaware Basin	364	—	*		639	—	*
Utica Shale	75	99	(24.4	)%	166	188	(12.1	)%
Total	3,237	1,993	62.4	%	5,745	3,900	47.3	%
Natural gas (MMcf)
Wattenberg Field	15,192	12,098	25.6	%	28,906	22,268	29.8	%
Delaware Basin	2,025	—	*		3,271	—	*
Utica Shale	566	575	(1.6	)%	1,190	1,083	9.9	%
Total	17,783	12,673	40.3	%	33,367	23,351	42.9	%
NGLs (MBbls)
Wattenberg Field	1,551	1,047	48.1	%	2,909	1,888	54.1	%
Delaware Basin	212	—	*		343	—	*
Utica Shale	51	45	11.9	%	105	87	19.8	%
Total	1,814	1,092	66.1	%	3,357	1,975	70.0	%
Crude oil equivalent (MBoe)
Wattenberg Field	6,882	4,957	38.8	%	12,667	9,311	36.0	%
Delaware Basin	914	—	*		1,527	—	*
Utica Shale	219	240	(8.5	)%	469	456	2.8	%
Total	8,015	5,197	54.2	%	14,663	9,767	50.1	%
Average crude oil equivalent per day (Boe)
Wattenberg Field	75,621	54,478	38.8	%	69,984	51,159	36.8	%
Delaware Basin	10,047	—	*		8,437	—	*
Utica Shale	2,410	2,633	(8.5	)%	2,590	2,505	3.4	%
Total	88,078	57,111	54.2	%	81,011	53,664	51.0	%

* Percentage change is not meaningful.

Amounts may not recalculate due to rounding.

In the Wattenberg Field, we rely on third-party midstream service providers to construct gathering, compression, and processing facilities to keep pace with our, and the overall field's natural gas production growth. From time to time, our production has been adversely affected by high line pressures on the gas gathering facilities, primarily due to higher ambient temperatures and increases in field-wide production volumes. In 2015, our primary midstream service provider added additional facilities which significantly reduced production constraints from late 2015 to mid-2017. However, we are

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starting to experience higher line pressures due primarily to continued growth in field-wide production volumes. As a result, we anticipate higher production curtailments in the second half of 2017 and through most of 2018 until our primary midstream provider completes construction of an additional midstream plant and facilities. We believe that our 2017 production guidance range appropriately reflects the foreseeable impact of such higher gathering line pressures in the Wattenberg Field; however, such curtailment estimations may differ from the actual impact to production due to incremental uncertainties.

We continue work closely with our third party midstream providers in an effort to ensure adequate system capacity going forward in the Wattenberg Field. For example, we along with other operators, made a commitment with DCP Midstream, LP ("DCP") in December 2016 in connection with DCP's construction of additional gathering, compression, and processing facilities in the field. This expansion is expected to increase DCP's system capacity, assist in the control of line pressures on its natural gas gathering facilities, and reduce production curtailments in the field. We will be bound to the incremental volume requirements in this agreement on the first day of the calendar month after the actual in-service date of the plant, which is currently expected to occur in late 2018. The agreement imposes a baseline volume commitment and we are required for the first three years of the contract to guarantee a certain target profit margin to DCP on these volumes sold. Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments, and we believe that the contractual target profit margin will be achieved without an additional payment from us. See footnote titled Commitments and Contingencies for additional details regarding the agreement. We also seek to negotiate construction of incremental projects designed to add capacity to our primary third-party midstream service provider's system between major new facility expansions.

The ultimate timing and availability of adequate infrastructure is not within our control and if our midstream service provider’s construction projects are delayed, we could experience higher gathering line pressures that may negatively impact our ability to fulfill our growth plans. Total system infrastructure performance may also be affected by a number of other factors, including potential additional increases in production from the Wattenberg Field.

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PDC ENERGY, INC.

Crude Oil, Natural Gas, and NGLs ~~Sales~~

~~The following tables present crude oil, natural gas and NGLs production and weighted-average sales price:~~

Three Months Ended September 30, Nine Months Ended September 30,
Production by Operating Region 2016 2015 Percentage Change 2016 2015 Percentage Change
Crude oil (MBbls)
Wattenberg Field 2,216.3
1,868.6
18.6 % 5,928.5
4,509.5
31.5 %
Utica Shale 123.5
139.2
(11.3 )% 311.7
386.4
(19.3 )%
Total 2,339.8
2,007.8
16.5 % 6,240.2
4,895.9
27.5 %
Natural gas (MMcf)
Wattenberg Field 12,700.0
8,478.3
49.8 % 34,968.2
21,040.7
66.2 %
Utica Shale 717.4
670.6
7.0 ��% 1,800.0
1,956.3
(8.0 )%
Total 13,417.4
9,148.9
46.7 % 36,768.2
22,997.0
59.9 %
NGLs (MBbls)
Wattenberg Field 1,353.0
730.6
85.2 % 3,240.4
1,692.5
91.5 %
Utica Shale 75.1
62.4
20.4 % 162.4
166.0
(2.2 )%
Total 1,428.1
793.0
80.1 % 3,402.8
1,858.5
83.1 %
Crude oil equivalent (MBoe)
Wattenberg Field 5,686.0
4,012.3
41.7 % 14,996.9
9,708.8
54.5 %
Utica Shale 318.2
313.3
1.6 % 774.1
878.5
(11.9 )%
Total 6,004.2
4,325.6
38.8 % 15,771.0
10,587.3
49.0 %

~~Amounts may not recalculate due to rounding.~~

Three Months Ended September 30, Nine Months Ended September 30,
Average Sales Price by Operating Region Percentage Change Percentage Change
(excluding net settlements on derivatives) 2016 2015 2016 2015
Crude oil (per Bbl)
Wattenberg Field $ 42.29
$ 38.90
8.7 % $ 37.42
$ 42.13
(11.2 )%
Utica Shale 38.93
40.02
(2.7 )% 35.61
43.28
(17.7 )%
Weighted-average price 42.11
38.98
8.0 % 37.33
42.22
(11.6 )%
Natural gas (per Mcf)
Wattenberg Field $ 2.08
$ 2.11
(1.4 )% $ 1.63
$ 2.17
(24.9 )%
Utica Shale 1.33
1.36
(2.2 )% 1.44
1.92
(25.0 )%
Weighted-average price 2.04
2.05
(0.5 )% 1.62
2.15
(24.7 )%
NGLs (per Bbl)
Wattenberg Field $ 11.07
$ 9.62
15.1 % $ 10.32
$ 10.36
(0.4 )%
Utica Shale 12.14
6.80
78.5 % 12.22
11.40
7.2 %
Weighted-average price 11.12
9.40
18.3 % 10.41
10.45
(0.4 )%
Crude oil equivalent (per Boe)
Wattenberg Field $ 23.77
$ 24.32
(2.3 )% $ 20.83
$ 26.07
(20.1 )%
Utica Shale 20.98
22.04
(4.8 )% 20.26
25.47
(20.5 )%
Weighted-average price 23.62
24.15
(2.2 )% 20.80
26.02
(20.1 )%

~~Amounts may not recalculate due to rounding.~~

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~~PDC ENERGY, INC.~~

~~For the three and nine months ended September 30, 2016, crude oil, natural gas and NGLs sales revenue increased compared to the three and nine months ended September 30, 2015 due to the following:~~

September 30, 2016
Three Months Ended Nine Months Ended
(in millions)
Increase in production $ 27.7
$ 102.5
Increase (decrease) in average crude oil price 7.3
(30.5 )
Decrease in average natural gas price (0.1 ) (19.4 )
Increase (decrease) in average NGLs price 2.4
(0.1 )
Total increase in crude oil, natural gas and NGLs sales revenue $ 37.3
$ 52.5

Production for the third quarter of 2016 was 6.0 million Boe, up from 4.3 million Boe in the third quarter of 2015. Year-to-date, production was 15.8 million Boe, up from 10.6 million Boe in the first nine months of 2015. Production increased as a result of continued drilling and completion activities as discussed in Operational Overview.

From time to time, our production has been adversely affected by high line pressures in the Wattenberg Field. Such pressures did not materially affect our production for the three or nine months ended September 30, 2016. We rely on our third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with our production growth. We, along with other operators in the Wattenberg Field, continue to work closely with our third-party midstream providers in an effort to ensure adequate system capacity going forward. The timing and availability of adequate infrastructure, including potential line pressure impacts in 2017, is not within our control and may be affected by a number of factors, including potential increases in production from the Wattenberg Field and warmer than expected weather.Pricing

~~Crude Oil, Natural Gas and NGLs Pricing~~. Our results of operations depend upon many factors. Key factors ~~particularly~~are the price of crude oil, natural gas, and NGLs and our ability to market our production effectively. Crude oil, natural gas, and NGL prices ~~are among the most volatile~~have a high degree of ~~all commodity prices. While the price of~~volatility and our realizations can change substantially. Our realized prices for crude oil, ~~decreased~~natural gas, and NGLs increased during the ~~first nine~~three and six months ~~of 2016~~ended June 30, 2017 compared to the ~~first nine~~three and six months ~~of 2015,~~ended June 30, 2016. NYMEX crude oil increased 6 percent and 27 percent, and natural gas prices increased ~~during the third quarter of 2016~~63percent and 61 percent, respectively, as compared to the ~~first half of 2016 as the number of U.S. crude oil rigs~~three and inventories declined. Natural gas prices decreased during the first nine months of 2016 when compared to the same prior year period. Although we did experience improved pricing by the end of the third quarter of 2016, due to an oversupply of nearly all domestic NGLs products, our average realized sales price for NGLs during the first nine months of 2016 reflected the same low levels seen during 2015. With the initiation of ethane exports and increased demand for NGLs, we are starting to see NGL prices trend upward.

Crude oil pricing is predominately driven by the physical market, supply and demand, financial markets and national and international politics. In the Wattenberg Field, crude oil is sold under various purchase contracts with monthly and longer term pricing provisions based on NYMEX pricing, adjusted for differentials. We have entered into longer term commitments ranging from three months to six months to deliver crude oil to competitive markets and these agreements have resulted in significantly improved deductions compared to the comparable period in 2015. We continue to pursue various alternatives with respect to oil transportation, particularlyended June 30, 2016. The realized NGL prices in the Wattenberg Field ~~with a view toward further improving pricing~~are reflected in the tables below, net of the processing and ~~limiting our use of trucking of production. We began delivering crude oil~~transport costs that are embedded in ~~accordance with our long term commitment to~~ the ~~White Cliffs Pipeline, LLC ("White Cliffs") pipeline in July 2015. This is one of several agreements we have entered into to facilitate deliveries of~~applicable percent-of-proceeds contracts, as are a portion of our ~~crude oil to the Cushing, Oklahoma market. In addition, we have signed a long-term agreement for gathering~~Delaware Basin NGL sales.

The following tables present weighted-average sales prices of crude oil, atnatural gas, and NGLs for the ~~wellhead by pipeline from several~~periods presented. Our acquisitions of ~~our pads~~assets in the ~~Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability~~Delaware Basin closed in December 2016; therefore, there is no comparative data for the three and reducing the overall physical footprint of our well pads. We began delivering crude oil into this pipeline during the fourth quarter of 2015 and the system was fully operational on certain wells in 2016. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual pad based on NYMEX pricing, adjusted for differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities or barge loading terminals on the Ohio River.six months ended June 30, 2016:

~~Natural gas prices vary by region and locality, depending upon the distance~~



	Three Months Ended June 30,						Six Months Ended June 30,
Weighted-Average Realized Sales Price by Operating Region					Percentage Change						Percentage Change
(excluding net settlements on derivatives)	2017		2016		Percentage Change		2017		2016		Percentage Change
Crude oil (per Bbl)
Wattenberg Field	$	46.19	$	40.41	14.3	%	$	47.46	$	34.51	37.5	%
Delaware Basin	44.81		—		*		46.73		—		*
Utica Shale	43.19		39.57		9.1	%	45.05		33.44		34.7	%
Weighted-average price	45.97		40.37		13.9	%	47.31		34.46		37.3	%
Natural gas (per Mcf)
Wattenberg Field	$	2.24	$	1.36	64.7	%	$	2.30	$	1.38	66.7	%
Delaware Basin	1.37		—		*		1.60		—		*
Utica Shale	2.76		1.58		74.7	%	2.88		1.51		90.7	%
Weighted-average price	2.16		1.37		57.7	%	2.26		1.38		63.8	%
NGLs (per Bbl)
Wattenberg Field	$	14.13	$	11.87	19.0	%	$	16.24	$	9.78	66.1	%
Delaware Basin	17.33		—		*		19.33		—		*
Utica Shale	17.10		13.27		28.9	%	22.58		12.29		83.7	%
Weighted-average price	14.59		11.93		22.3	%	16.75		9.89		69.4	%
Crude oil equivalent (per Boe)
Wattenberg Field	$	26.91	$	21.27	26.5	%	$	27.50	$	19.03	44.5	%
Delaware Basin	24.91		—		*		27.32		—		*
Utica Shale	25.72		22.59		13.9	%	28.29		19.75		43.2	%
Weighted-average price	26.65		21.33		24.9	%	27.50		19.07		44.2	%

* Percentage change is not meaningful.

Amounts may not recalculate due to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The price we receive for our natural gas produced in the Wattenberg Field is based on CIG and local utility prices, adjusted for certain deductions, while natural gas produced in the Utica Shale is based on TETCO M-2 pricing. We anticipate that the significant Appalachian pipeline differentials that impact our Utica Shale natural gas will continue through the remainder of 2016 and into 2017.

Our price for NGLs produced in the Wattenberg Field is based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. The NGLs produced in the Utica Shale are sold based on month-to-month pricing to various markets. While NGL prices had been declining, we have seen a stabilization of prices in 2016.rounding.

Our crude oil, natural gas, and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the ~~"net-back"~~net-back method of accounting for natural gas and NGLs, as well as the majority of our crude oil production from the Wattenberg Field, for all of our crude oil, NGLs, and a portion of our natural gas in the Delaware Basin, and for crude oil from the Utica Shale, as ~~the majority of~~ the purchasers of these commodities also provide transportation, gathering, and processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds, or have fixed our sales price at index less specified deductions. We sell our commodities at the wellhead, or what is equivalent to the wellhead in situations where we gather multiple wells into larger pads, and collect a price and recognize revenues based on the wellhead sales price, as transportation and processing costs downstream of the wellhead are incurred by the purchaser and ~~reflected~~therefore embedded in the wellhead price. The net-back method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we earn.

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~~wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.~~ We use the ~~"gross"~~gross method of accounting for Wattenberg Field crude oil delivered through certain pipelines, a portion of our natural gas in the ~~White Cliffs and Saddle Butte pipelines~~Delaware Basin, and for natural gas and NGLs sales related to production from the Utica Shale, as the purchasers do not provide transportation, gathering or processing ~~services.~~services as a function of the price we earn. Rather, we contract separately with midstream providers for the applicable transport and processing based 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 a result of the White Cliffs and Saddle Butte agreements, during the nine months ended September 30, 2016, our Wattenberg Field crude oil average sales price increased approximately $1.24 per barrel relative to the benchmark price because we recognized the costs for transportation on the White Cliffs and Saddle Butte pipelines as an increase in transportation expense, rather than as a deduction from revenues.

~~Lease Operating Expenses~~

~~Lease operating expenses during~~As discussed above, we enter into agreements for the ~~three months ended September 30, 2016 increased $0.2 million as compared to~~sale and transportation, gathering and processing of our production, the ~~three months ended September 30, 2015, primarily due to increases~~terms of ~~$0.8 million~~which can result in variances in the per unit realized prices that we receive for payroll and employee benefits and $0.8 million for leased compressors to address increases in line pressure. These increases were partially offset by decreases of $1 million related to mechanical integrity testing of wells and $0.2 million in environmental project costs. Lease operating expenses during the nine months ended September 30, 2016 increased $0.3 million as compared to the nine months ended September 30, 2015, primarily due to increases of $1.6 million for payroll and employee benefits, $1.1 million for leased compressors to address line pressure issues and $1 million for various other lease operating expenses. These increases were partially offset by decreases of $2.6 million for environmental project costs and $0.7 million for plugging and abandonment costs. Lease operating expenses per Boe decreased 27% and 32% to $2.33 and $2.73 during the three and nine months ended September 30, 2016, respectively, compared to $3.20 and $4.04 during the three and nine months ended September 30, 2015, respectively. The significant decreases in lease operating expense per Boe were the result of production growth of 39% and 49%, respectively.

~~Production Taxes~~

~~Production taxes are directly related to~~our crude oil, natural gas and ~~NGLs sales. The $4.1 million increase in production taxes during the three months ended September 30, 2016 compared to the three months ended September 30, 2015 was primarily~~NGLs. Information related to the ~~36% increase~~components and classifications in the condensed consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based upon average daily prices throughout each month and our natural gas ~~and NGLs sales, as well as higher severance tax rates~~average NYMEX pricing is based upon ~~projected~~first-of-the-month index prices as this is the method used to sell the majority of each of these commodities pursuant to terms of the respective sales ~~revenue. The $6.5 million increase in production taxes during~~agreements. For NGLs, we use the ~~nine months ended September 30, 2016 compared to the nine months ended September 30, 2015 was primarily related to the 19% increase in~~NYMEX crude oil ~~natural gas and NGLs sales,~~price as ~~well as higher severance tax rates due to higher projected sales revenue coupled with~~ a ~~decrease in ad valorem tax credits available from 2015 production due to depressed commodity pricing in 2015.~~

~~Transportation, Gathering and Processing Expenses~~

reference for presentation purposes. The ~~$1.1 million increase in~~average realized price before transportation, gathering, and processing expenses ~~during~~shown in the three months ended September 30, 2016 compared to the three months ended September 30, 2015 was mainly attributable to oil transportation costs on the Saddle Butte pipeline as we began delivering crude oil on this pipeline in December 2015. The $7 million increase in transportation, gathering and processing expenses during the nine months ended September 30, 2016, compared to the nine months ended September 30, 2015, was mainly attributable to oil transportation costs on the White Cliffs and Saddle Butte pipelines as we began delivering crude oil on these pipelines in July 2015 and December 2015, respectively. We expect to continue to incur these oil transportation costs pursuant totable below represents our ~~long-term transportation agreements.~~approximate composite per barrel price for NGLs.



For the three months ended June 30, 2017	Average NYMEX Price		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	48.28	95	%	$	45.97	$	1.38	$	44.59
Natural gas (per MMBtu)	3.18		68	%	2.16		0.08		2.08
NGLs (per Bbl)	48.28		30	%	14.59		0.31		14.28
Crude oil equivalent (per Boe)	37.48		71	%	26.65		0.81		25.84

For the three months ended June 30, 2016	Average NYMEX Price		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	45.59	89	%	$	40.37	$	1.63	$	38.74
Natural gas (per MMBtu)	1.95		70	%	1.37		0.07		1.30
NGLs (per Bbl)	45.59		26	%	11.93		0.26		11.67
Crude oil equivalent (per Boe)	31.82		67	%	21.33		0.86		20.47

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For the six months ended June 30, 2017	Average NYMEX Price		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	50.10	94	%	$	47.31	$	1.44	$	45.87
Natural gas (per MMBtu)	3.25		70	%	2.26		0.09		2.17
NGLs (per Bbl)	50.10		33	%	16.75		0.35		16.40
Crude oil equivalent (per Boe)	38.50		71	%	27.50		0.84		26.66

For the six months ended June 30, 2016	Average NYMEX Price		Average Realization Percentage Before Transportation, Gathering and Processing Expenses		Average Realized Price Before Transportation, Gathering and Processing Expenses		Average Transportation, Gathering and Processing Expenses		Average Realized Price After Transportation, Gathering and Processing Expenses
Crude oil (per Bbl)	$	39.52	87	%	$	34.46	$	1.58	$	32.88
Natural gas (per MMBtu)	2.02		68	%	1.38		0.08		1.30
NGLs (per Bbl)	39.52		25	%	9.89		0.28		9.61
Crude oil equivalent (per Boe)	28.60		67	%	19.07		0.87		18.20

Commodity Price Risk Management, Net

We use ~~various~~commodity derivative instruments to manage fluctuations in crude oil, natural gas, and ~~crude oil~~NGLs prices. We have in place a variety of collars, fixed-price swaps, and basis swaps on a portion of our estimated crude oil, natural gas, and ~~crude oil~~propane production. Because we sell all of our crude oil, natural gas, and ~~crude oil~~NGLs production at prices ~~similar~~related to the indexes inherent in our underlying derivative instruments, ~~adjusted for certain fees and surcharges stipulated in the applicable sales agreements,~~ we ultimately realize ~~a price, before contract fees,~~value related to our collars of no less than the floor and no more than the ~~ceiling and, for~~ceiling. For our commodity swaps, we ultimately realize the fixed price value related to ~~our swaps, less deductions.~~the swaps. See ~~Note 4,~~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 ~~September~~June 30, ~~2016.~~2017.

Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments and the change in fair value of unsettled commodity derivatives related to our crude oil, ~~and~~ natural gas, and propane production. Commodity price risk management, net, does not include derivative transactions related to our ~~natural~~ gas marketing, which are included in ~~sales from~~other income and ~~cost~~other expenses.

Net settlements of commodity derivative instruments are based on the difference between the crude oil, natural gas, ~~marketing. See Note 3,~~ ~~Fair Value of Financial Instruments~~, and ~~Note 4,~~ ~~Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for additional details of our derivative financial instruments.~~

~~Net settlements are primarily the result of crude oil and natural gas~~propane index prices at ~~maturity~~the settlement date of our commodity derivative instruments compared to the respective strike ~~prices. Net~~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 ~~asset~~value increase or decrease in the ~~beginning-of- period~~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 corresponding impact of settlement of the commodity derivative instruments ~~that settled~~ during the period is included in net settlements for the ~~period as discussed above. Net~~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, and NGLs forward curves and changes in ~~basis index pricing. See Note 4,~~ ~~Derivative Financial Instruments, to our condensed consolidated financial statements included elsewhere in this report for a detailed description of net settlements on our various derivatives.~~certain differentials.

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

Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
(in millions)
Commodity price risk management gain (loss), net:
Net settlements:
Crude oil $ 39.5
$ 60.7
$ 131.6
$ 142.4
Natural gas 8.2
7.3
36.3
20.1
Total net settlements 47.7
68.0
167.9
162.5
Change in fair value of unsettled derivatives:
Reclassification of settlements included in prior period changes in fair value of derivatives (40.6 ) (48.1 ) (169.5 ) (140.2 )
Crude oil fixed price swaps 3.3
50.4
(33.8 ) 51.4
Crude oil collars 1.5
28.5
(14.5 ) 28.6
Natural gas fixed price swaps 5.4
19.5
(10.7 ) 31.0
Natural gas basis swaps 1.4
(1.0 ) 0.7
(2.4 )
Natural gas collars 0.7
6.2
(2.4 ) 10.3
Net change in fair value of unsettled derivatives (28.3 ) 55.5
(230.2 ) (21.3 )
Total commodity price risk management gain (loss), net $ 19.4
$ 123.5
$ (62.3 ) $ 141.2



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017		2016
	(in millions)
Commodity price risk management gain (loss), net:
Net settlements of commodity derivative instruments:
Crude oil fixed price swaps and collars	$	5.1		$	38.7		$	1.9	$	92.0
Natural gas fixed price swaps and collars	4.8			14.6			8.5		28.1
Natural gas basis protection swaps	2.0			—			2.0		—
NGLs (propane portion) fixed price swaps	0.1			—			0.1		—
Total net settlements of commodity derivative instruments	12.0			53.3			12.5		120.1
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments	(5.1		)	(60.8		)	18.4		(115.5		)
Crude oil fixed price swaps and collars	43.1			(57.8		)	88.7		(62.8		)
Natural gas fixed price swaps and collars	8.3			(27.5		)	16.7		(23.1		)
Natural gas basis protection swaps	(0.2		)	—			2.3		(0.4		)
NGLs (propane portion) fixed price swaps	(0.2		)	—			—		—
Net change in fair value of unsettled commodity derivative instruments	45.9			(146.1		)	126.1		(201.8		)
Total commodity price risk management gain (loss), net	$	57.9		$	(92.8	)	$	138.6	$	(81.7	)

Net settlements of commodity derivatives decreased for the three and six months ended June 30, 2017 as compared to the three and six months ended June 30, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior to commodity prices becoming depressed in late 2014. Substantially all of these higher-value agreements had settled by the end of 2016. Net settlements for the three and six months ended June 30, 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices. Based upon the forward strip pricing at June 30, 2017, we expect that settlements will continue to be substantially lower in 2017 on a relative basis as compared to those in 2016.

Lease Operating Expenses

Lease operating expenses improved to $2.50 per Boe and $2.72 per Boe during the three and six months ended June 30, 2017, respectively, compared to $2.63 per Boe and $2.97 per Boe during the three and six months ended June 30, 2016, respectively. The improvement in lease operating expense per Boe was predominately driven by production growth of 54 percent and 50 percent during the three and six months ended June 30, 2017, respectively, which was partially offset by higher lease operating expense of $4.88 per Boe and $5.53 per Boe in the Delaware Basin during the three and six months ended June 30, 2017, respectively.

Aggregate lease operating expenses during the three months ended June 30, 2017 increased $6.4 million as compared to the three months ended June 30, 2016, of which $4.5 million related to our recently-acquired properties in the Delaware Basin. The increase of $6.4 million is primarily due to increases of $2.4 million for payroll and employee benefits related to increases in headcount for 2017 as compared to 2016, $1.0 million for water hauling, $1.0 million related to compressor rentals, and $0.5 million for workover projects. These increases were partially offset by a decrease of $0.4 million in environmental remediation costs.

Aggregate lease operating expenses during the six months ended June 30, 2017 increased $10.8 million as compared to the six months ended June 30, 2016, of which $8.4 million related to our recently-acquired properties in the Delaware Basin. The increase of $10.8 million is primarily due to increases of $4.2 million for payroll and employee benefits related to increases in headcount for 2017 as compared to 2016, $1.8 million for water hauling, $1.7 million for workover projects, and $1.7 million related to compressor rentals. These increases were partially offset by a decrease of $1.6 million in environmental remediation costs. We expect continued increases in our headcount through the remainder of 2017 as we grow our Delaware

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Basin production base and production team. We expect much of this increased cost of personnel will be offset by increases in our production.

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. There are a number of 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. The $9.0 million and $17.3 million increases in production taxes during the three and six months ended June 30, 2017, respectively, compared to the three and six months ended June 30, 2016 were primarily related to the 93 percent and 117 percent increases in crude oil, natural gas, and NGLs sales, and an increase in our effective tax rate to approximately seven percent for the three and six months ended June 30, 2017 as compared to five percent for the three and six months ended June 30, 2016.

Transportation, Gathering, and Processing Expenses

Transportation,gathering, and processing expenses increased $2.0 million and $3.9 million during the three and six months ended June 30, 2017, respectively, compared to the three and six months ended June 30, 2016. The primary drivers of these increases were $1.2 million and $2.2 million increases in oil transportation costs due to increased volumes delivered through a pipeline in the Wattenberg Field and increases of $0.7 million and $1.4 million related to natural gas gathering operations in our recently acquired properties in the Delaware Basin, respectively. When feasible, we use pipelines in the Wattenberg Field to deliver crude oil to the market in an effort to decrease field truck traffic and air emissions. Transportation, gathering, and processing expenses per Boe improved to $0.81 and $0.84 for the three and six months ended June 30, 2017, respectively, compared to $0.86 and $0.87 for the three and six months ended June 30, 2016, respectively.

Impairment of Properties and Equipment

Impairment of proved and unproved properties. Amounts represent the retirement or expiration of certain leases that are no longer part of our development plan or that we are not able to extend prior to termination of the lease. Deterioration of commodity prices or other operating circumstances could result in additional impairment charges as such a change could decrease the number of wells drilled in future periods.

During the three months ended June 30, 2017, we impaired certain unproved Delaware Basin leasehold positions totaling $27.0 million that expired during the three months ending June 30, 2017, or are projected to expire between June 30, 2017 and December 31, 2017. Subsequent to closing the acquisitions in the Delaware Basin, it was determined that development of certain acreage tracts would not meet our internal expectations for acceptable rates of return due to a combination of weakening commodity prices; higher per well development and operational costs; and updated technical analysis. As a result, we allowed or expect to allow certain acreage to expire, and in other circumstances we were unable to obtain necessary lease term extensions.

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015		2017		2016		2017		2016
	(in millions)								(in millions)

Impairment of proved and unproved properties	$	0.3	$	150.8	$	2.4	$	152.8
Impairment of unproved properties									$	27.5	$	1.1	$	29.6	$	2.1
Amortization of individually insignificant unproved properties	0.6		3.2		0.7		8.4		0.1		0.1		0.2		0.1
Impairment of crude oil and natural gas properties	0.9		154.0		3.1		161.2		27.6		1.2		29.8		2.2
Land and buildings	—		—		3.0		—		—		3.0		—		3.0
Impairment of properties and equipment	$	0.9	$	154.0	$	6.1	$	161.2
Total impairment of properties and equipment									$	27.6	$	4.2	$	29.8	$	5.2

General and Administrative Expense

~~Impairment of proved~~General and ~~unproved properties~~. Due to a significant decline in commodity prices and a decrease in net-back realizations in the third quarter of 2015, we experienced a triggering event that required us to assess our crude oil and natural gas propertiesadministrative expense increased $6.0 million for ~~possible impairment. As a result of our assessment, we recorded an impairment charge during~~ the three months ended ~~September~~June 30, 2015 of $150.3 million to write-down our Utica Shale proved and unproved properties. Of this impairment charge, $24.7 million was recorded to write-down certain capitalized well costs on our Utica Shale proved producing properties. Additionally,2017 as a result of the outlook for future commodity prices at that time, we recorded an impairment charge of $125.6 million to write-down all of our Utica Shale lease acquisition costs and pad development costs for pads not in production. Future deterioration of commodity prices could result in additional impairment charges to our crude oil and natural gas properties.

~~Amortization of individually insignificant unproved properties.~~ ~~Amounts relate to insignificant leases that were subject to amortization. The decreases in amortization during the three and nine months ended September 30, 2016~~ compared to the three ~~and nine~~ months ended ~~September~~June 30, ~~2015 were due~~2016, of which $2.9 million is related to the Delaware Basin. The increase of $6.0 million was primarily attributable to increases of $1.5 million in payroll and employee benefits related to an ~~impairment~~increase in ~~the third quarter of 2015 that significantly reduced the carrying value of our Utica Shale leases.~~

~~Land and buildings.~~ ~~The impairment charge~~headcount for the nine months ended September 30, 2016 represents the excess of the carrying value over the estimated fair value, less the cost to sell, of a field operating facility in Greeley, Colorado, and 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters. The fair values of these assets were determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input.2017

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~~General~~as compared to 2016, $1.1 million related to professional services, and ~~Administrative Expense~~$0.4 million in software maintenance agreements and subscriptions.

General and administrative expense increased ~~$12.2 million to $32.5~~$9.5 million for the ~~three~~six months ended ~~September~~June 30, 2017 as compared to the six months ended June 30, 2016, ~~compared~~of which $5.7 million is related to ~~$20.3 million for~~ the ~~three months ended September 30, 2015.~~Delaware Basin. The increase of $9.5 million was primarily attributable to ~~$11.3~~increases of $3.8 million ~~of fees and expenses related to the Delaware Basin Acquisition and a $1.2 million increase in payroll and employee benefits.~~

~~General and administrative expense increased $16.8 million to $78.9 million for the nine months ended September 30, 2016 compared to $62.1 million for the nine months ended September 30, 2015. The increase was primarily attributable to $11.3 million of fees and expenses related to the Delaware Basin Acquisition, a $4.5 million increase~~ in payroll and employee benefits ~~and a $0.6 million~~due to an increase in ~~costs~~headcount for ~~consulting~~2017 as compared to 2016, $1.8 million related to professional services, $0.7 million in software maintenance agreements and ~~other professional services.~~subscriptions, and $0.7 million in rent expense. We expect continued increases in our headcount through the remainder of 2017 as we build out our Delaware Basin operations.

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 ~~$112.1~~$124.4 million and ~~$314.4~~$232.2 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017, respectively, compared to ~~$79.8~~$106.1 million and ~~$203.5~~$202.4 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2015.~~ 2016, respectively. Through June 30, 2017, our capital investment in the Delaware Basin has not yet resulted in the addition of related proved reserves, resulting in an elevated DD&A expense rate for the three and six months ended June 30, 2017.

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


	September 30, 2016				June 30, 2017
	Three Months Ended		Nine Months Ended		Three Months Ended			Six Months Ended
	(in millions)				(in millions)
Increase in production	$	32.0	$	104.1	$	56.2		$	94.9
Increase in weighted-average depreciation, depletion and amortization rates	0.3		6.8
Decrease in weighted-average depreciation, depletion and amortization rates					(37.9		)	(65.1		)
Total increase in DD&A expense related to crude oil and natural gas properties	$	32.3	$	110.9	$	18.3		$	29.8

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended June 30,				Six Months Ended June 30,
Operating Region/Area	2016		2015		2016		2015		2017		2016		2017		2016
	(per Boe)								(per Boe)
Wattenberg Field	$	19.17	$	19.10	$	20.42	$	19.92	$	15.30	$	20.73	$	16.05	$	21.19
Delaware Basin									18.14		—		15.46		—
Utica Shale	9.59		10.08		10.52		11.49		11.27		13.84		11.26		11.16
Total weighted-average	18.66		18.44		19.94		19.22		15.51		20.41		15.83		20.72

Non-crude oil and natural gas properties.Depreciation expense for non-crude oil and natural gas properties was ~~$0.9~~$1.7 million and ~~$2.9~~$3.2 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, respectively, compared to ~~$1.2~~$0.9 million and ~~$3.4~~$2.0 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2015,~~2016, respectively.

Provision for Uncollectible Notes Receivable

~~During~~In the first quarter of 2016, we recorded a provision for uncollectible notes receivable of $44.7 million to impair two third-party notes receivable whose collection was not reasonably assured. ~~During~~As described in the ~~three months ended September 30, 2016, we subsequently collected a $0.7 million promissory note and reversed the related provision and allowance for uncollectible notes receivable. See Note 3,~~footnote titled Fair Value of Financial Instruments ~~- Notes Receivable~~, in April 2017, we signed a definitive agreement and simultaneously closed on the sale of one of the associated notes receivable to ~~our condensed consolidated financial statements included elsewhere~~an unrelated third-party. Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during the three months ended June 30, 2017, since all cash was collected in ~~this report~~April 2017 from the sale of the Promissory Note.

Interest Expense

Interest expense increased $8.9 million to $19.6 million for ~~additional information.~~the three months ended June 30, 2017 compared to $10.7 million for the three months ended June 30, 2016. The increase is primarily attributable to a $6.4 million increase in interest

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~~Interest Expense~~

~~Interest expense increased $8.1 million and $7.4 million during the three and nine months ended September 30, 2016 compared~~relating to the ~~three~~issuance of our 2024 Senior Notes, a $2.6 million increase in interest expense relating to the issuance of our 2021 Convertible Notes, and ~~nine months ended September 30, 2015. The increases were primarily attributable~~a $0.9 million increase related to ~~a $9 million charge~~fees for the ~~bridge loan commitment related to~~redetermination of the ~~Delaware Basin Acquisition,~~borrowing base under our revolving credit facility. These increases were partially offset by ~~decreases~~a $1.3 million decrease in interest expense on ~~the~~our 2016 Convertible Notes, ~~as they matured~~which were settled in May 2016.

Interest ~~Income~~

~~Interest income decreased $1.2~~expense increased $16.5 million ~~and $1.8~~to $39.1 million ~~during~~for the ~~three and nine~~six months ended ~~September~~June 30, ~~2016~~2017 compared to $22.6 million for the ~~three and nine~~six months ended ~~September~~June 30, ~~2015, as we ceased recognizing non-cash~~2016. The increase is primarily attributable to a $12.7 million increase in interest ~~income~~relating to the issuance of our 2024 Senior Notes, a $5.1 million increase in interest expense relating to the issuance of our 2021 Convertible Notes, and a $1.6 million increase related to fees for the redetermination of the borrowing base under our revolving credit facility. These increases were partially offset by a $3.4 million decrease in interest expense on ~~two third-party notes receivable.~~our 2016 Convertible Notes, which were settled in May 2016.

Provision for Income Taxes

~~See Note 7,~~ ~~Income Taxes, to the accompanying condensed consolidated financial statements included elsewhere in this report for a discussion of the changes in our~~The effective income tax ~~rate~~rates for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 were 37.3 percent and 36.8 percent expense on income, respectively, compared to ~~the three~~37.9 percent and ~~nine months ended September 30, 2015. The effective tax rate of 34.0% and 37.1%~~37.5 percent benefit on loss for the three and ~~nine~~six months ended ~~September~~June 30, 2016, ~~respectively, is~~respectively. The effective income tax rates are based onupon a full year forecasted pre-tax ~~loss~~income for the year adjusted for ~~state tax,~~ permanent ~~differences and discrete items of tax.~~differences. The forecasted full year effective income tax rate has been applied to the quarter-to-date pre-tax ~~loss~~income, resulting in aan income tax ~~benefit~~expense for the period. Because the estimate of full-year income or loss may change from quarter to quarter, the effective income tax rate for any particular quarter may not have a meaningful relationship to pre-tax income or loss for the quarter or the actual annual effective income tax rate that is determined at the end of the year.

~~Our deferred~~ The effective income tax ~~liability at September~~rates for the three and six months ended June 30, ~~2016 decreased $99.1~~2017 include discrete income tax benefits of $0.2 million ~~compared to December 31, 2015. This decrease is primarily attributable~~and $1.8 million relating to the ~~significant positive net settlements from derivatives~~excess income tax basis recognized with the vesting of stock awards during the ~~nine~~three and six months ended ~~September~~June 30, ~~2016~~2017, which resulted in a 0.3 percent and 1.3 percent reduction to our effective income tax rates. There were no significant discrete income tax items recorded during the ~~significant reduction in fair value of unsettled derivatives held at September~~three months ended June 30, ~~2016, partially offset by the $15 million deferred tax liability for the equity component of the 2021 Convertible Notes issued in September~~ 2016.

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

~~Net loss for~~The factors resulting in changes in net income in the three and ~~nine~~six months ended ~~September~~June 30, ~~2016 was $23.3~~2017 of $41.2 million and ~~$190.3~~$87.4 million, ~~compared to~~respectively, and a net loss ~~of $41.5 million and $71.3 million for~~in the three and ~~nine~~six months ended ~~September~~June 30, ~~2015. Adjusted~~2016 of $95.5 million and $167.0 million, respectively, are discussed above. These same reasons similarly impacted adjusted net ~~loss,~~income (loss), a non-U.S. GAAP financial measure, was $5.8 million and $47.7 million for the three and nine months ended September 30, 2016 compared to adjusted net loss of $75.9 million and $58.1 million for the same prior year periods. The components of the quarter-over-quarter and year-over-year changes in net loss are discussed above. These changes similarly impacted adjusted net loss, with the exception of the ~~tax affected~~ net change in fair value of unsettled ~~derivatives.~~derivatives, adjusted for taxes, of $28.7 million and $78.9 million for the three and six months ended June 30, 2017, respectively, and $90.5 million and $125.1 million for the three and six months ended June 30, 2016, respectively. Adjusted net income (loss), a non-U.S. GAAP financial measure, was $12.5 million and $8.5 million for the three and six months ended June 30, 2017, respectively, and adjusted net loss of $5.0 million and $41.9 million for the three and six months ended June 30, 2016, respectively. See Reconciliation of Non-U.S. GAAP Financial Measures, below for a more detailed discussion of this non-U.S. GAAP financial measure and a reconciliation of this measure to the most comparable U.S. GAAP measure.

Financial Condition, Liquidity and Capital Resources

~~Historically, our~~Our primary sources of liquidity ~~have been~~are cash flows from operating activities, our revolving credit facility, proceeds raised in debt and equity capital market transactions, and asset sales. For the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, our primary sources of liquidity were the net proceeds received from the March 2016 public offering of our common stock of $296.6 million, net proceeds from the Securities Issuances of approximately $1.1 billion, and net cash flows from operating activities ~~of $360.8~~were $263.2 million. We used a portion of the net proceeds of the March 2016 common stock offering to repay all amounts then outstanding on our revolving credit facility and the principal amount owed upon the maturity of the 2016 Convertible Notes in May 2016 and retained the remainder for general corporate purposes. The net proceeds from the Securities Issuances are expected to be used to fund a portion of the purchase price of the Delaware Basin Acquisition (see Note 6, ~~Pending Acquisition), to pay related fees and expenses and for general corporate purposes.~~

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 ~~substantially~~principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage 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. ~~The~~Our revolving credit agreement 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 significant fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. Given current commodity prices and our hedge position, we expect that positive net settlements on our derivative positions will continue to be a significant positive component of our 2016 cash flows from operations. As of September 30, 2016, the fair value of our derivatives was a net asset of $33.5 million. Based ~~on the forward pricing strip at September 30, 2016, we would expect positive net settlements totaling approximately $39.3 million during the fourth quarter of 2016. However, based~~ upon our ~~current~~ hedge position and assuming ~~current~~forward strip pricing inas of June 30, 2017, ~~and thereafter~~ our derivatives may ~~no longer~~not be a significant source of cash flow ~~and may result~~ in ~~cash outflows. For~~ the ~~nine months ended September 30, 2016 and 2015, net settled derivatives comprised approximately 47% and 57%, respectively, of our cash flows from operating activities. See Part I, Item 3,~~ ~~Quantitative and Qualitative Disclosures about Market Risk, included elsewhere in this report for additional information regarding our derivatives positions by year of maturity.~~near term.

Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility. At June 30, 2017, we had working capital of $65.6 million compared to $129.2 million at December 31, 2016. The decrease in working capital as of June 30, 2017 is primarily the result of a decrease in cash and cash equivalents of $41.8 million related to capital investment exceeding operating cash flows

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~~our revolving credit facility. At September 30, 2016, we had working capital of $1,148.8 million compared to $30.7 million at December 31, 2015. The~~andan increase in ~~working capital as~~accounts payable of ~~September 30, 2016 is primarily the result of~~$86.2 million related to increased development and exploration activity, which was partially offset by an increase in the net fair value of our unsettled commodity derivative instruments of $86.8 million.

Our cash and cash equivalents ~~related to the Securities Issuances and the repayment of the 2016 Convertible Notes in May 2016, offset in part by a decrease in the fair value of unsettled derivatives.~~

In recent periods, including the first nine months of 2016, we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of securities. We ended September 2016 with cash and cash equivalents of $1,197.7were $202.3 million at June 30, 2017 and availability under our revolving credit facility ~~of $438.3~~was $700.0 million, providing for a total liquidity position of ~~$1,636~~$902.3 million ~~compared~~as of June 30, 2017. We anticipate that our capital investments will exceed our cash flows from operating activities in 2017, resulting in cash and cash equivalents estimated to ~~$402.2~~be between $100 million atto $150 million as of December 31, ~~2015. These amounts exclude an additional $250 million available~~2017.

Based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, that will be available following the closing of the Delaware Basin Acquisition and may be available in other circumstances subject to certain terms and conditions of the agreement. The increase in liquidity of $1,233.8 million, or 306.8%, during the nine months ended September 30, 2016 was primarily attributable to net cash flows from operating activities of $360.8 million and net cash flows from financing activities of $1,284.8 million (including proceeds from the Securities Issuances), offset in part by cash paid for capital expenditures of $353.7 million. Our liquidity position was reduced by the cash payment of approximately $115 million upon the maturity of our 2016 Convertible Notes in May 2016. With our current derivative position, liquidity position and expected cash flows from operations, we believe that we have sufficient capital to fund our planned activities during 2017. Our liquidity was further augmented by the ~~cash portion~~$40.2 million of proceeds received in the second quarter of 2017 from the sale of the ~~purchase price for~~Promissory Note, as described previously.

Our revolving credit facility is a borrowing base facility and availability under the ~~Delaware Basin Acquisition~~facility is subject to redetermination each May and November, based upon a quantification of our ~~planned drilling operations for~~proved reserves at each June 30 and December 31, respectively. The maturity date of our revolving credit facility is May 2020. Our ability to borrow under the ~~next 12 months. We cannot, however, assure sources~~revolving credit facility is limited under our 2022 Senior Notes to the greater of ~~capital available to us in~~$700 million or the ~~past will be available to us in the future.~~calculated value under an Adjusted Consolidated Tangible Net Asset test, as defined.

In March 2015, we filed an automatic shelf registration statement on Form S-3 with the SEC. Effective upon filing, the shelf provides for the potential sale of an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants or purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital and to have the flexibility to raise such funds in one or more offerings should we perceive market conditions to be favorable. Pursuant to this shelf registration, we sold approximately four million shares of our common stock in March 2015 in an underwritten public offering at a price to us of $50.73 per share, approximately six million shares of our common stock in March 2016 in an underwritten public offering at a price to us of $50.11 per share and, in September 2016, approximately nine million shares of our common stock in an underwritten public offering at a price to us of $61.51 per share and $200 million principal amount of convertible notes in an underwritten offering at par.

~~In September 2016,~~May 2017, we entered into a ~~Third~~Fifth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, amends the revolving credit facility to ~~permit the completion~~reflect an increase of the Delaware Basin Acquisition and, effective upon closing of the acquisition, adjusts the interest rate payable on amounts borrowed under the facility and increases the aggregate commitments under the facility from $450 million to $700 million (with the borrowing base ~~remaining at~~from $700 ~~million). The maturity~~million to $950 million. We have elected to maintain a $700 million commitment level as of the date of this report. In addition, the Fifth Amendment made changes to certain of the covenants in the existing agreement as well as other administrative changes.

Amounts borrowed under the revolving credit facility bear interest at either an alternate base rate option or a LIBOR option as defined in the revolving credit facility plus an applicable margin, depending on the percentage of the commitment that has been utilized. As of June 30, 2017, the applicable margin is ~~May 2020.~~ 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment fee is 0.50 percent.

We had no balance outstanding ~~balance~~ on our revolving credit facility as of ~~September~~June 30, ~~2016. While~~2017. In May 2017, we ~~have added~~replaced our $11.7 million irrevocable standby letter of credit that we held in favor of a third-party transportation service provider to secure a firm transportation obligation with a $9.3 million deposit, which is classified as restricted cash and ~~expect to continue to add producing reserves through~~is included in other assets on the condensed consolidated balance sheet. As of June 30, 2017, the available funds under our ~~drilling operations, the effect of any such reserve additions~~revolving credit facility was $700 million based on our borrowing base could be offset by other factors including, among other things, a prolonged period of depressed commodity prices or regulatory pressure on lenders to reduce their exposure to exploration and production companies.elected commitment level.

In October 2016, we entered into the Fourth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, reaffirmed our borrowing base at $700 million and made certain other immaterial modifications to the existing agreement, including an increase in the amount we can hedge of our future production.

Our revolving credit facility contains financial maintenance covenants. The covenants require that we ~~maintain:~~maintain (i) a leverage ratio defined as total debt of less than ~~4.25~~4.0 times the trailing 12 months earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled commodity derivatives, exploration expense, gains (losses) on sales of assets and other non-cash ~~extraordinary or non-recurring~~ gains (losses) ~~("EBITDAX")~~ and (ii) an adjusted current ratio of at least ~~1.0 to~~ 1.0:1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of crude oil and natural gas commodity derivative instruments. Additionally, available borrowings under our revolving credit facility are added to the current asset calculation and the current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. ~~Effective upon closing of the Delaware Basin Acquisition, the maximum leverage ratio will be modified to a maximum of 4.00 to 1.00.~~ At ~~September~~June 30, ~~2016,~~2017, we were in compliance with all debt covenants, as defined by the revolving credit agreement, with a ~~2.2 times debt to EBITDAX~~leverage ratio of 1.9 and a ~~8.9 to 1.0~~ current ~~ratio.~~ratio of 3.3. We expect to remain in compliance throughout the next ~~year.~~12-month period.

The indentures governing our ~~2024~~2022 Senior Notes and ~~2022~~2024 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. At ~~September~~June 30, ~~2016,~~2017, we were in compliance with all covenants and expect to remain in compliance throughout the next ~~year.~~12-month period.

~~See Part I, Item 3,~~ ~~Quantitative~~In January 2017, pursuant to the filing of the supplemental indentures for the 2021 Convertible Senior Notes, the 2022 Senior Notes, and ~~Qualitative Disclosures about Market Risk, for~~the 2024 Senior Notes, our ~~discussion~~subsidiary PDC Permian, Inc. became a guarantor of ~~credit risk.~~the notes.

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Cash Flows

Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs, and general and administrative expenses. Cash flows from operating activities increased by ~~$77.8~~$65.4 million for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2015,~~2016, primarily due to increases in crude oil, natural gas and NGLs sales of ~~$52.5 million, net settlements from our derivative positions of $5.4~~$217.1 million and ~~crude oil, and~~

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~~the~~an increase in changes in assets and liabilities of ~~$45.2~~$12.3 million related to the timing of cash payments and receipts. These increases were offset in part by a decrease in commodity derivative settlements of $107.6 million and increases in production taxes of $17.3 million, interest expense of $16.5 million, lease operating expenses of $10.8 million, and general and administrative expenses of ~~$16.8 million, transportation, gathering and processing expenses of $7 million and production taxes of $6.5~~$9.5 million. ~~The key components for the changes in our cash flows provided by operating activities are described in more detail in~~ ~~Results of Operations~~ ~~above.~~

Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased ~~$32.6~~$53.0 million during the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017 compared to the ~~nine~~six months ended ~~September~~June 30, ~~2015.~~2016. 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. Adjusted ~~EBITDA,~~EBITDAX, a non-U.S. GAAP financial measure, ~~decreased~~increased by ~~$16.6~~$150.4 million during the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017, compared to the ~~nine~~six months ended ~~September~~June 30, ~~2015.~~2016. The ~~decrease~~increase was primarily the result of recording a provision for uncollectible notes receivable of $44 million and the increases in transportation, gathering and processing expenses of $7 million, production taxes of $6.5 million and general and administrative expense of $16.8 million, offset in part by increases in crude oil, natural gas and NGLs sales of ~~$52.5~~$217.1 million, the recording of a provision for uncollectible notes receivable of $44.7 million during the six months ended June 30, 2016, and the reversal of a provision for uncollectible notes receivable of $40.2 million during the six months ended June 30, 2017. These increases were partially offset by a decrease in commodity derivative settlements of $107.6 million and ~~net settlements from our derivative positions~~increases in production taxes of ~~$5.4~~$17.3 million, lease operating expenses of $10.8 million, and general and administrative expenses of $9.5 million. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of non-U.S. GAAP financial 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 ~~expenditures.~~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 ~~$448.8~~$299.1 million during the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017, was primarily related to cash utilized for our drilling operations, including completion activities of ~~$353.7~~$334.4 million, purchases of short-term investments of $49.9 million, and a ~~$100~~$9.3 million deposit ~~toward~~with a third-party transportation service provider for surety of an existing firm transportation obligation previously secured by a letter of credit. Partially offsetting these investments was the ~~cash portion~~receipt of approximately $49.9 million related to the sale of short-term investments, $40.2 million from the sale of the ~~purchase price~~Promissory Note, and $5.4 million related to post-closing settlements of ~~the Delaware Basin Acquisition.~~properties acquired in 2016.

Financing Activities. Net cash from financing activities for the ~~nine~~six months ended ~~September~~June 30, ~~2016 increased~~2017 decreased by approximately ~~$1,091.5~~$147.2 million compared to the ~~nine~~six months ended ~~September~~June 30, ~~2015. Net cash from~~2016. Certain capital markets and financing activities ~~of $1,284.8 million for the nine months ended September 30,~~occurred in 2016 ~~was primarily related to the $855.1~~including $296.6 million received from ~~the issuances~~an issuance of our common ~~stock, $392.3 million of proceeds from issuance of the 2024 Senior Notes and $194 million of proceeds from issuance of the 2021 Convertible Notes,~~stock. These amounts were partially offset by the ~~$115~~$115.0 million payment of principal amounts owed upon the maturity of the 2016 Convertible Notes and net payments of approximately ~~$37~~$37.0 million to pay down amounts borrowed under our revolving credit ~~facility.~~

~~Drilling Activity~~

The following table presents our net developmental drilling activity for the periods shown. Productive wells consist of wells spud, turned-in-line and producing during the period. In-process wells represent wells that have been spud, drilled or are waiting to be completed and/or for gas pipeline connection during the period.

Net Drilling Activity
Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
Operating Region/Area Productive In-Process Dry (1) Productive In-Process Dry (1) Productive In-Process Dry (1) Productive In-Process Dry (1)
Development Wells
Wattenberg Field, operated wells 34.7 40.1 — 26.5 52.8 1.1 87.4
40.1
0.4 75.0
52.8
2.1
Wattenberg Field, non-operated wells 1.8 2.2 — 1.2 4.9 — 5.0
2.2
— 5.4
4.9
—
Utica Shale — 1.7 — — — — 2.8
1.7
— 3.0
—
—
Total drilling activity 36.5 44.0 — 27.7 57.7 1.1 95.2
44.0
0.4
83.4
57.7
2.1

~~______________~~

~~(1) Represents mechanical failures that resulted~~facility in the ~~plugging and abandonment~~first quarter of ~~the respective wells.~~2016.

Off-Balance Sheet Arrangements

At ~~September~~June 30, ~~2016~~,2017, we had no off-balance sheet arrangements, as defined under SEC rules, ~~that~~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 ~~expenditures~~investments, or capital resources.

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Commitments and Contingencies

See ~~Note 11,~~the footnote titled Commitments and Contingencies to the accompanying condensed consolidated financial statements included elsewhere in this report.

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Recent Accounting Standards

See ~~Note 2,~~the footnote titled Summary of Significant Accounting Policies, to the accompanying condensed consolidated financial statements included elsewhere in this report.

Recent Regulatory Developments

On May 2, 2017, in response to an incident in Firestone, Colorado, the Colorado Oil & Gas Conservation Commission (“COGCC”) issued a Notice to Operators (the “Notice”). Among other things, the Notice included requirements for all operators of oil and gas wells in Colorado to inspect all existing flowlines and pipelines located within 1,000 feet of a building unit; inspect any abandoned flowlines or pipelines, regardless of distance to ensure proper abandonment; and test integrity of all connected flowlines. Additional regulations or mandates from the COGCC or other regulators related to this matter are expected to arise.

We timely complied with both phases of the Notice. We have an existing Flowline Integrity Management Program to inspect all Denver-Julesburg Basin wells and related pipelines on an annual basis, and will continue to engage in this process.

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 consolidated financial statements and accompanying notes contained in our ~~2015~~2016 Form 10-K filed with the SEC on February ~~22, 2016.~~28, 2017.

Reconciliation of Non-U.S. GAAP Financial Measures

We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted ~~EBITDA,~~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. Beginning in 2017, we have included non-cash stock-based compensation and exploration, geologic and geophysical expense to our reconciliation of adjusted EBITDAX calculation. In prior periods, we included adjusted EBITDA, a non-U.S. GAAP financial measure that did not include these adjustments. We have elected to disclose Adjusted EBITDAX rather than Adjusted EBITDA in this report and other public disclosures because we believe it is more comparable to similar metrics presented by others in the industry. All prior periods have been conformed for comparability of this information. 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~~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 ~~only~~ 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. ~~See the condensed consolidated statements of cash flows in the accompanying condensed consolidated financial statements included elsewhere in this report.~~

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

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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 ~~EBITDA.~~EBITDAX. We define adjusted ~~EBITDA~~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, ~~and~~ accretion of asset retirement obligations, and non-cash stock-based compensation, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted ~~EBITDA~~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 ~~EBITDA~~EBITDAX includes certain non-cash costs incurred by ~~the Company~~us and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted ~~EBITDA~~EBITDAX differently than we do, limiting its usefulness as a comparative measure. We believe adjusted ~~EBITDA~~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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The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
	(in millions)												(in millions)
Adjusted cash flows from operations:
Net cash from operating activities													$	123.7		$	96.6		263.2			$	197.8
Changes in assets and liabilities													19.2			16.0			(6.6		)	5.8
Adjusted cash flows from operations	$	122.6		$	122.7		$	326.2		$	293.6		$	142.9		$	112.6		$	256.6		$	203.6
Changes in assets and liabilities	40.4			13.8			34.6			(10.6		)
Net cash from operating activities	$	163.0		$	136.5		$	360.8		$	283.0

Adjusted net loss:
Adjusted net loss	$	(5.8	)	$	(75.9	)	$	(47.7	)	$	(58.1	)
Gain (loss) on commodity derivative instruments	19.4			123.5			(62.3		)	141.2
Adjusted net income (loss):
Net income (loss)													$	41.2		$	(95.5	)	$	87.4		$	(167.0	)
(Gain) loss on commodity derivative instruments													(57.9		)	92.8			(138.6		)	81.7
Net settlements on commodity derivative instruments	(47.7		)	(68.0		)	(167.9		)	(162.5		)	12.0			53.3			12.5			120.2
Tax effect of above adjustments	10.8			(21.1		)	87.6			8.1			17.2			(55.6		)	47.2			(76.8		)
Net loss	$	(23.3	)	$	(41.5	)	$	(190.3	)	$	(71.3	)
Adjusted net income (loss)													$	12.5		$	(5.0	)	$	8.5		$	(41.9	)

Adjusted EBITDA to net loss:
Adjusted EBITDA	$	128.7		$	129.1		$	297.4		$	314.0
Gain (loss) on commodity derivative instruments	19.4			123.5			(62.3		)	141.2
Net income (loss) to adjusted EBITDAX:
Net income (loss)													$	41.2		$	(95.5	)	$	87.4		$	(167.0	)
(Gain) loss on commodity derivative instruments													(57.9		)	92.8			(138.6		)	81.7
Net settlements on commodity derivative instruments	(47.7		)	(68.0		)	(167.9		)	(162.5		)	12.0			53.3			12.5			120.2
Non-cash stock-based compensation													5.4			6.4			9.8			11.1
Interest expense, net	(20.1		)	(10.7		)	(40.9		)	(31.8		)	18.9			10.5			38.1			20.8
Income tax provision	12.0			21.2			112.2			40.6
Income tax expense (benefit)													24.5			(58.3		)	50.9			(100.2		)
Impairment of properties and equipment	(0.9		)	(154.0		)	(6.1		)	(161.2		)	27.6			4.2			29.8			5.2
Depreciation, depletion and amortization	(112.9		)	(81.0		)	(317.3		)	(206.9		)
Exploration, geologic, and geophysical expense													1.0			0.2			2.0			0.4
Depreciation, depletion, and amortization													126.0			107.0			235.3			204.4
Accretion of asset retirement obligations	(1.8		)	(1.6		)	(5.4		)	(4.7		)	1.7			1.8			3.4			3.6
Net loss	$	(23.3	)	$	(41.5	)	$	(190.3	)	$	(71.3	)
Adjusted EBITDAX													$	200.4		$	122.4		$	330.6		$	180.2

Adjusted EBITDA to net cash from operating activities:
Adjusted EBITDA	$	128.7		$	129.1		$	297.4		$	314.0
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities													$	123.7		$	96.6		$	263.2		$	197.8
Interest expense, net	(20.1		)	(10.7		)	(40.9		)	(31.8		)	18.9			10.5			38.1			20.8
Stock-based compensation	4.1			4.8			15.2			14.3
Amortization of debt discount and issuance costs	9.9			1.8			12.9			5.3			(3.2		)	(1.3		)	(6.4		)	(3.1		)
Gain on sale of properties and equipment	(0.2		)	(0.1		)	—			(0.3		)
Gain (loss) on sale of properties and equipment													0.5			(0.3		)	0.7			(0.2		)
Exploration, geologic, and geophysical expense													1.0			0.2			2.0			0.4
Other	0.2			(2.2		)	41.6			(7.9		)	40.3			0.7			39.6			(41.3		)
Changes in assets and liabilities	40.4			13.8			34.6			(10.6		)	19.2			16.0			(6.6		)	5.8
Net cash from operating activities	$	163.0		$	136.5		$	360.8		$	283.0
Adjusted EBITDAX													$	200.4		$	122.4		$	330.6		$	180.2

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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 2022 Senior Notes have fixed rates, and therefore near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.

As of ~~September~~June 30, ~~2016~~,2017, our interest-bearing deposit accounts included money market accounts, certificates of deposit, and checking and savings accounts with various banks. The amount of our interest-bearing cash, cash equivalents, and restricted cash as of ~~September~~June 30, ~~2016~~2017 was ~~$1,167~~$201.5 million with a weighted-average interest rate of ~~0.3%.~~0.9 percent. Based on a sensitivity analysis of our interest-bearing deposits as of ~~September~~June 30, ~~2016~~2017 and assuming we had ~~$1,167~~$201.5 million outstanding throughout the period, we estimate that a 1%one percent increase in interest rates would have increased interest income for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 by approximately ~~$8.7~~$1.0 million.

As of ~~September~~June 30, ~~2016~~,2017, we had no outstanding balance on our revolving credit facility.

Commodity Price Risk

We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, natural gas basis, and NGLs. 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, natural gas basis, and propane 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.

~~The following table presents our derivative positions related to crude oil and natural gas sales in effect as of~~ ~~September 30, 2016~~:

Collars Fixed-Price Swaps Basis Protection Swaps
Commodity/ Index/
Maturity Period

Quantity
(Gas -
BBtu (1)
Oil - MBbls)

Weighted-Average
Contract Price

Quantity
(Gas -
BBtu (1)
Oil - MBbls)

Weighted-
Average
Contract
Price

Quantity
(BBtu) (1)

Weighted-
Average
Contract
Price

Fair Value
September 30,
2016 (2)
(in millions)
Floors Ceilings
Natural Gas
NYMEX
2016 900.0
$ 3.75
$ 4.04
7,805.0
$ 3.67
8,403.2
$ (0.27 ) $ 5.3
2017 7,920.0
3.59
4.13
27,290.0
3.55
12,000.0
(0.28 ) 17.0
2018 1,230.0
3.00
3.67
45,280.0
2.94
16,200.0
(0.28 ) 2.4

Total Natural Gas 10,050.0
80,375.0
36,603.2
24.7

Crude Oil
NYMEX
2016 435.0
77.59
97.55
930.0
72.21
—
—
34.0
2017 1,464.0
49.22
65.95
3,004.0
44.92
—
—
(15.1 )
2018 1,512.0
41.85
54.31
1,512.0
51.06
—
—
(10.1 )

Total Crude Oil 3,411.0
5,446.0
—
8.8
Total Natural Gas and Crude Oil $ 33.5

~~____________~~


~~(1)~~	~~A standard unit of measurement for natural gas (one BBtu equals one MMcf).~~


~~(2)~~	Approximately 33.1% of the fair value of our derivative assets and 19.2% of the fair value of our derivative liabilities were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value Measurements, to the condensed consolidated financial statements included elsewhere in this report.

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PDC ENERGY, INC.

The following table presents our commodity and basis derivative positions related to crude oil, natural gas, and propane in effect as of June 30, 2017:



	Collars					Fixed-Price Swaps
Commodity/ Index/ Maturity Period	Quantity (Gas - BBtu Oil - MBbls)	Weighted-Average Contract Price				Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls)	Weighted- Average Contract Price			Fair Value June 30, 2017 (1) (in millions)
Commodity/ Index/ Maturity Period	Quantity (Gas - BBtu Oil - MBbls)	Floors		Ceilings		Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls)	Weighted- Average Contract Price			Fair Value June 30, 2017 (1) (in millions)
Crude Oil
NYMEX
2017	1,232.0	$	49.54	$	62.32	3,680.1	$	50.13		$	18.3
2018	1,512.0	41.85		54.31		6,472.0	52.54			26.5
Total Crude Oil	2,744.0					10,152.1				$	44.8

Natural Gas
NYMEX
2017	5,900.2	$	3.38	$	4.02	19,620.0	$	3.40		$	8.3
2018	5,230.0	3.00		3.54		51,280.0	2.95			(1.1		)
Total Natural Gas	11,130.2					70,900.0				$	7.2

Basis Protection
CIG
2017	—	—		—		25,128.4	$	(0.33	)	$	1.0
2018	—	—		—		30,200.0	(0.34		)	2.7
Waha
2018	—	—		—		1,825.0	(0.43		)	—
Total Basis Protection	—					57,153.4				$	3.7

Propane
Mont Belvieu
2017	—	—		—		642.9	$	26.29		$	0.3
Commodity Derivatives Fair Value										$	56.0

____________


(1)	Approximately 15.0percent of the fair value of our commodity derivative assets and 13.4percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).

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PDC ENERGY, INC.

In addition to our commodity derivative positions as of June 30, 2017, we entered into the following commodity derivative positions subsequent to June 30, 2017 that are effective as of August 3, 2017:



	Fixed-Price Swaps
Commodity/ Index/ Maturity Period	Quantity (Oil - MBbls Gas and Basis- BBtu Propane - MBbls)		Weighted- Average Contract Price

Crude Oil
NYMEX
2018	500.0		$	49.75
2019	800.0	—	49.75
Total Crude Oil	1,300.0

Basis Protection
Waha
2018	4,175.0		$	(0.53	)

Propane
Mont Belvieu
2017	114.3		$	30.56
2018	285.7		27.25
Total Propane	400.0

Our realized prices vary regionally based on local market differentials and our transportation agreements. The following table presents average ~~NYMEX and CIG closing~~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 Nine Months Ended Year Ended
September 30, 2016 September 30, 2016 December 31, 2015
Average Index Closing Price:
Crude oil (per Bbl)
NYMEX $ 44.94
$ 41.33
$ 48.80
Natural gas (per MMBtu)
NYMEX $ 2.81
$ 2.29
$ 2.66
CIG 2.47
1.98
2.44
TETCO M-2 (1) 1.47
1.31
1.49

Average Sales Price Realized:
Excluding net settlements on derivatives
Crude oil (per Bbl) $ 42.11
$ 37.33
$ 40.14
Natural gas (per Mcf) 2.04
1.62
2.04
NGLs (per Bbl) 11.12
10.41
10.72

~~_____________~~

~~(1) TETCO M-2 is an index price upon which a majority of our natural gas produced in the Utica Shale is sold.~~



	Three Months Ended		Six Months Ended		Year Ended
	June 30, 2017		June 30, 2017		December 31, 2016
Average NYMEX Index Price:
Crude oil (per Bbl)	$	48.28	$	50.10	$	43.32
Natural gas (per MMBtu)	3.18		3.25		2.46

Average Sales Price Realized:
Excluding net settlements on commodity derivatives
Crude oil (per Bbl)	$	45.97	$	47.31	$	39.96
Natural gas (per Mcf)	2.16		2.26		1.77
NGLs (per Bbl)	14.59		16.75		11.80

Based on a sensitivity analysis as of ~~September~~June 30, ~~2016~~,2017, we estimate that a ~~10%~~ten percent increase in natural gas, ~~and~~ crude oil, and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives in place, would have resulted in a decrease in the fair value of our derivative positions of ~~$80.3~~$74.8 million, whereas a ~~10%~~ten percent decrease in prices would have resulted in an increase in fair value of ~~$80.3~~$74.2 million.

~~See Note 3,~~ ~~Fair Value~~

Table of ~~Financial Instruments, and Note 4,~~ ~~Derivative Financial Instruments~~, to our condensed consolidated financial statements included elsewhere in this report for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts.contents

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 and entering into transactions with high-quality counterparties. 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~~oil and ~~Gas Exploration~~gas exploration and ~~Production segment's~~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.

Amounts due to our ~~Gas Marketing segment~~gas marketing business are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions, and end-users in various industries. The underlying operations of these entities are geographically concentrated in the same region, which increases the credit risk associated with this business. As natural gas prices continue to remain depressed, certain third-party producers ~~under~~relating to our ~~Gas Marketing segment have begun and~~gas marketing business continue to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. We have initiated several legal actions for breach of contract, collection and related claims against certain third-party producers that are delinquent in their payment obligations, which have to date resulted in ~~one~~two default ~~judgment.~~judgments. We expect this trend to continue for this ~~segment.~~business.

A group of 42 independent West Virginia natural gas producers has filed a lawsuit in Marshall County, West Virginia, naming Dominion, certain entities affiliated with Dominion, and RNG as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. RNG and Dominion have removed the case to the U.S. District Court for the Northern District of West Virginia and are preparing pre-trial pleadings, including an answer to the compliant and a motion to dismiss the case. At this time, RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defense.

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 ~~Note 4,~~ 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.

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~~PDC ENERGY, INC.~~

Disclosure of Limitations

Because the information above included only those exposures that existed at ~~September~~June 30, ~~2016~~,2017, 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 ~~September~~June 30, ~~2016~~,2017, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Principal Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e).

Based on the results of this evaluation, the Chief Executive Officer and the Principal Financial Officer concluded that our disclosure controls and procedures were effective as of ~~September~~June 30, ~~2016~~.2017.

Changes in Internal Control over Financial Reporting

During the three months ended ~~September~~June 30, ~~2016~~,2017, we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) 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~~From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations, or liquidity.

Environmental

Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be ~~found~~reasonably estimated. Except as discussed herein, we are not aware of any environmental claims existing as of June 30, 2017, 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 past non-compliance with environmental laws will not be discovered on our properties. Accrued environmental liabilities are recorded in ~~Note 10,~~ ~~Commitments and Contingencies – Litigation, to our~~other accrued expenses on the condensed consolidated ~~financial statements included elsewhere~~balance sheets.

In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the U.S. Environmental Protection Agency ("EPA"). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focuses on historical operation and design information for 46 of our production facilities and asks that we conduct sampling and analyses at the identified 46 facilities. We responded to the Information Request with the requested data in January 2016.

In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law.

For more than a year, we held a series of meetings with the EPA, Department of Justice (“DOJ”) and CDPHE on the above matters. On June 26, 2017, the DOJ on behalf of the EPA and the State of Colorado filed a complaint against us based

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on the above matters. We continue to schedule meetings with these agencies in working toward a resolution of the matters. The ultimate outcome related to these combined actions is not known at this ~~report.~~time.

Action Regarding Firm Transportation Contracts

In June 2016, a group of 42 independent West Virginia natural gas producers filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. ("Dominion"), certain entities affiliated with Dominion, and our subsidiary RNG as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. The case has been transferred to the Business Court Division of the Circuit Court of Marshall County, West Virginia, and the parties are awaiting that court's ruling on previously-filed pre-trial pleadings. RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses.

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 ~~2015~~2016 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 ~~2015~~2016 Form ~~10-K, except for the following:~~

If completed, the Delaware Basin Acquisition may not achieve its intended results and may result in us assuming unanticipated liabilities. To date, we have conducted only limited diligence regarding the assets and liabilities we would assume in the transaction.

We entered into the Delaware Basin Acquisition agreements with the expectation that the acquisition would result in various benefits, growth opportunities and synergies. Achieving the anticipated benefits of the transaction is subject to a number of risks and uncertainties. For example, under the acquisition agreements, we have the opportunity to conduct customary environmental and title due diligence following the execution of the agreements, but our diligence efforts to date have been limited. As a result, we may discover title defects or adverse environmental or other conditions of which we are currently unaware. Environmental, title and other problems could reduce the value of the properties to us, and, depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We would assume substantially all of the liabilities associated with the acquired properties and would be entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure you that such potential remedies will be adequate for any liabilities we incur, and such liabilities could be significant. In addition, certain of the properties to be acquired are subject to consents to assign and preference rights. If all applicable waivers cannot be obtained, we may not be able to acquire certain properties as originally contemplated and our expected benefits of the acquisition may be adversely affected. Further, the acquisition agreements allow the sellers to include a specified amount of additional leases in the transaction, which would increase the purchase price. Also, it is uncertain whether our existing operations and the acquired properties and assets can be integrated in an efficient and effective manner.

As with other acquisitions, the success of the Delaware Basin Acquisition depends on, among other things, the accuracy of our assessment of the reserves and drilling locations associated with the acquired properties, future oil, NGL and natural gas prices and operating costs and various other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price for the acquisition from the sale of production from the property or recognize an acceptable return from such sales. See "-Risks Related to Our Business and the Industry-Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties" in our 2015 Form 10-K. Although the properties to be acquired are subject to many of the risks and uncertainties to which our business and operations are subject, risks associated with the Delaware Basin Acquisition in particular include those associated with our ability to operate efficiently in an area where we have no current operations, the significant size of the transaction relative to our existing operations, the fact that a substantial majority of the properties to be acquired are undeveloped and the additional indebtedness we have incurred in connection with the acquisition. We also expect that pursuing our future development plans for the properties to be acquired will require

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~~capital in excess of our projected cash flows from operations for some period of time beginning in 2017, which may increase our need for external financing.~~

In addition, the integration of operations following the Delaware Basin Acquisition will require substantial attention from our management and other personnel, which may distract their attention from our day-to-day business and operations and prevent us from realizing benefits from other opportunities. Completing the integration process may be more expensive than anticipated, and we cannot assure you that we will be able to effect the integration of these operations smoothly or efficiently or that the anticipated benefits of the transaction will be achieved.

~~The reserves, production and drilling locations estimates with respect to the properties to be acquired in the Delaware Basin Acquisition may differ materially from the actual amounts.~~

The reserves, production and drilling locations estimates with respect to the properties to be acquired in the Delaware Basin Acquisition are based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines. Such analysis is based, in significant part, on data provided by the sellers. We cannot assure you that these estimates are accurate. After such data is further reviewed by us and our independent engineers, the actual reserves, production and number of viable drilling locations may differ materially from our expectations.

~~We have incurred significant transaction-related costs in connection with the Delaware Basin Acquisition and the related financing transactions.~~

We have incurred a number of significant transaction-related costs associated with the Delaware Basin Acquisition and the related financing transactions. We continue to assess the magnitude of these costs and additional unanticipated costs, including costs incurred in the integration of the properties to be acquired, which may be significant.

~~Failure to complete the Delaware Basin Acquisition could negatively affect our stock price as well as our business and financial results.~~

Closing of the Delaware Basin Acquisition is subject to a number of conditions. If the Delaware Basin Acquisition is not completed, we will be subject to a number of risks, including but not limited to the following:

~~We must pay costs related to the acquisition including, among others, legal, accounting and financial advisory fees, whether the acquisition is completed or not.~~

~~In some circumstances set forth in the acquisition agreements, we could be required to forfeit the $100 million aggregate deposit we made at the time the agreements were executed.~~

~~We may experience negative reactions from the financial markets.~~

~~We could be subject to litigation related to the failure to complete the acquisition.~~

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

July 1 - 31, 2016 19,261
$ 54.38
August 1 - 31, 2016 440
55.48
September 1 - 30, 2016 —
—
Total third quarter purchases 19,701
54.40



Period	Total Number of Shares Purchased (1)	Average Price Paid per Share

April 1 - 30, 2017	52,518	$	62.35
May 1 - 31, 2017	—	—
June 1 - 30, 2017	—	—
Total second quarter 2017 purchases	52,518	$	62.35

__________


(1)	Purchases primarily 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 ~~Principal~~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 ~~Principal~~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~~

~~Fourth Amendment to Third Amendment and Restated Credit Agreement~~

101.INS

XBRL Instance 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

*~~Management contract or compensatory arrangement.~~

** Furnished herewith.

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PDC ENERGY, INC.

SIGNATURES

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



	PDC Energy, Inc.
	(Registrant)




Date: ~~November 3, 2016~~August 8, 2017	/s/ Barton R. Brookman
	Barton R. Brookman
	President and Chief Executive Officer
	(principal executive officer)

	/s/ ~~R. Scott Meyers~~David W. Honeyfield
	~~R. Scott Meyers~~David W. Honeyfield
	Senior Vice President and Chief ~~Accounting~~Financial Officer
	(principal financial officer)

4552



Counterparty Name	Fair Value of Derivative Assets
	(in thousands)
Canadian Imperial Bank of Commerce (1)	$	21,343
JP Morgan Chase Bank, N.A (1)	17,929
Bank of Nova Scotia (1)	15,166
Wells Fargo Bank, N.A. (1)	9,891
NATIXIS (1)	7,171
Other lenders in our revolving credit facility	2,491
Various (2)	36
Total	$	74,027



	Amount
	(in thousands)
Note receivable:
Principal outstanding, December 31, 2015	$	43,069
Paid-in-kind interest	969
Principal outstanding, September 30, 2016	44,038
Allowance for uncollectible notes receivable	(44,038		)
Note receivable, net	$	—



	Shares		Weighted-Average Grant Date Fair Value

Non-vested at December 31, 2015	525,081		$	50.23
Granted	269,709		57.12
Vested	(256,976	)	48.60
Forfeited	(14,716	)	55.70
Non-vested at September 30, 2016	523,098		54.43



	Three Months Ended September 30,						Nine Months Ended September 30,
Average Sales Price by Operating Region					Percentage Change						Percentage Change
(excluding net settlements on derivatives)	2016		2015		Percentage Change		2016		2015		Percentage Change
Crude oil (per Bbl)
Wattenberg Field	$	42.29	$	38.90	8.7	%	$	37.42	$	42.13	(11.2	)%
Utica Shale	38.93		40.02		(2.7	)%	35.61		43.28		(17.7	)%
Weighted-average price	42.11		38.98		8.0	%	37.33		42.22		(11.6	)%
Natural gas (per Mcf)
Wattenberg Field	$	2.08	$	2.11	(1.4	)%	$	1.63	$	2.17	(24.9	)%
Utica Shale	1.33		1.36		(2.2	)%	1.44		1.92		(25.0	)%
Weighted-average price	2.04		2.05		(0.5	)%	1.62		2.15		(24.7	)%
NGLs (per Bbl)
Wattenberg Field	$	11.07	$	9.62	15.1	%	$	10.32	$	10.36	(0.4	)%
Utica Shale	12.14		6.80		78.5	%	12.22		11.40		7.2	%
Weighted-average price	11.12		9.40		18.3	%	10.41		10.45		(0.4	)%
Crude oil equivalent (per Boe)
Wattenberg Field	$	23.77	$	24.32	(2.3	)%	$	20.83	$	26.07	(20.1	)%
Utica Shale	20.98		22.04		(4.8	)%	20.26		25.47		(20.5	)%
Weighted-average price	23.62		24.15		(2.2	)%	20.80		26.02		(20.1	)%



	Net Drilling Activity
	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Operating Region/Area	Productive	In-Process	Dry (1)	Productive	In-Process	Dry (1)	Productive	In-Process	Dry (1)	Productive	In-Process	Dry (1)
Development Wells
Wattenberg Field, operated wells	34.7	40.1	—	26.5	52.8	1.1	87.4	40.1	0.4	75.0	52.8	2.1
Wattenberg Field, non-operated wells	1.8	2.2	—	1.2	4.9	—	5.0	2.2	—	5.4	4.9	—
Utica Shale	—	1.7	—	—	—	—	2.8	1.7	—	3.0	—	—
Total drilling activity	36.5	44.0	—	27.7	57.7	1.1	95.2	44.0	0.4	83.4	57.7	2.1



	Collars					Fixed-Price Swaps			Basis Protection Swaps
Commodity/ Index/ Maturity Period	Quantity (Gas - BBtu (1) Oil - MBbls)	Weighted-Average Contract Price				Quantity (Gas - BBtu (1) Oil - MBbls)	Weighted- Average Contract Price		Quantity (BBtu) (1)	Weighted- Average Contract Price			Fair Value September 30, 2016 (2) (in millions)
Commodity/ Index/ Maturity Period	Quantity (Gas - BBtu (1) Oil - MBbls)	Floors		Ceilings		Quantity (Gas - BBtu (1) Oil - MBbls)	Weighted- Average Contract Price		Quantity (BBtu) (1)	Weighted- Average Contract Price			Fair Value September 30, 2016 (2) (in millions)
Natural Gas
NYMEX
2016	900.0	$	3.75	$	4.04	7,805.0	$	3.67	8,403.2	$	(0.27	)	$	5.3
2017	7,920.0	3.59		4.13		27,290.0	3.55		12,000.0	(0.28		)	17.0
2018	1,230.0	3.00		3.67		45,280.0	2.94		16,200.0	(0.28		)	2.4

Total Natural Gas	10,050.0					80,375.0			36,603.2				24.7

Crude Oil
NYMEX
2016	435.0	77.59		97.55		930.0	72.21		—	—			34.0
2017	1,464.0	49.22		65.95		3,004.0	44.92		—	—			(15.1		)
2018	1,512.0	41.85		54.31		1,512.0	51.06		—	—			(10.1		)

Total Crude Oil	3,411.0					5,446.0			—				8.8
Total Natural Gas and Crude Oil													$	33.5