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 ~~June 30, 2016~~March 31, 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: ~~47,154,493~~65,855,290 shares of the Company's Common Stock ($0.01 par value) were outstanding as of ~~July~~April 18, ~~2016.~~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
	Notes to Condensed Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2023
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3440
Item 4.	Controls and Procedures	3643

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	3644
Item 1A.	Risk Factors	3644
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3844
Item 3.	Defaults Upon Senior Securities	3844
Item 4.	Mine Safety Disclosures	3844
Item 5.	Other Information	3845
Item 6.	Exhibits	3946

	SIGNATURES	4047

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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.") 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 transactions contemplated by the Noble exchange agreements are 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, including our expectation that 2016 cash flows from operations will approximate cash flows from investing activities; 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 in the second half 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; expected 2016 production~~wells, drill times and ~~cash flow ranges~~number of rigs employed; rates of return; operational enhancements and ~~timing~~efficiencies; management of ~~turn-in-lines; our evaluation method of our customers'~~lease expiration issues; financial ratios; 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 debtmidstream capacity and senior notes covenants; impact of litigation on our results of operations and financial position; that we do not expect to pay dividends in the foreseeable future; our belief that certain proposed initiatives in Colorado may not qualify to be included on the ballot in 2016; 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 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;

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;

cost of pending or future litigation;

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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

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for further information on risks and uncertainties that could affect our business, financial condition, results of operations, and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

REFERENCES

Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships. ~~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)


	June 30, 2016			December 31, 2015				March 31, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	109,099		$	850			$	207,624		$	244,100
Short-term investments							—	49,890			—
Accounts receivable, net	107,350			104,274				122,484			143,392
Fair value of derivatives	98,839			221,659				27,047			8,791
Prepaid expenses and other current assets	3,847			5,266				4,726			3,542
Total current assets	319,135			332,049				411,771			399,825
Properties and equipment, net	1,930,595			1,940,552				4,098,463			4,008,266
Fair value of derivatives	12,745			44,387				13,921			2,386
Goodwill								56,058			62,041
Other assets	9,195			53,555				12,917			13,324
Total Assets	$	2,271,670		$	2,370,543			$	4,593,130		$	4,485,842

Liabilities and Shareholders' Equity
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable	$	64,234		$	92,613			$	144,440		$	66,322
Production tax liability	19,261			26,524				25,065			24,767
Fair value of derivatives	22,824			1,595				26,495			53,595
Funds held for distribution	49,965			29,894				76,067			71,339
Current portion of long-term debt	—			112,940
Accrued interest payable	8,557			9,057				18,977			15,930
Other accrued expenses	22,358			28,709				26,938			38,625
Total current liabilities	187,199			301,332				317,982			270,578
Long-term debt	492,997			529,437				1,046,461			1,043,954
Deferred income taxes	41,133			143,452				427,205			400,867
Asset retirement obligation	81,583			84,032
Asset retirement obligations								78,162			82,612
Fair value of derivatives	26,830			695				4,302			27,595
Other liabilities	17,363			24,398				47,841			37,482
Total liabilities	847,105			1,083,346				1,921,953			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, 47,162,446 and 40,174,776 issued as of June 30, 2016 and December 31, 2015, respectively	472			402
Stockholders' equity
Common shares - par value $0.01 per share, 150,000,000 authorized, 65,797,748 and 65,704,568 issued as of March 31, 2017 and December 31, 2016, respectively								658			657
Additional paid-in capital	1,211,876			907,382				2,492,276			2,489,557
Retained earnings	213,442			380,422				180,354			134,208
Treasury shares - at cost, 23,822 and 20,220 as of June 30, 2016 and December 31, 2015, respectively	(1,225		)	(1,009		)
Total shareholders' equity	1,424,565			1,287,197
Total Liabilities and Shareholders' Equity	$	2,271,670		$	2,370,543
Treasury shares - at cost, 34,433 and 28,763 as of March 31, 2017 and December 31, 2016, respectively								(2,111		)	(1,668		)
Total stockholders' equity								2,671,177			2,622,754
Total Liabilities and Stockholders' Equity								$	4,593,130		$	4,485,842

~~See accompanying Notes to Condensed Consolidated Financial Statements~~

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PDC ENERGY, INC.

Condensed Consolidated Statements of Operations

(unaudited; in thousands, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2016			2015			2016			2015			2017			2016
Revenues
Crude oil, natural gas and NGLs sales	$	110,841		$	96,928		$	186,208		$	171,037
Sales from natural gas marketing	1,879			2,523			4,050			5,756
Commodity price risk management gain (loss), net	(92,801		)	(49,041		)	(81,745		)	17,621
Well operations, pipeline income and other	178			550			2,415			1,178
Crude oil, natural gas, and NGLs sales													$	189,692		$	75,367
Commodity price risk management gain, net of settlements													80,704			11,056
Other income													3,311			4,408
Total revenues	20,097			50,960			110,928			195,592			273,707			90,831
Costs, expenses and other
Lease operating expenses	13,675			12,639			29,005			28,924			19,789			15,330
Production taxes	6,043			3,837			10,114			7,730			12,399			4,071
Transportation, gathering and processing expenses	4,465			1,308			8,506			2,646			5,902			4,041
Cost of natural gas marketing	2,125			2,836			4,703			6,094
Exploration expense	237			275			447			560
General and administrative expense													26,315			22,779
Exploration, geologic, and geophysical expense													954			210
Depreciation, depletion and amortization													109,316			97,388
Impairment of properties and equipment	4,170			4,404			5,171			7,176			2,193			1,001
General and administrative expense	23,579			20,728			46,358			41,773
Depreciation, depletion and amortization	107,014			70,106			204,402			125,926
Accretion of asset retirement obligations													1,768			1,812
Gain on sale of properties and equipment													(160		)	(84		)
Provision for uncollectible notes receivable	—			—			44,738			—			—			44,738
Accretion of asset retirement obligations	1,811			1,588			3,623			3,148
(Gain) loss on sale of properties and equipment	260			(207		)	176			(228		)
Total cost, expenses and other	163,379			117,514			357,243			223,749
Loss from operations	(143,282		)	(66,554		)	(246,315		)	(28,157		)
Other expenses													3,528			2,578
Total costs, expenses and other													182,004			193,864
Income (loss) from operations													91,703			(103,033		)
Interest expense	(10,672		)	(11,567		)	(22,566		)	(23,292		)	(19,467		)	(11,894		)
Interest income	177			1,135			1,735			2,248			240			1,558
Loss before income taxes	(153,777		)	(76,986		)	(267,146		)	(49,201		)
Provision for income taxes	58,327			30,116			100,166			19,393
Net loss	$	(95,450	)	$	(46,870	)	$	(166,980	)	$	(29,808	)
Income (loss) before income taxes													72,476			(113,369		)
Income tax (expense) benefit													(26,330		)	41,839
Net income (loss)													$	46,146		$	(71,530	)

Earnings per share:
Basic	$	(2.04	)	$	(1.17	)	$	(3.78	)	$	(0.78	)	$	0.70		$	(1.72	)
Diluted	$	(2.04	)	$	(1.17	)	$	(3.78	)	$	(0.78	)	$	0.70		$	(1.72	)

Weighted-average common shares outstanding:
Basic	46,742			40,035			44,175			38,202			65,749			41,608
Diluted	46,742			40,035			44,175			38,202			66,117			41,608

~~See accompanying Notes to Condensed Consolidated Financial Statements~~

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PDC ENERGY, INC.

Condensed Consolidated Statements of Cash Flows

(unaudited; in thousands)

Six Months Ended June 30,
2016 2015
Cash flows from operating activities:
Net loss $ (166,980 ) $ (29,808 )
Adjustments to net loss to reconcile to net cash from operating activities:
Net change in fair value of unsettled derivatives 201,825
76,869
Depreciation, depletion and amortization 204,402
125,926
Provision for uncollectible notes receivable 44,738
—
Impairment of properties and equipment 5,171
7,176
Accretion of asset retirement obligation 3,623
3,148
Stock-based compensation 11,126
9,465
(Gain) loss on sale of properties and equipment 176
(228 )
Amortization of debt discount and issuance costs 3,077
3,521
Deferred income taxes (102,319 ) (22,630 )
Non-cash interest income (1,194 ) (2,247 )
Other (93 ) (402 )
Changes in assets and liabilities (5,754 ) (24,333 )
Net cash from operating activities 197,798
146,457
Cash flows from investing activities:
Capital expenditures (235,707 ) (358,135 )
Proceeds from sale of properties and equipment 4,903
243
Net cash from investing activities (230,804 ) (357,892 )
Cash flows from financing activities:
Proceeds from sale of equity, net of issuance cost 296,575
202,851
Proceeds from revolving credit facility 85,000
272,000
Repayment of revolving credit facility (122,000 ) (275,000 )
Redemption of convertible notes (115,000 ) —
Other (3,320 ) (3,106 )
Net cash from financing activities 141,255
196,745
Net change in cash and cash equivalents 108,249
(14,690 )
Cash and cash equivalents, beginning of period 850
16,066
Cash and cash equivalents, end of period $ 109,099
$ 1,376

Supplemental cash flow information:
Cash payments for:
Interest, net of capitalized interest $ 22,462
$ 22,828
Income taxes 167
9,936
Non-cash investing and financing activities:
Change in accounts payable related to purchases of properties and equipment $ (28,999 ) $ (41,490 )
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposals 843
1,395
Purchase of properties and equipment under capital leases 1,074
950

~~See accompanying Notes to Condensed Consolidated Financial Statements~~

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	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	46,146		$	(71,530	)
Adjustments to net income (loss) to reconcile to net cash from operating activities:
Net change in fair value of unsettled commodity derivatives	(80,153		)	55,770
Depreciation, depletion and amortization	109,316			97,388
Impairment of properties and equipment	2,193			1,001
Accretion of asset retirement obligations	1,768			1,812
Non-cash stock-based compensation	4,454			4,682
Gain on sale of properties and equipment	(160		)	(84		)
Amortization of debt discount and issuance costs	3,184			1,754
Deferred income taxes	26,280			(43,372		)
Provision for uncollectible notes receivable	—			44,738
Other	722			(1,202		)
Changes in assets and liabilities	25,750			10,193
Net cash from operating activities	139,500			101,150
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties	(129,826		)	(122,309		)
Capital expenditures for other properties and equipment	(821		)	(450		)
Acquisition of crude oil and natural gas properties, including settlement adjustments	6,181			—
Proceeds from sale of properties and equipment	737			90
Purchases of short-term investments	(49,890		)	—
Net cash from investing activities	(173,619		)	(122,669		)
Cash flows from financing activities:
Proceeds from issuance of equity, net of issuance cost	(8		)	296,578
Proceeds from revolving credit facility	—			85,000
Repayment of revolving credit facility	—			(122,000		)
Other	(2,349		)	(364		)
Net cash from financing activities	(2,357		)	259,214
Net change in cash and cash equivalents	(36,476		)	237,695
Cash and cash equivalents, beginning of period	244,100			850
Cash and cash equivalents, end of period	$	207,624		$	238,545

Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest	$	13,224		$	599
Income taxes	(39		)	—
Non-cash investing and financing activities:
Change in accounts payable related to purchases of properties and equipment	$	69,604		$	(23,544	)
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals	1,233			404
Purchase of properties and equipment under capital leases	1,190			635

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~June 30, 2016~~March 31, 2017

~~(Unaudited)~~(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 Ohio.~~Southeastern Ohio, although management expects to begin the process of divesting these properties later in 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.~~Wolfcamp zones. As of ~~June 30, 2016,~~March 31, 2017, we owned an interest in approximately ~~3,000~~2,900 gross productive wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Beginning with the first quarter of 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 ~~segments: Oil~~ and, ~~Gas Exploration and Production and Gas Marketing.~~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 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 six~~ months ended ~~June 30, 2016~~March 31, 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.

~~In August 2014, the FASB issued a new standard related to the disclosure~~

Table 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.contents

PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

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~~August 2016, the FASB issued an accounting update on ~~stock-based compensation intended~~statements of cash flows 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 liabilitiesaddress diversity in practice in how certain cash receipts and ~~the classification on~~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, ~~2016,~~2017, and interim periods within those fiscal years, with early adoption permitted. We ~~expect to adopt this standard in~~are currently evaluating the ~~fourth quarter of 2016. Adoption of this standard is not expected to~~impact these changes may have ~~a significant impact~~ on our ~~condensed~~ consolidated financial statements.

~~Table~~In January 2017, the FASB issued an accounting update clarifying the definition of ~~contents~~

~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This guidance is to be applied using a prospective method and 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 a step in the determination of whether goodwill should be considered impaired. 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 are currently evaluating the impact these changes may have on our consolidated financial statements.

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

~~Determination of Fair Value~~

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

~~Level 1~~Delaware Basin Acquisition. ~~– Quoted prices (unadjusted)~~On December 6, 2016, we closed on an acquisition which has been accounted 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~~as a business combination. The transaction was for the ~~asset or liability, including quoted prices~~purchase of approximately 57,900 net acres, approximately 30 wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, 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~~an aggregate consideration to the ~~contractual price~~sellers of approximately $1.64 billion, comprised of approximately $946.0 million in cash, including the payment of $40.0 million of debt of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

~~We validate our fair value measurement through the review of counterparty statements~~seller at closing 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 informationpurchase price adjustments, 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 fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our collars and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:

June 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 $ 74,823
$ 36,761
$ 111,584
$ 174,657
    $ 91,288
    $ 265,945
Basis protection derivative contracts —
—
—
101
—
101
Total assets 74,823
36,761
111,584
174,758
91,288
266,046
Liabilities:
Commodity-based derivative contracts 38,518
9,476
47,994
738
—
    738
Basis protection derivative contracts 1,660
—
1,660
1,552
—
    1,552
Total liabilities 40,178
9,476
49,654
2,290
—
2,290
Net asset $ 34,645
$ 27,285
$ 61,930
$ 172,468
$ 91,288
$ 263,756

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

~~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,
2016 2015 2016 2015
(in thousands)
Fair value, net asset beginning of period $ 73,105
$ 74,817
$ 91,288
$ 62,356
Changes in fair value included in statement of operations line item:
Commodity price risk management gain (loss), net (26,422 ) (10,749 ) (20,257 ) 4,440
Sales from natural gas marketing —
(1 ) (20 ) —
Settlements included in statement of operations line items:
Commodity price risk management gain (loss), net (19,398 ) (5,809 ) (43,656 ) (8,534 )
Sales from natural gas marketing —
(3 ) (70 ) (7 )
Fair value, net asset end of period $ 27,285
$ 58,255
$ 27,285
$ 58,255

Net change in fair value of unsettled derivatives included in statement of operations line item:
Commodity price risk management gain (loss), net $ (18,210 ) $ (10,056 ) $ (13,105 ) $ 3,629

The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by 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 for possible impairment when events and circumstances indicate a possible decline in the recoverability 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 will be sold.

~~The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or~~9.4 million shares of our common ~~stock.~~stock valued at approximately $690.7 million at the time the acquisition closed. 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 ~~June 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 ~~June 30, 2016, we estimate the~~estimated fair value of assets acquired and liabilities assumed in the ~~portion of our long-term debt related~~acquisition presented below are preliminary and subject to our 7.75% senior notes due 2022 to be $521.3 million, or 104.3% 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~~customary additional post-closing adjustments as more detailed analysis associated with the ~~variable nature~~acquired properties is completed. As of the ~~imputed interest rates and~~date of this report, the ~~duration~~final settlement statement has been agreed upon with the sellers. We are in the process of finalizing the fair values of the ~~related vehicle lease.~~

~~Concentration of Risk~~

~~Derivative Counterparties.~~ ~~Our derivative arrangements expose us~~assets acquired and liabilities assumed and expect 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 evaluatedkeep 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 June 30, 2016, taking into account the estimated likelihood of nonperformance.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

~~The following table presents the counterparties that expose us to credit risk as of~~ ~~June 30, 2016~~ ~~with regard to our derivative assets:~~

Counterparty Name Fair Value of
Derivative Assets
(in thousands)
Canadian Imperial Bank of Commerce (1) $ 33,559
JP Morgan Chase Bank, N.A (1) 29,011
Bank of Nova Scotia (1) 22,676
Wells Fargo Bank, N.A. (1) 13,351
NATIXIS (1) 10,418
Other lenders in our revolving credit facility 2,329
Various (2) 240
Total $ 111,584

~~__________~~

~~(1)Major lender in our revolving credit facility. See Note 7, Long-Term Debt.~~

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

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

Amount
(in thousands)
Note receivable:
Principal outstanding, December 31, 2015 $ 43,069
Paid-in-kind interest 969
Principal outstanding, June 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 $39.0 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 ~~June 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. The Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets.

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 $44.0 million outstanding balance as of March 31, 2016, which was included in the condensed consolidated balance sheet line item other assets.

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 $1.0 million was PIK Interest, and we recognized $1.1 million and $2.2 million of interest income related to the Note for the three and six months ended June 30, 2015, respectively, of which $0.8 million and $1.6 million, respectively, was PIK Interest.

Additionally, 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 is not reasonably assured based on the analysis we performed as of March 31, 2016.

~~As of June 30, 2016, there has been no change to our assessment of the collectibility of the notes or related interest since March 31, 2016.~~

~~Commencing in~~transaction open through the second quarter of ~~2016, we have ceased recognizing interest income on~~2017 to ensure that any post-closing adjustments associated with the ~~notes and~~period through final settlement are ~~accounting for~~appropriately reflected in the ~~notes under the cash basis method.~~final purchase price allocation.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~- Continued~~

March 31, 2017

(unaudited)

The details of the estimated purchase price and the preliminary allocation of the purchase price for the transaction, which reflects certain post-closing adjustments, are presented below (in thousands):



	March 31, 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	$	7,173
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	56,058
Total assets acquired	2,046,408
Liabilities assumed:
Current liabilities	(24,519		)
Asset retirement obligations	(4,248		)
Deferred tax liabilities, net	(379,952		)
Total liabilities assumed	(408,719		)
Total identifiable net assets acquired	$	1,637,689

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, 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 recorded related to the Delaware Basin acquisition has decreased as compared to the initial amount recorded as of December 31, 2016, due to customary purchase price allocations. Such amounts will be finalized with final purchase accounting. 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

March 31, 2017

(unaudited)

The following table presents the changes in goodwill:



	Amount
	(in thousands)

Balance at beginning of period, January 1, 2017	$	62,041
Purchase price adjustments, net of tax	(5,983		)
Balance at end of period, March 31, 2017	$	56,058

With the creation of goodwill from this transaction, we will perform our annual evaluation of goodwill for impairment on an annual basis or when a triggering event occurs, beginning in 2017. We evaluate goodwill for impairment by either performing a qualitative evaluation or a two-step 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 properties and equipment, net of accumulated depreciation, depletion, and amortization ("DD&A"):



	March 31, 2017			December 31, 2016
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	3,675,076		$	3,499,718
Unproved	1,874,552			1,874,671
Total crude oil and natural gas properties	5,549,628			5,374,389
Infrastructure, pipeline, and other	74,046			62,093
Land and buildings	14,896			12,165
Construction in progress	132,776			122,591
Properties and equipment, at cost	5,771,346			5,571,238
Accumulated DD&A	(1,672,883		)	(1,562,972		)
Properties and equipment, net	$	4,098,463		$	4,008,266

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



	Three Months Ended March 31,
	2017		2016
	(in thousands)

Impairment of proved and unproved properties	$	2,102	$	969
Amortization of individually insignificant unproved properties	91		32
Total impairment of properties and equipment	$	2,193	$	1,001

NOTE 5 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas, and NGLs. To manage a portion of our exposure to price volatility from producing crude oil, ~~and~~ natural gas, ~~we 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 in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical ~~market; and~~market.

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 ~~June 30, 2016~~,March 31, 2017, we had derivative instruments, which were comprised of collars, ~~fixed-price~~fixed-

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

price swaps, and basis protection swaps, ~~and physical sales and purchases,~~ in place for a portion of our anticipated production through 2018 for a total of ~~71,560~~13,912 MBbls of crude oil,75,615 BBtu of natural gas, and ~~9,214~~ 536MBbls 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 ofunder 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.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

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:	Balance sheet line item	June 30, 2016		December 31, 2015		Derivative instruments:	Condensed consolidated balance sheet line item	March 31, 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	$	98,526	$	221,161
	Related to natural gas marketing	Fair value of derivatives	313		441
	Basis protection contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	—		57
			98,839		221,659
	Non-current						Commodity derivative contracts	Fair value of derivatives	$	24,437	$	8,490
	Commodity contracts						Basis protection derivative contracts	Fair value of derivatives	2,610		301
	Related to crude oil and natural gas sales	Fair value of derivatives	12,673		44,292				27,047		8,791
	Related to natural gas marketing	Fair value of derivatives	72		51		Non-current
	Basis protection contracts						Commodity derivative contracts	Fair value of derivatives	11,279		1,123
	Related to crude oil and natural gas sales	Fair value of derivatives	—		44		Basis protection derivative contracts	Fair value of derivatives	2,642		1,263
			12,745		44,387				13,921		2,386
Total derivative assets			$	111,584	$	266,046	Total derivative assets		$	40,968	$	11,177

Derivative liabilities:	Current						Current
	Commodity contracts						Commodity derivative contracts	Fair value of derivatives	$	26,489	$	53,565
	Related to crude oil and natural gas sales	Fair value of derivatives	$	21,179	$	—	Basis protection derivative contracts	Fair value of derivatives	6		30
	Related to natural gas marketing	Fair value of derivatives	251		417				26,495		53,595
	Basis protection contracts						Non-current
	Related to crude oil and natural gas sales	Fair value of derivatives	1,394		1,178		Commodity derivative contracts	Fair value of derivatives	4,302		27,595
			22,824		1,595				4,302		27,595
	Non-current
	Commodity contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	26,509		275
	Related to natural gas marketing	Fair value of derivatives	54		46
	Basis protection contracts
	Related to crude oil and natural gas sales	Fair value of derivatives	267		374
			26,830		695
Total derivative liabilities			$	49,654	$	2,290	Total derivative liabilities		$	30,797	$	81,190

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
Condensed consolidated statement of operations line item	2016			2015			2016			2015			2017		2016
	(in thousands)												(in thousands)
Commodity price risk management gain (loss), net
Commodity price risk management gain, net
Net settlements	$	53,301		$	44,049		$	120,132		$	94,461		$	551	$	66,831
Net change in fair value of unsettled derivatives	(146,102		)	(93,090		)	(201,877		)	(76,840		)	80,153		(55,775		)
Total commodity price risk management gain (loss), net	$	(92,801	)	$	(49,041	)	$	(81,745	)	$	17,621
Sales from natural gas marketing
Net settlements	$	53		$	165		$	298		$	396
Net change in fair value of unsettled derivatives	(299		)	(124		)	(519		)	(293		)
Total sales from natural gas marketing	$	(246	)	$	41		$	(221	)	$	103
Cost of natural gas marketing
Net settlements	$	(49	)	$	(157	)	$	(277	)	$	(375	)
Net change in fair value of unsettled derivatives	346			115			571			264
Total cost of natural gas marketing	$	297		$	(42	)	$	294		$	(111	)
Total commodity price risk management gain, net													$	80,704	$	11,056

Net settlements of commodity derivatives decreased significantly for the three months ended March 31, 2017, as compared to the three months ended March 31, 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 agreements settled by the end of 2016. Net settlements for the three months ended March 31, 2017 reflect derivative instruments entered into since mid-2014 which approximate recent realized prices. Based upon the forward strip pricing at March 31, 2017, we expect that settlements will be substantially lower on a relative basis as compared to periods in 2016.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~- Continued~~

March 31, 2017

(unaudited)

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 June 30, 2016	Derivative instruments, recorded in condensed consolidated balance sheet, gross		Effect of master netting agreements			Derivative instruments, net
As of March 31, 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	$	111,584	$	(30,404	)	$	81,180	$	40,968	$	(22,720	)	$	18,248

Liability derivatives:
Derivative instruments, at fair value	$	49,654	$	(30,404	)	$	19,250	$	30,797	$	(22,720	)	$	8,077


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

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

June 30, 2016 December 31, 2015
(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved $ 3,067,916
$ 2,881,189
Unproved 61,202
60,498
Total crude oil and natural gas properties 3,129,118
2,941,687
Equipment and other 31,566
30,098
Land and buildings 9,040
12,667
Construction in progress 117,190
113,115
Properties and equipment, at cost 3,286,914
3,097,567
Accumulated DD&A (1,356,319 ) (1,157,015 )
Properties and equipment, net $ 1,930,595
$ 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:

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

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

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

Derivative Financial Instruments

We measure the fair value of our derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors,

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~- Continued~~

March 31, 2017

(unaudited)

~~The following table presents impairment charges recorded for~~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.

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

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

Impairment of proved and unproved properties $ 1,084
$ 1,631
$ 2,053
$ 1,919
Amortization of individually insignificant unproved properties 54
2,773
86
5,257
Impairment of crude oil and natural gas properties
1,138
4,404
2,139
7,176
Land and buildings 3,032
—
3,032
—
Impairment of properties and equipment $ 4,170
$ 4,404
$ 5,171
$ 7,176



	March 31, 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	$	33,483		$	7,485		$	40,968		$	6,350		$	4,827		$	11,177
Total liabilities	(25,628		)	(5,169		)	(30,797		)	(66,789		)	(14,401		)	(81,190		)
Net asset (liability)	$	7,855		$	2,316		$	10,171		$	(60,439	)	$	(9,574	)	$	(70,013	)

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



	Three Months Ended March 31,
	2017			2016
	(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period	$	(9,574	)	$	91,288
Changes in fair value included in condensed consolidated statement of operations line item:
Commodity price risk management gain, net	13,360			6,165
Settlements included in statement of operations line items:
Commodity price risk management gain, net	(1,470		)	(24,258		)
Fair value of Level 3 instruments, net asset end of period	$	2,316		$	73,195

Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item:
Commodity price risk management gain, net	$	11,427		$	4,185

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

Short-term Investments

We categorize our short-term investments as held-to-maturity as we have the positive intent and ability to hold the securities to maturity. We have invested in commercial paper with entities with financial ratings in the A1/P1 category. At March 31, 2017, all of our held-to-maturity securities had maturities within one year of the balance sheet date and we did not realize any losses. Short-term investments in marketable securities potentially subject us to a concentration of credit risk as substantially all of our debt securities are held with one counterparty. We hold our marketable securities with major corporations with high credit standings. The carrying value of our short-term investments approximates fair value due to the short-term maturities of these investments. The amortized cost of our held-to-maturity securities at March 31, 2017 was $49.9 million. We did not hold any short-term investments at December 31, 2016.

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 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 the derivation of the value estimation.

The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of March 31, 2017.



		Estimated Fair Value		Percent of Par
		(in millions)
Senior notes:
	2021 Convertible Notes	$	206.0	103.0	%
	2022 Senior Notes	530.0		106.0	%
	2024 Senior Notes	416.0		104.0	%

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. 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; however, 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 March 31, 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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

substantially all of our deposits held in financial institutions were in excess of the FDIC insurance limits at March 31, 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 PDCM 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 analyze 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, based upon the evaluation of preliminary 2016 year-end financial statements and related information of the issuer and existing market conditions for natural gas, 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 satisfied exclusively from the existing operations of the issuer of the Promissory Note based on the latest available information.

At the end of April 2017, PDC entered into an agreement to sell the Promissory Note to an unrelated third-party buyer. Such agreement transferred all of the Company’s legal right to collect from the issuer of the Promissory Note. The sale of the Promissory Note was for cash consideration of approximately $40.3 million. The transaction closed and all funds were collected simultaneously on the date the definitive agreement to sell the Promissory Note was signed. As an agreement to sell the Promissory Note was not in effect and did not exist at March 31, 2017, this transaction has been deemed to be a subsequent event to be recorded in the second quarter of 2017. Accordingly, the Company reversed $40.3 million of the provision for uncollectible notes receivable in April 2017.

NOTE 67 - 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 tax rate, adjusted for the effect of discrete items.

The effective tax rate for the three ~~and six~~ months ended ~~June 30, 2016~~March 31, 2017, was ~~a 37.9% and 37.5% benefit~~36.3 percent expense on ~~loss~~income compared to ~~a 39.1% and 39.4%~~36.9 percent benefit on loss for the three ~~and six~~ months ended ~~June 30, 2015.~~March 31, 2016. The effective tax rate for the three ~~and six~~ months ended ~~June 30,~~March 31, 2017, includes discrete tax benefits of $1.6 million relating to the excess tax basis recognized with the vesting of stock awards during the three months ended March 31, 2017, which resulted in a 2.2 percent reduction to our effective tax rate.

The effective tax rate for the three months ended March 31, 2017, is based upon a full year forecasted tax provision on income and is greater than the statutory federal tax rate, primarily due to state 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 tax rates from the impact of stock-based compensation tax deductions as they are treated as discrete tax items. The effective tax rate for the three months ended March 31, 2016 iswas based upon a full year forecasted tax benefit on loss and is greater than the statutory federal tax rate, primarily due to state taxes and percentage depletion, partially offset by nondeductible officers’ compensation and nondeductible lobbying expenses. The effective tax rate for the three and six months ended June 30, 2015 differs from the statutory rate primarily due to state taxes and nondeductible officers' compensation, partially offset by percentage depletion and domestic production deduction. There were no significant discrete tax items recorded during the three ~~and six~~ months ended ~~June 30, 2016 or June 30, 2015.~~March 31, 2016.

As of ~~June 30, 2016,~~March 31, 2017, there is no liability for unrecognized 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 for the 2016 and 2017

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

tax years, and received final acceptance of our 2015 federal income tax return and ~~2016 tax years. With respect to~~closure of the ~~2014~~2015 tax year ~~we have agreed to a post filing adjustment with~~during 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.~~three months ended March 31, 2017.

NOTE 78 - LONG-TERM DEBT

Long-term debt consisted of the following as of:

June 30, 2016 December 31, 2015
(in thousands)
Senior notes:
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 discount and unamortized debt issuance costs —
112,940

7.75% Senior notes due 2022:
Principal amount 500,000
500,000
Unamortized debt issuance costs (7,003 ) (7,563 )
7.75% Senior notes due 2022, net of unamortized debt issuance costs 492,997
492,437
Total senior notes 492,997
605,377

Revolving credit facility —
37,000
Total debt, net of discount and unamortized debt issuance costs 492,997
642,377
Less current portion of long-term debt —
112,940
Long-term debt $ 492,997
$ 529,437

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~



	March 31, 2017			December 31, 2016
	(in thousands)
Senior notes:
1.125% Convertible Notes due 2021:
Principal amount	$	200,000		$	200,000
Unamortized discount	(35,727		)	(37,475		)
Unamortized debt issuance costs	(4,346		)	(4,584		)
1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs	159,927			157,941

7.75% Senior Notes due 2022:
Principal amount	500,000			500,000
Unamortized debt issuance costs	(6,162		)	(6,443		)
7.75% Senior Notes due 2022, net of unamortized debt issuance costs	493,838			493,557

6.125% Senior Notes due 2024:
Principal amount	400,000			400,000
Unamortized debt issuance costs	(7,304		)	(7,544		)
6.125% Senior Notes due 2024, net of unamortized debt issuance costs	392,696			392,456

Total senior notes	1,046,461			1,043,954

Revolving credit facility	—			—
Total long-term debt, net of unamortized discount and debt issuance costs	$	1,046,461		$	1,043,954

Senior Notes

~~3.25%~~2021 Convertible ~~Senior Notes Due~~Notes. In September 2016,~~. In November 2010,~~ we issued ~~$115~~$200.0 million ~~aggregate principal amount~~ of ~~3.25%~~1.125% convertible senior notes due ~~2016~~2021 (the ~~"Convertible~~"2021 Convertible Notes") in a ~~private placement to qualified institutional buyers.~~public offering. 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. The conversion stock price at maturity is $85.39 per share. We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was ~~May 15, 2016. At December 31, 2015, our indebtedness included~~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. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Note have been capitalized as debt issuance costs. As of March 31, 2017, 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 percent.

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 ~~in May 2016, we paid~~method to satisfy our conversion obligation, which allows us to settle the ~~aggregate~~ principal amount of the 2021 Convertible Notes ~~plus~~in cash ~~for~~and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional ~~shares, totaling approximately $115.0 million, utilizing proceeds from our March 2016 equity offering. Additionally,~~shares.

2022 Senior Notes. In October 2012, we issued ~~792,406 shares of common stock for the $47.9~~$500.0 million ~~excess conversion value. See Note 11,~~ ~~Common Stock,~~ ~~for more information.~~

~~7.75% Senior Notes Due 2022.~~ 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 to qualified institutional buyers.~~. The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15. ~~The indenture governing~~Approximately $11.0 million in costs associated with the

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

issuance of the 2022 Senior Notes ~~contains customary restrictive incurrence covenants. Capitalized~~have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the ~~2022~~notes using the effective interest method.

2024 Senior Notes. In September 2016, we issued $400.0 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”) in a private placement to qualified institutional buyers. 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. 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.

In January 2017, pursuant to the filing of supplemental indentures for the 2021 Convertible Notes, 2022 Senior Notes, and the 2024 Senior Notes (the "Notes"), our wholly-owned subsidiary, PDC Permian, Inc., became a guarantor of our obligations under the Notes. Accordingly, condensed consolidating financial information for PDC and PDC Permian, Inc. is presented in the footnote titled Subsidiary Guarantor.

As of ~~June 30, 2016,~~March 31, 2017, we were in compliance with all covenants related to the ~~2022 Senior~~ Notes, and expect to remain in compliance throughout the next 12-month period.

Revolving Credit Facility

Revolving Credit ~~Facility~~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. In May 2016, we completed~~base and certain limitations under our senior notes. The borrowing base amount available under the ~~semi-annual redetermination of our~~ revolving credit facility ~~by the lenders, which resulted in the reaffirmation of our borrowing base at $700 million; however, we have elected to maintain the aggregate commitment at $450 million. 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 a pledge of the stock of certain of our 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. The current borrowing base and aggregate commitments under the facility are $700 million. The May 1, 2017 redetermination has not been finalized as of the date of this report.

As of March 31, 2017 and December 31, 2016, debt issuance costs related to our revolving credit facility were $8.1 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 ~~June 30, 2016, compared to $37.0 million outstanding as of~~March 31, 2017 or December 31, ~~2015.~~2016. The ~~weighted-average interest rate on the~~ outstanding ~~balance on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.6% per annum as of December 31, 2015.~~

~~As of~~ ~~June 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 currently expires in September 2016 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces theprincipal amount of available funds under our revolving credit facility by an amount equal to the letter of credit. As of June 30, 2016, the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $438.3 million. In addition to our currently elected commitment of $450 million, we have an additional $250 million of borrowing base availability under the revolving credit facility ~~subject~~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 ~~terms~~time periods. Additionally, commitment fees, interest margin, and ~~conditions~~other bank fees, charged as a component of interest, vary with our utilization of the ~~agreement.~~facility. As of March 31, 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 fee is 0.50 percent. No principal payments are generally required until the revolving credit facility expires in May 2020, or in the event that the borrowing base falls below the outstanding balance.

The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of ~~1.00 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 ~~June 30, 2016,~~March 31, 2017, we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. As defined by the revolving credit facility, our current ratio was 3.7and our leverage ratio was 2.0as of March 31, 2017.

As of March 31, 2017, we had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure a firm transportation obligation. As of March 31, 2017, the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $688.3 million.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~- Continued~~

March 31, 2017

(unaudited)

NOTE 89 - OTHER ACCRUED EXPENSES

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



	March 31, 2017		December 31, 2016
	(in thousands)

Employee benefits	$	7,659	$	22,282
Asset retirement obligations	12,937		9,775
Environmental expenses	4,624		4,438
Other	1,718		2,130
Other accrued expenses	$	26,938	$	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 ~~June 30, 2016:~~March 31, 2017:


	Amount			March 31, 2017			December 31, 2016
	(in thousands)			(in thousands)
Vehicles	$	2,674		$	4,126		$	2,975
Accumulated depreciation	(464		)	(973		)	(776		)
	$	2,210		$	3,153		$	2,199

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 June 30,	Amount
For the Twelve Months Ending March 31,				Amount
	(in thousands)			(in thousands)
2017	$	820
2018	1,075			$	1,413
2019	734			1,376
2020				946
	2,629			3,735
Less executory cost	(105		)	(155		)
Less amount representing interest	(305		)	(402		)
Present value of minimum lease payments	$	2,219		$	3,178

Short-term capital lease obligations	$	606		$	1,108
Long-term capital lease obligations	1,613			2,070
	$	2,219		$	3,178

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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

NOTE 911 - 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 beginning of period, January 1, 2017				$	92,387
Obligations incurred with development activities	843			1,232
Accretion expense	3,623			1,768
Obligations discharged with disposal of properties and asset retirements	(5,475		)
Balance end of period, June 30, 2016	88,483
Obligations discharged with asset retirements				(4,288		)
Balance at end of period, March 31, 2017				91,099
Less current portion	(6,900		)	(12,937		)
Long-term portion	$	81,583		$	78,162

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 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 March 31, 2017, the credit-adjusted risk-free 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

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

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 1012 - COMMITMENTS AND CONTINGENCIES

Firm Transportation, Processing, and Sales 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 statements ~~only~~of operations reflect our share of ~~costs based upon our working interest in the wells.~~these firm transportation 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 of June 30, 2016, we have recorded an allowance for doubtful accounts of approximately $0.9 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. There have been no collections received to date and and some of the third-party producers have shut-in their wells.

A group of independent West Virginia natural gas producers has filed, but not served on RNG, a complaint 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 is aware of this lawsuit filing but has not received formal service of process which commences the litigation against RNG. Furthermore, 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.

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 June 30,													For the Twelve Months Ending March 31,
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		15,138		43,625		August 31, 2022
Wattenberg Field														—		5,845		18,849		18,798		84,666		128,158		September 30, 2025
Delaware Basin														13,400		14,600		14,640		11,000		—		53,640		December 31, 2020
Gas Marketing														7,117		7,117		7,136		7,117		9,796		38,283		August 31, 2022
Utica Shale	2,738		2,738		2,738		2,745		8,444		19,403		July 22, 2023	2,737		2,737		2,745		2,737		6,391		17,347		July 22, 2023
Total	9,855		9,855		9,855		9,881		23,582		63,028			23,254		30,299		43,370		39,652		100,853		237,428

Crude oil (MBbls)
Wattenberg Field	2,413		2,413		2,413		2,421		—		9,660		June 30, 2020	2,413		2,413		2,420		602		—		7,848		June 30, 2020

Dollar commitment (in thousands)	$	17,573	$	16,536	$	16,324	$	16,369	$	9,052	$	75,854		$	18,726	$	24,216	$	36,799	$	26,211	$	86,280	$	192,232

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

~~Litigation.~~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 September 30, 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 then 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.

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. The contract is effective May 1, 2017 and is in effect through December 31, 2020.

For each of the three months ended March 31, 2017 and March 31, 2016, commitments for long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $0.9 million and were recorded in transportation, gathering, and processing expense in our condensed consolidated statements of operations. During the three months ended March 31, 2017 and March 31, 2016, long-term firm transportation costs for our gas marketing business associated with the commitments shown above were $2.2 million and $2.4 million, respectively, and were recorded in other expenses in our condensed consolidated statements of operations.

Litigation and Legal Items. The Company is involved in various legal ~~proceedings that it considers normal to its business.~~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 the best interests of the Company. ~~There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any,~~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 ~~exceed the amounts reserved.~~yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations, or liquidity.

Environmental.Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events ~~that require remediation~~ are probable ~~to require remediation~~ and the costs can be reasonably estimated. ~~As of June 30, 2016 and December 31, 2015,~~Except as discussed herein, we ~~had accrued environmental liabilities in the amount of $4.0 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 ~~June 30, 2016~~March 31, 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 other accrued expenses on the condensed consolidated 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 ~~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

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

the Information Request in January 2016. ~~We continue to meet with~~In December 2016, we received a draft consent decree from the ~~EPA and provide additional information, but cannot predict the outcome of this matter at this time.~~EPA.

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 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 in the process of responding to the advisory, and working~~This matter has been combined with the ~~agency on specific response processes, but cannot predict~~matter discussed above. We have ongoing discussions with the EPA, U.S. Department of Justice, and Colorado Department of Public Health and Environment regarding these matters. The ultimate outcome ~~of this matter~~related to these combined actions has not been determined at this time.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

~~Employment Agreements with Executive Officers~~. Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant 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 followed a change of control of the Company.

NOTE 1113 - COMMON STOCK

~~Sale of Equity Securities~~

In March 2016, we completed a public offering of 5,922,500 shares of our common stock, par value $0.01 per share, 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 additional paid-in capital ("APIC") on the June 30, 2016 condensed consolidated balance sheet. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in March 2015. Upon maturity of our Convertible Notes in May 2016, we paid the aggregate principal amount, plus cash for fractional shares, totaling approximately $115.0 million, utilizing proceeds from the offering. Additionally, we issued 792,406 shares of common stock for the premium in excess of the conversion price of $42.40 per share.

In March 2015, we completed a public offering of 4,002,000 shares of our common stock, par value $0.01 per share, 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.

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 June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2016			2015			2016			2015			2017			2016
	(in thousands)												(in thousands)

Stock-based compensation expense	$	6,444		$	5,097		$	11,126		$	9,465		$	4,453		$	4,682
Income tax benefit	(2,452		)	(1,936		)	(4,233		)	(3,595		)	(1,666		)	(1,782		)
Net stock-based compensation expense	$	3,992		$	3,161		$	6,893		$	5,870		$	2,787		$	2,900

Stock Appreciation Rights ("SARs")

The 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.

~~In January 2016, the~~The Compensation Committee of our Board of Directors awarded ~~58,709~~ SARs to our executive ~~officers.~~officers during the three months ended March 31, 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:


	Six Months Ended June 30,						Three Months Ended March 31,
	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

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

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 three months ended March 31, 2017:

Six Months Ended June 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 (114,853 ) 38.71
$ 2,488
—
—

Outstanding at June 30, 270,309
41.86
7.4 4,258
347,285
38.94
7.8 $ 5,107
Vested and expected to vest at June 30, 263,546
41.70
7.4 4,193
339,980
38.88
7.7 5,019
Exercisable at June 30, 162,895
38.31
6.4 3,144
191,149
35.68
6.9 3,433



	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 March 31, 2017	298,220	47.39		7.2	5,123
Exercisable at March 31, 2017	186,248	39.38		6.1	4,279

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

Total compensation cost related to SARs granted ~~net of estimated forfeitures,~~ and not yet recognized in our condensed consolidated statement of operations as of ~~June 30, 2016~~March 31, 2017, was ~~$2.0~~$3.2 million. The cost is expected to be recognized over a weighted-average period of ~~2.1~~2.3 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 of 61,634 time-based restricted shares that vest ratably over a~~ ~~three-year period ending in January 2019.~~

The following table presents the changes in non-vested time-based awards to all employees, including executive officers, for the ~~six~~three months ended ~~June 30, 2016~~:March 31, 2017:


	Shares		Weighted-Average Grant Date Fair Value		Shares		Weighted-Average Grant Date Fair Value

Non-vested at December 31, 2015	525,081		$	50.23
Non-vested at December 31, 2016					479,642		$	56.09
Granted	267,379		57.11		106,401		73.28
Vested	(233,269	)	49.74		(48,656	)	50.46
Forfeited	(12,306	)	55.27		(2,244	)	72.58
Non-vested at June 30, 2016	546,885		53.69
Non-vested at March 31, 2017					535,143		59.95

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 Six Months Ended June 30,

2016 2015
(in thousands, except per share data)

Total intrinsic value of time-based awards vested $ 13,314
$ 10,126
Total intrinsic value of time-based awards non-vested 31,506
34,556
Market price per common share as of June 30, 57.61
53.64
Weighted-average grant date fair value per share 57.11
48.54

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~



	As of/Three Months Ended March 31,
	2017		2016
	(in thousands, except per share data)

Total intrinsic value of time-based awards vested	$	3,602	$	3,072
Total intrinsic value of time-based awards non-vested	33,366		32,687
Market price per common share as of March 31,	62.35		59.45
Weighted-average grant date fair value per share	73.28		51.74

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 ~~June 30, 2016~~March 31, 2017, was ~~$21.7 million.~~$21.5 million This cost is expected to be recognized over a weighted-average period of 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 three months ended March 31, 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:

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Six Months Ended June 30,
2016 2015

Expected term of award 3 years
3 years
Risk-free interest rate 1.2 % 0.9 %
Expected volatility 52.3 % 53.0 %
Weighted-average grant date fair value per share $ 72.54
$ 66.16
PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)



	Three Months Ended March 31,
	2017			2016

Expected term of award (in years)	3			3
Risk-free interest rate	1.4		%	1.2		%
Expected volatility	51.4		%	52.3		%
Weighted-average grant date fair value per share	$	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 ~~six~~three months ended March 31, 2017:~~June 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
(11,283 ) 98.50
Non-vested at June 30, 2016
84,546
61.51



	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 March 31, 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 Six Months Ended June 30,				As of /Three Months Ended March 31,
	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	$	—
Total intrinsic value of market-based awards non-vested	4,871		6,068		$	4,769	$	5,697
Market price per common share as of June 30,	57.61		53.64
Market price per common share as of March 31,					62.35		59.45
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 ~~June 30, 2016~~March 31, 2017, was ~~$2.2~~$3.8 million. This cost is expected to be recognized over a weighted-average period of ~~2.0~~2.3 years.

Preferred Stock

We are authorized, pursuant to stockholder approval in 2008, 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. As of March 31, 2017 and December 31, 2016, no preferred shares had been issued.

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~~PDC ENERGY, INC.~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued~~

NOTE 1214 - 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~~convertible notes, and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

The following table presents a reconciliation of the weighted-average diluted shares outstanding:


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended March 31,
	2016	2015	2016	2015	2017	2016
	(in thousands)				(in thousands)

Weighted-average common shares outstanding - basic	46,742	40,035	44,175	38,202	65,749	41,608
Dilutive effect of:
Restricted stock					211	—
Other equity-based awards					157	—
Weighted-average common shares and equivalents outstanding - diluted	46,742	40,035	44,175	38,202	66,117	41,608

We reported a net loss for the three ~~and six~~ months ended ~~June 30, 2016 and 2015, respectively.~~March 31, 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 June 30,		Six Months Ended June 30,		Three Months Ended March 31,
	2016	2015	2016	2015	2017	2016
	(in thousands)				(in thousands)

Weighted-average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Restricted stock	768	871	745	832	76	723
Convertible notes	358	677	478	523	—	508
Other equity-based awards	103	118	105	99	18	100
Total anti-dilutive common share equivalents	1,229	1,666	1,328	1,454	94	1,331

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

In November 2010, we issued ~~our~~$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 7,~~ ~~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.

Shares issuable upon conversion of the 2021 Convertible Notes and 2016 Convertible Notes were excluded from the diluted earnings per share calculation for the ~~three and six months ended June 30, 2016 and 2015~~applicable periods as the effect would be anti-dilutive to our earnings per share.

NOTE 1315 - ~~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 and resells natural gas produced by unrelated third-parties. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income, less costs of natural gas marketing and direct general and administrative expense.

~~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.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ~~- Continued~~

March 31, 2017

(unaudited)

The Guarantor is 100% owned by the Parent beginning in December 2016. The Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the condensed consolidating financial information follows the same accounting policies as described in the notes to the condensed consolidated financial statements.

The following ~~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 June 30, Six Months Ended June 30,
2016 2015 2016 2015
(in thousands)
Segment revenues:
Oil and gas exploration and production $ 18,218
$ 48,437
$ 106,878
$ 189,836
Gas marketing 1,879
2,523
4,050
5,756
Total revenues $ 20,097
$ 50,960
$ 110,928
$ 195,592

Segment income (loss) before income taxes:
Oil and gas exploration and production $ (118,508 ) $ (44,364 ) $ (152,541 ) $ 16,161
Gas marketing (246 ) (313 ) (653 ) (338 )
Unallocated (35,023 ) (32,309 ) (113,952 ) (65,024 )
Loss before income taxes $ (153,777 ) $ (76,986 ) $ (267,146 ) $ (49,201 )



	Condensed Consolidating Balance Sheets
	March 31, 2017
	Parent		Guarantor		Eliminations			Consolidated
	(in thousands)
Assets
Current assets	$	397,276	$	14,495	$	—		$	411,771
Properties and equipment, net	1,923,981		2,174,482		—			4,098,463
Intercompany receivable	43,550		—		(43,550		)	—
Investment in subsidiaries	1,765,386		—		(1,765,386		)	—
Goodwill	—		56,058		—			56,058
Noncurrent assets	26,653		185		—			26,838
Total Assets	$	4,156,846	$	2,245,220	$	(1,808,936	)	$	4,593,130

Liabilities and Stockholders' Equity
Current liabilities	$	266,368	$	51,614	$	—		$	317,982
Intercompany payable	—		43,550		(43,550		)	—
Long-term debt	1,046,461		—		—			1,046,461
Other noncurrent liabilities	172,840		384,670		—			557,510
Stockholders' equity	2,671,177		1,765,386		(1,765,386		)	2,671,177
Total Liabilities and Stockholders' Equity	$	4,156,846	$	2,245,220	$	(1,808,936	)	$	4,593,130

June 30, 2016 December 31, 2015
(in thousands)
Segment assets:
Oil and gas exploration and production $ 2,244,799
$ 2,294,288
Gas marketing 4,117
4,217
Unallocated 22,754
72,038
Total assets $ 2,271,670
$ 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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)



	Condensed Consolidating Statements of Operations
	Three Months Ended March 31, 2017
	Parent			Guarantor			Eliminations		Consolidated
	(in thousands)

Operating and other revenues	$	254,740		$	18,967		$	—	$	273,707
Operating expenses	37,499			6,681			—		44,180
General and administrative	23,529			2,786			—		26,315
Depreciation depletion and amortization	101,738			7,578			—		109,316
Impairment of properties and equipment	604			1,589			—		2,193
Interest (expense) income	(19,357		)	130			—		(19,227		)
Income before income taxes	72,013			463			—		72,476
Income tax expense	(26,162		)	(168		)	—		(26,330		)
Net income	$	45,851		$	295		$	—	$	46,146



	Condensed Consolidating Statements of Cash Flows
	Three Months Ended March 31, 2017
	Parent			Guarantor			Eliminations			Consolidated
	(in thousands)

Cash flows from operating activities	$	131,661		$	7,839		$	—		$	139,500
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural properties	(82,489		)	(47,337		)	—			(129,826		)
Capital expenditures for other properties and equipment	(890		)	69			—			(821		)
Acquisition of crude oil and natural gas properties, including settlement adjustments	—			6,181			—			6,181
Proceeds from sale of properties and equipment	737			—			—			737
Purchases of short-term investments	(49,890		)	—			—			(49,890		)
Intercompany transfers	(33,795		)	—			33,795			—
Net cash from investing activities	(166,327		)	(41,087		)	33,795			(173,619		)
Cash flows from financing activities:
Proceeds from issuance of equity, net of issuance costs	(8		)	—			—			(8		)
Other	(2,339		)	(10		)	—			(2,349		)
Intercompany transfers	—			33,795			(33,795		)	—
Net cash from financing activities	(2,347		)	33,785			(33,795		)	(2,357		)
Net change in cash and cash equivalents	(37,013		)	537			—			(36,476		)
Cash and cash equivalents, beginning of period	240,487			3,613			—			244,100
Cash and cash equivalents, end of period	$	203,474		$	4,150		$	—		$	207,624

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.

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PDC ENERGY, INC.

EXECUTIVE SUMMARY

Financial Overview

Production volumes increased ~~substantially~~ to ~~5.2 MMboe and 9.8~~6.6 MMboe for the three ~~and six~~ months ended ~~June 30, 2016, respectively,~~March 31, 2017, representing ~~increases~~an increase of ~~54% and 56%, respectively,~~46 percent as compared to the three ~~and six~~ months ended ~~June 30, 2015.~~March 31, 2016. The increase in production volumes was primarily attributable to the continued success of our ~~successful~~ horizontal Niobrara and Codell drilling program in the Wattenberg ~~Field.~~ Field and our first full quarter of production from the newly-acquired Delaware Basin properties.Crude oil production increased ~~26% and 35%~~32 percent for the three ~~and six~~ months ended ~~June 30, 2016, respectively,~~March 31, 2017 compared to the ~~same prior year periods.~~three months ended March 31, 2016. Crude oil production comprised approximately ~~38% and 40%~~38 percent of total production in the three ~~and six~~ months ended June 30, 2016. Our ratio of crude oil production to total production decreased as expected as we shifted our focus to the higher gas to oil ratio inner core area of the Wattenberg Field. We expect our ratio of crude oil to total production to increase during the second half of 2016 as we move drilling operations back toward the middle core area of the Wattenberg Field.March 31, 2017. Natural gas production increased ~~73% and 69%~~46 percent in the three ~~and six~~ months ended ~~June 30, 2016, respectively,~~March 31, 2017 compared to the three ~~and six~~ months ended ~~June 30, 2015.~~ March 31, 2016.NGL production increased ~~93% and 85%~~75 percent for the three ~~and six~~ months ended ~~June 30, 2016, respectively,~~March 31, 2017 compared to the ~~same prior year periods. Our inner~~three months ended March 31, 2016. While our oil production has increased at a meaningful level, our middle core wells in the Wattenberg Field have ~~shown stronger~~performed even better, with wet gas production ~~than anticipated, which~~that has outpaced oil and contributed to the growth of gas and ~~NGL production. The majority~~NGLs production at a relatively higher rate. On a combined basis, total liquids production comprised 61 percent of ~~our wells turned-in-line~~total production during each of the three months ended March 31, ~~2016 occurred toward~~2017 and March 31, 2016. For the ~~end~~month ended March 31, 2017, we maintained an average quarterly production rate of ~~the quarter, while wells turned-in-line during~~approximately 73,900 Boe per day, up from approximately 50,200 Boe per day for the three months ended ~~June 30,~~March 31, 2016.

On a sequential quarterly basis, production volumes for the three months ended March 31, 2017, as compared to the three months ended December 31, 2016, ~~occurred more evenly throughout~~increased by four percent. The modest increase in production was primarily related to the ~~period. As expected, this drove our quarter-over-quarter~~scheduled 46 wells turned-in-line for the three months ended March 31, 2017 occurring in the later portion of the quarter as well completion activity resumed in January 2017 following a period in November and December 2016 in which no wells were completed. The decision to delay well completions created a two to three month delay in wells being turned-in-line, which resulted in the relatively flat production ~~increase of approximately 0.6 Mboe, or 14%.~~on a sequential basis. We expect the timing of ~~the~~ wells to be turned-in-line to sales during the remainder of 2017 to be relatively steady. When this trend is combined with our increased level of capital investment, we expect to have more substantial increases in sequential quarterly production volumes throughout the remainder of 2017 as compared to that of the three months ended ~~September 30, 2016 to be relatively even, similar to the timing for~~March 31, 2017, versus the three months ended ~~June 30,~~December 31, 2016. We expect a modest increase in production for the third quarter as compared to the second quarter. For the month ended June 30, 2016, our average production rate was 58 MBoe per day, up from 42 MBoe per day for the month ended June 30, 2015.

Crude oil, natural gas, and NGLs sales ~~coupled with the impact of settled derivatives, increased during the three and six months ended June 30, 2016 relative to the same prior year periods. Crude oil, natural gas and NGLs sales~~ increased to ~~$110.8 million and $186.2 million during the three and six months ended June 30, 2016 compared to $96.9 million and $171.0~~$189.7 million in the ~~same prior year periods due~~three months ended March 31, 2017, compared to ~~54% and 56% increases in production, respectively, offset in part by 26% and 30% decreases, respectively,~~$75.4 million in the three months ended March 31, 2016. This 152 percent increase in sales revenues was driven by the 73 percent increase in realized commodity prices and a 46 percent increase in production. We had net commodity price ~~per barrel~~risk management gains of ~~crude oil equivalent ("Boe"). The realized prices per Boe~~$80.7 million and $11.1 million, of which $0.5 million and $66.8 million were ~~$21.33 and $19.07~~positive net settlements, for the three ~~and six~~ months ended ~~June 30,~~March 31, 2017 and March 31, 2016, respectively, compared to $28.79 and $27.32, respectively, for the same prior year periods. Positive net settlements on derivatives increased to $53.3 million and $120.1 million during the three and six months ended June 30, 2016, respectively, compared to positive net settlements on derivatives of $44.1 million and $94.5 million in the same prior year periods, due to lower crude oil and natural gas index settlement prices. As a result of these increases,respectively. The combined revenue from crude oil, natural gas, and NGLs sales and ~~the impact of~~ net ~~settled derivatives totaled $164.1~~settlements received on our commodity derivative instruments increased 34 percent to $190.2 million ~~and $306.3 million during~~in the three ~~and six~~ months ended ~~June 30, 2016, respectively, compared to $141.0~~March 31, 2017, from $142.2 million ~~and $265.5 million during~~in the three ~~and six~~ months ended ~~June 30, 2015, respectively. This represents increases~~March 31, 2016.

Net settlements of ~~16% and 15% during~~derivatives decreased significantly for the three ~~and six~~ months ended ~~June 30, 2016, respectively,~~March 31, 2017, as compared to the ~~same~~three months ended March 31, 2016. We entered into agreements for the derivative instruments that settled throughout 2016 prior ~~year periods. The realized~~to commodity prices ~~per Boe, including~~becoming depressed in late 2014. Substantially all of these high-value derivatives settled by the ~~impact~~end of ~~net~~2016. Net settlements ~~on derivatives, were $31.58 and $31.36~~ for the three ~~and six~~ months ended ~~June 30, 2016, respectively,~~March 31, 2017, reflect derivative instruments entered into since mid-2014 which approximate recent realized prices. Based upon the forward strip pricing at March 31, 2017, we expect that settlements will be substantially lower on a relative basis as compared to ~~$41.88 and $42.40 for the same prior year~~ periods ~~respectively.~~in 2016.

~~Additional~~In the three months ended March 31, 2017, we generated net income of $46.1 million, or $0.70 per diluted share. During this same period, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $130.2 million, and we invested $199.4 million in the development and exploration of our oil and natural gas properties, exclusive of the change in accounts payable related to capital expenditures. Beginning in 2017, we have included non-cash stock-based compensation and exploration, geologic and geophysical expense to our adjusted EBITDAX calculation. In prior periods, we included adjusted EBITDA, a non-U.S. GAAP financial measure, that did not include these adjustments. All prior periods have been conformed for comparability of this updated presentation. In the same period of 2016, our net loss per diluted share was $1.72 and our adjusted EBITDAX, a non-GAAP financial measure, was $57.8 million. Our cash flow from operations was $139.5 million and our adjusted cash flow from operations, a non-U.S. GAAP financial measure, was $113.7 million in the three months ended March 31, 2017. See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures.

Other significant changes impacting our results of operations for the three months ended ~~June 30, 2016~~March 31, 2017, include the following:

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~~Negative~~

Positive net change in the fair value of unsettled ~~derivative positions during~~derivatives for the three months ended ~~June 30, 2016~~March 31, 2017 was ~~$146.1~~$80.2 million, compared to a negative net change in the fair value of unsettled ~~derivative positions~~derivatives for the three months ended March 31, 2016 of ~~$93.1 million during~~$55.7 million. The increase in the ~~same prior year period. The decrease in~~ fair value of unsettled ~~derivative positions was primarily attributable~~derivatives is largely driven by a downward shift in the crude oil forward curve during the three months ended March 31, 2017, as compared to ~~a more significant~~an upward shift in the crude oil ~~and natural gas~~ forward ~~curves that occurred~~curve during ~~the current quarter as compared to~~ the three months ended ~~June 30, 2015; and~~March 31, 2016.

Depreciation, depletion, and amortization expense increased to ~~$107.0~~$109.3 million during the three months ended ~~June 30, 2016~~March 31, 2017, as compared to ~~$70.1~~$97.4 million in the ~~same prior year period,~~three months ended March 31, 2016. The increase was primarily due to ~~increased production.~~

~~Additional significant changes impacting our results of operations for~~ the ~~six~~increase in production and an increase in the property balance during the three months ended ~~June 30, 2016 include~~March 31, 2017 as compared to the ~~following:~~

~~Negative net change~~three months ended March 31, 2016. The increase in the ~~fair value of unsettled derivative positions during the six months ended June 30, 2016 was $201.8 million compared~~property balance is due to a negative net change in the fair value of unsettled derivative positions of $76.8 million during the same prior year period. The decrease in fair value of unsettled derivative positions was primarily attributable to a higher beginning-of-period fair value of derivatives instruments that settled during the six months ended June 30, 2016 and an upward shift in the crude oil and natural gas forward curves that occurred during the second quarter of 2016;

~~Depreciation,~~our Delaware Basin acquisitions. Our depreciation, depletion, and amortization expense ~~increased~~decreased to ~~$204.4 million~~$16.44 per Boe during the ~~six~~three months ended ~~June 30,~~March 31, 2017 from $21.31 per Boe during the three months ended March 31, 2016 ~~compared to $125.9 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; and~~

~~During the first quarter of 2016, we determined that collection of two third-party notes receivable arising from the sale~~because of our ~~interest in properties in the Marcellus Shale was not reasonably assured based upon current market conditions and new information~~

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made available to us. As a result, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.7 million outstanding balance as of March 31, 2016. As of June 30, 2016, there has been no change to our assessment of the collectibility of the notes. See Note 3, ~~Fair Value of Financial Instruments - Notes Receivable, to our condensed consolidated financial statements included elsewhere in this report for additional information.~~

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, the principal amount owed upon the maturity of the Convertible Notes in May 2016 and retained the remainder for general corporate purposes.

The Convertible Notes matured in May 2016. We paid 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 Energy, Inc. and certain of its subsidiaries ("Noble") to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the terms of the agreements, this strategic trade includes leasehold acreage only, and does not include production or wellbores. We expect to receive approximately 13,500 net acres in exchange for approximately 11,700 net acres, subject, in each case, to title examination and other customary adjustments. The difference in net acres is primarily due to variances in net revenue interests. This acreage trade is expected to increase opportunities for longer horizontal laterals with significantly increased ~~working interests, while minimizing potential surface impact. We anticipate closing this transaction early in the fourth quarter of 2016.~~proved reserve profile;

Available liquidity as of ~~June 30, 2016~~March 31, 2017, was ~~$547.4~~$945.8 million compared to ~~$402.2~~$932.4 million as of December 31, ~~2015.~~2016. Available liquidity as of ~~June 30, 2016~~March 31, 2017 is comprised of ~~$109.1~~$207.6 million of cash and cash equivalents, $49.9 million of short-term investments, and ~~$438.3~~$688.3 million available for borrowing under our revolving credit facility. ~~These amounts exclude~~Our liquidity will be impacted by our planned 2017 capital investment activities. We expect decreases in our cash balances over the course of 2017 as we continue development in the core Wattenberg Field and the expected 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 flow from our 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, utilization of our borrowing capacity under our revolving credit facility, ~~subject~~and when warranted, the utilization of capital markets transactions from time to certain terms and conditions of the agreement. In May 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. 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 execute our expected 2016 development program.time.

Operational Overview

~~Drilling Activities~~. During the ~~six~~three months ended ~~June 30, 2016,~~March 31, 2017, we continued to execute our strategic plan to grow production while preserving our financial strength and ~~liquidity by managing our capital spending to approximate our cash flows from operations. Through July 2016,~~liquidity. During the three months end March 31 2017, we ~~ran four automated~~operated three drilling rigs in the Wattenberg ~~Field. During the six months ended June 30, 2016, we spud 76 horizontal wells~~Field and ~~turned-in-line 81 horizontal wells~~two increasing to three rigs in the ~~Wattenberg Field.~~Delaware Basin. We also participated in 24 gross, 6.5 net, horizontal non-operated wells that were spud and 12 gross, 3.2 net, horizontal non-operated wells which were turned-in-line. During the six months ended June 30, 2016, we drilled and completed five wellsdid not have a drilling rig operating in the Utica Shale ~~three of which were turned-in-line~~ during the period. Of

The following table summarizes our drilling and completion activity for the three months ended March 31, 2017:



	Wattenberg Field				Delaware Basin				Total
	Gross		Net		Gross		Net		Gross		Net
In-process as of December 31, 2016	76		55.5		5		4.8		81		60.3
Wells spud during the period	42		26.2		7		6.7		49		32.9
Wells turned-in-line to sales	(43	)	(32.7	)	(3	)	(3.0	)	(46	)	(35.7	)
In-process as of March 31, 2017	75		49.0		9		8.5		84		57.5

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. We do not have a practice of inventorying our drilled but uncompleted wells. The majority of these ~~three~~in-process wells ~~one~~at each period end are drilled but not completed as we do not begin the completion process until the entire well pad is ~~a 10,000 foot lateral well located~~drilled. 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 ~~Guernsey County and two~~the period in which the wells are ~~6,000 foot lateral wells located in Washington County. We plan to turn-in-line the two remaining wells over the next several months.~~completed.

~~2016~~2017 Operational Outlook

We ~~are raising the mid-point of our production range and now~~previously announced that we expect our production for ~~2016~~the full year 2017 to berange between ~~21.0~~30.0 MMBoe to 33.0 MMBoe. Based on the timing and ~~22.0 MMBoe and~~estimated productivity of wells associated with our capital investment program, we currently believe that our production ~~rate~~ will ~~average~~come in at levels in the top third of the range. We expect that approximately ~~58,000 to 60,000 Boe per day.~~41 percent of our 2017 production will be crude oil and approximately 22 percent will be NGLs, for total liquids of approximately 63 percent of our 2017 production. Our ~~revised 2016~~ capital forecast of ~~$400~~between $725 million ~~to $420~~and $775 million is focused on ~~continuing to provide value-driven production growth by exploiting our substantial inventory of reasonable rate-of-return projects~~continued development in the core Wattenberg ~~Field.~~Field and the continued integration and development of the core Delaware Basin assets. We added the third rig in the Delaware Basin sooner than originally anticipated and have adjusted the costs per

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well in the Delaware Basin up from our initial estimates to reflect higher service costs during the first quarter of 2017. Our total capital investment program will vary based on the number of wells ultimately drilled and completed. Based on the current operating plan and current cost estimates, we expect that our 2017 capital investment program will be in the upper half of the range.

Wattenberg Field. ~~As a result~~The 2017 investment forecast of ~~increased working interests in planned wells resulting from the anticipated acreage exchange with Noble, we reduced the number of rigs~~approximately $470 million in the Wattenberg Field anticipates a three to four-rig drilling ~~plan~~program based on our current commodity price outlook. Approximately $460 million of our 2017 capital investment program is expected to ~~three beginning in August 2016. With the reduction from four drilling rigs~~be allocated to ~~three in the Wattenberg Field, our 2016 capital forecast has been slightly reduced to approximately $375 million in the field,~~development activities, comprised of approximately ~~$340~~$440 million for our operated drilling program and approximately $20 million for ~~non-operated projects.~~wells drilled and operated by others. The remainder of the Wattenberg Field capital investment program is expected to be used for ~~leasing, workover projects~~miscellaneous well equipment and ~~other~~ capital ~~improvements.~~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, we anticipate spudding approximately 139 and turning-in-line approximately 139 horizontal operated wells with lateral lengths of 4,000 to 10,000 feet.

Delaware Basin. Our 2017 investment forecast contemplates the operation of a two-rig to four-rig program in the Delaware Basin from time to time during the year. Total capital investment in the Delaware Basin is estimated to be $290 million, of which approximately $225 million is allocated to spud 32 and turn-in-line an estimated 23 wells. Of the 23 planned turn-in-lines, 11 are expected to have 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 12 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. Based on the timing of our operations and the requirements to hold acreage, we may adapt our capital investment program to drill wells in addition to those currently anticipated, as we are continuing to analyze terms of the leaseholds related to our recent acquisitions of properties in the basin. We plan to ~~spud 128~~invest approximately $30 million for leasing, seismic, and ~~turn-in-line 140 horizontal Niobrara or Codell~~technical studies with an additional $35 million for midstream-related projects including gas connections, salt water disposal wells, and ~~participate~~surface location infrastructure.

We will 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 anticipate that this will result in approximately ~~15 gross, 4.0 net, non-operated horizontal opportunities~~$5 million to $10 million of exploration expense in ~~2016. During the six months ended June 30, 2016, we invested approximately $182 million, or approximately 49%, of our 2016 capital forecast for the Wattenberg Field.~~2017.

Utica Shale.As a result of our evaluation of our strategic alternatives with respect to our Utica Shale position, we expect to divest these properties during 2017. As of ~~June 30, 2016, all of~~March 31, 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 drilling and completion activity in the Utica Shale for 2016 has been completed as described above. We plan to turn-in-line the two remaining wells during the second half of 2016 once midstream pipeline facilities are available for connection. Additionally, we plan to perform modest amounts of drill site preparation and to pursue infill leasing opportunities. During the six months ended June 30, 2016, we have invested approximately $25 million of our total 2016 capital forecast for the Utica Shale of approximately $30 million.

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~~2016 Operational Flexibility~~

~~In December 2015, the Board of Directors approved our 2016 development plan. This plan, which primarily focuses on the drilling program in the Wattenberg Field, was based upon our goal to preserve our~~condensed consolidated balance sheet by managing our capital spending to approximate our cash flows from operations. Additionally, with the proceeds from our March 2016 equity offering and settlement of our convertible notes in May 2016, we believe we have further strengthened our balance sheet, while concurrently increasing production and cash flows.

~~We maintain significant operational flexibility to reduce the pace of our capital spending.~~sheets. We will continue to ~~monitor~~evaluate the classification of these assets in future ~~commodity prices, and should prices remain depressed or further deteriorate, we believe an adjustment~~quarters. Minimal capital is expected to be committed to our development plan may be appropriate. We believe we have ample opportunities to reduce capital spending, including but not limited to: working with our vendors to achieve further cost reductions; reducing the number of rigs being utilizedUtica Shale assets in our drilling program; and/or managing our completion schedule. The production impact of reduced 2016 capital spending would be felt primarily in 2017 and thereafter, as our anticipated long-term production growth would likely be reduced. This operational flexibility is maintained with little exposure to incurring additional costs, given that all of our acreage in the Wattenberg Field is held by production, a reduction in rigs would not cause us to incur substantial idling costs as our rig commitments are short term (30 to 90 days), and we do not anticipate having additional material unfulfilled transportation commitment fees.

~~Ballot Initiative Update~~

Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state. Proponents of two such initiatives have submitted signatures in an effort to qualify the initiatives to appear on the ballot in November 2016. The signatures are subject to a verification process to be conducted by the Colorado Secretary of State. This process could take up to 30 days. We do not know what the outcome of this process will be. However, based on unofficial reports regarding the number of signatures submitted and the expectation that some signatures will be invalidated, we believe there is a substantial likelihood that the initiatives will not qualify for the ballot. If the initiatives qualify and are approved by the voters of Colorado, the proposals will take effect by the end of 2016.

One of the initiatives that could appear on the ballot, which we refer to as the “local control” initiative, would amend 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. The other initiative, which we refer to as the “setback” initiative, would amend 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 “area of special concern,” broadly defined to include 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. The current minimum required setback between oil and gas wells and occupied structures is generally 500 feet. If implemented, the 2,500 foot setback proposal would effectively prohibit the vast majority of our planned future drilling activities and would therefore make it impossible to pursue our current development plans. The local control proposal would potentially have a similar effect, depending on the nature and extent of regulations implemented by relevant local governmental authorities.

Because substantially all of our current operations and reserves are located in Colorado, the risks we face with respect to these proposals, and possible similar future proposals, are greater than those of our competitors with more geographically diverse operations. We cannot predict the outcome of the potentially pending initiatives or possible future regulatory developments.

~~See Part II, Item1A,~~ 2017.~~Risk Factors, for additional information regarding the ballot initiatives.~~

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Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results:


	Three Months Ended June 30,								Six Months Ended June 30,								Three Months Ended March 31,
	2016			2015			Percentage Change		2016			2015			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)	1,992.6			1,581.4			26.0	%	3,900.4			2,888.1			35.1	%	2,508			1,908		31.5	%
Natural gas (MMcf)	12,672.8			7,323.7			73.0	%	23,350.8			13,848.1			68.6	%	15,584			10,678		45.9	%
NGLs (MBbls)	1,092.5			565.0			93.4	%	1,974.7			1,065.5			85.3	%	1,543			882		74.8	%
Crude oil equivalent (MBoe) ~~(2)~~	5,197.1			3,367.1			54.3	%	9,766.8			6,261.7			56.0	%	6,648			4,570		45.5	%
Average MBoe per day	57.1			37.0			54.3	%	53.7			34.6			56.0	%
Average Boe per day																	73,866			50,216		47.1	%
Crude Oil, Natural Gas and NGLs Sales
Crude oil	$	80.4		$	76.4		5.2	%	$	134.4		$	128.4		4.7	%	$	123.0		$	54.0	127.8	%
Natural gas	17.4			14.9			16.8	%	32.3			30.6			5.6	%	36.9			14.9		147.7	%
NGLs	13.0			5.6			132.1	%	19.5			12.0			62.5	%	29.8			6.5		358.5	%
Total crude oil, natural gas and NGLs sales	$	110.8		$	96.9		14.3	%	$	186.2		$	171.0		8.9	%
Total crude oil, natural gas, and NGLs sales																	$	189.7		$	75.4	151.6	%

Net Settlements on Derivatives (3)
Net Settlements on Commodity Derivatives (1)
Crude oil	$	38.7		$	37.0		4.6	%	$	92.0		$	81.7		12.6	%	$	(3.2	)	$	53.3	*
Natural gas	14.6			7.1			105.6	%	28.1			12.8			119.5	%	3.7			13.5		(72.6	)%
Total net settlements on derivatives	$	53.3		$	44.1		20.9	%	$	120.1		$	94.5		27.1	%	$	0.5		$	66.8	(99.3	)%

Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	40.37		$	48.31		(16.4	)%	$	34.46		$	44.47		(22.5	)%	$	49.04		$	28.29	73.3	%
Natural gas (per Mcf)	1.37			2.03			(32.5	)%	1.38			2.21			(37.6	)%	2.37			1.39		70.5	%
NGLs (per Bbl)	11.93			10.01			19.2	%	9.89			11.23			(11.9	)%	19.29			7.37		161.7	%
Crude oil equivalent (per Boe)	21.33			28.79			(25.9	)%	19.07			27.32			(30.2	)%	28.53			16.49		73.0	%

Average Lease Operating Expenses (per Boe) (4)
Wattenberg Field	$	2.66		$	3.92		(32.1	)%	$	3.00		$	4.80		(37.5	)%
Utica Shale	2.08			1.55			34.2	%	2.28			1.67			36.5	%
Weighted-average	2.63			3.71			(29.1	)%	2.97			4.52			(34.3	)%

Natural Gas Marketing Contribution Margin (5)	$	(0.2	)	$	(0.3	)	(33.3	)%	$	(0.6	)	$	(0.3	)	(100.0	)%

Other Costs and Expenses
Average Costs and Expenses (per Boe)
Lease operating expenses																	$	2.98		$	3.35	(11.0	)%
Production taxes	$	6.0		$	3.8		57.5	%	$	10.1		$	7.7		30.8	%	1.87			0.89		110.1	%
Transportation, gathering and processing expenses	4.5			1.3			241.4	%	8.5			2.6			221.5	%	0.89			0.88		1.1	%
Impairment of properties and equipment	4.2			4.4			(5.3	)%	5.2			7.2			(27.9	)%
General and administrative expense	23.6			20.7			13.8	%	46.4			41.8			11.0	%	3.96			4.98		(20.5	)%
Depreciation, depletion and amortization	107.0			70.1			52.6	%	204.4			125.9			62.3	%	16.44			21.31		(22.9	)%
Provision for uncollectible notes receivable	—			—			*		44.7			—			*

Interest expense	$	10.7		$	11.6		(7.7	)%	$	22.6		$	23.3		(3.1	)%
Lease Operating Expenses by Operating Region (per Boe)
Wattenberg Field																	$	2.66		$	3.40	(21.8	)%
Delaware Basin																	6.48			—		*
Utica Shale																	1.60			2.50		(36.0	)%


*	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, natural gas 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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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 June 30, Six Months Ended June 30,
Production by Operating Region 2016 2015 Percentage Change 2016 2015 Percentage Change
Crude oil (MBbls)
Wattenberg Field 1,894.0
1,449.7
30.6 % 3,712.2
2,640.9
40.6 %
Utica Shale 98.6
131.7
(25.1 )% 188.2
247.2
(23.9 )%
Total 1,992.6
1,581.4
26.0 % 3,900.4
2,888.1
35.1 %
Natural gas (MMcf)
Wattenberg Field 12,097.8
6,651.1
81.9 % 22,268.2
12,562.4
77.3 %
Utica Shale 575.0
672.6
(14.5 )% 1,082.6
1,285.7
(15.8 )%
Total 12,672.8
7,323.7
73.0 % 23,350.8
13,848.1
68.6 %
NGLs (MBbls)
Wattenberg Field 1,047.3
509.9
105.4 % 1,887.4
961.8
96.2 %
Utica Shale 45.2
55.1
(18.0 )% 87.3
103.7
(15.8 )%
Total 1,092.5
565.0
93.4 % 1,974.7
1,065.5
85.3 %
Crude oil equivalent (MBoe)
Wattenberg Field 4,957.5
3,068.2
61.6 % 9,310.9
5,696.5
63.4 %
Utica Shale 239.6
298.9
(19.8 )% 455.9
565.2
(19.3 )%
Total 5,197.1
3,367.1
54.3 % 9,766.8
6,261.7
56.0 %

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

Three Months Ended June 30, Six Months Ended June 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 $ 40.41
$ 48.09
(16.0 )% $ 34.51
$ 44.41
(22.3 )%
Utica Shale 39.57
50.78
(22.1 )% 33.44
45.12
(25.9 )%
Weighted-average price 40.37
48.31
(16.4 )% 34.46
44.47
(22.5 )%
Natural gas (per Mcf)
Wattenberg Field $ 1.36
$ 2.03
(33.0 )% $ 1.38
$ 2.21
(37.6 )%
Utica Shale 1.58
2.06
(23.3 )% 1.51
2.22
(32.0 )%
Weighted-average price 1.37
2.03
(32.5 )% 1.38
2.21
(37.6 )%
NGLs (per Bbl)
Wattenberg Field $ 11.87
$ 10.01
18.6 % $ 9.78
$ 10.91
(10.4 )%
Utica Shale 13.27
9.95
33.4 % 12.29
14.17
(13.3 )%
Weighted-average price 11.93
10.01
19.2 % 9.89
11.23
(11.9 )%
Crude oil equivalent (per Boe)
Wattenberg Field $ 21.27
$ 28.78
(26.1 )% $ 19.03
$ 27.31
(30.3 )%
Utica Shale 22.59
28.86
(21.7 )% 19.75
27.38
(27.9 )%
Weighted-average price 21.33
28.79
(25.9 )% 19.07
27.32
(30.2 )%

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

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~~PDC ENERGY, INC.~~

For the three ~~and six~~ months ended ~~June 30, 2016,~~March 31, 2017, crude oil, natural gas, and NGLs sales revenue increased compared to the three ~~and six~~ months ended ~~June 30, 2015~~March 31, 2016 due to the ~~following:~~following (in millions):

June 30, 2016
Three Months Ended Six Months Ended
(in millions)
Increase in production $ 36.0
$ 76.2
Decrease in average crude oil price (15.8 ) (39.0 )
Decrease in average natural gas price (8.4 ) (19.4 )
Increase (decrease) in average NGLs price 2.1
(2.6 )
Total increase in crude oil, natural gas and NGLs sales revenue $ 13.9
$ 15.2



Increase in production	$	28.7
Increase in average crude oil price	52.0
Increase in average natural gas price	15.2
Increase in average NGLs price	18.4
Total increase in crude oil, natural gas and NGLs sales revenue	$	114.3

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 quarter ended March 31, 2016:



	Three Months Ended March 31,
Production by Operating Region	2017	2016	Percentage Change
Crude oil (MBbls)
Wattenberg Field	2,142	1,818	17.8	%
Delaware Basin	275	—	*
Utica Shale	91	90	2.3	%
Total	2,508	1,908	31.5	%
Natural gas (MMcf)
Wattenberg Field	13,714	10,170	34.8	%
Delaware Basin	1,246	—	*
Utica Shale	624	508	23.0	%
Total	15,584	10,678	45.9	%
NGLs (MBbls)
Wattenberg Field	1,358	840	61.7	%
Delaware Basin	131	—	*
Utica Shale	54	42	27.3	%
Total	1,543	882	74.8	%
Crude oil equivalent (MBoe)
Wattenberg Field	5,786	4,354	32.9	%
Delaware Basin	613	—	*
Utica Shale	249	216	15.3	%
Total	6,648	4,570	45.5	%

* Percentage change is not meaningful.

Amounts may not recalculate due to rounding.

~~Production for the second quarter of 2016~~From time to time, our production was ~~5.2 million Boe, up from 3.4 million Boe~~adversely affected by high line pressures in the ~~second quarter of 2015. Year-to-date, production was 9.8 million Boe, up from 6.3 million Boe~~natural gas gathering facilities in the ~~first six months of 2015. Production increased~~Wattenberg Field. This situation improved significantly in 2015 as a result of ~~continued drilling and completion activities as discussed~~the investment in ~~Operational Overview. Gathering system line pressures decreased following~~additional field processing by the ~~commissioning of DCP’s Lucerne II plant~~primary midstream service provider in the ~~summer of 2015, down~~basin. Line pressures did not materially affect our production during the threemonths endedMarch 31, 2017 or 2016 due to ~~levels that were consistent with~~the aforementioned investment by our ~~projections. We continued to experience 24% lower line pressures~~midstream providers and a decrease in development activity by certain producers in the ~~second quarter~~Wattenberg Field. During the threemonths endedMarch 31, 2017 and 2016, approximately 91 percent and 88 percent, respectively, of ~~2016~~our production in the Wattenberg Field was delivered from horizontal wells, with the remaining production coming from vertical wells. Horizontal wells typically have greater producing capacity and higher well pressures, and therefore tend to be more resilient to the negative impacts of high line pressures as compared to the comparable period of 2015 on our primary service provider’s system. Line pressures averaged 225 pounds per square inch gage ("psig") during the second quarter of 2015 and averaged 170 psig during the second quarter of 2016. Line pressures began to build during the quarter as system volumes increased and the region experienced warmer weather. Other contributing factors to the increase in line pressures were our primary service provider experiencing significant unexpected downtime during the quarter on some of its major plants, as well as performing extensive scheduled maintenance on one of its higher capacity gas plants. As a result of the increased line pressures, we experienced a curtailment of our legacy vertical well gas production of approximately 1.2 MMcf per day, or 6% of our vertical production, at the end of June, representing approximately 0.5% of our total Wattenberg Field gas production, along with associated oil production. The 170 psig average line pressure experienced during the quarter had negligible impact on our horizontal production. We expect the gathering system pressures on the primary service provider’s system to stabilize and then decrease as cooler weather arrives by the end of the third quarter of 2016.wells.

Our secondary midstream service provider, which currently gathers and processes approximately 36% of our Wattenberg Field gas, has limited its capital program in 2016, which has resulted in a curtailment of approximately 10 MMcf per day of our 2016 volumes. To help mitigate the impact of this curtailment, we have elected to contribute upfront capital of $0.6 million to our secondary midstream service provider to facilitate timely connection of certain of our well pads. We expect to be reimbursed by our secondary midstream service provider for this amount during the fourth quarter of 2016. With continued pressure on commodity prices impacting their revenue, we have seen more requests for upfront capital contributions by our third-party midstream service providers in order to ensure well connections are completed in a timely manner. We expect this trend to continue, and we will evaluate these requests on an individual basis. We rely on our third-party midstream service providers to construct compression, gathering, and processing facilities to keep pace with our and the overall field's production growth. AsWe anticipate gathering system pressures to vary throughout the year, with increases coinciding with the warmer summer months and expected field-wide production increases. We also expect that with our increased production and the development activities of other producers in the region,

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pressures will increase somewhat during 2017. Accordingly, we have reflected estimates of this impact in our forecast range for production. In order to manage this situation, 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 as evidenced by a ~~result,~~recent commitment of DCP Midstream, LP ("DCP") to build additional gathering and processing in the field. This expansion of gathering and processing facilities is expected to improve natural gas gathering pipelines and processing facilities and assist in the control of line pressures in the Wattenberg Field. In December 2016, in anticipation of our future drilling activities in the Wattenberg Field, we entered into a facilities expansion agreement with DCP to expand and improve its natural gas gathering pipelines and processing facilities. 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 estimated to be currently September 30, 2018. The agreement requires a baseline volume commitment. 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 volumes sold. Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments. Using the NYMEX forward pricing strip at March 31, 2017, the target profit margin would be achieved without an additional payment from us. See footnote titled Commitments and Contingencies for additional details regarding the agreement. The ultimate timing and availability of ~~additional facilities going forward~~adequate infrastructure is ~~beyond~~not within our ~~control. Falling commodity prices have resulted~~control and if our midstream provider's construction projects are delayed, we could experience higher line pressures that may negatively impact our ability to fulfill our growth plans. Total system infrastructure needs may also be affected by a number of factors, including potential increases in ~~reduced investment in midstream facilities by some third parties, increasing~~production from the ~~risk that sufficient midstream infrastructure will not be available in future periods.~~Wattenberg Field and warmer than expected weather.

Crude Oil, Natural Gas, and NGLs Pricing

. Our results of operations depend upon many factors, particularly 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 significantly during the first ~~half~~quarter of ~~2016~~2017 compared to the first ~~half~~quarter of ~~2015,~~2016. NYMEX crude oil and natural gas prices increased ~~substantially during the second quarter of 2016~~55 percent and 59 percent, respectively, as compared to the first quarter of 2016 as the number of U.S. crude oil rigs and inventories declined. Natural gas prices decreased during the first half of 2016 when compared to the same prior year period. Although we did experience improved pricing by the end of the second quarter of 2016, due to an oversupply of nearly all domestic NGLs products, our average realized sales price for NGLs during the first half of 2016 reflected the same low levels seen during the last quarter of 2015. With the initiation of ethane exports and increased demand for NGLs, we are starting to see NGL prices trend upward.2016.

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, particularly in the Wattenberg Field, with a view toward further improving pricing and limiting our use of trucking of production. We began delivering crude oil 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 a portion of our crude oil to the Cushing, Oklahoma market. In addition, we have signed a long-term agreement for gathering of crude oil at the wellhead by pipeline from several of our pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability 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 the first half of 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.

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

The following tables present weighted-average sales price of ~~pipeline capacity and supply and demand relationships in that region or locality. The price we receive for our~~crude oil, natural gas, ~~produced~~and NGLs for the periods presented. Our acquisitions of assets in the ~~Wattenberg Field~~Delaware Basin closed in December 2016; therefore, there is ~~based on CIG and local utility prices, adjusted~~no comparative data 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 2016.~~quarter ended March 31, 2016:

~~Our price for NGLs produced in the Wattenberg Field~~



	Three Months Ended March 31,
Weighted-Average Realized Sales Price by Operating Region					Percentage Change
(excluding net settlements on derivatives)	2017		2016		Percentage Change
Crude oil (per Bbl)
Wattenberg Field	$	49.12	$	28.37	73.1	%
Delaware Basin	49.28		—		*
Utica Shale	46.55		26.69		74.4	%
Weighted-average price	49.04		28.29		73.3	%
Natural gas (per Mcf)
Wattenberg Field	$	2.38	$	1.39	71.2	%
Delaware Basin	1.98		—		*
Utica Shale	2.98		1.43		108.4	%
Weighted-average price	2.37		1.39		70.5	%
NGLs (per Bbl)
Wattenberg Field	$	18.64	$	7.18	159.6	%
Delaware Basin	22.58		—		*
Utica Shale	27.75		11.24		146.9	%
Weighted-average price	19.29		7.37		161.7	%
Crude oil equivalent (per Boe)
Wattenberg Field	$	28.19	$	16.49	71.0	%
Delaware Basin	30.93		—		*
Utica Shale	30.55		16.60		84.0	%
Weighted-average price	28.53		16.49		73.0	%

* Percentage change 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~~not meaningful.

Amounts may not recalculate due to various markets. While NGL prices had been declining, we have seen a stabilization of prices in the second quarter of 2016. We expect NGL prices to remain stable amid indications that prices could increase later 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 commodities 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 a specified deduction. 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 ~~below~~lower than the indices for which the production is ~~based.~~based because the operating costs and profit of the midstream facilities are embedded in the net price we earn. We use the ~~"gross"~~gross method of accounting for Wattenberg Field crude oil delivered through the White Cliffs and Saddle Butte pipelines, 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 the midstream provider 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 six months ended June 30, 2016, our Wattenberg Field crude oil average sales price increased approximately $1.65 per barrel 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~~

~~The $1.0 million increase~~As discussed above, we enter into agreements for the sale and transportation, gathering and processing of our production, the terms of which can result in ~~lease operating expenses during~~variances in the three months ended June 30, 2016 compared to the three months ended June 30, 2015 was primarily due to an increase of $0.4 million in contract labor, $0.3 million in leased generators and $0.9 million in other lease operating expenses, offset in part by a decrease of $0.5 million in regulatory compliance projects. Lease operating expenses during the six months ended June 30, 2016 were comparable to the six months ended June 30, 2015. Lease operating expenses per Boe decreased 29% and 34% to $2.63 and $2.97 during the three and six months ended June 30, 2016, respectively, compared to $3.71 and $4.52 during the three and six months ended June 30, 2015, respectively. The significant decreases in lease operating expense per Boe were the result of production growth of 54% and 56%, respectively.

~~Production Taxes~~

~~Production taxes are directly related to~~unit realized prices that we receive for our crude oil, natural gas and NGLs sales. The $2.2 million and $2.4 million increases in production taxes during the three and six months ended June 30, 2016, respectively, compared to the three and six months ended June 30, 2015 were primarilyNGLs. Information related to the ~~14%~~components and ~~9% increases~~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~~average NYMEX pricing is based upon first-of-the-month index prices as this is how the majority of each of these commodities are sold pursuant to terms of the respective sales agreements. For NGLs, ~~sales, respectively, and 2015 production taxes reflecting downward adjustments related to ad valorem rates~~we use the NYMEX crude oil price as a reference for ~~production in 2014 and 2015.~~

~~Transportation, Gathering and Processing Expenses~~

presentation purposes. The ~~$3.2 million and $5.9 million increases in~~average realized price before transportation, gathering, and processing expenses ~~during~~shown in the three and six months ended June 30, 2016, respectively, compared to the three and six months ended June 30, 2015 were mainly attributable to oil transportation cost 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 barrel price for NGLs.

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For the three months ended March 31, 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)	$	51.92	94	%	$	49.04	$	1.58	$	47.46
Natural gas (per MMBtu)	3.32		71	%	2.37		0.06		2.31
NGLs (per Bbl)	51.92		37	%	19.29		0.22		19.07
Crude oil equivalent (per Boe)	39.42		72	%	28.53		0.89		27.64

For the three months ended March 31, 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)	$	33.45	85	%	$	28.29	$	1.55	$	26.74
Natural gas (per MMBtu)	2.09		67	%	1.39		0.07		1.32
NGLs (per Bbl)	33.45		22	%	7.37		0.31		7.06
Crude oil equivalent (per Boe)	25.31		65	%	16.49		0.88		15.61

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 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 ~~June 30, 2016.~~March 31, 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 of 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.~~other expenses.

Net settlements of commodity derivative instruments are ~~primarily~~based on the ~~result of~~difference between the crude oil, ~~and~~ natural gas, and 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-~~

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~~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 certain differentials. ~~See Note 4,~~ ~~Derivative Financial Instruments, to our consolidated financial statements included elsewhere in this report for a detailed description~~

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PDC ENERGY, INC.

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 June 30, Six Months Ended June 30,
2016 2015 2016 2015
(in millions)
Commodity price risk management gain (loss), net:
Net settlements:
Crude oil $ 38.7
$ 37.0
$ 92.0
$ 81.7
Natural gas 14.6
7.1
28.1
12.7
Total net settlements 53.3
44.1
120.1
94.4
Change in fair value of unsettled derivatives:
Reclassification of settlements included in prior period changes in fair value of derivatives (60.8 ) (54.3 ) (115.5 ) (89.4 )
Crude oil fixed price swaps (38.2 ) (24.5 ) (43.9 ) (1.5 )
Crude oil collars (19.6 ) (8.8 ) (18.9 ) (0.5 )
Natural gas fixed price swaps (23.1 ) (2.2 ) (19.4 ) 12.1
Natural gas basis swaps —
(2.5 ) (0.4 ) (2.0 )
Natural gas collars (4.4 ) (0.8 ) (3.7 ) 4.5
Net change in fair value of unsettled derivatives (146.1 ) (93.1 ) (201.8 ) (76.8 )
Total commodity price risk management gain (loss), net $ (92.8 ) $ (49.0 ) $ (81.7 ) $ 17.6



	Three Months Ended March 31,
	2017			2016
	(in millions)
Commodity price risk management gain, net:
Net settlements of commodity derivative instruments:
Crude oil fixed price swaps and collars	$	(3.2	)	$	53.3
Natural gas fixed price swaps and collars	3.6			13.5
Natural gas basis protection swaps	0.1			—
Total net settlements of commodity derivative instruments	0.5			66.8
Change in fair value of unsettled commodity derivative instruments:
Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments	9.1			(58.9		)
Crude oil fixed price swaps and collars	56.2			(4.2		)
Natural gas fixed price swaps and collars	11.2			7.8
Natural gas basis swaps	3.3			(0.4		)
Propane fixed price swaps	0.4			—
Net change in fair value of unsettled commodity derivative instruments	80.2			(55.7		)
Total commodity price risk management gain, net	$	80.7		$	11.1

Net settlements of commodity derivatives decreased significantly for the three months ended March 31, 2017 as compared to the three months ended March 31, 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 agreements had settled by the end of 2016. Net settlements for the three months ended March 31, 2017 reflect derivative instruments entered into since mid-2014 which approximate recent realized prices. Based upon the forward strip pricing at March 31, 2017, we expect that settlements will be substantially lower on a relative basis as compared to periods in 2016.

Lease Operating Expenses

Lease operating expenses decreased 11 percent to $2.98 per Boe during the three months ended March 31, 2017, compared to $3.35 per Boe during the three months ended March 31, 2016.The decrease in lease operating expense per Boe was predominately driven by the production growth of 46 percent, which was partially offset by a higher lease operating expense of $6.48 per Boe in the Delaware Basin. Aggregate lease operating expenses during the three months ended March 31, 2017 increased $4.5 million as compared to the three months ended March 31, 2016, primarily due to increases of $3.7 million related to operations in the Delaware Basin, $1.2 million for payroll and employee benefits due to a 13 percent average increase in headcount for the three months ended March 31, 2017, as compared to the three months ended March 31, 2016, and $0.7 million for workover projects. We expect continued increases in our headcount through the remainder of 2017 as we build out our Delaware Basin production team. We expect much of this increased cost of personnel will be offset by increases in our production. These increases were partially offset by a decrease of $1.2 million related to environmental project costs.

Production Taxes

Production taxes are directly related to crude oil, natural gas, and NGLs sales and are generally assessed as a percentage of net revenues. Production taxes are comprised mainly of severance tax and ad valorem tax. There are a number of adjustments to the statutory rates for these taxes based on certain credits that are determined based on activity levels and relative commodity prices from year-to-year. The $8.3 million increase in production taxes during the three months ended March 31, 2017, compared to the three months ended March 31, 2016 was primarily related to the 152 percent increase in crude oil, natural gas, and NGLs sales and an increase in our effective tax rate to approximately seven percent for the three months ended March 31, 2017 as compared to six percent for the three months ended March 31, 2016. These increases were partially offset by year-end return adjustments.Production taxes per Boe increased to $1.87 for the three months ended March 31, 2017 compared to $0.89 for the three months ended March 31, 2016.

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Transportation, Gathering, and Processing Expenses

The $1.9 million increase in transportation, gathering, and processing expenses during the three months ended March 31, 2017, compared to the three months ended March 31, 2016, was mainly attributable to a $1.0 million increase in oil transportation costs due to increased volumes delivered through the Saddle Butte pipeline in the Wattenberg Field and a $0.7 million increase related to compressor rentals for our Delaware Basin properties. The use of pipelines allows us to deliver crude oil to the Cushing, Oklahoma market, where we benefit from the liquidity associated with the purchasers’ delivery point. Additional benefits of utilization of pipelines are decreased field truck traffic and decreased air emissions. Transportation, gathering, and processing expenses per Boe increased to $0.89 for the three months ended March 31, 2017 compared to $0.88 for the three months ended March 31, 2016.

Impairment of Properties and Equipment

Impairment of proved and unproved properties. Amounts represent the retirement of certain leases that were 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.

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

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

Impairment of proved and unproved properties $ 1.1
$ 1.6
$ 2.1
$ 1.9
Amortization of individually insignificant unproved properties 0.1
2.8
0.1
5.3
Impairment of crude oil and natural gas properties
1.2
4.4
2.2
7.2
Land and buildings 3.0
—
3.0
—
Impairment of properties and equipment $ 4.2
$ 4.4
$ 5.2
$ 7.2

~~Impairment of proved and unproved properties~~. Amounts represent the write-down of certain capitalized well costs on our properties as the expected development date for these locations are beyond the limits of the SEC five-year rule. Further 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 six months ended June 30, 2016 compared to the three and six months ended June 30, 2015, were due to an impairment in the third quarter of 2015 that significantly reduced the carrying value of our Utica Shale leases.

~~Land and buildings.~~ The impairment charge 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.

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	Three Months Ended March 31,
	2017		2016
	(in millions)

Impairment of proved and unproved properties	$	2.1	$	0.9
Amortization of individually insignificant unproved properties	0.1		0.1
Total impairment of properties and equipment	$	2.2	$	1.0

General and Administrative Expense

General and administrative expense increased ~~$2.9~~$3.5 million to ~~$23.6~~$26.3 million for the three months ended ~~June 30, 2016~~March 31, 2017 compared to ~~$20.7~~$22.8 million for the three months ended ~~June 30, 2015.~~March 31, 2016. The increase was primarily attributable to a ~~$2.7~~$2.3 million increase in payroll and employee benefits ~~of which $1.3 million was stock-based compensation.~~

~~General and administrative expense increased $4.6 million~~due to ~~$46.4 million~~a 13 percent average increase in headcount for the ~~six~~three months ended ~~June 30, 2016~~March 31, 2017 as compared to ~~$41.8 million for~~ the ~~six~~three months ended ~~June 30, 2015. The increase was primarily attributable to a $3.3~~March 31, 2016, and $0.5 million ~~increase in payroll and employee benefits,~~ of ~~which $1.6 million was stock-based compensation, a $0.7 million increase in costs for consulting and other~~ professional services ~~and a $0.4 million increase~~fees related to the Delaware Basin acquisitions. We expect continued increases in ~~marketing and government relations activities.~~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 ~~$106.1 million and $202.4~~$107.8 million for the three ~~and six~~ months ended ~~June 30, 2016~~March 31, 2017 compared to ~~$69.0 million and $123.7~~$96.3 million for the three ~~and six~~ months ended ~~June 30, 2015.~~March 31, 2016. The period-over-period change in DD&A expense related to crude oil and natural gas properties was primarily due to the ~~following:~~following (in millions):


	June 30, 2016
	Three Months Ended			Six Months Ended
	(in millions)
Increase in production	$	39.0		$	72.8		$	38.4
Increase (decrease) in weighted-average depreciation, depletion and amortization rates	(1.9		)	5.9
Decrease in weighted-average depreciation, depletion and amortization rates							(26.9		)
Total increase in DD&A expense related to crude oil and natural gas properties	$	37.1		$	78.7	��	$	11.5

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

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Three Months Ended June 30, Six Months Ended June 30,
Operating Region/Area 2016 2015 2016 2015
(per Boe)
Wattenberg Field $ 20.73
$ 21.09
$ 21.19
$ 20.50
Utica Shale 13.84
14.23
11.16
12.27
Total weighted-average 20.41
20.48
20.72
19.76

~~The weighted-average DD&A expense rates for the three and six months ended June 30, 2016 were comparable to the three and six months ended June 30, 2015.~~



	Three Months Ended March 31,
Operating Region/Area	2017		2016
	(per Boe)
Wattenberg Field	$	16.94	$	21.72
Delaware Basin	11.46		—
Utica Shale	11.24		8.19
Total weighted-average	16.22		21.08

Non-crude oil and natural gas properties.Depreciation expense for non-crude oil and natural gas properties was ~~$0.9 million and $2.0~~$1.5 million for the three ~~and six~~ months ended ~~June 30, 2016, respectively,~~March 31, 2017 compared to $1.1 million ~~and $2.2 million~~ for the three ~~and six~~ months ended ~~June 30, 2015, respectively.~~March 31, 2016.

Provision for Uncollectible Notes Receivable

AIn the first quarter of 2016, we recorded a provision for uncollectible notes receivable of $44.7 million ~~was recorded during the six months ended June 30, 2016~~ to impair two third-party notes receivable whose collection iswas not reasonably assured. ~~See Note 3,~~As described in the 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 $40.3 million of the provision for notes receivable in ~~this report for additional information.~~the second quarter of 2017.

Interest Expense

Interest expense ~~decreased $0.9~~increased $7.6 million ~~and $0.7~~to $19.5 million ~~during~~for the three ~~and six~~ months ended ~~June 30, 2016~~March 31, 2017 compared to $11.9 million for the three ~~and six~~ months ended ~~June 30, 2015.~~ March 31, 2016. The ~~decreases were~~increase is primarily attributable to ~~decreases~~a $6.3 million increase in interest onrelating to the issuance of our 2024 Senior Notes, a $2.6 million increase in interest expense relating to the issuance of our 2021 Convertible Notes, ~~as they matured~~and a $0.7 million increase related to fees for the redetermination of the borrowing base under our revolving credit facility. The increases were offset by a $2.2 million decrease in interest expense from our 2016 Convertible Notes, which were settled in May 2016.

~~Interest Income~~

Interest income decreased $1.0 million and $0.5 million during the three and six months ended June 30, 2016 compared to the three and six months ended June 30, 2015, as we ceased recognizing non-cash interest income on two third-party notes receivable.

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Provision for Income Taxes

~~See Note 6,~~ ~~Income Taxes, to the accompanying condensed consolidated financial statements included elsewhere in this report for a discussion of the changes in our~~The effective tax rate for the three ~~and six~~ months ended ~~June 30, 2016~~March 31, 2017 was 36.3 percent expense on income compared to ~~the three and six months ended June 30, 2015. The effective tax rate of 37.9% and 37.5%~~36.9 percent benefit on loss for the three ~~and six~~ months ended ~~June 30, 2016, respectively,~~March 31, 2016. The effective tax rate for the three months ended March 31, 2017 is based onupon a full year forecasted pre-tax ~~loss~~income for the year adjusted for permanent differences. The forecasted full year effective tax rate has been applied to the quarter-to-date pre-tax ~~loss~~income, resulting in a tax ~~benefit~~expense for the period. Because the estimate of full-year income or loss may change from quarter to quarter, the effective 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 tax rate that is determined at the end of the year. The additional tax benefit for stock-based compensation was the only discrete tax item reported for the three months ended March 31, 2017, and resulted in a 2.2 percent reduction to our effective tax rate. There were no significant discrete tax items recorded during the three months ended March 31, 2016.

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

The factors resulting in changes in net income ~~tax liability at June 30, 2016 decreased $102.3 million compared to December 31, 2015. This decrease is primarily attributable to~~in the ~~significant positive net settlements from derivatives during the six~~three months ended ~~June 30,~~March 31, 2017 of $46.1 million, and a net loss in the three months March 31, 2016 ~~and~~of $71.5 million are discussed above. These same reasons similarly impacted adjusted net loss, a non-U.S. GAAP financial measure, with the ~~significant negative~~exception of the net change in fair value of unsettled derivatives, ~~held at June 30, 2016.~~

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

~~Net loss~~adjusted for ~~the three and six months ended June 30, 2016 was $95.5~~taxes, of $50.2 million and ~~$167.0 million compared to net loss of $46.9 million and $29.8~~$34.5 million for the three ~~and six~~ months ended ~~June 30, 2015.~~March 31, 2017 and March 31, 2016, respectively. Adjusted net ~~loss,~~income (loss), a non-U.S. GAAP financial measure, was ~~$5.1~~adjusted net loss of $4.1 million and ~~$41.9~~$37.0 million for the three ~~and six~~ months ended ~~June 30,~~March 31, 2017 and 2016, compared to adjusted net income of $10.8 million and $17.9 million for the same prior year periods. The quarter-over-quarter changes in net loss are discussed above, with the most significant changes related to the decrease in commodity price risk management activity income and the increase in crude oil, natural gas and NGLs sales and DD&A expense. The year-over-year changes in net loss are discussed above, with the most significant changes related to the decrease in commodity price risk management activity income and the increase in crude oil, natural gas and NGLs sales, DD&A expense and provision for uncollectible notes receivable. These changes similarly impacted adjusted net income (loss), with the exception of the tax effected net change in fair value of unsettled derivatives.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 reconciliation of this measure to the most comparable U.S. GAAP measure.

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Financial Condition, Liquidity and Capital Resources

Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in debt and equity capital market transactions, and asset sales. For the ~~six~~three months ended ~~June 30, 2016,~~March 31, 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 and net~~ cash flows from operating activities of ~~$197.8~~$139.5 million. We used a portion of the net proceeds of the offering to repay all amounts then outstanding on our revolving credit facility, the principal amounts owed upon the maturity of the Convertible Notes in May 2016, and retained the remainder 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 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. ~~For instruments that mature in three years or less, our debt covenants restrict us from entering into hedges that would exceed 85%~~The revolving credit agreement imposes limits on the amount of our ~~expected future~~ production ~~from total proved reserves for such related time period (proved developed producing, proved developed non-producing~~we can hedge, and proved undeveloped). For instruments that mature later than three years, but no more than our designated maximum maturity, our debt covenants limit us from entering into hedges that would exceed 85% of our expected future production from proved developed producing properties during that time period. Wewe may choose not to hedge the maximum amounts ~~permitted under our covenants.~~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~~Based upon our hedge position ~~we expect that positive net settlements on~~and assuming forward strip pricing as of March 31, 2017, our ~~derivative positions will continue to~~derivatives may not be a significant ~~positive component~~source of ~~our 2016~~cash flow in the near term, and may result in cash outflows in 2017 and 2018. During the three months ended March 31, 2017, we had $0.5 million of positive cash flows from ~~operations.~~operations related to net settlements of commodity derivative instruments, compared to $66.8 million for the three months ended March 31, 2016. As of ~~June 30, 2016,~~March 31, 2017, the fair value of our derivatives was a net asset of ~~$61.9 million. Based on~~$10.1 million, of which $4.1 million will settle in the ~~forward pricing strip at June 30, 2016, we would expect positive net settlements totaling approximately $75.9 million during the second half~~remaining nine months of ~~2016. However,~~2017 based upon ~~our current hedge position and assuming current~~forward strip pricing ~~during periods subsequent to 2016 our derivatives may no longer be a significant source~~as of ~~cash flow, and may result in cash outflows. For~~that date at the ~~six months ended June 30, 2016 and 2015, net settled derivatives comprised approximately 61% and 65%, 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.~~current price.

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, 2016,~~March 31, 2017, we had working capital of ~~$131.9~~$93.8 million compared to ~~$30.7~~$129.2 million at December 31, ~~2015.~~2016. The ~~increase~~decrease in working capital as of ~~June 30, 2016~~March 31, 2017 is primarily the result of an increase in accounts payable of $78.1 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 $45.4 million.

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

~~In recent periods, including the first half of 2016, we have been able to access borrowings under~~were $207.6 million at March 31, 2017, our ~~revolving credit facility and to obtain proceeds from the issuance of securities. We ended June 2016 with cash and cash equivalents of $109.1~~short-term investments were $49.9 million, and availability under our revolving credit facility ~~of $438.3~~was $688.3 million, providing for a total liquidity position of ~~$547.4~~$945.8 million as of March 31, 2017, compared to ~~$402.2~~$932.4 million at December 31, ~~2015. These amounts exclude an additional $250 million available under our revolving credit facility, subject to certain terms and conditions of the credit agreement.~~2016. The increase in liquidity of ~~$145.2~~$13.4 million, or ~~36.1%, during the six months ended June 30, 2016~~one percent, was primarily attributable to net cash flows from operating activities of ~~$197.8~~$139.5 million, partially offset by capital investments associated with development and ~~net cash flows from financing activities~~exploration activity of ~~$141.3~~$129.8 million ~~primarily due to~~during the three months ended March 31, 2017.

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~~March 2016 public offering of~~Based on our common stock, offset in part by cash paid for capital expenditures of $235.7 million. Our liquidity position was reduced by the cash payment of approximately $115 million upon the maturity of our Convertible Notes in May 2016. With our current derivative position, liquidity position and expected cash flows from operations, our cash and cash equivalent and short-term investments balances and availability under our revolving credit facility, we believe that we have sufficient capital to fund our planned ~~drilling operations for~~activities during 2017. Our liquidity will be further augmented by the ~~next 12 months. We cannot, however, assure sources~~$40.3 million of ~~capital available to us~~proceeds received in the ~~past will be available to us in~~second quarter of 2017 from the ~~future.~~

~~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,~~a third-party Note, 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 and 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.described previously.

Our revolving credit facility is a borrowing base facility and availability under the facility is subject to a redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. In May 2016, we completed the semi-annual redetermination of our revolving credit facility by the lenders, which resulted in the reaffirmation of our borrowing base at $700 million. However, we elected to maintain the aggregate commitment level at $450 million. The maturity date of ~~the~~our revolving credit facility is May 2020. As of March 31, 2017, the borrowing base is $700 million. Our ability to borrow under the revolving credit facility is limited under our 2022 Senior Notes to the greater of $700 million or the calculated value under an Adjusted Consolidated Tangible Net Asset test, as defined. The May 2017 redetermination of our borrowing base has not been finalized as of the date of this report.

Our borrowings 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 March 31, 2017, the applicable margin is 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 ~~June 30, 2016. While~~March 31, 2017. As of March 31, 2017, we ~~have added and expect~~had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to ~~continue to add producing reserves through~~secure a firm transportation obligation. As of March 31, 2017, the available funds under our ~~drilling operations,~~revolving credit facility, including the ~~effect~~reduction for the $11.7 million letter of any such reserve additions 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.credit, was $688.3 million.

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,

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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. At ~~June 30, 2016,~~March 31, 2017, we were in compliance with all debt covenants with a ~~1.0~~ leverage ratio, as defined by the revolving credit agreement, of 2.0times ~~debt to EBITDAX ratio~~ and a ~~4.0 to~~ 3.7:1.0current ratio. We expect to remain in compliance throughout the next ~~year.~~12-month period.

The ~~indenture~~indentures governing our ~~7.75% senior notes due~~ 2022 ~~contains~~Senior Notes and 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 ~~June 30, 2016,~~March 31, 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 subsidiary guarantor of ~~credit risk.~~the notes.

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 ~~$51.3~~$38.4 million for the ~~six~~three months ended ~~June 30, 2016~~March 31, 2017 compared to the ~~six~~three months ended ~~June 30, 2015,~~March 31, 2016, primarily due to increases in ~~net settlements from our derivative positions of $25.7 million and~~ crude oil, natural gas and NGLs sales of ~~$15.2~~$114.3 million and ~~the~~an increase in changes in assets and liabilities of ~~$18.6~~$15.6 million related to the timing of cash payments and receipts. These increases were offset in part by ~~the increase~~a decrease in ~~transportation, gathering~~commodity derivative settlements of $66.3 million and ~~processing~~increases in lease operating expenses of ~~$5.9~~$4.5 million, production taxes of $8.3 million, general and administrative expenses of $3.5 million, and interest expense of $7.6 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 ~~$32.8~~$22.7 million during the ~~six~~three months ended ~~June 30, 2016,~~March 31, 2017 compared to the ~~six~~three months ended ~~June 30, 2015.~~March 31, 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 ~~$16.3~~$72.4 million during the ~~six~~three months ended ~~June 30, 2016~~March 31, 2017, compared to the ~~six~~three months ended ~~June 30, 2015.~~March 31, 2016. The ~~decrease~~increase was primarily the result of increases in crude oil, natural gas and NGLs sales of $114.3 million and the recording of a provision for uncollectible notes receivable of $44.7 million during the three months ended March 31, 2016. These increases were partially offset by a decrease in commodity derivative settlements of $66.3 million and ~~the increase~~increases in ~~transportation, gathering and processing~~lease operating expenses of ~~$5.9~~$4.5 million, production taxes of $8.3 million, and general and administrative ~~expense~~expenses of ~~$4.6 million, offset in part by increases in net settlements from our derivative positions of $25.7 million and crude oil, natural gas and NGLs sales of $15.2~~$3.5 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.

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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 ~~$230.8~~$173.6 million during the ~~six~~three months ended ~~June 30, 2016~~March 31, 2017, was primarily related to cash utilized for our drilling operations, including completion ~~activities. For~~activities of $129.8 million and purchases of short-term investments of $49.9 million. Partially offsetting these investments was the ~~full year 2016, we expect that our cash flows from operations will approximate our cash flows from investing activities.~~receipt of approximately $6.2 million related to post-closing settlements of properties acquired in 2016.

Financing Activities. Net cash from financing activities for the ~~six~~three months ended ~~June 30, 2016~~March 31, 2017 decreased by approximately ~~$55.5~~$261.6 million compared to the ~~six~~three months ended ~~June 30, 2015. Net cash from~~March 31, 2016. Certain capital markets and financing activities ~~of $141.3 million for the six months ended June 30,~~occurred in 2016 ~~was primarily related to~~including the $296.6 million received from the issuance of our common ~~stock in March 2016,~~stock. These amounts were partially offset by ~~the $115.0 million payment of principal amounts owed upon the maturity of the Convertible Notes and~~ net payments of approximately $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 June 30, Six Months Ended June 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 27.7 47.2 0.4 35.4 45.9 1.0 52.6
47.2
0.4 48.5
45.9
1.0
Wattenberg Field, non-operated wells 1.7 7.7 — 1.6 4.9 — 3.2
7.7
— 4.2
4.9
—
Utica Shale 2.8 1.7 — 3.0 — — 2.8
1.7
— 3.0
—
—
Total drilling activity 32.2 56.6 0.4 40.0 50.8 1.0 58.6
56.6
0.4
55.7
50.8
1.0

~~______________~~

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

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Off-Balance Sheet Arrangements

At ~~June 30, 2016~~,March 31, 2017, we had no off-balance sheet arrangements, as defined under SEC rules, that 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.

Commitments and Contingencies

See ~~Note 10,~~the footnote titled Commitments and Contingencies to the accompanying condensed consolidated financial statements included elsewhere in this report.

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.

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 adjusted EBITDAX calculation. In prior periods, we included adjusted EBITDA, a non-U.S. GAAP financial measure, that did not include these adjustments. All prior periods have been

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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

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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 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 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 June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2016			2015			2016			2015			2017			2016
	(in millions)												(in millions)
Adjusted cash flows from operations:
Net cash from operating activities													$	139.5		$	101.2
Changes in assets and liabilities													(25.8		)	(10.2		)
Adjusted cash flows from operations	$	112.6		$	96.9		$	203.6		$	170.8		$	113.7		$	91.0
Changes in assets and liabilities	(16.0		)	(32.3		)	(5.8		)	(24.3		)
Net cash from operating activities	$	96.6		$	64.6		$	197.8		$	146.5

Adjusted net income (loss):
Adjusted net income (loss)	$	(5.1	)	$	10.8		$	(41.9	)	$	17.9
Gain (loss) on commodity derivative instruments	(92.7		)	(49.0		)	(81.7		)	17.6
Net income (loss)													$	46.1		$	(71.5	)
Gain on commodity derivative instruments													(80.7		)	(11.1		)
Net settlements on commodity derivative instruments	(53.3		)	(44.1		)	(120.2		)	(94.5		)	0.5			66.8
Tax effect of above adjustments	55.6			35.4			76.8			29.2			30.0			(21.2		)
Net loss	$	(95.5	)	$	(46.9	)	$	(167.0	)	$	(29.8	)
Adjusted net income (loss)													$	(4.1	)	$	(37.0	)

Adjusted EBITDA to net loss:
Adjusted EBITDA	$	115.7		$	102.6		$	168.7		$	185.0
Gain (loss) on commodity derivative instruments	(92.7		)	(49.0		)	(81.7		)	17.6
Net income (loss) to adjusted EBITDAX:
Net income (loss)													$	46.1		$	(71.5	)
Gain on commodity derivative instruments													(80.7		)	(11.1		)
Net settlements on commodity derivative instruments	(53.3		)	(44.1		)	(120.2		)	(94.5		)	0.5			66.8
Non-cash stock-based compensation													4.5			4.7
Interest expense, net	(10.5		)	(10.4		)	(20.8		)	(21.1		)	19.2			10.3
Income tax provision	58.3			30.1			100.2			19.4
Income tax expense (benefit)													26.3			(41.8		)
Impairment of properties and equipment	(4.2		)	(4.4		)	(5.2		)	(7.2		)	2.2			1.0
Depreciation, depletion and amortization	(107.0		)	(70.1		)	(204.4		)	(125.9		)
Exploration, geologic, and geophysical expense													1.0			0.2
Depreciation, depletion, and amortization													109.3			97.4
Accretion of asset retirement obligations	(1.8		)	(1.6		)	(3.6		)	(3.1		)	1.8			1.8
Net loss	$	(95.5	)	$	(46.9	)	$	(167.0	)	$	(29.8	)
Adjusted EBITDAX													$	130.2		$	57.8

Adjusted EBITDA to net cash from operating activities:
Adjusted EBITDA	$	115.7		$	102.6		$	168.7		$	185.0
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities													$	139.5		$	101.2
Interest expense, net	(10.5		)	(10.4		)	(20.8		)	(21.1		)	19.2			10.3
Stock-based compensation	6.4			5.1			11.1			9.5
Amortization of debt discount and issuance costs	1.3			1.8			3.1			3.5			(3.2		)	(1.8		)
(Gain) loss on sale of properties and equipment	0.3			(0.2		)	0.2			(0.2		)
Gain on sale of properties and equipment													0.2			0.1
Exploration, geologic, and geophysical expense													1.0			0.2
Other	(0.6		)	(2.0		)	41.3			(5.9		)	(0.7		)	(42.0		)
Changes in assets and liabilities	(16.0		)	(32.3		)	(5.8		)	(24.3		)	(25.8		)	(10.2		)
Net cash from operating activities	$	96.6		$	64.6		$	197.8		$	146.5
Adjusted EBITDAX													$	130.2		$	57.8

~~Regulatory Update~~

In May 2016, the EPA issued a draft Information Collection Request that will impact all known operators in the U.S. and which is aimed at regulating existing onshore oil and gas sources. The EPA also finalized a rule regarding source determination and permitting requirements for the onshore oil and gas industry under the Clean Air Act. Under this final rule, our operations could be subject to increased permitting costs and more stringent control requirements. In June 2016, the EPA published amendments to the 2012 NSPS OOOO rules focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The EPA also finalized pretreatment standards for the discharge of wastewater to publicly-owned treatment works for the onshore oil and gas extraction industry. Other agencies have also published new proposed or final rules impacting the onshore oil and gas industry. For example, the U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration issued an additional notice of proposed rulemaking in June 2016 related to the safety of transmission and gathering lines. In addition, in March 2016, the U.S. Fish and Wildlife Service finalized a rule to alter how it identifies critical habitat for endangered and threatened species, which could expand the reach of the Endangered Species Act depending on how it is implemented.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market-Sensitive Instruments and Risk Management

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

Interest Rate Risk

Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents, and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our ~~7.75% senior notes due~~2021 Convertible Notes, 2024 Senior Notes, 2022 Senior Notes, and short-term investments have a fixed ~~rate~~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 ~~June 30, 2016~~,March 31, 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 ~~June 30, 2016~~March 31, 2017 was ~~$90.2~~$169.1 million with a weighted-average interest rate of ~~0.3%.~~0.5 percent. Based on a sensitivity analysis of our interest-bearing deposits as of ~~June 30, 2016~~,March 31, 2017 and assuming we had $169.1 million outstanding throughout the period, we estimate that a 1%1 percent increase in interest rates would ~~increase~~have increased interest income for the ~~six~~three months ended ~~June 30, 2016~~March 31, 2017 by approximately ~~$0.5~~$1.7 million.

As of ~~June 30, 2016~~,March 31, 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~~ ~~June 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
June 30,
2016 (2)
(in millions)
Floors Ceilings
Natural Gas
NYMEX
2016 2,280.0
$ 3.80
$ 4.12
15,410.0
$ 3.66
13,806.5
$ (0.29 ) $ 10.6
2017 7,920.0
3.59
4.13
27,290.0
3.55
12,000.0
(0.28 ) 13.6
2018 1,230.0
3.00
3.67
17,430.0
3.00
—
—
(0.1 )

Total Natural Gas 11,430.0
60,130.0
25,806.5
24.1

Crude Oil
NYMEX
2016 870.0
77.59
97.55
1,860.0
72.21
—
—
65.3
2017 1,464.0
49.22
65.95
3,004.0
44.92
—
—
(17.4 )
2018 1,512.0
41.85
54.31
504.0
47.08
—
—
(10.1 )

Total Crude Oil 3,846.0
5,368.0
—
37.8
Total Natural Gas and Crude Oil $ 61.9

~~____________~~


~~(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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The following table presents our commodity and basis derivative positions related to crude oil, natural gas, and propane in effect as of March 31, 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 March 31, 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 March 31, 2017 (1) (in millions)
Crude Oil
NYMEX
2017	1,848.0	$	49.54	$	62.32	5,480.5	$	50.11		$	(5.1	)
2018	1,512.0	41.85		54.31		5,072.0	53.85			6.2
Total Crude Oil	3,360.0					10,552.5				$	1.1

Natural Gas
NYMEX
2017	8,550.3	$	3.40	$	4.05	20,555.0	$	3.50		$	6.3
2018	1,230.0	3.00		3.67		45,280.0	2.94			(3.0		)
Total Natural Gas	9,780.3					65,835.0				$	3.3

Basis Protection
2017	—	—		—		21,104.0	$	(0.29	)	2.5
2018	—	—		—		18,200.0	(0.29		)	2.8
Total Basis Protection	—					39,304.0				$	5.3

Propane
Mont Belvieu
2017	—	—		—		535.7	$	26.78		$	0.4
Commodity Derivatives Fair Value										$	10.1

____________


(1)	Approximately 18.4 percent of the fair value of our commodity derivative assets and 16.9 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).

In addition to our commodity derivative positions as of March 31, 2017, we entered into the following commodity derivative positions related to natural gas subsequent to March 31, 2017 that are effective as of April 18, 2017:

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	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
		Floors		Ceilings
Natural Gas
NYMEX
2017	—	$	—	$	—	7,000.0		$	3.42
2018	4,000.0	3.00		3.50		—	—	—
Total Natural Gas	4,000.0					7,000.0

Basis Protection
2017	—	—		—		14,000.0		$	(0.39	)
2018	—	—		—		6,000.0		(0.41		)
Total Basis Protection	—					20,000.0

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 Six Months Ended Year Ended
June 30, 2016 June 30, 2016 December 31, 2015
Average Index Closing Price:
Crude oil (per Bbl)
NYMEX $ 45.59
$ 39.52
$ 48.80
Natural gas (per MMBtu)
NYMEX $ 1.95
$ 2.02
$ 2.66
CIG 1.67
1.73
2.44
TETCO M-2 (1) 1.27
1.23
1.49

Average Sales Price Realized:
Excluding net settlements on derivatives
Crude oil (per Bbl) $ 40.37
$ 34.46
$ 40.14
Natural gas (per Mcf) 1.37
1.38
2.04
NGLs (per Bbl) 11.93
9.89
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		Year Ended
	March 31, 2017		December 31, 2016
Average NYMEX Index Price:
Crude oil (per Bbl)	$	51.92	$	43.32
Natural gas (per MMBtu)	3.32		2.46

Average Sales Price Realized:
Excluding net settlements on commodity derivatives
Crude oil (per Bbl)	$	49.04	$	39.96
Natural gas (per Mcf)	2.37		1.77
NGLs (per Bbl)	19.29		11.80

Based on a sensitivity analysis as of ~~June 30, 2016~~,March 31, 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 ~~$63.0~~$87.6 million, whereas a ~~10%~~10 percent decrease in prices would have resulted in an increase in fair value of ~~$63.0~~$87.6 million.

~~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 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.

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

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PDC ENERGY, INC.

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. There have been no collections received to date and and some of the third-party producers have shut-in their wells and we~~judgments. We expect this trend to continue for this ~~segment.~~business.

A group of independent West Virginia natural gas producers has filed, but not served on RNG, a complaint 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. 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 ~~June 30, 2016~~,March 31, 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 ~~June 30, 2016~~,March 31, 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 ~~June 30, 2016~~.March 31, 2017.

Changes in Internal Control over Financial Reporting

During the three months ended ~~June 30, 2016~~,March 31, 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

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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 March 31, 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 in January 2016. In December 2016, we received a draft consent decree from the EPA.

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 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. This matter has been combined with the matter discussed above. We have ongoing discussions with the EPA, U.S. Department of Justice, and Colorado Department of Public Health and Environment regarding these matters. The ultimate outcome related to these combined actions has not been determined 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:~~10-K.

Ballot initiatives have been proposed in Colorado that would impose draconian limitations on statewide oil and gas development activities or could result in vastly expanded authority of local governments to regulate or prohibit oil and natural gas production and development in their jurisdictions. Proponents of two such initiatives have submitted signatures in an effort to qualify the initiatives to appear on the ballot in November 2016. Either of these proposals could result in an effective ban on new development operations in areas where we have significant leasehold and existing production, and one of these proposals might affect production from existing wells. If either initiative is implemented and survives legal challenge, it would have a severe impact on our development plans and on our results of operations, financial condition and reserves. Future initiatives, legislation or regulations may be adopted with similar effects.

As previously disclosed, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state. Proponents of two such initiatives have submitted signatures in an effort to qualify the initiatives to appear on the ballot in November 2016. The signatures are subject to a verification process to be conducted by the Colorado Secretary of State. This process could take up to 30 days. We do not know what the outcome of this process will be. If approved by the voters of Colorado, the proposals will take effect by the end of 2016.

One of the initiatives, which we refer to as the “local control” initiative, would amend 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. If implemented, this amendment could result in our operations being subject to a variety of different, and possibly inconsistent, requirements in numerous different jurisdictions within the state of Colorado, and could prohibit exploration, development and production altogether in some or all of these jurisdictions. This would likely materially increase our costs and make our operations less efficient, and it could prevent us from developing and producing significant properties.

The other initiative, which we refer to as the “setback” initiative, would amend 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 “area of special concern,” broadly defined to include 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. The current minimum required setback between oil and gas wells and occupied structures is generally 500 feet. The Colorado Oil and Gas Conservation Commission has estimated that implementation of the

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proposed initiative would make drilling unlawful on approximately 90% of the surface area of the state of Colorado, and approximately 85% of the surface area of Weld County. If passed, this proposal would effectively prohibit the vast majority of our planned future drilling activities, and would therefore make it impossible to continue to pursue our current development plans. This would have a highly material and adverse effect on our results of operations, financial condition and reserves.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

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

April 1 - 30, 2016 41,911
$ 59.59
May 1 - 31, 2016 —
—
June 1 - 30, 2016 6,595
57.61
Total second quarter purchases 48,506
59.32



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

January 1 - 31, 2017	27,514	$	74.34
February 1 - 28, 2017	—	—
March 1 - 31, 2017	—	—
Total first quarter 2017 purchases	27,514	$	74.34

__________


(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.

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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: ~~August 9, 2016~~May 5, 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)

4047



Counterparty Name	Fair Value of Derivative Assets
	(in thousands)
Canadian Imperial Bank of Commerce (1)	$	33,559
JP Morgan Chase Bank, N.A (1)	29,011
Bank of Nova Scotia (1)	22,676
Wells Fargo Bank, N.A. (1)	13,351
NATIXIS (1)	10,418
Other lenders in our revolving credit facility	2,329
Various (2)	240
Total	$	111,584



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



	Three Months Ended June 30,						Six Months Ended June 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	$	40.41	$	48.09	(16.0	)%	$	34.51	$	44.41	(22.3	)%
Utica Shale	39.57		50.78		(22.1	)%	33.44		45.12		(25.9	)%
Weighted-average price	40.37		48.31		(16.4	)%	34.46		44.47		(22.5	)%
Natural gas (per Mcf)
Wattenberg Field	$	1.36	$	2.03	(33.0	)%	$	1.38	$	2.21	(37.6	)%
Utica Shale	1.58		2.06		(23.3	)%	1.51		2.22		(32.0	)%
Weighted-average price	1.37		2.03		(32.5	)%	1.38		2.21		(37.6	)%
NGLs (per Bbl)
Wattenberg Field	$	11.87	$	10.01	18.6	%	$	9.78	$	10.91	(10.4	)%
Utica Shale	13.27		9.95		33.4	%	12.29		14.17		(13.3	)%
Weighted-average price	11.93		10.01		19.2	%	9.89		11.23		(11.9	)%
Crude oil equivalent (per Boe)
Wattenberg Field	$	21.27	$	28.78	(26.1	)%	$	19.03	$	27.31	(30.3	)%
Utica Shale	22.59		28.86		(21.7	)%	19.75		27.38		(27.9	)%
Weighted-average price	21.33		28.79		(25.9	)%	19.07		27.32		(30.2	)%



	Net Drilling Activity
	Three Months Ended June 30,						Six Months Ended June 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	27.7	47.2	0.4	35.4	45.9	1.0	52.6	47.2	0.4	48.5	45.9	1.0
Wattenberg Field, non-operated wells	1.7	7.7	—	1.6	4.9	—	3.2	7.7	—	4.2	4.9	—
Utica Shale	2.8	1.7	—	3.0	—	—	2.8	1.7	—	3.0	—	—
Total drilling activity	32.2	56.6	0.4	40.0	50.8	1.0	58.6	56.6	0.4	55.7	50.8	1.0



	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 June 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 June 30, 2016 (2) (in millions)
Natural Gas
NYMEX
2016	2,280.0	$	3.80	$	4.12	15,410.0	$	3.66	13,806.5	$	(0.29	)	$	10.6
2017	7,920.0	3.59		4.13		27,290.0	3.55		12,000.0	(0.28		)	13.6
2018	1,230.0	3.00		3.67		17,430.0	3.00		—	—			(0.1		)

Total Natural Gas	11,430.0					60,130.0			25,806.5				24.1

Crude Oil
NYMEX
2016	870.0	77.59		97.55		1,860.0	72.21		—	—			65.3
2017	1,464.0	49.22		65.95		3,004.0	44.92		—	—			(17.4		)
2018	1,512.0	41.85		54.31		504.0	47.08		—	—			(10.1		)

Total Crude Oil	3,846.0					5,368.0			—				37.8
Total Natural Gas and Crude Oil													$	61.9