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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2017

or

£ 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," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x	Accelerated filer  o
Non-accelerated filer  o (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: 65,855,290 shares of the Company's Common Stock ($0.01 par value) were outstanding as of April 18, 2017.

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PDC ENERGY, INC.

TABLE OF CONTENTS

	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		23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		40
Item 4.	Controls and Procedures		43
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		44
Item 1A.	Risk Factors		44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		44
Item 3.	Defaults Upon Senior Securities		44
Item 4.	Mine Safety Disclosures		44
Item 5.	Other Information		45
Item 6.	Exhibits		46
	SIGNATURES		47

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"), and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations, and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements". Words such as expects, anticipates, intends, plans, believes, seeks, estimates, and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements may include, among other things, statements regarding future: reserves, production, costs, cash flows, and earnings; drilling locations and growth opportunities; capital investments and projects, including expected lateral lengths of wells, drill times and number of rigs employed; rates of return; operational enhancements and efficiencies; management of lease expiration issues; financial ratios; and midstream capacity and 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 and prices for the products we produce;

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

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

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

•	declines in the value of our crude oil, natural gas, and NGLs properties resulting in 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 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, 2016 (the "2016 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 28, 2017, and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations, and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.

REFERENCES

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

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PDC ENERGY, INC.

Condensed Consolidated Balance Sheets

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

			March 31, 2017				December 31, 2016
Assets
Current assets:
Cash and cash equivalents			$	207,624			$	244,100
Short-term investments	—		49,890				—
Accounts receivable, net			122,484				143,392
Fair value of derivatives			27,047				8,791
Prepaid expenses and other current assets			4,726				3,542
Total current assets			411,771				399,825
Properties and equipment, net			4,098,463				4,008,266
Fair value of derivatives			13,921				2,386
Goodwill			56,058				62,041
Other assets			12,917				13,324
Total Assets			$	4,593,130			$	4,485,842
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable			$	144,440			$	66,322
Production tax liability			25,065				24,767
Fair value of derivatives			26,495				53,595
Funds held for distribution			76,067				71,339
Accrued interest payable			18,977				15,930
Other accrued expenses			26,938				38,625
Total current liabilities			317,982				270,578
Long-term debt			1,046,461				1,043,954
Deferred income taxes			427,205				400,867
Asset retirement obligations			78,162				82,612
Fair value of derivatives			4,302				27,595
Other liabilities			47,841				37,482
Total liabilities			1,921,953				1,863,088
Commitments and contingent liabilities
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			2,492,276				2,489,557
Retained earnings			180,354				134,208
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 March 31,
		2017				2016
Revenues
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		273,707				90,831
Costs, expenses and other
Lease operating expenses		19,789				15,330
Production taxes		12,399				4,071
Transportation, gathering and processing expenses		5,902				4,041
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		2,193				1,001
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
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		(19,467		)		(11,894		)
Interest income		240				1,558
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		$	0.70			$	(1.72	)
Diluted		$	0.70			$	(1.72	)
Weighted-average common shares outstanding:
Basic		65,749				41,608
Diluted		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)

		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

See accompanying Notes to Condensed Consolidated Financial Statements

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION

PDC Energy, Inc. ("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production company that produces, develops, 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, 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 Delaware Basin operations are currently focused in the Wolfcamp zones. As of March 31, 2017, we owned an interest in approximately 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 and, therefore, all of our operations are presented as a single segment for all periods presented.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of our 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 of normal recurring adjustments, necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The December 31, 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 2016 Form 10-K. Our results of operations and cash flows for the three months ended 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 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 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 in the process of assessing potential impacts of the new standard on our existing revenue recognition criteria, as well as on related revenue recognition disclosures.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 a right-of-use asset and lease liability for its right to use the underlying asset and 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 in the process of assessing the impact these changes may have on our consolidated financial statements.

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

In January 2017, the FASB issued an accounting update clarifying the definition of 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 - BUSINESS COMBINATION

Delaware Basin Acquisition. On December 6, 2016, we closed on an acquisition which has been accounted for as a business combination. The transaction was for the purchase of approximately 57,900 net acres, approximately 30 wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the 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 seller at closing and other purchase price adjustments, and 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed. The estimated fair value of assets acquired and liabilities assumed in the acquisition presented below are preliminary and subject to customary additional post-closing adjustments as more detailed analysis associated with the acquired properties is completed. As of the date of this report, the final settlement statement has been agreed upon with the sellers. We are in the process of finalizing the fair values of the assets acquired and liabilities assumed and expect to keep the transaction open through the second quarter of 2017 to ensure that any post-closing adjustments associated with the period through final settlement are appropriately reflected in the final purchase price allocation.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, natural gas, and propane, which is an element of 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.

 

We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of March 31, 2017, we had derivative instruments, which were comprised of collars, fixed-

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

price swaps, and basis protection swaps, in place for a portion of our anticipated production through 2018 for a total of 13,912 MBbls of crude oil, 75,615 BBtu of natural gas, and 536 MBbls of propane. Our commodity derivative contracts have been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market 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 under hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the condensed consolidated statements of operations.

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

					Fair Value
Derivative instruments:			Condensed consolidated balance sheet line item		March 31, 2017				December 31, 2016
					(in thousands)
Derivative assets:	Current
	Commodity derivative contracts		Fair value of derivatives		$	24,437			$	8,490
	Basis protection derivative contracts		Fair value of derivatives		2,610				301
					27,047				8,791
	Non-current
	Commodity derivative contracts		Fair value of derivatives		11,279				1,123
	Basis protection derivative contracts		Fair value of derivatives		2,642				1,263
					13,921				2,386
Total derivative assets					$	40,968			$	11,177
Derivative liabilities:	Current
	Commodity derivative contracts		Fair value of derivatives		$	26,489			$	53,565
	Basis protection derivative contracts		Fair value of derivatives		6				30
					26,495				53,595
	Non-current
	Commodity derivative contracts		Fair value of derivatives		4,302				27,595
					4,302				27,595
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 March 31,
Condensed consolidated statement of operations line item		2017				2016
		(in thousands)
Commodity price risk management gain, net
Net settlements		$	551			$	66,831
Net change in fair value of unsettled derivatives		80,153				(55,775		)
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

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. We have elected not to offset the fair value positions recorded on our condensed consolidated balance sheets.

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

As of March 31, 2017		Derivative instruments, recorded in condensed consolidated balance sheet, gross				Effect of master netting agreements				Derivative instruments, net
		(in thousands)
Asset derivatives:
Derivative instruments, at fair value		$	40,968			$	(22,720	)		$	18,248
Liability derivatives:
Derivative instruments, at fair value		$	30,797			$	(22,720	)		$	8,077

As of December 31, 2016		Derivative instruments, recorded in condensed consolidated balance sheet, gross				Effect of master netting agreements				Derivative instruments, net
		(in thousands)
Asset derivatives:
Derivative instruments, at fair value		$	11,177			$	(10,930	)		$	247
Liability derivatives:
Derivative instruments, at fair value		$	81,190			$	(10,930	)		$	70,260

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

Determination of Fair Value

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

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

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

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

Derivative Financial Instruments

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

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

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 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:

	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

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.

    

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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 7 - INCOME TAXES

We evaluate and update our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of our actual annual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. 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 months ended March 31, 2017, was 36.3 percent expense on income compared to 36.9 percent benefit on loss for the three months ended March 31, 2016. The effective tax rate for the three months ended 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 was 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. There were no significant discrete tax items recorded during the three months ended March 31, 2016.

As of 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 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 closure of the 2015 tax year during the three months ended March 31, 2017.

NOTE 8 - LONG-TERM DEBT

Long-term debt consisted of the following as of:

	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

2021 Convertible Notes. In September 2016, we issued $200.0 million of 1.125% convertible senior notes due 2021 (the "2021 Convertible Notes") in a 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 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 method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares.

 

2022 Senior Notes. In October 2012, we issued $500.0 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”). The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15. 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 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.

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 March 31, 2017, we were in compliance with all covenants related to the Notes, and expect to remain in compliance throughout the next 12-month period.

Revolving Credit Facility

Revolving Credit Facility. The revolving credit facility is available for working capital requirements, capital 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 and certain limitations under our senior notes. The borrowing base amount available under the revolving credit facility is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. 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 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 March 31, 2017 or December 31, 2016. The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium), or at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin, and other bank fees, charged as a component of interest, vary with our utilization of the 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 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of 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 3.7 and our leverage ratio was 2.0 as 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

March 31, 2017

(unaudited)

NOTE 9 - 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 percent of the fair value of the leased vehicles at inception of the lease.

 

The following table presents vehicles under capital lease as of March 31, 2017:

 

		March 31, 2017				December 31, 2016
		(in thousands)
Vehicles		$	4,126			$	2,975
Accumulated depreciation		(973		)		(776		)
		$	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 March 31,		Amount
		(in thousands)
2018		$	1,413
2019		1,376
2020		946
		3,735
Less executory cost		(155		)
Less amount representing interest		(402		)
Present value of minimum lease payments		$	3,178
Short-term capital lease obligations		$	1,108
Long-term capital lease obligations		2,070
		$	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 11 - ASSET RETIREMENT OBLIGATIONS

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

	Amount
	(in thousands)
Balance at beginning of period, January 1, 2017	$	92,387
Obligations incurred with development activities	1,232
Accretion expense	1,768
Obligations discharged with asset retirements	(4,288		)
Balance at end of period, March 31, 2017	91,099
Less current portion	(12,937		)
Long-term portion	$	78,162

Our estimated asset retirement 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. As of March 31, 2017, the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 6.5 percent to 8.2 percent. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors, and changes to our credit-adjusted risk-free rate as market conditions warrant. Short-term asset retirement obligations are included in other accrued expenses on the condensed consolidated balance sheets.

NOTE 12 - 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 whose volumes we market on their behalf. Our statements of operations reflect our share of these firm transportation costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered.

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 March 31,
Area		2018				2019				2020				2021				2022 and Through Expiration				Total				Expiration Date
Natural gas (MMcf)
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		2,737				2,737				2,745				2,737				6,391				17,347				July 22, 2023
Total		23,254				30,299				43,370				39,652				100,853				237,428
Crude oil (MBbls)
Wattenberg Field		2,413				2,413				2,420				602				—				7,848				June 30, 2020
Dollar commitment (in thousands)		$	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)

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

Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any 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 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 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 time.

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(unaudited)

NOTE 13 - COMMON STOCK

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 March 31,
		2017				2016
		(in thousands)
Stock-based compensation expense		$	4,453			$	4,682
Income tax benefit		(1,666		)		(1,782		)
Net stock-based compensation expense		$	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.

The Compensation Committee of our Board of Directors awarded SARs to our executive 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:

	Three Months Ended March 31,
	2017				2016
Expected term of award (in years)	6				6
Risk-free interest rate	2.0		%		1.8		%
Expected volatility	53.3		%		54.5		%
Weighted-average grant date fair value per share	$	38.58			$	26.96

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

    

The following table presents the changes in our SARs for the three months ended March 31, 2017:

	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 and not yet recognized in our condensed consolidated statement of operations as of March 31, 2017, was $3.2 million. The cost is expected to be recognized over a weighted-average period of 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.

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

	Shares			Weighted-Average Grant Date Fair Value
Non-vested at December 31, 2016	479,642			$	56.09
Granted	106,401			73.28
Vested	(48,656	)		50.46
Forfeited	(2,244	)		72.58
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/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, and not yet recognized in our condensed consolidated statements of operations as of March 31, 2017, was $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.

    

The Compensation Committee of our Board of Directors awarded a total of 28,069 market-based restricted shares to our executive officers during the three months ended March 31, 2017. In addition to continuous employment, the vesting of these shares is contingent on our total stockholder return ("TSR"), which is essentially 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, 2019, and can result in a payout between 0 percent and 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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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 three months ended March 31, 2017:

		Shares			Weighted-Average Grant Date Fair Value per Share
Non-vested at December 31, 2016		48,420			$	64.97
Granted		28,069			94.02
Non-vested at 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 /Three Months Ended March 31,
	2017				2016
	(in thousands, except per share data)
Total intrinsic value of market-based awards non-vested	$	4,769			$	5,697
Market price per common share as of March 31,	62.35				59.45
Weighted-average grant date fair value per share	94.02				72.54

Total compensation cost related to non-vested market-based awards, not yet recognized in our condensed consolidated statements of operations as of March 31, 2017, was $3.8 million. This cost is expected to be recognized over a weighted-average period of 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.

NOTE 14 - EARNINGS PER SHARE

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

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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 March 31,
	2017			2016
	(in thousands)
Weighted-average common shares outstanding - basic	65,749			41,608
Dilutive effect of:
Restricted stock	211			—
Other equity-based awards	157			—
Weighted-average common shares and equivalents outstanding - diluted	66,117			41,608

We reported a net loss for the three months ended 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 March 31,
	2017			2016
	(in thousands)
Weighted-average common share equivalents excluded from diluted earnings
per share due to their anti-dilutive effect:
Restricted stock	76			723
Convertible notes	—			508
Other equity-based awards	18			100
Total anti-dilutive common share equivalents	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 $115.0 million aggregate principal amount of 3.25% convertible senior notes that were due in 2016 ("2016 Convertible 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. Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method when the average market share price exceeded the $42.40 conversion price during the 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 applicable periods as the effect would be anti-dilutive to our earnings per share.

NOTE 15 - SUBSIDIARY GUARANTOR

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

(i)	PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries;
(ii)	PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our 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").

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PDC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

		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

		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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PDC ENERGY, INC.

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 review the Special Note Regarding Forward-Looking Statements.

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PDC ENERGY, INC.

EXECUTIVE SUMMARY

Financial Overview

Production volumes increased to 6.6 MMboe for the three months ended March 31, 2017, representing an increase of 46 percent as compared to the three months ended March 31, 2016. The increase in production volumes was primarily attributable to the continued success of our horizontal Niobrara and Codell drilling program in the Wattenberg Field and our first full quarter of production from the newly-acquired Delaware Basin properties. Crude oil production increased 32 percent for the three months ended March 31, 2017 compared to the three months ended March 31, 2016. Crude oil production comprised approximately 38 percent of total production in the three months ended March 31, 2017. Natural gas production increased 46 percent in the three months ended March 31, 2017 compared to the three months ended March 31, 2016. NGL production increased 75 percent for the three months ended March 31, 2017 compared to the 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 performed even better, with wet gas production that has outpaced oil and contributed to the growth of gas and NGLs production at a relatively higher rate. On a combined basis, total liquids production comprised 61 percent of total production during each of the three months ended March 31, 2017 and March 31, 2016. For the month ended March 31, 2017, we maintained an average quarterly production rate of approximately 73,900 Boe per day, up from approximately 50,200 Boe per day for the three months ended 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, increased by four percent. The modest increase in production was primarily related to the 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 on a sequential basis. We expect the timing of 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 March 31, 2017, versus the three months ended December 31, 2016.

Crude oil, natural gas, and NGLs sales increased to $189.7 million in the three months ended March 31, 2017, compared to $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 risk management gains of $80.7 million and $11.1 million, of which $0.5 million and $66.8 million were positive net settlements, for the three months ended March 31, 2017 and March 31, 2016, respectively. The combined revenue from crude oil, natural gas, and NGLs sales and net settlements received on our commodity derivative instruments increased 34 percent to $190.2 million in the three months ended March 31, 2017, from $142.2 million in the three months ended March 31, 2016.

    

Net settlements of 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 high-value derivatives 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.

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 March 31, 2017, include the following:

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PDC ENERGY, INC.

•

Positive net change in the fair value of unsettled derivatives for the three months ended March 31, 2017 was $80.2 million, compared to a negative net change in the fair value of unsettled derivatives for the three months ended March 31, 2016 of $55.7 million.  The increase in the fair value of unsettled 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 an upward shift in the crude oil forward curve during the three months ended March 31, 2016.

•

Depreciation, depletion, and amortization expense increased to $109.3 million during the three months ended March 31, 2017, as compared to $97.4 million in the three months ended March 31, 2016. The increase was primarily due to the increase in production and an increase in the property balance during the three months ended March 31, 2017 as compared to the three months ended March 31, 2016. The increase in the property balance is due to our Delaware Basin acquisitions. Our depreciation, depletion, and amortization expense decreased to $16.44 per Boe during the three months ended March 31, 2017 from $21.31 per Boe during the three months ended March 31, 2016 because of our increased proved reserve profile;

Available liquidity as of March 31, 2017, was $945.8 million compared to $932.4 million as of December 31, 2016. Available liquidity as of March 31, 2017 is comprised of $207.6 million of cash and cash equivalents, $49.9 million of short-term investments, and $688.3 million available for borrowing under our revolving credit facility. 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 active commodity derivative hedging program, utilization of our borrowing capacity under our revolving credit facility, and when warranted, the utilization of capital markets transactions from time to time.

Operational Overview

During the three months ended March 31, 2017, we continued to execute our strategic plan to grow production while preserving our financial strength and liquidity. During the three months end March 31 2017, we operated three drilling rigs in the Wattenberg Field and two increasing to three rigs in the Delaware Basin. We did not have a drilling rig operating in the Utica Shale during the period.

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 in-process wells at each period end are drilled but not completed as we do not begin the completion process until the entire well pad is 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 the period in which the wells are completed.

2017 Operational Outlook

We previously announced that we expect our production for the full year 2017 to range between 30.0 MMBoe to 33.0 MMBoe. Based on the timing and estimated productivity of wells associated with our capital investment program, we currently believe that our production will come in at levels in the top third of the range. We expect that approximately 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 capital forecast of between $725 million and $775 million is focused on continued development in the core Wattenberg 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. The 2017 investment forecast of approximately $470 million in the Wattenberg Field anticipates a three to four-rig drilling program based on our current commodity price outlook. Approximately $460 million of our 2017 capital investment program is expected to be allocated to development activities, comprised of approximately $440 million for our operated drilling program and approximately $20 million for wells drilled and operated by others. The remainder of the Wattenberg Field capital investment program is expected to be used for miscellaneous well equipment and capital projects. Wells in the Wattenberg Field typically have productive horizons at a depth of approximately 6,500 to 7,500 feet below the surface. In 2017, 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 invest approximately $30 million for leasing, seismic, and technical studies with an additional $35 million for midstream-related projects including gas connections, salt water disposal wells, and 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 $5 million to $10 million of exploration expense in 2017.

Utica Shale. As a result of our evaluation of our strategic alternatives with respect to our Utica Shale position, we expect to divest these properties during 2017. As 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 condensed consolidated balance sheets. We will continue to evaluate the classification of these assets in future quarters. Minimal capital is expected to be committed to our Utica Shale assets in 2017.

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Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results:

	Three Months Ended March 31,
	2017				2016				Percentage Change
	(dollars in millions, except per unit data)
Production
Crude oil (MBbls)	2,508				1,908				31.5	%
Natural gas (MMcf)	15,584				10,678				45.9	%
NGLs (MBbls)	1,543				882				74.8	%
Crude oil equivalent (MBoe)	6,648				4,570				45.5	%
Average Boe per day	73,866				50,216				47.1	%
Crude Oil, Natural Gas and NGLs Sales
Crude oil	$	123.0			$	54.0			127.8	%
Natural gas	36.9				14.9				147.7	%
NGLs	29.8				6.5				358.5	%
Total crude oil, natural gas, and NGLs sales	$	189.7			$	75.4			151.6	%
Net Settlements on Commodity Derivatives (1)
Crude oil	$	(3.2	)		$	53.3			*
Natural gas	3.7				13.5				(72.6	)%
Total net settlements on derivatives	$	0.5			$	66.8			(99.3	)%
Average Sales Price (excluding net settlements on derivatives)
Crude oil (per Bbl)	$	49.04			$	28.29			73.3	%
Natural gas (per Mcf)	2.37				1.39				70.5	%
NGLs (per Bbl)	19.29				7.37				161.7	%
Crude oil equivalent (per Boe)	28.53				16.49				73.0	%
Average Costs and Expenses (per Boe)
Lease operating expenses	$	2.98			$	3.35			(11.0	)%
Production taxes	1.87				0.89				110.1	%
Transportation, gathering and processing expenses	0.89				0.88				1.1	%
General and administrative expense	3.96				4.98				(20.5	)%
Depreciation, depletion and amortization	16.44				21.31				(22.9	)%
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.

Amounts may not recalculate due to rounding.

______________

(1)	Represents net settlements on derivatives related to crude oil, natural gas and natural gas basis.

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Crude Oil, Natural Gas, and NGLs Sales

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

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.

From time to time, our production was adversely affected by high line pressures in the natural gas gathering facilities in the Wattenberg Field. This situation improved significantly in 2015 as a result of the investment in additional field processing by the primary midstream service provider in the basin. Line pressures did not materially affect our production during the three months ended March 31, 2017 or 2016 due to the aforementioned investment by our midstream providers and a decrease in development activity by certain producers in the Wattenberg Field. During the three months ended March 31, 2017 and 2016, approximately 91 percent and 88 percent, respectively, of 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 vertical wells.

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. We 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 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 adequate infrastructure is not within our 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 production from the 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 have a high degree of volatility and our realizations can change substantially. Our realized prices for crude oil, natural gas, and NGLs increased significantly during the first quarter of 2017 compared to the first quarter of 2016. NYMEX crude oil and natural gas prices increased 55 percent and 59 percent, respectively, as compared to the first quarter of 2016.

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The following tables present weighted-average sales price of crude oil, natural gas, and NGLs for the periods presented. 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,
Weighted-Average Realized Sales Price by Operating Region										Percentage Change
(excluding net settlements on derivatives)		2017				2016
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 not meaningful.

Amounts may not recalculate due to 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 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 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 therefore embedded in the wellhead price. The net-back method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we earn. We use the 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 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 discussed above, we enter into agreements for the sale and transportation, gathering and processing of our production, the terms of which can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. Information related to the components and classifications in the condensed consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based upon average daily prices throughout each month and our natural gas 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, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price before transportation, gathering, and processing expenses shown in the table below represents our 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 commodity derivative instruments to manage fluctuations in crude oil, natural gas, and 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 propane production. Because we sell all of our crude oil, natural gas, and NGLs production at prices related to the indexes inherent in our underlying derivative instruments, we ultimately realize 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 the swaps. See the footnote titled Commodity Derivative Financial Instruments for a detailed presentation of our derivative positions as of 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, natural gas, and propane production. Commodity price risk management, net, does not include derivative transactions related to our gas marketing, which are included in other income and other expenses.

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

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

	Three Months Ended 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 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 $3.5 million to $26.3 million for the three months ended March 31, 2017 compared to $22.8 million for the three months ended March 31, 2016. The increase was primarily attributable to a $2.3 million increase in 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 $0.5 million of professional services fees related to the Delaware Basin acquisitions. We expect continued increases in our headcount through the remainder of 2017 as we build out our Delaware Basin operations.

    

Depreciation, Depletion and Amortization Expense

Crude oil and natural gas properties. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $107.8 million for the three months ended March 31, 2017 compared to $96.3 million for the three months ended 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 (in millions):

Increase in production		$	38.4
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		$	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 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 $1.5 million for the three months ended March 31, 2017 compared to $1.1 million for the three months ended March 31, 2016.

Provision for Uncollectible Notes Receivable

In the first quarter of 2016, we recorded a provision for uncollectible notes receivable of $44.7 million to impair two third-party notes receivable whose collection was not reasonably assured. As described in the footnote titled Fair Value of Financial Instruments, in April 2017, we signed a definitive agreement and simultaneously closed on the sale of one of the associated notes receivable to an unrelated third party. Accordingly, we reversed $40.3 million of the provision for notes receivable in the second quarter of 2017.

Interest Expense

Interest expense increased $7.6 million to $19.5 million for the three months ended March 31, 2017 compared to $11.9 million for the three months ended March 31, 2016. The increase is primarily attributable to a $6.3 million increase in interest relating 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, 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.

Provision for Income Taxes

The effective tax rate for the three months ended March 31, 2017 was 36.3 percent expense on income compared to 36.9 percent benefit on loss for the three months ended March 31, 2016. The effective tax rate for the three months ended March 31, 2017 is based upon a full year forecasted pre-tax 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 income, resulting in a tax 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 Income (Loss)/Adjusted Net Income (Loss)

 

The factors resulting in changes in net income in the three months ended March 31, 2017 of $46.1 million, and a net loss in the three months March 31, 2016 of $71.5 million are discussed above. These same reasons similarly impacted adjusted net loss, a non-U.S. GAAP financial measure, with the exception of the net change in fair value of unsettled derivatives, adjusted for taxes, of $50.2 million and $34.5 million for the three months ended March 31, 2017 and March 31, 2016, respectively. Adjusted net income (loss), a non-U.S. GAAP financial measure, was adjusted net loss of $4.1 million and $37.0 million for the three months ended March 31, 2017 and 2016, respectively. See Reconciliation of Non-U.S. GAAP Financial Measures, below for a more detailed discussion of this non-U.S. GAAP financial measure and 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 three months ended March 31, 2017, our primary sources of liquidity were the net cash flows from operating activities of $139.5 million.

Our primary source of cash flows from operating activities is the sale of crude oil, natural gas, and NGLs. Fluctuations in our operating cash flows are 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. The revolving credit agreement imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have significant fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. Based upon our hedge position and assuming forward strip pricing as of March 31, 2017, our derivatives may not be a significant source of 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 related to net settlements of commodity derivative instruments, compared to $66.8 million for the three months ended March 31, 2016. As of March 31, 2017, the fair value of our derivatives was a net asset of $10.1 million, of which $4.1 million will settle in the remaining nine months of 2017 based upon forward strip pricing as of that date at the 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 March 31, 2017, we had working capital of $93.8 million compared to $129.2 million at December 31, 2016. The decrease in working capital as of 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 were $207.6 million at March 31, 2017, our short-term investments were $49.9 million, and availability under our revolving credit facility was $688.3 million, providing for a total liquidity position of $945.8 million as of March 31, 2017, compared to $932.4 million at December 31, 2016. The increase in liquidity of $13.4 million, or one percent, was primarily attributable to net cash flows from operating activities of $139.5 million, partially offset by capital investments associated with development and exploration activity of $129.8 million during the three months ended March 31, 2017.

Based on our 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 activities during 2017. Our liquidity will be further augmented by the $40.3 million of proceeds received in the second quarter of 2017 from the sale of a third-party Note, as described previously.

Our revolving credit facility is a borrowing base facility and availability under the facility is subject to redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. The maturity date of 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 on our revolving credit facility as 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.

Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain (i) a leverage ratio defined as total debt of less than 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, gains (losses) and (ii) an adjusted current ratio of at least 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 March 31, 2017, we were in compliance with all debt covenants with a leverage ratio, as defined by the revolving credit agreement, of 2.0 times and a 3.7:1.0 current ratio. We expect to remain in compliance throughout the next 12-month period.

The indentures governing our 2022 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 March 31, 2017, we were in compliance with all covenants and expect to remain in compliance throughout the next 12-month period.

In January 2017, pursuant to the filing of the supplemental indentures for the 2021 Convertible Senior Notes, the 2022 Senior Notes, and the 2024 Senior Notes, our subsidiary PDC Permian, Inc. became a subsidiary guarantor of 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 $38.4 million for the three months ended March 31, 2017 compared to the three months ended March 31, 2016, primarily due to increases in crude oil, natural gas and NGLs sales of $114.3 million and an increase in changes in assets and liabilities of $15.6 million related to the timing of cash payments and receipts. These increases were offset in part by a decrease in commodity derivative settlements of $66.3 million and increases in lease operating expenses of $4.5 million, production taxes of $8.3 million, general and administrative expenses of $3.5 million, and interest expense of $7.6 million.

Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased $22.7 million during the three months ended March 31, 2017 compared to the three months ended 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 EBITDAX, a non-U.S. GAAP financial measure, increased by $72.4 million during the three months ended March 31, 2017, compared to the three months ended March 31, 2016. The 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 increases in lease operating expenses of $4.5 million, production taxes of $8.3 million, and general and administrative expenses of $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 investments.

Cash flows from investing activities primarily consist of the acquisition, exploration, and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $173.6 million during the three months ended March 31, 2017, was primarily related to cash utilized for our drilling operations, including completion activities of $129.8 million and purchases of short-term investments of $49.9 million.  Partially offsetting these investments was the 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 three months ended March 31, 2017 decreased by approximately $261.6 million compared to the three months ended March 31, 2016. Certain capital markets and financing activities occurred in 2016 including the $296.6 million received from the issuance of our common stock. These amounts were partially offset by net payments of approximately $37.0 million to pay down amounts borrowed under our revolving credit facility in the first quarter of 2016.

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Off-Balance Sheet Arrangements

At 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 investments, or capital resources.

Commitments and Contingencies

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

Recent Accounting Standards

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

Critical Accounting Policies and Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with U.S. GAAP required management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities, and the reported amounts of revenue and expenses.

There have been no significant changes to our critical accounting policies and estimates or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the condensed consolidated financial statements and accompanying notes contained in our 2016 Form 10-K filed with the SEC on February 28, 2017.

Reconciliation of Non-U.S. GAAP Financial Measures

We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, providing public guidance on possible future results. 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. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has 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.

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

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

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

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

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

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

    

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

	Three Months Ended March 31,
	2017				2016
	(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	$	113.7			$	91.0
Adjusted net income (loss):
Net income (loss)	$	46.1			$	(71.5	)
Gain on commodity derivative instruments	(80.7		)		(11.1		)
Net settlements on commodity derivative instruments	0.5				66.8
Tax effect of above adjustments	30.0				(21.2		)
Adjusted net income (loss)	$	(4.1	)		$	(37.0	)
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	0.5				66.8
Non-cash stock-based compensation	4.5				4.7
Interest expense, net	19.2				10.3
Income tax expense (benefit)	26.3				(41.8		)
Impairment of properties and equipment	2.2				1.0
Exploration, geologic, and geophysical expense	1.0				0.2
Depreciation, depletion, and amortization	109.3				97.4
Accretion of asset retirement obligations	1.8				1.8
Adjusted EBITDAX	$	130.2			$	57.8
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities	$	139.5			$	101.2
Interest expense, net	19.2				10.3
Amortization of debt discount and issuance costs	(3.2		)		(1.8		)
Gain on sale of properties and equipment	0.2				0.1
Exploration, geologic, and geophysical expense	1.0				0.2
Other	(0.7		)		(42.0		)
Changes in assets and liabilities	(25.8		)		(10.2		)
Adjusted EBITDAX	$	130.2			$	57.8

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market-Sensitive Instruments and Risk Management

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

Interest Rate Risk

Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents, and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes, 2024 Senior Notes, 2022 Senior Notes, and short-term investments have fixed rates, and therefore near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt.

As of March 31, 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 March 31, 2017 was $169.1 million with a weighted-average interest rate of 0.5 percent. Based on a sensitivity analysis of our interest-bearing deposits as of March 31, 2017 and assuming we had $169.1 million outstanding throughout the period, we estimate that a 1 percent increase in interest rates would have increased interest income for the three months ended March 31, 2017 by approximately $1.7 million.

As of 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, 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.

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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)
					Floors				Ceilings
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 market index prices for crude oil and natural gas for the periods identified, as well as the average sales prices we realized for our crude oil, natural gas, and NGLs production:

	Three Months Ended				Year Ended
	March 31, 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 March 31, 2017, we estimate that a ten percent increase in natural gas, 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 $87.6 million, whereas a 10 percent decrease in prices would have resulted in an increase in fair value of $87.6 million.

Credit Risk

Credit risk represents the loss that we would incur if a counterparty fails to perform its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure 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 and gas exploration and production business's crude oil, natural gas, and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers.

Amounts due to our 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 relating to our gas marketing business continue to

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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 two default judgments. We expect this trend to continue for this business.

We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. See the footnote titled Commodity Derivative Financial Instruments to our condensed consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial instruments.

Disclosure of Limitations

Because the information above included only those exposures that existed at March 31, 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 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 March 31, 2017.

Changes in Internal Control over Financial Reporting

During the three months ended 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

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 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 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 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 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 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 2016 Form 10-K.

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

    

    

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Period		Total Number of Shares Purchased (1)			Average Price Paid per Share
January 1 - 31, 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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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.

X

31.2

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

X

32.1*

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

99.1

Fourth Amendment to Third Amendment and Restated Credit Agreement

X

101.INS

XBRL Instance Document

X

101.SCH

XBRL Taxonomy Extension Schema Document

X

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

X

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

X

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

X

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

X

* Furnished herewith.

46

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Table of contents

PDC ENERGY, INC.

SIGNATURES

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

	PDC Energy, Inc.
	(Registrant)
Date: May 5, 2017	/s/ Barton R. Brookman
	Barton R. Brookman
	President and Chief Executive Officer
	(principal executive officer)
	/s/ David W. Honeyfield
	David W. Honeyfield
	Senior Vice President and Chief Financial Officer
	(principal financial officer)

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