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•	the COVID-19 pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters;

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

•	geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries;

•	impacts of Colorado political matters;

•	volatility of commodity prices for crude oil, natural gas and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices, including risks relating to decreased revenue, income and cash flow, write-downs and impairments and availability of capital;

•	volatility and widening of differentials;

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

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

•	timing and receipt of necessary regulatory permits;

•	impact of regulatory developments in Colorado, particularly with respect to additional permit scrutiny;

•	declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments;

•	changes in estimates of proved reserves;

•	inaccuracy of reserve estimates and expected production rates;

•	potential for production decline rates from our wells being greater than expected;

•	timing and extent of our success in discovering, acquiring, developing and producing reserves;

•	availability and cost 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;

•	risks incidental to the drilling and operation of crude oil and natural gas wells;

•	difficulties in integrating our operations as a result of any significant acquisitions, including the merger with SRC Energy Inc. ("SRC"), or acreage exchanges;

•	increases in costs and expenses;

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•	limitations in the availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells;

•	potential losses of acreage due to lease expirations or otherwise;

•	future cash flows, liquidity and financial condition;

•	competition within the oil and gas industry;

•	availability and cost of capital;

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

•	effect of crude oil and natural gas derivative activities;

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

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

•	cost of pending or future litigation;

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

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

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

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PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones. As of June 30, 2020, we owned an interest in approximately 3,900 gross productive wells.

 

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. 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 presentation 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, 2019 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 2019 Form 10-K. Our results of operations and cash flows for the six months ended June 30, 2020 are not necessarily indicative of the results to be expected for the full year or any other future period.

Recently Adopted Accounting Standards.

In March 2020, the SEC adopted final rules that amend the financial disclosure requirements for subsidiary issuers and guarantors of registered debt securities in Rule 3-10 of Regulation S-X. The amended rules, which can be found under new Rule 13-01 of Regulation S-X, narrow the circumstances that require separate financial statements of subsidiary issuers and guarantors and streamline the alternative disclosures required in lieu of those statements. The amended rules allow registrants, among other things, to disclose summarized financial information of the issuer and guarantors on a combined basis and to present only the most recently completed fiscal year and subsequent year-to-date interim period. The rule replaces the requirement to provide condensed consolidating financial information with a requirement to present summarized financial information of the issuers and guarantors. These disclosures may be provided outside the notes to the condensed consolidated financial statements. The rule is effective in the first quarter of 2021, with earlier adoption permitted. We early adopted the rule in the first quarter of 2020 and have provided these disclosures outside the notes to the condensed consolidated financial statements.

In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt (the "SRC Acquisition"). Upon closing, we issued approximately 39 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the merger agreement that we entered into with SRC (the "Merger Agreement"). During the six months ended June 30, 2020, we recorded transaction costs related to the SRC Acquisition of $20.2 million. These expenses were accounted for separately from the assets and liabilities assumed and are included in general and administrative expense.

     

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The details of the estimated purchase price and the preliminary allocation of the purchase price are as follows:

	Six Months Ended June 30, 2020
	(in thousands)
Consideration:
Cash	$	40
Retirement of seller's credit facility	166,238
Total cash consideration	166,278
Common stock issued	1,009,015
Shares withheld in lieu of taxes	6,299
Total consideration	$	1,181,592
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Current assets	$	148,977
Properties and equipment, net - proved	1,607,175
Properties and equipment, net - unproved	109,615
Properties and equipment, net - other	16,242
Deferred tax asset	193,410
Other assets	9,489
Total assets acquired	2,084,908
Liabilities assumed:
Current liabilities	(254,465		)
Senior notes	(555,500		)
Asset retirement obligations	(40,383		)
Other liabilities	(52,968		)
Total liabilities assumed	(903,316		)
Total identifiable net assets acquired	$	1,181,592

This acquisition was accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the 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. 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 proved and unproved crude oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, lease terms and expirations and a market-based weighted-average cost of capital rate of 10 percent. These inputs require significant judgments and estimates by management at the time of the valuation. As of the date of this report, we expect that the measurement period may extend into the fourth quarter of 2020.

Pro Forma Information. The results of operations for the SRC Acquisition since the closing date have been included in our condensed consolidated financial statements for the three and six months ended June 30, 2020 and includes approximately $48.3 million and $151.8 million of total revenue, respectively, and $14.5 million and $1.4 million of loss from operations for the three and six months ended June 30, 2020, respectively. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the six months ended June 30, 2020 and for the three and six months ended June 30, 2019, assuming the acquisition had been completed as of January 1, 2019. The financial information for the three months ended June 30, 2020 is included in our condensed consolidated financial statements for the three and six months ended June 30, 2020 and therefore does not require a pro forma disclosure. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the business combination. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results.

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		Three Months Ended June 30,				Six Months Ended June 30,
		2019				2020				2019
		(in thousands, except per share data)
Total revenue		$	561,530			$	832,786			$	862,629
Net income (loss)		127,425				(667,575		)		65,245
Earnings per share:
Basic		$	1.21			$	(6.69	)		$	0.62
Diluted		$	1.21			$	(6.69	)		$	0.62

Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material.        

Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the three and six months ended June 30, 2020 and 2019:

		Three Months Ended June 30,											Six Months Ended June 30,
Revenue by Commodity and Operating Region		2020				2019				Percent Change			2020				2019				Percent Change
		(in thousands)
Crude oil
Wattenberg Field		$	93,540			$	203,548			(54.0	)%		$	300,189			$	383,974			(21.8	)%
Delaware Basin		22,231				70,620				(68.5	)%		64,756				121,277				(46.6	)%
Total		$	115,771			$	274,168			(57.8	)%		$	364,945			$	505,251			(27.8	)%
Natural gas
Wattenberg Field		$	29,443			$	30,129			(2.3	)%		$	69,520			$	76,831			(9.5	)%
Delaware Basin		1,605				910				76.4	%		1,042				6,680				(84.4	)%
Total		$	31,048			$	31,039			—	%		$	70,562			$	83,511			(15.5	)%
NGLs
Wattenberg Field		$	22,762			$	22,677			0.4	%		$	48,004			$	50,399			(4.8	)%
Delaware Basin		4,340				11,072				(60.8	)%		10,725				20,894				(48.7	)%
Total		$	27,102			$	33,749			(19.7	)%		$	58,729			$	71,293			(17.6	)%
Crude oil, natural gas and NGLs
Wattenberg Field		$	145,745			$	256,354			(43.1	)%		$	417,713			$	511,204			(18.3	)%
Delaware Basin		28,176				82,602				(65.9	)%		76,523				148,851				(48.6	)%
Total		$	173,921			$	338,956			(48.7	)%		$	494,236			$	660,055			(25.1	)%

Contract Assets.    Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with midstream service providers that are our customers. The intent of the payments is primarily to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are included in other assets. The contract assets will be amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer.

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The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for the six months ended June 30, 2020:

	Amount
	(in thousands)
Beginning balance, January 1, 2020	$	11,494
Additions	11,246
Amortized as a reduction to crude oil, natural gas and NGLs sales	(881		)
Ending balance, June 30, 2020	$	21,859

Determination of Fair Value

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

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

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

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

Derivative Financial Instruments

We measure the fair value of our derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. We validate our fair value measurement by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions and through the review of counterparty statements and other supporting documentation.

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

	As of June 30, 2020												As of December 31, 2019
	Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
	(in thousands)
Total assets	$	202,183			$	34,855			$	237,038			$	22,886			$	8,938			$	31,824
Total liabilities	(52,923		)		(7,897		)		(60,820		)		(3,089		)		(524		)		(3,613		)
Net asset	$	149,260			$	26,958			$	176,218			$	19,797			$	8,414			$	28,211

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

		Three Months Ended June 30,								Six Months Ended June 30,
		2020				2019				2020				2019
		(in thousands)
Fair value of Level 3 instruments, net asset beginning of period		$	67,240			$	12,990			$	8,414			$	58,329
Changes in fair value included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net		(13,169		)		10,597				54,361				(32,923		)
Settlements included in condensed consolidated statement of operations line items:
Commodity price risk management gain (loss), net		(27,113		)		(1,083		)		(35,817		)		(2,902		)
Fair value of Level 3 instruments, net asset end of period		$	26,958			$	22,504			$	26,958			$	22,504
Net change in fair value of Level 3 unsettled derivatives included in condensed consolidated statement of operations line item:
Commodity price risk management gain (loss), net		$	(13,675	)		$	6,200			$	21,989			$	(26,641	)

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

Non-Derivative Financial Assets and Liabilities

We utilize fair value on a nonrecurring basis to review our proved crude oil and natural gas properties for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. Unobservable inputs include estimated future crude oil and natural gas production, forward strip commodity pricing curves (adjusted for basis differentials), operating and development costs, future development plans and a discount rate of 17 percent, based on a weighted-average cost of capital (all of which were designated as Level 3 inputs within the fair value hierarchy).

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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 June 30, 2020							As of December 31, 2019
		Estimated Fair Value				Percent of Par			Estimated Fair Value				Percent of Par
		(in millions)
Senior notes:
	2021 Convertible Notes	$	183.0			91.5	%		$	188.6			94.3	%
	2024 Senior Notes	378.0				94.5	%		409.2				102.3	%
	2025 Senior Notes	86.3				84.4	%		—				—	%
	2026 Senior Notes	547.2				91.2	%		599.4				99.9	%

The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

Concentration of Risk

Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at June 30, 2020; however, this determination may change.

Cash and Cash Equivalents. We consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of the FDIC insurance limits at June 30, 2020 and December 31, 2019. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our revolving credit facility.

Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases.

 

We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of June 30, 2020, we had derivative instruments, which were comprised of collars, fixed-price swaps and basis protection swaps, in place for a portion of our anticipated 2020, 2021 and 2022 production. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount.

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As of June 30, 2020, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted-average contract price is shown.

		Collars											Fixed-Price Swaps
Commodity/ Index/ Maturity Period		Quantity (Crude oil - MBls Natural Gas - BBtu)			Weighted-Average Contract Price								Quantity (Crude Oil - MBbls Gas and Basis- BBtu )			Weighted- Average Contract Price				Fair Value June 30, 2020 (1) (in thousands)
					Floors				Ceilings
Crude Oil
NYMEX
2020		1,800			$	55.00			$	71.68			6,349			$	58.90			$	150,963
2021		—			—				—				9,180			46.90				60,169
2022		—			—				—				1,980			34.88				(11,705		)
Total Crude Oil		1,800											17,509							$	199,427
Natural Gas
NYMEX
2020		32,442			$	2.02			$	2.31			2,000			$	2.30			$	4,045
2021		30,000			2.28				2.61				31,800			2.40				(11,248		)
Total Natural Gas		62,442											33,800							$	(7,203	)
Basis Protection - Natural Gas
CIG
2020		—			$	—			$	—			32,525			$	(0.49	)		$	(8,341	)
2021		—			—				—				65,700			(0.49		)		(5,727		)
Waha
2020		—			—				—				2,000			(1.40		)		(1,938		)
Total Basis Protection - Natural Gas		—											100,225							$	(16,006	)
Commodity Derivatives Fair Value																				$	176,218

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(1)	Approximately 14.7 percent of the fair value of our commodity derivative assets and 13.0 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).

Subsequent to June 30, 2020, we entered into commodity derivative positions covering approximately 996 MBls of crude oil production at an average New York Mercantile Exchange ("NYMEX") contract price of $40.61 for 2021 and 8,700

BBtu of NYMEX natural gas production, at an average contract price of $2.73 for 2021.

We have not elected to designate any of our derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the condensed consolidated statements of operations.

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The following table presents the condensed consolidated balance sheet line item and fair value amounts of our derivative instruments as of June 30, 2020 and December 31, 2019:

					Fair Value
Derivative Instruments:			Condensed Consolidated Balance Sheet Line Item		June 30, 2020				December 31, 2019
					(in thousands)
Derivative assets:	Current
	Commodity derivative contracts		Fair value of derivatives		$	222,289			$	27,766
	Basis protection derivative contracts		Fair value of derivatives		30				312
					222,319				28,078
	Non-current
	Commodity derivative contracts		Fair value of derivatives		14,719				3,746
Total derivative assets					$	237,038			$	31,824
Derivative liabilities:	Current
	Commodity derivative contracts		Fair value of derivatives		$	13,092			$	529
	Basis protection derivative contracts		Fair value of derivatives		12,901				2,392
					25,993				2,921
	Non-current
	Commodity derivative contracts		Fair value of derivatives		31,692				692
	Basis protection derivative contracts		Fair value of derivatives		3,135				—
					34,827				692
Total derivative liabilities					$	60,820			$	3,613

    

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

		Three Months Ended June 30,								Six Months Ended June 30,
Condensed Consolidated Statement of Operations Line Item		2020				2019				2020				2019
		(in thousands)
Commodity price risk management gain (loss), net
Net settlements		$	114,795			$	(13,193	)		$	160,618			$	(21,645	)
Net change in fair value of unsettled derivatives		(235,581		)		60,542				153,294				(121,080		)
Total commodity price risk management gain (loss), net		$	(120,786	)		$	47,349			$	313,912			$	(142,725	)

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

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

As of June 30, 2020		Derivative Instruments, Gross				Effect of Master Netting Agreements				Derivative Instruments, Net
		(in thousands)
Asset derivatives:
Derivative instruments, at fair value		$	237,038			$	(46,969	)		$	190,069
Liability derivatives:
Derivative instruments, at fair value		$	60,820			$	(46,969	)		$	13,851

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As of December 31, 2019		Derivative Instruments, Gross				Effect of Master Netting Agreements				Derivative Instruments, Net
		(in thousands)
Asset derivatives:
Derivative instruments, at fair value		$	31,824			$	(2,619	)		$	29,205
Liability derivatives:
Derivative instruments, at fair value		$	3,613			$	(2,619	)		$	994

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

	June 30, 2020				December 31, 2019
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	7,369,104			$	6,241,780
Unproved	385,322				403,379
Total crude oil and natural gas properties	7,754,426				6,645,159
Equipment and other	64,898				41,888
Land and buildings	26,014				12,312
Construction in progress	492,497				408,428
Properties and equipment, at cost	8,337,835				7,107,787
Accumulated DD&A	(3,337,769		)		(3,012,585		)
Properties and equipment, net	$	5,000,066			$	4,095,202

    

Impairment Charges. During the three months ended March 31, 2020, we recorded impairment charges of $881.1 million. The impairment charges during the three months ended March 31, 2020 were due to a significant decline in crude oil prices, which was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded impairment charges of $881.1 million to write-down our proved and unproved properties. Of these impairment charges, approximately $753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and realized prices at which we reasonably expect the crude oil and natural gas will be sold. In addition to our proved property impairment, we also recognized approximately $127.3 million of impairment charges for our unproved properties in the Delaware Basin. These impairment charges were recognized based on a review of our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we have no development plans. During the three months ended June 30, 2020, we did not have any material impairments.

We recorded impairment charges of $29.0 million and $36.9 million, respectively, in the three and six months ended June 30, 2019, of which $2.2 million and $10.1 million, respectively, were related to leaseholds and leasehold expirations within our non-focus areas of the Delaware Basin where we were no longer pursuing plans to develop the properties. During the three and six months ended June 30, 2019, we also recorded impairments of $26.8 million related to certain midstream facility infrastructure in the Delaware Basin. We determined the fair value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold.

Midstream Asset Divestitures. During the second quarter of 2019, we completed the sales of our Delaware Basin produced water gathering and disposal, crude oil gathering and natural gas gathering assets (the "Midstream Asset Divestitures") for aggregate proceeds of $345.6 million. The proceeds were received upon closing, with the exception of

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$82.0 million that we received in June 2020. Concurrent with the Midstream Asset Divestitures, we entered into agreements with the purchasers which provide us with certain gathering, processing, transportation and water disposal services. See footnote titled Other Accrued Expenses and Other Liabilities for further details regarding these agreements. Proceeds were allocated first to the assets sold based upon the fair values of the tangible assets sold, with the remainder of $179.6 million allocated to the acreage dedication agreements. We recorded an aggregate gain on the sale of $34.0 million based on the fair value of the tangible assets sold.

    

Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the condensed consolidated balance sheets:

    

		Six Months Ended June 30,				Year Ended December 31, 2019
		(in thousands, except for number of wells)
Beginning balance		$	16,078			$	12,188
Additions to capitalized exploratory well costs pending the determination of proved reserves		11,556				31,901
Reclassifications to proved properties		(20,431		)		(28,011		)
Ending balance		$	7,203			$	16,078
Number of wells pending determination at period-end		2				4

During six months ended June 30, 2020, two wells classified as exploratory at December 31, 2019 were reclassified as productive and no new wells drilled were classified as exploratory.

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

		June 30, 2020				December 31, 2019
		(in thousands)
Employee benefits		$	12,480			$	21,611
Asset retirement obligations		30,350				32,200
Environmental expenses (1)		10,866				2,256
Operating and finance leases		9,602				5,926
Other		13,355				8,469
Other accrued expenses		$	76,653			$	70,462

          

(1) Amount includes $8.9 million of environmental liability assumed in the SRC Acquisition.

    

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

		June 30, 2020				December 31, 2019
		(in thousands)
Production taxes		$	29,585			$	68,020
Deferred oil gathering credits		19,095				20,100
Deferred midstream gathering credits		173,006				175,897
Operating and finance leases		14,354				15,779
Other		2,655				3,337
Other liabilities		$	238,695			$	283,133

Deferred Oil Gathering Credits. In 2018, we entered into an agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The payment is being amortized over the life of the agreement. Amortization charges related to this deferred oil gathering credit totaling approximately $0.5 million for the three months ended June 30, 2020 and 2019, respectively, and $1.0 million for the six months ended June 30, 2020 and 2019, respectively, are included as a reduction to transportation, gathering and processing expenses.

Deferred Midstream Gathering Credits. In the second quarter of 2019, concurrent with the sale of our Delaware Basin midstream assets, we entered into agreements with the purchasers that dedicated the gathering of certain of our production and all water gathering and disposal volumes in the Delaware Basin. The terms of these agreements range from 10 to 22 years. The credits are being amortized on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production. Amortization charges included in crude oil sales totaled approximately $0.9 million and $1.7 million for the three and six months ended June 30, 2020, respectively. Amortization charges included as a reduction to transportation, gathering and processing expenses totaled approximately $0.3 million and $0.4 million for the three and six months ended June 30, 2020, respectively. Amortization charges included as a reduction to lease operating expenses and capital costs totaled approximately $0.4 million and $0.8 million for the three and six months ended June 30, 2020, respectively. Amortization charges related to the deferred midstream gathering credits were not material for the three and six months ended June 30, 2019.

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Long-term debt consisted of the following as of:

	June 30, 2020				December 31, 2019
	(in thousands)
Senior Notes:
1.125% Convertible Notes due September 2021:
Principal amount	$	200,000			$	200,000
Unamortized discount	(10,589		)		(14,763		)
Unamortized debt issuance costs	(1,178		)		(1,666		)
Net of unamortized discount and debt issuance costs	188,233				183,571
6.125% Senior Notes due September 2024:
Principal amount	400,000				400,000
Unamortized debt issuance costs	(4,121		)		(4,611		)
Net of unamortized debt issuance costs	395,879				395,389
6.25% Senior Notes due December 2025:
Principal amount	102,324				—
Unamortized premium	956				—
Net of unamortized premium	103,280				—
5.75% Senior Notes due May 2026:
Principal amount	600,000				600,000
Unamortized debt issuance costs	(5,287		)		(5,734		)
Net of unamortized debt issuance costs	594,713				594,266
Total senior notes	1,282,105				1,173,226
Revolving Credit Facility:
Revolving credit facility due May 2023	653,000				4,000
Total long-term debt, net of unamortized discount and debt issuance costs	$	1,935,105			$	1,177,226

    

Senior Notes

2021 Convertible Notes. In September 2016, we issued $200 million of 1.125% convertible notes due September 15, 2021 (the "2021 Convertible Notes"). Interest is payable semi-annually on March 15 and September 15. The conversion price at maturity is $85.39 per share. We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes.

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

 

2024 Senior Notes. In September 2016, we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024 (the “2024 Senior Notes”). Interest is payable semi-annually on March 15 and September 15.

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Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes.

2025 Senior Notes. Upon completion of the SRC Acquisition in January 2020, we assumed $550 million aggregate principal amount of 6.25% senior notes due December 1, 2025 (the "2025 Senior Notes"). The 2025 Senior Notes were recorded at $555.5 million, representing the approximate fair value. The difference between the acquisition date fair value and the principal amount of the 2025 Senior Notes will be recognized as a reduction to interest expense over the remaining life of the notes. Interest is payable semi-annually on June 1 and December 1. On January 17, 2020, we commenced an offer to repurchase the 2025 Senior Notes from the holders at 101 percent of the principal amount of the 2025 Senior Notes, together with any accrued and unpaid interest. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding 2025 Senior Notes accepted the redemption offer for a total redemption price of approximately $452.2 million, plus accrued and unpaid interest of $6.2 million. The fair value of the 2025 Senior Notes approximated the repurchase offer price, resulting in recognition of an immaterial loss on extinguishment of the repurchased notes. The repurchase was funded by proceeds from our revolving credit facility. An aggregate principal amount of approximately $102.3 million remains outstanding.

2026 Senior Notes. In November 2017, we issued $600 million aggregate principal amount of 5.75% senior notes due May 15, 2026 (the "2026 Senior Notes"). Interest is payable semi-annually on May 15 and November 15. Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes.

 

Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2021 Convertible Notes, the 2024 Senior Notes, the 2025 Senior Notes and the 2026 Senior Notes (collectively, the "Notes"). As of June 30, 2020, we were in compliance with all covenants related to the Notes.

Revolving Credit Facility

In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”). Among other things, the Restated Credit Agreement provides for a maximum credit amount of $2.5 billion. The amount we may borrow under the Restated Credit Agreement is subject to certain limitations. As a result of closing the SRC Acquisition, the borrowing base on our revolving credit facility increased to $2.1 billion and we elected to increase the aggregate commitment amount under our revolving credit facility to $1.7 billion. On May 5, 2020, we entered into a Second Amendment to the Restated Credit Agreement (the “Second Amendment”) that amended our interest rate and certain other provisions in the Restated Credit Agreement. In connection with the Second Amendment and as part of our semi-annual redetermination of our borrowing base, the borrowing base under the Restated Credit Agreement was reduced to $1.7 billion, while the commitment amount was unchanged at $1.7 billion.

The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility.

The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month, plus a premium) or, at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of June 30, 2020, the applicable interest margin is one percent for the alternate base rate option or two percent for the LIBOR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the revolving credit facility expires in May 2023, unless the borrowing base falls below the outstanding balance.

The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of

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4.0:1.0. As of June 30, 2020, we were in compliance with all covenants related to the revolving credit facility.

We determine if an arrangement is representative of a lease at contract inception. Right-of-use ("ROU") assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the commencement date based on the present value of the expected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms of our leases include options to extend or terminate the lease only when we can ascertain that it is reasonably certain we will exercise that option.

We have operating leases for office space and compressors and finance leases for vehicles. Our leases have remaining lease terms ranging from one to five years. The vehicle leases include options to renew for up to four years. Lease payments associated with vehicle leases also include a contractually stated residual value guarantee.

The following table presents the components of lease costs:

		Three Months Ended June 30,								Six Months Ended June 30,
Lease Costs		2020				2019				2020				2019
		(in thousands)
Operating lease costs		$	1,930			$	1,384			$	3,812			$	2,731
Finance lease costs:
Amortization of ROU assets		$	500			$	497			$	989			$	987
Interest on lease liabilities		51				67				106				129
Total finance lease costs		$	551			$	564			$	1,095			$	1,116
Short-term lease costs		35,912				51,074				131,985				112,105
Total lease costs		$	38,393			$	53,022			$	136,892			$	115,952

Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense. Our short-term lease costs include amounts that are capitalized as part of the cost of another asset and are recorded as properties and equipment or recognized as expense.

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The following table presents the balance sheet classification and other information regarding our leases as of:

Leases		Condensed Consolidated Balance Sheet Line Item		June 30, 2020				December 31, 2019
				(in thousands)
Operating Leases:
Operating lease ROU assets		Other assets		$	15,172			$	14,926
Operating lease obligation - short-term		Other accrued expenses		$	7,749			$	4,159
Operating lease obligation - long-term		Other liabilities		11,947				12,944
Total operating lease liabilities				$	19,696			$	17,103
Finance Leases:
Finance lease ROU assets		Properties and equipment, net		$	4,289			$	4,637
Finance lease obligation - short-term		Other accrued expenses		$	1,852			$	1,767
Finance lease obligation - long-term		Other liabilities		2,407				2,835
Total finance lease liabilities				$	4,259			$	4,602
Weighted-average remaining lease term (years)
Operating leases				3.27				4.28
Finance leases				2.86				3.17
Weighted-average discount rate
Operating leases				5.0		%		5.0		%
Finance leases				5.0		%		5.0		%

Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of June 30, 2020 consist of the following:

 

		Operating Leases				Finance Leases				Total
		(in thousands)
2020 (remaining after June 30, 2020)		$	5,988			$	1,159			$	7,147
2021		6,027				1,621				7,648
2022		5,084				930				6,014
2023		1,559				680				2,239
2024		950				141				1,091
Thereafter		1,698				9				1,707
Total lease payments		21,306				4,540				25,846
Less interest and discount		(1,610		)		(281		)		(1,891		)
Present value of lease liabilities		$	19,696			$	4,259			$	23,955

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

	Amount
	(in thousands)
Balance at December 31, 2019	$	127,251
Obligations incurred with development activities and other	7,308
Obligations incurred with acquisition	45,639
Accretion expense	4,978
Obligations discharged with asset retirements	(20,221		)
Obligations discharged with divestitures	(85		)
Balance at June 30, 2020	164,870
Current portion	(30,350		)
Long-term portion	$	134,520

Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and surface reclamation costs considering federal and state regulatory requirements in effect at that time. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. Short-term asset retirement obligations are included in other accrued expenses.

Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. Our condensed consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. We may from time to time find ourselves unable to market our commodities at prices acceptable to us, or at all, which could cause us to be unable to meet these obligations. In such cases, we may be subject to penalties, fees, minimum margins or other payments.

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The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity and water delivery and disposal commitments:

		For the Twelve Months Ending June 30,
Area		2021				2022				2023				2024				2025 and Through Expiration				Total				Expiration Date
Natural gas (MMcf)
Wattenberg Field		63,922				63,923				63,922				64,098				102,988				358,853				August 31, 2026
Delaware Basin		29,326				13,045				9,125				9,125				70,775				131,396				March 31, 2031
Gas Marketing		7,117				6,874				1,147				—				—				15,138				August 31, 2022
Total		100,365				83,842				74,194				73,223				173,763				505,387
Crude oil (MBbls)
Wattenberg Field		16,332				16,006				14,415				9,882				21,384				78,019				August 31, 2026
Delaware Basin		8,398				8,030				8,030				4,048				—				28,506				December 31, 2023
Total		24,730				24,036				22,445				13,930				21,384				106,525
Water (MBbls)
Wattenberg Field		6,207				6,207				6,207				6,224				3,128				27,973				December 31, 2024
Dollar commitment (in thousands)		$	138,697			$	119,050			$	105,066			$	80,073			$	150,543			$	593,429

Wattenberg Field. We entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018 and the second plant was completed in August 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016 to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. In addition, as a result of the SRC Acquisition, we are subject to substantially similar facilities expansion agreements with the same primary midstream provider of 46.4 MMcfd and 43.8 MMcfd, respectively. We may be required to pay shortfall fees for any volumes under the 97.9 MMcfd and 77.3 MMcfd incremental commitments. Any shortfall in these volume commitments may be offset by other producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes.

Delaware Basin. In May 2018, we entered into a firm sales agreement that is effective from June 2018 through December 2023 with an integrated marketing company for our crude oil production in the Delaware Basin. Contracted volumes are currently 24,000 barrels of crude oil per day and decrease over time to 22,000 barrels per day. This agreement is expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices.

Crude Oil, Natural Gas and NGLs Sales. For the three months ended June 30, 2020 and 2019, amounts related to long-term transportation volumes in the table above were $6.6 million and $12.2 million, respectively, and were netted against our crude oil and natural gas sales. For the six months ended June 30, 2020 and 2019, amounts related to long-term transportation volumes in the table above were $13.0 million and $23.1 million, respectively, and were netted against our crude oil and natural gas sales.

,

Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the

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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 material environmental claims existing as of June 30, 2020 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses. The liability ultimately incurred with respect to a matter may exceed the related accrual.

    

In recent years, we have been executing a program to plug and abandon certain of our older vertical wells in the Wattenberg Field. A self-audit of final reclamation activities associated with site retirements, which we concluded in 2019, identified deficiencies, including incomplete documentation and agency submittals, inadequate plant growth and incomplete earthwork. In December 2019, we formally disclosed these deficiencies to the COGCC and are working to close this backlog of site reclamation work. During 2020, we are similarly assessing reclamation activities at sites acquired through the SRC Acquisition. We do not believe potential penalties and other expenditures associated with the deficiencies disclosed to the COGCC, nor any potential future disclosure of deficiencies associated with sites acquired in the SRC Acquisition, will have a material effect on our financial condition or results of operations, but they may exceed $100,000.

In July 2020, a ruling by the U.S. Court of Appeals for the District of Columbia Circuit found that U.S. Environmental Protection Agency (“EPA”) established the northern boundary of the Denver Metro/Northern Front Range ozone non-attainment area based on erroneous criteria and ordered the EPA to reconsider that boundary, potentially including more land within the designated area. All of our Wattenberg Field operations and leaseholds are within the current non-attainment area. Accordingly, we do not currently expect the ruling to impact us, regardless of the results of the EPA’s reconsideration.

Clean Air Act Agreement and Related Consent Decree. In June 2017, following our receipt of a 2015 Clean Air Act information request from the EPA and a 2015 compliance advisory from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Pollution Control Division, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law.

In October 2017, we entered into a consent decree to resolve the lawsuit and the compliance advisory. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects) of which the cash fines and the full cost of supplemental environmental projects were paid in the first and third quarters of 2018, respectively, (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations and (iii) mitigation with an estimated cost of $1.7 million continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our condensed consolidated financial statements.

Since the consent decree took effect, and more recently was expanded to include the 2018 Compliance Order on Consent, we have timely implemented the various programs that meet its requirements. Over the course of this execution, we have identified certain immaterial deficiencies in our implementation of the programs. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $100,000. 

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Stock-Based Compensation Plans

2018 Equity Incentive Plan. In May 2020, our stockholders approved an amendment to increase the number of shares of our common stock reserved for issuance pursuant to our long-term equity compensation plan for employees and non-employee directors (the “2018 Plan”) from 1,800,000 to 7,050,000. The 2018 Plan was approved in May 2018 and expires in March 2028. Shares issued may be either authorized but unissued shares, treasury shares or any combination thereof. Additionally, the 2018 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or paid out in the form of cash. However, shares tendered or withheld to satisfy the exercise price of options or tax withholding obligations, and shares covering the portion of exercised stock-settled stock appreciation rights ("SARs") (regardless of the number of shares actually delivered), count against the share limit. Awards may be issued in the form of options, SARs, restricted stock, restricted stock units ("RSUs"), performance stock units ("PSUs") and other stock-based awards. Awards may vest over periods of continued service or upon the satisfaction of performance conditions set at the discretion of the Compensation Committee of the Board (the "Compensation Committee"), with a minimum one-year vesting period applicable to most awards. With regard to SARs and options, awards have a maximum exercisable period of ten years. As of June 30, 2020, there were 5,142,500 shares available for grant under the 2018 Plan.

    

2010 Long-Term Equity Compensation Plan. Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was approved by stockholders in 2013 (as the same has been amended and restated from time to time, the "2010 Plan"), will remain outstanding and we may continue to use the 2010 Plan to grant awards. No awards may be granted under the 2010 Plan on or after June 5, 2023. As of June 30, 2020, there were 111,617 shares available for grant under the 2010 Plan. 

2015 SRC Equity Incentive Plan. Pursuant to the closing of the SRC Acquisition, SRC granted 155,928 PSUs to certain SRC executives under the 2015 SRC Equity Incentive Plan (the “2015 SRC Plan”). These PSUs (the “SRC PSUs”) were granted prior to the consummation of the merger, were assumed and converted into PDC PSUs at a rate of 0.158 per share and remain subject to the same terms and conditions (including performance-vesting terms) that applied immediately prior to the closing of the SRC Acquisition. The PSUs will result in a payout between zero and 200 percent of the target PSUs awarded. As of June 30, 2020, there were no shares available for grant under the 2015 SRC Plan.

Stock-based Compensation. The impact of our stock-based compensation plans on our results of operations was $6.4 million and $12.0 million for the three and six months ended June 30, 2020, respectively, and $7.6 million and $12.3 million for the three and six months ended June 30, 2019, respectively.

    

Restricted Stock Units

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

The following table presents the changes in non-vested time-based RSUs to all employees, including executive officers, for the six months ended June 30, 2020:

	Shares			Weighted-Average Grant Date Fair Value per Share
Non-vested at December 31, 2019	795,926			$	45.51
Granted	1,033,498			11.69
Vested	(394,007	)		42.71
Forfeited	(140,403	)		23.36
Non-vested at June 30, 2020	1,295,014			21.77

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

	As of/Six Months Ended June 30,
	2020				2019
	(in thousands, except per share data)
Total intrinsic value of time-based awards vested	$	5,432			$	10,424
Total intrinsic value of time-based awards non-vested	16,110				30,815
Market price per share as of June 30	12.44				36.06
Weighted-average grant date fair value per share	11.69				40.47

Total compensation cost related to non-vested time-based awards and not yet recognized in our condensed consolidated statements of operations as of June 30, 2020 was $21.8 million. This cost is expected to be recognized over a weighted-average period of 2.2 years.

Performance Stock Units

Market-Based Awards. The fair value of the market-based PSUs is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.

    

The Compensation Committee awarded a total of 289,494 market-based PSUs to our executive officers during the six months ended June 30, 2020. In addition to continuous employment, the vesting of these PSUs is contingent on a combination of absolute stock performance and our total stockholder return ("TSR"), which is essentially our stock price change, including any dividends over a three-year period ending on December 31, 2022, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between zero and 250 percent of the target PSUs awarded. The weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions:

	Six Months Ended June 30,
	2020				2019
Expected term of award (in years)	3				3
Risk-free interest rate	1.4		%		2.5		%
Expected volatility	46.6		%		41.4		%
Weighted-average grant date fair value per share	$	33.52			$	56.68

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.

SRC Performance Stock Units. Terms of the SRC PSUs are substantially the same as PDC PSUs, except that the awards do not require continuous employment and the performance period associated with the awards of January 1, 2019 through December 31, 2021 predates the grant date. The fair value of the SRC PSU awards was determined on the grant date of January 13, 2020 using the Monte Carlo pricing model using the following assumptions:

	Six Months Ended June 30,
	2020
Expected term of awards (in years)	2
Risk-free interest rate	1.6		%
Expected volatility	56.9		%
Weighted-average grant date fair value per share	$	33.35

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The expected term of the awards is based on the number of years from the grant date through the end of the performance period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant, extrapolated to approximate the life of the awards. The expected volatility was based on our historical volatility, as well as that of our peer group.

The following table presents the change in non-vested market-based awards, including SRC PSUs, during the six months ended June 30, 2020:

		Shares			Weighted-Average Grant Date Fair Value per Share
Non-vested at December 31, 2019		221,142			$	61.61
Granted		445,422			32.96
Forfeited		(11,014	)		40.69
Non-vested at June 30, 2020		655,550			42.49

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

	As of/Six Months Ended June 30,
	2020				2019
	(in thousands, except per share data)
Total intrinsic value of market-based awards non-vested	$	8,155			$	8,731
Market price per common share as of June 30,	12.44				36.06
Weighted-average grant date fair value per share	32.96				56.68

Total compensation cost related to non-vested market-based awards not yet recognized in our condensed consolidated statements of operations as of June 30, 2020 was $13.0 million. This cost is expected to be recognized over a weighted-average period of 1.9 years.

Stock Appreciation Rights

The SARs vest ratably over a three-year period and may generally be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. The following table presents the change in SARs during the six months ended June 30, 2020:

		Shares			Weighted-Average Grant Date Fair Value per Share
Outstanding at December 31, 2019		290,258			$	46.64
Exercised		(7,807	)		24.44
Expired		(71,776	)		40.83
Outstanding at June 30, 2020		210,675			49.45

All outstanding SARs as of June 30, 2020 have vested and the related compensation cost has been fully recognized.

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Preferred Stock

We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by the Board from time to time. Through June 30, 2020, no shares of preferred stock have been issued.

Stock Repurchase Program

In April 2019, the Board approved the acquisition of up to $200 million of our outstanding common stock, depending on market conditions (the "Stock Repurchase Program"). Effective upon the closing of the SRC Acquisition, our Board approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million. Repurchases under the Stock Repurchase Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board at any time. During the six months ended June 30, 2020, we repurchased 1.3 million shares of our outstanding common stock at a cost of $23.8 million. The last repurchases occurred in early March 2020. Approximately $346.8 million of our outstanding common stock remains available for repurchase under the Stock Repurchase Program. We expect repurchases made pursuant to the Stock Repurchase Program to extend beyond December 31, 2021, given current market conditions.

We compute our quarterly tax provision using the effective tax rate method by applying the anticipated annual effective rate to our year-to-date income or loss, except for discrete items. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs.

As previously noted, we recorded impairments totaling $881.1 million for the six months ending June 30, 2020. These impairments resulted in three years of cumulative historical pre-tax losses and a net deferred tax asset position. We also have net operating loss carryovers (“NOLs”) for federal income tax purposes of $500.0 million. These losses were a key consideration that led us to continue to provide a valuation allowance against our net deferred tax assets as of June 30, 2020 since we cannot conclude that it is more likely than not that our net deferred tax asset will be fully realized in future periods.

The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead us to conclude that it is more likely than not that our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. We will continue to evaluate whether the valuation allowance is needed in future reporting periods.

As noted in the footnote Business Combinations, the accounting for the SRC Acquisition is still in the measurement period. Additional purchase accounting adjustments recorded in the quarter ended June 30, 2020 resulted in an insignificant change to the preliminary purchase price allocated to the net deferred income tax assets from the SRC Acquisition. This also impacted the income tax provision effects from the valuation allowance recorded against our net deferred tax assets recorded in the quarter ended March 31, 2020. Additional adjustments during the measurement period for the SRC Acquisition may have an impact on the income tax provision in future periods, although such adjustments are not expected to be material. Other than business combination accounting adjustments during the measurement period, we will likely not have any additional income tax expense or benefit other than for state income taxes as long as we continue to conclude that it is appropriate to maintain a full valuation allowance against our net deferred tax assets.

The effective income tax rate for the three and six months ended June 30, 2020 was 1.9 percent and 0.5 percent benefit on loss, respectively, compared to a 24.8 percent provision on income for the three months ended June 30, 2019 and a 22.3 percent benefit on loss for the six months ended June 30, 2019.

As of June 30, 2020, there is no liability for unrecognized income tax benefits. As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. The IRS has accepted our 2018 federal income tax return with no tax adjustments. We continue to voluntarily

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participate in the IRS CAP Program for the review of our 2019 and 2020 tax year. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings.

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

The following table presents our weighted-average basic and diluted shares outstanding:

	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
	(in thousands)
Weighted-average common shares outstanding - basic	99,566			65,815			96,821			65,998
Dilutive effect of:
RSUs and PSUs	—			85			—			—
Other equity-based awards	—			26			—			—
Weighted-average common shares and equivalents outstanding - diluted	99,566			65,926			96,821			65,998

We reported a net loss for the three and six months ended June 30, 2020 and the six months ended June 30, 2019. As a result, our basic and diluted weighted-average common shares outstanding were the same for those periods because the effect of the common share equivalents was anti-dilutive.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
	(in thousands)
Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
RSUs and PSUs	1,914			770			1,600			1,048
Other equity-based awards	244			208			236			302
Total anti-dilutive common share equivalents	2,158			978			1,836			1,350

The 2021 Convertible Notes give the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes were not included in the diluted earnings per share calculation using the treasury stock method for any periods presented because the average market price of our common stock did not exceed the conversion price.

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		Six Months Ended June 30,
		2020				2019
		(in thousands)
Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest		$	39,168			$	29,034
Income taxes		(204		)		200
Non-cash investing and financing activities:
Change in accounts payable related to capital expenditures		$	(7,223	)		$	41,273
Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals		44,082				(1,139		)
Issuance of common stock for the acquisition of crude oil and natural gas properties, net		1,009,015				—
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		$	4,421			$	2,914
Operating cash flows from finance leases		109				127
ROU assets obtained in exchange for lease obligations:
Operating leases		$	4,217			$	1,428
Finance leases		703				1,593

    

Subsequent to the filing of our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2019, we identified an immaterial error in our condensed consolidated statement of cash flows related to cash paid for capital expenditures for development of crude oil and natural gas properties for the period ended June 30, 2019. Our balance sheet and statement of operations for the relevant period were not impacted. We evaluated the error under the guidance of Accounting Standards Codification 250, Accounting Changes and Error Corrections ("ASC 250"). Based on the guidance in ASC 250, we determined that the error did not have a material impact on our previously-issued financial statements or those of the period of correction.

The error resulted in an overstatement of cash flows from operations of $24.8 million and an overstatement of cash used in investing activities of $24.8 million in each period as follows:

		Six Months Ended
		June 30, 2019
		(dollars in thousands)
Cash flows from operating activities, as reported		$	442,236
Adjustment		(24,753		)
Cash flows from operating activities, as adjusted		$	417,483
Cash flows from investing activities, as reported		$	(348,805	)
Adjustment		24,753
Cash flows from investing activities, as adjusted		$	(324,052	)

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•	Prolonged depressed crude oil prices may have adverse effects on the financial wellbeing of our business, including with respect to revenue, profitability, cash flows and liquidity; quantity and present value of our reserves; borrowing base under our revolving credit facility; and access to other sources of capital;

•	Decreased crude oil prices may require us to shut in production for a significant portion of our producing wells, which will reduce our revenue and require monetary compensation to mineral lessors;

•	Domestic oversupply of crude oil may lead to insufficient storage capacity and could impact our midstream providers’ ability to accept and transport our production to market;

•	Effects of COVID-19, including demand destruction, reduction in skilled workforce and state and local orders regarding public health and safety may result in claims of force majeure by us or our counterparties relating to obligations under material agreements;

•	Low commodity prices may lead to financial distress and restructuring events affecting working interest partners, vendors, service providers and other counterparties;

•	Negative financial impacts to our business partners may cause delays or failure to pay service providers, which could result in liens filed against our real and personal property;

•	Our reduced capital spend and projected decline in revenues have led to temporary and permanent reductions in our work force and decreases to our director, executive and employee compensation, which may affect our ability to attract and retain experienced technical and other professional personnel;

•	Our reduced drilling program may result in losses of acreage due to lease expirations, which could result in impairment charges and the loss of future drilling opportunities;

•	Reported reductions in the work forces of our service providers may result in delays in procuring products and services essential to our operations;

•	State and local orders, ordinances and guidance related to COVID-19 have forced a significant portion of our employees to work remotely, which may result in decreased productivity and continuity among the employee base;

•	Current market conditions and impacts on our business generally may lead to an increased risk of litigation; and

•	The cumulative effects of COVID-19 on the economy may result in a long-term global recession or depression.

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(1)

Certain purchases represent shares withheld from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. The withheld shares are not issued or considered common stock repurchased under the Stock Repurchase Program described in the footnote titled Common Stock to our accompanying condensed consolidated financial statements included elsewhere in this report.

(2)

In April 2019, the Board approved a program to acquire up to $200 million of our outstanding common stock and in August 2019, effective with the closing of the SRC Acquisition, increased such amount to $525 million. The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board at any time; further repurchases pursuant to the program have been suspended and, when we resume the program, we expect to slow the pace of previously planned share repurchases as we continue to prioritize our financial strength and liquidity. We expect purchases made pursuant to the Stock Repurchase Program to extend beyond December 31, 2021, given current market conditions.

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