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

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

•	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 related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations;

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

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

•	changes in estimates of proved reserves;

•	inaccuracy of estimated reserves and 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;

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•	availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production;

•	timing and receipt of necessary regulatory permits;

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

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

•	increases or changes in costs and expenses;

•	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;

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

•	effect of crude oil, natural gas and NGLs derivatives 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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•	$2.50 change in the NYMEX crude oil price from $52.50, our adjusted cash flows from operations would increase or decrease by approximately $30 million;

•	$0.25 change in the NYMEX natural gas price from $2.00, our adjusted cash flows from operations would increase or decrease by approximately $20 million; and

•	$1.00 change in the composite price for NGLs from $11.00, our adjusted cash flows from operations would increase or decrease by approximately $20 million.

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Strong financial position. We maintain a disciplined financial strategy that focuses on strong liquidity, low leverage ratios and an active commodity derivative program to help mitigate a portion of the risk associated with commodity price fluctuations. We believe that execution of this strategy will allow us to deliver strong corporate returns year-over-year, even through challenging commodity price environments. As of December 31, 2019, we had total liquidity of $1.3 billion, a leverage ratio, as defined in our revolving line of credit facility agreement, of 1.4 and commodity derivative positions covering approximately 10.8 MMBbls and 3.2 MMBbls of crude oil production for 2020 and 2021, respectively. As of the same date, we had hedged approximately 4.0 Bcf of natural gas production for 2020.

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Focus on generating sustainable cash flows from operations in excess of capital investments. We are focused on generating multi-year sustainable cash flows from operations in excess of our capital investments through managing capital spending and growth rates, adjusting the timing of completion of our inventory of drilled uncompleted wells ("DUCs"), utilizing commodity derivative instruments, focusing on margin improvement from reductions in our cost structure and through increased capital efficiency from technological innovation.

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Return of capital to shareholders. We are focused on returning capital to shareholders through our ongoing share repurchase program and a focus on debt reduction. Through February 24, 2020, we have repurchased an aggregate 5.3 million shares of our outstanding common stock for a total cost of $166.9 million. Through successful execution of our business plan, our projected cash flows are expected to position us to deliver on our commitment to return capital to shareholders.

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Significant operational control in our core areas. We have, and expect to continue to have, a substantial degree of operational control over our properties. As a result of successfully executing our strategy of acquisitions and acreage trades in our core areas of operations, we have built multiple concentrated acreage positions with high working interests that we believe will allow us to enhance the value of our assets and replenish our drilling inventory. Including wells that we received in the SRC Acquisition, we currently operate approximately 78 percent of all the wells in which we have an interest. This operational control allows us to better manage our drilling, production, operating and administrative costs and to leverage our technical expertise in our core operating areas. Our leaseholds that are held by production further enhance our operational control by providing us with additional flexibility on the timing of drilling of those locations.

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Project inventory in two premier crude oil, natural gas and NGL plays. We have a substantial multi-year inventory of high-quality horizontal drilling opportunities across two premier U.S. onshore basins: the Wattenberg Field in Weld County, Colorado and the Delaware Basin in Reeves County, Texas. Our portfolio has a proven record of delivering strong and repeatable economic returns and provides us the ability to allocate capital investments and manage risk as each basin has its own operating and competitive dynamic in terms of commodity price markets, service costs, takeaway capacity and regulatory and political considerations. We have a disciplined development program that seeks to expand our project inventory through testing new intervals and considering various spacing configurations. We believe our project inventory will allow us to achieve attractive rates of return and grow our proved reserves and

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Efficiency through technology and consolidation. Technological innovation has led to continued improvement in our drilling and completion times. We are utilizing technology to improve the efficiency of our horizontal drilling and completion operations in the Wattenberg Field. In the Delaware Basin, we continue to make progress towards improved capital efficiency through various drilling initiatives and completion designs. The technology associated with our completions process continues to improve as we design wellbore placement and stage spacing and, in the Wattenberg Field, increase the completed lateral length of our wells. In addition, completion equipment, perforation clusters, fluid and sand type and concentration decisions continue to result in more efficient recoveries of crude oil and natural gas reserves. As with our drilling operations, we are currently working toward using the expertise we have developed in the Wattenberg Field to increase the efficiency of our Delaware Basin completions activities. Additionally, acreage consolidation, particularly in the Wattenberg Field, increases our ability to drill longer length lateral wells. Longer laterals allow us to develop our properties with a smaller number of wells and less truck traffic, with resulting benefits for our operations and for the communities in which we operate.

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Strong environmental, health and safety compliance programs and community outreach. We have focused on establishing effective environmental, health and safety programs that are intended to promote safe working practices for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies and public officials. This is an important part of our strategy in effectively operating in today’s intensive regulatory climate. For the year ended December 31, 2019, we achieved our strategic priorities around our environment, health and safety programs. We are also dedicated to being an active and contributing member of the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships.

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Experienced management team with proven track record. We have a strong executive management team that has an average of 25 years of experience in the oil and gas industry. Collectively, this experience includes technical, operational, commercial, financial and strategic aspects of the oil and gas industry. This team has a proven track record of executing on value-added capital investment programs that have been implemented with a focus on financial discipline and improving on an already strong balance sheet, while growing production and proved reserves. Additionally, our team's experience has helped us continue to achieve our strategic objectives through periods of commodity price volatility, cost inflation and other challenging operating environments.

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(1)	Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months.

(3)	For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes.

(4)	These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity.

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(1)	Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI, of approximately $6.8 billion, $9.1 billion and $6.2 billion as of December 31, 2019, 2018 and 2017, respectively, less an internally-estimated undiscounted future income tax expense of approximately $0.9 billion, $1.4 billion and $0.7 billion, respectively.

(2)

PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure.

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•	the inability to successfully integrate SRC into our company in a manner that permits us to achieve the anticipated benefits and cost savings from the SRC Acquisition;

•	complexities associated with managing a larger, more complex, integrated business;

•	not realizing anticipated operating synergies;

•	integrating personnel from the two companies and the loss of key employees;

•	potential unknown liabilities and unforeseen expenses associated with the SRC Acquisition;

•	integrating relationships with customers, vendors and business partners;

•	performance shortfalls as a result of the diversion of management’s attention caused by the SRC Acquisition and the integration of SRC’s operations into our company;

•	managing expanded environmental and other regulatory compliance obligations related to SRC's facilities and operations;

•	consolidating information technology systems; and

•	the disruption of, or the loss of momentum in, our business or inconsistencies in standards, controls, procedures and policies.

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•	our revenue, profitability and cash flows;

•	our liquidity;

•	the quantity and present value of our reserves;

•	the borrowing base under our revolving credit facility and access to other sources of capital; and

•	the nature and scale of our operations.

•	relatively minor changes in regional, national or global supply and demand;

•	regional, national or global economic conditions, and perceived trends in those conditions;

•	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 ("OPEC"), and global events, such as the ongoing COVID-19 outbreak; and

•	regulatory changes.

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•	Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties;

•	Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities;

•	Some upstream energy companies have sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure; and

•	The possibility that new or amended regulations, including regulations that increase mandatory setbacks or enhance local control of oil and gas development, could result in severely curtailed drilling activities in Colorado may discourage investment in midstream facilities.

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From time to time ballot initiatives have been proposed in Colorado that would adversely affect our operations. For example, Proposition 112, a voter initiative that qualified for the ballot for the general election in November 2018, would have effectively prohibited the vast majority of our planned drilling activity in Colorado by imposing mandatory 2,500 foot setbacks between new oil and gas wells and any occupied structure or designated "vulnerable area." Although Proposition 112 was defeated at the polls, subsequent legislation significantly amended existing state law to, among other things, require the COGCC to prioritize public health and environmental concerns in its decisions, instruct the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and authorize local governmental authorities to impose limitations on oil and gas development activities more stringent than those imposed at the state level. In October 2019, the CDPHE released a study of potential health risks that modeled certain exposure scenarios at distances up to 2,000 feet, based on

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Substantially all of our drilling activities involve the use of hydraulic fracturing, and proposals are made from time to time at the federal, state and local levels to further regulate, or to ban, hydraulic fracturing practices. Additional laws or regulations regarding hydraulic fracturing could, among other things, increase our costs, reduce our inventory of economically viable drilling locations and reduce our reserves.

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Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other GHGs. For example, the EPA has made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane emissions from oil and gas operations. In addition, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline (although President Trump subsequently announced that the U.S. is withdrawing from the Paris Agreement). Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program. In addition, like other energy companies, we could be named as a defendant in GHG-related lawsuits.

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Proposals are made from time to time to amend U.S. federal and state tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling.

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The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage and use of surface water or groundwater or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, any of which could have an adverse effect on our operations and financial condition.

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•	fluctuations in prices of crude oil, natural gas and NGLs produced from the wells in the area;

•	natural disasters;

•	restrictive governmental regulations; and

•	curtailment of production or interruption in the availability of gathering, processing or transportation infrastructure and services and any resulting delays or interruptions of production from existing or planned new wells.

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•	the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any particular group of properties;

•	future depreciation, depletion and amortization (“DD&A”) rates and amounts;

•	impairments in the value of our assets;

•	the classifications of reserves based on risk of recovery;

•	estimates of future net cash flows;

•	timing of our capital expenditures; and

•	the amount of funds available for us to borrow under our revolving credit facility.

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•	crude oil, natural gas and NGL prices;

•	the availability and cost of capital;

•	drilling and production costs;

•	availability of drilling services and equipment;

•	drilling results;

•	lease expirations or limitations as to depth;

•	midstream constraints;

•	access to and availability of water sourcing and distribution systems;

•	regulatory approvals; and

•	other factors.

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•	unusual or unexpected geological formations;

•	pressures;

•	fires;

•	floods;

•	loss of well control;

•	loss of drilling fluid circulation;

•	title problems;

•	facility or equipment malfunctions;

•	unexpected operational events;

•	shortages or delays in the delivery of equipment and services;

•	unanticipated environmental liabilities;

•	compliance with environmental and other governmental requirements; and

•	adverse weather conditions.

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•	our proved reserves;

•	the amount of crude oil, natural gas and NGLs we are able to produce from existing wells;

•	the prices at which crude oil, natural gas and NGLs are sold;

•	the costs to produce crude oil, natural gas and NGLs; and

•	our ability to acquire, locate and produce new reserves.

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•	incur additional debt;

•	pay dividends on, redeem or repurchase stock;

•	create liens;

•	make specified types of investments;

•	apply net proceeds from certain asset sales;

•	engage in transactions with our affiliates;

•	engage in sale and leaseback transactions;

•	merge or consolidate;

•	restrict dividends or other payments from restricted subsidiaries;

•	sell equity interests of restricted subsidiaries; and

•	sell, assign, transfer, lease, convey or dispose of assets.

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•	changes in production volumes, worldwide demand and prices for crude oil and natural gas;

•	inability to hedge future production at the same pricing level as our current or prior hedges;

•	changes in securities analysts’ estimates of our financial performance;

•	fluctuations in stock market prices and volumes, particularly among securities of energy companies;

•	changes in market valuations and valuation multiples of similar companies;

•	changes in interest rates;

•	announcements regarding adverse timing or lack of success in discovering, acquiring, developing and producing crude oil and natural gas resources;

•	announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures or capital commitments;

•	decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or lenders ceasing to participate in our revolving credit facility syndicate;

•	operating results that fall below market expectations or variations in our quarterly operating results;

•	loss of a major customer;

•	loss of a relationship with a partner;

•	regulatory developments

•	the occurrence and severity of environmental events and governmental and other third-party responses to the events; or

•	additions or departures of key personnel.

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•	the organization of our Board as a classified board, which provides that approximately one-third of our directors are subject to election each year;

•	bylaw provisions that require advance notice of some types of shareholder proposals; and

•	Delaware law provisions which prohibit us from engaging in any business combination with any "interested stockholder," meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met.

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The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.

•	If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy.

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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 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.

(3)	Subsequent to December 31, 2019, we repurchased $12.5 million of our outstanding common stock as part of the Stock Repurchase Program. As of February 24, 2020, $358.2 million of our outstanding common stock remained available for repurchase under the Stock Repurchase Program.

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(1)	In 2016, we closed an acquisition in the Delaware Basin for aggregate consideration of approximately $1.76 billion.

(2)	Includes impact of change in accounts payable related to capital expenditures.

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•	$2.50 change in the NYMEX crude oil price from $52.50, our adjusted cash flows from operations would increase or decrease by approximately $30 million;

•	$0.25 change in the NYMEX natural gas price from $2.00, our adjusted cash flows from operations would increase or decrease by approximately $20 million; and

•	$1.00 change in the composite price for NGLs from $11.00, our adjusted cash flows from operations would increase or decrease by approximately $20 million.

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(1)	Table does not include net deferred income tax liability to taxing authorities of $195.8 million due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

(2)	Amount presented does not agree with the consolidated balance sheets in that it excludes $14.8 million of unamortized debt discounts and $12.0 million of unamortized debt issuance costs.

(3)	Represents our gross liability related to the fair value of derivative positions.

(4)	Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements.

(5)	The table does not include termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

(6)	Amounts presented include $241.5 million to the holders of our 2026 Senior Notes, $122.5 million to the holders of our 2024 Senior Notes and $4.5 million payable to the holders of our 2021 Convertible Notes. Amounts also include interest of $16.7 million related to unutilized commitments at a rate of 0.375 percent per annum.

(7)	Represents our gross commitment which includes volumes produced by us and purchased from third parties and produced by other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf.

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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. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of December 31, 2019, we owned an interest in approximately 2,649 productive gross wells.

The accompanying audited consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. Pursuant to the proportionate consolidation method, our accompanying 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.

The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased and exchanged businesses and assets; and valuation of deferred income tax assets.

Certain immaterial reclassifications have been made to our prior period balance sheet to conform to the current period presentation. The reclassifications had no impact on previously reported results.

Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents.

Restricted Cash. At December 31, 2018, our total cash, cash equivalents and restricted cash of $9.4 million was comprised of $1.4 million of cash and cash equivalents and $8.0 million of restricted cash. We included restricted cash in other assets at December 31, 2018. We did not have any restricted cash at December 31, 2019.

Commodity Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes.

Derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of issuing or holding the derivative. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows.

The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

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Properties and Equipment.

Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A.

    

Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded.

Proved Property Impairment. Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and estimated future cash flows. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A.

Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment.

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Other Property and Equipment. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years. Total depreciation expense related to other property and equipment was $5.7 million, $8.5 million and $6.6 million in 2019, 2018 and 2017, respectively.

We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment.

Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is recognized.

Internal-Use Software. Internal-use software costs incurred during the development stage of our ERP software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2019 and December 31, 2018, our capitalized costs for internal-use software were $25.9 million and $1.4 million, respectively.

Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $13.4 million, $9.2 million and $5.0 million in 2019, 2018 and 2017, respectively.

Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year.

Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable.

Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets.

Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value,

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is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations.

Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings.

Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2019, 2018 and 2017, the impact of any natural gas imbalances was not significant.

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

We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses.

Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers.

Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties.

In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by

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additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value.

If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Acreage Exchanges. From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement.

Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations.

Recently Adopted Accounting Standards.

In February 2016, the Financial Accounting Standards Board ("FASB") issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. As provided by practical expedients, we made accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset. The FASB issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that, if elected, permits an organization to not evaluate the accounting for existing land easements that are not accounted for under the previous lease accounting standard. We elected this practical expedient, and accordingly, existing land easements at December 31, 2018 were not assessed. All new or modified land easements entered into after January 1, 2019 are evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Adoption of the New Lease Standard resulted in increases to other assets of $20.1 million, other accrued expenses of $4.6 million and other liabilities of $15.5 million at January 1, 2019, with no adjustment to the opening balance of retained earnings.

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In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt. 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 terms of the Merger Agreement. We expect to account for the SRC Acquisition under the acquisition method of accounting for business combinations and are currently in the process of determining preliminary estimated acquisition date fair values of identifiable assets acquired and liabilities assumed. During 2019, we recorded transaction costs related to the SRC Acquisition of $7.3 million, which are included in general and administrative expense.

As 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. As part of the SRC acquisition, we assumed the SRC Senior Notes and paid off and terminated SRC's revolving credit facility, which had an outstanding balance of $165.0 million at closing. The indenture governing the SRC Senior Notes has a change of control provision pursuant to which, if a “Change of Control” occurs, the issuer is required to make an offer to repurchase the SRC Senior Notes at a price equal to 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase. It was determined that the SRC Acquisition did result in a "Change of Control", and on January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding SRC Senior Notes accepted our redemption offer for a total redemption price of approximately $452.2 million, plus accrued and unpaid interest of $6.2 million. We funded the repurchase with proceeds from our revolving credit facility.

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On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $11.3 million in 2017 with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for 2018, we applied the new guidance to contracts that were not completed as of December 31, 2017. The adoption of the New Revenue Standard has not significantly impacted our net income.

Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2019, 2018 and 2017:

		Year Ended December 31,
Revenue by Commodity and Operating Region		2019				2018				2017 (1)
		(in thousands)
Crude oil
Wattenberg Field		$	767,760			$	783,158			$	529,562
Delaware Basin		252,929				252,107				82,677
Utica Shale (2)		—				2,696				12,814
Total		$	1,020,689			$	1,037,961			$	625,053
Natural gas
Wattenberg Field		$	137,143			$	130,073			$	131,792
Delaware Basin		13,877				32,010				21,251
Utica Shale (2)		—				1,109				5,216
Total		$	151,020			$	163,192			$	158,259
NGLs
Wattenberg Field		$	94,347			$	132,820			$	104,298
Delaware Basin		41,219				55,148				20,756
Utica Shale (2)		—				840				4,718
Total		$	135,566			$	188,808			$	129,772
Revenue by Operating Region
Wattenberg Field		$	999,250			$	1,046,051			$	765,652
Delaware Basin		308,025				339,265				124,684
Utica Shale (2)		—				4,645				22,748
Total		$	1,307,275			$	1,389,961			$	913,084

(1)	As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017
	have not been restated. Such changes would not have been material.
(2)	In March 2018, we completed the disposition of our Utica Shale properties.

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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.

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 December 31,
	2019												2018
	Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
	(in thousands)
Total assets	$	22,886			$	8,938			$	31,824			$	118,521			$	59,693			$	178,214
Total liabilities	(3,089		)		(524		)		(3,613		)		(3,364		)		(1,364		)		(4,728		)
Net asset	$	19,797			$	8,414			$	28,211			$	115,157			$	58,329			$	173,486

    

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

		Year Ended December 31,
		2019				2018				2017
		(in thousands)
Fair value of Level 3 instruments, net asset (liability) beginning of period		$	58,329			$	(9,687	)		$	(9,574	)
Changes in fair value included in consolidated statements of operations line item:
Commodity price risk management gain (loss), net		(41,749		)		63,257				6,241
Settlements included in consolidated statements of operations line items:
Commodity price risk management gain (loss), net		(8,166		)		4,759				(6,354		)
Fair value of Level 3 instruments, net asset (liability) end of period		$	8,414			$	58,329			$	(9,687	)
Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item:
Commodity price risk management gain (loss), net		$	(22,694	)		$	—			$	(866	)
Total		$	(22,694	)		$	—			$	(866	)

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.

    

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 December 31, 2019 and 2018:

	As of December 31,
	2019							2018
	Estimated Fair Value				Percent of Par			Estimated Fair Value				Percent of Par
	(in millions)
Senior notes:
2021 Convertible Notes	$	188.6			94.3	%		$	175.4			87.7	%
2024 Senior Notes	409.2				102.3	%		370.2				92.5	%
2026 Senior Notes	599.4				99.9	%		532.4				88.7	%

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.

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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 December 31, 2019, we had derivative instruments, which were comprised of fixed-price swaps, collars and basis protection swaps, in place for a portion of our anticipated 2020 and 2021 production. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount.

As of December 31, 2019, our derivative instruments were comprised of fixed-price swaps, collars and basis protection swaps.

•

Fixed-price swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty;

•

Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty;

•	Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

    

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As of December 31, 2019, 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 December 31, 2019 (1) (in thousands)
					Floors				Ceilings
Crude Oil
NYMEX
2020		3,600			55.00				71.68				7,160			60.98				27,162
2021		—			—				—				3,200			55.76				3,054
Total Crude Oil		3,600											10,360							$	30,216
Natural Gas
NYMEX
2020		—			—				—				4,000			2.30				75
Dominion South
2020		—			—				—				14			2.54				—
Total Natural Gas		—											4,014							$	75
Basis Protection - Natural Gas
CIG
2020		—			$	—			$	—			20,500			$	(0.62	)		$	(2,392	)
Waha
2020		—			—				—				4,000			(1.40		)		312
Total Basis Protection - Natural Gas		—											24,500							$	(2,080	)
Commodity Derivatives Fair Value																				$	28,211

(1)	Approximately 28.1 percent of the fair value of our commodity derivative assets and 14.5 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3).

Subsequent to December 31, 2019, we entered into commodity derivative positions covering approximately 1,000 MBbls and 2,000 MBbls of crude oil production for 2020 and 2021, respectively. Additionally, we received commodity derivative positions covering approximately 3,900 MBbls of crude oil production for 2020 as a result of the SRC Acquisition.

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 consolidated statements of operations.

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The following table presents the balance sheet location and fair value amounts of our derivative instruments as of December 31, 2019 and 2018:

 

					Fair Value
Derivative Instruments:			Consolidated Balance Sheet Line Item		2019				2018
					(in thousands)
Derivative assets:	Current
	Commodity derivative contracts		Fair value of derivatives		$	27,766			$	84,492
	Basis protection derivative contracts		Fair value of derivatives		312				—
					28,078				84,492
	Non-current
	Commodity derivative contracts		Fair value of derivatives		3,746				93,722
Total derivative assets					$	31,824			$	178,214
Derivative liabilities:	Current
	Commodity derivative contracts		Fair value of derivatives		$	529			748
	Basis protection derivative contracts		Fair value of derivatives		2,392				2,616
					2,921				3,364
	Non-current
	Commodity derivative contracts		Fair value of derivatives		692				1,364
Total derivative liabilities					$	3,613			$	4,728

    

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

		Year Ended December 31,
Consolidated Statements of Operations Line Item		2019				2018				2017
		(in thousands)
Commodity price risk management gain (loss), net
Net settlements		$	(17,598	)		$	(115,538	)		$	13,324
Net change in fair value of unsettled derivatives		(145,246		)		260,775				(17,260		)
Total commodity price risk management gain (loss), net		$	(162,844	)		$	145,237			$	(3,936	)

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 consolidated balance sheets.

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

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

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As of December 31, 2018		Derivative instruments, gross				Effect of Master Netting Agreements				Derivative Instruments, Net
		(in thousands)
Asset derivatives:
Derivative instruments, at fair value		$	178,214			$	(3,985	)		$	174,229
Liability derivatives:
Derivative instruments, at fair value		$	4,728			$	(3,985	)		$	743

Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts:

	As of December 31,
	2019				2018
	(in thousands)
Crude oil, natural gas and NGLs sales	$	149,758			$	155,756
Joint interest billings	29,510				19,580
Midstream asset divestitures deferred payments	81,702				—
Derivative counterparties	—				3,937
Other	12,860				6,542
Allowance for doubtful accounts	(7,476		)		(4,381		)
Accounts receivable, net	$	266,354			$	181,434

        

Our accounts receivable primarily relate to sales of our crude oil, natural gas and NGLs production, receivable balances from other third parties that own working interests in the properties we operate and derivative counterparties. For the years ended December 31, 2019 and 2018, amounts written off to allowance for doubtful accounts were not material. As of December 31, 2019 and December 31, 2018, four and three, respectively, of our customers represented 10 percent or more of our crude oil, natural gas and NGLs accounts receivable balance.

    

Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues:

		Year Ended December 31,
Customer		2019			2018			2017
Occidental Marketing, Inc.		20.0	%		—	%		—	%
DCP Midstream, LP		17.0	%		12.5	%		19.6	%
Mercuria Energy Trading, Inc.		16.0	%		—	%		—	%
United Energy Trading, LLC		11.0	%		—	%		—	%
Suncor Energy Marketing, Inc.		—	%		—	%		16.4	%

Derivative Counterparties. We utilize commodity derivative instruments to manage a portion of our exposure to price volatility from producing crude oil, natural gas and NGLs. 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 December 31, 2019.

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

		As of December 31,
		2019				2018
		(in thousands)
Employee benefits		$	21,611			$	25,811
Asset retirement obligations		32,200				25,598
Environmental expenses		2,256				3,038
Operating and finance leases		5,926				1,779
Other		8,469				18,907
Other accrued expenses		$	70,462			$	75,133

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

	As of December 31,
	2019				2018
	(in thousands)
Production taxes	$	68,020			$	61,310
Deferred oil gathering credits	20,100				22,710
Deferred midstream gathering credits	175,897				—
Operating and finance leases	15,779				2,900
Other	3,337				5,744
Other liabilities	$	283,133			$	92,664

Deferred Oil Gathering Credits. In January 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 $2.0 million and $1.4 million for 2019 and 2018, respectively, are included as a reduction to transportation, gathering and processing expenses.

Deferred Midstream Gathering Credits. In May 2019, concurrent with the sale of our Delaware Basin produced water gathering and disposal midstream assets, we entered into an agreement with the purchaser which dedicates all of our water gathering and disposal volumes in the Delaware Basin via pipeline for a term of 15 years. We recorded a long-term deferred credit of $40.5 million attributable to the value of the dedication, which is being amortized using the units-of-production basis. Amortization charges related to this deferred credit totaling $0.9 million for 2019 are included as a reduction to lease operating expenses and capital costs.

In May 2019, concurrent with the sale of our Delaware Basin crude oil gathering midstream assets, we entered into an agreement with the purchaser which provides us with gathering and transport for crude oil from dedicated acreage within an area of mutual interest for a term of 15 years. We recorded a long-term deferred credit of $28.9 million attributable to the value of the dedication, which is being amortized on a units-of-production basis. Amortization charges related to this deferred credit totaling $0.5 million for 2019 are included as crude oil sales.

In June 2019, concurrent with the sale of our Delaware Basin natural gas gathering midstream assets, we entered into an agreement with the purchaser which provides us with gathering, processing and transportation of our natural gas from certain dedicated leases for a term of 22 years. We recorded a long-term deferred credit of $110.2 million attributable to the value of the dedication, which is being amortized on a units-of-production basis. Amortization charges related to this deferred credit totaling $2.0 million for 2019 are included as a reduction to transportation, gathering and processing expenses.

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The following table presents the components of properties and equipment, net of accumulated DD&A:

	As of December 31,
	2019				2018
	(in thousands)
Properties and equipment, net:
Crude oil and natural gas properties
Proved	$	6,241,780			$	5,452,613
Unproved	403,379				492,594
Total crude oil and natural gas properties	6,645,159				5,945,207
Infrastructure and other	41,888				60,612
Land and buildings	12,312				11,243
Construction in progress	408,428				356,095
Properties and equipment, at cost	7,107,787				6,373,157
Accumulated DD&A	(3,012,585		)		(2,370,295		)
Properties and equipment, net	$	4,095,202			$	4,002,862

Midstream Asset Divestitures. During 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. 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. 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.

In May 2019, we completed the sale of our produced water gathering and disposal midstream assets in the Delaware Basin for $126.3 million, subject to certain customary post-closing adjustments, plus potential future long-term incentive payments of up to $56.3 million. We recorded a gain on the sale of $25.7 million based on the fair value of the tangible assets sold during 2019.

In May 2019, we also completed the sale of our crude oil gathering midstream assets in the Delaware Basin for $37.3 million, subject to certain customary post-closing adjustments, plus potential future long-term incentive payments of up to $15.2 million. We recorded a loss on the sale of $0.2 million based on the fair value of the tangible assets sold during 2019.

In June 2019, we completed the sale of our natural gas gathering midstream assets in the Delaware Basin for $182.0 million ($100.0 million of which was paid upon closing with the remaining $82.0 million to be paid in June 2020), subject to certain customary post-closing adjustments, plus potential future long-term incentive payments of up to $60.5 million. The $82.0 million receivable is included in accounts receivable at December 31, 2019. We recorded a gain on the sale of $8.5 million based on the fair value of the tangible assets sold during 2019.

 

The Midstream Asset Divestitures did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for the divested assets as discontinued operations.

Acreage Acquisition. In September 2019, we exchanged acreage located in Reeves County, Texas with a third party. As additional consideration for the acreage acquired, we paid $2.7 million in cash and recognized a loss of $45.6 million based on the carrying value of the acreage sold.

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Classification of Assets and Liabilities as Held-for-Sale. Assets held-for-sale at December 31, 2018 included assets sold in the Midstream Asset Divestitures and certain non-core Delaware Basin crude oil and natural gas properties. The following table presents balance sheet data related to assets and liabilities held-for-sale:

	December 31, 2018
	(in thousands)
Assets
Properties and equipment, net	$	137,448
Other assets	3,257
Total assets	$	140,705
Liabilities
Asset retirement obligation	$	4,111
Total liabilities	$	4,111

During 2019, we sold certain Delaware Basin crude oil and natural gas properties for net cash proceeds of $33.4 million, which approximated the net book value, resulting in no gain or loss on the sale.

Impairment Charges. The following table presents impairment charges recorded for properties and equipment:

	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Impairment of proved and unproved properties	$	10,599			$	458,397			$	285,465
Amortization of individually insignificant unproved properties	—				—				422
Impairment of infrastructure and other	27,937				—				—
Total impairment of properties and equipment	$	38,536			$	458,397			$	285,887

During 2019 and 2018, we recorded impairment charges totaling $10.6 million and $458.4 million, respectively, related to the divestiture of leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin that we determined not to develop. We determined the fair value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. During 2019, we also recorded impairments of $27.9 million related to certain midstream facility infrastructure in the Delaware Basin. Upon closing of the Midstream Asset Divestitures, it was determined that the net book value of these assets was not recoverable.

 

Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment:

	As of December 31,
	2019				2018
	(in thousands, except for number of wells)
Beginning balance	$	12,188			$	15,448
Additions to capitalized exploratory well costs pending the determination of proved reserves	31,901				35,127
Reclassifications to proved properties	(28,011		)		(38,387		)
Ending balance	$	16,078			$	12,188
Number of wells pending determination at period-end	4				2

    During 2019, the two wells classified as exploratory at December 31, 2018 were reclassified as productive and four new wells drilled were classified as exploratory.

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Exploration Expenses. The following table presents the major components of exploration, geologic and geophysical expense:

	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Exploratory dry hole costs	$	—			$	113			$	41,297
Geological and geophysical costs, including seismic purchases	3,017				3,401				3,881
Operating, personnel and other	1,037				2,690				2,156
Total exploration, geologic and geophysical expense	$	4,054			$	6,204			$	47,334

Exploratory dry hole costs. During 2017, two exploratory dry holes, associated lease costs and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.3 million. The conclusion to expense these items was based on our determination that the acreage on which these wells were drilled was exploratory in nature and, following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable.

Long-term debt consisted of the following as of:

	As of December 31,
	2019				2018
	(in thousands)
Senior Notes:
1.125% Convertible Notes due September 2021:
Principal amount	$	200,000			$	200,000
Unamortized discount	(14,763		)		(22,766		)
Unamortized debt issuance costs	(1,666		)		(2,640		)
Net of unamortized discount and debt issuance costs	183,571				174,594
6.125% Senior Notes due September 2024:
Principal amount	400,000				400,000
Unamortized debt issuance costs	(4,611		)		(5,590		)
Net of unamortized debt issuance costs	395,389				394,410
5.75% Senior Notes due May 2026:
Principal amount	600,000				600,000
Unamortized debt issuance costs	(5,734		)		(6,628		)
Net of unamortized debt issuance costs	594,266				593,372
Total senior notes	1,173,226				1,162,376
Revolving Credit Facility:
Revolving credit facility due May 2023	4,000				32,500
Total long-term debt, net of unamortized discount and debt issuance costs	$	1,177,226			$	1,194,876

    

Senior Notes

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2021 Convertible Notes.  In September 2016, we issued $200 million of 1.125% convertible notes due September 15, 2021 in a public offering. Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on March 15 and September 15.

The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, at an initial conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per share. The conversion rate is subject to adjustment upon certain events. 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.

 

We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible.

 

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. As of December 31, 2019, the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes. Based upon the December 31, 2019 stock price of $26.17 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount.

2024 Senior Notes. In September 2016, we issued $400 million aggregate principal amount of 6.125% senior notes due September 15, 2024. Interest is payable semi-annually on March 15 and September 15. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. The 2024 Senior Notes are redeemable after September 15, 2019 at fixed redemption prices, currently 104.594 percent of the principal amount redeemed.

2026 Senior Notes. In November 2017, we issued $600.0 million aggregate principal amount 5.75% senior notes due May 15, 2026. 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.

The 2026 Senior Notes are redeemable after May 15, 2021 at fixed redemption prices beginning at 104.313 percent of the principal amount redeemed. At any time prior to May 15, 2021, we may redeem all or part of the 2026 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at May 15, 2021 and remaining interest payments on the 2026 Senior Notes at the time of redemption.

At any time prior to May 15, 2021 we may redeem up to 35 percent of the outstanding 2026 Senior Notes with proceeds from certain equity offerings at a redemption price of 105.75 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2026 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering.

The 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes.

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Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes and the 2026 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase.

The indentures governing the 2024 Senior Notes and 2026 Senior Notes contain covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. As of December 31, 2019, we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Convertible Notes and the 2026 Senior 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 under our senior notes. In August 2019, we entered into a First Amendment to the Restated Credit Agreement (the "First Amendment"). The First Amendment primarily provided for certain borrowing in connection with the SRC Acquisition and modified certain sections of the Restated Credit Agreement to permit the consummation of the SRC Acquisition. In October 2019, as part of our semi-annual redetermination, the borrowing base on our revolving credit facility was reaffirmed at $1.6 billion and we elected to retain our commitment amount at $1.3 billion.

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. As part of the SRC acquisition, we assumed the SRC Senior Notes. The SRC Senior Notes contained a change of control provision pursuant to which, if the consummation of the SRC Acquisition resulted in a “Change of Control” under the indenture governing the SRC Senior Notes, we were required to make an offer to repurchase the SRC Senior Notes at a price equal to 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase. It was determined that the SRC Acquisition did result in a "Change of Control", and on January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes at 101 percent of the principal amount. See the footnote titled Acquisition for information regarding the redemption of the SRC Senior Notes.

    

The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. Substantially all of our crude oil and natural gas properties 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 December 31, 2019, the applicable interest margin is 0.25 percent for the alternate base rate option or 1.25 percent for the LIBOR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the revolving credit facility expires in May 2023, unless the borrowing base falls below the outstanding balance.

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

As of December 31, 2019 and 2018, debt issuance costs related to our revolving credit facility were $8.9 million

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and $11.5 million, respectively, and are included in other assets. As of December 31, 2019 and 2018, availability under our revolving credit facility was $1.3 billion. As of December 31, 2019, the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was five percent.

On January 1, 2019, we adopted the New Lease Standard issued by the FASB. We determine if an arrangement is representative of a lease under the New Lease Standard at contract inception. ROU assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the commencement date based on the present value of the expected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms of our leases include options to extend or terminate the lease only when we can ascertain that it is reasonably certain we will exercise that option.

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

The following table presents the components of lease costs:

Lease Costs		Year Ended December 31, 2019
		(in thousands)
Operating lease costs		$	4,917
Finance lease costs:
Amortization of ROU assets		$	1,961
Interest on lease liabilities		252
Total finance lease costs		$	2,213
Short-term lease costs		170,064
Total lease costs		$	177,194

Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense on our consolidated statements of operations. Our short-term lease costs include amounts that are capitalized as part of the cost of another asset and are recorded as properties and equipment 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		Consolidated Balance Sheet Line Item		December 31, 2019
				(in thousands)
Operating Leases:
Operating lease ROU assets		Other assets		$	14,926
Operating lease obligation - short-term		Other accrued expense		$	4,159
Operating lease obligation - long-term		Other liabilities		12,944
Total operating lease liabilities				$	17,103
Finance Leases:
Finance lease ROU assets		Properties and equipment, net		$	4,637
Finance lease obligation - short-term		Other accrued expense		$	1,767
Finance lease obligation - long-term		Other liabilities		2,835
Total finance lease liabilities				$	4,602
Weighted-average remaining lease term (years)
Operating leases				4.28
Finance leases				3.17
Weighted-average discount rate
Operating leases				5.0		%
Finance leases				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 December 31, 2019 consist of the following:

 

		Operating Leases				Finance Leases				Total
		(in thousands)
2020		$	4,847			$	1,949			$	6,796
2021		4,923				1,423				6,346
2022		5,016				855				5,871
2023		1,559				637				2,196
2024		950				95				1,045
Thereafter		1,698				—				1,698
Total lease payments		18,993				4,959				23,952
Less: Interest and discount		(1,890		)		(357		)		(2,247		)
Present value of lease liabilities		$	17,103			$	4,602			$	21,705

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

	Year Ended December 31,
	2019				2018
	(in thousands)
Beginning balance	$	115,021			$	87,306
Obligations incurred with development activities	4,605				2,793
Obligations incurred with acquisition	2,882				4,332
Accretion expense	6,117				5,075
Revisions in estimated cash flows	28,991				30,166
Obligations discharged with asset retirements	(23,426		)		(14,651		)
Obligations discharged with divestitures	(6,939		)		—
Balance at December 31	127,251				115,021
Liabilities held-for-sale	—				(4,111		)
Current portion	(32,200		)		(25,598		)
Long-term portion	$	95,051			$	85,312

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 and purchased from third parties and other third-party working, royalty and overriding royalty interest owners, whose volumes we market on their behalf. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered.

        

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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:

		Year Ending December 31,
Area		2020				2021				2022				2023				Thereafter				Total				Expiration Date
Natural gas (MMcf)
Wattenberg Field		30,608				31,025				31,025				31,025				63,992				187,675				August 31, 2026
Delaware Basin		37,552				28,241				9,125				9,125				66,175				150,218				March 31, 2031
Gas Marketing		7,136				7,056				4,495				—				—				18,687				August 31, 2022
Total		75,296				66,322				44,645				40,150				130,167				356,580
Crude oil (MBbls)
Wattenberg Field		9,992				16,243				16,243				12,567				37,255				92,300				December 31, 2027
Delaware Basin		8,784				8,030				8,030				8,030				—				32,874				December 31, 2023
Total		18,776				24,273				24,273				20,597				37,255				125,174
Water (MBbls)
Wattenberg Field		6,224				6,207				6,207				6,206				6,223				31,067				December 31, 2024
Total		6,224				6,207				6,207				6,206				6,223				31,067
Dollar commitment (in thousands)		$	85,159			$	106,322			$	101,107			$	85,774			$	202,532			$	580,894

    

Wattenberg Field. We have entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018 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. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. We are currently satisfying the volume commitment.

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 of crude oil 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 2019, amounts related to long-term transportation volumes, net to our interest, for Wattenberg Field crude oil and Delaware Basin natural gas were $50.1 million and in accordance with the guidance in the New Revenue Standard, were netted against our crude oil and natural gas sales. In addition, for 2019 and 2018, $1.9 million and $1.6 million, respectively, related to long-term transportation volumes were recorded in transportation, gathering and processing expense. Amounts related to long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas of $10.0 million for 2017 were recorded in transportation, gathering and processing expense. In March 2018, we completed the disposition of our Utica Shale properties.

Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.

    

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Action Regarding Partnerships. In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al. (the "Dufresne Case"), filed in the United States District Court for the District of Colorado (the "District Court"). The original complaint stated that it was a derivative action brought by a number of limited partner investors seeking to assert claims for breach of fiduciary duties on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP (collectively, the "Partnerships"), against PDC. The complaint was subsequently amended to include putative class claims for breach of the partnership agreements. The plaintiffs also included claims against two of our senior officers and three independent members of the Board for allegedly aiding and abetting PDC's purported breach of fiduciary duty. We filed a motion to dismiss on July 31, 2018. On February 19, 2019, the District Court granted the motion to dismiss, in part. It dismissed all claims against the individuals named as defendants. It also held that that the plaintiffs were time-barred from using the failure to assign acreage to the Partnerships as grounds to support their claims for breach of fiduciary duty against PDC. On June 4, 2019, the District Court entered an order holding its opinion on the motion to dismiss in abeyance pending resolution of the Partnerships' bankruptcy cases and staying the litigation. As discussed in more detail below, the District Court in Colorado has dismissed the Dufresne Case.

Partnership Bankruptcy Filings. On October 30, 2018, the Partnerships filed petitions under Chapter 11 of the Bankruptcy Code (the "Chapter 11 Proceedings") in the United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"). Prior to the bankruptcy filings, PDC designated a third-party (the “Responsible Party”) to analyze strategic options for the Partnerships. After designation of the Responsible Party and before filing the Chapter 11 Proceedings, PDC and the Partnerships agreed to enter into a transaction pursuant to which PDC would acquire substantially all of the Partnerships’ assets through a Chapter 11 plan of liquidation and obtain a release of claims from the Partnerships, including the claims asserted in the Dufresne Case. In June 2019, the Responsible Party, PDC and the plaintiffs in the Dufresne Case reached a settlement of the matters raised in the Dufresne Case and the Chapter 11 Proceedings. The settlement, which settles all claims asserted against PDC, whether direct or derivative, including, but not limited to, the claims asserted in the Dufresne Case, was incorporated into an Amended Chapter 11 Plan (the “Amended Chapter 11 Plan”). The Disclosure Statement accompanying the Amended Chapter 11 Plan was approved by the Bankruptcy Court in August 2019 along with procedures for soliciting votes on the Amended Chapter 11 Plan. The Amended Chapter 11 Plan was distributed to the Partnership unit holders for voting. On October 2, 2019, the Bankruptcy Court held a hearing to consider confirmation of the Amended Chapter 11 Plan and, on October 3, 2019, entered an order confirming the Amended Chapter 11 Plan. The requirements for the Amended Chapter 11 Plan to become effective were met on October 21, 2019 (the “Effective Date”). As contemplated by the Amended Chapter 11 Plan, on the Effective Date, PDC funded the settlement payment, purchase price for the Partnership’s oil and gas assets and the administrative reserve. Additionally, the Partnership’s oil and gas assets were conveyed to PDC and PDC and the plaintiffs in the Dufresne Case submitted an agreed order dismissing the Dufresne Case with prejudice to the District Court. The District Court entered the agreed order on October 23, 2019, dismissing the Dufresne Case with prejudice. On December 5, 2019, the Bankruptcy Court entered orders approving final fee applications of the debtors' legal representatives and professional service providers, which were paid before the end of 2019, along with distributions of the settlement amount pursuant to the Amended Chapter 11 Plan to the Partnership unit holders.

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 December 31, 2019 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses. The liability ultimately incurred with respect to a matter may exceed the related accrual.

On October 23, 2018, we agreed to an Administrative Order by Consent ("AOC") with the Colorado Oil and Gas Conservation Commission relating to a historical release discovered during the decommissioning of a location in Weld County, Colorado, pursuant to which, among other things, we agreed to a penalty of approximately $130,000, of which 20 percent would be suspended subject to compliance with certain corrective actions identified in the AOC. In addition to the penalty, we agreed to timely complete certain corrective actions set forth in the AOC relating to procedures for completing future work on buried or partially buried produced water vessels, and to reestablish vegetation and otherwise reclaim the location. We have completed the corrective actions in a timely manner and some of our reclamation activities are ongoing.

    

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,

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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. We do not believe potential penalties and other expenditures associated with this disclosure will have a material effect on our financial condition or results of operations, but they may exceed $100,000.

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. Additionally, we are subject to the revised requirements of the COC entered into by SRC with CDPHE as described in "Risk Factors -We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business." We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements.

We are in the process of implementing the consent decree program, recently expanded to include the COC. Over the course of its execution, we have identified certain immaterial deficiencies in our implementation of the program. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $100,000. 

In addition, in December 2018, we were named as a nominal defendant in a derivative action filed in the Delaware chancery court. The complaint, which seeks unspecified monetary damages and various forms of equitable relief, alleges that certain current and former members of the Board violated their fiduciary duties, committed waste and were unjustly enriched by, among other things, failing to implement adequate environmental safeguards in connection with the issues that gave rise to the Department of Justice lawsuit and consent decree. We believe that this lawsuit is without merit but cannot predict its outcome.

Further, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations.

 

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Stock-Based Compensation Plans

2018 Equity Incentive Plan. In May 2018, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the “2018 Plan”). The 2018 Plan provides for a reserve of 1,800,000 shares of our common stock that may be issued pursuant to awards under the 2018 Plan and a term that expires in March 2028. Shares issued may be either authorized but unissued shares, treasury shares or any combination. Additionally, the 2018 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or paid out in the form of cash. However, shares tendered or withheld to satisfy the exercise price of options or tax withholding obligations, and shares covering the portion of exercised stock-settled stock appreciation rights ("SARs") (regardless of the number of shares actually delivered), count against the share limit. Awards may be issued in the form of options, SARs, restricted stock, restricted stock units ("RSUs"), performance stock units ("PSUs") and other stock-based awards. Awards may vest over periods of continued service or the satisfaction of performance conditions set at the discretion of the Compensation Committee of 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. We began issuing shares from the 2018 Plan during 2019. As of December 31, 2019, there were 1,429,004 shares available for grant under the 2018 Plan.

    

2010 Long-Term Equity Compensation Plan. Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was most recently approved by stockholders in 2013 (as the same has been amended and restated from time to time, the "2010 Plan"), will remain outstanding and we may continue to use the 2010 Plan to grant awards. As of December 31, 2019, there were 133,330 shares available for grant under the 2010 Plan. 

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:

		Year Ended December 31,
		2019				2018				2017
		(in thousands)
Stock-based compensation expense		$	23,837			$	21,782			$	19,353
Income tax benefit		(5,780		)		(5,210		)		(7,372		)
Net stock-based compensation expense		$	18,057			$	16,572			$	11,981

    

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 2019:

	Shares			Weighted-Average Grant Date Fair Value per Share
Non-vested at December 31, 2018	618,407			$	54.16
Granted	588,899			40.34
Vested	(307,450	)		52.98
Forfeited	(103,930	)		45.62
Non-vested at December 31, 2019	795,926			45.51

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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/Year Ended December 31,
	2019				2018				2017
	(in thousands, except per share data)
Total intrinsic value of time-based awards vested	$	11,652			$	12,282			$	16,303
Total intrinsic value of time-based awards non-vested	20,829				18,404				24,334
Market price per share as of December 31,	26.17				29.76				51.54
Weighted-average grant date fair value per share	40.34				50.69				65.14

Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2019 was $21.4 million. This cost is expected to be recognized over a weighted-average period of 1.7 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 139,197 market-based PSUs to our executive officers during 2019. In addition to continuous employment, the vesting of these PSUs is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2021, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between zero and 200 percent of the target PSUs awarded. The weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions:

		Year Ended December 31,
		2019			2018			2017
Expected term of award (in years)		3			3			3
Risk-free interest rate		2.5	%		2.4	%		1.4	%
Expected volatility		41.4	%		42.3	%		51.4	%

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 2019:

		Shares			Weighted-Average Grant Date Fair Value per Share
Non-vested at December 31, 2018		102,914			$	74.88
Granted		139,197			56.68
Vested		(20,969	)		94.02
Forfeited		—			—
Non-vested at December 31, 2019		221,142			61.61

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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/Year Ended December 31,
	2019				2018				2017
	(in thousands, except per share data)
Total intrinsic value of market-based awards vested	$	530			$	620			$	2,687
Total intrinsic value of market-based awards non-vested	5,787				3,063				2,698
Market price per share as of December 31,	26.17				29.76				51.54
Weighted-average grant date fair value per share	56.68				69.98				94.02

Total compensation cost related to non-vested market-based awards not yet recognized in our consolidated statements of operations as of December 31, 2019 was $7.5 million. This cost is expected to be recognized over a weighted-average period of 1.6 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 Compensation Committee awarded SARs to our executive officers in 2017. There were no SARs awarded to our executive officers in 2018 or 2019. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions:

            

	Year Ended December 31, 2017
Expected term of award (in years)	6
Risk-free interest rate	2.0		%
Expected volatility	53.3		%
Weighted-average grant date fair value per share	$	38.58

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.

    

The following table presents the changes in our SARs for all periods presented (in thousands, except per share data):

	Year Ended December 31,
	2019														2018											2017
	Number of SARs			Weighted-Average Exercise Price				Average Remaining Contractual Term (in years)			Aggregate Intrinsic Value				Number of SARs			Weighted-Average Exercise Price				Aggregate Intrinsic Value				Number of SARs			Weighted-Average Exercise Price				Aggregate Intrinsic Value
Outstanding at January 1,	290,258			$	46.64			4.6			$	125			298,220			$	47.39			$	2,490			244,078			$	41.36			$	7,620
Awarded	—			—				—			—				—			—				—				54,142			74.57				—
Modified	—			—				—			—				63,969			42.83				—				—			—				—
Expired	—			—				—			—				(71,931	)		46.34				—				—			—				—
Outstanding at December 31,	290,258			46.64				3.6			41				290,258			46.64				125				298,220			47.39				2,490
Exercisable at December 31,	276,775			45.28				3.4			41				260,101			44.88				125				223,865			43.28				2,267

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We expect all SARs outstanding as of December 31, 2019 to vest in 2020. The SARS modified during 2018, as included in the table above, were related to one employee and the total compensation cost associated with the modification was not material to our consolidated statement of operations. Total compensation cost related to SARs granted and not yet recognized in our consolidated statements of operations as of December 31, 2019 is not material and will be recognized within the next twelve months.

Preferred stock

The table below presents the components of our provision for income tax (expense) benefit for the years presented:

	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Current:
Federal	$	1,366			$	887			$	8,443
State	(300		)		(188		)		(200		)
Total current income tax benefit	1,066				699				8,243
Deferred:
Federal	4,507				(1,986		)		193,809
State	(2,251		)		(4,119		)		9,876
Total deferred income tax (expense) benefit	2,256				(6,105		)		203,685
Income tax (expense) benefit	$	3,322			$	(5,406	)		$	211,928

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The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes:

	Year Ended December 31,
	2019			2018			2017
Federal statutory tax rate	21.0	%		21.0	%		35.0	%
State income tax, net	3.6			(6.4	)		1.8
Federal tax credits	(3.3	)		(52.1	)		—
Effect of state income tax rate changes	(6.4	)		6.7			—
Change in valuation allowance	(0.6	)		45.5			—
Non-deductible compensation	(5.0	)		21.8			(0.3	)
Non-deductible acquisition costs	(2.3	)		—			—
Non-deductible government relations	(1.0	)		31.8			—
Other non-deductible items	(0.5	)		4.9			—
Federal tax reform rate reduction	—			—			33.7
Non-deductible goodwill impairment	—			—			(7.7	)
Other	—			(0.4	)		(0.1	)
Effective tax rate	5.5	%		72.8	%		62.4	%

Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2019 and 2018 are presented below.

	As of December 31,
	2019				2018
	(in thousands)
Deferred tax assets:
Deferred compensation	$	9,905			$	9,963
Asset retirement obligations	30,993				27,166
Federal NOL carryforward	22,965				54,736
State NOL and tax credit carryforwards, net	9,508				13,223
Federal tax - credit carryforwards	4,448				7,756
Prepaid revenue	4,874				5,288
Other	3,887				4,647
Valuation allowance	(3,775		)		(3,380		)
Total gross deferred tax assets	82,805				119,399
Deferred tax liabilities:
Properties and equipment	268,234				270,565
Net change in fair value of unsettled derivatives	6,841				41,496
Convertible debt	3,571				5,434
Total gross deferred tax liabilities	278,646				317,495
Net deferred tax liability	$	195,841			$	198,096

As of December 31, 2019, we have prior year federal NOL carryforwards of $175.7 million of which $31.5 million will begin to expire in 2036. Also, we acquired a federal NOL of $60.1 million as a component of our 2016 acquisition in the Delaware Basin that will begin to expire in 2034 and is subject to an annual limitation of $15.1 million as a result of the acquisition, which constitutes a change of ownership as defined under IRS Code Section 382. We expect to utilize $126.4 million of these NOLs to offset current federal taxable income.

As of December 31, 2019, we have state NOL carryforwards of $265.9 million that begin to expire in 2030 and state credit carryforwards of $4.0 million that begin to expire in 2022. We expect to utilize $98.0 million of these NOLs to offset current state taxable income. Due to the potential non-utilization of our state tax credit carryforwards before their expiration, we have recorded a valuation allowance for the future tax benefit of these credit carryforwards.

Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2019. The statutes of limitations for most of our state tax jurisdictions are open for tax year 2015 forward.

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The IRS partially accepted our 2018 tax return. The 2018 tax return is in the IRS CAP Program post-filing review process, with no significant tax adjustments currently proposed. We continue to voluntarily participate in the IRS CAP Program for the 2019 and 2020 tax years. 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 restricted stock, outstanding SARs, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive.

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

	Year Ended December 31,
	2019			2018			2017
	(in thousands)
Weighted-average common shares outstanding - basic	64,032			66,059			65,837
Dilutive effect of:
RSUs and PSUs	—			173			—
Other equity-based awards	—			71			—
Weighted-average common shares and equivalents outstanding - diluted	64,032			66,303			65,837

For 2019 and 2017, we reported a net loss. 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:

	Year Ended December 31,
	2019			2018			2017
	(in thousands)
Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
RSUs and PSUs	989			145			590
Other equity-based awards	302			109			75
Total anti-dilutive common share equivalents	1,291			254			665

The 2021 Convertible Notes give the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $85.39 conversion price during the periods presented. During 2019, 2018 and 2017, the average market price of our common stock did not exceed the conversion price; therefore, shares issuable upon conversion of the 2021 Convertible Notes were not included in the diluted earnings per share calculation.

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		Year Ended December 31,
		2019				2018 (1)				2017 (1)
		(in thousands)
Supplemental cash flow information:
Cash payments (receipts) for:
Interest, net of capitalized interest		$	57,439			$	55,586			$	69,880
Income taxes		(1,167		)		(6,719		)		(13,925		)
Non-cash investing and financing activities:
Change in accounts payable related to capital expenditures		(68,246		)		36,328				50,761
Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal		29,533				37,136				839
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		$	5,301			$	—			$	—
Operating cash flows from finance leases		253				—				—
Financing cash flows from finance leases		1,952				—				—
ROU assets obtained in exchange for lease obligations:
Operating leases		$	1,428			$	—			$	—
Finance leases		2,323				—				—

(1) As we have elected the modified retrospective method of adoption for the New Lease, cash flows related to lease liabilities

have not been restated for 2018 and 2017.

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PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the consolidating financial information separately for:

(i)	PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries;
(ii)	PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes;
(iii)	Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and
(iv)	Parent and subsidiaries on a consolidated basis ("Consolidated").

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

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

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		Consolidating Balance Sheets
		December 31, 2019
		Parent				Guarantor				Eliminations				Consolidated
		(in thousands)
Assets
Current assets:
Cash and cash equivalents		$	963			$	—			$	—			$	963
Accounts receivable, net		140,742				125,612				—				266,354
Fair value of derivatives		28,078				—				—				28,078
Prepaid expenses and other current assets		8,204				431				—				8,635
Total current assets		177,987				126,043				—				304,030
Properties and equipment, net		2,328,337				1,766,865				—				4,095,202
Intercompany receivable		348,818				—				(348,818		)		—
Investment in subsidiaries		1,286,931				—				(1,286,931		)		—
Fair value of derivatives		3,746				—				—				3,746
Other assets		38,863				6,839				—				45,702
Total Assets		$	4,184,682			$	1,899,747			$	(1,635,749	)		$	4,448,680
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable		$	72,212			$	26,722			$	—			$	98,934
Production tax liability		67,509				8,727				—				76,236
Fair value of derivatives		2,921				—				—				2,921
Funds held for distribution		83,072				15,321				—				98,393
Accrued interest payable		14,281				3				—				14,284
Other accrued expenses		68,803				1,659				—				70,462
Total current liabilities		308,798				52,432				—				361,230
Intercompany payable		—				348,818				(348,818		)		—
Long-term debt		1,177,226				—				—				1,177,226
Deferred income taxes		169,520				26,321				—				195,841
Asset retirement obligations		87,749				7,302				—				95,051
Fair value of derivatives		692				—				—				692
Other liabilities		105,190				177,943				—				283,133
Total liabilities		1,849,175				612,816				(348,818		)		2,113,173
Commitments and contingent liabilities
Stockholders' equity
Common shares		617				—				—				617
Additional paid-in capital		2,384,309				1,766,775				(1,766,775		)		2,384,309
Retained deficit		(47,945		)		(479,844		)		479,844				(47,945		)
Treasury shares		(1,474		)		—				—				(1,474		)
Total stockholders' equity		2,335,507				1,286,931				(1,286,931		)		2,335,507
Total Liabilities and Stockholders' Equity		$	4,184,682			$	1,899,747			$	(1,635,749	)		$	4,448,680

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		Consolidating Balance Sheets
		December 31, 2018
		Parent				Guarantor				Eliminations				Consolidated
		(in thousands)
Assets
Current assets:
Cash and cash equivalents		$	1,398			$	—			$	—			$	1,398
Accounts receivable, net		146,529				34,905				—				181,434
Fair value of derivatives		84,492				—				—				84,492
Prepaid expenses and other current assets		6,725				411				—				7,136
Total current assets		239,144				35,316				—				274,460
Properties and equipment, net		2,270,711				1,732,151				—				4,002,862
Assets held-for-sale, net		—				140,705				—				140,705
Intercompany receivable		451,601				—				(451,601		)		—
Investment in subsidiaries		1,316,945				—				(1,316,945		)		—
Fair value of derivatives		93,722				—				—				93,722
Other assets		30,084				2,312				—				32,396
Total Assets		$	4,402,207			$	1,910,484			$	(1,768,546	)		$	4,544,145
Liabilities and Stockholders' Equity
Liabilities
Current liabilities:
Accounts payable		$	110,847			$	71,017			$	—			$	181,864
Production tax liability		53,309				7,410				—				60,719
Fair value of derivatives		3,364				—				—				3,364
Funds held for distribution		90,183				15,601				—				105,784
Accrued interest payable		14,143				7				—				14,150
Other accrued expenses		73,689				1,444				—				75,133
Total current liabilities		345,535				95,479				—				441,014
Intercompany payable		—				451,601				(451,601		)		—
Long-term debt		1,194,876				—				—				1,194,876
Deferred income taxes		162,368				35,728				—				198,096
Asset retirement obligations		79,904				5,408				—				85,312
Liabilities held-for-sale		—				4,111				—				4,111
Fair value of derivatives		1,364				—				—				1,364
Other liabilities		91,452				1,212				—				92,664
Total liabilities		1,875,499				593,539				(451,601		)		2,017,437
Commitments and contingent liabilities
Stockholders' equity
Common shares		661				—				—				661
Additional paid-in capital		2,519,423				1,766,775				(1,766,775		)		2,519,423
Retained earnings (deficit)		8,727				(449,830		)		449,830				8,727
Treasury shares		(2,103		)		—				—				(2,103		)
Total stockholders' equity		2,526,708				1,316,945				(1,316,945		)		2,526,708
Total Liabilities and Stockholders' Equity		$	4,402,207			$	1,910,484			$	(1,768,546	)		$	4,544,145

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		Consolidating Statements of Operations
		Year Ended December 31, 2019
		Parent				Guarantor				Eliminations				Consolidated
		(in thousands)
Revenues
Crude oil, natural gas and NGLs sales		$	999,250			$	308,025			$	—			$	1,307,275
Commodity price risk management loss, net		(162,844		)		—				—				(162,844		)
Other income		10,972				720				—				11,692
Total revenues		847,378				308,745				—				1,156,123
Costs, expenses and other
Lease operating expenses		94,829				47,419				—				142,248
Production taxes		61,577				19,177				—				80,754
Transportation, gathering and processing expenses		23,719				22,634				—				46,353
Exploration, geologic and geophysical expense		1,111				2,943				—				4,054
General and administrative expense		144,345				17,408				—				161,753
Depreciation, depletion and amortization		451,282				192,870				—				644,152
Accretion of asset retirement obligations		5,446				671				—				6,117
Impairment of properties and equipment		292				38,244				—				38,536
(Gain) loss on sale of properties and equipment		(853		)		10,587				—				9,734
Other expenses		11,317				—				—				11,317
Total costs, expenses and other		793,065				351,953				—				1,145,018
Income (loss) from operations		54,313				(43,208		)		—				11,105
Interest expense		(75,257		)		4,086				—				(71,171		)
Interest income		71				1				—				72
Loss before income taxes		(20,873		)		(39,121		)		—				(59,994		)
Income tax (expense) benefit		(5,784		)		9,106				—				3,322
Equity in loss of subsidiary		(30,015		)		—				30,015				—
Net loss		$	(56,672	)		$	(30,015	)		$	30,015			$	(56,672	)

    

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		Consolidating Statements of Operations
		Year Ended December 31, 2018
		Parent				Guarantor				Eliminations				Consolidated
		(in thousands)
Revenues
Crude oil, natural gas and NGLs sales		$	1,050,696			$	339,265			$	—			$	1,389,961
Commodity price risk management gain, net		145,237				—				—				145,237
Other income		10,744				2,717				—				13,461
Total revenues		1,206,677				341,982				—				1,548,659
Costs, expenses and other
Lease operating expenses		92,228				38,729				—				130,957
Production taxes		67,819				22,538				—				90,357
Transportation, gathering and processing expenses		16,607				20,796				—				37,403
Exploration, geologic and geophysical expense		1,234				4,970				—				6,204
General and administrative expense		152,798				17,706				—				170,504
Depreciation, depletion and amortization		389,841				169,952				—				559,793
Accretion of asset retirement obligations		4,617				458				—				5,075
Impairment of properties and equipment		27				458,370				—				458,397
(Gain) loss on sale of properties and equipment		(4,387		)		4,781				—				394
Other expenses		11,829				—				—				11,829
Total costs, expenses and other		732,613				738,300				—				1,470,913
Income (loss) from operations		474,064				(396,318		)		—				77,746
Interest expense		(73,251		)		2,521				—				(70,730		)
Interest income		413				—				—				413
Income (loss) before income taxes		401,226				(393,797		)		—				7,429
Income tax (expense) benefit		(98,611		)		93,205				—				(5,406		)
Equity in loss of subsidiary		(300,592		)		—				300,592				—
Net income (loss)		$	2,023			$	(300,592	)		$	300,592			$	2,023

Net loss for the Guarantor for the year ended 2018 is primarily the result of impairment of certain unproved Delaware Basin leasehold positions.

    

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		Consolidating Statements of Operations
		Year Ended December 31, 2017
		Parent				Guarantor				Eliminations				Consolidated
		(in thousands)
Revenues
Crude oil, natural gas, and NGLs sales		$	788,400			$	124,684			$	—			$	913,084
Commodity price risk management loss, net		(3,936		)		—				—				(3,936		)
Other income		11,901				567				—				12,468
Total revenues		796,365				125,251				—				921,616
Costs, expenses and other
Lease operating expenses		68,031				21,610				—				89,641
Production taxes		53,236				7,481				—				60,717
Transportation, gathering and processing expenses		23,301				9,919				—				33,220
Exploration, geologic and geophysical expense		1,092				46,242				—				47,334
General and administrative expense		107,518				12,852				—				120,370
Depreciation, depletion and amortization		403,984				65,100				—				469,084
Accretion of asset retirement obligations		5,965				341				—				6,306
Impairment of properties and equipment		4,951				280,936				—				285,887
Impairment of goodwill		—				75,121				—				75,121
Gain on sale of properties and equipment		(766		)		—				—				(766		)
Provision for uncollectible notes receivable		(40,203		)		—				—				(40,203		)
Other expenses		13,157				—				—				13,157
Total costs, expenses and other		640,266				519,602				—				1,159,868
Income (loss) from operations		156,099				(394,351		)		—				(238,252		)
Loss on extinguishment of debt		(24,747		)		—				—				(24,747		)
Interest expense		(79,919		)		1,225				—				(78,694		)
Interest income		2,261				—				—				2,261
Income (loss) before income taxes		53,694				(393,126		)		—				(339,432		)
Income tax (expense) benefit		(33,643		)		245,571				—				211,928
Equity in loss of subsidiary		(147,555		)		—				147,555				—
Net loss		$	(127,504	)		$	(147,555	)		$	147,555			$	(127,504	)

Net loss for the Guarantor for the year ended 2017 is primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions and the impairment of goodwill.

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		Consolidating Statements of Cash Flows
		Year Ended December 31, 2019
		Parent				Guarantor				Eliminations				Consolidated
		(in thousands)
Cash flows from operating activities		$	579,464			$	278,762			$	—			$	858,226
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties		(485,725		)		(370,183		)		—				(855,908		)
Capital expenditures for other properties and equipment		(20,361		)		(478		)		—				(20,839		)
Acquisition of crude oil and natural gas properties		(12,141		)		(1,066		)		—				(13,207		)
Proceeds from sale of properties and equipment		399				1,706				—				2,105
Proceeds from divestiture		5,515				196,561				—				202,076
Restricted cash		8,001				—				—				8,001
Intercompany transfers		105,004				—				(105,004		)		—
Net cash from investing activities		(399,308		)		(173,460		)		(105,004		)		(677,772		)
Cash flows from financing activities:
Proceeds from revolving credit facility		1,577,000				—				—				1,577,000
Repayment of revolving credit facility		(1,605,500		)		—				—				(1,605,500		)
Payment of debt issuance costs		(72		)		—				—				(72		)
Purchase of treasury stock		(154,363		)		—				—				(154,363		)
Purchase of treasury shares for employee stock-based compensation tax withholding obligations		(4,003		)		—				—				(4,003		)
Principal payments under financing lease obligations		(1,654		)		(298		)		—				(1,952		)
Intercompany transfers		—				(105,004		)		105,004				—
Net cash from financing activities		(188,592		)		(105,302		)		105,004				(188,890		)
Net change in cash, cash equivalents and restricted cash		(8,436		)		—				—				(8,436		)
Cash, cash equivalents and restricted cash, beginning of period		9,399				—				—				9,399
Cash, cash equivalents and restricted cash, end of period		$	963			$	—			$	—			$	963

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		Consolidating Statements of Cash Flows
		Year Ended December 31, 2018
		Parent				Guarantor				Eliminations				Consolidated
		(in thousands)
Cash flows from operating activities		$	625,206			$	264,096			$	—			$	889,302
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties		(482,534		)		(463,816		)		—				(946,350		)
Capital expenditures for other properties and equipment		(9,806		)		(1,249		)		—				(11,055		)
Acquisition of crude oil and natural gas properties		(179,955		)		(71		)		—				(180,026		)
Proceeds from sale of properties and equipment		1,929				1,633				—				3,562
Proceeds from divestiture		44,693				—				—				44,693
Restricted cash		1,249				—				—				1,249
Intercompany transfers		(199,584		)		—				199,584				—
Net cash from investing activities		(824,008		)		(463,503		)		199,584				(1,087,927		)
Cash flows from financing activities:
Proceeds from revolving credit facility		1,072,500				—				—				1,072,500
Repayment of revolving credit facility		(1,040,000		)		—				—				(1,040,000		)
Payment of debt issuance costs		(7,704		)		—				—				(7,704		)
Purchase of treasury shares for employee stock-based compensation tax withholding obligations		(5,147		)		—				—				(5,147		)
Principal payments under financing lease obligations		(1,318		)		(177		)		—				(1,495		)
Other		(55		)		—				—				(55		)
Intercompany transfers		—				199,584				(199,584		)		—
Net cash from financing activities		18,276				199,407				(199,584		)		18,099
Net change in cash, cash equivalents and restricted cash		(180,526		)		—				—				(180,526		)
Cash, cash equivalents and restricted cash, beginning of period		189,925				—				—				189,925
Cash, cash equivalents and restricted cash, end of period		$	9,399			$	—			$	—			$	9,399

    

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		Consolidating Statements of Cash Flows
		Year Ended December 31, 2017
		Parent				Guarantor				Eliminations				Consolidated
		(in thousands)
Cash flows from operating activities		$	546,954			$	50,859			$	—			$	597,813
Cash flows from investing activities:
Capital expenditures for development of crude oil and natural gas properties		(439,897		)		(297,311		)		—				(737,208		)
Capital expenditures for other properties and equipment		(3,539		)		(1,555		)		—				(5,094		)
Acquisition of crude oil and natural gas properties		(21,000		)		5,372				—				(15,628		)
Proceeds from sale of properties and equipment		10,084				(93		)		—				9,991
Sale of promissory note		40,203				—				—				40,203
Restricted cash		(9,250		)		—				—				(9,250		)
Sales of short-term investments		49,890				—				—				49,890
Purchases of short-term investments		(49,890		)		—				—				(49,890		)
Intercompany transfers		(239,191		)		—				239,191				—
Net cash from investing activities		(662,590		)		(293,587		)		239,191				(716,986		)
Cash flows from financing activities:
Proceeds from issuance of senior notes		592,366				—				—				592,366
Redemption of senior notes		(519,375		)		—				—				(519,375		)
Payment of debt issuance costs		(50		)		—				—				(50		)
Purchase of treasury shares for employee stock-based compensation tax withholding obligations		(6,672		)		—				—				(6,672		)
Principal payments under financing lease obligations		(1,092		)		(76		)		—				(1,168		)
Other		(103		)		—				—				(103		)
Intercompany transfers		—				239,191				(239,191		)		—
Net cash from financing activities		65,074				239,115				(239,191		)		64,998
Net change in cash, cash equivalents and restricted cash		(50,562		)		(3,613		)		—				(54,175		)
Cash, cash equivalents and restricted cash, beginning of period		240,487				3,613				—				244,100
Cash, cash equivalents and restricted cash, end of period		$	189,925			$	—			$	—			$	189,925

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Net Proved Reserves

All of our crude oil, natural gas and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas and NGLs reserves. As of December 31, 2019, 2018 and 2017 (as applicable), all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott and NSAI prepared the reserve reports for the Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves are those quantities of crude oil, natural gas and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement that they be scheduled to be drilled within five years of each location’s initial booking date.

The indicated index prices for our reserves, by commodity, are presented below.

		Average Benchmark Prices (1)
As of December 31,		Crude Oil (per Bbl) (2)				Natural Gas (per Mcf) (2)				NGLs (per Bbl) (3)
2019		$	55.69			$	2.58			$	55.69
2018		65.56				3.10				65.56
2017		51.34				2.98				51.34

The netted back price used to estimate our reserves, by commodity, are presented below.

		Price Used to Estimate Reserves (4)
As of December 31,		Crude Oil (per Bbl)				Natural Gas (per Mcf)				NGLs (per Bbl)
2019		$	52.63			$	1.50			$	12.21
2018		61.14				2.15				23.04
2017		48.68				2.31				20.21

(1)	Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months.

(2) Our benchmark prices for crude oil and natural gas are WTI and Henry Hub, respectively.

(3)	For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes.

(4)	These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity.

    

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The following tables present the changes in our estimated quantities of proved reserves:

	Crude Oil, Condensate (MBbls)			Natural Gas (MMcf)			NGLs (MBbls)			Total (MBoe)
Proved reserves, January 1, 2017	118,169			833,697			84,288			341,407
Revisions of previous estimates	28,334			96,119			8,104			52,457
Extensions, discoveries and other additions	2,923			11,541			1,158			6,005
Acquisition of reserves	18,971			289,223			19,604			86,778
Dispositions	(653	)		(4,597	)		(481	)		(1,900	)
Production	(12,902	)		(71,689	)		(6,981	)		(31,830	)
Proved reserves, December 31, 2017	154,842			1,154,294			105,692			452,917
Revisions of previous estimates	26,548			94,738			12,674			55,011
Extensions, discoveries and other additions	8,786			61,750			8,868			27,946
Acquisition of reserves	19,644			148,674			15,936			60,360
Dispositions	(2,507	)		(35,750	)		(2,656	)		(11,121	)
Production	(16,964	)		(88,017	)		(8,527	)		(40,160	)
Proved reserves, December 31, 2018	190,349			1,335,689			131,987			544,953
Revisions of previous estimates	25,875			328,290			31,559			112,147
Extensions, discoveries and other additions	1,056			10,262			1,519			4,285
Acquisition of reserves	553			4,558			448			1,761
Dispositions	(1,412	)		(5,052	)		(614	)		(2,868	)
Production	(19,166	)		(115,950	)		(10,923	)		(49,414	)
Proved reserves, December 31, 2019	197,255			1,557,797			153,976			610,864

Proved developed reserves, as of:
December 31, 2017	46,862			365,332			35,220			142,971
December 31, 2018	61,821			443,151			43,856			179,535
December 31, 2019	66,211			554,234			55,411			213,994
Proved undeveloped reserves, as of:
December 31, 2017	107,980			788,962			70,472			309,946
December 31, 2018	128,528			892,538			88,131			365,418
December 31, 2019	131,044			1,003,563			98,565			396,870

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	Developed			Undeveloped			Total
	(MBoe)
Proved reserves, January 1, 2017	98,285			243,122			341,407
Revisions of previous estimates	18,291			34,166			52,457
Extensions, discoveries and other additions	2,292			3,713			6,005
Acquisition of reserves	1,305			85,473			86,778
Dispositions	(20	)		(1,880	)		(1,900	)
Production	(31,830	)		—			(31,830	)
Undeveloped reserves converted to developed	54,648			(54,648	)		—
Proved reserves, December 31, 2017	142,971			309,946			452,917
Revisions of previous estimates	6,284			48,727			55,011
Extensions, discoveries and other additions	7,874			20,072			27,946
Acquisition of reserves	8,758			51,602			60,360
Dispositions	(4,486	)		(6,635	)		(11,121	)
Production	(40,160	)		—			(40,160	)
Undeveloped reserves converted to developed	58,294			(58,294	)		—
Proved reserves, December 31, 2018	179,535			365,418			544,953
Revisions of previous estimates	27,452			84,695			112,147
Extensions, discoveries and other additions	4,285			—			4,285
Acquisition of reserves	441			1,320			1,761
Dispositions	(474	)		(2,394	)		(2,868	)
Production	(49,414	)		—			(49,414	)
Undeveloped reserves converted to developed	52,169			(52,169	)		—
Proved reserves, December 31, 2019	213,994			396,870			610,864

2019 Activity. During 2019, we increased proved reserves by 65.9 MMBoe, or 12 percent, relative to December 31, 2018. The increase in proved reserves was primarily the result of our 2019 development activities and our future drilling schedule. In 2019, we produced 49.4 MMboe.

Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 17.3 MMBoe due to a decrease in operating costs, performance revisions and other items. We also experienced an additional increase of 10.2 MMBoe in proved developed reserves related to our current year drilling activities. These net positive revisions were partially offset by a decrease in prices for crude oil, natural gas and NGLs.

Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 74.2 MMBoe reflecting additional locations on proven acreage resulting from our drilling plan. Other changes impacting the increase were due to commodity pricing, lease operating expenses and type curve revisions, which resulted in further upward revisions of 23.4 MMBoe of PUD reserves. Partially offsetting this increase was a negative revision of 12.9 MMBoe due to drilling schedule changes.

Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed activity for 2019 included the addition of 4.3 MMBoe of developed reserves related to three gross (three net) newly-drilled wells.

Extensions, Discoveries and Other Additions-PUDs. There were no extensions, discoveries or other additions for PUD reserves during 2019.

Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and acquisitions were 0.4 MMBoe during 2019.

Acquisitions of Reserves-PUDs. We acquired 1.3 MMBoe of PUD reserves in 2019 in acreage swaps and acquisitions.

Dispositions-Proved Developed Reserves. Dispositions of 0.5 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps.

Dispositions-PUDs. Dispositions of 2.4 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps.

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At December 31, 2018, we projected a PUD reserve conversion rate of 16 percent for 2019. During 2019, a smaller number of wells were turned-in-line than we anticipated, resulting in an actual conversion rate of 14 percent. We converted 52.2 MMBoe of PUD reserves at December 31, 2018 to proved developed reserves as of December 31, 2019.

Based on economic conditions on December 31, 2019, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2019, our 2020 PUD reserve conversion rate is expected to be approximately 26 percent. The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities.

2018 Activity. During 2018, we increased proved reserves by 92.0 MMBoe, or 20 percent, relative to December 31, 2017. The increase in proved reserves was primarily a result of acreage exchange transactions and acquisitions in the Wattenberg Field and reserve additions on proved acreage resulting from our 2018 development activities. In 2018, we produced 40.2 MMboe.

    

Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 11.4 MMBoe due to an increase in prices for crude oil, natural gas and NGLs, offset by net negative revisions of 5.1 MMBoe for an increase in operating costs, performance revisions and other items.

Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 71.7 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 26.8 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2018 acreage exchanges, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and type curve revisions, which resulted in further upward revisions of 3.8 MMBoe of PUD reserves.

Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2018 included the addition of 7.9 MMBoe of developed reserves related to 17 gross (9.2 net) newly-drilled wells.

Extensions, Discoveries and Other Additions-PUDs. PUD activity was comprised primarily of 20.1 MMBoe of PUD reserves related to 16 gross (15.0 net) PUD locations in the Delaware Basin.

Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and an acquisition were 8.8 MMBoe during 2018.

Acquisitions of Reserves-PUDs. We acquired 47.6 MMBoe and 4.0 MMBoe of PUD reserves in 2018 in acreage swaps and an acquisition, respectively.

Dispositions-Proved Developed Reserves. Dispositions of 4.5 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps.

Dispositions-PUDs. Dispositions of 6.6 MMBoe reflect that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2017 in the acreage swap transactions.

At December 31, 2017, we projected a PUD reserve conversion rate of 16 percent for 2018. During 2018, a larger number of wells were turned-in-line than we anticipated, resulting in an actual conversion rate of 19 percent. We converted 58.3 MMBoe of PUD reserves at December 31, 2017 to proved developed reserves as of December 31, 2018.

2017 Activity. During 2017, we increased proved reserves by 111.5 MMBoe, or 33 percent, relative to December 31, 2016. The increase in proved reserves was primarily a result of an increase in acquisitions and reserve additions on proved acreage in the Delaware Basin from our 2017 development plan. In 2017, we produced 31.8 MMBoe.

Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 17.7 MMBoe due to an increase in prices for crude oil, natural gas and NGLs and net positive revisions of 0.6 MMBoe reflecting changes in operating costs, performance revisions and other items.

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Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 89.8 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 58.5 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2017 acreage swaps, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and other, which resulted in further upward revisions of 2.9 MMBoe of PUD reserves.

Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2017 included the addition of 2.3 MMBoe of developed reserves related to newly-drilled wells.

Extensions, Discoveries and Other Additions-PUDs. PUD activity was comprised primarily of 3.7 MMBoe of PUD locations in the Delaware Basin.

Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps were 1.3 MMBoe during 2017.

    

Acquisitions of Reserves-PUDs. We acquired 85.5 MMBoe of PUD reserves in 2017 in acreage swaps.

Dispositions-Proved Developed Reserves. Dispositions were related to acreage surrendered in various acreage swaps.

Dispositions-PUDs. Dispositions of PUDs were 1.9 MMBoe, reflecting the fact that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2016 in the acreage swap transactions.

At December 31, 2016, we projected a PUD reserve conversion rate of 26 percent for 2017. As a result of drilling plans being extended in our Delaware Basin in the first half of 2017, our actual conversion rate was 23 percent, resulting in 54.6 MMBoe of reserves recorded as PUDs at December 31, 2016, being converted to proved developed reserves as of December 31, 2017.

Results of Operations for Crude Oil and Natural Gas Producing Activities

The results of operations for crude oil and natural gas producing activities are presented below.

	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Revenue:
Crude oil, natural gas and NGLs sales	$	1,307,275			$	1,389,961			$	913,084
Commodity price risk management gain (loss), net	(162,844		)		145,237				(3,936		)
	1,144,431				1,535,198				909,148
Expenses:
Lease operating expenses	142,248				130,957				89,641
Production taxes	80,754				90,357				60,717
Transportation, gathering and processing expenses	46,353				37,403				33,220
Exploration expense	4,054				6,204				47,334
Depreciation, depletion and amortization	638,499				551,265				462,482
Accretion of asset retirement obligations	6,117				5,075				6,306
Impairment of properties and equipment	38,536				458,397				285,887
(Gain) loss on sale of properties and equipment	9,734				394				(766		)
	966,295				1,280,052				984,821
Results of operations for crude oil and natural gas producing activities before income taxes	178,136				255,146				(75,673		)
Income tax (expense) benefit	(9,869		)		(185,667		)		47,247
Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs	$	168,267			$	69,479			$	(28,426	)

    

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Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates.

Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below.

	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Acquisition of properties: (1)
Proved properties	$	16,007			$	205,253			$	172
Unproved properties	9,567				5,477				18,914
Development costs (2)	780,851				970,970				688,165
Exploration costs: (3)
Exploratory drilling	32,218				36,704				80,103
Geological and geophysical	3,017				3,401				3,881
Total costs incurred (4)	$	841,660			$	1,221,805			$	791,235

(1)	Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property.

(2)

Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2019, 2018 and 2017, $308.9 million, $438.4 million and $463.4 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $35.3 million, $74.6 million and $32.8 million of infrastructure and pipeline costs in 2019, 2018 and 2017 respectively.

(3)	Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells.

(4)	During 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved undeveloped and development costs of $24.6 million. We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017.

Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities

Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below:

	As of December 31,
	2019				2018
	(in thousands)
Proved crude oil and natural gas properties	$	6,241,780			$	5,452,613
Unproved crude oil and natural gas properties	403,379				492,594
Uncompleted wells, equipment and facilities	382,409				332,264
Capitalized costs	7,027,568				6,277,471
Less accumulated DD&A	(2,982,929		)		(2,341,897		)
Capitalized costs, net	$	4,044,639			$	3,935,574

    

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves

The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted

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by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties.

    

The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves.

	As of December 31,
	2019				2018				2017
	(in thousands)
Future estimated cash flows	$	14,590,604			$	17,554,880			$	12,340,407
Future estimated production costs (1)	(4,530,173		)		(4,782,948		)		(3,245,627		)
Future estimated development costs	(3,257,106		)		(3,632,822		)		(2,893,335		)
Future estimated income tax expense	(907,382		)		(1,404,121		)		(748,494		)
Future net cash flows	5,895,943				7,734,989				5,452,951
10% annual discount for estimated timing of cash flows	(2,585,609		)		(3,287,273		)		(2,572,846		)
Standardized measure of discounted future estimated net cash flows	$	3,310,334			$	4,447,716			$	2,880,105

(1) Represents future estimated lease operating expenses, production taxes and transportation, gathering and processing expenses.

    

The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows:

	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Beginning of period	$	4,447,716			$	2,880,105			$	1,420,629
Sales of crude oil, natural gas and NGLs production, net of production costs	(1,037,920		)		(1,131,244		)		(729,506		)
Net changes in prices and production costs (1)	(2,122,538		)		936,077				841,713
Extensions, discoveries and improved recovery, less related costs	39,606				190,084				47,240
Sales of reserves	(14,533		)		(42,362		)		(2,613		)
Purchases of reserves	18,816				467,807				224,483
Development costs incurred during the period	605,753				462,088				419,047
Revisions of previous quantity estimates	538,242				631,198				484,431
Changes in estimated income taxes	346,826				(232,002		)		(138,560		)
Net changes in future development costs	206,003				(123,663		)		25,183
Accretion of discount	532,127				583,744				167,487
Timing and other	(249,764		)		(174,116		)		120,571
End of period	$	3,310,334			$	4,447,716			$	2,880,105

(1)	Our weighted-average price, net of production costs per Boe, in our 2019 reserve report decreased to $16.18 as compared to $23.44 for 2018 and $20.08 for 2017.

    

The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of

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the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

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QUARTERLY FINANCIAL INFORMATION - UNAUDITED

Quarterly financial data for the years ended December 31, 2019 and 2018 is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year.

	2019
	Quarter Ended
	March 31				June 30				September 30				December 31
	(in thousands, except per share data)
Total revenues	$	134,500			$	390,658			$	365,943			$	265,022
Total costs, expenses and other	275,120				280,623				321,562				267,713
Income (loss) from operations	(140,620		)		110,035				44,381				(2,691		)
Income (loss) before income taxes	(157,588		)		91,135				26,570				(20,111		)
Net income (loss)	$	(120,176	)		$	68,548			$	15,908			$	(20,952	)
Earnings per share:
Basic	$	(1.82	)		$	1.04			$	0.25			$	(0.34	)
Diluted	(1.82		)		1.04				0.25				(0.34		)

	2018
	Quarter Ended
	March 31				June 30				September 30				December 31
	(in thousands, except per share data)
Total revenues	$	260,600			$	212,531			$	280,717			$	794,811
Total costs, expenses and other	260,924				400,770				270,593				538,626
Income (loss) from operations	(324		)		(188,239		)		10,124				256,185
Income (loss) before income taxes	(17,705		)		(205,580		)		(7,310		)		238,024
Net income (loss)	$	(13,139	)		$	(160,257	)		$	(3,434	)		$	178,853
Earnings per share:
Basic	$	(0.20	)		$	(2.43	)		$	(0.05	)		$	2.71
Diluted	(0.20		)		(2.43		)		(0.05		)		2.71

    

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Schedule II -VALUATION AND QUALIFYING ACCOUNTS

Description		Beginning Balance January 1,				Charged to Costs and Expenses				Deductions (1)				Ending Balance December 31,
		(in thousands)
2019:
Allowance for doubtful accounts		$	4,381			$	3,209			$	114			$	7,476
Allowance for expirations of unproved crude oil and natural gas properties		542,709				8,523				544,351				6,881
2018:
Allowance for doubtful accounts		3,128				1,276				23				4,381
Allowance for expirations of unproved crude oil and natural gas properties		251,159				388,068				96,518				542,709
2017:
Allowance for uncollectible notes		$	44,038			$	—			$	44,038			$	—
Allowance for doubtful accounts		2,190				1,108				170				3,128
Allowance for expirations of unproved crude oil and natural gas properties		359				263,817				13,017				251,159

(1)

For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset.

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