Certain information required by Items 10, 11, 12, 13, and 14 of Part III is incorporated by reference from portions of the registrant’s Definitive Proxy Statement on Schedule 14A relating to its 2020 annual meeting of stockholders to be filed within 120 days after December 31, 2019.

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•	the amount and nature of future capital expenditures and the availability of liquidity and capital resources to fund capital expenditures;

•	any changes to the borrowing base or aggregate lender commitments under our Sixth Amended and Restated Credit Agreement, as amended (the “Credit Agreement”);

•	our outlook on future crude oil, natural gas, and natural gas liquids (also respectively referred to as “oil,” “gas,” and “NGLs” throughout this document) prices, well costs, service costs, lease operating costs, and general and administrative costs;

•	the drilling of wells and other exploration and development activities, the ability to obtain permits and governmental approvals, and plans by us, our joint development partners, and/or other third-party operators;

•	possible or expected acquisitions and divestitures, including the possible divestiture or farm-down of, or joint venture relating to, certain properties;

•	oil, gas, and NGL reserve estimates and the estimates of both future net revenues and the present value of future net revenues associated with those reserve estimates;

•	future oil, gas, and NGL production estimates, identified drilling locations, as well as drilling prospects, inventories, projects and programs;

•	cash flows, anticipated liquidity, interest and related debt service expenses, changes in our effective tax rate, and the future repayment of debt;

•	business strategies and other plans and objectives for future operations, including plans for expansion and growth of operations or to defer capital investment, plans with respect to future dividend payments, and our outlook on our future financial condition or results of operations;

•	plans, objectives, expectations and intentions; and

•	other similar matters, such as those discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of this report.

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(1)	Amounts may not calculate due to rounding.

(2)	Regional costs incurred do not sum to total costs incurred due primarily to corporate overhead charges incurred on exploration activities that are excluded from this regional table. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

(3)	Costs incurred for 2019 included $11.3 million related to acquisitions of primarily unproved oil and gas properties in the Midland Basin. Please refer to Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

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(1)	Amounts may not calculate due to rounding.

(2)	For the years ended December 31, 2019, 2018, and 2017, proved gas reserves contained 44.9 Bcf, 59.1 Bcf, and 48.1 Bcf of gas, respectively, that we expect to produce and use as a field equipment fuel source (primarily to power compressors).

(3)	The prices used in the calculation of proved reserve estimates reflect the 12-month average of the first-day-of-the-month prices in accordance with SEC rules. We then adjust these prices to reflect appropriate quality and location differentials over the period in estimating our proved reserves.

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(1)	Amounts may not calculate due to rounding.

(2)	For each of the years ended December 31, 2019, 2018, and 2017, total estimated proved reserves attributed to our Midland Basin assets and our Eagle Ford shale assets exceeded 15 percent of our total estimated proved reserves expressed on an equivalent basis.

(3)	During the first quarter of 2017, we completed the divestiture of our outside-operated Eagle Ford shale assets. These assets represented approximately 1.5 MMBOE of net production on an equivalent basis for the year ended December 31, 2017.

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(1)	Developed acreage is acreage assigned to producing wells for the state approved spacing unit for the producing formation. Our developed acreage that includes multiple formations with different well spacing requirements may be considered undeveloped for certain formations but has been included only as developed acreage in the table above.

(2)	Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, gas, and/or NGLs regardless of whether such acreage contains estimated net proved reserves.

(3)

As of February 6, 2020, approximately 1,354, 184, and 155 net acres of undeveloped acreage are scheduled to expire by December 31, 2020, 2021, and 2022, respectively, if production is not established or we take no other action to extend the terms of the applicable leases. Certain of our Eagle Ford shale acreage is subject to lease consolidation agreements containing drilling, completion, and other obligations that we currently intend to satisfy. Failure to meet these obligations results in termination of the lease consolidation agreements, which could result in additional future lease expirations if continuous development obligations required by individual leases are not met.

(4)	As of December 31, 2019, total Midland Basin acreage excludes approximately 1,940 net acres associated with drill-to-earn opportunities that we intend to pursue.

(5)	Includes other non-core acreage located in Louisiana, Montana, North Dakota, Texas, Utah, and Wyoming.

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(1)	These major customers are purchasers of a portion of our production from our Midland Basin assets.

(2)	In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10 percent of our total oil, gas, and NGL production revenue.

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•	require the acquisition of various permits before drilling commences;

•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling and production and saltwater disposal activities;

•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including areas containing certain wildlife or threatened and endangered plant and animal species; and

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•	require remedial measures to mitigate pollution from former and ongoing operations, such as closing pits and plugging abandoned wells.

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•	global and domestic supplies of oil, gas, and NGLs, and the productive capacity of the industry as a whole;

•	the level of consumer demand for oil, gas, and NGLs;

•	overall global and domestic economic conditions;

•	weather conditions;

•	the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas;

•	liquefied natural gas deliveries to and from the United States;

•	the price and availability of alternative fuels;

•	technological advances and regulations affecting energy consumption and conservation;

•	the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to maintain effective oil price and production controls;

•	political instability or armed conflict in oil or gas producing regions;

•	actual or perceived epidemic risks, such as the Coronavirus outbreak in early 2020;

•	strengthening and weakening of the United States dollar relative to other currencies;

•	stockholder activism or activities by non-governmental organizations to limit sources of funding or restrict the exploration and production of oil, gas, and NGLs and related infrastructure; and

•	governmental regulations and taxes.

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•	the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

•	the liquidity available under our Credit Agreement could be reduced if any lender is unable to fund its commitment;

•	our ability or the ability of our suppliers or contractors to access the capital markets may be restricted or non-existent at a time when we or they would like, or need, to raise capital for our or their business, including for the exploration and/or development of reserves;

•	our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; and

•	variable interest rate spread levels, including for LIBOR (or any applicable replacement rate) and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate based borrowings under our Credit Agreement.

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•	limit our ability to access debt markets, including for the purpose of refinancing our existing debt;

•	cause us to refinance or issue debt with less favorable terms and conditions, which debt may restrict, among other things, our ability to make any dividend distributions or repurchase shares;

•	negatively impact current and prospective customers’ willingness to transact business with us;

•	impose additional insurance, guarantee and collateral requirements;

•	limit our access to bank and third-party guarantees, surety bonds and letters of credit; and

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•	cause our suppliers and financial institutions to lower or eliminate the level of credit provided through payment terms or intraday funding when dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay outstanding indebtedness.

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•	amount and timing of actual production;

•	supply and demand for oil, gas, and NGLs;

•	curtailments or increases in consumption by oil purchasers and gas pipelines;

•	changes in government regulations or taxes, including severance and excise taxes; and

•	escalations or reductions in service provider and equipment costs resulting from changes in supply and demand.

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•	unexpected adverse drilling or completion conditions;

•	title problems;

•	disputes with owners or holders of surface interests on or near areas where we operate;

•	pressure or geologic irregularities in formations;

•	engineering and construction delays;

•	equipment failures or accidents;

•	hurricanes, tornadoes, flooding, or other adverse weather conditions;

•	governmental permitting delays;

•	compliance with environmental and other governmental requirements; and

•	shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.

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•	our production is less than expected;

•	one or more counterparties to our commodity derivative contracts default on their contractual obligations; or

•	there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement.

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•	$476.8 million of long-term senior unsecured debt relating to our 6.125% Senior Notes due 2022 (“2022 Senior Notes”) that we issued on November 17, 2014;

•	$500.0 million of long-term senior unsecured debt relating to our 5.0% Senior Notes due 2024 (“2024 Senior Notes”) that we issued on May 20, 2013;

•	$500.0 million of long-term senior unsecured debt relating to our 5.625% Senior Notes due 2025 (“2025 Senior Notes”) that we issued on May 21, 2015;

•	$500.0 million of long-term senior unsecured debt relating to our 6.75% Senior Notes due 2026 (“2026 Senior Notes”) that we issued on September 12, 2016;

•	$500.0 million of long-term senior unsecured debt relating to our 6.625% Senior Notes due 2027 (“2027 Senior Notes”, and all senior notes collectively referred to as the “Senior Notes”) that we issued on August 20, 2018; and,

•	$172.5 million in aggregate principal amount of long-term senior unsecured convertible debt relating to our 1.50% Senior Convertible Notes due July 1, 2021 (“Senior Convertible Notes”) that we issued on August 12, 2016.

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•	making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements;

•	requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to productive investments;

•	limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends;

•	placing us at a competitive disadvantage compared to our competitors with less debt; and

•	making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.

•	incur additional debt;

•	make certain dividends or pay dividends or distributions on our capital stock or purchase, redeem, or retire common stock;

•	sell assets, including common stock of our subsidiaries;

•	restrict dividends or other payments of our subsidiaries;

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•	create liens that secure debt;

•	enter into transactions with affiliates; and

•	merge or consolidate with, or transfer or lease all or substantially all of our assets to another company.

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•	requirements for methane emission reductions from existing oil and gas equipment;

•	increased scrutiny for sources emitting high levels of methane, including during permitting processes;

•	analysis, regulation and reduction of methane emissions as a requirement for project approval; and

•	actions taken by one agency for a specific industry establishing precedents for other agencies and industry sectors.

•	changes in oil, gas, or NGL prices;

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•	changes in the outlook for regional, national, or global commodity supply and demand;

•	variations in drilling, recompletion, and operating activity;

•	changes in financial estimates by securities analysts;

•	changes in market valuations of comparable companies;

•	additions or departures of key personnel;

•	increased volatility due to the impacts of algorithmic trading practices;

•	future sales of our common stock;

•	changes in the national and global economic outlook, including potential impacts from trade agreements; and

•	international trade relationships, potentially including the effects of trade restrictions or tariffs affecting the raw materials we utilize and the commodities we produce in our business.

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(1)	All shares purchased by us in 2019 were to offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying Restricted Stock Units (“RSUs”) issued under the terms of award agreements granted under the SM Energy Equity Incentive Compensation Plan, as amended and restated effective as of May 22, 2018 (the “Equity Plan”).

(2)

In July 2006, our Board of Directors approved an increase in the number of shares that may be repurchased under the original August 1998 authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the filing of this report, subject to the approval of our Board of Directors, we may repurchase up to 3,072,184 shares of common stock on a prospective basis. The shares may be repurchased from time to time in open market transactions or privately negotiated transactions, subject to market conditions and other factors, including certain provisions of our Credit Agreement, the indentures governing our Senior Notes and Senior Convertible Notes, and compliance with securities laws. Stock repurchases may be funded with existing cash balances, internal cash flows, or borrowings under our Credit Agreement. The stock repurchase program may be suspended or discontinued at any time.

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(1)	Amounts may not calculate due to rounding.

(2)	As a result of adopting new accounting standards in prior periods, certain prior period amounts have been reclassified to conform to the current period presentation on the consolidated financial statements.

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net loss of $187.0 million, or $1.66 per diluted share, for the year ended December 31, 2019, compared with net income of $508.4 million, or $4.48 per diluted share, for the year ended December 31, 2018. Please refer to Comparison of Financial Results and Trends Between 2019 and 2018 and Between 2018 and 2017 below for additional discussion regarding the components of net income (loss) for each period presented;

•	net cash provided by operating activities was $823.6 million for the year ended December 31, 2019, compared with $720.6 million in 2018, which was an increase of 14 percent year-over-year. Please refer to Analysis of Cash Flow Changes Between 2019 and 2018 and Between 2018 and 2017 below for additional discussion; and

•	adjusted EBITDAX, a non-GAAP financial measure, for the year ended December 31, 2019, was $993.4 million, compared with $900.4 million for the same period in 2018. Please refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to our net income (loss) and net cash provided by operating activities.

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(1)	Includes adjustments related to previously drilled wells that we no longer intend to complete.

(1)	Please refer to the caption Costs Incurred in Oil and Gas Producing Activities in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

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(1)	Average OPIS prices per barrel of NGL, historical or strip, are based on a product mix of 37% Ethane, 32% Propane, 6% Isobutane, 11% Normal Butane, and 14% Natural Gasoline for all periods presented. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

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(1)	Amounts and percentage changes may not calculate due to rounding.

(2)	Derivative settlements for the years ended December 31, 2019, 2018, and 2017, are included within the net derivative (gain) loss line item in the accompanying consolidated statements of operations (“accompanying statements of operations”).

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(1)	We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.

(1)	We divested all remaining producing assets in the Rocky Mountain region in the first half of 2018. As a result, there have been no production volumes from this region after the second quarter of 2018.

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(1)	Long-term debt consists of the $122.5 million balance on our revolving credit facility, our Senior Notes, and our Senior Convertible Notes and assumes no principal repayment until the maturity dates of these instruments. The actual payment dates may vary significantly.

(2)

Interest payments on our Senior Notes and Senior Convertible Notes are estimated assuming no principal repayment until the maturity dates of these instruments. Interest payments on our credit facility have been estimated using the rate applicable to the outstanding balance on our credit facility as of December 31, 2019, and assume no future borrowings or repayments until the September 28, 2023 maturity date of the Credit Agreement. The actual interest payments on our Senior Notes, Senior Convertible Notes, and our credit facility may vary significantly.

(3)

Please refer to Note 6 – Commitments and Contingencies in Part II, Item 8 of this report for additional discussion regarding our operating leases, contracts, and gathering, processing, transportation throughput, and delivery commitments. The amount relating to our gathering, processing, transportation throughput, and delivery commitments reflects the aggregate undiscounted deficiency payments assuming we delivered no product. This amount does not include any costs that may be incurred for certain contracts where we cannot predict with accuracy the amount and timing of any payments that may be incurred for not meeting certain minimum commitments, as such payments are dependent upon the price of oil in effect at the time of settlement.

(4)

Amounts shown represent estimated future undiscounted plugging and abandonment costs. The discounted obligations are recorded as liabilities on our accompanying consolidated balance sheets (“accompanying balance sheets”) as of December 31, 2019. The timing and amount of the ultimate settlement of these obligations is unknown and can be impacted by economic factors, a change in development plans, and federal and state regulations. Please refer to Note 14 – Asset Retirement Obligations in Part II, Item 8 of this report for additional discussion.

(5)

Amounts shown represent only the liability portion of the marked-to-market value of our commodity derivatives based on future market prices as of December 31, 2019, and exclude estimated oil, gas, and NGL commodity derivative receipts. This amount varies from the liability amounts presented on the accompanying balance sheets, as those amounts are presented at fair value, which considers time value, volatility, and the risk of non-performance for us and for our counterparties. The ultimate settlement amounts under our derivative contracts are unknown, as they are subject to continuing market risk and commodity price volatility. Please refer to Note 10 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.

(6)	The majority of this amount is related to the unfunded portion of our estimated pension liability of $35.2 million, for which we have estimated the timing of future payments based on historical annual contribution amounts.

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(1)	The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated proved reserve volumes as of December 31, 2019, and does not include additional impacts to our estimated proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs.

(2)

The change solely reflects the impact of replacing SEC pricing with the five-year average NYMEX strip pricing as of December 31, 2019. SEC pricing of $55.69 per Bbl for oil, $2.58 per MMBtu for gas, and $22.68 per Bbl for NGLs as of December 31, 2019, compared to the five-year average NYMEX strip pricing of $53.65 per Bbl for oil, $2.42 per MMBtu for gas, and $19.67 per Bbl for NGLs as of December 31, 2019, would result in a one percent decrease to our total reported estimated proved reserve volumes.

(3)	The change solely reflects a 10 percent decrease in proved undeveloped reserves as of December 31, 2019, and does not include any additional impacts to our estimated proved reserves.

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(1)

Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

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(1)	Please refer to Note 8 – Pension Benefits for additional discussion on the pension liability adjustment.

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(1)	Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies for additional information.

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Note 1 – Summary of Significant Accounting Policies

Description of Operations

SM Energy Company, together with its consolidated subsidiaries, is an independent energy company engaged in the acquisition, exploration, development, and production of oil, gas, and NGLs in the state of Texas.

Basis of Presentation

The accompanying consolidated financial statements include the accounts of the Company and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated events subsequent to the balance sheet date of December 31, 2019, through the filing of this report. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the consolidated financial statements.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization expense, impairment of proved properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements.

Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

Accounts Receivable

The Company’s accounts receivable consists mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil, gas, and NGL receivables are collected within 30 to 90 days and the Company has had minimal bad debts.

Although diversified among many companies, collectibility is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. Please refer to Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses for additional disclosure.

Concentration of Credit Risk and Major Customers

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to regular review.

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The Company does not believe the loss of any single purchaser of its production would materially impact its operating results, as oil, gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating regions. The following major customers and entities under common control accounted for 10 percent or more of its total oil, gas, and NGL production revenue for at least one of the periods presented:

	For the Years Ended December 31,
	2019			2018			2017
Major customer #1 (1)	18	%		18	%		6	%
Major customer #2 (1)	14	%		5	%		1	%
Major customer #3 (1)	13	%		7	%		—	%
Major customer #4 (1)	9	%		10	%		10	%
Group #1 of entities under common control (2)	13	%		18	%		17	%
Group #2 of entities under common control (2)	11	%		12	%		8	%

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(1)	These major customers are purchasers of a portion of the Company’s production from its Midland Basin assets.

(2)	In the aggregate, these groups of entities under common control represented purchasers of more than 10 percent of total oil, gas, and NGL production revenue for at least one of the periods presented; however, no individual entity comprising either group was a purchaser of more than 10 percent of the Company’s total oil, gas, and NGL production revenue.

The Company generally contracts with the affiliates of the lenders under its Credit Agreement as its derivative counterparties, and the Company’s policy is that each counterparty must have investment grade senior unsecured debt ratings.

The Company maintains its primary bank accounts with a large, multinational bank that has branch locations in the Company’s areas of operations. The Company’s policy is to diversify its concentration of cash and cash equivalent investments among multiple institutions and investment products to limit the amount of credit exposure to any single institution or investment. The Company maintains investments in highly rated, highly liquid investment products with numerous banks that are party to its revolving credit facility.

Oil and Gas Producing Activities

Proved properties. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method, the costs of development wells are capitalized whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities in the field, are depleted on a group basis (properties aggregated based on geographical and geological characteristics) using the units-of-production method based on estimated proved developed oil and gas reserves. Similarly, proved leasehold costs are depleted on the same group asset basis; however, the units-of-production method is based on estimated total proved oil and gas reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment.

Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses an income valuation technique, which converts future cash flow to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts, as selected by the Company’s management. The Company uses discount rates that are representative of current market conditions and considers estimates of future cash payments, reserve categories, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The discount rates typically range from 10 percent to 15 percent based on the reservoir specific weightings of future estimated proved and unproved cash flows. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS pricing, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates.

The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties.

Unproved properties. The unproved oil and gas properties line item on the accompanying balance sheets consists of costs incurred to acquire unproved leases. Leasehold costs allocated to those leases, or partial leases that have associated proved reserves recorded, are reclassified to proved properties and depleted on a units-of-production basis. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. Lease acquisition costs that are not individually significant are aggregated by prospect and the portion of such costs estimated to be nonproductive prior to lease expiration are amortized over the appropriate period. The estimate of what could be nonproductive is based on historical trends or other information, including current drilling plans and the Company’s intent to renew leases. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant

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assumptions: remaining lease terms, future development plans, risk-weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants.

For the sale of unproved properties where the original cost has been partially or fully amortized by providing a valuation allowance on a group basis, neither a gain nor loss is recognized unless the sales price exceeds the original cost of the property, in which case a gain shall be recognized in the accompanying statements of operations in the amount of such excess.

Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory wells costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of capital expenditures within the accompanying statements of cash flows.

Other Property and Equipment

Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing, and installation activities. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from 3 to 30 years, or the unit of output method when appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Other property and equipment costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. To measure the fair value of other property and equipment, the Company uses an income valuation technique or market approach depending on the quality of information available to support management’s assumptions and the circumstances. The valuation includes consideration of the proved and unproved assets supported by the property and equipment, future cash flows associated with the assets, and fixed costs necessary to operate and maintain the assets.

Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties, including facilities requiring decommissioning. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired, or a facility is constructed. The increase in carrying value is included in the proved oil and gas properties line item in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the cash flows from operating activities section of the accompanying statements of cash flows.

The Company’s estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s plugging and abandonment liabilities range from 5.5 percent to 12 percent. In periods subsequent to initial measurement of the liability, the Company must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or economic life, or changes in inflation factors or the Company’s credit-adjusted risk-free rate as market conditions warrant. Please refer to Note 14 – Asset Retirement Obligations for a reconciliation of the Company’s total asset retirement obligation liability as of December 31, 2019, and 2018.

Derivative Financial Instruments

The Company periodically enters into commodity derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. These instruments typically include commodity price swaps and costless collars, as well as, basis differential swaps. Commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its derivative commodity contracts as hedging instruments. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its accompanying statements of operations as they occur. Gains and losses on derivatives

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are included within the cash flows from operating activities section of the accompanying statements of cash flows. For additional discussion on derivatives, please refer to Note 10 – Derivative Financial Instruments.

Revenue Recognition

The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized at the point in time when custody and title (“control”) of the product transfers to the purchaser, which may differ depending on the applicable contractual terms. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.

Stock-Based Compensation

At December 31, 2019, the Company had stock-based employee compensation plans that included restricted stock units (“RSUs”) and performance share units (“PSUs”) issued to employees, RSUs and restricted stock issued to non-employee directors, and an employee stock purchase plan available to eligible employees. These are more fully described in Note 7 – Compensation Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and is included within the general and administrative and exploration expense line items in the accompanying statements of operations. For stock-based compensation awards containing non-market based performance conditions, the Company evaluates the probability of the number of shares that are expected to vest, and then adjusts the expense to reflect the number of shares expected to vest and the cumulative vesting period met to date. Further, the Company accounts for forfeitures of stock-based compensation awards as they occur.

Income Taxes

The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the consolidated financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis. Please refer to Note 4 – Income Taxes for additional disclosure.

Earnings per Share

The Company uses the treasury stock method to determine the potential dilutive effect of non-vested RSUs, contingent PSUs, and Senior Convertible Notes. Please refer to Note 9 - Earnings Per Share for additional discussion.

Comprehensive Income (Loss)

Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss) (“accompanying statements of comprehensive income (loss)”). The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach. Please refer to Note 8 – Pension Benefits for detail on the changes in the balances of components comprising other comprehensive income (loss).

Fair Value of Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had a $122.5 million balance under its credit facility as of December 31, 2019, compared with a zero balance as of December 31, 2018. The Company’s Senior Notes and Senior Convertible Notes are recorded at cost, net of any unamortized discount and deferred financing costs, and their respective fair values are disclosed in Note 11 – Fair Value Measurements. Additionally, the Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.

Industry Segment and Geographic Information

The Company operates in the exploration and production segment of the oil and gas industry, onshore in the United States. The Company reports as a single industry segment.

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Off-Balance Sheet Arrangements

The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or SPEs, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that the Company is the primary beneficiary of a variable interest entity, that entity is consolidated. The Company has not been involved in any unconsolidated SPE transactions in 2019 or 2018.

Recently Issued Accounting Standards

Effective January 1, 2017, the Company adopted, using various transition methods, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 is meant to simplify certain aspects of accounting for share-based arrangements, including income tax effects, accounting for forfeitures, and net share settlements. The Company adopted the various applicable amendments, which are summarized as follows:

•	On January 1, 2017, a $44.3 million cumulative-effect adjustment was made to retained earnings and a corresponding deferred tax asset was recorded for previously unrecognized excess tax benefits using a modified retrospective transition method. Effective January 1, 2017, excess tax benefits are presented in net cash provided by operating activities on the accompanying statements of cash flows.

•

On January 1, 2017, the Company elected to change its policy to account for forfeitures of share-based payment awards as they occur, rather than applying an estimated forfeiture rate. This change was made using a modified retrospective transition method and resulted in an increase in additional paid-in capital of $1.1 million, a decrease in deferred tax assets of $400,000, and a net $700,000 cumulative effect decrease to retained earnings.

•	Under this new guidance, excess tax benefits and deficiencies from share-based payments impact the Company’s effective tax rate between periods.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASU 2016-02” or “Topic 842”). The Company adopted ASU 2016-02 on January 1, 2019, using the modified retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby lease accounting for previously reported periods continues to be reported in accordance with historical accounting guidance for leases in effect for those prior periods. Policy elections and practical expedients the Company implemented in connection with the adoption of ASU 2016-02 include (a) excluding from the balance sheet leases with terms that are less than one year, (b) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (c) the package of practical expedients, which among other requirements, allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements that existed or expired before adoption of ASU 2016-02. The scope of ASU 2016-02 does not apply to leases used in the exploration or use of minerals, oil, natural gas, or other similar non-regenerative resources.

Upon adoption on January 1, 2019, the Company recognized approximately $50.0 million in right-of-use (“ROU”) assets and related lease liabilities for its operating leases. There was no cumulative effect adjustment to retained earnings upon the adoption of this guidance. Please refer to Note 12 - Leases for additional discussion.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The guidance is to be applied using a modified retrospective method and is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 is not expected to result in a material impact to the Company’s consolidated financial statements or disclosures.

In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017-07”). ASU 2017-07 requires presentation of service cost in the same line item(s) as other compensation costs arising from services rendered by employees during the period, and presentation of the remaining components of net benefit cost in a separate line item, outside operating items. In addition, only the service cost component of net benefit cost is eligible for capitalization. The Company adopted ASU 2017-07 on the effective date of January 1, 2018, with retrospective application of the service cost component and the other components of net benefit cost in the consolidated statements of operations, and prospective application for the capitalization of the service cost component of net benefit costs in assets. While the adoption of ASU 2017-07 resulted in the Company reclassifying certain amounts from operating expenses to non-operating expenses, ASU 2017-07 did not result in a material impact to the Company’s consolidated financial statements or disclosures.

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In February 2018, the FASB issued ASU No. 2018-02, Income Statement–Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (“ASU 2018-02”). ASU 2018-02 permits entities to reclassify tax effects stranded in accumulated other comprehensive income (loss) to retained earnings as a result of the 2017 Tax Act. The Company early adopted ASU 2018-02 effective January 1, 2018 using a retrospective method. As a result of adopting ASU 2018-02, the Company reclassified $3.0 million of tax effects stranded in accumulated other comprehensive loss to retained earnings as of January 1, 2018. The Company’s policy for releasing income tax effects within accumulated other comprehensive loss is an incremental, unit-of-account approach.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). ASU 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company adopted ASU 2018-15 on January 1, 2020, with prospective application. The adoption of ASU 2018-15 is not expected to have a material impact to the Company’s consolidated financial statements or disclosures.

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”). ASU 2019-12 was issued as a means to reduce the complexity of accounting for income taxes for those entities that fall within the scope of the accounting standard. The guidance is to be applied using a prospective method, excluding amendments related to franchise taxes, which should be applied on either a retrospective basis for all periods presented or a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company is evaluating the impact of ASU 2019-12 on its consolidated financial statements.

There are no other ASUs applicable to the Company that would have a material effect on the Company’s consolidated financial statements and related disclosures that have been issued but not yet adopted by the Company as of December 31, 2019, and through the filing of this report.

Note 2 - Revenue from Contracts with Customers

The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs in its Midland Basin and South Texas assets. Following the divestiture of the Company’s remaining assets in the Rocky Mountain region during the first half of 2018, there has been no production revenue from this region after the second quarter of 2018. Oil, gas, and NGL production revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers.

The tables below present the oil, gas, and NGL production revenue by product type for each of the Company’s operating regions for the years ended December 31, 2019, 2018, and 2017:

	For the year ended December 31, 2019
	Midland Basin				South Texas				Total
	(in thousands)
Oil production revenue	$	1,119,786			$	63,426			$	1,183,212
Gas production revenue	75,827				186,702				262,529
NGL production revenue	123				139,886				140,009
Total	$	1,195,736			$	390,014			$	1,585,750
Relative percentage	75		%		25		%		100		%

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Note: Amounts may not calculate due to rounding.

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	For the year ended December 31, 2018
	Midland Basin				South Texas				Rocky Mountain				Total
	(in thousands)
Oil production revenue	$	938,004			$	72,821			$	54,851			$	1,065,676
Gas production revenue	125,603				227,252				1,595				354,450
NGL production revenue	1,000				214,441				790				216,231
Total	$	1,064,607			$	514,514			$	57,236			$	1,636,357
Relative percentage	65		%		32		%		3		%		100		%

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Note: Amounts may not calculate due to rounding.

	For the year ended December 31, 2017
	Midland Basin				South Texas				Rocky Mountain				Total
	(in thousands)
Oil production revenue	$	419,732			$	82,674			$	151,844			$	654,250
Gas production revenue	61,781				301,780				5,849				369,410
NGL production revenue	547				226,031				3,545				230,123
Total	$	482,060			$	610,485			$	161,238			$	1,253,783
Relative percentage	38		%		49		%		13		%		100		%

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Note: Amounts may not calculate due to rounding.

The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the purchaser, which differs depending on the applicable contractual terms. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred by the Company prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations. When control is transferred at or near the wellhead, sales are based on a wellhead market price that is impacted by fees and other deductions incurred by the purchaser subsequent to the transfer of control. In general, the Company generates production revenue from a combination of the following types of contracts:

•	The Company sells oil and gas production at or near the wellhead and receives an agreed-upon market price from the purchaser. Under this type of arrangement, control transfers at or near the wellhead.

•

The Company has certain processing arrangements that include the delivery of unprocessed gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs extracted during processing, the midstream processor remits payment to the Company based on the proceeds the processor realizes from selling the NGLs to third parties. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer. These fees are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations.

Significant judgments made in applying the guidance in ASC Topic 606, Revenue from Contracts with Customers, relate to the point in time when control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with generally predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.

The Company’s performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a purchaser at the wellhead, inlet, or tailgate of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.

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Revenue is recorded in the month when performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within the accounts receivable line item on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of December 31, 2019, and 2018, were $146.3 million and $107.2 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser.

Note 3 – Divestitures, Assets Held for Sale, and Acquisitions

2019 Divestiture Activity

No material divestitures occurred during 2019.

2018 Divestiture Activity

PRB Divestiture. On March 26, 2018, the Company completed the PRB Divestiture, divesting of approximately 112,000 net acres for total cash received at closing, net of costs (referred to throughout this report as “net divestiture proceeds”), of $492.2 million, and recorded a final net gain of $410.6 million for the year ended December 31, 2018.

Divide County Divestiture and Halff East Divestiture. During the second quarter of 2018, the Company completed the Divide County Divestiture and the Halff East Divestiture, for combined net divestiture proceeds of $252.2 million, and recorded a combined final net gain of $15.4 million for the year ended December 31, 2018.

The following table presents loss before income taxes from the Divide County, North Dakota assets sold for the years ended December 31, 2019, 2018, and 2017. The Divide County Divestiture was considered a disposal of a significant asset group.

	For the Years Ended December 31,
	2019				2018				2017
	(in thousands)
Loss before income taxes (1)	$	—			$	(28,975	)		$	(468,786	)

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(1)	Loss before income taxes reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, depletion, depreciation, amortization, and asset retirement obligation liability accretion expense, impairment expense, and net loss on divestiture activity. During the year ended December 31, 2017, the Company recorded a write-down of $523.6 million on these assets.

2017 Divestiture Activity

Eagle Ford Divestiture. On March 10, 2017, the Company divested its outside-operated Eagle Ford shale assets, including its ownership interest in related midstream assets, for final net divestiture proceeds of $744.1 million. The Company recorded a final net gain of $396.8 million related to these divested assets for the year ended December 31, 2017. This divestiture was considered a disposal of a significant asset group. For the year ended December 31, 2017, income before income taxes from the outside-operated Eagle Ford shale assets sold was $24.3 million. This amount reflects oil, gas, and NGL production revenue, less oil, gas, and NGL production expense, and depletion, depreciation, amortization, and asset retirement obligation liability accretion expense.

During 2017, the Company divested certain non-core properties for net divestiture proceeds of $36.2 million and recognized an insignificant final net gain.

The Company determined that executed asset sales in 2018 and 2017 did not qualify for discontinued operations accounting under financial statement presentation authoritative guidance.

2019 Acquisition Activity

During 2019, the Company completed several non-monetary acreage trades of primarily undeveloped properties located in Howard, Martin, and Midland Counties, Texas, resulting in the exchange of approximately 2,200 net acres, with $73.4 million of carrying value attributed to the properties transferred by the Company. These trades were recorded at carryover basis with no gain or loss recognized.

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2018 Acquisition Activity

During the year ended December 31, 2018, the Company acquired approximately 1,030 net acres of primarily unproved properties located in Martin and Howard Counties, Texas, in two separate transactions which closed in 2018. Combined total cash consideration paid by the Company was $33.3 million. Under authoritative accounting guidance, these transactions were both individually considered to be asset acquisitions. Therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and the transaction costs were capitalized as a component of the cost of the assets acquired.

During the third quarter of 2018, the Company completed two non-monetary acreage trades of primarily undeveloped properties located in Howard and Martin Counties, Texas, which resulted in the exchange of approximately 2,650 net acres, with $95.1 million of carrying value attributed to the properties transferred by the Company. These trades were recorded at carryover basis with no gain or loss recognized.

2017 Acquisition Activity

During the year ended December 31, 2017, the Company acquired approximately 3,600 net acres of primarily unproved properties in Howard and Martin Counties, Texas, in multiple transactions for a total of $76.5 million of cash consideration. Under authoritative accounting guidance, these transactions were individually considered to be asset acquisitions. Therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and the transaction costs were capitalized as a component of the cost of the assets acquired.

Also during the year ended December 31, 2017, the Company completed several non-monetary acreage trades of primarily unproved properties in Howard and Martin Counties, Texas, resulting in the exchange of approximately 8,125 net acres for approximately 7,580 net acres with $294.0 million of carrying value attributed to the properties transferred by the Company in such trades. These trades were recorded at carryover basis with no gain or loss recognized.

Note 4 – Income Taxes

The provision for income taxes consists of the following:

	For the Years Ended December 31,
	2019				2018				2017
	(in thousands)
Current portion of income tax expense (benefit)
Federal	$	(3,826	)		$	—			$	5,698
State	1,618				1,662				3,398
Deferred portion of income tax expense (benefit)	(41,835		)		141,708				(192,066		)
Income tax expense (benefit)	$	(44,043	)		$	143,370			$	(182,970	)
Effective tax rate	19.1		%		22.0		%		53.2		%

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The components of the net deferred tax liabilities are as follows:

	As of December 31,
	2019				2018
	(in thousands)
Deferred tax liabilities
Oil and gas properties	$	205,028			$	218,094
Derivative assets	4,646				35,247
Other	12,361				4,812
Total deferred tax liabilities	222,035				258,153
Deferred tax assets
Credit carryover	11,270				22,554
Pension	5,971				6,427
Federal and state tax net operating loss carryovers	4,172				4,217
Stock compensation	3,503				3,263
Other liabilities	10,803				1,497
Total deferred tax assets	35,719				37,958
Valuation allowance	(3,070		)		(3,083		)
Net deferred tax assets	32,649				34,875
Total net deferred tax liabilities	$	189,386			$	223,278
Current federal income tax refundable	$	3,885			$	59
Current state income tax payable	$	1,404			$	1,331

As of December 31, 2019, the Company estimated its federal net operating loss (“NOL”) carryforward at $3.3 million and state NOL carryforwards at $77.8 million. The Company has federal research and development (“R&D”) and AMT credit carryforwards of $7.4 million and $4.3 million, respectively. The majority of federal NOLs do not expire but the state NOLs and state tax credits expire between 2021 and 2038. The federal R&D credit carryforwards expire between 2028 and 2035. The Company’s AMT credit carryforwards are expected to be fully refunded by 2022. The Company’s current valuation allowance relates to state NOL carryforwards and state tax credits, which are expected to expire before they can be utilized.

Recorded income tax expense or benefit differs from the amount that would be provided by applying the statutory United States federal income tax rate to income before income taxes. These differences primarily relate to the effect of state income taxes, excess tax benefits and deficiencies from stock-based compensation awards, tax limitations on compensation of covered individuals, changes in valuation allowances, and the cumulative impact of other smaller permanent differences, and is reported as follows:

	For the Years Ended December 31,
	2019				2018				2017
	(in thousands)
Federal statutory tax expense (benefit)	$	(48,519	)		$	136,873			$	(120,335	)
Increase (decrease) in tax resulting from:
Federal tax reform changes - 2017 Tax Act	—				—				(63,675		)
State tax expense (benefit) (net of federal benefit)	260				2,771				(3,286		)
Change in valuation allowance	(13		)		105				(2,727		)
Employee share-based compensation	3,346				2,508				8,190
Other	883				1,113				(1,137		)
Income tax expense (benefit)	$	(44,043	)		$	143,370			$	(182,970	)

Acquisitions, divestitures, drilling activity, and basis differentials, which impact the prices received for oil, gas, and NGLs, impact the apportionment of taxable income to the states where the Company owns oil and gas properties. As these factors change, the Company’s state income tax rate changes. This change, when applied to the Company’s total temporary differences, impacts the total state income tax expense (benefit) reported in the current year. Items affecting state apportionment factors are evaluated upon completion of the prior year income tax return, after significant acquisitions and divestitures, if there are significant changes in drilling activity, or if estimated state revenue changes occur during the year. As a result of the 2018 divestitures, the Company’s state apportionment rate reflects its significant Texas presence.

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During the fourth quarter of 2019, the Company claimed and received a $7.7 million refund for a portion of its deferred AMT credit carryover. An additional refund of $3.8 million is expected to be claimed in 2020. For all years before 2015, the Company is generally no longer subject to United States federal or state income tax examinations by tax authorities.

The Company complies with authoritative accounting guidance regarding uncertain tax provisions. The entire amount of unrecognized tax benefit reported by the Company would affect its effective tax rate if recognized. Interest expense in the accompanying statements of operations includes a negligible amount associated with income taxes. The Company does not expect a significant change to the recorded unrecognized tax benefits in 2020.

The total amount recorded for unrecognized tax benefits for each of the years ended December 31, 2019, 2018, and 2017, was $446,000.

Note 5 – Long-Term Debt

Credit Agreement

On September 19, 2019, the Company and its lenders entered into the Second Amendment to the Sixth Amended and Restated Credit Agreement which permitted the Company to enter into swap agreements with respect to the price of electricity in order to minimize exposure to electrical price volatility. As of December 31, 2019, the Credit Agreement provided for a senior secured revolving credit facility with a maximum loan amount of $2.5 billion, a borrowing base of $1.6 billion, and aggregate lender commitments of $1.2 billion. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both the Company’s (a) proved oil and gas properties reflected in the Company’s most recent reserve report; and (b) commodity derivative contracts, each as determined by the Company’s lender group. The next scheduled borrowing base redetermination date is April 1, 2020.

The Credit Agreement is scheduled to mature on the earlier of September 28, 2023, (the “Scheduled Maturity Date”), and August 16, 2022, to the extent that, on or before such date, the Company’s outstanding 2022 Senior Notes are not repurchased, redeemed, or refinanced to have a maturity date at least 91 days after the Scheduled Maturity Date unless, on August 16, 2022, both (i) the aggregate outstanding principal amount of the 2022 Senior Notes is not more than $100.0 million and (ii) after giving pro forma effect to the repayment in full at maturity of the 2022 Senior Notes then outstanding, the aggregate amount of unrestricted cash and certain types of unrestricted investments held by the Company and its Consolidated Restricted Subsidiaries plus the amount of unused availability under the Credit Agreement is at least $300.0 million.

The Company must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring the Company to maintain certain financial ratios, as defined by the Credit Agreement. The financial covenants under the Credit Agreement require that the Company’s (a) total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX ratio for the most recently ended four consecutive fiscal quarters (excluding the first three quarters which used annualized adjusted EBITDAX), cannot be greater than 4.25 to 1.00 beginning with the quarter ending December 31, 2018, through and including the fiscal quarter ending December 31, 2019, and for each quarter ending thereafter, the ratio cannot be greater than 4.00 to 1.00; and (b) adjusted current ratio cannot be less than 1.0 to 1.0 as of the last day of any fiscal quarter. The Company was in compliance with all financial and non-financial covenants as of December 31, 2019, and through the filing of this report.

Interest and commitment fees associated with the credit facility are accrued based on a borrowing base utilization grid set forth in the Credit Agreement. At the Company’s election, borrowings under the Credit Agreement may be in the form of Eurodollar, Alternate Base Rate (“ABR”), or Swingline loans. Eurodollar loans accrue interest at LIBOR, plus the applicable margin from the utilization grid, and ABR and Swingline loans accrue interest at a market-based floating rate, plus the applicable margin from the utilization grid. Commitment fees are accrued on the unused portion of the aggregate lender commitment amount at rates from the utilization grid and are included in the interest expense line item on the accompanying statements of operations. The borrowing base utilization grid as set forth in the Credit Agreement is as follows:

Borrowing Base Utilization Percentage	<25%			≥25% <50%			≥50% <75%			≥75% <90%			≥90%
Eurodollar Loans (1)	1.500	%		1.750	%		2.000	%		2.250	%		2.500	%
ABR Loans or Swingline Loans	0.500	%		0.750	%		1.000	%		1.250	%		1.500	%
Commitment Fee Rate	0.375	%		0.375	%		0.500	%		0.500	%		0.500	%

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(1)

The Company’s Credit Agreement specifies that in the event that LIBOR is no longer a widely used benchmark rate, or that it shall no longer be used for determining interest rates for loans in the United States, a replacement interest rate that fairly reflects the cost to the lenders of funding loans shall be established by the Administrative Agent, as defined in the Credit Agreement, in consultation with the borrower.

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The following table presents the outstanding balance, total amount of letters of credit outstanding, and available borrowing capacity under the Credit Agreement as of February 6, 2020, December 31, 2019, and December 31, 2018:

	As of February 6, 2020				As of December 31, 2019				As of December 31, 2018
	(in thousands)
Revolving credit facility (1)	$	113,500			$	122,500			$	—
Letters of credit (2)	—				—				200
Available borrowing capacity	1,086,500				1,077,500				999,800
Total aggregate lender commitment amount	$	1,200,000			$	1,200,000			$	1,000,000

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(1)	Unamortized deferred financing costs attributable to the revolving credit facility are presented as a component of the other noncurrent assets line item on the accompanying balance sheets and totaled $5.9 million and $6.4 million as of December 31, 2019, and 2018, respectively. These costs are being amortized over the term of the credit facility on a straight-line basis.

(2)	Letters of credit outstanding reduce the amount available under the credit facility on a dollar-for-dollar basis. The letter of credit outstanding as of December 31, 2018, was released effective January 8, 2019.

Senior Notes

The Senior Notes, net of unamortized deferred financing costs line item on the accompanying balance sheets as of December 31, 2019, and 2018, consisted of the following:

	As of December 31,
	2019												2018
	Principal Amount				Unamortized Deferred Financing Costs				Principal Amount, Net of Unamortized Deferred Financing Costs				Principal Amount				Unamortized Deferred Financing Costs				Principal Amount, Net of Unamortized Deferred Financing Costs
	(in thousands)
6.125% Senior Notes due 2022	$	476,796			$	2,920			$	473,876			$	476,796			$	3,921			$	472,875
5.0% Senior Notes due 2024	500,000				3,766				496,234				500,000				4,688				495,312
5.625% Senior Notes due 2025	500,000				4,903				495,097				500,000				5,808				494,192
6.75% Senior Notes due 2026	500,000				5,571				494,429				500,000				6,407				493,593
6.625% Senior Notes due 2027	500,000				6,601				493,399				500,000				7,533				492,467
Total	$	2,476,796			$	23,761			$	2,453,035			$	2,476,796			$	28,357			$	2,448,439

The Senior Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. There are no subsidiary guarantors of the Senior Notes. The Company is subject to certain covenants under the indentures governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends. The Company was in compliance with all such covenants under its Senior Notes as of December 31, 2019, and through the filing of this report. All Senior Notes are registered under the Securities Act. The Company may redeem some or all of its Senior Notes prior to their maturity at redemption prices based on a premium, plus accrued and unpaid interest as described in the indentures governing the Senior Notes.

On July 16, 2018, the Company redeemed its 2021 Senior Notes which resulted in the payment of total cash consideration, including accrued interest, of $355.9 million. Additionally, during the third quarter of 2018, the Company used the proceeds from the issuance of its 2027 Senior Notes, as discussed below, and cash on hand to fund the cash tender offer and redemption of $395.0 million of its 2023 Senior Notes and $85.0 million of its 2022 Senior Notes. The Company paid total consideration, including accrued interest, of $497.8 million to complete these transactions. As a result of the redemption of the 2021 Senior Notes, and the cash tender offer and redemption of all of the 2023 Senior Notes and a portion of the 2022 Senior Notes, the Company recorded a combined loss on extinguishment of debt of $26.7 million for the year ended December 31, 2018. This amount included combined premiums paid of $20.4 million and $6.3 million of accelerated unamortized deferred financing costs for the redemption.

2022 Senior Notes. On November 17, 2014, the Company issued $600.0 million in aggregate principal amount of 6.125% Senior Notes due 2022 at par, which mature on November 15, 2022. The Company received net proceeds of $590.0 million after deducting fees of $10.0 million, which are being amortized as deferred financing costs over the life of the 2022 Senior Notes. During the first quarter of 2016, the Company repurchased $38.2 million in aggregate principal amount of its 2022 Senior Notes for a

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settlement amount of $24.3 million, excluding interest. During the third quarter of 2018, through the tender offer discussed above, the Company retired $85.0 million of its 2022 Senior Notes for total consideration, including accrued interest, of $89.5 million.

2024 Senior Notes. On May 20, 2013, the Company issued $500.0 million in aggregate principal amount of 5.0% Senior Notes due 2024 at par, which mature on January 15, 2024. The Company received net proceeds of $490.2 million after deducting fees of $9.8 million, which are being amortized as deferred financing costs over the life of the 2024 Senior Notes.

2025 Senior Notes. On May 21, 2015, the Company issued $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025 at par, which mature on June 1, 2025. The Company received net proceeds of $491.0 million after deducting fees of $9.0 million, which are being amortized as deferred financing costs over the life of the 2025 Senior Notes.

2026 Senior Notes. On September 12, 2016, the Company issued $500.0 million in aggregate principal amount of 6.75% Senior Notes due 2026, at par, which mature on September 15, 2026. The Company received net proceeds of $491.6 million after deducting fees of $8.4 million, which are being amortized as deferred financing costs over the life of the 2026 Senior Notes.

2027 Senior Notes. On August 20, 2018, the Company issued $500.0 million in aggregate principal amount of 6.625% Senior Notes due 2027, at par, which mature on January 15, 2027. The Company received net proceeds of $492.1 million after deducting fees of $7.9 million, which are being amortized as deferred financing costs over the life of the 2027 Senior Notes. As discussed above, the net proceeds were used to fund the tender offer and redemption of all of the Company’s 2023 Senior Notes and a portion of its 2022 Senior Notes.

Senior Convertible Notes

On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of 1.50% Senior Convertible Notes due July 1, 2021, unless earlier converted. The Senior Convertible Notes are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt and are senior in right of payment to any future subordinated debt. The Company received net proceeds of $166.6 million after deducting fees of $5.9 million, of which a portion is being amortized over the life of the Senior Convertible Notes.

Holders may convert their Senior Convertible Notes at their option at any time prior to January 1, 2021, only under the following circumstances: (1) during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending on September 30, 2016, if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (2) during the five business day period after any five consecutive trading day period (the “measurement period”) in which the trading price (as defined in the indenture) per $1,000 principal amount of Notes for each trading day of the measurement period was less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (3) upon the occurrence of specified corporate events. On or after January 1, 2021, until the maturity date, holders may convert their Senior Convertible Notes at any time. The Company may not redeem the Senior Convertible Notes prior to the maturity date. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. Holders may convert their notes based on a conversion rate of 24.6914 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equal to an initial conversion price of approximately $40.50 per share, subject to adjustment.

The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal amount in cash with any excess conversion in shares of the Company’s common stock. The Senior Convertible Notes were not convertible at the option of holders as of December 31, 2019, or through the filing of this report. Notwithstanding the inability to convert, the if-converted value of the Senior Convertible Notes as of December 31, 2019, did not exceed the principal amount.

Upon the issuance of the Senior Convertible Notes, the Company recorded $132.3 million as the initial carrying amount of the debt component, which approximated its fair value at issuance, and, was estimated by using an interest rate for nonconvertible debt with terms similar to the Senior Convertible Notes. The effective interest rate used was 7.25%. The $40.2 million excess of the principal amount of the Senior Convertible Notes over the fair value of the debt component was recorded as a debt discount and a corresponding increase in additional paid-in capital. The Company incurred transaction costs of $5.9 million relating to the issuance of the Senior Convertible Notes, which were allocated between the debt and equity components in proportion to their determined fair value amounts. The debt discount and debt-related issuance costs are amortized to the principal value of the Senior Convertible Notes as interest expense through the maturity date of July 1, 2021. Interest expense recognized on the Senior Convertible Notes related to the stated interest rate and amortization of the debt discount totaled $11.0 million, $10.5 million, and $9.9 million for the years ended December 31, 2019, 2018, and 2017, respectively.

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The Senior Convertible Notes, net of unamortized discount and deferred financing costs line on the accompanying balance sheets consisted of the following as of December 31, 2019 and 2018:

	As of December 31,
	2019				2018
	(in thousands)
Principal amount of Senior Convertible Notes	$	172,500			$	172,500
Unamortized debt discount	(13,861		)		(22,313		)
Unamortized deferred financing costs	(1,376		)		(2,293		)
Senior Convertible Notes, net of unamortized discount and deferred financing costs	$	157,263			$	147,894

As of both December 31, 2019 and 2018, the net carrying amount of the equity component of the Senior Convertible Notes recorded in additional paid-in capital on the accompanying balance sheets was $33.6 million. There have been no changes to this amount since issuance.

If the Company undergoes a fundamental change, as defined by the governing indenture, holders of the Senior Convertible Notes may require the Company to repurchase for cash all or any portion of their notes at a fundamental change repurchase price equal to 100% of the principal amount of the Senior Convertible Notes to be repurchased, plus accrued and unpaid interest. The indenture governing the Senior Convertible Notes contains customary events of default with respect to the Senior Convertible Notes, including that upon certain events of default, the trustee by notice to the Company, or the holders of at least 25% in principal amount of the outstanding Senior Convertible Notes by notice to the Company, may declare 100% of the principal and accrued and unpaid interest, if any, due and payable immediately. In case of certain events of bankruptcy, insolvency or reorganization involving the Company or a significant subsidiary, 100% of the principal and accrued and unpaid interest on the Senior Convertible Notes will automatically become due and payable.

The Company is subject to certain covenants under the indenture governing the Senior Convertible Notes and was in compliance with all covenants as of December 31, 2019, and through the filing of this report.

Capped Call Transactions

In connection with the issuance of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters of such issuance. The aggregate cost of the capped call transactions was approximately $24.2 million. The capped call transactions are generally expected to reduce the potential dilution upon conversion of the Senior Convertible Notes and/or partially offset any cash payments the Company is required to make in excess of the principal amount of converted Senior Convertible Notes in the event that the market price per share of the Company’s common stock is greater than the strike price of the capped call transactions, which initially corresponds to the approximate $40.50 per share conversion price of the Senior Convertible Notes. The cap price of the capped call transactions is initially $60.00 per share. If the market price per share exceeds the cap price of the capped call transactions, there could be dilution or there would not be an offset of such potential cash payments. The Company classified the costs associated with the capped call transactions as equity instruments with no recurring fair value measurement recorded.

Capitalized Interest

Capitalized interest costs for the Company for the years ended December 31, 2019, 2018, and 2017, totaled $18.5 million, $20.6 million, and $12.6 million, respectively. Capitalized interest costs are included in total costs incurred. Please refer to Costs Incurred in Oil and Gas Producing Activities in Overview of the Company in Part II, Item 7, and Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

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Note 6 – Commitments and Contingencies

Commitments

The Company has entered into various agreements, which include drilling rig and completion service contracts of $34.1 million, gathering, processing, transportation throughput, and delivery commitments of $218.5 million, office leases, including maintenance, of $28.3 million, fixed price contracts to purchase electricity of $53.2 million, and other miscellaneous contracts and leases of $15.5 million. The annual minimum payments for the next five years and total minimum payments thereafter are presented below:

Years Ending December 31,		Amount (in thousands)
2020		$	102,550
2021		94,494
2022		73,826
2023		41,661
2024		12,349
Thereafter		24,697
Total		$	349,577

Drilling Rig and Completion Service Contracts. The Company has several drilling rig and completion service contracts in place to facilitate its drilling and completion plans. As of December 31, 2019, the Company’s drilling rig and completion service contract commitments totaled $34.1 million, included in the table above. If all of these contracts were terminated as of December 31, 2019, the Company would avoid a portion of the contractual service commitments; however, the Company would be required to pay $26.3 million in early termination fees. Excluded from these amounts are variable commitments and potential penalties determined by the number of completion crews the Company has in operation in a particular area under a completion service arrangement. As of December 31, 2019, potential penalties under this completion service agreement, which expires on December 31, 2023, range from zero to a maximum of $13.4 million.

Pipeline Transportation Commitments. The Company has gathering, processing, transportation throughput, and delivery commitments with various third-parties that require delivery of a minimum amount of oil, gas, and produced water. As of December 31, 2019, the Company has commitments to deliver a minimum of 24 MMBbl of oil and 424 Bcf of gas through 2023, and 18 MMBbl of produced water through 2027. The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. As of December 31, 2019, if the Company fails to deliver any product, as applicable, the aggregate undiscounted deficiency payments total approximately $218.5 million. This amount does not include deficiency payment estimates associated with approximately 16.5 MMBbl of future oil delivery commitments where the Company cannot predict with accuracy the amount and timing of these payments, as such payments are dependent upon the price of oil in effect at the time of settlement. Under certain of the Company’s commitments, if the Company is unable to deliver the minimum quantity from its production, it may deliver production acquired from third-parties to satisfy its minimum volume commitments.

Office Leases. The Company leases office space under various operating leases with terms extending as far as 2026. Rent expense for the years ended December 31, 2019, 2018, and 2017, was $5.5 million, $4.5 million, and $4.8 million, respectively.

Electrical Power Purchase Contracts. During the second quarter of 2019, the Company entered into a fixed price contract for the purchase of electrical power that increased the purchase commitment under an existing agreement. As of December 31, 2019, the Company had a commitment to purchase electrical power through 2027 with a total remaining obligation of $53.2 million.

Delivery and Purchase Commitments. During the second quarter of 2019, the Company executed an amendment to its existing sand sourcing agreement that created certain commitments and potential penalties that vary based on the amount of sand the Company uses in well completions occurring in a particular area. This amended sand sourcing agreement expires on December 31, 2023. As of December 31, 2019, potential penalties under this sand sourcing agreement range from zero to a maximum of $10.0 million.

Drilling and Completion Commitments. The Company has an agreement in place that includes minimum drilling and completion requirements on certain leases. If these minimum requirements are not satisfied by March 31, 2020, the Company would be required to make a liquidated damage payment based on the difference between actual development progress and the minimum development requirements. As of December 31, 2019, the Company did not expect to meet certain minimum development requirements.

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In the fourth quarter of 2019, the Company recognized one-time charges associated with expected payments to lessors related to drilling and completion obligations and early termination fees for drilling rigs totaling $18.2 million. These amounts are included in the other operating expense line item on the accompanying statements of operations.

Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the anticipated results of any pending litigation and claims are not expected to have a material effect on the results of operations, the financial position, or the cash flows of the Company.

Note 7 – Compensation Plans

Equity Incentive Compensation Plan

There are several components to the Company’s Equity Incentive Compensation Plan (“Equity Plan”) that are described in this section. Various types of equity awards have been granted by the Company in different periods.

As of December 31, 2019, approximately 4.4 million shares of common stock were available for grant under the Equity Plan. The issuance of a direct share benefit, such as a share of common stock, a stock option, a restricted share, an RSU, or a PSU, counts as one share against the number of shares available to be granted under the Equity Plan. Each PSU has the potential to count as two shares against the number of shares available to be granted under the Equity Plan based on the final performance multiplier.

Performance Share Units

The Company grants PSUs to eligible employees as part of its Equity Plan. The number of shares of the Company’s common stock issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on certain performance criteria over a three-year performance period. PSUs generally vest on the third anniversary of the date of the grant or upon other triggering events as set forth in the Equity Plan. Employees who are retirement eligible at the time a PSU award was granted, vest in each portion of that award equally in six-month increments over a three-year period beginning at grant date. Retirement eligible employees must stay with the Company through the entire six-month vesting period to receive that increment of vesting and any non-vested portions of a PSU award will be forfeited when the employee leaves the Company.

The fair value of PSUs is measured at the grant date with a stochastic Monte Carlo simulation using geometric Brownian motion (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three-year performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the path the stock price may take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three-year vesting period, as well as the volatilities and dividend yields for each of the Company’s peers.

For PSUs granted in 2017, which the Company has determined to be equity awards, the settlement criteria include a combination of the Company’s Total Shareholder Return (“TSR”) on an absolute basis, and the Company’s TSR relative to the TSR of certain peer companies over the associated three-year performance period. The fair value of the PSUs granted in 2017 was measured on the grant date using the GBM Model. As these awards depend entirely on market-based settlement criteria, the associated compensation expense is recognized on a straight-line basis within general and administrative expense and exploration expense over the vesting period of the awards.

For PSUs granted in 2018 and 2019, the settlement criteria include a combination of the Company’s TSR relative to the TSR of certain peer companies and the Company’s cash return on total capital invested (“CRTCI”) relative to the CRTCI of certain peer companies over the associated three-year performance period. In addition to these performance measures, the award agreements for these grants also stipulate that if the Company’s absolute TSR is negative over the three-year performance period, the maximum number of shares of common stock that can be issued to settle outstanding PSUs is capped at one times the number of PSUs granted on the award date, regardless of the Company’s TSR and CRTCI performance relative to its peer group. The fair value of the PSUs granted in 2018 and 2019 was measured on the applicable grant dates using the GBM Model, with the assumption that the associated CRTCI performance condition will be met at the target amount at the end of the respective performance periods. Compensation expense for PSUs granted in 2018 and 2019 is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. As these awards depend on a combination of performance-based settlement criteria and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected CRTCI performance relative to the applicable peer companies.

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The Company records compensation expense associated with the issuance of PSUs based on the fair value of the awards as of the date of grant. Total compensation expense recorded for PSUs was $10.9 million, $10.3 million, and $9.7 million for the years ended December 31, 2019, 2018, and 2017, respectively. As of December 31, 2019, there was $15.9 million of total unrecognized expense related to PSUs, which is being amortized through 2022.

A summary of the status and activity of non-vested PSUs is presented in the following table:

	For the Years Ended December 31,
	2019							2018							2017
	PSUs (1)			Weighted-Average Grant-Date Fair Value				PSUs (1)			Weighted-Average Grant-Date Fair Value				PSUs (1)			Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year	1,711,259			$	20.68			1,533,491			$	22.97			828,923			$	43.25
Granted	793,125			$	12.80			572,924			$	24.45			977,731			$	15.86
Vested	(346,021	)		$	26.32			(233,102	)		$	44.25			(94,338	)		$	85.85
Forfeited	(135,778	)		$	16.98			(162,054	)		$	21.79			(178,825	)		$	44.99
Non-vested at end of year	2,022,585			$	16.87			1,711,259			$	20.68			1,533,491			$	22.97

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(1)	The number of awards assumes a multiplier of one. The final number of shares of common stock issued may vary depending on the three-year performance multiplier, which ranges from zero to two.

The fair value of the PSUs granted in 2019, 2018, and 2017 was $10.2 million, $14.0 million, and $15.5 million, respectively.

During the years ended December 31, 2019, 2018, and 2017, PSUs that were granted in 2016, 2015, and 2014, respectively did not satisfy the minimum performance requirements. This resulted in a multiplier of zero times and therefore no shares of common stock were issued upon settlement.

The total fair value of PSUs that vested during the years ended December 31, 2019, 2018, and 2017 was $9.1 million, $10.3 million, and $8.1 million, respectively.

Employee Restricted Stock Units

The Company grants RSUs to eligible persons as part of its Equity Plan. Each RSU represents a right to receive one share of the Company’s common stock upon settlement of the award at the end of the specified vesting period. RSUs generally vest one-third of the total grant on each anniversary date of the grant over a three-year vesting period or upon other triggering events as set forth in the Equity Plan. Employees who are retirement eligible at the time an RSU award is granted, vest in each portion of that award equally in six-month increments over a three-year period beginning at grant date. Retirement eligible employees must stay with the Company through the entire six-month vesting period to receive that increment of vesting and any non-vested portions of an RSU award will be forfeited when the employee leaves the Company.

The Company records compensation expense associated with the issuance of RSUs based on the fair value of the awards as of the date of grant. The fair value of an RSU is equal to the closing price of the Company’s common stock on the day of the grant. Compensation expense for RSUs is recognized within general and administrative expense and exploration expense over the vesting periods of the respective awards. Total compensation expense recorded for employee RSUs for the years ended December 31, 2019, 2018, and 2017, was $11.1 million, $10.8 million, and $10.3 million, respectively. As of December 31, 2019, there was $16.9 million of total unrecognized compensation expense related to non-vested RSU awards, which is being amortized through 2022.

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A summary of the status and activity of non-vested RSUs granted to employees is presented in the following table:

	For the Years Ended December 31,
	2019							2018							2017
	RSUs			Weighted- Average Grant-Date Fair Value				RSUs			Weighted- Average Grant-Date Fair Value				RSUs			Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year	1,243,163			$	21.50			1,244,262			$	20.25			604,116			$	37.39
Granted	978,932			$	12.36			583,552			$	25.77			1,020,780			$	16.64
Vested	(466,535	)		$	21.94			(407,529	)		$	24.30			(246,025	)		$	43.99
Forfeited	(223,429	)		$	18.16			(177,122	)		$	17.26			(134,609	)		$	26.38
Non-vested at end of year	1,532,131			$	16.01			1,243,163			$	21.50			1,244,262			$	20.25

The fair value of RSUs granted to eligible employees in 2019, 2018, and 2017 was $12.1 million, $15.0 million, and $17.0 million, respectively.

A summary of the shares of common stock issued to settle employee RSUs is presented in the table below:

	For the Years Ended December 31,
	2019			2018			2017
Shares of common stock issued to settle RSUs (1)	466,535			407,529			246,025
Less: shares of common stock withheld for income and payroll taxes	(132,136	)		(115,784	)		(74,747	)
Net shares of common stock issued	334,399			291,745			171,278

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(1)	During the years ended December 31, 2019, 2018, and 2017, the Company issued shares of common stock to settle RSUs that related to awards granted in previous years. The Company and a majority of grant recipients mutually agreed to net share settle a portion of the awards to cover income and payroll tax withholdings in accordance with the Company’s Equity Plan and individual award agreements.

The total fair value of employee RSUs that vested during the years ended December 31, 2019, 2018, and 2017 was $10.2 million, $9.9 million, and $10.8 million, respectively.

Director Shares

In 2019, 2018, and 2017, the Company issued 96,719, 63,741, and 71,573 shares, respectively, of its common stock to its non-employee directors under the Equity Plan. In 2017, the Company issued 8,794 RSUs to a non-employee director. For the years ended December 31, 2019, 2018, and 2017, the Company recorded $1.2 million, $1.7 million, and $1.6 million, respectively, of compensation expense related to director shares and RSUs issued.

All shares issued to non-employee directors fully vest on December 31 of the year granted. The RSUs issued to a non-employee director in 2017 fully vested on December 31, 2017, and will settle upon the earlier to occur of May 25, 2027, or the director resigning from the Board of Directors.

Employee Stock Purchase Plan

Under the Company’s Employee Stock Purchase Plan (“ESPP”), eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of eligible compensation, without accruing in excess of $25,000 in value from purchases for each calendar year. The purchase price of the stock is 85 percent of the lower of the fair market value of the stock on either the first or last day of the purchase period. The ESPP is intended to qualify under Section 423 of the Internal Revenue Code (the “IRC”). The Company had approximately 1.3 million shares of its common stock available for issuance under the ESPP as of December 31, 2019. There were 314,868, 199,464, and 186,665 shares issued under the ESPP in 2019, 2018, and 2017, respectively. Total proceeds to the Company for the issuance of these shares were $3.2 million for each of the years ended December 31, 2019, and 2018, respectively, and $2.6 million for the year ended December 31, 2017.

The fair value of ESPP grants is measured at the date of grant using the Black-Scholes option-pricing model. Expected volatility is calculated based on the Company’s historical daily common stock price, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with a six-month vesting period.

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The fair value of ESPP shares issued during the periods reported were estimated using the following weighted-average assumptions:

	For the Years Ended December 31,
	2019			2018			2017
Risk free interest rate	2.3	%		1.8	%		0.9	%
Dividend yield	0.7	%		0.4	%		0.5	%
Volatility factor of the expected market price of the Company’s common stock	56.6	%		55.9	%		62.5	%
Expected life (in years)	0.5			0.5			0.5

The Company expensed $1.1 million for each of the years ended December 31, 2019, and 2018, respectively, and $1.0 million for the year ended December 31, 2017, based on the estimated fair value of the ESPP grants.

401(k) Plan

The Company has a defined contribution plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute a maximum of 60 percent of their base salaries up to the contribution limits established under the IRC. For employees hired before December 31, 2014, the Company matches 100 percent of each employee’s contribution in cash on a dollar for dollar basis, up to six percent of the employee’s base salary and performance bonus, and may make additional contributions at its discretion. The Company matches 150 percent of contributions made by employees hired after December 31, 2014, up to six percent of the employee’s base salary and performance bonus in lieu of pension plan benefits, and may make additional contributions at its discretion. Please refer to Note 8 – Pension Benefits for additional discussion of pension benefits. The Company’s matching contributions to the 401(k) Plan were $5.1 million, $4.9 million, and $4.5 million for the years ended December 31, 2019, 2018, and 2017, respectively.

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Note 8 – Pension Benefits

The Company has a non-contributory defined benefit pension plan covering employees who meet age and service requirements and who began employment with the Company prior to January 1, 2016 (the “Qualified Pension Plan”). The Company also has a supplemental non-contributory pension plan covering certain management employees (the “Nonqualified Pension Plan” and together with the Qualified Pension Plan, the “Pension Plans”). The Company froze the Pension Plans to new participants, effective as of January 1, 2016. Employees participating in the Pension Plans prior to the plans being frozen will continue to earn benefits.

Obligations and Funded Status for the Pension Plans

The Company recognizes the funded status (i.e. the difference between the fair value of plan assets and the projected benefit obligation) of the Company’s Pension Plans in the accompanying balance sheets as either an asset or a liability and recognizes a corresponding adjustment within the other comprehensive income (loss), net of tax, line item in the accompanying statements of comprehensive income (loss). The projected benefit obligation is the actuarial present value of the benefits earned to date by plan participants based on employee service and compensation including the effect of assumed future salary increases. The accumulated benefit obligation uses the same factors as the projected benefit obligation, but excludes the effects of assumed future salary increases. The Company’s measurement date for plan assets and obligations is December 31.

	For the Years Ended December 31,
	2019				2018
	(in thousands)
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	66,086			$	71,937
Service cost	5,582				6,730
Interest cost	2,791				2,622
Actuarial (gain) loss	2,035				(7,155		)
Benefits paid	(5,651		)		(8,048		)
Projected benefit obligation at end of year	70,843				66,086
Change in plan assets:
Fair value of plan assets at beginning of year	30,100				30,978
Actual return (loss) on plan assets	3,985				(964		)
Employer contribution	7,200				8,134
Benefits paid	(5,651		)		(8,048		)
Fair value of plan assets at end of year	35,634				30,100
Funded status at end of year	$	(35,209	)		$	(35,986	)

The Company’s underfunded status for the Pension Plans as of December 31, 2019, and 2018, was $35.2 million and $36.0 million, respectively, and is recognized in the accompanying balance sheets within the other noncurrent liabilities line item. There are no plan assets in the Nonqualified Pension Plan.

Accumulated Benefit Obligation in Excess of Plan Assets for the Pension Plans

	As of December 31,
	2019				2018
	(in thousands)
Projected benefit obligation	$	70,843			$	66,086
Accumulated benefit obligation	$	60,877			$	52,368
Less: fair value of plan assets	(35,634		)		(30,100		)
Underfunded accumulated benefit obligation	$	25,243			$	22,268

Pension expense is determined based upon the annual service cost of benefits (the actuarial cost of benefits earned during a period) and the interest cost on those liabilities, less the expected return on plan assets. The expected long-term rate of return on plan assets is applied to a calculated value of plan assets that recognizes changes in fair value over a five-year period. This practice is

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intended to reduce year-to-year volatility in pension expense, but it can have the effect of delaying recognition of differences between actual returns on assets and expected returns based on long-term rate of return assumptions. Amortization of the unrecognized net gain or loss resulting from actual experience different from that assumed and from changes in assumptions (excluding asset gains and losses not yet reflected in market-related value) is included as a component of net periodic benefit cost for the year. If, as of the beginning of the year, the unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation and the market-related value of plan assets, then the amortization is the excess divided by the average remaining service period of participating employees expected to receive benefits under the plan.

The pre-tax amounts not yet recognized in net periodic pension costs, but rather recognized in the accumulated other comprehensive loss line item within the accompanying balance sheets as of December 31, 2019, and 2018, were as follows:

	As of December 31,
	2019				2018
	(in thousands)
Unrecognized actuarial losses	$	14,406			$	15,741
Unrecognized prior service costs	31				48
Accumulated other comprehensive loss	$	14,437			$	15,789

The pension liability adjustments recognized in other comprehensive income (loss) during 2019, 2018, and 2017, were as follows:

	For the Years Ended December 31,
	2019				2018				2017
	(in thousands)
Net actuarial gain (loss)	$	377			$	4,329			$	(2,995	)
Amortization of prior service cost	17				18				17
Amortization of net actuarial loss	958				1,327				1,297
Settlements	—				—				3,009
Total pension liability adjustment, pre-tax	1,352				5,674				1,328
Tax expense	(291		)		(4,265		)		(561		)
Cumulative effect of accounting change (1)	—				2,969				—
Total pension liability adjustment, net	$	1,061			$	4,378			$	767

_________________________________________

(1)	Please refer to Recently Issued Accounting Standards in Note 1 – Summary of Significant Accounting Policies and Statements of Stockholders’ Equity for additional information.

Components of Net Periodic Benefit Cost for the Pension Plans

	For the Years Ended December 31,
	2019				2018				2017
	(in thousands)
Components of net periodic benefit cost:
Service cost	$	5,582			$	6,730			$	6,638
Interest cost	2,791				2,622				2,689
Expected return on plan assets that reduces periodic pension benefit cost	(1,574		)		(1,862		)		(2,244		)
Amortization of prior service cost	17				18				17
Amortization of net actuarial loss	958				1,327				1,297
Settlements	—				—				3,009
Net periodic benefit cost	$	7,774			$	8,835			$	11,406

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Pension Plan Assumptions

The weighted-average assumptions used to measure the Company’s projected benefit obligation are as follows:

	As of December 31,
	2019		2018
Projected benefit obligation:
Discount rate	3.6%		4.4%
Rate of compensation increase	4.5%		6.2%

The weighted-average assumptions used to measure the Company’s net periodic benefit cost are as follows:

	For the Years Ended December 31,
	2019		2018		2017
Net periodic benefit cost:
Discount rate	4.4%		3.8%		4.2%
Expected return on plan assets (1)	5.0%		5.5%		6.5%
Rate of compensation increase	6.2%		6.2%		6.2%

____________________________________________

(1)	There is no assumed expected return on plan assets for the Nonqualified Pension Plan because there are no plan assets in the Nonqualified Pension Plan.

The Company’s pension investment policy includes various guidelines and procedures designed to ensure that assets are prudently invested in a manner necessary to meet the future benefit obligation of the Pension Plans. The policy prohibits the direct investment of plan assets in the Company’s securities. The Qualified Pension Plan’s investment horizon is long-term and accordingly the target asset allocations encompass a strategic, long-term perspective of capital markets, expected risk and return behavior and perceived future economic conditions. The key investment principles of diversification, assessment of risk, and targeting the optimal expected returns for given levels of risk are applied.

The Qualified Pension Plan’s investment portfolio contains a diversified blend of investments, which may reflect varying rates of return. The investments are further diversified within each asset classification. This portfolio diversification provides protection against a single security or class of securities having a disproportionate impact on aggregate investment performance. The actual asset allocations are reviewed and rebalanced on a periodic basis to maintain the target allocations.

The weighted-average asset allocation of the Qualified Pension Plan is as follows:

		Target			As of December 31,
Asset Category		2020			2019			2018
Equity securities		35.0	%		36.9	%		31.8	%
Fixed income securities		40.0	%		38.1	%		41.3	%
Other securities		25.0	%		25.0	%		26.9	%
Total		100.0	%		100.0	%		100.0	%

There is no asset allocation of the Nonqualified Pension Plan since there are no plan assets in the plan. An expected return on plan assets of 5.0 percent, 5.5 percent, and 6.5 percent was used to calculate the Company’s net periodic pension cost under the Qualified Pension Plan for the years ended December 31, 2019, 2018, and 2017 respectively. The expected long-term rate of return assumption of the Qualified Pension Plan is based upon the target asset allocation and is determined using forward-looking assumptions in the context of historical returns and volatilities for each asset class, as well as correlations among asset classes. The Company evaluates the expected rate of return on plan assets assumption on an annual basis.

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Pension Plan Assets

The fair values of the Company’s Qualified Pension Plan assets as of December 31, 2019, and 2018, utilizing the fair value hierarchy discussed in Note 11 – Fair Value Measurements are as follows:

								Fair Value Measurements Using:
	Actual Asset Allocation (1)			Total				Level 1 Inputs				Level 2 Inputs				Level 3 Inputs
				(in thousands)
As of December 31, 2019
Equity securities:
Domestic (2)	17.3	%		$	6,176			$	4,130			$	2,046			$	—
International (3)	19.6	%		6,958				6,958				—				—
Total equity securities	36.9	%		13,134				11,088				2,046				—
Fixed income securities:
Core fixed income (4)	31.4	%		11,199				11,199				—				—
Floating rate corporate loans (5)	6.7	%		2,379				2,379				—				—
Total fixed income securities	38.1	%		13,578				13,578				—				—
Other securities:
Real estate (6)	5.4	%		1,929				—				—				1,929
Collective investment trusts (7)	3.3	%		1,168				—				1,168				—
Hedge fund (8)	16.3	%		5,825				2,006				—				3,819
Total other securities	25.0	%		8,922				2,006				1,168				5,748
Total investments	100.0	%		$	35,634			$	26,672			$	3,214			$	5,748
As of December 31, 2018
Equity securities:
Domestic (2)	15.4	%		$	4,639			$	3,197			$	1,442			$	—
International (3)	16.4	%		4,941				3,642				1,299				—
Total equity securities	31.8	%		9,580				6,839				2,741				—
Fixed income securities:
Core fixed income (4)	34.4	%		10,342				10,342				—				—
Floating rate corporate loans (5)	6.9	%		2,078				2,078				—				—
Total fixed income securities	41.3	%		12,420				12,420				—				—
Other securities:
Real estate (6)	6.0	%		1,820				—				—				1,820
Collective investment trusts (7)	3.1	%		934				—				934				—
Hedge fund (8)	17.8	%		5,346				—				1,659				3,687
Total other securities	26.9	%		8,100				—				2,593				5,507
Total investments	100.0	%		$	30,100			$	19,259			$	5,334			$	5,507

____________________________________________

(1)	Percentages may not calculate due to rounding.

(2)

Level 1 equity securities consist of United States large and small capitalization companies, which are actively traded securities that can be sold upon demand. Level 2 equity securities are investments in a collective investment fund that is valued at net asset value based on the value of the underlying investments and total units outstanding on a daily basis. The objective of these funds is to approximate the S&P 500 by investing in one or more collective investment funds.

(3)	International equity securities consists of a well-diversified portfolio of holdings of mostly large issuers organized in developed countries with liquid markets, commingled with investments in equity securities of issuers located in emerging markets and believed to have strong sustainable financial productivity at attractive valuations.

(4)	The objective of core fixed income funds is to achieve value added from sector or issue selection by constructing a portfolio to approximate the investment results of the Barclay’s Capital Aggregate Bond Index with a modest amount of variability in duration around the index.

(5)	Investments consist of floating rate bank loans. The interest rates on these loans are typically reset on a periodic basis to account for changes in the level of interest rates.

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(6)	The investment objective of direct real estate is to provide current income with the potential for long-term capital appreciation. Ownership in real estate entails a long-term time horizon, periodic valuations, and potentially low liquidity.

(7)	Collective investment trusts invest in short-term investments and are valued at the net asset value of the collective investment trust. The net asset value, as provided by the trustee, is used as a practical expedient to estimate fair value. The net asset value is based on the fair value of the underlying investments held by the fund less its liabilities.

(8)	The hedge fund portfolio includes investments in actively traded global mutual funds that focus on alternative investments and a hedge fund of funds that invests both long and short using a variety of investment strategies.

Included below is a summary of the changes in Level 3 plan assets (in thousands):

Balance at January 1, 2018	$	5,209
Purchases	—
Realized gain on assets	191
Unrealized gain on assets	152
Disposition	(45		)
Balance at December 31, 2018	$	5,507
Purchases	—
Realized gain on assets	190
Unrealized gain on assets	51
Disposition	—
Balance at December 31, 2019	$	5,748

Contributions

The Company contributed $7.2 million, $8.1 million, and $7.0 million to the Pension Plans for the years ended December 31, 2019, 2018, and 2017, respectively. The Company expects to make a $5.6 million contribution to the Pension Plans in 2020.

Benefit Payments

The Pension Plans made actual benefit payments of $5.7 million, $8.0 million, and $10.8 million in the years ended December 31, 2019, 2018, and 2017, respectively. Expected benefit payments over the next 10 years are as follows:

Years Ending December 31,	(in thousands)
2020	$	7,609
2021	$	3,914
2022	$	4,022
2023	$	6,308
2024	$	4,939
2025 through 2029	$	25,065

Note 9 - Earnings Per Share

Basic net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average number of common shares outstanding for the respective period. Diluted net income or loss per common share is calculated by dividing net income or loss available to common stockholders by the diluted weighted-average number of common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist primarily of non-vested RSUs, contingent PSUs, and shares into which the Senior Convertible Notes are convertible, which are measured using the treasury stock method.

PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading Performance Share Units.

On August 12, 2016, the Company issued $172.5 million in aggregate principal amount of Senior Convertible Notes due 2021. Upon conversion, the Senior Convertible Notes may be settled, at the Company’s election, in shares of the Company’s common stock, cash, or a combination of cash and common stock. The Company has initially elected a net-settlement method to satisfy its conversion obligation, which would result in the Company settling the principal amount of the Senior Convertible Notes in cash and the excess

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conversion value in shares. However, the Company has not made an irrevocable election and thereby reserves the right to settle the Senior Convertible Notes in any manner allowed under the indenture as business circumstances warrant. Shares of the Company’s common stock traded at an average closing price below the $40.50 conversion price for the years ended December 31, 2019, 2018, and 2017, therefore, the Senior Convertible Notes had no dilutive impact. In connection with the offering of the Senior Convertible Notes, the Company entered into capped call transactions with affiliates of the underwriters that would effectively prevent dilution upon settlement up to the $60.00 cap price. The capped call transactions will always be anti-dilutive and therefore will never be reflected in diluted net income or loss per share. Please refer to Note 5 – Long-Term Debt for additional discussion.

When the Company recognizes a net loss from continuing operations, as was the case for the years ended December 31, 2019, and 2017, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted net loss per common share.

The following table details the weighted-average anti-dilutive securities for the years presented:

	For the Years Ended December 31,
	2019			2018			2017
	(in thousands)
Anti-dilutive	684			—			264

The following table sets forth the calculations of basic and diluted net income (loss) per common share:

	For the Years Ended December 31,
	2019				2018				2017
	(in thousands, except per share data)
Net income (loss)	$	(187,001	)		$	508,407			$	(160,843	)
Basic weighted-average common shares outstanding	112,544				111,912				111,428
Dilutive effect of non-vested RSUs and contingent PSUs	—				1,590				—
Diluted weighted-average common shares outstanding	112,544				113,502				111,428
Basic net income (loss) per common share	$	(1.66	)		$	4.54			$	(1.44	)
Diluted net income (loss) per common share	$	(1.66	)		$	4.48			$	(1.44	)

Note 10 – Derivative Financial Instruments

Summary of Oil, Gas, and NGL Derivative Contracts in Place

The Company has entered into various commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. As of December 31, 2019, all derivative counterparties were members of the Company’s Credit Agreement lender group and all contracts were entered into for other-than-trading purposes. The Company’s commodity derivative contracts consist of swap and collar arrangements for oil and gas production, and swap arrangements for NGL production. In a typical commodity swap agreement, if the agreed upon published third-party index price (“index price”) is lower than the swap fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. For collar arrangements, the Company receives the difference between an agreed upon index price and the floor price if the index price is below the floor price. The Company pays the difference between the agreed upon ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and ceiling prices.

The Company has also entered into fixed price oil basis swaps in order to mitigate exposure to adverse pricing differentials between certain industry benchmark prices and the actual physical pricing points where the Company’s production volumes are sold. Currently, the Company has basis swap contracts with fixed price differentials between NYMEX WTI and WTI Midland for a portion of its Midland Basin production with sales contracts that settle at WTI Midland prices. The Company also has basis swaps with fixed price differentials between NYMEX WTI and Intercontinental Exchange Brent Crude (“ICE Brent”) for a portion of its Midland Basin oil production with sales contracts that settle at ICE Brent prices.

As of December 31, 2019, the Company had commodity derivative contracts outstanding through the fourth quarter of 2022, as summarized in the tables below.

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Oil Swaps

Contract Period		NYMEX WTI Volumes			Weighted-Average Contract Price
		(MBbl)			(per Bbl)
First quarter 2020		2,486			$	59.65
Second quarter 2020		2,838			$	58.81
Third quarter 2020		3,361			$	56.43
Fourth quarter 2020		3,937			$	56.94
2021		667			$	56.00
Total		13,289

Oil Collars

Contract Period		NYMEX WTI Volumes			Weighted-Average Floor Price				Weighted-Average Ceiling Price
		(MBbl)			(per Bbl)				(per Bbl)
First quarter 2020		2,267			$	55.00			$	63.91
Second quarter 2020		1,881			$	55.00			$	62.17
Third quarter 2020		1,252			$	55.00			$	62.90
Fourth quarter 2020		610			$	55.00			$	61.90
2021		329			$	55.00			$	56.70
Total		6,339

Oil Basis Swaps

Contract Period		WTI Midland-NYMEX WTI Volumes			Weighted-Average  Contract Price (1)				NYMEX WTI-ICE Brent Volumes			Weighted-Average Contract Price (2)
		(MBbl)			(per Bbl)				(MBbl)			(per Bbl)
First quarter 2020		4,193			$	(0.68	)		—			$	—
Second quarter 2020		3,495			$	(0.68	)		910			$	(8.06	)
Third quarter 2020		3,325			$	(0.74	)		920			$	(8.01	)
Fourth quarter 2020		3,261			$	(0.73	)		920			$	(8.01	)
2021		5,954			$	0.59			3,650			$	(7.86	)
2022		—			$	—			3,650			$	(7.78	)
Total		20,228							10,050

____________________________________________

(1)	Represents the price differential between WTI Midland (Midland, Texas) and NYMEX WTI (Cushing, Oklahoma).

(2)	Represents the price differential between NYMEX WTI (Cushing, Oklahoma) and ICE Brent (North Sea).

Gas Swaps

Contract Period		IF HSC Volumes			Weighted-Average Contract Price				WAHA Volumes			Weighted-Average Contract Price
		(BBtu)			(per MMBtu)				(BBtu)			(per MMBtu)
First quarter 2020		9,123			$	2.98			3,099			$	1.93
Second quarter 2020		4,160			$	2.20			3,196			$	0.56
Third quarter 2020		4,493			$	2.41			3,268			$	1.03
Fourth quarter 2020		3,722			$	2.36			3,419			$	1.17
2021		—			$	—			4,224			$	1.51
Total (1)		21,498							17,206

____________________________________________

(1)	The Company has natural gas swaps in place that settle against Inside FERC Houston Ship Channel (“IF HSC”), Inside FERC West Texas (“IF WAHA”), and Platt’s Gas Daily West Texas (“GD WAHA”). As of December 31, 2019, WAHA volumes were comprised of 92 percent IF WAHA and eight percent GD WAHA.

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NGL Swaps

		OPIS Ethane Purity Mont Belvieu							OPIS Propane Mont Belvieu Non-TET
Contract Period		Volumes			Weighted-Average Contract Price				Volumes			Weighted-Average Contract Price
		(MBbl)			(per Bbl)				(MBbl)			(per Bbl)
First quarter 2020		447			$	11.53			382			$	22.64
Second quarter 2020		264			$	11.13			382			$	22.34
Third quarter 2020		—			$	—			409			$	22.33
Fourth quarter 2020		—			$	—			466			$	22.29
Total		711							1,639

Commodity Derivative Contracts Entered Into Subsequent to December 31, 2019

Subsequent to December 31, 2019, the Company entered into the following commodity derivative contracts:

•	fixed price NYMEX WTI oil swap contracts for the fourth quarter of 2020 through January 2021 for a total of 0.6 MMBbl of oil production at a weighted-average contract price of $57.82 per Bbl; and

•	fixed price WTI Midland-NYMEX WTI oil basis swap contracts for the second quarter of 2020 through the fourth quarter of 2022 for a total of 16.3 MMBbl of oil production at a weighted-average contract price of $1.14 per Bbl.

Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the commodity derivative contracts at December 31, 2019, and 2018, was a net asset of $21.5 million and $158.3 million, respectively.

The following table details the fair value of commodity derivative contracts recorded in the accompanying balance sheets, by category:

	As of December 31, 2019				As of December 31, 2018
	(in thousands)
Derivative assets:
Current assets	$	55,184			$	175,130
Noncurrent assets	20,624				58,499
Total derivative assets	$	75,808			$	233,629
Derivative liabilities:
Current liabilities	$	50,846			$	62,853
Noncurrent liabilities	3,444				12,496
Total derivative liabilities	$	54,290			$	75,349

Offsetting of Derivative Assets and Liabilities

As of December 31, 2019, and 2018, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.

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The following table provides a reconciliation between the gross assets and liabilities reflected on the accompanying balance sheets and the potential effects of master netting arrangements on the fair value of the Company’s commodity derivative contracts:

		Derivative Assets								Derivative Liabilities
		As of December 31,								As of December 31,
		2019				2018				2019				2018
		(in thousands)
Gross amounts presented in the accompanying balance sheets		$	75,808			$	233,629			$	(54,290	)		$	(75,349	)
Amounts not offset in the accompanying balance sheets		(35,075		)		(56,041		)		35,075				56,041
Net amounts		$	40,733			$	177,588			$	(19,215	)		$	(19,308	)

The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring such amounts in accumulated other comprehensive income (loss). The Company had no derivatives designated as hedging instruments for the years ended December 31, 2019, 2018, and 2017. Please refer to Note 11 – Fair Value Measurements for more information regarding the Company’s derivative instruments, including its valuation techniques.

The following table summarizes the commodity components of the net derivative (gain) loss line item presented in the accompanying statements of operations:

	For the Years Ended December 31,
	2019				2018				2017
	(in thousands)
Derivative settlement (gain) loss:
Oil contracts	$	19,685			$	68,860			$	31,176
Gas contracts	(23,008		)		13,029				(87,857		)
NGL contracts	(35,899		)		53,914				35,447
Total derivative settlement (gain) loss	$	(39,222	)		$	135,803			$	(21,234	)
Net derivative (gain) loss:
Oil contracts	$	172,055			$	(192,002	)		$	71,502
Gas contracts	(41,205		)		35,411				(76,315		)
NGL contracts	(33,311		)		(5,241		)		31,227
Total net derivative (gain) loss	$	97,539			$	(161,832	)		$	26,414

Credit Related Contingent Features

As of December 31, 2019, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. Under the Credit Agreement, the Company is required to provide mortgage liens on assets having a value equal to at least 85 percent of the total PV-9, as defined in the Credit Agreement, of the Company’s proved oil and gas properties evaluated in the most recent reserve report. Collateral securing indebtedness under the Credit Agreement also secures the Company’s derivative agreement obligations.

Note 11 – Fair Value Measurements

The Company follows fair value measurement accounting guidance for all assets and liabilities measured at fair value. This guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of the following inputs:

•	Level 1 – quoted prices in active markets for identical assets or liabilities

•	Level 2 – quoted prices in active markets for similar assets or liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

•	Level 3 – significant inputs to the valuation model are unobservable

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Please refer to Note 1 – Summary of Significant Accounting Policies for additional information on the Company’s policies for determining fair value for the categories discussed below.

The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2019:

	Level 1				Level 2				Level 3
	(in thousands)
Assets:
Derivatives (1)	$	—			$	75,808			$	—
Liabilities:
Derivatives (1)	$	—			$	54,290			$	—

____________________________________________

(1)	This represents a financial asset or liability that is measured at fair value on a recurring basis.

The following table is a listing of the Company’s assets and liabilities that are measured at fair value in the accompanying balance sheets and where they are classified within the fair value hierarchy as of December 31, 2018:

	Level 1				Level 2				Level 3
	(in thousands)
Assets:
Derivatives (1)	$	—			$	233,629			$	—
Liabilities:
Derivatives (1)	$	—			$	75,349			$	—

____________________________________________

(1)	This represents a financial asset or liability that is measured at fair value on a recurring basis.

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy.

Derivatives

The Company uses Level 2 inputs to measure the fair value of oil, gas, and NGL commodity derivatives. Fair values are based upon interpolated data. The Company derives internal valuation estimates taking into consideration forward commodity price curves, counterparties’ credit ratings, the Company’s credit rating, and the time value of money. These valuations are then compared to the respective counterparties’ mark-to-market statements. The considered factors result in an estimated exit price that management believes provides a reasonable and consistent methodology for valuing derivative instruments. The commodity derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid. The oil, gas, and NGL commodity derivative markets are highly active.

Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. However, an adjustment may be necessary to reflect the credit quality of a specific counterparty to determine the fair value of the instrument. The Company monitors the credit ratings of its counterparties and may require counterparties to post collateral if their ratings deteriorate. In some instances, the Company will attempt to novate the trade to a more stable counterparty.

Valuation adjustments are necessary to reflect the effect of the Company’s credit quality on the fair value of any commodity derivative liability position. This adjustment takes into account any credit enhancements, such as collateral margin that the Company may have posted with a counterparty, as well as any letters of credit between the parties. The methodology to determine this adjustment is consistent with how the Company evaluates counterparty credit risk, taking into account the Company’s credit rating, current credit facility margins, and any change in such margins since the last measurement date.

The methods described above may result in a fair value estimate that may not be indicative of net realizable value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation methods utilized are appropriate and consistent with authoritative accounting guidance and other marketplace participants, the Company recognizes that third-parties may use different methodologies or assumptions to determine the fair value of certain financial instruments that could result in a different estimate of fair value at the reporting date.

Refer to Note 10 – Derivative Financial Instruments for more information regarding the Company’s derivative instruments.

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Oil and Gas Properties

Proved oil and gas properties. Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that associated carrying costs may not be recoverable. The Company uses Level 3 inputs and the income valuation technique to measure the fair value of proved properties through an application of discount rates and price forecasts representative of the current operating environment, as selected by the Company’s management.

Unproved oil and gas properties. Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses a market approach, which takes into account the following significant assumptions: remaining lease terms, future development plans, risk weighted potential resource recovery, estimated reserve values, and estimated acreage value based on price(s) received for similar, recent acreage transactions by the Company or other market participants.

There were no proved or unproved oil and gas properties recorded at fair value on the accompanying balance sheets as of December 31, 2019, or December 31, 2018.

The following table presents impairment of proved properties expense and abandonment and impairment of unproved properties expense recorded for the periods presented:

	For the Years Ended December 31,
	2019				2018				2017
	(in millions)
Impairment of proved properties	$	—			$	—			$	3.8
Abandonment and impairment of unproved properties	33.8				49.9				12.3
Impairment of oil and gas properties	$	33.8			$	49.9			$	16.1

Abandonment and impairment of unproved properties expense recorded during the years ended December 31, 2019, 2018, and 2017 primarily related to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks.

Long-Term Debt

The following table reflects the fair value of the Company’s unsecured senior note obligations measured using Level 1 inputs based on quoted secondary market trading prices. These notes were not presented at fair value on the accompanying balance sheets as of December 31, 2019, or 2018, as they were recorded at carrying value, net of any unamortized discounts and deferred financing costs. Please refer to Note 5 – Long-Term Debt for additional discussion.

	As of December 31,
	2019								2018
	Principal Amount				Fair Value				Principal Amount				Fair Value
	(in thousands)
6.125% Senior Notes due 2022	$	476,796			$	481,564			$	476,796			$	452,336
5.0% Senior Notes due 2024	$	500,000			$	479,815			$	500,000			$	439,265
5.625% Senior Notes due 2025	$	500,000			$	475,835			$	500,000			$	436,460
6.75% Senior Notes due 2026	$	500,000			$	494,860			$	500,000			$	448,305
6.625% Senior Notes due 2027	$	500,000			$	493,750			$	500,000			$	442,500
1.50% Senior Convertible Notes due 2021	$	172,500			$	164,430			$	172,500			$	158,614

The carrying value of the Company’s credit facility approximates its fair value, as the applicable interest rates are floating, based on prevailing market rates.

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Note 12 - Leases

Effective January 1, 2019, the Company adopted Topic 842, which requires lessees to recognize operating and finance leases with terms greater than 12 months on the balance sheet. The Company adopted this standard using the modified retrospective method and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance. As of December 31, 2019, the Company did not have any agreements in place that were classified as finance leases under Topic 842. Arrangements classified as operating leases are included on the accompanying balance sheets within the other noncurrent assets, other current liabilities, and other noncurrent liabilities line items. For any agreement that contains both lease and non-lease components, such as a service arrangement that also includes an identifiable ROU asset, the Company’s policy for all asset classes is to combine lease and non-lease components together and account for the arrangement as a single lease. Aside from the recognition of ROU assets and corresponding lease liabilities on the accompanying balance sheets, Topic 842 does not have a material impact on the timing or classification of costs incurred for those agreements considered to be leases.

As outlined in Topic 842, a ROU asset represents a lessee’s right to use an underlying asset for the lease term, while the associated lease liability represents the lessee’s obligations to make lease payments. At the commencement date, which is the date on which a lessor makes an underlying asset available for use by a lessee, a lease ROU asset and corresponding lease liability is recognized based on the present value of the future lease payments. The initial measurement of lease payments may also be adjusted for certain items, including options that are reasonably certain to be exercised, such as options to purchase the asset at the end of the lease term, or options to extend or early terminate the lease. Excluded from the initial measurement of a ROU asset and corresponding lease liability are certain variable lease payments, such as payments made that vary depending on actual usage or performance.

The Company evaluates a contractual arrangement at its inception to determine if it is a lease or contains an identifiable lease component as defined by Topic 842. When evaluating a contract to determine appropriate classification and recognition under Topic 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, which options are reasonably likely to be exercised, fair value of the underlying ROU asset or assets, upfront costs, and future lease payments that are included or excluded in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating a contract that meets the definition of a lease under Topic 842 include:

•	Discount Rate - Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease inception.

•

Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain an option will be exercised. Because of the Company’s intent to maintain financial and operational flexibility, there are no available options to extend that the Company is reasonably certain it will exercise. Additionally, based on expectations for those agreements with early termination options, there are no leases in which material early termination options are reasonably certain to be exercised by the Company.

Currently, the Company has operating leases for asset classes that include office space, office equipment, drilling rigs, midstream agreements, vehicles, and equipment rentals used in field operations. For those operating leases included on the accompanying balance sheets, which only includes leases with terms greater than 12 months at commencement, remaining lease terms range from less than one year to approximately six years. The weighted-average lease term remaining for these leases is approximately three years. Certain leases also contain optional extension periods that allow for terms to be extended for up to an additional 10 years. An early termination option also exists for certain leases, some of which allow for the Company to terminate a lease within one year. Exercising an early termination option may also result in an early termination penalty depending on the terms of the underlying agreement.

Subsequent to initial measurement, costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying ROU asset is utilized and in accordance with GAAP requirements. For example, costs associated with drilling rigs and completion crews that are considered ROU assets are typically capitalized as part of the development of the Company’s oil and gas properties. Please refer to Note 1 – Summary of Significant Accounting Policies for additional information on its accounting policies for oil and gas development and producing activities. When calculating the Company’s ROU asset and liability for a contractual arrangement that qualifies as an operating lease, the Company considers all of the necessary payments made or that are expected to be made upon commencement of the lease. Excluded from the initial measurement are certain variable lease payments, which for the Company’s drilling rigs, completion crews, and midstream agreements, may be a significant component of the total lease costs.

For the year ended December 31, 2019, total costs related to operating leases, including short-term leases, and variable lease payments made for leases with initial lease terms greater than 12 months, were $442.9 million. This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners.

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Components of the Company’s total lease cost, whether capitalized or expensed, for the year ended December 31, 2019, were as follows:

	For the Year Ended December 31, 2019
Operating lease cost	$	35,570
Short-term lease cost (1)	301,373
Variable lease cost (2)	106,006
Total lease cost (3)	$	442,949

____________________________________________

(1)

Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount is significant as it includes drilling and completion activities and field equipment rentals, most of which are contracted for 12 months or less. It is expected that this amount will fluctuate primarily with the number of drilling rigs and completion crews the Company is operating under short-term agreements.

(2)

Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding liability for lease agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain midstream agreements, actual usage associated with drilling rigs, completion crews, and vehicles, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes delivered and the number of drilling rigs and completion crews operating under long-term agreements.

(3)	Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset.

Other information related to the Company’s leases for the year ended December 31, 2019, was as follows:

	For the Year Ended December 31, 2019
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	12,074
Investing cash flows from operating leases	$	24,129
Right-of-use assets obtained in exchange for new operating lease liabilities	$	25,360

Maturities for the Company’s operating lease liabilities included on the accompanying balance sheets as of December 31, 2019, were as follows:

	As of December 31, 2019
	(in thousands)
2020	$	21,102
2021	12,600
2022	5,749
2023	3,602
2024	2,081
Thereafter	1,639
Total Lease payments	$	46,773
Less: Imputed interest (1)	(4,447		)
Total	$	42,326

____________________________________________

(1)	The weighted-average discount rate used to determine the operating lease liability as of December 31, 2019 was 6.6 percent.

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Amounts recorded on the accompanying balance sheets for operating leases as of December 31, 2019, were as follows:

	As of December 31, 2019
	(in thousands)
Other noncurrent assets	$	39,717
Other current liabilities	$	19,189
Other noncurrent liabilities	$	23,137

As of December 31, 2019, and through the filing of this report, the Company has no material lease arrangements which are scheduled to commence in the future.

Note 13 – Accounts Receivable and Accounts Payable and Accrued Expenses

Accounts receivable are comprised of the following accruals:

	As of December 31,
	2019				2018
	(in thousands)
Oil, gas, and NGL production revenue	$	146,308			$	107,230
Amounts due from joint interest owners	22,681				31,497
State severance tax refunds	4,069				4,415
Derivative settlements	6,868				9,475
Other	4,806				14,919
Total accounts receivable	$	184,732			$	167,536

Accounts payable and accrued expenses are comprised of the following accruals:

	As of December 31,
	2019				2018
	(in thousands)
Drilling and lease operating cost accruals	$	96,925			$	139,711
Trade accounts payable	52,094				56,047
Revenue and severance tax payable	109,847				94,806
Property taxes	24,535				18,694
Compensation	41,540				31,486
Derivative settlements	5,851				1,287
Interest	44,175				40,840
Other	27,041				20,328
Total accounts payable and accrued expenses	$	402,008			$	403,199

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Note 14 – Asset Retirement Obligations

Please refer to Asset Retirement Obligations in Note 1 – Summary of Significant Accounting Policies for a discussion of the initial and subsequent measurements of asset retirement obligation liabilities and the significant assumptions used in the estimates.

A reconciliation of the Company’s total asset retirement obligation liability is as follows:

	As of December 31,
	2019				2018
	(in thousands)
Beginning asset retirement obligations	$	94,194			$	114,470
Liabilities incurred (1)	3,927				4,054
Liabilities settled (2)	(4,105		)		(33,024		)
Accretion expense	4,016				4,438
Revision to estimated cash flows	(11,186		)		4,256
Ending asset retirement obligations (3)	$	86,846			$	94,194

____________________________________________

(1)	Reflects liabilities incurred through drilling activities and acquisitions of drilled wells.

(2)	Reflects liabilities settled through plugging and abandonment activities and divestitures of properties.

(3)	Balances as of December 31, 2019, and 2018, included $2.7 million and $2.3 million, respectively, related to the Company’s current asset retirement obligation liability, which is recorded in the accounts payable and accrued expenses line item on the accompanying balance sheets.

Note 15 – Suspended Well Costs

The following table reflects the net changes in capitalized exploratory well costs during 2019, 2018, and 2017. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year:

	For the Years Ended December 31,
	2019				2018				2017
	(in thousands)
Beginning balance	$	11,197			$	49,446			$	19,846
Additions to capitalized exploratory well costs pending the determination of proved reserves	11,925				11,197				49,446
Divestitures	—				(109		)		—
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	(11,197		)		(49,337		)		(19,846		)
Capitalized exploratory well costs charged to expense	—				—				—
Ending balance	$	11,925			$	11,197			$	49,446

As of December 31, 2019, there were no exploratory well costs that were capitalized for more than one year.

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(1)	Includes facility costs of $28.3 million, $72.6 million, and $43.8 million for the years ended December 31, 2019, 2018, and 2017, respectively.

(2)	Includes amounts related to leasing activity and acquiring surface rights outside of acquisitions of proved and unproved properties totaling $8.7 million, $23.4 million, and $12.8 million for the years ended December 31, 2019, 2018, and 2017, respectively.

(3)	Includes amounts relating to estimated asset retirement obligations of $(9.9) million, $7.1 million, and $13.6 million for the years ended December 31, 2019, 2018, and 2017, respectively.

(4)	Includes capitalized interest of $18.5 million, $20.6 million, and $12.6 million for the years ended December 31, 2019, 2018, and 2017, respectively.

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(1)

For the year ended December 31, 2019, the Company added 98.4 MMBOE from its drilling program and further development plan optimization. These additions were offset by net downward revisions of 94.7 MMBOE, which were primarily driven by declining commodity prices during 2019. Please refer to Areas of Operation in Part I, Items 1 and 2 of this report, and to Oil and Gas Reserve Quantities in Critical Accounting Policies and Estimates in Part II, Item 7 of this report for additional information.

(2)

For the year ended December 31, 2018, the Company added 188.0 MMBOE from its drilling program and through development plan optimization. The Company divested 40.3 MMBOE during 2018, primarily as a result of the PRB Divestiture, Divide County Divestiture, and Halff East Divestiture. The Company also had net downward revisions of 68.8 MMBOE, which resulted primarily from changes in development plans in its Eagle Ford shale program.

(3)	For the year ended December 31, 2017, the Company added 175.0 MMBOE from its drilling program. The Company divested 76.0 MMBOE during 2017, including 72.5 MMBOE related to its outside-operated Eagle Ford shale assets.

(4)	Please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions for additional information.

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(1)	Results of operations during 2019 were primarily impacted by the following:

(2)

For the first quarter of 2018, the Company recorded an estimated $409.2 million net pre-tax gain on divestiture activity related to the PRB Divestiture, which was partially offset by a $24.1 million write-down on certain assets. During the second quarter of 2018, the Company recorded an estimated $15.7 million net pre-tax gain on divestiture activity related to the Divide County Divestiture and Halff East Divestiture (please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions). During the third quarter of 2018, the Company recorded a $26.7 million loss on the early extinguishment of its 2021 Senior Notes, 2023 Senior Notes, and a portion of its 2022 Senior Notes (please refer to Note 5 – Long-Term Debt). For the first, second, third, and fourth quarters of 2018, the Company recorded net derivative losses of $7.5 million, $63.7 million, $178.0 million, and a net derivative gain of $411.1 million. Please refer to Note 10 – Derivative Financial Instruments for greater detail.

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(i)	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

(ii)	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

(iii)	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements.

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(1)

In May 2006, the stockholders approved the Equity Plan to authorize the issuance of restricted stock, restricted stock units, non-qualified stock options, incentive stock options, stock appreciation rights, performance shares, performance units, and stock-based awards to key employees, consultants, and members of the Board of Directors of the Company or any affiliate of the Company. The Company’s Board of Directors approved amendments to the Equity Plan in 2009, 2010, 2013, 2016, and 2018 and each amended plan was approved by stockholders at the respective annual stockholders’ meetings. The number of shares of the Company’s common stock underlying awards granted in 2019, 2018, and 2017 under the Equity Plan were 1,868,776, 1,220,217, and 2,078,878, respectively.

(2)

RSUs and PSUs do not have exercise prices associated with them, but rather a weighted-average per unit fair value, which is presented in order to provide additional information regarding the potential dilutive effect of the awards. The weighted-average grant date per unit fair value for the outstanding RSUs and PSUs was $16.04 and $16.89, respectively. Please refer to Note 7 – Compensation Plans in Part II, Item 8 of this report for additional discussion.

(3)	The number of awards to be issued assumes a one multiplier. The final number of shares of the Company’s common stock issued upon settlement may vary depending on the three-year multiplier determined at the end of the performance period under the Equity Plan, which ranges from zero to two.

(4)

Under the ESPP, eligible employees may purchase shares of the Company’s common stock through payroll deductions of up to 15 percent of their eligible compensation. The purchase price of the common stock is 85 percent of the lower of the fair market value of the common stock on the first or last day of the six-month offering period, and shares issued under the ESPP on or after December 31, 2011, have no minimum restriction period. The ESPP is intended to qualify under Section 423 of the IRC. The number of shares of the Company’s common stock issued in 2019, 2018, and 2017 under the ESPP were 314,868, 199,464, and 186,665, respectively.

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***	Certain portions of this exhibit have been redacted and are subject to a confidential treatment order granted by the Securities and Exchange Commission pursuant to Rule 24b-2 under the Exchange Act.

†	Exhibit constitutes a management contract or compensatory plan or agreement.

††	Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on July 30, 2010 primarily to reflect the change in the name of the registrant from St. Mary Land & Exploration Company to SM Energy Company. There were no material changes to the substantive terms and conditions in this document.

+	Exhibit constitutes a management contract or compensatory plan or agreement. This document was amended on

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