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•	Fluctuations in the price we receive for our oil, gas, and NGL production, including local market price differentials, which may be exacerbated by the demand destruction resulting from the highly transmissible and pathogenic coronavirus known as severe acute respiratory syndrome coronavirus 2 (SARS-CoV-2) that causes the disease known as COVID-19;

•	Cash flow and anticipated liquidity;

•	Disruptions to the availability of workers and contractors due to illness and stay at home orders related to the COVID-19 pandemic;

•	The availability of gathering, pipeline, refining, transportation and other midstream and downstream activities and our ability to sell oil, gas, and NGLs, which may be negatively impacted by the COVID-19 pandemic and risks and lead to a lack of any available markets;

•	Availability of supply chains and critical equipment and supplies, which may be negatively impacted by the COVID-19 pandemic and other risks;

•	Operating costs and other expenses;

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•	The effectiveness of our internal control over financial reporting and our ability to remediate a material weakness in our internal control over financial reporting;

•	Declines in the SEC PV10 value of our oil and gas properties resulting in full cost ceiling test impairments to the carrying values of our oil and gas properties;

•	Impairments of goodwill;

•	Our continuing compliance with the financial covenant contained in our amended and restated credit agreement;

•	The requirement to establish valuation allowances against our net deferred tax assets;

•	Our hedging activities and the viability of our hedging counterparties, many of whom have been negatively impacted by the COVID-19 pandemic;

•	Availability of financing and access to capital markets;

•	Higher than expected costs and expenses, including the availability and cost of services and materials;

•	Timing and amount of future production of oil, gas, and NGLs;

•	Reductions in the quantity of oil, gas, and NGLs sold and prices received because of decreased demand and/or curtailments in production relating to mechanical, transportation, storage, capacity, marketing, weather, the COVID-19 pandemic, or other problems;

•	Potential payments for failing to meet minimum oil, gas, and NGL delivery or sales commitments;

•	Estimates of proved reserves, exploitation potential, or exploration prospect size;

•	Our ability to successfully integrate the business acquired from Resolute Energy Corporation (“Resolute”);

•	Unknown liabilities related to Resolute;

•	Amount, nature, and timing of capital expenditures;

•	Administrative, legislative, and regulatory changes;

•	Operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated;

•	Exploration and development opportunities that we pursue may not result in economic, productive oil and gas properties;

•	Drilling of wells;

•	Increased financing costs due to a significant increase in interest rates;

•	Proving up undeveloped acreage;

•	Compliance with environmental and other regulations;

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•	Costs and availability of third party facilities for gathering, processing, refining, and transportation;

•	Risks associated with concentration of operations in one major geographic area;

•	Environmental liabilities;

•	The ability to receive drilling and other permits and rights-of-way in a timely manner;

•	Development drilling and testing results;

•	The potential for production decline rates to be greater than expected;

•	Performance of acquired properties and newly drilled wells;

•	Regulatory approvals, including regulatory restrictions on state and federal lands;

•	Legislative or regulatory changes, including initiatives related to hydraulic fracturing, emissions, and disposal of produced water;

•	Unexpected future capital expenditures;

•	Economic and competitive conditions;

•	The availability and cost of capital;

•	The ability to obtain industry partners to jointly explore certain prospects, and the willingness and ability of those partners to meet capital obligations when requested;

•	Changes in estimates of proved reserves;

•	Derivative and hedging activities;

•	The success of the company’s risk management activities;

•	Title to properties;

•	Litigation;

•	The ability to complete property sales or other transactions; and

•	Other factors discussed in the company’s reports filed with the Securities and Exchange Commission (“SEC”).

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1.	BASIS OF PRESENTATION

Cimarex Energy Co. (“Cimarex,” “we,” or “us”), a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, and New Mexico. The accompanying unaudited financial statements have been prepared pursuant to rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain disclosures required by accounting principles generally accepted in the United States and normally included in Annual Reports on Form 10-K have been omitted. Although management believes that our disclosures in these interim financial statements are adequate, they should be read in conjunction with the financial statements, summary of significant accounting policies, and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2019.

In the opinion of management, the accompanying financial statements reflect all adjustments necessary to fairly present our financial position, results of operations, and cash flows for the periods and as of the dates shown. The accounts of Cimarex and its subsidiaries are presented in the accompanying financial statements, with intercompany balances and transactions eliminated in consolidation. Certain amounts in the prior year financial statements have been reclassified to conform to the 2020 financial statement presentation.

On March 1, 2019, we acquired Resolute Energy Corporation (“Resolute”) in a cash and stock transaction. The results of Resolute’s operations have been included in our consolidated financial statements since the March 1, 2019 acquisition date. See Note 13 for more information on this transaction.

Use of Estimates

Areas of significance requiring the use of management’s judgments include the estimation of proved oil and gas reserves used in calculating depletion, the estimation of future net revenues used in computing ceiling test limitations, the estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill. Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, lease liabilities, and contingencies.

Prior Year Reclassifications

Certain amounts in the prior year financial statements have been reclassified to conform to the 2020 financial statement presentation. These reclassifications include reclassifying certain “Gas gathering and other” expenses to “Transportation, processing, and other operating” expense and “Production” expense. These reclassifications were made to reflect an allocation of the costs incurred to operate our gas gathering facilities as a cost to transport our equity share of gas produced and operate our wells. The following table shows the reclassifications made:

		Three Months Ended March 31, 2019
(in thousands)		Prior Year Presentation				Current Year Reclassifications				Current Year Presentation
Production		$	77,233			$	1,171			$	78,404
Transportation, processing, and other operating		$	53,608			5,967				$	59,575
Gas gathering and other		$	12,320			(7,138		)		$	5,182
						$	—

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Oil and Gas Well Equipment and Supplies

Our oil and gas well equipment and supplies are valued at the lower of cost and net realizable value, where net realizable value is estimated selling prices in the ordinary course of business, less reasonably predictable costs of disposal and transportation. Declines in the price of oil and gas well equipment and supplies in future periods could cause us to recognize impairments on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.

Oil and Gas Properties

We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Under the full cost method of accounting, we are required to perform a quarterly ceiling test calculation to test our oil and gas properties for possible impairment. If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes. We currently do not have any unproven properties that are being amortized. Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.

The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, overall exploration and development costs, and deferred taxes.  If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we may incur a full cost ceiling test impairment. The calculated ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.  Any impairment of oil and gas properties is not reversible at a later date. 

At March 31, 2020, we incurred a ceiling test impairment of $333.7 million.  The impairment resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, gas, and NGLs as well as significant basis differentials utilized in determining the estimated future net cash flows from proved reserves. We expect these conditions to continue at least through June 30, 2020 and possibly beyond and, therefore, expect to incur another ceiling test impairment at June 30, 2020.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. In performing the goodwill test, we compare the fair value of our reporting unit with its carrying amount. If the carrying amount of the reporting unit were to exceed its fair value, an impairment charge would be recognized in the amount of this excess, limited to the total amount of goodwill allocated to that reporting unit. We evaluate our goodwill for impairment in the fourth quarter of each year and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based upon our assessment as of October 31, 2019, goodwill was not impaired. However, during the quarter ended March 31, 2020 the company’s market capitalization declined significantly driven by current macroeconomic and geopolitical conditions including the collapse of oil prices driven by surplus supply and decreased demand caused by the COVID-19 pandemic. In addition, the uncertainty related to oil demand continues to have a significant impact on our investment and operating decisions. Based on these events, we concluded that a triggering event occurred, which required us to perform an interim quantitative impairment test for goodwill as of March 31, 2020. As a result of that quantitative impairment test, which utilized quoted market prices for the company’s common stock as a basis for determining fair value, we concluded that goodwill was impaired at March 31, 2020.

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The following table reflects components of the change in the carrying amount of goodwill for the three months ended March 31, 2020:

(in thousands)		Three Months Ended March 31, 2020
Goodwill balance at January 1, 2020		$	716,865
Resolute acquisition purchase price adjustments (Note 13)		(2,418		)
Impairment		(714,447		)
Goodwill balance at March 31, 2020		$	—

Revenue Recognition

Oil, Gas, and NGL Sales

Revenue is recognized from the sales of oil, gas, and NGLs when the customer obtains control of the product, when we have no further obligations to perform related to the sale, and when collectability is probable. All of our sales of oil, gas, and NGLs are made under contracts with customers, which typically include variable consideration based on monthly pricing tied to local indices and monthly volumes delivered. The nature of our contracts with customers does not require us to constrain that variable consideration or to estimate the amount of transaction price attributable to future performance obligations for accounting purposes. As of March 31, 2020, we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas, and/or NGLs. Our contracts with customers typically require payment within one month of delivery.

Our gas is sold under various contracts. Under these contracts the gas and its components, including residue gas and NGLs, may be sold to a single purchaser or separate purchasers. Regardless of the contract, we are compensated for the value of the residue gas and NGLs at current market prices for each product. Depending on the specific contract terms, certain gathering, treating, transportation, processing, and other charges may be deducted against the prices we receive for the products. Our oil typically is sold at specific delivery points under contract terms that also are common in our industry.

Gas Gathering

When we transport and/or process third-party gas associated with our equity gas, we recognize revenue for the fees charged to third-parties for such services.

Gas Marketing

When we market and sell gas for other working interest owners, we act as agent under short-term sales and supply agreements and may earn a fee for such services. Revenues from such services are recognized as gas is delivered.

Gas Imbalances

Revenue from the sale of gas is recorded on the basis of gas actually sold by or for us. If our aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

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2.	LONG-TERM DEBT

Long-term debt at March 31, 2020 and December 31, 2019 consisted of the following:

		March 31, 2020												December 31, 2019
(in thousands)		Principal				Unamortized Debt Issuance Costs and Discounts (1)				Long-term Debt, net				Principal				Unamortized Debt Issuance Costs and Discounts (1)				Long-term Debt, net
4.375% Notes due 2024		$	750,000			$	(3,316	)		$	746,684			$	750,000			$	(3,535	)		$	746,465
3.90% Notes due 2027		750,000				(6,105		)		743,895				750,000				(6,289		)		743,711
4.375% Notes due 2029		500,000				(4,821		)		495,179				500,000				(4,930		)		495,070
		$	2,000,000			$	(14,242	)		$	1,985,758			$	2,000,000			$	(14,754	)		$	1,985,246

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(1)

The 4.375% Notes due 2024 were issued at par, therefore, the amounts shown in the table are for unamortized debt issuance costs only. At March 31, 2020, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $4.7 million and $1.4 million, respectively. At March 31, 2020, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.2 million and $0.6 million, respectively. At December 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $4.8 million and $1.5 million, respectively. At December 31, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.3 million and $0.6 million, respectively.

Bank Debt

On February 5, 2019, we entered into an Amended and Restated Credit Agreement for our senior unsecured revolving credit facility (“Credit Facility”). The Credit Facility has aggregate commitments of $1.25 billion with an option for us to increase the aggregate commitments to $1.5 billion, and matures on February 5, 2024. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. As of March 31, 2020, we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of $1.248 billion. During the three months ended March 31, 2020, we borrowed and repaid an aggregate of $101.0 million on the Credit Facility to meet cash requirements as needed.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR (or an alternate rate determined by the administrative agent for the Credit Facility in accordance with the Credit Facility when LIBOR is no longer available) plus 1.125 – 2.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.125 – 1.0%, based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of 0.125 – 0.35%, based on the credit rating for our senior unsecured long-term debt.

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. As of March 31, 2020, we were in compliance with all of the financial covenants.

At March 31, 2020 and December 31, 2019, we had $3.9 million and $4.0 million, respectively, of unamortized debt issuance costs associated with our Credit Facility, which were recorded as assets and included in “Other assets” on our Condensed Consolidated Balance Sheets. These costs are being amortized to interest expense ratably over the life of the Credit Facility.

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Senior Notes

On March 8, 2019, we issued $500 million aggregate principal amount of 4.375% senior unsecured notes due March 15, 2029 at 99.862% of par to yield 4.392% per annum.  We received $494.7 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs.  The notes bear an annual interest rate of 4.375% and interest is payable semiannually on March 15 and September 15, with the first payment made on September 15, 2019.  We used the net proceeds to repay borrowings outstanding under our Credit Facility that were used to help fund the Resolute acquisition on March 1, 2019. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.50%.

In April 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes at 99.748% of par to yield 3.93% per annum. These notes are due May 15, 2027 and interest is payable semiannually on May 15 and November 15. The effective interest rate on these notes, including the amortization of debt issuance costs and discount, is 4.01%.

In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and interest is payable semiannually on June 1 and December 1. The effective interest rate on these notes, including the amortization of debt issuance costs, is 4.50%.

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We periodically use derivative instruments to mitigate volatility in commodity prices.  While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future cash flow from favorable price changes.  Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. 

As of March 31, 2020, we have entered into oil and gas collars and oil basis swaps. We also occasionally enter into fixed price swaps. Under our collars, we receive the difference between the published index price and a floor price if the index price is below the floor price or we pay the difference between the 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 the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price plus or minus a fixed differential, as applicable, and the applicable local index price under which the underlying production is sold. By using a basis swap, we have fixed the differential between the published index price and certain of our physical pricing points. For our Permian oil production, the basis swaps fix the price differential between the WTI NYMEX (Cushing Oklahoma) price and the WTI Midland price. For our Permian and Mid-Continent gas production, the contract prices in our collars are consistent with the index prices used to sell our production. Under our fixed price swaps, we receive the difference between the fixed price and the published index price if the published index price is below the fixed price and we pay the difference between the fixed price and the published index price if the published index price is above the fixed price. The following tables summarize our outstanding derivative contracts as of March 31, 2020:

Oil Collars		First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total
2020:
WTI (1)
Volume (Bbls)		—				2,821,000				3,588,000				3,588,000				9,997,000
Weighted Avg Price - Floor		$	—			$	50.43			$	41.47			$	41.47			$	44.00
Weighted Avg Price - Ceiling		$	—			$	61.55			$	50.32			$	50.32			$	53.49
2021:
WTI (1)
Volume (Bbls)		2,790,000				1,911,000				1,104,000				1,104,000				6,909,000
Weighted Avg Price - Floor		$	39.27			$	34.38			$	29.67			$	29.67			$	34.85
Weighted Avg Price - Ceiling		$	47.10			$	41.41			$	36.25			$	36.25			$	42.06

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(1)	The index price for these collars is West Texas Intermediate (“WTI”) as quoted on the New York Mercantile Exchange (“NYMEX”).

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Gas Collars		First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total
2020:
PEPL (1)
Volume (MMBtu)		—				5,460,000				6,440,000				6,440,000				18,340,000
Weighted Avg Price - Floor		$	—			$	1.90			$	1.75			$	1.75			$	1.79
Weighted Avg Price - Ceiling		$	—			$	2.28			$	2.17			$	2.17			$	2.20
Perm EP (2)
Volume (MMBtu)		—				2,730,000				5,520,000				5,520,000				13,770,000
Weighted Avg Price - Floor		$	—			$	1.40			$	1.33			$	1.33			$	1.35
Weighted Avg Price - Ceiling		$	—			$	1.82			$	1.61			$	1.61			$	1.65
Waha (3)
Volume (MMBtu)		—				2,730,000				3,680,000				3,680,000				10,090,000
Weighted Avg Price - Floor		$	—			$	1.57			$	1.28			$	1.28			$	1.35
Weighted Avg Price - Ceiling		$	—			$	1.97			$	1.54			$	1.54			$	1.65
2021:
PEPL (1)
Volume (MMBtu)		4,500,000				3,640,000				1,840,000				1,840,000				11,820,000
Weighted Avg Price - Floor		$	1.71			$	1.67			$	1.70			$	1.70			$	1.69
Weighted Avg Price - Ceiling		$	2.11			$	2.06			$	2.12			$	2.12			$	2.10
Perm EP (2)
Volume (MMBtu)		3,600,000				3,640,000				1,840,000				1,840,000				10,920,000
Weighted Avg Price - Floor		$	1.33			$	1.33			$	1.50			$	1.50			$	1.38
Weighted Avg Price - Ceiling		$	1.58			$	1.58			$	1.80			$	1.80			$	1.66
Waha (3)
Volume (MMBtu)		3,600,000				3,640,000				1,840,000				1,840,000				10,920,000
Weighted Avg Price - Floor		$	1.28			$	1.28			$	1.50			$	1.50			$	1.35
Weighted Avg Price - Ceiling		$	1.54			$	1.54			$	1.75			$	1.75			$	1.61

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(1)	The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC.

(2)	The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC.

(3)	The index price for these collars is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.

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Oil Basis Swaps		First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total
2020:
WTI Midland (1)
Volume (Bbls)		—				2,366,000				2,392,000				2,392,000				7,150,000
Weighted Avg Differential (2)		$	—			$	0.44			$	0.36			$	0.36			$	0.39
2021:
WTI Midland (1)
Volume (Bbls)		1,620,000				1,092,000				644,000				644,000				4,000,000
Weighted Avg Differential (2)		$	0.21			$	0.03			$	(0.68	)		$	(0.68	)		$	(0.13	)

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(1)	The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.

(2)	The index price we receive under these basis swaps is WTI as quoted on the NYMEX plus or minus, as applicable, the weighted average differential shown in the table.

The following tables summarize our derivative contracts entered into subsequent to March 31, 2020 through May 8, 2020:

Oil Collars		First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total
2020:
WTI (1)
Volume (Bbls)		—				304,000				184,000				184,000				672,000
Wtd Avg Price - Floor		$	—			$	28.39			$	30.00			$	30.00			$	29.27
Wtd Avg Price - Ceiling		$	—			$	34.91			$	40.50			$	40.50			$	37.97
2021:
WTI (1)
Volume (Bbls)		180,000				182,000				184,000				184,000				730,000
Wtd Avg Price - Floor		$	30.00			$	30.00			$	30.00			$	30.00			$	30.00
Wtd Avg Price - Ceiling		$	40.50			$	40.50			$	40.50			$	40.50			$	40.50

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(1)	The index price for these collars is WTI as quoted on the NYMEX.

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Gas Collars		First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total
2020:
PEPL (1)
Volume (MMBtu)		—				300,000				920,000				920,000				2,140,000
Weighted Avg Price - Floor		$	—			$	1.78			$	1.78			$	1.78			$	1.78
Weighted Avg Price - Ceiling		$	—			$	2.18			$	2.18			$	2.18			$	2.18
Perm EP (2)
Volume (MMBtu)		—				300,000				920,000				920,000				2,140,000
Weighted Avg Price - Floor		$	—			$	1.52			$	1.52			$	1.52			$	1.52
Weighted Avg Price - Ceiling		$	—			$	1.80			$	1.80			$	1.80			$	1.80
Waha (3)
Volume (MMBtu)		—				300,000				920,000				920,000				2,140,000
Weighted Avg Price - Floor		$	—			$	1.50			$	1.50			$	1.50			$	1.50
Weighted Avg Price - Ceiling		$	—			$	1.76			$	1.76			$	1.76			$	1.76
2021:
PEPL (1)
Volume (MMBtu)		900,000				910,000				920,000				920,000				3,650,000
Weighted Avg Price - Floor		$	1.78			$	1.78			$	1.78			$	1.78			$	1.78
Weighted Avg Price - Ceiling		$	2.18			$	2.18			$	2.18			$	2.18			$	2.18
Perm EP (2)
Volume (MMBtu)		900,000				910,000				920,000				920,000				3,650,000
Weighted Avg Price - Floor		$	1.52			$	1.52			$	1.52			$	1.52			$	1.52
Weighted Avg Price - Ceiling		$	1.80			$	1.80			$	1.80			$	1.80			$	1.80
Waha (3)
Volume (MMBtu)		900,000				910,000				920,000				920,000				3,650,000
Weighted Avg Price - Floor		$	1.50			$	1.50			$	1.50			$	1.50			$	1.50
Weighted Avg Price - Ceiling		$	1.76			$	1.76			$	1.76			$	1.76			$	1.76

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(1)	The index price for these collars is PEPL as quoted in Platt’s Inside FERC.

(2)	The index price for these collars is Perm EP as quoted in Platt’s Inside FERC.

(3)	The index price for these collars is Waha as quoted in Platt’s Inside FERC.

Oil Basis Swaps		First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total
2020:
WTI Midland (1)
Volume (Bbls)		—				150,000				552,000				552,000				1,254,000
Weighted Avg Differential (2)		$	—			$	(0.59	)		$	(0.62	)		$	(0.62	)		$	(0.61	)
2021:
WTI Midland (1)
Volume (Bbls)		540,000				546,000				552,000				552,000				2,190,000
Weighted Avg Differential (2)		$	(0.62	)		$	(0.62	)		$	(0.62	)		$	(0.62	)		$	(0.62	)

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(1)	The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.

(2)	The index price we receive under these basis swaps is WTI as quoted on the NYMEX plus or minus, as applicable, the weighted average differential shown in the table.

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Oil Swaps		First Quarter				Second Quarter				Third Quarter				Fourth Quarter				Total
2020:
WTI (1)
Volume (Bbls)		—				427,000				—				—				427,000
Weighted Avg Price		$	—			$	20.73			$	—			$	—			$	20.73

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(1)	The fixed price on these swaps is NYMEX WTI.

Derivative Gains and Losses

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The following table presents the components of “(Gain) loss on derivative instruments, net” for the periods indicated.

		Three Months Ended March 31,
(in thousands)		2020				2019
Decrease (increase) in fair value of derivative instruments, net:
Gas contracts		$	12,493			$	(9,846	)
Oil contracts		(196,319		)		116,247
		(183,826		)		106,401
Cash (receipts) payments on derivative instruments, net:
Gas contracts		(11,719		)		3,764
Oil contracts		(31,395		)		5,287
		(43,114		)		9,051
(Gain) loss on derivative instruments, net		$	(226,940	)		$	115,452

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Derivative Fair Value

Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and are subject to master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same counterparty. Our accounting policy is to not offset asset and liability positions in our balance sheets.

The following tables present the amounts and classifications of our derivative assets and liabilities as of March 31, 2020 and December 31, 2019, as well as the potential effect of netting arrangements on our recognized derivative asset and liability amounts.

				March 31, 2020
(in thousands)		Balance Sheet Location		Asset				Liability
Oil contracts		Current assets — Derivative instruments		$	189,689			$	—
Gas contracts		Current assets — Derivative instruments		10,848				—
Oil contracts		Non-current assets — Derivative instruments		7,121				—
Oil contracts		Current liabilities — Derivative instruments		—				2,963
Gas contracts		Current liabilities — Derivative instruments		—				3,809
Oil contracts		Non-current liabilities — Derivative instruments		—				12,829
Gas contracts		Non-current liabilities — Derivative instruments		—				3,406
Total gross amounts presented in the balance sheet				207,658				23,007
Less: gross amounts not offset in the balance sheet				(23,007		)		(23,007		)
Net amount				$	184,651			$	—
				December 31, 2019
(in thousands)		Balance Sheet Location		Asset				Liability
Oil contracts		Current assets — Derivative instruments		$	1,624			$	—
Gas contracts		Current assets — Derivative instruments		16,320				—
Oil contracts		Non-current assets — Derivative instruments		580				—
Oil contracts		Current liabilities — Derivative instruments		—				16,681
Oil contracts		Non-current liabilities — Derivative instruments		—				824
Gas contracts		Non-current liabilities — Derivative instruments		—				194
Total gross amounts presented in the balance sheet				18,524				17,699
Less: gross amounts not offset in the balance sheet				(9,865		)		(9,865		)
Net amount				$	8,659			$	7,834

We are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties. We mitigate our exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of our bank credit facility. Our member banks do not require us to post collateral for our derivative liability positions, nor do we require our counterparties to post collateral for our benefit. In the future we may enter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.

4.	FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The FASB has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable.

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The following table provides fair value measurement information for certain assets and liabilities as of March 31, 2020 and December 31, 2019:

		March 31, 2020								December 31, 2019
(in thousands)		Book Value				Fair Value				Book Value				Fair Value
Financial Assets (Liabilities):
4.375% Notes due 2024		$	(750,000	)		$	(591,075	)		$	(750,000	)		$	(792,225	)
3.90% Notes due 2027		$	(750,000	)		$	(502,200	)		$	(750,000	)		$	(778,050	)
4.375% Notes due 2029		$	(500,000	)		$	(334,800	)		$	(500,000	)		$	(530,400	)
Derivative instruments — assets		$	207,658			$	207,658			$	18,524			$	18,524
Derivative instruments — liabilities		$	(23,007	)		$	(23,007	)		$	(17,699	)		$	(17,699	)

Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The fair value (Level 1) of our fixed rate notes was based on quoted market prices. The fair value of our derivative instruments (Level 2) was estimated using discounted cash flow and option pricing models. These models use certain observable variables including forward prices, volatility curves, interest rates, and credit ratings and spreads. The fair value estimates are adjusted relative to non-performance risk as appropriate. See Note 3 for further information on the fair value of our derivative instruments.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. Included in “Accrued liabilities — Other” at March 31, 2020 are accrued operating expenses (e.g. production, transportation, and gathering expenses) of approximately $71.7 million. Included in “Accrued liabilities — Other” at December 31, 2019 are: (i) accrued operating expenses (e.g. production, transportation, and gathering expenses) of approximately $74.7 million and (ii) accrued general and administrative costs, primarily payroll-related, of approximately $43.3 million.

Most of our accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and gas industry. Concentration of customers may impact our overall credit risk because our customers may be similarly affected by changes in economic or other conditions within the industry. We conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary. Pursuant to the operating agreements we have with the co-owners of our operated properties, we have the right to realize amounts due to us from the co-owners by netting the co-owners’ production revenues from those properties.

We routinely assess the recoverability of all material accounts receivable and accrue a reserve to the allowance for doubtful accounts based on our estimation of expected losses over the life of the receivables. At March 31, 2020 and December 31, 2019, the allowance for doubtful accounts was $3.8 million and $3.6 million, respectively.

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5.	CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At March 31, 2020, there were 102.1 million shares of common stock outstanding and 62.5 thousand shares of 8.125% Series A Cumulative Perpetual Convertible Preferred Stock outstanding (the “Convertible Preferred Stock”). Holders of the Convertible Preferred Stock are entitled to receive, when, as, and if declared by the Board, cumulative cash dividends at an annual rate of 8.125% of each share’s liquidation preference of $1,000. In the event of any liquidation, winding up, or dissolution of Cimarex, each holder will be entitled to receive in respect of its shares, up to each share’s liquidation preference, with the total liquidation preference being $62.5 million in the aggregate, after satisfaction of liabilities and any senior stock (of which there is currently none) and before any payment or distribution to holders of junior stock (including common stock). Each holder has the right at any time, at its option, to convert any or all of such holder’s shares of Convertible Preferred Stock into a certain number of shares of Cimarex common stock based on a conversion rate that adjusts upon the occurrence of certain events, including the payment of cash dividends to common shareholders, plus $471.40 in cash per share of Convertible Preferred Stock. The March 31, 2020 conversion rate was 8.17712 shares of common stock for each share of Convertible Preferred Stock. As a result of the cash component included in the redemption feature of the Convertible Preferred Stock conversion option, with such conversion not solely within our control, the instruments are classified as Redeemable preferred stock in temporary equity on the Condensed Consolidated Balance Sheets.

Dividends

Common Stock

In February 2020, our Board of Directors declared a cash dividend of $0.22 per share of common stock. The dividend is payable on or before June 1, 2020 to stockholders of record on May 15, 2020. Dividends declared are recorded as a reduction of retained earnings to the extent retained earnings are available at the close of the period prior to the date of the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital. The $22.5 million dividend declared during the first quarter 2020 was recorded as a reduction of retained earnings and is included as a payable in “Accrued liabilities — Other” on the Condensed Consolidated Balance Sheet at March 31, 2020. Nonforfeitable dividends paid on stock awards that subsequently forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to stock compensation expense in the period in which the forfeitures occur. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

Preferred Stock

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6.	STOCK-BASED COMPENSATION

We have recognized stock-based compensation cost as shown below for the periods indicated.

		Three Months Ended March 31,
(in thousands)		2020				2019
Restricted stock awards:
Performance stock awards		$	4,060			$	5,394
Service-based stock awards		7,377				7,231
		11,437				12,625
Stock option awards		498				622
Total stock compensation cost		11,935				13,247
Less amounts capitalized to oil and gas properties		(5,541		)		(6,534		)
Stock compensation expense		$	6,394			$	6,713

7.	ASSET RETIREMENT OBLIGATIONS

We recognize the present value of the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs related to the plugging and abandonment of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is accreted each period. If there is a change in the estimated cost or timing of retirement, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost. Capitalized costs are included as a component of the depreciation and depletion calculations.

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the three months ended March 31, 2020:

(in thousands)		Three Months Ended March 31, 2020
Asset retirement obligation at January 1, 2020		$	181,869
Liabilities incurred		1,080
Liability settlements and disposals		(7,440		)
Accretion expense		1,925
Revisions of estimated liabilities		2,800
Asset retirement obligation at March 31, 2020		180,234
Less current obligation		(22,841		)
Long-term asset retirement obligation		$	157,393

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8.	EARNINGS (LOSS) PER SHARE

The calculations of basic and diluted net earnings (loss) per common share under the two-class method are presented below for the periods indicated:

		Three Months Ended March 31,
		2020											2019
(in thousands, except per share information)		Income (Numerator)				Shares (Denominator)			Per-Share Amount				Income (Numerator)				Shares (Denominator)			Per-Share Amount
Net (loss) income		$	(774,282	)									$	26,316
Less: dividends and net income attributable to participating securities (1)		(550		)									(445		)
Less: preferred stock dividends		(1,269		)									(1,269		)
Basic (loss) earnings per share
(Loss) income available to common stockholders		(776,101		)		99,842			$	(7.77	)		24,602				95,922			$	0.26
Effects of dilutive securities
Options (2)		—				—							—				10
Diluted (loss) earnings per share
(Loss) income available to common stockholders and assumed conversions		$	(776,101	)		99,842			$	(7.77	)		$	24,602			95,932			$	0.26

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(1)	Participating securities do not have a contractual obligation to share in the losses of the entity, therefore, net losses are not attributable to participating securities.

(2)

Inclusion of certain potential common shares would have an anti-dilutive effect, therefore, these shares were excluded from the calculations of diluted earnings (loss) per share. Excluded from the calculation for the three months ended March 31, 2020 were 474.5 thousand potential common shares from the assumed exercise of employee stock options, 511.1 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock, and 8.8 thousand potential common shares from the assumed vesting of incremental shares of unvested restricted stock awards. Excluded from the calculation for the three months ended March 31, 2019 were 388.6 thousand potential common shares from the assumed exercise of employee stock options and 502.6 thousand potential common shares from the assumed conversion of the Convertible Preferred Stock.

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9.	INCOME TAXES

The components of our provision for income taxes and our combined federal and state effective income tax rates were as follows:

		Three Months Ended March 31,
(in thousands)		2020				2019
Current tax benefit		$	(198	)		$	—
Deferred tax (benefit) expense		(16,357		)		8,073
		$	(16,555	)		$	8,073
Combined federal and state effective income tax rate		2.1		%		23.5		%

At December 31, 2019, we had a U.S. net tax operating loss carryforward of approximately $1.93 billion, which will expire in tax years 2032 through 2039. We believe that the carryforward will be utilized before it expires. We also had enhanced oil recovery and marginal well credits of $3.9 million at December 31, 2019.

On March 1, 2019, we completed the acquisition of Resolute. For federal income tax purposes, the acquisition was a tax-free merger whereby Cimarex acquired carryover tax basis in Resolute’s tax assets and liabilities. As of December 31, 2019, we recorded a net deferred tax liability of $31.1 million to reflect the difference between the fair value of Resolute’s assets and liabilities recorded in the acquisition and the income tax basis of the assets and liabilities assumed. As of March 31, 2020, no adjustments have been made to the net deferred tax liability reported at December 31, 2019. See Note 13 for more information regarding the purchase price allocation. The net deferred tax liability includes certain deferred tax assets net of valuation allowances. The acquired tax attributes include federal net operating loss, capital loss, and enhanced oil recovery tax credit carryforwards. The carryforwards are subject to an annual limitation under Internal Revenue Code Section 382.

At March 31, 2020, we had no unrecognized tax benefits that would impact our effective tax rate and have made no provisions for interest or penalties related to uncertain tax positions. The tax years 2016 through 2018 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities, which remain open to examination for tax years 2015 through 2018.

Our combined federal and state effective income tax rates differ from the U.S. federal statutory rate of 21% primarily due to state income taxes and non-deductible expenses. The combined federal and state effective income tax rate for the three months ended March 31, 2020 is impacted by the tax effects of the impairment of the non-deductible goodwill recorded as a discrete item during the quarter. As such, we believe our effective tax rate will be higher in subsequent periods.

10.	COMMITMENTS AND CONTINGENCIES

At March 31, 2020, we had estimated commitments of approximately: (i) $239.2 million to finish drilling, completing, or performing other work on wells and various other infrastructure projects in progress and (ii) $14.4 million to finish gathering system and water facilities construction in progress.

At March 31, 2020, we had firm sales contracts to deliver approximately 558.5 Bcf of gas over the next 11.3 years. If we do not deliver this gas, our estimated financial commitment, calculated using April 2020 index prices, would be approximately $519.6 million. The value of this commitment will fluctuate due to price volatility and actual volumes delivered.

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In connection with gas gathering and processing agreements, we have volume commitments over the next 8.8 years. If we do not deliver the committed gas or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of March 31, 2020, would be approximately $691.1 million.

We have minimum volume delivery commitments associated with agreements to reimburse connection costs to various pipelines. If we do not deliver this gas or oil, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of March 31, 2020, would be approximately $111.4 million. Of this total, we have accrued a liability of $4.4 million, representing the estimated amount we will have to pay due to insufficient forecasted volumes at particular connection points.

At March 31, 2020, we have various firm transportation agreements for gas and oil pipeline capacity with end dates ranging from 2021 - 2028 under which we will have to pay an estimated $66.5 million over the remaining terms of the agreements.

All of the noted commitments were routine and made in the ordinary course of our business.

Litigation

We have various litigation matters related to the ordinary course of our business. We assess the probability of estimable amounts related to these matters in accordance with guidance established by the FASB and adjust our accruals accordingly. Though some of the related claims may be significant, we believe the resolution of them, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations after consideration of current accruals.

11.	SUPPLEMENTAL CASH FLOW INFORMATION

		Three Months Ended March 31,
(in thousands)		2020				2019
Cash paid during the period for:
Interest (net of capitalized amounts of $7,328 and $740, respectively) (1)		$	5,559			$	18,588
Income taxes		$	—			$	6
Cash received for income tax refunds		$	204			$	1

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(1)	The three months ended March 31, 2019 includes $17.6 million in interest paid upon the redemption of Resolute’s senior notes and credit facility on March 1, 2019.

12.	RELATED PARTY TRANSACTIONS

Helmerich & Payne, Inc. (“H&P”) provides contract drilling services to Cimarex. Cimarex incurred drilling costs of approximately $15.6 million and $24.5 million related to these services during the three months ended March 31, 2020 and 2019, respectively. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P.

13.	ACQUISITIONS

On March 1, 2019, we completed the acquisition of Resolute Energy Corporation, an independent oil and gas company focused on the acquisition and development of unconventional oil and gas properties in the Delaware Basin area of the Permian Basin of west Texas. The principal factors considered by management in making this acquisition included: (i) our expectation that Resolute’s assets’ attractive returns are competitive with those in our existing portfolio, (ii) the opportunity to apply our experience and learnings from already operating in this area to generating productivity gains from Resolute’s properties, (iii) the ability to increase our acreage position in the Delaware Basin, and (iv) the expectation that the acquisition will be financially accretive.

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We acquired 100% of the outstanding common shares and voting interests of Resolute in a cash and stock transaction. The acquisition date fair value of the consideration transferred totaled $820.3 million, which consisted of cash, common stock, and a newly created series of preferred stock (see Note 5 for more information on the preferred stock) as follows:

(in thousands)		Fair Value of Consideration Transferred
Cash		$	325,677
Common stock (5,652 shares issued)		413,015
Preferred stock (63 shares issued)		81,620
		$	820,312

The fair value of the common stock issued as part of the consideration was determined on the basis of the closing market price of Cimarex common stock on the acquisition date. The fair value of the preferred stock issued as part of the consideration was determined using a multiple probability simulation model.

Purchase Price Allocation

The Resolute acquisition has been accounted for as a business combination, using the acquisition method. The following table presents the allocation of the Resolute purchase price to the identifiable assets acquired and liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded to goodwill. The table also presents the adjustments made to the purchase price allocation during the 12-month period following the acquisition date. The purchase price allocation was finalized during the three months ended March 31, 2020. The most significant adjustment was made to reduce the fair value of the unproved oil and gas properties acquired by $30.3 million based on the finalization of the quantity of acres acquired. The tax effect of this adjustment reduced the related deferred income taxes by $6.9 million. The completion of the final Resolute tax returns provided the underlying tax basis of Resolute’s assets and liabilities and net operating losses and resulted in a reduction of the deferred tax liability of $24.4 million. The remaining adjustments were related to finalization of working capital balances. The offset to all of the adjustments was goodwill.

The following table sets forth the purchase price allocation:

(in thousands)		March 1, 2019				Adjustments				March 1, 2020
Cash		$	41,236			$	—			$	41,236
Accounts receivable		50,739				11,521				62,260
Other current assets		13,280				(1,176		)		12,104
Proved oil and gas properties		692,600				—				692,600
Unproved oil and gas properties		1,054,200				(30,314		)		1,023,886
Fixed assets		5,355				(32		)		5,323
Goodwill		107,341				(13,126		)		94,215
Other assets		142				—				142
Current liabilities		(202,735		)		1,790				(200,945		)
Long-term debt		(870,000		)		—				(870,000		)
Deferred income taxes		(62,409		)		31,337				(31,072		)
Asset retirement obligation		(9,437		)		—				(9,437		)
Total identifiable net assets		$	820,312			$	—			$	820,312

In connection with the acquisition, we assumed, and immediately repaid, $870.0 million principal amount of long-term debt consisting of $600.0 million of senior notes and $270.0 million of credit facility borrowings. On March 1,

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2019, we repaid Resolute’s credit facility borrowings, delivered a notice of optional redemption of Resolute’s senior notes for an April 1, 2019 redemption date, and irrevocably deposited with a trustee the full amount of funds to repay the aggregate outstanding senior notes principal balance plus accrued and unpaid interest, incurring a $4.3 million loss on early extinguishment of debt. The cash consideration transferred and the repayment of Resolute’s long-term debt was funded using cash on hand and borrowings on our Credit Facility. We subsequently repaid the borrowings on our Credit Facility using the net proceeds from the March 8, 2019 issuance of $500 million aggregate principal amount of 4.375% senior unsecured notes.

Goodwill of $94.2 million was recognized in the purchase price allocation principally as a result of recording net deferred tax liabilities arising from the difference between the tax basis and the purchase price allocated to Resolute’s assets and liabilities, and anticipated opportunities for cost savings through administrative and operational synergies. We concluded that goodwill was impaired at March 31, 2020 (see Note 1 for more information regarding the goodwill impairment).

Acquisition-related costs incurred in the three months ended March 31, 2019 were $8.3 million. These costs, which were comprised primarily of advisory and legal fees, are included in the “Other operating expense, net” line item in the Condensed Consolidated Statement of Operations and Comprehensive Income.

Pro Forma Financial Information

The results of Resolute’s operations have been included in our consolidated financial statements since the March 1, 2019 acquisition date. The following supplemental pro forma information for the three months ended March 31, 2019 has been prepared to give effect to the Resolute acquisition as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of the combined company’s proved oil and gas properties, (ii) the capitalization of interest expense, and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by Cimarex of $8.3 million and transaction-related costs incurred by Resolute of $60.0 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by Cimarex to integrate the Resolute assets. The pro forma financial data has not been adjusted to reflect any other acquisitions or dispositions made during the period presented as their results were not deemed material.

The pro forma information is not necessarily indicative of the results that might have occurred had the transaction actually taken place on January 1, 2018 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities, and other factors.

(in thousands, except per share information)		Three Months Ended March 31, 2019
Revenue		$	630,093
Net income		$	12,617
Net income per common share:
Basic		$	0.11
Diluted		$	0.11

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•	Total production volumes increased 7% to 276.6 MBOE per day.

•	Oil volumes increased 13% to 89.8 MBbls per day.

•	Gas volumes increased 9% to 694.3 MMcf per day.

•	NGL volumes decreased 3% to 71.1 MBbls per day.

•	Total production revenue decreased $107.8 million to $459.5 million.

•	Cash flow provided by operating activities increased 23% to $308.8 million.

•	Exploration and development expenditures decreased 32% to $248.7 million.

•	Net loss was $774.3 million, or $7.77 per diluted share, for the first three months of 2020, as compared to net income of $26.3 million, or $0.26 per diluted share, for the first three months of 2019.

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(1)

In order to conform with the 2020 presentation, the 2019 amount presented reflects the reclassification of certain “Gas gathering and other” expenses to “Transportation, processing, and other operating” expenses and “Production” expense. These reclassifications were made to reflect an allocation of the costs incurred to operate our gas gathering facilities as a cost to transport our equity share of gas produced and operate our wells. See Note 1 to the Condensed Consolidated Financial Statements for further information regarding these prior year reclassifications.

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(1)

The 4.375% Notes due 2024 were issued at par, therefore, the amounts shown in the table are for unamortized debt issuance costs only. At March 31, 2020, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $4.7 million and $1.4 million, respectively. At March 31, 2020, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.2 million and $0.6 million, respectively. At December 31, 2019, the unamortized debt issuance costs and discount related to the 3.90% Notes due 2027 were $4.8 million and $1.5 million, respectively. At December 31, 2019, the unamortized debt issuance costs and discount related to the 4.375% Notes due 2029 were $4.3 million and $0.6 million, respectively.

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•	Operations-related accounts payable and accrued liabilities decreased by $110.5 million, primarily due to a decrease in revenue payable due to declines in prices and a decrease in taxes other than income due to ad valorem tax payments made at the beginning of the year and due to declines in prices lowering our production taxes payable.

•	Accounts receivable decreased by $118.6 million, primarily due to declines in prices lowering our oil and gas sales receivable, partially offset by an increase in trade receivables.

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(1)	The interest payments presented above include the accrued interest payable on our long-term debt as of March 31, 2020 as well as future payments calculated using the long-term debt’s fixed rates, stated maturity dates, and principal amounts outstanding as of March 31, 2020. See Note 2 to the Condensed Consolidated Financial Statements for additional information regarding our debt.

(2)	Operating leases include the estimated remaining contractual payments under lease agreements as of March 31, 2020. These lease agreements are primarily comprised of leases for commercial real estate, which consists primarily of office space, and compressor equipment.

(3)	Of the total unconditional purchase obligations, $66.5 million represents obligations for firm transportation agreements for gas and oil pipeline capacity.

(4)	We have excluded the presentation of the timing of the cash flows associated with our long-term asset retirement obligations because we cannot make a reasonably reliable estimate of the future period of cash settlement. The long-term asset retirement obligation is included in the total asset retirement obligation presented.

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(5)	Other long-term liabilities include contractual obligations associated with our employee supplemental savings plan, gas balancing liabilities, and other miscellaneous liabilities. All of these liabilities are accrued on our Condensed Consolidated Balance Sheet. The current portion associated with these long-term liabilities is also presented in the table above.

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•	Performance of a quarterly evaluation of the quantitative effect associated with the inclusion or exclusion of certain inputs in the company’s oil and gas reserve database.

•	Revision and communication of controls, policies and procedures relating to identifying and assessing changes that could potentially impact the system of internal control governing preparation of the oil and gas reserve database.

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•	unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

•	data corruption or operational disruption of production-related infrastructure could result in a loss of production, or accidental discharge;

•	a cyber attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt our major development projects;

•	a cyber attack on third-party gathering, pipeline, or rail transportation systems could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues; and

•	a cyber attack on our accounting or accounts payable systems could expose us to liability to employees and third parties if their personal identifying information is obtained.

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•	reducing or delaying capital expenditures;

•	seeking additional debt financing or equity capital;

•	selling assets; or

•	restructuring or refinancing debt.

•	create certain liens;

•	consolidate, merge, or transfer all, or substantially all, of our assets and our restricted subsidiaries; or

•	enter into sale and leaseback transactions.

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