Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Item 1A. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We operate in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.

Upstream Operations

In our upstream segment, our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.

As of December 31, 2020, we had approximately 378,678 net acres, which primarily consisted of approximately 194,591 net acres in the Midland Basin and approximately 152,587 net acres in the Delaware Basin. As of December 31, 2020, we had an estimated 10,413 gross horizontal locations that we believe to be economic at $60.00 per Bbl WTI.

In addition, our publicly traded subsidiary Viper owns mineral interests underlying approximately 787,264 gross acres and 24,350 net royalty acres in the Permian Basin and Eagle Ford Shale. Approximately 52% of these net royalty acres are operated by us.

Midstream Operations

In our midstream operations segment, Rattler’s crude oil infrastructure assets consist of gathering pipelines and metering facilities, which collectively gather crude oil for its customers. Rattler’s facilities gather crude oil from horizontal and vertical wells in our ReWard, Spanish Trail, Pecos and Fivestones areas within the Permian Basin. Rattler’s natural gas gathering and compression system consists of gathering pipelines, compression and metering facilities, which collectively service the production from our Pecos area assets within the Permian Basin. Rattler’s water sourcing and distribution assets consists of water wells, frac pits, pipelines and water treatment facilities, which collectively gather and distribute water from Permian Basin aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Rattler’s gathering and disposal system spans approximately 517 miles and consists of gathering pipelines along with produced water disposal, or PWD, wells and facilities which collectively gather and dispose of produced water from operations throughout our Permian Basin acreage.

We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in 2034, utilizing Rattler’s infrastructure assets or its planned infrastructure assets to provide an array of essential services critical to our upstream operations in the Delaware and Midland Basins. Our agreements with Rattler include substantial acreage dedications.

2020 Transactions and Recent Developments

COVID-19 and Collapse in Commodity Prices

On March 11, 2020, the World Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a “pandemic.” To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers. Although many stay-at-home orders have expired and certain restrictions on conducting business have been lifted, the COVID-19 pandemic resulted in a

widespread health crisis and a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets.

In early March 2020, oil prices dropped sharply and continued to decline reaching negative levels. During 2020, the posted price for the WTI price for crude oil ranged from $(37.63) to $63.27 per barrel, or Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.48 to $3.35 per MMBtu. On January 29, 2021, the NYMEX WTI price for crude oil was $52.20 per Bbl and the NYMEX Henry Hub price of natural gas was $2.56 per MMBtu. In response to recent volatility in commodity prices, many producers have reduced their capital expenditure budgets. This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including actions taken by OPEC members and other exporting nations impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic. While OPEC members and certain other nations agreed in April 2020 to cut production and subsequently extended such production cuts through December 2020, which helped to reduce a portion of the excess supply in the market and improve crude oil prices, they agreed to increase production by 500,000 barrels per day beginning in January 2021. We cannot predict if or when commodity prices will stabilize and at what levels.

As a result of the reduction in crude oil demand caused by factors discussed above, in 2020, we lowered our 2020 capital budgets and production guidance, curtailed near term production and reduced rig count, all of which may be subject to further reductions or curtailment if the commodity markets and macroeconomic conditions worsen. Although we have restored curtailed production, actions taken in response to the COVID-19 pandemic and depressed commodity pricing environment have had and are expected to continue to have an adverse effect on our business, financial results and cash flows.

In addition, as a result of the sharp decline in commodity prices in early March 2020, and the continued depressed oil pricing throughout the second and third quarters of 2020, we recorded $6.0 billion of aggregate non-cash ceiling test impairments for the year ended December 31, 2020. These impairment charges adversely affected our results of operations but did not reduce our cash flows. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will have material write downs in subsequent quarters. Our production, proved reserves and cash flows will also be adversely impacted. Our results of operations may be further adversely impacted by any government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic, the depressed commodity prices and the adverse macroeconomic conditions will persist, the full extent of the impact they will have on our industry and our business, financial condition, results of operations or cash flows, or the pace or extent of any subsequent recovery.

Pending Merger with QEP Resources, Inc.

On December 20, 2020, we, QEP and the Merger Sub, entered into the merger agreement under which the Merger Sub will be merged with and into QEP, with QEP surviving as our wholly owned subsidiary. If the pending merger is completed, each QEP stockholder will receive, in exchange for each share of QEP common stock held by such stockholder immediately prior to the closing of the pending merger, 0.050 of a share of our common stock. The completion of the pending merger is subject to satisfaction or waiver of certain customary mutual closing conditions, including the receipt of the required approvals from QEP’s stockholders. The pending merger is expected to close shortly following the special meeting of the QEP stockholders, which is scheduled for March 16, 2021, subject to QEP stockholder approval and other customary closing conditions. See “Items 1 and 2. Business and Properties—Overview—Pending Merger with QEP Resources, Inc.” for additional information regarding the pending merger.

We expect that the pending merger will:

• add material Tier-1 Midland Basin inventory;

• be accretive on all relevant 2021 per share metrics including cash flow per share, free cash flow per share and leverage, before accounting for synergies;

• lower 2021 reinvestment ratio and enhance ability to generate free cash flow, de-lever and return capital to our stockholders; and

• realize significant, tangible annual synergies of $60 to $80 million comprised of general and administrative expense savings, cost of capital and interest expense savings, improved capital efficiency from high-graded development of

combined acreage, physical adjacencies to increase lateral lengths and significant adjacent Permian Basin midstream assets.

In addition, we expect to maintain our investment grade credit ratings following the completion of the pending merger.

Pending Guidon Acquisition

On December 18, 2020, we entered into a definitive purchase and sale agreement with Guidon and certain of Guidon’s affiliates to acquire approximately 32,500 net acres in the Northern Midland Basin and certain related oil and natural gas assets, which we refer to as the Pending Guidon Acquisition. Consideration for the Pending Guidon Acquisition consists of $375 million in cash and 10.6 million shares of our common stock, subject to adjustment. The cash portion of this transaction is expected to be funded through a combination of cash on hand and borrowings under our credit facility. The Pending Guidon Acquisition is expected to close on February 26, 2021.

Fourth Quarter 2020 Dividend Declaration and Increase

On February 18, 2021, our board of directors declared a cash dividend for the fourth quarter of 2020 of $0.40 per share of common stock, payable on March 11, 2021 to our stockholders of record at the close of business on March 4, 2021, representing a 6.7% increase per share from the previously paid quarterly dividend.

Implementation of Viper’s Common Unit Repurchase Program

On November 6, 2020, the board of directors of Viper’s general partner approved an expansion of Viper’s return of capital program with the implementation of a common unit repurchase program to acquire up to $100 million of Viper’s outstanding common units through December 31, 2021. During the year ended December 31, 2020, Viper repurchased approximately $24 million of its common units under its repurchase program. As of December 31, 2020, $76 million remained available for use to repurchase common units under Viper’s common unit repurchase program.

Implementation of Rattler’s Common Unit Repurchase Program

On October 29, 2020, the board of directors of Rattler’s general partner approved a common unit repurchase program to acquire up to $100 million of Rattler’s outstanding common units through December 31, 2021. During the year ended December 31, 2020, Rattler repurchased approximately $15 million of its common stock under its repurchase program. As of December 31, 2020, $85 million remained available for use to repurchase common units under Rattler’s common unit repurchase program.

May 2020 Notes Offering

On May 26, 2020, we completed a notes offering of $500 million in aggregate principal amount of our 4.750% Senior Notes due 2025, which we refer to as the May 2020 Notes. We received net proceeds of approximately $496 million from the offering of the May 2020 Notes which we used to, among other things, make an equity contribution to Energen to purchase $209 million in aggregate principal amount of Energen’s 4.625% senior notes pursuant to a tender offer. For additional information regarding this notes offering, see “—Liquidity and Capital Resources—Indebtedness—The May 2020 Notes and Tender Offer for Energen’s 4.625% Senior Notes and Repurchase of Energen’s 7.35% Medium-term Notes” below.

Rattler Notes Offering

On July 14, 2020, Rattler completed an offering, which we refer to as the Rattler Notes Offering, of its 5.625% senior notes due 2025 in the aggregate principal amount of $500 million, which we refer to as the Rattler Notes. Rattler received net proceeds of approximately $490 million from the Rattler Notes Offering and loaned the gross proceeds of the Rattler Notes Offering to Rattler LLC to pay down borrowings under its revolving credit facility. For additional information regarding the Rattler Notes Offering, see “—Liquidity and Capital Resources—Indebtedness—Rattler’s Notes” below.

Operational Update

Our development program is focused entirely within the Permian Basin, where we continue to focus on long-lateral multi-well pad development. Our horizontal development consists of multiple targeted intervals, primarily within the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Springs formations in the Delaware Basin.

As of December 31, 2020, we were operating eight drilling rigs and currently intend to operate between eight and 12 drilling rigs in 2021 on average across our current acreage position in the Midland and Delaware Basins.

In the Midland Basin, we continued to have positive results across our core development areas located within Midland, Martin, Howard, Glasscock and Andrews counties, where development has primarily focused on drilling long-lateral, multi-well pads targeting the Spraberry and Wolfcamp formations.

In the Delaware Basin, we have now drilled and completed a significant number of wells in Pecos, Reeves and Ward counties targeting the Wolfcamp A, which we believe has been de-risked across a significant portion of our total acreage position and remains our primary development target. In 2021, we expect to focus development on these areas.

In the fourth quarter of 2020, we executed on our business strategy, providing a foundation for continued solid operational performance in 2021. We are starting to see the benefits from our strategy to cut activity and high-grade development focusing on our most productive areas in terms of capital efficiency and early-time well performance. While the impact of the recent winter storms in the Permian Basin on the first quarter 2021 production is expected to be significant (ranging from four to five days of total net production lost), we expect to overcome this adverse impact for the full year 2021. Well costs and cash operating costs remain near all-time lows, providing for increased returns to our stockholders as commodity prices have risen in recent months. In 2021, we intend to continue to focus on low cost operations and best in class execution and currently plan to hold our fourth quarter 2020 production flat while generating free cash flow used to pay dividends and pay down debt. To combat potential fluctuation in service costs, we have worked to implement new and more efficient drilling and completions methodologies and will continue to seek opportunities to control additional well cost where possible. Our 2021 drilling and completion budget accounts for capital costs that we expect to occur during the year.

In 2021, we remain focused on navigating our industry challenges by staying disciplined, improving our industry-leading cost structure, maintaining production and increasing environmental transparency.

Environmental Responsibility Initiatives and Highlights

In February 2021, we announced significant enhancements to our commitment to environmental, social responsibility and governance, or ESG, performance and disclosure, including Scope 1 and methane emission intensity reduction targets. Our goals include the reduction of our Scope 1 greenhouse gas intensity by at least 50% and methane intensity by at least 70%, in each case by 2024 from the 2019 levels. To further underscore our commitment to carbon neutrality, we are also implementing our “Net Zero Now” initiative under which, effective January 1, 2021, every hydrocarbon molecule we produce is anticipated to be produced with zero Scope 1 emissions. To the extent our greenhouse gas and methane intensity targets do not eliminate our carbon footprint, we intend to purchase carbon credits to offset the remaining emissions. We also plan to increase the weighting of ESG metrics in our annual short-term incentive compensation plan to motivate our executives to advance our environmental responsibility goals.

With respect to flaring, we flared 0.9% of our gross natural gas production in the fourth quarter of 2020. For the full year ended 2020, we flared 2.0% of our gross natural gas production, down 64% from 2019.

2021 Capital Budget

We have currently budgeted 2021 total capital spend of $1.4 billion to $1.6 billion, consisting of $1.2 billion to $1.4 billion for horizontal drilling and completions including non-operated activity, $60 million to $80 million for midstream investments, excluding joint venture investments, and $70 million to $90 million for infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions. We expect to drill and complete 215 to 235 gross horizontal wells in 2021. Should commodity prices weaken, we intend to act responsibly and, consistent with our prior practices, reduce capital spending. If commodity prices strengthen, we intend to grow oil production within our 2021 budget, pay down indebtedness and return cash to our stockholders.

Results of Operations

For a discussion of the results of operations for the year ended December 31, 2019 as compared to the year ended December 31, 2018, please refer to “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the year ended December 31, 2019 (filed with the SEC on February 27, 2020), which discussion is incorporated in this report by reference from such prior report on Form 10-K. The following table sets forth selected historical operating data for the periods indicated:

			Year Ended December 31,
			2020						2019
Revenues (in millions):
Oil sales			$	2,410					$	3,554
Natural gas sales			107						66
Natural gas liquid sales			239						267
Total oil, natural gas and natural gas liquid revenues			$	2,756					$	3,887
Production Data (in thousands):
Oil (MBbls)			66,182						68,518
Natural gas (MMcf)			130,549						97,613
Natural gas liquids (MBbls)			21,981						18,498
Combined volumes (MBOE)			109,921						103,285
Daily oil volumes (BO/d)			180,825						187,721
Daily combined volumes (BOE/d)			300,331						282,972
Average Prices:
Oil ($ per Bbl)			$	36.41					$	51.87
Natural gas ($ per Mcf)			$	0.82					$	0.68
Natural gas liquids ($ per Bbl)			$	10.87					$	14.42
Combined ($ per BOE)			$	25.07					$	37.63
Oil, hedged ($ per Bbl)(1)			$	40.34					$	51.96
Natural gas, hedged ($ per MMbtu)(1)			$	0.67					$	0.86
Natural gas liquids, hedged ($ per Bbl)(1)			$	10.83					$	15.20
Average price, hedged ($ per BOE)(1)			$	27.26					$	38.00

(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.

Production Data

Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables set forth our production data for the years ended December 31, 2020 and 2019:

			Year Ended December 31,
			2020						2019
Oil (MBbls)			60		%				66		%
Natural gas (MMcf)			20		%				16		%
Natural gas liquids (MBbls)			20		%				18		%
			100		%				100		%

Comparison of the Years Ended December 31, 2020 and 2019

Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.

The net dollar effect of the change in prices are shown below:

			Change in prices						Production volumes**(1)**						Total net dollar effect of change
															(in millions)
Effect of changes in price:
Oil			$	(15.46)					66,182						$	(1,023)
Natural gas			$	0.14					130,549						$	18
Natural gas liquids			$	(3.55)					21,981						$	(77)
Total revenues due to change in price															$	(1,082)
			Change in production volumes**(1)**						Prior period average prices						Total net dollar effect of change
															(in millions)
Effect of changes in production volumes:
Oil			(2,336)						$	51.87					$	(121)
Natural gas			32,936						$	0.68					$	22
Natural gas liquids			3,483						$	14.42					$	50
Total change in revenues															$	(49)
															$	(1,131)

(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Our oil, natural gas and natural gas liquids revenues decreased by approximately $1.1 billion, or 29%, to $2.8 billion for the year ended December 31, 2020 from $3.9 billion for the year ended December 31, 2019, largely attributable to lower oil average sales prices resulting from the impact of the COVID-19 pandemic and other volatility in global commodity prices as discussed in “—COVID-19 and collapse in Commodity Prices” above.

Average daily production sold increased by 17,359 BOE/d to 300,331 BOE/d during the year ended December 31, 2020 from 282,972 BOE/d during the year ended December 31, 2019, primarily due to an increase in natural gas liquids and natural gas production, which was partially offset by temporarily curtailing a portion of our oil production volumes during 2020 in response to the sudden drop in demand and prices for oil stemming from the COVID-19 pandemic.

Midstream Services Revenue. The following table shows midstream services revenue for the years ended December 31, 2020 and 2019:

			Year Ended December 31,
			2020						2019
			(in millions)
Midstream services			$	50					$	64

Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. Midstream services revenue decreased by $14 million for the year ended December 31, 2020 as compared to the year ended December 31, 2019 primarily due to a reduction in sourced water volumes due to the lower level of drilling and completion activity in 2020.

Lease Operating Expenses. The following table shows lease operating expenses for the years ended December 31, 2020 and 2019:

			Year Ended December 31,
			2020									2019
(in millions, except per BOE amounts)			Amount			Per BOE						Amount			Per BOE
Lease operating expenses			$	425		$	3.87					$	490		$	4.74

Lease operating expenses for the year ended December 31, 2020 as compared to the year ended December 31, 2019 decreased by $65 million, or $0.87 per BOE. Lease operating expenses decreased due to a reduction in work over and well maintenance activity through overall efficiencies gained, as well as improvements in infrastructure which reduced power generation costs and trucking fees. In addition to these efficiencies we have seen a reduction in service pricing in 2020, driven by the reduction in current industry activity levels. We expect service pricing may increase in future periods, particularly if current industry activity levels increase.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the years ended December 31, 2020 and 2019:

			Year Ended December 31,
			2020									2019
(in millions, except per BOE amounts)			Amount			Per BOE						Amount			Per BOE
Production taxes			$	135		$	1.23					$	184		$	1.78
Ad valorem taxes			60			0.54						64			0.62
Total production and ad valorem expense			$	195		$	1.77					$	248		$	2.40
Production taxes as a % of oil, natural gas, and natural gas liquids revenue			4.9		%							4.7		%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes for the year ended December 31, 2020 as compared to the year ended December 31, 2019 decreased by $49 million, or $0.55 per BOE, due to current year commodity prices. Production taxes as a percentage of production revenues remained consistent for the year ended December 31, 2020 compared to the year ended December 31, 2019.

Gathering and Transportation Expense. The following table shows gathering and transportation expense for the year ended December 31, 2020 and 2019:

			Year Ended December 31,
			2020									2019
(in millions, except per BOE amounts)			Amount			Per BOE						Amount			Per BOE
Gathering and transportation expense			$	140		$	1.27					$	88		$	0.86

For the year ended December 31, 2020, the per BOE increases for gathering and transportation expenses are primarily attributable to recording minimum volume commitment fees in 2020, as well as an increase in fees for our gas production and an overall change in our product mix, with gas and natural gas liquids production becoming a greater percentage of overall production.

Midstream Services Expense. The following table shows midstream services expense for the years ended December 31, 2020 and 2019:

			Year Ended December 31,
			2020						2019
			(in millions)
Midstream services expense			$	105					$	91

Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities. Midstream services expense for the year ended December 31, 2020 as compared to the year ended December 31, 2019 increased by $14 million primarily due to increased volume and build out of the Rattler systems.

Depreciation, Depletion and Amortization. The following table provides the components of our depreciation, depletion and amortization expense for the years ended December 31, 2020 and 2019:

			Year Ended December 31,
(in millions, except BOE amounts)			2020						2019
Depletion of proved oil and natural gas properties			$	1,242					$	1,398
Depreciation of midstream assets			44						33
Depreciation of other property and equipment			18						16
Depreciation, depletion and amortization expense			$	1,304					$	1,447
Oil and natural gas properties depletion per BOE			$	11.30					$	13.54

The decrease in depletion of proved oil and natural gas properties of $156 million for the year ended December 31, 2020 as compared to the year ended December 31, 2019 resulted primarily from a reduction in the average depletion rate for our oil and natural gas properties in 2020, which stemmed from a decrease in the net book value of our properties due to the full cost ceiling impairments recorded in the first three quarters of 2020 as well as lower production levels in 2020 as compared to 2019.

Impairment of Oil and Natural Gas Properties. As a result of the decline in commodity prices during 2020 and 2019, we recorded non-cash ceiling test impairments for the years ended December 31, 2020 and 2019 of $6.0 billion and $790 million, respectively, which is included in accumulated depletion, depreciation, amortization and impairment on our consolidated balance sheet. The impairment charges affected our results of operations but did not reduce cash flow. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will continue to have material write-downs in subsequent quarters.

General and Administrative Expenses. The following table shows general and administrative expenses for the years ended December 31, 2020 and 2019:

			Year Ended December 31,
			2020									2019
(in millions, except per BOE amounts)			Amount			Per BOE						Amount			Per BOE
General and administrative expenses			$	51		$	0.46					$	56		$	0.54
Non-cash stock-based compensation			37			0.34						48			0.46
Total general and administrative expenses			$	88		$	0.80					$	104		$	1.00

General and administrative expenses for the year ended December 31, 2020 as compared to the year ended December 31, 2019 decreased by $16 million primarily due to a decrease in non-cash stock-based compensation.

Net Interest Expense. The following table shows net interest expense for the years ended December 31, 2020 and 2019:

			Year Ended December 31,
			2020						2019
			(in millions)
Interest expense, net			$	197					$	172

Net interest expense increased by $25 million for the year ended December 31, 2020 as compared to the year ended December 31, 2019. This increase was primarily due to an increase in borrowings resulting from the issuance of the May 2020 Notes and the Rattler Notes. See Note 11—Debt for further details regarding outstanding borrowings and interest expense.

Derivatives. The following table shows the net gain (loss) on derivative instruments and the net cash received (paid) on settlements of derivative instruments for the years ended December 31, 2020 and 2019:

			Year Ended December 31,
			2020						2019
			(in millions)
Gain (loss) on derivative instruments, net			$	(81)					$	(108)
Net cash received (paid) on settlements			$	250					$	80

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains; while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

Net cash received (paid) on settlements of derivative instruments for the years ended December 31, 2020 and 2019 include cash received on contracts terminated prior to their contractual maturity of $17 million related to commodity contracts and $43 million related to interest rate swap contracts, respectively.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the years ended December 31, 2020 and 2019:

			Year Ended December 31,
			2020						2019
			(in millions)
Provision for (benefit from) income taxes			$	(1,104)					$	47

The change in our income tax provision was primarily due to the pre-tax loss for the year ended December 31, 2020 as compared to pre-tax income for the year ended December 31, 2019, and the impact of recording a valuation allowance on Viper’s deferred tax assets during the year ended December 31, 2020.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility and proceeds from the issuance of the senior notes. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties.

As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the depressed commodity markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Liquidity and Cash Flow

Our cash flows for the years ended December 31, 2020 and 2019 are presented below:

			Year Ended December 31,
			2020						2019
			(in millions)
Net cash provided by (used in) operating activities			$	2,118					$	2,739
Net cash provided by (used in) investing activities			(2,101)						(3,888)
Net cash provided by (used in) financing activities			(37)						1,062
Net change in cash			$	(20)					$	(87)

Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See “–Sources of our revenue” and Item 1A. “Risk Factors” above.

Net cash provided by operating activities decreased to $2.1 billion for the year ended December 31, 2020 as compared to $2.7 billion for the year ended December 31, 2019, primarily due to a decline in our oil and natural gas revenues, which was partially offset by a decrease in lease operating expenses and other operating expenses and an increase in cash received on settlements of our derivative contracts.

Investing Activities

The purchase and development of oil and natural gas properties and related assets, and contributions to our equity method investments accounted for the majority of our $2.1 billion and $3.9 billion in cash outlays for investing activities during the years ended December 31, 2020 and 2019, respectively.

Contributions to equity method investments decreased to $102 million for the year ended December 31, 2020 as compared to $485 million for the year ended December 31, 2019 as construction of both the EPIC Pipeline and Gray Oak Pipeline, which required substantial capital in 2019, was completed during April 2020. As of December 31, 2020, Rattler’s anticipated future capital commitments for its equity method investments total $72 million in the aggregate. For additional information regarding our equity method investments, see Note 10—Equity Method Investments included in notes to the consolidated financial statements included elsewhere in this Annual Report.

Capital Expenditure Activities

Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:

			Year Ended December 31,
			2020						2019
			(in millions)
Drilling, completions and non-operated additions to oil and natural gas properties(1)(2)			$	1,611					$	2,557
Infrastructure additions to oil and natural gas properties			108						120
Additions to midstream assets			140						244
Total			$	1,859					$	2,921

(1) During the year ended December 31, 2020, in conjunction with our development program, we drilled 208 gross (195 net) operated horizontal wells, of which 75 gross (70 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 171 gross (159 net) operated horizontal wells to production, of which 78 gross (74 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin.

(2) During the year ended December 31, 2019, in conjunction with our development program, we drilled 330 gross (296 net) operated horizontal wells, of which 159 gross (142 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 317 gross (289 net) operated horizontal wells to production, of which 139 gross (126 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin.

Financing Activities

During the year ended December 31, 2020, the amount used in financing activities was primarily attributable to $348 million of repayments, net of borrowings, on our credit facilities, $239 million in aggregate repayments on the Energen Notes and Viper Notes, $236 million in dividends paid to stockholders, $98 million of share repurchases as part of our stock repurchase program, and $93 million in distributions to non-controlling interest. These cash outlays were partially offset by net proceeds of $997 million from the issuance of the May 2020 Notes and the Rattler Notes during 2020.

During the year ended December 31, 2019, the amount provided by financing activities was primarily attributable to $341 million in net proceeds from Viper’s public offering completed on March 1, 2019, $720 million in net proceeds from the Rattler Offering, $39 million in proceeds from joint ventures and $2.2 billion in proceeds from the December 2019 Notes, net of repayments, partially offset by $1.4 billion of repayments, net of borrowings, under our credit facility, $44 million of premium on debt extinguishment, $122 million of distributions to our non-controlling interest, $13 million of share

repurchases for tax withholdings, $593 million of share repurchases as part of our stock repurchase program and $112 million of dividends to stockholders.

Indebtedness

Second Amended and Restated Credit Facility

At December 31, 2020, the maximum credit amount available under our credit agreement was $2.0 billion and the maturity date is November 1, 2022. As of December 31, 2020, we had approximately $23 million of outstanding borrowings under our revolving credit facility, which we believe provides ample availability for future borrowings, including funding for the cash portion of the Guidon acquisition in the first quarter of 2021. As of December 31, 2020, there was an aggregate of $3 million in letters of credit outstanding under our credit agreement, which reduce available borrowings on a dollar for dollar basis. The weighted average interest rate on the credit agreement was 2.02% for the year ended December 31, 2020.

The credit agreement contains a financial covenant that requires us to maintain a total net debt to capitalization ratio (as defined in the credit agreement) of no more than 65%. Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets.

At December 31, 2020, we were in compliance with all financial maintenance covenants under the credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

The May 2020 Notes and Tender Offer for Energen’s 4.625% Senior Notes and Repurchase of Energen’s 7.35%

Medium-term Notes

On May 26, 2020, we completed a registered offering of $500 million in aggregate principal amount of our 4.750% Senior Notes due 2025. Interest on the May 2020 Notes accrues from May 26, 2020, and is payable in cash semi-annually on May 31 and November 30 of each year, beginning November 30, 2020. The May 2020 Notes mature on May 31, 2025. We received net proceeds of approximately $496 million from the offering.

We used the net proceeds, among other things, to make an equity contribution to Energen to purchase $209 million in aggregate principal amount of Energen’s 4.625% senior notes pursuant to a tender offer. As of December 31, 2020, $191 million in aggregate principal amount of Energen’s 4.625% senior notes remained outstanding.

During the third quarter of 2020, we repurchased all $10 million in principal amount of Energen’s outstanding 7.350% medium-term notes due on July 28, 2027 at a price of 120% of the aggregate principal amount.

For additional information, see Note 11—Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report.

Energen Notes

On November 29, 2018, Energen became our wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530 million in notes, which we refer to as the Energen Notes. As of December 31, 2020, the aggregate principal amount of the Energen Notes had been reduced to $311 million consisting of: (a) $191 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (b) $100 million of 7.125% notes due on February 15, 2028, and (c) $20 million of 7.32% notes due on July 28, 2022.

For additional information regarding the Energen Notes, See Note 11—Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report.

Viper’s Credit Agreement

The Viper credit agreement provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $580 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st, and was reaffirmed at $580 million by the

lenders during the regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of December 31, 2020, Viper LLC had $84 million of outstanding borrowings and $496 million available for future borrowings under the Viper credit agreement. During the year ended December 31, 2020, the weighted average interest rate on Viper’s revolving credit facility was 2.20%.

As of December 31, 2020, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement, as then in effect.

Viper’s Notes

On October 16, 2019, Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of $500 million. Viper received net proceeds of approximately $490 million from the notes offering and loaned the gross proceeds to Viper LLC to pay down borrowings under the Viper credit agreement. Interest on the Viper notes accrues at a rate of 5.375% per annum, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2020. The Viper notes will mature on November 1, 2027.

During the year ended December 31, 2020, Viper repurchased $20 million of outstanding principal of the Viper notes at a cash price ranging from 97.5% to 98.5% of the aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt, and $480 million in aggregate principal amount remained outstanding at December 31, 2020.

See additional discussion in Note 11—Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report.

Rattler’s Credit Agreement

In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo Bank, as administrative agent, and a syndicate of banks, as lenders party thereto, which we refer to as the Rattler credit agreement.

The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million and has a maturity date of May 28, 2024. As of December 31, 2020, Rattler LLC had $79 million of outstanding borrowings and $521 million available for future borrowings under the Rattler credit agreement. During the year ended December 31, 2020, the weighted average interest rate on the Rattler LLC revolving credit facility was 2.10%.

As of December 31, 2020, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

Rattler’s Notes

On July 14, 2020, Rattler completed an offering of $500 million in aggregate principal amount of its 5.625% Senior Notes due 2025, or the Rattler Notes Offering. Interest on the Rattler notes is payable on January 15 and July 15 of each year, beginning on January 15, 2021. The Rattler notes mature on July 15, 2025. Rattler received net proceeds of approximately $490 million from the Rattler Notes Offering. Rattler loaned the gross proceeds to Rattler LLC under the terms of a subordinated promissory note, dated as of July 14, 2020. The promissory note requires Rattler LLC to repay the intercompany loan to Rattler on the same terms and in the same amounts as the Rattler notes and has the same maturity date, interest rate, change of control repurchase and redemption provisions. Rattler LLC used the proceeds from the Rattler Notes Offering to repay a portion of the outstanding borrowings under the Rattler credit agreement.

For additional information regarding our indebtedness, see Note 11—Debt included in notes to the consolidated financial statements included elsewhere in this Annual Report.

Capital Requirements and Sources of Liquidity

Our board of directors approved a 2021 capital budget for drilling, midstream and infrastructure of $1.4 billion to $1.6 billion, representing a decrease of 50% from our 2020 capital budget. We estimate that, of these expenditures, approximately:

• $1.2 billion to $1.4 billion will be spent on drilling and completing 215 to 235 gross (197 to 215 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,100 feet;

• $60 million to $80 million will be spent on midstream infrastructure, excluding joint venture investments; and

• $70 million to $90 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

During the year ended December 31, 2020, we spent $1.6 billion on drilling and completion, $140 million on midstream, $108 million on infrastructure and $58 million on non-operated properties, for total capital expenditures of $1.9 billion.

In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. We repurchased approximately $98 million of our common stock under this program during the year ended December 31, 2020, prior to the program’s expiration.

The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We are currently operating eight drilling rigs and nine completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas prices and production expectations for 2021, we believe our cash flows from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2021. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2021 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

We monitor and adjust our projected capital expenditures in response to the results of our drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. If there is a decline in commodity prices, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.

Guarantor Financial Information

As of December 31, 2020, Diamondback O&G LLC is the sole guarantor under the December 2019 Notes Indenture governing the December 2019 Notes, the May 2020 Notes and the 2025 Indenture governing the 2025 Senior Notes.

Guarantees are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the December 2019 Notes Indenture and the 2025 Indenture, such as, with certain exceptions, (1) in the event Diamondback O&G LLC (or all or substantially all of its assets) is sold or disposed of, (2) in the event Diamondback O&G LLC ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (3) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.

Diamondback O&G LLC’s guarantees of the December 2019 Notes, the May 2020 Notes and the 2025 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The rights of holders of the Senior Notes against Diamondback O&G LLC may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback O&G LLC’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of Diamondback O&G LLC. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback O&G LLC, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity.

			December 31, 2020
Summarized Balance Sheets:			(in millions)
Assets:
Current assets			$	308
Property and equipment, net			$	6,934
Other noncurrent assets			$	6
Liabilities:
Current liabilities			$	355
Intercompany accounts payable, non-guarantor subsidiary			$	335
Long-term debt			$	4,293
Other noncurrent liabilities			$	886

			Year Ended December 31, 2020
Summarized Statement of Operations:			(in millions)
Revenues			$	1,618
Income (loss) from operations			$	(3,466)
Net income (loss)			$	(2,344)

Contractual Obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2020:

			Payments Due by Period
			2021						2022-2023						2024-2025						Thereafter						Total
			(in millions)
Secured revolving credit facility(1)			$	—					$	23					$	—					$	—					$	23
Senior notes			191						20						2,300						2,100						4,611
Interest expense related to the senior notes(2)			181						342						279						212						1,014
DrillCo Agreement			—						—						—						79						79
Viper's secured revolving credit facility(1)			—						84						—						—						84
Viper's senior notes			—						—						—						480						480
Interest expense related to Viper's senior notes			26						52						52						52						182
Rattler's secured revolving credit facility(1)			—						—						79						—						79
Rattler's senior notes			—						—						500						—						500
Interest expense related to Rattler's senior notes			28						56						55						—						139
Asset retirement obligations(3)			1						—						—						108						109
Drilling commitments(4)			29						—						—						—						29
Sand supply agreements			18						36						36						5						95
Transportation commitments			60						111						95						133						399
Equity method investment capital contributions(5)			57						15						—						—						72
Produced water disposal commitments			5						9						9						33						56
Operating lease obligations(6)			6						3						—						—						9
			$	602					$	751					$	3,405					$	3,202					$	7,960

(1)Includes the outstanding principal amount under the revolving credit facilities, the table does not include commitment fees, interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.

(2)Interest represents the scheduled cash payments on the senior notes and Energen Notes.

(3)Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 9—Asset Retirement Obligations in the notes to the consolidated financial statements included elsewhere in this Annual Report.

(4)Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2020.

(5)Timing of when capital commitments will be requested can vary.

(6)Operating lease obligations represent future commitments for building, equipment and vehicle leases.

The table above does not include estimated deficiency fees related to certain volume commitments as they are based off future volume deliveries and differences from market pricing which we cannot predict.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Critical accounting policies cover accounting estimates that are inherently uncertain because the future resolution of such matters is unknown and actual results could differ from those estimates.

Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include (i) the method of accounting for our oil and natural gas properties, (ii) estimates of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, (iii) impairments of the carrying value of oil and natural gas properties, (iv) fair value estimates of commodity derivatives and (v) estimates of income taxes.

Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments.

Method of accounting for oil and natural gas properties

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties.

Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. If our production remains at approximately the same level from year to year, depletion expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Oil and natural gas reserve quantities and standardized measure of future net revenue

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Impairment

Under the full cost method of accounting, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash write-down is required. Impairments of our evaluated oil and natural gas properties are not reversible.

Derivatives

From time to time, we have used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and the counterparties’ creditworthiness.

We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.

Income Taxes

The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and provincial tax jurisdictions. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.

See Note 2—Summary of Significant Accounting Policies of the notes to the consolidated financial statements included elsewhere in this Annual Report for a full discussion of our significant accounting policies.

Recent Accounting Pronouncements

For information regarding recent accounting pronouncements, See Note 2—Summary of Significant Accounting Policies included in notes to the consolidated financial statements included elsewhere in this Annual Report.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2020. Please read Note 17—Commitments and Contingencies included in notes to the consolidated financial statements included elsewhere in this Form 10-K for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.