MIDLAND, Texas, Feb. 22, 2022 (GLOBE NEWSWIRE) — Diamondback Energy, Inc. (NASDAQ: FANG) (“Diamondback” or the “Company”) today announced financial and operating results for the fourth quarter and full year ended December 31, 2021.

FOURTH QUARTER 2021 HIGHLIGHTS

  • Average production of 226.3 MBO/d (387.1 MBOE/d)
  • Permian Basin production of 224.4 MBO/d (383.5 MBOE/d)
  • Cash flow from operating activities of $1,167 million; Operating Cash Flow Before Working Capital Changes (as defined and reconciled below) of $1,206 million
  • Cash capital expenditures of $434 million; Q4 2021 activity-based capital expenditures incurred of approximately $427 million
  • Free Cash Flow (as defined and reconciled below) of $772 million
  • Increasing annual dividend by 20.0% to $2.40 per share; declared Q4 2021 cash dividend of $0.60 per share payable on March 11, 2022; implies a 1.8% annualized yield based on the February 18, 2022 share closing price of $131.47
  • Repurchased 3,858,931 shares of common stock (~2.1% of prior quarter shares outstanding) in Q4 2021 for ~$409 million ($105.96 / share)
  • Total return of capital of $515 million (67% of Q4 2021 Free Cash Flow) from stock repurchases and the declared Q4 2021 dividend; above commitment to return at least 50% of Free Cash Flow to stockholders
  • Flared 1.55% (1.32% excluding QEP Permian) of gross natural gas production in the fourth quarter of 2021

FULL YEAR 2021 HIGHLIGHTS

  • Full year 2021 average production of 223.3 MBO/d (375.3 MBOE/d)
  • Generated full year 2021 cash flow from operating activities of $3,944 million; Operating Cash Flow Before Working Capital Changes (as defined and reconciled below) of $3,908 million
  • Full year 2021 cash capital expenditures of $1,487 million; turned 275 horizontal wells to production
  • Generated full year 2021 Free Cash Flow (as defined and reconciled below) of $2,421 million
  • YE 2021 total debt of $6,756 million and consolidated net debt (as defined and reconciled below) of $6,102 million, down 20% from the end of Q1 2021; redeemed $1,277 million of Senior Notes over the same period
  • Proved reserves as of December 31, 2021 of 1,789 MMBOE (928 MMBO, 52% oil), up 36% year over year; proved developed producing (“PDP”) reserves of 1,201 MMBOE (620 MMBO, 52% oil, 67% of proved reserves), up 47% year over year
  • 2021 consolidated proved developed finding and development (as defined below and referred to as “PD F&D”) costs of $7.87/BOE; drill bit finding and development (as defined below and referred to as “Drill bit F&D”) costs of $4.53/BOE
  • Flared 1.00% (1.45% including QEP Permian) of gross natural gas production for the full year ended 2021, down 49% (26% including QEP Permian) from 2020

2022 GUIDANCE HIGHLIGHTS

  • Full year 2022 oil production guidance of 218 – 222 MBO/d (369 – 376 MBOE/d)
  • Full year 2022 cash CAPEX guidance of $1.75 – $1.90 billion
  • Assuming current strip commodity prices and the midpoint of Diamondback’s production and operating cost guidance, the Company expects to generate approximately $5.8 billion of net cash provided by operating activities in 2022
  • Assuming the net cash provided by operating activities guidance above and the midpoint of 2022 CAPEX guidance, the Company expects to generate approximately $4.0 billion of Free Cash Flow in 2022
  • The Company expects to drill between 270 and 290 gross (248 – 267 net) wells and complete between 260 and 280 gross (240 – 258 net) wells with an average lateral length of approximately 10,200 feet in 2022
  • Q1 2022 oil production guidance of 218 – 222 MBO/d (369 – 376 MBOE/d)
  • Q1 2022 cash CAPEX guidance of $435 – $475 million

“Diamondback’s fourth quarter topped off a record year for the Company. In the quarter, Diamondback generated $772 million of Free Cash Flow with production and capital both positively exceeding expectations. As we have stated previously, we are committed to returning at least 50% of this Free Cash Flow to stockholders, and in the fourth quarter we exceeded this target and returned 67% of our Free Cash Flow through opportunistic share repurchases and our growing base dividend,” stated Travis Stice, Chief Executive Officer of Diamondback.

Mr. Stice continued, “Going forward, we will remain committed to capital discipline by maintaining flat Permian oil production. In 2022, at current strip pricing, we expect this maintenance capital plan to generate nearly $4.0 billion of Free Cash Flow, of which at least 50% will be returned to stockholders through a combination of our growing base dividend, our opportunistic share repurchase program and, if needed, a variable dividend. Diamondback’s Board believes long-term shareholder value is created in this business through consistent execution at the lowest cost structure. Free Cash Flow generation and the return of that Free Cash Flow to the owners of the Company is the output of that value creation. As mentioned earlier, we expect to return a significant amount of cash back to stockholders this year, at least 50% of Free Cash Flow. The Board also retains discretion on what to do with the other 50% of the Free Cash Flow we generate. If we do not have a use for this capital that creates unreasonable value for our shareholders, then we will return it through the method our Board believes presents the best return to our stockholders at the time.”

Mr. Stice continued, “Our operational achievements in the field in 2021 set a new bar for Diamondback. We will continue to build off of these operational efficiencies by controlling the variable portion of our operating and capital costs, which will help mitigate the inflationary pressures we are seeing across our business. As a result, we are confident we can maintain our best-in-class capital efficiency and cost structure through the cycle.”

OPERATIONS UPDATE

The tables below provide a summary of operating activity for the fourth quarter of 2021.

Total Activity (Gross Operated):
Number of Wells Drilled Number of Wells Completed
Midland Basin 40 55
Delaware Basin 13 15
Total 53 70
Total Activity (Net Operated):
Number of Wells Drilled Number of Wells Completed
Midland Basin 38 54
Delaware Basin 12 15
Total 50 69

During the fourth quarter of 2021, Diamondback drilled 40 gross horizontal wells in the Midland Basin and 13 gross horizontal wells in the Delaware Basin. The Company turned 55 operated horizontal wells to production in the Midland Basin and 15 operated horizontal wells to production in the Delaware Basin. The average lateral length for the wells completed during the fourth quarter was 9,711 feet. Operated completions during the fourth quarter consisted of 27 Wolfcamp A wells, 18 Lower Spraberry wells, eight Middle Spraberry wells, eight Wolfcamp B wells, four Third Bone Spring wells, two Jo Mill wells, two Second Bone Spring wells and one Barnett well.

For the full year ended December 31, 2021, Diamondback drilled 175 gross horizontal wells in the Midland Basin and 41 gross horizontal wells in the Delaware Basin. The Company turned 207 operated horizontal wells to production in the Midland Basin, 64 operated horizontal wells in the Delaware Basin and four operated horizontal wells in the Williston Basin. The average lateral length for wells completed during the full year was 10,602 feet, and consisted of 88 Wolfcamp A wells, 68 Lower Spraberry wells, 33 Middle Spraberry wells, 25 Wolfcamp B wells, 23 Jo Mill wells, 13 Third Bone Spring wells, 12 Second Bone Spring wells, seven Dean wells, two Barnett wells, two Bakken wells and two Three Forks wells.

FINANCIAL UPDATE

Diamondback’s fourth quarter 2021 net income was $1,002 million, or $5.54 per diluted share. Adjusted net income (a non-GAAP financial measure as defined and reconciled below) was $657 million, or $3.63 per diluted share.

Fourth quarter 2021 Consolidated Adjusted EBITDA (as defined and reconciled below) was $1,256 million. Adjusted EBITDA net of non-controlling interest was $1,192 million.

Fourth quarter 2021 average unhedged realized prices were $74.50 per barrel of oil, $4.56 per Mcf of natural gas and $35.02 per barrel of natural gas liquids (“NGLs”), resulting in a total equivalent unhedged realized price of $56.47 per BOE.

Diamondback’s cash operating costs for the fourth quarter of 2021 were $10.17 per BOE, including lease operating expenses (“LOE”) of $4.21 per BOE, cash general and administrative (“G&A”) expenses of $0.93 per BOE, production and ad valorem taxes of $3.40 per BOE and gathering and transportation expenses of $1.63 per BOE.

As of December 31, 2021, Diamondback had $595 million in standalone cash and no borrowings outstanding under its revolving credit facility, with approximately $1.6 billion available for future borrowing under the facility and approximately $2.2 billion of total liquidity.

During the fourth quarter of 2021, Diamondback spent $347 million on operated drilling and completion and non-operated properties, $80 million on infrastructure and $7 million on midstream, for total cash capital expenditures of $434 million. For the year ended December 31, 2021, Diamondback spent $1,298 million on operated drilling and completion, $123 million on infrastructure, $36 million on non-operated properties and $30 million on midstream, for total cash capital expenditures of $1,487 million.

DIVIDEND DECLARATION

Diamondback announced today that the Company’s Board of Directors declared a cash dividend of $0.60 per common share for the fourth quarter of 2021 payable on March 11, 2022, to stockholders of record at the close of business on March 4, 2022. Future dividends remain subject to review and approval at the discretion of the Company’s Board of Directors.

COMMON STOCK REPURCHASE PROGRAM

On September 15, 2021 the Board of Directors of Diamondback authorized the Company to acquire up to $2.0 billion of common stock. During the fourth quarter of 2021, Diamondback repurchased 3,858,931 shares of common stock at an average share price of $105.96 for a total cost of approximately $409 million. For the full year 2021, the Company repurchased 4,127,222 shares of common stock for a total cost of approximately $431 million, or approximately 22% of the Board approved program.

Diamondback intends to purchase common stock under the common stock repurchase program opportunistically with cash on hand, free cash flow from operations and proceeds from potential liquidity events such as the sale of assets. This repurchase program has no time limit and may be suspended from time to time, modified, extended or discontinued by the Board at any time. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions in compliance with Rule 10b-18 under the Securities Exchange Act of 1934, as amended, and will be subject to market conditions, applicable legal requirements and other factors. Any common stock purchased as part of this program will be retired.

RESERVES

Ryder Scott Company, L.P. prepared estimates of Diamondback’s proved reserves as of December 31, 2021. Reference prices of $66.56 per barrel of oil and $3.60 per Mmbtu of natural gas were used in accordance with applicable rules of the Securities and Exchange Commission. Realized prices with applicable differentials were $64.78 per barrel of oil, $2.61 per Mcf of natural gas and $23.71 per barrel of natural gas liquids.

Proved reserves at year-end 2021 of 1,789 MMBOE represent a 36% increase over year-end 2020 reserves. Proved developed reserves increased by 47% to 1,201 MMBOE (67% of total proved reserves) as of December 31, 2021, reflecting the continued development of the Company’s horizontal well inventory. Proved undeveloped reserves (“PUD” or “PUDs”) increased to 588 MMBOE, an 18% increase over year-end 2020, and are comprised of 619 locations, of which 65 are in the Delaware Basin. Crude oil represents 52% of Diamondback’s total proved reserves.

Net proved reserve additions of 610 MMBOE resulted in a reserve replacement ratio of 445% (defined as the sum of extensions, discoveries, revisions, purchases and divestitures, divided by annual production). The organic reserve replacement ratio was 280% (defined as the sum of extensions, discoveries and revisions, divided by annual production).

Extensions and discoveries of reserves were the primary contributor to the increase in reserves totaling 519 MMBOE followed by net purchases of reserves totaling 225 MMBOE, with downward revisions of 135 MMBOE. PDP extensions accounted for 15% of the total increase in reserves. PDP extensions were the result of 125 wells in which the Company has a working interest, and PUD extensions were the result of 439 new locations in which the Company has a working interest. Net acquisitions of reserves of 225 MMBOE were the net result of acquisitions of 285 MMBOE and divestitures of 60 MMBOE. Downward revisions of 135 MMBOE were primarily the result of PUD downgrades related to changes in the corporate development plan following the QEP and Guidon acquisitions of 256 MMBOE, which were partially offset by positive revisions of 121 MMBOE associated with higher commodity prices and improved well performance.

The SEC PUD guidelines allow a company to book PUD reserves associated with projects that are to occur within the next five years. With its current development plan, the Company expects to continue its strong PUD conversion ratio in 2022 by converting an estimated 25% of its PUDs to a Proved Developed category, and develop approximately 86% of the consolidated 2021 year-end PUD reserves by the end of 2024.

Oil (MBbls) Liquids (MBbls) Gas (MMcf) MBOE
Proved Reserves As of December 31, 2020 759,401 289,196 1,607,064 1,316,441
Extensions and discoveries 271,222 127,479 720,125 518,722
Revisions of previous estimates (160,570 ) (6,685 ) 195,302 (134,705 )
Purchase of reserves in place 176,261 58,587 302,770 285,310
Divestitures (36,503 ) (11,597 ) (70,048 ) (59,775 )
Production (81,522 ) (27,246 ) (169,406 ) (137,002 )
Proved Reserves As of December 31, 2021 928,289 429,734 2,585,807 1,788,991

Diamondback’s exploration and development costs in 2021 were $1,739 million. PD F&D costs were $7.87/BOE. PD F&D costs are defined as exploration and development costs, excluding midstream, divided by the sum of reserves associated with transfers from proved undeveloped reserves at year-end 2020 including any associated revisions in 2021 and extensions and discoveries placed on production during 2020. Drill bit F&D costs were $4.53/BOE including the effects of all revisions including pricing revisions. Drill bit F&D costs are defined as the exploration and development costs, excluding midstream, divided by the sum of extensions, discoveries and revisions.

Year Ended December 31,
2021 2020 2019
(In millions)
Acquisition costs:
Proved properties $ 2,805 $ 13 $ 194
Unproved properties 1,829 106 418
Development costs 516 381 956
Exploration costs 1,223 1,098 1,915
Total $ 6,373 $ 1,598 $ 3,483

FULL YEAR 2022 GUIDANCE

GLJ

Below is Diamondback’s initial guidance for the full year 2022, which includes first quarter production and capital guidance.

2022 Guidance 2022 Guidance
Diamondback Energy, Inc. Viper Energy Partners LP
Total net production – MBOE/d 369 – 376 29.50 – 31.50
Oil production – MBO/d 218 – 222 17.75 – 19.00
Q1 2022 oil production – MBO/d (total – MBOE/d) 218 – 222 (369 – 376)
Unit costs ($/BOE)
Lease operating expenses, including workovers $4.00 – $4.50
G&A
Cash G&A $0.65 – $0.80 $0.60 – $0.80
Non-cash equity-based compensation $0.40 – $0.50 $0.10 – $0.20
DD&A $8.75 – $9.75 $9.75 – $10.75
Interest expense (net of interest income) $1.10 – $1.30 $3.25 – $3.75
Gathering and transportation $1.60 – $1.80
Production and ad valorem taxes (% of revenue)(a) 7% – 8% 7% – 8%
Corporate tax rate (% of pre-tax income) 23%
Cash tax rate (% of pre-tax income) 6% – 11%
Capital Budget ($ – million)
Drilling, completion, capital workovers, and non-operated properties $1,560 – $1,670
Midstream (ex. equity method investments) $80 – $100
Infrastructure and environmental $110 – $130
2022 Capital expenditures $1,750 – $1,900
Q1 2022 Capital expenditures $435 – $475
Gross horizontal wells drilled (net) 270 – 290 (248 – 267)
Gross horizontal wells completed (net) 260 – 280 (240 – 258)
Average lateral length (Ft.) ~10,200′
Midland Basin well costs per lateral foot $520 – $580
Delaware Basin well costs per lateral foot $700 – $780
Midland Basin net lateral feet (%) ~80%
Delaware Basin net lateral feet (%) ~20%

(a)   Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes.

CONFERENCE CALL

Diamondback will host a conference call and webcast for investors and analysts to discuss its results for the fourth quarter of 2021 on Wednesday, February 23, 2022 at 8:00 a.m. CT. Participants should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and use the confirmation code 8984419. A telephonic replay will be available from 11:00 a.m. CT on Wednesday, February 23, 2022, through Wednesday, March 2, 2022 at 11:00 a.m. CT. To access the replay, call (855) 859-2056 (United States/Canada) or (404) 537-3406 (International) and enter confirmation code 8984419. A live broadcast of the earnings conference call will also be available via the internet at www.diamondbackenergy.com under the “Investor Relations” section of the site. A replay will also be available on the website following the call.

About Diamondback Energy, Inc.

Diamondback is an independent oil and natural gas company headquartered in Midland, Texas focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. For more information, please visit www.diamondbackenergy.com.

Forward-Looking Statements

This news release contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties, and assumptions. All statements, other than statements of historical fact, including statements regarding Diamondback’s: future performance; business strategy; future operations (including drilling plans and capital plans); estimates and projections of revenues, losses, costs, expenses, returns, cash flow, and financial position; reserve estimates and its ability to replace or increase reserves; anticipated benefits of strategic transactions (including acquisitions and divestitures); and plans and objectives of management (including plans for future cash flow from operations and for executing environmental strategies) are forward-looking statements. When used in this news release, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to Diamondback are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Although Diamondback believes that the expectations and assumptions reflected in its forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond Diamondback’s control. Accordingly, forward-looking statements are not guarantees of future performance and Diamondback’s actual outcomes could differ materially from what Diamondback has expressed in its forward-looking statements.

Factors that could cause the outcomes to differ materially include (but are not limited to) the following: changes in supply and demand levels for oil, natural gas, and natural gas liquids, and the resulting impact on the price for those commodities; the impact of public health crises, including epidemic or pandemic diseases such as the COVID-19 pandemic, and any related company or government policies or actions; actions taken by the members of OPEC and Russia affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments; regional supply and demand factors, including delays, curtailment delays or interruptions of production, or governmental orders, rules or regulations that impose production limits; federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations; and the risks and other factors disclosed in Diamondback’s filings with the Securities and Exchange Commission, including its Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the Securities and Exchange Commission’s web site at http://www.sec.gov.

In light of these factors, the events anticipated by Diamondback’s forward-looking statements may not occur at the time anticipated or at all. Moreover, Diamondback operates in a very competitive and rapidly changing environment and new risks emerge from time to time. Diamondback cannot predict all risks, nor can it assess the impact of all factors on its business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those anticipated by any forward-looking statements it may make. Accordingly, you should not place undue reliance on any forward-looking statements made in this news release. All forward-looking statements speak only as of the date of this news release or, if earlier, as of the date they were made. Diamondback does not intend to, and disclaims any obligation to, update or revise any forward-looking statements unless required by applicable law.

Diamondback Energy, Inc.
Consolidated Balance Sheets
(unaudited, in millions, except share amounts)
December 31, December 31,
2021 2020
Assets
Current assets:
Cash and cash equivalents $ 654 $ 104
Restricted cash 18 4
Accounts receivable:
Joint interest and other, net 72 56
Oil and natural gas sales, net 598 281
Inventories 62 33
Derivative instruments 13 1
Income tax receivable 1 100
Prepaid expenses and other current assets 28 23
Total current assets 1,446 602
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($8,496 million and $7,493 million excluded from amortization at December 31, 2021 and December 31, 2020, respectively) 32,914 27,377
Midstream assets 1,076 1,013
Other property, equipment and land 174 138
Accumulated depletion, depreciation, amortization and impairment (13,545 ) (12,314 )
Property and equipment, net 20,619 16,214
Funds held in escrow 12 51
Equity method investments 613 533
Derivative instruments 4
Deferred income taxes, net 40 73
Investment in real estate, net 88 101
Other assets 76 45
Total assets $ 22,898 $ 17,619
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable – trade $ 36 $ 71
Accrued capital expenditures 295 186
Current maturities of long-term debt 45 191
Other accrued liabilities 436 302
Revenues and royalties payable 452 237
Derivative instruments 174 249
Total current liabilities 1,438 1,236
Long-term debt 6,642 5,624
Derivative instruments 29 57
Asset retirement obligations 166 108
Deferred income taxes 1,338 783
Other long-term liabilities 40 7
Total liabilities 9,653 7,815
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value; 400,000,000 shares authorized; 177,551,347 and 158,088,182 shares issued and outstanding at December 31, 2021 and December 31, 2020, respectively 2 2
Additional paid-in capital 14,084 12,656
Retained earnings (accumulated deficit) (1,998 ) (3,864 )
Total Diamondback Energy, Inc. stockholders’ equity 12,088 8,794
Non-controlling interest 1,157 1,010
Total equity 13,245 9,804
Total liabilities and equity $ 22,898 $ 17,619
Diamondback Energy, Inc.
Consolidated Statements of Operations
(unaudited, $ in millions except per share data, shares in thousands)
Three Months Ended December 31, Year Ended December 31,
2021 2020 2021 2020
Revenues:
Oil, natural gas and natural gas liquid sales $ 2,011 $ 754 $ 6,747 $ 2,756
Midstream services 10 13 45 50
Other operating income 1 2 5 7
Total revenues 2,022 769 6,797 2,813
Costs and expenses:
Lease operating expenses 150 93 565 425
Production and ad valorem taxes 121 47 425 195
Gathering and transportation 58 35 212 140
Midstream services expense 19 24 89 105
Depreciation, depletion, amortization and accretion 320 270 1,275 1,311
Impairment of oil and natural gas properties 1,022 6,021
General and administrative expenses 47 24 146 88
Merger and integration expense 1 78
Other operating expense (5 ) 6 4
Total costs and expenses 711 1,515 2,796 8,289
Income (loss) from operations 1,311 (746 ) 4,001 (5,476 )
Other income (expense):
Interest expense, net (29 ) (50 ) (199 ) (197 )
Other income (expense), net (6 ) 1 (10 ) (7 )
Gain (loss) on derivative instruments, net 47 (163 ) (848 ) (81 )
Gain (loss) on sale of equity method investments 23
Gain (loss) on extinguishment of debt (2 ) (75 ) (5 )
Income (loss) from equity investments 9 15 (10 )
Total other income (expense), net 19 (212 ) (1,094 ) (300 )
Income (loss) before income taxes 1,330 (958 ) 2,907 (5,776 )
Provision for (benefit from) income taxes 279 (202 ) 631 (1,104 )
Net income (loss) 1,051 (756 ) 2,276 (4,672 )
Net income (loss) attributable to non-controlling interest 49 (17 ) 94 (155 )
Net income (loss) attributable to Diamondback Energy, Inc. $ 1,002 $ (739 ) $ 2,182 $ (4,517 )
Earnings (loss) per common share:
Basic $ 5.56 $ (4.68 ) $ 12.35 $ (28.59 )
Diluted $ 5.54 $ (4.68 ) $ 12.30 $ (28.59 )
Weighted average common shares outstanding:
Basic 180,143 157,975 176,643 157,976
Diluted 180,998 157,975 177,359 157,976
Dividends declared per share $ 0.60 $ 0.40 $ 1.95 $ 1.525
Diamondback Energy, Inc.
Consolidated Statements of Cash Flows
(unaudited, in millions)
Three Months Ended December 31, Year Ended December 31,
2021 2020 2021 2020
Cash flows from operating activities:
Net income (loss) $ 1,051 $ (756 ) $ 2,276 $ (4,672 )
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes 258 (202 ) 606 (1,042 )
Impairment of oil and natural gas properties 1,022 6,021
Depreciation, depletion, amortization and accretion 320 270 1,275 1,311
(Gain) loss on extinguishment of debt 2 75 5
(Gain) loss on derivative instruments, net (47 ) 163 848 81
Cash received (paid) on settlement of derivative instruments (400 ) (38 ) (1,247 ) 250
Equity-based compensation expense 14 10 51 37
(Gain) loss on sale of equity method investments (23 )
Other 8 (1 ) 47 30
Changes in operating assets and liabilities:
Accounts receivable 111 (48 ) (196 ) 217
Income tax receivable 152 (62 )
Prepaid expenses and other (3 ) 3 20 2
Accounts payable and accrued liabilities (2 ) (2 ) (41 ) (20 )
Revenues and royalties payable (109 ) 18 148 (41 )
Other (36 ) (36 ) (47 ) 1
Net cash provided by (used in) operating activities 1,167 403 3,944 2,118
Cash flows from investing activities:
Drilling, completions and infrastructure additions to oil and natural gas properties (427 ) (219 ) (1,457 ) (1,719 )
Additions to midstream assets (7 ) (7 ) (30 ) (140 )
Property acquisitions (374 ) (31 ) (812 ) (185 )
Proceeds from sale of assets 708 61 820 63
Contributions to equity method investments (107 ) (12 ) (114 ) (102 )
Distributions from equity method investments 13 9 40
Other (9 ) (51 ) 45 (58 )
Net cash provided by (used in) investing activities (216 ) (246 ) (1,539 ) (2,101 )
Cash flows from financing activities:
Proceeds from borrowings under credit facilities 554 213 1,313 1,130
Repayments under credit facilities (147 ) (240 ) (1,000 ) (1,478 )
Proceeds from senior notes 2,200 997
Repayment of senior notes (653 ) (3,193 ) (239 )
Proceeds from (repayments to) joint venture (6 ) (7 ) (20 ) 40
Premium on extinguishment of debt (178 ) (2 )
Repurchased shares under buyback program (409 ) (431 ) (98 )
Repurchased units under buyback program (31 ) (39 ) (94 ) (39 )
Dividends to stockholders (91 ) (59 ) (312 ) (236 )
Distributions to non-controlling interest (40 ) (16 ) (112 ) (93 )
Financing portion of net cash received (paid) for derivative instruments (3 ) 22
Other 6 (36 ) (19 )
Net cash provided by (used in) financing activities (820 ) (148 ) (1,841 ) (37 )
Net increase (decrease) in cash and cash equivalents 131 9 564 (20 )
Cash, cash equivalents and restricted cash at beginning of period 541 99 108 128
Cash, cash equivalents and restricted cash at end of period $ 672 $ 108 $ 672 $ 108
Diamondback Energy, Inc.
Selected Operating Data
(unaudited)
Three Months Ended December 31, Year Ended December 31,
2021 2020 2021 2020
Production Data:
Oil (MBbls) 20,819 16,173 81,522 66,182
Natural gas (MMcf) 45,220 34,067 169,406 130,549
Natural gas liquids (MBbls) 7,254 5,655 27,246 21,981
Combined volumes (MBOE)(1) 35,610 27,506 137,002 109,921
Daily oil volumes (BO/d) 226,293 175,793 223,348 180,825
Daily combined volumes (BOE/d) 387,065 298,978 375,348 300,331
Average Prices:
Oil ($ per Bbl) $ 74.50 $ 38.64 $ 66.19 $ 36.41
Natural gas ($ per Mcf) $ 4.56 $ 1.35 $ 3.36 $ 0.82
Natural gas liquids ($ per Bbl) $ 35.02 $ 14.68 $ 28.70 $ 10.87
Combined ($ per BOE) $ 56.47 $ 27.41 $ 49.25 $ 25.07
Oil, hedged ($ per Bbl)(2) $ 58.70 $ 37.35 $ 52.56 $ 40.34
Natural gas, hedged ($ per Mcf)(2) $ 3.12 $ 0.97 $ 2.39 $ 0.67
Natural gas liquids, hedged ($ per Bbl)(2) $ 34.46 $ 14.50 $ 28.33 $ 10.83
Average price, hedged ($ per BOE)(2) $ 45.30 $ 26.14 $ 39.87 $ 27.26
Average Costs per BOE:
Lease operating expenses $ 4.21 $ 3.38 $ 4.12 $ 3.87
Production and ad valorem taxes 3.40 1.71 3.10 1.77
Gathering and transportation expense 1.63 1.27 1.55 1.27
General and administrative – cash component 0.93 0.51 0.69 0.46
Total operating expense – cash $ 10.17 $ 6.87 $ 9.46 $ 7.37
General and administrative – non-cash component $ 0.39 $ 0.36 $ 0.37 $ 0.34
Depletion $ 8.51 $ 8.98 $ 8.77 $ 11.30
Interest expense, net $ 0.81 $ 1.82 $ 1.45 $ 1.79

(1)   Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2)   Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects includes realized gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting.

NON-GAAP FINANCIAL MEASURES

ADJUSTED EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as net income (loss) attributable to Diamondback Energy, Inc., plus net income (loss) attributable to non-controlling interest (“net income (loss)”) before non-cash (gain) loss on derivative instruments, net, interest expense, net, depreciation, depletion, amortization and accretion, depreciation and interest expense related to equity method investments, impairment and abandonments related to equity method investments, (gain) loss on sale of equity method investments, (gain) loss on extinguishment of debt, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, merger and integration expense, other non-cash transactions and provision for (benefit from) income taxes, if any. Adjusted EBITDA is not a measure of net income as determined by United States’ generally accepted accounting principles (“GAAP”). Management believes Adjusted EBITDA is useful because the measure allows it to more effectively evaluate the Company’s operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company adds the items listed above to net income (loss) to determine Adjusted EBITDA because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of the Company’s operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets. The Company’s computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts.

The following tables present a reconciliation of the GAAP financial measure of net income (loss) attributable to Diamondback Energy, Inc. to the non-GAAP financial measure of Adjusted EBITDA:

Diamondback Energy, Inc.
Reconciliation of Net Income (Loss) to Adjusted EBITDA
(unaudited, in millions)
Three Months Ended December 31, Year Ended December 31,
2021 2020 2021 2020
Net income (loss) attributable to Diamondback Energy, Inc. $ 1,002 $ (739 ) $ 2,182 $ (4,517 )
Net income (loss) attributable to non-controlling interest 49 (17 ) 94 (155 )
Net income (loss) 1,051 (756 ) 2,276 (4,672 )
Non-cash (gain) loss on derivative instruments, net (450 ) 125 (377 ) 331
Interest expense, net 29 50 199 197
Depreciation, depletion, amortization and accretion 320 270 1,275 1,311
Depreciation and interest expense related to equity method investments 13 12 43 32
Impairment and abandonments related to equity method investments 4 17
(Gain) loss on sale of equity method investments (23 )
(Gain) loss on extinguishment of debt 2 75 5
Impairment of oil and natural gas properties 1,022 6,021
Non-cash equity-based compensation expense 20 14 71 53
Capitalized equity-based compensation expense (6 ) (4 ) (20 ) (16 )
Merger and integration expense 1 78
Other non-cash transactions (3 ) (3 ) 6 9
Provision for (benefit from) income taxes 279 (202 ) 631 (1,104 )
Consolidated Adjusted EBITDA 1,256 528 4,238 2,184
Less: Adjustment for non-controlling interest 64 53 145 142
Adjusted EBITDA attributable to Diamondback Energy, Inc. $ 1,192 $ 475 $ 4,093 $ 2,042

ADJUSTED NET INCOME

Adjusted net income is a non-GAAP financial measure equal to net income (loss) attributable to Diamondback Energy, Inc. plus net income (loss) attributable to non-controlling interest (“net income (loss)”) adjusted for non-cash (gain) loss on derivative instruments, net, (gain) loss on sale of property, plant and equipment, (gain) loss on extinguishment of debt, merger and integration expense and related income tax adjustments, if any. The Company’s computation of adjusted net income may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts. Management believes Adjusted Net Income helps investors in the oil and natural gas industry to measure and compare the Company’s performance to other oil and natural gas companies by excluding from the calculation items that can vary significantly from company to company depending upon accounting methods, the book value of assets and other non-operational factors.

The following table presents a reconciliation of adjusted net income to net income (loss) attributable to Diamondback Energy, Inc.:

Diamondback Energy, Inc.
Adjusted Net Income
(unaudited, in millions, except per share data)
Three Months Ended December 31, 2021
Amounts Amounts Per
Diluted Share
Net income (loss) attributable to Diamondback Energy, Inc. $ 1,002 $ 5.54
Net income (loss) attributable to non-controlling interest 49 0.27
Net income (loss) 1,051 5.81
Non-cash (gain) loss on derivative instruments, net (450 ) (2.49 )
(Gain) loss on sale of property, plant and equipment (3 ) (0.02 )
(Gain) loss on extinguishment of debt 2 0.01
Merger and integration expense 1 0.01
Adjusted net income excluding above items 601 3.32
Income tax adjustment for above items 94 0.52
Adjusted net income 695 3.84
Less: Adjusted net income attributable to non-controlling interest 38 0.21
Adjusted net income attributable to Diamondback Energy, Inc. $ 657 $ 3.63
Weighted average common shares outstanding:
Basic 180,143
Diluted 180,998

OPERATING CASH FLOW BEFORE WORKING CAPITAL CHANGES AND FREE CASH FLOW

Operating cash flow before working capital changes, which is a non-GAAP financial measure representing net cash provided by operating activities as determined under GAAP without regard to changes in operating assets and liabilities. The Company believes operating cash flow before working capital changes is a useful measure of an oil and natural gas company’s ability to generate cash used to fund exploration, development and acquisition activities and service debt or pay dividends. The Company also uses this measure because adjusted operating cash flow relates to the timing of cash receipts and disbursements that the Company may not control and may not relate to the period in which the operating activities occurred. This allows the Company to compare its operating performance with that of other companies without regard to financing methods and capital structure.

Free Cash Flow, which is a non-GAAP financial measure, is cash flow from operating activities before changes in working capital in excess of cash capital expenditures. The Company believes that Free Cash Flow is useful to investors as it provides a measure to compare both cash flow from operating activities and additions to oil and natural gas properties across periods on a consistent basis. These measures should not be considered as an alternative to, or more meaningful than, net cash provided by operating activities as an indicator of operating performance. The Company’s computation of operating cash flow before working capital changes and Free Cash Flow may not be comparable to other similarly titled measures of other companies. The Company uses Free Cash Flow to reduce debt, as well as return capital to stockholders above the base dividend as determined by the Board of Directors. This release provides 2022 guidance for Free Cash Flow (non-GAAP measure) and net cash provided by operating activities (the comparable GAAP measure). These guidance amounts are based on assumptions including current strip commodity prices and the midpoint of Diamondback’s production, operating cost and capital expenditure guidance. Working capital changes assumed in the calculation of Free Cash Flow are assumed to be minimal, but the Company is unable to provide a full quantitative reconciliation of these measures because management cannot reliably quantify certain of the individual components of working capital changes. Those components could be significant.

The following tables present a reconciliation of net cash provided by operating activities to operating cash flow before working capital changes and to Free Cash Flow:

Diamondback Energy, Inc.
Operating Cash Flow
(unaudited, in millions)
Three Months Ended December 31, Year Ended December 31,
2021 2020 2021 2020
Net cash provided by operating activities $ 1,167 $ 403 $ 3,944 $ 2,118
Less: Changes in cash due to changes in operating assets and liabilities:
Accounts receivable 111 (48 ) (196 ) 217
Income tax receivable 152 (62 )
Prepaid expenses and other (3 ) 3 20 2
Accounts payable and accrued liabilities (2 ) (2 ) (41 ) (20 )
Revenues and royalties payable (109 ) 18 148 (41 )
Other (36 ) (36 ) (47 ) 1
Total working capital changes (39 ) (65 ) 36 97
Operating cash flow before working capital changes(1)(2) $ 1,206 $ 468 $ 3,908 $ 2,021
Diamondback Energy, Inc.
Free Cash Flow
(unaudited, in millions)
Three Months Ended December 31, Year Ended December 31,
2021 2020 2021 2020
Operating cash flow before working capital changes $ 1,206 $ 468 $ 3,908 $ 2,021
Drilling, completions and infrastructure additions to oil and natural gas properties (427 ) (219 ) (1,457 ) (1,719 )
Additions to midstream assets (7 ) (7 ) (30 ) (140 )
Total Cash CAPEX (434 ) (226 ) (1,487 ) (1,859 )
Free Cash Flow(1)(2) $ 772 $ 242 $ 2,421 $ 162

(1)   The year ended December 31, 2021 includes cash paid on commodity contracts terminated prior to their contractual maturity of $16 million.
(2)   The year ended December 31, 2020 includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million.

NET DEBT

The Company defines net debt as total debt less cash and cash equivalents. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company’s outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. The Company believes this metric is useful to analysts and investors in determining the Company’s leverage position because the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt.

December 31, 2021 Net Q4 Principal
Borrowings/
(Repayments)
September 30, 2021 June 30, 2021 March 31, 2021 December 31, 2020
(in millions)
Diamondback Energy, Inc.(a) $ 5,277 $ (661 ) $ 5,938 $ 6,373 $ 6,623 $ 4,713
Viper Energy Partners LP(a) 784 212 572 542 537 564
Rattler Midstream LP(a) 695 195 500 505 554 579
Total debt 6,756 $ (254 ) 7,010 7,420 7,714 5,856
Cash and cash equivalents (654 ) (457 ) (344 ) (121 ) (104 )
Net debt $ 6,102 $ 6,553 $ 7,076 $ 7,593 $ 5,752

(a)  Excludes debt issuance costs, discounts, premiums and fair value hedges.

PV-10

PV-10 is the Company’s estimate of the present value of the future net revenues from proved oil and natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” The Company believes PV-10 to be an important measure for evaluating the relative significance of its oil and natural gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, the Company believes the use of a pre-tax measure is valuable for evaluating the Company. The Company believes that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and natural gas industry. The following table reconciles PV-10 to the Company’s standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.

(in millions) December 31, 2021
Standardized measure of discounted future net cash flows after tax $ 18,717
Add: Present value of future income tax discounted at 10% 3,109
PV-10 $ 21,826

DERIVATIVES

As of February 18, 2022, the Company had the following outstanding consolidated derivative contracts, including derivative contracts at Viper Energy Partners LP. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing and Crude Oil Brent pricing and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing. When aggregating multiple contracts, the weighted average contract price is disclosed.

Crude Oil (Bbls/day, $/Bbl)
Q1 2022 Q2 2022 Q3 2022 Q4 2022 1H 2023 2H 2023
Swaps – WTI (Cushing) 1,000 1,000
$45.00 $45.00
Swaps – Crude Brent Oil(1) 13,900 13,900
$67.54 $67.54
Costless Collars – WTI (Cushing) 19,500 13,000 4,000
Long Put Price ($/Bbl) $46.28 $46.92 $45.00
Ceiling Price ($/Bbl) $72.67 $75.00 $92.65
Costless Collars – WTI (Magellan East Houston) 24,000 28,000 17,000 7,000
Long Put Price ($/Bbl) $46.25 $47.14 $50.00 $50.00
Ceiling Price ($/Bbl) $72.66 $74.13 $84.44 $95.55
Costless Collars – Crude Brent Oil 55,000 34,000 13,000 7,000
Long Put Price ($/Bbl) $45.55 $46.47 $48.08 $46.43
Ceiling Price ($/Bbl) $71.08 $77.00 $82.93 $84.40
Long Puts – WTI (Cushing) 9,500 10,000 8,000
Long Put Price ($/Bbl) $47.51 $47.50 $47.50
Deferred Premium ($/Bbl) $-1.57 $-1.49 $-1.52
Long Puts – WTI (Magellan East Houston) 6,000 8,000 12,000 10,000
Long Put Price ($/Bbl) $50.00 $50.00 $50.00 $50.00
Deferred Premium ($/Bbl) $-1.98 $-1.87 $-1.89 $-1.85
Long Puts – Crude Brent Oil 14,000 24,000 36,000 32,000
Long Put Price ($/Bbl) $50.00 $50.00 $50.00 $50.00
Deferred Premium ($/Bbl) $-1.66 $-1.80 $-1.83 $-1.83
Basis Swaps – WTI (Midland) 17,000 17,000 10,000 10,000
$0.66 $0.66 $0.84 $0.84
Basis Spread Puts – WTI (Cushing) / Brent 50,000 50,000 50,000 50,000
Spread Price ($/Bbl) $-10.40 $-10.40 $-10.40 $-10.40
Deferred Premium ($/Bbl) $-0.78 $-0.78 $-0.78 $-0.78
Roll Swaps – WTI 38,611 55,000 55,000 55,000
$0.77 $0.89 $0.89 $0.89
Natural Gas (Mmbtu/day, $/Mmbtu)
Q1 2022 Q2 2022 Q3 2022 Q4 2022 1H 2023 2H 2023
Costless Collars – Henry Hub 350,000 390,000 360,000 360,000 179,890 140,000
Long Put Price ($/Mmbtu) $2.67 $2.65 $2.76 $2.76 $2.88 $2.86
Ceiling Price ($/Mmbtu) $4.76 $5.20 $6.16 $6.16 $7.03 $6.42
Natural Gas Basis Swaps – Waha Hub 230,000 230,000 250,000 250,000 170,000 150,000
$-0.36 $-0.36 $-0.43 $-0.43 $-0.89 $-0.94

(1) Excludes swaptions of 8,250 BO/d in second half 2022, whereby the counterparty has the right to exercise the hedge at a weighted-average price of $68.62/Bbl.