MIDLAND, Texas, Feb. 18, 2020 (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, 2019.
FOURTH QUARTER 2019 HIGHLIGHTSQ4 2019 average production of 195.0 MBO/d (301.3 MBOE/d), with average oil production up 5% over Q3 2019 and 50% over Q4 2018Q4 2019 net loss of $(487) million, which includes a $790 million impairment due to lower SEC commodity pricing; adjusted net income (as defined and reconciled below) of $308 million, or $1.93 per diluted shareQ4 2019 Consolidated Adjusted EBITDA (as defined and reconciled below) of $869 million; adjusted EBITDA net of non-controlling interest of $827 millionQ4 2019 capital expenditures of $748 million; turned 78 gross operated horizontal wells to productionApproved a 100% increase in the annual cash dividend policy to $1.50 per common share starting with Q4 2019 payment, subject to discretion of the BoardDeclared Q4 2019 cash dividend of $0.375 per share payable on March 10, 2020; implies a 2.0% annualized yield based on the February 14, 2020 share closing price of $74.97Repurchased 2,415,000 shares in Q4 2019 for ~$199 millionClosed inaugural offering of $3.0 billion of investment grade notes; proceeds used to fully redeem $1.25 billion of 4.75% notes and pay down a portion of outstanding credit facility borrowingsQ4 2019 unhedged realized oil prices of $54.74/Bbl, representing ~96% of WTI and up 6% versus Q3 2019; expect to realize ~98-101% of WTI in 2020Successfully traded majority of operated New Mexico acreage in the Northern Delaware Basin for operated Texas acreage in both the Midland and Delaware Basin; less than 0.1% of current net acreage now on federal landClosed previously announced Drop-Down transaction to subsidiary Viper Energy Partners LP (NASDAQ:  VNOM) (“Viper”)“Diamondback ended 2019 in a position of strength, achieving 5% sequential oil production growth along with our highest oil realizations of the year.  This, combined with our industry-leading cost structure, resulted in 18% quarter over quarter Adjusted EBITDA growth and 31% Adjusted EPS growth in the quarter.  We repurchased 2.4 million shares in the quarter for approximately $199 million, utilizing free cash flow and a $43 million gain from interest rate swaps unwound as part of our first investment grade bond offering in November to repurchase shares at a depressed valuation.  Further, Diamondback did not slow operations in the second half of 2019 and maintained continuous operations with eight completion crews running consistently through the end of the year, setting us up for continued growth and operational momentum in 2020,” stated Travis Stice, Chief Executive Officer of Diamondback.FULL YEAR 2019 HIGHLIGHTSFull year 2019 net income of $240 million, or $1.47 per diluted share; full year 2019 adjusted net income (as defined and reconciled below) of $1.1 billion, or $6.93 per diluted shareFull year 2019 consolidated adjusted EBITDA of $3.1 billion, or $18.71 per diluted shareFull year 2019 average production of 187.7 MBO/d (283.0 MBOE/d), an increase of 26% from combined 2018 average daily oil volumes, after adjusting for the full year 2018 impact of the Energen transaction which closed on November 29, 2018Full year 2019 capital expenditures of $2,921 million; turned 317 operated horizontal wells to productionProved reserves as of December 31, 2019 of 1,128 MMboe (711 MMBo, 63% oil, 67% PDP), up 14% year over year; proved developed producing (“PDP”) reserves of 760 MMboe (457 MMBo, 60% oil), up 18% year over year2019 consolidated proved developed finding and development (“PD F&D”) costs of $10.87/boe; drill bit finding and development costs of $11.11/boeRepurchased 6,385,000 shares for ~$598 million; represents 30% of the Board approved program for up to $2.0 billion of stock repurchases through December 31, 2020 and ~4% of the Company’s float at December 31, 2018“Looking back, 2019 was a historic year for Diamondback.  We successfully integrated our merger with Energen Resources, doubling the size of our Company while achieving greater cost synergies in a shorter period of time than originally promised at time of deal announcement.  We grew pro forma oil production 26% year over year with a $2.9 billion capital budget, increased our dividend by 50% and repurchased 6.4 million shares, or ~4% of our float entering the year.  We sold non-core assets for over $320 million of gross proceeds, dropped down mineral interests to Viper and took our midstream business public with approximately $720 million of net proceeds to Diamondback while retaining 71% post-IPO ownership.  In November, we executed the final piece of our synergy scorecard and refinanced $3.0 billion of the Company’s long-term debt following our upgrade to investment grade at a weighted average 3.23% interest rate,” stated Travis Stice, Chief Executive Officer of Diamondback.Mr. Stice continued, “While we are proud of what we accomplished in 2019, we do not spend time looking backward at our tracks in the sand, but rather looking ahead and concentrating on the future.  2020 has already brought its own industry challenges, and we are focused on navigating these challenges by staying disciplined, improving our industry-leading cost structure, growing production, increasing environmental transparency, and returning more cash to stockholders as evidenced by our dividend announcement today.  Should commodity prices weaken further or remain weak for an extended period of time, we will act responsibly as we have many times in the past and reduce capital spending.  If commodity prices strengthen, we will grow oil production within our previously announced 2020 budget, and return cash to stockholders or pay down debt.”ENVIRONMENTAL, SOCIAL, GOVERNANCE AND COMPENSATION: RECENT AND EXPECTED CHANGESAdditionally, Diamondback today announced recent and planned changes regarding environmental, social and governance (“ESG”) disclosure and performance, as well as approved and expected changes to its compensation program.  The Company plans to provide additional detail for these and other changes in its upcoming proxy, which it expects to file in the second quarter of 2020.Formed Safety, Sustainability and Corporate Responsibility Committee of the Board of Directors in the fourth quarter of 2019 with the goal to become best in class in terms of both disclosure and performance as it relates to sustainable long term development of our natural resources  Adopted Proxy Access in the fourth quarter of 2019Plan to add an absolute total shareholder return (“TSR”) modifier to long term incentive (“LTI”) compensation that reduces payouts upon negative performance period TSR, pays at target upon achieving a performance period annual TSR of 0-15%, and has a multiplier upon achieving a performance period annual TSR of greater than 15%Plan to replace executive employment agreements with a severance and change of control plan consistent with current market practicePlan to update annual short-term incentive (“STI”) metrics to include an ESG component with expected weighting of 10-15%ESG component expected to be determined by meeting or exceeding key environmental and safety metrics including, but not limited to: flaring, GHG emissions, recycled water, fluid spill control and Total Recordable Incident Rate (safety); each metric will be measured and compensation will be tied to the metrics presented, without discretionExisting metrics expected to remain unchanged (return on average capital employed, per lateral foot well costs and per boe PD F&D costs, LOE and Cash G&A expense)“Diamondback has steadily made changes to compensation and governance practices as the Company has grown and the market has evolved.  The Company was one of the first in our industry to remove all growth metrics from its scorecard five years ago, replacing those metrics with cost control and capital efficiency metrics while also adding return on average capital employed in 2018.  The Company is taking the next step forward in 2020 by adding tangible environmental and safety targets to the scorecard.  One unique aspect of Diamondback’s annual cash incentive program is that while 100 percent of senior management’s cash incentive compensation is tied to the scorecard, up to half of each employee’s discretionary cash incentive compensation is also tied to the same scorecard, creating alignment throughout the organization.  Diamondback is committed to being both best in class in terms of disclosure, but more importantly performance, when it comes to sustainable development of our natural resources in West Texas, where we are headquartered and operate,” stated Steve West, Chairman of the Board of Directors of Diamondback.OPERATIONS UPDATEDiamondback’s Q4 2019 production averaged 301.3 MBOE/d (195.0 MBO/d), up 5% quarter over quarter from 287.1 MBOE/d in Q3 2019, and up 65% year over year from 182.8 MBOE/d in Q4 2018.During the fourth quarter of 2019, Diamondback drilled 76 gross horizontal wells and turned 78 operated horizontal wells to production.  The average lateral length for the wells completed during the fourth quarter was 9,393 feet.  Operated completions during the fourth quarter consisted of 37 Wolfcamp A wells, 21 Lower Spraberry wells, eight Wolfcamp B wells, six Third Bone Spring wells, two Second Bone Spring wells, two Jo Mill wells, one Middle Spraberry well and one Wolfcamp D well.For the full year ended December 31, 2019, the Company drilled 331 gross horizontal wells and turned 317 operated horizontal wells to production. The average lateral length for wells completed during the full year 2019 was 9,598 feet, and consisted of 179 Wolfcamp A wells, 64 Lower Spraberry wells, 33 Wolfcamp B wells, 11 Third Bone Spring wells, 10 Middle Spraberry wells, nine Second Bone Spring wells, eight Jo Mill wells, two Wolfcamp D wells and one Meramec well.Diamondback recently began initial appraisal of its Limelight exploration acreage in Southeast Ector and Northeast Crane counties, completing its first well targeting the Meramec with a 4,720 foot lateral.  This well, the Xanadu 31 1H, commenced with an average 30-day 2-stream initial production (“IP”) rate of 104 boe/d per 1,000 feet (83% oil) and went on to achieve an average 90-day rate of 76 boe/d per 1,000 feet (82% oil).In the Midland Basin, Diamondback continues to have success in the Middle Spraberry and Jo Mill intervals.  The Company recently completed a three well pad in Midland County with an average lateral length of 9,253 feet.  These wells commenced with an average peak 30-day IP rate of 113 boe/d per 1,000 feet (83% oil).In the Delaware Basin, the Company continues to be encouraged by operated completions targeting the Second Bone Spring.  Most recently, Diamondback completed the SNL 27-25 UNIT 4BS well with a 7,554 lateral in Pecos County, which achieved a peak 30-day IP rate of 154 boe/d per 1,000 feet (89% oil).FINANCIAL UPDATEDiamondback’s fourth quarter 2019 net loss was $(487) million, or $(3.04) per diluted share.  Adjusted net income (a non-GAAP financial measure as defined and reconciled below) was $308 million, or $1.93 per diluted share, up 31% from $1.47 in Q3 2019 and up 60% from $1.21 in Q4 2018.Fourth quarter 2019 Adjusted EBITDA net of non-controlling interest (as defined and reconciled below) was $827 million, up 18% from $699 million in Q3 2019 and up 82% from $455 million in Q4 2018.Fourth quarter 2019 average realized prices were $54.74 per barrel of oil, $1.07 per Mcf of natural gas and $15.15 per barrel of natural gas liquids, resulting in a total equivalent unhedged price of $39.28/BOE.  As previously indicated, Diamondback expects realized prices to improve relative to WTI through the remainder of 2020 as out of market fixed differential contracts have now rolled off and converted to Diamondback’s commitments on the EPIC and Gray Oak pipelines or the current Midland market price.  Based on current market differentials and estimated in-basin gathering costs, Diamondback expects to realize ~98-101% of WTI in 2020, all including the effect of current basis hedges, firm transportation agreements and in-basin gathering costs.Diamondback’s cash operating costs for the fourth quarter of 2019 were $8.77 per BOE, including lease operating expenses (“LOE”) of $4.52 per BOE, cash general and administrative (“G&A”) expenses of $0.54 per BOE and production and ad valorem taxes and gathering and transportation of $3.71 per BOE.In December 2019, Diamondback completed an offering of $3.0 billion aggregate principal amount of investment grade notes, comprised of $1.0 billion of 2.875% senior notes due 2024, $800 million of 3.250% senior notes due 2026 and $1.2 billion of 3.500% senior notes due 2029.  Net proceeds from these transactions were used to repay a portion of the outstanding borrowings under its credit facility, and to fully redeem $1.25 billion aggregate principal amount of its 4.750% senior notes at an aggregate purchase price of approximately $1.3 billion.As of December 31, 2019, Diamondback had $109 million in standalone cash and approximately $13 million of outstanding borrowings under its revolving credit facility.During the fourth quarter of 2019, Diamondback spent $652 million on drilling and completion, $23 million on non-operated properties, $15 million on infrastructure and $58 million on midstream, for total capital expenditures of $748 million.  For the year ended December 31, 2019, the Company spent $2,452 million on drilling and completion, $105 million on non-operated properties, $120 million on infrastructure and $244 million on midstream, for total capital expenditures of $2,921 million.CAPITAL RETURN PROGRAMDiamondback announced today that the Company’s Board of Directors declared a cash dividend of $0.375 per common share for the fourth quarter of 2019 payable on March 10, 2020, to stockholders of record at the close of business on March 3, 2020.During the fourth quarter of 2019, Diamondback repurchased 2,415,000 shares of common stock for approximately $199 million.  For the full year 2019, Diamondback repurchased 6,385,000 shares, or approximately 30% of the Board approved program.The repurchase program is authorized to extend through December 31, 2020, and the Company intends to purchase stock under the repurchase program opportunistically with funds from cash generated from operations and liquidity events such as the sale of assets.  This repurchase program may be suspended from time to time, modified, extended or discontinued by the Board of Directors 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, contractual obligations and other factors.  Any stock purchased as part of this program will be retired and made available for future issuances by the Company.RESERVESRyder Scott Company, L.P. prepared estimates of Diamondback’s proved reserves as of December 31, 2019.  Reference prices of $55.69 per barrel of oil and $2.58 per MMbtu of natural gas were used in accordance with applicable rules of the Securities and Exchange Commission. Realized prices with applicable differentials were $51.88 per barrel of oil, $0.18 per Mcf of natural gas and $15.65 per barrel of natural gas liquids.Proved reserves at year-end 2019 of 1,128 MMboe represent a 14% increase over year-end 2018 reserves.  Proved developed reserves increased by 18% to 760 MMboe (67%  of total proved reserves) as of December 31, 2019, reflecting the continued development of the Company’s horizontal well inventory. Proved undeveloped reserves (“PUD” or “PUDs”) increased to 368 MMboe, a 6% increase over year-end 2018, and are comprised of 499 locations, 97 which are in the Delaware Basin. Crude oil represents 63% of Diamondback’s total proved reserves.Net proved reserve additions of 239 MMboe resulted in a reserve replacement ratio of 231% (defined as the sum of extensions, discoveries, revisions and purchases, divided by annual production). The organic reserve replacement ratio was 250% (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 376 MMboe followed by net purchases of reserves totaling 21 MMboe, with divestitures of 41 MMboe and downward revisions of 118 MMboe. PDP extensions accounted for 41% of the total increase in reserves. PDP extensions were the result of 283 wells in which the Company has a working interest, and PUD extensions were the result of 291 new locations in which the Company has a working interest. Net divestitures of reserves of 20 MMboe were the net result of acquisitions of 21 MMboe and divestitures of 41 MMboe primarily associated with the sale of the Company’s conventional Central Basin Platform assets. Downward revisions of 118 MMboe were the result of negative revisions due to lower product pricing of 42 MMboe and PUD downgrades of 70 MMboe primarily from changes in the corporate development plan and inventory optimization. These revisions were partially offset by positive performance revisions of 10 MMboe from increased NGL recoveries.88% of the PUD downgrades, or 61 MMboe, are related to the reclassification of PUDs to non-proved categories that do not fit in the Company’s current three year development plan due to inventory optimization and high grading after the Energen and Diamondback merger. The SEC PUD guidelines allow a company to book PUD reserves associated with projects that are to occur within the next five years, but Diamondback takes a more conservative approach to the booking of PUD reserves by choosing to book minimal PUD reserves outside of its three year development plan. The benefit of booking PUDs has decreased as the Company has grown and no longer has a reserve-based revolving credit facility after earning investment grade status in late 2019. With its current development plan, the Company expects to continue its strong PUD conversion ratio in 2020 by converting an estimated 35% of its PUDs to a Proved Developed category, and develop ~66% of the consolidated 2019 year-end PUD reserves by the end of 2021.Diamondback’s exploration and development costs in 2019 were $2,871 million.  PD F&D costs were $10.87/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 2018 including any associated revisions in 2019 and extensions and discoveries placed on production during 2018. Drill bit F&D costs were $11.11/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. Diamondback’s approach to PUD reserve booking negatively impacted drill bit F&D in 2019. If Diamondback’s PUD to PDP ratio had remained constant compared to 2018 along with constant year over year product pricing, the Company estimates its drill bit F&D would have been ~$2.50/boe less in 2019.UPDATED 2020 GUIDANCEBelow is Diamondback’s guidance for the full year 2020, which is unchanged from the production, activity and capital budget guidance released in November 2019, and has been updated to reflect unit cost expectations.Note the 2020 capital program includes 100% working interest capital for 15 – 17 wells on the San Pedro joint venture acreage with Carlyle due to the accounting treatment of the joint venture, resulting in over $175 million of gross capital for these projects in the consolidated budget.  Per the joint development agreement, Diamondback’s net capital contribution to these wells will be less than 20% of the total capital ($35 million).  The majority of the working interest associated with this development reverts back to Diamondback should certain return thresholds be met.CONFERENCE CALL
Diamondback will host a conference call and webcast for investors and analysts to discuss its results for the fourth quarter of 2019 on Wednesday, February 19, 2020 at 9:00 a.m. CT. Participants should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and use the confirmation code 2383801. A telephonic replay will be available from 12:00 p.m. CT on Wednesday, February 19, 2020 through Wednesday, February 26, 2020 at 12:00 p.m. CT. To access the replay, call (855) 859-2056 (United States/Canada) or (404) 537-3406 (International) and enter confirmation code 2383801. 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 in the Permian Basin in West Texas.  For more information, please visit www.diamondbackenergy.com.Forward Looking StatementsThis news release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.  All statements, other than historical facts, that address activities that Diamondback assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements.  The forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events, including acquisitions and sales of assets, future dividends, production, drilling and capital expenditure plans and effects of hedging arrangements.  These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of Diamondback.  Information concerning these risks and other factors can be found 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. Diamondback undertakes no obligation to update or revise any forward-looking statement.


NON-GAAP FINANCIAL MEASURESAdjusted 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 plus non-cash (gain) loss on derivative instruments, net, interest expense, net, depreciation, depletion and amortization, impairment expense, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, loss on extinguishment of debt, (gain) loss on revaluation of investment, merger and integration expense and income tax (benefit) provision. 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 it 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 in arriving at 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, none of which are components of Adjusted EBITDA. 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 non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income.Adjusted net income is a non-GAAP financial measure equal to net income attributable to Diamondback Energy, Inc. adjusted for non-cash gain on derivative instruments, gain on revaluation of investments, loss on extinguishment of debt, impairment of oil and natural gas properties and related income tax adjustments. 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.The following table presents a reconciliation of adjusted net income to net income:PV-10PV-10 is the Company’s estimate of the present value of the future net revenues from proved oil and 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 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 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 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.DerivativesAs of the filing date, the Company had the following outstanding derivative contracts. 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 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.
Investor Contact:
Adam Lawlis
+1 432.221.7467
[email protected] 
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