Press Release

MIDLAND, Texas, Nov. 05, 2019 (GLOBE NEWSWIRE) -- Diamondback Energy, Inc. (NASDAQ: FANG) (“Diamondback” or the “Company”) today announced financial and operating results for the third quarter ended September 30, 2019 and announced 2020 capital and production guidance.

THIRD QUARTER 2019 HIGHLIGHTS

• Q3 2019 net income of $368 million, or $2.26 per diluted share; adjusted net income (as defined and reconciled below) of $239 million, or $1.47 per diluted share
• Q3 2019 Consolidated Adjusted EBITDA (as defined and reconciled below) of $732 million; adjusted EBITDA net of non-controlling interest of $699 million
• Q3 2019 production of 287.1 MBOE/d (65% oil), up 2% over Q2 2019 and 133% over Q3 2018
• Q3 2019 capital expenditures of $825 million; turned 88 wells to production
• Updated 2019 CAPEX guidance of $2.85 - $2.90 billion, narrowed from $2.725 - $2.950 billion previously
• Declared Q3 2019 cash dividend of $0.1875 per share payable on November 22, 2019; implies a 0.9% annualized yield based on the November 1, 2019 share closing price of $86.79
• Repurchased 2,954,000 shares in Q3 2019 for ~$296 million; repurchases through Q3 2019 of $400 million represent 20.0% of the Board approved program for up to $2.0 billion of stock repurchases through December 31, 2020
• On October 1, 2019, closed previously announced Drop-Down transaction to subsidiary Viper Energy Partners LP

2020 CAPITAL AND OPERATING PLAN HIGHLIGHTS

• Full year 2020 production guidance of 310.0 - 325.0 MBOE/d, implied growth of 10% - 15% from midpoint of anticipated full year 2019 production
• Full year 2020 oil production guidance of 205.0 - 215.0 MBO/d, implied growth of 10% - 15% from midpoint of anticipated full year 2019 production
• Full year 2020 CAPEX guidance of $2.8 - $3.0 billion, including drill, complete and equip ("D,C&E") of  $2.45 - $2.60 billion, $200 - $225 million of midstream capital and $150 - $175 million of infrastructure capital
• Plan to operate between 20 - 23 drilling rigs and complete between 320 - 360 gross wells with an average lateral length of approximately 9,700 feet
• Diamondback believes it can maintain flat exit 2019 to exit 2020 production with 15 operated drilling rigs and ~$1.7 billion of D,C&E capital assuming current service costs

"After growing significantly during the first two quarters of the year, Diamondback’s oil production declined in the third quarter due to the sale of our Central Basin Platform assets effective July 1, 2019, which removed ~5,800 barrels per day of low margin oil production from our asset base.  Notwithstanding the effect of this sale, Diamondback’s overall production grew, but the oil percentage declined in the third quarter due to the completion of 18 wells in our Vermejo area in Reeves County and 14 wells in Glasscock County, five of which were DUCs drilled prior to the closing of the Energen merger.  Wells in these two areas on average begin production with oil cuts of ~65% and made up over 35% of total gross wells completed in the third quarter, versus 12% of wells completed in the first half of 2019 and ~15% of expected fourth quarter wells.  This completion mix, along with the return of significant oil volumes that were impacted by offset completions in the third quarter, is expected to result in fourth quarter 2019 oil production growth of ~3% from third quarter volumes.  As a result of the change in our portfolio asset mix due to the Energen merger, we now expect to average 66% - 67% oil for full year 2019 and ~66% oil in 2020," stated Travis Stice, Chief Executive Officer of Diamondback.

Mr. Stice continued, “Our per lateral foot well costs continue to decline and we expect that a combination of continued efficiency gains and service cost tailwinds will drive well costs lower into 2020.  As a result, we are initiating a capital efficient 2020 capital plan of $2.8 - $3.0 billion, which includes all facilities, midstream and infrastructure spending along with drilling and completion capital.  We plan to complete over 10% more net lateral feet and over 20 more gross total wells within the same consolidated budget framework as 2019.  This plan is expected to result in 10% - 15% estimated year over year oil production growth, while generating free cash flow after paying our dividend, based on a commodity price deck of $45 per Bbl WTI for oil, a realized price of $13 per Bbl for NGLs and a realized price of $1.50 for natural gas.  Should commodity prices decline in 2020, we will be prepared to act responsibly and cut capital spending as we have done multiple times over the past few years.  If commodity prices rally, we plan to use excess free cash flow to complete our buyback program or pay down debt.  Over the long term, Diamondback intends to continue to grow production and free cash flow on a per share basis, while maintaining our best in class cost structure."

OPERATIONS UPDATE

Diamondback’s Q3 2019 production averaged 287.1 MBOE/d (65% oil), up 133% year over year from 123.0 MBOE/d in Q3 2018, and up 2% quarter over quarter from 280.4 MBOE/d in Q2 2019.

During the third quarter of 2019, Diamondback drilled 83 gross horizontal wells and turned 88 operated horizontal wells to production.  The average lateral length for the wells completed during the third quarter was 9,549 feet.  Operated completions during the third quarter consisted of 58 Wolfcamp A wells, 10 Lower Spraberry wells, seven Wolfcamp B wells, four Middle Spraberry wells, four Jo Mill wells, two Second  Bone Spring wells, one Third Bone Spring well, one Wolfcamp D well and one Meramec well.

For the nine months ended September 30, 2019, the Company drilled 255 gross horizontal wells and turned 239 operated horizontal wells to production. The average lateral length for wells completed during the first nine months of 2019 was 9,665 feet, and consisted of 142 Wolfcamp A wells, 43 Lower Spraberry wells, 25 Wolfcamp B wells, nine Middle Spraberry wells, seven Second Bone Spring wells, six Jo Mill wells, five Third Bone Spring wells, one Wolfcamp D well and one Meramec well.

FINANCIAL UPDATE

Diamondback's third quarter 2019 net income was $368 million, or $2.26 per diluted share.  Adjusted net income (a non-GAAP financial measure as defined and reconciled below) was $239 million, or $1.47 per diluted share, down 13% from $1.70 in Q2 2019 and down 12% from $1.67 in Q3 2018.

Third quarter 2019 Adjusted EBITDA (as defined and reconciled below) was $699 million, down 9% from $772 million in Q2 2019 and up 88% from $372 million in Q3 2018.

Third quarter 2019 average realized prices were $51.71 per barrel of oil, $0.62 per Mcf of natural gas and $11.61 per barrel of natural gas liquids, resulting in a total equivalent unhedged price of $36.20/BOE.  As previously indicated, Diamondback expects realized prices to improve relative to WTI through the remainder of 2019 and 2020 as fixed differential contracts roll off and convert to Diamondback's commitments on the EPIC and Gray Oak pipelines or move to the current Midland market price.  Based on current market differentials and estimated in-basin gathering costs, Diamondback expects to realize ~95% of WTI for the remainder of 2019 and ~100% 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 third quarter of 2019 were $8.70 per BOE, including lease operating expenses ("LOE") of $4.85 per BOE, cash general and administrative ("G&A") expenses of $0.59 per BOE and production and ad valorem taxes and transportation of $3.26 per BOE.

As of September 30, 2019, Diamondback had $77 million in standalone cash and approximately $1.6 billion of outstanding borrowings under its revolving credit facility.

During the third quarter of 2019, Diamondback spent $701 million on drilling and completion, $28 million on non-operated properties, $21 million on infrastructure and $75 million on midstream, for total capital expenditures of $825 million.  For the nine months ended September 30, 2019, the Company spent $1,801 million on drilling and completion, $82 million on non-operated properties, $104 million on infrastructure and $186 million on midstream, for total capital expenditures of $2,173 million.

CAPITAL RETURN PROGRAM

Diamondback announced today that the Company's Board of Directors declared a cash dividend of 18.75 cents per common share for the third quarter of 2019 payable on November 22, 2019, to stockholders of record at the close of business on November 15, 2019.

During the third quarter of 2019, Diamondback repurchased 2,954,000 shares of common stock for approximately $296 million.  As of September 30, 2019, Diamondback repurchased 3,970,000 shares, or approximately 20% 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.

PRELIMINARY 2020 GUIDANCE

Diamondback expects full year 2020 average daily production of 310.0 - 325.0 MBOE/d and average daily oil production of 205.0 - 215.0 MBO/d with an estimated capital spend of $2.8 - $3.0 billion.  The capital budget includes $200 - $225 million of midstream capital and $150 - $175 million of infrastructure capital.  During 2020, Diamondback expects to complete between 320 - 360 gross operated wells from a 20 - 23 rig drilling program.  Full year 2020 well costs are expected to be between $720 - $750 per lateral foot in the Midland Basin and between $1,075 - $1,125 per lateral foot in the Delaware Basin.

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.

FULL YEAR 2019 GUIDANCE

Diamondback is narrowing its full year 2019 guidance for average daily production to between 281.0 to 282.0 MBOE/d and is narrowing full year 2019 CAPEX to between $2.85 - $2.90 billion.  Diamondback now expects to complete 310 - 315 gross operated horizontal wells in 2019.

(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 third quarter of 2019 on Wednesday, November 6, 2019 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 2569298.  A telephonic replay will be available from 12:00 p.m. CT on Wednesday, November 6, 2019 through Wednesday, November 13, 2019 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 2569298.  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 Statements

This 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 proposed 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.

1. Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
2. The volumes presented are based on actual results and are not calculated using the rounded numbers in the table above.
3. 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 commodity derivatives, which we do not designate for hedge accounting.

NON-GAAP FINANCIAL MEASURES

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 plus non-cash (gain) loss on derivative instruments, net, interest expense, net, depreciation, depletion and amortization, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, gain (loss) on revaluation of investment 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 (loss).

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 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:

Derivatives

As 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
alawlis@diamondbackenergy.com

Source: Diamondback Energy, Inc.