Diamondback Energy, Inc. Announces Third Quarter 2018 Financial and Operating Results

Source Press Release
Company Diamondback Energy Inc.Ajax Resources, LLC 
Tags Asset Deals, Deals, Tight Gas & Liquids, Shale Oil, Shale Gas, Unconventional Resources, Upstream Activities, Capital Spending, Guidance, Financial & Operating Data, Strategy - Corporate
Date November 06, 2018

MIDLAND, Texas, Nov. 06, 2018 (GLOBE NEWSWIRE) -- Diamondback Energy, Inc.(NASDAQ: FANG) (“Diamondback” or the “Company”) today announced financial and operating results for the third quarter ended September 30, 2018.


  • Q3 2018 net income of $157 million, or $1.59 per diluted share; adjusted net income (as defined and reconciled below) of $165 million, or $1.67 per diluted share
  • Q3 2018 production of 123.0 Mboe/d (72% oil), up 9% over Q2 2018 and 45% year over year
  • Increasing full year 2018 production guidance range to 118.5 – 119.5 Mboe/d, up 2% from prior guidance midpoint; implies 50% annualized growth at the midpoint from full year 2017 average daily production
  • Q3 2018 cash dividend of $0.125 per share payable on November 26, 2018; implies a 0.4% annualized yield based on the November 5, 2018 share closing price of $115.99
  • Shareholder meetings to vote on the previously announced all-stock acquisition of Energen Corporation are scheduled for November 27; deal expected to close shortly thereafter pending shareholder approval
  • On October 31, 2018, closed previously announced acquisition of leasehold interests and related assets from Ajax Resources, LLC" (Ajax")
  • Also on October 31, 2018, closed additional tack-on acquisitions of 3,646 net leasehold acres, ~3,500 boe/d of estimated current net production and related assets in Northwest Martin and Northeast Andrews counties from ExL Petroleum Management, LP, ExL Petroleum Operating, Inc." (ExL") and EnergyQuest II, LLC" (EnergyQuest") for $312.5 million, subject to adjustment; complementary assets adjacent to existing Diamondback and Ajax acreage
  • Rattler Midstream intends to exercise its right to acquire a 10% equity interest in the Gray Oak Pipeline, subject to certain closing conditions; Diamondback has increased its volume commitment to the Gray Oak Pipeline from 50,000 bo/d to 100,000 bo/d, taking Diamondback's total volume commitment to new long-haul pipelines to 200,000 bo/d (including previously announced volume commitment of 100,000 bo/d on the EPIC Crude Oil Pipeline project)
  • Acquired ownership of overriding royalty interests across a large portion of Ajax's asset base in Northwest Martin and Northeast Andrews counties; increases net revenue interest by 1% across field
  • Executed joint development agreement with Carlyle for development of the San Pedro area of Pecos County and commenced drilling operations

“Diamondback continued to deliver on both our near-term objectives and long-term strategic initiatives through the third quarter and into the fourth quarter of 2018.  First, we were able to deliver significant quarter over quarter production growth while maintaining our best in class margins and operational efficiencies.  Second, we closed multiple highly complementary asset acquisitions in the Northern Midland Basin and have since taken over operations.  Finally, we continued executing on our midstream and long-haul takeaway strategy through our commitment to, and ownership interest in, the Gray Oak Pipeline project.  With our commitment to Gray Oak and EPIC, Diamondback has secured waterborne pricing and "wellhead to water" solutions for all of the current and expected production from our existing asset base, while also building value for our midstream business through strategic joint ventures," stated Travis Stice, Chief Executive Officer of Diamondback.

Mr. Stice continued, "Since the beginning of the year, Diamondback has been able to generate $12 million in free cash flow while growing production 45% over the last 12 months.  Our existing 14 operated rigs, along with the 10 rigs currently operated by Energen, will provide the baseline for our 2019 operating plan assuming the approval of the merger by the shareholders of both companies on November 27 and the closing of the merger shortly thereafter.  With respect to capital, we are raising our infrastructure budget for 2018 due to the continued growth of our midstream operations and the added infrastructure costs related to the signing of our joint development agreement with Carlyle, along with staying ahead of our accelerated rig count.  As we look ahead into 2019, we look forward to delivering on the synergies presented from our merger with Energen while growing production at industry-leading rates, maintaining our best in class operating metrics, generating free cash flow and increasing our return of capital program."


Diamondback’s Q3 2018 production was 123.0 Mboe/d (72% oil), up 45% year over year from 85.0 Mboe/d in Q3 2017, and up 9% quarter over quarter from 112.6 Mboe/d in Q2 2018.

During the third quarter of 2018, Diamondback drilled 40 gross horizontal wells and turned 43 operated horizontal wells to production.  The average completed lateral length for third quarter wells was 9,638 feet.   Operated completions during the third quarter consisted of 18 Wolfcamp A wells, 11 Wolfcamp B wells, 10 Lower Spraberry wells, two Middle Spraberry wells and two Second Bone Spring wells.

The Company operated 13 drilling rigs and five dedicated frac spreads during the third quarter of 2018.  Following the closing of the Ajax acquisition, Diamondback assumed operations of one additional operated rig, and plans to maintain this cadence for the remainder of 2018.  The Company now expects to turn between 170 and 175 gross operated horizontal wells to production for the full year 2018.


In Pecos County, Diamondback continues to achieve strong performance from operated completions targeting the Wolfcamp A.  In Block 142 in the eastern third of our acreage, the Neal Lethco A 17-18 1WA was completed with a lateral length of 9,883 feet and achieved an average peak 30-day 2-stream flowing initial production ("IP") rate of 229 boe/d per 1,000 feet (89% oil).  The State Neal Lethco 10-9 B 2WA, which commenced with a peak 30-day flowing IP rate of 173 boe/d per 1,000 feet (80% oil), went on to produce a peak 90-day flowing IP rate of 149 boe/d per 1,000 feet (79% oil).

Also in Pecos County, the Company recently completed two additional tests of the Second Bone Spring.  The Black Stone State 1-12 B 1SB, with a lateral length of 10,081 feet, achieved a peak 30-day flowing IP rate of 121 boe/d per 1,000 feet (91% oil).  The Stewart 28-21 Unit 1SB, after commencing with a peak 30-day flowing IP rate of 124 boe/d per 1,000 feet (85% oil), went on to achieve a peak 90-day IP rate of 103 boe/d per 1,000 feet (84% oil).

In the ReWard area of the Delaware Basin, Diamondback recently completed a two-well pad targeting the Wolfcamp A.  The Nokota 19 DODT 1WA and 2WA, completed with an average lateral of 10,090 feet, produced an average 24-hour IP rate of 292 boe/d per 1,000 feet (74% oil).  The Jane M Graves A 3WA, which commenced with a peak 30-day flowing IP rate of 217 boe/d per 1,000 feet (81% oil), went on to achieve a peak 90-day IP rate of 191 boe/d per 1,000 feet (80% oil).

In the Delaware Basin, Diamondback has recently begun testing the use of 100% local sand after closely monitoring offset activity and results.  The Company recently implemented the use of 100% local sand with all three of its frac crews in the Midland Basin and has realized a ~$60 per lateral foot reduction in well costs relative to Northern White sand pricing from the first quarter of 2018.  Additionally in the Delaware Basin, Diamondback is assessing the economic benefit of substituting diesel use with natural gas by running one rig and one completion crew with dual fuel capabilities.  If successful and economic, Diamondback has five rigs and two completion crews with dual fuel capabilities in its current fleet.

In the Midland Basin, Diamondback has taken over operations from ExL, which recently completed a three-well pad targeting the Wolfcamp A.  The UL Comanche A4144 Unit was completed with an average lateral length of 7,807 feet and produced an average peak 30-day IP rate of 166 boe/d per 1,000 feet (93% oil).


Diamondback's third quarter 2018 net income was $157 million, or $1.59 per diluted share.  Adjusted net income (a non-GAAP financial measure as defined and reconciled below) was $165 million, or $1.67 per diluted share.

Third quarter 2018 Adjusted EBITDA (as defined and reconciled below) was $372 million, up 60% from $232 million in Q3 2017.

Third quarter 2018 average realized prices were $55.99 per barrel of oil, $1.90 per Mcf of natural gas and $30.44 per barrel of natural gas liquids, resulting in a total equivalent unhedged price of $46.59/boe, up 22% from $38.25/boe in Q3 2017.

Diamondback's cash operating costs for the third quarter of 2018 were $8.70 per boe, including lease operating expenses ("LOE") of $4.34 per boe, cash general and administrative expenses of $0.78 per boe and taxes and transportation of $3.58 per boe.

As of September 30, 2018, Diamondback had $492 million in standalone cash and no outstanding borrowings under its revolving credit facility.  In connection with its Fall 2018 redetermination, which closed in October, the borrowing base under Diamondback's credit facility increased to $2.65 billion from $2.0 billion, and the Company's aggregate elected commitment amount was increased to $2.0 billion from $1.0 billion previously.

During the third quarter of 2018, Diamondback spent $321 million on drilling, completion and non-operated properties, and $74 million on infrastructure and midstream.  Year-to-date, Diamondback has spent $934 million on drilling, completion and non-operated properties, and $205 million on infrastructure and midstream, while generating free cash flow of $12 million, excluding acquisitions.


Diamondback announced today that the Company's Board of Directors has declared a cash dividend for the third quarter of 12.5 cents per common share payable on November 26, 2018, to stockholders of record at the close of business on November 19, 2018.


Giving effect to the Ajax, ExL and EnergyQuest acquisitions that closed on October 31, 2018, as well as continued outperformance of Diamondback's legacy assets, Diamondback is increasing its full year 2018 production guidance to a range of 118.5 Mboe/d to 119.5 Mboe/d, up 2% from the midpoint of the prior range.  This guidance increase does not take into effect the Energen merger, which is expected to close in the fourth quarter subject to shareholder approvals.

Additionally, Diamondback is increasing full year 2018 CAPEX guidance to a range of $1.5 to $1.575 billion from $1.4 to $1.5 billion previously.  This increase is due to the added infrastructure costs related to the signing of Diamondback's joint development agreement with Carlyle, as well as the accelerated build out and upgrade of midstream assets in the Southern Delaware through its subsidiary Rattler Midstream.  Diamondback expects to exit the year operating 14 drilling rigs, excluding the pending Energen merger, which is above its original expectations of 10 to 12 rigs for the year.  This acceleration requires up front infrastructure capital as Diamondback continues operational momentum into 2019, thus increasing its overall infrastructure budget.

  2018 Guidance   
  Diamondback Energy, Inc.  Viper Energy Partners LP  
Total Net Production – MBoe/d  118.5 – 119.5  16.75 - 17.25 
Oil Production - % of Net Production  72% - 74%  69% - 73% 
Unit costs ($/boe)     
Lease operating expenses, including workovers  $3.75 - $4.50   
Gathering & Transportation  $0.25 - $0.75  $0.20 - $0.40 
Cash G&A  Under $1.00  $0.75 - $1.25 
Non-cash equity-based compensation  $0.50 - $1.00  $0.50 - $0.75 
DD&A  $11.00 - $14.00  $8.00 - $11.00 
Interest expense (net of interest income)  $1.00 - $2.00   
Production and ad valorem taxes (% of revenue)(a)  7.0%  7.0% 
Corporate tax rate (% of pre-tax income)  20% - 23%   
Gross horizontal D,C&E/Ft. - Midland Basin  $760 - $810   
Gross horizontal D,C&E/Ft. - Delaware Basin  $1,175 - $1,225   
Horizontal wells completed (net)  170 - 175 (146 - 154)   
Capital Budget ($ - million)     
Horizontal drilling and completion  $1,250 - $1,300   
Infrastructure  $250 - $275   
2018 Capital Spend  $1,500 - $1,575   

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


Diamondback will host a conference call and webcast for investors and analysts to discuss its results for the third quarter of 2018 on Wednesday, November 7, 2018 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 8268326.  A telephonic replay will be available from 11:00 a.m. CT on Wednesday, November 7, 2018 through Wednesday, November 14, 2018 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 8268326.  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.  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.

Diamondback Energy, Inc. 
Consolidated Statements of Operations 
(unaudited, in thousands, except share amounts and per share data) 
  Three Months Ended 
September 30,
  Nine Months Ended 
September 30,
  2018    2017    2018    2017 
Oil, natural gas and natural gas liquids  527,068      299,237      1,508,764      799,169   
Lease bonus  1,322      322      2,250      2,507   
Midstream services  7,280      1,694      26,658      4,241   
Other operating income  2,359      —      6,825      —   
Total revenues  538,029      301,253      1,544,497      805,917   
Operating expenses:               
Lease operating expenses  49,111      32,498      129,103      88,113   
Production and ad valorem taxes  33,536      18,371      93,042      49,975   
Gathering and transportation  6,976      3,476      18,074      9,110   
Midstream services  19,725      4,445      48,515      7,127   
Depreciation, depletion and amortization  146,318      87,579      391,401      221,681   
General and administrative expenses(1)  14,185      11,888      45,039      37,524   
Asset retirement obligation accretion  387      357      1,107      1,030   
Other operating expense  940      —      2,416      —   
  Total expenses  271,178      158,614      728,697      414,560   
Income from operations  266,851      142,639      815,800      391,357   
Other income (expense):               
Interest expense, net  (18,548    (9,192    (49,345    (29,662 
Other income, net  1,962          89,170      9,472   
Gain (loss) on derivative instruments, net  (48,373    (50,645    (139,305    20,376   
Gain (loss) on revaluation of investment  (199    —      5,165      —   
Total other income (expense), net  (65,158    (59,834    (94,315    186   
Income before income taxes  201,693      82,805      721,485      391,543   
Provision for income taxes  42,276      857      82,750      4,393   
Net income  159,417      81,948      638,735      387,150   
Net income attributable to non-controlling interest  2,363      8,924      99,723      19,448   
Net income attributable to Diamondback Energy, Inc.  157,054      73,024      539,012      367,702   
Earnings per common share:               
Basic  1.59      0.74      5.47      3.81   
Diluted  1.59      0.74      5.45      3.80   
Weighted average common shares outstanding:               
Basic  98,638      98,144      98,603      96,491   
Diluted  98,818      98,369      98,820      96,752   
Dividends declared per share  0.125      —      0.375      —   

(1) Includes non-cash expense of $5,350 and $6,187 for the three months ended September 30, 2018 and 2017, respectively, and $18,451 and  $19,418 for the nine months ended September 30, 2018 and 2017, respectively.

Diamondback Energy, Inc. 
Selected Operating Data 
  Three Months Ended 
September 30, 2018
  Three Months Ended
June 30, 2018
  Three Months Ended 
September 30, 2017
Production Data:           
Oil (MBbl)  8,120      7,478      5,678   
Natural gas (MMcf)  7,804      7,367      5,935   
Natural gas liquids (MBbls)  1,893      1,540      1,155   
Oil Equivalents (MBOE)(1)(2)  11,314      10,246      7,823   
Average daily production (BOE/d)(2)  122,975      112,592      85,029   
% Oil  72    73    73 
Average sales prices:           
Oil, realized ($/Bbl)  55.99      61.57      45.62   
Natural gas realized ($/Mcf)  1.90      1.54      2.51   
Natural gas liquids ($/Bbl)  30.44      28.02      21.87   
Average price realized ($/BOE)  46.59      50.26      38.25   
Oil, hedged ($/Bbl)(3)  51.23      55.53      46.90   
Natural gas, hedged ($ per MMbtu)(3)  1.93      1.75      2.64   
Average price, hedged ($/BOE)(3)  43.19      45.87      39.28   
Average Costs per BOE:           
Lease operating expense  4.34      4.16      4.15   
Production and ad valorem taxes  2.96      3.14      2.35   
Gathering and transportation expense  0.62      0.66      0.44   
General and administrative - cash component  0.78      0.87      0.73   
Total operating expense - cash  8.70      8.83      7.67   
General and administrative - non-cash component  0.47      0.55      0.79   
Depreciation, depletion and amortization  12.93      12.68      11.20   
Interest expense, net  1.64      1.67      1.18   

(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.


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, net interest expense, depreciation, depletion and amortization, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, gain 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. Adjusted net income is a non-GAAP financial measure equal to net income attributable to Diamondback Energy, Inc. plus non-cash loss on derivative instruments, gain on revaluation of investment and related income tax adjustments. The Company’s computations of Adjusted EBITDA and 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 tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).

Diamondback Energy, Inc. 
Reconciliation of Adjusted EBITDA to Net Income 
(unaudited, in thousands) 
  Three Months Ended 
September 30, 2018
  Three Months Ended
June 30, 2018
  Three Months Ended 
September 30, 2017
Net income  159,417      301,164      81,948   
Non-cash loss on derivative instruments, net  9,913      13,667      58,645   
Interest expense, net  18,548      17,096      9,192   
Depreciation, depletion and amortization  146,318      129,867      87,579   
Non-cash equity-based compensation expense  7,688      7,999      8,354   
Capitalized equity-based compensation expense  (2,338    (2,349    (2,167 
Asset retirement obligation accretion expense  387      365      357   
Loss (gain) on revaluation of investment  199      (4,465    —   
Income tax (benefit) provision  42,276      (6,607    857   
Consolidated Adjusted EBITDA  382,408      456,737      244,765   
Adjustment for non-controlling interest  (10,832    (86,568    (12,306 
Adjusted EBITDA attributable to Diamondback Energy, Inc.  371,576      370,169      232,459   
Adjusted EBITDA per common share:           
Basic  3.77      3.75      2.37   
Diluted  3.76      3.75      2.36   
Weighted average common shares outstanding:           
Basic  98,638      98,614      98,144   
Diluted  98,818      98,797      98,369   

Adjusted net income is a performance measure used by management to evaluate performance, prior to non-cash loss on derivative instruments, gain on revaluation of investment, loss on sale of assets, other income and related income tax adjustments.

The following table presents a reconciliation of adjusted net income to net income:

Diamondback Energy, Inc. 
Adjusted Net Income 
(unaudited, in thousands, except share amounts and per share data) 
  Three Months Ended 
September 30, 2018
  Pre-Tax Amounts    Amounts Per Share 
Net income attributable to Diamondback Energy, Inc.  157,054      1.59   
Non-cash loss on derivative instruments  9,913      0.10   
Gain on revaluation of investments  199      —   
Adjusted income excluding non-cash loss on derivative instruments, gain on revaluation of investment and other income  167,166      1.69   
Income tax adjustment for above items  (2,190    (0.02 
Adjusted net income  164,976      1.67   


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.

  Crude Oil (Bbls/day, $/Bbl) 
  Q4 2018    Q1 2019    Q2 2019    Q3 2019    Q4 2019 
Swaps - West Texas Intermediate (Cushing)  26,000      7,000      4,000      4,000      3,000   
51.27      55.29      51.86      51.59      49.82   
Swaps - West Texas Intermediate (Magellan East Houston)  7,000      7,000      4,000      2,000      1,000   
71.06      69.65      74.64      75.65      75.74   
Swaps - Crude Brent Oil  10,000      5,000      2,000      2,000      2,000   
62.51      72.82      75.43      74.95      74.45   
Basis Swaps  15,000        3,000      —      —      —   
(0.88    (9.42    —      —      —   
Three-Way Collar Short Put - West Texas Intermediate (Cushing)  —      10,000      10,000      —      —   
—      45.00      45.00      —      —   
Three-Way Collar Floor - West Texas Intermediate (Cushing)  —      10,000      10,000      —      —   
—      55.00      55.00      —      —   
Three-Way Collar Ceiling - West Texas Intermediate (Cushing)  —      10,000      10,000      —      —   
—      70.76      69.71      —        —   
Three-Way Collar Short Put - West Texas Intermediate (Magellan East Houston)  7,000      7,000      4,000      —      —   
56.43      56.43      57.50      —      —   
Three-Way Collar Floor - West Texas Intermediate (Magellan East Houston)  7,000      7,000      4,000      —      —   
66.43      66.43      67.50      —      —   
Three-Way Collar Ceiling - West Texas Intermediate (Magellan East Houston)  7,000      7,000      4,000      —      —   
78.82      77.56      77.68      —      —   
Three-Way Collar Short Put - Crude Brent Oil  —      8,000      8,000      4,000      2,000   
—      55.00      55.00      55.00      55.00   
Three-Way Collar Floor - Crude Brent Oil  —      8,000      8,000      4,000      2,000   
—      65.00      65.00      65.00      65.00   
Three-Way Collar Ceiling - Crude Brent Oil  —      8,000      8,000      4,000      2,000   
—      81.25      81.25      84.58      87.90   
  Natural Gas (Mmbtu/day, $/Mmbtu) 
  Q4 2018 
Swaps  20,000   

Investor Contact:
Adam Lawlis
+1 432.221.7467

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