MIDLAND, Texas, Nov. 06, 2017 (GLOBE NEWSWIRE) — Diamondback Energy, Inc. (NASDAQ:FANG) (“Diamondback” or the “Company”) today announced financial and operating results for the third quarter ended September 30, 2017.
- Q3 2017 net income of $73 million, or $0.74 per diluted share; adjusted net income (as defined and reconciled below) of $131 million, or $1.33 per diluted share
- Previously announced Q3 2017 production of 85.0 Mboe/d (73% oil), up 10% over Q2 2017 and 89% year over year
- Increasing full year 2017 production guidance to 77.5 – 78.5 Mboe/d, up 3% from prior full year guidance midpoint
- Narrowing full year 2017 CAPEX guidance to $850 – $900 million from $800 – $950 million previously
- Q3 2017 cash operating costs of $7.67/boe, including LOE of $4.15/boe, cash G&A of $0.73/boe and taxes and transportation of $2.79/boe
- Expect to turn 35 to 40 gross operated horizontal wells to production during Q4 2017 and 120 to 125 wells for the full year 2017
- Operating nine horizontal rigs and four dedicated frac spreads, with plans to add a 10th horizontal rig in the coming weeks
- Wolfcamp A well in Reeves County with peak 90-day flowing 2-stream initial production (“IP”) rate of 184 boe/d per 1,000 feet (79% oil)
- Two-well Upper/Lower Wolfcamp A pad in Pecos County with average peak 10-day IP rate of 152 boe/d per 1,000 feet (80% oil)
- First Lower Second Bone Spring well in Pecos County with peak 90-day IP rate of 149 boe/d per 1,000 feet (91% oil); performing in line with Wolfcamp A results in the area
“Over the past five years as a publicly traded company, Diamondback has remained committed to a strategy of best-in-class execution, low cost operations and transparency. In an industry that often rewards ‘growth for growth’s sake’, Diamondback has maintained strict capital discipline, growing production over 175% within operating cash flow over the past 11 quarters,” stated Travis Stice, Chief Executive Officer of Diamondback.
Mr. Stice continued, “Diamondback continues to confirm the productive capacity of its Southern Delaware assets through strong extended well performance, while continuing to grow production in the Midland Basin at peer-leading capital efficiency. We expect to add our 10th operated rig in the coming weeks, and as we look into 2018, our strategy has not changed in that we expect to match our capital budget to our projected operating cash flow.”
As previously announced, Diamondback’s Q3 2017 production was 85.0 Mboe/d (73% oil), up 89% year over year from 44.9 Mboe/d in Q3 2016, and up 10% quarter over quarter from 77.0 Mboe/d in Q2 2017.
During the third quarter of 2017, Diamondback drilled 42 gross horizontal wells and turned 24 operated horizontal wells to production. The average completed lateral length for third quarter wells was 9,603 feet, up from 7,716 feet in the second quarter. Operated completions during the third quarter consisted of 10 Wolfcamp A wells, seven Lower Spraberry wells, six Wolfcamp B wells, and one Middle Spraberry well. The Company operated nine rigs throughout the quarter and recently added its fourth dedicated frac spread.
As of September 30, 2017, Diamondback had drilled 106 gross horizontal wells year to date, with 85 gross operated horizontal wells turned to production over the same period. The Company plans to add a tenth rig to the Midland Basin in the coming weeks, and maintain this cadence until year end. As a result, Diamondback now expects to turn between 35 and 40 gross operated horizontal wells to production during Q4 2017 and 120 to 125 operated horizontal wells for the full year 2017.
DELAWARE BASIN OPERATIONS UPDATE
In Pecos County, Diamondback continues to see strong performance from early operated completions targeting the Wolfcamp A. The Company’s first operated two-well pad, the State Neal Lethco 36-3201WA and State Neal Lethco 36-3202WA, achieved an average peak 30-day flowing IP rate of 130 boe/d per 1,000 feet (88% oil). Subsequently, the Company completed a second two-well pad targeting the Upper and Lower Wolfcamp A with an average lateral length of 7,462 feet. The Sibley 3-2 2WA and Sibley 3-2 3WA achieved an average 10-day peak flowing IP rate of 152 boe/d per 1,000 feet (80% oil).
Also in Pecos County, The Kelley State 2H, the Company’s first operated Lower Second Bone Spring well, reached a peak 30-day flowing IP rate of 195 boe/d per 1,000 feet (92% oil) and attained a peak 90-day IP rate of 149 boe/d per 1,000 feet (91% oil). This well continues to exceed expectations and compares favorably with Wolfcamp A wells in the area. As a result, Diamondback plans to continue to test this zone in 2018.
In Reeves County, the Company continues to see strong extended performance from its second operated Wolfcamp A well. After achieving a peak 30-day flowing IP rate of 205 boe/d per 1,000 feet (80% oil), the Waler State Unit 4 1WA attained a peak 90-day IP rate of 184 boe/d per 1,000 feet (79% oil). Most recently, Diamondback completed another Wolfcamp A well in Reeves County with a 10,372 foot lateral. The Warlander 501 WA commenced with a current peak 10-day IP rate of 193 boe/d per 1,000 feet (81% oil), with production continuing to increase.
MIDLAND BASIN OPERATIONS UPDATE
In Midland County, the Company recently completed two four-well pads targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B. Four wells on the Blackfoot West Unit pad were completed with an average lateral length of 9,721 feet and achieved an average peak 30-day IP rate of 152 boe/d per 1,000 feet (89% oil). Subsequently, Diamondback completed the Whitefish Unit pad with an average lateral length of 12,843 feet, with the Wolfcamp B well achieving a peak 30-day flowing IP rate of 156 boe/d per 1,000 feet (86% oil).
In Andrews County, Diamondback recently completed a two-well pad targeting the Lower Spraberry with an average lateral of 12,940 feet. The UL Mason West Unit wells had an average 30-day IP rate of 114 boe/d per 1,000 feet (91% oil) and 90-day IP rate of 97 boe/d per 1,000 feet (91% oil).
Diamondback’s third quarter 2017 net income was $73 million, or $0.74 per diluted share. Adjusted net income (a non-GAAP financial measure as defined and reconciled below) was $131 million, or $1.33 per diluted share.
Third quarter 2017 Adjusted EBITDA (as defined and reconciled below) was $232 million, up 6% from $218 million in Q2 2017. Third quarter 2017 revenues were $301 million, up 12% from $269 million in Q2 2017.
Third quarter 2017 average realized prices were $45.62 per barrel of oil, $2.51 per Mcf of natural gas and $21.87 per barrel of natural gas liquids, resulting in a total equivalent price of $38.25/boe, roughly equal to the Q2 2017 total equivalent price of $38.18/boe.
Diamondback’s cash operating costs for the third quarter 2017 were $7.67 per boe, including lease operating expenses (“LOE”) of $4.15 per boe, cash general and administrative expenses of $0.73 per boe and taxes and transportation of $2.79 per boe. On a per-unit basis, Q3 2017 cash operating costs declined 16% year over year.
As of September 30, 2017, Diamondback had $26 million in standalone cash and $235 million outstanding on its revolving credit facility. In connection with its Fall 2017 redetermination expected to close in November 2017, the lead bank on Diamondback’s credit facility recommended a borrowing base increase to $1.8 billion from $1.5 billion with the Company to elect an increase in the lenders’ aggregate commitment to $1.0 billion from the current elected commitment of $750 million. Additionally, Viper Energy Partners LP (“Viper”), a subsidiary of Diamondback, expects to have its borrowing base increased to $400 million from $315 million currently.
During the third quarter of 2017, Diamondback spent $225 million on drilling, completion and non-operated properties, and $33 million on infrastructure. As of September 30, 2017, Diamondback had spent $491 million on drilling, completion and non-operated properties, and $63 million on infrastructure year to date, while generating free cash flow of $84 million, excluding acquisitions.
Diamondback acquired over 1,000 net acres of leasehold and over 950 net royalty acres of minerals for $102 million during the third quarter. The royalty acres will likely be dropped down to Viper after commencing active development in 2018.
FULL YEAR 2017 GUIDANCE
Below is Diamondback’s full year 2017 guidance, which has been updated to reflect higher production, a narrowed capital budget and lower expenses.
|Diamondback Energy, Inc.||Viper Energy Partners LP|
|Total Net Production – MBoe/d||77.5 – 78.5||11.0 – 11.5|
|Unit costs ($/boe)|
|Lease operating expenses, including workovers||$4.00 – $4.50||n/a|
|Gathering & Transportation||$0.25 – $0.75||$0.15 – $0.25|
|Cash G&A||Under $1.00||$0.75 – $1.25|
|Non-cash equity-based compensation||$0.75 – $1.25||$0.50 – $1.00|
|DD&A||$10.50 – $11.50||$9.00 – $10.00|
|Interest expense (net of interest income)||$1.00 – $2.00|
|Production and ad valorem taxes (% of revenue)(a)||7.0%||7.0%|
|Corporate tax rate (% of pre-tax income)||5% – 15%||n/a|
|($ – million)|
|Gross horizontal well costs – Midland Basin(b)||$5.0 – $5.5||n/a|
|Gross horizontal well costs – Delaware Basin(b)||$7.0 – $8.0|
|Horizontal wells completed (net)||120 – 125 (103 – 108)|
|Capital Budget ($ – million)|
|Horizontal drilling and completion||$725 – $750||n/a|
|Infrastructure||$125 – $150||n/a|
|2017 Capital Spend||$850 – $900||n/a|
|(a) Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes.
|(b) Assumes a 7,500’ average lateral length.|
Diamondback will host a conference call and webcast for investors and analysts to discuss its financial and operating results for the third quarter of 2017 on Tuesday, November 7, 2017 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 99808131. A telephonic replay will be available from 12:00 p.m. CT on Tuesday, November 7, 2017 through Tuesday, November 14, 2017 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 99808131. 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. Diamondback’s activities are primarily focused on the horizontal exploitation of multiple intervals within the Wolfcamp, Spraberry, Clearfork, Bone Spring and Cline formations.
Forward Looking Statements
This news release contains forward-looking statements within the meaning of the federal securities laws. 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
|Nine Months Ended
|Oil, natural gas liquids and natural gas||$||299,237||$||142,131||$||799,169||$||342,095|
|Lease operating expenses||32,498||22,180||88,113||59,080|
|Production and ad valorem taxes||18,371||9,123||49,975||25,244|
|Gathering and transportation||3,476||2,843||9,110||8,064|
|Depreciation, depletion and amortization||87,579||44,746||221,681||126,686|
|Impairment of oil and natural gas properties||—||46,368||—||245,536|
|General and administrative expenses(1)||11,888||9,908||37,524||32,411|
|Asset retirement obligation accretion||357||270||1,030||770|
|Income (loss) from operations||142,639||6,693||391,357||(155,696||)|
|Gain (loss) on derivative instruments, net||(50,645||)||2,034||20,376||(8,665||)|
|Total other income (expense), net||(59,834||)||(7,293||)||186||(37,284||)|
|Income (loss) before income taxes||82,805||(600||)||391,543||(192,980||)|
|Provision for income taxes||857||—||4,393||368|
|Net income (loss)||81,948||(600||)||387,150||(193,348||)|
|Net income (loss) attributable to non-controlling interest||8,924||1,630||19,448||(2,716||)|
|Net income (loss) attributable to Diamondback Energy, Inc.||$||73,024||$||(2,230||)||$||367,702||$||(190,632||)|
|Earnings per common share:|
|Weighted average common shares outstanding:|
|(1) Includes non-cash expense of $6,187 and $6,265 for the three months ended September 30, 2017 and 2016, respectively, and $19,418 and $20,643 for the nine months ended September 30, 2017 and 2016, respectively.|
|Diamondback Energy, Inc.
Selected Operating Data
June 30, 2017
|Natural gas (MMcf)||5,935||4,939||2,673|
|Natural gas liquids (MBbls)||1,155||945||687|
|Oil Equivalents (MBOE)(1)(2)||7,823||7,005||4,133|
|Average daily production (BOE/d)(2)||85,029||76,977||44,923|
|Average sales prices:|
|Oil, realized ($/Bbl)||$||45.62||$||45.43||$||42.11|
|Natural gas realized ($/Mcf)||2.51||2.57||2.37|
|Natural gas liquids ($/Bbl)||21.87||17.83||13.76|
|Average price realized ($/BOE)||38.25||38.18||34.39|
|Oil, hedged ($/Bbl)(3)||46.90||46.32||41.98|
|Natural gas, hedged ($ per MMbtu)(3)||2.64||3.52||2.37|
|Average price, hedged ($/BOE)(3)||39.28||38.85||34.30|
|Average Costs per BOE:|
|Lease operating expense||$||4.15||$||4.14||$||5.37|
|Production and ad valorem taxes||2.35||2.27||2.21|
|Gathering and transportation expense||0.44||0.43||0.69|
|General and administrative – cash component||0.73||0.82||0.88|
|Total operating expense – cash||$||7.67||$||7.66||$||9.15|
|General and administrative – non-cash component||$||0.79||$||0.88||$||1.52|
|Depreciation, depletion and amortization||11.20||10.73||10.83|
|(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 (loss) plus non-cash (gain) loss on derivative instruments, net, interest expense, depreciation, depletion and amortization, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense and income tax provision. Adjusted EBITDA is not a measure of net income (loss) 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 (loss) 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 (loss) 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 (loss) attributable to Diamondback Energy, Inc. plus non-cash (gain) loss on derivative instruments, net, (gain) loss on the sale of assets, net, other income, impairment of oil and gas properties 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)
June 30, 2017
|Net income (loss)||$||81,948||$||164,128||$||(600||)|
|Non-cash (gain) loss on derivative instruments, net||58,645||(28,635||)||(2,425||)|
|Depreciation, depletion and amortization||87,579||75,173||44,746|
|Impairment of oil and natural gas properties||—||—||46,368|
|Non-cash equity-based compensation expense||8,354||8,069||7,181|
|Capitalized equity-based compensation expense||(2,167||)||(1,901||)||(916||)|
|Asset retirement obligation accretion expense||357||350||270|
|Income tax provision||857||1,579||—|
|Consolidated Adjusted EBITDA||$||244,765||$||227,008||$||104,858|
|EBITDA attributable to noncontrolling interest||(12,306||)||(8,574||)||(2,614||)|
|Adjusted EBITDA attributable to Diamondback Energy, Inc.||$||232,459||$||218,434||$||102,244|
Adjusted net income is a performance measure used by management to evaluate performance, prior to non-cash (gain) loss on derivative instruments, net, (gain) on sale of assets, net, other income, impairment of oil and gas properties and related income tax adjustments.
The following table presents a reconciliation of adjusted net income to net income:
|Diamondback Energy, Inc.
Adjusted Net Income
(unaudited, in thousands, except share amounts and per share data)
June 30, 2017
|Net income (loss) attributable to Diamondback Energy, Inc.||$||73,024||$||158,405||$||(2,230||)|
|Non-cash (gain) loss on derivative instruments, net||58,645||(28,635||)||(2,425||)|
|(Gain) on sale of assets, net||—||(55||)||(9||)|
|Impairment of oil and gas properties*||—||—||46,368|
|Income tax adjustment for above items**||(604||)||344||—|
|Adjusted net income (loss) attributable to Diamondback Energy, Inc.||$||131,065||$||122,559||$||41,704|
|Adjusted net income per common share:|
|Weighted average common shares outstanding:|
|*Impairment has been adjusted for Viper’s noncontrolling interest.|
|**The tax impact is computed utilizing the Company’s effective federal and state income tax rates. The income tax rate for the three months ended September 30, 2017 was approximately 1.03%.|
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 (Bbs/day), $/Bbl)|
|Swaps – West Texas Intermediate||14,000||27,000||28,000||24,000||23,000||3,000||3,000||3,000||3,000|
|Swaps – Crude Brent Oil||—||2,000||6,000||6,000||6,000||—||—||—||—|
|Costless Collars Floor||18,000||6,000||—||—||—||—||—||—||—|
|Costless Collars Ceiling||9,000||3,000||—||—||—||—||—||—||—|
|Natural Gas (Mmbtu/day, $/Mmbtu)|
|Q4 2017||Q1 2018||Q2 2018||Q3 2018||Q4 2018|