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Diamondback Energy, Inc. Announces Fourth Quarter and Full Year 2018 Financial and Operating Results

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MIDLAND, Texas, Feb. 19, 2019 (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, 2018.

2018 HIGHLIGHTS

  • Full year 2018 net income of $846 million, or $8.06 per diluted share; adjusted net income (as defined and reconciled below) of $615 million, or $5.87 per diluted share
  • 2018 production of 121.4 Mboe/d (73% oil) excluding the effect of the Energen acquisition, up 53% year over year and above the high-end of 2018 guidance range
  • Closed the acquisition of Energen Corporation (NYSE:EGN) ("Energen") as well as multiple transactions in Spanish Trail North during Q4 2018, growing assets by 123% year over year to a total of approximately 461,000 net acres in the Permian (195,000 net acres in the Midland Basin, 170,000 net acres in the Delaware Basin and 96,000 net acres in other areas of the Permian)
  • Proved reserves as of December 31, 2018 of 992.0 MMboe (65% PDP, 63% oil), up 196% year over year; 2018 consolidated proved developed finding and development ("PD F&D") costs of $10.44/boe; drill bit finding and development costs of $7.28/boe

Q4 2018 HIGHLIGHTS

  • Q4 2018 net income of $307 million, or $2.50 per diluted share; adjusted net income (as defined and reconciled below) of $148 million, or $1.21 per diluted share
  • Q4 2018 Consolidated Adjusted EBITDA (as defined and reconciled below) of $468 million
  • Q4 2018 production of 182.8 Mboe/d (71% oil), up 49% over Q3 2018 and 97% year over year
  • Declared Q4 2018 cash dividend of $0.125 per share payable on February 28, 2019; implies a 0.5% annualized yield based on the February 15, 2019 share closing price of $105.50

2019 Update

  • Full year 2019 production guidance of 275 - 290 Mboe/d (68% - 70% oil), implies over 27% year over year growth from pro forma 2018 production
  • Lowered full year 2019 capital budget for drilling, completion, midstream and infrastructure to $2.7 - $3.0 billion; expect to complete between 290 to 320 gross horizontal wells
  • Full year 2019 Midland Basin drilling, completion and equip ("D,C&E") well costs of $770 - $800 per lateral foot, midpoint flat versus full year 2018 D,C&E guidance
  • Full year 2019 Delaware Basin D,C&E well costs of $1,075 - $1,150 per lateral foot, midpoint down 7% versus full year 2018 D,C&E guidance
  • Currently operating 21 rigs and plan to operate between 18 and 22 drilling rigs throughout 2019
  • Rattler Midstream exercised its option and acquired a 10% equity interest in EPIC Crude Oil Pipeline project ("EPIC"); closed on its acquisition of a 10% equity interest in the Gray Oak Pipeline project ("Gray Oak")
  • As previously announced, increasing annual cash dividend by 50% to $0.75 per common share to be payable quarterly beginning with Q1 2019 subject to Board approval

"2018 was another transformational year for Diamondback Energy.  We successfully closed three acquisitions in the fourth quarter, including our acquisition of Energen, which, combined, almost doubled our core acreage position.  During the fourth quarter, Diamondback outspent cash flow due to the dramatic decline in commodity prices and one time merger related expenses.  However, outspending cash flow is against our operating philosophy, and therefore we addressed the issue as quickly as possible by announcing a reduction in activity levels in late 2018 and acting on that plan immediately in 2019.  As investor sentiment shifts from growth to capital discipline and free cash flow generation, Diamondback is positioned to offer an unmatched combination of both due to our asset quality and peer leading capital and operating costs.  In 2019, we expect to grow production by over 27% year over year within cash flow while paying a 50% larger dividend and setting ourself up for significant free cash flow generation in 2020 and beyond at today's strip prices while still continuing to grow production at industry leading rates," stated Travis Stice, Chief Executive Officer of Diamondback.

Mr. Stice continued, "As we look ahead, we could not be more excited about the opportunities we have ahead of us.  Our 2019 capital plan and cost per completed lateral foot guidance for the Midland Basin is reflective of the synergies we presented when we first announced the Energen acquisition last August, with the midpoint of our  D,C&E well cost guidance of $785 per completed lateral foot being nearly equivalent to Diamondback's standalone second quarter 2018 well costs.  Our estimates for our Delaware Basin costs per completed lateral foot are significantly better than presented in our August announcement, and we expect overall well costs in the Delaware Basin to decline year over year.  Further, our general and administrative cost guidance also reflects the projected synergies presented with our merger announcement as we expect to maintain cash G&A costs of less than $1.00 per boe in 2019.  In addition to the cost synergies presented, we are actively executing on our grow and prune strategy as we consolidate our acreage position, increase our average lateral length and work to divest assets deemed non-core to our current development plan.  We look forward to crystallizing the midstream and mineral synergies presented, with a priority to drop down the remaining mineral and royalty assets held at Diamondback to Viper."

OPERATIONS UPDATE

Diamondback's Q4 2018 production was 182.8 Mboe/d (71% oil), up 97% year over year from 92.9 Mboe/d in Q4 2017, and up 49% quarter over quarter from 123.0 Mboe/d in Q3 2018.  Average daily production for the full year 2018 was 130.4 Mboe/d (72% oil), up 65% from 79.2 Mboe/d in 2017.

Excluding the effect of production acquired in the Energen acquisition, Diamondback's full year 2018 production was 121.4 Mboe/d (73% oil), up 53% over 2017 and above the high-end of its guidance range of 118.5 Mboe/d to 119.5 Mboe/d for the full year 2018.

During the fourth quarter of 2018, Diamondback drilled 55 gross horizontal wells and turned 48 operated horizontal wells to production.  The average lateral length for the wells completed during the fourth quarter wells was 9,306 feet.  Operated completions during the fourth quarter consisted of 31 Wolfcamp A wells, eight Lower Spraberry well, five Wolfcamp B wells, one Second Bone Spring well, one Third Bone Spring well, one Jo Mill well and one Middle Spraberry well.

For the full year 2018, Diamondback drilled 189 gross horizontal wells and turned 176 operated horizontal  wells to production.  The Company is currently operating 21 rigs and eight frac spreads and plans to operate between 18 and 22 horizontal rigs throughout 2019.  As a result, Diamondback expects to turn between 290 and 320 gross operated horizontal wells to production for the full year 2019 with an average lateral length of 9,400 feet.

In the Northern Delaware Basin, Diamondback took over operations from Energen at the end of November 2018.  Prior to Diamondback assuming operations, Energen completed three Wolfcamp A wells during the fourth quarter with an average lateral length of 4,546 feet.  These wells commenced with an average peak 30-day 2-stream flowing initial production ("IP") rate of 436 boe/d per 1,000 feet (71% oil) and went on to produce an average of 331 boe/d per 1,000 feet (72% oil) over 90 days.  Additionally, three Wolfcamp B wells with an average lateral length of 4,897 feet achieved an average peak 30-day IP rate of 261 boe/d per 1,000 feet (64% oil).

In Pecos County, Diamondback continues to achieve strong performance from operated completions targeting the Wolfcamp A.  In Block 48 in the central portion of its acreage position, the Company recently completed four wells with an average lateral length of 10,183 feet.  These wells commenced with a peak 30-day flowing IP rate of 173 boe/d per 1,000 feet (89% oil).  Also in Pecos County, the Blackstone State 1-12 B 1SB, which targeted the Second Bone Spring with a lateral length of 10,081 and commenced with a peak 30-day flowing IP rate of 153 boe/d per 1,000 feet (91% oil), went on to achieve a peak 90-day IP rate of 135 boe/d per 1,000 feet (91% oil).

In Central Martin County, three Lower Spraberry wells completed with an average lateral length of 7,503 feet commenced with an average 30-day IP rate of 177 boe/d per 1,000 feet (90% oil) and produced 139 boe/d per 1,000 feet (89% oil) over 90 days.  Also in the Midland Basin, Diamondback recently completed six wells in Howard County targeting the Wolfcamp A with an average lateral length of 9,316 feet.  These wells achieved 30-day peak IP rates of 207 boe/d per 1,000 feet (85% oil).

FINANCIAL HIGHLIGHTS

Diamondback's fourth quarter 2018 net income was $307 million, or $2.50 per diluted share.  Adjusted net income (a non-GAAP financial measure as defined and reconciled below) was $148 million, or $1.21 per diluted share.

Fourth quarter 2018 Adjusted EBITDA (as defined and reconciled below) was $456 million, up 51% from $302 million in Q4 2017.

Fourth quarter 2018 average realized prices were $45.51 per barrel of oil, $1.62 per Mcf of natural gas and $21.10 per barrel of natural gas liquids, resulting in a total equivalent unhedged price of $37.01/boe.  In the first quarter of 2019, Diamondback expects realized pricing to be weaker than the current Midland market, but to improve from Q2 2019 onward as fixed differential contracts roll off and convert to our commitments on EPIC and Gray Oak or move to the current Midland market price.  Based on current market differentials and estimated in-basin gathering costs, Diamondback expects to realize ~87-92% of WTI in the first half of 2019, ~90-95% of WTI in the second half 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 fourth quarter of 2018 were $8.10 per boe, including lease operating expenses ("LOE") of $4.51 per boe, cash G&A expenses of $0.67 per boe and taxes and transportation of $2.92 per boe.

As of December 31, 2018, Diamondback had $192 million in standalone cash and approximately $1.5 billion of outstanding borrowings under its revolving credit facility.  In October 2018, prior to the effective date of the Energen merger, Diamondback's borrowing base under its credit facility was increased to $2.65 billion from $2.0 billion, with the Company's aggregate elected commitment amount increased to $2.0 billion from $1.0 billion previously.

During the fourth quarter of 2018, Diamondback spent $424 million on drilling, completion and non-operated properties, and $101 million on infrastructure and midstream.  For the full year 2018, Diamondback spent $1,358 million on drilling, completion and non-operated properties, and $306 million on infrastructure and midstream.

DIVIDEND DECLARATION

As previously announced, Diamondback's Board of Directors declared a cash dividend for the fourth quarter of 12.5 cents per common share payable on February 28, 2019, to stockholders of record at the close of business on February 21, 2019.

RESERVES

Ryder Scott Company, L.P. prepared estimates of Diamondback's proved reserves as of December 31, 2018.  Reference prices of $65.56 per barrel of oil and $3.10 per MMbtu of natural gas were used in accordance with applicable rules of the Securities and Exchange Commission.  Realized prices with applicable differentials were $59.63 per barrel of oil, $1.47 per Mcf of natural gas and $24.43 per barrel of natural gas liquids.

Proved reserves at year-end 2018 of 992.0 MMboe represent a 196% increase over year-end 2017 reserves.  Proved developed reserves increased by 210% to 646.1 MMboe (65% of total proved reserves) as of December 31, 2018, reflecting the continued development of the Company's horizontal well inventory.  Proved undeveloped reserves increased to 345.9 MMboe, a 173% increase over year-end 2017, and are comprised of 416 locations, 82 which are in the Delaware Basin.  Crude oil represents 63% of Diamondback's total proved reserves.

Net proved reserve additions of 704.3 MMboe resulted in a reserve replacement ratio of 1,479% (defined as the sum of extensions, discoveries, revisions and purchases, divided by annual production).  The organic reserve replacement ratio was 457% (defined as the sum of extensions, discoveries and revisions, divided by annual production).

Net purchases of reserves totaling 486.7 MMboe of reserves were the primary contributor to the increase in reserves, followed by extensions of 202.1 MMboe, with upward revisions of 15.4 MMboe.  The Energen acquisition contributed 94% of the total purchases with Spanish Trail North purchases being the majority of the remainder.  Proved developed producing extensions accounted for 38% of the total.  PDP extensions were the result of 135 wells in which the Company has a working interest, and proved undeveloped extensions resulted from 138 new locations in which the Company has a working interest.  Net purchases of reserves of 486.7 MMboe were the result of acquisitions of 487.0 MMboe and divestitures of 0.3 MMboe.  Upward revisions of 15.4 MMboe were the result of higher product pricing, increased NGL recoveries and positive performance revisions.

  Oil (MBbls) Liquids (MBbls) Gas (MMcf) MBOE
Proved Reserves As of December 31, 2017 233,181 54,609 285,369 335,351
Extensions and discoveries 143,256 33,152 154,088 202,089
Revisions of previous estimates 3,689 11,138 3,642 15,434
Purchase of reserves in place 281,333 98,865 640,761 486,992
Divestitures (156) (8) (543) (255)
Production (34,367) (7,465) (34,668) (47,610)
Proved Reserves As of December 31, 2018 626,936 190,291 1,048,649 992,001
         

Diamondback's exploration and development costs in 2018 were $1,583 million.  PD F&D costs were $10.44/boe.  PD F&D costs are defined as exploration and development costs divided by the sum of reserves associated with transfers from proved undeveloped reserves at year-end 2017 including any associated revisions in 2018 and extensions and discoveries placed on production during 2018.  Drill bit F&D costs were $7.28/boe including the effects of all revisions including pricing revisions.  Drill bit F&D costs are defined as the exploration and development costs divided by the sum of extensions, discoveries and revisions.

  Year Ended December 31,
  2018   2017   2016
   
   
  (In thousands)
Acquisition costs:          
Proved properties $ 5,551,400     $ 452,661     $ 72,044  
Unproved properties 5,818,006     2,692,000     752,117  
Development costs 493,084     145,362     47,575  
Exploration costs 1,090,281     779,728     329,122  
Capitalized asset retirement costs 113,717     2,682     4,030  
Total $ 13,066,488     $ 4,072,433     $ 1,204,888  
                       

Separately, as of December 31, 2018, Diamondback had identified approximately 10,000 gross economic potential horizontal drilling locations at $60 per barrel of oil.  Approximately 58% of these identified locations had lateral lengths of at least 7,500 feet, with approximately 3,550 drilling locations in the Midland Basin and 2,768 drilling locations in the Delaware Basin.

FULL YEAR 2019 GUIDANCE

Below is Diamondback's guidance for the full year 2019.  The Company expects full year production to be between 275.0 and 290.0 Mboe/d with an estimated capital spend for drilling, completion, infrastructure, midstream and non-operated properties of $2.7 to $3.0 billion.  During 2019, Diamondback expects to complete between 290 and 320 gross operated horizontal wells from an 18 to 22 rig program.

  2019 Guidance  
  Diamondback Energy, Inc. Viper Energy Partners LP
     
Total Net Production – MBoe/d 275.0 – 290.0 20.00 – 23.00
Oil Production - % of Net Production 68% - 70% 67% - 71%
     
Unit costs ($/boe)    
Lease operating expenses, including workovers(a) $4.50 - $5.00  
Gathering & Transportation $0.40 - $0.70  
G&A    
Cash G&A Under $1.00 Under $1.00
Non-cash equity-based compensation $0.75 - $1.50 $0.40 - $0.65
Depletion $13.00 - $15.00 $9.00 - $10.50
Interest expense (net of interest income) $1.00 - $1.50  
     
Midstream service expense (net of revenue; $MM) $35 - $45  
Depreciation ($MM) $48 - $52  
Production and ad valorem taxes (% of revenue)(b) 7.00% 7.00%
Corporate tax rate (% of pre-tax income) 23%  
     
Gross horizontal D,C&E/Ft. - Midland Basin $770 - $800  
Gross horizontal D,C&E/Ft. - Delaware Basin $1,075 - $1,150  
Horizontal wells completed (net) 290 - 320 (255 - 280)  
Average lateral length (Ft.) 9,400  
     
Capital Budget ($ - million)    
Horizontal drilling and completion $2,300 - $2,550  
Midstream (ex. long-haul pipeline investments) $225 - $250  
Infrastructure $175 - $200  
2019 Capital Spend $2,700 - $3,000  

(a) Includes approximately $0.50/boe attributable to Central Basin Platform assets
(b) Includes production taxes of 4.6% for

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