RSP Permian, Inc. Announces Fourth Quarter and Year-End 2015 Financial and Operating Results, Year-End 2015 Proved Reserves and 2016 Capital Plan and Guidance

Feb 24, 2016, 17:30 ET from RSP Permian, Inc.

DALLAS, Feb. 24, 2016 /PRNewswire/ -- RSP Permian, Inc. ("RSP" or the "Company") (NYSE: RSPP) today reported financial and operating results for the quarter and year ended December 31, 2015, year-end 2015 proved reserves and 2016 capital plan and guidance.  In addition, the Company will file its Annual Report on Form 10-K for the year ended December 31, 2015 with the Securities and Exchange Commission (the "SEC") and posted an updated presentation on its website at www.rsppermian.com.

Highlights

  • 4Q15 production increased by 50% to 24.3 MBoe/d (75% oil) as compared to 4Q14 and increased 1% as compared to 3Q15. Full-year 2015 production increased by 77% to 21.0 MBoe/d (75% oil) as compared to 2014 pro forma amounts.
    • Production in 4Q15 was negatively impacted 1.4 MBoe/d, due to a fire at the Company's Cross Bar Ranch production facility in November and by a winter storm in December. The facility was repaired and production fully restored in early 1Q16.
  • 4Q15 adjusted EBITDAX increased by 12% to $74.4 million as compared to 4Q14 and decreased 5% as compared to 3Q15.
  • 4Q15 net loss was $20.8 million, or ($0.21) per share compared to pro forma net income of $57.7 million, or $0.74 per diluted share in 4Q14. Pro forma information eliminates certain non-recurring expenses and tax adjustments associated with our initial public offering. 4Q15 net loss includes a $30.0 million impairment of oil and gas properties. Adjusted net income for 4Q15, which does not include that item, was $12.1 million, or $0.12 per diluted share, compared to $12.6 million or $0.16 per diluted share in 4Q14.
  • 4Q15 cash operating expenses decreased by 33% to $9.98 per Boe as compared to 4Q14 and decreased 5% per Boe as compared to 3Q15. 4Q15 lease operating expenses of $4.76 per Boe (before gathering and transportation) and $5.18 per Boe including gathering and transportation.
  • Completed first four horizontal wells of a total of six drilled in western Glasscock County with early production results exceeding any RSP wells to date.
    • First two wells drilled to an average lateral length of approximately 9,900' and targeted the Wolfcamp A and Upper Wolfcamp B zones, produced average IP-30s of 1,817 Boe/d (83% oil) and average cumulative production after 60 days of approximately 93 MBoe per well.
    • Second two wells were shorter laterals, drilled to an average lateral length of approximately 4,950', and are still flowing naturally and achieved average IP-30s of 987 Boe/d (83% oil).
    • Two additional horizontal wells, with average lateral lengths of 9,484', targeting the Lower Spraberry and Lower Wolfcamp B zones were recently completed and in early flowback.
  • 4Q15 total capex, excluding acquisitions, of $64.1 million and full-year 2015 capex, excluding acquisitions, of $391.0 million.
  • Total proved reserves at year end 2015 increased 50% to 159.2 MMBoe (70% oil, 16% natural gas liquids, 14% natural gas) as compared to 2014, replacing 1,042% of 2015 production, 855% organically, with a drilling finding and development ("F&D") cost of $5.77 per Boe.
  • Maintained a strong year-end liquidity position with $142.7 million of cash and an undrawn $600 million revolver.
  • Rating agencies concluded review of RSP in 1Q16, S&P upgraded RSP's senior notes to B+ and affirmed B+ corporate family rating, Moody's affirmed RSP's B3 senior notes rating and B2 corporate family rating.

Recent Acquisitions

  • As previously announced, RSP closed the acquisition of oil and natural gas assets from Wolfberry Partners LLC ("WPR") for approximately $137.0 million in 4Q15.
    • Prior to closing the WPR acquisition, RSP completed an offering of 8.7 million shares of common stock, resulting in approximately $218.1 million of net proceeds.
  • RSP has recently acquired $29.4 million of additional interests in WPR properties and other properties the Company acquired during 2015. All acquired interests are in top-tier horizontal acreage located in the core of our operating areas in Midland, Martin and Glasscock counties.
    • These recent acquisitions added approximately 1,250 net acres, 115 Boe/d of production and 36 net horizontal locations.
    • Approximately $0.8 million was funded and closed prior to year-end and the remaining $28.6 million has closed in 1Q16.

Steve Gray, Chief Executive Officer, stated, "We increased our production rate slightly in the fourth quarter after growing it over 20% in the third quarter, even though we lost 1.4 MBoe per day of production as a result of a fire at Cross Bar Ranch and winter storms affecting our operations.  Despite these interruptions, we achieved our increased production guidance for the year and with our reduced completion pace, we were cash flow neutral in the fourth quarter.  I am also pleased to announce that our initial horizontal wells in western Glasscock County are record wells for RSP, generating the highest production rates out of our entire horizontal portfolio and highlighting the resource potential of this new core operating area of RSP.  We continue to test new spacing patterns and completion designs so that we can achieve higher recoveries, cost reductions and further expand our horizontal inventory."

Mr. Gray continued, "Although our capital efficiency and cost structure are among the best in the U.S. E&P industry and enable us to generate positive returns at current prices, we have reduced our activity level while prices are depressed and recently dropped to two horizontal rigs.  We have budgeted to spend 40% less than we did last year in our drilling program and will fund this amount primarily with operating cash flow and our cash position.  If current oil prices continue into next year, we intend to keep our two horizontal rig program and spend less in 2017 while maintaining our production rates and all of our core leasehold positions.  We will accelerate activity when pricing improves, but we are well positioned for the current environment with our premier asset base, efficient cost structure and a management team that has navigated market cycles before."

2016 Capital Plan and Guidance

RSP began 2016 with three operated horizontal rigs and recently released one of these rigs.  The Company has two operated horizontal rigs under contract for the remainder of 2016 with one contract expiring in January 2017 and the other contract expiring in April 2017.  As a result of a reduced completion pace in the fourth quarter of 2015, the Company built an inventory of 18 drilled and uncompleted horizontal wells at year end and 2 drilled and uncompleted vertical wells.  The Company intends to complete this inventory along with wells drilled during the year to complete between 36 to 48 gross operated horizontal wells and approximately 5 vertical wells.  RSP's capital budget in 2016 is $200 million to $260 million, down 41% compared to the $391 million invested in 2015 (excluding acquisitions), with $185 million to $235 million allocated to drilling and completion activities and $15 million to $25 million allocated to infrastructure and other.  The Company expects non-operated capital expenditures in 2016 to represent approximately 10% of total capital expenditures.

 

2015

2016

2015 Actuals and 2016 Guidance

Actual

 Guidance

Operated Horizontal Completions

45

36 - 48

Operated Vertical Completions

19

5

Total Capital Expenditures (excluding acquisitions) ($ in MM)

$391

$200 - $260

Average Daily Production (Boe/d)

21,047

23,000 - 27,000

% Oil

75%

75% - 76%

% Natural Gas

11%

10% - 11%

% NGLs

14%

13% - 14%

Operating Costs

Lease operating expenses (including workovers) ($/Boe)

$6.46

$5.00 - $6.00

Gathering and transportation ($/Boe)

$0.46

$0.45 - $0.50

Exploration expenses ($/Boe)

$0.31

$0.25 - $0.30

General and administrative - cash component ($/Boe)

$2.33

$2.00 - $2.50

General and administrative - stock comp ($/Boe)

$1.03

$1.25 - $1.50

Depreciation, depletion, and amortization ($/Boe)

$20.05

$18.00 - $20.00

Production and ad valorem taxes (% of oil and gas revenues)

7.0%

7.0% - 8.0%

 

Summary Financial Results

Three Months Ended

December 31,

Twelve Months Ended

December 31,

Actual

Pro Forma

Actual

Pro Forma

2015

2014

2014

2015

2014

(In thousands, except for per share data)

Total Revenues

73,508

79,458

79,458

283,992

281,925

286,909

  Net Cash from Derivative Instruments

23,122

9,379

9,379

92,118

5,943

5,943

  Adjusted Total Revenues

96,630

88,837

88,837

376,110

287,868

292,852

Adjusted EBITDAX (1)

$

74,367

$

66,579

$

66,579

$

285,058

$

215,281

$

222,552

Adjusted Net Income (1)

12,074

12,621

15,683

48,630

54,329

70,600

  Adjusted Net Income per Common Share - Diluted

0.12

0.16

0.20

0.56

0.75

0.94

Net Income (loss)

$

(20,751)

$

89,503

$

57,738

$

(18,254)

$

2,498

$

116,121

  Net Income (loss) per Common Share - Diluted

$

(0.21)

$

1.15

$

0.74

$

(0.21)

$

0.03

$

1.55

(1)

Adjusted EBITDAX and adjusted net income are non-GAAP financial measures. For a definition of Adjusted EBITDAX and adjusted net income and a reconciliation of Adjusted EBITDAX and adjusted net income to net income, see "Use of Non-GAAP financial measures" and our annual and quarterly statements of operations at the end of this release.

 

For the quarter ended December 31, 2015, total revenues, excluding the revenue impact from realized derivative instruments, were $73.5 million, a 7% decrease over the prior year quarter of $79.5 million.  Adjusted total revenues, including the net cash from derivative instruments, were $96.6 million, an increase of 9% over the prior year quarter of $88.8 million.  Adjusted EBITDAX for the quarter ended was $74.4 million, an increase of 12% over the prior year of $66.6 million.  Adjusted net income for the quarter ended was $12.1 million, or $0.12 per diluted share, compared with adjusted net income for the prior year of $12.6 million or $0.16 per diluted share.  Net loss for the fourth quarter of 2015 was $20.8 million, or ($0.21) per diluted share, while net income for the fourth quarter of 2014 was $89.5 million, or $1.15 per diluted share.  Pro forma net income for the fourth quarter of 2014 was $57.7 million, or $0.74 per diluted share.

For the year ended December 31, 2015, total revenues, excluding the revenue impact from realized derivative instruments, were $284.0 million, a 1% increase over the prior year of $281.9 million.  Adjusted total revenues, including the net cash from derivative instruments, was $376.1 million, an increase of 31% over the prior year ended 2014 of $287.9 million.  Adjusted EBITDAX for the year ended 2015 was $285.1 million, an increase of 32% over the prior year ended 2014 of $215.3 million.  Adjusted net income for the year ended 2015 was $48.6 million, or $0.56 per diluted share, a 10% decrease from the prior year ended 2014 of $54.3 million or $0.75 per diluted share.  Net loss for the year ended 2015 was $18.3 million, or ($0.21) per diluted share, while net income for the year ended 2014 was $2.5 million, or $0.03 per diluted share.  Pro forma net income for the year ended 2015 was $116.1 million, or $1.55 per diluted share.

Operational Update

The Company operated 3 horizontal drilling rigs during the fourth quarter and drilled 10 operated horizontal wells.  RSP completed 8 operated horizontal wells (1 Lower Spraberry, 4 Wolfcamp A and 3 Wolfcamp B).  The Company exited the year with 20 drilled and uncompleted wells, 18 uncompleted horizontal wells and 2 uncompleted vertical wells.  During 2015, RSP completed 45 operated horizontal wells (2 Middle Spraberry, 15 Lower Spraberry, 14 Wolfcamp A and 14 Wolfcamp B) and 19 operated vertical wells in 2015.

 

4Q15 Wells

Drilled

Completed

Waiting On Completion

4Q15 Wells

Operated Wells

Horizontal

10

8

18

Vertical

1

2

Non-Operated Wells

Horizontal

15

8

13

Vertical

Full-Year 2015 Wells

Operated Wells

Horizontal

53

45

Vertical

12

19

Non-Operated Wells

Horizontal

49

46

Vertical

4

5

 

Quarterly Operational Results

Three Months Ended December 31,

2015

2014

Production data:

Oil (MBbls)

1,683

1,080

Natural gas (MMcf)

1,554

939

NGLs (MBbls)

289

248

Total (MBoe)

2,231

1,485

Average net daily production (Boe/d)

24,250

16,141

Average prices before effects of hedges (1) (2):

Oil (per Bbl)

$40.00

$66.34

Natural gas (per Mcf)

1.91

3.14

NGLs (per Bbl)

11.13

19.60

Total (per Boe)

$32.95

$53.51

Average realized prices after effects of hedges (1) (2):

Oil (per Bbl)

$53.74

$74.97

Natural gas (per Mcf)

1.91

3.20

NGLs (per Bbl)

11.13

19.60

Total (per Boe)

$43.31

$59.82

Average costs (per Boe):

Lease operating expenses (excluding gathering and transportation)

$4.76

$7.01

Gathering and transportation

0.42

0.54

Production and ad valorem taxes

2.56

3.22

Depreciation, depletion and amortization

17.88

20.71

General and administrative - recurring cash component

2.24

4.21

General and administrative - recurring stock comp (3)

0.93

0.58

General and administrative - IPO stock comp (4)

0.15

2.54

(1)

Average prices shown in the table reflect prices both before and after the effects of our cash payments/receipts on our commodity derivative transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period, if applicable.

(2)

Average prices for oil are net of transportation costs. Average prices for natural gas do not include transportation costs; instead, transportation costs related to our gas production and sales are included in gathering and transportation which is included in lease operating expenses in our consolidated statements of operations. No transportation costs are associated with NGL production and sales.

(3)

Represents compensation expense related to restricted stock awards and performance share awards granted as part of the Company's ongoing compensation and retention programs.

(4)

Includes compensation expense related to the successful completion of the Company's initial public offering ("IPO").  These costs include cash bonuses, one-time restricted stock awards, and expense related to performance units.

 

Production volumes for the quarter ended December 31, 2015 averaged 24,250 Boe/d or a total of 2,231 MBoe, an increase of 50% over prior year's fourth quarter of 16,141 Boe/d.  Production for the fourth quarter of 2015 was comprised of 75% crude oil, 13% NGLs and 12% natural gas.  RSP's average realized commodity price per barrel of oil equivalents for the fourth quarter of 2015, before the effects of hedges, was $32.95. RSP's average realized oil price for the fourth quarter of 2015, before the effects of hedges, was $40.00 per barrel, a negative $2.18 differential compared to NYMEX WTI pricing for the same period, or 95% of NYMEX WTI pricing. RSP's average realized natural gas price for the fourth quarter of 2015, before the effects of hedges, was $1.91 per MMBtu, a negative $0.36 differential compared to NYMEX Henry Hub pricing for the same period, or 84% of NYMEX Henry Hub pricing.  Per unit cash operating expenses excluding interest expense but including lease operating expense, gathering and transportation, production and ad valorem taxes and recurring cash general and administrative expenses were $9.98 per Boe, a 33% decrease from prior year's comparable quarter and a 5% decrease from the prior quarter.

 

Year-End Operational Results

Twelve Months Ended December 31,

2015

2014

Production data:

Oil (MBbls)

5,805

3,049

Natural gas (MMcf)

4,991

2,974

NGLs (MBbls)

1,045

718

Total (MBoe)

7,682

4,263

Average net daily production (Boe/d)

21,047

11,679

Average prices before effects of hedges (1) (2):

Oil (per Bbl)

$45.36

$83.10

Natural gas (per Mcf)

2.11

3.55

NGLs (per Bbl)

9.75

25.04

Total (per Boe)

$36.97

$66.13

Average realized prices after effects of hedges (1) (2):

Oil (per Bbl)

$61.22

$85.01

Natural gas (per Mcf)

2.11

3.59

NGLs (per Bbl)

9.75

25.04

Total (per Boe)

$48.96

$67.53

Average costs (per Boe):

Lease operating expenses (excluding gathering and transportation)

$6.46

$7.49

Gathering and transportation

0.46

0.65

Production and ad valorem taxes

2.60

4.63

Depreciation, depletion and amortization

20.05

20.61

General and administrative - recurring cash component

2.33

4.25

General and administrative - recurring stock comp (3)

1.03

0.64

General and administrative - IPO stock comp (4)

0.19

4.11

(1)

Average prices shown in the table reflect prices both before and after the effects of our cash payments/receipts on our commodity derivative transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period, if applicable.

(2)

Average prices for oil are net of transportation costs. Average prices for natural gas do not include transportation costs; instead, transportation costs related to our gas production and sales are included in gathering and transportation which is included in lease operating expenses in our consolidated statements of operations. No transportation costs are associated with NGL production and sales.

(3)

Represents compensation expense related to restricted stock awards and performance share awards granted as part of the Company's ongoing compensation and retention programs.

(4)

Includes compensation expense related to the successful completion of the Company's IPO.  These costs include cash bonuses, one-time restricted stock awards, and expense related to performance units.

 

Production volumes for the year ended December 31, 2015 averaged 21,047 Boe/d or a total of 7,682 MBoe, an increase of 80% over prior year's volume of 11,679 Boe/d.  Production for 2015 was comprised of 75% crude oil, 14% NGLs and 11% natural gas.  RSP's average realized commodity price per barrel of oil equivalents for 2015, before the effects of hedges, was $36.97. RSP's average realized oil price for 2015, before the effects of hedges, was $45.36 per barrel, a negative $3.44 differential compared to NYMEX WTI pricing for the same period, or 93% of NYMEX WTI pricing. RSP's average realized natural gas price for 2015, before the effects of hedges, was $2.11 per MMBtu, a negative $0.56 differential compared to NYMEX Henry Hub pricing for the same period, or 79% of NYMEX Henry Hub pricing.  Per unit cash operating expenses excluding interest expense but including lease operating expense, gathering and transportation, production and ad valorem taxes and recurring cash general and administrative expenses were $11.85 per Boe, a 30% decrease from prior year.

Proved Reserves Summary

RSP's total proved reserves at December 31, 2015, audited by Netherland, Sewell, & Associates, Inc., our independent petroleum engineers, increased 50% over the prior year to 159.2 MMBoe.  Oil reserves increased 60% compared to prior year and totaled 111.1 MMBbls and combined with NGLs of 25.8 MMBbls equaled 86% of total proved reserves with natural gas of 133.5 MMcf making up the remaining 14% of total proved reserves.  Proved developed reserves increased 54% compared to last year and were 64.6 MMBoe or 41% of total proved reserves.

The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2015 and our net proved oil and natural gas reserves as of December 31, 2014 and in each case, prepared in accordance with the rules and regulations of the SEC.

 

Natural

Gas

(MMcf)

Oil

(MBbls)

NGLs

(MBbls)

MBoe

Proved developed and undeveloped reserves:

As of December 31, 2014

92,422

69,273

21,739

106,416

Revisions of previous estimates

(20,205)

(12,886)

(4,251)

(20,505)

Extensions, discoveries and other additions

55,313

50,375

6,971

66,565

Purchases of minerals in place

10,968

10,178

2,373

14,379

Production

(4,991)

(5,805)

(1,045)

(7,682)

As of December 31, 2015

133,507

111,135

25,787

159,173

 

RSP's acquisitions and drilling program added 66.6 MMBoe in 2015, replacing 1,042% of 2015 production as calculated by the sum of reserve extensions, discoveries, purchases and revisions (excluding price revisions), divided by annual production.  The Company's drill-bit F&D costs were $5.77 per BOE calculated as costs incurred for exploration and development divided by the sum of revisions of previous estimates (excluding price revisions), extensions, discoveries and other additions.  See "Drill-Bit F&D and Reserve Replacement Ratio" below for the calculations of the reserve replacement ratio and drill-bit F&D costs.

Capital Expenditures

RSP's capital expenditures for the year ended December 31, 2015 totaled $391.0 million which included approximately $354.0 million of drilling and completion and $37.0 million of infrastructure and other.  Of the total capital spent, approximately $66.1 million was on non-operated properties and approximately $48.8 million was on drilling wells the Company expects to complete in 2016.

Liquidity Update

As of December 31, 2015, the Company had no borrowings on its revolving credit facility, which has a $600 million borrowing base, and had $142.7 million of cash on hand, for total liquidity available of $742.7 million. Since the end of the third quarter 2015 RSP has acquired $29.4 million of additional interests in the WPR properties and other properties the Company acquired during 2015. Pro forma for these additional acquisitions RSP had $114.1 million of cash at year-end and approximately $714.1 million of total liquidity available.

Hedging

For 2016, the Company has three way collars covering 555,000 barrels of oil production at a blended floor price of $55.00, a blended ceiling price of $74.08, and a short-put price of $45.00.

 

Description & Production Period

Volume (Bbls)

Weighted Average

Floor price ($/Bbl) (1)

Weighted Average

Ceiling price ($/Bbl) (1)

Weighted Average

Short-Put price ($/Bbl) (1)

Crude Oil Collars:

January 2016 - March 2016

75,000

$55.00

$72.00

$45.00

January 2016 - December 2016

480,000

$55.00

$74.41

$45.00

(1)

The crude oil derivative contracts are settled based on the month's average daily NYMEX price of West Texas Intermediate Light Sweet Crude.

 

Fourth Quarter and Year-End 2015 Earnings Release and Conference Call

RSP will host a conference call for investors at 12:00 p.m. Central Time on Thursday, February 25, 2016 to discuss fourth quarter 2015 results.  Hosting the call will be Steve Gray, Chief Executive Officer, Zane Arrott, Chief Operating Officer and Scott McNeill, Chief Financial Officer.

The call may be accessed live over the telephone by dialing (877) 705-6003, or for international callers, (201) 493-6725.  A replay will be available shortly after the call and can be accessed by dialing (877) 870-5176, or for international callers (858) 384-5517. The passcode for the replay is 13629161.  The replay will be available until March 10, 2016. Interested parties may also listen to a simultaneous webcast of the conference call by logging onto RSP's website at www.rsppermian.com in the Investor Relations section. A replay of the webcast will also be available following the call.

About RSP Permian, Inc.

RSP is an independent oil and natural gas company focused on the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of our acreage is located on large, contiguous acreage blocks in the core of the Midland Basin, a sub-basin of the Permian Basin, primarily in the adjacent counties of Midland, Martin, Andrews, Glasscock, Dawson and Ector.  The Company's common stock is traded on the NYSE under the ticker symbol "RSPP."  For more information, visit www.rsppermian.com.

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 RSP assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. 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 RSP. Information concerning these risks and other factors can be found in RSP's filings with the SEC, including its Form 10-K, which can be obtained free of charge on the SEC's web site located at http://www.sec.gov. RSP undertakes no obligation to update or revise any forward-looking statement.

Use of Non-GAAP Financial Measures

We define Adjusted EBITDAX as oil and gas revenues including net cash receipts (payments) on settled derivative instruments and premiums paid on put options that settled during the period, less lease operating expenses, production and ad valorem taxes, and general and administrative expenses excluding stock based compensation.  Adjusted net income deducts from Adjusted EBITDAX depreciation, depletion, and amortization, accretion on asset retirement obligations, exploration expenses, interest expense, stock-based compensation and adjusted income tax expense.

Management believes Adjusted EBITDAX and adjusted net income are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above in arriving at Adjusted EBITDAX and adjusted net income because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX and adjusted net income 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 our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX and adjusted net income 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 EBITDAX. Our computations of Adjusted EBITDAX and adjusted net income may not be comparable to other similarly titled measures of other companies.

The following statements of operations include a reconciliation of the non-GAAP financial measures of Adjusted EBITDAX and Adjusted Net Income to the GAAP financial measure of net income.

 

Three Months Ended December 31,

Twelve Months Ended December 31,

2015

Actual

2014

 Actual

2014

Pro Forma

2015

 Actual

2014

 Actual

2014

Pro Forma

Revenues:

  Oil sales

$

67,318

$

71,646

$

71,646

$

263,286

$

253,371

$

257,830

  Natural gas sales

2,973

2,951

2,951

10,517

10,572

10,762

  NGL sales

3,217

4,861

4,861

10,189

17,982

18,317

           Total revenues

73,508

79,458

79,458

283,992

281,925

286,909

Net cash from derivative instruments

23,122

9,379

9,379

92,118

5,943

5,943

Adjusted Total Revenues

$

96,630

$

88,837

$

88,837

$

376,110

$

287,868

$

292,852

Operating expenses:

  Lease operating expenses

11,546

11,222

11,222

53,124

34,704

35,398

  Production and ad valorem taxes

5,722

4,781

4,781

19,995

19,758

20,009

  General and administrative expenses

4,995

6,255

6,255

17,933

18,125

14,893

           Total operating costs and expenses

$

22,263

$

22,258

$

22,258

$

91,052

$

72,587

$

70,300

Adjusted EBITDAX (2)

$

74,367

$

66,579

$

66,579

$

285,058

$

215,281

$

222,552

  Depreciation, depletion, and amortization

39,887

30,758

30,758

154,039

87,844

91,477

  Asset retirement obligation accretion

84

38

38

336

142

151

  Exploration

96

899

899

2,380

3,854

3,854

  Interest expense

13,175

9,517

9,517

43,538

14,031

14,031

  Stock-based compensation, net

2,409

4,634

862

9,384

20,232

2,726

Adjusted income before income taxes

$

18,716

$

20,733

$

24,505

$

75,381

$

89,178

$

110,313

Adjusted income tax expense

6,642

8,112

8,822

26,751

34,849

39,713

Adjusted net income (2)

$

12,074

$

12,621

$

15,683

$

48,630

$

54,329

$

70,600

  Adjusted net income per common share - Basic

$

0.12

$

0.16

$

0.20

$

0.56

$

0.75

$

0.94

  Adjusted net income per common share - Diluted

$

0.12

$

0.16

$

0.20

$

0.56

$

0.75

$

0.94

Other items included in income before taxes:

  Non-cash (loss) on derivatives, net

$

(19,683)

$

70,143

$

70,143

$

(71,212)

$

75,527

$

75,527

  Impairments

(30,031)

(4,344)

(4,344)

(34,269)

(4,344)

(4,344)

  Gain (loss) on asset sale

(302)

(15)

(15)

(306)

(13)

(13)

  Other income

242

(74)

(74)

469

(44)

(44)

Income (loss) before income taxes

$

(37,700)

$

78,331

$

81,393

$

(56,688)

$

125,455

$

141,726

Income tax (benefit) expense

$

(16,949)

$

(11,172)

$

23,655

$

(38,434)

$

122,957

$

25,605

Net Income (loss)

$

(20,751)

$

89,503

$

57,738

$

(18,254)

$

2,498

$

116,121

  Net income (loss) per common share - Basic

$

(0.21)

$

1.15

$

0.74

$

(0.21)

$

0.03

$

1.55

  Net income (loss) per common share - Diluted

$

(0.21)

$

1.15

$

0.74

$

(0.21)

$

0.03

$

1.55

Weighted Average Common Shares Outstanding:

Basic

98,556

77,292

77,292

86,770

71,898

74,297

Diluted

98,556

77,292

77,292

86,770

71,898

74,297

(1)

Information presented in this table reflects actual results of RSP and its predecessor.  The IPO and related transactions affect the comparability of each period presented in the table above.  2014 information represents information with respect to RSP's predecessor for the first 22 days of 2014 plus that of RSP for the remainder of the year.

(2)

Adjusted EBITDAX and adjusted net income are non-GAAP financial measures. For a definition of Adjusted EBITDAX and adjusted net income, see "Use of Non-GAAP Financial Measures" above.

 

Summary Balance Sheet

December 31, 2015

December 31, 2014

(in thousands)

Cash and cash equivalents

$

142,741

$

56,292

Other current assets

44,799

117,450

Total current assets

187,540

173,742

Property, plant and equipment, net

2,758,630

2,094,618

Other long-term assets

33,401

21,587

Total assets

$

2,979,571

$

2,289,947

Current liabilities

77,402

104,252

Long-term debt

698,650

500,000

Other long-term liabilities

344,935

359,924

Total stockholders'/members' equity

1,858,584

1,325,771

Total liabilities and stockholders'/members' equity

$

2,979,571

$

2,289,947

 

Drill-Bit F&D and Reserve Replacement Ratio

2015

Production (MBoe)

(A)

7,682

Proved Reserves (MBoe)

Non-price revisions (1)

(B)

(863)

Purchases

14,379

Extensions and discoveries

(C)

66,565

Total additions

(D)

80,081

Costs Incurred (thousands)

Property acquisition costs

Proved

104,532

Unproved

351,806

Exploration

(E)

Development

(F)

378,910

Total costs incurred

(G)

$

835,248

Drill-bit F&D ($/Boe)

(E+F) / (B+C)

5.77

All sources F&D ($/Boe)

(G) / (D)

10.43

Reserve replacement ratio

(D) / (A)

1,042

%

(1)

Total revisions for 2014 were 1,529 MBoe, including 5,582 MBoe non-price related revisions and negative revisions of 4,053 MBoe related to price.

 

Logo - http://photos.prnewswire.com/prnh/20160202/328754LOGO

 

SOURCE RSP Permian, Inc.



RELATED LINKS

http://www.rsppermian.com