Attached files
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| 8-K - FORM 8-K - RSP Permian, Inc. | d421152d8k.htm |
Exhibit 99.1
News Release
RSP Permian, Inc. Announces Second Quarter 2017 Financial and Operating Results
Dallas, Texas—August 7, 2017—RSP Permian, Inc. (“RSP” or the “Company”) (NYSE: RSPP) today reported financial and operating results for the quarter ended June 30, 2017. In addition, the Company filed its Quarterly Report on Form 10-Q with the Securities and Exchange Commission (the “SEC”) and posted a presentation that supplements the information in this release to its website at www.rsppermian.com.
Second Quarter 2017 and Recent Highlights
| • | Production increased 106% to 54.3 MBoe/d (72% oil, 88% liquids), compared to 2Q16 and increased 20% compared to 1Q17 |
| • | Net income of $31.1 million, or $0.20 per diluted share. Adjusted net income, which does not include certain items, was $26.0 million, or $0.17 per diluted share |
| • | Adjusted EBITDAX increased to $135.5 million, a 132% increase compared to 2Q16 and a 9% increase compared to 1Q17 |
| • | Cash operating expenses were $9.49 per Boe, 10% lower than 1Q17, including lease operating expense of $4.72 per Boe (before gathering and transportation), a 13% decrease from 1Q17 |
| • | Recently closed bolt-on acquisitions of leasehold acreage and mineral interests in the heart of the Company’s Delaware Basin position for an aggregate purchase price of $227.9 million acquiring approximately 6,000 net acres, 4,500 net royalty acres(1) and 500 Boe/d of production |
| • | Increased oil hedges, and now have total oil derivative contracts covering 5.2 million barrels of 2H17 oil volumes and 6.7 million barrels of 2018 oil volumes |
| • | Maintained strong liquidity position, with $33.8 million of cash and $58.0 million in borrowings outstanding under the Company’s revolving credit facility ($1.1 billion borrowing base, $900 million Company-elected commitment)(2) |
| (1) | Net royalty acre defined as one surface acre leased at a 1/8th royalty |
| (2) | Borrowings as of end of second quarter are prior to funding remaining $203 million of recently closed acquisitions |
1
Recent Well Results
| • | The Ludeman K 2105H Delaware Basin Lower Wolfcamp A well established a peak 30-day average rate of 1,905 Boe/d or 401 Boe/d per 1,000’ (73% oil) |
| • | The Crockett Reese St B 2403H Delaware Basin Lower Wolfcamp A well established a peak 30-day average rate of 1,706 Boe/d or 247 Boe/d per 1,000’ (73% oil) and has produced 147 MBoe in 115 days |
| • | The Rudd Draw 26-21 01H Delaware Basin Wolfcamp XY well established its peak 30-day average rate of 2,020 Boe/d or 301 Boe/d per 1,000’ (74% oil) after 189 days online and has produced 300 MBoe in that time period |
| • | Four Midland Basin wells targeting the Wolfcamp A and B in western Glasscock County established an average peak 30-day rate of over 1,300 Boe/d, including the Calverley 22 27 102H at 1,597 Boe/d or 209 Boe/d per 1,000’ (68% oil) |
Steve Gray, Chief Executive Officer of RSP, commented, “We delivered another strong quarter, increasing our production 20% compared to last quarter and lowering our cash operating costs on a per unit basis. Over the past four quarters we have more than doubled our production volumes and generated positive net income with average realized oil prices less than $50 per barrel over that time period, demonstrating the quality of our assets and our ability to deliver profitable growth in a lower oil price environment.
“I am also pleased to report that our infrastructure projects are on schedule and we will begin growing our production volumes in the Delaware Basin in the second half of the year. Our Delaware Basin wells continue to exceed our acquisition estimates and we expect to complete wells in five distinct zones during the second half of this year. In the Midland Basin, we continue to achieve outstanding and consistent results in several zones across our acreage position.
“We recently closed several acquisitions of acreage and mineral interests located in the heart of our Delaware Basin position. While further blocking up our contiguous acreage position and extending the average lateral length of our inventory, these acquisitions do not require any additional staffing or infrastructure as they are located in areas we have already scheduled to drill. The leasehold acquisitions increase our working interest in 14 sections to a majority working interest position and the mineral interests provide immediate uplift to our returns without any incremental capital requirements or production-related expenses on wells drilled in those areas.”
Mr. Gray continued, “As we consider our operating strategy and plans going into next year, we will look to closely balance our capital spending with our cash flow generation while remaining flexible to adjust our activity levels to market conditions. Because of our strong well performance and operating efficiency, we have the capability to continue to grow our annual production volumes on a double-digit basis within cash flow at oil prices below $50 per barrel.”
2
Operational Results
| Three Months Ended June 30, | ||||||||
| 2017 | 2016 | |||||||
| Production data: |
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| Oil (MBbls) |
3,527 | 1,760 | ||||||
| Natural gas (MMcf) |
3,651 | 1,725 | ||||||
| NGLs (MBbls) |
809 | 355 | ||||||
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| Total (MBoe) |
4,945 | 2,403 | ||||||
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| Average net daily production (Boe/d) |
54,341 | 26,407 | ||||||
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| Average prices before effects of hedges (1) (2): |
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| Oil (per Bbl) |
$ | 45.48 | $ | 42.50 | ||||
| Natural gas (per Mcf) |
2.70 | 1.47 | ||||||
| NGLs (per Bbl) |
15.88 | 11.69 | ||||||
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| Total (per Boe) |
$ | 37.03 | $ | 33.91 | ||||
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| Average realized prices after effects of hedges (1) (2): |
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| Oil (per Bbl) |
$ | 45.27 | $ | 43.05 | ||||
| Natural gas (per Mcf) |
2.70 | 1.47 | ||||||
| NGLs (per Bbl) |
15.88 | 11.69 | ||||||
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| Total (per Boe) |
$ | 36.88 | $ | 34.32 | ||||
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| Average costs (per Boe): |
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| Lease operating expenses (excluding gathering and transportation) |
$ | 4.72 | $ | 5.37 | ||||
| Gathering and transportation |
1.12 | 0.49 | ||||||
| Production and ad valorem taxes |
2.05 | 2.06 | ||||||
| Depreciation, depletion and amortization |
13.77 | 19.68 | ||||||
| General and administrative - recurring cash component |
1.60 | 2.06 | ||||||
| General and administrative - recurring stock comp (3) |
0.90 | 1.46 | ||||||
| General and administrative - non-recurring stock comp (4) |
— | 0.28 | ||||||
| (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 natural 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) | Non-recurring stock comp in 2016 was a one-time compensation charge associated with the retirement of an officer of the Company. |
Production volumes for the quarter ended June 30, 2017 averaged 54,341 Boe/d, or a total of 4,945 MBoe, an increase of 106% over prior year’s second quarter of 26,407 Boe/d. Production for the second quarter of 2017 was comprised of 72% crude oil, 12% natural gas and 16% NGLs. RSP’s average realized oil price for the second quarter of 2017, before the effects of hedges, was $45.48 per barrel, a negative $2.80 differential compared to average NYMEX WTI pricing of $48.28 per barrel for the same period, or 94% of NYMEX WTI pricing. RSP’s average realized natural gas price for the second quarter of 2017, before the effects of hedges, was $2.70 per Mcf, a negative $0.49 differential compared to average NYMEX Henry Hub pricing of $3.19 per MMBtu for the same period, or 85% of NYMEX Henry Hub pricing. RSP’s average realized NGL price for the second quarter of 2017, before the effects of hedges, was $15.88 per Bbl, or 33% of NYMEX WTI pricing for the same time period. RSP’s
3
average realized commodity price per barrel of oil equivalent for the second quarter of 2017, before the effects of hedges, was $37.03. Per unit cash operating expenses excluding interest expense but including lease operating expense, gathering and transportation expense, production and ad valorem taxes and recurring cash general and administrative expenses were $9.49 per Boe.
Operational Update
The Company operated four horizontal rigs in the Midland Basin during the second quarter 2017. In the Delaware Basin, the Company operated two horizontal rigs during the entire second quarter and added a third horizontal rig in May 2017. RSP utilized one full-time completion crew during the second quarter in the Midland Basin and a nearly full-time crew in the Delaware Basin. RSP drilled 22 operated horizontal wells and completed 18 operated horizontal wells (Midland: two Lower Spraberry, five Wolfcamp A, three Wolfcamp B; Delaware: six Wolfcamp A, one Wolfcamp XY, one Second Bone Spring). The Company began the quarter with 18 operated horizontal drilled but uncompleted wells (“DUCs”) and exited the quarter with a total of 22 operated horizontal DUCs.
Financial Results
| Three Months Ended | ||||||||||||
| June 30, | March 31, | |||||||||||
| (In thousands, except per share data) | 2017 | 2016 | 2017 | |||||||||
| Total Revenues |
$ | 183,100 | $ | 81,485 | $ | 169,931 | ||||||
| Net Cash from Derivative Instruments |
(716 | ) | 974 | (2,812 | ) | |||||||
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| Adjusted Total Revenues |
182,384 | 82,459 | 167,119 | |||||||||
| Net Income (Loss) |
$ | 31,090 | $ | (9,801 | ) | $ | 38,934 | |||||
| Net Income (Loss) per Common Share—Diluted |
0.20 | (0.10 | ) | 0.26 | ||||||||
| Adjusted Net Income (Loss)(1) |
$ | 26,048 | $ | (3,758 | ) | $ | 24,212 | |||||
| Adjusted Net Income (Loss) per Common Share—Diluted |
0.17 | (0.04 | ) | 0.16 | ||||||||
| Adjusted EBITDAX(1) |
$ | 135,450 | $ | 58,453 | $ | 124,451 | ||||||
| (1) | Adjusted EBITDAX and Adjusted Net Income (loss) are non-GAAP financial measures. For a definition of Adjusted EBITDAX and Adjusted Net Income (loss) and a reconciliation of Adjusted EBITDAX and Adjusted Net Income (loss) to Net Income (loss), see “Use of Non-GAAP financial measures” and our quarterly statements of operations at the end of this release. |
For the quarter ended June 30, 2017, total revenues, excluding the revenue impact from realized derivative instruments, were $183.1 million, a 125% increase over the prior year quarter of $81.5 million. Adjusted total revenues, including the net cash from derivative instruments, were $182.4 million, a 121% increase from the prior year quarter of $82.5 million. Net income for the second quarter of 2017 was $31.1 million, or $0.20 per diluted share, while net loss for the prior year quarter was $9.8 million, or negative $0.10 per diluted share. Adjusted net
4
income for the second quarter of 2017 was $26.0 million, or $0.17 per diluted share, compared to an Adjusted net loss for the prior year quarter of negative $3.8 million or negative $0.04 per diluted share. Adjusted EBITDAX was $135.5 million, a 132% increase from the prior year quarter of $58.5 million.
Capital Expenditures
RSP’s development capital expenditures, which includes our investment in drilling and completing wells, infrastructure, capitalized workovers, and other, but excludes the cost of acquisitions, for the quarter ended June 30, 2017 totaled $179.6 million ($168.7 million of drilling and completion and $10.9 million of infrastructure and other). Of the development capital, approximately $21.4 million, or 12%, was spent on non-operated properties.
Additionally, during the second quarter of 2017 the Company acquired $15.5 million of oil and gas properties.
5
Liquidity
As of June 30, 2017, the Company had $33.8 million of cash and $58.0 million of borrowings outstanding on its revolving credit facility, which has a $1.1 billion borrowing base and a $900 million Company-elected commitment.
Hedging
The summary below includes all hedges in place for the second half of 2017 and for 2018, as of August 7, 2017.
| Crude Oil Hedges |
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| (Bbl, $/Bbl) | Q3 2017 | Q4 2017 | Q1 2018 | Q2 2018 | Q3 2018 | Q4 2018 | ||||||||||||||||||
| Three-Way Collars(1) |
552,000 | 2,219,000 | 1,941,000 | 1,319,000 | 1,227,000 | |||||||||||||||||||
| Ceiling |
$ | 54.10 | $ | 58.81 | $ | 59.07 | $ | 60.56 | $ | 60.96 | ||||||||||||||
| Floor |
$ | 45.00 | $ | 46.96 | $ | 47.11 | $ | 47.79 | $ | 48.00 | ||||||||||||||
| Short Put |
$ | 35.00 | $ | 36.96 | $ | 37.11 | $ | 37.79 | $ | 38.00 | ||||||||||||||
| Costless Collars(1) |
1,150,000 | 1,150,000 | ||||||||||||||||||||||
| Ceiling |
$ | 60.05 | $ | 60.05 | ||||||||||||||||||||
| Floor |
$ | 45.00 | $ | 45.00 | ||||||||||||||||||||
| Deferred Premium Puts(1) |
920,000 | 920,000 | ||||||||||||||||||||||
| Floor |
$ | 48.50 | $ | 48.50 | ||||||||||||||||||||
| Deferred Premium(2) |
$ | (4.00 | ) | $ | (4.00 | ) | ||||||||||||||||||
| Swaps(1) |
552,000 | |||||||||||||||||||||||
| Swap |
$ | 48.95 | ||||||||||||||||||||||
| Total Hedge Volumes |
2,070,000 | 3,174,000 | 2,219,000 | 1,941,000 | 1,319,000 | 1,227,000 | ||||||||||||||||||
| Weighted Average Floor(3) |
$ | 44.78 | $ | 45.54 | $ | 46.96 | $ | 47.11 | $ | 47.79 | $ | 48.00 | ||||||||||||
| Mid-Cush Differential Swaps(4) |
920,000 | 276,000 | ||||||||||||||||||||||
| Swap |
$ | (0.38 | ) | $ | (0.50 | ) | ||||||||||||||||||
| (1) | The crude oil derivative contracts are settled based on the arithmetic average of the closing settlement price for the front month contract NYMEX price of West Texas Intermediate Light Sweet Crude. |
| (2) | The deferred premium is not paid until expiration date, aligning cash inflows and outflows with the settlement of the derivative contract. |
| (3) | Weighted average floor assumes the long put in three-way collars and put spreads and reflects the impact of premiums paid. |
| (4) | The Mid-Cush swap contracts are settled based on the difference in the arithmetic average during the calculation period of WTI MIDLAND ARGUS and WTI ARGUS prices in the Argus Americas Crude publication for the relevant period. |
| Natural Gas Hedges |
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| (MMBtu, $/MMBtu) | Q3 2017 | Q4 2017 | ||||||
| Costless Collars(1) |
2,422,000 | 2,545,000 | ||||||
| Ceiling |
$ | 3.86 | $ | 3.86 | ||||
| Floor |
$ | 3.00 | $ | 3.00 | ||||
| (1) | The natural gas derivative contracts are settled based on the last trading day’s closing price for the front month contract relevant to each period. |
6
2017 Annual Guidance
| 1H17 Actuals | 2017 Guidance | |||||
| Completions |
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| Operated Gross Horizontal Completions |
32 | 80 - 85(1) | ||||
| Operated Average Working Interest |
89 | % | 88% | |||
| Midland Basin Average Lateral Length |
~8,300’ | ~8,500’ | ||||
| Delaware Basin Average Lateral Length |
~5,700’ | ~6,250’ | ||||
| Production |
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| Average Daily Production (Boe/d) |
49,779 | 53,000 - 57,000 | ||||
| % Oil |
73 | % | 71% - 73% | |||
| % Natural Gas |
12 | % | 11% - 13% | |||
| % NGLs |
15 | % | 15% - 17% | |||
| Development Capital Expenditures ($ in MM) |
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| Drilling and Completion (D&C) |
$ | 279.2 | $575 - $625 | |||
| Infrastructure, Capitalized Workovers & Other |
$ | 16.0 | $50 - $75 | |||
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| Total Development Capital Expenditures |
$ | 295.2 | $625 - $700 | |||
| % Midland Basin |
69 | % | 60% - 70% | |||
| % Delaware Basin |
31 | % | 30% - 40% | |||
| % Non-Operated |
12 | % | 8% - 12%(1) | |||
| Income Statement ($/Boe) |
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| Lease operating expenses (including workovers) |
$ | 5.03 | $4.50 - $5.50 | |||
| Gathering and transportation |
$ | 1.00 | $1.10 - $1.40 | |||
| Exploration expenses |
$ | 0.60 | $0.40 - $0.60 | |||
| General and administrative - recurring cash component |
$ | 1.74 | $1.25 - $1.75 | |||
| General and administrative - recurring stock comp |
$ | 0.93 | $0.70 - $0.90 | |||
| Depreciation, depletion, and amortization |
$ | 14.33 | $14.00 - $16.00 | |||
| Production and ad valorem taxes (% of oil and gas revenues) |
5.6 | % | 6.0% - 8.0% | |||
| (1) | Represents updated 2017 guidance range. |
7
Second Quarter 2017 Earnings Release and Conference Call
RSP will host a conference call for investors at 1:00 PM Central Time on Tuesday, August 8, 2017, to discuss second quarter 2017 results. Hosting the call will be Steve Gray, Chief Executive Officer, Scott McNeill, Chief Financial Officer, Zane Arrott, Chief Operating Officer and other members of RSP’s management team.
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 (844) 512-2921, or for international callers (412) 317-6671. The passcode for the replay is 13667248. The replay will be available until August 22, 2017. 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 for approximately 30 days 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 and Delaware Basins, sub-basins of the Permian Basin. 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 Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q, 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.
8
Statements of Operations
| Three Months Ended June 30, | Three Months Ended March 31, |
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| (In thousands, except per share data) | 2017 | 2016 | 2017 | |||||||||
| Revenues |
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| Oil sales |
$ | 160,395 | $ | 74,799 | $ | 151,637 | ||||||
| Natural gas sales |
9,859 | 2,537 | 7,378 | |||||||||
| NGL sales |
12,846 | 4,149 | 10,916 | |||||||||
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| Total revenues |
183,100 | 81,485 | 169,931 | |||||||||
| Operating expenses |
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| Lease operating expenses |
28,892 | 14,094 | 25,411 | |||||||||
| Production and ad valorem taxes |
10,142 | 4,960 | 9,469 | |||||||||
| Depreciation, depletion, and amortization |
68,104 | 47,296 | 61,040 | |||||||||
| Asset retirement obligation accretion |
150 | 123 | 153 | |||||||||
| Impairments |
5,312 | 3,177 | 125 | |||||||||
| Exploration expenses |
2,869 | 405 | 2,580 | |||||||||
| General and administrative expenses |
12,343 | 9,135 | 11,712 | |||||||||
| Acquisition costs |
401 | — | 4,052 | |||||||||
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| Total operating expenses |
128,213 | 79,190 | 114,542 | |||||||||
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| Operating income |
54,887 | 2,295 | 55,389 | |||||||||
| Other income (expense) |
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| Other income, net |
589 | 104 | 720 | |||||||||
| Net gain (loss) on derivative instruments |
12,194 | (3,684 | ) | 17,121 | ||||||||
| Interest expense |
(19,508 | ) | (12,954 | ) | (19,224 | ) | ||||||
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| Total other expense |
(6,725 | ) | (16,534 | ) | (1,383 | ) | ||||||
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| Income (loss) before income taxes |
48,162 | (14,239 | ) | 54,006 | ||||||||
| Income tax (expense) benefit |
(17,072 | ) | 4,438 | (15,072 | ) | |||||||
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| Net income (loss) |
$ | 31,090 | $ | (9,801 | ) | $ | 38,934 | |||||
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| Net income (loss) per common share—Basic |
$ | 0.20 | $ | (0.10 | ) | $ | 0.27 | |||||
| Net income (loss) per common share—Diluted |
$ | 0.20 | $ | (0.10 | ) | $ | 0.26 | |||||
| Weighted Average Common Shares Outstanding |
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| Basic |
156,856 | 100,189 | 146,054 | |||||||||
| Diluted |
157,827 | 100,189 | 147,005 | |||||||||
9
Summary Balance Sheet
| (In thousands) | June 30, 2017 | December 31, 2016 | ||||||
| Cash and cash equivalents |
$ | 33,775 | $ | 690,776 | ||||
| Other current assets |
95,377 | 85,486 | ||||||
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| Total current assets |
129,152 | 776,262 | ||||||
| Property, plant and equipment, net |
5,657,788 | 4,129,635 | ||||||
| Other long-term assets |
72,133 | 90,530 | ||||||
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| Total assets |
$ | 5,859,073 | $ | 4,996,427 | ||||
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| Current liabilities |
138,949 | 108,269 | ||||||
| Long-term debt |
1,190,965 | 1,132,275 | ||||||
| Other long-term liabilities |
377,612 | 338,571 | ||||||
| Total stockholders’ equity |
4,151,547 | 3,417,312 | ||||||
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| Total liabilities and stockholders’ equity |
$ | 5,859,073 | $ | 4,996,427 | ||||
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10
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, acquisition costs 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 tables include a reconciliation of the non-GAAP financial measures of Adjusted EBITDAX and Adjusted Net Income to the GAAP financial measure of net income.
11
Reconciliation of Net Income (Loss) to Adjusted EBITDAX
| Three Months Ended June 30, | Three Months Ended March 31, |
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| (In thousands) | 2017 | 2016 | 2017 | |||||||||
| Net income (loss) |
$ | 31,090 | $ | (9,801 | ) | $ | 38,934 | |||||
| Interest expense |
19,508 | 12,954 | 19,224 | |||||||||
| Income tax expense (benefit) |
17,072 | (4,438 | ) | 15,072 | ||||||||
| Depreciation, depletion, and amortization |
68,104 | 47,296 | 61,040 | |||||||||
| Asset retirement obligation accretion |
150 | 123 | 153 | |||||||||
| Exploration expenses |
2,869 | 405 | 2,580 | |||||||||
| Acquisition costs |
401 | — | 4,052 | |||||||||
| Impairment of unproved properties |
5,312 | 3,177 | 125 | |||||||||
| (Gain) loss on derivative instruments |
(12,194 | ) | 3,684 | (17,121 | ) | |||||||
| Net settled derivative instruments |
(716 | ) | 974 | (2,812 | ) | |||||||
| Stock-based compensation |
4,443 | 4,183 | 3,924 | |||||||||
| Other income, net |
(589 | ) | (104 | ) | (720 | ) | ||||||
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| Adjusted EBITDAX |
$ | 135,450 | $ | 58,453 | $ | 124,451 | ||||||
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Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss)
| Three Months Ended June 30, | Three Months Ended March 31, |
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| (In thousands) | 2017 | 2016 | 2017 | |||||||||
| Net income (loss) |
$ | 31,090 | $ | (9,801 | ) | $ | 38,934 | |||||
| Acquisition costs |
401 | — | 4,052 | |||||||||
| Impairment of unproved properties |
5,312 | 3,177 | 125 | |||||||||
| (Gain) loss on derivative instruments |
(12,194 | ) | 3,684 | (17,121 | ) | |||||||
| Net settled derivative instruments |
(716 | ) | 974 | (2,812 | ) | |||||||
| Stock-based compensation—non-recurring |
— | 682 | — | |||||||||
| Other income, net |
(589 | ) | (104 | ) | (720 | ) | ||||||
| Income tax expense (benefit) for above items |
2,744 | (2,370 | ) | 1,754 | ||||||||
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| Adjusted Net Income (Loss) |
$ | 26,048 | $ | (3,758 | ) | $ | 24,212 | |||||
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Investor Contact:
Scott McNeill
Chief Financial Officer
214-252-2700
Alyssa Stephens
Director, Investor Relations
214-252-2764
Investor Relations:
IR@rsppermian.com
214-252-2790
Source: RSP Permian, Inc.
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