RSP PERMIAN INC RSP Permian, Inc. Announces Third Quarter 2017 Financial and Operating Results
DALLAS, Nov. 6, 2017 /PRNewswire / -- RSP Permian, Inc. ('RSP' or the 'Company') (NYSE: RSPP) today reported financial and operating results for the quarter ended September 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.
Third Quarter 2017 Highlights
- Production increased 98% to 58.9 MBoe/d (71% oil, 87% liquids), compared to 3Q16 and increased 8% compared to 2Q17
- Net income of $21.3 million, or $0.14per diluted share. Adjusted net income, which does not include certain items, was $28.2 million, or $0.18per diluted share
- Adjusted EBITDAX of $144.7 million, a 120% increase compared to 3Q16 and a 7% increase compared to 2Q17
- Borrowing base increased to $1.5 billionfrom $1.1 billionand Company negotiated reduced interest rate on outstanding borrowings' pricing grid
- Closed bolt-on acquisitions of leasehold acreage and mineral interests located primarily in the heart of the Company's DelawareBasin position for an aggregate purchase price of $234.4 millionacquiring approximately 5,800 net leasehold acres, 5,800 net royalty acres and 500 Boe/d of production
Borrowing base redetermination closed subsequent to 3Q17
Net royalty acre defined as one surface acre leased at a 1/8th royalty
Well Results
Midland Basin
- The Keystone 1007 Wolfcamp A well (9,800') established a peak 30-day average rate of 2,220 Boe/d or 227 Boe/d per 1,000' (90% oil)
- The Spanish Trail 347 02 Wolfcamp A well (6,500') established a peak 30-day average rate of 1,850 Boe/d or 285 Boe/d per 1,000' (82% oil)
DelawareBasin
- The Rudd Draw 29 03 01H Third Bone Spring well (4,440') is currently producing 1,822 Boe/d while still cleaning up at over 2,500 psi and established a seven day rate of 1,428 Boe/d or 322 Boe/d per 1,000' (79% oil)
- The Ludeman A 603 Wolfcamp B well (4,830') established a peak 30-day average rate of 935 Boe/d or 194 Boe/d per 1,000' (77% oil)
- The Ludeman D 2105H DelawareBasin Lower Wolfcamp A well (4,750') has produced 200 MBoe in 170 days (72% oil)
- The Rudd Draw 26-21 01H DelawareBasin Wolfcamp XY well (6,700') has produced 450 MBoe in 275 days (73% oil)
Steve Gray, Chief Executive Officer of RSP, commented, 'After closing our $2.4 billionacquisition of Silver Hill, 2017 has been all about execution. I am pleased to report that our build out of infrastructure in the DelawareBasin has been completed on time and on budget, and we remain on track to deliver on our 2017 guidance. Our well results in both the Midland and Delaware Basins are outperforming our expectations. As a result, we've slowed down our completion pace in order to minimize our outspend while at the same time reaffirmed our production guidance for the year.'
Mr. Gray continued, 'RSP is well positioned to accelerate our production and cash flow growth next year and to further enhance our capital efficiency as we work off our backlog of uncompleted wells. Our inventory of high-return, horizontal prospects located in multiple stacked zones in the core of the Midland and Delaware Basins, coupled with our low cost operations, provide us with decades of strong, profitable growth and will enable us to fund our drilling program out of operating cash flow before the end of next year at today's oil prices.'
Operational Results
Three Months Ended September 30, | |||||||
2017 | 2016 | ||||||
Production data: | |||||||
Oil (MBbls) | 3,808 | 1,989 | |||||
Natural gas (MMcf) | 4,339 | 1,720 | |||||
NGLs (MBbls) | 890 | 462 | |||||
Total (MBoe) | 5,422 | 2,738 | |||||
Average net daily production (Boe/d) | 58,932 | 29,761 | |||||
Average prices before effects of hedges (1) (2): | |||||||
Oil (per Bbl) | $ | 45.85 | $ | 42.60 | |||
Natural gas (per Mcf) | 2.23 | 2.27 | |||||
NGLs (per Bbl) | 19.52 | 10.82 | |||||
Total (per Boe) | $ | 37.19 | $ | 34.19 | |||
Average realized prices after effects of hedges (1) (2): | |||||||
Oil (per Bbl) | $ | 45.16 | $ | 41.46 | |||
Natural gas (per Mcf) | 2.24 | 2.27 | |||||
NGLs (per Bbl) | 19.52 | 10.82 | |||||
Total (per Boe) | $ | 36.72 | $ | 33.37 | |||
Average costs (per Boe): | |||||||
Lease operating expenses (excluding gathering and transportation) | $ | 5.18 | $ | 4.67 | |||
Gathering and transportation | 0.98 | 0.51 | |||||
Production and ad valorem taxes | 2.45 | 2.14 | |||||
Depreciation, depletion and amortization | 13.54 | 18.27 | |||||
General and administrative - cash component | 1.43 | 2.04 | |||||
General and administrative - stock comp (3) | 0.81 | 1.20 | |||||
(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. |
Production volumes for the quarter ended September 30, 2017 averaged 58,932 Boe/d, or a total of 5,422 MBoe, an increase of 98% over prior year's third quarter of 29,761 Boe/d. Production for the third quarter of 2017 was comprised of 71% crude oil, 13% natural gas and 16% NGLs. RSP's average realized oil price for the third quarter of 2017, before the effects of hedges, was $45.85per barrel, a negative $2.35differential compared to average NYMEX WTI pricing of $48.20per barrel for the same period, or 95% of NYMEX WTI pricing. RSP's average realized natural gas price for the third quarter of 2017, before the effects of hedges, was $2.23per Mcf, a negative $0.76differential compared to average NYMEX Henry Hub pricing of $2.99per MMBtu for the same period, or 75% of NYMEX Henry Hub pricing. RSP's average realized NGL price for the third quarter of 2017, before the effects of hedges, was $19.52per Bbl, or 40% of NYMEX WTI pricing for the same time period. RSP's average realized commodity price per barrel of oil equivalent for the third quarter of 2017, before the effects of hedges, was $37.19. 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 $10.04per Boe.
Operational Update
The Company operated four horizontal rigs in the Midland Basin and three horizontal rigs in the DelawareBasin throughout the third quarter 2017. RSP utilized two full-time completion crews during the third quarter. RSP drilled 26 operated horizontal wells and completed 22 operated horizontal wells (Midland: seven Lower Spraberry, seven Wolfcamp A, three Wolfcamp B, one Middle Spraberry; Delaware: two Wolfcamp A, one Wolfcamp B, one Third Bone Spring). The Company began the quarter with 22 operated horizontal drilled but uncompleted wells ('DUCs') and exited the quarter with a total of 26 operated horizontal DUCs.
Financial Results
(In thousands, except per share data) | ||||||||||
Three Months Ended | ||||||||||
September 30, | June 30, | |||||||||
2017 | 2016 | 2017 | ||||||||
Total Revenues | $ | 201,654 | $ | 93,621 | $ | 183,100 | ||||
Net Cash from Derivative Instruments | (2,567) | (2,258) | (716) | |||||||
Adjusted Total Revenues | 199,087 | 91,363 | 182,384 | |||||||
Net Income | $ | 21,326 | $ | 985 | $ | 31,090 | ||||
Net Income per Common Share - Diluted | 0.14 | 0.01 | 0.20 | |||||||
Adjusted Net Income (Loss) | $ | 28,187 | $ | (764) | $ | 26,048 | ||||
Adjusted Net Income (Loss) per Common Share - Diluted | 0.18 | (0.01) | 0.17 | |||||||
Adjusted EBITDAX | $ | 144,662 | $ | 65,732 | $ | 135,450 | ||||
(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, see 'Use of Non-GAAP financial measures' and our quarterly statements of operations at the end of this release. |
For the quarter ended September 30, 2017, total revenues, excluding the revenue impact from realized derivative instruments, were $201.7 million, a 115% increase over the prior year quarter of $93.6 million. Adjusted total revenues, including the net cash from derivative instruments, were $199.1 million, a 118% increase from the prior year quarter of $91.4 million. Net income for the third quarter of 2017 was $21.3 million, or $0.14per diluted share, while net income for the prior year quarter was $1.0 million, or $0.01per diluted share. Adjusted net income for the third quarter of 2017 was $28.2 million, or $0.18per diluted share, compared to an Adjusted net loss for the prior year quarter of negative $0.8 millionor negative $0.01per diluted share. Adjusted EBITDAX was $144.7 million, a 120% increase from the prior year quarter of $65.7 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 September 30, 2017totaled $191.6 million($168.9 millionof drilling and completion and $22.7 millionof infrastructure and other). Of the development capital, approximately $16.5 million, or 9%, was spent on non-operated properties.
Additionally, during the third quarter of 2017 the Company acquired $234.4 millionof oil and gas properties.
Liquidity
As of September 30, 2017, the Company had $46.5 millionof cash and $345 millionof borrowings outstanding on its revolving credit facility, which had a $1.1 billionborrowing base and a $900 millionCompany-elected commitment. Effective October 19, 2017, the Company increased the borrowing base under its revolving credit facility to $1.5 billion, from $1.1 billionand reduced the interest rate on outstanding borrowings' pricing grid. The Company maintained its elected commitment amount of $900 million.
Hedging
The summary below includes all hedges in place for the remainder of 2017 and for 2018, as of November 6, 2017.
Crude Oil Hedges | ||||||||||||||||||||
(Bbl, $/Bbl) | Q4 2017 | Q1 2018 | Q2 2018 | Q3 2018 | Q4 2018 | |||||||||||||||
Three-Way Collars | 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 | 1,150,000 | 571,000 | 516,000 | 890,000 | 736,000 | |||||||||||||||
Ceiling | $ | 60.05 | $ | 60.19 | $ | 60.20 | $ | 60.14 | $ | 60.16 | ||||||||||
Floor | $ | 45.00 | $ | 45.00 | $ | 45.00 | $ | 45.00 | $ | 45.00 | ||||||||||
Deferred Premium Puts | 920,000 | |||||||||||||||||||
Floor | $ | 48.50 | ||||||||||||||||||
Deferred Premium | $ | (4.00) | ||||||||||||||||||
Swaps | 552,000 | |||||||||||||||||||
Swap | $ | 48.95 | ||||||||||||||||||
Total Hedge Volumes | 3,174,000 | 2,790,000 | 2,457,000 | 2,209,000 | 1,963,000 | |||||||||||||||
Weighted Average Floor | $ | 45.54 | $ | 46.56 | $ | 46.67 | $ | 46.67 | $ | 46.87 | ||||||||||
Mid-Cush Differential Swaps | 1,104,000 | 1,800,000 | 1,820,000 | 1,840,000 | 1,840,000 | |||||||||||||||
Swap | $ | (0.63) | $ | (0.62) | $ | (0.62) | $ | (0.62) | $ | (0.62) | ||||||||||
(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 during the relevant period. |
(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 | ||||
(MMBtu, $/MMBtu) | Q4 2017 | |||
Costless Collars | 2,545,000 | |||
Ceiling | $ | 3.86 | ||
Floor | $ | 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. |
2017 Annual Guidance
Nine months | 2017 Guidance | ||||
Completions | |||||
Operated Gross Horizontal Completions | 54 | 70 - 74 | |||
Operated Average Working Interest | 91% | 92% | |||
Midland Basin Average Lateral Length | ~8,300' | ~8,500' | |||
Delaware Basin Average Lateral Length | ~5,600' | ~6,250' | |||
Production | |||||
Average Daily Production (Boe/d) | 52,864 | 53,000 - 57,000 | |||
% Oil | 72% | 71% - 73% | |||
% Natural Gas | 12% | 11% - 13% | |||
% NGLs | 16% | 15% - 17% | |||
Development Capital Expenditures ($ in MM) | |||||
Drilling and Completion (D&C) | $448.1 | $575 - $625 | |||
Infrastructure, Capitalized Workovers & Other | $38.7 | $50 - $75 | |||
Total Development Capital Expenditures | $486.8 | $625 - $700 | |||
% Midland Basin | 66% | 60% - 70% | |||
% Delaware Basin | 34% | 30% - 40% | |||
% Non-Operated | 10% | 8% - 12% | |||
Income Statement ($/Boe) | |||||
Lease operating expenses (including workovers) | $5.09 | $4.50 - $5.50 | |||
Gathering and transportation | $0.99 | $1.10 - $1.40 | |||
Exploration expenses | $0.48 | $0.40 - $0.60 | |||
General and administrative - cash component | $1.62 | $1.25 - $1.75 | |||
General and administrative - stock comp | $0.88 | $0.70 - $0.90 | |||
Depreciation, depletion, and amortization | $14.03 | $14.00 - $16.00 | |||
Production and ad valorem taxes (% of oil and gas revenues) | 5.9% | 6.0% - 8.0% |
(1) | Represents update to 2017 guidance. |
Third Quarter 2017 Earnings Release and Conference Call
RSP will host a conference call for investors at 10:00 AM Central Timeon Tuesday, November 7, 2017, to discuss third 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 13672586. The replay will be available until November 21, 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 RSP's 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.
Statements of Operations
(In thousands, except per share data) | |||||||||||
Three Months Ended September 30, | Three Months | ||||||||||
2017 | 2016 | 2017 | |||||||||
Revenues | |||||||||||
Oil sales | $ | 174,624 | $ | 84,722 | $ | 160,395 | |||||
Natural gas sales | 9,661 | 3,901 | 9,859 | ||||||||
NGL sales | 17,369 | 4,998 | 12,846 | ||||||||
Total revenues | 201,654 | 93,621 | 183,100 | ||||||||
Operating expenses | |||||||||||
Lease operating expenses | 33,385 | 14,174 | 28,892 | ||||||||
Production and ad valorem taxes | 13,281 | 5,872 | 10,142 | ||||||||
Depreciation, depletion, and amortization | 73,408 | 50,022 | 68,104 | ||||||||
Asset retirement obligation accretion | 151 | 118 | 150 | ||||||||
Impairments | 705 | 971 | 5,312 | ||||||||
Exploration expenses | 1,497 | 359 | 2,869 | ||||||||
General and administrative expenses | 12,120 | 8,857 | 12,343 | ||||||||
Acquisition costs | 30 | - | 401 | ||||||||
Total operating expenses | 134,577 | 80,373 | 128,213 | ||||||||
Operating income | 67,077 | 13,248 | 54,887 | ||||||||
Other income (expense) | |||||||||||
Other income, net | 1,106 | 310 | 589 | ||||||||
Net gain (loss) on derivative instruments | (21,626) | (2,934) | 12,194 | ||||||||
Interest expense | (21,553) | (13,146) | (19,508) | ||||||||
Total other expense | (42,073) | (15,770) | (6,725) | ||||||||
Income (loss) before income taxes | 25,004 | (2,522) | 48,162 | ||||||||
Income tax (expense) benefit | (3,678) | 3,507 | (17,072) | ||||||||
Net income | $ | 21,326 | $ | 985 | $ | 31,090 | |||||
Net income per common share - Basic | $ | 0.14 | $ | 0.01 | $ | 0.20 | |||||
Net income per common share - Diluted | $ | 0.14 | $ | 0.01 | $ | 0.20 | |||||
Weighted Average Common Shares Outstanding | |||||||||||
Basic | 156,864 | 100,234 | 156,856 | ||||||||
Diluted | 157,837 | 100,234 | 157,827 | ||||||||
Summary Balance Sheet
(In thousands) | |||||||
September 30, 2017 | December 31, 2016 | ||||||
Cash and cash equivalents | $ | 46,474 | $ | 690,776 | |||
Other current assets | 122,316 | 85,486 | |||||
Total current assets | 168,790 | 776,262 | |||||
Property, plant and equipment, net | 6,010,234 | 4,129,635 | |||||
Other long-term assets | 57,811 | 90,530 | |||||
Total assets | $ | 6,236,835 | $ | 4,996,427 | |||
Current liabilities | 200,263 | 108,269 | |||||
Long-term debt | 1,478,500 | 1,132,275 | |||||
Other long-term liabilities | 380,888 | 338,571 | |||||
Total stockholders' equity | 4,177,184 | 3,417,312 | |||||
Total liabilities and stockholders' equity | $ | 6,236,835 | $ | 4,996,427 | |||
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.
Reconciliation of Net Income to Adjusted EBITDAX
(In thousands) | |||||||||||
Three Months Ended September 30, | Three Months | ||||||||||
2017 | 2016 | 2017 | |||||||||
Net income | $ | 21,326 | $ | 985 | $ | 31,090 | |||||
Interest expense | 21,553 | 13,146 | 19,508 | ||||||||
Income tax expense (benefit) | 3,678 | (3,507) | 17,072 | ||||||||
Depreciation, depletion, and amortization | 73,408 | 50,022 | 68,104 | ||||||||
Asset retirement obligation accretion | 151 | 118 | 150 | ||||||||
Exploration expenses | 1,497 | 359 | 2,869 | ||||||||
Acquisition costs | 30 | - | 401 | ||||||||
Impairment of unproved properties | 705 | 971 | 5,312 | ||||||||
(Gain) loss on derivative instruments | 21,626 | 2,934 | (12,194) | ||||||||
Net settled derivative instruments | (2,567) | (2,258) | (716) | ||||||||
Stock-based compensation | 4,361 | 3,272 | 4,443 | ||||||||
Other income, net | (1,106) | (310) | (589) | ||||||||
Adjusted EBITDAX | $ | 144,662 | $ | 65,732 | $ | 135,450 | |||||
Reconciliation of Net Income to Adjusted Net Income (Loss)
(In thousands) | |||||||||||
Three Months Ended September 30, | Three Months | ||||||||||
2017 | 2016 | 2017 | |||||||||
Net income | $ | 21,326 | $ | 985 | $ | 31,090 | |||||
Acquisition costs | 30 | - | 401 | ||||||||
Impairment of unproved properties | 705 | 971 | 5,312 | ||||||||
(Gain) loss on derivative instruments | 21,626 | 2,934 | (12,194) | ||||||||
Net settled derivative instruments | (2,567) | (2,258) | (716) | ||||||||
Other income, net | (1,106) | (310) | (589) | ||||||||
Income tax expense (benefit) for above items | (11,827) | (3,086) | 2,744 | ||||||||
Adjusted Net Income (Loss) | $ | 28,187 | $ | (764) | $ | 26,048 | |||||
SOURCE RSP Permian, Inc.
For further information: Investor Contact: Scott McNeill, Chief Financial Officer, 214-252-2700 or Alyssa Stephens, Director, Investor Relations, 214-252-2764 or Investor Relations, IR@rsppermian.com, 214-252-2790
RSP Permian Inc. published this content on 06 November 2017 and is solely responsible for the information contained herein.
Distributed by Public, unedited and unaltered, on 06 November 2017 21:43:04 UTC.
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