RSP PERMIAN INC 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 $0.14 per diluted share. Adjusted net
income, which does not include certain items, was $28.2 million, or
$0.18 per 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 billion from $1.1 billion((1)) and
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 Delaware Basin position
for an aggregate purchase price of $234.4 million acquiring
approximately 5,800 net leasehold acres, 5,800 net royalty acres((2))
and 500 Boe/d of production
((1)) Borrowing base redetermination closed subsequent to 3Q17
((2)) 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)
Delaware Basin
-- 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 Delaware Basin Lower Wolfcamp A well (4,750') has
produced 200 MBoe in 170 days (72% oil)
-- The Rudd Draw 26-21 01H Delaware Basin 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 billion acquisition of Silver Hill, 2017 has been all about execution. I am pleased to report that our build out of infrastructure in the Delaware Basin 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 $45.85 per barrel, a negative $2.35 differential compared to average NYMEX WTI pricing of $48.20 per 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 $2.23 per Mcf, a negative $0.76 differential compared to average NYMEX Henry Hub pricing of $2.99 per 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 $19.52 per 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 $10.04 per Boe.
Operational Update
The Company operated four horizontal rigs in the Midland Basin and three horizontal rigs in the Delaware Basin 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)(1) $28,187 $(764) $26,048
Adjusted Net Income (Loss) per Common Share - Diluted 0.18 (0.01) 0.17
Adjusted EBITDAX(1) $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 $0.14 per diluted share, while net income for the prior year quarter was $1.0 million, or $0.01 per diluted share. Adjusted net income for the third quarter of 2017 was $28.2 million, or $0.18 per diluted share, compared to an Adjusted net loss for the prior year quarter of negative $0.8 million or negative $0.01 per 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, 2017 totaled $191.6 million ($168.9 million of drilling and completion and $22.7 million of 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 million of oil and gas properties.
Liquidity
As of September 30, 2017, the Company had $46.5 million of cash and $345 million of borrowings outstanding on its revolving credit facility, which had a $1.1 billion borrowing base and a $900 million Company-elected commitment. Effective October 19, 2017, the Company increased the borrowing base under its revolving credit facility to $1.5 billion, from $1.1 billion and 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(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) 1,150,000 571,000 516,000 890,000 736,000
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(1) 920,000
Floor $48.50
Deferred
Premium(2) $(4.00)
Swaps(1) 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(3) $45.54 $46.56 $46.67 $46.67 $46.87
Mid-Cush
Differential
Swaps(4) 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(1) 2,545,000
Ceiling $3.86
Floor $3.00
(1) The natural gas derivative
contracts are settled
based on the last trading
day's closing price for
the front month contract
relevant to each period.
2017 Annual Guidance
Nine months 2017 Guidance
ended 9/30/17
Actual
------
Completions
-----------
Operated Gross
Horizontal
Completions 54 70 - 74(1)
Operated Average
Working Interest 91% 92%(1)
Midland Basin
Average Lateral
Length ~8,300' ~8,500'
Delaware Basin
Average Lateral
Length ~5,600' ~6,250'
Production
----------
Average Daily
Production (Boe/
d) 52,864 53,000 - 57,000
% Oil 72% 71% - 73%
% Natural Gas 12% 11% - 13%
% NGLs 16% 15% - 17%
Development
Capital
Expenditures ($
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 Time on 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
Ended June 30,
--------------
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
Ended June 30,
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
Ended June 30,
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
======= ===== =======
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