RSP Permian, Inc. (“RSP” or the “Company”) (NYSE: RSPP) today
reported financial and operating results for the quarter and year
ended December 31, 2017, year-end 2017 proved reserves and 2018
guidance. In addition, the Company filed its Annual Report on Form
10-K for the year ended December 31, 2017 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.
Highlights for the Fourth Quarter and
Full Year 2017:
- 4Q17 production increased 74% to
62.4 MBoe/d (71% oil, 88% liquids) compared to 4Q16 and full year
2017 production increased 89% to 55.3 MBoe/d (72% oil, 88% liquids)
compared to 2016
- 4Q17 net income was $140.8 million,
or $0.89 per diluted share and adjusted net income (non-GAAP),
which does not include certain items, was $50.1 million, or $0.32
per diluted share. Full year 2017 net income was $232.1 million, or
$1.49 per diluted share and adjusted net income (non-GAAP), which
does not include certain items, was $128.6 million, or $0.83 per
diluted share
- 4Q17 adjusted EBITDAX (non-GAAP)
increased 102% to $182.4 million compared to 4Q16, and increased
26% compared to 3Q17. Full year 2017 adjusted EBITDAX (non-GAAP)
increased 134% to $587.0 million compared to 2016
- Full year 2017 development capital
expenditures of $673.3 million
- Maintained strong year-end liquidity
position of $561.2 million, including $523.1 million of available
borrowing capacity under the Company's revolving credit facility
and $38.1 million of cash
- Proved reserves increased by 59% to
376 MMBoe (70% oil, 87% liquids) compared to 2016; achieved low
drill-bit finding and development cost of $6.26/Boe, with a 771%
reserve replacement ratio and a 536% organic reserve replacement
ratio
Adjusted net income and adjusted EBITDAX are non-GAAP measures.
See "Use of Non-GAAP Financial Measures" below for definitions and
reconciliations. In addition, see below for Company's definition of
liquidity and calculations of "Drill-Bit F&D and Reserve
Replacement Ratios."
Operational Highlights
Midland Basin
- Spanish Trail 333 01H Wolfcamp A
well (8,600’) established a peak 30-day average rate of
1,821 Boe/d or 212 Boe/d per 1,000’ (84% oil)
- Basin leader in the development of
the Wolfcamp A target horizon. Full development underway in several
sections, including Spanish Trail Section 3-10; four of eight
planned Wolfcamp A wells averaged peak 30-day rates of 261 Boe/d
per 1,000' (78% oil)
Delaware Basin
- Recent Brunson D 3-well pad pilot
tested variations to completion design. Brunson D 1203H Wolfcamp A
well (7,500') established a peak 24-hour rate of 3,342 Boe/d or 446
Boe/d per 1,000' (67% oil); Brunson D 1201H Wolfcamp B well
(6,800') established a peak 24-hour rate of 2,460 Boe/d or 362
Boe/d per 1,000' (73% oil); Brunson D 1204H Third Bone Spring well
(8,500') established a peak 24-hour rate of 1,498 Boe/d or 176
Boe/d per 1,000' (71% oil)
- Rudd Draw 29 03 01H Third Bone
Spring well (4,400') established a peak 30-day average
rate of 1,724 Boe/d or 392 Boe/d per 1,000’ (71% oil)
2018 Guidance and 2019-2020 Preliminary
Outlook
- Average net daily production range
of 72.0 - 78.0 MBoe/d in 2018, a 30% - 41% increase over
2017
- Expect to generate cash flow in
excess of development spending by the fourth quarter of 2018, with
Net Debt / LTM EBITDAX of 2.0x or less by year-end at a $50 average
oil price
- Development capital expenditure
range of $815 - $895 million (drilling, completion, infrastructure
and other) with drilling and completion of $725 - $785 million and
infrastructure and other of $90 - $110 million
- Expanded hedge profile covering
approximately 60% of 2018E oil production volumes at the
midpoint
- Expecting 30%-plus annual production
growth in 2019 and 2020 with substantial free cash flow generated
at a $50 oil price
Steve Gray, Chief Executive Officer, commented, "I am proud of
our Company's accomplishments in 2017. We delivered on our annual
guidance objectives while nearly doubling the size of the Company,
integrating a new operating area in the Delaware Basin and building
out the infrastructure and team to accommodate our increased
activity levels and production growth in 2018. We continue to see
impressive well results in both our Midland and Delaware Basin
assets and this increased well productivity enabled us to meet the
mid-point of our production guidance despite completing twenty
fewer horizontal wells than we originally budgeted.
"We are well positioned for strong returns in 2018 as we
continue to increase our capital efficiency levels and accelerate
the completion of our drilled but uncompleted wells carried over
from last year's drilling program. We also expect to generate cash
flow in excess of our development spending by the fourth quarter of
2018 while growing production 35% at the mid-point of our
guidance."
Operational
Results
Three Months Ended December 31, Twelve Months
Ended December 31, 2017 2016
2017 2016 Production data: Oil
(MBbls) 4,078 2,337 14,445 7,790 Natural gas (MMcf) 4,210 2,278
15,126 7,188 NGLs (MBbls) 957 576 3,202 1,685
Total (MBoe) 5,737 3,293 20,168 10,673
Average net daily production (Boe/d) 62,359 35,793
55,255 29,161
Average prices before effects of hedges (1)
(2): Oil (per Bbl) $ 53.50 $ 47.23 $ 48.79 $ 41.28 Natural gas
(per Mcf) 2.21 2.24 2.39 1.94 NGLs (per Bbl) 22.50 12.94
19.57 10.87 Total (per Boe) $ 43.41 $ 37.33
$ 39.85 $ 33.15
Average realized prices after
effects of hedges (1) (2): Oil (per Bbl) $ 51.35 $ 46.20 $
47.75 $ 41.06 Natural gas (per Mcf) 2.27 2.24 2.43 1.94 NGLs (per
Bbl) 22.50 12.94 19.57 10.87 Total (per Boe) $
41.92 $ 36.60 $ 39.12 $ 32.99
Average costs
(per Boe): Lease operating expenses (excluding gathering and
transportation) $ 5.25 $ 4.41 $ 5.13 $ 4.93 Gathering and
transportation 0.89 0.57 0.96 0.48 Production and ad valorem taxes
2.79 2.01 2.43 2.03 Depreciation, depletion and amortization 13.45
15.94 13.87 18.21 General and administrative - recurring cash
component 1.19 2.11 1.50 2.10 General and administrative -
recurring stock comp (3) 0.77 0.98 0.85 1.23 General and
administrative - non-recurring stock comp (4) — — — 0.06
(1) Average prices shown in the table reflect
prices both before and after the effects of our cash
payments/receipts on the Company's commodity derivative
transactions. The 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. (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) The non-recurring
2016 amount is a compensation charge associated with the retirement
of an officer of the Company.
Production volumes for the quarter ended December 31, 2017
averaged 62,359 Boe/d or a total of 5,737 MBoe, an increase of 74%
over prior year’s fourth quarter of 35,793 Boe/d. Production for
the fourth quarter of 2017 was comprised of 71% oil, 12% natural
gas and 17% NGLs. RSP’s average realized oil price for the fourth
quarter of 2017, before the effects of hedges, was $53.50 per
barrel, a negative $1.90 differential compared to average NYMEX WTI
pricing of $55.40 per barrel for the same period, or 97% of NYMEX
WTI pricing. RSP’s average realized natural gas price for the
fourth quarter of 2017, before the effects of hedges, was $2.21 per
Mcf, a negative $0.72 differential compared to average NYMEX Henry
Hub pricing of $2.93 per MMBtu for the same period, or 75% of NYMEX
Henry Hub pricing. RSP’s average realized NGLs price for the fourth
quarter of 2017 was $22.50 per Bbl, or 41% of NYMEX WTI pricing for
the same time period. 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 $10.12 per
Boe.
Production volumes for the year ended December 31, 2017 averaged
55,255 Boe/d or a total of 20,168 MBoe, an increase of 89% over
prior year's total of 29,161 Boe/d. Production for 2017 was
comprised of 72% oil, 12% natural gas and 16% NGLs. RSP’s average
realized oil price for 2017, before the effects of hedges, was
$48.79 per barrel, a negative $2.16 differential compared to
average NYMEX WTI pricing of $50.95 per barrel for the same period,
or 96% of NYMEX WTI pricing. RSP’s average realized natural gas
price for 2017, before the effects of hedges, was $2.39 per Mcf, a
negative $0.72 differential compared to average NYMEX Henry Hub
pricing of $3.11 per MMBtu for the same period, or 77% of NYMEX
Henry Hub pricing. RSP’s average realized NGLs price for 2017 was
$19.57 per Bbl, or 38% of NYMEX WTI pricing for the same period.
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 $10.02 per Boe.
Operational Update
The Company operated three horizontal rigs in the Midland Basin
and three horizontal rigs in the Delaware Basin, and one horizontal
rig servicing both basins throughout the fourth quarter of 2017.
RSP utilized two full-time completion crews during the fourth
quarter. RSP drilled 26 gross operated horizontal wells and
completed 16 gross operated horizontal wells (Midland: five
Wolfcamp B, four Wolfcamp A and two Lower Spraberry; Delaware:
three Wolfcamp A, one Wolfcamp B and one Third Bone Spring). The
Company began the quarter with 26 operated horizontal drilled but
uncompleted wells ("DUCs") and exited the quarter with a total of
36 gross operated horizontal DUCs. During 2017, RSP drilled 95
gross and completed 70 gross operated horizontal wells (Midland: 21
Wolfcamp A, 16 Wolfcamp B, 13 Lower Spraberry and one Middle
Spraberry; Delaware: 12 Wolfcamp A, two Wolfcamp B, two Wolfcamp
XY, two Third Bone Spring and one Second Bone Spring). The
following table summarizes the Company's gross wells drilled and
completed during the periods:
4Q17 Wells 2017 Wells
Drilled Completed
Drilled
butUncompletedWells (DUCs)
Drilled Completed
Operated
Wells
Midland 17 11 27 68 51 Delaware 9 5 9 27
19 Total Operated 26 16 36 95 70
Non-Operated
Wells
Midland 9 13 9 34 35 Delaware 1 3 — 7 8
Total Non-Operated 10 16 9 41 43
Total
Wells
Midland 26 24 36 102 86 Delaware 10 8 9 34
27 Total Wells 36 32 45 136 113
Financial
Results
Three Months Ended December 31, Twelve Months
Ended December 31, (in thousands, except per share data)
2017 2016 2017
2016 Total Revenues $ 249,023 $ 122,934 $ 803,708 $ 353,857
Net Cash from Derivative Instruments (8,566 ) (2,398 ) (14,661 )
(1,732 ) Adjusted Total Revenues 240,457 120,536 789,047 352,125
Net Income (Loss) $ 140,786 $ 1,381 $ 232,136 $ (24,851 ) Net
Income (Loss) per Common Share - Diluted 0.89 0.01 1.49 (0.23 )
Adjusted Net Income (Loss) (1) 50,122 13,395 128,568 (7,358 )
Adjusted Net Income (Loss) per Common Share - Diluted 0.32 0.10
0.83 (0.07 ) Adjusted EBITDAX (1) $ 182,425 $ 90,529 $ 586,988 $
250,326 (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 quarterly
statements of operations at the end of this release.
For the quarter ended December 31, 2017, total revenues,
excluding the revenue impact from realized derivative instruments,
were $249.0 million, a 103% increase over the prior year quarter of
$122.9 million. Adjusted total revenues, including the net cash
from derivative instruments, were $240.5 million, a 99% increase
over the prior year quarter of $120.5 million. Net income for the
fourth quarter of 2017 was $140.8 million, or $0.89 per diluted
share, while net income for the prior year quarter was $1.4
million, or $0.01 per diluted share. The Company recorded a
one-time income tax benefit of $144.4 million during the fourth
quarter of 2017 as a result of the enactment of the U.S. Tax Cuts
and Jobs Act which lowered the federal corporate tax rate to 21%
from 35%. Adjusted net income for the fourth quarter of 2017 was
$50.1 million, or $0.32 per diluted share, compared with adjusted
net income for the prior year quarter of $13.4 million or $0.10 per
diluted share. Adjusted EBITDAX was $182.4 million, a 102% increase
from the prior year quarter of $90.5 million.
For the year ended December 31, 2017, total revenues, excluding
the revenue impact from realized derivative instruments, were
$803.7 million, a 127% increase over the prior year of $353.9
million. Adjusted total revenues, including the net cash from
derivative instruments, were $789.0 million, a 124% increase from
the prior year of $352.1 million. Net income for the year ended
2017 was $232.1 million, or $1.49 per diluted share, while net loss
for the prior year was $24.9 million, or negative $0.23 per diluted
share. Adjusted net income for the year ended 2017 was $128.6
million, or $0.83 per diluted share, compared with adjusted net
loss for the prior year of $7.4 million or negative $0.07 per
diluted share. Adjusted EBITDAX was $587.0 million, a 134% increase
from the prior year of $250.3 million.
Proved Reserves Summary
RSP’s proved reserves summary as of December 31, 2017 was
prepared by RSP and audited by Netherland, Sewell & Associates,
Inc.
The Company's proved oil and natural gas reserves increased from
236.9 MMBoe at January 1, 2017 to 375.9 MMBoe, or 59%, primarily
due to extensions and discoveries related to the Company's
development of the Midland Basin and Delaware Basin assets and the
Silver Hill E&P II, LLC ("SHEP II") acquisition in the first
quarter of 2017. Oil and NGLs reserves, in aggregate, equaled 87%
of the Company's total proved reserves. At December 31, 2017, 58%
of the Company's total proved reserves were undeveloped.
The following table summarizes the changes in the Company's
estimated net proved oil and natural gas reserves from January 1,
2017 to December 31, 2017 prepared in accordance with the
rules and regulations of the SEC.
Oil
(MBbls)
Natural
Gas
(MMcf)
NGLs
(MBbls)
Total
(MBoe)
Proved developed and undeveloped reserves: As of January 1,
2017 164,728 176,786 42,696 236,888 Production (14,445 ) (15,126 )
(3,202 ) (20,168 ) Extensions and discoveries 64,925 73,698 16,009
93,217 Purchases of minerals in place 34,997 33,772 6,859 47,485
Revisions of previous estimates 11,130 25,889 3,075
18,520 As of December 31, 2017 261,335 295,019
65,437 375,942
The following table presents the Company's estimated net proved
oil and natural gas reserves as of December 31, 2017, 2016 and
2015.
2017 2016
2015 Proved developed reserves: Oil (MBbls) 106,668
65,025 44,128 Natural gas (MMcf) 133,116 76,255 56,640 NGLs (MBbls)
30,162 18,759 11,020 Total (MBoe) 159,016 96,493
64,588
Proved undeveloped reserves: Oil (MBbls) 154,667
99,703 67,007 Natural gas (MMcf) 161,903 100,531 76,867 NGLs
(MBbls) 35,275 23,937 14,767 Total (MBoe) 216,926
140,395 94,585
Total proved reserves: Oil (MBbls) 261,335
164,728 111,135 Natural gas (MMcf) 295,019 176,786 133,507 NGLs
(MBbls) 65,437 42,696 25,787 Total (MBoe) 375,942
236,888 159,173
Capital Expenditures
RSP’s development capital expenditures, which includes our
investment in drilling and completing wells, infrastructure,
capitalized workovers, and other, but excludes acquisitions, for
the year ended December 31, 2017 totaled $673.3 million ($610.6
million of drilling and completion and $62.7 million of
infrastructure and other). The Company spent $78.9 million, or 12%
of development capital, on non-operated properties. The SHEP II
acquisition closed on March 1, 2017 for a purchase price of $1.3
billion, before purchase price adjustments, that included cash
consideration of $646.0 million, and approximately 16.0
million shares of RSP Inc. common stock, valued at $663.9
million based on our closing common share price of $41.44 per
share on March 1, 2017. In addition, we spent $279.0 million on
acquisitions of undeveloped acreage and additional mineral
interests.
Liquidity
In October 2017, the Company's borrowing base under its
revolving credit facility increased to $1.5 billion from
$1.1 billion, and the Company maintained its elected
commitment amount of $900.0 million. At December 31, 2017, the
Company had $523.1 million of borrowing capacity under its
revolving credit facility and $38.1 million of cash on hand.
The following table summarizes the Company's liquidity position
as of December 31, 2017:
(in thousands) December 31, 2017
Revolving Credit Facility elected commitment amount $ 900,000
Revolving Credit Facility borrowings (375,000 ) Letters of credit
(1,933 ) Available borrowing capacity 523,067 Cash and cash
equivalents 38,102 Liquidity $ 561,169
Hedging
The summary below includes all hedges in place for the full year
2018 and 2019, as of February 27, 2018.
Crude Oil Hedges (Bbl, $/Bbl)
Q1
2018 Q2 2018 Q3 2018
Q4 2018 2019 Three-Way
Collars(1) 2,219,000 1,941,000 1,319,000 1,227,000 —
Ceiling $ 58.81 $ 59.07 $ 60.56 $ 60.96 $ — Floor $ 46.96 $ 47.11 $
47.79 $ 48.00 $ — Short Put $ 36.96 $ 37.11 $ 37.79 $ 38.00 $ —
Costless Collars(1) 571,000 516,000 1,212,000
1,058,000 2,555,000 Ceiling $ 60.19 $ 60.20 $ 60.10 $ 60.11 $ 58.04
Floor $ 45.00 $ 45.00 $ 46.33 $ 46.52 $ 52.50
Crude Oil
Swaps(1) — 698,000 322,000 322,000 2,555,000 Swap $ — $
62.97 $ 55.77 $ 55.77 $ 55.74
Total Hedged Volumes
2,790,000 3,155,000 2,853,000 2,607,000 5,110,000
Weighted
Average Floor(2) $ 46.56 $ 50.27 $ 48.07 $ 48.36 $ 54.12
Mid-Cush Differential Swaps: 2,390,000 2,730,000
2,760,000 2,760,000 2,555,000 Swap(3) $ (0.47 ) $ (0.42 ) $ (0.42 )
$ (0.42 ) $ (0.29 ) (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) Weighted average floor assumes the long put in three way
collars. (3) 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.
2018 Annual Guidance
RSP anticipates spending $815 to $895 million in development
capital in 2018, generating production growth of 35% at the
midpoint of the production guidance range. At a $50 average oil
price, the Company expects to generate cash flow in excess of
development spending by the fourth quarter and exit the year at
less than 2.0x Net Debt / LTM EBITDAX.
The Company is running seven operated rigs currently, and with
an expected rig addition in April, will target four rigs running in
each basin going forward. RSP is currently running three completion
crews, two full-time and one spot crew, and expects to add a third
full-time crew in May to replace the spot crew. With 19 wells
completed in the first two months of 2018, RSP is off to a strong
start towards its guided range of 100-120 operated completions for
the full year 2018.
The following table summarizes the Company’s guidance for
2018.
2018 Guidance
Completions
Operated Gross Horizontal Completions 100 - 120 Operated Average
Working Interest 89% Midland Basin Average Lateral Length ~8,100'
Delaware Basin Average Lateral Length ~6,300'
Production
Average Daily Production (Boe/d) 72,000 - 78,000 % Oil 70% - 72% %
Natural Gas 12% - 14% % NGLs 15% - 17%
Development Capital
Expenditures ($ in MM)
Drilling and Completion (D&C) $725 - $785 Infrastructure,
Capitalized Workovers & Other $90 - $110 Total Development
Capital Expenditures $815 - $895 % Midland Basin 45% - 55% %
Delaware Basin 45% - 55% % Non-Operated 8% - 10%
Income Statement
($/Boe)
Lease operating expenses (including workovers) $5.00 - $5.50
Gathering and transportation $0.90 - $1.20 Exploration expenses
$0.10 - $0.20 General and administrative - cash component $1.25 -
$1.75 General and administrative - recurring stock comp $0.75 -
$0.95 Depreciation, depletion, and amortization ($/Boe) $12.50 -
$14.50 Production and ad valorem taxes (% of oil and gas revenues)
6.0% - 8.0%
Conference Call
RSP will host a conference call for investors at 9:00 AM Central
Time on Wednesday, February 28, 2017, to discuss fourth quarter and
full-year 2017 results. Hosting the call will be Steve Gray, Chief
Executive Officer, Zane Arrott, Chief Operating Officer, Scott
McNeill, Chief Financial Officer and Alyssa Stephens, Director of
Investor Relations.
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 13676620. The replay will
be available until March 14, 2018. 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 the
Company'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
Three Months Ended Twelve Months Ended (in
thousands, except per share data) December 31, 2017
September 30, 2017 December
31, 2016 December 31, 2017 December 31,
2016 Revenues: (Unaudited) (Unaudited)
(Unaudited) Oil sales $ 218,182 174,624 $ 110,376 $
704,838 $ 321,588 Natural gas sales 9,308 9,661 5,103 36,206 13,945
NGL sales 21,533 17,369 7,455 62,664
18,324
Total revenues 249,023 201,654 122,934 803,708
353,857
Operating expenses: Lease operating expenses 35,205
33,385 16,419 122,893 57,778 Production and ad valorem taxes 16,016
13,281 6,630 48,908 21,615 Depreciation, depletion, and
amortization 77,159 73,408 52,484 279,711 194,360 Asset retirement
obligation accretion 151 151 118 605 472 Impairments of oil and
natural gas properties 52,935 705 579 59,077 4,901 Exploration
expenses 825 1,497 265 7,771 1,093 General and administrative
expenses 11,233 12,120 10,173 47,408 36,170 Acquisition costs 42
30 6,374 4,525 6,374
Total
operating expenses 193,566 134,577 93,042
570,898 322,763
Operating income 55,457 67,077
29,892 232,810 31,094
Other income (expense) Other income,
net 1,021 1,106 1,246 3,436 1,833 Net loss on derivative
instruments (46,968 ) (21,626 ) (17,538 ) (39,279 ) (23,760 )
Interest expense (22,174 ) (21,553 ) (13,683 ) (82,459 ) (52,724 )
Total other expense (68,121 ) (42,073 ) (29,975 ) (118,302 )
(74,651 )
Income (loss) before income taxes (12,664 ) 25,004
(83 ) 114,508 (43,557 ) Income tax benefit (expense) 153,450
(3,678 ) 1,464 117,628 18,706
Net income
(loss) $ 140,786 $ 21,326 $ 1,381 $
232,136 $ (24,851 )
Earnings (loss) per common
share - Basic $ 0.89 $ 0.14 $ 0.01 $ 1.50 $ (0.23 )
Earnings
(loss) per common share - Diluted $ 0.89 $ 0.14 $ 0.01 $ 1.49 $
(0.23 )
Weighted Average Common Shares Outstanding:
Basic 156,874 156,864 128,811 154,162 107,324 Diluted 158,060
157,837 128,811 155,526 107,324
Summary Balance
Sheet
(in thousands) December 31, 2017 December
31, 2016 Cash and cash equivalents $ 38,102 $ 690,776 Other
current assets 111,221 85,486 Total current assets 149,323
776,262 Property, plant and equipment, net 6,080,719 4,129,635
Other long-term assets 40,144 90,530 Total assets $
6,270,186 $ 4,996,427 Current liabilities 206,561
108,269 Long-term debt 1,509,128 1,132,275 Other long-term
liabilities 232,139 338,571 Total stockholders' equity 4,322,358
3,417,312 Total liabilities and stockholders' equity $
6,270,186 $ 4,996,427
Drill-Bit F&D
Costs and Reserve Replacement Ratios
2017
Production (MBoe)
(A) 20,168
Proved Reserves
(MBoe)
Price revisions 3,712 Non-price revisions (B) 14,808 Purchases
47,485 Extensions and discoveries (C) 93,217
Total additions
159,222
Total additions (excluding price
revisions)
(D)
155,510
Costs Incurred
(thousands)
Property acquisition costs Proved $ 339,895 Unproved 1,253,326
Exploration (E) — Development (F) 675,988 Total costs
incurred (G) $ 2,269,209
Drill-Bit F&D
and Reserve Replacement Ratios (1)
Drill-bit F&D ($/Boe) (E+F) / (B+C) $ 6.26 Reserve replacement
ratio (D) / (A) 771 % Organic reserve replacement ratio (C+B) / (A)
536 % (1) Exclude impact of
price revisions.
Use of Non-GAAP Financial
Measures
The Company defines 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 the Company to more effectively evaluate
its operating performance and compare the results of its operations
from period to period without regard to financing methods or
capital structure. The Company excludes the items listed above in
arriving at Adjusted EBITDAX and Adjusted Net Income because these
amounts can vary substantially from company to company within the
Company's 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 the Company’s
financial performance, such as 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. The Company's
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 (Loss) to Adjusted EBITDAX
Three Months Ended Twelve Months Ended (in
thousands) December 31, 2017 September
30, 2017 December 31, 2016 December 31,
2017 December 31, 2016 Net income (loss) $
140,786 $ 21,326 $ 1,381 $ 232,136 $ (24,851 ) Interest expense
22,174 21,553 13,683 82,459 52,724 Income tax expense (benefit)
(153,450 ) 3,678 (1,464 ) (117,628 ) (18,706 ) Depreciation,
depletion, and amortization 77,159 73,408 52,484 279,711 194,360
Asset retirement obligation accretion 151 151 118 605 472
Exploration expenses 825 1,497 265 7,771 1,093 Acquisition costs 42
30 6,374 4,525 6,374 Impairments of oil and natural gas properties
52,935 705 579 59,077 4,901 Loss on derivative instruments 46,968
21,626 17,538 39,279 23,760 Net settled derivative Instruments
(8,566 ) (2,567 ) (2,398 ) (14,661 ) (1,732 ) Stock-based
compensation 4,422 4,361 3,215 17,150 13,764 Other income, net
(1,021 ) (1,106 ) (1,246 ) (3,436 ) (1,833 )
Adjusted
EBITDAX $ 182,425 $ 144,662 $ 90,529 $
586,988 $ 250,326
Reconciliation of
Net Income (Loss) to Adjusted Net Income (Loss)
Three Months Ended Twelve Months Ended (in
thousands) December 31, 2017 September
30, 2017 December 31, 2016 December 31,
2017 December 31, 2016 Net income (loss) $
140,786 $ 21,326 $ 1,381 $ 232,136 $ (24,851 ) Acquisition Costs 42
30 6,374 4,525 6,374 Impairments of oil and natural gas properties
52,935 705 579 59,077 4,901 Loss on derivative instruments 46,968
21,626 17,538 39,279 23,760 Net settled derivative Instruments
(8,566 ) (2,567 ) (2,398 ) (14,661 ) (1,732 ) Stock-based
compensation - non recurring — — — — 682 Other income, net (1,021 )
(1,106 ) (1,246 ) (3,436 ) (1,833 ) Adjustment to income taxes for
above items (181,022 ) (11,827 ) (8,833 ) (188,352 ) (14,659 )
Adjusted Net Income (Loss) $ 50,122 $ 28,187 $
13,395 $ 128,568 $ (7,358 )
View source
version on businesswire.com: http://www.businesswire.com/news/home/20180227006591/en/
RSP Permian, Inc.Scott McNeill, 214-252-2700Chief
Financial OfficerorAlyssa Stephens, 214-252-2764Director, Investor
RelationsorInvestor Relations, 214-252-2790IR@rsppermian.com
RSP PERMIAN, INC. (NYSE:RSPP)
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