RSP Permian, Inc. Announces Second Quarter Financial and Operating Results, Increased 2015 Outlook, and Bolt-on Midland Basin Acquisitions

Aug 03, 2015, 17:33 ET from RSP Permian, Inc.

DALLAS, Aug. 3, 2015 /PRNewswire/ -- RSP Permian, Inc. ("RSP" or the "Company") (NYSE: RSPP) today reported financial and operating results for the quarter ended June 30, 2015, increased its 2015 outlook, and announced bolt-on acquisitions in the core of the Midland Basin.  In addition, the Company filed its Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 with the Securities and Exchange Commission (the "SEC") and posted an updated quarterly presentation on its website at www.rsppermian.com

Second Quarter 2015 Highlights

  • Production increased by 86% to 19.9 MBoe/d as compared to 2Q14, and increased 25% as compared to 1Q15
  • Exit production rate was approximately 24.0 MBoe/d, a 21% increase over 2Q15 average, and a 36% increase over 1Q15 exit rate
  • Adjusted EBITDAX increased by 37% to $72.6 million as compared to 2Q14, and increased by 21% as compared to 1Q15
  • Net loss of $5.5 million, or $0.07 per diluted share. Includes a $31.6 million non-cash loss on derivatives. Adjusted net income, which does not include that item, was $13.0 million, or $0.16 per diluted share
  • Cash operating expenses decreased 30% to $13.58 per Boe as compared to 2Q14, and decreased 7% as compared to 1Q15
  • Accelerated completion activity from prior quarter, completing 18 operated horizontal wells and 11 operated vertical wells during 2Q15 compared to 8 operated horizontal wells and 3 operated vertical wells completed in 1Q15
  • At Johnson Ranch, completed remaining 8 horizontal wells in full development test of 10 upper Wolfcamp wells (5 Wolfcamp A / 5 Wolfcamp B) across a section. Despite early facility limitations, wells are outperforming type curve expectations and providing early confirmation of our spacing pattern
  • Continued strong performance from Wolfcamp A wells with 9 completions to date and average 30-day IPs of 1,104 Boe/d
    • Strongest well to date placed on production in the Spanish Trail area with the Spanish Trail 4827 Wolfcamp A well (6,900' lateral) achieving a 30-day IP of 1,720 Boe/d (84% oil) or 249 Boe/d per lateral foot
  • Began horizontal drilling program in Glasscock County, currently drilling upper Wolfcamp B and lower Wolfcamp B zones on Calverley lease
  • Increasing 2015 outlook - primarily due to strong well performance, additional completions and a small impact from acquired production
    • Increasing mid-point production guidance by 10%, expected to average 19,500 to 20,000 Boe/d or a total production growth target of 64% to 69%
    • Increasing expected oil production mix to 75%, resulting in a 14% increase to expected oil volumes at the mid-point of range
    • Increasing well completions range to 50 – 55 operated horizontal wells as a result of maintaining a fourth horizontal drilling rig and reduced drilling and completion times
    • Maintaining capital expenditure guidance range of $400 million - $450 million

Acquisition Highlights

  • Recently closed acquisitions of, or entered into definitive agreements to acquire, mostly contiguous, bolt-on properties in existing core operating areas in the Midland Basin for an aggregate purchase price of $274 million
  • All acquisitions privately negotiated transactions between RSP and sellers
  • 5,704 surface acres, 27,287 net effective horizontal acres
  • 162 net horizontal locations in five zones (Middle Spraberry, Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp D (Cline)
    • Other prospective formations may provide additional horizontal drilling locations on the acquired properties
  • Average lateral length of acquired horizontal inventory ~7,600'
  • 100% operated, 100% held by production (HBP), average royalty burden only 23%
  • Current production of 1,569 Boe/d
  • Over 85 million Boe resource potential in five target zones with additional upside in other prospective zones

Approximately $65.0 million of the acquisitions have already been completed and funded through a combination of cash on hand and a $50.0 million borrowing under our $500.0 million revolving credit facility.  The remaining acquisitions are expected to close before August 15, 2015, however, these acquisitions are subject to the satisfaction of closing conditions.  There can be no assurance that the Company will close on the remaining acquisitions.  RSP has also offered to purchase other working interest partners in the properties that could increase the aggregate purchase price of the acquisitions by approximately 10-15%.  The Company expects to finance the purchase price of the remainder of the acquisitions with borrowings under its current revolving credit facility, or, to the extent the Company deems market conditions favorable, the proceeds of one or more capital markets transactions. RSP is in preliminary discussions with its lenders under its credit facility and expects to receive a 20% increase in its borrowing base substantially concurrent with the closing of these transactions, although the increase is not dependent on the closing of the acquisitions.

Steve Gray, Chief Executive Officer, commented, "We are pleased to announce our second quarter results, highlighted by strong growth from our acceleration of completion activity from last quarter and continued strong well performance.  Additionally, we are excited to announce several contiguous, bolt-on acquisitions that are located in the core of our current operating areas.  They add highly prospective horizontal acreage that fits perfectly with our existing assets, operations, infrastructure and current horizontal drilling plans.  In addition, as a result of our continued strong well performance and increased number of completions, we are raising our total production forecast 10% and, as a result of a higher oil mix, our total oil volumes by 14%."

Summary Financial Results

Actual

Three Months Ended

June 30,

2015

2014

(In thousands, except for per share data)

Total Revenues

$78,465

$74,062

  Net Cash from Derivative Instruments

18,646

____(2,161)

  Adjusted Total Revenues

$97,111

$71,901

Adjusted EBITDAX (1)

$72,552

$53,085

Adjusted Net Income (1)

$13,046

$17,029

  Adjusted Net Income per Common Share - Diluted

$0.16

$0.23

Net Income (loss)

$(5,453)

$8,226

  Net Income (loss) per Common Share - Diluted

$(0.07)

$0.11

(1)

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

For the quarter ended June 30, 2015, total revenues, excluding the revenue impact from realized derivative instruments, were $78.5 million, a 6% increase over the prior year quarter of $74.1 million.  Adjusted total revenues, including the net cash from derivative instruments, was $97.1 million, an increase of 35% over the prior year quarter of $71.9 million.  Adjusted EBITDAX for the second quarter was $72.6 million, an increase of 37% over the prior year quarter of $53.1 million.  Adjusted net income for the second quarter was $13.0 million, or $0.16 per diluted share, a 24% decrease from the prior year quarter of $17.0 million.  Adjusted net income for the second quarter of 2015 and 2014 excluded an unrealized loss on derivative instruments of $31.6 million and $13.8 million, respectively.

Operational Update

The Company operated four horizontal drilling rigs during the second quarter and drilled thirteen operated horizontal wells.  In addition, RSP drilled one vertical well before dropping its last vertical rig.  During the course of the quarter, RSP employed two horizontal completion crews and one vertical completion crew to complete newly drilled wells as well as work off the backlog of wells that were carried over from the prior quarter. In total, RSP completed eighteen operated horizontal wells and eleven operated vertical wells, up from eight operated horizontal wells and three operated vertical wells in the prior quarter.  RSP completed four horizontal wells targeting the Lower Spraberry, eight horizontal wells targeting the Wolfcamp A and six horizontal wells targeting the Wolfcamp B. 

At the end of the second quarter, RSP had eleven operated horizontal wells and five operated vertical wells awaiting completion activities down from sixteen operated horizontal wells and fifteen operated vertical wells at the end of last quarter.  RSP expects to complete its remaining backlog of horizontal and vertical wells by the end of the third quarter.

For the second half of 2015, RSP anticipates operating four horizontal rigs with three of the drilling rigs under contract and one horizontal rig operating on well by well arrangement enabling the Company flexibility to drop the fourth rig. 

2Q15 Wells

Drilled

Completed

Waiting On Completion

Operated Wells

Horizontal

13

18

11

Vertical

1

11

5

Non-Operated Wells

Horizontal

14

11

12

Vertical

3

3

0

The Company finished drilling and completion activity on its Johnson Ranch pilot program, where RSP drilled and completed a staggered upper Wolfcamp pattern to test the spacing design of ten horizontal wells across a section, five in the Wolfcamp A and five in the Wolfcamp B.  The Company placed on production the remaining eight wells completed during the quarter and all ten wells of the pilot program are currently producing.   

Zane Arrott, Chief Operating Officer stated, "We are pleased with the strong early production rates of our upper Wolfcamp wells in our Johnson Ranch pilot program. In particular, we are very encouraged by our Wolfcamp A wells, which from early results, have been some of our highest rate of return wells.  This density test will help us better understand our lateral spacing assumptions and how we can optimize our future spacing to ensure we recover the maximum value of our resources under a full development scenario. We plan to monitor the operational performance of these wells over a longer time period before making any changes to our current spacing or ultimate recovery assumptions.  These wells were choked back in early production due to facility limitations but are currently tracking on or above our type curves and are on pace to generate cumulative production volumes above our expectations.  Importantly, the wells drilled the closest together are not showing any interference and performing as well as, or better than, the average of all the wells in the pilot."

Quarterly Operational Results

Three Months Ended June 30,

2015

2014

Production data:

Oil (MBbls)

1,377

687

Natural gas (MMcf)

1,029

712

NGLs (MBbls)

260

169

Total (MBoe)

1,809

975

Average net daily production (Boe/d)

19,879

10,714

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

Oil (per Bbl)

$53.68

$96.26

Natural gas (per Mcf)

1.97

4.38

NGLs (per Bbl)

9.69

28.47

Total (per Boe)

$43.37

$75.96

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

Oil (per Bbl)

$67.22

$93.12

Natural gas (per Mcf)

1.97

4.38

NGLs (per Bbl)

9.69

28.47

Total (per Boe)

$53.68

$73.74

Average costs (per Boe):

Lease operating expenses (excluding gathering and transportation)

$7.63

$8.55

Gathering and transportation

0.49

0.97

Production and ad valorem taxes

2.99

6.12

Depreciation, depletion and amortization

21.90

22.29

General and administrative – recurring cash component

2.47

3.66

General and administrative – recurring stock comp (3)

1.14

0.67

General and administrative – IPO stock comp (4)

0.19

1.03

(1)

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

(2)

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

(3)

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

(4)

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

Production volumes for the quarter ended June 30, 2015 averaged 19,879 Boe/d or a total of 1,809 MBoe, an increase of 86% over prior year's first quarter of 10,714 Boe/d.  Production for the second quarter of 2015 was comprised of 76% crude oil, 14% NGLs and 10% natural gas.  RSP's average realized commodity price for the second quarter of 2015, before the effects of hedges, was $43.37. RSP's average realized oil price for the second quarter of 2015, before the effects of hedges, was $53.68, a negative $4.26 differential compared to NYMEX WTI pricing for the same period, or 93% of NYMEX WTI pricing. RSP's average realized natural gas price for the second quarter of 2015, before the effects of hedges, was $1.97, a negative $0.68 differential compared to NYMEX Henry Hub pricing for the same period, or 74% of NYMEX Henry Hub pricing.  Per unit cash operating expenses excluding interest expense but including lease operating expense, gathering and transportation, production and ad valorem taxes and recurring cash general and administrative expenses were $13.58 per Boe, a 30% decrease from prior year's comparable quarter and a 7% decrease from the prior quarter.

Capital Expenditures

RSP's capital expenditures for the quarter ended June 30, 2015 totaled $147.0 million which included approximately $134.9 million of drilling and completion and $12.1 million of infrastructure and other.  Approximately 15% of total capital expenditures were on non-operated properties. 

Liquidity Update

As of June 30, 2015, the Company had no borrowings on its revolving credit facility, which has a $500 million borrowing base, and had $44.1 million of cash on hand, for total liquidity available of $543.5 million.  Subsequent to quarter end, the Company borrowed approximately $50.0 million to close on certain of the previously discussed acquisitions.  RSP is in discussions with its lenders under its revolving credit facility and expects its borrowing base to increase 20% substantially concurrent with the closing of the pending acquisitions, although the increase is not dependent on the acquisitions.

Hedging

For the remainder of 2015, the Company has floors in place for 996,000 barrels of oil production at a blended floor of $85.57, along with swaps covering 60,000 barrels of oil production at a price of $92.60.  The Company entered into new commodity price hedging contracts for 2016, entering into three way collars covering 555,000 barrels of oil production at a blended floor price of $55.00, a blended ceiling price of $74.08, and a short-put price of $45.00.

Description & Production Period

Volume (Bbls)

Weighted Average Floor price ($/Bbl) (1)

Weighted Average Ceiling price ($/Bbl) (1)

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

Weighted Average Swap price ($/Bbl) (1)

Crude Oil Swaps:

July 2015 - December 2015

60,000

--

--

--

$92.60

Crude Oil Collars:

July 2015 - December 2015

816,000

$85.70

$94.71

--

--

July 2015 - September 2015

90,000

$85.00

$92.60

--

--

October 2015 - December 2015

90,000

$85.00

$92.33

--

--

January 2016 - March 2016

75,000

$55.00

$72.00

$45.00

--

January 2016 - December 2016

480,000

$55.00

$74.41

$45.00

--

(1)

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

Updated 2015 Guidance

RSP is increasing its expected average daily production to a range of 19,500 - 20,000 Boe per day due to strong well performance, additional completions and a small impact from acquired production.  Additionally, expected oil production mix increases to 75%, resulting in a 14% increase to expected oil volumes at the mid-point of range.  RSP expects to complete 50 - 55 gross operated horizontal wells in 2015 targeting primarily the Lower Spraberry, Wolfcamp A and Wolfcamp B, the Company's highest return horizontal zones.  In addition, the Company expects to complete approximately 20 gross operated vertical wells during the year.  Despite the increase in completions, RSP is maintaining its $400-$450 million capital budget for 2015, of which RSP expects to spend $380-420 million on drilling and completion activities and $20-30 million on infrastructure and other. The Company believes that non-operated expenditures in 2015 will represent approximately 15% of total expenditures.

YTD 2015

2015

Actual

Guidance

 

Operated Horizontal Completions

26

50 - 55

 

Average Daily Production (Boe/d)

17,923

19,500 -20,000

% Oil

76%

74% - 76%

% Natural Gas

10%

10% - 12%

% NGLs

14%

13% - 15%

Operating Costs

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

$7.89

$7.25 - $7.75

Gathering and transportation ($/Boe)

$0.53

$0.50 - $0.55

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

7.4%

7.0% - 7.4%

Depreciation, depletion, and amortization ($/Boe)

$21.92

$20.00 - $24.00

Exploration expenses ($/Boe)

$0.64

$0.40 - $0.50

G&A expenses

     General and administrative – cash component ($/Boe)

$2.68

$2.25 - $2.75

     General and administrative – recurring stock comp ($/Boe)

$1.15

$1.10 - $1.15

     General and administrative – non-recurring IPO stock comp ($/Boe)

$0.25

$0.19 - $0.21

Second Quarter Earnings Release and Conference Call

RSP will host a conference call for investors at 10:00 a.m. Central Time on Tuesday, August 4, 2015 to discuss second quarter 2015 results.  Hosting the call will be Steve Gray, Chief Executive Officer, Zane Arrott, Chief Operating Officer and Scott McNeill, Chief Financial Officer.

The call may be accessed live over the telephone by dialing (877) 705-6003, or for international callers, (201) 493-6725.  A replay will be available shortly after the call and can be accessed by dialing (877) 870-5176, or for international callers (858) 384-5517. The passcode for the replay is 13599596.  The replay will be available until August 18, 2015. 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 Basin, a sub-basin of the Permian Basin, primarily in the adjacent counties of Midland, Martin, Andrews, Dawson, Ector and Glasscock.  The Company's common stock is traded on the NYSE under the ticker symbol "RSPP."  For more information, visit www.rsppermian.com.

Forward-Looking Statements

This news release contains forward-looking statements within the meaning of the federal securities laws. All statements, other than historical facts, that address activities that RSP assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. Forward-looking statements are based on management's current beliefs, based on currently available information, as to the outcome and timing of future events. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of RSP. Information concerning these risks and other factors can be found in RSP's filings with the SEC, including its Form 10-K and our most recent Quarterly Report 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.

Use of Non-GAAP Financial Measures

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

Management believes Adjusted EBITDAX and adjusted net income are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above in arriving at Adjusted EBITDAX and adjusted net income because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX and adjusted net income should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX and adjusted net income are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX and adjusted net income may not be comparable to other similarly titled measures of other companies.

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

 Three Months Ended June 30,

 Six Months Ended June 30,

2015

Actual

2014

 Actual

2015

 Actual

2014

 Actual

2014

Pro Forma

Revenues:

  Oil sales

$73,917

$66,134

$121,222

$117,606

$122,065

  Natural gas sales

2,028

3,117

4,261

5,323

5,514

  NGL sales

2,520

4,811

4,356

8,892

9,228

           Total revenues

$78,465

$74,062

$129,839

$131,821

$136,807

Net cash from derivative instruments

18,646

(2,161)

48,117

(2,766)

(2,766)

Adjusted Total Revenues

$97,111

$71,901

$177,956

$129,055

$134,041

Operating expenses:

  Lease operating expenses

14,693

9,279

27,304

16,342

17,036

  Production and ad valorem taxes

5,402

5,964

9,599

9,840

10,091

  General and administrative expenses

4,464

3,573

8,693

8,574

5,344

           Total operating costs and expenses

$24,559

$18,816

$45,596

$34,756

$32,471

Adjusted EBITDAX (2)

$72,552

$53,085

$132,360

$94,299

$101,570

  Depreciation, depletion, and amortization

39,620

21,734

71,121

38,096

41,728

  Asset retirement obligation accretion

84

38

168

66

76

  Exploration

889

1,233

2,067

1,989

1,989

  Interest expense

9,367

1,142

18,683

2,272

2,272

  Stock-based compensation, net

2,401

1,665

4,543

13,680

952

Adjusted income before income taxes

$20,191

$27,273

$35,778

$38,196

$54,553

Adjusted income tax expense

7,145

10,244

12,697

14,866

19,639

Adjusted net income (2)

$13,046

$17,029

$23,081

$23,330

$34,914

  Adjusted net income per common share - Basic

$0.16

$0.23

$0.28

$0.34

$0.48

  Adjusted net income per common share - Diluted

$0.16

$0.23

$0.28

$0.34

$0.48

Other items included in income before taxes:

  Non-cash (loss) on derivatives, net

($31,608)

($13,797)

($48,748)

($17,345)

($17,345)

  Other income

(37)

(302)

161

8

8

Income (loss) before income taxes

($18,599)

$2,930

($25,506)

$5,993

$17,577

Income tax (benefit) expense

($13,146)

($5,296)

($19,028)

$125,296

($6,241)

Net Income (loss)

($5,453)

8,226

($6,478)

($119,303)

$23,818

  Net income (loss) per common share - Basic

($0.07)

$0.11

($0.08)

($1.76)

$0.33

  Net income (loss) per common share - Diluted

($0.07)

$0.11

($0.08)

($1.76)

$0.33

Weighted Average Common Shares Outstanding:

Basic

83,088

72,500

80,639

67,702

72,500

Diluted

83,088

72,500

80,639

67,702

72,500

(1)

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

(2)

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

Summary Balance Sheet

June 30, 2015

December 31, 2014

(in thousands)

Cash and cash equivalents

$44,055

$56,292

Other current assets

95,009

117,450

Total current assets

139,064

173,742

Property, plant and equipment, net

2,271,288

2,094,618

Other long-term assets

23,301

21,587

Total assets

$2,433,653

$2,289,947

Current liabilities

116,015

130,041

Long-term debt

500,000

500,000

Other long-term liabilities

348,539

334,135

Total stockholders'/members' equity

1,469,099

1,325,771

Total liabilities and stockholders'/members' equity

$2,433,653

$2,289,947

 

SOURCE RSP Permian, Inc.



RELATED LINKS

http://www.rsppermian.com