rsp permian investor presentationfilecache.drivetheweb.com/mr5ir_rsppermian/108/download/rsp... ·...

RSP Permian Investor Presentation

August 2014

2

Forward-Looking Information

Certain statements and information in this presentation may constitute “forward-looking statements” within the meaning of the Private

Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or

other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-

looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While

management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future

developments affecting us will be those that we anticipate. Our forward-looking statements involve significant risks and uncertainties (some

of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our

present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking

statements include, but are not limited to, the volatility of commodity prices, product supply and demand, competition, access to and cost of

capital, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions

underlying production forecasts, the quality of technical data, environmental and weather risks, including the possible impacts of climate

change, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the costs and

results of drilling and operations, the availability of equipment, services, resources and personnel required to complete the Company’s

operating activities, access to and availability of transportation, processing and refining facilities, the financial strength of counterparties to

the Company’s credit facility and derivative contracts and the purchasers of the Company’s production, and acts of war or terrorism.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see

our filings with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2013 and our Quarterly Report on

Form 10-Q for the quarter ended June 30, 2014.

Existing and prospective investors are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date

hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a

result of new information, future events or otherwise.

3

Corporate Overview

4

RSP OverviewMarket Snapshot Permian Basin Pure Play

Pro Forma Production and Reserves(3)

___________________________(1) As of August 13, 2014. (2) Balance as of June 30, 2014, adjusted for primary equity offering priced August 7, 2014.(3) Pro forma reserves give effect to the formation transactions described in 10-K and 10-Q. Reserves per independent reserve report prepared by Ryder Scott as of 12/31/13, plus management’s estimate of reserves for the pending acquisitions announced July 25, 2014.(4) Average daily production for quarter ended June 30, 2014.

NYSE Symbol: RSPP

Market Cap(1): ~$2.1 billion

Net Debt(2): ~$0.0 billion

Enterprise Value: ~$2.1 billion

Acreage Summary

Average Daily Production (4) 10.7 MBoe/d

Proved Reserves 76.1 MMBoe

% Oil 59%

% NGL 21%

% Natural Gas 20%

% Proved Developed 31%

TX

Focus Areas

Dawson Area

Pending Acquisitions

Effective Horizontal Acreage

Gross Net

Middle Spraberry 53,306 38,370

Lower Spraberry 59,824 44,242

Wolfcamp A 40,015 26,834

Wolfcamp B 53,404 38,314

Wolfcamp D 44,077 30,691

Total Horizontal Acreage 250,626 178,450

Surface Acreage 63,035 46,738

5

Q2 2014 Financial UpdateFinancial Update

Pro Forma Results (1)(2)

___________________________(1) Please see reconciliation of Adjusted EBITDAX and Adjusted Net Income.(2) Pro forma results include formation transactions as described in 10-K and 10-Q.

18%

During Q2 2014, production averaged approximately 10.7 MBoe/d, a production increase of ~15% over Q1 2014 and an increase of ~43% over Q2 2013

RSP generated ~$54mm of pro forma Adjusted EBITDAX and ~$19mm of pro forma Adjusted Net Income in Q2 2014(1)

2,807

5,089

7,293

9,339

10,714

0

2,000

4,000

6,000

8,000

10,000

12,000

2011 2012 2013 Q1 2014 Q2 2014

Boe/d

Oil (Bbl/d) Natural Gas (Mcf/d) NGL (Bbl/d)

Net Daily Production (2)

RSP Permian, Inc.

Q2 2014 Pro Forma Q1 2014 Pro Forma

Avg Daily Production

Oil (Boe/d) 7,549 6,597

Natural Gas (Mcf/d) 7,824 6,904

NGL (Boe/d) 1,857 1,592

Total (Boe/d) 10,714 9,339

Avg Realized Prices

Oil (per Bbl) $96.26 $94.21

Natural Gas (per Mcf) 4.38 3.86

NGLs (per Bbl) 28.47 30.82

Total (per Boe) $75.96 $74.65

Total Revenues ($MM) $74.1 $62.7

Adjusted EBITDAX ($MM) 53.7 48.7

Adjusted Net Income ($MM) 18.5 17.0

Cash Expenses per Boe ($ / Boe)

LOE & Gathering/Transportation $9.52 $9.23

Production & Ad Valorem 6.12 4.91

G&A 4.34 2.46

2,807

5,089

7,2937,837

9,339

10,714

0

2,000

4,000

6,000

8,000

10,000

12,000

2011 2012 2013 Q4 2013 Q1 2014 Q2 2014

Boe/d

Vertical Production Horizontal Production

6

Contiguous Acreage in the Core of the Midland Basin

Overview RSP’s Acreage in the Midland Basin

Track Record of Production Growth

Large, contiguous, core acreage in the Midland Basin(1)

Permian pure-play with 63,035 gross (46,738 net) acres

Over 178,000 net “effective horizontal acres”(2)

Low-risk, oil-rich base with rapid growth potential

Proved reserves: 76.1 MMBoe; 59% oil, 21% NGLs, 20% natural gas(3)

Focus on horizontal drilling to maximize returns

Four current horizontal rigs going to five in late Q4 2014 and six during Q1 2015

RSP has participated in more than 75 horizontal wells (>35 operated)

Large inventory of identified drilling locations(1)

1,760 horizontal and 1,241 vertical drilling locations

___________________________(1) Includes Midland Basin acquisitions announced in July 2014. (2) Combined horizontal acreage position that management believes is prospective for hydrocarbon production across each target horizontal zone. (3) 12/31/2013 Ryder Scott reserve report, plus management’s reserve estimates for pending acquisitions announced July 25, 2014.(4) Based on Q2 2014 production of 10,714 Boe/d.

99%

1%

79%

21%

68%

32%

85%

15%

46%

54%

11,820 (1)

Acquired Production

TX

Focus Areas

Dawson Area

Pending Acquisitions

7

Acquisitions Increase RSP’s Drilling Inventory in Core of Midland Basin

Midland Basin Acquisitions Acquisitions Map

In Q1 2014, RSP completed $79 million of acquisitions adding 5,316 net acres and > 280 horizontal locations and >150 vertical locations based on 20-acre spacing

In July 2014, RSP entered into agreements to purchase primarily undeveloped acreage in Glasscock County for an aggregate price of ~$259 million

7,680 gross / 6,652 net surface acres

21,440 gross / 19,367 net effective horizontal acres

188 gross / 156 net horizontal locations with average lateral length >6,500’

316 gross / 264 net vertical locations on 20-acre spacing

Current net production of approximately 1,106 Boe/d (74% liquids) with only 13 vertical wells drilled to date

Net proved reserves of 22 MMBoe (9% developed)(1)

The July pending acquisitions are a significant bolt-on to RSP’s existing Glasscock acreage position, adding another primary operating area in the core of the Midland Basin

___________________________(1) Proved reserves of the assets to be acquired in the Pending Acquisitions is based solely on our internal evaluation and interpretation of reserve and

other information provided to us by the sellers of those assets in the course of our due diligence with respect to the Pending Acquisitions and has not been independently verified or estimated by our independent petroleum engineers or any other party.

Net Acreage (Focus Areas)

20,000

25,000

30,000

35,000

40,000

500

600

700

800

900

1,000

Net Hz Locations (Focus Areas) Net Vertical Locations

200

400

600

800

1,000

+23%

+20%+47%

Significant Undeveloped Inventory – Pending Acquisitions

Pending Acq.

RSPP Prior to

Acq.

Pending Acq.Pending

Acq.

RSPP Prior to

Acq.

RSPP Prior to

Acq.

Surface Horizontal Locations

Acreage Acreage LS WA WB WD Total Hz 40-acre 20-acre Total Vt

Gross 7,680 21,440 63 41 38 46 188 158 158 316

Net 6,652 19,367 52 34 33 37 156 132 132 264

In 6 months since IPO, announced ~$340 million of acquisitions, increasing locations and net acres

by ~50% and ~38%, respectively

TX

Dawson Area

Pending Acquisitions Acreage

1Q 2014 Acquisitions Acreage

Pending

Acquisitions of

6,652 Net Acres

Focus Areas

8

Pending Acquisitions Create Another Primary Operating Area for RSP

Pioneer

“Houston Ranch 1H,10H,11H”

Permitted Locations

Apache

“Shackelton 31W #3H” (Wolfcamp)

Permitted Location - ~4,900’ Lateral Length

Athlon

“Wilkinson 31 #8H” (Wolfcamp A)

30-day IP: 1,562 Boe/d – 69% Oil

7,132’ Lateral Length

Athlon

“Lawson 2703H” (Wolfcamp A)

30-day IP: 983 Boe/d – 76% Oil


Athlon

“Buckner 9H/10H” (Wolfcamp)

Permitted Locations

Laredo

“Lane Trust C/E 42-2HL” (Wolfcamp C)

30-day IP: 1,406 Boe/d – 79% Oil


“Lane Trust C/E 421HU” (Wolfcamp A)

30-day IP: 1,391 Boe/d – 76% oil


Pioneer

“E.T. O’Daniel #1H” (Wolfcamp B)

24-hr IP: 2,801 Boe/d – Cum: 165 Mboe

9,229’ lateral length

“E.T. O’Daniel #2H” (Wolfcamp D / Cline)

24-hr IP: 3,156 Boe/d – Cum: 128 MBoe


Pioneer

“Flanagan 14 Lloyd A #21H”

(Lower Spraberry)



Pioneer

“Flanagan 14 Lloyd B #1H” (Wolfcamp B)

24-hr IP: 1,460 Boe/d


Hunt

“Boone-Coffee 1HB, 2HB

Permitted Locations

BTA

“Cox Unit” 4 Permitted Locations

~6,900’ Planned Lateral Lengths

OXY

“Powell Ranch 151HC” Permitted Location

4,888 Planned Lateral Length

Energen

“Daniel Lease”

11 Permitted Locations

Pioneer

“Shackleford Unit

Permitted Locations

Apache

Cleveland Lease

2 Permitted Locations

Energen

Llano Lease

Permitted Locations

Glasscock

Midland

Existing RSP Permian acreage

Pending Acquisitions acreage

Acquisition Acreage Offset by Significant Industry Activity

___________________________Source: Texas Railroad Commission and investor presentations.

9

Asset Overview

10

RSP’s Focus Areas Are in the Most Prolific Areas of the Midland Basin

Midland Basin Historical Oil Production Heat MapRSP’s Acreage

Source: IHS Enerdeq, best-month oil production for wells completed between 1/1/2008 and 5/1/2014.

TX

Red dots indicate the most prolific oil production in the basin

Borden

Focus Areas

Dawson Area

Best-month oil

production (bbl)

>6,000

4,000-6,000

3,000-4,000

2,000-3,000

1,000-2,000

<1,000

TX

Focus Areas

Dawson Area

Midland Basin

Clearfork

Upper Spraberry

Middle Spraberry

Jo Mill

Lower Spraberry

Dean

Wolfcamp A

Wolfcamp B

Wolfcamp C

Wolfcamp D (Cline)

Strawn

Atoka

Mississippian

Industry Horizontal Drilling Targets

11

Leader in Multiple Pay Zones in the Midland Basin

RSP Success / Industry Commentary

RSP Permian and other industry players have unlocked multiple target zones for horizontal drilling

Formations highlighted in blue are RSP Target Horizontal Zones

___________________________Source: Texas Railroad Commission and investor presentations.

RSP successfully drilled and completed the first horizontal well targeting the Middle Spraberry

RSP successfully drilled and completed the first horizontal well targeting the Lower Spraberry

RSP recently drilled its first Wolfcamp A well with 30-day IP of 928 Boe/d

Among the first operators in the core of the Midland Basin to successfully drill and complete a horizontal well targeting the Wolfcamp B

Pioneer recently announced Cline wells with 24-hr IPs of 3,605 Boe/d, 3,156 Boe/d, 2,128 Boe/d and 1,509 Boe/d. RSP plans to process and evaluate two recent 3D seismic acquisitions prior to further drilling in the Wolfcamp D

12

Current Activity – Focused on Capital EfficiencyOperations Update

Currently operating two vertical rigs

Currently operating four horizontal rigs (4th operated horizontal rig arrived in April 2014)

Two pilot wells in Dawson scheduled for first production in Q3

Lower Spraberry and Wolfcamp B wells are in early flow-back stage

Six “dual well/dual zone” pads on production

Six “dual well/dual zone” pads currently drilling or completing

During remainder of 2014, all horizontal rigs will be drilling on multi-well/multi-zone pads

~90% will be long horizontals

Lower Spraberry wells and short (~5,000’) lateral Wolfcamp B wells significantly outperforming expectations

Updated type curves and reduced capital have increased expected IRR’s

Activity Map

Midland

Martin

Ector

Dawson

TX

Andrews

Parks Bell 3909

Fendley 404

Headlee 3505Kemmer 4210

Spanish Trail 217

Morgan 3601

Cross Bar Ranch 3025

Cross Bar Ranch 2017

Cross Bar Ranch 1717 Johnson Ranch 912

Wolfcamp B

Wolfcamp D (Cline)

Wolfcamp A

Lower Spraberry

Middle Spraberry

Hz Rig Location

Currently Drilling /

Completing

Headlee 3911

Johnson Ranch 1018

13

Accelerating Production Growth Through Horizontal Program RSP has grown production at a >70% CAGR since its inception, excluding sales and acquisitions RSP’s horizontal focus is driving recent production growth and future anticipated increases Although RSP is currently running four horizontal rigs, production from 3rd horizontal rig only recently began and

production from 4th horizontal rig will arrive in Q3 2014 RSP plans to bring in a 5th horizontal rig at the end of 2014 and a 6th horizontal rig in Q1 2015

Significant Production Growth Since IPOHorizontal Production Driving Growth

–

1,000

2,000

3,000

4,000

5,000

6,000

Jun-12 Sep-12 Dec-12 Mar-13 Jun-13 Sep-13 Dec-13 Mar-14 Jun-14

Ne

t B

oe

/d

First Test Wells

Hz Drilling Ramp (1 full-time rig)

2nd operated Hz rig

3rd operated Hz rig

(January)

4th operated Hz rig (April)

• Production from 4th Hz Rig starts to come online in Q3 2014

• 2H of 2014 will reflect production from all 4 Hz rigs, as the number of Hz wells POP expected to “catch-up” to the higher rig count

• Adding a 5th & 6th Hz rig at the end of 2014 and Q1 2015

• Anticipating ~25 Hz Completions in 2H 2014

___________________________

(1) Production of the assets to be acquired in the Pending Acquisitions is based solely on our internal evaluation and interpretation of reserve and other information provided to us by the sellers of those assets in the course of our due diligence with respect to the Pending Acquisitions and has not been independently verified or estimated by our independent petroleum engineers or any other party.

8,155

9,339

10,714

1,106

11,820

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

Stated Production at

IPO

Bo

e/d

Current Production(incl. acq.):

11,820

Q1 2014

Q2 2014

11,500 -12,000

2014 Guidance

RSP’s current production including acquisitions would be ~45% higher than stated production at IPO in January 2014, primarily via organic

growth

Q3 2013

Plus: Pending Acquisition Production

IPO

1,760

3,001

320

373

267

227

298

92

91

92

438

803

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

2,750

3,000

3,250

MiddleSpraberry

LowerSpraberry

Wolf A Wolf B Wolf D(Cline)

Total TargetHorizontalLocations

Vertical 40-Acre

Spacing

Vertical 20-Acre

Spacing

TotalLocations

76

32

1

3

0

2

4

6

8

2011 2012 2013 2014___________________________Note: As of June 30, 2014. Dawson area Wolfcamp locations categorized as “Wolfcamp A/B” and included in Wolfcamp B locations. Excludes Clearfork, Strawn, Atoka, and any other horizontal zones. 1) Focus Areas Includes locations from Midland Basin acquisitions announced in July 2014. 2) EUR reflects 7,000’ lateral type curve. Lack of production history in the Wolfcamp D (Cline) horizontal wells on RSP acreage. RSP will continue to monitor well results in assessing the Company’s EURs and resource potential.

14

Extensive Multi-Year Drilling Inventory with Strong Rates of Return

Identified Horizontal LocationsIdentified Vertical

LocationsHighlights

Multi-year inventory of horizontal and vertical drilling projects

Multiple stacked pay zones beneath concentrated acreage position

Focus Areas (1) Dawson Area

Peak Operated Horizontal Rigs

2 2

4

7

1

5

0

2

4

6

8

2012 2013 2014 2015

Peak Operated Vertical Rigs

Operated horizontal locations booked as 5 wells across a section in Wolfcamp

(~1,100’ spacing) and 7 wells across a section in Spraberry (~750’ spacing)

Currently running 4 rigs; Adding 5th rig in late Q4 2014

Net Locations:

Focus Areas(1)

202 248 159 145 191 946 333 509 1,788Dawson 67 66 - 67 - 201 - - 201

Total Net Locations: 270 315 159 212 191 1,147 333 509 1,989

EUR(2)

615 665 665 665 NAAvg. Lat. Length 6,748' 6,722' 6,627' 6,738' 6,727' 6,719'

Currently running 2 rigs; 3rd rig operating on pending

Glasscock acreage

Shift from Vertical Drilling to Horizontal Development

15

Large, Concentrated Acreage Blocks Provide Operating Advantages Large, Concentrated Acreage Blocks Map of Focus Areas

RSP leasehold positioned for horizontal development

North to South blocked-up position, which lays out ideally for horizontal drilling, given desired frac planes

Ability to drill long horizontal wells without having to rely on participation by industry players

Ability to drive down costs:

Sharing infrastructure and other critical drilling resources (water, disposal) across leasehold

Rig efficiencies of staying in one location to execute pad drilling on multi-zone horizontal development

Average lateral length of our target horizontal locations is ~6,700 ft (>70% will be long laterals)

Vast majority of operated horizontal wells to date have been drilled on multi-well pads

16

1717 WB

1717 WA

WA

WB

150’

325’

Gun Barrel View

Map of Cross Bar Ranch 1717

1717WA – 30-day IP: 928 Boe/d (~84% oil)

1717WB – 30-day IP: 867 Boe/d (~88% oil)

Treating pressures during zipper frac indicated wells are not in communication

Strong early results have significant implications for future spacing patterns

Cross Bar Ranch 1717H Wolfcamp A/B Pilot

Cross Bar Ranch 1717H Production History (1)

Wolfcamp A/B Spacing Pilot – Encouraging Early Results

100

1000

0 30 60 90 120 150 180

Wolfcamp A Wolfcamp B Wolfcamp A/B 7,000' Type Curve

Bo

e/d

665 MBOE (7,000’ lateral)

7,107’6,955’

___________________________(1) As estimated by Ryder Scott, our estimated average EURs from our Wolfcamp B PUD horizontal drilling locations as of 12/31/13 average 524 MBoe (approximately 70% oil, 16% NGLs and 14% natural gas) and have an average

assumed lateral length of approximately 6,000 feet.

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

0 30 60 90 120 150 180 210 240 270 300

Wolfcamp A/B 7,000' Lateral Type CurveAverage Operated Wolfcamp WellsCross Bar Ranch 1717 WA

17

Wolfcamp A/B Horizontals Continue to Exceed ExpectationsRSP Activity Wolfcamp A/B Cumulative Production (1)

Wolfcamp A/B Type Curve and Operated Well Production (1)

100

1,000

0 30 60 90 120 150 180 210 240 270 300Wolfcamp A/B 7,000' Lateral Type Curve Average Operated Wolfcamp Wells Cross Bar Ranch 1717 WA

Bo

e/d

12 operated Wolfcamp A/B wells on production, with 5 more drilling / completing

24 additional non-operated producing wells

RSP’s first Wolfcamp A well, Crossbar Ranch 1717WA, recently came on production and continues to outperform RSP’s type curves

Wolfcamp A/B results continue to exceed predicted type curves and reflect strong economics

665 MBOE

First Wolfcamp A Well Crossbar Ranch 1717WA:

Drilled on a Wolfcamp A/B Pad (~7,100 lateral)

Average Wolfcamp wells tracking higher than RSP

projected type curves

Bo

e

7,000' Lateral Per 1,000'

MBOE ~665 ~95

MBO ~475 ~68

W.C. A/B

___________________________Note: Production data normalized for a 7,000’ lateral and operational downtime. As of June 2014.(1) As estimated by Ryder Scott, our estimated average EURs from our Wolfcamp B PUD horizontal drilling locations as of 12/31/13 average 524 MBoe (approximately 70% oil, 16% NGLs and 14% natural gas) and have an average


18

Lower Spraberry Results Also Exceeding ExpectationsRSP Activity Lower Spraberry Cumulative Production (1)

Lower Spraberry Type Curve and Operated Well Production (1)

100

1,000

0 30 60 90 120 150 180Lower Spraberry 7,000' Lateral Type Curve Average Operated Lower Spraberry Wells

Bo

e/d

7 operated Lower Spraberry wells producing, with 4 more drilling / completing

1 additional non-operated producing well

Results from the Lower Spraberry have exceeded RSP’s type curve estimates on both long and short laterals

RSP has drilled more Lower Spraberry wells than any other operator in the Permian Basin 0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

0 30 60 90 120 150 180

Lower Spraberry 7,000' Lateral Type Curve

Average Operated Lower Spraberry Wells

665 MBOE

Lower Spraberry wells performing well above

the type curve

Bo

e


MBOE ~665 ~95

MBO ~475 ~68

L.S.

___________________________Note: Production data normalized for a 7,000’ lateral and operational downtime. As of June 2014.(1) As estimated by Ryder Scott, our estimated average EURs from our Lower Spraberry PUD horizontal drilling locations as of 12/31/13 average 652 MBoe (approximately 65% oil, 19% NGLs and 16% natural gas) and have an average


19

Early Middle Spraberry Results Reflect PotentialRSP Activity Middle Spraberry Cumulative Production (1)

Middle Spraberry Type Curve and Operated Well Production (1)

100

1,000

0 30 60 90 120 150 180Middle Spraberry 7,000' Lateral Type Curve Average Operated Middle Spraberry Wells

Bo

e/d

3 operated Middle Spraberry wells producing, with 3 more drilling / completing

While early, RSP’s Middle Spraberry results exceed expectations and reflect strong single-well economics

RSP has drilled more Middle Spraberry wells than any other operator in the Permian Basin and will continue to assess the zone’s potential –

20,000

40,000

60,000

80,000

100,000

120,000

140,000

0 30 60 90 120 150 180

Middle Spraberry 7,000' Lateral Type Curve

Average Operated Middle Spraberry Wells

615 MBOE

Early Middle Spraberry results trending stronger

than forecasted

Bo

e


MBOE ~615 ~88

MBO ~455 ~65

M.S.

___________________________Note: Production data normalized for a 7,000’ lateral and operational downtime. As of June 2014.(1) As estimated by Ryder Scott, our estimated average EURs from our Middle Spraberry PUD horizontal drilling locations as of 12/31/13 average 428 MBoe (approximately 65% oil, 18% NGLs and 17% natural gas) and have an average


20

Spraberry Potential Provides Additional Upside Leader in the Spraberry Substantial Horizontal Spraberry Inventory - Net Locations

RSP was the first operator to drill horizontal Lower Spraberry and horizontal Middle Spraberry

Early results point to economics as strong as Wolfcamp B

Lower D&C costs

Lower IP rates offset by shallower declines

Approximately 1/2 of RSP’s capex budget directed at horizontal Spraberry development (Middle Spraberry, Lower Spraberry)

Comparable Average Cumulative Production (Normalized to 7,000’ Lateral Length)

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

0 15 30 45 60 75 90 105 120 135 150 165 180

Average of Middle Spraberry Wells Average of Wolfcamp Wells Average of Lower Spraberry Wells

Bo

e

Reflects RSP Operated Middle Spraberry, Lower Spraberry & Wolfcamp wells with at least 90 days

of production history

D&C: $7.0mm Long Lateral / $6.0mm Short Lateral

315 315

159 270

270

212

585

371

–

100

200

300

400

500

600

LowerSpraberry

MiddleSpraberry

Middle + LowerSpraberry

WC-A + WC-B

D&C: $7.5mm Long Lateral / $6.3mm Short Lateral

___________________________Note: Production data normalized for a 7,000’ lateral and operational downtime. As of June 2014.

21

Consistent Pay Intervals Across RSP’s Contiguous Acreage Position

West to East Geologic AnalogMidland to Dawson Co. Stratigraphic Cross Section

Cross Section

All target intervals are present across RSP’s acreage

Similar log characteristics with consistent target zone thickness

Similar geologic characteristics / thermal maturity

A

A’

7,500’

8,500’

9,000’

9,500’

10,000’

10,500’

11,000’

8,000’

DATUM: TOP WOLFCAMP A

Horizontal Target

Lower Spraberry

Middle Spraberry

Wolfcamp A/B/C

Wolfcamp D (Cline)

Mississippian

Clearfork

Midland Basin

Nolan

Fisher

LynnGarza

Kent

22

Map of Midland Basin Activity

Midland Basin Horizontal Wells – Industry Activity

Pioneer

“Mabee K #1H” (Wolfcamp B)

30-day IP: 1,040 Boe/d – Cum: 120 Mboe


Pioneer

“University 7-43 10H” (Wolfcamp D / Cline)



Diamondback (FANG)

Core of FANG’s horizontal activity

“Gridiron N 1H” (Wolfcamp B)

30-day IP 1,991 Boe/d


“ST NW 2501H” (Wolfcamp B)

30-day IP: 683 Boe/d – Cum: 67,400 Boe


Pioneer

“Scharbauer #201H” (Wolfcamp D / Cline)

30-day IP: 662 Boe/d – Cum: 76 MBoe


Pioneer

“E.T. O’Daniel #1H” (Wolfcamp B)

24-hr IP: 2,801 Boe/d – Cum: 165 Mboe


“E.T. O’Daniel #2H” (Wolfcamp D / Cline)



Element

“SFH Unit 23 #1H” (Wolfcamp A)

30-day IP: 701 Boe/d


RSP Permian

“Cross Bar Ranch 1717WB” (Wolfcamp B)

30-day IP: 867 Boe/d (88% oil)

Cum: 44,593 Boe/68 days


“Cross Bar Ranch 1717WA” (Wolfcamp A)

30-day IP: 928 Boe/d (~84% oil)

Cum: 54,297 Boe/73 days


“Katie 1109H” (Wolfcamp B)


Cum: 50,578 Boe


“Kemmer 4209H” (Wolfcamp B)

30-day IP: 755 Boe/d (~85% oil)

Cum: 120,186 Boe


“Kemmer 4210H” (Wolfcamp B)

30-day IP: 760 Boe/d (~85% oil)

Cum: 74,864 Boe


“Headlee 3910H” (Wolfcamp B)

30-day IP: 727 Boe/d (~88% oil)

Cum: 112,574 Boe


“Sarah Ann 3812H” (Wolfcamp B)


Cum: 120,611 Boe


RSP’s successful Wolfcamp results are complemented by nearby operators’ announcements

___________________________Source: Texas Railroad Commission and investor presentations. 3-stream data. 30-day IP rates noted where available.

Scurry

Mitchell

Sterling

Glasscock

Midland

Ector

MartinHoward

BordenDawson

Gaines

Andrews

Crane

Upton

ReaganIrion

Tom

Green

Coke

SchleicherCrockett

Pecos

23

Map of Spraberry Activity

___________________________Source: Texas Railroad Commission and investor presentations. 3-stream data. 30-day IP rates noted where available.

Horizontal Spraberry Activity – Strong Early Results

Pioneer

“University 7-43 #16H” (Lower Spraberry)



Reliance

“Ratcliff A 2802 H” (Lower Spraberry)

30-day IP: 552 Boe/d


“Ratcliff A 2904 H” (Lower Spraberry)

24-hr IP: 827 Boe/d (88% oil)


RSP Permian

“Cross Bar Ranch 2017LS” (Lower Spraberry)

Completing


“Johnson Ranch 912MS” (Middle Spraberry)

30-day IP: 751 Boe/d (~87% oil)

Cum: 79,893 Boe


Diamondback

“ST-NW-25-1LS” (Lower Spraberry)

24-hr IP: 1,049 Boe/d (~92% oil)


Pioneer

“Flanagan 14 Lloyd A #21H” (Lower Spraberry)



Pioneer

“Scharbauer Ranch #501H” (Lower Spraberry)

24-hr IP: 691 Boe/d - Cum: 83 MBoe


Pioneer

“Mabee K #10H” (Lower Spraberry)



Pioneer

“Hutt C #21H” (Lower Spraberry)

24-hr IP: 537 Boe/d - Cum: 43 MBoe


RSP Permian

“Headlee 3505LS” (Lower Spraberry)

26-day IP: 589 Boe/d (~88% oil)


“Headlee 3911H” (Lower Spraberry)

30-day IP: 782 Boe/d (~88% oil)

Cum: 69,241 Boe


“Parks Bell 3304H” (Lower Spraberry)

30-day IP: 562 Boe/d (~90% oil)

Cum: 97,515 Boe


“Parks Bell 3909H” (Lower Spraberry)

30-day IP: 683 Boe/d (~93% oil)

Cum: 100,276 Boe


“Sarah Ann 3814MS” (Middle Spraberry)

30-day IP: 486 Boe/d (~83% oil)

Cum: 52,476 Boe


“Kemmer 4210LS” (Lower Spraberry)

30-day IP: 979 Boe/d (~88% oil)

Cum: 121,950 Boe


“Fendley 404MS” (Middle Spraberry)

30-day IP: 386 Boe/d (~86% oil)

Cum: 31,010 Boe


“Fendley 404LS” (Lower Spraberry)

30-day IP: 552 Boe/d (~91% oil)

Cum: 43,791 Boe


RSP Permian

“Keystone 1003LS” (Lower Spraberry)

30-day IP: 698 Boe/d (~93% oil)

Cum: 42,558 Boe


24

RSP’s Remaining Multi-Zone Development Projects For 20142014 Planned Horizontal WellsCommentary

1. Johnson Ranch 1018 & 1019 - 2-well stacked offsetting pads for

Wolfcamp B – Wolfcamp A spacing pattern test. Project on

production by end of Q4 2014

2. Cross Bar Ranch 2017 - 4 well stacked pad – Wolfcamp B is

currently producing, and Wolfcamp A (offset 440’ from

Wolfcamp B), Lower Spraberry & Middle Spraberry are drilled

and waiting on completion. Micro-seismic will be acquired to

study interaction during completion between the 4 zones.

Project on production in Q3 2014

3. Cross Bar Ranch 3025 - 4 well stacked pad – Wolfcamp D,

Wolfcamp B, Lower Spraberry & Middle Spraberry. Project on

production with all 4 wells in Q4 2014

4. Spanish Trail 217 - 2 well stacked pad – Lower Spraberry and

Wolfcamp B waiting on completion. Project on production early

Q3 2014; first operated RSP horizontal wells on Spanish Trail

5. Spanish Trail 4817 - 3 well stacked pad – Wolfcamp B, Lower

Spraberry and Middle Spraberry. Project on production late

2014

6. 3D Shoot - RSP is currently acquiring 3D seismic with partners

that will cover the key northern core acreage blocks

1

3

2

4

5

6 3D Shoot

Short Lateral Target

Long Lateral Target

010203040

Spud Prior to 6/30/13 Spud After 6/30/13

$0

$250

$500

$750


25

Horizontal Well Costs Coming DownCapital costs decreasing due to experience, efficiencies, completion / well design optimization, and pad development

Operated Horizontal Drilling & Completion Costs Per Lateral Foot (by Spud Date)

Co

st p

er L

ater

al F

oo

t

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

$2,200

Jun-12 Oct-12 Feb-13 Jul-13 Nov-13 Mar-14

Short Laterals Long Laterals

Recent well costs trending below budget for both drilling and

completion, and closer to RSP’s longer term cost targets

Average Operated Drilling Costs Per Lateral Foot

$0

$250

$500

$750


(26%)

Average Operated Completion Costs Per Lateral Foot

(24%)

Average Operated Spud to Rig Release (Days)

(28%)

___________________________Note: Data excludes one sidetracked horizontal well.

$64.75 $60.20

$55.43 $54.41 $48.45

$43.61 $39.70

$0.00

$20.00

$40.00

$60.00

$80.00

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6

26

Low-Cost Operator with Strong Margins

Pre-G&A Cash Margin (Twelve Months Ended 12/31/2013)

Commodity Mix (Proved Reserves)

68%59% 58%

40% 40%

61% 55%

15%21% 22%

28% 22%

17% 20% 20%31% 38% 39% 45%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%% Oil % NGL % Gas

___________________________Source: Company filings. Permian Basin Peers include AREX, ATHL, CXO, FANG, LPI, PXD.(1) As of 12/31/2013 pro forma for Midland Basin acquisitions announced in July 2014.(2) NGL percentage not disclosed.

(2)

$ / boe

(2)(1)Peer 1 Peer 3 Peer 5 Peer 6 Peer 2 Peer 4

27

Financial Overview

28

RSP’s Financial Strategy and Capitalization

___________________________(1) 6/30/14 balances adjusted to reflect net proceeds of approximately $118 million from RSP’s 4.8 million offering of primary shares (including overallotment) priced on August 7, 2014.(2) Please see reconciliation of Adjusted EBITDAX in Appendix.(3) As of 12/31/2013.(4) Q2 2014 average daily production.

Preserve financial strength

Ensure plenty of capital availability to execute drilling program

Keep strong balance sheet to remain flexible / take advantage of acquisition opportunities

Maintain conservative balance sheet

Target long-term Debt / EBITDAX at or less than 2.0x

Protect Cash Flows with Active Hedging Program

Provides certainty around executing drilling program and maintains strong financial position

Target 65% - 85% of production hedged on a rolling 2-year basis

Financial Strategy Capitalization

($ in millions) 6/30/2014 As Adjusted(1)

Cash $15 $15

Revolving Credit Facility 140 22

Total Debt $140 $22

Net Debt $125 $7

Financial & Operating Statistics

Q2 2014 Annualized Adjusted EBITDAX (2) $214.9 $214.9

Proved Reserves (MMboe) (3) 53.9 53.9

Proved Developed Reserves (MMboe)(3)

21.4 21.4

Latest Daily Production(4)

10.7 10.7

Credit Metrics

Net Debt / Annualized Adjusted EBITDAX(2)

0.6x 0.0x

Net Debt / Proved Reserves ($/Boe) $2.32 $0.13

Net Debt / Proved Developed Reserves ($/Boe) $5.85 $0.34

Net Debt / Latest Daily Production ($/Boe/d) $11,692 $678

Liquidity

Borrowing Base $375 $375

Less: Borrowings (140) (22)

Plus: Cash 15 15

Liquidity $250 $368

29

Capital Budget and Hedging Detail All production inputs are engineered

Drilling program modified as needed to re-focus on most attractive opportunities within portfolio

2014 Capital Budget

Lower Spraberry

Middle Spraberry

Wolfcamp A

Wolfcamp B

Horizontal75%

Vertical25%

$400 million

$300 million

Total Drilling & Completion

Horizontal Drilling & Completion

Hedging Detail

~90% expected to be long lateral

horizontal wells

Crude Oil

Q3 2014 Q4 2014 2015

Swaps

Volumes (Bbls) 60,000 60,000 120,000

Average Swap Price ($/Bbl) $94.50 $94.50 $92.60

Collars

Volumes (Bbls) 414,000 561,000 2,067,000

Average Floor ($/Bbl) $86.56 $87.49 $86.60

Average Ceiling ($/Bbl) $100.77 $100.73 $94.87

Total Volumes Hedged (Bbls) 474,000 621,000 2,187,000

Total Blended Floor $87.56 $88.16 $86.93

Daily Volumes (Bbls/day) 5,152 6,750 5,992

% Future Oil Production Hedged ~60% ~50%

Natural Gas

Q3 2014 Q4 2014 2015

Collars

Volumes (MMBtu) 450,000 450,000 –

Average Floor ($/MMBtu) $4.00 $4.00 NA

Average Ceiling ($/MMBtu) $4.78 $4.78 NA

2014 Capital Budget ($mm)

Drilling & Completion $400Infrastructure & Other 25Total $425

Does not include capital spend attributable to pending

acquisitions acreage

30

Adjusted EBITDAX and Adjusted Net Income ReconciliationAdjusted EBITDAX and Adjusted Net Income Reconciliation

($ in thousands, except per unit amounts) RSP Permian, Inc.

Pro Forma Actual & Predecessor

Quarter Ended Quarter Ended Quarter Ended Quarter Ended

June 30, 2014 March 31, 2014 June 30, 2014 June 30, 2013

Revenues

Oil sales $66,134 $55,930 $66,134 $22,442

Natural gas sales 3,117 2,397 3,117 1,397

NGL sales 4,811 4,417 4,811 1,309

Total revenues $74,062 $62,744 $74,062 $25,148

Net cash from derivative instruments (1,517) (380) (1,517) (1,342)

Adjusted Total Revenues $72,545 $62,364 $72,545 $23,806

Operating Expenses

Lease operating expenses $9,279 $7,757 $9,279 $3,944

Production and ad valorem taxes 5,964 4,127 5,964 783

General and administrative expenses 3,573 1,771 3,573 1,069

Total operating costs and expenses $18,816 $13,654 $18,816 $5,796

Adjusted EBITDAX $53,729 $48,709 $53,729 $18,010

Depreciation, depletion, and amortization $21,734 $19,994 $21,734 $12,032

Asset retirement obligation accretion 38 38 38 26

Exploration 1,233 756 1,233 94

Interest expense 1,142 1,131 1,142 477

Stock-based compensation, net 658 294 1,665 –

Adjusted income before income taxes $28,924 $26,497 $27,917 $5,381

Adjusted income tax expense 10,413 9,539 10,486 –

Adjusted net income, as defined $18,511 $16,958 $17,431 $5,381

Adjusted net income per common share - Basic $0.25 $0.23 $0.24 N/A

Adjusted net income per common share - Diluted $0.25 $0.23 $0.24 N/A

RSP’s executive team has decades of experience in identifying acquisition targets and evaluating resource potential

Spanish Trail, East Cowden, Verde, Dude and pending Glasscock acquisitions totaling almost $500 million in the last year are the most recent examples

Strategically pursue acquisition opportunities with oil-weighted potential

31

Identified Opportunities for Future Upside

Pad drilling = efficiency and lower costs

Several “stacked” 2 well pads currently producing; now moving to 4 “stacked” well pads on certain leases

RSP continuously evaluates and tests new technology

Currently utilizing cutting edge drilling techniques

3D seismic further delineates RSP’s stacked pay zones

Well cost efficiencies realized through RSP’s operatorship of 95% of its net acreage

Continuously improve drilling techniques, completion methodologies and reservoir evaluation processes

Strategic Acquisitions

New Technology

Multi-Zone Pad Drilling

Well Cost Efficiencies

Increased Economics/ Locations

RSP’s well costs are decreasing and IP rates outperforming type curves, leading to increasing economics

RSP evaluating increasing lateral density and drilling more laterals per section, increasing locations

32

Additional Disclosures

Supplemental Non-GAAP Financial Measures

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry

analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before interest expense, income taxes, depreciation, depletion

and amortization, exploration expense, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivative instruments and

premiums paid for put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation, asset retirement

obligation accretion expense, other income, gains and losses from the sale of assets and other non-cash operating items. Adjusted EBITDAX is not a measure of net

income as determined by United States generally accepted accounting principles (‘‘GAAP’’).

Management believes Adjusted EBITDAX is useful because it allows it to more effectively evaluate our operating performance and compare the results of our

operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net

income in arriving at Adjusted EBITDAX 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 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 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 presentation of Adjusted

EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX

may not be comparable to other similarly titled measures of other companies.

Certain Reserve Information

Cautionary Note to U.S. Investors: The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other

than “reserves,” as that term is defined by the SEC. This presentation discloses estimates of quantities of oil and gas using certain terms, such as “resource

potential,” “net recoverable resource potential,” “resource base,” “estimated ultimate recovery,” “EUR” or other descriptions of volumes of reserves, which terms

include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC’s guidelines strictly prohibit

the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are

subject to substantially greater risk of being recovered by the Company. U.S. investors are urged to consider closely the disclosures in the Company’s periodic

filings with the SEC. Such filings are available from the Company at 3141 Hood Street, Suite 500, Dallas, Texas 75219, Attention: Investor Relations, and the

Company’s website at www.rsppermian.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.

rsp permian investor presentationfilecache.drivetheweb.com/mr5ir_rsppermian/108/download/rsp... ·...

Documents