RSP Permian Q3 2016 Results Forward-Looking Statements Certain - - PowerPoint PPT Presentation

RSP Permian

Q3 2016 Results

Forward-Looking Statements

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 ability to assimilate acquisitions into our operations, the assumptions underlying production forecasts, our hedging strategy and results, the quality of technical data, environmental and weather risks, 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 RSP’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 RSP’s production and third parties providing services to RSP 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 United States Securities and Exchange Commisson (SEC), including our Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q. 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.

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RSP Permian Overview (NYSE: RSPP)

Contiguous Acreage Position in Core of Permian Basin

• Large, contiguous acreage blocks in the core of the

Midland and Delaware Basins(1)

• Midland: ~60,700 net surface acres and ~270,000 net

“effective horizontal acres”(2)

• ~96% operated
• Delaware: ~41,000 net surface acres and ~250,000 net

effective horizontal acres

• ~80% operated
• Current run rate production of ~50 MBoe/d
• ~5,800 horizontal locations in inventory with

significant upside

• Efficient operator – focused on execution
• Leading F&D costs, reserve replacement ratios and
• perating costs
• Drilled wells in five different horizontal benches in

Midland Basin

___________________________ (1) Silver Hill acquisition pending, expected close in Q4 2016 and Q1 2017. (2) Combined horizontal acreage position that Management believes is prospective for hydrocarbon production across each target horizontal zone. (3) Please see reconciliation of Adjusted EBITDAX in Appendix. (4) Based on Q3 2016 net debt and TTM Adjusted EBITDAX.

Q3 2016 Key Statistics

• Market Capitalization (10/31/16):
• 3Q16 Average Production:
• YE 2015 Proved Reserves:
• Net Debt / TTM EBITDAX(3)(4):
• Liquidity as of 9/30/16:

$4.6 billion 29.8 MBoe/d 159.2 MMBoe 3.0x $587 million

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Midland Basin ~60,700 net acres ~2,600 gross locations in focus area Delaware Basin Acquisition(1) ~41,000 net acres ~3,200 gross locations

3Q16 Update

Financial Results

• Added third Hz rig in September; utilized one full time completion crew and one spot crew for 2 completions
• Completed 17 operated Hz wells, 1 operated Vt well and 13 non-op Hz wells
• Began quarter with 19 operated Hz DUCs(1) (24 non-op DUCs) and finished with 12 operated Hz DUCs (18

non-op Hz DUCs)

• Entering into 6 month contract for 4th Hz rig in Midland Basin, expected to arrive in January 2017

3Q Operational Activity Liquidity / Hedging

• $587MM of liquidity at 9/30 with $22MM in cash and $35MM drawn on $600MM revolver ($1MM LC)
• 53% of 4Q’16E oil production hedged at a weighted average floor price of $43.49/Bbl (2)
• 56% of 2017E oil production hedged at a weighted average floor price of $44.63/Bbl (2)
• Expected full-year production range increased to 28.5 - 29.5 MBoe/d
• Development capital expenditure budget narrowed to $295 - $315 million
• Preliminary full-year 2017 production range of 52 - 56 MBoe/d with development capex of $570 - $630MM
• Average daily production of 29.8 MBoe/d (73% oil, 17% NGLs, 10% Natural Gas), up 13% from 2Q16 and 24%
• ver 3Q15
• Adjusted EBITDAX of $65.7MM (up 12% from 2Q16), with $73.2MM of 3Q16 development Capex
• Net income of $1.0MM, or $0.01 per share; adjusted net loss of ($0.8)MM, or ($0.01) per share
• Cash operating expenses of $9.36/Boe, 11% lower than 3Q15, and 6% lower than 2Q16

Increased 2016 Guidance and Provided 2017 Outlook

___________________________ (1) DUC is a drilled but uncompleted well. (2) Percent hedged based on corporate midpoint oil guidance, which includes Delaware Basin projected volumes.

Silver Hill Acquisition

• Announced acquisition of Silver Hill for approximately $2.4 billion
• Consideration includes $1.25 billion in cash and 31.0 million shares of RSP common stock
• On October 19, 2016, completed underwritten public offering of 25.3MM shares of common stock for total

net proceeds of approximately $1.0 billion

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Silver Hill Acquisition Overview

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• Highly contiguous operated position in the core of the

Delaware Basin

• ~68,000 gross / ~41,000 net acres
• ~80% operated with over 80% working interest in
• perated properties (acreage held by one operated rig)
• Conducive to efficient long lateral development
• Meaningful current production base of ~15 MBoe/d
• 69% oil and 86% liquids
• 2 operated horizontal rigs currently running
• 49 producing Hz wells and 9 producing Vt wells
• Over 4,500 ft. of stacked pay with 7 producing, horizontal

zones

• ~250,000 net effective horizontal acres
• Includes the Wolfcamp B, Lower and Upper (XY)

Wolfcamp A, 3rd Bone Spring, 2nd Bone Spring, 1st Bone Spring and Avalon

• Key offset operators include EOG, Anadarko, Shell,

Matador and Devon, among others

• Decades of highly economic horizontal drilling inventory
• ~3,200 gross / ~1,950 net drilling locations, largely
• perated
• Accretive to cash flow, production and NAV at current strip

prices

Silver Hill Acquisition Highlights Wolfcamp Structure Map (Subsea Depths)

TEXAS NEW MEXICO Culberson Ward Lea Eddy Reeves Pecos Winkler Andrews Loving Gaines

2500 2000 1500 1000 500

• 500
• 1000
• 1500
• 2000
• 2500
• 3000
• 3500
• 4000
• 4500
• 5000
• 5500
• 6000
• 6500
• 7000
• 7500
• 8000
• 8500

SILVER HILL ACREAGE WOLFCAMP STRUCTURE (TVDSS) CONTOUR INTERVAL = 500

• Rock Quality: Silver Hill located in the deepest, thickest over-pressured portion of the Delaware Basin characterized by low GOR
• Drives higher IPs, EURs and economics as well as higher density development across multiple zones
• Inventory includes horizontal wells with EURs of ~1.0 MMBoe and single well IRRs over 70% (1) at current strip pricing
• Delineated: high number of producing, de-risked zones
• Horizontals producing in 7 zones, including multiple Wolfcamp and Bone Spring targets as well as Avalon
• Affords meaningful long-term scale and enhanced NAV
• Contiguous: blocky acreage position
• Allows for efficient development with enhanced economics from the use of long-laterals
• Scale: meaningful existing base of production and cash flow
• 15 MBoe/d (69% oil, 86% liquids) as of October 2016
• Significantly larger production base than the majority of recently evaluated opportunities

RSP is a Selective Acquirer: Why Silver Hill?

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Silver Hill Meets All Key Acquisition Criteria

RSP has taken a measured approach to acquisitions – successfully growing asset base without sacrificing quality

___________________________ (1) Based on Management estimates.

3 5 RSP PF RSP RSP PF RSP RSP PF RSP ~2,600 ~5,800 RSP PF RSP ~35 ~50 RSP PF RSP

Strategic Combination Substantially Increases Scale

+123% Current Production (MBoe/d) (1) Current Rigs Running Net Surface Acreage Gross Horizontal Drilling Locations +68% Net Horizontal Drilling Locations Net Effective Horizontal Acreage +43% ~60,700 ~101,700 ~262,000 ~512,000 +67% +95%

___________________________ (1) Represents RSP current 3-week run-rate production and Silver Hill production as of October 2016.

~1,700 ~3,650 RSP PF RSP +115%

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3Q16 3Q15 % Change 2Q16 % Change Avg Daily Production (Boe/d) 29,761 24,000 24% 26,407 13% % Oil 73% 75% (3%) 73% – Average NYMEX Oil Price $44.94 $46.43 (3%) $45.59 (1%) Avg Realized Prices (Incl. Hedges) Oil (per Bbl) $41.46 $57.36 (28%) $43.05 (4%) Natural Gas (per Mcf) 2.27 2.27 – 1.47 54% NGLs (per Bbl) 10.82 8.72 24% 11.69 (7%) Total (per Boe) $33.37 $45.98 (27%) $34.32 (3%) Total Revenues + Realized Hedges ($MM) $91.4 $101.5 (10%) $82.5 11% Adjusted EBITDAX ($MM) 65.7 78.3 (16%) 58.5 12% Adjusted Net Income (Loss) ($MM) (0.8) 13.5 (106%) (3.8) 80% Cash Expenses (per Boe) LOE $4.67 $6.08 (23%) $5.37 (13%) Gathering & Transportation 0.51 0.38 34% 0.49 4% Production & Ad Valorem 2.14 2.12 1% 2.06 4% Cash G&A 2.04 1.92 6% 2.06 (1%) Total Cash Expenses $9.36 $10.50 (11%) $9.99 (6%) Non-Cash Expenses (per Boe) Recurring Stock Comp 1.20 0.95 26% 1.46 (18%) Non-Recurring Stock Comp – 0.15 (100%) 0.28 (100%) DD&A 18.27 19.49 (6%) 19.68 (7%) Capital Expenditures Drilling & Completion $65.3 $86.0 (24%) $56.5 16% Infrastructure & Other 7.9 9.3 (16%) 1.1 602% Total Capital Expenditures $73.2 $95.3 (23%) $57.6 27%

3Q16 Financial Results

___________________________ Note: Please see reconciliation of Adjusted EBITDAX and Adjusted Net Income in Appendix.

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RSP is in a Strong Financial Position

___________________________ (1) Please see reconciliation of Adjusted EBITDAX in Appendix.

Capitalization Table

• With strong liquidity, no near-term maturities, an

improved hedge position and attractive returns on

• ur drilling, RSP is well positioned to accelerate

activity beyond current levels

• $600MM borrowing base
• Anticipate borrowing base will be increased

upon closing SHEP I and SHEP II transactions

• During 1Q16, Moody’s confirmed RSP’s B3 rating on

its senior notes and S&P upgraded the senior notes a notch to B+

Debt Maturities ($MM)

$0 $200 $400 $600 $800 2016 2017 2018 2019 2020 2021 2022

Unused Borrowing Base Revolving Credit Facility Borrowings Senior Notes 6.625%

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($ in millions) Q3 2016 Cash $22 Revolving Credit Facility 35 6.625% Senior Unsecured Notes Due 2022 700 Total Debt $735 Net Debt $713 Liquidity Borrowing Base $600 Less: Borrowings & LCs (36) Plus: Cash 22 Liquidity $587 Financial & Operating Statistics Q3 2016 TTM Adjusted EBITDAX (1) $234.2 Q3 2016 Daily Production (MBoe/d) 29.8 Credit Metrics Net Debt / TTM Adjusted EBITDAX 3.0x Net Debt / Latest Daily Production ($/Boe/d) $23,945

Hedging Program Summary

• RSP opportunistically layers on hedges to protect returns and support planned capital expenditures
• Recently executed additional hedging arrangements to protect remaining 2016 and 2017 volumes
• Deferred premium put structure allows RSP to retain upside to future oil price increases

Hedge Contract Detail

Crude Oil (Bbl, $/Bbl) 4Q’16 1Q’17 2Q’17 3Q’17 4Q’17 2017

Three-Way Collars (1) 120,000 675,000 675,000 Ceiling Floor Short Put $74.41 $55.00 $45.00 $54.25 $45.00 $35.00 $54.25 $45.00 $35.00 Costless Collars (1) 450,000 1,137,500 1,150,000 1,150,000 3,887,500 Ceiling Floor $59.75 $45.00 $60.05 $45.00 $60.05 $45.00 $60.05 $45.00 $60.02 $45.00 Deferred Premium Puts / Put Spreads (1) 1,125,000 675,000 910,000 920,000 920,000 3,425,000 Floor Short Put Deferred Premium (2) $45.00 ($2.74) $45.00 $35.00 ($2.32) $48.50 ($4.00) $48.50 ($4.00) $48.50 ($4.00) $47.81 NM ($3.67) Total Hedge Weighted Average Floor (3) 1,245,000 $43.49 1,800,000 $44.13 2,047,500 $44.78 2,070,000 $44.78 2,070,000 $44.78 7,987,500 $44.63 % Hedged on Midpoint Oil Volume Guidance(5) 53% 56%

___________________________ (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) The deferred premium is not paid until expiration date, aligning cash inflows and outflows with the settlement of the derivative contract. (3) Weighted average floor assumes the long put in three way collars and put spreads and reflects the impact of premiums paid. (4) The natural gas derivative contracts are settled based on the last trading day’s closing price for the front month contract relevant to each period. (5) Utilizing 4Q16 and 2017 midpoint oil volume guidance.

Natural Gas (MMBtu, $/MMBtu) 4Q’16 1Q’17 2Q’17 3Q’17 4Q’17 2017

Costless Collars (4) 900,000 910,000 920,000 920,000 3,650,000 Ceiling Floor $3.64 $3.00 $3.64 $3.00 $3.64 $3.00 $3.64 $3.00 $3.64 $3.00

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2016 Horizontal Well Performance Exceeding Type Curves

• The average of all operated horizontal wells brought online in 2016 YTD is outperforming the weighted average

internal type curve by ~25%

• This group of wells includes, among others, R&D wells testing high density stimulation, increased density

spacing and alternate landing zone tests All Hz Wells Completed YTD vs. Weighted Avg. Type Curve (Boe) 20 40 60 80 100 120 140 160 180 200 220 240 Days

• Avg. Cum. Production

Weighted Avg. Type Curve

~25% Outperformance through 230 - Days 11

Updated 2016 Guidance and Preliminary 2017 Outlook

YTD 2016 Actuals and Revised Full Year Guidance

___________________________ (1) Prior guidance reflects that which was published by RSP in August 2016.

Preliminary 2017 Outlook

• Midland Basin: 4 rigs
• Delaware Basin: 2 rigs ramping to 4 by YE
• 2017 Production: 52,000 - 56,000 Boe/d
• Oil:

72% - 74%

• Natural Gas:

11% - 12%

• NGLs:

14% - 15%

• Total Development Capital: $570 - $630 million
• Drilling & Completion:

$520 - $560MM

• Infrastructure & Other:

$50 - $70MM

• % Non-Operated:

10% - 15%

Guidance Update

• Production guidance increased by 5% at the midpoint

based on well results exceeding expectations, including shallower decline profiles

• Narrowed capex range
• Guidance now incorporates flexibility for two

Delaware Basin operated Hz completions in late 4Q16

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• Aug. Revised
• Oct. Revised

YTD 2016 2016 2016 Production Actual Guidance

(1)

Guidance Average Daily Production (Boe/d) 26,931 26,500 - 28,500 28,500 - 29,500 % Oil 74% 75% - 76% 73% - 75% % Natural Gas 11% 10% - 11% 10% - 11% % NGLs 15% 13% - 14% 14% - 15% Income Statement ($/Boe) LOE (Including Workovers) $5.16 $5.00 - $6.00 $5.00 - $6.00 Gathering & Transportation $0.44 $0.45 - $0.50 $0.45 - $0.50 Exploration Expenses $0.11 $0.10 - $0.15 $0.10 - $0.15 Cash G&A $2.09 $2.00 - $2.25 $2.00 - $2.25 Recurring Non-Cash G&A $1.34 $1.25 - $1.50 $1.25 - $1.50 DD&A $19.23 $19.00 - $21.00 $19.00 - $21.00

• Prod. & Ad Val. (% of Rev.)

6.5% 6.0% - 7.0% 6.0% - 7.0% Capital Expenditures ($MM) Drilling & Completion $187.4 $270 - $290 $280 - $290 Infrastructure & Other $11.3 $15 - $25 $15 - $25 Total Development Capital $198.7 $285 - $315 $295 - $315 % Non-Operated 16% 10% - 15% 10% - 15% Completions Operated Gross Hz 39 52 - 56 54 - 58 Operated Gross Vt 4 5 6

3Q16 Activity Summary

• DUC inventory approaching normalized levels,

distributed across core position

• In 3Q16, RSP completed 17 operated Hz wells (11 LS,

3 WA, 3 WB) and 1 Vt well

• Ended 3Q16 with 12 operated Hz DUCs (18 non-
• perated DUCs)
• Production averaged 29,761 Boe/d during 3Q16, up

from 26,407 Boe/d during 2Q16 3Q16 Drilling & Completion Activity Summary

22,000 24,000 26,000 28,000 30,000 32,000 34,000 36,000 1/1/16 2/1/16 3/1/16 4/1/16 5/1/16 6/1/16 7/1/16 8/1/16 9/1/16 10/1/16 Boe/d

Progression of YTD Net Production (Weekly Basis)

1Q16 Avg. Production

• f 24,615

Boe/d Q2 Q1 2Q16 Avg. Production of 26,407 Boe/d Q3 Q2 3Q16 Avg. Production of 29,761 Boe/d

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2Q16 DUCs Drilled Completed 3Q16 DUCs Operated Horizontal 19 10 17 12 Vertical 3 1 2 Total 19 13 18 14 Non-Operated Horizontal 24 7 13 18 Vertical

• In 4Q16, RSP expects to complete 13-17 operated wells in

the Midland Basin

• 40-50% focused in the Lower Spraberry zone
• 4Q16 drilling and completion activity contemplates:
• 3 existing rigs
• 1 full-time frac crew
• Expect to end 2016 with 8-12 DUCs in the Midland Basin

2016 Midland Basin Operated Horizontal Drilling & Completion Summary YTD Operated Completions by Zone

2016 Drilling & Completion Activity Update

MS 2% LS 64% WA 22% WB 13% 18 13 10 10 13 11 11 17 13 8 17 12 5 10 15 20 2015 YE 1Q16 2Q16 3Q16 4Q16 1Q16 2Q16 3Q16 4Q16 2016 YE DUCs Drill Complete DUCs

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Well Cost Update

Drilling, Completion & Equip. Cost (7,500’ lateral)

• After declining for six straight quarters, drilling, completion & equipping costs have increased modestly
• Increase was in line with expectations based on significant increase in frac density employed vs. beginning of year
• Latest vintage completion design includes more than 1,900 lbs/ft of proppant, +/-14 perf clusters per stage and diverter

agents

• Expect enhanced well performance to more than offset incremental cost, resulting in a net positive impact on

per well and per section NPVs

• Two of three RSP rigs currently running have day rates of more than $25,000/d
• As two older rigs roll off contract in January and April of 2017, RSP will transition average day rate towards

current market levels

15 Spanish Trail Avg. 100 Day Cum. Production (MBoe)

Old Rig New Rig

Contingency Equip Enhanced Compl Base Compl Drill

$5.5-$5.9 MM $5.2-$5.6 MM Decreased day rate:

• $350k

+$250k 40 80 120 160 20 40 60 80 100 Spanish Trail Old Vintage Completion Spanish Trail New Vintage Completion Avg. +$250k Old Rig Rate New Rig Rate

Density Pilots Spanning Acreage Position

• In multiple spacing pilots across our core acreage position, RSP has successfully completed wells at or above our type

curve using 3 different landing targets

• RSP believes vertical separation (staggering) between landing targets allows for more dense drilling
• Potential for simultaneous development of 3 landing intervals within the Lower Spraberry exists in some areas

Spacing Pilots Delineate Core Position

Lower Spraberry

1 Mile (5280’)

Dean

Spanish Trail Johnson Ranch

Upper Landing Target Intermediate Landing Target Lower Landing Target

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400’ Producing Producing

Strong and Consistent Wolfcamp A Performance Across Position

• RSP has tested the Wolfcamp A zone across its core

acreage position with excellent results to date (20

• perated Hz Wolfcamp A wells)
• The Kemmer 4217 WA represents RSP’s westernmost

Wolfcamp A well to date and also its strongest performer on a per foot basis

• Implies an increase to Wolfcamp A inventory

(currently not carried along western edge of acreage)

17 Selected Top Wolfcamp A Wells Across Position Select West & East Side Wolfcamp A Wells

30 60 90 120 150 30 60 90 120 150 180 210 MBoe Days

1MMBOE Peer Type Curve Kemmer 4217 WA Woody 1H WA

1 2 3 4 5 6 Wolfcamp A Well Performance Well Name Lateral Length IP30/1,000’ (Boe/d) 1 Kemmer 4217 WA 4,960 254 2 Cross Bar Ranch 3027 WA 6,478 208 3 Spanish Trail 228 WA 6,475 201 4 Johnson Ranch 1021 WA 7,350 145 5 Woody 04-01 WA 4,954 196 6 Calverley 09-04 WA 9,968 184 Latest vintage completion design

20 total operated Hz Wolfcamp A wells

Spanish Trail – Long Laterals Exceeding Expectations

18 50 100 150 200 30 60 90 120 150 180 210 MBoe Days

1MMBOE Peer Type Curve WA Avg. WB Avg. LS Avg.

• RSP’s longest LS laterals to date completed

in Spanish Trail Section 47 (10,500’+)

• On average, wells have produced over

100MBoe in first 90 days

• Full half-section developed on base spacing;

all producing wells performing above peer 1MMBoe type curve with no observable degradation

• Results to date strengthen case for increased

well density

Spanish Trail Performance Spanish Trail Section 47 Update

Cross Bar Ranch – Lower Spraberry Increased Density Pilot

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• RSP’s 500’ spacing test at Cross Bar Ranch has

performed above expectations despite relatively less oil in place vs. other RSP core acreage

• Original 3 wells of pattern completed during July

2015 with prior frac design; next 3 wells completed during August 2016 with latest vintage frac design

• Performance to date strongly supportive of high

density frac design paired with downspacing

Cross Bar Ranch LS Performance Cross Bar Ranch Section 17 Update

• 20

40 60 80 100 120 140 30 60 90 120 150 180 MBoe Days

7,500' LS Type Curve (~830MBoe) Original 3 Well Avg. (prior frac design) Next 3 Well Avg. (latest vintage frac design)

Western Glasscock – Generating Strongest Economics Across Leasehold

20 50 100 150 200 250 30 60 90 120 150 180 210 MBoe Days

1MMBOE Peer Type Curve 1H WA 2H UWB 4H LWB

Calverley LS Performance Calverley Area Update

• RSP’s two initial Calverley wells continue to
• utperform peer 1MMBOE type curve
• Two test wells, 3H LS and 4H LWB, are now producing

in line with peer 1MMBOE type curve after R&D efforts reduced upfront well results

• Two recently completed LS wells were placed on ESP,

have been producing for ~60 days and are tracking peer 1MMBOE type curve

• Two additional Upper Wolfcamp wells scheduled to

be completed during 4Q16 or 1Q17

50 100 150 200 30 60 90 120 150 180 210 MBoe Days

1MMBOE Peer Type Curve 3H LS 5H LS & 6H LS Avg.

Calverley WC Performance

First 60 days restricted for R&D ESP Gas Lift

GLASSCOCK CO MIDLAND CO

Calverley Wells LS WA WB

2H 1H 3H 4H

U L

2H 1H 3H 5H 6H DUCs

RSP Permian – Delivering Value

Experienced Management Strong Financial Position Focused on Returns and Execution High Quality Assets

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Appendix

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Executing Accretive Bolt-on Acquisitions in Core Midland Areas

Locator Map of 2016 YTD Acquisitions

~$62MM in 2016 acquisitions

• YTD 2016 (through September), RSP has acquired

~$62 million of bolt-on oil and gas properties:

• ~2,500 net acres located in core Midland,

Martin, and Glasscock Counties

• ~$19 million of acquisitions in 3Q16
• Acquisitions funded with cash on the balance sheet

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Adjusted EBITDAX and Adjusted Net Income Reconciliation

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Reconciliation of Net Income (Loss) to Adjusted EBITDAX

(in thousands)

Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss)

(in thousands)

• Stock-based compensation - non-recurring

Other income, net Loss (gain) on asset sale 4 Three Months Ended September 30, Three Months Ended June 30, 2016 2015 2016 Loss (gain) on derivative instruments Interest Expense Income Tax Expense (Benefit) DD&A Impairments Net Income (Loss) 985 $ 8,974 $ (9,801) $ 50,022 43,031 47,296 971 4,238 3,177 13,146 11,680 12,954 (3,507) 4,953 (4,438) Net Cash Payments on Settled Derivative Instruments (2,258) 20,879 974 3,272 2,432 4,183 359 218 405 2,934 (18,098) 3,684 Exploration Expense Loss (Gain) on Derivative Instruments Non-Cash Equity Based Compensation

• Adjusted EBITDAX

78,329 $ 58,453 $ 118 84 123 (310) (66) (104) Asset Retirement Accretion Other income, net Loss (gain) on Sale of Assets 65,732 $ 4

• 2016

2015 2016 Three Months Ended September 30, Three Months Ended June 30, 20,879 974 Net income (loss) 985 $ 8,974 $ (9,801) $ Impairments 971 4,238 3,177 Net cash payments on settled derivative instruments Income tax expense (benefit) for above items (3,086) (2,458) (2,370) Adjusted Net Income (Loss) (764) $ 13,473 $ (3,758) $

• 682

(310) (66) (104) 2,934 (18,098) 3,684 (2,258)

Additional Disclosures

Supplemental 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

• ther 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.

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