Energy Corporation Resolute Energy is a regionally diversified growth oriented E&P company focused on long-lived domestic oil producing assets
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1 Energy Corporation Resolute Energy is a regionally diversified growth oriented E&P company focused on long-lived domestic oil producing assets Analyst day June 19, 2013
2 Forward looking statement Statements in this presentation, other than statements of historical fact, are forward-looking statements within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of Words such as expect, estimate, project, budget, forecast, target, anticipate, intend, plan, may, will, could, should, poised, believes, predicts, potential, continue, and similar expressions are intended to identify such forward-looking statements. Forwardlooking statements in this presentation include statements regarding future financial and operating results; statements regarding net asset value growth; statements regarding our production and cost guidance for 2013 and beyond; future production and reserve growth and ultimate recoveries of oil and gas; the progress and anticipated results of Greater Aneth Field CO 2 and water flood projects and additional CO 2 and water flood potential; anticipated capital projects and expenditures for 2013 and beyond and the sources of such funding; our ability to control costs; our operating, development and exploration plans and anticipated costs and results of exploration and testing; liquidity and availability of capital; our plans to sell our Bakken properties, the anticipated timing of such transactions and our anticipated use of proceeds therefrom; our expectations regarding reduction of leverage; our plans and expectations regarding our development activities including drilling, deepening, recompleting, fracing and refracing wells, the number of such potential projects, the anticipated timing, cost and rate of return of such activities, and the anticipated timing and activity required to reach held by production status; testing and prospectivity of our properties and acreage; downspacing potential; the successful integration of our acquisitions; and future cash flows from and prospectivity of the acquired Permian properties and acreage; our anticipated general and administrative expenses, lease operating expenses, taxes and depreciation, depletion and amortization rates. Forward looking statements in this presentation include matters that involve known and unknown risks, uncertainties and other factors that may cause actual results, levels of activity, performance or achievements to differ materially from results expressed or implied by this presentation. Such risk factors include, among others: the volatility of oil and gas prices; inaccuracy in reserve estimates and expected production rates; discovery, estimation, development and replacement of oil and gas reserves; the future cash flow, liquidity and financial position of Resolute; the success of the business and financial strategy, hedging strategies and plans of Resolute; the amount, nature and timing of capital expenditures of Resolute, including future development costs; availability and terms of capital; the effectiveness of Resolute s CO 2 flood program; the potential for downspacing or infill drilling in the Permian Basin and the Williston Basin or obstacles thereto; the timing of issuance of permits and rights of way; the timing and amount of future production of oil and gas; availability of drilling, completion and production personnel, supplies and equipment; the completion and success of exploratory drilling in the Bakken and Three Forks trends, the Mowry shale, and Turner, Frontier, Minnelusa, Phosphoria and Niobrara formations in Wyoming and the Permian Basin; potential delays in the completion, commissioning and optimization schedule of Resolute s gas gathering and facilities construction projects; operating costs and other expenses of Resolute; the success of prospect development and property acquisition of Resolute; the success of Resolute in marketing oil and gas; competition in the oil and gas industry; the impact of weather and the occurrence of disasters, such as fires, floods and other events and natural disasters; environmental liabilities; anticipated supply of CO 2, which is currently sourced exclusively under a contract with Kinder Morgan CO 2 Company, L.P.; availability of electric power in our operating areas; operational problems or uninsured or underinsured losses affecting Resolute s operations or financial results; government regulation and taxation of the oil and gas industry, including the potential for increased regulation of underground injection operations; changes in derivatives regulation; developments in oil-producing and gas-producing countries; Resolute s relationship with the Navajo Nation and the local Navajo community in the area in which Resolute operates; and the success of strategic plans, expectations and objectives for future operations of Resolute. Actual results may differ materially from those contained in the forward-looking statements in this presentation. Resolute undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after the date of this presentation. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. You are encouraged to review Item 1A. - Risk Factors and all other disclosures appearing in the Company s Form 10-K for the year ended December 31, 2012 and subsequent filings with the Securities and Exchange Commission for further information on risks and uncertainties that could affect the Company s businesses, financial condition and results of operations. All forward-looking statements are qualified in their entirety by this cautionary statement. Non-GAAP financial measures: This presentation includes certain non-gaap financial measures. A reconciliation of these measures to the most directly comparable GAAP measure is presented in the Appendix. 2
3 Resolute analyst day Conference call information Resolute Energy Corporation will hold a webcast June 19, at 3:00 p.m. Eastern Time, to allow analysts and shareholders the opportunity to hear management provide a comprehensive operational overview. The call is being webcast and can be accessed at the Resolute Energy Corporation website at Investors can also access the webcast at Slides will be posted at The webcast will be available for replay through September 19, Live participant dial in (toll free): Live participant dial in (international):
4 Resolute overview Company history Resolute formed Aneth Field: Assets acquired from Chevron Texaco Aneth Field: Assets acquired from ExxonMobil Market capitalization 1 $642.9 million SEC PV 2 10 $1.26 billion Long term debt 3 $792 million Shares outstanding million Debt to EBITDA 5 4.4x Interest coverage 5 4.2x SEC case proved reserves 2 87 MMBoe Oil 76% NGL 13% Gas 11% R/P ratio 6 23 years Powder River Basin assets acquired Entered Bakken trend joint venture with Halcon IPO Expanded Bakken trend farm out from Marathon Delaware Basin: Entered Wolfbone play Midland Basin: Acquired producing properties Reinforced Permian Basin presence Acquisitions in Midland Basin, Delaware Basin and Northwest Shelf 1. Assumes share price of $8.36 (closing price on June 18, 2013), 76.9 million common shares outstanding as of June 18, As of December 31, 2012, pro forma for all 2012 and first quarter 2013 acquisitions and divestitures. 3. As of March 31, As of June 18, As of March 31, 2013, pro forma for all 2012 and first quarter 2013 acquisitions and divestitures. 6. R/P ratio calculated using year end 2012 SEC case proved reserves and actual net production from
5 Our operating areas Pro forma proved reserves are 89% liquids Areas of operation Proved reserves by area 1 Bakken properties Wyoming properties Aneth Field properties Denver headquarters 2013 capital expenditures by area 2 Permian properties 1.Pro forma amounts for the year ended December 31, 2012, give effect to the Permian acquisitions as if they had occurred on January 1, Based on midpoints of April 5, 2013, guidance. 5
6 Company overview In Aneth Field Resolute continues to increase production by expanding and optimizing water and CO 2 floods In the Powder River Basin Resolute is targeting exploration plays in the Turner, Mowry and Minnelusa In the Permian Basin Resolute completed great acquisitions at year-end 2012 and in March 2013 We began drilling in 1st quarter We assumed operating responsibilities on most of the acquired properties in the second quarter We will spud the first of three Permian horizontal wells this month Resolute s dramatic increase in production from 2012 to 2013 is primarily the result of these acquisitions Resolute s planned 2013 activities, along with the activities of other industry participants, set up potential for an exciting drilling program in
7 Agenda Wednesday, June 19, :30 pm to 12:00 pm Registration and reception 12:00 pm to 1:00 pm Lunch 1:00 pm to 1:15 pm Company overview 1:15 pm to 2:30 pm Aneth Field 2:30 pm to 2:45 pm Break 2:45 pm to 4:00 pm Permian Basin 4:00 pm to 5:00 pm Northern Rockies 5:30 pm Evening reception 7
8 2013 production and cost guidance 50% production growth, improved cash margin 2012 actual 2013 range Improvement vs Projected total production (MBoe) 3,409 4,750 5,500 50% Boe/day 9,313 13,000 15,000 50% Projected costs LOE ($ per Boe) 2 $23.45 $20.63 $ % G&A ($ per Boe) 2 $4.49 $4.73 $5.05 (9%) Production taxes (% of prod. revenue) 13.8% 12.0% 13.0% 9% DD&A ($ per Boe) $23.00 $24.00 $26.00 (9%) Projected capital expenditures ($ million) 3 $217 $195 $220 4% On a revenue-basis: Oil = 91%; Liquids = 95% 4 On a volume-weighted basis: Oil = 78%; Liquids = 83% 4 1. Based on 2012 actuals to midpoint of 2013 range 2. Boe statistics compare low point of production range to low point of cost range and high point of production range to high point of cost range 3. Excludes Permian Basin acquisitions of $248 million in December 2012 and $256 million in March Based on midpoints of April 5, 2013, guidance. 8
9 Aneth Field
10 Aneth Field introduction Foundation asset Bbl/day 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 Aneth Field gross oil production forecast 2013 Oil production increases 60% from 2009 to peak Development of Ratherford CO 2 leads to higher peak and extends plateau After peak production, Aneth will experience a long, slow natural decline of about 7% per year far less than the hyperbolic declines typically seen in other plays Fields like Aneth are rare: Excellent current economics and cash flow Large OOIP, presenting ongoing opportunities to improve recovery efficiencies Large CO 2 recovery project, unlocks millions of additional recoverable barrels of oil Located 25 miles from the largest naturally occurring CO 2 resource in the country Production enhancement achieved with modest capital spending Nominal maintenance capex 10
11 Aneth Field introduction Foundation asset Aneth Field 1.5 billion barrels OOIP ~43,000 gross acres 719 wells 391 producers 328 injectors Produced 430 MMBbl of oil through 2012 Net proved reserves of 56.3 MMBoe 1 Q production (98% oil) 11,665 Boe/day gross 6,037 Boe/day net R/P ratio of 25 years 1. As of December 31, 2012, pro forma for all 2012 and first quarter 2013 acquisitions and divestitures. 11
12 Aneth Field geology Giant conventional oil field PhiH: Lower Ismay and Desert Creek Lower Ismay Gothic shale Zone I A B C Chimney Rock shale Akah Zone II Zone III Desert Creek Carbonate stratigraphic trap Conventional oil productive reservoir Porosity of five to fifteen percent Permeability up to 100 millidarcies Principal producing zones: Desert Creek at 5,600 feet Lower Ismay at 5,500 feet 12
13 Aneth Field economics Strong netbacks per barrel of production 2012 actual Operating income = $47.06 Production taxes = $12.56 Workover = $8.50 LOE = $16.70 $ / Boe 1 Category 2012 Operating income $ Overhead 1.58 Severance taxes 5.13 Ad valorem taxes 7.43 Workover 8.50 Equipment and materials 0.97 Fluids and chemicals 1.36 Other Power and fuel 3.48 Labor 4.39 Site repair and maintenance 4.45 Contractual differential of $6.25 per barrel from Nymex (2012 Nymex price was $91.07) Lease operating expense per Boe of production expected to decline as oil production grows 1.Excludes realized derivative settlements and non-cash expenses 2.Includes tools, equipment, water disposal, health, safety, compression, gathering, inspection, property maintenance and insurance expenses 13
14 Aneth Field cash flow Free cash flow from Aneth funds growth Net production for 2013 is expected to be 6,400 to 6,700 Boe/day This reflects the sale of working interest to Navajo Nation Oil and Gas Company in January 2013 Assuming 2012 net operating margin of $47.06 per barrel would generate operating cash flow of $110 to $115 million Forecast CO 2 purchases of $20 to $22 million Discretionary cash flow of $90 to $93 million Non-CO 2 capital budget for 2013 is $50 to $58 million Free cash flow of $35 to $40 million 14
15 Historical CO 2 response by unit 25 years of CO 2 response at Aneth Field McElmo Creek Unit CO 2 flood initiated in McElmo Creek Unit in in Oil production increased by ~30% over a 13-year period 1 Production returned to a state of natural decline in 1998 Resolute s activities flattened the decline in 2006 and increased production in 2011 Aneth Unit Resolute s comparatively faster CO 2 implementation is creating superior incremental performance in the Aneth Unit 1. A portion of that increase may have been the result of the operator drilling 24 infill/enhancement wells during the early years of the flood 15
16 Aneth Unit CO 2 flood Continuing production growth Aneth Unit PhiH map Aneth Unit CO 2 injection Pilot area CO 2 injection progression Aneth Unit encompasses 17,000 gross acres with OOIP of 534 MMBbl Texaco initiated a successful CO 2 pilot in 1998 in the northeast corner of the unit, but it never expanded project further Resolute took over operations in 2004 and initiated a CO 2 program in phases, with first injection occurring in 2007 Significant opportunity exists for incremental recoveries in Aneth Unit through CO 2 injection Estimated ultimate recovery of 40% of OOIP CO 2 injection progression 16
17 Aneth Unit CO 2 project area performance Production increase of 123% Oil production (Bbl/day) 4,000 3,500 3,000 2,500 2,000 1,500 1, CO 2 project area oil production (gross) Aneth Unit response: +2,100 Bbl/day From inception of the CO 2 project area flood, production has increased 123% Total production is up 2,100 gross Bbl/day over the forecast waterflood base decline Based on SEC parameters we expect to achieve incremental gross oil recovery of 45 MMBbl due to CO 2 flood Phase 1, 2 and 3 Phase 4 OOIP (MMBbl) Construction commenced First CO 2 injection July 2007 November 2011 First response November 2008 September Does not include Lower Ismay, Desert Creek III or the Pilot area OOIP 17
18 Aneth Unit CO 2 economics Attractive project economics Aneth costs ($ million gross) Type Spent to date Future discounted 1 Total CO 2 $99 $189 $288 Facilities $224 $107 $331 Total $323 $296 $619 Total incremental recovery 2 Discounted finding and development cost 45 MMBoe $13.76 per Boe 1. Reflects the PV 10 of CO 2 capital over 30+ year project life and facilities capital over four years 2. Includes incremental production to date 18
19 McElmo Creek Desert Creek IIC project Bypassed zone within active CO 2 flood area DC IIC Lower Ismay Gothic shale A B C Zone I Chimney Rock shale Akah Zone II Zone III Desert Creek DC IIC was a prolific producing zone under waterflood starting in the 1960s Zone was abandoned in the 1970s due to high water cuts and low commodity prices DC IIC zone within the central portion of the McElmo Creek Unit was not open when CO 2 flood commenced in 1985 Resolute activities started in 2010 Reactivate waterflood Increase production Re-pressurize zone Pilot CO 2 flood project now active Expanded injection of CO 2 expected to begin in
20 DC IIC project area waterflood Exceptional results from waterflood reinitiation DC IIC waterflood pair (gross) Total capital per well pair Initial incremental production Total reserves $1.8 million 110 Bbl/day 60.1 MBO Finding and development cost $29.95 DC IIC waterflood reactivation entails completions of injector/producer pairs 70 pairs within the core area; 25 pairs completed to date Incremental peak oil rates from the producers averaged 110 Bbl/day and ranged from 0 to 460 Bbl/day Targeting 10 producer/injector pairs for completion in 2013, leaving 35 projects for future years Re-pressurization through waterflood sets up future CO 2 projects by raising reservoir pressure above the minimum miscibility pressure 20
21 McElmo Creek DC IIC development Project background and PhiH map McElmo Creek Unit Production is 100% oil CO 2 pilot project commenced in 2012 Incremental production expected to grow 29% per year between 2014 and 2019; consistent 8% decline thereafter OOIP 84 MMBbl When combined with the waterflood reactivation incremental recovery should approach 17% or 14.6 MMBbl 1 mile 21
22 McElmo Creek DC IIC economics Significant resource in bypassed zone McElmo Creek DC IIC costs ($ million gross) Type Spent to date Future discounted 1 Total CO 2 - $51 $51 Facilities $34 $137 $171 Total $34 $188 $222 Total incremental recovery 2 Discounted finding and development cost 14.6 MMBoe $15.21 per Boe 1. Reflects the PV 10 of CO 2 capital over 40+ year project life and facilities capital over four years 2. Includes incremental production to date 22
23 Ratherford Unit introduction Significant unbooked upside Ratherford Unit OOIP Recovery to date Significant opportunity exists to enhance production in Ratherford Unit through waterflood optimization and future CO 2 flood Optimize existing waterflood by improving processing rates across the unit using Redrills Infill laterals Injector / producer sidetracks Initiate a CO 2 flood within the Ratherford Unit primarily targeting the DC IIC and DC IA zones Ratherford Unit 435 MMBoe ~105 MMBoe Ultimate recovery efficiency as currently engineered and without CO 2 26% 23
24 Ratherford CO 2 flood development projects Two project areas sum of DC IIC and DC I PhiH Ratherford Unit DC IIC project area Resource potential is not currently included in our engineering Resource potential of 11 MMBbl net to Resolute from just these two projects DC IIC Number of patterns 39 Resource potential (gross) 5 7 MMBbl DC I CO 2 flood in existing wells and laterals. Could occur in series or parallel with DC IIC 1 mile DC I Number of injectors 45 Resource potential (gross) MMBbl 24
25 Aneth Field other opportunity inventory High rate of return projects Infill laterals (gross) New drills (gross) Gross capital $0.8 $1.2 million per project Gross capital $1.8 $2.3 million per project 30 day IP Bbl/day 30 day IP Bbl/day EUR MBO EUR MBO Rate of return 40% 60% Locations 9 15 Rate of return 20% 35% Locations Resource potential 675 3,000 MBO Resource potential 3,750 6,000 MBO Short lateral pairs to improve processing rate Gross capital $1.6 $2.0 million per project 30 day IP Bbl/day Rate of return 40% 60% Locations Resource potential Economic acceleration Opportunity inventory captures currently identified projects This inventory is not exhaustive Success will expand these kinds of opportunities throughout the field 25
26 B-414 case study B-414 PhiH map -960 DC-IIB -960 DC-IIA Completed well cost Cumulative production through Q Peak daily rate B-414 $2.0 million 111 MBbl 832 Bbl/day Injector Producer C acre infill project completed in March 2012 Two offset injectors and one producer are permitted Scheduled to drill in Q EUR: 250 to 300 MBO (gross) Project rate of return ~30% Oil production (Bbl/day) Gross monthly average daily production Feb-12 May-12 Aug-12 Nov-12 Jan-13 26
27 Membrane plant Source: Membrane plant Current recycled gas stream in Aneth and McElmo Creek Units contains high quantities of hydrocarbons Membrane plant designed to separate methane and NGL from re-injected CO 2 stream Peak input of 100 MMcf/day based on forecast gas production yields 8 MMcf/day of methane and 1,500 Bbl/day of NGL, and purifies CO 2 stream for reinjection Currently reviewing project design and economics 27
28 CO 2 supply Long term contract in place McElmo Dome CO 2 field Long term contract with Kinder-Morgan Resolute pipeline connects field to McElmo Dome Current capacity: 68 MMcf/day with existing pump at McElmo Creek Unit Plan to increase capacity to 100 MMcf/day in Q through installation of second pump Contractual limits: 72 MMcf/day maximum for MMcf/day maximum for 2014 and
29 Aneth Field potential Reserve upside from identified projects Area (Average WI% / NRI%) Total proved reserves (MMBoe) 1 Aneth Unit (62% WI / 54% NRI) Inventory Vertical wells and CO 2 projects 29 - Resource potential (MMBoe) Horizontal wells 2 - New drills - 15 locations Short laterals (injector/producer pair) 2 - Acceleration project McElmo Creek Unit (68% WI / 55% NRI) Vertical wells and CO 2 projects 18 - New drills locations Short laterals (injector/producer pair) - - Acceleration project Ratherford Unit (59% WI / 51% NRI) Vertical wells 2 DC IA - 39 patterns DC IIC - 45 patterns New drills locations Laterals locations Total Year end 2012 SEC pro forma reserve report 29
30 Permian Basin
31 Permian Basin introduction In Q Resolute acquired acreage and began drilling in Reeves County in the Delaware Basin ( Reeves County ) Resolute subsequently acquired a small producing asset in the Midland Basin ( OTB ) Resolute started hiring core Permian Basin staff in November 2011 and opened a Midland office in June Current Midland-based staff is more than 30 employees covering key technical and managerial skills In December 2012 Resolute acquired producing properties and undeveloped acreage in the Midland Basin ( Big Spring ) and in the Northwest Shelf area of the Delaware Basin ( Denton ) Also in December 2012 Resolute acquired approximately 32% of certain producing properties and undeveloped acreage in the Midland Basin ( Gardendale ) In March 2013 Resolute acquired the remaining 68% of Gardendale 31
32 Permian Basin Transformational asset base 41,100 gross (20,300 net) acres 67% HBP; 90% operated 70% oil (based on Q1 production) 55% proved developed Q1 pro forma net production 5,030 Boe/day 1 Approximately 400 vertical drilling locations Provides exposure to some of the most attractive horizontal plays in the Permian Basin: 70 gross potential locations Two to five potential horizons per location Denton Northwest Shelf NM Delaware Basin Permian Basin map Central Basin Platform Reeves County Gardendale Midland office TX Midland Basin OTB and Big Spring 40 Miles 1.Pro forma amounts for the quarter ended March 31, 2013, give effect to the Permian acquisitions as if they had occurred on January 1,
33 Gardendale overview Assumed operating control on April 1 st Gardendale 1 mile 4,600 gross and net acres Q1 pro forma net production was 3,140 Boe/day drilling objectives: Three horizontal wells targeting the Wolfcamp B Twenty vertical wells Collecting microseismic data (vertical and horizontal) Refining petrophysical models and integrating seismic to refine development scenario Northwest Shelf NM Central Basin Delaware Platform Basin Midland Basin Eastern Shelf TX 1.Pro forma amounts for the quarter ended March 31, 2013, give effect to the Permian acquisitions as if they had occurred on January 1,
34 Gardendale stratigraphic column Horizontal and vertical potential Midkiff 1818H ~4,300 lateral planned Vertical completion interval Lower Clearfork 1 st Spraberry 2 nd Spraberry Basal Spraberry Dean Wolfcamp A Wolfcamp B Planning three Wolfcamp horizontals in 2013 Primary horizontal target is the Wolfcamp B Positive offset results Positive reservoir characteristics Secondary targets/potential: Basal Spraberry and the Wolfcamp A. Additional targets exist within the stratigraphic column Stacked potential Current vertical wells may target the Spraberry through the Atoka Seven to ten vertical completion stages per well Cline Strawn Atoka 34
35 Gardendale well activity Wolfcamp B horizontal results Gardendale Resolute horizontal locations 1 2 Nearby Wolfcamp B activity 1 24 hr IP rate (Boe/day) 30 day IP rate (Boe/day) Diamondback ST NW 2501H 1, Diamondback ST NW 2502H RSP Kemmer 4209H RSP Sarah Ann 3812H horizontal location Horizontal locations Completed Spud Permitted 1 mile 1.Based on publically disclosed information 35
36 Gardendale horizontal Midkiff 1818H Anticipate spud in early July Drilling Targeting Wolfcamp B horizon at 9,800 feet TVD Approximately 4,300 feet of cased and cemented lateral Drill and case cost: $3.1 million Completion Planning plug and perf completion Completion cost: $4.2 million (includes microseismic data acquisition) Wolfcamp B 36
37 Gardendale horizontal Type curve and economics 1 Gardendale horizontal wells Gross capital $7.1 million per well 30 day IP 400 1,000 Boe/day EUR (gross) MBoe Btu per Mcf 1,300 Rate of return 25% 45% Locations Resource potential (gross) 2 22 locations with multiple horizons MMBoe 1.Volumes reflect a three month moving average 2.Unrisked. Range of horizons two to four; average WI 100%, NRI 75% 37
38 Gardendale vertical development overview Halfway through 2013 vertical drilling plan Gardendale Resolute s current plan is to drill twenty vertical wells in 2013 Ten wells have been spud to date We anticipate completing three to four wells per month Three wells have been completed and are flowing back; very early indications are that they are in line with our expectations Producing Spud/drilled in mile To be drilled in
39 Gardendale vertical Type curve and economics Gross capital Gardendale vertical wells $2.1 million per well Bbl/day, Mcf/day and Boe/day day IP Boe/day EUR (gross) 125 MBoe Btu per Mcf 1,300 Rate of return 25% 35% Locations 40 Resource potential (gross) 1 5 MMBoe Months Oil Wet gas Boe 1. Unrisked. Average WI 100%, NRI 75% 39
40 Reeves County overview Potential horizontal development Northwest Shelf NM Mustang Central Basin Delaware Platform Basin Midland Basin Eastern Shelf TX Reeves County Appaloosa Acreage acquired in 2011 and ,000 gross (8,200 net) acres Vertical drilling program commenced in Q gross (10.6 net) wells Two primary project areas: Mustang area average working interest of 51% Appaloosa area working interest of 100% Q1 net production 246 Boe/day (59% oil) Transitioning from vertical development to horizontal wells targeting the Wolfcamp shale 40
41 Reeves stratigraphic column Horizontal and vertical potential 3 rd Bone Spring Upper Wolfcamp Wolfcamp A Wolfcamp B Wolfcamp C 1,250 feet of stacked potential in the Wolfcamp Organic rich shales and carbonates with encouraging log characteristics Resolute s current vertical wells are completed in various intervals from the Third Bone Spring through the Wolfcamp D Offset operators appear to be targeting the Wolfcamp A, C and D Stacked horizontal potential with meaningful upside based on potential downspacing Monitoring offset activity with an ongoing focus on horizontal development Wolfcamp D 41
42 Reeves County horizontal activity Resolute potential horizontal locations Delaware Basin Horizontal location Apache permit 11/12 BHP spud 1/13 Cimarex spud 4/13 Apache spud 2/13 6 Cimarex spud 3/13 EOG spud 3/ mile 42
43 Nearby horizontal activity Offset results 1 Well name Zone Reported production rates Lateral length 1 EOG HR H Wolfcamp A One day IP: Oil: NGL: Gas: 635 Bbl/day 480 Bbl/day 3,100 Mcf/day ~4, EOG HR H EOG Apache St H Cimarex Big Sky H Devon Gorden State 24-2H Cimarex Dixieland 10-1H Wolfcamp C Wolfcamp Wolfcamp D (6/11) Wolfcamp A (3/12) Wolfcamp D (3/11) One day IP: Oil: 377 Bbl/day NGL: 602 Bbl/day Gas: 3,900 Mcf/day One day IP: Oil: 815 Bbl/day NGL: 600 Bbl/day Gas: 3,800 Mcf/day IP 30: Oil: 201 Bbl/day Wet gas: 2,185 Mcf/day IP 30: Oil: 296 Bbl/day Wet gas: 970 Mcf/day One day IP: Oil: 136 Bbl/day Wet gas: 1,258 Mcf/day ~4,500 ~4,500 ~4,000 ~4,200 ~3,000 1.Based on publically disclosed information 43
44 Delaware Basin horizontal wells Type curve and economics 1 Delaware Basin horizontal wells Gross capital $7.0 $8.0 million per well 30 day IP Boe/day EUR (gross) 500 1,000 MBoe Btu per Mcf 1,230 Rate of return 20% 40% Locations 50 locations with multiple horizons Resource potential (gross) MMBoe 1. Unrisked. Range of horizons two to five, average WI 63%, NRI 47% 44
45 OTB and Big Spring Area overview OTB and Big Spring Howard OTB Martin Big Spring Resolute leasehold 1 mile 4,400 gross (2,200 net) acres More than 90% HBP Vertical Wolfberry asset 42 gross (25.4 net) producing wells Q1 pro forma production ~800 Boe/day 1 We believe the horizontal activity will move this way Northwest Shelf NM Central Basin Delaware Platform Basin Midland Basin Eastern Shelf TX 1.Pro forma amounts for the quarter ended March 31, 2013, give effect to the Permian acquisitions as if they had occurred on January 1,
46 OTB and Big Spring vertical Wolfberry Midland Basin Wolfberry development Vertical completion interval Spraberry Dean Wolfcamp Cline Canyon Strawn Mississippian Targeting Mississippian at 10,500 feet through Wolfcamp at 8,500 feet Typically a seven stage completion not including the Spraberry Drill and complete cost approximately $2.3 million Spraberry recompletion opportunities behind pipe Gross capital OTB / Big Spring vertical wells $2.3 million 30 day IP 134 Boe/day EUR (gross) MBoe Rate of return 25% - 30% Locations 64 Resource potential (gross) 1 1. Unrisked. Average WI 81%, NRI 61% MMBoe 46
47 Broader Big Spring area opportunity inventory Inventory of high rate of return projects Behind pipe Spraberry at 7,000 to 8,000 feet Anticipate completing the Spraberry after de-pressuring deeper zones approximately eighteen months after the initial completion Recompletes Gross capital $0.6 million 30 day IP 81 Boe/day EUR (gross) MBoe Rate of return 40% 50% Locations Resource potential (gross) MMBoe 1. Unrisked. Average WI 81%, NRI 61% 47
48 Denton Field overview Acquired producing asset in 2012 Denton Field 1 mile Siluro-Devonian carbonate field discovered in 1949 Highly faulted and fractured anticline Cumulative production through December 2012: ~110 MMBbl of oil ~100 Bcf of gas Some individual wells have produced more than two million barrels of oil Normally pressured reservoir at a depth of ~12,000 feet Q1 net production of ~800 Boe/day (88% oil) Northwest Shelf NM Central Basin Delaware Platform Basin Midland Basin Eastern Shelf TX 48
49 Denton Field opportunities Legacy field with significant upside Denton reservoir interval Woodford Silurian Improving field economics by lowering operating costs and increasing reliability Enhance the field through capital projects Infill drilling down to 20 acre spacing Deepening wells that were never completed throughout the entire Silurian section Well optimization work Evaluating seismic 49
50 Permian Basin potential Significant growth from horizontal activity Area Total proved (MMBoe) 1 Inventory Gardendale (100% WI / 75% NRI) Resource potential (MMBoe) Vertical locations Horizontal - 22 locations with multiple horizons Other 3 48 recompletes Delaware Basin (63% WI / 47% NRI) Vertical locations with Horizontal - multiple horizons OTB / Big Spring (81% WI / 61% NRI) Vertical 4 64 locations Other - 64 recompletes Denton / Other (77% WI / 61% NRI) Vertical Total Year end 2012 SEC pro forma reserve report 50
51 Wyoming 51
52 Wyoming introduction Big Horn Basin Powder River Basin Established operations with the 2008 acquisition of Hilight Field Our PDP production provides excellent free cash flow Our acreage position is well situated and provides a base from which to expand in the region Powder River Basin is seeing substantial renewed activity on the part of industry, targeting tight oil plays utilizing modern technology including horizontal drilling and multi-stage hydraulic fracing Active plays include Parkman, Sussex, Shannon, Niobrara, Turner/Frontier and the Mowry 52
53 W Hilight Field Excellent cash flow and exploration upside Hilight Field T46N-R72W T45N-R72W RESOLUTE GRADY UNIT T44N-R72W T46N-R71W T45N-R71W T44N-R71W T46N-R70W T45N-R70W RESOLUTE CENTRAL HILIGHT UNIT T44N-R70W RESOLUTE JAYSON UNIT T46N-R69W T45N-R69W T44N-R69W 49,600 gross (45,400 net) acres 100% HBP 100% operated 15% oil production 90% proved developed Q1 production 1,535 Boe/day 3.5 MMBoe proved reserves The Muddy formation, the productive zone in Hilight Field, had 345 MMBoe OOIP To date the Muddy formation has produced 68 MMBbl and 162 Bcf WY 53
54 Hilight Unit stratigraphic column Stacked prospective horizons Horizontal targets GR R_DEEP Niobrara Niobrara C Niobrara E Turner Current focus is on horizontal Turner potential and vertical Mowry recompletes Secondary targets/potential in the Niobrara C and E benches Low risk Muddy refracs to moderate production decline Deeper Minnelusa prospects identified by 3D seismic 9500 Mowry Muddy Current Resolute production 54
55 Turner prospect area Plan one horizontal test in 2013 T45N-R72W T44N-R72W Turner prospect area T45N-R71W T44N-R71W Castle 3-21H Spud: Q T45N-R70W 12,000 gross acres in the southwestern portion of Hilight Field Plan to drill one horizontal Turner well RESOLUTE CENTRAL HILIGHT UNIT T44N-R70W this year Currently permitting eight horizontal locations Pending initial success future development plans call for: Three to five appraisal wells in SOUTH HILIGHT UNIT 2014 Full development starting in 2015 Hilight Field 55
56 Nearby Turner well activity Commencing horizontal program in 2013 T45N-R72W T44N-R72W 4 5 Turner prospect area 3 1 T45N-R71W T44N-R71W 2 T45N-R70W RESOLUTE CENTRAL HILIGHT UNIT T44N-R70W Prospects supported by 3D seismic and subsurface well control 46 horizontal Turner wells have been drilled within 25 miles of Hilight Field Operators include Petro- Hunt, EOG, Devon, Ballard and Yates Approximately 70% oil in offset wells Well name Peak 30 day IP rate (Boe/day) 1 Resolute estimated EUR (MBoe) Petro-Hunt Ellbogen B-1H Petro-Hunt Stuart A-1H Petro-Hunt USA D-1H Devon Durham Ranches TH 352 N/A Devon Waterbuck T Based on publically disclosed information 56
57 Turner well activity Porosity-thickness map correlates offset results Turner prospect area Distribution of offset well EUR with PhiH similar to southern Hilight acreage supports type curve projections Extended production results from recent Devon completions may increase area in Hilight Field prospective for the Turner Petro-Hunt and EOG permitting 10,000 foot laterals in the area 57
58 Turner horizontal Type curve and economics Turner horizontal well Gross capital $5.8 $7.3 million per well 30 day IP Boe/day EUR (gross) MBoe Rate of return 14% 60% Locations 40 Resource potential (gross) MMBoe 1. Unrisked. Average WI 100%, NRI 83% 58
59 Turner development overview Commencing horizontal program in 2013 Turner prospect area Full development on 320 acre spacing 40 gross well locations Additional downspacing in the Turner untested in adjacent areas Castle 3-21H permitting Hilight Field 59
60 Mowry overview The Mowry is the black shale source rock for the Muddy formation oil and gas reserves and production Few offsets drilled to date Recent advances in the industry s understanding of source shales suggest that resource potential remains in the shale of as much as of several times that of expelled hydrocarbons It appears that there should be substantial remaining resource in the Mowry We have been testing vertical refracs in the Mowry with a distribution of results as might be expected Our interpretation of more recent seismic data suggests that the better results may be attributable to fracture swarms caused by deep seated structural movement Our current activity is intended to begin the process of testing that hypothesis Success could lead to an expanded horizontal drilling program targeting the Mowry formation 60
61 T46N-R72W Mowry prospect area Plan completions in three existing vertical wells 3D seismic T47N-R71W T46N-R71W Mowry prospect area T47N-R70W Arco Bishop vertical well EUR MBoe Mowry T46N-R70W T47N-R69W T46N-R69W Potential horizontal locations 9,600 gross acres within a seismically defined project area Our plan for this year is to complete three existing vertical wells to test the 3D seismic concept Pending success we may test a horizontal Mowry well in potential locations Dakota Curvature T45N-R71W T45N-R70W T45N-R69W Basement Curvature T44N-R72W Best EUR in existing recompletes T44N-R71W 2013 recompletes T44N-R70W T44N-R69W 61
62 PETRA 2/5/2013 9:54:01 AM Big Horn Basin exploration Exploration potential Park Big Horn Basin lease map MT WY Hot Springs Mowry Oil Play Area Big Horn Washakie Resolute leasehold 74,000 net acres Federal leases, ten year term; average three years remaining Other operators in area include Plains, Cirque, Bill Barrett and Koch Prospective formations include: Muddy Mowry Phosphoria Frontier WY 62
63 Bakken 63
64 Williston divestiture status Bakken Other BMO Capital Markets providing advisory services Multiple bids received Purchase and sale agreements being negotiated Due diligence is ongoing Anticipate July/August closings ND 64
65 Resolute potential Reserve upside from identified projects Area Total proved reserves (MMBoe) 1 Resource potential (MMBoe) Total (MMBoe) Aneth Field Permian Basin Northern Rockies Total Year end 2012 SEC pro forma reserve report 65
66 Key investment highlights Well-positioned to execute growth plan High quality base of long-lived oil producing properties Portfolio of significant organic development opportunities Exploration projects poised to provide incremental value Strong project returns and improving cost metrics Proven, experienced management and technical teams 66
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