Sustainability of Wolfcamp Development Water Recycling and Maximizing Infrastructure

Transcription

1 Sustainability of Wolfcamp Development Water Recycling and Maximizing Infrastructure J. Ross Craft Chairman and Chief Executive Officer Approach Resources Inc. Executive Oil Conference Water Forum November 6, 2017

2 Forward-looking statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including as to the Company s Wolfcamp shale resource play, estimated resource potential and recoverability of the oil and gas, estimated reserves and drilling locations, capital expenditures, typical well results and well profiles, type curve, and production and operating expenses guidance included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. When used in this presentation, the words will, potential, believe, intend, expect, may, should, anticipate, could, estimate, plan, predict, project, target, profile, model or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Cautionary statements regarding oil & gas quantities The Securities and Exchange Commission ( SEC ) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms estimated ultimate recovery or EUR, reserve or resource potential, and other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC s rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. EUR estimates, identified drilling locations and resource potential estimates have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Company s interest may differ substantially from the Company s estimates. There is no commitment by the Company to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of the Company s drilling project, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and actual drilling results, as well as geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per well EUR and resource potential may change significantly as development of the Company s oil and gas assets provides additional data. Type/decline curves, estimated EURs, resource potential, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, recovery factors and costs prove correct. The Company has limited production experience with this project, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of resource potential and EURs do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. Unless otherwise noted, IRR estimates are before taxes and assume NYMEX forward-curve oil and gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs. 2

3 Solid foundation for long-term value APPROACH RESOURCES OVERVIEW ASSET OVERVIEW Enterprise value 600 MM 1 High-quality reserve base MMBoe proved reserves 62% liquids, 31% oil Permian Basin core operating area 124,000 gross (111,000 net) acres ~1+ BnBoe gross, unrisked resource potential ~1,500 identified HZ drilling locations ~100% working interest Large contiguous acreage position with multiple benches Prolific Wolfcamp shale is the largest estimate of unconventional oil ever assessed by USGS 3 Capital program focused on aligning capex with cash flow Stable leasehold that is largely HBP provides for flexible budget Improving commodity prices would allow us to seamlessly increase capital budget, funded with operating cash flow Drilled 12 horizontal wells and completed 9 through 3Q17, ended 3Q17 with 9 DUCS DUC inventory provides agility in oil price recovery 1. Enterprise value is equal to market capitalization using net debt as of 9/30/17, the closing share price of $2.57 per share and the share count each as of 10/2/ Proved reserves as of 6/30/17 and acreage as of 9/30/2017. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Reserves were estimated using SEC pricing at June 30, 2017 and were calculated based on the first-of-the-month, twelve month average prices for oil, NGLs and natural gas of $49.00 per BBL, $15.57 per Bbl and $3.02 per MMBtu, respectively, adjusted for basis differentials, grade and quality 3. Per USGS estimates - 3

4 Bolt-0n acquisition highlights Transaction Overview Current production of approximately 550 Boe/d (48% oil) with existing field infrastructure and facilities Estimated PDP reserves of approximately 1.8 MMBoe (42% oil) Funded 100% with Approach stock Valuation in line with PDP value at NYMEX strip Total acreage post acquisition 166,625 gross (150,140 net) (1) Upton Reagan Irion 124,000 gross (111,000 net) acres Tom Green ~ 3,200 net producing acres, held by production Enhances credit metrics Reduces leverage by a half turn. Strategic Benefits Accretive to earnings and cash flow Pecos Terrell 42,625 gross (39,140 net) acres Approach Leasehold Bolt-on Acquisition Crockett Schleicher Sutton Miles 0 20 Improves margins and best-in-class cost structure Seamless integration of operations and production Complementary bolt-on asset Shared lease line with Approach s Pangea West acreage (1) Approximately 35,000 net acres subject to short term expiration and continuous drilling obligation in December 2017 Undeveloped acreage optionality Optionality/potential upside from ~35,000 net undeveloped acres 4

5 Long history of operating in Midland Basin WELLS DRILLED TO DATE 140 Drilled more than 750 wells in Midland Basin since Vertical gas wells & 187 Horizontal oil wells One of the first-movers in the HZ Wolfcamp play with longest production history and track record of full-scale development Well data, core data, 3-D seismic and micro-seismic reduces future development risk Focused execution through commodity cycles YTD Vertical Horizontal 12 5

6 Approach continues to achieve one of the lowest cost structures in the Permian Basin AREX D&C Historical Track Record ($ MM) $9.0 $8.6 $8.0 54% reduction since 2011 $7.0 $7.0 $6.56 $6.0 $5.8 $5.5 $5.0 $4.5 $4.0 $3.5 $4.0 2 $3.0 $2.0 $1.0 $ YTD Peer Average 2Q Source: Latest available company presentations and public filings. Peers include CPE, CXO, EGN, EPE, FANG, LPI, MTDR, PE, PXD, and RSPP. 2. For standard 7500 lateral well 6

7 LOE cost reductions driven by water handling infrastructure and field-level operating efficiencies AREX LOE Historical Track Record ($/Boe) $7.00 $6.48 $6.00 $0.99 $5.24 $5.00 $4.00 $1.69 $0.95 $0.79 $4.24 $0.62 $4.05 $0.71 Pumpers & Supervision $3.00 $1.90 $1.66 $0.95 $0.85 Well Repairs, Workover & Maintenance $2.00 $1.09 $0.83 Water hauling $1.00 $1.90 $1.84 $1.58 $1.66 Compressor Rental & Repair $ YTD17 7

8 Results outperform type curve 8

9 Approach asset base is unique due to low capital intensity 9

10 Strategic midstream asset PW DCP Tap Reagan Receipt Point Receipt Point Irion Crockett Schleicher PW CS #1 BLK 50 Compressor Receipt Point PW Pit PW 5701 SWD 228HA 204HA LACT PW Commingle Facility PANGEA WEST Receipt Point Receipt Point Receipt Point JPE Energy BLK 45 DCP Tap BLK 45 N Compressors 1401 SWD BLK 45 S Compressors Receipt Point Pit Baker Baker Pit 2 CS 1 2 Baker DCP Tap LACT BLK 42 / CT DCP Tap 1 2 LACT Recycle Facility 190 Pit LACT Baker Station Baker 101 SWD NORTH & CENTRAL PANGEA BLK 42 CS Baker Pit Pit 42 Commingle Facility LACT X SWD Nabors 16-1 SWD Midway Truck Station CT Compressor West 2106 SWD Pit Moore Pit Elliott Facility BLK 54 Pit BLK 54 Compressor DCP Tap Reduce D&C cost Reduce LOE Water Recycling Center 329,000 Bbl Capacity Increase project profit margin Minimize fresh water use, truck traffic and surface disturbance Recycled water has a positive impact on well performance due to chemical properties similar to those of formation Enhanced Oil Recovery OZONA Jim Terry Pit DCP Processing Plants Childress Pit Gas gathering lines Approach Bailey Compressor Childress Pit DCP Tap SOUTH PANGEA Rousselot Pit Sutton 10

11 Midland Basin significant shortage of frac water supply Mining Water Allocated (MMBbls) Water (MMBbls) Potential Water Needed for Wolfcamp Development Wolfcamp oil shale development using mining water allocated is not sustainable 150 Need alternative water 100 source to develop this vast resource Year 11

12 Midland Basin significant cost for sourcing, transporting & disposing frac water Water Sourcing Well $ Lease Road Local Highway $$$ Road damage Air pollution $4-5 per barrel (2012 early 2015) $1,200,000 - $1,500,000 per well Well Pad $$$ Road damage Air pollution ~$79 billion - ~$99 billion Lease Road Local Highway $ For the remaining wells Salt Water Disposal Well 12

13 Produced / flowback water quality Can produced / flowback water be used for fracing after processing? Total dissolved solids (TDS) Will not impede gelling hydration (E. Gruber) Treated high TDS (in excess of 270,000 ppm) water has been shown to be an effective base fluid for fracing (R. Lebas et al) Total suspended solids (TSS) Precipitation o o Filtration o Sulfate (SO 4-2 ) Chemical Gravitational Mechanical Heavy metals including Barium (Ba), Iron (Fe), Manganese (Mn) Bacteria Increasing Sensitivity Relative Fluid Sensitivity for Wolfcamp Well #1-20% Clay Well #2-21% Clay Well #3-22% Clay Well #4-26% Clay Well #5-28% Clay Well #6-30% Clay Well #7-30% Clay 7% KCl 3% NaCl Fresh 13

14 AREX flowback and produced water recycle facility Designed one of the highest industry KPI for water treatment Bacteria Sulfates Heavy metals Fines Best practice for water conservation and improving water use efficiency Reduces demand on fresh water sources Reduces road damage & air pollution Reduces D&C cost Reduces SWD cost 14

15 AREX flowback and produced water recycle facility N Centralized SWD Hauling Station Water Treatment 4 Connections & Filtration Facility 32,000 BBL Treated Water Tank 63,000 BBL Treated Water Tank 63,000 BBL Treated Water Tank 32,000 BBL Treated Water Tank 63,000 BBL Treated Water Tank 44,000 BBL Treated Water Tank 90 BPM Pump Station 8 Flowback & Produced Saltwater Line 8 Low Chloride Treated Frac Water Supply Line 20 Treated Flowback & Produced Frac Water Supply Line Flowback / Produced Water Separator Dirty Water Tank Chemical Treatment & Centrifuge 12 Poly Skim Oil Sales 32,000 BBL Dirty Water Tank 32,000 BBL Treated Water Tank Treated Water Tank Flowback & Produced Water Offloading Terminal & Separation Facility Flowback & Produced Water Supply Pump Station & Water Supply Line 15

16 AREX water recycling facility successfully implemented 30,000 Started up in March 2015 Ramped up during April 2015 Recycled up to 100% of AREX daily flowback/produced water volumes More than 2.2 million barrels of water treated More than $7mm of cost saved or value created 25,000 20,000 Recycled Water (Bbls/d) 15,000 10,000 5,

17 Significant cost saving for using recycled water for fracing Flowback / Producing Well Cost for recycled water $ $0.80 per barrel Waste Water Via existing water gathering lines Water Recycling Center KPI Physical Chemical $ per barrel $0.40 $0.60 per barrel $ $0.10 per barrel Cost saving for using recycled water & existing infrastructures $ $4.50 per barrel Cost saving for using recycled water $0.96mm - $1.35mm per well Via existing water transportation lines Valuable Water $63 billion - $89 billion saving For the remaining wells in Midland Basin Well Pad Ready For Fracing 17

18 Well pads serviced by centralized compressor and shared gas lift system efficient and significant cost saving Wells ~ 500 ft CPF 1 CPF 2 CPF 3 CPF 4 CPF 5 CPF 6 CPF 7 CPF 8 CPF 9 CPF 10 Low Pressure Gathering Line Low Pressure Gathering Line CS CS Dehy Dehy ~ 2000 ft High Pressure Sale / Gas Lift line 0.75 miles 0.75 miles This configuration saves $7.6 M / well / month 18

19 Approach asset base is unique due to low capital intensity 19

20 Approach gas lift infrastructure may lead to higher well recovery BLK 45 North BLK 45 South Wells with Positive Production Impact Injection Wells Recent pilot test indicates that gas can be reinjected back into the producing wells to increase well production and potentially well recoveries by utilizing existing gas lift infrastructure Baker Production Corridor Gas Injection Line Gas Gathering Line Oil Gathering Line Water Gathering Line Water Supply / Transportation Line 20

21 Approach pilot test results - 29 well injection study Lease: Blk. 45 North Total BOE Injection Gas 10,000 8 of the 21 wells were temporarily converted to injectors during Hurricane Harvey downtime. 124 MMcf of field gas was injected into the Wolfcamp formation over a 11 day period utilizing our extensive gas lift infrastructure system. 13 wells offsetting the injectors reacted positively. 18,000 16,000 14,000 1,000 12,000 BOE 10,000 8,000 Injection Gas (Mcf) 100 6,000 4,000 2,

22 Approach pilot test results - 31 well injection study Lease: Blk. 45 South Total BOE Injected Gas Volume 10,000 8 of the 23 wells were temporarily converted to injectors during Hurricane Harvey downtime. 129 MMcf of gas injected into the Wolfcamp formation over a 20 day period utilizing our gas lift infrastructure system. 15 wells offsetting the injectors reacted positively. 14,000 12,000 1,000 10,000 BOE 100 8,000 6,000 4,000 Injection Gas (Mcf) 2,

23 Approach pilot test results - 15 well injection study Lease: Baker South Total BOE Gas Injection 10,000 5 of the 10 wells were temporarily converted to injectors during Hurricane Harvey downtime. 44 MMcf of field gas was injected into the Wolfcamp formation over a 6 day period utilizing our gas lift infrastructure system. 5 wells offsetting the injectors reacted positively. 12,000 10,000 1,000 8,000 BOE 6,000 Injection Gas (Mcf) 100 4,000 2,

24 Summary An estimated 20 billion barrels of water is required to develop this significant discovery. However, water availability is limited in the Midland Basin due to 1) limited rainfall, 2) high evaporation rate, 3) low reservoir fill, and 4) depletion rate higher than replenishing rate. Recycled flowback and produced water have added benefits. Environmentally Sound Necessary for sustainable shale development Reduces formation damage resulting in improved well performance Significantly reduces D&C & LOE cost Approach has used more than 2.2 million barrels of flowback or produced water for fracing and saved more than $7mm in drilling and completion cost and lease operating expenses. Large scale gas lift infrastructure systems offer operators more flexibility. Reduces lifting cost Stabilizes well performance with less down time Shallower decline rates realized Minimizes oil production impacts caused by 3 rd party plant shut downs Miscible gas flooding and pressure maintenance Be Willing to Think Outside of the Box 24