Approach Resources Company Presentation January 5, 2017

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 1934. 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 (i) relate to stockholder approval and consummation of the transactions discussed herein, and (ii) 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 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. In addition, these risks, uncertainties, assumptions and other important factors include, but are not limited to (1) the inability to complete the transactions discussed in this presentation due to the failure to obtain approval of the Company’s stockholders to certain aspects thereof or other conditions to closing of the initial exchange and/or follow-on exchange offer, (2) the failure to achieve 100% participation in the follow-on exchange offer, (3) a continued decline in commodities prices, (4) the Company’s ability to recognize the anticipated benefits of the transactions, (5) costs related to the transactions, (6) changes in applicable laws or regulations, and (7) other risks and uncertainties indicated from time to time in a definitive proxy statement, including those under “Risk Factors” therein, and other documents filed or to be filed with the SEC by Approach. 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. 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. Cautionary statements regarding oil & gas quantities

Situation Overview

Situation overview The Company has a high-quality asset base in the Southern Midland basin of the greater Permian Basin Business anchored by long-lived, low-cost proved reserve base Over 1,600 remaining Hz Wolfcamp drilling locations provide significant upside and future growth Established infrastructure in place to achieve one of the lowest cost structures in the Permian Basin In response to the decline in commodity prices, the Company suspended drilling in 2015 and has focused on reducing costs, preserving liquidity and reducing leverage Without a reduction in leverage and interest expense, the Company will be unable to grow its reserve base and production while spending within cash flow given prolonged low commodity prices and limited operating liquidity The debt-for-equity Exchange Transactions are being pursued to reduce debt and interest expense, and increase operating liquidity and financing flexibility Company intends to redeploy up to $16.1 million of annual interest savings to increase 2017 capital budget and grow production and reserves De-risks the business and right-sizes the balance sheet for current commodity price environment Recapitalized balance sheet enhances opportunity set of strategic options including A&D and M&A

Company overview AREX OVERVIEW ASSET OVERVIEW Enterprise value $651MM High-quality reserve base 167 MMBoe proved reserves 63% Liquids, 33% oil $460 MM Standardized measure, $504 MM proved PV-10 (non-GAAP) 1 Available Sales Outlets – Cushing and Midland Permian Basin core operating area 138,000 gross (125,000 net) acres ~1+ BnBoe gross, unrisked resource potential ~1,800 Identified HZ drilling Large contiguous acreage with multiple benches Prolific Wolfcamp shale – largest estimate of continuous oil that USGS has ever assessed in the United States 2 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 Note: Proved reserves as of 12/31/15 and acreage as of 9/30/2016. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing share price of $3.70 per share on 12/6/2016, plus net debt as of 9/30/2016. 1. See “PV-10 (unaudited)” slide for reconciliation to GAAP measure. 2. Per USGS estimates - https://www.usgs.gov/news/usgs-estimates-20-billion-barrels-oil-texas-wolfcamp-shale-formation

Company’s leverage metrics and liquidity position have been negatively impacted by low oil prices Borrowing Base ($MM) $450.0 $600.0 $600.0 $525.0 $450.0 $450.0 $450.0 $325.0 $325.0 $325.0 Liquidity ($MM) $361.8 $300.1 $240.0 $193.4 $172.0 $177.3 $178.5 $50.6 $52.4 $51.5 Debt / LTM EBITDAX $ / barrel Note: Leverage is calculated by dividing total debt by EBITDAX. See “Pro forma leverage ratio (unaudited)” slide for reconciliation. 6

As commodity prices collapsed, we took proactive steps to align our capital budget with cash flow and reduce our cost structure Annual Capital Expenditures ($ MM) Improved Cost Structure Lease operating expense per Boe down 53% from 1Q14 Cash G&A per Boe down 27% from 1Q14

Highlights of exchange transaction 8 Large-scale strategic recapitalization anchored by a proven industry investor (Wilks Brothers family office) Elimination of up to $230.3 million of debt and $16.1 million in annual cash interest expense (assuming full participation in the Exchange Transactions) in exchange for a maximum of 69.1 million shares of common stock (62.5% of outstanding assuming Follow-On Exchange Rate = Initial Exchange Rate) Provides cash flow to invest in the business and positions the Company to resume growth Alliance with a strategic investor enhances access to OFS services if that market tightens in a rising price environment

Key transaction terms 1 9 1. The foregoing description of terms is qualified in its entirety by a definitive exchange agreement and exhibits, which were filed on November 2, 2016, as Exhibit 10.1 to our Current Report on Form 8-K and are incorporated herein by reference. 2. $953.62 is determined by multiplying 300 shares x exchange agreement VWAP. Exchange agreement Agreement with largest holder of our 7.00% Senior Notes due 2021 (senior notes), to exchange $130,552,000 principal amount of senior notes for 39,165,600 shares of AREX common stock Exchanging note holder Entities beneficially owned by the Wilks Family Office, based in Cisco, Texas and founders of FracTech, a hydraulic fracturing and oil field services firm that Wilks sold to Temasek Holdings consortium in 2011 Exchange ratio 300 shares of common stock per $1,000 principal amount of senior notes  Follow-on exchange offer After the Wilks exchange, Approach will launch follow-on exchange offer to holders of remaining $99,768,000 principal amount of senior notes on similar economic terms Follow-on exchange ratio At Company’s discretion, a ratio between (including the lesser of): 300 shares of common stock per $1,000 principal value senior notes, or  if 30-day VWAP of AREX common stock three days before follow-on launch (launch VWAP) is ≥ to $3.179 (exchange agreement VWAP), then $953.62 ÷ launch VWAP 2 Minimum participation required in follow-on exchange None Governance Wilks will appoint three directors to Approach’s current five-member board, bringing the total to eight board members Proportionate voting Wilks must vote their shares in proportion with non-Wilks shareholders on typical annual meeting matters, including director nominees Equity value trigger Proportionate voting falls away when Approach reaches equity market cap of between ~ $800 million and $1.1 billion Equity ownership cap Wilks ownership capped at 48.6% for duration of agreement Standstill 18-month standstill for Wilks for acquisitions of common stock above equity ownership cap, M&A proposals, proxy solicitations Pre-emptive rights Right of first offer for Wilks to acquire 2nd lien debt and pre-emptive rights to acquire equity securities Reg rights agreement Customary registration rights agreement Stockholder approval Stockholder approval required for Wilks exchange, follow-on exchange and increase in authorized shares of common stock from 90 million to 180 million Ability to consider unsolicited proposals Board may withdraw or modify its recommendation that stockholders vote in favor of the Exchange Transactions Termination fee No. Reimbursement of Noteholders’ expenses up to $500,000 if the Exchange Agreement is terminated for any reason other than Noteholders’ breach Management severance / parachute None Co-financial advisors Perella Weinberg Partners; Evercore Group L.L.C. Fairness opinion Perella Weinberg Partners Board support Unanimous Closing Expected closing 1Q2017

Exchange transaction summary (pro forma as of 9/30/16) Debt & Interest ($MM) 1 Ownership Total Debt / LTM EBITDAX 2 1. Represents principal amount of outstanding long-term debt and LTM cash interest as of 9/30/2016. 2. See “EBITDAX (unaudited)” slide for reconciliation to GAAP measure $505.3 $374.8 41.5 MM total shares 80.8 MM total shares 110.7 MM total shares Step 1: Initial exchange Step 2: Follow-on exchange $275.0 Credit facility due 2019 Senior Notes due 2021 Cash interest $25.1 $16.0 $9.0 10

Exchange transaction summary (estimated pro forma as of 12/31/16) Debt & Interest ($MM) 1 Ownership Total Debt / LTM EBITDAX 2 1. Represents principal amount of outstanding long-term debt and estimated LTM cash interest as of 12/31/2016. 2. See “EBITDAX (unaudited)” slide for reconciliation to GAAP measure $503.3 $372.8 41.5 MM total shares 80.8 MM total shares 110.7 MM total shares Step 1: Initial exchange Step 2: Follow-on exchange $273.0 Credit facility due 2019 Senior Notes due 2021 Cash interest $25.9 $16.7 $9.7 11

Estimated process timeline 12 Date Event January 26, 2017 Special Meeting of the Stockholders / Exchange Transactions are approved January – February, 2017 If approved, Initial Exchange is executed February – March, 2017 If approved, Follow-on Exchange is launched March – April, 2017 Follow-on Exchange closes

Exchange transactions will materially improve leverage and access to liquidity (NYMEX strip as of 10/13/2016) 2016 OCC Substandard Loan E&P Lending Guidance: 4.0x Note: Based on NYMEX strip pricing as of 10/13/2016. Leverage Access to additional low-cost bank capital is materially constrained when borrower leverage exceeds Office of the Comptroller of Currency (“OCC”) E&P lending guidelines, regardless of increasing commodity pricing or reserves base. 1. Leverage is calculated by dividing total debt by EBITDAX. See “Pro forma leverage ratio (unaudited)” slide for reconciliation. 13

Exchange transactions will materially improve leverage and access to liquidity (NYMEX strip as of 1/3/2017) 2016 OCC Substandard Loan E&P Lending Guidance: 4.0x Note: Based on NYMEX strip pricing as of 1/3/2017. Leverage Access to additional low-cost bank capital is materially constrained when borrower leverage exceeds Office of the Comptroller of Currency (“OCC”) E&P lending guidelines, regardless of increasing commodity pricing or reserves base. 1. Leverage is calculated by dividing total debt by EBITDAX. See “Pro forma leverage ratio (unaudited)” slide for reconciliation. 14

Reinvestment of interest expense will provide ongoing incremental liquidity needed to jumpstart production growth 15 Capital expenditures = operating cash flow ($MM) 1 Daily production (Mboe/d) 1 1. Based on commodity research consensus price forecast as of 10/13/2016 (oil prices of $54 in 2017, $61 in 2018 and 2019, and $66 in 2020) and D&C costs of $3.6 MM per well. Note: Graphs are included to illustrate that interest savings will lead to increases in operating cash flows and capital expenditures, which over time will lead to increases in production, and are not intended to provide guidance regarding our future expected capital expenditures, cash flows or production targets. Higher operating cash flow will allow for larger self-funded capital budget Higher capital budget will accelerate production growth and increase oil cut

Market reaction following transaction announcement 16 AREX stock closed at $2.70 on 11/2/2016, with the exchange agreement announced after hours. AREX stock was up 7.0% on 11/3/16, outperforming the S&P E&P Index, which was up less than 1%. The Initial Exchange will be executed at an implied price of $3.33/share, a 23% premium to the 11/2/2016 closing price. The follow-on exchange will be executed at a 5% discount to bond par value, representing an additional premium uplift to current share price. Since the announcement, AREX stock has traded up 41.9%, outperforming the S&P E&P Index, which was up 20.4% over the same period. $3.83 closing price on 12/15/2016

Key rationale for exchange transactions 17 Improved Capital Structure Significant reduction in debt Improvement in ability to service and refinance upcoming debt maturities Reposition the Company’s balance sheet and restore access to low-cost bank financing Reduction of leverage closer to new OCC guidelines of 4.0x Positive Financial Impact Preserving existing liquidity Elimination of annual cash interest expense of up to $16.1 million (assuming full participation in the Exchange Transactions) Allowing reallocation of cash interest expense to drilling operations to resume growth and maximize enterprise value Best Actionable Alternative Many alternatives were explored as described in proxy statement Asset Sales – Indications of interests received from potential counterparties did not meaningfully reduce leverage Sale of Equity – The size of any public offering or private placement necessary to accomplish similar leverage reduction would be significant and likely more dilutive Sale of Entire Company – Offers or indications of interest for such a sale were not in the best interest of stockholders or the Company

Asset and operations overview

Company overview AREX OVERVIEW ASSET OVERVIEW Enterprise value $651MM High-quality reserve base 167 MMBoe proved reserves 63% Liquids, 33% oil $460 MM Standardized measure, $504 MM proved PV-10 (non-GAAP) 1 Available Sales Outlets – Cushing and Midland Permian Basin core operating area 138,000 gross (125,000 net) acres ~1+ BnBoe gross, unrisked resource potential ~1,800 Identified HZ drilling Large contiguous acreage with multiple benches Prolific Wolfcamp shale – largest estimate of continuous oil that USGS has ever assessed in the United States 2 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 Note: Proved reserves as of 12/31/15 and acreage as of 9/30/2016. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing share price of $3.70 per share on 12/6/2016, plus net debt as of 9/30/2016. 1. See “PV-10 (unaudited)” slide for reconciliation to GAAP measure. 2. Per USGS estimates - https://www.usgs.gov/news/usgs-estimates-20-billion-barrels-oil-texas-wolfcamp-shale-formation 19

The business is anchored by long-lived, low-cost proved reserve base 20 12/31/2015 reserve summary prepared by DeGolyer and MacNaughton (“D&M”) Replaced 603% of produced reserves at a drill-bit F&D cost of $4.32 per Boe1 Total proved reserves up 14% YoY, proved PV-10 (non-GAAP) of $504 million2 Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) 3 Total (MBoe) PV-10 ($ MM) 2 PDP 15,476 20,362 154,202 61,539 $390.8 PDNP 191 52 450 317 $1.1 PUD 38,829 29,072 221,336 104,790 $112.1 Total Proved 54,496 49,486 375,988 166,646 $504.0 Total Proved Reserves Reserves by Commodity Proved PV-10 1. Drill-bit F&D costs are calculated by dividing the sum of exploration costs and development costs for the year by the total of reserve extensions and discoveries for the year. See “F&D costs (unaudited)” slide. 2. PV-10 calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and natural gas, of $50.16 per Bbl of oil, $15.13 per Bbl of NGLs and $2.64 per MMBtu of natural gas. See “PV-10 (unaudited)” slide for reconciliation to GAAP measure. 3. The gas reserves contain 42,617 MMcf of gas that will be produced and used as field fuel (primarily for compressors and artificial lifts) before the gas is delivered to a sales point.

Strong track record of reserve and production growth 21 RESERVE GROWTH CAGR 29% YE15 reserves up 14% YoY Replaced 603% of produced reserves at a drill-bit F&D cost of $4.32/Boe1 154.6 MMBoe proved reserves booked to HZ Wolfcamp play MMBoe PRODUCTION GROWTH CAGR 32% 2015 Production increased 10% YoY to a record 15.2 MBoe/d Anticipating production decline in 2016 with significantly reduced capital budget MBoe/d 1. Drill-bit F&D costs are calculated by dividing the sum of exploration costs and development costs for the year by the total of reserve extensions and discoveries for the year. See “F&D costs (unaudited)” slide.

AREX Wolfcamp assets offer significant upside 22 Approach assets deliver: Balanced production profile Shallow natural decline rate Meaningful cash flow allowing debt reduction during 4Q15 and operating within cash flow in 2016 Stacked-pay zone - Wolfcamp A, B and C offering more than 1,600 undrilled locations Low cost to drill & complete due to shallow depth, efficiency, and existing water system Contiguous acreage position allowing large-scale infrastructure that delivers one of the lowest lease operating cost for the life of the property Proximity to the under-supplied Mexican natural gas and natural gas liquid market Recent acquisitions by PE-backed entrants offsetting AREX acreage attest to asset quality and upside potential when commodity prices recover Recent M&A transactions in Southern Midland Basin: Amistad Energy Partners purchased EOG Crockett Co acreage Sequitur Energy purchased EOG Reagan, Irion, Schleicher and Crockett Co acreage Fleur de Lis purchased Devon Irion and Crockett Co acreage

23 AREX LOE Historical Track Record ($/Boe) 2015 Permian Peer LOE ($/Boe) AREX D&C Historical Track Record ($ MM) Current Permian Peer D&C Cost ($ MM) Source: Latest available company presentations and public filings. Peers include CPE, CWEI, CXO, EGN, FANG, LPI, MTDR, PE, PXD, and RSPP. AREX continues to achieve one of the lowest cost structures in the Permian Basin

Drilling and completion (D&C) cost reductions have significantly improved profitability despite lower commodity prices Note: HZ Wolfcamp economics assume $3.50/Mcf realized natural gas price and NGL price based on 40% of realized oil price. Realized price based on current 2017 NYMEX strip Realized price based on long-term commodity research consensus 24

Enhanced completion design drives outperformance from 2015 and 2016 wells 25 Note: Production data normalized for operational downtime Note: Production data normalized for operational downtime Cumulative Production (Boe) Time (Day) 2Q16 Wells Reduced stage spacing (< 200’) Increase percentage of 100 mesh sand Use of Recycled Produced Water 2nd Qtr. 2016 Wolfcamp B&C bench completions Average completed lateral length = 6,541'

Balanced production mix allows AREX to benefit from commodity price appreciation across all product streams 26 9M16 Commodity Mix Crude oil realized prices up 78% since January 2016 Natural gas realized prices up 37% since January 2016 NGL realized prices up 117% since January 2016 % Change in realized prices

Large resource potential with significant running room 27 AREX Horizontal Wells / Locations AREX Undrilled Locations Total identified undrilled locations: 1,639

PDP PUD PDP PUD PROB/POSS/RES Potential ~10,000’ laterals PROB/POSS/RES Potential ~10,000’ laterals PDNP 548 PDP 16 PUD 41 PROB / POSS / RES 2015 Year End A Bench (TOTAL) PDNP 1 AREX Wolfcamp A Bench wells and locations Production Corridor Production Corridor Production Corridor Production Corridor Production Corridor Pangea West Project Pangea 28

PDP PUD PROB/POSS/RES PUD PROB/POSS/RES Potential ~10,000’ laterals Potential ~10,000’ laterals Production Corridor Production Corridor Production Corridor Production Corridor Production Corridor PDP 392 PDP 105 PUD 109 PROB / POSS / RES 2015 Year End B Bench (TOTAL) AREX Wolfcamp B Bench wells and locations Pangea West Project Pangea 29

PDP PROB/POSS/RES Potential ~10,000’ laterals PDP PUD PROB/POSS/RES Potential ~10,000’ laterals PUD 449 PDP 43 PUD 100 PROB / POSS / RES 2015 Year End C Bench (TOTAL) AREX Wolfcamp C Bench wells and locations Production Corridor Production Corridor Production Corridor Production Corridor Production Corridor Pangea West Project Pangea 30

Established infrastructure in place is critical to low cost structure 31 Benefits of water recycling Reduce D&C cost Reduce lease operating expense (LOE) Increase project profit margin Minimize fresh water use, truck traffic and surface disturbance BLK 54 Compressor OZONA 42-14 Pit PW Pit Jim Terry Pit Childress Pit PW 5701 SWD Receipt Point Midway Truck Station DCP Gas Line BLK 45 DCP Tap DCP Gas Line Gas gathering lines WTG Low Pressure Gas line DCP Processing Plants 1401 SWD West 2106 SWD 42-15-7X SWD Approach Bailey Compressor Schleicher Crockett Irion Reagan Sutton NORTH & CENTRAL PANGEA PANGEA WEST SOUTH PANGEA PW DCP Tap PW CS #1 PW Commingle Facility Receipt Point Receipt Point Receipt Point Receipt Point Receipt Point Receipt Point DCP Tap BLK 45 S Compressors BLK 42 CS 45-13 Pit 190 Pit Baker CS Baker Pit 2 BLK 45 N Compressors BLK 54 Pit Baker Pit Baker Station DCP Gas Line CT Compressor 42-21 Pit LACT LACT 42 Commingle Facility LACT 3 1 2 2 1 2 2 1 Moore Pit LACT Rousselot Pit Childress Pit Recycle Facility Elliott Facility BLK 50 Compressor JPE Energy Baker DCP Tap BLK 42 / CT DCP Tap DCP Tap LACT 204HA 228HA

Significant cost savings from using recycled water for fracing 32 Flowback / Producing Well $2 per barrel Free Wellpad Via existing water gathering lines Cost Savings $400,000 to $600,000 per well Via existing water transportation lines $0.25 per barrel $0.25 per barrel $1.50 per barrel Free Water Recycling Center Cost for recycled water $2 - $3 per barrel Cost saving for using recycled water

AREX water recycling facility successfully implemented 33 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 produced water treated in the first 6 months More than $7mm of cost saved or value created in the first 6 months of operation

34 CPF 5 CPF 1 CPF 2 CPF 3 CPF 4 Low Pressure Gathering Line 0.75 miles CS 0.75 miles Gas lift to CPF Gas lift to Well Production to CPF Dehy ~ 2000 ft ~ 500 ft High Pressure Pipeline to Processing Plant High Pressure Sale line High Pressure Sale / Gas Lift line Wells CPF 10 CPF 6 CPF 7 CPF 8 CPF 9 Low Pressure Gathering Line CS Gas lift to CPF Gas lift to Well Production to CPF Dehy Well Pads Serviced by Centralized Compressor and Shared Gas Lift System – Efficient and Significant Cost Saving Cost ~ $4.3 M / Well / month for the 1st 30 months This configuration saves $7.6 M / well / month for the 1st 30 months Or $228M/well for the 1st 30 months

AREX has used the commodity price downturn to increase focus on cost reductions 35 LOE/Boe Prod. Taxes/Boe Cash G&A/Boe LOE down 53% from 1Q14 Cash G&A down 27% from 1Q14 Production taxes down 54% from 1Q14

36 Record low LOE cost driven by water handling infrastructure and field-level operating efficiencies AREX LOE Historical Track Record ($/Boe) Water hauling Compressor Rental & Repair Well Repairs, Workover & Maintenance Pumpers & Supervision

Cost reductions and improvement in commodity prices are translating into expanding profit margins 37 Profit margin per Boe Unhedged Cash Margin1 LOE Production Taxes Cash G&A $15.12 Realized Price $18.12 Hedged Realized Price $19.53 Realized Price $20.76 Hedged Realized Price $21.26 Realized Price $21.96 Hedged Realized Price 173% YTD improvement in unhedged profit margin 1. Defined as unhedged revenue per Boe less LOE, production taxes, and cash G&A per Boe.

Appendix

Current hedge position 39 Commodity & Period Contract Type Volume Contract Price Crude Oil  October 2016 – December 2016 Swap 750 Bbls/d $62.52/Bbl Natural Gas  October 2016 – December 2016 Swap 200,000 MMBtu/month $2.93/MMBtu October 2016 – March 2017 Swap 400,000 MMBtu/month $2.45/MMBtu November 2016 – March 2017 Swap 200,000 MMBtu/month $3.29/MMBtu January 2017 – December 2017 Collar 100,000 MMBtu/month $3.00/MMBtu - $3.65/MMBtu April 2017 – December 2017 Collar 400,000 MMBtu/month $3.00/MMBtu - $3.47/MMBtu April 2017 – December 2017 Collar 200,000 MMBtu/month $2.30/MMBtu - $2.60/MMBtu

Liquidity 40 (in thousands) Borrowing Base $325,000 Cash and Cash Equivalents 2,708 Borrowings under Credit Facility (275,000) Undrawn Letters of Credit (325) Liquidity $52,383 Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company’s ability to fund development and exploration activities. However, this measurement has limitations. This measurement can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the measurement on a company’s financial statements. This measurement is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website The table below summarizes our liquidity at September 30, 2016.

Pro forma leverage ratio (unaudited) Leverage ratio is calculated by dividing total debt by EBITDAX (non-GAAP)1 for the trailing 12 months. We use the leverage ratio as a measurement of our overall financial leverage, which impacts our ability to incur more debt. However, this ratio has limitations. This ratio can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the ratio on a company’s financial statements. This ratio is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. We define EBITDAX as net loss, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss (gain) on commodity derivatives, (5) gain on debt extinguishment, (6) write-off of debt issuance costs, (7) interest expense, net, and (8) income tax benefit. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net loss because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. The following table provides a reconciliation of EBITDAX to net loss for the three months ended December 31, 2015, March 31, 2016, June 30, 2016, and September 30, 2016, and 12 months ended September 30, 2016 (in thousands). (in thousands) September 30, 2016 Pro forma – Wilks exchange Pro forma – Full exchange Total Debt $ 500,011 $ 371,653 $ 273,561 LTM EBITDAX 63,508 63,508 63,508 Leverage ratio 7.9x 5.9x 4.3x Three Months Ended Twelve Months Ended (in thousands) December 31, 2015 March 31, 2016 June 30, 2016 September 30, 2016 September 30, 2016 Net loss $ (5,759) $ (13,660) $ (16,035) $ (9,073) $ (44,527) Exploration 228 569 1,622 1,047 3,466 Depletion, depreciation and amortization 23,173 20,229 19,991 19,422 82,815 Share-based compensation 1,954 1,550 1,374 1,357 6,235 Unrealized loss (gain) on commodity derivatives 10,285 957 8,076 (760) 18,558 Gain on debt extinguishment (9,080) - - - (9,080) Write-off of debt issuance costs - - 563 - 563 Interest expense, net 6,436 6,298 6,808 7,067 26,609 Income tax benefit (284) (7,245) (8,687) (4,915) (21,131) EBITDAX $ 26,953 $ 8,698 $ 13,712 $ 14,145 $ 63,508 1. See “EBITDAX (unaudited)” for a reconciliation to a GAAP measure. 41

Pro forma interest coverage ratio (unaudited) 42 Interest coverage ratio is calculated by dividing EBITDAX for the trailing 12 months by cash interest expense for the trailing 12 months. We use the interest coverage ratio as a measurement of our ability to make interest payments on our outstanding debt. However, this ratio has limitations. This ratio can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the ratio on a company’s financial statements. This ratio is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. We define EBITDAX as net loss, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss (gain) on commodity derivatives, (5) gain on debt extinguishment, (6) write-off of debt issuance costs, (7) interest expense, net, and (8) income tax benefit. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net loss because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. We define cash interest expense as interest expense excluding amortization of debt issuance costs. The following table provides a reconciliation of EBITDAX to net loss and cash interest expense to interest expense for the three months ended December 31, 2015, March 31, 2016, June 30, 2016, and September 30, 2016, and 12 months ended September 30, 2016 (in thousands). Three Months Ended Twelve Months Ended (in thousands) December 31, 2015 March 31, 2016 June 30, 2016 September 30, 2016 September 30, 2016 Net loss $ (5,759) $ (13,660) $ (16,035) $ (9,073) $ (44,527) Exploration 228 569 1,622 1,047 3,466 Depletion, depreciation and amortization 23,173 20,229 19,991 19,422 82,815 Share-based compensation 1,954 1,550 1,374 1,357 6,235 Unrealized loss (gain) on commodity derivatives 10,285 957 8,076 (760) 18,558 Gain on debt extinguishment (9,080) - - - (9,080) Write-off of debt issuance costs - - 563 - 563 Interest expense, net 6,436 6,298 6,808 7,067 26,609 Income tax benefit (284) (7,245) (8,687) (4,915) (21,131) EBITDAX $ 26,953 $ 8,698 $ 13,712 $ 14,145 $ 63,508 Interest expense $ 6,436 $ 6,298 $ 6,808 $ 7,067 $ 26,609 Amortization of debt issuance costs (383) (372) (346) (340) (1,441) Cash interest expense $ 6,053 $ 5,926 $ 6,462 $ 6,727 $ 25,168 (in thousands) September 30, 2016 Pro forma – Wilks exchange Pro forma – Full exchange LTM EBITDAX $ 63,508 $ 63,508 $ 63,508 Cash interest expense 25,168 16,029 9,046 Interest coverage ratio 2.5x 4.0x 7.0x

EBITDAX (unaudited) 43 We define EBITDAX as net loss, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) impairment of oil and gas properties, (5) unrealized (gain) loss on commodity derivatives, (6) gain on debt extinguishment, (7) termination costs, (8) write-off of debt issuance costs, (9) interest expense, net, and (10) income tax benefit. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net loss because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. The following table provides a reconciliation of EBITDAX to net loss for the three and nine months ended September 30, 2016 and 2015. (in thousands) Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Net loss $ (9,073) $ (148,787) $ (38,768) $ (168,345) Exploration 1,047 1,956 3,238 4,211 Depletion, depreciation and amortization 19,422 31,222 59,642 86,146 Share-based compensation 1,357 1,708 4,281 6,000 Impairment of oil and gas properties - 220,197 - 220,197 Unrealized (gain) loss on commodity derivatives (760) (296) 8,273 22,929 Gain on debt extinguishment - (1,483) - (1,483) Termination costs - 1,436 - 1,436 Write-off of debt issuance costs - - 563 - Interest expense, net 7,067 6,465 20,173 18,630 Income tax benefit (4,915) (81,756) (20,847) (93,121) EBITDAX $ 14,145 $ 30,662 $ 36,555 $ 96,600

F&D costs (unaudited) 44 F&D Cost reconciliation Cost summary (in thousands) Property acquisition costs Unproved properties $ 653 Proved properties - Exploration costs 4,439 Development costs 146,237 Total costs incurred $ 151,329 Reserves summary (MBoe) Balance – 12/31/2014 146,248 Extensions & discoveries 34,895 Production (1) (5,787) Revisions to previous estimates (8,709) Balance – 12/31/2015 166,646 F&D cost ($/Boe) All-in F&D cost $ 5.78 Drill-bit F&D cost 4.32 Reserve replacement ratio Drill-bit 603% All-in finding and development (“F&D”) costs are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year by the sum of reserve extensions and discoveries, purchases of minerals in place and total revisions for the year.   Drill-bit F&D costs are calculated by dividing the sum of exploration costs and development costs for the year by the total of reserve extensions and discoveries for the year.   We believe that providing F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and included in our annual report on Form 10-K filed with the SEC on March 4, 2016. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases.   As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company’s future F&D costs will not differ materially from those set forth above. Further, the methods used by us to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies.   The following table reconciles our estimated F&D costs for 2015 to the information required by paragraphs 11 and 21 of ASC 932-235. (1) Production includes 1,530 MMcf related to field fuel.

PV-10 (unaudited) 45 The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $504 million at December 31, 2015, and was calculated based on the first-of-the-month, twelve-month average prices for oil, NGLs and gas, of $50.16 per Bbl of oil, $15.13 per Bbl of NGLs and $2.64 per MMBtu of natural gas, adjusted for basis differentials, grade and quality. PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. The following table reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP. (in millions) December 31, 2015 PV-10 $ 504 Less income taxes: Undiscounted future income taxes (307) 10% discount factor 263 Future discounted income taxes (44) Standardized measure of discounted future net cash flows $ 460

Disclosure 46 THIS PRESENTATION IS NEITHER AN OFFER TO PURCHASE NOR A SOLICITATION TO BUY ANY OF THE EXISTING SENIOR NOTES NOR IS IT A SOLICITATION FOR ACCEPTANCE OF THE EXCHANGE OFFER OR THE FOLLOW-ON EXCHANGE. THE COMPANY IS MAKING THE EXCHANGE OFFER AND THE FOLLOW-ON EXCHANGE OFFER ONLY BY, AND PURSUANT TO THE TERMS OF, THE OFFERS TO EXCHANGE AND LETTERS OF TRANSMITTAL. THE EXCHANGE OFFER AND THE FOLLOW-ON EXCHANGE OFFER ARE NOT BEING MADE IN ANY JURISDICTION IN WHICH THE MAKING OR ACCEPTANCE THEREOF WOULD NOT BE IN COMPLIANCE WITH THE SECURITIES, BLUE SKY OR OTHER LAWS OF SUCH JURISDICTION. NONE OF THE COMPANY, ANY INFORMATION AGENT OR ANY EXCHANGE AGENT FOR THE EXCHANGE OFFER OR THE FOLLOW-ON EXCHANGE OFFER MAKES ANY RECOMMENDATION IN CONNECTION WITH SUCH EXCHANGE OFFERS. THIS PRESENTATION IS NEITHER AN OFFER TO SELL NOR A SOLICITATION OF AN OFFER TO BUY ANY OF THESE SECURITIES AND SHALL NOT CONSTITUTE AN OFFER, SOLICITATION OR SALE IN ANY JURISDICTION IN WHICH SUCH OFFER, SOLICITATION OR SALE IS UNLAWFUL. Additional Information and Where to Find It In connection with the exchange transactions, the Company filed a definitive proxy statement with the SEC on December 13, 2016. The definitive proxy statement (including any amendments or supplements thereto), and other relevant documents filed with the SEC in connection the Company’s solicitation of proxies for the meeting of stockholders to be held to approve certain aspects of the exchange transactions, contain important information about the exchange transactions and related matters. The Company’s stockholders and other interested persons are advised to read the definitive proxy statement and such other materials filed with the SEC because these materials contain important information about the exchange transactions. The definitive proxy statement was mailed to the Company stockholders of record as of December 12, 2016. Stockholders may also obtain copies of the definitive proxy statement, without charge, at the SEC’s website at www.sec.gov or by directing a request to: Approach Resources Inc., One Ridgmar Centre, 6500 West Freeway, Suite 800, Fort Worth, Texas 76116, Attention: Investor Relations, (817) 989-9000. Participants in Solicitation The Company and its directors and officers may be deemed participants in the solicitation of proxies of the Company’s stockholders in connection with the exchange transactions. The Company stockholders and other interested persons may obtain, without charge, more detailed information regarding the directors and officers of the Company in the Company’s proxy statement for its 2016 Annual Meeting of Stockholders, which was filed with the SEC on April 20, 2016. Information regarding the persons who may, under the SEC rules, be deemed participants in the solicitation of proxies to the Company stockholders in connection with the exchange transactions is set forth in the definitive proxy statement. Additional information regarding the interests of participants in the solicitation of proxies in connection with the exchange transactions is included in such definitive proxy statement. NO OFFER OR SOLICITATION

Contact information Suzanne Ogle Vice President – Investor Relations & Corporate Communications 817.989.9000 ir@approachresources.com www.approachresources.com