2 Disclaimer Forward Looking Statements This presentation contains “forward-looking statements.” Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. Such statements include those relating to pending acquisitions and associated costs, acreage, production, reserves, and other matters; drilling locations and potential drilling activities; production and sales volumes; proved, probable and possible reserves; operating and administrative costs; future operating or financial results; cash flow and anticipated liquidity; business strategy; future dividend policies and other matters. These forward-looking statements may generally, but not always, be identified by words such as “estimated”, “projected”, “potential”, “anticipated”, “forecasted” or other words that convey the uncertainty of future events or outcomes. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. These statements are based on current plans and assumptions and are subject to a number of risks and uncertainties as further outlined in our Forms 10-K and 10-Q. Therefore, the actual results may differ materially from the expectations, estimates or assumptions expressed in or implied by any forward-looking statement, and we caution readers not to place undue reliance on these forward looking statements, which speak only as of the date of this presentation. In particular, the pending acquisition disclosed in this presentation may not be consummated or, if it is, may be consummated upon materially different terms than currently anticipated and set forth in this presentation, including, for instance, as a consequence of the exercise of preferential purchase rights held by third parties which may dramatically reduce the acreage, reserves and production acquired. We undertake no obligation to update these forward looking statements to reflect events or circumstances occurring after the date of this presentation. Current SEC rules regarding oil and gas reserves information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose only proved reserves in our filings with the SEC. Our proved reserves as of June 30, 2021, were estimated by our independent petroleum engineering firm. In this presentation, proved reserves associated with acquired properties and probable and possible reserves, have been estimated by the Company’s internal staff of engineers. Estimates of probable and possible reserves are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. We also disclose proved and unproved drilling locations in this presentation. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interest may differ substantially from these 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 program, which will be directly affected by the decisions of the operators of our properties, availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, agreement terminations, regulatory approvals and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of reserves may change significantly as development of the Company’s oil and gas assets provides additional data. Adjusted EBITDA is a non-GAAP financial measure that is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis. It is also used to assess our ability to incur and service debt and fund capital expenditures. Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flows provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The Company defines Adjusted EBITDA as net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization (DD&A), stock-based compensation, other amortization and accretion, ceiling test impairment and other impairments, unrealized loss (gain) on change in fair value of derivatives, and other non-cash expense (income) items. Cautionary Note Regarding Oil and Gas Reserves Non-GAAP Reconciliation - Adjusted EBITDA
3 N Y S E : E P M Company Overview NYSE American EPM Shares Outstanding (2/7/2022) 33.69 MM Share Price (4/1/2022) $7.19 52 Week Range (4/1/2022) $3.01-$8.17 Market Cap (4/1/2022) $242.2 MM Common Dividend (3Q 2022) $0.40 per share (annualized) Dividend Yield (4/1/2022) 5.6% (annualized) EPM Net Production (1H 2022) 5,400 BOEPD (55% Natural Gas, 29% Oil, 16% NGL) EPM Pro Forma Net Production1 ~8,000 BOEPD (62% Natural Gas, 25% Oil, 13% NGL) Proved Reserves2 (FYE 2021) 23.4 MMBOE (92% PDP) Pro Forma Proved Reserves3 37.3 MMBOE Total Debt (4/1/2022)4 $37.0 MM Net Income (2Q 2022) $6.8 MM Adjusted EBITDA5 (2Q 2022) $10.2 MM Delhi EPM Headquarters Houston, TX Asset Locations Hamilton Dome Barnett Shale Jonah Field (Closed April 2022) Williston Basin Evolution Petroleum is an oil and natural gas company focused on delivering a sustainable dividend yield to its shareholders through the ownership, management, and development of producing oil and natural gas properties. Our long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisition, while seeking opportunities to maintain and increase production through selective development, production enhancement, and other exploitation efforts. See Slide 18 in Appendix for footnotes.
4 Closed Jonah Field acquisition on April 1, 2022 Completed financial audit and pro forma financial information as required by the SEC for the Williston Basin acquisition that closed in January 2022 Held annual working interest owners meetings with new and existing operating partners to receive updates on activity at Delhi Field, Hamilton Dome, Barnett Shale, and Williston Basin Completed Spring redetermination and increased the credit facility borrowing base to $50MM A p r i l 2 0 2 2 Recent Updates Added additional costless collar hedges covering 25% of projected production for the next 12 months for the Jonah Field acquisition as required under the credit facility Paid 34th consecutive quarterly dividend, returning to pre-pandemic levels of $0.10/share
5 P r o l i f i c N a t u r a l G a s F i e l d Jonah Field Overview Asset Highlights • Jonah Field is located within Wyoming’s Green River Basin in Sublette County • Produces from the Lance Pool consisting of 3,000’ to 5,000’ of gross thickness (~45% net pay) of over-pressured reservoir • Jonah Energy, a top-tier, responsible, and established operator, has operated the asset since 2014 • The purchase price, including preferential rights exercised by Jonah Energy, was $27.5MM(1) with a 2/1/2022 effective date and closed on 4/1/2022 • Preferential right exercised was valued at $1.9MM and included 53 wells in 29N 108W, section 25 • Long life reserves with sub-10% decline(2) • Multiple takeaway options for gas sales – Kern (West Coast), NWPL (Northwest), Overthrust / REX (Midcontinent) Operator Jonah Energy Avg. Net Daily Prod (1H FY2022) 12,847 MCFEPD / 2,141 BOEPD Acreage ~950 net acres, 100% HBP Average WI% / RI% / LNRI% (3) 19.6% WI / 14.9% RI / 75.9% LNRI Gross PDP Wells 595 Pricing Opal - Northwest Pipeline Commodity Split (Reserves) (4) 88% Gas / 6% Oil / 6% NGL Net PDP Reserves(4) 38.0 BCFE / 6.3 MMBOE Net PDP Reserves / Net Production (R/P) (4) 8.1 years Notes: 1. Purchase price of $27.5MM reflects preferential rights exercised and is subject to customary closing adjustments including a deposit of $1.5MM paid at PSA signing. 2. Estimated annual decline rate for first two years. ~950 Net Acres N Sublette County MILES 0 21 Statistics 3. Mathematical average of 595 PDP wells. 4. Company engineered reserves as of 2/1/2022 at 12/31/2021 SEC prices of $3.64/MMBTU and $66.55/bbl. Hamilton Dome Jonah Field WY ~100 miles 29N 108W 29N 107W 28N 108W AZ NM TX Marketing Optionality OR
6 1,231 7,982 409 3,630 571 2,141 G r o w i n g D a i l y P r o d u c t i o n T h r o u g h A c q u i s i t i o n s O v e r t h e L a s t 2 Ye a r s Scaling Evolution Through Acquisitions Asset Hamilton Dome (Wyoming) Barnett Shale (Texas) Williston Basin (North Dakota) Jonah Field(1) (Wyoming) Date Announced - 11/6/2019 3/30/2021 1/14/2022 2/9/2022 FY2022E Acquisition Price - $9.5 MM $18.2 MM $25.9 MM $27.5 MM(2) - Operator - 1H FY2022 Avg. Daily Production(3,4) 1,231 BOEPD 409 BOEPD 3,630 BOEPD 571 BOEPD 2,141 BOEPD 7,982 BOEPD Commodity Mix(3,5,6,7,8) (Reserves) 80% Oil 20% NGL 100% Oil 73% Gas 26% NGL 1% Oil 76% Oil 14% NGL 10% Gas 88% Gas 6% NGL 6% Oil 43% Oil 40% Gas 17% NGL Pro Forma Proved Reserves(3) 8.2 MMBOE(5) 1.8 MMBOE(5) 11.3 MMBOE(6) 9.7 MMBOE(7) 6.3 MMBOE(8) 37.3 MMBOE Net Acreage ~3,600 ~620 ~21,000 ~47,500 ~950 ~73,670 Working Interest / Revenue Interest 23.9% / 26.2% 23.5% / 19.7% 17.0% / 14.0% 38.7% / 32.5% 19.6% / 14.9% - Avg. 5-yr. Forward Strip at Acquisition - Oil $51.97 Gas $2.55 Oil $52.21 Gas $2.62 Oil $68.11 Gas $3.38 Oil $73.46 Gas $3.46 Oil $82.12(9) Gas $4.33(9) 1H FY2022 Production (BOEPD) See Slide 18 in Appendix for footnotes.
7 C o m p a n y P r o F o r m a w i t h W i l l i s t o n B a s i n & J o n a h F i e l d A c q u i s i t i o n s EPM Daily Production Jul-14 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Jul-20 Jan-21 Jul-21 Jan-22 B O E P D Jonah Field Williston Basin Barnett Shale Hamilton Dome Delhi Field Working Interest Reversion at Delhi Acquisition of Hamilton Dome Planned Facility Downtime at Delhi Acquisition of Barnett Shale Acquisition of Williston Basin Beginning of 9-month Shut-in of CO2 Supply Line for Repairs Acquisition of Jonah Field Projections
8 Hamilton Dome ~620 Net Acres Delhi ~3,600 Net Acres Barnett Shale ~21,000 Net Acres Williston Basin ~47,500 Net Acres (Closed January 2022) Jonah Field ~950 Net Acres (Closed April 2022) TX LA WY ND A c q u i s i t i o n s D i v e r s i f y & S t r e n g t h e n P r o v e d R e s e r v e s B a s e EPM Pro Forma: Diversified Portfolio Commodity Pro Forma Daily Production(2) Oil ~2,000 BOPD NGL ~1,000 BPD Gas ~30,000 MCFD Total ~8,000 BOEPD Pro Forma Annualized Revenue (1) Asset LocationsPro Forma Daily Production(1,2) Pro Forma Proved Reserves (MMBOE)(4) Notes: 1. Pro Forma Revenue is October 2021 through December 2021 including the Williston Basin and Jonah Field acquisitions as if they had been owned during that time. 2. Gas conversion ratio of 6:1; NGL ratio of 1:1. 3. Estimated average net production 6 months ended 12/31/2021. Excluding 130 BOEPD associated with Giddings Field accumulated royalties received in Q2 FY2022. Pro forma daily production includes the Williston Basin and Jonah Field acquisitions 4. EPM Reserves as of 7/1/2020 at 6/30/2021 SEC prices less 1H FY 2022 Production. Barnett reserves are Company adjusted for ethane rejection; see slide 20 in Appendix. Williston Basin Company engineered reserves as of 1/1/2022 at 12/31/2021 SEC prices of $3.64/MMBTU and $66.55/bbl. Jonah Field Company engineered reserves as of 2/1/2022 at 12/31/2021 SEC prices of $3.64/MMBTU and $66.55/bbl. Pro Forma Proved Reserves by Classification(4)Pro Forma Daily Production(2,3) 8.0 MBOE/D 25.2% 61.7% 13.1% $124.7MM 43.1% 43.0% 13.9% 37.3 MMBOE 17.5% 43.0% 39.5%Oil Gas Commodity Type: NGLs PDP PUD Classification: PDNP 24.3% 75.3% 0.4% 37.3 MMBOE
9 E s t a b l i s h e d P D P P r o d u c t i o n w i t h S i g n i f i c a n t U p s i d e Williston Basin Overview Asset Highlights • Assets located in the Williston Basin in western North Dakota in McKenzie, Golden Valley, and Billings Counties • Production primarily from the Three Forks, Pronghorn, and Bakken formations • Assets operated by Evolution’s partner, Foundation Energy Management • Acquisition closed on 1/14/2022 with an effective date of 6/1/2021 and net purchase price of $25.9 MM • Evolution is able to propose, fund, and drill wells via a joint development agreement with Foundation • Acquisition and a moderate capex drilling program will allow for reinvestment of free cash flow to maximize shareholder value • Large inventory of documented upside drilling locations Operator Foundation Energy Management Avg. Net Daily Prod (1H FY2022) 571 BOEPD Acreage ~47,500 net acres, 84.4% HBP Average WI% / RI% / LNRI% (1) 38.7% WI / 32.5% RI / 84.0% LNRI Gross PDP Wells 73 Pricing Williston Basin Sweet (WBS) Commodity Split (Reserves) (2) 76% Oil / 14% NGL / 10% Gas Net PDP Reserves / Net PUD Reserves(2) 2.2 MMBOE / 7.4 MMBOE Net PDP Reserves / Net Production (R/P) (2) 10.3 years Notes: 1. Mathematical average of 73 PDP wells. 2. Company engineered reserves as of 1/1/2022 at 12/31/2021 SEC prices of $3.64/MMBTU and $66.55/bbl.. N MILES 0 5 15 ~47,500 Net Acres NDMT 10 McKenzie Dunn Stark Billings Golden Valley Wibaux Richland Dawson Williston Basin Province SD ND MT WY MN Statistics
10 H i g h - Q u a l i t y D r i l l i n g L o c a t i o n s Significant Upside Nestled in Williston Acquisition 50.4 MMBoe Notes: 1. Gas conversion ratio of 6:1; NGL ratio of 1:1 2. Williston Basin Company engineered reserves as of 1/1/2022 at 12/31/2021 SEC prices of $3.64/MMBTU and $66.55/bbl. 3. SEC Proved Undeveloped locations are planned with ability to be drilled within 5 years. 4. 4/4/2022 strip pricing. 14.3% 75.5% 10.2% 50.4 MMBoe 4.4% 53.4% • 390 remaining Pronghorn/Three Forks 2-mile lateral locations classified as Probable or Possible • 106 of these locations are expected to meet all Proved requirements except for SEC 5-year rule(3) • With further development in the field, many of these Probable and Possible locations could be reclassified as Proved Undeveloped Oil Gas Commodity Type: NGLs PDP PUD Classification: PDNP PROB POSS 14.4% 27.5% 0.3% • 50 Pronghorn/Three Forks 2-mile lateral locations classified as SEC Proved Undeveloped(3) • Infrastructure in place and drilling pads already built on majority of locations • Years of high-quality drilling inventory • Expected drilling and completion costs ~$6.5-$7.0MM/well • 50+% IRR at current strip (4) Probable & Possible(1,2) Williston 3P Reserves by Commodity(1,2)Williston 3P Reserves by Classification(1,2) Proved Undeveloped(1,2)
11 W o r k i n g I n t e r e s t O w n e r s M e e t i n g s i n M a r c h 2 0 2 2 Operating Partners Update • Proposed a heat exchanger project that would improve field operations and provide cost savings • Three conformance projects identified and undergoing approval process • Expected capex through 1H FY23 ~$1.5MM • Restored production to pre-pandemic rates, continue to evaluate shut-in wells • Plan to consolidate tank batteries so vapor recovery system can be installed to further reduce emissions below State & Federal standards • Evaluating the potential of production from shallower formations • Expected capex through 1H FY23 ~$1.2MM • Permitting top three identified low risk Bakken behind pipe recompletions to be executed early FY2023 • Identified a group of potential low risk development projects to be permitted as early as Q4 of FY2022 and execution to begin shortly thereafter • Evolution and Foundation working together to identify top tier locations for new drill wells in the Three Forks/Pronghorn with goal of spudding first well mid-year FY2023 • Expected capex through 1H FY23 ~$2.1MM • Performed 25 workovers with average payout of ~1.5 months, ~2,900 Mcfpd gross total uplift, and ~38% under budget • Identifying return to sales wells through strategic management of water disposal • 20 wells returned to sales for ~2,650 Mcfpd gross total uplift • Working on upgrading saltwater disposal system • Optimizing field operations to increase production and cost savings • Expected capex through 1H FY23 ~$0.5MM Williston Basin, Foundation Energy Barnett Shale, Diversified Energy Delhi Field, DenburyHamilton Dome, Merit Energy
12 Oil NGL D e l h i H e a t E x c h a n g e r FY 2023 Denbury Capital Project Evolution participating in installation of 3 heat exchangers at Delhi Central Facility Project Objectives: • Heat from compressed CO2 recycled stream will warm cold production fluids before entering the EOR facility, reducing winter downtime • Cooled recycled CO2 stream increases injection rates in the warm summer months • Provide stable NGL processing during the cold winter months • Reduce LOE by removing current heating/cooling equipment Estimated Project Costs: • Estimated net spend for this project is $1.2MM • ~$0.1MM is anticipated to be spent in FY2022 • Remaining $1.1MM to be spent throughout the first half of FY2023 • The project is expected to be operational in Q3 FY2023 Hot CO2 Cooled CO2 Heated Inlet fluids Cold Inlet fluids Warmer Inlet Fluid Temperatures Reduce Winter DowntimeCooler CO2 Temperatures Increase Injection Rates Reduced CO2 injection rates due to warmer temperatures During cold weather, inlet production temperatures can cause downtime in the plant Months Days CO2 Purchase Line Down
13 $5.83 $6.35 $9.03 $4.70 $3.45 $2.83 $8.27 $9.33 $10.27 $13.43 $15.25 $16.59 $4.95 $7.25 $5.66 $5.34 $6.20 $1.30 FY17A FY18A FY19A FY20A FY21A 1H22A 1H22 Pro Forma $ /B O E Lease Operating Expenses (LOE) & Cash G&A(2) CO2 Expenses Other LOE Cash G&A 0.0x 0.0x 0.0x 0.0x 0.0x 0.1x < 1.0x 33.1 33.2 33.2 33.0 33.3 33.6 33.6 0.0 10.0 20.0 30.0 40.0 50.0 60.0 0.0 0.5 1.0 1.5 2.0 2.5 3.0 FY17A FY18A FY19A FY20A FY21A FYTD22 Annualized FYTD22 Pro Forma S h a re s O u ts ta n d in g ( M M ) T o ta l D e b t / A d ju st e d E B IT D A Total Debt/ Adjusted EBITDA & Shares Outstanding Debt/ Adj EBITDA Shares Outstanding $20.0 $23.8 $26.1 $12.9 $8.1 $37.4 $0.603 $0.716 $0.787 $0.389 $0.244 $1.113 $0.000 $0.150 $0.300 $0.450 $0.600 $0.750 $0.900 $1.050 $1.200 $1.350 $1.500 $1.650 $1.800 $1.950 $2.100 $0.0 $10.0 $20.0 $30.0 $40.0 $50.0 $60.0 $70.0 FY17A FY18A FY19A FY20A FY21A FYTD22 Annualized FYTD22 Pro Forma $ /S h a re $ M M Adjusted EBITDA ($MM) Adjusted EBITDA Adj EBITDA/ Weighted Share A d d i n g S i g n i f i c a n t S c a l e w i t h C o n s e r v a t i v e L e v e r a g e & w i t h o u t D i l u t i n g S h a r e h o l d e r s Evolution’s Growth Story 2,105 2,042 2,025 2,035 2,430 5,400 ~8,000 0.023 0.022 0.022 0.023 0.027 0.059 0.087 0.000 0.010 0.020 0.030 0.040 0.050 0.060 0.070 0.080 0.090 0.100 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 FY17A FY18A FY19A FY20A FY21A 1H22A 1H22 Pro Forma B O E /D ilu te d S h a re B O E P D Average Daily Production (BOE/day) Jonah Field Pro-Forma Williston Pro-Forma Barnett Shale Hamilton Dome Giddings Delhi Total Production / Weighted Share $19.05 $22.93 $24.96 $23.47 $24.90 $20.72 Notes: 1. 1H22 Pro Forma excludes Giddings volumes. 2. Cash G&A excludes stock-based compensation (1)
14 $0 $20 $40 $60 $80 $100 $120 $0.00 $0.02 $0.04 $0.06 $0.08 $0.10 $0.12 W T I A ve ra g e O il P ri ce Q u a rt e rl y D iv id e n d P e r S h a re Common Stock Dividends WTI EIA Avg Price for Quarter C o n s i s t e n t l y P a i d D i v i d e n d s T h r o u g h C o m m o d i t y C y c l e s Common Stock Dividends vs. Average Oil Price Cumulative Payout Dec’13 – Dec’21 ~$84MM ($2.51/share) Note: 1. WTI average oil price represents the average of daily close prices for WTI within the associated quarter as reported by EIA. For Quarter ended 3/31/2022, average price through 2/22/2022. (1) 3Q22 Dividend Increased to $0.10/share
15 N Y S E : E P M Evolution’s Value Proposition High Quality, Low Risk, Long-lived Asset Base • Low production decline and positive cash flow; 20+ years remaining life • Potential upside drilling and workover opportunities in recently acquired Williston Basin and Barnett Shale assets Attractive Dividend Supports Total Shareholder Return • Consecutively paid dividends since 2013 • Currently ~5.6% yield at $0.40/share annually Consistent Track Record of Generating Cash Flow • 9 years of positive operating cash flow • Substantial additional free cash flow from recent acquisitions Solid Financial Position • Low leverage at less than 1x pro forma debt/Adjusted EBITDA Executing a Disciplined Growth Plan • Closed Jonah Field acquisition on April 1, 2022 • Closed Williston Basin acquisition on January 14, 2022 • Closed Barnett Shale acquisition on May 7, 2021 • Closed Hamilton Dome field acquisition on November 1, 2019 • Positioned to execute future acquisitions and disciplined development with conservative leverage <1x $84 Million In Dividends Returned to Shareholders Since December 2013 $ 2.51 Per Share Returned to Shareholders Since December 2013 % 5.6 Current Dividend Yield (Annualized 3Q22)
16 Contact Information R E A C H U S Thank you for your interest in Evolution Petroleum Corporation NYSE: EPM +1 713 935 0122 info@evolutionpetroleum.com 1155 Dairy Ashford, Suite 425 Houston, TX 77079 www.evolutionpetroleum.com Management Team Robert Herlin | Evolution Petroleum Chairman & Co-founder Edward DiPaolo | Halliburton, Duff & Phelps William Dozier | Vintage Petroleum, Santa Fe Minerals & Amoco Kelly Loyd | JVL Advisors, LLC, RBC Capital Marjorie Hargrave | President & CFO of Enservco Board of Directors Jason Brown | President & CEO | Founder of LongBow Energy, Co-founder of Halcon Resources, RBC Richardson Barr, Petrohawk | jbrown@evolutionpetroleum.com Ryan Stash | Senior Vice President & CFO | Harvest Oil & Gas, Wells Fargo Securities, Ernst & Young | rstash@evolutionpetroleum.com
18 Footnotes Slide 3: 1. Pro Forma 1H FY2022 net production includes recent acquisitions in the Williston Basin and Jonah Field but excludes 130 BOEPD associated with past royalties in the Giddings Field that accumulated over a period of approximately three years and were received in Q2 FY2022. 2. Reserves from June 30, 2021 Fiscal Year End Reserves Report. Reserves determined using gas conversion ratio of 6:1; NGL ratio of 1:1. Proved reserves as of June 30, 2021 do not include Williston Basin or Jonah Field assets. 3. EPM Reserves as of 7/1/2021 at 6/30/2021 SEC prices less 1H FY 2022 Production. Barnett reserves are Company adjusted for ethane rejection; see slide 20 in Appendix. Williston Basin Company engineered reserves as of 1/1/2022 at 12/31/2021 SEC prices of $3.64/MMBTU and $66.55/bbl. Jonah Field Company engineered reserves as of 2/1/2022 at 12/31/2021 SEC prices of $3.64/MMBTU and $66.55/bbl. Jonah Field acquisition. 4. Effective March 4, 2022, the borrowing base was increased from $40MM to $50MM. There was $4MM borrowed at 12/31/2021 and a total of $33MM borrowed for the Williston Basin and Jonah Field acquisitions. 5. See Non-GAAP Reconciliation disclosure on slide 2 and Non-GAAP Reconciliation table in the Appendix. Slide 6: 1. See “Forward Looking Statements” on slide 2. 2. Jonah Field acquisition price of $27.5MM reflects preferential rights exercised and is subject to customary closing adjustments including a deposit of $1.5MM paid at PSA signing. The effective date of the transaction is February 1, 2022 with a closing date of April 1, 2022. 3. Gas conversion ratio of 6:1; NGL ratio of 1:1. 4. Estimated average net production 1H FY 2022 (6 months ended 12/31/2021) excluding 130 BOEPD from past royalties in the Giddings Field that accumulated over a period of approximately three years and were received in Q2 FY2022. 5. EPM Reserves as of 7/1/2021 at 6/30/2021 SEC prices of $2.47/MMBTU and $49.72/bbl, less 2022 1H Production. 6. Barnett reserves as of 7/1/2021 at 6/30/2021 SEC prices of $2.47/MMBTU and $49.72/bbl, less 2022 1H Production. Barnett reserves are Company adjusted for ethane rejection, see slide 20 in Appendix. 7. Williston Basin Company engineered reserves as of 1/1/2022 at 12/31/2021 SEC prices of $3.64/MMBTU and $66.55/bbl. 8. Jonah Company engineered reserves as of 2/1/2022 at 12/31/2021 SEC prices of $3.64/MMBTU and $66.55/bbl. 9. 4/4/2022 strip pricing.
19 N o n - G A A P R e c o n c i l i a t i o n Adjusted EBITDA Reconciliation Adjusted EBITDA is a non-GAAP financial measure that is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis. It is also used to assess our ability to incur and service debt and fund capital expenditures. Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flows provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The Company defines Adjusted EBITDA as net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization (DD&A), stock- based compensation, other amortization and accretion, ceiling test impairment and other impairments, unrealized loss (gain) on change in fair value of derivatives, and other non-cash expense (income) items. Year Ended FY17 FY18 FY19 FY20 FY21 Q2FY22 FYTD22 EBITDA Calculation ($ in 000s) Net Income (Loss) 8,044 19,618 15,377 5,937 (16,438) 6,832 12,050 + Interest Expense 82 111 117 111 91 51 102 + Income Tax Expense (Benefit) 4,841 (3,432) 3,482 (2,181) (4,984) 1,745 3,264 + DD&A 5,719 6,012 6,253 5,761 5,167 1,224 2,752 + Stock-Based Compensation 1,181 1,367 888 1,286 1,258 329 527 + Other amortization and accretion 60 90 - 25 10 - - + Impairments - - - - 24,938 - - - Unrealized (Gain)Loss on Derivatives 14 - - 1,911 (1,911) - - - Other Non-cash (Income) 17 - - - (12) - - Adjusted EBITDA 19,956 23,766 26,117 12,850 8,119 10,181 18,695
20 B a r n e t t R e s e r v e s Ethane Rejection Reconciliation Barnett Reserves as of 7-1-21 @ 6/30/2021 SEC Price Net Oil MBO Net Gas MMcf Net NGL BOE MBOE(1) Ethane Recovery (FYE 2021) 85 48,571 4,879 13,059 Ethane Rejection (Company Engineered) 87 52,516 3,135 11,975 Difference 3 3,946 -1,744 -1,084 Difference, % 2.96% 8.12% -35.75% -8.30% • FYE2021 Barnett reserves were modeled in ethane recovery • In FY2022 the operator of the Barnett assets has been electing to reject ethane due to the price of natural gas compared to ethane in order to maximize revenue; the operator expects to remain in ethane rejection at current pricing forecasts • Evolution adjusted FYE 2021 Barnett reserves to reflect ethane rejection, see summary table below • Although revenue and asset value increased, the total number of MBOE decreased Notes: 1. Gas conversion ratio of 6:1; NGL ratio of 1:1.