Strong Execution Continues in 2018 1Q18 Investor Presentation May 8, 2018
Forward-looking and Cautionary Statements Forward-looking Statement: All statements, other than statements of historical fact, appearing in this presentation constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward looking statements include, among other things, statements about our expectations, beliefs, intentions or business strategies for the future, statements concerning our outlook with regard to the timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, the nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, the timing and success of specific projects, operating costs and other expenses, proved oil and natural gas reserves, liquidity and capital resources, outcomes and effects of litigation, claims and disputes and derivative activities. Forward looking statements may include words such as anticipate, believe, could, estimate, expect, forecast, foresee, intend, may, plan, potential, predict, project, seek, will, or other words or expressions concerning matters that are not historical facts. These statements involve certain risks and uncertainties that may cause actual results to differ materially from expectations as of the date of this presentation. Except as otherwise disclosed, the forward looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. We base our forward looking statements on information currently available to us, and we undertake no obligation to correct or update these statements whether as a result of new information, future events or otherwise. Additional information regarding our forward looking statements and related risks and uncertainties that could affect future results of Energen, can be found in the Company s periodic reports filed with the Securities and Exchange Commission and available on the Company s website (www.energen.com). Cautionary Statements: The SEC permits oil and gas companies to disclose in SEC filings 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. Outside of SEC filings, we use the terms estimated ultimate recovery or EUR, reserve or resource potential, contingent resources and other descriptions of volumes of non-proved reserves or resources potentially recoverable through additional drilling or recovery techniques. These estimates are inherently more speculative than estimates of proved reserves and are subject to substantially greater risk of actually being realized. We have not risked EUR estimates, potential drilling locations, and resource potential estimates. Actual locations drilled and quantities that may be ultimately recovered may differ substantially from estimates. We make no commitment to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of our ongoing drilling program, 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 approvals, and geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per-well EUR, and resource potential may change significantly as development of our oil and gas assets provides additional data. Additionally, initial production rates contained in this presentation are subject to decline over time and should not be regarded as reflective of sustained production levels. 2
1Q18 Activity Delivers Strong Start to 2018 CY18 Off to Excellent Start in 1Q Total production of 92.9 mboepd surpasses guidance midpoint by 4% primarily due to well outperformance Oil production of 55.4 mbopd exceeds top end of 1Q18 guidance range up 5% from midpoint Per-unit net SG&A expense of $2.66/boe beats guidance midpoint by 11% Adjusted EBITDAX totaled $240.6 million, exceeding internal expectations by 10% >70% of estimated oil production (at guidance mdpt) for ROY hedged as well as 58% of the basis differential Bolt-on acquisitions in 1Q18 add 1,100 net leasehold acres for $18 million Strong Execution Showcased in 1Q18 25 gross (23 net) wells turned to production in 1Q18 as efficiencies help drive above-budget pace 8 new Gen 3 Wolfcamp wells in Delaware Basin deliver average peak 24- hour IP rates of >440 boepd/1,000 Performance of new Gen 3 Wolfcamp wells in central Midland Basin in line with type curve First Gen 3 Cline tests generate excellent results in north and central Midland Basin 3
1Q18 Production Beats Guidance Midpoint by 4% Continued Gen 3 completion outperformance and execution efficiencies combine to drive production growth in 1Q18. Total Production (mboepd) 89.5 92.9 52.8 33.3 8.9 10.6 53.0 55.4 17.5 18.2 19.0 19.3 Total production: Beats guidance midpoint by 4% Up 76% over 1Q17 Oil production: Beats guidance midpoint by 5% Up 66% over 1Q17 1Q17a 1Q18 Guidance Midpt 1Q18a Gas NGL Oil 4
1Q18 Expenses Continue YOY Decline LOE ($/boe) Net SG&A ($/boe) $8.68 $6.30 $6.30 1 $4.29 $3.00 $2.66 1Q17a 1Q18 Guidance Midpt 1Q18a 1Q17a 1Q18 Guidance Midpt 1Q18a 1 LOE in 1Q18 was impacted by the adoption of Accounting Standards Update 2014-09, Revenue from Contracts with Customers (ASC 606). For more information, refer to the Company s quarterly report on Form 10-Q for the three months ended March 31, 2018. 5
Delaware Basin Gen 3 Outperformance Continues Inventory Operational Highlights Primary target horizons: Wolfcamp A/B Turned 10 gross/10 net wells to production in 1Q18 Utilized an average of 3-4 Hz rigs and 2 frac crews during the quarter Estimated DC&E cost for 10,000 lateral: $1,025-$1,135/lateral foot New Mexico Texas Loving: 545 Reeves: 540 Denotes area of new 1Q18 wells Lea: 135 Winkler: 35 Ward: 338 Zone (# Wells) Wolfcamp A (3) Wolfcamp B (4) Wolfcamp BC (1) Avg. Completed Lateral Length 1Q18 Well Performance Avg. Peak 24-Hour IP Boepd/ 1,000 % Oil Avg. Peak 30-Day IP Boepd/ 1,000 % Oil 5,529 441 53 392* 58* Note: Excludes 1 well for which there was insufficient production history and 1 test well * 30-day peak data for 5 wells with sufficient production history EGN Acres w/ Identified Horizontal Locations YTD Acquisitions, Trades, and/or Increased WI As of 12.31.17: Net Acres Net Unrisked Engineered Locations Net Resource Potential % of Total Proved Reserves 60,689 1,592 >1.1 Billion BOE 24% Gen 3 Frac Design 1,800-2,400 lbs./ft proppant 200 stage spacing 40 bbls/ft fluid 33 cluster spacing 6
Cumulative Production (MBOE) Delaware Basin 2017-18 Gen 3 WC A/B Wells Exceeding Type Curve 600 550 500 450 400 350 300 250 200 150 100 50 0 Production and type curves normalized to 10,000 2017 Gen 3 avg. production (red line) includes operational downtime Individual well/lease production normalized for operational downtime Day 0 = first oil 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 480 510 Days 2018 Wells: 7 4 2 Ryder Scott Composite Curve for 2018 Program 2017 Gen 3 Avg Wolfcamp A/B (34 Wells) 2018 Gen 3 Avg Wolfcamp A/B (7 wells) 7
Midland Basin Gen 3 Driving Excellent Performance Dawson: 15 Inventory Martin: 805 Midland: 292 Howard: 229 Glasscock: 868 Operational Highlights Primary target horizons: Wolfcamp A/B plus Spraberry package in NMB Turned 15 gross/13 net wells to production in 1Q18 Utilized an average of 3 Hz rigs and 2 frac crews during the quarter 67% of wells with 1Q first production completed as pattern wells Estimated DC&E cost for 10,000 lateral: $790-$875/lateral foot Zone (# Wells) Avg. Completed Lateral Length 1Q18 Well Performance Avg. Peak 24-Hour IP Boepd/ 1,000 % Oil NMB WC B (1) 1 11,053 175 88 Avg. Peak 30-Day IP Boepd/ 1,000 % Oil Upton: 23 Reagan: 195 NMB Cline (1) 7,531 212 87 CMB WC A/B (11) 8,736 188 81 136 75 Denotes area of new 1Q18 wells (Crockett: 5) EGN Acres w/ Identified Horizontal Locations YTD Acquisitions, Trades, and/or Increased WI Potential Acreage Addition of 10,000 Net Acres As of 12.31.17: Net Acres Net Unrisked Engineered Locations Net Resource Potential % of Total Proved Reserves 88,298 2,431 >1.3 Billion BOE 66% CMB Cline (1) 2 6,572 353 69 188 65 1 Excludes a Lower Spraberry and a Jo Mill for which there is insufficient production history 2 Turned to production in late 4Q17 but not previously disclosed due to timing of first production Gen 3 Frac Design 1,700-2,000 lbs./ft proppant 150 stage spacing 40-45 bbls/ft fluid 30 cluster spacing 8
Cumulative Production (MBOE) Cumulative Production (MBOE) Midland Basin 2017-18 WC A/B Wells At or Above Type Curves Northern Midland Basin Central Midland Basin 275 250 225 200 175 150 125 100 75 50 25 0 0 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 480 Days 2018 Well: 1 2018 Wells: 11 7 5 Days Ryder Scott Composite Curve for 2018 Program 2017 Gen 3 Avg Wolfcamp A/B (13 Wells) Ryder Scott Composite Curve for 2018 Program Kathryn Ida 206H 2017 Gen 3 Avg Wolfcamp A/B (12 Wells) 2018 Gen 3 Avg Wolfcamp A/B (11 Wells) 300 275 250 225 200 175 150 125 100 75 50 25 Production and type curves normalized to 10,000 2017 Gen 3 avg. production (red line) includes operational downtime Individual well/lease production normalized for operational downtime Day 0 = first oil 9
Cumulative Production (MBOE) Cumulative Production (MBOE) Midland Basin 2017 Spraberry Wells Continue Outperformance Middle Spraberry / Jo Mill Lower Spraberry 300 275 250 225 200 175 150 125 100 75 50 25 0 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 Days 2017 Wells: 14 14 14 14 14 11 9 8 8 7 6 3 Ryder Scott Composite Curve for 2018 Program 2017 Gen 3 Avg MSprb/Jo Mill (14 Wells) 300 275 250 225 200 175 150 125 100 75 50 25 0 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 Days 2017 Wells: 9 9 9 9 9 6 4 4 4 4 4 4 1 Ryder Scott Composite Curve for 2018 Program 2017 Gen 3 Avg Lower Spraberry (9 Wells) Production and type curves normalized to 10,000 2017 Gen 3 avg. production (red line) includes operational downtime Individual well/lease production normalized for operational downtime Day 0 = first oil 10
Cumulative Production (MBOE) Cumulative Production (MBOE) Midland Basin Excellent Early Results from Gen 3 Cline Wells Northern Midland Basin Central Midland Basin 175 150 125 100 75 50 25 175 150 125 100 75 50 25 0 0 0 30 60 90 120 150 0 30 60 90 120 150 Days 2018 Well: 1 Days 2017 Well: 1 EGN Prior Generation Type Curve EGN Gen 3 Type Curve Tiger Unit 407H EGN Prior Generation Type Curve EGN Gen 3 Type Curve Foxtrot 405H Production and type curves normalized to 10,000 Individual well production normalized for operational downtime Day 0 = first oil 11
WATER GAS OIL Production Supported by Basin-wide Flow Assurance 85% of Permian Basin oil production on pipe 80% of Midland & Delaware oil sold to Plains All American, making EGN a top 5 customer Anchor tenant with Vaquero Midstream for FT and plant capacity in Delaware Basin Excellent access to extensive gas gathering and processing in Midland Basin Hedging with financial derivatives mitigates exposure to basis differentials Oil: 2018-58% ROY @ ($1.37)/bbl 2019-6.8 mmbo @ ($1.11)/bbl Gas: 2018-24% ROY hedged Basin-wide: Typically sold at the wellhead with custody transfer at the CDP Midland/Delaware Basins: Primary purchaser: Plains All American ( 80% oil sales) Multiple sales contracts; long-term working relationship PAA has extensive pipeline network; expansion and new projects underway Multiple delivery options include Cushing, Houston, and Corpus Christi markets Secondary purchaser: Shell ( 15% oil sales) All contracts are receipt-point dedicated Basin-wide: Typically sold at the plant tailgate under percent-of-proceeds contracts Delaware Basin: >90% of Delaware gas volumes sold to Vaquero (starting June 1) Plants: Caymus I & II online, Caymus III start-up 3Q19; each with 200 mmcf/d capacity Vaquero maintains access to multiple gas residue and NGL outlets Vaquero contract is long-term and acreage dedicated Midland Basin: Long-term contracts with primary purchasers, Targa and WTG Disposal: Own SWD wells with ample capacity to meet disposal needs Facilities designed to be reused over time (e.g., 3 rd BS/Wolfcamp XY Sand facilities) Current 3-year plan ensures build out of new facilities as needed No current issues with SWD permitting 95% of all produced water on pipe; permitted disposal capacity of 1.4 mmbwpd by YE18 Sources: Own water supply wells drilled on surface acreage leased from landowners Additional supply arrangements with third parties Limited amounts trucked or recycled 12
2018 Production Guidance CY18 Range: 92.0-99.0 MMBOEPD Production by Commodity* (mboepd) 107.0 92.9 93.0 95.5 91.0 66.5 55.4 53.0 55.5 57.5 2018 Operated Horizontal Program First Production/Flow Back (Gross/Net) Midland Basin Delaware Basin Total 1Q18a 15/13 10/10 25/23 2Q18e 10/9 8/6 18/15 18.2 18.0 17.5 19.0 18.0 19.3 20.0 20.0 21.0 20.0 1Q18a 2Q18e 3Q18e 4Q18e CY18e 3Q18e 20/20 9/8 29/28 4Q18e 20/17 22/21 42/38 CY18e 65/59 49/46 114/105 Note: Totals may not sum due to rounding Gas NGL Oil * Estimates graphed at midpoint of guidance range 13
2018 Capital Guidance CY18 Range Unchanged: $1.1B-$1.3B Capital Breakdown* Capital by Area* 13% 6% 10% 40% 50% 81% Operated Drilling & Development Facilities Non-Operated/Other Delaware Basin North Midland Basin Central Midland Basin 2018 Operated Horizontal Program Gross/Net Wells Avg. Lateral Length Avg. Working Interest YE17 DUC Completions 30/28 7,600 92% New Drill 2018 128/117 8,300 92% New Drill Completions 2018 93/86 8,100 92% YE18 DUCs 35/32 8,900 90% * Graphed at midpoint of $1.1- $1.3 billion guidance range 14
2018 Expense Guidance Updated Per BOE, except as noted 2Q18e 3Q18e 4Q18e 2018e LOE (production costs, marketing & transportation) $6.80 - $7.00 $6.50 - $6.70 $6.10 - $6.30 $6.40 - $6.60 Production & ad valorem taxes (% of revenues, excluding hedges) 6.2% 6.2% 6.2% 6.2% DD&A expense $14.75 - $15.25 $14.15 - $14.65 $13.40 - $13.90 $14.15 - $14.65 SG&A, net $2.50 - $2.90 $2.30 - $2.70 $1.80 - $2.20 $2.30 - $2.70 Exploration expense (seismic, delay rentals, etc.) $0.15 - $0.20 $0.15 - $0.20 $0.15 - $0.20 $0.15 - $0.20 Effective tax rate (%) 22%-24% 22%-24% 22%-24% 22%-24% CY18e LOE per BOE by Basin: Midland Basin $5.20-$5.40 Delaware Basin $5.25-$5.45 Central Basin Platform/Other $21.00-$21.20 CY18e Salaries and G&A, net ($ per BOE) Total $2.30 - $2.70 Cash $1.90 - $2.10 Non-cash equity-based comp $0.40 - $0.60 15
Energen Maintains Strong Balance Sheet 2018e Capitalization ($mm) Net debt at YE17 $ 783 Plus: Drilling & Development Capital $ 1,100 1,300 Leasehold/Other $ 28 Less: After-tax Cash Flows $ 1,003 Net Debt at YE18e $ 908 1,108 Net Debt/EBITDAX at YE18e 0.9 1.1 Cash at YE18e $ -- Amount outstanding on revolver at YE18e $ 380 580 Notes at YE18e $ 528 Undrawn line of credit $ 670-870 EBITDAX reflects hedges, known commodity prices, and assumed prices for unhedged volumes of $65.00/barrel (April-December), $0.70/gallon (April- December), and $2.85 per Mcf (May-December). Assumes $1.25 billion line of credit (increased from $1.05 billion) with a new borrowing base of $2.15 billion (increased from $1.7 billion). Maturity Schedule of Notes $400 $110 $20 2018 2019 2020 2021 2022 2023 2024+ Corporate Debt Ratings Moody s: Ba3-Stable S&P: BB-Stable 16
Hedges Limit Commodity, Differential Price Exposure Hedge Position (as of 5.1.18) 1Q18 2Q18 3Q18 4Q18 CY18 CY19 Oil: Swaps Volume (MBbl) Price ($/Bbl) --- 360 $60.17 480 $60.28 540 $60.25 1,380 $60.24 3,600 $57.28 Oil: Three-way Costless Collars 1 Volume (MBbl) Call Price (Avg. $/Bbl) Put Price (Avg. $/Bbl) Short Put Price (Avg. $/Bbl) 3,375 $60.04 $45.47 $35.47 3,375 $60.04 $45.47 $35.47 3,375 $60.04 $45.47 $35.47 3,375 $60.04 $45.47 $35.47 13,500 $60.04 $45.47 $35.47 5,760 $61.65 $45.94 $35.94 % Estimated Oil Production Hedged 2 77% 75% 64% 72% Midland WTI-Cushing WTI (Sweet) Differential Volume (MBbl) Price ($/Bbl) 2,700 ($1.01) 2,910 ($1.19) 3,150 ($1.46) 3,150 ($1.46) 11,910 ($1.29) 6,840 ($1.11) % Estimated Oil Basis Hedged 2 60% 62% 51% 57% NGL: Swaps Volume (MGal) Price ($/Gal) 26,460 $0.59 34,020 $0.61 34,020 $0.61 34,020 $0.61 128,520 $0.60 85,680 $0.64 % Estimated NGL Production Hedged 2 49% 50% 46% 47% Permian Natural Gas: Swaps Volume (MMcf) Price ($/Mcf) 3 900 $2.56 2,700 $1.98 2,700 $1.98 2,700 $1.98 9,000 $2.04 --- % Estimated Gas Production Hedged 2 25% 24% 23% 21% 1 When the NYMEX price is above the call price, Energen receives the call price; when the NYMEX price is between the call price and the put price, Energen receives the NYMEX price; when the NYMEX price is between the put price and the short put price, Energen receives the put price; and when the NYMEX price is below the short put price, Energen receives the NYMEX price plus the difference between the put price and the short put price. 2 Assumes midpoint of guidance. 3 Represents net Permian Basin price. 17
2017: Proven Execution Story Quality Portfolio Year-end total proved reserves increased > 40% to 444 MMBOE Undeveloped resource potential of 2.7 billion BOE from > 4,000 net locations Successful bolt-on acquisition/trade program Key Performance Metric Improvements Operational Success 2016 2017 Gen 3 success drove strong IRRs through higher EURs and/or acceleration Multi-zone pattern wells completed in batches at original reservoir pressure achieved stand-alone performance Reserve additions of > 115 MMBOE replaced production by 415% Financial Strength YE17 net debt to EBITDAX of 1.2x Strong balance sheet helped ensure capital flexibility Hedging program helped minimize price risk and protect cash flows Proved Reserves (MMBOE) 316 +40% 444 Daily Production (MBOEPD) 54.6 +39% 76.1 Adj. EBITDAX ($MM) $293 +123% $653 LOE (incl M&T) ($/BOE) $7.86-16% $6.61 SG&A Costs ($/BOE) $4.32-29% $3.05 Consistent Performance Successfully completed company s largest number of Hz wells to date Production exceeded guidance every quarter during 2017 Continued to significantly drive down per unit LOE and SG&A costs Results reflect Energen s transformation into a low-cost Permian pure-play with a strong foundation for profitable growth 18
Peer-Leading Drill-Bit Economics in 2017 2017 Adjusted PDP Finding & Development Cost ($/boe) 1 $8.91 $10.72 $11.35 $13.04 $13.29 $14.20 $14.98 $20.63 EGN Peer Peer Peer Peer Peer Peer Peer 2017 Recycle Ratio 2 2.93 2.66 2.19 2.04 1.82 1.80 1.55 1.49 Peer EGN Peer Peer Peer Peer Peer Peer Source: April 17, 2018 Seaport Global 2017 Capital Efficiency Study; peers include CPE, CXO, FANG, LPI, PE, PXD, and RSPP 1 A proprietary SGS calculation which represents reserves added from wells actually drilled during the year vs. actual capital spent during the year to drill, complete and build supportive infrastructure 2 Defined as unhedged operating margin ($/boe) divided by adjusted PDP F&D cost ($/boe) 19
Three-Year Outlook Brings Forward Value The Company s three-year plan achieves cash flow neutrality in 2020 at $57/bbl. Capital Drilling & development capital estimated to increase to $1.6B-$1.8B in 2020 Three-year plan assumes continuation of approximate 50/50 capital allocation between Midland and Delaware basins Production 3-year production CAGR (at midpoint) estimated to exceed 28% Annual production estimated to exceed 160 mboepd in 2020 4Q exit rates expected to increase from 107 mboepd (at midpoint) in 2018 to approximately 135 mboepd in 2019 and 170 mboepd in 2020 Cash Flow Three-year plan assumes WTI oil prices of $58/bbl in 2018, $54/bbl in 2019 and $52/bbl in 2020 EBITDAX estimated to exceed $1.6B in 2020 for 3-year CAGR 35% Balance Sheet Growth occurs as Company continues to maintain already outstanding balance sheet Net debt to EBITDAX estimated to be within 1.0x-1.5x in each year 20
Energen: A Compelling Investment A pure-play Permian Basin operator Creating long-term shareholder value by bringing forward NAV in a responsible manner Return-driven focus with corporate level returns across all operating areas that significantly exceed company s weighted average cost of capital Under-levered balance sheet managed to 1.0x-1.5x net debt to EBITDAX Approximately 149,000 net acres of top-tier Permian assets Attractive 3-year production CAGR of approximately 28% (2018-2020) Early leader in pattern development that avoids parent/child well degradation issues Current Generation 3 frac design and spacing delivering outstanding stand alone performance Takeaway capacity for growing oil & gas production along with outstanding water disposal network Experienced management team with Permian exposure since 1997 21
Appendix 22
Premium Permian Basin Acreage Energen s Permian Footprint (12/31/2017) Basin Gross Acres Net Acres Delaware 93,897 62,313 Midland 118,922 95,105 Platform 116,334 82,578 23
387 201 637 613 266 185 388 491 334 Identified Net Potential @ 12.31.17 Midland Basin: >1.3 Billion BOE Midland Basin M. Spraberry Jo Mill L. Spraberry Shale Dean Wolfcamp A Wolfcamp B Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations 1 (Gross/Net) Remaining Horizontal Undeveloped Resource 2 (Net MMBOE) 14 41,354 271/161 95 9 41,330 276/170 101 40 70,347 818/489 261 111 74,164 654/382 228 107 72,040 632/375 243 Wolfcamp C Penn Shale Cline 4 39,332 486/295 158 4 66,215 903/559 235 289 4,040/2,431 1,321 30% of identified locations (897 gross/717 net) have lateral lengths of 10,000 ; average WI is 80% 18% of identified locations (451 gross/440 net) have lateral lengths of 10,000 ; average WI is > 90% 27% of identified locations (938 gross/658 net) have lateral lengths of 6,700 & 7,500 ; average WI is 70% 1 Potential drilling locations engineered to the longest lateral allowed by lease geometry or current/expected agreement based on Energen s acreage and spacing plans; may change materially over time as Energen and offset operators gain additional data in each zone; actual lateral lengths may vary depending on various factors including lease geometry, relationship with offset operators, allowed spacing, reservoir characteristics, and other criteria. 2 Reflects estimates of PUD, probable and possible reserves and contingent resources prepared by the company and reviewed by Ryder Scott; net of royalty interest of 25%. 24
439 374 317 243 252 405 387 249 Identified Net Potential @ 12.31.17 North Midland Basin: 695 MMBOE Midland, Martin, Dawson & Howard Counties M. Spraberry Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations 1 (Gross/Net) Type Curve Remaining Horizontal EUR per 1000 2 Undeveloped Resource 3 (Gross MBOE/MBO) (Net MMBOE) 14 41,176 271/161 130 (94) 95 Jo Mill L. Spraberry Shale Dean Wolfcamp A Wolfcamp B 9 41,152 276/170 130 (94) 101 34 41,196 528/313 115 (84) 163 29 37,956 325/188 120 (83) 100 31 36,989 358/216 130 (83) 139 Penn Shale Cline 2 32,303 465/290 65 (42) 97 119 2,223/1,338 695 26% of identified locations (422 gross/343 net) have lateral lengths of 10,000 ; average WI is 81% 18% of identified locations (245 gross/240 net) have lateral lengths of 10,000 ; average WI is > 90% 25% of identified locations (441 gross/332 net) have lateral lengths of 6,700 & 7,500 ; average WI is 81% 1 Potential drilling locations engineered to the longest lateral allowed by lease geometry or current/expected agreement based on Energen s acreage and spacing plans; may change materially over time as Energen and offset operators gain additional data in each zone; actual lateral lengths may vary depending on various factors including lease geometry, relationship with offset operators, allowed spacing, reservoir characteristics, and other criteria. 2 Estimated gross EURs normalized to 1,000 lateral lengths; based on various geological and engineering assumptions made by management using company and pubic data sources; EUR estimates may change materially over time as Energen and offset operators gain additional production data. 3 Reflects estimates of PUD, probable and possible reserves and contingent resources prepared by the company and reviewed by Ryder Scott; net of royalty interest of 25%. 25
387 201 637 613 266 185 388 491 334 Identified Net Potential @ 12.31.17 Central Midland Basin: 626 MMBOE Glasscock, Upton & Reagan Counties Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations 1 (Gross/Net) Type Curve EUR per 1000 2 (Gross MBOE/MBO) Remaining Horizontal Undeveloped Resource 3 (Net MMBOE) M. Spraberry Jo Mill L. Spraberry Shale Dean Wolfcamp A Wolfcamp B 6 29,150 290/176 105 (85) 98 82 36,208 329/194 130 (65) 128 76 35,050 274/159 120 (49) 104 Wolfcamp C Penn Shale Cline 4 37,285 486/295 100 (54) 158 2 33,912 438/269 95 (43) 138 170 1,817/1,093 626 34% of identified locations (475 gross/374 net) have lateral lengths of 10,000 ; average WI is 79% 18% of identified locations (206 gross/200 net) have lateral lengths of 10,000 ; average WI is > 90% 30% of identified locations (527 gross/326 net) have lateral lengths of 6,700 & 7,500 ; average WI is 62% 1 Potential drilling locations engineered to the longest lateral allowed by lease geometry or current/expected agreement based on Energen s acreage and spacing plans; may change materially over time as Energen and offset operators gain additional data in each zone; actual lateral lengths may vary depending on various factors including lease geometry, relationship with offset operators, allowed spacing, reservoir characteristics, and other criteria. 2 Estimated gross EURs normalized to 1,000 lateral lengths; based on various geological and engineering assumptions made by management using company and pubic data sources; EUR estimates may change materially over time as Energen and offset operators gain additional production data. 3 Reflects estimates of PUD, probable and possible reserves and contingent resources prepared by the company and reviewed by Ryder Scott; net of royalty interest of 25%. 26
375 325 Identified Net Potential @ 12.31.17 Delaware Wolfcamp Shale: >1.1 Billion BOE 250 325 425 Texas Wolfcamp Upper A Wolfcamp A Wolfcamp B Wolfcamp BC Wolfcamp C Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations 1 (Gross/Net) Type Curve EUR per 1000 2 (Gross MBOE/MBO) Remaining Horizontal Undeveloped Resource 3 (Net MMBOE) 27 48,994 497/269 210 (130) 300 25 46,694 438/259 210 (130) 287 5 41,111 429/264 190 (80) 255 41,111 432/264 190 (80) 253 57 1,796/1,057 1,095 New Mexico Wolfcamp Upper A Wolfcamp A Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations 1 (Gross/Net) Type Curve EUR per 1000 2 (Gross MBOE/MBO) Remaining Horizontal Undeveloped Resource 3 (Net MMBOE) 1 6,192 113/34 130 (110) 22 30% of Wolfcamp locations (560 gross/330 net) have lateral lengths of > 10,000 ; average WI is 59% 22% of locations (270 gross/242 net) have lateral lengths of > 10,000 ; average WI is 90% 22% of Wolfcamp locations (316 gross/236 net) have average lateral lengths of approximately 7,500 ; average WI is 75% 1 Potential drilling locations engineered to the longest lateral allowed by lease geometry or current/expected agreement based on Energen s acreage and spacing plans; may change materially over time as Energen and offset operators gain additional data in each zone; actual lateral lengths may vary depending on various factors including lease geometry, relationship with offset operators, allowed spacing, reservoir characteristics, and other criteria. 2 Estimated gross EURs normalized to 1,000 lateral lengths; based on various geological and engineering assumptions made by management using company and pubic data sources; EUR estimates may change materially over time as Energen and offset operators gain additional production data. 3 Reflects estimates of PUD, probable and possible reserves and contingent resources prepared by the company and reviewed by Ryder Scott; net of royalty interest of 25%. 27
294 609 442 316 257 795 106 226 Identified Net Potential @ 12.31.17 Delaware Other Plays: 250 MMBOE Other Plays Lwr Brushy Canyon Bone Spring Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations 1 (Gross/Net) Type Curve EUR per 1000 2 (Gross MBOE/MBO) Remaining Horizontal Undeveloped Resource 3 (Net MMBOE) 32,396 82/26 110 (90) 13 Avalon 5,395 121/31 100 (55) 15 1st Bone Spring Sand 2nd Bone Spring Shale 40,004 35/12 100 (80) 5 2nd Bone Spring Sand 2 48,094 122/41 100 (80) 19 3 rd Bone Spring Shale 3 rd Bone Spring/WC XY Sand 51,515 413/310 110 (80) 162 120 57,314 163/80 100 (80) 36 122 939/501 250 25% of Other locations (203 gross/126 net) have lateral lengths of 10,000 ; average WI is 62% 19% of locations (105 gross/96 net) have laterals lengths of 10,000 ; average WI is 91% 16% of Other locations (107 gross/80 net) have average lateral lengths of approximately 7,500 ; average WI is 75% 1 Potential drilling locations engineered to the longest lateral allowed by lease geometry or current/expected agreement based on Energen s acreage and spacing plans; may change materially over time as Energen and offset operators gain additional data in each zone; actual lateral lengths may vary depending on various factors including lease geometry, relationship with offset operators, allowed spacing, reservoir characteristics, and other criteria. 2 Estimated gross EURs normalized to 1,000 lateral lengths; based on various geological and engineering assumptions made by management using company and pubic data sources; EUR estimates may change materially over time as Energen and offset operators gain additional production data. 3 Reflects estimates of PUD, probable and possible reserves and contingent resources prepared by the company and reviewed by Ryder Scott; net of royalty interest of 25%. 28
439 439 374 374 317 317 243 243 252 252 405 405 387 387 249 Inventory Spacing: North Midland Basin Inventory Spacing per 640-acre Section* 4 4 8 Dean Wolfcamp A Wolfcamp B 6 6 8 1 Mile * Subject to change based on continued testing and analysis of spacing and frac designs NOTE: Additional horizontal potential from other intervals such as Clearfork, Atoka/Barnett, Woodford 29
201 637 613 266 185 Inventory Spacing: Central Midland Basin Inventory Spacing per 640-acre Section* 6 387 388 6-8 6-8 8 8 1 Mile * Subject to change based on continued testing and analysis of spacing and frac designs NOTE: Additional horizontal potential from other intervals such as Clearfork, Middle Spraberry, Jo Mill 30
400 344 364 417 Inventory Spacing: Delaware Basin WC Shale Inventory Spacing per 640-acre Section* 6 6 Wolfcamp BC 6 6 1 Mile * Subject to change based on continued testing and analysis of spacing and frac designs 31
294 609 442 316 257 795 Inventory Spacing: Delaware Basin Other 3 rd Bone Spring Shale Inventory Spacing per 640-acre Section* 159 106 226 4 6 4 4 6 4 1 Mile * Subject to change based on continued testing and analysis of spacing and frac designs 32
YE17 Proved Reserves Increase >40% Reserve additions replaced production by 415% 2017 proved developed F&D cost totaled $8.38 per boe 1 Value of PDP reserves increased from $1.1B to $2.7B Delaware Basin proved reserves jumped 177% due to increased activity levels, Gen 3 performance, and higher pricing 3P and Contingent Resources totaled 3.0 billion BOE, up 33% from 2016 (mmboe) Proved Reserves Price Other YE16 Production Acq/(Div) Additions YE17 by Basin Revisions Revisions Midland Basin 236.4 15.5 0.0 49.0 7.0 16.9 293.8 Delaware Basin 39.1 9.4 0.2 66.3 0.9 10.9 108.1 Platform/Other 40.9 3.0 0.0 0.1 3.7 0.4 42.1 TOTAL 316.3 27.8 0.2 115.5 11.6 28.2 444.0 Proved Reserves by Commodity 2017 2016 Oil 257 200 Natural gas liquids 91 58 Natural gas 96 58 TOTAL 444 316 NOTE: Totals may not sum due to rounding Basin Proved Probable Possible Contingent Resources Total Midland Basin 294 154 130 979 1,557 Delaware Basin 108 40 46 1,243 1,437 Platform/Other 42 0 0 1 43 TOTAL 444 194 176 2,223 3,037 YE17 Reserves Pricing: oil $51.34/barrel WTI; NGL (before T&F) $0.57/gallon; natural gas $2.98/mcf Henry Hub 1 Proved developed finding and development (F&D) cost per boe is defined as exploration and development costs divided by the sum of reserves associated with discoveries and extensions placed on production during 2017, transfers from proved undeveloped reserves at year end 2016, and revisions (excluding price-related revisions) of previous estimates of proved developed reserves in 2017. 33
Non-GAAP Financial Measures Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (GAAP) / PV-10 (non-gaap): The standardized measure of discounted future net cash flows (SMOG) is the Company s GAAP estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, operating expenses, development costs, and income taxes discounted at an annual rate of 10%. PV-10 is a non-gaap measure that excludes the Company s estimates of future income taxes (discounted at an annual rate 10%). The Company believes that PV-10 allows for additional comparability among companies in the oil and gas industry due to the unique factors that may impact the timing of future income taxes to be paid. The Company also believes PV-10 to be important for evaluating the relative significance of its 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. The Company believes disclosing the year-over-year change in the PV-10 for Proved Developed Producing (PDP) reserves is a meaningful indication of the increase in value of the Company s producing properties. The following table reconciles the Company s standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP) to PV-10. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP. ($ in millions) 2017 2016 Standardized measure of discounted future net cash flows (GAAP) $3,320 $1,350 Add: Present value of future income taxes discounted at 10% $418 $147 PV-10 Total Proved reserves $3,738 $1,497 Less: PV-10 Proved Developed Non-Producing reserves $1,014 $349 PV-10 Proved Developed Producing reserves $2,724 $1,148 34
For More Information Julie S. Ryland Vice President Investor Relations 205-326-8421 jryland@energen.com www.energen.com 35