Strong Execution Driving Growth and Value A P R I L I N V E S T O R P R E S E N T A T I O N

Transcription

1 Strong Execution Driving Growth and Value A P R I L I N V E S T O R P R E S E N T A T I O N Deutsche Bank Midland Tour April 5, 2018

2 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 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 ( 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

3 Execution Continues to Deliver Superior Results Strong Execution Leads to Excellent Results in 4Q17 4Q17 production beat guidance by 14% and surpassed 3Q17 by 20% 4Q17 oil production grew to 58.1 mbopd and exceeded guidance by 8% 4Q17 per-unit LOE and SG&A beat guidance midpoints by 10% and 9%, respectively CY17 production of 76.1 mboepd grew 39% from CY16 on strength of Generation 3 completions and increased activity level Additions replaced 415% of 2017 production, driving 40% increase in YE17 proved reserves Updated inventory supports net undeveloped resource potential of 2.7 billion BOE Gen 3 Pattern Wells Continue to Generate Outstanding Results Gen 3 performance drives strong IRRs through higher EURs and/or acceleration Updated type curves support superior economics 25 gross/21 net wells were turned to production in 4Q17; 64% were multi-zone pattern wells completed in batches New wells reflect outstanding 24-hour and 30-day IP rates in Midland and Delaware basins, with 4Q17 Delaware Basin wells generating average 24-hour IP rate of 402 boepd/1,000 and average 30-day IP rate of 272/1,000. Results reflect Energen s transformation into low-cost Permian pure-play with strong foundation for profitable growth 3

4 Focus on Value Creation Bringing Value Forward in CY18 Drilling & development capital estimated to range from $1.1B to $1.3B Plans include drilling approximately 130 gross/120 net horizontal wells and completing approximately 123 gross/113 net horizontal wells (including 30 gross/28 net DUCs at YE17) 2018 YOY production growth estimated at 25% at guidance midpoint 3-Year Outlook Leverages Superior Economics to Further Drive Shareholder Value 3-year production CAGR expected to exceed 28% Annual production estimated to reach 160 mboepd in 2020, with 4Q exit rate of 170 mboepd Drilling & development capital estimated to increase to $1.6B-$1.8B in year EBITDAX CAGR estimated at approximately 35% Balance sheet ensures capital flexibility as net debt to EBITDAX estimated to remain within 1.0x-1.5x each year Three-year outlook reflects commitment to bringing forward NAV of high quality assets while maintaining strong balance sheet 4

5 Another Production Beat in 4Q17 By Basin (mboepd) By Commodity (mboepd) Q17a 4Q17 Guidance 4Q17a Central Basin/Other Midland Basin Delaware Basin Q17a 4Q17 Guidance 4Q17a Gas NGL Oil Total production up 14% over guidance and 20% over prior quarter Midland and Delaware Basin production each up approximately 14% over guidance Oil production up 8% over guidance and 19% sequentially Note: Totals may not sum due to rounding 5

6 2017 Production Grows 39% Total 2017 production: 76.1 mboepd Delaware Basin production grows approximately 150% YOY in 2017 Midland Basin production exceeds 42 mboepd in 2017 Production (mboepd) Growth rate (5-year CAGR): 20% total production 34% Midland Basin 27% Delaware Basin 31% Midland & Delaware (9%) CBP/Other Central Basin/Other Midland Basin Delaware Basin Note: All years exclude asset sales 6

7 4Q17 Expenses Beat Guidance Midpoints LOE ($/boe) Net SG&A ($/boe) $7.85 $6.70 $6.02 ($4.94*) $4.25 $2.85 $2.58 4Q16a 4Q17 Guidance Mdpt 4Q17a 4Q16a 4Q17 Guidance Mdpt 4Q17a LOE/boe down 10% from guidance LOE/boe down 23% from 4Q16 SG&A/boe down 9% from guidance SG&A/boe down 39% from 4Q16 * Per-unit LOE for Midland/Delaware basins totaled $4.94/boe Note: 4Q16a excludes asset sales 7

8 Focus on Cost Reductions, Operating Efficiencies Drive Decline in YOY Expenses Midland/Delaware LOE ($/boe) Net SG&A ($/boe) $6.23 $5.28 $4.32 $ Note: 2016 excludes asset sales 8

9 CY17 Ends with Strong Balance Sheet 2017 Capitalization ($mm) Net debt at YE16 $ 165 Plus: Total Capital Expenditures* $ 1,189 Less: After-tax Cash Flows $ 571 Net Debt at YE17 $ 783 Net Debt/EBITDAX at YE Cash at YE17 $ -- Amount outstanding on revolver at YE17 $ 255 Notes at YE17 $ 528 Undrawn borrowing base $ 795 Maturity Schedule of Notes $400 $110 $ * Includes $287 mm for leasehold, mineral acquisitions, and miscellaneous costs incurred during 2017 Corporate Debt Ratings Moody s: Ba3-Stable S&P: BB-Stable 9

10 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 Delaware Basin Platform/Other TOTAL Proved Reserves by Commodity Oil Natural gas liquids Natural gas TOTAL NOTE: Totals may not sum due to rounding Basin Proved Probable Possible Contingent Resources Total Midland Basin ,557 Delaware Basin ,243 1,437 Platform/Other TOTAL ,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

11 Identified Inventory 4,023 Net Locations on 148,987 Net Acres Midland Basin (WC, SPB, Cline): 2,431 Net Locations on 88,298 net acres Delaware Basin (WC, BS, Avalon, BC): 1,592 Net Locations on 60,689 net acres Dawson: 15 Martin: 805 Howard: 229 New Mexico Texas Lea: 135 Loving: 545 Winkler: 35 Midland: 292 Glasscock: 868 Ward: 338 Upton: 23 Reagan: 195 (Crockett: 5) EGN Acres w/ Identified Horizontal Locations (2017 acquisitions, trades, increased WI shown in blue) Potential acreage addition of 10,000 net acres Reeves: 540 EGN Acres w/ Identified Horizontal Locations (2017 acquisitions, trades, increased WI shown in blue) Potential drilling locations as of 12/31/2017; engineered based on company s acreage and spacing plans and may change materially over time as the company 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 relevant criteria. 11

12 25 Wells Turned to Production in 4Q17 Area # Wells Avg. Completed Lateral Length Boepd Avg. Peak 24-Hr IP Boepd/ 1,000 % Oil Boepd Avg. Peak 30-Day IP Boepd/ 1,000 % Oil Delaware Basin 5 N. Midland Basin 4 Wolfcamp A (4) 3 rd BS Sand (1) Wolfcamp A (2) Wolfcamp B (2) 6,297 2, , ,548 1, , N. Midland Basin 5 Lower Spraberry 7,451 1, , N. Midland Basin * 9 Mid. Spraberry (5) Jo Mill (4) 7, C. Midland Basin 2 Wolfcamp A 9,160 1, , * Includes one Middle Spraberry well and one Jo Mill well turned to production in 3Q17 but not previously disclosed due to timing of first production Note: Excludes 2 test wells (one in Northern Midland Basin and one in Central Midland Basin) drilled in other formations 64% of wells turned to production in 4Q17 were multi-zone pattern wells completed in batches 12

13 Cumulative Production (MBOE) 2018 Delaware Basin Program Type Curves, EURs Updated New Ryder Scott Composite Curve for 2018 Delaware Basin program features 2.2 MMBOE EUR, up from prior midpoint of possible EURs of 1.75 MMBOE (59% oil). Higher EURs and acceleration driving higher IRRs. Recent wells continue to show outstanding results, as does average of 30 Delaware Basin Gen 3 Wolfcamp A/B wells brought on line in 2017 (red line); 50% are multi-zone pattern wells completed in batches Days # Wells: Prior Midpoint of Possible EURs Cessna 601H Avg Goldfinger Lease (2 Wells) 2017 Gen 3 Wolfcamp A/B Avg (30 Wells) Production and type curves normalized to 10, Gen 3 avg. production (red line) includes operational downtime Individual well/lease production normalized for operational downtime Day 0 = first oil Ryder Scott Composite Curve for 2018 Program Avg Alameda Lease (6 Wells) Avg New Mexico Well (1 WCA, 1 3rd Bone) 13

14 Cumulative Production (MBOE) 2018 NMB Wolfcamp A/B Program Type Curves, EURs Updated New Ryder Scott Composite Curve for 2018 North Midland Basin Wolfcamp A/B wells features 1.2 MMBOE EUR (67% oil). Updated shape of curve reflects acceleration, which is driving higher IRRs. Recent wells continue to show outstanding results, as does average of 13 North Midland Basin Gen 3 Wolfcamp A/B wells brought on line in 2017 (red line); 85% are multi-zone pattern wells completed in batches Production and type curves normalized to 10, Gen 3 avg. production (red line) includes operational downtime Individual well/lease production normalized for operational downtime Day 0 = first oil Days # Wells: Prior Midpoint of Possible EURs Ryder Scott Composite Curve for 2018 Program Gaskins 103H Avg Tiger Lease (4 Wells) 2017 Gen 3 Avg Wolfcamp A/B (13 Wells) 14

15 Cumulative Production (MBOE) 2018 NMB Lower Spraberry Program Type Curves, EURs Updated New Ryder Scott Composite Curve for 2018 North Midland Basin Lower Spraberry wells features 1.15 MMBOE EUR (73% oil). Updated shape of curve reflects acceleration, which is driving higher IRRs. Recent wells continue to show outstanding results, as does average of 9 North Midland Basin Gen 3 Lower Spraberry wells brought on line in 2017 (red line); 100% are multi-zone pattern wells completed in batches Days # Wells: Prior Midpoint of Possible EURs Avg Tiger Lease (5 wells) Production and type curves normalized to 10, Gen 3 avg. production (red line) includes operational downtime Individual well/lease production normalized for operational downtime Day 0 = first oil Ryder Scott Composite Curve for 2018 Program 2017 Gen 3 Avg Lower Spraberry (9 Wells) 15

16 Cumulative Production (MBOE) 2018 NMB Middle Spraberry/Jo Mill Program Type Curves, EURs New Ryder Scott Composite Curve for 2018 North Midland Basin Middle Spraberry and Jo Mill wells features 1.3 MMBOE EUR (72% oil). Higher EURS driving higher IRRs. Shape of curve adjusted to better reflect flowback profiles as compared to Lower Spraberry. Recent wells continue to show outstanding results, as does average of 14 North Midland Basin Gen 3 Middle Spraberry and Jo Mill wells brought on line in 2017 (red line); 86% are multi-zone pattern wells completed in batches Production and type curves normalized to 10, Gen 3 avg. production (red Line) includes operational downtime Individual well/lease production normalized for operational downtime Day 0 = first oil Days # Wells: Prior Midpoint of Possible EURs Gaskins 803H Avg Tiger Lease (5 Wells) Ryder Scott Composite Curve for 2018 Program Adams 601H 2017 Gen 3 Avg MSprb/Jo Mill (14 Wells) 16

17 Cumulative Production (MBOE) 2018 CMB Wolfcamp A/B Program Type Curves, EURs Updated New Ryder Scott Composite Curve for 2018 Central Midland Basin Wolfcamp A/B wells features 1.3 MMBOE EUR (48% oil); Wolfcamp A has higher oil mix at 50% as compared with 41% for Wolfcamp B. Higher EURS driving higher IRRs. Latest wells continue to show outstanding results, as does average of 12 Central Midland Basin Gen 3 Wolfcamp A/B pattern wells brought on line in 2017 (red line); 83% are multi-zone pattern wells completed in batches Prior Midpoint of Possible EURs Avg Pecos Lease (6 Wells) 2017 Gen 3 Avg Wolfcamp A/B (12 Wells) Production and type curves normalized to 10, Gen 3 avg. production (red line) includes operational downtime Individual well/lease production normalized for operational downtime Day 0 = first oil # Wells: Days Ryder Scott Composite Curve for 2018 Program Avg Moore 11-2 Lease (2 Wells) 17

18 7,500 Lateral IRR IRR IRR 10,000 Lateral IRR IRR IRR Attractive IRRs Support 2018 Program DB Wolfcamp A/B NMB 5-Zone Average CMB Wolfcamp A/B 160% 140% 120% 100% 80% 60% 40% 20% 0% Gross EUR: 2,200 mboe $50 $60 $70 NYMEX Oil $/bbl 140% 120% 100% 80% 60% 40% 20% 0% Gross EUR: 1,200 mboe $50 $60 $70 NYMEX Oil $/bbl 80% 70% 60% 50% 40% 30% 20% 10% 0% Gross EUR: 1,300 mboe $50 $60 $70 NYMEX Oil $/bbl -$1.0MM $10.8MM +$1.0MM -$1.0MM $8.3MM +$1.0MM -$1.0MM $8.5MM +$1.0MM 160% 140% 120% 100% 80% 60% 40% 20% 0% Gross EUR: 1,650 mboe $50 $60 $70 NYMEX Oil $/bbl 120% 100% 80% 60% 40% 20% 0% Gross EUR: 915 mboe $50 $60 $70 NYMEX Oil $/bbl 80% 70% 60% 50% 40% 30% 20% 10% 0% Gross EUR: 975 mboe $50 $60 $70 NYMEX Oil $/bbl -$1.0MM $8.3MM +$1.0MM -$1.0MM $6.8MM +$1.0MM -$1.0MM $6.9MM +$1.0MM EURs based on Ryder Scott composite curves for 2018 program Gas and NGL prices held constant at $3/MMBTU and 35% of WTI, respectively Estimated 2018 DC&E Cost 18

19 2018 Drilling & Development Capital Estimated to Range from $1.1B - $1.3B Drilling & Development Capital: $1.1B-$1.3B Hz new drills: approximately 130 gross/120 net wells Hz completions: approximately 123 gross/113 net wells, including 30 gross/28 net YE17 DUCs Hz DUCs at YE18: approximately 37 gross/35 net wells 7 gross/7 net vertical wells to be drilled (6 completions) Average of 8-10 drilling rigs and 4-5 frac crews Completed wells in 2018 program expected to have average lateral lengths of 8,000 and average working interests of 90% 2018 Horizontal Drilling Program Midland Basin: $550MM-$650MM Primary targets NMB: WC A/B, Spraberry package Primary targets CMB: WC A/B Delaware Basin: $550MM-$650MM Primary targets: WC A/B Capital Breakdown* 13% 6% 81% Operated Drilling & Development Facilities Non-Operated/Other Capital by Area* 10% YOY Production Growth at Guidance Midpoint: 25% Annual production estimated to be 95.0 mboepd at midpoint (range: mboepd) Production estimated to range from mboepd in 4Q Delaware Basin production estimated to grow 48% YOY 40% 50% Note: 2018 capital plan assumes prices of $58/bbl WTI, $0.65/gal NGL (before T&F) and $2.75/mcf Henry Hub * Graphed at midpoint of capital guidance range Delaware Basin North Midland Basin Central Midland Basin 19

20 Production Estimated to Increase to MBOEPD in 4Q18 Production by Commodity* (mboepd) Operated Horizontal Program First Production/Flow Back (Gross/Net) Midland Basin Delaware Basin 1Q18e 9/8 4/4 2Q18e 16/15 12/ Q18 2Q18 3Q18 4Q18 3Q18e 15/14 14/13 4Q18e 26/22 21/21 CY18e 66/58 51/48 Note: Totals may not sum due to rounding Gas NGL Oil * Guidance at midpoint 20

21 2018e YOY Production Growth: 25% Five-year total production CAGR: approximately 20% Delaware Basin estimated to grow 48% YOY in 2018 (at guidance midpoint) Production (mboepd) e Note: Guidance at midpoint; all years exclude asset sales Platform/Other Midland Basin Delaware Basin 21

22 Attractive Per-Unit Expenses Expected in 2018 Per BOE, except as noted 2018e 2017 LOE (production costs, marketing & transportation) $ $6.60 $6.61 Production & ad valorem taxes (% of revenues, excluding hedges) 6.2% 6.0% DD&A expense $ $14.50 $17.23 Salaries and general & administrative expenses $ $2.70 $3.05 Exploration expense (seismic, delay rentals, etc.) $ $0.20 $0.29 Interest expense ($mm) $ $51.5 $38.4 Effective tax rate (%) 22%-24% 37% CY18e LOE per BOE by Basin: Midland Basin $5.05-$5.25 Delaware Basin $5.35-$5.55 Central Basin Platform/Other $21.55-$21.75 CY18e Salaries and G&A, net ($ per BOE) Total $ $2.70 Cash $ $2.05 Non-cash equity-based comp $ $

23 Energen Maintains Strong Balance Sheet 2018e Capitalization ($mm) Net debt at YE17 $ 783 Plus: Total Capital Expenditures $ 1,100 1,300 Less: After-tax Cash Flows $ 877 Net Debt at YE18 $ 1,006 1,206 Net Debt/EBITDAX at YE Cash at YE18 $ -- Amount outstanding on revolver at YE18 $ Notes at YE18 $ 528 Undrawn line of credit $ EBITDAX reflects hedges, known commodity prices, and assumed prices for unhedged volumes of $58.00/barrel (January-December), $0.65/gallon (January-December), and $2.75 per Mcf (February-December). Maturity Schedule of Notes $400 $110 $ Corporate Debt Ratings Moody s: Ba3-Stable S&P: BB-Stable Strong financial position provides foundation for future growth and value creation 23

24 Hedges Help Minimize Risk Hedge Volumes Oil 3-way Collars¹ 13.5 mmbo 65% Call Price Put Price Short Put Price % Hedged 2 Avg. NYMEX Price $ 60.04/bbl $ 45.47/bbl $ 35.47/bbl Oil Swaps 1.4 mmbo 7% $ 60.24/bbl Commodity Hedge Volumes % Hedged 2 Avg. NYMEXe Price NGL mm gal 46% $ 0.60/gal Natural gas 9.0 bcf 20% $ 3.04/mcf Energen also has hedged the Midland to Cushing differential on 11.1 mmbo ( 60%) of its estimated 2018 sweet oil production at an average price of $(1.03). Oil 3-way Collars¹ Call Price Put Price Short Put Price Commodity Hedge Volumes 5.8 mmbo Hedge Volumes Avg. NYMEX Price $ 61.65/bbl $ 45.94/bbl $ 35.94/bbl Oil Swaps 2.9 mmbo $ 56.52/bbl Avg. Price NGL 55.4 mm gal $ 0.64/gal Energen also has hedged the Midland to Cushing differential on 6.1 mmbo of its estimated 2019 sweet oil production at an average price of $(0.75). 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 24

25 Three-Year Outlook Drives Further Value Outlook for underscores Company s commitment to bringing value forward by developing its top-tier Permian inventory and operating efficiently 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 Q 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 continuation of backwardated price environment with 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 25

26 Providing Strong Platform for Value Creation as Permian Pure-Play Solid execution leads to superior results in 2017 Continued execution in drives growth and value Oil-focused inventory > 4,000 net locations in key Permian Basin trends support net, undeveloped resource potential of 2.7 billion BOE Top-tier asset base and return potential $1.1B-$1.3B capital investment estimated for drilling and completion activities in year production CAGR expected to exceed 28% per year Strong balance sheet helps ensure capital flexibility 26

27 Appendix 27

28 EGN Frac Design Evolution Delaware Basin Generation 1 ( ) 1,000 lbs./ft proppant 240 stage spacing 39 bbls/ft fluid 50 cluster spacing Midland Basin Generation 1 ( ) 1,250-1,400 lbs./ft proppant stage spacing bbls/ft fluid cluster spacing Generation 2 (2015) 1,330 lbs./ft proppant 260 stage spacing 39 bbls/ft fluid 65 cluster spacing Generation 2 (2016) 1,600-1,700 lbs./ft proppant stage spacing bbls/ft fluid cluster spacing Generation 3 ( ) 1,800-2,400 lbs./ft proppant 200 stage spacing 40 bbls/ft fluid 33 cluster spacing Generation 3 ( ) 1,700-2,000 lbs./ft proppant 150 stage spacing bbls/ft fluid 30 cluster spacing 28

29 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 29

30 Identified Net 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, / , / , / , / , / Wolfcamp C Penn Shale Cline 4 39, / , / ,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%. 30

31 Identified Net 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 EUR per (Gross MBOE/MBO) Remaining Horizontal Undeveloped Resource 3 (Net MMBOE) 14 41, / /94 95 Jo Mill L. Spraberry Shale Dean Wolfcamp A Wolfcamp B 9 41, / / , / / , / / , / / Penn Shale Cline 2 32, /290 65/ ,223/1, % 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%. 31

32 Identified Net 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 (Gross MBOE/MBO) Remaining Horizontal Undeveloped Resource 3 (Net MMBOE) M. Spraberry Jo Mill L. Spraberry Shale Dean Wolfcamp A Wolfcamp B 6 29, / / , / / , / / Wolfcamp C Penn Shale Cline 4 37, / / , /269 95/ ,817/1, % 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%. 32

33 Identified Net Delaware Wolfcamp Shale: >1.1 Billion BOE 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 (Gross MBOE/MBO) Remaining Horizontal Undeveloped Resource 3 (Net MMBOE) 27 48, / / , / / , / / , / / ,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 (Gross MBOE/MBO) Remaining Horizontal Undeveloped Resource 3 (Net MMBOE) 1 6, /34 130/ % 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%. 33

34 Identified Net 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 (Gross MBOE/MBO) Remaining Horizontal Undeveloped Resource 3 (Net MMBOE) 32,396 82/26 110/90 13 Avalon 5, /31 100/ st Bone Spring Sand 2nd Bone Spring Shale 40,004 35/12 100/80 5 2nd Bone Spring Sand 2 48, /41 100/ rd Bone Spring Shale 3 rd Bone Spring/WC XY Sand 51, / / , /80 100/ / % 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%. 34

35 Inventory Spacing: Northern Midland Basin Inventory Spacing per 640-acre Section* Dean Wolfcamp A Wolfcamp B 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 35

36 Inventory Spacing: Central Midland Basin Inventory Spacing per 640-acre Section* 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 36

37 Inventory Spacing: Delaware Basin WC Shale Inventory Spacing per 640-acre Section* 6 6 Wolfcamp BC Mile * Subject to change based on continued testing and analysis of spacing and frac designs 37

38 Inventory Spacing: Delaware Basin Other 3 rd Bone Spring Shale Inventory Spacing per 640-acre Section* Mile * Subject to change based on continued testing and analysis of spacing and frac designs 38

39 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) 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 39

40 For More Information Julie S. Ryland Vice President Investor Relations