Gen 3 Frac Design Driving Significant Outperformance 3 Q 17 Q UA R T E R LY E A R N I N G S C A L L No ve mb e r 8, 2017
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 filing. 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 Statement: 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
Gen 3 Performance Tops 3Q17 Highlights New Gen 3 Wells Delivering Outstanding Results in All Key Areas Average cumulative production uplift of 80 Gen 3 wells, 78% of which are multi-zone pattern wells completed in batches, performing at or above the highest EUR type curve – and significantly outperforming the midpoint EUR type curve – identified for each formation group (normalized to 10,000’) Public data continues to show Gen 3 wells in Midland and Delaware basins performing at or above other operators’ wells 3Q17 Production Beats Guidance by 9%; All Commodities Exceed Expectations 3Q17 oil production up 9% sequentially 4Q17 production guidance raised for all commodities; total 4Q17 production estimate increased 5%; YOY growth in 4Q exit rate now 60% Continued outperformance by new wells with Gen 3 fracs On track to generate 34% YOY growth in total production (prior estimate 29%) Midland and Delaware YOY production growth now estimated to be 43% Operating Expenses Down Significantly Per-unit LOE declined 17% over guidance Per-unit SG&A decreased 12% over guidance Bolt-on Lease Acquisitions Continue >11,000 net acres acquired in first nine months of 2017 for average price of ≈$21,400 per acre 2016 through September 2017, Energen acquired ≈20,300 net acres for ≈$355mm, or <$17,500 per acre 3
Gen 3 Performance Drives Production Beat By Ba sin (mboe pd) By Commodity (mboe pd) 81.3 81.3 74.8 74.8 72.5 72.5 28.7 26.2 23.4 49.0 47.9 45.1 44.8 41.3 40.6 15.7 13.5 12.9 16.6 13.9 13.9 7.9 8.0 7.9 2Q17a 3Q17 Guidance 3Q17a 2Q17a 3Q17 Guidance 3Q17a Gas NGL Oil Central Basin/Other Midland Basin Delaware Basin Total production up 9% over guidance and 12% over prior quarter Midland and Delaware Basin production each up 10% over guidance Oil production up 2% over guidance and 9% sequentially 4 Note: Totals may not sum due to rounding
4Q17 Production Guidance Increased 5% By Ba sin (mboe pd) By Commodity (mboe pd) 45.4 54.0 44.8 41.3 49.0 45.1 32.4 31.8 28.7 33.3 23.4 16.8 16.6 15.7 12.8 14.9 13.9 13.5 10.6 8.3 7.9 7.8 7.9 8.9 Midland Delaware CBP/Other Oil NGL Gas 1Q17a 2Q17a 3Q17a 4Q17e 1Q17a 2Q17a 3Q17a 4Q17e 5 Note: Totals may not sum due to rounding
YOY Production Growth Now Estimated at 34% Total 2017 production estimate: 73.2 mboepd Total 2017 Midland and Delaware production estimate of 65.2 mboepd reflects 43% YOY growth 4Q17 to 4Q16 exit rate estimated at 60% Pr oduc tion (mboe pd) 73.2 (e xc luding asse t sale s) 24.4 Growth rate (5-year CAGR): 54.6 53.6 19% total production 10.3 44.7 12.1 33% Midland Basin 37.8 25% Delaware Basin 13.3 30% Midland & Delaware 30.8 11.6 (10%) CBP/Other 40.8 7.9 35.3 31.6 20.3 13.9 9.7 13.2 12.3 11.1 9.9 9.0 8.0 2012 2013 2014 2015 2016 2017e Delaware Basin Midland Basin Central Basin/Other 6
3Q17 LOE, SG&A Decline Significantly L OE * ($/ boe ) SGA ($/ boe ) $7.15 $6.66 $3.25 $5.95 $3.00 $2.87 2Q17a 3Q17 Guidance 3Q17a 2Q17a 3Q17 Guidance 3Q17a Mdpt Mdpt LOE/boe down 17% from guidance SG&A/boe down 12% from guidance LOE/boe drops 11% from 2Q17 SG&A/boe drops 4% from 2Q17 7 * Includes Central Basin Platform
Energen Continues to Cut Costs; Compares Favorably with Permian Peers Boe 1 ($/ Boe ) Boe 1 ($/ Boe ) Adjuste d SG&A pe r L OE pe r Dark = 2015A Dark = 2015A Light = 2016A Light = 2016A (19%) (29%) (25%) (7%) $6.37 $8.01 $7.71 $6.46 $4.52 $5.81 $4.41 $4.09 2 3 Energen Permian peer median Energen Permian peer median 3,4 Boe 1 ($/ Boe ) Boe 1 ($/ Boe ) 2017e Guidanc e L OE pe r 2017e Guidanc e Adjuste d SG&A pe r $3.85 $5.75 $5.44 $3.30 Energen Permian Energen 2 Permian peer 3,5 peer median 3 median %∆ from 2016 %∆ from 2016 (16%) (1%) (27%) (6%) Source: Company disclosures 1 LOE Includes marketing and transportation; adjusted SG&A includes capitalized SG&A amounts, where available 2 LOE figures for EGN exclude Central Basin Platform 3 Permian peers include: CPE, CXO, FANG, LPI, PE, PXD, and RSPP; for three peers, 2017e LOE based on known actuals, as annual LOE guidance not given 4 For three peers, capitalized SG&A ranged from $11-$15 mm in 2015 and from $13-$19 mm in 2016 8 5 For three peers, 2017e capitalized SG&A annualized based on known actuals, as annual guidance not given
26 Wells Turned to Production in 3Q17 Avg. Avg. Peak 24-Hr IP Avg. Peak 30-Day IP Completed Area # Wells Lateral Boepd/ Boepd/ Boepd % Oil Boepd % Oil Length 1,000’ 1,000’ Wolfcamp A (6) Delaware Basin † 7 8,851’ 2,806 317 55 2,204 249 51 Wolfcamp B (1) Wolfcamp A (3) N. Midland Basin †† 7 9,189‘ 1,466 160 81 1,070 116 83 Wolfcamp B (4) † Excludes 2 Wolfcamp BC wells †† Excludes 10 Northern Midland Basin Spraberry interval wells due to timing of first production or disposal-related choke management 77% of wells turned to production in 3Q17 were multi-zone pattern wells completed in batches 9
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