Gen 3 Frac Design Driving Significant Outperformance 3 Q 17 Q UA R - - PowerPoint PPT Presentation

3 Q 17 Q UA R T E R LY E A R N I N G S C A L L

Gen 3 Frac Design Driving Significant Outperformance

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

• r 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

• r 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

• f 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

• ngoing 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

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• 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

2Q17a 3Q17 Guidance 3Q17a

7.9 8.0 7.9 41.3 40.6 44.8 23.4 26.2 28.7

Central Basin/Other Midland Basin Delaware Basin

2Q17a 3Q17 Guidance 3Q17a

13.9 13.9 16.6 13.5 12.9 15.7 45.1 47.9 49.0

Gas NGL Oil

Gen 3 Performance Drives Production Beat

By Ba sin (mboe pd) By Commodity (mboe pd)

4

74.8 81.3 74.8

• 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

81.3

Note: Totals may not sum due to rounding

72.5 72.5

4Q17 Production Guidance Increased 5%

5

Midland Delaware CBP/Other

31.8 12.8 8.3 41.3 23.4 7.9 44.8 28.7 7.9 45.4 32.4 7.8

By Ba sin (mboe pd)

1Q17a 2Q17a 3Q17a 4Q17e

Oil NGL Gas

33.3 8.9 10.6 45.1 13.5 13.9 49.0 15.7 16.6 54.0 14.9 16.8

By Commodity (mboe pd)

1Q17a 2Q17a 3Q17a 4Q17e Note: Totals may not sum due to rounding

YOY Production Growth Now Estimated at 34%

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• 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%

2012 2013 2014 2015 2016 2017e

13.2 12.3 11.1 9.9 9.0 8.0 9.7 13.9 20.3 31.6 35.3 40.8 7.9 11.6 13.3 12.1 10.3 24.4

Delaware Basin Midland Basin Central Basin/Other

54.6 30.8 37.8 44.7 53.6 73.2

• Growth rate (5-year CAGR):
• 19% total production
• 33% Midland Basin
• 25% Delaware Basin
• 30% Midland & Delaware
• (10%) CBP/Other

Pr

• duc tion (mboe pd)

(e xc luding asse t sale s)

3Q17 LOE, SG&A Decline Significantly

SGA ($/ boe ) L OE * ($/ boe )

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• SG&A/boe down 12% from guidance
• SG&A/boe drops 4% from 2Q17
• LOE/boe down 17% from guidance
• LOE/boe drops 11% from 2Q17

2Q17a 3Q17 Guidance Mdpt 3Q17a

$6.66 $7.15 $5.95

2Q17a 3Q17 Guidance Mdpt 3Q17a

$3.00 $3.25 $2.87

* Includes Central Basin Platform

Energen Continues to Cut Costs; Compares Favorably with Permian Peers

Energen Permian peer median

$5.44 $5.75

2017e Guidanc e L OE pe r Boe 1 ($/ Boe )

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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 5 For three peers, 2017e capitalized SG&A annualized based on known actuals, as annual guidance not given

Energen Permian peer median

$8.01 $7.71 $6.46 $5.81

L OE pe r Boe 1 ($/ Boe ) Energen Permian peer median

$3.30 $3.85

Energen Permian peer median

$6.37 $4.41 $4.52 $4.09

Adjuste d SG&A pe r Boe 1 ($/ Boe )

(19%) (25%) (29%) (7%) Dark = 2015A Light = 2016A Dark = 2015A Light = 2016A

2 2 3 3,4 3 3,5

%∆ from 2016 (27%) (6%) %∆ from 2016 (16%) (1%)

2017e Guidanc e Adjuste d SG&A pe r Boe 1 ($/ Boe )

26 Wells Turned to Production in 3Q17

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Area # Wells Avg. Completed Lateral Length

• Avg. Peak 24-Hr IP
• Avg. Peak 30-Day IP

Boepd Boepd/ 1,000’ % Oil Boepd Boepd/ 1,000’ % Oil Delaware Basin† 7 Wolfcamp A (6) Wolfcamp B (1) 8,851’ 2,806 317 55 2,204 249 51

• N. Midland Basin††

7 Wolfcamp A (3) Wolfcamp B (4) 9,189‘ 1,466 160 81 1,070 116 83

77% of wells turned to production in 3Q17 were multi-zone pattern wells completed in batches

†

Excludes 2 Wolfcamp BC wells

†† Excludes 10 Northern Midland Basin Spraberry interval wells due to timing of first production or disposal-related choke

management

Delaware Basin Gen 3 Wolfcamp A/B Wells

50 100 150 200 250 300 350 400 450 500 550 600 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450

Cumulative Pr

• duc tion (MBOE

) Da ys

• Production and type curves normalized to 10,000’
• Production normalized for operational downtime
• Day 0 = first oil
• ≈21% average cumulative production uplift over 1.75 mmboe EUR type curve at 340 days for 14 Wolfcamp

A and 13 Wolfcamp B wells; 15 of 27 are multi-zone pattern wells completed in batches

• ≈8% average cumulative production uplift over 2.0 mmboe EUR type curve

# We lls: 27 23 20 18 17 11 4 3 3 1 1 1

10

North Midland Basin Gen 3 Spraberry Pattern Wells

# We lls: 18 16 12 11 7 6 1

25 50 75 100 125 150 175 200 225 30 60 90 120 150 180 210 240

Cumulative Pr

• duc tion (MBOE

) Da ys

• Production and type curves normalized to 10,000’
• Production normalized for operational downtime
• Day 0 = first oil
• ≈40% average cumulative production uplift over 1.2 mmboe EUR type curve at 175 days for 5 Middle

Spraberry, 4 Jo Mill, and 9 Lower Spraberry; 16 of 18 are multi-zone pattern wells completed in batches

• ≈15% average cumulative production uplift over 1.4 mmboe EUR type curve

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North Midland Basin Gen 3 Wolfcamp A/B Pattern Wells

# We lls: 17 15 13 10 9 9 2 2 1

25 50 75 100 125 150 175 200 225 250 275 300 30 60 90 120 150 180 210 240 270 300 330 360

Cumulative Pr

• duc tion (MBOE

) Da ys

• Production and type curves normalized to 10,000’
• Production normalized for operational downtime
• Day 0 = first oil
• ≈6% average cumulative production uplift over 1.2 mmboe EUR type curve at 250 days for 6 Wolfcamp

A and 11 Wolfcamp B wells; 13 of 17 are multi-zone pattern wells completed in batches

• Average cumulative production uplift approximates 1.3 mmboe EUR type curve

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Central Midland Basin Gen 3 Wolfcamp A/B Pattern Wells

25 50 75 100 125 150 175 200 225 250 30 60 90 120 150 180 210 240 270 300 330

Cumulative Pr

• duc tion (MBOE

) Da ys

• Production and type curves normalized to 10,000’
• Production normalized for operational downtime
• Day 0 = first oil
• ≈11% average cumulative production uplift over 1.2 mmboe EUR type curve at 250 days for 7 Wolfcamp

A and 9 Wolfcamp B wells; all 16 are multi-zone pattern wells completed in batches

• ≈3% average cumulative production uplift over 1.3 mmboe EUR type curve

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# We lls: 16 16 16 16 16 10 7 7 6 1

Central Midland Basin Gen 3 Lower Spraberry Pattern Wells

25 50 75 100 125 150 175 200 30 60 90 120 150 180 210 240 270 300 330

Cumulative Pr

• duc tion (MBOE

) Da ys

• Production and type curves normalized to 10,000’
• Production normalized for operational downtime
• Day 0 = first oil
• ≈45% average cumulative production uplift over 850 mboe EUR type curve for northern Midland Basin

Lower Spraberry wells at 240 days for 2 Lower Spraberry wells; both are multi-zone pattern wells completed in batches

• ≈23% average cumulative production uplift over 1.0 mmboe EUR type curve for northern

Midland Basin Lower Spraberry wells

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# We lls: 2 2 2 2 2 2 2 2 1

10 20 30 40 50 60 6 12 18 24 30 36 Avg Cumulative Production (Mboe) Months 10 20 30 40 50 60 6 12 18 24 30 36 Avg Cumulative Production (Mboe) Months

Midland Gen 3 Pattern Wells Completed in Batches at Original Reservoir Pressure Outperforming Offset Pattern Wells

• f Peers and All Operators

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Data Sources: IHS and internal Company data as of September 30, 2017. Data from wells that was non-allocated, incomplete or from laterals less than 3,000 feet were excluded. Note: Production data normalized to 1,000 feet. Basin Pattern analysis based on available public survey information or permitted BHL indicating a minimum of 4 wells per zone per section with a maximum of 1,000 feet between wells. Offset patterns are defined as those patterns where offset wells first reported production at least six months after the initial well. 1 Peers include: CPE, CXO, FANG, LPI, PE, PXD and RSPP 2 Operators include: APA, CPE, CVX, CXO, FANG, ECA, EPE, EQT, LPI, OXY, PE, PXD, QEP, RSPP, Sable Permian Resources, SM, WTI, XOM and 16 additional private companies reporting in Martin, Midland, Howard, Glasscock, Reagan, Upton, and Andrews counties.

• In combination with its Gen 3 frac design, Energen’s practice of completing multi-zone pattern wells at original reservoir pressure has shown

notable outperformance compared to drilling primarily offset pattern wells, i.e., drilling stand-alone wells first then returning to drill offset wells at a later time.

• When a stand-alone well is drilled, the resulting pressure drop reduces productivity from subsequent offset wells.

E GN Ge n 3 Patte r n We lls vs Pe e r s’ Patte r n We lls E GN Ge n 3 Patte r n We lls vs All Ope r ator s’ Patte r n We lls

Energen Avg Peer Avg1 Each Peer’s Avg Energen Avg Operator Avg2 Each Operator’s Avg

% of Pattern Wells Completed in Batches at Original Reservoir Pressure: EGN: 100% Peers: 15% % of Pattern Wells Completed in Batches at Original Reservoir Pressure: EGN: 100% Operators: 25%

10 20 30 40 50 60 6 12 18 24 30 36 Avg Cumulative Production (Mboe) Months 10 20 30 40 50 60 6 12 18 24 30 36 Avg Cumulative Production (Mboe) Months

Midland Gen 3 Wells Performing At or Above Those of Peers and All Operators with Proppant Loads of 1,700-2,500 lbs/ft

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Data Sources: IHS and internal Company data as of September 30, 2017. Data from wells that was non-allocated, incomplete or from laterals less than 3,000 feet were excluded. Note: Production data from EGN and peer wells defined by proppant loads ranging 1,700 lbs/ft to 2,500 lbs/ft. Production data normalized to 1,000 feet. Basin Pattern analysis based on available public survey information or permitted BHL indicating a minimum of 4 wells per zone per section with a maximum of 1,000 ft. between wells. 1 Peers include: CPE, CXO, FANG, LPI, PE, PXD and RSPP 2 Operators include: APA, CPE, CVX, CXO, FANG, ECA, EPE, EQT, LPI, OXY, PE, PXD, QEP, RSPP, Sable Permian Resources, SM, WTI, XOM and 16 additional private companies reporting in Martin, Midland, Howard, Glasscock, Reagan, Upton, and Andrews counties.

• Energen’s performance versus Permian peers and all operators is even more notable given Energen’s focus on multi-zone pattern wells

completed in batches at original reservoir pressure as opposed to stand-alone wells.

E GN Ge n 3 We lls vs Pe e r We lls (w/ similar pr

• ppant loads)

E GN Ge n 3 We lls vs All Ope r ator We lls (w/ similar pr

• ppant loads)

Energen Avg Peer Avg1 Each Peer’s Avg Energen Avg Operator Avg2 Each Operator’s Avg

% Pattern Wells: EGN: 82% Peers: 47% % Pattern Wells: EGN: 82% Operators: 43%

10 20 30 40 50 60 6 12 18 24 30 36 Avg Cumulative Production (Mboe) Months 10 20 30 40 50 60 6 12 18 24 30 36 Avg Cumulative Production (Mboe) Months

Midland Gen 3 Pattern Wells Outperforming Those of Peers and All Operators with Proppant Loads of 1,700-2,500 lbs/ft

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Data Sources: IHS and internal Company data as of September 30, 2017. Data from wells that was non-allocated, incomplete or from laterals less than 3,000 feet were excluded. Note: Production data from EGN and peer wells defined by proppant loads ranging 1,700 lbs/ft to 2,500 lbs/ft. Production data normalized to 1,000 feet. Basin Pattern analysis based on available public survey information or permitted BHL indicating a minimum of 4 wells per zone per section with a maximum of 1,000 ft. between wells. 1 Peers include: CPE, CXO, FANG, LPI, PE, PXD and RSPP 2 Operators include: APA, CPE, CVX, CXO, FANG, ECA, EPE, EQT, LPI, OXY, PE, PXD, QEP, RSPP, Sable Permian Resources, SM, WTI, XOM and 16 additional private companies reporting in Martin, Midland, Howard, Glasscock, Reagan, Upton, and Andrews counties.

• Energen believes multi-zone pattern wells should be completed in batches at the original reservoir pressure.
• Energen’s performance versus peers and all operators is even more notable given Energen’s focus on multi-zone patterns rather than

single-zone patterns.

E GN Ge n 3 Pa tte rn We lls vs Pe e r Pa tte rn We lls (w/ simila r proppa nt loa ds) E GN Pa tte rn We lls vs All Ope ra tor Pa tte rn We lls (w/ simila r proppa nt loa ds)

Energen Avg Peer Avg1 Each Peer’s Avg Energen Avg Operator Avg2 Each Operator’s Avg

10 20 30 40 50 60 6 12 18 24 30 36 Avg Cumulative Production (MBOE) Months 10 20 30 40 50 60 6 12 18 24 30 36 Avg Cumulative Production (MBOE) Months

Delaware Gen 3 Wells Outperforming Those of Peers and All Operators with Proppant Loads of 1,700-2,500 lbs/ft

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• Energen’s performance versus Permian peers and all operators is even more notable given Energen’s focus on multi-zone pattern wells

completed in batches at original reservoir pressure as opposed to primarily stand-alone wells.

E GN Ge n 3 We lls vs Pe e r We lls (w/ simila r pr

• ppa nt loa ds)

E GN Ge n 3 We lls vs All Ope r a tor We lls (w/ simila r pr

• ppa nt loa ds)

Energen Avg Peer Avg1 Each Peer’s Avg Energen Avg Operator Avg2 Each Operator’s Avg

Data Sources: IHS and internal Company data as of September 30, 2017. Data from wells that was non-allocated, incomplete or from laterals less than 3,000 feet was excluded. Note: Production data from EGN and peer wells defined by proppant loads ranging 1,700 lbs/ft to 2,500 lbs/ft. Production data normalized to 1,000 feet. Basin Pattern analysis based on available public survey information or permitted BHL indicating a minimum of 4 wells per zone per section with a maximum of 1,000 ft. between wells. 1 Peers include: CPE, CXO, FANG, LPI, PE, PXD and RSPP 2 Operators include: APC, APA, CRZO, CDEV, XEC, CXO, FANG, EOG, JAG, MTDR, NBL, OXY, PE, Patriot Resources, PDCE, RDS.A, REN, RSPP, WPX and 13 additional private companies reporting in Ward, Winkler, Loving, Reeves, and Pecos counties % Pattern Wells: EGN: 43% Peers: 14% % Pattern Wells: EGN: 43% Operators: 12%

$490 $405 $5 2017e Ca pita l by Ba sin ($850- 900mm)

Midland Basin Delaware Basin Central Basin/ARO

2017e Drilling & Development Capital Unchanged

82% 5% 13% 2017e Ca pita l Bre a kdown ($850- 900mm)

Operated Drilling & Development Non-Operated/Other Facilities

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2017 Drilling Program Targets 106 Net Completions

2017 Operated Horizontal Program Gross/Net Wells

• Avg. Completed

Lateral Length Average WI Midland Basin YE16 DUC Completions 44/43 9,600’ 98% New Drills 55/47 New Drill Completions 35/29 8,300’ 82% YE17 DUCs 20/19 Delaware Basin YE16 DUC Completions 17/17 9,000’ 98% New Drills 32/31 New Drill Completions 17/17 8,200’ 100% YE17 DUCs 15/14

20

• Energen also plans to drill and complete 3 gross/3 net vertical wells in the Midland Basin.

Hedge Position – 4Q17

Hedge Volumes

• Avg. NYMEX Price

Oil Swaps 2.0 mmbo $ 50.68 per barrel Oil 3-way Collars¹ 1.2 mmbo Call Price $ 62.18 per barrel Put Price $ 45.00 per barrel Short Put Price $ 35.00 per barrel

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.

• Energen also has hedged the Midland to Cushing differential on approximately 3.0 mmbo (approximately 68

percent) of its sweet oil production for the last three months of 2017 at an average price of $ (0.68). Commodity Hedge Volumes % Hedged

• Avg. NYMEXe Price

NGL 20.8 mm gallons 36% $ 0.57 per gallon Gas 4.4 bcf 47% $ 3.36 per mcf

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• In last three months of 2017, approximately 64% of estimated oil production hedged

2018 - 2019 Hedges

Hedge Volumes

• Avg. NYMEX

Price Oil 3-way Collars¹ 13.5 mmbo Call Price $ 60.04/bbl Put Price $ 45.47/bbl Short Put Price $ 35.47/bbl Commodity Hedge Volumes

• Avg. NYMEXe

Price NGL 105.8 mm gal $ 0.59/gal Natural gas 3.6 bcf $ 3.19/mcf

22

• Energen also has hedged the Midland to Cushing

differential on 10.8 mmbo of its estimated 2018 sweet

• il production at an average price of $(1.01).

2018 2019

• Energen also has hedged the Midland to Cushing

differential on 1.4 mmbo of its estimated 2019 sweet

• il production at an average price of $(0.53).

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. Hedge Volumes

• Avg. NYMEX

Price Oil 3-way Collars¹ 1.4 mmbo Call Price $ 58.61/bbl Put Price $ 45.00/bbl Short Put Price $ 35.00/bbl

Key Expenses in 2017 Revised Downward

Per BOE, except as noted 4Q17e 2017e Prior 2017e LOE (production costs, marketing & transportation) $6.55 - $6.85 $6.70 - $7.00 $7.05 - $7.45 Production & ad valorem taxes (% of revenues, ex. hedges) 6.2% 6.4% 6.5% DD&A expense* $16.05 - $16.55 $17.70 - $18.10 $17.45 - $17.85 Salaries and general & administrative expenses $2.70 - $3.00 $3.00 - $3.30 $3.00 - $3.40 Exploration expense (seismic, delay rentals, etc.) $0.15 - $0.25 $0.25 - $0.35 $0.25 - $0.35 Interest expense ($mm) $9.5 - $10.5 $38.0 - $39.0 $38.5-$39.5 Effective tax rate (%) 36% - 38% 37% - 39% 37% - 39% CY17e LOE by Basin ($ per BOE):

• Delaware Basin

$4.95-$5.25

• Midland Basin

$5.50-$5.80

• Central Basin Platform/Other

$18.20-$18.50

* DD&A expense does not reflect potential 4Q17 look-back adjustment

CY17e Salaries and G&A ($ per BOE):

• Total

$3.00-$3.30

• Cash and other

$2.55-$2.65

• Non-cash equity-based comp

$0.45-$0.65

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2017e Capitalization ($mm)

Net debt at YE16 $ 165 Plus: Total Capital Expenditures* $ 1,115 – 1,165 Less: After-tax Cash Flows (includes working capital adjustment) $ 562 Net Debt at YE17 $ 718 – 768 Net Debt/EBITDAX at YE17† 1.2x - 1.3x Cash at YE17 $

• Amount outstanding on revolver at YE17

$ 190 – 240 Notes at YE17 $ 528 Undrawn line of credit $ 810 - 860

Energen Maintains Strong Balance Sheet

2017 2018 2019 2020 2021 2022 2023+

$400 $20 $110

Maturity Schedule of Notes

† EBITDAX reflects hedges, known commodity prices, and assumed prices for unhedged volumes for the last three months of the year of approximately $51.46/barrel, $0.76/gallon, and $2.93 per Mcf (November-December). * Includes $265 mm for leasehold, mineral acquisitions, and miscellaneous costs incurred in first nine months of 2017

Corporate Debt Ratings Moody’s: Ba3-Stable S&P: BB-Stable

24

Identified Inventory:

4,116 Net Locations on 147,428 Net Acres

† Potential drilling locations as of 7/1/2017; 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.

Dawson: 15 Howard: 253 Martin: 874 Midland: 302 Glasscock: 913 Reagan: 231 (Crockett: 17) Upton: 25 EGN Acres w/ Identified Horizontal Locations (YTD acquisitions, trades, increased WI shown in blue) Potential acreage addition of ≈10,000 net acres 25

• Midland Basin (WC, SPB, Cline ):

2,629 Ne t L

• c ations† on 87,230 ne t ac r

e s

EGN Acres w/ Identified Horizontal Locations (YTD acquisitions, trades, increased WI shown in blue)

New Mexico Texas

Loving: 510 Winkler: 17 Ward: 297 Reeves: 534 Lea: 128

• De lawar

e Basin (WC, BS, Avalon, BC): 1,487 Ne t L

• c ations † on 60,198 ne t ac r

e s

Working to Enhance Shareholder Value

• Gen 3 wells continue to outperform type curves and
• ther operators’ wells
• High quality, oil focused assets in Delaware and Midland

basins

• 4,116 net locations identified in key Permian Basin

trends

• Top-tier asset base
• Financial strength and flexibility
• $850-$900 million capital investment estimated for

drilling and completion activities in 2017

• 34% estimated YOY production growth in 2017
• Midland and Delaware basin YOY production growth

estimated to increase 43% in 2017

• 4Q17e exit rate 60% higher than 4Q16 exit rate

26

Appendix

27

EGN Frac Design Evolution

Midland Basin

Ge ne ra tio n 1

(2013-2015)

• 1,250-1,400 lbs./ft proppant
• 250’-300’ stage spacing
• 30-40 bbls/ft fluid
• 65’-75’ cluster spacing

Ge ne ra tio n 2

(2016)

• 1,600-1,700 lbs./ft proppant
• 200’-225’ stage spacing
• 40-42 bbls/ft fluid
• 50’-55’ cluster spacing

Ge ne ra tio n 3

(2017)

• 1,700-2,000 lbs./ft proppant
• 150’ stage spacing
• 40-45 bbls/ft fluid
• 30’ cluster spacing

De lawar e Basin

Ge ne ra tio n 1

(2012-2014)

• 1,000 lbs./ft proppant
• 240’ stage spacing
• 39 bbls/ft fluid
• 50’ cluster spacing

Ge ne ra tio n 2

(2015)

• 1,330 lbs./ft proppant
• 260’ stage spacing
• 39 bbls/ft fluid
• 65’ cluster spacing

Ge ne ra tio n 3

(2016-2017)

• 1,800-2,400 lbs./ft proppant
• 200’ stage spacing
• 40 bbls/ft fluid
• 33’ cluster spacing

28

Premium Permian Basin Acreage

Platform (117,574 gross acres/83,885 net acres) Midland Basin (118,727 gross acres/94,037 net acres) Delaware Basin (91,071 gross acres/61,690 net acres)

29

Energen’s Permian Footprint (7/1/2017)

Identified Net Potential @ 7.1.17

Midland Basin: >1.3 Billion BOE

Midland Basin

• 37% of identified locations (1,409 gross/1,061 net) have lateral lengths of 6,700’ & 7,500’; average WI is 75%
• 22% of identified locations (795 gross/629 net) have lateral lengths of 10,000’; average WI is 79%

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; net of royalty interest of ≈25%.

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334’ 491’ 388’ 185’ 266’ 613’ 637’ 201’ 387’

• L. Spraberry Shale

Dean Wolfcamp A Wolfcamp B Penn Shale Cline Wolfcamp C

• M. Spraberry

Jo Mill

Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations1 (Gross/Net) Type Curve EUR Range2 (Gross MBOE) Remaining Horizontal Undeveloped Resource3 (Net MMBOE) 14 41,155 272/172 100 – 140 83 8 41,212 276/177 100 – 140 86 39 70,041 826/512 70 – 140 273 99 72,148 691/429 110 – 130 245 101 69,842 651/400 110 – 130 227 4 38,484 507/330 80 – 105 146 2 66,002 940/609 60 – 85 253 267 4,163/2,629 1,313

Identified Net Potential @ 7.1.17

North Midland Basin: 699 MMBOE

• L. Spraberry Shale

Dean

Wolfcamp A Wolfcamp B

Penn Shale

Cline

• M. Spraberry

Jo Mill

• 38% of identified locations (609 gross/539 net) have lateral lengths of 6,700’ & 7,500’; average WI is 89%
• 17% of identified locations (324 gross/243 net) have lateral lengths of 10,000’; average WI is 75%

Midland, Mar tin, Dawson & Howar d Countie s

Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations1 (Gross/Net) Type Curve EUR Range2

(Gross MBOE/1,000’)

Remaining Horizontal Undeveloped Resource3 (Net MMBOE) 14 40,978 272/172 100 – 140 83 8 40,954 276/177 100 – 140 86 33 40,998 536/336 100 – 140 187 23 36,558 339/214 110 – 130 113 29 35,591 363/230 110 – 130 121 1 32,102 480/314 60 – 70 109 108 2,266/1,442 699 31

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; net of royalty interest of ≈25%.

249’ 387’ 405’ 252’ 243’ 317’ 374’ 439’

Identified Net Potential @ 7.1.17

Central Midland Basin: 614 MMBOE

• 36% of identified locations (800 gross/522 net) have lateral lengths of 6,700’ & 7,500’; average WI is 65%
• 27% of identified locations (471 gross/385 net) have lateral lengths of 10,000’; average WI is 82%

Glassc oc k, Upton & Re agan Countie s

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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; net of royalty interest of ≈25%.

334’ 491’ 388’ 185’ 266’ 613’ 637’ 201’ 387’

• L. Spraberry Shale

Dean Wolfcamp A Wolfcamp B Penn Shale Cline Wolfcamp C

• M. Spraberry

Jo Mill

Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations1 (Gross/Net) Type Curve EUR Range2 (Gross MBOE) Remaining Horizontal Undeveloped Resource3 (Net MMBOE) 6 29,042 290/177 70 – 100 86 76 35,590 352/215 110 – 130 131 72 34,250 288/170 110 – 130 107 4 36,564 507/330 80 – 105 146 1 33,899 460/296 60 – 85 144 159 1,897/1,187 614

Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations1 (Gross/Net) Type Curve EUR Range2

(Gross MBOE/1000’)

Remaining Horizontal Undeveloped Resource3 (Net MMBOE) 17 38,641 353/213 150 – 200 231 19 38,457 362/227 150 – 200 244 5 33,544 350/221 150 – 200 184 33,544 354/225 150 – 200 188 41 1,419/886 847

• 24% of Wolfcamp locations (344 gross/254 net) have average lateral lengths of approximately 7,500’; average WI is 74%
• 28% of Wolfcamp locations (523 gross/304 net) have lateral lengths of ≥10,000’; average WI is 58%
• 20% of locations (237 gross/212 net) have laterals lengths of ≥10,000’; average WI is 89%

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Identified Net Potential @ 7.1.17

Delaware Wolfcamp Shale: 970 MMBOE

* Reflects New Mexico and Texas (other Eastern zones are Texas only) 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; net of royalty interest of ≈25%.

Wolfcamp Upper A Wolfcamp B Wolfcamp C Wolfcamp A Wolfcamp BC

Ce ntr al

278’ 316’ 250’ 325’ 159’

Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Net Locations1 (Gross/Net) Type Curve EUR Range2

(Gross MBOE/1000’)

Remaining Horizontal Undeveloped Resource3 (Net MMBOE) 3 15,765 238/96 110 – 130 59 2 7,133 65/27 110 – 130 17 6,431 64/32 110 – 130 23 6,431 64/32 110 – 130 23 5 431/188 123

Wolfcamp Upper A Wolfcamp B Wolfcamp C Wolfcamp A* Wolfcamp BC

E aste r n

278’ 316’ 250’ 325’ 159’

3rd Bone Spring/WC XY Sand

3rd Bone Spring Shale 2nd Bone Spring Sand 2nd Bone Spring Shale 1st Bone Spring Sand Avalon Lwr Brushy Canyon

Net Operated Wells Drilled to Date Net Acreage Inventory: Engineered Locations1 (Gross/Net) Type Curve EUR Range2

(Gross MBOE/1000’)

Remaining Horizontal Undeveloped Resource3 (Net MMBOE) 31,772 72/22 80 - 120 12 5,349 107/31 80 - 120 17 38,912 27/8 80 - 120 4 2 47,212 111/39 80 - 120 18 45,912 305/238 90 - 130 118 118 56,693 143/74 90 - 130 33 120 765/413 203

• 18% of other plays locations (100 gross/74 net) have average lateral lengths of approximately 7,500’; average WI is 74%
• 25% of other plays locations (168 gross/105 net) have lateral lengths of ≥10,000’; average WI is 63%
• 20% of locations (90 gross/82 net) have laterals lengths of ≥10,000’; average WI is 91%

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Identified Net Potential @ 7.1.17

Delaware “Other” Plays: 203 MMBOE

795’ 257’ 316’ 442’ 609’ 294’ 226’ 106’

Othe r Plays

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; net of royalty interest of ≈25%.

Bone Spring

* 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

Inventory Spacing: Northern Midland Basin

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249’ 387’ 405’ 252’ 243’ 317’ 374’ 439’

Inventory Spacing per 640-acre Section*

De an Wolfc amp A Wolfc amp B

4 4 8 6 6 8

1 Mile

249’ 387’ 405’ 252’ 243’ 317’ 374’ 439’

NOTE: Additional horizontal potential from other intervals such as Clearfork, Middle Spraberry, Jo Mill

36

* Subject to change based on continued testing and analysis of spacing and frac designs Inventory Spacing per 640-acre Section* 6 6-8 8 6-8 8

185’ 266’ 613’ 637’ 201’ 387’ 388’

1 Mile

Inventory Spacing: Central Midland Basin

37

Inventory Spacing per 640-acre Section* * Subject to change based on continued testing and analysis of spacing and frac designs 6 6 6 6

417’ 364’ 344’ 400’

Wolfc a mp BC

1 Mile

Inventory Spacing: Delaware Basin WC Shale

Inventory Spacing: Delaware Basin “Other”

38

Inventory Spacing per 640-acre Section* * Subject to change based on continued testing and analysis of spacing and frac designs

3r

d Bone Spr

ing Shale

795’ 257’ 316’ 442’ 609’ 294’ 159’ 106’ 226’

6 4 4 6 4 4

1 Mile

Non-GAAP Financial Measures

• Per unit LOE excluding the Central Basin Platform is a Non-GAAP financial measure (GAAP refers to generally accepted accounting

principles). This information is useful in comparing the company and other oil and gas producing companies operating primarily in the Midland and Delaware basins. 39 NOTE: Amounts may not sum due to rounding

Re c onc iliation of 2015 GAAP to L OE E xc luding Ce ntr al Basin Platfor m

$mm Production (mboe) $/boe

LOE (GAAP)

$ 228,380 24,022 $9.51

Less: LOE associated with Central Basin Platform

$ 64,361 3,548 $18.14

LOE (Non-GAAP)

$ 164,019 20,474 $8.01

Re c onc iliation of 2016 GAAP to L OE E xc luding Ce ntr al Basin Platfor m

$mm Production (mboe) $/boe LOE (GAAP) $ 171,714 21,639 $7.94 Less: LOE associated with Central Basin Platform $ 52,526 3,176 $16.54 LOE (Non-GAAP) $ 119,188 18,463 $6.46

Non-GAAP Financial Measures

• Per unit SG&A including capitalized costs is a Non-GAAP financial measure (GAAP refers to generally accepted accounting

principles). This information is useful in comparing the company with other oil and gas producing companies in the Midland and Delaware basins that capitalize certain internal SG&A costs. 40 NOTE: Amounts may not sum due to rounding

Re c onc iliation of 2015 GAAP to SG&A Inc luding Capitalize d Costs

$mm Production (mboe) $/boe

SG&A (GAAP)

$ 149,132 24,022 $6.21

Add: Capitalized SG&A costs

$ 3,868

Adjusted SG&A (Non-GAAP)

$ 153,000 24,022 $6.37

Re c onc iliation of 2016 GAAP to SG&A Inc luding Capitalize d Costs

$mm Production (mboe) $/boe SG&A (GAAP)

$ 95,689 21,639 $4.42

Add: Capitalized SG&A costs

$ 2,167

Adjusted SG&A (Non-GAAP)

$ 97,856 21,639 $4.52

For More Information

Julie S. Ryland Vice President – Investor Relations 205-326-8421 jryland@energen.com www.energen.com

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