strong execution driving growth and value
TRANSCRIPT
S C O T I A H O W A R D W E I L 2 0 1 8 E N E R G Y C O N F E R E N C E
Strong Execution DrivingGrowth and Value
Monday, March 26, 2018, New Orleans
Forward-looking andCautionary 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.
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Execution Continues to Deliver Superior Results
3
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
Focus on Value Creation
4
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-$1.8B in 2020 3-year EBITDAX CAGR estimated at approximately 35% Balance sheet ensures capital flexibility as net debt to EBITDAX estimated to remain
within 1.0x-1.5x each year
Three-year outlook reflects commitment to bringing forward NAV of high quality assets
while maintaining strong balance sheet
3Q17a 4Q17 Guidance 4Q17a
7.9 7.8 8.2
44.8 45.4 51.7
28.7 32.437.4
Central Basin/Other Midland Basin Delaware Basin
3Q17a 4Q17 Guidance 4Q17a
16.6 16.8 20.0
15.7 14.919.4
49.0 54.058.1
Gas NGL Oil
Another Production Beat in 4Q17
By Basin (mboepd) By Commodity (mboepd)
5
85.7
97.485.7
Total production up 14% over guidance and 20% over prior quarter Midland and Delaware Basin production each up approximately 14% over guidance Oil production up 8% over guidance and 19% sequentially
97.4
Note: Totals may not sum due to rounding
81.3 81.3
2017 Production Grows 39%
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Total 2017 production: 76.1 mboepd Delaware Basin production grows approximately 150% YOY in 2017 Midland Basin production exceeds 42 mboepd in 2017
2012 2013 2014 2015 2016 2017
13.2 12.3 11.1 9.9 9.0 8.1
9.7 13.9 20.331.6 35.3 42.47.9
11.613.3
12.1 10.3
25.6
Central Basin/Other Midland Basin Delaware Basin
54.6
30.837.8
44.7
53.6
76.1
Growth rate (5-year CAGR): 20% total production 34% Midland Basin 27% Delaware Basin 31% Midland & Delaware (9%) CBP/Other
Production (mboepd)
Note: All years exclude asset sales
4Q17 Expenses Beat Guidance Midpoints
LOE ($/boe)
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SG&A/boe down 9% from guidance SG&A/boe down 39% from 4Q16
LOE/boe down 10% from guidance LOE/boe down 23% from 4Q16
4Q16a 4Q17 GuidanceMdpt
4Q17a
$4.25
$2.85 $2.58
4Q16a 4Q17 GuidanceMdpt
4Q17a
$7.85
$6.70$6.02
* Per-unit LOE for Midland/Delaware basins totaled $4.94/boeNote: 4Q16a excludes asset sales
Net SG&A ($/boe)
($4.94*)
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2016 2017
$6.23
$5.28
Focus on Cost Reductions, Operating Efficiencies Drive Decline in YOY Expenses
Net SG&A ($/boe)
2016 2017
$4.32
$3.05
Midland/Delaware LOE ($/boe)
Note: 2016 excludes asset sales
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 YE17 1.20
Cash at YE17 $ --
Amount outstanding on revolver at YE17 $ 255
Notes at YE17 $ 528
Undrawn borrowing base $ 795
2017 2018 2019 2020 2021 2022 2023+
$400
$20
$110
Maturity Schedule of Notes
* Includes $287 mm for leasehold, mineral acquisitions, and miscellaneous costs incurred during 2017
Corporate Debt Ratings
Moody’s: Ba3-StableS&P: BB-Stable
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CY17 Ends with Strong Balance Sheet
Reserve additions replaced production by 415% 2017 proved developed F&D cost totaled $8.38 per boe1
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
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Proved Reservesby Basin YE16 Production Acq/(Div) Additions Price
RevisionsOther
Revisions YE17
Midland Basin 236.4 15.5 0.0 49.0 7.0 16.9 293.8Delaware Basin 39.1 9.4 0.2 66.3 0.9 10.9 108.1Platform/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 200Natural gas liquids 91 58Natural gas 96 58
TOTAL 444 316
Basin Proved Probable Possible Contingent Resources Total
Midland Basin 294 154 130 979 1,557Delaware Basin 108 40 46 1,243 1,437Platform/Other 42 0 0 1 43
TOTAL 444 194 176 2,223 3,037NOTE: Totals may not sum due to rounding
YE17 Proved Reserves Increase >40%
(mmboe)
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.
Identified Inventory 4,023 Net Locations on 148,987 Net Acres
† Potential drilling locations as of 12/31/2017; engineered based on company’s acreage and spacing plans and may change materially overtime as the company and offset operators gain additional data in each zone; actual lateral lengths may vary depending on various factorsincluding lease geometry, relationship with offset operators, allowed spacing, reservoir characteristics, and other relevant criteria.
Dawson: 15
Howard: 229Martin: 805
Midland: 292 Glasscock: 868
Reagan: 195(Crockett: 5)Upton: 23
EGN Acres w/ Identified Horizontal Locations (YTD acquisitions, trades, increased WI shown in blue)Potential acreage addition of ≈10,000 net acres
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Midland Basin (WC, SPB, Cline): 2,431 Net Locations† on 88,298 net acres
EGN Acres w/ Identified Horizontal Locations (YTD acquisitions, trades, increased WI shown in blue)
New MexicoTexas
Loving: 545Winkler:
35
Ward: 338
Reeves: 540
Lea: 135
Delaware Basin (WC, BS, Avalon, BC): 1,592 Net Locations † on 60,689 net acres
25 Wells Turned to Production in 4Q17
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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 5 Wolfcamp A (4)3rd BS Sand (1) 6,297’ 2,529 402 74 1,716 272 73
N. Midland Basin 4 Wolfcamp A (2)Wolfcamp B (2) 7,548‘ 1,469 195 90 1,020 135 84
N. Midland Basin 5 Lower Spraberry 7,451‘ 1,779 239 93 1,425 191 90
N. Midland Basin * 9 Mid. Spraberry (5)Jo Mill (4) 7,964‘ 867 109 89 676 85 86
C. Midland Basin 2 Wolfcamp A 9,160‘ 1,766 193 91 1,159 126 82
Note: Excludes 2 test wells (one in Northern Midland Basin and one in Central Midland Basin) drilled in other formations
* 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
64% of wells turned to production in 4Q17 were multi-zone pattern wells completed in batches
2018 Delaware Basin ProgramType Curves, EURs Updated
0
50
100
150
200
250
300
350
400
450
500
550
600
0 30 60 90 120 150 180 210 240 270 300 330 360 390
Cum
ulat
ive
Prod
uctio
n (M
BOE)
Days
Prior Midpoint of Possible EURs Ryder Scott Composite Curve for 2018 Program Cessna 601H Avg Alameda Lease (6 Wells)Avg Goldfinger Lease (2 Wells) Avg New Mexico Well (1 WCA, 1 3rd Bone)2017 Gen 3 Wolfcamp A/B Avg (30 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
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.
# Wells: 30 29 27 26 19 19 17 16 9 3 2 2
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2018 NMB Wolfcamp A/B ProgramType Curves, EURs Updated
# Wells: 13 13 13 12 9 9 9 8 7
0
25
50
75
100
125
150
175
200
225
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275
300
325
350
0 30 60 90 120 150 180 210 240 270 300 330 360
Cum
ulat
ive
Prod
uctio
n (M
BOE)
Days
Prior Midpoint of Possible EURs Ryder Scott Composite Curve for 2018 ProgramGaskins 103H Avg Tiger Lease (4 Wells)2017 Gen 3 Avg Wolfcamp A/B (13 Wells)
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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 10,000’ 2017 Gen 3 avg. production (red line) includes operational downtime Individual well/lease production normalized for operational downtime Day 0 = first oil
0
25
50
75
100
125
150
175
200
225
250
275
300
0 30 60 90 120 150 180 210 240 270 300 330 360
Cum
ulat
ive
Prod
uctio
n (M
BOE)
Days
Prior Midpoint of Possible EURs Ryder Scott Composite Curve for 2018 ProgramAvg Tiger Lease (5 wells) 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
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.
2018 NMB Lower Spraberry ProgramType Curves, EURs Updated
# Wells: 9 7 7 4 4 4 4 4 4 115
2018 NMB Middle Spraberry/Jo Mill ProgramType Curves, EURs
0
25
50
75
100
125
150
175
200
225
250
275
0 30 60 90 120 150 180 210 240 270 300 330 360
Cum
ulat
ive
Prod
uctio
n (M
BOE)
Days
Prior Midpoint of Possible EURs Ryder Scott Composite Curve for 2018 ProgramGaskins 803H Adams 601HAvg Tiger Lease (5 Wells) 2017 Gen 3 Avg MSprb/Jo Mill (14 Wells)
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# Wells: 14 14 14 13 9 9 8 7 7 5 3
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% aremulti-zone pattern wells completed in batches.
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
2018 CMB Wolfcamp A/B ProgramType Curves, EURs Updated
0
25
50
75
100
125
150
175
200
225
250
275
300
0 30 60 90 120 150 180 210 240 270 300 330 360 390 420
Cum
ulat
ive
Prod
uctio
n (M
BOE)
Days
Prior Midpoint of Possible EURs Ryder Scott Composite Curve for 2018 ProgramAvg Pecos Lease (6 Wells) Avg Moore 11-2 Lease (2 Wells)2017 Gen 3 Avg Wolfcamp A/B (12 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
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# Wells: 12 10 10 10 10 10 10 10 9 4 3 3 1
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% aremulti-zone pattern wells completed in batches.
Attractive IRRs Support 2018 Program
0%20%40%60%80%
100%120%140%160%
$50 $60 $70NYMEX Oil $/bbl
-$1.0MM $8.3MM +$1.0MM
Gross EUR:1,650 mboe
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10,0
00’ L
ater
al
0%20%40%60%80%
100%120%
$50 $60 $70NYMEX Oil $/bbl
-$1.0MM $6.8MM +$1.0MM
Gross EUR:915 mboe
0%10%20%30%40%50%60%70%80%
$50 $60 $70NYMEX Oil $/bbl
-$1.0MM $6.9MM +$1.0MM
Gross EUR:975 mboe
IRR
IRR
IRR
DB Wolfcamp A/B
0%20%40%60%80%
100%120%140%160%
$50 $60 $70NYMEX Oil $/bbl
-$1.0MM $10.8MM +$1.0MM
Gross EUR:2,200 mboe
NMB 5-Zone Average
0%20%40%60%80%
100%120%140%
$50 $60 $70NYMEX Oil $/bbl
-$1.0MM $8.3MM +$1.0MM
Gross EUR:1,200 mboe
CMB Wolfcamp A/B
0%10%20%30%40%50%60%70%80%
$50 $60 $70NYMEX Oil $/bbl
-$1.0MM $8.5MM +$1.0MM
Gross EUR:1,300 mboe
IRR
IRR
IRR
EURs based on Ryder Scott composite curves for 2018 program Gas and NGL prices held constant at $3/MMBTU and 35% of WTI, respectively
7,50
0’ L
ater
al
Estimated 2018 DC&E Cost
81%
13%
6%
Capital Breakdown*
Operated Drilling & DevelopmentFacilitiesNon-Operated/Other
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2018 Drilling & Development Capital Estimated to Range from $1.1B - $1.3B
* Graphed at midpoint of capital guidance range
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
YOY Production Growth at Guidance Midpoint: ≈25% Annual production estimated to be 95.0 mboepd at midpoint
(range: 91.5-98.5 mboepd) Production estimated to range from 103.5-110.5 mboepd in 4Q Delaware Basin production estimated to grow 48% YOY
Note: 2018 capital plan assumes prices of $58/bbl WTI, $0.65/gal NGL (before T&F) and $2.75/mcf Henry Hub
50%
40%
10%
Capital by Area*
Delaware BasinNorth Midland BasinCentral Midland Basin
20
Production Estimated to Increase to103.5-110.5 MBOEPD in 4Q18
1Q18 2Q18 3Q18 4Q18
19.0 20.0 20.0 21.0
17.5 18.0 17.5 19.0
53.0 53.0 55.566.5
Production by Commodity*(mboepd)
Gas NGL Oil
107.0
93.091.089.5 2018 Operated Horizontal ProgramFirst Production/Flow Back (Gross/Net)
MidlandBasin
DelawareBasin
1Q18e 9/8 4/4
2Q18e 16/15 12/10
3Q18e 15/14 14/13
4Q18e 26/22 21/21
CY18e 66/58 51/48
* Guidance at midpoint
Note: Totals may not sum due to rounding
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2018e YOY Production Growth: ≈25%
2013 2014 2015 2016 2017 2018e
12.3 11.1 9.9 9.0 8.1 7.0
13.9 20.331.6 35.3 42.4 50.011.6
13.3
12.1 10.3
25.6
38.0
Platform/Other Midland Basin Delaware Basin
76.1
95.0
54.653.6
44.737.8
Production (mboepd)
Five-year total production CAGR: approximately 20% Delaware Basin estimated to grow 48% YOY in 2018 (at guidance midpoint)
Note: Guidance at midpoint; all years exclude asset sales
Per BOE, except as noted 2018e 2017LOE (production costs, marketing & transportation) $6.40 - $6.60 $6.61Production & ad valorem taxes (% of revenues, excluding hedges) 6.2% 6.0%DD&A expense $14.00 - $14.50 $17.23Salaries and general & administrative expenses $2.30 - $2.70 $3.05Exploration expense (seismic, delay rentals, etc.) $0.15 - $0.20 $0.29Interest expense ($mm) $46.5 - $51.5 $38.4Effective tax rate (%) 22%-24% 37%
CY18e Salaries and G&A, net ($ per BOE) Total $2.30 - $2.70 Cash $1.85 - $2.05 Non-cash equity-based comp $0.45 - $0.65
22
Attractive Per-Unit Expenses Expected in 2018
CY18e LOE per BOE by Basin: Midland Basin $5.05-$5.25 Delaware Basin $5.35-$5.55 Central Basin Platform/Other $21.55-$21.75
2018e Capitalization ($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 YE18† 1.1 – 1.3
Cash at YE18 $ --
Amount outstanding on revolver at YE18 $ 478 – 678
Notes at YE18 $ 528
Undrawn line of credit $ 372 - 572
Energen Maintains Strong Balance Sheet
2018 2019 2020 2021 2022 2023 2024+
$400
$20
$110
Maturity Schedule of Notes
Corporate Debt Ratings
Moody’s: Ba3-StableS&P: BB-Stable
23
† 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).
Strong financial position provides foundation for future growth and value creation
2018 - 2019 Hedges Help Minimize Risk
Hedge Volumes % Hedged 2 Avg. NYMEX
Price
Oil 3-way Collars¹ 13.5 mmbo 65%
Call Price $ 60.04/bbl
Put Price $ 45.47/bbl
Short Put Price $ 35.47/bbl
Oil Swaps 1.4 mmbo 7% $ 60.24/bbl
Commodity HedgeVolumes % Hedged 2 Avg. NYMEXe
Price
NGL 128.5 mm gal 46% $ 0.60/gal
Natural gas 9.0 bcf 20% $ 3.04/mcf
24
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).
2018 2019
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, Energenreceives 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 NYMEXprice 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
Commodity HedgeVolumes Avg. Price
NGL 55.4 mm gal $ 0.64/gal
HedgeVolumes
Avg. NYMEX Price
Oil 3-way Collars¹ 5.8 mmbo
Call Price $ 61.65/bbl
Put Price $ 45.94/bbl
Short Put Price $ 35.94/bbl
Oil Swaps 2.9 mmbo $ 56.52/bbl
Three-Year Outlook Drives Further Value
25
Outlook for 2018-2020 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
Balance Sheet
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
Production
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%
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
Providing Strong Platform for Value Creation as Permian Pure-Play
Solid execution leads to superior results in 2017
Continued execution in 2018-2020 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 2018
3-year production CAGR expected to exceed 28% per year
Strong balance sheet helps ensure capital flexibility
26
EGN Frac Design Evolution
Midland BasinGeneration 1
(2013-2015)• 1,250-1,400 lbs./ft proppant• 250’-300’ stage spacing• 30-40 bbls/ft fluid• 65’-75’ cluster spacing
Generation 2(2016)
• 1,600-1,700 lbs./ft proppant• 200’-225’ stage spacing• 40-42 bbls/ft fluid• 50’-55’ cluster spacing
Generation 3(2017-2018)
• 1,700-2,000 lbs./ft proppant• 150’ stage spacing• 40-45 bbls/ft fluid• 30’ cluster spacing
Delaware Basin
Generation 1(2012-2014)
• 1,000 lbs./ft proppant• 240’ stage spacing• 39 bbls/ft fluid• 50’ cluster spacing
Generation 2(2015)
• 1,330 lbs./ft proppant• 260’ stage spacing• 39 bbls/ft fluid• 65’ cluster spacing
Generation 3(2016-2018)
• 1,800-2,400 lbs./ft proppant• 200’ stage spacing• 40 bbls/ft fluid• 33’ cluster spacing
28
Premium Permian Basin Acreage
29
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
Identified Net Potential @ 12.31.17Midland Basin: >1.3 Billion BOE
MidlandBasin
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
334’
491’
388’
185’
266’
613’
637’
201’
387’
L. Spraberry Shale
DeanWolfcamp 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)
Remaining Horizontal Undeveloped Resource2
(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
4 39,332 486/295 158
4 66,215 903/559 235
289 4,040/2,431 1,321
Identified Net Potential @ 12.31.17North Midland Basin: 695 MMBOE
L. Spraberry Shale
Dean
Wolfcamp A
Wolfcamp B
Penn Shale
Cline
M. Spraberry
Jo Mill
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%
Midland, Martin, Dawson& Howard Counties
Net Operated Wells Drilled to Date
Net Acreage
Inventory:Engineered Locations1
(Gross/Net)
Type CurveEUR per 1000’2
(Gross MBOE/MBO)
Remaining Horizontal Undeveloped Resource3
(Net MMBOE)
14 41,176 271/161 130/94 95
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
2 32,303 465/290 65/42 97
119 2,223/1,338 695
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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 and reviewed by Ryder Scott; net of royalty interest of ≈25%.
249’
387’
405’
252’
243’
317’
374’
439’
Identified Net Potential @ 12.31.17Central Midland Basin: 626 MMBOE
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%
Glasscock, Upton & Reagan Counties
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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 and reviewed by Ryder Scott; net of royalty interest of ≈25%.
334’
491’
388’
185’
266’
613’
637’
201’
387’
L. Spraberry Shale
DeanWolfcamp 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 CurveEUR per 1000’2
(Gross MBOE/MBO)
Remaining Horizontal Undeveloped Resource3
(Net MMBOE)
6 29,150 290/176 105/85 98
82 36,208 329/194 130/65 128
76 35,050 274/159 120/49 104
4 37,285 486/295 100/54 158
2 33,912 438/269 95/43 138
170 1,817/1,093 626
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%
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Identified Net Potential @ 12.31.17Delaware Wolfcamp Shale: >1.1 Billion BOE
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%.
Wolfcamp Upper A
Wolfcamp B
Wolfcamp C
Wolfcamp A
Wolfcamp BC
Texas
325’
250’
325’
425’
Net Operated WellsDrilled to Date
NetAcreage
Inventory:Engineered Locations1
(Gross/Net)
Type CurveEUR per 1000’2
(Gross MBOE/MBO)
Remaining Horizontal Undeveloped Resource3
(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 25357 1,796/1,057 1,095
Net Operated WellsDrilled to Date
NetAcreage
Inventory:Engineered Locations1
(Gross/Net)
Type CurveEUR per 1000’2
(Gross MBOE/MBO)
Remaining Horizontal Undeveloped Resource3
(Net MMBOE)
1 6,192 113/34 130/110 22Wolfcamp Upper AWolfcamp A
New Mexico
375’
3rd Bone Spring/WC XY Sand
3rd Bone Spring Shale
2nd Bone Spring Sand
2nd Bone Spring Shale1st Bone Spring Sand
Avalon
Lwr Brushy Canyon
Net Operated WellsDrilled to Date
NetAcreage
Inventory:Engineered Locations1
(Gross/Net)
Type CurveEUR per 1000’2
(Gross MBOE/MBO)
Remaining Horizontal Undeveloped Resource3
(Net MMBOE)32,396 82/26 110/90 13
5,395 121/31 100/55 15
40,004 35/12 100/80 5
2 48,094 122/41 100/80 19
51,515 413/310 110/80 162
120 57,314 163/80 100/80 36122 939/501 250
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Identified Net Potential @ 12.31.17Delaware “Other” Plays: 250 MMBOE
795’
257’
316’
442’
609’
294’
226’
106’
Other 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 and reviewed by Ryder Scott; net of royalty interest of ≈25%.
Bone Spring
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%
* 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
3524
9’38
7’40
5’25
2’24
3’31
7’37
4’43
9’
Inventory Spacing per 640-acre Section*
Dean
Wolfcamp A
Wolfcamp 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’
Wolfcamp 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
3rd Bone SpringShale
795’
257’
316’
442’
609’
294’
159’
106’
226’
6
4
4
6
4
4
1 Mile
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 thetiming 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.
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($ 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
For More Information
Julie S. RylandVice President – Investor Relations
www.energen.com
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