EX-99.1

Forward-Looking Statements

This

presentation

(including

associated

oral

commentary)

contains

statements

expressing

expectations

future

plans,

objectives,

and

performance

that

constitute

forward-looking

statements

made

pursuant

the

Safe

Harbor

Provision

the

Private

Securities

Litigation

Reform

Act

1995.

Unless

noted,

these

statements

not

reflect

possible

pending

acquisitions,

divestitures,

restructurings.

Statements

based

expectations

are

forward-looking

statements

that

are

dependent

certain

events,

risks,

and

uncertainties

that

could

cause

actual

results

differ

materially

from

those

anticipated. A discussion of risks and uncertainties may be found in the Company’s periodic reports filed with the Securities

and Exchange Commission (SEC).

You should not place undue reliance on any of the Company’s forward-looking statements. All forward-looking statements

speak

only

the

date

which

such

statements

are

made,

and

the

Company

undertakes

obligation

correct

update any forward-looking statement, whether as a result of new information, future events, or otherwise, except as

required by applicable law.

Oil & Gas Quantities: 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

not

constitute

such

reserves.

Outside

SEC

filings,

the

Company

uses

the

terms

“estimated

ultimate

recovery”

“EUR,”

reserve or resource “potential,”

and other descriptions of volumes of reserves potentially recoverable through additional

drilling or recovery techniques. These estimates are inherently more speculative than estimates of proved, probable, and

possible reserves and are subject to substantially greater risk of actually being realized by the Company.

EUR estimates, potential drilling locations, and resource potential estimates have not been risked by the Company. Actual

locations drilled and quantities that may be ultimately recovered from the Company’s interest may differ substantially from

the Company’s estimates. There is no commitment by the Company to drill all of the drilling locations that have been

attributed

these

quantities.

Factors

affecting

ultimate

recovery

include

the

scope

the

Company’s

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 approval, and actual drilling results,

as well as geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per-well EUR, and

resource potential may change significantly as development of the Company’s oil and gas assets provides additional data.

Energen Investment Highlights

Domestic asset base

High exposure to oil and NGL from 3P reserves

Large resource potential in Midland and Delaware basins

Permian Basin exploration

Permian Basin development

Double-digit oil and NGL production growth

Excellent hedges help protect cash flows

Strong balance sheet and financial capacity

Wolfcamp (horizontal)

Cline (horizontal)

Wolfberry (vertical)

3rd Bone Spring (horizontal)

Energen Profile

Other:

7 MMBOE (1%)

San Juan Basin:

339 MMBOE (46%)

Permian Basin:

389 MMBOE (53%)

Farmington

Arcadia

Birmingham

3P Reserves at YE12

by Area (excluding

BWB assets)

Midland

NOTE: All data is as of YE12, (unless otherwise noted); YE12 and YE13e data have been restated to exclude Black Warrior Basin assets

NYSE: EGN

Shares Outstanding (6.30.13)

72.2

Market Cap (9.5.13)

4.9

Adjusted EBITDA (Non-GAAP)

801.8

2013e Total Debt

1.8

Enterprise Value (9.5.13)

6.7

PV10 Pre-tax

4.4

2013e Debt-to-Total Cap

39%

Reserves at YE12 (excluding BWB assets):

Proved Reserves

330.2

MMBOE

Probable Reserves

113.9

MMBOE

Possible Reserves

290.9

MMBOE

Total 3P Reserves

735.0

MMBOE

% Oil & NGL

57%

Production from continuing operations:

2012

2013e

MMBOE

22.0

24.3-24.7

Double-Digit Liquids Production Growth

16.6

18.4

22.0

24.5

Liquids production expected to

double

from 2010 to 2013

Wolfberry, 3

Bone Spring drive

2013 production growth

(MMBOE)

(MMBOE

)

* Includes 0.1 MMBOE and 0.5 MMBOE in Midland and Delaware basins, respectively,

for Wolfcamp production

NOTE: Production from continuing operations

1.9

2.2

2.6

3.5

10.6

8.8

6.3

5.1

9.6

9.9

10.6

10.4

2010

2011

2012

2013e

Midpoint

Gas

Oil

NGL

Midland Basin*

Delaware

Basin*

Central Basin

San Juan Basin

Other

2011

2012

2013e Midpoint

2.3

3.5

5.4

0.6

2.9

4.9

4.8

4.3

9.6

9.9

9.3

1.0

0.9

0.6

2013e E&P Capital, Drilling Plans

Permian Basin

Wolfcamp

9 net wells

Wolfcamp

10 net wells

* Includes 2 net injector wells

Midland Basin

Wolfberry

Delaware Basin

Bone Spring

30 net wells

124 net wells

Other Permian

80 net wells*

46%

42%

Midland Basin -

$460 MM

Delaware Basin -

$425 MM

Central Basin -

$85 MM

San Juan/Other -

$30 MM

Capital Investment:

$1,000 MM

Permian Development :

$775 MM

Permian Exploration:

$195 MM

San Juan /Other:

$ 30 MM

$740

$760

$802

$907-

$937

Energen After-Tax Cash Flows

($MM)

E&P estimated development capital of

$805 MM approximates 2013e after-

tax cash flows from all operations

Approximately $160 million in

proceeds from sale of Black Warrior

Basin assets will help offset estimated

exploration capital of $195 MM

NOTE: From all operations

$30

Utility

BWB

E&P

E&P Range

$62

$49

$30

$20

$110

$119

$103

$101

$568

$592

$669

$786

2010

2011

2012

2013e

2013 Guidance

Exploration & Production

Sensitivity to Commodity Prices

NOTE: From continuing operations

Assumed prices unhedged volumes:

$4.00 gas •

$90 oil •

86¢

NGL

Est. E&P expenses/BOE:

LOE:

11.45

11.65

Prod. Taxes

2.70

2.80

DD&A:

19.15

19.55

G&A:

4.10

4.30

Interest :

2.15

2.25

Assumed unhedged basis differentials,

July-December

WTI Mid-Cushing

0.50

WTS Mid-Cushing

1.00

Gas basis

0.20

$400,000 for every $1 change from $90/barrel

OIL

NGL

GAS

$450,000 for every 1¢ change from 86¢ /gallon

$200,000 for every 10¢ change from $4.00/Mcf

CY2013e cash cost (continuing operations):

CY2013e net income break-even (continuing ops):

$19.00/barrel

$38.50/barrel

Hedges Minimize Price Risk

WTS Midland to WTI Cushing:

1.8 MMBO @ $3.00

WTI Midland to WTI Cushing:

2.1 MMBO @ $1.00

2H2013e

CY2014e

* Basin-specific hedges converted to NYMEXe price by adding to them

assumed San Juan and Permian basis differentials of 20¢/Mcf in 2013

and 2014.

Unhedged Gas

Unhedged Oil

Unhedged NGL

Hedged Gas

Hedged Oil

Hedged NGL

27% NGL Hedged

at $1.02

85% Gas Hedged at

NYMEXe $4.64

84% Oil Hedged at

NYMEXe $91.47

2H2013e

Hedged

Volumes

Hedge %

(based on estimated

production midpoint from

continuing operations)

Average

Price*

Oil

NGL

Gas

4.8 MMBO

23.4 MMgal

27.3 Bcf

84%

27%

85%

91.47

1.02

4.64

Hedge Volumes

Average Price*

92.64

4.60*

MMBO

Bcf

9.8

51.8

Oil

Gas

73% of 2H2013e production hedged

3P Reserves Total 735 MMBOE (Adjusted)

Proved Reserves by Product

(Excludes Black Warrior Basin assets)

232

277

320

330

3P Reserves by Area @ YE12

(Excludes Black Warrior Basin assets)

Midland Basin

Delaware Basin

San Juan Basin

Other

Resource Potential Not Included

Midland Basin

Delaware Basin

Wolfberry downspacing

Wolfcamp Shale

Cline Shale

Avalon Shale

Wolfcamp shale*

* 100 net locations based on 160-acre spacing and 4,400’

lateral lengths included in YE12 possible reserves

103

130

155

119

136

133

124

2009

2010

2011

2012

Gas

Oil

NGL

($MM)

26%

21%

46%

Central Basin

Permian

Overview

Legacy Assets

Major

Acquisitions,

2009-12

Gaines

Dawson

Borden

Mitchell

Irion

Sterling

Glasscock

Reagan

Upton

Midland

Martin

Howard

Andrews

Yoakum

Northwest Shelf

Eastern

Shelf

Diablo Platform

Marathon Ouachita Fad Belt

Winkler

Ward

Loving

Reeves

Eddy

Lea

NEW MEXICO

TEXAS

Ozona Arch

Total net acres:

300,000

$1B in acquisitions, 2009-12

Midland Basin

Wolfberry (V)

Wolfcamp shale (H)

Cline (H)

Delaware Basin

3 Bone Spring (H)

Wolfcamp shale (H)

Avalon shale (H)

Central Basin Platform:

San Andres (V)

Waterfloods (V)

Cline Play

Wolfberry Play

Wolfcamp Play

Bone Spring Focus Area

Central

Basin

Platform

Delaware Basin

Midland Basin

Gaines

Borden

Andrews

Martin

Howard

Midland

Upton

Reagan

Sterling

Coke

Tom

Green

Glasscock

Dawson

Mitchell

Irion

Coke

Scurry

Tom

Green

Midland Basin

Slick water stimulations

Northern wells drilled to Mississippian

Atoka

Barnett

Mississippi Lime

Horizontal potential

63,000 net acres

27,000 net undeveloped acres

670 potential locations (40-acre spacing)

670 potential locations (20-acre infill)

NOTE: Energen acreage in yellow

2Q13 2-Stream Results

(62 net wells tested)

Avg. Peak 24-hr. IP :

Peak 30-day Avg.:

114 boepd (78% oil)

96 boepd (78% oil)

WOLFBERRY (VERTICAL)

Vertical Wolfberry: Rust Outline

Average Wolfberry Type Curve

NOTE: Based on slick water type curves and mix of 670 net well inventory

EUR: 190 MBOE

Working Interest: 100%

Net Revenue Interest: 75%

Drill & complete cost:

Post-plant product mix:

31% ROR (pre-tax)

$100/barrel

$4/MMBtu

40% realizations (NGL)

40-acre spacing

6-8 frac stages

160

140

120

100

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

$2.5 MM

60% oil/24% NGL/16% gas

Months

Midland Basin

Gaines

Dawson

Borden

Andrews

Martin

Howard

Midland

Upton

Reagan

Mitchell

Irion

Sterling

Scurry

Glasscock

NOTE: Energen acreage in yellow

Lavaca 38 #101H –

3-Stream Results

Peak 24-hour IP: 861 boepd (60% oil)

Peak 20-day Avg: 709 boepd (65% oil)

Lateral length: 4,250’

Stimulation: Slick water

Vertical Wolfberry: Rust Outline

Cline Play:

Red Outline

Wolfcamp Play: Blue Outline

Lavaca 38 #101H –

On production

Two additional Glasscock County wells

completing/flowing back

Progressively longer lateral lengths up to 7,500’

100 net wells/36 MMBOE booked as possible reserves

at YE12 (EUR: 460 MBOE, 4,400’

lateral length, 160-

acre spacing)

CLINE HORIZONTAL

87,000 net acres

1,085 potential locations (80-acre spacing)

70,000 net acres

2,005 potential locations (80-acre spacing)

9 net Wolfcamp test wells in 2013

WOLFCAMP HORIZONTAL

Bone

Spring

Type

Curve

EUR: 475 MBOE

Working interest: 100%

Net Revenue Interest: 75%

Drill & complete:

$6.9 MM

Post-plant product mix:

66% oil/18% NGL/16% gas

66% ROR (pre-tax)

$100/barrel

$4/MMBtu

40% realizations (NGL)

4,400’

lateral lengths

10-11 frac stages

NOTE: Based on reserve type curves and remaining mix of wells in

program

700

600

500

400

300

200

100

350

300

250

200

150

100

Months

Delaware Basin

3 BONE SPRING

2Q13 2-stream Results

Avg. Peak 24-Hr. IP (10 net):

1,035 boepd (70% oil)

Peak 30-day Avg.: (7 net):

695 boepd (68% oil)

NOTE: Energen acreage in yellow

Wolfcamp Play

Rust Outline

3 Bone Spring Focus

Area –

Red Outline

114,000 net acres –

3,371 potential locations

10 net Wolfcamp test wells in 2013

E. J. Brady 56-1 #1H on production in Reeves Co.

University 28-21 #1H on production in Winkler Co.

Five wells currently in various stages of

drilling/completion/flow back

30,000 net acres

7,500 net undeveloped acres

46 potential locations (160-acre spacing)

WOLFCAMP

Loving

Reeves

Ward

Winkler

New Mexico

Texas

Loving

Reeves

Ward

Winkler

NOTE: Energen acreage in yellow

Delaware Basin Wolfcamp Results

University

28-21

#1H

University

39-17

#1H

E.J.

Brady

56-1

#1H

Peak 24-hour IP (3 stream):

969 boepd (74% oil)

Peak 30-day Avg (3 stream):

653 boepd (74% oil)

Lateral length: 4,200’

Stimulation: Slick water

Peak 24-hour IP (3 stream):

1,798 boepd (27% oil)

1,585 boepd (27% oil)

Lateral length: 3,800’

Stimulation: Slick water

Peak 24-hour IP (3 stream):

Peak 20-day Avg (3 stream)

1,187 boepd (61% oil)

Peak 30-day Avg (3 stream)

950 boepd (60% oil)

Lateral length: 4,000’

Stimulation: Hybrid

Wolfcamp Play

Rust Outline

San Juan Basin: Long-term Optionality

HBP

Oil phase

72,900 net undeveloped

acres

Wet gas phase

8,550 net undeveloped acres

Gas phase

58,300 net undeveloped

acres

WPX, Encana deem

“commercial”

play

Niobrara Shale

Farmington

Encana

Colorado

New Mexico

Oil Phase

Wet Gas Phase

Dry Gas Phase

Encana wells

WPX wells

NOTE: Energen acreage in yellow

ENERGEN

Years Ended 12/31

($ in millions)

2010

2011

2012

2013e

Net income (GAAP)

291

260

254

228

258

DD&A (including asset impairment)

248

284

441

536

Deferred income taxes, net

134

129

124

121

Other

$ 87

(17)

Consolidated after-tax cash flows (Non-GAAP)

740

760

802

907

937

Less: AGC cash flows from operations

$(110)

(119)

(103)

(101)

$ (101)

Adj. cash flows from ops excl. AGC (Non-GAAP)

630

641

699

806

$ 836

Note: 2013e data constitute forward-looking statements

The U.S. Securities and Exchange Commission (SEC) requires public companies to reconcile Non-GAAP financial measures to

related GAAP measures. GAAP refers to generally accepted accounting principles. After-tax Cash Flow (ATCF) is a Non-GAAP

financial measure. Energen believes ATCF is relevant as a measure of cash available to fund its capital expenditures, dividends,

debt reduction, and other investments.

After-tax Cash Flow Reconciliation to GAAP

ENERGEN ($MM)

Year Ended 12/31/12

Net income (GAAP)

253.6

Interest expense

65.6

Income tax expense

143.8

Depreciation, depletion and amortization

419.6

EBITDA (Non-GAAP)

882.5

Adjustment for asset impairment

21.5

Adjustment for mark-to-market (gains)/losses

(58.8)

Consolidated adjusted EBITDA (Non-GAAP)

845.3

Black Warrior Basin EBITDA (Non-GAAP)

43.5

Consolidated adjusted EBITDA excluding BWB (Non-GAAP)

801.8

The U.S. Securities and Exchange Commission (SEC) requires public companies to reconcile Non-GAAP financial

measures to related GAAP measures. GAAP refers to generally accepted accounting principles. After-tax Cash Flow

(ATCF) is a Non-GAAP financial measure. Energen believes ATCF is relevant as a measure of cash available to fund its

capital expenditures, dividends, debt reduction, and other investments.

Adjusted EBITDA Reconciliation to GAAP

Wolfcamp Potential by County

Up to 12.5% of Midland Basin wells may be contingent on regulatory approval

NOTE:

Unrisked,

80-acre

spacing,

4,400’

laterals

Midland Basin*

Wolfcamp A

Wolfcamp B

Wolfcamp C

Locations

Net Acres

Locations

Net Acres

Locations

Net Acres

Glasscock

347

27,727

296

23,657

291

23,271

Howard

6,722

Martin

227

18,198

227

18,188

Midland

112

8,986

104

8,341

Reagan

7,084

6,377

3,750

Upton

889

649

Total Midland

870

69,606

799

63,934

338

27,021

Texas

Delaware

Basin

Wolfcamp

Locations

Net

Acres

Locations

Net

Acres

Locations

Net

Acres

Loving

145

11,569

145

10,913

Ward

336

26,852

336

23,747

Winkler

251

20,109

251

18,868

Total East

732

58,530

732

53,528

Reeves

695

55,597

632

46,379

580

46,379

Total

Delaware

1,427

114,127

1,364

109,114

580

46,379

Total

Permian

Wolfcamp

2,297

183,733

2,163

173,048

918

73,400