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Energen Corporation : Six New Wolfcamp Wells Generate Excellent Rates

02/11/2014 | 10:39pm US/Eastern

2014 Production, Capital Guidance Announced
Energen Reports 4th Quarter 2013 Operating, Financial Results
3P Reserves and Contingent Resources Increase 96%

Highlights

  • Wolfcamp "B" well in western Reeves County sets known record for peak 24-hour IP (3-phase) in southern Delaware Basin at 2,387 boepd.
  • 7,000 foot Wolfcamp "B" well in Midland Basin (Glasscock County) produces at peak 24-hour IP (3 phase) of 1,387 boepd (80% oil) without artificial lift.
  • 2014 drilling and development capital estimated at $1.05 billion.
  • Permian Basin production in 2014 estimated to increase 16% year-over-year (YOY).
  • Oil and NGL ("liquids") production estimated to increase 12%, building on company high 13.6 MMBOE in 2013.
  • 2013 Permian Basin production rises 27% YOY despite ≈240,000 BOE impact from 4th quarter ice storms.

BIRMINGHAM, Ala.--(BUSINESS WIRE)--Feb. 11, 2014--

Headline of release should read: Six New Wolfcamp Wells Generate Excellent Rates (sted: Four New Wolfcamp Wells Generate Excellent Rates)

The corrected release reads:

SIX NEW WOLFCAMP WELLS GENERATE EXCELLENT RATES

2014 Production, Capital Guidance Announced
Energen Reports 4th Quarter 2013 Operating, Financial Results
3P Reserves and Contingent Resources Increase 96%

Highlights

  • Wolfcamp "B" well in western Reeves County sets known record for peak 24-hour IP (3-phase) in southern Delaware Basin at 2,387 boepd.
  • 7,000 foot Wolfcamp "B" well in Midland Basin (Glasscock County) produces at peak 24-hour IP (3 phase) of 1,387 boepd (80% oil) without artificial lift.
  • 2014 drilling and development capital estimated at $1.05 billion.
  • Permian Basin production in 2014 estimated to increase 16% year-over-year (YOY).
  • Oil and NGL ("liquids") production estimated to increase 12%, building on company high 13.6 MMBOE in 2013.
  • 2013 Permian Basin production rises 27% YOY despite ≈240,000 BOE impact from 4th quarter ice storms.

Energen Corporation (NYSE: EGN) has tested six new Wolfcamp wells in the Permian Basin, including two "B" bench wells in western Reeves County and two "B" bench well with 7,000-foot drilled lateral lengths in southern Glasscock County. All produced at very attractive initial rates. [See locator maps at www.energen.com].

The Winchester 57-10 #1H in western Reeves County produced at a peak 24-hour rate (3-stream) of 2,387 boepd, which is the highest initial production (IP) rate for a southern Delaware Wolfcamp well known to have been publicly disclosed to date. Were it not for its shorter completed lateral length, the Tisdale 56-8 #1H - also in western Reeves County - likely would have been comparable to the Winchester.

In the Midland Basin, the company's first "B' bench wells and first wells with 7,000-foot lateral lengths, the San Saba NS 37-48 #205H and #204H, tested without artificial lift at peak 24-hour rates (3-stream) of 1,387 boepd and 1,205 boepd, respectively. Oil comprised 79- 80 percent of the product mix in both wells.

"We continue to be very pleased with the Wolfcamp results we are achieving in the "A" and "B" benches in both the Midland and Delaware basins," said James McManus, Energen's chairman and chief executive officer. "We have six horizontal rigs currently drilling in the Midland Basin, as we significantly ramp up our activity level there. During 2014 we plan to drill and operate 57 gross Wolfcamp wells and 2 gross Cline wells.

"Our horizontal development plan in the Midland Basin is designed to maximize drilling and completion efficiencies; optimize spacing, work flow, and rig utilization; maximize stimulated reservoir volume for enhanced fracture complexity; and minimize stimulation impacts."

"In the Delaware Basin, we are concentrating on drilling to hold leases, to further delineate our extensive acreage position there, and to drive down well costs. We plan to have two rigs working the Wolfcamp play in the Delaware Basin throughout 2014 and expect to drill and operate 12 gross Wolfcamp wells there," he said.

"All-in-all, we expect our drilling and development capital spending in 2014 to approximate $1.05 billion, or about $225 million more than our estimated E&P after-tax cash flows," McManus added. "In this transition year, we expect production to be relatively flat during the first half of 2014 before picking up steam as our Wolfcamp production accelerates in the second half of the year. Our 2014 exit rate (December average at midpoint) could well be approximately 73 mboe per day, up from some 64 mboe per day at mid-year (June average at midpoint).

"I am really looking forward to 2014 as a year of significant progress for Energen," McManus said. "I believe the results of our aggressive drilling program in the Midland Basin in 2014 will provide a springboard for even greater acceleration in 2015 and beyond as we pursue 2,475 potential net Wolfcamp and Cline locations on our 81,500 net acres in the Midland Basin and Eastern Shelf.

"And another year of delineation in the Delaware Basin could well lead in 2015 to the start of development of the more than 3,100 potential net Wolfcamp locations we have identified on our 106,000 net acres in Ward, Winkler, Loving and Reeves counties."

2013 Earnings Summary

For the 12 months ended December 31, 2013, Energen reported consolidated net income of $204.6 million, or $2.82 per diluted share. After adjusting for non-cash and/or non-recurring items and for discontinued operations, Energen's adjusted income from continuing operations in 2013 totaled $216.9 million, or $2.99 per diluted share. In 2012, the comparable adjusted income from continuing operations totaled $218.0 million, or $3.01 per diluted share.

Non-cash and/or non-recurring items in 2013 included non-cash mark-to-market revenue losses, a gain on the sale of the company's Black Warrior Basin assets partially offset by the non-cash impairment of properties held for sale in North Louisiana/East Texas, a gain on the sale of the company's Birmingham utility service center, and income from discontinued operations.

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations

[See "Non-GAAP Financial Measures" beginning on pp. 18 for more information]

CY13 CY12
$M $/dil. sh. $M $/dil. sh.
Net Income All Operations (GAAP) $ 204,554 $ 2.82 $ 253,562 $ 3.51
Less: Non-cash Mark-to-Market gain/(loss) (30,574 ) (0.42 ) 37,247 0.52
Adjusted Net Income All Operations (Non-GAAP) $ 235,128 $ 3.24 $ 216,315 $ 2.99
Less: Gain on Sale of Utility Service Center 6,772 0.09 -- --
Less: E&P Discontinued Operations
Impairment (Loss)/Gain on Disposal 3,594 0.05 (13,416 ) (0.19 )
Income from Discontinued Operations 7,813 0.10 11,758 0.16
Adj. Income Continuing Operations (Non-GAAP) $ 216,949 $ 2.99 $ 217,973 $ 3.01

Note: Per share amounts may not sum due to rounding

In comparing the two years: The impact of a 10 percent increase in 2013 production from continuing operations, including a 20 percent increase in oil and natural gas liquids (NGL), and higher realized oil and natural gas prices were essentially offset by higher depreciation, depletion and amortization (DD&A) expense, greater lease operating expense (LOE) and production taxes, increased net administrative expenses, and increased exploration expense primarily associated with write-offs of miscellaneous parcels of leasehold expiring in first half of 2014.

Relative to the company's calendar year guidance issued on October 30, 2013, adjusted income from continuing operations fell below the midpoint largely due to the negative impact on production and expenses of two Permian Basin ice storms ($0.10) and a write-off of approximately 5,000 miscellaneous acres of unproved leasehold ($0.06). In addition, lower net general and administrative expense, a change in the effective tax rate, and higher commodity prices were offset by a slight decrease in expected production and greater-than-anticipated LOE.

Production by Commodity (MBOE)

Commodity CY13 CY12 Change
Continuing Operations
Oil 10,364 8,749

18 %

NGL 3,233 2,573 26 %
Natural Gas 9,684 9,861 (2) %
Total Continuing Operations 23,281 21,183 10 %
Discontinued Operations 2,081 2,883 (28) %
Total All Operations 25,362 24,066 5 %

Energen's adjusted EBITDAX from continuing operations (excluding non-cash and/or non-recurring items) totaled $937 million in 2013 and compared with $818 million in 2012. Energen Resources, the company's oil and gas exploration and production subsidiary, had adjusted EBITDAX from continuing operations (excluding mark-to-market) of $797 million in 2013 and $681 million in the same period a year ago. [See "Non-GAAP Financial Measures" beginning on pp. 18 for more information and reconciliation.]

4thQuarter 2013 Earnings Summary

For the 3 months ended December 31, 2013, Energen reported consolidated net income of $84.1 million, or $1.15 per diluted share. After adjusting for non-cash and/or non-recurring items and for discontinued operations, Energen's adjusted income from continuing operations in the fourth quarter of 2013 totaled $56.4 million, or $0.77 per diluted share. In the fourth quarter of 2012, the comparable adjusted income from continuing operations totaled $44.9 million, or $0.62 per diluted share.

Non-cash and/or non-recurring items in the fourth quarter of 2013 included non-cash mark-to-market revenue gains, a gain on the sale of the company's Black Warrior Basin assets partially offset by the non-cash impairment of properties held for sale in North Louisiana/East Texas, a gain on the sale of the company's Birmingham utility service center, and income from discontinued operations.

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations

[See "Non-GAAP Financial Measures" beginning on pp. 18 for more information]

4Q13 4Q12
$M $/dil. sh. $M $/dil. sh.
Net Income All Operations (GAAP) $ 84,093 $ 1.15 $ 62,823 $ 0.87
Less: Non-cash Mark-to-Market gain/(loss) 157 0.00 15,669 0.22
Adjusted Net Income All Operations (Non-GAAP) $ 83,936 $ 1.15 $ 47,154 $ 0.65
Less: Gain on Sale of Utility Service Center 6,772 0.09 -- --
Less: E& P Discontinued Operations
Impairment (Loss)/Gain on Disposal 19,272 0.27 -- --
Income from Discontinued Operations 1,496 0.02 2,271 0.03
Adj. Income Continuing Operations (Non-GAAP) $ 56,396 $ 0.77 $ 44,883 $ 0.62

Note: Per share amounts may not sum due to rounding

In comparing the two periods: The impact of a 9 percent increase in fourth quarter 2013 production from continuing operations, including an 18 percent increase in oil and natural gas liquids, and higher realized oil, NGL, and natural gas prices were partially offset by modest increases in DD&A expense, LOE and production taxes, net general and administrative expense, and exploration expense primarily associated with write-offs of miscellaneous parcels of expiring leasehold.

Production by Commodity (MBOE)

Commodity 4Q13 4Q12 Change
Continuing Operations
Oil 2,694 2,335

15 %

NGL 888 692

28 %

Natural Gas 2,446 2,515

(3) %

Total Continuing Operations 6,028 5,542

9 %

Discontinued Operations 175 674
Total All Operations 6,203 6,216

Energen's adjusted EBITDAX from continuing operations (excluding non-cash and/or non-recurring items) totaled $249 million in the fourth quarter of 2013 and compared with $204 million in the same period last year. Energen Resources had adjusted EBITDAX from continuing operations (excluding mark-to-market) of $213 in the fourth quarter of 2013 and $170 million in the same period a year ago. [See "Non-GAAP Financial Measures" beginning on pp. 18 for more information and reconciliation.]

MIDLAND BASIN WOLFCAMP EXPLORATORY WELLS - GLASSCOCK COUNTY

Well Zone Lateral length

Frac
Stages

Peak 24-Hour IP
Drilled* Completed Boepd

Oil
(Bopd)

NGL
(Bpd)

Gas
(Mcfd)

Guadalupe
48 #101H

A 5,300' 5,246' 21 1,000 743 139 709

San Saba
NS 37-48
#204H

B 7,000' 6,706' 27 1,205 957 132 693

San Saba
NS 37-48
#205H

B 7,000' 6,782' 27 1,387 1,115 134 830

* Represents distance from surface to toe

Energen's first two Wolfcamp "B" wells in southern Glasscock County and its first two wells drilled to a 7,000-foot lateral length have generated excellent results. The San Saba NS 37-48 #205H and #204H tested at attractive peak 24-hour IP rates of 1,387 boepd (80% oil, 10% NGL, and 10% gas) and 1,205 boepd (79% oil, 11% NGL, and 10% gas), respectively. The #205H has the highest peak 24-hour IP drilled by the company in the Midland Basin to-date. The Guadalupe 48 #101H is an "A" bench well with a 5,300-foot drilled lateral length. Its peak 24-hour IP was a solid 1,000 boepd (74% oil, 14% NGL, and 12% gas).

Management said it does not have 30-day rates for these wells yet because the company is fracture-stimulating neighboring wells before these are brought on production; however, management said it is comfortable disclosing just the peak 24-hour IP given the consistency of results being generating by its southern Glasscock County wells.

The last two wells in Energen's 2013 exploratory drilling program in the Midland Basin are flowing back or awaiting completion.

The company's 2014 exploratory drilling program in the Midland Basin consists of 17 gross (16 net) Wolfcamp wells and 2 gross (2 net) Cline wells. The first three wells in the 2014 exploratory program currently are awaiting completion or drilling, including the company's first well in Martin County and its first Cline test well.

Another 40 gross (39 net) Wolfcamp development wells are scheduled to be drilled in 2014 in southern Glasscock County. Our 2014 Wolfcamp development program is focused on drilling stacked laterals in the "A" and "B" benches with lateral lengths of 6,700 feet and 7,500 feet. The company estimates that unrisked ultimate recoveries (EURs) from these development wells will range from 550-750 MBOE for a 6,700-foot lateral and 650-850 MBOE for a 7,500-foot lateral.

DELAWARE BASIN

Well Zone Lateral length

Frac
Stages

Peak 24-Hour IP Peak 30-day Average
Drilled* Completed Boepd Oil (Bopd) NGL (Bpd) Gas (Mcfd) Boepd Oil (Bopd) NGL (Bpd) Gas (Mcfd)
Winchester 57-10 #1H B 4,400' 4,218 18 2,387 972 648 4,598 2,186 840 617 4,376
Tisdale 56-8 #1H B 4,400' 3,242' 14 2,081 657 682 4,451 1,804 535 608 3,968
Red Rock 6-6 #1H A 4,400' 4,437 19 1,471 956 265 1,500 1,137 731 209 1,180

* Represents distance from surface to toe

Energen's first two Wolfcamp "B" wells in the Delaware Basin were drilled in far west Reeves County approximately 10 miles apart. Both have generated excellent results. The Winchester 57-10 #1H tested at an outstanding peak 24-hour IP rate of 2,387 boepd (41% oil, 27% NGL, and 32% gas). This not only is the highest rate among Energen's Wolfcamp wells, the Winchester has the highest known 24-hour peak IP of any southern Delaware Basin Wolfcamp well reported to date. The peak 30-day average rate was 2,186 boepd (38% oil, 28% NGL, and 33% gas).

The Tisdale 56-8 #1H, despite a shorter, completed lateral length, tested at a peak 24-hour IP rate of 2,081 boepd; this 3-stream rate was 32% oil, 33% NGL, and 36% gas. The peak 30-day average rate (3-stream) was 1,804 boepd (30% oil, 34% NGL, 37% gas).

Also in Reeves County, located near the previously disclosed Bodacious C7-19 #1H, Energen drilled the Red Rock 6-6 #1H in the "A" bench of the Wolfcamp shale. The Red Rock was a solid well that tested at a peak 24-hour IP rate of 1,471 boepd. The 3-stream rate was 65% oil, 18% NGL, and 17% gas. The peak 30-day average rate (3-stream) was 1,137 boepd (64% oil, 18% NGL, and 17% gas).

The last two wells in Energen's 2013 exploratory program are "A" bench wells in Reeves County that are drilling or awaiting completion. The company's 2014 exploratory drilling program in the Delaware Basin consists of 12 gross (10 net) Wolfcamp wells. The first two wells in the 2014 exploratory program currently are drilling.

2014 Capital and Production Guidance

Energen estimates that it will invest approximately $1.1 billion in 2014, including $1.05 billion for oil and gas drilling and development and $75 million for utility system maintenance, information technology, and construction of new service centers in Birmingham.

In accelerating the drilling of its horizontal Wolfcamp and Cline potential in the Midland Basin, Energen is committing 45 percent of its planned capital spending of $1.05 billion to drill 55 net Wolfcamp shale wells and 2 net Cline shale wells in 2014. The average drill-and-complete cost of a Wolfcamp well in 2014 is estimated to be $8.5 MM; 24 net Wolfcamp wells have a planned drilled lateral length of 6,700 feet, while the other 31 are to be drilled to 7,500 feet. The drill-and-complete cost of the two, planned Cline wells with 7,200-foot drilled lateral lengths is estimated to average $9 million.

Elsewhere in the Midland Basin, the company is scaling back its vertical Wolfberry program in 2014 as it focuses on the higher-return horizontal program. Two vertical drilling rigs are expected to drill an estimated 49 net wells, which is sufficient to meet Energen's continuous drilling obligations in the Wolfberry play.

With significant Wolfcamp potential in the Delaware Basin, as well, the company will be running two rigs and investing approximately $108 million to drill 10 net wells that will further delineate its 106,000 net acres and secure expiring leases. Still in the exploratory phase, these wells are expected to cost approximately $10 million to drill, complete, and install surface facilities.

Elsewhere in the Delaware Basin, Energen plans to drill 22 net 3rd Bone Spring wells in the southern Delaware Basin and two net 2nd Bone Spring wells in the northern Delaware Basin in New Mexico for approximately $173 million. Energen's 3rd Bone Spring program has been one of the two major drivers of the company's oil and NGL production growth over the last three years. With only 5 net locations remaining to be drilled after this year, the company anticipates concluding its 3rd Bone Spring drilling program in early 2015.

Energen's legacy Permian Basin assets are in the Central Basin Platform, where the company plans to invest $17 million to drill 13 net producers and 8 net injector wells in 2014. And in the San Juan Basin, which is home to approximately 65 percent of the company's proved natural gas reserves, Energen will be investing only $15 million in 2014; of that amount, 40 percent reflects the company's 50 percent working interest in two non-operated Niobrara oil shale wells to be drilled by WPX Energy.

2014e Drilling and Development Capital and Production Summary

Operated Wells Operated Production Midpoint
Capital ($MM) To Be Drilled Rig Count Continuing Ops -- MMBOE
Gross (Net)

2014e

2013

Midland Basin

$

668

113 (106

)

8

7.4

5.1

Wolfcamp/Cline

475 59 (57 ) 6 2.2 0.0

Wolfberry/Other

121 54 (49 ) 2 5.2 5.1

Facilities/Other

72
Delaware Basin

$

315

41 (34

)

5-6

5.4

4.7

3rd Bone Spring/Other

173 29 (24 ) 3-4 4.5 4.2

Wolfcamp

108 12 (10 ) 2 0.9 0.5

Facilities/Other

34
Other Permian

$

42

26 (21

)

*

1

3.7

4.4

Waterfloods/CO(2) floods

17

26 (21

)

*

Facilities/Other

25
San Juan Basin/Other

$

15

0 (0

)

0

8.4

9.1

Facilities/Other

15
Net Carry In/Carry Out

$

10

TOTAL - Contg. Ops

$

1,050

180 (161

)

14

24.9

23.3

Note: "Facilities" capital includes salt water disposal wells, artificial lift, and central gathering facilities; "Other" capital includes payadds, refracs, and non-operated activities.

* Includes 10 gross (8 net) injectors

Production from continuing operations in 2014 is estimated to range from 24.4 MMBOE to 25.4 MMBOE, with a midpoint of 24.9 MMBOE. At the midpoint, this reflects a 16 percent increase (YOY) in total Permian Basin production while production in the San Juan Basin, the company's primary natural gas-producing region, is expected to see production decline 8 percent in 2014.

In the Midland Basin, where the company is transitioning from its vertical Wolfberry focus to a focus on the Wolfcamp and Cline shales, production is estimated to increase 45 percent (YOY). In the Delaware Basin, where growth from the maturing 3rd Bone Spring program is slowing in 2014, production is estimated to increase approximately 15 percent. Production from Energen's legacy oil assets in the Central Basin Platform is expected to decline some 16 percent.

Production from Continuing Operations by Area (MMBOE)

Area 2014e Midpoint 2013 Change
Midland Basin 7.4 5.1 45 %
Delaware Basin 5.4 4.7 15 %
Central Basin Platform 3.7 4.4 (16) %
Total Permian Basin 16.5 14.2 16 %
San Juan Basin/Other 8.4 9.1 (8) %
Total Continuing Operations 24.9 23.3 7 %

Oil and NGL production is estimated to grow 12 percent in 2014, while natural gas production is expected to remain essentially flat as a result of associated gas in the Permian Basin offsetting natural gas declines in the San Juan Basin.

Production from Continuing Operations by Product (MMBOE)

Commodity 2014e Midpoint 2013 Change
Oil 11.4 10.4 10 %
NGL 3.8 3.2 19 %
Natural Gas 9.7 9.7 0 %
Total Continuing Operations 24.9 23.3 7 %

Production from Continuing Operations by Basin and Product (MMBOE)

Basin Oil NGL Gas Total
2014e 2013 2014e 2013 2014e 2013 2014e 2013
Midland Basin 4.6 3.2 1.5 1.0 1.3 0.9 7.4 5.1
Delaware Basin 3.3 3.1 0.9 0.7 1.2 0.9 5.4 4.7
Central Basin Platform/Other 3.4 3.9 0.2 0.2 0.1 0.2 3.7 4.4
San Juan Basin/Other 0.1 0.1 1.2 1.3 7.1 7.7 8.4 9.1
Total Continuing Operations 11.4 10.4 3.8 3.2 9.7 9.7 24.9 23.3

NOTE: 2014e production reflects the midpoint of guidance

Production is expected to remain relatively flat through the first six months of 2014, then accelerate in the second half as a result of the company's Wolfcamp drilling in the Midland Basin.

2014e Production from Continuing Operations by Basin per Quarter (MMBOE)

Basin

1st Quarter

2nd Quarter 3rd Quarter 4th Quarter
2014e 2013 2014e 2013 2014e 2013 2014e 2013
Midland Basin 1.5 1.0 1.5 1.2 2.1 1.4 2.3 1.5
Delaware Basin 1.3 1.0 1.3 1.2 1.3 1.3 1.5 1.2
Central Basin Platform/Other 1.0 1.1 0.9 1.1 0.9 1.1 0.9 1.1
San Juan Basin/Other 2.1 2.2 2.1 2.4 2.1 2.3 2.1 2.2
Total Production - Contg Ops 5.9 5.3 5.8 5.9 6.4 6.1 6.8 6.0

NOTE: 2014e production reflects the midpoint of guidance

Energen's 2014 guidance range for consolidated after-tax cash flows is an estimated $907 million to $937 million. Energen Resources' after-tax cash flows are estimated to be $812 million to $842 million, and Alagasco is expected to generate after-tax cash flows of approximately $95 million. [See "Non-GAAP Financial Measures" beginning on pp 18 for more information and reconciliation.]

Consolidated earnings from continuing operations in 2014 are estimated to range from $200 million to $230 million, or $2.74-$3.14 per diluted share, with Alagasco's utility operations contributing approximately 20 percent.

Energen Resources' estimated exploration and production expenses from continuing operations per barrels of oil equivalents (BOE) in calendar year 2014 are:

Lease Operating expense
Base, marketing, and transportation $ 11.25 - $ 11.75
Production taxes $ 2.75 - $ 2.95
DD&A expense $ 20.50 - $ 21.50
General & Administrative expense, net $ 4.75 - $ 5.25
Interest expense $ 2.25 - $ 2.45

Exploration expense (delay rentals, seismic, G&G)

$ 0.85 - $ 0.95

Approximately 74 percent of the company's total estimated midpoint of 2014 production from continuing operations is hedged. Assumed prices applicable to Energen Resources' unhedged volumes for the remainder of the year are $90.00 per barrel of oil, $0.89 per gallon of NGL, and $4.00 per Mcf of natural gas.

Energen's 2014 guidance also includes assumed prices for various basis differentials. These assumptions for oil are $2.58 per barrel (WTS Midland to WTI Cushing, "sour oil") and $1.75 per barrel (WTI Midland to WTI Cushing). Energen estimates that approximately 70 percent of its oil production in 2014 is sweet. Gas basis assumptions are $0.19 per Mcf in both the San Juan and Permian basins.

The company's current hedge position for 2014 is as follows:

Commodity

Hedge Volumes

2014e Production

(Contg Ops) Midpoint

Hedge %

NYMEX Price

Oil

9.8 MMBO

11.4 MMBO

86 %

$ 92.64 per barrel

NGL

--

159.8 MMgal

--

--

Natural Gas

51.8 Bcf

57.8 Bcf

90 %

$ 4.61 per Mcf

Note: Known actuals included

In the table above, basin-specific contract prices for natural gas have been converted for comparability purposes to a NYMEX-equivalent price by adding to them Energen Resources' assumed San Juan and Permian basis differentials.

Average realized oil and gas prices for Energen Resources' production associated with NYMEX contracts as well as for unhedged production will reflect the impact of basis differentials; average realized oil prices also will reflect oil transportation charges of approximately $2.60 per barrel in 2014; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.09 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin. The company also has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price.

As a result of Energen's 2014 hedge position for oil and gas, changes in commodity prices will have a significantly lessened impact on Energen's 2014 cash flows. Every $1.00 change in the average NYMEX price of oil from $90 per barrel represents an estimated net impact of $670,000, and every 10-cent change in the average NYMEX price of gas from $4.00 represents an immaterial impact. Because NGL production is unhedged, the net income impact of every 1-cent change in the average price of NGL from $0.89 per gallon is estimated to be approximately $840,000. Price-related events such as substantial basis differential changes could cause these sensitivities to be different from those outlined.

CY2013 Earnings Detail

Excluding non-cash and/or non-recurring items, Energen Resources' adjusted income from continuing operations totaled $166.0 million in 2013 and $168.5 million in 2012.

Production from Continuing Operations by Area (MBOE)

Area CY13 CY12 Change
Midland Basin 5,092 3,516 45 %
Delaware Basin 4,672 2,908 61 %
Central Basin Platform 4,423 4,774 (7) %
Total Permian Basin 14,187 11,198 27 %
San Juan Basin/Other 9,094 9,985 (9) %
Total Continuing Operations 23,281 21,183 10 %

Average Realized Sales Prices from Continuing Operations

Commodity CY13 CY12 Change
Oil (per barrel) $ 87.65 $ 83.46 5 %
NGL (per gallon) $ 0.75 $ 0.79 (5 ) %
Natural Gas (per Mcf) $ 4.19 $ 3.66 14 %

Per-unit LOE from continuing operations in 2013 increased approximately 15 percent YOY to $15.10 per BOE. Base LOE and marketing and transportation expenses increased approximately 15 percent to $12.20 per BOE largely due to increased workovers and repairs, equipment rental, gathering costs, and environmental compliance. Commodity price-driven production taxes increased approximately 15 percent on a per-unit basis to $2.90 per BOE.

Per-unit DD&A expense from continuing operations in 2013 totaled $19.32 per BOE, increasing approximately 21 percent from the same period last year largely due to year-over-year increases in development costs and production and to the impact of reduced year-end 2012 natural gas reserves resulting from lower commodity prices.

Per-unit net G&A expense in the 2013 year-to-date period increased approximately 35 percent from the same period last year to $4.61 per BOE. This largely was due to increased stock-based compensation.

Alagasco generated 2013 net income of $57.4 million, including an after-tax gain of $6.8 million on the sale of its Birmingham service center. Utility net income in 2012 totaled $49.4 million in 2012.

Fourth Quarter Earnings Detail

Excluding non-cash and/or non-recurring items, Energen Resources' adjusted income from continuing operations totaled $43.5 million in the fourth quarter of 2013 and $32.6 million in the same period a year ago.

Production from Continuing Operations by Area (MBOE)

Area 4Q13 4Q12 Change
Midland Basin 1,477 934 58 %
Delaware Basin 1,229 984 25 %
Central Basin Platform 1,096 1,164 (6) %
Total Permian Basin 3,802 3,082 23 %
San Juan Basin/Other 2,226 2,461 (10) %
Total Continuing Operations 6,028 5,543 9 %

Average Realized Sales Prices from Continuing Operations

Commodity 4Q13 4Q12 Change
Oil (per barrel) $ 87.80 $ 80.66 9 %
NGL (per gallon) $ 0.79 $ 0.77 3 %
Natural Gas (per Mcf) $ 4.35 $ 3.72 17 %

Per-unit LOE from continuing operations in the fourth quarter of 2013 increased approximately 6 percent from the same period a year ago to $15.18 per BOE. Base LOE and marketing and transportation expenses increased approximately 3 percent to $12.21 per BOE largely due to increased workovers and repairs, labor, non-operated activities, environmental compliance, and increased ad valorem taxes partially offset by decreased water disposal costs and equipment rental. Commodity price-driven production taxes increased approximately 19 percent on a per-unit basis to $2.97 per BOE.

Per-unit DD&A expense from continuing operations in the 4th quarter of 2013 totaled $19.96 per BOE, increasing approximately 14 percent from the same period last year largely due to year-over-year increases in development costs and production.

Per-unit net G&A expense increased approximately 50 percent in the fourth quarter of 2013 to $4.28 per BOE primarily due to increased stock-based compensation.

Alagasco's net income in the fourth quarter of 2013 totaled $19.8 million, including an after-tax gain of $6.8 million on the sale of its Birmingham service center. Net income totaled $12.2 million in the same period a year ago.

Contingent Resources Increase 172%

The strength of Energen's extensive inventory of unrisked Wolfcamp and Cline drilling locations is reflected in the 172 percent increase in the company's year-end 2013 contingent resources.

Contingent resources are defined by the Petroleum Resource Management System as "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies."

After consultation with its third party reserve engineers, Energen determined that much of its Wolfcamp and Cline potential in the Midland and Delaware basins does not have sufficient well control data to support a 3P reserve classification. The driver of that conclusion was the limited number of wells drilled and completed in the two basins. As Energen's continuing exploration and development drilling increases the body of geologic and engineering data for these plays, the company expects its contingent resources to begin moving into 3P reserve categories.

Energen's proved reserves at year-end 2013 totaled a record 348 MMBOE and were essentially unchanged from the prior year as record production and divestures essentially offset the addition of previously classified unproved reserves and contingent resources and upward price-related revisions.

Oil and NGL reserves at year end represented more than 65 percent of total proved reserves and are expected to increase as Energen continues to focus on the exploration and development of the liquids-rich Permian Basin.

Commodity prices used for calculating reserves at year-end 2013 were $96.94 per barrel of oil (up from $94.71 in 2012), $3.67 per thousand cubic feet (Mcf) for natural gas (up from $2.76 in 2012); and an average of $0.76 per gallon of NGL before transportation and fractionation (down from $0.88 per gallon in 2012).

Proved Reserves by Basin (MMBOE)

Basin YE12

2013
Production

2013
Acquisitions/
(Divestitures)

Additions Price/Other

Revisions

YE13
Permian 225.0 (14.2) 0.1 34.5 1.2 246.6
San Juan Basin/Other 101.8 (9.1) 0.0 2.3 2.3 97.3
Black Warrior/NL/ETX 19.6 (2.1) (14.7) 0.0 1.1 3.9
TOTAL 346.4 (25.4) (14.6) 36.8 4.6 347.8

Proved Reserves by Commodity (MMBOE)

Commodity 2013 2012 % Change
Oil 164.9 155.3 6.2
Natural gas liquids 63.0 56.2 12.1
Natural gas 119.9 134.9 (11.1 )
TOTAL 347.8 346.4 0.4

YE2013 3P Reserves & Contingent Resources (MMBOE)

Basin Proved Probable Possible Contingent

Total

Permian Basin 247 46 152 2,230 2,675
Delaware Basin 42 9 19 1,379 1,448

-Wolfcamp

8 3 19 1,378 1,408

-3rd Bone Spring/Other

34 6 0 0 40
Midland Basin 134 26 91 851 1,102

-Wolfcamp/Cline

6 4 86 851 947

-Wolfberry

128 22 5 0 155
Central Basin Platform 71 11 42 0.0 125
San Juan/Other 97 59 167 255 578
North Louisiana/East TX 4 2 1 3 10
TOTAL 348 107 320 2,488 3,263

Contingent Resources, 2013 vs 2012 (MMBOE)

Basin Contingent
2013 2012
Permian Basin 2,230 569
Delaware Basin 1,379 199

-Wolfcamp

1,378 199

-3rd Bone Spring/Other

0 0
Midland Basin 851 370

-Wolfcamp/Cline

851 370

-Wolfberry

0 0
Central Basin Platform 0.0 0
San Juan/Other 255 341
North Louisiana/East TX 3 3
TOTAL 2,488 913

The definitions of probable and possible reserves imply different probabilities of potential recovery in each classification; the quantities reported here are unrisked and based on the Company's best estimate of current costs to drill wells in each basin/area and bring associated production to market.

CONFERENCE CALL

Energen will hold its quarterly conference call Wednesday, February 12, at 11:00 a.m. EDT. Members of the investment community may participate by calling 1-866-939-3921. A live audio Webcast of the program as well as a replay may be accessed through Web site, www.energen.com.

Energen Corporation is an oil and gas exploration and production company with headquarters in Birmingham, Alabama. Through Energen Resources Corporation, the company has approximately 775 million barrels of oil-equivalent proved, probable, and possible reserves and another 2.5 billion barrels of contingent resources. These all-domestic reserves and resources are located primarily in the Permian Basin in west Texas. For more information, go to http://www.energen.com.

FORWARD LOOKING STATEMENT: This release contains statements expressing expectations of future plans, objectives and performance that constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company's forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. We undertake no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise. All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. A more complete discussion of risks and uncertainties that could affect future results of Energen and its subsidiaries is included in the Company's periodic reports filed with the Securities and Exchange Commission.

Financial, operating, and support data pertaining to all reporting periods included in this release are unaudited and subject to revision.

Non-GAAP Financial Measures

Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles) which excludes certain non-cash mark-to-market derivative financial instruments. Adjusted Income from continuing operations further excludes a gain on the sale of utility service center, a gain on disposal of discontinued operations, non-cash impairment charges and income from discontinued operations. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies.

Quarter Ended 12/31/2013
Consolidated Net Income ($ in millions except per share data) Net Income

Per Diluted Share

Net Income (GAAP) 84.1 1.15
Non-cash mark-to-market gains (net of $0.5 tax) (0.2 ) (0.00 )
Adjusted Net Income from All Operations (Non-GAAP) 83.9 1.15
Gain on sale of utility service center (net of $4.1 tax) (6.8 ) (0.09 )
Gain on disposal of discontinued operations (net of $12.9 tax) (22.5 ) (0.31 )
Non-cash impairment charge (net of $2.0 tax) (1) 3.2 0.04
Income from discontinued operations (net of $1.5 tax) (1.5 ) (0.02 )
Adjusted Income from Continuing Operations (Non-GAAP) 56.4 0.77
Quarter Ended 12/31/2012
Consolidated Net Income ($ in millions except per share data) Net Income

Per Diluted Share

Net Income (GAAP) 62.8 0.87
Non-cash mark-to-market gains (net of $9.0 tax) (15.7 ) (0.22 )
Adjusted Net Income from All Operations (Non-GAAP) 47.2 0.65
Income from discontinued operations (net of $1.3 tax) (2.3 ) (0.03 )
Adjusted Income from Continuing Operations (Non-GAAP) 44.9 0.62
Year-to-Date Ended 12/31/2013
Consolidated Net Income ($ in millions except per share data) Net Income

Per Diluted Share

Net Income (GAAP) 204.6 2.82
Non-cash mark-to-market losses (net of $17.3 tax) 30.6 0.42
Adjusted Net Income from All Operations (Non-GAAP) 235.1 3.24
Gain on sale of utility service center (net of $4.1 tax) (6.8 ) (0.09 )
Gain on disposal of discontinued operations (net of $12.9 tax) (22.5 ) (0.31 )
Non-cash impairment charge (net of $10.9 tax) (1) 18.9 0.26
Income from discontinued operations (net of $2.2 tax) (7.8 ) (0.10 )
Adjusted Income from Continuing Operations (Non-GAAP) 216.9 2.99
Year-to-Date Ended 12/31/2012
Consolidated Net Income ($ in millions except per share data) Net Income

Per Diluted Share

Net Income (GAAP) 253.6 3.51
Non-cash mark-to-market gains (net of $21.5 tax) (37.2 ) (0.52 )
Adjusted Net Income from All Operations (Non-GAAP) 216.3 2.99
Non-cash write-down of natural gas properties (net of $8.1 tax) (2) 13.4 0.19
Income from discontinued operations (net of $7.3 tax) (11.8 ) (0.16 )
Adjusted Income from Continuing Operations (Non-GAAP) 218.0 3.01
Note: Amounts may not sum due to rounding

(1) Current year-to-date and quarter-to-date loss on impairment ($18.9 and $3.2, respectively) included in gain (loss) on disposal of discontinued operations on the income statement

(2) Prior year-to-date write down of natural gas properties ($13.4) included in income (loss) from discontinued operations on the income statement

Non-GAAP Financial Measures

Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles) which excludes certain non-cash mark-to-market derivative financial instruments. Adjusted Income from continuing operations further excludes a gain on disposal of discontinued operations, non-cash impairment charges and income from discontinued operations. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies.

Energen Resources Net Income ($ in millions) Quarter Ended 12/31/2013 Year-to-date 12/31/2013
Net Income (GAAP) 64.4 146.8
Non-cash mark-to-market (gains) losses (net of ($0.5) and $17.3 tax) (0.2 ) 30.6
Adjusted Net Income from All Operations (Non-GAAP) 64.2 177.4
Gain on disposal of discontinued operations (net of $12.9 and $12.9 tax) (22.5 ) (22.5 )
Non-cash impairment charge (net of $2.0 and $10.9 tax) (1) 3.2 18.9
Income from discontinued operations (net of $1.5 and $2.2 tax) (1.5 ) (7.8 )
Adjusted Income from Continuing Operations (Non-GAAP) 43.5 166.0
Energen Resources Net Income ($ in millions) Quarter Ended 12/31/2012 Year-to-date 12/31/2012
Net Income (GAAP) 50.6 204.1
Non-cash mark-to-market gains (net of $9.0 and $21.5 tax) (15.7 ) (37.2 )
Adjusted Net Income from All Operations (Non-GAAP) 34.9 166.9
Non-cash write-down of natural gas properties (net of $8.1 tax) (2) - 13.4
Income from discontinued operations (net of $1.3 and $7.3 tax) (2.3 ) (11.8 )
Adjusted Income from Continuing Operations (Non-GAAP) 32.6 168.5
Note: Amounts may not sum due to rounding

(1) Current year-to-date and quarter-to-date loss on impairment ($18.9 and $3.2, respectively) included in gain (loss) on disposal of discontinued operations on the income statement

(2) Prior year-to-date write down of natural gas properties ($13.4) included in income (loss) from discontinued operations on the income statement

Non-GAAP Financial Measures

Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (EBITDAX) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles).  Adjusted EBITDAX from continuing operations further excludes a gain on the sale of utility service center, non-cash asset impairments, a gain on disposal of discontinued operations, certain non-cash mark-to-market derivative financial instruments, and income from discontinued operations. Energen believes these measures allow analysts and investors to understand the financial performance of the company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing the company and other oil and gas producing companies.

Reconciliation To GAAP Information Year-to-Date Ended 12/31 Quarter Ended 12/31
($ in millions) 2012 2013 2012 2013
Consolidated Net Income (GAAP) 253.6 204.6 62.8 84.1
Interest expense 65.5 69.2 17.1 17.4
Income tax expense 144.5 105.3 34.0 31.4
Depreciation, depletion and amortization 385.5 497.4 109.0 132.0
Accretion expense 6.3 7.0 1.6 1.8
Exploration expense 19.4 27.9 6.0 14.0
Adjustment for gain on sale of utility service center - (10.9 ) - (10.9 )
Adjustment for asset impairment, net of tax (1) 13.4 18.9 - 3.2
Adjustment for gain on disposal of discontinued operations,net of tax - (22.5 ) - (22.5 )
Adjustment for mark-to-market (gains) losses (58.8 ) 47.8 (24.7 ) (0.6 )
Adjustment for income from discontinued operations, net of tax (11.8 ) (7.8 ) (2.3 ) (1.5 )
Consolidated Adjusted EBITDAX from Continuing Operations (Non-GAAP) 817.7 936.9 203.6 248.5
Reconciliation To GAAP Information Year-to-Date Ended 12/31 Quarter Ended 12/31
($ in millions) 2012 2013 2012 2013
Energen Resources Net Income (GAAP) 204.1 146.8 50.6 64.4
Interest expense 50.0 54.0 13.1 13.5
Income tax expense 115.1 71.3 27.0 19.8
Depreciation, depletion and amortization 343.2 453.5 98.3 120.8
Accretion expense 6.3 7.0 1.6 1.8
Exploration expense 19.4 27.9 6.0 14.0
Adjustment for asset impairment, net of tax (1) 13.4 18.9 - 3.2
Adjustment for gain on disposal of discontinued operations,net of tax - (22.5 ) - (22.5 )
Adjustment for mark-to-market (gains) losses (58.8 ) 47.8 (24.7 ) (0.6 )
Adjustment for income from discontinued operations, net of tax (11.8 ) (7.8 ) (2.3 ) (1.5 )
Energen Resources Adjusted EBITDAX from Continuing Operations (Non-GAAP) 681.0 796.9 169.6 212.9
Note: Amounts may not sum due to rounding

(1) Current year-to-date and quarter-to-date loss on impairment ($18.9 and $3.2, respectively) included in gain (loss) on disposal of discontinued operations on the income statement. Prior year-to-date write down of natural gas properties ($13.4) included in income (loss) from discontinued operations on the income statement.

Non-GAAP Financial Measures

After-tax Cash Flows is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes after-tax cash flows are relevant because they are a measure of cash available to fund the Company's capital expenditures, dividends, debt reduction, and other investments.  Adjusted after-tax cash flows excluding Alagasco provides a measure of cash flows available to fund the Company's exploration and production activities.

Reconciliation To GAAP Information Years Ended 12/31
($ in millions) 2012 Actual 2013 Actual 2014 Estimate (e)
Consolidated Net Income (GAAP) 254 205 200 230
Depreciation, depletion and amortization 441 558 572 572
Deferred income taxes 124 83 96 96
Exploratory expense 17 16 - -
Other (34) 48 39 39
After-tax Cash Flows (Non-GAAP) 802 910 907 937
Changes in assets and liabilities and other adjustments (66) 15 2 2
Net Cash Provided by Operating Activities (GAAP) 736 925 909 939
Reconciliation To GAAP Information Years Ended 12/31
($ in millions) 2012 Actual 2013 Actual 2014 Estimate (e)
Net Cash Provided by Operating Activities (GAAP) 736 925 909 939
Changes in assets and liabilities and other adjustments 66 (15) (2) (2)
After-tax Cash Flow (Non-GAAP) 802 910 907 937
Less: AGC cash flows from operations and other (103) (116) (95) (95)
Adj. After-tax Cash Flows Excluding Alagasco (Non-GAAP) 699 794 812 842

(e) This estimate is a "forward-looking statement" as defined by the Securities and Exchange Commission.  All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated.  In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts.  A discussion of risks and uncertainties, which could affect future results of Energen and its subsidiaries, is included in the Company's periodic reports filed with the Securities and Exchange Commission.

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 3 months ending December 31, 2013 and 2012

4th Quarter
(in thousands, except per share data) 2013 2012 Change
Operating Revenues
Oil and gas operations $ 329,962 $ 289,891 $ 40,071
Natural gas distribution 142,771 124,406 18,365
Total operating revenues 472,733 414,297 58,436
Operating Expenses
Cost of gas 52,007 48,049 3,958
Operations and maintenance 148,949 121,516 27,433
Depreciation, depletion and amortization 132,026 108,988 23,038
Taxes, other than income taxes 27,313 22,487 4,826
Accretion expense 1,808 1,648 160
Total operating expenses 362,103 302,688 59,415
Operating Income 110,630 111,609 (979 )
Other Income (Expense)
Interest expense (17,449 ) (17,095 ) (354 )
Other income 1,674 662 1,012
Other expense (145 ) (598 ) 453
Total other expense (15,920 ) (17,031 ) 1,111
Income From Continuing Operations Before Income Taxes

94,710

94,578

132

Income tax expense 31,385 34,026 (2,641 )
Income From Continuing Operations 63,325 60,552 2,773
Discontinued Operations, net of taxes
Income from discontinued operations 1,496 2,271 (775 )

Gain on disposal of discontinued operations, net

19,272

19,272
Income From Discontinued Operations 20,768 2,271 18,497
Net Income $ 84,093 $ 62,823 $ 21,270
Diluted Earnings Per Average Common Share
Continuing operations $ 0.87 $ 0.84 $ 0.03
Discontinued operations 0.28 0.03 0.25
Net Income $ 1.15 $ 0.87 $ 0.28
Basic Earnings Per Average Common Share
Continuing operations $ 0.87 $ 0.84 $ 0.03
Discontinued operations 0.29 0.03 0.26
Net Income $ 1.16 $ 0.87 $ 0.29
Diluted Avg. Common Shares Outstanding 73,086 72,319 767
Basic Avg. Common Shares Outstanding 72,628 72,138 490
Dividends Per Common Share $ 0.145 $ 0.14 $ 0.005

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 12 months ending December 31, 2013 and 2012

Year-to-date
(in thousands, except per share data) 2013 2012 Change
Operating Revenues
Oil and gas operations $ 1,205,312 $ 1,089,230 $ 116,082
Natural gas distribution 533,338 451,589 81,749
Total operating revenues 1,738,650 1,540,819 197,831
Operating Expenses
Cost of gas 215,455 142,228 73,227
Operations and maintenance 562,350 458,084 104,266
Depreciation, depletion and amortization 497,381 385,453 111,928
Taxes, other than income taxes 105,268 86,801 18,467
Accretion expense 6,995 6,339 656
Total operating expenses 1,387,449 1,078,905 308,544
Operating Income 351,201 461,914 (110,713 )
Other Income (Expense)
Interest expense (69,200 ) (65,542 ) (3,658 )
Other income 16,803 4,285 12,518
Other expense (375 ) (903 ) 528
Total other expense (52,772 ) (62,160 ) 9,388
Income From Continuing Operations Before Income Taxes

298,429

399,754

(101,325

)

Income tax expense 105,282 144,534 (39,252 )
Income From Continuing Operations 193,147 255,220 (62,073 )
Discontinued Operations, net of taxes
Income (loss) from discontinued operations 7,813 (1,658 ) 9,471

Gain on disposal of discontinued operations, net

3,594 3,594
Income (Loss) From Discontinued Operations 11,407 (1,658 ) 13,065
Net Income $ 204,554 $ 253,562 $ (49,008 )
Diluted Earnings Per Average Common Share
Continuing operations $ 2.67 $ 3.53 $ (0.86 )
Discontinued operations 0.15 (0.02 ) 0.17
Net Income $ 2.82 $ 3.51 $ (0.69 )
Basic Earnings Per Average Common Share
Continuing operations $ 2.67 $ 3.54 $ (0.87 )
Discontinued operations 0.16 (0.02 ) 0.18
Net Income $ 2.83 $ 3.52 $ (0.69 )
Diluted Avg. Common Shares Outstanding 72,471 72,316 155
Basic Avg. Common Shares Outstanding 72,318 72,119 199
Dividends Per Common Share $ 0.58 $ 0.56 $ 0.02
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of December 31, 2013 and December 31, 2012
(in thousands) December 31, 2013 December 31, 2012
ASSETS
Current Assets
Cash and cash equivalents $ 5,555 $ 9,704
Accounts receivable, net of allowance 257,545 277,900
Inventories 52,330 63,994
Regulatory asset 2,756 45,515
Assets held for sale 51,104
Other 57,941 28,007
Total current assets 427,231 425,120
Property, Plant and Equipment
Oil and gas properties, net 5,087,573 4,673,886
Utility plant, net 885,509 842,643
Other property, net 30,556 25,107
Total property, plant and equipment, net 6,003,638 5,541,636
Other Assets
Regulatory asset 84,890 110,566
Long-term derivative instruments 5,439 40,577
Other 101,014 57,991
Total other assets 191,343 209,134
TOTAL ASSETS $ 6,622,212 $ 6,175,890
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Long-term debt due within one year $ 60,000 $ 50,000
Notes payable to banks 539,000 643,000
Accounts payable 250,756 257,579
Regulatory liability 49,006 45,116
Other 211,131 164,087
Total current liabilities 1,109,893 1,159,782
Long-term debt 1,343,464 1,103,528
Deferred Credits and Other Liabilities
Regulatory liability 94,125 80,404
Deferred income taxes 1,013,245 905,601
Long-term derivative instruments 398 11,305
Other 203,068 238,580
Total deferred credits and other liabilities 1,310,836 1,235,890
Total Shareholders' Equity 2,858,019 2,676,690
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 6,622,212 $ 6,175,890

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending December 31, 2013 and 2012

4th Quarter
(in thousands, except sales price data) 2013 2012 Change
Oil and Gas Operations (GAAP)
Operating revenues from continuing operations
Natural gas $ 43,332 $ 59,765 $ (16,433 )
Oil 257,125 210,770 46,355
Natural gas liquids 29,994 20,968 9,026
Other (489 ) (1,612 ) 1,123
Total (GAAP) $ 329,962 $ 289,891 $ 40,071
Oil and Gas Operations excluding

mark-to-market (Non-GAAP)

Operating revenues from continuing operations
Natural gas $ 63,861 $ 56,159 $ 7,702
Oil 236,525 188,339 48,186
Natural gas liquids 29,438 22,290 7,148
Other (489 ) (1,612 ) 1,123
Total (Non-GAAP)* $ 329,335 $ 265,176 $ 64,159
Production volumes from continuing operations
Natural gas (MMcf) 14,676 15,090 (414 )
Oil (MBbl) 2,694 2,335 359
Natural gas liquids (MMgal) 37.3 29.1 8.2
Total production volumes (MMcfe) 36,168 33,252 2,916
Total production volumes (MBOE) 6,028 5,542 486

Revenue per unit of production including effects of designated cash flow hedges

Natural gas (Mcf) $ 4.35 $ 3.72 $ 0.63
Oil (barrel) $ 87.80 $ 80.66 $ 7.14
Natural gas liquids (gallon) $ 0.79 $ 0.77 $ 0.02

Revenue per unit of production excluding effects of all derivative instruments

Natural gas (Mcf) $ 3.50 $ 3.23 $ 0.27
Oil (barrel) $ 92.84 $ 81.10 $ 11.74
Natural gas liquids (gallon) $ 0.73 $ 0.68 $ 0.05
Other data from continuing operations
Lease operating expense (LOE)
LOE and other $ 73,598 $ 65,451 $ 8,147
Production taxes 17,890 13,808 4,082
Total $ 91,488 $ 79,259 $ 12,229
Depreciation, depletion and amortization $ 120,784 $ 98,269 $ 22,515
General and administrative expense $ 25,827 $ 15,873 $ 9,954
Capital expenditures $ 212,054 $ 333,298 $ (121,244 )
Exploration expenditures $ 14,040 $ 5,974 $ 8,066
Operating income $ 76,015 $ 88,868 $ (12,853 )

*Operating revenues excluding mark-to-market gains of $627 and $24,715 in fourth quarter 2013 and 2012, respectively.

Natural Gas Distribution
Operating revenues
Residential $ 81,072 $ 76,161 $ 4,911
Commercial and industrial 33,572 30,822 2,750
Transportation 15,993 16,093 (100 )
Other 12,134 1,330 10,804
Total $ 142,771 $ 124,406 $ 18,365
Gas delivery volumes (MMcf)
Residential 4,900 4,413 487
Commercial and industrial 2,534 2,235 299
Transportation 12,801 13,271 (470 )
Total 20,235 19,919 316
Other data
Depreciation and amortization $ 11,242 $ 10,719 $ 523
Capital expenditures $ 20,979 $ 20,083 $ 896
Operating income $ 34,800 $ 22,951 $ 11,849

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 12 months ending December 31, 2013 and 2012

Year-to-date
(in thousands, except sales price data) 2013 2012 Change
Oil and Gas Operations (GAAP)
Operating revenues from continuing operations
Natural gas $ 239,643 $ 216,073 $ 23,570
Oil 865,100 788,937 76,163
Natural gas liquids 101,550 85,938 15,612
Other (981 ) (1,718 ) 737
Total (GAAP) $ 1,205,312 $ 1,089,230 $ 116,082
Oil and Gas Operations excluding

mark-to-market (Non-GAAP)

Operating revenues from continuing operations
Natural gas $ 243,562 $ 216,588 $ 26,974
Oil 908,361 730,151 178,210
Natural gas liquids 102,202 85,459 16,743
Other (981 ) (1,718 ) 737
Total (Non-GAAP)* $ 1,253,144 $ 1,030,480 $ 222,664
Production volumes from continuing operations
Natural gas (MMcf) 58,104 59,166 (1,062 )
Oil (MBbl) 10,364 8,749 1,615
Natural gas liquids (MMgal) 135.8 108.1 27.7
Total production volumes (MMcfe) 139,686 127,098 12,588
Total production volumes (MBOE) 23,281 21,183 2,098

Revenue per unit of production including effects of designated cash flow hedges

Natural gas (Mcf) $ 4.19 $ 3.66 $ 0.53
Oil (barrel) $ 87.65 $ 83.46 $ 4.19
Natural gas liquids (gallon) $ 0.75 $ 0.79 $ (0.04 )

Revenue per unit of production excluding effects of all derivative instruments

Natural gas (Mcf) $ 3.51 $ 2.69 $ 0.82
Oil (barrel) $ 92.73 $ 87.56 $ 5.17
Natural gas liquids (gallon) $ 0.67 $ 0.75 $ (0.08 )
Other data from continuing operations
Lease operating expense (LOE)
LOE and other $ 284,053 $ 224,503 $ 59,550
Production taxes 67,488 53,690 13,798
Total $ 351,541 $ 278,193 $ 73,348
Depreciation, depletion and amortization $ 453,474 $ 343,183 $ 110,291
General and administrative expense $ 107,397 $ 72,394 $ 35,003
Capital expenditures $ 1,104,745 $ 1,291,211 $ (186,466 )
Exploration expenditures $ 27,942 $ 19,356 $ 8,586
Operating income $ 257,963 $ 369,765 $ (111,082 )

* Operating revenues excluding mark-to-market loss of $47,832 and gain of $58,750 in 2013 and 2012, respectively.

Natural Gas Distribution
Operating revenues
Residential $ 340,563 $ 277,698 $ 62,865
Commercial and industrial 136,990 115,711 21,279
Transportation 61,254 58,857 2,397
Other (5,469 ) (677 ) (4,792 )
Total $ 533,338 $ 451,589 $ 81,749
Gas delivery volumes (MMcf)
Residential 20,279 16,014 4,265
Commercial and industrial 9,968 8,372 1,596
Transportation 47,534 48,106 (572 )
Total 77,781 72,492 5,289
Other data
Depreciation and amortization $ 43,907 $ 42,270 $ 1,637
Capital expenditures $ 88,769 $ 71,869 $ 16,900
Operating income $ 93,768 $ 93,216 $ 552

Source: Energen Corporation

Energen Corporation
Julie S. Ryland, 205-326-8421


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Latest news on ENERGEN CORPORATION
2d ago ENERGEN : Sets Date for 3rd Quarter 2014 Earnings Release Date, Conference Call
3d ago ENERGEN : Entry into a Material Definitive Agreement, Change in Directors or Pri..
3d ago ENERGEN : Declares Quarterly Cash Dividend
4d ago ENERGEN : Declares Quarterly Cash Dividend
4d ago ENERGEN : Change in Directors or Principal Officers (form 8-K)
10/16 ENERGEN : Schedules 3rd Quarter 2014 Earnings Release Date, Conference Call
10/13 ENERGEN : Announces 3rd Quarter 2014 Earnings Release Date, Conference Call
10/13 ENERGEN : Investment Community Meetings Slated for October 15-16
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09/25 ENERGEN : to Present at Johnson Rice 2014 Energy Conference
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