BIRMINGHAM, Ala.--(BUSINESS WIRE)--Energen Corporation (NYSE: EGN) announced today that a 40 percent increase in oil and natural gas liquids (NGL) production and a 12 percent higher realized oil price were major contributors to the energy company’s first quarter 2012 net income of $57.4 million, or 79 cents per diluted share. Excluding non-cash items, adjusted net income (a non-GAAP measure) totaled $96.1 million, or $1.33 per diluted share. See “Non-GAAP Financial Measures” for explanation and reconciliation. Non-cash items in the quarter were mark-to-market losses on certain financial commodity contracts of $40.7 million ($25.3 million after tax, or 35 cents per diluted share) and a commodity price-related write-down of natural gas properties in East Texas of $21.5 million (13.4 million after tax, or 19 cents per diluted share). Prior-year results totaled $94.3 million, or $1.30 per diluted share.
Consolidated adjusted EBITDA (a non-GAAP measure) totaled $262.8 million and compared with $222.1 million in the prior-year first quarter. Energen’s oil and gas exploration and production company, Energen Resources Corporation, had adjusted EBITDA of $173.3 million in the first quarter of 2012 and $136.9 million in the same period a year ago. See “Non-GAAP Financial Measures” for explanations and reconciliation.
3rd Bone Spring Results Continue to Exceed Expectations
Energen Resources’ 3rd Bone Spring program continued to generate improved well performance in 2012, particularly now that the company has focused its operations on its core acreage east of the Pecos River in Ward, Winkler, and Loving counties in west Texas. The company’s 3rd Bone Spring drilling programs in 2012 and 2013 will be concentrated in this core area.
Energen Resources also is adding 4 net wells to its 2012 drilling schedule; this brings the total number of wells to be drilled in the horizontal 3rd Bone Spring play in the Delaware Basin to 47 gross (43 net) wells. During the first quarter, Energen Resources drilled 11 gross (10 net) wells. The company plans to continue running 5-7 rigs in the Delaware Basin in 2012.
Energen tested 7 gross (6.5 net) 3rd Bone Spring wells in the first three months of 2012. The initial stabilized rates of the wells ranged from 514 barrel of oil equivalents per day (61% oil) to 1,737 BOE per day (76% oil), with an average of 1,004 BOE/day (73% oil). At 1,737 BOE/day, this Ward County well has become the company’s top initial performer; the well was tested on a 16/64” choke at a pressure of 4,400 PSI. Initial stabilized rates reflect consistent flow rates after clean-up of stimulation fluid. The five first quarter wells with sufficient production history had a 30-day average (gross) production rate of 783 BOE/day (72% oil).
To better reflect the gross reserve potential of 3rd Bone Spring wells to be drilled in this core area east of the Pecos River over the next several years, Energen has adjusted the estimated ultimate recovery (EUR) to an average 475,000 BOE per well; the company’s net revenue interest is 75 percent. The estimated product mix is 66 percent oil, 18 percent NGL, and 16 percent dry gas.
At $100 per barrel of oil and $4 per Mcf of natural gas, Energen estimates that its 3rd Bone Spring program over the next several years will generate a 72 percent before-tax rate of return. A post-plant type curve and cumulative production curve for the wells currently scheduled to be drilled in 2012-14 is available on the company’s Website: www.energen.com.
Additionally, the company expects to realize cost savings for the remainder of 2012 associated with continued stimulation optimization and a water recycling program. The company’s targeted cost to drill and complete a well in the 3rd Bone Spring play for the remainder of 2012 is $6.9 million. This drill and complete cost reflects 4,400-foot lateral lengths and 10-11 frac stages.
Energen Resources has approximately 85,000 net acres in the Delaware Basin thought to be prospective for the 3rd Bone Spring sand; 70,500 of those acres remain undeveloped. On the east side of the Pecos River, the company’s net acreage position is 33,000, with 17,300 undeveloped. Based on the high likelihood of 160-acre spacing, Energen Resources estimates that it has 92 potential locations remaining to be drilled.
Vertical Wolfberry Wells in Midland Basin Performing to Expectations
Energen Resources’ vertical Wolfberry program in the Midland Basin continues to perform to expectations. In 2012, the company plans to drill 177 gross (170 net) wells in this developmental play as it closely monitors the potential for horizontal Wolfcamp and Cline on its acreage position. During the first quarter, Energen Resources drilled 33 gross (32 net) wells. The company plans to continue running 7-8 rigs in the Midland Basin in 2012.
Energen tested 51 gross (50 net) Wolfberry wells in the first three months of 2012. The initial stabilized rates of the wells averaged 88 BOE/day (73% oil) and 30-day average (gross) production rates of 73 BOE/day (77% oil).
Wolfberry average EURs are 155,000 BOE per well; the company’s net revenue interest is 75 percent. The estimated product mix is 61 percent oil, 23 percent NGL, and 16 percent dry gas. At $100 per barrel of oil and $4 per Mcf of natural gas, Energen estimates that its vertical Wolfberry program over the next several years will generate a 33 percent before-tax rate of return. A post-plant type curve for the wells currently scheduled to be drilled in 2012-14 as well as a cumulative production curve is available on the company’s Website: www.energen.com.
The company’s estimated cost to drill and complete a vertical Wolfberry well in 2012 is $2.3 million. This drill and complete cost reflects 6-8 frac stages.
Energen Resources has approximately 49,000 net acres in the Midland Basin that are prospective for the vertical Wolfberry play; approximately 33,000 net acres remain undeveloped. Based on 40-acre spacing, Energen Resources estimates that it has 825 potential locations remaining to be drilled. The potential for 20-acre spacing across its acreage position could add 675 potential drilling locations.
3P Reserves at Year-End 2011 Total Record 941 MMBOE
Energen’s proved, probable, and possible reserves at the end of the 2011 totaled a record 941 MMBOE. As reported in January, Energen’s year-end proved reserves totaled 343 MMBOE; probable reserves totaled 182 MMBOE and possible reserves totaled 416 for total unproved reserves of 598 MMBOE.
The company’s unproved reserves included 8 MMBOE added through acquisition since March 31, 2011, as well as 20 MMBOE associated with 160-acre down-spacing in the 3rd Bone Spring play in our areas of planned operation in 2012-2014. Since March 31, 2011, approximately 45 MMBOE of unproved reserves were reclassified as proved reserves.
Potential not yet reflected in Energen’s unproved reserves include Wolfberry downspacing, horizontal Wolfcamp, horizontal Cline, and horizontal Avalon shale.
Oil and natural gas liquids now comprise more than 47 percent of Energen’s 3P reserves, and the Permian Basis is home to 43 percent of 3P reserves.
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YE2011 3P Reserves (MMBOE) |
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| Basin | Proved | Probable | Possible | Total Unproved | 3P Total | |||||
| Permian | 183.6 | 96.4 | 124.8 | 221.3 | 404.9 | |||||
| San Juan | 129.6 | 81.5 | 286.2 | 367.7 | 497.3 | |||||
| Other | 29.9 | 3.9 | 4.8 | 8.7 | 38.6 | |||||
| TOTAL | 343.1 | 181.8 | 415.8 | 597.7 | 940.8 | |||||
All year-end 2011 reserves were priced at $4.12 per Mcf of gas (vs. $4.38 per Mcf in the prior year), $96.19 per barrel of oil (vs. $79.43 per barrel in the prior year) and $1.23 cents per gallon of NGL (vs. 98 cents per gallon in the prior year).
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.
2012 Production, Capital, and Other Guidance
Energen has raised its guidance range for 2012 after-tax cash flows to $795-$824 million on a consolidated basis (prior guidance $764-$793 million), with Energen Resources’ after-tax cash flows estimated to be $694-$723 million in 2012. The increase is due in large part to increased oil production partially offset by lower realized commodity prices. The company’s guidance excludes non-cash mark-to-market impacts.
Energen estimates that the average realized sales price of oil will decline from the previous guidance primarily due to the potential for a wider WTI-Midland to WTI-Cushing differential. This differential has widened since the end of 2011 from less than $1.00 per barrel to approximately $3 per barrel today; during April 2012, the differential widened to more than $9.00 per barrel for a brief period.
Energen’s sweet oil and unhedged sour oil production (approximately 65 percent of estimated oil production for the remainder of 2012) is exposed to this differential; however, as additional, planned pipeline capacity is added this year and in 2013, the company expects the differential to move closer to its historical price of less than $1.00 per barrel.
Energen Resources’ estimated 2012 production is 24.5 MMBOE, up 2 percent from previous guidance. This increase largely is due to better-than-expected 3rd Bone Spring production and the addition of existing production from a February Wolfberry acquisition. Partially offsetting these gains is a decrease in natural gas production resulting primarily from the previously announced capital spending cuts in the San Juan Basin in the second half of the year.
Capital spending excluding acquisitions is now estimated to be approximately $950 million (prior guidance $890 million). This $60 million increase primarily is related to the planned drilling of an additional four net 3rd Bone Spring wells in the Delaware Basin, increased acquisition-related development in the Midland Basin, and higher investment in non-operated Permian properties.
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Estimated 2012 Production and Capital (excluding acquisitions) |
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| Area | Production (MMBOE) | Capital ($MM) | |||
| Permian Basin | |||||
| Wolfberry | 4.1 | $ | 420 | ||
| 3rd Bone Spring/Delaware | 3.0 | $ | 350 | ||
| Waterflood/Conventional | 5.0 | $ | 145 | ||
| San Juan Basin | 9.7 | $ | 32 | ||
| Other | 2.7 | $ | 3 | ||
Total oil production in 2012 is estimated to be 9.0 MMBOE, up from 8.5 MMBOE, while NGL and natural gas volumes are estimated to remain 2.8 MMBOE and 12.7 MMBOE, respectively.
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Energen’s estimated exploration and production expenses per BOE in 2012 are: |
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| Lease Operating Expense | |||
| Base, marketing, and transportation | $ | 9.25 | |
| Production taxes | $ | 2.40 | |
| DD&A expense* | $ | 16.00 | |
| Unidentified exploration expense | $ | 1.00 | |
| General & Administrative expense, net | $ | 2.75 | |
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Interest expense |
$ | 2.00 | |
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* Excludes the non-cash impairment of East Texas natural gas properties in the first quarter of 2012 |
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Approximately 60 percent of the company’s total estimated production for the remainder of 2012 is hedged. Assumed prices applicable to Energen’s unhedged oil and natural gas volumes for the remainder of the year are $95 per barrel and $3 per Mcf; the assumed price for unhedged NGL production is $1.06 per gallon.
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Energen Resources’ hedge position for the remainder of 2012 is as follows: |
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Commodity |
Hedge Volumes |
Estimated Production |
Hedge % |
NYMEXe Price |
||||
|
Oil |
5.3 MMBO |
7.1 MMBO |
75 % |
$ 88.87 |
||||
|
NGL |
44.2 MMgal |
92.7 MMgal |
48 % |
$ 0.98 |
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Natural Gas |
29.0 Bcf |
57.1 Bcf |
51 % |
$ 4.88 |
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NOTE: Reflects known actuals |
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Energen Resources’ oil and natural gas hedge positions by hedge type for 2012 are as follows: |
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|
Oil Hedges |
Volumes |
Assumed Differentials |
NYMEXe Price |
|||
|
Sour Oil (WTS) |
2,312 MBO |
$ 3.50 per barrel |
$ 83.69 per barrel |
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|
NYMEX |
2,995 MBO |
– |
$ 92.86 per barrel |
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|
Gas Hedges |
Volumes |
Assumed Differential |
NYMEXe Price |
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|
San Juan Basin |
21.0 Bcf |
$ 0.20 per Mcf |
$ 4.81 per Mcf |
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|
NYMEX |
7.9 Bcf |
– |
$ 5.07 per Mcf |
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NOTE: Reflects known actuals |
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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, including the WTI-Midland to WTI-Cushing differential that currently is greater than its 10-year historical average. Average realized NGL prices will be net of transportation and fractionation fees. For production associated with basin-specific contracts, Energen Resources will receive the contracted hedge price. Energen may hedge basis differentials as applicable.
In the tables above, basin-specific contract prices were converted for comparability purposes to a NYMEX-equivalent price by adding to them Energen Resources' assumed basis differentials. Gains and losses from the change in fair value of derivative instruments that do not qualify for cash flow hedge accounting are reported in operating revenues each applicable reporting period and can cause non-cash earnings volatility.
Sensitivity of 2012 Cash Flows to Changes in Commodity Prices
Changes in commodity prices for the remainder of the year are estimated to have the following impact on Energen's 2012 cash flows:
- Every 10-cent change in the average NYMEX price of gas from $3.00 represents an estimated net impact of $1.25 million.
- Every $1.00 change in the average NYMEX price of oil from $95 per barrel represents an estimated net impact of $850,000.
- Every 1-cent change in the average price of liquids from $1.06 per gallon represents an estimated net impact of approximately $215,000.
Price-related events such as substantial basis differential changes could cause earnings sensitivities to be materially different from those outlined above.
Alabama Gas Corporation (Alagasco), the company’s utility subsidiary, has the opportunity to earn a return on average equity that is estimated to be approximately $360 million in 2012. Alagasco is expected to invest approximately $70 million of capital in 2012 for normal distribution and support system needs and technology-related projects designed to improve customer service.
EXPLORATION & PRODUCTION FINANCIAL RESULTS
Excluding non-cash items (non-GAAP), Energen Resources’ adjusted first quarter net income totaled $48.2 million in 2012 as compared with $49.7 million in 2011. While Energen Resources’ production increased 22 percent year-over-year, including a 43 percent increase in oil production and a 32 percent increase in NGL production, net income was negatively affected by a 29 percent decline in realized natural gas prices, higher LOE, increased DD&A expense, and increased interest expense.
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Average Realized Sales Prices |
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| Commodity | 1Q12 | 1Q11 | Change | ||||||
| Oil (per barrel) | $ | 85.12 | $ | 75.70 | 12.4 | % | |||
| NGL (per gallon) | $ | 0.87 | $ | 0.89 | (2.2 | ) % | |||
| Natural Gas (per Mcf) | $ | 3.94 | $ | 5.52 | (28.6 | ) % | |||
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Production |
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| Commodity | 1Q12 | 1Q11 | Change | ||||
| Oil (MBO) | 1,953 | 1,364 | 43.2 | % | |||
| NGL (MMgal) | 26.0 | 19.7 | 32.0 | % | |||
| Natural Gas (Bcf) | 19.1 | 17.3 | 10.4 | % | |||
| Total (MBOE) | 5,755 | 4,723 | 21.9 | % | |||
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Production by Area (MBOE) |
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| Area | 1Q12 | 1Q11 | Change | ||||
| Permian Basin | 2,490 | 1,640 | 51.8 | % | |||
| San Juan Basin | 2,499 | 2,342 | 6.7 | % | |||
| Other | 766 | 741 | 3.4 | % | |||
Permian Basin production in the first quarter of 2012 increased year-over-year by 52 percent largely due to the company’s 2011 Wolfberry acquisitions and associated development and increased 3rd Bone Spring development in the Delaware Basin. San Juan Basin production increased 7 percent primarily due to new well development. A slight increase in production in other areas was small in terms of volumes and reflected the company’s capital investment focus in its Permian Basin oil properties.
Total LOE per unit in the first quarter of 2012 decreased approximately 2 percent from the same period last year to $12.30 per BOE. Base LOE and marketing and transportation expenses decreased about 1 percent to $9.84 per BOE. Commodity price-drive production taxes declined approximately 5 percent on a per-unit basis.
DD&A expense per unit in the first quarter of 2012, excluding the non-cash write-down of gas properties in East Texas, increased approximately 35 percent from the same period last year to $14.44 per BOE; this increase generally reflects year-over-year increases in development costs and production.
Per-unit net G&A expense decreased approximately 22 percent in the first quarter of 2012 to $3.12 per BOE primarily due to decreased labor and performance-based compensation.
Alagasco: Energen’s natural gas utility generated first quarter net income of $46.9 million in 2012. This slight increase from $44.2 million in the first quarter of 2011 primarily is due to the utility’s ability to earn on a higher level of equity partially offset by the timing of rate recovery.
ENERGEN MAINTAINS STRONG HEDGE POSITIONS THROUGH 2014
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Energen Resources has hedges in place through 2014 to help protect its future cash flows from commodity price volatility. The company’s current hedge position for 2013 is as follows: |
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Commodity |
Hedge Volumes |
Estimated Production |
NYMEXe Price |
|||
|
Oil |
8.1 MMBO |
10.0-10.5 MMBO |
$ 90.52 per barrel |
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NGL |
44.5 MMgal |
126.0-147.0 MMgal |
$ 1.02 per gallon |
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|
Natural Gas |
38.9 Bcf |
72.0-78.0 Bcf |
$ 5.04 per Mcf |
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Energen Resources’ oil and natural gas hedge positions by hedge type for 2013 are as follows: |
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|
Oil Hedges |
Volumes |
Assumed Differential |
NYMEXe Price |
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|
Sour Oil (WTS) |
2.8 MMBO |
$ 3.00 per barrel |
$ 85.34 per barrel |
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|
NYMEX |
5.3 MMBO |
– |
$ 93.20 per barrel |
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|
Gas Hedges |
Volumes |
Assumed Differential |
NYMEXe Price |
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|
San Juan Basin |
27.7 Bcf |
$ 0.30 per Mcf |
$ 5.06 per Mcf |
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|
NYMEX |
11.2 Bcf |
– |
$ 4.99 per Mcf |
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Energen Resources’ 2014 hedges are as follows: |
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Commodity |
Hedge Volumes |
NYMEXe Price |
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|
Oil |
7.9 MMBO |
$ 92.70 per barrel |
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|
Natural Gas |
29.8 Bcf |
$ 5.07 per Mcf |
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Energen Resources’ natural gas hedge positions by hedge type for 2014 are as follows: |
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|
Gas Hedges |
Volumes |
Assumed Differential |
NYMEXe Price |
|
San Juan Basin |
22.0 Bcf |
$ 0.30 per Mcf |
$ 5.18 per Mcf |
|
NYMEX |
7.8 Bcf |
– |
$ 4.76 per Mcf |
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, including the WTI-Midland to WTI-Cushing differential that currently is greater than its 10-year historical average. Average realized NGL prices will be net of transportation and fractionation fees.
For production associated with basin-specific contracts, Energen Resources will receive the contracted hedge price. Energen may hedge basis differentials as applicable. In the tables above, basin-specific contract prices were converted for comparability purposes to a NYMEX-equivalent price by adding to them Energen Resources' assumed basis differentials. Gains and losses from the change in fair value of derivative instruments that do not qualify for cash flow hedge accounting are reported in operating revenues each applicable reporting period and, therefore, can cause non-cash earnings volatility.
ANNUAL MEETING
Energen will host its Annual Meeting of Shareholders today, April 25, at 10:30 a.m. EDT. A live audio Webcast of the Annual Meeting as well as the replay may be accessed via www.energen.com.
CONFERENCE CALL
Energen will hold its quarterly conference call today, April 25, at 3:00 p.m. EDT. Members of the investment community may participate by calling 1-866-821-5457 (reference Energen earnings call). A live audio Webcast of the program as well as the replay may be accessed via 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 950 million barrels of oil-equivalent proved, probable, and possible reserves. These all-domestic reserves are located mainly in the Permian and San Juan basins. 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.
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Non-GAAP Financial Measures
The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures. Adjusted Net Income is a Non-GAAP financial measure which excludes certain non-cash mark-to-market derivative financial instruments and a commodity price-related write-down of natural gas properties. 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. |
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| Year-to-Date Ended 3/31/2012 | |||||
| Consolidated Net Income ($ in millions except per share data) | Net Income | Per Diluted Share | |||
| Net Income (GAAP) | 57.4 | 0.79 | |||
| Non-cash mark-to-market losses (net of $15.4 tax) | 25.3 | 0.35 | |||
| Non-cash write-down of natural gas properties (net of $8.1 tax) | 13.4 | 0.19 | |||
| Adjusted Net Income (Non-GAAP) | 96.1 | 1.33 | |||
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Year-to-Date |
|||||
| Energen Resources Net Income ($ in millions) | Net Income | ||||
| Net Income (GAAP) | 9.5 | ||||
| Non-cash mark-to-market losses (net of $15.4 tax) | 25.3 |
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| Non-cash write-down of natural gas properties (net of $8.1 tax) | 13.4 | ||||
| Adjusted Net Income (Non-GAAP) | 48.2 | ||||
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Non-GAAP Financial Measures
The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures. Earnings before interest, taxes, depreciation, and amortization (EBITDA) is a Non-GAAP financial measure. Energen believes this measure allows analysts and investors to understand the financial performance of the company by computing earnings from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing profitability between the company and other oil and gas producing companies. Adjusted EBITA excludes certain non-cash mark-to-market derivative financial instruments and a commodity price-related write-down of natural gas properties. |
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| Reconciliation To GAAP Information | Year-to-Date Ended 3/31 | |||
| ($ in millions) | 2011 | 2012 | ||
| Consolidated Net Income (GAAP) | 94.3 | 57.4 | ||
| Interest expense | 9.4 | 15.4 | ||
| Income tax expense | 57.3 | 33.3 | ||
| Depreciation, depletion and amortization | 61.1 | 94.5 | ||
| EBITDA (Non-GAAP) | 222.1 | 200.6 | ||
| Adjustment for asset impairment | - | 21.5 | ||
| Adjustment for mark-to-market losses | - | 40.7 | ||
| Consolidated Adjusted EBITDA (Non-GAAP) | 222.1 | 262.8 | ||
| Reconciliation To GAAP Information | Year-to-Date Ended 3/31 | |||
| ($ in millions) | 2011 | 2012 | ||
| Energen Resources Net Income (GAAP) | 49.7 | 9.5 | ||
| Interest expense | 5.9 | 11.5 | ||
| Income tax expense | 29.9 | 6.0 | ||
| Depreciation, depletion and amortization | 51.4 | 84.1 | ||
| Energen Resources EBITDA (Non-GAAP) | 136.9 | 111.1 | ||
| Adjustment for asset impairment | - | 21.5 | ||
| Adjustment for mark-to-market losses | - | 40.7 | ||
| Energen Resources Adjusted EBITDA (Non-GAAP) | 136.9 | 173.3 | ||
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Non-GAAP Financial Measures
The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures. After-tax Cash Flows is a Non-GAAP financial measure. 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. |
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| Reconciliation To GAAP Information | Years Ended 12/31 | |||||||||||
| ($ in millions) | 2010 Actual | 2011 Actual | 2012 Estimate (e) | |||||||||
| Consolidated Net Income (Before asset impairment) | 291 | 260 | 235 | 264 | ||||||||
| Asset impairment | - | - | (14 | ) | (14 | ) | ||||||
| Consolidated Net Income (GAAP) | 291 | 260 | 221 | 250 | ||||||||
| Depreciation, depletion and amortization (Including asset impairment) | 248 | 284 | 461 | 461 | ||||||||
| Deferred income taxes, net | 134 | 129 | 113 | 113 | ||||||||
| After-tax Cash Flows (Non-GAAP) | 673 | 673 | 795 | 824 | ||||||||
| Changes in assets and liabilities and other adjustments | (2 | ) | 89 | 15 | 15 | |||||||
| Net Cash Provided by Operating Activities (GAAP) | 671 | 762 | 810 | 839 | ||||||||
| Reconciliation To GAAP Information | Years Ended 12/31 | |||||||||||
| ($ in millions) | 2010 Actual | 2011 Actual | 2012 Estimate (e) | |||||||||
| Net Cash Provided by Operating Activities (GAAP) | 671 | 762 | 810 | 839 | ||||||||
| Changes in assets and liabilities and other adjustments | (69 | ) | 25 | (15 | ) | (15 | ) | |||||
| After-tax Cash Flow (Non-GAAP) | 602 | 787 | 795 | 824 | ||||||||
| Less: AGC cash flows from operations and other | (94 | ) | (107 | ) | (101 | ) | (101 | ) | ||||
| Adj. Cash Flows from Operations Excluding Alagasco (Non-GAAP) | 508 | 680 | 694 | 723 | ||||||||
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(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. |
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CONSOLIDATED BALANCE SHEETS (UNAUDITED) As of March 31, 2012 and December 31, 2011 |
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| 1st Quarter | ||||||||||||
| (in thousands, except per share data) | 2012 | 2011 | Change | |||||||||
| Operating Revenues | ||||||||||||
| Oil and gas operations | $ | 223,957 | $ | 216,792 | $ | 7,165 | ||||||
| Natural gas distribution | 194,487 | 269,572 | (75,085 | ) | ||||||||
| Total operating revenues | 418,444 | 486,364 | (67,920 | ) | ||||||||
| Operating Expenses | ||||||||||||
| Cost of gas | 59,586 | 131,749 | (72,163 | ) | ||||||||
| Operations and maintenance | 110,561 | 103,782 | 6,779 | |||||||||
| Depreciation, depletion and amortization | 94,534 | 61,128 | 33,406 | |||||||||
| Asset impairment | 21,545 |
- |
21,545 | |||||||||
| Taxes, other than income taxes | 26,235 | 28,175 | (1,940 | ) | ||||||||
| Accretion expense | 1,813 | 1,649 | 164 | |||||||||
| Total operating expenses | 314,274 | 326,483 | (12,209 | ) | ||||||||
| Operating Income | 104,170 | 159,881 | (55,711 | ) | ||||||||
| Other Income (Expense) | ||||||||||||
| Interest expense | (15,425 | ) | (9,404 | ) | (6,021 | ) | ||||||
| Other income | 2,032 | 1,230 | 802 | |||||||||
| Other expense | (113 | ) | (163 | ) | 50 | |||||||
| Total other expense | (13,506 | ) | (8,337 | ) | (5,169 | ) | ||||||
| Income Before Income Taxes | 90,664 | 151,544 | (60,880 | ) | ||||||||
| Income tax expense | 33,258 | 57,276 | (24,018 | ) | ||||||||
| Net Income | $ | 57,406 | $ | 94,268 | $ | (36,862 | ) | |||||
| Diluted Earnings Per Average Common Share | $ | 0.79 | $ | 1.30 | $ | (0.51 | ) | |||||
| Basic Earnings Per Average Common Share | $ | 0.80 | $ | 1.31 | $ | (0.51 | ) | |||||
| Diluted Avg. Common Shares Outstanding | 72,326 | 72,240 | 86 | |||||||||
| Basic Avg. Common Shares Outstanding | 72,102 | 72,001 | 101 | |||||||||
| Dividends Per Common Share | $ | 0.14 | $ | 0.135 | $ | 0.005 | ||||||
|
CONSOLIDATED BALANCE SHEETS (UNAUDITED) As of March 31, 2012 and December 31, 2011 |
||||||
| (in thousands) | March 31, 2012 | December 31, 2011 | ||||
| ASSETS | ||||||
| Current Assets | ||||||
| Cash and cash equivalents | $ | 49,618 | $ | 9,541 | ||
| Accounts receivable, net of allowance | 203,642 | 231,925 | ||||
| Inventories | 72,539 | 74,012 | ||||
| Regulatory asset | 54,790 | 57,143 | ||||
| Other | 55,914 | 71,547 | ||||
| Total current assets |
436,503 |
444,168 | ||||
| Property, Plant and Equipment | ||||||
| Oil and gas properties, net | 4,005,163 | 3,783,842 | ||||
| Utility plant, net | 818,420 | 813,428 | ||||
| Other property, net | 23,827 | 23,506 | ||||
|
Total property, plant and equipment, net |
4,847,410 | 4,620,776 | ||||
| Other Assets | ||||||
| Regulatory asset | 91,478 | 95,633 | ||||
| Long-term derivative instruments | 10,608 | 31,056 | ||||
| Other | 46,773 | 45,783 | ||||
| Total other assets | 148,859 | 172,472 | ||||
| TOTAL ASSETS | $ | 5,432,772 | $ | 5,237,416 | ||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||
| Current Liabilities | ||||||
| Long-term debt due within one year | $ | 1,000 | $ | 1,000 | ||
| Notes payable to banks | 165,000 | 15,000 | ||||
| Accounts payable | 340,633 | 302,048 | ||||
| Regulatory liability | 30,049 | 58,279 | ||||
| Other | 137,349 | 167,552 | ||||
| Total current liabilities | 674,031 | 543,879 | ||||
| Long-term debt | 1,153,686 | 1,153,700 | ||||
| Deferred Credits and Other Liabilities | ||||||
| Regulatory liability | 74,159 | 87,234 | ||||
| Deferred income taxes | 813,451 | 806,127 | ||||
| Long-term derivative instruments | 61,066 | 34,663 | ||||
| Other | 182,555 | 179,650 | ||||
| Total deferred credits and other liabilities | 1,131,231 | 1,107,674 | ||||
| Total Shareholders’ Equity | 2,473,824 | 2,432,163 | ||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 5,432,772 | $ | 5,237,416 | ||
|
SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 3 months ending March 31, 2012 and 2011 |
|||||||||
| 1st Quarter | |||||||||
| (in thousands, except sales price data) | 2012 | 2011 | Change | ||||||
| Oil and Gas Operations | |||||||||
| Operating revenues | |||||||||
| Natural gas | $ | 75,580 | $ | 95,599 | $ | (20,019) | |||
| Oil | 124,314 | 103,256 | 21,058 | ||||||
| Natural gas liquids | 23,712 | 17,533 | 6,179 | ||||||
| Other | 351 | 404 | (53) | ||||||
| Total | $ | 223,957 | $ | 216,792 | $ | 7,165 | |||
| Production volumes | |||||||||
| Natural gas (MMcf) | 19,092 | 17,334 | 1,758 | ||||||
| Oil (MBbl) | 1,953 | 1,364 | 589 | ||||||
| Natural gas liquids (MMgal) | 26.0 | 19.7 | 6.3 | ||||||
| Total production volumes (MMcfe) | 34,530 | 28,338 | 6,192 | ||||||
| Total production volumes (MBOE) | 5,755 | 4,723 | 1,032 | ||||||
| Revenue per unit of production including effects of all derivative instruments | |||||||||
| Natural gas (Mcf) | $ | 3.96 | $ | 5.52 | $ | (1.56) | |||
| Oil (barrel) | $ | 63.65 | $ | 75.70 | $ | (12.05) | |||
| Natural gas liquids (gallon) | $ | 0.91 | $ | 0.89 | $ | 0.02 | |||
| Revenue per unit of production including effects of qualifying cash flow hedges | |||||||||
| Natural gas (Mcf) | $ | 3.94 | $ | 5.52 | $ | (1.58) | |||
| Oil (barrel) | $ | 85.12 | $ | 75.70 | $ | 9.42 | |||
| Natural gas liquids (gallon) | $ | 0.87 | $ | 0.89 | $ | (0.02) | |||
|
Revenue per unit of production excluding effects of
all derivative instruments |
|||||||||
| Natural gas (Mcf) | $ | 2.69 | $ | 4.01 | $ | (1.32) | |||
| Oil (barrel) | $ | 77.12 | $ | 88.67 | $ | (11.55) | |||
| Natural gas liquids (gallon) | $ | 0.99 | $ | 1.01 | $ | (0.02) | |||
| Other data | |||||||||
| Lease operating expense (LOE) | |||||||||
| LOE and other | $ | 56,612 | $ | 46,945 | $ | 9,667 | |||
| Production taxes | 14,162 | 12,283 | 1,879 | ||||||
| Total | $ | 70,774 | $ | 59,228 | $ | 11,546 | |||
| Depreciation, depletion and amortization | $ | 84,088 | $ | 51,348 | $ | 32,740 | |||
| Asset impairment | $ | 21,545 | $ |
- |
$ | 21,545 | |||
| General and administrative expense | $ | 17,943 | $ | 18,894 | $ | (951) | |||
| Capital expenditures | $ | 340,967 | $ | 140,323 | $ | 200,644 | |||
| Exploration expenditures | $ | 1,789 | $ | 614 | $ | 1,175 | |||
| Operating income | $ | 26,005 | $ | 85,059 | $ | (59,054) | |||
|
Natural Gas Distribution |
|||||||||
| Operating revenues | |||||||||
| Residential | $ | 130,509 | $ | 187,674 | $ | (57,165) | |||
| Commercial and industrial | 46,756 | 66,906 | (20,150) | ||||||
| Transportation | 15,598 | 16,493 | (895) | ||||||
| Other | 1,624 | (1,501) | 3,125 | ||||||
| Total | $ | 194,487 | $ | 269,572 | $ | (75,085) | |||
| Gas delivery volumes (MMcf) | |||||||||
| Residential | 8,238 | 12,591 | (4,353) | ||||||
| Commercial and industrial | 3,442 | 5,000 | (1,558) | ||||||
| Transportation | 12,036 | 12,970 | (934) | ||||||
| Total | 23,716 | 30,561 | (6,845) | ||||||
| Other data | |||||||||
| Depreciation and amortization | $ | 10,446 | $ | 9,780 | $ | 666 | |||
| Capital expenditures | $ | 14,943 | $ | 13,540 | $ | 1,403 | |||
| Operating income | $ | 78,560 | $ | 75,059 | $ | 3,501 | |||