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EGN > SEC Filings for EGN > Form 10-Q on 9-May-2014All Recent SEC Filings

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Form 10-Q for ENERGEN CORP


9-May-2014

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Energen's net income totaled $53.3 million ($0.73 per diluted share) for the three months ended March 31, 2014 compared with net income of $56.7 million ($0.78 per diluted share) for the same period in the prior year. In the first quarter of 2014, Energen's income from continuing operations totaled $55.5 million ($0.76 per diluted share) and compared with income from continuing operations of $54.7 million ($0.75 per diluted share) in the same period a year ago. Loss from discontinued operations for the current-quarter period was $2.2 million as compared with income of $2.0 million from the prior-year first quarter. Energen Resources Corporation, Energen's oil and gas subsidiary, had net income for the three months ended March 31, 2014, of $10.0 million as compared with net income of $8.8 million in the same quarter in the previous year. Energen Resources generated net income from continuing operations of $12.2 million in the current quarter as compared with income of $6.8 million in the same quarter last year. This increase in net income from continuing operations was primarily the result of higher oil, natural gas liquids and natural gas production volumes (approximately $30 million after-tax), increased oil and natural gas commodity prices (approximately $5 million after-tax) and a year-over-year after-tax $4.4 million non-cash mark-to-market increase in derivatives (resulting from an after-tax $21.5 million non-cash mark-to-market loss on derivatives for the first quarter of 2014 and an after-tax $26 million non-cash mark-to-market loss on derivatives for the first quarter of 2013). Negatively affecting net income was the impact of higher depreciation, depletion and amortization (DD&A) expense (approximately $19 million after-tax), higher exploration expense (approximately $7 million after-tax), increased production taxes (approximately $4 million after-tax), and higher administrative expense (approximately $3 million after-tax). Energen's natural gas utility, Alagasco, reported net income of $43.0 million in the first quarter of 2014 compared to net income of $47.2 million in the same period last year.

Oil and Gas Operations
Revenues from continuing oil and gas operations rose 25.8 percent to $297.3 million for the three months ended March 31, 2014 largely as a result of higher production volumes, increased realized oil and natural gas commodity prices and the non-cash mark-to-market increase in derivatives partially offset by decreased realized natural gas liquids commodity prices. During the current quarter, revenue per unit of production for oil rose 1.4 percent to $86.86 per barrel, while natural gas liquids revenue per unit of production fell 2.6 percent to an average price of $0.75 per gallon. Natural gas revenue per unit of production increased 8.2 percent to $4.51 per thousand cubic feet (Mcf). Revenues per unit of production include realized prices and the effects of designated cash flow hedges and exclude the impact of the non-cash mark-to-market hedges.

Production from continuing operations for the current quarter increased largely due to higher volumes related to increased field development in certain Permian Basin liquids-rich properties partially offset by normal production declines. Oil volumes in the first quarter increased 18.9 percent to 2,751 thousand barrels (MBbl), natural gas liquids production rose 37.3 percent to 37.9 million gallons (MMgal) and natural gas production in the first quarter rose 2.2 percent to 14.1 billion cubic feet (Bcf). Oil and natural gas liquids comprised approximately 61 percent of Energen Resources' production from continuing operations for the current quarter.

Operations and maintenance (O&M) expense increased $15.1 million for the quarter. Lease operating expense (excluding production taxes) generally reflects year-over-year increases in the number of active wells resulting from Energen Resources' ongoing development, exploratory and acquisition activities. Lease operating expense (excluding production taxes) decreased $0.1 million for the quarter largely due to lower ad valorem taxes (approximately $1.9 million) and decreased equipment rental expense (approximately $1.6 million) partially offset by higher workover and repair expense (approximately $1.4 million), additional other O&M expense (approximately $1.1 million) and increased labor costs (approximately $0.6 million). On a per unit basis, the average lease operating expense (excluding production taxes) for the current quarter was $12.49 per barrel of oil equivalent (BOE) as compared to $14.25 per BOE in the same period a year ago. Administrative expense increased $4.0 million for the three months ended March 31, 2014 largely due to increased costs from the Company's benefit and performance-based compensation plans (approximately $4.1 million) and higher labor costs (approximately $1.7 million) partially offset by decreased legal expenses (approximately $1.2 million). Exploration expense increased $11.3 million in the first quarter of 2014 primarily due to higher delay rental payments and seismic costs.

Energen Resources' DD&A expense for the quarter rose $29.3 million. The average depletion rate for the current quarter was $20.52 per BOE as compared to $17.84 per BOE in the same period a year ago. The increase in the current quarter per unit DD&A rate, which contributed approximately $16.1 million to the increase in DD&A expense, was largely due to higher rates resulting from an increase in development costs and greater oil volumes as a percent of total production. Higher production volumes contributed approximately $13.1 million to the increase in DD&A expense for the quarter.


Energen Resources' expense for taxes other than income taxes was $6.0 million higher in the three months ended March 31, 2014 largely due to production-related taxes. In the quarter, higher oil, natural gas liquids and natural gas commodity market prices contributed approximately $4.1 million to the increase in production-related taxes and increased production volumes contributed approximately $1.9 million to the increase. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution
Natural gas distribution revenues increased $26.2 million for the quarter largely due to higher customer usage combined with an increase in the pass-through of gas costs partially offset by adjustments from the utility's rate setting mechanisms. During the first quarter of 2014, Alagasco had a net $16.2 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the first quarter of 2013, Alagasco had a net $2.4 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Weather, for the current quarter, that was 26.2 percent colder compared with the same period in the prior year contributed to a 25.7 percent increase in residential sales volumes and a 26.3 percent rise in commercial and industrial customer sales volumes. Transportation volumes decreased slightly in period comparisons. Increased gas purchase volumes and higher gas costs resulted in a 34.2 percent increase in cost of gas for the quarter. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco's rate schedule provides for a pass-through of gas cost fluctuations to customers without markup. Alagasco's tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco's earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense declined 4.7 percent in the current quarter primarily due to lower labor-related costs (approximately $1.9 million).

A 5.6 percent increase in depreciation expense in the current quarter was primarily due to the extension and replacement of the utility's distribution system and replacement of its support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items
Interest expense for the Company rose $0.9 million in the first quarter of 2014 largely due to the December 2013, issuance of $600 million in Senior Term Loans with a floating interest rate due March 31, 2014 through December 17, 2017. The $600 million issuance includes $400 million with a floating rate of the London Interbank Offered Rate plus 1.625 percent, currently 1.778 percent at March 31, 2014 and $200 million swapped to a fixed rate at 2.6675 percent. These increases in interest expense for 2014 were partially offset by the October 2013 repayment of $50 million of 5 percent Notes, the December 2013 repayment of the Senior Term Loans of $300 million issued in November 2011 and lower short-term borrowings. Income tax expense for the Company increased $0.4 million in the current quarter largely due to higher pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $297.0 million as compared to $261.5 million in the prior period. The Company's working capital needs were influenced by accrued taxes, commodity prices and the timing of payments and recoveries, including gas supply pass-through adjustments and refundable negative salvage costs. Working capital needs at Alagasco were additionally affected by higher gas costs and changes to storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $281.0 million for the three months ended March 31, 2014 primarily due to additions of property, plant and equipment of $289 million. Energen Resources incurred on a cash basis $273 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. Energen Resources had cash proceeds in the first quarter of $7.3 million primarily from the sale of the North Louisiana/East Texas properties. Utility capital expenditures on a cash basis totaled $15.5 million year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities and information systems.

The Company provided net cash of $13.8 million from financing activities in the year-to-date primarily due to an increase in short-term borrowings partially offset by the payment of dividends to common shareholders and the reduction of long-term debt for current maturities.


Oil and Gas Operations
The Company plans to continue investing significant capital in Energen Resources' oil and gas production operations. For 2014, the Company expects its oil and gas capital spending to total approximately $1.3 billion, primarily all of which is for existing properties. On an annual basis, the development and exploration expenditures cannot be reasonably segregated as drilling and development throughout the course of the year may change the classification of locations currently identified as exploratory.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace. Energen Resources' ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions, except as disclosed above, are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company expects to use internally generated cash flow supplemented by its credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company currently has no plans for the issuance of equity.

Discontinued Operations
In March 2014, Energen Resources completed the sale on its North Louisiana/East Texas natural gas and oil properties for $30.3 million (subject to closing adjustments). The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen Resources classified these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the first quarter of 2014 of $1.7 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months ended March 31, 2014. Energen Resources also recognized non-cash impairment writedowns on these properties in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. At December 31, 2013, proved reserves associated with Energen's North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for-sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen's Black Warrior Basin properties totaled 97 Bcf of natural gas.

Natural Gas Distribution
In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness.

Alagasco is subject to regulation by the Alabama Public Service Commission
(APSC) which established the Rate Stabilization and Equalization (RSE)
rate-setting process in 1983. Alagasco's current RSE order has a term extending through September 30, 2018 and will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco's allowed range of return on average common equity is 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. The previous allowed range of return on average common equity was 13.15 percent to 13.65 percent through December 31, 2013. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments.

On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $14.2 million, $16.3 million, $14.2 million, $22.2 million and $2.7 million for the periods January through March 2014, the years ended December 31, 2013, 2012, 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $12.4 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $28.8 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through 2019 through lower tariff rates. The total amount refundable to customers is subject to adjustments over the remaining five year period for charges made to the Enhanced Stability Reserve and


other APSC approved charges. The refunds as of March 31, 2014 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco's actual removal cost experience, combined with technology improvements and Alagasco's system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates.

Alagasco maintains an investment in storage gas that is expected to average approximately $40 million in 2014 but will vary depending upon the price of natural gas. During 2014, Alagasco plans to invest approximately $74 million in capital expenditures for the normal needs of its distribution, support systems and technology-related projects and the construction of a service center to replace the Metro Operations Center sold during 2013. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities. Alagasco also may issue long-term debt periodically to replace short-term obligations, enhance liquidity and provide for permanent financing.

In August 2013, Alagasco recorded a pre-tax gain of $10.9 million related to the sale of its Metro Operations Center which is located in Birmingham, Alabama, and has been in service since the 1940's. The Company received approximately $13.8 million pre-tax in cash from the sale of this property. During the third quarter of 2013, the gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. In conjunction with the receipt of the rate order from the APSC on December 20, 2013, Alagasco recognized the deferred revenues from this sale in the fourth quarter of 2013. Effective upon the sale of the Metro Operations Center, Alagasco leased the facility from the purchaser for a period of approximately 20 months.

Derivative Commodity Instruments
Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. At March 31, 2014, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with two of its active counterparties and in a net loss position with the remaining twelve at March 31, 2014. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.


Energen Resources entered into the following transactions for the remainder of 2014 and subsequent years:

                                                         Average Contract
Production Period                 Total Hedged Volumes        Price             Description
Oil
2014                                   7,392  MBbl          $92.65 Bbl          NYMEX Swaps
2015                                   7,260  MBbl          $89.07 Bbl          NYMEX Swaps
2015                                   1,020  MBbl*         $90.99 Bbl          NYMEX Swaps
Oil Basis Differential
2014                                     600  MBbl*        $(3.30) Bbl     WTS/WTI Basis Swaps**
2014                                   1,200  MBbl*        $(3.08) Bbl    WTI/WTI Basis Swaps***
Natural Gas Liquids
2014                                      46  MBbl*         $0.93 Gal          Liquids Swaps
Natural Gas
2014                                     7.9  Bcf           $4.55 Mcf           NYMEX Swaps
                                                                          Basin Specific Swaps -
2014                                    23.5  Bcf           $4.60 Mcf            San Juan
                                                                          Basin Specific Swaps -
2014                                     7.4  Bcf           $3.81 Mcf             Permian
                                                                          Basin Specific Swaps -
2015                                    12.0  Bcf           $4.05 Mcf            San Juan
                                                                          Basin Specific Swaps -
2015                                    11.0  Bcf*          $4.23 Mcf            San Juan
                                                                          Basin Specific Swaps -
2015                                     6.0  Bcf*          $4.20 Mcf             Permian
Natural Gas Basis Differential
2014                                     4.6  Bcf          $(0.09) Mcf     San Juan Basis Swaps
2014                                     1.5  Bcf          $(0.17) Mcf      Permian Basis Swaps

*Contract entered into subsequent to March 31, 2014 **WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing ***WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Realized prices are anticipated to be lower than New York Mercantile Exchange (NYMEX) prices primarily due to basis differences and other factors.

See Note 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for information regarding the Company's policies on fair value measurement.

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

                                           March 31, 2014
(in thousands)                    Level 2*    Level 3*     Total
Current assets                   $  (6,646 ) $ 10,003   $   3,357
Noncurrent assets                    1,192      1,446       2,638
Current liabilities                (42,531 )  (10,071 )   (52,602 )
Noncurrent liabilities                (802 )        -        (802 )
Net derivative asset (liability) $ (48,787 ) $  1,378   $ (47,409 )


                                         December 31, 2013
(in thousands)                    Level 2*    Level 3*    Total
Current assets                   $  (1,658 ) $ 19,121   $ 17,463
Noncurrent assets                    4,383      1,056      5,439
Current liabilities                (28,414 )   (1,888 )  (30,302 )
Net derivative asset (liability) $ (25,689 ) $ 18,289   $ (7,400 )

*Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

Level 3 assets and liabilities as of March 31, 2014, represent an immaterial amount of total assets and liabilities. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $18 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $18 million associated with open Level 3 mark-to-market derivative contracts. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets and requires the Commodities Futures Trading Commission (CFTC) and the Securities and Exchange Commission (SEC) to promulgate implementing rules and regulations. The Dodd-Frank Act imposes certain margin, clearing and trade execution requirements. Energen's derivative transactions qualify for the end-user exception which exempts them from certain Dodd-Frank Act margin and exchange clearing requirements pursuant to final regulations adopted by the CFTC and SEC and published in the Federal Register on July 19, 2012. However, the Company could experience increased costs and reduced liquidity in the markets as a result of the new rules and regulations, which could reduce hedging opportunities and negatively affect the Company's revenues and cash flows.

Credit Facilities and Working Capital
On October 30, 2012, Energen and Alagasco entered into $1.25 billion and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. Energen's obligations under the $1.25 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of not more than 65 percent for both the Company and Alagasco.

At March 31, 2014, the Company reported negative working capital of $771.5 million arising from current liabilities of $1,210.5 million exceeding current assets of $439.0 million. The negative working capital is primarily due to a $36 million increase in borrowings during the three months ended March 31, 2014 and a $628 million increase in borrowings during 2012 partially offset by a $104 million decrease in borrowings during 2013 under the syndicated credit facilities and in support of Energen's capital projects. Generally accepted accounting principles require short-term classification for obligations such as these that are subject to the execution of individual notes with maturity dates less than one year. The syndicated credit facilities were entered into on October 30, 2012 and have a five-year term.

Working capital of Energen is also influenced by the fair value of the Company's derivative financial instruments associated with future production. Energen's accounts receivable and accounts payable at March 31, 2014 include $3.4 million and $52.6 million, respectively, associated with its derivative financial instruments. Working capital of Alagasco is additionally impacted by the recovery and pass-through of regulatory items and the seasonality of Alagasco's business and reflects an expected pass-through to rate payers of $12.4 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates. Energen and Alagasco rely upon cash flows from operations supplemented by their syndicated credit facilities to fund working . . .

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