ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CRITICAL ACCOUNTING POLICIES

The Company’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Management has identified the following critical accounting policies in the application of existing accounting standards or in the implementation of new standards that involve significant judgments and estimates by the Company. The application of these accounting policies necessarily requires managements’ most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements:

Oil and Gas Operations

Accounting for Natural Gas and Oil Producing Activities and Related Reserves: The Company utilizes the successful efforts method of accounting for its natural gas and oil producing activities. Under this accounting method, acquisition and development costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of total proved and proved developed reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and gas reserves have been determined by Company engineers. Independent oil and gas reservoir engineers have reviewed the estimates of proved reserves of natural gas, crude oil and natural gas liquids attributed to the Company’s net interests in oil and gas properties as of December 31, 2005. The independent reservoir engineers have issued reports covering approximately 91 percent of the Company’s ending proved reserves and in their judgment these estimates are reasonable in the aggregate. The Company’s production of undeveloped reserves requires the installation or completion of related infrastructure facilities such as pipelines and the drilling of development wells.

Changes in oil and gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated reserves held by the Company. If reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the property’s book value if an impairment is warranted. The table below reflects the estimated increase in 2006 depreciation, depletion and amortization expense associated with assumed downward changes in oil and gas reserve quantities from the reported amounts at December 31, 2005.

Asset Impairments: Oil and gas developed properties periodically are assessed for possible impairment, generally on a field-by-field basis, using the estimated undiscounted future cash flows of each field. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. The Company monitors its oil and gas properties as well as the market and business environments in which it operates and makes assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, substantial commodity price declines, unanticipated increased operating costs, and lower-than-expected production performance. If a material event occurs, Energen’s oil and gas subsidiary, Energen Resources Corporation, makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, the Company will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows.

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Cash flow and fair value estimates require Energen Resources to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These variables can, and often do, differ from the estimates and can have a positive or negative impact on the Company’s need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact the Company’s original and ongoing assessments of potential impairment.

Energen Resources adheres to Statement of Financial Accounting Standards (SFAS) No.19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” for recognizing any impairment of capitalized costs to unproved properties. The greatest portion of these costs generally relates to the acquisition of leasehold costs. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. The Company considers a combination of geologic and engineering factors to evaluate the need for impairment of these costs.

Derivatives: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended requires all derivatives to be recognized on the balance sheet and measured at fair value. Realized gains and losses from derivatives designated as cash flow hedges are recognized in oil and gas production revenues when the forecasted transaction occurs. Energen Resources from time to time enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. SFAS No. 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Company’s financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred.

Natural Gas Distribution

Regulated Operations: Alabama Gas Corporation (Alagasco), Energen’s utility subsidiary, applies SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” to its regulated operations. This standard requires a cost to be capitalized as a regulatory asset that otherwise would be charged to expense if it is probable that the cost is recoverable in the future through regulated rates. Likewise, if current recovery is provided for a cost that will be incurred in the future, SFAS No. 71 requires the cost to be recognized as a regulatory liability. The Company anticipates SFAS No. 71 will continue as the applicable accounting standard for its regulated operations. Alagasco’s rate setting methodology, Rate Stabilization and Equalization, has been in effect since 1983.

Consolidated

Employee Pension Plans: The Company calculates net periodic pension expense and liabilities on an actuarial basis under the provisions of SFAS No. 87, “Employers’ Accounting for Pensions.” The key assumptions used in determining these calculations are disclosed in Note 5, Employee Benefit Plans, in the Notes to Financial Statements. Actuarial assumptions attempt to anticipate future events and are used in calculating the expenses and liabilities related to these plans. The calculation of the liability related to the Company’s defined benefit pension plans requires assumptions regarding the appropriate weighted average discount rate, estimated weighted average rate of increase in the compensation level of its employee base and the expected long-term rate of return on the plans’ assets. The selection and use of such assumptions affects the amount of expense recorded in the Company’s financial statements related to its defined benefit pension plans. In selecting the discount rate, consideration is given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments. The discount rate used for actuarial purposes covering a majority of employees was 5.75 percent for the year ended December 31, 2005. A

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hypothetical 25 basis point change in the discount rate would impact total pension expense by approximately $1,010,000. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The return on assets used for actuarial purposes was 8.5 percent for the year ended December 31, 2005. A hypothetical 25 basis point change in the return on assets would impact total pension expense by approximately $320,000. The estimated weighted average rate of increase in the compensation level of the Company’s employees was 4 percent for the year ended December 31, 2005. A hypothetical 25 basis point change in the estimated rate of increase in the compensation level of applicable employees would impact total pension expense by approximately $670,000. The discount rate, return on plan assets and estimated rate of compensation increase used in the actuarial assumptions for 2006 is 5.5 percent, 8.5 percent, and 3.5 percent, respectively.

Asset Retirement Obligation: The Company records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company will settle the obligation for its recorded amount and the resulting gain or loss. Energen Resources has an obligation to remove tangible equipment and restore land at the end of oil and gas production operations. Alagasco has certain removal cost obligations related to its gas distribution assets and a conditional asset retirement obligation to purge and cap its distribution and transmission lines upon abandonment. The estimate of future restoration and removal costs includes numerous assumptions and uncertainties, including but not limited to, inflation factors, discount rates, timing of settlement, and changes in contractual, regulatory, political, environmental, safety and public relations considerations.

RESULTS OF OPERATIONS

Consolidated Net Income

Energen Corporation’s net income for the year ended December 31, 2005 totaled $173 million, or $2.35 per diluted share and compared favorably to the year ended December 31, 2004 net income of $127.5 million, or $1.74 per diluted share. This 35.1 percent increase in earnings per diluted share (EPS) largely reflected the result of significantly higher prices for natural gas, oil and natural gas liquids as well as the impact of a 3.5 billion cubic feet equivalent (Bcfe) increase in production volumes from Energen Resources. For the year ended December 31, 2005, Energen Resources earned $135.3 million, as compared with $94.1 million in the previous year. Alagasco generated a 9.4 percent increase in net income, earning $37 million in the current year as compared with net income in the prior period of $33.8 million. For the year ended December 31, 2003, Energen reported earnings of $110.7 million, or $1.55 per diluted share.

2005 vs 2004: Energen Resources’ net income rose 43.8 percent to $135.3 million in 2005. Energen Resources’ income from continuing operations totaled $135.2 million in 2005 as compared with $93.9 million in 2004. Discontinued operations in 2005 generated income of $126,000 as compared with income of $158,000 in 2004. The primary factors positively influencing income from continuing operations included increased commodity prices of approximately $62 million after-tax along with the impact of increased production volumes of approximately $10 million after-tax. These increases were partially offset by higher lease operating expense of approximately $16 million after-tax, higher production taxes of approximately $9 million after-tax, increased depreciation, depletion and amortization (DD&A) expense of approximately $5 million after-tax and increased administrative expenses of approximately $5 million after-tax.

Alagasco earned net income of $37 million in 2005 as compared with net income of $33.8 million in 2004. This increase in earnings largely reflected the utility’s ability to earn on a higher level of equity. Alagasco’s return on average equity (ROE) was 13.5 percent in 2005 compared with 12.8 percent in 2004.

2004 vs 2003: For the year ended December 31, 2004, Energen Resources’ net income totaled $94.1 million as compared with $78.9 million for the 12 months ended December 31, 2003. Energen Resources’ income from continuing operations totaled $93.9 million in 2004 as compared with $78.4 million in 2003, primarily due to higher commodity prices of approximately $31 million after-tax along with the impact of increased production volumes of approximately $6 million after-tax. The primary negative influences on income from continuing operations were higher lease operating expense of approximately $7 million after-tax, higher production taxes of approximately $6 million after-tax and increased administrative expenses of approximately $4 million after-tax.

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Alagasco earnings increased to $33.8 million in 2004 from $33 million in 2003 largely as a result of the utility earning on a higher level of equity. Alagasco achieved a ROE of 12.8 percent in 2004 compared with 13.5 percent in 2003.

Operating Income

Consolidated operating income in 2005, 2004 and 2003 totaled $315.7 million, $244.8 million and $217.6 million, respectively. This growth in operating income has been influenced by strong financial performance from Energen Resources under Energen’s diversified growth strategy, implemented in fiscal 1996. Alagasco also contributed to this growth in operating income consistent with increases in the levels of equity upon which it has been able to earn a return.

Oil and Gas Operations: Revenues from oil and gas operations rose in the current year largely as a result of increased commodity prices and increased production volumes. Increases in production primarily related to the August 2004 purchase of San Juan Basin coalbed methane properties and increased drilling of wells in North Louisiana. Negatively affecting production was a normal production decline in excess of new production coming on-line primarily in the Permian Basin. Revenue per unit of production for natural gas production increased 23.8 percent to $5.99 per thousand cubic feet (Mcf), oil revenue per unit of production rose 22.8 percent to $35.18 per barrel and natural gas liquids revenue per unit of production increased 22.2 percent to an average price of $0.55 per gallon during 2005. Production from continuing operations increased 4 percent to 91 Bcfe during 2005. Natural gas production rose 6.8 percent to 61 billion cubic feet (Bcf) and oil volumes declined 3.4 percent to 3,316 thousand barrels (MBbl). Production of natural gas liquids increased 3.4 percent to 70.5 million gallons (MMgal).

In 2004, revenues from oil and gas operations increased primarily as a result of increased commodity prices, an increase in volumes related to the August 2004 acquisition of coalbed methane properties and additional drilling of coalbed methane wells in the San Juan and Black Warrior basins. Revenue per unit of production related to natural gas increased 13.9 percent to $4.84 per Mcf, oil revenues per unit of production rose 12.1 percent to $28.66 per barrel and natural gas liquids revenue per unit of production increased 15.4 percent to an average price of $0.45 per gallon during the year ended December 31, 2004. Production from continuing operations rose 2.6 percent to 87.5 Bcfe in 2004. Natural gas production increased 3.4 percent to 57.2 Bcf, oil volumes increased slightly to 3,434 MBbl and natural gas liquids production increased 2.4 percent to 68.2 MMgal.

Coalbed methane operating fees are calculated as a percentage of net proceeds on certain properties, as defined by the related operating agreements, and vary with changes in natural gas prices, production volumes and operating expenses. Revenues from operating fees were $8.7 million, $6.6 million and $6.1 million in 2005, 2004 and 2003, respectively.

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Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company is required to reflect gains and losses on the dispositions of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144,”Accounting for Impairment or Disposal of Long-Lived Assets”. During 2005, Energen Resources recorded a pre-tax gain of $213,000 primarily from a property sale located in the Permian Basin. Energen Resources had no property sales during 2004. In 2003, Energen Resources recorded a pre-tax gain of $9.4 million in discontinued operations from the sale of properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region, which were subsequently sold in 2003 for a pre-tax gain of $0.4 million.

Operations and maintenance (O&M) expense increased $31.1 million and $19 million in 2005 and 2004, respectively. Lease operating expense (excluding production taxes) in 2005 increased $25.1 million primarily due to increased workover and maintenance expenses, increased ad valorem taxes, higher transportation costs and other overall price increases related to higher commodity prices. Partially offsetting these increases were lower compliance costs related to prior year regulations for below-grade storage pits. In 2004, lease operating expense (excluding production taxes) increased by $11.4 million primarily due to increased workover and maintenance expense, costs associated with storage pit regulatory requirements and higher transportation costs. Administrative expense increased $7.5 million in 2005 largely due to labor-related costs. In 2004, administrative expense increased $6.6 million primarily due to labor-related costs as well as costs related to the San Juan Basin property acquisition. Exploration expense decreased $1.4 million in 2005 largely due to decreased exploratory efforts. In 2004, exploration expense increased $1 million.

DD&A expense increased $8.4 million in 2005 and $1.4 million in 2004. The average depletion rates were $0.96 per Mcfe in 2005, $0.90 per Mcfe in 2004 and $0.92 per Mcfe in 2003. The increase in the 2005 rate was largely due to a higher depletion rate on coalbed methane properties purchased in the prior year as well as to the current year production mix that reflects a higher percentage of the Company’s shorter-lived North Louisiana/East Texas production. Increased production volumes also contributed to the increase in DD&A expense during 2005.

Energen Resources’ expense for taxes other than income primarily reflected production-related taxes. Energen Resources recorded severance taxes of $52.3 million, $37.3 million and $27.7 million for 2005, 2004 and 2003, respectively. Increased severance taxes were the result of increased commodity prices and production.

Natural Gas Distribution: As discussed more fully in Note 2, Regulatory Matters, in the Notes to Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002, the APSC issued an order to extend the utility’s rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the company and a hearing, the Commission votes to either modify or discontinue its operation.

Alagasco generates revenues through the sale and transportation of natural gas. The transportation rate does not contain an amount representing the cost of gas, and Alagasco’s rate structure allows similar margins on transportation and sales gas. Weather can cause variations in space heating revenues, but operating margins essentially remain unaffected due to a temperature adjustment mechanism that requires Alagasco to adjust certain customer bills monthly to reflect changes in usage due to departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

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Alagasco’s natural gas and transportation sales revenues totaled $600.7 million, $526.7 million and $489.1 million in 2005, 2004 and 2003, respectively. Sales revenue in 2005 and 2004 increased primarily due to an increase in commodity gas costs. In 2005, weather was 3.6 percent colder than in the prior year. Residential sales volumes declined 3.1 percent while commercial and industrial volumes increased 1.4 percent. Large transportation volumes decreased 8.3 percent primarily related to higher gas prices. During 2004, weather that was 6 percent warmer than in the prior year contributed to a 6.8 percent decline in residential sales volumes and a 1.9 percent decrease in commercial and industrial volumes. Large transportation volumes decreased 2.2 percent. In 2005, higher commodity gas costs along with increased gas purchase volumes contributed to a 21.6 percent increase in cost of gas. Higher commodity gas cost generated a 10.9 percent increase in cost of gas in 2004.

O&M expense at the utility increased 3.4 percent in 2005 largely due to higher bad debt expense and distribution maintenance expenses. These increases were partially offset by decreased labor-related expense, primarily as a result of additional labor costs capitalized in the current year. In 2004, O&M expense increased 6.9 percent primarily due to increased labor-related costs. The increase in O&M expense per customer for the rate years ended September 30, 2004 and 2003 were above the inflation-based Cost Control Measurement (CCM) established by the APSC as part of the utility’s rate-setting mechanism; as a result, three quarters of the differences, or $1.2 million and $0.1 million pre-tax, respectively, were returned to the customers through RSE (see Note 2, Regulatory Matters, in the Notes to Financial Statements). Alagasco’s O&M expense fell within the index range for the rate year ended September 30, 2005.

Depreciation expense rose 6.2 percent and 7.3 percent in 2005 and 2004, respectively, due to normal growth of the utility’s distribution and support systems. Alagasco’s expense for taxes other than income primarily reflects 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

Consolidated: Interest expense in 2005 increased $4.1 million primarily due to the issuance of $100 million of Floating Rate Senior Notes by Energen in November 2004, Alagasco’s issuance of $80 million of long-term debt in January 2005 and Alagasco’s $80 million issuance of long-term debt in November 2005. Positively impacting interest expense was Alagasco’s redemption of $56.7 million, $18 million and $30 million of long-term debt in December 2005, August 2005 and April 2004, respectively. Interest expense in 2004 increased $0.5 million largely due to a full year’s interest on $50 million of long-term debt issued by Energen in October 2003 and increased short-term borrowings due to the acquisition of San Juan Basin coalbed methane properties in August 2004. The average daily outstanding balance under short-term credit facilities was $17.7 million in 2005. The average daily outstanding balance under short-term credit facilities was $92.6 million in 2004 as compared to $81.1 million in 2003.

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Income tax expense increased in the periods presented primarily due to higher pre-tax income. As of December 31, 2005, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $34.8 million.

Exposure to Natural Disaster

The Company’s production properties and distribution system did not suffer significant damage from Hurricanes Katrina and Rita which occurred in the third quarter of 2005. Energen Resources experienced minimal loss of production and Alagasco had no significant supply disruptions as a result of these hurricanes. These events, however, highlight the potential for a period of production shut-in for Energen Resources resulting from a prolonged interruption of service in areas which have a concentration of fractionation plants and refineries through which a substantial portion of the Company’s natural gas liquids and oil production flow. Alagasco’s customer base is geographically concentrated in central Alabama. Damage to Alagasco’s delivery infrastructure, Energen Resources’ production infrastructure or to third party facilities which serve Alagasco and/or Energen Resources due to a natural disaster or other event could result in significant adverse financial consequences to Alagasco and/or the Company.

FINANCIAL POSITION AND LIQUIDITY

The Company’s net cash from operating activities totaled $335.1 million, $291.1 million and $243.1 million in 2005, 2004 and 2003, respectively. Operating cash flow in 2005, 2004 and 2003 benefited from higher realized commodity prices and production volumes at Energen Resources. During the periods presented, working capital needs at Alagasco were primarily affected by increased gas costs compared to the prior period and storage gas inventory. Other working capital items, which primarily are the result of changes in throughput and the timing of payments, combined to create the remaining increases for all years.

During 2005, the Company made net investments of $400.7 million. Energen Resources invested $188.4 million in property acquisitions, $157.5 million for development costs including approximately $123 million to drill 294 gross development wells and $5.1 million for exploration. In December 2005, Energen Resources completed its purchase of oil properties located in the Permian Basin from a private company for a contract price of approximately $168 million. The acquisition added approximately 131 Bcfe of proved reserves and had an effective date of November 1, 2005. Energen Resources sold certain properties during 2005, resulting in cash proceeds of $10.8 million. Utility expenditures in 2005 totaled $73.3 million and primarily represented system distribution expansion and support facilities. Cash used in investing activities totaled $453.4 million in 2004. Energen Resources invested $274.4 million in property acquisitions, $124.6 million for development costs including approximately $89 million to drill 288 gross development wells and $5 million for exploration. In August 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $273 million adding approximately 245 Bcfe of proved reserves. Utility expenditures in 2004 totaled $58.2 million. During 2003, the Company made net investments of $190.4 million. Energen Resources invested $40.5 million in property acquisitions, $121.9 million for development costs including approximately $89 million to drill 347 gross development wells and $0.4 million for exploration. Energen Resources sold certain properties during 2003, resulting in cash proceeds of $29.1 million. Utility expenditures in 2003 totaled $57.9 million.

During 2005, the Company added approximately 131 Bcfe of reserves from the Permian Basin acquisition. Energen Resources expects this acquisition to utilize approximately $9 million, net of development costs, of pretax cash flows in 2006. Over the five-year period ending December 31, 2010, the Company expects this acquisition to contribute approximately $14 million, net of development costs, to pretax cash flows. Also during 2005, Energen Resources added 90 Bcfe of reserves from discoveries and other additions, primarily the result of improved drilling technology that increased the number of available drilling locations for certain wells in the San Juan Basin as well as continued downspacing in the Permian Basin. Energen Resources added approximately 315 Bcfe and 236 Bcfe of reserves in 2004 and 2003, respectively.

In 2005, net cash provided from financing activities totaled $69.8 million. In January 2005, Alagasco issued $40 million of long-term debt with an interest rate of 5.2 percent due January 15, 2020 and $40 million of long-term debt with an interest rate of 5.7 percent due January 15, 2035. In November 2005, Alagasco issued $80 million of long-term debt with an interest rate of 5.368 percent due December 1, 2015. Long-term debt was reduced by $84.8

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million including Alagasco’s redemption of $18 million in Medium-Term Notes maturing June 27, 2007 to July 5, 2022 in August 2005 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 in December 2005. The Company provided $164.6 million from financing activities in 2004. Energen issued $100 million of Floating Rate Senior Notes in November 2004. Long-term debt was reduced by $40.1 million in 2004, including $30 million of Medium-Term Notes called by Alagasco in April 2004. In 2003, net cash used in financing activities totaled $55.4 million. In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration which generated net proceeds of $32.1 million. Energen issued $50 million of long-term debt in October 2003. Long-term debt was reduced by $23 million for current maturities in 2003. For each of the years, net cash used in financing activities also reflected dividends paid to common stockholders and the issuance of common stock through the dividend reinvestment and direct stock purchase plan as well as the employee benefit plans.

Capital Expenditures

Oil and Gas Operations: Energen Resources spent a total of $924.3 million for capital projects during the years ended December 31, 2005, 2004 and 2003. Property acquisition expenditures totaled $503.3 million, development activities totaled $403.9 million, and exploratory expenditures totaled $10.5 million.

Natural Gas Distribution: During the years ended December 31, 2005, 2004 and 2003, Alagasco invested $189.4 million for capital projects: $134.1 million for normal expansion, replacements and support of its distribution system and $55.3 million for support facilities, including the replacement of liquifaction equipment and the development and implementation of information systems.