Williams Reports Fourth-Quarter and Full-Year 2005 Financial Results

TULSA, Okla., Feb. 28 /PRNewswire-FirstCall/ -- Williams announced 2005 unaudited net income of $313.6 million, or 53 cents per share on a diluted basis, compared with net income of $163.7 million, or 31 cents per share on a diluted basis, for 2004.

Results for 2005 reflect the benefit of increased natural gas production and higher net realized average prices for production sold, along with reduced levels of interest expense. Results for 2004 included $282.1 million in costs associated with the early retirement of debt.

Results for 2005 also include unrealized mark-to-market gains of $172 million from the Power business, compared with $304 million in 2004.

For fourth-quarter 2005, the company reported net income of $66.8 million, or 11 cents per share on a diluted basis, compared with net income of $73.4 million, or 13 cents per share on a diluted basis, for fourth-quarter 2004.

Results for fourth-quarter 2005 include $64 million in litigation accruals to resolve legacy issues associated with gas reporting and $61 million of impairment charges associated with two non-core equity investments.

The company reported 2005 income from continuing operations of $317.4 million, or 53 cents per share on a diluted basis, compared with $93.2 million, or 18 cents per share on a diluted basis, in 2004.

For fourth-quarter 2005, the company reported income from continuing operations of $68.8 million, or 11 cents per share on a diluted basis, compared with $95.5 million, or 17 cents per share on a diluted basis, for fourth-quarter 2004.

CEO Perspective

"Our growth is creating real economic value," said Steve Malcolm, chairman, president and chief executive officer. "The investments we're making in our businesses are generating significant results for shareholders and adding energy supplies and delivery reliability to the domestic market.

"In 2005, we more than doubled our performance on a key financial measure - our recurring earnings exclusive of the effect of mark-to-market accounting.

"We took critical steps last year to increase the pace of proving up natural gas reserves and increasing production in the United States. Our efforts paid off with significant increases in both production and reserves through drilling activity.

"This year, we are deploying still more drilling rigs. These rigs are designed to drill more efficiently and effectively. And we are continuing to expand our drilling horizon within the Piceance Basin of the Western Rockies, doubling the number of wells we drill in the comparatively undeveloped Highlands, where we drilled 25 wells last year. We clearly expect these continued efforts to yield proportional growth in financial performance in 2006 and beyond," Malcolm said.

"Williams is rich with opportunity that spans the natural gas value chain from domestic reserves and production growth to midstream infrastructure development and pipeline capacity growth to meet demand on the Eastern Seaboard, Florida and the Northwest.

"We are projecting a growth horizon that will push our 2008 consolidated recurring segment profit to more than $2 billion on a basis adjusted for the effect of mark-to-market accounting," he said.

Recurring Results Adjusted for Effect of Mark-to-Market Accounting

To provide an added level of disclosure and transparency, Williams continues to provide an analysis of recurring earnings adjusted to remove all mark-to-market effects from its Power business unit. Recurring earnings exclude items of income or loss that the company characterizes as unrepresentative of its ongoing operations.

Recurring income from continuing operations - after adjusting for the mark-to-market effect to reflect income as though mark-to-market accounting had never been applied to Power's designated hedges and other derivatives - was $512.8 million, or 86 cents per share, for 2005. In 2004, the adjusted recurring income from continuing operations was $189.5 million, or 35 cents per share.

For the fourth quarter of 2005, recurring income from continuing operations - after adjusting for the mark-to-market effect - was $154.3 million, or 26 cents per share, compared with $51 million, or 9 cents per share, for the same period in 2004.

A reconciliation of the company's income from continuing operations to recurring income from continuing operations and mark-to-market adjustments accompanies this news release.

Business Segment Performance

Williams' primary businesses - Exploration & Production, Midstream Gas & Liquids, Gas Pipeline and Power - reported combined segment profit of $1.39 billion in 2005. A year ago, these businesses reported combined segment profit of $1.45 billion.

Results for 2005 were reduced by lower levels of forward unrealized mark- to-market gains and litigation accruals associated with agreements to resolve gas reporting issues. This year's results benefited from increased natural gas production volumes and higher net realized average prices.

In the fourth quarter of 2005, the four major businesses reported combined segment profit of $342.2 million, compared with $419 million for the same period last year. The fourth quarter of 2004 included a $93.6 million gain from an insurance arbitration award.

Exploration & Production: U.S. Volumes Up 18 Percent in 2005 from Drilling Activities

Exploration & Production, which includes natural gas production and development in the U.S. Rocky Mountains, San Juan Basin and Mid-Continent, and oil and gas development in South America, reported 2005 segment profit of $587.2 million.

A year ago, the business reported segment profit of $235.8 million. The improvement in 2005 reflects the benefit of significant increases in both production volumes and net realized average prices for production sold.

In addition, average sales prices in 2005 reflect a lower share of hedged volumes and increased contracted prices on hedged volumes, along with approximately $30 million in net gains on the sale of non-operated properties.

The benefit of higher volumes and prices in 2005 was only partially offset by higher operating expenses.

For 2005, average daily production from domestic and international interests was approximately 662 million cubic feet of gas equivalent (MMcfe), compared with 564 MMcfe for the same period in 2004 - an increase of approximately 17 percent.

Production solely from domestic interests increased 18 percent to approximately 612 MMcfe in 2005 from 519 MMcfe in 2004.

For the fourth quarter of 2005, Exploration & Production reported segment profit of $206.4 million, compared with $70.9 million for the same period last year.

During the fourth quarter of 2005, Williams realized net domestic average prices of $5.66 per thousand cubic feet of gas equivalent (Mcfe), compared with $3.16 per Mcfe in the fourth quarter a year ago - an increase of 79 percent. Hedging activities limited the extent of the company's ability to capture a higher benefit from market prices.

The improvement in the 2005 quarter also reflects an increase in production volumes. Average daily production from domestic volumes totaled 646 MMcfe during the fourth quarter of 2005. Increased production continues to primarily reflect higher volumes in the Piceance Basin.

In a separate announcement today, Williams reported year-end 2005 proved U.S. natural gas reserves of 3.4 trillion cubic feet equivalent, up 13.3 percent from year-end 2004 reserves. Including its international interests, Williams had total proved natural gas and oil reserves of 3.6 trillion cubic feet equivalent at year-end 2005.

Domestic additions and revisions of 603 billion cubic feet equivalent exceeded last year's 451 billion cubic feet in additions and revisions - an increase of approximately 34 percent. Over the past three years, Williams has successfully transferred more than 1.4 trillion cubic feet of domestic reserves from probable to proved.

In 2005, Williams had a drilling success rate of approximately 99 percent. The company drilled 1,629 gross wells, of which 1,617 were successful. In 2004, Williams also achieved a 99 percent success rate, drilling 1,395 gross wells.

Williams currently has 19 rigs operating in the Piceance Basin of western Colorado - the company's cornerstone for production and reserves growth.

Williams is deploying a new generation of drilling rig from Helmerich & Payne that is specifically designed for conditions in the Piceance Basin. Williams received two of the new rigs in the first quarter of 2006. Eight more rigs are scheduled for delivery at a pace of one per month during the year.

Williams plans to invest $950 million to $1.05 billion of capital in Exploration & Production in 2006. These investments are primarily focused on increasing domestic production by 15 to 20 percent during the year.

For 2006, Williams expects $650 million to $725 million in segment profit from Exploration & Production.

Midstream Gas & Liquids: Posts Strong Results, Despite Hurricanes and Lower Margins

Midstream, which provides natural gas gathering and processing services, along with natural gas liquids (NGL) fractionation and storage services and olefins production, reported 2005 segment profit of $471.2 million, compared with $549.7 million in 2004.

For the fourth quarter of 2005, Midstream reported segment profit of $112.4 million, compared with $235.7 million for the same period in 2004.

Results for 2004 were favorably affected by a fourth-quarter gain of $93.6 million related to an insurance arbitration award.

Results for 2005 benefited from $20.6 million in higher domestic gathering and processing fee-based revenues than a year ago, primarily a result of higher gathering fees and deepwater production handling payments.

These benefits were offset partially by a decrease in net NGL margins as volumes associated with natural gas processing facilities were affected by hurricane-related production shut-ins, power outages and intermittent periods of NGL rejection in the fourth quarter.

In 2005, Midstream sold 1.27 billion gallons of NGL equity volumes, compared with equity sales of 1.43 billion gallons in 2004. Third and fourth quarter performance in 2005 was negatively affected by hurricanes Katrina and Rita, as well as intermittent periods of unfavorable NGL recovery economics in the fourth quarter of 2005. These equity volumes are retained and subsequently marketed by Williams as payment-in-kind under the terms of certain processing contracts.

Gathering volumes increased slightly year-over-year despite the effects of the hurricanes during the third quarter. Gathering volumes were 1,253.3 trillion British thermal units (TBtu) in 2005, compared with 1,251.9 TBtu in 2004. As a result of the hurricanes, fee processing volumes declined year- over-year. In 2005, fee processing volumes were 721.4 TBtu, compared with 767.7 TBtu in 2004.

During the fourth quarter of 2005, Williams began receipt of new volumes of oil and gas from the Triton and Goldfinger fields at its Devils Tower deepwater spar in the eastern Gulf of Mexico. Also, Williams agreed to expand two of its deepwater pipelines in the same area to transport oil and gas production from the Blind Faith acreage beginning in 2008.

Effective Jan. 1, 2006, Williams acquired full ownership of the fourth cryogenic processing train at its Opal, Wyo., facility for approximately $32.5 million. Under a previous agreement, Williams shared the revenue stream from that unit. Williams now owns the entire Opal complex and is in the process of adding a fifth cryogenic processing train, scheduled for completion in second- quarter 2007.

Earlier this month, the company's Cameron Meadows natural gas processing plant returned to service at partial capacity. This facility in Louisiana's Cameron Parish had been offline since Hurricane Rita struck on Sept. 24. Williams expects to return the plant to full service in the second quarter this year.

Williams plans to invest $280 million to $300 million of capital in Midstream in 2006. These investments are primarily focused on expanding Midstream's gathering and processing systems in the western United States and in the deepwater Gulf of Mexico.

For 2006, Williams expects $400 million to $500 million in segment profit from Midstream.

Gas Pipeline: Assesses Customer Demand for Possible Expansions

Gas Pipeline, which primarily delivers natural gas to markets along the Eastern Seaboard, in Florida and in the Northwest, reported 2005 segment profit of $585.8 million, comparable to the same level of segment profit a year ago.

Compared with 2004, segment profit in 2005 reflects higher equity earnings of approximately $14 million from Gulfstream and a $14.2 million favorable adjustment from the resolution of litigation associated with fuel-tracker filings. Those benefits were partially offset by approximately $24 million in lower transportation revenues, mainly from the termination a firm transportation agreement related to the Grays Harbor lateral on the Northwest system.

Additionally, 2005 includes prior-period income of $17.1 million associated with corrections to 2003-2004 pension obligations and $17.7 million associated with reversal of prior-period accruals, offset by a prior-period charge of approximately $27.5 million related to accounting and valuation corrections for certain inventory items, and an accrual of approximately $9.8 million for contingent refund obligations.

For the fourth quarter of 2005, Gas Pipeline reported segment profit of $92.8 million compared with $156.8 million for the same period in 2004. The decrease is primarily because of the previously mentioned prior-period charge of $27.5 million for certain inventory items and the $9.8 million contingent loss accrual.

The decrease in fourth-quarter 2005 also reflects the termination of the Grays Harbor contract, effective January 2005, combined with higher labor and benefits costs as well as the write-off of certain previously capitalized system costs.

During the fourth quarter and already in 2006, Williams has announced a variety of potential projects for expansions on all of its major interstate gas pipeline holdings - Transco, Northwest and Gulfstream Natural Gas System L.L.C., a joint venture in which Williams owns a 50 percent interest.

These non-binding open seasons are a preliminary, necessary step in soliciting customer interest for potential service expansions.

As an example, Williams concluded an open season for the proposed Sentinel project during the fourth quarter. As proposed, the Transco project was designed to provide an additional 200,000 to 300,000 dekatherms of natural gas deliverability per day in the Northeast. Williams ultimately received requests for a total of 256,000 dekatherms per day of capacity - well within the scope of the original plan.

Williams is evaluating the facility requirements to support the Transco Sentinel capacity and is in the process of negotiating shipper agreements with the parties that expressed interest. Service could be available as early as November 2008, subject to Federal Energy Regulatory Commission approval.

In December - following the successful completion of a prior open season in the summer of 2004 and a subsequent customer contract in spring 2005 - Transco filed an application with FERC to construct the Leidy to Long Island expansion in 2007. It will add 100,000 dekatherms of capacity, along with a compressor station, at an approximate cost of $121 million. Most of that expenditure is planned for 2007.

Also in the fourth quarter, Williams completed construction of a $16 million project to add 105,000 dekatherms per day of firm service on its Transco system in central New Jersey. This expansion was placed into service Nov. 1.

Williams plans to invest $710 million to $785 million of capital in Gas Pipeline in 2006. These investments are predominantly tied to maintenance, a capacity replacement project on Northwest Pipeline in Washington and expansions.

For 2006, Williams expects $475 million to $520 million in segment profit from Gas Pipeline. The projected decline compared with 2005 results is in part because of a new accounting rule that requires certain pipeline assessment costs that have historically been capitalized to be recorded as expense beginning in 2006, and higher interest expense at Gulfstream as a result of a debt offering in October 2005.

Power: Generates Positive Cash Flow in 2005; Continues to reduce forward risk

Power manages a portfolio of more than 7,000 megawatts and provides services that support Williams' natural gas businesses.

Power Recurring Segment Profit Adjusted for Mark-to-Market Impact 2005 2004 (millions) (millions) Segment profit (loss) ($256.7) $76.7 Non-recurring adjustments $116.6 - Recurring Segment profit (loss) ($140.1) $76.7 Mark-to-market adjustments -- net $137.7 ($118.0) Recurring segment loss after mark-to- market adjustments ($2.4) ($41.3) Power Recurring Segment Profit Adjusted for Mark-to-Market Impact 4Q '05 4Q '04 (millions) (millions) Segment profit (loss) ($69.4) ($44.4) Non-recurring adjustments $91.7 - Recurring Segment profit (loss) $22.3 ($44.4) Mark-to-market adjustments -- net ($22.4) ($29.1) Recurring segment loss after mark-to- market adjustments ($0.1) ($73.5)

Power reported a 2005 segment loss of $256.7 million, compared with a segment profit of $76.7 million in 2004. Reported results include the effect of forward unrealized mark-to-market gains and losses.

The reduction is primarily the result of lower unrealized mark-to-market gains, lower tolling margins because of the effect of milder weather in California, and the effect of hurricanes on liquidity in the market. Results for 2005 also were reduced by significant litigation accruals and the impairment of a non-core equity investment.

Power reported a recurring segment loss adjusted for the effect of mark- to-market accounting of $2.4 million in 2005, compared with a loss of $41.3 million in 2004.

The year-over-year improvement on the adjusted basis primarily reflects the absence of losses from the interest rate and crude and refined products portfolios and lower selling, general and administrative expenses. That improvement was partially offset by lower margins from tolling and other accrual contracts in 2005.

Power reported a fourth quarter 2005 segment loss of $69.4 million, compared with a segment loss of $44.4 million in fourth-quarter 2004. Reported results include the effect of forward unrealized mark-to-market results.

The increased loss in the fourth quarter of 2005 is primarily the result of litigation accruals associated with resolving gas reporting issues and the impairment of a non-core equity investment, partially offset by higher unrealized mark-to-market gains and higher accrual revenues.

For the fourth quarter of 2005, Power reported a recurring segment loss adjusted for the effect of mark-to-market accounting of $0.1 million, compared with a loss of $73.5 million in 2004.

The year-over-year improvement on the adjusted basis primarily reflects the absence of losses from the interest rate and legacy natural gas portfolios and lower selling, general and administrative expenses.

In 2005, Power generated approximately $188 million in cash flow from operations, largely the result of working capital changes, including the return of margin dollars. In 2004, Power generated approximately $565 million in cash flow from operations, reflecting a significant return of margin dollars resulting from new letter of credit facilities, and changes in working capital.

Power last year also completed 17 new power sales contracts that range in term and volume through 2010. These contracts effectively reduce risk, increase value and increase cash-flow certainty. Additionally, the contracts reduce the portfolio's future exposures to fuel-price and weather volatility.

For 2006, Williams expects a segment loss of between $135 million to $235 million from Power, absent the effect of any future unrealized mark-to-market gains or losses. In regard to cash flow from operations, Williams expects $50 million to $150 million from Power in 2006, excluding changes in working capital and payment of accruals associated with gas reporting agreements.

On a basis adjusted for the effect of mark-to-market accounting, Williams expects Power to generate 2006 recurring segment profit of $50 million to $150 million.

Cash and Debt: Company Ends 2005 With Available Liquidity of $2.6 Billion

At the close of business on Dec. 31, 2005, Williams had total liquidity of more than $2.6 billion. This consisted of approximately $1.6 billion in unrestricted cash and cash equivalents, approximately $123 million in other liquid investments and $961 million in unused and available revolving credit facilities.

Net cash provided by operating activities in 2005 was approximately $1.45 billion, comparable with the 2004 level of $1.49 billion.

Williams reduced its debt by approximately $249 million in 2005 through scheduled payments, maturities and conversions.

At Dec. 31, 2005, Williams' total outstanding debt was approximately $7.7 billion. Approximately $220 million of debt - via the form of 5.5 percent junior subordinated convertible debentures - was converted to common equity in January 2006.

As a result of significant debt reductions in prior years such as 2003 and 2004, Williams realized a $162.7 million decrease in interest expense in 2005 compared with the prior year. The company had interest expense of $671.7 million in 2005, compared with $834.4 million in 2004 - a decrease of 19 percent.

Guidance Through 2008

In 2006, Williams expects $1.52 billion to $1.86 billion in consolidated segment profit and earnings per share of 78 cents to $1.03, both on a recurring basis adjusted for the effect of mark-to-market accounting. The projected increase over 2005 is primarily the result of expected increases in natural gas production volumes and anticipated pricing for those volumes.

In 2007, Williams expects consolidated segment profit of $1.83 billion to $2.25 billion on a recurring basis adjusted for the impact of mark-to-market accounting. The projected increase over 2006 is primarily the result of anticipated increases in natural gas production volumes, successfully completing Gas Pipeline rate cases, and increases in natural gas liquids volumes.

In 2008, Williams expects consolidated segment profit of $2.02 billion to $2.58 billion on a recurring basis adjusted for the impact of mark-to-market accounting. The projected increase over 2007 is primarily the result of anticipated increases in natural gas production volumes, the completion of expansions in Gas Pipeline and increases in natural gas liquids volumes.

Guidance for consolidated segment profit includes results for the four primary businesses, as well as the Other segment, which includes certain equity investments.

The company's overall capital budget is $1.95 billion to $2.15 billion for 2006; $1.6 billion to $1.8 billion for 2007; and $1.5 billion to $1.75 billion for 2008.

Today's Analyst Call

Williams' management will discuss the company's 2005 financial results and outlook through 2008 during an analyst presentation to be webcast live beginning at 10 a.m. Eastern today.

Participants are encouraged to access the presentation and corresponding slides via http://www.williams.com/. A limited number of phone lines also will be available at (800) 818-5264. International callers should dial (913) 981- 4910. Callers should dial in at least 10 minutes prior to the start of the discussion.

Replays of the webcast will be available for two weeks at http://www.williams.com/ following the event.

Form 10-K

The company expects to file its Form 10-K with the Securities and Exchange Commission in early March. The document will be available on both the SEC and Williams websites.

About Williams

Williams, through its subsidiaries, primarily finds, produces, gathers, processes and transports natural gas. The company also manages a wholesale power business. Williams' operations are concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, Southern California and Eastern Seaboard. More information is available at http://www.williams.com.

Williams' reports, filings, and other public announcements might contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" within the meaning of Private Securities Litigation Reform Act of 1995. You typically can identify forward-looking statements by the use of forward- looking words, such as "anticipate," believe," "could," "continue," "estimate," "expect," "forecast," "may," "plan," "potential," "project," "schedule," "will," and other similar words. These statements are based on our intentions, beliefs, and assumptions about future events and are subject to risks, uncertainties, and other factors. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, other factors could cause our actual results to differ materially from the results expressed or implied in any forward- looking statements. Those factors include, among others: changes in general economic conditions and changes in the industries in which Williams conducts business; changes in federal or state laws and regulations to which Williams is subject, including tax, environmental and employment laws and regulations; the cost and outcomes of legal and administrative claims proceedings, investigations, or inquiries; the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions; the level of creditworthiness of counterparties to our transactions; the amount of collateral required to be posted from time to time in our transactions; the effect of changes in accounting policies; the ability to control costs; the ability of each business unit to successfully implement key systems, such as order entry systems and service delivery systems; the impact of future federal and state regulations of business activities, including allowed rates of return, the pace of deregulation in retail natural gas and electricity markets, and the resolution of other regulatory matters; changes in environmental and other laws and regulations to which Williams and its subsidiaries are subject or other external factors over which we have no control; changes in foreign economies, currencies, laws and regulations, and political climates, especially in Canada, Argentina, Brazil, and Venezuela, where Williams has direct investments; the timing and extent of changes in commodity prices, interest rates, and foreign currency exchange rates; the weather and other natural phenomena; the ability of Williams to develop or access expanded markets and product offerings as well as their ability to maintain existing markets; the ability of Williams and its subsidiaries to obtain governmental and regulatory approval of various expansion projects; future utilization of pipeline capacity, which can depend on energy prices, competition from other pipelines and alternative fuels, the general level of natural gas and petroleum product demand, decisions by customers not to renew expiring natural gas transportation contracts; the accuracy of estimated hydrocarbon reserves and seismic data; and global and domestic economic repercussions from terrorist activities and the government's response to such terrorist activities. In light of these risks, uncertainties, and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time that we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

In regard to the company's reserves in Exploration & Production, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We have used certain terms in this news release, such as "probable" reserves and "possible" reserves and "new opportunities potential" reserves that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Probable and possible reserves are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Possible reserve estimates are less certain than those for probable reserves. New opportunities potential is an estimate of reserves for new areas for which we do not have sufficient information to date to raise the reserves to either the probable category or the possible category. New opportunities potential estimates are even less certain that those for possible reserves. Reference to "total resource portfolio" include proved, probable and possible reserves as well as new opportunities potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our website at http://www.williams.com.

Reconciliation of Income (Loss) from Continuing Operations to Recurring Earnings (Loss) (UNAUDITED) 2004 (Dollars in millions, except per-share amounts) 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Income (loss) from continuing operations available to common stockholders $- ($18.5) $16.2 $95.5 $93.2 Income (loss) from continuing operations - diluted earnings (loss) per common share $- ($0.03) $0.03 $0.17 $0.17 Nonrecurring items: Power Accrual for a regulatory settlement (1) - - - - - Accrual for litigation contingencies (1) - - - - - Impairment of Aux Sable - - - - - Prior period correction - - - - - Total Power nonrecurring items - - - - - Gas Pipeline Prior period liability corrections - TGPL - - - - - Prior period pension adjustment - TGPL - - - - - Write-off of previously- capitalized costs - idled segment of Northwest's pipeline - 9.0 - - 9.0 Income from favorable ruling on FERC appeal (1999 Fuel Tracker) - - - - - Prior period inventory corrections - TGPL - - - - - Accrual of contingent refund obligation - TGPL - - - - - Total Gas Pipeline nonrecurring items - 9.0 - - 9.0 Exploration & Production Gain on sale of E&P properties - - - - - Loss provision related to an ownership dispute - 11.3 - 4.1 15.4 Total Exploration & Production nonrecurring items - 11.3 - 4.1 15.4 Midstream Gas & Liquids La Maquina depreciable life adjustment - - 6.4 1.2 7.6 Gain on sale of Louisiana Olefins assets - - - (9.5) (9.5) Gulf Liquids arbitration award (Winterthur) - - - (93.6) (93.6) Impairment of Discovery - - - 16.9 16.9 Devils Tower revenue correction - (16.5) 16.5 - - Total Midstream Gas & Liquids nonrecurring items - (16.5) 22.9 (85.0) (78.6) Other Impairment of Longhorn - 10.8 - - 10.8 Write-off of capitalized project development costs - - - - - Augusta environmental reserve - - - 11.8 11.8 Gain on sale of real property - - - - - Longhorn recapitalization fee 6.5 - - - 6.5 Total Other nonrecurring items 6.5 10.8 - 11.8 29.1 Nonrecurring items included in segment profit (loss) 6.5 14.6 22.9 (69.1) (25.1) Nonrecurring items below segment profit (loss) Impairment of cost-based investments (Investing income (loss) - Various) - - 15.7 2.3 18.0 Write-off of capitalized debt expense (Interest accrued - Corporate) - 3.8 - - 3.8 Premiums, fees and expenses related to the debt repurchase and debt tender offer (Other income (expense) - net - Corporate and Exploration & Production) - 96.7 155.1 29.7 281.5 Gulf Liquids arbitration award (Winterthur) - interest income - (Investing income / loss) - Midstream) - - - (9.6) (9.6) Gain on sale of remaining interests in Seminole Pipeline and MAPL (Investing income / loss - Midstream) - - - - - Loss provision related to an ownership dispute - interest component (Interest accrued - Exploration & Production) - 1.9 - 2.1 4.0 Directors and officers insurance policy adjustment (General corporate expenses - Corporate) - - - - - Loss provision related to ERISA litigation settlement (Other income (expense) - net - Corporate) - - - - - Legal fees associated with shareholder litigation (General corporate expenses - Corporate) - - - - - - 102.4 170.8 24.5 297.7 Total nonrecurring items 6.5 117.0 193.7 (44.6) 272.6 Tax effect for above items (1) 2.5 44.8 74.1 (17.1) 104.3 Adjustment for nonrecurring excess deferred tax benefit - - - - - Recurring income (loss) from continuing operations available to common stockholders $4.0 $53.7 $135.8 $68.0 $261.5 Recurring diluted earnings (loss) per common share $0.01 $0.10 $0.26 $0.12 $0.49 Weighted-average shares - diluted (thousands) 519,485 521,698 529,525 586,497 535,611 2005 (Dollars in millions, except per-share amounts) 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year Income (loss) from continuing operations available to common stockholders $202.2 $40.7 $5.7 $68.8 $317.4 Income (loss) from continuing operations - diluted earnings (loss) per common share $0.34 $0.07 $0.01 $0.11 $0.53 Nonrecurring items: Power Accrual for a regulatory settlement (1) 4.6 - - - 4.6 Accrual for litigation contingencies (1) - 13.1 0.4 68.7 82.2 Impairment of Aux Sable - - - 23.0 23.0 Prior period correction 6.8 - - - 6.8 Total Power nonrecurring items 11.4 13.1 0.4 91.7 116.6 Gas Pipeline Prior period liability corrections - TGPL (13.1) (4.6) - - (17.7) Prior period pension adjustment - TGPL - (17.1) - - (17.1) Write-off of previously- capitalized costs - idled segment of Northwest's pipeline - - - - - Income from favorable ruling on FERC appeal (1999 Fuel Tracker) - - (14.2) - (14.2) Prior period inventory corrections - TGPL - - - 27.5 27.5 Accrual of contingent refund obligation - TGPL - - - 9.8 9.8 Total Gas Pipeline nonrecurring items (13.1) (21.7) (14.2) 37.3 (11.7) Exploration & Production Gain on sale of E&P properties (7.9) - (21.7) - (29.6) Loss provision related to an ownership dispute 0.3 - - - 0.3 Total Exploration & Production nonrecurring items (7.6) - (21.7) - (29.3) Midstream Gas & Liquids La Maquina depreciable life adjustment - - - - - Gain on sale of Louisiana Olefins assets - - - - - Gulf Liquids arbitration award (Winterthur) - - - - - Impairment of Discovery - - - - - Devils Tower revenue correction - - - - - Total Midstream Gas & Liquids nonrecurring items - - - - - Other Impairment of Longhorn - 49.1 - 38.1 87.2 Write-off of capitalized project development costs - 4.0 - - 4.0 Augusta environmental reserve - - - - - Gain on sale of real property - - - (9.0) (9.0) Longhorn recapitalization fee - - - - - Total Other nonrecurring items - 53.1 - 29.1 82.2 Nonrecurring items included in segment profit (loss) (9.3) 44.5 (35.5) 158.1 157.8 Nonrecurring items below segment profit (loss) Impairment of cost-based investments (Investing income (loss) - Various) - - - - - Write-off of capitalized debt expense (Interest accrued - Corporate) - - - - - Premiums, fees and expenses related to the debt repurchase and debt tender offer (Other income (expense) - net - Corporate and Exploration & Production) - - - - - Gulf Liquids arbitration award (Winterthur) - interest income - (Investing income / loss) - Midstream) - - - - - Gain on sale of remaining interests in Seminole Pipeline and MAPL (Investing income / loss - Midstream) - (8.6) - - (8.6) Loss provision related to an ownership dispute - interest component (Interest accrued - Exploration & Production) 2.7 - - - 2.7 Directors and officers insurance policy adjustment (General corporate expenses - Corporate) - - 13.8 - 13.8 Loss provision related to ERISA litigation settlement (Other income (expense) - net - Corporate) - - 5.0 - 5.0 Legal fees associated with shareholder litigation (General corporate expenses - Corporate) - - - 9.4 9.4 2.7 (8.6) 18.8 9.4 22.3 Total nonrecurring items (6.6) 35.9 (16.7) 167.5 180.1 Tax effect for above items (1) (2.8) 10.7 (6.4) 48.0 49.5 Adjustment for nonrecurring excess deferred tax benefit - - - (20.2) (20.2) Recurring income (loss) from continuing operations available to common stockholders $198.4 $65.9 ($4.6) $168.1 $427.8 Recurring diluted earnings (loss) per common share $0.33 $0.11 ($0.01) $0.28 $0.72 Weighted-average shares - diluted (thousands) 599,422 578,902 580,735 609,106 605,847 (1) No tax effect on $.6 million of the accrual for a regulatory settlement in 1st quarter 2005 and $8 million and $42 million of the accrual for litigation contingencies in 2nd quarter 2005 and 4th quarter 2005, respectively. Note: The sum of earnings (loss) per share for the quarters may not equal the total earnings (loss) per share for the year due to changes in the weighted-average number of common shares outstanding. Adjustment to remove MTM impact Dollars in millions except for per share amounts 2005 1Q 2Q 3Q 4Q Year Recurring income (loss) from cont. ops available to common shareholders $198 $67 $(5) $168 $428 Recurring diluted earnings per common share $0.33 $0.11 $(0.01) $0.28 $0.72 Mark-to-Market (MTM) adjustments: Reverse forward unrealized MTM gains/losses (221) (22) 141 (70) (172) Add realized gains/losses from MTM previously recognized 113 77 72 48 310 Total MTM adjustments (108) 55 213 (22) 138 Tax effect of total MTM adjustments (42) 21 83 (8) 53 After tax MTM adjustments (66) 34 130 (14) 85 Recurring income from cont. ops available to common shareholders after MTM adjust. $132 $101 $125 $154 $513 Recurring diluted earnings per share after MTM adj. $0.22 $0.17 $0.22 $0.26 $0.86 weighted average shares - diluted (thousands) 599,422 578,902 580,735 609,106 605,847 2004 1Q 2Q 3Q 4Q Year Recurring income from cont. ops available to common shareholders $4 $54 $136 $68 $261 Recurring diluted earnings per common share $0.01 $0.10 $0.26 $0.12 $0.49 Mark-to-Market (MTM) adjustments: Reverse forward unrealized MTM gains/losses (24) (70) (187) (23) (304) Add realized gains/losses from MTM previously recognized 136 11 45 (6) 186 Total MTM adjustments 112 (59) (142) (29) (118) Tax effect of total MTM adjustments 44 (23) (55) (11) (46) After tax MTM adjustments 68 (36) (87) (17) (72) Recurring income from cont. ops available to common shareholders after MTM adjust. $72 $18 $49 $51 $190 Recurring diluted earnings per share after MTM adj. $0.14 $0.03 $0.09 $0.09 $0.35 weighted average shares - diluted (thousands) 519,485 521,698 529,525 586,497 535,611