Exhibit 99.1
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NYSE: WMB | | |
Date:Feb. 28, 2006
Williams Reports Fourth-Quarter and Full-Year 2005 Financial Results
| • | | U.S. Natural Gas Production Climbs 18% During 2005 |
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| • | | Businesses Generate $1.45 Billion in Net Cash from Operating Activities for 2005 |
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| • | | 4Q Results Reduced by Litigation Accruals and Investment Impairments |
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| • | | Company Plans to Double Drilling Activity in Piceance Highlands in 2006 |
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| • | | Company Provides Guidance Through 2008 |
Year-End Summary Financial Information
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| | | 2005 | | | 2004 | |
| Per share amounts are reported on a fully diluted basis | | millions | | | per share | | | millions | | | per share | |
| Income from continuing operations | | $ | 317.4 | | | $ | 0.53 | | | $ | 93.2 | | | $ | 0.18 | |
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| Income (loss) from discontinued operations | | ($ | 2.1 | ) | | | – | | | $ | 70.5 | | | $ | 0.13 | |
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| Cumulative effect of change in accounting principle | | ($ | 1.7 | ) | | | – | | | | – | | | | – | |
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| Net income | | $ | 313.6 | | | $ | 0.53 | | | $ | 163.7 | | | $ | 0.31 | |
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| Recurring income from continuing operations* | | $ | 427.8 | | | $ | 0.72 | | | $ | 261.5 | | | $ | 0.49 | |
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| After-tax mark-to-market adjustments | | $ | 85.0 | | | $ | 0.14 | | | ($ | 72.0 | ) | | ($ | 0.14 | ) |
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| Recurring income from continuing operations — after mark-to-market adjustment* | | $ | 512.8 | | | $ | 0.86 | | | $ | 189.5 | | | $ | 0.35 | |
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| * | | A schedule reconciling income (loss) from continuing operations to recurring income (loss) from continuing operations and mark-to-market adjustments (non-GAAP measures) is available on Williams’ Web site at www.williams.com and as an attachment to this press release. |
Quarterly Summary Information
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| | | 4Q 2005 | | | 4Q 2004 | |
| Per share amounts are reported on a fully diluted basis | | millions | | | per share | | | millions | | | per share | |
| Income from continuing operations | | $ | 68.8 | | | $ | 0.11 | | | $ | 95.5 | | | $ | 0.17 | |
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| Income (loss) from discontinued operations | | ($ | 0.3 | ) | | | – | | | ($ | 22.1 | ) | | ($ | 0.04 | ) |
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| Cumulative effect of change in accounting principle | | ($ | 1.7 | ) | | | – | | | | – | | | | – | |
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| Net income | | $ | 66.8 | | | $ | 0.11 | | | $ | 73.4 | | | $ | 0.13 | |
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| Recurring income from continuing operations* | | $ | 168.1 | | | $ | 0.28 | | | $ | 68.0 | | | $ | 0.12 | |
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| After-tax mark-to-market adjustments | | ($ | 13.8 | ) | | ($ | 0.02 | ) | | ($ | 17.0 | ) | | ($ | 0.03 | ) |
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| Recurring income from continuing operations — after mark-to-market adjustment* | | $ | 154.3 | | | $ | 0.26 | | | $ | 51.0 | | | $ | 0.09 | |
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TULSA, Okla. – Williams (NYSE:WMB) 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 $520 million in segment profit from Gas Pipeline. The projected decline compared with 2005 results is in part because of a new accounting rule that requires certain pipeline assessment costs that have historically been capitalized to be recorded as expense beginning in 2006, and higher interest expense at Gulfstream as a result of a debt offering in October 2005.
Power: Generates Positive Cash Flow in 2005; Continues to Reduce Forward Risk
Power manages a portfolio of more than 7,000 megawatts and provides services that support Williams’ natural gas businesses.
2005 Power Recurring Segment Profit Adjusted for Mark-to-Market Impact
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| | | 2005 | | | 2004 | |
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| Segment profit (loss) | | ($ | 256.7 | ) | | $ | 76.7 | |
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| Non-recurring adjustments | | $ | 116.6 | | | | – | |
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| Recurring Segment profit (loss) | | ($ | 140.1 | ) | | $ | 76.7 | |
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| Mark-to-market adjustments — net | | $ | 137.7 | | | ($ | 118.0 | ) |
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| Recurring segment loss after mark-to-market adjustments | | ($ | 2.4 | ) | | ($ | 41.3 | ) |
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4Q Power Recurring Segment Profit Adjusted for Mark-to-Market Impact
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| | | 4Q ’05 | | | 4Q ’04 | |
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| Segment profit (loss) | | ($ | 69.4 | ) | | ($ | 44.4 | ) |
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| Non-recurring adjustments | | $ | 91.7 | | | | – | |
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| Recurring Segment profit (loss) | | $ | 22.3 | | | ($ | 44.4 | ) |
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| Mark-to-market adjustments — net | | ($ | 22.4 | ) | | ($ | 29.1 | ) |
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| Recurring segment loss after mark-to-market adjustments | | ($ | 0.1 | ) | | ($ | 73.5 | ) |
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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 viawww.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 atwww.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 (NYSE:WMB)
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 atwww.williams.com.
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Contact: | | Kelly Swan |
| | | Williams (media relations) |
| | | (918) 573-6932 |
| | | |
| | | Travis Campbell |
| | | Williams (investor relations) |
| | | (918) 573-2944 |
| | | |
| | | Richard George |
| | | Williams (investor relations) |
| | | (918) 573-3679 |
| | | |
| | | Sharna Reingold |
| | | Williams (investor relations) |
| | | (918) 573-2078 |
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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 www.williams.com.
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Financial Highlights
(Unaudited) | |  |
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| | | Three months ended | | Years ended |
| | | December 31, | | December 31, |
| (Millions, except per-shareamounts) | | 2005 | | 2004 | | 2005 | | 2004 |
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| Revenues | | $ | 3,676.1 | | | $ | 2,964.2 | | | $ | 12,583.6 | | | $ | 12,461.3 | |
| Income from continuing operations | | $ | 68.8 | | | $ | 95.5 | | | $ | 317.4 | | | $ | 93.2 | |
| Income (loss) from discontinued operations | | $ | (0.3 | ) | | $ | (22.1 | ) | | $ | (2.1 | ) | | $ | 70.5 | |
| Cumulative effect of change in accounting principle | | $ | (1.7 | ) | | $ | — | | | $ | (1.7 | ) | | $ | — | |
| Net income applicable to common stock | | $ | 66.8 | | | $ | 73.4 | | | $ | 313.6 | | | $ | 163.7 | |
| Basic earnings (loss) per common share: | | | | | | | | | | | | | | | | |
| Income from continuing operations | | $ | .12 | | | $ | .17 | | | $ | .55 | | | $ | .18 | |
| Income (loss) from discontinued operations | | $ | — | | | $ | (.04 | ) | | $ | — | | | $ | .13 | |
| Cumulative effect of change in accounting principle | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Net income | | $ | .12 | | | $ | .13 | | | $ | .55 | | | $ | .31 | |
| Average shares (thousands) | | | 573,371 | | | | 552,272 | | | | 570,420 | | | | 529,188 | |
| Diluted earnings (loss) per common share: | | | | | | | | | | | | | | | | |
| Income from continuing operations | | $ | .11 | | | $ | .17 | | | $ | .53 | | | $ | .18 | |
| Income (loss) from discontinued operations | | $ | — | | | $ | (.04 | ) | | $ | — | | | $ | .13 | |
| Cumulative effect of change in accounting principle | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Net income | | $ | .11 | | | $ | .13 | | | $ | .53 | | | $ | .31 | |
| Average shares (thousands) | | | 609,106 | | | | 586,497 | | | | 605,847 | | | | 535,611 | |
| Shares outstanding at December 31 (thousands) | | | | | | | | | | | 573,592 | | | | 557,957 | |
| |
Fourth Quarter 2005
| | |
Consolidated Statement of Operations
(Unaudited) | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | Three months ended | | Years ended |
| | | | | December 31, | | December 31, |
| | | (Millions, except per-share amounts) | | 2005 | | 2004 | | 2005 | | 2004 |
| | | |
| REVENUES | | Power | | $ | 2,786.7 | | | $ | 2,038.6 | | | $ | 9,093.9 | | | $ | 9,272.4 | |
| | | Gas Pipeline | | | 374.7 | | | | 351.3 | | | | 1,412.8 | | | | 1,362.3 | |
| | | Exploration & Production | | | 420.2 | | | | 214.1 | | | | 1,269.1 | | | | 777.6 | |
| | | Midstream Gas & Liquids | | | 890.9 | | | | 867.1 | | | | 3,232.7 | | | | 2,882.6 | |
| | | Other | | | 7.8 | | | | 6.5 | | | | 27.2 | | | | 32.8 | |
| | | Intercompany eliminations | | | (804.2 | ) | | | (513.4 | ) | | | (2,452.1 | ) | | | (1,866.4 | ) |
| | | |
| | | Total revenues | | | 3,676.1 | | | | 2,964.2 | | | | 12,583.6 | | | | 12,461.3 | |
| | | |
| SEGMENT COSTS AND EXPENSES | | Costs and operating expenses | | | 3,162.9 | | | | 2,543.5 | | | | 10,871.0 | | | | 10,751.7 | |
| | | Selling, general and administrative expenses | | | 98.6 | | | | 97.8 | | | | 325.4 | | | | 355.5 | |
| | | Other (income) expense – net | | | 62.5 | | | | (77.4 | ) | | | 61.2 | | | | (51.6 | ) |
| | | |
| | | Total segment costs and expenses | | | 3,324.0 | | | | 2,563.9 | | | | 11,257.6 | | | | 11,055.6 | |
| | | |
| | | General corporate expenses | | | 48.6 | | | | 35.3 | | | | 154.9 | | | | 119.8 | |
| | | |
| OPERATING INCOME (LOSS) | | Power | | | (46.5 | ) | | | (50.8 | ) | | | (236.8 | ) | | | 86.5 | |
| | | Gas Pipeline | | | 85.5 | | | | 148.0 | | | | 542.2 | | | | 557.6 | |
| | | Exploration & Production | | | 200.5 | | | | 67.7 | | | | 568.4 | | | | 223.9 | |
| | | Midstream Gas & Liquids | | | 102.9 | | | | 247.0 | | | | 446.6 | | | | 552.2 | |
| | | Other | | | 9.7 | | | | (11.6 | ) | | | 5.6 | | | | (14.5 | ) |
| | | General corporate expenses | | | (48.6 | ) | | | (35.3 | ) | | | (154.9 | ) | | | (119.8 | ) |
| | | |
| | | Total operating income | | | 303.5 | | | | 365.0 | | | | 1,171.1 | | | | 1,285.9 | |
| | | |
| | | Interest accrued | | | (176.4 | ) | | | (171.5 | ) | | | (671.7 | ) | | | (834.4 | ) |
| | | Interest capitalized | | | 2.9 | | | | 1.0 | | | | 7.2 | | | | 6.7 | |
| | | Investing income (loss) | | | (21.2 | ) | | | 16.8 | | | | 23.7 | | | | 48.0 | |
| | | Early debt retirement costs | | | (0.4 | ) | | | (29.7 | ) | | | (0.4 | ) | | | (282.1 | ) |
| | | Minority interest in income of consolidated subsidiaries | | | (8.9 | ) | | | (5.4 | ) | | | (25.7 | ) | | | (21.4 | ) |
| | | Other income – net | | | 14.6 | | | | 7.5 | | | | 27.1 | | | | 21.8 | |
| | | |
| | | Income from continuing operations before income taxes and cumulative effect of change in accounting principle | | | 114.1 | | | | 183.7 | | | | 531.3 | | | | 224.5 | |
| | | Provision for income taxes | | | 45.3 | | | | 88.2 | | | | 213.9 | | | | 131.3 | |
| | | |
| | | Income from continuing operations | | | 68.8 | | | | 95.5 | | | | 317.4 | | | | 93.2 | |
| | | Income (loss) from discontinued operations | | | (0.3 | ) | | | (22.1 | ) | | | (2.1 | ) | | | 70.5 | |
| | | |
| | | Income before cumulative effect of change in accounting principle | | | 68.5 | | | | 73.4 | | | | 315.3 | | | | 163.7 | |
| | | Cumulative effect of change in accounting principle | | | (1.7 | ) | | | — | | | | (1.7 | ) | | | — | |
| | | |
| | | Net income applicable to common stock | | $ | 66.8 | | | $ | 73.4 | | | $ | 313.6 | | | $ | 163.7 | |
| | | |
| EARNINGS (LOSS) PER SHARE | | Basic earnings (loss) per common share: | | | | | | | | | | | | | | | | |
| | | Income from continuing operations | | $ | .12 | | | $ | .17 | | | $ | .55 | | | $ | .18 | |
| | | Income (loss) from discontinued operations | | | — | | | | (.04 | ) | | | — | | | | .13 | |
| | | |
| | | Income before cumulative effect of change in accounting principle | | | .12 | | | | .13 | | | | .55 | | | | .31 | |
| | | Cumulative effect of change in accounting principle | | | — | | | | — | | | | — | | | | — | |
| | | |
| | | Net income | | $ | .12 | | | $ | .13 | | | $ | .55 | | | $ | .31 | |
| | | |
| | | Diluted earnings (loss) per common share: | | | | | | | | | | | | | | | | |
| | | Income from continuing operations | | $ | .11 | | | $ | .17 | | | $ | .53 | | | $ | .18 | |
| | | Income (loss) from discontinued operations | | | — | | | | (.04 | ) | | | — | | | | .13 | |
| | | |
| | | Income before cumulative effect of change in accounting principle | | | .11 | | | | .13 | | | | .53 | | | | .31 | |
| | | Cumulative effect of change in accounting principle | | | — | | | | — | | | | — | | | | — | |
| | | |
| | | Net income | | $ | .11 | | | $ | .13 | | | $ | .53 | | | $ | .31 | |
| | | |
See accompanying notes.
Fourth Quarter 2005
| | |
Notes to Consolidated Statement of Operations
(Unaudited) | | |
1.BASIS OF PRESENTATION
Discontinued operations
The following are presented as discontinued operations in our Consolidated Statement of Operations:
| | • | | Refining, retail and pipeline operations in Alaska, part of the previously reported Petroleum Services segment; |
| |
| | • | | Straddle plants in western Canada, previously part of the Midstream segment. |
Unless indicated otherwise, the information in the Notes to Consolidated Statement of Operations relates to our continuing operations.
Cumulative effect of change in accounting principle
In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation 47, “Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143”. The Interpretation clarifies that the term “conditional asset retirement” as used in Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.
We adopted the Interpretation on December 31, 2005, and as a result, we recorded a cumulative effect of change in accounting principle of $1.7 million (net of $1 million of taxes).
2.HEDGE ACCOUNTING – POWER SEGMENT
As a result of our past intent to exit the Power business, our Power segment did not previously qualify for hedge accounting. Therefore, we reported changes in the forward fair value of our derivative contracts in earnings as unrealized gains or losses. However, with the decision to retain the business, Power became eligible for hedge accounting under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and elected hedge accounting beginning October 1, 2004, on a prospective basis for certain qualifying derivative contracts. Under cash flow hedge accounting, to the extent that the hedges are effective, prospective changes in the forward fair value of the hedges are reported as changes in other comprehensive income in the equity section of the balance sheet, and then reclassified to earnings when the underlying hedged transactions (i.e. power sales and gas purchases) affect earnings.
3.SEGMENT REVENUES AND PROFIT (LOSS)
Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge. Other primarily consists of corporate operations and certain continuing operations that were included within the previously reported International and Petroleum Services segments.
We currently evaluate performance based on segment profit (loss) from operations, which includes segment revenues from external and internal customers, operating costs and expenses, depreciation, depletion and amortization, equity earnings (losses) and income (loss) from investments, including impairments related to investments accounted for under the equity method. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.
During 2004, Power was party to intercompany interest rate swaps with the corporate parent, the effect of which is included in Power’s segment revenues and segment profit (loss) as shown in the reconciliation within the following tables. We terminated all interest-rate derivatives in the fourth quarter of 2004.
The majority of energy commodity hedging by certain of our business units is done through intercompany derivatives with Power which, in turn, enters into offsetting derivative contracts with unrelated third parties. Power bears the counterparty performance risks associated with the unrelated third parties. External revenues of our Exploration & Production segment includes third-party oil and gas sales, more than offset by transportation expenses and royalties due third parties on intercompany sales.
Fourth Quarter 2005
| | |
Notes to Consolidated Statement of Operations (continued)
(Unaudited) | | |
3.Segment revenues and profit (loss) (continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Exploration | | Midstream | | | | | | |
| | | | | | | Gas | | & | | Gas & | | | | | | |
| (millions) | | Power | | Pipeline | | Production | | Liquids | | Other | | Eliminations | | Total |
| |
Three months ended December 31, 2005 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Segment revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
External | | $ | 2,510.1 | | | $ | 365.6 | | | $ | (81.3 | ) | | $ | 878.1 | | | $ | 3.6 | | | $ | — | | | $ | 3,676.1 | |
Internal | | | 276.6 | | | | 9.1 | | | | 501.5 | | | | 12.8 | | | | 4.2 | | | | (804.2 | ) | | | — | |
| | |
Total segment revenues | | $ | 2,786.7 | | | $ | 374.7 | | | $ | 420.2 | | | $ | 890.9 | | | $ | 7.8 | | | $ | (804.2 | ) | | $ | 3,676.1 | |
| | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Segment profit (loss) | | $ | (69.4 | ) | | $ | 92.8 | | | $ | 206.4 | | | $ | 112.4 | | | $ | (30.3 | ) | | $ | — | | | $ | 311.9 | |
Less: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity earnings (losses) | | | 0.1 | | | | 7.3 | | | | 5.9 | | | | 9.2 | | | | (2.0 | ) | | | — | | | | 20.5 | |
Income (loss) from investments | | | (23.0 | ) | | | — | | | | — | | | | 0.3 | | | | (38.0 | ) | | | — | | | | (60.7 | ) |
| | |
Segment operating income (loss) | | $ | (46.5 | ) | | $ | 85.5 | | | $ | 200.5 | | | $ | 102.9 | | | $ | 9.7 | | | $ | — | | | | 352.1 | |
| | |
General corporate expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | (48.6 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Consolidated operating income | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 303.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended December 31, 2004 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| External | | $ | 1,784.8 | | | $ | 345.7 | | | $ | (27.7 | ) | | $ | 859.2 | | | $ | 2.2 | | | $ | — | | | $ | 2,964.2 | |
| Internal | | | 256.7 | | | | 5.6 | | | | 241.8 | | | | 7.9 | | | | 4.3 | | | | (516.3 | ) | | | — | |
| | |
| Total segment revenues | | | 2,041.5 | | | | 351.3 | | | | 214.1 | | | | 867.1 | | | | 6.5 | | | | (516.3 | ) | | | 2,964.2 | |
| | |
| Less intercompany interest rate swap income | | | 2.9 | | | | — | | | | — | | | | — | | | | — | | | | (2.9 | ) | | | — | |
| | |
| Total revenues | | $ | 2,038.6 | | | $ | 351.3 | | | $ | 214.1 | | | $ | 867.1 | | | $ | 6.5 | | | $ | (513.4 | ) | | $ | 2,964.2 | |
| | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment profit (loss) | | $ | (44.4 | ) | | $ | 156.8 | | | $ | 70.9 | | | $ | 235.7 | | | $ | (21.0 | ) | | $ | — | | | $ | 398.0 | |
| Less: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity earnings (losses) | | | 3.5 | | | | 8.8 | | | | 3.2 | | | | 5.5 | | | | (9.3 | ) | | | — | | | | 11.7 | |
| Loss from investments | | | — | | | | — | | | | — | | | | (16.8 | ) | | | (.1 | ) | | | — | | | | (16.9 | ) |
| Intercompany interest rate swap income | | | 2.9 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 2.9 | |
| | |
| Segment operating income (loss) | | $ | (50.8 | ) | | $ | 148.0 | | | $ | 67.7 | | | $ | 247.0 | | | $ | (11.6 | ) | | $ | — | | | | 400.3 | |
| | |
| General corporate expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | (35.3 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated operating income | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 365.0 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Fourth Quarter 2005
Notes to Consolidated Statement of Operations (continued)
(UNAUDITED)
3. SEGMENT REVENUES AND PROFIT (LOSS) (continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| | | | | | | | | | | Exploration | | | Midstream | | | | | | | | | | |
| | | | | | | Gas | | | & | | | Gas & | | | | | | | | | | |
| (millions) | | Power | | | Pipeline | | | Production | | | Liquids | | | Other | | | Eliminations | | | Total | |
| |
Year ended December 31, 2005 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Segment revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
External | | $ | 8,192.5 | | | $ | 1,395.0 | | | $ | (201.6 | ) | | $ | 3,187.6 | | | $ | 10.1 | | | $ | — | | | $ | 12,583.6 | |
Internal | | | 901.4 | | | | 17.8 | | | | 1,470.7 | | | | 45.1 | | | | 17.1 | | | | (2,452.1 | ) | | | — | |
| |
Total segment revenues | | $ | 9,093.9 | | | $ | 1,412.8 | | | $ | 1,269.1 | | | $ | 3,232.7 | | | $ | 27.2 | | | $ | (2,452.1 | ) | | $ | 12,583.6 | |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Segment profit (loss) | | $ | (256.7 | ) | | $ | 585.8 | | | $ | 587.2 | | | $ | 471.2 | | | $ | (105.0 | ) | | $ | — | | | $ | 1,282.5 | |
Less: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity earnings (losses) | | | 3.1 | | | | 43.6 | | | | 18.8 | | | | 23.6 | | | | (23.5 | ) | | | — | | | | 65.6 | |
Income (loss) from investments | | | (23.0 | ) | | | — | | | | — | | | | 1.0 | | | | (87.1 | ) | | | — | | | | (109.1 | ) |
| |
Segment operating income (loss) | | $ | (236.8 | ) | | $ | 542.2 | | | $ | 568.4 | | | $ | 446.6 | | | $ | 5.6 | | | $ | — | | | | 1,326.0 | |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
General corporate expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | (154.9 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Consolidated operating income | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 1,171.1 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year ended December 31, 2004 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| External | | $ | 8,346.2 | | | $ | 1,345.0 | | | $ | (84.0 | ) | | $ | 2,844.7 | | | $ | 9.4 | | | $ | — | | | $ | 12,461.3 | |
| Internal | | | 912.5 | | | | 17.3 | | | | 861.6 | | | | 37.9 | | | | 23.4 | | | | (1,852.7 | ) | | | — | |
| |
| Total segment revenues | | | 9,258.7 | | | | 1,362.3 | | | | 777.6 | | | | 2,882.6 | | | | 32.8 | | | | (1,852.7 | ) | | | 12,461.3 | |
| |
| Less intercompany interest rate swap loss | | | (13.7 | ) | | | — | | | | — | | | | — | | | | — | | | | 13.7 | | | | — | |
| |
| Total revenues | | $ | 9,272.4 | | | $ | 1,362.3 | | | $ | 777.6 | | | $ | 2,882.6 | | | $ | 32.8 | | | $ | (1,866.4 | ) | | $ | 12,461.3 | |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Segment profit (loss) | | $ | 76.7 | | | $ | 585.8 | | | $ | 235.8 | | | $ | 549.7 | | | $ | (41.6 | ) | | $ | — | | | $ | 1,406.4 | |
| Less: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Equity earnings (losses) | | | 3.9 | | | | 29.2 | | | | 11.9 | | | | 14.6 | | | | (9.7 | ) | | | — | | | | 49.9 | |
| Loss from investments | | | — | | | | (1.0 | ) | | | — | | | | (17.1 | ) | | | (17.4 | ) | | | — | | | | (35.5 | ) |
| Intercompany interest rate swap loss | | | (13.7 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (13.7 | ) |
| |
| Segment operating income (loss) | | $ | 86.5 | | | $ | 557.6 | | | $ | 223.9 | | | $ | 552.2 | | | $ | (14.5 | ) | | $ | — | | | | 1,405.7 | |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| General corporate expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | (119.8 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated operating income | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 1,285.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Fourth Quarter 2005
Notes to Consolidated Statement of Operations (continued)
(UNAUDITED)
4. ASSET SALES, IMPAIRMENTS AND OTHER ACCRUALS
Significant gains or losses from asset sales, impairments and other accruals included in other (income) expense-net within segment costs and expenses for the three months and the years ended December 31, 2005 and 2004, are as follows:
| | | | | | | | | | | | | | | | | |
| | | (Income) Expense | |
| | | Three months ended | | | Years ended | |
| | | December 31, | | | December 31, | |
| (millions) | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
| |
Power | | | | | | | | | | | | | | | | |
| Accrual for litigation contingencies | | $ | 68.7 | | | $ | — | | | $ | 82.2 | | | $ | — | |
Gas Pipeline | | | | | | | | | | | | | | | | |
| Write-off of previously-capitalized costs | | | — | | | | — | | | | — | | | | 9.0 | |
Exploration & Production | | | | | | | | | | | | | | | | |
| Gain on sale of certain natural gas properties | | | — | | | | — | | | | (29.6 | ) | | | — | |
| Loss provision related to an ownership dispute | | | — | | | | 4.1 | | | | — | | | | 15.4 | |
Midstream Gas & Liquids | | | | | | | | | | | | | | | | |
| Impairment of Gulf Liquids assets | | | — | | | | 2.5 | | | | — | | | | 2.5 | |
| Arbitration award on a Gulf Liquids insurance claim dispute | | | — | | | | (93.6 | ) | | | — | | | | (93.6 | ) |
Other | | | | | | | | | | | | | | | | |
| Environmental accrual related to the Augusta refinery facility | | | — | | | | 11.8 | | | | — | | | | 11.8 | |
| Gain on sale of land | | | (9.0 | ) | | | — | | | | (9.0 | ) | | | — | |
Power
Accrual for litigation contingencies.This accrual for the year ended December 31, 2005, includes a $77.2 million charge for agreements reached to substantially resolve exposure related to the inaccurate reporting of natural gas prices and volumes to an industry publication in 2002.
Midstream Gas & Liquids
Arbitration award on a Gulf Liquids insurance claim dispute.Winterthur International Insurance Company (Winterthur) issued policies to Gulf Liquids providing financial assurance related to construction contracts. After disputes arose regarding obligations under the construction contracts, Winterthur disputed coverage resulting in arbitration between Winterthur and Gulf Liquids. In July 2004, the arbitration panel awarded Gulf Liquids $93.6 million, plus interest of $9.6 million. Following the arbitration decision, Winterthur filed a petition to vacate the final award in the New York State court and Gulf Liquids filed a cross-petition to confirm the final award. Prior to the State court’s ruling, Winterthur agreed to the terms of the award and on November 1, 2004, remitted the proceeds to us. As a result, we recognized total income of approximately $103 million related to the arbitration award in fourth-quarter 2004.
Other
Environmental accrual related to the Augusta refinery facility.As a result of information obtained in the fourth quarter of 2004 related to the Augusta refinery site, we accrued additional expense for completion of certain remediation work and other reasonably estimated net remediation costs.
Additional items
Costs and operating expenses within our Gas Pipeline segment for the year ended December 31, 2005 includes:
| | • | | An adjustment to reduce costs by $12.1 million to correct the carrying value of certain liabilities recorded in prior periods; |
| |
| | • | | Income from a liability reversal of $14.2 million associated with a favorable ruling involving adjustments to estimated gas purchase costs for operations in prior periods; |
| |
| | • | | A prior period charge of approximately $27.5 million related to accounting and valuation corrections for certain inventory items; |
| |
| | • | | An accrual of approximately $9.8 million for contingent refund obligations. |
Selling, general and administrative expenses within our Gas Pipeline segment for the year ended December 31, 2005, includes:
| | • | | An adjustment to reduce costs by $5.6 million to correct the carrying value of certain liabilities recorded in prior periods; |
| |
| | • | | A $17.1 million reduction in pension expense for the cumulative impact of a correction of an error attributable to 2003 and 2004. |
General corporate expenses for the year ended December 31, 2005, includes $13.8 million of expense in our Other segment related to the settlement of certain insurance coverage issues with an insurer that had underwritten portions of the fiduciary insurance applicable to our Employee Retirement Income Security Act litigation settlement and the directors and officers insurance applicable to our pending securities litigation.
Fourth Quarter 2005
Notes to Consolidated Statement of Operations (continued)
(UNAUDITED)
5. INVESTING INCOME (LOSS)
Investing income (loss) for the three months and the years ended December 31, 2005 and 2004, is as follows:
| | | | | | | | | | | | | | | | | |
| | | Three months ended | | | Years ended | |
| | | December 31, | | | December 31, | |
| (millions) | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
| |
| Equity earnings* | | $ | 20.5 | | | $ | 11.7 | | | $ | 65.6 | | | $ | 49.9 | |
| Loss from investments* | | | (60.7 | ) | | | (16.9 | ) | | | (109.1 | ) | | | (35.5 | ) |
| Impairments of cost-based investments | | | — | | | | (5.1 | ) | | | (2.2 | ) | | | (28.5 | ) |
| Interest income and other | | | 19.0 | | | | 27.1 | | | | 69.4 | | | | 62.1 | |
| |
| Total | | $ | (21.2 | ) | | $ | 16.8 | | | $ | 23.7 | | | $ | 48.0 | |
| |
| | |
| | | *Item also included in segment profit (see Note 3). |
�� Loss from investments for the year ended December 31, 2005, includes:
| | • | | An $87.2 million additional impairment of our investment in Longhorn Partners Pipeline L.P. (Longhorn), which is included in our Other segment. Of the total impairment, $38.1 million relates to fourth quarter. |
| |
| | • | | A $23 million fourth-quarter additional impairment of our equity interest in Aux Sable Liquids Products, L.P., which is included in our Power segment. |
Loss from investments for the year ended December 31, 2004, includes:
| | • | | A $10.8 million impairment of our Longhorn investment; |
| |
| | • | | $6.5 million net unreimbursed Longhorn recapitalization advisory fees; |
| |
| | • | | A $16.9 million fourth-quarter impairment of our equity investment in Discovery Producer Services LLC, which is included in our Midstream segment. |
Impairments of cost-based investments for the years ended December 31, 2005 and 2004 primarily include impairments of certain international investments.
6. EARLY DEBT RETIREMENT
Early debt retirement costs include premiums, fees and expenses related to the retirement of debt.
7. PROVISION FOR INCOME TAXES
We provide for income taxes using the asset and liability method as required by SFAS No. 109, “Accounting for Income Taxes.” During 2005, as a result of the reconciliation of our tax basis and book basis assets and liabilities, we recorded a $20.2 million tax benefit adjustment.
8. DISCONTINUED OPERATIONS
Income (loss) from discontinued operations in 2004 is composed of gains on the sales of the Canadian straddle plants and the Alaska refining, retail and pipeline operations of $189.8 million and $3.6 million, respectively, as well as $22 million in income from our Canadian straddles discontinued operation. Partially offsetting these are $153 million of charges to increase our accrued liability associated with certain Quality Bank litigation matters involving valuation methodologies for products transported on the Trans-Alaska Pipeline System.
9. RECENT ACCOUNTING STANDARDS
In December 2004, the FASB issued revised SFAS No. 123, “Share-Based Payment.” The Statement requires that compensation costs for all share-based awards to employees be recognized in the financial statements at fair value. The Statement, as issued by the FASB, was to be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, in April 2005, the Securities and Exchange Commission adopted a new rule that delayed the effective date for revised SFAS No. 123 to the beginning of the fiscal year that begins after June 15, 2005. We intend to adopt the revised Statement on January 1, 2006.
On June 30, 2005, the Federal Energy Regulatory Commission issued an order, “Accounting for Pipeline Assessment Cost,” to be effective January 1, 2006. The order requires companies to expense certain assessment costs that we have historically capitalized. As a result of this order, we anticipate expensing approximately $27 million to $35 million in 2006 that previously would have been capitalized.
Fourth Quarter 2005
Reconciliation of Income (Loss) from Continuing Operations to Recurring Earnings (Loss)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2004 | | | 2005 | |
| (Dollars in millions, except per-share amounts) | | 1st Qtr | | | 2nd Qtr | | | 3rd Qtr | | | 4th Qtr | | | Year | | | 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 | | | $ | 202.2 | | | $ | 40.7 | | | $ | 5.7 | | | $ | 68.8 | | | $ | 317.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Income (loss) from continuing operations — diluted earnings (loss) per common share | | $ | — | | | | ($0.03 | ) | | $ | 0.03 | | | $ | 0.17 | | | $ | 0.17 | | | $ | 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 | | | — | | | | 9.0 | | | | — | | | | — | | | | 9.0 | | | | — | | | | — | | | | — | | | | — | | | | — | |
| 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 | | | — | | | | 9.0 | | | | — | | | | — | | | | 9.0 | | | | (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 | | | — | | | | 11.3 | | | | — | | | | 4.1 | | | | 15.4 | | | | 0.3 | | | | — | | | | — | | | | — | | | | 0.3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Exploration & Production nonrecurring items | | | — | | | | 11.3 | | | | — | | | | 4.1 | | | | 15.4 | | | | (7.6 | ) | | | — | | | | (21.7 | ) | | | — | | | | (29.3 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 | | | | — | | | | 49.1 | | | | — | | | | 38.1 | | | | 87.2 | |
| Write-off of capitalized project development costs | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 4.0 | | | | — | | | | — | | | | 4.0 | |
| Augusta environmental reserve | | | — | | | | — | | �� | | — | | | | 11.8 | | | | 11.8 | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Gain on sale of real property | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (9.0 | ) | | | (9.0 | ) |
| Longhorn recapitalization fee | | | 6.5 | | | | — | | | | — | | | | — | | | | 6.5 | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Other nonrecurring items | | | 6.5 | | | | 10.8 | | | | — | | | | 11.8 | | | | 29.1 | | | | — | | | | 53.1 | | | | — | | | | 29.1 | | | | 82.2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nonrecurring items included in segment profit (loss) | | | 6.5 | | | | 14.6 | | | | 22.9 | | | | (69.1 | ) | | | (25.1 | ) | | | (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) | | | — | | | | — | | | | 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) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (8.6 | ) | | | — | | | | — | | | | (8.6 | ) |
Loss provision related to an ownership dispute — interest component (Interest accrued — Exploration & Production) | | | — | | | | 1.9 | | | | — | | | | 2.1 | | | | 4.0 | | | | 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | — | | | | 102.4 | | | | 170.8 | | | | 24.5 | | | | 297.7 | | | | 2.7 | | | | (8.6 | ) | | | 18.8 | | | | 9.4 | | | | 22.3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total nonrecurring items | | | 6.5 | | | | 117.0 | | | | 193.7 | | | | (44.6 | ) | | | 272.6 | | | | (6.6 | ) | | | 35.9 | | | | (16.7 | ) | | | 167.5 | | | | 180.1 | |
Tax effect for above items(1) | | | 2.5 | | | | 44.8 | | | | 74.1 | | | | (17.1 | ) | | | 104.3 | | | | (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 | | $ | 4.0 | | | $ | 53.7 | | | $ | 135.8 | | | $ | 68.0 | | | $ | 261.5 | | | $ | 198.4 | | | $ | 65.9 | | | ($ | 4.6 | ) | | $ | 168.1 | | | $ | 427.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Recurring diluted earnings (loss) per common share | | $ | 0.01 | | | $ | 0.10 | | | $ | 0.26 | | | $ | 0.12 | | | $ | 0.49 | | | $ | 0.33 | | | $ | 0.11 | | | ($ | 0.01 | ) | | $ | 0.28 | | | $ | 0.72 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted-average shares — diluted (thousands) | | | 519,485 | | | | 521,698 | | | | 529,525 | | | | 586,497 | | | | 535,611 | | | | 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.
Non-GAAP Utility Statement:
This press release includes certain financial measures, EBITDA, free cash flow, recurring earnings and recurring segment profit, that are non-GAAP financial measures as defined under the rules of the Securities and Exchange Commission. EBITDA represents the sum of net income (loss), net interest expense, income taxes, depreciation and amortization of intangible assets, less income (loss) from discontinued operations. Recurring earnings and recurring segment profit provide investors meaningful insight into the Company’s results from ongoing operations. This press release is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare company performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of the Company’s assets and the cash that the business is generating. Neither EBITDA nor recurring earnings, free cash flow and recurring segment profit are intended to represent cash flows for the period, nor are they presented as an alternative to net income or cash flow from operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles.
Certain financial information in this press release is also shown including Power mark-to-market adjustments. This press release is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Previously the Company did not qualify for hedge accounting with respect to its Power segment as a result of the Company’s stated intent to exit the Power business. The Company ceased efforts to market the sale of Power during the third quarter 2004, and now qualifies for hedge accounting. Hedge accounting reduces earnings volatility associated with Power’s portfolio of certain derivative hedging instruments. Prior to the adoption of hedge accounting, these derivative hedging instruments were accounted for on a mark-to-market basis with the change in fair value recognized in earnings each period. Management uses the mark-to-market adjustments to better reflect Power’s results on a basis that is more consistent with Power’s portfolio cash flows and to aid investor understanding. The adjustments reverse forward unrealized mark-to-market gains or losses from derivatives and add realized gains or losses from derivatives for which mark-to-market income has been previously recognized, with the effect that the resulting adjusted segment profit is presented as if mark-to-market accounting had never been applied to designated hedges or other derivatives. The measure is limited by the fact that it does not reflect potential unrealized future losses or gains on derivative contracts. However, management compensates for this limitation since reported earnings do reflect unrealized gains and losses of derivative contracts. Overall, management believes the mark-to-market adjustments provide an alternative measure that more closely matches realized cash flows for the Power segment.
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 | |
