NYSE: WMB
Date:Nov. 3, 2005
Williams Reports Third-Quarter 2005 Financial Results
| • | | Natural Gas Production Climbs 19% During First 9 Months |
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| • | | Net Cash from Operations Exceeds $1 Billion Through First Three Quarters |
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| • | | Third-Quarter Results Lowered by Effect of Mark-to-Market Losses |
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| • | | Guidance Raised for 2005, 2006 and 2007 on Higher Natural Gas Prices |
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| • | | Company Plans Sale of Certain Interests to Williams Partners L.P. |
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| • | | 2006 Capital Spending Increased by $300 Million for E&P and Midstream |
3Q Summary Financial Information
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| | | 3Q 2005 | | | 3Q 2004 | |
| | | millions | | | per share | | | millions | | | per share | |
| Income from continuing operations | | $ | 5.7 | | | $ | 0.01 | | | $ | 16.2 | | | $ | 0.03 | |
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| Income (loss) from discontinued operations | | | ($1.3 | ) | | $ | 0.00 | | | $ | 82.4 | | | $ | 0.16 | |
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| Net income | | $ | 4.4 | | | $ | 0.01 | | | $ | 98.6 | | | $ | 0.19 | |
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| Recurring income (loss) from continuing operations* | | ($ | 4.6 | ) | | $ | (0.01 | ) | | $ | 135.8 | | | $ | 0.26 | |
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| After-tax mark-to-market adjustments | | $ | 129.9 | | | $ | 0.23 | | | ($ | 86.8 | ) | | ($ | 0.17 | ) |
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| Recurring income from continuing operations - after mark-to-market adjustment* | | $ | 125.3 | | | $ | 0.22 | | | $ | 49.0 | | | $ | 0.09 | |
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Year-to-Date Summary Financial Information
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| | | YTD 2005 | | | YTD 2004 | |
| | | millions | | | per share | | | millions | | | per share | |
| Income (loss) from continuing operations | | $ | 248.6 | | | $ | 0.42 | | | ($ | 2.3 | ) | | ($ | 0.01 | ) |
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| Income (loss) from discontinued operations | | ($ | 1.8 | ) | | $ | 0.00 | | | $ | 92.6 | | | $ | 0.18 | |
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| Net income | | $ | 246.8 | | | $ | 0.42 | | | $ | 90.3 | | | $ | 0.17 | |
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| Recurring income from continuing operations* | | $ | 259.7 | | | $ | 0.44 | | | $ | 193.5 | | | $ | 0.37 | |
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| After-tax mark-to-market adjustments | | $ | 97.6 | | | $ | 0.16 | | | ($ | 54.2 | ) | | ($ | 0.10 | ) |
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| Recurring income from continuing operations - - after mark-to-market adjustment* | | $ | 357.3 | | | $ | 0.60 | | | $ | 139.3 | | | $ | 0.27 | |
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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. |
TULSA, Okla. – Williams (NYSE:WMB) today announced third-quarter 2005 unaudited net income of $4.4 million, or 1 cent per share on a diluted basis, compared with net income of $98.6 million, or 19 cents per share, for third-quarter 2004.
Year-to-date through Sept. 30, Williams reported net income of $246.8 million, or 42 cents per share on a diluted basis, compared with net income of $90.3 million, or 17 cents per share, for the first three quarters of 2004.
For third-quarter 2005, the company reported income from continuing operations of $5.7 million, or 1 cent per share on a diluted basis, compared with $16.2 million, or 3 cents per share, for third-quarter 2004 on a restated basis.
Results for the 2005 quarter reflect the benefit of increased natural gas production and higher net realized average prices for production sold, along with reduced levels of interest expense. These benefits were offset by the impact of forward unrealized mark-to-market losses experienced in the Power segment. Results for the 2004 quarter reflect the benefit of forward unrealized mark-to-market gains experienced in Power, offset by approximately $155 million in pre-tax charges associated with the early retirement of debt.
Rising natural gas prices during the third quarter of this year benefited Williams’ Exploration & Production business, but contributed to reduced results in the company’s Power business.
For the first nine months of 2005, Williams reported income from continuing operations of $248.6 million, or 42 cents per share on a diluted basis, compared with a loss of $2.3 million, or a loss of 1 cent per share, for the same period in 2004 on a restated basis.
CEO Perspective
“The benefit of having diversity in our businesses and our revenue streams was evident during the third quarter,” said Steve Malcolm, chairman, president and chief executive officer.
“We were able to create value and produce positive results, despite dealing with the hurricanes and a variety of factors that strained results in our Power business.
“At the same time, our cash flows remain strong, we’re raising our guidance and we’ve increased our capital spending estimate for 2006.
“We’re making these investments to produce the natural gas that America needs, to provide reliable services to our customers, and to seize opportunities to help bring even more energy online by building new pipeline and processing systems,” Malcolm added.
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 for 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 impact to reflect income as though mark-to-market accounting had never been applied to Power’s designated hedges and other
derivatives – was $125.3 million, or 22 cents per share, for the third quarter of 2005. In last year’s third quarter, the adjusted recurring income from continuing operations was $49.0 million, or 9 cents per share, on a restated basis.
Results for the 2005 quarter reflect the benefit of increased natural gas production and higher net realized average prices for production sold, along with reduced levels of interest expense.
For the first nine months of 2005, recurring income from continuing operations – after adjusting for the mark-to-market impact to reflect income as though mark-to-market accounting had never been applied to Power’s designated hedges and other derivatives – was $357.3 million, or 60 cents per share, compared with $139.3 million, or 27 cents per share, for the same period in 2004 on a restated basis.
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 $214.6 million in the third quarter of 2005.
In the third quarter a year ago, these businesses reported combined segment profit of $433.6 million on a restated basis.
For the first nine months of 2005, the four major businesses reported combined segment profit of $1.05 billion compared with $1.03 billion for the same period last year on a restated basis.
Results for 2005 have benefited primarily from increased natural gas production volumes and higher net realized average prices, and steady, expected performance in Gas Pipeline. Results for 2005 have been negatively affected by the level of forward unrealized mark-to-market losses during the third quarter.
Exploration & Production: Volumes Up 19 Percent for First Nine Months of 2005
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 third-quarter 2005 segment profit of $158.8 million.
In the third quarter a year ago, the business reported segment profit of $70.1 million. The improvement for the 2005 quarter reflects the benefit of significant increases in both production volumes and net realized average prices for production sold, along with a $21.7 million gain on the sale of certain outside-operated properties. These benefits were partially offset by higher expenses and a $15.8 million loss due to hedge ineffectiveness for future periods associated with the company’s NYMEX collars.
For the first nine months of 2005, Exploration & Production reported segment profit of $380.8 million, compared with $164.9 million for the same period last year. The increase is primarily a result of the same production and pricing factors listed above.
Year-to-date through Sept. 30, average daily production from domestic and international interests was approximately 649 million cubic feet of gas equivalent (MMcfe), compared with 546 MMcfe for the same period in 2004 – an increase of approximately 19 percent.
Average daily domestic production volumes for the third quarter of 2005 totaled 629 MMcfe. That was approximately 18 percent higher than domestic volumes of 535 MMcfe from the same quarter a year ago. Increased production continues to primarily reflect higher volumes in the Piceance Basin. Williams also is realizing favorable production growth from the Big George area in the Powder River Basin.
Year-over-year, the business has benefited from higher domestic production prices, offset somewhat by higher expenses. In addition, average sales prices in 2005 reflect a lower share of volumes that are hedged and increased contracted prices on the volumes that are hedged. During the third quarter of 2005, Williams realized net domestic average prices of $4.80 per Mcfe compared with $3.34 per Mcfe in the third quarter a year ago – an increase of approximately 44 percent.
Williams currently has 15 rigs operating in the Piceance Basin of western Colorado – its cornerstone property for production growth. Williams also is preparing to deploy a new rig from Helmerich & Payne in the Piceance later this month or in early December. The original delivery schedule has been impacted by approximately one month due to disruptions caused by Hurricane Rita at a fabrication facility. A total of 10 new rigs are scheduled for delivery in the Piceance during 2005 and 2006. Williams has each of the new rigs under contract for a term of three years.
Williams now plans to spend between $675 million to $725 million in its Exploration & Production business in 2005, compared with previous guidance of $605 million to $680 million. The change is primarily due to increased activity for new opportunities in the Piceance Basin, accelerated drilling in the Powder River Basin and increased drilling costs.
Williams also has increased its expectation for segment profit from Exploration & Production in 2005. The company now expects $575 million to $600 million in segment profit, which includes $29 million of non-recurring income and the negative impact of the $15.8 million loss due to hedge ineffectiveness. That expectation is up from previous guidance of $410 million to $485 million for that measure. The increase is primarily the result of higher realized prices during the third quarter and expected prices during the fourth quarter.
Midstream Gas & Liquids: Seizes Growth Opportunities in West, Deepwater Gulf
Midstream, which provides natural gas gathering and processing services, along with natural gas liquids (NGL) fractionation and storage services and olefins production, reported third-quarter 2005 segment profit of $121.1 million.
In the third quarter a year ago, the business reported segment profit of $105.4 million on a restated basis. The quarterly improvement primarily reflects increased gathering and processing fee income; higher natural gas liquids production margins realized in the West; and the absence of a $16.5 million unfavorable adjustment to revenues recorded in third-quarter 2004. These benefits were offset partially by lower revenues associated with natural gas gathering and processing facilities that were affected by production shut-ins caused by hurricanes Katrina and Rita. More information about these events is contained later in the news release.
For the first nine months of 2005, Midstream reported segment profit of $358.8 million compared with a restated $314 million for the same period last year.
Through Sept. 30, Midstream had sold 1.01 billion gallons of NGL equity volumes compared with equity sales of 1.03 billion gallons for the first three quarters of 2004. Third-quarter 2005 performance was negatively affected by hurricanes Katrina and Rita. These equity volumes are retained and subsequently marketed by Williams as payment-in-kind under the terms of certain processing contracts.
Gathering and processing volumes increased modestly year-over-year despite the effects of hurricanes Katrina and Rita during the third quarter. Gathering volumes were 949.4 trillion British thermal units (TBtu) in the first three quarters of 2005, compared with 931.4 TBtu in the 2004 period. Fee processing volumes in the first three quarters of 2005 were 555.8 TBtu compared with 555.2 TBtu in the first nine months of 2004.
Williams’ financial results for Midstream have benefited from favorable natural gas liquids (NGL) margins in both 2005 and 2004, particularly in its western U.S. natural gas processing operations in areas such as Opal and Wamsutter in Wyoming.
Citing the increased demand for processing capacity, Williams today announced plans to expand its Opal, Wyo., facility by adding a fifth cryogenic processing train. The project is designed to boost the overall processing capacity of Williams’ Opal facility from more than 1.1 billion cubic feet per day to approximately 1.45 billion cubic feet per day, with the ability to recover approximately 68,000 barrels per day of NGL products. Work on the project is scheduled to be completed in second-quarter 2007.
Subsequent to the close of the third quarter, Williams also announced a $177 million offshore expansion to gather oil and gas from the Blind Faith Field in the deepwater Gulf of Mexico. To accommodate this anticipated production, Williams has agreed to extend its Canyon Chief and Mountaineer pipelines by 37 miles each. The project is scheduled for completion in third-quarter 2007.
During the third quarter, Williams Partners L.P. (NYSE:WPZ) completed its initial public offering. The Williams Companies, Inc. (NYSE:WMB) and certain of its affiliates own approximately 60 percent of the new master limited partnership that primarily gathers, transports and processes natural gas and fractionates and stores natural gas liquids.
In addition to Williams Partners’ initial asset portfolio, Williams now proposes to sell an approximate 25 percent interest in its existing gathering and processing assets in the Four Corners area to the master limited partnership.
On a 100 percent basis, the unaudited operating income plus depreciation from the Four Corners assets has been $154 million, $151 million and $165 million for 2002, 2003 and 2004 respectively. The same measure for the first nine months of 2005 is $136 million.
The terms of this proposed transaction, including price, will be subject to approval by the boards of directors of both Williams and Williams Partners’ general partner. Assuming such approvals are obtained, it is expected that the transaction would be completed during the second quarter of 2006.
Williams continues to plan to spend $120 million to $140 million on capital expenditures in its Midstream business in 2005.
Williams has increased its expectation for segment profit from Midstream in 2005. The company now expects $440 million to $480 million in segment profit from Midstream. That expectation is changed from previous guidance of $400 million to $470 million for that measure. The increase is primarily the result of favorable liquids margins.
Gas Pipeline: Expansions Tied to Market Demand
Gas Pipeline, which primarily delivers natural gas to markets along the Eastern Seaboard, in Florida and in the Northwest, reported third-quarter 2005 segment profit of $161.1 million. In the third quarter a year ago, the business reported segment profit of $148.8 million.
The increase in third-quarter 2005 segment profit compared with a year ago is primarily attributable to the benefit of a $14.2 million favorable adjustment from the resolution of litigation associated with its fuel tracker filings and an increase in equity earnings from Gulfstream Natural Gas System, L.L.C., a joint venture in which Williams owns a 50 percent interest. These items were partially offset by the termination of a firm transportation agreement related to the Gray’s Harbor lateral on the Northwest system effective January 2005.
For the first nine months of 2005, Gas Pipeline reported segment profit of $493 million compared with $429 million for the same period last year. The increase for the nine-month period in 2005 is primarily the result of the previously noted litigation adjustment; the benefit of a second-quarter pension expense correction of $17 million; approximately $13 million in liability reductions associated with prior periods; $16 million in higher equity earnings from its Gulfstream investment; and the absence of a $9 million write-off of capitalized costs in 2004. These were partially offset by the termination of the previously mentioned Gray’s Harbor agreement.
Following the close of the third quarter, Transco completed construction of a $16 million project to add 105,000 dekatherms per day of new firm service in central New Jersey. This expansion was placed into service Nov. 1.
Transco also completed a successful open season in the third quarter for new capacity into the greater Washington, D.C., area. Customers executed precedent agreements for a total of 165,000 Dth/d of firm transportation service from receipt points in Guilford and Rockingham counties in North Carolina to certain mainline delivery points in northern Virginia and Maryland. The project, which is subject to Federal Energy Regulatory Commission approval, is anticipated to be placed into service in November 2007.
Within the past week, Transco and Northwest Pipeline also announced new open seasons to provide between 200,000 and 300,000 Dth/d of additional capacity in the Northeast and approximately 575,000 Dth/d of additional capacity in Colorado, respectively.
In Washington state, Williams has received final approval from the FERC to construct and operate approximately 80 miles of 36-inch pipeline loop in the existing Northwest Pipeline right of way between Sumas and Washougal, Wash. The estimated $333 million project will replace most of the capacity served previously by 268 miles of an existing 26-inch pipeline. Most of the construction is scheduled to occur in 2006 with an in-service date of November 2006.
In August, Gulfstream began providing transportation service to Tampa Electric under a new long-term firm service agreement. The new contract provides up to 48,000 Dth/d to serve the H.L. Culbreath Bayside power generation facility in Hillsborough County, Fla.
In October, Gulfstream completed a debt offering, issuing $850 million of senior unsecured notes of various maturities to certain institutional investors via a 144A private placement. Gulfstream used the proceeds to repay an existing construction loan and to return capital to its equity owners, including approximately $310 million to Williams.
Williams is raising the low end of its 2005 capital spending range for Gas Pipeline by $20 million to reflect higher activity through the third quarter. The company now plans to spend $390 million to $420 million in capital expenditures for Gas Pipeline this year.
Williams also is increasing its expectation for 2005 segment profit from Gas Pipeline. The company now expects $630 million to $645 million in segment profit from this business, which includes $50 million of non-recurring items and adjustments related to prior periods. Williams previously expected $590 million to $615 million in segment profit for 2005. The increase is primarily the result of the $14 million non-recurring item recorded in the third quarter, as well as lower than anticipated expenses in the last half of the year.
Power: Continues Cash-Flow Positive Year-to-Date
Power manages an approximately 7,000-megawatt power portfolio and provides services that support Williams’ natural gas businesses.
3Q Power Recurring Segment Profit Adjusted for Mark-to-Market Impact
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| | | 3Q '05 | | | 3Q '04 | |
| | | (millions) | | | (millions) | |
| Recurring Segment profit (loss) | | ($ | 226.0 | ) | | $ | 109.3 | |
| Mark-to-market adjustments — net | | | 213.0 | | | | (142.2 | ) |
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| Recurring segment loss after mark-to-market adjustments | | ($ | 13.0 | ) | | ($ | 32.9 | ) |
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YTD Power Recurring Segment Profit Adjusted for Mark-to-Market Impact
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| | | YTD '05 | | | YTD '04 | |
| | | (millions) | | | (millions) | |
| Recurring Segment profit (loss) | | ($ | 162.4 | ) | | $ | 121.1 | |
| Mark-to-market adjustments — net | | | 160.1 | | | | (87.1 | ) |
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| Recurring segment loss after mark-to-market adjustments | | ($ | 2.3 | ) | | $ | 34.0 | |
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Power reported a third-quarter 2005 segment loss of $226.4 million, significantly reduced from a segment profit for the same quarter a year ago of $109.3 million. The reduction is primarily the result of unfavorable year-over-year changes from forward unrealized mark-to-market results. The changes consist of $141.1 million in forward unrealized mark-to-market losses in third-quarter 2005 versus $187.9 million in forward unrealized mark-to-market gains in third-quarter 2004. The mark-
to-market gains in the third quarter of 2004 resulted primarily from gas price increases on net long gas contracts that did not qualify for hedge accounting. The mark-to-market losses in third-quarter 2005 resulted from gas price increases on net short gas contracts that do not qualify for hedge accounting.
Due to the adoption of hedge accounting in fourth-quarter 2004 and the related designation of certain derivative contracts as hedges, there was a significant change in the pool of contracts that are subject to changes in fair value being recognized as mark-to-market income in the current period.
In recognition of its stated business intent, Power seeks to reduce its economic risk by selling power forward and by buying needed gas forward to maintain a balanced position. During third-quarter 2005 as new power sales/hedges were being completed, and in the normal course of business to reduce risk, Power began reducing certain less effective hedges by entering into offsetting economic contracts. Some of these offsetting contracts did not qualify for hedge accounting and the related changes in fair value were recorded as mark-to-market losses in the current period. Net unrealized gains of $379 million related to the effective portion of Power’s hedges are reported in accumulated other comprehensive loss in third-quarter 2005.
Power reported a recurring segment loss adjusted for the effect of mark-to-market accounting of $13.0 million in third-quarter 2005, compared with a loss of $32.9 million a year ago. The year-over-year improvement primarily reflects the absence of losses from the interest rate and crude and refined products portfolio, offset by the effects of milder weather in California, an unplanned outage at the Ironwood facility and the impact of Hurricane Katrina.
For the first nine months of 2005, Power reported a segment loss of $187.3 million compared with segment profit of $121.1 million for the same period in 2004. That change is primarily the result of $179 million in lower forward unrealized mark-to-market gains this year, the impact of milder weather in California, lower spark spreads due to higher natural gas prices, the losses from Hurricane Katrina, the outage at the Ironwood facility and $12 million in higher expenses related to settlements and litigation contingencies.
For the first nine months of 2005, Power reported a recurring segment loss of $2.3 million adjusted for the effect of mark-to-market accounting, compared with segment profit of $34.0 million for the same period in 2004.
The year-over-year decline is primarily due to milder weather in California, losses from Hurricane Katrina, the outage at the Ironwood facility in the third quarter, and the absence of a legacy natural gas portfolio that liquidated in first-quarter 2004, offset by the absence of losses in the interest rate portfolio, which was liquidated in fourth-quarter 2004, and the absence of losses in the crude and refined products portfolio.
During and subsequent to this year’s third quarter, Power completed four new power sales contracts, ranging in term and volume, through 2010. These new contracts effectively reduce risk, increase value and increase cash-flow certainty. Additionally, these power sales reduce the portfolio’s future exposures to fuel-price and weather volatility.
In the third quarter of 2005, Power used approximately $41 million in cash flow from operations, largely the result of the above referenced portfolio losses and working capital changes. For the first nine months of 2005,
Power generated approximately $44 million in cash flow from operations, largely the result of changes in working capital.
As a result of the unexpectedly mild weather in California and the other factors already listed, the company has changed its 2005 expectation for cash flow from operations in Power to $25 million to $75 million on a basis that excludes future changes in working capital used in commodity risk management activity on behalf of all of Williams’ commodity businesses. Williams previously expected to generate cash flow from operations of $50 million to $150 million in 2005.
As a result of the large mark-to-market losses recorded in the third quarter, coupled with the effects of higher natural gas prices and milder summer weather in California, Williams now expects a revised segment loss of between $175 million to $225 million from Power on a basis that excludes future mark-to-market changes. Williams previously expected a segment profit range of a $50 million loss to a $50 million profit.
On a basis adjusted for the effects of mark-to-market accounting, Williams also has revised its expectation for Power’s 2005 recurring earnings to range from a loss of $50 million to break even due to the mild weather and other factors previously mentioned. Williams previously expected Power to generate 2005 recurring earnings of $50 million to $150 million on a basis adjusted for the effects of mark-to-market accounting.
Cash, Liquidity and Debt: New Credit Facilities Provide Additional Liquidity
For the year through Sept. 30, net cash provided by operating activities was $1.08 billion, compared with $1.09 billion for the same period in 2004. The company has increased its expectation for cash flow in 2005 to $1.325 billion to $1.525 billion. The company previously expected $1.15 billion to $1.45 billion for the year.
At the end of the third quarter, Williams had total liquidity of more than $2 billion. This consists of unrestricted cash and cash equivalents of approximately $1.4 billion, other liquid investments of $86 million, and $768 million in unused and available revolving credit facilities.
In September, the company obtained $700 million in two five-year unsecured credit facilities. Williams now has a total of $2.475 billion in credit facilities.
For the first three quarters of 2005, Williams has realized a year-over-year decrease in interest expense of $167.6 million as a result of debt reductions. At Sept. 30, 2005, Williams’ total outstanding long-term debt was approximately $7.7 billion.
Gulf Coast Update: Hurricane Rita Hits Close to Home for Operations, Employees
Williams shut-in the majority of its onshore and offshore gathering and processing assets in the Gulf as a precaution in advance of hurricanes Katrina and Rita.
The Transco and Gulfstream natural gas pipeline systems remained operational throughout both hurricanes and continued to meet market demand, although volumes were reduced on both systems because of producers’ storm-related supply shut-ins.
Williams’ operations were relatively unscathed by the first hurricane, but the eye of the second hurricane came through the vicinity of Cameron, La., and Johnsons Bayou where Williams operates the Cameron Meadows natural gas processing plant and a Transco compression and metering station. Both facilities were damaged by the storm and more than half of the company’s 34 employees in the area lost their homes.
Repairs are essentially complete at the Transco compressor station. The facility returned to service at a limited capacity Nov. 1. The station is flowing and dehydrating natural gas.
The Cameron Meadows processing plant sustained significant damage and is expected to remain out of service for an extended period. Williams is evaluating the extent, nature, projected cost and feasibility of repairs at the Cameron Meadows plant. The company also is considering other options for restoring processing services in 2006 for the customers that have been served by the facility. The plant is covered by standard property and business interruption insurance.
Offshore, the Devils Tower deepwater spar at Mississippi Canyon block 773 is preparing to resume commercial operations. Startup is expected to occur today or within the next few days. The facility has been available for service since shortly after Hurricane Katrina, but production had been shut-in until a downstream third-party oil terminal near Venice, La., reopened for business.
Guidance: Company Raises Profit Targets and Capital Spending
In 2005, Williams now expects consolidated segment profit of $1.375 billion to $1.525 billion, compared with previous expectations of $1.3 billion to $1.585 billion for this measure.
On a recurring basis adjusted for the impact of mark-to-market accounting, Williams now expects $1.55 billion to $1.70 billion in consolidated segment profit and earnings per share of 84 cents to 94 cents for 2005. The company previously expected $1.375 billion to $1.660 billion in consolidated segment profit and earnings per share of 70 cents to 90 cents for 2005, on a recurring basis adjusted for the impact of mark-to-market accounting.
In 2006, Williams now expects consolidated segment profit of $1.520 billion to $1.820 billion on a recurring basis adjusted for the impact of mark-to-market accounting, compared with previous expectations of $1.515 billion to $1.815 billion for this measure.
In 2007, Williams now expects consolidated segment profit of $1.830 billion to $2.255 billion on a recurring basis adjusted for the impact of mark-to-market accounting, compared with previous expectations of $1.640 billion to $2.065 billion for this measure.
In 2008, Williams expects consolidated segment profit of $2.05 billion to $2.6 billion on a recurring basis adjusted for the impact of mark-to-market accounting.
Williams cited favorable prices for natural gas as the primary factor for increasing the company’s consolidated segment profit forecasts.
The company’s overall capital budget has increased, as well. It now plans to spend $1.2 billion to $1.35 billion for 2005; $1.825 billion to $2.050 billion for 2006; and $1.425 billion to $1.625 billion for 2007.
Previously, Williams forecasted capital spending of $1.1 billion to $1.3 billion for 2005; $1.525 billion to $1.750 billion for 2006; and $1.1 billion to $1.3 billion for 2007.
The $300 million increase in capital spending guidance for 2006 is budgeted for increased drilling costs and additional drilling in Exploration & Production, along with new infrastructure projects in Midstream.
Today’s Analyst Call
Williams’ management will discuss the company’s third-quarter 2005 financial results and outlook 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 www.williams.com. A limited number of phone lines also will be available at (877) 502-9276. International callers should dial (913) 981-5591. Callers should dial in at least 10 minutes prior to the start of the discussion. Replays will be available atwww.williams.com.
Form 10-Q
The company is filing its Form 10-Q today with the Securities and Exchange Commission. 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 |
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| | | Richard George |
| | | Williams (investor relations) |
| | | (918) 573-3679 |
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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.
Reconciliation of Income (Loss) from Continuing Operations to Recurring Earnings
(UNAUDITED)
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| | | 2004 | | | 2005 | |
| (Dollars in millions, except for per-share amounts) | | 1st Qtr | | | 2nd Qtr | | | 3rd Qtr | | | 4th Qtr | | | Year | | | 1st Qtr | | | 2nd Qtr | | | 3rd 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 | | | $ | 248.6 | |
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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 | | | $ | 0.42 | |
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Nonrecurring items: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Power | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Accrual for a regulatory settlement(1) | | | — | | | | — | | | | — | | | | — | | | | — | | | | 4.6 | | | | — | | | | — | | | | 4.6 | |
Accrual for litigation contingencies(1) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 13.1 | | | | 0.4 | | | | 13.5 | |
| Prior period correction | | | — | | | | — | | | | — | | | | — | | | | — | | | | 6.8 | | | | — | | | | — | | | | 6.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Power nonrecurring items | | | — | | | | — | | | | — | | | | — | | | | — | | | | 11.4 | | | | 13.1 | | | | 0.4 | | | | 24.9 | |
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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 | ) |
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Total Gas Pipeline nonrecurring items | | | — | | | | 9.0 | | | | — | | | | — | | | | 9.0 | | | | (13.1 | ) | | | (21.7 | ) | | | (14.2 | ) | | | (49.0 | ) |
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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 | |
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Total Exploration & Production nonrecurring items | | | — | | | | 11.3 | | | | — | | | | 4.1 | | | | 15.4 | | | | (7.6 | ) | | | — | | | | (21.7 | ) | | | (29.3 | ) |
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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 | | | | | | | | — | | | | — | | | | — | | | | — | | | | — | |
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Total Midstream Gas & Liquids nonrecurring items | | | — | | | | (16.5 | ) | | | 22.9 | | | | (85.0 | ) | | | (78.6 | ) | | | — | | | | — | | | | — | | | | — | |
Other | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Impairment of Longhorn | | | — | | | | 10.8 | | | | — | | | | — | | | | 10.8 | | | | — | | | | 49.1 | | | | — | | | | 49.1 | |
| Write-off of capitalized project development costs | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 4.0 | | | | — | | | | 4.0 | |
| Augusta environmental reserve | | | — | | | | — | | | | — | | | | 11.8 | | | | 11.8 | | | | — | | | | — | | | | — | | | | — | |
| Longhorn recapitalization fee | | | 6.5 | | | | — | | | | — | | | | — | | | | 6.5 | | | | — | | | | — | | | | — | | | | — | |
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Total Other nonrecurring items | | | 6.5 | | | | 10.8 | | | | — | | | | 11.8 | | | | 29.1 | | | | — | | | | 53.1 | | | | — | | | | 53.1 | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nonrecurring items included in segment profit (loss) | | | 6.5 | | | | 14.6 | | | | 22.9 | | | | (69.1 | ) | | | (25.1 | ) | | | (9.3 | ) | | | 44.5 | | | | (35.5 | ) | | | (0.3 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | — | | | | 102.4 | | | | 170.8 | | | | 24.5 | | | | 297.7 | | | | 2.7 | | | | (8.6 | ) | | | 18.8 | | | | 12.9 | |
Total nonrecurring items | | | 6.5 | | | | 117.0 | | | | 193.7 | | | | (44.6 | ) | | | 272.6 | | | | (6.6 | ) | | | 35.9 | | | | (16.7 | ) | | | 12.6 | |
Tax effect for above items(1) | | | 2.5 | | | | 44.8 | | | | 74.1 | | | | (17.1 | ) | | | 104.3 | | | | (2.8 | ) | | | 10.7 | | | | (6.4 | ) | | | 1.5 | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 | ) | | $ | 259.7 | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Recurring diluted earnings (loss) per common share | | $ | 0.01 | | | $ | 0.10 | | | $ | 0.26 | | | $ | 0.12 | | | $ | 0.49 | | | $ | 0.33 | | | $ | 0.11 | | | ($ | 0.01 | ) | | $ | 0.44 | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted-average shares — diluted (thousands) | | | 519,485 | | | | 521,698 | | | | 529,525 | | | | 586,497 | | | | 535,611 | | | | 599,422 | | | | 578,902 | | | | 580,735 | | | | 604,749 | |
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| (1) | | No tax effect on $.6 million of the accrual for a regulatory settlement in 1st quarter 2005 and $8 million of the accrual for litigation contingencies in 2nd quarter 2005. |
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.
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| Reconciliation of Mark-to-Market Adjustments |
| | | | | | | | | | | | | | | | | | | | | |
| | | 2005 | |
| Dollars in millions except for per share amounts | | 1Q | | | 2Q | | | 3Q | | | 4Q | | | Year | |
Recurring income from cont. ops available to common shareholders | | $ | 198 | | | $ | 66 | | | $ | (5 | ) | | | | | | $ | 260 | |
Recurring diluted earnings per common share | | $ | 0.33 | | | $ | 0.11 | | | $ | (0.01 | ) | | | | | | $ | 0.44 | |
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| Mark-to-Market (MTM) adjustments: | | | | | | | | | | | | | | | | | | | | |
| Reverse forward unrealized MTM gains/losses | | | (221 | ) | | | (22 | ) | | | 153 | | | | | | | | (90 | ) |
| Add realized gains/losses from MTM previously recognized | | | 113 | | | | 77 | | | | 60 | | | | | | | | 250 | |
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| Total MTM adjustments | | | (108 | ) | | | 55 | | | | 213 | | | | | | | | 160 | |
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| Tax effect of total MTM adjustments (at 39%) | | | (42 | ) | | | 21 | | | | 83 | | | | | | | | 62 | |
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| After tax MTM adjustments | | | (66 | ) | | | 34 | | | | 130 | | | | | | | | 98 | |
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Recurring income from cont. ops available to common shareholders after MTM adjust. | | $ | 132 | | | $ | 100 | | | $ | 125 | | | | | | | $ | 357 | |
Recurring diluted earnings per share after MTM adj. | | $ | 0.22 | | | $ | 0.17 | | | $ | 0.22 | | | | | | | $ | 0.60 | |
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| weighted average shares — diluted (thousands) | | | 599,422 | | | | 578,902 | | | | 580,735 | | | | | | | | 604,749 | |
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| | | 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 | |
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| 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 (at 39%) | | | 44 | | | | (23 | ) | | | (55 | ) | | | (11 | ) | | | (46 | ) |
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| | | | | | | | | | | | | | | | | | | | | |
| After tax MTM adjustments | | | 68 | | | | (36 | ) | | | (87 | ) | | | (17 | ) | | | (72 | ) |
| |
Recurring income from cont. ops available to common shareholders after MTM adjust. | | $ | 72 | | | $ | 18 | | | $ | 49 | | | $ | 50 | | | $ | 189 | |
Recurring diluted earnings per share after MTM adj. | | $ | 0.14 | | | $ | 0.03 | | | $ | 0.09 | | | $ | 0.09 | | | $ | 0.35 | |
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| | | | 519,485 | | | | 521,698 | | | | 529,525 | | | | 586,497 | | | | 535,611 | |
