Exhibit 99.1
Date: May 4, 2006
Williams Reports First Quarter 2006 Financial Results
| • | | Proved, Probable and Possible Reserves Increase 22% to 10.7 Tcfe |
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| • | | Natural Gas Production Up 16% to 714 MMcfe per day |
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| • | | Williams Continues to Deploy New Rigs in the Piceance Basin |
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| • | | Gathering & Processing Revenues Drive Midstream to Near-Record Quarter |
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| • | | Company Working To Complete $360 Million Transaction with Williams Partners L.P. |
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| Quarterly Summary Information | | 1Q 2006 | | | 1Q 2005 | |
| Per share amounts are reported on a diluted basis | | millions | | | per share | | | millions | | | per share | |
| Income from continuing operations | | $ | 131.1 | | | $ | 0.22 | | | $ | 202.2 | | | $ | 0.34 | |
| Income (loss) from discontinued operations | | $ | 0.8 | | | | — | | | | ($1.1 | ) | | | — | |
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| Net income | | $ | 131.9 | | | $ | 0.22 | | | $ | 201.1 | | | $ | 0.34 | |
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| Recurring income from continuing operations* | | $ | 135.9 | | | $ | 0.23 | | | $ | 198.4 | | | $ | 0.33 | |
| After-tax mark-to-market adjustments | | $ | 21.1 | | | $ | 0.03 | | | | ($66.0 | ) | | | ($0.11 | ) |
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| Recurring income from continuing operations — after mark-to-market adjustment* | | $ | 157.0 | | | $ | 0.26 | | | $ | 132.4 | | | $ | 0.22 | |
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* A schedule reconciling income from continuing operations to recurring income from continuing operations and mark-to-market adjustments (non-GAAP measures) is available at www.williams.com and as an attachment to this press release.
TULSA, Okla. — Williams (NYSE:WMB) today announced first-quarter 2006 unaudited net income of $131.9 million, or 22 cents per share on a diluted basis, compared with net income of $201.1 million, or 34 cents per share, for first-quarter 2005.
The first quarter of 2005 benefited from $221.1 million in unrealized mark-to-market gains from the Power segment, compared with $43.0 million in unrealized mark-to-market gains in the first quarter of 2006.
Results for the first quarter of 2006 also reflect increased natural gas production and higher net realized average prices for production sold, along with increased gathering and processing revenue in Midstream. These benefits were offset by higher operating expenses.
On a basis adjusted for the effect of mark-to-market accounting, Williams earned 26 cents per share in the first quarter of 2006, up from 22 cents per share a year ago. Additional detail about the mark-to-market adjustment is included in this news release.
CEO Perspective
“We’re fully engaged in expanding our business in a way that creates additional economic value,” said
Steve Malcolm, chairman, president and chief executive officer.
“At the beginning of the year, we outlined ambitious three-year goals that include increasing segment profit by 50 percent and growing natural gas production to more than one billion cubic feet per day by 2008.
“Based on our performance in the first quarter, we’re getting out of the gate on the right foot. Natural gas production is up 16 percent and we achieved near-record segment profit in Midstream.
“The results in Midstream provide an example of why we choose to have an integrated business model at Williams. Even though natural gas prices are down somewhat, Midstream benefits from the margin between these lower fuel costs and higher prices for its NGL products.
“We’re also continuing to invest capital and seize opportunities to execute on our strategy of driving even greater results and returns in 2007 and 2008. Our capital investments increased more than 100 percent in the first quarter, up from $223 million a year ago to $468 million this year.
“We’re focusing much of this capital on the rapid development of our natural gas reserves. Our total proved, probable and possible reserves have increased by 22 percent because of our early drilling success in the Piceance Highlands.”
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 — increased 19 percent from a year ago, up from $132.4 million, or 22 cents per share in 2005, to $157.0 million, or 26 cents per share, for the first quarter of 2006.
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
Consolidated results include segment profit for Williams’ primary businesses — Exploration & Production, Midstream Gas & Liquids, Gas Pipeline and Power — as well as results reported in the Other segment.
Consolidated Recurring Segment Profit Adjusted for Mark-to-Market Effect
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| | | 1Q '06 | | | 1Q '05 | |
| | | (millions) | | | (millions) | |
| Segment profit | | $ | 412.3 | | | $ | 509.7 | |
| Non-recurring adjustments | | | ($8.3 | ) | | | ($9.3 | ) |
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| Recurring segment profit | | $ | 404.0 | | | $ | 500.4 | |
| Reverse forward unrealized mark-to-market gains | | | ($43.0 | ) | | | ($221.1 | ) |
| Add realized mark-to-market gains that were previously recognized | | $ | 77.1 | | | $ | 113.0 | |
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| Recurring segment profit after mark-to-market adjustments | | $ | 438.1 | | | $ | 392.3 | |
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Williams’ businesses reported consolidated segment profit of $412.3 million in the first quarter of 2006, compared with $509.7 million a year ago. Results were reduced from a year ago primarily due to lower levels of forward unrealized mark-to-market gains in the Power segment.
On a basis adjusted for the effect of mark-to-market accounting, Williams had recurring consolidated segment profit of $438.1 million in the first quarter of 2006, compared with $392.3 million a year ago — an increase of 12 percent.
The first quarter of 2006 benefited from increased natural gas production and higher net realized average prices for production sold, along with increased gathering and processing revenue in Midstream.
Exploration & Production: Proved, Probable and Possible Reserves Up 22%
Exploration & Production reported first-quarter 2006 segment profit of $147.6 million, up 42 percent from a year ago when the business reported segment profit of $103.7 million.
These activities include natural gas production and development in the U.S. Rocky Mountains, San Juan Basin and Mid-Continent, and oil and natural gas operations in South America.
The year-over-year improvement reflects significant increases in both production volumes and net realized average prices for production sold, as well as a $9 million increase in unrealized gains from hedge ineffectiveness. These increases were partially offset by higher lease operating expenses and depreciation, depletion and amortization, and the absence of an $8 million gain on the sale of certain assets in 2005.
In the first quarter of 2006, average daily production from domestic and international interests was approximately 714 million cubic feet of gas equivalent (MMcfe), compared with 614 MMcfe in the first quarter of 2005 — an increase of 16 percent. The increased production was primarily from the Piceance Basin.
First-quarter 2006 average daily production solely from domestic volumes increased 16 percent from the same period a year ago, growing from 568 MMcfe to 661 MMcfe.
The business also benefited from its ability in the first quarter to realize domestic production prices averaging 18 percent higher than last year.
Williams has 21 rigs operating in the Piceance Basin of western Colorado — its cornerstone properties for
production growth. The rig count includes four new-generation drilling rigs that are purpose-built for conditions in the Piceance Basin.First-quarter 2006 average daily production from the Piceance Basin was 360 MMcfe per day — a 29 percent increase over year-ago levels.
Williams also has increased the company’s total proved, probable and possible reserves to an estimated 10.7 trillion cubic feet equivalent (Tcfe) — an increase of 22 percent from the previous estimate of 8.8 Tcfe. This figure includes 3.6 Tcfe of proved reserves at Dec. 31, 2005. Total reserves are comprised of international and domestic interests.
The increase in estimated reserves is based on Williams’ latest analysis, particularly from its early drilling results in the relatively undeveloped areas of the Piceance Highlands.
Williams has lowered the range of segment profit it expects in 2006 from Exploration & Production.
Williams previously expected $650 million to $725 million in segment profit for Exploration & Production this year. The company now expects $525 million to $625 million in segment profit for this business. The decrease is primarily the result of lower realized and projected natural gas prices.
Midstream Gas & Liquids: Increases Guidance by $100 Million for 2006
Midstream reported first-quarter 2006 segment profit of $151.5 million, up 18 percent compared with $128.6 million a year ago.
This business provides natural gas gathering and processing services, along with NGL fractionation and storage services and olefins production.
The year-over-year improvement primarily reflects higher net revenues from its domestic gathering and processing business, as well as $9 million from the favorable resolution of an international contract dispute, partially offset by lower net olefins margins and higher costs from maintenance expenses.
The improvement in the domestic gathering and processing business was driven by significantly higher production handling revenues in the deepwater Gulf of Mexico, higher fee-based processing volumes and revenues and higher per unit NGL margins.
In first-quarter 2006, Midstream sold 333.7 million gallons of NGL equity volumes, a decrease of 16 percent compared with equity sales of 398.7 million gallons in the prior-year period. Lower volumes of equity sales were primarily the result of an increase in volumes subject to fee-based processing contracts.
Gathering volumes in the first quarter of 2006 were 296.9 trillion British thermal units (TBtu), compared with 315.5 TBtu in the 2005 period. Processing fee volumes were 191.8 TBtu in the first quarter of 2006, compared with 181.0 TBtu in the 2005 period. Revenues for both gathering and fee-based processing were higher year over year.
For the NGL equity volumes that Williams retains under certain processing contracts, the company continues to benefit from favorable margins. For the seventh quarter in a row, NGL sales margins remained above the company’s five-year average.
The Cameron Meadows natural gas plant in Louisiana’s Cameron Parish has been processing approximately 270 million cubic feet per day (MMcf/d) since returning to partial service in February. The facility is now scheduled to return to its full design capacity of 500 MMcf/d early in the third quarter. The plant was damaged by Hurricane Rita last September.
In Wyoming, Williams has received a permit to begin construction of the fifth cryogenic gas processing train at its Opal, Wyo., facility. The project will boost Opal’s overall processing capacity from 1.1 billion cubic feet per day (Bcf/d) to more than 1.45 Bcf/d, with the ability to recover in excess of 68,000 barrels per day of NGL products.
Subsequent to the close of the quarter, Williams also reached an agreement with Williams Partners L.P. (NYSE:WPZ) for its acquisition of a 25.1 percent interest in Williams’ Four Corners LLC subsidiary, which at closing will own certain gathering, processing and treating assets in the Four Corners area. The $360 million transaction — subject to standard closing conditions — is expected to close in the second quarter.
Williams has increased by $100 million the range of segment profit it expects in 2006 from Midstream. The company now expects $500 million to $600 million in segment profit from Midstream. The increase is primarily the result of higher first-quarter gathering and processing results, as well as projected NGL margins for the balance of the year. The company has entered into fixed-price sales contacts for a portion of its 2006 NGL production.
Gas Pipeline: Rate Case Filings On-Schedule
Gas Pipeline reported first-quarter 2006 segment profit of $134.7 million, down 20 percent compared with $167.4 million a year ago.
Gas Pipeline primarily delivers natural gas to markets along the Eastern Seaboard, in the Northwest, and in Florida.
The 2005 period benefited from $13 million in expense reductions related to prior periods and a $4.6 million construction fee that was associated with completing an expansion project.
The decrease in first-quarter 2006 segment profit is also attributable to higher operating costs, driven in part by higher labor costs, certain environmental remediation costs, hurricane-related damage assessments, pipeline integrity spending, and feasibility costs associated with certain business development projects.
Williams continues to prepare for new rate case filings with the Federal Energy Regulatory Commission later this year. The company expects to complete its filing for Northwest Pipeline in July and its filing for Transco in September. The new rates are expected to be effective by January and March 2007, respectively.
During the first quarter, Gulfstream reached a 23-year agreement to provide up to 345,000 dekatherms per day of firm natural gas transportation service to a Florida utility. With the agreement, all of Gulfstream’s nearly 1.1 billion dekatherms of capacity is now under firm long-term contract. Williams owns a 50-percent interest in the Gulfstream Natural Gas System, L.L.C., joint venture.
Subsequent to the close of the quarter, Northwest Pipeline finalized a partnership with two other companies to develop the Pacific Connector Gas Pipeline. The proposed 223-mile project would connect a proposed liquefied natural gas terminal being developed near Coos Bay, Ore., to two pipeline systems, including Northwest. The project — tentatively expected to be completed in 2010 — is in the preliminary stages and is subject to environmental reviews and FERC approval.
Williams continues to expect $475 million to $520 million in segment profit from Gas Pipeline in 2006.
Power: On-Course to Meet 2006 Expectations
Power manages a portfolio of more than 7,000 megawatts and provides services that support Williams’ natural gas businesses.
Power Recurring Segment Profit Adjusted for Mark-to-Market Effect
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| | | 1Q '06 | | | 1Q '05 | |
| | | (millions) | | | (millions) | |
| Segment profit (loss) | | | ($22.5 | ) | | $ | 114.1 | |
| Non-recurring adjustments | | $ | 0.0 | | | $ | 11.4 | |
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| Recurring segment profit (loss) | | | ($22.5 | ) | | $ | 125.5 | |
| Mark-to-market adjustments — net | | $ | 34.1 | | | | ($108.1 | ) |
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| Recurring segment profit after mark-to-market adjustments | | $ | 11.6 | | | $ | 17.4 | |
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Power reported a first-quarter 2006 segment loss of $22.5 million, compared with a segment profit of $114.1 million in the same period in 2005. Results include the effect of forward non-cash unrealized mark-to-market gains and losses.
The year-over-year reduction is primarily the result of lower non-cash unrealized mark-to-market gains, partially offset by lower selling, general and administrative expenses.
On a basis adjusted for the effect of mark-to-market accounting, Power reported recurring segment profit of $11.6 million in first-quarter 2006, down 33 percent compared with $17.4 million in 2005.
The year-over-year decline in adjusted recurring segment profit reflects lower results from the natural gas portfolio, partially offset by higher results from the power portfolio and lower selling, general and administrative expenses. Lower expenses are primarily due to the positive effect of a $23.7 million gain on the sale of certain third-party receivables.
To date in 2006, Power has completed six new sales contracts that range in term and volume through December 2009. These contracts effectively reduce risk and increase cash-flow certainty.
In the first quarter, Power used approximately $142 million in cash flow from operations, largely the result of working capital changes that include the payment of margin dollars to counterparties on behalf of other Williams’ entities.
On a standalone basis, excluding working capital used or received for other Williams’ entities, Power generated $9 million in cash flow from operations in the first quarter. Williams continues to expect $50 million to
$150 million of standalone cash flow from operations in Power this year, excluding changes in working capital and payment of accruals associated with gas reporting agreements.
For 2006, Williams has decreased by $30 million the range of segment loss it expects from Power due to unrealized mark-to-market earnings in the first quarter. The company now expects a $105 million to $205 million segment loss from Power, absent the effect of any future unrealized mark-to-market gains or losses.
On a basis adjusted for the effect of mark-to-market accounting, Williams continues to expect Power to generate 2006 recurring segment profit of $50 million to $150 million.
Cash and Debt: Company Replacing Nearly All Secured Debt
At the close of business on March 31, 2006, Williams had total liquidity of approximately $2.6 billion. This consisted of approximately $1.1 billion in unrestricted cash and cash equivalents, approximately $184 million in other liquid investments and $1.3 billion in unused and available revolving credit facilities.
With regard to the company’s revolving credit facilities, on May 1 Williams replaced an existing $1.275 billion secured facility with a new $1.5 billion unsecured facility. The new revolver removed the last secured debt from Williams’ credit portfolio, with the exception of non-recourse project debt for its operations in Venezuela.
Subsequent to the close of the first quarter, Williams’ liquidity was reduced by approximately $489 million for the early retirement of secured debt — including related interest — that was scheduled to mature in 2008. Williams plans to replace a portion of this liquidity on an unsecured basis later this year.
Williams’ total outstanding debt at March 31, 2006, was approximately $7.4 billion. As Williams supports its planned capital investments during 2006, the company expects to conclude the year at a debt level that is comparable with year-end 2005.
Net cash provided by operating activities in the first quarter was $164.7 million, compared with $304.4 million in the same period a year ago. Net cash in the 2006 quarter was reduced by $150.1 million in margin deposits paid to third parties.
Guidance Through 2008
The forecast for earnings per share in 2006 remains at 78 cents to $1.03 on a recurring basis adjusted for the effect of mark-to-market accounting.
In 2006, Williams continues to expect $1.52 billion to $1.86 billion in consolidated segment profit on a recurring basis adjusted for the effect of mark-to-market accounting.
In 2007, Williams continues to expect consolidated segment profit of $1.83 billion to $2.25 billion on a recurring basis adjusted for the effect of mark-to-market accounting.
In 2008, Williams continues to expect consolidated segment profit of $2.02 billion to $2.58 billion on a recurring basis adjusted for the effect of mark-to-market accounting.
The company’s overall capital budget continues to be $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. More capital may be required based on the potential development of additional projects.
Today’s Analyst Call
Williams’ management will discuss the company’s first-quarter 2006 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 (800) 289-0496. International callers should dial (913) 981-5519. Callers should dial in at least 10 minutes prior to the start of the discussion.
Replays of the first-quarter webcast will be available for two weeks at www.williams.com.
Form 10-K
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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| | | Travis Campbell |
| | | Williams (investor relations) |
| | | (918) 573-2944 |
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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.
Consolidated Statement of Operations
(UNAUDITED)
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| | | 2005 | | | 2006 | |
| (Dollars in millions, except per-share amounts) | | 1st Qtr | | | 2nd Qtr | | | 3rd Qtr | | | 4th Qtr | | | Year | | | 1st Qtr | |
| Revenues | | $ | 2,954.0 | | | $ | 2,871.2 | | | $ | 3,082.3 | | | $ | 3,676.1 | | | $ | 12,583.6 | | | $ | 3,027.5 | |
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| Segment costs and expenses: | | | | | | | | | | | | | | | | | | | | | | | | |
| Costs and operating expenses | | | 2,390.3 | | | | 2,491.6 | | | | 2,826.2 | | | | 3,162.9 | | | | 10,871.0 | | | | 2,588.7 | |
| Selling, general and administrative expenses | | | 73.5 | | | | 62.7 | | | | 90.6 | | | | 98.6 | | | | 325.4 | | | | 71.0 | |
| Other (income) expense — net | | | (1.8 | ) | | | 21.9 | | | | (21.4 | ) | | | 62.5 | | | | 61.2 | | | | (22.3 | ) |
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| Total segment costs and expenses | | | 2,462.0 | | | | 2,576.2 | | | | 2,895.4 | | | | 3,324.0 | | | | 11,257.6 | | | | 2,637.4 | |
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| Equity earnings | | | 17.7 | | | | 9.8 | | | | 17.6 | | | | 20.5 | | | | 65.6 | | | | 22.2 | |
| Loss from investments | | | — | | �� | | (48.4 | ) | | | — | | | | (60.7 | ) | | | (109.1 | ) | | | — | |
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Total segment profit | | | 509.7 | | | | 256.4 | | | | 204.5 | | | | 311.9 | | | | 1,282.5 | | | | 412.3 | |
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| Reclass equity earnings | | | (17.7 | ) | | | (9.8 | ) | | | (17.6 | ) | | | (20.5 | ) | | | (65.6 | ) | | | (22.2 | ) |
| Reclass loss from investments | | | — | | | | 48.4 | | | | — | | | | 60.7 | | | | 109.1 | | | | — | |
| General corporate expenses | | | (28.0 | ) | | | (35.5 | ) | | | (42.8 | ) | | | (48.6 | ) | | | (154.9 | ) | | | (31.8 | ) |
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| Operating income | | | 464.0 | | | | 259.5 | | | | 144.1 | | | | 303.5 | | | | 1,171.1 | | | | 358.3 | |
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| Interest accrued | | | (164.7 | ) | | | (164.6 | ) | | | (166.0 | ) | | | (176.4 | ) | | | (671.7 | ) | | | (162.8 | ) |
| Interest capitalized | | | 1.1 | | | | 1.4 | | | | 1.8 | | | | 2.9 | | | | 7.2 | | | | 3.0 | |
| Investing income (loss) | | | 31.0 | | | | (17.2 | ) | | | 31.1 | | | | (21.2 | ) | | | 23.7 | | | | 46.9 | |
| Early debt retirement costs | | | — | | | | — | | | | — | | | | (0.4 | ) | | | (0.4 | ) | | | (27.0 | ) |
| Minority interest in income of consolidated subsidiaries | | | (5.2 | ) | | | (4.8 | ) | | | (6.8 | ) | | | (8.9 | ) | | | (25.7 | ) | | | (7.1 | ) |
| Other income (expense) — net | | | 5.5 | | | | 8.1 | | | | (1.1 | ) | | | 14.6 | | | | 27.1 | | | | 8.1 | |
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| Income from continuing operations before income taxes and cumulative effect of change in accounting principle | | | 331.7 | | | | 82.4 | | | | 3.1 | | | | 114.1 | | | | 531.3 | | | | 219.4 | |
| Provision (benefit) for income taxes | | | 129.5 | | | | 41.7 | | | | (2.6 | ) | | | 45.3 | | | | 213.9 | | | | 88.3 | |
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Income from continuing operations | | | 202.2 | | | | 40.7 | | | | 5.7 | | | | 68.8 | | | | 317.4 | | | | 131.1 | |
| Income (loss) from discontinued operations | | | (1.1 | ) | | | 0.6 | | | | (1.3 | ) | | | (0.3 | ) | | | (2.1 | ) | | | 0.8 | |
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| Income before cumulative effect of change in accounting principle | | | 201.1 | | | | 41.3 | | | | 4.4 | | | | 68.5 | | | | 315.3 | | | | 131.9 | |
| Cumulative effect of change in accounting principle | | | — | | | | — | | | | — | | | | (1.7 | ) | | | (1.7 | ) | | | — | |
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Net income | | $ | 201.1 | | | $ | 41.3 | | | $ | 4.4 | | | $ | 66.8 | | | $ | 313.6 | | | $ | 131.9 | |
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| | | | | | | | | | | | | | | | | | | | | | | | | |
| Diluted earnings per common share: | | | | | | | | | | | | | | | | | | | | | | | | |
Income from continuing operations | | $ | 0.34 | | | $ | 0.07 | | | $ | 0.01 | | | $ | 0.11 | | | $ | 0.53 | | | $ | 0.22 | |
| Income (loss) from discontinued operations | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | |
| Income before cumulative effect of change in accounting principle | | | 0.34 | | | | 0.07 | | | | 0.01 | | | | 0.11 | | | | 0.53 | | | | 0.22 | |
| Cumulative effect of change in accounting principle | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | |
Net income | | $ | 0.34 | | | $ | 0.07 | | | $ | 0.01 | | | $ | 0.11 | | | $ | 0.53 | | | $ | 0.22 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Weighted-average number of shares used in computation (thousands) | | | 599,422 | | | | 578,902 | | | | 580,735 | | | | 609,106 | | | | 605,847 | | | | 607,073 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Common shares outstanding at end of period (thousands) | | | 570,501 | | | | 571,502 | | | | 572,922 | | | | 573,592 | | | | 573,592 | | | | 595,007 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Market price per common share (end of period) | | $ | 18.81 | | | $ | 19.00 | | | $ | 25.05 | | | $ | 23.17 | | | $ | 23.17 | | | $ | 21.39 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Common dividends per share | | $ | 0.05 | | | $ | 0.05 | | | $ | 0.075 | | | $ | 0.075 | | | $ | 0.25 | | | $ | 0.075 | |
| | |
| 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.
Reconciliation of Income from Continuing Operations to Recurring Earnings (Loss)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2005 | | | 2006 | |
| (Dollars in millions, except per-share amounts) | | 1st Qtr | | | 2nd Qtr | | | 3rd Qtr | | | 4th Qtr | | | Year | | | 1st Qtr | |
Income from continuing operations available to common stockholders | | $ | 202.2 | | | $ | 40.7 | | | $ | 5.7 | | | $ | 68.8 | | | $ | 317.4 | | | $ | 131.1 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Income from continuing operations — diluted earnings (loss) per common share | | $ | 0.34 | | | $ | 0.07 | | | $ | 0.01 | | | $ | 0.11 | | | $ | 0.53 | | | $ | 0.22 | |
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| | | | | | | | | | | | | | | | | | | | | | | | | |
Nonrecurring items: | | | | | | | | | | | | | | | | | | | | | | | | |
Exploration & Production | | | | | | | | | | | | | | | | | | | | | | | | |
| Gain on sale of E&P properties | | | (7.9 | ) | | | — | | | | (21.7 | ) | | | — | | | | (29.6 | ) | | | — | |
| Loss provision related to an ownership dispute | | | 0.3 | | | | — | | | | — | | | | — | | | | 0.3 | | | | — | |
| | | | | | | | | | | | | | | | | | | |
Total Exploration & Production nonrecurring items | | | (7.6 | ) | | | — | | | | (21.7 | ) | | | — | | | | (29.3 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Gas Pipeline | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior period liability corrections — TGPL | | | (13.1 | ) | | | (4.6 | ) | | | — | | | | — | | | | (17.7 | ) | | | — | |
| Prior period pension adjustment — TGPL | | | — | | | | (17.1 | ) | | | — | | | | — | | | | (17.1 | ) | | | — | |
| 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 | | | | — | |
| Reversal of litigation contigency due to favorable ruling — TGPL | | | — | | | | — | | | | — | | | | — | | | | — | | | | (2.0 | ) |
| | | | | | | | | | | | | | | | | | | |
Total Gas Pipeline nonrecurring items | | | (13.1 | ) | | | (21.7 | ) | | | (14.2 | ) | | | 37.3 | | | | (11.7 | ) | | | (2.0 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Midstream Gas & Liquids | | | | | | | | | | | | | | | | | | | | | | | | |
| Settlement of an international contract dispute | | | — | | | | — | | | | — | | | | — | | | | — | | | | (6.3 | ) |
| | | | | | | | | | | | | | | | | | | |
Total Midstream Gas & Liquids nonrecurring items | | | — | | | | — | | | | — | | | | — | | | | — | | | | (6.3 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
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 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Other | | | | | | | | | | | | | | | | | | | | | | | | |
| Impairment of Longhorn | | | — | | | | 49.1 | | | | — | | | | 38.1 | | | | 87.2 | | | | — | |
| Write-off of capitalized project development costs | | | — | | | | 4.0 | | | | — | | | | — | | | | 4.0 | | | | — | |
| Gain on sale of real property | | | — | | | | — | | | | — | | | | (9.0 | ) | | | (9.0 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | |
Total Other nonrecurring items | | | — | | | | 53.1 | | | | — | | | | 29.1 | | | | 82.2 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Nonrecurring items included in segment profit (loss) | | | (9.3 | ) | | | 44.5 | | | | (35.5 | ) | | | 158.1 | | | | 157.8 | | | | (8.3 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Nonrecurring items below segment profit (loss) | | | | | | | | | | | | | | | | | | | | | | | | |
Gain on sale of remaining interests in Seminole Pipeline and MAPL (Investing income / loss — Midstream) | | | — | | | | (8.6 | ) | | | — | | | | — | | | | (8.6 | ) | | | — | |
Loss provision related to an ownership dispute — interest component (Interest accrued — Exploration & Production) | | | 2.7 | | | | — | | | | — | | | | — | | | | 2.7 | | | | — | |
Directors and officers insurance policy adjustment (General corporate expenses — Corporate) | | | — | | | | — | | | | 13.8 | | | | — | | | | 13.8 | | | | — | |
Loss provision related to ERISA litigation settlement (Other income (expense) — net — Corporate) | | | — | | | | — | | | | 5.0 | | | | — | | | | 5.0 | | | | — | |
Legal fees associated with shareholder litigation (General corporate expenses — Corporate) | | | — | | | | — | | | | — | | | | 9.4 | | | | 9.4 | | | | 1.2 | |
Reversal of interest accrual related to reversal of litigation contingency noted above (Other interest expense — Gas Pipeline — TGPL) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (5.0 | ) |
Premium and fees related to convertible debt conversion — (Other income (expense) — net — Corporate) | | | — | | | | — | | | | — | | | | — | | | | — | | | | 27.0 | |
Gain on sale of Algar/Triangulo shares (Investing income / loss — Other) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (6.7 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | | 2.7 | | | | (8.6 | ) | | | 18.8 | | | | 9.4 | | | | 22.3 | | | | 16.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total nonrecurring items | | | (6.6 | ) | | | 35.9 | | | | (16.7 | ) | | | 167.5 | | | | 180.1 | | | | 8.2 | |
Tax effect for above items(1) | | | (2.8 | ) | | | 10.7 | | | | (6.4 | ) | | | 48.0 | | | | 49.5 | | | | 3.4 | |
| Adjustment for nonrecurring excess deferred tax benefit | | | — | | | | — | | | | — | | | | (20.2 | ) | | | (20.2 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Recurring income (loss) from continuing operations available to common stockholders | | $ | 198.4 | | | $ | 65.9 | | | | ($4.6 | ) | | $ | 168.1 | | | $ | 427.8 | | | $ | 135.9 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Recurring diluted earnings (loss) per common share | | $ | 0.33 | | | $ | 0.11 | | | | ($0.01 | ) | | $ | 0.28 | | | $ | 0.72 | | | $ | 0.23 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted-average shares — diluted (thousands) | | | 599,422 | | | | 578,902 | | | | 580,735 | | | | 609,106 | | | | 605,847 | | | | 607,073 | |
| | |
| (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. The tax rate applied to Midstream’s international contract dispute settlement in 1st quarter 2006 is 34%. |
| |
| Note: | | The sum of earnings (loss) per share for the quarters may not equal the total earnings (loss) per share for the year due to changes in the weighted-average number of common shares outstanding. |
Adjustment to remove MTM effect
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Dollars in millions except for per share amounts | | | | | | | |
| | | 2006 | | | | 2005 | |
| | | 1Q | | | 2Q | | | 3Q | | | 4Q | | | Year | | | | 1Q | | | 2Q | | | 3Q | | | 4Q | | | Year | |
Recurring income from cont. ops available to common shareholders | | $ | 136 | | | | | | | | | | | | | | | $ | 136 | | | | $ | 198 | | | $ | 67 | | | $ | (5 | ) | | $ | 168 | | | $ | 428 | |
Recurring diluted earnings per common share | | $ | 0.23 | | | | | | | | | | | | | | | $ | 0.23 | | | | $ | 0.33 | | | $ | 0.11 | | | $ | (0.01 | ) | | $ | 0.28 | | | $ | 0.72 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mark-to-Market (MTM) adjustments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Reverse forward unrealized MTM gains/losses | | | (43 | ) | | | | | | | | | | | | | | | (43 | ) | | | | (221 | ) | | | (22 | ) | | | 141 | | | | (70 | ) | | | (172 | ) |
| Add realized gains/losses from MTM previously recognized | | | 77 | | | | | | | | | | | | | | | | 77 | | | | | 113 | | | | 77 | | | | 72 | | | | 48 | | | | 310 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total MTM adjustments | | | 34 | | | | | | | | | | | | | | | | 34 | | | | | (108 | ) | | | 55 | �� | | | 213 | | | | (22 | ) | | | 138 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Tax effect of total MTM adjustments (at 39%) | | | 13 | | | | | | | | | | | | | | | | 13 | | | | | (42 | ) | | | 21 | | | | 83 | | | | (8 | ) | | | 53 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| After tax MTM adjustments | | | 21 | | | | | | | | | | | | | | | | 21 | | | | | (66 | ) | | | 34 | | | | 130 | | | | (14 | ) | | | 85 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Recurring income from cont. ops available to common shareholders after MTM adjust. | | $ | 157 | | | | | | | | | | | | | | | $ | 157 | | | | $ | 132 | | | $ | 101 | | | $ | 125 | | | $ | 154 | | | $ | 513 | |
Recurring diluted earnings per share after MTM adj. | | $ | 0.26 | | | | | | | | | | | | | | | $ | 0.26 | | | | $ | 0.22 | | | $ | 0.17 | | | $ | 0.22 | | | $ | 0.26 | | | $ | 0.86 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| weighted average shares — diluted (thousands) | | | 607,073 | | | | | | | | | | | | | | | | 607,073 | | | | | 599,422 | | | | 578,902 | | | | 580,735 | | | | 609,106 | | | | 605,847 | |
Adjustments have been made to reverse estimated forward unrealized MTM gains/losses and add estimated realized gains/losses from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives.
