Table of Contents
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): August 5, 2004
The Williams Companies, Inc.
(Exact name of registrant as specified in its charter)
| Delaware | 1-4174 | 73-0569878 | ||
| (State or other | (Commission | (I.R.S. Employer | ||
| jurisdiction of | File Number) | Identification No.) | ||
| incorporation) |
One Williams Center, Tulsa, Oklahoma
|
74172 | |||
(Address of principal executive offices)
|
(Zip Code) | |||
Registrant’s telephone number, including area code: 918/573-2000
Not Applicable
(Former name or former address, if changed since last report)
TABLE OF CONTENTS
Table of Contents
Item 7. Financial Statements and Exhibits.
(a) None
(b) None
(c) Exhibits
Exhibit 99.1
|
Copy of Williams’ slide presentation to be utilized | |
| during the August 5, 2004, public conference call and webcast. | ||
Exhibit 99.2
|
Copy of Williams’ press release dated August 5, 2004, | |
| publicly announcing its second quarter 2004 financial results. | ||
Exhibit 99.3
|
Copy of Williams’ Reconciliation of Income (Loss) from | |
| Continuing Operations to Recurring Earnings. |
Item 9. Regulation FD Disclosure.
The Williams Companies, Inc. (“Williams”) wishes to disclose for Regulation FD purposes its slide presentation, filed herewith as Exhibit 99.1, to be utilized during a public conference call and webcast on the morning of August 5, 2004.
Item 12. Results of Operations and Financial Condition.
On August 5, 2004, Williams issued a press release announcing its financial results for the quarter ended June 30, 2004. The press release is accompanied by a reconciliation of certain non-GAAP financial measures disclosed in the press release with the GAAP financial measures that Williams’ management believes are most directly comparable. A copy of the press release and the reconciliation are furnished as a part of this current report on Form 8-K as Exhibit 99.2 and Exhibit 99.3, respectively, and are incorporated herein in their entirety by reference.
This Report on Form 8-K is being furnished pursuant to Item 12, Results of Operations and Financial Condition. The information furnished is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the filing under the Securities Act of 1933, as amended.
Pursuant to the requirements of the Securities Exchange Act of 1934, Williams has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| THE WILLIAMS COMPANIES, INC. |
||||
| Date: August 5, 2004 | /s/ Brian K. Shore | |||
| Name: | Brian K. Shore | |||
| Title: | Corporate Secretary | |||
2
Table of Contents
INDEX TO EXHIBITS
| EXHIBIT | ||
| NUMBER |
DESCRIPTION |
|
99.1
|
Copy of Williams’ slide presentation to be utilized during the August 5, | |
| 2004, public conference call and webcast. | ||
99.2
|
Copy of Williams’ press release dated August 5, 2004. | |
99.3
|
Copy of Williams’ Reconciliation of Income (Loss) from Continuing | |
| Operations to Recurring Earnings. |
3
Exhibit 99.1
| Williams Analyst Conference Call 2nd Quarter 2004 August 5, 2004 |
| Forward Looking Statements Our 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" with in 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: ·Our ability to divest successfully certain assets and our ability to identify and achieve cost savings measures, which may be dependent on factors outside of our control; ·Our ability to timely divest our wholesale power and energy trading business which may be dependent on factors outside of our control; ·Recent developments affecting the wholesale power and energy trading industry sector that have reduced market activity and liquidity; ·Because we no longer maintain investment grade credit ratings, our counterparties might require us to provide increasing amounts of credit support; ·Electricity, natural gas liquids and gas prices are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain existing businesses; ·We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets; ·Our risk measurement and hedging activities might not prevent losses; ·Our operating results might fluctuate on a seasonal and quarterly basis; ·Risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments; ·Legal proceedings and governmental investigations related to the energy marketing and trading business; ·Our businesses are subject to complex government regulations that are subject to changes in the regulations themselves or in their interpretation or implementation; ·Our ability to gain adequate, reliable and affordable access to transmission and distribution assets due to the FERC and regional regulation of wholesale market transactions for electricity and gas; ·The different regional power markets in which we compete or will compete in the future have changing regulatory structures; ·Our gas sales, transmission and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our ability to recover the costs of operating our pipeline facilities; ·We could be held liable for the environmental condition of any of our assets, which could include losses or costs of compliance that exceed our current expectations; ·Environmental regulation and liability relating to our business will be subject to environmental legislation in all jurisdictions in which it operates, and such legislation may be subject to change; ·Potential changes in accounting standards that might cause us to revise our financial disclosure in the future, which might change the way analysts measure our business or financial performance; ·The continued availability of natural gas reserves to our U.S. and Canadian natural gas transmission and midstream businesses; ·Our gathering, processing and transporting activities involve numerous risks that might result in accidents and other operating risks and costs; ·The threat of terrorist activities and the potential for continued military and other actions; and ·The historic drilling success rate of our exploration and production business is no guarantee of future performance. 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. |
| 2Q04 Review Steve Malcolm, Chairman, President & CEO |
| Headlines Williams delivers on restructuring Balance sheet gets stronger Adequate liquidity continues Debt reduction ramps up; new tender announced today Asset sale program ending Credit-rating agencies take notice Western power issues go away; utilities pay their bill IBM deal helps to lock in G&A cost reductions Power - no exit to date; cash flow positive year-to-date |
| Headlines Williams delivers solid 2Q performance Recurring results see big improvement Gas Pipeline steady Midstream gets boost from new deepwater expansions and strong olefins; increases guidance E&P increases production but lowers 2004 earnings guidance as Costs increase Hedges limit upside Power in-line with our expectations; mark-to-market gains offset seasonally soft quarter and legacy position impacts |
| Headlines Williams poised for post-restructuring growth, value-creation Natural gas businesses provide organic growth opportunities Investments today preserve, enhance competitive position Drilling activity, production levels both increase Deepwater Gulf infrastructure prime for incremental business Seriously considering MLP for certain Midstream assets and future acquisitions Gulfstream expansion gets under way Scale and scope of investments ramp up as restructuring finish line nears Value creation Growth Financial discipline |
| Midstream Complete deepwater projects Complete asset sales Maintain competitive position - MLP? Capture our share of new deepwater production 2004 2005 2006 2007 & beyond Gas Pipeline Exploration & Production Corporate Power CORE BUSINESSES The Road Ahead Complete announced expansion projects Northwest testing and return to service Northwest capacity replacement Rate cases Expansions Piceance major growth vehicle Powder River permits and dewatering Arkoma production doubles Early debt retirement New credit facilities Cost reductions Support growth Investment-grade ratios if exit Power Examine dividend level Spark spreads improve Risk Reduction Solid Financial Footing Disciplined Growth Powder River grows Exit or optimize If no exit, continue to reduce risk, generate cash, meet commitments Piceance growth continues MLP? |
| Financial Results & 2004 Outlook Don Chappel, CFO |
| 2nd Quarter YTD 2004 2003 2004 2003 Income (Loss) from Continuing Ops.* ($18) $114 ($19) $70 Income (Loss) from Discont. Ops. - 156 11 146 Effect of Accounting Change - - - (761) Net Income/(Loss)* ($18) $270 ($8) ($545) Net Income/(Loss) Share* ($0.03) $0.46 ($0.02) ($1.10) Recurring. Inc./(Loss) from Cont. Ops Avail to Common Shareholders** $64 ($12) $67 ($55) Rcr. Inc./(Loss) from Cont. Ops /Share** $0.12 ($0.02) $0.13 ($0.10) Financial Results * Includes gains on asset sales, impairments, prior period corrections, restatements for discontinued operations and the reclassification of results related to the transfer of certain regulated gathering assets from Midstream to Gas Pipelines (see Notes 1 & 2 of the current 10-Q). ** A schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions (except per share amounts) |
| 2004 2003 2004 2003 Income/(Loss) from Cont. Ops. ($18) $114 ($19) $70 Gains on Sale of Assets - (274) - (274) Impairments/Losses/Write-offs 24 137 24 149 Income (Expense) Related to Prior Periods 11 (93) 11 (107) Debt Retirement Expenses 97 - 97 - Other 1 18 8 31 Less: Income Tax Provision 51 (109) 54 (105) Recurring Income from Cont. Ops. $64 $11 $67 ($26) Preferred Dividend - (23) - (29) Rec. Inc./(Loss) from Cont. Ops. Avail. to Com. $64 ($12) $67 ($55) Recurring Income/(Loss) from Cont. Ops/Share $0.12 ($0.02) $0.13 ($0.10) Recurring Income from Cont. Operations Dollars in millions A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. 2nd Quarter YTD |
| 2004 2003 2004 2003 Segment Profit $305 $636 $571 $880 Net Interest Expense (222) (395) (461) (736) Debt Retirement Expense (97) - (97) - Other Income (Expense) - Net (21) (1) (38) 40 Income/(Loss) from Cont. Ops. Before Tax* (35) 240 (25) 184 Provision (Benefit) for Income Tax (17) 126 (6) 114 Income/(Loss) from Continuing Ops.* ($18) $114 ($19) $70 Income from Discontinued Ops. - 156 11 146 Effect of Accounting Change - - - (761) Net Income/(Loss)* ($18) $270 ($8) ($545) Net Income Components * Income/(Loss) from Continuing Operations includes certain gains on asset sales and impairments in 2003 and has been restated primarily for discontinued operations (See Note 2 of the current 10Q). Dollars in millions (except per share amounts) 2nd Quarter YTD |
| Second Quarter Segment Profit Reported Recurring 2Q04 2Q03 2Q04 2Q03 Gas Pipeline $133 $116 $142 $142 Exploration & Production(1) 43 179 55 87 Midstream Gas & Liquids 99 45 99 54 $275 $340 $296 $283 Power(2) 45 348 45 93 Other (15) (52) (5) (2) Segment Profit(3) $305 $636 $336 $374 Dollars in millions (1) E&P 2Q04 reported results include $11 million loss provision related to prior periods. (2) Power 2Q03 reported results include $93 million income for prior period item correction (3) Reported segment profit Includes certain gains on asset sales and impairments in 2003 and has been restated primarily for discontinued operations (See Note 2 of the current 10Q). A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. |
| YTD Segment Profit Reported Recurring 2004 2003 2004 2003 Gas Pipeline $280 $266 $289 $292 Exploration & Production(1) 95 293 106 201 Midstream Gas & Liquids 207 157 207 166 $582 $716 $602 $659 Power(2) 12 212 12 (45) Other (23) (48) (5) 3 Segment Profit(3) $571 $880 $609 $617 Dollars in millions (1) E&P 2Q04 reported results include $11 million loss provision related to prior periods. (2) Power 2003 reported results include $107 million income for prior period item correction (3) Reported segment profit Includes certain gains on asset sales and impairments in 2003 and has been restated primarily for discontinued operations (See Note 2 of the current 10Q). A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. |
| Recurring Segment Profit 2Q2003 $374 Power (49) - Lower gross margin incl. MTM -$63 million - Reduced SG&A expenses +$12 Midstream 45 - New deepwater assets +$13 million - Higher NGL margins +$13 million - Improved olefins results +17 million Gas Pipeline 0 - New projects added +$13 million - Increased expenses and property taxes -$4 million - Lower short term firm revenues and credits -$10 million Exploration & Production (32) - Lower net realized price & 2003 MTM gain -$18 million - Loss of excess firm transport & asset sales -$14 million - Higher operating costs -$7 million - Higher volumes in 2Q04 +$7 million Other (3) Recurring Segment Profit 2Q2004 $336 Major Changes in Recurring Segment Profit Dollars in millions |
| Beginning Cash @ 12/31/03* $2,318 Cash Flow from Continuing Operations 604 Cash Flow from Discontinued Operations 12 Asset Sales 394 Restricted Investments (LC Collateral) 381 Debt Retirements (2,218) Capital Expenditures/Investments (331) Debt Premiums/Issuance Costs (100) Other-Net (30) Ending Cash @ 6/30/04* $1,030 Change in Cash ($1,288) Restricted Cash (not included above) $176 YTD Cash Information Dollars in millions * Includes cash for discontinued operations of $2.5 million at 12/31/03 and $0 at 6/30/04 |
| Debt Balance Debt Balance @ 12/31/03 * $11,978 7.7% Scheduled Debt Retirements & Amortization (778) Tendered Debt Retirements (1,171) Open Market Purchases (269) Debt Balance @ 6/30/04 $9,760 7.3% Net Decrease in Debt ($2,218) Fixed Rate Debt $9,165 7.6% Variable Rate Debt $595 3.3% Avg. Cost * Debt is long-term debt due within 1 year plus long-term debt plus notes payable; includes FELINE PACS Dollars in millions |
| Consolidated 2004 Segment Profit Guidance Dollars in millions 2004 Forecast * Midstream excludes Canadian assets sold and reclassified as discontinued operations ** Restated to remove Canadian assets sold and reclassified as discontinued operations *** Power guidance assumes zero 2nd half 2004 mark-to-market gains / (losses) Gas Pipeline $540 - 570 Exploration & Production 235 - 260 Midstream* 325 - 375 Other/Rounding 0 - 45 $1,100 - 1,250 Power*** 0 - 150 Total $1,100 - 1,400 275 - 300 275 - 360 ** 0 - (10) $1,075 - 1,375 ** $1,075 - 1,225 ** $525 - 575 |
| Segment profit $1,100 - $1,400 $1,075 - $1,375 Net Interest Expense (820) - (860) Early Debt Retirement Costs (250) - (200) (225) - (175) Other (Primarily General Corporate Costs) (80) - (125) Pretax Income (Loss) ($50) - $215 Provision (Benefit) for Income Tax 5 - (125) 5 - (105) Income / (Loss) from Continuing Ops (45) - 90 Income from Discontinued Ops * 160 - 185 Net Income (Loss) - Reported $115 - $275 Diluted EPS - Reported $0.22 - $0.52 Net Income - Recurring ** $107 - $212 Diluted EPS - Recurring ** $0.20 - $0.40 Dollars in millions, except per-share amounts Consolidated 2004 Forecast Guidance * Includes gain on sale of Canadian straddle plants ** Excludes early debt retirement costs, gains and losses on assets sales and impairments *** Previous guidance restated for Canadian asset sale and reclassification to discontinued operations (840) - (880) ($70) - $195 ($65) - $90 0 - 20 ($65) - $110 ($0.12) - $0.21 $75 - $195 $0.14 - $0.37 Previous*** same Current |
| 2004 Forecast EBITDA Reconciliation Dollars in millions Net Income $115 - $275 Income from Disc. Operations (160) - (185) Net Interest 820 - 860 DD&A 650 - 700 Provision (Benefit) for Income Taxes (5) - 125 Other/Rounding (70) - 25 EBITDA - Reported $1,350 - $1,800 Early Debt Retirement Fees 250 - 200 EBITDA - Recurring $1,600 - $2,000 |
| MLP Direction Positives Acquisition currency Retain control of assets Additional access to capital markets Added visibility for Midstream business unit valuation Considerations Complicated tax / governance / reporting structure Hurdles due to current financial agreements Ratings agencies neutral to negative view Current direction Seriously considering establishment of MLP Initial assets may include some of remaining assets for sale, e.g. Conway Flexibility for expansion through acquisition or drop-down transaction Expected IPO timing likely 1Q or 2Q 2005 |
| MLP Initial Scale Considerations Starting small Maximum flexibility to make acquisitions and drop-down acquisitions Growth more sustainable starting from a smaller base As GP, Williams incentive distributions increase geometrically as distributable cash flow grows Asset considerations Not all Midstream assets are appropriate Targeting more mature assets Rating agency considerations Small size would mitigate concerns of ratings agencies Covenants Certain covenants would initially limit assets which could be an MLP Some midstream assets are pledged as collateral |
| Business Unit Results |
| Exploration & Production Ralph Hill, Senior Vice President |
| 2nd Quarter YTD 2004 2003 2004 2003 Exploration & Production Segment Profit Dollars in millions Segment Profit $43 $179 $95 $293 Non recurring: Ownership issue 11 - 11 - Gain on sale of assets - (92) - (92) Recurring Segment Profit $55* $87 $106 $201 2Q04 to 2Q03 decrease includes ($18) million primarily due to market to market gain in 2Q03 and lower net realized price ($8) million due to excess transport ($7) million due to higher operating expenses ($6) million due to assets sold in 2Q03 $7 million increase due to higher volumes in 2Q04 $55 million negative hedge impact in second quarter 2004, $101 million year to date Base business sequential quarter improved Sequential volumes increased 11%, recurring profit increased 6% * Does not add due to rounding |
| 1Q '03 2Q '03 3Q '03 4Q '03 1Q '04 2Q '04 Retained Properties 130.6 111.7 101.2 90.3 94 101.1 Sold Properties 9.3 9.3 Exploration & Production Recurring Segment Profit + DD&A |
| Exploration & Production Second Quarter Accomplishments Significant Production Growth Drilling activities increases Shorter Piceance drilling cycle Additional rigs added in San Juan, Arkoma and Powder River Powder River permitting progress Bolt on acquisitions accomplished: Arkoma San Juan Powder River Piceance Trail Ridge area drilling commences Significant Big George volume growth Expanded Piceance firm takeaway capacity Avg 2002 Avg 2003 Jun 04 Retained Production 460 465 511 International 42 44 44 |
| Piceance Powder River San Juan Arkoma/Other International Jan. '04 166 121 142 28 41 Jun '04 226 119 143 28 43 Dec. '04 268 119 145 30 44 Exploration & Production Current and Projected Volumes Additional volumes due to drilling efficiencies Previous Estimate |
| Williams Big George Gross Production Increasing 61.6 MMcfd, 603 wells 100 Miles 60 Miles Wyodak Fairway 743.1 MMcfd* CAMPBELL COUNTY Gillette JOHNSON SHERIDAN Big George Fairway 147.5 MMcfd* * WOGCC Data April 2004 Williams Operated Pilots Scale 0 6 miles Partner Operated Pilots Other Industry Pilots Exploration & Production Powder River Basin, WY - Big George and Wyodak Coal Fairways Carr Draw South Prong Schoonover Road S.G. Palo Pleasantville Areas Kingsbury Area All Night Creek Area Bullwhacker Creek |
| Exploration & Production Piceance Basin Acreage Denver |
| 2004 Previous Guidance $275 - 300 Revisions: 1) Hedge price impact ( 7) 2) Excess transport ( 15) 3) Higher operating expenses ( 11) 4) Gathering fees/other ( 10) 5) Increased volumes 15 ($28) Non-Recurring ($11) Revised Guidance $235 - 260 Dollars in millions Exploration & Production 2004 Segment Profit Guidance Revision |
| 2004 Previous Guidance $325 - 375 Revisions: 1) Increase in overall drilling program costs 13 2) Additional operated wells drilled 27 3) Additional partner operated wells 11 4) Accelerated plant & compression upgrades 21 Revised Guidance $400 - 450 Dollars in millions Exploration & Production 2004 Capital Guidance Revision Additional growth capital $59 million |
| Exploration & Production 2004-2006 Guidance Note: If guidance has changed, previous guidance from 5/6/04 is shown in italics directly below. Economic impact of hedges may be different from the volume hedged due primarily to fuel and shrink and direct taxes 2004 2005 2006 Segment profit $235 - 260 $375 - 475 $425 - 525 Annual DD&A $160 - 180 $195 - 225 $230 - 260 Capital spending $400 - 450 $400 - 450 $450 - 500 Production (MMcfe/d) 525 - 550 600 - 700 700 - 800 Hedged Volume (MMcfe/d) 418 286 298 Hedged Price (NYMEX) $4.04 $4.44 $4.39 Dollars in millions $325 - 375 $275 - 300 |
| Delivering on our volume growth Stepping up development drilling activity Decreasing 2004 segment profit guidance due to "boom" costs and hedged prices Plan based on organic growth from existing positions Investments are short time cycle, fast cash returns High-quality reserve base History of high success, low finding costs Diverse producing basins, long-term drilling inventory Significant probables and possibles inventory Experienced and talented work force Exploration & Production Key Points |
| Midstream Alan Armstrong, Senior Vice President |
| Segment Profit $99 $45 $207 $157 Aux Sable Impairment - 9 - 9 Recurring Segment Profit $99 $54 $207 $166 Dollars in millions Midstream Segment Profit 2Q04 vs. 2Q03 Impact New Deepwater Assets $ +13 Higher NGL Margins +13 Improved Olefins results +17 2nd Quarter YTD 2004 2003 2004 2003 |
| Midstream Second Quarter Accomplishments First production on Devils Tower Canadian straddles sale Favorable Gulf Liquids arbitration award Secured Front Runner dedication Federal court remands FERC ruling * Excludes gains/losses/impairments 3Q '02 4Q '02 1Q '03 1Q '04 2Q '03 2Q '04 3Q '03 4Q '03 1Q 2Q 3Q 4Q 143 118.8 151.1 150.7 92.9 143.5 109 105.7 Recurring Segment Profit 102.2 78 112.3 108.3 53.6 98.5 69.4 65.6 Depreciation 40.8 40.8 38.8 42.4 39.3 45 39.6 40.1 2003 151 93 109 106 2004 151 144 Recurring Segment Profit + Depreciation* |
| Midstream targeted $500 - 600 MM Canadian straddles yield $536 million cash + $30 million of L.C. capacity South Texas regulated assets - $28 million Yields nearly $600 million Gulf Liquids pending Ethylene distribution system and storage system pending NGL storage assets held back for MLP Midstream Asset Sale Update |
| Midstream MLP Discussion Points Provides acquisition vehicle for additional scale in Midstream Maintains our competitive advantage in core basins Allows continuing presence in NGL services sector Allows Williams to retain control of assets No negative impact to current earnings guidance |
| Midstream 2004-2006 Guidance Dollars in millions 2004 2005 2006 Segment Profit $325-375 $300-400 $350-450 Annual DD&A $170-180 $175-185 $175-185 Capital Spending $90-110 $60-80 $50-70 $275-360 Note: - - Both current & previous guidance excludes results & gains associated with Canada straddle plants that are now included in Discontinued Operations. - - If guidance has changed, previous guidance from 5/6/04 is shown in italics directly below Discontinued Ops. Adjustment - Canadian Straddle Plants Segment Profit $25 - - Annual DD&A $10 - - |
| Midstream Key Points Continued strong demand for services in core areas 2Q 2004 performance yields second consecutive increase in guidance Asset sales goals accomplished Deepwater projects adding significant operating profit Reliable operational performance attracting growth around existing assets MLP would benefit Midstream's scale focused strategy |
| Gas Pipeline Doug Whisenant, Senior Vice President |
| Gas Pipeline Segment Profit 2nd Quarter YTD 2004 2003 2004 2003 Segment profit $133 $116 $280 $266 Includes: Write-off software project - 26 - 26 Write-off of previously capitalized cost for idled segment 9 - 9 - Recurring Segment Profit $142 $142 $289 $292 2Q04 vs. 2Q03 Incremental projects, $14 million Offset by: Lower transportation revenue, $5 million Higher operating taxes, $4 million Gas cost credit in 2003, $2 million Lower environmental credit sales, $3 million Dollars in millions |
| Gas Pipeline Second Quarter Accomplishments Began construction of Gulfstream Phase II Assumed operations of Transco production area facilities Began construction of Everett Delta Lateral Partial (131 MDtd) return to service of 26-inch Successful Leidy to Long Island open season 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2003 209.1 202.5 203.2 213.8 2004 207.8 203 |
| 2004 2005 2006 Segment profit $540 - 570* $525 - 575 $525 - 575 Annual DD&A $270 - 280 $280 - 290 $290 - 300 Capital spending $280 - 320 $350 - 400 $450 - 520 Dollars in millions Gas Pipeline 2004-2006 Guidance $335 - 380 $430 - 490 $295 - 340 $525-575 $275-285 * Includes $9 million non-recurring charge in 2Q '04 |
| Gas Pipeline 2004-2006 Capital Spending Detail $450 - 520 $350 - 400 $280 - 320 Total 20 - 30 20 - 30 35 - 45 260 - 300 45 - 55 35 - 45 70 - 75 $140 - 150 $195 - 215 $140 - 155 Normal Maintenance 2006 2005 2004 Dollars in millions $430 - 490 40 - 50 $335 - 380 Clean Air Act NWP 26" Restore/Replace Expansion 90 - 100 30 - 40 60 - 75 15 - 25 25 - 35 240 - 275 $150 - 160 $155 - 165 75 - 85 $295 - 340 105 - 115 25 - 30 30 - 45 Note: Amounts include AFUDC If guidance has changed, previous guidance from 5/06/04 is shown in italics directly below |
| Gas Pipeline Northwest 26-inch Restore-to-Service Completed restoration phase Restored 111 miles of 26-inch mainline Represents 131Mdth/d of idled 360 Mdth/d capacity In-service June 22 |
| Gas Pipeline Northwest 26-inch Capacity Replacement Replace 360 MDth/d of capacity Approximately 80 miles of 36" loop; 12,000 hp of compression November 2006 in-service Incorporates 13 MDth/d of capacity relinquished in Reverse Open Season Environmental and permitting work underway Projected cost $310-360 million Rate Case planned effective January 2007 to recover costs |
| Gas Pipeline Transco Leidy to Long Island Expansion 100 MDtd fully subscribed expansion from the Leidy Hub to Long Island, NY Capital investment ? $150 million Projected in-service date, Nov 2007 Leidy Hub PA NY MD NJ Long Island |
| Gas Pipeline Gulfstream Update Phase II construction underway 109-mile, 30" extension to serve Florida Power & Light's Martin plant 350 Mdth/d, long-term commitment by FPL December 2004 in-service Capacity under long-term contract Today: 305 Mdth/d (28% of capacity) Mid-2005: 705 Mdth/d (64% of capacity) Phase II project economics Total cost $250 million; project financed Long-term project financing in 2005 |
| 26-inch Return-to-Service complete (June 22) 26-inch Capacity Replacement, 11/06 targeted ISD Expansion projects Central New Jersey Leidy to Long Island Gulfstream Phase II Rate cases effective in 2007 NWP TGPL Gas Pipeline Key Points |
| Power Bill Hobbs, Senior Vice President |
| 2nd Quarter YTD 2004 2003 2004 2003 Power Segment Profit Dollars in millions Gross Margin $72 $228 $71 $138 SG&A (20) (44) (36) (81) Op. Exp. & Other Inc / (Exp) (7) 164 (23) 155 Reported Segment Profit $45 $348 $12 $212 Includes: Regulatory Settlement - 20 - 20 Prior period correction* - (93) - (107) Gains on sale of assets/contracts - (182) - (182) Reduction in force costs - - - 12 Recurring Segment Profit $45 $93 $12 ($45) * 2003 amounts reflect corrections as disclosed in 2003 10-K |
| Portfolio cash flows consistent with forecast in Power Tutorial Portfolio volumes up more than 70% Portfolio cash flow up more than $60 million Held Power tutorial on June 17 Western power issues resolved February 25 settlement with three California utilities FERC approved settlement on July 2 Williams has received approximately $104 million related to the settlement Power Second Quarter / Recent Accomplishments |
| Power Undiscounted Cash Flows Variance Analysis 4Q03 4Q02 2003 2002 Dollars in millions Dollars in millions * Forecast included in Power Tutorial held 6/17/04 |
| Power Power Segment CFFO * "Other BU Working Capital" relates to other business units but is managed by the Power Business Unit. Actual Forecast 3Q & 4Q 1Q2004 2Q2004 YTD 2004 2004 2004 Power Portfolio 6 19 25 35-65 60-90 Storage & Legacy 75 (33) 42 (82)-(52) (40)-(10) 81 (14) 67 (47)-13 20-80 Other Working Capital: Power Stand-Alone 82 (75) 7 Power Stand-Alone CFFO 163 (89) 74 (3)-137 130-270 Other BU Working Capital* (76) 202 126 Power Segment CFFO 87 113 200 (50)-150 150-350 Dollars in millions |
| Segment Profit to Cash Flow Total Segment 2Q04 Dollars in millions |
| 2004 2005 2006 Segment Profit* $0 - 150 $50 - 150 $50 - 200 Capital Expenditures $0 $0 $0 Cash Flows from Operations $150 - 350 $50 - 150 $50 - 200 Dollars in millions Power 2004-2006 Guidance * Assumes 2nd half 2004 MTM gains or losses are zero, however actual results will vary due to MTM results |
| Power Key Points Expect to generate positive cash flow from operations Significantly hedged cash flow through 2010 Significant natural gas business Merchant upside in West and Northeast Working to reduce risk through forward power sales Operational and environmental obligations very limited Resolving legacy issues Strong commercial and financial capabilities Continue efforts to increase transparency |
| Financial Overview & 3-Year Outlook Don Chappel |
| Consolidated 2004 - 2006 Outlook 2006 2005 2004 Dollars in millions Segment Profit DD&A Cash Flow from Ops. Capital Expenditures Effective Tax Rate** Cash Tax Rate $1,100 - 1,400 $650 - 700 $1,000 - 1,300 $775 - 875 39% 3-5% $1,300 - 1,600 $650 - 750 $1,300 - 1,600 $800 - 1,000 39% 3-5% $1,400 - 1,700 $700 - 800 $1,400 -1,700 $900 - 1,100 39% 4-8% $725 - 825 $1,075 - 1,375 * * Restated to remove Canadian assets sold and reclassified as discontinued operations ** An additional $25 million income tax expense is forecast each year Note: If guidance has changed, previous guidance from 5/6/04 is shown in italics directly below |
| 2004 2005 2006 Exploration & Production $400 - 450 $400 - 450 $450 - 500 Midstream 90 - 110 60 - 80 50 - 70 Gas Pipeline 280 - 320 350 - 400 450 - 510 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $775 - 875 $800 - 1,000 $900 - 1,100 Dollars in millions 2004-2006 Capital Exp. By Business Notes: - - Sum of ranges for each business line does not necessarily match total range - - If guidance has changed, previous guidance from 5/6/04 is shown in italics directly below $325 - 375 $725 - 825 295 - 340 335 - 380 430 - 490 |
| $1.5 billion cash at August 1, 2004 Today commencing cash tender offer and consent solicitation for all $800 million 8 5/8% notes due 2010 Will use available cash and liquidity to fund purchase of notes accepted under the offer Increasing revolving credit facility by $275 million to a total capacity of $1.275 billion and combined credit facilities total $1.8 billion ($1.1 billion available) Total liquidity is not affected by tender offer Achieves year-end goal of reducing debt to ~$9 billion Debt Reduction Action |
| Cash @ 6/30/04 $1.0 Proceeds from Canada Sale 0.5 Cash Available $1.5 Current Unused Revolver 0.8 Increase in Revolver Capacity 0.3 Total Liquidity $2.6 Liquidity Cushion Required (1.3) Liquidity Available for Tender Offer $1.3 Liquidity Available for Tender Offer Dollars in billions * * Targeted minimum liquidity is $1.0 billion |
| Scheduled Debt Maturities 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013-2020 2021-2022 2023-2026 2027-2030 2031 2032 2033 Misc. Notes 54 247 119 323 640 53 214 1018 998 757 751 292 100 1170 850 300 PACS 1100 Tender Offer 800 Dollars in millions 800 |
| Maintain a cash/liquidity cushion of $1.0 billion plus Continue to de-lever; striving for investment-grade ratios Uses of excess cash Pay scheduled debt retirements Early debt reduction Disciplined EVA(r) -based investment Consider dividend and/or share repurchase policy upon achieving investment grade ratios Combination of growth in operating cash flows and reduction in interest costs drives value creation Drive/enable sustainable growth in EVA(r)/ shareholder value Financial Strategy/Key Points |
| Summary Steve Malcolm |
| Midstream Complete deepwater projects Complete asset sales Maintain competitive position - MLP? Capture our share of new deepwater production 2004 2005 2006 2007 & beyond Gas Pipeline Exploration & Production Corporate Power CORE BUSINESSES The Road Ahead Complete announced expansion projects Northwest testing and return to service Northwest capacity replacement Rate cases Expansions Piceance major growth vehicle Powder River permits and dewatering Arkoma production doubles Early debt retirement New credit facilities Cost reductions Support growth Investment-grade ratios if exit Power Examine dividend level Spark spreads improve Risk Reduction Solid Financial Footing Disciplined Growth Powder River grows Exit or optimize If no exit, continue to reduce risk, generate cash, meet commitments Piceance growth continues MLP? |
| Summary 2nd quarter results solid Debt reductions continue with new tender announced today Asset sales program essentially completed Adequate liquidity continues Growth opportunities identified Significant work outsourced to IBM Seriously considering MLP Continuing efforts to exit Power |
| Non-GAAP Reconciliations |
| Non-GAAP Reconciliation Schedule |
| Non-GAAP Reconciliation Schedule |
| 2Q 2004 EBITDA Reconciliation 168 DD&A (17) Provision for Income Taxes 222 Net Interest Expense Dollars in millions ($18) Net Income (Loss)* $355 EBITDA* - - Income from Disc. Operations * Includes gains and impairments on asset sales and prior period adjustments |
| 2004 YTD EBITDA Reconciliation 329 DD&A (6) Provision for Income Taxes 461 Net Interest Expense Dollars in millions ($8) Net Income (Loss)* $765 EBITDA* (11) Income from Disc. Operations * Includes gains and impairments on asset sales and prior period adjustments |
| * Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions 2Q 2004 Segment Contributions Gas Pipeline E&P Midstream Power Corp/Other Total Segment Profit (Loss) $133 $43 $99 $45 ($15) $305 DD&A 68 46 45 5 4 168 Segment Profit before DDA $201 $89 $144 $50 ($11) $473 General Corporate Expense (28) Investing Income* 13 Other Income (107) TOTAL $355 |
| Gas Pipeline E&P Power 235 - 260 160 - 180 395 - 440 0 - 150 20 - 25 20 - 175 540 - 570 270 - 280 810 - 850 Segment Profit (Loss) DD&A Segment Profit before DDA General Corporate Expense Investing Income Other/Rounding TOTAL RECURRING Midstream 325 - 375 180 - 190 505 - 565 Total 1,100 - 1,400 650 - 700 1,750 - 2,100 (130) - (110) 0 - 50 (20) - (40) 1,600 - 2,000 Corp/Other 0 - 45 20 - 25 20 - 70 Consolidated 2004 Forecast Segment Contribution |
| Appendix |
| Exploration & Production 2004 Net Realized Price Calculation Example for any given quarter: * Remaining 2004 hedge position |
| 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 U.S. 149 135 151 150 147 119 138 132 Canada 144 145 162 155 153 123 132 150 Williams NGL Equity Mix Midstream Domestic NGL Production & Weighted Avg Margins Note: Computed using NGL prices FOB plant tailgate less shrinkage costs. Weighted average is computed using Williams' equity percentages by region. Williams Wtd Avg Net Liquid Margin 1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 1Q '04 2Q '04 3Q '04 4Q '04 2005 2Q '05 3Q '05 4Q '05 2006 2Q '06 3Q '06 4Q '06 Wtd Avg Margin 4.64 10.69 14.79 10.32 12.74 2.98 3.95 7.58 9.89 8.4 5-Yr High 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 13.65 5-Yr Low 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5.79 5-Yr Avg 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 8.96 2002 Avg 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 2003 Avg 6.81 6.81 6.81 6.81 5-Yr High 5-Yr Avg 5-Yr Low 2003 Avg 2002 Avg |
| Enterprise Risk Management Margins & Ad. Assur. $187 $18 $197 - $402 Prepayments - 7 31 - 38 Subtotal $187 $25 $228 $ - $440 Letters of Credit 302 132 196 43 673 Total as of 6/30/04 $489 $157 $424 $43 $1,113 Total as of 3/31/04 $364 $74 $441 $81 $960 Change $125 $83 ($17) ($38) $153 Corp./ E&P Midstream Power Other Total Dollars in millions |
| Enterprise Risk Management Margin volatility (99% confidence interval) - - Incremental liquidity requirement 6/30/04 12/31/03 30 days ($214) ($185) 180 days ($274) ($309) 360 days ($300) ($390) Assumption: The margin numbers above consist of only the forward marginable position values, starting from May 2004. Dollars in millions |
| Enterprise Risk Management Sensitivities Analysis 1 Assumes a correlated movement in prices across all commodities, including spreads. 2 Assumes a non-correlated change in West power prices only, no change in power volatility, full extrinsic value not included. Heat rate and position change associated with Spark Spread increase is consistent across all months. Cash flow ranges are not linear. 3 Assumes a non-correlated change in NGL processing spread (i.e. change in NGL price only). Midstream figures for 2004 does not include price sensitivity on Canadian assets based on the assumption the Canadian assets would be sold in 2004. Price Increase 2004 2005 2006 1 Power West Spark Spread Power Price (Per MWh) $5.00 $0-5 $5-10 $5-15 2 Midstream Processing Margin NGL Price (Per Gallon) $0.01 $4-10 $10-15 $10-15 3 Estimated dollars in millions |
| Power Total Undiscounted Cash Flows Note: Actual cash flows realized upon liquidation or sale of the portfolio may differ materially from those shown. Also, please note that proprietary positions, storage, transportation, transmission, crude and refined products, interest rates, and option premiums are not included. Combined Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006 F Tolling Demand Payment Obligations ($88) ($99) ($396) ($397) ($401) Resale of Tolling $41 $35 $137 $111 $95 Full Requirements ($1) $11 $14 $16 $16 Long-term Physical Forward Power Sales $27 $21 $70 $73 $58 OTC Hedges $36 $37 $169 $69 $125 Tolling Cash Flows Associated With Hedges $7 $34 $155 $261 $282 Subtotal $22 $39 $150 $133 $174 Merchant Cash Flows $0 $0 $7 $18 $71 Est. Combined Power Portfolio Cash Flows $22 $39 $156 $150 $245 Forecasted Direct SG&A ($8) ($14) ($50) ($50) ($50) Forecasted Indirect SG&A ($8) ($6) ($25) ($25) ($25) Subtotal $6 $19 $81 $75 $170 Legacy Portfolio and Other Working Capital $81 $94 $233 $51 $36 Estimated Cash Flows $87 $113 $315 $127 $206 |
| Power West - Total Undiscounted Cash Flows Dollars in millions West Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006 F Tolling Demand Payment Obligations ($39) ($38) ($154) ($154) ($156) Resale of Tolling $41 $35 $86 $0 $0 Long-term Physical Forward Power Sales $29 $24 $59 $0 $0 OTC Hedges $15 $24 $192 $235 $236 Tolling Cash Flows Associated With Hedges $12 $26 $104 $160 $176 Subtotal $58 $70 $287 $241 $256 Merchant Cash Flows $0 $0 $0 $0 $28 Estimated Cash Flows $58 $70 $287 $241 $285 |
| Power Central - Total Undiscounted Cash Flows Dollars in millions Mid-Continent Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006F Tolling Demand Payment Obligations ($13) ($21) ($87) ($88) ($89) Long-term Physical Forward Power Sales ($2) ($3) ($16) $2 $0 OTC Hedges $1 $9 $21 ($11) ($8) Tolling Cash Flows Associated With Hedges ($3) $1 $11 $33 $20 Subtotal ($17) ($15) ($71) ($64) ($77) Merchant Cash Flows $0 $0 $0 $0 $25 Estimated Cash Flows ($17) ($15) ($71) ($64) ($52) |
| Power East - Total Undiscounted Cash Flows East Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006 F Tolling Demand Payment Obligations ($36) ($39) ($155) ($154) ($157) Full Requirements ($1) $11 $14 $16 $16 OTC Hedges $19 $4 $34 $26 $49 Tolling Cash Flows Associated With Hedges ($1) $7 $41 $67 $87 Subtotal ($18) ($17) ($67) ($44) ($6) Merchant Cash Flows $0 $0 $7 $18 $18 Estimated Cash Flows ($18) ($17) ($60) ($25) $12 Dollars in millions |
| Consolidated Drivers Dollars in millions |
EXHIBIT 99.2
NYSE: WMB
Date: Aug. 5, 2004
Williams Reports Second-Quarter 2004 Results
• Company Reduced Debt $1.5 Billion During Quarter; Initiates New Tender Offer
Today
• Consolidated Operating Results Solid
TULSA, Okla. – Williams (NYSE:WMB) today announced a second-quarter 2004 unaudited net loss of $18.2 million, or a loss of 3 cents per share on a diluted basis, compared with net income of $269.7 million, or 46 cents per share, for second-quarter 2003.
For second-quarter 2004, the company reported a loss from continuing
operations of $18 million, or a loss of 3 cents per share on a diluted basis,
compared with income of $113.7 million, or 17 cents per share, on a restated
basis for the same period in 2003. Results for the 2004 quarter were reduced by
approximately $97 million in pre-tax charges for premiums, as well as related
fees and expenses, associated with the early retirement of debt.
Results for 2003 have been restated to reflect the operating results from
the Canadian straddle plants as discontinued operations following the second
quarter authorization to sell these assets, which were sold on July 28. In
addition, the operating results associated with certain regulated gas gathering
assets were transferred from Midstream to Gas Pipeline following a transfer of
operating control between these segments due in part to a recent order by the
Federal Energy Regulatory Commission.
Year-to-date, the company reported a net loss of $8.3 million, or a loss
of 2 cents per share on a diluted basis, compared with a loss of $544.8
million, or a loss of $1.10 per share, for the first half of 2003. Results for
the first half of 2003 were reduced by an after-tax charge of $761.3 million,
or $1.45 per share, to primarily reflect the cumulative effect of adopting the
newly mandated accounting standard for contracts involved in energy trading and
risk management activities.
For the first six months of the year, Williams reported a loss from
continuing operations of $19.5 million, or a loss of 4 cents per share on a
diluted basis, compared with income of $70.6 million, or 7 cents per share, on
a restated basis for the same period in 2003.
Factors influencing the six-month decrease in income from continuing
operations are primarily attributable to the absence of gains on two asset
sales in the prior-year period, the impact of lower net realized average prices
for natural gas production, the costs of early debt retirement and lower Power
segment profit, reflecting lower overall unrealized mark-to-market gains on
derivative contracts.
Offsetting those factors were the favorable impact of continued strong performance in the company’s Midstream Gas & Liquids unit, significantly reduced interest expense and the absence of impairment charges reported in investing income in 2003.
The company reported a loss of $200,000 in discontinued operations, or 0
cents per share, in second-quarter 2004, compared with income of $156 million,
or diluted earnings per share of 29 cents, on a restated basis for the same
period last year. The 2003 results include significant gains from the sales of
assets. For the first six months of the year, income from discontinued
operations was $11.2 million, or 2 cents per share on a diluted basis, compared
with $145.9 million, or 28 cents per share, on a restated basis for the first
half of 2003.
Net cash provided by operating activities for the first half of the year
was $615.1 million, including $11.5 million from discontinued operations.
“Williams’ turnaround is on track,” said Steve Malcolm, chairman,
president and chief executive officer. “We are driving our progress by
delivering on our restructuring program, taking strategic advantage of our cash
position and realizing the strength of our core businesses.
“For example, we have consistently executed on our business plan over the
past two years. We’ve done exactly what we said we would — complete our major
asset sales, strengthen our liquidity, reduce debt, live within our means and
simplify our business mix.
“Second, even after paying down another $1.5 billion of debt during the
second quarter, we have launched a new tender offer today for another $800
million in outstanding debt. Our stated goal is to reduce our total long-term
debt to less than $8 billion by the end of 2005.
“Finally, as we’ve re-shaped, re-sized and restructured the company, we’ve
retained some crown jewels in our core natural gas businesses that are showing
the results of disciplined investments. Our Midstream business had another
near-record quarter, in part due to almost $1 billion in new assets that we’ve
added in the Gulf of Mexico since 1997.”
Recurring Results
Recurring income from continuing operations – which excludes items of income or loss that the company characterizes as unrepresentative of its ongoing operations – was $64.4 million, or 12 cents per share, for the second quarter of 2004. In last year’s second quarter, there was a recurring loss from continuing operations of $11.5 million, or 2 cents per share, on a restated basis.
For the first half of this year, recurring income from continuing
operations was $66.9 million, or 13 cents per share, compared with a loss of
$55.2 million, or a loss of 10 cents per share, for the first six months of
2003 on a restated basis.
A reconciliation of the company’s income from continuing operations – a
generally accepted accounting principles measure – to its recurring results
accompanies this news release.
Update on Debt and Cash
Williams reduced its debt by approximately $1.5 billion during the second quarter, including $1.17 billion through cash tender offers and $255 million through open market repurchases ahead of schedule. The company ended the second quarter with total long-term debt of approximately $9.8 billion.
Year-to-date, Williams has reduced its debt by approximately $2.2 billion
through scheduled maturities and early debt retirements. Earlier today,
Williams commenced a cash tender offer for an additional $800 million of
outstanding notes.
At July 30, Williams had available cash and cash equivalents of
approximately $1.5 billion. The amount includes the benefit of approximately
$536 million in proceeds from the July 28 sale of the Canadian straddle plants.
In addition to cash, Williams’ overall liquidity is supported by
approximately $800 million in available credit capacity under the company’s
revolving credit facilities that were obtained during the first quarter. The
facilities are used primarily for issuing letters of credit and for liquidity.
Williams also has a commitment from its agent bank to expand the company’s
credit facility by an additional $275 million.
Business Segment Performance
Williams’ natural gas businesses – Exploration & Production, Midstream Gas & Liquids and Gas Pipeline – reported combined segment profit of $274.7 million in the second quarter of 2004.
A year ago in the second quarter, the natural gas businesses reported
combined segment profit of $339.3 million on a restated basis, which included
the benefit of a $91.5 million gain on the sale of certain Exploration &
Production properties.
For the first six months of 2004, the natural gas businesses reported
combined segment profit of $581.9 million vs. $715.6 million for the same
period last year on a restated basis.
Exploration & Production
Exploration & Production, which includes natural gas production and development in the U.S. Rocky Mountains, San Juan Basin and Midcontinent, reported second-quarter 2004 segment profit of $43.3 million.
In the second quarter a year ago, the business reported segment profit of
$178.7 million, which included the benefit of a $91.5 million gain on the sale
of certain properties. Second-quarter 2004 results decreased primarily due to
lower income on derivative instruments that did not qualify for hedge
accounting, reduced income from the utilization of excess transportation
capacity, an $11.3 million loss provision associated with an ownership issue
and the absence of the asset sale gain.
For the first six months of 2004, Exploration & Production reported
segment profit of $94.8 million vs. $292.5 million for the same period last
year. The first half of 2003 included the benefit of the asset sale gain,
volumes associated with properties that have since been divested and higher net
average realized prices.
In the second quarter of 2004, average daily production was approximately 555 million cubic feet of gas equivalent, compared with 502 MMcfe in the first quarter of 2004, or an 11 percent increase. Production has now surpassed levels that were reached prior to last year’s asset sales.
In the Piceance Basin where drilling activity has increased throughout the
year, average daily production continues to rise. In the second quarter,
average daily production was 210 million cubic feet of gas equivalent. This was
an increase of 19 percent vs. the average daily production in the first quarter
of 177 million cubic feet of gas equivalent. Year-to-date, Piceance production
has increased 33 percent since the fourth quarter of 2003, when average daily
production was 158 million cubic feet of gas equivalent.
For the full year, Williams now expects $235 million to $260 million in
segment profit from Exploration & Production. The company previously expected
$275 million to $300 million in segment profit from Exploration & Production.
The change reflects a higher impact from hedging, the $11.3 million charge,
reduced income from the utilization of excess transportation capacity and
higher other costs, partially offset by increased production revenues.
Midstream Gas & Liquids
Midstream, which provides gathering, processing, natural gas liquids fractionation and storage services, reported second-quarter 2004 segment profit of $98.6 million.
In the second quarter a year ago, Midstream reported segment profit of
$45.1 million on a restated basis. The increase in segment profit from the 2004
second quarter vs. the 2003 second quarter reflects the contribution of newly
constructed assets in the deepwater Gulf of Mexico, higher natural gas liquids
processing and olefins margins, and higher equity earnings from partially owned
domestic assets.
For the first six months of 2004, Midstream reported segment profit of
$206.9 million vs. a restated $157.3 million for the same period last year.
The increase in segment profit for the first six months reflects the
contribution of newly constructed deepwater assets and higher olefins margins.
Earnings from partially owned domestic assets increased in part due to the
absence in 2004 of both impairment charges and prior period accounting
adjustments recorded in 2003. Operations in Venezuela contributed approximately
$7 million in higher segment profit primarily due to reduced levels of
operations in 2003 following a fire at the El Furrial facility.
Operating activities for the second quarter of 2004 include the May 5
receipt of first production at the newly built Devils Tower offshore platform
at Mississippi Canyon block 773. This production initiated flows into the
related Canyon Chief natural gas pipeline and the Mountaineer oil pipeline that
were also recently constructed to serve this area in the deepwater Gulf of
Mexico.
Subsequent to the close of the quarter, Williams on July 28 completed the
sale of three natural gas liquids straddle plants in Canada for approximately
$536 million in U.S. funds. Williams also signed an agreement to divest
approximately 500 miles of certain onshore pipeline in Texas for $27.4 million,
subject to approval by FERC.
For the full year, Williams now expects $325 million to $375 million in segment profit from Midstream. The company previously expected $275 million to $360 million in segment profit from Midstream after giving effect to the reclassification of the Canadian straddle plants to discontinued operations. The increase in guidance is based on strong performance in the second quarter and improving natural gas liquids margin expectations.
Gas Pipeline
Gas Pipeline, which provides natural gas transportation and storage services primarily in the Northwest and along the Eastern Seaboard, reported second-quarter 2004 segment profit of $132.8 million.
In the second quarter a year ago, Gas Pipeline reported segment profit of
$115.5 million on a restated basis. The increase in segment profit in
second-quarter 2004 reflects earnings from expansion projects placed into
service after the first quarter of 2003 and the absence of a $25.5 million
charge in 2003 to write-off certain capitalized software development costs.
These were partially offset by the second-quarter 2004 charge of $9 million to
write-off previously capitalized costs incurred on an idled segment of the
Northwest system that will not be returned to service, lower transportation and
gathering revenues, and lower sales of environmental credits.
For the first six months of 2004, Gas Pipeline reported segment profit of
$280.2 million vs. a restated $265.8 million for the same period last year.
Operating activities for the second quarter of 2004 included the temporary
restoration of 131,000 dekatherms per day of service on 111 miles of the
Northwest system in western Washington that had been idled since December 2003.
The company currently plans to permanently replace in 2006 the full 360,000
dekatherms per day of capacity that was idled in December 2003.
Transco also completed a successful open season of its proposed
Leidy-to-Long Island expansion and the jointly owned Gulfstream pipeline
commenced construction on a 110-mile expansion project.
For the full year, Williams now expects $540 million to $570 million in
segment profit from Gas Pipeline. The company previously expected $525 million
to $575 million in segment profit from Gas Pipeline.
Power
Power, which manages more than 7,500 megawatts of power through long-term contracts, reported second-quarter 2004 segment profit of $44.7 million.
In the second quarter a year ago, Power reported segment profit of $348
million, which included a $175 million gain on the sale of an energy contract
and the benefit of approximately $93 million in revenues from the correction of
prior period amounts for certain third-party derivative contracts. The balance
of the decrease in segment profit primarily results from lower unrealized
mark-to-market gains associated with natural gas derivative contracts.
For the first six months of 2004, Power reported a segment profit of $12
million vs. segment profit of $211.6 million for the same period last year.
The company has been pursuing efforts to exit the Power business through a sale, but the number of viable parties expressing an interest has been limited.
As an alternative to continuing a plan of pursuing a complete exit from
the Power business, Williams is evaluating whether the benefits of realizing
the positive cash flows expected to be generated by this business through
continued ownership exceed the benefits of a sale at a depressed price. If
this alternative is pursued, Williams expects to continue the current program
of managing this business to minimize financial risk, generate cash and manage
existing contractual commitments.
For the full year, Williams continues to expect break-even to $150 million
in segment profit from Power.
Other
In the Other segment, the company reported a second-quarter 2004 loss of $14.3 million, largely resulting from an impairment charge associated with an investment in a Texas pipeline project following a determination that additional funding would be required to commission the project into service.
In
the second quarter a year ago, Other reported a segment loss of $51.7 million,
which included a $42.4 million impairment of the same investment in a Texas
pipeline project.
For the first six months of 2004, Other reported a segment
loss of $23 million vs. a segment loss of $46.9 million for the same period
last year.
Earnings Guidance
For the full year, Williams now expects recurring earnings of $0.20 to $0.40 per share. On a basis restated for the reclassification of the Canadian straddle plants to discontinued operations, the company previously expected recurring earnings of $0.14 to $0.37 per share.
Williams now expects consolidated segment profit of $1.1 billion to $1.4
billion for the year. On a basis restated for the reclassification of the
Canadian straddle plants to discontinued operations, the company previously
expected consolidated segment profit of $1.075 billion to $1.375 billion.
Individual segment-profit guidance is outlined in their respective sections in
this announcement.
The company confirmed its expectations to generate $1 billion to $1.3
billion in cash flow from operations this year.
Analyst Call
Williams’ management will discuss the company’s second-quarter 2004 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) 810-0924. International callers should dial (913) 981-4900.
Callers should dial in at least 10 minutes prior to the start of the
discussion.
The webcast replay – audio and slides –will be available at www.williams.com later today. Audio-only replays of the presentation will be available at approximately 3 p.m. Eastern today through midnight Eastern on Aug. 12. To access the replay, dial (888) 203-1112. International callers should dial (719) 457-0820. The replay confirmation code is 523724.
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. Williams’ gas wells, pipelines and midstream facilities are concentrated in the Northwest, Rocky Mountains, Gulf Coast and Eastern Seaboard. More information is available at www.williams.com.
Contact:
|
Kelly Swan | |
| Williams (media relations) | ||
| (918) 573-6932 | ||
| Travis Campbell | ||
| Williams (investor relations) | ||
| (918) 573-2944 | ||
| Richard George | ||
| Williams (investor relations) | ||
| (918) 573-3679 | ||
| Courtney Baugher | ||
| Williams (investor relations) | ||
| (918) 573-5768 |
# # #
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.
Exhibit 99.3
Reconciliation of Income (Loss) from Continuing Operations to Recurring Earnings
(UNAUDITED)
| 2003 |
2004 |
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| (Dollars in millions, except for per-share amounts) |
1st Qtr * |
2nd Qtr * |
3rd Qtr * |
4th Qtr * |
Year * |
1st Qtr * |
2nd Qtr |
Year |
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Income
(loss) from continuing operations(1) |
$ | (43.1 | ) | $ | 113.7 | $ | 20.0 | $ | (62.4 | ) | $ | 28.2 | $ | (1.5 | ) | $ | (18.0 | ) | $ | (19.5 | ) | |||||||||||
Preferred stock dividends |
6.8 | 22.7 | — | — | 29.5 | — | — | — | ||||||||||||||||||||||||
Income (loss) from continuing operations available to common stockholders |
$ | (49.9 | ) | $ | 91.0 | $ | 20.0 | $ | (62.4 | ) | $ | (1.3 | ) | $ | (1.5 | ) | $ | (18.0 | ) | $ | (19.5 | ) | ||||||||||
Income (loss) from continuing operations — diluted earnings per share |
$ | (0.10 | ) | $ | 0.17 | $ | 0.04 | $ | (0.12 | ) | $ | (0.01 | ) | $ | — | $ | (0.03 | ) | $ | (0.04 | ) | |||||||||||
Nonrecurring items: |
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Power |
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Accelerated compensation expense associated with workforce reductions |
11.8 | — | — | — | 11.8 | — | — | — | ||||||||||||||||||||||||
Severance accrual |
— | 0.6 | — | — | 0.6 | — | — | — | ||||||||||||||||||||||||
Loss accrual for regulatory issues(2) |
— | 20.0 | — | — | 20.0 | — | — | — | ||||||||||||||||||||||||
Prior period item correction(3) |
(13.7 | ) | (93.1 | ) | (1.0 | ) | (9.0 | ) | (116.8 | ) | — | — | — | |||||||||||||||||||
Gain on sale of Jackson EMC power contracts |
— | (175.0 | ) | (13.0 | ) | — | (188.0 | ) | — | — | — | |||||||||||||||||||||
Gain on sale of crude contracts and pipeline |
— | (7.1 | ) | — | — | (7.1 | ) | — | — | — | ||||||||||||||||||||||
Gain on sale of eSpeed stock |
— | — | (13.5 | ) | — | (13.5 | ) | — | — | — | ||||||||||||||||||||||
Impairment of goodwill(2) |
— | — | — | 45.0 | 45.0 | — | — | — | ||||||||||||||||||||||||
Hazelton impairment |
— | — | — | 44.1 | 44.1 | — | — | — | ||||||||||||||||||||||||
California rate refund and other accrual adjustments(4) |
— | — | — | 33.3 | 33.3 | — | — | — | ||||||||||||||||||||||||
Total Power nonrecurring items |
(1.9 | ) | (254.6 | ) | (27.5 | ) | 113.4 | (170.6 | ) | — | — | — | ||||||||||||||||||||
Gas Pipeline |
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Write—off of Oneline information system project |
— | 25.5 | — | 0.1 | 25.6 | — | — | — | ||||||||||||||||||||||||
Severance accrual |
— | 0.9 | — | — | 0.9 | — | — | — | ||||||||||||||||||||||||
Write—off of previously—capitalized costs — idled segment of Northwest’s pipeline |
— | — | — | — | — | — | 9.0 | 9.0 | ||||||||||||||||||||||||
Total Gas Pipeline nonrecurring items |
— | 26.4 | — | 0.1 | 26.5 | — | 9.0 | 9.0 | ||||||||||||||||||||||||
Exploration & Production |
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Gain on sale of certain E&P properties |
— | (91.5 | ) | — | — | (91.5 | ) | — | — | — | ||||||||||||||||||||||
Loss provision related to an ownership dispute |
— | — | — | — | — | — | 11.3 | 11.3 | ||||||||||||||||||||||||
Total Exploration & Production nonrecurring items |
— | (91.5 | ) | — | — | (91.5 | ) | — | 11.3 | 11.3 | ||||||||||||||||||||||
Midstream Gas & Liquids |
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Impairment of investment in Aux Sable |
— | 8.5 | 5.6 | — | 14.1 | — | — | — | ||||||||||||||||||||||||
La Maquina depreciable life adjustment |
— | — | 4.2 | — | 4.2 | — | — | — | ||||||||||||||||||||||||
Gain on sale of West Texas LPG Pipeline, L.P. |
— | — | (11.0 | ) | — | (11.0 | ) | — | — | — | ||||||||||||||||||||||
Gain on sale of wholesale propane |
— | — | — | (16.2 | ) | (16.2 | ) | — | — | — | ||||||||||||||||||||||
Total Midstream Gas & Liquids nonrecurring items |
— | 8.5 | (1.2 | ) | (16.2 | ) | (8.9 | ) | — | — | — | |||||||||||||||||||||
Other |
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Impairment
of Longhorn and Aspen project (5) |
— | 49.6 | — | — | 49.6 | — | 10.8 | 10.8 | ||||||||||||||||||||||||
Gain on sale of butane blending inventory |
— | — | (9.2 | ) | — | (9.2 | ) | — | — | — | ||||||||||||||||||||||
Longhorn recapitalization fee |
— | — | — | — | — | 6.5 | — | 6.5 | ||||||||||||||||||||||||
Total Other nonrecurring items |
— | 49.6 | (9.2 | ) | — | 40.4 | 6.5 | 10.8 | 17.3 | |||||||||||||||||||||||
Nonrecurring items included in segment profit (loss) |
(1.9 | ) | (261.6 | ) | (37.9 | ) | 97.3 | (204.1 | ) | 6.5 | 31.1 | 37.6 | ||||||||||||||||||||
Nonrecurring items below segment profit (loss) |
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Convertible preferred stock dividends(2)(Preferred stock dividends — Corporate) |
— | 13.8 | — | — | 13.8 | — | — | — | ||||||||||||||||||||||||
Impairment of
cost-based investments(2) (Investing income (loss) —Various) |
— | 19.1 | 2.3 | — | 21.4 | — | — | — | ||||||||||||||||||||||||
Severance accrual (General corporate expenses) |
— | 3.0 | — | — | 3.0 | — | — | — | ||||||||||||||||||||||||
Impairment of Algar Telecom investment (Investing income (loss) — Other) |
12.0 | — | 1.2 | — | 13.2 | — | — | — | ||||||||||||||||||||||||
Write-off of capitalized debt expense (Interest accrued — Corporate) |
— | 14.5 | — | — | 14.5 | — | 3.8 | 3.8 | ||||||||||||||||||||||||
Premiums, fees and expenses related to the debt repurchase and debt tender offer |
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(Other income (expense) — net — Corporate and Exploration & Production) |
— | — | — | 66.8 | 66.8 | — | 96.7 | 96.7 | ||||||||||||||||||||||||
Loss provision related to an ownership dispute — interest component (Interest accrued — Exploration & Production) |
— | — | — | — | — | — | 1.9 | 1.9 | ||||||||||||||||||||||||
| 12.0 | 50.4 | 3.5 | 66.8 | 132.7 | — | 102.4 | 102.4 | |||||||||||||||||||||||||
Total nonrecurring items |
10.1 | (211.2 | ) | (34.4 | ) | 164.1 | (71.4 | ) | 6.5 | 133.5 | 140.0 | |||||||||||||||||||||
Tax effect for above items |
3.9 | (108.7 | ) | (14.0 | ) | 43.4 | (75.5 | ) | 2.5 | 51.1 | 53.6 | |||||||||||||||||||||
Recurring income (loss) from continuing operations available to common stockholders |
$ | (43.7 | ) | $ | (11.5 | ) | $ | (0.4 | ) | $ | 58.3 | $ | 2.8 | $ | 2.5 | $ | 64.4 | $ | 66.9 | |||||||||||||
Recurring diluted earnings per common share |
$ | (0.08 | ) | $ | (0.02 | ) | $ | — | $ | 0.11 | $ | 0.01 | $ | — | $ | 0.12 | $ | 0.13 | ||||||||||||||
Weighted—average shares — diluted (thousands) |
517,652 | 534,839 | 524,711 | 518,502 | 518,137 | 525,752 | 521,698 | 520,592 | ||||||||||||||||||||||||
(1)Includes $126.8 million positive valuation adjustment associated with agreement to terminate contract with Allegheny in second quarter 2003.
(2)No tax benefit
(3)Power recognized $116.8 million of revenue in 2003 from a correction of the accounting treatment previously applied to certain third party derivative contracts during 2002 and 2001.
(4)For $5.6 million, no tax benefit
(5)For $20.2 million, no tax benefit in 2nd Qtr 2003.
* Amounts have been restated from 1st quarter 2004 to reflect the Canadian straddle plants as discontinued operations.
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.