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): June 17, 2004
The Williams Companies, Inc.
(Exact name of registrant as specified in its charter)
| Delaware | 1-4174 | 73-0569878 | ||
| (State or other jurisdiction of incorporation) |
(Commission File Number) |
(I.R.S. Employer Identification No.) |
| 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
| Item 7. Financial Statements and Exhibits. | ||||||||
| Item 9. Regulation FD Disclosure. | ||||||||
| INDEX TO EXHIBITS | ||||||||
| Copy of Slide Presentation | ||||||||
Table of Contents
Item 7. Financial Statements and Exhibits.
Williams files the following exhibit as part of this report:
Exhibit 99.1 Copy of Williams’ slide presentation dated June 17, 2004.
Item 9. Regulation FD Disclosure.
The Williams Companies, Inc. wishes to disclose for Regulation FD purposes its slide presentation, filed herewith as Exhibit 99.1, utilized during a public conference call and webcast held the morning of June 17, 2004.
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: June 17, 2004
|
/s/ Brian K. Shore | |
| Name: Brian K. Shore | ||
| Title: Secretary |
Table of Contents
INDEX TO EXHIBITS
| EXHIBIT | ||
| NUMBER |
DESCRIPTION |
|
99.1
|
Copy of Williams’ slide presentation utilized during the June 17, 2004, public conference call and webcast. |
Exhibit 99.1
| Williams Power Tutorial June 17, 2004 |
| Forward Looking Statements 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" 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: 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. |
| The Road Ahead 2004 2005 2006 2007 & beyond Risk Reduction Spark spreads improve Exit or Optimize If no exit, continue to reduce risk, generate cash, meet contractual commitments 1Q '04 Earnings Call |
| Key Points Expected 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 contracted to third parties Resolving legacy issues Strong commercial and financial capabilities Continued efforts to increase transparency 1Q '04 Earnings Call |
| Today's Discussion Overview of natural gas operations Updated regional power information Positions Fuel management Short- and long-term fundamentals Opportunities Updated financials Q&A |
| Key Takeaways Daily / hourly power plant optimization creates significant value above the forward curve Sustained $5-$10 spark spreads are not realistic Long-term fundamentals favor tail risk Steam plants in California economically and operationally viable Confident in cash flow guidance |
| Natural Gas |
| Physical Natural Gas Average annual requirements 2.8 Bcf/d with peak of 3.5 Bcf/d 40% for Power 20% power-plant supply 20% third-party transactions 60% for Williams' core businesses Transportation 2.5 Bcf/d 30% for gas marketing (including power-generation fuel) 70% for Williams' core businesses Storage 17 Bcf 67% for gas marketing (including power-generation fuel) 33% for Williams' core businesses Improving market liquidity and credit |
| E&P Gas Marketing Total volumes marketed Transportation Storage - 5 Bcf at Clay Basin |
| Supply fuel and shrink Transportation Midstream Fuel Management Mobile Bay MMBtu/d 362,250 |
| Transco Agency Service (FS Business) 190,000 MMBtu/d no-notice obligation 8 customers (Mid-Atlantic and Northeast) Notification has been given to terminate April 1, 2005 contracts terminate FERC settlement implications 1.3 Bcf of Eminence storage |
| Third-Party Marketing Transportation Storage Third-party sale obligations - 65,000 MMBtu/d Colorado Interstate Questar Southern Star Central Columbia Transco SW VA Alliance Pipeline Total MMBtu/d 34,500 30,000 29,500 15,000 15,000 10,000 134,000 |
| Power |
| Characteristics Asset-based power business with long-term contractual commitments 6 tolling contracts Approximately 7,700 megawatts Approximately $400 million in annual demand charges 8 key offsetting contracts Over-the-counter (OTC) hedges Estimated coverage of demand payment = 101% cumulative through 2010* * As of 3/31/04. See slide 88 for more detailed information. |
| Types of Hedging Transactions Resale of tolling rights Full requirements Forward power sales Mid-market structured sales Note: Appropriate quantity of gas purchased (if needed) at time of power hedge |
| Types of Hedging Transactions Resale of Tolling Rights Resale of all or part of rights under tolling arrangements Example California Department of Water Resources (CDWR) Product D Essentially mirrors underlying tolling contract |
| Counterparty-tailored arrangement where Williams ... Serves counterparty's power demand requirements Dispatches counterparty's power plants / resources Markets excess energy produced by these resources and covers short positions Examples Georgia Electric Membership Corporations Four individual contracts Allegheny Electric Cooperative Types of Hedging Transactions Full Requirements |
| Physical or financial sale of a defined quantity of power over a set period of time Examples CDWR Products A, B and C Cleco Utility Group Standard OTC transactions Typical counterparties Power marketers Financial institutions Utilities Time horizon for hedging with forward contracts has lengthened as credit and liquidity have improved Types of Hedging Transactions Forward Power Sales |
| Non-standardized, near-term transactions Customized to meet customer/counterparty needs Term less than 3 years Examples Resale of tolling, full requirements, load serving, capacity Typical counterparties Utilities, municipalities and cooperatives Power marketers and retail aggregators Financial institutions Opportunity to hedge near-term volumes over next 2 to 3 years Types of Hedging Transactions Mid-Market Structured Sales |
| Hourly prices provide additional value beyond forward prices Thus, cannot determine full value based solely on forward prices Each unit has unique operational characteristics Peaker vs. intermediate vs. base-load Start-up costs, start time, minimum run time, ramp-down capability, etc. Generation Optimization Considerations |
| Examples illustrate value of daily/hourly markets Example 1: Monthly optimization Example 2: Daily/hourly optimization Forward prices assumptions* On-peak: $58.62 / MWh Off-peak: $40.21 / MWh Gas: $6.83 / MMBtu Simplified unit operational characteristics applied to both examples 650 MW capacity; 7,000 heat rate; $2.25 variable O&M and 8-hour minimum run time * Average of actual May 2004 historical hourly prices for PJM's Ironwood real-time LMP (locational marginal price) and Tetco M-3 gas Generation Optimization Example Assumptions |
| Spark-Spread Revenue* On-Peak: $1.8 million Off-Peak: $0.0 million Total: $1.8 million Spark-Spread Margin* On-Peak: $8.55 / MWh Off-Peak: $0.00 / MWh Never dispatch out-of-money No dispatch off-peak since: Production Cost > Off-Peak average price * Net of variable O&M. Intended to be illustrative example and does not include all specific operational costs & parameters Generation Optimization Example 1: Monthly Dispatch |
| Spark-Spread Revenue* On-Peak: $2.1 million Off-Peak: $1.5 million Total: $3.6 million Spark-Spread Margin* On-Peak: $(28)-62/ MWh Off-Peak: $(45)-77/ MWh Occasional dispatch out-of-money to maximize total spark-spread revenues (subject to 8-hour minimum run time) * Net of variable O&M. Intended to be illustrative example and does not include all specific operational costs & parameters Generation Optimization Example 2: Daily/Hourly Dispatch |
| Additional capacity and infrastructure enhancements needed to support growth New construction not viable at $5-$10/MWh spark spreads For all but most efficient plants, revenues would be less than construction / interconnection costs Difficult for majority of power plants to recoup production costs at $5-$10/MWh spark spreads Market forces will align spark spreads with growth requirements, resulting in supply-demand balance Timing of return to balance uncertain, different by region $5-$10 Spark Spreads Not Realistic |
| Utilization Factor: 45% Spark-Spread: $5.00/MWh Spark-Spread Revenue: $19.71/kW-yr (.45 * 8760 * $5.00) /1,000 Construction $615/kW ** Interconnection $229/kW ** Total $844/kW Total $74.97 /kW-yr * plus Fixed 0&M $10.34 /kW-yr ** Total Annual $85.31 /kW-yr * 8.0% cost of capital, 30 years ** Assumption for Adv. Gas/Oil Comb Cycle from EIA Annual Energy Outlook 2004 $5-$10 Spark Spreads Not Realistic |
| West |
| AES 4000 Tolling Arrangement Capacity: 4,141 MW* Base term: June 2013 5-year option for either party to extend to 2018 Annual demand payment: $153 million in 2004-05 Escalates 1.0% annually until 2013; flat after 2013 Variable O&M payment $2.28/MWh in 2004 Annual escalator is lesser of 2.5% or CPI Owned: Milagro 60 MW Natural-gas fired Tolling: AES 4000 4,141 MW Through 2018 Forward Power Sale: CDWR A, B, C 50-450 MW Through 2010 Resale of Toll: CDWR D 1,045-1,175 MW Through 2010 * Receiving non-availability payments for 266 MWs that have been retired |
| AES 4000 Capacities and Heat Rates Alamitos Unit 1 184 10.7 Unit 2 184 10.6 Unit 3 336 9.5 Unit 4 336 9.7 Unit 5 * 504 9.4 Unit 6 * 504 9.5 Unit 7 ** 133 16.5 Huntington Beach Unit 1 * 226 9.8 Unit 2 226 9.8 Unit 5 ** 133 16.5 Redondo Beach Unit 5 184 11.8 Unit 6 184 11.8 Unit 7 504 9.4 Unit 8 504 9.4 AES 4000 Total 4,141 9.84*** Capacity (MW) Heat Rate (MMBtu/MWh) * CDWR Product D; ** Unavailable due to environmental limitations; *** Excludes unavailable units Note: Based on AES 4000 tolling agreement. |
| Younger plants are more efficient, have higher capacities, dispatched more frequently Favorable economics to repower older units Convert 184MW steam units into 450-525 MW combined cycle Estimate cost to be 75-80% of comparable new capacity Goal to exit has precluded additional capital expense No intention to repower at this time Repowering Considerations AES 4000 |
| Third-party engineering study found average U.S. plant life across all fuels is 70.1 years Excluding unavailable units, average AES 4000 age is 43 years Repowering Considerations AES 4000 0 100 200 300 400 500 600 700 800 900 1000 1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000-03 In-Service Date of U.S. Steam Turbines Number of Units AES 4000 - Other Units Alamitos 5 & 6 (CDWR D) Redondo Beach 7 & 8 |
| AES 4000 Offsetting Contracts CDWR Products A, B, C Forward power sale Product A July 1, 2003 to Dec 31, 2007 200 MW 7x24 @ $62.50/MWh Product B July 1, 2003 to Dec 31, 2010 450 MW 6x16 @ $87.00 to $74.07/MWh Product C July 1, 2008 to Dec 31, 2010 50 MW 6x16 @ $70.00/MWh Contract terms: http://www.cers.water.ca.gov/power_contracts.cfm |
| CDWR Product D Resale of tolling rights Essentially, a mirror-image toll Term Jan. 2003 to Dec. 31, 2010 Quantity 1,175 MW through Dec. 31, 2007 1,045 MW through Dec. 31, 2010 Price $140/kW-year (to Dec. 31, 2007) to $117/kW-year (Jan. 1, 2008, to Dec. 31, 2010) Includes availability guarantees and potential penalties AES 4000 Offsetting Contracts Contract terms: http://www.cers.water.ca.gov/power_contracts.cfm |
| AES 4000 Transportation agreements cover 95% of 650,000 MMBtu/d peak need Kern: 107,625 MMBtu/d El Paso: 5,484 MMBtu/d SoCal: 506,794 MMBtu/d Storage 4 Bcf SoCal Intrastate 1 Bcf Clay Basin storage CDWR contract CDWR Product D contract gas management / supply Fuel Management West |
| AES 4000 Locational Advantages AES 4000 generation "in-city" with premium Los Angeles locations Serves constrained load pocket Williams sells critical ancillary services to California ISO AES 4000-generated energy could benefit from accelerated schedule to enhance reserve margins and/or locational marginal pricing (LMP) No premium associated with LMP included in projections Development of capacity market WECC reserve margins not reflective of unique Southern California fundamentals |
| Hydroelectric capability ~80% of 30-year average (National Oceanic and Atomospheric Administration) Major SP-15 transmission line capacity lowered by one- third for summer 2004 Triple-digit temperatures in May resulted in SP-15 hourly peak prices in excess of $180/MWh California ISO predicts peak demand growth of 3.56% (approx. 1,500 MW) in 2004, with no growth in net resource capacity 31% year-on-year peak demand increase in April; 7% year- on-year average energy use increase in April (California ISO) Short-Term Fundamentals West |
| No merchant generation investment until functioning market proven Long-term power purchase agreements likely necessary to secure financing for new power plants Infrastructure enhancements causing high interconnection costs for new generation CA Public Utility Commission easing restrictions which previously prevented long-term hedging by utilities Potential LMP implementation should result in premium energy prices for "in-city" generation Unfavorable political climate for utilities to add generation to rate base Long-Term Fundamentals West |
| Short-term 1- to 3-year RFPs issued by utilities Resource adequacy rules currently being developed in CA Ability to sell physical capacity (viewed by utilities as superior to financial products offered by non-physical marketers) Long-term Hedging opportunities expected to emerge as 18,000 MW of contracts* in CA expire AES 4000 contract includes option to re-power units LNG re-gasification projects would likely reduce regional fuel prices * Including QF (qualifying facilities), utility and CDWR between 2004-2013. See Slide 79 in Appendix. Opportunities West |
| Original CDWR Contracts Commenced Heat Rate (Btu/kWh) AES 4000 Hedging vs. Market West |
| Mid-Continent |
| Tolling agreements 1,306 MW 7,700 average heat rate Accounts for approximately 22% of approximately $400 million annual demand charges Tolling: Cleco Evangeline 765 MW Through 2020 Forward Power Sale: Cleco Evangeline 100-250 MW Through 2005 Tolling: Kinder Morgan - Jackson 541 MW Through 2018 Portfolio Characteristics Mid-Continent |
| Forward power sales Capacity sold from Cleco Evangeline 250 MW through 2004 Call option from Cleco Evangeline 200 MW through 2004 100 MW through 2005 Offsetting Contracts Mid-Continent |
| Cleco Evangeline (Entergy) 145,000 MMBtu/d Columbia Gulf firm transportation capacity Peak day needs of 110,000 MMBtu/d 1 Bcf Egan (storage) KM Jackson (ECAR) 75,000 MMBtu/d full-requirements supply agreement Balancing account provided Gas Daily index price Fuel Management Mid-Continent |
| Cleco Evangeline (Entergy) Markets depressed in short-term Possibility for some upside to spark spreads to relieve temporary system constraints KM Jackson (ECAR) Markets depressed in short-term Short-Term Fundamentals Mid-Continent |
| Broader market significantly oversupplied Reserve margins will remain high for considerable length of time Plant located in relatively constrained portion of electric power grid SPP reserve margins not reflective of unique Central Louisiana fundamentals Long-Term Fundamentals Cleco Evangeline (Entergy) |
| Long-Term Fundamentals KM Jackson (ECAR) AEP's expected integration into PJM market (~Oct 2004) increases transmission efficiency MISO's implementation of a wholesale energy market targeted for March 2005 KM Jackson facility located in MISO footprint, providing future opportunities for energy and capacity sales into an organized market |
| Opportunities Cleco Evangeline and KM Jackson Short-term RFPs issued by host utilities for capacity and energy Resale of tolling to retail aggregators and market participants Long-term RFPs issued by host utilities for capacity and energy Cooperative and municipal load-serve transactions |
| East |
| Portfolio Characteristics East Tolling agreements 2,276 MW 7,000 average heat rate Accounts for approximately 40% of approximately $400 million annual demand charges Full Requirements: Allegheny Electric Co-op 515-600 MW Through 2008 Tolling: AES Ironwood 666 MW Through 2021 Tolling: AES Red Oak 766 MW Through 2022 Owned: Hazleton 147 MW Natural gas-fired Full Requirements: Four Georgia EMCs 600-1,500 MW Through 2015 Tolling: TenaskaLindsay Hill 844 MW Through 2020 |
| Offsetting Contract East - PJM Full requirements Agreement with Allegheny Electric Cooperative Not affiliated with Allegheny Energy Supply (AYE) Term December 2008 Capacity sold Approximately 600 MW peak demand |
| Offsetting Contracts East - SERC Full requirements 4 agreements with Walton, Colquitt, Satilla and Rayle EMCs Term December 2015 Capacity sold 600 MW in 2005, growing to 1,500 MW in 2015 |
| Fuel Management East AES Ironwood (PJM) Peak daily requirement - 130,000 MMBtu/d 80,000 MMBtu/d no-notice supply agreement AES Red Oak (PJM) Peak daily requirement - 130,000 MMBtu/d 50,000 MMBtu baseload supply agreement Supplemental supply agreement Tenaska Lindsay Hill (SERC) Peak daily requirement - 110,000 MMBtu/d 65,000 MMBtu/d seasonal transportation agreement Hedging of heating oil fuel requirements |
| Short-Term Fundamentals Ironwood/Red Oak (PJM) PJM forecasts 2.1% increase in 2004 peak demand Significantly higher than 0.4% realized in 2003 2004 year-to-date actual PJM Eastern spark spreads* $5.82/MWh higher than 2003 comparables due to high coal prices and corresponding off-peak energy prices ComEd integrated into PJM market on May 1, 2004 Potential to efficiently serve larger market with Virginia integration into PJM *Assumes around-the-clock avg. real-time prices for PJM's JCPL Zone and Transco Z-6 with 7,000 heat rate |
| Long-Term Fundamentals Ironwood/Red Oak (PJM) Three RTOs (PJM, ISO-NE and NYISO) reevaluating design of capacity markets Proposed redesign intended to provide clearer price signals on value of capacity Revision to price mitigation for reliability units would more fairly compensate existing units Likely structure will include demand curve component Proposed redesign would likely increase capacity value Announced retirements in PJM are currently approximately 1,300 MW of ~70,000 MW demand Another 3,500+ MW likely to be retired within five years |
| Short- and Long-Term Fundamentals Tenaska Lindsay Hill (SERC) Committed to Georgia EMCs through 2015 |
| Opportunities East Ironwood/Red Oak (PJM) Increasing longer-term market liquidity Utilities, municipalities and cooperatives are re-entering the market for structured deals Continued grid inefficiencies should benefit Red Oak Forward sales to bidders of future retail load auctions (BGS and Maryland); total value of 2004 BGS auction was $5.1 billion Tenaska Lindsay Hill (SERC) Committed to Georgia EMCs through 2015 |
| Ironwood/Red Oak Hedging vs. Market East - PJM Allegheny Electric Coop. Commenced Heat Rate (Btu/kWh) |
| Tenaska Hedging vs. Market East - SERC Georgia EMC Full Requirements Commenced Heat Rate (Btu/kWh) |
| Consolidated Financials |
| Undiscounted Cash Flows Combined Segment Portfolio Note: Actual cash flows realized upon liquidation or sale of the portfolio may differ materially from those shown. Variability in actuals versus forecast is reflected in range of guidance provided. Dollars in millions |
| Tolling cash flows associated with hedges Represents a percentage of the value of the underlying tolling option Includes value associated with optionality, such as volatility, that is not effectively hedged with all products; thus, actual cash flows may vary from estimates provided Merchant cash flows Represents unhedged cash flow from expected generation associated with underlying tolling option Includes value associated with optionality, such as volatility; thus, actual cash flows may vary from estimates provided Undiscounted Cash Flows Line Item Clarification |
| 1Q04 4Q03 1Q03 Reported Segment Profit Total Segment Gross Margin ($2) $40 ($91) SG&A (16) (17) (36) Op. Exp. & Other Inc / (Exp) (15) (124) (9) Reported Segment Profit ($33) ($101) ($136) Includes: Impairments - 89 - Prior Period Adjustment - (12) - Cal. Refund & Other Accrual Adj. - 33 - Reduction in Force Costs - - 11 Recurring Segment Profit ($33) $9 ($125) Dollars in millions 1Q '04 Earnings Call |
| Segment Profit to Cash Flow Total Segment 1Q04 Dollars in millions |
| Hedge Accounting Considerations Mark-to-market (MTM) volatility in earnings significantly reduced, but not eliminated GAAP earnings not likely to track cash flows due to MTM recognized prior to hedge accounting election date Legacy positions may not qualify for hedge accounting, thus will continue to be MTM Ineffectiveness in hedge portfolio still MTM |
| 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 2004-2006 Guidance Total Segment * Assumes full year forward MTM gains or losses are zero ** Excludes commodity margin volatility 1Q '04 Earnings Call |
| Enterprise Risk Management Margin volatility (99% confidence interval) - - Incremental liquidity requirement 3/31/04 12/31/03 30 days ($185) ($183) 180 days ($309) ($324) 360 days ($390) ($349) Incremental Margin requirement from historical price spike 2/27/03 ($139) Assumption: The margin numbers above consist of only the forward marginable position values, starting from May 2004. Dollars in millions 1Q '04 Earnings Call |
| Enterprise Risk Management Sensitivities Analysis* * 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. Estimated dollars in millions 1Q '04 Earnings Call |
| Summary |
| Key Takeaways Daily / hourly power plant optimization creates significant value above the forward curve Sustained $5-$10 spark spreads are not realistic Long-term fundamentals favor tail risk Steam plants in California economically and operationally viable Confident in cash flow guidance |
| Summary Operating business to Reduce risk Generate cash Meet contractual commitments Continuing difficulty in exiting business Viable business fundamentals both short- and long-term |
| Q&A |
| Appendix |
| Business Background |
| Tolling Concept Input Output Heat Rate (Fuel Conversion Efficiency) Natural Gas, Coal, Fuel Oil, Steam Power Power Generation (Fuel Converter) Tolling - Fuel conversion arrangement. Williams supplies fuel to plants and markets electricity output. Plant owner receives fixed fee and retains operational responsibility. |
| Heat Rate Concept Heat rate - The amount of fuel a power plant requires to produce one unit of power. A measure of the efficiency of generating plants. MMBtu MWh Key concepts The lower the heat rate, the more efficient the power-generation unit. Heat rate, when considered in conjunction with a unit's input fuel, generally determines a power-generation unit's economic viability in a given market. = Heat Rate |
| Power Cost: Power Price Fuel Cost Heat Rate Spark Spread Example: $42/Mwh $4/MMBtu 10MMBtu/MWh $2/MWh Spark Spread Concept Spark spread - The difference between the price of power and the cost it takes to produce it at a given facility. Key concepts The higher the spark spread, the higher the margin. A negative spark spread indicates it is more economical to purchase power to meet commitments than run generating facilities "out of the money." - - x = - - x = * Variable O&M costs typically included in spark-spread calculation, but not reflected here for sake of simplicity. |
| Tolling Cash Flows Assoc. with Hedges Estimated Cash Flow Underlying Associated w/ Associated w/ Toll Market Hedge Toll* Hedge Net ($25) $35 $35 $10 $0 $10 ($25) $30 $35 $5 $5 $10 ($25) $20 $35 $0 $15 $15 * Both the hedge and the underlying toll are marked against current market prices. Example 1 Example 2 Example 3 Represents the estimated tolling cash flows that have been hedged. |
| Summary of NG Storage Agreements * Maximum Storage Quantity in Bcf $5.8 10.9 Total $1.9 Transport Associated with Storage Mar '12 $0.4 0.8 NGPL Midcontinent Mar '12 $0.8 1.6 NGPL Gulf Coast Mar '13 $0.9 2.0 Dawn Apr '08 $3.7 6.4 Clay Term Demand MSQ* Storage Agreements Dollars in millions |
| Summary of NG Transport Agreements Demand = Dollars in millions per year Capacity = MMBtu/d $14.7 136,588 Total Transport Dec '07 $2.2 29,494 WNG-CIG Annual $0.8 6,880 Transco (6,880) Oct '04 $0.8 5,000 Transco - PG Energy Jun '06 $0.7 5,484 El Paso Dec '04 $1.2 10,000 CIG (Elk Basin to Baker) Nov '05 $0.9 7,730 CIG (Elk Basin to Lakin) Aug '09 $2.9 25,000 CIG (Bl Forest, King & Grn River to Lakin) Dec '07 $0.7 15,000 CIG (CGF & Elk Basin to WIC) Dec '07 $0.4 15,000 CIG (Cave Gulch & Cyclone Ridge to WIC) Aug '09 $0.8 7,000 CIG (Green River to Tomahawk/Cheyenne) Sep '15 $3.4 10,000 Alliance Term Demand Capacity Transportation Agreements |
| California Contract Expirations 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 CDWR 0 50 25 50 75 750 2000 1900 4900 100 QF 0 25 50 50 1000 0 1000 0 0 0 Utility 1100 0 1000 0 1000 3200 0 0 0 0 Source: CA PUC Staff Report, A Core/Noncore Structure for Electricity on California. March 15th 2004. P.19 |
| NERC Regions Red Oak Ironwood Hazelton Tenaska Evangeline AES 4000 KM Jackson |
| NERC Projected Capacity Margins WECC Source:Reliability Assessment 2003-2012. NERC Dec. 2003 ECAR MACC SERC |
| Forward Spark-Spreads SP-15 (AES4000) Spark-spread represents the variable net margin per MWh of energy production Curve assumes a 7 heat rate conversion efficiency and assumes no VO&M Spark-Spread = Power Price - (7 ? Gas Price) Note: For consistency with Est. Cash Flow projections, Current curves presented above represent market conditions as of 3/31/2004 |
| Forward Spark-Spreads Entergy (Cleco Evangeline) Spark-spread represents the variable net margin per MWh of energy production Curve assumes a 7 heat rate conversion efficiency and assumes no VO&M Spark-Spread = Power Price - (7 ? Gas Price) Note: For consistency with Est. Cash Flow projections, Current curves presented above represent market conditions as of 3/31/2004 |
| Forward Spark-Spreads ECAR/MI (KM Jackson) Spark-spread represents the variable net margin per MWh of energy production Curve assumes a 7 heat rate conversion efficiency and assumes no VO&M Spark-Spread = Power Price - (7 ? Gas Price) Note: For consistency with Est. Cash Flow projections, Current curves presented above represent market conditions as of 3/31/2004 |
| Forward Spark-Spreads PJM-West (Red Oak / Ironwood) Spark-spread represents the variable net margin per MWh of energy production Curve assumes a 7 heat rate conversion efficiency and assumes no VO&M Spark-Spread = Power Price - (7 ? Gas Price) Note: For consistency with Est. Cash Flow projections, Current curves presented above represent market conditions as of 3/31/2004 |
| Forward Spark-Spreads Southern (Tenaska) Spark-spread represents the variable net margin per MWh of energy production Curve assumes a 7 heat rate conversion efficiency and assumes no VO&M Spark-Spread = Power Price - (7 ? Gas Price) Note: For consistency with Est. Cash Flow projections, Current curves presented above represent market conditions as of 3/31/2004 |
| Financials & Accounting |
| Dollars in millions Demand Payment Coverage |
| Total Undiscounted Cash Flows West Power Portfolio Dollars in millions 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, option premiums and margins are not included. |
| Total Undiscounted Cash Flows Mid-Continent Power Portfolio Dollars in millions 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, option premiums and margins are not included. |
| Total Undiscounted Cash Flows East Power Portfolio Dollars in millions 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, option premiums and margins are not included. |
| 1Q04 Change in Power-Only Portfolio Cash Flows 4Q03 4Q02 2003 2002 Dollars in millions Dollars in millions Note: Represents change in estimated value over a 3 month time frame from 12/31/03 to 3/31/04 1Q '04 Earnings Call |
| Undisc. Cash Flow Variance Analysis Power-Only Portfolio Dollars in millions Dollars in millions Combined Power Portfolio Actual Forecast Actual 1Q04 v. Forecast 1Q04 1Q04 1Q04 Tolling Demand Payment Obligations $(88) $(85) Resale of Tolling 41 42 Full Requirements (1) (4) Long-term Physical Forward Power Sales 27 22 OTC Hedges 36 46 Estimated Hedged Tolling Revenues 7 (0) Total Cash Flows 22 21 Estimated Merchant Revenue Unhedged - - Forecasted Direct SG&A (8) (13) Forecasted Indirect SG&A (8) (6) Estimated Cash Flows After SG&A $6 $2 1Q '04 Earnings Call |
| Dollars in millions MTM Realizations Power Segment Derivative Balances Expected to be Realized Based on 3/31/04 Fair Value 2Q 2004 $10 3Q 2004 63 4Q 2004 19 2005 188 2006 174 2007-2010 170 2011-2022 20 |
| Revenue Recognition EITF 02-3 Adoption of EITF 02-3 on Jan. 1, 2003, requires: Non-derivative contracts be reported on an accrual basis Derivative contracts continue to be reported on a fair value basis under SFAS 133 Not currently qualified for cash flow hedge accounting under SFAS 133 due to stated intent to exit the business |
| Revenue Recognition EITF 02-3 Prohibits the use of fair-value accounting treatment for contracts that do not qualify as derivatives under FAS 133 "Accounting for Derivative Instruments and Hedging Activities" Derivative instruments: Underlying Notional Net settlement or instrument is readily convertible to cash Minimal net initial investment |
| Revenue Recognition EITF 02-3 Derivative instruments Financial transactions Options Swaps Futures Forward physical transactions Non-derivative instruments Tolling CDWR Product D Full requirements Storage Transportation Transmission Transco Agency Service Spot physical transactions |
| Revenue Recognition EITF 02-3 Since not currently qualified for cash flow hedge accounting... Derivative instruments accounted for on a fair-value (MTM) basis Changes in the forward value of these instruments are recorded as unrealized gains / losses on the income statement and balance sheet Non-derivatives reported on an accrual basis |
| Revenue Recognition EITF 02-3 GAAP earnings vary from economic results and cash flows: MTM gains or losses reflect change in fair value of derivative hedge portfolio, but not change in fair value of underlying non-derivative contracts such as tolling agreements Accrual earnings reflect earnings from underlying non-derivative contracts, but do not include previously recognized unrealized gains or losses from derivative contracts Normal purchases & sales contracts are no longer MTM but reflect realized accrual earnings offset by periodic reversal of previously recognized MTM earnings GAAP earnings are volatile because hedges are MTM without offsetting impact of change in fair value of underlying contract Cash flows provide proxy for accrual-based economic results, but include changes in working capital |
| Other changes mandated by EITF 02-3 Revenue Recognition EITF 02-3 Before EITF 02-3 Inventory accounted for on MTM basis All trading revenues reported on a net basis After EITF 02-3 Inventory accounted for on a Lower of Cost or Market (LCM) basis Revenue reporting mixed Unrealized derivative revenues reported net Financially settled realized derivative revenues reported net Non-derivative revenues reported gross Physically settled realized derivative revenues reported gross |
| Revenue Recognition - EITF 02-3 Summary of Accounting Treatment by Contract type: Contract Type Acctg Acctg Income Revenues "Bucket" Method =Cash? Gross/Net Tolling Non-Derivative Accrual Yes Gross Full Requirements Non-Derivative Accrual Yes Gross Storage Non-Derivative Accrual Yes Gross Transportation Non-Derivative Accrual Yes Gross Transmission Non-Derivative Accrual Yes Gross Firm Service Non-Derivative Accrual Yes Gross CDWR Product D Non-Derivative Accrual Yes Gross Spot Physical Trxs Non-Derivative Accrual Yes Gross CDWR ABC Derivative Normal P&S No Gross & Net OTC/NYMEX Fins Derivative MTM No Gross & Net Forward Physicals Derivative MTM No Gross & Net |
| Revenues include: Gross revenue for non-derivative contracts (eg., tolling) Gross revenue for realization of physically settled forward sales contracts Net revenues for changes in fair value of derivatives (unrealized gains and losses) Note: Changes in fair value of non- derivatives no longer reported Selling, General & Administrative Expenses Costs & op exps include: Demand payments Gross purchases for realization of physically settled forward purchases Income Statement: 1Q 2004 10-Q Note: The full 1Q04 consolidated statement of operations is available on williams.com. |
| Balance Sheet: 1Q 2004 10-Q Accounts Receivable: Commodity sales and derivative settlements Derivative Assets: Fair value (unrealized gains) of derivatives Margins: Margins, adequate assurance and prepays paid to others Note: Fair value of non-derivative contracts no longer reported on the balance sheet Accounts Payable: Commodity purchases Derivative Liabilities: Fair value (unrealized losses) of derivatives Note: The full 1Q04 consolidated balance sheet is available on williams.com. |
| Frequently Asked Questions |
| FAQ What happens if a plant realizes a heat rate greater (or less) than what is provided under the contract? Although the terms vary, all of the tolling agreements have "heat rate guarantees" that effectively put the risk and benefit of heat rates that differ from the guaranteed rates on the plant owner/operator. These contractual/financial guarantees by the owner/operator allow Williams to focus on market conditions in making dispatch decisions. What happens if a plant exhibits low availability? All of Williams' tolling agreements have availability guarantees, again with variations in terms, that provide for discounts to Williams' payments in the event target availabilities are not achieved. Availability bonuses are designed to give owner/operators incentives to achieve higher availabilities. Please explain what re-powering (improvement) rights Williams has under the AES4000 agreement? Subject to specified conditions, Williams has the right to cause unit repowering to achieve heat rate improvements. If the repowering is not pursued, Williams has a buy-out right for an amount equal to the outstanding debt attributable to the unit, plus costs, and equity (including ROE). How does the Product D contract compare to the AES4000 PPA? The Product D contract functions essentially as a "mirror image" of the the AES 4000 agreement: CDWR has tolling and dispatch rights to designated units that mirror Williams' rights with AES, subject to important exceptions, including price and volume. Does Williams have any gas price risk associated with Product D? CDWR is responsible for obtaining (at its cost) fuel for the designated units. Williams has supplied index-priced fuel to the CDWR for designated units under a fuel supply plan. Note: All answers regarding Williams' contracts are necessarily summary in nature and subject to the specific provisions of the agreements. |
| FAQ (Cont.) Is Williams required to supply energy for the CDWR contracts from the AES 4000 plants? Product D is the only contract that requires delivery of energy from the AES 4000 plants. Energy for Products ABC can be supplied from the market and as long as it is scheduled to SP-15. How do the ratings agencies calculate imputed debt for the power portfolio? It is our understanding that S&P discounts the demand payments back at 10% and takes 70% of that number. While Moody's uses a similar methodology, they do not publish their calculated results. |