UNITED STATES 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
of the Securities Exchange Act of 1934
Date
of Report (Date of earliest event reported): November 30,
2005
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)
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy
the filing obligation of the registrant under any of the following provisions:
o
|
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |
o
|
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240-14a-12) | |
o
|
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |
o
|
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 7.01. Regulation FD Disclosure.
The Williams Companies, Inc. (“Williams”) wishes to disclose for Regulation FD purposes its
slide presentation, furnished herewith as Exhibit 99.1, to be utilized during a public conference
call and webcast the morning of November 30, 2005.
The slide presentation is being furnished pursuant to Item 7.01, Regulation FD Disclosure. 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 Securities Act of 1933, as amended.
Item 9.01. Financial Statements and Exhibits.
| (a) | None | ||
| (b) | None | ||
| (c) | Exhibits |
| Exhibit 99.1 Copy of Williams’ slide presentation dated November 30, 2005. |
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: November 30, 2005
|
/s/ Brian K. Shore | |||||
| Name: | Brian K. Shore | |||||
| Title: | Secretary | |||||
2
INDEX TO EXHIBITS
| EXHIBIT | ||
| NUMBER | DESCRIPTION | |
Exhibit 99.1
|
Copy of Williams’ slide presentation dated November 30, 2005. |
3
Exhibit 99.1
| Williams Midstream & Power Update November 30, 2005 |
| 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" within the meaning of the 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 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; 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; The different regional power markets in which we compete or will compete in the future have changing regulatory structures; Our risk measurement and hedging activities might not prevent losses; 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 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 our business; 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 have required us to provide higher amounts of credit support; Despite our restructuring efforts, we may not attain investment grade ratings; Institutional knowledge represented by our former employees now employed by our outsourcing service provider might not be adequately preserved; Failure of the outsourcing relationship might negatively impact our ability to conduct our business; Our ability to receive services from outsourcing provider locations outside the United States might be impacted by cultural differences, political instability, or unanticipated regulatory requirements in jurisdictions outside the United States; 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 natural gas transmission and midstream businesses; Our drilling, production, gathering, processing and transporting activities involve numerous risks that might result in accidents and other operating risks and costs; Compliance with the Pipeline Improvement Act may result in unanticipated costs and consequences; Estimating reserves and future net revenues involves uncertainties and negative revisions to reserve estimates and oil and gas price declines may lead to impairment of oil and gas assets; The threat of terrorist activities and the potential for continued military and other actions; The historic drilling success rate of our exploration and production business is no guarantee of future performance; and Our assets and operations can be affected by weather and other phenomena. 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. Forward Looking Statements |
| Agenda Midstream Update 8:30 a.m. - 10:30 a.m. Break 10:30 a.m. - 10:45 a.m. Power Update 10:45 a.m. - 12:15 p.m. |
| Williams Midstream & Power Update Steve Malcolm Chairman, President & CEO |
| Midstream Update Alan Armstrong Senior Vice President, Midstream November 30, 2005 Midstream |
| Agenda Midstream Strategy and Outlook Alan Armstrong Midstream Deepwater Gulf of Mexico Story Rory Miller Dissecting Midstream's Earnings Dave Darcey Conclusion and Wrap Up Alan Armstrong Q&A Midstream |
| What is Midstream's Business? Midstream Onshore Gas Wells Processing Plant Refineries Chemical Plants Agricultural/ Residential Industrial Fuels Fractionator Residue Gas to Interstate Pipelines Storage Product Pipeline NGL Pipeline Offshore Oil/ Gas Platforms Net Book Value + Equity Investment @12/31/04 = $3,500 MM 2004 Recurring Segment Profit = $471 MM 2004 Recurring Segment Profit + DD&A = $649 MM A more detailed schedule reconciling segment profit (loss) to recurring segment profit is available on Williams' Web site at www.williams.com and at the end of this presentation. |
| Business Overview Midstream Strategy Overview Regional Overview Growth Overview |
| Strategy & Business Focus We safely operate large-scale midstream infrastructure where there is a high potential for extremely high capacity utilization and low per-unit costs. We leverage the scale of these assets to defend the lowest-cost operations in the markets we serve. We consistently attract new business to our assets by providing the highest level of reliability. Strategy Williams delivers the most reliable midstream services that maximize the value of our reserves. Customer Value Proposition Productive Capacity Large-volume, high-utilization factors on large-scale gathering and processing assets. Quality Be considered the most reliable service provider. Business Focus Competitive Necessity Midstream |
| Midstream Reliability Reliability |
| Gas Processing Plant Scale And Utilization Midstream 2006P 2007P 2008P 2100 554 636 728 1850 344 355 185 1600 1350 1300 1300 Williams 1100 1100 1000 1000 900 860 850 800 800 800 780 740 700 700 Williams 650 650 650 Williams 600 600 600 600 600 Williams 500 500 500 450 425 425 Williams 390 365 Williams 350 350 330 325 310 305 Williams 300 300 300 290 285 270 270 270 265 260 260 250 250 250 250 250 250 250 240 235 230 225 225 Williams 220 210 206 205 200 200 200 200 200 200 190 180 180 180 180 175 175 175 175 175 170 170 170 165 165 165 162 160 160 160 154 150 150 150 Opal Echo Springs Ignacio Mobile Bay Markham Larose Cameron 2004 Plant Capacity For Top 50% of Plants in Lower 48 Kutz Williams' Plant Utilization Opal - 100% Echo Springs - 103% Ignacio - 109% Kutz/Lybrook - 88% Markham - 104% Mobile Bay - 80% Larose - 54% Cameron - 71% Williams Avg - 87% Group Avg* - 60% *For Top 50 Plants Based on Oil & Gas Journal Survey Lybrook 10% 20% 30% 40% 50% |
| Business Overview Midstream Strategy Overview Regional Overview Growth Overview |
| Gulf Coast Assets Midstream World's largest dry tree spar GOM's deepest sub-sea tie-back Significant number of large scale, high growth opportunities |
| West Region Assets Midstream Exposure to significant drilling activity 2nd largest NGL producing complex in lower 48 Largest gatherer in San Juan Basin Enjoys advantages of economies of scale Opal Kutz Milagro Echo Springs Lybrook |
| World's 2nd largest compression station Operations at PDVSA'a #1 producing oil field in Venezuela Long term contracts in place Venezuela Assets Midstream |
| Canadian Assets Midstream Only processor of tar sands off-gas Only olefins fractionator in western Canada |
| Business Overview Midstream Strategy Overview Regional Overview Growth Overview |
| Midstream Strong Free Cash Flow Note: - - Segment Profit is stated on a recurring basis. Segment Profit for 2003 & 2004 has been restated to reflect reclassifications - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges. - - Margin uplift represents actual realized margin in excess of forecasted margin. Dollars in millions 0 100 200 300 400 500 600 700 800 Capital 2003 Seg Profit + DDA Seg Profit & DDA Discretionary Expansion Margin Uplift Base Capital Spending Historic Expansion Discretionary Expansion Maintenance Well Connects Capital Seg Profit + DDA 2004 Capital Seg Profit + DDA 2005 Capital Seg Profit + DDA 2006 Capital Seg Profit + DDA 2007 From 3Q 2005 Analyst Presentation |
| Life Cycle Comparison - West Versus Gulf Midstream Operating Income + DD&A Operating Income + DD&A Net Book Value 1997 1998 1999 2000 2001 2002 2003 2004 Operating Income 225 171 195 264 204 270 288 352 NBV 888 942 1050 1133 1138 1171 1171 1128 1997 1998 1999 2000 2001 2002 2003 2004 Operating Income 12 7 33 54 35 65 144 180 NBV 68 159 196 212 313 632 958 1029 Net Book Value |
| Major Growth Projects Update Overland Pass Western Deepwater 40 20 40 Western G&P Expansions Overland Pass NGL Pipeline Deepwater Expansions Development/Proposal Stage 2006 2007 2008 Spending $500-700MM 40% 20% 40% Western Region: Wamsutter Phase II Echo Springs TXP-IV Deepwater: Bass Lite Telemark Pipelines Under Negotiation 2006 2007 2008 Spending $200-300MM Western Deepwater 50 50 50% 50% Opal Blind Faith 30 70 Blind Faith Opal TXP-V Contracted/Approved 2005 2006 2007 Spending $250MM 70% 30% Midstream |
| Wyoming Assets Midstream Drilling Permits By County Sublette - Up 44% in 05 vs 04 Lincoln - Doubled from 03 to 05 Sweetwater - Up 20% 05 vs 04 Wyoming NGL Production - MBPD 2001 2002 2003 2004 61 66 63 74 |
| Proposed Overland Pass Pipeline Midstream Expected NGL Production End of Year 2008 Opal Processing Plant 65-70 MBPD Echo Springs Processing Plant 40-45 MBPD |
| The Midstream Deepwater Gulf of Mexico Story Rory Miller, Vice President Gulf Coast Midstream November 30, 2005 Midstream: Deepwater |
| Why the deepwater Gulf? What about existing deepwater projects? Is the aggregation thesis working? What are the key competencies? Where will growth come from? Overview of Major Sections Midstream: Deepwater |
| 0 1,000 2,000 3,000 4,000 5,000 6,000 1990 1992 1994 1996 1998 2000 2002 2004 BCF Shelf Deepwater *2004 - Some production lost due to Hurricane Ivan +40% - -35% Gulf of Mexico Annual Gas Production Midstream: Deepwater |
| 0 100 200 300 400 500 600 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 MMBO Shelf Deepwater *2004 - Some production lost due to Hurricane Ivan - -26% +28% Gulf of Mexico Annual Oil Production Midstream: Deepwater |
| * MMS 2003 Assessment, P-mean values Estimated Undiscovered Oil & Gas Reserves Midstream: Deepwater |
| Worldwide Undiscovered Resources Regions 3 - Region 8 Onshore Offshore Oil 24 76 Onshore Offshore Gas 27 73 USGS Study - Proportions of onshore and offshore assessed undiscovered resources for the world excluding regions identified as OPEC and Former Soviet Union. Onshore Offshore Midstream: Deepwater |
| Gulf of Mexico - Western Gulf Area Midstream: Deepwater |
| Gulf of Mexico - Discovery Area Midstream: Deepwater |
| Gulf of Mexico - Eastern Gulf Area Midstream: Deepwater |
| The Architecture of Aggregation Midstream: Deepwater |
| Aggregation: Reducing Risk Floating Production System Processing Capacity vs. Time 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Year Processing Capacity (BOE/Day) Expanded Processing Capacity Initial Processing Capacity Top End Risk Back End Risk Production Forecast Producers toll across floating production systems and export systems Lower tolls due to economies of scale Williams assumes aggregation risks; lower than sum of individual risks Reduces cycle time and economic threshold for marginal prospects Midstream: Deepwater |
| East Breaks: Initial Justification 4 discoveries at time of sanctioning Original reserve forecast (P50) provides return of capital (to small single digit returns on capital) Initial justification: 1999 - 2000 Midstream: Deepwater |
| 12 discoveries in dedicated area today Additional undedicated discovery in area 3 - 5 additional exploration wells planned next year Pipeline well situated for Alaminos Canyon development Earning a return in excess of cost of capital East Breaks: Today and the Future Midstream: Deepwater |
| Devils Tower: Today and the Future 59% contracted 5% in negotations 36% uncontracted Midstream: Deepwater |
| Leadership Structural Engineering SCR Design/Verification Topsides Hull & Mooring Hydraulics Cost Estimating Project Management Commercial Expertise Deepwater Operations Building Our Deepwater Competencies Midstream: Deepwater |
| Our Strategy Highlights Deliver safe, reliable, efficient service Pursue only when scale and scope warrant Understand the basin before pricing the business Build competencies specific to deepwater infrastructure Projects require high trust, transparent negotiations Grow business based on attraction rather than promotion Midstream: Deepwater |
| Deepwater Expansion Projects Tahiti 16" Gas Pipeline Discovery system offshore interconnect 34 Mile length; approx. $60 - $70MM capital expenditure Completion est. Q3 2007 Blind Faith 16" Oil & Gas Pipelines Tie-in point to Mountaineer & Canyon Chief tails 37 mile length; $177 MM capital expenditure Completion est. Q3 2007 Triton-Goldfinger Devils Tower Tie-back Dominion & Pioneer joint project No additional capital expenditure for Midstream Initial delivery 11/16/05 New Deepwater Projects currently under negotiation $550 million of pipeline projects to be awarded in the market in the next 6 months Numerous floating production system investment opportunities over next several years (approximately $250-350MM each) Midstream well positioned to win these projects Midstream: Deepwater |
| Questions? Midstream: Deepwater |
| Dissecting Midstream's Earnings Dave Darcey Director of Planning and Analysis Midstream November 30, 2005 Midstream: Earnings |
| Dissecting Midstream's Earnings Breakdown of Midstream's segment profit by asset Overview of Midstream's Gathering & Processing (G&P) operations and impact upon the financials Frac Spread 101, Net Liquid Margin 101 Deciphering Midstream's net liquid margins Can Midstream make money in today's commodity price environment? Impact of changing net liquid margins upon Midstream's earnings The stability of Midstream's G&P fee revenues Midstream: Earnings |
| Segment Profit** **Excludes Allocated G&A Midstream Segment Profit Breakdown - YTD Sept 2005 G&P Western Region Gulf Coast Olefins Venezuela Other EBITDA 0.55 0.19 0.05 0.18 0.03 Domestic G&P is 74% of total Midstream: Earnings |
| Dissecting Midstream's Earnings Breakdown of Midstream's segment profit by asset Overview of Midstream's Gathering & Processing (G&P) operations and impact upon the financials Frac Spread 101, Net Liquid Margin 101 Deciphering Midstream's net liquid margins Can Midstream make money in today's commodity price environment? Impact of changing net liquid margins upon Midstream's earnings The stability of Midstream's G&P fee revenues Midstream: Earnings |
| What Do G&P Operations Look Like? NGL Line Gathering & Compression 419 MMcfd (465 BBtud) Residue Gas to Interstate Pipelines 348 MMcfd NGL Production to NGL Lines 28 MBpd Total 16 MBpd Customers 12 MBpd Williams Processing for a Fee 222 MMcfd (249 BBtud) Processing for Liquids 190 MMcfd Processing Inlet 412 MMcfd Echo Springs Processing Plant Midstream: Earnings |
| NGL Line Linking G&P Operations to Financials Gathering & Compression 419 MMcfd (43 TBtu) Residue Gas to Interstate Pipelines 348 MMcfd NGL Production to NGL Lines 28 MBpd Total 16 MBpd Customers 12 MBpd Williams Processing for a Fee 222 MMcfd Processing for Liquids 190 MMcfd Processing Inlet 412 MMcfd Echo Springs Processing Plant Midstream: Earnings |
| NGL Line Linking G&P Operations to Financials Gathering & Compression 419 MMcfd Residue Gas to Interstate Pipelines 348 MMcfd NGL Production to NGL Lines 28 MBpd 16 MBpd Customers 12 MBpd Williams Processing for a Fee 222 MMcfd (22.9 TBtu) Processing for Liquids 190 MMcfd Echo Springs Processing Plant Processing Inlet 412 MMcfd Midstream: Earnings |
| NGL Line Linking G&P Operations to the Financials Gathering & Compression 419 MMcfd Residue Gas to Interstate Pipelines 348 MMcfd NGL Production 28 MBpd Total 16 MBpd Customers 12 MBpd (45 MM gallons) Williams Processing for a Fee 222 MMcfd Processing for Liquids 190 MMcfd Processing Inlet 412 MMcfd Echo Springs Processing Plant Midstream: Earnings |
| Dissecting Midstream's Earnings Breakdown of Midstream's segment profit by asset Overview of Midstream's Gathering & Processing (G&P) operations and impact upon the financials Frac Spread 101, Net Liquid Margin 101 Deciphering Midstream's net liquid margins Can Midstream make money in today's commodity price environment? Impact of changing net liquid margins upon Midstream's earnings The stability of Midstream's G&P fee revenues Midstream: Earnings |
| So, Which Commodity is the Most Valuable? Commodity Prices in Absolute Terms Ethane Propane Butane Natural Gasoline 35 32 20 13 NGL Barrel Composition 35% 13% 20% 32% Midstream: Earnings |
| The NGL Barrel Is the Most Valuable Commodity Prices Stated in $ / MMBTU Midstream: Earnings |
| Calculating Frac Spreads and Net Liquid Margins Midstream: Earnings |
| Dissecting Midstream's Earnings Breakdown of Midstream's segment profit by asset Overview of Midstream's Gathering & Processing (G&P) operations and impact upon the financials Frac Spread 101, Net Liquid Margin 101 Deciphering Midstream's net liquid margins Can Midstream make money in today's commodity price environment? Impact of changing net liquid margins upon Midstream's earnings The stability of Midstream's G&P fee revenues Midstream: Earnings |
| Western Region NGL Sales $182.1 MM NGL Cost of Goods Sold $134.7 MM NGL Equity Sales 208 MM gallons NGL Margin $.23 / gallon Gulf Coast Region NGL Sales $62.1 MM NGL Cost of Goods Sold $54.9 MM NGL Equity Sales 68 MM gallons NGL Margin $.11 / gallon Midstream Domestic NGL Sales $244.2 MM NGL Cost of Goods Sold $189.6 MM NGL Equity Sales 276.4 MM gallons NGL Margin $.1976 / gallon NGL Cost of Goods Sold include Shrink, Fuel and Trans & Frac Charges Where Are NGL Margin Components On Midstream's Financials? Midstream: Earnings |
| Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Average Realized Margin shown for 2000-04. Margins Above Average Domestic NGL Average Realized Net Margin and Volumes by Quarter Margin (Cents / Gallon) Total Production & Equity Volumes by Quarter (MM Gallons) Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Avg. Realized Margin Midstream: Earnings From 3Q 2005 Analyst Presentation |
| Gas Processing & Treatment Plants Gathering Areas Opal Ignacio Echo Springs Kutz Lybrook Markham Cameron Mobile Bay Midstream's Sept 2005/YTD 2005 NGL Margin by Region Midstream Domestic Average 15.7 cents / gallon Western Region 17.8 cents / gallon Gulf Coast Region 11.3 cents / gallon Midstream: Earnings |
| Opal Ignacio Echo Springs Kutz Lybrook Markham Cameron Mobile Bay Gulf Coast Region NGL Sales = 78.3 cents per gallon Fuel & Shrink Cost = 62.0 cents per gallon Shrink Cost = $7.00 / MMBtu Midstream Domestic Average NGL Sales = 76.6 cents / gallon Fuel & Shrink Cost = 54.0 cents / gallon Shrink Cost = $6.28 / MMBtu Western Region NGL Sales = 75.8 cents / gallon Fuel & Shrink Cost = 50.0 cents / gallon Shrink Cost = $5.93 / MMBtu Western Region Gulf Region 684 328 Midstream's Sept 2005/YTD 2005 NGL Margin Components Gas Processing & Treatment Plants Gathering Areas Midstream: Earnings |
| 1Q'99 2Q'99 3Q'99 4Q'99 1Q'00 2Q'00 3Q'00 4Q'00 1Q'01 2Q'01 3Q'01 4Q'01 1Q'02 2Q'02 3Q'02 4Q'02 1Q'03 2Q'03 3Q'03 4Q'03 1Q'04 2Q'04 3Q'04 4Q'04 1Q'05 2Q'05 3Q'05 September Henry Hub 1.8 2.2 2.55 2.45 2.61 3.63 4.48 6.41 6.42 4.38 2.76 2.39 2.53 2.39 3.2 4.24 6.29 5.61 4.87 5.06 5.61 6.08 5.44 6.26 6.39 6.96 9.71 13.36 San Juan 1.62 1.86 2.31 2.43 2.3 3.13 3.69 4.98 6.62 4.01 2.33 2.04 2.12 2.04 2.49 3.11 4.38 4.15 4.39 4.57 4.99 5.22 4.88 5.51 5.69 6.17 7.71 10.27 Rockies 1.62 1.96 2.21 2.33 2.39 3.17 3.57 5.99 6.12 3.47 2.15 2.06 2.24 2.06 1.26 2.76 3.95 4.17 4.34 4.53 4.95 5.13 4.83 5.57 5.71 5.93 7.32 10.37 September Average First of Month Gas Prices by Region Regional Gas Basis Differentials Bolster Our Diversified Portfolio Midstream: Earnings |
| Dissecting Midstream's Earnings Breakdown of Midstream's segment profit by asset Overview of Midstream's Gathering & Processing (G&P) operations and impact upon the financials Frac Spread 101, Net Liquid Margin 101 Deciphering Midstream's net liquid margins Can Midstream make money in today's commodity price environment? Impact of changing net liquid margins upon Midstream's earnings The stability of Midstream's G&P fee revenues Midstream: Earnings |
| Can Midstream Make $$ With Current Commodity Prices? Q1 2004 Q2 2004 Q3 2004 Q4 2004 Q1 2005 Q2 2005 Q3 2005 Oil 35.15 38.32 43.88 48.28 49.84 53.17 65.02 NGL Barrel 26 26.5 31.23 34.6 32.15 32.72 39.78 Gas - Henry 5.61 6.08 5.44 6.26 6.39 6.96 9.71 Gas - Opal 4.97 5.13 4.83 5.57 5.71 5.93 7.32 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr East 20.4 27.4 90 20.4 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 Q1 2004 Q2 2004 Q3 2004 Q4 2004 Q1 2005 Q2 2005 Q3 2005 Realized Margin 9.84 9.41 17.73 23.09 15.02 13.42 20.39 Realized Margin - West 10.49 9.7 17.97 24.8 16.8 14.5 22.85 Realized Margin - GC 8.79 6.24 17.46 19.39 11.77 11.4 12.17 Q1 2004 Q2 2004 Q3 2004 Q4 2004 Q1 2005 Q2 2005 Q3 2005 Realized Margin 33 29 65 91 60 45 55 Realized Margin - West 22 23 45 65 43 31 47 Realized Margin - GC 11 6 20 26 17 14 7 Q1 2004 Q2 2004 Q3 2004 Q4 2004 Q1 2005 Q2 2005 Q3 2005 Oil 6.05 6.6 7.56 8.32 8.6 9.16 11.21 NGL Barrel 7.16 7.32 8.6 9.53 8.86 9.02 10.96 Gas - Henry 5.61 6.08 5.44 6.26 6.39 6.96 9.71 Gas - Opal 4.97 5.13 4.83 5.57 5.71 5.93 7.32 Midstream: Earnings |
| Five Years of Historical NGL Margins 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr East 20.4 27.4 90 20.4 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 2000 2001 2002 2003 2004 YTD 2005 Annual Avg Margin 15 7.3 9 11 15 15.7 2000 - 2004 5 Yr Avg 11.4 11.4 11.4 11.4 11.4 11.4 Midstream: Earnings |
| YTD Sept 2005 Net Revenues with Actual NGL Margins Gathering, Compression & Treating Fees Fee Proc. Storage & Trans. Fee Olefins Margins NGL Margins Other Revenue 2003 0.48 0.12 0.06 0.07 0.21 0.06 Gathering, Compression & Treating Fees Fee Proc. Storage & Trans. Fee Olefins Margins NGL Margins Other Revenue 2003 0.54 0.14 0.05 0.08 0.16 0.03 Net Revenues w/Historical 5 Yr Avg** NGL Margins Net Revenues w/Lowest Annual Avg NGL Margins in Historical 5 Years Impact of Changing NGL Margins On Midstream's Net Revenues Gathering, Compression & Treating Fees Fee Proc. Storage & Trans. Fee Olefins Margins NGL Margins Other Revenue 2003 0.57 0.15 0.05 0.08 0.11 0.03 ** 5 Yr avg based on 2000-04 Midstream: Earnings |
| Dissecting Midstream's Earnings Breakdown of Midstream's segment profit by asset Overview of Midstream's Gathering & Processing (G&P) operations and impact upon the financials Frac Spread 101, Net Liquid Margin 101 Deciphering Midstream's net liquid margins Can Midstream make money in today's commodity price environment? Impact of changing net liquid margins upon Midstream's earnings The stability of Midstream's G&P fee revenues Midstream: Earnings |
| The Stability of Midstream's G&P Fee Revenues Q1 2003 Q2 2003 Q3 2003 Q4 2003 Q1 2004 Q2 2004 Q3 2004 Q4 2004 Q1 2005 Q2 2005 Q3 2005 G&P Fee Revenue 99 106 95 95 91 91 94 98 94 98 99 Well Connect Capex 6 6 6 6 9 9 9 9 11 9 12 Q1 2003 Q2 2003 Q3 2003 Q4 2003 Q1 2004 Q2 2004 Q3 2004 Q4 2004 Q1 2005 Q2 2005 Q3 2005 Gathering Volumes 325 321 311 313 307 308 315 321 315 323 310 Processing Volumes 164 153 195 183 176 184 195 212 181 185 191 Avg Gathering Rate 0.23 0.25 0.23 0.23 0.23 0.226 0.226 0.231 0.224 0.23 0.239 Avg Processing Rate 0.145 0.16 0.118 0.125 0.122 0.117 0.119 0.115 0.13 0.131 0.134 Midstream: Earnings |
| A Typical Western Region Well Connect... Is the result of long-term contractual obligations and dedications Typically costs $45k to $80k Flows between 350-650 MMBtu / day in 1st year Flows approximately 0.8-1.4 TBtu over the first 10 years Provides a combined G&P revenue stream: Between $45k and $70k in 1st year Declines 6-14% / year thereafter Is contractually covered if well doesn't flow to expectations Midstream: Earnings |
| Midstream Conclusion & Wrap Up Alan Armstrong Senior Vice President, Midstream November 30, 2005 |
| Summary of Key Points Well-positioned, large-scale Midstream infrastructure produces EVA(r) and strong net cash flows Williams has created and maintains competitive advantages Base is strong, poised for growth via expansion of existing platform Williams Partners is great complement to our scale-based strategy Deepwater Gulf of Mexico is an emerging but important infrastructure play Midstream business benefits from geographic and contractual diversity Midstream |
| Power Overview and 2005 Highlights Bill Hobbs Senior Vice President, Power November 30, 2005 Power |
| Agenda Power overview and 2005 highlights Bill Hobbs Market fundamentals Phil Scalzo Financial review Andrew Sunderman Conclusion and Wrap Up Bill Hobbs Q&A Power |
| New Power Contracts - 2005 Highlights Deals consummated around each toll All customer classes have been represented Utilities Co-ops and munis Hedge funds and banks Favorable credit terms Zero margining provisions in two deals in excess of 4 years Margin caps in place for approx. 2,000 MW of toll resale Lower margining agreements and netting will result in lower liquidity needs 3Q05 Earnings Call Power |
| Structured Deals More Efficient than OTC Hedges Structured deals are... Customer-specific customized products More reflective of hourly production rates Priced to provide economic value and/or risk reduction Extremely efficient mechanism for hedging commodity price exposure Recent toll resale in West significantly reduces future liquidity volatility versus standard OTC/NYMEX products Recent CLECO contract has zero collateral requirements, significantly reducing future liquidity volatility versus standard OTC/NYMEX products A more effective hedge for less-liquid commodities (e.g., capacity and ancillary services) Power |
| 2005 Successes West 1,500 MW resale of tolling from AES 4000: 854 MW starting in 2006 and growing to 1,500 MW in 2007-10 490-MW resale of toll from AES 4000 for 2006-08 100-MW heat rate call option for 2008 690-MW capacity sales: from AES 4000 for June-Sept 2005 Mid-Continent 500-MW heat rate-priced energy and capacity sale to CLECO utility starting in 2006-09 100-MW heat-rate call option for 5 years - 2009 (Kinder toll) 244-MW (max) block heat rate-priced energy sale for June-Sept 2005 Northeast 100-MW capacity sale from Ironwood to municipality for June 2005-May 2006 1,000 MW of heat-rate call options sold through 2006 Updated 3Q '05 Earnings Call Power |
| Power Positions and Other Williams Assets AES 4000 Hazleton AES Red Oak AES Ironwood Kinder Morgan Jackson Tenaska Lindsay Hill Cleco Evangeline Milagro Power |
| Power Power Overview November 30, 2005 |
| Total volumes marketed (as of November 1, 2005) Transportation Storage - 6.4 Bcf at Clay Basin Power Markets E&P Gas MMBtu/d Piceance Basin 465,000 San Juan Basin 167,000 Powder River 125,000 Arkoma 15,000 Green River 12,000 Total 735,800 MMBtu/d Colorado Interstate Gas Co. 359,000 Wyoming Interstate Pipeline 353,000 Trailblazer Pipeline 202,000 Transcolorado Gas Transmission 195,000 Northwest Pipeline 50,000 Questar Pipeline 30,000 Transwestern Pipeline 25,000 Total 1,214,000 Fort Worth Basin 1,800 Power |
| Power Manages Midstream Fuel Requirements Supply fuel and shrink Transportation Mobile Bay MMBtu/d 362,250 MMBtu/d San Juan (includes X-haul) 240,000 Rockies 176,000 Gulf Coast 130,000 Canada 50,000 Total 596,000 Power |
| State of the Power Industry Spark spreads have bottomed out and are improving High gas prices favor coal and nuclear generation Regulatory environment stabilizing Market liquidity improving Economy continues to improve New builds of power plants have slowed dramatically Energy merchant sector remains troubled Power |
| Key Issues and Mitigating Factors Future structured deals Improving spark spreads Tail risk Growing demand for electricity Declining reserve margins Increasing natural gas prices Improving WMB credit and liquidity Customer net-outs Open lines increasing Williams' credit Actively managing credit risk Part of an integrated energy company with long-term contracts Financial woes of industry participants Significant progress has been made Unresolved litigation Issue Mitigating Factors Power |
| Power: Market Fundamentals Market Fundamentals Phillip Scalzo Vice President, Power November 30, 2005 |
| Energy Generation by Technology Power Industry History Evolving Domestic Electric Generation Supply Generating Capacity by Fuel 1960 1975 1985 1995 2005 2015 Fossil/Steam/Other Combined Cycle Hydro Nuclear Integrated Gasified Combined Cycle 1960 1975 1985 1995 2005 2015 Other Petroleum Gas Coal Water Nuclear Load Energy Policy Act 1992 Open access Retail deregulation initiatives Merchant power added 200 GW of natural gas combined-cycle Nuclear program Oil embargo Demand growth Pipeline expansion Three Mile Island Gas Policy Act PURPA 78 (81) Demand growth "Green power" technology Combined-cycle advancement Energy Policy Act 2005 State/regional regulatory policy New environmental regulations Explosive global Btu consumption Supply and demand shake-out Explosive gas prices Enron California Investigations Emergence of coal Power: Market Fundamentals Source: Global Energy Decisions; Company Analysis |
| Reserve margins are tightening making Power generation more valuable Energy Policy Act of 2005 Encourages spending on new energy infrastructure Bolsters FERC authority State/Regional Regulatory Policy Capacity markets are developing RTO-lite organizations emerging as alternative to full RTOs New Environmental Regulations CAIR/CAMR encouraging large industry spend to retrofit for further reduction in SO2 and NOx Carbon policy to be determined Global Btu Demand Global commodity markets are more connected than ever Domestic LNG deliveries will fall short Supply/Demand Shakeout Resilient economy chipping away at surplus generation Next build will be slower and more expensive New Entrants and Competitors Financial participates providing liquidity Unprecedented high commodity prices highlight need for providers of risk management services Customer need for risk management services - back to our basics External drivers setting stage for next cycle Uplift to existing generation Effect on Williams Power Company Gradual improvement to route-to-market Increased cost to competitors with no material cost to Power Electric prices will track gas prices in regions where gas is on-the-margin Power: Market Fundamentals Externalities Influencing Sector |
| Clean Air Intrastate Rule (CAIR) issued by EPA on March 10, 2005 Mandatory reductions of Sulfur (SO2) and Nitrogen Oxides (NOx) SO2 targeted reductions of 50% by 2010 and 65% by 2015 NOx reductions of 60% by 2015 Will require retrofit of coal-fired generation facilities Clean Air Mercury Rule (CAMR) issued by EPA on March 15, 2005 First ever federally mandated requirements that coal-fired electric utilities reduce emissions of mercury (Hg) Establishes standards of performance limiting mercury emissions from new and existing coal-fired power plants Regional Green House Gas Initiative (RGGI) submitted to governors August 25, 2005 Cooperative effort by nine Northeastern and Mid-Atlantic states to reduce carbon dioxide CO2 emissions Establishes market-based cap-and-trade program for states to meet C02 budgets SO2 Retrofit Cost New environmental regulations will change the landscape of the power industry Power Fleet Existing Environmental Exposure None -- Natural Gas fired plants don't emit sulfur Hg Retrofit Cost NOx Retrofit Cost CO2 Retrofit Cost No direct exposure on tolls as risk allocated to plant owner; indirect exposure due to potential reduced availability* None - Natural gas fired plants don't emit mercury Dependant on nature of rules implemented* - if like existing NOx rules, risk allocated to plant owner under tolls ? * Williams retains environmental exposure of owned assets - Hazelton (150 MW) and Milagro (60 MW). Hazelton is located in a CAIR state and may be required to reduce NOx emissions or purchase emission credits. Power: Market Fundamentals New Environmental Regulations |
| Announced Environmental Spend Regulated Utilities AEP: $3.7 billion by 2010 Southern: $6.0 billion by 2015 Cinergy: $1.8 billion by 2009 Ameren: $0. 6 - 1.8 billion by 2009 Merchant Generators To date, largely silent US Coal Fired Generation Coal Generators' Environmental Spend Of the 317 GW of coal-fired generation in the U.S. only 30% have any form of S02 control Assuming $140-$240/kW, scrubber retrofit will cost coal-fired generators $13-$23 billion* Assuming scrubber retrofit cost $140-240 per kW; estimates of SO2 control cost from Southern Company's 2005 Analyst Meeting presentation material; March 16-17 2005 The cost of complying with new environmental regulations should increase the value of Williams gas-fired generation fleet Source: Global Energy Decisions CAIR States Power: Market Fundamentals |
| Domestic Incremental Coal Generation Capacity By Status 2 4 6 8 10 12 14 16 18 20 22 1940 1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 GW Feasibility Proposed App Pending Permitted Under Const Operating 2006-2015 60 GW Feasibility 3 Under Const 6 Permitted 10 App Pending 15 Proposed 26 Source: Global Energy Decisions Power: Market Fundamentals |
| Source: Global Energy Decisions Time Line 8-10 years: Proposed (~5%) Feasibility (~10%) 7 years: Application Pending (~30%) 5 years: Permitted (~50%) Under Const. (<100%) Power: Market Fundamentals Proposed Coal Plant Additions |
| Domestic Net Generation Additions, 1960-2015 With the long lead time and environmental hurdles of coal and nuclear generation, excess gas-fired generation utilization must increase Supply/Demand Shake-out Working Off the Excess Source: Global Energy Decisions Notes: As of September 2005, equilibrium need assumes no retirements and a 15% reserve requirement Beyond 2005, additions assume only generation which is currently under construction. 1970's Renewable 1% Nuclear 13% Coal 43% Gas 18% Water 14% 1960's Nuclear 2% Petro 9% Renewable 1% Water 21% Gas 23% Coal 44% Petro 11% 1980's Petro 0% Renewable 4% Gas 8% Water 15% Nuclear 32% Coal 41% 1990's Nuclear 1% Coal 11% Petro 2% Gas 67% Renewable 5% Water 14% 2000's Gas 93% Water 2% Coal 1% Renewable 3% Petro 1% - - 10 20 30 40 50 60 70 80 1960 1961 1962 1963 1964 1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 GW's Equilibrium Need Not all MWs are created the same Power: Market Fundamentals |
| Power Plant Technology Costs Coal and nuclear, while seemingly good alternatives to high natural gas prices, require large capital investments and long lead times Assumes: Coal at $60/ton, NG at $10.00 and 5.00/MMBtu, NOx at $3,000/ton, and SO2 at $1,000/ton Technology: Development Time: High Gas Low Gas Capital Cost ($/kW) Production Cost ($/MWh) Power: Market Fundamentals |
| Macro economics drive shape and magnitude of power demand curve Power: Market Fundamentals Hours in Year GW PJM Mid-Atlantic 2010 70 80 6,129 6,512 6,895 7,278 7,661 8,044 8,427 Intermediate Load Base Load 3,065 3,448 3,831 4,214 4,597 4,980 5,363 5,746 Peaking 0 10 20 30 40 50 60 1 384 767 1,150 1,533 1,916 2,299 2,682 Load Duration Curve Source: PJM and Company Analysis |
| Production cost key determinates: Supply Stack - A region's total cumulative available generating capacity sorted from lowest to highest according to production cost $/MWh Cumulative System Capacity in GW PJM Mid-Atlantic (2005) Power: Market Fundamentals Fuel prices Emission prices Technology Other variables Production Cost: "The Supply Stack" Source: Global Energy Decisions; Company Analysis |
| Key Determinates: System load (demand) Weather Delivered fuel price Emission prices Supply (outages) Transmission import capability Marginal Clearing Price - the price at which the least costly unit can satisfy system's load $/MWh Daily Load $33 $115 $70 Cumulative System Capacity in GW PJM Mid-Atlantic (2005) Power: Market Fundamentals Short-Term Electricity Prices Source: Global Energy Decisions; Company Analysis |
| Key Determinates: System load Delivered fuel prices Regulatory & environmental policy Generation supply New technology Load growth will increase the utilization of combined-cycle gas-fired units $/MWh Cumulative System Capacity in GW Fuel Prices Hydro: Renewable: Nuclear: Coal: NG ($/MMBtu): Oil ($/Gallon): Emission Prices NOx ($/ton): S02 ($/ton): C02 ($/ton): ~$0 ~$0 $60 $13 $1.70 $3,000 $1,000 $0 $6 $1.20 PJM Mid-Atlantic Combined-Cycle 2010 Power: Market Fundamentals Long-Term Electricity Prices Source: Global Energy Decisions; Company Analysis |
| High Gas > $7.00 Moderate Gas $5.00 - $7.00 Low Gas < $5.00 Onerous New Environmental Regulations Future Gen (Hydrogen) Renewables (Wind, Biomass) Large-scale transmission build-out IGCC with CO2 sequestration Retrofit existing PCs (with BACT) for CO2 capture of sequestration. NG CC with BACT and CO2 sequestration Current / Contemplated Environmental Regulations IGCC with CO2 Retrofit existing PC with BACT Renewables/Biomass Gasification/LNG Existing transmission reinforcement Compliance coal NG CC with BACT Relaxed Environmental Regulations Unscrubbed PC life extension IGCC without CO2 New PC with BACT PC life extension with BACT Work off excess CC capacity Stall new generation additions New conventional NGCC as required Extend life of old, inefficient PCs Long-Term Gas View Long Term Environmental View New Technology Focus Optimization and arbitrage focus with existing technology implementation Status quo - existing portfolio harvest BACT - Best Available Control Technology IGCC - Integrated Gasification Combined Cycle CC - Combined Cycle Plant PC - Pulverized Coal Plants Long-term fundamental view drives investments Power: Market Fundamentals Sector Long-Term Investment Alternatives |
| Power: Regional Review Regional Review November 30, 2005 |
| In-city generation Highly hedged while retaining upside potential California likely to introduce capacity market in 2007 Tolling agreement provides Williams with re-power rights Market for Williams' E&P gas Reserve margins tight and expected to compress further 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 Resale of Toll: 490 MW Through 2008 Resale of Toll: 854-1,500 MW Through 2010 Power: Regional Review West |
| Positioned in most-developed competitive markets in U.S. New PJM demand-curve-style (NYISO like) capacity market implementation likely in 2007 Neptune undersea transmission line will improve Red Oak's route to premium New York market COD expected by summer of 2007 Path from Sayerville, NJ (Red Oak) to Long Island, NY Reserve margins tight and continuing to compress Full Requirements: Allegheny Electric Co-op 515-600 MW Through 2008 Tolling: Red Oak 766 MW Through 2022 Owned: Hazleton 147 MW Natural gas-fired Tolling: Ironwood 666 MW Through 2021 Power: Regional Review Northeast |
| Tolling: Jackson 541 MW Through 2018 Evangeline Toll is highly hedged Transmission constrained area provides opportunities for premium pricing Expected improvements in route to market: Entergy's Independent Coordinator Hurricanes may result in improvements to transmission infrastructure Regional reserve margins remain high Tolling: Evangeline 765 MW Through 2020 Forward Heat Rate Sale: 500 MW Through 2009 Jackson MISO market implemented in April, resulting in immediate improvement to Jackson's dispatch utilization Reserve margins beginning to tighten Power: Regional Review Mid-Continent and South Central |
| Materially hedged with full-requirements load contracts Southern reserve margins remain high Benefiting supply obligations for EMC's Full Requirements: Four Georgia EMCs 600-1,500 MW Through 2015 Tolling: Lindsay Hill 844 MW Through 2020 Power: Regional Review Southeast |
| 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 California Northeast Mid-Continent Southeast South Central Equilibrium in most markets by 2010 Source: Energy Velocity (EV) and Company Analysis; Generation supply assumes 100% for Under Construction and Testing, for Proposed, Permitted, App Pending and Feasibility assumes 50%. Load projections are provided by EV and represent a ISO/NERC projections where available and EV forecast otherwise. EV load forecast only extend through 2013, values for subsequent years were extrapolated based on holding generation capacity and 2013 load growth rate constant. Targeted Region Williams Generation Fleet 2005 2010 2015 Reserve Margin Califorinia AES 4000 12.0% 12.1% 2.8% 15-17% Northeast Red Oak, Ironwood, & Hazelton 16.2% 9.9% 1.4% 15% Mid-Continent Jackson 22.8% 17.4% 9.0% 15-17% Southeast Lindsay Hill 37.2% 25.1% 9.5% 15-17% South Central * Evangeline 85.6% 82.9% 66.7% 15-17% Estimated Reserve Margins * Represents Entergy NERC sub region, localized reserve margins in CLECO Evangeline's market are much tighter and transmission constrained. Power Market Recovery Timeline Power: Regional Review Supply/Demand Shakeout |
| Not all megawatts are created equal Power plants are dispatched based on relative production costs For non-base-load plants, the relationship between plant utilization rates and profit margins is not linear Coming cycle will see new base-load generation (i.e., coal and nuclear) Regulatory, financing and environmental uncertainties are delaying new additions Long lead time Mid-term fundamentals look good for gas-fired generators Power: Regional Review Key Takeaways |
| Power: Financial Review Financial Review Andrew Sunderman Vice President, Power November 30, 2005 |
| Key Points from 3Q05 Results for 3rd quarter impacted by several uncontrollable issues Mild weather in West Unplanned plant outages in East and West Hurricanes and high natural gas prices CFFO YTD positive Full-year recurring segment profit after adjusting for impact of mark-to-market is nearly break-even despite mild weather and higher gas prices Deal flow has increased Power: Financial Review |
| Williams' Use of Derivatives Williams uses derivatives to hedge its commodity price and basis risks Focus on using effective economic derivatives as hedges that also are effective hedges under FAS 133 Williams accounts for these derivatives under FAS 133 with changes in fair value for effective, designated derivatives being deferred through Other Comprehensive Income (OCI). Changes in the fair value of the ineffective portion of a designated derivative and/or non-designated derivatives go through MTM income. Williams' normal derivative portfolio position is as follows: E&P - short natural gas price positions Power - long natural gas price positions and short power positions Power: Financial Review |
| Williams reported the following changes related to its derivative portfolio: The net change in Derivative Assets and Liabilities for E&P was negative, reflecting the rise in gas prices against a short derivative position. The net change in Derivative Assets and Liabilities for Power was positive, reflecting the increased economic value of the Power derivatives, primarily due to the rise in gas prices against a long derivative position. 3Q Financial Statement Changes for Derivatives Positions Note: Change in OCI is pre-tax and includes only commodity-based changes. Change in Derivative A/L includes only those changes that affect OCI or Income (e.g., not Prepaid Option Premiums). * Income impact in prior period. Power: Financial Review MTM Realized Der A/L OCI G / (L) (G) / L Net Change in Consolidated Derivative Values (538) $ (391) $ (157) $ 10 $ E&P hedges change in Derivative A/L (700) $ - change in OCI - unrealized (771) $ - ineffectiveness booked to MTM (16) $ - realized from OCI to Income 87 $ Power hedges 162 $ - change in OCI - unrealized 380 $ - current period MTM losses (141) $ - previously recognized MTM (60)* $ - realized from OCI to Income (17) $ Balance Sheet Income Statement |
| OK, We See the Overall Economic Change Was Positive... Why Was MTM Negative? During and subsequent to 3Q, Power successfully executed several new structured transactions that provided additional value, added cash flow certainty and reduced future liquidity requirements. Power then needed to reverse prior OTC and NYMEX hedges to ensure it did not find itself in an economic over-hedged position. To do this, Power entered into certain gas sales contracts and power purchase contracts. Certain of these gas sales and power purchase contracts were not designated during 3Q; thus, rising gas prices caused a derivative loss against certain of these trades that was recorded to MTM income. Power: Financial Review |
| Conclusions MTM gains or losses are non-cash in the period recognized The majority of Power's derivatives positions are effective economic hedges Power has consistently presented non-GAAP results after adjusting for MTM changes (gains or losses) to better reflect cash flows and value of the business Continued focus on enhancing communication and transparency Power: Financial Review |
| Changes from Previous Power Update "Resale of Tolling & Heat Rate Option Premiums" represents cash premium to be received Previously, "Resale of Tolling" represented market value of mirror tolls, net of premium "Percentage Capacity Available Hedged" represents contractual MW sales as a percentage of Total Capacity Available Previously, the "Percentage Volume Hedged" represented expected MW sales as a percentage of Expected Output "Other Hedges and Hedged Tolling Revenues" represents the estimated value of the rest of the power hedges (OTC, NYMEX, Long-Term Forward Sales and Full Requirements), including the estimated underlying tolling revenues that have been hedged Previously, each of these categories of hedges was broken out in addition to estimated hedged tolling revenues. Power: Financial Review |
| Undiscounted dollars in millions Note: 3Q05 forecast estimated as of 9/30/05 and includes new CA Resale of Tolling and Cleco Long Term Physical deals completed in 4Q05. 3Q05 actual cash flows agree in total with Power's Cash Flow Statement; however the allocation of actual cash flows to the various deal types is based on estimates. This schedule includes non-recurring items. Power: Financial Review Total Undiscounted Cash Flows Note: Working Capital changes not forecast |
| Variance from Prior Power Update (New Methodology) Total Undiscounted Cash Flows Undiscounted dollars in millions Power: Financial Review Note: Working Capital changes not forecast |
| 2006 2007 Prior Segment Profit Guidance ($270) - (120) ($220) - (70) MTM Earnings (3Q05) Est. Forward MTM Impact 50 40 Chg due to Mkt Conditions, New deals & Other 0 - (50) Total Impact 50 - 0 40 Change in Segment Profit Guidance 50 - 0 40 Segment Profit Guidance (225) - (125) (180) - (30) Estimated MTM Adjustments 270 230 320 270 Reported Segment Profit after MTM Adj 50 - 150 50 - 200 50 - 200 Non-Recurring 0 0 Recurring Segment Profit after MTM Adj 50 - 150 50 - 200 50 - 200 Capital Expenditures - - Dollars in millions 2006-07 Guidance Note: If guidance has changed, previous guidance from 2nd quarter is shown in italics directly below Cash Flow from Operations 50 - 150 0 - 200 3Q05 Earnings Call Power: Financial Review |
| Conclusion & Wrap Up Bill Hobbs Senior Vice President, Power Power |
| Key Points Power's third quarter CFFO YTD remains positive Deal flow has increased Markets are expected to improve throughout guidance period Recently completed deals provide increased value and cash flow certainty Power remains committed to improving transparency around financial performance Power remains focused on reducing risk, creating cash flow certainty and honoring contractual commitments Power |
| Q&A |
| Williams Midstream & Power Update November 30, 2005 |
| Appendix |
| Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation |
| Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation |
| Total NGL Production 152 MBpd Williams' Equity Share 89 MBpd Opal Ignacio Echo Springs Kutz/Lybrook Markham Mobile Bay Total=46 MBpd WMB=38 MBpd Total=28 MBpd WMB=12 MBpd Total=20 MBpd WMB=8 MBpd Total=16 MBpd WMB=3 MBpd Total=17 MBpd WMB=15 MBpd Total=12 MBpd WMB=12 MBpd Total=12 MBpd WMB=2 MBpd Cameron Last Twelve Month Peak Day Production 163 MBpd Midstream's Domestic NGL Production - YTD Sept 2005 Gas Processing & Treatment Plants Gathering Areas Midstream |
| Total Domestic Shrink Requirement 306,628 MMBtu/d Opal Ignacio Echo Springs Kutz/Lybrook Markham Mobile Bay Total=46 MBpd WMB=38 MBpd Total=28 MBpd WMB=12 MBpd Total=20 MBpd WMB=8 MBpd Total=16 MBpd WMB=3 MBpd Total=17 MBpd WMB=15 MBpd Total=12 MBpd WMB=12 MBpd Total=12 MBpd WMB=2 MBpd Cameron Midstream's Domestic NGL Shrink Requirements YTD Sept 2005 Gas Processing & Treatment Plants Gathering Areas Midstream |
| Western Gulf Coast - Key Assets Markham Gas Processing Facility 325mm scf/d capacity 24/7 operation (Manned daylight hours only) Residue delivery to Transco Junction Platform GA A244 24/7 manned operation - 2 individuals 7/7 rotation 20,000 HP of oil pumping capacity into Exxon HOOPS BANJO (Oil) & Seahawk (Gas) Pipelines Export from Boomvang & Nansen Spars 16" Oil line and 18" Gas line Alpine (Oil) Pipeline 18" export from Gunnison Spar Cameron Meadows Gas Processing Facility 500mm scf/d capacity 24/7 operation Residue delivery to Transco/NGL to Dynegy Down due to Hurricane Rita - will resume ~12/15/05 Midstream: Deepwater |
| Discovery - Key Assets Larose Gas Processing Facility 600mm scf/d capacity 24/7 manned operation Residue outlets Tennessee, Columbia, Bridgeline, Transco, TETCO Paradis Fractionator 40,000 bbl/d capacity Purity Products EP, P, I, N, G Truck & Rail loading GI 115 Platform Leased to POGO Deepwater Export Gas P/L Supply Agip - Allegheny and Morpeth Murphy - Front Runner Chevron - Tahiti Numerous additional discoveries/prospects being pursued All Discovery assets are in a partnership (partially MLP) Midstream: Deepwater |
| Eastern Gulf Coast Area - Key Assets Mobile Bay Gas Processing Facility 650mm scf/d capacity 24/7 operation Canyon Station Platform 500mm scf/d capacity Methanol Distillation, Glycol Dehydration & Gas Compression 24/7 operation - 7 individuals 7/7 rotation TFE operates Canyon Express, 2 TFE employees on location Devils Tower Spar Owned by Midstream/Operated by Dominion Midstream maintains 1 employee on location Triton and Goldfinger tied in and flowing as of 11/16/05 Additional gas discovery tie-back dedicated Mountaineer (Oil) Pipeline & Canyon Chief (Gas) Pipeline 18" oil export and 18" gas export from Devils Tower 16" oil and gas lateral from Blind Faith under construction Three additional discoveries under negotiation Carbonate Trend (Offshore gas) Pipeline (MLP Asset) Midstream: Deepwater |
| Note: MTM Adjustments (recurring) excludes $12mm paid in 3Q05 for buyout of gas supply contract Dollars in millions 2005 2004 2005 2004 Gross Margin (Includes MTM) ($203) $131 ($98) $202 SG&A (21) (20) (54) (56) Operating & Other Inc./(Expense) (2) (2) (35) (25) Segment Profit/(Loss) (Includes MTM) (226) 109 (187) 121 MTM Adjustments 201 (142) 149 (87) Segment Profit/(Loss) After MTM Adjustments ($25) ($33) ($38) $34 Segment Profit/(Loss) (Includes MTM) ($226) $109 ($187) $121 Nonrecurring: Expense related to Settlements and Litigation Contingencies 0 0 13 0 Expense related to prior period 0 0 12 0 Recurring Segment Profit/(Loss) (226) 109 (162) 121 MTM Adjustments (recurring) 213 (142) 160 (87) Recurring Segment Profit/(Loss) After MTM Adjustments ($13) ($33) ($2) $34 3rd Qtr YTD 3Q05 Earnings Call Power Segment Profit |
| 1 Includes YTD nonrecurring adjustments which decrease reported Segment Profit by $25 million and reported Segment Profit after MTM Adjustments and CFFO by $37million. Power Segment Profit after MTM Adjustments and Power Segment Standalone CFFO would be $36 million higher on a recurring basis. 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. YTD - Segment Profit to Cash Flow Power and Dollars in Millions Natural Gas Other Total YTD Gross Margin ($98) ($98) SG&A & Other Inc/(Exp) (89) (89) Segment Profit/(Loss) 1 (187) 0 (187) MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (101) (101) Add Realized Gains from MTM previously recognized 250 250 Segment Profit/(Loss) after MTM Adjustments 1 (38) 0 (38) Total Working Capital Change 0 82 82 Power Segment CFFO 1 (38) 82 44 Est. Working Capital Used for Other BU's 0 (39) (39) Power Segment Standalone CFFO ($38) $43 $5 3Q05 Earnings Call Power |
| Dollars in millions Items Impacting 3Q Performance Segment Profit After MTM Adjustments: Q305 Forecast (as of 6/30/05) $54 Estimated impact of mild weather in the West: (30) Cooling Degree Days (CDDs) at Los Angeles (LAX) YTD are 17% below 5 yr avg and 43% below '04 Average September peak load in Cal-ISO system 13% below 2004 Estimated impact of higher NG prices, hurricanes & others (25) Estimated impact of plant outages (12) Buyout of gas supply contract (12) ______ Q305 Segment Profit After MTM Adjustments ($25) 3Q05 Earnings Call Power |
| Cash Flow Analysis Undiscounted dollars in millions (GAAP Measure) Note: 3Q05 forecast estimated as of 12/30/04. 3Q05 actual cash flows agree in total with Power's Cash Flow Statement; however, the allocation of actual cash flows to the various deal types is based on estimates. Note: Estimated Cash Flows includes YTD nonrecurring adjustments which decrease reported cash flows by $36 million. Estimated cash flows would be $36million higher on a recurring basis. Combined Power Portfolio Actual v. Forecast 3Q'05 Q3'05A Q3'05F YTD05A YTD05F Tolling Demand Payment Obligations ($126) ($126) ($310) ($310) Resale of Tolling 34 14 116 87 Full Requirements (6) 0 (1) 6 Long-term Physical Forward Power Sales 3 10 46 54 OTC Hedges 13 4 89 74 Est. Tolling Cash Flows Associated with Hedges 117 165 Estimated Merchant Cash Flows 60 64 Subtotal Cash Flows 7 79 64 142 NG & Other Commodity (8) (6) (13) (7) SG&A and Other (24) (18) (89) (54) Working Capital & Other (15) (7) 82 83 Power segment CFFO (40) 48 44 164 Est. Working Capital Used for Other BU's 16 0 (39) 0 Power Standalone Cash Flows ($24) $48 $5 $164 88 123 3Q05 Earnings Call Power |
| Types of Sales Around Tolling Deals Generally from the Most- to Least-Effective Hedges Type of Sale Resale of tolling Heat-rate sales Full requirements Capacity sales Forward fixed-price sales How It Works Williams buys tolling rights for a certain dollar amount per kilowatt-year and sells the same or similar tolling rights to another party. Example: CDWR Product D Sells call rights on energy, or fixed amounts of energy, at a price determined by a heat rate and fuel price. Serves the load (demand) of an entity often at a fixed price, utilizing production from other Williams assets and/or the entity's resources. Examples: EMC and Allegheny Co-op contracts Sells the right to claim the generation as capacity. Some energy rights are usually associated. Sells fixed blocks of power at a specified price, usually w/o specifying a source. Example: CDWR ABC Power |