Williams Companies, Inc. (the) · NYSE:WMB
Williams Companies, Inc. (the) — Q2 2004 Earnings Presentation
82 slides from Williams Companies, Inc. (the)'s earnings presentation, Aug 5, 2004
Slide 1: Williams Analyst Conference Call 2nd Quarter 2004
Williams Analyst Conference Call 2nd Quarter 2004 August 5, 2004
Slide 2: Forward Looking Statements
Forward Looking Statements Our reports, filings, and other public announcements might contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" with in the meaning of Private Securities Litigation R
Slide 3: 2Q04 Review
2Q04 Review Steve Malcolm, Chairman, President & CEO
Slide 4: Headlines: Williams delivers on restructuring
Headlines Williams delivers on restructuring Balance sheet gets stronger Adequate liquidity continues Debt reduction ramps up; new tender announced today Asset sale program ending Credit-rating agencies take notice Western power issues go away; utilities pay their bill IBM deal helps to lock in G&A
Slide 5: Headlines: Solid 2Q performance
Headlines Williams delivers solid 2Q performance Recurring results see big improvement Gas Pipeline steady Midstream gets boost from new deepwater expansions and strong olefins; increases guidance E&P increases production but lowers 2004 earnings guidance as Costs increase Hedges limit upside Power
Slide 6: Headlines: Poised for post-restructuring growth
Headlines Williams poised for post-restructuring growth, value-creation Natural gas businesses provide organic growth opportunities Investments today preserve, enhance competitive position Drilling activity, production levels both increase Deepwater Gulf infrastructure prime for incremental business
Slide 7: The Road Ahead
Midstream Complete deepwater projects Complete asset sales Maintain competitive position - MLP? Capture our share of new deepwater production 2004 2005 2006 2007 & beyond Gas Pipeline Exploration & Production Corporate Power CORE BUSINESSES The Road Ahead Complete announced expansion projects Northw
Slide 8: Financial Results & 2004 Outlook
Financial Results & 2004 Outlook Don Chappel, CFO
Slide 9: Financial Results
2nd Quarter YTD 2004 2003 2004 2003 Income (Loss) from Continuing Ops.* ($18) $114 ($19) $70 Income (Loss) from Discont. Ops. - 156 11 146 Effect of Accounting Change - - - (761) Net Income/(Loss)* ($18) $270 ($8) ($545) Net Income/(Loss) Share* ($0.03) $0.46 ($0.02) ($1.10) Recurring. Inc./(Loss) f
Slide 10: Recurring Income from Continuing Operations
2004 2003 2004 2003 Income/(Loss) from Cont. Ops. ($18) $114 ($19) $70 Gains on Sale of Assets - (274) - (274) Impairments/Losses/Write-offs 24 137 24 149 Income (Expense) Related to Prior Periods 11 (93) 11 (107) Debt Retirement Expenses 97 - 97 - Other 1 18 8 31 Less: Income Tax Provision 51 (109)
Slide 11: Net Income Components
2004 2003 2004 2003 Segment Profit $305 $636 $571 $880 Net Interest Expense (222) (395) (461) (736) Debt Retirement Expense (97) - (97) - Other Income (Expense) - Net (21) (1) (38) 40 Income/(Loss) from Cont. Ops. Before Tax* (35) 240 (25) 184 Provision (Benefit) for Income Tax (17) 126 (6) 114 Inco
Slide 12: Second Quarter Segment Profit
Second Quarter Segment Profit Reported Recurring 2Q04 2Q03 2Q04 2Q03 Gas Pipeline $133 $116 $142 $142 Exploration & Production(1) 43 179 55 87 Midstream Gas & Liquids 99 45 99 54 $275 $340 $296 $283 Power(2) 45 348 45 93 Other (15) (52) (5) (2) Segment Profit(3) $305 $636 $336 $374 Dollars in millio
Slide 13: YTD Segment Profit
YTD Segment Profit Reported Recurring 2004 2003 2004 2003 Gas Pipeline $280 $266 $289 $292 Exploration & Production(1) 95 293 106 201 Midstream Gas & Liquids 207 157 207 166 $582 $716 $602 $659 Power(2) 12 212 12 (45) Other (23) (48) (5) 3 Segment Profit(3) $571 $880 $609 $617 Dollars in millions (1
Slide 14: Major Changes in Recurring Segment Profit
Recurring Segment Profit 2Q2003 $374 Power (49) - Lower gross margin incl. MTM -$63 million - Reduced SG&A expenses +$12 Midstream 45 - New deepwater assets +$13 million - Higher NGL margins +$13 million - Improved olefins results +17 million Gas Pipeline 0 - New projects added +$13 million - Increa
Slide 15: YTD Cash Information
Beginning Cash @ 12/31/03* $2,318 Cash Flow from Continuing Operations 604 Cash Flow from Discontinued Operations 12 Asset Sales 394 Restricted Investments (LC Collateral) 381 Debt Retirements (2,218) Capital Expenditures/Investments (331) Debt Premiums/Issuance Costs (100) Other-Net (30) Ending Cas
Slide 16: Consolidated 2004 Segment Profit Guidance
Consolidated 2004 Segment Profit Guidance Dollars in millions 2004 Forecast * Midstream excludes Canadian assets sold and reclassified as discontinued operations ** Restated to remove Canadian assets sold and reclassified as discontinued operations *** Power guidance assumes zero 2nd half 2004 mark-
Slide 17: Consolidated 2004 Forecast Guidance
Segment profit $1,100 - $1,400 $1,075 - $1,375 Net Interest Expense (820) - (860) Early Debt Retirement Costs (250) - (200) (225) - (175) Other (Primarily General Corporate Costs) (80) - (125) Pretax Income (Loss) ($50) - $215 Provision (Benefit) for Income Tax 5 - (125) 5 - (105) Income / (Loss) fr
Slide 18: 2004 Forecast EBITDA Reconciliation
2004 Forecast EBITDA Reconciliation Dollars in millions Net Income $115 - $275 Income from Disc. Operations (160) - (185) Net Interest 820 - 860 DD&A 650 - 700 Provision (Benefit) for Income Taxes (5) - 125 Other/Rounding (70) - 25 EBITDA - Reported $1,350 - $1,800 Early Debt Retirement Fees 250 - 2
Slide 19: MLP Direction
MLP Direction Positives Acquisition currency Retain control of assets Additional access to capital markets Added visibility for Midstream business unit valuation Considerations Complicated tax / governance / reporting structure Hurdles due to current financial agreements Ratings agencies neutral to
Slide 20: MLP Initial Scale Considerations
MLP Initial Scale Considerations Starting small Maximum flexibility to make acquisitions and drop-down acquisitions Growth more sustainable starting from a smaller base As GP, Williams incentive distributions increase geometrically as distributable cash flow grows Asset considerations Not all Midstr
Slide 21: Business Unit Results
Business Unit Results
Slide 22: Exploration & Production
Exploration & Production Ralph Hill, Senior Vice President
Slide 23: E&P Second Quarter Accomplishments
Exploration & Production Second Quarter Accomplishments Significant Production Growth Drilling activities increases Shorter Piceance drilling cycle Additional rigs added in San Juan, Arkoma and Powder River Powder River permitting progress Bolt on acquisitions accomplished: Arkoma San Juan Powder Ri
Slide 24: E&P Current and Projected Volumes
Piceance Powder River San Juan Arkoma/Other International Jan. '04 166 121 142 28 41 Jun '04 226 119 143 28 43 Dec. '04 268 119 145 30 44 Exploration & Production Current and Projected Volumes Additional volumes due to drilling efficiencies Previous Estimate
Slide 25: Powder River Basin Big George and Wyodak Coal Fairways
Williams Big George Gross Production Increasing 61.6 MMcfd, 603 wells 100 Miles 60 Miles Wyodak Fairway 743.1 MMcfd* CAMPBELL COUNTY Gillette JOHNSON SHERIDAN Big George Fairway 147.5 MMcfd* * WOGCC Data April 2004 Williams Operated Pilots Scale 0 6 miles Partner Operated Pilots Other Industry Pilot
Slide 26: Piceance Basin Acreage
Exploration & Production Piceance Basin Acreage Denver
Slide 27: E&P 2004 Segment Profit Guidance Revision
2004 Previous Guidance $275 - 300 Revisions: 1) Hedge price impact ( 7) 2) Excess transport ( 15) 3) Higher operating expenses ( 11) 4) Gathering fees/other ( 10) 5) Increased volumes 15 ($28) Non-Recurring ($11) Revised Guidance $235 - 260 Dollars in millions Exploration & Production 2004 Segment P
Slide 28: E&P 2004 Capital Guidance Revision
2004 Previous Guidance $325 - 375 Revisions: 1) Increase in overall drilling program costs 13 2) Additional operated wells drilled 27 3) Additional partner operated wells 11 4) Accelerated plant & compression upgrades 21 Revised Guidance $400 - 450 Dollars in millions Exploration & Production 2004 C
Slide 29: E&P 2004-2006 Guidance
Exploration & Production 2004-2006 Guidance Note: If guidance has changed, previous guidance from 5/6/04 is shown in italics directly below. Economic impact of hedges may be different from the volume hedged due primarily to fuel and shrink and direct taxes 2004 2005 2006 Segment profit $235 - 260 $3
Slide 30: E&P Key Points
Delivering on our volume growth Stepping up development drilling activity Decreasing 2004 segment profit guidance due to "boom" costs and hedged prices Plan based on organic growth from existing positions Investments are short time cycle, fast cash returns High-quality reserve base History of high s
Slide 31: Midstream
Midstream Alan Armstrong, Senior Vice President
Slide 32: Midstream Segment Profit 2Q04 vs. 2Q03
Segment Profit $99 $45 $207 $157 Aux Sable Impairment - 9 - 9 Recurring Segment Profit $99 $54 $207 $166 Dollars in millions Midstream Segment Profit 2Q04 vs. 2Q03 Impact New Deepwater Assets $ +13 Higher NGL Margins +13 Improved Olefins results +17 2nd Quarter YTD 2004 2003 2004 2003
Slide 33: Midstream Second Quarter Accomplishments
Midstream Second Quarter Accomplishments First production on Devils Tower Canadian straddles sale Favorable Gulf Liquids arbitration award Secured Front Runner dedication Federal court remands FERC ruling * Excludes gains/losses/impairments 3Q '02 4Q '02 1Q '03 1Q '04 2Q '03 2Q '04 3Q '03 4Q '03 1Q
Slide 34: Midstream Asset Sale Update
Midstream targeted $500 - 600 MM Canadian straddles yield $536 million cash + $30 million of L.C. capacity South Texas regulated assets - $28 million Yields nearly $600 million Gulf Liquids pending Ethylene distribution system and storage system pending NGL storage assets held back for MLP Midstream
Slide 35: Midstream MLP Discussion Points
Midstream MLP Discussion Points Provides acquisition vehicle for additional scale in Midstream Maintains our competitive advantage in core basins Allows continuing presence in NGL services sector Allows Williams to retain control of assets No negative impact to current earnings guidance
Slide 36: Midstream 2004-2006 Guidance
Midstream 2004-2006 Guidance Dollars in millions 2004 2005 2006 Segment Profit $325-375 $300-400 $350-450 Annual DD&A $170-180 $175-185 $175-185 Capital Spending $90-110 $60-80 $50-70 $275-360 Note: - - Both current & previous guidance excludes results & gains associated with Canada straddle plants
Slide 37: Midstream Key Points
Midstream Key Points Continued strong demand for services in core areas 2Q 2004 performance yields second consecutive increase in guidance Asset sales goals accomplished Deepwater projects adding significant operating profit Reliable operational performance attracting growth around existing assets M
Slide 38: Gas Pipeline
Gas Pipeline Doug Whisenant, Senior Vice President
Slide 39: Gas Pipeline Segment Profit
Gas Pipeline Segment Profit 2nd Quarter YTD 2004 2003 2004 2003 Segment profit $133 $116 $280 $266 Includes: Write-off software project - 26 - 26 Write-off of previously capitalized cost for idled segment 9 - 9 - Recurring Segment Profit $142 $142 $289 $292 2Q04 vs. 2Q03 Incremental projects, $14 mi
Slide 40: Gas Pipeline Second Quarter Accomplishments
Gas Pipeline Second Quarter Accomplishments Began construction of Gulfstream Phase II Assumed operations of Transco production area facilities Began construction of Everett Delta Lateral Partial (131 MDtd) return to service of 26-inch Successful Leidy to Long Island open season 1Q 2Q 3Q 4Q 2002 193.
Slide 41: Gas Pipeline 2004-2006 Guidance
2004 2005 2006 Segment profit $540 - 570* $525 - 575 $525 - 575 Annual DD&A $270 - 280 $280 - 290 $290 - 300 Capital spending $280 - 320 $350 - 400 $450 - 520 Dollars in millions Gas Pipeline 2004-2006 Guidance $335 - 380 $430 - 490 $295 - 340 $525-575 $275-285 * Includes $9 million non-recurring ch
Slide 42: Gas Pipeline 2004-2006 Capital Spending Detail
Gas Pipeline 2004-2006 Capital Spending Detail $450 - 520 $350 - 400 $280 - 320 Total 20 - 30 20 - 30 35 - 45 260 - 300 45 - 55 35 - 45 70 - 75 $140 - 150 $195 - 215 $140 - 155 Normal Maintenance 2006 2005 2004 Dollars in millions $430 - 490 40 - 50 $335 - 380 Clean Air Act NWP 26" Restore/Replace E
Slide 43: Northwest 26-inch Restore-to-Service
Gas Pipeline Northwest 26-inch Restore-to-Service Completed restoration phase Restored 111 miles of 26-inch mainline Represents 131Mdth/d of idled 360 Mdth/d capacity In-service June 22
Slide 44: Northwest 26-inch Capacity Replacement
Gas Pipeline Northwest 26-inch Capacity Replacement Replace 360 MDth/d of capacity Approximately 80 miles of 36" loop; 12,000 hp of compression November 2006 in-service Incorporates 13 MDth/d of capacity relinquished in Reverse Open Season Environmental and permitting work underway Projected cost $3
Slide 45: Transco Leidy to Long Island Expansion
Gas Pipeline Transco Leidy to Long Island Expansion 100 MDtd fully subscribed expansion from the Leidy Hub to Long Island, NY Capital investment ? $150 million Projected in-service date, Nov 2007 Leidy Hub PA NY MD NJ Long Island
Slide 46: Gas Pipeline Key Points
26-inch Return-to-Service complete (June 22) 26-inch Capacity Replacement, 11/06 targeted ISD Expansion projects Central New Jersey Leidy to Long Island Gulfstream Phase II Rate cases effective in 2007 NWP TGPL Gas Pipeline Key Points
Slide 47: Power
Power Bill Hobbs, Senior Vice President
Slide 48: Power Segment Profit
2nd Quarter YTD 2004 2003 2004 2003 Power Segment Profit Dollars in millions Gross Margin $72 $228 $71 $138 SG&A (20) (44) (36) (81) Op. Exp. & Other Inc / (Exp) (7) 164 (23) 155 Reported Segment Profit $45 $348 $12 $212 Includes: Regulatory Settlement - 20 - 20 Prior period correction* - (93) - (10
Slide 49: Power Second Quarter / Recent Accomplishments
Portfolio cash flows consistent with forecast in Power Tutorial Portfolio volumes up more than 70% Portfolio cash flow up more than $60 million Held Power tutorial on June 17 Western power issues resolved February 25 settlement with three California utilities FERC approved settlement on July 2 Willi
Slide 50: Power Undiscounted Cash Flows Variance Analysis
Power Undiscounted Cash Flows Variance Analysis 4Q03 4Q02 2003 2002 Dollars in millions Dollars in millions * Forecast included in Power Tutorial held 6/17/04
Slide 51: Power Segment CFFO
Power Power Segment CFFO * "Other BU Working Capital" relates to other business units but is managed by the Power Business Unit. Actual Forecast 3Q & 4Q 1Q2004 2Q2004 YTD 2004 2004 2004 Power Portfolio 6 19 25 35-65 60-90 Storage & Legacy 75 (33) 42 (82)-(52) (40)-(10) 81 (14) 67 (47)-13 20-80 Other
Slide 52: Segment Profit to Cash Flow
Segment Profit to Cash Flow Total Segment 2Q04 Dollars in millions
Slide 53: Power 2004-2006 Guidance
2004 2005 2006 Segment Profit* $0 - 150 $50 - 150 $50 - 200 Capital Expenditures $0 $0 $0 Cash Flows from Operations $150 - 350 $50 - 150 $50 - 200 Dollars in millions Power 2004-2006 Guidance * Assumes 2nd half 2004 MTM gains or losses are zero, however actual results will vary due to MTM results
Slide 54: Financial Overview & 3-Year Outlook
Financial Overview & 3-Year Outlook Don Chappel
Slide 55: Consolidated 2004-2006 Outlook
Consolidated 2004 - 2006 Outlook 2006 2005 2004 Dollars in millions Segment Profit DD&A Cash Flow from Ops. Capital Expenditures Effective Tax Rate** Cash Tax Rate $1,100 - 1,400 $650 - 700 $1,000 - 1,300 $775 - 875 39% 3-5% $1,300 - 1,600 $650 - 750 $1,300 - 1,600 $800 - 1,000 39% 3-5% $1,400 - 1,7
Slide 56: 2004-2006 Capital Expenditures By Business
2004 2005 2006 Exploration & Production $400 - 450 $400 - 450 $450 - 500 Midstream 90 - 110 60 - 80 50 - 70 Gas Pipeline 280 - 320 350 - 400 450 - 510 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $775 - 875 $800 - 1,000 $900 - 1,100 Dollars in millions 2004-2006 Capital Exp. By Business
Slide 57: Debt Reduction Action
$1.5 billion cash at August 1, 2004 Today commencing cash tender offer and consent solicitation for all $800 million 8 5/8% notes due 2010 Will use available cash and liquidity to fund purchase of notes accepted under the offer Increasing revolving credit facility by $275 million to a total capacity
Slide 58: Liquidity Available for Tender Offer
Cash @ 6/30/04 $1.0 Proceeds from Canada Sale 0.5 Cash Available $1.5 Current Unused Revolver 0.8 Increase in Revolver Capacity 0.3 Total Liquidity $2.6 Liquidity Cushion Required (1.3) Liquidity Available for Tender Offer $1.3 Liquidity Available for Tender Offer Dollars in billions * * Targeted mi
Slide 59: Scheduled Debt Maturities
Scheduled Debt Maturities 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013-2020 2021-2022 2023-2026 2027-2030 2031 2032 2033 Misc. Notes 54 247 119 323 640 53 214 1018 998 757 751 292 100 1170 850 300 PACS 1100 Tender Offer 800 Dollars in millions 800
Slide 60: Financial Strategy/Key Points
Maintain a cash/liquidity cushion of $1.0 billion plus Continue to de-lever; striving for investment-grade ratios Uses of excess cash Pay scheduled debt retirements Early debt reduction Disciplined EVA(r) -based investment Consider dividend and/or share repurchase policy upon achieving investment gr
Slide 61: Summary
Summary Steve Malcolm
Slide 62: The Road Ahead
Midstream Complete deepwater projects Complete asset sales Maintain competitive position - MLP? Capture our share of new deepwater production 2004 2005 2006 2007 & beyond Gas Pipeline Exploration & Production Corporate Power CORE BUSINESSES The Road Ahead Complete announced expansion projects Northw
Slide 63: Summary
Summary 2nd quarter results solid Debt reductions continue with new tender announced today Asset sales program essentially completed Adequate liquidity continues Growth opportunities identified Significant work outsourced to IBM Seriously considering MLP Continuing efforts to exit Power
Slide 64: Willianis.
Willianis. ao Willianté. (a
Slide 65: Non-GAAP Reconciliations
Non-GAAP Reconciliations
Slide 66: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule
Slide 67: Non-GAAP Reconciliation Schedule
Non-GAAP Reconciliation Schedule
Slide 68: 2Q 2004 EBITDA Reconciliation
2Q 2004 EBITDA Reconciliation 168 DD&A (17) Provision for Income Taxes 222 Net Interest Expense Dollars in millions ($18) Net Income (Loss)* $355 EBITDA* - - Income from Disc. Operations * Includes gains and impairments on asset sales and prior period adjustments
Slide 69: 2004 YTD EBITDA Reconciliation
2004 YTD EBITDA Reconciliation 329 DD&A (6) Provision for Income Taxes 461 Net Interest Expense Dollars in millions ($8) Net Income (Loss)* $765 EBITDA* (11) Income from Disc. Operations * Includes gains and impairments on asset sales and prior period adjustments
Slide 70: 2Q 2004 Segment Contributions
* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions 2Q 2004 Segment Contributions Gas Pipeline E&P Midstream Power Corp/Other Total Segment Profit (Loss) $133 $43 $99 $45 ($15) $305 DD&A 68 46 45 5 4 168 Segment Profit before DDA $201 $89 $1
Slide 71: Consolidated 2004 Forecast Segment Contribution
Gas Pipeline E&P Power 235 - 260 160 - 180 395 - 440 0 - 150 20 - 25 20 - 175 540 - 570 270 - 280 810 - 850 Segment Profit (Loss) DD&A Segment Profit before DDA General Corporate Expense Investing Income Other/Rounding TOTAL RECURRING Midstream 325 - 375 180 - 190 505 - 565 Total 1,100 - 1,400 650 -
Slide 72: Appendix
Appendix
Slide 73: E&P 2004 Net Realized Price Calculation
Exploration & Production 2004 Net Realized Price Calculation Example for any given quarter: * Remaining 2004 hedge position
Slide 74: Midstream Domestic NGL Production & Weighted Avg Margins
1Q '02 2Q '02 3Q '02 4Q '02 1Q '03 2Q '03 3Q '03 4Q '03 U.S. 149 135 151 150 147 119 138 132 Canada 144 145 162 155 153 123 132 150 Williams NGL Equity Mix Midstream Domestic NGL Production & Weighted Avg Margins Note: Computed using NGL prices FOB plant tailgate less shrinkage costs. Weighted avera
Slide 75: Enterprise Risk Management
Enterprise Risk Management Margins & Ad. Assur. $187 $18 $197 - $402 Prepayments - 7 31 - 38 Subtotal $187 $25 $228 $ - $440 Letters of Credit 302 132 196 43 673 Total as of 6/30/04 $489 $157 $424 $43 $1,113 Total as of 3/31/04 $364 $74 $441 $81 $960 Change $125 $83 ($17) ($38) $153 Corp./ E&P Midst
Slide 76: Enterprise Risk Management
Enterprise Risk Management Margin volatility (99% confidence interval) - - Incremental liquidity requirement 6/30/04 12/31/03 30 days ($214) ($185) 180 days ($274) ($309) 360 days ($300) ($390) Assumption: The margin numbers above consist of only the forward marginable position values, starting from
Slide 77: Enterprise Risk Management Sensitivities Analysis
Enterprise Risk Management Sensitivities Analysis 1 Assumes a correlated movement in prices across all commodities, including spreads. 2 Assumes a non-correlated change in West power prices only, no change in power volatility, full extrinsic value not included. Heat rate and position change associat
Slide 78: Power Total Undiscounted Cash Flows
Power Total Undiscounted Cash Flows Note: Actual cash flows realized upon liquidation or sale of the portfolio may differ materially from those shown. Also, please note that proprietary positions, storage, transportation, transmission, crude and refined products, interest rates, and option premiums
Slide 79: Power West - Total Undiscounted Cash Flows
Power West - Total Undiscounted Cash Flows Dollars in millions West Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006 F Tolling Demand Payment Obligations ($39) ($38) ($154) ($154) ($156) Resale of Tolling $41 $35 $86 $0 $0 Long-term Physical Forward Power Sales $29 $24 $59 $0 $
Slide 80: Power Central - Total Undiscounted Cash Flows
Power Central - Total Undiscounted Cash Flows Dollars in millions Mid-Continent Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006F Tolling Demand Payment Obligations ($13) ($21) ($87) ($88) ($89) Long-term Physical Forward Power Sales ($2) ($3) ($16) $2 $0 OTC Hedges $1 $9 $21 (
Slide 81: Power East - Total Undiscounted Cash Flows
Power East - Total Undiscounted Cash Flows East Power Portfolio Estimated as of 6/30/04 Q1 A Q2 A 2004 A+F 2005 F 2006 F Tolling Demand Payment Obligations ($36) ($39) ($155) ($154) ($157) Full Requirements ($1) $11 $14 $16 $16 OTC Hedges $19 $4 $34 $26 $49 Tolling Cash Flows Associated With Hedges
Slide 82: Consolidated Drivers
Consolidated Drivers Dollars in millions