Williams Companies, Inc. (the) · NYSE:WMB
Williams Companies, Inc. (the) — Q1 2005 Earnings Presentation
92 slides from Williams Companies, Inc. (the)'s earnings presentation, May 12, 2005
Slide 1: Williams Business Update
Williams Business Update Steve Malcolm, President and CEO May 12, 2005
Slide 2: 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" within the meaning of the Private Securities Litigation Reform Act of 1995. You t
Slide 3: Oil & Gas Reserves Disclaimer
Oil & Gas Reserves Disclaimer The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We use certain terms in this presentation, such as "probable and possible" reserves that the SEC's guidelines strictly prohibit us from including in filings with the
Slide 4: Power Update
Power Update Bill Hobbs, Senior Vice President Power May 12, 2005
Slide 5: Key Points
Key Points Positive CFFO in a shoulder quarter CFFO expected to remain positive Risk reducing contracts term sales are occurring Expect to see improvements Market liquidity Spark spreads Williams credit Active E&P drilling program will increase natural gas sales Factors impacting guidance Spark spre
Slide 6: Today's Discussion
Today's Discussion Brief overview of natural gas operations Discuss executed power sales Regional outlook Threats to competitive markets Q&A Power
Slide 7: Power
Power Natural Gas Williaris oe
Slide 8: Physical Natural Gas
Physical Natural Gas Average annual requirements 2.5 Bcf/d with peak of 3.0 Bcf/d 60% for Power 30% power-plant supply 70% third-party transactions 40% for Williams' core businesses Transportation 2.5 Bcf/d 50% for gas marketing (including power-generation fuel) 50% for Williams' core businesses Sto
Slide 9: Power
Power Power Williaris oe
Slide 10: Types of Sales Around Tolling Deals
Types of Sales Around Tolling Deals From Most Effective to Least Effective 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 similar or "mirror-im
Slide 11: Recent Successes
Recent Successes $32 Million EVA to Date on Deals West Partial resale or toll, plus gas sale 2006-2008 Heat-rate option sale 2008 Summer "capacity" sale (contractually-defined rights) 2005 Approx. cumulative 1250 MW total over 2005-2008 period Mid-Continent 170-MW forward energy sale from CLECO posi
Slide 12: Overview of West
Overview of West 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 $2.30/MWh in 2005 Annual escalator is lesser of 2.5% or CPI CDWR sales mo
Slide 13: Market Outlook in West
Market Outlook in West Market outlook Southern California remains tight on capacity and energy California Energy Commission report shows declining reserve margins in SP-15 through 2009 Financial players entering market need physical supply Development of capacity market should enhance Williams' posi
Slide 14: Overview of Mid-Continent
Overview of 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 Heat Rate Sale: Cleco Evangeline 170 MW Summer 2005 Tolling: Kinder Morgan - Jackson
Slide 15: Market Outlook in Mid-Continent
Market Outlook in Mid-Continent Market outlook Overbuilt in the South with transmission constraints Midwest Independent System Operator (MISO) energy- market implementation and future capacity-market development should increase KM-Jackson value Was active in the Cleco RFP process Industry data sugge
Slide 16: Market Outlook in Mid-Continent: Regulatory activity
Market Outlook in Mid-Continent Regulatory activity - Cleco Entergy introduces independent transmission coordinator (ITC) proposal with Southwest Power Pool as administrator Louisiana commission completes retirement study and identifies significant savings associated with elimination of old plants R
Slide 17: Overview of the East
Overview of the East Tolling agreements 2,276 MW; 7,000 average heat rate Accounts for approximately 40% of approximately $400 million annual demand charges Georgia EMCs and Allegheny can be supplied by Tenaska and Ironwood, respectively Full Requirements: Allegheny Electric Co-op 515-600 MW Through
Slide 18: Market Outlook in Northeast
Market Outlook in Northeast Market outlook Transmission congestion over last year increased Red Oak run time Capacity-market redesign expected to enhance Red Oak, Ironwood values Locational capacity values expected to benefit eastern PJM first Industry data suggests supply/demand equilibrium around
Slide 19: Potential Threats to Competitive Markets
Potential Threats to Competitive Markets Utility self-build despite existing capacity Greater threat to those building new plants Competitive solicitation levels playing field Price mitigation continues to undermine competition Utilize uncommitted capacity for reliability needs at below-fair-market
Slide 20: Estimated Total Cash Flows
Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2005 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. Note: Est. NG Portfolio Cash Flows represent expected cashflows from N
Slide 21: 2005-2007 Power Guidance
2005 2006 2007 2/23/05 Segment Profit Guidance ($250) - (150) ($200) - (50) ($100) - 50 1st Quarter 2005 Impact: MTM Earnings 221 Est. Forward Impact of MTM (32) (54) (92) Total 1st Quarter 2005 Impact 189 (54) (92) Change in Segment Profit Guidance 200 (50) (100) Revised Segment Profit Guidance ($5
Slide 22: Questions?
power = QRA Questions? 22} Wiligms Business Updte Thursday, My 12, 2008,
Slide 23: Gas Pipeline Update
Gas Pipeline Update Phil Wright, Senior Vice President Gas Pipeline May 12, 2005
Slide 24: Quality Assets Serving Growth Markets
Quality Assets Serving Growth Markets Gulfstream (50% Ownership) Underground storage LNG peaking facility Transco Northwest Gas Pipeline
Slide 25: Strategy Overview
Strategy Overview Strategic Objective Maximize utilization of pipeline system capacity Provide high quality, low cost services Maintain access to supplies and markets Customer Value Proposition Reliable service Low cost Gas Pipeline
Slide 26: Transco - Premier System Serving the Atlantic Seaboard
Transco - Premier System Serving the Atlantic Seaboard Peak day design capacity of 8.1 Bcf/d Assets 10,500 miles of pipeline 7 storage facilities 44 compressor stations; 1,630,000 HP Rate base $2.7 B Zonal rate structure Seasonal storage 220 Bcf of capacity 4,870 MMcf/d of withdrawal capability Gas
Slide 27: Transco Rate Comparison
Rate Comparison * Transco vs Competition $- $0.25 $0.50 $0.75 $1.00 $1.25 $1.50 Transco SNG Transco SNG CGT Transco Iroquois CGT Tenn TETCO Demand Commodity Fuel Other Basis Zone 4 Zone 5 Zone 6 0.407 0.530 0.590 0.530 0.815 0.766 1.225 0.879 0.936 1.205 (Mississippi thru Georgia) (S Carolina thru V
Slide 28: Northwest - Multiple Supply Sources
Northwest - Multiple Supply Sources Serving the Northwest Peak Day design capacity of 3.5 Bcf/d Assets 4,100 miles of pipeline 3 storage facilities 42 compressor stations; 350,000 HP Rate base $1.1 B Postage stamp rates Seasonal storage 12.4 Bcf of capacity 608 MMcf/d of withdrawal capability Gas Pi
Slide 29: Northwest Rate Comparison
Reno, NV Medford, OR Spokane, WA Rate Comparison * Northwest vs Competition 0.810 1.053 0.394 0.192 0.394 1.317 Northwest - Rate Comparisons Gas Pipeline * 100% Load Factor $- $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 $1.60 Northwest / Piaute GTN / Tuscarora Northwest GTN Northwest GTN Demand Commod
Slide 30: Gulfstream - Pipeline To A Fast Growing Market
Gulfstream - Pipeline To A Fast Growing Market Large supply sources Mobile Bay Eastern Louisiana Mississippi High growth Gas fired power generation Population Long term contracts Average contract life 20 years Assets Capacity 1.1 Bcfd 700 miles of pipeline; primarily 36" 1 compressor station; 114,00
Slide 31: Favorable Demand Outlook
Favorable Demand Outlook Gas Pipeline Gulfstream (50% Ownership) Underground storage LNG peaking facility Transco Northwest Source: EEA Apr 05 Compass Total Demand Increase: 9.99 Bcf/d Compound Annual Growth Rate: 2.3% 0.15 1.8% 1.05 2.6% 0.46 3.4% 1.35 3.1% 0.24 2.4% 1.11 7.0% 0.30 1.4% 0.81 0.9% 0
Slide 32: Supply Outlook - Access to Diverse Supplies
Gas Pipeline Gulfstream (50% Ownership) Underground storage LNG peaking facility Transco Northwest - -1.53 Arctic 1.06* - -0.05 1.66 - -0.5 - -0.16 - -0.05 - -0.64 - -1.04 2.00 - -.05 ..35 - -0.02 * Mackenzie pipeline on-stream in 09 2004 - 2010 US + Canada WCSB Net Increase in Production: 1.65 Bcf/
Slide 33: Positioned for Proposed & Existing LNG Imports
Positioned for Proposed & Existing LNG Imports Gas Pipeline Net Increase (Bcfd) Production: 1.65 LNG + Other: 8.34 Total 9.99
Slide 34: Accommodating LNG Imports
Accommodating LNG Imports WGP Advantages Serves markets that are large, diverse, and growing Proximity to LNG terminals Existing Cove Point facility on the east coast Advancing Gulf Coast projects Pacific Northwest proposals Redelivery flexibility Low rates Challenges Maintaining gas quality Maintai
Slide 35: Nature of Pipeline Investments
Nature of Pipeline Investments Utility franchise (FERC regulation) Relatively capital intensive with long lived immobile facilities Stable and predictable cash flow that provides financial synergies and higher credit ratings Gas Pipeline
Slide 36: How Pipelines Make Money
How Pipelines Make Money Provide transportation and storage service under firm and interruptible contracts Most revenue collected under long term contracts with credit- worthy customers Relatively limited exposure to throughput and basis fluctuations Subject to Cost of Service regulation Allowed to
Slide 37: How Pipelines Make Money - Cost of Service
Allowed to recover costs through rates based on "Cost of Service" Cost of Service O&M and A&G Expenses + Depreciation Expense + Taxes Other Than Income (state, ad valorem) + Federal and State Income Taxes + Allowed Return Cost of Service (revenue) Allowed Return = Rate Base x Rate of Return % Rate B
Slide 38: How Pipelines Make Money - Rate Design
How Pipelines Make Money - The Mechanics Gas Pipeline Straight Fixed Variable Rate Design Cost of Service Fixed Costs Variable Costs O&M and A&G Depreciation Taxes other than income Fed. & State income taxes Allowed return O&M Compressor Station Operating Expenses Maintenance Expenses Non-Tracked Fu
Slide 39: How Pipelines Make Money - Rate Cases
How Pipelines Make Money - The Mechanics FERC must approve rates through a rate case Customers and other interested parties may intervene Extensive documentation and support is presented in the rate case filing and through the discovery process Issues raised during the rate case are resolved either
Slide 40: Future Rate Case - Northwest
Future Rate Case - Northwest Next anticipated rate case effective Q1 2007 26-inch Replacement Project the primary driver Last rate case effective March 1997 No requirement to file Gas Pipeline J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D <-> NWPL Docket No. RP06-XX Key Dat
Slide 41: Future Rate Case - Transco
Future Rate Case - Transco Gas Pipeline Next rate case effective Q1 2007 Driven by Clean Air Act and Pipeline Safety Improvement Act spending Last rate case effective September 2001 Required to file per last settlement J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D 5 Month <
Slide 42: Operating Revenue Breakout
Approximately 90% of 2004 operating revenues were from transportation and storage reservation charges 2004 Revenue Revenue Breakout Gas Pipeline Transportation Reservation includes incrementally priced projects Deals Transportation Demand 0.903 Storage Demand 0.024 Transportation Commodity 0.061 Sto
Slide 43: Top Customers - Large, Long Term, Credit Worthy
Top Customers - Large, Long Term, Credit Worthy TGPL Customer Credit Rating PSEG BBB KeySpan A+ AGL Resources A- Piedmont A Con Ed A SCANA A- Exelon A- NWPL Customer Credit Rating Puget Sound BBB- N W Natural A+ Avista Corp BB+ Cascade Natural Gas BBB+ Pan Alberta Gas guarantee Intermountain Gas pri
Slide 44: Gas Pipeline 2005-2007 Guidance
2005 2006 2007 Segment Profit (1) $555 - 585 $500 - 565 $565 - 635 Annual DD&A 280 - 290 290 - 300 300 - 310 Segment Profit + DDA $835 - 875 $790 - 865 $865 - 945 Capital Spending $370 - 420 $475 - 550 $250 - 325 Dollars in millions 2005-2007 Guidance Note: If guidance has changed, previous guidance
Slide 45: Cornerstone of the Williams Portfolio
Cornerstone of the Williams Portfolio Stable and predictable cash flow Future investment opportunities Strong and diverse markets with growth Strong and diverse supply Premier pipeline franchises Both Transco and Northwest received top ranking in the Mastio & Co. customer survey Transco ranked #1 in
Slide 46: Questions?
GasPineine QRA Questions? 48} Wilms Business Updte / Thursday, My 12, 2008,
Slide 47: Exploration & Production Update
Exploration & Production Update Ralph Hill, Senior Vice President Exploration & Production May 12, 2005
Slide 48: Strategy
Grow our premier position in select regions, utilizing our expertise in basin-centered tight sands/shale and coal bed methane (CBM) Strategy remains rapid development of our significant drilling inventory Maintain top quartile position in efficiency and cost measures Be the operator of choice for la
Slide 49: 2005 Accomplishments
1Q 2005 Segment Profit over 100% higher than 1Q04 1Q 2005 production up 22%, 112 MMcfed since 1Q04 Piceance production up 59% since 1Q04 Piceance higher activity, 10 new H&P rigs contracted Additional Piceance 10-acre spacing approved Trail Ridge/Ryan Gulch additional drilling this year Big George v
Slide 50: Unique Drilling Portfolio
North American unconventional natural gas production Focused portfolio of large well-defined resources Repeatability of results, very high success rate Long-term, low-risk, high-return drilling portfolio Strong organic production growth R/P ratio of 15.6 years Drilling approx. 1,400 wells/yr Powder
Slide 51: Proved, Probable & Possible Reserves
Proved, Probable & Possible Reserves TOTAL: 3.0 Tcf Proved* * 99% of proved reserves were audited or prepared by Netherland, Sewell & Assoc., Inc. or Miller and Lents, LTD. TOTAL: ~7 Tcf Proved, Probable & Possible ** ** Please reference E&P oil & gas reserves disclaimer concerning reserves estimate
Slide 52: Domestic proved reserves up 10.5%
Domestic proved reserves up 10.5% to 3.0 Tcfe Total proved reserves 3.2 Tcfe 248% reserves replacement 99% success rate Moved 451 Bcfe to proven Domestic Reserves Exploration & Production Transfers of Probable to Proved (Bcf) 2002 2003 2004 Total Total for retained basins 313 408 451 1,172
Slide 53: Production Growth
0 100 200 300 400 500 600 700 800 900 1000 2004 2005* 2006* 2007* MMcfd Total Net Production * Assumes Midpoint of Guidance CAGR 16% Production Growth Exploration & Production
Slide 54: Cash Margin Analysis
Cash Margin Analysis Exploration & Production Reflective of core basins * Includes LOE, G&A, taxes and gathering ** Includes acquisition and development expenditures / proved reserves ('02-'04 average) 3-Year Average (2005-07) Cash Margin Cash Costs* $4.56 $1.56 $0.78 $3.00 $0.00 $1.00 $2.00 $3.00 $
Slide 55: Basin Summaries
Basin Summaries Exploration & Production
Slide 56: International E&P
Proved reserves total 37 MMboe (222 Bcfe) 5,700 Bbl/d net oil & liquids production 17 MMcf/d net gas production 69% ownership in Apco Argentina 10% ownership in La Concepcion In-fill, field extension drilling Exploration upside High investment returns, fast cash cycle Complements domestic long life
Slide 57: Arkoma Basin - Horizontal Expertise
CBM and emerging shale activity Williams' Basin Statistics: Proved reserves total 121Bcfe ~20 MMcf/d net production growing 10-15% annually Leasehold approx. 118,000 net acres ~325 total wells, 70% operated Have drilled 162 extended reach horizontal lateral wells 2004 drilling success rate of 90% 50
Slide 58: San Juan Basin - Foundation
Conventional and coal bed methane production Long life / slow decline wells Williams' proved reserves total 671 Bcfe ~150 MMcfe/d of net production growing 3-5% annually next two years 13% growth year over year Low risk in-fill drilling 40-60 operated wells drilled per year 200 - 250 undeveloped loc
Slide 59: Powder River Basin Overview
Current CBM production 891 MMcfe/d* 39 Tcf Gas-In-Place** 18,400 wells drilled to date* 33,600 additional potential locations in WY 15,000 potential locations in MT First significant CBM production 1995 * WOGCC Data January 2005 ** USGS Estimate 2002 Powder River Basin Overview Exploration & Product
Slide 60: Powder River Basin - Ready to Roll Again
High potential, low-risk development play, low cost wells Williams' proved reserves total 299 Bcfe Leasehold 1,021,400 gross/466,000 net acres ~4,810 total wells, 53% operated 2004 drilling success rate of 99% ~110 MMcfe/d net production ~9,000 drilling locations; 46% operated Powder River Basin - R
Slide 61: Powder River Basin Big George & Wyodak Coal Fairways
Powder River Basin Big George & Wyodak Coal Fairways Williams Big George Gross Production Increasing 97 MMcfd 100 Miles 60 Miles Wyodak Fairway 685.3 MMcfd* CAMPBELL COUNTY Gillette JOHNSON SHERIDAN Big George Fairway 205.2 MMcfd Williams Operated Pilots Scale 0 6 miles Partner Operated Pilots Other
Slide 62: Williams Operated Big George Daily Production
Powder River Basin Williams Operated Big George Daily Production Exploration & Production CAGR 107% 0 10 20 30 40 50 60 70 80 90 100 Apr-01 Jun-01 Aug-01 Oct-01 Dec-01 Feb-02 Apr-02 Jun-02 Aug-02 Oct-02 Dec-02 Feb-03 Apr-03 Jun-03 Aug-03 Oct-03 Dec-03 Feb-04 Apr-04 Jun-04 Aug-04 Oct-04 Dec-04 Feb-05
Slide 63: Powder River Basin Net Production Forecast
Powder River Basin Net Production Forecast Exploration & Production 136 - 151 111 - 123 100 - 111 118 MMcfe/d 770 - 775 770 - 775 700 - 775 705 Wells Spud CAGR 12% 43 36 - 40 41 - 45 45 - 50 0 20 40 60 80 100 2004 2005F 2006F 2007F Bcfe
Slide 64: Piceance Basin - Cornerstone Asset
Piceance Basin - Cornerstone Asset Exploration & Production
Slide 65: Piceance Basin Record of Results Delivery
Piceance Basin Record of Results Delivery Annual Net Production Reserves CAGR 11% Exploration & Production 1,310 1,370 1,560 1,806 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2001 2002 2003 2004 Bcfe 45 60 62 81 0 50 100 2001 2002 2003 2004 Bcfe Wells Spud 109 124 76 243 MMcfe/d 123 164 17
Slide 66: Piceance Basin Overview
Production ~900 MMcfe/d ~1,400,000 acres Gas-in-place estimates over 100 Tcf ~2,000 Mesaverde active wells ~3,000 additional locations on Williams valley acreage alone Piceance Basin Overview Exploration & Production
Slide 67: Piceance Basin Area Map
Piceance Basin Area Map 20th Year of Development 134,000 Net Acres One of the largest natural gas producers in Piceance Basin >350 MMcfd Gross Operated Production Operate 1100+ wells, 98% WI Operate 250+ miles of gathering and 4 gas plants Access to 5 major interstate / intrastate pipelines Currentl
Slide 68: Gas Recovery Estimates vs. Well Density
Piceance Basin Gas Recovery Estimates vs. Well Density Typical Piceance Valley Section 100 Bcf Gas in Place / Square Mile 20-Acre Development 32 Wells / Section Remaining Gas in Place 55 Bcf 45 Bcf, 45% GIP 1.4 Bcf per well 1.4 Bcf per well 40-Acre Development 16 Wells / Section 22 Bcf, 22% GIP Rema
Slide 69: Piceance Basin 2005 Approved 10-Acre Applications
Piceance Basin 2005 Approved 10-Acre Applications Exploration & Production
Slide 70: Record of Capital and EUR
Piceance Basin Record of Capital and EUR Average 1.41 Average $1,034 * Gross Estimated Ultimate Recovery Exploration & Production Average EUR* (BCF) 1.47 1.41 1.42 1.46 1.5 1.36 1.25 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 1998 1999 2000 2001 2002 2003 2004 Gross EUR (BCF) Average Cost (M$) 1,061 1,
Slide 71: Piceance Basin Drilling Efficiency
Piceance Basin Drilling Efficiency * Days from spud to rig release. Does not include rig move time. Exploration & Production 0 5 10 15 20 25 30 35 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004
Slide 72: Purpose Build Rig Program
Purpose Build Rig Program Incremental Activity ~50 ~20 0 Production MMCFD ~50 ~30 0 Segment Profit $MM ~200 ~200 ~30 Capital $MM * 8 6 0 Rigs 150 125 3 Operated Spuds 2007 2006 2005 Piceance Rig Design Improved performance in Piceance Basin drilling conditions Reduce the number and size of surface l
Slide 73: Piceance Basin Pipeline Infrastructure Capacity
CIG Questar TransColo NWPL WIC Expansion CIG/NWPL/Williams Greasewood DeBeque Lateral Gathering & Processing: Currently 600 MMcf/d Greasewood line DeBeque Lateral Rifle interconnect CIG interconnect Transport: TransColorado to San Juan TransColorado to Greasewood WIC expansion CIG NWPL Piceance Basi
Slide 74: Positioned for Continuing Valley Growth
Piceance Basin Positioned for Continuing Valley Growth Wells Spud 243 260 - 280 400 - 450 450 - 500 Net MMcfe/d 222 282 - 313 359 - 401 427 - 475 Exploration & Production Net Production 156 - 173 131 - 146 103 - 114 81 0 50 100 150 200 2004 2005F 2006F 2007F Bcfe CAGR 27%
Slide 75: Ryan Gulch Project Area
Williams Wells Industry Wells Earn 28,383 gross / 14,475 net acres Drilling obligations - 6 wells in 2 years; 3 Drilled, 3 remaining Williams operated at 51% WI 87% average NRI ~770 potential gross well locations ~700 net Bcf potential reserves Contiguous acreage block Additional Piceance Basin Oppo
Slide 76: Trail Ridge Project Area
17,316 gross/14,545 net acres Drilling obligation - 4 wells/year for 6 years 84% average NRI Williams operated at 100% WI ~500 potential well locations ~500 BCF potential reserves Contiguous acreage block 6 miles West of Grand Valley where completions average 1.2 Bcf/well Produces into Williams' Gra
Slide 77: Red Point Project Area
1,908 gross and net acres 85% average NRI 189 potential well locations ~200 Bcf potential reserves, at 1.3 BCF/well Adjacent well, which has a 1.3 Bcf Estimated Ultimate Recovery (EUR) Produces into Williams' Grand Valley Gathering System Additional Piceance Basin Opportunities Red Point Project Are
Slide 78: Additional Piceance Basin Opportunities Summary
Additional Piceance Basin Opportunities Summary Prospect Net Acres Gross Potential Locations* Net Potential Reserves*(BCF) Ryan Gulch (40 acre spacing) 14,475 770 700 Trail Ridge (40 acre spacing) 14,545 500 500 Red Point (10 acre spacing) 1,908 189 200 Total 30,928 1,459 1,400 * Not included in US
Slide 79: E&P 2005-2007 Guidance
2005 2006 2007 Segment profit $400 - 475 $480 - 555 $550 - 675 Annual DD&A $235 - 265 $280-320 $350-400 Segment Profit + DD&A $635 - 740 $760 - 875 $900 - 1075 Capital spending $530 - 605 $725 - 825 $725 - 875 Production (MMcfe/d) 600 - 700 720 - 820 825 - 925 Hedges (NYMEX Equivalent) Fixed Price:
Slide 80: Key Points
Delivering meaningful volume growth through expanded development drilling activity -- Piceance is primary growth driver Long history of high drilling success, low finding costs Short time cycle investments, fast cash returns Maintaining top quartile cost and efficiency position Long-term repeatable
Slide 81: Q&A Questions?
Q&A Questions? Exploration & Production
Slide 82: Appendix
Appendix Appendix May 12, 2005
Slide 83: Estimated Total Cash Flows - Combined Power Portfolio
Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2005 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. Note: Est. NG Portfolio Cash Flows represent expected cashflows from N
Slide 84: West - Estimated Total Cash Flows
West - Estimated Total Cash Flows Undiscounted dollars in millions Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2005 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. Wes
Slide 85: Central - Estimated Total Cash Flows
Central - Estimated Total Cash Flows Undiscounted dollars in millions Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2005 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues.
Slide 86: East - Estimated Total Cash Flows
East - Estimated Total Cash Flows Undiscounted dollars in millions Note: Actual cash flows realized may differ materially from those shown. Price hedges do not hedge 100% of Estimated Hedged Tolling Revenue. Note: 2005 Actual Merchant Cash Flows are included in Estimated Hedged Tolling Revenues. App
Slide 87: Power Segment Profit
Gross Margin $140 ($2) SG&A (16) (16) Op. & Other Inc / (Expense) (10) (14) Segment Profit $114 $(32) Nonrecurring: Expense related to prior period and other 11 - Recurring Segment Profit 125 (32) MTM Adjustments (108) 112 Recurring Segment Profit after MTM Adjustments $17 $80 1st Quarter 2005 2004
Slide 88: Segment Profit to Cash Flow
Segment Profit to Cash Flow Dollars in millions Power & Natural Gas Other Total Gross Margin $140 $140 SG&A & Other Inc/(Exp) (26) (26) Segment Profit $114 $0 $114 MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (221) (221) Add Realized Gains from MTM previously recognized 113 113 Segment Pr
Slide 89: Cash Flow Variance Analysis
Cash Flow Variance Analysis Undiscounted dollars in millions Note: 1Q05 forecast estimated as of 12/30/04. 1Q05 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. 1Q05 Earnings Call Combined
Slide 90: Enterprise Risk Management - Margins and Letters of Credit
Enterprise Risk Management Margins & Ad. Assur. $70 $1 $87 - $158 $134 Prepayments - 4 27 - 31 40 Subtotal $70 $5 $114 $ - $189 $174 Letters of Credit 496 104 257 90 947 855 Total as of 3/31/05 $566 $109 $371 $90 $1,136 $1,029 Total as of 12/31/04 $449 $135 $350 $95 $1,029 Change $117 ($26) $21 ($5)
Slide 91: Enterprise Risk Management - Margin volatility
Enterprise Risk Management Margin volatility (99% confidence interval) - - Incremental liquidity requirement 3/31/05 12/30/04 30 days ($124) ($106) 180 days ($328) ($268) 360 days ($341) ($353) Assumption: The margin numbers above consist of only the forward marginable position values, starting from
Slide 92: Enterprise Risk Management Sensitivity Scenarios
WMB 1 E&P 2 Midstream 3 Power 4 Natural Gas Natural Gas Processing Margin West Spark Spread (Per MMBTU) (Per MMBTU) (Per Gallon) (Per MWh) Price Increase $0.10 $0.10 $0.01 $5.00 2005 ($3) - $0 $5 - $6 $7 - $12 $5 - $10 2006 ($2) - $1 $10 - $11 $10 - $15 $5 - $15 2007 $8 - $11 $16 - $17 $10 - $15 $5