Natural Gas Pipelines Deb Macdonald
Infrastructure Development
Need for Natural Gas Infrastructure EIA predicts demand for natural gas to grow at 2% per year from 23 Tcf currently to 34 Tcf by 2020. Foster Associates indicates peak day requirements will grow from approximately 131 Bcf/d currently to over 170 Bcf/d in 2020. National Petroleum Council predicts that roughly 40,000 miles of new gas transmission lines and 275,000 miles of distribution mains will be needed by 2015. FERC holding regional conferences on adequacy of energy infrastructure. New infrastructure will be needed to move gas from remote sources being developed (deep water Gulf of Mexico, Alaska, coal bed methane and traditional production in the Rocky Mountains) and to facilitate imports into Mexico. 3
Challenges for Infrastructure Development FERC s s review of its Negotiated Rate Policy Has allowed sponsors/shippers to negotiate project benefits/risks Majority of new projects have been done with Negotiated Rates Provides long-term certainty for sponsors and shippers Turmoil in the Merchant Energy Company sector Merchants have consistently anchored new infrastructure projects LDCs and producers are beginning to step-up New contract structures may be necessary Environmental Access to Capital 4
Kinder Morgan Advantages Opportunity Large existing asset base leads to significant expansion and extension opportunities Access to Capital Best in class balance sheet ensures access to capital Efficient Structure MLP efficiently capitalizes long-lived lived pre-tax assets Low cost discipline 5
Infrastructure Development Opal Wheatland Project Horizon Cheyenne Hub Advantage St. Louis Lateral Blythe/ Ehrenberg Silver Canyon Blanco TransColorado Extension NGPL Permian Expansion NGPL North Texas Pipeline KMTP / KM Tejas KMIGT Trailblazer Pipeline TransColorado KM Retail RMNG / KMICD KM Gathering Gas Storage Gas Processing Market Hub West Texas Waha Monterrey NGPL North Lansing Storage Katy Henry 6
Areas of Focus Going Forward Incremental markets strategic to existing assets Mexico s s growing needs to import U.S. production Rocky Mountain/San Juan supply bottlenecks Southwest need for capacity 7
Incremental Markets Strategic to Existing Assets NGPL Permian Expansion NGPL St. Louis Extension Horizon Pipeline NGPL North Lansing Storage Expansion North Texas 8
NGPL Permian Expansion 7,000 HP compression 60,500 Dth/day capacity $1.2 MM capex 144 TW Eddy 167 $1.5 MM annual lease payment January, 2002 in-service Indian Basin Plant TW NGPL El Paso El Paso NEW MEXICO TEXAS Permian Expansion 139 TW Winkler Waha Hub 9
NGPL St. Louis Lateral 50 miles of 24 pipe 300,000 Dth/day capacity $37 MM capex 10 year contract life September, 2002 in-service Loudon Storage 206 St. Louis Lateral St. Louis NGPL 310 MISSOURI ILLINOIS 10
NGPL North Lansing Storage Expansion 6,000 HP compression 17 new wells 10.7 Bcf additional capacity $35.6 MM capex Fully contracted FERC approval received Projected Spring, 2003 in-service 802 Dallas North Lansing Storage NGPL 388 Longview Marshall 304 11
Horizon Pipeline Joint venture with Nicor 28 miles of 36 pipe 42 miles of NGPL leased capacity 116 8,900 HP compression 380,000 Dth/day capacity 10 year average contract life Chicago $80 MM capex May, 2002 in-service Horizon Pipeline 113 110 ILLINOIS 202 201 Herscher Storage 12
North Texas Pipeline 82 miles of 30 pipe 325,000 Dth/day capacity 30 year contract life $70 MM capex September, 2002 in-service North Texas Pipeline Station 802 NGPL Dallas North Lansing Storage 388 304 13
Mexico Monterrey Pipeline West Texas Pipeline 14
The National Challenge 10 SUPPLY DEMAND BALANCE 2002-2010 (Bcfd) 9 8 7 6 5 4 3 2 5.5 1.1 4.4 6.2 1.1 5.1 6.8 1.6 5.2 7.3 1.8 5.5 7.8 1.9 5.9 8.3 1.6 6.7 8.5 1.4 7.1 Imports National Supply Demand 9.0 1.7 7.3 9.5 1.9 7.6 By By 2010 imports in in the amount of of 1.9 Bcfd will be be required While supply will have a CAGR of of 6.3% from 2002 to to 2010,demand will increase at at a CAGR of of 8.1% during the same period. Imported gas is is currently used to to satisfy demand. 1 0 2002 2003 2004 2005 2006 2007 2008 2009 2010 Source: Prospectiva del Mercado de Gas Natural 2001-2010, Secretaria de Energia, Mexico. Expergo analysis 15
Demand Growth by Market Segment DEMAND BY SECTOR 2000-2010 (Bcfd) 10 9 Transportation Residential & Services Power Generation Industry Oil Industry (Pemex self supply) 8 7 6 5 4 3 2 1 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Source: Prospectiva del Mercado de Gas Natural 2001-2010, Secretaria de Energia, Mexico. Expergo analysis 16
Monterrey Pipeline Mexico Texas Laredo Corpus Christi Monterrey Pipeline U.S. scope-9 miles of 30 pipe Mexico scope-137.5 km of 30 pipe 375,000 Dth/day capacity $80 MM capex Fully contracted for 15 years Under Construction Projected April, 2003 in-service McAllen Iberdrola Power Plant Monterrey Proposed Monterrey Pipeline KM Texas Pipeline KM Tejas Pipeline NGPL Pemex Pipeline 17
Proposed West Texas Pipeline Proposed Texas Hinshaw pipeline Agreement in Principle with PEMEX 196 miles of 24 pipe 12,400 HP compression 300,000 Dth/day capacity $149 MM capex Projected June, 2004 in-service 144 TW 167 NGPL NNG El Paso El Paso EPNG PEMEX EPNG Hueco C.S. MEXICO NEW MEXICO TEXAS Proposed Pipeline Proposed Comp. Sta. Proposed Interconnect NGPL Waha Hub 139 NNG TW 18
Rocky Mountain/Southwest Trailblazer Expansion Completed Trailblazer Expansion Proposed CMC Storage Expansion Advantage Wheatland TransColorado Silver Canyon 19
Powder River Basin Coal Bed Methane MMcfd: Total Reserves estimated at 25 Tcf -- >70 years of production at current rates 1000 900 800 700 600 MMcfd 500 400 300 200 100 0 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 20
Cheyenne to NGPL Basis Since Inception of Cheyenne Posting 3.000 2.500 2.000 1.500 1.000 0.500 0.000-0.500-1.000 May-00 Aug-00 Nov-00 Feb-01 May-01 Aug-01 Nov-01 Feb-02 May-02 Aug-02 Nov-02 Feb-03 May-03 Aug-03 Nov-03 Feb-04 May-04 Aug-04 Nov-04 Feb-05 May-05 Aug-05 Approval/construction time for new pipeline project 21 Nov-05
Kansas Hugoton Production Declining 2000 757 MMcfd Loss since 1996 1800 1600 1400 ~10% annual decline 1200 MMcfd 1000 800 600 400 200 0 1995 1996 1997 1998 1999 2000 2001 2002 22
Trailblazer Pipeline Casper 50,000 HP compression at 3 stations 324,000 Dth/day capacity $50 MM capex 10 year average contract life April, 2002 in-service WYOMING Cheyenne NEBRASKA Omaha Cheyenne Hub Denver WNG CIG 601 COLORADO 602 603 Trailblazer Pipeline NNG 196 106 NGPL 195 Compressor Station NGPL 23
Trailblazer Expansion Scenarios 50,000 /Dth day expansion 30 miles of looping $32.5 MM capex 75,000 /Dth day expansion 58 miles of looping $64.3 MM capex 100,000 / Dth day expansion 87 miles of looping $94.1 MM capex Projected July 2004 In-service Trailblazer Pipeline CHEYENNE 601 602 603 Omaha HUB 196 Denver 195 106 105 Trailblazer Pipeline Proposed Expansion 193 104 194 Kansas City Trailblazer Compressor Station 103 NGPL Pipeline 192 24
Cheyenne Market Center 11,300 HP compression 10 new wells 6.0 Bcf additional capacity $28.4 MM capex Fully contracted for 10 years January 2002 FERC application Projected Summer, 2004 in-service W y o m i n g CIG Huntsman Storage N e b r a s k a Cheyenne Cheyenne Hub Proposed Advantage Pipeline KMIGT Pipeline Trailblazer El Paso-CIG El Paso-WIC Xcel Energy Denver C o l o r a d o 25
KMIGT s Proposed Advantage Pipeline Cheyenne N e b r a s k a Pursuing binding agreements 411 miles of 24 pipe 26,700 HP compression 330,000 Dth/day capacity $287 MM capex Projected October, 2005 in-service Omaha Cheyenne Hub Denver C o l o r a d o NGPL NNG Kansas City Proposed Advantage Pipeline Proposed Advantage Compression KMIGT NGPL Huntsman Storage Field K a n s a s PEPL WGP 26
KMIGT s Proposed Wheatland Expansion Project Pursuing binding agreements W Y O M I N G 80,000 Dth/day capacity Approx. 12,000 HP new compression $28 MM capex Projected October, 2005 in-service N E B R A S K A Cheyenne Omaha WHEATLAND PROJECT Proposed Compression Added Capacity from add l Comp. Proposed Advantage Pipeline Proposed Advantage Compression KMIGT Cheyenne Hub Denver C O L O R A D O NGPL PEPL NNG MCMC WNG ANR Kansas City WNG KMIGT Compression K A N S A S KMIGT Gas Storage NGPL 27
TransColorado-Silver Canyon Salt Lake City Opal Green River Uinta W Y O M I N G Washakie Cheyenne Cheyenne Hub Piceance D-J Basin Greasewood Denver U T A H Grand Junction Paradox C O L O R A D O Olathe C.S. Dolores C.S. Coyote Gulch Plant Las Vegas A R I Z O N A Farmington Blanco San Juan N E W M E X I C O Needles Topock Blythe/ Ehrenberg Flagstaff Phoenix Gallup TransColorado Proposed TransColorado Proposed Silver Canyon Pipeline KMIGT Trailblazer RMNG & KMICD Red Cedar Gathering Market Hub Gas Supply Basin 28
TransColorado/Silver Canyon Strategy TransColorado Options: 150 MMcf/d incremental long-haul capability from mainline compression additions Potential extensions to supply sources Potential mainline looping for additional long-haul capability Potential 750 MMcf/d extension from Blanco to Gallup/Window Rock to relieve San Juan Triangle constraints Staggered in-service dates to meet development profiles 29
TransColorado/Silver Canyon Strategy Silver Canyon Options: 750 MMCf/d capacity from Gallup/Window Rock Delivery options in New Mexico, Phoenix area, Blythe/Ehrenberg into SoCal Gas and North Baja Potential interconnects with proposed storage developments: Desert Crossing and Copper Eagle in Arizona and SoCal Gas in California 30
TransColorado/Silver Canyon Strategy Benefits: Outlet for Rocky Mountain production Relieves San Juan Triangle constraints Develops Gallup/Window Rock as hub interconnecting to Silver Canyon, Transwestern and El Paso Natural Gas with downstream optionality on moving gas east or west Meets the needs of Arizona/New Mexico/California markets left short in the allocation of El Paso system capacity Connects Rocky Mountain/San Juan supply to the North Baja Pipeline to meet Mexico s s import needs Competitively priced transport with significantly lower fuel rates than alternatives Flexible contract terms 31
TransColorado/Silver Canyon Strategy Estimated Capex: TransColorado - up to $250 million Silver Canyon - up to $740 million Potential in-service dates: From 2 nd quarter 2004 to 2 nd quarter 2006 depending on customer needs 32
Success to Date Internal Growth Projects at Kinder Morgan both at KMI and KMP $238.2 million completed in 2002, 5 projects* $293.6 million contracted/in process, 4 projects 5 additional projects proposed/open season Existing asset base provides platform for growth Expansions and new projects supported by long-term, firm contracts with fixed, negotiated rates *Includes 100% of Horizon Capex 33
Overall Gas Pipeline Update
KMP Natural Gas Pipelines Segment Overview (a) Terminals 19% Products Pipelines 36% CO2 Pipelines 15% Natural Gas Pipelines 30% Red Cedar/ Other Rockies 11% Trailblazer 14% Texas Intrastates 51% KMIGT 24% (a) 2003 budgeted distributable cash flow before allocation of G&A G and interest 35
KMP Pipelines Trend 01 Actuals 02 Budget 02 Actuals 03 Budget Income before DD&A $227 MM $347 MM $325 MM $365 MM Growth from 01 to 02 Tejas acquisition Trailblazer expansion/acquisition of Enron/CIG interests Deficit from 02 budget of $22 MM KMTP s s conversion to fee-based storage program Limits downside risk and earnings variability Limits upside in rising gas price environment Tejas failure to capture projected commercial upsides 03 Budget Caused by credit crunch in merchant energy sector Full year of Tejas Includes commercial upside on Tejas from BP transaction Offset by $10.3 MM increased sustaining capex related to new integrity regulations 36
NGPL Impact on KMI Earnings 2002 2003 Budget Power and Other 5% Retail 8% Trans- Colorado 2% Power 2% Retail 8% Trans- Colorado 2% KMP 42% KMP 45% NGPL 43% NGPL 43% (a) $360 million $377 million 2002 results and 2003 budgeted segment earnings before allocation n of G&A and interest expense. KMP includes: (i) general partner interest, (ii) earnings from 18 million KMP units and (iii) ii) earnings from 14 million KMR units. 37
Pipeline Update KMIGT Stable earnings base Long-term contracts (average 7(transport) to 8 (storage) years) Existing assets subject to limited competition Increase in Rocky Mountain production will drive growth Trailblazer Stable earnings base Long-term contracts (average 8 years) Increase in Rocky Mountain production will drive growth 38
Pipeline Update Horizon Stable earnings base Long-term contracts (average 9 years) Platform for expansion to serve power generation growth in Northern Illinois, Indiana, and Wisconsin TransColorado Extraordinary earnings growth from 2001 to 2002 Substantial increase in production adjacent to pipeline Increased North End (Phase II) throughput to current average of 280 dt/d Expansion/extension opportunities to be explored Expansion would include terming up existing contracts Current average term of 3 years 39
NGPL Update
Rollover Negotiations Completed NICOR 997,000 dt/d FTS 24.4 Bcf DSS 16.4 Bcf NSS Rolled for 3-year 3 term NIPSCO Sold incremental 84,500 dt/d FTS Dec. 02 Feb. 03 255,100 peak/138,000 off-peak dt/d long-haul FTS 10.5 Bcf DSS MidAmerican 80,000 dt/d market-area area FTS 40,000 dt/d Louisiana FTS Rolled entire portfolio for 3.3 year term Sold 25,000 dt/d incremental long-haul FTS for same term 115,000 peak/85,000 off-peak dt/d FTS 10 Bcf DSS Rolled for 2 years 41
Rollover Negotiations Completed Peoples 19.2 BCF NSS; Rolled for 3 years 175,000 peak/29,000 off-peak dt/d market area (short-haul) haul) FTS Rolled for 3-year 3 term and extended 65,000/d peak/29,000/d off-peak dt/d to long-haul FTS at higher rate Wisconsin Electric 71,000 dt/d long-haul FTS rolled to 3/31/04 33,133 dt/d annual FTS converted to winter-only 10,000 dt/d market area FTS rolled for one-year term 1.2 BCF DSS rolled for one year term Acquired 2.25 Bcf incremental NSS capacity for 5 year term [volume ratchets down over term] Aggregate annual revenue associated with LDC rollover excluding upside sharing on index-based FTS: $151.0 MM 42
NGPL FTS Capacity Summary (Volumes in TBtu/d) Long Haul Louisiana and Crosshaul Total Contract MDQ Expiring in 2003 2.01.63 2.64 Re-contracted 1.29.46 1.76 Remaining Capacity.72.17.90 43
Renegotiation of NSS Summary for 2003 Available Capacity 88.6 TBtu expiring /available in 2003 Sold 64.2 TBtu sold Average term = 3.34 years (23 month to 5 year contracts) Average rate = $.4750 (max rate = $.4912) Remaining 24.4 TBtu expiring in March - April 44
Renegotiation of DSS Summary for 2003 Available Capacity Sold 21.73 TBtu expiring in 2003 21.68 TBtu sold Average Term = 2.43 years Average Rate = $1.248 (max rate = $1.368) Remaining 0.05 TBtu expiring in the fall 45
Natural s Gas Fired Power Generation Market Megawatts under construction for in-service thru 2004 Gas Fired Generation Developed on Natural Gas Pipeline 20000 Megawatts 15000 10000 5000 0 Before '99 1999 2000 2001 2002 2003 2004 Peaker Baseload Total Year Plant in Service Before '99 1999 2000 2001 2002 2003 2004 Total Peaker 2,700 300 700 3,029 1,915 585 300 = 9,529 Baseload 225 0 1,000 1,612 2,995 2,320 0 = 8,152 Total 2,925 300 1,700 4,641 4,910 2,905 300 = 17,681 # of Plants 2 1 4 10 8 4 1 = 31 Numbers include both plants directly and indirectly connected to NGPL 46
Texas Intrastate Pipeline Group Update
Gulf Coast System Houston KM Texas-2,500 mile system 2.0 Bcf/day peak capacity KM Tejas-3,400 mile system 3.4 Bcf/day peak capacity Storage-12 Bcf working capacity Hubs-Katy, Agua Dulce, HSC W. Clear Lake Tejas-Stratton Ridge KMTP-Stratton Ridge Markham Storage Mexico Texas Laredo Corpus Christi McAllen Brownsville KM Texas Pipeline KM Tejas Pemex Gas Storage Field Compressor Station Processing Plant 48
Strategy Texas Intrastate Group Integration of Tejas and KMTP Physical interconnects Commercial integration Minimize commodity and basis risk Includes conversion to fee-based storage program Increase operational efficiencies Fuel efficiency Gas loss and unaccounted for Targeted market expansion opportunities Aggressive supply acquisition program 49
Electric Generation Texas Intrastate Group Electric Utility Electric Utility Electric Utility $11.0 MM Merchant $27.7 MM $16.6 MM Merchant $30.8 MM $14.5 MM Merchant $38.1 MM 2001: $44.3 MM 2002 est: $45.3 MM 2003 est: $49.1 MM 50
Contracting Success Texas Intrastate Group BP Firm Transportation and Storage Coral Power Sales: Term: September 1, 2002 to March 31, 2006 and year to year thereafter eafter unless terminated with 2 years notice Transport Volumes: 600,000/d ramping up to 1 Bcf/d in 03 Sales Volume: 50% of transport volume Storage Volume: 5.4 Bcf ramping up to 19 Bcf in 03 Term: 3 years beginning July 1, 2002 Southern Union Sales Volume: 18.5 bcf/year minimum delivered to the Tenaska Gateway plant in Rusk County, Texas Firm purchase obligation of 27.375 Bcf over 5-year 5 term, July 1, 2002 to June 30, 2007. Minimum of 20,000/d and maximum of 50,000/d 4 Bcf of winter/summer service for 5 years 51
Contracting Success Texas Intrastate Group CPS at San Antonio Combined firm transport/sales obligation of 50,000/d for 2-year 2 term, July 1, 2002 to June 30, 2004 Praxair, Inc. Sales contract Texas City Facility 100% requirements contract; 15 year term beginning 1 st quarter of 2004 Initial volumes of 40,000/d increasing to a maximum of 72,000/d starting July 2007 Port Arthur Facility 15,000/d for 5 years beginning 2 nd Quarter of 2004 In excess of 400,000 MMBtu/d of expiring or evergreen gas purchase contracts have been extended and in excess of 250,000 MMBtu/d of incremental supply was connected to KMTP/Tejas in 2002 52
Regulatory Developments
Regulatory Developments Order No. 637 Almost a non-event for KM pipelines Tighter Creditworthiness Provisions NGPL s test case pending Review of Negotiated Rate Policy 54
Regulatory Developments Rate Case Filing Requirements NGPL KMIGT No filing requirement Any change under NGA 5 prospective No filing requirement Cost and revenue study in 2004 Any change prospective TransColorado No filing requirement Any change prospective 55
Regulatory Developments Horizon Pipeline Trailblazer Three-year filing requirement Section 4 filing due mid-2005 Existing agreements are negotiated rate deals Rate Case Filing Requirements Rate decrease filed November 29, 2002 Rates effective January 1, 2003 Hearing no later than October 2003 with initial decision by March 2004 Expansion done under negotiated rates not impacted by change in recourse rate 56
Pipeline Safety & Integrity Development Pipeline Safety Improvement Act of 2002 Applies to interstate pipelines regulated by DOT Baseline integrity assessments required in high consequence areas s within 10 years 50% of highest risk segments must be completed within 5 years Reassessment required every 7 years Estimated impact on sustaining capex KMI - $10.1 MM increase from 02 budget KMP - $2.6 MM increase from 02 budget Texas Railroad Commission Integrity Regulations Baseline assessments 50% mileage required by 12/31/2005; remainder by 12/31/2010 (all lines regardless of class location) Estimated impact on sustaining capex: $7.8 MM annual increase from f 02 budget 57