Pipeline and Storage Infrastructure Projections through 2030

Transcription

1 Pipeline and Storage Infrastructure Projections through 2030 INGAA Foundation Spring Meeting April 16, 2009 Kevin R. Petak, Vice President, Gas Market Modeling Geoffrey N. Brand PhD, Project Manager, Gas Market Modeling ICF International

2 Disclaimer This presentation provides the views of ICF International developed based on some assumptions provided by the Interstate Natural Gas Association of America. The presentation includes forward-looking statements and projections. ICF has made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual market results to differ materially from the projections, anticipated results or other expectations expressed in this presentation. 2

3 Contents Study Overview Summary of Cases Midstream Infrastructure Requirements Issues and Conclusions 3

4 Study Overview 4

5 Study Objectives The objective of the study is to provide a long range planning document that can form a basis upon which the Foundation and industry can engage policy makers and stakeholders on the issues that are important for a healthy industry. The study is based on two detailed supply/demand outlooks for North American natural gas markets to provide a basis for infrastructure analyses. The first is an expected or reference case view of the future, and The second is an alternative natural gas case in which markets and policies lead to greater growth in gas consumption. The study estimates future natural gas infrastructure requirements for both market outlooks, discusses the factors that affect those requirements, and presents and analyzes the important issues that determine whether that infrastructure will be put in place on a timely basis. 5

6 Deliverables Results of Two Different Scenarios for U.S. and Canada Gas Markets Over the Next 20 Years Projected Gas Pipeline Infrastructure Needs for Both Scenarios Total and regional market requirements Quantification of expenditures, incremental mileage, and incremental compression needs Summary PowerPoint Presentation and Detailed Report Draft report to be completed by April 17 Final report to be completed by the end of April 6

7 Summary of Cases 7

8 Study Cases Base Case A status quo case that reflects an expected outcome for U.S. and Canada gas markets by considering, and, in most cases, continuing recent market trends. For example, the case projects that, after the economy rebounds, gas-fired power generation will continue to grow consistent with observed growth during the past 20 years. Alternate Scenario - The Alternate Case tests the upper range of possible infrastructure needs by assuming reasonable policies and market results that lead to greater demand for natural gas than in the Base Case. The case uses the Base Case as a starting point, and modifies key variables to reflect the impact of potential changes in policies signaled by the Obama administration. Some of the changes in the scenario reflect uncertainties in key assumptions. 8

9 General Case Assumptions U.S. economy in deep recession until 2010, delaying market growth for a few years. Annual economic growth rebounds to 2.75% in 2010 and thereafter. Oil prices dip to average $50 per barrel this year, but then rebound to average $70 per barrel (real$) after this year. Demographic trends consistent with trends during past 20 years. Electric load growth averages about 1.4% per year after economic rebound, somewhat below the 2.0% average over the past 20 years. Carbon policy enacted, taking effect in Power plant mix: renewables up to meet state RPS s, nuclear grows modestly and exclusively at existing locations, coal with carbon capture penetrates slowly, and gas is an important bridge fuel for carbon policy. Adoption of DSM programs and conservation and efficiency trends continue, consistent with recent history. Normal (30-year average) temperatures. 9

10 General Case Assumptions (continued) No significant hurricane disruptions to natural gas supply (20-year average). Current U.S. and Canada gas production from over 260 trillion cubic feet of proven gas reserves. Substantial North American natural gas resource base totaling about 2,100 trillion cubic feet of unproved plus discovered but undeveloped resource can supply U.S. and Canada gas markets for over 60 years. Unconventional gas comprises over 50 percent of remaining gas resource. Shale gas alone accounts for over 25 percent of the remaining resource. Drilling activity below recent levels this year, due to recession. After economic rebound, near-term drilling activity determined by announced plans. Future activity dependent on gas prices and remaining resource base. EURs (estimated ultimate recovery) and decline rates for wells consistent with currently observed values, but change to reflect gas resource developed in the future. Planned pipeline and storage expansions assumed per project announcements. Unplanned projects included when market signals need of capacity. 10

11 Contrasting Case Assumptions Energy Conservation Climate Policy Carbon Capture and Sequestration Renewables Nuclear Power Base Case Moderate goals consistent with recent trends are set and achieved. Emissions targets decline gradually at first, but more aggressively after Liberal offset policy reduces impact of targets before Technology is widely available and incentives are provided for development of carbon capture. About 40 GW of coal with carbon capture is built by Growth driven by state RPS requirements. About 25 GW of new nuclear capacity built through 2030, exclusively at existing sites. Alternate Case More aggressive goals are achieved, reducing energy intensity. Offsets are more limited, encouraging a more robust reduction of carbon emissions from coal plants, forcing greater retirement of coal capacity. No significant carbon capture before More aggressive growth than in the Base Case, due to additional incentives and more stringent carbon policy. Only a couple new plants are built (total of 10 GW including capacity creep ) through

12 Contrasting Case Assumptions (continued) Plug-in Electric Hybrids CNG and LNG Vehicles Upstream Technologies Base Case Modest market penetration before No national policy focused on incentives for natural gas vehicles. Growth in unconventional gas is very substantial. Alternate Case More significant penetration by Smart grid and time-of-day metering advanced. A national oil substitution policy is instituted, promoting substantial development of NGVs (particularly in long-haul trucking). Technological advancements accelerate and increase growth. Drilling Moratoria Despite 2008 action, most restrictions are re-introduced. Some restricted areas in offshore waters are opened to drilling. Arctic Gas Pipelines develop slowly; 2015 for Mackenzie Delta and 2020 for the Alaska Gas Pipeline. Projects accelerated by 3 years. 12

13 U.S. Power Generation Capacity (GW) Net Summer Dependable Capacity After Retirements Base Case Alternate Case Natural Gas Coal Nuclear Renewables / Hydro / Other Total 974 1,088 1,262 1,116 1,353 13

14 Policy Impacts on U.S. Generating Capacity (GW) Base Case Alternate Case Smart Metering Capacity Reduction Capacity for Ancillary Services for Renewables Capacity for Electric Cars na na Capacity Impact for Conservation Total

15 Base Case Overview Gas Demand The recent economic downturn will delay market growth for a few years. Gas consumption in the power sector is likely to grow significantly, and will be the most substantial driver of gas infrastructure in the foreseeable future. Carbon policy encourages growth of gas-fired power generation because it discourages continued reliance on coal-fired generation. Other sectors will grow much more modestly, consistent with recent trends U.S. & Canada Gas Consumption (Trillion Cubic Feet, Tcf) Power Generation Industrial Commercial Residential Other Total Delta Delta Tcf 5.1 Tcf 15

16 Base Case Overview Gas Supply The economic downturn will delay growth in supply for a few years as producers reduce E&P activity in response to lower gas prices. However, growth in unconventional supplies (i.e., gas from shales and tight formations) is likely to resume as the economy rebounds supply development is encouraged by market growth. LNG Tcf per Year Unconventional/ Other 10 5 Conventional Note: The unconventional/other category includes Arctic gas supplies. 16

17 Base Case Overview Increases in Interregional Flow, 2008 to Widespread growth in gas use, coupled with growth in unconventional gas supplies and Arctic gas development creates substantial interregional flow increases. New pipeline infrastructure will be needed to make the incremental transport possible (79) Canaport 264 NE Gateway 207 Everett Cove Point Costa Azul Elba Island 326 Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease Manzanillo Lazaro Cardenas Altamira Gulf LNG 1391 Energy < Freeport and Golden Pass < Lake Charles, Gulf Gateway, Sabine Pass and Cameron Florida (Offshore) Units: Million cubic feet per day 17

18 Base Case Overview Projected Gas Prices at Henry Hub $10.00 Gas prices are likely to rebound back into the $6 to $8 per MMBtu ballpark after the economy rebounds. Fuel Prices (2008 Dollars per MMBtu) $8.00 $6.00 $4.00 $2.00 Projected gas prices are at a level that is sufficient to encourage continued gas supply development, but not too high so as to discourage continued market growth. $

19 Alternate Case Overview Gas Demand U.S. & Canada Gas Consumption (Trillion Cubic Feet, Tcf) Delta Delta Compared to Base Case (Tcf) Power Generation Industrial Commercial Residential Other Note: The commercial sector includes gas use in vehicles. Total 3.6 Tcf 9.2 Tcf INGAA Base Case INGAA Alternate Case Gas use in the Alternate Scenario grows substantially above levels observed in the Base Case. Incremental growth is 80 percent greater than growth in the Base Case. Total gas use is up by an additional 12 percent or by 4 trillion cubic feet above the Base Case level by % of the increase is attributed to less coal and nuclear penetration in the power sector. Natural gas use in vehicles accounts for about 15% of the increase. Supply-side measures keep gas prices in check, reducing the potential for demand destruction and creating incremental increases in gas use. 19

20 Alternate Case Overview Increase in Flow Versus Base Case in 2030 Versus the Base Case, interregional transport increases in a number of areas to satisfy increased demand and to deliver incremental supplies. The most substantial increases are from currently restricted offshore production areas that are opened to development. Significant increases also occur from the Rockies and the Midcontinent shales where technology advancement fosters development of new supplies Florida (Offshore) Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease Units: Million cubic feet per day 20

21 Alternate Case Overview Projected Gas Prices Despite substantial increases in gas use versus the Base Case, gas prices in the Atternate Scenario are about $1 per MMBtu below levels in the Base Case. Substantial increases in supplies brought about by new E&P technologies and opening of areas currently restricted to supply development helps keep gas prices to consumers in check Henry Hub Gas Price Real 2008$/MMBtu INGAA Base Case INGAA Alternate Case 21

22 Summary of Case Results Trillion Cubic Feet 2008 Level 2030 Level %Chg 2008 to 2030 Base Alternate Base Alternate U.S. and Canada Gas Consumption % 34% U.S. and Canada Gas Use in Power Generation % 103% U.S. and Canada Gas Production % 33% Conventional Onshore Gas Production Unconventional Onshore Gas Production % -27% % 177% Offshore Production % 78% U.S. and Canada LNG Imports % 425% U.S. Exports to Mexico % 142% 22

23 Summary of Case Results From Pipe Dream to Reality Natural gas consumption is likely to grow, particularly in the power sector where gas-fired generation will be relied on to satisfy growing electric load. Penetration of new nuclear generation and new clean coal technologies with carbon capture will affect the magnitude of increase in gas-fired generation. Gas will be the bridge fuel for carbon control. Growing gas supply is needed to satisfy market growth. The gas industry thought the supply void could be filled with gas from the deeper waters of the Gulf of Mexico then, the industry hoped that LNG would be the answer now, the industry believes that shale and unconventional gas is the answer. This one is working! Significant amounts of new pipeline and storage infrastructure will be needed to satisfy market growth and to make deliveries of new supplies possible. Regional shifts in gas flow will create significant need for new gas infrastructure. 23

24 Midstream Infrastructure Requirements 24

25 Interregional Pipeline Expansions Projected Increases in Capacity from 2009 through Base Case Units: Million cubic feet per day 7500 Alternate Case Cove Point Cove Point Costa Azul Manzanillo Lazaro Cardenas 1500 Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease Altamira Gulf LNG Energy 310 Elba Island 1200 Florida (Offshore) Gulf LNG Energy In the Base Case, about 25 Bcfd of incremental pipeline capacity will be required to make transmission of new gas supplies to growing markets possible. This approximates to about a 20 percent increase in interregional transport capability, currently estimated at 130 Bcfd. Versus the Base Case, an incremental 12 Bcfd of interregional transport is needed in the Alternate Case. E&P technological advances, a less restrictive environment for offshore gas development, and increased gas use resulting from even greater reliance on gas-fired power generation encourage development of additional gas infrastructure. Costa Azul Manzanillo Lazaro Cardenas 1500 Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease Altamira Elba Island Florida (Offshore) 25

26 Miles of New Pipeline Pipeline Mileage Added Each Year 7,000 6,000 5,000 Base Case Alaska Project Alaska / Arctic 1 New Expansion Lateral 2 7,000 6,000 5,000 Alternate Case MacKenzie Project Alaska Project 1 Alaska / Arctic New Expansion Lateral2 Miles of Pipe 4,000 3,000 MacKenzie Project Miles of Pipe 4,000 3,000 2,000 2,000 1,000 1, Includes cost of downstream expansions on existing corridors in the U.S. and Canada in addition to the cost of arctic Canada and Alaska frontier projects. 2 Lateral is defined as a spur off the main transmission line, normally used to connect production, storage, power plants, LNG terminals or isolated demand centers. 1 Includes cost of downstream expansions on existing corridors in the U.S. and Canada in addition to the cost of arctic Canada and Alaska frontier projects. 2 Lateral is defined as a spur off the main transmission line, normally used to connect production, storage, power plants, LNG terminals or isolated demand centers. From 2009 through 2030, between 1,700 and 2,800 miles of gas transmission pipeline will be added each year. These additions are fairly consistent with recent levels. Construction of laterals will likely account for a greater share of the incremental mileage in the future. Much of the new pipeline in the future is likely to rely on and add to recently built projects. A substantial amount of the incremental mileage in the Alternate Case is associated with build-out of the interstate transmission system to accommodate natural gas vehicles. Arctic projects account for 4,000 to 5,000 miles of new pipeline. 26

27 Regional Breakout for Added Pipeline Mileage from 2009 through 2030 Base Case Western, 2.2 Arctic, 1.0 Canada, 4.7 Southwest, 8.6 Alternate Case Western, 3.9 Arctic, 1.0 Canada, 7.2 Southwest, 13.4 Central, 8.4 Central, 13.4 Southeast, 4.6 Offshore, 2.2 Midwest, 3.3 Northeast, Thousand Miles Southeast, 7.3 Offshore, 3.6 Northeast, Thousand Miles Midwest, ,700 to 61,600 miles of new pipeline capacity will be added from 2009 through Almost half of the new pipeline capacity is added in the Central and Southwest (Gas Producing Areas) in the U.S. 27

28 Compression Additions Horsepower Added Each Year Horsepower of Compression (1000s) 1,400 1,200 1, Base Case MacKenzie Project Alaska Project Horsepower of Compression (1000s) 1,400 1,200 1, Alternate Case MacKenzie Project Alaska Project Alaska / Arctic 1 New Expansion Lateral Alaska / Arctic 1 New Expansion Lateral 2 1 Includes cost of downstream expansions on existing corridors in the U.S. and Canada in addition to the cost of arctic Canada and Alaska frontier projects. 2 Lateral is defined as a spur off the main transmission line, normally used to connect production, storage, power plants, LNG terminals or isolated demand centers. 1 Includes cost of downstream expansions on existing corridors in the U.S. and Canada in addition to the cost of arctic Canada and Alaska frontier projects. 2 Lateral is defined as a spur off the main transmission line, normally used to connect production, storage, power plants, LNG terminals or isolated demand centers. From 2009 through 2030, between 370,000 to 530,000 horsepower will be added for new pipeline capacity each year. These additions are fairly consistent with recent levels. Much of the recently constructed capacity may be expanded by adding compression. Arctic projects will require over 1,000,000 horsepower of compression. 28

29 Regional Breakout for Added Compression from 2009 through 2030 Base Case Alternate Case Western, 0.5 Arctic, 0.3 Canada, 1.0 Western, 0.8 Arctic, 0.3 Canada, 1.3 Southwest, 1.7 Southwest, 2.6 Central, 1.6 Central, 2.3 Southeast, 1.2 Midwest, 0.7 Offshore, 0.5 Northeast, Million Horsepower Southeast, 1.5 Midwest, 1.1 Offshore, 1.0 Northeast, Million Horsepower 8.1 to 11.6 million horsepower of compression for new pipeline capacity will be added from 2009 through Almost half of the new compression is added in the Central and Southwest (Gas Producing Areas) in the U.S. 29

30 Costs of Pipelines and Compression All Costs Reported in Nominal Dollars $1000s per Inch-Mile $110 $100 $90 $80 $70 $60 $50 $40 Misc. Labor Material R.O.W. Historical Pipeline Costs Projection Dollars per Horsepower $2,500 $2,000 $1,500 $1,000 Misc. Labor Material Land Historical Compression Costs Projection $30 $20 $500 $10 $0 $ Average of large-diameter gas pipelines 30 to 36 inches FERC data compiled by Oil & Gas Journal 2010 to 2030 projections by cost component is based on trends from 1993 to Micellaneus includes includes surveys, engineering, supervision, interest, administration, overheads, contingencies, allowances for funds used during construction (AFUDC) and FERC fees. Regional Comparison of Costs (Index =1.0) Region Pipeline Compression Canada Central Midwest Northeast Offshore 0.86 na Southeast Southwest Western Grand Total Historical costs compiled by Oil & Gas Journal 2010 to 2030 projections by cost component is based on trends from 1999 to Micellaneus includes includes surveys, engineering, supervision, interest, administration, overheads, contingencies, allowances for funds used during construction (AFUDC) and FERC fees. Recent pipeline costs rose to over $100,000 per inchmile of pipe. Future pipeline costs bottom at about $60,000 per inch-mile of pipe after the recession, and escalate at about 2% per year thereafter. Recent compression costs have been almost $2,000 per horsepower. Future compression costs bottom at near $1,600 per horsepower after the recession, and rise at about 1% per year thereafter. Regional costs vary by up to 50 percent. Costs are highest in the Northeast U.S. and lowest in producing areas. 30

31 Capital Expenditures for New Pipeline Capacity Million Dollars (Nominal$) Spent Each Year, Including the Cost of Compression Millions of Dollars 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 Alaska / Arctic 1 New Expansion Lateral 2 Base Case MacKenzie Project Alaska Project Millions of Dollars 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 Alaska / Arctic 1 New Expansion Lateral2 Alternate Case 4,000 4,000 2,000 2, MacKenzie Project Alaska Project 1 Includes cost of downstream expansions on existing corridors in the U.S. and Canada in addition to the cost of arctic Canada and Alaska frontier projects. 2 Lateral is defined as a spur off the main transmission line, normally used to connect production, storage, power plants, LNG terminals or isolated demand centers. 1 Includes cost of downstream expansions on existing corridors in the U.S. and Canada in addition to the cost of arctic Canada and Alaska frontier projects. 2 Lateral is defined as a spur off the main transmission line, normally used to connect production, storage, power plants, LNG terminals or isolated demand centers. From 2009 through 2030, the annual expenditure for new pipeline capacity will average between $6 and $8 billion. Somewhat above recent expenditures that have averaged $4 to $5 billion per year. Arctic pipeline projects will account for 30 to 40 percent of the total expenditures over the period. Without the Arctic projects, expenditures would only average $3 to $5 billion per year, more closely aligning with recent averages. 31

32 Regional Breakout for Capital Expenditures for New Pipeline Capacity from 2009 through 2030 Base Case Alternate Case Southwest, $17.6 Western, $7.3 Arctic, $24.0 Southwest, $27.6 Western, $8.7 Arctic, $24.0 Southeast, $14.3 Offshore, $3.6 Canada, $30.6 Southeast, $15.4 Canada, $33.0 Northeast, $6.7 Offshore, $6.3 Midwest, $8.4 Central, $17.0 $129.5 Billion Northeast, $10.1 Midwest, $12.9 $162.8 Billion Central, $24.8 $129.5 to $162.8 billion will be spent for new pipeline capacity from 2009 through The vast majority of the expenditures are concentrated in the Arctic Projects and within producing areas in the U.S. 32

33 Summary of Pipeline Integrity Management According to a recent INGAA survey of 10 interstate pipelines that operate 120,000 miles of pipeline: 54% of all of the HCA (High Consequece Area) miles were inspected by the end of 2007, exceeding the regulatory requirement of 50%. From 2004 to 2007, less than 2 miles of pipeline in HCAs has been replaced as a result of integrity management. From 2004 to 2007, approximately 22 miles of pipeline has been replaced in non HCA locations. Nearly half of the damage in HCAs is due to 3 rd parties (excavation). Replacement of pipeline due to pipeline integrity inspections is very limited. Source: Process Performance Improvement Consultants, LLC The Impact of the Integrity Management Program on Gas Transmission Pipelines Summary of results for

34 Base Case Gas Storage Additions (Bcf), % Western Canada Depleted Reservoir/ Aquifer Salt Cavern Total +6% Eastern Canada Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity Capacity Additions Total Working Gas Capacity Daily Deliverability 2030 (Bcfd) Working Gas Capacity Capacity Additions Total Working Gas Capacity Daily Deliverability 2030 (Bcfd) % US/Canada Total West Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity Capacity Additions Total Working Gas Capacity Daily Deliverability 2030 (Bcfd) % +10% Central/Midwest Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity , ,497 Capacity Additions Total Working Gas Capacity , ,950 Daily Deliverability 2030 (Bcfd) Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity , ,364 Capacity Additions Total Working Gas Capacity , ,403 Daily Deliverability 2030 (Bcfd) % East Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity Capacity Additions Total Working Gas Capacity Daily Deliverability 2030 (Bcfd) % Producing Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity , ,228 Capacity Additions Total Working Gas Capacity , ,459 Daily Deliverability 2030 (Bcfd)

35 Alternate Case Gas Storage Additions (Bcf), % Western Canada Depleted Reservoir/ Aquifer Salt Cavern Total +10% Eastern Canada Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity Capacity Additions Total Working Gas Capacity Daily Deliverability 2030 (Bcfd) Working Gas Capacity Capacity Additions Total Working Gas Capacity Daily Deliverability 2030 (Bcfd) % West Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity Capacity Additions Total Working Gas Capacity Daily Deliverability 2030 (Bcfd) % +13% Central/Midwest US/Canada Total Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity , ,497 Capacity Additions Total Working Gas Capacity , ,095 Daily Deliverability 2030 (Bcfd) Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity , ,364 Capacity Additions Total Working Gas Capacity , ,413 Daily Deliverability 2030 (Bcfd) % East Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity Capacity Additions Total Working Gas Capacity Daily Deliverability 2030 (Bcfd) % Producing Depleted Reservoir/ Aquifer Salt Cavern Total Working Gas Capacity , ,228 Capacity Additions Total Working Gas Capacity , ,549 Daily Deliverability 2030 (Bcfd)

36 Costs and Expenditures for New Gas Storage Capacity All Values in Nominal Dollars Storage construction costs in 2007 ranged from $6.7 to $13.8 million for each billion cubic foot of working gas capacity. The non-base gas portion of the cost is assumed to escalate at 2% per year and the base gas portion changes along with gas prices in the cases. Regional costs vary significantly (by well over 100 percent). Total expenditures for new storage capacity from 2009 through 2030 range between $4.0 and $5.2 billion. These expenditures are well below pipeline and compression expenditures. Regional Comparison of Costs (Index =1.0) Assuumed Year Costs Region Factor Storage $Million's Costs per Bcf Working in Gas Capacity Canada 0.88 Field Type Expansion New Central 1.03 Salt $6.7 $8.4 Midwest 0.77 Depleted $4.9 $6.6 Northeast 1.83 Aquifer $10.9 $13.6 Southeast 1.10 Southwest 1.18 Non-base gas costs escalated at 2% per year. Western 0.93 Base gas costs adjusted for projected gas prices. Grand Total Million dollars per billion cubic feet of working gas capacity. Base Case Expenditures from 2009 through 2030 Southwest, $0.9 Western, $0.4, Canada, $0.3 Central, $0.2 Midwest, $0.3 Northeast, $0.8 Alternate Case Expenditures from 2009 through 2030 Southwest, $1.3 Western, $0.5, Canada, $0.4 Central, $0.2 Midwest, $0.4 Northeast, $1.0 Southeast, $1.0 $4.0 Billion, Southeast, $1.4 $5.2 Billion 36

37 Summary of Pipeline and Stroage Development From 2009 Through 2030 U.S. and Canada Gas Market Growth (Trillion Cubic Feet) Interregional Gas Transport Capability (Billion Cubic Feet Per Day) Storage Working Gas Capacity (Billion Cubic Feet) Base Case Alternate Case +4.9 (+18%) +9.1 (+34%) +25 (+20%) +37 (+30%) +453 (+10%) +598 (+13%) Added Pipeline Mileage 37,700 Total Miles 1,700 Miles Per Year 61,600 Total Miles 2,800 Miles Per Year Added Horespower of Compression for Pipelines 8.1 Million HP 370,000 HP Per Year 11.6 Million HP 530,000 HP Per Year Capital Expenditures for New Pipeline and Storage Capacity ~ $135 Billion ~ $6 Billion Per Year ~ $170 Billion ~ $8 Billion per Year 37

38 Other Midstream Development From 2009 Through 2030 Base Case Alternate Case Gathering Line Mileage +18,200 miles $13.8 Billion +26,000 miles $21.6 Billion Gas Processing Capacity Bcfd $10.1 Billion Bcfd $18.5 Billion LNG Import Capacity +3.0 Bcfd $1.5 Billion +3.0 Bcfd $1.5 Billion Capital Expenditures for All Midstream Infrastructure Development Will Range from $160 to $210 Billion from 2009 through

39 Issues and Conclusions 39

40 Potential Issues Regarding Pipeline and Storage Expansion Unclear direction for energy and carbon policies. Gas is not a slam dunk in the power sector. Market longevity is an issue. Negative bias of some policy makers toward natural gas. Future gas supply development is risky because of gas price uncertainty. Capital for expansions is difficult to arrange. Creditors are concerned about financing in an environment where the average length of pipeline contracts has shortened. Credit risk of capacity subscribers is also an issue. Difficulty securing commitments for capacity from shippers. Siting, right of way, access, and environmental issues persist. Regulatory process is cumbersome. Escalating construction costs, mostly driven by factors that are beyond the control of pipeline companies. 40

41 Potential Undertakings to Promote Natural Gas Work with policy makers and government officials to develop carbon neutral policies and energy policies that do not unfairly penalize natural gas. Expand and improve public relations efforts to widely promote and publicize natural gas as an environmentally friendly fuel. Form strategic alliances with renewables participants to promote co-use of renewables and natural gas to create a clean energy future. Expand efforts to promote natural gas use in fleet vehicles and long-haul trucking industry. Avoid promoting potentially divisive issues that have limited benefit. 41

42 Conclusions Significant gas market growth is expected during the next 20 years. Market will grow by between 18 and 34 %. Most of the growth will occur in the power sector. Electric load growth, renewables penetration, penetration of clean coal with carbon capture, and expansion of nuclear generation are areas of uncertainty. The North American natural gas resource base is robust and E&P technology advancements have significantly progressed development of unconventional gas supplies. The future is bright for these supplies and the industry should tout the supplies as a cost-effective domestic energy source for our future. Robust market growth with development of new supplies necessitates development of gas infrastructure. Needs for interregional gas transport are likely to increase by between 25 and 37 Bcfd, driving development of additional pipeline and storage capacity. 42

43 Conclusions (continued) 37,700 to 61,600 miles of new pipeline capacity will be needed from 2009 through million to 11.6 million HP of new compression will be needed. 450 to 600 Bcf of new gas storage capacity will be needed. Capital expenditures for new infrastructure will range from $160 to $210 billion from 2009 through Expansion of gas infrastructure is not a slam dunk. Many issues loom, particularly uncertainties regarding direction of energy and environmental policies and whether those policies will promote or discourage gas use. The industry would be well served to work with policy makers to develop balanced policies that do not unfairly penalize natural gas. An extensive public relations effort to widely promote natural gas as an environmentally friendly fuel may establish public support for the product. 43

44 Pipeline and Storage Infrastructure Projections through 2030 INGAA Foundation Spring Meeting April 16, 2009 Kevin R. Petak, Vice President, Gas Market Modeling Geoffrey N. Brand PhD, Project Manager, Gas Market Modeling ICF International