ASSESSMENT OF NATURAL GAS COMMODITY OPTIONS FOR CENTRA MANITOBA

Transcription

1 ASSESSMENT OF NATURAL GAS COMMODITY OPTIONS FOR CENTRA MANITOBA Prepared for: CENTRA MANITOBA FINAL REPORT Submitted By: ENERGY AND ENVIRONMENTAL ANALYSIS, INC N. Fort Myer Drive, Suite 600 Arlington, Virginia USA (703) Contacts: Bruce Henning Michael Sloan January 2007

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3 ABOUT ENERGY AND ENVIRONMENTAL ANALYSIS, INC. Energy and Environmental Analysis (EEA), located in metropolitan Washington, D.C., is a nationally recognized consulting firm offering technical, analytical, and management consulting services to a diverse clientele. Founded in 1974 to perform economic, engineering, and policy analysis in the energy and environmental fields, EEA has exhibited leadership and innovation in investigating energy and environmental issues. DISCLAIMER This report includes forward-looking statements and projections. Energy and Environmental Analysis, Inc. (EEA) 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 results to differ materially from the projections, anticipated results or other expectations expressed in this report, including, but not limited to, general economic and weather conditions in geographic regions or markets that may affect the gas market.

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5 EEA Final Report January 2007 TABLE OF CONTENTS 1 EXECUTIVE SUMMARY Introduction Fundamental Findings and Recommendations Conclusions that shape the Gas Contracting Strategy Gas Market Fundamentals Affecting Supply Options for Centra Gas Fundamentals that should be considered in the development and evaluation of alternatives to the Baseline service Evaluation of Alternatives 8 2 OVERVIEW OF ISSUES AND APPROACH Scope of Report Structure of Report 12 3 OVERVIEW OF CENTRA S OPERATIONS Centra Natural Gas Demand Forecasted Demand Peak Day Demand Impact of Manitoba Weather on Supply Planning Centra Gas Pipeline and Storage Capacity Transportation and Storage Contracts Centra Gas Supply Arrangements Stakeholder Concerns 34 4 SUSTAINABLE DEVELOPMENT ISSUES Review of Sustainable Development Issues Findings 38 Energy and Environmental Analysis, Inc. i

6 EEA Final Report January THE NORTH AMERICAN GAS MARKET Introduction Overview of Broad North American Market Trends Natural Gas Prices Changes in Natural Gas Supply and Transportation Patterns Impact of Demand and Production Trends on TransCanada Impact of Market Changes on Relative Gas Market Prices Impact of Market Changes on Natural Gas Price Volatility Value of Storage Market Liquidity and Alternative Sources of Natural Gas Supply Natural Gas Market Liquidity Manitoba Natural Gas Market Storage Potential 62 6 STRATEGY DEVELOPMENT FOR PRIMARY GAS ACQUISITION Introduction Strategic Framework Centra Supply Strategy Impact of TransCanada Tariff Structure on Centra Options Sources of Gas Supply: Basin Options and Analysis of Basin Diversification Sources of Gas Supply to Meet Primary Flowing Gas Demand Sources of Gas Supply for Seasonal Injection into Michigan Storage Potential Sources for U.S. Natural Gas Purchases Peaking Services Requirements and Analysis Implications for Phase 2 Analysis Requirements For and Anticipated Costs of Swing Service Comments on the Nature of Swing Service Changes in Outlook for Alberta Sourced Swing Service Storage as an Alternative to Swing Service Contracts with Marketers vs. Contracts with Producers for Primary Gas Supply Ownership of Production as a Source of Primary Gas Supply Implications of Marketer Requests for Changes to WTS 77 7 RECOMMENDATIONS AND NEXT STEPS FOR REPLACING THE CURRENT PRIMARY GAS SUPPLY CONTRACT WITH NEXEN 79 Energy and Environmental Analysis, Inc. ii

7 EEA Final Report January Extension of the Existing Nexen Contract and Context for the RFP Process RFP Development Identification of Bidder List Requested Term for RPF Responses Evaluation of Responses to the RFP 83 Energy and Environmental Analysis, Inc. iii

8 EEA Final Report January 2007 LIST OF TABLES TABLE 1 SCORING SHEET FOR ALTERNATIVE SUPPLY OPTIONS...9 TABLE 2 ANNUAL HEATING DEGREE DAYS...20 TABLE 3 DAILY VOLATILITY OF REGIONAL WEATHER ( )...20 TABLE 4 CENTRA PEAK DAY SUPPLY PORTFOLIO 2005/ TABLE 5 SUMMARY OF CENTRA PIPELINE AND STORAGE CONTRACTS...27 TABLE 6 TOP 40 COMPANIES HOLDING CAPACITY ON TRANSCANADA...29 TABLE 7 U.S. AND CANADA PRODUCTION (BCF PER YEAR)...43 TABLE 8 AVERAGE DAILY TRANSACTION VOLUMES...59 TABLE 9 VOLATILITY OF DAILY TRANSACTION VOLUMES...60 TABLE 10 MAJOR MARKETERS HOLDING CAPACITY IN THE COMPETITIVE MARKET REGION...82 TABLE 11 SCORING SHEET FOR ALTERNATIVE SUPPLY OPTIONS...85 Energy and Environmental Analysis, Inc. iv

9 EEA Final Report January 2007 LIST OF FIGURES FIGURE 1 EEA LONG-TERM FORECAST OF BASIS BETWEEN AECO AND OTHER MAJOR NATURAL GAS MARKETS...6 FIGURE 2 EEA NEAR-TERM FORECAST OF BASIS BETWEEN AECO AND OTHER MAJOR NATURAL GAS MARKETS...7 FIGURE 3 CENTRA MANITOBA NATURAL GAS CUSTOMERS...16 FIGURE 4 CENTRA MANITOBA NATURAL GAS DELIVERIES FIGURE 5 EEA FORECAST OF MANITOBA NATURAL GAS DEMAND IN THE RESIDENTIAL AND COMMERCIAL SECTORS...17 FIGURE 6 MONTHLY NORMAL TRADITIONAL HEATING DEGREE DAYS...19 FIGURE CENTRA MANITOBA DEMAND (TJ/DAY)...21 FIGURE 8 CENTRA MANITOBA LOAD PROFILE FIGURE 9 COMPARISON OF CENTRA MANITOBA AND NEW ENGLAND LOAD PROFILES...22 FIGURE 10 COMPARISON OF CENTRA MANITOBA AND NEW ENGLAND LOAD PROFILES...23 FIGURE 11 WEATHER VARIATION IN CENTRA MANITOBA LOAD DURATION CURVES...24 FIGURE 12 LOCATION OF CENTRA MANITOBA PIPELINE AND STORAGE ASSETS...26 FIGURE 13 PROJECTED U.S. AND CANADA NATURAL GAS CONSUMPTION (TCF PER YEAR)...43 FIGURE 14 PROJECTED NORTH AMERICAN LNG IMPORTS BY REGION (BCFD)...44 FIGURE 15 PROJECTED GAS PRICES (2005 C$ PER GJ)...45 FIGURE 16 IMPACT OF WEATHER ON AECO NEAR-TERM PRICES...46 FIGURE 17 AVERAGE FLOWS, 2005 (MMCFD)...47 FIGURE 18 INTERREGIONAL CHANGES IN PIPELINE FLOW 2005 TO 2015 (MMCFD)...48 FIGURE 19 HISTORICAL NATURAL GAS FLOWS THROUGH MANITOBA ON TRANSCANADA...49 FIGURE 20 WCSB NATURAL GAS PRODUCTION FORECAST...50 FIGURE 21 EEA NATURAL GAS DEMAND FORECAST FOR ALBERTA AND SASKATCHEWAN...50 FIGURE 22 FORECASTED DISPOSITION OF ALBERTA/SASKATCHEWAN NATURAL GAS SUPPLY...51 FIGURE 23 FORECASTED DISPOSITION OF TRANSCANADA PIPELINE FLOWS INTO MANITOBA...52 FIGURE 24 AVERAGE DAILY NATURAL GAS PRICE BASIS RELATIVE TO AECO...53 FIGURE 25 EEA LONG-TERM FORECAST OF BASIS BETWEEN AECO AND OTHER MAJOR NATURAL GAS MARKETS..53 FIGURE 26 EEA NEAR-TERM FORECAST OF BASIS BETWEEN AECO AND OTHER MAJOR NATURAL GAS MARKETS..54 FIGURE 27 SEASONAL ARBITRAGE VALUE OF NATURAL GAS STORAGE...56 FIGURE 28 DAILY NATURAL GAS TRANSACTIONS VOLUMES...59 Energy and Environmental Analysis, Inc. v

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11 EEA Final Report January EXECUTIVE SUMMARY 1.1 Introduction Centra Gas Manitoba Inc. ( Centra ) is a wholly owned subsidiary of Manitoba Hydro. Manitoba Hydro is a Crown Corporation headquartered in Winnipeg, Manitoba and the major energy utility for the Province. Centra serves approximately 258,000 residential, commercial, and industrial natural gas customers throughout southern Manitoba. Gas consumers that receive deliveries from Centra have the option of obtaining their primary gas supply from either Centra or from a third party marketer. As the major distributor of natural gas in the province, Centra retains a continuing responsibility to ensure that the requirements of all of its distribution customers are satisfied, including those who elect to purchase their gas supply from others. Centra s existing natural gas supply portfolio is based primarily on purchases of natural gas commodity from the Western Canadian Sedimentary Basin (WCSB), and transported to the Centra Manitoba service territory using capacity held by Centra on the TransCanada Pipeline. Currently, all of the primary gas supply purchased by Centra and delivered to the TransCanada pipeline is purchased according to the terms of a single contract with Nexen. The contract with Nexen will expire on October 31, 2007, unless Centra and Nexen mutually agree to extend the contract prior to May 1, 2007 EEA has been retained to provide a recommendation as to the most cost effective manner in which to replace or renew this existing supply contract in the context of Centra s existing portfolio of transportation and storage arrangements. EEA has also been retained to assist with the development of a request for proposals to solicit bids to meet the supply requirements, and to assist with the development of formal criteria to assess alternative contract proposals by different parties as appropriate. 1.2 Fundamental Findings and Recommendations EEA has decomposed the various attributes of the objectives identified in the scope of work in order to identify and examine the trade-offs inherent in developing a strategy for evaluating gas supply alternatives. A fundamental conclusion of the analysis is that the structure of the existing contract represents an appropriate baseline against which to evaluate the structure of a new gas supply agreement. However, given the changes in the supply and demand balance in gas production in the WCSB Energy and Environmental Analysis, Inc. 1

12 EEA Final Report January 2007 and the broader North American gas market, one should not expect that responses to an RFP that is structured to reproduce the terms of service provided by the current contract will be obtained under the same or better pricing terms. EEA estimates that the near-term increase in costs could result in swing service cost premiums increasing from $0.025 per GJ to $ $0.04 per GJ for the equivalent of the Nexen tranche one swing service, and increase from $0.05 to between $0.08 and $0.12 per GJ for incremental swing service equivalent to the Nexen tranche two swing service. An extension of the Nexen contract with pricing terms similar to the existing formula would represent a favourable outcome given the changes that have occurred in the North American gas commodity market and in the supply demand balance in the WCSB. Centra is and will remain a modestly-sized purchaser of gas that is participating in a market with much larger purchasers (e.g., other LDCs) along the TransCanada Pipeline system. The large market in which Centra participates is not a highly concentrated market, but does have a number of participants that are considerably larger than Centra. These larger participants are better situated to generate economies of scale and manage elements of risk related to commodity acquisition than Centra. A basic objective of the gas contracting strategy should be: To encourage proposals that generate cost efficiencies from these attributes; and, Capture a significant portion of the cost efficiencies to the direct benefit of Centra customers. Assuming that negotiations to extend the existing contract cannot be successfully completed, the gas supply strategy should incorporate an approach that fosters the creative aspects of competitive bids in order to create a supply agreement with the favorable attributes of the existing Nexen contract. To accomplish this, the RFP process should solicit and strongly encourage alternatives. The RFP should, therefore, request bidders to submit proposals that include a baseline supply transaction, as well as alternatives. The RFP should outline the basic structure of agreements that Centra is willing to consider. Energy and Environmental Analysis, Inc. 2

13 EEA Final Report January Conclusions that shape the Gas Contracting Strategy 1) The absence of seasonal and/or high delivery storage in the immediate area has implications for the gas contracting strategy that cannot be understated. 1 The lack of local storage results in all of the costs of load following, swing and variability of takes that cannot be addressed through the use of storage in Michigan being internalized in the gas commodity contract and are therefore allocated exclusively to the utility sales customers. By contrast, markets with significant amounts of storage (e.g. Ontario) can allocate the costs of swing and flexibility to all customers through the inclusion of storage costs in the delivery charges recouped on all delivery volumes irrespective of the customer s election of utility system supply or a third party supplier. 2) Several third-party marketers voiced the strong desire that Centra evaluate gas supply alternatives with an eye towards modifying the current protocol that allocates the daily variability in gas load proportionally to all gas suppliers on an equal basis EEA recommends that Centra not subordinate the objectives of pursuing minimizing the cost of supply and providing price stability to meeting the requests of the thirdparty marketers. EEA makes this recommendation for two reasons: a) First, adopting such an approach may not be sustainable. Currently, system sales constitute approximately 81 percent of the total volume of gas sold to residential customers in A contract that cross-subsidizes customers of third-party marketers at the expense of system sales customers could well increase the cost of gas for system sales customers relative to market based offerings by one to two cents per GJ or more. If however, the portion of system sales declined to 40 percent, then the impact on the remaining customers would roughly double. Ultimately, there is a risk that there could be insufficient volume providing swing capability to meet the actual requirements if the percentage of the load served by system supply continued to decline. b) Second, Centra could risk prudence disallowances based on a failure to acquire gas in a prudent manner. To the extent that such a contract results in additional costs beyond those required for proportional swing services and the MPUB has not explicitly addressed the recovery of those costs, Centra incurs additional regulatory risk. 3) Any RFP for a new natural gas supply agreement should establish a baseline service that is structured along the lines of the existing supply agreement. The baseline should specify an intermediate term of two to four years. The recommendation is based on several factors including: 1 Centra holds contract capacity on the ANR system providing access to storage in Michigan. However, this storage provides seasonal gas supplies that augment flowing gas. Energy and Environmental Analysis, Inc. 3

14 EEA Final Report January 2007 a. The timing of pipeline expansion projects that will increase the capacity to move gas supplies from the Rocky Mountains in the United States to markets in Illinois and further east. Construction of these pipelines would access additional supplies that could remove some of the pressure on WCSB supplies. A contract that expires after the completion of one or more of these projects would be favorable to future negotiations. b. An agreement of two to four years would allow for subsequent negotiations to be conducted after a review of existing pipeline and storage capacity contracts that was described as a Phase Two analysis in the original RFP for this study effort. 1.3 Gas Market Fundamentals Affecting Supply Options for Centra Gas 1) The balance between supply and demand over the past several years has been tight with little or no spare or surge production capacity. The absence of spare capacity has resulted in extreme gas price volatility and periods where gas prices were extremely high compared to gas prices that prevailed prior to the year In general, the period from 2000 through 2006 can be described as demand leading supply. Irrespective of the break in gas prices that has occurred in the last several months, these market conditions that have lead to high and volatile prices are likely to continue. a) The recent price break for natural gas is a result of combination of factors that are not likely to be repeated anytime in the next several years. These factors include: i) The much warmer than normal weather during the winter season (approximately eight percent below the 30 year norm), resulted in significantly more gas than normal remaining in storage at the end of the winter. The volume of working gas remaining in storage in North America at the end of March was 2,019 Bcf, which is 60 percent above the average of the past five years. 2 ii) Prices in the summer of 2006 that were supported by high oil prices (peaking above $75 (U.S.) per barrel and the concern that production losses due to hurricanes would be similar to the losses that occurred in the summer and fall of These high prices reduced industrial and power generation somewhat, thereby making even more gas available for injection into storage. 2 One should note that the five-year average itself reflects remaining working gas levels that are higher than would be expected for normal weather because actual weather has been warmer than the 30 year norm in all of the last five years. Energy and Environmental Analysis, Inc. 4

15 EEA Final Report January 2007 iii) Working gas in storage is approaching record levels and gas that is not being consumed in September and October (historically low consumption months) is in competition for the limited storage space that is remaining. b) Assuming that weather patterns over the next 24-months approach the 30- year norms, EEA projects that prices at AECO will rebound in 2007 and 2008 to $7.00 to $8.00 per MMBtu (U.S. $). 3 However, the standard deviation of the forecast prices in EEA s price probability distribution 4 is larger than EEA would normally expect, indicating that prices, which are always affected by actual weather, are even more uncertain than normal. 2) Gas production in the Western Canadian Sedimentary Basin (WCSB) is unlikely to keep pace with growth in natural gas demand in Manitoba, Central and Eastern Canada, and North America. 3) Gas demand in Alberta is projected to grow by an average of about three percent per year for 2006 through 2015, driven by consumption of gas in oil sand projects, power generation, and continued general economic growth. Given this growth in demand, gas supplies available for export from Alberta are likely to decline. a) While the completion of a pipeline that brings supplies from the Mackenzie Delta would add incremental gas supplies in the range of 1.2 to 1.7 Bcf per day, which could be available by 2011, this volume is not sufficient to stabilize or grow the volume of gas available for export from Alberta. b) Gas supplies from the North Slope of Alaska are unlikely to be available to Canadian and Lower-48 U.S. markets prior to Moreover, there is a risk that the completion of a natural gas pipeline from Alaska continues to be a pipe dream from the perspective of gas supply planning. 4) With reduced volumes of gas available for export from Alberta, the basis between the gas price at AECO and prices at other liquid market centers in Central and Eastern Canada, and U.S. markets in the Midwest and Gulf Coast is likely to fall. a) The basis from AECO to Dawn, Chicago, and other markets (including Henry Hub) has been quite volatile over the last five years. This volatility will likely continue. i) The expansion in basis observed in the last year was significantly influenced by the residual impacts of hurricanes Katrina and Rita and 3 EEA Monthly Gas Update, October EEA prepares a probabilistic forecast of near term natural gas prices to evaluate the potential impact of weather on natural gas prices. This probabilistic forecast is based on 74 different forecasts using actual weather for 74 historical years. The results of this analysis for AECO are shown in Figure 16 in Section five of this report. Energy and Environmental Analysis, Inc. 5

16 EEA Final Report January 2007 weather patterns that placed a premium on moving gas from production areas to market area storage. ii) These impacts are likely to be transient and the basis will likely compress as infrastructure continues to be returned to service and assuming more normal weather patterns (Figure 1 and Figure 2). b) The basis from AECO to Dawn, Chicago, (and to a lesser extent, other markets including Henry Hub) will continue to be affected by ratemaking strategies and service offerings implemented by TransCanada Pipeline and approved by the National Energy Board of Canada. Issues such as the availability of diversions, segmentation, and the established floor price for Interruptible Transportation as well as the proposed conversion of existing gas transmission capacity to an oil pipeline (The Keystone Project) will affect basis. Nevertheless, EEA believes that the fundamental forces in the gas markets will result in basis compression in spite of the actions of TransCanada. These actions, however, will likely add to the volatility of basis and increase the uncertainty and risk of contracting for deliveries on TransCanada. Figure 1 EEA Long-Term Forecast of Basis Between AECO and Other Major Natural Gas Markets Source: Energy and Environmental Analysis, $2.00 $1.50 $1.00 Henry Hub, Louisiana Chicago, Illinois Dawn, Ontario Opal, Wyoming Kansas/Oklahoma (2005 C$/GJ) $0.50 $- $(0.50) $(1.00) $(1.50) Energy and Environmental Analysis, Inc. 6

17 EEA Final Report January 2007 Figure 2 EEA Near-Term Forecast of Basis Between AECO and Other Major Natural Gas Markets Source: Energy and Environmental Analysis, (2005 C$/GJ) $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- $(0.50) $(1.00) Henry Hub, Louisiana Chicago, Illinois Dawn, Ontario Opal, Wyoming Kansas/Oklahoma Jan-05 May-05 Sep-05 Jan-06 May-06 Sep-06 Jan-07 May-07 Sep-07 Jan-08 May-08 Sep-08 Jan-09 May-09 Sep-09 Jan-10 May-10 Sep Fundamentals that should be considered in the development and evaluation of alternatives to the Baseline service The alternatives should be designed to reflect the changing fundamentals of North American gas markets over the next five to 10 years. These fundamentals include: 1) In future years, the price of gas at AECO is likely to lose some of its advantage in terms of basis compared to other supply basins and market centers. As a result, diversification away from a gas supply contract that relies exclusively on AECO prices should be explored completely. Such diversification can be accomplished in a number of ways. 2) Larger market participants have greater opportunities to generate cost savings from economies of scale and the management of market specific risk than does Centra directly. A number of these participants conduct business both upstream and downstream of Manitoba, which provides opportunity to mitigate marketspecific risk. i) Market specific risk refers to elements of volatility and uncertainty that are directly related to buying gas in a limited geographic market for a limited class of customers. Currently, Centra is subject to considerable market- Energy and Environmental Analysis, Inc. 7

18 EEA Final Report January 2007 specific risk for system sales in that the volume is dominated by temperature sensitive residential and commercial customers in Manitoba. 5 ii) Centra s current supplier of primary gas, Nexen, is one such participant that has the opportunity to generate economies of scale and mitigate market-specific risk They are not the only entity, but are perhaps best positioned to construct a supply offering that generates efficiencies Evaluation of Alternatives As noted above, an extension of the Nexen contract with pricing terms similar to the existing formula would represent a favourable outcome given the changes that have occurred in the North American gas commodity market and in the supply demand balance in the WCSB, and EEA recommends pursuing an extension of the existing contract. However, in the event that a renegotiation of the Nexen contract cannot be successfully completed with pricing terms similar to the existing agreement, a process to evaluate multiple alternative proposals will be required. To manage the process and to provide structure for the comparison of various bids, a Scoring Model that considers the various elements of the proposals and how they fit with the identified objectives could be applied to each bid received. The Scoring Model consists of a matrix of critical elements of service. Table 1 presents the initial proposal for the elements of the Scoring Model. The final structure of the elements of the model will be determined after consultation with Centra staff. The key to this approach is the identification and weighting of different contract elements in the final decision-making process. The approach is not intended to be mechanistic, but is instead intended to provide a quantitative framework for a qualitative comparison of alternatives. 5 At some time in the future, Centra, as a subsidiary of Manitoba Hydro, may be required to include gas supply planning for the Manitoba Hydro natural gas-fired power generation capacity. Given the very low load factors for these plants, inclusion of this requirement would tend to increase some aspects of market-specific risk in the gas portfolio, but likely would lead to benefits on the power generation side. This type of integration requires careful review and inclusion of the Regulators to determine the appropriate approach. In some jurisdictions, the regulatory framework developed has reduced or eliminated the cost benefits of convergence between gas and electric service. In-depth analysis and consideration of this alternative was considered beyond the scope of this effort. Nevertheless, the issue should be explored in the future. Energy and Environmental Analysis, Inc. 8

19 EEA Final Report January 2007 Table 1 Scoring Sheet for Alternative Supply Options Source: Energy and Environmental Analysis, Inc. Description of Option: Example Scoring Sheet for Alternative Supply Options Total Category Weight \* Sub Category Weight \* Minimum Acceptable Score \* Option Score (0-10) Weighted Score 1) Provides Reliable Supply Reliable Supply to Firm Customers Reasonable Service to Interuptible Customers ) Minimizes Total Cost of Supply Minimize commodity costs Minimize Fixed Asset Costs Minimize Internal Gas Supply Management Costs ) Meets Customer Objectives Price Stability Price Transparency ) Meets Direct Purchase Customer Objectives Provide Operational Nominations Flexibility Provide Customer Nominations Flexibility ) Meets Regulator Guidelines and Objectives ) Consistent with other Corporate Goals Sustainable Development Reduced Environmental Impacts Local Content Minimize Regulatory Risk Other Total of All Categories */ Category weights and minimum acceptable scores are preliminary, and are included for illustrative purposes only. Energy and Environmental Analysis, Inc. 9

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21 EEA Final Report January OVERVIEW OF ISSUES AND APPROACH 2.1 Scope of Report EEA has been retained to provide a recommendation as to the most cost effective manner in which to replace or renew this existing supply contract in the context of Centra s existing portfolio of transportation and storage arrangements. EEA has also been retained to assist with the development of a request for proposals to solicit alternative supply options and to assist with the development of formal criteria for the assessment of alternative contract proposals by different parties as appropriate. EEA has not been asked to specifically assess the mix of pipeline and storage capacity held by Centra. While the mix of pipeline and storage capacity held under contract is a key part of a long-term supply strategy, Centra intends to address the issues related to this mix after consideration of the replacement supply contract as a second phase to the current process. EEA has addressed the pipeline and storage capacity question to the extent necessary to understand Centra s current market environment, and to evaluate and make recommendations concerning the gas supply portfolio and the extension, renegotiation, or replacement of the current Nexen contract. This report provides an assessment of Centra s current transportation and storage arrangements, as well as EEA s assessment of natural gas market factors likely to influence Centra s supply strategy. The report also provides a description of feasible supply sources given those arrangements, as well as a series of recommendations concerning key issues to be considered and potential alternative supply strategies to be evaluated in the process of replacing or renewing the existing supply contract with Nexen. Although the goal of LDC gas procurement is often stated as finding the most cost effective option or least cost option, there are usually several goals that must be considered and balanced. These include: Provide adequate supply to firm customers and a reasonable level of service to interruptible customers Minimize cost of supply Stabilize price as much as practical Energy and Environmental Analysis, Inc. 11

22 EEA Final Report January 2007 Maintain flexibility on takes Avoid other costs (new transportation and storage costs) Assure approval from regulators Provide price transparency to customers Keep internal gas supply management costs low Maintain consistency with other corporate goals for reduced environmental impacts, sustainable development, local content, integrated resource plans, etc. EEA addresses each objective in our report and has put together an evaluation process to score each supply option in terms of all these goals. The report describes how each potential supply source measures up to each criterion and how each source should be ranked considering all criteria. The report also makes recommendations on how maximum value can be achieved in the procurement and contracting processes. 2.2 Structure of Report The report is structured in seven sections. Section one of this report provides an executive summary highlighting key conclusions and recommendations resulting from EEA s review of the Centra demand characteristics and supply options. Section three provides a detailed review of the current operating environment faced by Centra Manitoba, including a review of demand characteristics and existing pipeline and storage capacity contracts, and the current natural gas commodity purchase agreements. The third section also highlights stakeholder interests. Section four discusses sustainable development issues associated with Centra supply planning. Section five provides an overview of the North American natural gas market environment that Centra operates within, including an assessment of likely changes in the TransCanada Pipeline operating environment. Section five addresses several key questions, including: Will current market conditions change in ways likely to change the desired mix of Alberta vs. non-alberta supply options? What are the potential sources of natural gas commodity supply, and how should alternative supply locations be evaluated? Energy and Environmental Analysis, Inc. 12

23 EEA Final Report January 2007 How much of the total commodity should be sourced from Alberta vs. the U.S. Midwest 6 consistent with the current portfolio of transportation and storage assets and an objective of minimizing incremental transportation and storage costs? Section six identifies and evaluates specific natural gas supply options available to Centra, and addresses several key questions including: Should Centra continue to rely on a single marketer to provide the bulk of its natural gas commodity requirement, and essentially 100 percent of its Alberta supply? How much flexibility in takes should be internalized into the contract(s) for primary gas? Should the contract(s) for primary gas be structured so as to provide more than proportional flexibility, thereby reducing the variability in nominations for marketers? How should the costs of any increased flexibility be evaluated and recovered? What supply alternatives are available to Centra Manitoba? How will the changing fundamentals affect the phase two analysis of the appropriate balance between storage, TransCanada pipeline capacity and supply from Empress, and delivered swing service to meet seasonal and peak requirements? How can/should the replacement contract be structured and negotiated to preserve the option of operating with a different mix of infrastructure assets? What are the implications of the timing of the phase two analysis with respect to the term of the replacement agreement or portfolio of agreements? EEA s recommendations for the development of future natural gas supply arrangements are presented in Section Seven. One of the basic conclusions in the report is that existing contract with Nexen has served the consumers of Manitoba well. The structure of the contract provides reliable deliveries of gas at close to market price. As a result, there is not a compelling rationale to change the structure of the gas supply arrangement for primary gas that has worked well. Section Seven provides recommendations on development of a new supply contract that will be similar to the existing contract, with certain potential refinements. Section seven also identifies the most likely bidders in a supply contract bidding process. 6 Midwest supplies can be sourced from a variety of sources, including the U.S. Gulf Coast, midcontinent, or Rocky Mountains. However, the existing portfolio of transportation and storage contracts may not allow for all strategies to be considered. Energy and Environmental Analysis, Inc. 13

24 EEA Final Report January 2007 The report also includes five appendices available under separate cover. Appendix A provides a detailed review of recent natural gas market developments. Appendix B provides a detailed discussion of EEA s current long-term North American natural gas market forecast. Appendix C provides summary documentation on EEA s forecasting methodology. Appendix D provides a more detailed discussion of natural gas liquidity concepts. Appendix E includes documents related to stakeholder input into this review. Energy and Environmental Analysis, Inc. 14

25 EEA Final Report January OVERVIEW OF CENTRA S OPERATIONS This section provides a description of the gas demand, supply, storage and transportation portfolio and arrangements that Centra currently manages on a day to day basis to meet Manitoba s market requirements. 3.1 Centra Natural Gas Demand Centra Manitoba Inc. serves approximately 258,000 residential, commercial, and industrial natural gas customers throughout Manitoba. A very large percentage of these natural gas customers reside in the Winnipeg area, with the majority of the others located within a corridor that extends approximately 100 kilometers on either side of the TransCanada Pipeline. As shown in Figure 3, the total number of customers served by Centra, including both sales and transportation customers, has been growing steadily at slightly less than one percent per year since Over the same period, total volumes delivered by Centra have been relatively stable (Figure 4), with most of the year-to-year variation in delivery volumes resulting from differences in weather, rather than underlying market trends. Overall, transportation volumes have grown slightly and sales volumes have declined slightly. Centra Manitoba customers have the option of receiving their primary gas supply from either Centra or via direct purchases from a third party broker. However Centra, as the major distributor of natural gas in the province, retains a continued responsibility to all of its customers including those who elect to purchase their gas supply from others. The service provided by Centra to facilitate the transportation of Direct Purchase supplies is known as the Western Transportation Service ( WTS ), in which the consumer arranges, through a broker, a source of gas in Western Canada and Centra transports the gas from Western Canada to the consumer. In accordance with the terms of the WTS agreement, Centra is responsible for transporting the Primary Gas purchased by the consumer or broker from Western Canada to the consumer. The broker or supplier of the gas sets the sales price of the Primary Gas for its customers. WTS customers make up approximately 22% of Centra s customer base, and account for approximately 19% of Centra s total MDQ. The Direct Purchase volumes are transported using Centra s firm TCPL transportation capacity. In addition, Direct Purchase customers are allocated a share of the costs of pipeline and storage capacity held by Centra that is used to meet peak day and seasonal requirements of both system customers and direct purchase customers. Energy and Environmental Analysis, Inc. 15

26 EEA Final Report January 2007 Figure 3 Centra Manitoba Natural Gas Customers Source: Manitoba Hydro 2006 Annual Report, 300, ,000 Commercial/Industrial Residential 200, , ,000 50, Figure 4 Centra Manitoba Natural Gas Deliveries Source: Manitoba Hydro 2006 Annual Report, (PJ's per year) Transportation Customer Deliveries Commercial/ Industrial Sales Residential Sales Energy and Environmental Analysis, Inc. 16

27 EEA Final Report January Forecasted Demand EEA s Base Case projects that demand for natural gas in Manitoba for firm service residential and commercial customers will remain essentially flat between now and 2015 (Figure 5). Overall, Manitoba s gas use will grow moderately over time due to growth in industrial sector demand. We are projecting Manitoba s annual gas use to grow from about 93 Bcf in 2005 to over 111 Bcf in 2015, a growth rate of almost 2 percent per year. Figure 5 EEA Forecast of Manitoba Natural Gas Demand in the Residential and Commercial Sectors Source: Energy and Environmental Analysis, Inc (PJ's per Year) Commercial Residential EEA is projecting a continuation of growth in the number of residential and commercial sector natural gas customers in Manitoba at slightly less than one percent per year. However, improvements in overall efficiency of natural gas use are expected to offset most of the growth in the number of customers, resulting in stable natural gas demand in the residential and commercial sectors for the foreseeable future. Most of the growth in EEA s forecast (three-quarters of it) is expected to occur in the industrial sector. The growth in this sector is driven primarily by the broad economic growth trends in the province. The new industrial sector demand is expected to have a relatively flat load profile, and is expected to be served primarily by the transportation market using interruptible transportation on TransCanada Pipeline. As a result, the load Energy and Environmental Analysis, Inc. 17

28 EEA Final Report January 2007 growth in this sector is not expected to have a major impact on Centra seasonal or peak natural gas requirements. Unlike most of North America, EEA expects only limited growth in gas demand for power generation in Manitoba. Any power generation demand growth is expected to be based on potential for increased use of the 378 MW of gas-fired capacity installed by Manitoba Hydro in 2002, and unless natural gas prices drop substantially, any increase in gas demand would be driven by reductions in available hydropower generation due to drought and hence, would be temporary. Residential and commercial sector demands are expected to be the primary demand drivers for the Centra system. The relatively stable outlook for residential and commercial sector demand indicates that no fundamental shifts in the type of load to be served by Centra are expected and that the current load profile represents a reasonable expectation for the future for load planning purposes Peak Day Demand Centra Manitoba provides natural gas delivery and sales services to about 80 percent of the firm residential and commercial load in the Centra Manitoba service territory, and provides delivery service, but not gas purchase service to the remaining 20 percent of the firm load. Under the terms of Centra s service territory agreements with the Province of Manitoba, and consistent with the WTS agreements with third party marketers, Centra Manitoba is responsible for ensuring reliable service to all firm delivery customers. Centra Manitoba s firm peak day (the volume of gas required to serve all Firm Sales customers, including WTS customers, on the coldest winter day experienced) was forecasted to be 485,000 GJ/day during the 2005/06 winter. While EEA is forecasting minimal growth in total Manitoba demand, we are not forecasting near-term growth in the peak day demand to be served by Centra Manitoba. The growth in demand is expected to occur primarily in the industrial sector and will be served directly by TransCanada, or as transportation service by Centra. Centra transportation service requires Centra to maintain physical delivery system capacity to meet the growth in load;-, however it does not require Centra to provide for peak day natural gas commodity for transportation customers. While the number of residential and commercial customers is expected to increase steadily over time, residential and commercial requirements are expected to remain relatively stable as improvements in natural gas usage efficiency offset customer growth Impact of Manitoba Weather on Supply Planning The majority of Centra s load is in the residential and commercial sector where daily and monthly load requirements are determined primarily by weather. As a result, weather plays the major role in determining annual, seasonal and day-to-day natural gas demand. Centra s supply planning process is complicated by the fact that weather in Energy and Environmental Analysis, Inc. 18

29 EEA Final Report January 2007 Manitoba is more uncertain and more volatile than the weather in any of the other major markets served by TransCanada or consuming WCSB natural gas. Figure 6 illustrates the normal traditional heating degree days 7 in a variety of different regions served by natural gas supply produced in the WCSB. As shown in this figure, Manitoba has the highest degree of seasonal variation in heating requirements due to seasonal weather patterns of any of the regions considered. Manitoba also experiences the greatest uncertainty in terms of weather, both on an annual as well as a daily basis. Table 2 shows total annual heating degree days for Winnipeg and a variety of other market regions served by TransCanada for a normal year, as well as for the warmest year and the coldest year between 1995 and As shown on this table, Manitoba weather exhibits both the largest absolute amount of spread in traditional heating degree days (coldest year warmest year) as well as the largest relative range in traditional heating degree days ((coldest year warmest year)/normal year). Figure 6 Monthly Normal Traditional Heating Degree Days 2,000 1,800 HDD (Base 65 Degrees Fahrenheit) 1,600 1,400 1,200 1, Alberta British Columbia Manitoba Ontario Quebec Saskatchewan New Enlgand Mid-Atlantic East North Central West North Central Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 7 For all of EEA s analysis, the number of Heating Degree Days (HDD) is defined as the sum of the number of degrees Fahrenheit below 65 degrees Fahrenheit during each month or year. Energy and Environmental Analysis, Inc. 19

30 EEA Final Report January 2007 Table 2 Annual Heating Degree Days Comparison of Manitoba Weather to Other Regions Served by WCSB Gas Production Normal Weather Warmest Year Coldest Year Absolute Range Relative Range Manitoba 10,378 9,332 12,301 2,969 29% Alberta 9,423 9,097 11,146 2,048 22% Saskatchewan 10,003 9,633 12,370 2,737 27% British Columbia 5,339 4,896 5, % Ontario 6,582 6,087 7,742 1,655 25% Quebec 8,338 7,356 8,803 1,447 17% New Enlgand 6,611 5,848 6,887 1,039 16% Mid-Atlantic 5,911 4,969 6,134 1,165 20% East North Central 6,497 5,330 6,923 1,593 25% West North Central 6,750 5,887 7,318 1,431 21% In terms of utility operations and supply planning requirements, day-to-day volatility in demand may be more important than annual uncertainty. Utility planning must account for changes in day-to-day weather to ensure that the proper volume of gas is available to meet demand so that the utility is not generating imbalance fees. The Manitoba service territory served by Centra also experiences the greatest volatility in day-to-day weather of any of the market centers considered. Table 3 provides a comparison of the standard deviation in the change in daily mean temperature from one day to the next for a variety of market centers served by TransCanada. Table 3 Daily Volatility of Regional Weather ( ) Standard Deviation of Daily Changes in Temperature (Degrees Celsius) Summer (April - Oct) Winter (Nov - Mar) Average Manitoba (Manitoba) Alberta (Calgary) Saskatchewan (Saskatoon) Ontario (Toronto) Quebec (Montreal) U.S. North East Central (Chicago) Rocky Mountains (Denver) New England (Boston) The volatility in Manitoba weather is reflected in Centra s historical natural gas demand data. Figure 7 shows the Centra load profile by day for the year This figure Energy and Environmental Analysis, Inc. 20

31 EEA Final Report January 2007 illustrates the day-to-day volatility in demand, as well as the broad seasonal differences in demand. Figure 8 shows the annual load factor for each year from 1996 through 2001, where days have been sorted from highest demand to lowest demand. Figure Centra Manitoba Demand (TJ/Day) /1/ /1/2000 1/1/2001 2/1/2001 3/1/2001 4/1/2001 5/1/2001 6/1/2001 7/1/2001 8/1/2001 9/1/ /1/2001 (TJ/Day) As we would expect, given the weather patterns in Manitoba and the preponderance of residential and commercial demand, a very high percentage of Centra s demand is weather sensitive. The high percentage of Centra s load that is weather sensitive, combined with the very cold winter weather in Manitoba results in a load profile that is amongst the most highly seasonal of any LDC in North America. 8 This comparison is illustrated in Figure 9, which compares the average Centra load profile to the normal weather load profile for New England. This figure, which compares daily load to the average load for the year suggests that the Centra load profile is more than twice as seasonal as the natural gas load profile in New England. 8 Enstar, in South Central Alaska, has a more seasonal load profile for residential and commercial load, however, there is also a large industrial load that stabilizes the average overall load profile. Energy and Environmental Analysis, Inc. 21

32 EEA Final Report January 2007 Figure 8 Centra Manitoba Load Profile (TJ/Day) Days per Year 365 Figure 9 Comparison of Centra Manitoba and New England Load Profiles 300% Comparison of Centra Manitoba Natural Gas Load Profile to New England Natural Gas Load Profile (As a Percent of Average Day) (Percent of Average Day) 250% 200% 150% 100% Centra New England 50% 0% 1 (Days Per Year) 365 Energy and Environmental Analysis, Inc. 22

33 EEA Final Report January 2007 However, the Centra load profile is also somewhat less peaky than demand in other cold weather regions. Figure 10 shows the same load profile as Figure 9, but normalizes the data to the peak day, rather than to the annual average. This figure indicates that for the 35 days with the highest demand, the Centra load profile is somewhat less peaky than the New England load profile. Figure 10 Comparison of Centra Manitoba and New England Load Profiles 100% Comparison of Centra Manitoba Natural Gas Load Profile to New England Natural Gas Load Profile (As a Percent of Peak Day) (Percent of Peak Day) 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Centra New England 1 (Days Per Year) 365 As a result, Centra requires more seasonal gas resources, and requires more flexibility in day-to-day gas supply requirements, but also requires a smaller share of needle peak gas resources than other cold weather markets. The volatility in the weather patterns in Manitoba, combined with the high degree of weather sensitive load, can substantially increase daily swings in demand in the province. Figure 11 illustrates the range of forecasted demand based on weather, as forecasted by Centra Manitoba. This figure illustrates the demand curve for the theoretical coldest year (maximum), warmest year (minimum) and average year, where the weather for each day of the year represents the coldest/warmest weather for that date over a 30 year historical period. These demand profiles indicate that for much of the year, demand can vary by 100 percent or more from day to day based on differences in weather. Energy and Environmental Analysis, Inc. 23

34 EEA Final Report January 2007 Figure 11 Weather Variation in Centra Manitoba Load Duration Curves 600 Weather Variation in Centra Manitoba Load Duration Curves (Maximum, Mininimum and Average Weather over Twenty Years) 500 (TJ's per Day) Maximum Average Minimum (Days per Year That Load Exceeds) Centra Gas Pipeline and Storage Capacity 9 There is essentially no natural gas produced in Manitoba. Currently, most of the natural gas commodity purchased by Centra Manitoba is sourced from the Western Canadian Sedimentary Basin (WCSB) to the west of the Centra Manitoba service territory. Centra also holds a significant amount of storage capacity in Michigan to meet winter seasonal load, and to minimize requirements to hold TransCanada Pipeline capacity from Alberta to Manitoba. Centra also purchases seasonal natural gas supplies from the Mid- Continent along the southwest leg of the ANR pipeline system for winter peak supply and for injection into ANR Storage, and from Louisiana along the southeast leg of the ANR pipeline system for injection into ANR storage in Michigan, and peak day supply as a delivered service at the Centra Manitoba city gate. Centra s pipeline and storage capacity holdings are determined by Centra s long-term strategy for meeting peak day, winter and annual gas requirements. Centra Manitoba provides natural gas delivery and sales services to about 80 percent of the firm load in the Centra Manitoba service territory, and provides delivery service, but not gas 9 The majority of the information in this section was taken from the background section included in the Centra RFP, and from more detailed reviews of contracts with commodity, pipeline and storage providers provided to EEA by Centra. Energy and Environmental Analysis, Inc. 24

35 EEA Final Report January 2007 purchase service to the remaining 20 percent of the firm load. Under the terms of Centra s service territory agreements with the Province of Manitoba, and consistent with the WTS agreements with third party marketers, Centra Manitoba is responsible for ensuring reliable service to all firm delivery customers. Centra Manitoba s firm peak day (the volume of gas required to serve all Firm Sales customers, including WTS customers, on the coldest winter day experienced) is 485,000 GJ/day. Table 4 depicts the sources of supply used to meet design firm peak day requirements for the 2005/06 fiscal year. Table 4 Centra Peak Day Supply Portfolio 2005/06 Sources of Supply to Meet Projected Design Firm Peak Day Requirements GJ/day % System Supply 167, % Direct Purchase (WTS) 37, % Total Under FS Transportation on TCPL 204,784 Oklahoma Supply 7, % Storage Withdrawal 208, % Delivered Services 63, % Total Design Firm Peak Requirement 485, % According to the 2005/06 peak day plan, TransCanada firm service transportation from Alberta, including both Centra System Supply and Direct Purchase volumes would provide 42.2 percent of the total peak requirements, and withdrawals from ANR storage in Michigan would be used to meet 43 percent of peak day requirements. The remaining 14.7 percent of requirements are met with a combination of delivered services and Oklahoma supply. During the winter, about 62 percent of total requirements are met with firm service transportation on TransCanada, with most of the remainder met using withdrawals from Michigan storage. On an annual basis, between 90 and 100 percent of the total system and direct purchase supply comes from the Western Canadian Sedimentary basin, and is transported from Alberta or Saskatchewan via the TransCanada pipeline. Year to year changes in weather and in demand patterns can shift the percentage of Energy and Environmental Analysis, Inc. 25

36 EEA Final Report January 2007 supplemental gas purchased from sources outside of the WCSB resulting in the total percentage of gas supplied from the WCSB ranging from between 90 to 100 percent of the total requirements. Figure 12 shows the location of the pipelines and storage fields serving Manitoba requirements relative to the Centra Manitoba service territory. As shown on this figure, the location of the storage and pipeline assets on Great Lakes Gas Transmission and ANR are downstream of the Centra service territory. 10 Figure 12 Location of Centra Manitoba Pipeline and Storage Assets TransCanada Centra Manitoba Service Territory Great Lakes Gas Transmission ANR Storage ANR Southwest ANR Southeast 10 It is important to highlight that even though Centra Manitoba has some supply diversity in its purchasing strategy, and holds pipeline capacity to enable deliveries of natural gas from Michigan to the Centra Service territory during the winter, 100 percent of the physical natural gas supply used by natural gas consumers in the Centra Manitoba service territory is produced in the WCSB and is delivered to the Centra system from the west on the TransCanada Pipeline system. Even on peak day, when about 45 percent of the nominal supply of natural gas delivered to the Centra service territory comes from withdrawals from Michigan storage and from purchases in Oklahoma, and reaches the Centra service territory via backhaul on Great Lakes Gas Transmission and TransCanada Pipeline, the physical gas consumed is coming from the west. In physical terms, Centra customers are using natural gas delivered to TransCanada by other TCPL customers located downstream of Centra. This gas is replaced further east by natural gas withdrawn from ANR storage in Michigan by Centra Manitoba. Energy and Environmental Analysis, Inc. 26

37 EEA Final Report January Transportation and Storage Contracts Centra Manitoba holds pipeline capacity on TransCanada, Great Lakes Gas Transmission (GLGT), and ANR Pipeline, as well as ANR storage capacity in Michigan. The pipeline and storage capacity held by Centra Manitoba are summarized in Table 5, and described below: Table 5 Summary of Centra Pipeline and Storage Contracts Type of Service Annual Summer Winter TransCanada Pipeline (GJ/Day) Empress to Saskatchewan FT 3,832 Empress to Manitoba FT 200,952 Manitoba to Emerson Firm STS 54,418 Emerson to Manitoba Firm STS 215,614 Great Lakes Gas Transmission (GJ/Day) Emerson to Crystal Falls (ANR) FT 53,351 Crystal Falls (ANR) to Emerson FT (Backhaul) 237,388 ANR Pipeline (GJ/Day) Crystal Falls to ANR Storage FT 52,448 ANR Storage to Deward/GLGT FT 208,591 Oklahoma to ANR Storage FT 7,860 Louisiana to ANR Storage FT 22,380 ANR Storage ANR Storage Capacity (GJ) 15,509,323 ANR Storage Deliverability (GJ/Day) 208,591 ANR Storage Injection (GJ/Day) 88,625 ANR Pipeline Storage Contracts Centra leases 15,509,323 GJ of ANR storage capacity in Michigan. This storage provides a maximum winter deliverability of 208,591 GJ/day, net of pipeline compressor fuel, with a maximum summer daily injection capacity of 88,625 GJ/day. This storage is used to improve Centra s transportation and purchase load factor on the TransCanada Pipeline system and reduce the unutilized demand charges associated with the use of transportation capacity at a low system load factor. As indicated earlier, storage inventory is filled primarily using Primary Gas transported from Alberta on TransCanada and Great Lakes Gas Transmission. Supplemental Gas supplies from Oklahoma and Louisiana are also used for storage fill when required to meet storage inventory targets. Energy and Environmental Analysis, Inc. 27

38 EEA Final Report January 2007 TransCanada Pipeline All of the natural gas supplies delivered to the Centra Manitoba service territory are delivered by the TransCanada Pipeline. Centra Manitoba holds four sets of transportation capacity contracts on TransCanada. 1) All supplies purchased or received from Western Canada, either as system supply or Direct Purchase supply, are transported to Saskatchewan and Manitoba on the TransCanada PipeLine using Firm Service (FS) contracts. Some customers (e.g. Dauphin, Russell) are supplied from a meter station on TCPL that is located in Saskatchewan and is part of the Saskatchewan Zone on the TCPL system. The April 1, 2006 TCPL DCQs are forecast at 3,832 GJ/day for Saskatchewan Zone deliveries and 200,952 GJ/day for Manitoba Zone deliveries. These contracts expire on October 31, 2006 and Centra has the option to renew them on an annual basis. On an annual basis, under normal weather conditions, Centra utilizes this capacity at roughly an 81 percent load factor. 2) Centra also holds Storage Transportation Service capacity on TransCanada between Manitoba and Emerson to provide access to Centra storage capacity in Michigan. The TCPL STS contract provides 54,418 GJ/Day of capacity during the summer (April 1 to October 31) to deliver Alberta natural gas to ANR storage in Michigan, and 215,614 GJ/Day of capacity from the TransCanada/GLGT interconnect at Emerson back to Manitoba during the winter (November 1 to March 31). This contract terminates on March 31, 2007 and Centra has the option to renew it on an annual basis. 3) Centra has an Interruptible Backhaul Transportation contract (IT Backhaul) for receipt points downstream of Winnipeg, primarily from Emerson, for the occasions in winter when Centra purchases delivered service. The DCQ is unlimited, however, TCPL has the discretion to curtail or interrupt the nomination volume request in the event there are constraints on TCPL s pipeline system. This contract continues to force until terminated by either party by giving 30 day written notice. 4) Finally, Blanket Interruptible Transport allows Centra to move incremental gas. The DCQ is unlimited, however, TCPL has the discretion to curtail or interrupt the nomination volume request in the event there are constraints on TCPL s pipeline system. This contract continues to force until terminated by either party by giving 30 day written notice. Key Players on the TransCanada System Centra Manitoba is currently the ninth largest holder of firm capacity on TransCanada. However, capacity on TransCanada is widely distributed amongst a wide variety of companies, and Centra holds only about four percent of the total capacity under contract at the Empress Receipt point. The largest contract holder on TransCanada, Energy and Environmental Analysis, Inc. 28

39 EEA Final Report January 2007 Nexen, holds only about 12 percent of the total capacity under contract at the Empress receipt point. Table 6 shows the TransCanada Pipeline Firm Service capacity held by the 40 largest holders of capacity. Table 6 Top 40 Companies Holding Capacity on TransCanada TransCanada Pipeline FT Capacity Under Contract (GJ's per Day) ********Primary Receipt Point********** Other SHIPPER Total FT Capacity Empress Union Dawn St. Clair Receipt Points Nexen Marketing 887, , ,899 29,183 15,000 Gaz Metro Limited Partnership 577, , , Union Gas Limited 553, ,711 80, Coral Energy Canada Inc. 541, ,924 79, ,403 - Cargill Limited 530, , Enbridge Gas Distribution Inc. 512, , , ProGas Limited 352, , Husky Energy Marketing Inc. 274, ,677-21,420 - Centra Gas Manitoba Inc. 203, , Dynegy Canada Marketing and Trade 165, ,142 41,491 Rochester Gas and Electric Corporation 144, ,803 - Canadian Natural Resources 138, ,317-37,160 - EnCana Oil & Gas Partnership 132, , Nova Scotia Company 108, , DTE Energy Trading, Inc. 85,413 16,014-69,399 - ConocoPhillips Canada Limited 84,903 42,701-21,101 21,101 Cinergy Canada, Inc. 66,189 39,813-26,376 - Selkirk Cogen Partners, L.P. 58,485 58, Michigan Consolidated Gas Company 52,753 52, BP Canada Energy Company 51,755 51, Direct Energy Marketing Limited 51,447 51, Tenaska Marketing Canada 50,148 50, EnCana Corporation 42,744 21,372-21,372 - NJR Energy Services Company 40,000-40, Simplot Canada Limited 38,339 22, ,422 Anadarko Canada Corporation 34,140 34, Talisman Energy Canada 33,941 33, United States Gypsum Company 31,763 31, Enserco Energy Inc. 31,652 31, EPCOR Power L.P. 30,402 30, TransGas Limited 30,243 30, National Fuel Gas Distribution Corporation 28,854 28, Brooklyn Navy Yard Cogeneration Partners, L.P. 26,956 26, NOVA Chemicals Corporation 23,512 23,512 - Constellation Energy Commodities Group, Inc. 23,214 23,214 - Lake Superior Power Limited Partnership 22,437 22,437 - Abitibi-Consolidated Company of Canada 21,100 21,100 - Kingston CoGen Limited Partnership 21,045 21,045 - Iroquois Falls Power Corp. 20,874 20,874 - West Windsor Power 20,645 20,645 - Petro-Canada Oil and Gas 20,332 20,332 - Total of 79 Other Contract Holders 460, ,484 25,086-11,213 Total 6,627,664 4,906, , , ,227 Source: TCPL Index of Customers September 2006 Energy and Environmental Analysis, Inc. 29

40 EEA Final Report January 2007 Great Lakes Gas Transmission (GLGT) Transportation In order to use ANR storage capacity in Michigan, Centra holds pipeline capacity on the Great Lakes Gas Transmission system between the TransCanada/Great Lakes interconnect at Emerson, and the Great Lakes/ANR storage interconnects at Crystal Falls and Deward. The capacity contracts are structured separately for summer and winter periods. 1) During the summer (April 1 to October 31), Centra holds 53,351 GJ/day of Firm Transportation (FT) capacity from Emerson, Manitoba to Crystal Falls, Michigan where Great Lakes Gas Transmission interconnects with ANR Pipeline. 2) During the winter (November 1 to March 31), Centra has 237,388 GJ/day of Firm Backhaul Transportation (FT Backhaul) capacity from the ANR pipeline/glgt interconnect at Deward to the TransCanada/GLGT interconnect at Emerson. This transportation capacity provides access to Centra s ANR Pipeline Storage inventory to serve winter load demand. ANR Pipeline Centra Manitoba holds four different types of capacity on the ANR pipeline system. The most critical contracts provide transportation into and out of ANR storage. Centra also holds long haul transportation capacity to provide access to natural gas produced in Louisiana and Oklahoma: 1) 52,448 GJ/Day of Firm Transportation from the GLGT Crystal Falls interconnect to ANR Pipeline s storage facilities. This capacity is only available during the summer storage injection period to move Primary Gas to storage. 2) 208,591 GJ/Day of Firm Transportation from ANR Storage to the Deward Interconnect with GLGT. This capacity is only available during the winter storage withdrawal period. 3) 7,860 GJ/day of Firm Transportation Service from Oklahoma. During the winter this capacity is used to deliver gas to the Manitoba market via transportation to the ANR/GLGT interconnects and then backhaul on GLGT and TransCanada to Manitoba. During the summer this capacity is used to assist in refilling Supplemental Gas withdrawn from storage. 4) The final component is summer-only Firm Transportation Service from Louisiana of 22,380 GJ/day that is also used to assist in refilling storage. 3.3 Centra Gas Supply Arrangements Centra purchases Western Canadian supplies in conjunction with TCPL s Firm Services ( FS ) from Empress, Alberta to Saskatchewan and Manitoba. During the summer, Energy and Environmental Analysis, Inc. 30

41 EEA Final Report January 2007 TCPL FS capacity exceeds Manitoba Market requirements. The Manitoba market requirements are met first and any capacity in excess of those requirements is used to refill ANR storage in Michigan or to sell to other parties where feasible. The storage refill is accomplished by using the TCPL FS capacity to Manitoba, TCPL Storage Transportation Service ( STS ) to the Emerson interconnect with Great Lakes Gas Transmission ( GLGT ), GLGT Firm Transportation to the interconnect with ANR Pipeline at Crystal Falls, Michigan and ANR Pipeline Firm Transportation Service ( FTS ) to the ANR Pipeline storage facilities in Northern Michigan. In addition, to assist in refilling storage after cold winters, Centra has ANR Pipeline FTS on its southwest system to transport Oklahoma supplies to storage and ANR Pipeline FTS on its southeast system to refill storage with Louisiana supplies. The two main components of Centra s Gas Supply Portfolio are Primary Gas and Supplemental Gas. Primary Gas Centra considers natural gas received from Western Canadian sources at the Alberta border (Empress), whether Centra-supplied or broker-supplied (Direct Purchase) to be Primary Gas. Primary Gas System Supply Natural gas purchased by Centra Manitoba from Western Canadian sources and delivered to the Alberta border at Empress are considered to be primary gas system supply. Centra currently sources all primary gas system supply through a long-term contract with Nexen. The existing agreement with Nexen became effective on November 1, 2004, and expires on October 31, Upon mutual agreement of both parties, the term of the agreement may be extended for further one or two year period, as long as the mutual agreement to extend is completed six months prior to the expiration of the current contract. The Nexen agreement requires Centra to purchase its utility supply service requirements from Nexen, and prohibits Centra from reselling gas supplied by Nexen to other third parties with minor exceptions for unusual circumstances where Nexen has turned down its contractual right of first refusal. Except for the purchase of gas supplies for its Direct Purchase customers from a supplier(s) other than Nexen as required, from time to time, Centra agrees to exclusively purchase from Nexen all quantities of gas it requires to meet its System Gas Requirements, which are defined as Centra s in-franchise gas requirements, less its Direct Purchase Supply requirements, as delivered at Empress. Centra shall not resell gas supplies provided by Nexen either at Empress or any other delivery point except in the event that Centra is left with excess supply after exhausting its System Requirements and making reasonable efforts to manage Energy and Environmental Analysis, Inc. 31

42 EEA Final Report January 2007 any excess supply through nomination cycles or by utilizing parking services made available to it by the pipeline. In total, Nexen is expected to provide an expected Daily Contract Quantity ( DCQ ) as of April 1, 2006 of 165,895 GJ/day or approximately 81% of Centra s firm TransCanada pipeline capacity. The natural gas purchased from Nexen is divided into Base Volumes and Swing Volumes, with prices set based on Alberta index prices, adjusted for the level of delivery certainty. Base Volumes: The majority of gas volumes are purchased as Base Gas volumes on a firm basis. Base gas volumes delivered to Empress must be specified by Centra on a quarterly basis. Base gas is provided on a 100% take or pay obligation by Centra and to deliver by Nexen. Base gas volumes are priced based on the monthly NOVA Inventory Transfer Monthly Index Price (or NIT price) as published by the Canadian Gas Price Reporter, plus an adjustment to account for the cost of transportation to Empress. 70 Percent of the transportation cost adjustment to Empress is determined by the demand rate that is set forth in NOVA s Table of Rates, Tolls and Charges for firm transportation service to NOVA s Empress Border delivery point. The remaining 30 percent of the transportation cost adjustment to Empress is determined by the basis differential between AECO/NIT and Empress as reported for the delivery month in the Canadian Gas Price Reporter. Swing Volumes: Centra can also purchase swing volumes of up to 120,000 GJ/day from Nexen. The Swing Load Service provides for the purchase of gas on a day to day basis with the option to revise the quantity requested, subject to pipeline schedule deadlines. The swing volumes are used to fill the contracted pipeline capacity from Western Canada as required and are incremental to the combined Baseload volumes and gas received from Direct Purchase contracts. The current supply contract provides some nomination (ordering) flexibility during each day in order to react to changes in total system requirements. Swing volumes are purchased at the Daily AECO index plus the Empress/AECO monthly Canadian Gas Price reporter Basis Index plus a premium of $.025/GJ for volumes up to 80,000 GJ/day and a premium of $.05/GJ for volumes between 80,001 GJ/day and 120,000 GJ/day. Primary Gas Direct Purchase Supplies Any Manitoba natural gas consumer (including residential, commercial and industrial customers) may purchase their Primary Gas directly from a broker independent of Centra. The service provided by Centra to facilitate the transportation of Direct Purchase supplies is known as Western Transportation Services ( WTS ), in which the consumer arranges, through a broker, a source of gas in Western Canada and Centra transports the gas from Western Canada to the consumer. In accordance with the terms of the WTS agreement, Centra is responsible for transporting the Primary Gas purchased by the consumer or broker from Western Energy and Environmental Analysis, Inc. 32

43 EEA Final Report January 2007 Canada to the consumer. The broker or supplier of the gas sets the price of the Primary Gas to its customers. WTS customers make up approximately 22% of Centra s customer base and account for approximately 19% of the total firm requirements in Centra s service territory. This volume is transported using Centra s firm TCPL transportation capacity. Supplemental Gas Supplemental Gas is natural gas provided from sources other than Primary Gas, including, but not limited to, U.S. supplies, and Delivered Service. Supplemental Gas is required to serve the Manitoba market peak day and seasonal requirements when requirements exceed the deliverability of Primary Gas. Centra can acquire Supplemental Gas from four sources on daily, weekly, or monthly terms as required. 1) Centra holds sufficient pipeline capacity on ANR to purchase and deliver up to 7,860 GJ/Day from the ANR South West ( SW ) zone in Oklahoma. During the summer, this capacity is used to refill storage. During the winter, gas moved on this capacity is part of the firm peak day capacity. 2) During the summer, Centra also holds sufficient pipeline capacity to transport up to 22,380 GJ/Day from the ANR South East ( SE ) zone in Louisiana for injection into ANR storage in Michigan. 3) Centra includes up to 63,765 GJ/Day of Delivered Service to meet peaking requirements. Delivered Service involves the purchase of supplies either downstream of Manitoba or where the supply is delivered directly to Manitoba. 4) Finally, where possible, Capacity Management loan transactions are used as a source of daily peaking supplies. Interruptible Customer Requirements At the beginning of the winter, under the assumption of a normal year, gas is dispatched daily using Primary Gas, Storage, Oklahoma Supply, and then Delivered Service as necessary to meet both the Firm and Interruptible requirements. As the winter progresses, Centra monitors the extent that the weather has been colder than normal and monitors the level of storage withdrawals. If it is determined that storage withdrawals are greater than normal, Centra will curtail Interruptible customers as required in order to conserve storage gas for the firm market, such that it would be able to supply the maximum year firm requirement from that point to the end of the winter. In the event that a curtailment is required, Interruptible customers have the option of purchasing Alternate Supply. Supplemental Gas Alternate Supply Service Centra also provides an Alternate Supply Service to Interruptible customers in lieu of curtailment. Interruptible customers are offered the opportunity to accept Alternate Energy and Environmental Analysis, Inc. 33

44 EEA Final Report January 2007 Supply Services on a case-by-case basis, and at prices that reflect the cost of obtaining the Alternate Supply in each specific case. Alternate Supply Services, for all practical purposes, is also a Delivered Service, although it is priced separately to the Interruptible customer. Alternate Supply Service is arranged whenever demand exceeds Centra s ability to provide and deliver supply under its contractual arrangements and Interruptible customers elect to purchase it. Prices, quantities and other terms are arranged in a very short time frame, and rarely more than a day in advance. 3.4 Stakeholder Concerns As part of this effort and in accordance with the direction of the Manitoba Public Utilities Board (MPUB) (MPUB Order ), Centra convened a fact finding session to provide an opportunity for the stakeholders to voice their views, perspectives, and objectives with respect to Centra s gas supply re-contracting alternatives. As part of this effort, Centra reached out to consumer advocates, third-party marketers that do (or could) compete to provide gas merchant service in the Centra service territory, and environmental, efficiency and sustainable development advocates. In addition, representatives and consultants from the MPUB were invited to observe and/or participate. The input of the stakeholders fell into four broad areas. They were: 1) Price levels and rate volatility Consistent with Centra s own stated objectives and the MPUB s responsibility to protect the public interest, the twin objectives of minimizing cost of supply while stabilizing price as much as practical were identified as being of paramount importance. During the discussion, there was no dissent to the proposition that there is generally a cost to providing price stability that is incurred in the pursuit of price stability that is additive to the expected value of future prices. However, there was no clear expression as to the appropriate level of the relative trade off between stability of prices and the objective of minimizing the cost of supply. In a related matter, there was a view expressed by at least one marketer that Centra s role as the default supplier should influence the evaluation of gas supply alternatives. To the extent that Centra s system supply alternative is perceived by customers to be as good or superior to the offerings of third-party marketers, the pace and ultimate extent of migration from system supply to third-party marketers is reduced. The inference is that a strategy that balances the twin objectives of minimizing cost of supply while stabilizing price to the satisfaction of consumers should be subordinated to the goal of increasing participation in customer choice programs. 2) Stability and reduced volatility in daily nomination for third-party marketers Several third-party marketers voiced the strong desire that Centra evaluate gas supply alternatives with an eye towards modifying the current protocol that allocates the daily variability in gas load proportionally to all gas suppliers on an equal basis. The implication is that Centra should evaluate and consider a gas supply contract that allows Centra to modify the utility takes to accommodate Energy and Environmental Analysis, Inc. 34

45 EEA Final Report January 2007 the variation in requirements of system customers as well as some or all of the variation of the requirements of Western Transportation Service (WTS) customers. To the extent that there is a cost to acquiring the more than proportional flexibility under the system sales contract, the costs (if any) would be borne by the subset of customers that elect utility supply service. 3) Monthly enrollment Several third-party marketers expressed the desire that Centra evaluate gas supply alternatives that would allow Centra to allow monthly variations in each marketer s customer base. Similar to the reduction in volatility of daily nominations, the implication is that Centra should evaluate and consider a gas supply contract that allows Centra to modify the utility monthly takes such that the contract allows for the migration from and to utility sales service. To the extent that there is a cost to acquiring a contract that accommodates additional uncertainty in monthly takes under the system sales contract, the costs would be borne by the subset of customers that elect utility supply service. 4) Environmental Issues, full cost accounting, and sustainable development Several of the stakeholders requested assurances that environmental, full cost accounting, and sustainable development issues would be addressed. Energy and Environmental Analysis, Inc. 35

46 EEA Final Report January 2007 (Page Deliberately Left Blank) Energy and Environmental Analysis, Inc. 36

47 EEA Final Report January SUSTAINABLE DEVELOPMENT ISSUES 4.1 Review of Sustainable Development Issues In the course of the Stakeholder consultations as well as in the Scope of Work identified defined by Centra, EEA was directed to consider questions of Sustainability in considering the renewal/replacement of the contract for primary gas supplies. In fulfilling the requirement, EEA has considered a number of issues including air emissions, water use and effluents, and land use. The concept of sustainability has legal force in Manitoba through the Sustainable Development Act, which includes a number of principles, guidelines and definitions. The Act articulates the following purpose in section 2: The purpose of this Act is to create a framework through which sustainable development will be implemented in the provincial public sector and promoted in private industry and society generally. Air Emissions Air Emissions from natural gas operations are in the form of fugitive, vented, and combustion emissions. Fugitive emissions are unintentional leaks of natural gas emanating from pipelines and other system components. The gases released are predominantly methane and, to a lesser extent, carbon dioxide. Vented Emissions are discharges of natural gas to the atmosphere by system design, by operational practices, or from unintentional incidents. Finally, combustion emissions are comprised of the combustion gases in exhaust. Combustion occurs at the point of production (field use) and in transmission and distribution (compressor fuel). However, the combustion emissions from natural gas are predominately at the point of end use. Water use and effluents Natural gas production, transmission and distribution use very little water. With the exception of central station power generation, nature gas enduse applications do not use significant quantities of water. Natural gas production can be a source of water effluents. Coal bed methane production requires the de-watering of the resource in order to produce the natural gas. This process can require that considerable volumes of water be brought to the surface. In some instances, this water is or can be made to be potable at little cost. In other cases, the water can be contaminated with natural salts and minerals, requiring that the water be disposed of in a manner that is consistent with environmental Energy and Environmental Analysis, Inc. 37

48 EEA Final Report January 2007 regulations. Conventional gas production can involve the use of drilling mud and hydraulic fluids used to increase the production rates of the individual formations. These fluids must also be disposed of consistent with environmental regulations. Land use Natural gas production, transmission and distribution, like all development, require land. Production requires modest amounts of land for field facilities as well as road access. Transmission and distribution require temporary disruption during construction. But the use of new technology such as trenchless installation has reduced these impacts. In addition, once installed, the impact of the underground infrastructure is relatively modest. 4.2 Findings Natural gas generally is considered to be a clean fuel, with limited point-of-use emissions. When natural gas can be used to displace coal and oil, natural gas use provides significant environmental benefits. These benefits include: Air quality/emissions reductions. NO X. SO X. CO 2. Particulates. Surface Land Use. Exploration/mining. Transmission and distribution. In this report, the scope of the analysis of sustainability issues is more limited than a complete analysis of the environmental impacts and sustainability issues for total energy use by virtue of the fact that the scope only compares various gas alternatives. The task is to examine alternatives for the renewal or replacement of the existing contract for primary gas. As such, the analysis is confined to the supply contract and does not encompass the broad array of issues and options that affect total energy consumption or end-user fuel choice decisions. The differences in the environmental impacts between supply alternatives is limited to the difference in impacts from the production of different resources types, e.g., coal-bed methane, tight gas formations, associated gas, LNG, etc. These differences are modest compared to the differences between different energy sources, e.g., coal, wind, gas biomass, etc. In order for Centra to base a decision to contract for gas based upon the type of production, many if not all of the most economic alternatives would be precluded. To be certain of the type of production, Centra would have to: Energy and Environmental Analysis, Inc. 38

49 EEA Final Report January 2007 Acquire and produce gas reserves directly, or Contract directly with small producers that produce exclusively from a particular resource type. While these types of producers do exist, they have limited resources and little ability to assure reliably delivery on a continued basis. The large market participants that offer the best opportunity for least cost supply do not and cannot track the sources of gas. Their supply portfolio is the result of many interim transactions, buying and selling gas multiple times prior to the ultimate delivery of gas to the ultimate purchaser. The assessment of alternative supply options outlined in section seven of this report includes explicit weighting of sustainable development and environmental considerations. Energy and Environmental Analysis, Inc. 39

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51 EEA Final Report January, THE NORTH AMERICAN GAS MARKET 5.1 Introduction Changes in North American natural gas markets are changing the relationships between producing basins, pipelines, and commodity suppliers that underlie the current Centra commodity supply strategy. The major change in North American markets is a general tightening of the overall supply/demand balance. The market is not in danger of running out of gas supply any time soon, however, with the tight balance, gas prices will generally remain above 1990s levels, and some of the more extreme price volatility observed in the market will persist as supply and demand changes are rationalized by price changes. North American natural gas supply patterns are also changing quite dramatically in response to depletion of reserves in known fields, development of new sources of supply, and substantial increases in LNG imports. A number of these changes will have a significant impact on Centra Manitoba: Declining natural gas exports from Alberta are likely to increase the commodity price of natural gas at AECO and at Empress relative to natural gas prices in the remainder of North America. Declining flows on the TransCanada mainline are also likely to lead to upward pressure on firm service pipeline tariff rates on the TransCanada system. Growth in LNG imports is likely to increase the value of natural gas pipeline capacity from the Gulf Coast into the U.S. Midwest, reducing the price of natural gas in the Gulf Coast production region, and increasing the pipeline basis from the Gulf and Mid-Continent into the Midwest on ANR and other major pipelines. Completion of the Rockies Express Pipeline (or a competing project) is expected to deliver significant quantities of Rocky Mountain natural gas into the U.S. Midwest, which will change pipeline flow patterns, and natural gas price relationships. This section of the report provides an overview of the key changes in the North American market likely to influence Centra Manitoba. A more detailed assessment of the broader North American trends is included in Appendix A to this document. Energy and Environmental Analysis, Inc. 41

52 EEA Final Report January, Overview of Broad North American Market Trends The North American natural gas market has undergone a fundamental shift that started at the beginning of this decade. For the years 2000 through 2005, gas prices at AECO averaged almost $6.00 per GJ, far above the 1990s average of about $2.50 per GJ. Price volatility has increased as well. The supply and demand balance for natural gas is much tighter than it was in the 1990s. The market is not in danger of running out of gas supply any time soon, however, with the tight balance, gas prices will generally remain above 1990s levels, and some of the more extreme price volatility observed in the market will persist as supply and demand changes are rationalized by price changes. The environment that EEA projects in its Base Case for the North American market is one that is similar to the environment observed during the past few years and less similar to the 1990s environment. The EEA Base Case projects substantial growth in gas use over time. EEA projects U.S. and Canada gas use to grow from about 25 Tcf in 2005 to over 33 Tcf in 2025 (Figure 13), a growth rate of about 1.6 percent per year. Roughly 5 Tcf or two-thirds of the total growth of gas use is projected to occur in the power generation sector, where gas-based power generation increases significantly over time. There have been over 200 GW of new gas-based generating capacity recently built in the U.S. and much of that capacity is underutilized and readily available to satisfy incremental electric load growth. The annual growth rate for gas use in the U.S. power generation sector is projected to average well over 3 percent per year. Conversely, gas use in the residential, commercial, and industrial sectors is projected to grow much more slowly at under 1 percent per year. In the EEA Base Case environment where gas use is projected to grow, new supplies from a variety of sources will be necessary. We estimate that the U.S. and Canada have well over 200 Tcf of proven gas reserves and well over 1,700 Tcf of gas resource, assuming current E&P technologies. However, the cost of developing that gas resource has risen in recent years as gas producers have focused on developing more costly unconventional gas resource (i.e., coal bed methane, deeper low permeability formations, and shale formations) and drilling costs have escalated with increased rig activity. Thus, although there is abundant domestic supply, the cost of that supply is greater than it has historically been, yielding upward pressure on gas prices. The increased cost of supply has created a renewed focus on new frontier supply development, most notably development of LNG imports and Arctic gas. Thus, most analysts are projecting significant growth in LNG imports in the foreseeable future, and some analysts expect that Arctic gas development may finally become a reality. In that vein, EEA projects that LNG imports and Arctic gas will become a significant portion of North America s gas supplies within the next 10 years. To satisfy the consumption growth discussed above, EEA projects that U.S. and Canada gas production will grow by 0.5 percent per year from a base annual production of a little over 25 Tcf to upwards of 27 Tcf in 2025 (Table 7). Most of the growth occurs as a result of Arctic gas development and unconventional gas development in the Rocky Mountain area and elsewhere. Even more striking is the growth in LNG imports, which are projected to Energy and Environmental Analysis, Inc. 42

53 EEA Final Report January, 2007 grow from a mere 1.7 Bcfd (approximately 600 Bcf) last year to over 20 Bcfd (approximately 7,300 Bcf) in 2025 (Figure 14). Figure 13 Projected U.S. and Canada Natural Gas Consumption (Tcf per Year) Source: Energy and Environmental Analysis, Inc (Trillion Cubic Feet, Tcf) Delta Delta Power Generation +3.8 Tcf +5.4 Tcf Industrial Commercial Residential Other Tcf +0.5 Tcf +0.9 Tcf +0.2 Tcf +1.4 Tcf +0.7 Tcf +1.3 Tcf +0.3 Tcf Table 7 U.S. and Canada Production (Bcf per Year) Source: Energy and Environmental Analysis, Inc. Change Gulf Offshore 5,123 4,688 4,461 4,069 3,484 3,676 3,809 3,808 3,700 (369) Gulf Onshore 5,308 5,213 5,324 5,417 5,384 5,506 5,368 5,240 5,078 (339) Western Canada 6,233 6,144 6,260 6,265 6,283 6,159 6,083 5,652 5,590 (675) Mid-Continenet 2,214 2,103 2,058 2,036 2,019 2,017 1,914 1,822 1,756 (280) Permian 1,506 1,491 1,467 1,479 1,480 1,436 1,406 1,389 1,366 (113) San Juan Basin 1,421 1,417 1,395 1,400 1,401 1,364 1,338 1,315 1,274 (126) Rockies 1,725 1,864 1,981 2,115 2,266 2,890 3,262 3,462 3,818 1,703 Arctic Gas ,142 2,493 2,540 2,120 All Other 2,164 2,115 2,123 2,112 2,109 2,267 2,327 2,340 2, Total 26,117 25,455 25,486 25,314 24,846 25,753 26,650 27,522 27,574 2,261 Energy and Environmental Analysis, Inc. 43

54 EEA Final Report January, 2007 Figure 14 Projected North American LNG Imports by Region (Bcfd) Source: Energy and Environmental Analysis, Inc (Billion Cubic Feet per Day, Bcfd) LNG Imports Total 1.7 Bcfd by 2005, 14.3 Bcfd by 2015, and 22.0 Bcfd by 2025 U.S. Gulf Coast U.S. & Canada East Coast U.S. West Coast and Baha Mexico Other Mexico While there is no appreciable natural gas production in Manitoba, the province is in close proximity to major gas producing basins in Alberta, and is well connected via backhaul on TransCanada and forward haul on a variety of U.S. pipelines to other major producing regions, including the mid-continent and U.S. Rocky Mountains. Centra Manitoba is currently purchasing natural gas commodity from the Western Canadian Sedimentary Basin (WCSB) the U.S. Mid-Continent (Kansas and Oklahoma) and Louisiana. Production is expected to be flat or declining in these regions in the mid term. Currently, pipeline access from the Rocky Mountain producing basins to Manitoba is limited by pipeline capacity flowing east from the Rockies into the Midwestern U.S. However, successful completion of the Rockies Express and/or other competing pipeline projects would provide additional capacity from the Rockies to the major Midwestern pipelines, including ANR, and provide a viable source of natural gas commodity into midwestern markets, including into ANR Michigan storage. Northern Rocky Mountain producing basins, most notably the Uinta, Piceance, and Greater Green River Basins located in southwestern Wyoming, northwestern Colorado, and northeastern Utah have been growing significantly during the past few years, and are projected to continue to grow in the foreseeable future. The EEA Base Case projects Energy and Environmental Analysis, Inc. 44

55 EEA Final Report January, 2007 that gas production from these basins will nearly double from a level of about 1.5 Tcf last year to almost 3 Tcf in Natural Gas Prices EEA is projecting a Base Case environment with growing gas demand and increased reliance on new supplies that will be potentially more costly to develop. In this environment, WCSB gas prices are projected to average between $8 and $10 per GJ on a real dollar basis (Figure 15) for the next several years. The case shows that relatively high and volatile gas prices will continue at least during the next few years until LNG imports can enter the market in sufficient amounts to have a noticeable impact on gas prices. 11 Prices are projected to moderate as LNG imports and Arctic gas are developed, but again rebound in the longer-term to levels that support continued supply development to satisfy demand. Figure 15 Projected Gas Prices (2005 C$ per GJ) Source: Energy and Environmental Analysis, Inc (2005 C$/GJ) AECO Henry Hub Dawn Opal Kansas 11 Near-term gas prices are very difficult to predict as the market is very sensitive to weather. Warmer than normal winter weather can lead to lower winter prices, as well as summer/fall price collapses as storage is filled. However, we expect these price decreases to be short-lived and unlikely to persist as storage levels are depleted during the subsequent winter. Again, this conclusion is sensitive to weather, most notably, hurricane activity and summer and winter temperatures. Energy and Environmental Analysis, Inc. 45

56 EEA Final Report January, 2007 Of course there are significant uncertainties in the EEA Base Case, as there are in any projection. In a constrained supply and robust demand environment, it can reasonably be expected that upward price pressure would persist, and gas prices could climb to and remain at above C$10 per GJ at many locations throughout North America. In this environment, significant price volatility would be expected. Conversely, if a robust supply and low demand environment were to evolve, gas prices could conceivably decline to $3 per GJ, which would be consistent with the 1990s price environment which was characterized by excess gas supply. Such an environment seems less likely because the prices that would materialize in the marketplace would be unlikely to support the supply development necessary for the low prices to persist. However, the results of alternate scenarios evaluated by EEA suggest that there is a potentially wide range for future gas prices. Even in the near-term, there is the potential for much wider than typical volatility in prices. Figure 16 illustrates EEA s forecast for the range in average price of gas at AECO for 2007 based only on differences in weather. 12 This chart summarizes 79 different forecasts for AECO gas prices. The only change between the forecasts is weather. The forecasts use weather data for 74 years of historical weather. Figure 16 Impact of Weather on AECO Near-Term Prices AECO Price Distribution For Jan Dec Average US$6.80 Base Case US$6.91 Observations % Fewer Heating Degree Days Than Normal 8% More Heating Degree Days Than Normal to to to to to to to to 8.00 US$/MMBtu 8.01 to to to to to This figure is shown in U.S. dollars per MMBtu to be consistent with the methodology used to generate the chart. Energy and Environmental Analysis, Inc. 46

57 EEA Final Report January, Changes in Natural Gas Supply and Transportation Patterns Gas delivery throughout North America is made possible by an extensive pipeline network that includes over 200,000 miles of interstate pipeline in the U.S., 60,000 miles of inter-provincial pipeline in Canada, and 100,000 miles of intrastate pipeline. This pipeline network has been relied on to transport significant volumes of gas from supply areas to market areas throughout North America (Figure 17). As supply and demand continue to evolve over time, EEA projects that significant changes in physical flow will occur. EEA projects that physical flow will substantially increase out of the Rocky Mountains both eastward and westward as robust supply growth continues in the area (Figure 18). Also, LNG imports will tend to dramatically shift flow patterns as gas supplies flow directly from the LNG facilities into different markets or other supplies are displaced into different markets as a result of the imports. Figure 17 Average Flows, 2005 (MMcfd) Source: Energy and Environmental Analysis, Inc Everett Elba Island Cove Point EEA April 2006 Base Case Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease Lake Charles 2013 & Gulf Gateway 1509 Energy and Environmental Analysis, Inc. 47

58 EEA Final Report January, 2007 Figure 18 Interregional Changes in Pipeline Flow 2005 to 2015 (MMcfd) Source: Energy and Environmental Analysis, Inc. Pipeline Flow (MMcfd) Change from 2005 to 2015 Jordon Cove (491) 254 (69) 27 (10) (555) (1256) (290) (174) (918) (225) (390) (689) (113) 282 (11) 597 (165) (379) (15) Cancouna 382 Canaport (65) 177 Neptune 53 Everett Costa Azul (431) EEA July 2006 Base Case Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease (438) (267) (809) (See Footnote A) (355) (40) (3) (1278) (29) 202 Golden Free-Pasport Gulf LNG (225) 1807 Lake 1085 (214) Energy 1165 Charles LLC Gulf Sabine Creole 718 Gateway Altamira Pass Trail Cameron 304 Cove Point 1098 Elba Island 290 Florida (Offshore) 5.5 Impact of Demand and Production Trends on TransCanada EEA projects that flows are likely to decline on TransCanada as a result of stable to declining WCSB gas supplies and increasing Alberta natural gas demand. Figure 19 shows historical monthly flows on TransCanada from Saskatchewan into Manitoba. The loss of gas production in the U.S. Gulf Coast, and the resulting increase in demand for Alberta gas from traditional Gulf Coast customers in the U.S. Midwest and Northeast, combined with increases in production resulting from the price induced increase in exploration and development activity in Alberta resulted in a substantial increase in TransCanada Pipeline flows into and through Manitoba during the later half of 2005 and the first half of However, this growth trend is not expected to continue. As discussed in more detail in section three, and documented in Appendix A, EEA expects WCSB production to stabilize and decline from current production levels (Figure 20). Combined with the expected growth in natural gas demand in Alberta and Energy and Environmental Analysis, Inc. 48

59 EEA Final Report January, 2007 Saskatchewan (Figure 21), this is expected to result in a substantial decline in natural gas available for export from the WCSB until the Alaska gas pipeline is completed, which appears unlikely to occur prior to While TransCanada is not the only pipeline exporting natural gas from Alberta, TransCanada projects that most of the decline in exports is likely to occur on the TransCanada system, while the other pipelines, including Alliance and Northern Border, are likely to see only limited declines in pipeline flows. In general directional terms, EEA agrees with the TransCanada assessment of future flows. EEA s forecast of the disposition of WCSB natural gas supply is shown in Figure 22. Total supply is projected to decline through 2015, while Alberta and Saskatchewan demand are projected to increase rapidly (primarily to meet industrial demand to produce oil from tar sands). Exports at Kingsgate, Monchy, and via Alliance are expected to be relatively stable, resulting in TransCanada as the primary swing pipeline. Figure 19 Historical Natural Gas Flows Through Manitoba on TransCanada Source: Lippman Consulting, Inc. 9,000 8,000 7,000 6,000 (TJ's per Day) 5,000 4,000 3,000 2,000 1,000 - Jan-03 Apr-03 Jul-03 Oct-03 Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Oct-05 Jan-06 Apr-06 Jul-06 Energy and Environmental Analysis, Inc. 49

60 EEA Final Report January, 2007 Figure 20 WCSB Natural Gas Production Forecast Source: Energy and Environmental Analysis, WCSB Gas Production Forecast by Type Bcf per Day ASM Conventional ASM Coalbed BC Conv. BC CBM Figure 21 EEA Natural Gas Demand Forecast for Alberta and Saskatchewan Source: Energy and Environmental Analysis, 2,000 1,800 1,600 1,400 (PJ's per Year) 1,200 1, Pipeline Fuel Industrial/Power Generation 400 Commercial 200 Residential Energy and Environmental Analysis, Inc. 50

61 EEA Final Report January, 2007 Figure 22 Forecasted Disposition of Alberta/Saskatchewan Natural Gas Supply Source: Energy and Environmental Analysis, 7,000 6,000 5,000 Consumption (PJ's per Year) 4,000 3,000 Exports to Kingsgate Exports to Alliance Exports to Monchy 2,000 1,000 Exports to Manitoba EEA s mid-term forecast of pipeline flows into and out of Manitoba on TransCanada is shown in Figure 23. EEA expects total flows on the TransCanada mainline into Manitoba to decline from current levels of around 2,320 PJs per year (6,500 TJs per day) to about 1,750 PJs per year by EEA is projecting that about two thirds of the decline will be concentrated on TransCanada exports at Emerson, and one third of the decline will take place on the TransCanada Northern Leg into Ontario. While the allocation of the decline represents an EEA forecast, it is consistent with the expected increase in natural gas supplies from the Rocky Mountains into the Great Lakes Gas Transmission System market via the proposed Rockies Express pipeline. Energy and Environmental Analysis, Inc. 51

62 EEA Final Report January, 2007 Figure 23 Forecasted Disposition of TransCanada Pipeline Flows into Manitoba Source: Energy and Environmental Analysis, 3,000 2,500 2,000 (PJ's per Year) 1,500 TranCanada Flows to Emerson 1, Total Manitoba Consumption TranCanada Mainline Flows to Ontario Impact of Market Changes on Relative Gas Market Prices The historical natural gas price basis between AECO and other major natural gas market centers has varied substantially over the last four years (Figure 24), with AECO prices falling to $3.00/GJ below Henry Hub prices after Hurricane Katrina and Rita in late 2005, before coming back to about $1.00 per GJ below Henry Hub in the summer of During the same time period, prices on the ANR SW leg fell below AECO prices for short periods during the 2005/2006 Winter. In the long-term, EEA is projecting natural gas price differences between AECO and other North American markets to decline (Figure 25 and Figure 26), as the decline in availability of Alberta gas, and the increase in availability of natural gas into the U.S. Midwest from other sources, including the Rocky Mountains, and from LNG imports into the U.S. Gulf Coast changes the relative balance in the market. The price of natural gas at AECO relative to prices at other major market hubs has the potential to be extremely volatile. Market fundamentals will act to drive the price of gas at AECO upward relative to other major market centers in the U.S., including Chicago, Emerson, the Rocky Mountains, and Henry Hub. However, the TransCanada tolling structure is likely to increase the cost of transportation capacity on TransCanada, which should act to suppress prices at Empress. Energy and Environmental Analysis, Inc. 52

63 EEA Final Report January, 2007 Figure 24 Average Daily Natural Gas Price Basis Relative to AECO Source: Energy and Environmental Analysis, 3.50 Average Natural Gas Basis Relative to AECO (C$ per GJ) Henry Hub Emerson Chicago Citygates ANR Oklahoma Dawn (0.50) Sep-02 Dec-02 Mar-03 Jun-03 Sep-03 Dec-03 Mar-04 Jun-04 Sep-04 Dec-04 Mar-05 Jun-05 Sep-05 Dec-05 Mar-06 Jun-06 Figure 25 EEA Long-Term Forecast of Basis Between AECO and Other Major Natural Gas Markets Source: Energy and Environmental Analysis, $2.00 $1.50 $1.00 Henry Hub, Louisiana Chicago, Illinois Dawn, Ontario Opal, Wyoming Kansas/Oklahoma (2005 C$/GJ) $0.50 $- $(0.50) $(1.00) $(1.50) Energy and Environmental Analysis, Inc. 53

64 EEA Final Report January, 2007 Figure 26 EEA Near-Term Forecast of Basis Between AECO and Other Major Natural Gas Markets Source: Energy and Environmental Analysis, (2005 C$/GJ) $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $- $(0.50) $(1.00) Henry Hub, Louisiana Chicago, Illinois Dawn, Ontario Opal, Wyoming Kansas/Oklahoma Jan-05 May-05 Sep-05 Jan-06 May-06 Sep-06 Jan-07 May-07 Sep-07 Jan-08 May-08 Sep-08 Jan-09 May-09 Sep-09 Jan-10 May-10 Sep-10 As a result, the price differential between AECO and Chicago, and AECO and Ontario may be supported by the TransCanada regulatory structure, even though market forces would indicate a substantial compression in prices. If market forces start to dominate the regulatory structure, which will occur if capacity contract holders on TransCanada begin releasing TransCanada capacity at rates below tariff costs, prices could rise very quickly relative to other markets and the pipeline basis collapses. The relationship between commodity prices in the US, and commodity prices in Alberta is not a critical issue for Centra baseload supply purchased for direct consumption in Manitoba, since the cost of Alberta commodity delivered to Manitoba from Alberta should always be lower than the cost of natural gas commodity delivered to Manitoba via backhaul from the U.S. However, changes in the relative price of gas between AECO and the U.S. supply regions can have a significant impact on the relative cost of natural gas injected into ANR storage. Currently, most of the Centra natural gas injected into ANR Michigan storage is primary gas supply purchased in Alberta. The cost of purchased gas in Alberta plus the incremental cost of transportation to ANR Energy and Environmental Analysis, Inc. 54

65 EEA Final Report January, 2007 storage typically has been less than the cost of gas purchased in the U.S. and transported to ANR storage. However, this has been true primarily due to the relatively large gas cost advantage in Alberta relative to other sources that has existed during most periods. A fundamental shift in the price of natural gas in Alberta relative to other U.S. sources could very well change the economics of natural gas delivered to ANR Michigan storage. As shown in Figure 25 and Figure 26, EEA s Base Case forecast of natural gas prices is showing just this type of shift in natural gas prices. Between 2010 and 2015, EEA is projecting the price of natural gas along the ANR Southwest leg in Oklahoma and Kansas to average about $0.05 per GJ below the price of gas at AECO, and the price at Henry Hub and along the Southeast (Louisiana) leg of the ANR pipeline to fall to near parity with AECO prices. 5.7 Impact of Market Changes on Natural Gas Price Volatility One of the key issues facing Centra Manitoba is the current volatility in natural gas markets. The current tight market conditions are leading to wide swings in natural gas market price due to any factor that either increases or decreases natural gas demand or supply. As a result, the loss of production capacity in the U.S. Gulf of Mexico due to hurricane activity in the fall of 2005, combined with major increases in world oil prices lead to major run-up in North American natural gas prices. However, growth in supply and demand destruction due to the higher prices, combined with a warmer than normal winter, and a relatively modest summer power generation load have resulted in very high storage fills, and falling natural gas prices in the fall of The primary driver for this price volatility is the extremely tight balance between supply and demand. EEA s forecast indicates that this tight balance is likely to persist for the foreseeable future, leading to major swings in natural gas prices around a historically high average. The swings in natural gas prices increase the risks associated with any natural gas purchasing strategy. 5.8 Value of Storage In the past, one of the main values of storage was the ability to arbitrage between natural gas prices in the summer, which were typically lower than the annual average price and the price of natural gas in the winter. In the recent natural gas market, the price difference between winter and summer is at an all-time high, resulting in an alltime high in the current value of natural gas storage. However, as prices stabilize, and as LNG imports increase, the seasonal price difference is expected to decline. EEA s forecast of the price difference between the average summer injection period (May September) price, and the Winter withdrawal period price (December February) for the next few years is shown in Figure 27. As noted above, the summer/winter price Energy and Environmental Analysis, Inc. 55

66 EEA Final Report January, 2007 differential is currently at an all time high, however EEA expects the actual natural gas differential to decline for the 2007/08 and 2008/09 winters, before climbing again in 2009/2010 winter. Figure 27 Seasonal Arbitrage Value of Natural Gas Storage Source: Energy and Environmental Analysis, Platt s Gas Daily (Winter - Summer Price Differential (C$/GJ) AECO Henry Hub Chicago NYMEX Strip (0.50) 2005/ / / / /10 Note that, as shown by the NYMEX values in the figure, the natural gas market is still expecting a significant seasonal price spread in 2007/08 as well as 2008/09. The storage values that market participants are willing to pay are determined by market expectations, and ability to hedge seasonal prices, hence the immediate value of storage is determined more by the NYMEX future strip rather than actual prices. The NYMEX strip behavior tends to change based on experience with actual prices, hence lags the actual market. 5.9 Market Liquidity and Alternative Sources of Natural Gas Supply Most natural gas transactions occur at a relatively small number of pricing points often referred to as market centers. Manitoba itself currently has no recognized natural gas pricing points. Therefore, Manitoba gas purchases must be indexed to a supply area 13 NYMEX Represents value of Henry Hub futures strip. The 2006/07 value is based on the April 28, 2006 strip. The 2007/08 and 2008/09 values are calculated from the October 2, 2006 strip. Energy and Environmental Analysis, Inc. 56

67 EEA Final Report January, 2007 pricing point, such as the AECO hub in Alberta, or to more liquid markets downstream in Ontario (Dawn) or the U.S. Midwest (Chicago). EEA has assessed market conditions at a variety of potential market centers available to Centra Manitoba. These include AECO, Empress, Emerson, ANR SW, Opal, Cheyenne, Henry Hub, Dawn and Chicago. AECO: The AECO price index tracks transactions in Alberta at the AECO-C, NIT Hub in southeastern Alberta. AECO-C is the principle storage hub on the Alberta TransCanada Pipeline. Chicago Citygate: The price index tracks deliveries into the Nicor Gas, Peoples Gas Light & Coke, North Shore Gas and Northern Indiana Public Service citygates in the Chicago metropolitan area. Receipts are from Natural Gas Pipeline Co. of America, ANR Pipeline, Alliance Pipeline, Northern Border Pipeline, and Midwestern Gas Transmission. Emerson: The Emerson, Viking GL index tracks deliveries into Great Lakes Gas Transmission from TransCanada Pipelines at the Emerson 2 compressor station at the U.S./Canadian border at Emerson, Manitoba and deliveries into Viking Gas Transmission from TransCanada at the Emerson 1 station. Dawn: The Dawn, Ontario price index tracks deliveries from the Union Gas Dawn Hub, a gathering point for 15 adjacent storage pools in Ontario near Port Huron, Michigan on the U.S./Canadian border. Included are deliveries into TransCanada Pipeline at Kirkwall, Ontario; deliveries into Great Lakes Gas Transmission at St. Clair, Michigan; deliveries into Consumers Energy at Bluewater, Michigan; deliveries into Panhandle Eastern Pipe Line at Ojibway, Michigan; and deliveries into Dawn storage. Deliveries from Union into TransCanada at Parkway, Ontario are not included. Kern River, Opal Plant: The Kern River, Opal Plant price index tracks transactions into Kern River at the Opal, Wyoming processing plant and the Muddy Creek compressor station in southwestern Wyoming where Kern River connects with the Northwestern, Questar, and Colorado Interstate Gas pipelines. Gas traded at the Opal plant that is not nominated into a specific pipeline is included in the price index. Cheyenne: The Cheyenne Hub price index currently tracks transactions into the Trailblazer pipeline, Public Service Company of Colorado, and Colorado Interstate Gas in the area around the Cheyenne Hub in northeast Colorado. ANR Oklahoma (ANR SW): ANR Oklahoma tracks deliveries into ANR pipeline at the start of the Southwest mainline at the Custer, Oklahoma compressor station, through the Texas Panhandle to the Greensburg, Kansas station. ANR Louisiana (ANR SE): ANR Louisiana tracks deliveries into ANR pipeline along the southeastern Louisiana lateral, starting offshore, and running to the Patterson, Louisiana compressor station. The index also includes transactions Energy and Environmental Analysis, Inc. 57

68 EEA Final Report January, 2007 into the ANR lateral from the HIOS system downstream of West Cameron 167 offshore to the Grand Chenier, Louisiana station onshore to the Eunice station and Eunice pool. The criteria the EEA report addresses are related to the location of the gas and would be expected to apply to all suppliers who can provide gas at that location. These locational criteria include: Liquidity of supply in a basin or hub: This is important in that it helps ensure competitive bids in the RFP process, good price discovery for index pricing and the capability to buy unexpected incremental requirements or sell excess supplies. Good liquidity also makes it more likely that Centra can acquire supplies in emergency cases of supplier default or force majeure. Degree of competition among suppliers: Like liquidity, a large number of suppliers helps ensure a successful RFP process with favorable price results and increases the chances of obtaining backup supplies when needed. Expected long-term production trends (resource base, F&D costs): Depending on the length of supply and pipeline contracts, the region s ability to replace reserves or grow production may be important. Availability of storage in basin or hub. Storage can be used by Centra to level out wellhead takes and to provide physical price hedges. The availability of storage also makes more likely an active market for swing gas, balancing services and emergency supplies. Adequate gas pipeline service out of the area. A supply location should be ranked higher if adequate gas pipeline capacity is available and relatively inexpensive Natural Gas Market Liquidity EEA evaluated the transaction liquidity for the market centers considered potential alternative supply points for Centra Manitoba. The liquidity evaluation focused on the size and volatility of the market, the stability of natural gas pricing, and access to the market. A more detailed review of liquidity concepts is included in Appendix D. The transaction volumes at each of these points are shown in Figure 28, and the key volume and price volatility parameters for each point are shown in Table 8 and Table 9. The volume and price data shown in the figure and tables highlights the significant volatility in transaction volumes and prices at even the most liquid of points, and the importance of relying on points with sufficient volume to ensure reliable transaction capabilities. Energy and Environmental Analysis, Inc. 58

69 EEA Final Report January, 2007 Figure 28 Daily Natural Gas Transaction Volumes Source: Platt s Gas Daily, AECO, Alberta Chicago Citygates, Illinois Emerson/Viking, Manitoba ANR SW, Oklahoma Opal, Wyoming Henry Hub, Louisiana Dawn, Ontario Northern Demarcation, Iowa ANR SE, Louisiana (000 MMBtu/day) Sep-02 Dec-02 Mar-03 Jun-03 Sep-03 Dec-03 Mar-04 Jun-04 Sep-04 Dec-04 Mar-05 Jun-05 Sep-05 Dec-05 Mar-06 Jun-06 Table 8 Average Daily Transaction Volumes Source:Platt s Gas Daily Henry Hub (000 MMBtu/Day) Emerson/ Viking Chicago Citygates Northern Demarc ANR SW ANR SE Cheyenne Opal AECO Dawn Summer (April -October) , Average Winter (Nov - March) , , Average Annual Average Energy and Environmental Analysis, Inc. 59

70 EEA Final Report January, 2007 Table 9 Volatility of Daily Transaction Volumes Standard Deviation in Daily Transaction Volumes Reported in Platt's "Gas Daily" (000 MMBtu/Day) Henry Hub Emerson/ Viking Chicago Citygates Northern Demarc ANR SW ANR SE Cheyenne Opal AECO Dawn Summer (April -October) Average Winter (Nov - March) Average Annual Average EEA s conclusions concerning liquidity at each of these points are summarized below. AECO: AECO is a highly liquid market. There are sufficient market players using the hub, and sufficient transaction volumes to ensure the availability of natural gas at a fair market price under almost all circumstances. AECO is, and should remain the primary market center for the purchase of natural gas for Manitoba gas consumers. Empress: Empress represents the start of the TransCanada Mainline Pipeline. Empress closely tracks the AECO market, but does not support the consistent volume of transactions observed at AECO. While Empress would be an acceptable market center for some transactions, there would be very limited, if any advantages to transactions conducted at Empress rather than at AECO. Emerson/Viking: The closest reported trading point to the Centra Manitoba service territory is just downstream of the Manitoba service territory at the Canadian/U.S. Border crossing at Emerson. This point provides relatively convenient access to Manitoba markets via backhaul on TransCanada. However, the point has limited liquidity due to relatively modest trading volumes, and market volatility related to volumes and prices. Trading volumes have increased and become more stable in the last couple of years, indicating an improvement in liquidity at this point. Chicago Citygate: The Chicago market is a highly liquid market, with large volumes and consistent prices. Although Chicago is not optimally placed to serve the Manitoba market, it is one of the largest and most stable market centers in North America. Chicago is a major market center that can be Energy and Environmental Analysis, Inc. 60

71 EEA Final Report January, 2007 accessed by a variety of natural gas pipelines and has relatively direct access to ANR Michigan storage. As such, Chicago could play an effective role in the Centra Manitoba supply strategy for supplemental gas in terms of pricing, and potentially as a location for exchange transactions with marketers and other gas market participants. Opal -- Wyoming: Opal is the largest market center in the U.S. Rocky Mountains with pipeline capacity that could potentially serve the Chicago market. Opal is the most liquid trading point in the U.S. Rockies. However, pipeline constraints limit the liquidity of this market during certain times of the year. Cheyenne -- Wyoming: The Cheyenne Hub currently has very low liquidity due to limited transactions volumes, relatively high price volatility and pipeline constraints that can limit pipeline flows leading away from the Hub. The Cheyenne Hub potentially will be one of the fastest growing market centers in the U.S. The Cheyenne Hub is the receipt point for the proposed Rockies Express pipeline. Hence, it would be a logical trading point for gas flowing on the new pipeline and might grow into a major trading point if/when the pipeline is completed. ANR SE -- Louisiana: The ANR Louisiana (SE) price index is relatively lightly traded and should be considered a low/moderate liquidity point. The volume is insufficient to support a liquid market. However, the location of this market in a major producing region provides a variety of options for purchasing natural gas supply, indicating that supply should be available on a consistent basis, although prices may reflect more market volatility than is desirable. ANR Oklahoma: The ANR Oklahoma price index is very lightly traded, and should be considered a low liquidity point. The volume is insufficient to support a liquid market. However, the location of this market in a major producing region provides a variety of options for purchasing natural gas supply, indicating that supply should be available on a consistent basis, although prices may reflect more market volatility than is desirable. Henry Hub -- Louisiana: Henry Hub is typically considered to be the most liquid market in the U.S. Henry Hub serves as a general index for current natural gas market prices, as well as futures prices throughout North America. While not optimally placed to serve as a market center for Manitoba, Henry Hub is located near the ANR Pipeline Southeast leg, and provides transaction liquidity assurance for natural gas transported on this pipeline. Dawn -- Ontario: Dawn is a highly liquid market center. Dawn is not optimally placed to serve Manitoba since it is well downstream of the ANR storage capacity held by Centra Manitoba, as well as the Centra Manitoba service territory. However, Dawn is a major market center accessed by a variety of natural gas pipelines and could play an effective role in the Centra Manitoba supply strategy in terms of pricing, and potentially as a location for exchange transactions with marketers and other gas market participants. Energy and Environmental Analysis, Inc. 61

72 EEA Final Report January, Manitoba Natural Gas Market Storage Potential There are currently no underground natural gas storage fields in Manitoba. There is some potential for the development of underground salt cavern storage near the Manitoba/Saskatchewan border. However, there have been no firm proposals to develop this storage. As of July 2005, Centra had evaluated the potential to develop these storage fields directly, but had, at least for the short-term, decided not to proceed. Energy and Environmental Analysis, Inc. 62

73 EEA Final Report January, STRATEGY DEVELOPMENT FOR PRIMARY GAS ACQUISITION 6.1 Introduction Centra currently purchases all of it s primary gas from Nexen under a three part umbrella contract. Baseload gas supplies, purchased on a 100 percent take or pay basis, are used to meet baseload demands year-round, and to fill Michigan storage. Swing gas supplies are nominated on a daily basis to meet daily requirements above the baseload levels throughout the year. This section of the report addresses issues related to the acquisition of primary gas, including fundamental questions related to Centra s overall approach to supply planning, the sources and basins for gas supply alternatives and options and potential costs for replacing primary gas supplies and meeting Centra swing requirements. 6.2 Strategic Framework Centra Supply Strategy The basic terms and approaches to renewing/replacing the existing Nexen contract for supply of primary natural gas are predicated on the overall supply strategy adopted by Centra. While a decision on how to proceed with the Nexen contract needs to be made in the relatively near future, and the fundamental structure of the existing contract may not change, Centra needs to either reaffirm the basic elements of it s current strategy for providing primary gas, or decide to pursue one of two alternative paths, prior to deciding how to proceed with the contract renewal/replacement. In Centra s current supply strategy, Centra has contracted with a specific natural gas marketer to provide both base and swing gas services. Centra has, in essence, contracted with an outside party to provide the significant majority of its natural gas supply. However, Centra still maintains the balancing function on TransCanada, as well as the responsibility for peak day planning and implementation. Centra also maintains operational control over both the upstream and downstream pipeline and storage assets held under contract by Centra. Energy and Environmental Analysis, Inc. 63

74 EEA Final Report January, 2007 This approach is relatively uncommon, but is not unusual. Most utilities retain the responsibility for meeting daily swing requirements more fully within the utility than has been Centra s recent practice. However, a few utilities have moved much further away from the traditional gas supply model than Centra has, and have developed supply strategies that assign additional contract assets and operational decision making to a third party, normally a natural gas marketer. In EEA s opinion, the current Centra approach is likely to be more efficient, and in some ways more reliable than the traditional LDC supply planning model for Centra. The swing services provided by the contract with Nexen allow the gas marketer to combine gas requirements in different markets, and pipeline and storage assets both upstream and downstream of Centra s service territory in a way that would be difficult for Centra to match at a similar cost. Providing the same function independent of a major natural gas marketer would likely require holding additional storage in Alberta, as well as developing a much larger and more active gas acquisition department. While Centra is ceding some control to Nexen, and exposing Centra to a certain level of risk associated with the financial viability of the gas marketer, EEA believes that this is an appropriate tradeoff for the cost savings that should be available to a marketer operating in both upstream and downstream markets, as long as part of those cost savings are passed along to Centra customers Impact of TransCanada Tariff Structure on Centra Options The options available to Centra are affected to a significant degree by the structure of the tariff services offered by TransCanada and the regulatory framework for the pricing of those services. While the structure of services on any pipeline in North America has some elements that differentiate that pipeline from others, there are number of aspects to the services, rates and rate regulation on TransCanada that are markedly different from other North American pipelines, particularly those in the United States. Differences that have particular significance to the structure and evaluation of alternative gas supply options for Centra include: 1) The absence of regulatory codification of secondary/alternative receipt and delivery point rights on the TransCanada Pipeline FERC Order 636 directed U.S. interstates pipelines in the United States to establish in their tariffs, a right for shipper s to designate receipt and delivery points that differ from the primary points specified under a contract for firm service. While the specifics of the nominations of alternative receipt and delivery points often differ on individual pipelines, the effect of the implementation of this aspect of FERC restructuring creates additional flexibility for shippers to manage pipeline capacity and gas supply contracts. On the TransCanada pipeline system, a shipper can request a diversion of gas being transported under a firm contract that can create some flexibility. However, without a broader policy for alternative receipt and delivery point rights, there is less certainty that the nomination along an alternative path can be reliably accomplished under an existing contract. Energy and Environmental Analysis, Inc. 64

75 EEA Final Report January, ) The absence of segmentation rights for firm pipeline capacity FERC Order 637 directed interstates pipeline in the United States to allow shippers to segment pipeline capacity held under contract to the greatest extent possible. The segmentation rights on most long-line pipelines include the right to backhaul along the transportation path, thereby potentially increasing the total volume of gas delivered under a firm contract. TransCanada Pipeline has no such segmentation rights. Under a hypothetical segmentation program for TransCanada, a shipper that holds a contract for 1,000 GJs per day from Empress to TQM could segment the capacity to increase the utilization. For example, the shipper could conceivably nominate 1,000 GJs to be moved from Empress to a point in Manitoba and nominate a 1,000 GJs backhaul from the Southwest zone to a different point in Manitoba that is downstream of the first point and nominate 1,000 GJs of gas from Parkway to TQM, all under the same contract. All of the nominations would be confirmed so long as there is space available at each of the individual points. 3) The absence of discounting authority and policies that encourage discounting of firm and/or interruptible pipeline transportation service TransCanada does not have the authority to sell firm transportation service at any rate other than the NEB approved tariff rate. By contrast, the cost of service rates established for FERC regulated pipelines specify a maximum regulated rate and a minimum rate that is set to recover the variable costs of the capacity. While there is no requirement that a pipeline must sell available capacity at any rate lower than the maximum rate, that pipeline may choose to discount capacity to meet competition and minimize the potential for under-recovery of the revenue requirement. Pipelines use this selective discounting authority under market conditions where there is insufficient demand to contract all of the capacity at the maximum rate. If the discount results in an under-recovery and the pipeline can demonstrate the discount was necessary to meet the market conditions, the pipeline may apply for an adjustment in the billing determinants used in a subsequent rate case so as to have the opportunity to recover the prudently incurred costs. FERC regulated pipelines have similar discount authority for the sale of interruptible capacity. By contrast, TransCanada has a floor price for IT capacity equal to 110 percent of the volumetric equivalent of the 100 percent load factor rate. From the perspective of potential suppliers of gas to Centra, these differences create significant differences in the manner in which production, transportation and storage assets can be managed to meet the requirements of the Centra system. These limitations limit the operational flexibility of a marketers portfolio of assets. 6.3 Sources of Gas Supply: Basin Options and Analysis of Basin Diversification Currently, most of the natural gas commodity purchased by Centra Manitoba is sourced from the Western Canadian Sedimentary Basin to the west of the Centra Manitoba service territory. Centra purchases seasonal natural gas supplies from the Mid- Energy and Environmental Analysis, Inc. 65

76 EEA Final Report January, 2007 Continent along the southwest and southeast legs of the ANR pipeline system for injection into ANR storage in Michigan, and peak day supply as a delivered service at the Centra Manitoba citygate. One of the key questions faced by Centra is whether or not the current balance of Alberta, U.S. Midwest, and delivered peaking services should be revised, and if so, where should additional supplies come from? Will current market conditions change in ways likely to change the desired mix of Alberta vs. non-alberta supply options? Midwest supplies can be sourced from a variety of sources, including the U.S. Gulf Coast, mid-continent, or Rocky Mountains. Where are the optimum supply sources, and how is the market likely to change in the future? EEA s assessment of current market conditions indicates that the North American natural gas market is in transition. As discussed earlier in this report, there are three fundamental, and predictable shifts in North American markets that could shift Centra Manitoba s supply strategy. These are: 1) The decline in natural gas flows from Empress east on TransCanada pipeline due to the combination of falling WCSB production and rising Alberta and Saskatchewan demand. 2) The potential completion of the Rockies Express pipeline, and the corresponding increase in gas supplies into the U.S. Midwest from the Rocky Mountains. 3) The expected influx of LNG into the U.S. Gulf Coast, which is likely to substantially increase flows on major pipelines into the U.S. Midwest. These three factors are likely to result in a change from the historical price relationships between the WCSB and markets in Chicago and the U.S. Midwest, resulting in a decline in the price premium between Chicago/U.S. Midwest prices relative to AECO prices as gas supply into the Chicago area increases, and supplies flowing out of Alberta decline. Given the location of the Centra Manitoba service territory, these changes would not be sufficient to indicate a fundamental shift in the Centra Manitoba supply strategy, and EEA believes that the primary supply question, how much supply should be sourced from the WCSB vs. from the U.S. Midwest, is unlikely to change in a fundamental way. Normally, a shift in relative prices of natural gas suggests that a modest shift in the source of gas commodity injected into storage might be appropriate. However, given that prices in the U.S. Midwest almost always exceed prices at Emerson, and that Centra is paying backhaul transportation costs on top of the value of the gas removed from Michigan storage, it is unlikely that the change in relative prices will change the fundamental reliance on Alberta supply. Energy and Environmental Analysis, Inc. 66

77 EEA Final Report January, 2007 However, the changes are likely to influence the relative attractiveness of alternative sources of natural gas serving the Midwest, and indicate that a review of alternative sources of U.S. gas for delivery into the upper Midwest might be appropriate Sources of Gas Supply to Meet Primary Flowing Gas Demand Even though Centra Manitoba has some supply diversity in its purchasing strategy, 100 percent of the physical natural gas supply used by Centra customers comes from the WCSB and is delivered to the Centra system from the west on the TransCanada Pipeline system. Even on peak day, when about 45 percent of the nominal supply of natural gas delivered to the Centra service territory comes from withdrawals from Michigan storage and from purchases in Oklahoma, and reaches the Centra service territory via backhaul on Great Lakes Gas Transmission and TransCanada Pipeline, the physical gas consumed is coming from the west. In physical terms, Centra customers are using natural gas delivered to TransCanada by other TCPL customers located downstream of Centra. This gas is replaced further east by natural gas withdrawn from ANR storage in Michigan by Centra Manitoba. This type of operational displacement is common in the gas industry. Given Centra s location, the WCSB is expected to continue to provide the significant majority of all of the natural gas purchased by Centra Manitoba, and with very limited exceptions, all of the natural gas purchased by Centra for immediate consumption (e.g. other than natural gas injected into storage downstream of Manitoba). The cost of purchasing natural gas at AECO and delivering to Manitoba on existing firm capacity on TransCanada will almost always be lower than the cost of purchasing natural gas downstream of Manitoba, even before consideration of incremental backhaul and fuel costs. The potential market centers in the WCSB include AECO NIT, and Empress. AECO is slightly further away from Manitoba than is the Empress trading point, however the variety of services available at AECO, including financial, and monthly, weekly, and daily physical transaction options is much larger at AECO than at Empress. In addition, the overall liquidity at AECO is much greater than at Empress. Hence, EEA recommends purchasing WCSB gas commodity at AECO, or basing purchases for delivery at Empress on AECO prices with an associated cost for delivery to Empress Sources of Gas Supply for Seasonal Injection into Michigan Storage Centra currently purchases (or has the option to purchase) small amounts of natural gas in the U.S. for injection into ANR storage in Michigan. Centra holds firm pipeline capacity on both the ANR Southwest and Southeast legs all the way into ANR storage, hence can purchase natural gas for injection into storage from the market areas served by these pipelines with minimal incremental transportation costs. Energy and Environmental Analysis, Inc. 67

78 EEA Final Report January, 2007 For the past several years, the amount of natural gas purchased from these sources has been minimal due to warmer than normal weather resulting in lower than anticipated natural gas demand. Given both the location of the Centra service territory, which is served directly only by TransCanada, as well as the historic price differential between AECO and other potential sources of natural gas in the U.S., the major rationale for purchasing gas from sources other than Alberta has been supply diversity. However, EEA is projecting a potential realignment in natural gas prices where market forces are likely to increase the price of gas in Alberta relative to other sources, as well as to make additional summer gas available to the U.S. Midwest. This shift suggests that natural gas originating from U.S. sources will become more economic relative to Alberta natural gas for Centra s storage injection program, particularly after the inservice date of new pipeline capacity from the U.S. Rocky Mountain production region to the U.S. Midwest, currently scheduled for January Between 2002 and 2006, U.S. mid-continent gas prices averaged about $0.50 per GJ higher than prices at AECO. EEA s long-term natural gas price forecast indicates that this difference in the market value of gas is likely to decline to $0.06 per GJ between 2007 and 2009, and that natural gas market value in the U.S. mid-continent is likely to average $0.05 per GJ less than the market value at AECO between 2010 and Between 2002 and 2006, Henry Hub prices in Louisiana averaged about $1.06 per GJ above than the price at AECO. EEA s long-term natural gas price forecast indicates that this difference in market value is likely to decline to $0.32 per GJ between 2007 and 2009 and to $0.02 per GJ between 2010 and When the relative cost of pipeline fuel is added to the equation, the U.S. sources of gas become even more favorable. EEA s forecast indicates that for Michigan gas storage injections, U.S. natural gas sources are likely to be less expensive than gas purchased at AECO from roughly 2009 through It is important to note that this transition is dependent on market values being reflected in available prices at AECO, which is a function of the pipeline basis on TransCanada. If TransCanada is able to support the existing basis structure, prices may not converge to the degree forecast by EEA. Given the uncertain and potentially volatile nature of the natural gas price relationship between Alberta and U.S. natural gas production regions, EEA recommends maintaining maximum flexibility to allow storage injection gas to be sourced from either Alberta or U.S. sources depending on the price relationships, consistent with current pipeline capacity contracts on TransCanada and ANR. One of the consequences of this recommendation is that reducing storage injections using Alberta natural gas also reduces the amount of natural gas purchased at favorable Base gas prices under a contract similar to the current Nexen contract, and might increase the amount of Alberta gas purchased under the more expensive swing Energy and Environmental Analysis, Inc. 68

79 EEA Final Report January, 2007 components of the contract. This may slightly increase the average cost of gas purchased in Alberta Potential Sources for U.S. Natural Gas Purchases Centra currently includes natural gas purchases from the U.S. Mid-Continent and from the Gulf Coast region in Louisiana as part of it s supply portfolio. However, Centra has a variety of alternative options including: Purchases at the Chicago natural gas market. Purchases of Rocky Mountain gas transported from Cheyenne to the Chicago area on the proposed Rockies Express Pipeline. Purchases of U.S. Gulf Coast production or LNG imports, transported on ANR or other pipelines to the Chicago area. Since Centra currently holds firm pipeline capacity on both the ANR Southwest and Southeast legs all the way into ANR storage, Centra is able to purchase natural gas for injection into storage from the market areas served by these pipelines with minimal incremental transportation costs. 14 However, while both pipeline legs are served by major natural gas production regions, neither area supports a highly liquid market center. The lack of liquidity at these points does not raise major concerns for natural gas purchased for storage injection. However, the reliance on the ANR Oklahoma leg for some peak day supplies raises some concern about market liquidity for this purpose. Since Centra holds long-term capacity contracts on the ANR pipeline from these points, the incremental costs of purchasing gas from these producing regions is expected to be lower than the cost of acquiring both gas commodity and transportation capacity from other alternative sources in the U.S. This is likely to continue to be the case as long as Centra Manitoba holds long-term firm pipeline capacity on ANR. However, if Centra increases purchases of U.S. gas for storage injection above the levels transportable on existing ANR pipeline capacity, and/or when the ANR pipeline capacity contracts come up for renewal, EEA would recommend that Centra consider Chicago as an alternative market center in order to avoid long-line pipeline capacity commitments. In addition, discounted IT or short-term seasonal firm service should be used for transportation to the storage facilities. Firm backhaul service will remain essential for the reliable delivery of gas to Manitoba from storage during the winter period. 14 Note that any calculation of relative prices needs to consider the value of ANR capacity in the capacity release market during the periods when it is not used by Centra. In the current natural gas market, this value is relatively limited due to heavy discounting on the ANR system, although future values could increase with the growth in LNG load, and the value of capacity north of the proposed Rockies Express interconnect could increase with the availability of additional Rockies natural gas. Energy and Environmental Analysis, Inc. 69

80 EEA Final Report January, Peaking Services Requirements and Analysis Centra currently plans on purchasing up to 63,765 GJ per Day of natural gas delivered to the Centra citygate to meet peak day natural gas requirements. During an average year, Centra expects to draw on these delivered services on about five days during the year, although some years peaking service could be required on as many as 25 days. In other years no peaking services would be required. Even during high usage years, the volumes purchased under peaking service agreements would be small, with peaking services ranging from about 0.2 percent of total requirements in a normal year to about 1.5 percent during a high usage year. Given the total amount of natural gas flowing on TransCanada, EEA expects that sufficient delivered gas options will be available to meet Centra peaking requirements. In the worst case scenario, Centra might have to bid gas away from other high value markets such as the U.S. Northeast. However, even though it may be very expensive, natural gas supply will be available on peak days. The key question is not so much availability as cost. EEA projects that the decline in natural gas available for export from Alberta is likely to increase the cost of delivered gas for peaking services. At this time, EEA has not projected a potential magnitude for this increase. The next question is whether or not Centra should explore an expansion of the current Nexen contract to include the delivered gas services component of the peak day supply portfolio. While EEA has not evaluated any of the existing delivered services contracts, we would recommend consideration of integrating the delivered services agreements into the primary gas contract. Integration would likely stabilize the cost of the peaking service, although potentially at an overall higher cost of gas supply Implications for Phase 2 Analysis This analysis has focused on the existing gas supply contract with Nexen. However, the analysis raises several issues related to the current portfolio of long-term capacity and delivered services contracts. These issues should be evaluated in a follow-on Phase II to this analysis. The key issues raised relative to a Phase II analysis include: Should Centra increase or decrease the amount of storage capacity under contract? Should Centra renew the upstream pipeline capacity contracts on ANR, or allow the contracts to expire to be replaced with purchases at the Chicago market or the Rocky Mountains? Would increases in purchases of supplemental supplies from the U.S. allow for a reduction in TransCanada mainline capacity contracts from Empress to Manitoba? Energy and Environmental Analysis, Inc. 70

81 EEA Final Report January, 2007 EEA s preliminary assessments indicate that additional storage capacity would be highly desirable, although costs are likely to be high, and we have not conducted a benefit to cost analysis. In addition, Centra may want to consider transitioning toward a purchasing strategy including Chicago and/or the Rocky Mountains, rather than renewing upstream capacity contracts on ANR. However the ANR contracts are in effect through 2013, so no decisions are necessary in the short-term. 6.4 Requirements For and Anticipated Costs of Swing Service The Manitoba service territory served by Centra Manitoba has one of, if not the most, variable seasonal demand profile of any major LDC in North America. Figure 6 (in Section 3) illustrates the seasonal nature of weather requirements in Manitoba relative to other areas serviced by TransCanada Pipeline and WCSB supply. This figure indicates that the seasonal weather pattern is more extreme in Manitoba than in any of the other represented regions. In addition, both the year to year weather uncertainty (see Table 2 in Section 3 of this report), and the day-to-day weather uncertainty (see Table 3 in Section 3 of this report) are generally greater than other regions. The combination of high weather volatility and a high concentration of Manitoba load in the weather sensitive residential and commercial sectors results in much more day-today swings in gas load than almost any other LDC in North America. The high day-today swings in demand also lead to significant forecasting errors in daily requirements. As a result, the Centra supply portfolio needs to be structured to provide cost-effective natural gas service over a wide variety of natural gas demand levels, as well as providing flexibility to meet wide variations in daily natural gas demand, and balancing services to account for differences between nominations and actual takes. Currently, Centra meets these requirements through the use of natural gas storage injections and withdrawals, and through daily purchases of WCSB gas based on the Swing Gas provisions of the Nexen contract. Under the current contract structure, Centra is responsible for balancing nominations and takes on the TransCanada system. Within the volumes specified in the Nexen contract, Nexen is responsible for deliveries of the nominated natural gas to Empress. The Nexen Swing Service is structured into two tranches (or blocks). The first allows Centra to make daily nominations between 0 GJ/Day and 80,000 GJ/Day at a cost above the daily market price 15 of $0.025/GJ. The second tranche allows Centra to make additional daily nominations of up to 40,000 GJ/Day at in incremental cost of $0.05/GJ above the daily market price. During the summer period, on days when demand exceeds the base gas purchases, Centra typically purchases additional swing gas according to the terms of the Nexen contract to meet demand, since storage withdrawals are not available. 15 The gas price in the Nexen contract is a delivered to Empress price that is based on the AECO/NIT daily gas price with the cost of delivery from AECO to Empress added to the price. Energy and Environmental Analysis, Inc. 71

82 EEA Final Report January, 2007 During the winter, natural gas demand above the base gas purchases is usually first met through purchases of swing gas according to the terms of the Nexen contract and then storage and other sources as required Comments on the Nature of Swing Service The management of supplies making up the equivalent of Centra s Swing Service is one of the key elements of any utility s supply plan. EEA expects that the cost and availability of swing service will be one of the key issues in the contract negotiations with any potential supplier. With respect to the acquisition of swing services, Centra is relatively unique in terms of geographic constraints and opportunities. The lack of storage capacity in Manitoba, combined with the existence of only one pipeline into and out of the service territory limits the options available to Centra and forces Centra to rely on pipeline services and supply contracts to meet swings in daily load. However, the limitations imposed by the lack of local storage and the lack of pipeline options are somewhat offset by Centra s location halfway between the major production region in Alberta and the major pipeline interconnects and storage regions around Chicago, Michigan, and Ontario. Centra can minimize the cost of swing services if it can leverage a combination of upstream and downstream assets. The differences between swing requirements in Manitoba and the downstream markets serviced by TransCanada provides an opportunity to reduce the costs of serving both markets if market requirements in Manitoba and downstream can be combined into a single portfolio. The primary sources of swing service currently used by Centra utilize the combination of upstream and downstream assets to minimize total costs. Centra contracts for swing services with a major marketer (Nexen) holding both upstream and downstream assets and serving both upstream and downstream markets. By optimizing assets to serve multiple markets, a marketer such as Nexen should be able to provide a specific service at a lower cost than a dedicated service unable to take advantage of the synergies associated with multiple markets. As noted previously, Nexen charges a cost premium over the daily market price of gas to provide the swing services. The cost premium is determined by two major factors. The first is the management cost of monitoring nominations, and daily gas volume management. The management of daily gas purchasing in a volatile market is significantly more expensive than the management of monthly baseload supplies. EEA believes that a cost premium of between $0.01 and $0.02 per GJ is a reasonable cost for this type of service. The second cost element reflects the premium required to provide the capability to meet the daily and intra-daily swings in demand. The contract allows Centra to change nominations on an intraday basis on the TransCanada nominations schedule. Nexen is Energy and Environmental Analysis, Inc. 72

83 EEA Final Report January, 2007 responsible for providing the natural gas to meet the TransCanada nominations. As a result, Nexen is responsible for balancing the daily nominations with actual takes in an environment where daily purchases are varying widely. EEA believes that Nexen handles the daily volatility in natural gas purchases through an integrated approach using it s entire portfolio of North American assets and customer base. This approach would be available to other major marketers serving the area, but is not available to Centra or to small or mid-sized producers. However, the market does provide options to accommodate this requirement that would be available to Centra as an alternative to the Nexen contract. The Natural Gas Exchange offers several intra-alberta services that could provide similar daily flexibility to Centra, including daily purchases on the the day-ahead market, and the daily market, as well as a balancing service called the Yesterday Price. These contracts allow the purchase of the difference between daily nominations and actual takes on an after-the-fact basis in order to balance without pipeline penalties. 16 These services are based in Alberta, and are applicable to shipping on the NOVA system, hence are not fully applicable to Centra. The cost of this service is market priced, and is determined daily. The price of the service can vary widely depending on market conditions. On many days, the cost would be less than $0.03 per GJ, however the range often exceeds $0.25 per GJ, and on peak days, the cost could reach several dollars per GJ or more. Of course, most swing volumes will not be subject to these balancing fees. These fees would be applicable to the forecast error in determining the amount of gas to purchase in the day-ahead market. Given the weather volatility in Manitoba, however, the amount of swing purchases requiring this type of service is expected to be substantial, particularly for the tranche two level of swing purchases. Value of Balancing on the TransCanada System TransCanada provides a certain level of balancing flexibility in it s base tariff. The base tariff provides for daily variation between nominations and receipts of up to 2 percent of the pipeline MDQ held by the customer without incurring balancing penalties. Above 2 percent variation from nominations, TransCanada assesses balancing penalties ranging from 20 percent to 100 percent of the daily demand charge. (Eastern Zone TransCanada Toll). TransCanada also offers a Parking and Loan service, which for $0.10 per GJ allows daily balancing on an interruptible basis. As an interruptible service, this cost 16 Utilities such as ATCO regularly use the Yesterday Price markets to meet daily swing and balancing requirements. Energy and Environmental Analysis, Inc. 73

84 EEA Final Report January, 2007 represents the lower bound on the cost of daily balancing above the flexibility provided in TransCanada s tariff service Changes in Outlook for Alberta Sourced Swing Service. The cost and availability of swing service is closely related to the amount of market flexibility. In an unconstrained market, swing service should be widely available at relatively modest premiums. In a constrained market, swing services will be expensive. While EEA does not believe that there should be any concern about availability of pipeline capacity on TransCanada from Alberta to Manitoba, we do see the market tightening for WCSB natural gas as the WCSB gas available for export declines. As the market tightens, EEA expects the incremental cost of swing service relative to baseload service to increase. In addition, the current high value market for natural gas storage increases the cost of providing swing service. In the longer-term, there are a number of foreseeable events that are likely to offset, to a certain degree, the impact of the decline in Alberta exports on the availability and cost of swing services. These include: Decline in the seasonal value of natural gas storage from current historic highs. Completion of the Rockies Express (or competing) pipeline capable of delivering significant quantities of gas into the U.S. Midwest Market. Increases in LNG imports in the U.S. Gulf capable of increasing winter flows into the Chicago market. Completion of LNG import facilities in Quebec and/or British Columbia capable of providing swing service to these markets, hence minimizing utilization of upstream assets for swing services. Completion of the Mackenzie Delta and Alaska Gas Pipelines. As a result, it is hard to estimate the magnitude of the increase without evaluating actual bids. That said, however, EEA estimates that the near-term increase in costs could result in swing service cost premiums increasing from $0.025 per GJ to $ $0.04 per GJ for the equivalent of the Nexen tranche one swing service, and increase from $0.05 to between $0.08 and $0.12 per GJ for incremental swing service equivalent to the Nexen tranche two swing services. This estimate is consistent based upon an analysis of volatility and a seller s best opportunity associated with gas turned back during low periods of demand Storage as an Alternative to Swing Service The ability to provide swing service is traditionally one of the key drivers for the development of natural gas storage, and utilities fortunate enough to have local storage resources have an array of swing service options not available to other companies. Centra Manitoba does not own any storage capacity, and no storage capacity currently exists within the Centra Manitoba service territory. Centra Manitoba is connected by pipeline to major storage facilities in Alberta via the TransCanada system, as well as to major downstream storage regions in Michigan and Ontario via backhaul. Centra Energy and Environmental Analysis, Inc. 74

85 EEA Final Report January, 2007 currently uses storage capacity held downstream in Michigan as one source of swing service. This storage provides up to about 26 percent of forecasted annual gas requirements in a cold year, and 43 percent of peak day gas requirements. Previous assessments of the Centra Manitoba gas supply portfolio 17 have recommended that Centra promote the development of salt cavern storage in Manitoba, and explicitly recommended that Centra Manitoba contract with TransGas to develop the storage capacity on Centra s behalf. EEA agrees with the IGC conclusion that additional storage capacity in Manitoba would have significant operational benefits to Centra Manitoba, however, EEA would not recommend that LDC s without significant background in storage development go into that market as equity developers. The storage development market has significant risks that would be difficult to reconcile with the risk profile of an LDC such as Centra Manitoba not already in the storage development business. EEA would recommend serious consideration of long-term contracts for storage capacity developed in Manitoba by a third party storage developer. EEA also believes that additional storage capacity, either in Alberta or downstream in Michigan or Ontario could play an economic role in Centra s supply strategy. However, in the current market environment, storage values are extremely high due to the recent expansion of the seasonal basis in natural gas prices. As a result, any additional storage available at market based rates would be extremely expensive in the short-term and additional cost-based storage would be largely unavailable. Hence, the costs of additional storage could very well exceed the benefits. As discussed previously, EEA expects that storage value will decline somewhat in the next couple of years as market conditions narrow the seasonal spread in natural gas prices. EEA expects that this issue would be more thoroughly evaluated in a Phase 2 analysis Contracts with Marketers vs. Contracts with Producers for Primary Gas Supply Centra currently purchases primary gas from a major natural gas marketer. Centra does have the option of purchasing primary gas directly from one or more producers, rather than from the marketer once the current purchase contract with Nexen expires in October Intuitively, this would seem to make sense in that Centra would be eliminating a middleman in the transaction and should therefore be able to reduce costs by eliminating the profit earned by the natural gas marketer. However, this only works if Centra or the producer(s) can provide nearly the same economies of scope and scale available to Nexen, or if the producer is willing to provide gas at below market rates in order to ensure an outlet for production. As noted previously, EEA believes that holding assets both upstream and downstream of Centra s service territory and serving a portfolio of customers in different regions with different weather patterns provides significant opportunities to reduce the costs associated with both transaction management and management of demand volatility. 17 International Gas Consulting, Inc, Review of Centra Gas: Supply, Storage and Transportation Portfolio, August 25, Energy and Environmental Analysis, Inc. 75

86 EEA Final Report January, 2007 These economies are unlikely to be available to an LDC of Centra s size and geographic circumstances or to a typical WCSB producer without a significant portfolio of customers downstream of Centra s service territory. While EEA expects the major marketers to be more cost effective than direct purchases from producers, this is a conclusion that should be tested in the market as part of the RFP process described in Section Seven of this report Ownership of Production as a Source of Primary Gas Supply One of the potential options available to Centra Manitoba as an alternative to open market purchases or a long-term supply agreement would be ownership of production. Ownership of production would provide gas commodity at a price not influenced by the day-to-day changes in natural gas commodity prices, potentially lowering natural gas prices and price risk to Centra Manitoba customers. However, this approach also exposes Centra Manitoba and it s customers to other non-traditional risks. As a result, EEA does not recommend this approach. Ownership of production could entail either purchases of existing reserves, or purchase/development of a dedicated exploration and development company with a mandate to develop reserves. The market value for reserves in the ground is generally substantially less than the market value of produced natural gas. Hence, ownership of reserves potentially could reduce gas costs to Centra Manitoba customers. However, the market price for reserves in the ground is typically a risk adjusted price reflecting current market expectations of the value of production over time, adjusted downward to reflect a variety of market risks atypical to an LDC, including geological, operational, and market risks. As a broad generalization, LDCs such as Centra Manitoba tend to be relatively risk averse, while producers tend to have business models that are based on a high degree of risk. As a result, LDC s tend to attach a higher cost to a specific level of risk than a producer would. Any acquisition of natural gas reserves or production capability in the open market would require competing against other market players with more risk tolerance and Centra would have to overpay for the assets relative to a typical LDC risk tolerances. By the same token, any producing properties that might be acquired by Centra Manitoba would have more value to other market players with higher risk tolerances than they would to Centra Manitoba. In addition, purchasing or developing reserves in today s high price market would result in a serious risk of buying at the top of the market. As a result, EEA would not recommend that Centra Manitoba purchase or develop reserves for the use of it s customers. Energy and Environmental Analysis, Inc. 76

87 EEA Final Report January, Implications of Marketer Requests for Changes to WTS As part of this effort and in accordance with the direction of the Public Utility Board (PUB Order ), Centra convened a fact finding session to provide an opportunity for stakeholders to voice their views, perspectives, and objectives with respect to Centra s gas supply re-contracting alternatives. As part of this effort, Centra reached out to consumer advocates, third-party marketers that do (or could) compete to provide gas merchant service in the Centra service territory, and environmental, efficiency and sustainable development advocates. In addition, representatives and consultants from the MPUB were invited to observe and/or participate. In this effort, a number of marketers raised two areas related to the nature of the WTS service. They are: Stability and reduced volatility in daily nominations for third-party marketers Several third-party marketers voiced the strong desire that Centra evaluate gas supply alternatives with an eye towards modifying the current protocol that allocates the daily variability in gas load proportionally to all gas suppliers on an equal basis, and; Monthly enrollment Several third-party marketers expressed the desire that Centra evaluate gas supply alternatives that would allow Centra to allow monthly variations in each marketer s customer base. Both of these areas have been raised in previous forums and proceedings directly addressing the elements of the WTS service. EEA believes that these issues should be addressed in those forums prior to affecting the form of the renewal or replacement of the contract for primary gas supply. The implication of changing the structure of the contract for primary gas to provide for stability in marketer nominations is that Centra should evaluate and consider a gas supply contract that allows Centra to modify the utility takes to accommodate the variation in requirements of system customers as well as some or all of the variation of the requirements of Western Transportation Service (WTS) customers. To the extent that there is a cost to acquiring the more than proportional flexibility under the system sales contract, the costs (if any) would be borne by the subset of customers that elect utility service, Similar to the reduction in volatility of daily nominations, the implication of changing the structure of the contract for primary gas to provide for more frequent enrollment periods is that Centra should evaluate and consider a gas supply contract that allows Centra to modify the utility monthly takes such that the contract allows for more frequent migration from and to utility sales service. To the extent that there is a cost to acquiring a contract that accommodates additional uncertainty in monthly takes under the system sales contract, the costs would be borne by the subset of customers that elect utility service. Energy and Environmental Analysis, Inc. 77

88 EEA Final Report January, 2007 EEA recommends that Centra not subordinate the objectives of pursuing the minimization of the cost of supply and providing price stability to meeting the requests of the third-party marketers. EEA makes this recommendation for two reasons: First, adopting such an approach may not be sustainable. Currently, system sales constitute approximately 81 percent of the total volume of gas sold to residential customers in A contract that cross-subsidizes customers of third-party marketers at the expense of system sales customers could well increase the cost of gas for utility supply service customers relative to market based offerings by one to two cents per MMBtu or more. If however, the portion of utility supply service customers declined to 40 percent, then the impact on the remaining customers would roughly double. Ultimately, there is a risk that there is insufficient volume providing swing capability to meet the actual requirements if the percentage of the load served by utility supply service continued to decline. Second, Centra could risk prudence disallowances based on a failure to acquire gas in a prudent manner. To the extent that such a contract results in additional costs beyond those required for proportional swing services and the MPUB has not explicitly addressed the recovery of those costs in system gas sales, Centra incurs additional regulatory risk. Energy and Environmental Analysis, Inc. 78

89 EEA Final Report January, RECOMMENDATIONS AND NEXT STEPS FOR REPLACING THE CURRENT PRIMARY GAS SUPPLY CONTRACT WITH NEXEN 7.1 Extension of the Existing Nexen Contract and Context for the RFP Process In our analysis, EEA reached a fundamental conclusion that the structure of the existing contract represents an appropriate baseline against which to evaluate the structure of a new gas supply agreement. The current Nexen contract provides Manitoba consumers with a reliable source of gas while meeting the objective of minimizing the cost of supply consistent with the responsibility to protect the public interest. EEA is recommending a process based on competitive bidding to select the best cost commodity purchasing option. However, as a first step, Centra should explore a one or two year extension of the existing contract with Nexen to confirm whether or not Nexen would be able to offer such an extension with the same pricing formula. Given the changes in the supply and demand balance for gas production in the WCSB and the broader North American gas market, there is no guarantee that the responses to an RFP that is structured to reproduce the terms of service provided by the current contract will be obtained under the same or better pricing terms than the current contract. As discussed previously, the market for gas in Alberta and indeed throughout North America has tightened. This tightening may well result in Nexen concluding that the appropriate value for the premium paid for swing volumes should be adjusted upward and as discussed in Chapter 6.4, there is a legitimate cost basis to support an increase. Nevertheless, it is still possible that Nexen would place some value to locking up the sales volume without risking the contract to the competitive bid process. Therefore, it should be communicated clearly to Nexen in the negotiation that a request for a material change to the pricing formula by Nexen would be a trigger for the initiation of the broader RFP process. An extension of the Nexen contract with pricing terms similar to the existing formula would represent a favourable outcome given the changes that have occurred in the North American gas commodity market and in the supply demand balance in the WCSB. Energy and Environmental Analysis, Inc. 79

90 EEA Final Report January, 2007 In the process of negotiating any extension to the existing contract with Nexen, Centra should still seek to maintain the flexibility to lower the baseload volume in order to maintain flexibility in determining the source for storage injection gas, and to otherwise adapt to changing market conditions. (See Section 6.3.2). One element of risk associated with an extension of the existing contract is that of prudence review. A simple extension of the contract without a full record developed including the responses to the issuance of an RFP carries some additional risk that the contract could be more expensive. EEA does not believe that such claims would be justified. Justification of an extension of the existing Nexen contract is based on analysis of the changes in natural gas market conditions that, ceterus parabus make flexibility in daily and monthly takes more expensive. 7.2 RFP Development Assuming that negotiations to extend the contract under the current pricing formula do not reach a successful conclusion, the RFP process should proceed in a layered manner with two basic alternatives to RFP development pursued simultaneously: The two alternatives include: 1. Develop and distribute an RFP that requests bids for a Baseline service structured along the lines of the existing contract, i.e., a base line two part service with base load volume at Empress and swing volume at Empress. The RFP would specify that pricing be based upon published indices at AECO-c plus NOVA transportation. The objective of the solicitation should be to generate a number (at least 3 or 4) of responses that can be evaluated and to provide a record to document the prudence of the choice of supplier. 2. Include in the RFP a request for alternative pricing formulas to the base line service that provide Centra with a hedge against basis volatility and the reduction in the AECO basis to Dawn, Chicago and Henry Hub that EEA anticipates will occur. Centra should include in the RFP a request that potential suppliers offer a pricing formula based on a market basket of pricing locations that includes downstream locations. The RFP would indicate that Centra believes (expects) that there would be a discount applied to the portion of the price formula utilizing downstream locations. For example, a portion of the price formula could be calculated based on a Dawn index minus a transportation value. It should be recognized that such a proposal would embody an assumption of basis risk by the supplier for which the supplier would expect to be compensated. This compensation a form of insurance against basis risk can be expected to add to the cost of the service. In addition, because this approach is fundamentally a hedge against basis risk, consideration of any alternative proposals should be considered in the context of Centra s hedging strategy, the accounting on hedges, and the views of regulators towards hedging and the resulting risk to cost recovery. Energy and Environmental Analysis, Inc. 80

91 EEA Final Report January, 2007 Finally, it should be recognized that it is possible that no qualified suppliers will choose to provide a bid structured in this way or that the imbedded cost of the assumption of risk by the marketer could make such bids unattractive. EEA believes that it is not very likely that this approach will yield results. However, the attempt to solicit and evaluate such proposals would not add significantly to the cost of the RFP process and might yield an advantageous offering Identification of Bidder List If Centra accepts the recommendations (and assuming that Centra is unable or chooses not to extend the existing contract with Nexen), the RFP will be distributed to potential service providers. Prospective suppliers must have a combination of the financial stability, market presence and operational flexibility to provide Centra Gas with an attractive commodity purchase contract. Any offer would need to result in a lower cost supply option than Centra would be able to structure on its own. In EEA s view, given Centra s location and size in the market, this is likely to be possible with only a limited number of market participants that are both sufficiently large to provide a high degree of financial stability, and also hold major positions both upstream and downstream of the Centra service territory. In order to prepare a first cut list of potential marketing partners that might be able to meet these criteria, EEA cross referenced a list of top North American natural gas marketers with pipeline and storage capacity holdings both upstream and downstream of Manitoba. The results of this analysis are provided in Table 10. While any competitive bid should be open to all qualified bidders, EEA s analysis indicates that the likely list of bidders would include Nexen, Coral, and Husky Gas Marketing. 18 These companies have a significant presence in the upstream and downstream markets and are likely to be able to generate significant synergies with their other market partners if selected to provide natural gas supply services to Centra. BP, Encana, and possibly CanNat could also be potential competitors. In particular, BP, as the largest North American marketer could potentially provide services and synergies not available to smaller competitors. However, while these companies have significant assets in the TransCanada market region, these assets are more limited than those held by Nexen, Coral and Husky Gas Marketing. While EEA would not recommend excluding other companies with sufficient financial backing to provide reliable service, EEA would be somewhat surprised if any market participants other than the ones listed above would be able to provide a package of gas purchasing options more attractive than what Centra would be able to put together on it s own. 18 Note: EEA has not completed any additional screening of potential gas marketers at this time. Hence this list should not be used to either screen in, or screen out potential bidders on any Centra supply contracts. Energy and Environmental Analysis, Inc. 81

92 EEA Final Report January, 2007 Table 10 Major Marketers Holding Capacity in the Competitive Market Region Company Interstate Storage Capacity FT Pipeline Capacity (Bcf) Natural Gas Intelligence Top Marketers (Second Quarter 2006) 2Q 2006 Sales (BCF/D) ANR Storage Washington 10 Storage TCPL at Empress (GJ/D) GLGT (Mcf/D) TCPL at Dawn/ St. Clair (GJ/D) BP ,755 42,808 ConocoPhillips ,701 21,101 Sempra Coral ,924 23, ,532 Constellation ,214 Chevron 7.30 UBS ,103 Cinergy ,813 26,376 Louis Dreyfus Tenaska , ,808 EnCana ,766 Oneok ExxonMobil 2.51 Williams 2.40 Nexen ,789 67, ,082 Devon ,816 8,104 Merrill Lynch 2.15 Sequent 2.09 Chesapeake 1.43 Anadarko ,140 Other Marketers Holding Capacity (Partial List) Husky Gas Marketing 252,677 42,989 21,420 Canadian Natural Resources (CanNat) 101,317 65,647 37,160 DTE Energy Trading ,014 69,399 Dynegy Marketing and Trade 119, ,142 Total Capacity Held by Listed Marketers ,580, , ,212 Centra Manitoba ,921 Total Capacity Under Contract ,906,292 2,321, ,986 Percent of Capacity Held By Listed Marketers 19% 89% 32% 22% 92% Data Sources: FERC Index of Customer Data April 1, 2006 for NFGS, ANR Pipeline, ANR Storage, GLGT, Vector. Washington 10 Storage Corporation Semi-Annual Storage Report April 2005 through October Transcanada Contract Demand Mainline Report September, 2006 Natural Gas Intelligence: Rankings of Top Marketers 2nd Quarter Energy and Environmental Analysis, Inc. 82

93 EEA Final Report January, Requested Term for RPF Responses The RFP should establish a baseline service that is structured along the lines of the existing supply agreement. The baseline should specify an intermediate term of two to four years. The recommendation for the term is based on several factors including: 1) The timing of pipeline expansion projects that will increase the capacity to move gas supplies from the Rocky Mountains in the United States to markets in Illinois and further east. Construction of these pipelines would access additional supplies that could remove some of the pressure on WCSB supplies. A contract that expires after the completion of one or more of these projects would be favorable to future negotiations. 2) An intermediate term agreement would allow for subsequent negotiations to be conducted after a review of existing pipeline and storage capacity contracts that was described as a Phase Two analysis in the original RFP for this study effort. 7.3 Evaluation of Responses to the RFP If Centra accepts these recommendations (and assuming that Centra is unable or chooses not to extend the existing contract with Nexen), Centra will receive a number of bids for the primary gas supply. EEA expects significant interest from the major market players identified above. While the number of players capable of providing a cost effective purchasing agreement to Centra is relatively limited, the players that are capable are very competitive. In addition, even with an RFP that describes elements of the service, EEA expects that proposals will differ in various ways. As a result, there may not be a clear cut best contract offer. Although the goal of LDC gas procurement is often stated as finding the most cost effective option or least cost option, there are a number of objectives that must be considered and balanced. These include: Provide adequate and reliable supply to firm customers Provide a reasonable level of service to interruptible customers Minimize cost of supply Stabilize price as much as practical Maintain flexibility on takes Avoid other costs (new transportation and storage costs) Consistent with regulator objectives and directives in order to facilitate approval from regulators Energy and Environmental Analysis, Inc. 83

94 EEA Final Report January, 2007 Provide price transparency to customers Keep internal gas supply management costs low Maintain consistency with other corporate goals for reduced environmental impacts, sustainable development, local content, integrated resource plans, etc. Only a few of these factors can be directly quantified without the application of judgment and analysis. Moreover, even the quantifiable components may not be directly comparable. As a result, an approach is needed to compare the relative value of different characteristics of alternative options. To manage the process and to provide structure for the comparison of various bids, a Scoring Model that considers the various elements of the proposals and how they fit with the identified objectives will be applied to each bid received. The Scoring Model consists of a matrix of the critical elements of the service. Table 11 presents the initial proposal for the elements of the Scoring Model. The final structure of the elements of the model will be determined after consultation with Centra Staff. The key to this approach is the identification and weighting of different contract elements in the final decision-making process. The approach is not intended to be mechanistic, but is instead intended to provide a quantitative framework for a qualitative comparison of alternatives. This approach depends on a quantitative weighting of the importance of different decision criteria, as well as a qualitative assessment of how each supply option addresses each criteria. See Table 11. As currently structured, the Scoring Model incorporates six areas. They encompass: Reliability of supply Gas cost minimization Price Stability and market transparency Accommodation of WTS Regulatory oversight and process Miscellaneous other objectives EEA would expect actual evaluation categories and category weights will be determined by Centra Gas. Energy and Environmental Analysis, Inc. 84

95 EEA Final Report January, 2007 Table 11 Scoring Sheet for Alternative Supply Options Source: Energy and Environmental Analysis, Inc. Description of Option: Example Scoring Sheet for Alternative Supply Options Total Category Weight \* Sub Category Weight \* Minimum Acceptable Score \* Option Score (0-10) Weighted Score 1) Provides Reliable Supply Reliable Supply to Firm Customers Reasonable Service to Interuptible Customers ) Minimizes Total Cost of Supply Minimize commodity costs Minimize Fixed Asset Costs Minimize Internal Gas Supply Management Costs ) Meets Customer Objectives Price Stability Price Transparency ) Meets Direct Purchase Customer Objectives Provide Operational Nominations Flexibility Provide Customer Nominations Flexibility ) Meets Regulator Guidelines and Objectives ) Consistent with other Corporate Goals Sustainable Development Reduced Environmental Impacts Local Content Minimize Regulatory Risk Other Total of All Categories */ Category weights and minimum acceptable scores are preliminary, and are included for illustrative purposes only. Energy and Environmental Analysis, Inc. 85

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99 ASSESSMENT OF NATURAL GAS COMMODITY OPTIONS FOR CENTRA MANITOBA Report Appendices Prepared for: CENTRA MANITOBA FINAL REPORT Submitted By: ENERGY AND ENVIRONMENTAL ANALYSIS, INC N. Fort Myer Drive, Suite 600 Arlington, Virginia USA (703) Contacts: Bruce Henning Michael Sloan January 2007

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101 ABOUT ENERGY AND ENVIRONMENTAL ANALYSIS, INC. Energy and Environmental Analysis (EEA), located in metropolitan Washington, D.C., is a nationally recognized consulting firm offering technical, analytical, and management consulting services to a diverse clientele. Founded in 1974 to perform economic, engineering, and policy analysis in the energy and environmental fields, EEA has exhibited leadership and innovation in investigating energy and environmental issues. DISCLAIMER This report includes forward-looking statements and projections. Energy and Environmental Analysis, Inc. (EEA) 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 results to differ materially from the projections, anticipated results or other expectations expressed in this report, including, but not limited to, general economic and weather conditions in geographic regions or markets that may affect the gas market. Energy and Environmental Analysis, Inc. Appendices

102 Energy and Environmental Analysis, Inc. Appendices

103 TABLE OF CONTENTS Page APPENDIX A: North American natural Gas Outlook... 1 A-1 North American Gas Demand... 1 A-1.1 North American Residential and Commercial Gas Consumption... 2 A-1.2 North American Industrial Gas Consumption... 5 A-1.3 North America Power Generation Gas Consumption... 8 A-1.4 Seasonal Gas Demand A-2 North American Gas Supply A-2.1 Drilling Rigs and Completion Activity A-2.2 Lower-48 and Canada Production and Forecast A-2.2 Trends in Supply Costs A-2.4 North American Gas Resource Base A-2.5 Regional Gas Supply Curves A-2.5 Activity by Region A Canada Gas Production A U.S. Production A-2.6 General Issues and Uncertainties Affecting Forecast A-3 North American Gas Transmission A-3.1 Regulation of Pipeline Companies A-3.2 North American Gas Storage A-3.3 North American Natural Gas Prices A Seasonal Gas Prices A North America A Highly Integrated Gas Market A Basis Regional Gas Price Difference APPENDIX B: North America Natural Gas Market Projections B-1 EEA Base Case Assumptions B-2 Projected Gas Consumption B-2.1 U.S. and Canada Gas Consumption Energy and Environmental Analysis, Inc. Appendices i

104 B-2.2 Manitoba, Saskatchewan, and Alberta Gas Consumption B-2.3 Projected Natural Gas Prices and Basis B-3 Demand Factors APPENDIX C: EEA s Gas Market Data and Forecasting System APPENDIX D: Review of natural Gas Market Liquidity Concepts APPENDIX E: Comments from Stakeholders E.1 Centra Gas Manitoba Stakeholder Meeting Minutes August 16, E.2 Letter From Peter Miller Summarizing RCM and TREE s Concerns E.3 Letter From Energy Savings (Manitoba) Corp Energy and Environmental Analysis, Inc. Appendices ii

105 LIST OF TABLES Page Table 1 North American Gas Consumption, Billion Cubic Feet (Bcf), Table 2 North American Natural Gas Use by Sector (Bcf), Table 3 Top 50 Gas Utilities... 6 Table 4 Recent Power Generation in the U.S. Lower-48, Bkwh Table 5 U.S. and Canada Historical Production Table 6 North American Gas Resource Base, in Tcf Table 7 Lower-48 Wellhead (Raw) Gas Production Summary, in Bcf per Year Table 8 Top 20 U.S. Pipelines, Ranked by Contracted Capacity Table 9 Summary of U.S. Gas Storage, Table 10 Planned New Storage Capacity Table 11 Tariffs for Major Storage Operators Table 12 Annual Basis from Henry Hub, $/MMBtu Table 13 EEA Base Case Key Assumptions - U.S. and Canada Table 14 U.S. and Canada Natural Gas Consumption by Sector (Bcf per Year) Table 15 Projected Chicago, Opal, Dawn, and AECO Basis (2005$ per MMBtu) Table 16 Factors that Help Determine Long-Run Natural Gas Markets Table 17 GMDFS Network Node List Energy and Environmental Analysis, Inc. Appendices iii

106 LIST OF FIGURES Page Figure 1 Regional Residential and Commercial Gas Use (Bcf), Figure 2 Regional Industrial Gas Use (Bcf), Figure 3 Gas-Based Power Generating Capacity (Gigawatts, GW)... 9 Figure 4 Regional Power Generating Gas Use (Bcf), Figure 5 Monthly Gas Use by Sector (Bcfd), Figure 6 U.S. and Canada Monthly Electricity Use (Bkwh), Figure 7 U.S. Drilling Rig Activity Figure 8 U.S. Onshore Gas Completions Figure 9 Canadian Rig Activity Since Figure 10 Canadian Gas Well Completions Figure 11 Canada Dry Marketed Gas Production Figure 12 EEA Canada Gas Production Forecast Figure 13 GOM Jackup Rig Day Rates Figure 14 U.S. Onshore Day Rates Figure 15 Map of EEA Supply Regions Figure 16 Regional Gas Supply Curves Figure 17 Aggregate U.S. and Canada Gas Supply Curve Figure 18 Map of Western Canada Figure 19 Canada Marketed Gas Production Figure 20 WCSB Coalbed Methane Production and Wells Figure 21 EEA WCSB Dry Gas Production Forecast Figure 22 Comparison of EEA and TransCanada WCSB Forecasts Figure 23 Comparison of EEA and TransCanada Forecasts by Production Type Figure 24 Impact of Gas Price on EEA Base Case Forecast Figure 25 Northern Rockies Wellhead Gas Production Figure 26 Lower-48 Supply Basins Figure 27 Southern Rockies Wellhead Gas Production Figure 28 EEA Rockies Dry Gas Production Forecast Energy and Environmental Analysis, Inc. Appendices iv

107 Figure 29 Gulf of Mexico Wellhead Gas Production Figure 30 Gulf of Mexico Dry Gas Production Forecast Figure 31 MidContinent Wellhead Gas Production Figure 32 Northeast Texas/North Louisiana Wellhead Gas Production Figure 33 Permian Basin Wellhead Gas Production Figure 34 Onshore Gulf Coast Wellhead Gas Production Figure 35 West Coast Gas Wellhead Gas Production Figure 36 Appalachia and Midwest Wellhead Gas Production Figure 37 Mexico Raw Gas Production by Region, MMcfd Figure 38 Major Pipelines in the U.S. and Canada Figure 39 Average Flows, 2005 (MMcfd) Figure 40 Interregional Pipeline Capacities, 2005 (MMcfd) Figure 41 North American Working Gas Levels, January 2000 through December 2005 (Bcf) 61 Figure 42 Daily Gas Prices for Select Locations, January 1999 to September Figure 43 Henry Hub Seasonal Price Variations, Monthly Price Relative to 12-Month Rolling Average, 1995 to Figure 44 Henry Hub to Chicago Basis versus Cost of Firm Transportation, January 1998 to December Figure 45 Henry Hub to New York City Basis Versus Cost of Firm Transportation, January 1998 to December Figure 46 Current and Projected North American LNG Regasification Capacity through Figure 47 North American Pipeline Capacity Additions Figure 48 Projected U.S. and Canada Natural Gas Consumption (Tcf per Year).. 78 Figure 49 Projected U.S. Lower-48 Coal and Gas Generation Capacity (Gigawatts) Figure 50 Projected U.S. Lower-48 Generation (Billion kilowatt-hours) Figure 51 Projected Manitoba, Saskatchewan, and Alberta Gas Consumption by Sector (Bcf per Year) Figure 52 Projected Manitoba, Saskatchewan, and Alberta Gas Consumption by Province (Bcf per Year) Figure 53 Projected Henry Hub and Other Selected Natural Gas Prices (2005$ per MMBtu) Figure 54 Supply/Demand Curves Figure 55 GMDFS Structure Energy and Environmental Analysis, Inc. Appendices v

108 Figure 56 GMDFS Transmission Network Figure 57 Model Drivers Figure 58 Model Output Figure 59 Demand Regions Figure 60 Production Regions Figure 61 Storage Regions Energy and Environmental Analysis, Inc. Appendices vi

109 APPENDIX A: NORTH AMERICAN NATURAL GAS OUTLOOK This Appendix provides an overview of EEA s outlook on the North American natural gas market. The first part of the section investigates gas consumption, reviewing recent trends in North American natural gas use. The second part of the section reviews recent gas supply trends, including recent LNG import activity. The third part of the section investigates gas infrastructure, i.e., gas transmission and storage. The final part of the section reviews recent trends in gas prices. A-1 North American Gas Demand Over the past six years, North American 1 gas consumption has averaged 25.2 trillion cubic feet (Tcf 2 ) per year (Table 1). The U.S. has accounted for 21.9 Tcf per year, or 87 percent of the total North American gas consumption, while Canada has accounted for 3.3 Tcf per year, or the remaining 13 percent of consumption. Natural gas is used for many purposes. Residential consumers rely on gas to heat homes, heat water, and cook with. Commercial establishments use gas mostly for space and water heating. To a more limited extent, they use gas for space cooling and electricity generation 3. Industrial consumers use gas for a variety of purposes, but mostly as a fuel for boilers, as a fuel for heating and drying, and as a feedstock. Some industrial consumers rely on natural gas for cogeneration to produce steam and electricity that are used in the manufacturing process. Power providers have relied on gas in power plants to generate electricity. North American gas consumption is provided by sector in Table 2. 1 Throughout this report, unless otherwise noted, North America statistics include the U.S. and Canada, but exclude Mexico. However, all analysis considers gas trade between the U.S. and Mexico. 2 One Tcf is equivalent to 1,000 Billion Cubic Feet (Bcf) or approximately 920 Terajoules (TJ). 3 During the past decade, commercial establishments, like McDonalds, have relied on natural gas to run portable generators at their site (often referred to as distributed generation), mostly as a backup to their purchased electricity to keep equipment running in the event of a disruption. Energy and Environmental Analysis, Inc. Appendices Page 1

110 Table 1 North American Gas Consumption, Billion Cubic Feet (Bcf), US Canada Total ,197 3,287 26, ,513 3,140 24, ,144 3,300 25, ,627 3,312 24, ,693 3,370 25, ,510 3,337 24,847 Average Annual 21,947 3,291 25,238 % of Total 87% 13% Source: Energy and Environmental Analysis, Inc. Table 2 North American Natural Gas Use by Sector (Bcf), Source: Energy and Environmental Analysis, Inc. Residential Commercial Industrial Power Generation Pipeline Fuel Lease & Plant Total ,621 3,655 9,904 4, ,877 26, ,295 3,422 8,427 4, ,905 24, ,440 3,494 8,885 4, ,853 25, ,682 3,556 8,174 4, ,867 24, ,459 3,424 8,462 4, ,875 25, ,462 3,426 7,949 5, ,867 24,847 Average Annual 5,493 3,496 8,633 4, ,874 25,238 % of Total 22% 14% 34% 19% 3% 7% A-1.1 North American Residential and Commercial Gas Consumption During the past six years, the residential and commercial sectors have accounted for an average of 9.0 Tcf per year, or 36 percent of the total gas consumption in North America ( Table 2). Because of the impact of weather, it is difficult to discern the trend for residential and commercial (R/C) gas use. The EIA data, which represents actual billed gas use (not weather normalized 5 ), indicates relatively flat, but erratic residential and 4 In EEA s modeling and market analysis, the industrial sector includes about 1,000 Bcf (i.e., 1 Tcf) of gas use in cogenerating facilities built prior to 1998 that the U.S. Energy Information Administration reports in the power sector. 5 The data can be weather normalized (or adjusted for weather) to determine the underlying growth rate of demand. To do this, the time series data may be fit with independent variables that include a counter to represent years in the time period and a measure of weather, often represented by heating degree Energy and Environmental Analysis, Inc. Appendices Page 2

111 commercial gas use over the period. However, when adjusted for weather, the data indicates that residential gas use has been growing by about 50 Bcf per year, or a little under 1 percent per year. Likewise, weather-adjusted commercial gas-use has been growing by about 50 Bcf per year, or a little over 1 percent per year. Many different factors drive residential and commercial gas use over time, but the most dominant driver is demographic trends. Simply put, growth in gas use is a direct result of population growth. In the residential sector, population growth translates into growth in gas heated homes. The U.S. population has been growing at about 1 percent per year, while the Canadian population has been growing at a slightly slower rate between one-half and one percent per year. The total number of gas heated homes has been increasing by a little over 1 percent per year as natural gas continues to be the preferred fuel for newly constructed units. Gas also continues to gain market share as gas distribution systems are built out and new gas service is offered to neighborhoods that did not have gas service before. The growth in gas households is offset, to some extent, by efficiency improvements (e.g., more efficient furnaces and water Over the past five years, residential and commercial (R/C) gas use has averaged 9.0 Tcf per year in the U.S. and Canada, or 36 percent of total consumption, and is growing at about 100 Bcf or by about 1 percent per year as a direct result of population growth. heaters, better insulation and windows, etc.). Over time, disposable income also has an impact. A wealthier population can afford larger homes, translating into increased natural gas use. High gas prices can have a negative impact on gas use, but the impact is generally small in the residential sector. In the commercial sector, population growth translates into growth in commercial floor space, which translates into increased gas use. As in the residential sector, efficiency improvements tend to dampen the growth in gas use over time as more efficient furnaces and water heaters and better insulation reduce the gas required per square foot of floor space. Disposable income and gas prices also have an impact, as they do in the residential sector. In addition, gas use for space cooling and onsite electric generation (i.e., distributed generation) is poised to make gains in the commercial sector over time. Overall, we expect that continued growth in population and the other factors mentioned above will continue to increase gas use in the residential and commercial sectors over time. days or the difference in heating degree days from average conditions. The coefficient for the counter indicates the amount of change in demand that may be attributed to the underlying growth rate of demand, and the weather coefficient indicates the amount of change that may be attributed to the impact of weather. Energy and Environmental Analysis, Inc. Appendices Page 3

112 On a regional basis, thirty-five percent of the total North American R/C gas use is concentrated in the central part of the U.S. (Figure 1), even though the region accounts for only 26 percent of population with 80 million residents 6. In the region, 74 percent of the housing units rely on natural gas for home heating, versus a national average of 59 percent. About 52 percent of commercial establishments rely on natural gas for space and water heating, a little above the national averages of 50 percent. Figure 1 Regional Residential and Commercial Gas Use (Bcf), 2005 Source: Energy and Environmental Analysis, Inc Canada West Central/ Midwest East Commercial Residential Gulf Producing The eastern region accounts for only 29 percent of R/C gas use in the U.S. even though one third of all U.S. and Canada residents or just over 100 million people reside in the area and the winter weather is very cold in many states within the region, requiring significant heating. Unlike the central part of the country where the penetration of gas heating is large, only 44 percent of the housing units rely on gas in the eastern area. Further, only 20 percent of the commercial establishments in the east rely on natural gas for water heating, well below the national average. This market has significant potential for additional gas use in the residential and commercial sectors, but the sparseness of pipeline service in some states, particularly in New England and the 6 Population as of 2000 for both U.S. and Canada. Energy and Environmental Analysis, Inc. Appendices Page 4

113 Carolinas is a potential shortcoming. Even so, we expect that about 40 percent of the future growth in R/C gas use in the U.S. will occur on the eastern seaboard, but that highly depends on the development of potential new gas supplies for the market, like LNG imports. Even though the Gulf Producing and West areas are as large geographically as the eastern and central markets, R/C gas use in these areas is only about 22 percent of the U.S. and Canada total. The regions account for 30 percent of the total population, and many of the states require little home heating during the winter. However, gas use for space cooling is likely to make gains in these areas; however, we expect that the potential growth is relatively small. Total Canadian R/C gas use is over 12 percent of the total. Population in Canada accounts for approximately 10 percent of total U.S. and Canada population. Colder climate is an obvious driver for the higher than average gas use in the R/C sector. The vast majority of the gas consumed in the residential and commercial sectors is gas purchased from gas utilities, often referred to as local distribution companies (LDCs). Utilities buy gas from producers, rely on pipeline capacity to transport the gas to their distribution system, and use their system to move the gas to residents and commercial establishments. About 1000 different gas utilities buy and resell gas to residential and commercial gas customers throughout the U.S. The top 50 gas utilities sell 5.6 Tcf of gas, or about 25 percent of the gas consumed in the U.S. (Table 3). Central Gas Manitoba would rank about 45 th on this list. A-1.2 North American Industrial Gas Consumption The industrial sector is currently the largest sector for natural gas use in North America, consuming an average of 8.6 Tcf per year, or 34 percent of the total gas consumed during the past six years. There are many different industrial gas consumers, including chemical providers, iron and steel manufacturers, paper mills, refiners, and food processors, among others. By far, chemical producers represent the single largest group of industrial gas consumers, accounting for almost one-third of the total gas consumed in the industrial sector. On a regional basis, about one-third of the industrial gas use is concentrated in the Gulf Producing area (Figure 2). The 2005 Gulf industrial gas consumption level would have been even higher if not for hurricane related damage. Much of the U.S. oil and gas production is concentrated in this area, hence, much of the U.S. petrochemical production and many of the U.S. refineries are also located in the area. Also, a significant amount of the U.S. ammonia production is located along the Gulf Coast. As gas The industrial sector is still the largest sector for gas use in the North America despite significant demand destruction over the past few years. We expect that industrial gas use will grow modestly as economic growth continues to shift towards non-energy intensive manufacturing in high-tech industries. Energy and Environmental Analysis, Inc. Appendices Page 5

114 consumption in these industries has declined, the region s share of total U.S. industrial gas use has declined from over 40 percent just a few years earlier. Table 3 Top 50 Gas Utilities Ranking of Companies By Total Gas Sales in 2001 Source: AGAeGUS Database Rank Company Name Sales (Bcf) /1 R evenue (M illion US$) Customers 1 SOUTHERN CALIFORNIA GAS CO 355 $2,999 5,048,929 2 KINDER MORGAN TEXAS PIPELINE 301 $1, PACIFIC GAS & ELEC CO 273 $3,087 3,888,946 4 PUB SVC ELEC & GAS CO 260 $1,551 1,665,724 5 NICOR GAS 245 $1,898 1,859,140 6 CONSUMERS ENERGY CO 229 $1,281 1,614,475 7 HOUSTON PIPELINE CO AEP 194 $ MICHIGAN CONSOL GAS CO 172 $953 1,169,552 9 COLUMBIA GAS DIST CO 170 $1,791 1,445, RELIANT ENERGY ENTEX 149 $1,039 1,499, TXU GAS DISTRIBUTION 143 $1,138 1,434, TXU FUEL CO 140 $ PUB SVC CO OF COLORADO 140 $1,132 1,111, RELIANT ENERGY MINNEGASCO 137 $1, , KEYSPAN ENERGY DEL LONG ISLA 128 $ , SOUTHW EST GAS CORP 124 $1,133 1,348, KEYSPAN ENERGY DEL CO 118 $1,252 1,155, PUGET SOUND ENERGY 108 $ , PEOPLES GAS LT & COKE CO 107 $1, , PEOPLES NAT GAS CO 106 $1, , CON EDISON CO OF NEW YORK INC 106 $1,294 1,048, EAST OHIO GAS CO 98 $ , NORTHERN STATES PW R CO 93 $ , NORTHERN INDIANA PUB SVC CO 90 $ , QUESTAR GAS CO 89 $ , OKLAHOMA NAT GAS CO 82 $ , LACLEDE GAS CO 78 $ , MIDAMERICAN ENERGY CO 78 $ , NORTHW EST NAT GAS CO 72 $ , W ASHINGTON GAS LT CO 72 $ , RELIANT ENERGY ARKLA 71 $ , W ISCONSIN GAS CO 68 $ , SAN ANTONIO PUB SVC BD 68 $ , NIAGARA MOHAW K PW R CORP 64 $ , KANSAS GAS SVS CO 64 $ , UNIT GAS TRANS CO 62 $ BOSTON GAS CO 62 $ , PIEDMONT NAT GAS CO 62 $ , INDIANA GAS CO INC 61 $ , PHILADELPHIA GAS W KS 61 $ , MISSOURI GAS ENERGY 58 $ , NATL FUEL GAS DISTR 56 $ , ILLINOIS PW R CO 54 $ , PECO ENERGY CO 54 $ , W ISCONSIN ELEC PW R CO 52 $ , SAN DIEGO GAS & ELEC CO 52 $ , PNM GAS SERVICES 50 $ , NUI CORP 47 $ , NEW JERSEY NAT GAS CO 47 $ , CINCINNATI GAS & ELEC CO 46 $ ,651 Total of Top 50 Companies 5,613 $45,958 43,028, Sales to all customers, including sales to industrial facilities and power providers. Energy and Environmental Analysis, Inc. Appendices Page 6

115 Figure 2 Regional Industrial Gas Use (Bcf), 2005 Source: Energy and Environmental Analysis, Inc Canada West Central/ Midwest East Industrial Gulf Producing About 25 percent of North American industrial gas use is concentrated in the central part of the U.S., particularly in the Upper Midwest (i.e.,. Ohio, Indiana, Illinois, and Michigan). This area is known for its heavy manufacturing, for example, auto manufacturing and iron and steel production. Many of these industries have been contracting or production has moved to other parts of the world, as the U.S. has become less competitive in these industries over the past two decades. The East Coast and western U.S. each have over 1 Tcf of annual gas use in the industrial sector. The industrial bases in these areas are very diverse, with many different types of manufacturing. Hence, the risk of these regions losing significant industrial load in the future is far less than it is on the Gulf Coast and in the central U.S. where fewer industries dominate. Canadian industrial gas use is about 13 percent of total North American Gas use and is proportional to U.S. averages. About 80 percent of the gas consumption is in three provinces: Alberta, Ontario, and Quebec. Alberta consumption roughly equals the Energy and Environmental Analysis, Inc. Appendices Page 7

116 combined Ontario and Quebec consumption. However, this may change as oil sands development in Alberta increases. Over the past few years, the industrial sector s share of total gas consumption has fallen as a result of demand destruction that has occurred at relatively high natural gas prices. We estimate that the industrial sector has shed over 1 Tcf of gas use in response to relatively high gas prices. The largest reductions have occurred in industries where the cost of gas is a high percent of value added. For example, petrochemical production, most notably ammonia production, has shed a significant amount of gas load. Conversely, industries where the cost of gas is a rather low percent of value added (e.g., stone, clay, and glass manufacturing) have shed much less load in response to high gas prices. Whether demand destruction will continue at its recent rate or whether it will slow has been a widely debated subject. Our expectation is that additional demand destruction will slow as there has already been significant demand destruction in the most price sensitive areas of the industrial sector over the past few years. In industries where the cost of gas is a low percent of value added, our expectation is that high gas prices will result in little additional demand destruction. Those industries are likely to absorb the higher gas costs, and pass the additional cost on to consumers of their products, assuming they haven t already done so. In the scope of things, other costs (e.g., cost of labor) have far greater importance to their bottom line. Over the long run, industrial production and efficiency of new equipment will drive industrial gas use. Over the past decade, industrial activity in energy intensive activities has slowed and activity in high-tech (generally not energy intensive) manufacturing operations (e.g., computer chip manufacturing) has accelerated as the U.S. has moved towards a high-tech economy. Such shifts in the economy and gains in efficiency have dampened the growth of gas use in the industrial sector. We expect the growth in industrial activity to continue to be concentrated in high-tech manufacturing with slower growth in energy-intensive industrial activities in the future, consistent with recent history. Hence, the industrial sector should experience only modest growth in the future. A-1.3 North America Power Generation Gas Consumption Over the past six years, the power sector has used an average of 4.9 Tcf of gas per year, accounting for about 19 percent of the gas used in the U.S. and Canada. Gas use in the power sector has been on an upward trend, along with the addition of new gasbased power plants. From 1998 through 2005, about 230 GW of new gas-based power generating capacity has been added in the U.S., more than doubling gas-based generating capability. Growth in Canadian gas-based generation has been more modest with about 4 GW of new capacity since 2000 (Figure 3). Gas generation has increased as electricity demand has increased. From 2000 through 2005, gas-based generation has risen from 411 to 542 billion kilowatt-hour (Bkwh) per Energy and Environmental Analysis, Inc. Appendices Page 8

117 year, or by over 30 percent (Table 4) 7,8 in the U.S. Lower-48. Coal Generation however has also increased by a similar amount in the same time period, 110 GWs for the U.S. Lower 48. Figure 3 Gas-Based Power Generating Capacity (Gigawatts, GW) Source: Energy and Environmental Analysis, Inc Canada West Gulf Producing Central/ Midwest East New Gas/Oil Capacity Built Pre-1998 Gas/Oil Capacity Because the recent construction boom has created a significant amount of underutilized gas-based capacity that can be relied on to satisfy growth in electricity demand, the power sector should continue to be an area of growth for natural gas use well into the future. Although there are opportunities for other types of generation, particularly at the relatively high natural gas prices recently experienced, gas generation still maintains some advantages over other types of generation. Considering a number of factors, we 7 Does not include about 200 Bkwh of gas-based cogeneration that the U.S. Energy Information Administration reports in the power sector. EEA includes cogeneration for units that existed prior to 1998 in its industrial sector, and not the power sector, in its modeling and market analysis. 8 Although gas use in power generation is up, it is not up by nearly as much as gas-based power generation on a percent basis. Some of the new gas units have displaced less efficient gas units, and, in some cases, this has reduced gas use while increasing electricity output. Energy and Environmental Analysis, Inc. Appendices Page 9

118 expect that incremental growth in electricity demand will be satisfied primarily by gasbased generation during the next few years 9. Table 4 Recent Power Generation in the U.S. Lower-48, Bkwh 10 Source: Energy and Environmental Analysis, Inc. Total Generation Gas Generation Coal Generation Other Generation , ,873 1, , ,859 1, , ,904 1, , ,922 1, , ,932 1, , ,983 1,165 Change % Change % 31.9% 5.9% 4.5% Regionally, gas-based power generation and natural gas use in the power sector are concentrated in those areas that contain the most gas generating capacity, which are the Gulf Coast and the east (more specifically, the southeast). Hence, the Gulf Coast 9 This conclusion will be discussed at greater length in the sections that follow. Other types of generation, most notably coal generation, are also likely to increase in the future. However, it is harder to increase growth of some of the other types of generation, like coal and nuclear, because utilization factors for the units are already above 70 percent on an annual basis, and in some regions above 90 percent. Also, construction of new coal and nuclear capacity is not likely to be significant over the next five years or so, due to the expense and difficulty of building the units, not to mention some of the environmental drawbacks. Today s relatively high gas prices encourage non-gas generation, but other factors discourage non-gas generation. This scenario will continue to play out in the future. 10 Does not include approximately 200 Bkwh of cogeneration that the U.S. Energy Information Administration reports in the power sector. EEA includes cogeneration for units that existed prior to 1998 in its industrial sector, and not the power sector, in its modeling and market analysis. Energy and Environmental Analysis, Inc. Appendices Page 10

119 and eastern states account for nearly two-thirds of the gas used for power generation in the U.S. and Canada (Figure 4). Figure 4 Regional Power Generating Gas Use (Bcf), 2005 Source: Energy and Environmental Analysis, Inc Canada West Power Generation Gulf Producing Central/ Midwest East The central U.S. is heavily dominated by coal generating capacity, and, as a result, it has not historically relied on much gas generation. The western U.S. has about 16 percent of the gas generating capacity and consumes about 16 percent of the gas used for power generation. The Canadian power sector is a smaller portion of the gas market relative to U.S. averages. This is due to hydro and other readily available power sources. Canadian power sector consumption accounts for 6 percent of total North American power sector consumption. A-1.4 Seasonal Gas Demand North American gas use is very seasonal, with peak winter levels of gas consumption well above consumption throughout the remainder of the year. For example, average daily North American gas consumption of 95 billion cubic feet per day (Bcfd) during January The seasonality of the natural gas market is not likely to change much over time. Despite significant growth in summer peaking gas load for power generation, growth in R/C load will be sufficient to maintain a winter peak. Energy and Environmental Analysis, Inc. Appendices Page 11

120 2005 exceeded average daily consumption for any other month of the year (Error! Reference source not found.). The main reason is that residential and commercial gas use, primarily used for space heating, is very seasonal. 11 During the months of January and February, the average daily residential and commercial gas consumption was nearly 50 Bcfd or 5 times greater than the R/C load during the summer. Figure 5 Monthly Gas Use by Sector (Bcfd), 2005 Source: Energy and Environmental Analysis, Inc Gas Use in Bcfd 60 Residential Power Generation 40 Commercial 20 Industrial 0 Other Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Other Industrial Commercial Residential Power Generation Unlike residential and commercial gas load, power sector gas load is summer peaking, consistent with the peak in electricity use. in the U.S. (Figure 6). The average daily gas use in the power sector in August of this past year was about 22 Bcfd, nearly double the January level of 11.5 Bcfd 12. We don t expect the overall seasonality of gas use to change much over time. Despite significant growth in gas generation, growth in gas used for space heating in the residential and commercial sectors will be sufficient to keep the gas market highly seasonal and winter peaking over time. 11 This is a result of seasonal temperature differences. For example, assuming normal weather (i.e., average weather over the past 30 years) the average daily wintertime temperature in the Northeast U.S. is 32 degrees Fahrenheit, versus the average daily July temperature of 77 degrees Fahrenheit. 12 August 2005 was 17 percent hotter than normal on average across the U.S. Thus, gas generation was above the level to be expected with normal weather conditions. However, even if the weather had been normal, last summer s peak still would have been substantially greater than last winter s peak. Energy and Environmental Analysis, Inc. Appendices Page 12

121 Figure 6 U.S. and Canada Monthly Electricity Use (Bkwh), 2005 Source: Energy and Environmental Analysis, Inc Electricity Use in Billions of Kwh Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec A-2 North American Gas Supply Since 2003, North American upstream activity has steadily increased, and gas well completion activity is at record levels. Gas production has been flat in the U.S. and declining slowly in Canada, but the high level of activity is beginning to result in a trend of increasing deliverability, especially in the Rockies and East Texas. In Canada, Alberta gas production has continued to decline, but increases in British Columbia have been significant. An emerging coalbed methane play in the Western Canadian Sedimentary Basin has the potential to greatly improve the production outlook from the basin. A-2.1 Drilling Rigs and Completion Activity U.S. Rigs and Completions Figure 7 illustrates the strong increase in U.S. drilling rig activity since The active rig count in August, 2006 was 1,730. This can be compared to an activity level of 850 rigs in The majority of the increase has been in onshore gas plays. Figure 8 shows the trend in U.S. gas completion activity by 5,000 foot interval. Approximately 27,000 gas well completions were recorded in EEA currently estimates that activity this year will exceed 30,000 completions. Energy and Environmental Analysis, Inc. Appendices Page 13

122 Figure 7 U.S. Drilling Rig Activity US Gas and Oil Directed Rigs - Onshore vs Gulf of Mexico Baker Hughes (Through 8/06) 2,000 1,800 1,600 Rig Count 1,400 1,200 1, Oil - GOM Oil Onshore Gas - GOM Gas Onshore Figure 8 U.S. Onshore Gas Completions Onshore Lower-48 Gas Completions by Depth Interval - API Quarterly Completion Report 30,000 25,000 Annual wells 20,000 15,000 10,000 15,000 + ft 10-15,000 ft 5-10,000 ft 0-5,000 ft 5, Energy and Environmental Analysis, Inc. Appendices Page 14

123 Canada Rigs and Completions Canadian rig activity has also increased, but not as rapidly as in the U.S., as shown in Figure 9. The chart shows the seasonal variation in activity that is a characteristic of Canada drilling. A recent peak of over 700 rigs was observed in February of this year. Gas well completion activity in the Western Sedimentary Basin has increased greatly since 1998, and over 15,000 gas wells were completed in both 2004 and 2005 (Figure 10). Much of the current completion activity is in the coalbed methane play in Alberta, where thousands of wells have been completed. Figure 9 Canadian Rig Activity Since 2000 Canada Rig Count Since Monthly Average Rigs A-2.2 Lower-48 and Canada Production and Forecast As shown in Table 5, North American gas production has been relatively flat since The recent peak Lower-48 dry gas production was 19.2 Tcf in Lower-48 production remained almost constant through 2004, then declined significantly in 2005, largely as a result of Hurricanes Katrina and Rita. Canadian production has declined slightly in recent years, although 2005 production was almost identical to that of Energy and Environmental Analysis, Inc. Appendices Page 15

124 Figure 10 Canadian Gas Well Completions Annual WCSB Gas Wells 18,000 16,000 14,000 Annual Completions 12,000 10,000 8,000 6,000 BC Sask. Alberta 4,000 2, Table 5 U.S. and Canada Historical Production U.S. and Canada Historical Production Wellhead Production Dry Production Bcf Canada Bcf Canada L48 Total Total L48 Total Total ,744 7,439 28, ,710 5,928 24, ,045 7,676 28, ,181 6,052 25, ,306 7,610 27, ,498 6,081 24, ,353 7,388 27, ,641 5,880 24, ,166 7,464 27, ,268 5,898 24, ,791 7,446 27, ,651 5,887 23,539 Bcfd Canada Bcfd Canada L48 Total Total L48 Total Total Figure 11 is a monthly series showing Canada dry gas production since Alberta production is dominant, but was experiencing a gradual decline recently through The initiation of the Horseshoe Canyon formation coalbed methane play in 2005 has Energy and Environmental Analysis, Inc. Appendices Page 16

125 contributed to the stabilization of Alberta gas production. Gas production in British Columbia has experienced an increase in recent years as a result of exploration and development activity in conventional reservoirs. Saskatchewan production has been relatively constant. Eastern Canada gas production is predominantly from the Sable Island offshore gas fields in Nova Scotia, which produce about 400 million cubic feet per day. Figure 11 Canada Dry Marketed Gas Production Canada Dry Marketed Monthly Production Through June EEA and StatsCanada Data Bcf per Day E.Can/Other Sas. BC Alberta Jan-01 Apr-01 Jul-01 Oct-01 Jan-02 Apr-02 Jul-02 Oct-02 Jan-03 Apr-03 Jul-03 Oct-03 Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Oct-05 Jan-06 Apr-06 Figure 12 presents the current EEA forecast of dry gas production for the Lower-48 and Canada through These data are from the current EEA Base Case model run, and the forecast incorporates the assumptions that are included in that run. The chart shows that EEA is forecasting an increase in North American gas production from 65 Bcf/d to 72 Bcf/d by Most of the forecast increase occurs in the U.S. Energy and Environmental Analysis, Inc. Appendices Page 17

126 Figure 12 EEA Canada Gas Production Forecast Lower-48 and Canada Gas Production Forecast Bcf per Day A-2.2 Trends in Supply Costs 2009 Lower Canada Historically, as upstream activity increases, drilling and development costs increase. Cost components include drilling day rates, completion costs, lease costs, and operating costs. Rig day rates in the U.S. are at unprecedented levels, as shown in Figure 13 and Figure 14. The rate for Gulf of Mexico jackup rigs has increased from $20,000 per day in 2002 to a recent peak of $130,000 per day. Onshore rig day rates have increased from $7,000 per day in 2003 to current levels of over $14,000. The high day rates have improved the economics of rig leasing such that we are seeing significant additions to the U.S. rig fleet, as drilling firms can justify new rig construction. The high drilling costs are having a large impact on producers. The cost has a direct impact on rate of return, and many marginal plays and areas may become uneconomic. Energy and Environmental Analysis, Inc. Appendices Page 18

127 Figure 13 GOM Jackup Rig Day Rates GOM Jackup Day Rates vs. Gas and Oil Prices Thousand Dollars per Day (nominal) Jackup Avr. HH Gas Price $/MMBtu WTI $/MMBtu $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 Dollars per MMBtu for gas and oil 20 $ Jul-99 Oct-99 Jan-00 Apr-00 Jul-00 Oct-00 Jan-01 Apr-01 Jul-01 Oct-01 Jan-02 Apr-02 Jul-02 Oct-02 Jul-03 Oct-03 Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Jan-03 Apr-03 Month Oct-05 Jan-06 Apr-06 Jul-06 $0.00 Figure 14 U.S. Onshore Day Rates Average Onshore U.S. Day Rate $16,000 $14,000 $12,000 Dollars per Day $10,000 $8,000 $6,000 $4,000 $2,000 $0 Q1.99 Q2.99 Q3.99 Q4.99 Q1.00 Q2.00 Q3.00 Q4.00 Q1.01 Q2.01 Q3.01 Q4.01 Q1.02 Q2.02 Q3.02 Q4.02 Q1.03 Q2.03 Q3.03 Q4.03 Q1.04 Q2.04 Q3.04 Q4.04 Q1.05 Q2.05 Q3.05 Q4.05 Q1.06 Q2.06 Quarter A-2.4 North American Gas Resource Base North America has an abundance of unproved and undiscovered natural gas resources. The current EEA resource base assessment indicates that the combined resources of the U.S., Canada, and Mexico total 1,386 Tcf of proved ultimate recovery (past Energy and Environmental Analysis, Inc. Appendices Page 19

128 production and proved reserves) and another 1,742 Tcf of unproved/undiscovered resource. Table 6 summarizes the current EEA North American gas resource base. The regions shown are those of the EEA Hydrocarbon Supply Model, which was the model used for resource base and production analysis in the 2003 National Petroleum Council gas study (illustrated in Figure 15). Proved resource categories include cumulative production and proved reserves, summing to ultimate recovery. Unproved categories include discovered undeveloped fields (in frontier areas), new fields, and shale, coalbed, and tight gas resources. In terms of unproved/undiscovered gas resources, the U.S. resource is assessed at 1,312 Tcf, Canada at 337 Tcf, and Mexico at 93 Tcf. North American coalbed methane resources are assessed at 155 Tcf, with 122 Tcf in the U.S. and 33 Tcf in Canada. North American shale gas resources are assessed at 87 Tcf, with 71 Tcf in the U.S. and 17 Tcf in Canada. Tight gas resources in the U.S. are 174 Tcf, while the tight gas resources of Canada are included with the new field category, which is assessed at 219 Tcf. Table 6 North American Gas Resource Base, in Tcf Source: Energy and Environmental Analysis, Inc. (Tcf dry; total gas) (Technically recoverable resource; includes inaccessible resource) Energy and Environmental Analysis, Inc. Discovered/ proved Discovered Undeveloped Unproved Unproved Super Super Plus Region Region Cumulative Proven Ultimate Discovered Old Field New Low-BTU/ Discovered Number Name Production Reserves Recovery Undeveloped Appreciation Fields Shale Coalbed Tight other Undeveloped 1 Alaska West Coast Onshore Great Basin Rockies West Texas Gulf Coast Onshore Mid-continent Eastern Interior Gulf of Mexico U.S. Atlantic Offshore U.S. Pacific Offshore WCSB Arctic Canada Eastern Canada Onshore Eastern Canada Offshore Western British Columbia Mexico North America 1, , ,741.7 Lower , ,017 Canada U.S , ,312 U.S. + Canada 1, , ,649 Energy and Environmental Analysis, Inc. Appendices Page 20

129 Figure 15 Map of EEA Supply Regions Energy and Environmental Analysis, Inc. Appendices Page 21

130 A-2.5 Regional Gas Supply Curves EEA has developed gas supply curves (resource cost of development curves) for each region in the U.S. and Canada. We applied a discounted cash flow procedure that evaluates the economics of each component of undeveloped gas. Using the procedure, it is possible to develop wellhead supply curves that show the relationship between wellhead gas prices and the amount of economic gas resource within each region. Figure 16 shows the wellhead supply curves by production region for the accessible portion of the resource base, using current technology, while Figure 17 shows the aggregate gas supply curve for North America. 13 The supply curves indicate that there is over 400 Tcf of gas that is currently economic to develop at wellhead gas prices at or below US$5 per MMBtu. On a regional basis, the majority of the remaining gas resource is concentrated in the supply areas that are currently the largest producing areas: the Gulf Coast Onshore, the Western Canadian Sedimentary Basin, the Gulf Coast Offshore, and the Rocky Mountains. In these areas alone, there is over 290 Tcf of supply that can be developed at gas prices of US$5 per MMBtu or less. In fact, the costs represented in these supply curves are relatively conservative, since they are based on current technology. As exploration and production technologies improve over time, the real cost of developing the resource base will decrease. This will increase the amount of supply that is economic to develop. The other important thing to note about the supply curves is that they become very price elastic as the price drops below US$5 per MMBtu. Between $4 and $5, there is a change of over 200 Tcf in the amount of resource that can be economically developed. So, if prices drop below $5 due to lower than expected demand growth or greater imports of LNG, less resource would be developed in the U.S. and Canada, which would tend to push prices higher. This supply elasticity effectively sets a floor on longterm gas prices of around US$4 to US$5 per MMBtu. 13 Since the majority of the natural gas production costs are in U.S. dollars, the analysis and following charts are presented in US dollars. Energy and Environmental Analysis, Inc. Appendices Page 22

131 Figure 16 Regional Gas Supply Curves Source: Energy and Environmental Analysis, Inc. $10 $9 $8 2004$/MMBtu $7 $6 $5 $4 $3 $2 0 50, , , , ,000 Bcf Undiscovered Gas West Coast Onshore Gas Supply Curve Great Basin Gas Supply Curve Rockies Gas Supply Curve West Texas Gas Supply Curve Gulf Coast Onshore Gas Supply Curve Midcontinent Gas Supply Curve Eastern Interior Gas Supply Curve Gulf of Mexico Gas Supply Curve US Atlantic Offshore Gas Supply Curve US Pacific Offshore Gas Supply Curve WCSB Gas Supply Curve Eastern Canada Onshore Gas Supply Curve Eastern Canada Offshore Gas Supply Curve Figure 17 Aggregate U.S. and Canada Gas Supply Curve Source: Energy and Environmental Analysis, Inc. $10 $9 $8 $7 2004$/MMBtu $6 $5 $4 $3 $2 $ , , , , , , , , ,000 1,000,000 Bcf Undiscovered Gas Energy and Environmental Analysis, Inc. Appendices Page 23

132 A-2.5 Activity by Region A Canada Gas Production Gas production in Canada is concentrated in the Western Canadian Sedimentary Basin (WCSB), a basin that encompasses portions of Alberta, British Columbia, and Saskatchewan. In 2005, the WCSB produced about 97 percent of the total Canadian production of 16 Bcfd. Gas production in the WCSB is dominated by conventional reservoirs and low permeability sandstones. A large-scale coalbed methane play has become active within the past few years, and is becoming a major contributor to the basin s gas production. There is also an extensive area of shallow gas production in southeastern Alberta. Figure 18 shows the province boundaries in western Canada. Along the western margin of the basin is the Foothills Belt, which extends the length of the basin from the U.S. border to the northern boundary of British Columbia. As shown in Figure 19, Alberta production continues to dominate Canadian gas production, but has declined since the late 1990s. Alberta gas production is declining because conventional exploration is becoming mature, with few significant discoveries. Although Alberta has a large non-conventional resource (tight gas, coalbed methane, and shale gas), these resources have only recently begun to be developed in a large way. The coalbed methane contribution to Canadian production is about 400 MMcfd and growing. Figure 20 shows the details of the EEA analysis of historical coalbed methane production and producing wells in the Western Canadian Sedimentary Basin, with a forecast though year-end EEA estimates that by year-end 2006, coalbed methane production will be 450 MMcfd from 5,000 wells. Gas production in eastern Canada is dominated by offshore production from the Nova Scotia shelf. This play has been producing since 2000 and currently produces about 400 MMcfd of raw gas. In addition to the developed resources of offshore Nova Scotia, numerous gas discoveries offshore Labrador and Newfoundland remain undeveloped. The gas associated with oil production in fields such as Hibernia offshore Newfoundland is being re-injected. EEA has assessed the remaining unproved potential in Canada at 337 Tcf. Of this quantity, 29 Tcf is reserve appreciation potential, 219 Tcf remains in undiscovered conventional fields, 17 Tcf is shale gas, and 33 Tcf is coalbed methane. The remaining resource (39 Tcf) is in discovered, undeveloped fields. Energy and Environmental Analysis, Inc. Appendices Page 24

133 Figure 18 Map of Western Canada Energy and Environmental Analysis, Inc. Appendices Page 25

134 Figure 19 Canada Marketed Gas Production Canada Dry Marketed Monthly Production Through June EEA and StatsCanada Data Bcf per Day E.Can/Other Sas. BC Alberta Jan-01 Apr-01 Jul-01 Oct-01 Jan-02 Apr-02 Jul-02 Oct-02 Jan-03 Apr-03 Jul-03 Oct-03 Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Oct-05 Jan-06 Apr-06 Energy and Environmental Analysis, Inc. Appendices Page 26

135 Figure 20 WCSB Coalbed Methane Production and Wells 800 WCSB Coalbed Methane Production and Producing Wells - From TransCanada April 2006 Slide and CSUG - EEA Estimates for Last Half of Prodution Includes Co-Mingled ; EEA August, , , MMCFD ,000 3,000 2,000 Producing Wells , Production Producing Wells WCSB Production Forecast Figure 21 presents the current EEA forecast for the Western Canadian Sedimentary Basin through Overall production is expected to decline slowly, but stabilize after 2015 at approximately 15.5 Bcf per day. Production from conventional and low permeability sandstone oil and gas fields in the Alberta-Saskatchewan-Manitoba region is expected to continue to decline. Coalbed methane production, currently contributing 400 MMcf/d is forecast to increase to 3.2 Bcf/d by 2025, with most of this attributed to Alberta. Conventional production in British Columbia will remain about constant. Energy and Environmental Analysis, Inc. Appendices Page 27

136 Figure 21 EEA WCSB Dry Gas Production Forecast WCSB Gas Production Forecast by Type Bcf per Day ASM Conventional ASM Coalbed BC Conv. BC CBM Uncertainty in Forecasting WCSB Production As discussed above, EEA has developed a forecast of WCSB activity and gas production through The forecast is from the EEA Base Case using the GMDFS model, and is based upon many elements, including: The proved and unproved resource base of conventional and non-conventional gas. The cost of supply of individual components of the resource. Analysis includes undiscovered field sizes and depth distribution for undiscovered conventional gas and ultimate recovery per well and deliverability profiles for unconventional gas such as coalbed methane. Overall North American market analysis including supply and demand equilibration and prices by node/region. Assumptions about startup years and volumes of Mackenzie Delta gas, Alaska gas, and LNG. Supply technology assumptions, including those impacting recovery per well and cost components. Energy and Environmental Analysis, Inc. Appendices Page 28

137 The overall uncertainty in the gas production forecast originates from uncertainties in these factors. However, EEA believes that the greatest sources of uncertainty in forecasting WCSB production are those related to the characteristics of the undiscovered/undeveloped resource base and the economics of producing it. Since most analysts now agree that gas production from conventional sources will at best be flat for the near term before continuing to decline, the potential to sustain or increase WCSB production over the long term is generally believed to fall largely on the nonconventional resources coalbed methane, tight gas, and possibly shales. Figure 22 presents a comparison of the EEA WCSB production forecast with those of TransCanada Pipelines. 14 Each year, TransCanada develops a Base Case study of mainline throughput for North American pipelines. The report includes both a TCPL Base Case and the results of a probability analysis to evaluate uncertainty in the WCSB supply forecast. The probability analysis uses a Monte Carlo process applied to nine model cases. The model cases represent three gas resource base scenarios and three gas price scenarios. After the probability range was developed for the total gas production forecast, separate probability distributions were developed for coalbed methane and tight gas, and these were incorporated into the analysis. This analysis produced the TransCanada forecasts shown on the chart. The TransCanada Base Case forecast results in a total gas production rate of 13 Bcf per day in This can be compared to the EEA forecast of 15.5 Bcf per day. The TransCanada low production case (P90) has 8.2 Bcfd in 2020 and their high case (P10) is 16.2 Bcfd. Figure 23 compares the TransCanada and EEA base case runs on the basis of conventional (including tight) and coalbed methane. EEA is more optimistic on coalbed methane and the non-coalbed methane forecasts are very similar. TransCanada Views on Uncertainty in Production Forecast In their report, TransCanada discusses WCSB production potential and the sources of uncertainty in their forecast. They state that there is a heightened awareness that the basin is maturing with a high probability that it has peaked or will peak in production within a few years. They also state that decline rates have increased and well productivity has decreased. Initial well production rates have declined approximately 65% between 1995 and 2005 and are expected to remain at relatively low levels over the forecast period. The also note the significant increase in supply costs. 14 National Energy Board, 2006, TransCanada Pipeline Canadian Mainline Throughput Study, Appendix G, June, Energy and Environmental Analysis, Inc. Appendices Page 29

138 Figure 22 Comparison of EEA and TransCanada WCSB Forecasts Comparison of EEA Base Case WCSB Production Forecast With 2006 TransCanada Forecasts Bcf per day EEA TransCan Base TransCan High TransCan Low 2003 NPC Figure 23 Comparison of EEA and TransCanada Forecasts by Production Type Comparison of EEA and TransCanada WCSB Forecasts - Coalbed Methane vs Conventional/Tight Bcf per Day EEA CBM TransCan CBM EEA Non-CBM TransCan Non-CBM Energy and Environmental Analysis, Inc. Appendices Page 30

139 TransCanada believes that there is significant uncertainty related to the development of coalbed methane, tight gas, and shale. They state that they recognize that the resource is present in both the Plains and Foothills region, but that there is uncertainty related to economic recovery. They also note that increased landowner opposition to coalbed methane development is expected. Their evaluation of uncertainty in 2020 coalbed methane production indicates a range of potential production of 1.0 to 2.8 Bcf per day, with a base case of 1.9 Bcfd. That can be compared to the current EEA forecast of 3.0 Bcfd. In terms of tight gas, TransCanada has developed an analysis and forecast based on the 0.1 millidarcy permeability cutoff that has been used in the U.S. Using this definition of tight gas, the company forecasts an increase in production from 200 MMcfd currently to a mean rate of 1.3 Bcfd in They have an uncertainty band of 0.7 to 1.8 Bcfd. TransCanada acknowledges the presence of a shale gas resource base, but states that there is no current commercial production. They believe that this resource has very little potential and have not developed a forecast of shale gas. The 2003 NPC report estimated that shale gas production would start in approximately 2008 and be at a level of 350 MMcf per day by 2020 and 1.3 Bcfd by In a report to the NEB published September 5 th of this year, GLJ Petroleum Consultants critiqued the TransCanada production analysis. 16 They concluded that TransCanada was too conservative and pessimistic in their analysis. They believe that the forecast of future drilling activity was too low, stating that the high case drilling activity was only slightly higher than the actual 2005 activity. They also believe that the TransCanada well productivity analysis was too conservative and included low-rate coalbed wells along with conventional wells rather than evaluating them separately. They see strong drilling activity, and increased conventional gas production in B.C. and Saskatchewan. Uncertainty in EEA WCSB Forecast One method of evaluating uncertainty in the WCSB production forecast is to look at the impact gas prices on the resulting model output. Figure 24 shows the EEA Base Case forecast, along with the results of a recent analysis of the impact of different AECO hub gas prices. The High Price case was $1.00 per MMBTU higher in 2010 and about $2.50 higher in 2020 than the Base Case. The Lower Price case was about $1.50 per MMTBU lower in 2010 and $2.00 per MMBTU lower in 2020 than the Base Case. In 2020, the Low Price case production was 3.5 Bcfd lower than the Base Case, and the High Price case production was 1.4 Bcfd higher than the Base Case. 15 National Petroleum Council, 2003, Balancing Natural Gas Policy, NPC, Washington, D.C. 16 National Energy Board, 2006, Proceeding MH ; report prepared by GLJ Petroleum Consultants, September 5, Energy and Environmental Analysis, Inc. Appendices Page 31

140 Figure 24 Impact of Gas Price on EEA Base Case Forecast Bcf per Day Base High Price Low Price A U.S. Production U.S. Lower-48 wellhead gas production 17 has averaged just over 20 Tcf per year during the past five years (Table 7). However, it is noteworthy that the trend has been generally down during the period. Production has been greatest in the Gulf of Mexico, exhibiting an average production rate of about 4.7 Tcf per year. However, production in the area has declined significantly during the period. On the flip side, production in the Rockies has grown significantly during the past five years, and the region currently ranks third among the listed regions with over 3 Tcf of production in Other large producing areas include the Gulf Coast onshore, the MidContinent, and Northeast Texas/North Louisiana. Production trends for each of the regions listed in Table 7 are discussed in greater detail below. 17 Gas production, as reported in this section, is on a wellhead (raw) basis. The stream represents production directly from the wells prior to any processing. Therefore, it includes both unprocessed liquids and non-hydrocarbon gases (e.g., CO 2 ). On a dry marketed basis, with liquids and nonhydrocarbon gases removed, production has averaged about 18 Tcf during the past five years, representing a 10 percent difference between dry and raw gas. Energy and Environmental Analysis, Inc. Appendices Page 32

141 Table 7 Lower-48 Wellhead (Raw) Gas Production Summary, in Bcf per Year Source: Energy and Environmental Analysis, Inc Northern Rockies 2,222 2,400 2,593 2,728 2,892 3,036 Southern Rockies 1,645 1,610 1,610 1,620 1,641 1,627 MidContinent 2,985 2,914 2,738 2,760 2,792 2,756 Northeast Texas/North Louisiana 1,551 1,680 1,778 1,960 2,199 2,333 Permian 1,666 1,668 1,632 1,599 1,564 1,572 Onshore Gulf Coast 4,127 4,077 3,835 3,712 3,602 3,409 Gulf of Mexico 5,310 5,420 4,864 4,763 4,279 3,874 West Coast Appalachian/Midwest Lower-48 20,744 21,045 20,306 20,353 20,166 19,791 Northern Rockies The Northern Rockies region as defined here includes Wyoming and parts of Colorado, Utah, Montana, and North Dakota. Production in the region is growing rapidly as a result of tight gas and coalbed methane development. In the late 1990s and early 2000s, the Powder River Basin coalbed play in northeastern Wyoming was the focus of activity. More recently, tight gas exploration has dominated in areas such as the Piceance Basin of northwestern Colorado and the Green River Basin of southwestern Wyoming. The region has the greatest volume of unproven recoverable gas resource of any region in the U.S., and the resource is primarily in tight (low permeability) sands. In the 1990s, transportation bottlenecks from the region were severe, and had a major impact on wellhead prices and activity. In recent years, numerous new pipelines and expansions have resulted in much greater capacity from the region. Figure 25 summarizes recent historical wellhead (raw) gas production for the region. It shows gas production by vintage, the base production decline, and the initial decline for new wells coming on each year. Average production in 2005 was 8.3 Bcfd. Figure 26 is a map showing the major Lower-48 producing basins. The Powder River Basin is located in northeastern Wyoming and southeastern Montana. Through the early 1990s it had a history of conventional oil and gas production. Beginning in the mid-1990s, significant activity and production started in the coalbed methane play. Production in the basin (including conventional gas) has grown from about 150 MMcfd in the late 1990s to the current rate of almost 1.0 Bcfd. Energy and Environmental Analysis, Inc. Appendices Page 33

142 Figure 25 Northern Rockies Wellhead Gas Production Source: Energy and Environmental Analysis, Inc processing of Lippman Data. Initially, activity primarily involved the shallow Wyodak Formation coals on the eastern flank of the basin. Wells are shallow, about 800-1,500 feet in depth, and typically produce around 250 to 300 MMcf over the life of the well. Currently, there are more than 14,000 producing coalbed wells in the basin. While basin production remains dominated by the shallow Wyodak play, over the past few years the deeper Big George coalbed formation has become increasingly important in terms of both activity and production. Well recoveries are significantly higher than in the Wyodak, and are said by one operator to be two to three times higher than the Wyodak, or approximately MMcf per well. EEA s assessment is that the remaining CBM resource is 26 Tcf. At an average well recovery of 400 MMcf, this would represent 65,000 potential wells. Energy and Environmental Analysis, Inc. Appendices Page 34

143 Figure 26 Lower-48 Supply Basins The Green River Basin encompasses portions of southwestern Wyoming and northwestern Colorado. Green River Basin wellhead production has increased from 1 Bcfd in 1990 to 3 Bcfd in Most of the production increase occurred after 1998, when production averaged 1.6 Bcfd. From a resource base perspective, the Green River basin contains the largest untapped gas resource of any basin in the region. The tight gas resource has been assessed by the U.S. Geological Survey at nearly 40 Tcf. The most significant activity in the Green River Basin is in the Jonah-Pinedale field area. This is the area responsible for essentially all of the gas production growth since the late 1990s. It is a structural anticline with multiple stacked tight gas sand reservoirs. A large number of development wells have been drilled on spacing as close as acres. Ultra Petroleum reports that there are 350 producing wells in Pinedale Field and 650 wells in Jonah Field. Raw gas production at Pinedale at yearend 2005 was 600 MMcfd and raw gas production at Jonah was 750 MMcfd. At Pinedale, Questar and Ultra Petroleum are developing the multi-tcf field. Well recoveries are reported to be up to 8 Bcf per well in the Lance Formation. At Jonah Energy and Environmental Analysis, Inc. Appendices Page 35

144 Field, Encana and Ultra Petroleum are the largest operators. The field contains about 4 Tcf of sweet gas in the Cretaceous Lance formation. The Wamsutter Field in the eastern portion of the basin is experiencing increased tight gas development drilling. This is the location of a large tight gas development by BP. BP plans to drill up to 2000 wells to increase production by up to 250 MMcfd. Land access is a major issue in the Green River Basin. NPC estimated that 37 percent of the resource is off limits. An additional 26 percent is higher cost because of regulations. EEA s assessment of the remaining tight gas resource base is 39 Tcf. The Uinta Basin is located in northeastern Utah. Gas production from the basin was relatively constant at 200 MMcfd through the mid-1990s. However, over the past decade production has increased to a rate of 760 MMcfd (wellhead). The Uinta Basin has a large undeveloped tight gas resource base. It also contains coalbed methane resources in the Ferron coalbed play of Emery County. Production from the coalbed play has flattened out in recent years. Tight gas resources are being actively developed in the Natural Buttes Field area. EEA assessed this area to have 2 Tcf of infill development potential. Most of the potential is in formations that are somewhat deeper than existing production. Stimulation and completion technology advances have been critical in this play, and well recoveries are reported to be up to 5.5 Bcf per well. The EEA assessment of Natural Buttes is conservative relative to information recently published by Kerr-McGee on Natural Buttes. They indicate that their acreage has unbooked reserve potential of 4.7 Tcf. EEA has assessed the tight gas resource base for the combined Uinta-Piceance at 27.5 Tcf. The Uinta Basin part of the assessment is about 16 Tcf. The coalbed methane resource for the two basins is 5.9 Tcf. About 2 Tcf of this is the Uinta Basin portion. The Piceance Basin in northwestern Colorado contains extensive tight gas resources. It is rapidly emerging as one of the key basins in the Rockies, and production growth in the basin is expected to play a major role in future Rockies production. The basin currently produces 875 MMcfd (wellhead). This is up from only about 300 MMcfd in The recent production growth is attributed to a ramp-up in tight gas development activity by Encana, Williams, and Exxon. Encana is drilling several hundred wells per year in the Mamm Creek field. There is the potential for almost 3,000 wells on 10 acre spacing, and each well is expected to recover about 1.5 Bcf. Williams claims it has about 3,000 undrilled tight gas well locations. Exxon has recently publicized their intentions to develop tight gas resources in the basin. Key to their efforts is a new technology to complete 40 or more zones in each well, and to use directional drilling to minimize surface impacts. They have plans to drill 75 wells or more per year in coming years, and gas production is expected to increase from 55 to 230 MMcfd. Land access is an issue in the basin. The NPC assessed the no-access resource at 19% of the total. Recent industry press has discussed an ongoing conflict between industry and environmental groups regarding the Roan Plateau area, which overlies a significant fraction of the tight gas resource. The Roan Plateau BLM study area encompasses several hundred square miles. Energy and Environmental Analysis, Inc. Appendices Page 36

145 EEA s assessment of the Piceance Basin tight gas is approximately 12 Tcf of recovery. The coalbed methane resource is 4 Tcf. The Wind River Basin, located in central Wyoming, produced at a rate of 664 MMcfd in 2005 (wellhead). Production is dominated by the Burlington Resources-operated Madden Field. Madden field contains sour gas in the Madison formation and sweet gas in shallower intervals. Madden accounts for approximately half of the total production from the basin. Wind River production almost doubled during the 1990s with the expansion of Madden Field production and processing capacity. In recent years, the operator has increased production from the Madison reservoir through the addition of processing capacity, and has also been active in developing the Fort Union tight sands at a depth of about 9,000 feet. There is significant Tertiary coalbed methane potential and additional tight gas potential in the Frontier at 20,000 feet. The Wyoming-Utah-Idaho Overthrust Belt is a north-south trending structural feature that extends for hundreds of miles. The portion of the Overthrust Belt that is gas productive is located in southwestern Wyoming and northeastern Utah. In Canada, a different segment of the North American Overthrust Belt produces in a similar geologic setting. Production is from conventional carbonate and sandstone reservoirs in discrete structures and there is no large-scale tight gas or coalbed methane potential. Most of the fields were discovered in the 1970s and 1980s, and the play has been relatively inactive. In the Wyoming and northern Utah part of the play, operators have been unable to extend the productive play area as they had once hoped could be accomplished. Production has declined in recent years. The Denver Basin of eastern Colorado produces approximately 600 MMcfd. Production has grown by 100 MMcfd in recent years. Recent activity has been dominated by extensive tight gas infill drilling, re-stimulation and recompletion activity in the giant Wattenberg Field, which accounts for most of the basin s production. Kerr McGee is the most active operator and is carrying out hundreds of drilling or completion operations per year. Spacing rules have been approved to allow 20 acre development in Wattenburg Field, and Kerr-McGee states that they have 1.5 Tcf of unbooked potential in the field. EEA has assessed the tight gas resource in the basin at 2 Tcf. Three other minor gas production areas included in the Northern Rockies are Bighorn Basin, the Las Animas Arch, and the Williston Basin. The Bighorn Basin is located in northern Wyoming and is primarily an oil-prone area. Undiscovered potential is generally low and the area has seen little recent activity. Wellhead production is about 60 MMcfd and has remained constant in recent years. The Las Animas Arch is located in southeastern Colorado and is a minor gas producing province. The Williston Basin of Montana and North Dakota is primarily an oil and associated gas province. Montana also has production in central Montana and a portion of the Powder River Basin. Energy and Environmental Analysis, Inc. Appendices Page 37

146 Southern Rockies The Southern Rockies region includes northwestern and northeastern New Mexico, southwestern Colorado, and southeastern Utah. Production is dominated by the San Juan Basin, which is a heavily gas prone basin that has been producing since the 1940s. The San Juan Basin produces tight gas and coalbed methane production. Also included in the region are the Raton Basin and the Paradox Basin of southeastern Utah. Figure 27 summarizes recent historical wellhead (raw) gas production for the region. It shows gas production by vintage, the base production decline, and the initial decline for new wells coming on each year. Average wellhead gas production in 2005 was 4.5 Bcfd. The San Juan Basin occupies portions of northwestern New Mexico and southwestern Colorado. It is a heavily gas-prone basin that produces over 4 Bcfd of gas. Dating to the 1940s, basin activity was dominated by tight gas development in the Cretaceous Dakota and Mesaverde intervals. In the 1980s, producers began having success with the Fruitland Formation coalbed methane play, and the play expanded throughout much of the basin and became a major regional contributor to gas supply. Activity in the basin continues in the area of tight gas infill development and continued drilling and completion in the coalbed methane play. EEA currently estimates that the basin contains 21 Tcf of tight gas potential and 8 Tcf of coalbed methane potential. The Raton Basin is located in southeastern Colorado and northeastern New Mexico, and is the location of a significant coalbed methane play that currently produces 250 MMcfd of gas. Most of the coalbed production to date has been in the Colorado part of the basin, but the New Mexico contribution is now very significant. USGS assessments of the basin indicate the potential for about 2 Tcf of coalbed methane. The Paradox basin is located primarily in southeastern Utah. It is an oil-prone basin and is not active to a significant degree in gas development. There are no significant non-conventional gas plays or assessed resources in the basin. Rockies Production Forecast As shown in Figure 28, EEA is forecasting a tremendous amount of growth in Rockies gas production through [Note that the forecast production data are on a dry basis, as opposed to the wellhead data used for the historical analysis]. Figure 29 is a map of Lower-48 basin level supply regions as defined for the 2003 NPC study. Overall dry gas production is expected to increase from 10.7 Bcf/d in 2005 to 14.6 Bcf/d in The basin contributing the greatest volume of new production during the period is the Green River Basin in southwestern Wyoming. This basin is the location of the largest assessed volume of recoverable tight gas in the U.S. A large amount of production growth is also forecast for the Uinta-Piceance basin in northwestern Colorado and northeastern Utah. Production from the Powder River Basin coalbed play is forecast to continue to increase until about 2015, and peak at around 1.5 Bcf per day. Energy and Environmental Analysis, Inc. Appendices Page 38

147 Production from the San Juan Basin will continue a steady decline through the forecast period. Figure 27 Southern Rockies Wellhead Gas Production Source: Energy and Environmental Analysis, Inc. processing of Lippman Data Energy and Environmental Analysis, Inc. Appendices Page 39

148 Figure 28 EEA Rockies Dry Gas Production Forecast Rockies Gas Production Forecast Bcf per Day San Juan Green River Powder River Uinta-Piceance Denver Other Gulf of Mexico The Gulf of Mexico geologic province is an extension of the onshore Gulf Coast Tertiary province. As such, reservoirs are conventional, high permeability sandstones and the dominant trapping mechanism is structural. Depth of production ranges from several thousand feet on the shelf to over 20,000 feet in both the shelf and deepwater areas. Figure 29 summarizes recent historical gas production for the region. Average wellhead production in 2005 was 10.6 Bcfd. Production has declined greatly from the 2001 rate of approximately 15 Bcfd, reflecting the poor performance of the shelf area. The Gulf of Mexico is divided into shelf and deepwater regions, with the boundary at 200 meters of water depth, which generally corresponds with the shelf break. Production on the shelf was initiated in the 1940s, while significant deepwater activity and production dates to the 1980s. Shelf oil and gas production has been in decline for years, and the decline continued in 2005, despite recent efforts to develop deep gas resources below 15,000 feet. Deepwater production is primarily oil and associated gas, and had been increasing rapidly up until 2003, when it began to level off. The hurricanes of 2004 and 2005 had a major impact on Gulf of Mexico infrastructure, production, and activity. Hurricanes Katrina and Rita resulted in over 800 Bcf of shut in Energy and Environmental Analysis, Inc. Appendices Page 40

149 gas production in federal waters, and currently, less than 1 Bcfd of production remains shut in. Figure 29 Gulf of Mexico Wellhead Gas Production Source: Energy and Environmental Analysis, Inc. processing of Lippman Data Despite the recent hurricane disruptions to supply, industry investment in the deepwater play continues at a large scale, and EEA anticipates that 15 new deepwater fields will start production in Most of the activity is in water depths of more than 1,500 feet and numerous floating production and processing facilities are being constructed. The deepwater play is being extended into the eastern Gulf of Mexico, into deeper waters in the central part of the play, and to offshore Texas. The deep shelf drilling play has been active for several years and has resulted in a number of gas discoveries, but has not yet been shown to be of a magnitude that would reverse the shelf decline. Energy and Environmental Analysis, Inc. Appendices Page 41

150 Recently, Chevron announced the discovery of one of the largest oil plays in U.S. history, the Gulf Lower Tertiary trend in water depths of 7,000 + feet in the Central and Western Gulf. The play has been assessed with the potential for up to 15 billion barrels of oil. Assuming an overall gas to oil ratio of 2, this represents the potential for 30 Tcf of undeveloped gas resources in the Gulf, and a large percentage of this resource has been discovered. Gulf of Mexico Production Forecast As shown in Figure 30, EEA is forecasting a near-term increase in Gulf of Mexico dry gas production, with production increasing from the hurricane-impacted 2005 rate of 9.7 Bcf per day to 11.3 Bcf per day in Between 2010 and 2025, production is forecast to decline to 9.9 Bcf per day. The low value on the chart for 2005 reflects the large volume of shut-in production (over 800 bcf) from Hurricanes Katrina and Rita. The overall gas production increase forecast over the next decade will be driven by continued success in the deepwater area. Mature areas of the shelf will continue to decline, although at a much slower rate than observed in recent years. Should the deep shelf play become very successful, our shelf forecast may turn out to be conservative. Figure 30 Gulf of Mexico Dry Gas Production Forecast Gulf of Mexico Gas Production Forecast Bcf per Day MidContinent Cent./W. Shelf Cent./W. Deepwater Eastern The MidContinent region encompasses Oklahoma, Kansas, the Texas Panhandle, and Northern Arkansas. The region has generally been in decline, but within the past few years, exploration activity has increased and there are some very important Energy and Environmental Analysis, Inc. Appendices Page 42

151 developments such as renewed activity in the deep Anadarko Basin and a new shale gas play in the Arkoma Basin of Arkansas and Oklahoma (Fayetteville Shale). Figure 31 summarizes recent historical wellhead (raw) gas production for the region. It shows gas production by vintage, the base production decline, and the initial decline for new wells coming on each year. Average wellhead gas production in 2005 was 7.6 Bcfd. Figure 31 MidContinent Wellhead Gas Production Source: Energy and Environmental Analysis, Inc. processing of Lippman Data The Anadarko Basin of western Oklahoma, the Panhandle of Texas, and western Kansas is one of the oldest gas producing areas of the U.S. and remains the principal gas producing area of the MidContinent region. The east-west trending basin contains up to 40,000 feet of sedimentary section ranging in geologic age from Cambrian through Permian. The Hugoton Field in the shallow, western portion of the basin has produced gas for decades from low-permeability strata. Basin production has declined from almost 6 Bcfd in 1990 to 4.4 Bcfd in Energy and Environmental Analysis, Inc. Appendices Page 43

152 The Arkoma Basin is located in southeastern Oklahoma and central Arkansas. Like the Anadarko Basin, this province is a relatively old producing area, with declining production since The Arkoma basin has long been known as a tight gas resource area, and historically the Pennsylvanian age tight sands have accounted for most of the production. The basin contains more than 19,000 feet of strata. Until recent years the Arkoma Basin had been relatively inactive. In the 1990s, a coalbed methane development effort met with success. The most significant basin development in recent years is the newly defined Fayetteville Shale gas play in the eastern or Arkansas part of the basin, which although only beginning in terms of gas production (approximately MMcf/d), has major implications for the basin and the entire MidContinent region. In addition to the Fayetteville Shale, a new Woodford-Caney Shale gas play is developing in southeastern Oklahoma. Newfield Exploration, Devon, and Chesapeake are active and numerous wells have tested in the range of more than 2 MMcf/d. Northeast Texas and North Louisiana The Northeast Texas and North Louisiana region has been the focus of a great deal of drilling activity in recent years, primarily in the Barnett Shale play of the Fort Worth Basin and the Cotton Valley/Bossier Trend of East Texas and northern Louisiana. Figure 32 summarizes recent historical gas production for the region. It shows gas production by vintage, the base production decline, and the initial decline for new wells coming on each year. Average wellhead production in 2005 was 6.4 Bcfd. The Fort Worth Basin is located in north Texas Railroad districts 9 and 7B northwest and west of the Dallas-Fort Worth area. This is the location of the Barnett Shale gas play, which has experienced a dramatic increase in activity and production over the past five years. Production from the play has increased from 100 MMcfd in 1999 to a current rate of 1.3 Bcfd. Prior to the initial activity in the Barnett, shale gas was primarily known for low production rates observed in the Appalachian Devonian Shale and the Michigan Basin Antrim Shale. Success in the Barnett play is largely the result of completion and stimulation methods developed in recent years, primarily by Mitchell Energy, which was the operator prior to being purchased by Devon. These techniques have greatly improved economics by increasing production rates. The East Texas and ARKLA (Arkansas-Louisiana) basin extends from East Texas (Districts 5 and 6) across Northern Louisiana. The Texas and Louisiana portions of the basin are separated by a structural high called the Sabine Uplift. From a conventional standpoint, the basin is considered to be maturely explored. However, very large-scale tight gas resources remain to be drilled, and the basin is the focus of intense industry activity, primarily targeted on the Bossier and Cotton Valley intervals. EEA has defined the Bossier play using field and reservoir name information. We currently estimate that the play is producing between 700 and 800 MMcfd in Texas, and approximately 300 MMcfd in Northern Louisiana. In Texas, production has increased by several hundred million cubic feet per day in the past few years. Rig counts and gas completions continue to surge throughout the play. Energy and Environmental Analysis, Inc. Appendices Page 44

153 Figure 32 Northeast Texas/North Louisiana Wellhead Gas Production Source: Energy and Environmental Analysis, Inc. processing of Lippman Data Permian Basin of West Texas and SE New Mexico The Permian Basin includes portions of Texas RRC Districts 8, 8A and 7C in West Texas, and southeastern New Mexico. The basin has traditionally been a conventional oil and associated gas producing basin, with some non-associated gas production. Recently, however, it has been the target of a large amount of exploration and development for non-conventional gas. Sustainability of the production will greatly depend on the economic viability of these resources. Figure 33 summarizes recent historical gas production for the region. Average wellhead production in 2005 was 4.3 Bcfd. The Permian Basin contains up to 30,000 feet of strata, and the predominant oil producing lithologies are limestone and dolomite. Thick shales and lenticular sands are also present. A substantial effort is underway by producers to evaluate the potential of Energy and Environmental Analysis, Inc. Appendices Page 45

154 the Barnett and Woodford shales in the basin, to determine whether these formations have economic potential. The shale formations closer to the Dallas-Fort Worth area are present here, but their commercial viability has not yet been fully established. This play is in the Delaware Basin, adjacent to southeastern New Mexico, and is substantially deeper than the Barnett in the Fort Worth Basin. Sustainability of the area s production will greatly depend on the economic viability of the shale resource. Figure 33 Permian Basin Wellhead Gas Production Source: Energy and Environmental Analysis, Inc. processing of Lippman Data Onshore Gulf Coast The onshore portion of the Gulf of Mexico geological province extends from the southern tip of Texas across the entire Gulf Coast through Louisiana, Mississippi and Alabama. Figure 34 summarizes recent historical gas production for the region. Average wellhead production in 2005 was 9.3 Bcfd. The Texas and Louisiana portion of the area is one of the oldest producing provinces in the U.S. Oil and gas production is primarily from conventional sandstone reservoirs above 15,000 feet. Production is declining because Energy and Environmental Analysis, Inc. Appendices Page 46

155 of the exploration maturity of the area, and because of a lack of active non-conventional gas plays. Most of the existing fields are structural in nature and are associated with either salt domes or faulting. The presence of stacked reservoirs and multiple objectives within individual wells has resulted in a great deal of recompletion activity in existing wells. Both South Texas and South Louisiana have remaining potential in deep strata below 15,000 feet. South Texas has tight gas resources in the District 4 area in the western portion of the province. In addition, the Austin Chalk horizontal gas play has received considerable attention. South Louisiana does not have an active non-conventional play. The Eastern Gulf Coast includes Mississippi, Alabama, and Florida. Gas production is principally from conventional high permeability sands and some carbonates. The Warrior Basin of northern Alabama produces coalbed methane. Figure 34 Onshore Gulf Coast Wellhead Gas Production Source: Energy and Environmental Analysis, Inc. processing of Lippman Data Energy and Environmental Analysis, Inc. Appendices Page 47

156 West Coast The West Coast region encompasses California and other western states. Essentially all of the production is in California. Figure 35 summarizes recent historical gas production for the region. Average wellhead gas production in 2005 was 930 MMcfd. The Sacramento Basin is located in central California northeast of San Francisco. The basin is about 200 miles long and contains approximately 30,000 feet of sediment. It is an important natural gas province and produces mostly non-associated gas from conventional reservoirs. The basin is generally mature from an exploration standpoint, although recent exploration activity has increased. Basin production in recent years has been approximately 200 MMcfd. Most basin exploration and production has been shallower than 12,000 feet and some deeper potential remains to be developed. Figure 35 West Coast Gas Wellhead Gas Production Source: Energy and Environmental Analysis, Inc. processing of Lippman Data Energy and Environmental Analysis, Inc. Appendices Page 48

157 The San Joaquin Basin is located in Central California to the north of the Los Angeles area. It is about 250 miles long and 50 miles wide and contains more than 30,000 feet of sediment. The southern part of the basin produces mostly oil and associated gas, while the northern part produces non-associated gas. Many wells have been drilled around the flanks of the basin looking for structural accumulations, and most drilling in the basin has been shallower than 15,000 feet. Most of the remaining potential is expected to be in reserve appreciation, including extensions and infill drilling. This basin is the location of one of the largest heavy oil deposits in the U.S. and considerable investment has gone into tertiary oil recovery. Gas production in District 4 which encompasses this basin has declined from about 570 MMcfd to 450 MMcfd since Appalachia and Midwest The Appalachia region includes West Virginia, Virginia, Pennsylvania, New York, Ohio, Tennessee, and Kentucky. The Midwest region includes Michigan and Illinois. Figure 36 summarizes recent historical gas production for the entire region. It shows gas production by vintage, the base production decline, and the initial decline for new wells coming on each year. Average wellhead production in 2005 was 2.3 Bcfd. The Appalachian Basin is the oldest producing area of the U.S. The basin is characterized by tens of thousands of low rate gas wells, with many of these wells producing from Devonian Shale or low permeability sandstones at shallow depths. The Devonian Shale play of eastern Kentucky, West Virginia, and Ohio has been producing for decades, but is in decline. Regional gas production has long been dominated by the state of West Virginia, which produces about 470 MMcfd. The second largest producing state is Pennsylvania, at 418 MMcfd. Although the Devonian Shale gas play is mature in the historic areas, the region has extensive remaining shale, tight gas, and coalbed methane resources. EEA has assessed the shale resource at 17 Tcf, the tight resource at 35 Tcf, and the coalbed resource at 8 Tcf. The remaining tight gas resource is concentrated in eastern Ohio, in the Clinton-Medina regional play. Coalbed methane is being developed in West Virginia and western Virginia, and has potential in Pennsylvania. A major recent development in coalbed methane is the success of the pinnate drilling technique being used by CDX in West Virginia. This technique drills a branching pattern of subsurface boreholes from a single well site. There is remaining potential in conventional gas reservoirs, as evidenced by recent successes with the Trenton-Black River formation gas play. Energy and Environmental Analysis, Inc. Appendices Page 49

158 Figure 36 Appalachia and Midwest Wellhead Gas Production Source: Energy and Environmental Analysis, Inc. processing of Lippman Data The state of Michigan produced about 200 Bcf of gas in This is a mature exploration region that has oil and gas production from a limestone-dominated Paleozoic sequence above 15,000 feet. In the 1980s and 1990s, a shallow shale gas play generated a great deal of interest (Antrim Shale) but efforts to expand the play beyond a small area in northern Michigan were not successful. An older sandstone formation (Prairie du Chien) was also active for a period of time but failed to materialize as a major play. EEA has assessed the Antrim shale play and another shale play (New Albany) at 7.3 Tcf of remaining potential. However, well rates and recoveries are much lower than those of the Fort Worth Basin, and EEA does not anticipate that future shale gas development will have a major impact here. There is also a modest coalbed methane resource in the basin. Energy and Environmental Analysis, Inc. Appendices Page 50

159 Atlantic Offshore The Atlantic Offshore province extends the length of the U.S. from Maine to Florida. No commercial oil or gas production has been established in the province, and the entire region is currently under federal drilling moratoria. The existence of recoverable gas has been established in two areas one off of New Jersey in the 1970s and one offshore North Carolina in the Manteo Unit in the 1990s. The MMS assessment for the undiscovered gas potential of the Atlantic OCS is approximately 33 Tcf. An aspect of the Atlantic offshore that indicates the potential for the area is the success in developing the Nova Scotia shelf area which currently produces over 400 MMcfd of gas. The geology of much of the Atlantic offshore region has similarities to that of offshore Nova Scotia. Mexico Gas Production Mexico produces about 4.8 Bcfd of raw gas and production is predominantly gas associated with oil production. Figure 37 shows annual raw gas production by region. There are three major producing regions an offshore region in the south (Pemex Offshore Region-Gulf of Campeche), a coastal southern region (Pemex South region), and a northern region adjacent to the Gulf of Mexico and Texas (Pemex North Region including Burgos Basin). Each of these regions currently produces about the same amount of gas, although in 2005, production grew in the north region such that it is now the largest producing area. An area which does not yet have production but has excellent potential is the Mexican extension of the U.S. deepwater play in the Gulf of Mexico. Despite a long term focus on oil exploration, Mexico has in recent years made a strong effort to increase gas production, to reduce its dependency on imports. The stateowned oil company, Pemex, is capital constrained because a large percentage of its revenues are used to fund government programs. The national constitution prohibits the types of production sharing contracts that are typically used to attract the international oil companies to upstream investments. About five years ago, Mexico made an effort to attract investment in the Burgos Basin non-associated gas basin adjacent to Texas through a certain type of service contract. Partly as a result of this program, Burgos basin gas production increased substantially, but has been relatively flat since the late 1990s, with the exception of 2005, which saw raw gas production in the basin increase from 1.5 Bcfd to 1.8 Bcfd. Energy and Environmental Analysis, Inc. Appendices Page 51

160 Figure 37 Mexico Raw Gas Production by Region, MMcfd Source: Petróleos Mexicanos (PEMEX) Proven gas reserves in Mexico as of January 2006 are 47 Tcf. This includes the categories of proved, probable, and possible reserves within existing fields. Of the 47 Tcf of total reserves, 15 Tcf is in the proved category. The EEA/NPC resource assessment for Mexico is 93 Tcf of undiscovered gas potential. That assessment is based largely upon USGS assessments. Non-conventional resources have not been assessed. Mexico imports a substantial amount of gas from the U.S. In 2005, average annual gas imports were over 1 Bcfd, while exports were negligible. Total rig activity in Mexico over the past decade has averaged less than 50 rigs on an annual basis. In 2003 and 2004, rig activity increased to greater than 100 active units. A-2.6 General Issues and Uncertainties Affecting Forecast There appears to be little doubt that potential growth of North American gas consumption offers significant opportunity for development of new gas supplies in the foreseeable future. The maturity of the North American gas resource base and the costs of remaining resource suggest that much of the future growth in supply will occur in new supply frontiers that include: Alaska gas Mackenzie Delta gas Continued development of the deeper waters of the Gulf of Mexico Continued development of unconventional gas supplies in the Rocky Mountains and elsewhere LNG imports Energy and Environmental Analysis, Inc. Appendices Page 52

161 Even though there appears to be a growing consensus that new frontier supplies will be necessary for the North American gas market, there is some doubt that the needed supply will be developed. There are many political, environmental, economic, and regulatory challenges facing development of the energy infrastructure necessary to bring new gas supplies into the North American gas market. Overall, the shift of the North American market towards new supplies will create market perturbations that may adversely affect many market participants. Many new sources of supply are geographically far removed from the ultimate markets that they will serve, which presents many challenges. Investment from market participants is more difficult to obtain, especially when participants may not realize direct benefits from a project. Development of new supplies will require significant capital outlays 18. Given the increased opposition to development of energy infrastructure, environmental permits for infrastructure to produce and deliver new supplies may also be difficult to obtain. Generally, there are many factors that will work against development of the North American gas market over time, and the gas industry faces both an opportunity and challenge that is unprecedented in its scope and complexity. Some of these general challenges are discussed in greater detail below. Environmental Permitting Environmental permitting is a potential impediment to development of gas resource and pipeline construction. Clearly, there is a need to balance environmental issues with development of energy infrastructure as North American energy markets continue to evolve. Even though environmental restrictions on development of energy infrastructure may be detrimental to the health of the U.S. economy, they are still likely to occur even when market constraints become evident, as they have in markets throughout North America. The impact of environmental restrictions has become evident in some markets that rely on pipeline capacity for gas supply. For example, California was subject to gas supply shortages in when much of the pipeline infrastructure was stressed to deliver gas to consumers during the power crisis. New York City has shown signs of constraint during periods of time over the past few years. In the past, there has been considerable environmental opposition to pipeline construction in both of these areas. Most recently, slow approval of environmental permits for water disposal has been one of the factors that has reduced gas supply development of Powder River Basin gas in eastern Wyoming. The Wyoming state office has been understaffed and unable to keep up with the water disposal applications, which has led to a slow approval process. Also, 18 A recent National Petroleum Council (NPC) study estimated that the total capital required to develop the North American gas market would be $1.6 trillion (US$) from present through 2015, a 35 percent increase over the capital expended during the 1990s. Specifically, NPC estimated that about $700 billion would be necessary to cover E&P operating expenses, about $780 billion would be required for E&P capital outlays, and over $120 billion would be necessary to develop transmission, storage, and distribution infrastructure to deliver gas to end-users. Given the current environment in the North American gas business where capital is difficult to obtain, acquiring this amount of capital would be extremely difficult. There are signs that the recent capital crunch has abated as many companies in the gas industry have cleaned up their balance sheets and returned to profitability. Even so, these are not trivial amounts of capital that will be easy to obtain, since the gas industry will compete with other industries for capital. Energy and Environmental Analysis, Inc. Appendices Page 53

162 there have been a number of lawsuits attempting to block continued development of Powder River Basin gas. These factors have contributed to the recent leveling off of Powder River Basin gas production Technical Challenges Much of the increase in future gas production is likely to occur in technically difficult environments or formations. Much of the recent E&P activity in the U.S. has focused on development of non-conventional formations, in particular coal bed methane (e.g., Powder River Basin), tight (i.e., very low permeability) gas resource, and shale resource (e.g., Barnett Shale). EEA expects that this trend will persist, which makes continued development of new technologies vital. Indeed, much of the improvement in completion and fracturing technologies over the past decade has permitted economic development of much of the unconventional gas resource that is currently being produced. Continued development of seismic technologies and seismic interpretation will be necessary for development of deeper formations. The gas market is already in need of better seismic technologies, particularly for development of subsalt gas resource located throughout the Gulf of Mexico. Development of better seismic technology is also necessary for development of highly fractured formations, like the San Joaquin Valley gas resource located in central California. To date, development of such resource has proven extremely challenging, if not impossible, because of the depth, pressure, temperature, and geological complexity of the hydrocarbon bearing formations. Continued advancements in drilling and completion techniques will also be necessary to get the most out of unconventional gas-bearing formations. For example, significant improvements in cavity completion technologies have led to the dramatic production increases in coalbed methane production in the San Juan Basin and elsewhere over the last 10 years. Such technologies must be further advanced to make development of currently uneconomic formations possible. In addition, some of the new gas supplies provide unique technical challenges. For example, the size and weight of the Alaskan gas pipeline requires heavy-duty cranes that the permafrost will not support. A fleet of new cranes that distribute weight over a large track area is required. Such technology will require significant time and capital to develop and implement. Equipment and Personnel Given continued focus on development of unconventional gas resource where well productivity is low, the fleet of North American drilling rigs will have to expand to satisfy gas drilling requirements over the next decade. Given the exodus of many qualified industry professionals over the past 20 years, maintaining the E&P business, let alone growth, will be difficult. The North American E&P business has had significant difficulty attracting and maintaining qualified personnel over the past decade. Remoteness and Scope of Development The remoteness of new gas supplies relative to the end-users and the size and complexity of many of the projects to tap the supplies present many challenges. The Energy and Environmental Analysis, Inc. Appendices Page 54

163 capital, time, and materials devoted to the planning and implementation of projects is significant. For example, Alaska producers to date have already spent $100 million to study the development of the Alaska gas resource. Lead times for developing many of the new frontier gas supplies are significant, potentially up to 15 years from initial conception to final development. A-3 North American Gas Transmission To transport natural gas supplies to market, North America has an extensive integrated network of pipelines (Figure 38). The system consists of over 200,000 miles of interstate pipelines in the U.S. and 60,000 miles of interprovincial pipelines in Canada 19. As of 2002, there were 85 interstate pipeline companies in the U.S., the largest 20 of which are listed in Table 8. The U.S. has an additional 100,000 miles of intrastate pipelines plus 20,000 miles of gathering mainlines and 1.1 million miles of distribution mainlines. These pipeline mileage values do not include smaller pipes that connect individual wells and consumers. Figure 38 Major Pipelines in the U.S. and Canada 20 Source: Canadian National Energy Board 19 Sources: U.S. Department of Transportation, Office of Pipeline Safety, Energy Information Administration, and Statistics Canada. 20 The purpose of this map is to illustrate that an extensive and well-connected pipeline network exists throughout North America. The map is not all-inclusive, and a few major pipelines are missing. They include the Tennessee Gas Transmission System and the Columbia Gulf and Columbia Gas Transmission Systems in the eastern U.S., Florida Gas Transmission and Gulfstream from the Gulf Coast to Florida, the Northern Natural, Guardian, and Viking pipeline systems in the central part of the U.S., and the TransColorado, Wyoming Interstate, Colorado Interstate, Paiute, and Tuscarora Pipelines in the Western part of the U.S., among others. Energy and Environmental Analysis, Inc. Appendices Page 55

164 Table 8 Top 20 U.S. Pipelines, Ranked by Contracted Capacity Sources: System capacities and pipeline mileage from U.S. Department of Transportation (DOT), maximum segment capacity from the Energy and Environmental Analysis, Inc. gas model, and tariffs from Electronic Bulletin Boards (EBBs) Maximum System Segment Maximum Principle Capacity Pipeline Capacity Firm Tariff/1 Rank Pipeline Parent Company Market (MMcf/d) Mileage (MMcf/d) $ per Dth 1 Transcontinental Gas PL Co The Williams Companies Inc Northeast 7,362 10,636 4,746 $ Columbia Gas Transmission Corp NiSource Corp Northeast 7,276 11,215 2,156 $ Tennessee Gas Pipeline Co El Paso Corp Northeast 7,271 14,761 2,213 $ ANR Pipeline Co El Paso Corp Midwest 6,667 10,600 2,150 $ Texas Eastern Transmission Corp Duke Energy Inc Northeast 6,438 12,118 2,980 $ Dominion Transmission Co Dominion Resources Inc Northeast 6,275 10,000 1,415 $ Natural Gas Pipeline Co of America Kinder Morgan Corp Midwest 5,001 10,076 1,775 $ El Paso Natural Gas Co El Paso Corp Western 4,882 10,200 3,290 $ Northern Natural Gas Co MidAmerican Energy Holdings Co Midwest 3,904 15,671 2,397 $ Gulf South Pipeline Co Gulf South Pipeline Company LP Southeast 3,782 7, $ Northern Border Pipeline Co Northern Border Partners LP Midwest 3,094 1,248 2,776 $ Northwest Pipeline Corp The Williams Companies Inc Western 2,900 3,932 1,135 $ Great Lakes Gas Transmission Ltd Great Lakes Gas Transmission LP Midwest 2,895 2,115 2,313 $ Transwestern Pipeline Co Enron Corp Western 2,836 2,532 1,490 $ Southern Natural Gas Co El Paso Corp Southeast 2,834 8,200 2,016 $ Texas Gas Transmission Co The Williams Companies Inc Southwest 2,800 5,926 1,880 $ CenterPoint Energy Gas Trans Co CenterPoint Energy Corp Southwest 2,797 6,228 1,000 $ Panhandle Eastern PL Co Southern Union Co Midwest 2,765 6,467 1,573 $ Gas Transmission Northwest Corp TransCanada Corp Western 2,700 1,336 1,140 $ Colorado Interstate Gas Co El Paso Corp Southwest 2,612 4, $ The Maximum Firm Tariff values exclude fuel charges. Most of the natural gas consumed in North America is produced in regions that are significant distances away from consuming markets (Figure 39). The largest supply regions for the United States are the Gulf Coast, both on and offshore, and Western Canada. In 2005, an average of 14.7 Bcfd was transported out of the Gulf Coast area, most of which flowed to markets in the southern U.S., including Florida, and to the East Coast. Flows out of the Gulf Coast area in 2005 were much lower than in recent years due to supply disruptions caused by hurricanes. In 2005, an average of 12.4 Bcfd of natural gas flowed out of Western Canada. Approximately 30 percent was transported to satisfy eastern Canadian consumption, and the remainder was exported to the U.S. Lower-48. Other smaller, but important supply areas include the San Juan Basin in New North America has an extensive and integrated pipeline system that is capable of delivering remote gas supplies to far away markets. Mexico and Colorado, the Northern Rocky Mountain Basins in Utah, Colorado and Wyoming, the Permian Basin in west Texas and eastern New Mexico, and the MidContinent producing area in Northwest Texas, Oklahoma, and Kansas. Well over 11 Bcfd flowed out of these regions to various markets. The flows are made possible by significant amounts of pipeline capacity between regions (Figure 40). Not surprisingly, the largest amounts of pipeline capacity originate in Western Canada and along the Gulf Coast, also the largest supply areas. Takeaway capacity from the Gulf Coast area is over 24 Bcfd, well above the 14.7 Bcfd of flow in The average annual load factor out of the Gulf Coast was only about 60 percent Energy and Environmental Analysis, Inc. Appendices Page 56

165 in This was relatively low compared to other recent years that were unaffected by hurricanes, which averaged closer to 75 percent. However, there is generally over 6 Bcfd of spare takeaway capacity from the Gulf Coast to markets north and east. This spare capacity could be used to move some additional gas supply, most notably LNG imports, to northern and eastern markets 21. Current export capacity out of Western Canada is about 15 Bcfd, not much above the 2005 flow of 12.4 Bcfd out of Western Canada. The average load factor out of Western Canada in 2005 was 83 percent. The spare capacity is not evenly distributed among all the pipeline corridors; over half of it is concentrated on Transcanada Pipeline. TransCanada s spare capacity averaged over 1 Bcfd in Figure 39 Average Flows, 2005 (MMcfd) Source: Energy and Environmental Analysis, Inc Everett Cove Point 375 Elba Island EEA April 2006 Base Case Blue Lines indicate LNG Gray Lines indicate an increase Red Lines indicate a decrease Lake Charles 2013 & Gulf Gateway 1509 Generally, declining production in mature basins can shift regional flow patterns leaving large excess pipeline capacity in some areas. The reverse is true for pipelines out of production areas that are increasing. Generally, the most heavily loaded pipelines are those out of the Rocky Mountain supply basins, which had averaged load factors of 90 percent or greater in Some of this unused capacity is a result of recent declines in Gulf Coast production. However, the remainder of the capacity is only underutilized in the summer, due to seasonal differences in gas consumption. Only the capacity that has recently been unloaded as a result of production declines will be available for incremental LNG imports on a firm basis. Energy and Environmental Analysis, Inc. Appendices Page 57

166 Figure 40 Interregional Pipeline Capacities, 2005 (MMcfd) Source: Energy and Environmental Analysis, Inc. A-3.1 Regulation of Pipeline Companies In the United States, interstate natural gas pipelines, which are pipelines that cross state lines, are regulated by the Federal Energy Regulatory Commission (FERC). The FERC sets rules of operations and approves various rates and tolls for services. In Canada, the National Energy Board (NEB) operates in a similar manner. State commissions regulate intrastate pipelines and the rules vary by state. Local distribution companies (LDCs), the utility retail seller that distributes gas to the ultimate consumer, are also regulated by the state (or the province in Canada). After deregulation of the gas market was completed in 1994, all interstate natural gas pipelines have operated as complete common carriers 22. They do not buy or sell gas (the commodity), nor do they hold title to any of the gas in their pipelines. They can buy some gas for operational purposes, such as for pipeline fuel, but no longer sell gas to 22 The wholesale price of natural gas (the commodity), either at the supply source (wellhead) or at any other intermediate step along the way, was fully deregulated in the U.S. in Deregulation of natural gas prices began in 1978 with the Natural Gas Policy Act (NGPA), induced by natural gas shortages of that time. Full decontrol of natural gas prices was achieved through the Wellhead Decontrol Act of The Wellhead Decontrol Act removed all price caps by However, most of the price caps at that time were moot since they far exceeded actual market rates. Energy and Environmental Analysis, Inc. Appendices Page 58

167 consumers or LDCs. Affiliates of pipeline companies can purchase pipeline transportation, but there are strict rules concerning communication and favoritism with the sister pipeline company. The buyers and sellers of gas typically purchase regulated transportation services from natural gas pipelines. Depending on the customer class and type of service, different rates are charged, although the variation between rates can be small or nonexistent. Rates also vary depending on whether the service is firm or interruptible. Firm service includes certain guarantees of delivery. Firm customers have specified rights for pipeline capacity. Interruptible customers do not have guarantees for delivery. Gas is delivered on a best efforts basis only when excess pipeline capacity is available. It s important to note that firm capacity owners cannot withhold the pipeline capacity they own. It s a use it or lose it policy. If a firm customer does not use their contracted capacity, the pipeline must offer that capacity to interruptible customers. Pipeline transportation rates, the price charged for moving third-party gas, have regulated maximums and minimums. Maximum pipeline transportation rates per unit are cost-based, based on the acquisition costs of capital, anticipated operating costs, and anticipated pipeline throughput. Minimum pipeline transportation rates are based on average variable costs. This minimum charge is in effect to insure that one customer is not subsidizing another. Maximum rates also include an approved return on equity. The pipeline may offer discounted pipeline transportation, as long as the rate is above the minimum and as long as it is done in a nondiscriminatory manner. Discounts are usually only offered to meet competition. Rates can be designed in two ways: a fixed demand charge, or a variable commodity charge. Demand charges are based on the maximum quantity of gas the customer can request per day. Commodity charges vary depending on the actual quantity of gas delivered. Demand charges are paid, usually monthly, whether the pipeline capacity is used or not. Demand charges, once the capacity is sold, are a source of guaranteed revenue and cost recovery for the pipeline. Commodity charges may recover more or less costs depending on the difference between actual and anticipated throughput in the pipeline. In practice, firm transportation capacity rates are a combination of both demand and commodity charges, while interruptible rates consist of commodity charges only. Due to FERC s straight-fixed-variable rate design requirement, firm pipeline demand charges are set so that the demand portion, which is the portion that the customer must pay, covers all of the fixed costs plus returns to equity, while the commodity portion covers only variable costs. Because the pipeline industry is very capital intensive, fixed costs typically are in excess of 95 percent of the total cost of transportation. Canadian pipelines also have a similar high demand portion and low commodity portion rate structure. Although there are some exceptions, interruptible commodity rates are usually set at the equivalent 100% load factor rate of the comparable firm service. A firm shipper that fully utilized his contract would pay the same amount as an interruptible shipper moving the same volume of gas. This is not necessarily the case in Canada, where interruptible rates on Transcanada are set at 110 percent of the per unit firm rates. Energy and Environmental Analysis, Inc. Appendices Page 59

168 Fuel charges on interstate and interprovincial pipelines are paid in-kind (i.e., fuel gas is provided by the shipper). In addition, some gas is taken for lost and unaccounted for gas. Fuel charges are usually not levied for backhaul or displacement transportation. Fuel charges can be the same for the entire pipeline system, a postage rate design, or be based on mileage or zones. Fuel designs vary by pipeline. A-3.2 North American Gas Storage North American natural gas storage plays a key role in balancing supply and demand. It is an essential part of the North American gas market, and is relied on to meet gas consumption during peak periods. Storage can reduce the need for both swing natural gas production deliverability and pipeline capacity by allowing production and/or pipeline throughput to remain relatively constant. Customers may use storage to reduce pipeline demand charges, to hedge against natural gas price increases, or to arbitrage temporal gas price differences. Pipelines and LDC s use storage for operational flexibility and reliability, providing an outlet for unconsumed gas supplies or a source of gas to meet unexpected gas demand. Storage at market trading hubs often provides balancing, parking, and loan services. gas storage is relied on to meet gas consumption during peak periods. Storage can reduce the need for both swing natural gas production deliverability and pipeline capacity by allowing production and/or pipeline throughput to remain relatively constant. According to the U.S. Energy Information Administration and the Canadian Gas Association, working gas capacity for underground storage in North America is approximately 4.6 Tcf, with 4.0 Tcf in the United States and 0.6 Tcf in Canada. However, as shown in Figure 41, we are currently (September 2006) at the maximum North American storage fill achieved at just under 4.0 Tcf. The reason that the observed fill is less than reported capacity is probably due to various operational constraints, and/or constraints on accessing pipelines, markets, or supplies. Therefore, the storage fills of just over 4.0 Tcf probably more closely reflects the practical maximum limit. Energy and Environmental Analysis, Inc. Appendices Page 60

169 Figure 41 North American Working Gas Levels, January 2000 through December 2005 (Bcf) Sources: U.S. Energy Information Administration and Canadian Gas Association Working Gas Fill in Bcf Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 The lowest observed level for North American working gas occurred in March 2003 at just under 0.8 Tcf. It is unlikely that North American working gas storage could fall to much lower levels because of constraints that become evident when storage levels and reservoir pressures fall below certain limits. Considering both the observed minimum and maximum levels over the past few years, the practical North American working gas capacity is probably about 4.0 Tcf less 0.8 Tcf, or only about 3.2 Tcf. This equates to an average 7-month injection season rate of 14.9 Bcfd and a 5-month withdrawal season rate of 21.3 Bcfd. However, withdrawals are typically concentrated in December through February, and daily withdrawals in January have recently averaged as high as 31.0 Bcfd in 2003 and 2004, well above the practical 5-month limit. There are three main types of underground storage: depleted reservoir, aquifer, and salt cavern storage. About 83 percent of working gas storage capacity and 63 percent of deliverability in the United States is in depleted natural gas or oil fields (Table 9). Likewise, most Canadian storage fields (not included in the table) are also depleted reservoirs. Depleted reservoirs are the most commonly used underground storage sites because of their wide availability. Conversion of a field from production to storage takes advantage of existing wells, gathering systems, and pipeline connections. Energy and Environmental Analysis, Inc. Appendices Page 61

170 Table 9 Summary of U.S. Gas Storage, 2000 Source: Energy Information Administration Aquifer Storage Depleted Gas/Oil Fields Salt Cavern Storage LNG Peak Shaving Total EIA Storage Regions Sites Woking Gas Capacity (Bcf) Max Deliv (MMcfd) Sites Woking Gas Capacity (Bcf) Max Deliv (MMcfd) Sites Woking Gas Capacity (Bcf) Max Deliv (MMcfd) Sites Woking Gas Capacity (Bcf) Max Deliv (MMcfd) Sites Woking Gas Capacity (Bcf) Max Deliv (MMcfd) Consuming East , ,658 33, , ,098 52,142 Consuming West , , , ,781 Producing , , ,163 31,486 Total , ,211 59, , , ,877 94,409 10% 10% 10% 63% 83% 63% 6% 4% 15% 20% 2% 12% 100% 100% 100% In some areas, most notably in Illinois and Indiana, natural aquifers have been converted to gas storage reservoirs. In the U.S., aquifer storage accounts for 10 percent of the working gas capacity and 10 percent of the deliverability. An aquifer is suitable for gas storage if the water-bearing sedimentary rock formation is overlaid with an impermeable cap rock. While similar to depleted production fields, aquifer use in gas storage usually requires more base gas and greater monitoring of withdrawal and injection performance. Operational flexibility is less than it is in other types of storage. Salt caverns provide very high withdrawal and injection rates relative to their working gas capacity. Base gas requirements are relatively low. In the U.S., salt cavern storage accounts for only 4 percent of the working gas capacity but 15 percent of the deliverability. The large majority of salt cavern storage facilities have been developed along the Gulf Coast, because that is the most favorable area geologically. Salt cavern construction has historically been more costly than depleted field conversion, when measured on the basis of dollars per thousand cubic feet of working gas capacity 23. However, the ability to perform several withdrawal and injection cycles each year reduces the per-unit cost of each cubic foot of gas injected and withdrawn. In the U.S., salt cavern storage typically averages more than 2 cycles per year. Other types of storage typically average less than 1 cycle per year. Currently, there are plans for over 40 new storage facilities in the U.S. and Canada, which would add up to 349 Bcf of working gas capacity (Table 10). As with the existing facilities, a large number of the planned facilities are at depleted fields. However, the majority of the planned facilities are in salt cavers, reflecting the increased interest in building high deliverability storage in response to price volatility and other relevant market factors. Another type of storage is LNG peak shaving. LNG peak shaving facilities are above ground facilities not reliant on geology, and can therefore be located anywhere. LNG peak shaving facilities typically operate for only a few days before the site capacity is exhausted. In the U.S., nearly 90 percent of the LNG peak shaving deliverability is located along the East Coast. 23 This was certainly the case in the 1990s when gas prices were low. However, after the turn of the century when gas prices increased, the cost of base gas has increased significantly, increasing the costs of other types of underground storage relative to high deliverability storage that requires less base gas. Thus, there has been a greater focus on construction of high deliverability storage during the past few years. Energy and Environmental Analysis, Inc. Appendices Page 62

171 Table 10 Planned New Storage Capacity Source: Energy Information Administration Working Gas Capapcity (MMcf) Maximum Deliverability (MMcfd) Field Name Operator Name State County Field Type Start Date East Detroit Freebird Gas Storage Alabama Lamar Depleted Reservoir 6, Apr 2007 McIntosh Bay Gas Storage Company Ltd. Alabama Washington Salt Dome 5, Apr 2007 MoBay Falcon Gas Storage Company Alabama Mobile Depleted Reservoir 20, Jun 2007 Edson TransCanada Alberta Edson Depleted Reservoir 50, Apr 2006 Copper Eagle Copper Eagle Gas Storage LLC Arizona Maricopa Bedded Salt 9, Jan 2007 Desert Crossing Desert Crossing Gas Storage Arizona Mohave Salt Dome 10, n/a Totem Totem Gas Storage Colorado Arapahoe Depleted Reservoir 9, n/a Windy Hill Phase 1 Chevron Colorado Morgan Salt Dome 3, Apr 2008 Windy Hill Phase 2 Chevron Colorado Morgan Salt Dome 3, Apr 2010 Midland - Expansion Texas Gas Transmission Kentucky Muhlenberg Depleted Reservoir 9, Nov 2007 Egan Market Hub Partners, LP. Louisiana Acadia Salt Dome 8,000 1,200 Jun 2006 Hackberry Storage Dominion Transmission Louisiana Cameron Salt Dome 8, Jun 2007 Liberty Gas Storage HNG Storage Co. Louisiana Calcasieu Salt Dome 17,600 1,100 Apr 2007 Magnolia Gas Storage Gulf South Louisiana Assumption Salt Dome 4, n/a Pine Praire Energy Center SG Resources Louisiana LLC Louisiana Evangeline Salt Dome 24,000 2,400 Apr 2006 Port Barre Bobcat Gas Storage Louisiana St. Landry Salt Dome 12,000 1,200 Apr 2008 Starks Gas Storage No. 1 EnCana Storage Louisiana Calcasieu Salt Dome 8, Apr 2006 Starks Gas Storage No.2 EnCana Storage Louisiana Calcasieu Salt Dome 10, Jun 2008 Washington 10 DTE Energy Michigan Macomb Depleted Reservoir 14, Apr 2006 Caledonia Caledonia Energy Partners Mississippi Lowndes, Monroe Depleted Reservoir 11, Apr 2006 Copiah (fomerly MS-1) Market Hub Partners, LP. Mississippi Copiah Salt Dome 3, n/a Four Mile Creek Jetta Gas Storage Mississippi Monroe Depleted Reservoir n/a 200 n/a Jackson Gulf South Mississippi Rankin Depleted Reservoir 1, Apr 2006 Petal Salt Dome Petal Gas Storage Mississippi Forrest Salt Dome 5, Apr 2008 Richton NUI Energy Partners Mississippi Perry Salt Dome n/a 600 n/a Southern Pines Energy Center SG Resources Mississippi LLC Mississippi Greene Salt Dome 12,000 1,200 Apr 2007 Grama Ridge Enstor (Scottish Power) New Mexico Lea Depleted Reservoir 1, Apr 2007 Cohocton Valley (New Avoca) SemGas New York Steuben Bedded Salt 5, Apr 2007 Quinlan Reef Dominion Transmission New York Carraraugus Depleted Reservoir 4, Apr 2008 Stagecoach Central New York Oil and Gas LLC (ecorp.) New York Tioga Depleted Reservoir 13, Apr 2008 Thomas Corner Steuben Gas Storage Co. New York Steuben Depleted Reservoir 5, Apr 2008 Wyckoff Wyckoff Gas Storage Co. LLC New York Steuben Depleted Reservoir 6, Apr 2007 Lac St. Pierre Altai Resources Quebec Lac St. Pierre Depleted Reservoir n/a 50 n/a Asquith TransGas Ltd. Saskatchewan Saskatoon Bedded Salt 2, Apr 2006 Hill-Lake Falcon Gas Storage Company Texas Eastland Depleted Reservoir 3, Apr 2006 Keystone Gas Storage Unocal Keystone Gas Storage Texas Winkler Salt Dome 2, Apr 2006 Worsham-Steed Falcon Gas Storage Company Texas Jack Depleted Reservoir 12, Apr 2006 Waha Enstor (Scottish Power) Texas Pecos Salt Dome 9, Apr 2008 Saltville Saltville Gas Storage Co. Virginia Smyth Bedded Salt 1, Apr 2007 Jackson Prairie 2, 9 Puget Sound Energy Washington Lewis Aquifer 1, Apr 2007 Hardy Columbia Gas Transmission West Virginia Hardy, Hampshire Depleted Reservoir 12, Apr 2007 Southwest Wyoming Questar Wyoming Uinta Bedded Salt 5, n/a Rock Springs Questar Wyoming Sweetwater Depleted Reservoir n/a n/a n/a Totals (excluding n/a): 349,000 19,081 In the U.S., approximately 60 percent of the underground storage capacity is operated by natural gas pipelines, 33 percent is operated by LDCs, and 7 percent is operated by independent operators. Much of the pipeline storage is contracted to LDCs. Hence, LDCs own or have under contract approximately two-thirds of current working gas capacity. For LDCs, storage is used to meet weather-sensitive load and for operational flexibility and reliability. LDC s are relatively insensitive to seasonal price differences and are more likely to fill storage before a heating season regardless of the difference between injection and withdrawal season gas prices. Over the past five years, LDC owned and operated storage sites have been filled to levels at 85 to 90 percent of capacity, versus 70 to 85 percent fill for non-ldc owned and operated storage. Storage tariffs rates vary by operator, as does the structure of the tariff charges. Generally, storage tariffs are broken down by component services, such as reservation rates and injection/withdrawal fees. Only tariffs for regulated entities, such as the storage held by the regulated divisions of interstate pipeline companies as shown in Table 11, are published. Costs for merchant storage operations are generally not publicly available. The actual cost of using storage is highly dependant on how the storage is utilized, that is, the rate at which gas is injected and withdrawn, and how long the gas is held in storage. Energy and Environmental Analysis, Inc. Appendices Page 63

172 Table 11 Tariffs for Major Storage Operators Source: Energy and Environmental Analysis, Inc. compilation of tariffs filed with FERC Regulated Company Charges Regulated Company Charges ANR Pipeline Reservation Rate: Deliverability- Monthly $2.04 per Dth Saltville Gas Storage Co. Space Reservation Charge: $1.265 per Dth Reservation Rate: Capacity - Monthly $0.4 per Dth Injection Reservation Charge: $2.534 per Dth Injection/Withdrawl Commodity Rate $ per Dth Withdrawal Reservation Charge: $1.267 per Dth ANR Storage Reservation Rate: Deliverability- Monthly $ per Dth Usage Charge - Storage Injection $0.079 per Dth Reservation Rate: Capacity - Monthly $ per Dth Usage Charge - Storage Withdrawal $0.079 per Dth Injection/Withdrawl Commodity Rate $ per Dth Southern California Gas Co. Reservation Charge Annual Frim Inventory: $0.214 per Dth Blue Lake Gas Storage Reservation Rate: Deliverability- Monthly $ per Dth Reservation Charge Monthly Firm Injection: $ per Dth per day Reservation Rate: Capacity - Monthly $ per Dth Reservation Charge Annual Firm Withdrawal: $ per Dth per day Injection/Withdrawl Commodity Rate $ per Dth O&M Injection Charge Retail/Wholesale: $0.127 per therm CenterPoint Energy Gas Transmission Deliverability Fee: $ per Dth O&M Withdrawal Charge Retail/Wholesale: $0.127 per therm Capacity Fee: $.0229 per Dth Southern Natural Gas Deliverability Charge: $1.572 per Dth Storage Fee: $.0154 per Dth Capacity Charge: $ per Dth CenterPoint Energy - Deliverability Charge: $ per Dth Injection Charge: $0.007 per Dth Mississippi River Transmission Capacity Charge: $ per Dth Withdrawal Charge: $0.007 per Dth Injection Charges: $ per Dth Southern Star Deliverabilty Reservation: $0.218 per Dth Withdrawal Charges: $ per Dth Central Pipeline Capacity Reservation: $.0010 per Dth Colorado Interstate Gas Storage Capacity Rate (Monthly Rate): $ per Dth Injection: $0.077 per Dth Reservation Rate (Monthly Rate): $ per Dth Withdrawal: $0.077 per Dth Hourly Rates of Flow Option (Monthly Rate): $ per Dth Southwest Gas Storage Co. Deliverability Charge: $ per Dth Quantity Injection Rate: $ per Dth Capacity Charge: $ per Dth Quantity Withdrawal Rate: $ per Dth Injection Charge: $ per Dth Columbia Gas Transmission Reservation Charge: $1.500 per Dth Withdrawal Charge: $ per Dth Capacity Charge: $ per Dth Steuben Gas Storage Co. Reservation Rate - Deliverability- Monthly: $4.638 per Dth Injection Charge: $ per Dth Reservation Rate - Capacity- Monthly: $ per Dth Withdrawal Charge: $ per Dth Injection/Withdrawal Commodity Rate: $.0032 per Dth Dominion Transmission Reservation Charge $2.232 per DT Tennessee Gas Pipeline Production Area - Deliverability Rate: $2.02 per Dth Usage Charge $0.000 per DT Production Area - Space Rate: $ per Dth DTE Energy Deliverability Rate Per Month: $ per Dth Production Area - Injection Rate: $.0053 per Dth Capacity Rate Per Month: $ per Dth Production Area - Withdrawal Rate: $.0053 per Dth Injection Rate: $ per Dth Market Area - Deliverability Rate: $2.02 per Dth Withdrawal Rate: $ per Dth Market Area - Space Rate: $ per Dth El Paso Natural Gas Storage Inventory Rate: $ per Dth Market Area - Injection Rate: $.0053 per Dth Quanity Injection Rate: $ per Dth Market Area - Withdrawal Rate: $.0053 per Dth Quanity Withdrawal Rate: $ per Dth Texas Eastern Transmission Reservation Charge: $ per Dth Equitrans Demand Charge: $ per Dth Space Charge: $ per Dth Storage Space Charge: $ per Dth Injection Charge: $ per Dth Injection Charge: $ per Dth Withdrawal Charge: $ per Dth Withdrawal Charge: $ per Dth Texas Gas Transmission Reservation Rate - Daily Deliverability: $ per Dth Gulf South Prices Negotiated Reservation Rate - Seasonal Capacity: $.0010 per Dth Kinder Morgan Interstate Gas Deliverability: $ per Dth Injection/Withdrawal Commodity Rate: $.0270 per Dth Transmission Co. Capacity: $ per Dth TransCanada To Centra Gas (Manitoba) Demand Toll: $ per GJ/mo Commodity Injection Rate: $ per Dth To Centra Gas (Manitoba) Commodity Toll: $ per GJ/mo Commodity Withdrawl Rate: $ per Dth To Kingston Demand Toll: $ per GJ/mo National Fuel Gas Demand: $ per Dth To Kingston Commodity Toll: $ per GJ/mo Capacity: $ per Dth To Gaz Metropolitain - EDA Demand Toll: $ per GJ/mo Injection/Withdrawal: $ per Dth To Gaz Metropolitain - EDA Commodity Toll: $ per GJ/mo Natural Gas Pipeline Co. Deliverability Charge (MDQ): $ per Dth TransGas Ltd. Contracted Capaccity Charge $ per GJ per Month Capacity Charge (MAC): $ per Dth Summer Use Firm $ per GJ per Month Injection Charge: $ per Dth Contracted Witthdrawal Charge $ pe GJ per Month Withdrawal Charge: $ per Dth Transcontinental Demand Charge: $ per DT Northern Natural Gas Maximum Reservation Fee: $ per Dth Gas Pipe Line Storage Quantity Capacity Charge: $ pe DT Maximum Capacity Fee: $ per Dth Quantity Injection Charge: $.0270 Injection Charge - Firm: $ per Dth Quantity Withdrawal Charge: $.0270 Withdrawal Charge - Firm: $ per Dth Trunkline Gas Pipeline Capacity Reservation Rate: $ per DT Annual Rollover Fee: per Dth Deliverability Reservation Rate: $ per DT Northwest Natural Gas Demand Charge: $ per Dth Injection Rate: $ per DT Capacity Demand Charge: $ per Dth Withdrawal Rate: $ per DT Volumetric Bid Rate Withdrawal Charge $ per Dth Union Gas Limited Combined Space and Deliverability: $0.022 per GJ/mo Storage Charge $ per Dth Injection Coommodity: $0.013 per GJ/mo Questar Monthly Reservation Charge: $ per Dth Withdrawal Coommodity: $0.013 per GJ/mo Injection Usage Charge: $ Williston Basin Capacity Reservation: $2.102 per DKT per MO. Withdrawl Usage Charge: $ Capacity Deliverability: $ per DKT per MO. Monthly Reservation Charge Deliverability: $ per Dth Injection: $0.888 per DKT Monthly Reservation Charge Capacity: $ per Dth Withdrawal: $0.888 per DKT Usage Charge Injection: $ per Dth Usage Charge Withdrawal: $ per Dth The cost of developing new storage capacity varies between locations and the type of storage. It is least expensive to provide working gas capacity in a depleted reservoir on a per unit basis while it is least expensive to provide deliverability in salt cavern storage on a per unit basis. Expansions of storage fields often enhance injection and withdrawal capabilities, without necessitating proportional increases in working gas capacity. Therefore, costs as measured per Mcf of working gas capacity are often higher than they are in new construction. Conversely, costs as measured per Mcf of deliverability are often lower than they are in new construction. The cost of developing new storage has risen recently due to increasing gas prices that equate to higher costs for base gas. This base gas cost increase affects depleted reservoir and aquifer storage more than salt cavern and LNG peak shaving storage. For example, base gas for the Young Storage Field built in the mid-to-late 1990s in Energy and Environmental Analysis, Inc. Appendices Page 64

173 Colorado cost $8.8 million, which accounted for 20 percent of the total construction cost of the field. At the time it was built, the average price for the base gas in the field was $1.86 per Mcf. At a price of $7.00 per Mcf, the cost of base gas would have risen to $32.9 million, accounting for about 50 percent of the total construction costs of the field. A-3.3 North American Natural Gas Prices Natural gas prices in North America have undergone a dramatic shift since the 1990s. Prior to the 1980s, natural gas commodity prices were regulated from wellhead to burner-tip, at least in the interstate market. Commodity prices were stable and were determined largely in pipeline cost of service rate proceedings. Shortages of natural gas were dealt with through priority rationing, and not with price increases. Due to declining natural gas reserves and a perceived shortage of natural gas, natural gas prices began to be deregulated in 1978, with the intended purpose being to stimulate production. Deregulation continued throughout the 1980s and into the early 1990s. Natural gas commodity prices were completely deregulated in As discussed earlier, transmission and distribution has been and is still regulated on a cost of service basis. The oil price shocks of the late 1970s and partial deregulation and the ability of pipelines to average into or roll in high priced gas with low priced reserves produced an economic incentive to overdrill for gas in unregulated or high price categories. The robust levels of drilling activity that resulted, and the declining industrial gas use in the 1980s resulted in the creation of excess natural gas productive capacity in the mid-tolate 1980s. The excess productive capacity or gas bubble, as it was commonly called, created a low and stable price environment for natural gas. The U.S. natural gas market balanced by shutting in gas production when prices were too low to justify production. The gas bubble persisted into the late 1990s, well after deregulation of the gas market was completed in In the post-1993 deregulated environment, productive capacity for natural gas has remained flat or declined, while, at the same time, natural gas demand has increased. With these divergent trends, the natural gas bubble that had existed for about 15 years finally disappeared at the end of the 1990s. The relative price stability that had existed with the gas bubble has disappeared. The U.S. natural gas market, as it exists today, operates at or nearly at 100 percent of productive capacity. The market can no longer balance by swinging supplies as it did throughout much of the 1980s when it was still partially regulated and even into the 1990s when deregulation was completed. The market now must balance by price-induced consumption decisions on the demand-side. This creates a relatively high priced and volatile market (Figure 42). The North American gas market, in its current condition, must balance by price-induced consumption decisions on the demand-side, which creates a relatively high priced ($5+ per MMBtu) and volatile market. Energy and Environmental Analysis, Inc. Appendices Page 65

174 Figure 42 Daily Gas Prices for Select Locations, January 1999 to September 2006 Source: Platts Gas Daily $20 $18 Increased Volatility and Prices $'s per MMBtu $16 $14 $12 $10 $8 $6 $4 $2 $0 Relative Price Stability Jan-99 Jul-99 Jan-00 Jul-00 Jan-01 Jul-01 Jan-02 Jul-02 Jan-03 Jul-03 Jan-04 Jul-04 Jan-05 Jul-05 Jan-06 Jul-06 Socal Chicago New York City Opal AECO Henry Hub A Seasonal Gas Prices North American natural gas prices exhibit seasonal variance (Figure 43). On average, peak winter prices (i.e., December through January) have been about 10 percent higher than the annual average price. Prices in the early part of the injection season (i.e., March through June) and the pre-winter months of October and November have roughly equaled the annual average price. Lower natural gas prices have tended to occur later in the injection season in July through September. Winter prices tend to be more volatile than summer prices (i.e., statistically, they exhibit higher variance), when storage levels, if relatively low, can send natural gas prices significantly higher. Energy and Environmental Analysis, Inc. Appendices Page 66

175 Figure 43 Henry Hub Seasonal Price Variations, Monthly Price Relative to 12-Month Rolling Average, 1995 to 2005 Source: Energy and Environmental Analysis, Inc. 200% Price Percentages Relative to 12-Month Moving Average 180% 160% 140% 120% 100% 80% 60% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Standard Deviation Average Maximum Minimum A North America A Highly Integrated Gas Market As discussed earlier, the North American natural gas pipeline grid is extensively spread throughout the U.S. Lower-48 states and the southern portions of Canada. Open access pipeline rules allow natural gas to freely flow to where it is needed. High price differentials between locations are not likely to Prices at many pricing points throughout North America are highly correlated indicating a well integrated market. persist when there is available pipeline capacity. Therefore, natural gas prices tend to rise and fall in tandem throughout the market (Figure 42). Pipeline bottlenecks can and do cause certain areas to disconnect from the rest of the larger North American market. This type of behavior was exhibited in New York during three out of the past four winters and in California during the energy crisis of 2000 and However, these disconnects are usually only temporary. Reconnection with the rest of the market occurs with the return of spare pipeline capacity in and out of the region in question. Energy and Environmental Analysis, Inc. Appendices Page 67

176 A Basis Regional Gas Price Difference 24 Pipeline rates or tolls do not determine basis or the price differential between markets. Instead, basis is determined by the opportunity costs to move gas between market centers. When there is significant excess pipeline capacity between markets, such as between Henry Hub and Chicago, basis differentials can be quite low. (Table 12, Figure 44) approaching variable costs. The largest component of variable cost is fuel. Due to the U.S. pipeline rate structures, the commodity portion of firm rates are more often than not a few cents per MMBtu even for the longest hauls. Conversely, in a market where there is sometimes a deficient amount of pipeline capacity, such as into New York City, regional basis will represent the true opportunity cost between markets (Table 12, Figure 45), or the potential value that new pipeline capacity could capture if built into the market. Even price cap restrictions on transportation in the primary and secondary capacity markets don t prevent the basis into the market from rising to levels that exceed tariff maximums, reflecting the true opportunity cost of supplying additional gas to the constrained market. Table 12 Annual Basis from Henry Hub, $/MMBtu Source: Platts Gas Daily Henry Hub Basis From Henry Hub to New York City So. Cal Chicago AECO Opal YTD The term basis, as used in this report, refers to locational price differences. Energy and Environmental Analysis, Inc. Appendices Page 68

177 Figure 44 Henry Hub to Chicago Basis versus Cost of Firm Transportation, January 1998 to December 2005 Source: Platts Gas Daily (basis) and pipeline bulletin boards (currently effective rates) $2.00 $1.50 $1.00 Henry Hub to Chicago NGPL $0.48 per MMBtu plus 3.26% Fuel Basis in $/MMbtu $0.50 $0.00 -$0.50 -$1.00 -$1.50 -$2.00 Jan-01 Apr-01 Jul-01 Oct-01 Jan-02 Apr-02 Jul-02 Oct-02 Jan-03 Apr-03 Jul-03 Oct-03 Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Oct-05 Figure 45 Henry Hub to New York City Basis Versus Cost of Firm Transportation, January 1998 to December 2005 Source: Platts Gas Daily (basis) and pipeline bulletin boards (currently effective rates) $2.00 $1.80 $1.60 Basis in $/MMbtu $1.40 $1.20 $1.00 $0.80 Henry Hub to NYC Transco $0.42 per MMBtu plus 3.96% Fuel $0.60 $0.40 $0.20 $0.00 Jan-01 Apr-01 Jul-01 Oct-01 Jan-02 Apr-02 Jul-02 Oct-02 Jan-03 Apr-03 Jul-03 Oct-03 Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Oct-05 Energy and Environmental Analysis, Inc. Appendices Page 69

178 (Page Deliberately Left Blank) Energy and Environmental Analysis, Inc. Appendices Page 70

179 APPENDIX B: NORTH AMERICA NATURAL GAS MARKET PROJECTIONS This section describes the assumptions and results for the EEA Base Case. The EEA Base Case is an independent projection of the North American natural gas market through EEA is widely known as a leader in North American energy market analysis. All projections discussed here have been produced by using the EEA Gas Market Data and Forecasting System, a widely used model for the North American natural gas market (see Appendix C for more details). EEA has been using its Gas Market Data and Forecasting System (GMDFS) to provide clients with analysis and forecasts of regional gas markets throughout North America for many years. The structure of EEA s GMDFS, which solves for monthly natural gas production and demand, storage injections and withdrawals, pipeline flows, and natural gas prices in well over 100 regional market locations, is ideal for studying the supply and demand dynamics that will drive the entire North American market, and also ideal for studying regional developments given the broader trends driving the entire market. To fully understand the supply and demand dynamics most relevant to Manitoba consumers, we feel that it is absolutely essential to study the regional market in the context of the entire North American gas grid, which our gas modeling system does. The section begins with discussing key assumptions. Projected natural gas consumption levels for both North America in general and Alberta, Saskatchewan, and Manitoba in particular are discussed, followed by a projection of regional gas prices and basis. The section ends with a discussion of storage potential and factors that determine natural gas demand. B-1 EEA Base Case Assumptions Key assumptions in the EEA Base Case are summarized in Table 13. The EEA Base Case is a continuation of current conditions in the North American natural gas market well into the future. Most notably, the supply/demand balance for natural gas continues to remain tight, and natural gas prices remain relatively high over time, well above price levels in the 1990s. U.S. Gross Domestic Product (GDP) is assumed to grow at 2.8 percent per year, lower than growth rates observed in the 1990s, but similar to 30-year averages. The Canadian economic growth rate is slightly lower at 2.5 percent per year, which is also similar to long-term averages. Long-term crude oil prices moderate to $45.00 per Energy and Environmental Analysis, Inc. Appendices Page 71

180 Table 13 EEA Base Case Key Assumptions - U.S. and Canada U.S. GDP +2.8 % per year all regions. U.S. industrial production +2.3 % per year. Canadian GDP +2.5 % per year. Long-term RACC price is $45 per barrel (Real 2005$). Electricity use grows at 1.7 % per year. Fossil fuel generation capacity U.S : Gas capacity grows by 148 GW (Net 72 GWs with retirements). Coal plant capacity grows by a net of 115 GW. Other generation: No new hydro generation capacity. Nuclear power capacity increases 5 GWs by 2025 through efficiency gains and capacity enhancement at existing plants. Renewable generation increases by 45 GWs. North American gas production (See Section A-2.2 above): 272 Tcf of reserves. 1,742 Tcf of remaining resource. U.S. and Canada have about 400 Bcf that is economic to develop at $5 per MMBtu or less, assuming current E & P technologies. Arctic gas supply projects: 1 Bcfd of Mackenzie Delta gas begins flowing in November Bcfd Alaska gas delivered to Canada and U.S. Lower-48 beginning in November North American LNG import terminals (See Figure 46): 14.0 Bcfd of LNG regasification capacity by Bcfd of LNG regasification capacity by Bcfd of LNG regasification capacity by Pipeline and storage constructed as justified. Pipelines (See Figure 47). Storage +502 Bcf working gas capacity U.S. and Canada barrel 25, but remain high by historical standards. The relatively high oil prices tend to discourage significant gas-to-oil switching above current levels. In addition, it is assumed that gas-to-oil switching will continue to be limited by oil infrastructure The oil price input to EEA s model is the U.S. average refiners acquisition cost of crude (RACC), which generally is 10% below West Texas Intermediate (WTI), consistent with historical averages. Prices are in Real U.S dollars. 26 A substantial amount of infrastructure, including refining, handling equipment, oil tanks, barges, and pipelines would be necessary to permit significant levels of oil burn in the power and industrial sectors. Energy and Environmental Analysis, Inc. Appendices Page 72

181 Along with the growing economy, total U.S. electricity sales grow at 1.7 percent per year. Fossil fuel generation capacity, including new natural gas-based combined cycle and combustion turbines, grow to meet additional electricity consumption. From 2005 to 2025, approximately 148 GWs of new gas-based generation capacity is built in the U.S. With retirement of 76 GWs of older oil-gas steam units, the net increase in gas capacity is 72 GWs from Coal capacity increases by 115 GWs over the same time period. Canadian electricity sales and generation are not explicitly calculated within the GMDFS model framework. Official Canadian natural gas consumption statistics from which the model was and is calibrated have historically combined the industrial and power sectors. Therefore generation and electricity sales projections are for the U.S. Lower- 48 only. Hydro generation capacity is assumed to remain at current levels. Generation from hydro sources assumes normal weather conditions, similar to 10-year averages. No new nuclear power plants are assumed to be built before However, efficiency enhancements and capacity creep at existing plants increases nuclear capacity by 5 GWs. U.S. renewable generation capacity increases by 45 GWs. The EEA Base Case is a continuation of current conditions in the North American natural gas market well into the future. Most notably, the supply/demand balance for natural gas continues to remain tight, and natural gas prices remain relatively high over time, well above price levels in the 1990s. With regards to gas supply, traditional North American gas supplies struggle to keep pace with growing gas demand, prompting an increased reliance on new frontier supplies. The U.S. and Canada are not in danger of running out of supplies anytime soon with well over 200 Tcf of gas reserves and about 400 Tcf of gas resource that is economic to develop at $5 per MMBtu or less, assuming current E & P Technologies. However, as exhibited by recent market conditions, these supplies are insufficient to permit market growth. The EEA Base Case assumes that planned Arctic projects are built within the next decade. Mackenzie Delta gas begins flowing in November 2011 at 1 Bcfd, and the Alaska Gas Pipeline project is built by the end of 2015 with a capacity of 4 Bcfd. North America currently has 5 operating LNG import terminals, all in the U.S.: Everett, Cove Point, Elba Island, Lake Charles, and Gulf Gateway. Total maximum regasification capacity is approximately 4.2 Bcfd. The EEA Base Case assumes that North American LNG import capacity grows significantly by 2025 with 15 new terminals and expansions at Cove Point, Elba Island, and Lake Charles (Figure 46). North American regasification capacity reaches 15.7 Bcfd in 2010, 27.2 Bcfd in 2015, and 33.4 Bcfd in Most new terminals and capacity are along the Gulf and East Coasts. Two terminals are projected for Canada and four for Mexico. Obtaining the necessary environmental approvals and permits to burn significant amounts of oil would be a difficult and cumbersome task given the current environmental climate in North America. Energy and Environmental Analysis, Inc. Appendices Page 73

182 EEA s modeling methodology adds pipeline capacity for near-term projects only when such projects are significantly advanced in the permitting and construction process to guarantee in-service. Generic pipeline capacity is added into the model when locational price spreads for gas (i.e., gas price basis) are higher than anticipated per unit pipeline costs on a sustained basis. Interregional pipeline capacity additions are shown in Figure 47. Figure 46 Current and Projected North American LNG Regasification Capacity through 2025 Source: Energy and Environmental Analysis, Inc. Given the expansion guidelines, relatively few interregional pipeline projects are assumed in the EEA Base Case even though annual gas use in North America is projected to rise by nearly 9 Tcf by 2025 (see the following Section 4.2). The reason that not much new pipe is anticipated to be built is because most new frontier gas supplies are projected to take advantage of existing but underutilized pipeline infrastructure, or, in the case of many LNG projects, target major consumption markets directly. In fact, one of the primary reasons that LNG imports target the Gulf Coast is that the region can absorb significant volumes without requiring major interregional pipeline expansions. This should not imply that there will not be future need for additional short-haul capacity, as short-haul pipeline capacity will likely be needed to Energy and Environmental Analysis, Inc. Appendices Page 74

183 connect LNG terminals in the Gulf Coast area to the major interstate and intrastate pipelines that originate in the area. Figure 47 North American Pipeline Capacity Additions Source: Energy and Environmental Analysis, Inc Jordon Cove Cancouna Canaport Neptune Cove Point 750 Costa Azul Elba Island 900 EEA0406 Blue Lines indicate LNG Manzanillo Lazaro 750 Cardenas 500 Golden Free-Pasport Vista del Sol Lake Charles Gulf Sabine Gateway Pass 1000 Altamira Beacon Port Gulf LNG Energy Creole Trail Cameron 800 Florida (Offshore) There are major exceptions to the above discussion that are very important to Manitoba gas consumers. For example, Kinder Morgan s Rockies Express Pipeline project will add 1.8 billion cubic feet per day of takeaway pipeline capacity east out of the Rocky Mountains. The first segments of Rockies Express are projected to be in service by early The project is expected to be completed to Ohio by June The EEA Base Case also includes pipeline projects that would bring Arctic supplies to northern Alberta, Canada and potentially further south into the U.S. Although the Mackenzie and Alaska projects bring 5 Bcfd of production to the south, very little pipeline capacity is needed into the U.S. Most of the production utilizes existing pipeline capacity or is consumed in Western Canada. Only 500 MMcfd of pipeline capacity along the Alliance corridor to Chicago and 300 MMcfd into the Pacific Northwest is assumed with the Alaska Pipeline Project. The additional 376 MMcfd of pipeline 27 Does not include localized expansions associated with LNG imports. Energy and Environmental Analysis, Inc. Appendices Page 75

184 capacity shown in the Pacific Northwest is replacing Northwest Pipeline capacity that was taken out of service due to structural problems. 28 Storage is added to the EEA Base Case to correspond with planned projects. Generic projects are added in the future in response to market growth. The case adds a total of 502 billon cubic feet of working gas capacity from 2006 to The EEA Base Case assumes two new LNG import terminals in the west, Costa Azul in the Baha region of Mexico and a Jordan Cove facility on the Oregon Coast. Costa Azul is assumed to open in June 2008 at a capacity of 1 Bcfd and is expanded to 2 Bcfd in Jordan Cove opens in 2011 at a capacity of 1 Bcfd. The combined capacity of the two terminals in 2012 at 3 Bcfd is 14 percent of total North American LNG import capacity. By 2025, the percentage drops to 9 percent as new units are added elsewhere. B-2 Projected Gas Consumption B-2.1 U.S. and Canada Gas Consumption Over the past 11 years, U.S. and Canada enduse gas consumption 29 has averaged 22.4 trillion cubic feet per year (Table 14, Figure 48). The residential and commercial sectors have accounted for an average of 9.0 Tcf per year, or 40 percent of the total enduse gas consumption. Because of the impact of weather, it is difficult to discern the historical trend for residential and commercial gas use. Consumption trends appear erratic but generally flat. However, if adjusted for weather, the data indicates that residential gas use has been growing by about 60 Bcf per year, or by about 1 percent per year. Likewise, weather-adjusted commercial gas-use has been growing by about 35 Bcf per year, or by just under 1 Residential, commercial, and industrial gas use in the U.S. and Canada will grow by a little under 1% per year from a current annual level of 17 Tcf to just over 20 Tcf by percent per year. These trends are expected to continue. By 2025, the R/C sectors will grow by approximately 2 Tcf over current levels. As discussed in Section A-1.1 above, many different factors drive residential and commercial gas use over time, but the most dominant driver is demographic trends. Simply put, growth in gas use is a direct result of population growth. In the residential sector, population growth translates into growth in gas heated homes. The U.S. population has been growing at about 1 percent per year and the number of gas heated homes has also been increasing by just over 1 percent per year as natural gas continues to be the preferred fuel for newly constructed units. The growth in gas households is offset, to some extent, by efficiency improvements (e.g., more efficient furnaces and water heaters, better insulation and windows, etc.). 28 This replacement capacity was placed in service in late Does not include pipeline fuel and lease and plant gas use. Energy and Environmental Analysis, Inc. Appendices Page 76

185 Table 14 U.S. and Canada Natural Gas Consumption by Sector (Bcf per Year) Source: Energy and Environmental Analysis, Inc. Residential Commercial Industrial Non Power Total Power Generation Total End Use ,448 3,454 9,491 18,393 3,570 21, ,897 3,612 9,849 19,358 3,082 22, ,606 3,643 9,876 19,126 3,214 22, ,025 3,306 9,753 18,084 3,595 21, ,291 3,464 9,917 18,671 3,997 22, ,621 3,655 9,904 19,179 4,579 23, ,295 3,422 8,427 17,145 4,772 21, ,440 3,494 8,885 17,820 4,914 22, ,682 3,556 8,172 17,410 4,779 22, ,458 3,423 8,477 17,358 4,940 22, ,460 3,427 7,992 16,879 5,169 22, ,277 3,296 7,983 16,555 5,924 22, ,805 3,565 8,110 17,480 5,884 23, ,881 3,607 8,119 17,606 6,330 23, ,891 3,610 8,190 17,691 6,830 24, ,963 3,677 8,338 17,977 7,213 25, ,019 3,722 8,553 18,294 7,530 25, ,119 3,800 8,656 18,575 7,751 26, ,161 3,849 8,803 18,814 8,010 26, ,225 3,900 8,780 18,905 8,251 27, ,261 3,912 8,863 19,035 8,611 27, ,334 3,949 9,042 19,324 8,994 28, ,356 3,966 9,092 19,414 9,181 28, ,402 3,990 9,082 19,474 9,264 28, ,452 4,019 9,120 19,590 9,513 29, ,526 4,053 9,208 19,787 9,787 29, ,526 4,036 9,276 19,838 9,873 29, ,567 4,050 9,370 19,986 9,882 29, ,619 4,077 9,459 20,156 9,957 30, ,706 4,123 9,551 20,380 10,026 30, ,724 4,130 9,618 20,472 10,036 30,508 Average Historical ,475 3,496 9,158 18,129 4,237 22,367 Annual Growth Rate % 0.9% 0.6% 0.8% 3.4% 1.5% 1) 2004 is used as the base year to calculate growth trends of avoid huricane-releated effects. In the commercial sector, population growth translates into growth in commercial floor space, which translates into increased gas use. As in the residential sector, efficiency improvements tend to dampen the growth in gas use over time as more efficient furnaces and water heaters and better insulation reduce the gas required per square foot of floor space. In addition, gas use for space cooling and onsite electric generation (i.e., distributed generation) is poised to make gains in the commercial sector. Overall, Energy and Environmental Analysis, Inc. Appendices Page 77

186 we expect that continued growth in population and the other factors mentioned above will continue to increase gas use in the residential and commercial sectors over time. Figure 48 Projected U.S. and Canada Natural Gas Consumption (Tcf per Year) Source: Energy and Environmental Analysis, Inc Delta Delta Power Generation +3.4 Tcf +4.9 Tcf 20 Industrial +0.9 Tcf +1.6 Tcf Commercial +0.5 Tcf +0.7 Tcf 5 Residential +0.8 Tcf +1.3 Tcf Other +0.2 Tcf +0.2 Tcf The industrial sector is currently the largest sector for natural gas use in the U.S. and Canada. There are many different industrial gas consumers, including chemical providers, iron and steel manufacturers, paper mills, refiners, and food processors, among others. By far, chemical producers represent the largest group of industrial gas consumers, accounting for almost one-third of the total gas consumed in the industrial sector. The sector has consumed an average of 9.2 Tcf per year, or 41 percent of the total enduse gas consumed during the past ten years. However, annual consumption in the industrial sector has recently declined by about 2 Tcf from levels observed in the late 1990s. The industrial sector is the most price sensitive of all sectors. We do not believe that demand destruction in the industrial sector will continue at its recent rate. Our expectation is that additional demand destruction will slow as the most price sensitive consumers have already left the market. In industries where the cost of gas is a low percent of value added, our expectation is that high gas prices will result in little additional demand destruction. Over the long run, industrial production and efficiency of new equipment will drive industrial gas use. Over the past decade, industrial activity in energy intensive activities has slowed and activity in high-tech (generally not energy intensive) manufacturing 30 Other gas use includes pipeline fuel and lease and plant gas use. Energy and Environmental Analysis, Inc. Appendices Page 78

187 operations (e.g., computer chip manufacturing) has accelerated as the U.S. and Canada has moved towards a high-tech economy. Such shifts in the economy and gains in efficiency have dampened the growth of gas use in the industrial sector. We expect the growth in industrial activity to continue to be concentrated in high-tech manufacturing with slower growth in energy-intensive industrial activities in the future, consistent with recent history. Hence, the industrial sector should experience only modest growth in the future. We project that gas consumption in the industrial sector will only grow at 0.5 percent per year. Much of the growth in Canada, about an incremental 500 Bcf per year is due to oil sands development. Even with continued growth throughout the projection, by 2025, industrial consumption will not exceed levels that occurred in the late 1990s. During the past ten years, gas consumption in the power sector has exhibited significant growth. In 1998, gas consumption for U.S. and Canada power generaion equaled 3.6 Tcf and was only 13 percent of enduse gas consumption. By 2005, the level reached 5.2 Tcf and accounted for over 23 percent of gas consumption. Gas use in the power sector has been on an upward trend, along with the addition of new gas-based power plants. From 1998 through 2005, about 230 GW of new gas-based power generating capacity has Incremental growth in electricity demand will be satisfied primarily by gas-based generation during the next ten years. Gas use in the power sector will grow by almost 4 percent per year, and the sector s consumption will double over the next 20 years. been added in the U.S., more than doubling gas-based generating capability (Figure 49). Because the recent construction boom has created a significant amount of underutilized gas-based capacity that can be relied on to satisfy growth in electricity demand, the power sector should continue to be an area of growth for natural gas use well into the future. However, future capacity additions may favor coal, especially at the relatively high natural gas prices recently experienced. Coal generation capacity should increase relative to gas generation capacity in the future. Gas generation should increase in the near term (Figure 50) as underutilized gas units increase their load factors. However, incremental generation will increasingly come from coal units by the end of next decade. Annual gas consumption in the power sector will increase by 5.6 Tcf from 2004 to 2025 to 10.0 Tcf, nearly doubling the sector s consumption. However, 3.4 Tcf, or over 70 percent of the increase, will occur before Energy and Environmental Analysis, Inc. Appendices Page 79

188 Figure 49 Projected U.S. Lower-48 Coal and Gas Generation Capacity (Gigawatts) Source: Energy and Environmental Analysis, Inc. 1,000 (Gigawatts) Coal Gas Figure 50 Projected U.S. Lower-48 Generation (Billion kilowatt-hours) Source: Energy and Environmental Analysis, Inc. 6,000 (Billion kilowatthours) 5,000 Other 4,000 Nuclear 3,000 Hydro 2,000 Coal 1,000 Oil Gas Energy and Environmental Analysis, Inc. Appendices Page 80

189 B-2.2 Manitoba, Saskatchewan, and Alberta Gas Consumption Gas consumption growth rates for Manitoba, Saskatchewan, and Alberta are projected to exceed U.S. and Canadian growth rates during the next 20 years (Figure 51 and Figure 52). Central Canada gas consumption in the EEA Base Case grows from 1.6 Tcf in 2005 to 2.4 Tcf in 2025, which equates to an annual growth rate of 1.9 percent. Manitoba gas consumption is expected to grow from 95 Bcf in 2005 to 135 Bcf in This also equates to a 1.9 percent growth rate. Although many different consumers are likely to increase their gas use from 2005 to 2025, almost all of the growth in central Canada s gas consumption is due to increasing consumption in the industrial, most notably oil sands development. Gas use in the residential and commercial sectors is projected to remain fairly stable, and with less growth than the North American average. As mentioned earlier, the U.S. and Canada growth rate in these sectors is projected to be about 1.0 percent per year, By 2025, annual gas consumption in the residential and commercial sectors will rise to approximately 421 Bcf versus 338 Bcf in Projected growth in these sectors is consistent with recent historical trends. Continued population and economic growth is expected to result in growth in the number of residential customers, and increases in commercial floor space. Natural gas market share in new construction is expected to remain high in the state. However, improvements in efficiency are expected to offset most of the growth in the number of natural gas customers. Unlike recent trends and consistent with other projected trends throughout North America, the EEA Base Case projects that recent declines in industrial sector gas use are unlikely to continue. As has been the case in other regions throughout North America, the most inefficient and marginally economic uses of gas in the industrial sector have already been squeezed out of the market at the relatively high gas prices that have occurred during the past few years. Hence, the EEA Base Case projects a steady increase in Manitoba s industrial gas use. Energy and Environmental Analysis, Inc. Appendices Page 81

190 Figure 51 Projected Manitoba, Saskatchewan, and Alberta Gas Consumption by Sector (Bcf per Year) Source: Energy and Environmental Analysis, Inc 3,000 3,000 Billion Cubic Feet 2,500 2,000 1,500 1, Power Generation Industrial Commercial Residential Other 2,500 2,000 1,500 1, Terajoules Figure 52 Projected Manitoba, Saskatchewan, and Alberta Gas Consumption by Province (Bcf per Year) Source: Energy and Environmental Analysis, Inc 3,000 2,500 Manitoba Saskatchewan Alberta 3,000 2,500 Billion Cubic Feet 2,000 1,500 1,000 2,000 1,500 1,000 Terajoules Energy and Environmental Analysis, Inc. Appendices Page 82

191 B-2.3 Projected Natural Gas Prices and Basis 31 The EEA Base Case can be best characterized as a demand pull scenario, which is to say that gas demand throughout the U.S. and Canada grows over time, largely a result of growing gas use in power generation, and it pulls gas supply along with it. Because supply in mature producing areas has been heavily exploited, the North American gas market becomes more reliant on new frontier gas supplies, such as imported LNG and Arctic gas. The supply/demand balance for natural gas remains tight in this environment, yielding gas prices that are much higher than those observed in the 1990s when the balance between supply and demand was much looser. Generally, projected gas prices in all scenarios are more consistent with prices observed over the past few years, and less consistent with prices observed in the 1990s (Figure 53). Projected Henry Hub 32 gas prices from 2006 through 2025 average approximately $6.65 per MMBtu 33,34. Gas prices in the EEA Base Case exhibit significant volatility going forward. Prices are expected to remain relatively high for the next five years. As a result, we anticipate that Henry Hub prices will continue to average near $7.00 per MMBtu through After 2010, prices are projected to moderate toward $6.00 per MMBtu as many new LNG import terminals begin operation. Any reduction in gas prices could be delayed or reduced if LNG import terminals are delayed or LNG volumes do not reach the levels projected in the EEA Base Case. 31 The term basis, as used in this report, refers to locational price differences. 32 Henry Hub is the most widely recognized transaction point for natural gas in North America, and most discussions regarding trends for North American Natural gas prices focus on prices at Henry Hub. 33 All prices stated as real 2005 dollars. 34 Projected gas prices and basis in this report represent marginal prices solved in the EEA model given assumptions about fundamental market conditions over time. The prices are not necessarily representative of prices at which gas may currently be purchased or sold, which are better represented by prices and basis in futures and swaps markets. For example, EEA is projecting average gas prices at Henry Hub of $7 to $8 per MMBtu during the next few years. However, the NYMEX strip (representative of Henry Hub prices) has recently exhibited gas prices that average $9 to $ 10 per MMBtu, well above EEA s Base Case. It should also be emphasized that the projected prices represent purchases in the spot market. Firm supplies with guarantees of delivery, even if bought at index, will likely command price premiums. No assumptions are made about the cost (or premiums) for firm contracts for either the commodity or pipeline capacity in the future. Energy and Environmental Analysis, Inc. Appendices Page 83

192 Figure 53 Projected Henry Hub and Other Selected Natural Gas Prices (2005$ per MMBtu) Source: Energy and Environmental Analysis, Inc $ per MMBtu Average Price (2005$) Henry Hub Chicago Opal Dawn AECO Chicago Opal Dawn AECO Henry Hub The addition of 4 Bcfd of Alaska gas in late 2015 further reduces average annual Henry Hub prices by about $1.50 per MMBtu, but that price impact tends to be short lived as the North American market re-equilibrates. If the Alaskan project is not built, additional LNG imports will most likely be needed to balance the market. Price levels and price volatility after 2015 is highly dependent on the amount of new LNG imports entering the North American market. Further, all of these price projections assume normal weather, and actual weather can swing average annual prices by several dollars per MMBtu above or below the projected prices. The dominant (but not the only) determinant of prices in Central Canada is the overall North American supply and demand balance. Therefore, natural gas prices in Central Canada follow North American trends (a proxy for which is the Henry Hub price series). Prices at AECO are expected to be relatively high for the next few years and moderate in the future as sufficient amounts of new frontier supplies, such as LNG imports and Alaska gas, are assumed to enter the North American market. The dominant (but not the only) determinant of prices in Central Canada is the North American supply and demand balance. Energy and Environmental Analysis, Inc. Appendices Page 84

193 Pricing points in supply basins such as Opal and AECO are projected to average between 25 and 50 cents per MMBtu lower than prices at Henry Hub (Table 15). Consumption pricing point indexes, such as Chicago and Dawn are projected to average values that are above the Henry Hub index. However, within the next five years, before significant west to east pipeline capacity is added, such as Rockies Express, all prices in the west, even consumption markets, may trade below Henry Hub prices. Table 15 Projected Chicago, Opal, Dawn, and AECO Basis (2005$ per MMBtu) Source: Energy and Environmental Analysis, Inc. Price Henry Hub Basis Chicago (0.04) Opal (1.11) (0.51) (0.24) (0.32) (0.41) (0.37) Dawn AECO (0.89) (0.38) (0.01) (0.38) (0.25) (0.25) In general, future basis to Henry Hub from Central and West Canada market centers are projected to be lower than recently observed values. Growing consumption in the west, increased LNG supplies along the Gulf Coast, and additional pipeline capacity to the east out of the Rocky Mountains reduce future west to east price differentials. The only exception may be immediately after an Alaska Pipeline Project that significantly utilizes existing pipeline infrastructure south of Alberta. This could temporarily widen AECO to Henry Hub basis. Energy and Environmental Analysis, Inc. Appendices Page 85

194 Table 16 Factors that Help Determine Long-Run Natural Gas Markets Source: Energy and Environmental Analysis, Inc. Factor Possible Effects World Oil Prices Scarcity and high price of crude oil would tend to lead to higher natural gas prices through inter-fuel competition, LNG pricing formulae, and competition for E&P capital. Economic and Political Trends in Gas Exporting Countries Environment favorable to large LNG trade volumes will help keep U.S. gas prices low. U.S. Population and Economic Growth The main engine of energy use is population growth and economic activity. U.S. Industrial Base Competition with foreign manufacturing will affect how much energy-intensive industry remains in the U.S. Energy Conservation and Efficiency Technologies and Policies More efficient energy use would reduce demand for electricity and natural gas. Long-term Trend in Electricity Consumption Lower consumption of electricity would lead to less use of natural gas to generate electricity. Drivers include technology developments and policies. Inter-fuel Competition in Power Generation Coal, nuclear, and renewables are most likely to compete for market share with natural gas. Drivers include alternative fuel prices, technologies, and policies such as renewable portfolio standards. Inter-fuel Competition and Technology Trends in the Industrial Sector Oil, electricity, coal, and waste fuels are most likely to compete for market share with natural gas. Drivers include alternative fuel prices, manufacturing technologies, and U.S. industrial base. Technology Trends and Competition in the Residential and Commercial Sectors Primary competition is with oil and electricity. New natural gas applications such as smallscale combined heat and power may play role in certain (cold weather) regions. Environmental Rules for SOx, NOx, Hg Environmental rules affect dispatch of existing plants and economics of new plants. Environmental Rules for Carbon Dioxide Carbon constraints can affect overall level of energy demand and competition among fuel sources. North American Natural Gas Resource Base A more abundant resource base will make lower gas prices and larger markets easier to achieve. Land Access to the Gas Resource Base Government policies that allow environmentally sound development of natural gas on public land would make more gas available to the market. Could affect production from Rockies, Pacific Offshore, Atlantic Offshore, and Eastern Gulf of Mexico. Upstream Technologies Advances in upstream technologies will help counteract the affects of resource depletion. Technology Advances for New Gas Sources such as Hydrates and Coal Gasification New source of gas developed at competitive prices would lead to lower prices and larger gas markets. Energy and Environmental Analysis, Inc. Appendices Page 86

195 B-3 Demand Factors The demand for natural gas will be influenced by many factors including those listed at the front of this section in Table 16. Some of the factors such as world oil prices, the investment environment in LNG exporting countries, and the competition between U.S. and foreign manufacturers are determined by international forces. Others, such as policies toward energy efficiency are determined almost completely within the U.S. Some of the key demand-side factors that will affect natural gas markets before and after 2025 are discussed below. Economic and Population Growth: Long-run economic growth is generally expected to be in the range of 2.5 to over 3.0 percent. This economic growth rate is often based on U.S. Census population growth rates that start near 0.9% per annum today and decline to about 0.75% per annum by the middle part of this century. Slower population and/or economic growth would be expected to decrease the rate of increase in demand for energy, including natural gas. On the other hand, higher population growth rates (e.g., through liberalized immigration policies) and higher economic growth would be expected to lead to greater demands for energy. Electricity Demand Growth: While considerable growth in electricity use is projected to continue, the pace should slow from historical rates. Some rapidly growing applications, such as air conditioning and computers, are projected to slow as penetration approaches saturation levels. Electrical efficiency also is expected to continue to improve, due in large part to efficiency standards, and the impacts tend to accumulate with the gradual turnover of appliance stocks. Since gas use for power generation is expected to be a large market for natural gas, a higher growth rate in electricity use would be expected to lead to increased gas use. World Oil Prices: World oil prices are determined by world resource endowment, technology factors, political considerations and demand throughout the world. Our expected price range for oil post-2025 is $20 per barrel to over $100 per barrel. Because natural gas competes with oil products in many enduse markets, higher oil prices tend to lead to higher natural gas prices. Oil prices also affect gas prices through oil-based pricing formulae used for LNG in many parts of the world. The competition for investment dollars between gas projects and oil projects, including GTL projects to convert natural gas to liquid fuels, may also be influenced by oil prices, and thus, a factor that influences gas prices. Enduse Technologies: Technologies that improve energy efficiencies can reduce the use of electricity and natural gas. Gas use can also be reduced through technologies that improve the competitive advantage of alternative fuels, such as electric heat pumps for residential space heating. On the other hand, gas use can be increased through technologies that improve the competitive advantage of natural gas versus other fuels or introduce gas into new markets such as small scale combined heat and power applications in the residential and commercial sectors. Energy and Environmental Analysis, Inc. Appendices Page 87

196 Energy Efficiency Policies: State and Federal policies to promote energy conservation of electricity and natural gas can have a substantial impact on market growth. Policies can include building standards, appliance standards, economic incentives, and various utility programs to promote conservation and efficient energy use. Fuel Use Policies: These policies include renewable portfolio standards and efforts to promote alternative fuels. An example is the nuclear power tax credit contained in the Energy Policy Act of Due to concerns about high prices and energy security, future policies are most likely to promote greater use of coal, nuclear power, and renewables at the expense of oil and natural gas. Environmental Regulations: Regulations of particulates, nitrogen oxides (NOx), sulfur oxides (SOx) and mercury (Hg) affect the burning of fossil and waste fuel for power generation and many industrial and commercial applications. Generally, such regulations favor natural gas over oil and coal because of the relatively clean characteristics of natural gas combustion. Future regulation of carbon dioxide is possible before The effects of carbon constraints on natural gas use are mixed; on the one hand, gas (a low carbon fuel) is favored over coal and oil. On the other hand, all uses of fossil energy likely will be reduced by greater energy conservation and increased use of renewables and nuclear power. Energy and Environmental Analysis, Inc. Appendices Page 88

197 APPENDIX C: EEA S GAS MARKET DATA AND FORECASTING SYSTEM EEA s Gas Market Data and Forecasting System (GMDFS), a nationally recognized modeling and market analysis system for the North American gas market will be used to obtain the scenario results for this project. EEA s GMDFS was developed in the mid- 1990s to provide forecasts of the North American natural gas market under different assumptions. In its infancy, the model was used to simulate changes in the gas market that occur when major new sources of gas supply are delivered into the marketplace. For example, much of the initial work with the model in focused on measuring the impact of the Alliance pipeline completed in The questions answered in the initial studies include: What is the price impact of gas deliveries on Alliance at Chicago? What is the price impact of increased takeaway pipeline capacity in Alberta? Does the gas market support Alliance? If not, when will it support Alliance? Will supply be adequate to fill Alliance? If not, when will supply be adequate? What is the marginal value of gas transmission on Alliance? What is the impact of Alliance on other transmission and storage assets? How does Alliance affect gas supply (both Canadian and U.S. supply)? What pipe is required downstream of Alliance to take away excess gas? Subsequently, EEA s model has been used to complete strategic planning studies for many private sector companies. The different studies include: Analyses of different pipeline expansions Measuring the impact of gas-fired power generation growth Assessing the impact of low and high gas supply Assessing the impact of different regulatory environments In addition to its use for strategic planning studies, the EEA model has been widely used by a number of institutional clients and advisory councils, including INGAA, who relied on the model for the 30 Tcf market analysis completed in 1998 and again in GRI has relied on the EEA model for the GRI Baseline Projection. The model was also the primary tool used to complete the widely referenced studies on the North American Gas Market for the National Petroleum Council in 1999 and EEA s Gas Market Data and Forecasting System is a full supply/demand equilibrium model of the North American gas market. The model solves for monthly natural gas prices throughout North America, given different supply/demand conditions, the assumptions for which are specified by the user. Overall, the model solves for monthly market clearing prices by considering the interaction between supply and demand curves at each of the model s nodes. On the supply-side of the equation, prices are determined by production and storage price Energy and Environmental Analysis, Inc. Appendices Page 89

198 curves that reflect prices as a function of production and storage utilization (Figure 54). Prices are also influenced by pipeline discount curves, which reflect the change in basis or the marginal value of gas transmission as a function of load factor. On the demand-side of the equation, prices are represented by a curve that captures the fuelswitching behavior of end-users at different price levels. The model balances supply and demand at all nodes in the model at the market clearing prices determined by the shape of the supply and demand curves. Unlike other commercially available models for the gas industry, EEA does significant backcasting (calibration) of the model s curves and relationships on a monthly basis to make sure that the model reliably reflects historical gas market behavior, instilling confidence in the projected results. Figure 54 Supply/Demand Curves Source: Energy and Environmental Analysis, Inc. There are ten different components of EEA s model, as shown in Figure 55. The user specifies input for the model in the drivers spreadsheet. The user provides assumptions for weather, economic growth, oil prices, and gas supply deliverability, among other variables. EEA s market reconnaissance keeps the model up to date with generating capacity, storage and pipeline expansions, and the impact of regulatory changes in gas transmission. This is important to maintaining model credibility and confidence of results. Energy and Environmental Analysis, Inc. Appendices Page 90

199 Figure 55 GMDFS Structure Source: Energy and Environmental Analysis, Inc. Market Drivers Weather Macroeconomics Crude Oil Prices Gas Supply Deliverability trends Market Reconnaissance Generating Units - New Capacity - Unit Availability Storage Activity Pipeline Transportation - Capacity & Rates - Secondary Market LNG - Liquefaction Facilities - Re-gasification Facilities Natural Gas Demand Module Electric Power Module Underground Gas Storage Module Natural Gas Transportation Module Natural Gas Supply Module LNG Supply Module Current Market Prices Natural Gas Petroleum Products Market Simulation Module Estimated Current Month Activity Forecast up to 192 Months into the Future Simulation of Gas /Electricity Markets Outputs The first model routine solves for gas demand across different sectors, given economic growth, weather, and the level of price competition between gas and oil. The second model routine solves the power generation dispatch on a regional basis to determine the amount of gas used in power generation, which is allocated along with end-use gas demand to model nodes. The model nodes are tied together by a series of network links in the gas transportation module. The structure of the transmission network is shown in Figure 56 and the nodes are identified by name in Table 17. The gas supply component of the model solves for node-level natural gas deliverability or supply capability. The Hydrocarbon Supply Model (HSM), as discussed in the next section may be integrated with the GMDFS to solve for deliverability. The last routine in the model solves for gas storage injections and withdrawals at different gas prices. The components of supply (i.e., gas deliverability, storage withdrawals, supplemental gas, LNG imports, and Mexican imports) are balanced against demand (i.e., end-use demand, power generation gas demand, LNG exports, and Mexican exports) at each of the nodes and gas prices are solved for in the market simulation module. A few other charts that summarize input/output and regional breakout for the EEA Model are shown as Figure 57, Figure 58, Figure 60, and Figure 61. The EEA model runs under the Microsoft Windows operating system, and relies on easy-to-use MS-Excel and MS- Access programs developed by EEA. Energy and Environmental Analysis, Inc. Appendices Page 91

200 Figure 56 GMDFS Transmission Network Source: Energy and Environmental Analysis, Inc. Energy and Environmental Analysis, Inc. Appendices Page 92

201 Figure 57 Model Drivers Source: Energy and Environmental Analysis, Inc. Figure 58 Model Output Source: Energy and Environmental Analysis, Inc. Outputs of the Forecasting System MONTHLY DATA DATA CONTENT GEOGRAPHIC DETAIL OF DATA Delivered to Pipeline Gas Pricing and Citygate Prices 114 Points Pipeline Transportation Gas Storage Inter-Regional Capacity Tariffs Caps Market Value of Capacity Working Gas Capacity Inventories Injection/Withdrawal Activity 343 Network Corridors 26 Storage Regions Natural Gas Demand By Sector 34 U.S. and (R/C/I) 7 Canada/Alaska Regions Deliverability Natural Gas Supply Dry Production 64 U.S. and Gas Imports/Exports 13 Canada/Alaska Regions Supplemental Fuels Natural Gas Demand Electricity Markets Electricity Demand (U.S. Only With Explicty Imports) Power Generation Balance 13 "NERC" Regions Gas-based Generation Energy and Environmental Analysis, Inc. Appendices Page 93