NATIONAL ENERGY BOARD
HEARING ORDER GH-1-2004
ADDITIONAL WRITTEN EVIDENCE
ASSESSMENT OF MACKENZIE VALLEY PIPELINE’S PROPOSED RETURN ON CAPITAL
Submitted on behalf of
The Mackenzie Valley Pipeline
Kathleen C. McShane
Senior Vice President
Foster Associates, Inc.
January 10, 2005 TABLE OF CONTENTS
A. TESTIMONY OF KATHLEEN C. McSHANE
B. ASSESSMENT OF MACKENZIE VALLEY PIPELINE’S PROPOSED RETURN ON CAPITAL
I. PURPOSE OF REPORT 1 II. KEY FACTORS IN ANALYSIS 1 III. SUMMARY OF MACKENZIE VALLEY PIPELINE’S 3 PROPOSED FINANCIAL PARAMETERS IV. CAPITAL STRUCTURE 3 V. BUSINESS RISK, CAPITAL STRUCTURE AND RETURN 13 ON EQUITY VI. MVP vs. ESTABLISHED NEB-REGULATED GAS 21 PIPELINES VII MVP vs. NEW CANADIAN PIPELINE COMPARATORS 25 VIII MVP vs. CANADIAN GREENFIELD GAS LDC 28 OPERATIONS IX. SUMMARY OF RETURN ON CAPITAL FOR CANADIAN 31 PIPELINES AND LDCs X. MVP vs. U.S. GAS PIPELINES 32 XI. DEEMED COST OF DEBT 38 XII. CONCLUSIONS 41
C. SCHEDULES
D. QUALIFICATIONS OF KATHLEEN C. McSHANE SECTION A
1 2 TESTIMONY OF 3 KATHLEEN C. McSHANE 4 5 6 Q. Please state your name, business address, occupation. 7 8 A. My name is Kathleen C. McShane and my business address is 4550 Montgomery 9 Avenue, Suite 350N, Bethesda, Maryland 20814. I am a Senior Vice President of 10 Foster Associates, Inc., an economic consulting firm. 11 12 Q. Please state your educational background and experience. 13 14 A. I hold a Masters in Business Administration with a concentration in Finance from 15 the University of Florida (1980) and the Chartered Financial Analyst designation 16 (1989). My professional experience is provided in Section D. 17 18 Q. What is the purpose of your report? 19 20 A. I have been asked by Mackenzie Valley Pipeline (MVP) to evaluate the 21 reasonableness of its approach to setting its financial parameters for ratemaking 22 purposes, including the reasonableness of utilizing a deemed cost of debt. I was 23 also asked to assess the reasonableness of the specific proposed financial 24 parameters. Section B, entitled, “Assessment of Mackenzie Valley Pipeline’s 25 Proposed Return On Capital”, presents the summary of my analysis and 26 conclusions. 27 SECTION B
1 ASSESSMENT OF MACKENZIE VALLEY PIPELINE’S 2 PROPOSED RETURN ON CAPITAL 3 4 5 I. PURPOSE OF REPORT 6 7 I have been asked by the proponents of the Mackenzie Valley Pipeline (MVP) to 8 evaluate the reasonableness of its approach to determining a fair return on capital 9 for ratemaking purposes. Specifically, I evaluated: 10 11 ● reliance on a deemed capital structure and deemed debt cost; 12 ● the proposed capital structure of 70% debt and 30% common equity; and, 13 ● the proposed rate of return on equity (ROE), which comprises the NEB’s 14 multi-pipeline ROE plus an ROE increment of 2.21%. 15 16 This report presents the summary of my analysis and conclusions. 17 18 II. KEY FACTORS IN ANALYSIS 19 20 Key factors in assessing the reasonableness of MVP’s proposals for capital 21 structure and return on equity include the following: 22 23 1. The Mackenzie Valley Pipeline is a greenfield project. Investors are being 24 asked to commit approximately $4.5 billion in debt and equity to connect 25 an untested supply basin to downstream markets. The greenfield nature of 26 the project is one of the characteristics that differentiate it from the mature 27 Canadian gas pipelines subject to the NEB multi-pipeline ROE. 28 29 2. There are no equity market data for greenfield pipelines, which means that 30 the equity return requirement is difficult to pinpoint. Thus, my analysis
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1 will focus on the reasonableness of the requested return and capital 2 structure by reference to the returns available on reasonably comparable 3 alternative investments for which data are available. Those alternatives 4 can establish a range of reasonableness. No single alternative should be 5 viewed as producing a definitive estimate of the return requirement for 6 MVP, since the derivation of the returns for various alternatives required a 7 material degree of judgement. 8 9 3. The evaluation of MVP’s requested capital structure and return on equity 10 needs to recognize that the two components are integrally related. The 11 required return on equity is a function of both business and financial risks 12 (capital structure). The use of any alternative investment to test the 13 reasonableness of MVP’s proposal needs to consider the impact of both 14 the capital structure and return on the magnitude of the total risk 15 compensation. 16 17 4. In the absence of specific proxies with market data that mirror MVP’s 18 business risk profile, the reasonableness of the proposed combined return 19 and capital structure can be assessed using comparators or “fence posts”, 20 to establish a range within which a reasonable return falls. By establishing 21 at least two “fence posts” which, in effect, encompass the spectrum of 22 risk/return benchmarks in the industry, MVP’s proposed financial 23 parameters can be situated within those boundaries, and their 24 reasonableness evaluated.1 25
1 This is analogous to the approach taken by the Independent Assessment Team (IAT) in 1999 when called upon by the Province of Alberta to estimate the cost of capital to be applied to the long-term Power Purchase Arrangements for the existing generation plants of the Alberta electric utilities. Since there were no “pure play” proxies for the PPAs given their unique risk characteristics, the IAT used, as its two comparators, or “fence posts”, an integrated electric utility at the low end, and merchant generation at the upper end, of the business risk spectrum. The IAT estimated the cost of capital for both “fence posts” and then estimated the cost of capital for the PPAs based on its assessment of where the PPAs fit on the business risk spectrum between regulated generation and merchant generation.
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1 III. SUMMARY OF MACKENZIE VALLEY PIPELINE’S 2 PROPOSED FINANCIAL PARAMETERS 3 4 MVP has applied to the NEB for approval of the following financial parameters 5 for tollmaking purposes: 6 7 1. A deemed equity ratio of 30%. 8 2. An equity rate of return 2.21% above the NEB formula ROE. 9 3. A deemed cost of debt based on the Aboriginal Pipeline Group’s (APG’s) 10 actual cost to project finance the debt portion of its ownership interest. 11 12 The 2.21% ROE increment was premised on the conclusion that an approximately 13 12% rate of return on equity was reasonable for the Mackenzie Valley Pipeline 14 project at the time the NEB formula return was 9.79% (2003).2 MVP’s proposal 15 varies the pipeline’s allowed ROE from year to year, over the first ten years of the 16 project, maintaining the ROE increment of 2.21% implied by the initial estimated 17 required return of 12.0%. 18 19 IV. CAPITAL STRUCTURE 20 21 A. Principles 22 23 Use of a deemed capital structure is a hallmark of Canadian regulation, originally 24 used primarily to protect tollpayers from the impact of riskier operations 25 conducted by the parent companies of regulated pipelines and utilities. 26 27 Reliance on a deemed capital structure reflects the application of the stand-alone 28 principle.3 The stand-alone principle encompasses the notion that the cost of
2 As discussed in MVP’s response to Board IR 1.14. 3 Regulation by the National Energy Board (NEB) follows the stand-alone principle. Most recently in RH- R-1-2002 (February 2003), the NEB stated, “The Board agrees with TransCanada that the stand-alone
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1 capital incurred by the ratepayers should be equivalent to that which would be 2 faced by the utility raising capital in the public markets on the strength of its own 3 business and financial parameters. The cost of capital should reflect neither 4 subsidies given to, nor taken from, other activities of the utility or its parent. 5 Application of the stand-alone principle to MVP means that its financial 6 parameters should be evaluated independently of pipeline ownership. Respect for 7 the stand-alone principle is intended to promote efficient allocation of capital 8 resources and avoid cross-subsidies. My evaluation of the MVP proposals is 9 premised on the application of the stand-alone principle. 10 11 The choice of a capital structure is premised on the level of business risks faced 12 and is based, in part, on the objective of minimizing the overall cost of capital. In 13 theory, there is a range of capital structures over which the cost of capital is 14 minimized. In practice, it is difficult to pinpoint that range, since the cost of 15 equity is not directly observable. Thus, in establishing a deemed capital structure 16 for a regulated entity, which is compatible with the goal of minimizing the cost of 17 capital, key factors are to ensure that the capital structure is: 18 19 1. reasonably reflective of the level of business risks faced; 20 21 2. in line with capital structures maintained by the industry; and, 22 23 3. adequate, in conjunction with the allowed rate of return on equity, to 24 achieve an investment grade debt rating that will permit access to capital 25 as required at reasonable rates. 26 27 In assessing whether MVP’s proposed deemed equity ratio of 30% is reasonable, 28 or whether a higher equity ratio should be used, given MVP’s business risk
principle is a fundamental concept of utility regulation and a concept that it should continue to apply in regulating TransCanada.”
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1 profile, it needs to be recognized that full compensation for the risks of MVP can 2 be achieved in one of three ways: 3 4 1. Through capital structure: 5 6 A capital structure (i.e., a level of financial risk) is established that results 7 in the same investment risk and equity return requirement as for a 8 “benchmark” NEB-regulated gas pipeline. 9 10 2. Through ROE: 11 12 A capital structure similar to that of the NEB-regulated gas pipelines is 13 established, with compensation for MVP’s unique business risk factors 14 being provided entirely through ROE. 15 16 3. Through a combination of capital structure and ROE: 17 18 The mix of capital structure and ROE compensates for MVP’s unique risk 19 circumstances. 20 21 The same principle underpins each of the three options. There is a trade-off 22 between capital structure and return on equity. Thus, the evaluation of the various 23 components of the cost of capital cannot be undertaken in isolation. Both the cost 24 of debt and cost of equity are a function of the business risks and financial risks of 25 the firm. Simplistically, there is an inverse relationship between the cost of equity 26 and the common equity ratio. All other things equal, the higher the common 27 equity ratio, the lower the cost of equity. Further, there is an inverse relationship 28 between the level of business risk faced by a company and the amount of debt 29 leverage that it is prudent to assume. A discussion of that relationship follows. 30
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1 The cost of capital to a firm is dependent on the business risk it faces. The 2 business risk, in turn, is a function of the variability of operating cash flows and 3 of the probability that the capital investment will not be fully recovered. The 4 higher the business risk, the higher is the cost of capital, ceteris paribus. In the 5 absence of income taxes and costs associated with the use of excessive debt (e.g., 6 bankruptcy costs), the cost of capital to a firm would not change if it changed its 7 capital structure, e.g., from 100% equity financing to 70% financing debt. 8 9 By issuing debt, the firm creates a class of investors whose claims on the 10 resources of the firm take precedence over those of the equity holder. The 11 issuance of debt, in the absence of income taxes and costs associated with the use 12 of excessive debt, does not change the sum of the cash flows that are available to 13 meet the return requirements of both the debt holders and equity holders. 14 However, the issuance of debt, which carries a fixed obligation, increases the 15 potential variability and/or underrecovery of the equity shareholder’s return. 16 Thus, as the debt ratio rises, the cost of equity rises, but the cost of capital remains 17 unchanged. 18 19 In practice, there are both income taxes and costs associated with potential 20 bankruptcy or loss of financing flexibility. These factors mean that at some point, 21 as more debt is added to the capital structure, the cost of capital does change. 22 The deductibility of interest expense means that there is a cash flow advantage to 23 equity holders from the assumption of debt. Thus, initially, as debt is added to the 24 capital structure, the after–tax cost of capital falls. As the proportion of debt in 25 the capital structure continues to increase, the loss of financing flexibility and 26 potential for bankruptcy will start to offset the benefits of interest deductibility. 27 At some proportion of debt, the cost of capital begins to rise. Further, although 28 interest expense is tax deductible at the corporate level, it may be taxable to 29 individual investors at a higher rate than equity (when both dividends and capital 30 gains are considered), offsetting some of the advantage of increasing the debt 31 component.
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1 2 Taking into account all of the above factors, within a reasonable range of capital 3 structures for an industry, as the debt ratio rises, the cost of equity will increase, 4 while the overall weighted average cost of capital (both pre-tax and after tax) 5 should not change significantly. Thus, there is no single “correct” capital 6 structure; a reasonable capital structure falls within a range. 7 8 Although the NEB, in the context of the multi-pipeline proceeding, has expressed 9 a preference for recognition of business risk differences through capital structure, 10 it does not mean that the other approaches are not equally valid nor that one of the 11 alternative approaches should be rejected, as long as the end result produces a 12 reasonable balance of capital structure and return on equity. To illustrate, 13 Maritimes and Northeast Pipeline (M&NP) has both a different capital structure 14 and ROE than an established gas pipeline subject to the Multi-Pipeline Cost of 15 Capital Decision (RH-2-94). 16 17 Both the British Columbia Utilities Commission (BCUC) and the Ontario Energy 18 Board (OEB), who, like the NEB, use automatic adjustment formulas for ROE, 19 have essentially used the third approach, a combination of capital structure and 20 ROE. The BCUC utilities, for example, all have different regulated capital 21 structures and different company-specific equity risk premiums. The OEB has 22 approved identical deemed common equity ratios for Enbridge Gas Distribution 23 and Union Gas, but has approved different equity risk premiums for the two gas 24 distributors. 25 26 Ultimately, MVP’s deemed capital structure should take into account the 27 following factors: 28 29 1. The level of business risk; 30 31 2. The availability of equity funding to participants in the project;
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1 2 3. Ratios that, on a stand-alone basis, in conjunction with the allowed ROE, 3 would allow the pipeline to be able to attract debt capital at a cost that is 4 representative of an A credit rating; and, 5 6 4. The goal of minimizing the overall cost of capital. 7 8 The 30% proposed equity ratio is consistent with the external funding that is 9 expected to be required and available, and is in line with the ratios maintained by 10 other Canadian gas pipelines. However, in my opinion, a 30% equity ratio for 11 MVP would not be adequate to achieve a stand-alone debt rating in the A 12 category absent a higher common equity rate of return than that applicable to a 13 benchmark NEB-regulated gas pipeline. 14 15 B. Relevance of Debt Rating Agencies 16 17 In assessing MVP’s proposed deemed capital structure, the views of the debt 18 rating agencies are relevant considerations. If MVP were raising funds on a 19 stand-alone basis, the analysis and conclusions of the debt rating agencies would 20 determine its debt ratings and access to the public debt markets. Application to 21 MVP on a stand-alone basis of the debt rating agencies’ approaches to rating 22 regulated companies will provide insight into the reasonableness of the pipeline’s 23 proposals. 24 25 The two major debt rating agencies4 in Canada are Standard & Poor’s (S&P) and 26 the Dominion Bond Rating Service (DBRS). A regulated company that intends to 27 issue debt into the public markets generally needs two debt ratings. The 28 combination of the debt ratings that are assigned to a utility will be determinative 29 of its actual cost of debt and ability to access the capital markets. Thus, the
4 Moody’s is also active in the Canadian debt rating market, but, at present, rates considerably fewer of the regulated firms than either S&P or DBRS.
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1 “notional” application of both S&P’s and DBRS’s approaches to rating a firm’s 2 debt is relevant to an assessment of MVP’s proposed deemed financial structure. 3 4 1. Standard & Poor’s Rating Methodology 5 6 Standard & Poor’s publishes quantitative criteria for debt ratings by business risk 7 profile ranking.5 For a relatively low risk pipeline, i.e., one with a business risk 8 rank of “2” or “3”6, and an A credit rating, S&P looks for the following financial 9 parameters: 10 Standard & Poor’s Quantitative Guidelines (A Rating) “2” “3” Funds from Operations7 12-20% 15-25% to Total Debt Funds From Operations 2-3X 2.5-3.5X Interest Coverage
Total Debt to Total Capital 52-58% 50-55%
11 12
5 Since 1999, S&P has assigned business profile scores to the utilities it rates on a scale of “1” to “10”, with “1” being the least risky. Each business profile category has corresponding quantitative financial ratio guidelines for the various debt rating categories. In June 2004, S&P reassessed its business risk profile scoring approach, and reached the conclusion that the “complete range of the 10-point scale was not being used to the fullest extent.” As a result of its findings, S&P reassigned scores to all the U.S. utilities it rates, which, in S&P’s view, reflect the differentiation in the utility and power industry today. S&P also revised its key financial guidelines, broadening the ranges and eliminating pre-tax interest coverage as one of its key credit ratios. (Standard & Poor’s, “New Business Profile Scores Assigned for U.S. Utility and Power Companies; Financial Guidelines Revised”, Utilities & Perspectives, June 7, 2004.) 6 TransCanada Corporation and Nova Gas Transmission are ranked “3”. Alliance and Maritimes and Northeast have not been formally assigned business risk profiles, being project-financed, but S&P indicated to me that they would be in the “2-3” range. S&P’s reassessment of the business profile scoring approach in June 2004 did not alter the scores assigned (explicitly or implicitly) to any of these four pipelines. The reassessment did, however, lower the scores of the rated U.S. gas pipelines to which business profile scores are assigned from an average of “4” to an average of “3”. 7 Net income plus depreciation, amortization, deferred taxes and other non-cash items.
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1 The more stringent guidelines for a regulated firm with a business risk profile 2 score of “3” reflect the need for stronger financial parameters to achieve the same 3 debt rating as a firm with lower business risk, e.g., with a score of “2”. 4 5 S&P does not mechanistically apply its guidelines. The debt rating agency is 6 concerned with the pipeline’s overall ability to service its debt obligations, not the 7 value of a single guideline. Thus, for a given debt rating, the debt ratio need not 8 lie within the specific guideline range, as long as the composite of the quantitative 9 ratios provides a sufficient cushion to debtholders to support the debt rating. 10 11 2. Application of S&P Guidelines to MVP 12 13 As shown below, based on MVP’s preliminary forecasts for the first ten years of 14 operation (2010-2019) (as filed in its Application to the Board), the average ratios 15 for MVP for S&P’s two quantitative guidelines (other than debt to total capital) 16 are expected to be: 17 18 Funds from Operations 14.8% 19 to Total Debt 20 21 Funds from Operations 3.4X 22 Interest Coverage 23 24 Pre-tax interest coverage is forecast to average 2.4 times. The 2.4 times estimate 25 is toward the bottom end of the range of S&P’s pre-June 2004 guidelines,8 which 26 indicated a target pre-tax interest coverage range of 2.3 to 3.4 times for a business 27 risk profile score of “2” to “3” and an A rating. 28
8 As previously noted, S&P eliminated pre-tax interest coverage as one of its key quantitative guidelines when it issued its revised guidelines.
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1 The application of the three quantitative guidelines to MVP’s forecasts as filed in 2 the application9 indicates sufficient financial strength on a composite basis to 3 support a stand-alone notional debt rating in the A category from S&P. 4 5 3. DBRS’ Rating Methodology 6 7 DBRS issued quantitative guidelines in “DBRS Methodology in Rating Utilities”, 8 which it stated could be used as “rough guides” for ratings in the A/BBB 9 category. However, in its discussion of its approach to rating utilities, DBRS 10 underscores the importance of qualitative factors in its assessment. The 11 guidelines focus on the characteristics of electric utilities, but appear to be 12 relevant to regulated gas distributors and pipelines as well. 13 14 The three quantitative guidelines provided by DBRS, as they apply to regulated 15 and mixed10 firms, include: 16 DBRS Quantitative Guidelines (A/BBB Ratings) Regulated Mixed % Debt 60-70% 50-60% Fixed Charge Coverage 1.5 X 1.5-2.0 X Cash Flow/Debt 0.10 0.10-0.15 17 18 Since the DBRS guidelines comprise two full rating categories, A and BBB, a 19 review of the debt ratings and the actual financial ratios that have been maintained 20 by Canadian pipelines may be useful. Table 1 below summarizes the current 21 ratings and the average of the actual ratios (over the most recent three-year period 22 available from DBRS reports) for the Canadian major gas pipelines with DBRS 23 ratings for long-term debt. The corresponding ratios for MVP represent averages
9 Includes the 11.77% ROE reflected in the application, which was based on the NEB’s 2004 multi-pipeline ROE.
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1 for the first ten years of operation based on the forecasts provided in the 2 Application. 3 4 Table 1 % Debt Fixed Charge Cash Flow/Debt DBRS Coverage Rating Three Year Average 1/ Alliance A(low) 69.1% 1.9 0.11 M&NP A 74.7% 1.8 0.10 Nova A 66.3% 2.3 0.15 TCPL A 67.2% 1.9 0.13 TQM A(low) 69.8% 2.3 0.10
Westcoast 2/ A(low) 64.2% 1.8 0.13 Average A/A(low) 68.6% 2.0 0.12 MVP 70.0% 2.4 0.15 5
6 1/ Ending either 2002 or 2003. 7 2/ Based on consolidated accounting principles. 8 9 A comparison of the estimated MVP ratios to those of the major gas pipelines 10 indicates that, with its proposed capital structure and return on equity, MVP’s 11 ratios would be reasonably similar to the Canadian industry average, and thus 12 supportive of an A rating by DBRS. 13 14 4. Sensitivity of Financial Ratios to Debt Cost 15 16 The calculated financial ratios above, which are based on the assumptions 17 included in the filed application, are sensitive to the actual long-term debt cost. 18 For purposes of MVP’s financial modeling, the debt cost has been assumed to be 19 6.1% for 20-year debt. The 6.1% used in the model is potentially on the low side
10 “Mixed” companies are those with regulated and unregulated components. Guidelines were also
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1 for 20-year debt for MVP, as it was based on the capital market conditions 2 prevailing in 2004, a period of relatively low interest rates. 3 4 In October 2004, Consensus Economics, Consensus Forecasts, published its long- 5 term consensus forecast for 10-year Canada bonds, in which the anticipated 6 average yield of 10-year Canada bonds was 5.9% for 2006-2008. The recent 7 indicated spreads for a new 10-year A-rated utility issue are in the range of 50-75 8 basis points,11 which would lead to a 10-year debt cost of about 6.5%. For a 30- 9 year issue, the corresponding 2006-2008 30-year Canada bond yield can be 10 estimated at about 6.25%, based on the same consensus 10-year Canada bond 11 forecast plus the historical average spread between 10- and 30-year Canadas of 12 approximately 35 basis points. The indicated spread for a new 30-year A-rated 13 utility issue was in the range of 85-130 basis points at the end of November 2004, 14 indicating a cost for a 30-year A-rated issue of about 7.25%. Based on these 10- 15 and 30-year cost of debt estimates , the actual cost rate for 20-year debt at the 16 time of issue could be closer to 7.0% than 6.1%. 17 18 With a debt cost closer to 7.0%, the actual debt coverage ratios (S&P’s Funds 19 From Operations Interest Coverage and DBRS’ Fixed Charge Coverage) could be 20 somewhat lower than indicated by the assumptions in the Application, depending 21 on the annual levels of the NEB’s multi-pipeline ROE. 22 23 V. BUSINESS RISK, CAPITAL STRUCTURE AND RETURN ON 24 EQUITY 25 26 A. Business Risk 27
provided for “unregulated” (e.g., merchant power) firms operating in the industry. 11 Based on RBC Capital Markets, New Issue Spread Indications, Power & Pipelines Weekly Review, November 25, 2004.
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1 Business risk analysis should be balanced. That is, it should recognize that there 2 are both risk mitigating and risk exacerbating factors12 that, as a whole, determine 3 the pipeline’s overall business risk profile. The following sets out both the 4 strengths and challenges that face MVP. 5 6 1. Key Strengths 7 8 The proposal that MVP is putting forth comprises various elements that mitigate 9 the investors’ risk, including: 10 11 a. Contracts covering 15-20 year terms. 12 13 MVP will offer firm service contracts for a period of either 15 or 14 20 years. Shippers contracting for firm service will pay a demand 15 charge based on their contract demand quantity. Relief from 16 payment of demand charges is very limited. 17 18 b. Full cost-of-service regulation. 19 20 Differences between the annual forecast and actual costs will be 21 accrued in deferral accounts and either refunded to or recovered 22 from shippers through tolls in the subsequent year. 23 24 c. Allowed ROE that floats with changes in interest rates. 25 26 For the first ten years of the pipeline’s operation, MVP proposes to 27 automatically adjust the allowed ROE from year-to-year based on 28 the NEB’s multi-pipeline ROE formula, maintaining an ROE 29 increment of 2.21% above the multi-pipeline ROE. At the end of
12 In DBRS’ terminology, “Strengths” and “Challenges”.
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1 ten years, the ROE will be determined either by negotiation with 2 shippers or through an application to the Board.
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1 2 d. No construction cost risk. 3 4 Shippers will be responsible for all costs incurred and approved by 5 the Board for inclusion in rate base. 6 7 e. Creditworthy shippers. 8 9 Shippers will be required to have, and maintain, a minimum S&P 10 bond rating of BBB, or, if below the minimum, provide additional 11 assurances of performance to the pipeline. The anchor shippers on 12 the pipeline are subsidiaries of major energy producers 13 (ConocoPhillips Canada (North) Limited, ExxonMobil Canada, 14 Imperial Oil Limited and Shell Canada Limited), whose parent 15 companies have strong credit ratings. 16 17 2. Key Challenges 18 19 The key challenges, arising primarily from the greenfield nature of the pipeline, 20 include: 21 22 a. The reliance on a single untested supply basin. There is no 23 production history; the resource base may be less than forecast. 24 25 b. The risks that (i) insufficient gas will be available after the initial 26 contracts expire or (ii) that firm commitments will not replace the 27 initial contracts when they expire (with significant capital left 28 unrecovered). These risks reflect the interplay of supply and 29 demand. 30
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1 The risk of insufficient gas subsequent to the expiry of the initial 2 contracts arises from both the physical availability of gas from the 3 basin, as well as the economics of producing it as compared to 4 other sources of gas or alternative forms of energy that may be 5 available at that time. Even if all forecasts are met, the distance of 6 the Mackenzie Delta gas supply from potential markets results in 7 higher supply costs than those delivered by pipelines which have 8 access to conventional gas sources. Higher than expected costs of 9 exploration and production due to unanticipated circumstances 10 (e.g., weather, reservoir performance) may weaken the economics 11 of production, rendering the gas uncompetitive and stranding the 12 reserves. 13 14 An integral component of the risk facing MVP is the demand for 15 the gas, which may shift from levels currently being forecast due to 16 factors such as energy policy and environmental constraints. 17 Lower than expected demand could impair the economics of 18 further basin development. The risks and uncertainties associated 19 with demand are outlined in the NCI-EEA Team assessment of the 20 long-term market need for the Mackenzie Delta gas; filed in CPCN 21 Volume 2 to the Application.13 22 23 c. There are risks that the pipeline project may be deferred beyond 24 the forecast start-up date, or potentially never proceed, which put 25 at risk the significant ($400 million) project development costs. 26 27 Delays resulting from the complicated regulatory environment that 28 MVP faces are quite possible. Permitting, unsettled land claims, 29 ensuring sufficient Aboriginal consultation, and potential legal 30 challenges are significant risks to the project. For the MVP, being
13 “Mackenzie Valley Pipeline Market Demand, Supply, and Infrastructure Analysis.”
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1 unable to gain regulatory approval and permits on schedule are a 2 key risk. Other events that could potentially delay the project 3 include material and equipment supply availability or disruptions, 4 changes in the market and supply/demand fundamentals for natural 5 gas, or labour availability. During construction, delays may occur 6 due to the short construction season resulting from the extreme 7 northern climate. 8 9 If the MVP schedule does not meet its current completion targets 10 for any of the reasons above, the MVP could potentially be further 11 deferred by other large projects, such as the Alaska Gas Pipeline,14 12 due to competition for construction personnel or equipment and 13 other market factors relating to supply, demand or downstream 14 pipeline capacity. 15 16 Examples of circumstances that could cause the project not to 17 proceed at all include the failure to obtain the required regulatory 18 approvals or the approvals given will contain conditions that are 19 unacceptable to the proponents. 20 21 d. Other risks, while perhaps not as proximate for the investors, 22 include the operation of a pipeline in a remote location in 23 conjunction with the competitive risks that the distance from 24 potential markets creates. Over the initial term(s) of the contracts, 25 the risks to the pipeline are limited by the existence of long-term 26 contracts that obligate the shippers to pay demand charges 27 covering the total cost of service. 28
14 The Alaska Gas Pipeline would have access to an estimated 36 TCF of gas (compared to MVP’s 12 TCF, as per the Application for the Approval of the Mackenzie Valley Pipeline, CPCN Volume 2, GLJ Final Gas Resources and Supply Study, page 3), and has recently moved forward by U.S. legislation which provides
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1 However, the actual costs borne by the shippers during the initial 2 terms of their contracts will determine the netbacks from the gas 3 that they deliver. The netbacks, in turn, will be a key factor in the 4 level of commitment to the further supply basin development that 5 is required to ensure the pipeline is utilized in its later years, and 6 the remaining capital recovered. A reduction in capacity 7 commitments in the later years of the pipeline would raise the rates 8 to remaining shippers, which in turn, would lead to deteriorating 9 economics for those shippers. 10 11 3. Relative Business Risk of MVP 12 13 The greenfield characteristics of MVP are the critical factors that distinguish 14 MVP from the established NEB-regulated pipelines accessing a well-developed 15 WCSB. The greenfield risk factors, which are principally related, directly or 16 indirectly, to the level and cost of supply, support the conclusion that the return 17 required by investors to commit capital to MVP is higher than that awarded to the 18 established NEB-regulated gas pipelines that are subject to the multi-pipeline 19 ROE. 20 21 4. Business Risk of MVP and Stand-Alone Capital Structure 22 23 On a stand-alone basis, if MVP were being financed in its entirety in the public 24 markets or if the NEB multi-pipeline ROE were expected to apply to MVP, the 25 greenfield characteristics of the pipeline, combined with the magnitude of the 26 investment, would require a higher equity component than that of the established 27 pipelines, whose regulated common equity ratios are in the range of 30-33%. An 28 equity ratio in the range of 40-45% would, in my view, approximately equate the 29 total investment risk of MVP and a mature NEB-regulated gas pipeline. In other
for an expedited review of the project, allows for accelerated amortization (seven years vs. the normal fifteen) and the U.S. government debt guarantees for 80% of the first $18 billion of financing.
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1 words, at a 40-45% common equity ratio, the same equity rate of return would be 2 applicable to MVP as would be applicable to a “benchmark” established Canadian 3 gas pipeline with a 30-33% common equity ratio. 4 5 A 40-45% common equity ratio, while higher than those allowed for the 6 established NEB-regulated gas pipelines, lies within the range of allowed capital 7 structures of other mature regulated Canadian firms, including oil pipelines 8 regulated by the NEB. Examples of regulated capital structures in the range of 9 40-45% include: 10 AltaGas Utilities 41.0% ATCO Pipelines 43.5% FortisBC 40.0% Maritime Electric 40.0% (legislated minimum) Newfoundland Power 44.5% PPAs (Alberta) 45.0% TransMountain (TMP) 45.0% 11
12 5. ROE Compensation for Financial Risk 13 14 For the reasons outlined in MVP’s response to Board IR.1.13, the proponents 15 have opted for a deemed common equity ratio of 30%. Consequently, the higher 16 financial risk borne by equity investors (relative to the stand-alone equity ratio of 17 40-45% that would be compatible with the multi-pipeline ROE) needs to be 18 compensated for in the equity rate of return. 19 20 The reasonableness of MVP’s proposed equity return at a 30% equity ratio can be 21 estimated as follows. First, the pre-tax cost of capital for MVP at a 40-45% 22 common equity ratio (mid-point of 42.5%) is estimated based on the following 23 assumptions: 24
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1 1. Cost of long-term debt equal to MVP’s assumed 6.1% (for a 20-year 2 issue). 3 4 2. Tax rate of 36.12%. 5 6 3. NEB multi-pipeline ROE for 2005 as a proxy for the cost of equity 7 (9.46%). 8 9 The pre-tax cost of capital under those assumptions is: 10 Proportion Cost Rate Weighted Component Debt 57.5% 6.1% 3.51% Equity 42.5% 9.46% 4.02% 7.53% Tax Allowance 2.27% Pre-Tax Cost 9.80% 11 12 13 Second, if the equity ratio is reduced from 42.5% to 30% and assuming that the 14 pre-tax cost of capital remains unchanged at 9.80%, the resulting return on equity 15 can be estimated as follows: 16 17 Pre-Tax Cost of Capital 9.80% 18 Less: Weighted Interest Component (6.1% x 70%) 4.27% 19 20 Pre-Tax Weighted Equity Component 5.53% 21 Less: Tax @ 36.12% 2.00% 22 23 After-Tax Weighted Equity Component 3.53% 24 25 ROE (After-Tax Equity Component ÷ 30% Equity 26 Ratio) 11.78% 27 28 The indicated ROE of 11.78% is very close to the 11.67% ROE that would apply 29 to MVP based on the 2005 multi-pipeline ROE (9.46% + 2.21% ROE increment).
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1 2 VI. MVP vs. ESTABLISHED NEB-REGULATED GAS PIPELINES 3 4 A further way of testing the reasonableness of the proposed increment to the ROE 5 is to subject MVP and its proposed financial parameters to a risk positioning 6 analysis using the findings of the NEB in its decisions underpinning the multi- 7 pipeline cost of equity. The risk positioning methodology, in conjunction with the 8 equity risk premium test, is used to assess the cost of equity for projects or firms 9 that are not publicly traded.15 10 11 As suggested earlier, the objective is to position the target investment between at 12 least two comparators or “fence posts” whose costs of capital can be directly 13 estimated, and then to infer the target project’s cost of capital based on its total 14 business and financial risk relative to that of the “fence posts”. To test the 15 reasonableness of MVP’s proposed equity risk premium using this approach, I 16 used conclusions found in RH-2-94 (Multi-Pipeline Cost of Capital Decision) and 17 in RH-4-2001 (TransCanada PipeLines). These conclusions, in effect, represent 18 the status quo with respect to allowed returns and capital structure. In both 19 decisions, the NEB relied primarily on the Capital Asset Pricing Model (CAPM) 20 for estimating the pipeline cost of equity. The simple CAPM adjusts the risk 21 premium for the equity market portfolio for the relative risk of the relevant 22 company. To evaluate MVP in this context, the two “fence posts” are an 23 established gas pipeline, as the lower risk comparator, and the equity market 24 portfolio as the higher risk comparator. 25 26 The three key conclusions drawn by the NEB are as follows: 27 28 1. In RH-4-2001, the NEB concluded that there was no reason to alter the 29 allowed return that had been determined by the automatic adjustment
15 As indicated earlier in this report, this methodology was used to set ROEs and capital structures for the “heritage” generation facility PPAs in Alberta in 1999 (Decision U99113).
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1 formula originally established in RH-2-94. Based on that formula, the 2 benchmark pipeline’s return on equity for 2005, at a forecast long Canada 3 yield of 5.55%, is 9.46%. The “all in” (including flotation costs) risk 4 premium above the forecast 30-year Canada for a “benchmark” pipeline 5 subject to the automatic adjustment formula is thus 3.91 percentage points 6 in 2005. 7 8 2. The NEB also concluded in RH-4-2001 that the market risk premium is 9 5.5% - 6.0%, and, 10 11 3. In RH-4-2001, the Board determined that the business risk faced by 12 TransCanada PipeLines (TCPL) had increased since RH-2-94, warranting 13 an increase in the allowed common equity ratio from 30% to 33%. 14 15 Using the Board’s findings with respect to the market risk premium and the 16 benchmark pipeline risk premium, one can infer the relative risk adjustment, or 17 investment risk beta, implied in the Board’s decisions. Assuming some small 18 increment in the “all in” multi-pipeline risk premium for flotation costs (15 basis 19 points),16 the implied investment risk beta, can be estimated at approximately 20 0.65.17 21 22 The investment risk (or levered) beta of a security reflects both business and 23 financial risk. To test the reasonableness of MVP’s proposed financial parameters 24 (capital structure plus ROE) using risk positioning in conjunction with the CAPM, 25 it is necessary to segregate the business risk and financial risk components of the 26 beta. 27
16 The flotation cost allowance was estimated from the conclusions drawn by the NEB in RH-2-94. 17 “All-In” Pipeline Risk Premium less Flotation Costs = 3.91% - .15% =0.65 Market Risk Premium 5.75%
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1 An estimated business risk beta (referred to as an asset beta) can be extracted 2 from the investment risk beta using what has been called the Hamada equation.18 3 4 The equation is as follows: 5 6 Investment Risk Beta =Asset Beta x (1 + Debt (1 – tax rate)) 7 Equity 8 9 The business risk, or asset, beta can thus be estimated at 0.28, assuming the 10 marginal income tax rate used by MVP in its filing (36.12%) and the 67% debt 11 ratio approved by the Board in RH-4-2001. 12 13 The asset beta for the equity market portfolio (or alternatively, for an average risk 14 stock) can also be estimated. The equity market portfolio, by definition, has an 15 investment risk beta of 1.0. The equity market, as proxied by the S&P/TSX 16 Composite, has an average common equity ratio of approximately 57%,19 and 17 thus has materially more equity (less financial risk) than an established NEB- 18 regulated gas pipeline. The equity market’s asset beta (based on book value 19 capital structures) can be estimated at 0.67, as shown below: 20 21 1.0 = Asset Beta x (1 + .43 (1 - .3612)) 22 .57 23 Asset Beta = 0.67 24 25 Using its proposed 30% common equity ratio and 2.21% ROE increment (relative 26 to the NEB’s multi-pipeline ROE), MVP’s implied asset beta can then be 27 estimated in the same manner as was done for an established NEB-regulated gas 28 pipeline.
18 The Hamada equation is derived from the synthesis of the CAPM and the Modigliani-Miller theory of capital structure with corporate income taxes, as set forth in Robert S. Hamada, “The Effect of the Firm’s Capital Structure on the Systematic Risk of Common Stock”, Journal of Finance, Volume 27, May 1972. 19 Fiscal year end 2003 capital structures weighted by market value of equity as of month-end October 2004.
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1 2 First, MVP’s implied investment risk beta is estimated as follows: 3 4 MVP Risk Premium20 - Flotation Cost Allowance21 = 6.12% - .15% = 1.04 5 Market Risk Premium 5.75% 6 7 MVP’s corresponding asset beta is estimated as 0.42: 8 9 MVP Investment Beta 1.04 = Asset Beta (1 + .70 (1 - .361)) 10 .30 11 Asset Beta = 0.42 12 13 When the asset betas of an established gas pipeline, MVP, and the equity market 14 portfolio are positioned on a risk spectrum (see below), MVP is approximately 15 one-third of the way between the lower business risk fence post, a benchmark 16 established gas pipeline, and the upper fence post, the equity market portfolio. In 17 other words, MVP’s asset, or business risk, beta places it closer to a benchmark 18 established gas pipeline than to an average business risk entity. 19 20 Benchmark 21 Gas Pipeline MVP Mid-Point TSX/S&P Composite 22 23 24 Asset Beta 0.28 0.42 0.475 0.67 25 26 27 In light of its unique greenfield risks (including supply, start-up and operating 28 risks), MVP’s risk position (within the context of the NEB’s findings) relative to 29 the benchmark established gas pipeline and the average risk stock is not
20 Based on the multi-pipeline 2005 risk premium of 3.91% plus MVP’s proposed 2.21% ROE increment. 21 Based on the premise that MVP’s flotation cost allowance is identical to that included the multi-pipeline ROE, and thus already accounted for in the “benchmark” pipeline risk premium.
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1 unreasonable. The implied asset beta of 0.42, resulting investment risk beta of 2 1.04 (at a 30% equity ratio), and corresponding risk premium are reasonable.22 3 4 5 VII. MVP vs. NEW CANADIAN PIPELINE COMPARATORS 6 7 In order to demonstrate to the fullest extent the reasonableness of MVP’s 8 proposed combined capital structure and ROE, proxies whose circumstances are 9 as similar as possible to MVP should be used. As indicated earlier, the proposed 10 2.21% ROE increment needs a quantitative context through which to demonstrate 11 its reasonableness. However, reliance on other pipelines as proxies needs to be 12 tempered with the following recognitions: 13 14 1. There is no single pipeline or other regulated entity that faces identical risk 15 circumstances to MVP. 16 17 2. The allowed capital structure and ROE for any individual comparator 18 represent values that can be used to establish a range of reasonableness. 19 Each reflects the result of a qualitative assessment of the business risks of 20 that entity relative to other regulated entities, in conjunction with capital 21 market conditions at the time the financial parameters were set. No single 22 approved return/capital structure value can be viewed as “the right” 23 number. 24 25 3. ROEs and capital structures set as a result of a settlement may reflect 26 multiple considerations on the part of the parties to the settlement.
22 As noted earlier, the risk positioning approach was relied upon by the IAT in Alberta to estimate the incremental return required to invest in a long-term cost of service-type Power Purchase Arrangement relative to that applicable to an integrated electric utility. The IAT-recommended and EUB-approved result was a 45% common equity ratio and a 4.50 percentage point equity risk premium (compared to a 40% common equity ratio and 3.50 percentage point risk premium that had previously been allowed by the AEUB for an integrated electric utility). The approved capital structure and ROE for the PPAs comprise a similar total return on capital as MVP’s requested capital structure and equity risk premium. The
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1 Nevertheless, the end result remains an indicator of what was viewed by 2 the parties and the NEB as a fair and reasonable return and capital 3 structure for a pipeline. 4 5 A. Maritimes and Northeast Pipeline 6 7 The closest Canadian pipeline proxy to MVP is Maritimes and Northeast Pipeline 8 (M&NP). M&NP, like MVP, is a greenfield single line, high-pressure pipeline, 9 accessing a new supply basin. Its markets are in part undeveloped (New 10 Brunswick, Nova Scotia), but are largely in New England, where the markets are 11 competitive and the demand for new sources of natural gas is high. The pipeline 12 has Firm Service Agreements, which average 15 years, with creditworthy 13 shippers, and a 20-year backstop, which obligates ExxonMobil to pay for 14 unsubscribed capacity. 15 16 M&NP is currently operating with an allowed ROE of 13.0% and a common 17 equity ratio of 25%. These levels were approved by the NEB in GH-6-96 18 (December 1997). In its decision, the Board focused on M&NP’s greenfield 19 supply and operating conditions, stating: 20 21 “Concerning the cost of equity capital, the Board agrees with the Joint 22 Review Panel’s statement, ‘ …M&NPP can be viewed as having the same 23 business risk as other Group 1 pipelines.’ However, the circumstances 24 faced by M&NPP are substantially different from those faced by other 25 pipelines regulated by the Board. It is a greenfield project, its only 26 sources of gas are new and untested fields, it will be serving an untested 27 market in Canada, and it is facing significant competition for its anchor 28 market in the U.S. northeast. Consequently, the Board approves the 29 combination of a 25 percent common equity portion coupled with a 13 30 percent rate of return on that equity as appropriate in the circumstances of 31 this pipeline.” 32
comparability of the total return on capital approved for the PPAs and that proposed by MVP provides, in itself, a further indicator that MVP’s proposal lies in a zone of reasonableness.
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1 At the time of approval , the corresponding NEB formula ROE for established gas 2 pipelines was 10.67%, suggesting a differential risk premium for M&NP of 2.3 3 percentage points. M&NP’s 13.0% ROE was recently retained as part of a 4 settlement covering 2004-2006 (TG-4-2003). On average from the first year of 5 operation (1999) through 2005, M&NP’s actual incremental equity risk premium 6 has averaged close to 3.4 percentage points above the multi-pipeline ROE (13.0% 7 versus 9.7%). In relation to the 2005 NEB formula ROE of 9.46%, M&NP’s 8 ROE increment is now over 3.5 percentage points as compared to MVP’s 9 proposed 2.21 percentage points. While the M&NP settlement addressed multiple 10 issues in addition to ROE, the agreed-to ROE, in conjunction with M&NP’s 25% 11 equity ratio, remains one indicator of the reasonableness of MVP’s proposal. 12 13 In sum, MVP’s proposed ROE is reasonable when compared to M&NP’s allowed 14 return recognizing: 15 16 1. The fact that, in the absence of market data specific to greenfield utilities, 17 M&NP’s initial applied-for ROE was partly judgemental; 18 19 2. The initial ROE was accepted as reasonable by the NEB in large part due 20 to the greenfield nature of the pipeline; and, 21 22 3. The recent M&NP settlement retained the 13% ROE in a lower interest 23 rate environment. 24 25 B. Alliance Pipeline 26 27 A second, but somewhat less comparable, proxy for MVP is Alliance Pipeline, 28 whose initial target ROE was 12% on a 30% common equity ratio (GH-3-97, 29 November 1998). Similar to MVP, Alliance has a full cost-of-service tolling 30 methodology and long-term contracts. Alliance has 15 year take-or-pay contracts 31 and minimal throughput risk. Alliance has a diversified shipper base, with 19 32 shippers representing close to 70% of the pipeline capacity, the preponderance of 33 which are investment grade.
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1 2 The key differences between MVP and Alliance are: 3 4 1. Alliance’s allowed ROE is locked in for 15 years, while MVP’s will vary 5 with changes in interest rates; 6 7 2. Alliance took construction cost risk, which could have potentially reduced 8 its allowed ROE to 10.0% (or increased it to 14%). In fact, the allowed 9 ROE was reduced to 11.3% on the Canadian segment of the pipeline; and 10 11 3. Alliance’s supply basin is the established Western Canada Sedimentary 12 Basin. As such, it is not a true greenfield operation, but rather a new 13 competitive pipeline accessing a developed basin. 14 15 Based on Alliance’s target return of 12.0% and the NEB-formula pipeline ROE 16 for 1998 of 10.21%, the expected value of Alliance’s ROE increment at the time 17 can be estimated at approximately 1.8% relative to the then-applicable multi- 18 pipeline ROE. Using Alliance’s current allowed ROE of 11.3% and the 1998- 19 2005 average NEB multi-pipeline return of 9.7%, the actual value of Alliance’s 20 ROE increment has been 1.6% above the multi-pipeline return (11.3% - 9.7%). 21 MVP’s proposed 2.21% ROE increment is not unreasonable relative to that of 22 Alliance, given MVP’s risks associated with being a greenfield pipeline. 23 24 VIII. MVP vs. CANADIAN GREENFIELD GAS LDC OPERATIONS 25 26 For purposes of putting MVP’s proposed 2.21% ROE increment in a broader 27 “greenfield” perspective, it is useful to compare the combined capital structures 28 and ROE allowed for greenfield Canadian local gas distribution companies 29 (LDCs) and their mature peers.23 The objective of this comparison is, in the first 30 instance, to demonstrate the magnitude of the total return on capital that has been
23 It bears noting that the difference in the allowed rate of return on rate base for the typical major gas LDC and the typical mature gas pipeline in Canada is minimal when compared to the “greenfield” differential within the LDC industry. The average allowed common equity ratio for the major LDCs (rate base over $1 billion) is 36%; the corresponding average for gas pipelines of similar size (TCPL, NGTL and Westcoast) is 33%. There is no measurable difference in allowed ROE. The difference in regulated capital structures between gas LDCs and gas pipelines translates into a differential in total return of less than 50 basis points.
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1 allowed by regulators for greenfield risk. Further, it provides an additional 2 perspective on the relative size and reasonableness of the ROE increment 3 proposed by MVP. Specifically, the greenfield Canadian LDCs and the 4 established NEB-regulated pipelines supply a further set of “fence posts” between 5 which MVP’s proposed capital structure and ROE can be positioned. Those 6 “fence posts”, which effectively encompass the full spectrum of return on capital 7 within the regulated gas industry in Canada, provide an additional indicator of the 8 reasonableness of MVP’s proposed capital structure and ROE. 9 10 The best examples of Canadian greenfield LDCs are Enbridge Gas New 11 Brunswick and Heritage Gas (Nova Scotia).24 Both have the benefit of revenue 12 deficiency accounts, which permit the deferral (and rate base treatment) of 13 unrecovered costs (including the allowed return) during the developmental years, 14 with the deficiency to be recovered through rates once the market is established. 15 16 The allowed returns on equity and capital structure for the two greenfield LDCs 17 are as follows: 18 19 Equity Ratio Equity Return 20 EGNB 50% 13% 21 Heritage Gas 45% 13% 22 23 A representative ROE for a mature gas distributor, given the level of interest rates 24 at the time the regulatory approvals for EGNB (6/2000) and Heritage Gas 25 (2/2003) were issued, was about 9.75%,25 which indicates an incremental risk 26 premium for the greenfield LDCs’ of 3.25 percentage points relative to the mature 27 LDCs. However, this comparison does not recognize the lower financial risk of 28 the greenfield LDCs, as reflected in their higher common equity ratios of 45-50%.
24 Others of less relevance are Inuvik Gas, due to its light-handed regulation, and Terasen Gas (Vancouver Island), formerly Centra B.C., due to a high level of government support. 25 The average of allowed returns for major Canadian gas distributors for test years 2000 and 2003 were 9.83% and 9.73%, respectively.
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1 By comparison, the average common equity ratio for all mature gas distributors in 2 Canada is approximately 35%. 3 4 To allow a comparison between the greenfield and mature LDCs that accounts for 5 both differences in capital structure and ROE, the ROEs for the former can be 6 restated based on a capital structure similar to the average for mature LDCs’, i.e., 7 35% common equity. 8 9 Assuming the pre-tax cost of capital remains unchanged with the changes in 10 capital structure, the corresponding ROE for EGNB at 35% equity would be 11 approximately 16.0% and for Heritage Gas, 15.0%, implying ROE increments 12 relative to mature Canadian LDCs in the neighbourhood of five to six percentage 13 points. (See Section C, Schedule 1 attached for calculation). 14 15 An alternative approach would be to rely on the average finding derived from 16 theoretical and empirical analysis of capital structures. Eugene F. Brigham, Louis 17 C. Gapenski, and Dana A. Aberwald, “Capital Structure, Cost of Capital, and 18 Revenue Requirements”, Public Utilities Fortnightly, January 8, 1987 summarizes 19 various relevant theoretical and empirical studies. In summary, these studies 20 indicate that the cost of equity rises (falls) by approximately 7-14 basis points for 21 every percentage point increase (reduction) in the debt ratio, or approximately 10 22 basis points (0.1 percentage point) on average. Using a “rule of thumb” of a 0.1 23 percentage point increase in ROE for every one percentage point increase in debt 24 ratio adds an ROE increment of 1.0-1.5 percentage points to the approximately 25 3.25 percentage point ROE increment approved for the greenfield LDCs, 26 indicating an ROE for the greenfield LDCs 4.25-4.75 percentage points higher 27 than that of a mature LDC of similar equity ratio.
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1 2 With its contractual commitments and greater access to developed markets for 3 natural gas, MVP’s greenfield risks are less than those of the LDCs, and, thus, a 4 lower risk premium above an established benchmark is required to induce the 5 required long-term commitment of capital. MVP’s proposed ROE increment of 6 2.21% relative to the allowed ROE for an established gas pipeline represents less 7 than 50% of the incremental return approved for the greenfield LDCs relative to 8 their mature peers. When evaluated in the context of the full risk spectrum that 9 the regulated Canadian gas industry encompasses, MVP’s proposed ROE and 10 capital structure are within the zone of reasonableness. 11 12 IX. SUMMARY OF RETURN ON CAPITAL FOR CANADIAN 13 PIPELINES AND LDCs 14 15 The following table is intended to provide a summary perspective on MVP’s 16 proposed capital structure and return on equity relative to the Canadian pipelines 17 and LDCs. Since there are differences in both the capital structures and ROEs 18 across these entities, a return on capital was calculated for each to allow an 19 “apples to apples” comparison. For this purpose, the cost of debt was assumed to 20 be identical26 for each of the entities, to allow the focus to be solely on the 21 impacts of the capital structure and allowed ROE on the allowed return on capital.
26 The cost of debt was assumed to be 6.1%, equal to the forecast cost of 20-year debt included in MVP’s application to the Board.
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1 2 3 Table 2 COMPARISON OF RETURNS ON CAPITAL FOR CANADIAN PIPELINES AND LDCs
Return Cost Return on Debt Equity of Debt on Equity Capital TransCanada Main Line 67.0% 33.0% 6.1% 9.46% 7.21%
Oil Pipelines (TMP) 55.0% 45.0% 6.1% 9.46% 7.61%
Alliance Pipeline 1/ 70.0% 30.0% 6.1% 11.3% 7.66%
Mackenzie Valley Pipeline 70.0% 30.0% 6.1% 11.7% 7.77%
M&NP 75.0% 25.0% 6.1% 13.0% 7.83% Heritage Gas 55.0% 45.0% 6.1% 13.0% 9.21% Enbridge Gas New Brunswick 50.0% 50.0% 6.1% 13.0% 9.55% 4 5 1/ 7.87% based on initial target ROE of 12.0%. 6 7 The table demonstrates that MVP’s proposed capital structure and ROE would 8 place it squarely in the center of the comparators by ranking, but materially closer 9 to the established pipelines than to the greenfield LDCs on a total return basis. 10 11 X. MVP vs. U.S. GAS PIPELINES 12 13 Since there are few greenfield utilities in Canada from which to draw direct 14 quantitative comparisons with MVP’s proposed financial parameters, some 15 perspective on the reasonableness of the size of the risk premium proposed by 16 MVP can be gained by looking at the returns for regulated pipelines elsewhere in 17 North America. The very nature of a greenfield operation means there are no 18 market data for proxies that can provide a direct measure of its cost of equity.
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1 Consequently, the reasonableness of the requested return and capital structure 2 should be inferred from available quantitative data. 3 4 For this purpose, the rates of return for U.S. gas pipelines provide a further 5 comparator. In the context of a risk positioning exercise, the U.S. pipelines would 6 serve as the higher risk “fence post” and a benchmark established NEB-regulated 7 pipeline would serve as the lower risk “fence post”. Within these two boundaries, 8 MVP’s risk/return profile can be positioned and the reasonableness of its capital 9 structure and ROE proposals evaluated. 10 11 The objective in using U.S. gas pipelines is: 12 13 1. to recognize that capital available for investment (either direct or 14 portfolio) in regulated assets is not constrained to the Canadian market; 15 16 2. to recognize that investment in U.S. gas pipelines is an alternative to 17 investment in Canadian gas pipelines, with due respect to differences in 18 risk profiles; and, 19 20 3. to serve as an additional quantitative marker to evaluate the 21 reasonableness of MVP’s proposed capital structure and return on equity. 22 23 The use of U.S. gas pipelines as “comparators” requires recognition of the 24 differences between their operating and regulatory environment and that of 25 Canadian gas pipelines, established or greenfield. Comparison of the returns for 26 U.S. gas pipelines to MVP’s proposal needs to take account of the following:
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1 2 1. U.S. gas pipelines, as an industry, face a higher level of competitive risks 3 than Canadian pipelines; 4 5 2. U.S. pipelines file rate cases less frequently than Canadian pipelines, and 6 are explicitly encouraged to negotiate settlements; 7 8 3. While both Canadian and U.S. gas pipelines use the full fixed variable 9 method for setting firm transportation rates, U.S. pipelines are at greater 10 risk of earnings shortfalls due to uncommitted capacity. U.S. pipelines 11 have greater freedom to discount rates, but discounting is undertaken at 12 the risk of the pipeline; 13 14 4. U.S. pipelines operate on normalized taxes, which tend to improve their 15 interest coverage ratios relative to Canadian pipelines’. Use of normalized 16 taxes lessens the risk of underrecovery of taxes payable in future years 17 when competitive conditions may impose constraints on raising rates to 18 recover those costs; 19 20 5. U.S. pipelines operate with less financial risk than Canadian pipelines. 21 The typical allowed equity ratio for U.S. pipelines is in the range of 50- 22 55%, versus 30-35% for Canadian pipelines. 23 24 On balance, the total risk of U.S. gas pipelines, including the financial risk 25 embodied in the capital structure, would be viewed by an equity investor as 26 exceeding that of established Canadian gas pipelines. The returns on equity for 27 U.S. gas pipelines would thus, in conjunction with their corresponding capital 28 structures, provide an upper fence post for evaluation purposes, relative to the 29 NEB-approved multi-pipeline ROE and capital structures. 30
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1 In assessing the capital structures and allowed returns of the U.S. gas pipelines, I 2 first determined whether any sensitivity to a particular risk class could be 3 detected. To test for any differentials, I reviewed the capital structures and 4 returns for the universe of major gas pipelines as well as three sub-groups. Those 5 three sub-groups included: (i) the largest pipelines (those with a rate base in 6 excess of $500 million); (ii) those pipelines that deliver Canadian gas from the 7 border to U.S. markets; and (iii) the gas pipelines considered by S&P to face the 8 lowest business risk (business risk score of “3” and below). The latter two sub- 9 groups should, in principle, be more closely aligned with MVP than the universe 10 of U.S. gas pipelines. 11 12 As shown on Section C, Schedule 2, the average common equity ratio27 and rate 13 of return on equity have been approximately 50% and 12.4% respectively for the 14 largest gas pipelines, compared to 56-58% and 12.3% for all the major (“Form 2”) 15 pipelines. For the ten pipelines that deliver gas from the Canadian border to U.S. 16 markets, some of which are project-financed,28 the average common equity ratio 17 is approximately 42-47%, with a common equity return of 12.3%. For the 18 pipelines with the lowest S&P business risk profile scores, the average common 19 equity ratio is close to 60% and the corresponding ROE is 12.4%, both well above 20 those proposed by MVP.29
27 The reported common equity ratios are not necessarily those that have been allowed for ratemaking purposes. The FERC has generally limited allowed equity ratios to 65% or less. 28 The typical ROE allowed by FERC for the recourse rates of new project-financed pipelines has been 14.0% on equity ratios in the 25-30% range (the most recent being Horizon Pipeline, Cross Bay Pipeline, Island East, Millenium Pipeline and Georgia Strait Crossing). 29 In setting allowed ROEs, the FERC has an objective of encouraging investment in infrastructure assets. That goal can be seen in its regulation of inter-state electric transmission facilities. The FERC policy provides ROE incentives to a base ROE of approximately 12.4% for participation in RTOs, independent transmission companies (ITCs) or new facilities (grid enhancement projects). The ROE-incentive adders range from 50 basis points for participation in an RTO to 150 basis points for divestiture of assets to an ITC that participates in an RTO. The incentive risk premium for new facilities is 100 basis points.
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1 2 To compare the returns for U.S. gas pipelines to MVP’s proposed return, both 3 capital structure and ROE need to be considered. The impact of both capital 4 structure and rate of return on equity can be captured by using the overall return 5 on capital (or return on rate base). For this purpose, I assumed that the cost of 6 new long-term debt was the same for all pipelines, Canadian and U.S., at 6.1%.30 7 Table 3 below shows the range of returns on rate base for the various Canadian 8 and U.S. pipeline comparators. 9 10 While the results for the sub-groups of U.S. gas pipelines do not reveal any clear 11 risk-related differentiation, they do suggest that the “upper fence post” for the gas 12 pipeline industry is a rate of return on capital of approximately 9.0-10.0%, 13 compared to 7.5% for a benchmark Canadian pipeline. 14 15 At MVP’s proposed 30% common equity ratio and risk premium, its indicated 16 return on capital of 7.77% is similar to M&NP’s and Alliance’s and lies well 17 below the mid-point of the range of returns on capital that comprise the spectrum 18 of business risk with the gas pipeline industry in North America. Based on the 19 level of MVP’s business risks relative to the two “fence posts” of the gas pipeline 20 business risk spectrum, its proposed capital structure and return on equity are 21 within a reasonable range.
30 The assumption of equal debt costs permits focus on the interaction of capital structure and ROE only. The cost of a long-term A rated utility issue in the U.S. would be similar to that in Canada.
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1 2 Table 3 3 RETURN ON CAPITAL COMPARISON FOR SELECTED CANADIAN AND U.S. PIPELINES AND GAS DISTRIBUTORS
Return Cost Return on on Debt Equity of Debt Equity Capital
TransCanada PipeLines 67.0% 33.0% 6.1% 9.5% 7.21%
Oil Pipelines (TMP) 55.0% 45.0% 6.1% 9.5% 7.61%
Alliance Pipeline 1/ 70.0% 30.0% 6.1% 11.3% 7.66%
Mackenzie Valley Pipeline 70.0% 30.0% 6.1% 11.7% 7.77%
M&NP 75.0% 25.0% 6.1% 13.0% 7.83%
Canada to U.S. Pipelines 53.0% 47.0% 6.1% 12.3% 9.02%
Heritage Gas 55.0% 45.0% 6.1% 13.0% 9.21%
U.S. Pipelines with Rate Base > $500 million 48.0% 52.0% 6.1% 12.4% 9.38%
Enbridge Gas New Brunswick 50.0% 50.0% 6.1% 13.0% 9.55%
U.S. Pipelines 40.0% 60.0% 6.1% 12.6% 10.00% with S&P Business Risk ≤ 3 4 5 1/ 7.87% based on initial target ROE of 12.0%. 6
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1 2 XI. DEEMED COST OF DEBT 3 4 A. Principles 5 6 The project proponents propose to use a deemed cost of debt for MVP that 7 reflects the actual cost that APG will incur for its debt-related participation in the 8 project. It is my understanding that the cost of raising the debt will be based on 9 the characteristics of the pipeline investment, and thus should approximate the 10 cost of debt that would have been incurred had the pipeline had been wholly 11 project-financed. The question, therefore, is whether it is appropriate to deem as 12 debt 70% of the funds provided by the other proponents and at the same cost as 13 the actual debt raised by APG. 14 15 In my opinion, if the cost of the debt issued to project-finance a portion of the 16 pipeline reflects the risks of the pipeline, and is similar to the cost that would be 17 incurred if MVP were wholly project-financed, then it is appropriate to deem as 18 debt 70% of the funds provided by the other participants and at the actual cost of 19 the debt raised by APG. This approach is consistent with the stand-alone 20 principle that the NEB follows. 21 22 The argument in support of such an approach basically is that the cost of debt to 23 MVP should be established on a similar basis to its equity return – it should 24 reflect the cost that would be incurred if it were raising the debt on the basis of its 25 own business and financial risks, not those of the various participants. 26 27 B. Canadian Precedents 28 29 There are various precedents in Canadian regulation for the cost of debt to be set 30 at a deemed rate. In some instances, a deemed cost rate has been applied because 31 the actual capital structure and the capital structure determined to be reasonable
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1 for regulatory purposes are materially different. Thus, deemed debt may be 2 required to equate the rate base and the corresponding deemed capital structure. 3 In that case, a notional cost of debt must be applied to the imputed deemed debt 4 in order to match the rate base and the capital structure. 5 6 The more salient precedents are those for which the parent’s own cost of debt was 7 not viewed to be appropriate for the specific regulated operations. 8 9 The following are the most relevant to MVP’s circumstances: 10 11 1. In 1992, several of the debt issues used by Nova Corporation in part to 12 finance the Alberta pipeline operations were deemed by the AEUB to have 13 a lower cost rate than the actual rate incurred. The Board’s rationale was 14 that the pipeline operations would have been able to raise the debt on a 15 stand-alone basis at a lower cost. The Board correspondingly imputed a 16 deemed capital structure designed to be compatible with Nova Gas 17 Transmission’s stand-alone business risks.31 18 19 2. Alberta Natural Gas’ B.C. pipeline operations operated with a deemed 20 capital structure and a deemed long-term cost of debt in the early 1990s, 21 because the parent’s own debt structure was comprised largely of short- 22 term debt. The deemed cost of long-term debt was estimated as the yield 23 on long Canada bonds plus a spread for an A-rated utility bond. 24 25 3. Enbridge Inc., which raises debt on behalf of some of its regulated 26 subsidiaries, has been allowed by certain subsidiaries’ regulators to charge 27 these subsidiaries rates that differ from Enbridge Inc.’s own debt cost. 28 (The rates charged by Enbridge to its affiliates are then recovered from the 29 affiliates’ customers.) For example: 30
31 AEUB Decision E92086, October 1992.
Page 40 of 42 SECTION B
1 (a) Enbridge Gas New Brunswick, a greenfield gas distribution utility, 2 is allowed to recover a cost of debt which is equal to Enbridge 3 Inc.’s own cost of debt plus 100 basis points. 4 5 (b) Enbridge Inc. has been allowed to charge its small Québec gas 6 distribution subsidiary, Gazifère, a rate of 150 basis points above 7 long Canadas for long-term debt (which represented a premium of 8 between 50 to 100 basis points over Enbridge’s own cost in the 9 mid- to late-1990’s). The rate charged was based on independent 10 external estimates of the stand-alone cost of debt to Gazifère. 11 12 4. Heritage Gas, the greenfield Nova Scotia gas distributor, is allowed to use 13 a deemed stand-alone cost of debt, unrelated to its parents’ (SaskEnergy 14 and AltaGas Services) own costs of debt until such time as Heritage issues 15 debt in its own name. 16 17 5. The Ontario Energy Board (OEB) has subscribed to the general principle 18 that “it is appropriate for a utility to borrow funds for an affiliate and to 19 charge a banking spread for the service, so long as the total interest paid 20 by the affiliate is no greater than would occur if the affiliate raised the 21 funds itself.” (The Consumers’ Gas Company, E.B.R.O. 464, July 19, 22 1990.) Consumers Gas was permitted to charge its then-affiliate, 23 Tecumseh Gas Storage, a premium of 50 basis points above its own short- 24 term borrowing rate. 25 26 C. Conclusions on Deemed Debt 27 28 The use of a deemed cost of debt for the entire deemed debt of MVP (70% 29 of rate base) equal to the actual cost of the project-financed portion is 30 reasonable. It is consistent with the stand-alone principle and has 31 analogous precedents in Canada which support its implementation.
Page 41 of 42 SECTION B
1 2 XII. CONCLUSIONS 3 4 Based on my analysis, I have concluded that MVP’s proposed deemed capital structure 5 and return on equity are reasonable. 6 7 The proposed capital structure is in line with those maintained by other Canadian 8 pipelines, and, in conjunction with the proposed ROE, should be adequate to support a 9 stand-alone debt rating in the A category. 10 11 MVP’s proposed ROE increment of 2.21% relative to the NEB’s multi-pipeline ROE is 12 reasonable in light of its greenfield risks. Since those risks have not been compensated 13 for in the capital structure, the compensation for the risk taken by investors needs to be 14 reflected in the rate of return on equity. 15 16 MVP’s combined capital structure and return on equity are reasonable when positioned 17 within the range of the returns on capital for lower and higher risk comparators in the 18 Canadian and U.S. regulated gas industry; they are also reasonable when compared to 19 those of other new/greenfield Canadian gas projects. 20 21 MVP’s proposal to deem 70% of the pipeline financing as debt, and to deem the cost of 22 the debt at the actual cost to APG, are consistent with the stand-alone principle of 23 regulation and is supported by precedents in a number of Canadian regulatory 24 jurisdictions.
Page 42 of 42 Section C Schedule 1
Cost of Capital for Canadian Greenfield Local Gas Distribution Utilities
Enbridge Gas New Brunswick Allowed Cost of Capital June 2000
Tax Rate 35% T/(1-t) 54%
Proportion Cost Weighted Cost Debt /1 50.0% 8.18% 4.1% Common Equity 50.0% 13.00% 6.5% Total 100% 10.6%
Tax Allowance Common Equity* t/(1-t) 3.5%
Pre-Tax Cost of Capital 14.1%
New Weighted Cost of Debt at 65% Debt Ratio 5.3% New Weighted Pre-Tax Cost of Equity at 35% Equity Ratio 8.8% New Weighted After-Tax Cost of Equity (= 8.8%/(1+.54)) 5.7%
Indicated Equity Return at 35% Common Equity
Proportion Cost Weighted Cost Debt 65.0% 8.18% 5.3% Common Equity 35.0% 16.29% 5.7% Total 100.0% 11.0%
/1 Debt rate for EGNB is June 2000 CBRS A-rated 30 yr bond plus 100 bp as per decision
Heritage Gas Allowed Cost of Capital February 2003
Tax Rate 35% T/(1-t) 54%
Proportion Cost Weighted Cost Debt /1 55.0% 8.75% 4.8% Common Equity 45.0% 13.00% 5.9% Total 100% 10.7%
Tax Allowance Common Equity* t/(1-t) 3.2%
Pre-Tax Cost of Capital 13.8%
New Weighted Cost of Debt at 65% Debt Ratio 5.7% New Weighted Pre-Tax Cost of Equity at 35% Equity Ratio 8.1% New Weighted After-Tax Cost of Equity (= 8.1%/(1+.54)) 5.3%
Indicated Equity Return at 35% Common Equity
Proportion Cost Weighted Cost Debt 65.0% 8.75% 5.7% Common Equity 35.0% 15.09% 5.3% Total 100% 11.0%
/1 Debt rate from decision. Section C Schedule 2 RETURNS ON EQUITY AND CAPITAL STRUCTURES FOR U.S. NATURAL GAS PIPELINES
US Pipeline from Canadian Net Utility Return on Equity Border to US Plant Equity Ratio S&P Business Profile Market ($Millions) 17-May-04 2-Dec-04 Algonquin Gas Transmission 11.33 47.1$ 810 Alliance /1 10.70 39.1 Yes$ 1,613 ANR Pipeline 12.25 60.8 4 3$ 1,146 Colorado Interstate Gas Company 12.72 64.7 3 2$ 715 Columbia Gas Transmission /2 12.98 63.8 3 3$ 1,819 Columbia Gulf Transmission Company /2 12.98 63.8 3 3$ 267 Destin Pipeline Company 13.25 100.0$ 384 Dominion Transmission (CNG) 10.67 56.0$ 1,373 East Tennessee Natural Gas 12.78 57.3$ 455 El Paso Natural Gas 12.16 39.0 4 4$ 1,805 Equitrans, L.P. 10.00 67.8$ 166 Florida Gas Transmission 13.45 51.0 2 2$ 1,748 Gas Transmission Northwest /1 12.20 48.9 2 Yes$ 1,046 Great Lakes Gas Transmission 13.25 46.1 Yes$ 1,141 Gulf South Pipeline Company 10.27 100.0$ 383 Gulfstream Natural Gas System 14.00 30.0$ 1,468 Iroquois Gas Transmission 12.38 38.1 3 Yes$ 1,083 Kern River Gas Transmission 13.25 21.8 4 3$ 1,872 Kinder Morgan Interstate /3 13.71 40.3 5$ 483 Maritimes and Northeast Pipeline 14.00 36.3 Yes$ 745 Mojave Pipeline Company 11.27 100.0$ 130 National Fuel Gas Supply 11.30 46.3 6 7$ 383 Natural Gas Pipeline of America /3 13.71 40.3 5$ 1,136 Northern Border Partners 12.00 35.0 3 4 Yes$ 1,590 Northern Natural Gas Company 12.50 50.2 3 2$ 1,352 Northwest Pipeline 11.50 70.5 3 2 Yes$ 1,292 Panhandle Eastern Pipe Line 13.25 44.6 4 3$ 442 Portland Natural Gas Transmission 12.50 40.0 Yes$ 422 Questar Pipeline 11.75 45.1 3 3$ 391 Sabine Pipe Line LLC 12.10 100.0$ 23 Sea Robin Pipeline Company 12.10 100.0$ 42 Southern Natural Gas 12.00 55.9 4 2$ 1,443 Southern Star Central 11.41 69.0 3$ 505 Tennessee Gas Pipeline 12.71 46.5 4 3$ 2,482 Texas Eastern Transmission 12.75 57.1 4 3$ 2,321 Texas Gas Transmission 10.65 67.8 3$ 598 Trailblazer Pipeline Company 13.71 40.3$ 114 TransColorado Gas Transmission 13.71 40.3$ 266 Transcontinental Gas Pipe Line 12.40 71.5 3 2$ 3,100 Transwestern Pipeline 11.50 100.0 5 4$ 657 Trunkline Gas (CMS) 11.92 69.1$ 263 Vector Pipeline 12.75 45.0 Yes$ 637 Viking Gas Transmission 10.19 72.0 Yes$ 86 Williston Basin 12.36 64.4$ 190 Wyoming Interstate Company 12.50 72.7$ 320 Average 12.3 58.1 4 3$ 905 Median 12.4 55.9 4 3$ 657
Average Net Plant Over $500 Million 12.3 52.1 4 3$ 1,366 Median Net Plant Over $500 Million 12.4 48.9 4 3$ 1,292
Average CDN Border to US MKT. 12.1 47.1 3 3 $ 965 Median CDN Border to US MKT. 12.4 42.5 3 3 $ 1,112
Average BP <= 3 (December 2, 2004) 12.4 59.6 3 3$ 1,184 Median BP <= 3 (December 2, 2004) 12.4 58.9 3 3$ 1,115
1/ Equity ratios calculated from data reported on FERC Form 2 pages 112 and 113 (Comparative Balance Sheet) 2/ Business profile scores for Columbia Energy Group 3/ Business profile scores for Kinder Morgan Inc.
Note: The returns on equity and capital structures represent the 2003 values reported on FERC Form 2 page 218a (Computation of Allowance for Funds used During Construction Rates.) As per the FERC instructions, the return on equity is the rate granted in the last rate proceeding or, if that is not available, the average rate earned during the preceding 3 years.
Source: 2003 FERC Forms 2. Standard and Poor's, Utilities and Perspectives (May 17, 2004) and U.S. Utility Power Ranking List (December 2, 2004). SECTION D
QUALIFICATIONS OF KATHLEEN C. McSHANE
Kathleen McShane is a Senior Vice President and senior consultant with Foster Associates, Inc., where she has been employed since 1981. She holds an M.B.A. degree in Finance from the University of Florida, and M.A. and B.A. degrees from the University of Rhode Island. She has been a CFA charterholder (since 1989).
Ms. McShane worked for the University of Florida and its Public Utility Research Center, functioning as a research and teaching assistant, before joining Foster Associates. She taught both undergraduate and graduate classes in financial management and assisted in the preparation of a financial management textbook.
At Foster Associates, Ms. McShane has worked in the areas of financial analysis, energy economics and cost allocation. Ms. McShane has presented testimony in more than 125 proceedings on rate of return and capital structure before federal, state, provincial and territorial regulatory boards, on behalf of U.S. and Canadian telephone companies, gas pipelines and distributors, and electric utilities. These testimonies include the assessment of the impact of business risk factors (e.g., competition, rate design, contractual arrangements) on capital structure and equity return requirements. She has also testified on various ratemaking issues, including deferral accounts, rate stabilization mechanisms, excess earnings accounts, cash working capital, and rate base issues. Ms. McShane has provided consulting services for numerous U.S. and Canadian companies on financial and regulatory issues, including financing, dividend policy, corporate structure, cost of capital, automatic adjustments for return on equity, form of regulation (including performance-based regulation), unbundling, corporate separations, regulatory climate, income tax allowance for partnerships, change in fiscal year end, treatment of inter- corporate financial transactions, and the impact of weather normalization on risk.
Page 1 of 6 SECTION D
Ms. McShane was principal author of a study on the applicability of alternative incentive regulation proposals to Canadian gas pipelines. She was instrumental in the design and preparation of a study of the profitability of 25 major U.S. gas pipelines, in which she developed estimates of rate base, capital structure, profit margins, unit costs of providing services, and various measures of return on investment. Other studies performed by Ms. McShane include a comparison of municipal and privately owned gas utilities, an analysis of the appropriate capitalization and financing for a new gas pipeline, risk/return analyses of proposed water and gas distribution companies and an independent power project, pros and cons of performance-based regulation, and a study on pricing of a competitive product for the U.S. Postal Service. She has also conducted seminars on cost of capital for regulated utilities, with focus on the Canadian regulatory arena.
Publications, Papers and Presentations
■ “Utility Cost of Capital Canada vs. U.S.”, presented at the CAMPUT Conference, May 2003.
■ “The Effects of Unbundling on a Utility’s Risk Profile and Rate of Return”, (co- authored with Owen Edmondson, Vice President of ATCO Electric), presented at the Unbundling Rates Conference, New Orleans, Louisiana sponsored by Infocast, January 2000.
■ Atlanta Gas Light’s Unbundling Proposal: More Unbundling Required?” presented at the 24th Annual Rate Symposium, Kansas City, Missouri, sponsored by several Commissions and Universities, April 1998.
■ “Incentive Regulation: An Alternative to Assessing LDC Performance”, (co- authored with Dr. William G. Foster), presented at the Natural Gas Conference, Chicago, Illinois sponsored by the Center for Regulatory Studies, May 1993.
■ “Alternative Regulatory Incentive Mechanisms”, (co-authored with Stephen F. Sherwin), prepared for the National Energy Board, Incentive Regulation Workshop, October 1992.
Page 2 of 6 SECTION D
■ “Market-Oriented Sales Rates and Transportation Services of U.S. Natural Gas Distribution Companies”, (co-authored with Dr. William G. Foster), published by the IAEE in Papers and Proceedings of the Eighth Annual North American Conference, May 1987.
■ “Canadian Gas Exports: Impact of Competitive Pricing on Demand”, (co- authored with Dr. William G. Foster), presented to A.G.A.’s Gas Price Elasticity Seminar, February 1986.
■ “Marketing Canadian Natural Gas in the U.S.”, (co-authored with Dr. William G. Foster), published by the IAEE in Proceedings: Fifth Annual North American Meeting, 1983.
Page 3 of 6 SECTION D
Expert Testimony/Opinions on Rate of Return & Capital Structure
Alberta Natural Gas 1994 Alberta Power/ATCO Electric 1989, 1991, 1993, 1995, 1998, 1999, 2000, 2003 AltaGas Utilities 2000 Ameren (CIPS and & Union Electric) 2000 (3 cases), 2002 (3 cases) 2003 ATCO Gas 2000, 2003 ATCO Pipelines 2000, 2003 BC Gas 1992, 1994 Bell Canada 1987, 1993 Benchmark Utility Cost of Equity (British Columbia) 1999 Canadian Western Natural Gas 1989, 1998, 1999 Centra Gas B.C. 1992, 1995, 1996, 2002 Centra Gas Ontario 1990, 1991, 1993, 1994, 1996 Dow Pool A Joint Venture 1992 Edmonton Water/EPCOR Water Services 1994, 2000 Enbridge Gas Distribution 1988, 1989, 1991-1997, 2001, 2002 Enbridge Gas New Brunswick 2000 FortisBC 1995, 1999, 2001, 2004 Gas Company of Hawaii 2000 Gaz Metropolitain 1988 Gazifère 1993, 1994, 1995, 1996, 1997, 1998 Generic ROE Proceeding in Alberta (ATCO Utilities and AltaGas) 2003 Heritage Gas 2002 HydroOne/Ontario Hydro Services Corp. 1999, 2000 Illinois Power 2004 Insurance Bureau of Canada (Newfoundland) 2004
Page 4 of 6 SECTION D
Laclede Gas Company 1998, 1999, 2001, 2002 Maritimes NRG (Nova Scotia) and (New Brunswick) 1999 Multi-Pipeline Cost of Capital Hearing (National Energy Board) 1994 Natural Resource Gas 1994, 1997 Newfoundland & Labrador Hydro 2001, 2003 Newfoundland Power 1998, 2002 Newfoundland Telephone 1992 Northwestel, Inc. 2000 Northwestern Utilities 1987, 1990 Northwest Territories Power Corp. 1990, 1992, 1993, 1995, 2001 Nova Scotia Power Inc. 2001, 2002 Ozark Gas Transmission 2000 Pacific Northern Gas 1990, 1991, 1994, 1997, 1999, 2001 Platte Pipeline Co. 2002 St. Lawrence Gas 1997, 2002 Southern Union Gas 1990, 1991, 1993 Stentor 1997 Tecumseh Gas Storage 1989, 1990 Telus Québec 2001 TransCanada PipeLines 1988, 1989, 1991 (2 cases), 1992, 1993 TransGas and SaskEnergy LDC 1995 Trans Québec & Maritimes Pipeline 1987 Union Gas 1988, 1989, 1990, 1992, 1994, 1996, 1998, 2001 Westcoast Energy 1989, 1990, 1992 (2 cases), 1993 Yukon Electric Co. Ltd./Yukon Energy 1991, 1993
Page 5 of 6 SECTION D
Expert Testimony/Opinions on Other Issues
Client Issue Date
Caisse Centrale de Réassurance Collateral Damages 2004 Enbridge Gas New Brunswick AFUDC 2004 Heritage Gas Deferral Accounts 2004 ATCO Electric Carrying Costs on Deferral Account 2001 Newfoundland & Labrador Hydro Rate Base, Cash Working Capital 2001 Gazifère Inc. Cash Working Capital 2000 Maritime Electric Rate Subsidies 2000 Enbridge Consumers Gas Principles of Cost Allocation 1998 Enbridge Consumers Gas Unbundling/Regulatory Compact 1998 Maritime Electric Form of Regulation 1995 Northwest Territories Power Rate Stabilization Fund 1995 Canadian Western Natural Gas Cash Working Capital/ 1989 Compounding Effect Gaz Metro/ Cost Allocation/ 1984 Province of Québec Incremental vs. Rolled-In Tolling
Page 6 of 6 NATIONAL ENERGY BOARD
Hearing Order GH-1-2004
ADDITIONAL WRITTEN EVIDENCE
CAPITAL MARKETS EVIDENCE RELATED TO THE MACKENZIE VALLEY PIPELINE
submitted on behalf of The Mackenzie Valley Pipeline
Richard D. Falconer
CIBC World Markets
Vice Chairman
CIBC World Markets Inc. January 10, 2005
Table of Contents
1.0 Introduction ...... 3 1.1 Qualifications...... 3 1.2 Purpose of Testimony...... 3 1.3 Bases of Testimony...... 4
2.0 Conclusions...... 5
3.0 Key Investment Risks from a Capital Markets Perspective ...... 8 3.1 Greenfield Project Risks ...... 8 3.2 Natural Gas Supply Risk from the Mackenzie Delta ...... 10 3.3 Natural Gas Demand and Supply...... 11 3.4 Competitiveness ...... 12 3.5 Recontracting and Investment Recovery Risk ...... 13 3.6 Diversification...... 13 3.7 Refinancing Risks ...... 14 3.8 Liquidity Risk ...... 14 3.9 Summary ...... 14
4.0 Expected Equity Returns...... 16 4.1 Significance of the Pipeline and Utility Sector in Canada ...... 16 4.2 Historical Total Equity Returns in the Pipeline and Utility Sector ...... 17 4.3 Expected Total Equity Returns From Publicly Traded Pipeline Companies...... 21 4.4 Comparable Regulated Pipeline Equity Returns...... 22 4.5 Actual versus Requested ROEs ...... 22 4.6 Reasonableness of the MVP’s Requested Returns...... 22
5.0 Capital Structure...... 24 5.1 Trends in Credit Ratings ...... 24 5.2 Canadian Debt Market Overview...... 25 5.3 Reasonableness of Requested Capital Structure...... 27
6.0 Appendix A...... 30 Page 3 of 32
1 1.0 Introduction
2 1.1 Qualifications
3 My name is Richard D. Falconer and I am a Vice Chairman of CIBC World 4 Markets Inc. (“CIBC World Markets”). I have senior management and client coverage 5 responsibilities for CIBC World Markets’ worldwide investment banking activities. The 6 Investment Banking division at CIBC World Markets is one of the largest such groups 7 in Canada, serving clients with respect to debt and equity financings, financial advice, 8 expert testimony and merger and acquisition advice. A significant part of my 9 responsibilities involves advising major Canadian companies regarding capital 10 structure and the debt and equity markets. I am in regular contact with corporate 11 issuers, bond and stock analysts, investors and other capital markets participants.
12 I have appeared before the Alberta Energy and Utilities Board, the Canadian 13 Radio-television and Telecommunications Commission, the Nova Scotia Utility and 14 Review Board and the Ontario Energy Board. My academic background, employment 15 history and related activities are set forth in Appendix A.
16 1.2 Purpose of Testimony
17 This evidence is being presented at the request of the Mackenzie Valley Pipeline 18 Proponents (the “Proponents”) in connection with the filing of additional evidence in 19 conjunction with the original filings with the National Energy Board (“NEB”) in 20 October 2004. I have been asked to comment on the reasonableness, from the capital 21 markets perspective, of the 2.21% ROE increment over the NEB multi-pipeline rate of 22 return (this is assumed to equate to a 11.77% ROE based on the NEB’s formula for 2004) 23 and the 70% / 30% deemed debt / equity capital structure being requested by the 24 Proponents for the Mackenzie Valley Pipeline (“MVP”). Page 4 of 32
1 1.3 Bases of Testimony
2 In order to assess, from the capital markets’ perspective, the reasonableness of 3 the returns and capital structure being requested, I have considered the following:
4 • The key investment risks associated with the MVP and how they compare 5 with other regulated pipelines in Canada;
6 • Historical and expected equity returns in the pipeline and utilities sector;
7 • The equity returns and capital structures for other regulated pipelines and 8 utilities; and
9 • Recent trends in credit quality and returns, and the implications for the 10 appropriate capital structure.
11 I have also focused my efforts on reviewing the MVP as a stand-alone 12 investment, and not as a subsidiary or separate initiative of a larger financial entity, 13 such as one of the Proponents. The stand-alone review is how an investor would assess 14 the risks, returns and financing considerations for the MVP. Assessing the MVP as part 15 of a larger entity would not permit an investor to properly discern the risks specifically 16 attributed to the MVP.
17 Finally, I have relied on my experience in the capital markets from the 18 perspective of both investment banking and securities research. The source for my 19 financial and industry-related data is primarily from published financial reports and 20 other respected industry sources. Page 5 of 32
1 2.0 Conclusions
2 The conclusions I have drawn from my assessment are:
3 • The risks associated with investing in the MVP would be significant and 4 exceed the risks of the more established regulated pipelines in Canada;
5 • The primary risks of the MVP from a capital market’s perspective include: 6 o Unproven supply basin; 7 o Risks involved in the development, construction and operation of a 8 greenfield project of this magnitude in a very remote location; 9 o Risks of competing sources of supply, or lower than expected demand; 10 o Risk of erosion in the long-term economic competitiveness of the MVP; 11 o Recontracting risk at the end of the term of the initial transportation 12 agreements, and not being able to fully recover the capital invested; 13 o Diversification risk; 14 o Refinancing risk; and 15 o Liquidity risk;
16 • The pipeline and utilities sector is a significant and important part of the 17 Canadian capital markets, and has historically provided relatively consistent 18 and attractive returns to investors;
19 • The publicly traded pipeline and utility companies in Canada have generated 20 solid total equity returns over the last several years, comprised of both capital 21 appreciation and dividends. Total average annual returns have been 15.8% 22 over the last 10 years and 18.9% over the last five years. These are corporate 23 returns and investors in these companies not only benefit from the 24 diversification of assets these companies own and manage, but also the 25 investment liquidity they offer;
26 • While total returns to equity investors in this sector have been exceptional 27 over the last several years, augmented by the secular decline in interest and Page 6 of 32
1 inflation rates, expectations for total returns from publicly traded companies 2 in this sector over the longer term are likely to be lower (i.e. in the 9% to 10% 3 range based on the market’s expectation for dividend growth and current 4 dividend yields);
5 • Regulated equity rates of return ordered by the NEB in respect to other 6 greenfield pipelines in Canada have been in the range of 12% to 13%;
7 • Total equity returns in the U.S. sector have also been attractive. This is 8 important as Canadian investors can deploy their capital in any market, not 9 just in Canada. Data by the Pension Investment Association shows that 10 approximately 24% of the members’ equity investments are in the United 11 States, and 33% in countries outside of North America. In addition, the 12 investment in the United States has grown from approximately 18% in 1999 to 13 24% in 2003. U.S. investors have also invested capital in the Canadian 14 pipeline and utilities sector;
15 • On a stand-alone basis, the equity returns which would be realized from the 16 MVP could be lower than the requested ROE, primarily because a significant 17 portion of the initial capital invested is equity and any debt would likely be 18 retired sooner than the life of the pipeline;
19 • It is my opinion that the capital markets will perceive that the MVP faces 20 significant unique risks; therefore, investors would expect returns higher than 21 those from investing in publicly traded pipeline companies or directly in 22 more established regulated pipelines in North America. For the reasons cited 23 above, the 2.21% ROE increment being requested by the Proponents would 24 provide an overall return at the low end of the returns investors in the MVP 25 would expect;
26 • The requested capital structure of 30% equity is in line with other regulated 27 pipelines and should support credit ratios consistent with an ‘A’ credit rating, Page 7 of 32
1 provided the MVP proceeds as planned, performs financially as expected, 2 and receives the requested ROE equity increment; and
3 • A credit rating lower than A- may impact the ability of an issuer to access the 4 debt capital markets on a consistent basis and raise the amount of debt 5 required for this project on a stand alone basis, although the market for ‘BBB’ 6 issuers in Canada has grown over the last few years. A rating lower than A- 7 will also impact the cost of financing. Page 8 of 32
1 3.0 Key Investment Risks from a Capital Markets Perspective
2 An assessment of the principal investment risks of the MVP is key for 3 determining the reasonableness of the equity return and capital structure being 4 requested by the Proponents. I believe the primary risks, the capital markets will focus 5 on, many of which are interrelated, are as follows:
6 3.1 Greenfield Project Risks
7 At $4.5 billion, the MVP will be one of the largest projects undertaken in Canada 8 in recent history. The risks in investing in a greenfield project of this magnitude are 9 significant and vary depending on what stage the investment is made. For purposes of 10 discussing these risks, I have segmented the project into three specific phases:
11 • Pre-Development;
12 • Construction; and
13 • Start-up and Operating
14 Pre - Development Phase
15 The pre - development phase is defined as the period up to the date at which the 16 MVP receives the necessary approvals to proceed. Over this period, it is estimated that 17 the Proponents will have already invested approximately $400 million in the 18 development of the MVP. This will have occurred over several years with no assurance 19 that the project will proceed, or will proceed as planned. While companies take on 20 these risks with any major project, they only do so if they believe they will be 21 compensated for the risks taken. It is my opinion that the Proponents have experienced 22 considerable risk up to this point, especially when you consider the fact that a pipeline 23 from the Mackenzie Delta has been considered and evaluated during the last two to 24 three decades, and the fact that this is a complex regulatory process requiring numerous 25 approvals from many different agencies. Page 9 of 32
1 The absolute amount of money ($400 million) invested during this phase is also 2 relevant. Firms are typically willing to invest a small amount of money on a project that 3 is high risk, knowing that it will not significantly impact their overall returns from the 4 project if it is delayed or does not generate the returns expected. However, in this 5 situation, the amount of capital required during pre - development is so significant that 6 any deviation from plan could materially affect the economic returns from such a 7 project.
8 It is also important to note that the pre - development costs are being financed 9 by the Proponents. Given the Proponents’ capital structures, these pre - development 10 costs are more likely being financed with equity than a combination of debt and equity. 11 This is one of the reasons why the actual ROE being realized will be lower than the ROE 12 being requested. This is discussed in more detail in section 4.5.
13 Construction Phase
14 The risks associated with investing in the MVP, once it is under construction, 15 should be lower than those faced during the pre - development phase. However, the 16 risks are still very significant and include:
17 • Cost overruns: One of the key factors mitigating risk is that the shippers will 18 be responsible for any cost overruns. However, there is always a risk that 19 some or all of any cost overruns may not be approved by the NEB. This 20 would significantly impact the actual returns generated. The larger the 21 project, the greater the risk of this occurring. Even if all costs were allowed 22 by the NEB, any cost overruns would increase the tolls and therefore 23 adversely impact the long-term competitiveness of the MVP.
24 • Construction Delays: The MVP is expected to be constructed over a three 25 year period, compared to the much shorter construction period for both the 26 Maritimes and Northeast Pipeline (“M&NP”) and the Alliance Pipeline. The 27 seasonal window for pipeline construction in the Northwest Territories is Page 10 of 32
1 limited. There is a risk that the MVP could be delayed due to unforeseen 2 reasons such as weather, subsequent permitting and reviews, or delays in 3 obtaining equipment or materials. Any unforeseen delays could materially 4 prolong the project schedule and costs. If the costs of these delays are 5 deemed to be imprudent, the impact on overall returns could be significant.
6 Start-up and Operating Phase
7 The return expectations of the capital markets should decline even further once 8 the MVP is fully operational (i.e. investors will view investing in a pipeline already up 9 and running as a lower risk than investing in a project just being developed or 10 considered). Nevertheless, the risks for the MVP continue to be higher than most 11 mature regulated pipelines. These risks include gas supply, market demand, pipeline 12 competitiveness, recontracting and investment recovery, diversification, refinancing 13 and liquidity risks. These risks are discussed in more detail below.
14 3.2 Natural Gas Supply Risk from the Mackenzie Delta
15 The supply risks associated with the MVP are significant especially relative to 16 most other regulated pipelines in Canada. One issue relates to whether or not there is 17 sufficient gas to operate the pipeline more or less at 1.2 Bcfd over its life (i.e. 25 years). 18 The study conducted by Gilbert Laustsen Jung Associates Ltd. (“GLJ”) found that the 19 pipeline can only operate at the 1.2 Bcfd level for three years based on the discovered 20 onshore resource estimates, and for 18 years based on the discovered and undiscovered 21 resource size. 22 23 While the Proponents believe that the availability of pipeline transportation will 24 stimulate additional discoveries, there is no guarantee, at this time, that this will occur 25 or that additional resources will be discovered. Moreover there is no guarantee that 26 producers will continue to explore and develop gas prospects to use MVP beyond the 27 term of the existing transportation contracts if the netbacks prove less attractive than Page 11 of 32
1 the economics of developing other energy resources elsewhere. As a result, the risks of 2 investing in the MVP are significant as there can be no assurances that there will be 3 sufficient gas to fully recover the capital invested in the MVP.
4 Another issue relates to the fact that the Mackenzie Delta is an unproven supply 5 basin, and therefore there is uncertainty as to the amount of gas available. As more 6 drilling and exploration activity occurs, more will be known about the potential of the 7 basin. However, at this stage, the supply information is largely based on unproven 8 estimates only.
9 The NEB recognized the risk of an unproven supply basin in its decision for 10 M&NP. In that decision, the Board approved an ROE for M&NP of 13% on a capital 11 structure of 25% equity, in part because of the unproven supply, and the greenfield 12 nature of that project. The risk around supply for M&NP has also been and continues to 13 be an important consideration for the rating agencies and debt investors.
14 3.3 Natural Gas Demand and Supply
15 Navigant Consulting, Inc. and Energy and Environmental Analysis Inc. 16 (“Navigant/EEA”), in their report on the assessment of the long-term market need for 17 gas produced from the Mackenzie Delta region, reached the overall conclusion that the 18 gas markets in Canada and the U.S. support construction of the MVP. However, 19 Navigant/EEA also noted that the MVP is subject to a number of risks and 20 uncertainties, including:
21 • More rapid expansion of gas production in general, from traditional, existing 22 sources, could meet a larger share of future gas demand;
23 • Accelerated development of coalbed methane gas production in the Western 24 Canadian Sedimentary Basin (“WCSB”) could cause the region’s gas 25 production to grow more rapidly than expected;
26 • Slower industrial development could reduce Alberta gas demand; Page 12 of 32
1 • Rapid expansion of Liquified Natural Gas import capacity could lessen the 2 capacity of U.S. and Canadian markets to absorb Mackenzie Delta volumes 3 and lower gas prices throughout North America;
4 • Increases in the price of gas relative to oil and coal could encourage more 5 rapid development of lower cost energy supplies (e.g. coal), perhaps 6 facilitated by technological breakthroughs; and
7 • Changes in energy policy in Canada and the United States and technological 8 advances could promote alternate energy sources and thereby reduce the 9 market’s capacity to absorb Mackenzie Delta gas production.
10 3.4 Competitiveness
11 The market for natural gas is competitive. Although the MVP will be the only 12 natural gas pipeline transporting gas from the Mackenzie Delta, the MVP still faces 13 competition from other sources of gas or other energy sources. Any new pipeline could 14 offer transportation services that are more desirable to shippers because of location, 15 facilities or other factors. In addition, these pipelines could charge rates or provide 16 services to locations that result in greater net profit for shippers and thereby reduce the 17 competitiveness of the MVP.
18 For example, the proposed Alaska gas pipeline could compete directly with the 19 MVP. Recent legislation passed by U.S. congress, enhances the economics of the Alaska 20 gas pipeline by providing loan guarantees, tax breaks and accelerated permitting.
21 In addition, the long-term economic viability of the MVP is dependent on market 22 gas prices. If prices drop too low, netbacks to Mackenzie Delta producers could become 23 uneconomic, thereby impairing the long-term economics of the MVP. This will be 24 exacerbated if tolls are higher than projected due to any unrecovered cost overruns or 25 delays. Page 13 of 32
1 3.5 Recontracting and Investment Recovery Risk
2 MVP currently has commitments from the anchor shippers for firm 15 year and 3 20 year gas transportation quantities. While the shippers have the right to renew their 4 firm transportation service agreements beyond the primary terms of 15 and 20 years, 5 there is no guarantee that all or any of the shippers will renew at that time. If the 6 agreements are not renewed, or the number of shippers on the system is reduced, the 7 tolls paid by the remaining shippers and the Proponent’s ability to recover the capital 8 invested may be negatively impacted. While most pipelines face this risk, it is of greater 9 concern for pipelines serving a single unproven basin, where as discussed earlier, the 10 magnitude of gas resource is unknown and the relative economics, including higher 11 transportation costs, remain uncertain.
12 The tolls for the MVP are designed to recover 80% of the capital invested by year 13 20. In designing the toll, the Proponents took into consideration the need to establish 14 competitive tolls to ensure the long-term economic viability of the MVP. While the 15 Proponents have accepted the risk of not fully recovering their investment over the 15 16 to 20 year period, they should be compensated for taking on this risk. Based on the 17 earlier discussion on supply and demand, there is a risk as to whether or not the 18 pipeline owners will recover the remaining 20% of the investment, which equates to 19 approximately $900 million.
20 3.6 Diversification
21 Unlike many other pipelines, the MVP is currently underpinned by only a few 22 anchor shippers. While the anchor shippers have solid investment grade credits, any 23 material credit reduction in any one of these shippers could impact the credit quality of 24 the MVP on a stand alone basis. As a comparison, Alliance Pipeline is underpinned by 25 33 shippers and therefore a downgrade in any one shipper, while important, would not 26 have as significant an impact due to the greater diversification. Page 14 of 32
1 In addition to a greater number of shippers, many other regulated pipelines are 2 more diversified in terms of sources of supply. For instance, Alliance Pipeline is 3 dependent on the vast and proven WCSB where there are many companies discovering 4 and producing natural gas.
5 3.7 Refinancing Risks
6 The term of long-term debt for the MVP on a deemed stand alone basis would 7 likely be inside the initial terms of 15 and 20 years (weighted average of 16 years based 8 on the commitments by the anchor shippers) because of the risks around supply and 9 recontracting beyond year 20. As a result, MVP could face refinancing risks as the debt 10 matures.
11 3.8 Liquidity Risk
12 An investment in a single asset, such as the MVP, would be less liquid than an 13 investment in a highly liquid, publicly traded company. As a result, investors should 14 expect an increment for investing in a potentially less liquid entity.
15 3.9 Summary
16 To summarize, the MVP faces some unique risks that are more significant than 17 most other Canadian pipelines. In Figure 1, I have summarized my view of how the 18 market will assess the risks for MVP relative to the two most comparable NEB regulated 19 and recently constructed pipelines in Canada. Page 15 of 32
1 Figure 1: Relative Risk of MVP vs. Comparable Pipeline Projects
Risk Category MVP M&NP Alliance
Greenfield risk High Mod - High Mod Gas Supply High High Low - Mod Recontracting Risk High High Low - Mod Competition Mod - High Mod Low - Mod Market Demand Mod Mod Mod Diversification High High Low Overall High Mod - High Low - Mod ROE 11.77% 13.0% 12.0%1 ROE Increment2 2.21% 2.30% 1.80% Deemed Equity 30.0% 25.0% 30.0% Credit Rating DBRS N/A A A (low) S&P N/A A- BBB+
1 Alliance Pipeline was awarded 12.0% ROE but, due to cost overruns, the actual ROE was 11.3%. 2 Increment at time of decision to proceed. Page 16 of 32
1 4.0 Expected Equity Returns
2 4.1 Significance of the Pipeline and Utility Sector in Canada
3 The purpose of this section is to put into perspective the importance of the 4 pipeline and utility sector (the ”Sector”) in the Canadian capital markets. As will be 5 shown, the Sector is relatively large and liquid and well followed by the research 6 community. It also demonstrates that Canadian investors have alternatives to investing 7 in stand alone projects such as the MVP in that they can invest in much more liquid and 8 diversified publicly traded pipeline and utility companies.
9 The Sector in Canada, for purposes of this evidence, includes those companies 10 involved in natural gas, oil and electricity transmission and distribution3. While 11 companies in this group have different sets of assets, investors generally view them as 12 having somewhat similar risk profiles.
13 The Sector is an important part of the capital markets in Canada. In aggregate it 14 represents approximately 3.2% (as of December 31, 2004) of the S&P/TSX Composite 15 Index’ total market capitalization. In absolute terms, the combined market 16 capitalization of the Sector is $34.6 billion; this does not include U.S. companies with 17 significant pipeline and utilities investments in Canada (e.g. Duke Energy).
18 The Sector has continued to grow over the past several years, as companies have 19 executed on their growth plans and investors have been attracted to the overall total 20 equity returns offered by the Sector. As shown in Figure 2, the market capitalization of 21 the Sector has increased by almost $20 billion since 1999, representing an average 22 annual growth rate of over 17%.
3 Includes Canadian Utilities Ltd., Emera Inc., Enbridge, Inc., Fortis Inc., Terasen Inc., and TransCanada Corp. Page 17 of 32
1 Figure 2: Market Capitalization of the Sector4
$40 $34.6 $35 $31.8
$30 $26.1 $23.3 $25 $21.8 $20 $15.5 $15 (C$ Billions) (C$ $10 Market Capitalization Market $5
$0 1999 2000 2001 2002 2003 2004 2
3 The Sector in Canada is well followed by the equity and debt research 4 community, as shown in Figure 3. All of the Sector companies in Canada are covered 5 by several analysts (including coverage from U.S. research analysts), and by at least two 6 of the major rating agencies.
7 Figure 3: Equity Research and Rating Agency Coverage5
Number of Analysts Providing Number of Agencies Providing Company Equity Research Coverage Ratings
Canadian Utilities Ltd. 62 Emera Inc. 93 Enbridge Inc. 13 3 Fortis Inc. 92 Terasen Inc. 93 TransCanada Corp. 12 3
8 4.2 Historical Total Equity Returns in the Pipeline and Utility Sector
9 Pipeline and utility investments have traditionally attracted investors who desire 10 both the stability of dividends and the growth from an appreciation in the share price
4 As at December 31st of each year. 5 Source: Bloomberg. Page 18 of 32
1 (i.e. capital appreciation). Consequently, the combined market returns to equity 2 investors (“Total Equity Returns”) of dividend payments and earnings growth are key 3 reasons investors are attracted to this sector.
4 Earnings growth (“EPS growth”) has been significant during the last five years, 5 especially for the pipeline companies (i.e. Enbridge, TransCanada and Terasen). In 6 addition to growing their earnings and dividends, companies in the Sector provide 7 current dividend yields in the range of 3.0% to 4.6%.
8 Figure 4: EPS Growth and Dividend Yield historical performance
EPS6 Growth Dividend Growth Dividend Yield Company (1999-2003) (1999-2003) (Dec 31, 2004)
Canadian Utilities Ltd. 6.7% 4.4% 3.5% Emera Inc. 0.9% 0.9% 4.6% Enbridge Inc. 10.2% 9.4% 3.1% Fortis Inc. 17.4% 3.5% 3.3% Terasen Inc. 7.8% 7.3% 3.0% TransCanada Corp. 11.3% (0.9%) 3.9%
9 As shown in Figure 5, the Sector has provided equity investors with attractive 10 total returns over the last several years. During the last 10 years, the Sector has 11 generated an average annual total return of 15.8%. Total Equity Returns have been 12 even greater during the last five years.
13 As shown in Figure 5, the pipeline income funds have also provided investors 14 with significant Total Equity Returns during the last several years and investors in this 15 sector have come to expect a combination of dividend yield and capital growth.
6 “EPS” – Earnings per share from continuing operations. Page 19 of 32
1 Figure 5: Historical Total Equity Return Performance
Market Total Annual Return Capitalization Company (as of 31-Dec-04) 1 year 5 years 10 years (C$ millions)
Canadian Utilities Ltd. $3,457 8.2% 13.4% 14.4% Emera Inc. $2,086 12.8% 11.6% 11.4% Enbridge Inc. $10,004 15.2% 19.9% 20.2% Fortis Inc. $1,658 22.2% 22.4% 16.0% Terasen Inc. $2,907 19.5% 21.4% 20.0% TransCanada Corp. $14,440 11.4% 24.7% 12.9% Average 14.9% 18.9% 15.8%
Enbridge Income Fund7 $1,032 17.5% N/A N/A Fort Chicago Energy Partners L.P. $1,219 22.9% 16.7% N/A InterPipeline Fund $1,675 29.2% 25.9% N/A Pembina Income Fund $1,415 12.8% 25.9% N/A Average 20.6% 22.8% N/A
Philadelphia Utilities Index (U.S.) 26.0% 10.1% 9.7%
2 The U.S. sector has also generated solid total returns over the last twelve months 3 as represented by the Philadelphia Utilities Index in Figure 5. It is important to 4 consider the returns in the United States as Canadian investors can, and will, allocate 5 their capital to the markets and investments that generate the highest returns possible 6 for their level of risk tolerance. Canadian investors will also seek to diversify their 7 portfolios. One aspect of this is country diversification. This point is supported by the 8 fact that approximately 24% of all equity investments made by members of the Pension 9 Investment Association in Canada are in the U.S. (Figure 6). An additional 33% is 10 invested in countries outside of North America. Furthermore, the portion of equity 11 invested in the U.S. by the Canadian pension plans has grown from approximately 18% 12 in 1999 to 24% in 2003, as shown in Figure 7. U.S. companies and investors have also 13 invested capital into Canada. Examples of this include the acquisition of Westcoast 14 Energy by Duke Energy, and several of the Canadian publicly traded companies in the 15 Sector have shareholders based in the U.S.
7 The Enbridge Income Fund was founded June 30, 2003. Page 20 of 32
1 Figure 6: Canadian Pension Funds8 – Composition of Equity Investments 2003
Other Countries CDN Equities 33% 43%
U.S. Equities 24% 2
3 Figure 7: Canadian Pension Funds8 - Investments in U.S. Equities9
25% 24% 23% 22% 21% 20% 19% 18% 17% 16% 15% % of Equity Portfolio in U.S. Companies 1999 2000 2001 2002 2003 4
5 It is also useful to compare returns in other sectors as investors will also move 6 capital between sectors depending on past and expected performance. Figure 8 shows 7 how returns from the sector have compared to other sectors in Canada during the last 8 five years.
8 Source: Pension Investment Association of Canada. 9 As at December 31st of each year. Page 21 of 32
1 Figure 8: Total Equity Returns by Sector – 5 Year10
Energy 23.5% Consumer Staples 19.1% Financials 17.0% Utilities 16.9% Materials 7.6% Consumer Discretionary 3.4% Industrials 3.1% Telecom (1.9%) Healthcare (10.6%) Information Technology (29.6%)
(40%) (30%) (20%) (10%) 0% 10% 20% 30% Total Returns - Annualized 2
3 4.3 Expected Total Equity Returns From Publicly Traded Pipeline Companies
4 While total equity returns have been exceptional in the Sector during the last 5 several years due, in part, to a secular decline in inflation and interest rates, in the 6 future, equity investors are likely to expect lower returns in the range of 9% - 10% from 7 publicly traded pipeline companies. As shown in Figure 9, this will be comprised of 8 both earnings growth, and dividend yield. It is important to point out that these returns 9 are corporate returns for publicly traded companies, and not for higher risk single asset 10 investments such as the MVP. The publicly traded companies are of a lower risk as 11 they are more diversified, established, and offer significant investment liquidity.
12 Figure 9: Total Expected Equity Returns for Pipeline Companies
Expected EPS Current Dividend Total Expected Growth11 Yield Return TransCanada Corp. 4.7% 3.9% 8.6% Enbridge Inc. 6.4% 3.1% 9.5% Terasen Inc. 6.7% 3.0% 9.7%
10 Source: Bloomberg. It should be noted that Enbridge Inc. and TransCanada Corp. were moved from the Utilities sector to the Energy sector in April 2004; total return figure only reflects this transfer for the period April 2004 to current. 11 Source: Five year EPS growth rate as captured by Bloomberg from Analysts’ forecasts. Page 22 of 32
1 4.4 Comparable Regulated Pipeline Equity Returns
2 As was shown earlier in Figure 1, equity returns awarded to other pipelines that 3 are comparable to the MVP have been in the range of 12.0% to 13.0%.
4 4.5 Actual versus Requested ROEs
5 The actual equity returns which would be realized by the MVP could be lower 6 than the ROE being requested. This is due to a number of factors:
7 • The capital invested during the pre - development stages of the MVP is 8 arguably equity and not a combination of debt and equity;
9 • Any project debt is likely going to have to be repaid prior to the end of the life 10 of the MVP, especially if the pipeline is not fully recontracted at the end of the 11 primary terms of the initial transportation agreements. As a result, a material 12 portion of the equity investors’ return of capital will occur at the latter part of 13 the life of the pipeline; and
14 • If there are any disallowed cost over runs or recontracting risks.
15 4.6 Reasonableness of the MVP’s Requested Returns
16 From the capital markets’ perspective, it is my opinion that the 2.21% ROE 17 increment being requested by the Proponents is low considering the following:
18 • The MVP faces considerable risks, especially compared to other comparable 19 and established pipelines and publicly traded pipeline companies;
20 • Investors in the capital markets have been able to realize Total Equity Returns 21 in the mid to high teens from the Sector during the last ten years, and will 22 continue to expect attractive, albeit potentially lower, returns going forward. 23 It is also important to note that because most of these publicly traded 24 companies have several assets, and investors can move in and out of their 25 investment relatively easily, the risk of investing in the Sector at the publicly Page 23 of 32
1 traded level is low relative to a direct investment in a pipeline project such as 2 the MVP;
3 • Regulated equity rates of return awarded by the NEB in respect to other 4 greenfield pipelines in Canada have been in the range of 12.0% to 13.0%; and
5 • The actual equity returns realized are likely to be lower than the ROE 6 requested. Page 24 of 32
1 5.0 Capital Structure
2 5.1 Trends in Credit Ratings
3 An important objective of any entity in managing the composition of its capital 4 structure is to achieve a satisfactory credit quality for credit rating purposes, so that it 5 would be able to access the capital and the credit markets on reasonable terms. The 6 lower the rating, the less flexibility an entity has in accessing the markets at the right 7 time. Consequently, costs escalate and terms of the debt facilities are shorter and 8 covenants more restrictive.
9 In the United States and Canada, 2002 and 2003 were difficult credit years for 10 utility companies with broad exposure to unregulated assets. Rating agencies, such as 11 Standard and Poor’s, began to re-evaluate how they viewed the utilities industry, and 12 commenced a process of placing a number of Canadian utilities on negative watch, and 13 in some cases, ultimately downgraded their debt ratings. The same was true for utility 14 companies in the United States, which continued to feel repercussions from the 15 California electricity crisis and the Enron situation.
16 While the downward rating trend has moderated considerably, outlooks in the 17 U.S. utilities sector continue to have a decidedly negative tone. At the present time, 38% 18 of outlooks are negative, largely because financial and credit measures remain 19 pressured, 6% are positive, and 55% are stable.
20 In Canada, the majority of the companies in this sector were downgraded during 21 the last few years. More recently, however, credit ratings have stabilized as companies 22 have improved their balance sheets and credit ratios by paying down debt from net free 23 cash flow and asset sales. The changes in credit ratings for each of the Canadian 24 companies are shown in Figure 10. Page 25 of 32
1 Figure 10: Selected Utility and Pipeline Issuer S&P Corporate Credit Ratings
July 2001 Current S&P Business Profile
Canadian Utilities Ltd. A+ (Stable) A (Stable) N/A Emera Inc. A-(Stable) BBB+ (Stable) 4 Enbridge Inc. A (Stable) A- (Stable) 2 Fortis Inc. A- (Stable) BBB+ (Negative) 4 Terasen Inc. BBB+ (Stable) BBB (Stable) 3 TransCanada Corp.12 A- (Stable) A- (Negative) 3 Selected Municipal Electric Utilities13 EPCOR Utilities Inc. A- (Stable) BBB+ (Stable) N/A Hamilton Utilities Corp. A+ (Stable) A (Stable) N/A Toronto Hydro Corp. A (Positive) A- (Stable) N/A
2 5.2 Canadian Debt Market Overview
3 Cost of Debt Funding
4 Bond ratings are the single most important factor in credit assessments and 5 influence the pricing of fixed income securities and bank credit terms. Typically, the 6 lower the credit rating, the more difficult it is to access the debt capital markets and the 7 higher the cost to borrow money. As evidenced by Figure 11, the 10-year spreads on 8 ‘BBB’ rated utility bonds are higher than the yield for ‘A’ rated utility bonds.
9 Figure 11: Indicative 10-Year Spreads for Canadian Utility Issuers
Indicative 10-Year Spread (bps) S&P Rating (As of 31-Dec-04)
A (low) 70 BBB (high) 78 BBB (mid) 87 BBB (low) 105
10 It is important to note, however, that the cost of borrowing can vary for 11 companies with the same credit rating, depending on the investors’ perceived risk of
12 Current credit and business profile ratings are for TransCanada PipeLines Ltd. 13 Original ratings for the Ontario Municipal Electric Utilities are from 2002, when these ratings were first issued by S&P. Page 26 of 32
1 the company. Therefore, while the market utilizes the rating agency’s ratings as a broad 2 benchmark, bond investors and the capital markets ultimately ascribe a definitive risk 3 assessment to the company, resulting in the actual cost of borrowing.
4 Debt Market Access and Capacity
5 Raising long-term debt in the public markets is a function of the credit quality of 6 the issuer, the market’s capacity to absorb new debt issues, and the forecasted stability 7 in cash flows of the issuer, resulting in their ability to meet their interest and principal 8 payment obligations. For issuers who are in the ‘BBB’ rating category, it has historically 9 been more difficult to raise long-term debt in the Canadian market, and there have been 10 times when securities were not well received. As a result, a company with a ’BBB‘ 11 rating may have to access the capital markets more frequently and on terms less 12 favourable than an ’A‘ rated company. This potentially makes the company more 13 susceptible to financial market conditions and overall refinancing risks.
14 Figure 12 shows a summary of debt issues by rating and term since 2002 in 15 Canada. As shown, the majority of the issuances are less than five years in term, and 16 with a rating better than ‘BBB’.
17 Figure 12: Issuance by Term – Since January 200214
Term Credit Rating by S&P 0 – 5 years 6 – 10 years > 10 years
AAA $7,108 $2,437 $0 AA $15,666 $3,512 $4,192 A $35,954 $18,196 $10,812 BBB $13,552 $1,445 $1,450 Other $440 $350 $0 Total $72,720 $25,940 $16,454
18 A lower credit rating may also limit the number of buyers of the debt securities. 19 Most fund managers operate under investment guidelines that restrict the proportion of
14 Source: CIBC World Markets internal database; all ratings are from S&P, and if an issuer did not have an S&P rating, it was not Page 27 of 32
1 funds that they can invest in different categories of credit quality. Similarly, many 2 pension funds limit the total amount of sub ‘A’ bonds that the fund manager can hold. 3 This means that there are fewer portfolios that are allowed to purchase the securities of 4 lesser credits. The credit guidelines on a portfolio usually are set out by a trustee or 5 credit committee, often with pre-determined guidelines on the proportion of funds to be 6 committed for each rating category of security. In addition, many financial institutions 7 have approved lists of companies whose securities are acceptable for purchase.
8 In recent years, however, issuers in the ‘BBB’ category have been able to access 9 the market to a greater degree and the market for credits lower than ‘A’ has grown as a 10 percentage of the total market over the past five years. Nevertheless, in 2004 ‘BBB’ 11 issuances still only represented approximately 16% of total issuances.
12 Finally, it is worth noting that the amount of debt that would have to be raised 13 for the MVP on a stand alone basis would be over $3 billion. This would be a 14 significant amount of debt to be raised at any one time and would become more 15 difficult to raise over a short period of time if the MVP is a ‘BBB’ rated entity instead of 16 an ‘A’ credit.
17 5.3 Reasonableness of Requested Capital Structure
18 The Proponents are proposing a 30% equity/70% debt capital. Based on 19 Standard and Poor’s published ’A‘ rating financial ratio guidelines for the pipeline and 20 utility companies/assets with a business profile of ‘2’ and ‘3’, the financial ratios for 21 MVP at the 30% equity/70% debt structure are consistent with an ’A‘ rating, assuming 22 the financial forecasts prepared by the Proponents unfold as planned (Figure 13).
included; excludes securitizations Page 28 of 32
1 Figure 13: S&P ’A‘ Rating Criteria
Business Profile16 S&P Ratings Criteria MVP15 ’2’ ’3’
Funds from Operations17 to Total Debt 14.8% 12-20% 15-25% Funds From Operations Interest Coverage 3.4x 2-3x 2.5-3.5x Total Debt to Total Capital 70% 52-58% 50-55%
2 DBRS does not publish specific metrics solely for ‘A’ credits, but instead groups 3 ‘A’ and ‘BBB’ together. Therefore, Figure 14 compares the credit ratios for M&NP and 4 Alliance to MVP as both of those pipelines are rated ‘A’ by DBRS. As shown, based on 5 the 2.21% equity increment and 30% equity structure, MVP has metrics in line with an 6 ‘A’ rated credit.
7 Figure 14: Credit Ratio Comparison18
MVP Alliance M&NP
% Debt to Capitalization 70.0% 69.1% 74.7% EBIT Interest Coverage 2.4x 1.9x 1.8x EBITDA Interest Coverage 4.0x 2.8x 2.7x Cash Flow/Debt 0.15x 0.11x 0.10x
8 The rating agencies will consider factors other than just the quantitative financial 9 ratios noted above. These more qualitative factors will include, among other things, the 10 term of the transportation contracts, any guarantees on the debt or throughput, overall 11 gas supply and demand risks, the credit worthiness of the shippers contracts, the 12 regulatory framework, the competitiveness of the tolls, and any construction risks. 13 Therefore, although the financial metrics of the MVP would appear to support an ‘A’ 14 rating, there is no guarantee that the rating agencies will reach the same conclusion.
15 Average of metrics for the period 2010 to 2019. 16 Business characterization by S&P Rating Agency. 17 Net Income plus depreciation, amortization, deferred taxes and other non-cash items. 18 Average of metrics for periods (MVP 2010-2019, Alliance 2001-2003, M&NP 2000-2002); figures for Alliance and M&NP sourced from DBRS reports, August 2004 and August 2003 respectively. Page 29 of 32
1 It is our opinion that the MVP as a stand-alone entity, should target an ’A‘ rating 2 as the debt market for ’A‘ rated issuers is much greater in Canada than it is for ’BBB‘ 3 rated issuers, and the cost of financing is lower which is important to help ensure that 4 the MVP is a competitive pipeline. If any of the agencies rate the proposed MVP as a 5 ’BBB‘, it is our opinion that a capital structure with more equity than 30% or a higher 6 ROE increment should be considered to secure an ‘A’ rating. Page 30 of 32
1 6.0 Appendix A
2 Richard (Dick) D. Falconer 3 Vice Chairman 4 Investment Banking
5 • Responsible for senior investment banking relationships including Power and 6 Utilities. Extensive financing and M&A experience on major transactions.
7 • Joined Wood Gundy in 1970. Previous roles include Financial Analyst; 8 Director of Research; Co-Head Investment Banking. Appointed Vice 9 Chairman, CIBC World Markets, 1993. Current responsibilities include: 10 o Co-Chair, Deals Committee; 11 o CIBC Capital Partners Investment Committee; 12 o CIBC World Markets Senior Leadership Team; 13 o CIBC National Donations Committee; 14 o CIBC Pension & Benefits Investment Committee.
15 Written Evidence & Expert Testimony:
16 Before the Alberta Energy and Utilities Boards:
17 • Testimony for ENMAX Corporation, November 2003, regarding Generic Cost 18 of Capital.
19 • Testimony for TransAlta Utilities Corporation, February 1998, regarding 1995 20 Rate of Return on Common Equity.
21 • Testimony for TransAlta Utilities Corporation, February 1996, regarding 22 Capital Markets Evidence.
23 • Testimony for TransAlta Utilities Corporation, May 1991, regarding Capital 24 Markets Evidence. Page 31 of 32
1 Before the Nova Scotia Utility and Review Board:
2 • Testimony for Nova Scotia Power Inc., December 2001, regarding rate 3 increase.
4 Expert Testimony:
5 Before the Ontario Energy Board:
6 • Testimony for UnionGas, February 1998, regarding the separation of The 7 Ancillary Business.
8 • Testimony for British Gas plc, October 1990, regarding its purchase of The 9 Consumers’ Gas Company Ltd.
10 • Testimony for Inter-City Gas Corporation, December 1989, regarding the sale 11 of its gas distribution business to Westcoast Energy Inc.
12 • Testimony for ICG Utilities (Ontario) Ltd., October 1989, regarding its 13 cogeneration project at Fort Francis.
14 Before the CRTC:
15 • Testimony for AGT Limited, April 1993, regarding Capital Markets Evidence.
16 Before the Courts:
17 • Testimony, 1987, before the Ontario Courts in the matter of the privatization 18 of KeepRite Limited by Inter-City Gas Corporation.
19 Additional Activities:
20 • Honorary Governor, Shaw Festival;
21 • Member, Shaw Festival Development Committee;
22 • Chair, Shaw Festival Capital Campaign;
23 • Member, Campaign Executive Committee, Toronto General & Western 24 Hospital Foundation; Page 32 of 32
1 • Member, Executive Committee, The Bishop’s Company;
2 • Member, Major Gift Steering Committee, LOFT Community Services.
3 Education:
4 MBA, York University; Honours B.A., University of Toronto; Chartered Financial 5 Analyst. NATIONAL ENERGY BOARD
Hearing Order GH-1-2004
ADDITIONAL WRITTEN EVIDENCE
BUSINESS RISK EVIDENCE RELATED TO THE MACKENZIE VALLEY PIPELINE
submitted on behalf of The Mackenzie Valley Pipeline
Dr. Andrew Safir President Recon Research Corporation 6380 Wilshire Blvd; Suite 1604 Los Angeles, CA 90048
January 10, 2005 Written Evidence of Dr. Andrew Safir
1 I. INTRODUCTION
2 My name is Dr. Andrew Safir and I am President of Recon Research Corporation. My
3 business address is Suite 1604, 6380 Wilshire Blvd., Los Angeles, CA 90048.
4 I received a Bachelor of Arts degree in economics and psychology from the University of
5 Colorado in 1969, a Master of Arts in economics from Tufts University in 1970, and a
6 Ph.D. in economics from Tufts University in 1975.
7 During the 1970s, I held a variety of positions with the U.S. Government. In 1972, I held
8 a staff position on the President's Council of Economic Advisers. In 1973, I held a similar
9 position on the White House staff. In 1974, I moved to the Department of Justice, where
10 I served as a senior advisor on economic policy matters, including those pertaining to
11 industrial organization and market structure. In 1975, I was appointed as the Assistant
12 Director of the Office of International Energy Policy at the U.S. Treasury. I left that
13 position in 1978 to join the Administration of Governor Edmund G. Brown, Jr., as Chief
14 Business Economist for the State of California. However, I remained a special advisor to
15 the U.S. General Accounting Office specializing in energy, international finance, and
16 national security matters throughout much of the 1980s. I founded Recon Research
17 Corporation in 1980.
18 I have over 25 years of experience dealing with international energy issues. In 1984, I
19 began providing consulting services on energy policy and market issues and expert
20 testimony in natural gas proceedings in California. Since that time, I have continued to
21 provide these services throughout the U.S., as well as in Canada, the U.K. and Australia.
22 I have previously testified before the National Energy Board ("NEB" or the "Board"),
1 Written Evidence of Dr. Andrew Safir
1 including evidence given in RH-3-2004, RH-1-2002, RH-4-2001, RH-1-99 and RH-2-94.
2 A list of selected testimony experience is provided in Attachment A.
3 II. PURPOSE OF THE REPORT
4 I have been asked to provide an assessment of the business risks relevant to the Mackenzie
5 Valley Pipeline ("MVP") in order to assist in the evaluation of the financial parameters
6 requested by the Pipeline in its Application to the NEB. This analysis and my conclusions
7 appear below.
8 Section III first summarizes my opinion regarding the business risk relevant to the MVP
9 and which should be taken into account in any review of its requested financial parameters.
10 Section IV discusses in more detail the primary determinants of business risk, and the
11 unique manifestation of those risks in the context of the Pipeline project. Finally, Section
12 V provides a discussion of the differences and similarities in business risk between the
13 MVP project and those faced by other pipelines in the U.S. and Canada.
14 III. SUMMARY OF OPINIONS ON BUSINESS RISK ISSUES
15 In my opinion, the business risk faced by the MVP arises from such factors as the remote,
16 untested supply source it services, the northern environment it crosses, and the multiple
17 regulatory jurisdictions it must satisfy. In addition, the MVP faces market risk from
18 competitive supply sources that may be accessed via lower cost transportation. All of these
19 elements can increase its costs, and raise the risk of incomplete capital recovery. It is my
20 belief that, when these factors are taken into account, they support the suggested capital
21 structure and rate of return being requested by the Applicant in this Proceeding.
2 Written Evidence of Dr. Andrew Safir
1 Business risk can be defined as the uncertainty inherent in a firm’s future earnings arising
2 from the basic nature of the business and operations of the firm. It can be expressed in
3 terms of the expected variability of pipeline income over time. The greater the potential
4 variability, the greater the business risk. It can also be extended to include the probability
5 that the MVP will be unable to fully recover its revenue requirement, including invested
6 capital and authorized return over its economic life.1
7 For established pipelines, the NEB has usually reflected business risk in the capital structure
8 by reference to the percentage of the capital base represented by equity, i.e., the "thickness"
9 of the equity component.2 For greenfield pipelines, the Board has approved a combined
10 approach to reflect business risk, with an initial return on equity that is somewhat higher
11 in light of the lower equity ratio than the business risk might otherwise justify.3 A similar
12 combined evaluation has also been used by other Canadian Boards, such as the Ontario
13 Energy Board ("OEB") and the British Columbia Utilities Commission ("BCUC").4
1 For example, see TCPL Written Evidence on Fair Return, Appendix B-3, Business Risk, Jan 2004, revised Nov 2004, RH-2-2004, p. 8: "A firm's total business risk is made up of all the physical, economic, competitive, political and regulatory risks to which the income-earning potential of the assets of the business is exposed. In the case of the Mainline, the assessment of its business risk focuses on pipe-on-pipe competition, market risk, supply risk, regulatory risk, and operating risk." In addition, see NEB, Reasons for Decision, TCPL, RH-4-2001, Cost of Capital, p. 24: "Business risk represents the risk attributed to the nature of a particular business. It is made up of all the risks to which the income-earning capability of an asset is exposed."
2 NEB, Reasons for Decision, TCPL, RH-4-2001, Cost of Capital, p. 13: "Business risk has traditionally been reflected in the establishment of a deemed common equity ratio in a pipeline’s capital structure."
3 As an example, Maritimes and Northeast Pipeline ("M&NE") has a deemed equity percentage and authorized return on equity that varies from the established gas pipelines subject to the Multi-Pipeline Cost of Capital Decision (RH-2-94).
4 Despite using automatic adjustment formulas for the return on equity, the BCUC has different regulated capital structures and different company-specific equity risk premiums. The OEB, which also employs an automatic adjustment formula, has approved identical deemed common equity percentages but different returns on equity for Enbridge Gas Distribution and Union Gas.
3 Written Evidence of Dr. Andrew Safir
1 IV. PRIMARY DETERMINANTS OF BUSINESS RISK RELEVANT TO THE 2 PIPELINE PROJECT
3 The elements of business risk relevant to the MVP originate in several areas. These include
4 economic uncertainty regarding supply sources, market conditions, construction costs, and
5 regulatory policies. While some of these risk elements are common to all pipeline
6 operations, others are more specific to the Mackenzie Valley Project.
7 A. Supply Source Risk
8 Supply source risk pertains to the physical availability of natural gas and how
9 changes in that availability may affect a pipeline's cash flow. As explained in more
10 detail in the Application, while the MVP has the support of a number of shippers
11 who have signed long term commitments, the Pipeline will access only a single
12 supply source.5 Because this source has not yet been tested and commercially
13 produced, there are several inherent risks affecting the potential cash flow from
14 pipeline operations, as well as to the returns of and on equity.
15 The Mackenzie Delta region (except for Ikhil) has not yet commenced commercial
16 production and cannot until the MVP is completed and in operation.6 This clearly
17 exposes the pipeline to the business risk that the basin will simply not perform as
5 The MVP is currently contracted to provide transportation of gas from three separate fields, Taglu, Parsons Lake, and Niglintgak, in the northwest of Canada where the Northwest Territories border the Beaufort Sea. Because of their close proximity and the absence of any alternative means of access, these fields can be economically considered a single supply source.
6 The Ikhil/Inuvik gas project is a joint venture that supplies Inuvik with natural gas from two wells at the Ikhil reservoir that are about 30 miles northwest of Inuvik on Inuvialuit lands. The gas is transported via a small six inch pipeline.
4 Written Evidence of Dr. Andrew Safir
1 intended. Given the efforts that have been made by shippers and potential shippers
2 to determine the extent of recoverable resources, many producers may feel such risk
3 is low. However, from an economic standpoint, such risk exists and must be
4 considered.
5 B. Market Risk
6 Market risk typically refers to the risk that the MVP’s income-earning ability could
7 be affected by the market demand and supply for natural gas. It is influenced by
8 both the overall size of the gas market, by the market share serviced by the pipeline,
9 and by competing sources of supply.
10 One aspect of market risk arises from the remote location of the Mackenzie Delta
11 supply source. The transportation cost component of the total delivered gas price
12 will be substantially higher than for other basins. As a result, transportation costs
13 will constitute a higher percentage of the total selling price, with netbacks making
14 up a smaller percentage. Consequently there is a greater probability that the
15 revenues of Mackenzie Valley producers could approach the aggregate of production
16 and transportation costs, leaving producers much more sensitive to changes in
17 delivered gas prices. If long term netbacks to producers prove disappointing, the
18 pipeline may find it relatively more difficult to acquire new contracts, or to re-
19 contract with its shippers once initial long term contracts have expired.
20 In addition, the Mackenzie Valley area as a whole may well experience a reduction
21 in the incentive to further develop the supply basin, resulting in an increase in the
22 uncertainty of whether new producers would be willing to commit to the MVP. In
5 Written Evidence of Dr. Andrew Safir
1 turn, this raises the probability of increased variability in throughput and pipeline
2 cash flow, increasing the risk that capital may not be recovered.
3 Although long term contracts mitigate some portion of this business risk, it is too
4 simplistic and economically inaccurate to say that long term contracts will
5 completely insulate the MVP from all of this risk. When economic circumstances
6 change, leaving contractual terms far out of line with economic reality, contract
7 renegotiations become a real possibility. As a result, the MVP is subject to business
8 risk from changing market conditions.
9 Another element of business risk occurs even where the economic characteristics of
10 the MVP supply source are known with certainty. As the expected characteristics
11 of the fields in the Mackenzie Delta are more homogeneous than that of other basins,
12 the pipeline runs the risk that all of its shippers will be "out of the money"
13 simultaneously.7 That is, any loss of competitive standing in end use markets will
14 affect the viability of all shippers on the line more or less equally. In contrast,
15 production in areas such as the WCSB comes from a wide variety of production
16 profiles, including relatively inexpensive, shallow wells, expensive tight sands
17 production, and coal bed methane. Consequently, changing economic
18 circumstances, which may make some deliveries in the WCSB uneconomic, may not
19 have the same effect on others. As a result, pipelines drawing from the WCSB
20 supply source are backed by shippers whose commercial differences act as an
21 economic portfolio from the standpoint of the pipelines. This diversifies, and
7 This is not a market related risk faced by pipelines drawing from multiple basins or even a pipeline drawing solely from the WCSB.
6 Written Evidence of Dr. Andrew Safir
1 thereby reduces, the risk that the pipeline will be drawing from a commercially
2 unviable supply source.
3 Because of the relatively homogeneous production profiles of its expected shippers,
4 only limited diversification is possible for the MVP . As a result, any unexpected
5 reduction in commercial viability would affect all shippers on the MVP
6 simultaneously, potentially leading to adverse consequences for the pipeline.
7 In addition, the MVP will be coming on line at a time of increasing options for end
8 use gas markets. Anticipated demand growth for natural gas and its attendant price
9 rises is not only an economic driving force behind the MVP, but it has also resulted
10 in widespread interest in the development of LNG projects. According to recent
11 FERC estimates, there are 47 proposed LNG projects that would be able to service
12 North American demand. These are in addition to expansion proposals for the four
13 existing LNG terminals.8 If constructed, the total capacity of these proposed
14 terminals and expansions would be about 50 Bcf/day. Although no one expects that
15 all of these plants will ultimately prove market worthy, the very number of them
16 being proposed represents an extraordinary anticipation of natural gas growth.
17 Current levels of LNG imports are a fraction of what has been proposed.9 The
18 uncertainty regarding the amount of LNG capacity to be constructed, and its
19 subsequent effect on end market natural gas prices and netbacks received by
8 FERC, Office of Energy Projects, Existing and Proposed North American LNG Terminals, Dec 9, 2004.
9 In 2003, the U.S. imported about 506 Bcf of LNG. This is equivalent to a daily consumption of 1.4 Bcf/d. For 2004 year to date (July), EIA estimates LNG imports of 365 Bcf, equivalent to 1.7 Bcf/d, on an annual basis. EIA, Natural Gas Monthly, Sep 2004, Tables 5 & 6.
7 Written Evidence of Dr. Andrew Safir
1 Mackenzie Valley producers, represents another level of risk to which the MVP is
2 subject. In addition, potential changes in the relative costs of extracting natural gas
3 from sources such as coalbeds represents the same type of risk.
4 The MVP may also be competing with Alaskan gas delivery. Recent legislation
5 passed by the U.S. Congress will aid in the construction of a natural gas pipeline
6 transporting gas from the Alaskan North Slope southeast through Alberta. Although
7 still a proposal with no firm commitments from the prospective builders, financial
8 incentives recently made available by the U.S. government have increased the near
9 term viability of this project. Should such a line be constructed, it could affect the
10 net backs available to MVP shippers, and the re-contracting opportunities of the
11 pipeline once initial contracts have expired.
12 C. Construction Project Risk
13 Construction project risk can be viewed as the risk that the MVP's income earning
14 ability could be affected by the construction and logistics requirements associated
15 with the development of a greenfield pipeline. One such element is the uncertainty
16 regarding construction costs, which could include project delays and cost overruns.
17 The project is located in a remote region subject to high transportation and logistic
18 costs. Consequently, less is known regarding these costs than costs associated with
19 construction in relatively more accessible regions. For a new pipeline being
20 constructed in such a challenging environment, these are elements of construction
21 risk that differ from that of established pipelines with a longer history of commercial
22 activity. The toll design of the MVP calls for shippers to be responsible for
23 construction costs that have been approved by the NEB. However, there will still
8 Written Evidence of Dr. Andrew Safir
1 be some uncertainty regarding that actual level of cost overruns. Such cost overruns
2 may affect the overall competitiveness of this new supply basin.
3 In addition, the extensive nature of environmental mitigation and termination
4 requirements may require uncertain and open ended financial obligations extending
5 beyond the actual useful life of the pipeline itself. As the extent of these obligations
6 cannot easily be predicted, they entail the possibility that they will not be adequately
7 accounted for, or fully recovered in pipeline rates. Consequently, business risk is
8 generated as the result of these requirements.
9 D. Regulatory and Governmental Factors Affecting Business Risk
10 Regulatory and governmental policies can increase uncertainty in a pipeline's
11 expected income.
12 For example, the MVP faces rigorous regulatory review of environmental and socio-
13 economic matters by multiple parties as outlined in the Co-operation Plan. Should
14 the outcome of such review unexpectedly increase pipeline costs, these in turn could
15 affect the economic choices faced by potential shippers and increase the variability
16 in expected pipeline revenues over the life of the project. While no one is
17 questioning the wisdom of these investigations and analyses, it is undeniable that
18 they may well raise the business risk faced by the Applicant and increase uncertainty
19 regarding ultimate financial requirements.
20 Another aspect of governmental and regulatory risk is the fact that the MVP is being
21 constructed over territory with various regional and administrative forms of
9 Written Evidence of Dr. Andrew Safir
1 government as well as areas of unsettled land claims. Uncertainties regarding the
2 resolution of disputes over ownership claims can affect the probability and levels of
3 future income.
4 V. BUSINESS RISK OF THE MVP IN COMPARISON TO PIPELINES IN THE 5 U.S. AND CANADA
6 A. Canadian Comparisons
7 The business risks relevant to the MVP are most comparable to those faced by the
8 most recently constructed Canadian gas pipelines. These include the M&NE,
9 Alliance, and Vector pipelines.
10 All four pipelines rely on long-term contracts with shippers to mitigate supply risk.
11 Contract terms on Alliance and Vector are for 15 years, while terms average 15
12 years for M&NE.10 The MVP is proposing a mixture of 15 and 20 year contracts.
13 Such contracts do not completely eliminate the risk, but rather tend to shift it
14 towards the credit worthiness of its shippers. As a result, diversification in the
15 number of shippers works to reduce this element of risk. Currently, Vector and
16 Alliance rely on a broader base of shippers than does M&NE.
17 Although all of the three comparison pipelines have been built within the last
18 decade, M&NE comes closest to profiling the risk elements associated with MVP
19 supply. Unlike Alliance, which accesses an already established basin with a wide
20 range of production profiles, and Vector, which relies on other pipelines for its
10 M&NE also has a 20 year backstop that obligates a major shipper to pay for unsubscribed capacity.
10 Written Evidence of Dr. Andrew Safir
1 supply, both M&NE and MVP depend on a new source of gas. As a result, these last
2 two projects have in common uncertainties associated with new and untested fields,
3 such as the lack of good information about resources and expected production.
4 Another difference between the two sets of pipelines is that Alliance and Vector
5 were built in regions where pipelines had already been built. As a result, this
6 reduced the uncertainty concerning the set of difficulties that would be faced during
7 construction. However, the building of M&NE in an area new to pipelines led to
8 unusual problems, such as acid rock, requiring a level of expertise and costs not
9 typically necessary for pipeline construction. Likewise, for the MVP, the relatively
10 unique characteristics of the physical environment may also increase expenses.
11 This, of course, can affect the overall competitiveness of the supply basin and, in
12 turn, increase the variability in expected income of the MVP over its useful life.
13 Unlike the comparison with U.S. pipelines (see below), the regulatory risk facing
14 these four pipelines is somewhat similar. MVP's application for cost of service
15 regulation, with deferral accounts to recover differences in subsequent years, is most
16 like the method applicable to Alliance. Both Vector and M&NE are subject to fixed
17 forward test years. However, M&NE's regulation calls for minimal deferral
18 accounts and, in fact, the pipeline recently negotiated a multi-year settlement with
19 its shippers.
20 Although there are differences among the risk profiles confronting MVP in
21 comparison to Alliance, Vector, and M&NE, the preceding discussion indicates that
22 the differences are not so great as to prevent comparisons from being meaningful
11 Written Evidence of Dr. Andrew Safir
1 and applicable. As a result, the deemed equity ratios and returns on equity
2 authorized for these existing pipelines provide an accurate and reasonable starting
3 point for the determination of returns to capital for the MVP.
4 B. Comparison of Business Risks Faced by the MVP to Those Faced by U.S. 5 Pipelines
6 Because of the large number of U.S. pipelines, with all their individual
7 idiosyncracies and differences among the various risk elements, it is difficult to
8 make a blanket comparison for all the different elements of business risk. However,
9 one apparent difference is the distinction in the regulatory environment between the
10 two nations.
11 Although both Canada and the United States regulate their natural gas pipelines,
12 there are differences between the two that lead to differences in the risk profiles. In
13 Canada, regulation takes the form of setting tolls and tariffs such that all prudently
14 incurred costs are covered, including a fair rate of return on the utility's rate base.
15 Canadian utilities are also afforded the protection of balancing or deferral accounts
16 such that any deviation from forecasted output may be made up in succeeding years.
17 This type of regulation involves frequent rate hearings to keep tolls in line with costs
18 and to ensure that utilities continue to earn a reasonable rate of return on
19 shareholders' equity.
20 In the U.S., the public preference in favor of deregulation and market based
21 oversight has resulted in a process whereby the powers of regulation are used to
22 push natural gas pipelines into a more competitive, market driven environment. One
12 Written Evidence of Dr. Andrew Safir
1 important difference between the U.S. and Canada is that, since 1992, the FERC no
2 longer requires frequent rate hearings. In addition, the push for market signals to
3 replace day to day regulation led to several orders whereby the FERC made it clear
4 that costs resulting from un-contracted capacity would be borne by both shippers and
5 the pipeline. Pipelines were required to absorb or pay for any shortfalls in
6 forecasted throughput. However, they were also allowed to keep any gains above
7 forecasted throughput.
8 As a result of the differences in regulation between the two countries, U.S. pipelines
9 are subject to comparatively more risk. With rate hearings so infrequent in the U.S.,
10 there is a high probability that revenues and costs will begin to differ significantly
11 over time. Therefore it is more likely that pipeline revenues will either exceed or
12 fall short of costs. Likewise the ability and widespread practice of pipelines both in
13 negotiating and discounting rates also leads to more variability in revenues,
14 increasing the possibility the actual returns will either surpass or fall short of
15 allowable returns. As an element of comparison, it is clear that return on equity and
16 deemed equity percentages for higher risked U.S. pipelines would represent a upper
17 boundary for which to compare the MVP.
18 VI. CONCLUSIONS
19 1. Important elements of business risk relevant to the MVP originate from such
20 factors as the distant and untested supply source it services, the northern
21 terrain that it crosses, and the multiple regulatory jurisdictions it must satisfy.
13 Written Evidence of Dr. Andrew Safir
1 2. The MVP also faces market risk from competitive supply sources that may
2 be accessed via lower cost transportation.
3 3. Each of these elements has the potential to increase its costs, and thereby
4 increase the risk of incomplete capital recovery.
5 4. When these factors are taken into account, I believe that they support the
6 suggested capital structure and rate of return being requested by the
7 Applicant in this Proceeding.
14 Written Evidence of Dr. Andrew Safir
ATTACHMENT A: ENERGY INDUSTRY TESTIMONY OF DR. ANDREW SAFIR
Testimony before Regulatory Bodies:
Response Evidence of Dr. Andrew Safir on Behalf of the Canadian Association of Petroleum Producers before the National Energy Board regarding TransCanada PipeLines Limited Application for the North Bay Junction, July 2004, (NBJ RH-3-2004).
Written Evidence of Dr. Andrew Safir on Behalf of the Canadian Association of Petroleum Producers before the National Energy Board regarding TransCanada PipeLines Limited 2003 Tolls and Tariff Application, April 2003, (RH-1-2002).
Prepared Rebuttal Testimony of And Exhibits of Dr. Andrew Safir On Behalf of Coral Power L.L.C., November 2002, regarding the request by the California Public Utilities Commission and California Electricity Oversight Board to have long term power contracts abrogated as unjust and unreasonable, (EL02-60-003 and EL02-62-003).
Written Evidence of Dr. Andrew Safir on Behalf of the Canadian Association of Petroleum Producers before the National Energy Board regarding TransCanada PipeLines Limited 2001 and 2002 Fair Return Application, January 2002, (RH-4-2001).
Testimony of Dr. Andrew Safir on Behalf of the Canadian Association of Petroleum Producers before the National Energy Board regarding TransCanada's application for discretionary rate authority, January 2000, (RH-1-99).
Testimony of Dr. Andrew Safir on Behalf of the Canadian Association of Petroleum Producers before the Alberta Energy and Utilities Board regarding NGTL's proposal to unbundle intra-provincial pipeline rates, September 1999, (No. 990157).
Prepared Direct Testimony of Andrew Safir on Behalf of Northern Natural Gas Company, June 1998, regarding market-based rates for storage and secondary transportation services, FERC rate proceeding for Northern Natural Gas, (RP98-203-000).
Oral Testimony of Dr. Andrew Safir on Behalf of Amoco Canada, March/April 1998, National Energy Board proceeding regarding Alliance Pipeline application for certificate of public convenience and necessity.
15 Written Evidence of Dr. Andrew Safir
Written Testimony of Dr. Andrew Safir on Behalf of Amoco Canada, January 1998, National Energy Board proceeding regarding Alliance Pipeline application for certificate of public convenience and necessity.
Written Testimony of Dr. Andrew Safir on Behalf of Amoco Canada, April 1997, Alberta Energy and Utilities Board proceeding regarding NOVA Gas Transmission Ltd. proposal for load retention rates.
Oral Testimony of Dr. Andrew Safir on Behalf of El Paso Refinery, Refinery Holding Company and Chevron Products Co. USA, May 6, 1996, FERC rate proceeding for Santa Fe Pacific Pipeline (OR92-8-000, et al).
Prepared Sur-Surrebuttal Testimony of Dr. Andrew Safir on Behalf of El Paso Refinery, Refinery Holding Company and Chevron Products Co. USA, January 10, 1996, FERC rate proceeding for Santa Fe Pacific Pipeline (OR92-8-000, et al).
Prepared Rebuttal Testimony of Dr. Andrew Safir on Behalf of El Paso Refinery, Refinery Holding Company and Chevron Products Co. USA, August 27, 1995, FERC rate proceeding for Santa Fe Pacific Pipeline (OR92-8-000, et al).
Cross Answering Testimony of Dr. Andrew Safir on Behalf of Canadian Association of Petroleum Producers, February 7, 1995. FERC rate proceeding for Pacific Gas Transmission Company, dealing with the issue of rolled-in rate design and its applicability to the PGT expansion (RP94-149-000).
Prepared Direct Testimony of Dr. Andrew Safir on Behalf of National Power PLC and American National Power Inc., December 5, 1994. CPUC proceeding on uneconomic utility supply costs and the restructuring of California's electric services industry (R.94-04- 031/I94-04-032).
Prepared Direct Testimony of Dr. Andrew Safir on Behalf of Canadian Association of Petroleum Producers, November 17, 1994. FERC rate proceeding for Pacific Gas Transmission Company, dealing with the issue of rolled-in rate design and its applicability to the PGT expansion (RP94-149-000).
Prepared Direct Testimony of Dr. Andrew Safir, September 26, 1994. National Energy Board Pipeline Cost of Capital Proceeding.
16 Written Evidence of Dr. Andrew Safir
Testimony of Dr. Andrew Safir, March 1993. National Energy Board Export License Renewal for California Gas Sales.
Testimony of Dr. Andrew Safir, 1993. Alberta Energy Resources Conservation Board Hearings on Gas Pipeline Expansion Proposals.
Prepared Direct Testimony of Dr. Andrew Safir on behalf of the Canadian Petroleum Association, January 25, 1991. CPUC rulemaking regarding capacity brokering, natural gas procurement and systems reliability issues (R.88-08-018).
Prepared Rebuttal Testimony of Dr. Andrew Safir on behalf of the Producer/Shipper Group, May 14, 1990. CPUC proceeding regarding PG&E's application of a certificate of public convenience and necessity (A.89-04-033).
Prepared Rebuttal Testimony of Dr. Andrew Safir on behalf of Salmon Resources Ltd. and Mock Resources, Inc., November 29, 1989. CPUC proceeding regarding PG&E's application for authority to revise gas rates and tariffs (A.89-08-024).
Prepared Direct Testimony of Dr. Andrew Safir on behalf of Salmon Resources Ltd. and Mock Resources, Inc., November 9, 1989. CPUC proceeding regarding PG&E's application for authority to revise gas rates and tariffs (A.89-08-024).
Prepared Direct Testimony of Dr. Andrew Safir on behalf of Southern California Edison Company, July 24, 1989. CPUC investigation regarding adequacy of California pipeline capacity (I. 88-12-027).
Prepared Direct Testimony of Dr. Andrew Safir on behalf of Salmon Resources Ltd. and Mock Resources, Inc., June 30, 1989. CPUC proceeding regarding Southern California Gas Company's application for authority to revise gas rates and tariffs (A.89-04-021).
Prepared Testimony of Dr. Andrew Safir on behalf of Southern California Edison Company, June 19, 1989. CPUC rulemaking regarding capacity brokering, natural gas procurement and systems reliability issues (R.88-08-018).
Prepared Direct Testimony of Dr. Andrew Safir on behalf of Salmon Resources Ltd. and Mock Resources, Inc., April 24, 1989. CPUC proceeding regarding PG&E's application for authority to revise gas rates and tariffs (A.88-09-032).
17 Written Evidence of Dr. Andrew Safir
Application of Pacific Gas & Electric Company to the CPUC for a Certificate of Public Convenience and Necessity, Prepared Rebuttal Testimony of Dr. Andrew Safir on Behalf of the Producer/Shipper Group, Docket No. A.89-04-033, April 14, 1989.
Prepared Direct Testimony of Dr. Andrew Safir on behalf of Salmon Resources Ltd. and Mock Resources, Inc., November 21, 1988. CPUC proceeding regarding PG&E's application for authority to revise gas rates and tariffs (A.88-09-032).
Prepared Supplemental Testimony of Dr. Andrew Safir on behalf of Shell Canada Limited and Salmon Resources Ltd., January 23, 1988. CPUC investigation regarding unbundling storage costs for the non-core market, incremental storage banking, and underground storage services for wholesale customers (I.87-03-036).
Prepared Direct Testimony of Dr. Andrew Safir on behalf of Shell Canada Limited and Salmon Resources Ltd., December 3, 1987. CPUC investigation regarding unbundling storage costs for the non-core market, incremental storage banking, and underground storage services for wholesale customers (I.87-03-036).
Prepared Direct Testimony of Dr. Andrew Safir on behalf of the City of Palo Alto, December 3, 1987. CPUC investigation regarding unbundling storage costs for the non- core market, incremental storage banking, and underground storage services for wholesale customers (I.87-03-036).
Prepared Direct Testimony of Dr. Andrew Safir on behalf of Shell Canada Limited, July 2, 1987. CPUC investigation regarding transition costs, capacity priority rights for non-core customers, inter-utility priority rights, and unbundled gas utilities services (I.86-06-005).
Prepared Direct Testimony of Dr. Andrew Safir on behalf of the City of Palo Alto, July 1, 1987. CPUC investigation regarding transition costs, capacity priority rights for non-core customers, inter-utility priority rights, and unbundled gas utilities services (I.86-06-005).
Prepared Rebuttal Testimony of Dr. Andrew Safir on behalf of United States Borax & Chemical Corporation, June 26, 1987. FERC proceeding regarding certification of interstate pipelines to serve California (CP85-437-00 et al.).
Prepared Direct Testimony of Dr. Andrew Safir on behalf of United States Borax & Chemical Corporation, October 29, 1986. FERC proceeding regarding certification of interstate pipelines to serve California (CP85-437-00 et al.).
18