TRANSCANADA PIPELINES LIMITED
BUSINESS AND SERVICES RESTRUCTURING AND MAINLINE 2012 – 2013 TOLLS APPLICATION
PART D: FAIR RETURN
Appendix D1: Written Evidence of Paul R. Carpenter (The Brattle Group)
SEPTEMBER 1, 2011Revised October 31, 2011
NATIONAL ENERGY BOARD
IN THE MATTER OF the National Energy Board Act, R.S.C. 1985, c. N-7, as amended, and the Regulations made thereunder;
AND IN THE MATTER OF an Application for (1) approvals required to implement a Restructuring Proposal that affects the businesses and services of TransCanada PipeLines Limited, NOVA Gas Transmission Ltd. and Foothills Pipe Lines Ltd., and (2) approval of final tolls for the TransCanada Mainline for 2012 and 2013.
TRANSCANADA PIPELINES LIMITED
______
WRITTEN EVIDENCE OF PAUL R. CARPENTER THE BRATTLE GROUP
______
September 1, 2011Revised October 31, 2011
WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
TABLE OF CONTENTS
I. OVERVIEW/SUMMARY ...... 1 II. BACKGROUND ON THE CONCEPT OF BUSINESS RISK ...... 7 III. NORTH AMERICAN MARKET ENVIRONMENT AND MAINLINE BUSINESS RISK ...... 18 A. Review of North American Market Environment ...... 18 B. Competition Risk ...... 26 C. Supply Risk ...... 37 D. Market Risk ...... 38 E. Regulatory Risk ...... 42 F. Impact on the Mainline of Recent and Prospective Market Conditions ...... 46 IV. THE MAINLINE’S RESTRUCTURING PROPOSAL ...... 53 V. U.S. AND CANADIAN COMPARABLES FOR THE MAINLINE ...... 54 A. U.S. Interstate Gas Pipelines ...... 55 B. Dr. Vilbert’s Gas Pipeline Sample ...... 66 C. U.S. Oil Pipelines ...... 70 D. Dr. Vilbert’s Oil Pipeline Sample ...... 72 E. U.S. LDCs ...... 74 F. Dr. Vilbert’s U.S. LDC Sample ...... 78 G. Dr. Vilbert’s Canadian Sample ...... 84
i WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 I. OVERVIEW/SUMMARY
2 Q1. Please state your name, address and position.
3 A1. My name is Paul R. Carpenter. I am a Principal of The Brattle Group, an economic 4 and management consulting firm with offices in Cambridge, Washington D.C., San 5 Francisco, London, Brussels, Madrid, and Rome. My office is located at 44 Brattle 6 Street, Cambridge, Massachusetts 02138.
7 Q2. Will you briefly describe your educational background and professional 8 qualifications?
9 A2. Yes. I am an economist specializing in the fields of industrial organization, finance 10 and energy and regulatory economics. I received a Ph.D. in Applied Economics and 11 an M.S. in Management from the Massachusetts Institute of Technology, and a B.A. 12 in Economics from Stanford University. I have been involved in research and 13 consulting on the economics and regulation of the natural gas, oil and electric utility 14 industries in North America and abroad for over twenty-five years. I frequently have 15 testified before federal, state and Canadian regulatory commissions, in federal court 16 and before the U.S. Congress, on issues of pricing, competition and regulatory policy 17 in these industries. Outside of North America, I have advised governments and 18 regulatory bodies on the structure of their natural gas markets and the pricing of gas 19 transmission services. These assignments have included testimony before the U.K. 20 Monopolies and Mergers Commission and the Australian Competition Tribunal, and 21 advice to the governments of, and regulators in, Greece, Ireland, the Netherlands, 22 New Zealand and Australia.
23 I have been extensively involved in the evaluation of the economics and regulation of 24 the natural gas industry in North America. In Canada, I have advised pipeline 25 companies and have previously testified before the National Energy Board (“NEB” or 26 the “Board”) and the Alberta Energy and Utilities Board (“EUB”) on matters relating 27 to pipeline competition and capacity expansion, including the Alliance Pipeline Ltd.
1 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 certification proceeding. I gave evidence on business risk previously before the NEB 2 in the multi-pipeline cost of capital case on behalf of Foothills Pipe Lines, in more 3 recent NEB proceedings on behalf of TransCanada PipeLines Limited (“TCPL”), and 4 I also gave evidence on business risk in the last proceeding before the Board 5 involving the Trans Québec and Maritimes (“TQM”) pipeline that resulted in 6 Decision RH-1-2008. I provided evidence on business risk before the Ontario Energy 7 Board (“OEB”) on behalf of Union Gas Limited and Enbridge Gas Distribution Inc. 8 in each of their 2007 rate applications. I also provided business risk evidence before 9 the Québec Régie de l’énergie in Gaz Métro’s 2008 and 2010 rate cases. Further 10 details of my educational and professional background, as well as a listing of my 11 publications, are provided in my curriculum vitae appended to this evidence as 12 Attachment A.
13 Q3. What assignment were you given in this proceeding?
14 A3. I have been asked by TCPL to provide evidence concerning the Mainline’s current 15 and prospective business risks as they affect the return on capital required by 16 investors in the Mainline. My business risk evidence is one input to the estimates of 17 the Mainline’s cost of capital provided in the evidence of my Brattle colleagues Dr. 18 Lawrence Kolbe and Dr. Michael Vilbert. I have also been asked to evaluate the use 19 of U.S. interstate pipelines and U.S. natural gas local distribution companies 20 (“LDCs”) as comparables to the Mainline for cost of capital estimation purposes. 21 And in particular, I have been asked to provide evidence concerning the business 22 profile and regulatory environment of the LDCs that make up Dr. Vilbert’s U.S. LDC 23 sample and the subset of interstate natural gas pipelines contained in Dr. Vilbert’s 24 U.S. pipeline sample. Finally, I provide evidence concerning the comparability of Dr. 25 Vilbert’s Canadian utility and U.S. oil pipeline samples to the Mainline from a 26 business risk perspective.
2 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q4. Could you summarize your conclusions with respect to the Mainline’s current 2 and prospective business risks?
3 A4. Yes. There has been a substantial and unexpected change in the competitive 4 landscape of the North American natural gas market since the last time the Board 5 evaluated the business risk of the Mainline for cost of capital purposes in RH-2-2004. 6 In particular, the development of new sources of unconventional gas supplies in the 7 Lower 48 has had a profound impact on the pattern of natural gas flows on the 8 pipeline grid in North America. Increasing supplies of natural gas from shale 9 formations in the Lower 48 have reduced the need for Canadian natural gas imports 10 into the Lower 48, resulting in substantial throughput declines on some pipelines, 11 especially the Mainline. These changes are having a significant effect on pipelines 12 like the Mainline that are dependent on the Western Canada Sedimentary Basin 13 (“WCSB”) for gas supply.
14 As a result of these trends, business risk for the Mainline has increased significantly 15 since 2004. The Mainline’s risk has also increased since the time of the Board’s 16 decision in RH-1-2008 for TQM as a result of its deteriorating competitive position. 17 As described in the Company’s evidence, actual throughput on the Mainline for 2010 18 turned out to be over 0.3 Bcf/d lower than TCPL’s 2004 low case forecast in RH-2- 19 2004 Phase II. While WCSB production has declined in recent years, other North 20 American basins have been witnessing reserves and production growth and are 21 vigorously competing for, and capturing, U.S. and Canadian markets that have 22 historically been served by WCSB gas production transported on the Mainline.
23 As an example of these trends, flows on the Mainline into Tennessee Gas Pipeline 24 (“TGP”) at Niagara have declined substantially, from 0.8 Bcf/d in 2004 to 0.2 Bcf/d 25 in 2010, and it is contemplated that physical reversal of flow may occur in the future 26 at Niagara. These declines have occurred as Tennessee Gas Pipeline has received 27 increasing supplies on its system from the Marcellus Shale and the Rocky Mountain 28 Supply Area (via the Rockies Express Pipeline). In other words, WCSB supplies via
3 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 the Mainline are being displaced by unconventional Lower 48 gas supplies, which are 2 now competing to serve markets that have historically been served by the Mainline. 3 These trends have resulted in substantial long-haul throughput declines on the 4 Mainline, and a corresponding increase in the amount of unsubscribed Mainline 5 capacity.
6 While the development of shale gas plays in British Columbia has the potential to 7 more than mitigate declines in conventional gas production in Alberta, there is 8 significant uncertainty regarding the ultimate production of these shale plays and the 9 extent to which this shale production will flow on the Mainline versus other possible 10 outlets such as LNG liquefaction facilities proposed in British Columbia, or potential 11 new gas-to-liquids (GTL) projects. At least three such liquefaction terminals have 12 been proposed that would export WCSB supplies, including shale supplies in the 13 Horn River Basin and Montney formations, to markets in Asia where prices for 14 natural gas have been traditionally linked to world oil prices, substantially higher than 15 the prices available in North America for natural gas. Moreover, we have now 16 entered a period of relatively low prices for gas due to the economic downturn and an 17 apparent glut of supply in the U.S. If this low price environment persists, supply 18 development activity in the WCSB may decline even faster than already anticipated 19 relative to other supply basins, given its locational and thus netback price 20 disadvantage in serving key export markets in the Midwest and Eastern U.S. and 21 domestic markets in Eastern Canada. All of these factors contribute to my opinion 22 that the current and prospective business risks of the Mainline are much higher than 23 they have been in the past, and that they are very high relative to other gas 24 transmission pipelines.
25 Thus, the Mainline is facing substantial competition in both its supply areas (from 26 proposed liquefaction terminals in British Columbia) and its market areas (from 27 Rocky Mountain and eastern shale supplies). In addition, increasing intra-Alberta 28 natural gas demand for oil sands production is further reducing the quantity of WCSB
4 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 supply available for transport on the Mainline. This increased competition facing the 2 Mainline has substantially increased the Mainline’s business risk, particularly in the 3 Status Quo case. In the Status Quo case, the Mainline’s business risk is higher than 4 the higher-risk pipes among comparable U.S. gas pipelines, so U.S. oil pipelines 5 make a better benchmark for the Mainline’s business risk in the Status Quo case.
6 TCPL is putting forward in this application its Restructuring Proposal, which includes 7 a series of changes relating to the way tolls are determined and designed for the 8 Mainline. These changes are intended to help mitigate, and prevent the full 9 realization of, the heightened business risks I described above by making Mainline 10 tolls more competitive and by encouraging more efficient use of Mainline facilities. I 11 conclude, however, that even if the Board approves the Restructuring Proposal, the 12 Mainline’s competitive situation is such that it would still face business risks at the 13 top of the range of comparable North American natural gas pipelines.
14 Q5. What do you conclude with respect to the use of market data for U.S. gas 15 pipelines for purposes of estimating the cost of capital for the Mainline?
16 A5. The use of market data for U.S. gas pipelines to estimate the cost of capital for the 17 Mainline is appropriate and relevant. While there are certainly differences in 18 regulatory procedure in the two countries that primarily affect year-to-year variances 19 in achieved returns and thus short-term variability risks, the underlying cost-of- 20 service and contract-carriage regulatory model applied in both countries is so similar 21 that fundamental capital recovery risks should be considered comparable.1 Moreover, 22 the gas market environment is now fully integrated in terms of gas flows and price 23 formation, so the same underlying gas market business conditions affect pipelines 24 similarly on both sides of the border. In other words, the U.S. and Canadian gas
1 Other reports have also concluded that the regulatory environments in Canada and the U.S. are comparable. See for example “A Comparative Analysis of Return on Equity of Natural Gas Utilities,” prepared for The Ontario Energy Board, Concentric Energy Advisors, June 14, 2007, p. 2. See also “Return on Equity: Allowed Returns for Canadian Gas Utilities,” A Discussion Paper Developed by the Canadian Gas Association, May 2007, pp. 15-16.
5 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 markets are integrated both physically and commercially—they should not be viewed 2 as separate gas markets. Gas pipeline transportation contracting practices are 3 essentially the same on both sides of the border, with pipeline shippers paying fixed 4 demand and variable fuel charges for firm transportation services and to compensate 5 pipelines for the costs incurred. Finally, as discussed in the evidence of Mr. Aaron 6 Engen, changes in global financial markets allow capital to flow freely between 7 nations. It simply does not make sense to view Canada’s pipeline industry in 8 isolation from other pipeline and capital markets. The Board agreed with this view in 9 its Decision RH-1-2008.2
10 Q6. What do you conclude with respect to the use of market data for U.S. gas LDCs 11 and oil pipelines?
12 A6. U.S. LDCs are also useful for comparison purposes, but are of lower risk than 13 pipelines such as the Mainline. U.S. oil pipelines are also comparable in that they are 14 also capital-intensive and subject to regulation. The use of market data on U.S. oil 15 pipelines is therefore also relevant for estimating the Mainline’s cost of capital.
16 Q7. How is the rest of your evidence organized?
17 A7. In Section II, I provide background on how business risk is typically defined and 18 evaluated so as to set the remaining context. In Section III, I discuss how the 19 business environment for pipelines has changed in recent years for natural gas 20 pipelines in Canada like the Mainline, and I evaluate the Mainline’s prospective 21 business risks under a scenario in which the Board does not approve the Restructuring 22 Proposal. In Section IV I describe the ways in which the Restructuring Proposal is 23 intended to mitigate prospective business risks. In Section V, I provide evidence as to 24 the comparability of U.S. pipelines and LDCs with the Mainline with respect to 25 business risk, including those firms in Dr. Vilbert’s pipeline and LDC samples. I also 26 comment on Dr. Vilbert’s oil pipeline and Canadian samples.
2 NEB, Decision RH-1-2008, pp. 66-72.
6 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 II. BACKGROUND ON THE CONCEPT OF BUSINESS RISK
2 Q8. What is business risk and how does it relate to a regulator’s decision to establish 3 an appropriate return on capital for a natural gas pipeline?
4 A8. One of the bedrock principles for establishing a fair return on capital for a regulated 5 pipeline that has been long recognized by economists, regulators, and the courts in 6 Canada and the U.S. is that a reasonable return should “be comparable with the return 7 available from the application of the capital to other enterprises of like risk.”3 Risk 8 for a natural gas pipeline has been defined to include financial and business risks. 9 Financial risk involves the extent to which debt is employed in the company’s capital 10 structure. Business risk is a somewhat more subjective concept and is more difficult 11 to quantify precisely,4 but it is sometimes categorized to include the supply, demand 12 (or market), competitive, operating and regulatory risks that might be faced by 13 particular pipelines.5 Both business and financial risks are accounted for in the 14 methodology employed by Drs. Kolbe and Vilbert to estimate the cost of capital for 15 the Mainline. For example, as discussed in their evidence, the “equity betas” that are 16 estimated using the Equity Risk Premium method capture the combination of 17 financial and business risks for the particular sample of publicly traded companies 18 employed.
3 National Energy Board, RH-1-70, p.7-5. See also National Energy Board, RH-1-2008, pp.6-7, where the Board stated that a fair or reasonable return on capital should meet three requirements. It should: (1) “be comparable to the return available from the application of the invested capital to other enterprises of like risk (comparable investment requirement)”, (2) “enable the financial integrity of the regulated enterprise to be maintained (financial integrity requirement)”, and (3) “permit incremental capital to be attracted to the enterprise on reasonable terms and conditions (capital attraction requirement).” 4 The Board has recognized that the assessment of business risk is an inherently qualitative exercise. See National Energy Board, RH-2-94, p. 24: “The Board has systematically assessed the various risk factors for each of the pipelines but has not found it possible to express, in any quantitative fashion, specific scores or weights to be given to risk factors. The determination of business risk, in our view, must necessarily involve a high degree of judgment, and is best expressed qualitatively.” 5 See, for example, National Energy Board, RH-4-2001, p. 13.
7 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q9. What kinds of risks matter the most in evaluating a company’s business risk 2 from a cost of capital perspective?
3 A9. The risks that matter the most from an equity investor’s perspective are those that 4 cannot be diversified away through the holding of a broad portfolio of securities. 5 Risks that are hard to diversify are those that are generally correlated with the level of 6 (and changes in) general economic activity. Such risks are referred to as “systematic.” 7 Broadly speaking, systematic risks associated with the gas transmission business 8 include uncertainties in the demand for, and supply of, transmission services that are 9 affected by changes in economic activity, including incomes, prices and broad 10 governmental policies including environmental concerns.
11 Q10. How does rate regulation affect a company’s business risk?
12 A10. On the one hand, rate regulation reduces a company’s business risk if it provides 13 equity investors some assurance that a fair return on and of capital will be earned over 14 the lifetime of the firm’s assets. On the other hand, regulation may increase a 15 company’s business risk if investors perceive that there is uncertainty in the future 16 regulatory treatment of the firm’s businesses. That is why regulatory risk is 17 sometimes (for example, by ratings agencies) evaluated as a separate component of 18 business risk. While the equity securities of rate regulated firms are generally 19 perceived as relatively stable, low-risk investments, the greater exposure of such 20 firms to competition from other regulated and unregulated businesses, and alternative 21 fuels, has changed that perception somewhat in recent years, particularly in the 22 energy utility sector.
23 Q11. Is there a time dimension to business risk, and if so, how should one think about 24 it?
25 A11. In prior cost of capital cases, distinctions have been drawn between so-called “short- 26 term” and “long-term” business risks. But these labels have actually been used to 27 describe two different types of risk and not just the time dimension. Short-term risk 28 has typically referred to factors that affect the year-to-year earnings of the company
8 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 in question, what I will refer to as “variability” risk. One example, applicable to 2 certain regulated utilities, is variations in weather from year to year which increase 3 the variability of earnings, but do not affect the long term expected earnings stream. 4 While one would expect investors to pay more for a stable earnings stream than for a 5 more volatile one with the same long term expected value, it is not a risk on which 6 long term investors would place great importance. These earnings variability risks 7 may be mitigated through the use of deferral accounts, for example. Other examples 8 of variability risk include one-time events that would affect year-on-year earnings, 9 but would not necessarily affect an investor’s long-term estimate of expected 10 earnings.
11 In contrast, long-term risks involve more fundamental uncertainties in supply, 12 demand, competition, and regulation. I will refer to these as “fundamental” risks. 13 Changes in these fundamental factors occur over time and they have the potential to 14 result in a failure to recover the expected return of and on the capital invested in the 15 regulated firm. While longer-term in nature, fundamental risks may also be realized 16 in the short term. Another important aspect of fundamental risk that distinguishes it 17 from variability risk is asymmetry. Under conventional cost of service regulation, the 18 potential for economic loss due to exposure to fundamental risk is not offset by the 19 potential to recover more than the return on and of capital. In my opinion, equity 20 investors give greater weight to these types of fundamental, capital recovery risks in 21 terms of their required return than they do to earnings variability risk.
22 Q12. Why do you say that equity investors give greater weight to fundamental capital 23 recovery risk?
24 A12. When investors buy a share of stock, they are buying a share of a long-term earnings 25 stream. They are not buying only a month, or even a year’s worth of performance. 26 The time horizon of any equity investment is inherently long term. The year-to-year 27 variability in the earnings of an equity investment is only a small part of the business 28 risk picture. This is particularly important for investments such as gas pipelines that
9 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 when “sunk” into the ground are difficult to redeploy to other valuable uses should 2 their fundamental risks begin to be realized. Furthermore, the extent to which 3 investors will demand higher returns for bearing variability risk will depend on 4 whether these risks can be diversified.
5 Q13. What did the Board find with respect to the time dimension of business risk in 6 RH-1-2008?
7 A13. In its RH-1-2008 decision, the Board accepted that it was useful to distinguish 8 between long-term and short-term risks in the manner I have described above. The 9 Board took the view “that because of the more limited ability of regulators to respond 10 to the realization of long-term risks, there is a sense, in this aspect, that they are more 11 important than short-term risks.” With respect to the weight to be applied to each 12 type of risk, the Board suggested that would be case-specific and it “would depend on 13 the relative probability, size and timing of the potential impacts arising from the 14 specific risks being realized.”6 I concur with these observations made by the Board in 15 RH-1-2008.
16 Q14. How has the Board previously evaluated pipeline business risk in the cost of 17 capital context?
18 A14. Starting with its 1995 decision in RH-2-94, the Board applied a formula-based 19 allowed return on equity for a “benchmark pipeline” to all of the Group 1 gas and oil 20 pipelines subject to the RH-2-94 Decision, while establishing a deemed equity 21 thickness for each pipeline that was to be reflective of each pipeline’s particular 22 business risks.
23 In subsequent decisions on cost of capital the Board has periodically reviewed the 24 business risk environment faced by investors in particular pipelines. For example, in 25 RH-4-2001, the Board evaluated the Mainline’s business risk for the first time since 26 RH-2-94. In that decision, the Board laid out its framework for business risk
6 NEB, Decision RH-1-2008, pp.45-46.
10 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 evaluation which separates business risk into five main sources: pipeline competition 2 risk, market risk, supply risk, regulatory risk and operating risk. The Board also 3 evaluated the Mainline’s business risk in RH-2-2004 Phase II.
4 Q15. How would you describe, within the framework of the Board’s business risk 5 analysis, the current situation facing the Mainline?
6 A15. As the Company’s evidence describes in detail, throughput on the Mainline has 7 declined and tolls have increased.7 Absent the implementation of its Restructuring 8 Proposal, the Mainline may be faced with the prospect at some point in the future of 9 being unable to recover its full cost of service, because if it were to increase its tolls 10 in an attempt to do so, throughput would fall further as the Mainline became 11 uncompetitive relative to other existing and potential future transportation options. 12 Within the framework of the Board’s business risk analysis, competition risk is much 13 higher than recognized in past Board decisions. Some of this competition risk has 14 already been realized and has reduced the Mainline’s level of firm contract 15 subscriptions and throughput relative to previous forecasts.
16 Q16. What was the Board’s assessment of the Mainline’s business risk in previous 17 decisions?
18 A16. The Board assessed the Mainline’s business risk in the generic cost of capital 19 proceeding RH-2-94, and reassessed it in RH-4-2001 and again in RH-2-2004 Phase 20 II. The Board also discussed business risk in RH-1-2001 (a proceeding in which the 21 cost of capital was not an issue).
22 In RH-2-94 the Board concluded that the Mainline faced business risks equivalent to 23 “a low-risk, high-grade regulated pipeline”, and awarded the Mainline a 30 percent 24 equity thickness.
7 See Mainline 2012-2013 Tolls Application, Part D, Section 11.
11 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 The Board concludes that TransCanada is a low-risk pipeline and 2 is less risky than unregulated industrial companies. The Board is 3 of the view that TransCanada’s risks have not decreased since last 4 evaluated in the context of a toll proceeding.
5 The Board is of the view that TransCanada’s ability to access 6 financial markets on the basis of a 30% deemed common equity 7 ratio over the past 15 years, except for 1982 and 1983 when a 8 common equity ratio of 28% was deemed, is evidence which 9 supports the appropriateness of a 30% deemed common equity for 10 TransCanada at this time. [RH-2-94, p. 25]
11 In RH-1-2001 the Board rejected the suggestion that the cost of de-contracting should 12 be shared between the Mainline and remaining firm shippers, because it said that this 13 was the realization of a risk that the Mainline had not traditionally been required to 14 bear. [RH-1-2001, p. 13]
15 In RH-4-2001 the Board increased the Mainline’s equity thickness to 33 percent. It 16 did so because it found that competition and supply risk had increased since RH-2-94.
17 Overall, the Board concludes that the level of business risk facing 18 the Mainline has increased since 1994, although it remains low. 19 The increased business risk primarily reflects an increase in the 20 risk resulting from pipe-on-pipe competition and increased supply 21 risk. Other sources of risk have not changed materially. [RH-4- 22 2001, p. 28]
23 In RH-2-2004 Phase II the Board increased the Mainline’s equity thickness to 36 24 percent, again because it said competition and supply risk had increased since the 25 RH-4-2001 decision.
26 The Board finds that, overall, the business risk to which the 27 Mainline is exposed has increased since RH-4-2001, as a result of 28 increases in supply risk and competitive risk. [RH-2-2004 – Phase 29 II, p. 47]
30 On May 31, 2007, the Board issued Order TG-06-2007, through which it approved a 31 multi-year negotiated settlement for the Mainline for a five-year period commencing 1
12 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 January 2007 and terminating 31 December 2011 (2007-2011 Settlement). The 2007- 2 2011 Settlement incorporated a deemed common equity ratio for the Mainline of 40 3 percent in each year from 2007 to 2011, inclusively.
4 I summarize below in greater detail my understanding of the Board’s reasoning in 5 these decisions.
6 Q17. Did the Board say anything in its prior decisions concerning whether investors 7 in the Mainline should bear the impacts of the realization of risks (due to 8 decontracting) for which Mainline investors had not been previously 9 compensated?
10 A17. Yes. In RH-1-2001 the Board discussed shipper proposals that would “share” the 11 impact of de-contracting between remaining shippers and the Mainline. The Board 12 said:
13 The Board sees a clear distinction between risk sharing and the 14 sharing of the realization of such risk. Absent clear evidence that 15 TransCanada has been imprudent or that its actions have caused 16 contract non-renewals, the Board is not inclined to impose, after 17 the fact, the financial impact of the realization of a risk that 18 TransCanada has not traditionally borne. [RH-1-2001, p. 13]
19 The Board went on to reject the “risk-sharing” proposals of the shippers, and 20 concluded:
21 Having rejected the risk-sharing proposals, the Board is left with 22 consideration of the proposal of TransCanada which would 23 continue to allocate TransCanada’s costs to firm shippers in 2001 24 and 2002, based on the traditional cost of service methodology. 25 Based on the evidence put forward in this proceeding, the Board is 26 satisfied that continuing to allocate the full cost of the pipeline to 27 shippers, using the traditional cost of service methodology, is 28 appropriate for 2001 and 2002. [RH-1-2001, p. 14]
13 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q18. How did the Board describe its decision to increase the Mainline’s equity 2 thickness in RH-4-2001?
3 A18. In RH-4-2001 the Board increased the Mainline’s authorized equity thickness because 4 it found that competition and supply risk had increased since RH-2-94. Other 5 elements of the Board’s business risk assessment, including regulatory risk, had not 6 changed. The Board said:
7 Overall, the Board concludes that the level of business risk facing 8 the Mainline has increased since 1994, although it remains low. 9 The increased business risk primarily reflects an increase in the 10 risk resulting from pipe-on-pipe competition and increased supply 11 risk. Other sources of risk have not changed materially. [RH-4- 12 2001, p. 28]
13 Q19. What did the Board say about competition risk in RH-4-2001?
14 A19. The Board explained that the Mainline was now exposed to a greater degree of 15 competition risk than it had been at the time of RH-2-94. The Board noted:
16 While many of the changes that have taken place since 1994 were 17 contemplated at the time of the RH-2-94 hearing and reflected in 18 the Board’s previous assessment of the Mainline’s business risk, 19 the weight that specific risk factors should be given may have 20 changed and may need to be re-examined in light of this evolution. 21 For example, the Board is of the view that, while the prospect of 22 increased pipe-on-pipe competition was recognized in RH-2-94, 23 this source of risk should be given more weight in assessing the 24 Mainline’s prospective business risk in light of a change in the 25 probability of expansions of existing pipelines. [RH-4-2001, p. 24]
26 To date, TransCanada’s earnings have not been affected by the 27 excess capacity or increased pipe-on-pipe competition since the 28 Mainline has been allowed to increase its tolls with the result that 29 it has earned its full Revenue Requirement. Nonetheless, there is 30 some uncertainty over the Mainline’s future ability to attract 31 sufficient gas volumes, which could have an impact on its earnings. 32 Specifically, the Mainline’s ability to recover its full cost of service 33 would be put in jeopardy if its throughput declined to a point 34 where the resulting tolls exceeded what the market could bear.
14 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 While there is no indication that such an outcome is to be 2 expected, the possibility that it may happen appears to have 3 increased since 1994. Accordingly, the Board is of the view that 4 there has been an increase in pipe-on-pipe competition since 1994, 5 which acts to increase the Mainline’s prospective business risk. 6 [RH-4-2001, p. 26]
7 Q20. Did the Board consider the possibility that the Mainline might, in the future, be 8 unable to recover its full cost of service due to insufficient throughput?
9 A20. Yes. The passage quoted above indicates that the Board considered this possibility in 10 RH-4-2001. But as the passage indicates, while the Board did not expect this to 11 occur, it considered that the possibility of this outcome was greater than it was in 12 1994.
13 Q21. Did the Board affirm, in RH-4-2001, that the regulatory model for the Mainline 14 would continue to be supportive?
15 A21. Yes. The Board said:
16 Although the regulatory regime has permitted increased 17 competition, there has been no indication that it has increased the 18 possibility that prudently incurred costs will not be recovered. For 19 example, there has been an annual true-up through deferral 20 accounts to collect real costs as incurred and the cost of under- 21 utilized capacity has been borne by shippers. As a result, the 22 Board is of the view that the regulatory model continues to provide 23 the Mainline with a reasonable opportunity to recover its 24 prudently incurred costs. [RH-4-2001, p. 27]
25 The Board went on to say:
26 The Board does not expect that the way in which TransCanada 27 conducts its Mainline business will remain unchanged. The world 28 in which the Mainline operates continues to evolve and the Board 29 expects that TransCanada’s management will be proactive in 30 recognizing new sources of risk arising from this evolution and in 31 finding means to mitigate such risk. [RH-4-2001, p. 27]
15 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Thus, as of its decision in RH-4-2001, the Board evaluated the Mainline’s business 2 risk under the assumption that the historically supportive regulatory model would 3 continue, and that TransCanada would look for ways to mitigate the prospective risks.
4 Q22. What was the Board’s view of business risk in RH-2-2004 Phase II?
5 A22. In RH-2-2004 Phase II the Board increased the Mainline’s equity thickness because it 6 found that competition and supply risk had increased. Again, it found that other 7 elements of risk had not changed. The Board said:
8 The Board finds that, overall, the business risk to which the 9 Mainline is exposed has increased since RH-4-2001, as a result of 10 increases in supply risk and competitive risk. [RH-2-2004 Phase II, 11 p. 47]
12 Q23. What did the Board say about competition and regulatory risk in RH-2-2004 13 Phase II?
14 A23. The Board found that competition risk had increased. The Board said:
15 Taking into consideration the further deterioration in the 16 contractual underpinnings of the Mainline, the market interest in 17 acquiring natural gas supply at Dawn and the prospects for LNG 18 in the Mainline’s market areas, the Board finds that, on balance, 19 the Mainline’s competitive risk has increased since RH-4-2001, 20 although not to the extent suggested by TransCanada. [RH-2-2004 21 Phase II, p. 45]
22 With respect to regulatory risk, the Board noted that:
23 The regulatory context for the Mainline is evolving, but the Board 24 finds no reason to conclude that the Mainline’s regulatory risk has 25 increased. The regulatory model continues to provide the 26 Mainline with a reasonable opportunity to recover its prudently 27 incurred costs…. While the Board acknowledges that regulators 28 may be unable to protect the Mainline if tolls become 29 uncompetitive, this has always been true and does not constitute a 30 change in regulatory risk. [RH-2-2004 Phase II, p.43]
16 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q24. Did the issue of the Mainline’s depreciation rate enter into the discussion of the 2 Mainline’s business risk in RH-2-2004 Phase II?
3 A24. Yes, it did, in response to the position taken by some parties in the proceeding that 4 because of approved increases in the Mainline’s depreciation rate over the prior few 5 years, business risk was necessarily reduced for the Mainline.
6 Q25. What did the Board say about depreciation as it relates to business risk in RH-2- 7 2004 Phase II?
8 A25. The Board said:
9 …there is a potential that a company’s tolls may not incorporate 10 sufficiently high depreciation rates because competitive factors 11 would prevent such rates from being charged. This potential, if 12 significant, is appropriately compensated through the cost of 13 capital.
14 The assessment of cost of capital should assume that the 15 depreciation rates reflect the best assessment of economic life of 16 the pipeline. Consequently, resetting depreciation rates to reflect a 17 new best estimate of economic life does not, by itself, reduce 18 business risk from what it would be absent a change in the best 19 estimate. [RH-2-2004 Phase II, pp. 46-7]
20 Thus, the Board acknowledged in RH-2-2004 Phase II that competitive factors may 21 prevent the company from raising its tolls to account for a change in its economic life, 22 and that such risks, “if significant,” are appropriately compensated through the cost of 23 capital.
24
17 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 III. NORTH AMERICAN MARKET ENVIRONMENT AND MAINLINE 2 BUSINESS RISK
3 A. REVIEW OF NORTH AMERICAN MARKET ENVIRONMENT
4 Q26. Could you describe some of the changes in the natural gas market environment 5 in North America that have occurred in recent years and their implications for 6 natural gas infrastructure investment?
7 A26. Yes. In recent years, and certainly since the last time the Board examined the 8 business risk of the Mainline in RH-2-2004 Phase II, there have been fundamental 9 changes in the supply, market and competitive landscape of the North American 10 natural gas market. In response to high natural gas prices during most of the last 11 decade, gas producers in the lower 48 responded by developing new sources of 12 supply and technology, particularly to access new shale gas formations. The 13 development of these supplies resulted in a substantial expansion of the natural gas 14 pipeline network in the lower 48 in order to allow the new supplies to reach end-use 15 markets. These new supplies have also resulted in changing flow patterns in the 16 North American pipeline grid. As I will describe in more detail below, additional gas 17 pipeline capacity has been added from the Rocky Mountain supply area to the 18 pipeline systems serving eastern U.S. markets. New shale supplies have also been 19 flowing into the eastern U.S. pipeline grid, from shale supply areas in the U.S. Gulf 20 Coast region, and more recently from the rapidly developing Marcellus shale in the 21 Appalachian region of the U.S. These new supplies have altered the dynamics of 22 pipeline competition in the Midwest and U.S. Northeast market areas. The growth of 23 Marcellus shale supplies has been particularly noteworthy as a growing indigenous 24 source of supply in the Northeast U.S. that competes in Northeast markets with more 25 distant supply sources.
26 These developments have resulted in increased competition for some of the 27 incumbent pipelines, including the pipelines that transport Canadian supplies to U.S. 28 markets, and especially the Mainline. In addition to facing increased competition in 29 its market areas, there is evidence that the Mainline will face additional competition
18 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 for supplies in Western Canada as a result of several proposals to develop LNG 2 liquefaction terminals in British Columbia (which would be used to export Western 3 Canadian gas supplies to markets in Asia), and from competition for supplies to serve 4 increased intra-Alberta demand associated with oil-sands development.
5 Q27. Can you review the price history during the course of the last decade that 6 resulted in the development of new natural gas supplies?
7 A27. Yes. As shown below in Figure 1, natural gas prices at the Henry Hub increased 8 significantly post-2004 in response to a general tightening in the supply-demand 9 balance in North American gas markets. The 12-month forward price curve at Henry 10 Hub reached $9.00/MMBtu in August 2005 and $12.00/MMBtu in September 2005 11 (following hurricane activity in the U.S. Gulf Coast in that period).8 While prices 12 declined somewhat to the $8.00/MMBtu range in 2006-2007, prices spiked again in 13 2008 to over $13.00/MMBtu in the summer of 2008. Following their peak in mid- 14 2008 natural gas prices collapsed as new production came on-line in the lower 48 in 15 the face of weakened demand due to the economic crisis. Since late 2008, Henry Hub 16 prices have been primarily in the $4.00-$5.00/MMBtu range.
8 An MMBtu is short for one million British thermal units or Btu. In this report, I also refer to dekatherms (or Dth). One Dth is the equivalent of one MMBtu. I also refer to volumetric measurements of gas where one Mcf is short for thousand cubic feet, MMcf is short for million cubic feet, and Bcf is short for billion cubic feet. One Mcf is the equivalent of one MMBtu and one Dth (assuming a heat content of 1,000 Btu per cubic foot).
19 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 1
1
2 Q28. Can you quantify the gas production increases that have occurred in the U.S. 3 since the 2004 period?
4 A28. Yes. I show total Lower 48 U.S. gas production in the 2000-2010 period below in 5 Figure 2. As indicated, production generally declined in the first half of the last 6 decade, with production falling from roughly 51.4 Bcf/d in 2000 to 48.2 Bcf/d in 7 2005. However, as new sources of supplies were developed (in response to higher 8 prices) these production declines were reversed such that production grew 9 substantially in the second half of the decade, from 48.2 Bcf/d in 2005 to 58.1 Bcf/d 10 in 2010. The figure also shows the production growth in comparison with the 11 forecasts of production made by the U.S. DOE EIA in 2004. As indicated, production 12 growth in the Lower 48 has now outstripped even the highest forecast by EIA in 13 2004.
20 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 2
1
2 Q29. Can you elaborate on the new sources of supplies that were developed in 3 response to high prices?
4 A29. Yes. The most significant development activity in the post-2004 period occurred in 5 the Rocky Mountain supply area (Wyoming, Colorado, and Utah) and among various 6 shale gas plays in Texas, Louisiana, and Arkansas. The Staff of the U.S Federal 7 Energy Regulatory Commission noted this activity in its 2007 State of the Markets 8 Report (published in March 2008). The report commented that gas production 9 increases in the U.S. were
10 largely the result of tapping new gas sources in East Texas, the 11 Rockies and federal offshore. Natural gas prices in the United 12 States have now been high enough for long enough to see a 13 significant production response. Much of the new gas comes from 14 relatively new technologies that are economic at recent prices: gas
21 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 from shale in East Texas and Arkansas, record deep water gas in 2 the Gulf, along with coalbed methane and tight formation gas in 3 the Rockies. In fact, estimates suggest that gas rigs drilling for 4 “unconventional” plays accounted for about 68% of the total gas 5 rig count in 2007.9
6 More recently, substantial new supplies have been developed in the Marcellus shale 7 in the Appalachian region. As I will discuss in more detail below, these Marcellus 8 shale supplies represent another important new source of competition for supplies that 9 have historically been delivered by the Mainline into markets in the U.S. Northeast.
10 Q30. How much growth has there been in U.S. shale supplies since 2004?
11 A30. A recent 2011 EIA presentation shows the substantial increases in U.S. shale 12 production that have occurred during the last decade.10 As indicated in the slide 13 shown in Figure 3 below, reproduced from that presentation, U.S. shale supplies have 14 grown from roughly 0.5 Tcf (1.4 Bcf/d) in 2004 to nearly 5.0 Tcf in 2010 (13.7 15 Bcf/d), an increase of roughly 900 percent. This growth in shale supplies was 16 unforeseen at the time the NEB last reviewed the Mainline’s business risk. Another 17 slide shown in Figure 4 below, reproduced from the same presentation, shows that 18 EIA is currently projecting that shale supplies will serve an increasing percentage of 19 U.S. gas requirements in the future. As depicted in the figure, EIA projects the 20 percentage of shale production to grow from 14 percent of total U.S. consumption in 21 2009 to 46 percent in 2035, while net imports (including both LNG and pipeline 22 imports from Canada) are projected to decline from 11 percent in 2009 to 1 percent in 23 2035. Thus, shale gas is now predicted to effectively displace all Canadian gas 24 imports to the Lower 48 over the next 25 years.
9 2007 State of the Markets Report, prepared by Staff of the Federal Energy Regulatory Commission, March 20, 2008, slide 5. 10 See “Shale Gas and the Outlook for U.S. Natural Gas Markets and Global Gas Resources,” presentation by Richard Newell, Administrator to the Organization for Economic Cooperation and Development (OECD). June 21, 2011.
22 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 3
1
Figure 4
2
23 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q31. How has the development of new natural gas sources in the Rockies and in shale 2 gas plays changed the landscape of the U.S. natural gas pipeline grid?
3 A31. Because of their geographic dispersion, these new natural gas supplies have required 4 the development of a substantial amount of new gas pipeline capacity to allow this 5 production to be delivered to U.S. gas consumers. Figure 5 below shows the amount 6 of new pipeline capacity that has been added during the past decade. As indicated, 7 additions of pipeline capacity increased significantly at the end of the decade.
Figure 5
8
9 EIA explained the recent boom in pipeline construction as being directly tied to the 10 development of new natural gas sources,
11 Robust construction of natural gas infrastructure in 2008 resulted 12 in the completion of 84 pipeline projects in the lower 48 States, 13 adding close to 4,000 miles of natural gas pipeline. These
24 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 completions of new natural gas pipelines and expansions of 2 existing pipelines in the United States represented the greatest 3 amount of pipeline construction activity in more than 10 years. 4
5 Increased access to growing supplies continued to drive the high 6 level of pipeline construction during the year. The push for access 7 to new supply sources has led to rapid infrastructure growth in 8 relatively undeveloped production regions such as the Rocky 9 Mountains, as well as additions to well-established natural gas 10 transportation corridors such as in Northeast Texas, where industry 11 is exploiting unconventional resources. Furthermore, 12 infrastructure additions related to imports of natural gas, including 13 liquefied natural gas (LNG), were substantial in 2008.
14 ****
15 More than one-third of the pipeline projects in 2008 addressed a 16 growing need for additional natural gas pipeline capacity to 17 support transportation of new natural gas production to regional 18 markets, adding 16.3 Bcf per day of pipeline capacity overall. 19 Such projects were concentrated in the expanding natural gas 20 production areas of Wyoming, western Colorado, and the Barnett 21 shale formation in northeast Texas. About 10 percent of all newly 22 added natural gas pipeline capacity for 2008, or 4.6 Bcf per day, 23 was attributable to new intrastate pipelines built to transport 24 expanding Barnett shale production specifically. This layer of 25 infrastructure primarily provided access to local markets and 26 interconnections with the interstate natural gas pipeline network.11
27 Q32. How would you characterize the development of this new pipeline 28 infrastructure?
29 A32. In general, much of this new pipeline infrastructure represents “supply-push” projects 30 (rather than “demand-pull” projects) in that the projects are intended to allow new, 31 lower-cost sources of natural gas supplies to reach consuming markets. In other 32 words, much of the new capacity was not the result of incremental gas demand 33 growth that has required new supplies. The new supplies that have been able to reach
11 “Expansion of the U.S. Natural Gas Pipeline Network: Additions in 2008 and Projects Through 2011,” Energy Information Administration, p. 1, 3 (emphasis added).
25 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 market as a result of this new infrastructure are displacing other sources of more 2 expensive gas supplies, including WCSB gas supplies transported by the Mainline.
3 B. COMPETITION RISK
4 Q33. What is the importance of this “supply-push” pipeline infrastructure to the 5 Mainline’s business risk situation, and in particular the competition risk it now 6 faces?
7 A33. As I discuss in more detail below, the development of this new infrastructure has 8 created increased competition for the Mainline in the Midwest and Eastern U.S. 9 markets that it has historically served. Moreover, this new infrastructure has resulted 10 in changes to some of the flow patterns, contracting, and historical pricing 11 relationships in Western and Eastern markets in North America, which have served to 12 significantly reduce the value of long-haul transportation on the Mainline.
13 Q34. Can you provide some specific examples of new pipeline infrastructure that has 14 resulted in increased competition for the Mainline?
15 A34. Yes. One of the largest pipeline projects completed in the last decade was the 16 Rockies Express project. Rockies Express is a 1.8 Bcf/d pipeline that extends from 17 the Meeker and Wamsutter hubs in Colorado and Wyoming through Nebraska, 18 Kansas, Missouri, Illinois, Indiana and terminating in Ohio. The pipeline went into 19 service in separate phases. REX West (from Cheyenne to Missouri) entered into 20 service in May 2008 and REX East (from Missouri to the Lebanon Hub in Ohio) 21 entered into service in June 2009. A final leg of the pipeline (from Lebanon to 22 Clarington, Ohio) went into service in November 2009. The Rockies Express 23 pipeline allows Rocky Mountain supplies to be delivered into the Midwest and 24 Northeast markets that are also served by the Mainline. For example, Rocky 25 Mountain supplies delivered via Rockies Express are now delivered into Tennessee 26 Gas Pipeline, which directly competes with the Mainline in serving gas markets in 27 New York and New England.
26 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q35. Can you provide additional details regarding the competition the Mainline faces 2 from Tennessee Gas Pipeline in serving Northeast gas markets?
3 A35. Yes. The Mainline serves markets in New York and New England via 4 interconnections with Iroquois Pipeline in Waddington, New York, and Tennessee 5 Gas Pipeline and Empire State Pipeline near Niagara Falls, New York. In addition, 6 the Mainline delivers gas to the TQM system in Quebec, which serves the New 7 England gas market via an interconnection with the Portland Natural Gas 8 Transmission System (which delivers gas to customers in Maine, New Hampshire, 9 and Massachusetts).12
10 Tennessee Gas Pipeline delivers gas to New York and New England on segments of 11 its system known as Lines 200 and 300. Line 200 is the northernmost segment of the 12 TGP system (traversing western New York eastward across the state and through 13 Massachusetts) and receives supplies from the Mainline at Niagara and from Iroquois 14 at Wright. Line 300 passes through northern Pennsylvania, into New Jersey and ends 15 at the Connecticut-Massachusetts border.
16 The composition of TGP’s receipts on Line 200 and Line 300 has changed 17 significantly in the recent past due to the commencement of service of Rockies 18 Express and the development of new supplies in the Marcellus shale. In its current 19 rate proceeding before the FERC (Docket No. RP11-1566), TGP has provided 20 evidence (reproduced below in Figures 6 through 9) of the degree to which Rocky 21 Mountain and Marcellus supplies have become larger sources of supply on its system 22 while the volume of Canadian supplies received at Niagara and Wright (originating 23 from the Mainline) have declined dramatically.
12 PNGTS and Maritimes & Northeast Pipeline jointly own the segment of pipeline (known as the Joint Facilities) that extends from Westbrook, Maine to Dracut, Massachusetts. Maritimes owns an undivided two-thirds interest in the mainline of the Joint Facilities, while PNGTS owns an undivided one-third interest.
27 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 6
1
Figure 7
2
28 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 8
1
Figure 9
2
29 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 As can be seen in these charts, gas supplies from the Marcellus Shale and Rocky 2 Mountains are increasing sources of gas supplies on the TGP system, while gas 3 supplies from Canada have been declining substantially. In other words, the Mainline 4 has been losing significant market share in the Northeast markets it has historically 5 served.
6 Q36. Have there been other expansions of the pipeline system into the Northeast U.S. 7 that underscore the increased competitive pressures faced by the Mainline?
8 A36. Yes, other projects have been completed in the past few years that show increased 9 competition to the New England markets that have historically been served by the 10 Mainline. Tennessee Gas Pipeline placed its “Northeast ConneXion – New England” 11 project into service in November 2007. It provides 136,000 Dth/d of incremental 12 transportation capacity into New England. The project is supported by long-term 13 firm agreements with four shippers, the largest of which is National Grid (formerly 14 Boston Gas) with a contract for 112,700 Dth/d.
15 Another significant development has been the establishment of the Canaport LNG 16 terminal in eastern Canada, which began service in June 2009. The terminal, located 17 in Saint John, New Brunswick has 1.2 Bcf/d of send out capacity and provides gas to 18 markets in eastern Canada and New England via the Brunswick pipeline and an 19 expansion of the Maritimes & Northeast (M&NE) system. This expansion of M&NE 20 (known as the Phase IV expansion) was completed in January 2009 and roughly 21 doubled the capacity of the U.S. portion of M&NE from roughly 415,000 Dth/d to 22 833,000 Dth/d.13 The Phase IV expansion was underpinned by a contract with Repsol 23 Energy North America for 730,000 Dth/d of firm capacity (330,000 Dth/d to
13 118 FERC¶61,137. The FERC Order that approved this expansion of the Maritimes & Northeast pipeline noted that Maritimes had proposed in its original application to increase the capacity of the Maritimes/PNGTS joint facilities an additional 150,000 Dth/d for the account of PNGTS. However, in its amended application, Maritimes withdrew its proposal to construct this 150,000 Dth/d for PNGTS on the joint facilities because PNGTS was not able to make a definitive commitment to the new capacity on the joint facilities in the time frame necessary for the Phase IV expansion to be in service to deliver gas from the Canaport LNG terminal.
30 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Tennessee Gas Pipeline at Dracut, Massachusetts and 400,000 Dth/d to Algonquin at 2 Beverly, Massachusetts). LNG imports to the Canaport terminal have been 3 substantial, as shown below in Figure 10.
Figure 10
4
5 Two other LNG projects have also been built offshore Massachusetts, but have seen 6 little import activity to date. Excelerate Energy’s Northeast Gateway LNG project 7 was placed into service in May 2008. It has sendout capability of roughly 500-800 8 MMcf/d. The project delivers gas into Algonquin pipeline, which constructed an 800 9 MMcf/d lateral from its existing offshore Hubline project to the Northeast Gateway 10 deepwater LNG port. Suez Energy’s Neptune LNG project was completed in May 11 2010. It has 400-750 MMcf/d of sendout capability, and also interconnects with 12 Algonquin’s Hubline project.
31 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q37. Are there other prospective projects in the Northeast that further evidence the 2 increasing competitive pressures on the Mainline?
3 A37. Yes. There are several projects that have been proposed in the U.S. Northeast, most 4 of which are designed to allow additional gas supplies from the Marcellus Shale to 5 reach markets throughout the Northeast and into Ontario. For example, Tennessee 6 has proposed its “Northeast Supply Diversification Project” to transport up to 250,000 7 Dth/d of Marcellus Shale production to markets in the Northeast, including deliveries 8 westerly on its Line 300 via backhaul and into its Line 200 for deliveries to Niagara 9 (into the Mainline) or to delivery points in New England.14 Tennessee has proposed 10 other projects to transport Marcellus Shale production. It is currently conducting an 11 open season for a new expansion project that would connect its Line 300 in eastern 12 Pennsylvania with its Line 200 in New York near its interconnect with Iroquois.15 13 Empire Pipeline’s Tioga County Extension Project will allow a reversal of flow on 14 Empire such that it can receive up to 350,000 Dth/d of Marcellus supplies and 15 transport them to the Mainline at Chippawa (near Niagara).16 Similarly, National 16 Fuel has also proposed its Northern Access Project to transport up to 320,000 Dth/d 17 of Marcellus production received from Tennessee Gas Pipeline to the Mainline at 18 Niagara.17
19 Iroquois Gas Transmission is proposing its own projects that would allow it to 20 transport Marcellus supplies to markets on its system in New York and New England. 21 For example, Iroquois’ proposed Wright Transfer Compressor (“WTC”) Project
14 Tennessee filed its FERC application for this project in November 2010. The application noted that that project was supported by three shippers who have fully subscribed the capacity of the project. See Tennessee’s application dated November 12, 2010 in FERC Docket No. CP11-30. 15 See Open Season notice #818 on Tennessee Gas Pipeline’s website. The initial capacity of this project is anticipated to be approximately 600,000 Dth/d with an estimated in-service date in late 2016 or early 2017. 16 Empire filed its FERC application for this project in August 2010. See Empire’s application dated August 26, 2010 in FERC Docket No. CP10-493. 17 National Fuel filed its FERC application for this project in March 2011. The application noted that that the design capacity of the project has been subscribed under a precedent agreement contemplating a firm transportation agreement with a primary term of 20 years with a producer of gas from the Marcellus Shale. See National Fuel’s application dated March 7, 2011 in FERC Docket No. CP11-128.
32 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 would allow Iroquois to access Marcellus supplies at its interconnect with Tennessee 2 Gas Pipeline’s 200 Line in Wright, New York. WTC would compress 250,000 Dth/d 3 from a new Tennessee/Iroquois interconnect into Iroquois’ system at the existing 4 Wright meter station. Currently Wright functions primarily as a delivery point on the 5 Iroquois system (where Canadian supplies on Iroquois can be delivered into 6 Tennessee Gas Pipeline). The WTC Project would make the Wright interconnect bi- 7 directional, allowing Iroquois to receive substantial supplies from Tennessee (thereby 8 displacing supplies received via the Mainline). Iroquois has also proposed the 9 NYMarc Project that would allow it to receive Marcellus supplies from Millenium 10 Pipeline, Tennessee’s Line 300, or from new gathering systems in the Marcellus for 11 delivery to markets in New York, New England, and Eastern Canada. Initial capacity 12 is expected to be 500,000 Dth/d.18
13 Several other projects have also been proposed in the Northeast, most of which are 14 designed to transport Marcellus shale production to market. These projects are shown 15 below in Figure 11, a slide reproduced from a recent presentation by the president of 16 the Northeast Gas Association.19
18 Neither the WTC project nor the NYMarc project has been filed for at the FERC, but the projects are still indicative of the types of projects that are being proposed in the Northeast U.S. that are creating competitive risk for the Mainline. 19 See “Northeast Natural Gas Supply & Infrastructure,” by Tom Kiley, Northeast Gas Association, Presentation to Inter-Area Planning Stakeholder Advisory Committee (IPSAC) Webinar, June 27, 2011.
33 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 11
1
2 Q38. Are there other prospective projects in the Midwest that indicate increasing 3 competitive pressures on the Mainline?
4 A38. Yes. One project that has been proposed is the Dawn Gateway Project proposed by 5 Spectra Energy and DTE Energy. The Dawn Gateway Project is a proposed 21 mile 6 pipeline that would increase storage interconnectivity between Michigan and Ontario, 7 thereby allowing new sources of supplies such as Rockies gas to serve Ontario and
34 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 the Dawn Hub. The project would provide an initial capacity of 360,000 Dth/d using 2 a combination of new and existing pipelines.20
3 Aside from Dawn Gateway, there is the potential that some Marcellus gas could be 4 delivered via backhaul on Rockies Express into Midwest markets. In fact, Rockies 5 Express has acknowledged that its system is well-situated to provide growing 6 Marcellus production access to Midwest markets.21
7 Q39. In addition to facing new competition in its market areas, is the Mainline facing 8 increased competition in its supply area?
9 A39. Yes. The Mainline is facing additional competition for supplies in Western Canada, 10 where new shale supplies are also being developed. Most of the emerging shale 11 activity is located in northeast British Columbia, specifically in the Montney 12 formation and the Horn River Basin. However, there is the potential that some of 13 these emerging shale supplies will be transported to the west coast of British 14 Columbia for liquefaction and delivery to gas markets in Asia in the form of LNG. 15 There are currently two LNG export terminals proposed for British Columbia, the 16 Kitimat LNG terminal proposed by Apache Corporation, EOG Resources and Encana 17 Corporation, and a project proposed by BC LNG Export Co-operative LLC (“BC 18 LNG”).22 A third LNG export project is being considered by Shell that would have 19 the capability to export roughly 1 to 2 Bcf/d, and another project is being considered 20 by Progress Energy Resources and the Malaysian national oil and gas company 21 Petronas.23 These export projects are being driven by the opportunity to serve Asian
20 The Dawn Gateway Project has been delayed until November 2012 or until sufficient market support can be obtained. Nonetheless, the project is still indicative of the prospective competition risks facing the Mainline in its Midwest U.S. markets. 21 See “REX eyes backhaul in response to Marcellus growth,” Gas Daily, August 5, 2010. 22 Kitimat LNG filed its application with the NEB on December 9, 2010. Kitimat LNG requested approval to export up to 1.4 Bcf/d. It is initially planned as a 700 MMcf/d export terminal with a planned in-service date of 2015. BC LNG filed its application with the NEB on March 8, 2011. BC LNG requested approval to export up to 250 MMcf/d. It is initially planned as a 125 MMcf/d export terminal with a planned in- service date of 2013. 23 See “North America Natural Gas Export Plans,” Reuters, May 11, 2011. See also “Shell Canada says it’s looking at B.C. coast for new LNG terminal,” Vancouver Sun, May 28, 2011. See also August 2, 2011
35 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 natural gas markets, which are widely perceived as premium natural gas markets that 2 are willing to pay higher prices for LNG relative to natural gas prices in North 3 America. Current prices for LNG supplies in Japan generally exceed $10.00/MMBtu, 4 much higher than the $4.00-$5.00/MMBtu prices now prevailing in North American 5 markets. These price differences are explained by the tendency of Asian LNG 6 contract prices to be linked to oil prices (while North American gas prices are 7 determined in liquid spot markets). If these LNG export proposals in British 8 Columbia move forward and are constructed, a significant portion of the emerging 9 shale supplies in Western Canada may not be available for transportation on the 10 Mainline. The existing Westcoast system already transports gas from the Horn River 11 and Montney basins to the border of British Columbia and Washington state at 12 Huntingdon/Sumas. In fact, it has been reported that the increasing flows from these 13 shale basins has lowered prices at Sumas and reversed the price differential between 14 Sumas and Kingsgate (where supplies from Alberta enter the U.S. at the British 15 Columbia-Idaho state border).24
16 Q40. Are there other examples of the competition facing the Mainline in its supply 17 area?
18 A40. Yes, another example of competition for supplies can be seen in the recent 19 announcement that Talisman Energy and Sasol have teamed to launch a feasibility 20 study into a proposed natural gas-to-liquids plant in Western Canada. The project 21 sponsors have held talks with the British Columbia energy ministry about potentially 22 locating the plant in British Columbia.25 A potential gas-to-liquids project would 23 compete for the same shale supplies that the Mainline hopes to attract for 24 transportation to its market areas. Thus, this gas-to-liquids project and the potential 25 LNG projects described above are representative of the increased competition risk
news release of Progress Energy (“Progress Energy Announces the Closing of its Strategic Partnership with Petronas”). 24 See “New supply reverses Sumas-Kingsgate spread,” Gas Daily, August 1, 2011. 25 See “Multibillion-dollar plant for B.C. shale gas proposed, Talisman Energy and South Africa’s Sasol launch feasibility study,” The Vancouver Sun, June 30, 2011.
36 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 facing the Mainline at the supply end of the pipeline. In addition, as discussed in the 2 Company’s throughput study, the amount of gas available for transport on the 3 Mainline is dependent on gas demand in Western Canada. The Throughput Study 4 forecasts gas demand growth in Western Canada of roughly 1.9 Bcf/d in the 2010- 5 2020 period, of which 1.1 Bcf/d is related to oil sands production and 0.3 Bcf/d is for 6 electric generation.26
7 C. SUPPLY RISK
8 Q41. How has the Board defined supply risk in prior decisions?
9 A41. The most recent Board decision to interpret the concept of supply risk was RH-4- 10 2010 involving the Maritimes & Northeast Pipeline. In that decision, the Board 11 reiterated its view that supply risk involves the “risk that the physical availability of 12 economical natural gas volumes could affect a pipeline’s income earning capability.” 13 And the Board referred in that case to “the uncertainty about the reserves and 14 production of gas supply that would support throughput on the Pipeline.” 27
15 Q42. What is your general understanding of how WCSB production has changed 16 since 2004?
17 A42. My understanding of the WCSB supply situation is based on the Company’s evidence 18 and conclusions, including its Throughput Study.28 WCSB production is currently 19 much lower than that which was being forecast in 2004. However, current forecasts 20 are that WCSB production will increase as unconventional production comes on 21 stream, such that the 17 Bcf/d levels, which in 2004 were forecast to be achieved in 22 2010, are now forecast to be achieved by 2017.
26 See Mainline 2012-2013 Tolls Application, Appendix C1. 27 National Energy Board, RH-4-2010, p.14. 28 See Mainline 2012-2013 Tolls Application, Appendix C1.
37 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 The addition of the Northeast BC shales has resulted in a significant increase in 2 remaining WCSB economic potential, and this additional resource is expected to 3 result in increased throughput on downstream pipelines, including the Mainline.
4 At the same time as WCSB supply is increasing, local demand (principally for oil- 5 sands production) is also forecast to increase. However, the net effect is that WCSB 6 exports are forecast to increase between now and 2020.
7 In the longer term, there is the possibility that the Mackenzie and Alaska pipeline 8 projects could bring additional gas to Transcanada’s TransCanada’s systems, and that 9 this gas could offset declines in WCSB production. However, these projects are 10 highly uncertain and are not currently included in the Company’s base case forecasts.
11 D. MARKET RISK
12 Q43. Are there indications that the Mainline’s market risk has increased since 2004?
13 A43. One indicator of increased market risk is the lower level and rate of growth in the 14 current forecasts of natural gas demand in the U.S. markets served by the Mainline 15 relative to the same forecasts in 2004. As shown in Figure 12 below, the EIA has 16 substantially reduced its forecast for gas demand in the New England, Mid-Atlantic 17 and East North Central regions of the United States.29 In aggregate, forecast 2025 18 demand for these regions is 22.7 Bcf/d in the EIA’s 2011 forecast versus 29.0 Bcf/d 19 in the EIA’s 2004 forecast. The lower slope of the 2011 forecast in Figure 12 20 indicates that the growth rate in EIA’s forecast is also lower today than it was in 21 2004. Lower gas demand growth increases risk for the Mainline since it reduces the 22 likelihood that the Mainline will be able to attract incremental volumes to its system.
29 These regions cover the states of Wisconsin, Illinois, Indiana, Michigan, Ohio, Pennsylvania, New Jersey, New York, Connecticut, Rhode Island, Massachusetts, New Hampshire, Vermont, and Maine.
38 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 12
1
2 Q44. What are some of the expected trends in natural gas demand in the markets 3 served by the Mainline?
4 A44. One of the important emerging trends in the Mainline’s traditional market areas is the 5 potential growth in natural gas demand for use in electricity generation, particularly 6 as natural gas generating units substitute for retiring coal-fired electric generation 7 units. In Ontario, the phase out of coal-fired generation is already underway, with 8 nearly 7,500 MW of coal-fired generation expected to close by 2015. The NEB’s 9 2009 Energy Market Assessment noted that a combination of 3,900 MW of 10 combined-cycle gas and 1,300 MW of combustion turbines and cogeneration 11 facilities in Ontario would be relied on to meet demand following the phase out of
39 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 coal-fired generation in the province.30 The 2009 Energy Market Assessment 2 projected natural gas demand growth in Ontario from 2.4 Bcf/d in 2010 to 2.6 Bcf/d 3 in 2020, an increase of 0.2 Bcf/d (9 percent). However, it is important to note that to 4 the extent that new gas plants are built in the Mainline’s Central or Southwestern 5 Delivery Areas to serve electricity demand following the phase out of the coal units, 6 there is no assurance that this will result in new Mainline transportation contracts 7 since these are areas where the Mainline faces significant competition.
8 Q45. Are coal plant retirements and increased natural gas demand also expected in 9 the Midwest and Northeast U.S.?
10 A45. Many market observers are now expecting substantial coal plant retirements in the 11 U.S. (and corresponding increases in natural gas demand) as a result of new 12 environmental regulations by the U.S. Environmental Protection Agency. In 13 particular, some observers are expecting significant coal plant retirements in the 14 Midwest U.S. (a region that currently relies heavily on coal-fired generation) over the 15 next 5-10 years. For example, in a December 2010 study my colleagues at The 16 Brattle Group estimated that there could be 12-19 GW of coal plant retirements in the 17 Reliability First electric reliability region (which spans several states from Wisconsin 18 in the west to New Jersey in the east) as a result of the EPA regulations.31 While 19 some coal plant retirements are expected in the Northeast U.S., the amount of 20 retirements is much less than in the Midwest because the Northeast does not rely as 21 much on coal-fired generation. My colleagues have estimated only 2-3 GW of 22 potential coal plant retirements in the U.S. Northeast.
30 “2009 Reference Case Scenario: Canadian Energy Demand and Supply to 2020,” National Energy Board, July 2009, p. 36. 31 See “Potential Coal Plant Retirements Under Emerging Environmental Regulations,” Metin Celebi, Frank Graves, Gunjan Bathla, and Lucas Bressan, The Brattle Group, December 8, 2010, slide 7. The boundaries of Reliability First are defined by the service territories of Load Serving Entities (LSEs) and include all of New Jersey, Delaware, Pennsylvania, Maryland, District of Columbia, West Virginia, Ohio, Indiana, Lower Michigan and portions of Upper Michigan, Wisconsin, Illinois, Kentucky, Tennessee and Virginia.
40 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 While this projected growth in gas demand is possible, there is significant uncertainty 2 as to the amount of coal plant retirements and coal-to-gas substitution that will 3 ultimately occur, as well as in the timing and pace of any potential growth in gas 4 demand. This uncertainty exists due to regulatory, political and market uncertainties. 5 For example, while the EPA has issued certain rules and implementation timelines, 6 there is still political uncertainty regarding whether these rules will be implemented 7 as currently structured or whether there will be implementation delays.
8 Q46. Are there other factors in the electricity markets that may put downward 9 pressures on gas demand in the Mainline’s traditional market areas?
10 A46. Yes. The development of renewable energy resources may put downward pressures 11 on gas demand in some regions. For example, new renewable energy resources are 12 proposed for New England that would serve to reduce natural gas demand for electric 13 power generation. These facilities are typically developed as “must-take” resources 14 that can displace the marginal fuel from the dispatch order, which in New England is 15 natural gas. Thus, renewable resources can back out gas-fired generation and the 16 associated gas demand. Currently there is 3.4 GW of wind capacity proposed in New 17 England and 5.7 GW proposed in New York. There is also a proposal to build a new 18 transmission line into New England (known as the Northern Pass project) to access 19 1.2 GW of excess hydro generation owned by Hydro-Quebec. These projects have 20 the potential to reduce natural gas demand in New England and New York. Likewise, 21 Ontario has been actively encouraging the development of renewable energy. 22 Ontario’s Long-Term Energy Plan sets a target for clean renewable energy from 23 wind, solar and bioenergy of 10,700 MW by 2018 (excluding hydroelectric power).32
24 Q47. Can you summarize your opinion regarding the market risk facing the 25 Mainline?
26 A47. Overall, the Mainline’s market risk has increased due to the reduced level and growth 27 rate of, and the high uncertainty associated with, forecast natural gas demand in its
32 See “Ontario’s Long-Term Energy Plan,” p. 10.
41 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 key market areas, particularly since the Board last reviewed the Mainline’s business 2 risks in 2004. In addition, there is now considerable uncertainty as to whether a 3 robust economic recovery can be expected to occur any time soon. It is becoming 4 apparent that the recession experienced subsequent to the financial crisis of 2008 was 5 not simply a downturn in the typical business cycle, but that it could reflect more 6 serious and long-term structural problems in the U.S. and global economies that may 7 be difficult to rectify.
8 E. REGULATORY RISK
9 Q48. How has the Board defined the term “regulatory risk”?
10 A48. In RH-2-2004 Phase II, the Board defined regulatory risk as “the risk to the income- 11 earning capability of the [regulated] assets that arises due to the method of regulation 12 of the company.”
13 Q49. Is there a connection between regulatory risk and the other elements of business 14 risk?
15 A49. Yes. To an extent, the method of regulation (or what I will call the “regulatory 16 framework”) influences the extent to which risks in the Mainline’s external business 17 environment are borne by the Mainline’s investors, or by the Mainline’s customers. 18 For example, the external business environment might give rise to a risk associated 19 with year-to-year changes in throughput. A regulatory framework which required the 20 Mainline’s investors to bear this risk would give rise to greater business risk than a 21 regulatory framework which passes on this risk to customers through deferral and 22 true-up.
23 Relatedly, there is a connection between regulatory risk and competition risk. 24 Competition risk refers to the possibility that, at some point in the future, the 25 Mainline might not be able to recover its authorized revenue requirement, because of 26 insufficient throughput and competition for supply and/or market, or the threat of
42 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 competition from alternative pipelines. The regulatory framework influences the 2 extent to which competition risk is borne by the Mainline’s investors or its customers. 3 However, the regulatory framework also influences the way in which the Mainline is 4 able to respond to and mitigate competition risk. Thus, in a sense, the regulatory 5 framework can attenuate or magnify the magnitude of competition risk facing the 6 Mainline depending on how it is applied.
7 Q50. What has the Board said about the allocation of competition risk between the 8 Mainline’s investors and its customers?
9 A50. The Board has, in the past, rejected the suggestion that investors should bear (the 10 immediate consequences of) competition risk. The Board’s position has been that the 11 Mainline’s revenue requirement should be determined on a full cost-of-service basis. 12 At the same time, the Board has recognized that there is a limit to the tolls that the 13 market will bear. As I explained above, the Board has said that the Mainline should 14 be active in mitigating risk, and that the regulatory framework would continue to be 15 supportive.
16 The regulatory context for the Mainline is evolving, but the Board 17 finds no reason to conclude that the Mainline’s regulatory risk has 18 increased. The regulatory model continues to provide the 19 Mainline with a reasonable opportunity to recover its prudently 20 incurred costs. Indeed, the Board notes, as an example, that the 21 direction from the Board in the RH-1-2002 Decision emphasizing 22 “the importance of performing depreciation studies on a timely 23 basis and of ensuring that depreciation rates reflect up-to-date 24 information” would indicate a directional decrease in regulatory 25 risk. While the Board acknowledges that regulators may be 26 unable to protect the Mainline if tolls become uncompetitive, this 27 has always been true and does not constitute a change in 28 regulatory risk. (RH-2-2004 Phase II, p. 43, emphasis added)
43 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q51. What has the Board said about how the regulatory framework might allow the 2 Mainline to respond to and mitigate competition risk?
3 A51. The Board has said that it is for the Mainline to identify needed changes, but that the 4 Board would support the Mainline and the full cost-of-service model by making 5 necessary changes to allow the Mainline to respond to increasing competition risk. In 6 RH-2-2004 Phase II, the Board’s discussion was as follows.
7 In response to TransCanada’s contention that the Mainline has 8 been denied tools to compete, the Board notes that previous 9 decisions are based on the specific circumstances pertaining to 10 those proceedings. The Board also notes that most of the examples 11 cited by TransCanada, such as term differentiated rates and 12 changes to contract renewal policies, predate increased 13 competition. An examination of Board Decisions since the level 14 of competition has increased, in fact, shows that the Board has 15 been responsive in making changes when circumstances warrant 16 and in approving tools to compete. Examples of this include the 17 increase in the Mainline’s depreciation rate, the increase in the 18 interruptible transportation floor price, the approval of the 19 Southwest Zone, and the approval of the North Bay Junction 20 receipt and delivery point. (RH-2-2004 Phase II, p. 45, emphasis 21 added)
22 23 Q52. How do you interpret these passages from RH-2-2004 Phase II?
24 A52. In my opinion, the cited passages show that the Board expects the Mainline to bring 25 forward proposals that will allow it to respond as best it can to emerging and 26 increasing competition risk. The Board has said that it will support the Mainline by 27 approving necessary changes. The Board is therefore saying that regulatory risk has 28 not increased with the emergence of competition risk in part because the regulatory 29 framework adapts, in the face of competition risk, to support the full cost of service 30 model.
44 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q53. Have interveners supported this interpretation?
2 A53. Yes. In RH-2-2004 Phase II CAPP argued that the Mainline’s regulatory risk was low 3 because of the supportive regulatory framework. The Board described CAPP’s 4 position as follows:
5 CAPP expressed the view that the NEB regulatory approach not 6 only covers short-term regulatory risk, but also provides a long- 7 term predictable and secure regulatory foundation for the 8 Mainline while adapting to change in a prospective and balanced 9 manner. CAPP suggested that the annual toll adjustments and 10 predictable returns are the manifestation of a long-term bargain. 11 Features such as cost of service revenue protection, deferral 12 accounts, rolled-in pipeline costs for expansions and absence of 13 volume or load factor risk limit the business risk faced by the 14 Mainline due to regulatory uncertainty, as they have for the past 15 15 years or more. (RH-2-2004 Phase II, p. 34)
16 Q54. Given what you have said above, has the Mainline’s regulatory risk increased 17 since 2004?
18 A54. The Board has not announced any policy changes since 2004, so in one sense the 19 Mainline’s regulatory risk has not increased. However, I have shown that the 20 Mainline is facing significantly increased competition risk, and I have explained that 21 the regulatory framework influences not only whether investors or customers bear the 22 consequences of increased competition risk, but also whether the Mainline is able to 23 respond to and mitigate increased competition risk. In this sense, regulatory risk has 24 increased, because the probability that the Board will be able to maintain a supportive 25 regulatory framework in the face of this increased competition risk has decreased, in 26 my opinion.
27 The Board’s approval of the Restructuring Proposal would be in line with the Board’s 28 previously expressed position on the Mainline’s regulatory risk. If, in contrast, the 29 Board were to reject those changes which would allow the Mainline to respond to and 30 mitigate the increased competition risk and maintain the Status Quo, this would 31 constitute an increase in regulatory risk relative to the environment in 2004.
45 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 F. IMPACT ON THE MAINLINE OF RECENT AND PROSPECTIVE MARKET
2 CONDITIONS
3 Q55. What has been the impact of the increased competition you have described 4 above on the Mainline’s exports to U.S. markets?
5 A55. The increased competition has resulted in substantially lower deliveries on the 6 Mainline to U.S. export points both in the Midwest and U.S. Northeast, as shown in 7 Figures 13 and 14 below. Figure 13 shows how exports to the U.S. Midwest (into the 8 Great Lakes Gas Transmission and Viking Gas Transmission systems at Emerson, 9 Manitoba) have declined from roughly 2.5 Bcf/d to under 2.0 Bcf/d currently. Figure 10 14 shows the declines in exports to the Northeast U.S. from 2.2 Bcf/d in 2004 to 1.1 11 Bcf/d currently.
46 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 13
Mainline Exports to Midwest
3.0
2.5
2.0
1.5 Bcf/d
1.0
0.5
0.0 2004 2005 2006 2007 2008 2009 2010 2011 Source: Data provided by TransCanada. Note: Midwest includes exports to the Emerson 1 and Emerson 2 delivery points. 1 2011 represents average daily deliveries for January to June.
47 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 14
Mainline Exports to Northeast
3.0
2.5
2.0
1.5 Bcf/d
1.0
0.5
0.0 2004 2005 2006 2007 2008 2009 2010 2011 Source: Data provided by TransCanada. Note: Northeast includes exports to the following delivery locations: Chippawa, Cornwall, East Hereford, Iroquois, Napierville, Niagara Falls, Philipsburg. 1 2011 represents average daily deliveries for January to June.
2 Q56. Has the increased competition had an impact on price differentials across the 3 Mainline and thus the current value of Mainline transportation capacity?
4 A56. Yes. The increased competition has resulted in lower price differentials across the 5 Mainline, as shown in Figures 15 through 17. Figure 15 shows how bidweek 6 (monthly) spot price differentials from the Nova Inventory Transfer (“NIT”) pricing 7 point in Alberta to Niagara (at the Ontario-New York border) have declined over the 8 past several years such that they are now at their lowest level in the last decade. 9 Figure 16 and Figure 17 show a similar pattern for price differentials to the Dawn 10 Hub (also in Ontario) and to Chicago (both measured relative to NIT). These charts 11 demonstrate the decline in the market value of Mainline transportation over the past 12 several years.
48 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 15
1
49 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 16
1
50 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 17
1
2 Q57. How has the contractual profile of the Mainline changed as a result of the 3 increased competition you have described?
4 A57. As discussed in the Company’s evidence, the Mainline has experienced substantial 5 decontracting on its system such that it now has a very large amount of unsubscribed 6 capacity on its system.33 As shown in Figure 18, the Mainline’s contracted capacity 7 as of year-end 2011 will be roughly 4.3 Bcf/d (of which roughly 3.0 Bcf/d is short- 8 haul and roughly 1.2 Bcf/d is long-haul), substantially less than the Mainline capacity 9 for Western Receipts of approximately 7 Bcf/d. This large amount of unsubscribed 10 capacity on the Mainline indicates an unusually high level of business risk. 11 Moreover, the contracted capacity on the Mainline is of a very short-term nature, with
33 See Mainline 2012-2013 Tolls Application, Part D, Section 11.
51 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 a weighted average contract life of only 2.6 years. In 2012, the Mainline is facing 2 contract expirations of roughly 2.9 Bcf/d.
Figure 18
3
4 Q58. Is the contracting situation on the Mainline that you have described unusual in 5 your experience?
6 A58. Yes. The Mainline has an unusually high level of unsubscribed capacity on its 7 system. This is in contrast to the pipelines owned by the companies in Dr. Vilbert’s 8 gas pipeline sample, that generally have much lower levels of unsubscribed capacity.
52 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 IV. THE MAINLINE’S RESTRUCTURING PROPOSAL
2 Q59. How does the Restructuring Proposal influence the Mainline’s business risk 3 going forward?
4 A59. The Restructuring Proposal reduces tolls (relative to the tolls in the Status Quo case) 5 on various parts of the Mainline system.34 The Restructuring Proposal thus mitigates 6 the competition risk that the Mainline is currently facing. Competition risk is the key 7 driver of the Mainline’s currently elevated business risk. Therefore, if the 8 restructuring proposal is implemented, the Mainline’s business risk going forward 9 will be lower than it would otherwise be.
10 Implementation of the Restructuring Proposal will reduce the fair return required by 11 the Mainline’s investors through reducing the Mainline’s business risk. 12 Implementation of the Restructuring Proposal will also signal to investors that the 13 Board is continuing to support the existing “regulatory bargain” under which the 14 Board protects investors, so far as it is able, from risks for which they have not been 15 compensated. Absent the Restructuring Proposal, the fair rate of return required by 16 the Mainline’s investors, as well as investors in other infrastructure regulated by the 17 Board, will be elevated for this reason (as discussed in the evidence of Aaron 18 Engen).35
19 Q60. What is the impact of the Restructuring Proposal on tolls?
20 A60. The Restructuring Proposals reduces tolls relative to where they would be in the 21 Status Quo case. For example, the toll from NIT to Dawn would be $1.411.29/GJ 22 under the Restructuring Proposal, rather than $1.512.35/GJ in the Status Quo case. 23 Taking into account fuel costs, the total transportation cost is over 40 percent lower as 24 a result of the Restructuring Proposal.36
34 Mainline 2012-2013 Tolls Application, Part C, Section 9.0. 35 Mainline 2012-2013 Tolls Application, Appendix D2. 36 Mainline 2012-2013 Tolls Application, Part C, Section 9.0.
53 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q61. How does the Restructuring Proposal impact the Mainline’s business risk?
2 A61. The Restructuring Proposal reduces the Mainline’s business risk relative to where it 3 would be in the Status Quo case. This reduction in risk is associated with Mainline 4 tolls being lower under the Restructuring Proposal because the lower tolls help to 5 mitigate the competition risk to which the Mainline is exposed.
6 Q62. Can you indicate the magnitude of this effect with reference to throughput?
7 A62. The Company’s throughput study forecasts throughput up to 2020 under various 8 scenarios.37 Of particular relevance from a business risk perspective is the exposure 9 of the Mainline to throughput loss associated with the high tolls in the Status Quo 10 case. In the throughput study, the Company has modeled a “market response”, 11 including additional pipeline infrastructure, lower WCSB production and increased 12 western Canada demand. This market response is a consequence of the high tolls in 13 the Status Quo case, and would be avoided if the Restructuring Proposal is accepted. 14 A comparison of Case 1 (Restructuring Proposal) and Case 3 (Status Quo with 15 Market Response) indicates the magnitude of these impacts. Throughput over the 16 period 2012–2020 is 0.7 Bcf/d higher on average in the Restructuring Proposal case. 17 This difference is a measure of the significance of the Restructuring Proposal in 18 mitigating the Mainline’s exposure to external market factors, and hence reducing 19 business risk. The throughput study also shows that, directionally, the Restructuring 20 Proposal also mitigates some throughput loss associated with the Company’s “Low 21 Supply” scenario (although no market response was modeled in the Low Supply 22 cases).
23 V. U.S. AND CANADIAN COMPARABLES FOR THE MAINLINE
24 Q63. What risk comparisons have you made?
25 A63. I have compared the business risk of the Mainline with the business risk of the 26 following groups of comparators:
37 Mainline 2012-2013 Tolls Application, Appendix C1.
54 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 U.S. interstate gas pipelines, including the companies in Dr. 2 Vilbert’s gas pipeline sample 3 U.S. interstate oil pipelines, including the companies in Dr. 4 Vilbert’s oil pipeline sample 5 U.S. gas LDCs, including the companies in Dr. Vilbert’s 6 gas LDC sample 7 the companies in Dr. Vilbert’s sample of regulated firms in 8 Canada 9 Q64. Have you also reviewed allowed returns?
10 A64. Yes. I have reviewed the allowed returns for two groups of comparables: U.S. 11 interstate gas pipelines and U.S. LDCs.
12 A. U.S. INTERSTATE GAS PIPELINES
13 Q65. What have been the allowed ROEs for U.S. gas pipelines?
14 A65. Figure 19 shows the ROEs allowed for U.S. interstate gas pipelines as set by the 15 FERC in litigated rate cases from 1994 to the present.
55 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 19
1
2 In Figure 20, I show the same U.S interstate gas pipelines on a total return or overall 3 after-tax weighted-average cost of capital (ATWACC) basis. In calculating the 4 ATWACCs presented in Figure 20, I have used the capital structure for each 5 company and have assumed a 3.65 percent constant after-tax debt cost over time.
56 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 20
1
2 Q66. Given the differences in the regulation of natural gas pipelines between Canada 3 and the U.S., why should the Board consider comparisons across the two 4 jurisdictions?
5 A66. First, while there are some differences in regulatory procedure between Canada and 6 the U.S., the differences are not so great as to make these kinds of comparisons 7 irrelevant. Indeed, when one looks at the reports from ratings agencies and 8 investment banks on pipeline financial conditions, it is clear that they are constantly 9 making these kinds of comparisons. Second, when it comes to the element of risk 10 that matters most to investors, (i.e., fundamental risks to long-term earnings and 11 capital cost recovery), the regulatory regimes on both sides of the border have 12 fundamentally the same design. Unlike regimes elsewhere in the world, both the 13 Canadian and U.S. models establish pipeline tolls based on the same historical cost
57 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 rate base and cost-of-service approach. And both Canadian and U.S. regulators have 2 approved pipelines that compete with incumbent pipelines.38
38 For example, the Alliance pipeline in Canada and the Ruby pipeline in the U.S.
58 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 21 Canadian and U.S. Regulatory Models for Gas Pipelines
Canadian Model U.S. Model Comments
Rate Base Depreciated original cost. Depreciated original cost. No difference.
Allowed return should be equivalent Allowed return should be equivalent to return available for investments to return available for investments of similar risk, and should be of similar risk, and should be adequate to maintain financial adequate to maintain financial Allowed Return integrity of company. integrity of company. No difference.
No requirement for an annual determination of cost of service. If not barred by settlement, pipelines can request a change in rates under Section 4, and shippers can Annual or periodic determination of challenge existing rates under cost of service absent negotiated Section 5. FERC can also U.S. model increases variability Cost of Service settlements. challenge rates under Section 5. risks.
Relies on negotiated settlements for Relies on negotiated settlements for Negotiated Settlements rate determination. rate determination. No difference.
Deferral accounts for most costs Pipelines are at risk for costs and U.S. model increases variability Deferral Accounts and revenues. revenues between rate cases. risks.
Canadian model riskier as pipeline Income Taxes Flow-through methodology. Normalized methodology. ages.
No discount rate authority. Bypass Pipelines can discount rates. can be addressed through load Discounts can be passed through to retention rates which must be other customers in subsequent rate U.S. model decreases risk in the Discounted Rates approved on a case-by-case basis. cases. face of competition.
Pipelines can negotiate rates, but must offer service at recourse No negotiated rate authority without rates. Pipelines cannot negotiate U.S. model decreases risk in the Negotiated Rates regulatory approval. terms and conditions of service. face of competition.
Interruptible transportation tends to be priced at a premium to firm Pipelines are allowed but not transportation, and cannot be required to offer interruptible U.S. model decreases risk in the Interruptible Rates discounted. transportation at discounted rates. face of competition.
Expansions are backed by firm, long- term contracts. There is a presumption that expansions will be priced incrementally, unless the expansion represents "inexpensive expansibility" (so that roll-in lowers Expansions are backed by firm, long- existing customers' rates) or Rates for Capacity term contracts. Expansion costs improves service to existing Expansion are rolled-in. customers. No significant difference. 1
2 Figure 21 shows that with regard to earnings and capital recovery, the Canadian and 3 U.S. models are founded on the same basic principles. Gas pipelines are permitted to
59 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 recover their invested capital (which is measured as depreciated original cost) plus a 2 reasonable allowed return on their investment. This allowed return should meet three 3 standards. It should be equivalent to returns available for investments of comparable 4 risk, it should be adequate to maintain the pipeline’s financial integrity, and it should 5 allow the pipeline to attract capital on reasonable terms.39 These fundamental 6 similarities between the economics of U.S. and Canadian gas pipelines, and the way 7 they are regulated, make comparisons of allowed and earned returns between the two 8 jurisdictions highly meaningful.
9 Figure 21 shows that apart from these shared fundamental principles for earnings and 10 capital recovery, there are differences between the Canadian and U.S. models. Some 11 of these differences cause Canadian gas pipelines to be more risky than U.S. gas 12 pipelines, and some cause U.S. gas pipelines to be more risky (particularly in terms of 13 earnings variability) than Canadian gas pipelines. Overall, however, the similarities 14 in fundamental risk and capital recovery make U.S. and Canadian gas pipelines 15 comparable.
16 Q67. What was the Board’s view on the comparability of Canadian and U.S. gas 17 pipelines as expressed in the RH-1-2008 decision?
18 A67. The Board stated that:
19 “the risks faced by TQM and those faced by U.S. pipelines 20 are not so different as to make them inappropriate 21 comparators. The Board accepts that there are many 22 similarities between the risks faced by pipelines in the two 23 countries. This is due to the two regulatory models sharing, 24 to a large extent, the same fundamental principles. 25 Moreover, Canadian and U.S. pipelines operate in what the 26 Board views as an integrated North American natural gas 27 market, which informs the choices made by regulators in 28 the different jurisdictions.”
39 National Energy Board, RH-2-2004, p. 17. Bluefield Waterworks & Improvement Co. v. Public Service Commission, 262 U.S. 679 (1923) at 692 – 693.
60 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q68. Do you agree with this view?
2 A68. Yes.
3 Q69. What differences between the Canadian and U.S. models cause Canadian gas 4 pipelines to have lower variability risk than U.S. gas pipelines?
5 A69. Canadian gas pipelines are generally subject to periodic determinations of their cost 6 of service (unless operating under multi-year settlements), and utilize deferral 7 accounts to adjust for differences between forecast and actual revenues and costs 8 between annual rate cases. In the U.S., gas pipeline rate cases are relatively 9 infrequent, and pipelines typically do not utilize deferral accounts to adjust for 10 deviations in revenues and costs. These differences can cause year-to-year earned 11 returns on U.S. gas pipelines to be more variable relative to allowed returns than year- 12 to-year earned returns on Canadian gas pipelines. While U.S. gas pipelines may have 13 higher variability risk because of these differences, undue emphasis should not be 14 placed on it because it is fundamental risk that matters most to investors, as I 15 discussed above.
16 Q70. What did the Board say in RH-1-2008 about the differences in variability risk 17 between gas pipelines in the U.S. and Canada caused by short term changes in 18 volumes transported?
19 A70. In RH-1-2008 the Board said that it
20 “is of the view that volumetric risk is more a feature of the 21 U.S. regulatory model than the Canadian one. However, 22 the Board did not find that the evidence supported the 23 conclusion that volumetric risk impacts long-term risks of 24 capital recovery. The Board finds that volumetric risk 25 clearly impacts short-term risks of allowed earnings not 26 being achieved, and sometimes for consecutive years 27 between rate cases. The Board also finds it significant that
61 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 volumetric risk has a symmetric nature, presenting 2 pipelines with some counteracting upside opportunities.”40
3 Q71. Do you agree with this view of the difference in variability risks facing gas 4 pipelines in the U.S. and Canada?
5 A71. Yes.
6 Q72. Is there evidence that book returns on U.S. gas pipelines vary considerably from 7 year to year?
8 A72. I have seen evidence presented in prior proceedings that both U.S. gas pipelines and 9 U.S. LDCs have book returns which vary considerably from year to year. I have also 10 seen industry publications which show earned return variability for U.S. pipelines.
11 Q73. Is this evidence relevant to an assessment of the variability risk of U.S. gas 12 pipelines?
13 A73. While I agree that features of the U.S. regulatory regime do mean that U.S. gas 14 pipelines have higher variability risk than would be the case if the same pipelines 15 were regulated under the Canadian system, I do not view evidence on book returns 16 (or earnings) as very helpful for assessing their true earnings variability risk.
17 First, what matters to investors are the returns they actually receive—i.e., market 18 returns. Book accounting earnings are at best only a proxy for market returns. It is 19 investors’ expectations about actual future market returns on their investment that 20 determines the firm’s cost of capital.
21 Second, the evidence I have seen in relation to volatility of book returns of U.S. 22 pipelines (and LDCs) relates to returns calculated from regulatory accounts. As with 23 all accounting systems, these accounts may show book earnings volatility for a 24 number of reasons that do not reflect the underlying prospects for the business. For
40 RH-1-2008, p. 67.
62 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 example, there may be impacts from one-off exceptional items, or impacts from 2 timing differences associated with the reported accounts, which mean that the book 3 returns on equity calculated from the regulatory accounts do not reflect equity 4 investors’ expectations for the future.
5 For these reasons, although I have seen the evidence mentioned above, I have not 6 myself undertaken an analysis of book returns.
7 Q74. In RH-1-2008 the Board concluded that “the risks resulting from the regulatory 8 environment are higher for U.S. pipelines than for Canadian pipelines”. Do you 9 agree with this conclusion?
10 A74. As discussed above, I agree with the view that variability risk is higher in the U.S. 11 because of features of the regulatory system there which are not present to the same 12 extent in Canada. However, I also explained my view, with which the Board agreed 13 in RH-1-2008, that variability risk does not necessarily impact fundamental capital 14 recovery risk.41 In my view it is the latter which is more important to investors, and 15 is hence more important in a comparison of business risk between pipelines in the two 16 jurisdictions. Therefore, in comparing the overall business risk of Canadian and U.S. 17 gas pipelines I would attach greater weight to the relative risk of fundamental capital 18 recovery in the two jurisdictions.
19 Q75. What is your perception of the differences between the regulatory approaches as 20 applied to U.S. and Canadian gas pipelines as they relate to long term capital 21 recovery?
22 A75. One of the differences I have perceived between U.S. and Canadian regulation for 23 some time is that U.S. gas pipelines have had a greater opportunity to respond, 24 through the use of flexible pricing and service design, to the competition encouraged 25 by regulatory policies. See the rows in Figure 21 that describe differences between
41 “However, the Board did not find that the evidence supported the conclusion that volumetric risk impacts long-term risks of capital recovery” (RH-1-2008, p. 67).
63 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 the Canadian and U.S. models with regard to discounted, negotiated and interruptible 2 rates. These differences cause U.S. gas pipelines to be better positioned than 3 Canadian gas pipelines to mitigate the risk of increased competition and bypass. The 4 asymmetry in the Canadian situation, particularly in respect to the competition from 5 new pipelines and supply sources is notable in comparison to the U.S. scheme.
6 The FERC reaffirmed its discounting policy in May 2005. FERC found that “its 7 current policy on selective discounting is an integral and essential part of the 8 Commission’s policies furthering the goal of developing a competitive national 9 natural gas transportation market.”42 FERC explained the efficiency benefits of 10 discounting, and the benefit to interstate pipelines, as follows:
11 [D]iscounting also enables interstate pipelines with higher cost 12 structures to compete with lower cost pipelines for customers, 13 enabling the capacity of both pipelines to be utilized in the most 14 efficient manner possible. In the absence of such discounts, 15 existing customers of the higher cost pipeline with access to the 16 lower cost pipeline would likely switch to the lower cost pipeline 17 to the extent it has available capacity. Similarly, new customers 18 would contract first with the lower cost pipeline.43
19 Q76. Does the fact that the FERC has in the past accepted settlements in which U.S. 20 gas pipelines have agreed with their customers to share the costs associated with 21 capacity non-renewal indicate that the gas pipeline business is inherently more 22 risky in the U.S. than in Canada?
23 A76. Not in my opinion. The clear policy of the U.S. regulators, as articulated in Orders 24 No. 436, 500 and 636, is to permit gas pipelines the opportunity to recover their 25 prudently incurred costs, including costs associated with discounting to meet 26 competition, the cost of capacity non-renewals, and one-time costs resulting from the 27 transition to competition. While it is true that in some cases the FERC has accepted 28 settlements in which a pipeline has agreed with its customers to share such costs
42 “Order Reaffirming Discount Policy and Terminating Rulemaking Proceeding,” FERC Docket No. RM05- 2, May 31, 2005, p. 1. 43 Id., p. 13 (footnotes omitted).
64 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 (presumably getting something in return for such a sharing), these cases are relatively 2 few in number and do not reflect a fundamental shift in regulatory policy that gives 3 gas pipelines a fair opportunity to recover their prudently-incurred costs.
4 FERC made this point in its “Order on Technical Conference” in the Gas 5 Transmission Northwest (“GTN”) rate case in 2006. In responding to requests to 6 reject a risk-sharing proposal made by GTN, FERC stated:
7 [T]he Commission has not established a general policy or bright- 8 line test regarding risk-sharing mechanisms. To the contrary, the 9 Commission has addressed each proposal on a case-specific basis, 10 including a number of proposals included in settlements. A 11 number of these cases were relied on by the objecting parties, but 12 have no precedent value because they were the result of negotiated 13 settlements.44
14 Q77. What do you conclude regarding the relative risks of U.S. and Canadian gas 15 pipelines?
16 A77. I conclude that while in general the variability risk of U.S. gas pipelines is greater 17 than the variability risk of Canadian gas pipelines, the fundamental capital recovery 18 risk of these pipelines is similar. The fundamental risk of Canadian and U.S. gas 19 pipelines is similar because the Canadian and U.S. regulatory models are founded on 20 the same principles with regard to long-run earnings and capital recovery. I conclude 21 that because the fundamental risk of Canadian and U.S. gas pipelines is similar and 22 because fundamental risk is the risk that matters most to investors, comparisons of 23 Canadian and U.S. gas pipelines are highly meaningful.
44 “Order on Technical Conference,” FERC Docket No. RP06-407, December 21, 2006. p. 31.
65 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 B. DR. VILBERT’S GAS PIPELINE SAMPLE
2 Q78. What does your analysis above mean for the comparison between a specific 3 Canadian pipeline and a specific sample of U.S. pipelines?
4 A78. In my opinion, the relevance of the discussion above is that, in general, U.S. and 5 Canadian gas pipelines have similar risks. I am not sure that it is necessary or helpful 6 to attempt to make general statements about whether U.S. pipelines or Canadian gas 7 pipelines are riskier on average, because risk factors other than the regulatory 8 environment are also very important. In my view the overall risks of U.S. and 9 Canadian gas pipelines form two overlapping distributions. In order to conclude on 10 the relative risk ranking of specific pipelines in the two jurisdictions it is necessary to 11 look at the specific features of the pipelines in question—for example, their exposure 12 to supply risk, the risk of bypass or competition from other pipelines, and so on.
13 Q79. Have you examined the business activities of the companies included in Dr. 14 Vilbert’s U.S. gas pipeline sample?
15 A79. Yes. I have examined Dr. Vilbert’s U.S. gas pipeline sample and have identified 16 those companies that are most heavily involved in interstate natural gas transmission, 17 and thus represent a “pure-play” natural gas transmission sub-sample. The four 18 companies in this pure-play sub-sample are: TC PipeLines LP, Boardwalk Pipeline 19 Partners LP, El Paso Pipeline Partners LP and Spectra Energy Partners LP. These 20 companies are relatively pure-play natural gas transmission businesses, and are thus 21 good comparables for the Mainline. These four companies together own 14 pipelines 22 which, in aggregate, account for about 20% of total net interstate gas pipeline assets 23 in the U.S.
24 Q80. How were the four firms selected for inclusion in Dr. Vilbert’s sub-sample?
25 A80. Dr. Vilbert’s sample contains all eight firms for which reliable cost of capital 26 estimates can be made, and which are significantly concentrated in interstate natural
66 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 gas transportation. From this group of eight firms those four for which interstate 2 natural gas transportation is the sole or majority activity were selected.
3 In Figure 22 below I show how the earnings (EBITDA) of the firms in Dr. Vilbert’s 4 sample are split by business segment, and in Figure 23 I show the breakdown of 5 assets by business segment.
6 Figure 22 Gas S ample EBITDA
Gas pipeline Oil pipeline Terminals Midstream Distribution Other Total
Boardwalk 100% 0% 0% 0% 0% 0% 100% TC Pipelines LP 100% 0% 0% 0% 0% 0% 100% El Paso LP 100% 0% 0% 0% 0% 0% 100% Spectra Energy Partners LP 66% 0% 0% 0% 0% 34% 100% Williams Partners 46% 0% 0% 54% 0% 0% 100% Spectra Energy Corp 44% 0% 0% 12% 22% 21% 100% Oneok LP 32% 0% 0% 68% 0% 0% 100% KMEP 27% 22% 20% 0% 0% 31% 100%
Note Based on data in 2010 10K forms. Total excludes corporate costs and inter-segment eliminations. Spectra Energy Partners LP's "other" segment consists of equity investments in Gulfstream (gas pipeline) and Market Hub (storage), plus 7 unallocated corporate costs.
Figure 23 Gas Sample Total Assets
Gas pipeline Oil pipeline Terminals Midstream Distribution Other Total
Boardwalk 100% 0% 0% 0% 0% 0% 100% TC Pipelines LP 100% 0% 0% 0% 0% 0% 100% El Paso LP 100% 0% 0% 0% 0% 0% 100% Spectra Energy Partners LP 58% 0% 0% 0% 0% 42% 100% Williams Partners 60% 0% 0% 40% 0% 0% 100% Spectra Energy Corp 49% 0% 0% 5% 24% 22% 100% Oneok LP 24% 0% 0% 76% 0% 0% 100% KMEP 41% 29% 19% 0% 0% 10% 100%
Note Based on data in 2010 10K forms. Total excludes corporate costs and inter-segment eliminations. Spectra Energy Partners LP's "other" segment consists of equity investments in Gulfstream (gas pipeline) and Market Hub (storage), plus 8 unallocated corporate costs.
67 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Four of the firms, TC Pipelines LP, Boardwalk, Spectra Energy Partners LP and El 2 Paso Pipeline Partners, have no reportable segments other than natural gas pipeline 3 transportation (as I explain below, these firms also have gas storage and LNG 4 terminalling activities within their pipeline transportation segments). These four firms 5 should therefore be included in the pure-play sub-sample.
6 Q81. Can you describe the business activities of the four companies in the pure-play 7 sub-sample?
8 A81. Yes. Information about the comparator companies is also summarized in Attachment 9 B. TC Pipelines LP has ownership interests in six interstate pipeline systems. It fully 10 owns two smaller pipeline systems, North Baja Pipeline and Tuscarora Gas 11 Transmission. It also has partial ownership shares of two larger pipelines, Northern 12 Border Pipeline (50 percent ownership share) and Great Lakes Gas Transmission 13 (46.45 percent ownership share), and it recently purchased 25 percent stakes in the 14 GTN and Bison pipelines.45 These pipelines make up the totality of TC Pipelines 15 LP’s business activities.
16 Boardwalk Pipeline Partners is the sole owner of three interstate pipeline systems, 17 Gulf South Pipeline, Texas Gas Transmission, and Gulf Crossing Pipeline. These 18 pipelines make up the totality of Boardwalk’s business activities.
19 El Paso Pipeline Partners LP owns the Wyoming Interstate Company, the Southern 20 Natural Gas Company and the Elba Express company, as well as a majority interest in 21 the Colorado Interstate Gas Company (86 percent).46 These pipelines (and associated 22 storage), together with the Southern LNG terminal, make up the totality of El Paso 23 Partners’ business activities.
45 I do not include the GTN and Bison stakes in my analysis because they are minority shares which were purchased only recently. 46 This is a current description of El Paso Pipeline Partners LP. The segment analysis in Figure 22 and Figure 23 is based on the most recent (2010) Form 10-K data, and hence does not include the effects of transactions completed more recently.
68 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Spectra Energy Partners owns East Tennessee Natural Gas, Ozark Gas Transmission 2 and 49 percent of Gulfstream Natural Gas. It also owns Saltville Gas Storage and 50 3 percent of Market Hub Partners (a gas storage facility). Spectra Energy Partners LP 4 has no other business activities.
5 Q82. Can you describe in more detail how the Mainline’s business risk compares to 6 the pipelines owned by the four companies in the pure-play sub-sample?
7 A82. Yes. Attachment B is a table I have prepared that rank orders the pipelines owned by 8 the four companies in the pure-play sub-sample. These pipelines fall into three risk 9 categories: low-risk, medium risk, and high risk. I put the Mainline at the top of the 10 high-risk category due to its dependence on WCSB supplies and its large amount of 11 unsubscribed capacity. The Mainline’s position in its increasingly competitive export 12 markets is eroding as a result of the distance of these supplies from these export 13 markets, as well as the emergence of new competing sources of supply and 14 transportation routes. Among the other pipelines I place in the high-risk category are 15 Great Lakes and Northern Border. Great Lakes and Northern Border are similar to 16 the Mainline because they face substantial competition in the markets they serve. 17 Great Lakes also depends on WCSB supplies while Northern Border depends on 18 WCSB supplies and Rocky Mountain supplies delivered via Bison. The Mainline, 19 Great Lakes and Northern Border are each contracted under relatively short-term 20 contracts.
21 I place several pipelines in a medium-risk category, including Texas Gas, Gulf 22 Crossing, Gulf South, Wyoming Interstate and Tuscarora. These are pipelines that 23 compete with numerous pipelines in their respective market areas, but which 24 generally have lower supply risk than the Mainline and a higher weighted average 25 remaining contact life.
26 At the low-end of the risk range are North Baja, Elba Express, Southern Natural Gas, 27 Gulfstream and East Tennessee. These are pipelines that I believe have relative low
69 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 supply risks and strong market positions, as well as strong contractual positions. In 2 sum, I believe the Mainline is in the unfortunate position of a pipeline that has high 3 competitive risk, high market risk and a weak contractual position that results in it 4 being at the upper end of the risk range for the pipelines owned by the four companies 5 in the pure-play sub-sample.
6 C. U.S. OIL PIPELINES
7 Q83. Have you also compared the business risk of the Mainline with the business risk 8 of the firms in Dr. Vilbert’s sample of U.S. oil pipelines?
9 A83. Yes. I explained above that the regulation and business environment of gas pipelines 10 in Canada and the U.S. is sufficiently similar that a comparison of business risk is 11 highly relevant. The regulatory and business environments of U.S. oil pipelines are 12 also similar to those of gas pipelines, although with some differences which I explain 13 below.
14 Q84. How do the regulation and business environments of U.S. oil pipelines differ 15 from those of Canadian pipelines?
16 A84. The regulatory and business environments are in many respects similar. The main 17 differences are the following.
18 U.S. oil pipeline regulation is more “light-handed”. Whereas, in the absence of 19 multi-year settlements, regulators in Canada require annual or biennial rate cases 20 at which prices are reset based on cost of service, most U.S. oil pipelines have 21 indexed rates which in the past have been rarely reviewed and reset to the cost of 22 service. In some markets, U.S. oil pipelines have received approval to charge 23 “market based rates”. These arrangements, which effectively weaken the link 24 between rates and cost of service, expose U.S. oil pipelines to greater short-term 25 variability risk.
70 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 U.S. oil pipelines also face greater competition from alternative modes of 2 transportation, such as barges, railroads and trucks. And U.S. oil pipelines also 3 have somewhat greater freedom to respond to competitive pressures than 4 Canadian pipelines, for example by discounting their rates. This would tend to 5 offset the somewhat higher competition risk.
6 Regulators in Canada tend to make greater use (relative to both oil and gas 7 pipeline regulation in the U.S.) of true-ups and deferral accounts, which protect 8 firms from short term (year to year) variations in net income.
9 U.S. oil pipelines do not require construction authorization of the type that the 10 Board issues to Canadian oil pipelines (however, U.S. gas pipelines do). This 11 increases the risk of U.S. oil pipelines by making competitive entry slightly easier 12 in that business, but not in a way that materially affects business risk.
13 U.S. oil pipelines are not required to file a rate case when they offer additional 14 services (for example, through expansion). While of benefit to the pipeline, this 15 would tend to increase the pipeline’s exposure to short-term volatility risk 16 (because it increases the pipeline’s exposure to volume or demand variability).
17 Q85. Do these differences make a business risk comparison between the Mainline and 18 U.S. oil pipelines irrelevant?
19 A85. No. Directionally, these differences mean that a “standard” Canadian gas pipeline 20 has lower business risk than a “standard” U.S. oil pipeline. However, the Mainline is 21 not a “standard” pipeline, for the reasons discussed above and in the Company 22 evidence. Dr. Vilbert’s U.S. oil pipeline sample is therefore potentially a useful 23 comparator for the Mainline, particularly for the case in which the Board chooses not 24 to approve the Restructuring Proposal (i.e., the Status Quo case).
71 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q86. Why do you say that the comparison is potentially useful for the Status Quo 2 case?
3 A86. I concluded above that, even if the Restructuring Proposal is approved, the Mainline 4 will have higher business risk than the average U.S. gas pipeline, such that I would 5 place it at the top end of the range of risk of Dr. Vilbert’s U.S. gas pipeline sample. 6 However, if the Restructuring Proposal is not approved, Dr. Vilbert’s sample of U.S. 7 gas pipelines is no longer a good benchmark. I explain below why I consider Dr. 8 Vilbert’s oil pipeline sample to have higher risk than his gas pipeline sample, and 9 hence to be a better benchmark for the Mainline if the Restructuring Proposal is not 10 approved.
11 D. DR. VILBERT’S OIL PIPELINE SAMPLE
12 Q87. How were the companies in Dr. Vilbert’s oil pipeline sample selected?
13 A87. Dr. Vilbert’s oil pipeline sample selection process is described in his evidence. The 14 sample contains all U.S. companies for which reliable cost of capital estimates can be 15 made, and which have oil or oil products pipelines as a significant fraction of their 16 business activities.
17 Q88. Are the companies in Dr. Vilbert’s oil pipeline sample “pure play”?
18 A88. No. All of the companies in the sample have other reportable business segments 19 besides oil pipelines, and for some of the companies these other segments are 20 significant. In Figure 24 I show the breakdown of EBITDA by reported business 21 segment, and in Figure 25 I show the breakdown of assets. For two of the sample 22 companies (Magellan and Sunoco), oil pipelines are two-thirds or more of the 23 company, but for the sample as a whole the average is approximately one half.
72 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 24 Oil Sample EBITDA
Marketing / Oil pipeline Gas pipeline Terminals services Midstream Other Total
Magellan 79% 0% 22% 0% 0% -1% 100% Sunoco 67% 0% 33% 0% 0% 0% 100% Plains 50% 0% 26% 23% 0% 0% 100% NuStar 35% 0% 45% 20% 0% 0% 100% Enbridge 35% 0% 0% 1% 64% 0% 100% KMEP 22% 27% 20% 0% 0% 31% 100%
Average 48% 4% 24% 7% 11% 5% 100%
Note Based on data in 2010 10K forms. Enbridge paid approximately $328 million for environmental remediation, restoration, and cleanup activities from a crude oil release on the Lakehead system. In the absence of the costs associated with the spill, the oil pipeline would have contributed to roughly 63% of total EBITDA. 1 Total excludes corporate costs and inter-segment eliminations.
Figure 25 Oil Sample Total Assets
Marketing / Oil pipeline Gas pipeline Terminals services Midstream Other Total
Magellan 71% 0% 28% 0% 0% 1% 100% Sunoco 79% 0% 21% 0% 0% 0% 100% Plains 34% 0% 24% 42% 0% 0% 100% NuStar 26% 0% 50% 24% 0% 0% 100% Enbridge 54% 0% 0% 2% 44% 0% 100% KMEP 29% 41% 19% 0% 0% 10% 100%
Average 49% 7% 24% 11% 7% 2% 100%
Note Based on data in 2010 10K forms. Total excludes corporate costs and inter-segment eliminations.
2
3 Q89. What are the other business activities of the companies in Dr. Vilbert’s oil 4 sample?
5 A89. The sample is approximately one-half pure-play oil pipeline on aggregate. The 6 balance is about one quarter terminalling, with the remaining quarter split between 7 midstream activities (for example, gathering) and oil marketing and other services (as 8 well as gas pipelines for KMEP). I would expect all of these non-pipeline activities
73 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 to have higher risk than the oil pipeline business, because they are not regulated, are 2 competitive, and because they are likely to result in some exposure to commodity 3 prices.
4 Q90. What do you conclude about the relative business risk of the Mainline and Dr. 5 Vilbert’s oil pipeline sample?
6 A90. I explained above that in general I would expect oil pipelines to be somewhat riskier 7 than gas pipelines, because of differences in the regulatory framework and greater 8 exposure to competition. In addition, the oil pipeline companies in Dr. Vilbert’s 9 sample are not pure-play, but also have higher-risk unregulated activities. I would 10 therefore expect Dr. Vilbert’s oil pipeline sample to be of higher risk than the gas 11 pipeline sample, and of higher risk than the Mainline, if the Restructuring Proposal is 12 approved.
13 Dr. Vilbert’s oil pipeline sample may be a better comparator for the Mainline in the 14 Status Quo case, at least as a minimum. In that case, the Mainline is facing much 15 higher competition and regulatory risk than even the riskiest U.S. gas or oil pipeline. 16 I would therefore expect the Status Quo Mainline to have a level of business risk at 17 least as high as Dr. Vilbert’s oil pipeline sample.
18 E. U.S. LDCS
19 Q91. What have been the allowed ROEs for U.S. LDCs?
20 A91. Figure 26 shows the ROEs allowed for U.S. LDCs as determined in rate cases 21 concluded during 1994 to the present.47
47 Figures 26 and 27 include all major LDC rate decisions since 1994 where there was an explicit determination (either by the regulator or through approved settlement) of equity thickness.
74 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 26
1
2 In Figure 27, I show the same U.S. LDCs on a total return basis (again using the 3 capital structure for each company and assuming the same constant 3.65 percent 4 after-tax debt cost).
75 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 27
1
2 Q92. What is your opinion as to how gas pipelines and LDCs compare from a business 3 risk perspective?
4 A92. In my opinion, LDCs tend to have lower risk than interstate gas pipelines, because 5 LDCs tend not to be exposed to competition to the same degree as interstate gas 6 pipelines. LDCs tend to be insulated from competition by their franchised service 7 territories, and by the nature of their customer bases. Many LDCs do not own 8 significant high pressure transmission or storage assets that serve third parties in 9 competition with other facilities. Instead, LDCs tend to provide distribution service 10 to a customer base composed of predominantly residential and commercial customers 11 that are not at risk of bypass.
12 Put simply, an LDC has a local monopoly and can, in most cases, expect to pass on 13 any reasonably-incurred costs to end customers. Provided that the LDC in question
76 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 has a significant proportion of domestic and small business customers, it is unlikely to 2 have to worry about being unable to pass on allowed costs. Only if the LDC has an 3 unusually high proportion of more price-sensitive industrial load, or if it faces 4 unusually high competitive pressure from competing fuels (such as electricity for 5 home heating), is it exposed to the risk that it will not be able to recover allowed 6 costs.
7 The same is not necessarily true for interstate gas pipelines. In general, interstate gas 8 pipelines do not have “captive” franchise customers in the same way that LDCs do. 9 By definition, LDCs do not face competition from other LDC networks, whereas 10 interstate gas pipelines may face competition from alternative pipeline (or LNG) 11 routes. Gas pipelines are vulnerable to macro changes in the pattern of gas flows 12 around a region. LDCs are not.
13 In general, therefore, I would say that interstate gas pipelines are likely to face higher 14 risks than LDCs.
15 Q93. Has FERC expressed a view on the relative risks of gas pipelines and LDCs?
16 A93. Yes. FERC found that LDCs face lower risks than interstate gas pipelines in Opinion 17 No. 486 in the Kern River Gas Transmission Company rate case:
18 The evidence in this case is undisputed that the risk profile of 19 LDCs is different from the risk profile of typical interstate 20 pipelines. No party disagrees that LDCs face lower risk due to the 21 nature of their operations. As Kern River’s witness testified, LDCs 22 enjoy a natural service monopoly, with relatively low demand 23 elasticity, price sensitivity and throughput risks. The franchise 24 structure of an LDC results in lower overall business risk and 25 lower investor expectations. In contrast, gas pipelines are one 26 level removed from the end-use markets served by LDCs and retail 27 utilities and enjoy no such service monopoly or territorial 28 franchise.48
48 Opinion No. 486, FERC Docket No. RP04-274, October 19, 2006, page 72. Footnote omitted.
77 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Recognizing that the small proxy group it was using contained companies with 2 substantial LDC operations and that LDCs are of lower risk than the interstate gas 3 pipelines, the FERC approved a 50 basis point adjustment above the median ROE of 4 the proxy group.49
5 Q94. What did the Board conclude on the comparability of gas pipelines and U.S. 6 LDCs in RH-1-2008?
7 A94. In RH-1-2008 the Board acknowledged FERC’s views on the relative risks of LDCs 8 and gas pipelines. The Board was also satisfied that the evidence was sufficient to 9 establish that TQM and U.S. LDCs are sufficiently similar in risk as to make 10 comparisons meaningful. However, in that case the Board also stated that insufficient 11 evidence had been presented to support a clear finding of the relative long-term risks 12 of TQM versus U.S. LDCs, and that it would have benefitted from additional 13 information on the comparability of the LDC group with TQM.50 I present below 14 such evidence as seems to me relevant to allow the Board to assess the comparability 15 of the LDC sample with the Mainline.
16 F. DR. VILBERT’S U.S. LDC SAMPLE
17 Q95. Have you reviewed the companies in Dr. Vilbert’s U.S. LDC sample?
18 A95. Yes. In my opinion, the companies in Dr. Vilbert’s U.S. LDC sample are of lower 19 risk than the Mainline because their operations are almost exclusively in lower-risk 20 gas LDC activities. The five companies Dr. Vilbert considers represent a relatively 21 “pure play” U.S. LDC sample. I explained above why I consider gas LDCs to have 22 lower risk than interstate gas pipelines.
49 Id., pages 72-73. 50 RH-1-2008, p. 68.
78 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q96. Have you quantified the extent to which Dr. Vilbert’s LDC sub-sample is pure- 2 play?
3 A96. Yes. I show in Figure 28 and Figure 29 a breakdown of the reported business 4 segments of the eight firms in Dr. Vilbert’s broader LDC sample, both by assets and 5 by earnings. All five of the firms in Dr. Vilbert’s sub-sample had more than 80% of 6 both assets and earnings in regulated gas LDC activities.
Figure 28 LDC EBITDA
LDC Non-LDC Total
WGL Holdings 95% 5% 100% Northwest Natural Gas 94% 6% 100% Piedmont Natural Gas 91% 9% 100% Southwest Gas 91% 9% 100% Laclede 86% 14% 100% South Jersey Industries 82% 18% 100% Atmos 77% 23% 100% New Jersey Resources 75% 25% 100% NiSource 67% 33% 100%
Note Based on data in 2010 10K forms and annual reports. 7 Total excludes corporate costs and inter-segment eliminations.
79 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 29 LDC Total Assets
LDC Non-LDC Total
Piedmont Natural Gas 97% 3% 100% Southwest Gas 97% 3% 100% Northwest Natural Gas 88% 12% 100% WGL Holdings 87% 13% 100% Laclede 85% 15% 100% Atmos 81% 19% 100% South Jersey Industries 76% 24% 100% New Jersey Resources 74% 26% 100% NiSource 69% 31% 100%
Note Based on data in 2010 10K forms and annual reports. Total excludes corporate costs and inter-segment eliminations. 1
2 Q97. What is the nature of the non-LDC activities of the firms in Dr. Vilbert’s LDC 3 sub-sample?
4 A97. The non-LDC activities of the firms in the sub-sample consist, for the most part, of 5 associated unregulated activities, such as gas retailing or unregulated storage and 6 intrastate transmission. I would expect these activities to be of somewhat higher risk 7 than the regulated activities.
8 Q98. Are there circumstances in which you might expect a particular gas LDC to have 9 higher than average business risk?
10 A98. Yes. As I explained above, U.S. gas LDCs are potentially exposed to certain risks, 11 which, if present, could result in a particular LDC being of above average risk. As I 12 explained above, U.S. LDCs are typically exposed to short-term variability risk 13 because they do not in general have frequent rate cases, nor do U.S. state regulators 14 usually employ true-up or deferral account mechanisms to the same extent as do 15 Canadian regulators. This short-term variability risk would not usually be of concern 16 to investors (and would therefore not usually contribute to elevated overall business
80 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 risk), because investors are less concerned with year-on-year variation than they are 2 with longer-term fundamental risk of capital recovery. Nevertheless, there are some 3 circumstances under which an LDC could be exposed to more significant business 4 risk.
5 One such circumstance would be if the LDC were heavily dependent on supplying 6 industrial load or electric generation load. Such loads can be sensitive to economic 7 conditions generally, or to competition from specific sources (for example, coal-fired 8 generation). If an LDC were to obtain significant distribution revenues from such 9 load, it might as a consequence be exposed to some competition and general 10 systematic risk from which most LDCs are fully protected by their monopoly 11 franchises. In principle, large individual loads could even be at risk from “bypass”, 12 for example through direct connection to a transmission pipeline. Households and 13 most commercial loads are not generally exposed to competition in the same way.
14 A second such circumstance would be if the LDC’s throughput was declining over 15 time, without the LDC having adequate regulatory protection to ensure the recovery 16 of fixed costs despite falling volumes. Declining throughput can occur where the 17 LDC is exposed to competition even at the household level (for example, from 18 electric heating), because of depopulation, or because customers are improving 19 energy efficiency. A common regulatory response to the problem of fixed cost 20 recovery when throughput is declining would be to adjust the structure of rates so that 21 a greater proportion of revenue is recovered through a fixed monthly charge rather 22 than a per MMBtu charge.
23 Q99. Do the “higher-risk” circumstances you describe above apply to the LDCs in Dr. 24 Vilbert’s sample?
25 A99. No. On average, about 70% of throughput of the sample LDCs is associated with 26 residential and commercial customers. Three of the five LDCs in the sub-sample 27 have significant industrial or power generation load. However, all three mitigate the
81 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 risk of bypass through the use of discounted rates, or have been able to recover the 2 costs associated with bypass from franchise customers.
3 All five of sub-sample LDCs have weather normalization mechanisms, which tend to 4 reduce the volatility of earnings. In addition, four out of the five have mechanisms 5 which adjust revenues or margins to remove or reduce the impact of changing usage 6 patterns due to conservation efforts or other factors. All five also have mechanisms 7 to pass through to customers changes in gas commodity costs.
8 This information is recorded in Attachment C to this evidence
9 Q100. Can you quantify the extent to which the LDCs in the sub-sample are insulated 10 from business risk by the protections inherent in their monopoly franchises?
11 A100. A precise quantification is not possible. However, there are metrics available which 12 suggest to me that these LDCs enjoy significant protections. Two of the five LDCs 13 have customer bases that are almost entirely residential or commercial customers 14 (WGL Holdings and Laclede distribute more 95% and 86% of their throughput to 15 these customers, respectively). The other three LDCs have more significant industrial 16 and power station loads. However, these loads contribute relatively small proportions 17 of total margin (revenues less cost of gas). For Northwest Natural, more than 90% of 18 margin comes from residential and commercial customers. For Southwest Gas the 19 corresponding figure is 86% (with an additional 10% coming from transportation- 20 only customers). Piedmont Natural Gas does not provide a full breakdown of 21 margins by customer type, but it does say that 5% of its margin comes from industrial 22 or large commercial customers that can switch to another fuel, and that its electric 23 generation customers are transportation-only with rate structures such that margins do 24 not depend on volume.
82 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q101. What do you conclude about the fundamental risk of the companies in the LDC 2 sub-sample?
3 A101. I conclude that the companies in Dr. Vilbert’s U.S. LDC sample have lower 4 fundamental risk than the Mainline because the companies in Dr. Vilbert’s sample are 5 involved only to an insignificant degree in the provision of competitive transmission 6 and storage services. Their distribution services face a lesser degree of competition 7 than does the Mainline, because of the monopoly franchise nature of the LDC 8 activities, and their ability to avoid bypass risk, as I explained above.
9 Q102. What do you conclude about the short-term variability risk of the companies in 10 the LDC sub-sample?
11 A102. The variability risk of the companies in Dr. Vilbert’s U.S. LDC sub-sample may be 12 somewhat greater than the Mainline’s variability risk. As discussed earlier, the 13 Mainline has partial deferral account protection, which somewhat decreases the 14 variability of its earnings. Four of the five LDCs in Dr. Vilbert’s sub-sample have 15 decoupling or margin stabilization mechanisms or employ a rate structure which at 16 least partially protect them from revenue loss for a portion of their load due to factors 17 such as declining average use. All of the U.S. LDCs in Dr. Vilbert’s sub-sample have 18 weather normalization mechanisms, which decrease weather-induced earnings 19 variability, in place for at least a portion of their load. All of the U.S. LDCs in Dr. 20 Vilbert’s sub-sample have gas cost adjustment mechanisms that allow them to pass all 21 of their gas commodity costs to customers. On balance I consider the Mainline to 22 have somewhat lower variability risk than the U.S. LDCs, because of the Mainline’s 23 true-ups and deferrals, and because its rate-cases tend to be more frequent.
24 Q103. Please summarize your conclusion regarding the risk of the Mainline compared 25 to the risk of Dr. Vilbert’s U.S. LDC sample.
26 A103. I conclude that the Mainline faces more risk than the companies in Dr. Vilbert’s U.S. 27 LDC sample. The Mainline faces more fundamental risk than the companies in Dr. 28 Vilbert’s sample, which is not offset by the fact that the Mainline faces somewhat
83 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 lower variability risk than the companies in Dr. Vilbert’s sample. The Mainline’s 2 fundamental risk is higher than that facing the LDCs in the sample because the LDCs 3 have monopoly franchises with, for the most part, captive customers. The Mainline, 4 in contrast, faces significant competition risk and does not have the benefit of long- 5 term contracts with its shippers with significant remaining duration.
6 G. DR. VILBERT’S CANADIAN SAMPLE
7 Q104. Have you reviewed Dr. Vilbert’s sample of Canadian regulated firms, and if so 8 what do you conclude?
9 A104. Yes. I do not consider the sample of Canadian regulated firms to be a good 10 benchmark for the business risk of the Mainline because the Canadian sample is 11 diverse and is heavily weighted towards lower-risk utility-type activities.
12 Q105. Why do you say that the Canadian sample is diverse?
13 A105. Dr. Vilbert’s Canadian sample is made up of five firms: TransCanada, Canadian 14 Utilities, Fortis, Emera and Enbridge Inc. TransCanada is mostly a gas and oil 15 pipeline company, although it has significant generation interests; Emera and Fortis 16 are essentially gas and electricity distribution businesses; Canadian Utilities has gas 17 and electricity distribution, generation and competitive marketing, and gas pipelines 18 (within its utilities segment); and Enbridge has both gas and oil pipelines, and a gas 19 distribution business. The segment breakdown for these companies is shown in 20 Figure 30 and Figure 31.
84 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
Figure 30 Canadian companies' EBITDA
Pipelines Non-utility Utility Total
TransCanada 72% 28% 0% 100% Enbridge Inc. 59% 11% 30% 100% Emera 11% 0% 89% 100% Fortis 0% 9% 91% 100% Canadian Utilities 0% 37% 63% 100%
Average 28% 17% 55% 100%
Note Figures taken from 2010 annual reports. Utility segments contain the following businesses for each company: Fortis: Terasen Gas, together with various regulated electric subsidiaries in Canada and elsewhere. Canadian Utilities: ATCO Gas (distribution); ATCO Pipelines (transportation); ATCO Electric (distribution and transmission). Enbridge: Gas distribution segment. Emera: regulated electric utilities (Bangor Hydro and Nova Scotia Power Inc.). 1 TransCanada does not report EBITDA for its new oil pipelines segment in its 2010 10K.
Figure 31 Canadian companies' assets
Pipelines Non-utility Utility Total
TransCanada 71% 29% 0% 100% Enbridge Inc. 60% 13% 27% 100% Emera 8% 6% 86% 100% Fortis 0% 7% 93% 100% Canadian Utilities 0% 26% 74% 100%
Average 28% 16% 56% 100%
Note Figures taken from 2010 annual reports. Utility segments contain the following businesses for each company: Fortis: Terasen Gas, together with various regulated electric subsidiaries in Canada and elsewhere. Canadian Utilities: ATCO Gas (distribution); ATCO Pipelines (transportation); ATCO Electric (distribution and transmission). Enbridge: Gas distribution segment. 2 Emera: regulated electric utilities (Bangor Hydro and Nova Scotia Power Inc.).
85 WRITTEN EVIDENCE OF PAUL R. CARPENTER revised October 31, 2011
1 Q106. What is your evaluation of the Canadian utilities sample relative to the 2 Mainline?
3 A106. In Figure 30 and Figure 31 I have grouped the business activities of the Canadian 4 utilities sample into three categories: pipelines (interstate oil and gas pipelines); 5 utility (gas LDC and electric LDC); and non-utility (unregulated activities, such as 6 electric generation). Relative to the business risk of the Mainline, the pipelines 7 category is of similar or lower risk, the utility category is lower risk, and the non- 8 utility segment is of similar or higher risk. Since the utility category is the largest, the 9 sample as a whole has lower risk than the Mainline. However, it is also the case that 10 the Canadian utilities sample is diverse.
11 Q107. Does this conclude your written evidence?
12 A107. Yes.
86