British Columbia Hydro and Power Authority, 333 Dunsmuir Street, Vancouver BC V6B 5R3 www.bchydro.com

Fred James

Chief Regulatory Officer Phone: 604-623-4046 Fax: 604-623-4407 bchydroregulatorygroup@bchydro.com

February 15, 2019 Mr. Patrick Wruck Commission Secretary and Manager Regulatory Support British Columbia Utilities Commission Suite 410, 900 Howe Street Vancouver, BC V6Z 2N3 Dear Mr. Wruck: RE: Project No. 1598877

British Columbia Utilities Commission (BCUC or Commission) British Columbia Hydro and Power Authority (BC Hydro) Review of the Regulatory Oversight of Capital Expenditures and Projects Rebuttal Evidence

BC Hydro writes to provide the expert written evidence of Dr. Paul R. Carpenter and Dr. Toby Brown of The Brattle Group. The expert written evidence of Dr. Carpenter and Dr. Brown is being filed in addition to the Rebuttal Evidence submitted by BC Hydro under separate cover in the above referenced proceeding.

The evidence of Dr. Carpenter and Dr. Brown addresses whether the evidence filed by the Commercial Energy Consumers Association of B.C. (CEC) appropriately characterizes the objectives and role of the Commission with respect to the oversight of capital expenditures and projects, and provides their assessment of the CEC’s framework for assessing the cost-effectiveness of BC Hydro’s capital drivers, strategies and plans through an annual reporting process. The resumes of Dr. Carpenter and Dr. Brown are attached to their evidence.

For further information, please contact Geoff Higgins at 604-623-4121 or by email at bchydroregulatorygroup@bchydro.com.

Yours sincerely,

Fred James Chief Regulatory Officer cu/ma

Enclosure (1)

WRITTEN REBUTTAL EVIDENCE

OF

DR. TOBY BROWN DR. PAUL R. CARPENTER

FOR

BRITISH COLUMBIA HYDRO AND POWER AUTHORITY

British Columbia Hydro and Power Authority Review of the Regulatory Oversight of Capital Expenditures and Projects

Project No. 1598877

February 15, 2019

The Brattle Group

201 Mission Street, Suite 2800 San Francisco, California 94105

+1.415.217.1000

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TABLE OF CONTENTS 1 Introduction ..........................................................................................................................1 2 Role and Objectives of Commission....................................................................................5

2.1 Question 1 .................................................................................................................. 5

3 Mr. Craig’s Framework and Assessing “Beginning Stages” of Capital ............................13 3.1 Question 2 ................................................................................................................ 13

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1 INTRODUCTION 1

Q1. Who are the authors of this written evidence? 2

A1. Dr. Paul Carpenter and Dr. Toby Brown are co-authors of this written evidence. We 3

are Principals of The Brattle Group, an economic consulting firm. Dr. Carpenter’s 4

office is at 201 Mission Street in San Francisco, California, and Dr. Brown’s office is 5

at 5 Martin Place in Sydney, New South Wales. 6

Q2. Please describe your qualifications. 7

A2. Dr. Paul Carpenter is an economist specializing in the fields of industrial organization, 8

finance and energy and regulatory economics. He received a Ph.D. in Applied 9

Economics and an M.S. in Management from the Massachusetts Institute of 10

Technology, and a B.A. in Economics from Stanford University, and has been involved 11

in research and consulting on the economics and regulation of the natural gas, oil and 12

electric utility industries in North America and abroad for over thirty-five years. He has 13

frequently testified before federal and state regulatory commissions, in federal court 14

and before the U.S. Congress, on issues of pricing, competition and regulatory policy 15

in these industries. Outside of North America, he has advised governments and 16

regulatory bodies on the structure and performance of their natural gas markets and on 17

the reform of their regulatory regimes. These assignments have included testimony 18

before the U.K. Monopolies and Mergers Commission and the Australian Competition 19

Tribunal, and advice to the European Commission and to governments of and 20

regulators in, Greece, Ireland, the Netherlands, New Zealand and Australia. In Canada, 21

he has testified before the National Energy Board and several provincial regulatory 22

bodies on the subject of business risk and its relationship to the cost of capital for 23

natural gas pipelines and distributors. He testified before the Alberta Utilities 24

Commission in both of its generic Performance Based Ratemaking proceedings. 25

Further details of his educational and professional background, as well as a listing of 26

publications, are provided in his resume appended to this evidence as Attachment 1. 27

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Dr. Toby Brown specializes in the regulation and economics of the gas and electricity 1

sectors. He has over fifteen years of experience across the U.S., Canada, the UK and 2

Australia, primarily consulting for pipelines, utilities, and regulators, together with four 3

years at Ofgem, the energy regulator in Great Britain. He has particular expertise in the 4

application of incentive-based regulation in the energy sector, and has testified in 5

regulatory reform proceedings in Alberta and Hawai‘i. Dr. Brown’s consulting 6

experience includes analysing business risk in pipeline rate cases, assessing the 7

economic impacts of alternative regulatory frameworks and competitive structures in 8

the energy sector, and advising on regulatory best practices based on experience in 9

different jurisdictions worldwide. Dr. Brown also provides litigation support in a wide 10

range of areas, including damages estimations, competition assessments, gas contract 11

arbitrations, and utility and pipeline rate cases. He holds a D.Phil. in chemistry from 12

the University of Oxford. Dr. Brown’s resume is appended to this evidence as 13

Attachment 2. 14

Q3. By whom have you been retained in this proceeding? 15

A3. The Brattle Group has been retained by British Columbia Hydro & Power Authority 16

(BC Hydro). 17

Q4. What assignment were you given in this proceeding? 18

A4. We were asked to address two questions concerning the written evidence of Mr. David 19

Craig, submitted in this proceeding by the Commercial Energy Consumers Association 20

of British Columbia (the CEC). The questions we address are set out in a letter from 21

BC Hydro’s counsel, appended to this evidence as Attachment 3, and are quoted in full 22

in the body of our written evidence below. 23

We are aware that we owe a Duty of Independence, as described in Attachment 3, and 24

confirm that we have prepared this report in accordance with the Duty of Independence. 25

If called upon to give oral or written testimony, we will give that testimony in 26

conformity with the Duty of Independence. 27

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Q5. What conclusions have you reached with respect to Mr. Craig’s characterisation 1

of the role and objectives of the Commission in relation to BC Hydro’s capital 2

expenditures? 3

A5. BC Hydro invests in its system in order to be able to continue to provide safe and 4

reliable utility service to its customers as its existing assets age and as customer 5

demands change over time. In addition, where appropriate, BC Hydro will expand its 6

system. In our view, the Commission’s role includes ensuring that the major projects 7

BC Hydro is planning to undertake are in the public interest. As part of the approval 8

process, the Commission will test the cost-effectiveness of proposed projects. The 9

Commission’s role also includes ensuring that BC Hydro’s rates do not include 10

recovery for imprudent capital expenditures. The role of BC Hydro management 11

includes planning, implementing approved projects and managing the company’s 12

operations (including controlling costs). It would not be efficient or effective if the 13

Commission were to replicate or second-guess the role of BC Hydro management. 14

In order to assess whether proposed major capital projects are in the public interest, the 15

Commission will review information that BC Hydro provides to it. The anticipated 16

costs of proposed projects are relevant for assessing cost-effectiveness. However, BC 17

Hydro rates are trued up so that rates ultimately reflect the actual costs of additions to 18

the system rather than anticipated costs. The Commission’s assessment of cost-19

effectiveness of major projects takes place before the projects are implemented. 20

The Commission is also responsible for evaluating the prudence of BC Hydro’s capital 21

projects. The evaluation of prudence takes place after a project is implemented (but 22

without using hindsight). 23

Mr. Craig’s evidence emphasizes the Commission’s role in relation to the cost-24

effectiveness of BC Hydro’s capital spending. However, it also appears to conflate 25

control of BC Hydro costs with assessing cost-effectiveness of proposed projects. The 26

latter is part of the Commission’s role but the former, control of costs, is not. 27

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Q6. What conclusions have you reached with respect to Mr. Craig’s proposal to assess 1

cost-effectiveness via annual filing requirements? 2

A6. We have reviewed the evidence of Mr. Craig, as well as responses to information 3

requests concerning Mr. Craig’s evidence. We have not found in his evidence a clear 4

articulation of what is currently missing from BC Hydro’s proposed information 5

filings, nor a clear explanation of how the Commission would make use of any 6

additional information that Mr. Craig recommends be provided in Commission 7

decision-making. 8

Mr. Craig seems to be concerned about the overall strategic direction of BC Hydro’s 9

capital expenditure plans, and about whether BC Hydro is effectively controlling costs 10

when it implements its plans. Our understanding is that neither of these concerns relates 11

to a function of the Commission that is currently missing or that would be appropriate 12

to add. The overall strategic direction of BC Hydro’s capital expenditure plans, as with 13

utilities in many North American jurisdictions, is tested through an Integrated Resource 14

Planning (IRP) process. Controlling costs as BC Hydro’s capital expenditure plans are 15

implemented is the responsibility of BC Hydro’s management. Under current 16

procedures, all of BC Hydro’s capital expenditures can be reviewed for prudence, and 17

the Commission can direct BC Hydro to exclude imprudent sums from cost-recovery 18

in rates. 19

Consistent with our view, we note that Mr. Craig and the CEC have not identified how 20

any specific Commission processes or decisions would be assisted by the additional 21

filings Mr. Craig recommends. 22

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2 ROLE AND OBJECTIVES OF COMMISSION 1

Mr. Craig is of the view (at para. 2) that the role of the Commission with 2 respect to capital expenditures and investments is “to ensure that they 3 are cost-effectively deployed and provide full value for ratepayers.” Mr. 4 Craig’s view (at para. 12) is that the objectives of the Commission 5 should be: 6

“a) To determine whether the BC Hydro capital planning and planned 7 capital expenditures and investment will be cost-effective for ratepayers 8 and that the degree of cost-effectiveness will be improving over time. 9

b) To effectively employ the regulatory information obtained from 10 oversight of BC Hydro’s capital to support Commission decision on 11 approvals for CPCN applications, Section 44.2 of the Utilities 12 Commission Act (“UCA”) Expenditure Schedule Applications, and 13 Revenue Requirement Applications (“RRA”) as well as any other 14 related Commission approval or inquiry process.” 15

2.1 QUESTION 1 16

Has Mr. Craig properly characterized the role and objectives of a 17 regulator such as the Commission with respect to its oversight over a 18 public utility’s capital expenditures and projects? 19

Q7. What is the role of regulators of energy utilities with respect to oversight of capital 20

expenditures? 21

A7. A key role of energy regulators is to ensure that rates charged for utility service are just 22

and reasonable. As part of ensuring that rates are just and reasonable, regulators want 23

to make sure that utilities do not recover in rates the costs of investments that were 24

unrelated to providing utility service or which were unnecessary or wasteful. Such 25

investments would be judged imprudent. Imprudent capital expenditure is not 26

consistent with just and reasonable rates, so regulators will review capital expenditure 27

incurred before authorizing the corresponding capital additions to be included in rate 28

base. This is an after-the-fact review focused on the prudence standard. While prudence 29

reviews take place after a decision has been implemented, they are necessarily forward-30

looking in the sense that they should use only information available to the utility at the 31

time decisions were taken. 32

Regulators often have a role in relation to longer term strategic plans. For example, a 33

utility may have identified a long-term need to replace aging generation resources, and 34

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it may have choices over the type of replacement capacity to procure. Some 1

stakeholders might advocate procuring coal capacity because coal is expected to be 2

cheap; others may advocate gas-fired capacity because emissions are lower; while still 3

others might advocate a mix of renewables and other resources. Consideration of such 4

strategic options typically takes place in an IRP process. The IRP process is focused on 5

long-term strategy and does not usually result in approval of specific projects. Rather, 6

subsequent project approval processes may include testing how proposed projects 7

contribute to or are consistent with the approved IRP. 8

Regulators also often have a role in approving certain projects before they are 9

implemented. The utility may identify that new capacity will be needed in future—for 10

example, a constraint on the network, or a declining margin between peak demand and 11

peak supply. There may be more than one option for delivering the needed new 12

capacity, where the options have different characteristics. For example, one project 13

might be more expensive but have more favourable environmental characteristics. The 14

regulator may have a role in evaluating alternatives to a proposed project as part of the 15

approval process before the project is implemented. 16

In some jurisdictions authorized revenues (and therefore rates) reflect anticipated future 17

capital expenditures, and there are infrequent and prospective true-ups for differences 18

between anticipated and actual capital expenditures. This contrasts with the regime that 19

applies to BC Hydro, where authorized revenues and rates are trued up retrospectively 20

at every test period for differences between anticipated and actual capital expenditures. 21

In these other jurisdictions regulators are likely to be concerned with the level of 22

anticipated capital expenditure because they are prospectively incorporated into rates. 23

Typically, these regulators are concerned that the level of capital expenditure 24

corresponds to what is reasonably anticipated and is not biased upwards, since actual 25

expenditure below anticipated levels accrue to the utility as additional return over and 26

above the authorized rate of return. These regulators are concerned that rates should 27

reflect only the capital expenditure that is reasonably anticipated to be spent. 28

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Q8. In BC Hydro’s case, does the Commission need to be concerned about anticipated 1

levels of capital expenditure as it relates to future rates paid by customers? 2

A8. Anticipated levels of capital expenditure for different options are inputs to an 3

assessment of which option is the most cost-effective. However, anticipated levels of 4

capital expenditure do not ultimately influence the level of costs recovered from 5

customers. BC Hydro’s rates are trued-up such that rates ultimately only reflect actual 6

capital expenditure. In particular, if actual capital expenditure turns out to be lower than 7

the anticipated level, then that difference is returned to customers by reducing rates. It 8

does not accrue to BC Hydro as increased returns. In contrast with BC Hydro’s 9

situation, many other utilities are governed by a regulatory framework in which rates 10

are set to recover anticipated capital expenditures and are not trued up (retrospectively) 11

for differences between actual and anticipated expenditures. For these utilities it is 12

necessary for regulators to assess the cost-effectiveness of the planned level of capital 13

expenditure, since for these utilities the planned level of capital expenditure is reflected 14

in rates. 15

Q9. When would such concerns arise? 16

A9. Concerns about the level of anticipated capital expenditure reflected in rates arise in 17

jurisdictions where the true up for differences between anticipated and actual 18

expenditure is infrequent and is not retrospective. Great Britain, Australia, New 19

Zealand, California and, to an extent, Alberta are examples of jurisdictions where actual 20

capital expenditure below anticipated levels would result in increased returns for the 21

utility. 22

Q10. What is the rationale for limiting the true-up for differences between anticipated 23

and actual capital expenditures in this way? 24

A10. Avoiding a retrospective true-up for differences between anticipated and actual costs 25

is a way of aligning customer and utility incentives, so that the utility has a strengthened 26

incentive to control costs. For example, in relation to O&M expenses, the regulatory 27

framework in BC encourages BC Hydro to control O&M costs by reflecting anticipated 28

levels of reasonable O&M spending in rates, without truing up. 29

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Q11. Is it possible to achieve the same effect – encouraging the utility to control costs – 1

through regulatory oversight of capital expenditure plans? 2

A11. No. Controlling capital costs involves identifying worthwhile initiatives that have a 3

good chance of reducing costs, and managing their successful implementation. This is 4

the function of utility management, and regulators typically do not try to second guess 5

management decisions because they do not have the staff expertise and other resources 6

to be effective in doing so. 7

Q12. What do you understand by the term “cost-effective” as that term is used by the 8

Commission in its decision-making on major projects? 9

A12. “Cost-effective” is a term that can have different meanings in different contexts. In one 10

context, implementation of a particular project might be said to be cost-effective if the 11

work was done without incurring any unnecessary cost, or if the overall cost of the 12

project was minimized (without compromising the project’s scope). In a different 13

context, one option might be said to be more cost-effective than another option if the 14

former had a better overall balance of costs and benefits than the latter. In this second 15

context, the more cost-effective option is not necessarily the option with the lower 16

expected financial cost. The more cost-effective option might cost more but have a 17

better environmental outcome, for example, or it might have higher capital cost, but 18

have a longer expected economic life and lower expected lifetime costs once 19

maintenance is included. 20

We understand that when the Commission uses the term “cost-effective” in its decision-21

making, it is referring to the second context described above: where there is a choice 22

between several different options, the Commission will approve the most cost-effective 23

option (even if that option does not have the lowest expected cost).1 24

1 For example: “The principal distinction between most cost-effective and least-cost is the scope of

considerations that are relevant. In the context of this Decision, most cost-effective includes consideration of project characteristics such as reliability, dispatchability, timing, and location as well as the cost or price, in the case of an EPA. Least-cost is taken to only include cost or price considerations.”(BCUC, Decision and Order No. G-55-03, September 8, 2003, p. 77); “The task is not to select the least cost project, but to select the most cost-effective project. Therefore, as suggested by BC Hydro, reliability, safety, schedule, financing arrangements and other factors itemized in the VIGP

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In this evidence, when we use the term “cost-effective” we are referring to the choice 1

between several different options that have different expected costs and different 2

characteristics. In order to avoid confusion, when we refer to the idea that utilities 3

should implement chosen projects without incurring unnecessary costs we use the term 4

“cost control”. When we refer to Commission proceedings to approve major projects, 5

we are referring to CPCN and Section 44.2 proceedings.2 6

Q13. When “cost-effective” and related terms are used in Mr. Craig’s evidence, what 7

is implied by those terms? 8

A13. It appears that when “cost-effective” is used in Mr. Craig’s evidence, the term 9

sometimes means “cost-effective” as the Commission uses the term in CPCN 10

proceedings, and sometimes the term means “cost control”. For example, Mr. Craig’s 11

evidence states “The CEC provides in Part I of the evidence a set of templates for 12

quantitatively representing BC Hydro’s cost-effectiveness in managing and planning 13

capital expenditures and investments.”3 “Planning” of capital expenditures could 14

include both cost-effectiveness and cost control, but “managing” capital expenditures 15

seems to focus on cost control. Furthermore, Mr. Craig’s recommendations are for 16

ongoing annual filings across the utility as a whole, whereas cost-effectiveness is 17

focused on options and a choice between specific projects. In addition, in response to 18

an information request about cost-effectiveness of capital investments, the CEC said:4 19

The Commission’s oversight of the costs and importantly the benefits 20 of these expenditures can lead to improvements of BC Hydro’s cost-21 effectiveness. Over 10 years the total capital expenditures may involve 22 over $220 billion. If the oversight of the BC Hydro cost-effectiveness 23 results in a 1% improvement on $10 billion of expenditures this could 24 be worth $100 million of benefit for each 1% or $10 billion to which it 25 may be applicable. The benefit potential for ratepayers of improved 26 Commission oversight could be $10s of millions. 27

Decision and revised by BC Hydro are also relevant to the task before the Commission Panel” (BCUC, Decision and Order No. C-4-06, July 7, 2006, p. 15).

2 Utilities Commission Act, RSBC 1996, Chapter 473. 3 Exhibit C3-10, p. 2. 4 Exhibit C3-13, p. 8.

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In the quoted extract the CEC makes clear that it is talking about the benefit to 1

ratepayers of controlling costs rather than cost-effectiveness as that term is used in 2

Commission proceedings to approve major projects. Existing processes already provide 3

for the approval of the most cost-effective major projects and for imprudent costs to be 4

excluded from recovery in rates. Success in controlling costs would benefit ratepayers, 5

but this is a function of utility management. 6

Q14. Is there any connection between cost-effectiveness, as the Commission uses that 7

term in major project proceedings, and prudence? 8

A14. Yes. There is a connection in the sense that both cost-effectiveness and prudence should 9

be forward-looking assessments (when properly conducting a prudence review, the 10

regulator will assess the decision from the point of view of utility management at the 11

time the decision was taken, using only information that management knew or ought 12

to have known at that time). If a regulator had approved a project as cost-effective, and 13

the project was implemented as anticipated, the regulator would not reject it for 14

inclusion in rates due to imprudence even if unanticipated changes in business or 15

market conditions occurred such that the project became less cost-effective after the 16

fact. In short, an assessment of cost-effectiveness is undertaken before a project is 17

completed, whereas prudence is properly a forward-looking assessment undertaken 18

afterwards without resort to hindsight review. 19

Q15. Is it possible that a project approved as cost-effective could nonetheless be subject 20

to a prudence review and cost disallowance subsequently? 21

A15. Yes. If a utility were imprudent in implementing a particular project after the project 22

was approved as cost-effective, such as in the case of an imprudent cost overrun, the 23

costs of such imprudence should be excluded from rates. 24

Q16. If there were to be a finding that actual costs for a project exceeded the approved 25

budget for the project, would this necessarily imply imprudence? 26

A16. No. Actual costs can be different from the anticipated costs or the approved budget for 27

many reasons, including external circumstances changing after the project is approved. 28

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Costs are only imprudently incurred if they result from management decisions that were 1

unreasonable in light of what was known (or should have been known) at the time of 2

the decision. 3

Q17. If, after the fact, it is apparent that opportunities to reduce the costs of project 4

implementation were not taken up, does this imply imprudence? 5

A17. No. First a prudence review should be strictly forward looking and should not make 6

use of hindsight. Second, opportunities to reduce costs are often not without risk. 7

Therefore it is rarely possible to say with certainty that an alternative implementation 8

would have reduced costs. The prudence standard recognizes that utility management 9

has significant discretion provided that it acts in good faith.5 10

Q18. Does the CEC recognize this distinction between management’s role and the role 11

of the Commission? 12

A18. Yes. The CEC was asked, in relation to Mr. Craig’s proposals:6 13

Q: To what extent do your proposals move beyond gathering 14 information for regulatory oversight purposes toward directing the 15 decision-making process? Please situate your response in relation to the 16 Commission’s jurisdiction. 17

A: The CEC has attempted to ensure that its recommendations to the 18 Commission are confined to seeking Commission oversight information 19 not for the purpose of interfering in the management process but for the 20

5 For example, the Federal Energy Regulatory Commission examined the prudence standard in a 1985

decision concerning recovery of costs for a cancelled nuclear power plant. The FERC reviewed relevant precedent and said: “The adjectives used in the cases in discussing imprudent costs—“extravagant,” “ unnecessary,” “inefficient,” “improvident,” etc.—all describe rather than define imprudence… …Consistent with the cases discussed herein, we reiterate that managers of a utility have broad discretion in conducting their business affairs and in incurring costs necessary to provide services to their customers. In performing our duty to determine the prudence of specific costs, the appropriate test to be used is whether they are costs which a reasonable utility management (or that of another jurisdictional entity) would have made, in good faith, under the same circumstances, and at the relevant point in time. We note that while in hindsight it may be clear that a management decision was wrong, our task is to review the prudence of the utility's actions and the costs resulting therefrom based on the particular circumstances existing either at the time the challenged costs were actually incurred, or the time the utility became committed to incur those expenses.” (FERC, Opinion No. 231, Docket No. ER82-703-000, Issued April 11, 1985, p. 5).

6 Exhibit C3-14, pp. 2-3.

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purpose of the Commission’s approval role responsibilities under the 1 UCA. 2

The Commission cannot seek to direct the management decision making 3 process in BC Hydro. 4

We note, however, that the CEC’s answer goes on to say: 5

The CEC’s evidence is aimed at improvement of the Commission’s 6 oversight information. The CEC has recommended this so that the 7 Commission can assess BC Hydro’s management of its capital 8 expenditures and investments. The CEC believes that the Commission 9 needs to do this in order to build the Commission’s own understanding 10 of the cost-effectiveness of BC Hydro’s management of its capital 11 expenditures and investments. This understanding is essential to the 12 Commission’s role under the UCA. 13

Thus, despite the CEC’s stated policy view that its proposals should not interfere with 14

BC Hydro’s management processes, the information collection procedure and 15

Commission assessment of “BC Hydro’s management of its capital expenditures” that 16

CEC is recommending appears intended to do just that. 17

Q19. In your view, is it helpful “to build the Commission’s own understanding of the 18

cost-effectiveness of BC Hydro’s management of its capital expenditures and 19

investments”, as the CEC suggests? 20

A19. In our view, the CEC’s suggestion appears to be about cost control, not cost-21

effectiveness as that term is used by the Commission. The CEC’s suggestion is not 22

helpful because the CEC has not explained what Commission process or decision-23

making would be informed by such understanding. The Commission already has the 24

ability to review BC Hydro capital expenditures for prudence. The Commission already 25

assesses cost-effectiveness at the project approval stage, for major projects. We 26

understand that BC Hydro makes an application for Commission approval for projects 27

above a size threshold, prior to implementing the proposed projects.7 This allows the 28

Commission to focus its limited resources on assessing larger projects. 29

7 The proposed size thresholds are $100m for power system projects, $50m for buildings and $20m for

IT projects (Exhibit B-7, p. 7).

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3 MR. CRAIG’S FRAMEWORK AND ASSESSING “BEGINNING STAGES” OF 1 CAPITAL 2

In Part I of his evidence, Mr. Craig describes a framework for 3 information that should be provided to the Commission to facilitate its 4 review of capital expenditures and projects. 5

In Part II of his evidence, Mr. Craig explains how the regulatory process 6 should utilize this information (at para. 97) to build an understanding of 7 the “long-term cost-effectiveness of BC Hydro’s capital investments”. 8 Mr. Craig states the Commission’s process “should allow for greater 9 assessment at the beginning stages (drivers, strategies & plans) of the 10 capital expenditures” and (at para. 98) that “[a]ssessments being 11 conducted at a higher level and at an earlier stage will enable the 12 Commission’s regulatory processes to identify more improvement 13 opportunities and increase the ability of the Commission to determine 14 the cost effectiveness of BC Hydro capital expenditures.” Mr. Craig also 15 states (at para. 99) this process “would provide the Commission with 16 the opportunity to ensure that cost-effectiveness is embedded in the 17 whole stream of oversight for capital planning and decision making and 18 at a time that allows for significant changes in cost effectiveness to be 19 implemented.” 20

3.1 QUESTION 2 21

What is your assessment of Mr. Craig’s framework and proposal to 22 attempt to assess the cost-effectiveness of BC Hydro’s capital drivers, 23 strategies and plans through annual capital reports? 24

Q20. What does Mr. Craig’s evidence say about the limitations of the current 25

framework for BC Hydro to provide information to the Commission about its 26

capital expenditure? 27

A20. Mr. Craig’s evidence discusses various components of the existing framework for BC 28

Hydro to provide information about capital expenditures, as follows: 29

Both the RRA and the Annual Report to the Commission provide an 30 historical view of spending with only a limited review of future 31 spending, such that neither process provides an opportunity to assess 32 planned future spending.[8] 33

… 34

While the RRA process determines the expenditures that are permitted 35 to be reflected in rates over a future period, it is typically limited to three 36

8 Exhibit C3-10, pp. 53-54.

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years and limits the Commission’s opportunity to assess the overall 1 long-term capital expenditure plan and the processes which resulted in 2 those plans.[9] 3

… 4

The Commission also has opportunity to review the capital planning 5 process through the applications and the information request process for 6 CPCNs and Section 44.2 applications and in its review of the Annual 7 Report to the Commission. However, these environments are not 8 conducive to a significant assessment of the capital planning process, as 9 the focus is on the approval of a specific project expenditure or set of 10 project expenditures.[10] 11

… 12

Certain key strategic issues are addressed in various plans such as the 13 IRP and other places. For instance, information related to how much 14 growth should be addressed through DSM (versus other options) is 15 determined in the IRP, and this may be used as the basis for various 16 planning decisions. However, the IRP is developed only occasionally 17 and does not provide an ongoing examination of the strategies that the 18 company has available to address growth, sustainment, and risk drivers. 19 The current IRP was developed in 2013.[11] 20

In consequence, Mr. Craig recommends a focus on the “beginning stages (drivers, 21

strategies & plans)”,12 and on an annual process. 22

Q21. Do you agree with the concerns expressed in Mr. Craig’s evidence which you 23

quoted above? 24

A21. No. We have not reviewed the Commission’s approach to the various processes 25

described above in order to form a view of how well they meet the objectives of those 26

processes (RRA, CPCN, Section 44.2, Annual Report and IRP), but if Mr. Craig’s 27

characterisations of them is accurate, we do not consider that this constitutes identified 28

problems to which the appropriate solution is an additional annual filing requirement 29

focused on “beginning stages”. For example, if the current IRP is out-of-date, the 30

solution might be to update the IRP. The RRA does not need to look at longer time-31

9 Exhibit C3-10, p. 53. 10 Exhibit C3-10, p. 56. 11 Exhibit C3-10, p. 82. 12 Exhibit C3-10, p. 54.

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frames because major projects are subject to a separate approval process, and because 1

rates are trued up to reflect actual capital expenditure. Under current procedures, all of 2

BC Hydro’s capital expenditures can be reviewed for prudence, and the Commission 3

can direct BC Hydro to exclude imprudent sums from cost-recovery in rates. 4

Q22. In your view, what are the appropriate processes for oversight of BC Hydro’s 5

capital planning? 6

A22. The IRP process is the logical place to review BC Hydro’s strategic plans. As the 7

strategic plans are worked up into proposals for specific projects, those proposals are 8

appropriately reviewed in CPCN and Section 44.2 proceedings, with these proceedings 9

testing whether the proposed projects are cost-effective. Finally, it continues to be 10

appropriate for the Commission to review the prudence of past investments to ensure 11

that BC Hydro’s implementation decisions are reasonable. 12

Q23. Would an annual review of capital plans or the capital planning process improve 13

Commission oversight of cost-effectiveness? 14

A23. No. The CPCN and Section 44.2 processes already test the cost-effectiveness of 15

proposed projects, and the Commission is already able to review past expenditure for 16

imprudence in the RRA. If BC Hydro’s capital planning process is defective and results 17

in imprudence, the Commission already has the ability to ensure that imprudent 18

spending is not reflected in rates. Furthermore, the RRA process provides the 19

Commission with information about capital projects, including projects which do not 20

reach the thresholds for requiring Commission approval.13 21

Q24. Assume that BC Hydro’s planning process does not result in imprudent spending. 22

Would it be possible for additional or improved Commission oversight to find 23

ways of improving cost-effectiveness? 24

A24. No. Cost-effectiveness concerns the selection of the right project in a given 25

circumstance. That is addressed through the CPCN and Section 44.2 processes, and Mr. 26

13 See, for example, BC Hydro Fiscal 2017 to F2019 Revenue Requirements and Rates Application,

Appendix J, which provides information on all projects over $20m.

Page | 16

Craig’s evidence does not express concerns that these processes are not operating as 1

intended. Cost control in relation to project implementation could perhaps be improved, 2

but cost control is different from cost effectiveness, as we explained above. 3

Q25. Would an annual reporting process improve cost control of project 4

implementation? 5

A25. Not in our opinion. Cost control is properly the function of utility management. It 6

would not be efficient or effective for the Commission to second-guess management 7

decisions on project implementation. To be effective in this role, the Commission 8

would need to effectively duplicate the staff expertise that already resides in the utility. 9

This would be inefficient. Moreover, Commission involvement in project 10

implementation could result in biases, such as avoiding innovation in favour of 11

established technology or processes. 12

Q26. What is your view of the examples provided in CEC IR responses of instances 13

where Mr. Craig’s proposals are claimed to offer the potential for improvement? 14

A26. In the CEC’s response to IR 1.2 from the Commission Staff, four examples of “drivers, 15

strategies & plans” are given. According to the CEC, Mr. Craig’s annual reporting 16

proposals would add value in the following instances. 17

• Load growth driver: The CEC asserts that BC Hydro’s load forecast 18 might be over-forecasting, resulting in too much (or too early) load-19 driven capital expenditures, such that “it would be more cost-effective 20 for such capital expenditures to be better matched to the demand.”14 21

• Condition driver: The CEC asserts that BC Hydro’s life-cycle asset 22 management might be resulting in replacement activity either too early 23 or too late, resulting in opportunities for BC Hydro to obtain “more 24 value from its capital expenditures and investments were it to more cost-25 effectively manage these assets.”15 26

14 Exhibit C3-13, p. 5. 15 Exhibit C3-13, p. 6.

Page | 17

• Replacement strategies: The CEC asserts, in connection with fleet, 1 buildings, and smaller regional transmission and generation projects, 2 that “strategies may be more appropriately reviewed across the whole 3 set of potential projects, rather than passing through one project at a 4 time.”16 5

• IT capital plan: The CEC asserts that individual projects are below the 6 CPCN thresholds but have a common underlying strategy which is 7 never reviewed by the Commission: “There are a number of examples 8 within the Technology Group where platform strategies are followed by 9 numerous projects. These strategies can drive significant capital but 10 may not be seen as part of the Commission oversight.”17 11

If these assertions are alleged to be examples of BC Hydro making unreasonable 12

decisions, the consequences would be subject to prudence review. If these are examples 13

of management decisions which could perhaps be improved upon, this is not a cost-14

effectiveness concern. 15

Q27. Are you aware of any jurisdictions where concerns about oversight of utility cost-16

effectiveness have resulted in annual filing requirements similar to those 17

recommended in Mr. Craig’s evidence? 18

A27. No. Mr. Craig’s evidence recommends annual reporting of cost-effectiveness, 19

including quantified metrics of cost-effectiveness, focused on early stages (drivers, 20

strategies and plans). In our view, these annual information filing recommendations do 21

not relate to cost-effectiveness—meaning assessment of options before a project is 22

implemented. Rather these recommendations necessarily relate to controlling the costs 23

of projects as they are being implemented, an oversight role that is not appropriate or 24

necessary for the Commission to undertake. We are not aware of any jurisdictions that 25

have implemented similar annual reporting requirements, nor are any cited in Mr. 26

Craig’s evidence. 27

16 Exhibit C3-13, p. 7. 17 Exhibit C3-13, p. 8.

ATTACHMENT 1

RESUME OF DR. PAUL R. CARPENTER

PAUL R. CARPENTER Principal

San Francisco, CA +1.415.217.1000 Paul.Carpenter@brattle.com

1

Dr. Paul Carpenter holds a Ph.D. in applied economics and an M.S. in management from the Massachusetts

Institute of Technology, and a B.A. in economics from Stanford University. He specializes in the

economics of the natural gas, oil, electric utility and other infrastructure industries. Dr. Carpenter was a

co-founder of Incentives Research, Inc. in 1983. Prior to that he was employed by the NASA/Caltech Jet

Propulsion Laboratory and Putnam, Hayes & Bartlett, and he was a post-doctoral fellow at the MIT Center

for Energy Policy Research. He is currently a Principal and former Chairman of The Brattle Group. AREAS OF EXPERTISE

Energy economics

Regulation

Corporate planning

Pricing Policy

Antitrust

EXPERIENCE Natural Gas and Electric Utility Industries

Consulting and testimony on nearly all of the economic and regulatory issues surrounding the

transition of the natural gas and electric power industries from strict regulation to greater

competition. These issues have included stranded investments and contracts, design and pricing

of unbundled and ancillary services, evaluation of supply, demand and price forecasting models,

the competitive effects of pipeline expansions and performance-based ratemaking. He has

consulted on the regulatory and competitive structures of the gas and electric power industries in

the U.S., Canada, the United Kingdom, continental Europe, Australia and New Zealand. Valuation and Damages

Expert testimony before courts, tribunals and in arbitrations concerning asset valuation and

damages associated with breach of contract, bankruptcy and commercial disputes. Experience

includes expert testimony in U.S. federal and state courts, the British High Court of Justice, the

Australian Competition Tribunal and various arbitration and mediation panels in Australia,

Canada, New Zealand and the U.S. Listed as a leading expert in quantum of damages in Who’s Who Legal: Consulting Experts 2017.

Antitrust

Paul R. Carpenter

2

Expert testimony in several of the seminal cases involving the alleged denial of access to regulated

facilities; analysis of relevant market and market power issues, business justification defenses, and

damages. Regulation

Studies and consultation on alternative ratemaking methodologies for oil and gas pipelines and

other utilities, on “bypass” of regulated facilities before the U.S. Congress; advice and testimony

before several state utility commissions and the National Energy Board of Canada on new facility

certification policy. Finance

Research on business and financial risks in the regulated industries and testimony on risk, cost of

capital, and asset valuation for network industries, airports and seaports in the U.S., Canada.,

Australia and New Zealand. PROFESSIONAL AFFILIATIONS

American Economic Association ACADEMIC HONORS AND FELLOWSHIPS

Stewart Fellowship, 1983

MIT Fellowships, 1981, 1982, 1983

Brooks Master’s Thesis Prize (Runner-up), MIT, 1978 PUBLICATIONS

“Pipeline Regulatory Issues Arising From Oil and Natural Gas Production Growth in North America” with

Matthew O’Loughlin and Steve Levine, The Energy Law Advisor, Volume 8, No. 1, February 2014. “A Framework for Analyzing Market Manipulation.” Review of Law and Economics, September 2012 (with Shaun D. Ledgerwood) “Shale Gas and Pipeline Risk,” Public Utilities Fortnightly, April 2012 (with Steven H. Levine, A. Lawrence Kolbe and Bente Villadsen) “Options for Reforming the Building Blocks Framework.” Report to the Australian Energy Market Commission, 16 December 2009, (with Toby Brown).

Paul R. Carpenter

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“The Advent of U.S. Gas Demand Destruction and Its Likely Consequences for the Pricing of Future European Gas Supplies,” (with Carlos Lapuerta and Morten Frisch), 16 March 2005. “REx Incentives: Performance Based Ratemaking (PBR) Choices that Reflect Firms’ Performance Expectations,” (with Johannes P. Pfeifenberger and Paul C. Liu), The Electricity Journal, November 2001. “Asset Valuation and the Pricing of Monopoly Infrastructure Services: A Discussion Paper,” (with Carlos Lapuerta) 28 July 2000. “Competition in Gas Pipeline Markets: International Precedent for Regulatory Coverage Decisions,” Report to the National Competition Council of Australia (with Judy Chang), June 2000.

“Methodologies for Establishing National and Cross-Border Systems of Pricing of Access to the Gas System

in Europe,” Report to the European Commission (with Carlos Lapuerta and Boaz Moselle), February 2000.

“A Critique of Light-handed Regulation: The Case of British Gas,” (with Carlos Lapuerta), Northwestern Journal of International Law & Business, Volume 19, No. 3, Spring 1999.

“Separate Marketing of Natural Gas by Joint Venture Producers in Australia,” (with Jurgen Weiss),

prepared for Optima Energy, Australia, submitted to the Upstream Issues Working Group, Australian and

New Zealand Minerals and Energy Council, 26 September 1998.

“Likely Trends in Canadian Natural Gas Imports,” (with Matthew P. O’Loughlin and Gao-Wen Shao),

Natural Gas, Volume 14, No. 8, March 1998.

“Pipeline Pricing to Encourage Efficient Capacity Additions,” (with Frank C. Graves and Matthew P.

O’Loughlin), prepared for Columbia Gas Transmission Corporation and Columbia Gulf Transmission

Company, February 1998.

“The Outlook for Imported Natural Gas,” (with Matthew P. O’Loughlin and Gao-Wen Shao), prepared for

The INGAA Foundation, Inc., July 1997.

“Basic and Enhanced Services for Recourse and Negotiated Rates in the Natural Gas Pipeline Industry,” (with Frank C. Graves, Carlos Lapuerta, and Matthew P. O’Loughlin) May 29, 1996, prepared for Columbia Gas Transmission Corporation, Columbia Gulf Transmission Company. “Estimating the Social Costs of PUHCA Regulation,” (with Frank C. Graves) submitted on behalf of Central

and South West Corp. to the U.S. Securities and Exchange Commission in its Request for Comments on

the Modernization of Regulation of Public Utility Holding Companies, File No. S7-32-94, February 6,

1995.

“Review of the Model Developer’s Report, Natural Gas Transmission And Distribution Model (NGTDM) Of The National Energy Modeling System,” December 1994, prepared for U.S. Department of Energy,

Paul R. Carpenter

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Energy Information Administration and Oak Ridge National Laboratory under Subcontract No. 80X-SL220V. “Pricing of Electricity Network Services to Preserve Network Security and Quality of Frequency Under Transmission Access,” (with Frank C. Graves, Marija Ilic, and Asef Zobian) response to the Federal Energy Regulatory Commission’s Request for Comments in its Notice of Technical Conference Docket No. RM93-19-000, November 1993. “Creating a Secondary Market in Natural Gas Pipeline Capacity Rights Under FERC Order No. 636,” (with Frank C. Graves) draft December 1992, Incentives Research, Inc. “Review of the Component Design Report, Natural Gas Annual Flow Module, National Energy Modeling System,” August 1992, prepared for the U.S. Department of Energy, Energy Information Administration. “Unbundling, Pricing, and Comparability of Service on Natural Gas Pipeline Networks,” (with Frank C. Graves) November 1991, prepared for the Interstate Natural Gas Association of America. “Review of the Gas Analysis Modeling System (GAMS): Final Report of Findings and Recommendations,”

August 1991, prepared for the U.S. Dept. of Energy, Energy Information Administration.

“Estimating the Cost of Switching Rights on Natural Gas Pipelines,” (with F.C. Graves and J.A. Read) The Energy Journal, October 1989. “Demand-Charge GICs Differ from Deficiency-Charge GICs,” (with F.C. Graves) Natural Gas, Vol. 6, No. 1, August 1989. “What Price Unbundling?” (with F.C. Graves) Natural Gas, Vol. 5 No. 10, May 1989. Book Review of Drawing the Line on Natural Gas Regulation: The Harvard Study on the Future of Natural Gas, Joseph Kalt and Frank Schuller, eds., in The Energy Journal, April 1988. “Adapting to Change in Natural Gas Markets,” (with Henry D. Jacoby and Arthur W. Wright) in Energy, Markets and Regulation: What Have We Learned?, Cambridge: MIT Press, 1987. Evaluation of the Commercial Potential in Earth and Ocean Observation Missions from the Space Station Polar Platform, Prepared by Incentives Research for the NASA Jet Propulsion Laboratory under Contract

No. 957324, May 1986.

An Economic Comparison of Alternative Methods of Regulating Oil Pipelines, (with Gerald A. Taylor) Prepared by Incentives Research for the U.S. Department of Energy, Office of Competition, July 1985. “The Natural Gas Policy Drama: A Tragedy in Three Acts,” (with Arthur W. Wright) MIT Center for Energy Policy Research Working Paper No. 84-012WP, October 1984. Oil Pipeline Rates and Profitability under Williams Opinion 154 , (with Gerald A. Taylor), Prepared by Incentives Research for the U.S. Department of Energy, Office of Competition, September 1984.

Paul R. Carpenter

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Natural Gas Pipelines After Field Price Decontrol: A Study of Risk, Return and Regulation, Ph.D. Dissertation, Massachusetts Institute of Technology, March 1984. Published as a Report to the U.S. Department of Energy, Office of Oil and Gas Policy, MIT Center for Energy Policy Research Technical Report No. 84-004. The Competitive Origins and Economic Benefits of Kern River Gas Transmission, Prepared by Incentives

Research, Inc., for Kern River Gas Transmission Company, February 1994.

“Field Price Decontrol of Natural Gas, Pipeline Risk and Regulatory Policy,” in Government and Energy Policy, Richard L. Itteilag, ed., Washington D.C., June 1983. “Risk Allocation and Institutional Arrangements in Natural Gas,” (with Arthur W. Wright) invited paper presented to the American Economic Association Meetings, San Francisco, December 1983.

“Vertical Market Arrangements, Risk-shifting and Natural Gas Pipeline Regulation,” Sloan School of

Management Working Paper No. 1369-82, September 1982 (Revised April 1983).

Natural Gas Pipeline Regulation After Field Price Decontrol (with Dr. Henry Jacoby and Arthur W. Wright), prepared for U.S. Department of Energy, Office of Oil and Gas Policy, MIT Energy Lab Report No. 83-013, March 1983. Book Review of An Economic Analysis of World Energy Problems, by Richard L. Gordon, Sloan Management Review, Spring 1982. “Perspectives on the Government Role in New Technology Development and Diffusion,” (with Drew Bottaro) MIT Energy Lab Report No. 81-041, November 1981. International Plan for Photovoltaic Power Systems (co-author), Solar Energy Research Institute with the Jet Propulsion Laboratory Prepared for the U.S. Department of Energy, August 1979. Federal Policies for the Widespread Use of Photovoltaic Power Systems (contributor), Jet Propulsion Laboratory Report to the U.S. Congress DOE/CS-0114, March 24, 1980. “An Economic Analysis of Residential, Grid-connected Solar Photovoltaic Power Systems,” (with Gerald

A. Taylor) MIT Energy Laboratory Technical Report No. 78-007, May 1978.

SPEECHES/PRESENTATIONS “The Global Context for Alaskan Oil and LNG,” Energy in Alaska Conference, Anchorage, Alaska,

December 12, 2016.

“The Global Context for Alaskan LNG,” Energy in Alaska Conference, Anchorage, Alaska, December 7,

2015.

Paul R. Carpenter

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“The Collapse of World Oil Prices and its Effects on Global LNG Trade,” Energy Regulatory Commission

of Thailand, Bangkok, March 8, 2015.

“Changing Times – New Uncertainties: Assessing Their Effects on Global Energy and LNG Export

Markets,” Energy Markets and Regulation in Alaska Conference, December 8, 2014.

“Russia, Ukraine, and Trade,” Georgetown Center for Business and Public Policy, Washington D.C., April

23, 2014.

“The Uncertain Future For ANS LNG Exports,” Energy in Alaska Conference, Anchorage, Alaska,

December 3, 2012. “The Uncertain Future for Alaska North Slope Gas in the Lower-48,” Energy in Alaska Conference, Anchorage, Alaska, December 2, 2011. “Economic Perspectives on Gas Trading Markets and Regulation,” Canada/U.S. Energy Transactions Conference, Vancouver B.C., August 24, 2010. “Incentive Regulation – Design: Key Plan Components,” Alberta Utility Commission Workshop on Performance Based Regulation, Edmonton, Alberta, May 26, 2010. “LNG Access Policy and California,” California Resources Agency Workshop on LNG, June 1, 2005. Opening Remarks at the Eighth Central and Eastern European Power Industry Forum (CEEPIF 2001), Budapest, March 29, 2001. “CPUC v. El Paso Merchant Energy, et al., FERC Docket No. RP00-241-000,” ABA Forum, Washington, DC, September 6, 2001. “Overseas Experience B Lessons for Australian Gas and Power Markets from California and Europe,” 2001 Gas Industry Forum, The Australian Gas Association, Melbourne, Victoria, Australia, June 26, 2001. “Liberalizing Energy Markets: Lessons from California’s Crisis,” 20th Annual Conference on US-Turkish Relations, Washington, DC, March 27, 2001.

“Opening Remarks from the Chair: Rates, Regulations and Operational Realities in the Capacity Market

of the Future,” AIC conference on “Gas Pipeline Capacity ‘97,” Houston, Texas June 17, 1997.

“Lessons from North America for the British Gas TransCo Pricing Regime,” prepared for AIC conference

on: Gas Transportation and Transmission Pricing, London, England, October 17, 1996.

“GICs and the Pricing of Gas Supply Reliability,” California Energy Commission Conference on Emerging

Competition in California Gas Markets, San Diego, Ca. November 9, 1990.

Paul R. Carpenter

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“The New Effects of Regulation and Natural Gas Field Markets: Spot Markets, Contracting and Reliability,” American Economic Association Annual Meeting, New York City, December 29, 1988. “Appropriate Regulation in the Local Marketplace,” Interregional Natural Gas Symposium, Center for Public Policy, University of Houston, November 30, 1988. “Market Forces, Antitrust, and the Future of Regulation of the Gas Industry,” Symposium on the Future of Natural Gas Regulation, American Bar Association, Washington D.C., April 21, 1988. “Valuation of Standby Tariffs for Natural Gas Pipelines,” Workshop on New Methods for Project and Contract Evaluation, MIT Center for Energy Policy Research, Cambridge, March 3, 1988. “Long-term Structure of the Natural Gas Industry,” National Association of Regulatory Utility

Commissioners Meeting, Washington D.C., March 1, 1988.

“How the U.S. Gas Market Works or Doesn’t Work,” Ontario Ministry of Energy Symposium on Understanding the United States Natural Gas Market, Toronto, March 18, 1986. “The New U.S. Natural Gas Policy: Implications for the Pipeline Industry,” Conference on Mergers and Acquisitions in the Gas Pipeline Industry, Executive Enterprises, Houston, February 26-27, 1986. Various lectures and seminars on U.S. natural gas industry and regulation for graduate energy economics courses at Massachusetts Institute of Technology, 1984-96. Panelist in University of Colorado Law School workshop on state regulations of natural gas production, June 1985. (Transcript published in University of Colorado Law Review.) “Oil Pipeline Rates after the Williams 154 Decision,” Executive Enterprises, Conference on Oil Pipeline Ratemaking, Houston, June 19-20, 1984. “Issues in the Regulation of Natural Gas Pipelines,” California Public Utilities Commission Hearings on Natural Gas, San Francisco, May 21, 1984. “The Natural Gas Pipelines in Transition: Evidence From Capital Markets,” Pittsburgh Conference on Modeling and Simulation, Pittsburgh, April 20, 1984. “Financial Aspects of Gas Pipeline Regulation,” Pittsburgh Conference on Modeling and Simulation,

Pittsburgh, April 19-20, 1984.

“Natural Gas Pipelines After Field Price Decontrol,” Presentations before Conferences of the International Association of Energy Economists, Washington D.C., June 1983, and Denver, November 1982. “Spot Markets for Natural Gas,” MIT Center for Energy Policy Research Semi-annual Associates Conference, March 1983. “Pricing Solar Energy Using a System of Planning and Assessment Models,” Presentations to the XXIV

Paul R. Carpenter

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International Conference, The Institute of Management Science, Honolulu, June 20, 1979. TESTIMONY Federal, State and International Courts/Arbitration In the United States District Court for the Northern District of Texas, Dallas Division, Exxon Mobil Corp. vs. United States of America, Case No. 3:16-cv-2921, November 2018 (expert report). In the United States District Court for the Western District of Oklahoma, Marcia W. Davilla, et al., vs. Enable Midstream Partners L.P. et al., September 2018 (expert report). In the matter of an arbitration under the rules of the United Nations Commission on International Trade Law between Northwest Shelf Pty. Ltd and Korea Gas Corp., April 2018 (expert report). In the matter of an arbitration between CBH Group and Brookfield Rail under the Railways Access Code (2000) WA, Perth, Western Australia, September 2017. In the matter of an Arbitration between Niko Resources (Bangladesh) Ltd. v. Bangladesh Petroleum and Production Co. (BAPEX) and Bangladesh Oil Gas and Mineral Corp. (Petrobangla), quantum of damages expert report, March 2016. In the matter of an Arbitration Between Vector Gas Contracts Ltd and Shell (Petroleum Mining) Company Ltd. and Todd Petroleum Mining Company Ltd., Wellington, New Zealand, March 2015. Before the United States Civilian Board of Contract Appeals, Rockies Express Pipeline v. Department of the Interior, No.1821, January 2015, March 2015, (expert reports with Steven H. Levine). In the High Court of New Zealand, Wellington Registry, In the matter of an application pursuant to rule 27 of the First Schedule of the Arbitration Act of 1996 for non-party discovery, Between Vector Gas Contracts Ltd. And Contact Energy Ltd., October 2014. In the matter of an Arbitration between the Northwest Shelf Joint Venture and Verve Energy, Perth Western Australia, July 2013. In the District Court in and for Tulsa County, the State of Oklahoma, Bettina M. Whyte, as Trustee for the SemGroup Litigation Trust v. PriceWaterhouseCoopers, LLP, April 2013. In the matter of an Arbitration between the Gippsland Basin Joint Venture and Australia Gas Light, Melbourne, Victoria, March 2013. In the British High Court of Justice, Queen’s Bench Division, Commercial Court, GB Gas Holdings Limited v. Accenture, June 2011 (expert report). In the matter of an Arbitration between Woodside Energy Ltd and Alinta Sales Pty Ltd, Perth, Western Australia, July 2009, September 2009. In the Arbitration between Niska Gas Storage US, LLC and Alenco Inc., 2007.

Paul R. Carpenter

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In the Arbitration between the Southwest Queensland Producers and Xstrata, Ltd., Brisbane, Australia, 2006. In the Superior Court of the State of California, County of San Diego, Natural Gas Anti-trust Cases I, II, III, & IV, February 2006, May 2006, June 2006 (declarations). In the United States District Court for the State of California, County of Los Angeles, Central District, TXU Energy Services Company v. American Remedial Technologies, March 2003, April 2003. In the United States District Court for the Northern District of Alabama, Northeastern Division, The City of Huntsville d/b/a Huntsville Utilities v. Proliance Energy, LLC, February 2003, June 2003, February 2005. In the Arbitration between Wellington International Airport Ltd., and Air New Zealand and Qantas Airways Ltd., August 2002. In the United States District Court for the Eastern District of Virginia, Alexandria Division, Hess Energy Inc. v. Lightning Oil Company, Ltd., July 2002.

In the United States District Court for the District of Colorado, The Farm Credit Bank of Wichita, formerly

known as The Federal Land Bank of Wichita, et al., v. Atlantic Richfield Company, April 2001.

In the United States Bankruptcy Court for the District of Delaware, KCS Energy, Inc., et al., Debtors: Chapter 11, November 2000. Mediation between Methanex LTD, et al and Westgate Port, New Zealand, May 2000. In the matter of the Arbitration between American Central Gas Company v. Union Pacific Resources and Duke Energy Fuels, et al., July 2000. In the United States District Court for the Western District of Missouri, Riverside Pipeline Company, L.P., et al., v. Panhandle Eastern Pipeline Company, September 1998. In the United States District Court, District of Columbia, United States of America, Dept. of Justice v. Enova Corporation, August 1998. In the matter of the Arbitration between Western Power Corp. and Woodside Petroleum Corp., et al., Perth, Western Australia, May-July 1998. In the United States District Court for the District of Montana, Butte Division, Paladin Associates, Inc. v. Montana Power Company, November- December 1997. In the United States District Court for the District of Colorado, Atlantic Richfield Co. v. Darwin H. Smallwood, Sr., et al., July 1997. In the Australian Competition Tribunal, Review of the Trade Practices Act Authorisations for the AGL

Paul R. Carpenter

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Cooper Basin Natural Gas Supply Arrangements, on behalf of the Australian Competition and Consumer Commission, February 1997. In the Southwest Queensland Gas Price Review Arbitration, Adelaide, South Australia, May 1996. In the matter of the Arbitration between Amerada Hess Corp. v. Pacific Gas & Electric Co., May 1995. In re Columbia Gas Transmission Corp., Claims Quantification Proceeding in the U.S. Bankruptcy Court

for the District of Delaware, Before the Claims Mediator, July and November 1993.

Deposition Testimony in Fina Oil & Gas v. Northwest Pipeline Corp. and Williams Gas Supply (New Mexico) 1992. Testimony by Affidavit in James River Corp. v. Northwest Pipeline Corp. (Fed. Ct. for Oregon) 1989. Deposition and Testimony by Affidavit in Merrion Oil and Gas Col, et al., v. Northwest Pipeline Corp. (Fed. Ct. for New Mexico) 1989. Deposition Testimony in Martin Exploration Management Co., et al. v. Panhandle Eastern Pipeline Co. (Fed. Ct. for Colorado) 1988 and 1992. Trial Testimony in City of Chanute, et al. v. Williams Natural Gas (Fed. Ct. for Kansas) 1988. Deposition Testimony in Sinclair Oil Co. v. Northwest Pipeline Co. (Fed. Ct. for Wyoming) 1987. Deposition and Trial Testimony in State of Illinois v. Panhandle Eastern Pipeline Co. (Fed. Ct. for C.D. Ill) 1984-87. Economic/Regulatory Testimony Before the Federal Energy Regulatory Commission, Enable Mississippi River Transmission, LLC, Docket

No. RP18- -000, June 2018.

Before the Alberta Utilities Commission, Generic Cost of Capital 2018, Proceeding ID No. 22570,

December 2017.

Before the Federal Energy Regulatory Commission, Spire STL Pipeline LLC, Docket No. CP17-40-000,

February 2017.

Before the Alberta Utilities Commission, Generic Proceeding to Establish Parameters for the Next Generation of Performance-Based Regulation (PBR) Plans, Proceeding ID No. 20414, March 2016.

Before the Alberta Utilities Commission, Generic Cost of Capital 2016, Proceeding ID No. 20622,

February 2016.

Paul R. Carpenter

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Before the Federal Energy Regulatory Commission, ANR Pipeline Company, Docket No. RP16-440,

January 2016.

Before the Alberta Utilities Commission, Enmax Power Corp., Proceeding ID No. 21149, December

2015.

Before the National Energy Board of Canada, TransCanada Pipelines Ltd., Application for Approval of Mainline 2013- 2030 Settlement, August 2014.

Before the National Energy Board of Canada, TransCanada Pipelines Ltd., Application for Approval of Tariff Amendments, Docket RH-1-2013, August 2013.

Before the National Energy Board of Canada, Application of Chevron Canada Ltd. For a Priority Destination Designation on the TransMountain Pipeline, Docket MH-002-2012, December 2012.

Before the National Energy Board of Canada, TransCanada PipeLines Limited, NOVA Gas Transmission Ltd., Foothills Pipe Lines Ltd. - Business and Services Restructuring Proposal and Mainline Tolls for 2012-2013, Docket RH-003-2011, September 2011, May 2012.

Before the Alberta Utilities Commission, Rate Regulation Initiative, Proceeding 566, ATCO Gas and

ATCO Electric Performance Based Regulation Applications, July 2011, April 2012.

Before the Federal Energy Regulatory Commission and the Regulatory Commission of Alaska, BP Pipelines (Alaska) Inc., FERC Docket No. IS09-348, RCA Docket P-08-9, June 2011.

Before the Illinois Commerce Commission, Northern Illinois Gas Company d/b/a/ Nicor Gas Company, Reconciliation of Revenues Collected under Gas Adjustment Charges with Actual Costs Prudently Incurred, Docket No. 01-0705, May 2011. Before the Regulatory Commission of Alaska, In the Matter of the Petition by Aurora Energy, LLC to Exempt Steam Heat Rates from Economic Regulation, Docket No. U-10-158, December 2010, January 2011. Before the Federal Energy Regulatory Commission, Kern River Gas Transmission, Docket No. RP04-274, June 2010, September 2010. Before the Michigan Public Service Commission, SEMCO Energy Gas Company, Case No. U-16169, June 2010. Before the Régie de L’Énergie, Société en Commandite Gaz Métro Cause Tarifaire 2010, Docket No. R-3690-2009, May 2009. Before the Ontario Energy Board, The Cost of Capital in Current Economic and Financial Market Conditions, Docket No. EB-2009-0084, April 2009 (report).

Paul R. Carpenter

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Before the Alberta Utilities Commission, In The Matter Of Alberta Utilities Commission 2009 Generic Cost of Capital Hearing, Application No. 1578571, November 2008. Before the Federal Energy Regulatory Commission, Energy Transfer Partners, LP, Energy Transfer Company, ETC Marketing, Ltd., Houston Pipeline Company, Docket No. IN06-3-003, September 2008, May 2009. Before the Regulatory Commission of Alaska, In the Matter of the Tariff Revision, Designated as TA167-4, Regarding a Proposed Gas Sales Agreement Between ENSTAR Natural Gas Company and ConocoPhillips Alaska, Inc. and a Proposed Gas Sales Agreement Between ENSTAR and Marathon Oil Company, Docket No. U-08-58, May 2008, July 2008.

Before the California Public Utility Commission, Application of Pacific Gas & Electric Co. for Authorization to Enter Into Long-Term Natural Gas Transportation Arrangements with Ruby Pipeline, Docket No. A.07-12-021, May 2008, June 2008. Before the National Energy Board of Canada, In the Matter of Trans Québec and Maritimes Pipeline Inc., Docket RH-1-2008, December 2007, September 2008, October 2008. Before the Ontario Energy Board, Multi-year Incentive Rate Regulation for Natural Gas Utilities, Docket EB-2007-0606/0615, August 2007, September 2007, November 2007, December 2007. Before the Régie de L’Énergie, Société en Commandite Gaz Métro Cause Tarifaire 2008, Docket No. R-3630-2007, May 2007, August 2007. Before the Ontario Energy Board, Application by Enbridge Gas Distribution Inc. for an Order or Orders Approving or Fixing Just and Reasonable Rates and Other Charges for the Sale, Distribution, Transmission and Storage of Gas Commencing January 1, 2007, Docket No. EB-2006-0034, August 2006, February 2007. Before the California Public Utilities Commission, In the Matter of the Application of San Diego Gas & Electric Company (U 902 G) and Southern California Gas Company (U 904 G) for Authority to Integrate Their Gas Transmission Rates, Establish Firm Access Rights, and Provide Off-System Gas Transportation Services, Docket No. A. 04-12-004, July 2006. Before the Federal Energy Regulatory Commission, Gas Transmission Northwest Corporation, Docket No. RP06-407, June 2006, October 2006 (affidavits). Before the Regulatory Commission of Alaska, in the matter of the Gas Sales Agreement Between ENSTAR Natural Gas Company, A Division of SEMCO Energy Inc. And Marathon Oil Company filed as TA139-4, Docket No. U-06-2, March 2006, May 2006. Before the Ontario Energy Board, Application by Union Gas Limited for an Order or Orders Approving or Fixing Just and Reasonable Rates and Other Charges for the Sale, Distribution, Transmission and Storage of Gas Commencing January 1, 2007, Docket No. EB-2005-0520, January 2006.

Paul R. Carpenter

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Before the New Jersey Board of Public Utilities, in the matter of the Joint Petition of Public Service Electric and Gas Company and Exelon Corporation For Approval of a Change in Control of Public Service Electric and Gas Company, and Related Authorizations, Docket No. EM05020106, November 2005, December 2005, January 2006, March 2006. Before the Pennsylvania Public Utility Commission, Application for Approval of the Merger of Public Service Enterprise Group and Exelon Corporation, Docket No. A-110550F0160, June 2005, August 2005, September 2005. Before the National Energy Board of Canada, in the matter of TransCanada Pipelines LTD., RH-2-2004 Phase II, Cost of Capital, January 2005. Before the California Public Utilities Commission, Order Instituting Investigation into the Gas Market Activities of Southern California Gas Company, San Diego Gas and Electric, Southwest Gas, Pacific Gas and Electric, and Southern California Edison and their Impact on the Gas Price Spike Experience at the California Border from March 2000 through May 2001 on behalf of Southern California Edison, Docket No. I. 02-11-040, December 2003, May 2004, June 2004. Before the Alberta Energy and Utilities Board in the matter of Alberta Energy and Utilities Board Generic Cost of Capital Hearing on behalf of Nova Gas Transmission LTD, Proceeding No. 1271597, November 2003. Before the Federal Energy Regulatory Commission (FERC), California Public Utilities Commission v. El Paso Natural Gas Company, El Paso Merchant Energy-Gas, L.P., and El Paso Merchant Energy Company on behalf of Southern California Edison, Docket No. RP00-241-000, May 2001, February 2002. Before the National Energy Board of Canada, in the matter of TransCanada Pipelines, Ltd. Fair Return Application, March 2002. Before the California Public Utilities Commission, Application of Wild Goose Storage Inc. to Amend its Certificate of Public Convenience and Necessity to Expand and Construct Facilities For Gas Storage Operation, Docket No. A. 01-06-029, November 2001. Before the California Public Utilities Commission, Application of Southern California Gas Company Regarding Year Six (1999-2000) Under Its Experimental Gas Cost Incentive Mechanism and Related Gas Supply Matters, Application No. 00-06-023, (On behalf of Southern California Edison Company), November 2001. Before the U.S. Congress, House of Representatives, Subcommittee on Energy Policy, Natural Resources and Regulatory Affairs, Hearings on California Natural Gas Market, October 2001. Before the New Zealand Commerce Commission, Inquiry into Airfield Activities at Auckland, Wellington and Christchurch International Airports, July 2000, August 2001. Before the National Energy Board of Canada in the matter of the National Energy Board Act and the Regulations made thereunder; and in the matter of an Application by TransCanada PipeLines Limited for orders pursuant to Part I and Part IV of the National Energy Board Act, June 2001.

Paul R. Carpenter

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Before the California Assembly, Subcommittee on Energy Oversight, Hearings into the Causes of the Natural Gas Price Increases During the California Energy Crisis, April 2001. Before the California Public Utilities Commission, CPN Pipeline Co. & CPN Gas Marketing Co. v. Pacific Gas & Electric, Case No. C00-09-021, October 2000. Before the California Public Utilities Commission in the matter of Southern California Gas Co. for Authority to Implement a Rate for Peaking Service, Application No. 00-06-032, (On behalf of Kern River Gas Transmission and Questar Southern Trails Pipeline Co.), September 2000. Before the Federal Energy Regulatory Commission (FERC), California Public Utilities Commission v. El Paso Natural Gas Company, El Paso Merchant Energy-Gas, L.P., and El Paso Merchant Energy Company, Docket No. RP00-241-000, August 2000. Kern River Gas Transmission, Federal Energy Regulatory Commission (FERC) Docket No. RP99-274-003, August 2000. Before the California Public Utilities Commission, Rulemaking on the Commission’s Own Motion to Assess and Revise the Regulatory Structure Governing California’s Natural Gas Industry, California Natural Gas Market Conditions Report, Docket No. R.98-01-011, on behalf of Southern California Edison, July 1998. Before the National Energy Board of Canada, Application of Alliance Pipeline Ltd., Hearing Order GH-3-97, December 1997, April 1998. Before the California Public Utilities Commission, Pacific Enterprises, Enova Corporation, et al. Merger Proceedings, Docket A.96-10-038, on behalf of Southern California Edison, August 1997. In the Superior Court of the State of California for the County of Los Angeles, Pacific Pipeline System Inc. v. City of Los Angeles, on behalf of Pacific Pipeline System Inc., January 1997. Before the U.K. Monopolies and Mergers Commission, British Gas Transportation and Storage Price Control Review, on behalf of Enron Capital and Trade Resources Limited, January 1997. Northern Border Pipeline Company, Federal Energy Regulatory Commission (FERC) Docket No. RP96-45-000, July 1996. Wisconsin Electric Power Co., Northern States Power Co. Merger Proceedings. FERC Docket No. EC 95-16-000, on behalf of Madison Gas & Electric Co., Wisconsin Citizens Utility Board and the Wisconsin Electric Cooperative Association, May 1996. Before the California Public Utilities Commission, Application of PG&E for Amortization of Interstate Transition Cost Surcharge, Application 94-06-044, on behalf of El Paso Natural Gas, December 1995. Tennessee Gas Pipeline Company, FERC Docket No. RP95-112-000, on behalf of JMC Power Projects, September 1995.

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Before the National Energy Board of Canada, Drawdown of Balance of Deferred Income Taxes Proceeding, RH-1-95, on behalf of Foothills Pipe Lines Ltd., September 1995. Pacific Gas Transmission, FERC Docket No. RP94-149-000, on behalf of El Paso Natural Gas, May 1995. Before the California Public Utilities Commission, Application of Pacific Pipeline System, Inc., A.91-10-013, on behalf of PPSI, April 1995. Before the National Energy Board of Canada, Multipipeline Cost of Capital Proceeding, RH-2-94, on behalf of Foothills Pipe Lines Ltd., November 1994. Before the California Public Utilities Commission, Pacific Gas & Electric 1992 Operations Reasonableness Review, Application 93-04-011, on behalf of El Paso Natural Gas, November 1994. Before the National Energy Board of Canada, Foothills Pipe Lines (Alta.) Ltd., Wild Horse Pipeline Project, Order No. GH-4-94, October 1994. Iroquois Gas Transmission System, L.P., FERC Docket No. RP94-72-000, on behalf of Masspower and Selkirk Cogen Partners, September 1994. Tennessee Gas Pipeline Co., FERC Docket No. RP91-203-000, on behalf of JMC Power Projects and New England Power Company, February, May 1994. Before the California Public Utilities Commission, on the Application of Pacific Gas & Electric Company to Establish Interim Rates for the PG&E Expansion Project, July 1993. Before the Florida Public Service Commission, Petition of Florida Power Corporation for Order Authorizing A Return on Equity for Florida Power’s Investment in the SunShine Intrastate and the SunShine Interstate Pipelines, FPSC Docket No. 930281-EI, June 4, 1993. Before the Florida Public Service Commission, Application for Determination of Need for an Intrastate Natural Gas Pipeline by SunShine Pipeline Partners, FPSC Docket No. 920807-GP, April-May 1993. Northwest Pipeline Corp., et. al., FERC Docket No. IN90-1-001, February 1993. City of Long Beach, Calif., vs. Unocal California Pipeline Co., before the California Public Utilities Commission, Case No. 91-12-028, February 1993. Alberta Energy Resources Conservation Board, on Applications of NOVA Corporation of Canada to Construct Facilities, January 1993. Before the California Public Utilities Commission, on the Application of Pacific Gas & Electric Co. to guarantee certain financing arrangements of Pacific Gas Transmission Co. not to exceed $751 million, 1992. Mississippi River Transmission Co., FERC Docket No. RP93-4-000, October 1992, September 1993.

Paul R. Carpenter

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Unocal California Pipeline Co., FERC Docket No. IS92-18-000, August 1992. Before the California Public Utilities Commission, in the Rulemaking into natural gas procurement and system reliability issues, R.88-08-018, June 1992. Alberta Energy Resources Conservation Board, Altamont & PGT Pipeline Projects, Proceeding 911586, March 1992. Before the California Utilities Commission, on the Application of Southern California Gas Company for approval of capital investment in facilities to permit interconnection with the Kern River/Mojave pipeline, A.90-11-035, May 1992. Northern Natural Gas, FERC Docket No. RP92-1-000, October 1991. Florida Gas Transmission, FERC Docket No. RP91-1-187-000 and CP91-2448-000, July 1991. Tarpon Transmission, FERC Docket No. RP84-82-004, January 1991. Before the California Public Utilities Commission, on the Application of Pacific Gas & Electric Co. to Expand its Natural Gas Pipeline System, A.89-04-033, May 1990 and October 1991. CNG Transmission, FERC Docket No. RP88-211, March 1990. Panhandle Eastern Pipeline, FERC Docket No. RP88-262, March 1990. Mississippi River Transmission, FERC Docket No. RP89-249, October 1989, September 1990. Tennessee Gas Pipeline, FERC Docket No. CP89-470, June 1989. Empire State Pipeline, Case No. 88-T-132 before the New York Public Service Commission, May 1989. Before the U.S. Congress, House of Representatives, Committee on Energy and Commerce, Subcommittee on Energy and Power, Hearings on “Bypass” Legislation, May 1988. Tennessee Gas Pipeline, FERC Docket No. RP86-119, 1986-87. Mojave Pipeline Co., FERC Docket No. CP85-437, 1987-88. Consolidated Gas Transmission Corp., FERC Docket No. RP88-10, 1988. Panhandle Eastern, FERC Docket No. RP85-194, 1985. On behalf of the Natural Gas Supply Association in FERC Rulemaking Docket No. RM85-1, 1985-86. On behalf of the Panhandle Eastern Pipeline Co. in FERC Rulemaking Docket No. RM85-1, 1985.

ATTACHMENT 2

RESUME OF DR. TOBY BROWN

TOBY BROWN Principal

Sydney +61.2.8123.0999 Toby.Brown@brattle.com

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Dr. Toby Brown heads Brattle’s Sydney office. He specializes in energy markets and infrastructure regulation, and has consulted for oil and gas producers, pipelines, utilities and regulators in Australia, New Zealand, Europe, the United States and Canada. He provides litigation support in a wide range of commercial disputes, including damages estimation, valuation and pricing.

Dr. Brown’s consulting experience in Australia includes gas pricing, wholesale market design and advising on best practices for infrastructure access based on experience in different jurisdictions worldwide. He has advised on natural gas pricing in regulatory proceedings, commercial arbitrations and transfer pricing contexts. He has particular expertise in incentive-based regulation of energy networks.

Prior to joining Brattle, Dr. Brown worked at the UK energy regulator, Ofgem. He holds a D.Phil. in Chemistry from the University of Oxford.

EDUCATION

• D.Phil. in Chemistry, University of Oxford, 1999 • B.A. (Hons.) in Chemistry, University of Oxford, 1995

PROFESSIONAL WORK EXPERIENCE

• Principal, The Brattle Group, 2015–present • Associate then Senior Associate, The Brattle Group, 2006–2015 • Strategy then European teams, Ofgem, 2002–2006 • Consultant then Senior Consultant, Oxera, 1999–2002

AREAS OF EXPERTISE

• Natural gas and electricity markets • Network regulation • Infrastructure access

EXPERIENCE: Energy Regulation and Ratemaking

• On behalf of the HECO companies, Brattle provided an expert report in a proceeding to refine the regulatory framework in Hawai‘i. Our report examined financial incentives to control costs and the potential for bias between capital and operating expenditures, as well as regulatory responses in a number of jurisdictions worldwide.

• Brattle was retained by a large industrial customer to provide advice in connection with a dispute over the cost of using the high-voltage electricity transmission network supplying electricity to the facility. Dr. Brown led the Brattle team which analysed the implications of the transmission charges for the commercial viability of the facility, and authored an expert report submitted in the dispute.

• The Australian Energy Market Commission has commissioned Brattle to undertake many international reviews of various aspects of energy market and regulatory framework

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design. In these studies Brattle selects relevant overseas jurisdictions, collects information based on desk research and sometimes interviews with stakeholders. We synthesize the results to identify good practice and suggest lessons learned that are relevant for the AEMC’s role. Dr. Brown has participated in studies that focused on: integrating demand response into wholesale markets; the structure of charges for use of the distribution network, and in particular the recovery of the difference between incremental and total cost; transmission planning; interconnector charging; the use of Total Factor Productivity analysis in setting allowed revenues; methods used by regulators to assess utility capex and opex forecasts; regulators’ ability to collect and publish information held by regulated utilities; and standards for reliability and service quality of distribution networks. These studies were published by the AEMC and are available on the Brattle website.

• APA Group, the owner of several high-pressure gas transmission pipelines, asked Brattle to estimate the economic benefits and costs associated with integrating gas pipelines into a “east coast grid”. Dr. Brown co-authored the resulting report which estimated efficiency savings from integrated operations and valued new services provided by the integrated grid.

• Brattle was retained by a group of electric and gas distribution utilities in Alberta to provide expert evidence in a proceeding on the design of performance-based ratemaking in Alberta. Dr. Brown co-authored expert reports covering rebasing, funding for needed capital expenditures, and the “X” or “productivity factor” in the performance-based ratemaking formula. Dr. Brown provided oral testimony before the Alberta Utilities Commission.

• In connection with the sale of a large North American electric transmission entity, Dr. Brown was part of a Brattle team providing regulatory due diligence to a group of investors participating in the sale process. Dr. Brown analyzed the regulatory environment facing the entity and advised on the process for setting rates and for recovering future investment. Dr. Brown also helped the investors’ financial advisers to develop an effective valuation model.

• The Public Utilities Office in Western Australia asked Brattle to advise on methods for mitigating the exercise of market power in the Wholesale Electricity Market (WEM) of Western Australia. Dr. Brown was part of the Brattle team that reviewed relevant experience in international jurisdictions in order to advise the PUO.

• A Canadian utility asked Brattle to review certain aspects of the ratemaking process in U.S. jurisdictions, concentrating on how stakeholders participate in utility rate cases and mechanisms used by regulatory commissions to improve the efficiency of the ratemaking process. Dr. Brown led the Brattle team reviewing experience in nine U.S. jurisdictions and interviewing regulatory commission staff.

• The Hawaiian Electric Companies retained Brattle to provide expert advice on incentive rate-making and other aspects of the utility’s sales decoupling mechanism. Dr. Brown provided an expert report that was submitted to the public utilities commission of Hawai‘i and subsequently provided oral testimony.

• A North American electric utility asked Brattle to conduct a survey of utility strategies for managing key accounts and for addressing self-generation at large customer sites. Dr.

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Brown was part of the Brattle team that interviewed utilities and customers across North America and presented findings to senior management at the client. Installation of combined heat and power plants and adopting well-structured standby and other industrial rates were key issues in this study.

• A gas and electric retailer in Australia retained Brattle to forecast wholesale gas prices in south-east Australia and to provide an opinion on the wholesale price of gas that should be used to determine the maximum retail price. Dr. Brown co-authored an expert report that was submitted to the relevant regulatory body (the Independent Pricing and Regulatory Tribunal of New South Wales).

• In connection with the potential acquisition of a regulated electric utility in North America by a private equity group, Dr. Brown was part of a Brattle team advising the potential purchaser on the regulation of the target utility and the regulatory consequences of specific issues raised by an acquisition.

• The Australian Energy Market Operator asked Brattle to prepare a report on pipeline capacity trading, in connection with its initiative to develop a trading hub at Wallumbilla. Dr. Brown co-authored a report reviewing experience in Europe and North America.

• A gas and electric utility in North America retained Brattle to advise on the value of increased reliability of its gas and electric distribution systems in connection with a proposal to invest significant sums in improving system resilience. Dr. Brown was part of the team responsible for developing estimates of the cost of supply interruptions.

• A utility in Alberta engaged Brattle to provide consulting support as the utility developed a proposal for an incentive regulation scheme to replace its cost-of-service model. Dr. Brown reviewed several examples of incentive regulation schemes in place for other utilities, and advised on plan development.

• A European energy regulator asked Brattle to assist with the design of a regulatory framework for the newly introduced activity of building and operating offshore transmission cables (to connect off-shore wind generators to the transmission grid). Dr. Brown was responsible for recommending incentive arrangements that would encourage the cable operator to ensure that the cable would be reliable and delivered on time. The recommendations were developed by reviewing limited experience with such incentives in other jurisdictions and industries, and through illustrative examples of the financial impact of incentives on a hypothetical cable operator. The key issue was designing a sufficiently powerful incentive that would not threaten to bankrupt the operator.

• During negotiations over the “third package” of legislation aimed at liberalizing the EU’s gas and electricity markets, Brattle was commissioned to critique the European Commission’s “Impact Assessment” for its proposals on restructuring electricity transmission systems. Dr. Brown contributed an analysis of system operator/transmission owner coordination costs under an independent system operator model in Great Britain, and of the extent to which these arrangements have facilitated network investment.

• Brattle provided expert testimony for a gas distribution company rate case in Quebec. Dr. Brown analyzed the incentive mechanism in the company’s rate formula and helped to draft an expert report on the company’s overall business risk.

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• A U.S. utility hired Brattle to review prior rate case decisions and provide an opinion on the level of expenditure corresponding to the rates that had been authorized in prior rate case proceedings. Brattle constructed a cost-of-service model to impute rate base growth and the level of operating expenses and capital expenditures consistent with the authorized revenue requirement in each year.

• A North American energy utility asked Brattle to investigate whether shifting from a traditional to a decoupled rate structure should be associated with a reduction in the utility’s cost of capital. Members of Brattle reviewed the prevalence of decoupled rates amongst U.S. utilities, and conducted a quantitative analysis of the statistical relationship between decoupled rates and the cost of capital.

• Brattle was engaged by the Australian Pipeline Industry Association and the Dampier to Bunbury pipeline to prepare reports on how regulators in various jurisdictions use different models and market information to set the cost of equity and debt for regulated utilities, and to make recommendations for the development of guidelines by Australian regulators under the National Gas and Electricity Rules.

• Brattle was engaged to advise on business risk, capital structure, and the cost of equity for a natural gas pipeline in ratemaking proceedings before the Federal Energy Regulatory Commission. Dr. Brown carried out the necessary quantitative analysis and assisted with drafting testimony.

• Brattle advised a North American oil pipeline in relation to business risk and the cost of capital. Dr. Brown carried out a comparative analysis of North American pipelines to show how the riskiness of the client’s pipeline compared to the industry as a whole.

• A North American oil pipeline owner engaged Brattle to analyze the implications of certain proposed cost-sharing arrangements on competition and operating efficiency, in the context of a Federal Energy Regulatory Commission proceeding. Dr. Brown assisted with the analysis and drafting of testimony.

• The Australian Energy Market Commission engaged Brattle to investigate the use of Total Factor Productivity (TFP) analysis by network regulators in setting price controls. Dr. Brown wrote a factual review of TFP analyses used by energy regulators in the UK, the Netherlands, and New Zealand. The Brattle report made observations on the use of TFP in these jurisdictions that would be relevant to a regulator considering whether to make use of a TFP approach. Subsequently, the client asked us to write a further report comparing the incentive properties of TFP-based and building-block-based price controls.

• Following on from two earlier projects on Total Factor Productivity analysis, Brattle was hired by the Australian Energy Market Commission to write a short paper describing the range of ideas that have been raised in recent thinking about the future of the building-blocks framework for energy network regulation, both in Australia and elsewhere. Brattle was also asked to review a proposed model for quantifying different price control options.

• Brattle was asked to advise on the rules governing access to customer information in energy retail markets throughout various jurisdictions. Dr. Brown reviewed in detail the relevant rules in the UK, and also presented detailed evidence on how competition

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developed in the UK retail markets following liberalization and the lifting of price controls.

• In connection with a regulatory proceeding relating to the use of benchmarking, Dr. Brown reviewed a published critique of the UK energy regulator’s methodology that it had applied to electricity distribution companies.

• In connection with a pipeline rate case, Dr. Brown reviewed cost of capital decisions taken by regulators in jurisdictions outside the U.S. and summarized the key input parameters.

EXPERIENCE: Liquefied Natural Gas Pricing

• Advised on pricing of LNG in connection with an arbitration over re-determining the price in a long-term LNG supply contract.

• Advised on pricing in LNG sales agreements and valuation in connection with a corporate restructuring.

• Assessed the charging arrangements for an LNG liquefaction plant in connection with an analysis of resource taxes.

• Analyzed arm’s-length pricing for sales of LNG in the Pacific basin for transfer pricing purposes.

EXPERIENCE: Natural Gas Price Arbitrations and Energy Litigation

• Advised on the market price of natural gas in eastern Australia in connection with a dispute over a price renegotiation in a long-term supply contract.

• Brattle was retained in connection with a price dispute in a long-term gas supply agreement in New Zealand. Dr. Brown led the Brattle team analyzing the wholesale market price for gas in New Zealand, the value of flexibility and other key non-price terms. Dr. Brown also analyzed the economics of gas processing and appropriate terms for access to a shared gas processing facility.

• On behalf of a company involved in an arbitration in Australia, Brattle was asked to advise on the price in a long-term gas supply agreement. Dr. Brown drafted an expert report on the relevant economic principles.

• Brattle was asked to provide expert testimony in an arbitration in Australia to determine the price in a long-term gas supply agreement following a price re-opener. Dr. Brown assisted with drafting reports analyzing the prices in comparable long-term contracts in order to recommend a revised contract price.

• Brattle was retained to provide expert testimony assessing damage in connection with the bankruptcy of a midstream oil company. Dr. Brown led Brattle’s analysis of damage associated with oil and gas derivatives trading.

• Brattle was retained to provide advice on good practice in regulating gas distribution networks in connection with an investor-state dispute. Dr. Brown provided advice on

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how various elements of the regulatory framework compared with how gas distribution networks are regulated in the UK, Australia, the US and Canada.

• During a breach of contract dispute in the High Court in London, Brattle was engaged to provide expert testimony on the magnitude of damages flowing from a problematic IT implementation. Dr. Brown supported the Brattle expert with quantitative analysis of market share changes, and assisted with drafting testimony.

• Brattle was asked to provide expert testimony in an arbitration in Australia to determine the price in a long-term gas supply agreement following a price re-opener. Dr. Brown assisted with drafting a report on the economic theory that explained the existence and nature of long-term gas supply agreements, as well as a report critiquing the statistical validity of evidence submitted by another expert in the arbitration.

EXPERIENCE: Other litigation and regulatory matters

• Brattle was retained to advise a large rail logistics operator in connection with a dispute over the price of using the rail network. Dr. Brown led the team that produced expert reports on economic principles guiding the setting of access prices, and on modeling the costs of providing access.

• Brattle was retained to support a large water user participating in its local water utility rate case. Dr. Brown analyzed the utility’s cost of service model, cost allocation, and proposed rate structure.

• Dr. Brown was part of the Brattle team that supported Nobel Laureate Professor Joseph Stiglitz in preparing an amicus curiae brief submitted to the Supreme Court of the United States in connection with litigation arising from Argentina’s 2001 sovereign debt default.

• Dr. Brown supported an industry expert opining on the commercial strategies of generic pharmaceutical firms. Brattle used sales data to show that a variety of strategies could result in successful product launch.

• Brattle carried out a detailed investigation of retail electricity prices and supply costs, including an analysis of the number of customers that might save money by switching to a new tariff. Dr. Brown extracted the relevant consumption information for each of several million customers from the client’s meter reading database, and used this to estimate bills for each customer under different tariff assumptions.

• Following a proposed merger between two large vertically-integrated energy firms, The Brattle Group was commissioned by a third party to analyze the impacts of the merger on competition. Dr. Brown carried out a detailed analysis of bids and offers in the day ahead electricity market to identify which generators were setting prices most often, and hence to assess whether the merger might lead to competition concerns by putting a large share of the price-setting plant in common ownership.

• On behalf of a client, Brattle investigated claims that certain of its subsidiaries had caused their customers to overpay by participating in an illegal cartel. Dr. Brown assisted the client in collecting information on sales and analyzing the extent to which the cartel had an impact on customers, processing several million lines of operations data.

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• The Brattle Group was asked to prepare electricity price forecasts for a number of European countries using our proprietary electricity market model. Dr. Brown’s role was to generate EU Emissions Trading Scheme allowance price forecasts that would be consistent with our fuel price assumptions. Brattle generated carbon price forecasts by analyzing the impact of carbon prices on the marginal costs of competing gas- and coal-fired power stations.

• A European client commissioned us to analyze the framework of EU legislation and policy targets that addresses CO2 emissions, and to write a report about its implications for investment in carbon capture and sequestration. Dr. Brown developed an analytical framework that links the carbon price to the marginal costs of competing gas- and coal-fired power stations. He also analyzed the possible implications for EU emissions targets of various scenarios of power station investment, as well as the risks and uncertainties in the carbon price that are derived from the EU’s policies on renewable energy and energy efficiency.

• The Brattle Group was engaged to support a regulated firm during price control proceedings by critiquing certain aspects of the regulator’s cost of capital proposals. Dr. Brown assisted with a review of the latest evidence on the equity risk premium from historic stock and bond returns. He also measured the company’s equity and debt betas, and discovered mistakes in the regulator’s analysis.

• An energy utility in Northwestern Europe asked us to advise on its upstream gas strategy. Dr. Brown reviewed the lessons that might be learned from the experience of another European utility that had faced similar challenges. He went on to develop detailed recommendations about contracting strategies, and in particular how to index the contract price.

• The UK telecommunications regulator, Ofcom, commissioned Brattle to update some previous analyses of BT’s equity beta. Dr. Brown carried out the necessary regression analysis, examined the influence of “unusual” days on the estimates, and reviewed possible explanations for observed changes in the estimates over time.

• A power station developer commissioned us to advise on investment strategies by preparing forecasts of future electricity prices in Northwest Europe. Dr. Brown used Brattle’s in-house electricity market model to generate electricity price scenarios. He also analyzed EU greenhouse gas emissions targets to generate relevant carbon price forecasts.

• When Gaz de France and Suez proposed to merge, The Brattle Group analyzed the possible impacts of the merger on competition in the effected gas and electricity markets, in support of submissions to the European competition authorities. Dr. Brown carried out a detailed analysis of the prospects for competition in the French and Belgian wholesale gas markets.

• Dr. Brown was part of a team advising the Hong Kong government on the design of centralized cooling water provision (for building air-conditioning) to the proposed re-development of the Kowloon airport site. His role was to build an economic model of the cooling franchise, and to develop various options for the form of the franchise and for regulating the price of delivered cooling water.

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PUBLICATIONS AND PRESENTATIONS

These publications are available at http://brattle.com/experts/toby-brown.

Incentive Mechanisms in Regulation of Electricity Distribution: Innovation and Evolving Business Models, with Neil Lessem and Bill Zarakas, prepared for the Electricity Networks Association New Zealand, October 2018.

International Experiences in Retail Electricity Markets: Consumer Issues, with Agustin J. Ros, Serena Hesmondhalgh, James D. Reitzes, and Neil Lessem, Prepared for The Australian Competition and Consumer Commission, June 2018.

New Network Tariff Designs, with Neil Lessem, Presented at the Center for Research into Regulated Industries (CRRI) Western Conference, June 2018.

Electricity Distribution Network Tariffs: Principles and Analysis of Options, with Ahmad Faruqui, and Neil Lessem, Prepared for The Victorian Distribution Networks, April 2018.

Performance Based Regulation Plans: Goals, Incentives and Alignment, with William Zarakas, Léa Grausz, Heidi Bishop, and Henna Trewn, Prepared for DTE Energy, December 2017.

Near-Term Reliability Auctions in the NEM: Lessons from International Jurisdictions, with Kathleen Spees, Samuel A. Newell, David Luke Oates, Neil Lessem, Daniel Jang, and John Imon Pedtke, Prepared for the Australian Energy Market Operator, August 2017.

Lifting the Lid on Price Revision and Re-Opener Clauses: LNG Pricing and Price Review Triggers, with Dan Harris, and Léa Grausz, Presented at C5 Group’s Long Term Gas Supply Contracts, Singapore, February 2017.

Market Power Mitigation Mechanisms for the Wholesale Electricity Market in Western Australia, with Samuel Newell, Walter Graf, James Reitzes, Henna Trewn and Kai Van Horn, Prepared for the Government of Western Australia Department of Finance, Public Utilities Office, September 2016.

Benefits and Costs of Integration in Transmission/Transportation Networks: An Application to Eastern Australia Gas Markets, with Paul Carpenter, James Reitzes, Jeremy Verlinda and Neil Lessem, prepared for the APA Group, August 2016.

The Tariff Transition: Considerations for Domestic Distribution Tariff Redesign in Great Britain, with Ryan Hledik, Ahmad Faruqui, Jürgen Weiss, and Nicole Irwin, Prepared for Citizens Advice, April 2016.

“Efficient Tariff Structures for Distribution Network Services”, with Ahmad Faruqui and Léa Grausz, in Economic Analysis and Policy, December 2015, pp. 139–149.

International Review of Demand Response Mechanisms, with Samuel Newell, David Luke Oates and Kathleen Spees, prepared for the Australian Energy Market Commission, October 2015.

Structure of Electricity Distribution Network Tariffs: Recovery of Residual Costs, with Ahmad Faruqui, report prepared for the Australian Energy Market Commission, August 2014.

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Incentive-based ratemaking: Recommendations to the Hawaiian Electric Companies, with Michael J. Vilbert and Joseph B. Wharton, report prepared for the Hawaiian Electric Companies and submitted to the Public Utilities Commission of Hawai‘i in Docket No. 2013–0141.

International Experience In Pipeline Capacity Trading, with Dan Harris and Alessandro Massolo, report prepared for the Australian Energy Market Operator, August 2013.

Wholesale Gas Price for AGL’s VPA Proposal for 2014–16 (public version), with Paul Carpenter, prepared for AGL and submitted to the Independent Pricing and Regulatory Tribunal of New South Wales, February 2014.

Estimating the Cost of Equity for Regulated Companies, with Bente Villadsen, Paul R. Carpenter, Michael J. Vilbert, and Pavitra Kumar, report prepared for the Australian Pipeline Industry Association, February 17, 2013.

Estimating the Cost of Debt, with Bente Villadsen, a report for the Dampier-Bunbury Pipeline, March 4, 2013.

Framework for Assessing Capex and Opex Forecasts as Part of a “Building Blocks” Approach to Revenue/Price Determinations, with Pinar Bagci, Paul R. Carpenter, and Philip Q Hanser, report prepared for the Australian Energy Market Commission, June 2012.

Approaches to Setting Electric Distribution Reliability Standards and Outcomes, with Serena Hesmondhalgh and William P. Zarakas, a report to the Australian Energy Market Commission, January 2012.

Does the Market Risk Premium Change Over Time?, discussion at the Australian Competition and Consumer Commission Regulatory Conference 2011, July 28, 2011.

Is “Cost-of-Service Plus Incentives” the Best We Can Do?, with William B. Tye, paper presented to the Australian Competition and Consumer Commission Regulatory Conference 2011, July 28, 2011.

Incentive Regulation: Lessons from other Jurisdictions, with Paul R. Carpenter and Johannes P. Pfeifenberger, presented at the Alberta Utilities Commission Performance Based Ratemaking workshop, the Van Horne Institute, May 26-27, 2010.

Price Re-Openers in Natural Gas Supply Contracts: Avoiding Costly Mistakes in Arbitration, with Paul Carpenter, Brattle Newsletter 2010 No. 1 (Energy).

Is the smart grid going to fare better in competitive markets?, with Ahmad Faruqui, presented at the Gulf Coast Power Association Spring Conference, Houston, TX, April 14, 2010.

Options for Reforming the Building-Blocks Framework, with Paul Carpenter, a report to the Australian Energy Market Commission, December 16, 2009.

Review of Incentive Power and Regulatory Options in Victoria, with Paul Carpenter, a report to the Australian Energy Market Commission, December 2009.

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Incentives under Total Factor Productivity Based and Building-Blocks Type Price Controls, a report to the Australian Energy Market Commission, with Boaz Moselle, June 2009.

EU Climate and Energy Policy to 2030 and the Implications for Carbon Capture and Storage, a report for Alstom Power Systems, with Serena Hesmondhalgh and David Robinson, March 2009.

Use of Total Factor Productivity Analyses in Network Regulation: Case Studies of Regulatory Practice, a report to the Australian Energy Market Commission, with Boaz Moselle, October 2008.

Critique of the Industry Codes Governance Arrangements, a report to Ofgem, with Serena Hesmondhalgh, Boaz Moselle, and Simmons & Simmons, June 2008.

Models of Inter-regional Transmission Charging, a report to the Australian Energy Market Commission, with Boaz Moselle, March 2008.

International Review of Transmission Planning, presentation at Transmission and Distribution 2008, Amsterdam, March 12, 2008.

International Review of Transmission Planning Arrangements, a report to the Australian Energy Market Commission, with Boaz Moselle, October 2007.

TESTIMONY

Before the Public Utilities Commission of Hawai‘i, Improving the PBR Framework in Hawai‘i, Addressing the risk of “Capex Bias”, docket number 2018-0088, January 2019.

In the Supreme Court of Victoria, Affidavit in the matter between Lochard Energy (Iona Operations Holding) Pty Ltd, and Energy Australia Investments Pty Ltd, September 2018.

Before the Alberta Utilities Commission, AUC-initiated next generation performance-based regulation generic proceeding, Proceeding ID No. 20414, March 2016.

Before the Alberta Utilities Commission, Enmax Power Corp., Proceeding ID No. 21149, December 2015.

Before the Public Utilities Commission of Hawai‘i, Incentive-based ratemaking: Recommendations to the Hawaiian Electric Companies, Docket 2013–0141, May 2014 and September 2014.

Submitted to the Independent Pricing and Regulatory Tribunal of New South Wales, Wholesale Gas Price for AGL’s VPA Proposal for 2014–16, February 2014.

ATTACHMENT 3

LETTER OF INSTRUCTION