Discussion Paper – Transmission Cost Accountability Date:

Discussion Paper – Transmission Cost
Accountability
Date:
November 14, 2011
Prepared by: Transmission
Prepared for: Market Participants and Interested Stakeholders
Version:
1.0
Table of Contents
1
Executive Summary ................................................................................................................. 1
2
Introduction .............................................................................................................................. 1
3
Purpose..................................................................................................................................... 2
4
Scope ........................................................................................................................................ 2
5
Background .............................................................................................................................. 2
6
Current Roles and Accountabilities ....................................................................................... 4
7
8
9
6.1
AESO Role..................................................................................................................................... 5
6.2
TFO Role ....................................................................................................................................... 7
6.3
AUC Role ....................................................................................................................................... 8
6.4
MSA Role....................................................................................................................................... 9
Other Jurisdictions .................................................................................................................. 9
7.1
BC Hydro ....................................................................................................................................... 9
7.2
Hydro One...................................................................................................................................... 9
Challenges/Issues with Transmission Capital Costs ......................................................... 10
8.1
Accountability for cost estimates for transmission projects ......................................................... 10
8.2
Uncertainty associated with cost estimating ................................................................................ 10
8.3
Level of detail and transparency of transmission cost estimates ................................................ 11
8.4
Competitive procurement of materials and labour per ISO rules Section 9.1.5 .......................... 12
Stakeholder Consultation and Next Steps........................................................................... 13
APPENDIX A Legislated Rights and Obligations – Transmission Project Implementation. 14
APPENDIX B System Projects – Process Overview-Draft ....................................................... 19
APPENDIX C Estimating Guidelines and Standards ................................................................ 20
APPENDIX D Metals Price Volatility Illustration........................................................................ 22
APPENDIX E Brattle Group Report ............................................................................................ 23
APPENDIX F Rules for Transmission Facility Projects: Discussion Paper............................ 35
1 Executive Summary
The AESO is initiating discussion and consultation, in part as a response to a Transmission Facility Cost
Monitoring Committee recommendation, with respect to the current framework for cost accountability for
transmission development in Alberta. The purpose of this discussion paper is to stimulate industry
discussion with respect to the current cost accountability framework associated with the execution of
transmission projects and to solicit stakeholder feedback to assist in the development of
recommendations for change. The initiation of this discussion is in the interest of continuous improvement
to the transmission facility project implementation process.
The AESO has identified several areas for discussion on the current cost accountability framework in a
number of areas, including:
a) Accountability for cost estimates and cost control for transmission projects,
b) Uncertainty associated with cost estimating,
c) Apparent level of detail and transparency for transmission cost estimates, and
d) Competitive procurement of materials and labour pursuant to ISO rules Section 9.1.5.
The AESO shares stakeholder concerns with respect to the cost estimate accuracy for large transmission
projects (i.e. greater than $100 million) prior to these projects receiving regulatory approvals. Secondly,
concerns have been raised with respect to the control of actual project costs during execution, including
the process for reviewing these costs during and following project completion.
This discussion paper provides stakeholders with some historical context on the current cost
accountability framework and a description of the roles of the Alberta Electric System Operator (AESO),
Transmission Facility Owners (TFOs), Alberta Utilities Commission (AUC), and the Market Surveillance
Administrator (MSA), in accordance with legislative obligations, with respect to transmission project
development.
For comparative purposes, the AESO has also provided information on transmission project cost
accountability in other jurisdictions, including both Canadian utilities and U.S. Independent System
Operators (ISO) and Regional Transmission Organizations (RTO).
2 Introduction
The Transmission Facility Cost Monitoring Committee 1 (the “TFCMC”) has recommended to the Minister
of Energy (the “Minister”) that the AESO initiate a review process on the current framework for cost
accountability for transmission development. This recommendation is included in the June 2011 TFCMC
report 2 to the Minister and repeated here:
TFCMC Report Recommendation 6
“That the AESO initiate a review process on the current framework for cost accountability. This
process should discuss the challenges with implementing transmission project requirements
required by legislation. The TFCMC believes that the review would lead to other recommendations
for cost monitoring/cost management improvement, such as the creation of post-project variance
reports.”
The TFCMC is tasked with, among other things, the review of records which relate to the cost, scope,
schedule and variance of Alberta transmission facility projects that are forecast to cost in excess of $100
million. The AESO has prepared this discussion paper, in part as a response to the TFCMC report
recommendation and to also facilitate stakeholder dialogue regarding transmission capital project costs.
As an initial step, the AESO has presented information in this discussion paper based on both the
1
Refer to http://www.energy.alberta.ca/Electricity/pdfs/MO64TransmissionTFCMCommittee.pdf for the Ministerial Order 64/2010 and the terms of reference for the TFCMC.
A copy of the report titled “Review of the Cost Status of Major Transmission Projects in Alberta” is available at the following link
http://www.energy.alberta.ca/Electricity/pdfs/TFCMCJune2011.pdf .
2
Page 1
AESO’s perspective and comments received from stakeholders with respect to the challenges/issues
associated with implementing transmission project requirements required by legislation. This paper will be
followed by stakeholder consultation to solicit broader industry perspectives on the question of
transmission cost accountability. The AESO has identified some specific questions in the section titled
“Challenges/Issues with Transmission Costs” that the AESO invites stakeholders to respond to as part of
stakeholders overall commentary on the discussion paper.
3 Purpose
The purpose of this discussion paper is to identify the challenges/issues the industry faces with respect to
the execution of transmission projects within the current cost accountability framework and to solicit
stakeholder feedback to assist in the development of recommendations for improvement. The AESO has
identified several challenges/issues with the current cost accountability framework and seeks stakeholder
comments on the validity of these challenges/issues.
4 Scope
The consultation with stakeholders will follow the AESO’s standard consultation process. This discussion
will exclude reference to the proposed competitively procured Critical Transmission Infrastructure (CTI)
project identified in the Schedule of the Electric Utilities Act (EUA) as two single circuit 500 kV AC
transmission lines from the Edmonton region to the Fort McMurray region. The discussion is intended to
identify the challenges/issues, as related to cost accountability and control, associated with transmission
facility development that falls within the current AESO direct assign rules 3 and involves implementation by
the current regulated Transmission Facility Owners (TFO) in the Province.
The following aspects of cost review/accountability with respect to transmission projects are considered in
the context of the various challenges/issues identified in this discussion paper:
•
•
•
•
Processes that result in a project being selected and designed to meet both short term and long term
needs at a reasonable cost and are in the public interest (i.e. primarily design evaluation criteria at the
Need Identification Document (NID) stage);
Processes that result in a project being implemented at the lowest cost (e.g., TFO project execution,
including procurement practices);
The accuracy of cost estimates used to make project decisions ( i.e., both at the NID and Facility
Application (FA) stages); and
The management of scope changes to projects that affect cost estimates (e.g., Changes in
conditions, scope and schedule)
5 Background
Historically, the transmission system was owned and operated by vertically-integrated electric utilities
which delivered generation, transmission, and distribution services to residential, commercial, and
industrial customers throughout Alberta. There were no specific legislative provisions granting rights to
build transmission facilities in specific geographic areas, although the practice was for each verticallyintegrated utility to build the transmission facilities required in the service area in which it provided
distribution service. The generation and transmission costs of the integrated utilities were averaged to
ensure they were equalized across the province (except for Medicine Hat which operated as an
independent system connected to the Alberta transmission system).
3
ISO Rule 9.1 governs the current assignment of transmission facilities consistent with legislative requirements. Refer to
http://www.aeso.ca/downloads/Section_9_Transmission_-_ISO_Rules_-_July_1_2011.pdf for the complete details of Rule 9.1 – Transmission Facility Projects.
Page 2
Electric industry restructuring began with the EUA, initially proclaimed in force on May 17, 1995. Under
the EUA the vertically-integrated utilities were required to functionally separate their generation,
transmission, and distribution activities effective January 1, 1996. The EUA also required open access to
transmission to ensure non-discriminatory access to the power pool by all market participants.
The EUA left the ownership of the existing transmission system unchanged, but established an
independent transmission administrator to run it and ensure adequate system support and open access.
The EUA also established the Electric Transmission Council, composed of electric industry stakeholders,
to advise the transmission administrator on issues related to the grid, such as planning, operations, and
tariffs.
On June 1, 2003, the AESO was officially formed combining the previous Transmission Administrator of
Alberta and Power Pool of Alberta functions.
On December 22, 2003, Alberta Energy issued a Transmission Development Policy Paper which
concluded, in part, that transmission is characterized by large economies of scale with efficiencies when
an incumbent transmission facility owner provides operations and maintenance services to new facilities
in the geographic area they currently serve. “A ‘patchwork quilt’ of ownership does not have the same
level of coordination or economy of scale and so it would not operate as reliably and efficiently.
Contiguous ownership of lines, substation facilities and the associated operating infrastructure therefore
provides the greatest assurance of reliable and safe operation of the transmission system for customers
(and employees) and is therefore in the public interest.” 4
This policy was the foundation for the Transmission Regulation (T-Reg), initially proclaimed in force on
August 12, 2004. The T-Reg required the AESO to assign new transmission facilities to existing
transmission facility owners based on their existing geographic areas. It also required the AESO to make
rules respecting cost estimates, reporting, and competitive tendering of construction work by transmission
facility owners.
In November 2004, the AESO formed an industry work group to assist the AESO in developing ISO rules
that would comply with the legislative requirements in effect at that time. On June 1, 2005, the AESO
issued a Rules for Transmission Facility Projects: Discussion Paper (see Appendix F) seeking broader
stakeholder input prior to finalizing the ISO rules in August of 2005. This effort was acknowledged by the
Alberta Energy and Utilities Board (EUB) in subsequent decisions. 5
The 2004 T-Reg contained no specific wording with respect to cost reasonableness review requirements.
Consequently, the AESO articulated its role based on EUB requests, historical evolution and
unchallenged statements with respect to the TFO Tariff/Deferral Account processes. The following is
quoted from the EUB Decision 2005-019 with respect to the AltaLink 2004-2007 General Tariff
Application (GTA) dated March 12, 2005:
“In the AltaLink GTA decision, the Board commented on the proactive aspect of the AESO’s role
as follows: “...it is nonetheless evident to the Board that the AESO performs an essential
oversight and decision making role in the project cost control process that could not be performed
by any other party or parties.”
The Board commented further on the AESO’s discretion to authorize project changes:
“... the AESO should do so [authorize changes] with a view to fiscal management which might be
considered appropriate if the money being spent were its own.” It should be noted that despite the
4
Transmission Development Policy Paper, page 4.
Specifically, in EUB Decision 2007-012 (February 16, 2007), with respect to AltaLink’s 2007 and 2008 Transmission Facility
Owner Tariff, the EUB noted: “The Board notes that, as anticipated in Decision 2005-019, the AESO’s obligation under section 13(1)
of the Transmission Regulation to develop comprehensive direct assign project cost control rules was fulfilled through the issuance
of Section 9 of the ISO rules on August 10, 2005.”
5
Page 3
Board’s support for the proactive cost control role of the AESO, the Board has made it clear that
the onus to demonstrate prudence for the final project costs rests with the TFO.”
In November 2005, the Alberta Department of Energy (DOE) released its paper Roles and Mandates
Refinements for Alberta Electricity Industry Implementing Agencies. The paper contained no further
instruction regarding the AESO’s role in cost reasonableness reviews. However, the paper emphasized
that the EUB continued to have responsibility for assessing the prudency of those costs incurred by the
TFO and to subsequently approve those costs the TFO was seeking to recover under its tariff.
The next version of the T-Reg, released in 2007, and which remains in force today, makes it clear that
“…the Commission must not require the ISO to make any statement with respect to a TFO’s or other
person’s prudence in managing a transmission facility project.” 6 The responsibility for assessing TFO cost
prudence rests with the AUC, formerly the EUB.
The current T-Reg remains relatively unchanged from the 2004 T-Reg with respect to the development of
ISO rules covering the assignment of transmission projects, cost estimate consistency and procurement
of facilities. The ISO rules developed in 2005 have remained relatively unchanged and continue to apply
to the implementation of transmission capital projects.
The DOE introduced further amendments to the T-Reg in 2010, 7 obligating the AESO and TFOs to
provide copies of certain cost estimate records to the TFCMC established by the Minister pursuant to
Section 7 of the Government Organization Act. The AESO provides records to the TFCMC that include
the TFO monthly reports pursuant to ISO rules Section 9.1.3.
In September 2011, the AESO released a discussion paper 8 “Market Participant Choice to Construct,
Own, Operate, and Maintain Transmission Lines Connecting Its Facilities to the Interconnected Electric
System.” The paper is in response to market participants’ desire for an alternative to the incumbent TFO’s
role in constructing, owning, operating and maintaining these facilities. The AESO understands that this
desire has resulted primarily from the perceived high costs and lengthy schedules associated with the
incumbent TFOs constructing these interconnections.
6 Current Roles and Accountabilities
The roles and accountabilities for TFOs, the AUC and the AESO are outlined in various forms of
legislation including the EUA, the T-Reg, Alberta Utilities Commission Act (“AUC Act”), and the Hydro and
Electric Energy Act (“HEEA”). Please refer to Appendix A, which provides a more detailed outline of the
roles of the various agencies involved at the various stages of a transmission facility project. In addition,
the TFO Terms and Conditions 9 , as approved by the AUC, further define the relationship between the
AESO and the TFOs.
The high level descriptions of the various roles described in this section are based on the approach
whereby the system project advancement typically follows a sequential process. That is, the AESO would
direct the TFO to file a FA after the AUC has approved the AESO’s NID application. The legislation does
enable the AESO and the TFO to file concurrent NID and FAs enabling the AUC to consider the
applications concurrently.
The roles of the various implementing agencies with respect to managing transmission capital additions
may be best illustrated as follows:
6
For a more complete reference, refer to s.25 of the T-Reg.
Alberta Regulation 86/2007, including the 2010 amendments, is available at the Government of Alberta website at :
http://www.qp.alberta.ca/574.cfm?page=2007_086.cfm&leg_type=Regs&isbncln=9780779754298
8
A copy of the report is available at : http://www.aeso.ca/downloads/Discussion_Paper_-_MP_Choice_vFinal_Sept_28.pdf
9
AUC Decision 2010-116 provides for approval of the TFO T&Cs, dated February 1, 2010, and orders adoption, effective March 18, 2010, by all regulated TFOs.
7
Page 4
6.1
AESO Role
The AESO’s primary role with respect to transmission capital additions is determining, through the
AESO’s planning process, “what” facilities are required in order to meet the needs of Albertans and
are in the public interest. The transmission system in Alberta serves multiple purposes including the
facilitation of a competitive energy market, enabling access to interconnecting customers and
ensuring the continued reliability of the electric system. In planning for transmission reinforcement,
the AESO must take into account a multitude of requirements including, but not necessarily limited
to, load forecasts, generation interconnections, energy market operations, reliability standards, etc.
The AESO is obligated to fulfill its transmission planning duties in accordance with the EUA and TReg requirements, and more specifically is guided by section 33 of the EUA and sections 8, 10, 11,
15, and 16 of the T-Reg. Bulk transmission additions are inherently “lumpy” with the continued
challenge being to identify the appropriate level of capacity additions to meet long-term needs at a
reasonable cost. Balancing these requirements with efforts to minimize the potential negative
impacts on landowners through siting of new transmission facilities also continues to be a
challenge. Being short-sighted leads to transmission underbuild and could also potentially lead to
increased impacts on landowners as a result of the need to build more facilities in the future. While
overbuilding capacity likely minimizes the impact on landowners, it may lead to higher transmission
costs in the short term.
The AESO strives to find the appropriate balance and articulates the need adequately to enable the
appropriate review by the AUC. The T-Reg (section 15(e)(i)) requires the AESO to plan a
transmission system that “… is sufficiently robust so that 100% of the time, transmission of all
anticipated in-merit electric energy … can occur when all transmission facilities are in service…”
The AESO is obligated to develop transmission to accommodate all forms of in-merit generation
regardless of the load or capacity factor for the particular technology associated with the
Page 5
generation. The AESO recognizes this requirement is important in a competitive “energy only”
market to enable reasonably predictable cost recovery of all efficient generators.
The AESO develops a long-term transmission plan (LTP) 10 that includes a cost estimate of
transmission capital investments over a 20-year horizon. A reliable and robust transmission system
is critical for the continued reliability of the Alberta electric system. The following quote is taken from
the draft 2011 LTP:
“While some may argue that distributed generation can provide an alternative solution to
large-scale generation, this is refuted by two main points: (1) transmission is the low-cost
element in the total cost of electricity, supporting a competitive generation network, and
(2) generation at the local, or any level, cannot be a full substitute for transmission
because it is less available, and therefore less reliable, and can lead to issues of local
market power.”
The AESO evaluates various transmission alternatives which meet the identified need and utilizes
cost estimates 11 provided by the TFOs to assess the economic merit used to select a
recommended alternative which 12 is ultimately filed with the AUC for approval pursuant to Section
34(1) of the EUA. The AESO’s NIDs are the prime vehicle for demonstrating to both the AUC and
stakeholders the need for transmission system reinforcement within the context of the provincial
energy policies and regulations. Given the current legislative framework, attempting to monetize the
economic benefits of transmission would appear to be of questionable value and therefore has not
been undertaken by the AESO to date. Facilities associated with customer interconnections follow a
similar path (i.e. in terms of regulatory filings) as major system transmission projects and include
the appropriate cost allocation in accordance with the AUC approved AESO Transmission Tariff.
The AESO’s role regarding cost estimates for transmission projects includes:
•
•
•
•
Ensuring an understanding of the implications a planning decision will have relative to costs,
accounting for the timing of a transmission capital addition to meet a particular need (EUA
ss.17(g)(h)(i) and (j));
Ensuring scope and functional requirements result in reasonable and prudent capital costs
while still meeting the need and reliability standards;
Ensuring that cost estimates are reasonable and have sufficient detail and fall within bounds
of consistent accuracy such that scope, schedule, functionality, planning and tariff treatment
decisions can be satisfactorily arrived at (ISO rules Section 9.1, T-Reg s.25(1), (2));
Implementing the rules relating to standardized estimating/reporting (per ISO rules Section
9.1).
Pursuant to T-Reg section 25(1), the AESO reviews the cost estimates provided by the TFOs to
assess reasonableness for the intended use of the cost estimates, which is predominantly for the
purpose of making transmission system planning decisions.
The AESO prepares a project functional specification which forms the basis for the TFO to conduct
further engineering to prepare a Proposal to Provide Service (PPS), which includes a cost estimate
(+20/-10%), submitted to the AESO for review. Following the AESO’s review and acceptance of the
TFO’s proposal, the TFO is directed by the AESO pursuant to section 35(1) of the EUA, to submit a
facility proposal for AUC approval under the HEEA. In cases where the PPS cost estimate falls
outside the bounds of a NID level (+/-30%) estimate, the AESO would initiate a review of the
alternatives identified in the NID to determine whether one of the alternatives more appropriately
meets the need at a lower cost than the preferred or AUC approved solution. If one of the
alternatives represents a potential lower cost solution, the AESO would file a NID amendment for
AUC approval.
10
11
12
A copy of the AESO’s draft 2011 Long-term Transmission Plan is available at http://www.aeso.ca/downloads/AESO_2011_LTP_Sections_1.0-5.0.pdf
Need level estimates (+/-30%) are provided by the TFOs in accordance with ISO Rule 9.1 and its associated templates for preparing cost estimates.
The AESO seeks AUC approval for need with the exception of CTI projects which are legislated and identified in the EUA Schedule.
Page 6
The AESO may, pursuant to section 25.2 of the T-Reg, also direct the TFO to procure major
equipment (including other preparatory work), involving long-lead delivery times, for a transmission
project in order to achieve a required in-service date.
The AESO continues to work closely with the TFO during the course of project execution; however,
the AESO’s role is primarily one of monitoring schedule and costs as well as responding to any
“scope change” proposals in accordance with ISO rules Section 9.1.3.4 and 9.1.3.5. Any project
scope change that would fall outside the bounds of the terms of the AUC approval 13 would require
a resubmission of the application to the AUC for approval either by the AESO or the TFO as the
case may dictate.
The AESO provides the TFCMC with copies of the TFOs’ monthly reports (provided to the AESO
pursuant to ISO rules Section 9.1.3) for projects greater than $100 million.
The AESO monitors compliance to ISO rules and may conduct a review (pursuant to ISO rules
Section 9.1.5.8) of a TFO’s compliance to project procurement under ISO rules Section 9.1.5. If the
AESO suspects non-compliance with the rule, the matter is referred to the MSA for enforcement
including possible penalties.
6.2
TFO Role
The TFO is responsible for the reasonable and prudent execution of transmission projects (i.e.,
design and construction) based on direction from the AESO and contingent upon subsequent
approvals by the AUC. The TFO provides assistance 14 to enable the AESO to carry out its duties.
The AESO relies on the TFOs for cost estimates of proposed transmission developments to enable
it to carry out its evaluations of transmission alternatives to meet a particular need.
In accordance with ISO rules Section 9.1.2.2 and associated templates, the designated TFO (or
TFOs) prepares NID level cost estimates based on information provided by the AESO. This
information typically consists of a high level scope description of the various transmission
alternatives the AESO will consider to meet a particular need.
As a project advances beyond the need stage, and following a direction by the AESO, the TFO
prepares a PPS in accordance with ISO rules Section 9.1.2.4. The PPS and associated cost
estimate are based on the AESO’s functional specification. The TFO is responsible for siting any
new transmission facilities, consulting with affected parties, including landowners, as well as
obtaining any other necessary permits to enable the facility to be constructed. Following the
AESO’s review and acceptance of the PPS, and upon AESO direction, the TFO submits a Facility
Application (FA) for AUC approval in accordance with AUC Rule 007. The associated FA cost
estimate (+20/-10%) submission follows the AUC’s cost estimate reporting template per AUC Rule
007. The TFO is required to respond to any cost estimate related questions (i.e., through
Information Requests) posed by the AUC or registered intervenors during the AUC’s facility
application process and in accordance with AUC rules.
Following AUC approval of the FA, the TFO proceeds with the execution of the project in
accordance with any terms and conditions imposed by the AUC’s Permit and License. The TFO
provides the AESO monthly reporting with respect to the project progress (i.e., primarily cost and
schedule) and in accordance with ISO rules Section 9.1.3. Any scope change during the course of
the project is managed and communicated with the AESO in accordance with ISO rules Section
9.1.3.
Per ISO rules Section 9.1.3.6, the TFO also provides the AESO with a final cost report following the
completion of the project. The TFO provides a forecast of capital costs during the course of its
13
Approvals in this context refer to either AUC approvals/decisions with respect to AESO NID applications or AUC approvals/decisions with respect to the TFO’s Facility
Application, as a particular project scope change may dictate.
14
The duties of the TFO are outlined in the EUA, section 39. Assistance includes, among others, providing the AESO with cost estimates and proposals consistent with ISO
Rule 9.1.
Page 7
General Tariff Application and then submits the final project costs to the AUC for approval through a
TFO Deferral Account Proceeding. The TFO is required to respond to any prudence or
reasonableness questions posed by the AUC or registered intervenors during a Deferral Account
Proceeding.
The TFO is also responsible for the continued safe and reliable operation and maintenance of its
transmission assets.
6.3
AUC Role
The AUC reviews and approves AESO transmission facility NID applications and the subsequent
TFO FA. The process for applications is well laid out by the AUC 15 . The AUC is charged with acting
in the public interest and must take into account stakeholder concerns and balance those interests
with the requirement for electrical facilities to meet the need for power for all Albertans.
The AUC’s review of an AESO NID application is to confirm whether the proposed facilities are
needed and in the public interest. The AUC is required 16 to presume that the AESO’s assessment
of the need is correct unless an interested party satisfies the AUC that the application is technically
deficient or that approval of the NID would not be in the public interest. The AUC’s approval of the
NID at this stage, while providing support for the estimated reasonable expenditures for the project,
does not provide approval for the actual expenditures nor provide any guarantees that all TFO
expenditures will be permitted to be included in the TFO’s rate base.
The AUC’s review of a TFO FA is to decide on the location of the required transmission facilities.
The AUC must weigh the benefits against the impacts of the transmission project and establish
possible mitigation. The AUC’s approval of the FA at this stage, while providing support for the
estimated reasonable expenditures, does not provide approval for the actual expenditures nor
provide any guarantees that all TFO expenditures will be permitted to be included in the TFO’s rate
base.
The AUC’s public interest mandate is well articulated in Decision 2009-028:
“In the Commission’s view, assessment of the public interest requires it to balance the
benefits associated with upgrades to the transmission system with the associated
impacts, having regard to the legislative framework for transmission development in
Alberta. This exercise necessarily requires the Commission to weigh impacts that will be
experienced on a provincial basis, such as improved system performance, reliability, and
access, with specific routing impacts upon those individuals or families that reside or own
land along a proposed transmission route as well as other users of the land that may be
affected. This approach is consistent with the EUB’s historical position that the public
interest standard will generally be met by an activity that benefits the segment of the
public to which the legislation is aimed, while at the same time minimizing, or mitigating to
an acceptable degree, the potential adverse impacts on more discrete parts of the
17
community”.
The AUC approves forecast TFO costs, including direct assigned capital costs usually approved in
aggregate, as part of a TFO tariff application proceeding. Actual TFO costs undergo AUC review
and tests for prudence during the course of a TFO Deferral Account proceeding. This process
allows interveners to challenge or question the TFO’s costs put forward as part of the TFO’s
applications, both on an initial forecast and actual basis. The AUC considers the TFO’s costs just
and reasonable unless an interested party is able to convince the AUC that the costs put forward by
a TFO are unreasonable or imprudent. 18 The tests for prudence are well defined, with the following
(from Decision 2001-110) representing a good articulation of the tests applied by the AUC:
15
Refer to AUC web site at http://www.auc.ab.ca/acts-regulations-and-auc-rules/rules/Pages/Rule007.aspx
Refer to subsection 38(e) of the T-Reg
AUC Decision 2009-028, page 6.
18
Reference s.46(1) of the T-Reg
16
17
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“In summary, a utility will be found prudent if it exercises good judgment and makes
decisions which are reasonable at the time they are made, based on information the
owner of the utility knew or ought to have known at the time the decision was made. In
making decisions, a utility must take into account the best interests of its customers,
while still being entitled to a fair return.” 19
6.4
MSA Role
Under the Alberta Utilities Commission Act (“AUCA”) the Market Surveillance Administrator
(MSA) has a broad mandate including surveillance, investigation, and enforcement to help ensure
the fair, efficient, and openly competitive operation of electricity and retail natural gas markets in
Alberta. Section 39 (1) (b) of the AUCA requires that the MSA undertake activities to address
contraventions of ISO rules or reliability standards. Section 21.1 of the EUA requires that when the
AESO suspects that a market participant has contravened an ISO rule or Reliability Standard, it
must refer the matter to the MSA for enforcement.
7 Other Jurisdictions
The challenges of estimating and managing transmission project costs are not unique to Alberta. Other
jurisdictions in North America have recognized that variances between initial project estimates and actual
costs – particularly for large-scale transmission projects – draw considerable attention, both from
stakeholders and regulators. While final prudency reviews are still common at the transmission tariff
application stage, some jurisdictions have instituted mechanisms for monitoring costs of projects in
progress. The following summaries have been prepared based on readily available information and
through conversations or interviews with key personnel representing the various organizations. Please
also refer to Appendix E – The Brattle Group report Summary of Cost Control Mechanisms in Select US
Power Markets- October 2011.
7.1
BC Hydro
BC Hydro submits applications to the British Columbia Utilities Commission (BCUC) for projects
that require a Certificate of Public Convenience and Necessity (CPCN). A CPCN is required when
the project cost exceeds $50 million, when adverse impacts cannot be mitigated, for projects that
are considered high risk (defined under a specific framework), where the project establishes a
precedent for significant future investment, or where the BCUC exercises its discretion to require an
application. BC Hydro is required to submit detailed cost estimates as part of the CPCN application
although final determination of prudency occurs as part of a general rate hearing after the facility is
“used and useful” for inclusion in rates. Stakeholders may participate in each of the CPCN and rate
proceedings. Recognizing the concern over rising capital transmission project costs, in 2009 the
BCUC directed BC Transmission Corporation (now BC Hydro) to submit a plan to improve project
cost estimating, project controls, project teams, commercial management and resource
20
management. BC Hydro filed a response to the BCUC directive on October 13, 2009.
7.2
Hydro One
Hydro One is the largest transmission owner (96%) in Ontario. Hydro One determines which
transmission lines are to be built (substations are exempt from this process) and submits a proposal
to the Ontario Power Authority (OPA) which then evaluates the need and alternatives. The OPA
provides a notification and letter of support to Hydro One to proceed with an application to the
Ontario Energy Board (OEB) for approval of need and leave to construct. Hydro One may apply for
leave to construct transmission lines without the OPA support but it is considered an overwhelming
19
EUB Decision 2001-110, page 10.
Details of the BCHydro submission may be obtained at : http://transmission.bchydro.com/NR/rdonlyres/408F1235-D7BD-41D2-BC3946768BBEB659/0/ResponsetoF2010CapitalPlanDirectives13Oct2009.pdf
20
Page 9
barrier to approval. Hydro One’s application for approval to construct must include need, route,
costs, assumptions and detailed economic analysis to support a public interest mandate.
Transmission project cost estimates at the application stage must have an accuracy level of +/10%. At this estimate level, rights of way have been defined, consulted on and procured; 30% of all
engineering has been completed and all materials and labour contracts tendered. Hydro One is
legislatively obligated to follow Ontario Procurement Guidelines which are rigid and fairly
prescriptive. Once Hydro One obtains leave to construct, it must submit exception reporting to the
OEB in respect of construction schedule change, cost variance >10% of estimate, and changes in
functionality, circumstance, and route. The OEB has the authority to withdraw the leave to construct
if it considers increased costs render the project uneconomic, but has not done so to date.
Transmission projects undergo retrospective prudency reviews by the OEB for inclusion in rates.
Stakeholders typically intervene in Hydro One regulatory proceedings.
8 Challenges/Issues with Transmission Capital Costs
The AESO has identified several areas for discussion on the implementation of transmission capital
projects, incorporating concerns expressed by various stakeholders.
8.1
Accountability for cost estimates for transmission projects
Stakeholders have expressed concerns regarding the escalating costs of transmission and the
perceived lack of accountability by parties that construct these facilities in managing costs. Some of
these concerns are driven by evidence 21 of final project costs far exceeding the initial project
estimates for certain capital projects. Stakeholders have also expressed that there does not appear
to be sufficient incentive to limit expenditures on transmission projects during the regulatory
approval and construction stage of a project, notwithstanding both forecast and actual project costs
are subject to AUC prudence reviews as part of a TFO’s tariff and deferral account proceedings,
respectively. TFOs are required to demonstrate prudence to the AUC through the deferral account
proceedings. However, this takes place well after the project has been completed. Current
regulatory procedures do not contemplate a forward-looking stance that would apply both a
thorough review of the expenditures beforehand and allow for continuous, proactive oversight and
evaluation of construction costs while in progress.
Is the current regulatory framework adequate to ensure the appropriate checks and balances are
in place with respect to cost control of transmission projects?
8.2
Uncertainty associated with cost estimating
The AESO, through its draft 2011 LTP has identified the need for a significant level of transmission
build over the next 10 years in order to meet the requirements of load growth in the province. TFOs
are challenged to deliver transmission projects at an optimum or reasonable cost given the
challenges in transmission siting, regulatory approvals, and acquisition of low-cost labour, along
with commodity price volatility 22 . Requests for new customer interconnections are significant,
posing a challenge to meet customer in-service date requests.
Forecasting a reliable/dependable cost estimate for a transmission project is challenging given
such factors as the volatility in commodity and labour markets, seasonal construction requirements,
regulatory processes, and other factors. This is particularly the case with large transmission
projects that span a number of years. The cost performance of small (less than approximately $50
million) and short duration ( less than two years) transmission projects has been fairly good.
21
22
See TFCMC Conclusions and Recommendations – June 2011 report to the Minister – “Review of the Cost Status of Major Transmission Projects in Alberta”.
Please see Appendix D – Illustration of metals price volatility.
Page 10
However, the cost performance for large and long duration transmission projects requires
improvement.
The AESO and TFOs are challenged to advance transmission development (often driven by
customer demands) in a timely manner, while expending a reasonable level of effort to determine
quality cost estimates for a project. Standardized cost reporting was established in conjunction with
the development of ISO Rule 9.1, with the associated standardized templates made available on
the AESO’s web site. As is typical with estimating standards for projects, the expected estimating
accuracy for a project will vary through its life span as illustrated in Appendix C. The estimating
templates include provisions for the inclusion of a contingency to account for various unknown
factors the TFO considers necessary. At the NID stage, an estimating accuracy of +/-30% can be
expected given a number of parameters have not been finalized, and the absence of detailed
engineering and regulatory approvals, including, for example, final transmission line routing. At the
FA stage, an estimating accuracy of +20/-10% can be expected commensurate with additional
level of engineering, and the increased certainty in line routing, as an example. Given the project
has not received AUC approval, nor has the TFO tendered any of the materials and construction,
an estimating accuracy beyond the +20/-10% accuracy level would appear impractical at the FA
stage.
The AESO has implemented business practices to address matters such as cost estimates falling
outside the bounds of submitted estimates by a TFO. For example, in the event the AESO receives
a PPS cost estimate from a TFO that is outside the bounds (i.e. higher) than a NID (+/- 30%) class
estimate, the AESO initiates a review of the transmission alternatives identified in the NID to
determine whether an alternative, and potentially lower cost transmission alternative, should be
more appropriately advanced as a solution to meet the need. Variances to a PPS class estimate
following the filing of a FA are addressed through the AESO’s business practices under ISO rules
Section 9.1.3 which deals with project variance reporting, project change proposals and final cost
reports.
Are the current requirements (i.e., as required by ISO and AUC rules) for cost estimates still
adequate for large projects (i.e. over $100 million) developed over a span of five to 10 years?
8.3
Level of detail and transparency of transmission cost estimates
The AESO and TFOs provide industry with a certain level of detail with respect to transmission cost
estimates, either through the AESO’s NID applications or the TFOs’ FAs filed with the AUC.
Through Rule 007, the AUC prescribes the level of cost estimate detail required for applications
submitted to it for approval. Further, the regulatory process affords stakeholders opportunities to
ask for additional information with respect to cost estimates for projects. The AESO also provides
stakeholders updates with respect to cost estimates through the AESO’s Projects Quarterly
Reports 23 in accordance with ISO rules Section 9.1.4. The AESO also provides the TFCMC with
cost estimate information pursuant to section 25(1) of the T-Reg. This report encompasses system
projects greater than $100 million and includes any information the AESO receives from TFOs
pursuant to ISO rules Section 9.1.3.
The AESO submits project cost estimates (+/-30%) in connection with its NID application to the
AUC. The cost estimates are provided to the AESO by the TFOs, consistent with the ISO rules and
associated estimating templates 24 .
23
The following link provides a recent example of a Transmission Systems Quarterly Report: http://www.aeso.ca/downloads/2011_Q2_Tx_System_Quarterly_Report_R1.pdf
The AESO’s estimating templates are available at: http://www.aeso.ca/transmission/8852.html. The templates include guidelines with respect to the information to be provided
to the AESO.
24
Page 11
The TFO provides the AESO with a greater level of detail of the cost estimate for system projects
than what is normally shared with the public through subsequent Need or Facility Applications in
formats required by the AUC. The AESO carefully manages issuance of detailed cost estimate
information to the public for system projects due to concerns about market sensitivities and the
potential influence on prospective bidders wishing to supply materials and labour for transmission
projects. On the other hand, and consistent with ISO rules Section 9.1, for projects involving
customer interconnections, the customer receives the same level of cost estimate breakdown as
does the AESO. The AESO recognizes the importance of transparency with respect to
transmission project cost estimates, while balancing the desire for an increased level of cost
estimate detail with the need to maintain a level of confidentiality desired by the TFOs and
customers.
The AESO has enhanced its draft 2011 Long-term Transmission Plan to include an increased level
of detail on transmission project cost estimates 25 . The AESO is committed to updating the cost
estimates noted in the draft 2011 LTP every six months.
Stakeholders have raised concerns regarding the level of detail of the cost estimates provided,
through the AESO reports, the AESO’s NID filings, and TFO’s FA filings.
Is the AESO’s level of transparency on transmission cost reporting adequate? Should more detail
be provided recognizing the concern that providing more detail may negatively impact competitive
procurement?
8.4
Competitive procurement of materials and labour per ISO rules Section 9.1.5
TFOs are required to comply with ISO rules Section 9.1.5 26 for the procurement of materials and
labour for a transmission project direct assigned by the AESO. The objective of legislation 27 and the
associated ISO rule is to bring market forces to bear to enable the lowest possible cost delivery of a
transmission project, at least with respect to materials and construction labour which are expected
to be the majority of the costs associated with a transmission project (i.e., typically between 60%
and 70%). The balance of the costs tend to be “soft” or “owner” costs (i.e., typically between 30%
and 40%). The current procurement rules have remained essentially unchanged since 2005. As
such, the AESO invites comment as to whether the rules are adequate in terms of enabling a TFO
to deliver major transmission projects in the current market environment. The TFO’s final cost
report for a capital project includes a summary of the level of competitive procurement undertaken
during the course of the project.
The AESO has carried out compliance reviews 28 of certain projects, with regard to the TFO’s
procurement practice and level of compliance to ISO rules Section 9.1.5, consistent with the
provisions of ISO rules Section 9.1.5.8.
Are the current rules achieving the desired outcomes? Do the ISO rules offer sufficient flexibility
to enable TFOs to exercise procurement practices that lead to the lowest possible cost for a
facility? What are the appropriate measures that could be utilized to measure their effectiveness
in terms of delivering a transmission project at the lowest possible cost?
25
The AESO’s 2011 Draft Long-term Transmission Plan is available at: http://www.aeso.ca/transmission/22021.html
Rule 9.1.5 – Project Procurement- is intended to meet the requirements of the T-Reg , section 26(1).
Section 26(1) of the T-Reg obligates the ISO to “…provide for the competitive tender of construction costs, including materials and equipment, for..”
28
By way of example, refer to report on AESO’s web site at http://www.aeso.ca/downloads/Compliance_Review_-_Joffre_Report_Final_Part_A(1).pdf
26
27
Page 12
9 Stakeholder Consultation and Next Steps
The AESO invites stakeholders to comment on the AESO’s view of the challenges and issues associated
with the cost management of new transmission infrastructure build expressed in this paper using the
attached stakeholder comment matrix. Please provide written comments to [email protected]. Should
you have any questions on this discussion paper, please contact Fred Ritter at ph: 403-539-2616 or
[email protected].
The AESO will provide stakeholders with feedback on all comments received, consistent with the AESO’s
standards on consultation.
Page 13
APPENDIX A
Legislated Rights and Obligations – Transmission Project Implementation
Introduction
Alberta's transmission system is planned and operated by the AESO. The AESO's role is to maintain the
safe, reliable and efficient operation of the transmission system. The AESO's planning responsibility
includes determining the need for transmission system development and the manner in which that need is
met 29 . The AESO is also mandated to create and implement ISO Rules, including rules relating to the
processes for the expansion of the transmission system. The AESO is regulated by the AUC and must
apply to the AUC for approval of any filed need identification document ("NID").
While the AESO is responsible for identifying whether transmission system development is needed, the
AESO does not construct or have any stake in the actual transmission facility 30 . Instead, the AESO
requests the eligible TFO 31 to provide either a NID estimate 32 or request a service proposal 33 or both.
Once these have been received and reviewed by the AESO, a direction will be issued to the eligible TFO
that a transmission facility is needed and they are responsible for the siting and routing, construction,
operation and maintenance of the transmission facilities.
The following describes the processes for how the transmission system is planned through to completion
of a transmission project. The roles and responsibilities of the AESO, the TFO and the AUC will be
apparent from the wording of the applicable legislative provisions. The legislation reviewed in this
discussion include the Electric Utilities Act ("EUA"), the Hydro and Electric Energy Act ("HEEA"), and the
Transmission Regulation ("T-Reg"). ISO Rules and AUC Rules, if applicable, will also be reviewed with
references included.
Appendix B provides a simplified view of the process to initiate and implement transmission system
projects. References are provided in the following descriptions linking to points on the process map.
Step 1 – Identifying a Need (Stages 0, 1, and 2 – Process Map)
At this initial stage of the process, the AUC does not have any role or responsibility. In this step, the
AESO identifies a need for transmission infrastructure and begins to prepare the NID document for filing
with the AUC. If the AESO chooses, it can enlist the assistance of a TFO in the preparation of a NID 34 .
Section 33 of the EUA and sections 8 thru 10 of the T-Reg impose an obligation on the AESO to forecast
the needs of Alberta, to develop plans for the transmission system, to provide system access service on a
non-discriminatory basis and to implement any required transmission system expansions or
enhancements in a timely fashion. In addition, the AESO is required to consult on any transmission plans
it develops prior to completing the preparation of those plans 35 .
If the completed transmission plans reveal a need for transmission infrastructure to be built, section 34(1)
requires the AESO to prepare and submit a NID to the AUC for approval after the AESO has determined
29
See ss. 17(j) and 20(1)(f) of the EUA
See s. 9(6) of the EUA
31
See ISO Rule 9.1.1
32
See ISO Rule 9.1.2.1
33
See ISO Rule 9.1.2.3
34
See s. 39(2) of the EUA and ss. 13(1)(c) and 14(1)(c) of the T-Reg
35
See s. 33 of the EUA
Page 14
30
that an expansion or enhancement to the transmission system may be required to meet the needs of
Alberta and is in the public interest. Section 34(1), section 11(3) of the T-Reg and AUC Rule 007 36 set out
what the NID must contain. Sections (11)(4) and 11(5) contain further instruction should any of the
options set out in section 11(3) be preferred 37 .
Section 11(1) of the T-Reg states that when preparing a NID, the ISO may rely on the forecasts contained
in the long-term plan, and in so doing, may also indicate how the NID relates to the long-term plan.
Further, section 11(2) of the T-Reg permits the AESO to describe a need for more than one transmission
facility in a single NID.
Section 11(6) of the T-Reg contains exceptions to when a NID must be prepared and submitted to the
AUC 38 and section 12 of the T-Reg permits the AESO to develop an abbreviated NID approval process 39 ,
which is not discussed in this memo.
The EUA requires the AESO to determine who is eligible to apply for the construction and operation of the
transmission project on the basis of geographic areas under sections 28 and 29 of the HEEA 40 .
Consequently, ISO Rule 9.1 Transmission Facility Projects specifies which TFOs are eligible to build a
new facility as per the defined service areas. Further, ISO rules Section 9.1 operates in conjunction with
the EUA 41 and the T-Reg to obligate a TFO to provide a NID estimate and proposal to provide service
("PPS"), including the contents of same, relating to a NID project as requested by the AESO.
Step 2 – Filing a NID (Stage 4 – Process Map)
At this stage the AUC, in addition to the AESO, becomes involved in the process. Once the NID has been
filed with the AUC, section 34(3) of the EUA requires the AUC to approve the NID, refer the NID back to
the AESO for revision or refuse to approve the NID 42 . If the NID requires changes or is rejected, these
steps will be repeated until the AUC is satisfied that the NID includes and addresses those issues in
subsection 34(1)(a) thru (c).
As an alternative, the AESO may choose to file the NID in conjunction with the TFO's facility application
("FA") 43 . In this type of combined application, the two applications will be dealt with in a single AUC
process. However, the AESO will continue to be responsible for any concerns raised with respect to the
need identified 44 .
For further details regarding combined submissions and the AUC's requirements for FAs, please refer to
AUC Rule 007.
Step 3 – ISO Request for Service Proposal from TFO (Stage 2 and 3 – Process Map)
The next sequential filing step includes seeking cost information related to the proposed transmission
facility. The AESO will issue a request to the eligible TFO to provide a PPS, which includes an estimate of
the projected costs 45 .
36
See AUC Rule 007 - Rules Respecting Applications for Power Plants, Substations, Transmission Lines, and Industrial System
Designations. This hyperlink has been inserted for ease of reference
37
See ss. 11(3), 11(4) and 11(5) of the T-Reg
38
See s. 11(6) of the T-Reg
39
See s. 12 of the T-Reg
40
See s. 24(1)(a) of the EUA
41
Supra, at FN 10
42
See s. 34 of the EUA
43
See s. 15.4 of the HEEA
44
See AUC Rule 007, supra, at FN 4
45
See ISO Rule 9.1.2.3 and 9.1.2.4
Page 15
Under section 35(1) of the EUA, the AESO has two options: Direct a TFO to submit a FA for AUC
approval under the HEEA, or ask market participants to submit a proposal for AESO approval which
meets the need identified. However, the AESO has not, and does not plan to, issue the request to a
market participant. Instead, the AESO always issues the direction to the eligible TFO under section
34(1)(a) of the EUA and in accordance with ISO rules Section 9.1.1.2.
Step 4 – Review Proposal and Issue Direction for FA (Stage 4 –Process Map)
Once the TFO has submitted the PPS and estimate for the transmission project, the AESO will review
same and then issue a direction to the appropriate TFO 46 to bring a FA before the AUC, assuming the
AESO has not chosen the combined submission process.
If the AESO issues a direction to a TFO, then the TFO must comply unless there is a real and substantial
risk to the TFO's transmission facility, its employees or the environment 47 . It must be noted that a TFO
may also refuse any of the AESO's requests or directions at any stage, including a NID estimate or PPS,
should any of the three preceding reasons apply. From this step, the matter proceeds to a FA before the
AUC 48 .
Complementary to section 35 of the EUA, the T-Reg states the ISO must make rules or establish
practices for the preparation of cost estimates, project scope and schedule documents to ensure cost
estimates are reasonable and contain an appropriate level of detail, and that any subsequent changes to
the original documents are identifiable. Further, the AESO may satisfy itself that the cost estimates are
reasonable, but may only examine issues that are relevant to the intended use of the cost estimates 49 .
The AESO may do either of the following: certify to the AUC that a cost was incurred to meet either an
identified need or direction issued by the AESO; or notify the AUC of any concerns regarding the
projected costs of the transmission facility project. However, the AUC cannot require the AESO to make
any statement with respect to the prudency of managing a transmission facility project 50 .
Assuming the AESO has no issues with the PPS or accompanying estimate, and if any identified issues
have been corrected by the TFO, the AESO will then issue a notice to file which lifts all conditions
contained within the EUA section 35(1)(a) direction letter.
Step 5 – the Facility Application (Stage 4 –Process Map)
At this stage of the process, the AUC decides whether to issue a permit and license for the transmission
facility project. As mentioned above, this process can be combined with the filing of the NID by the
AESO 51 . Assuming the combined submission process has not been invoked, the next step involves
submitting all the necessary documentation with respect to the proposed transmission facility.
Sections 14 and 15 of the HEEA prohibit the transmission line from operating until a permit and license
have been issued by the AUC.
When considering the AESO-directed application by the TFO 52 , the AUC has obligations regarding its
decision-making process. For example, section 15.1 of the HEEA requires the AUC to take into account
46
Pursuant to ISO Rule 9.1.1.2
See s. 35(2) of the EUA
48
See ss. 35(3) and 39(4) of the EUA
49
See s. 25 of the T-Reg
50
Supra, at FN 18
51
Supra, at FN 9 and FN 10
52
Pursuant to s. 35(1)(a) of the EUA
47
Page 16
whether the AESO has certified that the technical aspects of the application are in accordance with the
requirements set out in the AESO's NID.
Further, the AUC is also required to make its decision in a timely manner 53 . If the AUC is unable to come
to a decision within the directed timeframe, then an extension of 90 days is permitted, provided the AUC
notifies the TFO, or other applicant, of the reason why it has not been able to make a decision. The HEEA
also permits the AUC to approve any incentives that are intended to result in cost savings or other
benefits associated with the transmission facility project 54 .
Section 19(1) of the HEEA grants to the AUC the discretion to approve, require amendments to, or deny
the application. Section 19(2) provides some examples of what the AUC could ask of the applicant when
prescribing amendments. Specifically, the AUC may require changes to: the plans and specifications; the
location of the transmission line; prescribe a date by which construction of the project must commence;
the location and route of the transmission line; and the location of the right of way and its boundaries.
However, the AUC's scope is not limited to these matters.
In addition to the requirements under the HEEA, the T-Reg authorizes the AESO to further direct a TFO
to acquire equipment and materials, including related engineering services. However, this direction
cannot be issued until after the AESO has issued a direction under section 35(1)(a) of the EUA to the
eligible TFO 55 .
Step 6 – TFO Cost Recovery through Tariff (Stage 6 – Process Map)
At this final stage in the process, the TFO will have completed the construction of the transmission facility
project and must submit to the AUC for approval, a tariff 56 setting out the rates to be paid by the AESO for
use of the transmission facility 57 . It should be noted that the TFO's tariff is unlikely to pertain to just the
proposed transmission facility and will recover those costs associated with all of the TFO's facilities.
The EUA contains several provisions prescribing the AUC's responsibilities when making a decision to
approve or reject a tariff application 58 . Section 121 states that the AUC must consider whether the tariff is
just and reasonable, that it is not unduly preferential, arbitrary or inconsistent with any enactment or law
and that the prescribed standard of liability is incorporated into the tariff, if required 59 .
Section 122 sets out what types of costs can reasonably be recovered by the TFO. These include costs
and expenses associated with investment capital, a fair return on the equity of shareholders, costs and
expenses associated with managing legal liability, load settlement and managing financial risk 60 . In
addition to the matters that must be considered by the AUC under section 122, the AUC must also
consider that it is in the public interest to provide consumers the benefit of unconstrained transmission
access to the competitive generation market 61 .
Regardless of which type of section 122 costs are sought to be recovered, in all cases those costs and
expenses must be considered prudent by the AUC. Prudent costs are those that would normally be paid
for property by reasonably judicious management. That said, it must be acknowledged that the concept of
53
See s. 15.2 of the HEEA, which states that 180 days is a "timely" decision.
See s. 15.3 of the HEEA
See s. 25.2 of the T-Reg
56
For clarification, the TFOs include direct-assign projects, as well as an estimate of future direct-assign projects (if a multi-year tariff
application is filed with the AUC), in the TFO tariffs on a forecast basis. The final stage involves a reconciliation of actual to forecast
costs and adjustment to the TFO tariff for any variances through the deferral account recovery application.
57
See s. 37(1) of the EUA
58
Including, but not limited to s. 124 of the EUA
59
See s. 121 for further detail on these requirements
60
See s. 122 of the EUA for a detailed list of recoverable costs
61
See s. 42 of the T-Reg
Page 17
54
55
prudency may be contentious to apply because it requires the use of value judgments in determining what
costs are excessive and what costs are necessary. Generally, costs intended to be incurred at the time of
the initial commitment can be assumed to be based on prudent judgment unless there is clear evidence
to the contrary.
Complimentary to sections 121 and 122 of the EUA and related to prudency, are sections 25(3) and 25(4)
of the T-Reg. These sections clearly state that nothing in the ISO Rules or practices relieve neither:
• A TFO from the burden of proof under section 121(4) to show that the proposed tariff is just and
reasonable, or
• The AUC from the responsibility of determining the TFO's prudence in managing its activities.
Pre-construction costs are also recoverable under section 39 of the T-Reg if a NID has been approved by
the AUC under section 34 of the EUA. If an application for the recovery of pre-construction costs is
approved by the AUC, the TFO may include those costs related to feasibility studies, engineering, the
purchase of equipment and materials and the purchase of land or acquiring rights of way 62 .
Assistance and secondary costs are also recoverable under the TFO's tariff. Sections 40 and 41 define
what are considered to be assistance and secondary costs respectively. For example, assistance costs
are those that have been incurred as a result of assisting the AESO. 63 Secondary costs are those that
have been incurred as a result of consequences arising from complying with a directive issued by the
AESO 64 .
Finally, the AUC is required to consider the costs and expenses referred to in sections 39, 40 and 41 of
the T-Reg recoverable under the TFO's tariff, together with payments made to landowners for rights of
entry or use of the land are prudent unless an interested person is able to satisfy the AUC that the same
are unreasonable 65 .
62
See s. 39 of the T-Reg
See s. 40 of the T-Reg for further detail
64
See s. 41 of the T-Reg for further detail
65
See s.46(1) of the T-Reg
63
Page 18
APPENDIX B
System Projects – Process Overview-Draft
The following process map is generally illustrative of the sequence of steps involved in the initiation and advancement of a system project. The process
is currently being refined by the AESO. This process has close similarity to the customer interconnection process map which is accessible on the
AESO’s web site at http://www.aeso.ca/downloads/Connection_Process_Overview_R5.pdf.
Legend:
- AESO activities
- TFO activities
- AUC activities
Page 19
APPENDIX C
Estimating Guidelines and Standards
The following figure is intended to illustrate the level of estimating accuracy during the stages of a typical
project; from concept through execution. The figure illustrates the Need Estimate (+/- 30%) stage (NID
application) as well as the PPS Estimate (+20/-10%) stage (Facility Application); both of which are key
steps in the AESO’s project execution process. Additionally, the AESO has included cost estimates (+/50%) in the draft 2011 LTP for projects in the early development or conceptual stage. Section 4.6 of the
draft 2011 LTP contains discussion regarding long-term transmission cost estimates.
The information is based on the Association for the Advancement of Cost Engineering (AACE) standards
for cost estimate classifications. The table 66 following the graph provides further context for the estimating
accuracy illustration.
Need
Estimate
PPS Estimate
+20/-10%
+/- 30%
66
The information has been taken from an AACE document titled “Recommended Practice No. 17R-97 –Cost Estimation Classification System – dated August 12, 1997.
Page 20
Page 21
APPENDIX D
Metals Price Volatility Illustration
The following information has been provided to the AESO by PowerAdvocate.
Metals Price Movements: 1Q2000‐3Q2011
600 500 400 Indexed
Ste
Cop
300 Alu
GO
Nic
200 Tita
Tin
100 Zin
‐
*Bold Lines Highlight Volatility of Copper and Steel Page 22
APPENDIX E
The Brattle Group Report
“Summary of Transmission Project Cost Control Mechanisms in Selected U.S. Power
Markets” – October 2011.
Page 23
Summary of Transmission Project
Cost Control Mechanisms in
Selected U.S. Power Markets
October 2011
Johannes P. Pfeifenberger
Delphine Hou
Prepared for
Copyright © 2008 The Brattle Group, Inc.
TABLE OF CONTENTS
I. Background ........................................................................................................................... 2 II. Overview of cost control through planning and prudence-reviews of U.S.
Transmission Investments......................................................................................................... 3 A. Planning of Transmission Projects in the U.S. ........................................................................... 3 B. Cost Control During the Development and Construction of Approved Projects ......................... 3 III. Summary of Selected U.S. Transmission Project Cost Control Mechanisms................. 4 A. ISO-New England ....................................................................................................................... 4 B. Texas CREZ ............................................................................................................................... 7 C. Southwest Power Pool................................................................................................................ 8 D. Midwest ISO.............................................................................................................................. 10 E. California ISO............................................................................................................................ 10 Copyright © 2011 The Brattle Group, Inc. This material may be cited subject to inclusion of this copyright
notice. Reproduction or modification of materials is prohibited without written permission from the authors.
Acknowledgements and Disclaimer
The authors acknowledge the valuable input from a number of market participants in various U.S. power
markets. Opinions expressed in this report, as well as any errors or omissions, are the authors’ alone.
The transmission cost control mechanisms summarized in this report represent our interpretations of
existing requirements. The authors are economic consultants, not lawyers, and nothing herein is
intended to provide, nor should the AESO infer that the report represents, legal advice or a legal opinion
in any form or fashion.
I. Background
We were asked by the Alberta Electric System Operator (“AESO”) to document and summarize U.S.
efforts aimed at controlling costs of transmission projects in an effort to mitigate the risk of significant
increases in the cost of planned transmission projects after they have been evaluated and approved.
More specifically, we were asked to address the following questions:
1) How are transmission costs managed? Who is responsible?
2) Who, or under what framework, reviews/approves transmission capital expenditure prudency?
3) What roles do independent system operators (“ISOs”) or regional transmission operators (“RTOs”)
play with respect to transmission cost control?
4) What interactions do ISO/RTOs have with stakeholders regarding transmission costs?
5) What incentives do transmission owners (“TOs”) and ISO/RTOs have with respect to transmission cost
containment?
The last several years have seen significant increases in transmission investments. For example, as we
have documented elsewhere, recent levels of annual U.S. transmission investments are four times the
annual investment levels during the 1990s, when investment levels were at historically low levels as
compared to the major construction boom during the 1960s through early 1980s. 67 The current increase
in transmission investments, which is anticipated to continue for the foreseeable future, 68 also has been
associated with significant increases in the initial planning-related cost estimates for transmission
projects.
For example, in 2008 the Public Utilities Commission of Texas (“PUCT”) approved a transmission plan to
integrate additional wind generation in selected competitive renewable energy zones (“CREZ”). In 2008,
this CREZ transmission plan (“CTP”) had an estimated total cost of $4.9 billion. 69 As of today, however,
the CTP projects are estimated to cost $6.8 billion—mostly because the initial cost estimates did not
account for a number of factors, such as financing costs during constructions, costs related to reactive
compensation, upgrades to lower-voltage transmission facilities, or the fact that the length of transmission
lines increased due to re-routing requirements. 70
In addition to cost increases resulting from more comprehensive and precise cost estimates, a number of
transmission projects planned prior to 2008 have seen significant cost increases due to unanticipated
increases in the costs of labor, equipment, and raw materials (such as steel, copper, and aluminum).
Between 2004 and 2007, the costs of transmission projects increased by approximately 30% while
economy-wide inflation increased the average costs of consumer goods and services by only 8%. 71 For
example, in an August 2004 filing before ISO New England Inc. (“ISO-NE”), NSTAR indicated that one of
its projects would cost $234 million. By March 2007, NSTAR informed ISO-NE that estimated project
costs had increased by $58 million, or almost 25 percent, for a revised total project cost of $292 million.
As NSTAR explained, this cost increase was driven by increases in both construction and material costs,
with construction bids coming in 24 percent higher than initially estimated. 72 These unexpected cost
increases were related to strong global demand for materials, which increased copper costs by 160
67
For example, see Pfeifenberger and Hou, "Employment and Economic Benefits of Transmission Infrastructure Investment in the U.S. and Canada," The Brattle
Group, prepared for WIRES, May 2011. Posted at: http://my.brattle.com/_documents/UploadLibrary/Upload947.pdf
68
Id.
69
PUCT, Docket No. 35665, Order on Rehearing, May 15, 2009.
70
Competitive Renewable Energy Zone Program Oversight, CREZ Progress Report No. 4 (July Update), prepared by RS&H for Public Utility Commission of Texas,
July 2011.
71
Chupka and Basheda, “Rising Utility Construction Costs: Sources and Impacts,” The Brattle Group, Prepared for The Edison Foundation, September 2007, p. 2.
72
Id., p. 11.
2
percent, core steel by 70 percent, flow-fill concrete by 45 percent, and dielectric fluid (used for cable
cooling) by 66 percent. 73
Since system operators and regulators often evaluate and approve projects based on initial cost
estimates, several U.S. regions have implemented or are evaluating the implementation of additional
mechanisms to reduce the risk of unexpected cost increases through improved cost estimation protocols
and monitoring of transmission costs. The remainder of this report summarizes the regulatory framework
for controlling transmission project costs in the U.S. and describes a number of mechanisms that were
implemented or are being considered in regions with significant recent transmission investment activity:
ISO-NE, Texas, the Southwest Power Pool (“SPP”), the Midwest ISO, and California.
II. Overview of cost control through planning and prudence-reviews of U.S.
Transmission Investments
A.
Planning of Transmission Projects in the U.S.
In U.S. electricity markets, the TOs and ISOs/RTOs are the primary parties responsible for managing
transmission costs from a planning perspective. In other words, ISOs/RTOs and transmission owners are
generally responsible for identifying cost effective transmission projects (or non-transmission alternatives)
via a transmission planning process that addresses transmission needs, such as identified reliability
concerns. These planning processes have to be compliant with transmission planning requirements set
out in Order 890 of the U.S. Federal Energy Regulatory Commission (“FERC”). FERC regulates all U.S.
wholesale transmission functions outside the Electric Reliability Council of Texas (“ERCOT”).
Transmission plans approved by ISOs/RTOs (in regions where they exist), however, still require that the
TOs responsible for implementing a particular ISO/RTO-approved transmission project obtain any
necessary permits from individual state commissions or state siting authorities and, where applicable,
federal land management authorities. These state-level permitting processes often include a
determination of needs, which may also require the evaluation of the cost effectiveness of a planned
transmission project from the perspective of each individual state.
B.
Cost Control During the Development and Construction of Approved Projects
TOs are the primary parties responsible for managing costs during the project development and
construction efforts, including the many factors that can influence costs, such as unforeseen route
changes to accommodate landowners or wildlife habitats, changes in material and labor costs throughout
the planning and construction effort, and other changes from original plans.
Prudence reviews are the primary U.S. regulatory mechanisms to provide incentives for cost
accountability during these development and construction phases of a project. Before transmission costs
can be recovered in transmission rates, their inclusion is subject to regulatory approval and the possibility
of prudence-related challenges. The process for prudence reviews of transmission projects differs
depending on the extent to which individual states have unbundled the transmission function in retail
rates.
FERC has jurisdiction over all wholesale transmission service, which includes any unbundled
transmission service to retail customers. Transmission service is an unbundled component of retail rates
in all states that introduced retail competition (e.g., California, Illinois, and most states on the east and
west coasts) as well as a few traditionally-regulated states (such as Arizona and Kansas) which have
unbundled transmission service to retail customers without restructuring and the introduction of retail
competition.
73
Id., p.11.
3
Parties that question the prudency of transmission costs before FERC are able to file a complaint under
Section 206 of the Federal Power Act. This requires a demonstration that an expenditure was
unnecessary or imprudent, such that the recovery of these costs would lead to FERC-jurisdictional
transmission rates that are unjust and unreasonable.
The Section 206 complaint option is also available to challenge the wholesale transmission rates of
vertically-integrated utilities even if they have not unbundled transmission services, both within and
outside of ISO/RTO regions. 74 However, utilities with bundled retail rates are also subject to prudency
reviews at the state level for their overall revenue requirements (including generation and distribution) in
each of their retail rate cases before the state regulatory commissions. Such state-level prudence
reviews of transmission costs do not apply to integrated utilities with unbundled transmission rates for
their provision of their retail service and wholesale-only transmission companies that are not subject to
state retail rate regulation.
While ISOs/RTOs, where they exist, have taken on a key role in the determination of transmission needs
and the development of cost-effective transmission plans to address these needs, they have only limited
means to control the costs of ISO/RTO-approved transmission projects as they progress through the
development and construction phases. Up until recently, most ISOs/RTOs relied solely on the basic
reporting process outlined in Order 890, which requires TOs to submit initial cost estimates with updates
to the estimates throughout the various phases of the transmission planning process. 75 This reporting
requirement provides some incentives for cost accountability and facilitates cost control by providing
stakeholders the opportunity to review and ask questions about initial cost estimates and the periodicallyreported updates.
As discussed in the remainder of this report, recent cost increases in major transmission projects have
prompted changes to some of the ISOs/RTOs’ cost estimation and reporting requirements. As
summarized below, several ISOs/RTOs have established or are evaluating additional cost control
measures:
•
•
ISO-NE, which implemented additional cost estimation processes and reporting requirements;
Texas, which established an oversight process for transmission planned and built under its CREZ
requirements;
•
•
•
SPP, which is in the process of developing cost estimation and reporting requirements;
The Midwest ISO, which is developing similar requirements; and
California, which allows for cost containment measures as part of its newly-approved competitive
bidding process for economic and public policy projects.
III. Summary of Selected U.S. Transmission Project Cost Control Mechanisms
A.
ISO-New England
ISO-NE has experienced a significant increase in transmission investments, having approved and placed
into service $4.6 billion of transmission over the last few years with a projected additional transmission
investment of $5.3 billion over the next 10 years. 76 Many of the approved projects received FERC
incentive returns and a number of them exceeded initial cost estimates, as illustrated by the NSTAR
74
Note that ISOs/RTOs operate regions that contain both restructured and traditionally-regulated retail electricity markets. For example, most (but not all) of the
states in the region covered by ISO-NE, NYISO and PJM have restructured retail markets, while most of the states in the region covered by the Midwest ISO and SPP still have
a traditionally-regulated industry with vertically-integrated, cost-of-service regulated utilities. ERCOT is operating in the retail restructured portion of Texas, but is not subject to
FERC regulation.
75
FERC Order 890 (paragraph 472) specifically “requires that transmission providers make available information regarding the status of upgrades identified in their
transmission plans in addition to the underlying plans and related studies. It is important that the Commission, stakeholders, neighboring transmission providers, and affected
state authorities have ready access to this information in order to facilitate coordination and oversight.” The order (issued February 16, 2007) is posted at:
http://www.ferc.gov/whats-new/comm-meet/2007/021507/E-1.pdf.
76
ISO New England, 2011 Regional System Plan: Public Meeting Draft, September 1, 2011, p. 90.
4
example summarized above. Since New England states are restructured and transmission costs are
recovered entirely through FERC-approved rates, New England state regulatory commissions voiced with
FERC their concerns over the magnitude of transmission investments, the FERC incentive ROEs, the
cost overruns, and the fact that the incentive ROEs are earned even on the cost overruns. For example,
in 2008 the New England Conference of Public Utilities Commissioners, Inc. (“NECPUC”) filed a Section
206 complaint against the New England Transmission Owners arguing that the FERC-approved incentive
ROEs were unjust and unreasonable. 77 As of May 2011, FERC had denied NECPUC’s compliant and
request for rehearing. 78
Although ISO-NE does not have a role in determining the accuracy of cost estimates or the prudence of
realized project costs, it has implemented a process for cost reviews (Planning Procedure No. 4 or PP4) 79 and project cost estimating guidelines (Attachment D to PP-4). 80 This process is applied mainly to
necessary regulated transmission projects over $5 million that will receive regional cost recovery (i.e.,
postage stamp treatment). 81 This cost review process does not apply to generator interconnection
upgrades, elective transmission upgrades, local area upgrades, and merchant transmission facilities. 82
PP-4 provides guidance on which projects are subject to cost review, what information the Project
Sponsor must provide to ISO-NE, the process for reviewing a Project Sponsor’s application, and periodic
reporting of costs associated with a project. 83 Each Project Sponsor must also complete and submit an
annual Transmission Cost Allocation (“TCA”) application. 84 If the TCA application is approved, the ISO
will allow regional cost allocation and include the sponsored project in the revenue requirement for
regional cost recovery unless disallowed by FERC in response to a Section 206 complaint.
Three groups within the ISO are charged with providing guidance and reviewing TCA applications. At the
initial planning stage, the ISO-NE Planning Advisory Committee (“PAC”) will “review proposed solutions
and may offer advisory input to the ISO as to the most cost effective and reliable solutions for the region
that meet a need identified in a Needs Assessment through the Regional System Planning Process.” 85
Project Sponsors can use this feedback in its TCA application, which is formally submitted to the
Reliability Committee (“RC”) for review and may include detailed cost breakdowns for labor, materials,
engineering, and permitting, costs of alternatives to the proposed project, and various maps and
diagrams. 86 The RC then makes a recommendation to the ISO and the ISO will provide a final written
findings and determination. Projects with significant costs and/or complexity may be subject to
information requests and additional stakeholder review. 87
Cost estimating guidelines provided in Attachment D to PP-4 are meant to ensure that different TOs use
the same approach and levels of accuracy for estimating costs at various stages of the planning and
project development process. For example, as Table 1 shows, projects at a conceptual planning stage
such as during “project initiation” can have a wide cost variance of -50% to +200% whereas cost
estimates for projects in the construction phase are required to have an uncertainty range of only +/-10%.
TOs use Attachment D guidelines to report updated cost estimates to the ISO and its PAC at least once a
year or whenever the cost estimates change by more than 10% or there is a material change in the
design of the facility. 88 The reports also get posted to the ISO website, 89 which allows other stakeholders
to protest and, if needed, get ready for a prudence challenge at FERC. This process is said to have
provided significant additional incentives for TOs to estimate costs accurately and control project costs to
77
New England Conference of Pub. Utils. Comm’rs, Inc. v. Bangor Hydro-Elec. Co., 124 FERC ¶ 61,291 (2008) (September 2008 Order).
New England Conference of Pub. Utils. Comm’rs, Inc. v. Bangor Hydro-Elec. Co., 135 FERC ¶ 61,140 (2011) (May 2011 Order).
ISO New England Planning Procedure No. 4, Procedure for Pool-Supported PTF Cost Review, September 17, 2010. Posted at: http://www.isone.com/rules_proceds/isone_plan/pp4_0_r5.pdf.
80
Posted at: http://www.iso-ne.com/rules_proceds/isone_plan/pp4_0_attachment_d.pdf
78
79
81
82
83
84
85
86
87
88
ISO New England, “Planning Procedure No. 4: Procedure For Pool-Supported PTF Cost Review” and “Attachment D” of Planning Procedure No. 4.
Id., p. 3.
Id., p. 1.
Id.
Id., p. 3.
Id., pp. 5-7.
Id.
ISO New England, Sections 1.4 and 1.10, “Planning Procedure No. 4: Procedure For Pool-Supported PTF Cost Review.”
89
The ISO reviews the Cost Estimation Update and posts the updates on the ISO website at the following address: http://www.isone.com/trans/pp_tca/req/proj_cst_est/index.html.
5
avoid overruns which, if found unreasonable, can jeopardize regional cost allocation and trigger prudence
challenges.
Table 1
Cost Estimate Types and Uncertainty Bands in ISO-NE Planning Procedures
Project Stage
Level of
Project
Definition
Estimate Type
Regional Review
RSP Listing
Target
Accuracy
Project Initiation
0% to 15%
Order of
Magnitude
Need Approval
(RSP Listing)
-50% to
+200%
Proposed Project
15% to 40%
Conceptual
Estimate
RC Review / Retain
Proposed Solution
-25% to +50%
Planning Project
40% to 70%
Planning
Estimate
PPA Approval
-25% to +25%
Final Project
Design
70% to 90%
Engineering
Estimate
Under
Construction
80% to 100%
Construction
Estimate
-10% to +10%
RC Review / TCA
Approval
-10% to +10%
Sources and Notes:
Selected data from ISO New England, Table 1: Cost Estimate types per project phase (From AACE definition &
customized for Transmission Project), Attachment D of “Planning Procedure No. 4: Procedure For Pool-Supported
PTF Cost Review.”
6
B.
Texas CREZ
ERCOT is the independent system operator for most of Texas. ERCOT differs from other ISO regions in
the U.S. because: (1) it is a single-state ISO (Texas); and (2) it is not regulated by the FERC. ERCOT
operations (including market monitoring and costs) are overseen by the Public Utility Commission of
Texas, which also regulates the rates and terms of all in-state transmission. In 2005, Texas Senate Bill
20 established a renewable energy requirement for the state and directed the PUCT to identify
Competitive Renewable Energy Zones (“CREZ”). Based on analysis performed by ERCOT, five major
zones were identified and a $4.9 billion transmission overlay was designed to interconnect a total of
18,500 MW of installed wind capacity. Companies designated to build portions of the CREZ transmission
overlay were selected by the PUCT and included both incumbents and new entrants. As part of its
implementation of CREZ, the PUCT also designated an Executive Director to establish a scope of work,
monitor the progress of assigned transmission projects, and report to the PUCT. With regard to cost
containment and deviations, the PUCT requires:
1. Within six months of granting a Certificate of Convenience and Necessity (“CCN”), the
responsible TO needs to report estimated total cost information for its designated facility based
on: CCN acquisition, right-of-way and land acquisition, engineering and design, procurement of
materials and equipment, and construction of facilities. 90 In addition, the PUCT required TOs to
report their financing methods, costs, and schedules. 91
2. Should costs deviate more than 15% from the most current estimate, TOs are required to report
any such deviations within 10 days of becoming aware of it.
3. One year after CCN approval, each designated TO will file an updated total cost estimate which
will be updated annually until the facility is placed in-service. 92
The PUCT also provides TOs, in collaboration with ERCOT, with some flexibility in proposing
modifications to planned projects to the extent that it reduces costs, increases the amount of generation it
interconnects, reduces time to construct, achieves technical efficiency, or improves cost-effectiveness. 93
As of July 2011, the original $4.9 billion (2008$) estimate for the total CREZ transmission overlay had
increased to $6.8 billion. 94 As explained in the quarterly reports of the CREZ Program Oversight, this
cost increase is due to a number of reasons including:
1. Transmission costs were based on illustrative costs before detailed engineering and design
analyses;
2. Right-of-way costs varied from illustrative costs;
3. Locations were only approximate relied on “straight-line” distances;
4. Original estimate is based on 2008$;
5. Contingency markups do not seem to have been used;
6. Original estimates did not include varying financing costs; and
7. Not all elements of the buildout were included in the original estimate such as the need for more
reactive power compensation. 95
While costs have increased, we are not yet aware of an incident where the PUCT has disallowed some of
these cost overruns or ordered modifications. However, we understand from conversations with TOs that
the cost estimation and reporting requirements significantly increased their efforts to improve the
90
Public Utility Commission Substantive Rule 25.216(f)(2).
Public Utility Commission of Texas, Order on Rehearing, Docket No. 35665, May 15, 2009, p. 21. (Note that TSP selection of Docket No. 35665 was remanded to
Docket No. 37902; however, cost reporting requirements remained unchanged.)
92
Public Utility Commission Substantive Rule 25.216(f)(5).
93
Public Utility Commission of Texas, Order on Rehearing, Docket No. 35665, May 15, 2009, p. 24.
94
Competitive Renewable Energy Zone Program Oversight, CREZ Progress Report No. 4 (July Update), prepared by RS&H for Public Utility Commission of Texas,
July 2011, p. 6.
95
Competitive Renewable Energy Zone Program Oversight, CREZ Progress Report No. 4 (July Update), prepared by RS&H for Public Utility Commission of Texas,
July 2011, pp. 4-5.
91
7
accuracy of cost estimates and control project costs to remain within an acceptable range of these
estimates.
For non-CREZ transmission builds, the PUCT allows TOs to update transmission rates twice a year to
reflect changes in invested capital. These interim rate adjustments are still subject to PUCT review and
final approval when the TO files a rate review or rate case.
C.
Southwest Power Pool
On April 27, 2010, the SPP Board approved $1.1 billion in new 345 kV upgrades called the Priority
Projects. 96 By October 2010, these engineering and construction cost estimates had increased by
$271 million, or 24%, for a variety of reasons including line re-routing due to environmental challenges,
additional reactive support, and refinement of the project scope within shared projects. 97 These costs
would be recovered through SPP’s new cost allocation methodology (“Highway/Byway”), which fully or
partially spreads costs across the entire RTO footprint for all Board-approved projects above 100 kV.
To improve project cost control and increase cost accountability, the SPP Regional State Committee
(“RSC”), comprised of state regulatory commission representatives from each state in the SPP region,
made five motions to address the issue of project cost management last fall. 98 Specifically the RSC
recommended that:
1. SPP review what is the best manner to address significant cost increases and/or overruns of
transmission projects that are regionally funded.
2. SPP review the “Novation Process” 99 and report to the RSC by April 2011.
3. SPP consider establishing design & construction standards for transmission projects above
100 kV that are fully or partially regionally funded.
4. SPP evaluate how cost estimates are established for transmission projects before cost-benefit
analyses are performed.
5. The CAWG 100 study various methods on how costs that exceed some standard can be
addressed with different cost allocation mechanisms and recommend strategies to the RSC.
Thus far SPP working groups have developed, and the RSC has approved, a series of improvements
grouped into the following four topics:
1. Design Best Practices and Performance Criteria – Develop best practices and performance
criteria so deviations and variations can be tracked and reported.
2. Tracking/Estimates – Implement a Standardized Cost Estimating Reporting Template (“SCERT”)
with increasing cost estimate requirements and narrowing variance bands as the project moves
from conceptual design to construction.
3. Estimates Outside a Bandwidth – Establish allowed cost variance bands and processes for
addressing deviations outside of the band.
4. Assignments and Novations – The RSC would review assignments and novations for cost
containment measures and potentially use a competitive bidding process if the assignment or
novation is not acceptable. 101
With respect to the last recommendation, note that SPP assigns Board-approved upgrades to incumbent
TOs within the RTO via a notice to construct (“NTC”). The incumbent TO has a 90 day right of first
refusal where it can “assign” the legal right to build an upgrade to a third party while retaining a legal
96
SPP, “SPP Approves Construction of New Electric Transmission Infrastructure To Bring $3.7 Billion in Regional Benefits,” April 27, 2010.
SPP, Priority Project Update, presented by Bruce Rew to the SPP Regional State Committee, October 25, 2010.
SPP Regional State Committee, “ITP20 and Priority Projects Update,” meeting notes for October 25, 2010 meeting, p. 5.
99
SPP has a process where an incumbent Transmission Owner has the option to assign its legal obligation to construct SPP Board-approved projects in its service
territory to a third party of its choosing.
100
Cost Allocation Working Group, a group under the Regional State Committee.
101
SPP RSC Cost Allocation Working Group (CAWG), “CAWG Report: Novations of SPP Approved Transmission Projects Reconsidered,” July 25, 2011.
97
98
8
obligation that the project is built. 102 On the other hand, the incumbent TO can use the novation process
to completely release itself from any legal obligation to build and assign it to a third party of its
choosing. 103 A cost containment concern arises from the novation process should an incumbent TO
assign a project to a TransCo affiliate that receives a higher return on equity (i.e., FERC-approved
incentive rates) “resulting in higher costs to ratepayers throughout the SPP footprint, with no apparent
increase in benefits.” 104
The newly formed SPP Project Cost Task Force (“PCTF”) has developed a revised process to evaluate
project costs from the conceptual stage through construction. Table 2 summarizes the proposal in the
PCTF’s most recent whitepaper, 105 showing the cost estimates and variance bands that will be used in
project evaluations. For example, at the conceptual stage of a project a variance band of -50% to + 100%
of estimated project costs is acceptable for including the project in the Integrated Transmission Plan
(“ITP” for both the 20-year and 10-year analyses) but only a -20% to +20% range variance band is
acceptable as the project moves into the construction phase. Of the five RSC motions, only the last one,
directed at the CAWG, remains outstanding as of the publication date of this report.
Table 2
Cost Estimate Stage Definition as Proposed by the SPP Project Cost Task Force
Estimate Name*
Project
Definition
End Usage
Precision
Bandwidth
Conceptual
0% to 10%
Concept screening for
ITP20/ITP10
-50% to + 100%
Study Phase
10% to 20%
Feasibility study and plan
development for ITP10/ITPNT
-30% to +30%
Notice to Construct is
issued
20% to 40%
Final baseline (Conditional
Notice to Construct or Notice
to Construct)**
-20% to +20%
Project design and
construction
40% to 100%
Design after Notice to
Construct issued and build the
project
-20% to +20%***
Sources and Notes:
Selected information from “Table 1: Cost Estimate Stage Definition” of SPP Project Cost Task Force, Project Cost Task Force
Whitepaper, July 19, 2011, p. 8.
* The conceptual estimate will be prepared by SPP. All subsequent estimates will be prepared by the designated TO(s).
**SPP board approval required to reset the baseline.
***Actual cost is expected to be within +/-20% of final baseline estimate.
102
SPP Strategic Planning Committee Task Force, “Response to RSC Motions,” June 16, 2011, p. 5. Note that the 90 day right of first refusal will likely be revised in
accordance to FERC Order 1000, Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities.
103
SPP Strategic Planning Committee Task Force, “Response to RSC Motions,” June 16, 2011, p. 5.
104
SPP RSC Cost Allocation Working Group (CAWG), “CAWG Report: Novations of SPP Approved Transmission Projects Reconsidered,” July 25, 2011.
105
SPP Project Cost Task Force, Project Cost Task Force Whitepaper, July 19, 2011.
9
D.
Midwest ISO
The Midwest ISO does not currently monitor and validate TO-reported costs but relies on quarterly
reporting of ISO-approved project costs by transmission owners to provide transparency as required
under FERC Order 890.
Under its planning function, the Midwest ISO is reviewing the cost effectiveness of proposed transmission
projects. For example, the Midwest ISO Board is currently reviewing a group of high-voltage Multi Value
Projects (“MVP”) estimated to cost over $4 billion. 106 These MVPs are part of a larger footprint-wide
transmission expansion to address various needs such as reliability and renewable integration and costs
would be eligible for regional cost allocation (i.e., postage stamp cost allocation).
E.
California ISO
The California ISO (“CAISO”) is a single-state ISO under FERC jurisdiction. California also unbundled the
transmission component of its retail rates, which makes transmission rates fully FERC jurisdictional.
In its recently FERC-approved Revised Transmission Planning Process (“RTPP”), CAISO implemented
the option of a competitive open bidding process for transmission projects that would meet public policy
and economic needs (i.e., not reliability driven projects). 107 CAISO would first identify such needs
through its planning process so that all interested developers can then propose projects to meet these
needs. Should CAISO receive competing proposals to build the same or similar transmission facility, it
will rely on 10 factors to evaluate the project, one of which is a voluntary demonstration of cost
containment measures or willingness to enter into a binding cost cap that would preclude the project
sponsor from recovering costs above the cap from the CAISO’s tariff-based cost recovery mechanism. 108
While cost containment measures or a binding cost cap may reflect favorably on a proposed project, the
CAISO declines to use the estimated cost of a project as a deciding factor to select amongst competing
proposals “because such a criterion would provide an incentive for Project Sponsors to deliberately
underestimate their costs, and the ISO, unlike public utility commissions … has no authority to enforce
compliance with such estimates.” 109 In its conditional approval of the RTPP, FERC agreed with CAISO’s
approach. 110 At this point the RTPP process is new and untested and may potentially undergo some
revision in response to FERC’s recent Order 1000 on U.S. transmission planning and cost allocation.
106
107
108
109
110
Midwest ISO, “Midwest ISO Board Approves MTEP10 Endorsing 231 New Projects,” December 2, 2010.
California ISO, Revised Transmission Planning Process Proposal, Docket No. ER10-1401, June 7, 2010.
California ISO, Order Conditionally Accepting Tariff Revisions and Addressing Petition for Declaratory Order, Docket No. ER10-1401, December 16, 2010, p. 65.
California ISO, Revised Transmission Planning Process Proposal, Docket No. ER10-1401, June 7, 2010, p. 9.
California ISO, Order Conditionally Accepting Tariff Revisions and Addressing Petition for Declaratory Order, Docket No. ER10-1401, December 16, 2010, p. 71.
10
APPENDIX F
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