Electricity Transmission Cost Allocation

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Prepared for Members and Committees of Congress

Electricity Transmission Cost Allocation

Summary

Perhaps the most contentious electricity transmission financing issue is cost allocation for new

interstate transmission lines—that is, deciding which electricity customers pay how much of the

cost of building and operating a new transmission line that crosses several states. This report

provides background and analysis of current transmission cost allocation policy and issues.

For many years, the Federal Energy Regulatory Commission (FERC) declined to go beyond

establishing general principles as set forth in its Order No. 890, which addressed “undue

discrimination and preference” in the providing of transmission services. Transmission cost

allocation proposals made by transmission service providers were therefore reviewed by FERC to

ensure compliance with the general principles outlined in Order No. 890 and the Federal Power

Act (FPA). However, there were calls for FERC to provide a clearer framework for cost

allocation. The decision of the Seventh Circuit in Illinois Commerce Commission v. FERC, to

reject a cost allocation plan approved by FERC which would have permitted “socialization” of

the costs for some new transmission projects (i.e., allowing the costs to be spread widely among

ratepayers in the PJM Interconnection, even those who do not substantially or clearly benefit

from a project) encouraged FERC to seek more clarity with respect to cost allocation. Congress

also entered the fray in the form of legislative proposals that would amend the Federal Power Act

to include new transmission cost allocation guidelines that FERC would be required to follow.

In 2009 FERC decided to take an in-depth look at cost allocation and other transmission planning

issues as part of a new docket. FERC observed that its “best remaining opportunity to eliminate

barriers to new transmission construction may therefore be to provide greater certainty in its

policies for allocating the cost of new transmission facilities, particularly for facilities that cross

multiple transmission systems.” FERC requested comments from stakeholders on transmission

planning issues.

After receiving and reviewing comments from stakeholders and offering a proposed rule in 2010,

FERC published Order No. 1000, a final rule reforming FERC’s transmission planning and cost

allocation requirements for transmission service providers, on July 21, 2011. The final rule

required transmission service providers to (1) participate in a regional transmission planning

process; (2) amend their transmission tariffs to provide for consideration of public policy; (3)

remove from their tariffs a federal right of first refusal for certain new transmission facilities; and

(4) improve coordination between neighboring transmission planning regions.

The Final Order comes as state renewable portfolio standards and the upcoming U.S.

Environmental Protection Agency (EPA) regulations for coal power plants may drive demand for

new transmission lines. The uncertainty regarding the implications for generation resources of

upcoming EPA regulations has caused some utilities to delay decisions on building new

generation, with plans to satisfy (at least interim) power needs from power markets until the

regulatory clarity they seek is provided.

This report analyzes recent developments concerning transmission cost allocation leading up to

Order No. 1000, as well as the contents of the order and their potential impact on the transmission

planning process in the future. FERC acknowledges that some key questions may only be

answered in the compliance filing process.

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Electricity Transmission Cost Allocation

Contents

Introduction...................................................................................................................................... 1

Background and History .................................................................................................................. 2

The Federal Power Act .............................................................................................................. 2

Development of the Interstate Transmission Grid and FERC Oversight Prior to Order

No. 890 ................................................................................................................................... 3

FERC Order No. 890 ................................................................................................................. 5

Examples of Cost Allocations Under Order 890 ....................................................................... 6

PJM Interconnection ........................................................................................................... 7

New England ISO (NE-ISO) ............................................................................................... 8

Florida Power and Light Company (FPL) ........................................................................... 8

Duke Energy Carolinas and Progress Energy Carolinas ..................................................... 8

Concluding Comments on Cost Allocation Examples ........................................................ 9

Illinois Commerce Commission v. FERC .................................................................................. 9

Legislative Efforts to Dictate Transmission Cost Allocation Principles.................................. 11

Order No. 1000 .............................................................................................................................. 12

Background to the Rulemaking and Initial Comments............................................................ 12

The Final Rule ......................................................................................................................... 15

Planning Requirements ..................................................................................................... 15

Cost Allocation Requirements ........................................................................................... 15

Nonincumbent Developer Requirements .......................................................................... 17

Compliance ....................................................................................................................... 18

Specific Observations on the Final Rule ................................................................................. 18

Planning Requirements ..................................................................................................... 18

Cost Allocation Requirements ........................................................................................... 19

Nonincumbent Developer Requirements .......................................................................... 20

General Comments .................................................................................................................. 21

Update on Order 1000 ....................................................................................................... 22

Contacts

Author Contact Information........................................................................................................... 22

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Electricity Transmission Cost Allocation

Introduction

Construction of new long-distance transmission lines has become a hotly debated energy policy

issue. Advocates see enhancements to the transmission grid as necessary for exploiting remote

sources of renewable power and improving the reliability of the transmission system. Others

argue that there are less costly and intrusive means of meeting energy needs than a large

transmission build-out.

Estimates of the cost of expanding the transmission grid to increase renewable power delivery

and other goals run into the tens of billions of dollars. For example (all figures in nominal

dollars):

•

The estimated transmission cost of the Joint Coordinated System Plan to bring

Great Plains wind power to the East Coast ranges from $49 billion to $80

billion.1

•

A Department of Energy (DOE) study of expanding the use of wind power

estimated transmission expansion costs of $60 billion by 2030.2

•

A study of transmission funding requirements for all purposes for the period 2010

to 2030 estimated total costs of about $300 billion.3

•

The North American Electric Reliability Corporation (NERC) identified 39,000

circuit-miles of projected high-voltage transmission over the next 10 years, with

roughly one-third of these transmission facilities used to integrate variable and

renewable resources.4

Perhaps the most contentious transmission financing issue is cost allocation for new interstate

transmission lines—that is, determining which customers must bear the costs of building and

operating new transmission lines that cross several states. This report provides background and

analysis of current transmission cost allocation policy and issues. The balance of the report is

organized as follows:

•

Background and history, including a discussion of federal authority under the

Federal Power Act.

•

Cost allocation policy at the federal and state levels in the years prior to the

adoption by the Federal Energy Regulatory Commission (FERC) of Order No.

1000.5

Executive summary to the Joint Coordinated System Plan 2008, p. 6, http://www.jcspstudy.org/. Note that the cost of

the transmission is modest compared to the estimated cost of the generation needed to meet demand and, in one

scenario, renewable energy goals ($674 billion to $1,050 billion).

U.S. Department of Energy, 20% Wind Energy by 2030, Washington, D.C., July 2008, p. 98,

http://www1.eere.energy.gov/windandhydro/pdfs/41869.pdf.

Marc Chupka et al., Transforming America’s Power Industry: The Investment Challenge 2010 - 2030, prepared by the

Brattle Group for The Edison Foundation, Washington, DC, November 2008, p. 40, http://www.eei.org/ourissues/

finance/Documents/Transforming_Americas_Power_Industry.pdf.

North American Reliability Corporation, 2010 Long-Term Reliability Assessment, October 2010,

http://www.nerc.com/files/2010%20LTRA.pdf.

Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000,

76 FR 49,842 (August 11, 2011), 136 FERC ¶ 61,051 (2011).

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•

A review of the transmission planning and cost allocation reforms in Order No.

1000.

Background and History

The Federal Power Act

The authority of the Federal Energy Regulatory Commission (FERC) to regulate interstate

electricity transmission is derived primarily from Sections 205 and 206 of the Federal Power Act

(FPA).6 Section 205 of the FPA provides that all rates and charges for the transmission of electric

energy subject to FERC’s jurisdiction, as well as rules and regulations affecting those rates, must

be “just and reasonable,” and that no public utility’s rates may “unduly discriminate” against any

customers.7 FERC’s section 205 authority has been characterized as “an essentially passive and

reactive” role.8

However, Section 206 of the FPA gives FERC a broader and more proactive rate authority:

Whenever the Commission, after a hearing had upon its own motion or upon complaint, shall

find that any rate, charge, or classification, demanded, observed, charged or collected by any

public utility for any transmission ... subject to the jurisdiction of the Commission, or that

any rule, regulation, practice, or contract affecting such rate, charge or classification is

unjust, unreasonable, unduly discriminatory or preferential, the Commission shall determine

the just and reasonable rate, charge, classification, rule, regulation, practice or contract to be

thereafter observed and in force, and shall fix the same by order.9

Section 206 thus permits FERC to make changes to existing utility rates, including transmission

charges, either on its own initiative or at the request of an interested party. In order to make such

changes, FERC must (1) find that the existing rates or practices are unjust, unreasonable, unduly

discriminatory, or preferential; and (2) show that its proposed changes are just and reasonable.10

Section 206 also allows FERC to establish a just and reasonable rule, regulation, or practice “to

be thereafter observed and in force,” and to “fix the same by order.”11

The statutory authority found in Section 206 of the FPA gives FERC broad authority to establish a

set of general principles to be applied in setting just and reasonable rates upon a finding of unjust,

unreasonable, unduly discriminatory, or preferential rates or practices in the industry. FERC has

cited its Section 206 authority in promulgating other significant rulemakings related to interstate

electricity transmission facilities, including Order No. 200012 (providing for the creation of

18 U.S.C. §824 et seq.

18 U.S.C. §824d(a) and (b).

City of Winfield v. FERC, 744 F.2d 871, 876 (D.C. Cir. 1984).

18 U.S.C. §824e(a).

Atlantic City Electric Company v. FERC, 295 F.3d 1, 9 (D.C. Cir. 2002) (citations omitted).

16 U.S.C. §824e(a).

Regional Transmission Organizations, Order No. 2000, 65 FR 809 (January 6, 2000), FERC Stats. & Regs., ¶ 31,089

(1999), order on reh’g, Order No. 2000–A, 65 FR 12,088 (March 8, 2000), FERC Stats. & Regs. ¶ 31,092 (2000),

affirmed sub nom. Public Utility District No. 1 of Snohomish County, Washington, et al. v. FERC, 272 F.3d 607 (D.C.

Cir. 2001).

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Regional Transmission Organizations to manage electricity transmission grids) and Orders 88813

and 89014 (requiring utilities to provide open access to transmission facilities and creating a pro

forma tariff for utilities to adopt for their transmission services). Most recently, FERC cited its

Section 206 authority when it issued Order No. 1000, the order that altered Commission policy on

transmission planning and cost allocation.

Development of the Interstate Transmission Grid and FERC

Oversight Prior to Order No. 890

FERC’s transmission cost allocation activities have often addressed complex projects with one or

more of the following types of characteristics:

•

May traverse multiple utility service territories and cross the boundaries between

power system planning areas.

•

May have multiple owners.

•

May provide benefits to many and diverse beneficiaries. These beneficiaries may

be difficult to accurately identify, and it may be even more difficult to quantify

the benefits.

However, cost allocation for these and other transmission lines was less contentious—or at least

less visible and pressing at the national level—in the past because of the nature of the industry

itself and federal/state regulation of the industry prior to the mid-1990s. Transmission lines were

historically constructed primarily by investor-owned utilities subject to traditional cost of service

regulation by state utility commissions. These utilities sold a “bundle” of electric power

transmission, generation, and distribution services to ratepayers as a single price. Customers in

the utility’s service area generally paid a share of the costs of transmission investments, whether

or not a particular transmission investment was of value to the customer; this universal sharing of

expenses is referred to as the “socialization” of costs.

Under this regulatory regime, cost allocation was therefore generally not a complex issue, since

the beneficiaries of the transmission service and the customers paying for the services were, in

effect, assumed to be the same—the utility’s entire set of captive ratepayers. As one analysis

points out, the bundling of costs made it possible and acceptable for cost allocation issues to be

“swept under the rug.”15

Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public

Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21,540 (May

10, 1996), FERC Stats. & Regs. ¶ 31.036 (1996), order on reh’g, Order No. 888–A, 62 FR 12,274 (March 14, 1997),

FERC Stats. & Regs. ¶ 31,048 (1997), order on reh’g, Order No. 888–B, 81 FERC ¶ 61,248 (1997), order on reh’g,

Order No. 888–C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group,

et al. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002).

Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 Fed. Reg. 12,266

(March 15, 2007), FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, 73 Fed. Reg. 2984 (January 16,

2008), FERC Stats. & Regs. ¶ 31,261 (2007).

Working Group for Investment in Reliable and Economic Electric Systems (WIRES), A National Perspective on

Allocating the Costs of New Transmission: Investment: Practice and Principles, September 2007, p. 32, footnote 34,

http://www.wiresgroup.com/images/Blue_Ribbon_Panel_-_Final_Report.pdf.

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Cost allocations, and related transmission planning issues, were also less contentious and visible

because of the historical development of the electric power grid. Transmission lines were first

built in the early 20th century by single utilities to move electricity to population centers from

relatively nearby power plants. As generation and transmission technology advanced, the

distances increased, but the model of a single entity building lines within its own service territory

to supply its own load still predominated. Over time, these local grids began to interconnect, due

to utilities building jointly owned power plants and because power companies began to grasp the

economic and reliability benefits of being able to exchange power.16 Nonetheless, this pattern of

development did not emphasize the construction of very long-distance inter-regional lines

involving multiple owners and jurisdictions, the kinds of projects likely to have difficult cost

allocation issues.

Cost allocation issues have become pressing in part because of the restructuring of the electric

power generation and transmission industries that began in the late 1970s. The Public Utility

Regulatory Policies Act of 1978 and the Energy Policy Act of 1992 had as one of their aims the

introduction of competition into generation service. In order to facilitate the ability of non-utility

generators to access the transmission grid, in 1996 FERC issued Orders 888 and 889, to establish

an open access regulatory regime for the transmission grid.17 These orders directed transmission

owners and operators to open their system to any connected generator or load on a “nondiscriminatory” basis (that is, without giving preference to their own generation or load). Rates

are to be cost or market based, and rates and conditions of service are to be embodied in an open

access transmission tariff (OATT) approved by FERC.

By allowing non-utility generators and loads to use the transmission system, open access broke

the formerly rigid link between the entities that built transmission and their captive ratepayers.

Now a new transmission line could be used by multiple entities to transmit or receive power. The

operational links between utilities and transmission were further weakened by FERC’s policy of

promoting regional transmission organizations (RTOs) in the 1990s and 2000s. In RTOs, utilities

retain ownership of the transmission grid but operational control is exercised by the RTO. The

object is to further ensure that the transmission grid is operated in a non-discriminatory fashion to

the benefit of all market participants.18

The restructuring of the transmission market had several consequences for transmission cost

allocation and planning:

•

Cost allocation became more complex and contentious because the clear links

that existed under traditional regulation between the parties that built, operated,

and benefited from new transmission lines were broken.

•

Under the traditional regulatory regime, distinctions between transmission

additions aimed at improving system reliability and those aimed at reducing the

costs of operating the power system (i.e., “economic” projects) had little

The power grid in the conterminous states now consists of three large interconnections: eastern, western, and

ERCOT (covering most of Texas). The linkages between these interconnections are limited and for most purposes the

three systems can be viewed as operationally independent.

FERC’s economic authority extends to “public utilities” engaged in interstate commerce, as defined by the Federal

Power Act.

The term independent system operator (ISO) is often used interchangeably with RTO. Strictly speaking, an

organization is an RTO only if it has been so designated by FERC, but these organizations operate the same.

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meaning. In the open access regime the distinction between reliability projects

and economic projects became an important one, since each type of project could

benefit different groups of customers to different degrees.

•

In the open access regime, much of the responsibility for transmission planning

shifted from utilities to either RTOs or, in the markets without RTOs, a plethora

of other planning organizations built around utilities, generators, and other

stakeholders.19

FERC Order No. 890

Prior to the adoption of Order No. 1000 in the summer of 2011, FERC’s most significant

articulation of the principles applicable to transmission cost allocation was Order No. 890, issued

by FERC in February 2007. The purpose of the order was to improve the operation of the open

access transmission market created by Order Nos. 888 and 889, including establishment of cost

allocation procedures as an element of transmission planning.20

Order No. 890 established nine transmission planning principles, of which one is “Cost

Allocation—a process must be included for allocating costs of new facilities that do not fit under

existing rate structures, such as regional projects.”21 This principle was included because FERC

found that “[t]he manner in which the costs of new transmission are allocated is critical to the

development of new infrastructure. Transmission providers and customers cannot be expected to

support the construction of new transmission unless they understand who will pay the associated

costs.”22

Examples of these non-RTO planning organizations include ColumbiaGrid in the northwest

(http://www.columbiagrid.org/), CapX 2020 in and around Minnesota (http://www.capx2020.com/), and the North

Carolina Transmission Planning Collaborative (http://www.nctpc.org/nctpc/).

The objectives of Order 890 were to amend “the regulations and the pro forma open access transmission tariff

adopted in Order Nos. 888 and 889 to ensure that transmission services are provided on a basis that is just, reasonable

and not unduly discriminatory or preferential. The final rule is designed to: (1) strengthen the pro forma open-access

transmission tariff, or OATT, to ensure that it achieves its original purpose of remedying undue discrimination; (2)

provide greater specificity to reduce opportunities for undue discrimination and facilitate the Commission’s

enforcement; and (3) increase transparency in the rules applicable to planning and use of the transmission system.”

Preventing Undue Discrimination and Preference in Transmission Service, FERC Order No. 890, 72 Fed. Reg. 12266

(March 15, 2007), FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, 73 FR 2984 (January 16, 2008),

FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g and clarification, Order No. 890-B, 73 FR 39092 (July 8, 2008),

123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 74 FR 12540 (March 25, 2009), 126 FERC ¶ 61,228

(2009), order on clarification, Order No. 890-D, 74 FR 61511 (November 25, 2009), 129 FERC ¶ 61,126 (2009).

The other eight principles are (1) Coordination—the process for consulting with transmission customers and

neighboring transmission providers; (2) Openness—planning meetings must be open to all affected parties; (3)

Transparency—access must be provided to the methodology, criteria, and processes used to develop transmission

plans; (4) Information Exchange—the obligations of and methods for customers to submit data to transmission

providers must be described; (5) Comparability—transmission plans must meet the specific service requests of

transmission customers and otherwise treat similarly-situated customers (e.g., network and retail native load)

comparably in transmission system planning; (6) Dispute Resolution—an alternative dispute resolution process to

address both procedural and substantive planning issues must be included; (7) Regional Participation—there must be a

process for coordinating with interconnected systems; (8) Economic Planning Studies—study procedures must be

provided for economic upgrades to address congestion or the integration of new resources, both locally and regionally.

Id.

FERC Stats. & Regs. ¶ 31,241 at P 496.

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A particular concern of FERC was cost allocation for long-distance transmission projects that

would cross multiple utility service areas and state jurisdictions. Another concern was the

treatment of projects that would yield economic benefits to multiple parties. According to FERC:

… we are not modifying the existing mechanisms to allocate costs for projects that are

constructed by a single transmission owner and billed under existing rate structures. Our

intent is not to upset existing cost allocation methods applicable to specific requests for

interconnection or transmission service under the pro forma OATT. The cost allocation

principle discussed herein is intended to apply to projects that do not fit under the existing

structure, such as regional projects involving several transmission owners or economic

projects….[emphasis added]23

FERC chose to leave transmission owners and operators with significant but not unlimited

latitude in establishing cost allocation policies. On the one hand, FERC stated that it “will not

impose a particular allocation method for such projects, but rather will permit transmission

providers and stakeholders to determine their own specific criteria which best fit their own

experience and regional needs.”24 On the other hand, FERC did conclude that “some overall

guidance [on cost allocation] is appropriate.”25 FERC’s overriding premise was that “‘[a]llocation

of costs is not a matter for the slide-rule. It involves judgment on a myriad of facts. It has no

claim to an exact science.’”26 FERC would therefore “allow regional flexibility in cost allocation

and, when considering a dispute over cost allocation, exercise our judgment by weighing several

factors.”27 Three factors were listed by FERC:

First, we consider whether a cost allocation proposal fairly assigns costs among participants,

including those who cause them to be incurred and those who otherwise benefit from them.

Second, we consider whether a cost allocation proposal provides adequate incentives to

construct new transmission. Third, we consider whether the proposal is generally supported

by state authorities and participants across the region.

These three factors are interrelated. For example, a cost allocation proposal that has broad

support across a region is more likely to provide adequate incentives to construct new

infrastructure than one that does not. The states, which have primary transmission siting

authority, may be reluctant to site regional transmission projects if they believe the costs are

not being allocated fairly. Similarly, a proposal that allocates costs fairly to participants who

benefit from them is more likely to support new investment than one that does not. Adequate

financial support for major new transmission projects may not be obtained unless costs are

assigned fairly to those who benefit from the project.28

Examples of Cost Allocations Under Order 890

The transmission planning processes required by Order 890 were generally filed by utilities and

RTOs (in the form of amendments to their OATTs) by December 7, 2007. The processes were

Id. at P 558.

Id.

Id. at P 559.

Id. at P 559, citing Colorado Interstate Gas Co. v. Federal Power Commission, 324 U.S. 581, 589 (1945).

Id.

Id. at P 560. See also FERC’s Transmission Planning Process Staff White Paper, August 2, 2007, pp. 17-19,

http://www.ferc.gov/industries/electric/indus-act/oatt-reform/order-890/white-paper.pdf.

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usually accepted by FERC as filed or accepted with requirements for amendment to ensure

compliance with Order 890’s planning principles. Several examples are shown below to illustrate

the diversity of approaches used throughout the nation. Although most of these approaches

involve a combination of beneficiary pays (also referred to as “participant funding”) and

socialization of costs, the details are wholly dissimilar. While Order No. 1000 (discussed in detail

later in this report) has been adopted recently, FERC will continue to allow the regions to define

their own allocation methods. Therefore, the methods briefly summarized here are useful

examples of the methodology that may carry over to filings in compliance with Order No. 1000.

PJM Interconnection29

The cost allocation process established by PJM and approved by FERC allocated costs in terms of

the physical characteristics and purpose of the proposed transmission line:

•

The cost of projects planned by individual utilities to meet local needs rather than

system-wide needs are to be charged to the customers in the zones of PJM that

benefit (i.e., beneficiary pays).

•

Beneficiaries are also to pay for new projects with a rating of less than 500

kilovolts (kV). FERC directed PJM and its customers to develop a standard

methodology for allocating the costs of such projects.

•

For “backbone” transmission projects with a rating of 500 kV or greater—that is,

the proposed lines with the greatest capability to move large amounts of

electricity—costs would be socialized throughout the PJM Interconnection (i.e.,

all customers within PJM would pay a portion of the costs of the facilities,

regardless of their location relative to where the upgrades were made, on the

assumption that all customers would benefit from these “backbone” upgrades).30

The socialization of the costs of 500 kV and greater facilities was controversial from the outset;

for example, the Illinois utility commission reportedly characterized it as “not only unjust and

unreasonable, but patently irrational.”31 On August 6, 2009, the United States Court of Appeals

for the Seventh Circuit, in response to petitions filed by the Ohio and Illinois utility commissions,

rejected PJM’s cost socialization approach and remanded the issue to FERC. The court stated that

FERC is not authorized to approve a pricing scheme that requires a group of utilities to pay

for facilities from which its members derive no benefits, or benefits that are trivial in relation

to the costs sought to be shifted to its members.… No doubt there will be some benefit to the

midwestern utilities just because the network is a network, and there have been outages in

the Midwest. But enough of a benefit to justify the costs that FERC wants shifted to those

utilities? Nothing in the Commission’s opinions enables an answer to that question.”32

PJM is the RTO covering a large area centered around the mid-Atlantic region of the United States. “PJM” originally

stood for Pennsylvania, New Jersey and Maryland, but the RTO now encompasses all or part of 13 states and the

District of Columbia.

FERC, Order No. 494, PJM Interconnection LLC, Dockets EL-05-121-000 and -002, April 19, 2007; PJM

Interconnection, Compliance filing in response to FERC Order No. 890, Docket OA08-32, December 7, 2009.

Jason Fordney, “Exelon, Illinois Commission and DP&L Protest PJM Allocation of Upgrade Costs,” Platts Electric

Utility Week, February 9, 2009.

Illinois Commerce Comm'n v. FERC, 576 F.3d 470, 476-477 (7th Cir. 2009) (italics in original) (citations omitted).

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This decision is discussed in greater detail below.

New England ISO (NE-ISO)

In NE-ISO the costs of reliability investments with region-wide benefits are paid for by all

customers in the RTO. A reported $4 billion in reliability investments have been made and

allocated region-wide since 2004. The ISO’s rules also provide for cost socialization for

economic investments that provide regional benefits, but “[t]hus far [i.e., through November

2009] there have been no Market Efficiency Upgrades determined to be needed through the

regional system planning process.”33 This experience illustrates how cost socialization for

reliability upgrades can be more easily justified than for economic upgrades. This is because a

failure at one point in a regional grid can potentially disrupt the entire system, while an economic

upgrade may benefit only a subset of the region, making it harder to justify region-wide cost

allocation.

Florida Power and Light Company (FPL)

FPL follows cost allocation procedures approved by the Florida Reliability Coordinating Council

(FRCC), the regional electric grid reliability entity (but not a RTO) covering most of Florida. In

brief, a party may be able to recover a portion of its costs for a new transmission project intended

to serve incremental load or generation if, among other factors, the upgrade will affect the

reliability of the FRCC grid and the transmission owner participates in the FRCC Regional

Transmission Planning Process. If these criteria are met, a portion of the costs associated with the

project will be split evenly between the customers in the zone with the need for the project and

the “sources or cluster of sources” that are creating the need.34

Duke Energy Carolinas and Progress Energy Carolinas

These utilities made a joint filing in response to Order 890. Both companies participate in the

North Carolina Transmission Planning Collaborative (NCTPC) regional transmission planning

process and adopted the organization’s standard cost allocation approach. In summary, that

approach defines exceptions to the general principle that investments in the transmission grid

should be allocated to the initiating utility company and its ratepayers (i.e., beneficiaries pay).

One exception is “Regional Reliability Projects” included in the NCTPC planning process. These

are projects undertaken by one utility that has region-wide reliability benefits; in this case costs

are allocated to other utilities in proportion to the savings each company receives by not having to

undertake its own reliability project.

The second exception is Regional Economic Transmission Path projects that reduce the cost of

transmission service across two or more utility systems. These are envisioned as projects with

multiple participants who will pay the upfront costs of the project. In return the participants will

receive back their investment via payments made by the utilities over a period of up to 20 years.

The utilities in turn will have the opportunity to recover the cost of these payments from

FERC Docket AD09-8-000, Transmission Planning Processes Under Order No. 890, “Comments of New England

Power Pool,” November 23, 2009, p. 3.

Florida Power & Light Co., Order 890 OATT Compliance Filing – Attachment K, FERC Docket No. OA08-29,

December 7, 2009, pp. 14-16.

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ratepayers.35 Economic projects must be included in the NCTPC planning process to qualify for

this type of cost allocation.36

Concluding Comments on Cost Allocation Examples

The examples presented above are only four of the dozens of Order No. 890 cost allocation

filings made with FERC. Nonetheless, they do illustrate several points about current cost

allocation policy at the federal and state levels. First, there is no uniformity in the cost allocation

procedures, and at least to date FERC has declined to go beyond establishing general principles.

Second is the regional focus of all four processes. NE-ISO and PJM are multi-state RTOs and

inherently take a regional perspective, but even the FPL, Duke, and Progress Energy processes

are tied back to regional transmission planning organizations. This is consistent with FERC’s

efforts to encourage a regional perspective on transmission planning that incorporates many

stakeholders in the planning process. Third, these examples illustrate the complexity involved in

socializing transmission costs. The PJM process was rejected by a federal court and remanded to

FERC. The NE-ISO process for socializing the costs of economic projects has never been used.

The NCTPC and FPL cost socialization processes for regional reliability upgrades are fairly

straightforward, but the NCTPC process for socializing economic project costs involves a multistep procedure extending for up to 20 years. FPL did not include socialization of economic

projects in its filing.

Illinois Commerce Commission v. FERC

The debate over the proper method of allocation of transmission costs has not been confined to

the executive and legislative branches of government. In Illinois Commerce Commission v.

FERC,37 the U.S. Court of Appeals for the Seventh Circuit heard a challenge to FERC’s approval

of a cost allocation proposal for certain new transmission facilities in the PJM Interconnection.38

Two state utility commissions in Midwestern states protested a FERC-approved allocation of

transmission costs for the PJM interconnection that required pro rata contributions from all

utilities in the region; that is, the utilities in the PJM region would increase their rates by a

uniform amount sufficient to cover the cost of the new facilities.39 According to the court, FERC’s

rationale for this pro rata increase was that (1) some of the PJM members entered into similar pro

rata cost sharing agreements in the past and would like to continue to allocate costs in that

manner; (2) the burden of determining which parties would benefit from the new transmission

(and to what degree they would benefit) would be onerous and would likely result in litigation;

and (3) that every member of the PJM Interconnection would benefit from the new transmission

facilities because the reliability of the entire network would improve.40

That is, the utilities involved retain ownership in the project and recover its capital costs from ratepayers.

Duke Energy Carolinas LLC and Progress Energy Carolinas LLC., Order 890 OATT Compliance Filing –

Attachment K, FERC Docket Nos. OA08-50 and -51, December 7, 2009, pp. 15 – 16, and the attached “NCTPC

Transmission Cost Allocation” statement.

576 F.3d 470 (7th Cir. 2009).

The court also heard a challenge to the approved cost allocation method for certain upgrades to existing facilities;

however, that discussion is not germane to the subject of this memorandum, and therefore is not discussed here.

576 F.3d at 474.

Id.

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The court held that the FERC-approved pro rata rate increase for recovery of transmission costs

was not supported by substantial evidence.41 The court quickly dispatched FERC’s two arguments

in favor of the reasonableness of the pro rata rates. According to the court, the fact that previous

arrangements among the PJM members had pro rata cost sharing arrangements in the past carried

no weight.42 The court rejected FERC’s argument regarding the difficulty of measuring benefits

and the likelihood of litigation, because of an absence of evidence of the relative difficulty of

assessing the benefits.43 The court did not dismiss the possibility of such a finding, noting that

feasibility concerns can play a role in rate determinations.44 However, in this instance, the court

found that FERC had not offered a sufficient explanation for this factor and the role it played in

the rate decision.45

The court spent more time addressing FERC’s third line of reasoning: that the new transmission

facilities would benefit every PJM member, and therefore that the costs should be allocated

among all of them. As the court acknowledged, even though the purpose of the new facilities was

to satisfy demand for eastern customers in the PJM system, the entire PJM system would benefit

from greater reliability as a result.46 However, the court found that it was possible that such

secondary benefits could be minor in relation to the costs to customers not in the eastern region

expected to benefit directly from the new transmission capacity, and that FERC had not provided

any information by which these benefits could be assessed.47 According to the court:

[i]f FERC cannot quantify the benefits to the midwestern utilities from new ... lines in the

East, but it has an articulable and plausible reason to believe that the benefits are at least

roughly commensurate with those utilities’ share of the total electricity sales in PJM’s

region, then ... the Commission can approve PJM’s proposed pricing scheme on that basis.

But it cannot use the presumption to avoid the duty of “comparing the costs assessed against

a party to the burdens imposed or benefits drawn by that party.”48

The impact of this decision on cost allocation going forward is not entirely clear. On the one

hand, as several observers have noted, the case appears to create a new obligation for FERC to

reconsider and potentially discard pro rata allocation of transmission costs.49 However, the ruling

seems to be directed more at FERC’s procedural failure to justify the ratemaking than a

substantive failure in the application of the law. The court repeatedly mentioned that FERC’s

arguments in favor of the pro rata allocation were dismissed not because such a cost allocation

method was unreasonable on its face, but rather because FERC had failed to demonstrate the

reasonableness of the rates. Perhaps the most significant restriction on FERC articulated by the

Seventh Circuit is that FERC must show reason to believe that the benefits received by the parties

are “at least roughly commensurate” with the pro rata cost allocation.50

Id. at 478.

Id. at 475.

Id.

Id. at 476.

Id.

Id. at 477.

Appeals Court Sets Precedent In Rejecting FERC Socialized Grid Costs, EnergyWashington Week (August 26,

2009).

576 F.3d. at 477.

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Legislative Efforts to Dictate Transmission Cost Allocation

Principles

As described above, the FPA’s only direction regarding the allocation of transmission costs are

that the rates charged for transmission service must be “just and reasonable.” This gives FERC

broad authority to dictate transmission cost allocation policy, although that authority has its

limits, as the Illinois Commerce Commission decision demonstrates. However, in recent years

Members of Congress have introduced legislation intended to provide a tighter framework for

FERC’s transmission cost allocation policy.

In the 112th Congress, at least one bill has been introduced that would amend the FPA to

specifically address transmission cost allocation. S. 400, introduced on February 17, 2011, by

Senator Bob Corker, would amend Section 205 of the Federal Power Act to provide that:

No rate or charge for or in connection with the transmission of electric energy contained in

any filing made [by a public utility] after June 17, 2010 shall be considered just and

reasonable unless the rate or charge is based on an allocation of costs for new transmission

facilities that is reasonably proportionate to measurable economic or reliability benefits

projected, as determined by the Commission, to accrue to the 1 or more persons that pay the

rate or charge.

This was not the first legislative effort to adopt principles for transmission cost allocation

requiring that costs be allocated in a way that is “reasonably proportionate to measurable

economic or reliability benefits.” During the 111th Congress, the Senate Committee on Energy

and Natural Resources reported out of committee S. 1462, the American Clean Energy

Leadership Act. The bill contained an amendment proposed by Senator Corker that would direct

FERC to issue a new electricity transmission cost allocation rule that could allow for “allocation

of the costs of high-priority national transmission projects to load-serving entities within all or a

part of a region, except that costs shall not be allocated to a region, or sub-region, unless the costs

are reasonably proportionate to measurable economic and reliability benefits.”51

When the amendment to S. 1462 was proposed during the 111th Congress, some advocates of new

electricity transmission construction expressed concern that it would limit FERC’s ability to

spread costs widely among all users in a given region.52 They also argued that the benefits from a

new transmission project may accrue over many years and therefore may not presently be

“measurable.”53 FERC Chairman Jon Wellinghoff was also critical of the amendment, saying that

it would both restrict the Commission’s ability to spread transmission costs across the region and

also needlessly tie up FERC in litigation over individual transmission cost allocations.54 Three

former FERC chairmen also voiced their disapproval of the amendment, noting in a letter that the

amendment could “hamstring” FERC and that the language could jeopardize planned

infrastructure investment due to uncertainty about cost recovery.55

S. 1462 (111th Congress), at §121.

Transmission Groups Push Senate Cost Allocation Provision Changes, EnergyWashington Week, (August 12, 2009).

Id.

Wellinghoff Criticizes Corker Transmission Cost Sharing Amendment, EnergyWashington Week (October 7, 2009).

Id.

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However, others voiced support for the amendment. A coalition of utilities offered its support,

noting that they believe transmission facility costs should be allocated narrowly in order to focus

on those receiving clear benefits from the new or upgraded facilities.56 Their concern was that the

broad allocation of costs could result in the subsidization of transmission with mostly localized

benefits (for example, Midwest wind power facilities) by those outside the area of direct benefit.57

Others argued that socialization of transmission costs over wide areas would give long-distance

transmission projects an economic advantage over alternatives (such as the local development of

renewable power, including off-shore wind farms, and energy efficiency) which might be

preferable if the playing field was kept level.58

Order No. 1000

After the ruling in Illinois Commerce Commission v. FERC and legislative efforts to amend the

FPA to direct FERC transmission cost allocation decisions, FERC initiated a rulemaking

proceeding to formulate a clearer policy for transmission cost allocation.

Background to the Rulemaking and Initial Comments

FERC initiated Docket AD09-8, Transmission Planning Processes under Order No. 890, on June

30, 2009.59 FERC’s first action under this docket, in September 2009, was to hold technical

conferences on transmission planning with transmission owners, operators, and other stakeholders

in Atlanta, Phoenix, and Philadelphia. Based on these meetings, the Commission concluded that

significant issues remained with the effectiveness of transmission planning generally and regional

and inter-regional planning specifically; the treatment of certain types of electricity resources in

the planning process (such as renewable power); and cost allocation for new transmission

projects. In relation to cost allocation, the Commission found that:

Determining the costs and benefits of adding transmission infrastructure to the grid is a

complex process, particularly for projects that affect multiple systems and therefore may

have multiple beneficiaries. At the same time, the expansion of regional power markets and

the increasing adoption of renewable energy requirements have led to a growing need for

transmission projects that cross multiple utility and RTO systems. There are few rate

structures in place today that provide the allocation and recovery of costs for these intersystem projects, creating significant risk for developers that they will have no identified

group of customers from which to recover the cost of their investment. [emphasis added]60

Following these meetings, FERC signaled, in an October 8, 2009, notice requesting comments on

cost allocation and other transmission planning issues, that it may take a more direct approach

toward cost allocation processes than in the past. The Commission noted that its “best remaining

Transmission Cost Allocation Fight Intensifies With New Pro-Corker Group, EnergyWashington Week (November

11, 2009).

Id.

Filings under this docket can be accessed through the FERC docket search web page, at http://elibrary.ferc.gov/

idmws/docket_search.asp.

FERC, Docket No. AD09-8-000, Transmission Planning Processes Under Order No. 890, “Notice of Request for

Comments,” October 8, 2009, p. 5.

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opportunity to eliminate barriers to new transmission construction may therefore be to provide

greater certainty in its policies for allocating the cost of new transmission facilities, particularly

for facilities that cross multiple transmission systems.”61 The specific questions for which FERC

requested comments also provide a window into FERC’s thinking. The questions included,

among others:

•

How can the beneficiaries of a specific project be identified, and should the

delineation of beneficiaries include generators in addition to loads? The unstated

but concomitant question is how should the level of benefits, and therefore the

cost responsibility of different customer groups, be determined? This goes to the

heart of the issue raised by the Seventh Circuit’s rejection of the PJM

Interconnection cost allocation process.62

•

Should cost allocation processes be designed to cover larger geographic regions?

This would seem to raise the contentious issue of whether costs should be

allocated over large areas and perhaps interconnection-wide.

•

Should cost allocations be static or change over time? This question was posed

by FERC as a general issue, and specifically in respect to transmission lines

which are initially built with overcapacity in anticipation of demand growth.

•

How, if at all, should non-quantifiable costs and benefits be incorporated into

cost allocations?63

By the end of November 2009 FERC had received 103 sets of comments. The comments manifest

a wide range of opinions on how FERC should proceed. For example:

•

American Electric Power, a large utility company operating within the PJM, SPP,

and ERCOT RTOs, argued for interconnection-wide planning and cost allocation

for extra-high voltage transmission lines, to be implemented by a FERC

rulemaking.64

•

Southern Company, a large southeastern utility operating outside of RTOs,

rejected the whole notion that problems with transmission planning and cost

allocation were inhibiting transmission development. Southern concluded that:

A significant misconception being promoted by certain aspects of the industry

in the name of promoting renewable resources is that the current transmission

planning processes and cost allocation methodologies are obstacles to the

expansion of the transmission grid. This is not the case. The reason that more

inter-regional transmission projects are not being built, at least in the

Southeast, is that they have not proven to be economic as compared to other

options. As a result, those who would benefit from these projects desire to

have other entities subsidize their costs by seeking to mandate the planning of

Id. at 7 (emphasis added).

Illinois Commerce Comm’n v. FERC, 576 F.3d 470 (7th Cir. 2009).

FERC, Docket No. AD09-8-000, Transmission Planning Processes Under Order No. 890, “Notice of Request for

Comments,” October 8, 2009, p. 7-8. An example of a non-quantifiable benefit may be the use of existing transmission

right of ways for new or upgraded transmission lines, in order to avoid the time and controversy that can accompany

efforts to place lines in new right of ways.

FERC Docket No. AD09-8-000, Transmission Planning Processes Under Order No. 890, “Comments of American

Electric Power Service Corporation,” November 23, 2009, pp. 23-24.

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these projects through restructured “top-down” planning processes and through

the broad socialization of the costs of such uneconomic transmission projects.65

•

The New England Power Pool Participants Committee (a committee of

stakeholders operating within the NE-ISO) stated that “it would be helpful for the

Commission to provide policy guidance on how it would treat a range of cost

allocation options.” [emphasis in the original]66 However, the committee was

opposed to the establishment of interconnection-wide or national cost allocation

rules, or to the notion of interconnection-wide cost allocation.67

•

The Southwest Power Pool RTO suggested that FERC implement standardized

rules for inter-regional transmission planning and cost allocation. It also

supported the establishment of cost allocation processes across broad areas, such

as the Eastern Interconnection.68 SPP stated that:

attempts to precisely define benefits are misplaced. The real benefits of a major

transmission project, as part of a robust EHV network, over its useful life will

never be fully captured in an economic model as there are many benefits that

fall outside the scope of economic modeling. While precise analysis may be

desirable, the limitations of such analysis must be acknowledged. Moreover, it

is important to recognize that doing nothing also has a cost…. Currently, SPP

is working to implement a cost allocation method that would even provide

more cost sharing for regional projects and simplify the cost allocation.69

•

In virtually complete contradiction to the position of SPP, the Electricity

Consumers Resource Council (ELCON), an association of industrial electricity

users, emphasized that cost allocation should follow a fundamental principal of

“beneficiary pays.” Rather than viewing the issue of allocating benefits as a

stumbling block to transmission project development, ELCON stated that:

[A]s FERC notes in the Request [for comments], how to allocate costs is “not a

new problem.” Indeed, courts have developed a carefully crafted body of law to

guide the allocation of the costs of transmission investment, centering on the

principle that the beneficiaries of a service are to pay for it.

[T]hose who are allocated costs based on actual, demonstrable benefits are less

likely to object to the construction of new transmission facilities than those who

are allocated costs based on an assumption that they will receive some general,

unquantifiable benefit. The “beneficiary pays” model is, therefore, more likely to

reduce controversy and assure that future transmission would be built where the

costs truly are justified.70

FERC Docket No. AD09-8-000, Transmission Planning Processes Under Order No. 890, “Initial Comments of

Southern Company Services, Inc.,” November 23, 2009, p. 3.

FERC Docket No. AD09-8-000, Transmission Planning Processes Under Order No. 890, “Comments of New

England Power Pool,” November 23, 2009, p. 7.

FERC Docket No. AD09-8-000, Transmission Planning Processes Under Order No. 890, “Comments of New

England Power Pool,” November 23, 2009, pp. 7 - 8.

FERC Docket AD09-8-000, Transmission Planning Processes Under Order No. 890, “Comments of Southwestern

Power Pool, Inc., Regarding Transmission Planning Processes Under Order No. 890,” November 23, 2009, p. 12.

Id. at p. 13.

FERC Docket AD09-8-000, Transmission Planning Processes Under Order No. 890, “Comments of the Electricity

Consumers Resource Council” November 23, 2009, pp. 2 and 14.

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The diversity of these comments indicated the lack of agreement on how FERC should have

proceeded in respect to cost allocation. In November 2009, at about the same time these

comments were filed, a transmission trade group and a consortium of environmental groups filed

separate petitions with FERC asking the Commission to establish a rulemaking to set

transmission cost allocation standards.71

The Final Rule72

The rulemaking proceeding culminated with the issuance of Order No. 1000 on July 21, 2011.

Order No. 1000 states that the Commission is amending Order No. 890 to ensure that FERCjurisdictional transmission services are provided at just and reasonable rates, and on a basis that is

just and reasonable, and not unduly discriminatory or preferential. The following paragraphs

summarize the Final Rule (which becomes effective October 11, 2011) and its major

requirements.

Planning Requirements

Order No. 1000 establishes three requirements for transmission planning:

•

Public utility transmission providers are required to participate in a regional

transmission planning process that satisfies Order No. 890 principles and

produces a regional transmission plan.

•

Local and regional transmission planning processes must consider transmission

needs driven by public policy requirements established by state or federal laws or

regulations.

•

Public utility transmission providers in each pair of neighboring planning regions

must coordinate to determine if more efficient or cost-effective solutions are

available.

Order No. 1000 further requires that each transmission provider participate in a regional

transmission planning process that includes both a regional cost allocation method for the cost of

new transmission facilities selected in a regional transmission plan and an interregional cost

allocation method for the cost of certain new transmission facilities located in two or more

neighboring transmission planning regions.

Cost Allocation Requirements

Order No. 1000 establishes three additional requirements for transmission cost allocation:

•

Regional transmission planning process must have a regional cost allocation

method for a new transmission facility selected in the regional transmission plan

Peter Behr, “FERC Enters a Maze of Questions About Renewable Energy Transmission,” The New York Times,

November 23, 2009, http://www.nytimes.com/cwire/2009/11/23/23climatewire-ferc-enters-a-maze-of-questions-aboutrenewa-29763.html?scp=3&sq=Conservation%20Law%20Foundation&st=cse.

Transmission Planning and Cost Allocation by Transmission, 136 FERC ¶ 61,051, 76 Fed. Reg. 49,842 (August 11,

2011).

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Electricity Transmission Cost Allocation

for purposes of cost allocation. The cost allocation method must satisfy six

regional cost allocation principles.

•

Neighboring transmission planning regions must have a common interregional

cost allocation method for a new interregional transmission cost facility that the

regions select. Cost allocation method must satisfy six similar interregional

cost allocation principles.

•

Participant-funding of new transmission facilities is permitted, but is not allowed

as the regional or interregional cost allocation method unless the individual

market participants agree to it.

While FERC declines to specify a standard or preferred methodology in Order No. 1000, it does

require each regional or interregional cost allocation method to satisfy six generalized cost

allocation principles:

•

Regional cost allocation principle 1: The cost of transmission facilities must be

allocated to those within the transmission planning region that benefit from those

facilities in a manner that is at least roughly commensurate with estimated

benefits.73

Interregional cost allocation principle 1: The costs of a new interregional

transmission facility must be allocated to each transmission planning region in

which that transmission facility is located in a manner that is at least roughly

commensurate with the estimated benefits of that transmission facility in each of

the transmission planning regions.74

•

Regional cost allocation principle 2: Those that receive no benefit from

transmission facilities, either at present or in a likely future scenario, must not be

involuntarily allocated any of the costs of those transmission facilities.75

Interregional cost allocation principle 2: A transmission planning region that

receives no benefit from an interregional transmission facility that is located in

that region, either at present or in a likely future scenario, must not be

involuntarily allocated any of the costs of that transmission facility.76

•

Regional cost allocation principle 3: If a benefit to cost threshold is used to

determine which transmission facilities have sufficient net benefits to be selected

in a regional transmission plan for the purpose of cost allocation, it must not be

so high that transmission facilities with significant positive net benefits are

excluded from cost allocation.77

Interregional cost allocation principle 3: If a benefit-cost threshold ratio is used

to determine whether an interregional transmission facility has sufficient net

benefits to qualify for interregional cost allocation, this ratio must not be so large

Id. at P 622.

Id.

Id. at P 637.

Id.

Id. at P 646.

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Electricity Transmission Cost Allocation

as to exclude a transmission facility with significant positive net benefits from

cost allocation.78

•

Regional Cost Allocation Principle 4: The allocation method for the cost of a

transmission facility selected in a regional transmission plan must allocate costs

solely within that transmission planning region unless another entity outside the

region or another transmission planning region voluntarily agrees to assume a

portion of those costs.79

Interregional Cost Allocation Principle 4: Costs allocated for an interregional

transmission facility must be assigned only to transmission planning regions in

which the transmission facility is located. Costs cannot be assigned involuntarily

under this rule to a transmission planning region in which that transmission

facility is not located.80

•

Regional Cost Allocation Principle 5: The cost allocation method and data

requirements for determining benefits and identifying beneficiaries for a

transmission facility must be transparent with adequate documentation to allow a

stakeholder to determine how they were applied to a proposed transmission

facility.81

Interregional Cost Allocation Principle 5: The cost allocation method and data

requirements for determining benefits and identifying beneficiaries for an

interregional transmission facility must be transparent with adequate

documentation to allow a stakeholder to determine how they were applied to a

proposed interregional transmission facility.82

•

Regional Cost Allocation Principle 6: A transmission planning region may

choose to use a different cost allocation method for different types of

transmission facilities in the regional transmission plan, such as transmission

facilities needed for reliability, congestion relief, or to achieve Public Policy

Requirements.83

Interregional Cost Allocation Principle 6: The public utility transmission

providers located in neighboring transmission planning regions may choose to

use a different cost allocation method for different types of interregional

transmission facilities, such as transmission facilities needed for reliability,

congestion relief, or to achieve Public Policy Requirements.84

Nonincumbent Developer Requirements

The Final Rule curtails the existing right of first refusal for incumbent transmission providers

previously had to build new transmission lines. FERC concludes in Order No. 1000 that retaining

Id.

Id. at P 657.

Id.

Id. at P 668.

Id.

Id. at P 685.

Id.

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Electricity Transmission Cost Allocation

a federal right of first refusal for transmission facilities selected in a regional transmission plan

for purposes of cost allocation could result in rates for FERC-jurisdictional services that are

unjust and unreasonable, or could otherwise result in undue discrimination by public utility

transmission providers. This aspect of the Final Rule will not affect any state or local laws or

regulations regarding the construction of transmission facilities (including but not limited to siting

or permitting), or the following types of projects:

•

The transmission facility is not in a regional transmission plan for purpose of cost

allocation.

•

The transmission facility is not a result of an upgrade to existing transmission

facilities, such as a tower change out or reconductoring.

•

The new transmission facility has already been subject to a regional process

which allows non-incumbent developers to compete with incumbents.

Compliance

Order No. 1000 will take effect on October 11, 2011, 60 days after publication in the Federal

October 11, 2012, or within 12 months of the effective date of the Final Rule. Compliance filing

for interregional transmission coordination and interregional cost allocation must be filed within

18 months of the effective date, that is by April 11, 2013. FERC expects that some RTO regions

may submit their existing procedures as being compliant with Order No. 1000’s regional cost

allocation requirements.

Order No. 1000 does not provide details regarding how FERC might enforce the Final Rule.

Public utility transmission providers are given schedules for compliance filings, and revision of

OATT schedules to reflect cost allocation methods as transmission providers are required to show

that they meet the provisions of the Final Rule. It is possible that potential issues regarding the

formation of regions could affect transmission provider compliance.

Specific Observations on the Final Rule

Planning Requirements

The need for transmission planning has traditionally resulted from load growth and the need to

connect new power generation resources to load centers. More recently, an increased focus on

power markets and reliability has caused discussion on the need for new transmission lines. With

Order No. 1000, FERC has issued regulations which seek to add state and federal public policies

as a factor in the decision-making process concerning which transmission projects emerge from

planning processes as construction projects. However, FERC’s use of the word “consider”85 with

regard to state or federal public policy requirements (i.e., as a factor in the planning process) may

not be enough of an imperative to actually push such transmission projects forward.

Order No. 1000 requires that public utility transmission providers establish a process for identifying those

transmission needs driven by Public Policy Requirements that are to be considered in the transmission planning

process. Id. at P 546.

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In the wake of the issuance of the Final Rule, the American Public Power Association (APPA)

observed that FERC may already have had the authority to move transmission projects forward

which are driven by the needs of load-serving entities (LSEs). APPA believes that transmission

planning should also focus on LSE needs as stipulated in the FPA, which by necessity may likely

include transmission facilities to access renewable resources as mandated by state RPS

requirements and other clean energy resources necessitated by state and federal environmental

regulations.86 APPA refers to section 217(b)(4) of the FPA, which states following:

The Commission shall exercise the authority of the Commission under this Act in a manner

that facilitates the planning and expansion of transmission facilities to meet the reasonable

needs of load-serving entities to satisfy the service obligations of the load-serving entities ...

Cost Allocation Requirements

Definition of benefits will likely be key in determinations of cost allocation. Order No. 1000

discusses many different types of potential benefits (e.g., economic, reliability, system-wide, etc.)

but does not seek to define specifically what a benefit is. The definition of benefits will lead to

the identification of beneficiaries, and thence to the identification of how much and to whom

costs will be allocated to. FERC is not prescribing a particular definition of “benefits” or

“beneficiaries” in this Final Rule. FERC noted that “[i]n our view, the proper context for further

consideration of these matters is on review of compliance proposals and a record before us.”87

FERC does not propose interconnection-wide cost allocation as a regional allocation method for

transmission facilities. The regions will define benefits, and FERC considers at least three

primary areas for benefits will be considered—reliability, economics and public policy. Order No.

1000 states there will be no cost allocation where there is no benefit:

Those that receive no benefit from new transmission facilities, either at present or in a likely

future scenario, must not be involuntarily allocated any of the costs of those facilities. That

is, a utility or other entity that receives no benefit from transmission facilities, either at

present or in a likely future scenario, must not be involuntarily allocated any of the costs of

those facilities.88

FERC also believes this Final Rule will protect transmission customers from free riders, that is,

those who receive benefits without paying for them. Order No. 1000 addresses the “free rider”

issue by invoking cost-causation principles:

In Order No. 890, the Commission recognized that the cost causation principle provide that

costs should be allocated to those who cause them to be incurred and those that otherwise

benefit from them. We conclude now that this principle cannot be limited to voluntary

arrangements because if it were “the Commission could not address free rider problems

associated with new transmission investment, and it could not ensure that rates, terms and

conditions of jurisdictional service are just and reasonable and not unduly discriminatory.89

Inside EPA - CLEAN ENERGY REPORT, Public Power Says FERC Clean Energy Order Abdicates Legal

Requirement, August 22, 2011, http://cleanenergyreport.com/iwpfile.html?file=aug2011%2Fce08222011_appa.pdf.

136 FERC at P 624.

Id. at P 219.

Id. at P 84.

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FERC is allowing the regions to define themselves, with the caveat that there must be more than

one utility in a region. Existing RTOs or ISOs are considered “natural regions that have

agreements in place already that will define those regions.”90 FERC expects that these regions

will be defined by transmission-owning utilities.91 It should also be recognized that some RTOs

stretch over non-continuous areas, which may lead to some RTO/ISOs or their members being in

more than one transmission planning region.

The definition of transmission-owning utility may be a complicating factor as some

owners/operators of generation facilities have been designated as transmission owners for

reliability purposes.92 Such entities could also be impacted by aspects of requirements from the

Final Rule.

Established regulatory principles may also bear on the definition of benefits, especially if rate

recovery extends to state jurisdictions or if states (or portions of states) are considered planning

regions. Timing is very important to the definition of benefits, as principles of intergenerational

equity may arise. FERC has stated that consideration of public policies should be limited to

existing policies. The time frame to which these existing policies apply would likely be used as

the limit to the planning horizon for which benefits and their costs could be allocated to

beneficiaries based on established “cost-causation” principles. Alternatively, under “used and

useful” ratemaking principles, the allocation of costs could be spread over the life of the

transmission facility asset itself, and the benefits timeline may be allocated over such a lifespan.

Nonincumbent Developer Requirements

FERC makes a distinction between a transmission facility in a regional plan, and a transmission

facility selected in a regional plan for purposes of cost allocation. FERC considers the latter a

more efficient/cost-effective solution to regional needs, presumably by virtue of being selected

pursuant to a Commission-approved regional planning process, even though there are no standard

procedures for a process likely to be approved by FERC. FERC assumes that the region will

select the most efficient solution since a cost-allocation scheme has been settled on by

transmission owning interests. This distinction also seems to illuminate the partial elimination of

a right of first refusal (ROFR) of a transmission provider to build a transmission facility chosen

for regional cost allocation. FERC is not preempting any state or local law or regulation that

establishes a ROFR, and only eliminates the ROFR in this very limited situation.

Order No. 1000 notes that each transmission provider would be required to amend its OATT if a

transmission facility project selected in a regional plan for purposes of cost allocation is delayed.

Local utilities would then be allowed to consider alternative solutions to ensure that reliability

needs and service obligations are met.

E&E TV, FERC - Chairman Wellinghoff discusses commission’s challenges in crafting transmission rule, July 26,

2011, http://www.eenews.net/tv/transcript/1382.

Response to question at FERC briefing on Final Rule. July 22, 2011.

For example, on June 16, 201, FERC denied an appeal by two wind farm generators (Cedar Creek Wind Energy,

LLC and Milford Wind Corridor Phase I, LLC.) against a NERC order to register as transmission owners and

operators. NERC had ordered the generators to comply with transmission-related reliability requirements applicable to

transmission-owners and operators because of high voltage (i.e., above 100 kV) tie-lines interconnecting their

generating facilities to the bulk power system. Cedar Creek Wind Energy LLC, Milford Wind Corridor Phase I, LLC,

136 FERC P 61,241 (2011).

Congressional Research Service

Electricity Transmission Cost Allocation

General Comments

Order No. 1000 is broadly intended to ensure that there is enough transmission capacity to meet

future U.S. electricity needs, and provide for the allocation of new costs to build the transmission

facilities by “identify[ing] transmission facilities that more efficiently or cost-effectively meet the

region’s reliability, economic and public policy requirements.”93

In paragraph 29 of Order No. 1000, FERC cites the expectations of the U.S. Department of

Energy and NERC with regard to the expansion of high-voltage transmission lines and facilities,

with up to a third of this new transmission capacity intended to serve new variable and renewable

energy generation. State renewable energy portfolio standards are seen as a major driver of this

new capacity. However, with most of the best regions for wind and solar resources located in the

western United States, and many of the load centers and many states with RPS requirements in

the eastern part of the country, some observers have discussed the potential for long, interstate

transmission lines to carry renewable energy to markets in the east. Order No. 1000 allows for

neighboring transmission planning regions to work out interregional plans for state public policies

such as RPS requirements. In the absence of a federal renewable energy or clean energy standard,

an imperative for a west-to-east, multistate renewable energy transmission line is unlikely, but a

segmented build-out of transmission facilities could accomplish a similar goal if benefits to local

regions can be shown. In that instance, the technologies and facility designs chosen to accomplish

the build out could be crucial to a benefits determination since alternating current transmission

lines have the potential for future “on- and off-ramps” to serve load growth along such routes,

while direct current transmission lines are limited in that capability.

Federal regulations may reduce the need for states or regions to have their own regulations to

address the same or similar issues. As such, federal regulations ease interstate commerce because

a multiplicity of state regulations is avoided, especially when the regulations developed in states

and regions addressing a specific issue can differ substantially. In Order No. 1000, FERC intends

to provide broad guidance on planning transmission facilities and cost allocation, while allowing

regions to tailor such arrangements to their own or interregional requirements with consideration

given to public policy goals:

The cost allocation principles are not intended to prescribe a uniform approach, but rather

each public utility transmission provider should have the opportunity to first develop its own

method or methods. Also, we recognize that regional differences may warrant distinctions in

cost allocation methods.94

Thus, in providing such discretion, FERC leaves the door open for broad interpretation of the

regulations, with the likelihood that a wide variation of plans will result.

FERC states in Order No. 1000 that transmission planners should seek the most efficient and

cost-effective ways to meet the transmission needs of regions. Order No. 1000 also identifies a

transmission facility selected in a regional plan for cost allocation purposes as a “more efficient

or cost-effective solution to regional transmission needs.”95 Sometimes, the optimal location of a

power generation facility can ease congestion-related reliability issues, and present a cost

Order No. 1000, 136 FERC at P 11.

Id. at P 604.

Id at P 7.

Congressional Research Service

Electricity Transmission Cost Allocation

effective solution with potential benefits to other regional transmission needs. It is not clear to

what extent the regional transmission planners will be required to think broadly and consider a

power generation solution when considering Order No. 1000 requirements for the most “efficient

or cost-effective solution” to regional power needs.

The Final Order comes as state renewable portfolio requirements and the upcoming U.S.

Environmental Protection Agency (EPA) regulations for coal power plants96 may increase

demand for new transmission lines. The uncertainty regarding the implications for generation

resources of upcoming EPA regulations has caused some utilities to delay decisions on building

new generation, with plans to satisfy (at least interim) power needs from power markets until the

regulatory clarity they seek is provided. Some commenters expect that shortfalls in transmission

capacity in some regions of the United States may have possible impacts on reliability resulting

from these additional needs. State public utility commission decisions authorizing new power

plants in rate base to replace retired coal plants will likely impact regional transmission planning

decisions.

There are many issues and many questions beyond those discussed in this report which will likely

arise as the many different stakeholders involved move to understand and satisfy their obligations

under the Final Rule. FERC acknowledges that some key questions may only be answered in the

compliance filing process.

Update on Order 1000

FERC issued Order 1000-A97 on May 17, 2012, to deny many rehearing requests for its Order

1000, affirming that all jurisdictional electric transmission providers must comply with Order

1000’s requirements to participate in regional and interregional planning processes for planning

new transmission facilities. Transmission cost allocation methods specified in Order 1000 are to

be employed for these new transmission facilities.

FERC subsequently issued Order 1000-B98 on October 18, 2012, to uphold its previous Orders

1000 and 1000-A, and to make clarifications to its rule. FERC again denied any requests for

rehearing of Order 1000 or Order 1000-A.

Author Contact Information

(name redacted)

Specialist in Energy Policy

[redacted]@crs.loc.gov, 7-....

(name redacted)

Legislative Attorney

[redacted]@crs.loc.gov, 7-....

CRS Report R41914, EPA’s Regulation of Coal-Fired Power: Is a “Train Wreck” Coming?, by (name redacted)

and (name redacted).

139 FERC ¶ 61,132.

141 FERC ¶ 61,044.

Congressional Research Service

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