PRINCETON UNIVERSITY

WWS402s: Renewable Energy and the Electric Grid in the United States

Professor Harold Feiveson

Shocks to the System: Assessing the Impacts of Pricing Alternatives, Legal Challenges, Competitive Renewable Energy

Zones, and Independent System Operators on Electrical Transmission

Kayley McGrath

3 May 2011

This assignment represents my own work in accordance with University regulations.

Signed, Kayley McGrath

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EXECUTIVE SUMMARY National Policies: FERC and Cost Allocation

Prior to the mid-1990s, investor-owned utilities constructed new transmission lines, and pricing was generally a single averaged rate, available to all ratepayers in a local area. Such cost socialization methods have become obsolete on a grid governed by Regional Transmission Organizations (RTOs), where cost-bearers and beneficiaries of new transmission projects do not align so precisely. The Federal Energy Regulatory Commission’s (FERC) Order No. 2000-A established these regional power pools of concentrated utilities. FERC has been increasingly relying upon broad, general principles in determining cost allocation policies while delegating more authority to regional operators. In February of 2007, FERC passed Order 890, which aimed to increase the transparency and fairness of cost allocation by standardizing transmission capacity calculations among utilities and creating incentives for RTOs to construct new, multi-jurisdiction transmission lines, which are often precluded by narrow, local interests. Although FERC must approve a region’s cost allocation proposals, state and regional regulators still hold the primary jurisdiction in determining what projects are pursued and who pays for them. These authorities will overwhelmingly consider their personal losses or benefits when approval is pending for a project. Thus, incentives to pursue multi-state or interregional projects are lacking, and impede FERC’s efforts to pursue projects that may impose diffuse costs on the national level – namely, renewable energy initiatives. Regional Initiatives: Cost Allocation Various regional Independent System Operators (ISOs), including the New England ISO (NE-ISO), and California ISO (CAISO), Florida Power and Light Company (FPL), the North Carolina Transmission Planning Collaborative (NCTPC), PJM Interconnection, and Competitive Renewable Energy Zones in Texas and California (CREZ initiatives), provide insightful strategies for cost allocation that may be useful in revamping national policies. In particular, the FPL and the NCTPC provide the most flexible strategies and incentives for allocating funding for new projects. The former bases a utility’s cost recovery ability for undertaking new transmission projects on the likelihood its project will disrupt the grid. This standard motivates utilities to propose high-quality expansions to the grid at the risk of bearing any fallout costs. Similarly, the NCTPC pushes the cost burden of new projects onto non-initiating utilities in proportion to their savings in not having to undertake the initial project that would likely benefit all – at least marginally – in reliability upgrades. Legal and Political Developments in Cost Allocation Policy The holding in Illinois Commerce Commission v. FERC (2009) indicates the Court’s aversion to backing broad cost socialization policies. The U.S. Court of Appeals, Seventh Circuit, ruled that PJM’s uniform allocation policy for all ratepayers funding projects exceeding 500 kilovolts was not a proportional or appropriate strategy. The Electric Transmission Customer Protection Act, proposed in the Senate in February of 2011, also endorses a “measurable reliability or economic benefit” standard for a project to merit funding from a party. These measures demonstrate a political distaste for broad national authority under FERC that supports diffusely borne electricity costs. Perhaps the approaches of the FPL and NCTPC will prove to be more legally tenable in taking proportional risks and economic benefits of utilities and customers into account. FERC can draw from these policies in formulating national standards. Such considerations are necessary, as continued regional policy discontinuity will undermine renewable energy initiatives that require national cooperation. Thus, FERC should strive to retain its authority, and endorse policies that trend toward national uniformity.

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

interstate transmission lines.”1

This controversial dynamic is attributable to the fact that the pricing of electrical

transmission has become increasingly complicated. Electrical providers and consumer

beneficiaries have, historically, aligned geographically. However, post-1996 open-access

transmission policy reforms under the Federal Energy Regulatory Commission (FERC) have

dissociated utilities from their ratepayers.2 Moreover, FERC delegates ample regional authority to

transmissions owners and operators in determining cost allocation methods, further exacerbating

the lack of national policy uniformity and clarity.3 These policies have ultimately reduced the

transparency of electrical energy pricing, and are stalling efforts to integrate renewable energy into

the grid in pursuit of greenhouse gas emissions reductions for the energy sector. Renewable

energy incorporation requires inter-regional transmission lines and concerted power line

construction and funding to connect the remote sources of wind, solar, or geothermal energy to

populated load centers.4 While various Independent System Operators (ISOs) and Regional

Transmission Organizations (RTOs)5 have proposed several alternative pricing schemes, the

legality of these proposals is uncertain. Currently, as evidenced by the landmark decision in Illinois

Commerce Commission v. FERC (2009), courts seem hesitant to endorse cost socialization

policies, in which all customers in a regional interconnection pay the price of a new project,

                                                        1 Stan Mark Kaplan, Electric Power Transmission: Background and Policy Issues, Rep. Congressional Research Service, 14 Apr. 2009. Web. 20 Mar. 2011. <www.crs.gov> 20. 2 Stan Mark Kaplan and Adam Vann, Electricity Transmission Cost Allocation, Rep. Congressional Research Service, 19 Apr. 2010. Web. 21 Mar. 2011. <http://www.wiresgroup.com/images/WIRES_Report_CostAlloc_041910.pdf> 3-4. 3 Ibid. 6. 4 Ibid. 10. 5 Federal Energy Regulatory Commission (FERC), "Regional Transmission Organizations (RTO)/Independent System Operators (ISO)," Federal Energy Regulatory Commission (FERC), 24 Mar. 2011. Web. 25 Mar. 2011. <http://www.ferc.gov/industries/electric/indus-act/rto.asp>.

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regardless of personal benefit.6 Cost allocation policy would benefit from an increase in FERC’s

unilateral control of pricing schemes and flexibility to pursue creative allocation alternatives; North

Carolina’s “Regional Reliability Projects” 7 and the Florida Reliability Coordinating Council’s policies

appear most promising and feasible in terms of bypassing legal constraints. Finally, concerning the

incorporation of renewable resources into new transmission lines along the grid, Competitive

Renewable Energy Zones (CREZ) initiatives assume a cost-effective approach to renewable

energy integration,8 and should prove to be useful prototypes in drafting similar national policies.

FERC: PAST TREATMENT OF COST ALLOCATION Prior to the mid-1990s, transmission lines were constructed by investor-owned utilities and

“subject to traditional cost of service regulations by state utility commissions.”9 Pricing was

generally a single averaged rate, available to all ratepayers receiving the distributed services and

allocated toward funding transmission investments, regardless of individual benefit.9 Such

regulatory socialization streamlined cost allocation, as the transmission beneficiaries, on average,

constituted the entire pool of ratepayers.9 Opaque pricing policies were compatible with

increasingly less transparent transmission planning processes. The transmission lines built at the

advent of the 20th century were engineered by single utility companies attempting to provide

concentrated local populations with energy from local power plants.9 While transmission planning

technologies advanced to provide more long-distance service, utilities built coalitions that

connected local grid systems, minimizing transmission risks while increasing reliability.10 Recently,

FERC has pursued projects that “traverse multiple utility service territories and cross the

                                                        6 Kaplan 21; Illinois Commerce Commission, Et Al. v. Federal Energy Regulatory Commission, Et Al. Nos. 08-1306, 08-1780, 08-2071, 08-2124, 08-2239. United States Court of Appeals for the Seventh Circuit. 6 Aug. 2009. <http://caselaw.findlaw.com/us-7th-circuit/1443922.html\>. 7 Kaplan and Vann 8. 8 Lower Colorado River Authority (LCRA), LCRA: Energy. Water. Community Services, Lower Colorado River Authority, 2011. Web. 20 Mar. 2011. <www.lcra.org>. 9 Kaplan and Vann 3. 10 Kaplan and Vann 10.

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boundaries between power system planning areas,…[have] multiple owners,…[and] provide

benefits to many and diverse beneficiaries.”11 These complicated endeavors have further

disconnected ratepayers from transmission beneficiaries, rendering cost allocation a murky, legally

contentious issue.

FERC derives its authority from the Federal Power Act (FPA) of 1935, which states that “all

rates and charges for the transmission of electric energy [are] subject to FERC’s jurisdiction,”12

and, in the event a public utility demands “unjust, unreasonable…[or] discriminatory”13 rates from

consumers, the Commission can modify and enforce a new, more appropriate pricing scheme.

FERC has cited the broad scope of this jurisdiction to justify more radical changes to transmission

cost allocations policies. First, the Public Utility Regulatory Policies Act of 1978 (PURPA)

implemented a pricing strategy that “would not provide…utilities with unfair competitive advantages

over…small businesses,”14 as well as mandated that utilities have readily available information

regarding seasonal or daily cost fluctuations, and supply their consumers with this information in

up-to-date rate schedules.15 The Energy Policy Act of 1992 amends and expands this provision

further in Section 111, in favor of small business, by requiring “integrated resource planning” such

that utilities’ investments in energy conservation and efficiency are at least profitable, encouraging

cost-effective improvements at the lowest net system cost.16

Such efforts to induce competition amongst generation providers culminated in FERC’s

                                                        11 Kaplan and Vann 3. 12 18 U.S.C. at §824d(a) and (b). qtd. in Kaplan and Vann 2. 13 18 U.S.C. §824e(a) qtd. in Kaplan and Vann 2. 14 Van Ness Feldman Law Firm, "PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978: Marked to Show Amendments Resulting from the Energy Policy Act of 2005, H.R. 6 (Aug. 8, 2005)," La Plata Electric Association (LPEA), 8 Aug. 2005. Web. 19 Mar. 2011. <http://www.lpea.coop/purpa/PURPA1978.pdf> 34. 15 Ibid. 12-13. 16 H.R. 776, 102nd Cong., Energy Policy Act of 1992 102 (1992) (enacted). <http://www.afdc.energy.gov/afdc/pdfs/2527.pdf>.

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Orders 888 and 889 of 1996.17 The former established an open access transmission tariff (OATT),

in which rates were market-based, and providers opened their systems to any load, barred from

treating their own load preferentially.17 The latter, Order 889, instituted open-access same-time

information system (OASIS), which strived to “foster greater competition in wholesale power

markets”18 by granting third-party users similar terms and rights to providers.18

Most significantly, Order No. 2000-A (Docket No. RM99-2-001) required public utilities

operating transmissions facilities to form and participate in a Regional Transmission Organization

(RTO), which is an independent operational authority to administer the transmission grid, and is

responsible for congestion management, improving efficiency, planning and expanding new lines,

and electrical market monitoring by removing discriminatory transmission practices within a

regional scope.19 RTO jurisdictions are diagramed in Figure 1, below.

Figure 1. A map of various RTOs under FERC’s jurisdiction.5

                                                        17 Kaplan and Vann 4. 18 Penton Media, "FERC Adopts Order No. 890, a Final Rule to Reform Landmark 1996 Open Access Rules," Transmission & Distribution World. 19 Feb. 2007. Web. 19 Mar. 2011. <http://tdworld.com/news/ferc-adopts-890/>. 19 Regional Transmission Organizations: Final Rule; Order on Rehearing, Docket No. RM99-2-001 Federal Energy Regulatory Commission (2000). <http://www.ferc.gov/legal/maj-ord-reg/land-docs/2000a.pdf> 2.

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This reform was an expansion of the Independent System Operators (ISOs) established in Orders

888/889, which constituted “tight power pools”20 of electrical transmission. RTOs addressed in this

report include the New England ISO (NE-ISO), California ISO (CAISO), PJM Interconnection, and

the Electric Reliability Council of Texas, Inc. (ERCOT RTO).21 While this measure delegates

management oversight to regional organizations, FERC retains the power to “authoriz[e] any

innovative transmission rate treatment” proposed by the RTO.22 These pricing plans must meet the

standard of reasonableness and appropriateness codified by the FPA.23 The creative privileges

granted to these regional organizations in allocating cost could include performance-based

transmission rates, adjustable risk premiums for locking in grid pricing in the short-term,24 or price

caps and future discounting policies.25 The Order’s assessment of past anti-discriminatory policies

in Orders 888 and 889, however, revealed that generation providers “retained the incentive and

ability”18 to discriminate against third parties with significant latitude and impunity.

Moreover, these previous reforms further severed the obvious links between transmission

providers and beneficiaries. This open-access pricing scheme shifted planning operations from

utilities to RTOs (or comparable organizations and stakeholders), rendering cost allocation a

regional, long-distance affair. Further complicating the scheme was the new, critical distinction

between cost allocation for both reliability and economic upgrades to the grid, which would newly

                                                        20 Federal Energy Regulatory Commission (FERC), "Regional Transmission Organizations (RTO)/Independent System Operators (ISO)," Federal Energy Regulatory Commission (FERC), 24 Mar. 2011. Web. 25 Mar. 2011. <http://www.ferc.gov/industries/electric/indus-act/rto.asp>. 21 Ibid. 22 Regional Transmission Organizations: Final Rule; Order on Rehearing, Docket No. RM99-2-001 Federal Energy Regulatory Commission (2000) 111. 23 Ibid. 112. 24, Fred Espen Benth, Pricing of Electricity Futures: The Risk Premium. Advanced Modelling in Finance and Insurance, RICAM Linz, Centre of Mathematics for Applications (CMA): University of Oslo, Norway, 22 Sept. 2008. Web. 20 Mar. 2011. <http://www.ricam.oeaw.ac.at/specsem/sef/events/program/slides/Benth_linz-sept08.pdf>. 25 Regional Transmission Organizations: Final Rule; Order on Rehearing, Docket No. RM99-2-001 Federal Energy Regulatory Commission (2000) 112-113.

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impact ratepayers in significantly disparate ways.26 Specifically, economic upgrades reduce the

operating costs of the power system through targeted projects that benefit a concrete cluster of

electrical consumers, whereas reliability upgrades tend to improve the reliability of the entire power

system.26 Thus, cost socialization policies have been criticized as inappropriate for narrowly

beneficial economic projects. Ultimately, past policies concerning transmission pricing left much to

be desired in terms of simplicity and transparency.

FERC: CURRENT TREATMENT OF COST ALLOCATION

FERC has increasingly been relying upon broad, general principles in determining cost

allocation policies, rather than its traditional, case-by-case treatment of pricing. In February of

2007, FERC passed Order 890, which substantially revised Orders 888 and 889 and the long-

standing and ineffectual open access procedures.18 To that end, FERC endorsed nine broad

planning principles: “coordination, openness, transparency, information exchange, comparability,

dispute resolution, regional coordination, economic planning studies, and cost allocation,”27 and

enacted several reforms intended to reduce discriminatory pricing. One such pricing improvement

corrects for unfair pricing flexibility in energy imbalances, in which differences between the

scheduled and actual delivery of energy to a load often result in exorbitant charges.28 FERC

remedied these discrepancies by enacting a tiered rate structure in which imbalance charges

increase proportionally to the size of the energy imbalance.26

Further, Order 890 grants consumers discretion in selecting which hours transmission could

be conditional, eliminates the previous price cap on transmissions costs, and requires providers to

post their policies and standards on the OASIS informational forum established in Order 889 to

                                                        26 Kaplan and Vann 5. 27 Order No. 890: Final Rule: Preventing Undue Discrimination and Preference in Transmission Service, FERC DOCKET NOS. RM05-25-000 AND RM05-17-000 Federal Energy Regulatory Commission (2007). <http://www.ferc.gov/industries/electric/indus-act/oatt-reform/order-890/fact-sheet.pdf> 3. 28 Ibid. 4.

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foster more competitive wholesale rates.29 Most significantly, the policy reformed Available

Transfer Capacity (ATC), which refers to “the transfer capability remaining on a transmission

provider’s transmission system that is available for further commercial activity over and above

already committed uses.”30 Prior to Order 890, transmission providers calculated their systems’

ATCs using different assumptions and methodologies, which the new Order standardized.28 This

enabled FERC to accurately characterize the capacity of each provider to pursue the construction

of new facilities, particularly those projects that would stand to benefit several parties economically.

31 FERC asserts:

… 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…. 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] (Order 890, February 16, 2007, paragraph 558, qtd. in Kaplan and Vann 6)

While FERC continues to grant considerable latitude to RTOs in crafting their cost allocation

policies, the Commission remains an active player in ratemaking in an advisory capacity. The

Commission’s criteria for determining the adequacy of a regional pricing strategy considers three

factors: the fairness of assigning cost between cost-bearers and beneficiaries, the creation of

adequate incentives for new transmission line construction, and the support for the policy among

participants and authorities within the region.32

Since Order 890, FERC has continued to pass numerous adjustments to its cost allocation

procedures. Following Order No. 890, FERC passed Order 890-B in 2008 to clarify its policies

                                                        29 Ibid. 4, 6. 30 Ibid. 2. 31 Kaplan and Vann 6. 32 FERC, Order 890, February 16, 2007, paragraphs 559 and 560.; Kaplan and Vann 6.

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regarding ATC standardization in response to several requests for elaboration.33 For example, the

Edison Electric Institute argued that the consistency requirement imposes disproportionately high

costs on transmission providers by requiring that they “constantly monitor” variations in values,

which does not outweigh any realized benefit of ATC coordination.34 FERC overruled the numerous

petitions received from utility companies to reinforce its initial ruling: ATC values on either side of

an interface must be consistent; however, the Commission acknowledged that variations in needs

and timing of transmission would inevitably preclude identical ATC values.35 Similarly, 890-B

reaffirmed the removal of the price cap on rates enacted in the original Order despite utility

protests, as well as the requirement of transmissions providers to pay operational penalties if they

fail to meet the Order’s “due diligence”36 standard of “processing service requests in a timely and

nondiscriminatory manner”34 within 60 days.37

On June 17th, 2010, FERC issued yet another ruling that invalidated previous measures

that grandfathered incumbent transmission providers into a class of utilities excepted from

complying with updated reforms.38 In this way, FERC eliminated the perverse incentives that would

deter transmission developers from incurring disadvantages by undertaking new projects subject to

stricter standards under the Commission’s reforms. Ultimately, FERC has demonstrated its

flexibility and receptiveness to policy modifications and feedback from utilities and state or regional

authorities. However, since state and regional regulators hold the primary jurisdiction in

determining what projects are pursued and who pays for them, these authorities will

                                                        33 Preventing Undue Discrimination and Preference in Transmission Service: Order on Rehearing and Clarification, Docket Nos. RM05-17-003 and RM05-25-003; Order No. 890-B Federal Energy Regulatory Commission (2008). <http://www.ferc.gov/whats-new/comm-meet/2008/061908/E-1.pdf> 5. 34 Ibid. 6. 35 Ibid. 9-10. 36 Ibid. 56. 37 Ibid. 45-46, 56. 38 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities: Notice of Proposed Rulemaking (NOPR), Docket No. RM10-23-000 Federal Energy Regulatory Commission § 131 FERC ¶ 61,253 (2010). <http://www.ferc.gov/whats-new/comm-meet/2010/061710/E-9.pdf> 1.

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overwhelmingly consider their personal losses or benefits when approval is pending for a project.

Thus, incentives to pursue multi-state or interregional projects are lacking, and impede FERC’s

efforts to pursue projects that may impose diffuse costs for narrow, particularized benefits on the

national level.

VARIOUS COST ALLOCATION METHODS: CREZ & SIMILAR INITIATIVES OF ISOs Thus, FERC should not ignore the progressive policies currently being implemented on a

regional scale. These strategies for cost allocation may endorse creative pricing solutions to

encourage investment in new transmission lines, and can perhaps be helpful in updating the

national regime. Various regional Independent System Operators (ISOs), including the New

England ISO (NE-ISO), and California ISO (CAISO), Florida Power and Light Company (FPL), the

North Carolina Transmission Planning Collaborative (NCTPC), PJM Interconnection, and

Competitive Renewable Energy Zones in Texas and California (CREZ initiatives), provide insightful

strategies.

New England ISO (NE-ISO)

NE-ISO was established in 1997,39 and services Connecticut, Maine, Massachusetts, New

Hampshire, Rhode Island, and Vermont through various load zones interspersed throughout the

states.39 Currently, and since 2004, NE-ISO endorses a cost socialization plan, in which the costs

of any project with region-wide benefits are borne by all customers within the RTO for Reliability

Transmission Upgrades (RTUs).40 Specifically, transmission owners share voltage payments

based on their loads, with distribution payments for reliability assigned directly to the owners.41

                                                        39 Federal Energy Regulatory Commission (FERC), "Electric Power Markets: New England (ISO-NE)," Federal Energy Regulatory Commission (FERC), 25 Mar. 2011. Web. 26 Mar. 2011. <http://www.ferc.gov/market-oversight/mkt-electric/new-england.asp#prices>. 40 Kaplan and Vann 8. 41 ISO New England, 2011 Wholesale Markets Project Plan, Rep. ISO New England, 2011. Web. 22 Mar. 2011. <http://www.iso-ne.com/pubs/whlsle_mkt_pln/isone_2011_wmpp.pdf> 45.

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According to NE-ISO’s 2011 Wholesale Markets Project Plan, released March 15th, 2011,42 cost

allocation for projects spanning multiple reliability regions within the RTO involves a two-step

process: first, “costs are allocated equally among the affected reliability regions.”38 Second, “these

costs are allocated pro rata to regional network load”38 for voltage support requirements (VAR) and

local second-contingency-protection resources (LSCPRs) within each of the reliability regions.

These regions are areas benefitting from reliability enhancements to the grid’s transmission of the

electric load. They may benefit differently from a single reliability upgrade. In the event the RTU is

considered to be a “localized cost,” as in, the “costs that exceed reasonable requirements for the

upgrade,”43 costs are allocated to the precise zone in which they were incurred.43

Although approximately $4 billion in reliability investments have been pursued and

distributed in a shared manner, cost socialization is more efficient for reliability upgrades than for

economic upgrades that provide regional benefits.40 This is due to the universal nature of reliability

upgrades: while a failure in a regional grid can impact the performance of the entire system,

economic upgrades are more specific in the scope of ratepayers affected, and thus are less

justifiable in a socialized price scheme.40 Thus, Market Efficiency Transmission Upgrades (METUs)

have a stricter qualification standard for funding than RTUs; although, once the project is approved,

costs “are allocated across all load in ISO-NE on a monthly coincident peak basis,”43 similar to

reliability upgrades. Sponsors fund unapproved METU projects.43

The ISO is evaluating whether to refashion the policy so that costs are allocated directly to

load across the reliability regions, rather than splitting the costs between the reliability regions first.

This modification may render the grid more receptive to economic improvements by eliminating an

                                                        42 Ibid. 18. 43 PJM Interconnection, A Survey of Transmission Cost Allocation Issues, Methods and Practices, Rep. PJM Interconnection, 10 Mar. 2010. Web. 21 Mar. 2011. <http://ftp.pjm.com/~/media/documents/reports/20100310-transmission-allocation-cost-web.ashx> 53.

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intermediary step in cost allocation that normalizes significant and inevitable regional differences.

Moreover, the simplification would make the pricing process more legally tenable, as courts look

favorably on policies that most closely align ratepayers and beneficiaries with costs proportional to

the risk of grid disruption, to be discussed.

California ISO (CAISO) & Renewable Energy Transmission Initiative (RETI)

CAISO services the majority of California,44 and has elected to approach cost allocation for

multi-regional projects “on a case-by-case basis.”45 More specifically, the payment plan for new

transmissions projects is contingent upon whether CAISO accepts or rejects the proposal.

Accordingly, “to the extent a proposed project or congestion study is accepted,”46 the costs of the

endeavor will be borne by its Participating Transmission Owners (PTOs) of the different reliability

regions.46 If the new proposal is rejected, costs are borne by the sponsor of the project.46 While this

small monetary penalty may be considered a disincentive for new transmission investments, it is,

conversely, an incentive for planning authorities to submit high-quality proposals that are more

likely to be selected for implementation by CAISO.

Similarly, in terms of incentives, CAISO has not formally established a policy mechanism for

encouraging joint investment and/or ownership of transmission facilities.46 However, CAISO, as the

independent overseer of new project proposals, can determine when related projects may benefit

from the collaboration of their sponsors.46 Once these synergies have been identified, CAISO can

encourage the sponsors to organize collectively, and thus minimize the costs to ratepayers.46

                                                        44 Federal Energy Regulatory Commission (FERC), "Electric Power Markets: California (CAISO)." Federal Energy Regulatory Commission (FERC), 27 Mar. 2011. Web. 28 Mar. 2011. <http://www.ferc.gov/market-oversight/mkt-electric/california.asp>. 45 CAISO: Planning and Infrastructure Development, FERC Order 890: Strawman Proposal In Compliance with the Nine Planning Principles of the Final Rule, Rep. California Independent System Operator (CAISO), 29 May 2007. Web. 22 Mar. 2011. <http://www.caiso.com/1bed/1bedf4875dee0.pdf> 17. 46 Ibid. 18.

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These costs may be socialized upfront, as the generators become interconnected.47 It is important

to note that the ISO’s standards for reliability and economic upgrades are essentially the same, as

both upgrades over 200 kV are allocated to all consumers on a megawatt-hour basis across all

load within the ISO.48 The only discernible difference involves CAISO’s approval process, in which

economic upgrades require a specific monetary metric weighing benefits, including “reduced

production costs, congestion, capacity costs, losses, or environmental costs”49 against costs. This

can involve unequal Capacity Revenue Rights (CRR), in which areas upstream of a previously

congested facility would experience price increases, along with increasing revenues and capacity

expenditures, while the once capacity-constrained suppliers themselves experience lower prices

and decreased revenues.49 The NE-ISO has faced similar challenges in reconciling simultaneous

and unequal locational costs or benefits.50

California has also adopted heightened standards requiring renewable energy resources to

account for a substantial portion of generation on the grid through infrastructure improvements.51

The statewide Renewable Energy Transmission Initiative (RETI), formed by CAISO in conjunction

with the California Energy Commission (CEC), and the California Public Utilities Commission

(CPUC), among other California power agencies, aims to identify new projects, called Competitive

Renewable Energy Zones (CREZ), that will foster renewable energy integration in observance of

the state’s 33 Percent Renewable Portfolio Standard goals.52 This 30-member collaborative effort,

although lacking administrative or legal standing, is an informal stakeholder responsible for

                                                        47 PJM Interconnection, A Survey of Transmission Cost Allocation Issues, Methods and Practices, 54. 48 Ibid. 54. 49 Ibid. 13-14. 50 Ibid. 13. 51 The California Energy Commission (CEC), "Renewable Energy Transmission Initiative (RETI)." The California Energy Commission (CEC), 4 Nov. 2010. Web. 22 Mar. 2011. <http://www.energy.ca.gov/reti/>. 52 "California Energy Commission: Renewable Energy Transmission Initiative," 2010 Award Winner: State Leadership in Clean Energy. Clean Energy States Alliance, 2010. Web. 22 Mar. 2011. <http://www.energy.ca.gov/reti/documents/2010_CESA_Award_for_RETI.pdf 1> 1.

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developing a “conceptual statewide transmission plan”53 to influence the goals and initiatives of

organizations with formal standing in terms of renewable energy planning and permitting.52 State,

local, federal, utility, environmental, and ratepayer interests are all represented.52 The goal of this

integrated approach, founded in 2007 by the CEC, is to address the “lack of broad stakeholder

[and public] support for transmission plans”54 by creating a more inclusive planning process.

Ultimately, the purpose of RETI is “to reduce costly litigation and delays during the permitting

process,”54 since the interests of potential policy objectors are considered preventatively, during the

planning stages. These consolidated proposals are intended to feed directly into CAISO’s planning

process, and improve the efficiency and transparency of transmission construction and renewable

energy generation.54

Competitive Renewable Energy Zones in Texas (CREZ Initiatives)

Similar to California’s RETI project is the CREZ initiative in Texas.55 According to the

Lower Colorado River Authority Transmission Services Corporation (LCRA TSC):

A CREZ is an area where wind generation facilities will be installed throughout West Texas and the Panhandle and from which transmission facilities will be built to various other areas of the state to deliver mostly renewable power to end-use consumers in the most beneficial and cost-effective manner. (Lower Colorado River Authority (LCRA))

The LCRA TSC is one of many transmission service providers under the jurisdiction of the Public

Utility Commission of Texas (PUCT) within ERCOT that was ordered to construct power lines to

connect the CREZs to load centers throughout the region.56 These providers were selected after a

                                                        53 Ibid. 1-2. 54 Ibid. 2. 55 Lower Colorado River Authority (LCRA), LCRA: Energy. Water. Community Services, Lower Colorado River Authority, 2011. Web. 20 Mar. 2011. <www.lcra.org>. 56 Lower Colorado River Authority (LCRA), "LCRA and CREZ," Lower Colorado River Authority, 1 Feb. 2011. Web. 20 Mar. 2011. <http://www.lcra.org/energy/trans/crez/index.html>.; Energy Reliability Council of Texas (ERCOT): System Planning, Analysis of Transmission Alternatives for Competitive Renewable Energy Zones in Texas, Rep. Energy Reliability Council of Texas (ERCOT), Dec. 2006. Web. 24 Mar. 2011. <http://www.ercot.com/news/presentations/2006/ATTCH_A_CREZ_Analysis_Report.pdf>.

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comprehensive evaluation conducted by ERCOT, which gathered inputs from stakeholders and the

Southwest Power Pool as to where the greatest potential for wind generation was located, and how

the grid could be expanded and improved to ensure delivery of wind-generated energy to ERCOT

consumers.57 This study intended to aid the PUCT in its efforts to comply with “its requirements

under the Public Utility Regulatory Act of 2005, Section 39.904 (g),”57 which mandated the

designation of CREZs.57 The PUCT’s Final Order declared in March of 2009 which transmission

facility projects would be pursued.58 Overall, the entire CREZ effort is expected to triple Texas’

current wind generation capacity to 18,456 MW while increasing the grid’s reliability.58 In terms of

expenses, the CREZ effort should yield total decreasing energy costs from wind farms of

approximately $1.50/MWh for every 1% increase in capacity factor.59 Much like the RETI initiative

of California, Texas also hopes to integrate diverse interests in the planning process in designating

routes for CREZ transmission lines.60 To involve the public, for example, public involvement

meetings hosted by the LCRA TSC embrace the opinions of stakeholders and geographically

affected landowners, taking into account “public input, environmental criteria, aesthetics, cost, and

land use.”60 The PUCT must then approve the routes that are favorable to these interests.

In terms of how CREZ initiatives impact the construction of new transmission lines and cost

allocation, it is important to note that ERCOT is an independent system operator not subject to

FERC’s jurisdiction, and not synchronously connected with the rest of the United States’ Eastern

                                                        57 Energy Reliability Council of Texas (ERCOT): System Planning, Analysis of Transmission Alternatives for Competitive Renewable Energy Zones in Texas, Rep. Energy Reliability Council of Texas (ERCOT), Dec. 2006. Web. 24 Mar. 2011. <http://www.ercot.com/news/presentations/2006/ATTCH_A_CREZ_Analysis_Report.pdf> 2. 58 Lower Colorado River Authority (LCRA), "LCRA and CREZ," Lower Colorado River Authority, 1 Feb. 2011. Web. 20 Mar. 2011. <http://www.lcra.org/energy/trans/crez/index.html>. 59 Energy Reliability Council of Texas (ERCOT): System Planning 24. 60 Lower Colorado River Authority (LCRA), "The Public Is Involved in All the Steps to Locate, Build and Maintain Transmission Lines," How LCRA Transmission Services Corporation Locates New Lines. Lower Colorado River Authority, 11 Mar. 2011. Web. 22 Mar. 2011. <http://www.lcra.org/energy/trans/line_routing/index.html>.

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and Western Interconnections.61 ERCOT’s method of cost allocation for PUCT-approved

transmission “without regard to reliability or economic drivers, are allocated 100 percent to load

based on the average monthly coincident peak”62 from June to September. Regional costs are

based on load-ratio share.62 However, it is notable that ERCOT is turning to its CREZ initiatives to

offset some of the incremental costs of Ancillary Services that benefit the interconnection as a

whole, such as synchronized reserves or day-ahead scheduling reserves.63 The Cost Allocation

Task Force (CATF) and the Wind Cost Allocation Task Force (WCATF) evaluated the benefits and

costs associated with assigning these costs to Wind Generation Resources (WGR) and to other

intermittent renewables, such as solar energy.64 One of the most well-received proposals was the

“Wind Plus Load Ratio Share,”65 in which wind generators would receive a designated obligation

for responsive reserves, which could be offset if the generator qualifies for reliability credits, which

could be obtained “through primary frequency response, voltage support, inertia or an inertia-like

response and metered contribution to the ERCOT peak.”66 Thus, CREZ initiatives not only strive to

foster a more inclusive transmission planning process, but also aim to increase the reliability and

sustainability of ERCOT’s grid.

Florida Power and Light Company (FPL)

The Florida Reliability Coordinating Council (FRCC), the regional authority on electrical

grid transmission and reliability, approves FPL’s cost allocation policies.37 These organizations

have created monetary incentives for new transmission projects. For example, if a coalition wanted

                                                        61 Federal Energy Regulatory Commission (FERC), "ERCOT," Federal Energy Regulatory Commission (FERC), 20 Jan. 2011. Web. 22 Mar. 2011. <http://www.ferc.gov/industries/electric/indus-act/rto/ercot.asp>. 62 PJM Interconnection, A Survey of Transmission Cost Allocation Issues, Methods and Practices, 54. 63 Energy Reliability Council of Texas (ERCOT): Board of Directors, and Brad Jones, Wind Cost Allocation Proposal, Rep. Energy Reliability Council of Texas (ERCOT), 16 Mar. 2010. Web. 22 Mar. 2011. <http://www.ercot.com/content/meetings/board/keydocs/2010/0323/Item_13d_-_Wind_Cost_Allocation_Proposal.pdf>. 64 Ibid. 1-2. 65 Ibid. 2. 66 Ibid. 2-8.

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to undertake a new project to expand the grid’s incremental load or generation, that party may be

eligible for partial cost recovery if the initial investment improves the reliability of the FRCC’s grid,

and the party participates in the FRCC Regional Transmission Planning Process.40 In terms of

allocating the costs of these new projects to the beneficiaries, the FRCC has mandated that the

customers in the zone with the need for the project will split the costs evenly.40

Despite such positive incentives for undertaking new projects, the FRCC does not eliminate

the potential risks and costs associated with grid expansions. For example, if the consequences of

one transmission owner’s upgrades or expansions to the grid result in the need for a 230 kV

upgrade or expansion of another transmission owner “affected” as a by-product of the

modifications, then the former owner is responsible for providing the latter with compensatory

financial assistance.67 Thus, if one project necessitates new generating units or other grid

improvements in another transmission owner’s jurisdiction to manage the altered capacity, the

initiator of the project must fund these improvements. Notwithstanding such compensatory

stipulations, “each Transmission Owner shall be responsible for all costs of upgrades to, and

expansions of, its transmission system,”68 including engineering, permitting, and materials and

equipment.69 This rule applies when upgrades are 230 kV or less; in the event the upgrade

exceeds this benchmark, the costs of an approved project are allocated to all transmission owners

within the FRCC.70 The initiating party of the upgrade may be eligible for partial cost recovery on a

case-by-case basis.40 This policy on cost recovery strives to reduce the cost burden on utilities that

may be deterred from planning new projects that require compensatory damages to other utilities

                                                        67 M. B. Miranda, FERC Electric Tariff, Volume No. 6: Open Access Transmission Tariff. Rep. Florida Power & Light Company (FPL), 30 Aug. 2010. Web. 22 Mar. 2011. <https://www.oatioasis.com/FPL/FPLdocs/FPL_OATT_Baseline_8_30_2010.pdf> 9.3.2-9.3.3. 68 Ibid. 9.3.3. 69 Ibid. 9.3.4. 70 John Chiles, "Transmission Cost Allocation: Comparison of Policies in Non-RTO Regions," GDS Associates, Inc.: Engineers and Consultants, 22 Apr. 2010. Web. 24 Mar. 2011. <http://www.spp.org/publications/E-RSC%20Supplemental%20Meeting%20Materials%20-%2004-22-10.pdf>.

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affected as a result.

North Carolina Transmission Planning Collaborative (NCTPC)

The NCTPC is the regional planning organization under which Duke Energy Carolinas and

Progress Energy Carolinas jointly filed under Order 89071 to participate in the regional transmission

planning process.40 Their system of cost allocation carves out exceptions to the generic standard

that investments in new projects for the transmission grid should be borne by the initiating utility

and its immediate consumers, the beneficiaries.40 The predominant exception is “Regional

Reliability Projects” of the NCTPC.40 These projects actually reverse the logic of previous

allocation-to-beneficiaries policies by allocating costs “to other utilities in proportion to the savings

each company receives by not having to undertake its own Reliability Project [emphasis added].”40

This policy applies to projects with region-wide reliability benefits, and certainly furnishes

transmission providers with monetary incentives to pursue new reliability-improving projects.

The second exception to the general principle that beneficiaries fund projects proposed by

the NCTPC is “Regional Economic Transmission Path” projects,72 which reduce the cost of

transmission throughout two or more utility jurisdictions.71 Such economic upgrades are funded

upfront by numerous unspecified planning participants,71 presumably stakeholders or local groups.

Over the ensuing 20 years after the project’s completion, the utilities would be responsible for

repaying the initial investment of these parties; the utilities would derive these funds from their

ratepayers.71 The anomaly in this process is that the allocation seems unnecessarily complicated:

which parties would be willing to fund the cost of a new project, other than potential ratepayers that

stand to gain from future cost improvements through the economic upgrades? Thus, these

                                                        71 Order Granting Rehearing: Duke Energy Carolinas, LLC and Progress Energy Carolinas, Inc., Docket Nos. OA08-50-004; OA08-51-003 Federal Energy Regulatory Commission § 130 FERC ¶ 61,181 (2010). <http://www.ferc.gov/EventCalendar/Files/20100315151841-OA08-50-004.pdf>. 72 Kaplan and Vann 8-9.

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ratepayers would end up paying the utilities to fund their initial investments, and ultimately bear the

cost. Even in the event other stakeholders or environmental groups contribute funding for new

transmission lines, any realized benefits in lower energy costs would be long-term relative to the

first large investment. In light of future discounting, potential beneficiaries or stakeholders may be

deterred from pursuing the economic improvements, in light of the fact that the immediate retention

of any would-be transmission investment would be perceived as preferable to long-term,

incremental price reductions in the cost of electricity.

PJM Interconnection

PJM is a regional transmission organization servicing 13 states in the northeastern United

States and the District of Columbia.73 Its cost allocation policies hinge on the characteristics and

expected use of the new lines.74 For example, projects planned by single utilities to benefit their

local ratepayers, instead of regional consumers, will be funded only by the local beneficiaries.74

More specifically, beneficiaries are also responsible for footing the costs of projects that transmit

less than 500 kV – FERC has encouraged PJM to develop a more specific funding scheme for this

class of projects. To that end, PJM has created a price ceiling for various upgrades: projects less

than $5 million are allocated specifically to the beneficiaries within the load zone, while projects

exceeding $5 million are allocated according to a flow-based method.75 This flow-based method

determines which zones bear the cost “based on [their] distribution factor (DFAX) contribution to

flows on the constrained facility or facilities causing the need for the transmission upgrade.”75

Proposals in the realm of 500 kV or greater require funding by the entire PJM Interconnection; in

this way, costs are socialized.74 To justify this policy, PJM alleges that these projects are

                                                        73 PJM Interconnection, "About PJM," PJM Interconnection, 2011. Web. 23 Mar. 2011. <http://www.pjm.com/about-pjm.aspx>. 74 Kaplan and Vann 7. 75 PJM Interconnection, A Survey of Transmission Cost Allocation Issues, Methods and Practices, 49.

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“backbone”74 upgrades that ultimately benefit the entire interconnection, as these lines have a

tremendous capacity to move large amounts of electricity over long distances.74 This policy applies

even to zones that do not directly benefit from the upgrade, and are not necessarily in close

proximity to the project.

The legality of PJM’s cost allocation policy, particularly the cost socialization policy

applicable to upgrades exceeding 500 kV, was questionable.76 An Illinois utility commission

ultimately challenged the proposal in the United States Court of Appeals for the Seventh Circuit,

and the resulting decision was a decisive blow to cost socialization policies.77

Overall, FERC’s role in guiding cost allocation strategies is minimalistic. There is no formal

national protocol for cost allocation beyond FERC’s nine “general principles.”78 At a hearing for the

Subcommittee on Energy and the Environment of the House Energy and Commerce Committee

held in March of 2010, FERC Chairman Jon Wellinghoff claimed that “each region decides which

[cost allocation] methodology works for it, and FERC reviews the different approaches to make

sure they are fair,”79 a glaring indication of the regional and inconsistent nature of electrical rate-

paying in the U.S.. To remedy these deficiencies, utilities have been relying upon legal action

through the Court system, which will presently be explored.

LEGAL & POLITICAL DEVELOPMENTS IN COST ALLOCATION POLICY

Before any value judgments can be assessed for each regional policy, the potential legal

obstacles, and thus the feasibility of each proposal, must be evaluated. The issue of cost has

become increasingly relevant, in light of the desire for sustainable renewable energy integration

into the grid. Abundant renewable resources in the western and southwestern United States are

                                                        76 Kaplan and Vann 7, 11. 77 Ibid. 7. 78 Ibid. 9. 79 Meghan Gordon, “Wellinghoff: Transmission Cost Rule Could be on the Way,” Inside FERC, March 29, 2010. qtd in Kaplan and Vann 9.

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distant from population load centers, and the delivery of such resources traverses several regions

and utility jurisdictions, producing ambiguities in pricing and disincentives to pursue nationally

beneficial projects at a regionally concentrated cost.80 First, consider the legal precedents of past

decisions on electrical cost allocation.

Illinois Commerce Commission v. FERC (2009)

This case, initiated by the Public Utilities Commission of Ohio and the Illinois Commerce

Commission as representatives of PJM’s Midwestern utilities, challenged PJM’s proposal for

pricing new transmission lines, which was formally approved by FERC.81 Prior to the lawsuit, costs

for new projects were assigned to utilities on the basis of the benefits the utility would receive from

the new facilities; while this practice would continue under the new scheme for projects less than

500 kV, projects exceeding this cutoff voltage would be funded on a uniform basis by all utilities,

regardless of their benefit.81 FERC justified its support of the policy on the following grounds:

…some of PJM's members entered into similar pro rata sharing agreements with each other more than forty years ago and would like to follow that precedent, that figuring out who benefits from a new transmission facility and by how much is very difficult and so generates litigation, and that everyone benefits from high-capacity transmission facilities because they increase the reliability of the entire network. (Circuit Judge Richard Posner, United States Court of Appeals, Seventh Circuit)

Despite these sound intentions, the Court ultimately rejected the pricing proposal. The Court

dismissed the precedential value of past pro rata pricing agreements, claiming that PJM is,

currently, a larger and more modern network that encompasses the more local electricity transport

in its western regions, and longer-distance, far-flung transmissions in the east, which cannot be

treated symmetrically, especially since the west’s lines normally do not exceed 345 kV.81 The

                                                        80 Kaplan and Vann 10. 81 Circuit Judge Richard Posner, United States Court of Appeals, Seventh Circuit, "Illinois Commerce Commission v. Federal Energy Regulatory Commission," FindLaw, 6 Aug. 2009. Web. 21 Mar. 2011. <http://caselaw.findlaw.com/us-7th-circuit/1443922.html>.

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decision, however, focused more heavily on the misalignment of ratepayers and beneficiaries.82

The primary concern was proportionality: while the west might benefit from the reliability upgrades

resulting from higher-transmission projects in the east, the Court declared that “such secondary

benefits could be minor in relation to the costs to customers not in the eastern region.”82 Although

this decision appears to be a blow to cost socialization policies intrinsically, the Court was careful

not to preclude the possibility of socialized allocation, provided the pro rata rates are reasonable

using a standard of “at least roughly commensurate”83 benefits given the cost.

The Electric Transmission Customer Protection Act The Electric Transmission Customer Protection Act stipulates an even stricter standard of

cost/benefit proportionality in terms of FERC’s cost allocation policies.84 The bipartisan legislation,

proposed in February of 2011, strives to protect consumers from funding new transmission projects

from which they do not benefit directly.85 It aims to block a proposal by FERC, to be considered on

FERC’s docket this Spring, which grants the Commission “sweeping authority to broadly spread

the associated costs to customers outside of the area immediately serviced by the new

transmission lines.”85 The Act endorses local- and community-funded projects, holding allocation

policies to a “measurable reliability or economic benefit”85 to merit funding from a local party. This

standard recalls the 2009 proposal by Senator Bob Corker, an addendum to the American Clean

Energy Leadership Act, to legalize a similar allocation criterion.86 While the bill aims to combat

superfluous cost socialization rates that may harm the senators’ constituencies, it will, ultimately,

                                                        82 Kaplan and Vann 12. 83 Ibid. 12-13.; Circuit Judge Richard Posner, United States Court of Appeals, Seventh Circuit. 84 Michael Bates, "Bill Threatens FERC's Cost-Allocation Proposal," North American Wind Power. 18 Feb. 2011. Web. 22 Mar. 2011. <http://www.nawindpower.com/e107_plugins/content/content.php?content.7373>. 85 "Corker, Wyden, Murkowski, Burr, Graham Introduce Bill to Protect Consumers from Unfair Electricity Costs," Corker in the News. Bob Corker, U.S. Senator for Tennessee, 17 Feb. 2011. Web. 22 Mar. 2011. <http://corker.senate.gov/public/index.cfm?p=News&ContentRecord_id=584f2577-8670-4079-be2f-ca60e789e51c&ContentType_id=b94acc28-404a-4fc6-b143-a9e15bf92da4&Group_id=650e2033-9317-4405-a8df-47cdd1c9d515>. 86 Kaplan and Vann 10.

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“‘thwart needed investment in the high-voltage grid and curtail the nation's ability to develop

domestic energy resources’”84 according to WIRES (Working Group for Investment in Reliable and

Economic Electric Systems), a non-profit working group for transmission owners.84 The legislation

will also significantly limit FERC’s allocation authority, according to former FERC chairman, Jon

Hoecker.84 While the legality of these policies is still to be determined by a vote on the Senate floor,

its implications are certain. Aside from markedly curtailing FERC’s power, the bill’s stipulation that

the benefits of a transmission be “measurable” to merit pricing could be an unreasonable standard

or impose unreasonable costs on FERC. Moreover, some benefits may accrue over time, and

change from the initial calculation, further increasing the ambiguities of cost allocation.86 Legislation

of this nature would also create almost insurmountable obstacles to cross-regional transmission

projects that would be indispensable to renewable energy transmission projects and CREZ

initiatives, which strive to connect the remote resources to populous load centers.

CONCLUSIONS: PRINCIPAL FINDINGS & RECOMMENDATIONS

Currently, RTOs are too powerful in their ability to stymie multi-jurisdictional transmission

projects; in effect, these new and potentially more efficient projects are a public good, for which no

one utility company or area has incentives to provide, especially when other regions are able to

challenge their implementation. FERC needs to take unilateral control in coordinating new projects

and vetoing narrow state interests. Its current proposed policy, to be approved this Spring, is a

Notice of Proposed Rulemaking (NOPR) that advocates for the more lenient “roughly

commensurate” proportionality cost/benefit standard advanced by the Court in Illinois Commerce

Commission v. FERC (2009).87 The policy would enable FERC to coordinate adjacent planning

                                                        87 Bracewell & Giuliani LLP, "FERC Proposes Significant Transmission Planning and Cost Allocation Reforms," Bracewell & Giuliani LLP, 22 June 2010. Web. 23 Mar. 2011. <http://www.bracewellgiuliani.com/index.cfm/fa/news.advisory/item/57bd8aef-208e-43d3-850a-57a91d162a77/FERC_Proposes_Significant_Transmission_Planning_and_Cost_Allocation_Reforms.cfm>.

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areas while disincentivizing incumbent transmission owners from refusing to construct new

projects; essentially, it expands Order 890.87 This choice is wise, in light of the non-binding status

of the Electric Transmission Customer Protection Act in the Senate, which proposes a standard

that will dangerously limit FERC’s ability to facilitate multi-interest projects. By incorporating the

judiciary’s decision into its policy hearings, which does not preclude the possibility of cost

socialization if rates are proportionally allocated, FERC tacitly supports the more moderate threat

to its jurisdiction. This tactic will enable the Commission to broadly allocate costs in a more legally

tenable fashion that does not ultimately compromise its national authority.

In regard to creative regional cost allocation policies that could potentially serve as

prototypes for FERC’s future pricing regimes, the Florida Power and Light Company of the FRCC

and the North Carolina Transmission Planning Collaborative (NCTPC) provide the most flexible

strategies and incentives for allocating funding for new projects. The FPL’s decision to base a

utility’s cost recovery ability on the likelihood its project disrupts surrounding transmission owners’

capacity is appropriate, as this standard motivates utilities to propose high-quality expansions to

the grid at the risk of bearing any fallout costs. Thus, in the event a nearby utility’s transmission

capacity is affected, said utility can obtain compensatory costs from the initiating utility in proportion

to the losses resulting from the disruption. This pricing alternative accounts for the Court’s

requirement for proportional costs given the transmission benefits from a project. Similarly, the

NCTPC pushes the cost burden of new projects onto non-initiating utilities in proportion to their

savings in not having to undertake the initial project that would likely benefit all – at least marginally

– in reliability upgrades. While this method creates adequate incentives for utilities within the region

to initiate new transmission projects, it may foster an overabundance of new initiatives: since an

initiating utility does not bear the costs of the project (unless, presumably, the project does not

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provide any benefits to the grid), utilities may propose an unreasonably high number of projects

with the expectation that other utilities would reimburse them.

While such excess will likely be checked by the fear that other utilities would take

advantage of the system, the methodology would greatly benefit from a written agreement among

all utilities that no one company would exploit the logic of the commons for its own gain.

Nonetheless, the FRCC’s pricing schemes appear most compatible with the Court’s demand that

beneficiaries pay for new projects in the form of compensatory damages to other, negatively

affected utilities. Perhaps these policies could serve as prototypes for FERC’s standard to ensure

that the Commission is approving only potentially legally successful allocation procedures.

Ultimately, these efforts will ensure a more fluid, accountable, fair, and transparent pricing system

for electric services, and pave the way to increased national allocation uniformity. It is the hope that

these procedural improvements will lend themselves to a more reliable, and increasingly

renewable, electric grid.

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