Hooking Up: Recent Cases Affecting Grid Interconnection

Hooking Up: Recent Cases Affecting Grid Interconnection

January 01, 2009

By Adam Wenner

Two major issues for independent power projects, especially wind, geothermal and large-scale solar, are who pays the costs of interconnection and which projects are allowed to use existing interconnection capacity. Renewable energy projects in particular tend to be far from population centers and more expensive to connect to the grid.

In addition, the status of a project in the interconnection queue significantly affects the viability of the project.

The Federal Energy Regulatory Commission, which regulates interconnections in the continental US, other than in the ERCOT area of Texas, has issued several decisions recently that affect generator interconnections.

Midwest ISO

“First come, first served” is now “first ready, first to interconnect” in the Midwest ISO.

To address its backlog of interconnection requests, the Midwest ISO proposed, and FERC accepted in large part, a proposal to revise the interconnection queue process.

The Midwest ISO proposal included 1) a pre-queue phase, 2) a modified feasibility study that permits requests to be routed to a “fast lane” to allow projects in unconstrained areas to proceed without delay, 3) establishing queue positions based on achievement of milestones, which is intended to avoid blocking of queues with non-viable or inactive projects, 4) increasing deposit amounts and changing the timing for making deposits and 5) changing the ability to suspend the transmission utility’s construction or installation of interconnection facilities or network upgrades for up to three years for any reason to permit suspension instead only in cases of force majeure.

The first phase in the Midwest ISO’s proposal is the system planning and analysis phase. It is similar to the current system impact study phase; however, queue position is less important because it can change through the interconnection process.

The next phase is the “definitive planning phase” in which a system impact restudy is performed, if necessary, as well as a facilities study. The fee to enter this phase is approximately double the expected actual cost, with the excess used to cover the facilities study and costs incurred to re-study lowerqueued projects if the generator drops out. Unused balances are returned to the customer. Study deposits are $30,000 for projects between 20 and 50 megawatts and $60,000 for projects between 50 and 500 megawatts.

Entering into the definitive planning phase also will require technical data and meeting milestones. Technical data required are 1) a detailed stability model, 2) a definitive point of interconnection, 3) a one-line diagram showing ratings and impedance information for associated electrical equipment, 4) the definitive amount of capacity of the project, 5) either recertification of site control or, if the project has provided a $100,000 deposit in lieu of showing site control, the deposit becomes non-refundable 10 business days after the start of the planning phase and 6) any two of four other items. The four are i) documentation of an application for state or federal permits and a showing that the application is proceeding, ii) approval of the project by a state utility commission, iii) approval from an independent board of directors of the applicant or a similar showing of organizational approval or iv) security equal to the nameplate capacity times the rate for one month of drive-out point-to-point transmission service.

In addition, before the Midwest ISO will start a facilities study, the generator must show that it has achieved one of the following additional milestones: 1) security for the cost of network upgrades as determined in the system planning and analysis review, 2) execution of a power sale agreement or an attestation that the project is included in a state resource adequacy plan or evidence that the generator will qualify as a designated network resource or 3) a demonstration that the turbines have been ordered.

Under the Midwest ISO’s prior interconnection procedures, a customer could suspend the effectiveness of an executed interconnection agreement for a total of three years for almost any reason. Under the revised program, suspension would only be permitted based on a force majeure event and for a total period of three years. In addition, a customer may have up to six months from completion of the system planning and analysis review to the start of the facilities study to meet the applicable milestones, and may obtain another three months between the completion of the facilities study and the execution of the interconnection agreement. However, a customer must provide security for the cost of its network upgrades in order to avoid harm to lowerqueued projects resulting from the suspension.

FERC ruled on the proposal in a ruling called Midwest Independent Transmission System Operator, Inc. A request for a rehearing is pending.

California ISO

Interconnection requests totaling more than 105,000 megawatts, including more than 68,000 megawatts of renewable resources, are in the California ISO or CAISO interconnection queue, far exceeding the 50,270 megawatts of peak demand for the CAISO balancing authority area as well as the capacity required for compliance with the California renewable portfolio standard. As in the Midwest ISO, many of these projects drop out, forcing a restudy of lower-queued projects, as upgrades that would have been built by the dropped-out projects are now assigned to the next project in line. These dropouts, as well as suspended in-service dates for projects, are clogging the interconnection queue and imposing cost uncertainty on other projects. To address these concerns, CAISO filed proposed interconnection queue reforms with the Federal Energy Regulatory Commission in early July.

The CAISO proposed to establish three categories of interconnection requests: a grandfathered group that will be processed under the existing large generator interconnection procedures, an initial generation interconnection process reform tariff called GIPR and a transition cluster group generally subject to the GIPR.

The CAISO filing notes that while clustering of interconnection requests has worked in Tehachapi, it alone cannot address the withdrawal and re-study problems created when projects drop out. CAISO’s response is to impose greater financial commitments on generator developers, but in return to provide more cost certainty. FERC approved the CAISO’s proposal one week after filing.

The CAISO subsequently filed a GIPR tariff amendment that would establish substantive changes to the interconnection process. It has three major parts: 1) adopting a clustering approach to process interconnection requests within a cluster window, as opposed to existing project-specific studies, processed in the order of receipt, 2) consolidation of interconnection studies from three into two, called the phase I interconnection study and the phase II interconnection study and 3) a significant increase and acceleration of financial commitments required to participate in the interconnection process.

Under the FERC’s and the CAISO’s current large generator interconnection procedures, under which interconnection applications are processed individually, later-queued projects depend on the availability of transmission network upgrades that are scheduled to be constructed on behalf of earlierqueued projects. A significant risk in this approach is that if a higher-queued project is not developed, the network upgrades that were assumed to be in place for the lowerqueued project will not be available. As a result, the lowerqueued generation project can face a significant and unexpected increase in the cost of interconnection, as it may be required to pay for facilities that were scheduled to be constructed by others.

This risk is one of the fundamental flaws that the CAISO proposal is intended to address. It does this by weeding out speculative projects and requiring increasingly non-refundable security, thereby reducing the likelihood of dropouts that were relied upon to complete their upgrades. Based on this reduced risk of dropouts, the CAISO proposal caps the cost of network upgrades for which a project can be held responsible at the originally-estimated cost, and the costs of the network upgrades to have been developed by the dropout projects are borne by the transmission utilities operated by the CAISO.

The CAISO proposed to use a clustering approach, with two queue cluster windows open each year, during which it will accept interconnection requests. Queue position would cease to have any significance. Following an extra cluster window of October 1, 2009 to January 31, 2010, the cluster windows will be four months long, including April 1 to July 31 and October 1 to January 31.

In order to weed out unviable or premature projects, the CAISO requires higher financial commitments and more data for a project to enter and remain in the queue. All required technical data must be submitted with the interconnection request. Wind developers will no longer have a six-month window to submit their detailed electrical design specifications and other technical data. The request must include a proposed commercial operation date when the entire output of the project will be in service. However, customers may identify proposed phasing, which often occurs in wind energy projects. Further, consistent with the current large generator interconnection procedures, generators would be permitted to delay commercial operation for up to three years without causing the withdrawal of the interconnection request or forfeiture of financial security.

The CAISO proposed to consolidate the three interconnection studies required for large generators — the feasibility study, the system impact study and the facilities study — into two studies: the phase I and phase II interconnection studies. The CAISO proposed to make additional transmission information and technical data available to prospective project developers, so that they can conduct their own preliminary assessments of interconnection requirements, rather than having to undergo a formal interconnection feasibility study upon entering the queue. The deposit required to cover the cost of processing interconnection studies would be increased from $10,000 to $250,000, which would cover both studies. The deposit will become non-refundable over time: $100,000 becoming non-refundable 30 days after the scoping meeting and the full amount becoming non-refundable 30 days after the phase I interconnection study results meeting. Amounts not needed to cover study costs and overhead are refunded after a customer executes a large generator interconnection agreement. The CAISO stated that these increased deposits are intended to insure that developers only seek interconnection for projects with a substantial probability of being completed, with the partial refundability approach designed to provide incentives for developers to withdraw projects as early as possible if they are found not to be viable.

The phase I interconnection study is intended to evaluate the impact of all interconnection requests received during the queue cluster window, preliminarily identify all network upgrades needed to address these requests, preliminarily identify all interconnection facilities required for each interconnection request, assess the requested point of interconnection and potential alternatives, establish maximum cost responsibility for network upgrades assigned to each interconnection request, and provide a good faith of the cost of interconnection facilities associated with each interconnection request.

The phase II interconnection study is intended to update the phase I study to reflect withdrawal of interconnection requests, finalize and assign financing responsibility for network upgrades, provide a plus or minus 20% cost estimate for the customer’s interconnection facilities and transmission owner’s interconnection facilities, and optimize in-service timing requirements to achieve commercial operation dates.

Under the cluster approach, the network upgrade costs associated with the cluster group are assigned on a pro rata basis to the members of the group, based on the capacity of the generating facility. In contrast to current large generator interconnection procedures, where cost responsibility estimates can change based on decisions made by other interconnection customers, under the CAISO proposal, phase I estimates for a customer’s cost responsibility for network upgrades are the maximum that can be assigned to that customer. If the cost of network upgrades increases after the phase I study, those increased costs will be paid by the CAISO transmission companies and passed on to their customers.

The current large generator interconnection procedures provide that the interconnection customer does not have to post security until construction of network upgrades or interconnection facilities begins. In contrast, the CAISO proposal requires an interconnection customer to post security equal to 20% of its total cost responsibility for network upgrades and transmission owner interconnection facilities by 90 days after publication of the final phase I interconnection study report. The remaining 80% must be posted within six months after the conclusion of the phase II interconnection study.

Financial security would become non-refundable over the course of a schedule, with the greater of $500,000 or 50% of the initially posted 20% of projected network upgrade costs becoming non-refundable regardless of the reason for withdrawal. FERC conditionally approved the CAISO proposal in late September. The case is called California Independent System Operator Corp. A rehearing is pending.

Distribution or Network Upgrade?

How interconnection facilities are classified for regulatory purposes determines who has to pay the cost.

The general FERC policy on interconnection facilities is that facilities on the generator’s side of the point of interconnection to the transmission grid are “directly assigned” to the generator, who must pay for these facilities with no transmission credits provided. In contrast, facilities added on the transmission provider’s side of the point of interconnection are “network upgrades,” which the transmission provider (and ultimately its customers) must pay for. The generator must initially fund the cost of network upgrades, but is repaid, with interest, through credits against its transmission charges. If there are no transmission charges, the amounts are refunded over time in cash.

FERC has recognized that there is a third category of interconnections — interconnections to the utility’s distribution system, which are on the utility’s side of the point of interconnection. The cost of upgrades to the utility’s distribution system is borne by the generator on the grounds that these upgrades do not benefit other transmission customers. Under this policy, the determination of whether the utility facilities to which a generator is connected are part of the transmission grid or the distribution system becomes crucial, since it determines who bears the cost of interconnection.

Distribution facilities are generally low voltage, while transmission facilities are higher voltage. However, low voltage facilities can be part of the trans mission grid, while high voltage facilities can be distribution facilities.

In a case involving wind projects in the wind-rich Tehachapi region of California, FERC ruled that the test for transmission versus distribution is made under the five-factor test adopted in a 2001 case called Mansfield. The five factors are 1) whether the facilities are radial or they loop back into the transmission system, 2) whether energy flows only in one direction, from the transmission system to the customer over the facilities, or in both directions, from the transmission system to the customer, and from the customer to the transmission system, 3) whether the transmission provider is able to provide transmission service to itself or other transmission customers over the facilities in question, 4) whether the facilities provide benefits to transmission service capability or reliability, and whether the facilities can be relied on for coordinated operation of the grid and 5) whether an outage on the facilities would affect the transmission system.

FERC held that under the Mansfield test, the facilities to which the windfarm is connected and that would require upgrades are distribution facilities. It also found that 1) the interconnected facilities are not part of a continuously closed loop and, therefore, are radial, 2) power only flows on the interconnected facilities from the wind farm to the CAISO grid, but not in the opposite direction, 3) CAISO, and not Southern California Edison, is the “transmission provider,” and CAISO does not provide service to itself or other customers over the interconnected facilities, 4) the interconnected facilities do not provide any benefits to the CAISO grid and 5) an outage on the interconnected facilities would not affect the reliability of the CAISO grid. As a result, FERC concluded that the upgrades are on a distribution system and not on the transmission grid and that the generator must pay for the upgrades.

The case is Cabazon Wind Partners, LLC v. Southern California Edison Co.

Extensions to Complete Projects

In another recent FERC ruling, there was no harm, no foul for extensions of the in-service date beyond the three-year safe harbor.

Network upgrades developed in connection with higher-queued projects affect lower-queued projects. As a result, the large generator interconnection procedures distinguish between “material modifications” to an interconnection proposal, which cause the customer to lose its place in the queue, and “nonmaterial modifications,” which do not affect the generator’s queue position.

The determination of whether a modification is “material” is generally based on whether or not it would harm lowerqueued generators. Section 4.4.5 of the large generator interconnection procedures states that extensions of less than three cumulative years in the commercial operation date of a generating facility seeking interconnection are not a “material” change, thus providing a safe harbor for delays in the completion of wind and other generation projects.

The form of large generator interconnection agreement provides, in section 5.16, that a generator may suspend the interconnecting utility’s work on network upgrades or utility-owned interconnection facilities for up to three cumulative years, provided that the generator covers the utility’s costs that have been incurred prior to the suspension and costs associated with the suspension, such as cancellation costs. This three-year grace period is intended to provide generators flexibility in the development process, but with a finite enddate, so as to avoid undue harm, in the form of delays, to customers that are farther back in the queue and are relaying on network upgrades that are to be developed by the generator seeking the suspension.

In a case involving an interconnection between the 188- megawatt Judith Gap wind farm, located in Montana, and NorthWestern Energy, FERC addressed the question of whether a delay in completion of the project to a date more than three years after the scheduled commercial operation date, was a major modification that would cause Judith Gap’s requested interconnection service to go to the end of the queue.

Like many projects, the Judith Gap project consists of two phases, phase I, 135 megawatts, that became operational within the scheduled date of November 15, 2005, and phase II, an additional 53 megawatts, that was delayed beyond the three year date (beyond November 15, 2008). Importantly, all of the interconnection facilities and network upgrades needed to accommodate the full 188 megawatts of capacity have already been constructed and placed in service.

FERC held that the three-year “safe harbor” for delaying the commercial operate date of the generator does not mean that all extensions beyond three years are considered material modifications. Instead, the standard is whether a further delay will harm lower-queued generators. Since all of the interconnection and network upgrade facilities associated with the full 188 megawatts of capacity are in service and available for use by lower-queued generators, FERC found that the additional delay is not a material modification and Judith Gap does not lose its place in the queue for phase II. FERC did not foreclose the possibility that delay in completing a generating project, as opposed to network upgrades, could be a material modification, but held that no harm was imposed in this circumstance.

The case is Judith Gap Energy LLC.

Losing the Queue Position

In another case involving NorthWestern and Montgomery Great Falls Energy Partners LP, a proposed 277-megawatt generator in Montana, FERC found that, in contrast to the situation in the Judith Gap case, extending the commercial operation date of a generation project would materially affect lower-queued projects. It accordingly upheld NorthWestern’s determination that the project must go to the back of the interconnection queue. Had the project maintained its lowerqueue position, it could have availed itself of available interconnection capacity and its interconnection costs would have been low. However, its end-of-the-queue position was behind five other projects, which would use up available capacity. As a result, Montgomery’s interconnection costs would be approximately $147 million.

NorthWestern had advised Montgomery that while it could not extend the commercial operation date beyond the three-year safe harbor for extensions provided in the FERC rules, and that a further extension would be a material modification because it would harm other projects in line behind Montgomery, it would interconnect 167 megawatts of project capacity — the gas turbine portion of a planned combined-cycle facility — that would be on line by the three-year extension date. However, a new interconnection request would have to be filed for the remaining 110 megawatts.

Montgomery’s response was to let the interconnection agreement be cancelled and to submit a new interconnection request. The consequence of those actions was that Montgomery lost its place in the NorthWestern queue, with the effect that its interconnection costs were substantially increased.

The key distinction between this case and the Judith Gap case is NorthWestern’s unchallenged finding that delay of the Montgomery project would harm other projects. In contrast, in Judith Gap, the upgrades required for interconnection of the delayed project had already been placed in service, and delaying the startup of the generator (a wind turbine project) did not harm lower-queued customers. FERC’s order cited specific examples of how delaying the Montgomery project would “delay or derail” other projects or potentially impose significant additional costs.

It is relevant that the FERC large generator interconnection procedures — the guidebook to interconnection issues and processes — permit a generator that wants to get a definitive answer as to whether a proposed change to its interconnection arrangements to do so. Section 4.4.3 of the form of large generator interconnection agreement permits a generator to request a determination from the interconnecting transmission utility about whether a modification would be a “material modification” — which results in a loss of queue position — or a non-material modification, which permits the generator to maintain its queue position.

The case is Montgomery Great Falls Energy Partners LP v. NorthWestern Corp.

Leapfrogging the Queue

What happens when the transmission system’s existing capability to support interconnections without upgrades is sufficient to accommodate higher spots in the interconnection queue, but a higher-queued project is delayed?

FERC held that if a lower-queued project can use the existing interconnection capacity, it is entitled to do so temporarily. However, if and when the higher-queued project does come on line, the lower-queued project must fund the costs of upgrades needed to interconnect the higher-queued project, so that the “first come, first served” policy in effect for non-RTO and ISO utilities is honored.

This approach avoids the risk that the lower-queued project will construct new upgrades that turn out not to be needed if the higher-queued project fails to come on line. This ruling, first adopted in a 2003 decision involving the Virginia Power transmission system, was followed in an August 2008 case involving the use of existing interconnection capacity by two competing merchant transmission projects.

The latest case is Hudson Transmission Partners, LLC v. New York Independent System Operator, Inc. A rehearing is pending.

Increases in Capacity

Even a small increase in capacity requires filing an updated large generator interconnection agreement.

A generation facility interconnected to the Midwest ISO transmission system sought to increase its capacity by 0.7 megawatts, from 32.4 megawatts to 33.1 megawatts. The interconnected customer had a pre-Order No. 2003 interconnection agreement, with terms and conditions that differ substantially from those in the standard form of large generator interconnection agreement used since 2003.

Consumers Energy, which owns the interconnected transmission system, argued that since the increase is tiny, it should not be required to file a new interconnection agreement, especially since the increase would not require upgrades, would have no perceptible effect on other plants in the queue, and would be essentially undetectable for operational purposes.

FERC disagreed on the grounds that under Order No. 2003, all new interconnection requests must comply with applicable large generator interconnection procedures, and the Midwest ISO’s procedures explicitly provide that any increase in generation capacity from an existing customer requires a new interconnection request and a new interconnection agreement conforming to the standard form of large generator interconnection agreement. As a result, it was appropriate to require that a new interconnection agreement be filed. Generators seeking to preserve preOrder No. 2003 interconnection agreements should take heed of this ruling. The case is Midwest Independent Transmission System Operator, Inc.


There is a cost when a generator asks PJM to accelerate improvements that PJM has already scheduled for its own reasons so that the generator can connect its project to the grid.

PJM plans for the enhancement and expansion of its transmission capability on a regional basis. PJM annually establishes a “baseline” of expansion plans needed to meet system enhancement requirements for firm transmission service, load growth, interconnection requests and other system enhancement factors. If a generation customer seeks to have PJM accelerate the schedule for constructing transmission system upgrades, so that it can use the upgrade to accommodate its own interconnection, PJM policy is that the interconnection customers must pay the costs to accommodate interconnection requests that would not have been incurred under the plan “but for” this new service request.

Previously, the costs for which the interconnection customer was responsible were limited to the time value to advance investment in network upgrades to the date sought by the customer. PJM transmission owners complained that the customers’ obligation, as stated, is not synonymous with the “time value of money,” and that there are many other costs associated with advancing the date of construction, such as overtime and additional siting and permitting costs. FERC accepted this proposed change to the PJM tariff to include these additional costs of delay. The case is PJM Transmission Owners.

Dealing with Federal Utilities

Beware of transmission owners that are not required to synchronize availability of interconnection and transmission services.

The Bonneville Power Administration is not subject to FERC jurisdiction. However, in order to avail itself of the open access transmission tariffs, or OATT, of FERC-regulated utilities, BPA must adopt an OATT similar to the FERC OATT. In response to a request from a generator seeking both transmission and interconnection, BPA filed a request for FERC to issue a declaratory order on the issue of whether it can require the customer to execute transmission service agreements prior to its offering an interconnection agreement to the customer.

FERC’s OATT, as well as the version adopted by BPA, allows a transmission customer to obtain up to five one-year extensions for the commencement of service, provided that it pays a fee equal to a one month charge for the firm transmission service for each year, or fraction of a year, for which an extension is sought. Because BPA is a federal agency, under the National Environmental Policy Act it is required to conduct an environmental review of actions that may significantly affect the environment. Pursuant to that requirement, BPA previously had delayed acting on transmission service requests until it completed its environmental review of a proposed interconnection. However, in mid-2007, BPA changed its practice and offered transmission service 15 days after it delivered an interconnection feasibility study, or if the customer waived the feasibility study, 15 days after it tendered a system impact study, with no delay for the environmental review of the interconnection. This policy can force the generator to begin paying for transmission service before the generator could use it, since the interconnection facilities cannot be constructed prior to the environmental review.

The generating customer argued that FERC should require that the timing of the transmission and interconnection offers should be linked since, under BPA’s approach, a customer could be required to pay significant charges for extending the commencement of service even though BPA was not ready to provide transmission service.

FERC rejected that argument, holding that transmission and interconnection are distinct services and that FERC has not required that they be synchronized or linked. FERC noted that, in addition to the option to pay to extend the commencement of transmission service, the generator can sell or assign its rights under its transmission agreement to a third party while awaiting completion of the interconnection. However, it is not necessarily the case that a willing purchaser of temporary transmission service can be found.

In contrast to BPA, investor-owned utilities are not required to conduct a review under the National Environmental Policy Act prior to constructing interconnection or transmission facilities, so that the opportunity for nonsynchronized transmission and interconnection service is reduced. However, the risk of non-synchronized availability is not eliminated, and it can pose the risk of significant financial harm to a project that requires both interconnection and transmission services. The case is US Department of Energy (Bonneville Power Administration). A rehearing is pending.

O&M Costs

A 50-megawatt biomass facility owned by Russell Biomass, LLC is seeking interconnection to the Western Massachusetts Electric Company, or WMECO, transmission system that is operated by ISO New England, via a new, 5.1-mile, 115-kV transmission line and a new switching station that will be constructed and paid for by Russell Biomass and conveyed to WMECO upon completion.

WMECO proposed to charge $515,200 annually for operating and maintenance costs for these facilities, based on the ratio of the capital cost of the facilities to WMECO’s total transmission investment. Russell Biomass contends that it should be responsible only for the incremental O&M charges directly associated with O&M on the facilities, which it estimates are $48,000 per year, which is less than one-tenth of the amount sought by WMECO. WMECO also asserted that Russell Biomass must pay for the WMECO and ISO-New England legal fees associated with negotiating the interconnection agreement and litigating the case.

FERC has set the matter for a hearing and urged the parties to reach a settlement.


The Tehachapi region of California has the potential for more than 4,500 megawatts of additional wind generation. Since under the California renewable portfolio standard, California utilities are obligated to obtain at least 20% of their power from renewable sources by 2010, there is tremendous interest by utilities and developers in constructing transmission to connect Tehachapi projects with the utility grid.

However, development has been hampered by the remote location and associated high cost of interconnecting to the California ISO grid, as well as the difficulties of coordinating planning and development of transmission involving many different wind developers with different timelines. In addition, standard regulatory policies inhibited development of interconnection. Normally developers must pay for “genties” that are used only to connect generation to the grid and are not part of the integrated transmission system, but the costs and coordination problems made that unviable. Utilities normally are not permitted to include the costs of gen-ties in their transmission cost of service and recover their costs from ratepayers. In addition, under FERC ratemaking policy, a utility normally may only recover the costs of facilities that are “used and useful,” and if interconnection facilities turn out not to be used because wind projects failed to materialize, utilities risk non-recovery of 50% of the costs of “abandoned plant.”

As a result, Southern California Edison was reluctant to proceed with a gen-tie line without contractual commitments from wind and solar energy project developers.

To solve this problem, the California ISO proposed a program to resolve the dilemma and permit needed development to occur. Under the plan, the CAISO identifies “energy resource areas” that have the potential for development of a significant quantity of “location constrained resources,” such as wind, solar and geothermal, that can only be developed where the resource is located. Interconnection lines to energy resource areas, called “multi-user resource trunk lines,” would be eligible for favorable rate treatment. Utilities that develop and own trunk line projects would be permitted to recover associated costs in their transmission rates, if these costs are not being recovered from generators. As generating resources are developed and sign up for interconnection service, they would be assigned a pro rata share of the costs of the trunk line, on a going-forward basis, and the utility and its ratepayers would be relieved of this portion of the costs. Since there are tremendous economies of scale in transmission, the costs of a pro rata share of a high voltage line are significantly lower than the costs of a standalone line with lower voltage and transfer capability.

In order for interconnection projects to qualify as trunk lines, they must not otherwise be eligible for inclusion in the utilities transmission rate base and must be turned over to the CAISO for operational control. The projects, which must be high-voltage transmission designed to serve multiplelocation-constrained resources, must be evaluated and approved by the CAISO in its transmission planning process. To limit potential cost impact on ratepayers, total investment in trunk line projects cannot exceed 15% of the total high voltage transmission plant of participating transmission owners. Finally, to limit the risk of stranded costs that would occur if the generation projects are not developed, construction of a trunk line project may only commence if 25% to 30% of the project’s capacity is subscribed, and there must be a “tangible demonstration of additional interest in or support for the project” in the range of an additional 25% to 35% of the trunk line’s capacity.

FERC approved the CAISO proposal in April 2007, and construction of portions of the trunk line project proposed by Southern California Edison is now underway.

Incentives for New Transmission Lines

In response to its concern that utilities were not investing sufficient capital in new transmission construction, as part of the Energy Policy Act of 2005, Congress added new section 219 to the Federal Power Act.

This law directs FERC to establish incentive rate opportunities for companies, including traditional utilities and independent transmission companies. In Orders 679 and 679-A, FERC held that to receive incentive rate treatment, an applicant must demonstrate that the transmission project would ensure reliability or reduce congestion and thereby reduce the cost of delivered power. FERC established a rebuttable presumption that a transmission project meets these standards if it has been authorized under a regional planning process that evaluates projects for reliability or congestion or if it has been approved by a state commission or state siting authority.

As proposed by Southern California Edison, the Tehachapi project is a $1.7 billion project broken into 11 segments and consists of more than 200 miles of 500-kV transmission line, approximately 10 miles of 220-kV transmission line and three new substation facilities. The Tehachapi project will ultimately interconnect up to 4,500 megawatts of generating resources, consisting primarily of wind generation, in the Tehachapi area to the Edison transmission system, located in the Tehachapi and Big Creek corridor areas.

After receiving FERC support for the CAISO innovative approach to ratemaking policies to develop the Tehachapi transmission project, Southern California Edison sought FERC authorization for several transmission rate incentives allowed under the FERC rules for that and two other transmission projects. For Tehachapi, Edison sought 1) an additional 150 basis points on its allowed return on equity, 2) authorization to include the costs of construction in its rate base, which is an exception to the general rule that project costs are normally includable in rate base only when they are in-service and 3) a commitment from FERC that if the project is cancelled due to factors beyond Edison’s control, then it could recover the costs that it had expended on the Tehachapi project.

FERC granted Edison’s request, finding that it satisfied the standards outlined earlier. In addition, FERC held that Edison had demonstrated that there is a nexus between the incentives sought and the investment being made in the transmission project. FERC found that authorizing the inclusion of Tehachapi project costs in rate base would reduce the pressures on Edison’s finances caused by investing large sums in transmission projects.

Regarding recovery of costs if the project is not completed, FERC found that because Edison had not received many of the needed federal, state and local approvals for the project, this created increased regulatory risk. FERC also ruled that Edison is entitled to the 150 basis point adder to its allowed return on equity for the costs of the Tehachapi project, based on Edison’s overall investment of $2.5 billion in transmission projects, an “unprecedented capital investment program that presents a significant financing challenge” for Edison.

These incentives, along with the FERC authorization to include the costs of the unsubscribed portions of the Tehachapi transmission project in Edison’s rate base, provide significant encouragement for Edison to develop the transmission infrastructure needed to interconnect with wind, solar and geothermal facilities for which, under traditional ratemaking policies, the cost of interconnection would have been a perhaps insurmountable obstacle.