Decisions are expected soon from the Federal Energy Regulatory Commission on access and pricing for capacity on merchant transmission lines and on excess capacity on dedicated gen-tie lines that connect independent power plants to the grid. The commission is sifting through reams of comments.
FERC issued a proposed policy statement in late July suggesting a new way to evaluate proposals for the construction and operation of transmission facilities of new, independent transmission companies. FERC proposes to allow transmission developers to negotiate privately to allocate capacity in new transmission facilities if the process is transparent and nondiscriminatory.
In addition, earlier in the year, FERC issued a notice of inquiry concerning the use of excess capacity on a generator interconnection line constructed for an affiliated power plant whose owner “overbuilds” its interconnection capacity beyond what the project needs to leave room for additional projects to be constructed later by the same developer. FERC’s current policy has allowed independent generators to get priority use of this excess capacity under certain conditions.
Comments on both FERC initiatives have been filed by interested parties, and both are awaiting FERC action. The decisions are likely to affect the way that new, non-traditional utility transmission and interconnection investment is structured and developed.
Trying to build high voltage transmission almost anywhere in the country is difficult, even for franchised utilities with the power of eminent domain. Independent transmission companies have an even more difficult road. FERC is seeking ways to encourage transmission line development for developers that do not have an existing obligation to build anything under any tariff or law. This encouragement is consistent with FERC’s recently issued Order No. 1000, which, among other things, does away with the existing preference that traditional transmission utilities had been given to build transmission through a right of first refusal as part of regional transmission planning. It should be noted that Order No. 1000 is subject to multiple challenges in the court of appeals, including this issue of incumbent preference.
The greatest opportunities for independent development are in the area of high voltage DC lines between high cost and lower cost regions. These lines provide for discrete, one way, point-to-point service, and lend themselves to separate, participant funding by specific users of the line. Over the last several years, FERC has attempted to give greater encouragement for developers to construct independent transmission by permitting such developers to use negotiated rates with customers instead of traditional cost-based rates and by permitting less oversight and fewer fixed standards at the planning stages. This has created a natural tension with FERC’s responsibilities under the Federal Power Act to assure that the rates and services for transmission service are just, reasonable and not unduly discriminatory or preferential. In particular, FERC’s efforts to encourage new transmission have caused it to reevaluate its policies about providing “open access” to transmission systems.
Since the Federal Power Act was passed in 1935, the Federal Power Commission (and now the Federal Energy Regulatory Commission) was given only limited authority over construction of transmission capacity. Although amendments to the Federal Power Act have gradually increased FERC’s authority in the area of transmission, FERC has never been given siting or certificate authority over transmission facilities, which remains a state-by-state enterprise. Nonetheless, for the last 25 years, FERC has been issuing orders, regulations and policy statements in an effort to encourage the utility industry both to grant greater access to existing transmission facilities and to increase transmission capacity.
Given the historic vertical integration of the utility industry, utilities were both reluctant to grant access to existing transmission facilities or to construct transmission facilities on behalf of independent generators who were a major competitive threat in the wholesale power business,
Independent transmission development has come slowly. The first “independents” were companies that acquired the existing transmission facilities of existing utilities during the wave of deregulation in the 1990s. Since then, there has been construction of a few, niche independent transmission projects that have been designed primarily to facilitate the transfer of lower cost energy from one market to a higher cost market in the neighboring or nearby region.
The proposed transmission policy statement deals with independent companies seeking to become a new “ merchant” transmission service provider, that is, a service provider with authority to charge negotiated rates for a discrete transmission line, as well as new transmission service providers proposing to charge cost-of-service rates for a discrete transmission line. FERC has referred to these latter, cost-based transmission projects as “new non-incumbent, cost-based, participant-funded transmission projects.” By using this new, tortured phrase, FERC is attempting to distinguish an independent cost-based transmission project from an “incumbent” cost-based project, that is, new transmission from either existing transmission service providers that can assign costs to captive customers and that have on file at FERC existing open access transmission tariffs or “OATT” on file at FERC or from providers that are part of a regional transmission organizations or independent system operators like PJM, MISO or CAISO. The proposed policy statement does not apply to these existing transmission providers, or “incumbents.” And it does not apply to independent developers that plan to build generator interconnection facilities from their power plants to the network grid that may have capacity in excess of the capacity needed for the associated generation. The issue of “gen-tie” use is the subject of a separate FERC notice of inquiry.
FERC in recent years has established multi-factor tests for determining whether to authorize a new independent transmission company to charge negotiated (as opposed to cost-of-service) rates for their new facilities. (FERC did not in the past impose a multi-factor test for independent transmission companies proposing to use cost-of-service rates, although they did authorize certain incentive price adders depending on the individual facts of those companies.) Initially creating a 10-factor test for determining whether to authorize negotiated rates for merchant transmission service, the commission reduced its criteria from 10 to a four-factor test in the 2009 in a decision called Chinook Power Transmission. In reality, the fourfactor test announced in Chinook was not substantially different from the 10. FERC undertakes an assessment of 1) the justness and reasonableness of the rates, 2) the potential for undue discrimination, 3) the potential for undue preference and 4) regional reliability and operational efficiency requirements.
By far the most important aspect of this four-part test is FERC’s reliance on the so-called “open season” process. The transmission developer is required to offer the transmission capacity to the world for a limited period and then post the results of the open season process and file the results at FERC. FERC would then have to confirm that the process was fair and transparent in order to authorize the developer’s right to rely on the negotiated rates and terms that resulted from the open season.
In addition, in Chinook, FERC also modified its policy of requiring that all of the capacity be subject to an open season by authorizing the developer to allocate up to 50% of the available capacity to so-called “anchor tenants,” with the remaining portion to be made available through an open season. The rationale behind the approval of an anchor tenant was FERC’s recognition that it needs to encourage the construction of more transmission capacity, that merchant developers are under no legal obligation to construct those facilities, and that it may be necessary for a developer to get advance commitments from financeable transmission customers at the outset in order to make a merchant transmission facility financially viable. At the same time, the modified policy still offered a substantial amount of available capacity to others in an open season, and the developer’s OATT, which it would have to file prior to operation of the new line, would include an obligation to expand its capacity for others upon a valid request for transmission service. Since Chinook was issued, FERC has permitted independent transmission developers to increase the percentage utilization by one or more anchor customers to 75% of the total planned capacity of the transmission line.
In the last year, FERC held a series of technical conferences on the capacity allocation policy for merchant transmission project and “non-incumbent” cost-of-service projects. This policy proposal is an outgrowth of the evolving decision precedents and the comments from those conferences.
Proposed New Policy
FERC’s new proposal does away with the four-factor test. Instead, it relies mostly on after-the-fact reporting obligations to demonstrate that the rates are just and reasonable and that the access to transmission capacity was not unduly discriminatory or preferential. In addition, for the first time, FERC proposes to permit the merchant transmission provider to allocate up to 100% of the available capacity through private, bilateral negotiations with an open solicitation but without an open season, and to permit transmission capacity to be allocated to a merchant company’s affiliates.
FERC is proposing that a company seeking negotiated rate authorization should issue a general notice in trade publications with sufficient technical specifications about the project, general contract requirements and mechanics for handling possible oversubscription of capacity and priority items like a candidate’s credit support and “first mover” status (for example, customers willing to commit early and take on greater project risk). A merchant transmission developer could then negotiate individually with identified candidates and come up with different terms and conditions as long as the distinctions between customer agreements are not unduly discriminatory or preferential. The commission proposes to allow a single customer to be allocated up to 100% of the capacity. In addition, one or more affiliates of the merchant transmission developer can be allocated this capacity. To ensure that the negotiations were fair, FERC proposes to have more extensive reporting requirements about the transaction process, including specific criteria used in the selection process and relevant terms and conditions, and showing how distinguishing among customers is justified on the facts.
Although FERC has consistently declined to apply its merchant transmission rate policy to independent developers proposing cost-of-service rates instead of negotiated rates, for the first time, FERC has proposed to apply the merchant rate policy to the so-called “non-incumbent, participant-funded transmission” developers. These have in the past been companies that made private deals with entities that have committed to use and fund a transmission expansion. If such a transmission developer proposes using an anchor tenant model, then it would have to follow the same process as described above for merchant developers. In addition, the transmission developer would have to satisfy FERC precedent and Federal Power Act requirements for cost-based transmission service. FERC did not propose a change in policy for existing transmission providers that may want to use cost-based participant funding for new transmission projects, explaining that existing OATT requirements would apply for new capacity built by an existing transmission provider and that an existing transmission owner is free to apply to FERC on a case-by-case basis to waive such requirements if the alternative was shown to be fair.
Lots of Comments
The comments submitted by interested parties in late September fell into three predictable camps.
Companies or associations that develop either independent transmission or independent generating facilities or their trade association are strongly in support of the proposed policy statement and, in some cases want FERC to scale back its oversight of independent transmission even more.
On the other hand, municipal and cooperative utilities and their trade associations, already wary of the current FERC policy on independent transmission, generally oppose what they perceive as a further loosening of requirements that are embedded in the Federal Power Act.
The third group, investor-owned utilities and Edison Electric Institute, their trade association, generally support the proposed policy, but EEI suggested making clear that this policy only applies to proposals where the costs of the project will not be recovered from captive customers.
So-called “independents” who want to promote merchant transmission either approve of the policy statement without significant comment or approve but want less restrictive requirements than those proposed by FERC to assure no undue discrimination or undue preference is present. For example, several independents asked FERC not to expand the after-the-fact reporting requirements beyond those already required for the open season under the current policy, and to permit either omission of commercially-sensitive information or the filing of such information on a confidential basis. While a few of the independents want FERC to be more specific about open solicitation or reporting details, others want FERC to keep things flexible and view the overall selection process in its totality. In addition, several of the independents want FERC to state expressly that it will not question the report on the open solicitation results absent a filing of a specific protest, and others want the scope of FERC’s review limited only to claims of undue discrimination and preference.
The three main trade groups or associations that were critical of the new policy statement were the American Public Power Association, which represents municipal utilities, mostly distribution utilities, the National Association of Rural Electric Cooperative Association, and a group that calls itself the transmission dependent utilities. This group sees little to gain from independent transmission. The group has criticized and continues to criticize FERC for its failure in Order No. 1000 to require independent developers to submit their plans to regional transmission organizations, like PJM or MISO. It sees the new policy proposal as exacerbating the risk that independents will abuse a scarce resource — transmission — without giving entities that may be harmed by the actions of an independent transmission company a realistic chance to challenge its actions, which may be discriminatory or preferential. In particular, the so-called “dependent utility” trade associations argue that simply allowing a rejected would-be customer to file a section 206 complaint under the Federal Power Act if it is denied an allocation would not assure that the independent developer is not behaving in a discriminatory fashion.
The dependent utility trade associations also complained that a merchant has no incentive to “right size” the transmission facilities, in particular, that the facilities could be deliberately designed to be too small to accommodate competitors. One of the trade associations asked FERC to increase the burden on the transmission developer to justify that its plan is reasonable if certain “red flags” appeared.
Accordingly, the dependent utility trade associations have asked FERC to retain the open season requirement, to limit the anchor customer percentage to no more than 75% and allow the additional customers to get the same terms and conditions of the anchor clients. To the extent that FERC adopts its proposed policy, the group wants more extensive and more specific reporting requirements than FERC has detailed thus far, and wants to extract a commitment from FERC not to backtrack over time on its reporting requirements, or to permit information to be filed confidentially which will prevent the public from evaluating the actual details of the transmission developers’ actions.
There is no time limit on FERC’s response to these comments, nor is FERC required to issue a formal policy statement. However, given its consistent efforts to provide incentives for construction of new transmission lines to facilitate competitive transfers of electric generation, FERC can be expected to move reasonably quickly to address issues that it feels may be an impediment to future development.
In addition, on a completely separate track, FERC has been applying, on a case-by-case basis, a policy of dealing with new interconnection lines associated with new independent power plants. Every independent generator needs to interconnect with the integrated transmission network, and frequently undertakes to construct and own the interconnection line between its power plant and the network. Like merchant transmission lines, gen-ties are developed by an entity that is not an “incumbent” transmission provider and has no obligation to file an OATT. But because the gen-tie is inextricably linked with a generating plant, without which it would not be constructed, FERC has viewed the issue of gen-tie access differently.
Particularly in the western United States, project developers that have intended to build renewable generating capacity that are located considerable distances from major network interconnection points and load centers have constructed or have planned to construct interconnection lines from their planned power plants to the interconnection points with transfer capacity greatly in excess of the maximum capacity of their planned generating units. FERC has authority under the Federal Power Act to direct a transmission line (which includes an interconnection line) owner to offer excess capacity to third parties that request it, provided certain conditions are met. It also has authority to order the owner of a transmission line to expand its capacity. However, FERC has consistently held that a developer that owns a generation facility with a gen-tie can establish firm transmission priority for itself or an affiliate over unused capacity on the gen-tie if the developer demonstrates that it has specific pre-existing plans with milestones for phased development of the generation projects that would require use of the excess gen-tie capacity, and makes initial and consistent material progress toward meeting those initial plans and milestones.
Further, FERC thus far has identified no minimum voltage, distance or other technical threshold beyond which the developer would or would not be at risk for third party use of excess gen-tie capacity. In addition, FERC has in the past refused to consider a “safe harbor” period during which the generation developer can rely on exclusive use of the excess gen-tie capacity while it tries to develop additional generation projects. FERC has on two occasions directed gen-tie owners to provide service for an unaffiliated third party. FERC has also typically granted to the gen-tie owner a waiver of the requirement to file an OATT unless and until it receives a bona fide request for transmission service on the gen-tie line.
In issuing a notice of inquiry, which builds on a FERC technical conference on the gen-tie issue conducted a year earlier, FERC asked interested parties whether its current, case-by-case policy relating to priority of use of excess gen-tie capacity should be modified or left alone. FERC gave a long list of questions that it is interested in having answered.
There were a greater variety of power sector stakeholders responding to the notice of inquiry than the merchant transmission policy statement. Although it is safe to say that the overwhelming number of comments argued for a change in FERC policy on access to unused gen-tie capacity, the suggested modifications varied widely. Only a few comments offered more extreme positions — on the one hand, that gen-tie owners should simply provide open access without any priority or, on the other hand, that gen-tie owners should have unfettered discretion to use gen-tie lines as they see fit because they are radial lines unsuited to transmission service.
Most of the comments suggest that FERC take one of four actions: 1) clarify and refine its current policy granting priority use of gen-tie by its owners and affiliates, 2) tailor the pro forma OATT to recognize the much more limited services that a gen-tie owner can realistically perform, 3) modify the pro forma large generator interconnection agreement — specifically section 9.9.2 of the LGIA, dealing with transmission capacity allocation — entered into between the transmission provider (and possibly the independent system operator, like CAISO or PJM) and the gen-tie owner to cover use of interconnection facilities of the gen-tie owner as well or 4) some combination of the above.
Almost without exception, commenters that represent gen-tie developers support a “safe harbor” period during which the gen-tie owner could use the excess capacity for the development of additional affiliated generation projects in the same region without the need to demonstrate specific, pre-existing development plans or milestones. The commenters suggest between five and 10 years from initial energization of the line. Following the safe harbor period, these commenters also suggest that FERC permit priority use of the line for the gen-tie developer if it can show specific, pre-existing development plans and milestones in a manner similar to FERC’s existing policy. Short of implementing a safe harbor period, several commenters asked FERC to make more transparent what specific showings need to be made by the gen-tie owners in order to establish priority of use of the unused gen-tie capacity.
A second group of commenters wants to reform the OATT requirement. Commenters in this group asserted that FERC’s current policy of requiring a gen-tie owner to file a pro forma OATT within 60 days after a third party requests interconnection service from the gen-tie owner is a bad idea. They pointed out that, unlike a true transmission provider, a gen-tie owner cannot provide ancillary services and that imposing system impact studies on a gen-tie owner is outside of its business and would be unduly burdensome. In addition, they argued that it is wrong to include in the OATT an obligation of the gen-tie owner to expand its gen-tie line to accommodate a third party request, pointing out the gen-tie owner never wanted to be in the transmission business in the first place. Further, several commenters argued that no OATT should have to be filed until the third party generator really commits financially to follow through on the request and that it be required to show specific plans and milestones. Otherwise, they claim, the filing of an OATT would be time consuming and may ultimately be pointless. Most indicated that if an OATT were still required, it must be a “tailored” OATT, and that the third party generator requesting service must also obtain an agreement with the transmission provider and transmission operator under a separate OATT.
A group of commenters wants FERC to forget the OATT and modify the LGIA instead. A good number of commenters in this group supported the idea that many of the problems with FERC’s current gen-tie policy could be overcome with a relatively simple fix — modify section 9.9.2 of the LGIA between the transmission provider (and independent system operator) and the gen-tie owner to incorporate analysis and allocation of capacity use and charges related to the gen-tie as well. They pointed out that transmission providers, unlike gen-tie owners, are in the business of doing transmission studies. Besides, they pointed out, even if the third party generator sought and obtained access on the gen-tie from the gen-tie owner, the third party generator would still need to apply for and reach agreement with the transmission provider in order to get access that the transmission grid attached to the gen-tie line. Modifying section 9.9.2 in this way, they asserted, would simply amount to one-stop shopping.
However, several commenters pointed out obvious challenges with this approach. First there would be no contractual link between the third party generator and the gen-tie owner and thus no mechanism to enforce the LGIA with the third party generator. One option to fill this contractual gap would be to require either a separate, four-party agreement among the transmission provider, independent system operator (like CAISO or PJM), gen-tie owner and third party generator, which may be difficult to accomplish and be more trouble than it is worth. Moreover, since the transmission provider does not own or operate the gen-tie line, this will raise issues of rights and liabilities of the gen-tie owner on the line versus rights and liabilities of the transmission provider, including, among other things, who bears the costs, how would costs be recovered from other parties, including ratepayers, and cost allocation.
Some of the commenters that suggested that, in lieu of promoting a second, four-party agreement, a better solution would be to give the gen-tie owner the right to negotiate a bilateral agreement with the third party generator, in concert with the modification to the LGIA with the transmission provider and the gen-tie owner, and eliminate the requirement of the gen-tie owner to file an OATT. This would require good faith negotiations between the gen-tie owner and the third party generator, and a remedy if the negotiations failed. Three alternative solutions were offered. First, since the transmission provider has the obligation to interconnect and to expand its system anyway, the third party generator can go forward with interconnection with the transmission provider regardless of the absence of an agreement with the gen-tie owner. Second, the third party generator can force the gen-tie owner to file an unexecuted interconnection service agreement at FERC if bilateral negotiations fail, allowing FERC to resolve any open issues. Alternatively, third, if there is no bilateral agreement reached within a reasonable period, the third party generator could force the gen-tie owner to file an OATT with FERC.
There can be no assurance that FERC will make changes to its current policy on a case-by-case basis or undertake a proposed rulemaking to consider changes to this policy, and the comments received by FERC in the aggregate demonstrate that there are no easy solutions.
But there appears to be sufficient support for moving either to a “tailored” OATT or a modification to the pro forma LGIA in order for FERC to proceed in one of these directions. In the interim, FERC may be willing to clarify its current gen-tie priority policy in the context of a specific developer’s filing for a declaratory order requesting priority on the use of some or all of the excess capacity on its gen-tie line.
Same Policy on Both?
Should the policy on merchant transmission and gen-tie capacity be the same? Gen-tie owners have argued that FERC policy should be different for them than for owners of merchant transmission capacity in large part because gen-tie owners never intended to become transmission providers whereas merchant transmission owners always intended to provide that service. But should original intent really matter?
Certainly finding “intent” is relevant in criminal law, where establishing intent is critical to establishing guilt or distinguishing between categories of crimes. But FERC’s obligation to serve the public interest includes the obligation to ensure that the jurisdictional services and facilities are not subject to undue discrimination or preference, where the intent of a provider’s action may be less important than its effects.
Most of the merchant transmission to date has involved one-way, DC transmission for point-to-point service. This type of service would not be materially distinguishable from a gen-tie owner’s point-to-point delivery of generation from its generating unit to the network grid. The size, voltage and delivery capacity of the gen-tie line can be, and often has been, as large or larger than the size of merchant transmission lines. With FERC’s “anchor tenant” policy for merchant transmission (and non-incumbent cost-based transmission), the merchant transmission provider will be allowed to lock up as much as 100% of the transmission capacity, even with affiliate generation. Gen-tie owners are also seeking ways that they can lock up unused gen-tie capacity for themselves and their affiliates for a safe harbor period or with a demonstration of plans for future use of the line.
Neither merchant transmission developers nor gen-tie developers have a legal obligation to construct transmission in the first instance. In both cases, the additional transmission capacity will bring needed generation to a networked system that values that generation. In each case there will be or can be a preference for the use of that capacity for one or more generation companies and its affiliates against unaffiliated potential competitors. FERC has to decide where to draw the line and how many lines it needs to draw.