Tapping the Power of Wind: Ferc Initiatives to Facilitate Transmission of Wind Power
Blakeway, Darrell, White, Carol Brotman, Energy Law Journal
So getting the [wind] plants built, getting the generation built is a very big step, but it's not the ultimate step. The ultimate step is getting that renewable power to the customer. . . . Barriers to entry for the wind energy have been and continue to be significant. . . . Because it's all about nondiscrimination. . . . It's giving a new technology which has a popular appeal, which has good environmental attributes, giving that technology a fair seat at the table with coal, nuclear, hydro, and gas. . . . I think the biggest barrier today that's preventing wide access to wind resources reaching customers is [the lack of] a robust transmission grid.1
I. INTRODUCTION AND SUMMARY
The wind energy industry is experiencing a phenomenal period of growth. It has become the fastest growing fuel-type for electrical generation installed in the U.S., with an average annual growth rate of over 27% from 2000-2004.2 Its growth has been spurred by public sentiment, state and federal policies, economics, technological improvements, increasing utility acceptance, and evidence from other countries that integrating large amounts of wind-generated electricity into the system does not degrade system operations. In particular, this growth is motivated by a growing public concern about pollution from conventional fossil-fuel energy sources, about enhancing national energy security by decreasing dependence on imported fuel, and the possible adverse climate effects from accumulating carbon dioxide in our atmosphere. The growing commercial interest in wind energy, and other forms of renewables, has also been driven by dramatic increases in the prices of fossil fuels-crude oil, gasoline, natural gas, and coal-and thus electricity. These price increases, with little hope for future reductions, have made various renewable energy technologies economically competitive.
Once built, however, wind generation faces stiff obstacles in reaching customers. Optimal wind resources are often located far from load, which may require additional transmission investment and construction. Wind developers and other generators might better utilize existing transmission paths by means of new transmission services that use transmission capacity during all but peak periods of transmission usage. Rules for financing and allocating costs of transmission facilities need to be re-examined in connection with developing wind resource areas. In response to these issues, the Federal Energy Regulatory Commission (FERC or Commission) has undertaken a series of steps to reexamine many of its rules to ensure they are not discriminatory against wind and other emerging renewable energy technologies.
First, the Commission conducted a rulemaking proceeding to establish special standards and procedures for interconnecting wind generation resources to the transmission system, because of their different characteristics compared to other conventional generation resources. After initiating the rulemaking proceeding, the Commission issued a Staff Briefing paper assessing the state of wind energy in the wholesale electricity markets, and conducted a public hearing on this topic. The Commission then convened a two-day public workshop to consider proposals for establishing new conditional firm and priority non-firm transmission services as a means of serving new wind developments because of insufficient additional firm transmission capacity. The Commission initiated a second rulemaking to establish non-punitive imbalance penalties for wind generators. Finally, the Commission acted on a filing to determine the mechanisms for recovery of the costs of transmission facilities needed to provide access to the grid for potential wind developments in the Tehachapi wind resource area of California.
A. History of Recent Commission Actions Affecting Wind Energy
Beginning in 2004, the FERC initiated a series of proceedings to address the problems faced by the wind industry, and particularly the problem of gaining access to the transmission system on reasonable and nondiscriminatory terms. The Commission had previously promulgated regulations governing interconnection of large generators to transmission. In Order No. 2003-A, on rehearing, the Commission noted that the standard interconnection procedures and agreement were based on the needs of traditional generators, and that a different approach might be necessary for generators relying on non-synchronous technologies, such as wind plants. The Commission appended a blank Appendix G as a placeholder for future adoption of special provisions for wind generation interconnection, as well as other asynchronous and/or intermittent energy sources.3
On September 24, 2004, the Commission conducted a technical conference on the American Wind Energy Association's (AWEA's) proposed standards for interconnection of wind generators to the grid, what AWEA labeled a "grid code." On January 24, 2005, the FERC issued a Notice of Proposed Rulemaking (NOPR) on various provisions of AWEA's grid code,4 and on May 25, 2005, issued the Final Rule as Order No. 661,5 providing the content for Appendix G, with national standards for grid safety and reliability for wind generators. On July 5, the North America Electric Reliability Council (NERC) filed a Request for Rehearing. (Full discussion in Section II below.)
On November 22, 2004, the Commission issued the agenda for a technical conference on wind energy to be convened in Denver, Colorado, on December 1, 2004, along with a staff paper, Assessing the State of Wind Energy in Wholesale Electricity Markets, which laid out a number of the issues the Commission expected to address at the conference.6 The issues raised by participants, audience members, and Commission staff gave rise to a number of initiatives discussed later in this article. (Full discussion in Section III, below.)
At the December conference, the Renewable Northwest Project (RNP)7 and West Wind Wires (WWW)8 announced that they had been working with Bonneville Power Administration (BPA or Bonneville) to develop a form of transmission service intermediate between long-term firm service and short-term non-firm. This new service would be called "Conditional Firm," and would be useful and available to intermittent wind and other generators that are unable to secure long-term firm transmission service. On February 1, 2005, the Commission issued a notice of a Technical Workshop on March 16-17, 2005, to discuss a draft of Bonneville's proposal, where the staffs of the BPA, FERC, and Western Electricity Coordinating Council (WECC) could work with market participants to develop definitions of conditional firm and other wholesale electric transmission services that could be offered in public utilities' open access transmission tariffs. (Full discussion in Section IV, below.)
Also at the December conference, a Southern California Edison Company (SCE) representative announced a proposal that SCE was working on to build long transmission lines to the Tehachapi wind resource area north of Los Angeles. He discussed the difficulty in expecting developers of relatively small wind projects to finance the costs of the extensive new transmission facilities there if such facilities were classified as "generation-tie facilities," needed only to connect generators to the grid. On March 24, 2005, SCE filed a request for declaratory order with the Commission, seeking rulings that the costs of three phases of its proposed transmission facilities from the Tehachapi Area could be rolled into system transmission costs that would be recovered from all transmission customers served by the California Independent System Operator (CAISO).9 On July 1, 2005, the Commission issued an order granting SCE's request in part, but denying rolled-in rate treatment for the segment of new transmission lines closest to the anticipated new wind projects. (Full discussion in Section VII, below.)
On April 14, 2005, the Commission issued a Notice of Proposed Rulemaking on Imbalance Penalties10 to require public utilities to append an intermittent generator imbalance service schedule to their Open Access Transmission Tariffs (OATTs).11 The schedule would widen the service to reflect a bandwidth of +/- 10% and allow net hourly intermittent generator imbalances within the bandwidth to be settled at a system's incremental cost at the time of the imbalance. The Commission also reiterated its policies that transmission customers are and must be allowed to change their schedule up to twenty minutes before the hour. (Full discussion in Section V, below.)
On April 22, 2005, the Commission conducted a Technical Conference "to examine impediments to investment in electric transmission infrastructure and explore potential solutions-including the formation of new business models as well as appropriate ratemaking incentives that would encourage new investment in transmission."12 The conference was convened more than two years after issuance of a Notice of Proposed Pricing Policy for Efficient Operation and Expansion of Transmission Grid.13
On May 12, 2005, the Commission issued the Final Rule on Standardization of Small Generator Interconnection Agreements and Procedures (Order No. 2006) for generators of no more than 20 MW capacity and concluded that no special provisions, such as those in the proposed Grid Code for interconnection of large generators, were necessary for small wind generators.14 (Full discussion in Section VI, below.)
B. Other Actions That Would Facilitate Development of Wind Energy
After having taken a number of steps to ensure that interconnection rules and transmission tariff provisions are fair and non-discriminatory to wind development, and that existing transmission capacity is being used most efficiently, the next important thing that can be done to facilitate greater use of wind energy is to implement policies that will foster construction of new transmission facilities. There will be many beneficiaries of new transmission infrastructure-all forms of generation, whether renewable or not, increased competition among generation sources, and increased reliability of the transmission system. But transmission facilities in locations where they can be economically accessed by wind generators in wind resource areas are critical to tapping the power of wind.
The costs of transmission facilities for wind developments are often higher than for conventional energy plants that can locate nearer electric transmission facilities and system loads. Moreover, the load factors for use of such transmission facilities by wind generators are lower than for generators that can be run almost continuously, or when most needed.15 Wind resources must be tapped where and when they are available, and many land-based wind resources are in areas remote from the major population centers, and thus the load centers.16 This is especially true for many mid-continent wind resource areas. On the other hand, there are strong wind resource areas just offshore of the United States, including many sites on the East Coast that are in relatively shallow waters, where the costs and technological feasibility of offshore wind developments are the best.17 Moreover, many of the country's population centers are closer to the offshore wind resources than the mid-continent resources, and can thus be interconnected to the grid with lower cost transmission facilities, although overall costs of offshore developments are still higher than onshore developments.
The outcome of public debates over the propriety and suitability of siting offshore wind developments between Cape Cod and Nantucket Island (the Cape Wind Project) and southeast of Jones Beach off Long Island (Long Island Offshore Wind Park) will have significant effects on the prospects for further offshore wind developments. The FERC could examine its pertinent jurisdiction to develop any applicable policies enabling fair interconnection of transmission infrastructure necessary to allow offshore developments.
Integrating and efficiently utilizing wind power is much easier in regions with independent system operators (ISOs) or regional transmission organizations (RTOs), with their large control areas, centrally dispatched energy markets, and day-ahead and real-time spot markets.18 The most efficient and cost-effective use of wind power, due to its intermittent nature, is to operate all other generators within a fairly large geographic area to augment the power from wind.19 In ISOs and RTOs, the market and operating rules and centrally dispatched balancing markets tend to be wind-friendly by their very nature. Even where no ISOs exist, the larger the "control area" for coordinating power markets, the easier it is to integrate wind resources and to dispatch the system efficiently. In parts of the country that do not have ISOs or RTOs, the Commission could continue to develop provisions of its electric utility Open Access Transmission Tariffs (OATTs) that eliminate undue discrimination against wind resources.
The proposals for conditional firm and high-priority non-firm transmission service will be evaluated when they are formally proposed to assure that existing transmission capacity is fully and efficiently utilized. Careful attention will also be given to how transmission owners calculate their Available Transfer Capability (ATC) (also called Available Transmission Capacity) to assure that transmission capacity is not only being used efficiently, but also fairly.20 Conditional firm and other alternative transmission products are not a substitute for construction of new transmission facilities, but can serve to utilize existing transmission facilities more fully and efficiently until they can be augmented.
The most important impediment for development of many of our wind resources is the lack of a robust transmission system, as former Chairman Pat Wood III has often noted. Accordingly, the Commission's efforts to foster and implement policies that remove barriers to the expansion of the transmission grid and provide appropriate incentives for private and public investment in such expansion, will be most important to the long-run interests for all forms of generation, including wind, and the enhanced reliability and security of our national electric systems.21
II. INTERCONNECTION FOR WIND ENERGY
Order No. 2003, the Large Generator Interconnection Rulemaking, was issued after nearly two years of stakeholder input involving generators, transmission providers, regulators, and trade associations. It required jurisdictional public utilities to amend their OATTs to include standard interconnection procedures (LGIP) and agreements (LGIA) for generators larger than 20 MW. Subsequently, in Order No. 2003-A, the Commission recognized that the interconnection needs of non-synchronous generators,22 such as wind plants, may be different than those of large synchronous generators, and that some provisions of the LGIA and LGIP may not be appropriate. Order 2003-A thus appended a blank Appendix G to the standard LGIA as a placeholder for future adoption of requirements for newer technologies.23 In 2004, AWEA initiated a series of events which led to the Commission's approving requirements for wind generators in Appendix G.
A. Timeline for Grid-Interconnection Rule for Large Wind Power Facilities
On May 20, 2004, AWEA requested that the FERC hold a Technical Conference to address the blank Appendix G.24 AWEA voluntarily proposed national wind performance and equipment standards that would address the concerns of both grid operators and the wind generation industry. The equipment, or technical, standards included low-voltage ride-through (LVRT) capability, power factor design criteria (reactive power), and supervisory control and data acquisition (SCADA) capability.25 The process standards included wind plant interconnection modeling, self-study of interconnection feasibility, and queuing procedures.26
On September 24, 2004, the FERC staff held a Technical Conference on the interconnection of wind energy projects and other alternative technologies. Sixteen panelists addressed staff questions on the special interconnection requirements for wind energy, the engineering implications of provisions in the proposal, and the potential impact on grid reliability and safety if the proposed standards for wind generators were to be adopted. Staff also asked panelists whether the proposed grid standards were applicable to small wind generation.27
On January 19, 2005, the FERC issued a proposed Rule for Wind Power Interconnection. The NOPR recognized the differences between connecting wind plants and conventional large central generation, and proposed performance and process standards for large wind generation in response to the areas suggested by AWEA. In its request for comments, the FERC asked whether other technologies should also comply with these standards.
The Final Rule on Interconnection for Wind Energy was issued on June 2, 2005, and published in the Federal Register on June 16 as Appendix G to Order No. 2003. The Rule applies only to the interconnection of wind plants over 20 MW. All public utilities subject to Commission jurisdiction are required to append the standard procedures and technical requirements for the interconnection of large wind generators to their standard large generator interconnection procedures (LGIP) and agreements (LGIA) in their OATTs.29
On July 5, the NERC requested a rehearing of Order No. 661, asserting that the adopted low-voltage ride-through (LVRT) standard for wind would permit violations of a reliability rule.30 On August 5, the FERC accepted a joint request from AWEA and NERC to extend the effective date of the Final Rule for 60 days, to allow them time to negotiate a solution. On September 19, AWEA and NERC jointly filed a report suggesting phased-in changes to the LVRT standard. Comments were due to the FERC by October 3; the Commission had not ruled on their proposed solution at the time of publication.
B. Why Did Wind Energy Need Separate Standards?
AWEA's proposal recognized the maturing of wind energy technology, its increasing presence on several transmission systems, and the needs of wind generators to be responsible grid citizens in terms of grid reliability and safety.
The performance and process standards, which became known as the "grid code," would provide national interconnection standards for wind developers and manufacturers, rather than the existing patchwork of standards, which vary by region, and for different manufacturers and technologies.31 Similar standards have been adopted in other countries once the wind industry reached similar levels of technological maturity and rates of penetration on transmission systems.
Wind power requires separate interconnection rules because large wind plants can consist of hundreds of small non-synchronous induction generators, located on sites laid out over a number of miles, and connected to the transmission system at a single point through a medium voltage collector system.32 Historically, wind generation has consumed reactive power, rather than providing it to the grid, as do large synchronous generators. In some cases, facilities are needed to provide reactive power to offset the effect of wind generators.33
In its Rule, the FERC noted that standards "minimize [the] opportunities for undue discrimination by Transmission Providers and removefs] unnecessary obstacles to the development of wind generation . . . ."34 The changes between the NOPR and Rule reduce the burdens on wind plant to install costly equipment that is not needed for safety or reliability. A national standard can benefit consumers; and a stable, consistent design target decreases manufacturing costs, thus lowering wind power's cost. A standard encourages competition, increases efficiency, and promotes technological improvement.
C. What Standards Are Included and Under What Circumstances?
1. Equipment or Technical Standards
AWEA's proposal and the Final Rule address equipment standards for wind interconnection to enhance system reliability in three areas: the ability to stay online during voltage disturbances, to provide reactive power to the grid, and to have real-time communications and data exchange capability between the wind plant and grid operator.
Low-voltage ride-through (LVRT) equipment enables wind plants to stay on-line during voltage disturbances on the grid. Early wind generation technology often was shut down when the grid system experienced sudden drops in voltage. Unlike large synchronous facilities, wind generators are not equipped with automatic voltage controls. Wind generators want to stay on-line, and technology advances have made it possible. AWEA proposed a low-voltage ride-through standard for large wind plants. The Rule adopts the LVRT standard, but changed the language to allow interconnection of wind plants that possess LVRT capability, where it is needed, without requiring them to provide that capability in every situation. It also notes that the standard is similar to those used in other countries and recently adopted by the Western Electricity Coordinating Council (WECC).35 AWEA and NERC proposed an interim standard for wind farms with interconnection agreements signed in 2006 or which had turbine orders executed in 2005. It would require wind farms to stay on line during system voltage sags as low as 15% of normal, for up to 0.15 seconds. For wind farms developed after these dates, the standard would require them to stay connected through voltage dips to as low as zero volts.
Reactive power support for the grid, also known as "power factor design criteria," is necessary to balance the reactive power needs of the transmission system. Because of the increasing size of wind plants and their increasing presence on various transmission systems, AWEA proposed that wind facilities should demonstrate this capability. The rule adopts the same criteria for large wind power as for large conventional generation, which requires that plants operate within a power factor range of 0.95 leading to 0.95 lagging, where needed. In addition, the Rule gives wind plants the flexibility to use a variety of combinations of equipment to provide reactive power capability,36 including dynamic voltage-ampere reactive37 (DVAR) banks, switched capacitors (static), or a combination.38
SCADA capability enables real-time communications and data exchange between the power producers and grid operators. It consists of bi-directional electronic communications equipment, which allows the exchange of information for scheduling and forecasting. The Rule requires that the wind interconnection customer provide SCADA capability, with the underscored caveat that the specific capability and type of information to be exchanged must be negotiated between the wind plant and the transmission provider, outside of Appendix G and the LGIA. The Rule does not give the transmission provider the right to control the wind plant.39
2. Process Standards
AWEA's proposal and the Final Rule address two process standards for wind interconnection: models for wind plant interconnection and a change in procedures to enter the interconnection queue.
AWEA's "grid code" urged the Commission to require Transmission Providers and wind generator manufacturers to "participate in a formal process for developing, updating and improving the engineering models and turbine specifications used for modeling the wind plant interconnection."40 In both the proposed and final Rule, the FERC recognized that wind interconnection modeling improvements would be helpful, but suggested that this process should be undertaken by industry technical groups, the NERC, and regional reliability councils.41
The second process proposal addressed what the wind industry saw as a "Catch-22" in entering the interconnection queue. It suggested that wind plants be allowed to enter the queue and receive the base-case data to "self-study" the feasibility of its proposed interconnection without having first submitted a formal "interconnection request" that includes power and load flow data and fully completed plant electric design specifications, as required under Order No. 2003. AWEA argued that turbine selection and the electrical design of the entire wind farm is an output of the feasibility study, which could only be determined once the base case data was received, especially since the turbine selection decision is influenced by grid conditions at the point of interconnection (POI).42
In the NOPR, the FERC denied AWEA's request, in part, not to favor one form of generation over another, and in part not to compromise Critical Energy Infrastructure Information. In the Rule, the FERC found a compromise on entering the queue. The Rule allows a wind plant to provide a preliminary set of design specifications that depict the entire wind plant as a single equivalent generator in terms of its megawatt output (MW or real power) and reactive power (M-VAR) range. The wind plant developer would then pay a fee, enter the queue, and receive the base case data as provided in Order No. 2003.43
The Order noted that some of the data received by the wind plant from the transmission provider was key to final siting:
[the] physical placement of the turbines, transformers and voltage support devices that affect the electrical characteristics created by the medium voltage collector system depend on the size and location of the wind plant and the location of other generators on the Transmission Provider's system. For these reasons, wind plant developers are unable to submit completed design specifications for individual wind turbines until much later in the interconnection process, in comparison with other developers.44
D. Where Should Technical Capability Be Measured?
The LVRT modification proposes that it be measured at the "high-side" of the step-up transformer, that is, on the transmission side of the system. While the NOPR proposed that LVRT and power factor capability be measured at the high voltage side of the wind plant substation transformer,45 the Rule clarifies that the appropriate point to measure the capability is the Point of Interconnection (POI). The Rule notes for LVRT that the "Point of Interconnection is the point at which the Interconnection Customer's responsibility ends and the Transmission Provider's responsibility begins."46 The POI is also appropriate for measurement of the power factor, because it is closer to the bulk electric power system, and this requirement is consistent with Order No. 2003. One commenter who concurred noted that while the POI may be more costly for wind plants with long generation tie lines, using a different measuring point would not meet system reliability needs.47
E. When Should the Standards Be Required and Be Effective?
The Rule makes a critical departure from the NOPR by requiring LVRT and reactive power standards only when needed by the grid for safety or reliability. The Rule shifts the burden of proof from wind plants to transmission providers to demonstrate the need for additional equipment at a particular location. The NOPR would have required large wind plants seeking interconnection to "demonstrate LVRT capability" and to "maintain a power factor within the range of 0.95 leading to 0.95 lagging" (as required by Order No. 2003) "unless waived by the Transmission Provider on a comparable and not unduly discriminatory basis for all wind plants."48
The Rule, instead, adopts "the standard[s] proposed in the NOPR, but will not require that [they] be met unless . . . the Transmission Provider shows, through the System Impact Study, that such capability is required [of that plant] to ensure safety or reliability."49 Numerous cotnmenters to the NOPR waiver provision expressed concern that the transmission provider would routinely require the new equipment standards of all wind plants, whether needed or not. A universal requirement would add unnecessary costs without necessarily increasing reliability, thus inhibiting wind power development. As Chairman Wood said, in effect, at the May 25, 2005 Commission meeting, just because a transmission operator wants something, does not mean it is necessary for reliability or for engineering requirements, and the Commission needs to prevent undue discrimination.50
The Rule creates two compliance dates. The procedural requirements take effect sixty days from publication in the Federal Register, but create a transition period for the substantive technical requirements for LVRT, SCADA, and power factor design criteria. These will be applied, if applicable, only to LGIAs signed or filed with the Commission on or after January 1, 2006, or six months from the date of the Rule's publication in the Federal Register, whichever is later.51 This transition period allows manufacturers sufficient lead-time to add the equipment features to wind turbines. A transition would not disrupt deliveries of turbines already ordered before the Rule was issued. Existing LGIAs are grandfathered. Transmission providers are required to amend their LGIAs and LGIPs with these procedures and technical requirements, as provided in Appendix G.52
The Rule imposes a six-month time limit between a wind plant's receiving base case data from the transmission provider and its submitting completed detailed design specifications. The transmission provider needs these details to complete its System Impact Study. The deadline ensures that the transmission provider doesn't have "uncertain projects in the queue."53
III. ASSESSING THE STATE OF WIND ENERGY IN WHOLESALE ELECTRICITY MARKETS
On November 22, 2004, the FERC issued a Staff Briefing paper that described the current state of wind power, the drivers behind its growth, and the issues wind energy faces for future development. Concurrently with issuing the Staff Paper, the FERC issued an agenda for a technical conference to discuss issues raised in that paper and a series of specific questions addressed to the invited panelists.54
A. Staff Briefing Paper
The briefing paper described a number of drivers and issues affecting the development of wind power, some of which are described below, others are noted in the introduction and throughout this article where relevant to particular actions undertaken by the FERC.
1. State Policies
States' policies increasingly promote renewable energy through a variety of mechanisms. Twenty-one states and the District of Columbia have enacted or administratively promulgated Renewable Portfolio Standards (RPS); nine of these were passed or amended in 2004 and seven were passed or amended in 2005.55 An RPS reflects a State's commitment to adding rencwables to the mix of generation, generally at a rate that increases yearly and which applies to all retail electricity suppliers. The durations of an RPS, the percent of renewables in the goal, and which fuels are included vary widely. Some States that have already achieved their initial goals are considering raising them by amending their RPS. A few have specified a percent of the total that must be met by a particular fuel, such as wind or solar. States have enacted these standards to encourage fuel diversity, to lessen dependence on fuel imports, to acknowledge public environmental concerns, and to meet more stringent EPA emissions requirements.
Other state renewable incentives include loan funds, grant programs, tax exemptions, net metering, and green power purchasing programs. Many state governments have committed to purchasing an increasing percent of their supply from renewable energy. Some states without an RPS are also encouraging retail electric suppliers to increase the percent of renewables in their generation mix or requiring some larger suppliers to include renewable energy as a tradeoff for other generation approvals.
2. Costs More Attractive
A modern wind turbine can generate electricity for 4¢-6¢/kWh, before federal tax subsidies or other state financial incentives.56 After subsidies, large-scale wind in the United States today can sell power to utilities at a low of 2¢/kWh, and a high of around 5¢/kWh, with a more common range of 2.5¢/kWh-3.5¢/kWh for new projects.57 Given current natural gas prices, the levelized cost of building a new wind generation plant can compare favorably with the cost of a new gas-fired plant, which costs at least 5.5¢/kWh, including both fuel and capital costs.58
3. Companies' Increased Comfort With Wind Power
Large international companies are making changes in their energy purchases to begin compliance with global carbon caps, while others include assumptions on carbon costs in their energy analyses, on the assumption that the United States may some day institute carbon taxes, caps, or adders. The California Energy Commission has already instituted a carbon adder that utilities must use when they compare the costs of responses to RFPs (requests for proposals) for future capacity. Some utility planners are voluntarily calculating similar adders when they assess new resources. These economic assumptions give an additional boost to wind resources as a part of companies' energy portfolios, many of which are seeking hedges against rising fuel prices.
As utilities become more familiar with integrating wind resources into their portfolios and transmission systems, they are less wary about dealing with issues such as the intermittency of wind. They have discovered that these issues can be resolved without large additional expenditures. Recent studies for Minnesota and New York demonstrated that the addition of large amounts of wind on their systems could be accomplished at an incremental operating cost between $1/MWh and $4.60/MWh, with similar reductions in market prices.59
4. Production Tax Credits
The Federal Production Tax Credit (PTC) for wind-generated electricity was renewed in October 2004; the PTC, now 1.9¢/kWh,60 is good for ten years from the date a project is operational for projects online by the end of 2005. Its renewal set off a flurry of new wind generation projects. Within a month, five utilities and their affiliates announced that fully permitted projects totaling 829 MW, all stalled during the lapse, were going forward. The wind industry association expected between 2,000 MW and 2,500 MW to be installed in 2005.61
The PTC is a key for financing wind projects, because it increases annual cash flow by close to 38% for the first ten years of a plant's life.62 The PTC's history has been one of two-year extensions followed by a lapse of several months before its renewal, creating a boom-bust cycle in the building of wind projects.63 This cycle creates planning uncertainty for wind developers, financial backers, turbine manufacturers, and skilled workers.64 While several groups called upon Congress to extend the PTC for five years; the final Energy Bill passed by the 109th Congress extended it for two years, through 2007.65
5. Long-Term Contracts
Another key to wind development is the availability of long-term contracts for the off-take of wind power, usually for ten to twenty years. Unlike in the early years of wind power development under provisions of the Public Utilities Regulatory Policy Act of 1978 (PURPA),66 modern wind plants tend to be built either as merchant plants or in response to a utility RFP (request for proposal) for wind. In both cases, developers need to secure long-term power purchase agreements to obtain financial backing. Some states encourage long-term contracts in their RPSs; in others where utilities are moving slowly to meet their mandates, wind advocates are encouraging states to require long-term contracts to enable renewable financing.67
B. Technical Conference on Wind Energy in Wholesale Power Markets
The December 1st Technical Conference had three objectives for its panel sessions: first, drivers and issues to wind energy participation in wholesale markets; second, planning, grid operation and utilization to account for wind and other emerging technologies; and third, OATT-services and pricing issues faced by wind generators.
The main theme of the conference revolved around tariff reform and how the FERC could make Order No. 888's pro forma tariff68 more "wind friendly." The subjects raised most often by panelists and by audience comments were the need to address punitive imbalance charges levied against wind, the need for tariff reform and new transmission products other than the two described under Order No. 888, the need to find ways to use the existing transmission system more efficiently until the day when more transmission is built, and the need for better forecasting.69 The issues raised by participants, audience members, and Commission staff gave rise to a number of initiatives discussed elsewhere in this article, including:
* A Proposed Rule on Imbalance Provisions for Intermittent Resources (see Section VI),
* Bonneville's Conditional Firm Transmission Service Proposal (see Section IV), and
* Southern California Edison's Renewable Trunk-Facility proposal (see Section VII).
C. Conference Follow-Up
In its request for comments, the FERC noted that a number of "action items" were raised at the conference by the Commission staff or conference participants. Among them were whether the FERC should re-evaluate the imbalance penalties under Order No. 888's pro forma transmission tariff; how the FERC and the industry could make more efficient use of existing transmission facilities with potential new wholesale transmission services; if the FERC should examine the possibility of adopting a new transmission interconnection category-a "Renewable Resource Trunk Facility"-that would not be treated as a generation-tie and which would be rolled into rates; how the FERC could work with the states on their preferences for Renewable Portfolio Standards; what special issues Native American tribes face in developing wind energy and on what issues should the FERC consult with them on wind development; and if the FERC should help to establish capacity credit criteria or advocate a method of determining capacity value of intermittent resources.70
The FERC's initial efforts followed two lines of tariff reform: resolving whether imbalance penalties frequently assessed on wind generation under Order No. 888's OATT were unduly discriminatory, and developing new transmission services that would allow for more efficient use of existing transmission capacity for all sources of generation. The Commission undertook extensive outreach with wind industry participants and the public for feedback on issues which were raised at the conference and how best to facilitate wind's integration into the transmission system.71
IV. BONNEVILLE'S CONDITIONAL FIRM PROPOSAL
A. What Is the Need for Conditional Firm Transmission Service?
Wind developments need long-term transmission contracts in order to arrange financing for their projects, but under "OATTs" required by the FERC, there are only two transmission products available to wind developers: long-term firm, when the transmission owner can provide firm transmission under all circumstances when the system is not generally curtailed, and short-term nonfirm, in which the customer is subject to curtailment whenever necessary to meet the transmission demands of the long-term firm customers.72 Typically, however, short-term non-firm service is only available for less than a year, and does not entail the right to rollover such service for succeeding years, as do long-term firm service contracts. Short-term non-firm service, while it may provide adequate service, is not attractive to investors and lenders for project financing of wind developments because it does not provide a basis for projecting long-term revenues from projects.
B. Background of the Proposal
The Renewable Northwest Project (RNP) and West Wind Wires (WWW) both participated in the Rocky Mountain Area Transmission Study (RMATS). RMATS grew out of a call by the Western Governors' Association in response to the 2000-2001 energy market crisis in the western states to develop a preliminary transmission study and state siting protocol to address electric transmission needs in western power markets.73 The RMATS Report, presented to the Western Governors' Association in September 2004, concluded, among other things, that making the most efficient use of existing transmission infrastructure is a prerequisite for persuading regulators, political leaders, and the public that new transmission construction is truly needed. The Report noted that there is not year-round Available Transmission Capacity (ATC) on many transmission paths in the Western Electric Coordinating Council (WECC) region, but there were paths that were congested for only twenty to fifty hours per year, and that wind generators could use such capacity to move substantial amounts of wind energy if the transmission owners would provide some form of service that was intermediate between short-term non-firm and long-term firm service.74 The RMATS study group recommended that transmission owners and operators develop two more transmission service products that are intermediate between long-term firm and short-term non-firm, namely long-term "conditional firm," and "priority non-firm" services.75
At the December 1st Conference, a Bonneville representative said that it had been in consultation with RNP and WWW about developing such tariff provisions for its OATT, was planning a two-day workshop in February 2005, to discuss the details of such proposals, and hoped to have FERC involvement in that workshop. Accordingly, the FERC created a new docket to consider such proposals,76 and participated in a Technical Workshop on that topic in Portland, Oregon, on March 16-17, 2005.
Under the proposal, conditional firm service would be like long-term firm, except the transmission provider would specify certain periods of the year when its expectations of transmission congestion require the curtailment of conditional firm service prior to any curtailment of firm service customers. For example, a conditional firm customer might receive firm service for ten or eleven months of the year, but be subject to curtailment prior to curtailment of firm service customers during one or two specified months of the year, when transmission congestion is most likely.
The transmission provider could also specify a cap on the number of hours a conditional firm customer would be curtailed prior to curtailment of firm customers during the specified months of conditional firm service. If curtailment of firm service customers became necessary during the months that conditional firm customers are assured firm service, or after the maximum number of hours specified for curtailment during a month when conditional firm service is conditional, the conditional firm customers could be curtailed at the same time (not prior to), and in the same proportion, as all other firm customers. Conditional firm service would only be offered to a customer who has requested firm service, but cannot receive it due to the lack of ATC on the path in question, and conditional firm customers must be willing to accept firm service when and if it becomes available.77
Long-term priority non-firm service would be subject to curtailment of service prior to any curtailment of firm or conditional firm service customers, but only after curtailment of all other non-firm service customers. Moreover, priority non-firm service would be offered for a term of one year or longer, unlike the limitation of non-firm service to terms of less than a year.78
The intriguing feature of Bonneville's possible offering of conditional firm-is that it might provide the virtual equivalent of firm service for most of the time that wind generators need the transmission capacity. The periods of time when BPA's firm transmission commitments preclude offering new firm service to wind may largely coincide with the periods when wind generation is least likely. But, even without such a happy coincidence, if wind generators could be offered long-term service that was virtually firm for a substantial part of the year, with a defined period and defined number of hours during which wind would be curtailed prior to curtailment of firm service customers, the ability of developers to finance wind generation could be significantly enhanced.
C. Comments Filed After Technical Workshop
In its post-conference filing, the American Public Power Association (APPA) argued that the transmission providers should not guarantee a limited number of curtailment events or hours. According to APPA, such guarantees are difficult to make even to firm customers, and providing such guarantees to conditional firm customers would discriminate against firm customers without such guarantees. APPA also asserted that conditional firm service may be feasible for BPA because of the large amount of hydroelectric facilities whose output can be quickly varied in response to available wind energy, and where pumped storage hydroelectric projects would permit excess wind energy to 'be "stored" by using it to fill pumped storage reservoirs.79 However, APPA doubted that other regions of the country without so much hydroelectric capacity could integrate with wind energy as easily, and that the conditional firm service that BPA is considering may not work in omer regions.80
Southern Company's post-workshop comments urged the Commission not to apply BPA's conditional firm proposal to other transmission providers in different circumstances (i.e., not in the Southeast). Southern also questioned the reliability and accuracy of the "probabilistic analysis" that BPA's proposal entails, rather than the conventional "deterministic method." Southern foresaw significant problems establishing where a request for conditional firm service would fit into the "queue" along with requests for firm and non-firm service, and determining when conditional firm service should be curtailed in relation to firm service, both point-to-point firm and network service firm.81 Southern was also concerned that providing conditional firm transmission for a lower rate than firm, but guaranteeing it firm service on the basis of probabilistic analysis that may prove to be inaccurate, will result in firm transmission customers subsidizing conditional firm customers, or retail ratepayers bearing the costs associated with possible decreases in available firm transmission service.82
AWEA et al. responded to some of these comments, clarifying that any cap on the number of hours that a conditional firm customer would be curtailed meant a cap on the number of hours that the customer would be curtailed while firm customers are not being curtailed. There would be no limits on the number of hours or events of curtailment of conditional firm pro rata with curtailment of firm customers at the same time. As explained in its responsive comments, AWEA et al. viewed conditional firm as enabling incremental amounts of new generation to interconnect to the grid, even though there may not be enough new generation capacity to justify construction of new transmission facilities. Furthermore, AWEA et al. anticipated that revenues from conditional firm would be greater than existing levels of revenue from short-term firm and shortterm