Green Gridworks


Case studies on integrating renewable resources.

Fortnightly Magazine - February 2012

Transmission issues of need and siting have been around for decades. More recently, the push to integrate renewable resources has raised new transmission issues of planning, risk allocation, and funding responsibility. Many regional transmission organizations (RTOs) and other transmission entities have been wrestling with these new issues, and now FERC has weighed in with Order 1000 that provides transmission planning and cost allocation guidelines while preserving the RTO stakeholder processes.

FERC issued its final rule in Order 1000 on July 21, 2011. Order 1000 applies Order 890’s planning principles—coordination, openness, transparency, information exchange, comparability, dispute resolution, regional coordination, economic planning, and cost allocation—to regional transmission planning. Order 1000 also requires RTOs and other entities to cooperate on transmission planning and cost allocation matters, and requires regions to adopt a form of “beneficiaries pay” cost allocation to ensure that transmission costs are allocated to beneficiaries, commensurate with estimated benefits.

Some of the regions where the wind integration processes have been most successful developed and adopted basic transmission planning and cost allocation principles prior to FERC Order 1000. Instructive examples can be found in the experiences of three states that have integrated, or are trying to integrate, substantial wind resources into their high voltage grids: Texas, California, and Hawaii.

Texas and Hawaii transmission organizations aren’t jurisdictional to FERC, so Order 1000 doesn’t apply to them directly. Texas and California have single-state RTOs, which has facilitated renewable development and has avoided free rider and cost allocation issues plaguing multi-state RTOs. Hawaii, also a single-state market, is wrestling with these very issues. Notwithstanding the successes to date, there are still many renewable integration challenges that require further attention.

Texas: Competitive Zones

Parts of Texas have significant wind resources. In 2005, the Texas Legislature established a Renewable Energy Program directing the Public Utility Commission of Texas (PUCT) to identify competitive renewable energy zones (CREZ), geographic areas ideally suited for wind generation construction. In response to this legislation, the PUCT issued an order in Docket No. 33672 in 2008 designating CREZ areas and defining a set of transmission upgrades to interconnect the wind projects, plus a small amount of other renewable energy projects. Those upgrades were planned to transmit energy from 18,456 MW of wind resources in remote parts of west-central and northern (Panhandle) Texas to highly populated metropolitan areas of the state, including Austin, Dallas-Fort Worth, and San Antonio. The new wind resources were planned to be located in five CREZ zones with a total incremental capacity of 11,553 MW (see Figure 1). The remaining 6,903 MW is the base-case wind capacity that would exist without the CREZ program. It was expected that the wind energy would improve the air quality in Texas and minimize reliance on the then-high cost of gas-fired generation.

The PUCT approved $4.93 billion for seven transmission service providers to construct the CREZ transmission upgrades. Several of these lines also would meet the long-term needs of the growing area west of the I-35 corridor near San Antonio and Austin. The PUCT identified three categories of CREZ upgrades: “default projects” (accounting for 19.2 percent of the expected cost), “priority projects” (20.3 percent), and “subsequent projects” (60.5 percent).

Default projects are those that refit, rebuild, or enhance the existing transmission infrastructure. The CREZ default projects were awarded to the transmission service providers that owned the existing infrastructure. A number of CREZ default projects have been completed and others are in various stages of completion.

Priority projects are those necessary to alleviate current or projected transmission congestion issues and have the highest priority for completion. CREZ priority projects were awarded to two incumbent transmission service providers: Oncor Electric Delivery and Lower Colorado River Authority Transmission Services.

Subsequent projects are the remaining CREZ upgrades. These comprise the largest cost category because they involve creating new rights-of-way.

The transmission upgrades were originally identified through the CREZ Transmission Optimization Study conducted by the Electric Reliability Council of Texas (ERCOT) in 2008. This study was a planning-level evaluation designed to identify which areas of Texas were best suited for the continued expansion of installed wind farm electrical generation and what transmission upgrades would be necessary to transmit that generation to the population centers (see Figure 2). ERCOT applied three overarching criteria to the optimization study: system reliability, sufficient transfer capacity, and how “beneficial and cost-effective to consumers” each project would be. The optimization study included preliminary cost estimates and designated the general locations of substations and transmission routes from a planning-level perspective, with four different scenarios of various system configurations and power capacities. The PUCT selected Scenario 2 with an associated cost of $4.93 billion to accommodate 18,456 MW of wind power.

ERCOT subsequently commissioned ABB to refine the scope of transmission upgrades based on a more detailed CREZ Reactive Power Study that identified the size, type, and location of equipment needed to control, condition, and route the power through the CREZ upgrades to the existing electric grid. Results from the reactive power study, published in December 2010, are being reviewed by the transmission service providers and likely will result in additional reactive power equipment—and costs—being added to some of the CREZ projects.

Additional necessary transmission projects were identified after the optimization study was published and are being finalized as wind projects and the CREZ upgrades continue to be developed. The total cost of the CREZ upgrades is currently estimated at $6.79 billion, as unforeseen route conditions and adjustments to the rights-of-way have required design changes. The total CREZ transmission cost likely will continue changing over the next year as more detailed transmission upgrades are expected based on the reactive power study.

As in most states, a Texas transmission service provider must submit an application for a certificate of convenience and necessity (CCN) to the PUCT in order to construct a new transmission line. A CCN allows transmission service providers to proceed with construction and exercise the power of eminent domain where necessary. The CCN applications in CREZ program are contested cases that generally focus on selecting a transmission route from alternatives proposed by the transmission service providers. In contrast to the regular CCN applications, the applicant in a CREZ proceeding doesn’t need to show that the construction is necessary for the service, accommodation, convenience, or safety of the public. CCN applicants are required to identify a preferred route, though this designation doesn’t necessarily mean that the PUCT will approve it. CREZ CCN applications are statutorily required to be completed within 180 days, instead of the normal one-year period, and the PUCT has the option of approving a route, approving it in part, or denying the application.

The PUCT recognized the critical issue of project-on-project risk, i.e. wind projects require the CREZ transmission build-outs and vice versa. Delays or cancellations of wind development, even with commitment guarantees, could result in under-utilization of the new transmission lines, while aggressive wind development in advance of transmission build-out could result in transmission congestion and market inefficiencies. The PUCT’s solution, per CREZ amendments in November 2009, was to require renewable generators to demonstrate sufficient financial commitment before the PUCT would process the CCN applications for the associated CREZ transmission upgrades. The PUCT determined that installed generating capacity, active construction of new generation, and signed interconnection agreements—a critical development milestone—were the best measures of wind generator financial commitment. For the three west-central CREZ zones—McCamey, Central, and Central West—the PUCT determined that the wind generation that was already developed, along with additional wind generation under active development, and the wind capacity with signed interconnection agreements as of October 2009, demonstrated that sufficient financial commitments had been made to justify the construction of the CREZ upgrades to these zones. The financial commitments of these wind generators are formally recognized in related CCN proceedings.

The PUCT also determined that the wind developers in the northern CREZ zones, Panhandle A and B, hadn’t yet demonstrated sufficient financial commitments. Those wind generators will have the opportunity to either meet the standard described above or demonstrate financial commitment by posting collateral before the PUCT processes their CCN applications. Under the PUCT’s amendments, those wind generators would have to post collateral of $15,350 per MW of capacity corresponding to their planned projects, or $10,000 per MW if the capacity is supported by appropriate lease agreements. These collateral amounts are equivalent to roughly 1 percent or less of the wind projects’ total estimated capital cost. If the total capacity represented by completed projects, projects under construction, projects with signed interconnection agreements, and projects posting collateral is at least 50 percent of the designated capacity for a CREZ upgrade, the financial commitment requirement will be deemed to be met. Collateral would be refunded when a wind or other renewable generator signs an interconnection agreement with the relevant transmission service provider but would otherwise be forfeited.

Most of the CREZ default projects didn’t require a CCN and have either been completed or are under construction. All of the CREZ priority and subsequent projects required new rights-of-way and thus CCN applications. All but one of the CCN applications for CREZ priority projects were approved by the PUCT and are proceeding toward acquiring rights-of-way and construction. One priority project, the Lower Colorado River Authority’s Gillespie-Newton transmission line, was denied by the PUCT and canceled. It likely will be replaced by an upgrade to existing transmission infrastructure in the near term.

The last CREZ upgrade is expected to be completed by Dec. 31, 2013. There are still risks of scheduling delays over the next year, as many of the upgrades are still being developed, routes selected, and designs with schedules finalized.

California: Expansion Planning

California has a range of significant renewable resource potential—solar, wind, geothermal, and biomass. The California integration experience is mixed, with considerable transmission progress made to deliver renewable energy from one region, the Tehachapi Wind Resource Area, and more limited progress to link up geothermal and solar energy in another, the Imperial Valley.

In 2002, California established its renewable portfolio standard (RPS) program, with an initial goal of having renewable energy contribute 20 percent of the state’s retail sales by 2017. Later studies recommended accelerating that goal, and Senate Bill 107 in 2006 codified a 20 percent RPS target by 2010. Figure 3 shows the progress since the start of the RPS program of the three largest investor owned utilities, which serve about two thirds of California’s load. Prior to 2011, compliance with RPS targets by municipals, cooperatives, and other public power utilities was voluntary. According to the California Energy Commission, public utilities added only 290 MW of renewables since the RPS program began, and the total statewide renewable generation in 2010 was about 16 percent of statewide retail sales—less than the 20 percent target.

In 2008, Gov. Arnold Schwarzenegger signed Executive Order S-14-08 requiring that “...[a]ll retail sellers of electricity shall serve 33 percent of their load with renewable energy by 2020.” The following year, Executive Order S-21-09 directed the California Air Resources Board to enact regulations to achieve the 33 percent renewable energy goal by 2020. According to the California Independent System Operator (CAISO) 2010-2011 Transmission Plan, the quantity of renewable generation will have to more than double current levels in order to meet the goal in 2020. The additional 53 TWh required to meet that goal (see Figure 4), would require about 20,000 MW of new renewable wind resources, a very ambitious goal considering the fact that only 2,300 MW of renewable resources were added between 2003 and 2010.

When the 2002 RPS law was passed, the Tehachapi area was already one of the major wind generation centers in California with about 700 MW in service. Tehachapi, about 100 miles north of Los Angeles, is served by Southern California Edison. In their 2003 reports to the legislature, both the California Energy Commission and the California Public Utilities Commission (CPUC) stated that the Tehachapi area had the potential to supply about 40 percent of the energy needed to meet the RPS. According to the California Energy Commission’s 2003 Renewable Resources Development Report, the Tehachapi Area has the largest renewable resource potential in California, except for solar power installations, which weren’t considered to be cost-competitive at the time. The CPUC issued Decision No. 0406010 in 2004 that convened the Tehachapi Collaborative Study Group to produce a comprehensive development plan for a phased transmission expansion to accommodate 4,500 MW of potential renewable capacity in the Tehachapi wind resource area. The CPUC also required Southern California Edison to prepare a formal CCN application for the first phase of that expansion.

As with other states, California had to address the question of transmission cost recovery. In response to a petition from Southern California Edison for a declaratory order (Docket No. EL05-80), FERC initially determined that Segment 3 of the planned Tehachapi Renewable Transmission project (see Figure 5) wasn’t a network upgrade and, therefore, wasn’t eligible for rolled-in rate treatment. FERC noted further that FERC precedent wouldn’t allow the costs of such facilities to be shifted from the interconnection customers to all users of the transmission grid. Nevertheless, the CPUC approved Phase 1 of the Tehachapi project in March 2007 that included $207 million of new 500 kV lines—initially operated at 230 kV—and associated upgrades to accommodate 700 MW of new capacity. Under the CPUC’s decision, Southern California Edison was permitted to recover through its retail rates any costs not approved by FERC for recovery through CAISO’s wholesale transmission rates.

FERC issued an order granting petition for declaratory order in November 2007 regarding an expanded Tehachapi project consisting of the three Phase 1 segments previously reviewed plus eight additional Phase 2 segments (see Figure 6). FERC determined that most of Segment 3 could now be considered a network facility—by the addition of Segments 4 and 10—and therefore qualified for rolled-in rate treatment.

In December 2007, FERC approved an amendment to the CAISO tariff that added provisions for “location constrained resource interconnection facilities.” Before that time, the costs of radial generator interconnections weren’t eligible for recovery through the CAISO tariff. Under the new provisions, the costs of location constrained resource interconnection facilities designed to serve more than one generator can initially be covered by the CAISO tariff with the costs ultimately to be paid by the connecting generators after they come on line. In May 2009, the CAISO announced that the radial line from Windhub to Highwind—a portion of Segment 3—had been approved by the CAISO Board as the first location constrained resource interconnection facility. However, construction of this project remains on hold until sufficient capacity on the lines is requested by generators.

In 2009, the CPUC approved the remaining Phase 2 segments, estimated to cost $1.8 billion, and reiterated the Tehachapi project’s eligibility for backstop retail rate recovery. Phase 1 was completed in 2009, and several segments of Phase 2 have been completed, with the last planned for completion in 2013. At this writing, FERC was expected to approve cost recovery of all phases through CAISO transmission rates, so backstop retail rate cost recovery might not be utilized.

Transmission to interconnect new geothermal and biomass resources in the Imperial Valley followed a different development path. The Imperial Irrigation District provides electric power to the Imperial Valley and parts of Riverside and San Diego counties, and it operates its own balancing area independent of CAISO. An Imperial Valley study group was formed as an outgrowth of CPUC Decision No. 0406010 to address transmission plans for geothermal and solar renewable resources in that region. The group’s 2005 report analyzed several transmission alternatives to export about 2,200 MW of renewable energy from the Imperial Irrigation District’s territory; the total potential for renewable energy was estimated to be even larger. According to a 2009 report by a statewide collaborative group, the Renewable Energy Transmission Initiative, the Imperial North A CREZ was found to have the best environmental ranking—e.g., the lowest score—and one of the best economic rankings (see Figure 7). The potential renewable generation is much greater than the Imperial Irrigation District’s native load of about 1,000 MW—less than 2 percent of California’s statewide load—and is almost an order of magnitude greater than the amount the Imperial Irrigation District would need to meet its own 33 percent RPS target. Therefore, development of these resources would be primarily for the benefit of the other California balancing authority areas and would require associated transmission upgrades to export the added renewable energy from the Imperial Irrigation District.

Because of its small size, Imperial Irrigation District faced a significant risk that the transmission costs for 2,200 MW of exports might become stranded if renewable development was delayed or abandoned. However, the development of a statewide transmission plan under the auspices of the California Transmission Planning Group appears to have improved the likelihood that Imperial Irrigation District will be able to build transmission for export in the next few years. The group was formed in early 2009 as a result of discussions facilitated by FERC to address California‘s transmission needs in a coordinated manner that would include all California balancing authorities. It provides a forum for conducting joint transmission planning studies consistent with FERC Order 890 principles and for coordinating transmission planning among its members. In February 2011, the California Transmission Planning Group issued its first statewide plan that evaluated numerous potential transmission projects against four scenarios of potential renewable development and recommended selected projects.

According to the California Transmission Planning Group report, the Imperial Irrigation District wheels approximately 580 MW of geothermal energy from the Imperial Valley into the CAISO balancing authority. With new planned upgrades, Imperial Irrigation District exports could increase to almost 1,800 MW by 2014. The Imperial Irrigation District recently completed an open season for long-term wheeling contracts on Path 42, the interface between Imperial Irrigation District and Southern California Edison. More than 1,550 MW of capacity was requested, and generators will pay for all transmission studies and system upgrades on the Imperial Irrigation District portion of Path 42. The generators will be reimbursed for necessary system upgrades through transmission credits equal to the amount that they contributed to the upgrades.

Integrated Planning

In June 2010, CAISO revised its transmission planning process when it submitted tariff changes to FERC in Docket No. ER10-1401 to implement a revised transmission planning process. In its cover letter, CAISO stated that it had concluded “that the infrastructure improvements needed to allow the state to reach the 33 percent target by 2020 won’t occur if the state’s transmission system is assessed and built in a piecemeal fashion, project by project.”

The revised transmission planning process manages the risk of stranded transmission investment by creating a distinction between Category 1 (transmission elements that will be approved as part of the transmission plan) and Category 2 (transmission elements that will be re-evaluated in the future). Category 1 projects are to have a high probability of utilization by renewables. To the extent that Category 1 projects are insufficient to fulfill the 33 percent RPS, Category 2 projects will be identified based on assessments of locations where renewable development will most likely be commercialized.

CAISO’s revised transmission planning process contained many elements that are remarkably similar to changes FERC required in Order 1000 a year later. Specifically, CAISO’s process created a new policy-driven criterion for identifying and approving needed transmission additions and upgrades, and the associated concepts of Category 1 and Category 2 transmission elements. It also called for further consideration of a statewide conceptual plan that’s based on a statewide assessment of transmission needs to achieve federal or state policy goals and that provides a key input to the ISO’s identification of policy-driven elements—and other infrastructure needs—for its own balancing authority area.

It also removed of the right of first refusal for incumbent transmission owners to implement transmission upgrades, except in those cases that involve existing rights of way or upgrades to existing facilities.

The 2010/2011 CAISO transmission plan is the first to incorporate the revised transmission planning process. In addition to the RPS issues, it addresses all CAISO transmission needs, including generator interconnection upgrades and reliability upgrades. In support of the 33 percent RPS, the plan includes one Category 1 project and four Category 2 projects. The CAISO Category 1 project will support importing about 1,000 MW of renewable capacity from Imperial Irrigation District to Southern California Edison—a CAISO member. CAISO reports that Imperial Irrigation District has over 1,000 MW of renewable generation in the late stages of contract negotiations for interconnection and transmission services that would fund the Imperial Irrigation District upgrades needed to support the exports.

Based on its assessment of the status of Imperial Irrigation District’s contract negotiations, the CAISO Board approved the associated SCE upgrades that are also required. In August 2011, the Imperial Irrigation District Board approved the Imperial Irrigation District upgrades, which are expected to be completed by December 2013. However, the district contracts provide the generators with the option to withdraw if detailed design results in significant cost increases. Therefore, some risk remains that the either the Imperial Irrigation District or Southern California Edison upgrades could become stranded assets. It’s possible that if the voluntary inter-regional cost sharing described in FERC’s Order 1000 had been in place, the risks faced by both CAISO and Imperial Irrigation District—with their mutually beneficial upgrades—might have been reduced, thereby allowing the transmission projects to proceed with less risk to both parties.

Hawaii: Island Economics

Hawaii is blessed with sunshine, beautiful beaches, lush lands, and wind. Indeed, the economics of wind power in Hawaii are compelling; Hawaii has the highest retail power costs in the U.S. due to the isolation of the relatively small systems on each island and their heavy dependence on oil-fired generation. The island of Oahu is the most populous island and accounts for about 75 percent of Hawaii’s load and peak demand. Wind resources are limited on Oahu, but plentiful on the nearby islands of Molokai, Lanai, and Maui (see Figure 8). Hawaii Electric Co. (HECO) and its subsidiaries serve about 95 percent of Hawaii’s load, including these islands.

In 2007, HECO released a solicitation of interest announcing plans to issue a renewable resource RFP for projects up to 100 MW. The RFP would allow HECO and its subsidiaries to meet the Hawaii RPS law that requires renewable resources to supply 10 percent of their net electricity sales by 2010, 15 percent by 2015, 25 percent by 2020, and 40 percent by 2030. HECO issued the RFP in 2008 and received PUC permission to negotiate with two much larger (400 MW) wind proposals on the nearby islands of Molokai and on Lanai that would deliver their power to Oahu by undersea cable. The two wind and cable projects, plus necessary upgrades to the HECO system on Oahu, are referred to as the Big Wind project.

In a parallel effort, the U.S. DOE’s National Renewable Energy Laboratory commenced a technical study to examine the technical feasibility and cost for the undersea AC or HVDC cable systems from Molokai and Lanai. Additional wind development on Maui will be considered in the future. Released in February 2011, the National Renewable Energy Laboratory Oahu Wind Integration and Transmission Study (OWITS) reached several conclusions.

AC wasn’t viable because the three-core XLPE cable, which would minimize the magnetic field and losses, would be too heavy and limit its depth. An AC cable could be utilized for shallower applications, however, as was recommended in the Phase 2 report issued later. HVDC was preferred, and voltage source converters were found to be “the only practical converters” because they “create a stable AC supply for [the] wind turbine generators” and “offer a significant buffer to AC system faults.” A 200 MW cable system was determined to be the maximum rating consistent with HECO’s normal operating practice of 180 MW of spinning reserves. Adjusted budgetary cost estimates for two 150-kV, 200-MW cable systems ranged from $466 to $709 million. Roughly one-half of the costs were for the converter stations and one-half for the cables.

The report concluded that the system must be designed to avoid problems “when the DC cable is tripped out of service at its receiving (Oahu) end.” Interconnecting the wind farms to the small local loads on Molokai and Lanai wouldn’t be practical; the connection would have to be treated like any other source of generation whose loss is an N-1 event.

National Renewable Energy Laboratory’s Phase 2 report found significant cost savings by running a 230 kV AC undersea cable between Lanai and Molokai where an HVDC line wasn’t required (see Figure 9). This would avoid the cost for one set of HVDC converters and avoid the associated land development on Lanai.

Working with HECO, the two RFP developers, Castle & Cook (Lanai) and First Wind (Molokai), agreed to reduce their projects to 200 MW each, which would allow both to progress, with the provision that if one developer had to drop out the other could develop the full 400 MW.

There was considerable local opposition on both islands because all of the power will be dedicated to Oahu. Castle & Cook, which has considerable holdings on Lanai, offered a hefty benefits package to the local community, and HECO promised to levelize local rates to match those on Oahu. As a result, Castle & Cook has reached its development milestone requirements. First Wind, however, was unable to reach a deal with the Molokai land owner. HECO tried to assign those contract rights to Castle & Cook, but that was rejected by the PUC as deviating too far from its original approval. The PUC ordered HECO to issue another RFP for renewable energy on any island by mid-October, and later denied HECO’s motion for reconsideration.

While developers had offered to construct, own, and operate the wind farms, the state of Hawaii commissioned a study to evaluate a range of commercial issues, including ownership options, funding, and project economics. Among the key conclusions, the study produced a more detailed estimate of the cable project’s capital cost—$655 million—and determined that the overall Big Wind project breaks even at a $108/barrel price of oil. Big Wind would also hedge against unpredictable and volatile oil prices.

The study also concluded that the preferred cable ownership option was to have a developer construct, own, and operate it as regulated independent transmission entity, referred to as a “certified cable company.” Having a separate transmission developer leads to a fundamental project coordination risk between the wind projects and the cable project. While this project-on-project risk can be mitigated, it isn’t clear who will pay if one project is completed while the other is delayed or cancelled.

The Big Wind project demonstrates that local community issues are often a key development issue, particularly if a large wind project is to be sited in a beautiful location and the power is to be exported. The technical issues appear to have been rigorously evaluated and the Scenario 1 plan to utilize an AC line between Molokai and Lanai will make Big Wind more cost-effective. The project coordination risk is recognized as difficult at best, and might require revising the basic Big Wind project structure if regulators are unwilling to have ratepayers back stop the transmission commitment.

Policy Leadership

Wind integration programs in Texas, California, and Hawaii illustrate that integrating large-scale wind resources and the associated transmission build-out is easier to accomplish in power markets that are under the jurisdiction of a single state. Multi-state market areas have to deal with many difficult challenges, e.g., inconsistent state policies, transmission cost allocation, local siting opposition, and free riders, unless the wind resources and the delivery points happen to be located in the same state or are sufficiently coordinated regionally.

These examples also demonstrate that coordination of wind development and transmission build-out, i.e., project-on-project risk, is a key issue. Renewable generators won’t invest without an assured delivery pathway, and regulators are reluctant to approve transmission cost recovery without sufficient assurances from generators. This issue is compounded by the long lead times and high development cost for both.

The Texas solution is to establish different classes of transmission upgrades and to require wind generators to make sufficient commitments—in terms of capacity that’s built, is under construction, has signed interconnection agreements, or has provided collateral—before a CCN application can be processed. In California, the CPUC approved a backstop provision for retail rate recovery and CAISO established two categories of transmission upgrades to facilitate wind integration. Even in California, however, the multiple balancing authority areas create additional risks when costs are incurred in one area for the benefit of another. Inter-regional agreements as envisaged in FERC Order 1000 could mitigate some of these risks. In Hawaii, inter-island wind transmission makes economic sense but the project-on-project risk issue hasn’t yet been resolved.

Additionally, experience has shown that actual transmission costs are very likely to exceed original planning-level estimates. In some cases, such as Texas, the increase can be significant. Developing massive transmission infrastructure to deliver remote wind energy can be done in stages to minimize planning, construction, and cost recovery problems.

Major transmission build-out to accommodate wind development might require special legislation and tariff modifications to assure cost recovery and address other risk issues. CREZ legislation in Texas designated the PUCT as the lead state agency in charge of locating the regions where wind farms would be sited and awarding transmission contracts to 11 utility companies to interconnect the wind farms. California law allows investor-owned utilities to recover transmission costs for approved projects if those costs can’t be recovered from FERC-approved wholesale transmission rates. Hawaii hasn’t yet resolved this issue in spite of its aggressive RPS standards.

Experiences in Texas, California, and Hawaii suggest that integrating large scale renewable resources into the transmission grid is a challenging but achievable endeavor. It requires thoughtful strategy and coordination on the part of policymakers, utilities, and generators—particularly with regard to risk issues. Whether or not renewable resource goals are achieved in the most effective manner ultimately depends on policy leadership and how efficiently conflicting interests are resolved.