Late last year FERC learned that the Midwest regional grid likely would require at least 40 years — until 2050 — simply to clear its backlog of proposed gen projects awaiting a completed interconnection agreement to certify their compatibility with the interstate power grid. But grid engineers would meet that date only by shortening the process and studying multiple projects simultaneously in clusters. To apply the process literally, studying one project at a time, as envisioned by current rules, the Midwest reportedly would need 300-plus years to clear its project queue.
Bringing this bad news were Clare Moeller, vice president of transmission asset management for the Midwest Independent Transmission System Operator (MISO), and John Norris, chairman of the Iowa Utilities Board. Norris serves also as president of the Organization of MISO States, the group that represents the state utility regulators who function within the MISO footprint.
Each man had appeared as a witness at a technical conference held at FERC on December 11 to explore ways to fix the commission’s LGIA rule. That rule, set some five years ago in FERC Order 2003, sets the process for a proposed large generating facility to obtain an Interconnection Agreement, which would certify the plant in question as a fully deliverable “network resource.” The completed IA ensures that the plant’s operation at full capacity will mesh with existing grid operating parameters and in so doing will not hinder the operations of other, previously certified network resources. But the process has become badly outdated.
“It’s now time to look at our interconnection process and see whether there are tweaks that need to be made,” said FERC Commissioner Suedeen Kelly, who had first suggested the project interconnection queue as a topic for study, according to Chairman Joseph Kelliher. Yet the problem may well call for more than a tweak.
A month before the conference, the governors of seven Midwestern states wrote to MISO CEO Graham Edwards to express their “growing concern” about how wind-energy developers face a “crisis” in the delays they encounter in bringing new projects on line. Citing a study conducted in April 2007, Norris predicted at the conference that wind-energy development in the Upper Midwest during the next six years or so could generate some $59 million in payments to farmers and ranchers, plus $148 million in new property taxes in sparsely populated rural areas.
As each conference speaker took the microphone, it became evident that some grid operators and regional transmission organizations (RTOs) have had to stretch to complete the complicated engineering studies and restudies seemingly required by FERC’s LGIA rule. “Transmission engineers are overtaxed,” said Kris Zadlo, transmission vice president for Calpine.
In written handouts distributed at the meeting, Laurence Chaset, senior staff attorney from the California Public Utilities Commission, explained that the “first come, first served” right embodied in FERC’s LGIA rule, combined with the implied requirement of conducting serial studies for each single project as it rises to the top of the queue, was “seriously undermining” the CPUC’s efforts to comply with California’s aggressive timetables for renewable energy, and “seriously impeding” the ability of the California grid operator (CAISO) and its participating transmission owners to carry out their responsibilities under FERC rules.
During the final Q&A conference session in the late afternoon, CAISO’s vice president for planning and infrastructure development, Armando Perez, admitted: “We actually have taken the step of starting our own academy at the ISO … teaching power system engineering classes.”
Stephen Rourke, ISO New England’s system planning vice president, echoed that comment, saying, “We’ve also had to add to the engineering staff. We have started to reach out to universities in the area, sponsoring a grad power class right at the ISO.”
At the end of the day, however, the question goes far beyond ISO staffing concerns. After all, FERC’s LGIA rule, an element of the pro forma open-access transmission tariff (OATT), requires grid operators to notify applicants and give reasons for any delay greater than 45 days in completing the interconnection Feasibility Study, or 90 days for the System Impact Study (SIS).
The G&T cooperative, AMP-Ohio, alleges that PJM took five and ten months each for the feasibility system-impact studies for a 1,000 MW coal-fired plant under development for southern Ohio, and 12 months for an SIS for a simple 5-MW wind project. (See FERC Docket No. AD08-2, comments filed Feb. 5, 2008.)
Similarly, Dominion alleges that PJM was months late on studies for capacity upgrades on its 1,100-MW Ford Mill coal-fired plant, which Dominion says will jeopardize its ability to bid the higher plant capacity into PJM’s new capacity market, known as the RPM, or Reliability Pricing Model. (See FERC Docket No. EL08-36, complaint filed Jan. 28, 2008.)
Despite FERC’s vaunted new enforcement authority, it appears the commission so far has avoided assessing fines against grid operators for unreasonable delays in completing interconnection studies.
“I think the queue process is broken, said FERC Commissioner Jon Wellinghoff at the December conference. “It needs to be fixed.”
No one can disagree that applications for grid interconnection for new generating projects have risen dramatically across the country during the last several years. This is especially true in areas possessing a high wind-energy potential, and in regions where individual states have adopted renewable portfolio standards to boost investment in alternative energy sources. However, this explosion of project applications far exceeds the level of new resources that might appear warranted by state RPS laws or favorable terrain.
Consider this data reported by the ISO/RTO Council in a white paper it filed with FERC in early January, reflecting surveys of regional interconnection queues completed in October 2007:
• Midwest ISO: 73,000 MW of active projects are in the queue, including 57,000 MW of wind projects (compared with only 12,600 MW of renewable generation that would be needed to meet current renewable mandates in MISO states).
• SouthWest Power Pool: 67 wind projects are pending out of 76 projects in the interconnection queue. Capacity represented by new wind projects with interconnection agreements under study exceeds the entire current peak load for the SWPP footprint.
• PJM: Number of interconnection requests by its biannual study groups has increased 120 percent from 2005 to 2007.
• New York ISO: 400 MW of wind generation in commercial operation; 7,000 MW in wind projects (15-plus times greater) pending in the interconnection queue.
• California ISO: 118 (40,000 MW) of 173 active interconnection requests (57,686 MW total) represent renewable resources, with the renewable portion growing from 5,700 MW as of January 2006, and 11,000 MW as of January 2007. By contrast, CAISO’s all-time peak demand (summer 2006) is 50,270 MW.
The Buffalo Ridge area of southwestern Minnesota, lying within Lincoln, Pipestone, and Murray counties, offers a particularly acute example of the growth of wind projects in regional interconnection queues, and many see such growth as pure speculation.
According to MISO, some 22,000 MW of wind-energy projects for that area remain pending in the regional interconnection queue, proposed for commercial operation by 2014, while the local grid serving the Buffalo Ridge feature is expected to offer only 1,900 MW of exportable outlet capacity as of 2014.
Of course, FERC late last year did grant incentive rate authority to Xcel Energy for some $1 billion in grid system investment planned for the larger Upper Great Plains region. The new investments include the BRIGO project (Buffalo Ridge Incremental Generation Outlet Project, consisting of three new 115-kV lines), plus three separate 345-kV projects designed to import power from the wind-rich Dakotas to Minnesota’s Twin Cities and load centers in eastern Minnesota and western Wisconsin. (See Docket No. ER07-1415, order issued Dec. 21, 2007, 121 FERC ¶61,284) Nevertheless, the Buffalo Ridge situation has prompted some observers (including at least one FERC staff member) to pin the blame for queue delays on a fundamental shortage of transmission capacity. They say that in conducting their system-impact studies, engineers are trying to find ways to pour a quart of water into a one-cup container.
As MISO Vice President and General Counsel Stephen Kozey explained in written comments on the Buffalo Ridge problem, “once those electrons flow past the interconnection facilities, they try to flow with other electrons from other queued generators and the transmission lines simply cannot handle the strain.”
Most observers describe the queue explosion as a “wind problem,” exacerbated perhaps by wind developers racing the clock against the next scheduled legislative renewal of the federal production tax credit. They add that the low-level ante for queue entry ($10,000) and FERC’s policy allowing developers to elect a no-fault, on-demand three-year suspension of a queued project after issuance of an IA creates asymmetric risk, making it too easy to join the queue, and too difficult for grid operators to winnow the backlog. All this leads presumably to a plethora of speculative, “phantom projects.”
Thus, as FERC Commissioner Mark Spitzer observed, “Clearly we have a paradigm that was based upon the combined-cycle gas turbine. The realities [today] are quite different.”
Even wind energy developer Competitive Power Ventures (CPV) conceded in written comments following the conference that “phantom projects inflate the size of the queue.”
Some participants at the conference bolstered this theory by noting the large number of projects that tend to drop out before earning an interconnection agreement, producing a small success rate of only about 25 to 30 percent in the typical queue.
One developer, LS Power Associates, filed written comments observing that, “while this success rate may be true, this is just the nature of new generation development, in which project cancellations are common.”
Jan Smutny-Jones, the longtime executive director of California’s Independent Energy Producers Association, echoed this argument at the conference, where he declared poetically that “One man’s phantom is another man’s dream.”
Moreover, as Calpine’s Zadlo notes, the choice of fuel should exert no effect on the engineering studies that have proven so problematic for queue management.
“It doesn’t matter,” he noted at the conference, “if it’s nuke, coal, wind, gas.
“Four years ago the queues were filled with gas generators; today it’s renewables. Three or four years from now it’s going to be another generation technology.”
Yet CPV adds, quite rightly, that the queue logjam and FERC’s policies on transmission pricing and cost recovery “are particularly harmful to projects which could be constructed relatively quickly, such as most wind projects, [which] are located far from the existing grid and developed in smaller increments than other types of generation.”
According to James Johnson, Xcel Energy’s assistant general counsel, who filed written comments for the company on January 15, the “straw that breaks the camel’s back” in the interconnection queue is FERC’s policy on costs of required grid network upgrades. Under the pro forma OATT, as Johnson noted, FERC assigns up-front funding responsibility “to the individual generation project [or projects] that push the capacity of a specific transmission facility over its rating.” That policy, as Johnson writes, “encourages developers to enter the queue multiple times … either to take advantage of transmission capacity created by earlier queued projects, or to shift the cost of network upgrades onto another generator.”
In other words, a project developer might well prefer to go “upgrade shopping” and finish in second or third place, rather than first. By losing the race for queue position, the developer might piggyback as a free-rider on the cost contribution to grid development that is required to be offered by other developers proposing similar projects that occupy a higher position in the queue.
Robert Gramlich, policy director for the American Wind Energy Association (AWEA) cites this particular FERC policy — forcing gen project developers to fund the necessary grid improvements — as the “root of much evil” in the interconnection queue.
“It’s a crazy process,” he said. “It would be like planning a highway expansion and putting all the costs on the first car to come up the entrance ramp.”
Many others agree, such as CPUC Counsel Chaset, who explained the problem in more detail at the conference, citing a hypothetical example “Generator A,” in a high queue position, which proposes to build a 300-MW wind facility, but which must pay millions up front for grid upgrades.
“Generator A, seeing these huge up-front costs, can easily and without penalty withdraw from the queue,” forcing those costs “onto the next generator down the queue in the same electrical zone.”
When that happens, as many conference participants noted in their later-filed comments, the transmission provider then is forced to re-study lower-queued projects and reallocate transmission upgrade costs. The cycle of queue reshuffling continues, and likely repeats itself, while the grid operator makes no real progress in clearing the backlog.
“In our view,” Chaset concludes, “the rules encourage perpetual uncertainty and a game of tag-you’re-it on generators whose facilities may ultimately be beneficial and desirable.”
Yet the behavior of the developers appears entirely rational, as Competitive Power Ventures explained it its written comments: “There is no meaningful mechanism in place for developers to identify the cost of interconnection at any particular site except to throw the dice and submit exploratory interconnection applications.”
Under FERC’s standard timelines for completing the various studies and milestones, as stated in the LGIA pro forma tariff, assuming no restudies or undue delays, a developer ordinarily will not discover its true costs for a year or more after filing an interconnection request. But by that time, as CPV notes, “the developer would have had to invest significant resources into other activities, such as land and equipment acquisition and permitting.”
This up-front funding obligation becomes even more problematic for developers in regions such as MISO, where the RTO tariff limits reimbursement of those costs, either directly or through transmission rate credits or assignment of financial transmission rights. (See the prior Commission Watch column, “Tilting to Windward,” Public Utilities Fortnightly, Sept. 2007, for more explanation.)
In fact, the Midwest stand-alone transmission companies, ITC and METC, claim they have mitigated the problem somewhat by adopting a different rule than what applies in the rest of MISO. Last year, ITC and METC won permission from FERC to roll back the MISO rule and offer a full 100 percent cost reimbursement to developers who supply upfront funding for upgrades to ITC or METC facilities. (See comments, FERC Docket No. AD08-2, filed Jan. 10, 2008; see also Docket No. ER07-1141, order issued Sept. 7, 2007, 120 FERC ¶61,220.)
Either way, however, the inability to estimate costs before committing assets can make financing particularly difficult for new gen projects. As Commissioner Spitzer noted, “they want transmission before they write the check to finance, but can’t get the transmission.
“It’s like dealing with any bank,” he mused. “You have to prove you don’t need the money.”
Commissioner Spitzer asks whether grid operators could be found guilty of violating state law private property rights if they seek to clear the queue by allowing a favored developer to jump queue positions, leapfrogging past a project in a higher-priority queue that might be deemed less worthy.
For example, Colorado PUC chairman Ron Binz suggested that projects qualifying under state-sponsored resource-planning processes ought to have some ability to “jump the queue.”
And for regions that have adopted capacity markets that include competitive bidding, the question already has arisen, as FERC chairman Joe Kelliher noted, of “whether a resource chosen through a capacity market auction moves to a higher place in the queue.”
In other words, a project might submit a winning bid in New England’s FCM auction or PJM’s RPM program, and yet might have a queue position so low as to virtually disqualify it from achieving certain milestones on time, as required for auction winners.
ISO New England is working on the problem, having already formed a stakeholder group (the FCM-Generator Interconnection Study Group), which held its sixth meeting on January 8, and which already has adopted a list of twelve principles for coordinating the interconnection queue with the FCM auction.
Nevertheless, the discussion can descend very quickly down a slippery slope. Should FERC ask grid operators or RTOs to make value judgements or choose one fuel over another in granting interconnection agreements for new gen projects? In fact, engineers could refer to numerous objective criteria in making such judgements, such as whether the project has gained financing, site control, purchased-power agreements or any necessary environmental permits. Engineers also could take account of plant capacity factors, heat rates or greenhouse emissions. However, to give a green light to engineers and operators, to serve as both judge and jury on evaluating the merits of new projects, would appear to place FERC’s open-access policy on a direct collision course with state portfolio mandates and planning needs.
At the California ISO, Armando Perez suggested FERC should consider affording greater flexibility to ISOs and RTOs to prioritize projects and studies, but warned that “creation of priorities in the study process must clearly be weighed against open access principles as they have been traditionally implemented.”
Rather than shore up FERC’s current study process with stricter controls on queue management, or by authorizing regional grid operators to pick winners and losers, renewable-energy developers tend to look outside the box. They favor a larger role for corroborative regional transmission planning, to ensure that the needed grid capacity is there before the developers arrive with their project proposals. That makes the study process less complicated. With no big upfront funding surprises for gen developers, this solution presumably would minimize or eliminate the many motives for upgrade shopping, queue manipulation, and phantom filings.
The California Wind Energy Association and other renewable developers largely favor this sort of integrated collaborative planning. In fact, they argue that FERC’s LGIA process “needlessly duplicates” the typical process for regional transmission expansion planning (RTEP) and makes little sense, given that transmission construction carries a lower risk than gen plant development, and makes up a smaller portion of the typical customer’s overall electric bill.
First, the study process does not take into account other system needs stemming from reliability issues and economic opportunities the association says could be addressed simultaneously. And second, as the association explains in its written comments, network transmission facilities are rarely built as a result of the studies. Often, says the group, generators will limit their planned output artificially, or else accept “work-around” solutions that avoid any need for a required upgrade identified in an engineering study, rather than undertake the identified upgrade. The group adds, “the fact that the entire analysis can be upset by the decision of a single generator to withdraw, once it receives its cost estimate, makes the exercise wasteful and inefficient.”
Full agreement comes from Brightsource Energy, the West Coast solar developer, in the words of Joshua Bar-Lev, the company’s vice president for regulatory affairs.
Bar-Lev told FERC at the December conference that “the actual transmission upgrades needed to interconnect projects should be planned through a regional transmission planning process so there’s no difference between the developers and the utilities.”
Renewable project developers like to cite ERCOT and the state of Texas as an example of this idea.
In early October 2007, the Texas PUC issued an interim final order that designated five so-called CREZ areas (Competitive Renewable Energy Zones) in West Texas and the Texas Panhandle to help plan for new grid capacity to foster development of wind energy and other renewable resources to help the state achieve its mandates and goals for alternative energy. The order helps carry out the policy initiated in Senate Bill 20, enacted by the state legislature in its 2005 session. The Texas policy anticipated what the wind energy developers have been saying in FERC’s queue initiative — that the best way to interconnect new renewable gen projects to the grid is to start from the top down and use a full, region-wide assessment and planning of transmission requirements. First, one identifies and pinpoints renewable resource potential, then plans the new grid capacity required to support those resources. Only then do individual projects come forward with new interconnection requests, when the studies need only ratify the grid capacity assessments already built in to the process.
California now has chosen to emulate the Texas CREZ model. Under California’s recently formed Renewable Energy Transmission Initiative (known as RETI, see www.energy.ca.gov/reti), the state’s Energy Commission and PUC eventually will designate CREZ-like areas. (See Comments of AWEA, including Appendix on state and regional initiatives to develop transmission for renewable energy, FERC Docket No. AD08-2, filed Jan. 10, 2008.)
Meanwhile, FERC already has approved a recent move by the California ISO to expand and refine its existing LCRIF tariff, first sanctioned in April 2007, and designed to provide financial incentives for the construction of new grid facilities to help develop and deliver renewable resources. (See Docket No. ER08-140, order issued Dec. 21, 2007, 121 FERC ¶61,286.)
The program allows CAISO PTOs (participating transmission owners) to boost their transmission revenue requirements and rates to pay for grid upgrades for so-called Location-Constrained Renewable Interconnection Facilities, rather than force upfront funding for all such upgrade costs on renewable project developers.
No CREZ-like initiative appears underway in the Midwest, however, where FERC’s basic LGIA process still holds sway, with its apparently duplicative and inefficient grid planning methods.
Of that regime, with its problematic interconnection queue, Bar-Lev says:
“Here what we’re doing is we’re designing everything from the bottom-up.
“I think that’s just a basic flaw.”