Transmission expansion costs are spread unevenly, driving a wedge between utilities and regions.
Bruce W. Radford is publisher of Public Utilities Fortnightly.
Back in June, the Bismarck Tribune ran an interview with North Dakota Public Service Commissioner Tony Clark that showed just how difficult it is to build national consensus for renewable energy.
The interview dealt with the massive transmission expansion now underway to accommodate wind project development in the Dakotas, Iowa, and Minnesota, and the ensuing threats from Otter Tail Power and Montana-Dakota Utilities (MDU) to cancel their memberships as part of MISO (the Midwest Independent Transmission System Operator) unless MISO somehow can modify its scheme for funding the enormously expensive wind-driven grid upgrades so Otter Tail, MDU and their ratepayers won’t have to pay a huge share of the cost, as is the case now under the current MISO tariff. (See, “N.D. Regulators Seek Rule Change on Wind Power Costs,” by Dale Wetzel, AP writer, Bismarck Tribune, June 4, 2009, State-and-Regional News Section.)
“What I would tell wind developers is, ‘You’d better solve this,’” Clark was quoted.
“If you don’t,” he added, “the political support, which in North Dakota has been almost unanimous for wind, will evaporate.”
Commissioner Clark was speaking about the MISO tariff regime known as RECB (regional expansion criteria and benefits, pronounced wreck-be), which dictates how MISO allocates costs for transmission system network upgrades (net-ups) for project developers who join the MISO queue to obtain an interconnection agreement (IA) to link new power plants with the regional grid. Since 2006, some 70 percent of all new power plant development projects in MISO are slated for sites in the Dakotas, Iowa or Minnesota. Most of these projects are wind-driven.
Clark continued, arguing that gen project developers should pay for all the new transmission—not Otter Tail or MDU, which don’t need the new projects to serve their modest loads, or even to meet state guidelines for renewable energy portfolios:
“People in North Dakota will really, I think, rebel against wind power,” Clark added. “They will see this power that’s going for export and all they see is their rates going up to subsidize power going to Chicago.”
No Good Solution
As of this summer, the new gen projects slated for Otter Tail’s service territory exceeded the utility’s peak load (745 MW) by a ratio of nearly 13 to one. For MDU, the ratio was almost five to one. And though past experience has shown that more than three-quarters of queue projects tend to drop out—usually before the system impact study (now referred to in MISO as the SPA stage (system planning and analysis)—MISO planners reported this summer that at least 1,700 MW of the 12,150 MW of new projects slated for the Otter Tail and MDU service territories had reached the stage where zero dropouts are expected.
Moreover, since these wind projects largely would serve in distant locales, Otter Tail and MDU ratepayers would see very few benefits from their grid investments. MISO’s license-plate scheme for transmission pricing allows only the utility transmission owner (TO) that serves the remote consumption zone, where the power “sinks,” to collect payments for the grid upgrades—not the utility that hosts the wind projects. Thus, Otter Tail and MDU would not recoup their grid investments through the transmission portion of retail rates; at least not if they remain members of MISO.
Late last year, Otter Tail and MDU gave notice of their intent to withdraw as members of the MISO regional transmission organization (RTO). That put a fire under MISO management to explore alternative cost-allocation methods, to save the ISO as an institution.
Of course, if Otter Tail and MDU were to follow through on their threats, they would need to comply with FERC Order 2003, governing generator interconnections for non-RTO members, which requires the host transmission owner to reimburse project developers for all (!) net-up costs, but which allows TOs to offer credits against their own utility transmission service rates in manner of payment.
Would wind developers then drop out and decline to build in Otter Tail and MDU territory—solving the current problem because they’d lack access to MISO markets and face transmission rate pancaking? Would FERC impose a de-pancaking condition of withdrawal, to make Otter Tail and MDU think twice? It all comes down to credibility.
This past summer, MISO proposed a new tariff to deal with rising net-up costs and preserve RTO unity. The proposal virtually would absolve the host utility of all responsibility to fund wind-driven net-ups, as well as upgrades for coal, natural gas, and other gen projects, both within the Otter Tail and MDU territories, and all across the entire MISO footprint as well. Instead, it would fall on gen project developers to pay for nearly all grid upgrades. As an exception, 10 percent of upgrade costs would be shared ratably among all MISO TOs, but only for lines with capacities equal or greater than 345 kilovolts. (See, MISO RECB Phase I Interim Tariff Proposal, FERC Docket ER09-1431, filed July 9, 2009.)
The MISO proposal assumes that project developers will recover the upgrade costs from their energy customers, through either the MISO day-ahead energy market, or else private purchased-power agreements. But that could impose a significant carrying charge on the generation sector. Wind project developers say that lenders won’t finance the developers’ share of grid upgrade expenses, as the developers don’t own the grid and so can’t provide a transmission service revenue stream to back loans, nor pledge the upgrades as collateral for the lender’s security.
MISO had adopted its current RECB cost-allocation method because grid planners had assumed most new gen projects simply would replace aging infrastructure or fix reliability problems. Thus, MISO’s RECB tariff had required TO utilities to reimburse developers in most cases for one-half of net-up costs, with the TOs sharing that obligation among themselves, largely according to the way in which the grid upgrades would improve power flows on existing lines, as measured by an engineering formula known as LODF (line outage distribution factor).
This LODF method made perfect sense for reliability upgrades, designed to relieve constraints imposed by new gen plants on nearby transmission lines. LODF meant that the TO utilities closest to the site of the new projects would end up carrying the lion’s share of the 50-percent refund obligation. This tendency did no harm at first, during the years 2004 through 2006, in which the ratio of new projects to MISO load trended around replacement level, and when developers tended to site their new projects homogenously across the entire MISO footprint.
However, as pointed out by attorney Carmen Gentile (Bruder, Gentile & Marcoux), in written comments he filed on the MISO proposal for Integrys Energy Group, the building of large quantities of generation in remote, low-density areas, known as far load simply “breaks the back of the current defective cost allocation scheme.” MISO’s method, writes Gentile, is “ill-suited to the dynamics of a centrally dispatched transmission system that is in a state of continuous growth and evolution.” (See, Comments of Integrys Energy Group Cos., FERC Docket ER09-1431, filed Aug. 13, 2009.)
Testifying for MISO in support of the new tariff proposal, among others, were Eric Laverty, MISO’s director of transmission access planning, and JoAnn Thompson, manager of Otter Tail’s federal regulatory compliance and policy.
According to Laverty and Thompson, the many gen projects now slated for MISO’s geographic Group 5 study area (Dakotas, Iowa, Minnesota) would boost Otter Tail’s net-up costs by 5,200 percent, giving rise to a 24-percent increase in Otter Tail’s transmission rate charged to retail ratepayers. Counting all new gen projects across the entire MISO footprint, Thompson reported that Otter Tail’s share of net-up cost allocations would climb 9,500 percent, forcing a 44-percent hike in the transmission-related retail rate.
Figures for MDU were comparable, though not quite so shocking: For Group 5 projects, net-up costs would rise 826 percent, with retail T rates up 1.8 percent. For MISO-wide projects, net-up costs climb 2,600 percent, with retail T rates up 5.9 percent. (See, Supporting Comments of Montana-Dakota Utils. filed Aug. 13, 2009.)
Suffice it to say, however, that these numbers don’t tell the whole story. Wind power advocates dispute them, claiming that Otter Tail, MDU and MISO both have overestimated the real effects on North Dakota ratepayers, and underestimated the likely chilling effect on wind project development. Others point out these rate impacts ignore benefits from integrating more wind into resource portfolios, such as avoided carbon emissions and the likely lowering of locational marginal clearing prices (LMPs) in regional energy markets.
For example, MISO, Laverty, Thompson and other witnesses argued that the new tariff would increase wind project development costs by only 4.8 percent, based on data sets showing an installed capacity cost of $2,000/kW, and a typical unit net-up cost of $200/kW, on the assumption that wind-driven upgrades in the Group 5 study area would involve only the smaller 115- and 230-kV lines.
But key opponents, including Edison Mission Energy, Nextera Energy Resources, Iberdrola Renewables, Horizon Wind Energy, GE Energy, the Natural Resources Defense Council, and the American Wind Energy Association, question MISO’s cost estimates.
They allege that the $200/kW figure comes from the $195 estimate in the Eastern Interconnect study conducted by the joint coordinated system plan, which assumes a single, organized, interconnection-wide grid overlay at very high voltages (765 and 800 kV), thus capturing significant economies of scale. By contrast, they argue, real-world grid expansion projects in the MISO queue occur sequentially, in piecemeal fashion, and so prove much more costly.
Opponents claim that MISO studies already have assigned much higher upgrade costs to various Group 5 projects now in the queue. These costs, they say, suggest wind developers will be required to pay for the $700 million (or more) Bookings 345-kV transmission line planned for southern Minnesota. They provide estimates for unit net-up costs ranging anywhere from $370/kW to $1,156/kW. Such figures imply that wind project development costs could climb by 7 to 14 percent, or even by as much as 17 percent, according to one estimate. AWEA reports that the plan of the CAPX2020 utility consortium to build transmission lines to serve 2,400 MW of new wind generation assumes a $625/kW unit net-up cost, and that net-up costs for some 19 projects (2,800 MW) in MISO Group 6 will be $2.2 billion, or about $770/kW.
Even the DOE’s Lawrence Berkeley National Lab has pegged the national median unit net-up cost at $300/kV, as was reported previously in this column. (See, Titans of Transmission, March 2009.)
AWEA adds that for a typical 100-MW wind project operating at a high 40-percent capacity factor (as is possible in wind-rich North Dakota), every $25 million increment in grid upgrade cost requires an increase of $8/MWh in the wholesale LMP energy price for wind developers to be made whole. (See generally, industry comments, FERC Docket ER09-1431, filed through Aug. 13, 2009.)
These industry advocates would prefer to see net-up costs shared pro rata by all utility TOs within a given RTO, a sharing method commonly known as “postage-stamp” pricing. They see RTO-wide cost-sharing as particularly appropriate in light of wind energy’s apparent public benefits, such as carbon emissions reductions, as documented earlier this year by Dr. Ira Shavel, in his FERC testimony on the landmark study by Charles River Associates that analyzed CO2 reductions likely from the massive Green Power Express transmission line. (See, Exhibit GPE-400, Direct Testimony of Dr. Ira Shavel, FERC Docket No. ER09-681, filed Feb. 9, 2009.)
And as AWEA noted in its written comments on the MISO tariff, the cost to typical residential consumers of postage-stamp pricing would total “less than the cost of an actual postage stamp on their monthly bill.”
MISO, however, doesn’t remain completely indifferent to wind project developers and their plight. For example, it recently has worked on reforms to its project queue, including a rule change that would allow a multi-party facility construction agreement, by which a group of similarly situated wind projects could share responsibility for upgrade costs, even if they come on line sequentially, thus mitigating the notorious “first-mover/free-rider” problem, which otherwise encourages developers to delay signing an interconnection agreement to avoid getting socked with the first round of upgrades. (See, FERC docket No. ER09-1610, filed Aug. 2009.)
MISO also explains that its new tariff will serve only as an interim measure—adopted on an emergency basis to avert member defections and preserve the RTO as an institution. It will be replaced, MISO promises, by a permanent Phase II solution, to be filed at FERC by July 2010, that presumably will be more favorable to the wind industry.
Again, however, the wind industry and many other stakeholders see MISO’s proposed cure as worse than the disease. They point out that if FERC should approve this “interim” proposal, that MISO members will have gotten what they wanted, and so will have no bargaining incentive to cede ground when MISO’s RECB task force reconsiders the problem next year.
Instead, why not just craft a private settlement with Otter Tail and MDU? Or, perhaps socialize the Otter Tail and MDU costs across the entire MISO footprint via an “uplift” charge tacked on to LMPs in the regional energy market. Why discourage wind project development across the entire Midwest, when the problem is much narrower, involving only Otter Tail and MDU as special cases?
Opponents argue as well that MISO’s proposal runs counter to the spirit of FERC’s recent order approving a much more wind-friendly allocation method for net-up costs in the Southwest Power Pool, which faces the same explosion in wind power development as does MISO. (See, Southwest Power Pool, Inc., Docket ER09-1039, June 18, 2009, 127 FERC ¶61,283.)
Yet all these well-intentioned efforts to identify, calculate and weigh costs and benefits and then apportion the bill accordingly miss the big picture, according to a federal appeals court judge sitting in Chicago. That judge, Richard Cudahy, urges that regulators view grid expansion as a broad-based national enterprise, in which all utilities have a stake and a duty, and so should remain unfettered by traditional regulatory bean-counting aimed at equalizing costs and benefits.
In August, on a challenge to FERC policy brought by the Illinois state utility commission, Cudahy issued a scathing dissent to the majority ruling of the U.S. 7th Circuit Court of Appeals, which struck down and remanded a 2007 FERC order that had OK’d a PJM tariff that had provided for equal, “postage-stamp” cost-sharing among utility TOs across the entire PJM regional grid footprint (based on utility-specific load-ratio shares) for new, large-scale transmission upgrades rated at 500kV or higher, and designed to provide extensive regional benefits by moving electricity large distances across the entire regional transmission organization (RTO). The case had involved Project Mountaineer, designed to facilitate cheap power imports from the Midwest to the Mid-Atlantic, but two of three judges ruled that FERC had provided insufficient evidence to show that Commonwealth Edison, operating in Illinois, would receive benefits commensurate to its cost contribution. (Illinois Comm. Comm’n v. FERC, Nos. 08-1306, et al. Aug. 6, 2009, 7th Cir.)
In his dissenting opinion, Judge Cudahy wrote: “However theoretically attractive may be the principle of ‘beneficiary pays,’ an unbending devotion to this rule in every instance can only ignite controversy, sustain arguments, and discourage construction while the nation suffers from inadequate and unreliable transmission.”
Cudahy went on to quote from a 2004 opinion from the D.C. Circuit (affirming cost allocations in the formation of MISO) written then by the now-current U.S. Supreme Court Chief Justice, John Roberts. In that opinion, Roberts suggested that RTO-member utilities should share the cost of establishing and maintaining the grid system, even if all don’t benefit equally, just as all U.S. taxpayers help pay to sustain the federal courts:
“The MISO Owners’ position is tantamount to saying that if they are not a litigant, they should not be made to pay for any of the costs of having a court system.” (MISO Trans. Owners v. FERC, 373 F.3d 1361, at 1371, D.C. Cir. 2004.)
Attorney Karen Hill, vice president for federal regulatory affairs at Exelon, echoes these ideas in comments addressing the current MISO proposal. (See, Comments of Exelon, FERC Docket ER09-1431, filed Aug. 13, 2009.) Hill and Exelon urge FERC to fix the problem in a generic way that would cover the nation’s entire grid system. Hill even appears to question the usefulness of longstanding rate-making concepts, such as utility-specific peak load, and utility-specific resource adequacy.
“In Exelon’s view,” she writes, “this case illustrates perfectly why optimal development of the nation’s wind energy resources calls for interconnection-wide planning and cost allocation … There is no good case-by-case solution for the conundrum presented here. The commission is facing similar issues in other regions …
“Today, the national goal of developing renewable resources transcends the historic mission of an individual utility to secure an adequate electricity supply to serve its particular load over time.