Michigan chafes over regional grid planning, providing a policy lesson for the feds.
Bruce W. Radford is publisher of Public Utilities Fortnightly.
This month the nation’s utilities will report back to the U.S. Federal Energy Regulatory Commission on how they will comply with FERC Order 1000, the rule issued last summer that requires all transmission providers to participate in regional grid planning, and forces grid planners to take account of state and federal policy governing renewable energy.
And with this landmark step, the industry turns back full circle to the days of vertically integrated resource planning, before everything broke loose in electric restructuring.
With Order 888, issued in 1996, the feds unbundled transmission from generation. That led directly to the formation of regional transmission organizations (RTOs), ensuring that grid management and centralized unit dispatch and would be overseen by agencies with no financial interest in energy markets or the generation revenue stream.
Now, however, with Order 1000, the commission has engineered a virtual rebundling of these two sectors—power plants and wires—by requiring regional planners, when they study where to lay down the lines, to consider not only what power flows are needed to keep the lights on, but also the motives, mandates, and economics of various portfolios of generation resources, and their effects on wholesale prices and retail rates.
That’s called integrated resource planning (IRP), the longtime province of state regulators and vertically integrated electric utilities. But with Order 1000, IRP is being ferried away from the states and reinvented on a regional level, in a process to be managed by the feds.
Speaking at a press gathering last month, FERC Chairman Jon Wellinghoff conceded that his agency likely would “get some pushback” from the industry in those Order 1000 compliance filings. But on that score he cited rights of first refusal (ROFR)—the notion that incumbent transmission owners ought to get a first crack at building infrastructure identified in the planning process:
“Some areas have different ideas on that,” Wellinghoff said.
But as for the bigger question—how much transmission to build—the chairman saw no basic conflict that markets can’t resolve.
Of course, cost estimates have run as high as $800 billion for the new lines needed to gather wind and solar from flyover country to load centers in the Midwest and East, to satisfy state-mandated renewable portfolio standards (RPS). And by contrast, however, as Wellinghoff noted, some see the cost of solar photovoltaic cells installed behind the customer meter falling as low as $2 a watt, not to mention all that transmission investment that is thereby avoided.
So the chairman reminded his audience of energy beat reporters that FERC, as a federal agency, would stay neutral in the contest between supply-side and demand-side solutions. That would leave the industry free to meet renewable energy goals either by wind from the Dakotas, implying a massive wires build-out, or instead by rooftop PV—a fix that could turn much of any future big build into stranded investment.
“We need,” he said, “to build only the transmission that we need.”
To find real pushback against FERC’s Order 1000, however, one might start with Michigan. That’s where the governor, chamber of commerce, congressmen, utilities, and the state public service commission have joined forces over the past several years to fight—though without success—against a policy-based transmission planning regime in the Midwest ISO (MISO), the grid operator for parts of 11 states and one Canadian province, in a broad region stretching from eastern Montana to the Motor City.
That program, known as MVP (multi-value projects), might well be seen as a stalking horse for FERC Order 1000. It won FERC approval nearly two years ago, despite Michigan’s heated objections, and now is taking flight well ahead of Order 1000, with the announcement by MISO in March of this year of an initial $5.2 billion portfolio of 17 major MVP grid projects, deemed by ISO planners to satisfy policy mandates. (See, Multi-Value Project Portfolio: Results and Analysis, Jan. 10, 2012, filed Mar. 27, 2012 by MISO as part of its MVP Informational Report in FERC Docket ER10-1791-001.)
The big cost would be $8.7 to $16.4 billion in higher annual revenue requirements for transmission access charges. Ratepayers across MISO also would pony up a monthly energy usage charge estimated initially at $1.01 per MWh (2011 dollars). But according to MISO, the portfolio of grid expansion projects likely would produce some $15 to $49 billion (present value) in total benefits across the MISO footprint over the next 20 to 40 years. According to MISO, about 75 percent of that benefit total would stem from savings in energy production costs—provided, as MISO believes and FERC agrees, that these savings will filter down eventually to retail ratepayers via reductions in wholesale power prices in MISO’s centralized day-ahead market.
But there’s the rub. Doubts continue to be heard.
In the latest iteration, the warnings come from consultant Ken Rose, now senior fellow with the Institute of Public Utilities at Michigan State, and before that senior economist at the National Regulatory Research Institute at Ohio State, the research arm for NARUC (the National Association of Regulatory Utility Commissioners).
This past summer Rose performed an independent review of the MISO MVP portfolio, on behalf of Michigan Citizens Against Rate Excess (Mich-CARE), which has challenged the MISO portfolio in comments filed at FERC on the grounds that Michigan ratepayers and the state in general will end up losers under the MISO plan. (See, Comments of Mich-CARE, FERC Dkt. ER10-1791-001, filed July 10, 2012.)
Now here it must be said that the Midwest ISO staunchly denies Mich-CARE’s grievance that the 17-project MVP portfolio will leave Michigan ratepayers high and dry. In fact, the FERC already has denied rehearing of its MISO MVP approval order, so that in strictly legal terms, the Mich-CARE missive is out of order: an impermissible collateral attack on a tariff already filed.
Thus MISO answers that “Mich-CARE’s comments largely consist of arguments already rejected by the commission’s earlier MVP orders.” (See, Answer of MISO, FERC Dkt. ER10-1791-001, filed July 25, 2012.)
And as MISO also notes: FERC found that Michigan consumers should benefit because MVP projects would address the existing lack of transmission capacity within and around Michigan and improve Michigan’s ability to import power from regions with lower prices. (MISO Answer, citing MVP rehearing order, at ¶¶148-49.)
Nevertheless, with the aid of various MISO-derived contour maps (see Figures 2-4), showing wholesale locational marginal prices (LMP) across the region from May of this year, Rose argues that evidence is lacking to show the predicted production cost savings and LMP reductions will trickle down to Michigan consumers enough to balance out the costs the state will end up paying to fund the build-out.
“Michigan is paying the highest prices in MISO,” Rose told Fortnightly in mid-September.
“And we aren’t talking about a momentarily high price in Michigan,” he continued. “These high prices are pretty consistent. Even eastern Michigan will sometimes be higher than western Michigan.”
In short, even if grid expansion lowers the gross regional cost of electric energy production, ratepayers in Michigan will be no better off if—according to Rose—it turns out that all that cheap power fails to translate into reduced LMPs for grid node locations in Michigan.
MISO looked mainly at production cost, Rose said, “which isn’t the same as ratepayer cost in today’s world.”
And so if the pricing patterns shown in the figures should recur too frequently, the state of Michigan—at least the more populous lower peninsula—could be left on the outside looking in.
But why should that trouble the grid planners? Why not just do the policy planning needed to build a renewables-friendly grid and then let the LMP chips fall where they may? After all, if prices remain high at particular nodes or across an entire state, wouldn’t plant developers step in and build more generation on the short side of the constraints, thus leveling out the LMPs?
“The original argument for LMP pricing was to provide a signal to generators to build in that area,” Rose said. “But it’s difficult to see how this problem in Michigan can be solved simply by building generation.”
He added that LMP pricing also should provide a price signal of where to build transmission.
“But in MISO,” he explained, “the problem is that the transmission owners and the generation owners are the same people, so there isn’t a lot of incentive to build transmission that’s only going to be for economic purposes, to lower congestion costs.”
Benefits Not Additive
To understand how eastern lower Michigan might pay $400/MWh, even as Illinois and Indiana see prices of $135 and $143 (see Figure 4), we need go back in time and examine how the MISO MVP plan came about, and why Michigan fought it for so long.
MISO’s MVP plan provides for socialized, region-wide allocation of transmission expansion costs, through both the transmission access charge and a load-based energy charge, of major grid expansions that meet at least one of three criteria, such as: 1) supporting energy policy mandates; 2) reducing wholesale energy production costs and “load costs” (LMPs); or 3) producing economic value across multiple pricing zones.
But consider MISO’s MVP Criterion No. 2:
“The project must provide multiple types of economic value across multiple pricing zones with a total project benefit-to-cost ratio of 1.0 or higher… In conducting the benefit-to-cost analysis, the reduction costs and the associated reduction of locational marginal prices resulting from a transmission congestion relief project are not additive and are considered a single type of economic value.”
Not additive? That appears to mean that if grid expansion reduces generation costs, but at the same time doesn’t bring down actual LMP market prices—as Ken Rose warns—then that’s still OK.
One problem, as the Michigan PSC pointed out two years ago in its initial comments in the MVP case, is that Michigan lacks strong electrical connections to the rest of MISO, and those connections would become even weaker after the defections of Duke and First Energy’s ATSI grid subsidiary to PJM:
“In effect,” wrote the PSC, “Michigan is becoming more of a Midwest ISO island than a peninsula.” (See, Comments of Mich PSC, pp. 8-9, FERC Dkt. ER10-1791, filed Sept. 10, 2010.)
Also opposing the plan, Consumers Energy, Detroit Edison, and municipal agencies had emphasized that Michigan’s RPS law requires that all renewable energy satisfying the mandate must come from in-state sources. Thus, any MISO MVP grid projects sited outside the state would do nothing to advance Michigan policy. Yet this 17-project plan would foist something like 20 percent of its capital cost on Michigan ratepayers under MISO’s load-weighted, postage-stamp cost allocation scheme.
Back in 2010, the protesting utilities also had introduced testimony from Andrew Dotterwich, electric transmission and markets regulations director for Consumers, and also from Consumers Senior Engineer Denis Leitch. Those two witnesses showed that after the withdrawal of ATSI from MISO, Michgan’s lower peninsula—also known as MISO local resource zone seven, or “MISO Northeast”—would retain no more than 450 MW of transmission connections with the rest of MISO, compared to 12,930 MW of grid links with PJM and Canada:
“Because 96.5 percent of the physical interconnected capability is with transmission systems outside of the Midwest ISO, the benefits to the MISO Northeast … from transmission upgrades external to MISO northeast are primarily derived from projects constructed in [Ontario] and PJM and not from transmission upgrades constructed in the Midwest ISO. This is a unique defining characteristic of MISO Northeast.” (See, Affidavit of Andrew Dotterweich, p.3, Protest of MISO Northeast Trans. Customers, FERC Dkt. ER10-1792, filed Sept. 10, 2010.)
These protests, however, went nowhere. FERC eventually signed off on the MVP in December 2010 (133 FERC ¶61,221), and again on rehearing in October 2011 (137 FERC ¶61,074.)
MISO planners eventually would locate one—and only one—of the 17 MVP portfolio projects in Michigan: ITC’s 345-kV Thumb Loop Expansion. The Michigan Wind Energy Resource Zone Board had identified Michigan’s thumb as a primary wind resource area. The state PSC later endorsed the board’s finding. (See, Mich.PSC Case U-15899, Jan. 27, 2010.)
But that only added insult to injury. As the protesting utilities noted, the new transmission plant revenue requirement imposed on Michigan ratepayers to pay MVP projects located outside the state, and ineligible to satisfy Michigan’s RPS, would dwarf by a factor of five the Michigan revenue requirement implied by the Thumb project—itself sufficient to allow the state to meet its RPS. (Protest of NE Trans. Customers, pp.18.)
In the meantime, however, FERC has issued and reaffirmed its landmark Order 1000, rendering moot all Michigan’s arguments against the MISO plan.
In page 86 of its Results and Analysis study, MISO predicts that its 17-project MVP portfolio will yield benefit-to-cost ratios that are roughly equal for each of the region’s seven local resource zones:
• Zone 1. (MN, MT, ND, SD, Western WI) Benefits estimated as between 1.6 – 2.9 times cost.
• Zone 2. (Eastern WI & Upper MI) 2.0 – 3.3x.
• Zone 3. (IA) 1.6 – 2.8x.
• Zone 4. (IL) 1.6 – 2.8x.
• Zone 5. (MO) 1.8 – 3.2x.
• Zone 6. (IN, KY, OH) 1.8 – 3.0x.
• Zone 7. (Lower MI) 1.7 – 3.0x.
Was MISO simply trying to spread the wealth, to achieve a politically acceptable result?
Ken Rose agreed: “Yes, this was the point. I was concerned they were simply spreading the costs around. And again, my concern was that MISO is only looking at production cost savings, rather than pricing.”
But when asked for this column, a MISO spokesman provided key program facts indicating that the MVP portfolio would cost the average MISO residential customer only $11 a year, but pay back some $23 in benefits.
Back in July 2010, when it first proposed its MVP regime, MISO submitted testimony from John Lawhorn, its director of regulatory and economic studies, that showed how for policy-based planning, MISO had employed a production cost study model focusing more directly on generation attributes and how markets might be expected to behave:
“While load or power flow models are the basis for most transmission reliability and operational planning, production cost models are best used for transmission planning and market analysis. Production cost models allow the simulation of all hours over a year, rather than the single peak (or off-peak) hour as performed with a power flow model. This annual approach provides the Midwest ISO [with] detailed information, such as LMPs, line flows, and congestion across a full range of operating conditions for 8760 hours… [I]t allows the focus on an annual energy basis rather than a single point in time, which may not necessarily be indicative of economic effects.”
Lawhorn continued to explain how a production cost model includes all manner of detailed information, including fuel cost forecasts, unit heat rates, ramp rates, outage rates, and unit operating costs—all carried out to an hourly demand profile on a control area granularity.
And to account for different possible future economic conditions or public policy decisions, such as a federal RPS law or carbon emissions regulations, that might effect demand growth levels, inflation rates, or wind energy penetration, Lawhorn explained how MISO analyzed five different future macro scenarios:
• Business As Usual: The current power system, with growth rates based on pre-recession historical data.
• RPS Future: Assume a 20-percent federal RPS requirement, with wind capacity factors varying regionally from 35 percent to 45 percent, and solar generation modeled at 10 percent.
• Carbon Cap / Smart Grid / Electric Vehicle Future: A 20-percent federal RPS, plus a carbon cap modeled after the then-active Waxman-Markey bill, plus smart grid investment and widespread electric vehicle use.
• Mid-Low Demand: Assume continuation of the Great Recession.
• Carbon Cap / Nuclear Future: Assume that generation technologies such as integrated gasification combined-cycle (IGCC) and combined-cycle with carbon sequestration won’t develop, requiring much out-year thermal generation to be nuclear.
Given this outline, Fortnightly asked Ken Rose whether a policy-based transmission planning regime, like MISO’s MVP and FERC’s Order 1000, represented a virtual rebundling of generation and transmission at the federal level.
He didn’t necessarily agree:
“The ‘rebundling’ of generation and transmission isn’t really the point. The point is the most efficient design of new transmission; how to design transmission to minimize costs to ratepayers.”
But he added: “It isn’t inconsistent to ask transmission planners to consider LMPs.
“It’s as if FERC had forgotten what their earlier charge was—to facilitate the wholesale market.”
Given the lack of electrical connections between Michigan and the rest of MISO, and the state’s conviction that benefits from policy planning are unlikely to flow to Michigan consumers through lower LMP wholesale prices, what might be in store for Michigan under FERC Order 1000?
“I’m not one of them, but there are people in Michigan saying they would be better off going it alone: doing the planning on their own,” Rose said.
“Right now it looks like Michigan will be paying for transmission expansion that won’t benefit the state at all.
“There is really no project in there that will bring any price relief.”