The models and motives behind tomorrow’s transmission expansion.
Bruce W. Radford is editor-in-chief for Public Utilities Fortnightly.
The grid is busting out all over, but not everywhere in the same way. In the past 12 months, developers have announced plans for a number of new transmission projects of regional, if not national significance, but with markedly different goals and aims. In short, two distinct models have emerged for new grid development, one in the East, the other in the West.
The Eastern model, designed to mesh with grid system operators and RTOs (regional transmission organizations), views transmission as a profit-making business. The process is well defined. You map out markets, study the locational marginal prices (LMPs) at various nodes, calculate heat rates and fuel prices, and then design your project to compete against those numbers. Along the way, you work with the local RTO through a series of studies for feasibility and system impacts, to ensure proper management of loop flows, reactive power support, voltage stability, and so forth. The major remaining hurdles concern site permitting and NIMBYism (“not in my back yard”).
But in the West, by contrast, the game proves much more complicated. Without RTO markets to fix prices and set protocols for planning, impact studies, and cost allocation, it has fallen to state governments to fill the vacuum. In fact, lawmakers in several states already have created new state agencies assigned the task of building out the grid. Governors, too, have formed regional state coalitions to push projects. Under this model, transmission becomes a virtual arm of the state—a tool to boost jobs, taxes, and the state’s economy. But by investing transmission with public-interest goals, the ante is raised.
Thus, in the West, the developer must begin as often as not by identifying the location of under-exploited natural resources. Where are the coal and lignite deposits, the gas reservoirs, the geothermal springs, the windiest plateaus? You plan the line to capture those resources. The resource plan comes first; the electrons seem almost secondary by comparison.
And then things get dicey. Concerns over climate change and greenhouse-gas emissions—once the sole worry of California regulators—now extend across the West. Even the fly-over states have begun to question the concept of transmission expansion as a tool for resource development, if it means burning more coal. In California, the regulators have become even more aggressive. Just in the past six weeks, the state public utilities commission (PUC) has issued new mandates for controlling greenhouse-gas emissions as part of resource procurement plants for its investor-owned electric utilities, making it clear that in-state environmental rules will apply with equal force to power electrons imported via the interstate grid. These events reportedly have spurred some developers to rethink plans for building coal-fired power plants in the Intermountain West, since they must remain dependent upon California as the prime destination market. This new reticence likely will force developers to rely much more on renewables in putting together a business plan for any of the three very large regional grid projects proposed recently for the West:
• Frontier Line. Proposed by the Wyoming Infrastructure Authority and a four-state coalition led by the governors of Wyoming, Utah, Nevada, and California, and envisioned to run across those same states;
• TransWest Express. Proposed by Arizona Public Service Co., with a route running roughly congruent to that envisioned for Frontier; and
• Northern Lights. A direct-current (DC) project proposed by TransCanada, with possible alternative routes leading from Montana, or thereabouts, and running southwest into California.
Other projects, though smaller, appear just as caught up in squabbles over state policy favoring renewable energy. Examples are the Sunrise Powerlink, proposed by San Diego Gas & Electric, and the Green Path, proposed jointly by the Imperial Valley Irrigation District and the Los Angeles Department of Water and Power, with heavy participation by Citizens Energy, the pro-consumer combine made famous by Congressman Joseph Kennedy.
Not so, apparently, in the East. That’s where American Electric Power Co. (AEP) and Allegheny Energy rocked the electric industry in January and late February with proposals for two new monster transmission lines:
• AEP Interstate Project. A 765-kV line, with transfer capacity of roughly 5,000 MW, running west to east from West Virginia through western Maryland, eastern Pennsylvania, and into New Jersey; and
• Trans-Allegheny Interstate Line. A 330-mile, 500-kV project running from Allegheny’s Wylie Ridge Substation, near Wierton, W.V., to a new substation in central Maryland near Kemptown, near the company’s eastern territorial boundary (announced on Feb. 28).
The AEP and Allegheny proposals contrast so vividly against the Western situation because of the way in which FERC’s pro-market policies appear to motivate the two projects. AEP’s line in particular would target Baltimore, Washington, D.C., and the suburbs in-between—an area marked recently by relatively high spot energy prices in PJM’s regional markets.1 The Allegheny proposal appears to follow much of the same strategy.2 Small wonder, then, that FERC Chairman Joseph T. Kelliher took pains recently to plug the new AEP project at the commission’s recent technical conference, held on Feb. 3, to examine an entirely different topic: PJM’s reliability pricing model. Clearly, FERC must see the AEP project as validation for its oft-maligned standard market design (SMD); that RTOs and locational pricing really can entice developers to launch new grid projects.
For example, AEP took care in its application filed at FERC (on Jan. 31, 2006) to show how its project should help dampen the extreme nodal price differentials seen last summer in Maryland. Moreover, AEP has asked FERC for special financial incentives to reward the investment, as envisioned by the EPACT 2005 law, and exactly as promised by FERC itself in a recent policy initiative.3
Markets & Prices: The Eastern Model
The story of AEP’s proposed Interstate grid project begins with the company’s decision to join the PJM RTO grid system (see Figure 1). That move paved the way for AEP to tout its profit strategy of exporting low-cost power into areas of the PJM footprint marked by high locational spot energy prices.
At the time AEP applied for membership, the company also had sponsored a cost-benefit study, conducted by Cambridge Energy Research Associates, showing a boost to AEP’s bottom line from new off-system power sales revenues, plus significant consumer savings for ratepayers residing in the high-cost mid-Atlantic states who would buy the cheaper exports. In essence, those predictions have come to pass, but there remains a large potential for additional market exploitation. Now AEP’s new project would mine that vein even further.
Money on the Table. For example, in a separate presentation designed to justify AEP’s integration into PJM, consultant Michael Schnitzer (Northbridge Group) had testified before FERC on behalf of Exelon on the potential for capturing economic rent in exporting power from the Midwest to Mid-Atlantic:
“”The generation mix in PJM and in the Midwest are quite different. … The ability to import more coal energy into PJM and displace gas energy can be quite valuable. … During 2003, a positive spread of $10/MWh or more was observed for approximately 1,500 hours, or 17 percent of the year.”
Schnitzer then noted how much money was being left on the table by failing to develop the necessary long-haul transmission capacity to exploit and capture this rent:
“During these hours,” he explained (when coal is on the margin out West, and gas on the margin back East) “an uneconomic level of physical transmission service, relative to regional LMP markets, can be quite expensive. For example, 500 MW of foregone import capability under these circumstances could ‘cost’ $10,000 per hour, or $15 million if there were 1,500 hours per year where coal was available to displace gas. For 1,000 MW of foregone import capability, the cost could be twice as high, or $30 million per year.”4
Now jump ahead about two years and see what has happened to markets and prices with the integration of AEP (plus Commonwealth Edison, Allegheny Power, and Dayton Power & Light) into PJM. In short, with some key exceptions, spot locational energy prices have started to even out across the PJM grid area. Nothing can illustrate this phenomenon better than a pair of visual exhibits presented recently by PJM executive vice president and COO Audrey A. Zibelman, at FERC’s February conference (see Figure 2).
The left-hand graphic snapshot shows price patterns as they appeared prior to AEP’s integration into PJM (cool colors indicate lower prices; warm colors show higher prices). Then, on the right, you see the patterns after integration. The blue and gray appear much more prevalent, and now cover a good chunk of the footprint, indicating a lack of price differential within that area.
A Maginot Line. Nevertheless, AEP has not yet finished the job of exploiting high-priced markets.
In December, in releasing a 10-year plan for the state’s electric utilities, the Maryland Public Service Commission noted that because of transmission congestion, daytime spot locational energy prices in the state during last summer had appeared higher than for any other region in the PJM system. And, according to the commission, Maryland appeared “vulnerable to a further widening in this LMP gap.”
The PSC presented further data showing summer after noon spot LMP prices running much higher for in the service territories of Baltimore Gas & Electric and Potomac Electric Power than for AEP, Allegheny Power, Dayton Power & Light, or even the PJM system overall. As for the source of the transmission congestion, the commission in particular cited the Doubs substation and the Doubs-Mt. Storm 500 kV circuit. Most impressively, however, the PSC presented two power price maps, similar in form to Zibelman’s exhibits from PJM, but this time showing snapshots of prices on particular summer afternoons. One of those shots, reproduced here shows a remarkable “Maginot Line” separating the high-priced mid-Atlantic seaboard from the lower-priced interior of West Virginia, western Pennsylvania, and Ohio (see Figure 3).
Clearly, the integration of Midwestern utilities into PJM had not exploited all available market opportunities. Thus the new project proposal from AEP.
The AEP Project. The 550-mile Interstate Project would originate at AEP’s Amos Substation in West Virginia (part of its network of 765-kV lines), then span the Potomac River to Allegheny Power’s Doubs Substation, near Frederick, Md., and terminate in New Jersey at the Dean substation, operated by Public Service Electric & Gas. According to AEP, the line offers a significant alternative path to existing west-to-east grid constraints across PJM, which should make locational energy prices less volatile between western Maryland and the load centers along the Baltimore-Washington corridor (see Fig. 4).
AEP estimates that its new line could end up costing about $3 billion. Yet that figure would pale when compared to congestion costs expected in PJM over the next 20-30 years, where congestion hit $800 million in 2005, and was expected to exceed $1 billion this year, according to Michael G. Morris, AEP’s chairman, president, and COO. Moreover, AEP predicts that its new line would reduce transmission losses by approximately 280 MW during peak loading conditions—equivalent, when measured across all hours, to avoiding the nominal capital investment of $175 million required for a new combined-cycle gas turbine power plant.
To soften the cost blow, AEP has created “AEP Transco,” a wholly-owned subsidiary designed as a stand-alone grid company, conducting no commerce outside of its primary business of financing, constructing and owning transmission lines and making grid service available from those facilities. This move will help AEP justify its request for financial compensation of the type that FERC promised in its recent rulemaking on transmission investment incentives, such as expense treatment for pre-construction costs, rate-base recovery of construction work in progress, and a higher rate of return. (AEP also has asked for an adder of 200 basis points, should FERC end up deciding that a new grid expansion warrants such a generous reward if it serves regional needs.)
When asked how PJM would go about reviewing AEP’s Interstate Project, PJM Chief Communications Officer Terry Williamson told Fortnightly that the RTO would “consider all aspects of the project including, cost-benefit analysis, in so far as examining the value the line brings, versus the economic impact it will have on a variety of factors, such as congestion and generation.”
The Rate Design Question. All of this leads to the most important question: Who pays?
Last spring, in a key order, FERC acknowledged that AEP’s integration into PJM had raised doubts about whether PJM’s policy of license-plate pricing still was valid for setting the basic RTO access charges for regional transmission service.5
In fact, FERC had recognized the problem much earlier, back when it issued its proposed SMD rulemaking, that license-plate pricing becomes unfair when an RTO eliminates its internal wheeling charges, as PJM had now done, with the demise of utility-imposed through-and-out (T&O) charges:
“This may create problematic cost shifts for certain transmission providers that currently receive a significant amount of revenue from exports and wheel-throughs—e.g., AEP and Cinergy.”
For its part, PJM has proposed to maintain its current license-plate rate design until Jan. 31, 2008, albeit in “modified” form, with the cost of some new facilities spread beyond the local rate zone under Schedule 6 of its Operating Agreement, and Schedule 12 of its Open Access Transmission Tariff (OATT). By contrast, AEP has proposed a “highway-byway” design, whereby grid costs are spread across the entire RTO footprint for high-voltage RTF lines (regional transmission facilities) of 345 kV or higher. Craig Baker, AEP senior vice president for regulatory services, argues why:
“On its face, it makes no sense that participants in an active electricity market stretching from Chicago, Illinois, to the eastern shore of the United States, who are able to take advantage of the vast transmission system in the PJM region, would not share in the responsibility of carrying the costs of the regional network.”6
To be clear, AEP’s application filed at FERC for its new Interstate Project does not make the proposal contingent upon FERC acceptance of its proposed RTF rate design. That said, however, the two clearly were meant for each other.
Suppose AEP should convince FERC to accept its proposed RTF transmission rate design for all utilities across the entire PJM footprint. How would that affect consumers served by other retail utilities, residing in other service-territory rate zones?
Dennis Bethel, AEP’s managing director for regulated tariffs, provides a rough picture on how that would work out in his testimony presented last September in the same case.
As Bethel explains, some PJM utilities, naturally, would own more high-voltage RTF line-miles than others, and would claim proportionately higher shares of the total RTO-wide RTF revenue requirement. Thus, the RTF plan would create winners and losers. Utilities owning the most significant portions of the high-voltage RTF asset base (those with the highest percentage of RTO-wide revenue requirement for RTF facilities) would receive credits. Those owning smaller shares of RTF lines would run a deficit, and would end up reimbursing their transmission-rich cousins.
For example, as Bethel explained, six utility zones would “experience net charges” of anywhere between 1 percent and 11 percent of the transmission revenue requirement otherwise assigned to that utility zone under the current license-plate pricing regime. Five zones (utilities) would see net charges of 20 percent to 31 percent of their erstwhile zonal revenue requirements. Four zones, meanwhile (including AEP), would receive net credits totaling $158 million per year.7
Clearly, AEP’s credit position under a highway-biway rate design would improve even more with construction of the new, high-voltage, 765-kV Interstate Project. Would PJM accept such a scenario? Interestingly enough, PJM executives had foreseen much of this debate long before AEP came forward with its RTF rate proposal.
Last summer, at a conference held in West Virginia to explore transmission investment options to facilitate greater reliance on coal-fired power, PJM’s Western region president Karl Pfirrmann had presented a remarkable talk on “Project Mountaineer”—PJM’s ultimate pipe dream of a transmission project.
Pfirrmann advised his audience not to think of Mountaineer as an actual project, but instead, as an overview of what PJM would want to commission and build if all its wishes could come true. But Pfirrmann’s description of how the Mountaineer might appear now looks quite a bit like AEP’s Interstate Project. Thus, he staked out Mountaineer as a hypothetical network of new 500-kV and 765-kV transmission paths stretching 550 to 900 miles—linking Kentucky and West Virginia to Eastern load centers stretching from Washington, D.C. to Northern New Jersey—costing between $3.3 billion and $3.9 billion, and capable of carrying 5,000 MW of power. Pfirrmann offered maps, as well; look them over and you see a virtual blueprint for AEP’s Interstate Project, proposed seven months later.8
Even more remarkable, however, was Pfirrmann’s comment on how to deal with the cost:
“Although this [Mountaineer] is clearly a costly undertaking, it is worth noting that … $4 billion in new transmission investment [translates] to only 1 mill/kWh on a typical residential bill if such costs were spread across the entire PJM footprint.”
AEP could not have said it better.
Resource Development: The Western Model
One year ago, on April 4, 2005, California Gov. Arnold Schwarzenegger joined with fellow governors Kenny Guinn (of Nevada), Dave Freudenthal (of Wyoming), and John Huntsman (of Utah) to announce a four-state effort to build a new high-voltage electric transmission line across the Western United States, originating in Wyoming, and with terminal connections in each of the other states. This project, to be known as the Frontier Line, would cost between $1 billion and $1.7 billion. According to a memorandum of understanding released by the four governors, Frontier would allow for development in the Intermountain West of up to 6,000 MW of wind generation, plus 6,000 MW of clean coal power, to serve major load centers such as Salt Lake City, Reno, Las Vegas, and Southern and Northern California. The idea was developed by a number of stakeholders and technical experts working as part of the Rocky Mountain Area Transmission Study (RMATS). RMATS, in turn, operates as part of the Western Transmission Protocol, a brainchild of the Western Governors’ Association. Frontier’s acknowledged lead sponsor, however, is the Wyoming Infrastructure Authority, a state agency created in June 2004 by the Wyoming legislature for the express purpose of getting new transmission built.9
Six months after the Frontier announcement came word of more projects of similar heft and purpose: First, in September 2005, TransCanada proposed its Northern Lights Transmission Line (see Figure 6), running southwest from Montana into Idaho, Nevada and California.10
Then, in October, there was the TransWest Express (see Figure 7), proposed by Arizona Public Service Co., the utility subsidiary of PinnacleWest, to run from Wyoming through Utah to Arizona, with a possible new link into Southern California via a separate proposal to construct a second parallel line between Palo Verde and the Devers substation.11
When interviewed for this article, WIA executive director Steve Waddington said that the Frontier sponsors had not yet come up with a proposed route, but said that the California Independent System Operator (Cal-ISO) was doing some scoping work and putting together some ideas.
When asked who grants final certification authority for such a large project, however, Waddington admitted a bit of a conundrum: “We don’t have RTOs to conduct all those studies. Instead, the four states will have to play a huge role in the permitting and cost review.”
Waddington conceded that TransWest, with its “anchor tenant,” was probably a little bit ahead of Frontier. Yet he remains optimistic on Frontier: “The TransWest footprint is somewhat different than the Frontier concept, but this is not a horse race. The two lines are compatible, and we see a lot of potential for TransWest and Frontier to coordinate their efforts.
“And as for Frontier, stay tuned for utility partners.”
Indeed, TransWest does appear much farther along. Last November, Pinnacle West included route maps and some technical analysis in an 11-page notice of intent filed with the U.S. Department of Energy (Office of Electricity Delivery Reliability) to participate in the DOE’s efforts to prepare a “programmatic environmental impact statement” in tandem with DOE’s program to designate “National Interest Electric Transmission Corridors” on federal lands, throughout the West, as required by the Sec. 368 of the EPACT 2005 legislation.12
Bob Smith, manager of transmission planning for Arizona Public Service, told the Fortnightly, “We are running an open stakeholder process, but we will need partners to build this project, and we are probably looking at 2 AC circuits. We included [TransWest] in an update to our 10-year transmission plan filed with the Arizona Corporation Commission [the state PUC]. During the next year we will assemble a consortium. At APS we will probably lead the cost-benefit analysis. But it’s still to be determined as to what each owner would have to do within their own service territories.”
When asked about the purpose of the line, Smith said that APS owned no generation resources in the Wyoming area, but added, “One view is that if renewable resources can be developed in Arizona, so much the better. But I’ll tell you, the wind is much better in Wyoming than Arizona.”
And would Frontier, TransWest, and Northern Lights have to fight amongst each other to obtain exclusive certification rights? Smith thought not.
“In my mind,” he predicted, “there’s no doubt that all these projects will come together. “It’s difficult to believe that we can overbuild transmission out here in the West.”
Some puzzling questions remain however. Who will conduct the final review of the economic merits of these western projects? What factors might control such a review?
Project Goals and Review. One key uncertainty arises because the regional reliability council for the Intermountain West, the Western Electricity Coordinating Council, finds itself right in the middle of reforming its standards for review of transmission expansion projects. According to WECC spokesman Jay Loock, the council is phasing out its SSGWI protocol (Seams Steering Group Western Interconnection) at the request of Western region governors. In its place, WECC is developing a transmission expansion planning policy (TEPP). WECC held a TEPP workshop in mid February in Salt Lake City, and its Web site offers a look at presentations from the workshop on what “products” and factors should play a role in project review.
When asked about reviewing the Frontier Line, Loock responded, “We don’t perform analyses per se, but provide a forum for resolution of problems and for rating the line and determining seasonal capability. We would not conduct a system impact study.”
A second problem stems from the very nature of project sponsorship in the West. For example, the Wyoming Infrastructure Authority, the key Frontier Line sponsor, was created by legislation in Wyoming13 to “diversify and expand the Wyoming economy through improvements in the state’s electric transmission infrastructure.” The WIA even enjoys authority to provide financing by issuing bonds for grid projects. In Wyoming Executive Order 2003-4, issued by Gov. Steve Freudenthal, sets out strict guidelines for WIA in leading project development efforts. Among other things, it orders the WIA and state utility commission to a include a governor’s appointee in any project team formed to coordinate project reviews.
Other states can be seen moving in the same direction. The Western Governors’ Association last summer recognized formation of similar governmental agencies in several Great Plains states, and that New Mexico might follow suit.14
Consider North Dakota, another state rich in wind power resources (and also lignite), but poor in consumer load. Lawmakers there created a state transmission authority patterned after the WIA.15
Among other things, the North Dakota legislation declares it “an essential governmental function and public purpose” to remove transmission export constraints to help facilitate development of the state’s natural resources. With this sort of mandate, how should western regulators balance consumer benefits in California and downstream markets, against job creation and development upstream in the production areas?
Climate Change Policy. Six weeks ago, the California PUC announced its intention to adopt ceilings on emissions of greenhouse gases from electric generation. The emissions caps would be keyed to delivery of power to load, rather than operation of power plants; thus, the caps would apply to electricity imported into the state via long-haul transmission lines, as well as to in-state power generation.16
Clearly, these new emissions caps will impose severe resource constraints on any proposed grid project, as the PUC already had required that investor-owned utilities (IOUs) employ a carbon dioxide adder of an initial $8 per ton in evaluating costs and benefits under long-term resource procurement plans. Moreover, the new greenhouse ceilings presumably will conform to the PUC’s previously issued “greenhouse gas performance standard.” That standard declares that for any procurement contracts longer than three years, IOUs must maintain greenhouse-gas emissions at levels no higher than expected from a combined-cycle natural gas turbine. When interviewed for this article, Commissioner John Geesman of the California Energy Commission (CEC) confirmed that the CEC had endorsed that standard in its landmark 2005 Energy Policy Report (IEPR), and would apply it in reviewing resource procurement plans, including review of transmission line projects.17
Consider also the state’s Energy Action Plan, which requires California’s electric IOUs to procure 20 percent of their electric retail sales from eligible renewable resources by 2010—seven years earlier than the 2017 target set by Senate Bill 1078. Moreover, the PUC also reportedly is considering whether it should accelerate that goal to 33 percent by 2010, to conform with the governors signed Executive Order S-3-05.18
Compare these goals with the progress made so far by the IOUs: Renewables make up 18 percent of load for Southern California Edison, 12 percent for Pacific Gas & Electric, and only 4.5 percent for San Diego Gas & Electric.19
Thus, you begin to see the pressure building on California utilities, to deliver renewable energy to their ratepayers. And problems can arise even when a utility seeks to build a short-haul transmission line for the sole purpose of gaining access to renewables. The classic example comes courtesy of Southern California Edison, which failed last year in attempts to obtain guaranteed cost recovery before the fact, with costs rolled in to its existing transmission rates, for a new “trunk” line to be built to gain access to anticipated wind power development in the Antelope Valley.
In that case, FERC said the new line would not provide system-wide network benefits, but would operate sole-use facilities benefiting only a single party—the anticipated wind project developer. Thus, FERC would treat the new proposed trunk line as a generation tie, and require the wind plant developers to fund it themselves. Edison, the American Wind Energy Association, and FPL Energy (famous for its wind projects) had complained to no avail that forcing wind developers to fund transmission access would discourage most grid expansions aimed at capturing wind energy potential.20
The Coal Shadow. At the same time that California utilities are hunting frantically for renewable energy, especially in imports from the Intermountain West, the proposed Frontier, Northern Lights, and TransWest Projects suffered an acute embarrassment: The projects would both begin in, and pass through, areas flush with proposed projects to build coal-fired power plants. Thus, opponents have attacked the Frontier Line as a vehicle for importing dirty coal-fired power into California.21
At Western Resource Advocates, economist John Neilsen reports that several utilities and developers are rethinking their plans to build coal-fired power plants in Nevada, Utah, New Mexico, and elsewhere in the West, citing concerns about the tightening policies emerging from California on power imports.
In August of last year, at a workshop held by the CEC to develop its 2005 IEPR document, Neilsen reported that some 31 new coal-fired plants representing 18,500 MW had been proposed for the Interior West, and he counted 16 such plants (8,200 MW) then in the permitting process. That total, he said (the 8,200 MW), would emit more than 66 million tons of CO2 per year (59.9 MMtCO2e). That potential dollop of greenhouse gases would easily exceed the CO2 reductions in California produced by all the CPUC’s energy efficiency goals—8 MMtCO2e, plus motor vehicle emissions reductions under the state’s Pavley Law—30 MMtCO2e, plus Gov. Schwarzenegger’s proposed acceleration of renewable energy to 33 percent by 2020—11 MMtCO2e.22
Now, however, Neilsen cites Sempra and its 1,200-MW Granite Fox coal-fired generating plant proposed for Gerlach, Nev., just outside the California border. The Granite Fox plant otherwise would have easy access to California markets via the high-capacity Pacific DC Intertie.
Neilsen cites other proposed out-of-state coal-fired plants as rethinking their plans as well. Those projects include: (1) the 1,500-MW Desert Rock Power Plant (near Farmington, N.M.) proposed by Sithe Global Power (owned by a private equity fund); and (2) the planned addition of new capacity to the Intermountain Plant, in Utah, by a consortium of municipal utilities. (The Intermountain project, however, would have access to a DC tie line owned by the Los Angeles Dept. of Water and Power, which, as a public power entity, lies outside CPUC jurisdiction.)
Note that the Wyoming Infrastructure Authority had asked the CEC “to seriously reevaluate the legal foundation” of its GHG performance standard in comments filed with the CEC during the run-up to release of its IEPR. Wyoming had argued that the GHG standard raised problems with the Commerce Clause: “Although the standard purports to be fuel-neutral, in fact it is not,” claimed the WIA, “since of the likely sources of generation that could serve California in significant quantities, only coal generation cannot meet the standard.”23
Neilsen recommends more work on coal gasification to solve this dilemma, and notes that Xcel Energy is supporting a bill pending in Colorado to help foster an ICGT project. He also cites help on the way from the EPACT 2005 legislation, which provides for assistance in developing IGCT technology for western coals, at altitudes above 4000 feet, which poses certain technical problems for gas combustion turbines.
Nevertheless, Neilsen warns that the “shadow” of all this potential coal-fired power threatens to polarize the energy debate in the West.24
1. See, Petition for Declaratory Order, FERC Docket No. EL06-50, filed Jan. 31, 2006.
3. See “A Candy-Coated Grid,” Public Utilities Fortnightly, March 2006, p. 24, discussing proposals in FERC Docket RM06-4, issued Nov. 17, 2005.
4. See, Exelon Corp. Exhibit 1, FERC Docket No. ER03-262, filed Jan. 7, 2004. See also, “It’s Down to Dollars for AEP and PJM,” Fortnightly’s Spark, February 2004, pp. 6, 13.
5. Docket Nos. ER04-156 et. al., May 31, 2005, 111 FERC ¶61,308.
6. See, Prepared Direct Testimony of J. Craig Baker, FERC Docket No. EL05-121, p. 22, filed Sept. 30, 2005.
7. See, Prepared Direct Testimony of Dennis W. Bethel, FERC Docket No. EL05-121, pp. 14-18, and Exhibit AEP-204, filed Sep. 30, 2005.
8. See, Testimony of Karl Pfirrmann, FERC Docket No. AD05-3, June 24, 2005.
9. For background on the Frontier Line, see www.westernroundtable. com/energy/Frontier_Line_backgrounder.pdf. For updates on project status, see also http://psc.state.wy.us/htdocs/subregional/updates.htm.)
10. See, www.northernlightstransmission.com.
11. See APS New Release at www.aps.com/general_info/newsrelease/newsreleases/ NewsRelease_300.html. For technical presentation and analysis, refer to the “STEP” process—“Southwest Transmission Expansion Plan”— at the California ISO, at http://www.caiso.com/docs/2002/11/04/ 2002110417450022131.html, and the company’s presentation at a Cal-ISO meeting on Oct. 28, 2005 meeting, at http://www.caiso.com/ 14bc/14bcead62520.pdf.
12. (See, 70 Fed.Reg.36647, Sept. 28, 2005. See also, West-wide Energy Corridor Programmatic EIS Information Center, at http://corridoreis.anl.gov.
13. Wyo. Stats. sec. 37-5-303(a)
14. See WGA Policy Resolution 05-07, June 14, 2005.
15. See North Dakota House Bill 1169, regular session commencing Jan. 4, 2005. See also, comments of Jerry Lein, Analyst, N.D. Pub. Serv. Comm’n, submitted at FERC technical conference, “Promoting Regional Transmission Planning and Expansion to Facilitate Fuel Diversity,” Charleston, W.Va., May 13, 2005, FERC Docket No. AD05-3.
16. See Cal. P.U.C. Decision 06-02-032, Feb. 16, 2006.
17. See, Integrated Energy Policy Report, CEC-100-2005-007-CMF, November 2005, p. E-14.
18. See Cal. P.U.C. I.05-09-005, 2005.
19. See Affidavit of Gary Allen, filed March 24, 2005, FERC Docket No. EL05-80.
20. See Order on Petition for Declaratory Order, Docket No. EL05-80, July 1, 2005, 112 FERC ¶61,014.
21. See, for example, “Importing Power, Fostering Pollution: Four-State Electric Line Encourages Coal-Fired Plants,” San Francisco Chronicle, May 15, 2005.
22. See Clean Coal Technology and California Energy Policy, John Neilsen, Western Resource Advocates, Aug. 17, 2005, at www.westernresourceadvocates.org.
23. Comments of Wyoming Infrastructure Authority on Advance Coal Technologies and Recommended GHG Performance Standard, filed Oct. 5, 2005, available at http://www.wyia.org/Docs/Comments/CA%20Comments%2010-05-05.pdf.
24. For a comprehensive 70-page analysis of California imports of coal-fired electric generation from across the West, see “Clearing California’s Coal Shadow from the American West,” J. Milford, J. Nielsen, V. Patton, N. Ryan, V. White, C. Copeland, Western Resource Advocates, Environmental Defense, Center for energy Efficiency and Renewable Technologies, August 2005, at www.westernresources.org/media/pdf/CA%20Coal%20Shadow.pdf.