Issue 83: February 24, 2006
When the dust cleared in Santa Fe after the year's 30-day legislative session, the one bright spot for renewable energy in New Mexico was passage of the Solar Market Development Act, which established an income tax credit for homeowners and businesses that install solar electric and solar heating systems. Governor Bill Richardson's other proposals, including the high-priority Renewable Energy Transmission Authority, did not pass.
Richardson described the session as "the least productive" since he has been governor. He is considering calling a special session to address unfinished business, including the transmission authority, but he hasn't done so yet.
The new solar legislation provides a tax credit equal to 30 percent of the installed cost of a photovoltaic system, minus any applicable federal credits, up to a maximum of $9,000 in credits per system, according to the Coalition for Clean Affordable Energy, which has worked with the governor for years to get the solar tax credit passed. The $5 million-a-year program extends for 10 years; $3 million is allocated for PV systems and $2 million for solar thermal systems.
Jon Goldstein, spokesman for Richardson, said the new program, combined with federal credits, would mean about one-third off the cost of a typical residential solar system.
"It will improve energy efficiency for homeowners in New Mexico and also help the state's solar industry grow," he said.
The legislation says only systems certified by New Mexico's Energy, Minerals and Natural Resources Department will be eligible to receive the credits and requires a rulemaking be held to determine certification procedures. Richardson's special assistant for renewable energy, Craig O'Hare, told Prospects that the department will conduct a public process to establish those rules between now and June.
Richardson's push to make New Mexico the first state with a renewable energy transmission authority seemed to be succeeding at first, but then fell by the wayside as budget and minimum wage fights intensified. The legislation would have created a quasi-governmental agency to plan, finance and acquire land for transmission lines that carry at least 30 percent renewable energy. The goal was to get the transmission needed to develop more wind energy projects in the state.
"Even during this short session, the governor got the Renewable Energy Transmission Authority bill through both houses," Ned Farquhar, Richardson's energy policy advisor, told Prospects, pointing out that a procedural tactic on the last night of the session caused 60 bills, including several energy bills, to die. But even if passing the transmission authority legislation has to wait until next year, Richardson will continue to push for action on New Mexico's transmission needs and wind energy development, he said. "With the federal Production Tax Credit for wind expiring in just a couple of years, he'll try to make things happen -- New Mexico can't afford to sit on its hands for another year."
The legislature did pass a memorial calling for the establishment of a task force to evaluate how New Mexico agricultural entities can contribute to the production of renewable fuels, to develop strategies for building a renewable fuels industry in the state and recommend legislation for renewable fuels standards. The task force will make its first report in October.
This year, Richardson asked the New Mexico Public Regulation Commission to take up the issue of net metering, something he offered as legislation in 2005. Richardson wants PRC rules changed to require larger (up to 100 kW) customer-owned renewable systems to be net-metered by interconnected utilities. The current limit is 10 kW.
On New Mexico's energy efficiency front, PNM, the state's largest utility, held the first meeting on Feb. 22 of a new advisory group that will help design a demand-side management program for its residential, commercial and industrial electricity customers. On Feb. 1, PNM launched a new energy efficiency program for its residential natural gas customers. Consumers receive rebates for programmable thermostats and water heater wraps, as well as rebates for contractor-installed services such as home insulation.
One of the first tasks of the electricity DSM study will be an "appliance saturation survey," which involves visits by a consultant to homes and businesses to assess appliance efficiency, according to PNM spokesman Don Brown. The advisory group includes representatives from environmental and consumer groups, industrial users and state government PNM intends to file an outline of the new program with the PRC in January of next year, Brown said.
Gail Ryba, New Mexico representative for the Southwest Energy Efficiency Project, which has been pushing for these types of programs to be put in place, said SWEEP will participate in the study. "We'll be watching to make sure their efforts are ambitious," she said [Susan Whittington].
Coalition for Clean Affordable Energy
New Mexico Energy, Minerals and Natural Resources Department
Southwest Energy Efficiency Project (SWEEP)
2] WECC Takes on Transmission Expansion Planning DB
Continuing to take on the challenge posed by Western governors and the ad-hoc Western Assessment Group (WAG), WECC is creating a committee that will help the region plan new region-wide affecting transmission projects from an economic standpoint and a so-called 10,000-foot level. A first major meeting about the creation of the Transmission Expansion Planning Policy Committee (TEPPC) was held Feb. 15 in Salt Lake City. More than 100 people were in attendance to find out what the new committee will do and, almost as importantly, what it will not do.
Scott Gutting, chair of WECC's Reliability Policy Issues Committee (RPIC), told the gathered attendees that the day's work, and the work of the RPIC to create the new committee, would result in another process for the Western Interconnection.
"The end product of this is a process," he said to laughter. "A planning process for the whole Western Interconnection that is going to look at transmission planning at the ten-thousand foot level."
After the meeting, Gutting qualified that statement for Prospects. "In the last few years, with the new board, we [board members] have stepped up and taken a lot of responsibility to make sure the old WSCC -- which was criticized -- is more goal oriented." He also made it clear at the meeting that the TEPPC itself could be disbanded after a few years when multiple stakeholder processes are in place around the West.
Another process for transmission planners to go through may sound like an exercise in unnecessary paper shuffling, pencil pushing and bean counting, especially for a transmission system as strapped as the Western Interconnection. But Gutting says that the process needs to be jump started because there has been such a lack of investment in transmission planning since the failure of a viable RTO to form in the West.
He also noted that what the TEPPC is going to do will not be new. Instead, it will be taking over the work done by the Seams Steering Committee-Western Interconnection (SSG-WI).
In June 2005, SSG-WI, an unfunded, volunteer organization charged with facilitating the creation of a seamless Western market, asked WECC to look at the feasibility of taking over its transmission expansion planning database. That database contains information regarding potential transmission projects that would affect the entire Western Interconnection. At the same time, the WAG was forming a similar conclusion that WECC would be the correct home for such efforts.
That group published a white paper which concluded that WECC "is leading the WAG's next steps to address transmission planning and expansion, resource adequacy, and transaction practices."
After creating a Western Interconnection expansion planning database, completing two biennial expansion studies on the entire Interconnection in 2002 and 2003 and developing an open process to look at transmission expansion planning, SSG-WI is now ready to pass the whole kit and caboodle off to WECC, according to Dean Perry who headed up the effort at SSG-WI.
Along with the transfer of the SSG-WI database to WECC, a white paper that has been published outlining the needs and goals of the TEPPC. Gutting said there is funding in the WECC budget for the new committee and plans to designate it as the point of contact for many of the Energy Policy Act of 2005 (EPAct) discussions taking place in the West. Finally, a formal recommendation is being made by the RPIC to the board to adopt the white paper as a guiding document and initial charter for the new committee.
As the TEPPC slowly edges toward official existence, it will perform three main functions to meet the needs of WECC members and non-members who would also have access to the public transmission expansion planning (TEP) database. It will be a repository for project sponsors looking for information on adequacy issues and for those who want to see what neighboring transmission system owners are talking about and planning. It will facilitate a West-wide TEP and will support West-wide TEP analyses and studies. The analyses will be done, at first, only at a broad, region-wide level. Subregional projects will be left to groups overseeing those areas such as the Southwest Area Transmission group (SWAT) and the Rocky Mountain Area Transmission Study (RMATS). The TEPPC could begin to look at sub-regional projects if asked to do so by WECC membership.
Gutting said that none of this has to be a part of permanent process however. "There has been a lack of transmission planning over the past few years in the West," he said in response to questions from Energy Prospects. "This process will jump-start that. In three years, it may not be necessary." He noted that the TEPPC will create "institutional tools that will help the process work for the West."
Almost as important to the attendees of the TEPPC conference as what the TEPPC will do was what the new committee will not do. Gutting laid a lot of minds at ease in Salt Lake City, telling the crowd that the TEPPC will not act as a backstop authority to get any specific transmission project built, nor will it recommend the a track to take between competing project proposals, devise cost allocation criteria, take the initiative on projects or assign transmission rights.
Perry, the former head of TEP at SSG-WI, agreed with this delineation. He sees a need in the West for a neutral organization to take on this analytical work. "Let the marketplace determine when is the right time to build instead of a central planning entity decide what is to be done," he said [Charles Redell].
RPIC page at WECC
3] WY Looks at Expanding WIA Role
A handful of energy-related bills have recently been introduced in the Wyoming State Legislature in a session that started Feb. 13, and one has already been approved and handed over to the state Senate.
Five new bills -- House Bills 61, 105, 129, and 189, and House Joint Resolution 8 -- relate to transmission, tax exemptions for clean coal facilities, low income energy assistance and include an amendment to the state constitution.
House Bill 105 appropriates more than $5.5 million for the low income energy assistance program. If approved, the bill will fund the program at 250 percent above the federal poverty level.
House Bill 61 covers coal value-added facilities-tax exemptions, and would provide "a sales and use tax exemption for new coal gasification or coal liquefaction facilities." The Wyoming House easily passed this bill Feb. 20 with a vote of 48 to 9. It will now go to the Senate. The bill could cost state and local governments as much as $9.3 million to $62.4 million per plant, according to an analysis by the Wyoming Department of Revenue.
The other three bills relate to infrastructure issues, which is one of the hottest topics in Wyoming energy circles. Most of the large transmission projects currently proposed for the West originate in, or are routed through, Wyoming. At the same time, Wyoming's largely untapped wind potential is begging for more transmission capacity.
House Bill 129 expands the purpose of the Wyoming Infrastructure Authority (WIA) to also promote advanced coal technology facilities and advanced energy technology facilities, in addition to its existing mission of expanding transmission infrastructure in Wyoming. This change instructs the WIA to promote generation as well as transmission, electric or not. With Wyoming's energy industry currently focused on making the most of the Powder River Basin's low-sulfur coal supply, Wyoming's legislature seems determined to make the most of its natural resources.
The WIA's executive director Steve Waddington told Energy Prospects, "There has been a lot of discussion over the last six months or so on the advancement of coal technologies, so that Wyoming can take advantage of emerging opportunities, especially on the West coast. The thrust [of H.B. 129] is to ask the Infrastructure Authority to take the lead in Wyoming to support and promote the emergence of these technologies as it relates to electricity generation. There is also a coal liquefaction process that would rely on pipelines, so the Pipeline Authority would take the lead on that. The governor and legislature are moving toward expanding the roles of the two authorities to cover that work." Waddington told Prospects that the bill is expected to pass.
In a related development, the WIA is also considering an opportunity to take advantage of a federal tax credit program that might spur the development of more renewable generation in Wyoming [see "WIA Looking to Help Renewables in WY," Feb. 24, 2006].
The second of the three transmission-related bills is House Bill 189. It would set up an electric transmission infrastructure account within the state's revolving investment fund to be funded with $10 million initially. Those funds can be loaned to "any enterprise proposing the development of any energy transmission project which will employ people within the state, provide services within the state, use resources within the state or otherwise add economic value to natural resources produced in the state," at an interest rate of not more than 4 percent, to be repaid within 10 years.
"The funding that the Infrastructure Authority received last year included $5 million set aside to fund feasibility work on transmission projects," said Waddington. "This would bump that up to $10 million. Those funds are available to the WIA if they make a business case and present it to the five elected officials." The Infrastructure Authority has not yet used any of last year's $5 million. Waddington said the pre-feasibility work WIA has been doing has thus far come out of their $1.6 million operating budget.
The last bill regarding transmission is House Joint Resolution 8, which would amend the Wyoming state Constitution to authorize the state to "engage in works of internal improvement for energy transmission and consumption, without submitting the question of the state's authority to engage in such works to a vote of the people." This would be put on the ballot at the next state general election.
When asked for Waddington's take on Resolution 8, he replied, "This came about primarily because the Pipeline Authority wanted an increase in their bonding authority. That proposal started to raise concern about whether the structure in place for the authorities is constitutional. These resolutions would clear up that uncertainty." The thinking has thus far been that it likely is constitutional because they use loans and not appropriations.
"If it fails, then we would continue to labor under the structure that we already have in place, and there would be some question about whether what we're doing is constitutional or not, but in my mind, it wouldn't stop what we're doing," Waddington said [Timothy McClanahan].
Wyoming Infrastructure Authority
4] Montana, Environmental Groups Challenge EPA on Clean Coal
In mid-February, Montana and a national environmental group filed a case that may have wide ramifications for clean-coal power generation in a federal appeals court in Washington, D.C. The case is challenging the U.S. Environmental Protection Agency's determination that integrated gasification combined-cycle (IGCC) power systems cannot be applied as a "best available control technology" (BACT) for air quality reasons.
An EPA spokesperson in Washington, D.C., said the courts now may challenge the agency's interpretation of the federal Clean Air Act as it relates to BACT generally and IGCC specifically. EPA reiterated that it is a strong supporter of IGCC, and its interpretive letter on the BACT issue does not change that.
The Montana Environmental Information Center and Washington, D.C.,-based Environmental Defense Inc. challenged the EPA interpretation.
While Montana has a proposed 250-MW public sector coal-fired plant that the environmental center would like to see use IGCC, the key point of contention was a letter last December from the EPA's Office of Air Quality, Planning and Standards director in response to a query from a Colorado-based energy consulting firm.
"The question in this instance is whether IGCC results in a redefinition of the basic design or the source if the permittee is proposing to build a super-critical pulverized coal (SCPC) unit," said Stephen D. Page, the EPA director, responding to an inquiry from E3 Consulting LLC. "In this situation, EPA's view is that applying the IGCC technology would fundamentally change the scope of the project and redefine the basic design of the proposed source."
Montana's environmental center jumped on the EPA interpretation of the Clean Air Act, asking the court to reverse it. In a prepared statement issued the day of the legal filing, EPA indicated it would respond in the court case.
"EPA will respond appropriately in due course. EPA supports IGCC and clean coal technology, but under the Clean Air Act, EPA must consider it as an entirely different type of plant, not air pollution control technology that can be added to an existing facility."
"As Montana has more and more coal-fired plants proposed, we have an interest in making sure they use the best technology possible to control their air pollution," said Anne Hedges, program director at the Montana Environmental Information Center, whose joint filing contends that EPA's new position violates the federal Clean Air Act.
In separate but related developments earlier this month, Montana Gov. Brian Schweitzer designated a new state climatology office at the University of Montana to develop policies and programs for mitigating global warming. In addition, Xcel Energy's CEO Richard Kelly told a National Mining Conference in Denver that IGCC is an "untested" technology for which his Colorado-based utility is seeking state and federal funding to build a 300-MW demonstration plant [see "Xcel Aims to Build IGCC Demo Plant in Colorado, Feb. 24. 2006"].
EPA did not comment on clean coal's technological or commercial feasibility in responding to the inquiry from an E3 senior partner, Paul Plath. Instead, the federal agency said it was interpreting the application of BACT when there is a designation that a project was seeking a so-called "prevention of significant deterioration" (PSD) construction permit.
It is the EPA's interpretation that Congress separated production processes, such as IGCC, or combined-cycle natural gas, that produce electricity from available technologies applicable to a particular plant.
Montana is proposing what EPA called a "super-critical pulverized coal" (SCPC) plant that is cleaner than conventional coal-fired generation. It will provide 250 MW to five Montana rural electric co-ops and the city of Great Falls. Southern Montana Electric Generation and Transmission Corp. is set to build the $515-million project.
Although the E3 request to EPA didn't specifically ask about SCPC plants, EPA's Page addressed the subject in his clarification letter, saying IGCC would not be applicable as a BACT for these type units either. "Nonetheless, we believe that the technology should be considered under [parts of the Clean Air Act] when an SCPC unit is proposed in non-attainment areas." [Richard Nemec]
U. S. Environmental Protection Agency
Montana Environmental Information Center
Environmental Defense Inc.
5] Refinery-Waste Power Plant Proposal has Enviros Dreaming
Proponents of renewable energy, clean coal and various efforts aimed at zero-emission power generation might be trying to avoid the proverbial pinch of reality for fear that it will awaken them from a dream after hearing about plans unveiled earlier this month by two energy giants to build a greenhouse gas emissions-free electric generation plant in the heart of Southern California's population center. Petroleum refinery coke is supposed to be converted to a hydrogen gas that will fuel turbines to make electricity in a 500-MW, $1 billion project next to the largest refinery in California.
Infrastructure details are still being worked out, and putting steel in the ground is still years away. Even the project's financial feasibility is still to be determined over the next 18 to 24 months and buyers for the plant's output are nowhere to be found, although the utility affiliate of one of the partners proposing the project could take all of the supplies in one big gulp. If the project proves economically feasible, new power supplies could be produced adjacent to the refinery by 2011.
The sponsors are BP's United States operating unit, BP America; and Edison Mission Group (EMG), Edison International's merchant energy provider and an affiliate to Southern California Edison Co., one of the largest electric utilities in the nation. The location is BP's Carson refinery, about 20 miles south of downtown Los Angeles, and in close proximity to the heavily industrialized areas in and around the combined Long Beach and Los Angeles harbors, which collectively form the busiest port in the nation, and third busiest in the world.
The project would involve a "first-of-its-kind" plant that would use a waste source for fuel and eliminate substantial amounts of carbon dioxide by re-deploying the greenhouse gas that is widely considered to be a leading contributor to global warming. EMG and BP will target completing what the companies described as "detailed engineering/commercial studies" this year. Costs of the proposed hydrogen-powered electric generation system are higher than traditional means of making electricity, so the partners acknowledged they would need to tap federal incentives called for in the 2005 Energy Policy Act (EPAct).
Proponents are touting the project's potential environmental and economic advantages, including 500 MW of new electric supplies in the heart of the Southern California load center; eliminating 4 million tons of carbon dioxide (CO2) annually by sequestering it underground; tapping previously unrecoverable California oil reserves through use of some of the captured CO2; and boosting the local economy with 1,000 construction jobs and 150 permanent operational positions.
Along with the eventual sales contracts, part of the engineering scenarios are how to best connect the innovative new power and sequestered gas sources with sufficient gas and electric infrastructure. Unlike a remote site, the major links are not far away, but they will have to be made in a heavily urbanized area. The logistics likely will not be simple. At the appropriate times, there will be requests for offers (RFOs) and requests for proposals (RFPs) for various phases of what pencils out as a major engineering, economic and regulatory undertaking.
At its formal announcement Feb. 10, the project was lauded by elected officials, regulators and environmentalists. California Gov. Arnold Schwarzenegger said he is convinced the state does not have to "choose between a healthy environment and a healthy economy -- we can have both." He called the proposal an "environmental showpiece" and a "billion-dollar investment" in California's future growth.
While being careful not to endorse the project in keeping with his organization's neutrality on energy projects, David Hawkins, director of the Natural Resources Defense Council's (NRDC's) Climate Center agreed that "in the right locations," projects like the process petroleum coke, gasification and sequestration facility could potentially produce "significant environmental and economic benefits." However, Hawkins also cautioned that the Long Beach area is a "challenging location" for any major new power plant construction, regardless of how advanced and presumably green its technology happens to be.
Using a locally available fuel source and treated waste water, the proposed project would seek to combine several existing industrial processes to provide what the sponsors are calling "a new option for generating electricity without significant CO2 emissions."
Petroleum coke produced at refineries throughout the state will be converted to hydrogen and CO2 gases, with about 90 percent of the latter gas captured and separated. The hydrogen gas would be used to fuel a gas turbine to generate electricity.
"The captured CO2 would be transported by pipeline to an oil field and injected into reservoir rock formations thousands of feet under, both stimulating additional oil production and permanently trapping the CO2," the companies' joint written announcement said. Subsequently, an EMG spokesperson noted that detailed studies of potential oilfields would need to be completed before the potential repository for the CO2 is finally identified.
Both BP and EMG are in discussions with federal, state and local governmental officials, as well as potential buyers of the plant's output. BP is also in discussions with Occidental Petroleum to develop options for the CO2 sequestering in Occidental's extensive California oil fields, which include the former U.S. Strategic Petroleum Reserve at Elk Hills in the central valley northwest of Bakersfield, Calif [Richard Nemec].
Edison Mission Group
6] Nevada Power Launches Aggressive AC Rebate Program
Las Vegas-based Nevada Power Co. is upping its air conditioner rebate program from $2.6 million to $14.5 million, according to a plan approved Feb. 1 by the Public Utilities Commission of Nevada (PUCN). The additional funding will be embedded into the electric bills of Nevada Power's 100,000 customers in southern Nevada.
Thirty-two of Las Vegas Valley's largest home builders are throwing in another $12 million to go exclusively toward high-efficiency air conditioning units installed in the homes they build. According to a Nevada Power spokesman, 90 percent of the new homes built in southern Nevada during the first half of 2006 -- nearly 22,000 -- will have the new high-efficiency units, which translates into 32,000 air conditioning units, thanks to the souped-up rebate program.
Air conditioning units with a 13 seasonal energy efficiency rating (SEER) or better will qualify for the rebate. Nevada Power will be paying a $300 rebate and the home builders will be contributing an additional $300 per unit in the homes they build. The cost will be factored into the price of the home.
Air conditioning units with a 13 SEER -- the new federal standard -- are 30 percent more efficient than most units currently cooling homes in the United States. The cost to install a high-efficiency unit is about $600 more than the cost of installing a unit of average efficiency.
"Multiply that 30 percent in energy savings by 32,000 units, and that's a big deal," said Bob Balzar, Nevada Power's director of energy conservation. "Residential air conditioning accounts for about 40 percent of Nevada Power's summer load, so we pay a lot of attention to it."
Homeowners with failing units who would like to invest in high-efficiency units may also apply for Nevada Power's $300 rebate. Balzar estimates that about 4,000 of its 100,000 customers will take advantage of the rebate in the first half of 2006.
"That's about 5 percent of the retrofit market in southern Nevada," Balzar said.
After June, Nevada Power will no longer be issuing rebates for 13 SEER units, because, according to Balzar, the utility will then view 13 SEER units as the baseline for the region. After June, rebates will be issued only for units having better than a 13 SEER rating. In July, Nevada Power will refile for a revised air conditioner rebate program for 2007 to 2009, and hopes the rebate program will nudge the market toward high-efficiency air conditioning units for the next several years.
Southern Nevada experiences a demand growth of about 6 percent a year, by far the highest in the country. The rebate program will help the utility save about 75 million Kwh per year.
"That's less than 1 percent of the total load in southern Nevada, but it's 1 percent in the right direction," said Balzar.
The rebate program now counts toward Nevada Power's renewables portfolio standard requirements, since Assembly Bill 3, an energy conservation bill passed during a special legislative session during the 2005 Nevada legislative session, allows conservation measures to qualify.
Nevada Power will also be filing an application with the PUCN in March to ramp up its refrigerator recycling program. Currently, Nevada Power has a $500,000 recycling program, but if the PUCN approves its application, an additional $700,000 in potential rebates will also take effect. The utility expects 9,000 customers to participate, saving potentially as many refrigerators from languishing in steamy Nevada garages, where they consume exponentially greater amounts of electricity than they do in air-conditioned kitchens.
The utility will also be requesting from the PUCN an additional $1.2 million for a compact fluorescent lighting program, to be facilitated by retailers, such as Home Depot and Lowe's Home Improvement Centers [Penelope Kern].
Nevada Power's AC Rebate Program
7] Eastern-Based Energy Market Analysts Wear Developer Hats, Too
Edward N. Krapels, a Johns Hopkins Ph.D., who sequentially has analyzed oil, natural gas and most recently wholesale electricity prices, does more than crunch the numbers when it comes to high-voltage transmission investment and development. He is also a founder and developer of independent, for-profit electric transmission projects, the most notable being Atlantic Energy Partners' (AEP's) 680-MW HVDC sub-sea cable transmission project now underway between New Jersey and Long Island.
At the same time, he and colleagues at the market research firm he helped found in Wakefield, Mass., Energy Security Analysis Inc. (ESAI), have established a national transmission collaborative. From their New England perch, they watch developments in the West about as closely as the energy think tanks along the Pacific Coast. Nationally, their work last year for the Edison Electric Institute concluded that there is about $50 billion in new transmission projects needing investment.
With colleague Stephen Conant, Krapels publishes a quarterly report on transmission developments, the most recent one of which concluded that an increased pace of investment in transmission last year was a "natural reaction to the decline in investment in generation," along with what their ESAI report called a "maturation" of independent system operators (ISOs) and regional transmission organizations (RTOs).
Afterward, putting on his other hat -- of entrepreneur and developer -- Krapels sees "opportunities that do exist" for transmission development, despite what he says are ongoing "deficiencies in the market design."
On the regulatory front, Krapels and Conant warn that the ongoing "notice of proposed rulemaking" (NOPR) on transmission investment by the Federal Energy Regulatory Commission (FERC) should not be taken lightly. They see it as historic in importance. The avid market watchers also are waiting and wondering why it is taking so long for a well-designed capacity market to be launched in the U. S. wholesale power sector.
"I am amazed that the 'locational installed capacity' (LICAP) and associated capacity market constructs are not yet in place," says Krapels, founder most recently of Anbaric LLC, an independent electric transmission company and one of five principals earlier founding the firms that created AEP as the developer of Neptune that will begin operations next year with a 20-year contract with Long Island Power Authority (LIPA).
"I was one of the original Atlantic Energy partners and provided market advisory services through the period of development [until construction began last June]," Krapels says. "I continue to have an ownership interest in the project, and from that position have launched Anbaric as a new company that will specialize in transmission development."
Anbaric has identified at least ten potential transmission opportunities for independent developers, including several in the West. Similarly, the "Transmission Collaborative" meeting upcoming in San Francisco, although national in scope, will emphasize as part of its closed sessions a presentation on "Regional Planning in the West," including speakers from the California Independent System Operator (CAISO), the Rocky Mountain Area Transmission Plan on the proposed Frontier Line, and Arizona Public Service Co. on its proposed new regional transmission projects.
In little more than a year, "the collaborative has attracted lots of different folks," says Conant, a former senior consultant for Stone & Webster Management Consultants, where he prepared due-diligence analyses for major power asset transfers, including coal, natural gas and hydroelectric power plants and natural gas transmission lines. The increased interest, he thinks, goes hand-in-hand with the post-August 2003 major power grid outage.
"There is nothing like a crisis to get people's attention," he said. "Historically, the reason we have the North American Electricity Reliability Council (NERC) is the blackout in New York City in 1965."
Both analysts think that transmission needs are best discussed regionally, and the need for major new transmission in the WECC depends "substantially on the desire of consumers and utilities and governments for diverse power portfolios. Projects under discussion in California, Arizona and elsewhere are aimed at expanding the role of wind and 'clean coal' in these states. The only way to do that is to build very large new transmission systems," Krapels says.
Among the crowded field of companies doing energy analysis these days, Conant says ESAI has "always understood that transmission was a very important component of the electric industry, and we've always had a separate publication on transmission -- quarterly and now monthly, too."
Mounting congestion, regulatory changes, dried-up investment in the past, and a growing push for generation from renewable energy sources has turned up the spotlight and the wattage on transmission, Conant says. Thus, he thinks major cross-region transmission lines, such as the Frontier project, eventually will get built.
"But how they are going to come about, I am not sure," Conant adds as a caveat. If history is any guide, consortiums, particularly public-private partnerships may be the preferred mechanism.
Joint venturing and collaboration used to develop naturally when vertically integrated utilities -- both private and public sector -- joined hands to build major power generation facilities, such as the Palo Verde Nuclear Plant south of Phoenix, Ariz. Since many utilities have been severed from the generation part of the business, particularly in developing new plants, Conant thinks the impetus for groups coalescing may have to come from the private developers, such as the companies Ed Krapels has brought together.
The industry is on the verge of becoming more dependent on so-called "Transco's," independent transmission companies, which Conant and Krapels think will grow from their current five or six major firms to 15 or 20 notable firms. While the Transco won't be the dominant entity, they will grow in presence in the years to come, they contend.
If there is going to be a continued interest in diversifying the nation's and region's electricity sources, then policymakers and citizens must be ready to "pay more for transmission," beyond the usual reliability investment, Krapels says [Richard Nemec].
Energy Security Analysis, Inc. (ESAI)
8] Booming in the North and South, Alberta Wires Up
Sandwiched between the demands of booming oil sands development in the north, an explosion of wind interconnection requests in the south, a rapidly growing Calgary economy and an increasing need to import and export electricity, the Alberta Electric System Operator is embarking on Alberta's biggest transmission expansion in nearly 20 years.
While Alberta's generation capacity has increased by more than 30 percent since 1998, there's been no significant new investment in its transmission infrastructure since 1988. Upgrades and additions to Alberta's transmission "backbone" -- the major transmission corridor that runs about 200 miles from the generation-rich north to the power-hungry south -- are currently in the last phases of planning. So are enhancements to the system in the southern part of the province to accommodate burgeoning wind development there. At the same time, the Alberta Electric System Operator (AESO) is also working with oil sands developers and electric generators in the north and looking at projects and proposals addressing Alberta's links with the outside world: namely, its interties with neighboring provinces and an energy-hungry neighbor to the south.
There are six, 240-kV transmission lines, the backbone of Alberta's electric grid, currently running south from Alberta's epicenter of power generation, near Edmonton, to Calgary, the province's primary load center. That backbone, according to the AESO transmission planners, is congested, impeding not only province-wide transmission and distribution, but the ability to import and export electricity to and from British Columbia. To address the problem, AESO filed a "need identification" document with the Alberta Energy and Utilities Board (EUB) last year and got the green light in April 2005 to convert the 240-kV lines to 500-kV lines, to upgrade the Edmonton area substations serving those lines, and to build a new 200-mile, 500-kV line from the Genesee substation west of Edmonton to the Langdon substation east of Calgary.
Calgary-based AltaLink, Alberta's largest transmission provider, which serves more than 85 percent of the province, will be building the lines and upgrading the substations at an approximate cost of $400 million. According to AltaLink and the AESO, the upgrades to existing structures should be completed in 2006, and construction should begin on the new 500-kV line in 2007, with an in-service date of 2009.
AESO also received approval in April 2005 from the EUB to upgrade substations and add transmission lines in the southwest of the province to accommodate the interconnection requests from wind developers and small hydro operations in the region. AltaLink will oversee the $80-million expansion project, which consists of upgrading the Pincher Creek, Peigan and Lethbridge substations, running double-circuit 240-kV transmission lines between the three substations, and running a 138-kV line from Tempest to Stirling. AltaLink is also proposing to run a 20-mile, double-circuit 240-kV line from a proposed substation at Goose Lake to the Peigan substation, located on the Piikani First Nation Reserve.
"The entire southern region is inundated with wind farm interconnection requests, and falling behind is our biggest concern, because then we'd have to curtail interconnections, and that would put an economic damper on development in the province, which would have huge repercussions," said AESO transmission planner Pung Toy.
According to Toy, oil sands development in the northern part of the province is also putting the pinch on Alberta's existing transmission.
"It's been really hard to maintain pace with that development," said Toy. "We didn't anticipate the speed of development in response to oil prices. Now, all the excess transmission capacity has been used up, so we're in need of significant development in that area."
In response to that dilemma, the AESO is currently communicating with the large industries in the region to determine their plans for the next 15 years in order to get an idea of their load and anticipated generation additions. Armed with that information, the AESO can tailor a robust and flexible transmission system to accommodate the region.
The AESO is also engaged in a fact-finding mission in central Alberta, where a lot of heavy oil upgrading capacity is coming online, threatening to put additional strain on the transmission system. According to Toy, the AESO is undecided on whether 240-kV or 500-kV lines will service those two regions, but he emphasizes the "tremendous need" to have Alberta's grid reinforced by 2013 at the latest.
Also on the collective mind of the AESO and private Canadian transmission providers are Alberta's interties to other systems such as those of neighboring provinces Saskatchewan and British Columbia, as well as the United States.
At present, Alberta has a 500-kV AC interconnection with the B.C. grid and a 150-MW DC intertie with Saskatchewan. The B.C. intertie can only be operated at about 60 percent of its 1000-MW capacity, and according to Cliff Monar, AESO's director of strategic of initiatives, Alberta usually doesn't move much power through the B.C. intertie because of restrictions on the Alberta backbone.
"But once we get the congestion solved with the Edmonton-to-Alberta project, that will improve the situation greatly," he said. "Currently, at our peak times, our exports are down to zero, and off-peak it's usually 200, 300, maybe 400 megawatts, so our Department of Energy put out a regulation in 2004 that said part of an efficient market is that you're able to have a free flow of power and commerce between markets, so AESO needed to get the interties back to their rated capacity."
While Monar stresses that the primary problem with the intertie conundrum has its roots in the congested Edmonton-Alberta transmission backbone, he and other AESO representatives do point to transmission projects that are addressing Alberta's links with the United States.
One such planned link between Alberta's grid and the western U.S. grid is in the final planning stages, under the helm of a consortium of private investors, called MATL -- the Montana-Alberta Tie Ltd. MATL is planning to connect Alberta and the United States through a 240-kV, 300-MW capacity transmission line. The merchant line would run 190 miles from Lethbridge, Alberta, to Great Falls, Mont., and would be the third intertie on Alberta's grid. MATL filed for regulatory approval in April 2005 and hopes to begin construction by September of this year, with a projected in-service date of March 2007.
Calgary-based TransCanada Energy has also proposed a transmission link with the U.S., in the form of a 500-kV DC line running from northern Alberta into either the Pacific Northwest or south to Nevada or California. At this time, the finer points of TransCanada's ambitious proposal are still under wraps [Penelope Kern].
9] Desert Rock Coal Plant Gets Water, but Not Tax Relief
The 1,500-MW Desert Rock coal plant that Sithe Global is proposing to construct on Navajo Nation lands in northwestern New Mexico had some momentum building when the Navajo Nation Resources Committee approved a Large Water User Master Agreement for it in February. The agreement with the Dine Power Authority (DPA), the Navajo entity working with Sithe to build the plant, sets the charges for the groundwater the facility will use.
"It's a huge step forward and puts on paper our commitment to working as a good partner with the Navajo Nation," said Frank Maisano, Washington, D.C. representative for Sithe. "Built into the agreement is an ability to monitor environmental conditions and mitigate as necessary. It signals our commitment to the water and the land."
Maisano told Prospects the draft air permit for the project, expected to come out "sometime soon," will set a baseline for the lowest level of emissions for a pulverized coal plant ever issued by EPA, one that "gets you to the level of an IGCC facility" [see "Desert Rock Wants to Push the Emissions Control Envelope," June 24, 2005].
But Desert Rock hit a roadblock in Santa Fe Feb. 16 when the New Mexico legislature failed to approve a $60 million tax credit for the plant. The legislation would have granted an "intergovernmental compensating tax credit" to offset taxes paid to the Navajo Nation. "We'll keep pushing, but if we don't get the tax relief, the economics of the project are negatively impacted," Maisano said.
"We are working to provide a fair and competitive tax structure and get in place a facility that can provide a significant economic boost to the Navajo Nation," he added.
Unemployment is 50 percent in the area where the plant is proposed, said Steven Begay of DPA. Besides jobs, the new facility would add $50 million annually to Navajo Nation revenues, according to Sithe.
Desert Rock is also considered the "anchor plant" that could trigger construction of the 500-kV Navajo Transmission Project, which DPA has proposed to move power from the Four Corners area to Arizona and beyond. At the January meeting of the Southwest Area Transmission (SWAT) group, Bob Smith of Arizona Public Service reported that along with the studies for the TransWest Express [see "APS Sparks Interest in Two 500-kV Lines to Wyoming," Oct. 28, 2005], APS and Sithe/DPA have agreed that APS will do the work needed for the NTP to go through the WECC path rating process. That study will involve Segment 1 of the NTP, which would start near the new coal plant and extend 180 miles west to Page, Ariz., where it could connect to APS transmission lines.
Desert Rock is slated to go online in 2010. Its schedule fits within the time frame Arizona's two largest utilities established for signing up new long-term generation in RFPs issued last month [see "Arizona Thirsts for Thermals and Talks Renewables," Feb. 10, 2006].
"There's a huge hunger for baseload resources between Phoenix and Tucson and Las Vegas and Albuquerque," Maisano said. "The sooner the Desert Rock plant gets going, the sooner the Navajo Nation will realize its benefits. There's a dramatic need for us to produce this power to help electrify the local Navajo authority and meet the Southwest's need for baseload power." [Susan Whittington]
10] Wind Developers Can Have Their Cake and Eat It, Too
On Feb. 6, the U.S. Treasury Department issued a ruling that clarifies potential confusion over whether wind developers may receive state and local tax credits and still qualify for the federal wind energy production tax credit.
The revenue ruling, issued as a public guidance, states that receiving state and local tax credits does not reduce eligibility for the federal wind energy production tax credit (PTC). The Treasury issued the ruling in response to an individual request for clarification of the PTC tax code, but the ruling will be applicable nationwide.
In question was Section 45 of the federal wind energy PTC, which stipulates that the PTC must be reduced by the amount of "any other credit allowable." The Treasury's public guidance states that "The term 'any other credit allowable' ... will be construed to include only federal tax credits ... and not to include state or local credits."
The issue was initially raised in 2003 by San Diego-based Eurus Energy American Corp., a wind developer, when it approached the U.S. Internal Revenue Service about the potential conflict between the receipt of tax credits from the Oregon Business Energy Tax Credit program and the receipt of federal PTCs. The IRS refused to rule on the issue and directed Eurus to seek a public guidance from the Treasury Dept. Eurus did so with the backing of the American Wind Energy Association (AWEA), the Oregon Dept. of Energy and U.S. Sen. Ron Wyden of Oregon.
Previously, Eurus -- as well as other wind developers -- had accepted reduced PTC payments under the assumption that their projects were not fully eligible. According to AWEA spokeswoman Christine Real de Azua, the Treasury's ruling comes as very good news for the wind industry and may encourage states currently without wind development incentives to adopt them.
The public guidance comes on the heels of the U.S. wind industry's most productive year. In 2005, the industry broke earlier records, installing nearly 2,500 MW of in new wind farms in 22 states, boosting the cumulative U.S. installed wind power fleet by more than 35 percent to a total of nearly 9,200 MW. The previous record was set in 2001, when 1,697 MW of new wind farms were installed [Penelope Kern].
Database of State Incentives for Renewable Energy
Office of the Tax Legislative Counsel, U.S. Dept. of the Treasury
11] WIA Looking to Help Renewables in WY
The Wyoming Infrastructure Authority (WIA) released an RFP Feb. 21 looking for renewable power developers interested in using Clean and Renewable Energy Bonds (CREBs) for renewable energy projects within the state. The WIA is hoping to provide funding to "mature" renewable energy projects using CREBs -- a federal incentive program created with the passage of the Energy Policy Act of 2005 (EPAct) last year.
According to Steve Waddington, executive director of the WIA, the authority has no preconceived notions regarding its input or participation in any of the selected projects. They have no goal for the number of projects they will accept or the amount of power that will eventually come out of them. Rather, he said, the WIA sees the CREB program as a valuable opportunity the WIA can use to increase the amount of renewable energy generated in Wyoming.
"We didn't want to let an opportunity slip by without asking the question of the developer community in Wyoming whether applying for bonds as a public entity would add value to their projects," Waddington said.
He told Prospects that while the WIA has few expectations about what types of projects will be accepted, he said that there are a couple of points which will help a developer be successful with an application. Projects should be mature enough to have a realistic chance of being in service in time to collect on the full potential of the issued bonds -- the deadline for that is Jan. 1, 2008. He also noted that those that include transmission investments within the state of Wyoming will be viewed more favorably since the WIA can help with the capital costs of that part of a project as well.
The tax credit bonds issued under the CREB program are essentially an interest-free source of capital. The WIA says that they "could significantly reduce the overall cost of renewable generation projects in Wyoming." The bonds will be issued by the Internal Revenue Service on a project-by-project basis, which is why the WIA is looking for projects now. The deadline for the WIA to apply to the IRS for the bonds is April 26. The deadline for the RFP is March 20 [Charles Redell].
12] Idaho, California Regulators OK PacifiCorp Purchase
Idaho and California became the third and fourth states to sign off on MidAmerican Energy Holding Co.'s bid to acquire PacifiCorp earlier this month. The $9.4-billion deal would transfer ownership of the Portland, Ore.-based utility from ScottishPower.
The Idaho Public Utilities Commission's approval came on Feb. 13, and was followed three days later by the California Public Utility Commission's approval. The votes of both commissions were unanimous.
PacifiCorp does business as Utah Power in Idaho, where its serves 60,000 customers in the southeast portion of the state. In its order, the IPUC commissioners commented that, of the three sale or merger transactions involving Utah Power, the MEHC acquisition had been "the least contentious."
PacifiCorp serves about 1.5 million customers in a territory that includes Utah, Oregon, Washington and Wyoming, as well as Idaho and California. Regulators in Utah and Wyoming gave their approvals in late January [see " Wyoming May Benefit from PacifiCorp Sale," Feb. 10, 2006].
MEHC aims to wrap up the deal by the end of March. Settlements have been made with interveners in Oregon and Washington, the two remaining states yet to approve the deal. Oregon regulators took additional briefs earlier this month addressing the settlement's benefits and provisions for mitigating "harms" arising from the sale, which they said were not clearly articulated.
Washington regulators conducted a hearing Feb. 9, similarly requesting clarification on terms in the settlement reached with the state's stakeholders. Of particular concern were "off-settable rate credits." In setting the meeting, the Utilities and Transportation Commission said that neither the settlement terms nor supporting testimony provided "clear and sufficient explanations of how these provisions will be reflected on PacifiCorp's books and treated for purposes of rates." [Rick Adair]
13] Xcel Aims to Build IGCC Demo Plant in Colorado
Minneapolis-based Xcel Energy is looking to build a coal-fired integrated gasification combined cycle demonstration plant in Colorado within the next few years, and the company is backing proposed Colorado legislation that would pave the way for the endeavor.
Colorado House Bill 1281, the Clean Coal Technology Demo Program bill, would promote "the establishment of a program to demonstrate the use of breakthrough advanced coal technology to promote low-emitting, coal-fueled electricity generation" through public utility cost recovery in connection with such projects, including the costs of feasibility studies, by facilitating state and federal assistance and proposed appropriations in the bill. On Feb. 15, the bill was approved by the House Committee on Transportation and Energy and was passed onto the Appropriations Committee.
House Bill 1322, the Clean Energy Development Fund Seed Capital bill, would "support the development of clean energy resources" by diverting state mining severance taxes to grant upward of $3 million annually to feasibility studies of operating an IGCC plant at altitudes above 4,000 feet, using Western subbituminous coal. On Feb. 8, the bill was introduced into the House and is currently with the House Finance Committee.
In addition to backing the proposed legislation, Xcel is currently looking for partners for the proposed feasibility studies. Construction and operation of the demonstration plant are contingent on the results of the studies.
If things pan out as Xcel hopes and studies indicate that an IGCC plant could operate at altitude using Western coal, Xcel could qualify to receive up to $200 million in federal money to build the demonstration plant. Construction would likely begin sometime in 2008, and the plant would be running by 2011 or 2012.
"At this point, everything hinges on the results of the study," said Xcel spokesman Tom Henley. Henley added that the plant would generate at least 300 MW and would cost between $500 million and $1 billion, and would employ carbon dioxide sequestration, possibly in the oil or natural gas fields in eastern Colorado [Penelope Kern].
Colorado General Assembly Home Page
14] Wyoming Wind Winds Up
Teton Power Holdings, LLC applied in January for permission to build a wind farm in southwest Wyoming. Sweetwater County officials were unprepared for such an application, however, and had to scramble to develop emergency rules for commercial wind farms which they've not had to address before.
The project would see the construction of 133 turbines in the 2 MW to 2.5 MW range on a privately-owned site on White Mountain, between Rock Springs and Green River. Mark Kot, Sweetwater County development supervisor, said, "What we're trying to do is put together balanced regulations that allow for wind energy development so we can contribute to the energy demands of the country and also balance the needs of the community." Kot said the county is at the very beginning of commercial wind farm development.
Kot told Prospects that emergency regulations were put in place Feb. 21, and address such concerns as environmental issues, as well as visual, historical, archaeological and cultural effects. The emergency rules are in effect for 120 days, with a 120-day extension possible under Wyoming statues. Kot said the emergency rules only cover commercial wind farms, but when the permanent regulations are created, they will also address private wind farms. Since the emergency rules weren't in place at the time of their application, Teton Power voluntarily withdrew their application until such rules were put into place, but haven't yet reapplied under the emergency rules.
The emergency rules were quickly put together by a seven-member committee, said Kot, made up of people representing environmental concerns, local business owners, wind industry and others.
Officials in other Wyoming counties have been caught off guard by the escalating interest in wind power. FPL Energy Inc. and Florida Power Inc., for example, opened a 144-MW 80-turbine wind farm in Uinta County in southwest Wyoming. Uinta County planner Kent Williams said, "We never really thought about wind development until [the FPL Energy] project."
This problem is something that will likely be repeated in the future if some of the state's proposed transmission projects come online. The Wyoming Infrastructure Authority is working on expanding transmission in the state, which will help provide access to Wyoming's vast untapped wind potential. Some of the projects the Infrastructure Authority is helping along are the TOT3 expansion and the TransWest Express project, connecting Wyoming with Colorado and Arizona, respectively [Timothy McClanahan].
15] Ground Breaks for 64-MW CSP Project in Nevada
A Feb. 11 groundbreaking launched construction of a Nevada concentrating-solar plant that will become one of the world's largest sources of solar power. It will also help the state's largest utilities meet their renewables portfolio standards.
Dubbed Nevada Solar One, the 64-MW-capacity venture in Boulder City will be the first of its kind built in the past 15 years, according to Gary Bailey, Western area manager for project developer Solargenix Energy.
"It's like starting an industry over again," he told Energy Prospects.
His company's basic concept is identical to 354 MW of parabolic-trough plants developed in the California desert from 1984 to 1991, collectively known as the Kramer Junction Solar Electricity Generating Systems.
In this form of solar power, tracking mirrors concentrate sunlight on receiver tubes containing oil. The oil heats to temperatures higher than 750 degrees, and heat exchangers generate steam to drive a turbine to create electricity.
"What we've done is expand the efficiencies of it," said Bailey, through operational and structural advances from the earlier projects.
He declined to share cost information, but said the facility would generate power at about half the per-unit cost of solar photovoltaics.
Nevada Solar One is scheduled for completion by March 2007. All its generated electricity will be delivered to Nevada Power and Sierra Pacific Power under amended 20-year power-purchase agreements approved by state regulators in 2005. Bailey said this will fulfill for both investor owned utilities for three years the 5-percent annual solar requirement in the overall renewables component of Nevada's RPS. Both utilities fell short of RPS targets in 2003 and 2004, as planned renewables projects were delayed or shelved for a variety of reasons [see, "Nevada's Lofty RPS Goals Fail to Materialize," June 10, 2005]. Bailey said the utilities' financial woes slowed his company's project, until the subsequent creation of the state Temporary Renewable Energy Development (TRED) program.
In July Solargenix received state approval for about $15 million in sales and property tax breaks [see, "Solargenix Energy Gets Tax Cut for 65 MW Thermal Plant," July 22, 2005].
Nevada Solar One will occupy part of a 3,000-acre solar energy park on municipally owned land in Boulder City, about 20 miles southeast of Las Vegas. Solargenix could eventually expand to 500 MW on the site, Bailey said. His firm hopes to land additional solar contracts from the Nevada utilities, and sell to other prospective utility buyers in California and the Southwest [Mark Ohrenschall; Garrett Hering and Rich Nemec also contributed to this article].