[Yesterday’s post discussed how FERC failed to implement the siting authority granted in the Energy Policy Act of 2005 and examined a case study about why it failed. Part II looks at Obama’s “green power” superhighway, the recent work by regional transmission planning organizations to bring renewable energy to market, and the extremely high costs to do so.]
Public policy has long supported the ability to construct new transmission lines that relieve congestion and reduce the cost of energy to consumers. However, it is another question entirely to construct a new “green” coast-to-coast transmission corridor given the mess our transmission system is in today and its prohibitive cost. Critics have complaint that it is throwing good (transmission) money at bad (renewable) generation money.
Slowly, regional system operators are resolving transmission bottlenecks and improving the smooth flow of energy in their service territories. The good news is that virtually all of the most important regional projects are likely to be in-service well before our Washington representatives will complete their transmission siting authority “power grab” (not that it will change their game plan). Also, regional transmission planning organizations are actively promoting and siting transmission lines. The regional system is working and they don’t need FERC or congress to help to fix it.
The local siting processes are working (regardless of how you feel about siting renewables-only transmission lines) but the costs for constructing this transmission is extremely expensive per unit of energy generated given the periodicity of the output from wind and solar power installations. Costs of constructing new transmission for renewable projects can easily equal a quarter of the cost of building the generation alone. In ERCOT, the price is over $2 million per mile to bring renewable energy into the existing grid and will add at least 5 cents/kWh for the transmission portion of the cost of renewable electricity alone—more than double the cost of electricity from our existing fleet of nuclear power plants and 60% more than the cost of coal-fired electricity at the busbar. The Western Interconnect planning process is currently identifying likely renewable sites and looking at transmission line corridors.
FERC: Try, Try Again
In Part I we discussed how federal siting authority of new transmission lines was granted under the Energy Policy Act of 2005 (EPAct) yet FERC’s implementation of that authority failed judicial scrutiny. In addition, the case study presented concerning adding an interconnection between Southern California and Arizona clearly shows that there are many other issues that must be considered when establishing the need for FERC to intercede on behalf of one state or another. In my mind, the most significant issue, and the Arizona Corporation Commission agrees, is that a state must completely exercise their ability to construct local power generation facilities before attempting to cross connect to an adjacent state. Merely needing the power is no reason for the federal government to exercise its eminent domain powers when there is an unwillingness to construct new plants.
Today, we now hear the next stanza to this same tired tune. We continue to be told that a complete overhaul of the U.S. power delivery system is required but now the grid updates must also accommodate the higher levels of renewable energy expected to be generated over the next decade. Senator Harry Reid (D-NV) gave us a look at our future when, at a conference in February hosted by the Center for American Progress Action Fund, a group organized by John Podesta, proclaimed, “My legislation (referring to another round of legislation he promised to introduce that will speed approvals of transmission lines) will require the president to designate renewable energy zones with significant clean energy-generating potential.” Reid went on to explain that the federal government should be given the authority, through FERC, to overrule state and local governments that slow the development of Obama’s promised 3,000 miles of new interstate transmission lines.
The proposed legislation would also provide FERC the power of eminent domain should states be unwilling to yield to the inevitable pressure from Washington to approve the plans. “We cannot let 231 state regulators hold up progress,” Reid said. “They should be given every opportunity to see if we can work this out through the state regulators. If that can’t be done I think there are very few alternatives for the American people,” other than eminent domain. But any delays or obstacles would be quickly settled, Reid said. “Whatever we pass at the federal level trumps all that,” he said.
John Podesta, president of the Center for American Progress, said a stronger federal siting authority is needed, given that the 4th U.S. Circuit Court of Appeals ruled that FERC’s interpretation of its backstop siting authority under the 2005 energy bill was too expansive.
“It’s time to get back to the table and find a way so that states and regions can plan for the transmission that they need but that the federal government has a role to play to make sure that gets done,” Podesta said.
Reid has yet to provide any details of his proposed bill but a legislative aid said the bill would contain four main components: an interregional planning component, federal siting authority, a national cost allocation plan and a requirement that any generation that connects to the grid meet “green” standards. The four parts appear very similar to a plan produced by the Energy Future Coalition and the Center for American Progress.
Thankfully, Reid’s proposed legislation has yet to see the light of day given the extraordinary costs involved with constructing new national interstate transmission lines. For example, grid operators in the eastern half of the U.S. earlier released in August a study estimating that more than $80 billion in new transmission infrastructure would be needed to get 20% percent of the region’s electricity from wind generation by 2024.
Does Siting need Fixing?
The Federal Energy Regulatory Commission (FERC) recognizes the challenges posed by bringing electrons from new and disparately located renewable energy sources to population centers. In late May, FERC announced a series of transmission planning meetings that will focus on “wider integration of regional energy resources into the nation’s power grid.” In essence, renewable energy generation, principally wind energy, is located where the transmission infrastructure does not exist, and other distributed energy resources are located in transmission-constrained regions.
According to FERC Chairman Jon Wellinghoff, “Planning is one of the three legs on the transmission policy stool—the others are siting and cost allocation—and all are crucial to meeting the goals of assimilating demand resources, renewable energy and distributed generation into the grid for the benefit of consumers.” Here we go again.
From Market Pull to Product Push
Historically, electric utilities dictated when, where, and how much new generation would be added. Their integrated resource plans (IRP) determined the timing of plant additions, the fuel sources, and the location of the new generation resources. Transmission planners followed the lead of utilities to route the necessary transmission capacity while also seeking to lessen area congestion, if necessary. Traditionally, new power generation resources—and, by extension, new transmission—responded to a market pull: predicted load demand. The role of the state and local governments was oversight, providing access to transmission, and setting rates.
In contrast, renewable mandates have upended the traditional approach to developing an IRP. Rather than anticipated customer demand driving generation and transmission decisions, government mandates are now in the driver’s seat. Twenty-nine states and the District of Columbia have a renewable portfolio standard that requires utilities in those states to supply some percentage of renewable electricity by a date certain.
For instance, the California Public Utility Commission requires that 33% of that state’s power originate from renewable energy sources by 2020. In order to achieve this extraordinary goal, all new power generation procured by the state’s utilities must come from renewable energy sources. In this new world, the “pull” of market demand has been supplanted by a government-mandated “technology push” that determines which renewable developers pushing new power into the system in response to state-mandated levels of renewable power have access to limited transmission infrastructure.
One of the other challenges to building new transmission capacity to move renewable energy long distances that was discussed by Wellinghoff is identifying acceptable siting locations for renewable energy facilities. In spite of FERC’s interest is being part of that decision process, much progress has been made at the local level that makes FERC irrelevant in siting transmission lines in practice.
Transmission Planning Out West
One important initiative toward this goal in the Western Interconnection is the Western Governor’s Association’s (WGA) Western Renewable Energy Zones (WREZ) study. In the WREZ study—which covers 11 western states, two Canadian provinces, and areas of Mexico that are part of the Western Interconnection—as many as 50 zones with substantial renewable resources are in the process of being identified so that renewable projects can be expedited and transmission projects can be planned in advance.
The ultimate goal of the WGA is to “develop 30,000 MW of clean and diversified energy by 2015.” The approach used by WGA is to first identify regions with high potential for generating renewable energy—solar, wind, geothermal, etc by involving all the relevant stakeholders. The results of these studies in turn drive transmission planning.
The most recent draft map from the Western Governor’s Association illustrates Qualified Resource Areas as those areas with a high density of developable renewable energy resources after screening for known technical and environmental limitations for which data are available. These data will be used to determine Western Renewable Energy Zones (WREZ) in the Western Interconnection.
The state with the largest installed wind power capacity has already identified Competitive Renewable Energy Zones (CREZ) within the ERCOT Interconnection. In March, the Texas PUC assigned approximately $5 billion of transmission projects to be constructed in these CREZ that will eventually transmit 18,456 MW of wind power over more than 2,300 miles of new transmission lines from power-heavy West Texas and the Panhandle to highly populated metropolitan areas of the state. To put the magnitude of these numbers into perspective, the cost of transmission is over $2,000,000 per mile or over $270/kW of installed capacity.
The regulatory body expects that the new lines will be in service within four or five years. The Texas PUC took about three years to select the most productive wind zones in the state, designate them as CREZ, and devise a transmission plan to move power generated from those zones to various populated areas in the state. Many of these new transmission projects will begin construction later this year.
As an aside, T. Boone Pickens’ investment in his now delayed plan to build 1,000 MW of wind power in the Texas panhandle is in jeopardy. The ERCOT transmission plans do not extend the wires far enough into the Panhandle to reach Pickens’ projects. Pickens now has 687 wind turbines available that cost him a cool $2 billion that he hopes to recycle on a number of smaller projects in the U.S. and Canada. That’s a lot of wind turbines.
The Cost of New Transmission Is Substantial
More insidious are unpredictable transmission costs. Power sellers, buyers, and investors adamantly want price certainty in the total delivered cost. However, congestion charges can make the delivered price vary, especially in locational marginal pricing.
Everyone wants to know the answer to the question: What is the added premium to deliver renewable energy? Many transmission networks have both fossil fuel and renewable generators sharing the same network. Certainly, intermittent renewable sources have higher system-integration costs. Load balancing is more involved as well.
A recent Lawrence Berkeley National Laboratory study may provide an early answer to the cost question. Lawrence Berkeley National Laboratory (LBNL) recently issued a research report that examines the expected costs for new transmission infrastructure that would be needed to support an accelerated program for renewable energy projects, particularly wind energy. The report, “The Cost of Transmission for Wind Energy: A Review of Transmission Planning Studies” was released in February 2009. (A copy of the report can be downloaded at http://eetd.lbl.gov/ea/ems/reports/lbnl-1471e.pdf.)
The authors’ objectives in preparing this report were threefold: to define the transmission costs for a rapidly growing wind power industry, to discuss different transmission planning approaches, and to examine the models used to estimate future wind deployment. Our interest is this article is to focus on the transmission cost estimates prepared by LBNL.
The cost estimates are based on a review of 40 transmission planning studies completed between 2001 and 2008 by various developers, independent system operators/regional transmission operators, state agencies, and individual utilities. There is a wide range in transmission costs, although the costs are generally less than $500/kW. The cost of the median study scenario was $300/kW, or about 15% to 23% of the typical installed cost of a wind turbine plant. These numbers are quite consistent with the $270/kW from ERCOT discussed above.
The authors also concluded that variation in the study methodologies used in these 40 transmission siting studies and the characteristics of the specific grid may affect transmission installation costs (see table). Depending on the original purpose of the transmission line under study (whether it was congestion or deliverability focused), the authors concluded that the purpose affected the costs of adding wind energy to the mix.
Estimated Installed Cost of Wind Transmission Based on Three Higher-Level Studies of Wind Transmission. Source: LBNL
Wind Capacity; Unit Cost of Transmission for Wind Power; 10% Wind Energy by 2030 (AEP 765 kV Overlay Study)
200-400 GW @ $150-$300/kW
20% Wind Energy by 2030: Wind Deployment System
290 GW @ $207/kW
Annual Energy Outlook 2008 Projections for 2030: National Energy Modeling System
40 GW @ $450/kW consisting of $316/kW for transmission and $133/kW for “long-term” multipliers
The study also reviewed three high-level wind transmission–only studies, as shown in the table above. These costs are generally consistent with the median cost identified in the original study sample of $500/kW, or about 25% of the $2,000/kW cost of constructing a new wind project.
The study also concluded that the historic cost of transmission was in the range of $35/MWh to $79/MWh with an average of $45/MWh. Using reasonable economic assumptions on the ERCOT transmission projects and a 33% capacity factor, the transmission lines add about $50/MWh to the price of power generated by the wind projects. For perspective, existing nuclear plants as an industry deliver power to the grid at less than $20/MWh and coal plants are in the range of $30 MWh.
Another Approach: Requiring Backup Power
Nevertheless, renewables do add additional costs to the whole system. For instance, speedy ramp-up of backup power is essential when a wind farm goes down with as little as one-hour warning. Reliability issues kick in as well.
For example, an ERCOT report concluded that only 8.7% of historic wind generation was produced during peak power hours limiting its effectiveness in trimming system peak demand.
Someplace in the delivery chain this intermittency of energy production versus load demand must be smoothed out. Utilities traditionally have taken on this burden themselves. Typically, a utility backfills wind/solar gaps with gas-fired plants to make up for any shortfall in energy production based on a number of factors, including the season, weather, and the region’s operating experience. Using the same approach with very remote wind and solar farms isn’t as straightforward. To do so would make the entire long-distance energy delivery chain, in effect, run intermittently—if the remediating, balancing measures are not applied.
A more recent procurement practice is for the electric utility to insist that the renewable producer directly supply steady, baseload-style power. In particular the utility expects the renewable power producer to have its own storage or natural gas backups. An example would be Xcel Energy’s April 2009 request for proposal for 600 MW of solar thermal that is “fortified” in this way.
Central planning based on temporary political majorities–or, dare one say, ‘political whim’–is not a viable long-term electricity policy. Free-market incentives to expand and build are preferable, and do not expect a 3,000-mile ‘green’ superhighway as a result.
— Also contributing to this article was Sonal Patel, POWER senior writer, and Martin Piszczalski (Ph.D), an industry analyst with Sextant Research