CSP – is it time? Coverage of CSP Today's CSP Project Development USA Conference
Amid optimistic announcements for gigawatts of CSP installations over the next few years, stage whispers of the barriers this industry continues to face continue. At CSP Today’s Project Development conference held in Denver on October 25 and 26, Stephen Mullennix, Partner at U.S. Renewables Group, a renewable energy investment firm, said, “From the capital market perspective, CSP is at a critical point. Currently there is a 7.7 GW project pipeline, if the industry does not execute on it, capital markets will walk away."
Wow, them’s fighting words. Truthfully, CSP faces daunting barriers and these cannot be trivialized. In a morning session, How is America’s CSP Gold Rush likely to pan out? – John White, executive director of the Center for Energy Efficiency and Renewable Technologies, CEERT, began his presentation by noting that the holy trinity of barriers for multi-megawatt projects are permitting, transmission and financing.
Permitting in California can be a challenge, particularly for CSP. Mr. White presented a map showing a significant area of the southwest U.S. is ideal for CSP and for PV. He then pointed out that other interests have already claimed most of this territory. Examples of acreage that is unavailable for solar projects include 4.8 million acres held for the desert tortoise, 3.3 million acres for the defense department, 1.7 million acres for the Mojave ground squirrel, ~1 million acres held for national monuments, and 0.7 million acres for off road vehicles (ORF). Locating multi-megawatt projects remains a challenge once viable land is found, for example, projects on I10 in California have to run a gauntlet of approvals including those for transmission, utilities and FERC.
Permitting remains a significant challenge to CSP project development. Along with permitting, challenges include wildlife habitat protection, developer acquisition of a habitat, water concerns, competing land uses and local government entitlement fees. Dry cooling technology may solve the water issue; however, use of drying cooling has made projects more expensive. In an industry with downward price/cost pressure, additional costs can have a chilling effect on a project.
Problems with transmission and interconnection can, and have, led to project demise. FERC policies and tariffs can prove a difficult hurdle, and, a faster approval time would help project success.
Following Mr. White’s opening presentation; he joined a panel to discuss the challenges facing CSP projects in the U.S. Other panel members were Scott Frier, COO, Abengoa Solar, Albert Fong, Chief Engineering Officer, Albiasa Solar, Stephen Mullennix, Partner, U.S. Renewables Group and Udi Helman, Principal Economist, California ISO. Insights from the panel included:
- From Mr. Mullennix, U.S. Renewables Group: From the capital market perspective, CSP is at a critical point. With a ~7.7-GW pipeline, if the industry does not execute at a high level the capital markets may well walk away.
- From Mr. Helman, California ISO: Regarding integrating solar into system operations and into the economic dispatch, the challenge is the ramp up of solar in the morning and ramp down in the evening. When the system has too much non-dispatchable energy sources on line, how do you manage it and who do you back down? You can back natural gas, but how do you back down inflexible sources? Storage of course would help mitigate, but how do you value it? There is a lot of natural gas in California and a lot will be pushed off the system by renewables. Back to storage, the value is not currently apparent for the next ~five years, but, this will change in a 33% RPS world.
- From Scott Frier, Abengoa: Financing is the biggest challenge in moving projects forward – it is where the rubber meets the road. The Federal Loan Guarantee program is almost a game of brinksmanship in that you have to prove that you have transmission, permitting and off-taking. There is not enough commercial debt available to allow projects to meet deadlines, without the Federal loan guarantee a project might be dead. We might see a resurgence of smaller footprint projects (~20 MW) because of the cost of getting 250 MW projects off of the ground.
- From Mr. Mullennix, U.S. Renewables Group: The DoE is currently determining winners and losers in terms of projects. Initially the loan guarantee program was Plan B, not it is Plan A and you often cannot get financing without it.
Following the panel, Frank Wilkins, CSP Team Leader with the DoE Solar Energy Technologies program offered some insights on barriers for CSP. Mr. Wilkins broke the barriers into three categories:
- Cost – without incentives the cost is too high;
- Finance – currently banks are reluctant; and
- Environment – land issues are improving.
Land and water are other concerns facing CSP, but transmission is the elephant in the room. Clustering projects might ease transmission issues. Mr. Wilkins said that, given the nature of the industry, with CSP the projects must be built to take advantage of learning for future projects.
Regarding land, CSP requires ~1 square mile of land per 100 MW. Currently 119 million acres of land in the Southwest United States is managed by the BLM.
The water issue could potentially be mitigated with dry cooling, which is currently being investigated. According to Mr. Wilkins, wet cooling uses 700 to 900 gallons of water per MWh, while dry cooling uses 70 to 90 gallons/MWh. Mirror washing and steam cycle cleaning use 50 gallons/MWh.
In the session, Understanding your Customers, David Hicks, Development Director, Renewable Energy for NV Energy, offered insights into Nevada’s RPS, means to reach it and the state’s transmission. NV Energy is the parent company for Nevada Power and Sierra Pacific Power.
The One Nevada Transmission line was approved in 2010. This 500 kV transmission line built at a cost of US$510 billion with Great Basin Transmission, an affiliate of New York-based grid developer LS Power will be in operation by the end of 2012 and will integrate the utility’s subsidiaries Nevada Power and Sierra Pacific Power.
Concerning Nevada’s RPS, it requires 20% of generation by renewables by 2015 and 25% by 2025. Up to 25% of the RPS requirement can be met by energy efficiency and conservation. Nevada’s RPS law allows for a REC multiplier of 2.4 x 1 REC for self consumption towards retiring the state’s RPS. California is the primary customer for electricity from Nevada installations. Regarding RECs, NV energy gets the RECs.
Mr. Hicks noted that the PPA price a utility is willing to pay is lower than the 13.2 cents/kWh paid to NextLight two years ago. Though Mr. Hicks referred to the fire sale on PV, he did not directly reference the current acceptable PPA price. He noted that multi-megawatt systems must pass muster with the PUC and must be financeable
Mr. Hicks noted that currently the PV variability is of concern, noting an 80% energy loss with cloud disturbance. Mr. Hicks noted that there is no way to ameliorate this, though it is somewhat mitigated with geographically diverse installations. Mr. Hicks concluded his paper with the following points:
- The Federal Loan Guarantee and financing are inexorably linked and without the loan guarantee financing is unlikely
- Loss of the ITC as a grant will have a very bad effect on future projects
- Storage is becoming increasingly important to NV Energy
- PV intermittency is becoming a bigger problem
Scott Frier, COO Abengoa Solar, reiterated crucial points while presenting a case study, The Inside View on Successfully Selling Power. Mr. Frier began by noting a growing level of PPA failures and concerns over which PPAs are financeable. He noted that the financeable PPAs are coming from utilities. Mr. Frier made the point that who you are and what you do matters in terms of financing. Concerning future project sizes, Mr. Frier said that the jury is out until the financial markets recover. Mr. Frier concluded by saying that transmission is mission critical – no transmission, no project.
During a session titled Site Selection Challenges: How to avoid the most common issues, Dr. Tom Stoffel, Manager, NREL, said that NREL is still working on what the solar variability really is, and that DNI is very difficult to measure and model. Currently for PV, NREL is being asked about the 1-second variability of the solar resource. Turning to slope, Dr. Stoffel said that the ideal slope for CSP is 1% to 3%.
Continuing on the subject of site selection, Tyler Kropf, Land Advisor, Ashwill Associates, noted that for CSP the size, shape and configuration of the site is crucial, and that project developers should assume 6 to 8 acres per MW, with storage a factor in significantly increasing necessary acreage. For CSP, a square or rectangular lot is preferred. Points of consideration when choosing a site include:
• Proximity to substation, transmission or distribution (to mitigate power loss because of distance to delivery point)
• DNI (6.5)
• Flood maps
• Flatter slopped land (<3%)
• Environmental concerns
• Try to stay away from public lands and choose private to mitigate permit waiting times
When conducting due diligence the following are significant:
• Title, and authority to sell
• Higher level and independent environmental studies
• Water rights, adjudicated versus municipal rights
• Mineral rights
• Access issues, dedicated roads and/or easements (do not assume that a dirt road suffices)
During his presentation, Assessing the Usability of the Site, Eric Flodine, Vice President of Community Planning for Strata Equity, reiterated the importance of understand (un-cloud) the title to the property. He advised project developers to ensure that the title and escrow companies are one and the same. Mr. Flodine noted that flexibility in the agreement structure is important; examples are purchase/option to purchase, lease/option to lease, joint venture and joint development agreement.
The permitting process can offer hurdles to curdle the blood and test the resolve of multi-megawatt project developers. Discussing the permitting process when using public lands, Helen Hankins, State Director, BLM Colorado noted the following as crucial to speeding up the BLM permitting process:
• In 2008 the BLM and the DoE began work on the Programmatic EIS (PEIS), the draft of this study will be available in Q1 2011, but essentially will identify 23-million acres with development potential
• President Obama’s goal of 10% energy production by 2012
• January 2009 Secretarial order 3823 that encouraged permitting of renewable energy projects on public lands
• Also in January, the BLM designated 6000 miles for an energy transmission corridor on public lands
• March 2009 Secretarial order 3825 establishing energy zones and fast tracking of large scale projects
State Director Hankins said that when evaluating projects, the BLM looks at technology, load, generation and transmission, and is required to complete an environmental review that focuses on environment, impacts to land and water and social concerns. In general, states have responsibility for ground water issues. A public engagement is required during the approval process, which includes scoping, comments on the draft decision and the opportunity to challenge the decision. The BLM prefers that private lands and disturbed public lands are used for projects instead of untouched public land.
In a session titled Grassroots partnerships, Helen O’Shea, Deputy Director Western Renewable Energy Project, Natural Resources Defense Council, noted that California is “ground zero” for renewable project development in that it either installs the systems or buys the electricity. Regarding project development, Deputy Director O’Shea said that early screening and public participation are crucial to project success. A stringent environmental review and permitting process is important to eliminate speculative applications, provide interagency coordination, document consistency and quality, monitoring, best management practices, standardization of terms and conditions. Deputy Director O’Shea noted that challenging time lines have led to inconsistent documents. She noted that mitigation can be costly for the project developer, and early stakeholder involvement would serve (in many cases) to avoid future problems.
Abraham Breehey, Director of Legislative Affairs, International Brotherhood of Boilermakers, offered a view of how the solar industry can partner with labor unions. In sum, the union urges project developers to consider signing a project labor agreement (PLA). A project labor agreement requires contractors (whether unionized or not) to sign what is essentially a collective bargaining agreement.
Albert Fong, Managing Director, Albiasa Solar, offered some insights during his presentation: Land Acquisition on Private and BLM Land. Mr. Fong offered the following private land designations:
- Municipality held sites
- City owned
Stating that there are major differences between using public and private lands, and that in his view, private land is cheaper and faster, Mr. Fong offered the following examples of the differences:
- The type of permits required
- Applicability of section 10 of the Endangered Species Act
- NEPA (National Environmental Policy)
- MBTA (Migratory Bird Treaty Act
- FAA (Federal Aviation Administration)
Mr. Fong noted that public land permitting can take a long time, up to five years, while permitting on private lands can take 12 to 18 months. On public lands road access may have to be constructed before the project can begin. A disadvantage to using private land is that the permitting process varies from county to county and city to city.
Commentary and Analysis
Multi-megawatt projects for both CSP and PV face non-trivial hurdle going forward, as amply demonstrated during this useful and informative conference.
For CSP, however, the time to prove its future efficacy is now. Should the CSP industry begin to execute on its significant pipeline it will begin to capture share from the PV Industry in the U.S. for these large projects.
Significantly, however, the transmission issue, which looms as a problem for all renewables, along with the cost of storage (important to utilities to mitigate variability) could stall progress. Concerning transmission, the governments of Nevada and Arizona are concerned about building transmission to serve the California market, bringing up the issue of who should pay for it. CSP project developers face a daunting set of barriers that must be overcome before building can begin.
A CSP forecast can only logically be constructed from a combination of announcements and actual construction starts. It takes ~2 years to build a plant once construction starts. Remembering that announcements are not data, you must track the announcement to the construction start and forecast from there. Annual growth rates will be misleading for this industry, and CAGR an unreliable tool.
Posted 01/11/2010 by Paula Mints
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