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Cash for Clunkers Extension Takes $2 Billion from DOE Loan Guarantee Program

With a flurry of last-minute sales, the federal government's Car Allowance Rebate System (aka "CARS" aka "Cash for Clunkers") program ended last Tuesday at 8 PM.  A late extension gave dealers an extra day to file the necessary paperwork, but it was the earlier, $2 billion extension of the program that caught our eye.  CARS (a clever, underused acronym, so we'll use it here) initially received a $1 billion appropriation under the ARRA, but the program proved so popular with consumers and beleagured auto dealers and manufacturers that those funds were used up after just a week. Congress gave the program an additional $2 billion that lasted until this past Tuesday.

Many news reports neglected to mention the source of the additional $2 billion in funding: the ARRA's $6.5 billion appropriation for loan guarantees to fund renewable energy and transmission projects.  Though renewable energy advocates were assured the money will be restored, Congress can be forgiven for redirecting ARRA money toward efforts that have a more immediate stimulus effect.  Earth2Tech suggests that CARS may offer a model for other cleantech initiatives: create a small but popular/successful government program then use that success/popularity to push for additional appropriations later.  The Department of Energy's loan guarantee program offers another, perhaps more familiar model: create a small and by most accounts unsuccessful program and then deliver a massive additional appropriation alongside an aggressive effort at reform.  (The DOE loan guarantee program was created by the Energy Policy Act of 2005 but didn't offer its first loan guarantee--to solar panel manufacturer Solyndra--until March of this year.) If the program can show that it can effectively issue guarantees and encourage energy development, Congress may be more easily persuaded to restore the pilfered funds.

Recent proposed changes could help that happen.  On August 6, the DOE issued proposed regulations that would remove the requirement in the existing program's rules that the DOE receive a first lien position on all project assets of any loan guarantee recipient. Many potential applicants were disappointed that the first round of ARRA-funded loan guarantee solicitations retained the existing program's rules, including the first lien requirement. Often, large projects involve other owners and sources of financing who would expect to share, pari passu, any collateral used to secure the project's debt.  These new changes, if approved, will allow for more flexible lending arrangements, and hopefully, more financing for renewable energy and transmission projects through the loan guarantee program.

Long Term PPA’s: Avoiding Déjà vu All Over Again

A significant key to financing a renewable energy project is an offtake agreement.  If a developer starts explaining to lenders the concept of “bidding zero” into the wholesale market and being a “price taker” resource, the lenders will go into shutdown mode pretty quickly (that’s especially true in New England today, where the market clearing price is linked to natural gas prices which are at a seven year low).  In these tight credit markets, lenders want to see a steady and predictable revenue stream coming into the project from a creditworthy counterparty. 

So what is a project developer to do?  ARRA-related incentives and state programs only go so far, and they simply aren’t geared toward providing long-term stable revenue streams.  Developers need someone willing in this economy to sign up for a 10-20 year contract to take renewable (and variable) resource at a rate that may not be attractive today, let alone just a few years from now.  Any takers . . . ?  Anyone . . . ?

As we’ve noted previously, to address this issue, states have returned to a familiar idea: require the state’s utilities to enter into long-term contracts with the developers.  After all, the utilities are serving load either as a vertically integrated utility or, if the state has restructured its electric industry, then the utility likely has a standard offer or default service that it provides to consumers.  A fine idea, conceptually.  But let’s remember where we’ve been recently and try to avoid going back there. 

Do PURPA, state mini-PURPAs and the avoided cost debacle ring any bells?  Back in the late 70’s, while the US was in the throes of an earlier energy crisis, vertically integrated utilities were perceived as building too much big, fossil-fired generation.  In response, the Public Utility Regulatory Policies Act of 1978 (PURPA) and the state PURP-ettes were enacted to require local utilities to enter into offtake deals with small QF generators.  (A concise history of the creation and implementation of PURPA can be found here (pdf).)  The term for those contracts?  Well, the project developers demanded 10-20 year terms because that’s what bankers needed to finance the projects (sound familiar?).  The contract price?  By law, it was tied to the utility’s long-term “avoided costs,” or the cost to the utility to generate or procure that same energy which the utility “avoided” by purchasing instead from the small generator.  Brilliant.  Policy makers achieve the goal of developing small, distributed non-fossil generation resources and consumers would pay the same price they would have paid for fossil-fuel generated power! 

Long story short:  the predictions made in the early 80’s as to what a utility’s avoided costs would be in the 1990’s and beyond turned out to be overstated.  And not by just a little.  By a lot.  PURPA contract prices that were five to six times the then-existing market wholesale price were not unheard of.  Consumers overpaid.

Trying to predict anything twenty years into the future is a daunting task.  The complexity and dynamic nature of the US energy industry provokes sleepless nights in even the most accomplished energy forecaster.  So, the fact that the PURPA avoided cost predictions were proved wrong by reality isn’t a knock against the forecasters.  It does, however, serve as a reminder that we need to think long and hard before going back down the road of requiring utilities to enter into long-term PPAs to provide a buyer that the market is not self-supplying.

If states are going to head down this path again, here are a few suggestions to help ensure that long-term PPAs are successful for all concerned: 

1. Avoid avoided costs.   Period.
2. Drive project efficiency.  Use competitive processes such as auctions to wring efficiencies from project developers.  Use industry published development costs to ensure bidders are being realistic. 
3. Procure in stages.  Don’t purchase all of your long-term capacity needs in your first auction.  Rather, take advantage of the likelihood that renewable industries will become more efficient as technologies and methodologies mature over time. 
4. Consider innovative deal structures.  For example, a contract for differences may allow the developer to satisfy its lender’s need to finance against a predictable income stream, but consumers benefit when wholesale markets exceed the strike price. 
5. To thine own self (and thine constituents) be true:  Consumers are smarter than politicians often give credit.  Consumers know they will be paying more in the “short” term for long-term environmental benefits and the development of diverse and secure renewable resources.  Be up front about the objectives, the costs and ensure fairness to all stakeholders.

FERC and Maine Sign MOU on Ocean Tidal Power

Recognizing Maine’s “vast, untapped renewable ocean energy resources, including tidal power resources” and the state’s potential to become “an international proving ground for testing promising new technologies in state waters”, FERC Chairman Jon Wellinghoff today signed a Memorandum of Understanding (MOU (pdf)) with the State of Maine, providing that the federal and state regulators will coordinate – and streamline – the permitting process for tidal energy projects.

The MOU is the first of its kind on the East Coast (Washington signed a similar MOU (pdf) in June, 2009; Oregon signed one (pdf) in March, 2008); and was recommended (pdf) by the tidal power subcommittee of Maine’s Ocean Energy Task Force (OETF) earlier this year, which noted that a lack of coordination between the state and FERC permitting processes can limit the ability to move projects forward.

The MOU agreement will reinforce the close working relationship between federal and state regulators needed to ensure timely consideration of pilot project license and commercial project license applications.  Under the agreement, for instance, FERC and Maine agree that:

• Each will notify the other when they become aware of a potential applicant seeking a preliminary permit, project pilot license, or other license to develop a hydrokinetic tidal energy project;
• Maine will take action on a demonstration hydrokinetic tidal energy project’s application for a state permit and water quality certification within 60 days of the state’s acceptance of the application; and
• Both will designate management contacts to work through any procedural issues that arise in the review of a particular proposed tidal energy project.

In addition to these provisions designed to streamline the permit review process, the MOU also seeks to coordinate the substantive review of pilot projects and support the development of tidal energy by sharing critical data gathered from these innovative projects.  Maine commits to support FERC’s establishment of a permit process to allow short-term hydrokinetic tidal energy projects and FERC agrees to review permits with a view to ensure projects are compatible with Maine comprehensive plans and offshore wind energy test areas, as defined by new Maine law (pdf), which creates a streamlined DEP permit process for tidal energy demonstration projects.  Recognizing that gathering information regarding the economic and technical feasibility of new ocean technologies can be a stumbling block for their development, Maine and FERC also agree that any required pre- and post-licensing studies for pilot projects should be reasonable in scope and that any data gathered on pilot projects should be shared.

The MOU will promote the close working relationship between federal and state regulators needed to ensure timely consideration of pilot project license and commercial project license applications.  This is good news for the tidal power development community, and addresses concerns like those raised by the OETF, that an uncoordinated approach to permitting can lead to the failure of projects - like Finavera Renewables' (pdf) proposed tidal project in Makah Bay, WA - to make it past the planning stage.  The new framework will provide an efficient and predictable permitting process that will better enable the United States – and specifically the State of Maine – to compete effectively in the global race to develop tidal power technology and power projects.

Treasury Guidance: Energy Tax Credits

Last Thursday, the Treasury Department released guidance and began accepting applications for new Internal Revenue Code § 48C, the Advanced Energy Manufacturing Tax Credit, created by the American Recovery and Reinvestment Act.  The 30% tax credit will provide up to $2.3 billion “to re-equip, expand or establish” clean energy manufacturing facilities, and is expected to support $7.7 billion in new clean energy investment.

Eligible facilities will produce any of the following:

• property designed for use in the production of energy from the sun, wind, geothermal deposits, or other renewable resources;
• fuel cells, microturbines, or an energy storage system for use with electric or hybrid-electric motor vehicles; 
• electric grids to support the transmission of intermittent sources of renewable energy, including property for the storage of such energy;
• property designed to capture and sequester carbon dioxide and sequester carbon dioxide emissions; 
• property designed to refine or blend renewable fuels (but not fossil fuels) or to produce energy conservation technologies (including energy-conserving lighting technologies and smart grid technologies);
• new plug-in electric drive motor vehicles, or components that are designed specifically for use with such vehicles; or
• other property designed to reduce greenhouse gas emissions as may be determined by the Service.

To obtain the tax credit, a facility must first be certified by the IRS: the initial application period for this certification runs from August 13, 2009 to December 17, 2009.  Applicants must also submit a simple preliminary application to the Department of Energy (DOE); more details on the DOE application process are available in this recent Pierce Atwood publication.

Owners of facilities that are certified by the IRS will receive the tax credit when the facility enters service. Qualified progress expenditures may also be available.  To receive the credit, the facility must be placed in service within three yrs, and must show significant progress toward this goal (including obtaining necessary regulatory approvals) within one year.

The detailed IRS guidance, including the relevant application forms, can be found here (pdf).  

Forest Carbon Incentives Program

Earlier this week, Sen. Jeanne Shaheen (D-NH) introduced legislation that would establish a system of incentive payments to qualifying forest-land owners who create permanent conservation easements or agree to undertake certain forest-management techniques to maximize the amount of carbon sequestered by their trees. 

In introducing the bill, Sen. Shaheen pointed out that NH is the second most forested state in the nation (Maine is the first) and noted that while large forest owners have the opportunity to achieve carbon offset goals by participating in carbon offset markets, family and smaller landowners usually lack the efficiencies of scale to handle the substantial transactional costs that go along with market participation.  (For example, the Chicago Climate Exchange requires forestry management offset projects to go through a forestry management practice certification process and to quantify annual carbon sequestration through modeling or annual inventory.)

According to Sen. Shaheen, if conserved and managed properly, our forests could capture up to 20% of US carbon emissions, so it makes sense to provide some incentives to property owners to do so.  And since more than half of private forestland is privately owned in parcels of 100 acres or less, it makes sense to provide incentives to small property owners.  (New Hampshire law affords a similar incentive to small renewable energy generators by allowing behind-the-meter renewable generation--and even solar hot water heaters--to generate RECs, starting in 2010.)

Whether Sen. Shaheen’s bill ultimately succeeds is anyone’s guess, though it has garnered the support of a broad spectrum of organizations, from conservation organizations like the Trust for Public Land to timber industry organizations like the New Hampshire Timberland Owners Association.  But her comments suggest that carbon markets are the most effective way to provide forest management incentives, begging the question:  why not propose a program that lets small forest owners aggregate their acreage and participate in the offset markets along with larger forest owners?  This might save the Department of Agriculture the trouble of re-creating the wheel, since markets have already developed standards and protocols for offset projects.  Turns out, in fact, the markets have already thought of that, and there are many organizations registered as aggregators of small offset (and renewable energy) projects.  (An EPA report (pdf) describes how aggregators work with the Chicago Climate Exchange – see page 10 for a helpful flow-chart.)  In the end, the incentives in Shaheen's legislation may actually be an attempt to address a different but related issue:  carbon offset prices that are too low to adequately incentivize small forest owners to participate in the market through an aggregator.

DOE Opens for Loan Guarantee Business

Last Wednesday, July 29, the Department of Energy (DOE) released two solicitations for its loan guarantee program that renewable energy and transmission project developers have been anticipating since the passage of the American Recovery and Reinvestment Act (ARRA) last February.  The first solicitation (pdf) is for transmission infrastructure investment projects, and the second (pdf) is for renewable energy, energy efficiency and advanced T&D technologies.  The latter  solicitation will fund up to $8.5 billion in loan guarantees to support projects utilizing new or significantly improved technology for renewable energy, leading edge biofuels for transportation, energy efficiency and electricity T&D. 

The solicitation lists nine technical categories of eligible projects:

• alternative fuel vehicles
• biomass
• efficient electricity transmission, distribution and storage
• energy efficient building technologies and applications
• geothermal
• hydrogen and fuel cell technologies
• energy efficiency projects
• solar
• wind and hydropower 

Guarantees are available both for stand-alone projects and for facilities that  manufacture the components of eligible projects.  Both must use "new or significantly improved technologies," defined as technologies that have not been used in three or more commercial projects in the United States for at least five years.

The new solicitation includes guarantees under both the existing DOE loan guarantee program (Section 1703 of the Energy Policy Act of 2005) and the new program established by the ARRA (Section 1705 of EPAct 2005).  Although most observers generally expected that DOE would release a new set of rules for its loan guarantee program, DOE instead retained its existing rules, including the requirement that eligible projects utilize "new or significantly improved technologies," which was not included in the statutory language of the ARRA.  Still, differences remain between the two programs, and the self-selection of one program or the other at the time of application may have important implications.  For example, certain qualifying Section 1705 projects are eligible to have their credit subsidy cost (i.e., the cost of the loan guarantee) paid by the DOE, but project construction must begin by September 30, 2011, and the guarantee recipient will be subject to the various reporting, purchasing and labor requirements that commonly attach to ARRA funding.  By contrast, Section 1703 applicants must front the credit subsidy cost, but they generally are not subject to the requirements of the ARRA. 

The loan guarantee application process requires applicants to file two sequential parts.  Part I contains an executive summary, project overview and initial information.  Part II contains more detailed information DOE will use to conduct its due diligence.  The DOE will review applications in seven rounds. According to DOE, applicants applying in the early rounds will enjoy a "first-movers advantage" relative to later applicants.  Part I applications for the first round are due no later than September 16, 2009, with Part II for that round due two months later.  The final round of Part I applications will be due August 24, 2010 (followed by Part II in December of 2010). 

For more information on the loan guarantees, see Pierce Atwood's renewable energy alert on this topic.