FINANCING BIOMASS-TO-POWER AND ADVANCED BIOFUELS . EUCI Renewable Biomass For Affordable Power Generation Conference Financing Biomass Workshop Minneapolis, MN March 25, 2010. . Mark J. Riedy | Partner Mintz Levin Cohn Ferris Glovsky and Popeo P.C. 701 Pennsylvania, NW Work: 202-434-7474
EUCI Renewable Biomass For Affordable Power Generation ConferenceFinancing Biomass WorkshopMinneapolis, MNMarch 25, 2010
Mark J. Riedy | Partner
Mintz Levin Cohn Ferris Glovsky and Popeo P.C.
701 Pennsylvania, NW
A. Status Of The Biomass-To-Biofuels Industries
1. At year end 2009, U.S. ethanol capacity was about 11.5 billion gallons per year while production reached a record 10.75 billion annual gallons. 2009 production had been targeted at 13.2 billion gallons per year. 2009 biodiesel installed capacity was approximately 2.68 billion gallons per year. However, 2009 production amounted to less than 200 million gallons per year, or approximately 10% of capacity, due to a significant countervailing duty in the European market. These biofuels predominantly are first generation with principal feedstocks consisting of foodgrade grain--corn--for ethanol and edible oils (soy, canola and palm), animal fats and recycled greases for biodiesel.
2. Second generation biofuels, or advanced biofuels, have feedstocks that are inedible. These advanced and cellulosic biofuels' feedstocks will consist principally of cellulose, lignocellulose and hemicellulose for cellulosic ethanol (e.g. switchgrass, wood chips, etc.), municipal solid waste-to-fuel and other combustion-to-fuel products, and biodiesel (algae and jatropha-based).
3. The CAPEX numbers are significantly higher for second generation versus first generation biofuels (approximately $5.00 per gallon to $10.00 per gallon versus approximately $1.00 per gallon to $3.00 per gallon). However, second generation biofuels operating costs should be significantly lower than those for first generation biofuels.
4. In February 2010 the Environmental Protection Agency (“EPA”) issued final rules for the National Renewable Fuel Standard program that require that life-cycle greenhouse gas ("GHG") emissions for advanced biofuels be at least 50% lower than the same GHG emissions for petroleum-based fuels (from a 2005 baseline) in order to qualify for the monetizable Federal renewable fuel standard ("RFS") credit. The cellulosic biofuels component of advanced biofuels will be required to meet a more stringent standard of life-cycle GHG emissions that are at least 60% lower than the same GHG emissions for petroleum-based fuels (again, from a 2005 baseline) to qualify for the monetizable RFS credit.
5. The RFS for 2010 has been set at 12.95 billion gallons per year, with 950 million gallons per year for advanced biofuels, 650 million gallons per year for biomass-based diesel, and 100 million gallons per year for cellulosic biofuel. However, very small amounts of cellulosic ethanol are currently in commercial production and there is a low likelihood of meeting the 2010 target.
6. In response, the EPA has set the 2010 cellulosic biofuel standard at 6.5 million annual ethanol-equivalent gallons. While this volume is significantly less than that set forth for 2010 originally, a number of companies and projects appear to be poised to expand production over the next several years. The EPA also will make cellulosic credits available to obligated parties for end-of-year compliance, should they need them, at a price of $1.56 per gallon.
7. The EPA’s final rules on the National Renewable Fuel Standard program set the Federal RFS mandate at 36 billion gallons per year by 2022. The Obama Administration has stated it intends to increase the mandate to 60 billion gallons per year by 2030.
8. Some of the challenges for advanced biofuels (including cellulosic biofuels) are the ability to:
a. comply with life-cycle GHG emissions standards in order to obtain the RFS credit;
b. finance these new second-generation biofuels technologies with debt during a period of time without demonstrable historical revenue-producing examples for each new technology--the so-called "valley of death" period (which Federal financing must address) and, thus, making substantial equity percentages and/or government-guaranteed debt a must;
c. obtain technology construction and performance guarantees (or “project wraps”) when engineering and construction companies have little to no track record in developing such projects, and thus, the traditional EPC-engineering, procurement, construction option is generally not viable for emerging technology projects;
d. provide the required acquisition, transportation and storage of new and dense feedstocks for production purposes;
e. overcome the expected "blend-wall" constraint by 2013 at EPA's 10% gasoline-blend volume waiver with approximately 140 billion annual gallons of U.S. gasoline consumption (by increasing EPA's blend waiver to E-12, E-15 or higher blends/increase in E-85 vehicles and E-85 dispensing pump infrastructure, which may occur by mid-Summer 2010); and
f. develop new markets or demonstrate the ability to economically survive the European antidumping duties imposed on U.S.-subsidized and exported biodiesel in its traditional strongest marketplace of Europe.
9. Biofuels projects would benefit immensely from the establishment of a new percentage ITC, similar to that accorded to renewable power applications as discussed below, which can:
a. be used either as a tax credit in the year that the project is placed in service or taken as a cash grant/equity contribution at financial closure of the project financing instead of at the date of commercial operation; and
b. avail government financing without any penalty.
B. Status Of The Biomass-To-Power Industries
1. Biomass-to-power plants burn organic wastes to produce steam that turn generators to produce electricity. Their typical size is approximately 20 MW. Small producers operate most such projects and sell the power to large utilities.
2. Biomass-to-power projects (nearly 11,000MW in the U.S.) currently constitute approximately 1% of U.S. power capacity and approximately 11% of U.S. renewable power. As such, this power source rivals wind power which most recently is growing faster than biopower at a 39% annual growth rate. Still, biomass-to-power grew by approximately 14% in 2009. It is significantly more prevalent than solar and geothermal power projects.
3. Of the current U.S. biomass-to-power capacity, wood-fired power projects represent nearly 60% of that capacity, while municipal solid waste (about 89 plants), landfill gas (approximately 300 plants), animal waste (a large number include anaerobic digestion-to-power plants) and agricultural refuse (several cornstalks/sunflower shells- to- power plants) make-up the remaining capacity of approximately 40%.
4. Like the RFS and monetizable credits thereto for biofuels, the renewable portfolio standard ("RPS") (for the purchase and use of green power) and its monetizable renewable energy credits ("RECs") thereto for biomass-to-power (and other renewable power applications) are expanding the industry substantially, as RPS requirements are established in approximately 50% of U.S. states. As a result of the RPS growth and potential expanded Federal emissions restrictions, coal-fired power plants are being converted to biomass-to-power projects and thus increasing their normal MW size significantly.
5. Organic feedstocks for biomass-to-power emit approximately the same amount of carbon whether combusted in a power plant or allowed to decay in a landfill or simply on the ground. Thus, biomass-to-power plants are relatively carbon-free.
6. Furthermore, landfill decay can produce methane which is much more harmful than CO2 from a GHG emissions perspective. Also, biomass-to-power plants can emit relatively high levels of NOx and particulate emissions.
7. Some of the challenges for biomass-to-power are the following:
a. the energy value in a pound of coal is approximately 50% to 66% greater than that produced from a pound of wood chips or household trash, requiring transportation of large amounts of biomass within an approximate 75 mile radius of a plant to be economic when including transportation costs;
b. 20MW biopower projects generally are less cost-efficient than a 500MW coal-fired power plant;
c. the cost to produce biomass-to-power (approximately $3 million to $5 million per MW in CAPEX) generally is 90% greater than coal and 25% greater than wind; and
d. feedstock availability and conversion can be problematic.
e. unclear or conflicting definitions of “biomass” in Federal legislation may adversely impact financing - at present 16 biomass definitions appear in federal statutes, regulations, notices and guidances, with many of them in direct conflict.
8. Many biomass technologies in the current depressed economic environment are nevertheless being funded by angel, venture and private equity participants principally located in the areas surrounding Silicon Valley, Northern Virginia, New York, New Jersey and Boston. Since the capital markets are generally unavailable, these technologies are pursuing additional private placement rounds. I recently have completed a Series A finance and bridge loan for a biomass compaction technology company, a follow-on Series A round of each funding, and have commenced a Series B funding for the same technology provider.
9. The hope is that the lending community will recover, as these technologies are developed, to then pursue larger biofuels and biomass-to-power projects on a project finance basis. International markets still offer project finance opportunities for these projects, with multilateral and bilateral finance institutions taking the lead funding roles. I have completed venture capital and private equity funding, as applicable, on two biodiesel projects and ethanol projects in India; biomass-to-power projects in India and the Philippines; solar-powered water treatment projects in Greece, Turkey, India and Bangladesh; wind projects in India, and small hydro power projects in India. At present, I have been engaged for more than 1500MW of solar, wind and biopower projects in India and approximately 500MW of biopower projects in the Philippines.
A. Energy Production Tax Credit For Electricity Produced From Renewable Resources
1. The ARRA includes a three-year extension of the renewable energy production tax credit ("PTC") for wind and refined coal energy facilities (through December 31, 2012, which otherwise expired on December 31, 2009) and for closed-loop biomass, open-loop biomass, geothermal, small irrigation, hydropower, landfill gas, waste-to-energy, and marine renewable facilities (through December 31, 2013, which otherwise would have expired on December 31, 2010).
2. The Emergency Economic Stabilization Act of 2008 ("EESA") had extended the PTC from December 31, 2008 for one year on the wind, and two years on the second set of the above-listed, renewable power technologies. As originally authorized by the Energy Policy Act of 1992, as amended, Section 45 of the Internal Revenue Code ("IRC") provides a 10-year, inflation-adjusted, PTC for certain forms of renewable energy (described above).
3. The PTC is available from the date in which the power facility is placed in service/commences the generation of power. The PTC for biomass-to-power applications currently range from 1.0 cent/KwH (for feedstocks from municipal solid waste--landfill gas, trash combustion--and open-loop biomass--livestock, forest, agricultural waste--) to 2.1 cents/KwH (for feedstocks from organic plant material planted exclusively to produce electricity in closed-loop biomass-to-power projects). This tax incentive is available from the date of the generation of energy from the qualified facility.
4. Some other PTC-qualified renewable energy technologies instead may receive incentives in an range of the lower 1 cent/KwH incentive--small irrigation power, qualified hydropower, marine and hydrokinetic power--to the higher 2.1 cents/KwH incentive--wind, geothermal, pre-2006 solar power.
B. Elections Of Investment Tax Credit In Lieu Of Production TaxCredit/Treasury Department Grants In Lieu Of Tax Credits And Removal Of "Double-Dipping" Penalty
1. IRC Section 48 provides an investment tax credit ("ITC") for certain forms of commercial energy technologies, including solar, fuel cells and small wind projects (all of which are eligible for a tax credit of 30% of the project's qualifying costs); as well as for microturbines, combined heat and power and geothermal projects (all of which are eligible for a tax credit of 10% of the project's qualifying costs). At present, only the ITCs for microturbine and fuel cell technologies are subject to a dollar cap.
2. The EESA generally extended the ITC for eight years from December 31, 2008 through December 31, 2016. However, the geothermal ITC has no expiration date and the solar ITC, unless otherwise extended, will reduce to 10%, rather than expiring completely at the end of 2016.
3. The ITC is realized in the year in which the facility is placed in service or commences its commercial operation. However, it vests linearly over a five year period. Therefore, should the project owner sell the project prior to the conclusion of its fifth year of operation, the Internal Revenue Service will recapture the unvested portion of the tax credit.
4. The ARRA, however, has provided a new election for owners of such PTC-qualifying facilities. It permits such owners to claim a 30% ITC against the qualifying cost basis of its particular project, when the property is placed in service, in lieu of taking the PTC. Approximately 92% - 95% of the cost basis constitutes eligible costs against which to claim the 30% ITC/cash grant. Moreover, the ARRA permits taxpayers to elect to receive grants/cash payments of equal value of the 30% ITC, on an un-capped dollar basis (but for the 30% cost basis limit), from the Treasury Department in lieu using the PTC.
5. If the grant/cash payment is elected, it is not included in project gross income. Furthermore, the "construction of the project”, defined in the July 2009 Treasury Guidance, must commence on or before December 31, 2010. Congress is considering extending the “in construction” deadline to December 31, 2012. It also is considering making the Section 1603 30% of CAPEX cash grants available to advanced biofuels projects. Notwithstanding, the commercial operations date need not occur until or before:
a. December 31, 2013 for biomass-to-power and certain other renewable power technologies; December 31, 2012 for wind power; and
b. December 31, 2016 for solar and certain other specified renewable energy property described in IRC Section 48. Also, the application for such a grant/cash payment must be made to the Treasury Department on or before October 1, 2011.
6. The Treasury Department will issue a grant/cash payment equal to 30% of the qualifying costs of the renewable energy facility within 60 days of the facility being placed in service (or, if later, within 60 days of receiving a completed application for the grant). Notwithstanding, some legal considerations/technicalities may exist with respect to the issuance of these cash grants. The Treasury Department, like all federal agencies dispensing ARRA funds, requires a determination of compliance with the National Environmental Policy Act ("NEPA"), before issuing cash grants. Congress has directed that all such compliance procedures be conducted on an “expeditious basis.”
7. This election generally will occur when the project owner/taxpayer has insufficient taxable income or the project owner is unable to secure a tax equity participant for the project. However, before making this election, the project owner/taxpayer must determine quantitatively (using various nominal discount rates to determine the net value of the ITC versus the PTC) whether the value of taking the one-time 30% ITC, at the time of placing the facility in service, exceeds the value of taking the PTC in each year of a 10-year period.
8. Whether the ITC is used or a grant/cash payment is taken, the election in lieu of taking an otherwise qualified PTC is irrevocable. Furthermore, the depreciable basis of the project must reduced by one-half of the amount of the ITC used or the grant/cash payment taken.
9. This cash grant election is to compensate for the substantial reduction in the number of tax equity investors (e.g., generally commercial banks, investment banks, insurance companies and other strategic investors) and provide cash infusions into qualified renewable power projects. Many of these traditional tax equity investors (which at one time numbered approximately 20-25 major players and then reduced to approximately 4-9 major investors due to the economic down turn) either ceased operations or no longer had taxable income requiring offsetting tax credits (as they were running at losses). As a result, the election is a way to fund these types of renewable energy projects.
10. Notwithstanding, it would have been even more lucrative to project developers had Congress shifted the point of eligibility for the cash grants from the commercial operation date to the date of financial closing. This eligibility date shift would have made the cash grant more of a valuable project equity infusion than a post-construction grant to offset other financing. It would have made such projects even easier to finance.
11. Finally, the ARRA removes the "double-dipping" penalty (i.e., otherwise reducing the ITC where the ITC-qualifying project was financed with tax-exempt industrial development bonds or through any Federal, state or local government subsidized financing--grants, loans, loan guarantees, etc--program) for project owners/taxpayers that elect to take the ITC or an ITC-equivalent grant/cash payment, in lieu of taking the PTC. The "double-dipping" penalty remains in place, however, for those electing to use the PTC.
C. Power Project-- Bonus Depreciation
1. Any project owner/taxpayer of a project qualified for the PTC or ITC may write off 50% of the depreciable basis in the first year, with the remaining basis depreciated as normal according to the applicable schedules.
2. The ARRA extended this 50% bonus depreciation for one year from 2008 to December 31, 2009 to qualified renewable energy projects acquired and/or placed in service in 2009. Congress currently in proposed tax legislation is considering extending this bonus depreciation provision.
D. Advanced Biofuels Project--Bonus Depreciation
1. A cellulosic ethanol project owner/taxpayer may take a 50% depreciation expense against the cost of the production facility in the year in which the facility is placed in service.
2. In a recent IRS Ruling, the IRS permits this depreciation expensing notwithstanding that the cellulosic ethanol is not produced directly from breaking down plant material. In this regard, the IRS rules that it is permissible to ferment the broken down plants and then produce the ethanol from that process.
3. The balance of the project cost is recovered through regular depreciation. Furthermore, the 50% bonus depreciation write-off is allowed against the alternative minimum tax.
E. Advanced Energy Investment Tax Credit
1. The ARRA establishes a new 30 percent ITC for qualified investment in a “qualifying advanced energy project.” Qualified investments include tangible personal property that is depreciable and required for the production process. A qualifying advanced energy project is a project that re-equips, expands or establishes a manufacturing facility for the production of:
a. property designed to be used to produce energy from renewable resources;
b. fuel cells, microturbines, or energy storage systems for use with electric or hybrid electric motor vehicles;
c. electric grids to support the transmission of intermittent sources of renewable energy;
d. property designed to capture and sequester carbon dioxide emissions;
e. property designed to refine or blend renewable fuels or to produce energy conservation technologies;
f. new qualified plug-in electric drive motor vehicles, qualified plug-in electric vehicles or components designed to for use with such vehicles, or
g. other advanced energy property designed to reduce greenhouse gas emissions.
2.These credits are available only for projects certified by the Secretary of the Treasury in consultation with the Secretary of Energy. Once certified, the project applicant has three years from the date of certification issuance to place the project in service. If the project is not placed in service during such period, then the certification will become invalid. A competitive bidding process applies in order to receive certification. Up to $2.3 billion of credits were available for certification under this program but, as of today, the entire $2.3 billion has been fully committed, and the RFP was oversubscribed more than 3 to 1. Congress may appropriate an additional $2.3 billion to $5 billion through pending legislative proposals.
3. The advanced energy ITC provision is silent regarding whether a double-dipping penalty is applicable to reduce this tax credit's percentage if the taxpayer also uses any tax exempt and/or government financing as in the case of the ITC/PTC discussion above. That said, developers of such advanced energy technologies might consider seeking a clarification of the new cash grant provision to include such technologies for grants in lieu of the new advanced energy ITC.
4. Nevertheless, if this advanced energy ITC is used, the taxpayer may not claim/use other IRC Section 48 tax credits, such as the ITC and PTC.
F. New Market Tax Credit
1. The New Markets Tax Credit ("NMTC") Program permits taxpayers to receive a credit against Federal income taxes for making qualified equity investments in designated Community Development Entities ("CDEs"). Substantially all of the qualified equity investment, in turn, must be used by the CDE to provide investments in low-income communities.
2. The credit provided to the investor totals 39% of the cost of the investment. It is claimed over a seven-year credit allowance period.
3. In each of the first three years, the investor receives a credit equal to five percent of the total amount paid for the stock or capital interest at the time of purchase. For the final four years, the value of the credit is six percent annually. Investors may not redeem their investments in CDEs prior to the conclusion of the seven-year period.
4. Throughout the life of the NMTC Program, the Community Development Financial Institutions Fund ("Fund"), directed by the Treasury Department, is authorized to allocate to CDEs the authority to issue to their investors up to the aggregate amount of$26 billion in equity against which NMTCs can be claimed. This amount includes $1 billion of special allocation authority to be used for the recovery and redevelopment of the Gulf Opportunity Zone.
5. To date, the Fund has made 396 awards totaling $21 billion in allocation authority. In the most recent funding round, which took place in October of 2009, Treasury announced NMTC awards of $5 billion, including $1.5 billion made possible through the ARRA. An organization seeking to receive awards under the NMTC Program must be certified as a CDE by the Fund. A CDE application can take approximately 90 days to complete and file, as it is a time-consuming process requiring significant paperwork.
6. The Treasury hopes to expand and extend the NMTC program with a proposal in the FY 2011 budget that would appropriate an additional $10 billion to the program over the next two years.
7. To qualify as a CDE, an organization must:
a. be a domestic corporation or partnership at the time of the certification application;
b. demonstrate a primary mission of serving, or providing investment capital for, low-income communities or low-income persons; and
c. maintain accountability to residents of low-income communities through representation on a governing board of, or advisory board to, the entity.
G. Biofuels Tax Incentives
1. The following tax incentives are available for biofuels:
a. volumetric ethanol excise tax credit (“VEETC”) of $0.45/gallon for the blending of grain-ethanol with gasoline;
b. cellulosic biofuels tax incentive of $1.01/gallon for the production, blending and sale of cellulosic ethanol ($0.45/gallon VEETC and $0.56/gallon producer payment).
2. The following tax incentives for biodiesel expired December 31, 2009. They likely will be extended in a 2010 tax bill to at least December 31, 2010 with retroactive applications to the 2009 expiration date, as follows:
a. a $1.00 gallon tax incentive for biodiesel regardless of whether the feedstock is virgin (e.g., non-recycled biomass such as plant oils, animal fats) or non-virgin (e.g., recycled biomass such as restaurant greases);
b. a $0.50/gal tax incentive for co-processed renewable diesel; and
c. a $1.00/gallon tax incentive for non co-processed renewable diesel.
3. Leaders of the advanced biofuel industry are calling upon Congress to create an investment tax credit for biorefineries that would apply Section 1603 cash grants to 30% of the qualified CAPEX of advanced biofuels projects.
H. EESA/ARRA CO2 Capture Credits
1. The EESA, as fine-tuned by the ARRA, also provided a $10 credit per ton for the first 75 million metric tons of CO2 captured and transported from an industrial source for use in U.S. enhanced oil recovery.
2. It also provides $20 per ton credit for CO2 captured and transported from an industrial facility for permanent storage in a U.S. geological formation.
3. A qualifying facility must capture 500,000 metric tons CO2 per year.
4. The EESA authorizes $1.119 billion over the next 10 years for this opportunity.
I. Clean Renewable Energy Bonds
1. The ARRA authorizes an additional $1.6 billion of new clean renewable energy bonds ("CREBs") to finance facilities that generate electricity from the following resources: closed-loop biomass, open-loop biomass, geothermal, trash combustion, wind, small irrigation, hydropower, landfill gas and marine renewable projects.
2. This CREBs funding is subdivided into the following amounts: 1/3 available for qualifying projects of state, local, or tribal governments; 1/3 available for qualifying projects of public power providers; and 1/3 available for qualifying projects of electric cooperatives. It expands upon the previous funding level for CREBs at $800 million.
3. Tax credit bonds, unlike taxable bonds, pay the bondholders by providing a credit against their Federal income tax. CREBs, in effect, will provide interest-free financing for renewable energy projects, including certain qualified biomass-to-power plants. Since the Federal government "pays the bond interest" through tax credits, the Treasury Department must allocate such credits in advance through the authorized funding levels.
4. To attract bondholders who will benefit from such an investment in the current economic downturn, the ARRA permits regulated investment companies to pass through the tax credits earned by such CREBs to their shareholders. The ARRA also provides a prevailing wage requirement to projects financed with CREBs.
A. Department Of Energy
1. Integrated Biorefineries Grant Program
a. On December 22, 2008, the Department of Energy ("DOE") issued a competitive Funding Opportunity Announcement ("FOA"), originally for up to $200 million over six years (Fiscal Years 2009-2014 subject to Congressional appropriations). This funding supports the development of pilot and demonstration scale projects, including the use of feedstocks such as algae for second generation biofuels and production of advanced biofuels (such as cellulosic ethanol, bio-butanol, green gasoline, green diesel, and other non-food based liquid transportation fuels).
b. Edible oil-based biodiesel and corn-based ethanol were specifically excluded. Also, electric power production from biomass as a primary product was excluded. However, heat recovery and secondary power generation was included.
c. This program aimed to increase the nation's energy, economic and national security by reducing our reliance on foreign oil, and reducing greenhouse gases by deploying increased biofuels usage through research and development of advanced biofuels technologies.
d. The FOA had two topic areas for biorefinery development:
i. Pilot-scale, minimum throughput of one dry ton of feedstock/day, with a minimum nonFederal cost-share of 30%/funding - $25 million (previously $15 million)/project.
ii. Demonstration-scale, minimum throughput of 50 dry tons of feedstock/day, with a minimum non-Federal cost-share of 50%/funding-$50 million/project.
e. In December 2009, the DOE awarded $564 million to 19 projects, 14 of which were pilot-scale, 4 which were demonstration-scale, and 1 which was an already existing refinery that had previously received Federal funding. An example of an awardee is Algenol Biofuels, which received $25 million, in addition to $34 million of private funding, to construct a refinery that will produce 100,000 annual gallons of ethanol from CO2 and seawater using algae.
f. The intent of this FOA is to have integrated biorefinery projects at the pilot and demonstration scale levels operational within three to four years after applicants are selected. All projects must be located within the U.S., use feedstock from domestic biomass and demonstrate significant greenhouse gas reductions.
g. These pilot and demonstration-scale facilities are intended to lead to commercialization in the near term. The projects selected will demonstrate the commercial viability for producing advance biofuels from a variety of biomass conversion technologies and non-food feedstocks, therefore reducing U. S. dependence on oil.
h. Advanced biofuels produced from these projects are expected to reduce greenhouse gas emissions by a minimum of 50 percent, as determined by the EPA.
i. It is possible that, over the coming year, additional funds will be allocated to create at least a new round of Integrated Biorefinery solicitations and awards.
2. Two Loan Guarantee Programs
a. Title XVII of the Energy Policy Act of 2005 ("2005 Energy Act") established the DOE loan guarantee program (through Section 1702 but defined under Section 1703) with a particular focus on providing such guarantees for the commercialization of advanced biofuels, renewable power, certain other renewable energy/climate change, emissions-reducing fossil fuels and nuclear technologies/projects. The Energy Independence and Security Act of 2007 expanded on this program. The concept of loan guarantees originally was implemented in the Energy Security Act of 1980 for the DOE and the U.S. Department of Agriculture (“USDA”). It has continued to the present at the USDA, but, due to abuse, was ended at the DOE in 1981 until the 2005 Energy Act restored it.
b. Before the enactment of the ARRA, the Title XVII DOE Loan Guarantee Program had approximately $42.5 billion in Congressionally-appropriated funds. Of this funding, Congress appropriated approximately $14.5 billion for the commercialization of advanced biofuels technologies, $18 billion for nuclear power and approximately $28 billion for the commercialization of renewable power, certain other renewable energy/climate change technologies and emissions-reducing fossil fuels. Total funding for the Loan Guarantee Program peaked at about $110 billion from congressional appropriations pursuant to authority established or expanded in EPACT, EISA, the ARRA, a 2009 Congressional appropriation and a line of credit from Treasury. Of this total funding, about $80 billion remains for commitment and issuance.
c. DOE Section 1703 guarantee authority will cover up to 80% of the project costs and up to 100% of the project loan amount. Where 100% of the loan is guaranteed, however, the DOE's rules require that the Treasury Department's Federal Financing Bank provide the loan. Also, these loan guarantees cannot guarantee municipal bonds and generally guarantee loans with terms of five to 30 years. Loans of less than five years are questionably eligible for these guarantees. Loan guarantees can guarantee taxable corporate bonds.
d. The ARRA expands the categories of commercial projects eligible for DOE Loan Guarantees through a new second program (through Section 1705 amending the 2005 Energy Act) and appropriates $6 billion in new funding to cover the credit subsidy costs (i.e., loan guarantee default contingencies) for guaranteed projects. This appropriation essentially will support an approximate additional $60 billion in new loan guarantees, depending on how the OMB scores the credit risks of the qualified projects. This amount was reduced by $2 billion, or $20 billion in loan guarantee authority, when the Congress redirected funds to the Cash-for-Clunkers Program. However, Congress currently is considering restoring to the Program the full $2 billion/$20 billion in loan guarantee authority through pending legislation.
e. $500 million of the $6 billion originally was intended for advanced biofuels projects. If similarly extrapolated, this amount supports approximately $5 billion in loan guarantee authority. However, the DOE has not done so.
f. In other words, the new Section 1705 loan guarantee program differs from the original Section 1703 loan guarantee program in several ways. Unlike the original loan guarantee program which required the employment of new/innovative or significantly improved technologies (i.e., generally a technology that over the past five years has not been used in more than three projects in the U.S.), the new program is not limited to innovative, first-of-a-kind technologies. The new program funding can apply to existing/proven commercial renewable energy (e.g., biofuels, biomass, wind, solar, geothermal, hydropower, hydrogen, advanced coal energy technologies, carbon capture and sequestration, pollution control, etc.) and electric transmission technologies.
g. Section 1703 authorizes DOE loan guarantees for renewable energy and certain other projects.
h. Section 1705 authorizes DOE loan guarantees for three specific types of commercial renewable energy projects:
i. Renewable energy systems.
ii. Electric power transmission systems.
Iii. Leading edge biofuel projects.
i. Nuclear and fossil fuel (e.g. coal-to-liquids) projects are ineligible in this new program, although Congress initially had considered authorizing up to an additional $50 billion for these technologies. Notwithstanding, the DOE decided to provide $3.4 billion for clean coal technologies outside of this program into other DOE programs.
j. This new program requires a lesser payment of upfront fees (processing, etc.) than those that are characteristic of the initial program. Instead, it also may permit such fees to be paid at the loan closing or over the life of the loan.
k. The coverage limits differ for Sections 1703 and 1705. Under Section 1703, borrower applicants can request that 100% of 80% of the total project costs be guaranteed, enabling them to obtain a loan from Treasury’s Federal Financing Bank at 22 to 75 basis points over U.S. Treasuries (or about a 4% interest rate) and 20-30 year tenures on the debt. Under Section 1705, the private lender, and not the borrower, is the applicant. Section 1705 provides loan guarantees of up to 80% of up to 80% of the total project costs, or coverage of up to 64% of the total project costs. Private lenders currently are providing project loans at approximately 7% interest rates and 1 - 7 year tenures. They presently characterize long-term loans at 7 - 10 years. Thus, it is difficult to finance projects in the current economic environment.
l. Schedule of Five (5) Non-Refundable Fees Payable to DOE for Section 1703:
m. July 29, 2009 Section 1703 Solicitation for Energy Efficiency, Renewable Energy and Advanced Transmission and Distribution Technologies.
n. Schedule of Four (4) Non-Refundable Fees Payable to DOE for Section 1705:
o. October 7, 2009 Solicitation for Section 1705 for Renewable Power Projects:
p. Additionally, the DOE may allow current applicants in the Section 1703 program to transfer their applications into the Section 1705 program to obtain better terms, such as the elimination of the Section 1703 credit subsidy payment.
q. The DOE, through final rules released in December 2009, reversed its earlier decision to require a first priority lien and credit ratings on guaranteed projects. Nevertheless, the Secretary reserves the right to make determinations regarding first lien and credit support at his discretion.
r. Section 1705, unlike Section 1703, imposes two major conditions:
i. any eligible loan guarantee project must “commence construction” (an undefined term) on or before September 30, 2011 (as DOE's authority to allocate funds ends on that date); and
ii. such projects must comply with the Davis-Bacon Act by adhering to wage rate requirements during construction.
s. Energy Secretary Stephen Chu has noted his intentions to expedite the loan guarantee programs by streamlining and reducing paperwork, providing rolling appraisals on applications as submitted (instead of after application deadlines) and making decisions on applications expeditiously.
t. There are currently three (3) open solicitations: i) the Financial Institution Partnership Program solicitation (October 7, 2009), under Section 1705, and ii) the Energy Efficiency, Renewable Energy and Advanced Transmission and Distribution Technologies solicitation, and iii) the Transmission Infrastructure solicitation (each announced on July 29, 2009) under Section 1703.
u. The DOE issued the first loan guarantee under the 2005 Energy Act loan guarantee program on March 20, 2009 in the amount of $535 million to Solyndra, a California solar manufacturer, for the expansion of its manufacturing facility for solar photovoltaic panels. More recent loan guarantee recipients include Nissan, Tesla Motors, and Brightsource.
v. No loan guarantee can be issued until after the completion of a successful NEPA assessment/certification. However, ARRA projects may be provided expedited NEPA considerations.
w. Congress is being lobbied to extend the dates of these programs. If an energy bill is passed with the creation of the Clean Energy Development Agency (“CEDA”), the so-called “Green Bank”, then at least the Section 1703, if not the Section 1705, loan guarantee programs may be made permanent fixtures with annual appropriations thereto.
3. Stimulus Act Funding
a. For FY 2009 the DOE's Office of Energy Efficiency and Renewable Energy (“EERE”) received nearly a tenfold increase over its FY 2008 funding levels through Stimulus Act funding of $16.8 billion.
b. Much of this new funding will be available for direct grants/rebates for renewable energy and energy efficiency applications. Big funding winners are utility-scale biomass-to-power ($800 million) and geothermal energy ($400 million) projects. In January 2010, DOE awarded $78 million to two biofuels consortia, the National Alliance for Advanced Biofuels and Bioproducts (“NAABB”) and the National Advanced Biofuels Consortium (“NABC”), for research of advanced algae-based biofuel development.
4. Recent Budget Funding
a. Additionally, Congress worked on the FY 2009 Budget independent of the Stimulus Act funding and proposed to add another $3.55 trillion in funding government programs. This funding would have permitted the use of approximately $150 billion over a 10-year period, commencing in 2010 at $15 billion per year, to promote clean energy and energy efficiency. Congress also proposed to use $75 billion of the total FY 2009 Budget to make the R&D tax credit permanent. Much of this proposed legislation, including a cap-and-trade regime, never passed, though such passage remains a strong possibility moving forward.
c. The FY 2011 budget includes approximately $4.5 billion for DOE, a 7% increase in the DOE FY 2010 budget and a 50% increase in the DOE FY 2006 budget. More than half, or approximately $2.35 billion, goes to the EERE, the DOE office responsible for promoting renewable energy in the United States. Approximately $220 million was requested for the EERE’s biomass and biorefinery program and $325 million for the vehicle technologies program, for a total of $545.3 million for all Advanced Fuels and Vehicles programs.
i. Biomass and biorefinery funding includes $50 million for large-scale biopower, $54 million for integrated biorefineries, $26 million for feedstocks and $80 million for conversion.
d. The FY 2011 budget also includes about $300 million for the new Advanced Research Projects Agency - Energy (“ARPA-E”). ARPA-E’s mission is to fund projects that will develop transformational (i.e. “breakthrough”) energy technologies that reduce America’s GHG emissions and develop renewable energy. ARPA-E received $400 million under the ARRA.
1. In Round 1 of funding, 37 of 70 finalists, of more than 5,000 applicants, received grants totaling $150 million.
2. In Round 2, $100 million is to be awarded.
3. At the Inaugural ARPA-E Energy Innovation Summit on March 2, 2010, the Agency announced a new 3rd Round$100 million funding opportunity for grid-scale energy storage, electrical power technology, and building energy efficiency.
4. Round 4, which is yet to be announced, will have the balance of the ARRA $50 million and additional sums depending on the passage of the FY 2011 appropriation bill.
B. Department Of Agriculture
1. Advanced Biorefinery Guaranteed Loans-Biorefinery Assistance Program
a. On November 19, 2008, the USDA issued a competitive FOA requesting applications for loan guarantees under the Biorefinery Assistance Program (Farm Act 2008, Title IX (amending Farm Act 2002), Section 9003--Biorefinery Assistance Program), authorized by the Food, Conservation, and Energy Act of 2008, ("Farm Act 2008"). This was the Program’s last major funding announcement, and another is expected soon. The Program is funded through FY 2012.
b. The Biorefinery Assistance Program is designed to promote the development of new and emerging technologies for the production of advanced biofuels. It provides loan guarantees for the development, construction and retrofitting of viable commercial-scale biorefineries producing advanced biofuels.
c. Guarantee fee. For any loan, the guarantee fee will be paid to USDA by the lender at the time the guarantee is requested, and is nonrefundable.
i. The guarantee fee will be calculated by multiplying the outstanding principal balance by the percentage of the loan that is guaranteed under this program by the guarantee fee rate shown below. The guarantee fee rate shall be determined as follows:
(A) 2% for guarantees on loans greater than 75% of total project cost.
(B) 1.5% for guarantees on loans of greater than 65% but less than or equal to 75% of total project cost.
(C) 1% for guarantees on loans of 65% or less of total project cost.
ii. The guarantee fee may be passed on to the borrower.
d. Annual renewal fee. The annual renewal fee will be calculated on the unpaid principal balance as of close of business on December 31 of each year. Annual renewable fees are due on January 31. For loans where the guarantee is issued between October 1 and December 31, the first annual renewal fee payment will not be due until the January 31st immediately following the first anniversary of the date the guarantee was issued.
e. The maximum permitted loan guarantee is $250 million per project, and may cover up to 80% of the project debt, subject to the availability of Congressionally-appropriated funds. This coverage shortly may be increased to a limit of 90%, and other changes could occur, through an anticipated USDA proposed rule. Preference will be given to projects where first-of-a-kind technology will be deployed on a commercial scale.
f. Advanced biofuels are defined as fuels that do not rely on corn kernel starch as the feedstock. For example, cellulosic ethanol may be produced from switchgrass, corn stover, forest waste, animal waste, food waste, yard waste, fast-growing trees, woodchips, canola, algae and other plant material rather than from the edible portion of crops such as corn. It also will include
i. butanol or other alcohol fuels and biogas (e.g., from landfills, sewage) manufactured by converting organic renewable biomass, biogas, and
ii. green diesel and green gasoline produced from renewable biomass.
g. These energy crops require further research and development. However, they represent a key long-term component to a sustainable biofuels industry.
h. The program is geared to create energy-related jobs in rural America and encourage economic development, along with promoting resource conservation and market diversification for agricultural and forestry products, including agricultural waste materials.
i. Under Phase 1 Funding, Range Fuels received a commitment in February 2009 for the first loan guarantee for $80 million, which was closed in the first week of March 2010.
j. USDA Secretary Tom Vilsack recently announced that San Diego, California based Sapphire Energy will receive a loan guarantee for up to $54.5 million through the Biorefinery Assistance Program to demonstrate an integrated algal biorefinery process that will cultivate algae in ponds, and will use dewatering and oil extraction technology to produce an intermediate that will then be processed into drop-in green fuels such as jet fuel and diesel.
2. Loans/Loan Guarantees--Business & Industry ("B&I") Program
a. The purpose of the B&I Guaranteed Loan Program (Section 9007) is to improve, develop, or finance business, industry, and employment and improve the economic and environmental climate in rural communities.
b. This purpose is achieved by bolstering the existing private credit structure through the guarantee of quality loans which will provide lasting community benefits. It is not intended that the guarantee authority will be used for marginal or substandard loans or for relief of lenders having such loans.
c. A borrower may be a cooperative organization, corporation, partnership, or other legal entity organized and operated on a profit or nonprofit basis; an Indian tribe on a Federal or State reservation or other Federally-recognized tribal group; a public body; or an individual.
d. A borrower must be engaged in or proposing to engage in a business that will:
i. Provide employment;
ii. Improve the economic or environmental climate;
iii. Promote the conservation, development, and use of water for aquaculture; or
iv. Reduce reliance on nonrenewable energy resources by encouraging the development and construction of solar energy systems and other renewable energy systems.
e. Corporations or other nonpublic body organization-type borrowers must be at least 51% owned by persons who are either citizens of the U.S. or reside in the U.S. after being legally admitted for permanent residence.
f. B&I loans are normally available in rural areas, which include all areas other than cities or towns of more than 50,000 people. Rural areas also include the contiguous and adjacent urbanized area of such cities or towns.
g. Loan purposes must be consistent with the general purpose contained in the regulation. They include but are not limited to the following:
i. Business and industrial acquisitions when the loan will keep the business from closing, prevent the loss of employment opportunities, or provide expanded job opportunities.
ii. Business conversion, enlargement, repair, modernization, or development.
iii. Purchase and development of land, easements, rights-of-way, buildings, or facilities.
iv. Purchase of equipment, leasehold improvements, machinery, supplies, or inventory.
h. The guarantee percentage, up to the maximum allowed, is a matter of negotiation between the lender and the USDA B&I. The maximum guarantee percentage is 80% for loans of $5 million or less, 70% for loans between $5 and $10 million, and 60% for loans exceeding $10 million. However, 90% guarantees of up to $10 million are available for high priority projects.
i. The total amount of USDA B&I loans to one borrower must not exceed $10 million. However, the B&I Administrator, at his/her discretion, may grant an exception to the $10 million limit for loans of $25 million under certain circumstances. The USDA Secretary may approve guaranteed loans in excess of $25 million, up to $40 million, for rural cooperative organizations that process value-added agricultural commodities.
j. Equity requirements are as follows:
i. 10% for existing businesses;
ii. 20% for start-ups; and
iii. 25% to 40% for energy projects (i.e., the lower end of the percentage range of energy projects requirements is for start-ups, scaling upward for energy companies that have been in business for longer periods of time).
k. The maximum repayment for loans on real estate will not exceed 30 years. Machinery and equipment repayment will not exceed the useful life of the machinery and equipment purchased with loan funds or 15 years, whichever is less. Working capital repayment will not exceed seven years.
l. The interest rate for the guaranteed loan will be negotiated between the lender and the applicant. It may be either fixed or variable, as long as it is a legal rate. Interest rates are subject to USDA review and approval. The variable interest rate may be adjusted at different intervals during the term of the loan. However, the adjustments may not be more often than quarterly.
m. Collateral must have a documented value sufficient to protect the interest of the lender and the USDA. The discounted collateral value normally will be at least equal to the loan amount. Lenders will discount collateral consistent with sound loan-to-value policy.
n. The annual renewal fee is paid once a year. It is required to maintain the enforceability of the guarantee as to the lender. The rate of the annual renewal fee (a specified percentage) is established in an annual notice published in the Federal Register, multiplied by the outstanding principal loan balance as of December 31 of each year, multiplied by the percent of guarantee. The rate is the rate in effect at the time the loan is obligated, and will remain in effect for the life of the loan.
o. The rate of the annual renewal fee (a specified percentage) is established by USDA's Rural Development Division in an annual notice published in the Federal Register, multiplied by the outstanding principal loan balance as of December 31 of each year, multiplied by the percent of guarantee. The rate is the rate in effect at the time the loan is obligated, and will remain in effect for the life of the loan.
p. Annual renewal fees are due on January 31. Payments not received by April 1 are considered delinquent and, at the Agency’s discretion, may result in cancellation of the guarantee to the lender. Any delinquent annual renewal fees will bear interest at the note rate and will be deducted from any loss payment due the lender.
q. Holders’ rights will continue in effect as specified in the Loan Note Guarantee and Assignment Guarantee Agreement.
r. Completed applications should be sent to the USDA Rural Development State Office for the project location.
C. Joint DOE/USDA Advanced Biofuels Grant Program
1. On January 30, 2009, the DOE and USDA (Farm Act 2008, Title IX (amending the Farm Act 2002) (Section 9008--Biomass Research and Development Initiative) issued a joint competitive FOA of up to $25 million for biomass technology research, development and demonstration. To apply, projects must reduce greenhouse gas emissions by a minimum of 50% and be focused on non-edible feedstock development, biofuel and bio-based product development, and biofuel development analysis. Originally, interested parties were to apply by March 6, 2009, though the date was extended to May 30, 2009.
2. The funds are subject to annual Congressional appropriations. The dollar amounts of each project award are expected to range between $1 million to $5 million for no longer than a four-year period. Award recipients must cost-share at least 20% of the total cost for research and development pilot projects, and at least 50% of the total cost for demonstration projects.
3. DOE and USDA announced $24 million of awards in November 2009. The funding went towards private companies developing next generation biofuels and bioproducts (GE, Gevo, Itaconix) as well as feedstock development (Agrivida), and to research universities conducting biofuels development analysis (Purdue University).
A. Federal Renewable Portfolio Standard
1. The Administration expressly has announced its plans to pursue national RPS and new energy efficiency programs through Federal legislation. These programs would be enacted through separate acts of Congress or enacted in one Federal statute. To date, despite Congressional efforts, no national RPS exists. It remains a top priority for many industries, however, and is likely to pass Congress in one form or another.
2. Such RPS legislation would create and then enable the trading of valuable Federal RECs thereto. Such RECs would create new revenue streams for qualifying projects, including biomass-to-power.
3. The Administration has stated its intentions for a minimum 10% RPS by 2012 and a 25% RPS by 2025. Approximately 50% of U.S states currently have their respective mandatory RPS standards programs in place at varying similar percentage requirements. To date, 29 states have mandatory RPS standards, and it is widely expected that more will develop such standards if the federal government does not act.
4. Federal legislation may not replace, but instead supplement, existing state RPS programs due to the many binding contracts already entered into under those initiatives. In the several RPS bills previously before Congress in 2009, the DOE was required to coordinate between the Federal and state RPS programs. However, such Federal legislation would create the mandatory RPS/REC requirements in those states without existing programs.
B. Federal Greenhouse Gas Emissions Standards
1. The Administration originally expressed its intentions to move national greenhouse gas ("GHG") emissions legislation for enactment by year's end 2009. This program, as proposed by the Administration, would have generated revenues commencing in FY 2012 at approximately $78.7 billion to approximately $646 billion by FY 2019. It would have permitted the use of approximately $15 billion/year for renewable energy in the following 10 years commencing in FY 2010.
2. The proposed GHG legislation, also known as cap-and-trade, sought to reduce U.S. GHG emissions to 14% below the 2005 levels by 2020 and to 83% below the 2005 levels by 2050.
3. At present Congress is not debating any cap-and-trade legislation, though consideration in the future remains a distinct possibility. Climate change has become an increasingly thorny political issue, and the Administration has spent much of its time on health care reform and economic issues.
4. Several alternative proposals to a cap-and-trade regime are being discussed in Congress, including a carbon tax, a “narrow” cap-and-trade scheme that would target only utilities, and a “safe markets” scheme.
5. At present, approximately 29 U.S. states have mandatory GHG emissions legislation in place, such as the Regional Greenhouse Gas Initiative in the 6 New England states.
6. These state programs, as would a Federal initiative, rely on cap-and-trade standards and will create valuable tradable GHG emissions credits thereto. These monetizable credits will create new revenue streams for renewable energy projects, including those for biomass-to-power and advanced biofuels.
7. Unlike a Federal RPS, a Federal GHG cap-and-trade system likely would replace/preempt the existing state programs.
8. Before the debacle at Copenhagen and Congress’ inability to pass a cap-and-trade bill, some experts believed that the international carbon credit trading market of GHG emission credits alone would reach $4.5 trillion annually by 2020. Such programs’ revenues, thus, likely may be overstated.
C. Federal Green Bank
1. The Congress likely will move towards proposing legislation to establish a Federal Green Bank with an initial capitalization of $10 billion through the issuance of "green bonds" by the Treasury Department.
2. The Green Bank would have a maximum authorized limit of $50 billion in green bonds outstanding at any one time.
3. These green bonds would finance and accelerate the development, finance, construction and operation of low-carbon energy projects across the U.S.
D. Clearer Biomass Definitions in Legislation
1. The term “biomass” has been a part of legislation enacted by Congress for more than 30 years, but its characterization has evolved over time, resulting in often conflicting definitions. As mentioned, at present, 16 often conflicting such definitions exist in federal statutes, regulations, notices and guidances.
2. These biomass definitions are built into legislative provisions and programs that support research and development, encourage technology transfer, enable financing and reduce technology costs for landowners and businesses. Thus, the nature of the definitions influences the extent to which biomass can be researched, developed, financed and applied to produce energy.
3. A single, universally applicable legislative definition would streamline Federal regulations and remove any confusion regarding what materials may be used, where, and by whom. It would enable the financing of projects requiring biomass as feedstock.
A. Grant Program For ITCs
1. The ITC Grant Program, as discussed above, will make cash payments for 30% of the “basis of the property” from the Treasury Department within 60 days of the "placed in-service" date, subject to meeting certain deadlines related to the commencement of construction and placement in-service. The dates for “placed in-service” and “construction commencement” appear clear. However, clarification is required for the following:
a. what exactly constitutes 30% of the “basis of the property"/are the eligible costs? (“soft costs” and project development costs seemingly are not included); is “used equipment” included in these costs?; and
b. what are the exact parameters of the 5% safe harbor in construction funding that must be completed before December 31, 2010? Development. feasibility, consultant/attorney fees seemingly are not available, while the emphasis is on “hard costs”, such as executed contracts committing the project to equipment purchases, etc.
2. What is the treatment of conversions from coal-fired to biomass generation? How is co-firing with fossil fuels treated?
3. How will the eligible costs be certified--who, what, where, and when?
4. Will there be a “reasonableness” test regarding the cost, design, or overall purpose of the project?
5. What are the conditions precedent to meeting the “placed-in-service” date?
6. Will the 30% grant be funded in one lump sum payment directly to the project company within 60 days of the “placed-in-service” date, or in installments over a period of time and based on any milestones? Proposed legislation may make receipt of these payments subject to annual refund procedures.
7. What are steps are required to apply for the grant? Will there be a requirement for interim notices during construction? How will the project company notify the Treasury Department regarding achievement of the “placed-in-service” date? For example, will the project company submit a filing containing a detailed description of the project, its eligible costs, operational profile, etc.? Once the grant request is filed, will the Treasury Department certify, prior to financial closing, that the project is eligible for the grant, subject to meeting certain conditions at the date the project is placed in-service? Although many cash grants have been provided, are these conditions and procedures being applied consistently?
8. The ARRA contains a five year claw-back provision. Will purchases or sales of equity, upstream of the project company, upset or affect the grant during this period? Will there be any minimum financial or credit requirements during this period? Will any amounts due the Federal government under this provision be treated like a tax lien? How will the project company fulfill these requirements? Will there be any continuing reporting requirements? If so, what are they?
9. The ARRA contains a U.S.-ownership requirement to qualify for the ITC grant payment program. How will the Treasury Department apply this test as to (i) whom qualifies and (ii) what percentage of foreign ownership or control (at the project level or upstream) disqualifies a project from this program? How might pending legislation, such as Senator Schumer’s bill, affect this qualification?
10. Is a partnership or corporate structure more efficient to preserve the right to receive the ITC cash grant at the "placed in-service" date? What is more efficient from a tax perspective, assuming treatment as an interest-free grant from the Federal government?
11. Are there any environmental or labor conditions during construction or operation that must be met to qualify for the ITC cash grant? Must the project company satisfy any NEPA requirements? What about Buy America Act provisions?
12. What representations, if any, are required to be made to the Federal government? Are they similar to those traditionally made by qualifying recipients of the PTCs for wind or ITCs for solar projects? Will these representations be standardized? How far up the ownership chain must any representations be made? Can they be kept at the project level?
13. What, if any, per-project dollar limitations exist? What is the overall amount appropriated for this ITC grant program, as the ARRA is silent and they grants per company appear to be an "uncapped" dollar amount subject to satisfaction of the 30% cost basis requirement?
14. Moreover, why can’t the measuring date for the ITC cash grant be the financial closing, in lieu of the “placed-in-service,” date, so that the funds act as an equity infusion before construction, instead of the current situation of a post-construction funding requiring like amount financing during the construction period?
B. DOE Loan Guarantee Programs
1. Does the DOE have the internal resources, expertise, and capacity to solicit, evaluate, approve, and monitor the two renewable and transmission project loan guarantee programs? It took three years for the DOE to issue its first loan guarantee under its 2006 RFP. As such, should the Federal government remove the DOE and USDA, among other agencies, funding programs into a new agency modeled after the Overseas Private Investment Corporation and/or U.S. Export-Import Bank and containing similar experienced financial personnel/officials?
2. What are the parameters and rules for these two programs? Can they be made more lender-friendly to ensure their widespread use?
3. Why doesn’t the $500 million of the $6 billion ARRA loan guarantee program set aside for advanced biofuels extrapolate to $5 billion in new conventional loan guarantee authority, as the $6 billion program extrapolates to $60 billion of new loan guarantee authority? Why hasn’t the DOE issued RFPs for advanced biofuels and manufacturers of advanced energy property under the Section 1705 Loan Guarantee program?
4. What is the current size of the DOE Loan Guarantee staff?
5. When will the DOE issue the FUNDCO regulations providing loan guarantees into funds to leverage equity for investments in cleantech and renewable energy projects?
6. What is meant by “shovel ready” projects? What permits, agreements and other documents does DOE require to be in place at the submission of a Phase 2 application? Must all permits be obtained? Must all project contracts be executed? If so, which ones?
7. What are the exact definitions of biomass, advanced biofuels, inclusion of biomass thermal, biogas, black liquor, power and fuel production costs, “cutting edge” biofuels, supply chain costs (pelletizers), and equipment for supply chain manufacture?
8. What is the treatment of non-traditional lenders as “designated” - state finance agencies, VC, private equity pools?
9. Will there be changing sources of program lenders over time vs. a static solicitation approach?
10. What is the continued role, if any, of rating agencies?
11. How will DOE treat other financing sources - coordination, treatment as equity:
b. Other Federal agencies (USDA, EPA, other ARRA programs)?
c. State and local economic development, energy, SEP funding?
d. Third party equity (any minimum requirements); treatment of grants as equity?
e. Tax exempt finance?
f. What will be treated as equity?
12. What are the environmental issues:
a. Is NEPA compliance necessary for every loan?
b. What procedures exist for collaborating with EPA, state agencies?
c. What other approaches to streamlining environmental requirements has DOE implemented?
13. What cost and structure does DOE require in the loan guarantee program?
i. What is the scope of loan coverage, e.g., capital costs, soft costs?
ii. What are the DOE security priorities/exercise of remedies if default - relationships with DOE and non-DOE venders?
iii. What are the standard term sheet/standard loan contracts (possibilities)?
iv. Has DOE established any precise biomass terms sheets for designated lenders?
b. What cost and application fees are required - timing and responsibility:
i. Due diligence costs:
A. What consultants are required: independent engineer, financial advisor, insurance advisor, others? Are there approved entities? Can the consultants represent both DOE and the commercial lenders?
B. Can due diligence costs be capitalized as part of the project costs and funded at financial closings?
ii. How does DOE treat various loan guarantee fees:
A. What up-front fee(s) and scheduled payments are required?
B. What transferability and treatment in refinancing is permitted?
C. Can the guarantee be transferred from one lender(s) to another in the event of a refinancing?
D. What opportunity exists to defer, backend, or waive fees?
14. Where is DOE in the creation of small business rules to reduce or waive one or more of the currently required DOE program fees?
C. Elimination of Section 48 Restrictions
1. Under certain circumstances, biomass-to-power projects can qualify for volume cap in states where they are located and issue tax exempt debt for a large portion of their project cost. The ARRA eliminated certain restrictions allowing tax-exempt borrowers to be eligible to claim PTCs or ITCs. If these borrowers are eligible to claim PTCs or ITCs under the new program, are they eligible for any type of Federal and/or state funding program as well? If not, can programs be amended so that tax incentives and government funding can co-exist on all qualified renewable energy projects without any penalty?