Smart Money for Renewables
Originally published June 24, 2013
Franklin, Tenn., collaborated with a Nashville solar company to design, fund and build a 200-kW solar photovoltaic system. Photo courtesy of the City of Franklin.
Five years ago, the U.S. Department of Energy named Knoxville, Tenn., as a partner in its Solar America Cities program. With that partnership came a $200,000 grant to help reduce barriers to the growth of solar.
A major barrier that the Solar America City grant helped to identify was the high up-front cost of a photovoltaic (PV) system. So it began looking for ways to reduce that cost.
One option, a power purchase agreement (PPA), was off the table. The city purchases all of its power supply from the Tennessee Valley Authority, whose bylaws ban distributors from buying power from a third-party. However, TVA would purchase all the output from a qualifying PV system at a premium under its Generation Partners program.
It was time for Knoxville to get creative. The city began exploring a public-private financing model. Under such an arrangement, it would contribute the $250,000 from the American Recovery and Reinvestment Act-funded DOE energy efficiency block grant, and a third party solar developer would provide the rest of the funding. FLS, a North Carolina company, won the bid to finance the rest of the 90-kW project.
Structuring the deal was not easy, said Susanna Sutherland, director of the city’s office of sustainability. “We were doing something new, something that no other city in the Tennessee Valley had done.”
Under an umbrella agreement, the privately owned solar system would be installed on the roof of the city’s convention center. The agreement included lease arrangements, utility agreements, a maintenance component and a buyout provision.
After seven years, the city has the option of purchasing the system. “At that time, we’ll have the system appraised to determine the fair market value,” said Sutherland. The snag is that no one knew exactly what that value would be, she said, which made it difficult to estimate returns from the financial model. “Part of determining whether this was a good deal was knowing how much we would end up paying for the system.” This is not an issue just for Knoxville, she said. “It’s an unresolved issue nationwide.” Still, the city is leaning toward the purchase of the system.
The umbrella agreement also included a payment schedule. “The project’s incentive came in the form of a credit on our power bill, so we had to make a physical payment to the third-party company every month,” said Sutherland.
Assembling the agreement took two years of hard work. But it was a valuable learning process. “If we did it again—and we’re open to that—it wouldn’t involve as much pain,” said Sutherland.
The PV system, which began operating in 2011, generates 118,240 kWh annually and is expected to save the city up to $685,000 over 40 years.
“We’re trying to be a leader in renewable energy,” said Jake Tisinger, a project manager in Knoxville’s sustainability office. “And we want other cities to use our third-party model.”
But there are variations on that theme, he noted. “Cities should think creatively. There’s no one right or wrong answer.”
Leasing model. When the mayor of Franklin, a Tennessee city served by TVA, asked staff to look into solar, heads turned toward Knoxville. “We knew the city had used grant funding, together with private investment, for its PV project,” said Andrew Orr, sustainability/grant coordinator for the department of planning and sustainability.
But Franklin wanted to explore other financing models—especially those that did not involve any up-front funding from the city. That’s what led Orr to Raleigh, N.C., and a leasing model. “We had the land, that was our bargaining chip,” he said. “The 110-acre site—at our wastewater treatment facility—had good, unobstructed southern exposure.”
The city collaborated with a Nashville solar company that agreed to design, fund, build and maintain a 200-kW PV system.
Franklin negotiated a 20-year ground lease with the solar company and structured an 80/20 financing arrangement, with the solar company getting 80 percent of the revenues and the city getting 20 percent
All the power generated by the system is sold to TVA, which credits the city’s utility bill. The city’s revenue share goes into a revenue expense account—about $12,000 annually.
When the system is fully paid off, which is estimated at year nine—in 2021—the split flips, with the city receiving 80 percent of revenues. The solar company is still responsible for maintaining the system, said Orr.
The financing model used by Franklin is replicable, said Orr. “At least one other city in Tennessee—Kingston—has adopted this model.” And, he added, a number of cities around the country are structuring deals involving PV systems on municipal property.
Grants: Then and Now. The city of Franklin looked for a financing model that did not depend on a grant because of the uncertainty. By using all private investment, the project timeline was greatly condensed. The entire project took eight months, including contract approvals, permitting, and the actual construction of the ground mounted array. And if Knoxville were to sponsor another PV project, it would consider models that do not involve up-front investment, said Tisinger. “We’d like to get away from grants, which can be hit or miss.”
Franklin’s Orr noted that there were more grant opportunities a few years ago than there are today. “Many of the grants I am aware of were one-time blocks of money.”
Lease-PPA. Several factors influenced the decision by Raleigh, N.C., to pursue a PV project, said Julian Prosser, the city’s sustainability policy adviser and former assistant manager. One driver was the state’s renewable energy and efficiency portfolio standard, which requires the state’s investor-owned utilities to produce 12.5 percent of their energy from renewables by 2021. Raleigh purchases its power from Progress Energy Carolinas.
In addition, the city had been pursuing sustainability initiatives for several years, said Prosser. “The City Council encouraged us to consider new technologies, to be progressive in working with the private sector.” In response, Raleigh’s Public Utilities Department commissioned a study to identify ways of pursuing alternative energy sources—especially solar energy—with the aim of reducing long-term energy costs. The city also wanted to mitigate its future carbon emissions, said Prosser.
When Progress Energy issued an RFP for renewable energy projects in 2007, Raleigh invited several experienced solar power developers to provide bids.
The city negotiated a lease agreement with the two companies selected to design, build and operate a 1.3-MW PV system. Under the deal, the system would be sited on 10 acres at the city’s Neuse River wastewater treatment plant. Progress Energy would buy the power from the system under a 20-year PPA negotiated with the developers.
The PV system, which began operating in 2012, produces an estimated 1.7 million kWh annually. “We will have an income stream from the lease, and we have the option of buying the system at the end of the PPA,” said Prosser.
Other models, other renewables. A public/private partnership can be structured in many ways, depending on such factors as the municipal utility’s goals as well as state and federal requirements and incentives. And while PV systems are a popular choice for municipal utilities that want to add renewable energy to their portfolio, there are other options. But regardless of the type of renewable energy, projects generally require most of their capital upfront. So the most successful financing models are those that include a funding source for some, if not all, of the project’s construction.
Prepaid PPA. Spurred by an imminent Washington state requirement that utilities produce 15 percent of their energy from renewables by 2020, Cowlitz County Public Utility District began exploring options.
The utility wanted a financing model for a renewable energy project that would reduce the cost of the project’s energy by providing upfront funding. The solution: a prepaid power purchase agreement.
Cowlitz County PUD teamed up with three other publicly owned utilities to sponsor a 205-MW wind farm in Klickitat County. “Cowlitz played a leading role organizationally and had the largest financial interest in the project,” said David Domansky, a partner with Bracewell & Giuliani who helped structure the deal.
The utilities—Klickitat PUD, Lakeview Light & Power and Tanner Electric Cooperative as well as Cowlitz—financed the prepayment on their balance sheets, with the two PUDs issuing general obligation bonds and the two coops using commercial bank loans. They also acquired the land for the wind farm and signed a purchase agreement with the turbine supplier, making a substantial down-payment on the turbines, said Domansky.
Two institutional investors served as tax equity investors and a bank provided 100 percent of the construction cost.
When the White Creek project began operating in 2007, the construction debt was repaid by contributions from the two tax equity investors and prepayments from the four sponsoring utilities. The tax equity partners became official owners of the project so they could receive the production tax credits.
The four utilities contributed about 52 percent of the $360 million project cost, while the two equity partners contributed 48 percent. The prepayments and equity contributions covered the cost of construction, so there was no long-term debt on the project.
Each utility negotiated separate 20-year power purchase agreements. After 10 years of operation and assuming the tax equity investors have achieved their target return, the utilities have the option of buying the wind farm at fair market value.
“This financing model can be replicated,” said Domansky. “But it would have to be done on a large scale given the transaction costs. It wouldn’t be efficient, for instance, for a PV project of less than 15 MW.” Interested utilities need to weigh the benefit of prepayment versus the cost of long-term debt, he said. And they need to take account of federal tax issues as well as any restrictions imposed by state laws on public-private transactions.
The prepaid PPA model also works for PV systems. Prepayment of a utility-scale PV project could pay 20 to 40 percent of the cost of the system, according to the National Renewable Energy Laboratory.
Standard PPA. California’s aggressive renewable energy standard—33 percent by 2020 (a legislative mandate commonly referred as a floor and not a ceiling)—is driving the development of various kinds of projects. A number involve PPAs, which allow the project developer to reduce costs through the federal investment tax credit and modified accelerated cost recovery.
“Riverside’s Public Utilities Board and City Council have a long history of supporting renewable energy, and back in 2003, Riverside was one of the first municipal utilities to adopt a Renewable Portfolio Standard,” said Reiko Kerr, the assistant general manager for resources. “We’re very selective about the projects we undertake. A lot of developers wouldn’t make it through our financial risk analysis.”
Riverside Public Utilities, for instance, has signed a 25-year agreement with SunEdison. The 20-MW solar project, which will be located on land owned by the Metropolitan Water District in the city of Hemet, is expected to come on line in 2015. A power purchase agreement avoids project development and permitting risks, said Kerr. “And it gives us price and rate certainty, mitigating the impact on customers.” The levelized cost over 25 years is $95/MWh. “For a peaking resource, that’s good in California,” said Kerr.
In addition, the city is also pursuing utility scale solar projects within the city. Riverside itself has significant landholdings, and recently issued a request for proposal to develop a 5-MW solar project within the city, Kerr said. Those holdings would give the city site control for future projects, she said. “And the land would help us get a better price for a PPA.”
The Sacramento Municipal Utility District also received a DOE grant, which it put toward four renewable energy projects, one solar system and three anaerobic digesters, two of which are at dairy farms in its service territory. These projects were part of the utility’s Community Renewable Energy Deployment program.
The goal of the program is to demonstrate and expand awareness of renewable technologies, said Elaine Sison-Lebrilla, a senior project manager at SMUD.
One of the dairy digester projects, for example, uses a covered lagoon technology that “needs to find legs in California,” she said. “There are a few such systems in the state, but hopefully once farms realize the benefits, future deployments of this technology won’t need to be augmented with grant money.”
For one of the dairy digester projects, SMUD also is buying carbon offsets, said Sison-Lebrilla. Project partners invested some of their own funding, the California Energy Commission contributed $125,000 and the remaining funds came from a loan by the New Resources Bank.
The solar project, a 1.5 MW system in a regional park located on the site of a closed landfill, has been approved by the city of Sacramento. The facility is expected to be in construction by the end of the year. SMUD has signed a 20-year PPA with the developer, which has a site lease with the city. Project construction is awaiting completion of the developer’s financing agreements.
With stimulus funding drying up, SMUD is looking at other funding options, said Vicky Zavattero, Manager of Energy Research & Development. “We hope to get research grants from funding sources like the DOE and the California Energy Commission. And we’re looking for opportunities to partner with private parties and research institutes.”
Grant County Public Utility District in Washington state was used $132.4 million in Clean Renewable Energy Bonds to upgrade 10 turbines and generators at Wanapum Dam on the Columbia River. Photo Courtesy of Grant County PUD.
CREBs. Clean Renewable Energy Bonds can be used by publicly owned utilities to help finance renewable energy projects. For Grant County Public Utility District in Washington, using CREBS meant the utility received a rebate from the federal government on interest payments made to bondholders.
In 2008, Congress allocated $800 million for what are known as “New CREBs.” In February 2009, the American Recovery and Reinvestment Act allocated an additional $1.6 billion for the bond program. Bond allocation for government entities and public power utilities was fully allocated in October 2009. The Internal Revenue Service is no longer accepting applications for the bond program.
Grant County Public Utility District in Washington state was awarded $132.4 million in CREBs financing in 2009 to upgrade 10 turbines and generators at Wanapum Dam on the Columbia River. Wanapum and Priest Rapids Dam are licensed together as the Priest Rapids project.
“Installing new turbines and rebuilding the generators at Wanapum Dam will ensure 40 or more years of useful life,” said Bonnie Overfield, director of finance for the PUD. “And we’ll be able to generate more electricity using the same amount of water.” PUD studies show that new turbines will help to protect young salmon and steelhead passing through the dams on their way to the ocean.
New turbines and rebuilt generators at the Wanapum Dam in Grant County, Wash., are expected add 40 or more years of useful life to the project. Photo Courtesy of Grant County PUD.
The PUD issued Build America Bonds in 2010 and CREBs in 2010 and 2012, said Overfield. “Our analysis showed they would save the PUD a significant amount of interest. In fact, we estimated at the time of issuance that the 2010 and 2012 CREBs will save the utility an estimated $100 million in interest payments over their 30 year lifespan.”
TheThe application process was fairly straightforward, said Overfield. “And it was well worth the time invested.” However, she added, federal government programs and the allocation process may change. “Every CREB program can be different,” said Overfield
New Markets Tax Credits. Some cities may benefit—as Celina, Ohio, did—from the use of New Markets Tax Credits (NMTC). These tax credits are available to the developers of certain qualifying projects that are sited in an area designated as 'eligible' for NMTC. Eligible Census Tracts meet the criteria to be designated as economically distressed and are generally low income areas of the communities. The NMTC qualified areas are further defined as either urban or rural.
Based on Census data, the federal government designated an area in Celina as eligible for rural NMTC, said Jeffrey Hazel, the city’s mayor. “We had been looking at options for renewables.”
SolarVision LLC, an Ohio solar project developer proposed the construction of a PV system, and the city worked with the company and its group of investors to structure a Power Purchase Agreement. Because the PV project qualified and the site was “eligible”, financing for the $18 million project included federal and state New Markets Tax Credits and nearly $12 million of private funds.
The proposed site, which was not suitable for commercial/industrial development, was licensed for use to the developer. “We used some of the money from the up-front licensing fee to buy the property, which had previously been annexed into the city,” said Hazel.
The 5-MW PV system, which began operating at the end of 2012, provides 2-3 percent of the city’s power. “At that level, it won’t affect rates,” said Hazel. Under a 20-year PPA with the developer, the city will pay $67.50/MWh for the first five years and $70/MWh for the next five.
“Our customers are our ‘stockholders,’ and their dividend is lower energy prices,” said Hazel. "The project is a win-win for all parties."
Help from joint action agencies. For a number of public power utilities, a joint action agency can provide the muscle—and the funding—for renewable energy projects that might otherwise be out of reach.
At the Southern California Public Power Agency, the agency has used its bond-rating clout to help fund projects in which several of its member utilities participate. SCPPA used the prepaid PPA model for the 204-MW Millford Phase I project, said Vernon Oates, the agency’s director of finance & accounting. “Our Milford I Project was the first tax-exempt energy prepayment financing for the construction of a large scale renewable project. It was the first transaction to combine the monetization of federal production tax credits for wind energy with tax-exempt financing.”
Project participants included the Los Angeles Department of Water & Power, Burbank Water & Power and Pasadena Water & Power. SCPPA won the Bond Buyer Far West Region and National Deal of the Year award in 2010 for the $237.24 million in revenue bonds that it issued.
LADWP and Glendale Water & Power participated in Phase II of the Utah project, which brought the capacity to 102 MW.
SCPPA also used the prepaid model for two other wind projects, both in Washington state: the 262-MW Windy Point/Windy Flats facility and the 50-MW Linden Wind Energy facility. LADWP and Glendale participated in both the Windy Flats and Linden projects.
The U.S. Treasury Department provided a 30 percent cash payment of approximately $170 million for the Windy Flats project, which eliminated the need for institutional investors. The combination of the Treasury grants and the more than $500 million prepayment paid off the project’s construction costs.
In all four projects, the participating utilities signed 20-year PPA contracts.
Riverside has participated in several SCPPA-sponsored projects, said Kerr. “Smaller utilities without the resources or load to undertake a project on their own look to our joint action agency.”
Whether it’s with help from a joint action agency—or on their own—public power utilities are using varied creative financing models to support a growing number of renewable energy projects.
The Morris Model
New Jersey does not immediately strike one as a solar state. But it is second only to California. One reason is an ambitious renewable portfolio standard: 22.5 percent of energy from renewables by 2021, with a separate solar provision of at least 4.1 percent by 2028. A second reason is a wide range of incentives, from tax credits to rebates to loans.
And finally, the state is the birthplace of the Morris Model, a bond-purchased power agreement financing model. The model gets its name from Morris County, where the county’s Improvement Agency issued bonds for a 3.2 MW PV project.
Here’s how the model works. A public entity issues a low-interest government bond and transfers the resulting low-cost capital to a developer in exchange for a lower-priced power purchase agreement (PPA). Because the bond proceeds are used to finance a privately owned project, they must be taxable.
In the Morris Model, the solar developer makes lease payments that cover the bond payments. The lease payments are lower than the loan payments that a solar developer would otherwise have to make, which allows the developer to offer a lower priced PPA. The power is purchased by the facilities hosting the PV systems, not by the county. The electricity rate for a community college that will receive power from an 8-MW PV system under construction, for instance, is expected to be approximately 3 cents/kWh.
The model has worked well in New Jersey because the good credit rating of the bond-issuing counties tends to reduce the borrowing rate. The average rate on these bonds is in the neighborhood of 3.8 percent.
In the past, local governments in New Jersey had two options for procuring a solar system, said Stephen Pearlman of Inglesino Pearlman, who is credited with creating the Morris Model. “They could issue their own bonds or they could enter into a turnkey PPA contract.” Neither option worked too well, he said. “So we put the two together.”
Under the model, a pool of prospective sites is assembled to create economies of scale. “A developer would rather bid on an 8-MW project than a single small one,” said Pearlman. The pool of sites includes an anchor site, one that is highly desirable, together with less desirable sites. The first Morris Model project—a 3.2 MW solar system—consisted of PV panels on 19 schools and county buildings.
Once a pool is assembled, the county issues an RFP asking developers to offer a PPA price. The county bonds are issued off the balance sheet, said Pearlman. “And more importantly, the county guarantees the bonds.” Bonds are rated based on the county’s credit. For Morris County, it was triple A.
The key, said Pearlman, is that the county provides cheap financing and structures the model in a way that makes the developer the project owner for federal tax purposes.
Can the Morris Model work in other states? That depends on four laws, said Pearlman.
“In addition, you need governments at the regional level that are willing to guarantee their bonds,” said Pearlman.
“If people don’t use innovative techniques, I don’t see how they can meet their RPS.”
Where To Learn More
For public power utilities that want to explore models for financing renewable energy projects, there is no shortage of information.
Asked what resources he would suggest, Julian Prosser, the sustainability policy adviser for the city of Raleigh, N.C., offered several——on renewables as well as financing options. Some of these resources are intended for municipalities in the state and some for cities anywhere in the country.
The National Renewable Energy Laboratory issued a report last year titled Mobilizing Public Markets to Finance Renewable Energy Projects: Insights from Expert Stakeholders. The report is available at http://www.nrel.gov/docs/fy12osti/55021.pdf.
Raleigh’s Prosser also suggested that municipal utilities familiarize themselves with various renewable technologies and cost trends. “As technology costs decline and electricity costs rise, you want to be ready to act before those cost lines cross.”
He also recommended forming an internal team of financial staff and energy and facility managers to study financing options.
Please Sign in to rate this.
Members of the American Public Power Association receive Public Power magazine as part of their annual dues payments. The subscription rate for non-members without the annual directory is $100 per year in the United States and $130 per year outside of the United States. A subscription that includes the annual directory is $200. The annual directory alone can be purchased for $150.
Public Power is published eight times a year by the American Public Power Association. Opinions expressed in single articles are not necessarily policies of the association.
The Sheridan Group of Hunt Valley, Md., is the authorized exclusive seller of reprints of articles published in Public Power magazine. Reprints may be ordered online.
Manager, Integrated Media
David L. Blaylock
Integrated Media Editor
Senior Vice President, Publishing
Jeanne Wickline LaBella
Robert Thomas III
- House passes pipeline review, electric transmission bills
- Report catalogues state net metering, DG actions in the second quarter
- Lawmakers hear about capacity market flaws, rising grid costs
- Hamilton Utilities’ urban forestry program boosts safety, reliability
- Kansas City BPU exceeds 45 percent renewable energy threshold
- Officials urge public power utilities to be prepared for cyberattacks
- Public power utilities recognized for high customer satisfaction
- Lawmakers hear about capacity market flaws, rising grid costs
- Report sees more than seven million plug-in EVs in U.S. by 2025
- Cyber Hygiene: Preventive Care to Avoid Electric System Decay