Draft Wind Energy Assessment District Department of the Environment April, 2011 Wind Power for the Washington, D.C Government: An Appraisal of Options April 2011 Authors: Michael Philips Charlie Fitzgerald Jon Miles Energy Ventures International P.O. Box 5844 Takoma Park, Maryland 20913 (301) 891‐1010 1 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Abbreviations and Acronyms CREB Clean Renewable Energy Bond DSC debt service coverage EPC engineering, procurement and construction IRR internal rate of return KW Kilowatt kWh kilowatt‐hour LCW levelized cost of wind LMP locational marginal pricing MW megawatt (1,000 kilowatts) MWh megawatt‐hour (1,000 kilowatt‐hours) NOL net operating losses NPV net present value PJM Pennsylvania‐Jersey‐Maryland grid, the regional transmission organization serving a number of mid‐Atlantic and Midwest states, including DC. PPA power purchase agreement PTC production tax credit REC renewable energy credit or certificate RPS Renewable energy Portfolio Standard T&D transmission and distribution TE tax equity WACC weighted average cost of capital WGES Washington Gas Energy Services 2 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Table of Contents Introduction 4 I. US Wind Background 6 II. Acquiring Wind Generation 7 III. Siting and Size 10 IV. General Legal Issues 27 V. Cost 27 VI. Potential Project Revenues 35 VII. Development Timeline 37 VIII. Financing 38 IX. Transaction Structuring Options 53 56 X. Financial Feasibility Analysis XI. Risk Analysis – Rating Underwriting Criteria 90 XII. Sensitivity Analysis – Testing Key Assumptions 91 XIII. Summary of all Financial Results 97 XIV. Preliminary Findings and Recommendations 105 Appendix A: Planned & Existing Wind Farm on the PJM Grid 3 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Introduction The purpose of this report, commissioned by the Government of Washington, D.C.’s District Department of the Environment (DDOE), is to identify ways for the DC government to acquire the wind power for its own facilities in a way that allows it come out ahead financially – that is, to pay less for wind power than it now pays for its conventional electricity. To do this, the report seeks to determine whether it makes financial sense for the District to add direct‐generation wind energy to its electricity portfolio, and how it would go about doing so. Adding “direct generation” means that the District would acquire the electricity produced by a wind farm located on the local PJM grid at the marginal cost of producing a unit1 of that electricity – in other words, the District would effectively own, or take an equity position in, a wind farm and then either offtake the power produced by the farm or sell the generated electricity and use the income to offset its electric bill. Essentially, this report asks the question: Does it make economic sense for the DC government to take an ownership position in a wind farm and then supply its own facilities with the electricity at a lower price than it now pays for its electricity? The short answer to this question is yes. The fundamental analysis to perform when assessing financial feasibility of such a project is to compare the average per‐unit cost of wind production over the lifetime of the project (or “levelized” cost2) to the per unit price the District would otherwise pay for energy over the same time period. The result is a stream of cash flows from the savings margin achieved between the cost of producing (and delivering) wind energy directly compared to what the District would otherwise have paid for that portion of its electricity bill. After taking all development costs into consideration, if the project can provide a reasonable financial return within acceptable bounds of risk from those savings, it will be deemed financially feasible. In addition to the determination of financial feasibility, this report also reviews the technical aspects of how the District might add wind generation to its portfolio, scenarios under which such a project could be viable, and the risks and challenges that might be involved in each. It also identifies some upcoming wind projects in the region in which the DC government could potentially participate from an equity standpoint or from a special wind power offtaking arrangement. The DC government already buys wind energy. But it buys it in the form of renewable energy credits (RECs). RECs are purchased separately from electricity and are bought at a premium above and beyond what the 1
A unit of electrical energy is typically expressed in terms of a kilowatt hour (kWh) or Megawatt hour (MWh) where one kWh is produced by a 1,000‐w generator operating continuously for one hour. 2
“Levelized cost” is an industry term used to compare the aggregate power delivery costs from direct wind generation to the cost of power in the market with which it must compete over a specified time frame. In such an analysis, costs are levelized by discounting all future costs to the present using an appropriate discount factor, adding that to present costs, and dividing by total energy expected to be produced over the project lifetime. 4 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 government pays for electricity. The RECs allow the government to claim it is purchasing green power, but they are not a good deal for the government economically. First, they are an extra expense. Second, they don’t even provide the government with a hedge against rising conventional electricity prices. That is, even if the government were to purchase wind RECs equivalent to 100 percent of its electricity consumption, higher coal or natural gas prices would still result in electricity bill increases. We therefore sought to find a way for the DC government to purchase wind power in a way that would provide not just environmental benefits but economic benefits as well. We examined a range of options. First, we examined the possibility of the DC government finding a suitable windy location within the PJM grid, hiring an EPC contractor to build the wind farm, and hiring an operator to run it. This is a viable option, but also a risky one. The DC government has no experience managing a project of this kind and it would face many project risks as well as taking on the full brunt of the financial risk. The second option we examined was the possibility of the DC government buying a share of an existing wind farm. Some wind farms on the PJM grid are already either ten years old or close to it. Many of the original investors were motivated by the tax benefits, and we reasoned they would be looking to exit their investment because the federal wind production tax credit is only good for ten years. However, where a tax‐motivated investor is exiting, it appears the other partners are simply buying the tax investor’s share and would not welcome a new investor. This option may still be viable, but it will take further contacting of ownership groups. Also, buying into an aging wind farm would involve some additional O&M risk and would not be as satisfying as buying into a new one employing the latest technologies. The third option we examined the DC government joining an ownership group for a new wind farm. DC would take a minority position and leave the major decision‐making on siting, technology choice, permitting, etc. to an experienced senior partner/developer. Pursuing such an option would mean finding such a senior partner. Most wind farms are built by owner/developers such as FPL Energy or Iberdrola, who raise the capital, build the wind farm, and operate it without any outside partners. There is no opportunity for the DC government to gain a stake in these wind farms. However, we identified some experienced wind developers, particularly in Virginia, that are looking for additional equity partners and are open to the idea of a municipal government such as Washington, D.C. playing that role and bringing tax exempt financing to the deal. We think this is the best option for the DC government. In taking an ownership position in a wind farm under any of the three options, the DC government would not actually receive the electricity from the wind farm. The electricity would simply be fed into the grid and be bought by a utility such as Pepco or Allegheny or one of the other distribution utilities operating on the PJM grid. Owners of wind farms want to sell their electricity at the highest price they can get. They also want to sell the RECs. As an owner, the DC government would get a share of the income from the electricity and REC sales. While there’s a possibility DC could work out a deal whereby its income could be in the form of taking a portion of the electricity at cost, this could be complicated and would involve the other partners 5 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 agreeing to the extra complication. A more straightforward approach would be for the DC government to simply take its share of the income and then use it to offset its electricity bill. For many wind farm investors, the main benefit to investing in wind farms is the tax benefit – chiefly, the federal production tax credit and accelerated depreciation. Because the DC government is not a tax paying entity, it cannot benefit from the tax incentives. However, as a government entity, it can sell tax exempt bonds and thus bring low‐cost financing to the project. In exchange for bringing in low‐cost debt, it could potentially negotiate a larger ownership share of the wind farm. The main obstacle to the DC government taking an ownership position in a wind farm is the capital cost. Ownership of say, a 50 MW share of a new wind farm, representing somewhat less than half the DC government’s electric bill, will cost $90 million or more. There are various sources of grants and loan guarantees to help defray the cost, but ultimately the government will need to sell municipal bonds to cover most of the cost. The DC government is currently at its bonding limit, so the question of financing a wind farm at this point in time is academic. When bonds can once again be issued, the wind farm will face the politics of being in competition with other uses of bond proceeds. But unlike the other uses, the wind farm investment will generate tangible cash income for the city. The income can be used to repay bondholders and reduce the government’s electric bill. A revenue‐generating project like a wind firm can be financed with revenue bonds in other jurisdictions. That is, the security for the bondholders is the revenue from the sales of the wind‐generated electricity and RECs. There is no need to encumber the tax base of the City. Non‐revenue‐generating activities like building schools or repairing streets, are typically financed with general obligation bonds, which obligate a portion of the jurisdiction’s tax base to repaying the bonds. There is a finite amount of tax revenue and thus a finite amount of bonds that can be sold and repaid with that tax revenue. Although a wind farm would not have to rely on the tax base to repay the bonds, all bonds sold by the City of Washington, D.C. encumber the tax base. Thus, according to City officials, revenue bonds are not a financing option for the wind farm. I. US Wind Background Wind energy in recent years has become a critical part of America’s clean energy future. Wind energy is consistently one of the most cost‐effective and proven renewable energy sources for producing utility‐scale electricity. Recent developments in the financial sector and policy arena have brought renewable energy options into the main stream, and in some cases have made renewable energy cost competitive with traditional technologies Wind energy projects can vary in size from single units sized for residences or small businesses, to mid‐size projects known as distributed wind power systems that might serve a small community, to larger projects 6 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 that are often characterized as “commercial” or “utility‐scale” projects, or wind farms, and are designed to provide wholesale electricity to utilities or to an electricity market. Large wind energy projects can be built on land or offshore. However, to date, wind projects in the United States have been built only on land. The wind industry, as well as state and federal agencies, conventionally discuss wind turbines in terms of the power generating capacity of a single turbine: small turbines are those with a generating capacity of less than 100 KW, and large turbines are those with a capacity greater than 100 KW. From the perspective of the public, the physical size of a turbine, the number of turbines at a specific site, the land area of the wind farm, and the broad purpose of the installation (for example onsite versus utility‐scale) are key considerations in determining their support or opposition. The emphasis of this report is on large, utility‐scale, commercial wind power projects. Typically, a utility‐scale project is designed and financed by one or more companies experienced with large‐scale energy projects, and is usually owned and operated by a for‐profit corporation or independent power producer. Large wind power facilities in general comprise a network of individual wind turbines that are connected to one another and to a substation by way of an underground electrical connection, and subsequently to the electrical transmission system. Typical projects range in generating capacity from around 5 to several hundred megawatts (MW), where small projects may involve only a few turbines, but hundreds in the case of larger projects. The largest U.S. wind farm is Shepherd’s Flat, an 845 MW project under construction in North Central Oregon that will generate enough electricity to power 235,000 homes. II. Acquiring Wind Generation There are three broad options for the District to acquire wind energy. Two of the ways generate net electricity expenditure savings over time for the District compared to its current energy expenditures. The third option, included in the list below, is the “business as usual” strategy and involves a continuation of the District’s current strategy of purchasing retail wind RECs. A brief description of each option follows. 1) Owner of a wind project This is the option of primary focus in this report. It represents the District’s specific desire to understand the feasibility of owning or co‐owning a wind farm and directly offtaking wind energy as close to the marginal cost of production as possible. This may be done in three ways: A) Directly, through construction and outright ownership of the project entity which owns the asset. The District would construct a new wind farm by contracting with a private developer under a build‐transfer (BT) or build‐operate‐transfer (BOT) relationship. ; B) Indirectly through a private partnership, such as a lease or pre‐paid PPA; and 7 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 C) Purchase a portion of an existing wind farm that is already operational. The least‐risk option from a development perspective, such a transaction would thus theoretically require the highest acquisition premium. Under all three options, the District could offtake the electricity, but would more likely sell the electricity and use the income to offset its electricity bills. Under the offtaking option, the District would not be literally offtaking the electrons generated by the wind project. Rather, the power generated would be fed into the grid and the District would take out the same amount of power at the other end (possibly minus transmission losses). In our opinion, the most viable ownership option is to take a minority equity position in a wind farm that sells its power under a PPA to a large 3rd party offtaker such as an energy supplier or traditional utility. Net profits from operating the wind farm would then be used to directly off‐set the District’s current electricity bills in proportion to the District’s ownership stake in the project. In this scenario the District would approach a developer of a wind project and either: a. negotiate an ownership stake in a larger project based on a percentage of the wind power desired; or b. strategically partner with the developer during financing period using a tax‐efficient indirect ownership structure, such as a lease. 2) Offtaker of a commercial wind project This option involves purchasing power directly from a wind farm. It would be conducted by requesting specific wind power delivery price bids from developers and owners of wind projects under either a standard or pre‐paid PPA contract. If there were a bid that achieved electricity savings in an amount that compensates the District for any attendant risk, this could prove a financially feasible option. It could possibly be handled as part of an energy delivery contract with the District’s contracted scheduler3, currently Washington Gas Energy Services (WGES). This may be a suitable strategy for the District, but it involves paying an equity premium or fee to the project owner/developer and thus it may be more difficult to achieve the high level of cost savings normally associated with a direct‐offtake scenario. However, this option also comes with less risk and should be evaluated to see if it presents the best option from a risk‐return perspective. A) Standard consumption‐based (pay‐as‐you‐go) PPA with a private wind farm owner/developer 3
A scheduler is an entity, often a for‐profit company that is responsible for acquiring and delivering power from multiple energy generation sources and suppliers. The District’s current scheduler, responsible for supplying 100% of the District’s electricity requirements, is Washington Gas and Energy Services (WGES). 8 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 The District could seek price bids in a competitive process with a private wind farm owner/developer for a specified amount of wind under a PPA. The PPA could take various structures each with potentially different economic return and risk profiles, including: • long‐term (20‐years), pay‐as‐you‐go • medium‐term (10‐years) pay‐as‐you‐go w/ option to purchase at end of term If financially attractive this would allow the District to achieve its cost‐savings goals while eliminates all upfront capital requirements and development risk for the District, a large plus from the perspective of the District. B) Pre‐paid PPA with a private wind farm owner/developer The District could seek price bids in a competitive process with a private wind farm owner/developer for a specified amount of wind, pre‐paying for a guaranteed amount (over a specified time frame) at some discount relative to the consumption‐based PPA price: • long‐term (20‐years), greatest discount • medium‐term (10‐years), lesser discount, but option to purchase at end of term This would still require the District to come up with some type of up‐front finance arrangement, but may prove more cost‐effective and generate even more savings than a standard PPA over the course of project life. 3) Buyer of Renewable Energy Credits (RECs) only Adding RECs is included as an option in this report because RECs are already included in the District’s generation portfolio and are therefore already accounted for in the baseline of the “business as usual” scenario to which any other potential option must be compared. The other options above will allow the District to discontinue REC purchases once the REC purchase contract ends, thereby providing a cost savings to the District. Each of the above options and sub‐options has its own risk profile, transaction challenges, and general advantages and disadvantages in relation to the goal of the District generating savings through the direct offtake of electricity from wind. These issues are summarized in Table 1 below: 9 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Option 1. Direct ownership 2. Partnership 3. Existing Farm 4. Standard PPA 5. Pre‐paid PPA Project Risk Key Challenges Profile High • Maximizing available subsidies given tax‐exempt status of District • Structuring a public‐private partnership that shares risks evenly • Farm yet to be built and therefore output completely unproven • District taking on majority of development risk – may be possible to manage through minimum performance guarantees with EPC contractors Medium • Negotiating a partnership that gives District enough control • Structuring a public‐private partnership that shares risks evenly, maintains access to private sector subsidies • Wind farm output still unproven Medium • Wind farm output proven, but likely structured under a PPA Æ likely requires a renegotiation of PPA with current off‐taker, a potentially complex undertaking • The facility is older and maintenance costs may be higher than expected • Identifying an existing facility that matches the needs of the District • May be a need to re‐power the site with capital expenditure for major equipment replacement needed Low • Eliminates all development risk to the District • Allows firming and shaping of wind resource embedded in price • Eliminates upfront capital expenditures from the project • May be higher cost compared to other options, but could be managed through competitive and non‐binding bid option Medium‐
• Exposes District to some development risk, but most can Low be mitigated under PPA contract • Does not eliminate upfront capital expenditures • May achieve greater discount compared to standard PPA Table 1: Direct‐Offtake Options 10 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 III. Siting and Size One of the first issues the District will face is deciding where the wind farm will be and how large it will be in terms of electric generating capacity (in megawatts – MW). Wind is an energy resource that occurs at non‐uniform times, speeds and directions – it is thus termed an “intermittent” resource. Wind can generally be predicted using a combination of knowledge of localized meteorological conditions and scientific observations of historical wind data, but it cannot be known with absolute certainty ahead of time. Different locations have different wind “profiles”, or patterns in how (direction and strength) and when during a given day, month, or season the wind blows. Some locations have more predictable wind patterns than others. The greater the consistency and strength of the wind resource, the better the economics a given project will be and the greater an economic case could be made to add such a resource directly to the District’s electricity profile. Thus, the location of a wind farm, the design of the facility, and the size of the project will play a large role in the ultimate feasibility of adding direct‐offtake wind to the District’s energy portfolio. Location influences the quality of the wind resource available. Wind facility design and engineering quality will directly affect conversion efficiency and thus overall performance. The total installed capacity will impact economies of scale achieved and the parameters for incorporating the resource directly into the District’s electricity generation portfolio. A. Land‐Based Locations The wind resource across the United States varies significantly by region and on every scale. The wind resource map released recently by the U.S. Department of Energy and shown in Figure 1 describes the average wind speed occurring throughout the year at 80 meters above ground level (agl) throughout the U.S. One can see by examination of this map that the strongest winds nationally occur in the Midwest, extending north from Texas into the Dakotas and Montana. This phenomenon has led to one school of thought promulgated by Mr. T. Boone Pickens that the focus of U.S. wind power development should be on the center of the U.S. However, this notion overlooks the very important point that the majority of our load centers in the U.S. are stationed along large bodies of water, especially along either coast, and the transmission infrastructure in the U.S. is not capable of moving large quantities of wind energy from the middle of the country to the regions where electrical energy is in greatest demand. There is a significant wind resource over water in the U.S., with four distinct regions specified and currently under consideration: East Coast, West Coast, Gulf Coast, and the Great Lakes. The U.S. Bureau of Energy Management and Regulation (formerly Minerals Management Service) holds the permitting authority for wind power projects in federal waters and released in June 2009 its final rules in this regard. In September 2010 the U.S. Department of Energy announced its five‐year strategic plan and the formation of a new program for offshore wind. There is no installed wind capacity to date over water in the U.S.; however, it is projected that projects that are now in development of the coasts of New England and the mid‐Atlantic 11 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 could go online as early as 2015. A distinct advantage to offshore wind is the proximity of such projects to the large load centers along both coasts. Figure 1: United States 80‐meter wind resource map. This report considers only the region of the U.S. that is served by PJM. PJM Interconnect is a Regional Transmission Organization (RTO) that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia. The following states are included in PJM’s service area: Delaware, Illinois, Indiana, Ohio, Kentucky, Maryland, Michigan, New Jersey North Carolina, Pennsylvania, Virginia, West Virginia, and the District of Columbia, as shown in Figure 2. PJM regulates and manages the generation and movement of power, but does not generate or transmit power themselves. PJM helps power companies provide service to approximately 51 million people in the network, with 163,500 megawatts of generating capacity available each day. PJM headquarters are centrally located in Valley Forge, PA and is the largest centrally dispatched grid in North America. 12 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Figure 2: PJM territory broken down by individual service territories. PJM uses a two‐tier governance structure to run the network. The top tier is run by an independent board of 10 members that are unbiased and unassociated with any companies under the PJM umbrella. These ten members are responsible for maintaining PJM’s independence and ensuring that PJM maintains the reliability of the power grid. The second tier is made up of the member representatives participating in the PJM network. Each member or customer in the PJM network can have a representative on the members committee and they are able to propose and vote on changes and programs within PJM. There are five voting sectors that a member of the committee could be on, but they may only be on one. The sectors are: power generators, transmission owners, electric distributors, power marketers, and consumers. In order to be certain that the independent board is aware of the most salient issues a liaison committee meets with the board regularly comprises representatives from each of the five member sectors. The power companies listed in Figure 2 are the primary recipients of the power managed by PJM. When individual power generating assets are added to the PJM network the power is distributed to the entire PJM region. In the eastern United States, commercial wind projects are most likely to be found along mountain ridgelines and in open spaces in rural areas. In general, the economic feasibility of wind developments at different scales is determined by (i) quality of the wind resource; (ii) ease of access to transmission; and (iii) wholesale price of electricity. Figure 1 illustrates the variability of wind resources in the United States. Green and yellow shades suggest a more modest wind resource, while shades of orange, red and blue 13 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 suggest stronger resources. The most generous wind resources tend to coincide with mountain ranges and within the central plains. There is a clear and well‐understood relationship between the average wind speed at a particular site and the economic potential of wind power development at that location. While a measure of the average wind speed provides only a gross approximation of the quality of the wind resource at a site, it is more typical to find utility‐scale wind power projects in areas where the annual average wind speed is 7.0 to 7.5 m/s or higher. It should be noted that the nameplate capacity of a wind turbine is a rating of the power it produces only when the wind conditions are ideal. Since wind speeds vary constantly, a wind turbine produces power at its optimum rate only during a small fraction of the time. The average amount of energy produced by a wind turbine over an extended period is on the order of one‐third of its nameplate capacity, depending upon location, design, and size of the turbine. This fraction of nameplate capacity is referred to as its capacity factor. For instance, a 2‐MW wind turbine operating at a capacity factor of 35% during one year will produce 2,000 kW × 8,760 hr/yr ×0.35 = 6,132,000 kWh or 6,132 MWh in that year. B. Offshore Locations Offshore wind has been recognized for some time as an expensive yet promising alternative to wind energy on land. There are numerous advantages to developing wind offshore – the wind resource tends to be stronger and more steady than on land; the visual impacts associated with wind on land can in cases be averted; the developable offshore wind resources in the U.S. are to a great extent located close to major load centers as opposed to land‐based wind resources which are greater in the more rural parts of the country. To date, offshore wind projects have been built in northern Europe and more recently in China. The Obama administration, however, has indicated a strong interest in developing offshore wind in the U.S. and has requested for nearly $50 million to be spent in FY 2011 to advance the technology and deployment. The figure below illustrates the sheer magnitude of the winds off the east and west coasts, off the Gulf coast, and in the Great Lakes. 14 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Figure 3: Composite wind map of the U.S. As part of the Energy Policy Act of 2005, Congress authorized the Minerals Management Service (MMS) within the U.S. Department of Interior to grant easements in federal waters on the Outer Continental Shelf to commercial offshore wind energy developments. MMS took over the review from the U.S. Army Corps of Engineers and designed a lease structure for offshore wind projects. In June 2009 the MMS, recently renamed the Bureau of Energy Management, Regulation and Enforcement (BOEMRE), announced the final rules for assigning lease blocks and permitting offshore wind projects. In September 2009 two unsolicited bids for offshore lease blocks were submitted to the MMS by Seawind Renewable Energy and Apex Wind Energy, both Virginia‐based companies. To date, these are the only two projects submitted to MMS under the rules promulgated in 2009 although a number of offshore projects were already in development. The Cape Wind project off the coast of Massachusetts is the only project approved so far by Interior. The figure below illustrates the significant level of activity that has developed in recent years with respect to offshore wind, the two projects for which applications were submitted under the new federal rules are not depicted in this map. 15 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Figure 4: Proposed offshore wind projects along eastern seaboard (http://offshorewind.net). The Virginia General Assembly passed in 2006 the Virginia Energy Plan in which the Virginia Coastal Energy Research Consortium (VCERC) was established and subsequently charged to bring coastal energies from research and development to commercial interest. VCERC was funded between 2007 and 2009 at a level of $3.1 million and issues its final report in Spring 2010 that presented extensive findings pertaining to the economic feasibility of offshore wind in federal waters off Virginia; detailed maps that recognize specific areas that are better or not as well suited for wind development; and specific opportunities and challenges related to economic development and the supply chain. In 2009, at the request of Governor Tim Kaine, the MMS established a federal‐state‐local task force to engage in the offshore wind leasing process in federal waters off of Virginia, including coordination between federal, state, and local governments. This provided the forum to engage the Department of Defense on possible conflicting uses of the offshore waters. Also in 2009 the Virginia Offshore Wind Coalition, an industry group comprised of developers, supply chain companies, localities, and utilities, was formed and subsequently a legislative agenda was developed and bills were carried to successful passage in the General Assembly. Virginia, Maryland and Delaware formed the mid‐Atlantic Offshore Wind cooperative agreement as well. 16 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Figure 5: VCERC identified 25 MMS lease blocks that appeared to have minimal conflict with existing uses by the Navy, NASA‐Wallops, commercial shipping, or commercial fishing. These are all beyond 12 nautical miles offshore and in water depths less than 100 ft, and could support 3,200 MW of wind capacity generating 11 kWh/yr. In 2010 the Virginia General Assembly passed legislation creating the Virginia Offshore Wind Development Authority (VOWDA) which creates a body with the authority to manage PPAs, accept contributions, grants, property, etc. Governor McDonnell announced his appointees to the Authority in late October 2010. The General Assembly also passed legislation to further incentivize offshore wind within the structure of the state’s voluntary renewable energy standard. Also within the past year the Task Force unveiled vetted lease blocks that had been provisionally approved by DOD. Virginia also joined the Atlantic Offshore Wind Energy Consortium which comprises the Governors or their designees from each of the following states: Maine, New Hampshire, Massachusetts, Rhode Island, New York, New Jersey, Delaware, Maryland, Virginia and North Carolina. One of the main goals for the Consortium is to work to reduce the permitting timeline for approval of offshore wind projects. DOI’s Secretary Salazar agreed to work with the Consortium and pledged reductions in the timeline. In October of this year The Virginia submitted its vetted lease blocks to BOEMRE for preparation of the RFI for Virginia lease blocks for consideration by offshore wind developers (a required step in the process triggered by the two applications submitted by Seawind and Apex). In June 2010 the U.S. Department of Energy (DOE) released an RFI for offshore wind stakeholders to provide information to DOE as they begin to develop their strategic plan for offshore wind in the U.S. In September the DOE released its Draft Strategic Plan for Offshore Wind in the U.S. DOE and hosted a webinar and breakout sessions in Washington D.C., with a request for feedback on the plan from 17 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 stakeholders by the end of October 2010. The three major target areas within the DOE Draft Strategic Plan are Market Barrier Removal, Technology Development, and Advanced Technology Demonstration Projects. During the American Wind Energy Association (AWEA) Offshore Wind Conference in Atlantic City, NJ in October and announcement was made by Gamesa and Northrop Grumman announcement of a partnership they had formed to develop a new 5‐MW offshore wind turbine, with development based in Virginia and the possibility that testing of the new turbine would occur in Virginia as well. At this time Google made an announcement as well that they would provide major funding toward the development of an offshore transmission backbone that would extend from southeastern Virginia to New York, this infrastructure would serve a major role in terms of attracting offshore wind developers, with a secondary benefit of reducing transmission congestion along the northeast corridor. There has been a very abrupt shift in attention toward offshore wind within the last several years, driven by a number of forces ranging from the availability of new studies that describe the feasibility of offshore wind deployed in a cost‐effective manner, to new state and federal policies that mandate the procurement of electricity from clean and renewable energy sources. Among the states that are engaging within PJM, Virginia would appear to be one of the most aggressive, and is likely to be one of the first to build out. Virginia has an excellent offshore wind resource with sufficiently shallow waters extending a great distance out across the Outer Continental Shelf; is fairly well insulated from extreme wind conditions that are more likely to occur off the coasts to the north and south as well as in the Gulf; and made the strategic decision in 2006 to invest in scientific studies in order to gain understanding of the potential, rather than to set policies designed attract, or even mandate, industry engagement before sufficient information became available to estimate the cost of electricity in a reliable fashion. The VCERC report estimates that for investor‐owned utilities in Virginia, balance‐sheet financing of new generation projects having an in‐service date of 2012 and an installed capacity just under 600 MW yields the following levelized cost of energy (LCOE) estimates, in constant March 2008 dollars: $105‐130 per megawatt‐hour (MWh) for an offshore wind farm; $85‐100 per MWh for a coal‐fired plant; $80‐100 per MWh for a combined‐cycle gas turbine (CCGT) plant. These estimates do not include carbon capture and sequestration (CCS) as potential added costs for fossil fuel projects. Assuming that CCS has a levelized cost of $50 per ton of carbon dioxide (tCO2) over the service life of a generation project commissioned in 2012, with emission rates of 1.0 tCO2 per MWh for a coal‐fired project and 0.4 tCO2 per MWh for a CCGT project, then levelized electricity costs would increase to $135‐150 per MWh for coal‐fired generation and $100‐
120 per MWh for CCGT generation. Thus, when CCS has a levelized cost of $50 per tCO2, utilities can anticipate that a new offshore wind project will yield a lower energy cost than a new coal‐fired project, and may be marginally competitive with a new CCGT project. The offshore opportunity is an intriguing one in the mid‐Atlantic region of the U.S. The federal government has begun to move aggressively in order to streamline the review process for new projects and is establishing a new program at the U.S. DOE to support technological advances and increase the competitiveness of offshore wind. The attendance at the AWEA offshore wind conference in October was twice that of the first offshore conference one year ago, suggesting a rapid growth in interest from 18 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 industry. Dominion Power is engaging in a substantive fashion in North Carolina and Virginia and has made clear by its actions its intent to develop offshore wind power. The U.S. Navy is also engaging and views offshore wind as one opportunity to meet its own aggressive goals for procuring electricity derived from clean and renewable sources. And while it is not likely that offshore wind projects will be built until the second half of this decade, the opportunity for the District to engage in a long‐term commitment to purchase offshore wind is one that should be considered over the short term. The District, while not likely to host or even own an offshore wind project, could initiate or join efforts immediately to establish a consortium of large municipal and/or private customers that would present the appropriate signal to industry that sufficient demand exists for offshore power for development and deployment to proceed. C. Wind farms on the PJM grid [See Appendix A] D. Specific Opportunities Within PJM The development of the database in Appendix A was critical to gaining an understanding of which states within PJM would be most desirable for consideration by the District. The database also provided a means to make a recommendation in terms of which projects already in service, in development, or under study, or what sorts of future opportunities in the region, would be most appropriate for consideration. A summary is provided below which shows by state total installed wind capacity. The data in the second column was acquired from the U.S. DOE Wind Powering America web site. The data in the third column was distilled from PJM data. State
Delaware Illinois Indiana Maryland Michigan New Jersey North Carolina Ohio Pennsylvania Tennessee Virginia West Virginia Total Total MW in State Total MW in PJM 12/31/2009
6/23/2010 0.0
0.0 1,547.5
643.8 1,036.0
902.0 0.0
0.0 138.5
0.0 7.6
7.5 0.0
0.0 7.4
0.0 748.2
695.0 29.0
0.0 0.0
0.0 330.0
564.0 3,844.2
2812.3 Table 2: Breakdown by state of installed wind capacity 19 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 The following categories were defined in order to provide to the District a set of appropriate and distinct options: Greenfield, Existing Development, Existing Farm, and Long‐term PPA. For Greenfield, the state within PJM that is most highly recommended is Virginia, an emerging state, for a number of reasons. First Virginia is one of only three states in PJM that is recognized by the U.S. DOE as a “high priority state” on the basis of its generous wind resource; that it presents appropriate policies and regulatory framework; effective organizations and leadership to support wind development, and to date no commercial wind power has been installed. Further, in January 2011 a new and, by national standards, innovative environmental permitting process will go into effect in the form of a Permit By Rule. This follows from state legislation passed in the 2009 General Assembly intended to streamline the permitting process for projects less than 100 MW, to encourage development of renewable energy projects, and to address concerns for impacts on wildlife and historic resources. As many as one half dozen, likely more, established and reputable wind developers have projects in development in Virginia, it is perceived by many as one of the most promising new wind states in the east. Another consideration that applies in Virginia as well as other states in PJM is development on federal lands. There is one project in Virginia already on the drawing board that would entail the development of new capacity on U.S. Forest Service lands. There are also new siting guidelines that were development by the U.S. Fish and Wildlife Service that reflect federal policies in regard to wind development on federal lands, but to date there is very little precedent in the east (although significant wind development has occurred on Bureau of Land Management lands in the west). The unique opportunity for the District, however, is that a project on federal lands with the District of Columbia, a federal entity, as developer or financing agent could offset the resistance by some member so the public who feel that a private company should not be entitled to profit by development of wind on public lands. There are vast areas in Virginia and other eastern states that present excellent wind resources and could provide significant development opportunities. For Existing Development and Existing Farm, Pennsylvania is the state that is recommended for most serious consideration. Pennsylvania is an established state that has significant installed wind capacity, has demonstrated along with New York the strongest leadership among eastern states in terms of setting appropriate policies and establishing guidelines that support appropriate and responsible wind development, and is the state among those studied that presents the third‐most installed capacity, the oldest wind power projects in the region, and at least one project that is only partially developed, thus Pennsylvania may be considered for either of the two options stated. For Long‐term PPA, there are two directions that should be considered by the District. The lower risk, shorter‐term opportunity resides with projects that are in development or on the drawing board, there are a number of projects that fit this category in Pennsylvania and Virginia. The higher‐risk, longer‐term, and potentially higher‐reward opportunity applies to offshore wind projects, none of which have been constructed yet in the U.S. although many are in development. The first project is expected to be commissioned as early as 2012, but 2015‐16 is the more likely target date in the mid‐Atlantic region. Several states in PJM territory including Delaware, Maryland, New Jersey, and Virginia are active in offshore 20 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 development and engaging with the development community and the Bureau of Energy Management, Regulation and Enforcement (formerly Minerals Management Service) to apply the new regulatory framework announced in 2009 and advance project development. The database developed for this study and presented in this report provides a detailed and cumulative accounting of commercial‐scale wind power projects across the PJM region that presents a broad overview of regional wind development. This database is intended to provide to the district the means to identify potential projects in which they may consider to engage. However, for the sake of providing more detailed guidance, three separate projects, one commissioned over ten years ago and two in development, are described below. These were chosen to represent the broadest range of project opportunities and reflect, in the opinion of the authors, three of the best opportunities for the District to consider. Solaya Energy, LLC – Cow Knob Phase I Virginia is recognized as presenting arguably the best opportunities among emerging states in PJM for new development of commercial wind power. The state is recognized by the DOE as a high priority state because of its generous wind resource, appropriate state policies, and the presence of an effective wind working group. Further, the General Assembly passed in 2009 legislation to create a Permit By Rule (PBR) structure to streamline and expedite environmental review of wind power projects of 100 MW installed capacity or less. At present, there are at least nine experienced and reputable wind developers active in Virginia pursuing projects. In December 2010 the Board of Supervisors of Rockingham County is expected to approve the first large wind ordinance in its history. In January 2011 the state PBR process is expected to go into effect. Thus, from a regulatory perspective, Rockingham County offers an attractive opportunity by virtue of clear and predictable permitting processes available at both local and state levels. The former (Democratic) and current (Republican) governors and their administrations have offered definitive signs of support for commercial wind development in Virginia. There are several ridges that extend along the western border of Virginia and West Virginia through Rockingham County, Virginia, and Hardy and Pendleton Counties, West Virginia. Several companies are actively exploring development opportunities in this region and have already established a presence by installing meteorological masts to assess the wind resource. These companies have also engaged local landowners and participated on the wind working group charged by the county to develop the large wind siting ordinance. One of these companies, Solaya Energy, LLC, based in Boston, Massachusetts, is developing Cow Knob, Phase I, with an intended installed capacity of 54 MW. There are at least two distinguishing characteristics associated with Solaya that differentiate them from other members of the development community active in Virginia. First, they have sought to engage landowners in a non‐traditional fashion, that is to empower the future hosts of the wind turbines they will install to acquire a majority ownership stake in their project. The more traditional approach is one in which a developer would secure a long‐term land lease agreements with property owners through which the landowners would collect revenues, but otherwise hold no stake in the project. Second, Solaya prefers to 21 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 generate its return on investment through the actual development and construction activities, and by contracting over the long term to conduct operations and maintenance of the project, but prefers to retain only a minority stake in the ownership of the project. Given the unique nature of this business model, and the fact that local landowners have very limited financial means, the success of the Cow Know wind project relies significantly on securing equity investors to participate. Cow Know Phase I is intended to comprise 27 2.0‐MW turbines, each with a hub height of 80 m and rotor diameter of 82‐87 m, for a total installed capacity of 54 MW. Current estimates are for P50 production of 183,673 MWh and P85 production of 165,305 MWh. The estimated total project cost is between $105M and $115M. The second phase of the project would involve the installation of an additional 105 MW. The general area that Solaya and two other developers are considering is shown in Figure 6 with the locations of two meteorological towers indicated. A program of data acquisition and analysis is ongoing. Figure 6: Region along border of Virginia and West Virginia under study for commercial wind development with sites of two existing meteorological towers indicated. A recent study conducted by the National Renewable Energy Laboratory states that the average all‐in installed costs of wind turbines are $2,120/kW and $2,170/kW respectively for 1.5‐MW and 2.5‐MW 22 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 machines which represents the nominal range for land‐based wind power in the U.S. at present; the total operations costs are $45/kW for both turbines. Solaya projects an installed cost for Cow Know Phase 1 within a range of $1,944/kW and $2,091/kW which would appear, without consideration of performance projections, competitive given the current state of the industry. FreedomWorks, LLC – Shenandoah As an alternative to developing on private lands a developer may seek to develop a wind power project on public lands. In western states, the U.S. Dept. of the Interior, Bureau of Land Management (BLM) is supporting effort to evaluate new wind development on public lands.4 The BLM currently administers numerous wind energy right‐of‐way authorizations on lands in several western states. The U.S. Army National Guard, Coast Guard, and Navy are also engaging in studies to evaluate the potential for project at their bases. The Searsburg, Vermont wind power facility was commissioned in 1997 and has a capacity of 6 MW. This facility is run by Green Mountain Power. In November 2004, Deerfield Wind asked the U.S. Forest Service for authorization to use federal lands for a new wind project. Any expansion to the Searsburg facility has not yet been realized, but it is widely recognized that there are many federal lands in the east that are under the jurisdiction of the U.S. Dept. of Agriculture, Forest Service that may present opportunities for commercial wind development. In March 2010 the Wind Turbine Guidelines Advisory Committee which was established in 2006 under the Federal Advisory Committee Act submitted to the Secretary of the Interior its final policy recommendations on developing effective measures to avoid or minimize impacts to wildlife and their habitats related to land‐based wind energy projects. The committee recognized that the environmentally‐friendly development of wind energy and the protection of the nation’s natural resources are priorities for both the administration and the American people. An example cited by the committee was Executive Order 3285 issued by the Secretary in March 2009 make the production and delivery of renewable energy a priority for the Department of Interior. The work of this committee was intended to influence the final guidelines for siting of wind energy facilities put forth by the U.S. Fish & Wildlife Service as well as the corresponding guidelines adopted by the U.S. Forest Service. The Forest Service manual, Chapter 2720 – Special Uses Administration addresses Energy Generation and Transmission and considers, in particular, wind energy facilities. The George Washington and Jefferson National Forests stretch across Virginia from one end to the other, and extend into West Virginia as well, along the Appalachian mountains. The management of the national forests occurs at two levels. Long‐range Forest plans provide broad, general management direction similar to how local land use planning occurs. However, before a project that involves ground disturbance takes place, a more site‐specific project plan must be completed. 4
Wind Powering America program, U.S. Department of Energy 23 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 In December 2007 FreedomWorks proposed to the Forest Service two wind energy projects to be sited in the George Washington National Forest. Their proposal was for 215 MW on Shenandoah Mountain in Virginia. In February 2008 a pre‐screening meeting was held and adjustments were made to the original proposal in light of potential environmental impacts that were revealed. To date, FreedomWorks has been denied a testing permit by the Forest Service to install a meteorological tower and special use permits to facilitate avian and bat mist net studies. FreedomWorks was prepared to develop an environmental impact statement to ensure that the project would be environmentally sound. The testing and study period was expected to last two years after permit issuance. Figure 7: Proposed site of Freedomworks wind energy project on federal lands. To date, the only large wind projects develop on federal lands have been built in the western states on BLM lands. Despite policy advances designed to address the priorities of the current administration and development of guidelines for siting wind energy facilities that can be applied on U.S. Forest Service lands, no developer today has successfully secured permits for such a project. The FreedomWorks proposed project is one that presents significant opportunities. The areas proposed are likely to present excellent wind resources. Federal siting guidelines already exist. And the Virginia Wind 24 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Energy Collaborative (VWEC) in 2005 released the Landscape Classification System (LCS) that is available for determine which Forest Service lands within Virginia would be feasible for wind development, which would likely present significant barriers, and which should be ruled out. Finally, it is likely that if the District were to engage in a project on federal lands, then significant cost savings could be realized by virtue of the fact that lease payments to private landowners would not factor into the overall financial model. Further, the negative public sentiment that has been expressed toward private developers who wish to build commercial wind projects on public lands would likely be counteracted if the perceived beneficiary of such a project was the federal government. E. How Much Capacity? When determining how much capacity should be targeted, it is important to note a tension between inherent advantages and disadvantages of increasing the capacity of the project. Significant economies of scale and therefore lower levelized costs per kWh can be achieved as capacity increases due to the relatively high up‐front capital costs of constructing and integrating wind farms. On the other hand, as capacity of the project increases, so does the proportion of direct generation wind capacity to be incorporated into the District’s energy portfolio, increasing the difficulty and cost of managing the inherent intermittency of the resource. One of the most important factors that will determine the best target capacity for a direct‐offtake wind project scenario is the District government’s current electricity profile. The only data obtained thus far from the District in terms of its electricity consumption pattern of the government came from the District’s Office of Energy Management. That office was able to collate 12 months of data for fiscal year 2008‐2009 beginning in October of 2008 on a total month‐to‐month basis only. Figure 8 below displays this data as the authors received it, modified to graphical form. 25 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Figure 8: The District’s monthly electricity consumption pattern, FY 2008‐2009. As Figure 8 indicates, the District’s FY 2008‐2009 annual power requirement was 404,590,807 kWh per year. To understand where the best balance point lies, the authors decided to start with a reasonable capacity assumption that would account for a large minority of the District’s current annual power needs. As an initial assumption, a 50MW capacity was analyzed first. At 50MW capacity, assuming a 30% net capacity factor5, a wind farm would produce roughly 131,000,000 kWh per year, or just over 32% of the District’s 2009 electricity consumption. A 50MW capacity farm therefore appears to offer a median balance between the need to maximize economies of scale, but also to minimize the difficulty of integrating an intermittent energy resource into the overall electricity profile of the District. IV. General Legal Issues 5
Net capacity factor refers to the ratio of the rate of actual wind production compared to what the rate would be if the wind blew and energy was produced at 100% capacity. The figure takes into account all items that could affect production of wind, including wind speed, wind variability, mechanical breakdown, etc. For reference, a 15% capacity factor is considered very bad, while a 50%+ capacity factor is considered extremely good. The 2008 DOE Wind Technologies Report suggests that for regions that would be within likely areas to locate the wind farm, a capacity factor of 30% is a median estimate. 26 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Government and tax‐exempt entities are by law generally not permitted to utilize tax credits or Treasury grants as subsidies for wind farms as owners. Private financing of the project that utilizes any form of tax credit or grant as subsidy (applies to greenfield development scenarios) will require tailored legal structuring to comply with IRS restrictions on tax‐exempt and government entity ownership and/or lessee/lessor utilization of such benefits. Further, there are specific restrictions governing the generation and distribution of electricity by non‐utility municipal governments. V. Cost The cost of building a wind farm is highly site and project specific. However, it is possible to gain a general understanding of the factors affecting development costs of wind farms, and incorporate that understanding to identify a market‐defined set of conservative assumptions. This chapter offers a discussion of the various factors affecting final levelized cost of wind. To conduct the analysis, a summary of all major factors affecting the turn‐key cost of wind farm development was first collected. Second, a review of publicly available turbine and wind production cost secondary market data was conducted. Third, primary interviews with developers and other financial industry players with knowledge of the wind market were conducted to enhance anecdotal quality of available data. The goal is to provide both a general understanding of the key factors, as well as specific knowledge of market trends at data points on which to base our assumptions when assessing financial feasibility. In terms of publicly available secondary market data, the U.S. Department of Energy’s (DOE) Wind Technologies Market Report, 2008 and Wind Technologies Market Report, 2009 provides the best publicly available resource on wind project costs; this document was used to create the framework for this report’s wind cost analysis. Interviews with the report’s authors were also conducted to ensure the most up‐to‐
date information available. A second publicly available document with secondary wind project cost information is the DOE’s 20% Wind Energy by 2030, which also served as a foundation for the data in this report. Other publicly available data culled online from private research reports, available for sale by their respective organizations, were also used in conducting the analysis: first, New Energy Finance recently began offering a Wind Turbine Price Index (first published 2009) that describes the latest trends in turbine pricing; similarly, publicly available information from the American Wind Energy Association’s (AWEA) 2009 Annual Report and AWEA’s website were also used to supplement the research. An analysis of the key cost factors in the development of a wind farm based on the resources above is provided below: A. Turbine Prices: 27 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 A review of available data suggests that, if a contract is signed for turbines within the next year for a new on‐shore wind project of 50MW size located in PJM integration territory (e.g., East coast states, mid‐Atlantic north), installed turnkey development costs will not exceed $2.2mil per MW; a median estimate would be $1.8mil/MW installed. As summary of the estimates for installed turn‐
key total development costs revealed thus far is: Very conservative: $2.25+ million per MW Conservative: $2.1 million per MW Median: $1.9 million per MW Aggressive <$1.7 million per MW Key market facts from which we reached this conclusion are: • Peak prices for turbines (turbine purchase plus delivery to site, not including VAT) reached as high as $2.25mil/MW in 2008, with an average of $1.88mil/MW • An 18% drop in average turbine prices (non‐turnkey) across projects from 2008 to 2009 for a 2010 delivery was observed • Factors affecting the drop in prices were a drawback in demand due to the financial crisis, and rapidly expanding supply capacity that had begun before the crisis to relieve previous bottlenecks • Actual cost of turbines + delivery (but not including tax, balance of plant, financing, and install costs) typically make up 75‐80% of total capital costs (on‐land) • A slight uptick in prices in 2009‐2010 has thus far been observed as demand picks up slightly with economic recovery – industry consensus estimates are that any upcoming price increases will be very gradual • Prices are not expected to climb again to the highs of 2008 in the near term because the majority of the price increases at that time were due to supply bottlenecks, which have since been significantly reduced, and any increase in demand is forecast to be gradual with truncated periods in which prices could fall again. B. Operating Expenses Operating expenses, including O&M costs, are an important factor to consider in a levelized cost analysis because they carry a relatively greater degree of uncertainty in wind projects compared to more established fossil fuel powered energy plants. Even if the District owns the wind farm, the District need not operate or maintain the wind farm directly – all operating costs can be fully contracted out to 3rd party operators, in some cases a single operator is possible. The authors have broken out portions of operating costs here that will be most pertinent to the District in determining its final levelized cost point. 28 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Item Description Cost per kWh, 20‐
yr average $0.0015 General management • Management salaries and other costs associated with managing the wind farm’s normal operations $0.003 Operations labor and • All labor associated with operating the wind administration farm day‐to‐day as determined by management $0.0085 Insurance • workers compensation, property, general liability, fire, as well as any other project‐
specific insurance items required. Legal and accounting $0.002 • standard professional services required to transact and operate • increase with greater complexity, particularly in transactional stage $0.0095 Maintenance • any labor, equipment and resource costs associated with standard upkeep of energy‐
generating machinery • includes regularly scheduled and predictable capital expenditure requirements • replacement equipment can be covered by OEM warranty for up to 5 years depending on provider, turbine type, and install type. Total (average year 1 operations) $0.0245 per kWh Table 3: Conservative initial year all‐in operating expense estimates associated with a wind project of less than 100MW capacity. Assuming that the District outsources 100% of these costs to a 3rd party operator, the contract may be structured as a flat fee over multiple years or as a per kWh charge with or without an annual escalation factor. To the extent that the risk of operating the facility is diverted to the 3rd party operator, a risk premium will likely be demanded by the operator. However, a portion of this cost, namely a reserve for major repairs not covered under warranty, may be able to substitute for a portion of these costs through an upfront capitalization. Given the critical nature of the functions conducted under an O&M agreement (as well as other operating expenses), a key risk reduction strategy will be contracting with a large and experienced operator at a reasonable premium for risk diversion. A final point to note is that in the initial years of a project, prior to year 7, O&M costs usually are relatively low and predictable. Data for projects beyond this age threshold are still somewhat limited, but indications are that it is possible for costs to escalate quickly by 100%+. For example, 29 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 the DOE Wind Technologies Report, which relies heavily on data from National Renewable Energy Lab (NREL), the most comprehensive source of publicly available raw wind project data, has 35 projects in its sample for year two O&M costs, only 7 projects for year eight O&M cost estimation, but no data beyond year eight. Year two average O&M costs are less than $0.01 per kWh, but rise to almost $0.02 in year eight. Note that this is only a portion of total operating expenses involved in the wind farm. Informal conversations with developers active in the current market have placed total operating expenses (as defined in the table immediately above) at between $0.018 to $0.025 per kWh depending on how the projects are structured and the extent of economies of scale achieved with other developments in a portfolio. However, another item to consider is project capacity when predicting future O&M prices. Projects with greater than 50MW appear to achieve more stable costs through time, toward the upper limit of potential wind project sizes the District could consider. Finally, newer technology compared to a decade ago, using much fewer moving mechanical parts, theoretically should achieve greater cost stabilization through time in terms of maintenance, but this is not yet proven. But newer technology may also be less acceptable to lenders who are more risk averse when financing newer technology. C. Non‐Warranty Capital Expenditures (CAPEX) Capital expenditures that are not regularly scheduled and predicted through time after warranty has expired, including turbine replacement, large‐scale mechanical malfunction, etc., also must be taken into consideration. Because depreciation is accelerated under current U.S. regulations, depreciation is not a good predictor of this factor. These expenditures are doubly impactful because, not only do they require expensive capital infusions to the project, they also have the potential to reduce a project’s net annual output and consequently reduce a project’s capacity factor (net efficiency at converting nameplate capacity to kWhs). On the other hand, warranties do vary but can cover most or all of these costs (with the exception of project down‐time) for a project’s initial years up to the first 5 years depending on the supplier and desired premium. Usually purchase costs include 2 years o equipment warranty, with while an extra 3 years (up to 5 years) can be purchased for an extra up to $60,000 per turbine per year. However, these expenditures are inherently difficult to predict, can vary widely by project, and the authors currently have relatively little data to support a particular assumption. We have estimated these costs at 25% of initial turbine install costs, and amortized them over the course of 20 years, or in a 50MW capacity scenario roughly $12 million total, $600k per year, and an average $0.0046 per kWh delivered. This may also be modeled instead by including an additional major repair reserve capitalized up front. This will raise the total development costs, but lower the ongoing operating costs, and so will depend on cost of financing what effect this will have in the analysis. 30 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 D. Firming Premium The firming premium is another important factor in determining the financial and technical feasibility of adding direct‐offtake wind generation to the District’s electricity portfolio. The term “firming” refers to taking an intermittent energy generation resource and structuring it so that the product delivered is incorporated in a predictable and cost‐effective fashion. It is similar in principal to an interest rate swap, in which a floating interest rate is “swapped” for a fixed interest rate in exchange for some economic premium or fee. Similar to the swap, the goal of firming in electricity delivery is to reduce risk and increase predictability. Also similar to the swap, there is a cost associated with the reduced risk and greater predictability. Firming premiums depend upon the magnitude of intermittency, the structure used to firm an intermittent resource, and the portion that intermittent resource comprises of a given electricity portfolio. The rule of thumb is that the greater the portion of electricity comes from such an intermittent resource, the more difficult and costly it will be to blend that resource with the non‐
intermittent resources in a portfolio. The issue is the variability in wind output – it could not be known with certainty ahead of time when the wind will blow. As such, the District’s scheduler will be in the position of using whatever wind power is on hand, then adding from other sources to reach the load capacity of the District at any one time. Despite the potential difficulty, this is a common problem in the electricity supply market, and firming methods are available to handle this issue. Three firming structures identified by the authors that could be used to integrate direct‐offtake wind delivery to the District electricity profile are: Contract for differences; Natural gas pairing; and Day‐ahead netting. The net effect of these various structures, despite their various mechanics, is to “hedge” the price of energy. For example, under a contract for differences the cost of supplying the balance of power required above and beyond any supplied by the District’s wind facility would be stabilized by pre‐agreed future price point. On the other hand, under natural gas pairing the price stability of wind is combined with the price instability of natural gas, while the supply stability of natural gas is paired with the supply instability of wind. The authors have not yet identified a specific market of firming products per se, but very large wind developers and energy suppliers do have the capacity to offer that as a part of an overall wind product solution. The question most important in terms of this report is the cost associated with such products. The firming premium, or cost of implementing and managing a solution to the problem of intermittency, is not yet known with certainty. Likely the best method for the District to both minimize cost and maximize risk reduction in the firming product is to put the requirement to bid with schedulers at the next electricity procurement contract renewal (in 2012) or otherwise before 31 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 such time as the project will become operational. This would make it a requirement for any winning bidder to include a structure and a cost maximum associated with incorporating the direct offtake of wind into their electricity delivery service. To‐date the authors have approached this question by understanding the bounds within which the project can be feasible given the expected added cost of firming. In addition to this approach, two proxies for what this may cost in the market are: 1) the cost for large energy suppliers to integrate wind into their own profile; 2) price differential between wind that is sold under a PPA on its own and wind that is packaged with a conventional source in a PPA. The authors currently have no data for the second item, which would be very difficult to gauge anyway because it would be comparing the PPA prices for two different projects, thus requiring control for the multiple other variables that can impact final sales price. For the first, the DOE Wind Technologies Report offers a table with rough estimates for the extra cost associated with having wind of varying proportions in a large energy supplier’s energy mix. Given a roughly 30% integration proportion at 50MW capacity, the authors extrapolate that this could potentially add $0.01 cost per kWh delivered, or even greater. On the other hand, one developer that was interviewed for this report indicated that >10% of any PPA price might be conservative, which may indicated the $0.01 per kWh is too high. It should be noted then that $0.01 this is a preliminary assumption and could vary widely from this figure in either direction, which is why we consider the more pertinent analysis at this time a sensitivity analysis based on a “maximum possible” principle, all else being equal Finally, the authors conducted brief discussions with schedulers, including the District’s current scheduler WGES, to see if any further anecdotal data could be obtained on the issue of firming. E. Transmission and Distribution (T&D) PJM is a regional transmission organization (RTO) that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia, North Carolina north to Pennsylvania and New Jersey, and west to Ohio. Transmission and distribution (T&D) charges are paid by an electricity customer for the movement of electricity across a transmission grid. The District currently pays these charges through a 3‐year exclusive contract with its scheduler, Washington Gas and Electric Services (WGES). One method of handling T&D charges associated with moving the electricity from its source to the District load if direct wind is added to the District’s portfolio is to assume them to be equal to those charged under its contract with WGES, as the authors maintain for the baseline analysis in this report. If the charges are equal then the net effect is zero, and thus do not affect the analysis. 32 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 However, a more specific discussion of an integrator’s (specifically PJM’s) rationale for their T&D pricing reveals that, were the District offtaking the wind production directly, the site location could potentially change the T&D cost compared to what the District currently pays for the portion of electricity replaced by the wind farm, and which may be lesser or greater depending on its effect under PJM’s Locational Marginal Pricing (LMP) mechanism. Thus, when considering adding direct‐
offtake wind generation to the District’s portfolio, potential changes in these costs must be taken into account. LMP is a market‐based pricing system used by integrators to manage congestion over a bulk transmission grid in a given region. There are three major components to this pricing system: energy, congestion, and losses. Energy as delivered over a given region is constant and does not change, and in the District’s case would be represented by the actual levelized cost of production. Prices charged to customers based on congestion and losses, however, do vary depending on a number of technical factors based around location of power being produced and where it needs to be delivered.6 The important point is that if the District wishes to offtake electricity produced by the wind farm directly, the location of the farm even within a single integrator’s territory (e.g., PJM) may impact the T&D charges to the District associated with that power. The exact amount cannot be determined precisely because a specific wind farm site is not yet chosen, and even after this information is known, the price may still vary daily based on real time grid conditions. Several methods do exist to hedge the potential variability and achieve a predictable and stable price depending on customer load profile and generation site location, all are commonly used by PJM customers.7 For the District’s purposes, this can and most likely should be controlled by the District’s scheduler at the time the wind farm becomes operational, and could be viewed as a layer in the firming premium associated with integrating the wind into the District’s portfolio. Similar to the firming cost analysis, the authors have conducted a sensitivity analysis to determine the effects of potential variability and a conservative limit that an additional LMP‐based T&D charge could be (on an average annual basis) and still achieve a financially feasible project. The clear implication is that, in any negotiation for a future project no matter the structure, the possibility for cost differential in the T&D portion must be considered in the analysis as this will be out of the hands of private developers. 6
Phone conversation with Bill Both, Vice President at FirstEnergy Generation on 25 May 2010; phone conversation with Lou Pinkerton, interconnection specialist at PJM, on 18 June 2010. An excellent online training course developed by PJM that discusses their LMP pricing system and options for hedging associated variability can be found by clicking on the “Part 5 – Energy Markets and Congestion Hedging” link at: http://www.pjm.com/sitecore/content/Globals/Training/Courses/ol‐pjm‐101.aspx 7
Ibid. 33 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 F. Project Performance Finally, given the capital intensive nature of building wind power projects, one of the critical factors in determining levelized cost is the performance of the project. Simply put, the greater the wind blows, the more power will be produced, the higher the capacity factor, and the lower the final levelized cost. Conversely, less wind means less power production, lower capacity factors, and a higher levelized cost. The single most important factor in efficient production of wind is a strong and reliably present resource. As an intermittent power source, all wind is inherently non‐uniform and comes with some level of uncertainty in terms of the amount of power that will be produced in the future at any given point in time. Different sites do produce more or less wind, with more or less variable patterns. Wind resources assessments, which have improved markedly in the past decade, mitigate this risk somewhat by enabling an accurate smoothed‐average prediction over a longer time period, thus enabling greater risk assessment accuracy (and subsequently greater control in the underwriting of wind power projects). However, to achieve such confidence intervals, those studies often require at least 2 years of historical site‐specific wind data taken with an anemometer at multiple heights, and do not remove all such risk. Turbine breakdown can also have a serious impact on final levelized cost. If there are long‐term breakdowns during peak wind periods, a project’s annual performance can be severely impaired. Ensuring proper maintenance and even paying a premium for strong OEM warranties are often a good investment in minimizing final levelized cost, along with seeking minimum performance guarantees where available from EPC contractors, OEM partners, or other 3rd parties. Another key variable is farm design quality. Put simply, if the farm is poorly designed, wind output and therefore capacity factors can suffer. It is crucially important, then, to maximize all possible efficiency upfront with a high‐quality, well‐thought‐out design with proven technology. Given the above, a site‐specific wind resource assessment should be completed to have an accurate prediction of not only the amount of wind but its intra‐year and intra‐day profile. Knowing this allows rational planning and site engineering to maximize the resource and minimize levelized cost – thus, issues of siting, turbine choice, and farm engineering and design all have an influence on project efficiency and resulting capacity factor8, impacting the total amount of power produced and thus the final cost per unit. 8
Generally, the percentage of power actually produced divided by the theoretical amount that would be produced if the wind blew 100% of the time. 34 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 The financial model developed by the authors captures issues of project performance by testing more conservative capacity factors in conjunction with conservative assessments for future capital expenditure requirements to properly maintain the farm, and the resulting sensitivity analysis provides a minimum below which a project is likely unfeasible, and conversely above which a project will be possible. This phenomenon is also often referred to in statistical terminology as P50, P90, P95, and P99. These numbers refer to an amount of wind production from a particular project by which that amount is 50%, 75%, 95%, and 99% probable to be actually delivered by the project. As might be expected, P50 will be higher than P99. Due the variability of wind and based on the experience of developers and wind resource analysts, the P99 value will usually be approximately 23‐27% lower than the P50 value. Assuming 25% lower, for a project that at P50 would otherwise achieve a capacity factor of 0.3, this would reduce that capacity factor to 0.225. This is important as, depending on the financing structure, some guarantees are only valid up to the P99 amount. VI. Potential Project Revenues A. Electricity savings If it is possible to produce electricity from wind at a cost cheaper than the price the District pays to acquire its power, a savings revenue stream would be generated for the District by incorporating the lower cost wind energy into its electricity portfolio. This is the key revenue potential of adding direct‐generation wind energy to the District’s electricity portfolio. One key purpose of this report is to determine exactly how many kWh of electricity could be offset by a wind project in a direct offtake scenario, and the magnitude of the resulting cost differential over time. B. Net Project Income A project’s net income would become a potential revenue source only if the District chose to offset its current electricity bills with the net income of a for‐profit project with an existing PPA. In such case the gross sales of electricity less the cost of operating the wind farm, or the project’s net income, would flow to the District according to its proportion of ownership in the project. The resulting revenue stream would then be applied to offset the District’s current electricity bill. As noted for the reasons described above, this option is not considered in this report. C. Renewable Energy Credits (RECs) Renewable energy credits, or RECs, would be generated by the production of wind energy by the project. In standard private‐sector projects, this value is usually incorporated into a PPA price 35 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 offered by a project owner to an energy supplier or utility to comply with states’ various renewable portfolio standards (RPS). Under the direct offtake scenario considered by this report, the RECs would be available for sale on the open market as a wholly separate revenue stream. If the District were the owner of the project, the District could choose to sell any portion of the RECs generated by the project it chooses, up to 100%, to enhance the cash flows of the project. In that same scenario, if the District wishes to use the project to meet its own RPS requirement (20% energy met by renewable by 2020, with 0.4% solar carve out), sale of RECs would not be an option, only the owner of the RECs would claim that right. However, if the District were partnering with private developers in some way, for example by seeking bids and entering a standard PPA with a separate IPP, the RECs would be a portion of the revenue stream of a given project’s private owners, part of which would flow through to the District as a reduction in the net price those developers might bid. D. Carbon Credits All positive environmental attributes of a renewable energy project, including carbon benefits, are embodied by RECs, carbon credits would not be applicable in any project if RECs are claimed, saved, or sold.9 Carbon credit transactions are currently more expensive, complex, and time intensive than the more liquid REC market. Further, REC markets are driven mainly by compulsory state‐level RPS mandates and currently have more predictable demand, unlike voluntary carbon markets. Finally, because RECs represent 100% of all positive environmental benefits of a project, RECs theoretically should provide a more valuable asset for project owners over the long‐term. Therefore, should the District wish to monetize the carbon‐specific benefits of the project, its current best option is most likely to sell the RECs generated by the project to a 3rd party buyer. However, various carbon‐related legislation initiatives are under consideration by Congress that may affect the state of the market above, including complete energy and carbon reform legislation. These developments should be monitored prior to making a decision regarding carbon benefits further along the development timeline. For now, this report assumes that RECs will be the environmental attribute of choice for sale to a 3rd party. E. Tax Credits Generally speaking, tax credits cannot be utilized directly by a tax‐exempt or public entity such as the District, nor is the project eligible for tax credits if owned by such an entity. The income stream resulting from tax credits can only be used in years in which there is taxable income, often after year 5 in a wind project, creating a present value discount on the nominal value of the benefits. 9
Phone conversation with Yuri Horowitz, CEO of SolSystems (and SREC aggregator and former wind project development lawyer), 6 April 2009. 36 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Further, much of this benefit often goes unused without a tax credit specific investor because the project cannot generate enough taxable income over the life of the project to use them all. Thus, if the District wishes to indirectly take advantage of these subsidies it almost certainly must seek to partner with the private sector in a lease, PPA, or other legally appropriate arrangement. Different partnership structures will be variously efficient at passing such benefits through to the District. F. Net Operating Losses (NOLs) NOLs are benefits driven primarily by the accelerated depreciation benefits associated with wind farms, and have a tax value to a potential investor of the amount of loss multiplied by the marginal tax bracket of the investor. Similar to tax credits, the resulting income stream can only be used in years in which there is taxable income, often after year 5 in a wind project creating a present value discount on the nominal value of the benefits. However, also similar to tax credits, NOLs generally cannot be utilized directly by a tax‐exempt or public entity such as the District, or by a project owned by such entity, but project structures do exist to allow indirect inclusion of such benefits in the District’s project. VII. Development Timeline Issues to be considered include permitting, construction and turbine lead time. According to discussions with wind turbine manufacturers as well as project developers, the market has softened compared with 2007‐2008, and 50MW projects today are well within the interest of major turbine suppliers with lead times running roughly 12 months from contract signing.10 VIII. Financing A. Summary Financing can have a significant effect on the levelized price of wind delivered by a given project due to wind’s capital intensive nature. In general there are two options for financing the cost to develop the wind project: • Public: The District would finance development by issuing bonds at the best possible rate in accordance with all applicable debt cap limitations for up to 100% of project capital costs •
Private: The District would partner with the private sector using some mix of District funds, private equity, developer equity, commercial debt, tax credits, grants, subsidized loans and/or other fund sources to finance the project 10
Phone discussion with General Electric wind turbine Sales Representative Daniel Schafer; 22 April 2010. 37 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Since 2008, the general cost of financing for public sector entities such as municipalities has decreased significantly while the cost of project finance in the private sector has increased. Prior to the end of 2008 the spread between public bond financing and private financing was +300bps, with private financing structures costing only about 66% greater than public. The current spread is now +500‐
600bps for standard commercial finance structures, or potentially >150% higher than current public financing costs. The changes in relative cost between the public and private options are due to: • An opening up of the Build America Bonds (BAB) market since the beginning of 2009 under the American Recovery and Reinvestment Act (ARRA) of February 2009. This change reduced public sector borrowing costs by 100 to 150 basis points. • The tax equity market has shrunk significantly since October 2008, and required internal rates of return (IRRs) by tax credit investors have increased by >25%, although have shown signs of returning to more normal levels in recent months. • While the reduction of the Fed lending rate to at or near zero did reduce prime rates after the economic crisis at the end of 2008, project debt11 from commercial lenders in the wind energy space remains more expensive than before due to perceived riskiness of wind project debt and a more conservative underwriting strategy from lenders. From a structural simplicity standpoint the preferable solution for direct ownership and offtake of a wind farm asset would be public financing option: lower cost of debt; possibly no equity required; and less complex structurally in general. However, there is a significant hurdle associated with the public finance option that currently faces the District when considering publicly financing such a project, namely the legislated caps on the District’s ability to issue a greater amount of debt: • The Home Rule Act of the District limits total general obligation debt service to 17% of local source revenues12 • A new Council act adopted in 2008 and amended in FY2010, called the “Cap Act”, further limits a broader range of District government debt service to 12% of expenditures13 • Currently DC is up against the 12% cap under the Cap Act, and therefore has little leeway to issue any form of bond that will increase debt service under this Act 11
“Project debt” is a term that refers specifically to loans that are secured by project assets and revenues only. Specifically, section 603(b)(1) of the Home Rule Act (DC Official Code § 206.03(b)(1)). 13
“Cap Act”: District of Columbia Code § 47‐334, et. seq. (DC Law 17‐360; amended Fiscal Year 2010 Budget Support Second Emergency Act of 2009 (Enrolled Bill 18‐443)). 12
38 | P a g e •
•
Draft Wind Energy Assessment District Department of the Environment April, 2011 Local source revenues (and thus expenditures) declined precipitously at the end of 2008 through 2009 – regular revenue recalculations are conducted and if greater revenues are predicted, the Cap Act ratio will improve possibly opening up opportunity The DC CFO’s office is on the record indicating the CFO’s and Council Chairman’s opposition to any exemptions from the Cap Act14 Further, under the private partnership option a separate difficulty must be overcome, that if private capital is brought in, and tax credit equity is used as part of the financial structure, it is unclear whether and how the District could legally benefit from these subsidies based on the statutory restrictions placed on tax‐exempt owners and in some cases even lessees in such transactions. In summary, the District must work creatively to open avenues of financing for such a project that comply with the complex regulations governing tax‐exempt entity participation in such transactions, and the restrictive legislation surrounding new bond issuances for capital projects such as wind farms, even if the resulting farm would be financial worth it for the District. The following section describes the various financing options available in more detail, and presents an analysis of options to overcome the current barriers mentioned above. B. Financing Options A brief discussion of the various forms of financing and support available to the District for development or acquisition of a wind farm is provided first, followed by an analysis of the realistic potential for use in the District’s plan to own and offtake energy from a wind facility directly into their electricity portfolio. 1. Public Bonds Public bonds would be the simplest and possibly the cheapest structure available to the District for financing the project. Up to 100% of project costs could be financed in this way, requiring little or no upfront equity. Backed by a general obligation (e.g., “full faith and credit”) style guarantee and concomitant investment grade rating, such an issue would achieve long‐term tenors (20+ years) at current District borrowing costs, now below 4.0%.15 However, as was noted above, this option currently appears off the table unless an upward revision in expected local source revenues is noted (thus reducing the ratio controlled by the Cap Act), or an exception/change to the Cap Act is made. 2. Project Bonds 14
15
Email from Marcy Edwards, District of Columbia Senior Financial Policy Advisor, 1 June 2010. Verbal discussion with Marcy Edwards, District of Columbia Senior Financial Policy Advisor; 23 April 2010. 39 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Project or “project revenue” bonds, issued by the District and secured by the revenue stream generated by the project and project assets only, would not be restricted under Cap Act limitations. Project revenue bonds would be more expensive than public bonds, but possibly less expensive than standard commercial loans. However, for two reasons this type of structure may be more difficult than in a standard wind transaction. First, the revenues in this project are not from a power purchase agreement (PPA) but instead based on a projected savings to the District over time. Establishing an appropriate baseline to accurately determine savings that would achieve good quality ratings from ratings agencies is a difficult proposition, although some precedent may be found in energy service companies (ESCOs) providing energy efficiency financing.16 Second, anecdotal discussions with prospective financiers17 in the market indicate that even if project assets were pledged, further guarantees would likely be needed given the small size of the proposed wind project combined with the unusual aspect of revenues being generated by “savings” and not a long‐term PPA.18 DOE loan guarantees, discussed below, would likely not be enough on their own to secure project bonds as a financing source for such a project, but would be helpful.19 Underwriting criteria surrounding the successful issuance of project bonds and/or commercial debt in wind transactions are discussed further below. 3. Tax Credits20 The preferred structure among private developers and financiers in the wind market historically has been a Production Tax Credit (PTC) “flip” structure. Between accelerated bonus depreciation allowances, a 2‐3% equity cash preference from the project, a fair market value flip price, and the current $0.021/kWh credit available, the PTC can subsidize >65% of a given project’s total development costs, depending on the production capability of the particular project and an investor staying in the deal for the full 10 years21. Based on a severe contraction in the current tax equity market due to the economic recession since late 2008; current demand for tax equity exceeding supply; more reticence in the commercial loan market; and resulting increased return expectations from tax equity investors, the total subsidy figure is generally not exceeding 50% under present market conditions.22 16
Phone conversation with Arthur Simonson, Managing Director, Fitch Ratings Services. 3 September 2010. Lee White; Tom Cochran and Richard Corrigan, DOE Loan Guarantee Program Officers 18
Lee White; Tom Cochran and Richard Corrigan, DOE Loan Guarantee Program Officers 19
Tom Cochran, DOE Loan Guarantee 20
Room for Tax Equtiy in a Cash‐Grant World, North American Wind Power; by John Marciano and Eli Katz of Chadbourne and Parke LLP; May 2010. Copyright Zackin Publications. Update: Tax Equity and Debt Markets, Project Finance, NewsWire; Chadbourne and Parke, LLP, February 2010, pgs 24‐39. Update: Tax Equity Market, Project Finance, NewsWire; Chadbourne and Parke, LLP, April 2010, pgs 8‐19. 21
In a change from past legislation, ARRA 2009 legislation allows a PTC investor to exit a partnership prior to the 10 year term. 22
Ibid., citation 15 17
40 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 A sale‐leaseback structure, as opposed to the more common “flip” structure, has recently become more prevalent in the market. Under such a structure the developer sells the project to a tax credit investor, who then leases the project to the developer. The developer has a PPA with an accredited offtaker, and the model tends to work best in markets with relatively high retail rates for electricity and/or strong RPS requirements of energy suppliers and utilities. Current law does not permit government (or tax‐exempt) entities to utilize tax credits in any form as either an owner or in most cases a lessee of a wind project23, and therefore any recommendation as to the ability of the District to utilize alternative structures would require the counsel of experienced tax attorney capable of issuing a formal tax opinion. However, an analysis of structures that upon first analysis have potential to allow the District to take advantage of these subsidies indirectly and in accordance with current regulations are described further in Section IX ‐ Transaction Structuring Options. 4. Treasury Cash Grant24 Another option stipulated under the American Recovery and Reinvestment Act of 2009 (ARRA) is to elect the Investment Tax Credit (ITC) and then request a Treasury cash grant in lieu of the ITC. Like the PTC, there may be structures available discussed in Section IX ‐ Transaction Structuring Options that would allow the District to indirectly access the cash grant. Again, for the purposes of this report, until such counsel is issued the authors do not offer comment on the legality of such options, only initial financial viability analysis in the event it would be possible. Another issue with the Treasury cash grant option is timing – for the District’s purposes, under current regulation a project must spend a minimum of 5% of total eligible construction costs by year 31 December 2010 and complete the place‐in‐service (PIS) deadline by 2012 to qualify for and retain the cash grant. It is unlikely the District will be able to meet these current deadlines, and thus this subsidy will not be available to the District under any structure unless the program is extended to future years. It is unknown whether, when and under what rules Congress will extend the program at time of writing. 5. Other Tax Equity (from Depreciation/NOLs) In private‐sector only deals, the value of depreciation (specifically, its ability to generate valuable net operating losses (NOLs) for tax purposes) alone, beyond the tax credits or treasury 23
Commercial Finance: The Dark Arts of Leverage, Tax Equity, Leases and More, by Ed Feo and Stephen Tracy; Solar Power International 2009 Conference Presentation; October 26, 2009. 24
Ibid., citation 14. 41 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 grant generated by a project, can attract a tax investor to pay equity up‐front for the resulting NOLs irrespective of any credits involved. This allows a structure in which, at least in the current private sector market, tax equity is being used in conjunction with Treasury grants as a funding source, which commonly achieves a gross subsidy level of >50% of total capital costs of a wind project (greater than what is currently being achieved using the PTCs due to poor market factors, with less structural complexity/cost – thus its present popularity). Similar to tax credits, however, current law does not permit government (or any tax‐exempt) entities to directly utilize tax credits in any form as either an owner or in most cases a lessee of a wind project25. This report does analyze structures that include this funding source that may be possible to achieve indirect benefits from these subsidies, but offers no official tax opinion on the ability of the District to legally utilize it. 6. Commercial Loans Commercial loans are generally available in the current market for wind project development and acquisition, as the market has slowly become more liquid compared to the crisis at the end of the 2008 and the very slow market in 2009. It is unclear, however, whether or not a commercial loan could be arranged for a project whose revenues are dependent on savings, instead of set revenues from a PPA, as this adds another moving part to the risk profile of a wind project compared to a fixed price PPA. It is likely that this structure would be acceptable to some lenders, with the ESCO market and even merchant power market providing a comparative – also, discussions with commercial providers thus far to determine the underwriting potential and possible rates associated with such a project have revealed that debt service coverage (DSC) ratios should be 1.4+ with adequate reserves (up to .25x total debt service), with rates at 30‐day LIBOR + 600‐800 basis points, or roughly 6.26 to 8.26%. Thus, a key to securing commercial debt for such a project will be the provision of a guarantee for a large majority percentage of the amount of savings predicted to be generated by the project. This would likely be done by stipulating a minimum guaranteed set‐aside and a specific formula for measuring “savings” for underwriting purposes that would accrue regardless of whether predicted savings materialize as planned, and utilizing other programs such as the DOE loan program as further supplements.26 7. Sustainable Energy Trust Fund (SETF) 25
Commercial Finance: The Dark Arts of Leverage, Tax Equity, Leases and More, by Ed Feo and Stephen Tracy; Solar Power International 2009 Conference Presentation; October 26, 2009. 26
Phone discussion, Lee White. 42 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 A set‐aside from the Sustainable Energy Trust Fund (SETF), a fund capitalized by an assessment on the natural gas and electricity companies based on sales, and used for a variety of energy‐
efficiency, renewable energy, and low‐income energy programs, could be escrowed in a reserve account in the initial 2‐5 years of the project as security for any wind power bonds issued by the District in order to maximize the bond rating. Representatives of the DOE loan guarantee program suggest that such a set‐aside in a project’s early years would be beneficial to a bond’s ratings (and total financing cost) in the market if not secured by local source revenues from the District.27 8. DOE Loan Guarantees The District as a government entity can legally be a "Project Sponsor" under the DOE loan guarantee program, and could be eligible to receive a DOE loan guarantee for this project regardless of whether it uses a 3rd party private sector partner or an entity created by the District. 28 The DOE Loan Guarantee program may be an important tool to offset the “savings”‐
based nature of the predicted revenue stream as well as the premium in the commercial lending market that would otherwise be associated with term debt to such a project. That said, no other similarly structured projects, with a non‐utility public (e.g., municipality) Project Sponsor seeking to own and directly offtake wind power, have yet been considered under the current program. In fact, there has been no other similar project proposed to the DOE at all, but representatives of the Loan Guarantee Program have verbally confirmed that the DOE is open to the concept and willing to meet with District representatives at any time to work through financing issues of the project. 29 There are two types of loan guarantees: conventional technology (Section 1705) and innovative technology (Section 1703), with a total of roughly $4billion to deploy collectively. The difference between the two types of guarantees is small and both pools of money could be accessible by the District. As noted above, an SEU set‐aside from the SETF, or using funds allocated the District by the DOE under the SEP program would be viewed favorably by the DOE and bond rating agencies. A key provision, however, is that loan guarantees cannot be used with tax‐exempt debt, but can be used with taxable bonds. 27
Phone discussion with Tom Cochran and Richard Corrigan, Senior Loan Guarantee Advisors for the DOE, on 7 June 2010. 28
Phone discussion with Tom Cochran and Richard Corrigan, Senior Loan Guarantee Advisors for the DOE, on 7 June 2010. 29
Phone discussion with Tom Cochran and Richard Corrigan, Senior Loan Guarantee Advisors for the DOE, on 7 June 2010. 43 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 In any case the capacity of the District’s project is quite small (50MW) by wind power project standards, and such a small project would be at a disadvantage with ratings agencies, as well as the DOE loan guarantee program, under a bond issuance pledged only from project revenues and assets. As noted in the section describing underwriting criteria for wind projects, this may become even more difficult if the revenue that secures a project is generated from "savings" and not a true PPA. The fees associated with the loan guarantee program are set out clearly in the solicitation announcements30 (see Attachment C of solicitation number DE‐FOA‐0000140), and a preliminary analysis indicates they are not prohibitive even at the size of 50MW because a majority are calculated as a percentage of project costs (instead of flat fees). However, timing could be a difficulty unless the District begins engaging the DOE early in the process to ensure a timely bid acceptance. The ability of the DOE to evaluate whether and exactly what type of a guarantee might be possible would depend on the final financing structure and project‐specific details (100% public bond issue; using PTCs; acquisition of existing farm using commercial finance, etc.) as to what they could provide exactly, and how they could structure it. The DOE Loan Guarantee officers with whom the authors spoke indicated their clear desire to work with the District through the process on offering any financing guidance the District may need. 31 9. Clean Renewable Energy Bonds (CREBs)32 CREBs will be a small amount but still important source of financing for any direct‐offtake wind project ultimately taken on by the District. CREBs (IRS Notice 2009‐33) were issued in the last round at $2.4billion: • of that, $800mil was issued for public entities such as municipalities, counties, etc • of the $800mil public entity allocation, the decision of allocation was controlled by the Treasury • the Treasury allocated the funds according to amount of request: smallest (first) to largest (last) • in that round, a $2.7million allocation was the largest amount allocated to any one project; anything above that figure did not receive any CREBs The key point of above is that if the rules are the same in the next round, the District should likely not ask for more than $2 million for its allocation to make sure it has a chance of getting some funding. While this is a small amount, it would have the impact of lowering total 30
Attachment C of solicitation number DE‐FOA‐0000140 provides a complete description of DOE Loan Guarantee fees. Tom Cochran, Richard Corrigan. 32
Phone conversation with Zoran Stojanovic, CREB Program Officer at the IRS. 31
44 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 financing costs between 25‐50 bps, depending on the structure used. It is not clear when a new issuance of CREBs will occur and is dependent on guidance from Congress. The rules may change in the next round so it will be an important point to monitor. 10. USDA Rural Energy for America (REAP) Grants/Loans/Guarantees33 The United States Department of Agriculture (USDA) REAP program, under the new 2008 Farm Act, provides grants, loans, and loan guarantees for the development and purchase of renewable energy systems. Loan guarantee limits are $25 million or a maximum combined award amount up to 75% of the cost of the program, whichever is less. Eligible project costs under REAP loan guarantee and grant programs (or combinations thereof) include purchase and installation of equipment, construction, permits or fees, professional service fees, feasibility studies and technical reports, business plans, etc. In the 2008 Farm Act Congress increased mandatory funding for REAP to $255 million over four years. In 2009, the USDA guarantee fee was 1% of the guaranteed portion of the REAP loan and the annual renewal fee was 0.25% of the guaranteed portion of the loan. In addition to loan guarantees, REAP also provides grants. Grants for feasibility studies are a new feature this year. The maximum amount of a REAP grant is $500,000 maximum of eligible project costs for renewable energy system grants; $50,000 for feasibility studies. In 2009, 20% of REAP funding was set aside for grants of $20,000 or less and USDA added 10 points to the application score for these projects. As mentioned above, USDA has not yet issued a funding notice for 2010, but may use similar ranking criteria as in 2009. 11. RECs – Presale Another option that may be available is pre‐sale of RECs in which a project owner sells multiple years worth of RECs upfront at a negotiated discount. If a standard REC contract might conservatively add $0.015 per kWh of revenue over 10 years, or about $20 million gross in a 50MW project with 30% capacity factory. Discounting this 10‐year revenue stream at 10%, the present value of that revenue stream would be roughly $12 million. A REC pre‐sale might be negotiated on the basis of some margin less than $12 million, perhaps 16% for net REC pre‐sale proceeds of approximately $10 million. The extent and under what circumstances this strategy could be using given the District’s goal of owning and directly offtaking power from a wind power asset must be considered. 12. Qualified Energy Conservation Bonds (QECBs) 33
See http://www.rurdev.usda.gov/rbs/busp/9006grant.htm; http://www.nixonpeabody.com/publications_detail3.asp?ID=3171 45 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 In 2009, the District received an allocation of $6.14 million in QECBs from the Federal government from a total allocation of $3.2 billion allocated to states and territories by Congress based on population. The QECB program provides Federal funding for a wide variety of clean energy and energy efficiency purposes, to be decided by the allocatee. With respect to the project under consideration by this report, the QECB allocation received by the District could be used to fund capital expenditures for construction or purchase of a wind farm to offset the District’s electricity consumption should the District so choose. C. Major Funding Sources – Nominal Cost Analysis A breakdown of the major financing options available to fund the project and their associated nominal financing cost is described in Table 4 below: 46 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Type Sub‐Type PUBLIC Public Bonds34 Com‐
plexity Low Loan Term 20‐25 years
Financing Cost 3.5‐4.5% Med Ongoing 4‐6%35 PRIVATE Grant in lieu ITC Med 60 days 0% Investment Tax Credits (ITC) High 6 years 8‐12%* Production Tax Credits (PTC) High 7‐10 years 9‐14%* Commercial Loan Med 10‐20 years
7‐9% Owner Equity Low n/a 15%+ Project Bonds Notes • Backed by the credit of the District • Would affect the Cap Act • Backed by the revenues generated by the wind project • Would not affect the Cap Act • Quicker with less trans. costs than other private options • Applicable only for greenfield development • Applicable only for greenfield development • Not currently used in the market b/c T. Grant is preferable • Cost and risk is higher than ITC • Applicable only for greenfield development • Assumed funded by traditional equity and debt only • Highest cost capital due to highest risk Table 4: Options to finance the acquisition or development of direct‐offtake wind generation *Note: This represents required ROE to tax credit investors. It does not necessarily represent true cost of capital to the District, because the two largest components of this figure come from tax credits and accelerated depreciation, a product of direct government subsidy, neither of which could be taken by the District, and much of which would either go unused or be deferred significantly if a private developer only. Appropriate net cost of this tranche to the District in a transaction would most likely be between 0‐5% depending on final deal specifics. D. Comparing Potential Capital Structures The true financing cost associated with a given capital project is determined not by the nominal amount of specific funding types but instead by averaging the “real” (economically speaking) opportunity cost of each component of a capital structure based on its proportion within that structure, also called weighted average cost of capital (WACC). This is important because it allows 34
Secured by the local source revenues of the District (i.e., tax base) and would therefore generally fall under Cap Act limitations. 35
Based on the borrowing rate of the PACE revolving loan fund quoted from DC Memorandum subject “Fiscal Impact Statement – ‘Energy Efficiency Financing Act 2009’”, 14 Dec 2009. These rates may be higher in the case of a wind project. 47 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 comparison of different types of capital structures, or combinations of different funding types. Calculating the WACC of a given capital structure is straightforward, however determining what the true cost of financing should be for each component of a capital structure can be imprecise in some cases, particularly in the case of tax‐based subsidies such a tax equity, depending on the project sponsor and complexity of the structure. Thus, any calculated WACC at this stage will be an estimation based on assumptions that can establish a conservative range and be applied in a financial model. The goal of such an analysis is not to get a precise figure, but a comparative understanding of the net cost to finance the District’s wind project under different capital structures. As a final note, this analysis assumes that current legislation will be extended as‐is to the time of project development, and does not try to predict future changes in regulation. This is only one possible scenario however, as significant legislative changes affecting financing of wind farms may have been enacted by that time or other provisions may have been allowed to sunset. When determining which capital structure to use, the first step is to determine the most likely combinations of funding types that might be used to finance the wind project. Based on an initial review by the authors, for each capital structure there is likely to be some combination of tax equity, developer equity, Treasury grants, CREBs, District bonds, commercial loans36, and small grants. For any commercial loans included there may need to be a DOE loan guarantee attached to achieve acceptable rates as the authors have assumed for this analysis. For a capital structure that includes anything other than CREBs, District bonds, or small non‐Treasury grants, such structure will require some form of private‐sector partnership for some portion (or some time period) of ownership. That aspect is detailed and analyzed further in Section IX: Transaction Structures as it will have a separate effect on project cost. Thus far five potential capital structure scenarios have been determined as representative of likely capital structures to finance the construction of a new wind facility in which the District is either direct owner or otherwise partners with the private sector. Note that if the District does not own the wind farm, but instead serves as an offtaker in some form for a portion of the project life, CREBs are not likely an option, but may be replaced by the addition of other small subsidies (such a RZFBs, NMTCs, etc) depending on the details of the specific project. “CREBs” is thus used as a rough estimation of the inclusion of at least one these small minority portions of the capital structure, and in any case accounts for just slightly more than 2% of capital costs. 1. Treasury grant, CREBs, commercial debt: 36
Throughout the text the authors will generally use “commercial” loan to be long‐term permanent debt from a private bank commonly used in development finance to take‐out construction loans, to distinguish it from any for of bond issued by the District. 48 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 This structure assumes that a construction loan combined with some amount of developer equity will be raised to finance construction. An allocation of CREBs in conjunction with a long‐
term commercial loan will take out most of the construction loan, while a Treasury grant will take out the remainder of the construction loan along with any remaining developer equity as desired. 2. PTC tax equity, CREBs, commercial debt, developer equity: By including PTC tax equity the Treasury grant option is excluded. Similar to the first structure, a construction loan combined with some amount of developer equity will be raised to finance construction. An allocation of CREBs in conjunction with a long‐term commercial loan will take out a minority of the construction loan, while tax equity from PTCs will take out the remainder of the construction loan along with any remaining developer equity as desired down to 1%, as in a PTC structure the project sponsor must maintain at least 1% ownership of the project until the “flip”37 in later years. 3. Treasury grant, CREBs, NOL tax equity, commercial debt: Under this structure a private project sponsor would use a small amount of developer equity and a 95% Treasury cash grant bridge loan for the 60 (or greater) days until the project can secure the grant. A construction loan would be taken out for the remainder, and by 90 days after placed‐in‐service (PIS) date a combination of CREBs, tax equity (based on NOLs generated by depreciation and tax losses only, not credits) along with a commercial loan issue would then take out the rest of the construction loan and potentially the developer equity if desired. 4. Treasury grant, CREBs, NOL tax equity, District bonds: Similar to structure 3, a private project sponsor would use a small amount of developer equity and a 95% Treasury cash grant bridge loan for the 60 (or greater) days until the project can secure the grant. A construction loan would be taken out for the remainder, and by 90 days after placed‐in‐service (PIS) date a combination of CREBs and tax equity (based on NOLs generated by depreciation and tax losses only, not credits) would take out some portion of the construction loan, while a minority District bond issue (instead of a commercial loan) would take out the rest of the construction loan and potentially the developer equity if desired. 5. CREBs, District bonds: This is the least complex of the structures identified here, and is the only option that would require no private‐sector ownership partnership should the District choose to move forward. The District would raise 100% of the development costs from a public bond issue using a G.O.‐
type obligation (or some alternative structure/guarantee acceptable to ratings agencies). The 37
This would occur sometime between year 6‐10 as is allowable under current regulations, as soon as the tax equity investor has achieved their required return. 49 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 District would apply for a CREB allocation at some point prior to completion of development, and use the proceeds to take out that portion of the bonds. E. WACC Analysis – Understanding Capital Cost Interaction Figure 8 below summarizes the calculation of weighted average cost of capital (WACC) under five different scenarios given just under $95 million of total capital costs. (Note: This section is a preliminary analysis to understand how different tranches of capital within some likely capital structures might affect financing costs of the project. More specific and detailed transaction structuring and modeling analysis is carried out in later sections of the report.) 1. TREASURY GRANT w/ Commercial Debt
capital cost WACC calc
Capital Structure
T.Grant
26,275,000
0.75%
0.21%
CREBS
2,000,000
0.00%
0.00%
Tax Equity
‐
0.00%
0.00%
Permanent Debt
66,401,908
7.25%
5.08%
Equity
‐
15.00%
0.00%
94,676,908
WACC =
5.29%
4. TAX EQUITY w/ T.Grant and Public Bond Debt
Capital Structure
capital cost
T.Grant
26,275,000
0.75%
CREBS
2,000,000
0.00%
Tax Equity
30,964,785
6.68%
Public Bond Debt
35,437,123
3.95%
Equity
‐
15.00%
94,676,908
WACC =
0.21%
0.00%
2.18%
1.48%
0.00%
3.87%
2. PRODUCTION TAX CREDIT (PTC) w/ Commercial Debt
Capital Structure
capital cost
T.Grant
‐
0.00%
0.00%
CREBS
2,000,000
0.00%
0.00%
PTC
44,427,735
6.68%
3.13%
Permanent Debt
47,042,943
7.25%
3.60%
Equity
1,206,229
15.00%
0.19%
94,676,908
WACC =
6.93%
5. PUBLIC BONDS (e.g., BABs)
Capital Structure
T.Grant
‐
CREBS
2,000,000
Tax Equity
‐
Public Bond Debt
92,676,908
Equity
‐
94,676,908
0.00%
0.00%
0.00%
3.87%
0.00%
3.87%
3. TAX EQUITY w/ T.Grant and Commercial Debt
capital cost
Capital Structure
T.Grant
26,275,000
0.75%
CREBS
2,000,000
0.00%
Tax Equity
30,964,785
2.90%
Permanent Debt
35,437,123
7.25%
Equity
‐
15.00%
94,676,908
WACC =
capital cost
0.00%
0.00%
0.00%
3.95%
15.00%
WACC =
0.21%
0.00%
0.95%
2.71%
0.00%
3.87%
Figure 8: WACC calculation summary under different types of financial structure scenarios by 90 days after PIS date. Several important assumptions should be highlighted to understand this analysis: • The permanent debt capital cost figure of 7.25% is intended to represent an all‐in points, fees, and real interest rate for the loan. Figures in current private PTC flip deals are ranging roughly around 30‐day LIBOR + 600 bps premium + 800 bps. 50 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 • CREBs were set at $2 million per the discussion contained in under section B.8. above. • The Treasury grant technically does not carry any interest rate, but a small one is included here (0.75%) on the assumption that a Treasury grant “bridge loan” would have to bridge the gap for 60 days, or until the Treasury grant would be received and take out the construction loan, a common practice in the present private‐sector market. • Only structures 2 and 3 would require initial sponsor equity to remain in the deal beyond placed‐in‐
service (PIS) date, at an amount of roughly 1% of total development costs. Required return for that portion was set at 15%. • True net tax equity (TE) capital cost in a given deal is a very difficult item to gauge. It is not the same as the required return on capital by the tax equity investor (which ranges from 8‐15%) because a large portion of the return (exact amount depending on the particular transaction structure) is generated purely by tax benefits. The reduction compared to nominal TE required return would be even greater if the project sponsor could use few or no tax benefits (a common situation) because the relative opportunity cost would be lower. In such case, the project would have to be owned by an entity with passive income and would have to carry forward any tax credits and net operating losses (NOLs), primarily from the accelerated depreciation benefits, to future profitable project years. The true cost to a project, then, would take into account a 2‐3% equity cash preference (annual cash return on invested equity, roughly equal to 1.5‐2.25% ROE in a 10‐year deal) plus some premium for the opportunity cost of tax benefits the project may have been able to use in later time periods but had to give up (e.g., applying some portion of NOL's to later profitable years). That premium depends on what portion of the benefits the project could use, the amount of the particular benefit, and when the project would realize it. For this iteration the authors estimated the premium would be 0‐3%, yielding a true net financing cost of a given tranche of TE between 1.5‐5.25% depending on the structure. • Total subsidy rates under structures 3 and 4, in which the Treasury cash grant is combined with tax equity for the tax losses in a public private partnership, have intentionally been kept below 60% of total capital costs. F. Cost of Capital: Results Summary The value of this analysis is that it allows relative comparison of the real cost of different capital structures. It also highlights two similar structures (options 3 and 4) with a financing cost comparable to a straight public bond issue. 51 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Given conservative assumptions and using the public bonds option as a baseline to compare financing cost, we also can estimate a net financing cost for the tax equity tranche below in structure 4 in which lower net capital costs than the public bond option might be achieved. Similarly, in option 3 where commercial debt is used instead of public bonds for the permanent debt portion (a more likely scenario), the same upper limit for net tax equity financing can be assessed. The results are, for option 4 based on the assumptions above, such a structure may be cheaper than long‐term public bonds if: • the net financing cost to the District of the tax equity tranche is less than 6.68% (even greater than the conservative end of our current net financing cost assumptions for tax equity) Additionally, for option 3 based on the assumptions above, such a structure may be cheaper than long‐
term public bonds if: • the true net financing cost of the tax equity tranche is below 2.90% (an aggressive but potentially applicable assumption). The bulk of the possible savings under both options comes from the potential to combine and maximize low‐cost public bond funding and Federal renewable energy subsidies as stipulated under the American Recovery and Reinvestment Act 2009. And while option 4 does still use public bond debt as part of the capital structure and would be more complicated than a straight public bond issue by the District, the bond issue would be relatively smaller. The follow on question is whether and under what circumstances either capital structure is legally possible, and in the case of option 4, whether public bonds could be included at all. Thus, the results presented in this section should be considered comparative only, reflective, but not precise indicators, of the actual cost to finance the wind farm. This analysis is also useful in thinking through realistic financing options and developing more complete transaction scenarios as discussed in the following sections. This initial comparative analysis is explored in more specific detail in the following sections as realistic transaction structures are determined, and the most likely financing scenarios based on currently available information are modeled. IX. Transaction Structuring Options Transaction structure, as opposed to capital structure, refers to how the District will execute a given capital structure, not just the mix of particular funding sources used. Most importantly, it refers to the legal ability and ultimate choice to complete a wholly public transaction, as in the case with a 100% public bonds issue, 52 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 or to partner with the private sector in some way to gain access to various forms of tax‐based wind energy subsidies. Two major transactional hurdles must be overcome in order to complete this project depending on whether a publicly or privately financed transaction is desired. The key hurdles are: If a publicly financed transaction: 1. a structure that complies with the District’s 2008 Cap Act limitations must be found. If privately financed transaction: 2. a legal structure must be identified that complies with all relevant tax‐based subsidy regulations while maximizing the indirect benefits of such subsidies for the District. A. Publicly Financed Transaction ‐ Potential Solutions Two potential structures that may allow the District to issue public bonds within the limitations of the Cap Act (and that would meet with DOE Loan Guarantee approval and could be underwritable in the market) would be: o Moral Obligation Guarantee (or "appropriations" guarantee): The guarantee in this case would be, in the event of default, appropriations to fund the shortfall or default would be available subject to legislative appropriation. The Council of Development Finance Agencies (CDFA) defines it as38: “Moral obligation bonds do not carry the full faith and credit pledge of the obligor (i.e. state or locality). Rather, the moral obligation requires the issuer to maintain a debt service reserve fund at a specified reserve requirement, typically maximum annual debt service, and report any deficiencies that arise to an appropriate official of state or local government. The official then is required to request an appropriation from the legislative body to make up any shortfall. Since there is no legal requirement to make the appropriation, timely payment depends on the obligor’s willingness to support the debt.” Because such a guarantee is short of a "full faith and credit" guarantee and would theoretically not fall under the Cap Act limitations, but this compromise may be good enough for ratings agencies to issue adequate ratings for bond holders on such bonds39. In such cases ratings agencies usually reduce the rating on the bond one full step below the issuer’s ratings (in the case of the District such a bond would be rated below the District’s current A1/A+ rating). 38
39
http://www.cdfa.net/cdfa/cdfaweb.nsf/pages/sep2003tlc.html Tom Cochran and Richard Corrigan, DOE Loan Guarantee Officers. 53 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Insurance coverage is available in the municipal real estate lease market to guarantee the timely payment of rent/lease payments for the term of the lease in the event of budget non‐
appropriation by the agency (assuming such payment is a “moral obligation” guarantee), and such precedent may be applicable to an operating wind asset as well. o
Revolving Fund: A “revolving fund” structure of approximately $35 million has been set up for the District’s Property Assessed Clean Energy (PACE) program which, according to a Dec 2009 public memorandum written by District CFO Natwar M. Gandhi, allows that program to avoid impacting the debt cap limitations stipulated under the Cap Act.40 This is a set amount of capital from which initial loans are made. Repaid principal and interest payments from the initial set of loans replenish the fund, allowing a self‐sustaining fund from which to issue loans, secured primarily by the credit of the borrowers. This option is being investigated further to understand how and under what circumstances a similar concept or structure might be applied to the wind farm project and still meet Cap Act guidelines. B. Privately Financed Transaction – Potential Solutions Two possible structures that the authors have identified thus far that may allow indirect use of available tax‐based incentives for public‐sector entities, and which in the authors’ opinion warrant further legal analysis, are: o Sale‐leaseback: The District would partner with a developer, who would sell the development project to an investor who can utilize the various tax subsidies, and who would then lease the project back to the developer over a set period of time (likely through a lower‐level project entity). The developer through than entity would lease the facility to the District. The District would pay a lease payment to the developer, who would then pay a lease payment to the investor. The developer would be responsible for maintaining the facility. At the end of the lease term, which is negotiable amongst the partners, the wind farm asset would revert to ownership to either the developer or the District at a predetermined price. This is a highly structured contract‐based option that, like a PPA, all payments could be known and fixed in advance. From a legal perspective, this is the option that carries risk from a tax‐based subsidy perspective. There may be other structures with similar concepts that the authors have yet to identify that appropriate legal expertise could assist identify. o Prepaid PPA: The District would issue bonds or other financing to pay upfront at some negotiated discount for an amount of electricity production that can be guaranteed within a certain confidence level (e.g., 99% confidence interval, “P99” structure) over the prepaid term. All remaining power would be sold on the spot market or in a separate PPA to either the 40
Fiscal Impact Statement – “Energy Efficiency Financing Act of 2009”; Memorandum, Natwar M. Gandhi, CFO; December 14, 2009. 54 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 District or a separate offtaker; if desired, less than 100% of projected P99 power can be pre‐
paid, and at end of the prepaid term the project can be acquired by the District. o
Standard PPA: The District could seek to enter a fixed‐price PPA with a private developer/owner of a wind farm facility for a period of up to 20 years and an option to purchase at end of term as appropriate. This would require no upfront capital, create long‐
term electricity price certainty, and pose very little or no develop risk to the District. In fact, all aspects of this option, like the pre‐paid PPA, could be requested publicly in an RFP process and then negotiated upfront with the developer. C. Analysis of the Partnership Options The purpose of this section is to analyze the ways in which the options above could be used to allow the District to finance development or acquisition of a wind farm. Other than to note an economic premium associated with the privately financed transactions above that will be charged by the private sector in return for risk sharing and use of their equity, this report does not provide nor constitute any guidance on the legality of such solutions. The authors do analyze the potential financing cost of such structures assuming they could be utilized (see Section X), using in particular sensitivity analysis to understand how large the private‐sector transaction premium could be and still achieve a financial feasibility under conservative assumptions. Use of a moral obligation guarantee may prove to be the most useful of the four options discussed above. It may allow the District to issue bonds at a credit rating acceptable to the bond market while still (depending on final legal opinion) complying with the terms of the Cap Act. The limitation on this option would then become what is the largest amount the District is willing to establish and guarantee as a debt service reserve. Assuming a term of 20 years and an interest rate of 5.25% (up to 150 bps higher than current District borrowing rates, reflecting the full‐step ratings downgrade), and principal amount of $90 million, the required annual reserve would be roughly $7.4 million. This reserve would need to be available every year for the term of the bond, and if any portion utilized, would have to be replenished the following year. However, the bond would still be non‐recourse in that, should the District become unable to pay the loan due to the project not generating the predicted savings, the bondholders carry that risk. Using a sale‐leaseback arrangement may also prove difficult in a wind project scenario. Sale‐leasebacks are usually used for real estate with predictable rents or solar where a more predictable amount of electricity is generated. Electricity produced by wind can vary widely from day to day, making monthly rental payments difficult to establish, a key requirement of the leaseback structure. Thus, the product delivered in such an arrangement would need to be combined with a power firming solution (see Section X). 55 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 One financing issue faced by any project is the nature of the revenues. All revenues accruing to the District would in the form of net savings on the electricity bill – that is, reduced expenditures compared to future expected costs under the direct generation and offtake scenario (as opposed to a specific PPA contract in which expected revenues are explicitly specified). As such, unless contractually guaranteed or insured, revenues based on future savings are generally viewed as more risky by the capital markets, the reason being its reliance on a long‐term “business as usual” prediction requirement. One option to overcome this issue is to contractually set a baseline of future energy costs that spells out the exact reference energy cost comparison figure during the project life to which the cost of the project would be compared. A similar structure is used in energy saving performance contracts, wherein an energy service company (ESCO) conducts energy‐efficiency improvements and is paid based on savings compared to baseline energy consumption projected into future years. The District may be hesitant to establish a long‐term (e.g., 20‐yr) baseline when current electricity supply contract lock‐ins are only three years. Further, a baseline founded on future energy price predictions may be a difficult sell, both politically and to capital markets, despite common and reliable historical trends that energy prices track changes in CPI which in the U.S. has been relatively steady at around 3% for decades. If a future savings‐based revenue source is ultimately deemed unacceptable by capital markets, utilizing a pre‐paid PPA structure may provide two solutions at once. On the one hand, it would allow the District to indirectly take advantage of private‐sector tax subsidies normally prohibited tax‐exempt entities; on the other, it would be a contractually guaranteed payment, at least solidifying the baseline cost of power acquisition and perhaps making a savings‐based revenue source more attractive to the capital markets. However, this structure would still require a large up front capital payment. Section VIII option 5 analyzes the pre‐paid PPA option for the District in greater depth. X. Financial Feasibility Analysis A. The Baseline – Business as Usual Because the expected revenues to be generated by the project will predominantly be future savings in the form of avoided costs, it is important to establish a conservative and reasonable baseline of future electricity costs the District would expect to pay during the lifetime of the wind farm assuming the wind project were not built. The obvious starting point is the current price the District pays for electricity generation under its contract with WGES, $0.087 per kWh energy delivered, $35 million per year (not including T&D costs), or over $700 million over the 20‐year life of the average wind farm assuming 404 million kWh consumed per year (the District’s annual consumption during FY 2008‐2009). 56 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 It is further unlikely that the total amount of electricity consumed by the District will be the same over the course of 20 years. The authors made an assumption that the total amount of electricity consumed by the District will change by an amount equal to the annual change in GDP less an energy efficiency reduction factor. Since both are heavily dependent on future changes, not historical trends, the authors made another median assumption that this change will average +1.5% per year for 20 years. Under such case the 20‐year price the District would pay to acquire electricity would be 25% greater than if the current price remained steady. Under the assumptions above, the District can conservatively expect to pay a total of about $980 million in electricity charges over the course of the next 20 years if the current cost of electricity to DC stays the same. Thus seeking potential avenues to reduce this expense could translate into very large monetary savings the District could apply to other core programs and services. Electricity Price Escalator It is unlikely that $0.087 per kWh currently paid by the District for its generated power would remain steady throughout the 20‐year average lifespan of a new wind farm, however. Instead, some sort of predictive factor must be applied to achieve a realistic price trend line over the course of 20 years. That predictive factor is commonly reduced to an annual average increase based on historical trends in a specific market, the consumer price index (CPI) measure of inflation (a large part of which is energy prices), analysis of future energy market conditions, or most accurately some combination of all three. In this baseline case the authors have used an initial estimate of 1.0% expected price increase per year, or less than 1/3 the historical long‐term baseline CPI in the United States. This equates to only a $0.0188 per kWh price increase over the course of 20 years, an extremely conservative assumption given historical trends. Timeline – 20 Years Because today’s standard wind projects have an assumed lifetime of 20 years, the authors use this assumption as the baseline scenario timeframe. This is a good assumption assuming a project is newly developed or acquired early in the project’s life. If a project is acquired by the District years after beginning operation, that time difference must be reflected in the comparative analysis in the form of a shorter project timeline. “Relevant Portion” This analysis does not compare the total amount of electricity consumed by the District, but only the portion to be served by the wind farm, what the authors call “relevant portion”. The relevant portion served by the wind farm is determined by dividing the amount of electricity produced by the wind farm by the total amount of electricity consumed by the District during the same time period. 57 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Two items, the total size of the project in terms of capacity as well as the project’s net capacity factor (or overall efficiency at using the total capacity of the wind farm to generate electricity), determine the amount of electricity produced by the wind farm. For example, assuming a 50MW nameplate capacity project that operates at a net capacity factor of 30%, electricity produced in year one would be just over 130 million kWhs, or about 32% of the District’s FY 2008‐2009 total electricity consumption. Over 20 years and assuming a 0.5% annual production efficiency loss factor, the total relevant portion of electricity produced would be approximately 2.5 billion kWhs, compared to a total predicted requirement of 9.7 billion kWhs. Operating Assumptions The authors have used what we consider to be conservative assumptions in all scenarios based on research of secondary materials and anecdotal discussions with project developers. We have been particularly conservative with operating expense assumptions, including any ongoing capital expenditures to replace machinery and resulting turbine down time as reflected in the capacity factor chosen. These assumptions are virtually identical throughout the scenarios to improve the value of the comparison, with any differences clearly highlighted under each option below. Key assumptions that the authors consider conservative in this analysis include: • Extra revenue from RECs (nor carbon credits) are not included in the analysis • Total project operating expenses plus ongoing capital expenditure costs are estimated to be at least $0.03 per kWh over the life of the project • Combined financing costs are modeled at the higher end of conservative ranges as determined thus far in conversations with developers active in the market. • Technology efficiency loss of 0.5% per year for 20 years. Baseline Results Thus, the baseline scenario is established using the following assumptions: − 50MW nameplate capacity comparative − 30% 20‐year net capacity factor (standard assumption) − 131.13 million kWhs produced in year one − 0.5% industry standard annual project efficiency loss factor − $0.087 per kWh 2010 energy generation price − 2013 operations begin − 20‐year project lifetime ¾ THE RESULTS is, were the wind project NOT built, over 20 years the District would conservatively expect to pay $248,934,533 for the equivalent portion of electricity that could otherwise be provided by a wind farm with the above specifications (not including T&D charges). The question then is, how much would it cost the District if it got that portion of its 58 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 electricity from a wind farm instead? Would it be less than $248 million? If so, by how much and would it be worth any added risk? Put a different way, how much less might the District pay for this portion of its electricity if the District owned or contracted for its own wind resource, and would that compensate the District for any extra risk inherent in such a project? The following sections seek to answer these questions. B. Financial Analysis – Project Scenarios This section combines the capital structuring and transaction analysis above to create a set of scenarios under which the District’s goal of adding direct‐offtake wind power to its electricity profile might practically move forward. For each scenario, a discounted cash flow model calculates the levelized cost of wind production under a given scenario, predicts future electricity use and cost of the District, and estimates the annual savings cash flows that might be expected to accrue given each scenario’s assumptions. Four scenarios are analyzed and discussed as follows: 1. Public option, direct ownership a) Publicly financed: Public Bonds with CREBs b) Buying into an project currently under development 2. Private partnership, indirect ownership a) Privately financed 1: Sale‐Leaseback with Treasury Grant b) Privately financed 2: Sale‐Leaseback with PTCs 3. Buy a portion of a private operating project at end of 10‐year PTC period 4. PPA with independent power supplier a) Long‐term (10+ years), standard consumption‐based (pay as you go) PPA b) Pre‐paid PPA Determining Results First, each scenario is analyzed using a set of common assumptions where possible in order to isolate the effects of each different structure and financing option. Second, a sensitivity analysis changes key assumptions common among the structures to “stress” the model and understand, where specific data is not available, the most important factors affecting feasibility of the project. Finally, a comparative discussion of each of the three major scenarios is offered to put the detailed analysis into a summary context useful for decision‐making. 59 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 It is important to note that all scenarios in this section assume the District has chosen a 50MW capacity option. All common assumptions are set at conservative levels. The analysis uses the following comparative indicators to better understand the results: ƒ Levelized cost of wind (LCW) analysis ƒ Comparison of total savings and other net cash flows to what the District would otherwise pay for electricity over 20 years. ƒ Weighted Average Cost of Capital (WACC) analysis ƒ Net Present Value (NPV) of net cash flows based on the WACC of a given scenario’s capital structure ƒ Debt Service Coverage (DSC) ratio analysis ƒ Internal Rate or Return (IRR) calculation where applicable 1. 50 MW Greenfield Development, direct ownership public finance a) Financing Option 1: Public Bonds with CREBs This option represents a likely scenario of the District chose to finance the project from public bonds issued by the District backed at least in part by the tax revenues of the District, and own the project directly. This would open the District up to Cap Act limitations as far as the authors can thus far determine, but would allow long‐term, low‐cost financing that achieves significant savings for the District over the life of the project. Project assumptions and results under this scenario are described below. Key assumptions: Construction
Pre-Development
Turbines Delivered
Interconnection
Balance of Plant and Install
Capitalized Interest
Construction Contingency
Reserve Capitalization
Total CAPEX
60 | P a g e total
400,000
82,500,000
1,250,000
1,750,000
3,601,413
4,275,000
3,000,000
$ 96,776,413
per kW
8.00
1,650.00
25.00
35.00
72.03
85.50
60.00
1,935.53 Draft Wind Energy Assessment District Department of the Environment April, 2011 Capital Structure
Public Bond
Grant
CREBs
PTC
Permanent Debt
Tax Equity
•
•
•
•
•
•
•
•
•
•
•
94,776,413
2,000,000
96,776,413 CREBs were included as the only other post construction capital source besides bonds at $2 million Construction was financed by the bond proceeds at 3.95% for 100% of the costs, less CREBs Construction period was 12 months and placed in service occurred Jan 1, 2013 100% of construction period interest was capitalized Capital costs before construction interest were $92,175,000, with installed turbine costs accounting for 89.5% of that total. Capacity nameplate was set at 50,000kW with 30% capacity factor resulting in 131,130,000kWh per year An efficiency‐loss factor of 0.5% per annum was included After inclusion of construction period interest, total cost per MW equaled $1.885 million Total capital costs post construction were funded by a 3.95%, 20‐year public bond No extra cost provision was included for a locational marginal pricing (LMP) charge Other key operating costs were estimated as follows: Operations
2009 DC annual energy consumption
2010 DC energy generation paid cost
Annual energy price escalator
Annual energy consumption escalator
Firming Premium
Location Marginal Pricing (LMP) excess
Operating Costs
Yr 1 O&M
Escalator
Insurance
Ongoing CAPEX (5yr warranty)
Minor (20-yr amort)
Major (20-yr amort)
Reserve Account Interest
Land Lease
404,590,807
$ 0.087
1.50%
1.50%
$
0.0100
$
$
$
$
$
$
$
1,346,908
0.01275 per kWh
3.00% per year
325,000 per year
185,625
412,500
2.50%
175,000
Figure 9: Select operating assumptions for Financing Option 1. 61 | P a g e Unit
kWh
per kWh
per year
per year
per kWh
per kWh
per
per
per
per
year
year
year
year
Draft Wind Energy Assessment District Department of the Environment April, 2011 Financing Option 1, Results Summary: Under this scenario the District achieves a $0.0888 per kWh 20‐year average levelized cost for the portion of energy delivered by a 50MW greenfield wind farm development with total savings over 20 years estimated at nearly $50 million compared to baseline, or an 19.8% savings compared to what the District would otherwise pay (baseline). YR 1 LCW $0.0816 per kWh 20‐yr Average LCW $0.0888 per kWh 20‐yr Net Savings $49,304,710 Net Savings as Percent of Baseline 19.8% Project WACC 3.87% 20‐yr Project NPV discounted @ WACC $30,159,459 YR 1 DSC ratio 1.23 20‐yr Project IRR 7.02% 62 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Finance Option 1: Pub Bonds + CREBs
Levelized Cost Calculation
Year
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Total
PROD
FINANCING
Net Annual Wind
Production (kWh)
Debt Service
131,130,000
130,474,350
129,821,978
129,172,868
128,527,004
127,884,369
127,244,947
126,608,722
125,975,679
125,345,800
124,719,071
124,095,476
123,474,999
122,857,624
122,243,336
121,632,119
121,023,958
120,418,838
119,816,744
119,217,661
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
(6,942,973)
2,501,685,544
(138,859,459)
OPERATING COSTS
Land Lease
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
O&M
Insurance
Minor Capex
(amtized)
TOTAL
Major Capex
(amtized)
LMP Cost
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
-
(1,311,300)
(1,304,744)
(1,298,220)
(1,291,729)
(1,285,270)
(1,278,844)
(1,272,449)
(1,266,087)
(1,259,757)
(1,253,458)
(1,247,191)
(1,240,955)
(1,234,750)
(1,228,576)
(1,222,433)
(1,216,321)
(1,210,240)
(1,204,188)
(1,198,167)
(1,192,177)
(10,699,305)
(10,733,156)
(10,768,252)
(10,804,629)
(10,842,324)
(10,881,377)
(10,921,825)
(10,963,712)
(11,007,077)
(11,051,965)
(11,098,420)
(11,146,488)
(11,196,216)
(11,247,653)
(11,300,850)
(11,355,857)
(11,412,729)
(11,471,519)
(11,532,285)
(11,595,085)
(3,500,000) (36,191,909)
(6,500,000)
(3,712,500)
(8,250,000)
-
(25,016,855)
(222,030,724)
Figure 10: Calculation of the levelized cost of wind under Financing Option 1, using public bonds. 63 | P a g e Total Costs
(1,346,908)
(1,387,315)
(1,428,934)
(1,471,802)
(1,515,956)
(1,561,435)
(1,608,278)
(1,656,526)
(1,706,222)
(1,757,409)
(1,810,131)
(1,864,435)
(1,920,368)
(1,977,979)
(2,037,318)
(2,098,438)
(2,161,391)
(2,226,233)
(2,293,020)
(2,361,810)
Total Production over Project Life
Total Costs over Project Life
Total Savings over Project Life
Average Levelized Cost of Wind
Notes:
Firming
Premium
$
$
$
Annual LCW
0.0816
0.0823
0.0829
0.0836
0.0844
0.0851
0.0858
0.0866
0.0874
0.0882
0.0890
0.0898
0.0907
0.0916
0.0924
0.0934
0.0943
0.0953
0.0962
0.0973
2,501,685,544 kWh
(222,030,724)
49,304,710
0.0888 per kWh
Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Finance Option 1: Pub Bonds + CREBs
Revenue Calculation
Year
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Total
Capex
(96,776,413)
(96,776,413)
Cost to the District,
No Wind Farm
(Relevant Portion)
Cost to Produce
Wind Energy
Net Annual
Savings under
Wind Farm
REC
Sales
Total
Potential
Revenue
(12,108,364)
(12,228,540)
(12,349,908)
(12,472,481)
(12,596,270)
(12,721,288)
(12,847,547)
(12,975,059)
(13,103,837)
(13,233,892)
(13,365,238)
(13,497,888)
(13,631,855)
(13,767,151)
(13,903,790)
(14,041,785)
(14,181,150)
(14,321,898)
(14,464,043)
(14,607,598)
(10,699,305)
(10,733,156)
(10,768,252)
(10,804,629)
(10,842,324)
(10,881,377)
(10,921,825)
(10,963,712)
(11,007,077)
(11,051,965)
(11,098,420)
(11,146,488)
(11,196,216)
(11,247,653)
(11,300,850)
(11,355,857)
(11,412,729)
(11,471,519)
(11,532,285)
(11,595,085)
1,409,059
1,495,384
1,581,656
1,667,852
1,753,946
1,839,912
1,925,722
2,011,348
2,096,760
2,181,927
2,266,819
2,351,401
2,435,639
2,519,498
2,602,940
2,685,928
2,768,421
2,850,379
2,931,757
3,012,513
-
1,409,059
1,495,384
1,581,656
1,667,852
1,753,946
1,839,912
1,925,722
2,011,348
2,096,760
2,181,927
2,266,819
2,351,401
2,435,639
2,519,498
2,602,940
2,685,928
2,768,421
2,850,379
2,931,757
3,012,513
(266,419,585)
(222,030,724)
44,388,861
-
44,388,861
Reserve
Capital
Expenditure
-
20-YR Project NPV
20-YR Project IRR
Notes:
Figure 11: Net savings revenue calculation under Financing Option 1, using public bonds.
64 | P a g e Final
Reserve
Net Revenue
4,915,849
1,409,059
1,495,384
1,581,656
1,667,852
1,753,946
1,839,912
1,925,722
2,011,348
2,096,760
2,181,927
2,266,819
2,351,401
2,435,639
2,519,498
2,602,940
2,685,928
2,768,421
2,850,379
2,931,757
7,928,363
4,915,849
49,304,710
30,159,459
7.02% Draft Wind Energy Assessment District Department of the Environment April, 2011 b) Risk‐management: Buying into Project Already Under Development Buying into a project that is under development is a similar analysis to the development scenario presented above, the primary difference being there is some premium that will be layered in that decreases performance expectations to some extent. In fact this would be a sliding scale – to the extent the project is closer to being completed (and risk from the project removed), the greater such premium would be. However, it is not likely in any case to overly affect the economics of the project, as long as developer fee premiums and held within market norms of roughly 5% of total development costs. It should be noted that even this extra cost may be offset (or even more than offset), to the extent that a better performing and more economical wind farm is acquired as a result, by purchasing a portion of a large wind farm that can take advantage of greater economies of scale, either in terms of lower per unit cost of equipment and install, O&M costs through time, or net capacity factors. ¾ Thus, the key analytical measure of this option from a feasibility perspective is to understand the price premium that will be demanded by developers for project that is already nearing completion, and ensure that in return the District is getting a more efficient project and/or a project with an overall less risk profile than it would likely get in a truly greenfield development scenario (i.e., development from scratch). 2. 50MW Greenfield Development, private partnership (indirect ownership) a) Financing Option 2: Private Option ‐ Sale‐Leaseback without PTCs This option is the second of two financing options presented in this report if the District wishes to partner more fully with the private sector. This option represents a likely scenario if the Treasury grant option is extended at the end of 2010, making the Treasury grant the most appropriate form of tax subsidy in the deal. The remainder of the deal would be financed by private partner equity and a long‐term commercial loan. A 10‐year sale‐leaseback structure is used, whereby the private partner is bought out through a sale‐leaseback agreement that provides them a specified return on equity. Project assumptions and results under this scenario are described further below. Key assumptions: •
The capital structure and capital costs were assumed as: 65 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Construction Costs Pre‐Development Turbines Delivered
Interconnection
Balance of Plant and Install
Capitalized Interest
Construction Contingency
Reserve Capitalization
Total CAPEX
Capital Structure
Partner Equity
Treasury Grant
Other Grant (from DC CREBs)
PTC
Permanent Debt
Other Tax Equity (NOL-based)
•
•
•
•
•
•
•
•
•
•
•
•
total
400,000
82,500,000
1,250,000
1,750,000
2,968,629
4,275,000
3,000,000
$ 96,143,629
per KW
8.00
1,650.00
25.00
35.00
59.37
85.50
60.00
1,922.87 7,434,700
25,125,000
2,000,000
42,129,966
19,453,963
96,143,629 A sale‐leaseback annual equity premium of 20% was included to reflect the a 10‐year RROE of 15% for the equity investor. Estimated net cost of capital to the District for the tax equity tranche was 3.0% annually over 10 years based on reasoning in Section X. Permanent debt was 20 year tenor, regularly amortizing, 7.25% annual rate Construction was financed by the a commercial construction loan at 8.75% for 75% of the costs, less CREBs Construction period was 12 months and placed in service occurred Jan 1, 2013 100% of construction period interest was capitalized Capital costs before construction interest were $92,175,000, with installed turbine costs accounting for 89.5% of that total. Capacity nameplate was 50,000kW with 30% capacity factor resulting in 131,130,000kWh per year An efficiency‐loss factor of 0.5% per annum was included After inclusion of construction period interest, total cost per MW equaled $1.930 million No extra cost provision was included for a locational marginal pricing (LMP) charge Other baseline key operating costs were estimated as follows: 66 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Operations
2009 DC annual energy consumption
2010 DC energy generation paid cost
Annual energy price escalator
Annual energy consumption escalator
Firming Premium
Location Marginal Pricing (LMP) excess
Operating Costs
Yr 1 O&M
Escalator
Insurance
Ongoing CAPEX (5yr warranty)
Minor (20-yr amort)
Major (20-yr amort)
Reserve Account Interest
Land Lease Payment
Sale-Leaseback Lease Equity Premium (annual)
404,590,807
$ 0.087
1.50%
1.50%
$
0.0100
$
$
$
$
$
$
$
Unit
kWh
per kWh
per year
per year
per kWh
per kWh
1,346,908
0.01275 per kWh
3.00% per year
325,000 per year
185,625
412,500
2.50%
175,000
20.00%
Figure 12: Select operating assumptions for Financing Option 2 per year
per year
per year
of partner equity
contributed1
Financing Option 2, Results Summary: Under this scenario the District achieves a $0.0797 per kWh 20‐year average levelized cost for the portion of energy delivered by a 50MW greenfield wind farm development with total savings over 20 years estimated at over $72 million compared to baseline, or a 26.7% savings compared to what the District would otherwise pay (baseline). YR 1 LCW $0.0889 per kWh 20‐yr Average LCW $0.0797 per kWh 20‐yr Net Savings $72,075,914 Net Savings as Percent of Baseline 26.7% Project WACC 4.75% 20‐yr Project NPV discounted @ WACC $13,487,544 YR 1 DSC ratio 1.32 20‐yr Project IRR 6.25% 67 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Financing Option 2: Private Option, Sale-Leaseback without PTCs
Levelized Cost Calculation
Year
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Total
NetPROD
Annual
Wind
Production
(kWh)
Debt Service
FINANCING
Tax Equity
Non-Cash
Cost2
OPERATING COSTS
Leaseback
Equity
Premium1
131,130,000
130,474,350
129,821,978
129,172,868
128,527,004
127,884,369
127,244,947
126,608,722
125,975,679
125,345,800
124,719,071
124,095,476
123,474,999
122,857,624
122,243,336
121,632,119
121,023,958
120,418,838
119,816,744
119,217,661
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(3,773,548)
(2,051,974)
(2,038,281)
(2,024,657)
(2,011,100)
(1,997,612)
(1,984,191)
(1,970,837)
(1,957,549)
(1,944,329)
(1,931,174)
-
(1,383,948)
(1,383,948)
(1,383,948)
(1,383,948)
(1,383,948)
(1,383,948)
(1,383,948)
(1,383,948)
(1,383,948)
(1,383,948)
-
2,501,685,544
(75,470,964)
(19,911,703)
(13,839,484)
Land Lease
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
O&M
(1,346,908)
(1,387,315)
(1,428,934)
(1,471,802)
(1,515,956)
(1,561,435)
(1,608,278)
(1,656,526)
(1,706,222)
(1,757,409)
(1,810,131)
(1,864,435)
(1,920,368)
(1,977,979)
(2,037,318)
(2,098,438)
(2,161,391)
(2,226,233)
(2,293,020)
(2,361,810)
(3,500,000) (36,191,909)
Notes:
1. Premium = 20% annual ROE based on net contributed partner equity; reflects a payment to equity holders
for risk of development/ownership which would be included in the contractual total lease payment
under the sale-leaseback agreement. (Assumption: such payment provides a 15% total 10-year ROE
to equity holders)
Insurance
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
Minor
Capex
(amtized)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
Major
Capex
(amtized)
TOTAL
LMP
Excess
Firming
Premium
Tax Equity
Cash Pef
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
-
(1,311,300)
(1,304,744)
(1,298,220)
(1,291,729)
(1,285,270)
(1,278,844)
(1,272,449)
(1,266,087)
(1,259,757)
(1,253,458)
(1,247,191)
(1,240,955)
(1,234,750)
(1,228,576)
(1,222,433)
(1,216,321)
(1,210,240)
(1,204,188)
(1,198,167)
(1,192,177)
(686,610)
(686,610)
(686,610)
(686,610)
(686,610)
(686,610)
(686,610)
(686,610)
(686,610)
(686,610)
-
(11,652,414)
(11,672,571)
(11,694,043)
(11,716,863)
(11,741,070)
(11,766,701)
(11,793,796)
(11,822,395)
(11,852,540)
(11,884,273)
(7,928,995)
(7,977,063)
(8,026,791)
(8,078,229)
(8,131,425)
(8,186,432)
(8,243,304)
(8,302,094)
(8,362,860)
(8,425,660)
(6,500,000) (3,712,500) (8,250,000)
-
(25,016,855)
(6,866,105)
(199,259,520)
Total Production over Project Life
Total Costs over Project Life
Total Savings over Project Life
Average Levelized Cost of Wind
2. The non-cash portion of return to tax equity (TE) accounts for the cost to achieve the TE investor's required ROE,
taking into consideration the opportunity cost difference between project owner and TE investor due to timing
difference of when those benefits would be realized by each, assumed 3% after tax credits.
Figure 13: Calculation of the levelized cost of wind under Financing Option 2: private option, sale‐leaseback without PTCs. 68 | P a g e Total Costs
$
$
$
Annual LCW
0.0889
0.0895
0.0901
0.0907
0.0914
0.0920
0.0927
0.0934
0.0941
0.0948
0.0636
0.0643
0.0650
0.0658
0.0665
0.0673
0.0681
0.0689
0.0698
0.0707
2,501,685,544 kWh
(199,259,520)
72,075,914
0.0797 per kWh
Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Financing Option 2: Private Option, Sale-Leaseback without PTCs
Revenue Calculation
Year
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Total
Capex
(96,143,629)
(96,143,629)
Cost to the District,
No Wind Farm
(Relevant Portion)
Cost to Produce
Wind Energy
Net Annual
Savings
REC Sales
Total
Potential
Revenue
Reserve
Capital
Expenditure
(11,652,414)
(11,672,571)
(11,694,043)
(11,716,863)
(11,741,070)
(11,766,701)
(11,793,796)
(11,822,395)
(11,852,540)
(11,884,273)
(7,928,995)
(7,977,063)
(8,026,791)
(8,078,229)
(8,131,425)
(8,186,432)
(8,243,304)
(8,302,094)
(8,362,860)
(8,425,660)
455,951
555,969
655,866
755,618
855,200
954,587
1,053,751
1,152,664
1,251,297
1,349,619
5,436,244
5,520,826
5,605,064
5,688,923
5,772,365
5,855,353
5,937,846
6,019,803
6,101,182
6,181,938
-
455,951
555,969
655,866
755,618
855,200
954,587
1,053,751
1,152,664
1,251,297
1,349,619
5,436,244
5,520,826
5,605,064
5,688,923
5,772,365
5,855,353
5,937,846
6,019,803
6,101,182
6,181,938
-
4,915,849
455,951
555,969
655,866
755,618
855,200
954,587
1,053,751
1,152,664
1,251,297
1,349,619
5,436,244
5,520,826
5,605,064
5,688,923
5,772,365
5,855,353
5,937,846
6,019,803
6,101,182
11,097,787
(266,419,585)
(199,259,520)
67,160,065
-
67,160,065
-
4,915,849
72,075,914
Figure 14: Net savings revenue calculation under Financing Option 2: private option, sale‐leaseback without PTCs. 69 | P a g e Net Revenue
(12,108,364)
(12,228,540)
(12,349,908)
(12,472,481)
(12,596,270)
(12,721,288)
(12,847,547)
(12,975,059)
(13,103,837)
(13,233,892)
(13,365,238)
(13,497,888)
(13,631,855)
(13,767,151)
(13,903,790)
(14,041,785)
(14,181,150)
(14,321,898)
(14,464,043)
(14,607,598)
20-YR Project NPV
20-YR Project IRR
Notes:
Reserve
Final
13,487,544
6.25%
Draft Wind Energy Assessment District Department of the Environment April, 2011 b) Financing Option 3: Private Option ‐ Sale‐Leaseback with PTCs This option is the second of two financing options if the District wishes to partner more robustly with the private sector. This first option represents a likely scenario if the Treasury grant option expires on schedule at the end of 2010 and is not renewed, making production tax credits (PTCs) the likely form of subsidy. The remainder of the deal would be financed by private partner equity and a long‐term commercial loan. A 10‐year sale‐leaseback structure is used, whereby the private partner is bought out through a sale‐leaseback agreement that provides them a specified return on equity. Project assumptions and results under this scenario are described further below. Key assumptions: DC WIND FINANCIAL MODEL ‐ Financing Option 3: Priv
Inputs
Construction Costs Pre‐Development Turbines Delivered
Interconnection
Balance of Plant and Install
Capitalized Interest
Capital Structure
Partner Equity
Treasury Grant
Other Grant (from DC CREBs)
PTC
Permanent Debt
Other Tax Equity (NOL-based)
•
•
•
•
•
•
•
total
400,000
82,500,000
1,250,000
1,750,000
2,878,470
per KW
8.00
1,650.00
25.00
35.00
57.57 7,742,097
2,000,000
49,812,915
36,498,458
96,053,470
A sale‐leaseback annual equity premium of 20% was included to reflect the a 10‐year RROE of 15% for the equity investor. Estimated net cost of capital to the District for the tax equity tranche was 3.0% annually over 10 years based on reasoning in Section X. Permanent debt was 20 year tenor, regularly amortizing, 7.25% annual rate Construction was financed by the a commercial construction loan at 8.75% for 75% of the costs, less CREBs Construction period was 12 months and placed in service occurred Jan 1, 2013 100% of construction period interest was capitalized Capital costs before construction interest were $92,175,000, with installed turbine costs accounting for 89.5% of that total. 70 | P a g e •
•
•
•
•
Draft Wind Energy Assessment District Department of the Environment April, 2011 Capacity nameplate was 50,000kW with 30% capacity factor resulting in 131,130,000kWh per year An efficiency‐loss factor of 0.5% per annum was included After inclusion of construction period interest, total cost per MW equaled $1.930 million No extra cost provision was included for a locational marginal pricing (LMP) charge Other baseline operating costs were estimated as follows: Operations
2009 DC annual energy consumption
2010 DC energy generation paid cost
Annual energy price escalator
Annual energy consumption escalator
Firming Premium
Location Marginal Pricing (LMP) excess
Operating Costs
Yr 1 O&M
Escalator
Insurance
Ongoing CAPEX (5yr warranty)
Minor (20-yr amort)
Major (20-yr amort)
Reserve Account Interest
Land Lease Payment
Sale-Leaseback Lease Equity Premium (annual)
404,590,807
$ 0.087
1.50%
1.50%
$
0.0100
$
$
$
$
$
$
$
Unit
kWh
per kWh
per year
per year
per kWh
per kWh
1,346,908
0.01275 per kWh
3.00% per year
325,000 per year
185,625
412,500
2.50%
175,000
20.00%
per year
per year
per year
of partner equity
contributed1
Figure 15: Select operating assumptions for financing option 3. Financing Option 3, Results Summary: Under this scenario the District achieves a $0.0830 per kWh 20‐year average levelized cost for the portion of energy delivered by a 50MW greenfield wind farm development with total savings over 20 years estimated at almost $63 million compared to baseline, or a 25.2% savings compared to what the District would otherwise pay (baseline). YR 1 LCW $0.0969 per kWh 20‐yr Average LCW $0.0830 per kWh 20‐yr Net Savings $62,844,971 Net Savings as Percent of Baseline 25.2% Project WACC 5.52% 20‐yr Project NPV discounted @ WACC $238,197 YR 1 DSC ratio 1.14 20‐yr Project IRR 5.55% 71 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Financing Option 3: Private Option, Sale-Leaseback with PTCs
Levelized Cost Calculation
Year
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Total
NetPROD
Annual
Wind
Production
(kWh)
FINANCING
Tax Equity
Debt Service Non-Cash Cost2
OPERATING COSTS
Leaseback
Equity
Premium1
131,130,000
130,474,350
129,821,978
129,172,868
128,527,004
127,884,369
127,244,947
126,608,722
125,975,679
125,345,800
124,719,071
124,095,476
123,474,999
122,857,624
122,243,336
121,632,119
121,023,958
120,418,838
119,816,744
119,217,661
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(3,512,423)
(2,391,020)
(2,391,020)
(2,391,020)
(2,391,020)
(2,391,020)
(2,391,020)
(2,391,020)
(2,391,020)
(2,391,020)
(2,391,020)
-
(1,548,419)
(1,548,419)
(1,548,419)
(1,548,419)
(1,548,419)
(1,548,419)
(1,548,419)
(1,548,419)
(1,548,419)
(1,548,419)
-
2,501,685,544
(70,248,465)
(23,910,199)
(15,484,194)
Land Lease
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
O&M
(1,346,908)
(1,387,315)
(1,428,934)
(1,471,802)
(1,515,956)
(1,561,435)
(1,608,278)
(1,656,526)
(1,706,222)
(1,757,409)
(1,810,131)
(1,864,435)
(1,920,368)
(1,977,979)
(2,037,318)
(2,098,438)
(2,161,391)
(2,226,233)
(2,293,020)
(2,361,810)
(3,500,000) (36,191,909)
Notes:
1. Premium = 20% annual ROE based on net contributed partner equity; reflects a payment to equity holders
for risk of development/ownership which would be included in the contractual total lease payment
under the sale-leaseback agreement. (Assumption: such payment provides a 15% total 10-year ROE
to equity holders)
Insurance
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
Minor
Capex
(amtized)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
(185,625)
Major
Capex
(amtized)
TOTAL
LMP
Excess
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
(412,500)
-
(6,500,000) (3,712,500) (8,250,000)
-
Firming
Premium
(1,311,300)
(1,304,744)
(1,298,220)
(1,291,729)
(1,285,270)
(1,278,844)
(1,272,449)
(1,266,087)
(1,259,757)
(1,253,458)
(1,247,191)
(1,240,955)
(1,234,750)
(1,228,576)
(1,222,433)
(1,216,321)
(1,210,240)
(1,204,188)
(1,198,167)
(1,192,177)
Tax Equity
Cash Pef
(1,494,387)
(1,494,387)
(1,494,387)
(1,494,387)
(1,494,387)
(1,494,387)
(1,494,387)
(1,494,387)
(1,494,387)
(1,494,387)
-
(12,702,583)
(12,736,433)
(12,771,529)
(12,807,906)
(12,845,601)
(12,884,654)
(12,925,103)
(12,966,989)
(13,010,354)
(13,055,242)
(7,667,870)
(7,715,938)
(7,765,666)
(7,817,104)
(7,870,300)
(7,925,307)
(7,982,179)
(8,040,970)
(8,101,736)
(8,164,535)
(25,016,855) (14,943,875)
(207,757,998)
Total Production over Project Life
Total Costs over Project Life
Total Savings over Project Life
Average Levelized Cost of Wind
2. The non-cash portion of return to tax equity (TE) accounts for the cost to achieve the TE investor's required ROE,
but taking into consideration the opportunity cost difference between project owner and TE investor due to timing
difference of when those benefits would be realized by each one, assumed to be 3% after tax credits.
Figure 16: Calculation of the levelized cost of wind (LCW) under Financing Option 3, private option sale‐leaseback with PTCs. 72 | P a g e Total Costs
$
$
$
Annual LCW
0.0969
0.0976
0.0984
0.0992
0.0999
0.1008
0.1016
0.1024
0.1033
0.1042
0.0615
0.0622
0.0629
0.0636
0.0644
0.0652
0.0660
0.0668
0.0676
0.0685
2,501,685,544 kWh
(207,757,998)
62,844,971
0.0830 per kWh
Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Financing Option 3: Private Option, Sale-Leaseback with PTCs
Revenue Calculation
Year
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Total
Capex
(96,053,470)
(96,053,470)
Cost to the District,
No Wind Farm
(Relevant Portion)
Cost to Produce
Wind Energy
(12,108,364)
(12,228,540)
(12,349,908)
(12,472,481)
(12,596,270)
(12,721,288)
(12,847,547)
(12,975,059)
(13,103,837)
(13,233,892)
(13,365,238)
(13,497,888)
(13,631,855)
(13,767,151)
(13,903,790)
(14,041,785)
(14,181,150)
(14,321,898)
(14,464,043)
(14,607,598)
(12,702,583)
(12,736,433)
(12,771,529)
(12,807,906)
(12,845,601)
(12,884,654)
(12,925,103)
(12,966,989)
(13,010,354)
(13,055,242)
(7,667,870)
(7,715,938)
(7,765,666)
(7,817,104)
(7,870,300)
(7,925,307)
(7,982,179)
(8,040,970)
(8,101,736)
(8,164,535)
(266,419,585)
(207,757,998)
Net Annual
Savings
(594,218)
(507,893)
(421,621)
(335,425)
(249,331)
(163,365)
(77,555)
8,070
93,483
178,650
5,697,368
5,781,950
5,866,189
5,950,048
6,033,490
6,116,478
6,198,971
6,280,928
6,362,307
6,443,063
58,661,587
REC Sales
-
Total
Potential
Revenue
(594,218)
(507,893)
(421,621)
(335,425)
(249,331)
(163,365)
(77,555)
8,070
93,483
178,650
5,697,368
5,781,950
5,866,189
5,950,048
6,033,490
6,116,478
6,198,971
6,280,928
6,362,307
6,443,063
58,661,587
Reserve
Deposit
Reserve
Capital
Expenditure
594,218
507,893
421,621
335,425
249,331
163,365
77,555
-
3,787,994
4,023,552
5,781,950
5,866,189
5,950,048
6,033,490
6,116,478
6,198,971
6,280,928
6,362,307
10,231,058
(1,954,020)
2,349,409
3,787,994
62,844,971
Figure 17: Net savings revenue calculation under Financing Option 3, private option sale‐leaseback with PTCs.
73 | P a g e Net Revenue
(8,070)
(93,483)
(178,650)
(1,673,817)
-
20-YR Project NPV
20-YR Project IRR
Notes:
Reserve
Final
238,197
5.55%
•
Draft Wind Energy Assessment District Department of the Environment April, 2011 Results Summary – Comparing 3 Financing Options for Greenfield Development Scenario Indicator Option 1 (Pub Bonds + CREBs) Option 2 (Sale‐
Leaseback without PTC) $0.0889 per kWh $0.0797 per kWh $72,075,914 Option 3 (Sale‐
Leaseback with PTC)
YR 1 LCW $0.0816 per kWh $0.0969 per kWh 20‐yr Average LCW $0.0888 per kWh $0.0830 per kWh 20‐yr Net Savings $49,304,710 $62,844,971 Net Savings as Percent of 19.8% 26.7% 25.2% Baseline WACC 3.87% 4.75% 5.52% 20‐yr Project NPV $30,159,459 $13,487,544 $238,197 discounted @ WACC YR 1 DSC ratio 1.23 1.32 1.14 20‐yr Project IRR 7.02% 6.25% 5.55% Table 5: Comparison of 3 financing options for greenfield development scenario. Key observations from the analysis above include: •
using public bonds to finance the transaction offers better return on assets and is thus an overall more efficient financing structure at the project level •
however, over the 20‐year project life, options 2 and 3 using a sale‐leaseback structure offer greater overall savings and a lower average LCW than option 1 •
thus, there may be a private financing structure that provides a lower LCW than public bonds if sale‐leaseback or other private partnership option is legal for the District as a tax‐exempt entity •
it is cheaper and transactionally more simple to use Treasury grant with other tax equity compared to using Production Tax Credits (PTCs) Summary conclusion: if public bonds are not an option due to Cap Act restrictions, seeking a private‐
sector solution through sale‐leaseback or similar arrangement that allows indirect use of tax‐based subsidies, if legally possible, may offer greater total savings and lower levelized cost of wind, particularly if the Treasury grant is extended It should be emphasized that the IRR and NPV calculation is at project level. The reason is that the return to the District given any savings is infinite since none of the financial structures here include District equity. The only meaningful IRR is thus at project level (unlevered), and uses pre‐debt cash‐
flows measured against total required capital. The discrepancy between the increase in aggregate net savings in conjunction with the decrease in NPV and IRR in the second and third options compared to the first option comes from cash flow timing differences and transaction structure. First, because the tenor of tax equity is 10 years compared to the public bond at 20 years, the carrying cost of capital over the full 20 years is actually lower, even 74 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 with the WACC technically higher than the bond rate. Second, for this analysis the authors have assumed a portion of the tax equity return must be considered an operating cost (as a “cash preference”), not a part of the debt for tax purposes, which reduces the relative amount of savings that can be included in the project NPV and IRR calculation. Third, a greater value of the aggregate savings is pushed to the final 10 years (instead of amortized in a 20‐year public bond scenario), increasing project revenues in early years under the bond option and raising the project NPV and IRR for that option. Thus, particularly in the last 10 years of the project, the portion of the savings stream that can flow to the District under options 2 and 3 increases dramatically. It can also be seen from the analysis the effect of the lower‐cost Treasury grant structure (option 2) compared to PTCs (option 3). The DSC ratio suffers under the PTC option, as do net revenues in the early years impacting overall net savings to the District. Negative cash flows occur in years 1‐7, but are covered by a capitalized reserve, which then must be replenished in subsequent years. The reserve is released in the final year with any accrued interest. Realistically, a capital reserve is just one method to reconcile these cash flows. A number of other aspects of the capital structure may be amended to either restructure cash flows or plan for negative cash flows in the early years. No matter the strategy, compared to public bonds or private sale‐leaseback with Treasury grant, using PTCs will clearly put greater stress on cash flows, making financing the PTC option more difficult, raising the amount of partner equity required and/or increasing the required debt service reserve and ultimately capital costs. As noted earlier, we have used conservative assumptions throughout the analysis, particularly in terms of the true cost to the District of any indirect use of private‐sector subsidies. Whether using PTCs or the Treasury grant in the private sale‐leaseback structure, a large number of factors will affect the net cost and precise timing of cash flows and further analysis should be done at that time once specific outlines of the project are known. What can be said with clarity at this time is that partnering with the private sector in sale‐leaseback or similar form (assuming such a structure is legally possible): 1) will be easier if the Treasury grant gets extended and PTCs are not needed; and 2) could potentially be even more cost‐effective than financing with 100% public bonds. 3. Purchase an Existing Wind Farm Purchasing an existing wind farm may be a lower‐cost, lower‐risk option than developing a new asset, namely because the District would be purchasing an asset with proven operational characteristics at a depreciated value. While financing costs are important in this scenario, the financial viability of this option will depend heavily on the purchase price in relation to the operational efficiency of the facility. A key risk factor for this scenario is the tax penalty implications of a tax‐exempt entity such as the District purchasing a wind farm that used tax equity and other subsidies to finance the project. Many wind farms have used PTCs as a financing source, and thus if the District acquired the asset any time 75 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 during its first 10 years, there may be tax credit recapture risk due to eligibility exclusions surrounding tax‐exempt entities. Another risk is that purchasing an operating wind facility at mid‐life may require renegotiating the existing PPA that facility has with its offtaker(s), the financial penalties from which may make this option infeasible. Barring a legal opinion otherwise, the most conservative (and most likely) avenue under this scenario would therefore require the District to purchase a wind facility that is at least 10 years old. One exception to this would be if the project had not included tax‐based subsidies in the sources of funds, but this would in turn likely raise the required purchase price. Another important assumption is that the project will be able to renegotiate the PPA successfully with negligible financial penalty on the deal itself, which may or may not be the case in a given deal. Ideally the District would also be able to identify projects with prior PPAs of maximum 10 years, completely mitigating the renegotiation risk. While the amount of capital required would be much lower than in scenario 1 or scenario 2, purchasing an operating wind facility already in operation would still require either issuance of public bonds or use of some kind of private‐sector partnership. Purchase and Existing Wind Farm Advantages Disadvantages Wind farm already existing Farm is older with shorter expected life Operational history and data‐proven May be more expensive to operate in later performance years No development risk May require some capital equipment replacement Up to half the capital costs of new Difficulty reaching “fair market value” development conclusion Table 6: Advantages and disadvantages of purchasing an existing wind farm at mid‐project life. An analysis was thus carried out assuming purchase of an operating wind asset at beginning of year 11 with a 10 year project horizon (compared to 20 years under the greenfield development scenario). Purchase prices were analyzed by first taking 50% of development costs in scenario 1 (10 years / 20 years = 0.5), then incrementally adding various percentage “purchase premiums” to that. This scenario was modeled using both a public bond financing and a standard commercial financing. The public bonds, as before, assume a small amount of CREBs in addition to public bonds at a 20‐year tenor and “full faith” interest rates. The standard commercial financing assumes 15 year tenor permanent financing and market rate equity at a 0.75 loan to value ratio. Sensitivity analysis further tests stressors to these assumptions. 76 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 (Note: All LCW and Net Revenue calculations shown below are modeled at a 5% purchase premium. Sensitivity analyses that follow show the effect of different purchase premiums.) The following initial conclusions that were drawn include: • Financial feasibility is heavily dependent on purchase price • Cash flow margins will be thin even under medium assumptions for wind production capacity factor ‐ if debt too expensive or short‐term the project will not meet minimum DSC ratio requirements, and will need greater equity, DOE loan guarantees, reserve set‐
asides, or other combination of credit enhancement • Commercial debt appears too expensive for this option unless can get >15yr term, which may be unlikely due to shorter project life (assumed 10 years) • Available free cash flow from savings at current assumption levels using standard commercial financing may make enticing a private equity investor partner difficult • Under public bond financing assumptions from scenario 1, price premiums of up to 60% above one‐half scenario 1 capital costs (in this case >$77 million) produces acceptable DSC ratios (>1.3x) – total savings are over $41 million at a 5% price premium, $34 million at a 25% premium. • Under a non‐subsidized standard commercial financing structure, performance is dramatically reduced, and only under long‐term debt tenors (>15 years) combined with zero to small purchase price premiums (<10%) can the project achieve financial feasibility using traditional measures. 77 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Purchase existing at Yr10, Public Bonds
Levelized Cost Calculation
PROD
Net Annual Wind
Production (kWh)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
FINANCING
Debt Service
124,719,071
124,095,476
123,474,999
122,857,624
122,243,336
121,632,119
121,023,958
120,418,838
119,816,744
119,217,661
(3,566,290)
(3,566,290)
(3,566,290)
(3,566,290)
(3,566,290)
(3,566,290)
(3,566,290)
(3,566,290)
(3,566,290)
(3,566,290)
1,219,499,826
(35,662,898)
TOTAL
OPERATING COSTS
Land Lease
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
O&M
Insurance
Minor
Capex
(amtized)
Major
Capex
(amtized)
LMP Cost
Total Costs
(1,810,131)
(1,864,435)
(1,920,368)
(1,977,979)
(2,037,318)
(2,098,438)
(2,161,391)
(2,226,233)
(2,293,020)
(2,361,810)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
-
(1,247,191)
(1,240,955)
(1,234,750)
(1,228,576)
(1,222,433)
(1,216,321)
(1,210,240)
(1,204,188)
(1,198,167)
(1,192,177)
(7,907,362)
(7,955,429)
(8,005,158)
(8,056,595)
(8,109,792)
(8,164,799)
(8,221,670)
(8,280,461)
(8,341,227)
(8,404,027)
(1,750,000) (20,751,124)
(3,250,000)
(2,475,000)
(5,362,500)
-
(12,194,998)
(81,446,520)
Total Production over Project Life
Total Costs over Project Life
Total Savings over Project Life
Average Levelized Cost of Wind
Figure 18: LCW analysis for purchasing an existing asset at year 10 using public bond financing 78 | P a g e Firming
Premium
$
$
$
Annual LCW
0.0634
0.0641
0.0648
0.0656
0.0663
0.0671
0.0679
0.0688
0.0696
0.0705
1,219,499,826 kWh
(81,446,520)
41,559,561
0.0668 per kWh
Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Purchase existing at Yr10, Public Bonds
Revenue Calculation
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
Capex
(50,682,337)
(50,682,337)
Cost to the
District, No Wind
Farm (Relevant
Portion)
Cost to Produce
Wind Energy
Net Annual
Savings
REC Sales
Total Net
Revenue
(11,516,388)
(11,630,688)
(11,746,123)
(11,862,703)
(11,980,440)
(12,099,346)
(12,219,432)
(12,340,710)
(12,463,192)
(12,586,889)
(7,907,362)
(7,955,429)
(8,005,158)
(8,056,595)
(8,109,792)
(8,164,799)
(8,221,670)
(8,280,461)
(8,341,227)
(8,404,027)
3,609,027
3,675,259
3,740,965
3,806,108
3,870,649
3,934,547
3,997,762
4,060,249
4,121,965
4,182,862
-
3,609,027
3,675,259
3,740,965
3,806,108
3,870,649
3,934,547
3,997,762
4,060,249
4,121,965
4,182,862
(120,445,912)
(81,446,520)
38,999,392
-
38,999,392
Reserve
Capital
Expenditure
-
Final
Reserve
Net Revenue
2,560,169
3,609,027
3,675,259
3,740,965
3,806,108
3,870,649
3,934,547
3,997,762
4,060,249
4,121,965
6,743,031
2,560,169
41,559,561
10-YR Project NPV
10-YR Project IRR
10,192,195
7.63%
Figure 19: Net revenue calculation for purchasing an existing asset at year 10 using public bond financing Sensitivity Analysis – Purchase Premium Variability Public Bond Financing Scenario
Price Premium
Purchase Price
Project IRR
Yr1 DSCR
10-Yr Total Savings to District
10-Yr LCW
-8.8%
44,000,000
10.81%
2.33
46,454,796
0.0628
-4.7%
46,000,000
9.79%
2.23
44,989,670
0.0640
-0.6%
48,000,000
8.83%
2.13
43,524,543
0.0652
3.6%
50,000,000
7.93%
2.04
42,059,416
0.0664
7.7%
52,000,000
7.08%
1.96
40,594,289
0.0676
11.9%
54,000,000
6.28%
1.88
39,129,162
0.0688
16.0%
56,000,000
5.52%
1.81
37,664,036
0.0700
20.2%
58,000,000
4.81%
1.75
36,198,909
0.0712
24.3%
60,000,000
4.13%
1.69
34,733,782
0.0724
28.4%
62,000,000
3.48%
1.63
33,268,655
0.0736
Table 7: Sensitivity analysis of different purchase price premiums on a 10‐year wind facility asset under public bond finance assumptions. 79 | P a g e 32.6%
64,000,000
2.87%
1.58
31,803,529
0.0748
Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Purchase existing at Yr10, Standard Commercial Financing
Levelized Cost Calculation
PROD
Net Annual Wind
Production (kWh)
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
FINANCING
Debt
Service*
Cost of Equity
Land Lease
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
(175,000)
124,719,071
124,095,476
123,474,999
122,857,624
122,243,336
121,632,119
121,023,958
120,418,838
119,816,744
119,217,661
(3,910,127)
(3,910,127)
(3,910,127)
(3,910,127)
(3,910,127)
(3,910,127)
(3,910,127)
(3,910,127)
(3,910,127)
(3,910,127)
(2,500,000)
(2,500,000)
(2,500,000)
(2,500,000)
(2,500,000)
(2,500,000)
(2,500,000)
(2,500,000)
(2,500,000)
(2,500,000)
1,219,499,826
(39,101,271)
(25,000,000)
*Debt service is 15 year tenor at 6.75% interest.
TOTAL
OPERATING COSTS
O&M
Insurance
Minor
Capex
(amtized)
Major
Capex
(amtized)
LMP Cost
Total Costs
(1,810,131)
(1,864,435)
(1,920,368)
(1,977,979)
(2,037,318)
(2,098,438)
(2,161,391)
(2,226,233)
(2,293,020)
(2,361,810)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(325,000)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(247,500)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
(536,250)
-
(1,247,191)
(1,240,955)
(1,234,750)
(1,228,576)
(1,222,433)
(1,216,321)
(1,210,240)
(1,204,188)
(1,198,167)
(1,192,177)
(10,751,199)
(10,799,267)
(10,848,995)
(10,900,432)
(10,953,629)
(11,008,636)
(11,065,508)
(11,124,298)
(11,185,064)
(11,247,864)
(1,750,000) (20,751,124)
(3,250,000)
(2,475,000)
(5,362,500)
-
(12,194,998)
(109,884,894)
Total Production over Project Life
Total Costs over Project Life
Total Savings over Project Life
Average Levelized Cost of Wind
Figure 20: LCW analysis for purchasing an existing asset at year 10 using standard commercial financing 80 | P a g e Firming
Premium
$
$
$
Annual LCW
0.0862
0.0870
0.0879
0.0887
0.0896
0.0905
0.0914
0.0924
0.0934
0.0943
1,219,499,826 kWh
(109,884,894)
13,121,187
0.0901 per kWh
Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Purchase existing at Yr10, Standard Commercial Financing
Revenue Calculation
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
Capex
(50,682,337)
-
Cost to the
District, No Wind
Farm (Relevant
Portion)
(50,682,337)
Cost to Produce
Wind Energy
Net Annual
Savings
REC Sales
Reserve
Capital
Expenditure
-
Total Net
Revenue
(11,516,388)
(11,630,688)
(11,746,123)
(11,862,703)
(11,980,440)
(12,099,346)
(12,219,432)
(12,340,710)
(12,463,192)
(12,586,889)
(10,751,199)
(10,799,267)
(10,848,995)
(10,900,432)
(10,953,629)
(11,008,636)
(11,065,508)
(11,124,298)
(11,185,064)
(11,247,864)
765,189
831,421
897,128
962,271
1,026,811
1,090,710
1,153,924
1,216,412
1,278,127
1,339,025
-
765,189
831,421
897,128
962,271
1,026,811
1,090,710
1,153,924
1,216,412
1,278,127
1,339,025
(120,445,912)
(109,884,894)
10,561,018
-
10,561,018
-
10-YR Project NPV
10-YR Project IRR
Final
Reserve
Net Revenue
2,560,169
765,189
831,421
897,128
962,271
1,026,811
1,090,710
1,153,924
1,216,412
1,278,127
3,899,194
2,560,169
13,121,187
(2,013,219)
7.63%
Figure 21: Revenue calculation for purchasing an existing asset at year 10 using standard commercial financing Under Public Bond Financing Scenario
Price Premium
-13.2%
Purchase Price
44,000,000
Project IRR
10.81%
Yr1 DSCR
2.25
10-Yr Total Savings to District
20,342,608
10-Yr LCW
0.0842
-9.2%
46,000,000
9.79%
2.11
18,181,262
0.0860
-5.3%
48,000,000
8.83%
1.98
16,019,916
0.0877
-1.3%
50,000,000
7.93%
1.87
13,858,570
0.0895
2.6%
52,000,000
7.08%
1.77
11,697,224
0.0913
6.5%
54,000,000
6.28%
1.68
9,535,879
0.0930
10.5%
56,000,000
5.52%
1.60
7,374,533
0.0948
14.4%
58,000,000
4.81%
1.53
5,264,409
0.0966
18.4%
60,000,000
4.13%
1.46
4,195,301
0.0984
22.3%
62,000,000
3.48%
1.40
4,571,870
0.1001
Table 8: Sensitivity analysis of different purchase price premiums on a 10‐year wind facility asset under standard commercial finance. 81 | P a g e 26.3%
64,000,000
2.87%
1.34
6,291,010
0.1019
Draft Wind Energy Assessment District Department of the Environment April, 2011 4. PPA with independent power supplier a) Long‐term (10+ years), standard consumption‐based (pay as you go) PPA Currently the District already incorporates wind energy into its portfolio through the use of Renewable Energy Credits (RECs) from other wind projects. The District’s energy scheduler, WGES, has added these at the request of the District. This method is certainly the lowest risk, but is the highest‐cost method the District has available to add wind to its portfolio. Instead of RECs, or seeking to own a wind facility, the District could independently solicit bids from independent power producers or other private developers for a long‐term pricing contract under a power purchase agreement (PPA). Under such a plan the District would contract independently of its primary energy scheduler for the best‐price bid for a term of 15‐20 years, with 20 years likely preferable as it will secure the lowest possible price. The standard PPA option is different from just incorporating wind RECs into the District’s energy portfolio in a couple of important ways: • This would engage two distinct parties in two separate contracts, one with the District’s energy scheduler and a second directly with the wind power developer. The District’s energy scheduler, each time the District put that contract to bid (currently every 3 years) would be responsible for submitting a bid that reflected the reduced demand based on consumption of wind power directly from the separate PPA throughout the term of the PPA. • The important focus would be the energy itself, with environmental benefits taking a secondary role. In such case the District could opt to include none of the associate RECs with the wind energy (which are often incorporated as part of the PPA price), allowing the developer to sell some or all to a third party (such as a large regional utility under pressure from state RPS regulations to increase clean energy in their portfolio) for a portion or all of the years of the project, which would in turn improve financing feasibility of the project. Like the option to purchase an existing asset, the advantage of this structure from the perspective of the District compared to the others is that the District would avoid all direct risk associated with developing and constructing a wind energy generation asset. Unlike the purchase of an existing asset however, this option also eliminates all upfront capital expenditures, adds a new wind asset instead of a 10‐yr‐old asset, and avoids all potential legal obstacles to ownership that the District may face otherwise. The primary risk is that the price, in conjunction with the cost of integrating the power with the other power being supplied by the District’s energy scheduler, may not be competitive with the current price to achieve a level of savings sufficient to make the project feasible. The District may also be passing up an opportunity to generate even greater risk‐adjusted savings in the future by pursuing other options. 82 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 This risk may be able to be managed, however, through a competitive bidding process for both the PPA partner and the new energy scheduler and active firming and shaping of the asset to fit the District’s specific energy usage profile. A competitive bid will ensure the best possible rate, and the District can then with specific data in hand decide if it makes sense to pursue this option vis a vis the others on the table. Another risk is that project location may prove much more influential in price feasibility. If the energy produced by a specific facility must be directly offtaken by, and delivered to, the District, transmission and distribution charges must be investigated and monitored carefully to strike a balance between minimizing such charges and choosing the best site from a wind resource perspective to maximize the project’s lifetime capacity factor. To the extent possible, these should be fixed in long‐term contracts with T&D operators. The cost of such a project cannot be known in advance because it will be dependent on a bid process, but given the District’s cost of generation at $0.087 per kWh, there may be potential for cost savings. According to the public reports by the US DOE41, the capacity weighted average levelized cost to generate wind was $61 per MWh ($0.061 per kWh) up from a low of $32 per MWh ($0.032 per kWh) in 2003‐2003 and up from $51 per MWh ($0.051 per kWh) in 2008. What this shows is that thus far the average cost of wind is cyclical, largely dependent on available subsidies in the market (which are still in flux) and capital cost of equipment. The price the District could achieve by entering into a long‐
term PPA will thus depend heavily on the market at the specific time of bid. However, even conservatively assuming: • $0.061 per kWh (the highest average price of wind during the past decade according to DOE) year 1 PPA price • adding 25% to that as a conservative buffer • adding the same additional firming margin for any required integration with the District’s regular energy sources as all other scenarios analyzed in this report ($0.01 per kWh) • adding a 2% escalation factor to the PPA over a 20 year term Result: under conservative assumptions the District could still expect to save roughly $20 million over 20 years without the development and ownership risk of the other options. It should be emphasized that the analysis above is currently highly speculative and only a competitive bid process will allow the District to know with clarity what savings it might reasonably achieve under this option, but given the potential for large savings with little risk, this option should be pursued vigorously. 41
U.S. Department of Energy’s (DOE) Wind Technologies Market Report, 2009. 83 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 DC WIND FINANCIAL MODEL - Long-Term PPA
Revenue Calculation
Year
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Projected Annual
Generation Cost,
No Wind ($ per
kWh)
0.0923
0.0937
0.0951
0.0966
0.0980
0.0995
0.1010
0.1025
0.1040
0.1056
0.1072
0.1088
0.1104
0.1121
0.1137
0.1154
0.1172
0.1189
0.1207
0.1225
Total
Net Annual
Wind
Production,
50MW (kWh)
131,130,000
130,474,350
129,821,978
129,172,868
128,527,004
127,884,369
127,244,947
126,608,722
125,975,679
125,345,800
124,719,071
124,095,476
123,474,999
122,857,624
122,243,336
121,632,119
121,023,958
120,418,838
119,816,744
119,217,661
2,501,685,544
PPA Cost of
Wind ($ per
kWh)
0.0732
0.0747
0.0762
0.0777
0.0792
0.0808
0.0824
0.0841
0.0858
0.0875
0.0892
0.0910
0.0928
0.0947
0.0966
0.0985
0.1005
0.1025
0.1045
0.1066
Cost
Differential
0.0191
0.0191
0.0190
0.0189
0.0188
0.0187
0.0185
0.0184
0.0183
0.0181
0.0179
0.0178
0.0176
0.0174
0.0172
0.0169
0.0167
0.0164
0.0162
0.0159
Cost to the
District, No
Wind Farm
(Relevant
PPA Cost of Wind
(total $)
Net Annual
Savings under
Wind Farm
Firming Margin
REC Sales
Net Potential
Savings
(12,108,364)
(12,228,540)
(12,349,908)
(12,472,481)
(12,596,270)
(12,721,288)
(12,847,547)
(12,975,059)
(13,103,837)
(13,233,892)
(13,365,238)
(13,497,888)
(13,631,855)
(13,767,151)
(13,903,790)
(14,041,785)
(14,181,150)
(14,321,898)
(14,464,043)
(14,607,598)
(9,598,716)
(9,741,737)
(9,886,889)
(10,034,203)
(10,183,713)
(10,335,450)
(10,489,449)
(10,645,741)
(10,804,363)
(10,965,348)
(11,128,732)
(11,294,550)
(11,462,838)
(11,633,635)
(11,806,976)
(11,982,900)
(12,161,445)
(12,342,651)
(12,526,556)
(12,713,202)
2,509,648
2,486,803
2,463,019
2,438,278
2,412,557
2,385,838
2,358,099
2,329,318
2,299,474
2,268,544
2,236,507
2,203,339
2,169,017
2,133,516
2,096,814
2,058,885
2,019,705
1,979,247
1,937,487
1,894,397
(1,311,300)
(1,304,744)
(1,298,220)
(1,291,729)
(1,285,270)
(1,278,844)
(1,272,449)
(1,266,087)
(1,259,757)
(1,253,458)
(1,247,191)
(1,240,955)
(1,234,750)
(1,228,576)
(1,222,433)
(1,216,321)
(1,210,240)
(1,204,188)
(1,198,167)
(1,192,177)
-
1,198,348
1,182,060
1,164,800
1,146,549
1,127,287
1,106,994
1,085,649
1,063,231
1,039,717
1,015,086
989,316
962,384
934,267
904,940
874,381
842,564
809,465
775,059
739,319
702,220
(266,419,585)
(221,739,093)
44,680,492
(25,016,855)
-
19,663,637
Total Production over Project Life 2,501,685,544 kWh
Cost to District, Business as Usual
(266,419,585)
Total Costs over Project Life
(246,755,948)
Total Savings over Project Life $ 19,663,637
Average Levelized Cost of Wind
0.0989 per kWh
Notes:
Fig. 23 84 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 a) Pre‐paid PPA A final structure the District should consider is a pre‐paid PPA. Under this structure the District would sign a PPA with an independent developer that allows the District to pay the entire cost of the prospective electricity delivered up front, which is then used as capital to finance the transaction. In return, the District receives a discount on the total electricity provided. This type of arrangement is possible with wind power for several reasons: 1) the District would be able to stipulate the offtake only the P99 amount of electricity that could be produced, or the amount of electricity that will be produced with 99% statistical certainty, greatly lowering risk of overpayment and reducing uncertainty in the amount of power delivered; 2) the developer would be able to utilize the tax based subsidies to discount the net cost of development, passing on some of those savings in the form of an up‐front discount to the District; 3) any electricity produced beyond the P99 amount could be guaranteed offtaken by the District at a pre‐negotiated price per kWh, or sold by the facility’s owners at a retail rate on the market, in the latter case generating a profit source for the facility owners which may also be passed on in part to the District as a discount on the pre‐pay amount; 4) the developer would be able to offer a further pre‐pay discount if the District did not need to retain the RECs generated by the project. In sum, it may be possible for the District to acquire, at a significant discount to a standard pay‐as‐you‐
go PPA which charges per kWh consumed through time, a virtually guaranteed amount of electricity from clean wind power. The downside to this scenario from the District’s perspective is that, even with the discount, the District would still have to find some way to finance a still significant up‐front payment. Thus, any financing costs in the transaction would have to be amortized and added through time to adjust the final levelized cost calculation and determine how much savings through time are possible under this structure. This analysis is done in three stages. The first (a) compares a baseline in a P99 guaranteed offtake scenario between a 100% public bond financing and a 100% commercial loan financing AT NO DISCOUNT to the cost of development. The second (b) performs a sensitivity analysis to determine how varying amounts of discounts affect the economics of the transaction for the District. The third (c) then discusses what discounts the District might reasonably expect from developers in the market, and why. 85 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 a) P99 comparison, public bond and commercial finance Indicator 100% Public Bond Finance 100% Commercial Loan Finance $0.1186 per kWh $0.1239 per kWh ($32,603,832) YR 1 LCW $0.0821 per kWh 20‐yr Average LCW $0.0856 per kWh 20‐yr Net Savings $39,146,589 Net Savings as Percent of 15.3% ‐13.10% Baseline WACC 3.95% 8.5% 20‐yr Project NPV $24,924,592 ($17,955,632) discounted @ WACC Project Avg DSC ratio 1.23 N/A 20‐yr Project IRR 6.57% 6.06% Fig. 24: Comparison of three financing structures It is important to note before discussing the results above that a 100% commercial loan financing scenario is unlikely. In such case there will need to be either a minimum combination of equity, equipment pledge, and/or 3rd party guarantees which will have their own costs within the deal. The 8.5% WACC in this estimate is something of a best‐case scenario for cost of capital in a commercial financed transaction pre‐paid PPA transaction, and is modeled as if the cost were a 20‐year fully amortizing loan for total capital costs. The authors chose this route to keep the analysis simplified, and provide a base for which at the best of circumstances the minimum discount that would be required. To the extent that estimated WACC increases from there, a greater discount would be required. It is clear that under the public bond finance option, even with no discount the potential for savings for the District is great, with positive cash flows starting from year 1 and a large positive project NPV. In effect, compared to a commercially financed PPA, the relative cheap interest rate of the public bond acts as its own discount. Thus, we know that at a capital cost of just under $100 million for a 50MW wind facility, if the District pre‐paid using public bonds for the P99 amount of wind power from the facility, the District could save nearly $40mil over 20 years, or $2mil per year. b) Sensitivity Analysis Because public bond finance for such a transaction is still in question for the District, the cost of commercial finance must be analyzed as well. So the question becomes, at what discount to total development costs could the District use commercial finance (under the best‐case cost of capital assumptions for a commercially financed deal above) to match the public bond finance option? The answer using the current model is a 35.6% discount on the privately financed total development costs of $101 million, or a total pre‐paid price for the P99 amount of electricity (which for a 50MW 86 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 wind farm is about 19.6% of total kWhs that will be required by the District over the next 20 years) of $67.14 million. Item …to equal to public bond …to equal 50% of public bond financing net savings scenario’s net savings Total Development $101 million $101 million Costs, 50 MW Discount required for a 33.6% 24.4% P99 pre‐paid PPA Net price paid to $67,144,956 $76,406,390 developer for P99 power 20‐Year Net Savings to $39,146,589 $19,573,294 District Approx savings per 1% $1,165 mil $0.8 mil discount Equivalent cost of capital 3.95% 5.3% Approx savings per 1% $8.6 mil $6.116 mil cost of capital Fig. 25 Importantly, the result cannot be used to determine an approximate amount of discount per unit cost of capital because the effect is non‐linear. In any case, given all the assumptions that have been made throughout the analysis, it will be critical for the District to re‐model its options using deal‐specific data to ensure it is achieving the desired savings. c) Would such a discount be reasonable from the perspective of a developer? Thus far it has been shown that a pre‐paid PPA even at no discount would save the District at least $2 million per year for 20 years for the P99 amount of wind from an average 50MW wind farm. Under best‐case commercial financing cost assumptions, it has been shown that the District would have to negotiate a nearly 35% discount to estimated total development costs with an independent developer to achieve similar results. Even if the District could negotiate only a 25% discount, the savings would still be nearly $1 million per year, and cash flow positive from year 1. Table 9 on the following page shows net savings to the District under a pre‐pay scenario for various discounts to actual development costs for P99 power over 20 years compared to multiple cost of capital assumptions. Focusing on the scenarios described in (b), and still assuming a WACC of 8.5%, let’s assume further that the District’s goal is $1 million savings per year, or at least $20 million of total savings. At this transaction cost of capital the District would need to negotiate a 25% discount to actual total development costs with the developer in order to achieve the desired savings. Would the developer be willing to sell the power at such a discount? 87 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 A more inclusive way to ask the question analytically would be to ask what is the highest discount the developer might be willing to sell the P99 amount of electricity from a 50MW wind farm. First, in the current regulatory environment, it is possible to receive a cash grant from the Treasury department for 30% of eligible costs (usually 97‐98% of total development costs). Based on this, the developer would be willing to accept some discount up to 28%. Further, the developer would be able to sell any additional kWhs of electricity produced (say, up to the P50 amount, or roughly 30% of the electricity at the P99 amount), potentially at spot market or retail prices which would increase the profits of the developer. Let’s assume the developer earned a gross profit rate of $0.045 per kWh of on the net 30% extra (P99 – P50) amount of electricity sold. Finally, let’s assume after the treasury grant, the net cost of capital on the remaining 72% of development costs for the developer is 10.5%. How much would the extra revenue from the additional sales of electricity affect the discount the developer could reasonably offer the district. The answer based on the author’s analysis is up to roughly $14 million, or about 14% of extra discount the developer could pass on to the District and still meet their return targets (because the 10.5% WACC estimate assumed above includes a return on equity). This is because the developer would be getting in total over $33 million in total extra revenues, discount at 10.5% over 20 years is equal to roughly $14 million. If the developer offered the District an extra 14% discount, that would be a total discount of 42%, or a net price for P99 power (about 1.88 billion kWhs over 20 years) from the 50MW wind farm of about $58.5 million. Even at an 8.5% cost of capital and assuming no inclusion of public money, this would net the District over $57 million in total savings in 20‐years, or nearly $3 million per year. 88 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 WACC
PREPAID PPA: NET SAVINGS AS FUNCTION OF COST OF CAPITAL AND DISCOUNT TO DEVELOPMENT COSTS
(in thousands)
3.5%
4.0%
4.5%
5.0%
5.5%
6.0%
6.5%
7.0%
7.5%
8.0%
8.5%
9.0%
9.5%
10.0%
10.5%
11.0%
0%
50,607
31,972
13,337
- (5,298)
- (23,933)
- (42,568)
- (61,203)
- (79,838)
- (98,473)
- (117,108)
- (135,743)
- (154,378)
- (173,013)
- (191,648)
- (210,283)
- (228,918)
5%
60,227
42,966
25,706
8,445
- (8,816)
- (26,076)
- (43,337)
- (60,598)
- (77,858)
- (95,119)
- (112,380)
- (129,640)
- (146,901)
- (164,162)
- (181,423)
- (198,683)
Percentage Discount to Total Development Costs
10%
15%
20%
25%
30%
35%
69,521
78,489
87,131
95,446
103,435
111,098
53,588
63,837
73,714
83,217
92,347
101,104
37,655
49,186
60,296
70,988
81,259
91,111
21,722
34,534
46,879
58,758
70,171
81,117
5,789
19,882
33,462
46,529
59,083
71,124
- (10,144)
5,230
20,044
34,299
47,995
61,130
- (26,077)
- (9,422)
6,627
22,070
36,907
51,137
- (42,009) - (24,074)
- (6,790)
9,841
25,819
41,144
- (57,942) - (38,725) - (20,208)
- (2,389)
14,731
31,150
- (73,875) - (53,377) - (33,625) - (14,618)
3,642
21,157
- (89,808) - (68,029) - (47,042) - (26,848)
- (7,446)
11,163
- (105,741) - (82,681) - (60,459) - (39,077) - (18,534)
1,170
- (121,674) - (97,333) - (73,877) - (51,306) - (29,622)
- (8,824)
- (137,607) - (111,985) - (87,294) - (63,536) - (40,710) - (18,817)
- (153,540) - (126,636) - (100,711) - (75,765) - (51,798) - (28,811)
- (169,473) - (141,288) - (114,129) - (87,994) - (62,886) - (38,804)
40%
118,433
109,488
100,542
91,597
82,651
73,706
64,760
55,814
46,869
37,923
28,978
20,032
11,087
2,141
- (6,804)
- (15,750)
45%
125,441
117,497
109,552
101,608
93,664
85,719
77,775
69,830
61,886
53,942
45,997
38,053
30,108
22,164
14,219
6,275 Table 9: Total 20‐year net savings amounts as a function of cost of capital and net pre‐paid PPA price discount (relative to total development costs) that might be offered by a developer. Numbers are in the thousands. 89 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 XI. Risk Analysis – Ratings Underwriting Criteria One of the methods for understanding risk in a wind project is to look at underwriting requirements for lending institutions in such projects. Fitch Ratings, one of the top global ratings agencies, has made available several public documents that outline key considerations when it rates bonds secured by wind projects in the U.S.42 Broadly speaking, their analysis will assess volatility in revenues and volatility in expenses and ongoing required capex. The following table summarizes the general guidelines and relates them to the District’s wind project under consideration: Risk Criteria Fitch general guideline District wind project (assuming ownership) Regulatory Stable regulatory regime There are no particular Fed, state or District level regulations that would impact this project more than a standard U.S. based wind project Price Relative level of volatility to In all cases the District will have to contractually set a the extent there is contractual baseline 20‐year future electricity price expectation and price control guarantee savings that accrue compared to that baseline Construction Strong counterparty with District should partner with experienced developers and industry‐standard contractual contractors, and invest in legal counsel to insure strongest protections in case of delay, possible terms and conditions based on underwriting poor management, mistakes, criteria – if buying into existing project under etc. Inclusion of appropriate development, these should be present already contingencies and equity backstops during construction Wind Strength and stability of wind Experienced wind resource engineers capable of producing resource resource – baseline for model underwritable predictions of wind power at a given site up to P99 confidence should be engaged is P90 wind scenario Technology Commercially proven All major suppliers offer “conventional” technologies from technology with strong underwriting perspective. Several major global suppliers counterparty support should bid on price – technology chosen should take price, O&M history, warranty, and other supplier credits into consideration Operations Good O&M contracts with Emphasizes importance of choosing proper development large experienced firm, strong partners and/or engaging competent and well‐solvent balance sheet, clear and technology and O&M counterparties favorable terms, including supplier warranty Availability Strength of technology and Emphasizes importance of choosing proper development O&M plans partners and/or engaging competent and well‐solvent technology and O&M counterparties Supply chain Supply chain for wind turbine Choice of turbine supplier should also gauge delivery time delivery should not unduly and be within acceptable risk boundaries for construction completion influence completion Table 10: General bond underwriting guidelines from Fitch Ratings for onshore for‐profit wind facilities. 42
“Rating Criteria for Onshort Wind Farms Debt Instruments”, Global Infrastructre & Project Finance, Fitch Ratings, www.fitchratings.com, 25 March 2009. 90 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Fitch Ratings also published a specific case study43 for a diversified wind portfolio describing in detail the various factors that were considered in issuing a large, long‐term commercial debt credit rating for bonds secured primarily by project revenues. The rating achieved by the bond issuance in the case study was BBB‐, which is considered “investment grade” by Fitch rating standards. Key project and bond issue characteristics that contributed to the investment grade rating, and which can serve as example reference data points when the District considers its own project, included: •
•
•
•
•
•
•
•
Commercially proven technology Strong turbine warranty from large turbine supplier 5‐year extended manufacturer maintenance agreement additional to supplier warranty Fixed price PPA with investment grade utility Large experience construction contractor with strong damage provisions for construction delays and performance requirements Fully backstopped equity commitment during construction Equity rent reserve required to pay debt portion up to 12 months in advance DSCRs >1.2x for entire project life under below‐average operational expectation assumptions In addition, anecdotal conversations with Fitch Ratings representatives indicate that, similar to the District’s needs for this wind project, there are precedents for investment grade project bonds being issued when primary project revenues are savings‐based, such as in energy efficiency projects where cash flows come from lowered cost compared to a predicted baseline into the future. Public data on the specific cases are not available, but it is clear that the District should seek to limit the volatility of predicted savings revenues by agreeing to a baseline “business as usual” electricity price and contractually reaching an effective fixed cost for wind energy . Methods to do this may vary depending on the structure. For example, a long‐term PPA with a project developer would automatically be “contractually fixed” from the perspective of ratings agencies. In a public bond scenario, as long as bond tenor is at least as long as predicted project life, the cost would be effectively fixed. In a private scenario would be more complex, but the vast majority of costs of each strip of financing and operating expense can either be fixed or at least set by easily predictable formulas within “investment grade” bounds. XII. Sensitivity Analysis – Testing Key Assumptions Given the large number of moving parts in this analysis, the authors have chosen to narrow the sensitivity analysis to look at the most key development, operational and financial issues using the greenfield development scenario model. 43
“Alta Wind 2010 Pass‐Through Trust”, Global Infrastructre & Project Finance, Fitch Ratings, www.fitchratings.com, 9 July 2010. 91 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Again, in the public bond financing greenfield development scenario the base assumptions used were: Development Costs
Pre‐Development Turbines Delivered
Interconnection
Balance of Plant and Install
Capitalized Interest
Construction Contingency
Reserve Capitalization
Total CAPEX
•
•
•
•
•
•
•
•
•
•
•
total
400,000
82,500,000
1,250,000
1,750,000
3,601,413
4,275,000
3,000,000
$ 96,776,413
per KW
8.00
1,650.00
25.00
35.00
72.03
85.50
60.00
1,935.53
Capital Structure
Public Bond
Grant
CREBs
PTC
Permanent Debt
Tax Equity
94,776,413
2,000,000
96,776,413
CREBs were included as the only other post construction capital source besides bonds at $2 million Construction was financed by the bond proceeds at 3.95% for 100% of the costs, less CREBs Construction period was 12 months and placed in service occurred Jan 1, 2013 100% of construction period interest was capitalized Capital costs before construction interest were $92,175,000, with installed turbine costs accounting for 89.5% of that total. Capacity nameplate was set at 50,000kW with 30% capacity factor resulting in 131,130,000kWh per year An efficiency‐loss factor of 0.5% per annum was included After inclusion of construction period interest, total cost per MW equaled $1.885 million Total capital costs post construction were funded by a 3.95%, 20‐year public bond No extra cost provision was included for a locational marginal pricing (LMP) charge Other key operating costs were estimated as follows: 92 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Operations
2009 DC annual energy consumption
2010 DC energy generation paid cost
Annual energy price escalator
Annual energy consumption escalator
Firming Premium
Location Marginal Pricing (LMP) excess
Operating Costs
Yr 1 O&M
Escalator
Insurance
Ongoing CAPEX (5yr warranty)
Minor (20-yr amort)
Major (20-yr amort)
Reserve Account Interest
Land Lease
404,590,807
$ 0.087
1.50%
1.50%
$
0.0100
$
$
$
$
$
$
$
1,346,908
0.01275 per kWh
3.00% per year
325,000 per year
185,625
412,500
2.50%
175,000
Figure 26: Select operating assumptions for Financing Option 1 93 | P a g e Unit
kWh
per kWh
per year
per year
per kWh
per kWh
per
per
per
per
year
year
year
year
Draft Wind Energy Assessment District Department of the Environment April, 2011 The table below summarizes the results of the sensitivity analysis: Sensitivity Criteria How Tested To Amount Capital Costs ($1,935 per kW) Wind resource/ Availability (capacity factor at 0.30) Maintenance (O&M + ex‐
warranty ongoing amortized capex, $1.94 mil in year 1) Financing Cost, including any subsidies (3.87% WACC) Comparative Baseline Cost Escalator (at 1.5%) 94 | P a g e Resulting Net Savings (baseline = +$49 mil) Effect on Net Savings (Δ%) Effect on LCW (Δ%) Effect on 20‐
year Cash Flows (Δ%) Comments Increase by 10% $2,129 per kW +$35 mil ‐(28.8%) +6.4% ‐(31.94%) •
Cash flows still positive all years Increase by 25% $2,419 per kW +$15 mil ‐(68.1%) +15.9% ‐(79.8%) •
0.270 +$29.5 mil ‐(39.85%) +7.6% ‐(44.3%) •
•
Cash flows become negative during first 5 years, but still within acceptable reserve range Net savings still +$15 mil Cash flows still positive all years 0.240 +$9 mil ‐(80.8%) +17.1% ‐(88.5%) •
0.210 ‐($15) mil ‐(130.4%) +29.4% ‐(132.8%) •
Cash flows become negative during first 5 years, but still within acceptable reserve range Cash flows negative all years O&M + amortized capex to $2.5mil yr 1 +$35.3 mil ‐(28.8%) +6.4% ‐(32.0%) •
Cash flows still strongly positive for all years Increase by 25% + Escalator to 4.5% O&M + amortized capex to $2.5mil yr 1 +$27 mil ‐(44.9%) +9.9% ‐(49.9%) •
Cash flows still positive WACC at 4.87% 4.95% bond interest +$34.1 mil ‐(28.5%) +6.3% ‐(31.7%) •
Cash flows all still positive WACC at 5.87% 5.95% bond interest +$20.4 mil ‐(58.7%) +13.2% ‐(65.1%) •
WACC at 6.87% 6.95% bond interest +$2 mil ‐(93.9%) +20.0% ‐(100.3%) Increase 100% To 3.00% +$110 mil +123.9% 0.0% +137.6% •
•
•
Decrease 50% To 0.75% +$23.5 mil ‐(52.2%) 0.0% ‐(58.0%) Decrease 100% To 0.00% ‐($200k) ‐(100.3%) 0.0% ‐(109.8%) Year 1 cash flow slightly negative, still easily manageable Cash flow negative for first 10 years Project becomes unfeasible 20‐yr savings are >$110 mil, or $5.5 mil/yr over 20 yrs Savings still strong at $23.5 mil Cash flows still strongly positive Reserve >100% maxed in last 10 years Negative savings Decrease capacity factor 10% Decrease capacity factor 20% Decrease capacity factor 30% Increase by 25% •
•
•
•
Draft Wind Energy Assessment District Department of the Environment April, 2011 Renewable Energy Credits (RECs), (none) Add at $0.015 per kWh To $0.015 per kWh, 10 yrs +$68 mil +39.0% 0.0% +43.33% •
10‐year term over first years of project life Table 27: Sensitivity analysis across key financial criteria for changes in select wind project variables using the greenfield development option financed by public bonds as the baseline scenario. 95 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Sensitivity Criteria
How Tested
Capital Costs ($1,935 per
kW)
Increase by 10%
$2,129 per kW
+$35 mil
Increase by 25%
$2,419 per kW
+$15 mil
0.270
+$29.5 mil
0.240
+$9 mil
0.210
-($15) mil
O&M + amortized
capex to $2.5mil
yr 1
+$35.3 mil
Increase by 25%
+ Escalator to
4.5%
O&M + amortized
capex to $2.5mil
yr 1
+$27 mil
WACC at 4.87%
4.95% bond
interest
+$34.1 mil
WACC at 5.87%
5.95% bond
interest
+$20.4 mil
WACC at 6.87%
6.95% bond
interest
+$2 mil
To 3.00%
+$110 mil
To 0.75%
To 0.00%
To $0.015 per
kWh, 10 yrs
+$23.5 mil
-($200k)
+$68 mil
Wind resource/
Availability
(capacity factor at 0.30)
Maintenance (O&M + exwarranty ongoing
amortized capex, $1.94 mil
in year 1)
Financing Cost, including
any subsidies (3.87%
WACC)
Comparative Baseline Cost
Escalator (at 1.5%)
Renewable Energy Credits
(RECs), (none)
Decrease capacity
factor 10%
Decrease capacity
factor 20%
Decrease capacity
factor 30%
Increase by 25%
Increase 100%
Decrease 50%
Decrease 100%
Add at $0.015 per
kWh
To Amount
Resulting Net
Savings
(baseline =
+$49 mil)
Summary Effect
Even at a very conservative $2,400 per insta
mil for 50MW installation, this project still ac
savings for the District.
Capacity factor will be extremely important in
offtake wind ownership for the District. Unde
assumptions, a capacity factor of below abo
project. P90 wind values should reflect at le
moving forward.
O&M costs themselves do not have the abili
infeasible, however they must be monitored
conjunction with others may push a project i
infeasibility.
Financing costs are critical to creating a viab
absence of subsidies, use of District bonding
low-cost, long-term bonds will be critical to p
is NOT the case in private partnership financ
subsidies would reduce total capital costs an
This is a very important item to understand b
decision on any option delivered in this repo
conducting a technical economic analysis to
range for this figure.
The sale of RECs associated with such a pr
both total return and early-year cash flow pro
Table 28: Sensitivity analysis across key financial criteria – summary analysis of predicted effects. Because the changes tested in the above model are not necessarily equivalent across criteria, the “effects” on these criteria should not be used to create an absolute ranking. However, based on these results it can be seen why all of these factors are extremely important to understand and manage in the execution of any wind project in which the District is an active participant. Of particular importance seems to be: baseline cost escalator, capacity factor, net financing cost, and RECs. Both capacity factor and net financing cost are important because, at high‐stress (very conservative but still within reason) assumption levels, the project can become unfeasible from a risk/return perspective, even to the 96 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 point of being generating negative savings. RECs are important because they increase early year cash flow significantly, and also provide a significant boost to total savings, making projects that weren’t feasible due to early year cash flow problems become much more attractive. Finally, the model is perhaps most sensitive to the comparative baseline cost escalator. For example, even under otherwise medium assumptions, if the average cost of energy in a “business as usual” case to the District does not change appreciably over the next 20 years (denoted in the model by a 0% baseline cost escalation factor), then the District will find creating a financially feasible project quite difficult. However, if the baseline cost escalator is increased to 3%, or roughly equivalent to CPI (not an unreasonable assumption given historical energy price changes and expectations for future changes in this region), the project is almost certain to be extremely successful, with potential 20‐year savings in excess of $100 million for the District. Thus, establishing this with some reasonable level of certainty is a critical factor for the District in assessing the potential of direct‐
offtake wind. XIII. Summary of All Financial Results It is clear that the District can save money by adding direct‐offtake wind energy to its electricity portfolio under reasonable assumptions. In some cases, the extra savings justifies the potential risks involved, while other cases must be considered more carefully. Thus, the risks involved in adding wind energy specific to each scenario compared to a conservative financial assessment of savings will be a deciding factor. Further, depending on the strategy chosen, an analysis of the barriers to each option must be understood. At this time the authors are ruling out purchasing an existing project at year 10 because, although he PTC will have expired and the investors with a tax avoidance appetite may have exited the project corporation, it is unlikely new equity investors will be welcomed. Instead, one or more of the other partners, such as the project operator, will most likely increase their share in the project corporation. Thus, three broad options remain for adding direct‐offtake wind to the District’s energy profile: 1. Public Ownership: the District seeks to take an ownership stake in a new wind development a) Using some form of public bond 2. Private Partnership: the District partners with a private owner/developer so as to enable the use of tax‐
based subsidies a) Treasury grant still available b) Treasury grant expires and production tax credits (PTCs) are used 3. Independent PPA: the District enters into a PPA with an independent wind power supplier a) Long‐term standard PPA b) Pre‐paid PPA Two charts below summarize the annual cost and net savings differential compared to “business as usual” for the District. As can be seen, all but one of these potential scenarios generate positive cash flow for the District 97 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 starting in year one under current assumptions. Even the scenario whose savings in initial years are slightly negative (private partnership using PTCs) ultimately generates large savings over 20‐years, making up for the initial “loss”. In fact, even this loss is not a true loss, but just a slight increase in average cost of electricity of the District, equivalent to just 0.01% per year during the period until breakeven, at which point the gains in the remaining years of the project skyrocket. All others scenarios generate positive savings revenue for the District for every year over 20 years starting in year one, meaning the District frees money to use on core programs immediately with zero cash outlay. Also, the table below indicates that total potential savings over 20‐years mirrors the approximate risk level of each scenario – higher risk projects generate the potential for higher savings, but must contend with the risks of doing so. Both long‐term and pre‐paid PPAs offer the greatest certainty of savings, and the easiest ability to manage that risk up front. Of the two, pre‐paid PPAs offer the potential for greater savings but must be financed up front and thus carry greater risk for the District. 98 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Cost Comparison Summary:
16,000,000
Cost Curves of Options to Add Direct‐Offtake Wind to the District's Energy Portfolio
15,000,000
Baseline, No Wind Total Cost
$266 mil
Amount ($)
14,000,000
$247 mil
13,000,000
12,000,000
$227 mil
$217 mil
11,000,000
10,000,000
Ownership, Public Bonds
Private P‐shp w/T.Grant
Private P‐shp w/PTCs
Long‐term PPA
Pre‐Paid PPA
Baseline
9,000,000
8,000,000
7,000,000
$194 mil
$204 mil
6,000,000
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20
Year
Fig. 29 99 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Savings Revenue Comparison Summary:
7,500,000 20‐Year Savings
Savings Options to Add Direct‐Offtake Wind to the District's Energy Portfolio
6,500,000 $62 mil
$72 mil
Baseline
Ownership, Public Bonds
5,500,000 Private P‐shp w/T.Grant
Amount ($)
4,500,000 Private P‐shp w/PTCs
Long‐term PPA
3,500,000 $49 mil
$39 mil
Pre‐Paid PPA
2,500,000 1,500,000 $19 mil
500,000 $0 mil
‐500,000 Baseline, No Wind ‐1,500,000 1
2
3
4
5
6
7
8
9
10
11
Year
Fig. 30 100 | P a g e 12
13
14
15
16
17
18
19
20
Draft Wind Energy Assessment District Department of the Environment April, 2011 Summary of Risks Compared to Potential Savings by Scenario
Scenario 20‐Year Cost ($) 20‐Year Savings ($) Relative Risk Level Baseline 266 mil None Low Ownership, Public Bonds 217 mil 49 mil Medium‐
High Pvt Pship, T.Grant 194 mil 72 mil High Pvt Pship, PTCs 204 mil 62 mil High Long‐Term PPA 227 mil 19 mil Low Pre‐Paid PPA 247 mil 39 mil Medium 101 | P a g e Key Risks Major Barriers •
None Opportunity cost of not creating savings • Uncertain future cost of conventional energy sources • 100% of: − Development risk − Construction risk − Operational risk • Energy output risk • Shared w/ private partner: − Development risk − Construction risk − Operational risk • Partnership risk • Energy output risk • Shared w/ private partner: − Development risk − Construction risk − Operational risk • Partnership risk • Energy output risk • Energy output risk • Contractual risk • Energy output risk •
•
Political will Legal questions around utility regulation and District ownership • Authority for bond finance •
•
Political will Legal questions around what structures allow the District to partner with private sector in ownership •
•
Political will Legal questions around what structures allow the District to partner with private sector in ownership None None Draft Wind Energy Assessment District Department of the Environment April, 2011 •
Table 11: Summary of risks for each potential scenario analyzed.
102 | P a g e Contractual risk Draft Wind Energy Assessment District Department of the Environment April, 2011 Selected Example Charts: Fig. 31 Fig. 32 103 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Fig. 33 104 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 XIV. Preliminary Findings and Recommendations Findings: 1. Long‐term PPA price bids from independent power producers should be considered the key benchmark alternative to any other direct‐offtake scenarios the District considers (such as direct ownership, private partnership, etc), including both standard consumption‐based and pre‐paid PPA structures, as determined by a follow‐on RFP to be issued by the District. 2. An investment grade rating is possible even for “savings”‐based revenue bonds: there is historical precedent to achieve investment grade rating under standard ratings agency criteria for both commercial debt and project revenue bonds even when project cash flows are “savings”‐
based, according to both secondary data from the three primary ratings agencies and primary source data from Fitch Ratings. There is no specific criteria that ensure such a rating, but the threshold will be more strict than for a purely revenue based rating. 3. Baseline (comparative) energy price escalation is an extremely important factor when determining financial feasibility of the project: from the perspective of the District, the revenue from this project will be savings derived from a comparison to a “business as usual” baseline. The project financial model exhibits significant sensitivity to changes in assumptions of exactly how much change there would be in the District’s future average cost of electricity if the wind project were NOT undertaken. That said, in should also be noted that by using an escalation factor that simply mirrors historical consumer price index (CPI) inflation (an assumption still very much within reason), a wind project as contemplated in this report has the potential to be extremely successful. This is an very positive sign in favor of the District’s desire to add direct‐offtake wind energy to its portfolio. 4. It is possible, but not guaranteed, to achieve greater savings and lower all‐in financing costs through private partnership structures: under certain sets of reasonable assumptions it is theoretically possible to achieve a net lower cost by private partnership than with a fully public bond financing, but those assumptions cannot yet be known with enough certainty to make a final determination. Much more certain knowledge of project parameters will be critical to narrow the assumptions within acceptable bounds. Further, no matter the scenario, any extra financial benefit beyond the benchmark of a pay‐as‐you‐go or pre‐paid PPA option (if any) must be weighed against any potential legal risks attendant to some form of direct participation. 5. Non‐PPA private partnership structures are more legally and structurally complex than a publicly financed transaction: in order for the District to create opportunity to pass on a greater share of tax‐based subsidies available in private transactions than would be possible under a long‐term PPA, greater legal and structural risk may be attendant. Thorough legal analysis of the potential options 105 | P a g e 6.
7.
8.
9.
Draft Wind Energy Assessment District Department of the Environment April, 2011 for private sector partnership, with goal of maximizing utilization of tax‐based subsidies, is an important aspect of feasibility not fully considered in this report. Public bonds are not absolutely necessary, but would be strongly beneficial as an option for creating a successful cash‐flow positive project: despite the limitations of the Cap Act, public “full faith and credit” bonds are still a powerful tool to finance a project of this type, and they are worth making every effort to include as part of a feasible capital structure based on the potential relative increase in revenue from savings to the District from using them compared to the risk to the District associated with their inclusion (relative to private partnership structures). Further, if a private developer with whom the District is attempting to negotiate a PPA knows the District cannot compete with any other option, the District will lose negotiating leverage not just on price but on other key terms of the PPA. No strategic scenario can yet be rejected based on the financial analysis alone: this report analyzed multiple options the District can pursue to add direct‐offtake wind into its portfolio. It was possible to find some combination of reasonable assumptions under which all scenarios analyzed in this report, whether privately or publicly financed, were financially feasible. It is important to begin to narrow down the list of assumptions with real project data. In addition, the final decision must rest on an analysis of other general risk factors associate with each strategy in conjunction with the financial feasibility of a specific project once the specific outline and details of that project are known. It is possible, both technically and economically, to blend the day‐to‐day uncertainty of wind production into the District’s existing energy portfolio (e.g., “firming”): technical methods are available for dealing with the day‐to‐day supply uncertainty at the inclusion ratio under consideration in this report (roughly 20‐30%), otherwise known as “firming”; the cost of firming wind into the District’s energy portfolio at these levels can be economical and still allow the District to achieve its cost‐savings goals, but will depend on the other costs as to the relative flexibility the District will have around this expected cost. Under any greenfield development scenario, development risk must be weighed very carefully: development risk in wind projects is an entrepreneurial‐level risk the District should closely consider in relation to marginal returns above a long‐term or pre‐paid PPA. If such reasonably expected extra return does not meet the requirements of the large extra step‐up in risk, the District should not pursue that path. Our results show that gaining such extra return to compensate for the risk is possible, but not guaranteed. It will be difficult for the District to fully mitigate its exposure to that risk under a direct ownership scenario. 106 | P a g e Draft Wind Energy Assessment District Department of the Environment April, 2011 Recommendations: 1. The District should solicit independent PPA wind price bids for both pay‐as‐you‐go (standard consumption‐based) and pre‐paid PPAs with independent power producers (IPPs) or other wind energy suppliers in a follow‐on RFP to establish that option as a comparative potential opportunity (relative little cost, large potential gain) 2. The District should conduct a formal search for potential new wind projects in the region with which to partner: it was shown in the financial analysis of this report that it is possible under a set of reasonable assumptions to generate financially attractive risk‐adjusted savings by partnering with a private developer in a new development. The goal of the search would be to identify two or more potential developers who have experience partnering with tax‐exempt entities such as the District and with the capacity and track record to successfully develop at least 50MW of wind power, and request them to propose project ideas and pricing for review. 3. The District should conduct a formal search for existing operational wind farms for potential purchase: it was similarly shown in the financial analysis of this report that it is possible under a set of reasonable assumptions to generate financially attractive risk‐adjusted savings by purchasing a wind facility at the end of tax‐based subsidy period. The goal of the search would be to identify at least two existing projects with strong operating track record at a 50MW capacity or greater who are open to an exit to a tax‐exempt entity such as the District, and approach them about opening a due diligence process. 4. The District should generate a statistically significant estimation of its expected future energy price under “business‐as‐usual” conditions: this should be undertaken given this figure’s importance in the financial feasibility analysis of any wind project for the District. It should offer some reasonable estimate as a range, within 90% confidence interval or better that would establish an objective assumption to use with any follow on financial analysis. This would significantly improve the objective validity of any financial analysis. 5. The District should seek definitive legal clarification of private‐sector partnership options and risks: the District should seek final legal clarification over whether and how it can partner with the private sector in projects that use tax‐based subsidies. There is significant legal risk (e.g., “recapture” risk from the IRS in which the subsidies could be revoked and return of them demanded with interest) in a tax‐exempt entity owning in any way an asset that receives tax‐based subsidies such as tax credits. There may be structures in the market as discussed in this report that can mitigate this risk and allow the District to legally take advantage of such subsidies, but a thorough legal analysis is a critical component in determining the specifics of those options, their respective risk profiles, and their appropriateness for any prospective project. 107 | P a g e