Lava Law. Legal Issues in Geothermal Energy Development. C o m p l i m e n t s o f

Transcription

1 F i f t h E d i t i o n w w w. s t o e l. c o m Lava Law Legal Issues in Geothermal Energy Development C o m p l i m e n t s o f

2 Geothermal Energy Team Attorney team members are admitted to practice in the following jurisdictions: WASHINGTON Jennie L. Bricker Jerry R. Fish Timothy L. McMahan Alan R. Merkle Karl F. Oles OREGON Jennie L. Bricker Edward D. Einowski Jerry R. Fish Stephen C. Hall Christopher M. Heaps William H. Holmes Karen E. Jones Jennifer H. Martin Timothy L. McMahan Mary Jo N. Miller Marcus Wood IDAHO Kevin J. Beaton Krista K. McIntyre UTAH Martin K. Banks John M. Eriksson Clint M. Hanni John S. Kirkham CALIFORNIA Randall M. Faccinto John A. McKinsey Howard E. Susman NEVADA Jennie L. Bricker Randall M. Faccinto

3 Ta b l e o f C o n t e n t s Lava law Legal Issues in Geothermal Energy Development 1. Just Starting Out: Leasing, Siting, and Permitting Geothermal Energy Projects Jerry R. Fish Christopher M. Heaps 2. Running Interference: Groundwater and Related Features of State Regulation Jennie L. Bricker John S. Kirkham 3. Signing Up: Power Purchase Agreements and Environmental Attributes John M. Eriksson William H. Holmes Karen E. Jones 4. Setting Up Shop: Design, Engineering, Construction, and Turbine Purchase Agreements Alan R. Merkle Karl F. Oles 5. Penciling Out: Project Finance for Geothermal Power Projects Edward D. Einowski Mary Jo N. Miller 6. Getting Some Credit: Tax Issues Robert T. Manicke Kevin T. Pearson 7. Delivering the Goods: Regulatory and Transmission- Related Issues Stephen C. Hall Jennifer H. Martin Marcus Wood 8. Resumes and contact INFORMATION Lava Law, Fifth Edition is a publication of the Stoel Rives Geothermal Energy Team for the benefit and information of any interested parties. This document is not legal advice or a legal opinion on specific facts or circumstances. The contents are intended for informational purposes only. Copyright 2008 Stoel Rives LLP.

4 WELCOME TO THE LAW OF LAVA Dear Member of the Geothermal Energy Community, As a reliable renewable energy source, geothermal can help power our homes and businesses and buttress local economies while leaving cleaner skies for our children. Major global corporations, new sources of investment capital, and power buyers large and small have been drawn to geothermal power. The Energy Policy Act of 2005 provided long-awaited federal support. At the same time, more and more states are crafting legislation to support renewable energy and a cleaner environment, including renewable portfolio standards and tax incentives. The industry outlook for geothermal energy is strong. Nonetheless, geothermal energy projects, like other major energy projects, face a plethora of real property issues, regulatory and permitting requirements, interconnection, transmission, and power purchase negotiations, financing challenges, construction contracting issues, and tax considerations. Recognizing these challenges, and as part of our commitment to the growth and success of the renewable energy industry, in 2004 the Stoel Rives Geothermal Team developed LAVA LAW: Legal Issues in Geothermal Energy Development. This guide contains insights we have gained during the last eleven years of serving the U.S. geothermal industry. You have in your hands the Fifth Edition of LAVA LAW, revised in 2008 to reflect the current state of play on the legal and policy issues most likely to affect the geothermal industry generally and the development of individual geothermal projects. We update this publication annually, so please contact us with any comments. Stephen C. Hall, Chair Stoel Rives Renewable Energy Team schall@stoel.com direct Portland fax STOEL RIVES LLP 2008 Introduction Pg. 1

5 Chapter One THE LAW OF LAVA Just Starting Out: Leasing, Siting, and Permitting Geothermal Projects Jerry R. Fish, Christopher M. Heaps Although geothermal energy projects are commonly praised for producing sustainable, base load power with minimal environmental impacts, they have rarely received preferential leasing and permitting treatment. With the enactment of the Energy Policy Act of 2005 and adoption of the Bureau of Land Management s ( BLM ) Geothermal Strategic Plan, the winds of change may be beginning to blow in a more favorable direction. The Energy Policy Act substantially altered the manner in which geothermal leases are issued, and directed the Secretaries of Interior and Agriculture to make timely completion of administrative actions relating to geothermal development a priority. The Energy Policy Act also required that future forest and resource management plans for areas with high geothermal resource potential consider geothermal leasing and development. Likewise, the BLM Geothermal Strategic Plan aims to improve the agency s effectiveness and efficiency in processing lease and permit applications. Despite these changes, geothermal developments still raise local land use, environmental, and community concerns similar to those raised by other commercial and industrial projects. Several of the country s largest proposed geothermal developments have faced such concerted local opposition that their schedules and pro formas have been affected, leaving their futures in doubt. This has sensitized project financiers, who scrutinize permitting and environmental issues closely. In this climate, project developers can achieve a significant competitive advantage by doing leasing and permitting the right way: imposing a disciplined focus on site assessment, due diligence, early land control, project design, and strategic consultation with interested agencies, communities, and interest groups. I. Geothermal Development on Federal Lands. Approximately 90 percent of geothermal resources in the United States are located on federal lands, particularly those within eastern Oregon, western Utah and Idaho, and much of Nevada and California. Therefore, successful development of geothermal resources requires a keen understanding of federal leasing and permitting. A. Obtaining Leases. The Secretary of the Interior has delegated authority to the BLM to issue geothermal leases under a leasing program similar to that employed under the federal Mineral Leasing Act. Developers with experience in federal oil and gas leasing will likely be familiar with many parts of the geothermal leasing process. Actual ownership of geothermal resources beneath federal lands is retained in the federal mineral estate. The BLM grants access to this resource primarily through a competitive leasing process established by the Geothermal Steam Act of 1970, as amended. Formerly, exploration leases were awarded through a competitive bidding process only in BLM-designated Known Geothermal Resource Areas ( KGRAs ). Following the enactment of the Energy Policy Act, all geothermal leases are offered on a competitive basis, not just those in KGRAs. The Energy Policy Act directed the Secretary of the Interior to accept nominations for land to be leased at any time from any qualified company or individual. Competitive lease sales must be held at least once every two years in states where nominations are pending. Parties may submit bids pursuant to a BLM-established bidding process through which leases are awarded to the highest responsible qualified bidder. Rents and royalties are then assessed in STOEL RIVES LLP 2008 Ch. 1 Pg. 1

6 addition to the bonus bid. If a competitive lease sale is held for a land tract, but no competitive lease sale bids are received, then that land tract will be available for noncompetitive leasing for a two-year period. Likewise, lands subject to existing mining claims may also be available for noncompetitive leasing. Leases may also be available for competitive bidding as a block. If a geothermal resource can reasonably be expected to underlie more than one nominated parcel, the several parcels that encompass the common geothermal resource may be offered for bidding as a block in a competitive lease sale. Not all land is available for lease. In general, leases may be issued only on land administered by the BLM or the U.S. Forest Service, or land that the federal government has conveyed to a private party but in which it has retained mineral rights. Geothermal leases may not be issued in national parks, monuments, wildlife refuges, national recreation areas, wilderness areas, wilderness study areas, and similar protected areas, as well as Indian trust lands and reservations. Additionally, no permits can be issued that would cause an adverse impact on significant thermal features of the National Park System, including the Crater Lake, Mount Rainier, and Lassen Volcanic national parks. Upon the establishment of new protected areas (for example, the Mount St. Helens and Newberry national volcanic monuments), the BLM has exchanged geothermal leases originally within the monuments for leases outside the monuments. B. Cooperative Agreements. Cooperative resource development is essential when a common geothermal reservoir or field underlies several leaseholds. When this occurs, issuance of stand-alone leases may result in unnecessarily rapid resource depletion, as lessees compete to appropriate a greater share of the resource. Subject to BLM approval, lessees in such areas are allowed to bundle their leases into unit agreements in order to cooperatively develop the underlying resource. When a common geothermal resource is especially at risk of being overdeveloped and the public interest so requires, the Secretary of the Interior may require the formation of a unit agreement between lessees. The Secretary must review all unit agreements every five years and may remove any land not necessary for unit operations. C. Lease Acreage Limitations. Previously, the Geothermal Steam Act limited geothermal leases to a reasonably compact area of 2,560 acres per lease. The Energy Policy Act has expanded this acreage limitation to 5,120 acres. Additionally, the limitation on total control and ownership of geothermal leases within any one state has been expanded from 20,480 acres to 51,200 acres. Acres that are committed to a unit do not count against the 51,200-acre limit. Developers must pay careful attention to these limits, because the BLM may cancel leases of parties holding more than the maximum. D. Lease Terms. Geothermal leases are issued for a primary term of 10 years. For leases issued before August 8, 2005, if geothermal steam is produced or used in commercial quantities within the primary term of the lease, the lessee may extend the primary term for up to an additional 40 years. If, at the end of the 40-year term, geothermal steam continues to be commercially produced and used, the lessee has a preferential right to renew the lease for a second 40-year term. For leases issued after August 8, 2005, if the lessee does not reach commercial production within the 10-year primary term, the lessee may qualify for two five-year primary term extensions if the lessee either (1) meets a minimum annual work requirement, quantified as a dollar expenditure per acre, or (2) makes minimum annual STOEL RIVES LLP 2008 Ch. 1 Pg. 2

7 payments. In addition to these two five-year extensions, if at the end of either the primary term or a primary term extension the lessee is drilling a well for the purpose of commercial energy production, the lessee may also qualify for a five-year drilling extension. Once the lessee either begins producing geothermal resources in commercial quantities or makes diligent efforts to use a well capable of producing geothermal resources in commercial quantities, the lessee may qualify for a production extension of up to 35 years. So long as the lessee continues to produce or use geothermal resources in commercial quantities during the production extension, the lessee may qualify for a lease renewal period of up to an additional 55 years. All lessees holding leases issued after August 8, 2005 must pay an annual rent in advance of the year for which rental is due. For leases issued on a competitive basis, the annual rental is not more than $2 per acre during the first year and not more than $3 per acre for the remainder of the primary term (years 2-10). For leases issued on a noncompetitive basis, the annual rental is not more than $1 per acre for the entire primary term (years 1-10). For each year after the 10th year, the annual rental may be increased to not more than $5 per acre, regardless of whether the lease was initially issued through a competitive or noncompetitive process. Rental fees paid before the first day of the year for which the rental is owed may be credited against the amount of royalty that is required under a lease for that year. All geothermal leases must allow for a readjustment of lease terms and conditions at no greater frequency than every 10 years. Rent and royalty stipulations may also be adjusted after 35 years from the date geothermal steam is produced. Leases may be terminated for nonpayment of rental fees. E. Royalties. The Energy Policy Act amended the Geothermal Steam Act to reduce lease royalty percentages to between 1 and 2.5 percent of gross proceeds from the sale of electricity during the first 10 years of production under a lease. After that period, royalty payments cannot exceed 5 percent of gross proceeds. Current BLM regulations provide for a 1.75 percent royalty during the first 10 years of electricity production and 3.5 percent thereafter. The BLM allows lease applications that were either effective or pending on August 8, 2005 to be converted to these new royalty rates. If, after a lessee achieves commercial production, production ceases for any reason, a lease may remain in full force for up to 10 years so long as the lessee pays royalties in advance at a monthly average rate equal to the royalty that was paid during the period of production. Only under limited exceptions will the requirement to pay royalties be waived after a halt in production. As an additional incentive for existing leaseholders, leases in effect before August 8, 2005 may qualify for a 50 percent reduction in royalty payments during the first four years of commercial production if commercial production is achieved within six years of Energy Policy Act enactment. This also applies to qualified expansions of existing facilities. An expansion qualifies if it increases net electric generation by 10 percent within six years of the Energy Policy Act s enactment and if such production increase is greater than 10 percent of the average production by the facility during the prior five-year period. F. Agency Responsibilities. Although the BLM issues all geothermal leases on federal land, including land managed by the U.S. Forest Service, the BLM may not authorize the use of Forest Service lands without the consent and incorporated conditions of the U.S. Forest Service Chief. In addition, lands located STOEL RIVES LLP 2008 Ch. 1 Pg. 3

8 within hydropower project areas may be leased only with the consent of the Department of Energy. All leasing is discretionary, and each of these agencies may condition the grant of a lease issued on its respective land. For example, geothermal leases typically specify the degree to which a lessee may use surface lands in developing and producing underlying geothermal resources. Although the BLM has attempted to process geothermal permit applications within 90 days of submittal and issue permits within six months of the date of successful application, the BLM s dependence on actions of other federal agencies has often rendered it unable to act within these time frames. To address this problem, the Energy Policy Act required the Secretaries of Interior and Agriculture to enter a memorandum of understanding regarding coordinated geothermal leasing and permitting. The Act also required the secretaries to (1) establish uniform administrative procedures to expedite geothermal lease applications, (2) establish a five-year program for geothermal leasing of lands in the National Forest System, (3) establish a five-year program for reducing the backlog of outstanding lease applications by 90 percent, and (4) establish a joint data retrieval system for tracking lease and permit applications. G. Relation to Other Federal Resource Laws. A geothermal lease does not grant a developer an exclusive right to develop a parcel of land. Although a developer gains an exclusive right to develop geothermal resources within a leasehold, the developer does not acquire the right to develop minerals unassociated with geothermal production and does not acquire the right to prohibit others from developing minerals present within a leasehold. To the contrary, a parcel of land subject to a geothermal lease may be concurrently subject to leases issued pursuant to other federal mining and mineral extraction laws. When multiple leases attach to the same parcel of land, each lessee is under a duty not to unreasonably interfere with the development rights of others. A geothermal lease grants a developer the right to produce and use valuable by-products obtained in the production, use, or conversion of geothermal steam. However, the production or use of such by-products is subject to the rights of preexisting leases, claims, and permits covering the same land. Extraction and use of byproducts may also subject the lessee to additional royalty payments. The Geothermal Steam Act expressly disclaims any preemption of state water law, so if water is to be evaporated or consumed as part of the geothermal resource s use, a lessee may need to obtain water rights under the law of the state in which a lease is sought. Some states have created laws and regulations applicable specifically to water use in geothermal exploration or production with the goal of facilitating the development of geothermal resources. H. Federal Environmental Review. Under the National Environmental Policy Act ( NEPA ), the BLM is required to review environmental consequences of granting exploration, drilling, utilization, and commercial use permits. The BLM issues either an Environmental Assessment to support a Finding of No Significant Impact on the environment, or an Environmental Impact Statement ( EIS ) detailing all of the alternatives to permit issuance and their associated impacts on the environment. If a lease is issued before permit application, the issuance of the lease also requires federal environmental review. The level of federal environmental review of a geothermal lease depends on the degree of surface disturbance that will accompany geothermal development. No surface occupancy leases generally do not require full review STOEL RIVES LLP 2008 Ch. 1 Pg. 4

9 under NEPA, and the BLM will usually issue an Environmental Assessment with, if applicable, a Finding of No Significant Impact on the environment. The granting of a surface-occupancy lease, however, usually requires the preparation of an EIS under NEPA. The EIS must enumerate reasonable alternatives to the proposed action. NEPA does not, however, require the government to accept or reject specific lease applications. To expedite the federal leasing process and clear the current backlog of lease applications, the BLM and the Forest Service have undertaken a Programmatic EIS of geothermal leasing on BLM and Forest Service land in the Western U.S., Alaska, and Hawaii identified as having geothermal potential. Further developments beyond surface leasing may require an EIS if, in the judgment of the BLM, such developments would have a significant impact on the environment. Thus, if the terms of a surface lease do not include the ability to construct buildings, issuance of a construction permit can trigger additional review. I. Permit Requirements. BLM permits are required along each step of the geothermal leasing process: exploration, drilling, utilization (facility construction), and commercial use. Permit applications generally require a detailed identification of the land to be affected, procedures and equipment to be used, and buildings to be constructed (if applicable). The BLM may require additional information at its discretion. In general, an applicant may make minor changes to a permit application by filing a notice with the BLM instead of submitting a new permit application. All applicants must have a bond on file with the BLM. J. Exploration Permits. An exploration permit is required for any geothermal exploration activity when federal lands may be adversely affected and when a developer is present on the land. Exploration activities covered by permits include geophysical operations, drilling temperature gradient wells, drilling holes used for explosive charges for seismic exploration, and core drilling. Exploration permits are also required for related road construction or surface travel in explored areas. Although most exploration permit applicants will hold a geothermal lease, a geothermal lease is not required to apply for an exploration permit. However, the land must be open to leasing to be open to exploration. One can even apply for a permit on lands leased to others so long as the exploration does not interfere with ongoing exploration or production. Activities also must not cause unnecessary or undue degradation of the lands in keeping with the BLM s general duty to protect the public domain. If exploration is to occur on leased land administered by the U.S. Forest Service or another surface management agency, that agency must also approve the exploration permit. Applications for exploration permits must describe in detail the lands, procedures, and equipment to be used; must identify potential effects on geothermal resources; and must identify mitigation measures for surface disturbance. The applicant must also identify environmental protection measures it will take throughout the exploration process. The BLM may impose additional conditions before issuing the permit. Exploration operations must be conducted so as to afford the maximum protection to natural resources. Noise must be kept to a level that will not disturb recreation or wildlife. Most developers are required to share data collected on the leased land with the BLM annually. STOEL RIVES LLP 2008 Ch. 1 Pg. 5

10 K. Drilling Permits. Drilling permits are necessary for drilling wells and conducting activities related to performing flow tests, producing geothermal fluids, and injecting fluids into a geothermal reservoir. A drilling permit is also required for the construction of well pads or roads to access drilling operations. Unlike exploration permits, drilling permits require the applicant to hold a geothermal lease. If the drilling is to take place on land administered by an agency other than the BLM, that agency must also approve the permit. Drilling operations must in general comply with the same environmental standards as exploration operations. A separate permit application must be submitted for each well. Drilling permit applications must include a detailed plan of operations, including a description of all planned facilities ancillary to the drilling operations and a description of planned environmental protection and surface reclamation measures. A plan of operations must be submitted before any surface disturbance is made. Additionally, an applicant must submit a drilling program that describes its plan to drill, complete, and test a well. This plan may be submitted before a permit application is filed. Once a well is complete, data collected from the well must be submitted to the BLM within 30 days. Wells may not be abandoned without BLM approval. L. Utilization Permits. Utilization permits are required for construction and operation of electrical generation facilities, direct-use steam plants, and related facility and well field operations, including well field production and injection. ( Utilization is a catchall term that includes construction permits.) Either a site license or a lease and construction permit is required before beginning site preparation work for a facility. Facilities must be built on land encumbered by a geothermal lease, but the operator/applicant does not have to be the leaseholder. However, a separate site license is required if the operator is not a party to the geothermal lease. A utilization permit applicant must submit a utilization plan along with its facility construction permit application. This plan should describe the facilities that will be constructed and any expected environmental impacts, along with a plan for mitigating those impacts. It also must include, among other information, projected production rates, water usage data, and a plan for minimizing visual impacts of the facility. M. Commercial Use Permits. Once a facility has been constructed, a commercial use permit is required before commercial operations may begin. A commercial use permit application must include a description of the methods and rates of production and injection. An applicant must also inform the BLM of any existing power purchase agreements for the sale of electricity from the generating facility. II. Geothermal Development on State or Private Lands. Geothermal resources that are not located on federal land are subject to state law. Developers often encounter hurdles developing this land because states have different ways of defining the resource, determining ownership, and issuing permits. A. Mineral or Water. Many states do not clearly delineate geothermal resources from mineral or water resources. This can create confusion for developers because the ownership of mineral or water rights may also entail the right to develop geothermal resources. Washington State, for example, defines the geothermal resource for other than direct use to include only the heat energy in extracted water that is practical for use in commercially producing electricity. Under this definition, the resource is neither mineral nor water, but a resource unto itself. In contrast, Wyoming characterizes geothermal resources as a water resource. Hawaii and California consider geothermal resources to be part of the mineral estate. Utah treats geothermal fluids as a STOEL RIVES LLP 2008 Ch. 1 Pg. 6

11 special kind of underground water resource, but ownership of the geothermal resource derives from an interest in land and not from an appropriative right to geothermal fluids. B. Geothermal Resource Ownership. States have taken different approaches to determining ownership, depending on how the geothermal resource is characterized. Often, a landowner will own the rights to both the surface land and the underlying geothermal resources, but sometimes surface ownership is severed from ownership of the underlying geothermal resource. In the latter case, a developer generally must negotiate with both the surface and subsurface resource owner before drilling can begin. In Washington, geothermal rights are vested in the surface owner, while in Wyoming geothermal rights are a public resource and are only available through appropriation. In Alaska, the state claims ownership of all geothermal resources but priority to develop the resource is given to the surface owner. In Oregon, the owner of the surface property also retains ownership of geothermal resources. C. Exploration and Drilling. Many states have adopted provisions for the issuance of exploration and prospecting permits for geothermal resources on state lands. In Oregon, the Department of Geology and Minerals Industries is responsible for overseeing the drilling, abandonment, and reclamation of geothermal wells. California vests oversight of geothermal well drilling, operation, maintenance, plugging, and abandonment with the Division of Oil, Gas & Geothermal Resources within the state s Department of Conservation. In California, issuance of these permits is subject to the state s environmental review process and the Division of Oil, Gas & Geothermal Resources is the lead agency for environmental review. In Nevada, applicants seeking to drill or operate an individual geothermal well must submit an application to the Division of Minerals of the Commission on Mineral Resources. D. State Environmental Review. Some states have comprehensive environmental review statutes similar to NEPA. Washington and California, for example, require such a review. Washington s review is pursuant to its State Environmental Policy Act ( SEPA ) and California s is pursuant to its California Environmental Quality Act ( CEQA ). Oregon, Nevada, Idaho, Utah, Wyoming, and New Mexico do not have comprehensive environmental review statutes akin to NEPA. The net effect of state statutes such as SEPA and CEQA is increased processing time, additional cost, and often the imposition of additional mitigation requirements. Nevada s environmental review of geothermal developments is less stringent; usually only an environmental assessment is required and the permitting process generally takes from three months to one year, regardless of whether drilling is on private or public lands. E. Power Facility Permitting. A few states Oregon, Washington, and California included have state siting councils or boards with mandatory siting jurisdiction over the siting of geothermal power production facility development. Oregon s siting body has jurisdiction over geothermal energy facilities with a peak generating capacity of MW or greater. California s siting body exercises jurisdiction over geothermal energy facility siting for plants with a generating capacity of 50 MW or greater. Washington s siting council may exercise jurisdiction over the siting of geothermal energy facilities of any size, but only if it is requested to do so by the applicant. In each of these states, siting permits are binding on state and local political bodies, except that in Oregon a developer may choose to obtain permits directly from local land use boards. In both California and Washington, siting body determinations incorporate environmental reviews, and Washington s siting council has the authority to issue state permits under the federal Clean Air Act and Clean Water Act. Neither Idaho nor STOEL RIVES LLP 2008 Ch. 1 Pg. 7

12 Nevada coordinates facility siting at the state level. In these states, developers must obtain necessary permits from separate state and local boards and agencies. F. Local Permitting. For local siting applications, an applicant may be required to work with local planning commissions, zoning boards, and county boards. The county governing board, typically a board of commissioners, generally must approve and issue a permit, usually a conditional use permit. In most counties throughout the United States, a geothermal project is conditionally allowed in rural land use zones; it is not expressly allowed or prohibited, but rather subject to a discretionary review by the appropriate local authority. To secure a conditional use permit, an applicant typically must show that a project will be compatible with adjacent land uses (usually farming or ranching). Conditional use ordinances often require review by and consultation with state or federal agencies in the permitting process. For instance, if the project could negatively impact wildlife species listed by state or federal agencies as threatened or endangered, the appropriate state or federal agencies must be consulted. State and federal wildlife agency review may also occur as a matter of course through the environmental review process. III. Key Substantive Issues. A. Water Impacts. In early geothermal developments, wastewater was disposed of in surface ponds or rivers. Today, in almost every geothermal development worldwide, water obtained from wells is injected back into the subsurface. Not only does this minimize surface water disturbance, it also replenishes geothermal wells to help sustain the hydrothermal system. Despite this minimization of impact to surface waters, pollution discharge and consumptive use permits may still be necessary, depending on local hydrologic conditions, solute levels, and state and federal legal requirements. Geothermal fields may also present an opportunity for disposal of urban and agricultural wastewater. Even if water obtained from a geothermal system is reinjected, steam pressure typically declines as a geothermal well matures. To forestall this decline, wastewater from nearby communities can be injected into production wells in order to recover lost pressure. B. Air Impacts. Typically, geothermal power plants emit no nitrogen oxides, very low amounts of sulfur dioxide, and about one-sixth the carbon dioxide of a natural gas power plant. Moreover, airborne emissions from binary geothermal plants are essentially nonexistent, because geothermal gases are not released into the atmosphere. Nevertheless, most geothermal development still requires air discharge permits. Air discharge permits may be obtained either through a coordinated permitting body or through a state or regional board. C. Land Use Compatibility. Compliance with applicable land use criteria is typically required. If a state has a coordinated permitting body, that body s permit may operate in lieu of local permits. If no such body exists, developers may have to negotiate permits directly with local land use boards. Each county has its own land use criteria, which may be dictated by statewide land use requirements. County land use codes often have vague standards and criteria, requiring (or allowing) highly discretionary determinations of public need, public safety, and compatibility with other land uses. Typically, geothermal power plants take up little land space, using only 5 to 10 percent of the land in a project area, and, with careful design, can easily blend into the STOEL RIVES LLP 2008 Ch. 1 Pg. 8

13 surrounding environment. Therefore, in addition to supporting a power plant, surface land often can still be used for other purposes, such as livestock grazing. D. Wildlife Impacts. Geothermal energy projects can disturb wildlife and plant species. It is important to assess whether any of the species present in a project area are listed as federal or state threatened or endangered species or species of concern. This is generally determined through a database inventory of species likely to occur in a project s vicinity, combined with site visits that typically require a spring survey for plants and some animal species. E. Visual Impacts. Geothermal resource areas are often located in remote locations. Frequently, associated energy production facilities represent the only development in otherwise undisturbed natural areas. As such, they can often draw the attention of environmental groups in spite of their significant environmental benefits compared with other forms of energy production. Visual impacts can be greatly minimized by using air cooling, a low profile, colors that match the natural landscape, and natural landscaping. F. Cultural Resources. Geothermal fields are sometimes associated with Native American cultural sites. When appropriate, early and constant involvement of local Native American tribes is advisable. Mitigation may also be necessary. Mitigation typically requires avoiding protected sites or moving protected sites if they cannot be avoided. In addition, it may be necessary to have an expert in native culture or paleontology on site during construction to protect identified sites and alert work crews to additional sites that may be unearthed during construction. G. Transmission Access. Because the heat energy of steam dissipates rapidly, it cannot be transported and must be used where it occurs. Resources are often located in remote areas beyond the reach of the existing power grid, and construction of power lines can be an expensive and contentious endeavor. IV. Conclusion. Siting a geothermal energy facility on federal, state, or private land requires a keen understanding of legal requirements and issues. As with any proposed development, a key strategy for the specific issues presented in this chapter is early, meaningful contact with interested local, state, and federal agencies as well as other stakeholders. STOEL RIVES LLP 2008 Ch. 1 Pg. 9

14 Chapter Two THE LAW OF LAVA Running Interference: Groundwater and Related Features of State Regulation Jennie L. Bricker, John S. Kirkham The center of the Earth is a hot place more than 7,600 degrees Fahrenheit. To get there, or at least to locate water or steam temperatures that are viable for electric generation, a prospector of geothermal energy usually must drill through groundwater resources and perhaps lower-temperature geothermal resources as well. This journey from cold water to superheated steam may also take the prospector through the jurisdiction of various state agencies and their respective regulatory requirements. This chapter provides a brief overview of some of the state regulatory issues that the geothermal energy developer encounters along that journey. I. Groundwater Protection. Because geothermal resources lie beneath groundwater, virtually all western states have laws that protect groundwater from the effects of geothermal exploration and production. Drillers must install casings to seal off any strata containing fresh water, and operators are normally liable, by statute, for any damage resulting from contamination or depletion of groundwater resources. Injection wells are subject to similar and often more stringent requirements. Abandoned wells must be plugged and sealed, both to prevent freshwater contamination and to protect against blowouts. Casing requirements vary from state to state in both their level of detail and their stringency. Nevada administrative rules, for example, require surface casing to extend to a depth of at least 10 percent of total well depth, or a minimum of 50 feet. Oregon rules specify 10 percent of well depth for wells deeper than 500 feet, with a 25-foot minimum. However, Oregon requires a minimum 300-foot surface casing for wells located in areas with no nearby drilling history, unless the Department of Geology and Minerals ( DOGAMI ) permits otherwise. OAR Sealing requirements for prospect wells also vary. For example, Nevada regulations provide simply that [h]oles drilled into or through artesian aquifers must be sealed to prevent upward leakage after the drilling pipe is withdrawn at the conclusion of drilling operations. NAC 534A.150. In Oregon, regulations are more detailed, creating a classification scheme based on freshwater pressure and requiring bottom-to-top plugging of prospect wells where artesian water is present. II. Protection of Other Geothermal Resources. In many states, casing and sealing requirements also apply to protect against interference between adjacent or connected geothermal resources. Idaho s 1987 Geothermal Resources Act is an interesting example. Modeled on provisions of federal law, it allows owners of adjacent geothermal areas to enter into cooperative unit agreements that impose drilling and operations restrictions designed to maximize the overall resource. Once approved by the Idaho Water Resource Board, the agreement is immune from antitrust liability under the state action doctrine. If the Department of Water Resources determines that a geothermal resource area should be operated cooperatively to prevent waste of the resource, but the owners refuse to enter into a cooperative unit agreement, then the Water Resource Board can order that the area be operated as a unit and that proceeds and liability be shared equitably. A. Classification of the Resource. Idaho s Geothermal Resources Act is an example of a state s struggle to classify geothermal resources for purposes of regulation. The act provides: Geothermal resources are found and hereby declared to be sui generis, being neither a mineral resource nor a water resource, but they are STOEL RIVES LLP 2008 Ch. 2 Pg. 1

15 also found and hereby declared to be closely related to and possibly affecting and affected by water and mineral resources in many instances. IC The classification of geothermal resources varies from state to state. Generally, states have chosen between two already established legal templates for resource management: they classify geothermal resources under legal doctrines that govern groundwater appropriation, or they classify the resources according to oil, gas, and mineral principles. In United States v. Union Oil Company, 549 F.2d 1271 (9th Cir. 1977), the Ninth Circuit Court of Appeals concluded that the mineral reservation in the Stock-Raising Homestead Act of 1916 was intended to include geothermal resources. Thus we know that under federal law geothermal resources are treated as mineral rights. Likewise, in Hawaii, Texas, and Alaska, geothermal resources are classified and regulated as minerals. Wyoming and Utah, conversely, use the groundwater classification system. Although Utah law separately defines geothermal resources as those with temperatures of at least 120 degrees Celsius, the state classifies geothermal fluids as groundwater. Other western states including Oregon, New Mexico, and California use a bifurcated classification system, regulating low-temperature resources differently than high-temperature resources. The Idaho Geothermal Resources Act bifurcates the resource into high- and low-temperature, but the Act regulates geothermal resource development under groundwater appropriation principles, and geothermal permitting is governed by the Department of Water Resources. The state s ambivalence about such classification can be detected elsewhere in Idaho law, however, such as the statute that reserves to the state the mineral rights located beneath state-owned lands including, for that purpose, geothermal resources. Oregon s system provides an example of how differences in classification can create potential for regulatory confusion. In Oregon, geothermal resources with a bottom hole temperature of 250 degrees Fahrenheit and above are regulated by DOGAMI, while those with a bottom hole temperature of less than 250 degrees are considered groundwater resources, administered by the Water Resources Department. Each agency has its own administrative rules and permitting requirements. In addition, other state agencies are involved. If the resource is located on state-owned land, the Department of State Lands imposes its own chapter of administrative rules on geothermal leasing. If the development requires disposal of drilling or other fluids, DOGAMI regulates reinjection, while the Department of Environmental Quality regulates other disposal methods. If the project will generate MW or more, the Oregon Energy Facility Siting Council requires a site certificate. In any such development, of course, local land use and other laws will come into play. Lending further flavor to this regulatory stew, Oregon defines high-temperature geothermal resources not only by temperature but, alternatively, by depth of the well. Thus a high-temperature resource is one with a bottom hole temperature of at least 250 degrees, but Oregon statutes leave open the possibility that any well located at least 2,000 feet below the surface could be regulated as a geothermal resource. Oregon administrative rules employ an intent-based standard to distinguish among water supply wells, which are constructed to develop groundwater resources; low-temperature geothermal wells, which are constructed or used for the thermal characteristics of the fluid contained within ; and geothermal wells, which are drilled to explore for or produce geothermal resources from any depth. OAR (5); OAR (11). This system inevitably creates the potential for double regulation by both DOGAMI and the Water Resources Department. Oregon law addresses such potential regulatory conflict with provisions requiring cooperation among state agencies; these general mandates to cooperate may or may not be helpful to developers trying to navigate the various requirements of different state agencies. STOEL RIVES LLP 2008 Ch. 2 Pg. 2

16 Oregon s dual agency system may have the advantage of keeping both players minerals and groundwater in the game. ORS provides, for example, that the two agencies will work cooperatively to resolve conflicts between geothermal wells and groundwater appropriations, using criteria for resolution that will maximize the most beneficial use of the water and heat resources while preserving individual rights and protecting the public interest. Oregon also provides a set of rules permitting the conversion of a prospect well to a groundwater well, in which case the owner would apply for a groundwater appropriation permit from the Water Resources Department, basically shifting the endeavor from the jurisdiction of one agency to another. Other states have also crafted laws designed to bridge the gap between regulatory jurisdictions. In Nevada, for instance, geothermal development is regulated by the Division of Minerals of the Commission on Mineral Resources. Although geothermal drilling is technically also under the jurisdiction of the Nevada State Engineer, who is in charge of groundwater, the State Engineer has authority to waive water appropriation permitting requirements for geothermal exploration. Thus the agencies appear to share regulatory authority, with an administrative system in place for one agency to defer to the other. In Utah, the State Engineer administers groundwater, while the Division of Oil, Gas and Mining regulates mineral resources. The state controls geothermal development with a hybrid form of regulation: although geothermal fluids are treated as groundwater, the State Engineer nevertheless controls geothermal resource development in much the same way as the Division of Oil, Gas and Mining controls the development of mineral resources. In particular, under Utah law, ownership of a geothermal resource derives from an ownership interest in land and not from an appropriative right to geothermal fluids. The Idaho Department of Water Resources administers separate permit programs for groundwater and for hightemperature geothermal resources. The geothermal developer must obtain both a permit to appropriate groundwater as well as a geothermal well permit in any case in which the proposed geothermal development will decrease ground water in any aquifer or other ground water source or will unreasonably decrease ground water available for prior water rights in any aquifer or other ground water source of water for beneficial uses. IC In states with bifurcated classification systems, line-drawing problems seem inevitable. Oregon divides highfrom low-temperature resources at the 250-degree point; Idaho puts the line at 212 degrees. California and New Mexico specify the boiling point at the altitude where the resource is found. The differences in classification (often paired with very different regulatory requirements) suggest a qualitative difference in the resource, such as the difference between a resource that can be used to generate electricity and one whose economic value lies in direct use. As technology advances, however, the temperature necessary for economical generation of electricity will continue to shift downward; already, binary systems can generate with resources well below 200 degrees. One hopes that state regulatory systems will keep pace with technology. III. How Regulatory Classification Affects Ownership Rights. Besides causing the potential for regulatory stickiness, the classification of geothermal resources also affects the owner s rights to those resources. Generally, states that classify the resource as groundwater treat ownership rights in accordance with the doctrine of prior appropriation, while states that use the mineral classification treat ownership under the law of real STOEL RIVES LLP 2008 Ch. 2 Pg. 3

17 property associated with mineral estates, usually termed the correlative rights doctrine. These two doctrines of ownership are distinct, both conceptually and in practical application. A. Prior Appropriation Doctrine. Almost all western states have adopted the prior appropriation doctrine to control rights to water. The mantra of prior appropriation is first in time, first in right. Thus water belongs to the first person to put it to beneficial use. That person has the most senior rights to water, but only to the exact quantity actually put to use, and only for so long as the use continues giving rise to the second mantra of western water law, use it or lose it. In times of shortage, senior users take their full measure of water first (that is, they call the river ); when no more water is available, junior users get cut off altogether. Those holding junior rights know to expect that possibility and prepare for it, just as senior users know they can rely on their full water right. In applying the prior appropriation doctrine to geothermal resources, states can impose a familiar system of seniority to govern competing interests in the same resource, and they can nudge developers in the direction of efficient utilization of the resource. However, title to water is not equivalent to real property ownership, and the prior appropriation doctrine does not give the geothermal developer real estate-caliber title to the resource. In most states, water (and thus geothermal resources) is owned by the public, or by the state in trust for the public. The water rights holder or geothermal developer possesses only a usufruct a mere right of use, not of ownership. B. Doctrine of Correlative Rights. From the common law of real property, landowners are graced with ownership ad coelum, in which ownership of a parcel of land is considered to include the sky above the parcel and the subsurface area below the parcel, bounded by the parcel s boundaries and presumably extending to the Earth s core. The mineral rights in most states, however, are subject to the rule of capture, which means that although I may own the subsurface area below my land, if I fail to capture the minerals there, someone on an adjoining parcel is free to do so. That rule is, in turn, limited by another rule of law, the correlative rights doctrine, which is the legal principle that adjoining landowners must limit their capture of a common underground resource to a reasonable, proportionate share based on the acreage of surface ownership. Some states such as Utah have confirmed by statute that the rights to geothermal resources and to geothermal fluids extracted in the course of production of geothermal resources shall be based on the principle of correlative rights. For geothermal development in jurisdictions that classify geothermal resources as mineral interests, this means that land ownership or leasehold rights are paramount. Under the rule of capture, the owner of the mineral estate can obtain title to geothermal resources (subject to the correlative rights of adjacent owners) as fast as he or she can get them out of the ground. Conversely, and again depending on the activities of adjacent landowners, if I own the subsurface geothermal resources but fail to develop them, my title remains secure until I decide to develop; the first in time and use it or lose it principles do not apply. From the standpoint of economic efficiency, this is beneficial, because the owner need only capture the potential of the resources when it is economical to do so. On the other hand, from the standpoint of resource management, an owner who fails to make use of a geothermal resource can tie it up and prevent anyone else from developing it. IV. Conclusion. More significant to the practical realities of geothermal energy development is the question of which type of ownership is more secure and more attractive to investors. Moreover, it is important for developers to understand the classification scheme used by the state in which geothermal resources are located STOEL RIVES LLP 2008 Ch. 2 Pg. 4

18 because the nature of ownership will affect not only regulatory decisions, but also decisions about how to structure sales contracts, leases, operating agreements, and insurance policies. A thorough understanding of the specific state s regulatory system can help the geothermal developer ensure that drilling deep will not land him or her in legal territory that s too hot to handle. STOEL RIVES LLP 2008 Ch. 2 Pg. 5

19 Chapter Three LAVA LAW Signing Up: Power Purchase Agreements and Environmental Attributes John M. Ericksson, William H. Holmes, Karen E. Jones I. The Basics. A. The Parties. 1. The Seller. The seller is usually the developer and owner (or the developer with investors in an ownership entity) of a geothermal power plant that will generate energy and associated environmental attributes ( output ); the seller could also be a power marketer that does not own the plant, but buys and resells the plant s output at wholesale to one or more buyers. If a power marketer is reselling output, the power purchase agreement ( PPA ) for the resale of that output will usually track the relevant terms of the underlying PPA with the project owner in a back-to-back PPA for the resale, because the marketer will not want to promise more than it has the right to deliver. The terms of the back-to-back PPA will be almost the same as those in the underlying project PPA, except for price or other unique items that the marketer does not wish to, or agrees not to, pass through to the ultimate buyer. 2. The Buyer. The buyer is usually a utility that purchases the geothermal plant s output to serve its load. The utility may also be motivated by a renewable portfolio standard or other regulatory requirement or policy that encourages the development of renewable energy. In a state that permits direct access, the buyer may be a retail purchaser, such as a manufacturing facility that wishes to hold itself out as a green company. Power marketers may also buy the geothermal plant s output for resale to one or more third parties. 3. Credit Support Provider. The PPA will require the buyer to buy the output that the seller delivers. It may also require the seller to pay the buyer if the project is not built on schedule or fails to achieve certain output levels or other performance standards. Each party will be concerned about the other s ability to satisfy these payment obligations. If one party is not sufficiently creditworthy, the concerned party may require the other party to provide a guaranty or post a letter of credit or other security to ensure that amounts due under the PPA will be paid. Utilities will typically resist any requirement that they provide credit support, but may be willing to provide it if their debt rating falls below investment grade. 4. The Lender. Frequently the project will be financed. The lender may also be the provider of the credit support required of the seller. The lender will be concerned that it has rights to protect its collateral in the PPA and in the project itself before the buyer s exercise of remedies under the PPA, especially if any specific seller event of default entitles the buyer to terminate, or to exercise other extraordinary remedies such as step-in rights. B. Regulatory Concerns. 1. Exempt Wholesale Generator and Market-Based Rates. Unless the geothermal plant is a qualifying facility under a certain size (measured in MW), or is owned directly by a utility to serve its customers, the project owner must obtain authorization from the Federal Energy Regulatory Commission ( FERC ) under section 205 of the Federal Power Act so the seller can charge market-based rates, even if all sales are made under a single contract. The seller should also self-certify to FERC, or petition FERC for a STOEL RIVES LLP 2008 Ch. 3 Pg. 1

20 determination that the seller qualifies as an exempt wholesale generator as defined in the Energy Policy Act of Qualifying Facility. If the geothermal plant is a qualifying facility under the Public Utility Regulatory Policies Act of 1978 ( PURPA ), the energy that it generates may be sold by the project owner without a FERC section 205 tariff so long as the sale is made pursuant to PURPA utility must-buy obligations or the project is under a certain size (in MW). 3. Retail Sales. With certain exceptions, power sold to an end user, such as a residential customer or an industrial user, is a retail sale that may subject the seller to regulation as a public utility under applicable state laws. Because such regulation is burdensome and costly, project owners usually avoid retail sales of energy. In states with retail deregulation (or direct access ), it may be possible to sell power at retail rates to certain end users. The law of the end user s state must be checked to see if any retail sales are permitted and, if so, under what circumstances. II. The Term. A. Relationship to Project Financing. If the geothermal plant is financed with limited-recourse financing, the term of the PPA needs to be sufficiently long to amortize the project debt. In project financings, the debt amortization period generally needs to be shorter than the PPA term, to allow work-out time in case the project encounters financial difficulties in later years. Thus, for example, if the term of the PPA is 20 years, lenders will generally be willing to amortize the debt over a 15- to 16-year period. Generally, only the base term of the PPA is taken into account, because the lender has no assurance that the buyer will elect to continue the PPA into a renewal term. B. Useful Life. Because the buyer under a PPA effectively pays for the entire capital cost of the project (plus a profit to the project owner), the buyer will normally want the PPA to capture the entire value of the project by covering the entire economic life of the project facilities. Because the entire capital cost of the project will generally be amortized over the base term of the PPA, it is possible to eliminate the cost elements that relate to the original project debt from the power price during the renewal terms, and the buyer may therefore seek a price during the renewal term that is less than the power price during the base term. On the other hand, the seller will want to consider that new debt may be required to enable the plant to keep producing, as well as the fact that the market price for power at the expiration of the base term will very likely be much higher than a price that is reduced to reflect the elimination of the original project debt. C. Effective Date. The PPA should be binding on the date it is signed (often called the effective date ). This ensures that the buyer will buy the output once the project is built and that the project owner will not have the right to sell its output to anyone other than the buyer. D. Commercial Operation Date. The term of the PPA usually begins on the effective date, but the length of the term is usually defined by reference to a commercial operation date. For example, the term might end on the 25th anniversary of the January 1 following the commercial operation date. Thus, if the term were 25 years and commercial operation began on November 1, 2001, the term would end on January 1, In other PPAs, the term begins on the commercial operation date and extends for a stated number of years from STOEL RIVES LLP 2008 Ch. 3 Pg. 2

21 that date. In general, geothermal facilities require longer lead-time to develop and construct than do wind projects, and this fact should be taken into account in establishing the mechanism for determining the term. Because the commercial operation date often sets the term (and sometimes the point at which the price for energy and environmental attributes switches from a test energy rate to a contract rate, or the point from which capacity payments are to be made), it is important to define commercial operation date carefully. In general, the commercial operation date can be defined as the date on which all portions of the project necessary to put it into operation, along with the interconnection facilities to the transmission system, have been constructed, installed, tested, and commissioned and are both authorized and able to operate and deliver energy in commercial quantities to the transmission system in accordance with prudent industry practices. Frequently the buyer will require that an inspecting engineer certify that these requirements have been met. If production tax credits will be available for the output of the project, consideration should also be given to the relationship between the commercial operation date and the in service date for purposes of the production tax credits. E. Termination Before the Commercial Operation Date. PPAs often include off-ramp provisions that enable one or both of the parties to terminate the PPA if certain events occur or fail to occur. Common reasons for early termination include (1) the failure of a public utility commission with regulatory authority over the buyer to approve a PPA; (2) the inability to obtain an interconnection agreement or needed transmission rights; (3) the seller s inability to obtain leases, rights-of-way, or other land rights required to build the project; (4) the seller s inability to obtain permits required to build or operate the project; (5) the seller s inability to obtain an authorization to sell power at market-based rates; (6) the seller s inability to obtain financing; and (7) the project s failure to achieve commercial operation by a certain date. Termination rights require careful negotiation to make sure that all possibilities have been considered, but both parties will want the circumstances under which the other party can terminate to be as limited as possible. A party is usually required to use diligent or reasonable efforts to satisfy the conditions set forth in the PPA before it can invoke the failure to satisfy such a condition as a reason to terminate the PPA. For example, the seller should not be able to assert the inability to obtain a permit as a basis for terminating the PPA unless the seller can demonstrate it has used diligent efforts to obtain the permit. III. Purchase and Sale. A. Delivery Point. The PPA will require the sale of energy generated by the plant to occur at a specified delivery point. If the energy is to be delivered at the plant in a busbar sale, the delivery point will usually be the high side of the transformer at the project substation. In a busbar transaction, the buyer provides the transmission required to transmit the energy from the project substation to the point where the buyer intends to use it (or to deliver it to another party in a resale transaction). The PPA may also require the seller to deliver energy to a specific point some distance from the plant, in which case the seller will be responsible for securing the required transmission rights to that delivery point and the buyer will be responsible for obtaining the transmission rights required to take the energy at and from that delivery point. In such a case, the seller will want to consider, in its pricing, the risk of curtailment of the transmission service to the delivery point, unless the buyer is willing to carry that risk. With environmental attributes or green tags based on delivered output, a busbar sale will benefit a buyer due to the avoidance of transmission losses that would occur with a more distant delivery point. Transmission ancillary services can be fairly costly and should be specifically allocated in the PPA. STOEL RIVES LLP 2008 Ch. 3 Pg. 3

22 Underlying transmission rights necessary to the transaction should be reviewed and verified. Title to and risk of loss of the energy being delivered should pass from seller to buyer at the agreed on delivery point specified in the PPA. B. Pricing. 1. Energy Rate. The price for energy is, of course, a very important part of the PPA. The price may be flat, escalate over time, or contain other features. An escalating price is often tied to a contract year that begins at a specified point after the commercial operation date, thus encouraging the seller to lock in the initial price and the escalation rate by achieving commercial operation as soon as possible. 2. Test Energy Rate. The PPA may require the buyer to buy power from the units included in the plant as they are installed, connected to the transmission grid, and tested. Such energy may be sold at a rate lower than the rate that will be paid once the commercial operation date for the entire project is reached. 3. Capacity Charge. Because geothermal energy is a reliable baseload resource, the buyer will sometimes pay a price for the plant s capacity in addition to the energy rate. This price is usually stated in dollars per kw-month or kw-year. 4. Mobile-Sierra Doctrine. The PPA should include a clause stating that the buyer will not make any unilateral application to FERC for a change in the PPA s rates, terms, and conditions or seek any relief from those rates, terms, and conditions under section 206 of the Federal Power Act. The clause should also provide that third-party or sua sponte challenges to the PPA will be governed by FERC s public interest standard of review rather than the less stringent just and reasonable test. C. Environmental Attributes. Environmental attributes are the credits, benefits, emissions reductions, environmental air-quality credits, emissions-reduction credits, offsets, and allowances resulting from the avoidance of the emission of a gas, chemical, or other substance attributable to the geothermal project, together with the right to report those credits. Environmental attributes are sometimes called green tags, green tag reporting rights, or renewable energy credits. The PPA should clearly state whether energy generated by the plant is being sold with or without environmental attributes the failure to do so has led to disputes about whether the environmental attributes remain with the project owner or are deemed sold to the buyer. If environmental attributes are being sold under the PPA, the seller will usually warrant its title to the attributes, but will not want to warrant the current or future use or value of the attributes or whether and to what extent they will be recognized at law. The PPA should also make it clear that state or federal tax credits and other financial incentives, and any attributes that the seller may need to run the plant, are not part of the environmental attributes and thus are not being conveyed to the buyer. D. Allocation of Taxes and Other Charges. The PPA should specify which party pays any sales, excise, or other taxes arising from the transaction. Although most states do not tax wholesale energy sales, the parties may wish to consider allocating the tax liability that might result from future legislation. PPAs typically provide for the buyer being responsible for taxes imposed at and after the delivery point. STOEL RIVES LLP 2008 Ch. 3 Pg. 4

23 IV. Permitting and Development. A. Commitment to Develop. A PPA with the project owner as seller will make the project owner responsible for developing and constructing the project. The seller usually prefers a PPA that requires it to sell the project s output only if the project is actually built. A buyer tends to view such a PPA as a put (that is, an option to require the other party to purchase output) and will usually insist that the seller make some commitment to develop the project. Many tense negotiations revolve around what the seller will or will not be required to do to develop and construct the project, as well as the off-ramps that each party has if the project does not achieve certain stated milestones. B. Status Reports. The buyer is typically interested in the ongoing development of the project because it needs to know when the energy will be delivered onto its system or when it will need to take a hedge position. As a result, PPAs frequently require the seller to deliver regular reports to the buyer about the status of permitting and construction. C. Milestones and Delay Damages. The PPA often includes a schedule of certain project milestones (for example, the date by which the seller must secure project financing, the date by which turbines and other major equipment must be ordered, the date by which all permits and the interconnection agreement must be in place, and the commercial operation date). If the seller fails to achieve a specified milestone, the buyer may have a right to terminate the PPA, collect delay damages, or require the seller to post additional credit support. The seller will therefore want to limit the number of milestones and bargain for some flexibility, especially in cases when a delay in achieving an interim milestone is not likely to delay a project s completion date. Sellers sometimes prefer PPAs that provide that the buyer s only remedy if the seller fails to meet a project milestone is to terminate the PPA without recovering damages although this can leave a seller with a halffinished project and no PPA and obviously leaves the buyer with no PPA. Buyers are concerned that this gives the seller a right that resembles a put and strongly prefer to require the seller to suffer some financial consequences if project milestones are missed. Sellers in turn can use these financial obligations as a way of maintaining the PPA in force notwithstanding delays. Many interesting negotiations revolve around the offramps that the seller will have versus the damages it will pay to the buyer if it fails to build the project in accordance with the PPA. A common middle ground is for the seller to agree to pay delay damages up to an agreed-on cap, which defines the limits of the seller s exposure if the project is not built, but gives the seller an incentive to use diligent efforts to finish the project on time. D. Interconnection and Transmission. The PPA often requires the seller to bear the cost of interconnection (including any network upgrades required by the new project, although some of these costs may be shared with other generators, especially if the buyer is a utility) and all costs of transmitting the energy to the specified delivery point. If the seller is the project owner (as opposed to a marketer), it will also be responsible for negotiating the interconnection agreement with the transmission provider. The buyer will be responsible for arranging and paying for transmission from the delivery point. E. Performance Incentives. A buyer may require the seller to warrant or guarantee that the project will meet certain performance standards. Such guarantees usually enable the buyer to recover all or part of its incremental cost of purchasing replacement power in the market to the extent that the project fails to perform STOEL RIVES LLP 2008 Ch. 3 Pg. 5

24 as expected, either on an equipment output or on an availability basis. Performance guarantees enable the buyer to plan around the plant s expected output and availability and strongly encourage the seller to maintain a reliable and productive project. F. Output Guarantees. The PPA may include an output guarantee to the buyer. An output guarantee requires the seller to pay the buyer if the project s output over a specified period fails to meet a specified level. The period may be biannual, annual, or any other period fixed by the parties. The seller s engineering and other technical data regarding the characteristics and capabilities of the geothermal resource composing the project will be crucial in determining appropriate levels of output guarantees. G. Availability Guarantees. The PPA pricing may be linked to a periodic availability test that enables the buyer to receive liquidated damages, which may be provided via a partial refund of capacity payments, if the facility is not available at least a certain percentage of the time. The PPA will then address how scheduled maintenance outages, forced outages, and force majeure events are to be taken into account when determining the facility s availability. H. Liquidated Damages. If a guarantee is not met, the PPA usually provides a mechanism for determining the damages suffered by the buyer. First, the parties determine the shortfall (stated in MWhs) relative to the amount of output or capacity that the buyer would have received had the project lived up to its guarant ees. Second, the shortfall is multiplied by a price per MWh determined by reference to an agreed-on index or other pricing factor. Because market indexes cover only power prices and do not include the value of environmental attributes, the PPA may also include an adjustment to account for the assumed value of the environmental attributes. The amount of liquidated damages is usually determined periodically, typically once per year. The seller pays the liquidated damages to the buyer or credits the damages against amounts owed by the buyer under the PPA. I. Termination Rights. To protect against chronic problems at an unreliable plant, the PPA may allow the buyer to terminate the PPA if the plant s output or availability falls below a stated minimum for a certain number of consecutive years. V. Curtailment and Force Majeure. A. Curtailment. The PPA often describes circumstances in which either party has a right to curtail output. For example, the seller may have a right to curtail deliveries if the plant is affected by an emergency condition. Or the PPA may permit the buyer to curtail for convenience, in which case the PPA usually requires the buyer to pay the purchase price for the curtailed generation, together with the after-tax value of any corresponding lost incentives, such as production tax credits. Geothermal plants are not as readily dispatchable as other types of power plants, so, from a seller s point of view, the PPA should provide for sufficient notice of dispatches and should contemplate base load operation as much as possible. B. Force Majeure. If energy is curtailed at a party s discretion or because the party is at fault, the PPA usually requires the curtailing party to pay damages to the other. If curtailment is caused by an event beyond a party s control, the party s duty to perform under the PPA will be excused. For example, if a natural disaster disables the transformer at the delivery point, the seller could be excused from delivering energy, and the STOEL RIVES LLP 2008 Ch. 3 Pg. 6

25 buyer could be excused from taking and paying for energy, until the transformer is repaired. The party responsible for maintaining the transformer would, of course, be required to use diligent efforts to make repairs. For geothermal projects, sellers will often want forces majeures to include unexpected depletions of the geothermal resource that fuels the project, but buyers will want to ensure that normal degradation of the resource over time does not provide a force majeure off-ramp to the seller. Parties often heavily negotiate force majeure provisions. Good provisions should carefully distinguish between events that constitute excuses (which relieve the affected party or parties from the duty to perform) and those that are risks (which are simply allocated to one party or the other). The ability to buy energy, capacity, or environmental attributes at a lower price from someone else, or to sell them at a higher price to someone else, is not appropriately characterized as a force majeure event. Moreover, a party s inability to pay should not constitute a force majeure event under the PPA. A well-drafted force majeure clause will usually list several items that both parties agree are force majeure events, as well as items that the parties agree are not force majeure events. VI. Operation and Metering. A. Operation and Maintenance. The PPA generally outlines the seller s responsibility to operate and maintain the project in accordance with prudent utility or electric industry practices. Such duties typically include regular inspection and repair, as well as completion of scheduled maintenance. To make it clear that the parties do not intend to allow the buyer to use the prudent utility or electric industry practice standard to improve on the output guarantee or availability guarantee, the PPA will often provide that the liquidated damages due for failure to achieve guaranteed output or availability are the buyer s sole remedy for underperformance by the project. B. Metering. The PPA s metering provision determines the quantity of energy and environmental attributes for which the seller will be paid. The PPA usually requires one party (typically the seller) to install and maintain a meter. The other party often has the right to install a check meter. If the seller s meter is out of service or generates inaccurate readings, the PPA should specify backup procedures for how the parties will determine the project s output. Tests should be conducted regularly to verify the accuracy of the seller s meters. The PPA usually states how often such tests will occur, at whose expense, and what form of notice will be given to each party. The PPA should specify how much variance in the meter s accuracy will be permitted and how repair or replacement of defective meters will be handled. The PPA may also provide that the plant s meter will be governed by third-party meter standards, such as those imposed on power plants located in California by the California Independent System Operator. VII. Billing and Payment. A. Billing and Payment. The PPA will describe how invoices are prepared, when they are issued, and how qu ickly they must be paid. The billing provision often states that an invoice is final if not challenged within a stated period of time (usually one or two years). The PPA usually sets forth procedures for raising and resolving billing disputes, as well as the interest rate and penalties that apply to late payments. STOEL RIVES LLP 2008 Ch. 3 Pg. 7

26 B. Right to Audit. The buyer will typically have the right, upon reasonable notice and agreement as to costs, to access those records of the seller necessary to audit the reports and data that the seller is required to provide to the buyer under the PPA. C. Defaults and Remedies. The PPA will usually list specific events that constitute defaults. These may include: failure by a party to pay an amount when due; failure by the seller to operate the plant and deliver energy to the buyer in accordance with the PPA; other types of material defaults, such as the seller s failure to use commercially reasonable efforts to achieve a material project milestone; the bankruptcy, reorganization, liquidation, or other similar proceeding of any party; and/or a material default by a party s guarantor. The default clause should specify how long the defaulting party has to cure a default. If the default is not cured within the agreed-on period, the nondefaulting party usually has the right to terminate the agreement and pursue damages or other remedies at law or in equity, to suspend performance of its obligations, or to seek specific performance and injunctive relief. The remedies clause may also limit remedies for example, in some PPAs the buyer s only remedy for the seller s failure to achieve a given milestone is to terminate the PPA without seeking damages. T he seller may seek to limit its overall liability to pay damages for its default under the PPA. If the PPA is built around a form such as the Edison Electric Institute form or Western Systems Power Pool form commonly used in trading and short-term transactions, care must be taken to override the termination payment components that are not desirable in a long-term PPA. The PPA should address when and how a party can exercise its rights to collect on any security posted to secure the other party s obligations under the PPA. 1. Project Lenders and Equity Investors. Even if the project is expected to be financed off of a developer s balance sheet, the terms of the PPA will usually take into account the possibility that the PPA will be assigned to a lender as collateral for project debt. The PPA will therefore contain provisions authorizing the seller to assign the PPA as collateral, requiring the buyer to provide consents, estoppels, or other documents needed in connection with financing, and giving the lender various protections (including additional time to cure defaults). The PPA may also include provisions to address the concerns and cure rights of future tax equity investors. 2. Buyer Options to Purchase the Project or Special Purpose Entity. In recent years, utilities have shown a growing interest in owning renewable energy projects. In PPAs, this interest often takes the form of an option to purchase the project or the entity that owns it on or after a specified date. Such options should be handled carefully. An option to purchase the project or the interests in the special-purpose entity that owns the project for anything other than fair market value at the time of exercise has been generally disfavored by STOEL RIVES LLP 2008 Ch. 3 Pg. 8

27 tax attorneys. O ther types of options can raise a fundamental question as to whether the owner of the project is an owner for federal income tax purposes or whether the financing arrangement is something other than ownership (e.g., a loan). Revenue Procedure explicitly provides as one of the qualifying elements that there is no developer/investor/related party purchase option for less than the fair market value (at time of exercise). D. Boilerplate and Examples. The PPA will also address boilerplate matters such as confidentiality, representations, and warranties, the parties rights to assign the PPA, governing law, the limitation of consequential damages, dispute resolution, consent to jurisdiction, and waiver of jury trials. Because the transaction betw een the parties may involve complex calculations, the PPA should also include several carefully considered examples that illustrate how those calculations will work in certain scenarios. As with any contract, an investment in negotiation time and careful drafting will pay off over the long term should disputes arise between the parties. STOEL RIVES LLP 2008 Ch. 3 Pg. 9

28 Chapter Four THE LAW OF LAVA Setting Up Shop: Design, Engineering, Construction, and Turbine Purchase Agreements Alan R. Merkle, Karl F. Oles This chapter provides an overview of the contractual structures that often apply to the construction of geothermal energy projects, including design and engineering, procurement and installation of steam turbine generators and related heat exchange equipment, and construction of ancillary facilities. This overview is written from the perspective of a geothermal energy project developer; however, the information set forth below should interest design and engineering, construction, operations and maintenance, and financing entities as well. As with any complex negotiated transaction, there is significant value to be won or lost by all parties, and the potential for creative legal strategies to meet or exceed everyone s expectations and interests. I. Construction-Related Agreements. Critical to the actual development of any geothermal energy project are the various agreements a project developer must enter into in relation to: design and engineering; procurement of power generation equipment (steam turbine generators and heat exchange components) and materials and equipment for balance-of-plant facilities such as cooling systems, extraction and injection wells, piping systems, foundations, roads, transformers, and maintenance facilities; obtaining construction iservices necessary to install the steam turbine generators and the balance of plant facilities; and operations and maintenance. Performance guarantees, warranty and insurance arrangements are critical elements in the agreements at each of these stages. Contracts that combine portions of the first three stages engineering, procurement, and construction are often referred to as EPC agreements. Often, these agreements also provide for, or anticipate, other services such as warranty services or operations and maintenance services for the steam turbine generators and related facilities. Sometimes all phases of the design and engineering, procurement, and construction/erection services are addressed in a single agreement (a full-wrap or turnkey agreement), usually when there is a single general contractor for the project. However, it is also common to have separate agreements such as design and engineering agreements, procurement/sale agreements, and construction/erection agreements ( balance-of-plant agreements ), using one or more contractors for each of the various services. Depending on the contractual structure, warranties, insurance, and other matters may be addressed in a single master agreement or in each individual agreement. II. Design and Engineering Services. Geothermal energy projects require design and engineering expertise that is unique to this sector of the power generation industry. For instance, relatively few firms (a) design, engineer, and manufacture geothermal-specific steam turbine generators and (b) design, engineer, and STOEL RIVES LLP 2008 Ch. 4 Pg. 1

29 construct related project facilities such as cooling and well systems. Project design expertise requires understanding the complexities of the geothermal resource that the project will utilize, including volumes of extracted and injected liquids and wastes (toxic and otherwise) generated from such liquids. These and other factors will determine the type of system the project will use, such as flash or double-flash steam systems or a binary-cycle system. III. Typical Contractual Structures for a Geothermal Project. Given the multiple factors influencing the development of a geothermal energy project, no single contractual structure applies to all such projects. Common contractual structures include turnkey EPC agreements and separate turbine procurement and balance-of-plant agreements. Using a turnkey EPC agreement, the project developer would contract with a contractor who would undertake the development of the entire project, including the procurement of suitable steam turbines and the design and engineering of the extraction and injection well system and related pipeline system, cooling system, waste management system, and connected facilities. Such a contractor is often responsible for the commissioning, start-up, and performance testing of the steam turbine generators and the balance-of-plant. Alternatively, the project developer may elect to contract separately with a steam turbine vendor for the procurement of the desired steam turbines and with a balance-of-plant contractor for the (a) installation of the steam turbines and (b) design, engineering, and construction of the other necessary facilities for the project, such as foundations, roads, warehouses, transformers, security systems, and maintenance facilities. In this instance, care must be taken in both sets of agreements to avoid interference, duplication, or omission between the scopes of work of the steam turbine supplier and the balance-of-plant contractor, and to ensure that, collectively, the agreements result in a fully constructed, integrated, and operational project. In either a turnkey EPC agreement or separate turbine supply/balance-of-plant agreements, the parties must focus on the scope of work, measures of completion, warranty obligations, limitation of liability, and time of completion (with particular focus on key dates set by power purchase commitments and tax credit deadlines, if any). These issues are discussed below. A. Scope of Work. Except in a true design-build project based solely on performance specifications, the parties should place great emphasis on the description of the scope of work set forth in the agreements. The scope of work should describe, in detail, the actual design, engineering, and construction obligations of the contracting parties. Generally, whatever is not provided for in the steam turbine supplier s and contractor s scope of work is the project developer s responsibility to complete or to contract with third parties to complete. A steam turbine supplier s scope of work typically includes the design and engineering of the steam turbine generators, including their principal parts and components, as well as certain obligations relating to the commissioning, start-up, and performance testing of the steam turbine generators. The turbine supplier s services may also include control systems, weather mitigation packages, and related warranty work. The balance-of-plant contractor s scope of work usually excludes steam turbine commissioning-related services and focuses on infrastructure and facilities design, engineering and construction, extraction and injection well and piping system STOEL RIVES LLP 2008 Ch. 4 Pg. 2

30 design and construction, earthworks, and related work. As with other aspects of such an agreement, the scope-ofwork provisions are usually heavily negotiated. B. Measures of Completion and Start-up Obligations. The scope-of-work provisions of the relevant agreement typically determine who shall be responsible for facility start-up and commissioning and when and how such activities will be accomplished. Given a turbine supplier s in-depth knowledge of its products, the turbine supplier will, at a minimum, supervise generator startup and may also be engaged to commission the steam turbine generators it supplies. However, this work may be the responsibility of the project developer (with assistance from the turbine supplier) or a third-party contractor on behalf of the project developer. In any case, the agreement must address the stages of completion, such as actual delivery of the steam turbines to the project site, installation, and commissioning, start-up, and performance testing of the turbines. Completion of these progress milestones is generally evidenced by the turbine supplier s or the turnkey contractor s certifications of, for example, substantial mechanical completion, final mechanical completion, and final sign-off ; each such certification is considered an incremental measure that the project must satisfy in order to progress to the next measure. As with other supply/construction-related agreements, progress payments by the project developer to the turbine supplier/contractor (as set forth in the relevant agreement) will be based, in part, on the milestones described above. For instance, the project developer will typically pay the steam turbine supplier a certain amount toward the agreed-upon contract price when its order is submitted and then make additional payments upon (a) the delivery of the steam turbine generators and related components to the project site, (b) the installation of the steam turbine generators, (c) successful testing of the control and monitoring system, and (d) assuming the foregoing stages are executed properly, the final sign-off by the parties. C. Warranty Obligations and Component Performance Guarantees. Performance guarantees and warranty-related obligations are likely to be an issue of substantial negotiation between parties to the steam turbine supply and the balance-of-plant agreements. The nature and scope of a contractor s warranty obligations usually depend on what services, materials, and equipment the contractor has contracted to provide. A turbine supplier s obligations generally include such things as a general parts warranty (the definition of a defect can be important when determining what is included or excluded as a defective or nonconforming part or component in a steam turbine), heat rate and output guarantees (this refers to the energy output of a steam turbine generator), and related matters. For a contractor providing balance-of-plant services, the warranties and guarantees may be limited in scope relative to the steam turbines, but would include warranties relating to parts and materials used in the balance of plant design services provided. The issues that contracting parties should consider with respect to warranties include (a) the period or term of a particular warranty and whether the term can be extended (a turbine supplier may offer certain extended warranty services for an agreed price), (b) the definition of a defect, (c) limitations on a warranty due to acts of third parties such as operation and maintenance personnel, and (d) the remedial measures a contractor may take to cure any defect. Additionally, a project developer may desire that any third-party contractor or subcontractor warranties that the steam turbine supplier and/or balance-of-plant contractor possesses in respect of any parts or components used in its work are passed through so that the project developer can enforce them directly. STOEL RIVES LLP 2008 Ch. 4 Pg. 3

31 D. Limitation of Liability. The turbine supplier and other contractors may seek to limit their liability to a project developer. It is not uncommon to exclude liability for consequential, indirect, incidental, or special damages, though such clauses should be scrutinized because what qualifies as a consequential as opposed to a direct damage is often unclear. A contractor may seek to limit its liability to liquidated damages of a certain value, usually an agreed-on percentage of the value of the relevant agreement, or may seek to establish a maximum aggregate liability limit. The project developer should consider bargaining for exclusions to such contractor liability limitations. For instance, the contractor could agree that it would be liable, without limit, for delay-related damages if the project developer is unable to satisfy its contractual commitments under a power purchase agreement or to obtain time-sensitive benefits such as tax credit or bonus depreciation due to an event in the contractor s control or a risk assumed by the contractor. E. Time of Completion and Production Tax Credits. Historically, geothermal energy projects have not been dependent on benefits derived from state or federal law for renewable-resources energy projects, such as the federal production tax credit ( PTC ) under Section 45 of the federal Internal Revenue Code. 1 However, the Energy Policy Act of 2005 provided PTCs for projects completed by a date certain (as of this writing, December 31, 2008), and these PTCs have contributed to promote geothermal energy development. PTC-related damages are usually the subject of much negotiation between a contractor and the project developer. Insurance coverage may be available for certain delay-related risks, including failure to qualify for a PTC. F. Project Financing. The high capital costs associated with geothermal energy projects mean that such projects will likely require some form of substantial debt financing or joint venture equity financing to fund the design, engineering, procurement, construction, and initial operations of the project. Financial institutions and other potential investors (including those investing to obtain the benefit of PTCs) will demand the opportunity to review and comment on a project s design and engineering, procurement, and construction agreements (and related operations and maintenance and warranty agreements, if separate) before committing funds. Of special interest to prospective lenders and/or investors are the provisions in the agreements that provide the lender/investor with the ability to step into the project if the project developer (as the borrower) defaults, and provisions that specify the extent and nature of any damages available to a project developer from a contractor. Additionally, financial institutions will want to comment on the payment plans and security, warranty, and inspection provisions set forth in the project agreements. Due to such involvement, and to avoid issues arising from any potential inconsistencies, the project developer should be prepared to present a consistent and cogent set of project agreements to lenders/investors and to listen to their suggestions for such agreements. Further, a project developer should be prepared for the possibility that lenders/investors may want to make substantial changes in the negotiated agreements. For instance, lenders will often be interested in the project s financial and operational viability (as may be reflected in a feasibility study), and much of that interest will necessarily focus on the project developer s rights and recourse under the relevant agreements. In particular, lenders will be interested in the extent, limitation, and operation of any contractor warranties, contractor indemnities, insurance policies, progress or performance-test milestones and payments, and 1 A PTC is a tax credit for a percentage of the taxable income generated by a project that qualifies for such credit. STOEL RIVES LLP 2008 Ch. 4 Pg. 4

32 performance and payment guarantees. Lenders will also want to know whether the various agreements are entered into on an arm s-length basis, meaning that the terms and conditions of such agreements are based on typical commercial terms and standards. G. Performance and Payment Guarantees. A project developer should cause the various contractors to procure, for the benefit of the project developer, performance and payment guarantees, or bonds, to ensure (a) the timely performance of contractors (whether engineers, constructors, or procurement contractors), (b) that such performance on the project has been completed pursuant to the terms of the relevant agreements, and (c) that no liens or other encumbrances are lodged against the project property or improvements. Typical guarantees are described below. 1. Performance Guarantee. A performance guarantee is usually issued by a parent company or other creditworthy entity, such as a bonding company, selected or approved by the project developer, for an agreed sum. The issuer of the guarantee is available to satisfy the project developer s damages if the contractor has failed to perform its contractual obligations as specified in the relevant agreement. For instance, if the contractor defaults or cannot complete the project, the project developer may use this bond or guarantee to pay another contractor to complete the project. The project developer will want to reserve its other rights against a defaulting contractor if the performance bond does not fully cover (i) the project developer s costs of completing the project or (ii) damages the project developer may incur if project delays cause the project developer to default on its obligations to third parties. 2. Payment Guarantee/Bond. A payment guarantee or bond is intended to ensure that, in case the contractor defaults on the project, no liens or other security interests will attach to the project developer s property or the project improvements. A lien claim, normally filed against the project developer s property, may be bonded-over so that it attaches instead to the payment guarantee or bond. Lenders, upon their review of the agreements, may demand or require such payment guarantees to enhance the lenders security interests in the project. Methods of substituting bonds for lien claims vary from state to state, so careful attention to the particular laws of the project state is important. The project developer or the lenders may require other security from contractors, such as parent guarantees, standby letters of credit, and other forms of assurance that the contractors will perform. The contractors will seek ample opportunity to cure any default or delay and will try to limit a project developer s ability to call on their security without clear proof of a failure of performance by the contractor. In turn, contractors will usually demand some form of reciprocal security issued by the project developer or its parent company, including parent guarantees, payment guarantees, and the like to ensure prompt and full payment for work properly performed. H. Liens and Releases Issues. When the project developer makes periodic payments to contractors, the developer should obtain a lien release from each contractor and subcontractor. A lien release will help protect the project developer from liens being filed on the project by subcontractors who have not been paid by a primary contractor (and its subcontractors). Such liens are undesirable because (among other things) once filed, they can delay or interfere with the project s financing. They also generate litigation, in which a successful lien claimant is often entitled to recover its attorney s fees in addition to the contractual amount due. Worse still, STOEL RIVES LLP 2008 Ch. 4 Pg. 5

33 if a lien claimant is successful, it may be entitled to force the sale of the project, or part of it, which could interfere with the sale of the project by the project developer. I. Insurance and Indemnity Issues. A project developer should obtain appropriate indemnities and insurance coverage from the various parties with whom it contracts, and should require those parties to obtain similar protections from their subcontractors and material suppliers for the benefit of the project developer. Relevant indemnities include a general indemnity for personal injury, death, and property damage claims, contractor and subcontractor lien indemnities, an indemnity for taxes (other than those payable by the developer), an indemnity for violation of applicable laws, and an indemnity for intellectual property infringement claims. Appropriate insurance policies include commercial general liability, workers compensation and employer s liability, automobile, errors and omissions (for design and engineering services), and builder s all risk (property insurance for the project improvements). Such policies should name the developer and its financing parties (if any) as additional insureds (though this is not available for errors and omissions insurance) and contain appropriate waivers of subrogation. Appropriate policy limits will vary with respect to the nature of the work being performed by the insured and the scope of the project. It is advisable for the project developer to consult with an insurance or risk management specialist to ensure that appropriate types and levels of coverage are obtained. IV. Relationship to Other Project Development Steps. Project design, procurement, construction, and maintenance agreements are closely tied to power purchase agreements and project financing. A power purchaser, usually a utility, expects assurances that the project will become operational, and therefore sometimes takes a strong interest in the necessary agreements and financing documents. If financing is required, as it almost always is, financial institutions expect to see that the project will generate revenues which requires a purchase agreement and appropriate design, procurement, construction and maintenance agreements. Recently, developers with a well developed risk appetite have developed some projects on a pure merchant basis, that is without a long term power purchase agreement in place. However, long term off-take agreements are still the norm for most project financed developments. And finally, EPC contractors want assurances that they will be paid for their work, including evidence that the project developer has secured financing and can sell the power to be generated. This circular relationship of contractors, financial institutions, and power purchasers often forces the developer to establish the contracts in incremental contractual steps, tied to incremental steps taken with the other parties. STOEL RIVES LLP 2008 Ch. 4 Pg. 6

34 Chapter Five THE LAW OF LAVA Penciling Out: Project Finance for Geothermal Power Projects Edward D. Einowski, Mary Jo N. Miller Since the vast majority of geothermal energy projects are larger than 25 MW in size, successfully financing one of these projects generally requires raising a substantial amount of capital. While debt usually is the source for a large part of the required capital (commonly 60 to 70 percent of the total project cost), lenders usually require that a significant amount of equity be invested in the project as well. Since all these types of investment are structured differently, come from separate sources, and often are at odds with each other, understanding both components of the financial picture (as well as their interaction) is a critical aspect of getting the projects launched. In general, debt is lower risk and is the most highly structured component of the financing deals are usually structured so that the lenders get priority on returns from cash flows and on disposition of assets and the equity investors are generally entitled only to what is left after the debt holders have been paid off. There is a natural tension between the allocation of the relative risks and rewards between the two groups of investors, so striking a reasonable balance that makes the overall financing work requires understanding the expectations and motivations of each group. I. Debt Financing. The essence of debt financing for electric generation projects is fashioning a loan package that provides adequate assurance (creditworthiness) that the loan will be repaid in a timely manner. Alternatively stated, it is the fashioning of a loan/credit package such that the risk of default (nonpayment) is minimized reduced or mitigated to bring the risk within levels acceptable to the lender. Creditworthiness and risk are thus two sides of the same coin: the greater the risk, the lower the creditworthiness, and vice versa. The lender s protection is usually accomplished by various legal undertakings, including mortgages and security interests granted in the project assets, revenues, and key project agreements; warranties and contractual requirements for the equipment and the work performed in making it operational; requirements for various types of insurance requirements to cover certain adverse events; and guarantees of each participant s obligations from creditworthy entities. The negotiation and documentation of these risk-shifting devices is the focus of activity in project debt financing, resulting in loan documentation of substantial heft and complexity. In broad terms, there are two basic approaches to addressing the credit/risk allocation issues in a manner that can be made to work (more or less) for all the participants involved: full-recourse (or balance sheet) financing, and limited-recourse (or project) financing. II. Full-Recourse (Balance Sheet) Financing. A. Defined. With balance sheet financing, the payment of the debt is backed by the legal obligation of an entity with sufficient financial resources (that is, its balance sheet) to underwrite the risk that the project will be successful and the debt will be repaid. It is full recourse in that the lender can enforce payment of the debt out of any and all unencumbered assets of the entity providing the balance sheet support, rather than being limited to the project assets or other specific collateral. On the other hand, balance sheet financing is STOEL RIVES LLP 2008 Ch. 5 Pg. 1

35 usually unsecured, with the lender taking no lien on or security interest in any tangible or intangible assets of the borrower. The balance sheet backing rarely comes from the entity that will serve as the project owner, as these tend to be single-purpose entities ( SPE ) with no substantial assets other than the project. Rather, it most typically is provided by an affiliate of the project owner an upstream parent or other affiliate with the requisite financial profile. B. Who Can Access Balance Sheet Financing? Balance sheet financing is generally available only to the more substantial players in the electric industry investor-owned utilities, power marketers, equipment manufacturers, and others whose long-term unsecured debt is rated at least investment grade by one of the national rating agencies. In a very real way, the reason balance sheet financing works is highlighted by the old joke: Question: Answer: What does it take to get a $100 million loan from a bank? $1 billion in cash collateral! Indeed, backing a loan with the balance sheet of an entity that has substantial liquid and tangible assets, acceptable levels of debt, and a proven track record of earnings can result in a risk posture to the lender that, in many respects, is the functional equivalent of overcollateralizing a loan with cash collateral. C. Focus Shifted Away from Project. With balance sheet financing, the focus is on the financial position and prospects of the entity providing the balance sheet, rather than on the legal, economic, and technical viability of the geothermal energy project. The reason is simple: when a lender is primarily relying on the overall credit strength of the balance sheet provider and has recourse to all of its unencumbered assets and revenues to enforce payment of the debt, the viability of the project to be financed is only one small piece of the credit picture, and thus should not be the primary focus in evaluating the credit. Whether the particular project will be successful is less of a concern than it would be if the success of the project were the only route to repayment of the debt. In many cases balance sheet financing simply is not an option for geothermal energy projects. There is often an unwillingness to use the balance sheet to support the debt. It is a question of opportunity cost: the more the balance sheet is used to support project debt, the less it will be available for other corporate purposes (such as the acquisition of other companies or the maintenance of a balance sheet debt posture that will not adversely affect the company s stock price). Thus, even for the more financially well-heeled players in the geothermal industry, balance sheet financing may not be an attractive course to pursue. The alternative is limited-recourse financing (often called project financing ). III. Limited-Recourse (Project) Financing. A. Defined. With limited-recourse, or project, financing, the debt is backed only by the project assets and the revenues they are able to generate. If the project fails to produce the revenues needed to pay STOEL RIVES LLP 2008 Ch. 5 Pg. 2

36 expenses and service the debt, the lender cannot pursue the nonproject assets or revenues of those who own the equity interests in the project owner. Recourse is limited to the project owner and the project assets and revenues. Indeed, this limited-recourse nature is generally reinforced by the ownership structures for geothermal energy projects, which tend to utilize SPEs to own the project. An SPE is set up to have no assets other than its interest in the geothermal energy project. Furthermore, the SPE is typically a legal form of entity (for example, corporations, limited liability companies, and limited partnerships that have as their ultimate general partners corporations or limited liability companies) that, in most instances, prevents the creditors from going after the nonproject assets of SPE owner(s) to satisfy payment of the debt. Thus, by both the contractual provisions of the lending documents and the type of ownership structure employed for the SPE, the lender s recourse to enforce payment of the debt is limited to the project assets and revenue-generating capability. B. Betting on the Project. Assuming that the debt is properly structured to eliminate or acceptably mitigate the lender s risk, the lender antes up on this bet on the project by making the loan. The exercise in structuring a limited-recourse financing is focused on those features that serve to eliminate or mitigate the risk to the lender. This, in turn, leads directly to an exhaustive examination of all aspects of the project the conditions at the site, the nature and adequacy of the land rights and permitting for the site, the reliability of the equipment used, the legal obligations and creditworthiness of the key project participants, the availability of transmission, and so on. Indeed, if the lender is to be limited to project assets and revenues to secure repayment of the debt, it is essential that all aspects of the project be thoroughly vetted to ensure that it will operate successfully (that is, pay its bills) even in a worst-case scenario. C. Project Viability Versus Collateral Value of Project Assets. It should be noted that while the lender will generally insist on and get a first-priority lien on all project assets, the tangible collateral securing the loan is, in reality, of secondary importance to the lender. The reason is simple: as a general rule, in a foreclosure situation, tangible collateral can usually be sold only at a price that produces a relatively small fraction of the debt it secures. A lender is far more likely to get repaid if the project operates successfully and produces the needed revenues than it is by liquidating the project assets in foreclosure. Therefore, the detailed examination of the project for purposes of limited-recourse financing is aimed primarily at determining the likelihood that the project will operate as planned, and then putting in place those security arrangements with the project participants that, in the judgment of the lender, are best calculated to ensure that the project will in fact perform up to expectations even in the face of a worst-case occurrence. In many cases, the limited-recourse nature of the debt financing does not truly come into play until the project has achieved full commercial operation, as the project owner is often required to guarantee the debt on a full-recourse basis during the construction period. D. Security Arrangements Creating a Sealed System. Thus far we have focused on those aspects of project finance that are aimed at vetting the risk associated with the ability of the project to perform up to expectations. We now turn to the security arrangements for project debt. In the context of a limited-recourse financing, the security arrangements are part of the core foundation on which the financing rests, as the lender has recourse only to the project assets and revenues to enforce payment. The lender therefore seeks control (by means of security interests, mortgages, and contract assignments) of all project assets (including all key project agreements) and all project revenues (also by means of security interests, but coupled with lockbox arrangements STOEL RIVES LLP 2008 Ch. 5 Pg. 3

37 as described below). One way of looking at it is that the lender seeks to create a sealed system whereby all project assets and revenues are, to the fullest extent possible, sealed off from other creditors or investors by means of the security arrangements, with the lender exercising control over the assets and revenues to ensure that they do not escape the system so as to jeopardize the repayment of the debt. This is the essence of the project finance bargain: the lender is willing to limit its recourse to the project assets and revenues, in exchange for a financing structure that effectively preserves all project assets and revenues for the sole benefit of the lender. In financing for PTC-dependent renewable energy projects, we have seen this essential bargain preserved even in the context of an A-B type of project finance debt structure that is, when there are two project loans, the primary (or A ) loan is payable out of power sales revenues, and the secondary (or B ) loan is payable out of the production tax credits available to the project. In such transactions, each loan corrals (by means of the security arrangements) its own source of repayment, taking paramount rights in the sealed system so created to the exclusion of the other loan. For geothermal facilities that qualify for the PTC (presently, those placed in service before January 1, 2009), this credit can constitute a crucial feature of the financing portfolio. 1. Power Purchase Agreements. One key aspect of the security arrangements that create the requisite sealed system is the power purchase agreement (the PPA ). The PPA is the core of the credit picture in a project financing, as it is the source of all revenues that will be needed to make the project successful. As such, the assignment to the lender of the project owner s rights under the PPA forms the centerpiece of the security arrangements. In addition to a price for power that will support the project operating expenses and debt service based on the expected production, lenders generally look for a PPA with the following features: a. Term. The term of the PPA (exclusive of renewal options) should generally be several years longer than the term of the financing. Thus, for example, if the term of the financing is 20 years (fully amortizing), the lender is likely to require a PPA term of 22 to 25 years. The additional years of the PPA term provide the lender with work-out room if the project encounters difficulties during the term of the financing. b. Purchaser s Creditworthiness and Credit Maintenance Provisions. The output purchaser under the PPA must be a creditworthy entity or have its obligations guaranteed by a creditworthy entity. Generally speaking, lenders will look for at least an investment grade rating on the long-term, senior unsecured debt of the purchaser or its guarantor. Because of their dependence on PPA revenues for repayment of the project debt, lenders often seek credit maintenance provisions whereby if the power purchaser s credit rating falls below a certain level, the power purchaser is required to post collateral to better secure its obligation to pay for the power delivered. However, there is as yet no universal willingness of power purchasers to agree to provide such credit assurances in the context of renewables when the purchaser is acquiring the resource in order to comply with a renewable portfolio standard imposed. Under current market conditions, it is generally not possible to obtain limitedrecourse financing for a geothermal energy project without a long-term PPA for the purchase of the output of the project. Merchant geothermal energy projects may someday and under some market conditions be capable of securing limited-recourse financing. But for now, balance sheet financing is the only workable option for merchant geothermal energy projects that is, those that will sell the electricity STOEL RIVES LLP 2008 Ch. 5 Pg. 4

38 into the market rather than pursuant to a long-term PPA. In lieu of using a credit rating as the trigger, other triggers, such as maintenance of a specified level of tangible net worth, are sometimes employed, either by themselves or in combination with a credit rating requirement by the local public utility commission. But when the purchaser is pursuing resources on its own motion (as many distributing utilities are doing these days for a variety of reasons that go beyond renewal portfolio standards), one sees a greater willingness to include credit maintenance provisions in the PPA. c. Reciprocal Credit Maintenance Provisions. While reciprocal credit maintenance requirements (in which both the seller and the purchaser agree to maintain a certain credit posture and to post collateral if the posture is not maintained) are common in PPAs for gas- and coalfired resources, they have been less common in PPAs for other types of power, for several reasons. First, historically many geothermal energy project developers were independent companies without the substantial financial resources to support a credit maintenance requirement. However, as more financially substantial players (such as the unregulated development arms of investor-owned utilities) have entered the development arena in recent years, this is proving less a stumbling block. d. Provisions Recognizing Lender s Rights. The PPA must contain provisions pursuant to which the output purchaser authorizes the project owner to assign the owner s rights under the PPA to the lender as security for the project debt and recognizes the right of the lender to cure defaults and perform the owner s obligations under the PPA. Any PPA signed without such provisions will certainly be revisited before project financing can be put in place. e. Transmission Curtailment Risk. While not universally required, a PPA will provide better security for the lender (and better revenues for the project owner) if it shifts the risk of transmission curtailment to the output purchaser. This is done by providing that during periods of transmission curtailment, the output purchaser will be obligated to pay for the power that would have been produced and delivered had the curtailment not prevented the plant from operating. 2. Assignments of Key Contracts and Permits. As a second feature of the sealed system, the lender will also require first-priority assignments of all key project contracts and permits. This ensures that it has control (via the security arrangements) over the entire project as a going concern. On the contract side, this includes the equipment supply agreement, the construction contracts, the interconnection agreement, the parts supply agreement, the equity contribution agreement between the owners of the project owner, the operation and maintenance ( O&M ) agreement (if the geothermal energy project is to be operated by a third-party operator), the leases or rights-of-way for the project site, and, of course, the PPA. In addition to taking assignments of the contracts from the project owner, the lender will also insist on having each counterparty to the assigned contracts consent in writing to the assignment in a manner in which the counterparty acknowledges the lender s rights, agrees to give the lender notice of any default by the project owner, and agrees to grant the lender certain cure rights. The consents may also include a so-called bankruptcy replacement clause whereby the counterparty agrees to enter into a replacement agreement with the lender if the project owner is the subject of a bankruptcy proceeding. Finally, when payments are or may be owing by the counterparty to the project owner under the contract (for example, the PPA), the consent also makes provisions for STOEL RIVES LLP 2008 Ch. 5 Pg. 5

39 those payments to go directly into an account controlled by the lender, as part of the lockbox arrangement discussed below. On the permit side, it can be more problematic to obtain a valid and enforceable assignment of a needed project permit. This is because under applicable law, the permit is often granted to a particular entity, such as the project owner, and either no provision is made for assignment of the permit to a third party or the nature of the permit is such that it may no longer be valid in the hands of anyone other than the original permittee. To solve such problems, the lender may sidestep the issue by taking a first-priority security interest in the equity ownership interests of the project owner the stock of the project owner if it is a corporation, or the membership or partnership interests in the project owner if it is a limited liability company or partnership. In this way, in a foreclosure situation, the lender forecloses upon the equity ownership interests, thus taking over ownership of the project owner and therefore the permits that are held by the project owner, but the permits themselves are never transferred from one entity to another. This may still require some action on the part of the lender to effectively complete the foreclosure. For example, in certain situations, foreclosing on the equity interests of the project owner may require authorization from the Federal Energy Regulatory Commission ( FERC ) under Section 203 of the Federal Power Act (if taking over the project owner results in a transfer of FERC jurisdictional assets that cannot be lawfully done without an approving order from FERC). But it nevertheless provides a path forward for the lender that may not otherwise be available (or be subject to significant legal doubt) were it to attempt to foreclose directly on a security interest in a permit. As one can imagine, this does not tend to be very popular with potential equity investors. 3. Flow of Funds and Lockbox Arrangements. The final piece of the puzzle needed to create a sealed system to protect the lender is the creation under the credit agreement of a flow of funds (often called a waterfall ) and an accompanying lockbox arrangement. Again, the key purposes of these provisions are to ensure that the project revenues are applied in a manner that will ensure the timely repayment of the project debt, and to place the lender in the position of controlling the revenues to see that they are, in fact, so applied. The lockbox arrangement requires all persons making payments to the project owner under the project agreements to pay those amounts into an account controlled by the lender. Thus all PPA payments flow directly into this account, as do warranty or liquidated damage payments under the turbine supply agreement and balance-of-plant contract. Typically, the account in question is an account established with the lender itself, if the lender is the type of financial institution capable of handling such an account. Alternatively, the account may be established with a third-party financial institution, in which case the lender s rights with respect to the account will be memorialized pursuant to a custodian agreement among the lender, the project owner, and the custodian financial institution. It is the flow-of-funds, or waterfall, provisions in the credit agreement that govern the lender s (and, by negation, the project owner s) rights with respect to the project revenues captured by the lockbox arrangement. Given that under limited-recourse financing the project debt will be repaid only if the project operates more or less according to projections, the flow-of-funds provisions generally specify a priority of application of project revenues that has as its primary goal the maintenance of the project operations so that the project will continue to produce power and earn the needed revenues from power sales. It does this in part by directing the project revenues first to those expenses that are needed to keep the project operational, and in part by requiring the funding of various subaccounts in a manner that will, in effect, create reserves to protect against STOEL RIVES LLP 2008 Ch. 5 Pg. 6

40 adverse events that could interrupt the flow of project revenues. Moneys get paid out of the lockbox in accordance with the priorities or waterfall established under the credit agreement. Disbursement of lockbox moneys is made against a requisition presented by the appropriate party (the project owner or the O&M operator), accompanied by the relevant invoices documenting the expenditures for which disbursement is sought. It is not unusual for the lender to remit lockbox moneys directly to the party to whom they are owed, in order to avoid misapplication by the project owner or O&M operator. A typical flow of funds will provide that project revenues will be applied for the following purposes in the order of priority set forth below: a. O&M Expenses. First, project revenues are applied to the payment of the ongoing O&M expenses of the project. For this purpose, O&M expenses are generally defined to capture the cash outlays the project will need to make to stay operational, and to exclude noncash items such as depreciation expense. A typical flow-of-funds provision will, over time, trap project revenues in the O&M subaccount until an amount (or reserve) equal to six months O&M expenses is on hand. b. Debt Service. Second, project revenues are applied to the payment of debt service on the project debt. Again, typical flow-of-funds provisions will, over time, capture project revenues at this level of the waterfall until the debt service subaccount has on hand an adequate debt service reserve amount (typically six months debt service on the project debt, but sometimes as long as one year). c. Major Maintenance Reserve. Third, project revenues are deposited into a major maintenance reserve account. This reserve is required to be funded over time in an amount such that sufficient funds will be on hand to pay for anticipated items of major maintenance on the project assets and to provide a source of funding to cover the cost of major unanticipated equipment failures. d. Distributions to the Project Owner. Fourth, any remaining project revenues are deposited in a subaccount that is variously called a sweep account, a distribution account, or a surplus cash account. Subject to restrictions imposed under the credit agreement, the project revenues that end up at this level of the waterfall are available for distribution to the project owner. Generally such distributions are permitted only on a quarterly basis, and then only to the extent the subaccounts higher up in the waterfall are fully funded at the time of the proposed distribution and there is no default under the credit agreement. Typically, the credit agreement will use a debt service coverage ratio (the DSCR ) as one of the tests for determining how cash in the distribution account is to be applied. The DSCR is the ratio of net project revenues to annual debt service, expressed as a number. For example, a DSCR of 1.20 means net revenues for the fiscal year must be at least equal to 120 percent of annual debt service. To the extent the project fails to produce revenues sufficient to meet the DSCR, it generally means that the project has not been able to make the required payments into one or more of the subaccounts higher up in the waterfall. In such a situation, moneys in the distribution subaccount are not permitted to be distributed to the project owner, but instead are swept into the higher waterfall subaccounts until they are fully funded. STOEL RIVES LLP 2008 Ch. 5 Pg. 7

41 IV. Equity Financing. The other critical portion of the financing picture for geothermal and other renewable energy projects is equity. As a residual stakeholder with rights to profits that generally take a back seat to those of secured lenders, the equity component of these types of projects often tends to be the most difficult to raise because a high level of return is expected in order to justify the risk. Matters tend to be further complicated by the fact that the pool of investors is limited and that there generally is a lack of understanding of the sometimes confusing private equity financial landscape by developers, owners, and operators. A. What Is Private Equity? Private equity is one of the terms that tends to be least understood by people outside of the financial community. Private equity refers to the sale and purchase of securities that are not publicly traded in other words, securities in private companies that have not yet been registered under federal and state securities laws and, therefore, are not freely transferable on stock exchanges such as the New York Stock Exchange or NASDAQ. The information reporting requirements for entities without publicly traded stock under the Securities Exchange Act of 1934 are substantially less than those for entities whose stock is publicly traded. As a result, the world of private equity investing tends to be somewhat secretive and have an aura of mystique. The concept of private equity is a broad one, with a large number of very different types of investment groups being classified under the general definition. Since most geothermal energy projects are privately owned, becoming familiar with the private equity landscape is a critical step toward successful fundraising. There are fundamentally two types of private equity investors: individual private equity investors and institutional private equity investors. 1. Individual Private Equity. As the name suggests, individual private equity is simply investment by individuals who have the appropriate net worth to make investments for their own personal portfolios. Since they are just individuals, the amounts of money that they are able to invest tend to be smaller (in the tens of thousands or hundreds of thousands of dollars, rather than the millions). They can be classified primarily by their relationship to the companies in which they invest rather than by the source of their money or structure of their investment vehicle. The most common types of individual private equity investor categories are: Self financiers the developer or original owner of the project puts up the capital him or herself. Friends and family people known to the individual owner/developer who invest based on their personal relationship to the owner/developer rather than necessarily on the merits of the project itself. Angels arm s-length individual investors who are willing to invest and are often interested in becoming actively involved with the project, because of experience with the industry or passion about it or both. Individual investors are generally best suited for the early stages of project exploration and development. In fact, the first million dollars or so of high-risk equity will probably have to come from these types of sources because such small investments simply are not large enough to attract the attention and justify the involvement of funds managing money for large financial institutions. STOEL RIVES LLP 2008 Ch. 5 Pg. 8

42 As a side note, while government grants are a common funding source for early-stage projects, grants are not technically considered equity. Unlike an equity investment, grants are not made with the expectation of profit or of being ultimately repaid. In this sense, they are more akin to gifts and, as such, can be one of the best and least expensive sources of financing for an early-stage company or project. 2. Institutional Private Equity. In contrast to the small scale and informality of individual investors, the bulk of all dollars available for investment in the United States comes directly or indirectly from large financial institutions such as pension funds, insurance companies, university endowments, and large corporations. These institutions have trillions of dollars under management and act as formal mechanisms for pooling money for very large numbers of individuals who wish to have their savings professionally managed and placed in diversified asset portfolios. In fact, in the United States today, there is so much money under management with these funds that the managers directly responsible for the investment decisions can only go to a certain level of depth in their analysis of, and day-to-day involvement with, investments. Specifically, they view the money as a resource of their portfolio that needs to be deployed and focus their efforts on asset allocation, meaning designating in which broad asset categories to place their money. Instead of trying to invest the money directly in companies themselves (although occasionally they do), they prefer to invest in a diversified portfolio of smaller, specialized investment funds managed by professional managers that have particular areas of expertise. The exact categories for the funds in which they invest varies from institution to institution, but generally the institutional equity investment taxonomy is as follows: Public Equity Mutual Funds Publicly Traded Stocks Private Equity Venture Capital Mezzanine Funds Hedge Funds Buyouts Work-outs/Turnarounds Real Estate/Development Project Investing 3. General Diversified Private Equity Groups. When making their investment allocations, it is not uncommon for the institutions simply to put a substantial portion of their funds in generic private equity funds. In these funds, then, the fund managers have the freedom to opportunistically make investments in many or all of the above-listed subcategories. Many of these diversified private equity funds, therefore, have the latitude and interest (in the name of portfolio diversity) to invest in renewable energy projects such as a geothermal development project. On the other hand, because they are generalists, they may not have any exceptional level of understanding or expertise in how those projects are put together and operated, so it may take some education before they are actually comfortable enough to invest. The investing activities of diversified private equity groups are distinguished by the following key characteristics: STOEL RIVES LLP 2008 Ch. 5 Pg. 9

43 They have very large pools of capital (often billions of dollars) that need to be deployed in a prudent manner. Like their institutional parents, they take a fairly high-level, general view of investing and focus very closely on diversification and portfolio theory. They view their investment capital as needing to be perpetually deployed and, as a result, view exiting an investment as a negative event (rather than a successful ultimate payoff) because it just means that they have to turn around and find another asset in which to put the same money. They very closely assess the risk/reward trade-off total return is assessed with respect to the risk involved. Only investments with the lowest risk/reward ratio tend to get done. They are large enough to spend the time and money to deal with complex legal structures or tax issues because of the large amount of money that they have to deploy and the economies of scale. They can often actually benefit from tax incentives because they have taxable income across their portfolio to offset. In short, these types of funds, if their managers understand or are willing to learn about the geothermal sector, can be good candidates for providing project equity. 4. Focused Private Equity: The Venture Capital Fund Example. While venture capital has gotten a lot of publicity in the past few years because a lot of people made a lot of money (and subsequently lost a lot of money) during the Internet bubble, the reality is that venture capital is a very narrowly focused type of investment activity and a very small subset of the entire private equity world. In contrast to the diversified investment approach of private equity funds described above, venture capital is designed to be very tightly focused on only the highest risk and highest reward investment opportunities and, as such, is viewed by the financial institutions as the highest risk component of the whole equity portfolio. In essence, this is a small amount of play money out of the whole portfolio that is set aside to swing for the fences, knowing full well that that some or much of it may lost and never recovered. The hope is that by investing in enough of these funds, the overall return will still be higher than other asset categories or diversified funds. The primary mission for venture investors, and the only way that they can generate the level of returns that they target, is to invest in growth companies with new technology. With that mission, they usually stay away from (and often are explicitly precluded by their organizational documents from) investing in any sort of one-time real estate, construction, or energy project. STOEL RIVES LLP 2008 Ch. 5 Pg. 10

44 Venture capitalists goals are to invest in ongoing businesses with high-quality management teams that capitalize on new technologies and opportunities arising from fundamental market shifts. Because of the uncertainty and lack of structure involved with the early-stage companies, they expect extremely high levels of return. Expectations of returns on the order of 10 times the original investment in 5 years or 45 to 55 percent compounded annual return per year are not unusual in this segment. Additionally, venture capitalists demand hands-on control of the companies with which they work. 5. Corporate Investors. While people initially tend to think of stand-alone investment funds as the primary source of equity investment for energy projects, another source of capital that is particularly applicable to the geothermal and renewable energy sector are corporate investors. Like institutions, large corporations often have large pools of capital to invest and can often be convinced to invest for either taxmotivated or strategic reasons. B. A Framework for Finding Equity Sources. With this full spectrum of private equity investors, the best way to attract investors is by doing your homework and making sure that you understand who you are talking to and what motivates them. Below is a list of items that should be considered when trying to determine how to focus your private equity fundraising efforts. 1. Stage of Company s Development. In the energy world, there are two primary stages: the development/exploration phase (which is roughly equivalent to seed stage in the venture world) and the project stage. The early stages of the project will probably have to be financed through some combination of self, friends and family, and angel funding, and government grants. There are some very small scale, institutionally backed seed funds or renewable energy funds that are beginning to emerge that can complement these more traditional sources, but they are generally few and far between. Institutional capital tends not to be available until the much later stages in the project s development. 2. Investment Philosophy. The key distinction here is the difference between investment in development projects and investment in growth companies built to exploit new technologies or fundamental market shifts. Venture capitalists tend to invest in new technologies and rapidly growing businesses and, therefore, are not a good source for any sort of project financing. 3. Geographical Focus. Some investors are national or global in focus and some tend to be more locally focused. As a general rule, the earlier stage the project, the more likely it will be that the investor is nearby. This is because working with unproven, incomplete, high-risk projects requires much closer attention and more regular interaction than later-stage opportunities, and this level of involvement is far easier if the investor is actually located in the same state or city. Investors who are not necessarily local tend to be more comfortable with later-stage investment opportunities in which the financial structure, rather than the day-to-day operational concerns, is the driving force. 4. Deal Size. The amount of money that a project is looking to raise also greatly effects which equity source is sought. If the equity amount sought is under $1 million, angels, friends and family, and self funding tend to be the best alterantive because institutional-backed funds do not make investments that STOEL RIVES LLP 2008 Ch. 5 Pg. 11

45 small. If the investment amount is in the $2 million to $5 million range, then venture capital is probably well suited, but the investment philosophy requirements of the investor still must be met. Since venture capitalists tend not to like project investing, corporate investors are probably better suited for this midlevel range of financing. If the project is seeking more than $10 million in equity, then the diversified private equity funds or strategic investors are probably the best source. 5. Risk/Return Profile. Venture capitalists money is the highest-risk capital, so naturally, they expect the highest rewards (45 to 55 percent per year compounded return). This generally precludes their involvement in development projects. Institutions, on the other hand, are usually satisfied with significantly less (maybe 15 to 20 percent per year compounded). Since their upside is limited, however, they expect the risk that they are asked to bear to be far lower. This means wanting to have many of the same types of assurances that lenders require, even if the lenders are expected to have a preferential financial position. 6. Liquidity Horizon. Its important to take a look at when investors expect to get their money back. Individuals and seed and start-up stage investors need to understand that they may get their money back only over the full life of the project (maybe 10, 20, or 30 years!). Venture capitalists generally look for a five- to seven-year horizon and then expect to be fully cashed out at the end of that period. Corporate investors who are motivated by tax savings tend only to remain interested in the project for the period of time during which they can receive the tax benefits (often 10 years). Institutional equity investors want to have as long of a horizon as they can get, provided they can maintain the appropriate level of returns, because redeploying capital is seen as a problem to be dealt with rather than an opportunity. 7. Industry Expertise. Remember that an additional reason for bringing in investors is for the value they add beyond just their capital contributions. It is wise to consider noneconomic benefits, such as industry expertise and connections, when targeting investors. V. Conclusion. Raising millions of dollars of financing for geothermal energy projects can be complex and present a wide range of challenges, especially since it will require significant debt and equity financing. But by understanding the underlying structures and motivations of both lenders and private equity investors, as well as the best ways to reflect their respective needs in terms of the deal and the legal documentation, one can create well-balanced, fully financed deals that are ultimately rewarding for all of the participants. STOEL RIVES LLP 2008 Ch. 5 Pg. 12

46 Chapter Six THE LAW OF LAVA Getting Some Credit: Tax Issues Robert T. Manicke, Kevin T. Pearson Production of electricity from geothermal resources raises numerous federal, state, and local tax issues in addition to those involved in general choice-of-entity considerations. These tax issues place a premium on careful structuring, and can create significant economic benefits or can give rise to significant costs. I. Federal Production Tax Credit. Section 45 of the Internal Revenue Code of 1986, as amended (the Code ) provides a credit against income tax, commonly known as the production tax credit ( PTC ), for electricity produced from certain renewable resources. Prior to 2004, the PTC applied only to electricity produced from wind, closed-loop biomass and poultry waste. As part of the American Jobs Creation Act of 2004, however, Congress extended the PTC to apply to geothermal facilities. This extension of the PTC significantly expanded and improved the financing alternatives available for geothermal facilities. A. Requirements for Claiming the PTC. The PTC is based on production, rather than the cost of a facility. The PTC applies to electricity produced by a taxpayer from qualified energy resources at a qualified facility and sold to an unrelated person during any taxable year in the credit period. Each of the following requirements must be satisfied for a taxpayer to claim the PTC: Produced by the Taxpayer The electricity must be produced by the taxpayer seeking to claim the PTC. If more than one person has an ownership interest in a facility, production from the facility is allocated among the owners in proportion to their respective ownership interests in the gross sales from the facility. Qualified Energy Resources The electricity must be produced from energy derived from a geothermal deposit, which is defined as a geothermal reservoir consisting of natural heat which is stored in rocks or in aqueous liquid or vapor, whether or not under pressure. Qualified Facility The electricity must be produced by a facility in the United States that is owned by the taxpayer seeking to claim the PTC and that is originally placed in service after October 22, 2004 and before the sunset date, discussed below. A facility generally is considered to be placed in service for this purpose when it is placed in a condition or state of readiness and availability to produce electricity. Sold by the Taxpayer to an Unrelated Person The electricity must be sold by the taxpayer seeking to claim the PTC to an unrelated person during the year for which the PTC is sought. No Advance Approval Required There is no advance approval requirement for claiming the PTC. A taxpayer who is entitled to the credit simply reports it on the taxpayer s federal income tax return. STOEL RIVES LLP 2008 Ch. 6 Pg. 1

47 B. Calculation of the PTC. The PTC for any taxable year during the credit period generally is equal to 1.5 cents, adjusted for inflation, per kilowatt hour of electricity produced and sold during the taxable year. The adjusted PTC amount for electricity produced and sold during calendar year 2007 is 2.0 cents per kilowatt hour. C. Credit Period. The PTC credit period for a qualifying geothermal facility is the 10-year period beginning on the date the facility was originally placed in service. D. Sunset Date. To qualify for the PTC, electricity must be produced at a facility that is placed in service before January 1, The sunset dates have been extended a number of times since Section 45 was added to the Code, and a number of proposals have been made in Congress that would extend the sunset date beyond At present, however, it is unclear whether any of these proposals will be adopted. II. Federal Energy Credit. Sections 46 and 48 of the Code provide a one-time credit against income tax for the cost of certain qualified geothermal energy property. The credit is calculated as a percentage, referred to as the energy percentage, of the tax basis (generally the cost) of any qualified energy property that is placed in service during a taxable year. A. Energy Percentage. The energy percentage with respect to a geothermal facility is 10 percent. B. Energy Property. The term energy property is defined for purposes of the energy credit to include any property that meets all of the following requirements: Geothermal Equipment The property must be equipment that is used to produce, distribute, or use energy derived from a geothermal deposit. In the case of electricity generated by geothermal power, this includes only equipment that is used up to (but not including) the electrical transmission stage. First Use or Construction by Taxpayer The property must be either (a) constructed, reconstructed, or erected by the taxpayer wishing to claim the credit or (b) if the property is acquired by purchase, the original use of the property must commence with that taxpayer wishing to claim the credit. Depreciable or Amortizable The property must be eligible for depreciation or amortization for federal income tax purposes. Performance and Quality Standards The property must meet performance and quality standards, if any, prescribed by the Secretary of the Treasury that are in effect at the time the property is placed in service. To date, the Secretary has not prescribed any such performance or quality standards. Not Public Utility Property The property must not be public utility property as defined in Section 46(f)(5) of the Code, as in effect on the day before the date of enactment of the Revenue Reconciliation Act of This generally includes any property used predominantly in the business of selling steam through a local distribution system or transporting gas or steam by pipeline, if the rates for such sales or transportation are established or approved by a governmental unit or agency. STOEL RIVES LLP 2008 Ch. 6 Pg. 2

48 C. Progress Expenditure Rules. In certain circumstances involving qualified energy property with a normal construction period of more than two years, a taxpayer may be entitled to claim the energy credit with respect to progress expenditures in tax years before the property is placed in service. D. Recapture of the Credit. The energy credit may be subject to recapture if a taxpayer sells or otherwise disposes of the energy property or stops using it in a manner that qualifies for the credit. III. Federal Tax Credit Limitations. There are a number of limitations that apply to both the PTC and the energy credit. Following are a few examples of those limitations. A. One Type of Credit Only (No Double Dipping). A taxpayer cannot claim both the PTC and the energy credit with respect to a particular geothermal facility. If a taxpayer claims the one-time energy credit with respect to the cost of a facility, the taxpayer cannot also claim the PTC with respect to electricity produced by the facility. Likewise, if a taxpayer claims the PTC with respect to electricity produced from a facility, the taxpayer cannot also claim the energy credit with respect to the cost of the facility. B. Cutback for Subsidized Energy Financing or Industrial Development Bonds. Both the PTC and the energy credit are limited with respect to facilities that are financed in whole or in part with certain government grants, proceeds of tax-exempt bonds, subsidized energy financing (that is, financing under a federal, state, or local program designed to provide subsidized financing for energy conservation projects), or other tax credits. All of the government funding available with respect to a particular facility should be carefully analyzed to determine whether and to what extent it will reduce the tax credits available with respect to the facility. C. Alternative Minimum Tax Limitation. Both the PTC and the energy credit are part of the general business credit allowed pursuant to Section 38 of the Code. As a result, the benefit of the credit to a taxpayer may be limited by alternative minimum tax provisions (although a limited exception to this rule is made with res pect to the PTC). D. Nonrefundable; Carryover of Unused Credit. Both the PTC and the energy tax credit are nonrefundable credits. If a person entitled to claim a credit does not have sufficient income tax liability to use the entire credit for a particular year, that person generally will not be entitled to a refund of federal income tax on account of the credit. Any unused portion of the credit, however, generally may be carried back one tax year and forward 20 tax years. E. Monetizing Credits. A taxpayer that has little or no need for tax credits (because, for example, it has little or no taxable income) may nevertheless be able to obtain some benefit from either the PTC or the energy credit by entering into an arrangement with an investor that does need tax credits. For example, a taxpayer could enter into a partnership with an investor that is willing to contribute cash to help fund construction of a geothermal facility. The partnership could then construct and operate the facility and, within certain limits, tax credits could be allocated to the partner having a need for credits. Another possible technique would be for an investor to own the facility and to enter into a power purchase agreement and an operation and maintenance agreement with the taxpayer. A taxpayer also may be able to lease a qualified facility to an investor and, with certain limitations, pass the credit to the lessee. Each of these techniques, and any other technique for monetizing tax credits, involves uncertainty and requires careful tax planning. These and other considerations STOEL RIVES LLP 2008 Ch. 6 Pg. 3

49 should be taken into account when choosing the type of entity that will own a geothermal facility and the various financing alternatives available. IV. Federal Election to Deduct Intangible Drilling and Development Costs. Section 263(c) of the Code authorizes a taxpayer to elect to deduct currently, rather than capitalize and depreciate or amortize, certain intangible drilling and development costs related to exploration for, and development of, geothermal deposits. The benefit of this election may be decreased by a special rule limiting the amount of certain corporate preference items. In addition, making the election may have alternative minimum tax consequences. Nevertheless, currently deducting a portion of these expenditures can result in significant tax savings. The potential deduction for intangible drilling and development costs also should be carefully analyzed in any transaction in which a developer wishes to monetize tax credits associated with the resulting geothermal facility. V. State and Local Tax Issues. In addition to federal income tax issues, construction and operation of geothermal facilities also raise numerous state and local tax issues that should be carefully examined. Following is a general description of the types of issues that may arise, with selected examples. A. Net Income Tax States. The vast majority of states impose a net income tax. States generally base their income tax system on the federal system, and many states have adopted relatively uniform rules governing division of the tax base and computation of taxable income. Despite these similarities, however, each state s tax system is different and must be separately analyzed. Nexus and Apportionment. Siting a geothermal project in a particular state will create nexus with that state and will allow the state to tax the income of the company that owns or operates the project. In addition, less substantial activities, such as consulting in a state, may create nexus. States generally measure the taxable income of a company by allocation and apportionment. In western states, including California, Idaho, Montana, and Utah, the company s overall business income from all sources is apportioned to the state based on the company s property, payroll, and sales within the state. Reflecting a national trend, Oregon s apportionment is now based entirely on sales. For purposes of apportioning sales of electricity among different states, some states, such as California, source the sale based on where the majority of income-producing activity related to the sale occurs. Other states may use different sourcing rules. Oregon, however, takes the position that sales of electricity are sourced to the state where delivery occurs. The apportionment rules can sometimes produce surprising results: if the company as a whole has taxable income, the company may owe tax to a state even if the activities in that state are not profitable on a stand-alone basis. Income Tax Incentives. Some income tax states offer incentives to promote the development of geothermal power and other alternative energy projects. It is important to understand the nature of each incentive, as there is considerable variation among the states. Also, as noted above, some state incentives may reduce the amount of the federal energy credit available for the project. For example, Oregon has adopted a business energy tax credit (the BETC ). The BETC program allows an Oregon taxpayer that owns and operates a geothermal power project to claim a credit against Oregon income tax to offset the eligible costs of construction of the project. Legislation passed in 2007 substantially increased the amount of the credit. Under the new law, the amount of the credit is 50 percent of the eligible costs, up to a STOEL RIVES LLP 2008 Ch. 6 Pg. 4

50 maximum total credit amount of $10 million (formerly $3.5 million). The total credit amount is claimed over five years, and unused credit may be carried forward for up to eight years. Although the amount of the BETC may be reduced by federal subsidies, the 2007 legislation eliminated the former requirement that the BETC be reduced by the federal energy credit discussed above. A developer may sell the BETC outright, at a discount rate established by the state. Montana offers a somewhat similar income tax credit for certain alternative energy systems, including geothermal systems. B. Sales and Use Taxes. Nearly all of the states impose a sales tax. In most states, the tax is imposed only on sales of tangible personal property. Some states also impose use tax on sales of certain kinds of services. In addition, some states impose a transfer tax on the sale (and sometimes the lease) of real property. Purchase or Use of Turbines and Other Equipment. Most states sales and use taxes will apply to purchases or use of turbines and other equipment within those states. Generally No Sales or Use Tax on Sales of Power. Most states that impose sales and use taxes do not impose those taxes on sales or use of electricity. Tax Incentives. Some states, such as Nevada, offer exemptions or other sales and use tax incentives for geothermal energy facilities. Idaho s 2005 legislature adopted a sales and use tax rebate for certain alternative energy generation equipment, including machinery and equipment used in generating electricity from geothermal resources. C. Property Tax. Virtually all states impose property tax that is assessed annually and is measured, in some fashion, by the value of real property. Most states also tax tangible personal property that is used for business purposes. Intangible property is taxable in some states if the owner is centrally assessed, as discussed below. Central Assessment Likely. In many western states, such as Oregon, a company that produces electricity is centrally assessed for property tax purposes. In Washington, central or local assessment depends in part on whether the company s property crosses county lines. In California, the facility s output is a factor in determining whether central assessment applies. Central assessment means that the amount of property tax is determined by the state revenue authority rather than by the county assessor s office. Valuation. States generally accept the three traditional valuation methods for valuing utility property (the cost approach, income approach, and comparable sales approach). Determining the correct value of a particular project is a matter of frequent controversy. It is often useful to consult an expert in the area of utility appraisal. Property Tax Reporting. Some states require owners of centrally assessed property to file annual returns reporting the value of their property. It is good practice to consult a valuation expert before filing the first return with respect to the property, in order to accurately communicate on the return items that could result in tax savings in future years. STOEL RIVES LLP 2008 Ch. 6 Pg. 5

51 Rollback Penalties in Farm and Timber Use Areas. Some states, such as Oregon and Washington, impose retroactive property tax penalties when land that is used for farming or timber is dedicated to a different use. In addition to those penalties, property taxes increase prospectively after the change of use. This issue may arise during the siting process. Property Tax Incentives. As part of due diligence in constructing or acquiring a geothermal facility, it is worthwhile to inquire whether any property tax incentives are available. Property tax incentives can be particularly advantageous because, in contrast to income tax credits, a property tax exemption typically applies at the front end of an investment and reduces what otherwise would be an unavoidable and substantial cost. Nevada and Montana, for example, offer a property tax exemption for certain renewable energy facilities, including geothermal energy facilities. Oregon s exemption statute was expanded in 2007 to allow exemption for a greater range of projects when the electricity is used on site. Also in Oregon, it may be possible to obtain a temporary property tax exemption under the state Enterprise Zone Program or the Strategic Investment Program. The Enterprise Zone Program typically offers an exemption for three to five years, but in rural areas the exemption period may be as long as 15 years. To qualify, state law requires that the company increase its permanent, fulltime employment within the zone by at least 10 percent. (Note that one employee may satisfy the minimum hiring requirement if the company has not previously operated within the zone). Other requirements, such as minimum capital investment size, may apply. The Strategic Investment Program statutes offer a partial exemption for 15 years, with a fee payable to the county and other potential conditions. The Strategic Investment Program statutes recently were revised to lower the minimum investment threshold. Negotiations for benefits under both the Enterprise Zone and Strategic Investment Programs generally occur at the county level, sometimes with participation of cities. D. Excise Taxes. When considering operation of a geothermal power facility, state and local excise taxes also should be taken into account. Washington Public Utility Tax. The state of Washington and a number of municipalities within Washington impose a public utility tax ( PUT ) on the privilege of engaging in certain utility businesses within the state and those localities. The state PUT is imposed at a rate of 3.62 percent of gross income derived from certain enumerated public service businesses, including the light and power business. The light and power business is defined for purposes of the state PUT as the business of operating a plant or system for the generation, production or distribution of electrical energy for hire or sale and/or the wheeling of electricity for others. The state PUT is intended to apply only to revenues derived from the retail sale of electricity to consumers. Accordingly, deductions in computing gross revenues are allowed for revenues derived from the sale of electricity for resale, among other deductions. To the extent a business is subject to the state PUT, that business will not be subject to the Washington business and occupation tax. Cities and towns may impose a PUT of up to 6 percent of gross revenues derived from conducting an electrical energy business. Other State and Local Excise Taxes. Other states and localities may impose other kinds of excise taxes. For example, some Nevada counties and cities, and some California cities, impose gross receipts taxes for the privilege of doing business in the locality. California imposes a fee based on gross receipts for the privilege of doing business as a limited liability company. STOEL RIVES LLP 2008 Ch. 6 Pg. 6

52 Chapter Seven THE LAW OF LAVA Delivering the Goods: Regulatory and Transmission-Related Issues Stephen C. Hall, Jennifer H. Martin, Marcus Wood Producers of renewable geothermal energy, like other sellers of electricity, must understand and meet the regulatory requirements applicable to the sale of power generated by their resources. In addition, in order to access the electric transmission grid, geothermal energy producers must negotiate and execute an interconnection agreements and transmission service agreements, and purchase necessary transmission ancillary services before the geothermal developer begins generating the first MW of power. This chapter presents a general discussion of these issues. Before embarking on a particular course of action, it is highly recommended that a developer seek the opinion of qualified counsel, especially considering that many of the laws and regulations relating to these topics may be affected by recent legislation and ongoing rulemaking proceedings. I. Regulatory Structure Issues PUHCA, EWGs, and QFs. The Energy Policy Act of 2005 repealed in part the Public Utility Holding Company Act of 1935 ( PUHCA 1935 ) and enacted the Public Utility Holding Company Act of 2005 ( PUHCA 2005 ). By opening the door to certain types of utility acquisitions and mergers that have been prohibited since 1935, Congress set the stage for a consolidation of the electric utility industry that will present both challenges and opportunities for renewable energy developers and producers. Under PUHCA 1935, unless exempted, geothermal energy project companies were subject to extensive regulation by the Securities and Exchange Commission ( SEC ). Although under PUHCA 2005 the SEC will no longer be regulating non-exempt geothermal energy project companies, the Energy Policy Act of 2005 has (1) granted state regulators and the Federal Energy Regulatory Commission ( FERC ) broad access to books and records of such companies, and (2) provided for FERC review of the allocation of costs for non-power goods or services between regulated and unregulated affiliates of such companies. Geothermal energy project companies can obtain exemptions from these remaining requirements. The two most common means of obtaining exemptions are for the project owner to obtain status as an exempt wholesale generator ( EWG ) or for the project to obtain status as a qualifying facility ( QF ). Each of these categories is summarized below. A. Exempt Wholesale Generator Status. In an effort to stimulate wholesale electric competition, Congress enacted the Energy Policy Act of 1992, which created an exemption from PUHCA for independent power producers that qualify as EWGs. EWG status is determined by FERC, and the EWG status generally begins at the time the independent power producer files an application with FERC. EWG status is available to any generator of electricity, regardless of size or fuel source, so long as such entity is exclusively in the business of owning and/or operating electric generation facilities for the sale of energy to wholesale customers. Certain incidental activities may also be permitted. Independent power producers should be aware of several issues associated with EWG status. First, the exclusively own and/or operate requirement mentioned above typically requires the creation of a special purpose entity to own the geothermal generation facility and sell its electric output. Second, EWGs are restricted to wholesale sales and therefore cannot take advantage of retail sale opportunities in jurisdictions that have approved retail direct access. Finally, EWGs are restricted in their ability to enter into certain types of transactions (such as leases) with affiliated regulated utilities. STOEL RIVES LLP 2008 Ch. 7 Pg. 1

53 Rates for power sales by EWGs are subject to FERC regulation under section 205 of the Federal Power Act. As a result, an EWG must apply for and FERC must grant either cost-based or market-based rate approval, i.e., powermarketing rights, before an EWG can enter sales for resale of power. FERC generally will grant market-based rate approval, provided that the applicant and its affiliates (if any) demonstrate that they do not have or have adequately mitigated horizontal market power (in electrical generation) and vertical market power (in transmission and other barriers to market entry) in the relevant markets. The Commission also imposes certain restrictions governing transactions and conduct between power sales affiliates where one or more of those affiliates have captive customers. Once FERC grants market-based rate approval, the EWG will have ongoing FERC filing and reporting requirements. B. Qualifying Facility Status. The Energy Policy Act of 2005 has changed the rules for qualified facilities (commonly referred to as QFs ), introducing both risk and opportunity. Developers of new geothermal projects, as well as sellers under existing QF contracts (especially those sellers with contracts that will be expiring soon), will want to familiarize themselves with these changes. During the energy crisis in the late 1970s, Congress passed the Public Utility Regulatory Policies Act of 1978 ( PURPA ) to encourage the development of cogeneration and small renewable energy projects (i.e., QFs). Prior to the passage of the Energy Policy Act of 2005, PURPA was important to renewable energy developers for several reasons, one of which was the exemption for many QFs from most of the provisions of the Federal Power Act and from certain types of state utility regulations. The Energy Policy Act of 2005 (and FERC s interpretation thereof) has limited the applicability of these exemptions, making it more difficult some types of projects to obtain such exemptions. On the other hand, the Energy Policy Act of 2005 s elimination of PURPA s limitations on utility ownership of QFs has generated new interest in such utility ownership increasing the potential value of both new and existing QF projects and the range of possible geothermal transaction structures with electric utilities. The Energy Policy Act of 2005 has narrowed the advantages that QFs previously enjoyed compared to EWGs. First, as mentioned above, QFs no longer enjoy such broad exemptions from the requirements of the Federal Power Act. Significantly, owners of QFs over 20 MWs (unless making state-imposed avoided costs sales or making sales under contracts that predate the effective date of FERC s new rules) now need a FERC-approved tariff before selling energy from the projects. Second, the Energy Policy Act of 2005 weakened the must buy obligation that allows QFs to require retail public utilities to purchase QF output at the utility s avoided costs, i.e., the costs the utility would have incurred but for the QF purchase. Utilities may now petition FERC for an exemption from PURPA s mandatory purchase requirement if the utility can demonstrate that a QF in its service territory would have nondiscriminatory access to competitive wholesale markets for energy and capacity that meet certain standards. The potential loss of this must buy requirement could be significant because stateestablished avoided cost rates often have exceeded prevailing wholesale market prices and such published rates have been an effective negotiating tool for gaining favorable pricing under non-qf renewable energy sale agreements. One clear advantage of QFs over EWGs is that PURPA does not restrict the ability of QFs to make retail sales to the extent such sales are allowed under state law. Another distinction between QFs and EWGs is that QFs sometimes are interconnected under state regulators interconnection rules, which may or may not be advantageous for a particular project. A QF may have an option to interconnect under FERC rules. STOEL RIVES LLP 2008 Ch. 7 Pg. 2

54 C. Other Ongoing Regulatory Requirements. Whether a geothermal developer is a EWG or QF, or has FERC approval to sell power at market-based rates, the geothermal developer may also be subject to other filing and reporting obligations at FERC. For example, FERC s prior approval is required before the developer disposes of FERC-jurisdictional facilities above certain dollar thresholds. This prior approval requirement generally applies to indirect disposition of such assets, which can include the sale of project membership interests to investors, and accordingly, consultation with a knowledgeable FERC attorney is advised in connection with any plans by the developer to restructure, sell, or otherwise dispose of its assets. Likewise, FERC may require updates to the market-based rate filing, EWG application, and/or QF certification in connection with changes in the material facts on which FERC relied in granting such status. Finally, FERC notice or approval may be required when certain directors or officers will hold similar positions in related affiliates. The foregoing list is not exhaustive and is intended to highlight only some of the various FERC notification and filing requirements related to jurisdictional geothermal developers, and therefore consultation with knowledgeable attorneys is recommended. II. Transmission and Interconnection Issues. In order to obtain project financing and gain access to wholesale power markets, geothermal resource producers must negotiate agreements to interconnect with the transmission system of the applicable transmission provider. In addition, a developer will generally need to obtain any necessary transmission service to deliver output from the project to the purchasers of that output. Most lenders and many investors will require evidence of executed generation interconnection and/or transmission service agreements as a condition of financing or project purchase. Most transmission providers are subject to jurisdiction by FERC, and therefore transmission service agreements and generation interconnection agreements are generally subject to regulation by FERC. Interconnection to utilities exempt from FERC interconnection rules raises unique questions, which should be considered when selecting project sites. A. Generation Interconnection Agreements. A generation interconnection agreement is a contract between the generation owner and the transmission provider that owns or operates the transmission system with which the project will be connected governing the interconnection of the project with the transmission system. In two landmark orders (Order Nos and 2006), FERC established standardized procedures and agreements for the interconnection of generating facilities with the interstate transmission facilities owned, controlled, or operated by the nation s investor-owned utilities. In regions where the transmission system is owned and operated by separate entities, FERC will require that both of those entities sign the interconnection agreement. FERC Order No establishes standard interconnection procedures and a standard interconnection agreement for generators larger than 20 MW ( Large Generators ). Similarly, FERC Order No establishes standard interconnection procedures and a standard interconnection agreement for generators with a capacity of 20 MW or less ( Small Generators ). Developers may discover less favorable contract terms when negotiating interconnection agreements with nonjurisdictional utilities, which would include many municipal utilities, cooperatives, and public utility districts. In some cases, these entities have adopted FERC s standardized procedures and agreements, but in other cases such utilities are likely to either continue to use either their own forms of agreement or offer revised versions of FERC s standardized procedures and agreements. STOEL RIVES LLP 2008 Ch. 7 Pg. 3

55 Generally, the two main purposes of interconnection agreements are (1) to identify and allocate the costs of any new facilities or facility upgrades that need to be constructed and (2) to set forth the technical and operational parameters governing the physical interconnection. In general, before the execution of an interconnection agreement, the transmission provider will commission a series of interconnection studies, at the interconnection customer s expense, to determine what new interconnection and transmission facilities need to be constructed to accommodate the new generation facility, and the cost of such construction. Because geothermal resources are often located in remote locations, substantial new facilities and facility upgrades may be required. Order Nos and 2006 directly assign the costs of interconnection facilities and distribution upgrades to the interconnection customer. Network upgrades (i.e., upgrades to the transmission system at or beyond the point of interconnection) are treated differently, however, and even though the costs of upgrades may initially be borne by the interconnection customer, those costs may be reimbursed to the interconnection customer in the form of transmission credits. In certain transmission systems, however, such as those controlled by the Midwest ISO or the PJM Interconnection, the interconnection customer will not be entitled to all or part of this reimbursement. For most interconnections of Small Generators, it is unusual to have network upgrades. The nature of the network upgrade reimbursement (partial or full) may also impact whether and to what extent tax gross-ups must be included in the payment by the interconnection customer. Determining the point of interconnection for purposes of distinguishing between interconnection facilities and network facilities is an area of potential dispute between the parties. Transmission providers have an incentive to design interconnections in a manner that places the majority of the new facilities on the customer s side of the interconnection, thereby depriving the customer of a transmission credit to offset the costs of such facilities. Consistent with FERC precedent, only such facilities as are necessary to reach the point of interconnection are properly classified as interconnection facilities. Agreements to reclassify interconnection facility costs as network upgrades, or vice versa, have not been found to be just and reasonable, and have been rejected by FERC. Interconnection agreements address such technical and operational issues as reactive power factors, responsibility for electrical disturbances, metering and testing of equipment, exchange of operating data, and curtailment events. B. Transmission Service Agreements. Interconnection service or an interconnection by itself does not confer any delivery rights from the generating facility to any points of delivery. Therefore, unless the project owner is able to sell the output of the project at the point of interconnection with the transmission grid, the project owner will be required to obtain transmission service from one or more transmission providers to wheel project output to the purchaser. An alternative is for the project owner to sell some or all of the output STOEL RIVES LLP 2008 Ch. 7 Pg. 4

56 under a contract shifting the transmission obligation to the purchaser. In addition, acquiring adequate transmission service is essential to obtaining debt or project financing on reasonable terms and conditions. Transmission providers are required by FERC to offer transmission service on an open, nondiscriminatory basis pursuant to a transmission tariff that will govern the terms by which such service is provided. Upon receiving a request for service, the transmission provider will evaluate available transmission on its system and determine whether additional transmission facilities need to be constructed to accommodate the requested service. In major parts of the United States, the transmission provider is a Regional Transmission Organization ( RTO ) or Independent System Operator rather than the actual owner of the applicable transmission facilities. Acquiring transmission service from nonjurisdictional transmission providers raises additional questions that depend on the nature of the entity, the scope of its transmission facilities, and other issues beyond the scope of this chapter. Under FERC s general transmission pricing policy, generators pay the greater of the incremental costs or embedded costs associated with requested transmission service. Incremental costs refer to the additional system costs (for example, construction of new facilities and upgrades) resulting from the requested service. Embedded costs reflect an allocation of system costs to the various users, generally based on MW of service. Some geothermal projects, because of their remote locations, may require substantial system upgrades that will result in the transmission customer paying an incremental cost rate that exceeds its pro rata share of the system costs. These transmission pricing rules may be different if the transmission provider is an RTO. The rules of the existing and proposed RTOs may in fact be much more favorable to geothermal resources than FERC pricing. For example, an RTO may recover the fixed costs of the applicable transmission system from end users, with a generator facing only any transmission congestion charges. The RTO also may eliminate rate pancaking, which is the imposition of multiple transmission charges for use of more than one transmission owner s transmission facilities. Obviously, rate pancaking is an important consideration for geothermal resources that are located far from energy markets. C. Ancillary Services. Project owners will be required under the transmission provider s tariff to either provide or purchase transmission ancillary services, which are products designed to ensure the reliability of the transmission system. These services include, for example, replacement of transmission losses and provision of operating reserves. D. Greater Access to the Transmission Grid. On February 16, 2007, FERC issued Order No. 890, which reforms open-access transmission tariff ( OATT ) rules, and is designed, in part, as an effort to improve transparency of transmission service and reduce transmission barriers for new projects. Once they go into effect, these amendments may result in increased and improved access to the transmission grid for geothermal energy developers. The details of Order No. 890 are too voluminous to be adequately covered in this chapter, so only a few key points will be discussed. A major obstacle to making more transmission capacity available is the fact that under current practice, long-term requests for service from a new generator may be denied based on the unavailability of transmission in only a few hours of a year, even though firm service is nonetheless available for the large majority of hours of the year. To STOEL RIVES LLP 2008 Ch. 7 Pg. 5

57 address these concerns, FERC created two new options: conditional firm service and modified redispatch service. Conditional firm service addresses the all or nothing problem transmission customers currently face. Conditional firm is a type of transmission service that renewable advocates have promoted as a partial solution to the lack of available firm transmission. Under this service, a conditional firm customer may enter a long-term contract for the capacity that is available on a transmission path. The customer would have firm service except for time periods designated in the contract and would have priority over nonfirm service for the hours in which available transfer capacity ( ATC ) is not available on a firm basis. Modified redispatch service, which adjusts the output of various generators to allow transactions that would otherwise be blocked by congestion on certain transmission paths, is routinely used by integrated utilities (those with transmission and generation) to serve native load and network customers and to make off-system sales. Order No. 890 requires transmission providers to offer and study the use of redispatch service to create additional long-term firm capacity on a transmission system. Under the rule, customers would agree to pay the costs of redispatch service during the periods when firm ATC is not available. Order No. 890 will be an ongoing process. And new developments may have occurred by the time you read this chapter. You should consult knowledgeable attorneys to obtain an updated report on this and other FERC proceedings. Finally, Order No. 890 contains other amendments that may increase access to existing transmission capacity and/or promote transmission expansion in key areas. For example, Order No. 890: (1) establishes a methodology to determine ATC and to make certain elements of ATC more consistent; (2) requires transmission providers to participate in an open and transparent regional transmission planning process; (3) reforms pricing policies related to imbalances, credits for customer-owned transmission facilities, and capacity reassignment; (4) revises rules under which a transmission provider must provide rollover rights and require the provision of hourly firm pointto-point service; and (5) requires transmission providers to post all business rules, practices, and standards on the Open Access Same-Time Information System, and to include credit review procedures in their OATT. The details of Order No. 890 are too voluminous to be adequately covered in this chapter and, therefore, geothermal developers and generators should consult a knowledgeable attorney for an update on this and other FERC proceedings. III. Reliability Standards. Recent developments in federal law have transformed historically voluntary standards into mandatory reliability standards with accompanying obligations and potential sanctions for failure to comply. In compliance with federal law requiring it to do so, FERC issued Order No. 672 on February 3, 2006, qualifying the National Electric Reliability Corporation ( NERC ) as the continent-wide, FERC-certified Electric Reliability Organization ( ERO ) responsible for proposing and enforcing mandatory reliability standards. As the ERO, NERC is responsible for monitoring and improving the reliability and security of the bulk electric system and, to do so, NERC has the authority to propose and enforce mandatory reliability standards and assess fines upward of $1 million per day for noncompliance. Pursuant to the Federal Power Act, all reliability standards must be just, reasonable, not unduly discriminatory or preferential, and in the public interest. NERC has delegated to designated regional entities the authority to monitor and enforce the reliability standards. In addition to their delegated duties, regional entities may also enforce region-specific reliability standards. STOEL RIVES LLP 2008 Ch. 7 Pg. 6

58 The reliability standards may apply to users, owners, and operators of the bulk electric system, and the specific applicability of a particular standard is specified therein. The regional entities are tasked with maintaining a Compliance Registry, which lists organizations against whom the reliability standards are enforceable. If a bulk electric system user, owner, or operator fails to register with the Compliance Registry, then the regional entity may take steps to register that user, owner, or operator. The Compliance Registry lists organizations by function, and compliance is analyzed by reference to function-specific reliability standards. NERC requires that certain generator owners and operators register with the Compliance Registry. A generator owner is an organization that owns generating units, and a generator operator is an organization that operates generating units and supplies energy. There are minimum requirements before a generator owner or generator operator is required to register, and a geothermal developer should consult with a knowledgeable attorney regarding such requirements. Though initially exempted from registration, QFs are now required to comply with the reliability standards as well. In addition, geothermal developers should also be aware that NERC in some instances has upheld the registration of generators for transmission functions due to the generator s operation or control of long interconnection lines. Upon such registration, those generator owners are required to comply with transmission owner reliability standards, which may be very burdensome for some generator owners. Thus it is important that geothermal developers pay close attention to the quickly-evolving requirements imposed by reliability standards. Overall, the mandatory reliability standards pose a challenge to an industry that recognized voluntary standards for many years. Given the breadth of the reliability standards and the punitive sanctions attached, industry participants must take appropriate steps to determine whether they should register with the appropriate regional entity, to understand each function, and to implement a comprehensive program that will track and ensure compliance. IV. Summary. Recent developments have made access to the transmission grid both easier and more economical. In particular, the implementation of standardized interconnection procedures and agreements for Large Generators and Small Generators subject to Order Nos and 2006 will help streamline the interconnection of renewable power sources with the transmission grid. Similarly, FERC s proposals to strengthen the OATT by addressing ATC calculation and transmission planning and requiring greater transparency in business rules and practices are steps in the right direction. Nevertheless, much work remains in order for the existing transmission infrastructure to be fully utilized and to and promote new transmission in key regions needed for new geothermal generation to reach markets eager to purchase energy from this remarkable resource. STOEL RIVES LLP 2008 Ch. 7 Pg. 7

59 Jennie L. Bricker Experience Jennie Bricker practices natural resources law, with a focus on water law, waterways, and wetlands. Recognized as one of the state s experts on navigability for title, Jennie advises riparian property owners about their rights to submerged and submersible lands on Oregon waterways. She also assists clients in obtaining permits under Clean Water Act Section 404 and the Oregon Removal-Fill Law. Law clerk, The Honorable Otto R. Skopil, Jr., Ninth Circuit Court of Appeals ( ); legal systems administrator ( ), editor ( ), Dark Horse Comics, Inc.; assistant editor, Spectroscopy magazine ( ); lecturer in English, University of Maryland, European Division ( ); Graduate Teaching Fellow in women s studies, University of Oregon ( ). Professional Honors and Activities Burton Award for legal achievement (2001); Member, Oregon State Bar Association Environmental and Natural Resources Section; Member, Oregon Women Lawyers; Member, State Bars of Nevada and Washington; Rocky Mountain Mineral Law Foundation; Geothermal Resources Council; Oregon Association of Nurseries; Oregon Groundwater Association; Oregon Association of Water Utilities; Board Member, Oregon Lakes Association. Publications Oregon reporter for the Water Law Newsletter, a publication of the Rocky Mountain Mineral Law Foundation; Coauthor, Ocean and Tidal Energy Lease Agreements, The Law of Ocean and Tidal Energy (Stoel Rives 2007); Author, CWA Wetlands Jurisdiction, The Water Report (July 15, 2006); Coauthor, Fractured Court Fails to Clarify Scope of Wetlands Regulation, California Real Estate Journal (July 3, 2006); Author, Federal Wetlands Jurisdiction, Oregon Insider (July 1, 2006); Partner Direct Fax jlbricker@stoel.com Education Lewis & Clark Law School, J.D., 1997, magna cum laude Form and style editor, Environmental Law Cornelius Honor Society Environmental law certificate University of Oregon, M.A. English, 1988 University of Oregon Robert D. Clark Honors College, B.A., 1986, with honors, magna cum laude Phi Beta Kappa Women s studies certificate Admissions State bars of Nevada, Oregon, Washington

60 Jennie L. Bricker Coauthor, Running Interference: Groundwater and Related Features of State Regulation, Lava Law: Legal Issues in Geothermal Energy Development (Stoel Rives 2004); Coauthor, Environmental and Natural Resources Law, 2003 Oregon Legislative Highlights (Oregon CLE 2003); Author, Navigability and Public Use: Charting a Course Up the Sandy River, 38 Willamette Law Review 93 (2002); Coauthor, Water Rights and Transactions, Fundamentals of Real Estate Transactions 11 (2001); Coauthor, Endangered Species Act Enforcement and Western Water Law, 30 Environmental Law 735 (2000); Coauthor, Water Law: What Real Estate Lawyers Need to Know, Growth and Development Issues in Real Estate and Land Use 3-1 (1999); Author, Comment, Wheelchair Accessibility in Wilderness Areas: The Nexus Between the ADA and the Wilderness Act, 25 Environmental Law 1243 (1995).

61 Edward D. Einowski Experience Ed Einowski specializes in project finance and development, representing developers, investor-owned utilities and their unregulated subsidiaries, biofuel producers, investment banking firms, commercial banks and other financial institutions, and state and local governments. He has handled project financings throughout the United States, from West Virginia to California. He also regularly represents biofuels and electric industry clients in such matters as the negotiation of long-term power purchase agreements for the output of wind powered, gas-fired and coal-fired generation facilities, and the buying and selling of biofuel plants and electric generation projects. Representative Work Ed has handled a number of highly specialized project-related transactions, including tax-advantaged U.S. leveraged leases, cross-border leases, and publicprivate partnerships for the joint development and financing of major infrastructure projects. His project finance work covers a broad range of infrastructure projects, including ethanol plants electric generation facilities (gas fired CT projects, wind farms, hog fuel burners, landfill gas to electricity, solid waste to energy facilities) light rail and other mass transit facilities airports, docks and wharfs water and sewer utilities solid waste disposal facilities hospital and health care facilities housing projects higher education facilities museums and other cultural facilities manufacturing facilities, commercial office buildings and retail facilities ranging from regional shopping malls to automobile assembly plants Partner Direct Fax eeinowski@stoel.com Education University of Michigan Law School, J.D., 1978, cum laude University of Michigan Residential College, B.A., 1975, summa cum laude Admissions State bars of Michigan, Oregon Professional Honors and Activities Listed in Best Lawyers in America (2009); Former member ( ) of the State of Oregon Municipal Debt Advisory Commission (initially appointed by Governor Kitzhaber); Editor-in-Chief and Editor Emeritus of the Municipal Finance Journal; Member, National Association of Bond Lawyers; Member, American Bar Association;

62 Edward D. Einowski Steering Committee member of National Association of Bond Lawyers, ( ); Associate Member, Oregon Municipal Finance Officers Association. Publications Preventing Further Restrictions on Tax-Exempt Obligations, 8 Mun Fin J 3 (1987); Author, Private Purpose Tax-Exempt Financing in Oregon, Or Bus & Corp L Dig, February 1985; The Project Finance for Wind Power Projects Chapter in the Stoel Rives publication The Law of Wind; Response to the Treasury Tax Reform Proposal: The Need for Flexibility in Determining the Business of Government, 6 Mun Fin J 73 (1985); Tax Reform, Federalism, and State Sovereignty, 7 Mun Fin J 91 (1986);

63 John M. Eriksson Experience John Eriksson s practice at Stoel Rives LLP is focused on energy law, primarily in the electric utility industry. He has represented electric energy companies in a variety of transactions, including power purchase and sales agreements, natural gas purchase and storage, and coal purchase and transportation agreements. He has also represented regulated utilities in a wide range of regulatory proceedings before state utility commissions, and in litigation in state and federal courts. John now focuses his practice on representing independent energy clients, advising them regarding state regulatory issues and negotiating and drafting agreements related to renewable energy projects, including agreements for power sales and renewable energy credit sales. Attorney, Utah Power & Light/PacifiCorp ( ). Civic Activities Chair, Centerville City Board of Adjustments. Of Counsel - Associate Direct Fax jmeriksson@stoel.com Education University of Utah, J.D., 1986 William H. Leary Scholar, 1986 Weber State College, B.S., 1979, magna cum laude, Phi Kappa Phi Admissions State bar of Utah U.S. District Court of Utah, 1986 U.S. Court of Appeals, 9 th and 10 th Circuits

64 Jerry R. Fish Experience Jerry Fish concentrates his practice in natural resources law, with an emphasis on matters relating to oil and gas exploration and storage, hydroelectric project relicensing and compliance, and mining for gold, silver, copper, coal and industrial minerals. Taught geology and oceanography, Reynolds High School, Portland, Oregon, ; reconnaissance geological work, Bureau of Mineral Resources, Australia, Representative Work Four transactions to buy or sell major underground natural gas storage facilities in Alberta and Texas; Leasing, permitting and development of an underground natural gas storage facility in Oregon; Acquisition and disposition of oil and gas fields in Alberta, Oregon, Colorado, California, Texas, Louisiana and Mississippi, and negotiation of gas sales agreements and gas gathering agreements relating to those fields; Negotiation and drafting of multiparty relicensing agreements for major hydroelectric projects in each of Oregon, Washington and Idaho; Negotiation of numerous long term coal contracts from coal mines in Montana and Wyoming, and other states, many for delivery of more than one million tons of coal per year; Negotiation of joint ventures, exploration agreements, acquisitions and dispositions of major gold and silver mines, and settling royalty disputes with respect to those mines; Title opinions for oil and gas, gold and silver properties; Obtaining permits for various oil and gas and mining projects. Professional Honors and Activities Listed in Best Lawyers in America, for the past eleven years; Member, American Bar Association, Natural Resources Section; Member, Oregon State Bar Association; Member, Missouri Bar Association; Member, Northwest Mining Association, Northwest Petroleum Association; Member, Washington Bar Association; Member, Northwest Hydroelectric Association; Natural Hydropower Association. Partner Direct Fax Education Northwestern School of Law of Lewis and Clark College, J.D., 1982, magna cum laude, first in class Distinguished Environmental Law Graduate Award, 1982 Certificate in environmental and natural resources law Associate editor, Environmental Law, Bernard F. O Rourke Award for best student paper on a natural resource topic Cornelius Honor Society University of Chicago, MAT, 1974 A.B., geology, Princeton University, 1971 Admissions State bar sof Missouri, Oregon, Washington

65 Jerry R. Fish Publications Coauthor, Rights in Minerals and Gravel, 2 Real Property 40 (Oregon CLE Supp 1985); Author, Preservation and Strategic Mineral Development in Alaska: Congress Writes a New Equation, 12 Envtl L 137 (1981); Commonwealth Edison v. Montana: Leading the Severance Tax Stampede, 12 Envtl L 1031 (1982); Regulation of Hardrock and Other Mineral Activity on National Forest Land, Public Land Management: The Forest Service (U. Wash. CLE 1984); Local Government Restrictions and Controls on Rights-of-Way, Rights of Access and Surface Use, Paper No. 5 (Rocky Mt Min L Fdn 1984); Access Across Private Lands, American Law of Mining 100 (2d ed 1984); Oregon s New Dormant-Mineral Statute, 47 Oregon Geology 78 (1985); Recent Developments in State and Local Regulation of Mineral Development (NW Mining Assoc. Convention, Spokane, Wash., Dec. 1986); Oregon and Washington reporter, Mineral Law Newsletter, Rocky Mtn Min L Fdn. Legal Aspects of Underground Storage Operations in the State of Washington (NW Petroleum Assoc Annual Symposium, Bellingham, Wash.); J. Fish and R. Nelson, Jr., Building Your Own Underground Gas Storage Project: From Leasing to Open Season Under FERC Order No. 636, 39 Rocky Mt. Min. L. Inst. Ch 19 (1993).

66 Stephen C. Hall Experience Stephen Hall is a partner in the Portland office of Stoel Rives LLP, and is the chair of the Firm s Renewable Energy Initiative. He has acted as counsel to renewable energy developers (solar, geothermal, wind and biomass), independent power producers, major utilities, investment banks, power marketers, large industrial users of electricity, and developers of green buildings in a variety of business transactions, litigation and regulatory proceedings. His renewable energy practice includes drafting and negotiation of power purchase agreements ( PPAs ), including solar PPAs, and advising sellers and buyers of environmental attributes, including green tags, renewable energy certificates ( RECs ), verified emission reductions ( VERs ) and carbon offsets. Prior to Stoel Rives, Steve was Director, UBS Warburg Energy LLC, ( ); Senior Counsel, Enron North America Corp. ( ); associate, Stoel Rives LLP ( ); law clerk, Chief Justice James H. Brickley, Michigan Supreme Court ( ). Professional Honors and Activities Executive Committee, Oregon State Bar Telecom and Utility Section; Member, American Bar Association Public Utility Section; Member, Energy Bar Association; Member, Multnomah Bar Association. Presentations Speaker, energy industry conferences on legal issues related to sustainability, climate policy and greenhouse gas legislation, carbon cap and trade, and the development and financing of renewable energy resources. Partner Direct Fax schall@stoel.com Education University of Notre Dame Law School, J.D., 1996, cum laude Book Review Editor, University of Notre Dame Law Review, Western Michigan University, B.B.A. accounting, 1992, cum laude Admissions State bar of Oregon Civic Activities Volunteer, Multnomah County Legal Aid Clinic; ASPIRE Volunteer Advisor; Board of Directors of the Autism Society of Oregon.

67 Christopher M. Heaps Experience Christopher Heaps is a member of the firm s Resources, Development, and Environment group. His practice focuses on leasing, siting, and permitting energy and natural resource development projects. Chris practice includes drafting and negotiation of leases and other agreements for development of oil, gas, mineral, and geothermal resources, agreements for the purchase and sale of renewable energy certificates ( RECs, also known as green tags ) and carbon emission credits, and assisting clients with air quality, water quality, and other environmental compliance issues. Law Clerk, Washington State Attorney General s Office, Seattle, Washington ( ); Extern, Judge Robert H. Whaley, U.S. District Court, Eastern District of Washington, Spokane, Washington (2004); Summer Associate, Stoel Rives, LLP (2005). Representative Work Advised client regarding the scope of review of a major mining operation under the National Environmental Policy Act, the Endangered Species Act, the Clean Water Act, and applicable State law. Drafted and negotiated geothermal lease and option agreements for project developers and private landowners in Oregon and Washington. Professional Honors and Activities Counsel, Oregon Lawyers for a Sustainable Future Law-Sustainability Study Task Force ; Moot Court Appellate Advocacy Competition Speaker s Award, A Case Study of How Gender Shapes the Law School Experience. Submitted; Coauthor, Just Starting Out: Leasing, Siting, and Permitting Geothermal Energy Projects, Lava Law: Legal Issues in Geothermal Energy Development (Stoel Rives 2007); Two Laws for One Wrong? Statutory and Common Law Causes of Action for Appropriation of Likeness in Washington. Submitted. Associate Direct Fax cmheaps@stoel.com Education University of Washington School of Law, J.D., 2006 The University of Tennessee, Ph.D., 1999 The University of Tennessee, M.A., 1996 Mississippi State University, B.A., 1994, summa cum laude Admissions State bar of Oregon Civic Activities Member, Bicycle Transportation Alliance; Member, Portland City Club.

68 William H. Holmes Experience Bill Holmes concentrates his practice in the area of energy law, with a special emphasis on wind, geothermal, biomass, tidal and ocean power, and other forms of renewable energy. He also has extensive experience with real estate law, water law, and general corporate transactions. Bill is the Energy and Telecommunications (ENTEL) practice group leader at Stoel Rives. Bill joined Stoel Rives as an associate in 1985 and has been a member of the firm since Before joining the firm, he served as Law Clerk to Judge Louis F. Oberdorfer, United States District Court for the District of Columbia ( ). Representative Work Represented clients in the negotiation of numerous major power purchase agreements on both the buy and the sell sides. Experience with work on many major wind power purchase agreements, including the agreement under which IBERDROLA RENEWABLES, Inc. purchases the output of the 300-MW Stateline Wind Project in Oregon and Washington. Advised clients in the negotiation of acquisition agreements for energy assets and companies, EPC agreements, O&M agreements, management agreements, LLC agreements, energy project development agreements, fuel supply agreements, and related documentation. Represented renewable energy clients in negotiations with a range of counterparties, including Idaho Power, PacifiCorp, Pacific Gas & Electric (PG&E), Southern California Edison (SCE), San Diego Gas & Electric (SDG&E), Snohomish PUD (SnoPUD), Sacramento Municipal Utility District (SMUD), and Kansas City Power & Light. Professional Honors and Activities Listed in Best Lawyers in America in Energy Law and Environmental Law ( ); Member, Oregon State Bar Public Utility Law Section; Member, American Bar Association Energy and Natural Resources Section; Practice Group Leader, Stoel Rives LLP, Energy and Telecommunications Practice Group; Chair, Stoel Rives LLP Technology Committee. Partner Direct Fax whholmes@stoel.com Education University of Michigan Law School, J.D., 1984, magna cum laude Certificate in water law; certificate in environmental law Associate editor, Michigan Law Review, Editor in chief, Michigan Law Review, Henry M. Bates Memorial Scholarship Abram W. Sempliner Memorial Award University of Texas, B.A. Plan II honors program, 1981, with highest honors Order of the Coif Phi Beta Kappa Admissions State bar of Oregon Publications Coauthor, Power Purchase Agreements in Chapter 8 of The Law Of Ocean and Tidal Energy (Stoel Rives);

69 William H. Holmes Coauthor, Power Purchase Agreements and Environmental Attributes, in Chapter 4 of The Law of Wind (Stoel Rives); Coauthor, Power Purchase Agreements and Environmental Attributes, in Chapter 4 of Lava Law (Stoel Rives); Coauthor, Water Rights and Transactions, Fundamentals of Real Estate Transactions (2001 Cumulative Supplement); Author, Dams for Sale: The Ins and Outs of Federal Facility Transfers, 43 Rocky Mt Min L Inst 24-1 (1997); Coauthor, Bureau of Reclamation Contract Renewal and Administration: When is a Contract Not a Contract? 41 Rocky Mt Min L Inst 23-1 (1995); Coauthor, Employee Benefits and ERISA Considerations in Natural Resources Transactions, 34 Rocky Mt Min L Inst 5-1 (1989); Coauthor, Natural Resources, Energy and Environmental Law, 1987 Oregon Legislation 21 (Oregon CLE 1987); Coauthor, Reporting Violations of Hazardous Substances Law: Mandatory Self-Incrimination, Or Envtl & Nat Resources L News, at 4 (fall 1986). Civic Activities United Way Leadership Giver; President, Board of Directors, Portland Habitat for Humanity ( ); Member, Board of Directors of Portland Habitat for Humanity ( ); Pro bono counsel, Portland Habitat for Humanity ( , ).

70 Karen E. Jones Experience Karen Jones concentrates her practice in the areas of energy and real estate law, with a special emphasis on wind and renewable energy. She also has extensive experience in project finance and general corporate transactions. Karen has a broad range of experience in the representation of clients in the development, finance, acquisition and sale of renewable and conventional electric generation facilities and biofuels facilities, and on the development, construction, leasing, management, finance, acquisition and sale of commercial real estate. She has extensive experience in wind energy project leasing; commercial real estate leasing; long-term power transaction contracting and structuring (on both the buy and the sell sides); the acquisition and sale of energy and non-energy assets and companies; equipment procurement and construction agreements; project development agreements; and related documentation. Karen has been Of Counsel to Stoel Rives since Prior legal experience includes: Assistant general counsel, Enron North America, Portland, Oregon ( ); Of Counsel, Perkins Coie LLP, Portland, Oregon ( ); associate, O Donnell, Ramis, Crew & Corrigan, Portland, Oregon ( ); associate, Vinson & Elkins L.L.P., Houston, Texas ( ). Professional Honors and Activities Listed in Best Lawyers in America, energy law (2009); Vice Chair, Renewable Energy Resources Committee of the American Bar Association SEER Section ( ); American Wind Energy Association; Member, American Bar Association Section of Business Law, Section of Environment, Energy and Resources, and Section of Real Property, Probate and Trusts; Member, Oregon State Bar Public Utility Law and Real Estate & Land Use sections; Member, Legislative Committee of the Oregon State Bar Real Estate & Land Use section ( ). Of Counsel - Associate Direct Fax kejones@stoel.com Education The University of Houston College of Law, J.D., 1984, cum laude Associate editor, Houston Law Review Order of the Barons The University of Texas at Austin, B.A., 1980, magna cum laude, music Admissions State bars of Oregon, Texas, Washington Publications Wind Energy Land Agreements, in Chapter 1 of The Law of Wind (Stoel Rives); Title Insurance and Survey Matters, in Chapter 2 of The Law of Wind (Stoel Rives); Power Purchase Agreements and Environmental Attributes, in Chapter 4 of Lava Law (Stoel Rives); Coauthor, Purchase and Sale Agreement Form 2, Oregon State Bar Documentation of Real Estate Transactions (1996 Supplement).

71 John S. Kirkham Experience John Kirkham practices natural resources law. He has extensive experience in the representation of clients involved in all aspects of the coal industry. He has experience in mining, public land, water, geothermal and environmental law. John has represented clients involved in the development and utilization of oil and gas, precious metals, uranium, potash, limestone, phosphate, synthetic fuels, silica, tungsten, copper and gilsonite. His experience also includes the representation of utilities and pipeline companies. John has supervised client representation in connection with litigation, bankruptcy, employment, financing and general corporate law. John has extensive experience in the analysis of oil and gas title issues and the preparation of title opinions related to oil and gas development. He regularly appears before the Board of Oil, Gas and Mining of the State of Utah and has worked extensively with the Division of Oil, Gas and Mining. Appearances before the Board have involved royalty issues, spacing, unitization, exception locations and the permitting of horizontal drilling activities. Stockholder ( ) and Associate ( ), Van Cott, Bagley, Cornwall & McCarthy; Associate ( ), Senior & Senior. Professional Honors and Activities Recognized by Best Lawyers in America in the energy, mining, natural resources, and oil and gas law categories (2009); Named in Who s Who in American Law ; Named in the 2007 Mountain States Super Lawyers directory; Recognized in 2007 as The Lawyer of the Year by the Energy, Natural Resources, and Environmental Law section of the Utah State Bar; AV rating with Martindale Hubbell; Office Managing Partner, Stoel Rives LLP Salt Lake City Office ( ); Trustee, Rocky Mountain Mineral Law Foundation (Utah Mining Association representative ); Member, Utah State Bar (Energy, Natural Resources and Environmental Law section; Ethics Advisory Opinion Committee ); Member, Salt Lake County Bar; Member, American Bar Association (Section of Environment, Energy and Resources). Principal Direct Fax jskirkham@stoel.com Education University of Utah College of Law, J.D., 1971 University of Utah, B.A., 1968, cum laude, with honors Admissions State bar of Utah U.S. Court of Appeals, Tenth Circuit U.S. District Court of Utah U.S. Supreme Court

72 John S. Kirkham Publications Author, Legal Issues in Solution and In-Situ Mining, 52 Rocky Mt. Min. L. Inst (2006); Coauthor, The Energy Policy Act of 2005, Connect magazine (July 2006); Author, Force Majeure - Does it Really Work? 30 Rocky Mt. Min. L. Inst. 6-1 (1984). Civic Activities Board of Trustees, Metropolitan Water District of Salt Lake and Sandy (2003 to present); Board of Directors, Utah Mining Association (1987 to present); President (2006 to present), Executive Board (1987 to present), Executive Committee, Vice President-Legal ( ), Great Salt Lake Council, Boy Scouts of America; Bureau of Land Management, Utah Statewide Resource Advisory Council ( ); Member of the U.S. Minerals Management Service Coal Subcommittee of Royalty Policy Committee (1997 to present).

73 Robert T. Manicke Experience Robert Manicke is a member in the firm s Portland office. His practice emphasizes state and local tax matters, employment tax matters and federal income tax planning. He regularly represents clients in the Oregon Tax Court and before the Internal Revenue Service. His practice includes advance federal and state tax rulings and drafting and advising on state and local tax legislation. Associate, Tax and International Transactions Group, Pillsbury Madison & Sutro ( ). Professional Honors and Activities Selected by his peers for inclusion in The Best Lawyers in America, Tax Law ( ); Executive Committee, Oregon State Bar Tax Section, chair of legislative and DOR liaison subcommittees; Member, ABA Tax Section, including State Tax Committee, state tax nexus article group and Employment Tax Committee; Board Member, German American School of Portland; Board Member, Portland Symphonic Girlchoir; Former Board Member, Oregon Tax Research. Publications Coauthor, Tax Incentives, in The Law of Building Green: Business and Legal Issues of Sustainable Real Estate Development (Stoel Rives 2007); Coauthor, Tax Issues, in The Law of Ocean and Tidal Energy: A Guide to Business and Legal Issues (Stoel Rives 2007); Coauthor, Taxation, in 2007 Oregon Legislation Highlights, (Oregon State Bar 2007); Property Tax Exemptions in Oregon: Slips and Tips, 8 Oregon State Bar Taxation Section Newsletter 1 (Spring 2005); Coauthor, Tax Issues, in The Law of Wind: A Guide to Business and Legal Issues (Stoel Rives 2005); Coauthor, Tax Issues, in Lava Law: Legal Issues in Geothermal Energy Development (Stoel Rives 2005); Coauthor, Tax Issues, in The Law of Biofuels: A Guide to Business and Legal Issues (Stoel Rives 2005); Partner Direct Fax rtmanicke@stoel.com Education University of Illinois College of Law, J.D., 1992, summa cum laude Order of the Coif Board of Editors, University of Illinois Law Review Willamette University, B.A., 1984, cum laude Admissions State bars of California, Oregon, Washington Languages Dutch (reading ability), German

74 Robert T. Manicke Coauthor, Oregon Pollution Control Facility Tax Credits: 2001 Legislative Changes, Oregon Insider, Issue 279 (September 1, 2001); Using a German Hybrid Entity: New Proposed Check-the-Box Regulations Would Simplify Planning, Require Election, Oregon State Bar Int l Law Section Newsletter 1 (July 1996), reprinted in International Lawyers Newsletter 5 (September/October 1996); Coauthor, chapter on Oregon property tax, ABA Property Tax Deskbook, annually since 1996; Coauthor, survey of Oregon and Idaho tax developments, Council on State Taxation (for Oregon), semiannually since 1995.

75 Jennifer H. Martin Experience Jennifer Martin is a member in the Portland office of the Energy Group and Renewable Energy Initiative. Her practice focuses primarily on representing renewable energy developers on a variety of energy-related matters before state and federal agencies. She has experience before state public utility commissions in the Western United States and the Federal Energy Regulatory Commission representing both utility and independent power producer interests. Jennifer also advises developers on power purchase and interconnection agreements and transmission service issues. Judicial Clerk, Minnesota Supreme Court ( ); Senior Note and Comment Editor, Journal of Gender Race and Justice at University of Iowa College of Law ( ); summer law clerk, Stoel Rives (1998); research assistant, Professor David Baldus, University of Iowa College of Law ( ); clerk, Circuit Court of Cook County (1993). Representative Work Representation of energy clients including wind and solar developers in administrative litigation and rulemaking matters before the Federal Energy Regulatory Commission (FERC), including Section 205 applications and approvals for FERC-jurisdictional sales, QF and exempt wholesale generator issues, market rate authority, Section 203 transfer of jurisdictional assets; investigations into compliance, and other issues. Representation of renewable energy developers in drafting and negotiating power purchase and renewable energy credit (REC) agreements and in obtaining interconnection and transmission services. Representation of energy efficiency clients on state regulatory and renewable energy credit (REC) issues and drafting customer participation agreement. Partner Direct Fax jhmartin@stoel.com Education University of Iowa College of Law, J.D., 1999 University of Notre Dame, B.A. English and gender studies, 1995 St. Patrick s College, University of Notre Dame foreign study program, Admissions State bars of Oregon, Utah U.S. Court of Appeals for the Ninth Circuit U.S. Court of Appeals for the D.C. Circuit Professional Honors and Activities Member, Public Utility Law Section, Oregon State Bar; Member, Public Utility Law Section, American Bar Association; Member, Energy Bar Association; Member, Multnomah Bar Association; Member, Western Power Trading Forum; Member, Oregon Women Lawyers. Civic Activities Volunteer instructor, YMCA, Northern Ireland ( ).

76 Alan R. Merkle Experience Alan Merkle practices primarily in the areas of energy and infrastructure, construction and design, government contracts and utility matters. He represents owners, engineers, architects, contractors, manufacturers and suppliers in a wide array of business matters. He is experienced in the drafting, negotiation and administration of contracts, including equipment supply, EPC and O&M agreements. He also handles bid protests, claims, litigation, arbitration, mediation and other alternative dispute resolution matters for a broad range of clients. In addition to serving as an advocate, he regularly serves as a neutral on Dispute Review Boards and as a mediator and arbitrator. Before practicing law, Mr. Merkle managed the technical and business side of major construction, engineering, manufacturing and energy projects. Registered professional engineer in Washington, Oregon, and Idaho. Active in the power generation, construction, engineering and manufacturing industries for 12 years while managing various General Electric Company operations. Professional Honors and Activities Listed in Best Lawyers in America (2009); Repeatedly named one of Washington s Super Lawyers by Washington Law & Politics; Named one of Seattle s Top 100 Lawyers by Seattle Magazine; Honorary AIA and a biographee in Who s Who in American Law and Who s Who in the World; Past chair, Public Procurement and Private Construction Law Section, Washington State Bar Association; Past board member and Legal Affairs Committee chair, Associated General Contractors of Washington; Member, WSBA Litigation Section, Oregon State Bar Association Construction Law and Litigation Sections, American Bar Association Public Contract Law and Litigation Sections, Federal Energy Bar Association; Board member, Seattle chapter, American Institute of Architects; Graduate, American Arbitration Association mediator training program. Principal Direct Fax armerkle@stoel.com Education Northwestern School of Law of Lewis & Clark College, J.D. 1982, cum laude Certificate of Environmental and Natural Resources Law, 1982 Associate editor, Environmental Law University of Idaho, M.B.A., 1971 University of Idaho, B.S., 1969, mechanical engineering Boise State University, A.S., civil engineering, 1967 Admissions State bars of Oregon, Washington

77 Alan R. Merkle Presentations Frequent speaker and writer on subjects of turbine warranties, operating and maintenance agreements, and EPC agreements for wind and biofuels industry; Author and speaker, Public Contracting in Washington ; Chair, Public Works Symposium; Author and speaker, Advanced Construction Law, National Business Institute; Author and speaker, Washington Construction Law, Law Seminars International. Publications Author, Construction Liens chapter for WSBA; Author, Damages chapters and chair of WSBA program Architect and Engineer Liability; Author, Licensing and Registration chapter, Oregon State Bar publication, Construction Law. Civic Activities Former council member and Mayor, City of Mercer Island.

78 Mary Jo N. Miller Experience Mary Jo Miller is an associate in the Corporate, Securities, and Finance section of the firm s Business Services Group. Her practice focuses on finance, securities, mergers and acquisition, and general corporate matters, with a strong focus on renewable energy-related projects and companies. Mary Jo s clients include public and private companies, renewable energy developers, financial institutions, underwriters, utility companies, private equity companies and governmental and quasi-governmental entities. She has handled a broad range of transactions, including asset and stock sales, project finance, syndicated and bilateral loan facilities, public bond financing and public offerings and private placements of debt and equity securities. Associate, Shearman & Sterling, London, England ( ); associate, Baker & McKenzie, Chicago, Illinois ( ). Representative Work Represented the borrower in connection with a public bond financing of a landfill gas electric-generation project; Represented the developer/seller in connection with the phased development and sale of four windfarms with aggregate installed capacity of 230-MWs; Represented the seller of a 125-MW gas-fired power plant; Represented the investors in connection with the phased development of a 120-MW geothermal electric-generation project; Represented a leading grower and supplier of specialty garden products in the sale of its plant business, structured as the sale of both assets and membership interests in special-purpose subsidiaries; Represented a manufacturer in the acquisition of the distressed assets of a competitor; Represented a timber company in connection with the restructuring of its syndicated secured credit facilities; Represented the underwriters in various securitized and high-yield note issues pursuant to exemptions from registration under Rule 144A and Regulation S; Represented the issuer in the first Internet IPO in the United Kingdom, listed on the London Stock Exchange and Nasdaq; Advised domestic and foreign private issuers with respect to compliance with the Securities Exchange Act of Associate Direct Fax mnmiller@stoel.com Education University of Notre Dame Law School, J.D., 1995, cum laude Executive Editor, Journal of College and University Law University of South Carolina, M.I.B., 1982 John Carroll University, B.S., 1980, magna cum laude ABA Stonier Graduate School of Banking, 1992, with honors Admissions State bars of Illinois, Oregon Languages Fluent in Spanish Basic skills in French, Italian, Portuguese

79 Mary Jo N. Miller Professional Honors and Activities Fourth Place, 1995 National ASCAP Nathan Burkan Memorial Legal Writing Competition Til Death Do We Part: The Moral Rights of Visual Artists in Their Work After Carter v. Helmsley-Spear. Publications Reading, Riting and Response: olding Colleges and Universities Liable Under CERCLA, 20 Journal of College and University Law 483 (1994); Coauthor, Regulatory Issues Affecting U.S. Financial Institutions Involved in Asset Securitisation, 8 International Securitisation Reporter 5 (1994). Civic Activities Member of the Board of Trustees, Childpeace Montessori School.

80 Karl F. Oles Experience Karl Oles is a principal in the Construction and Design section of the Litigation practice group. He has represented owners, architects, engineers, contractors and subcontractors in complex construction litigation and has experience in other complex business disputes. He has experience in trial, arbitration and mediation. Karl has also drafted and negotiated multi-million dollar design and construction contracts on a wide variety of projects, including alternative energy projects. Danielson Harrigan Leyh & Tollefson ( ); Law Clerk to the Honorable Robert R. Beezer, Ninth Circuit Court of Appeals ( ); Extern to the Honorable Eugene A. Wright, Ninth Circuit Court of Appeals (1986). Professional Honors and Activities Included in Super Lawyers, Washington Law & Politics ( ); Member, steering committee for Division 12 (Owners and Lenders), American Bar Association Forum on the Construction Industry; Member, arbitrator, American Arbitration Association Construction Panel; Past chair, Construction Section, Washington State Bar Association. Presentations Who s Steering the Ship? Construction Administration by Design Professionals and Agency Construction Managers, American Bar Association Forum on the Construction Industry Fall Meeting (Newport, RI, 2007); Construction Contract Formation and Drafting, Lorman Education Services, Comprehensive Construction Law in Washington (Seattle, WA, 2006); Delay Claim Damages Measurement, seminar, Contract Solutions Group (Seattle, WA, 2006); Beating Difficult Contract Clauses, seminar, Washington State Bar Construction Section (Seattle, WA, 2005); Avoiding Claims: Case Studies and Lessons Learned on Recent Public Projects, seminar, Washington State Bar Construction Section (Seattle, WA, 2003); Working with the Construction Expert, seminar, Washington State Bar Construction Section (Seattle, WA, 2002); Parties and Claim Theories in Construction Cases, seminar, Washington State Bar Construction Section (Seattle, WA, 2002). Principal Direct Fax kfoles@stoel.com Education University of Washington School of Law, J.D., 1986 University of California at Los Angeles, M.A., 1982 University of London, M.A., 1978 Pomona College, B.A., 1977, magnum cum laude Admissions State bar of Washington U.S. District Court for the Eastern and Western Districts of Washington Ninth Circuit Court of Appeals

81 Karl F. Oles Publications Coauthor, Design, Engineering, Construction and Turbine Purchase Agreements, The Law of Wind: A Guide to Business and Legal Issues (Stoel Rives, 2008); Coauthor, Solar Energy System Design, Engineering, Construction and Installation Agreements, Lex Helius The Law of Solar Energy: A Guide to Business and Legal Issues (Stoel Rives, 2008); Author, Ease into 08 with a Crash Course in Subpoenas, The Daily Journal of Commerce (Oregon, 2008); Coauthor, Setting Up Shop: Design, Engineering and Construction for Biofuels Plants, The Law of Biofuels: A Guide to Business and Legal Issues (Stoel Rives, 2007); Author, Contractors Eyeing Washington Must Heed State Statutes, The Daily Journal of Commerce (Oregon, 2007); Coauthor, Setting Up Shop: Design, Engineering, Construction and Turbine Purchase Agreements, Lava Law: Legal Issues in Geothermal Energy Development (Stoel Rives, 2007). Civic Activities Member, board of trustees, Episcopal Retirement Communities.

82 Kevin T. Pearson Experience Kevin is a member of the Tax Section of the firm s Business Services Group. His practice focuses principally on federal income tax law, including both transactional matters and tax controversy matters. As part of his transactional practice, Kevin regularly advises clients regarding all aspects of corporate taxation, including taxable and tax-free mergers and acquisitions, debt and equity offerings and other corporate finance transactions, consolidated return issues, and general corporate tax issues. He also regularly represents clients with respect to partnership, S corporation and limited liability company transactions and tax issues, as well as choice-of-entity issues, tax accounting issues, and general tax planning issues. In addition, Kevin frequently represents clients in renewable energy financing transactions, particularly those involving the federal production tax credit. As part of his tax controversy practice, Kevin regularly represents taxpayers in IRS audits and administrative appeals, deficiency litigation in the U.S. Tax Court, and refund litigation in U.S. District Courts and the U.S. Court of Federal Claims. Attorney-Adviser to Judge Laurence J. Whalen of the U.S. Tax Court ( ); legal intern, Office of the U.S. Attorney for the Eastern District of Washington ( ). Professional Honors and Activities Member, Tax Section, American Bar Association; Member, Tax and Business Law Sections, Washington State Bar Association; Member, Tax Section, Oregon State Bar; Member, Portland Tax Litigation Club, Multnomah Bar Association; Former board member, Linfield College Alumni Association. Presentations Speaker, New Proposed Anti-Morris Trust Regulations Under IRC 355(e), Portland Tax Forum (May 2001); Partner Direct Fax ktpearson@stoel.com Education Georgetown University Law Center, LL.M. Taxation, 1998 Gonzaga University School of Law, J.D., 1996, summa cum laude Articles Editor - Gonzaga Law Review, National Moot Court Linfield College, B.S., 1992 Admissions State bars of Oregon, Washington U.S. Court of Federal Claims U.S. Tax Court Speaker, various continuing legal education and other seminars regarding a wide variety of tax issues, including tax considerations in choosing a form of business entity, tax aspects of corporate reorganizations and other corporate transactions, tax considerations in partnership, S corporation and real estate transactions, tax planning for equity compensation, and ethical rules governing tax practitioners.

83 Kevin T. Pearson Publications Coauthor, Investing in Renewable Energy: Investment by Non-Utilities in Electric Generation Can Have Far-Reaching Tax Benefits, in The Energy and Utilities Project: Innovation for the Future (vol ); Coauthor, Tax Issues in The Law of Wind (Stoel Rives, 2005); Coauthor, Tax Issues, in Lava Law: Legal Issues in Geothermal Energy Development (Stoel Rives 2004); Coauthor, The 2003 Confidential Transaction Tax Shelter Regulations: Another Chapter in the Disclosure and List Maintenance Regulations Saga, in Corporate Taxation, (May/June 2004); Coauthor, Tax Issues, in The Law of Wind: A Guide to Business and Legal Issues (Stoel Rives 2003); Coauthor, The Sarbanes-Oxley Act of 2002: Important Tax-Related Issues, presented to the Tax Executives Institute (October 2002); Author, What Every Business Lawyer Needs to Know About Tax, presented to the Oregon State Bar Young Lawyers Division (October 2002); Coauthor, Corporate Reorganizations: Basic Concepts, Emerging Issues, and Unique Reorganizations, Oregon State Bar Tax Institute, (June 2000); Coauthor, Equity Compensation: Basic Concepts and Emerging Issues, presented to the Tax Executives Institute (April 1999).

84 Marcus A. Wood Experience Marcus Wood concentrates his practice in the representation of energy providers and energy facility developers. He has extensive experience in representing independent power company owners of both conventional and renewable energy projects, as well as regulated electric, natural gas and water utilities. He practices before the Federal Energy Regulatory Commission and before utility regulatory bodies in the states of Oregon, Washington, California, Idaho and Wyoming. Marcus has represented numerous parties in the acquisition and financing of interests in and in the disposition of the output from cogeneration and other conventional electric generation facilities, as well from wind-powered and geothermal energy resources. He has extensively advised and negotiated on behalf of clients with respect to the structuring of energy projects and with respect to the operating contracts, power sales contracts and transmission contracts required for such projects. He also has extensive experience advising sellers, purchasers and exchangers of electric capacity and energy, as well as advising both transmission service providers and purchasers of electric transmission and related services. He has been a leader in efforts for the creation of Regional Transmission Organizations. He has represented clients both in rate proceedings and in investigations before the Federal Energy Regulatory Commission. Professional Honors and Activities Selected by his peers for inclusion in the Public Utility Law section of The Best Lawyers in America. Partner Direct Fax mwood@stoel.com Education Yale University Law School, J.D., 1974 Vanderbilt University, B.A., 1969, cum laude Phi Beta Kappa Admissions State bar of Oregon U.S. District Court U.S. Court of Appeals for the Ninth Circuit U.S. Court of Appeals for the District of Columbia Circuit Civic Activities Former vice-chairman, Tigard Planning Commission; Former member, board of directors, Portland Youth Advocates; Former director and board president, Indochinese Cultural and Service Center; Former director and board president, Pacific Ballet Theatre; Former director, Outside In.

85 Stoel Rives Supports Renewable Energy Stoel Rives purchases Renewable Energy Credits known as RECs or green tags to offset 60 percent of its firmwide electricity usage. The carbon emissions that are avoided through this green power purchase is roughly equivalent to parking a car for 4,968 months or approximately 414 years, or not driving 5.2 million miles. We purchase our RECs from firm clients 3Degrees and Bonneville Environmental Foundation. With our green power purchase commitment, we are one of the first law firms nationwide to qualify as a member of the U.S. EPA Green Power Partnership s Leadership Club and the ABA-EPA Law Office Climate Challenge programs.