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Lava LawLegal Issues in Geothermal Energy Development

C o m p l i m e n t s o f

S i x t h E d i t i o n w w w . s t o e l . c o m

Attorney team members are admitted to practice in the following jurisdictions:

Geothermal Energy Team

Jennie L. BrickerJerry R. FishTimothy L. McMahanAlan R. MerkleKarl F. Oles

WASHINGTON

Gary R. BarnumJennie L. BrickerHeath CurtissEdward D. Einowski Jerry R. Fish Stephen C. HallWilliam H. HolmesKaren E. JonesJennifer H. MartinTimothy L. McMahanMary Jo N. MillerKevin T. PearsonMarcus Wood

OREGON

CALIFORNIARandall M. FaccintoJohn A. McKinsey Howard E. Susman

IDAHOKevin J. BeatonKrista K. McIntyre

Jennie L. BrickerRandall M. Faccinto

NEVADA

Martin K. BanksClint M. HanniJohn S. Kirkham

UTAH


Ta b l e o f C o n t e n t s

Lava Law, Sixth 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 2009 Stoel Rives LLP.

1. JuSt StartInG Out: Leasing, Siting, and Permitting

Geothermal Energy Projects Jerry R. Fish

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

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

Gary R. Barnum Edward D. Einowski Mary Jo N. Miller

6. GEttInG SOmE crEDIt: Tax Issues

Charles S. Lewis, III Adam C. Kobos 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

STO EL RIVES LLP © 2009 Intro duc tio n – Pg . 1

W ELCOME TO

THE LAW O F LA VA

Dear Member of the Geothermal Energy Community,

As a reliable renewable energy source, geothermal can help power our homes and businesses and buttress localeconomies while leaving cleaner skies for our children. Major global corporations, new sources of investmentcapital, and power buyers large and small have been drawn to geothermal power. The Energy Policy Act of 2005and the American Recovery and Reinvestment Act (also known as the Stimulus Bill) provided long-awaitedfederal support. At the same time, more and more states are crafting legislation to support renewable energy anda cleaner environment, including renewable portfolio standards, tax incentives and carbon regulations. Theindustry outlook for geothermal energy is strong.

Nonetheless, geothermal energy projects, like other major energy projects, face a host 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 energyindustry, in 2004 the Stoel Rives Geothermal Team published the first edition of LAVA LAW: Legal Issues inGeothermal Energy Development. This guide contains insights we have gained during the nearly two decades ofserving the U.S. geothermal industry.

You have in your hands the Sixth Edition of LAVA LAW, revised in 2009 to reflect the current state of play onthe legal and policy issues most likely to affect the geothermal industry generally and the development ofindividual geothermal projects. We update this publication annually, so please let us know if you have commentsor suggestions for future editions. In the meantime, we will comment on important developments affecting thegeothermal industry in our Energy Law Alerts (www.stoel.com/subscribe) and in our Renewable + Law Blog(www.lawofrenewableenergy.com).

STOEL RIVES LLP © 2009 Ch. 1 – Pg. 1

Chapter One THE LAW OF LAVA

Just Starting Out: Leasing, Siting, and Permitting Geothermal Projects

Jerry R. Fish

Geothermal energy is often praised for producing sustainable, base load power with minimal environmental impacts. Despite this, geothermal projects have rarely received preferential leasing and permitting treatment. With the enactment of the Energy Policy Act of 2005, adoption of the Bureau of Land Management’s (“BLM”) Geothermal Strategic Plan, completion of the Geothermal Leasing Programmatic Environmental Impact Statement (“PEIS”), and the opening of four Renewable Energy Coordinating Offices throughout the West, the winds of change may be beginning to blow in a more favorable direction.

The Energy Policy Act directed the Secretaries of Interior and Agriculture to reduce the backlog of pending geothermal lease applications, prioritize timely completion of administrative actions relating to geothermal development, and consider geothermal leasing and development in future forest and resource management plans for areas with high geothermal resource potential. Likewise, the BLM Geothermal Strategic Plan aims to improve the agency’s effectiveness and efficiency in processing lease and permit applications.

The Geothermal Leasing PEIS, completed at the end of 2008, provided the environmental analysis necessary for BLM to issue decisions on numerous pending lease applications and analyzed environmental impacts associated with geothermal leasing on 530 million acres of land administered by BLM and the U.S. Forest Service in 12 Western states. The PEIS also produced a comprehensive list of stipulations, best management practices, and procedures to guide future BLM decisions on geothermal leasing and development. Analysis in the PEIS will be tiered with analysis of site-specific environmental impacts necessary for development on individual leases. BLM hopes to expedite these decisions and analyses with the opening of its Renewable Energy Coordinating Offices, announced in May 2009.

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 (except some direct use leases) are offered on a competitive basis. 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 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 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. Lands Administered by Other Agencies. 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 lease of Forest Service lands without the consent and incorporated conditions of the U.S. Forest Service Chief. Because the Geothermal Leasing PEIS did not provide the environmental analysis necessary to amend forest management plans, these plans are being amended by the Forest Service individually for each forest. Additional environmental analysis may be required before the BLM can issue a lease on Forest Service lands. In addition, lands located 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.

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 by-products 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. Water use is a critical aspect of geothermal development and is discussed in greater detail in Chapter 2.

H. Federal Environmental Review. Under the National Environmental Policy Act (“NEPA”), the BLM is required to review the environmental consequences of granting leases and permits necessary for geothermal development. The BLM issues either an Environmental Assessment (“EA”) 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.


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 under NEPA, and the BLM will usually issue an EA with, if applicable, a Finding of No Significant Impact on the environment. The granting of a surface-occupancy lease, however, often 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.

Further developments beyond surface leasing (i.e., issuance of exploration, drilling, utilization, and commercial use permits) 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.

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. Nevertheless, leasing of private lands has increased in recent years and such leases offer both developers and landowners a chance to vary many of the terms that are set under federal leases.

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


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 38.85 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


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


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.


Chapter Two THE LAW OF LAVA

Running Interference: ⎯Groundwater and Related Features of State Regulation⎯

Jennie L. Bricker and 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 632-020-0095.

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


also found and hereby declared to be closely related to and possibly affecting and affected by water and mineral resources in many instances.” IC 42 4002.

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 38.85 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 690-230-0020(5); OAR 632-020-0010(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.


Oregon’s dual agency system may have the advantage of keeping both players—minerals and groundwater—in the game. ORS 522.255 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 high-temperature 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 42-4005.

In states with bifurcated classification systems, line-drawing problems seem inevitable. Oregon divides high- from 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


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


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 © 2009 Ch. 3– Pg. 1

Chapter Three LAVA LAW

—Signing Up: Power Purchase Agreements and Environmental Attributes—

William H. Holmes, Karen E. Jones, Jennifer H. Martin

I. The Parties.

A. The Seller. The seller is often the developer and owner of a geothermal power plant that will generate energy and environmental attributes (“output”). But the seller may also be a power marketer that is buying the output of a plant and selling it to one or more buyers. If a company is reselling output, the resale power purchase agreement (the “PPA”) will usually track the relevant terms of the underlying PPA, because the marketer will not want to promise more than it has the right to deliver. As a result, the marketer will often use a “back-to-back” PPA for the resale. The resulting terms 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 pass through to the ultimate buyer.

B. The Buyer. The buyer is often 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 policy that encourages the development of geothermal power and other forms of renewable energy. The significance of this driver is growing, as 29 states and the District of Columbia now have renewable portfolio standards, and a national renewable energy standard in some form is likely to be enacted in the near future. In a state that permits direct access or allows renewable energy to be sold at retail, the buyer may be a retail buyer, such as a manufacturing facility that wishes to hold itself out as a “green” company. Power marketers may also buy output for resale to one or more third parties. Power marketers sometimes can purchase all of a project’s output (something that no other single-market player may be able to do), taking a “merchant position” and enabling the owner to finance the plant.

C. 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 creditworthy, the other may require it to provide a guaranty, or post a letter of credit or other security to ensure that amounts due under the PPA will be paid.

D. The Lender. Frequently the project will be financed. 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.

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 will 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 build the project (subject to negotiated conditions) and not 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 often 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 was 25 years and commercial operation began on November 1, 2010, the term would end on January 1, 2036. In other PPAs, the term begins on the commercial operation date and extends for a specified number of years from that date. In general, geothermal facilities require a 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.

The commercial operation date often starts the PPA’s term, determines whether the project has avoided liquidated damages by achieving its “guaranteed commercial operation date,” and establishes the point at which the price switches from a “test energy rate” to a “contract rate,” or the point from which any capacity payments are made. It is therefore important to define “commercial operation date” carefully. Generally, “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 and 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. The parties often negotiate more specific standards for judging whether commercial operation has been achieved and occasionally require that an independent engineer be engaged to make findings that support the achievement of commercial operation.

E. Termination Before the Commercial Operation Date. PPAs usually 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 the (1) failure of a public utility commission to approve a PPA or allow its costs to be passed through to ratepayers; (2) inability to obtain an interconnection agreement or needed transmission rights; (3) inability to obtain leases, rights-of-way, or other land rights required to build the project; (4) inability to obtain permits required to build or operate the project; (5) inability to obtain an authorization to sell power at market-based rates; (6) project’s failure to reach a certain minimum size by a certain date;


(7) project’s failure to achieve commercial operation by a certain date; and (8) failure to qualify for the production tax credit (the “PTC”) (although this is less of a concern now since the PTC has been extended through December 31, 2013), the investment tax credit (“ITC”) or for the grants in lieu of ITC (“Grants in Lieu of ITC”) now available for certain eligible projects that (i) start construction by the end of 2010; and (ii) are “placed in service” on or before December 31, 2013. Geothermal projects usually have a fairly high capacity factor (unlike wind or solar projects), so they are much more likely to use the PTC rather than the ITC or a Grant in Lieu of ITC.

Termination rights require careful negotiation to make sure that all possibilities have been considered. 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 (e.g., the seller cannot assert the inability to obtain a permit as a basis for terminating the PPA unless the seller has used diligent efforts to obtain the permit). In cases where the buyer can invoke a termination right after the seller has exhausted its right to pay delay damages, careful attention should be paid to limiting the developer’s liability and the buyer’s remedy to the delay damages already paid to the buyer or to some other clearly defined payment.

III. Purchase and Sale.

A. Delivery Point. The PPA will require the sale of energy 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’s substation. In a busbar transaction, the buyer provides the transmission required to transmit the energy from the plant 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 provide necessary and adequate transmission to take the energy away from the project’s busbar or otherwise assign to the seller the curtailment risk associated with inadequate transmission away from the project. Alternatively, 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 to the delivery point, and the buyer will be responsible for obtaining the transmission required to take the energy at that delivery point. The risk of curtailment of the transmission service to and after the delivery point is a risk that should be carefully allocated in the PPA. Transmission ancillary services can be fairly costly and should be specifically allocated in the PPA. Title and risk of loss pass from seller to buyer at the delivery point.

B. Pricing.

1. Contract Rate. Price is usually the most 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 is achieved, thus encouraging the seller to lock in the initial price and the escalation rate by achieving commercial operation as soon as possible. The rate may also be differentiated depending upon the time of day or season of delivery of the energy.

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. However, since geothermal plants are usually run as much as possible to take full advantage of the PTC and the availability of the resource, geothermal PPAs are much more likely to be structured as sales of energy than as sales of capacity.

4. Excess Rate. A PPA often requires the seller to specify how many MWhs the plant is expected to produce each year. This output estimate may form the basis of an output guarantee or a mechanical-availability guarantee. To encourage the seller to make an accurate estimate of expected output, the seller may be paid less than the contract rate for each MWh of energy in excess of, for example, 110 percent of the estimated annual output.

C. Environmental Attributes. Environmental attributes are the credits, benefits, emissions reductions, environmental air-quality credits and 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 during the term of the PPA, 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 make it clear that the PTCs, any ITCs vs. Grants in Lieu of ITCs, renewable energy incentives (such as those that may be provided under a state program), and any other environmental attributes necessary to generate the quantity of power being sold to the buyer are not part of the environmental attributes and thus are not being conveyed to the buyer.

The PPA should clearly state whether energy generated by the plant is being sold with or without the environmental attributes. Failure to do so can (and has) led to disputes about whether the generator or the offtaker is entitled to the ownership and use of the environmental attributes. If environmental attributes are being sold, the seller will usually warrant title to the attribute, but will not warrant the current or future use or value of the attributes or whether and to what extent they will be recognized by law. In effect, the purchaser assumes the risk that the law or the market might change in a way that reduces the value of the environmental attributes.

The PPA should specify the delivery method of the environmental attributes. In the past this was done through a monthly or quarterly attestation and bill of sale delivered by the seller to the buyer. Today, most buyers will insist on the transfer of environmental attributes through a regional renewable energy registry and certificate tracking system, such as the Western Renewable Energy Generation Information System (WREGIS) or the Midwest Renewable Energy Tracking System (M-RETS), to ensure compliance with state renewable portfolio standards. These regional tracking systems generally involve both the verification of the number of environmental attributes created by a particular project in a particular calendar month and the transfer of such environmental attributes from one account holder to another.

D. Allocation of Taxes and Other Charges. The PPA should specify who 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.


IV. Permitting and Development.

A. Commitment to Develop. The PPA 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 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 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, the PPA usually requires 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 (e.g., the date by which the seller must secure project financing, the date by which major equipment for the project 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 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. Buyers are concerned that this gives the seller a right that resembles a put and strongly prefer to require the seller to suffer some consequences if project milestones are missed. In addition, Sellers often insist that there be no remedy for failure to meet interim milestones leading up to the commercial operation date, because unless and until the commercial operation date is actually missed, the Buyer suffers no damages. Many interesting negotiations revolve around the off-ramps 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.

V. Interconnection and Transmission. The PPA usually requires the seller to bear the cost of interconnection (including any network upgrades required by the new project) and all costs of transmitting the energy to the 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. (For more information on interconnection and transmission-related issues, see Chapter 7.)

VI. Performance Incentives. A seller will usually prefer to enter into an “as-delivered” PPA, which means that the seller is obligated to deliver only what the project actually produces. A buyer will often 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 and environmental


attributes in the market to the extent that the project fails to perform as expected. Performance guarantees enable the buyer to plan around the plant’s expected output for both load and, if applicable, renewable portfolio standard compliance, and strongly encourage the seller to maintain a reliable and productive project.

A. 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, after taking into account output lost because of force majeure, maintenance, or other agreed-on subtractors. The period may be annual, biannual, 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 comprising the project will be crucial in determining appropriate levels of output guarantees and should factor in, at least, any expected normal degradation over the term of the PPA.

B. 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 by means of a partial refund of any 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.

C. 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 output 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 guarantees. 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 currently 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 or may use a firm price index as a proxy for the value of the energy plus the environmental attributes. The amount of liquidated damages is usually determined 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. The seller may in addition seek to include the right to cure any output shortfall through delivery of replacement energy and environmental attributes at its option where seller and buyer can mutually agree on the time and place for such replacement deliveries. In any case, the seller will likely seek to cap liquidated damages or its replacement obligation on an annual or aggregate basis or both.

D. Termination Rights. To protect against chronic problems at an unreliable plant, the PPA may allow the buyer to terminate the PPA if the output or availability of the project is below a stated minimum for a certain number of years.

VII. 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. Facility curtailments caused by transmission congestion or conditions beyond the


point of delivery are often handled in the same manner, although the topic of curtailment is frequently a difficult issue in PPA negotiations.

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 may be excused. For example, if a disaster disables the transformer at the delivery point, the seller would be excused from delivering energy, and the buyer would 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 the definition of what events comprise “force majeure” 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 from its duty to perform) and those that are “risks” (which are simply allocated to a party). The ability to buy energy, capacity, or environmental attributes at a lower price, or sell them at a higher price, is generally not 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 a number of items that both parties agree are force majeure events, as well as list items that the parties agree are not force majeure events.

VIII. 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 mechanical availability guarantee, the PPA will often provide that the liquidated damages due for a failure to achieve guaranteed output or mechanical availability is the buyer’s sole remedy for an underperformance by the project.

B. Metering. The metering provision is used to determine the quantity of output 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 typically has the right to install a check meter. If the seller’s meter is out of service or generating inaccurate readings, the PPA should specify 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 and 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.


IX. Billing and Payment.

A. Billing and Payment. The PPA will describe how invoices are prepared, when they are issued, and how quickly they must be paid. The billing provision often states that an invoice is final if not challenged within a certain period of time (usually one or two years). The PPA usually sets forth procedures for raising and resolving billing disputes, and the interest rate and penalties that apply to late payments.

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 any party to pay an amount when due;

• other types of specified material defaults;

• the bankruptcy, reorganization, liquidation, or other similar proceeding of any party; or

• failure to provide or replace credit support within an agreed-on time.

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 PPA and pursue its remedies at law or in equity, or to suspend performance of its obligations. The remedies clause may also limit remedies or place a cap on a party’s damages. 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. The 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.

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 the project or entity’s fair market value at the time of exercise has been generally disfavored by tax attorneys. Other 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 2007-65 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, governing law, the limitation of consequential damages, dispute resolution, consent to jurisdiction, and waiver of jury trials. Because the transaction between the parties may involve complex calculations, the PPA should also include a number of carefully considered examples that illustrate how those calculations will work in certain scenarios.

X. Uniform Commercial Code. In some states, electricity is considered to be a “good” for purposes of the Uniform Commercial Code (“UCC”). In those states, the UCC would impose an implied warranty of merchantability and fitness for a particular purpose on the sale of electricity (and possibly on the sale of the associated environmental attributes) unless those warranties are conspicuously disclaimed in accordance with UCC § 2-316. In a state that applies the UCC to PPAs, a party with reasonable grounds for insecurity about the performance of the other party may require the posting of adequate assurances of performance under UCC § 2-609. This “reasonable assurances” standard may apply in cases where a PPA does not expressly disclaim the applicability of the UCC’s adequate assurances provisions, even if the PPA does not expressly apply a credit support standard to the buyer. In states that treat electricity as a good, the parties will want to give careful consideration to the effect of the UCC on the PPA.


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 enhance value for all parties.

I. Construction-Related Agreements. Critical to the development of any geothermal energy project are the various agreements a project developer must enter into for:

• 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 services necessary to install the power generation equipment and the balance of plant facilities; and

• operation and maintenance of the completed facility.

Frequently engineering, procurement, and construction tasks are combined in a single agreement called an “EPC agreement.” Separate agreements may provide for or anticipate other services such as warranty services or operations and maintenance services for the power generation equipment and related facilities.

Sometimes all phases of the design and engineering, procurement, and construction/installation services are addressed in a single agreement (a “full-wrap” or “turnkey” agreement) and a single entity is made responsible for the whole project. It is also common to have separate agreements such as design and engineering agreements, construction/installation agreements (“balance-of-plant agreements”), and procurement and sale agreements for major pieces of equipment, 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 construct related project facilities such as cooling and well systems. With the growth and maturation of the


industry world-wide, new vendors may be expected to enter the market, leading to increased standardization in design features.

Project design expertise requires understanding the complexities of the geothermal resource that the project will utilize, including temperatures, volumes, and constituents of extracted and injected steam and liquids and the associated wastes (toxic and otherwise). 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. Balance-of-Plant Design, Engineering and Construction Services. Developers of geothermal projects generally acquire power generation equipment from specialized vendors. This leaves substantial design and engineering work to be performed, including geotechnical studies, engineering of extraction and injection wells, equipment pads and foundations, road design and other earthworks, environmental mitigation, and power collection systems, substations and interconnection points, and (if applicable) facilities for supplying hot water for domestic use. This design and related procurement and construction balance-of-plant work could be performed by the supplier of the power generation equipment, but is more typically provided by a third party contracting directly with the project developer.

IV. Typical Contractual Structures for Geothermal Projects. 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 normally 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. In this scenario, 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 key terms, including 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 condensers, 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 design and construction, earthworks, and related work. As with other aspects of such an agreement, the scope-of-work 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 will 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 and optimize 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 relevant agreements 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 require 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.

D. Limitation of Liability. The turbine supplier and other contractors may seek to limit their liability to a project developer. A common request is for a waiver of consequential, indirect, incidental, and special damages. Such clauses should be negotiated carefully because what qualifies as a “consequential” as opposed to a “direct” damage may be unclear. A contractor may seek to limit its liability for late performance 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, federal, state and local incentives related to the American Recovery and Reinvestment Act of 2009 (the 2009 “Stimulus Act”) can be expected to promote alternative energy development but at the same time may impose conditions that must be dealt with when drafting the relevant contracts. Damages arising from loss of governmental incentives can be expected to be 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 governmental incentives.

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 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 (the borrower) defaults, and the provisions that specify the extent and nature of any damages available to a project developer from a contractor for late completion or failure of the project to generate expected amounts of power. 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

1 A PTC is a tax credit for a percentage of the taxable income generated by a project that qualifies for such credit.


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 performance and payment guarantees. Lenders will also want to know whether the various agreements are entered into on an “arm’s-length” basis, meaning (among other things) 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 bonds (or other guarantees) to ensure (a) the timely performance of contractors (whether engineers, constructors, or procurement contractors), (b) that such performance on the project is 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 Bond/Guarantee. A performance bond is usually issued by a bank or bonding company; a performance guarantee is usually issued by a parent company or other creditworthy entity selected or approved by the project developer. The issuer of the bond or 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 the bond or guarantee to pay another contractor to complete the project. The project developer will want to reserve its other rights against the defaulting contractor if the performance bond does not fully cover (a) the

project developer’s costs of completing the project or (b) damages the project developer may incur if project delays cause the project developer to default on its obligations to third parties.

2. Payment Bond/Guarantee. A payment bond or guarantee 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 bond or guarantee. 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 may 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, particularly if the developer’s only substantial asset is the project itself.


H. Lien Release Issues. When the project developer makes periodic payments to contractors, the developer should obtain lien releases. 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. 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, 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.

V. 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.

VI. Current Developments. Geothermal facilities provide less than 1% of the power generated in the United States, but the importance of this resource is growing both here and abroad and new technologies are appearing to maximize the power generated from geothermal sites. New governmental initiatives at both the state and federal level favor the development of “alternative” power sources. Where the underground resource is available, geothermal power can be an attractive option that generates reliable 24-hour a day power without regard to changeable factors like sunlight and wind, and generates minimal amounts of greenhouse gases. Recent disruptions in the banking industry and the associated business slowdown have once again given well-funded


developers a bargaining advantage. In these uncertain economic times, creative and experienced developers are working with new players and new strategies to meet their business needs.


Chapter Five THE LAW OF LAVA

Penciling Out: ⎯Project Finance for Geothermal Power Projects⎯ Edward D. Einowski, Gary R. Barnum and 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.

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 collateral security for repayment of the loan 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 to cover certain adverse events; and guarantees of the project 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.

I. 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 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 a “single” or “special” purpose entity (“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: What does it take to get a $100 million loan from a bank?

Answer: $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 by the project developer 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”).

II. 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 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.


This limited-recourse nature is generally reinforced by the ownership structures for geothermal energy projects, which tend to utilize an SPE 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, a corporation, limited liability company, or a limited partnership with a general partner which is a separate special purpose corporation or limited liability company) that, in most instances, prevents the creditors from going after the nonproject assets of the ultimate owner(s) of the SPE 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 goal is to limit the lender’s recourse to enforce payment of the debt 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 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 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 and 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, 2014), 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. 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 limited-recourse 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 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 alone 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 coal-fired resources, they have been less common in PPAs for other types of power. 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 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, Reserves 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 maintaining project operations so that power is produced and needed revenues from power sales are earned. 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 creates a variety of reserves to protect against, among other things, foreseen future expenses, the possibility of a mismatch of revenues and expenses during operation and 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 commonly named the “operating reserve” until an amount (or reserve) equal to a set period of projected O&M expenses (commonly, six months) is on hand and maintained. It is not unusual for an operating reserve and other reserves to be initially funded, in whole or in part, from funds available from the loan.

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 and maintains 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 on a periodic basis (quarterly, or for longer periods), 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.

III. 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.

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:

• 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.

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 tax-motivated 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 alternative because institutional funds do not make such small investments. 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 expectation generally precludes their involvement in development projects.

Institutions, on the other hand, are usually satisfied with significantly smaller returns on investment (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 that institutional investors often want 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. It is 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 (which may be up to 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.

IV. 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 address 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.


Chapte r SixTHE LAW O F LA VAGetting So me Cre dit:

—Tax Is sue s —Charles S. Lewis, III, Robert T. Manicke, Kevin T. Pearson, Adam C. Kobos

Septem ber 15, 2009

The tax system often is used to provide incentives for particular types of investments that the government wantsto encourage. These incentives raise tax planning issues that go well beyond those involved in general structural,choice-of-entity, and other financing considerations, and create the potential for significant economic benefit.The available incentives also have been subject to frequent changes as federal and state energy policies haveevolved. The following discussion is only a general summary and is current as of the date shown above. Pleasecontact one of the attorneys listed above for answers to your specific legal questions and to check on any changesthat may have occurred since the date of this publication.

I. Federal Income Tax Issues.

A. The Production Tax Credit. Section 45 of the Internal Revenue Code of 1986, as amended(“Code”), provides a credit against federal income tax for electricity produced from certain renewable resources,including geothermal. This credit is known as the “production tax credit” (“PTC”).

1. Requirements for Claiming the Credit. The PTC for geothermal power applies toelectricity that is (1) produced at a qualified facility during the 10-year period that begins on the date the facilitywas originally placed in service and (2) sold to an unrelated person during the taxable year. Each of the followingrequirements must be satisfied for a taxpayer to claim the PTC:

a. Produced by the Taxpayer. The electricity must be produced by the taxpayerseeking to claim the PTC. If more than one person has an ownership interest in a facility, production from thefacility is allocated among the owners in proportion to their respective ownership interests in gross sales from thefacility. A partnership (including an LLC that is taxed as a partnership) is treated as one person for purposes ofthis rule, which means that individual partners are not treated as owning separate undivided portions of a facilityowned by a partnership.

b. Qualified Energy Resources. The electricity must be produced from ageothermal deposit. A geothermal deposit is defined as a geothermal reservoir consisting of natural heat that isstored in rocks or in aqueous liquid or vapor, whether or not under pressure.

c . Qualified Facility. The electricity must be produced by a facility located inthe United States that is owned by the taxpayer claiming the PTC and that was originally placed in service afterOctober 22, 2004 and before January 1, 2014. A facility generally is considered to be “placed in service” forpurposes of this rule when it is placed in a condition or state of readiness and is available to produce commercialquantities of electricity.

d. So ld by the Taxpayer. The electricity must be sold by the taxpayer claimingthe PTC to an unrelated person during the taxable year.


e. No Advance Approval Required. There is no advance approval requirementfor claiming the PTC. A taxpayer that is entitled to the credit simply reports it on the appropriate form attachedto the taxpayer’s federal income tax return.

2. Calculation of the PTC. The PTC for any taxable year during the credit periodgenerally is equal to 1.5 cents, adjusted for inflation, multiplied by the number of qualified kilowatt hours ofelectricity produced and sold by the taxpayer during the year. For electricity produced and sold during 2009, theinflation-adjusted PTC amount was 2.1 cents per kilowatt hour.

3. Cutback for Government Financing. The amount of the PTC is reduced for facilitiesfinanced in whole or in part with certain government grants, proceeds of tax-exempt bonds, subsidized energyfinancing (financing provided under a federal, state, or local program designed to provide subsidized financing forenergy conservation projects), or other tax credits. The IRS has ruled that certain state tax credits do not reducethe PTC.

4. Nonrefundable Credit. The PTC is a “nonrefundable” credit. If a taxpayer entitled tothe PTC does not have sufficient income tax liability to use the entire credit for a particular year, the taxpayer isnot entitled to a refund of federal income tax on account of any excess credit. Any unused portion of the creditgenerally may first be carried back one tax year and then forward 20 tax years from the year the credit arose.

5. Sunset Date. To qualify for the PTC, a facility must be originally placed in servicebefore January 1, 2014. The sunset date has been extended a number of times since section 45 was first added tothe Code (once retroactively after the PTC had expired for a number of months). Most recently, the AmericanRecovery and Reinvestment Tax Act of 2009 extended the sunset date to January 1, 2014. Proposals to extendthe sunset date are a matter of frequent discussion, and it is possible that the sunset date could be extendedbeyond January 1, 2014 by future legislation.

B. The Investment Tax Credit. The owner of a qualified geothermal facility may claim theinvestment tax credit (“ITC”) in lieu of the PTC. The ITC is a one-time credit against income tax that is basedon the amount invested in a facility rather than on the amount of electricity produced and sold. The amount ofthe ITC for a qualified geothermal facility placed in service from 2009 through 2013 is 30 percent of the tax basis(generally the cost) of the qualifying property. The amount of the ITC for a geothermal facility placed in serviceafter 2013 is 10 percent of the tax basis of the qualifying property.

1. Requirements for Claiming the ITC. The ITC applies only to “energy property,”which is defined for purposes of a geothermal facility to include only property that meets the followingrequirements:

a. Geothermal Equipment. The property must be equipment that is used toproduce electricity from a geothermal deposit. The property must be (1) tangible personal property or (2) othertangible property (not including a building or its structural components) that is an integral part of thegeothermal facility.


b. Deprec iable or Amortizable. The property must be eligible for depreciationor amortization deductions for federal income tax purposes.

c . Irrevo cable Elec tion for 30% Credit. The owner of the property must makean irrevocable election to claim the ITC rather than the PTC for property that is placed in service from 2009through 2013.

2. Progress Expenditure Rules. In certain circumstances involving qualified energyproperty with a normal construction period of more than two years, a taxpayer may be entitled to claim theenergy credit with respect to progress expenditures in tax years before the property is placed in service.

3. Basis Reduction. The tax basis of property with respect to which the ITC is claimed isreduced for all tax purposes (including depreciation and calculating gain from a sale) by one-half of the amount ofthe credit. Thus, the tax basis of the qualifying components of a geothermal facility with respect to which the30 percent ITC is claimed generally will be 85% of the cost of those components.

4. Recapture o f the Credit. The ITC is subject to recapture if, within five years after afacility is placed in service, the taxpayer sells or otherwise disposes of the energy property or stops using it in amanner that qualifies for the credit. The amount of recapture depends on when during the five-year period theproperty is disposed of or ceases to be used in a qualifying manner.

5. No Cutback for Government Financing. The ITC for a geothermal project, unlikethe PTC, generally is not reduced with respect to facilities that are financed in whole or in part with the proceedsof tax-exempt bonds, subsidized energy financing, or other forms of government-supported financing.

6. Nonrefundable Credit. The ITC, like the PTC, is a nonrefundable credit. If ataxpayer entitled to the ITC does not have sufficient income tax liability to use the entire credit for a particularyear, the taxpayer is not entitled to a refund of federal income tax on account of the credit. Any unused portion ofthe credit generally may be carried first back one tax year and then forward 20 tax years from the year the creditarose.

7. Sunset Date. To qualify for the 30 percent ITC, a facility must be placed in serviceafter December 31, 2008 and before January 1, 2014. There is no sunset date for the 10 percent ITC forgeothermal facilities.

C. U.S. Treasury Department Grants. The American Recovery and Reinvestment Act of 2009allows the owner of a qualified geothermal facility that is eligible for the ITC (including by reason of an electionto claim the ITC rather than the PTC) to elect to receive a grant from the U.S. Treasury Department in lieu ofclaiming the ITC or the PTC with respect to the facility. The grant generally is designed to function in the samemanner as the ITC for which the owner of a project otherwise would have been eligible.

1. Qualification for Grant. To qualify for a grant, a geothermal project must (i) qualifyfor the ITC and (ii) be placed in service during 2009 or 2010 or, if construction is begun in 2009 or 2010, beplaced in service on or before January 1, 2013.


2. Amount of Grant. Like the ITC, the amount of the grant generally is 30% of the taxbasis (generally the cost) of qualifying property.

3. Exc luded from Income. A grant is not included in the taxable income of therecipient.

4. Basis Reduction. The tax basis of the property is reduced by one-half of the amount ofthe grant, in the same manner as if the ITC were claimed.

5. Recapture. A grant generally is subject to recapture if, within five years after a facilityis placed in service, the recipient stops using it in a manner that qualifies for the grant or sells or otherwisedisposes of the property to a person who would not have been eligible for the grant if that person had originallyplaced the property in service.

6. No ITC or PTC Allowed. No ITC or PTC may be claimed with respect to propertyfor which a grant has been claimed.

7. Timing of Payment. The U.S. Treasury Department is required to pay a grant to aqualifying project owner within 60 days after the date the project owner applies for payment or the date thefacility is placed in service, whichever is later.

8. Application Deadline. An application for the grant must be filed before October 1,2011.

D. Bonus Depreciation and MACRS Depreciation. In addition to tax credits or grant payments,geothermal facilities also can generate significant tax losses that can be quite valuable to owners with othersources of taxable income that can be offset by the losses. These losses result primarily from bonus depreciationand accelerated depreciation deductions under the modified accelerated cost recovery system (“MACRS”).

1. Bonus Deprec iation. An owner of qualifying property placed in service in 2009 isentitled to deduct 50% of the adjusted basis of the property in 2009. The remaining 50% of the adjusted basis ofthe property is depreciated over the regular tax depreciation schedule.

2. MACRS Depreciation. Qualifying components of a geothermal facility also areeligible for greatly accelerated depreciation deductions, typically over a five-year period based on the doubledeclining balance method.

E. Federal Election to Deduct Intangible Drilling and Development Costs. Section 263(c) ofthe 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, a geothermaldeposit. The benefit of this election may be decreased by a special rule limiting the amount of certain corporatepreference 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 as comparedto depreciation or amortization. The potential deduction for intangible drilling and development costs should becarefully analyzed in any transaction in which a developer wishes to monetize tax credits associated with the


resulting geothermal facility. Because intangible drilling costs arise before a project is constructed or placed inservice and such benefits cannot be transferred to a tax investor after they have become available, it may benecessary to monetize these benefits during development and separately from depreciation and credits applicableto the geothermal facility.

F. Monetizing Federal Income Tax Benefits; Ownership Structuring Issues. A taxpayer thathas little or no need for tax credits or losses (e.g., because it has little or no taxable income) may nevertheless beable to obtain the benefit of various tax incentives by entering into an arrangement with an investor that needscredits, losses, or both. For example, a taxpayer could enter into a partnership with an investor that is willing tocontribute cash to help finance a geothermal facility. The partnership could then operate the facility and, withincertain limits, the tax credits and losses could be allocated to the partner having a need for them. In thealternative, a taxpayer could develop a facility, place it in service, sell it to an investor, and then lease it back fromthe investor. This second alternative, known as a “sale-leaseback,” is available with respect to the ITC and thegrant, but generally is not available with respect to the PTC. These and other potential techniques for“monetizing” tax credits and losses involve risk and require careful tax planning. These considerations should betaken into account in the very early stages of a project, including when choosing the type of entity that will own afacility and the various financing alternatives available. The grant in lieu of the ITC provides a new financingoption for developers of geothermal facilities to consider. Even developers that opt for the grant, however, maystill desire to involve tax-motivated investors to take advantage of the accelerated depreciation and other taxbenefits associated with a project. A comparison of the economic benefits of the PTC, the ITC, and the grantsrequires, among other considerations, careful financial modeling of the projected costs and output of each specificproject and of the full array of potential tax and financing implications. This should include careful considerationof any limitations that may apply to a particular owner’s ability to claim the available tax benefits, such asalternative minimum tax liability, at-risk limitations, and passive activity limitations. The unique attributes ofgeothermal facilities relating to intangible drilling costs and development costs also place a premium on veryearly planning for financing a geothermal project.

II. State and Local Tax Issues. In addition to federal income tax issues, construction and operation ofgeothermal facilities also raise numerous state and local tax issues that should be carefully examined. Following isa 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 generallybase their income tax system on the federal system, and many states have adopted relatively uniform rulesgoverning division of the tax base and computation of taxable income. Despite these similarities, however, eachstate’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 thatstate and will allow the state to tax the income of the company that owns or operates the project. In addition, lesssubstantial 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 isapportioned 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 ofelectricity among different states, some states, such as California, source the sale based on where the majority ofincome-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. Theapportionment rules can sometimes produce surprising results: if the company as a whole has taxable income, thecompany 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 geothermalpower and other alternative energy projects. It is important to understand the nature of each incentive, as there isconsiderable variation among the states. Also, as noted above, some state incentives may reduce the amount ofthe federal energy credit available for the project.

For example, Oregon has adopted a business energy tax credit (the “BETC”). The BETC program allows anOregon taxpayer that owns and operates a geothermal power project to claim a credit against Oregon income taxto offset the eligible costs of construction of the project. Legislation passed in 2007 substantially increased theamount of the credit. Under the new law, the amount of the credit is 50 percent of the eligible costs, up to amaximum total credit amount of $10 million (formerly $3.5 million). The total credit amount is claimed overfive years, and unused credit may be carried forward for up to eight years. A developer may sell the BETCoutright, at a discount established by the state. Certain other incentives, including federal grants, and potentiallyincluding the federal grant in lieu of the PTC or the ITC, may reduce the amount of the BETC. Although the2009 legislature adopted a bill that would have cut back the BETC for many kinds of projects, the governorvetoed that bill, and the cutbacks did not become law.

Montana offers a somewhat similar income tax credit for certain alternative energy systems, including geothermalsystems.

B. Sales and Use Taxes. Nearly all of the states impose a sales tax. In most states, the tax isimposed only on sales of tangible personal property. Some states also impose use tax on sales of certain kinds ofservices. 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 oruse 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 imposethose taxes on sales or use of electricity.

Tax Incentives. Some states, such as Nevada, offer exemptions or other sales and use tax incentives forgeothermal energy facilities. Idaho’s 2005 legislature adopted a sales and use tax rebate for certain alternativeenergy generation equipment, including machinery and equipment used in generating electricity fromgeothermal resources. In 2009 Washington adopted a sales and use tax incentive for certain alternative energygeneration equipment, including machinery and equipment used in generating electricity from geothermalresources. The incentive is a 100 percent exemption from July 1, 2009 through June 30, 2011 and a 75 percentrebate from July 1, 2011 through June 30, 2013.


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 forbusiness purposes. Intangible property is taxable in some states if the owner is centrally assessed, as discussedbelow.

Central Assessment Likely. In many western states, such as Oregon, a company that produces electricity is“centrally assessed” for property tax purposes. Central assessment means that the amount of property tax isdetermined by the state revenue authority rather than by the county assessor’s office. In Washington, central orlocal assessment depends in part on whether the company’s property crosses county lines. In California, thefacility’s output is a factor in determining whether central assessment applies.

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 aparticular project is a matter of frequent controversy. It is often useful to consult an expert in the area of utilityappraisal.

Property Tax Reporting. States typically require owners of centrally assessed property to file annual returnsreporting the value of their property. It is good practice to consult a valuation expert before filing the first returnwith respect to the property, in order to accurately communicate on the return items that could result in taxsavings in future years.

Rollback Penalties in Farm and Timber Use Areas. Some states, such as Oregon, Washington, andCalifornia, impose property tax penalties when land that is used for farming or timber is dedicated to a differentuse. In addition to those penalties, property taxes increase prospectively after the change of use. This issue mayarise during the siting process.

Property Tax Incentives. As part of due diligence in constructing or acquiring a geothermal facility, it isworthwhile to inquire whether any property tax incentives are available. Property tax incentives can beparticularly advantageous because, in contrast to income tax credits, a property tax exemption typically applies atthe front end of an investment and reduces what otherwise would be an unavoidable and substantial cost. Nevadaand Montana, for example, offer a property tax exemption for certain renewable energy facilities, includinggeothermal energy facilities. Oregon’s exemption statute was expanded in 2007 to allow exemption for a greaterrange of projects when the electricity is used on site. Also in Oregon, it may be possible to obtain a temporaryproperty tax exemption under the state Enterprise Zone Program or the Strategic Investment Program. TheEnterprise Zone Program typically offers an exemption for three to five years, but in rural areas the exemptionperiod may be as long as 15 years. To qualify, state law requires that the company increase its permanent,full-time employment within the zone by at least 10 percent. (Note that one employee may satisfy the minimumhiring requirement if the company has not previously operated within the zone.) Other requirements, such asminimum capital investment size, may apply. The Strategic Investment Program statutes offer a partialexemption for 15 years, with a fee payable to the county and other potential conditions. Negotiations for benefitsunder 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 excisetaxes also should be taken into account.

Washington Public Utility Tax. The state of Washington and a number of municipalities withinWashington impose a public utility tax (“PUT”) on the privilege of engaging in certain utility businesses withinthe state and those localities. The state PUT is imposed at a rate of 3.873 percent of gross income derived fromcertain enumerated public service businesses, including the “light and power business.” The “light and powerbusiness” is defined for purposes of the state PUT as “the business of operating a plant or system for thegeneration, production or distribution of electrical energy for hire or sale and/or the wheeling of electricity forothers.” The state PUT is intended to apply only to revenues derived from the retail sale of electricity toconsumers. Accordingly, deductions in computing gross revenues may be allowed for revenues derived from thesale of electricity for resale, among other deductions. The Washington business and occupation tax may alsoapply, depending on the specific activities that the business conducts. Cities and towns also may impose a localPUT or a local business and occupation tax, or in some circumstances, both. Local rates can be substantial.

Other State and Local Excise Taxes. Other states and localities may impose other kinds of excise taxes. Forexample, some Nevada counties and cities, and some California cities, impose gross receipts taxes for the privilegeof doing business in the locality. California imposes a fee based on gross receipts for the privilege of doingbusiness as a limited liability company.


Chapter Seven THE LAW OF LAVA

Delivering the Goods: ⎯Regulatory and Transmission-Related Issues⎯

Stephen C. Hall, Marcus Wood, Jennifer H. Martin

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.


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., power-marketing 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 also 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) 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 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 state-established 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.


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. 2003 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. 2003 establishes standard interconnection procedures and a standard interconnection agreement for generators larger than 20 MW (“Large Generators”). Similarly, FERC Order No. 2006 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.


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. 2003 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. Making things more difficult, cost allocation methodologies in these and other regions are often in flux. 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.

More recently, certain regional transmission organizations, such as the Midwest Independent System Operator, the California ISO, and the Southwest Power Pool, have reformed their interconnection procedures and agreements in response to crippling backlogs and delays in the existing queues. Generally, queue reform has implemented a “first-ready, first-to-advance” methodology, requiring larger study deposits that may be nonrefundable and stricter adherence to progress milestones, and allowing fewer opportunities for developers to delay the process. Queue


reform is happening across the nation, and each reform to FERC’s traditional approach to interconnection responds to the problems faced in a particular region. Thus, it is important to engage knowledgeable counsel in order to remain aware of how the interconnection process may vary from one area to the next.

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 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. FERC’s Order No. 890 series rules are designed, in part, as an effort to improve transparency of transmission service and reduce transmission barriers for new projects. 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 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.

Finally, the Order No. 890 series contains other amendments that may increase access to existing transmission capacity and/or promote transmission expansion in key areas. For example, the series: (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 point-to-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 the Order No. 890 series 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 that include ongoing, audited obligations and the potential for sanctions as a result of compliance failures. 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 per violation for noncompliance. The Federal Power Act requires that all reliability standards must be just, reasonable, not unduly discriminatory or preferential, and in the public interest. In addition, NERC has delegated to designated regional entities the authority to monitor and enforce the reliability standards, and the regional entities may in turn enforce region-specific reliability standards.

The reliability standards apply to certain users, owners, and operators of the bulk electric system, and 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 broadly defined as an organization that owns generating units, and a generator operator is an organization that operates generating units and supplies energy. There are thresholds that may dictate whether a generator owner or generator operator must register, and a geothermal developer should consult with a knowledgeable attorney regarding such requirements. Though initially exempted from registration, QFs are now required to register with the appropriate regional entity and 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. 2003 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.

G a r y R . B a r n u m

Experience Gary Barnum is a member of the firm. He has a broad corporate practice, with an emphasis on finance, tax-motivated transactions, partnerships, mergers and acquisitions. His primary focus in recent years has been the utility industry, with particular emphasis in the renewable energy area. However, he has also a wide range of experience representing financial service companies, manufacturers, retailers, and other industry groups.

Gary has handled a wide range of transactions, including partnership (and limited

liability company) formations and syndications, mergers and acquisitions, public offerings, syndicated credit facilities, private placements, leveraged lease and project

financings, utility financings, asset backed financings and securitizations, commercial paper programs, and derivative arrangements. In addition to significant experience in

non-recourse and other project financing arrangements, he has also been involved

with a wide variety of tax-motivated transactions, including low-income housing credits and state tax credit programs, Federal and state energy credit transactions,

and industrial development and pollution control projects.

Representative Work

• Represented equity investors in connection with investments in IRC §45-qualified Wind Projects throughout the United States.

• Represented developer in connection with the financing of a 10MW geothermal electric-generation project.

• Represented a power generation company in separate transactions in connection with purchase and sale of multiple power projects located in California, Colorado, Maine, Michigan and Nevada.

• Represented a power generation company in a asset-backed private placement of notes, combined with a term loan facility, involving the financing of multiple natural gas-fired combined cycle facilities.

• Represented a power generation company in the sale of its general partnership and carried interest in a 240 megawatt natural gas-fired cogeneration power production facility (had previously represented this company in connection with the original construction financing, long-term financing, refinancing and syndication).

• Represented a power generation company in the sale of its general and limited partnership interest in a 25.3-megawatt waste-to-energy power production facility.

• Represented a power generation company in the development, construction and financing of several waste-to-energy power production facilities.

Member (503) 294-9114 direct (503) 220-2480 fax [email protected]

Education

• University of Washington Law School, J.D., 1981, honors

• University of Oregon, B.A., 1977, high honors

Admissions

• Oregon

• Washington

G a r y R . B a r n u m

• Represented a finance company in connection with the financing of several geothermal power production facilities.

• Represented a national syndicator in connection with multiple syndications to various institutional investors of investment funds engaged in the acquisition, development and operation of Federal tax-credit affordable housing projects throughout the United States.

• Represented developers in the development, construction and financing of Federal tax-credit affordable housing projects throughout the United States.

Professional Honors and Activities

• Listed in Best Lawyers in America, project finance, and structured and equipment finance sections, 2007, 2009

• Member, Business Section of the Oregon State Bar

• Member, Business Law Section of the American Bar Association

J e n n i e L . B r i c k e r

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 (1997 98);

legal systems administrator (1994 97), editor (1992 94), Dark Horse Comics, Inc.; assistant editor, Spectroscopy magazine (1991 92); lecturer in English, University of

Maryland, European Division (1989 90); Graduate Teaching Fellow in women's studies,

University of Oregon (1986 88).


• Burton Award for legal achievement (2001)

• Oregon State Bar Association Environmental and Natural Resources Section

• Oregon Women Lawyers

• Rocky Mountain Mineral Law Foundation

• Geothermal Resources Council

• Oregon Association of Nurseries

• Oregon Lakes Association

Presentations

• "Intersection of State Lands and Water," Oregon Water Law Conference, Portland, Oregon (2008)

• "Tribal Perspectives on Land Ownership and Environmental Stewardship" (moderator), Oregon Lakes Association Annual Meeting, Wallowa Lake, Oregon (2008)

• "Federal Regulations, Leasing and Unitization" (panelist), Geothermal Development and Finance Workshop, Las Vegas, Nevada (2008)

• "Problems & Solutions in the Law of Submerged and Submersible Lands," Oregon Water Law Conference, Portland, Oregon (2007)

• "Geothermal Land, Lease and Unit Legal Issues," Geothermal Resources Council Workshop, Reno, Nevada (2007)

• "Upper Klamath Lake: State Ownership and Authorization Requirements," Oregon Lakes Association Annual Meeting, Diamond Lake, Oregon (2007)

• "Recent Developments in the Law of Submerged and Submersible Lands," Oregon Water Law Conference, Portland, Oregon (2006)


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

• Oregon

• Nevada

• Washington

J e n n i e L . B r i c k e r

• "Water Boundaries in Oregon and Washington," Pacific Northwest Regional Conference, Portland, Oregon (2006)

• "Water Law 101," Oregon Water Law Conference, Portland, Oregon (2005)

Publications

• Oregon reporter for the Water Law Newsletter, a publication of the Rocky Mountain Mineral Law Foundation (quarterly)

• 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)

• 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)

E d w a r d D . E i n o w s k i

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 public-private partnerships for the joint development and financing of major infrastructure projects.

His project finance work covers a broad range of infrastructure projects, including:

• ethanol and biodiesel plants

• electric generation facilities:

o gas fired CT projects

o wind farms

o waste wood and hog fuel burners

o landfill gas to electricity

o solid waste to energy facilities

o solar projects

• 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

• manufacturing facilities, commercial office buildings and retail facilities ranging from regional shopping malls to automobile assembly plants


Education

• University of Michigan Law School, J.D., 1978, cum laude

• University of Michigan Residential College, B.A., 1975, summa cum laude

Admissions

• Michigan

• Oregon



• Listed in Best Lawyers in America, 2009

• Former member of the State of Oregon Municipal Debt Advisory Commission (initially appointed by Governor Kitzhaber), 1999-2007

• Editor-in-Chief and Editor Emeritus of the Municipal Finance Journal

• Member, National Association of Bond Lawyers

• Member, American Bar Association

• Steering Committee member of National Association of Bond Lawyers, 1991-1993

• Associate Member, Oregon Municipal Finance Officers Association

Presentations Mr. Einowski is a regular speaker on various renewable energy topics at national and local conferences. Recent and upcoming

speaking engagements include:

• Law of Renewable Energy; EUCI Webinar, Jun. 15, 2009; Moderator for Panel on Regulatory and Transmission Issues for Renewable Energy Projects

• Law of Renewable Energy; EUCI Webinar, Jun. 8, 2009; Moderator for Panel on EPC, Major Component, Construction and Balance of Plant Contracts for Renewable Energy Projects

• Law of Renewable Energy; EUCI Webinar, Jun. 1, 2009; Moderator for Panel on Siting and Permitting for Renewable Energy Projects

• Law of Renewable Energy; EUCI Webinar, May 18, 2009; Moderator for Panel on Power Purchase Agreements for Renewable Energy Projects

• Law of Renewable Energy; EUCI Webinar, May 11, 2009; Moderator for Panel on Real Estate and Site Rights for Renewable Energy Projects

• American Wind Energy Association Conference and Trade Show, May 4 to 7, 2009, Chicago, Illinois; Topic: Co-locating Renewable Energy Technologies: Shaping Production, Securing Our Clean Energy Future

• Law of Renewable Energy; EUCI Webinar, Apr. 27, 2009; Moderator for Panel on Tax and Project Finance Structuring Issues for Renewable Energy Projects

• National Hydrogen Association's Conference and Hydrogen Expo, Mar. 30-Apr. 3, 2009 in Columbia, South Carolina. Topic: Hydrogen Finance Workshop (workshop leader)

• Infocast Wind Finance & Investment Summit, Feb. 11-13, 2009 in San Diego, California. Topic: Consolidation and M&A in the Wind Industry

• Infocast Biomass Finance & Investment Summit, Jan. 26-29, 2009 in Coral Gables, Florida. Topic: Equity Investor's Perspectives on the Biomass Market

• AWEA Wind Finance & Investment Summit, Oct. 6-7, 2008 in New York City, New York. Topic: Debt Issues in Wind Finance

• National Hydrogen Association's Renewable Forum, Sep. 22-24, 2008 in Golden, Colorado. Topic: Renewable Hydrogen Finance

• 3rd Annual Renewable Energy Finance & Investment Summit, May 19-21, 2008 in Scottsdale, Arizona. Topic: Tax Equity Transactions for Renewable Energy Projects


• International Biomass '08 Conference & Trade Show; Apr. 15-17, 2008 in Minneapolis, Minnesota. Topic: Project Finance

• Wind Power Finance & Investment Summit, Feb. 6-8, 2008 in San Diego, California. Topic: Trends in Mergers and Acquisitions in the Wind Industry

• The Biomass Finance & Investment Summit, Jan. 22-23, 2008 in Miami, Florida. Topic: Project Finance

Publications

• "Dealing With Impact of Rising Oil Prices on Biomass Projects" (with Katherine A. Roek), Natural Gas & Electricity, September, 2008 edition

• "Risk Shifting Major Element in Project Finance for Renewables" (with Katherine A. Roek), Natural Gas & Electricity, October, 2007 edition

• "Investing In Renewable Energy" (with Kevin T. Pearson), The Energy and Utilities Project, Volume 5, 2005 edition

• The "Project Finance for Wind Power Projects" Chapter in the Stoel Rives publication The Law of Wind

• "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, Feb. 1985

• "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

J e r r y R . F i s h

Experience Jerry Fish is a member of the firm concentrating 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.

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.


• Listed in Best Lawyers in America, for over 20 years

• Member, American Bar Association, Natural Resources Section

• Member, Alaska Bar Association

• Member, Oregon State Bar Association

• Member, Missouri Bar Association

• Member, Northwest Mining Association, Northwest Petroleum Association

• Member, Washington Bar Association

• Member, Northwest Hydroelectric Association

Publications

• J. Fish and T. Wood., "Geologic Carbon Sequestration: Property Rights," 54 Rocky Mt. Min. L. Inst. Ch 3, 2008


Education

• Northwestern School of Law of Lewis and Clark College, J.D., 1982, magna cum laude, first in class Certificate in environmental and natural resources law Associate editor, Environmental Law, 1981-1982 Bernard F. O'Rourke Award for best student paper on a natural resource topic Cornelius Honor Society Distinguished Environmental Law Graduate Award

• University of Chicago, MAT, 1974

• A.B., geology, Princeton University, 1971

Admissions

• Alaska

• Oregon

• Missouri

• Washington

J e r r y R . F i s h

• 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

• "Legal Aspects of Underground Storage Operations in the State of Washington, NW Petroleum Assoc. 1991 Annual Symposium, Bellingham, Wash.

• "Recent Developments in State and Local Regulation of Mineral Development," NW Mining Assoc. Convention, Spokane, Wash., Dec. 1986

• "Oregon's New Dormant-Mineral Statute," 47 Oregon Geology 78, 1985

• "Rights in Minerals and Gravel," (coauthor), 2 Real Property § 40, Oregon CLE Supp., 1985

• "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

• "Commonwealth Edison v. Montana: Leading the Severance Tax Stampede," 12 Envtl L 1031, 1982

• "Preservation and Strategic Mineral Development in Alaska: Congress Writes a New Equation," 12 Envtl L 137, 1981

W i l l i a m H . H o l m e s

Experience Bill Holmes is a member of the firm and chair of the renewable energy initiative. Bill 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 represents clients in the negotiation of major power purchase agreements on both

the "buy" and the "sell" sides. This experience includes work on numerous major wind and renewable energy power purchase agreements.

Bill also advises 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. He has 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), Public Service Company of Colorado (PSCO), Kansas City Power & Light, and Southern California

Public Power Authority (SCPPA).

Bill joined Stoel Rives as an associate in 1985 and has been a member of the firm since 1992. Before joining the firm, he served as law clerk to Judge Louis F. Oberdorfer,

United States District Court for the District of Columbia (1984-1985).

To connect with Bill via LinkedIn, visit www.linkedin.com/in/billhholmes.

Representative Work Geothermal/Biomass

• Represented a major investor owned utility in re-negotiating a steam supply agreement, a series of steam prepayment agreements, production payment agreements, trust deeds and other documents relating to securing the steam supply required to operate a geothermal steam plant located in Utah.

• Represented a Pacific Northwest lumber company in the negotiation of a power purchase agreement (PPA) to sell the energy from a 7 MW Washington biomass plant to a public utility district.

• Represented a Pacific Northwest lumber company in the negotiation of a funding agreement with The Energy Trust of Oregon for a small biomass power plant.


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, 1982-83 Editor in chief, Michigan Law Review, 1983-84 Henry M. Bates Memorial Scholarship Abram W. Sempliner Memorial Award Order of the Coif

• University of Texas, B.A. Plan II honors program, 1981, with highest honors Phi Beta Kappa

Admissions

• Oregon

• Minnesota


Wind Energy

• Represented a large investor owner utility in negotiating a power purchase agreement (PPA) to purchase the energy and environmental attributes from a 50 MW wind energy plant located in Wyoming.

• Represented one of the largest wind developers in the United States in negotiating a PPA and associated credit guarantees to buy the energy and environmental attributes from a 300 MW wind plant located in Oregon and Washington.

• Represented one of the largest wind developers in the United States in negotiating a series of back-to-back power purchase agreements to "slice" and sell the output of a 300 MW wind energy plant to the Bonneville Power Administration and other municipalities and utility offtakers.

• Represented one of the largest wind developers in the United States in the negotiation of a power purchase agreement (PPA) and associate guarantees to buy all of the output of a 150 MW wind plant located in California.

• Represented one of the largest wind developers in the United States in negotiating a series of back to back power purchase agreements (PPA) to "slice" and sell the output of a 150 MW California wind plant to various municipalities and municipal utilities in California.

• Represented a major investor owner utility in negotiating a power purchase agreement (PPA) to purchase the energy and environmental attributes from a 41 MW wind energy plant located in Oregon.

• Represented one of the largest wind developers in the United States in negotiating a power purchase agreement (PPA) to purchase the output of a 150 MW wind plant located in Wyoming.

• Represented one of the largest wind developers in the United States in negotiating a power purchase agreement (PPA) to "slice" and re-sell the energy and environmental attributes a 150 MW Wyoming wind plant to various municipalities and municipal utilities in Utah and California.

• Represented one of the largest wind developers in the United States in negotiating a power purchase agreement for the sale to a California investor owner utility (IOU) of the energy and environmental attributes produced by a 66 MW wind energy plant located in California.

• Represented a major wind developer in negotiating a power purchase agreement for the sale to a California investor owned utility (IOU) of the energy and environmental attributes generated by a 45 MW wind energy plant in California.

• Represented a major wind power developer in negotiating and closing an asset sale agreement and a build-transfer agreement governing the sale and construction of a 100.5 MW Kansas wind project to a major Midwest investor owned utility (IOU).

• Represented a major US wind developer in negotiating a power purchase agreement for the sale to an Idaho investor owner utility (IOU) of the energy and environmental attributes produced by a 103 MW wind energy plant located in Oregon.

• Represented a major wind power developer in restructuring an asset sale agreement and an engineer, procure and construct (EPC) agreement governing the sale of a wind energy project to a major Pacific Northwest investor owned utility (IOU).

• Represented a major wind developer in negotiating a power purchase agreement for the sale to a California investor owned utility (IOU) of the energy and environmental attributes produced by a 103 MW wind energy plant located in Oregon.

Natural Gas

• Represented a major US energy developer and power marketer in the negotiation of a long-term power purchase agreement, operation and maintenance agreement, construction management agreement, and related documents for a 450 MW gas-fired cogeneration facility located in Oregon.

• Represented a major US energy developer and power marketer in selling "slices" of part of the output of a gas-fired cogeneration facility to several qualified governmental purchasers.


• Represent the owner of a gas-fired peaking facility in the negotiation of a power purchase agreement with a Colorado for the purchase of output and capacity.

• Represent the owner of a gas-fired peaking facility in the negotiation of a power purchase agreement for the sale of energy and capacity to a California utility.

Carbon Offset

• Represented a major gas utility in negotiating a carbon offset funding and purchase agreement to support customer greenhouse gas offset program.


• Listed in Best Lawyers in America in Energy Law and Environmental Law, 2007-2009

• Member, Oregon State Bar Public Utility Law Section

• Member, American Bar Association Energy and Natural Resources Section

• Chair, Stoel Rives LLP Technology Committee

• Chair, Stoel Rives LLP Renewable Energy Initiative

• Adjunct Professor, University of Oregon Law School, "Renewable Energy Law," Spring 2008, Spring 2009

Presentations

• Upcoming Moderator, "The Mighty Columbia," The Seminar Group, Seattle, Washington, Oct. 29, 2009

• Speaker, "Carbon Sequestration Summit," Information Forecast, Inc., Houston, Texas, Jul. 22, 2009

• Moderator, "Wind Energy Projects in a Stimulated Economy," ABA/ACORE Renewable Energy Teleconference Series, May 20, 2009

• Panelist, "Power Purchase Agreements for Renewable Energy Projects," Law of Renewable Energy; EUCI Webinar, May 18, 2009

• Speaker, "Survey of Legal Issues in Wind Development: Power Purchase Agreements," American Wind Energy Association WindPower 2009 Conference, Chicago, IL, May 6, 2009

• Speaker, "Biomass Related GHG Reduction Opportunities," BBI International Biomass Conference, Portland, Oregon, Apr. 30, 2009

• Panelist, "Greening the Grid: Building a Legal Framework for Carbon Neutrality--Wind," Lewis & Clark Law School, Portland, Oregon, Apr. 24, 2009

• Moderator and Speaker, "The Stimulus Package and Other Incentives Your Business Can Leverage: ARRA Overview," Clean Technology Alliance, InnoTech Conference, Portland, Oregon, Apr. 23, 2009

Publications

• Regular contributor to the Stoel Rives Renewable Energy & Climate Policy Law Blog

• "Power Purchase Agreements" (coauthor) in Chapter 8 of The Law Of Ocean and Tidal Energy, Stoel Rives

• "Power Purchase Agreements and Environmental Attributes," (coauthor) in Chapter 4 of The Law of Wind, Stoel Rives

• "Power Purchase Agreements and Environmental Attributes," (coauthor) in Chapter 4 of Lava Law, Stoel Rives

• "Water Rights and Transactions," (coauthor) Fundamentals of Real Estate Transactions, 2001 Cumulative Supplement

• "Dams for Sale: The Ins and Outs of Federal Facility Transfers," 43 Rocky Mt Min L Inst 24-1, 1997


• "Bureau of Reclamation Contract Renewal and Administration: When is a Contract Not a Contract?" (coauthor) 41 Rocky Mt Min L Inst 23-1, 1995

• "Employee Benefits and ERISA Considerations in Natural Resources Transactions," (coauthor) 34 Rocky Mt Min L Inst 5-1, 1989

• "Natural Resources, Energy and Environmental Law," 1987 Oregon Legislation § 21, Oregon CLE, 1987

• "Reporting Violations of Hazardous Substances Law: Mandatory Self-Incrimination," (coauthor) Or Envtl & Nat Resources L News, at 4, Fall 1986

Civic Activities

• United Way Leadership Giver

• President, Board of Directors, Portland Habitat for Humanity, 1995-1997

• Member, Board of Directors of Portland Habitat for Humanity, 1992-1997

• Pro bono counsel, Portland Habitat for Humanity, 1987-1995, 1997-2000

K a r e n E . J o n e s

Experience Karen Jones is of counsel practicing 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.


• Listed in Best Lawyers in America, energy law, 2009

• Vice Chair, Renewable Energy Resources Committee of the American Bar Association SEER Section, 2006-2007

• 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, 1996-1997

Publications

• Wind Energy Land Agreements," Chapter 1 The Law of Wind, Stoel Rives LLP

• "Title Insurance and Survey Matters," Chapter 2, The Law of Wind, Stoel Rives LLP

• "Power Purchase Agreements and Environmental Attributes," Chapter 4, Lava Law - Legal Issues in Geothermal Energy Development, Stoel Rives LLP

• "Purchase and Sale Agreement – Form 2," coauthor, Oregon State Bar Documentation of Real Estate Transactions, 1996 Supplement

Of Counsel (503) 294-9827 direct (503) 220-2480 fax [email protected]

Education

• 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. music, 1980, magna cum laude

Admissions

• Oregon

• Washington

• Texas

J o h n S . K i r k h a m

Experience John Kirkham is a member of the firm practicing in 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.


• 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, 1993-2006

• Trustee, Rocky Mountain Mineral Law Foundation (Utah Mining Association representative), 1989-1992

• Member, Utah State Bar (Energy, Natural Resources and Environmental Law section; Ethics Advisory Opinion Committee), 1983-1996

• Member, Salt Lake County Bar

• Member, American Bar Association (Section of Environment, Energy and Resources)

Publications

• "Legal Issues in Solution and In-Situ Mining," 52 Rocky Mt. Min. L. Inst. 17-1, 2006


Education

• University of Utah College of Law, J.D., 1971

• University of Utah, B.A., 1968, cum laude, with honors

Admissions

• Utah

• U.S. Court of Appeals for the Tenth Circuit

• U.S. District Court of Utah

• U.S. Supreme Court

J o h n S . K i r k h a m

• "The Energy Policy Act of 2005," coauthor, Connect magazine, Jul. 2006

• "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, 2003-2009

• Board of Directors, Utah Mining Association, 1987-2009

• President, 2006 to present, Executive Board, 1987-2009, Executive Committee, Vice President-Legal, 2003-2006, Great Salt Lake Council, Boy Scouts of America

• Bureau of Land Management, Utah Statewide Resource Advisory Council, 1995-1997

• Member of the U.S. Minerals Management Service Coal Subcommittee of Royalty Policy Committee, 1997-2009

A d a m C . K o b o s

Experience Adam Kobos is an associate in the Tax Section of the firm's Business Services Group. His practice encompasses a wide variety of federal and state tax issues, including:

• Taxable and tax-free corporate mergers and acquisitions;

• Transactions involving partnerships, S corporations, limited liability companies and other pass-through entities;

• Tax aspects of compensation arrangements, including stock options, restricted stock, and bonus plans;

• Debt and equity offerings and other financial transactions;

• Tax controversy matters; and

• State and local tax aspects of transactions.

Adam regularly represents clients who develop or invest in renewable energy projects, including wind, solar, biomass, hydroelectric, and other renewable energy generation

facilities and biofuel production facilities. His renewable energy practice focuses on federal, state, and local tax incentives and transaction structures that enable both

developers and investors to maximize the value of those incentives.

Representative Work Federal

• Advised ethanol producer concerning the federal income tax aspects of its combination with public company.

• Advised controlling owner of a large beef processing company concerning the federal income tax aspects of the sale of ownership interests to a foreign public company.

• Advised public company concerning the federal income tax aspects of the issuance of convertible notes and the undertaking of related call spread transactions.

• Advised outdoor apparel and accessories manufacturer concerning the federal income tax aspects of the sale of its business.

Renewable Energy

• Advised developers regarding tax aspects of development, operation, and sale of Washington and Nebraska wind energy projects.

• Advised developers regarding tax incentives and issues relating to partnership flip and leasing structures for Oregon, California, and Colorado solar projects.

• Advised paper manufacturer regarding alternative fuel mixture credits.

Associate (503) 294-9246 direct (503) 220-2480 fax [email protected]

Education

• Stanford Law School, J.D., 2002 Order of the Coif

• Harvard University, A.M., 1998, philosophy

• Amherst College, A.B., 1995, summa cum laude, philosophy and history Phi Beta Kappa

Admissions

• Oregon

• California

• U.S. Tax Court

A d a m C . K o b o s

• Advised developer regarding Washington tax issues relating to hydroelectric project.

State and Local

• Represented several wind developers obtaining property tax incentives under the Oregon Strategic Investment Program.

• Advised asset manager concerning the Washington transfer tax aspects of its acquisition of multi-billion dollar timber company and subsequent restructuring transactions.

• Represented natural gas exploration company in connection with favorable ruling from the Washington Department of Revenue concerning sales tax aspects of natural gas drilling activities.


• Member, American Bar Association, Tax Section

• Member, Oregon State Bar Association, Tax Section

Publications

• "Proposed Regulations Extend 'Share-by-Share Approach' to Basis Recovery in Distributions," Journal of Corporate Taxation, May/June 2009

• "Final Regs. Simplify Continuity-of-Interest Rule for Insolvent Corporations," Journal of Corporate Taxation, Mar./Apr. 2009

• "Renewable Energy Aspects of the American Recovery and Reinvestment Act," Biofuels International, Mar. 26, 2009 (coauthor)

• "Rev. Rul. 2008-25 Refines (and Revises) the Law of Two-Step Acquisitions," Journal of Corporate Taxation, Sep./Oct. 2008

• "Federal Tax Incentives for Green Buildings," Sustainable Land Development Today, July/Aug. 2008 (coauthor)

• "Final Regulations Concerning Allocations of Boot and Basis in Reorganizations and Section 355 Distributions," Journal of Corporate Taxation, May/June 2008

Civic Activities

• Member of Oregon Episcopal School Alumni Council

C h a r l e s S . L e w i s , I I I

Experience Carl Lewis is a member of the firm practicing in the Seattle office. Carl's practice focuses primarily on federal income tax, particularly with respect to planning and implementing sophisticated tax-motivated transactions, partnerships and joint ventures, financial instruments, and mergers and acquisitions. Carl has represented owners, developers, operators, buyers and sellers for over 25 years in tax-critical transactions ranging from partnerships, joint ventures and LLCs with skewed tax allocations, to leveraged leases, to multi-billion dollar mergers. These projects have included cogeneration projects, biomass generators, coal and gas-fired plants, synthetic fuel projects, wind plants and biofuels projects, and have been located throughout the United States and in Europe, Australia, The Philippines and South America. Recently, Carl assisted a client in creating, designing and implementing a sale and leaseback structure to monetize the remainder of nearly $12 million in Oregon pollution control tax credits. Subsequently, Carl helped the company use this structure again—with the addition of a complex lessee partnership, O&M agreement and operating agreement to bring in an additional tax credit investor when the original investor's tax appetite was insufficient—to monetize an additional $17 million in tax credits with respect to another facility.

Carl joined Stoel Rives in 1978 and is Lead Financial Partner and Tax Matters Partner for the firm.


• Included in Best Lawyers in America, 2004-2009

• Selected as one of "America's Leading Lawyers for Business" (Washington) by Chambers USA (Corporate/Commercial: Tax), 2006-2009

• Member, Washington State Bar Association taxation section

• Member, Oregon State Bar Association taxation section

• Member, American Bar Association taxation section

Presentations

• Frequently lectures on taxation subjects.

Publications

• "Like Kind Exchange of Property Used in a Trade or Business or for Investment," 5 Rev of Tax'n of Individuals 195, 1981

• "Partnership Taxation," 1 Advising Oregon Businesses, Chapter 4, Oregon CLE 1984 and 1989, coauthor 1994 and 1997


Education

• Willamette University College of Law, J.D., magna cum laude, 1978 CJS Award (1976, 1977, 1978)

• Lewis and Clark College, B.S., 1975, magna cum laude Delta Mu Delta, business honorary, OSCPA Accounting Student of the Year, 1975

• University of Southern California, 1971-1972

Admissions

• Washington

• Oregon

• U.S. Tax Court Bar

C h a r l e s S . L e w i s , I I I

• "The 2003 Confidential Transaction Tax Shelter Regulations: Another Chapter in the Disclosure and List Maintenance Regulations Saga," coauthor, Corporate Taxation, 2004

• The Tax Reform Act of 1986: Analysis and Commentary, coauthor, 1987

Civic Activities

• Member, Board of Directors, Seattle Chamber Music Society

R o b e r t T . M a n i c k e

Experience Robert Manicke practices in the firm's Portland office. He is the firm's lead member for state and local taxation, and his practice also emphasizes employment tax matters. He regularly represents clients in the Oregon Tax Court and before state revenue authorities, the Portland Revenue Bureau and the Internal Revenue Service.

His transactional practice includes state and local tax incentives, state and federal tax

rulings, and state and local tax legislative projects. He has extensive experience with

energy-related tax incentives, including the Oregon Business Energy Tax Credit, the Strategic Investment Program and the Enterprise Zone Program.

Representative Work Lead attorney in numerous cases in the Oregon Tax Court involving corporate and personal income tax, as well as property tax. Representative subjects include:

• Consolidated returns

• Public Law No. 86-272 and nexus

• Statutes of limitation

• Business/nonbusiness income and loss

• Property taxation of centrally assessed businesses

• Property tax exemption


• Listed in Best Lawyers in America, Tax Law, 2007-2009

• 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

• Member, Oregon Business Association Business and Finance Committee

Presentations

• "Oregon Tax Amnesty Program," Oregon State Bar Tax Section, Portland, Sep. 3, 2009

• "Oregon and Washington Update" (copresenter), Oregon Tax Institute, Portland, Jun. 7, 2009 (forthcoming)

• "Oregon Legislative Update," Oregon State Bar Tax Section, Portland, Apr. 9, 2009


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

• Oregon

• California

• Washington

Languages

• Dutch

• German

R o b e r t T . M a n i c k e

• "Tax Issues in Employment Settlements," Oregon Law Institute, Portland, Jun. 6, 2008

• "Financial Aspects of Green Building: Tax and Other Governmental Incentives for Green Projects," Lorman Seminar, Portland, Mar. 14, 2008

• "Oregon Legislative Developments: What You Need to Know About 2007 Changes," Lorman Seminar, Portland, Mar. 11, 2008

• "Solar Financial Incentives for Business Owners" (copresenter), Northwest Solar Expo, Portland, Sep. 14, 2007

• "Oregon Update," Oregon Tax Institute, Portland, May 18, 2007

• "Oregon Legislative Update," Oregon State Bar Tax Section, Portland, 2007

• Tax Executives International, Portland, Jun. 2006

• American Wind Energy Association, Pittsburgh, Feb. 2006

• Panel presentation on Oregon's repeal of its discriminatory Section 1031 statute, ABA Sales, Exchanges & Basis Committee, San Antonio, Texas, Jan. 25, 2003

Publications

• "Taxation," Oregon Legislation Highlights, Oregon State Bar, 2009

• Chapter on Oregon property tax (coauthor), ABA Property Tax Deskbook, annually since 1996

• Survey of Oregon and Idaho tax developments (coauthor), Council on State Taxation, semiannually since 1995 for Oregon, since 2006 for Idaho

• "Taxation," Oregon Legislation Highlights, Oregon State Bar, 2008

• "Taxation" (coauthor), Oregon Legislation Highlights, Oregon State Bar, 2007

• "Property Tax Exemptions in Oregon: Slips and Tips," Oregon State Bar Taxation Section Newsletter, Spring 2005

• "Oregon Pollution Control Facility Tax Credits: 2001 Legislative Changes" (coauthor), Oregon Insider, Issue 279, Sep. 1, 2001

• "Tax Incentives" (coauthor), The Law of Building Green: Business and Legal Issues of Sustainable Real Estate Development, Stoel Rives LLP, 2007

• "Tax Issues" (coauthor), The Law of Ocean and Tidal Energy: A Guide to Business and Legal Issues, Stoel Rives LLP, 2007-2008

• "Tax Issues" (coauthor), The Law of Wind: A Guide to Business and Legal Issues, Stoel Rives LLP, 2005-2009

• "Tax Issues" (coauthor), Lava Law: Legal Issues in Geothermal Energy Development, Stoel Rives LLP, 2005-2008

• "Tax Issues" (coauthor), The Law of Biofuels: A Guide to Business and Legal Issues, Stoel Rives LLP, 2005-2008

Civic Activities

• Participated in the 2007 task force that worked with the City of Portland on development of a tax incentive for venture capital firms.

• Board Member, German American School of Portland, since 1999

• Board Member, Portland Symphonic Girlchoir, 2006-2009

Foreign Languages

• Dutch (reading ability)

• German

J e n n i f e r H . M a r t i n

Experience Jennifer Martin is a member of the firm practicing in the Energy Group and Renewable Energy Initiative. Her practice focuses primarily on representing renewable energy developers in the negotiation of major power purchase agreements on both the "buy" and the "sell" sides. This experience includes work on many major wind power purchase agreements. Jennifer also advises developers in navigating the regulatory timelines and obligations for securing interconnection agreements and transmission agreements, and negotiating interconnection agreements in organized markets such as PJM, the Midwest ISO and SPP, and with individual utilities. Jennifer also represents renewable energy clients on a variety of energy-related regulatory 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.

She has represented renewable energy clients in negotiations with a range of counterparties, including Pacific Gas & Electric (PG&E), Bonneville Power

Administration (BPA), Sacramento Municipal Utility District (SMUD), Northern States Power (NSP), Salt River Project (SRP) and Northern Indiana Public Service Company

(NIPSCO).

Judicial Clerk, Minnesota Supreme Court, 1999-2000; Senior Note and Comment Editor, Journal of Gender Race and Justice at University of Iowa College of Law, 1998-

1999; summer law clerk, Stoel Rives, 1998; research assistant, Professor David Baldus,

University of Iowa College of Law, 1997-1999; clerk, Circuit Court of Cook County, 1993.

Representative Work Representative Regulatory 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 energy efficiency clients on state regulatory and renewable energy credit (REC) issues and drafting customer participation agreement.


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, 1992-1993

Admissions

• Oregon

• Utah

• U.S. Court of Appeals for the Ninth Circuit

• U.S. Court of Appeals for the D.C. Circuit

• United States Supreme Court

J e n n i f e r H . M a r t i n

Representative Transactional Work

• Represented wind developer in negotiation of 50 MW long term power purchase agreement, for sale of output and environmental attributes from Minnesota wind facility.

• Represented wind developer in negotiation of 63 MW long term power purchase agreement for sale of output and environmental attributes from Arizona wind facility.

• Represented wind developer in negotiation of 50 MW long term power purchase agreement for sale of output and environmental attributes from Iowa wind facility.

• Represented wind developer in negotiation of 30 MW long term power purchase agreement for sale of output and environmental attributes from Iowa wind facility.

• Represented wind developer in negotiation of 50 MW long term power purchase agreement for sale of output and environmental attributes from Oregon wind facility.

• Represented wind developer in negotiation of 90 MW long term power purchase agreement for sale of output and environmental attributes from Oregon wind facility.

• Represented renewable energy developer in negotiation of back to back power purchase and sales agreements from a 55 MW biomass facility in Washington state.


• Member, Energy, Telecom and Utility Law Section, Oregon State Bar

• Member, Public Utility, Communications and Transportation Law Section, American Bar Association

• Member, Energy Bar Association

• Member, Multnomah Bar Association

• Member, Women of Wind Energy

Presentations

• "Law of Renewable Energy: Regulatory and Transmission Issues for Renewable Energy Projects," upcoming Electric Utility Consultants, Inc. Webinar, June 15, 2009

• "Law of Renewable Energy: Power Purchase Agreements for Renewable Energy Projects," upcoming Electric Utility Consultants, Inc. Webinar, May 18, 2009

• Poster Presentation "FERC's Implementation of EPAct of 2005: Impacts on the Wind Energy Business," WINDPOWER 2007 Conference & Exhibition, Los Angeles, California, June 2007

Publications

• "Relocating the Wind: New Strategies for Moving Wind Generation from High-Wind Areas to High-Load Areas," North American Clean Energy, Aug. 4, 2008

A l a n R . M e r k l e

Experience Alan Merkle is Chair of the firm and a member of its Energy and Telecommunications practice group. He concentrates his practice primarily on energy and infrastructure, with particular focus on project development transactions and related matters.

Alan regularly leads due diligence teams in mergers and acquisitions of renewable energy companies, drafting and negotiating "frame agreement" and project specific

turbine supply, power generation equipment, operation and maintenance, and warranty, balance of plant and EPC construction agreements. Representative clients

include developers, owners, engineers, architects, contractors, manufacturers and

suppliers, together with a large number of leading wind project developers in the United States and Canada, as well as major players in the biofuels, solar, tidal and

nuclear power industries.

Alan also handles complex claims, litigation, arbitration, mediation and other alternative dispute resolution matters for a broad range of clients. In addition to his

advocacy work, he regularly serves as a neutral on Dispute Review Boards and as a mediator and arbitrator. Prior to practicing law, Alan managed the technical and

business sides of major energy, construction, engineering, and manufacturing

projects, including 12 years with General Electric Company. He is a registered professional engineer in Washington, Oregon, and Idaho.

Representative Work Wind

• Represented major Australian energy company in its acquisition and subsequent disposition of a Canadian and U.S. wind development company, as well as turbine supply and project agreements.

• Represented major Canadian energy company in acquisition of wind turbines, operation and maintenance and construction agreements in development of Canada's largest wind project.

• Represented major Canadian energy company in due diligence of large U.S. wind development company with pipeline of several thousand megawatts of projects.

• Represented one of the largest U.S. wind developers in first ever multi-year frame turbine supply agreement with leading U.S. turbine manufacturer.

• Represented one of Europe's largest wind developers in conversion of and renegotiation of worldwide turbine supply agreements for U.S. based, project financeable agreements.

• Represented one of the leading U.S. contractors in negotiating a series of balance of plant agreements for various developers throughout the United States.


Education

• Northwestern School of Law of Lewis & Clark College, J.D. 1982, cum laude Cornelius Honor Society 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

• Washington

• Oregon


• Represented one of the largest U.S. wind developers in negotiating the first ever turbine supply agreement from a major new European entrant to North America.

• Negotiated the first turbine supply agreements with a new North American turbine vendor.

• Represented a significant number of North America's largest wind developers in a full range of project developments for owner/operator and build/transfer projects for several thousand megawatts of wind power.

• Negotiated first of its kind stand-alone tower manufacturing contracts on behalf of project developer purchasing foreign made turbines without towers.

• Lead litigation counsel in a number of significant disputes regarding failed gearboxes, breach of contract, and warranty disputes on behalf of project Owners and developers.

Biofuels

• Represented major international biofuels designer/developer in matters related to development of the largest hydrogen manufacturing facility in North America.

• Represented industry leader in development of combined biodiesel, ethanol, methane, dairy, algae integrated facility.

• Represented major international developer of ethanol projects in unique biomass boiler/ethanol and fuel-dized bed boiler/ethanol production facilities.

• Represented United States largest biodiesel refiner in matters related to the engineering and construction agreements for its production facilities.

• Represented one of U.S. leading developers of algae production for biodiesel and ancillary products in project financing and development agreements.

Solar

• Represented one of the world's leading solar panel manufacturers in development of new manufacturing and production facilities in the United States.

• Represented one of the leading renewable energy developers in the United States in development of a series of solar projects in the western U.S.

Gas Fired Facilities

• Represented two of North America's largest combined cycle project developers in development of a series of large combined cycle projects, including negotiation of turbine and HRSG supply agreements and EPC contracts to design and construct facilities with different contractors and equipment vendors (several thousand megawatts).

• Represented major utility in designing its RFP process, as well as drafting and negotiating EPC and equipment agreements for 500-megawatt combined cycle plant.

• Represented major international energy company in negotiating EPC contracts for development of 500 megawatt combined cycle facility for third party refinery co-location.

• Represented major developer in negotiation of EPC and project related agreements to develop a combined enhanced oil recovery/combined cycle cogeneration facility.

Geothermal

• Represented geothermal developers in procurement, engineering, construction and related project agreements for new geothermal operations in California and Idaho.


Pump Storage

• Represented major North American developer in due diligence and project agreements for development of two pumped storage/wind integrated projects in North America.

Nuclear

• Represented one of leading developers of small scale modular nuclear power systems in negotiation of its engineering, manufacturing, co-development and project partner agreements.

• Represented major utilities in litigating claims against large scale nuclear power developer.


• Listed in Best Lawyers in America

• 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, Who's Who in America, 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

Presentations

• Frequent speaker and writer on subjects of turbine warranties, operating and maintenance agreements, and EPC agreements for wind, biofuels, waste to energy and related industries

Publications

• Author of numerous articles and chapters on subjects of design, construction, equipment procurement, project development and related topics.

Civic Activities

• Former council member and Mayor, City of Mercer Island

• Chair, Washington Department of Transportation Expert Review Panel

• Executive VP, Board member, French American Chamber of Commerce – Pacific Northwest

• Former Board member, Vice Chairman Cascade Water Alliance

M a r y J o N . M i l l e r

Experience Mary Jo Miller is a member of the Corporate Section of the firm's Business Services Group. Her practice focuses on finance, securities, merger 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 bi-lateral loan facilities, public bond financing and public offerings and private placements of debt and equity securities.

Associate, Shearman & Sterling, London, England, 1998-2001; associate, Baker &

McKenzie, Chicago, Illinois, 1995-1998.

Representative Work

• Represented the borrower in connection with a public bond financing of a landfill gas 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 purposes subsidiaries.

• Represented the developer/seller in connection with the phased development and sale of four wind farms with aggregate installed capacity of 230 MWs.

• Represented a timber company in connection with the restructuring of its syndicated secured credit facilities.

• Represented the investors in connection with the phased development of a 120MW geothermal electric-generation project.

• Represented a manufacturer in the acquisition of the distressed assets of a competitor.

• Represented the seller of a 125 MW gas-fired power plant.

• Represented the issuer in the first Internet IPO in the United Kingdom, listed on the London Stock Exchange and Nasdaq.

• Represented the underwriters in various securitized and high-yield note issues pursuant to exemptions from registration under Rule 144A and Regulation S.

• Advised financial institutions and corporate borrowers in connection with syndicated and bi-lateral loan facilities, secured and unsecured.

• Advised domestic and foreign private issuers with respect to compliance with the Securities Exchange Act of 1934.

Associate (503) 294-9636 direct (503) 220-3380 fax [email protected]

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

• Oregon

• Illinois

Languages

• French

• Italian

• Portuguese

• Spanish

M a r y J o N . M i l l e r


• American Bar Association

• Multnomah Bar Association

• Oregon Women Lawyers

• 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

• Co-author, "Pencilling Out: Project Finance for Geothermal Power Projects," Lava Law: Legal Issues in Geothermal Energy Development, 2008

• "Reading, 'Riting and Response: Holding Colleges and Universities Liable Under CERCLA," 20 J.C. & U.L. 483, 1994

• "Regulatory Issues Affecting U.S. Financial Institutions Involved in Asset Securitisation," 8 Int'l Securitisation Rep 5, 1994, (co-author with Jerome W. Jakubik)

Civic Activities

• Member of the Board of Trustees, Childpeace Montessori School

K a r l F . O l e s

Experience Karl Oles is a member of the firm practicing 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.


• Included in "Super Lawyers," Washington Law & Politics, 2003-2007

• Member, Technology committee and 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, Rhode Island, 2007

• "Construction Contract Formation and Drafting," Lorman Education Services, Comprehensive Construction Law in Washington, Seattle, Washington, 2006

• "Delay Claim Damages Measurement," seminar, Contract Solutions Group, Seattle, Washington, 2006

• "Beating Difficult Contract Clauses," seminar, Washington State Bar Construction Section, Seattle, Washington, 2005

• "Avoiding Claims: Case Studies and Lessons Learned on Recent Public Projects," seminar, Washington State Bar Construction Section, Seattle, Washington, 2003

• "Working with the Construction Expert," seminar, Washington State Bar Construction Section, Seattle, Washington, 2002

• "Parties and Claim Theories in Construction Cases," seminar, Washington State Bar Construction Section, Seattle, Washington, 2002

Publications

• "Design, Engineering, Construction and Turbine Purchase Agreements," coauthor, The Law of Wind: A Guide to Business and Legal Issues, Stoel Rives LLP, 2008

• "Solar Energy System Design, Engineering, Construction and Installation Agreements," coauthor, Lex Helius—The Law of Solar Energy: A Guide to Business and Legal Issues, Stoel Rives LLP, 2008


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, magna cum laude

Admissions

• Washington

• U.S. District Court for the Eastern and Western Districts of Washington

• Ninth Circuit Court of Appeals

K a r l F . O l e s

• "Ease into '08 with a Crash Course in Subpoenas," The Daily Journal of Commerce, Oregon, 2008

• "Setting Up Shop: Design, Engineering and Construction for Biofuels Plants," coauthor, The Law of Biofuels: A Guide to Business and Legal Issues, Stoel Rives LLP, 2007

• "Contractors Eyeing Washington Must Heed State Statutes," The Daily Journal of Commerce, Oregon, 2007

• "Setting Up Shop: Design, Engineering, Construction and Turbine Purchase Agreements," coauthor, Lava Law: Legal Issues in Geothermal Energy Development, Stoel Rives LLP, 2007

Civic Activities

• Board member, ACE Mentors of Washington

• Member, board of trustees, Episcopal Retirement Communities

K e v i n T . P e a r s o n

Experience Kevin is a member of the firm practicing in 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.


• 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

• 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.

Publications

• "Renewable Energy Aspects of the American Recovery and Reinvestment Act," coauthor, Biofuels International, Mar. 2009

• "Investing in Renewable Energy: Investment by Non-Utilities in Electric Generation Can Have Far-Reaching Tax Benefits," coauthor, in The Energy and Utilities Project: Innovation for the Future (vol. 5), 2005


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, 1995-1996 National Moot Court

• Linfield College, B.S., 1992

Admissions

• Oregon

• Washington

• U.S. Court of Federal Claims

• U.S. Tax Court

K e v i n T . P e a r s o n

• "Tax Issues," coauthor, in The Law of Wind, Stoel Rives LLP, 2005

• "Tax Issues," coauthor, in Lava Law: Legal Issues in Geothermal Energy Development, Stoel Rives LLP, 2004

• "The 2003 Confidential Transaction Tax Shelter Regulations: Another Chapter in the Disclosure and List Maintenance Regulations Saga," coauthor, in Corporate Taxation, May/Jun. 2004

• "Tax Issues," co-author, in The Law of Wind: A Guide to Business and Legal Issues, Stoel Rives LLP, 2003

• "The Sarbanes-Oxley Act of 2002: Important Tax-Related Issues," coauthor, presented to the Tax Executives Institute, Oct. 2002

• "What Every Business Lawyer Needs to Know About Tax," presented to the Oregon State Bar Young Lawyers Division, Oct. 2002

• "Corporate Reorganizations: Basic Concepts, Emerging Issues, and Unique Reorganizations," coauthor, Oregon State Bar Tax Institute, Jun. 2000

• "Equity Compensation: Basic Concepts and Emerging Issues," coauthor, presented to the Tax Executives Institute, Apr. 1999

M a r c u s W o o d

Experience Marcus Wood is a member and Chair of the Energy and Telecommunications (ENTEL) practice group. He focuses his practice on energy provider and energy facility developer clients. Marcus has extensive experience representing independent power company owners of 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, in investigations and in rate proceedings, and has been a leader in efforts to create Regional Transmission Organizations.

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 as wind-powered and geothermal energy resources. He regularly assists clients on the structuring of energy projects and 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.

Representative Work

• Led the Attorney's Committee in efforts to form the "IndeGo" and the "RTO West" Regional Transmission Organizations for the Northwestern United States.

• Represented a major independent power producer in negotiating and financing the acquisition of a 300 megawatt wind farm in Colorado.

• Represented a major investor-owned utility in re-negotiating a steam supply agreement, a series of steam prepayment agreements, production payment agreements, trust deeds and other documents related to securing the steam supply required to operate a geothermal steam plant located in Utah.

• Represented a major investor-owned utility in negotiating a development agreement for the acquisition of a 41 megawatt wind farm in Wyoming, and in creating a generation control, storage, and redelivery agreement for the transmission of the wind farm's output over constrained transmission facilities for firm delivery in Oregon.

• Represented a developer in negotiation of power purchase agreements for output of a geothermal steam plant located in Idaho and in negotiation of a power storage and redelivery agreement for project output to be stored and later redelivered to a purchaser located in Oregon.

• Represented a major wind project developer in negotiating multiple Renewable Energy Purchase Agreements for 400 megawatts of output from a wind farm in Indiana.


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

M a r c u s W o o d

• Represented a major wind project developer in negotiating the acquisition of a 24 megawatt wind farm in Oregon.

• Represented a major wind project developer in negotiating a Wind Development Acquisition and Sale Agreement for the development and sale of a 123 megawatt wind farm in Iowa.

• Represented a major developer in negotiating a long-term power tolling agreement for a new 550 megawatt gas-fired electric generation facility to be constructed by the developer.


• Listed in Best Lawyers in America in Energy Law category

Presentations

• "Renewable Energy Power Purchase Agreements: A 15-Minute Sampling of Particular Areas of Concern to Sellers," The Center for American and International Law 2nd Annual Power & Alternative Energy Law Conference, Houston, Texas, April 22, 2009

• "Global Warming Initiatives in the Western States: Impacts on the Location and Marketing of Electric Generation," Infocast Webinar, October 4, 2007

• "Transmission Policy, Incentives, and Expansion in the Western United States," Electric Utility Consultants, Inc. Conference on Transmission Expansion in the Western United States, Westminster, Colorado, May 21, 2007

• "Transmission Service Through Generation Redispatch: The Multiple Flavors of Redispatch," Utility Wind Integration Group Wind-Hydro Integration Conference, Portland, Oregon, May 22, 2007

• "California Global Warming Solutions Act of 2006: The Impacts on Ownership, Construction, and Marketing of Power from Electric Generation Facilities," Infocast Webinar, September 21, 2006

• "The Pacific Northwest – A Laboratory for Delivery of Grid Access and Transmission Services," American Wind Energy Association Annual conference, Denver, Colorado, May 17, 2005

Publications

• "Relocating the Wind: New Strategies for Moving Wind Generation from High-Wind Areas to High-Load Areas," North American Clean Energy, August 4, 2008

Stoel Rives Supports Renewable EnergyStoel Rives purchases Renewable Energy Credits

known as RECs or “green tags” to offset 100 percent

of its firmwide electricity usage. The emissions that are

avoided through this green power purchase is roughly

equivalent to the annual greenhouse emissions from 1,208

passenger vehicles or 748,617 gallons of gasoline. 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.

WashingtonJennie L. Bricker (503) 294-9631 [email protected] R. Fish (503) 294-9620 [email protected] L. McMahan (360) 699-5900 [email protected] R. Merkle (206) 386-7636 [email protected] F. Oles (206) 386-7535 [email protected]

OregonGary R. Barnum (503) 294-9114 [email protected] L. Bricker (503) 294-9631 [email protected] Curtiss (503) 294-9810 [email protected] D. Einowski (503) 294-9235 [email protected] R. Fish (503) 294-9620 [email protected] C. Hall (503) 294-9625 [email protected] H. Holmes (503) 294-9207 [email protected] E. Jones (503) 294-9827 [email protected] H. Martin (503) 294-9852 [email protected] L. McMahan (503) 294-9517 [email protected] Jo N. Miller (503) 294-9636 [email protected] T. Pearson (503) 294-9622 [email protected] Wood (503) 294-9434 [email protected]

CaliforniaRandall M. Faccinto (415) 617-8910 [email protected] A. McKinsey (916) 319-4746 [email protected] E. Susman (415) 617-8942 [email protected]

IdahoKevin J. Beaton (208) 387-4214 [email protected] K. McIntyre (208) 387-4239 [email protected]

UtahMartin K. Banks (801) 578-6975 [email protected] M. Hanni (801) 578-6904 [email protected] S. Kirkham (801) 578-6956 [email protected]

ContactsGeOthermal enerGy team

Stoel Rives is a leading business law firm with focused experience in the areas of energy and environmental law and nearly 400 attorneys in eight states.


Stoel Rives is proud to purchase Renewable Energy Credits to offset 100 percent of its firmwide electricity usage.

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