Is Third-Party Financing for Energy Efficiency Ready for Prime Time?

July 29, 2014

In recent years, innovations in finance helped spark explosive growth in distributed generation technologies such as roof-top solar. New and creative rooftop leasing transactions allow third-party investors, rather than homeowners, to fund project development. These structures overcome high upfront costs, one of the primary barriers to energy investments for ordinary homeowners and small businesses, while creating solid returns for investors. Third-party investment in energy efficiency, by contrast, has lagged. Several recent developments suggest this may be about to change.

First, Wall Street's interest in large-scale energy efficiency investments is growing, as demonstrated by a new Wall Street investment funds dedicated to energy efficiency that have been capitalized to the tune of hundreds of millions of dollars. The strong investor interest in efficiency investments is not surprising given the potential profits. A McKinsey & Company study, for example, estimates that the United States has the potential to reduce non-transportation energy consumption by 23%, which would produce present-value savings of $1.2 trillion, creating a solid return on the $520 billion upfront investment required. Energy savings on this magnitude would also reduce greenhouse gas emissions by 1.1 gigatons, equivalent to taking the entire U.S. transportation fleet off the road.

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Department of Energy Offers $4 Billion in Loan Guarantees for Energy Efficiency, Renewables, and Energy Storage

July 24, 2014

The U.S. Department of Energy's Loan Programs Office recently announced a new solicitation for federal loan guarantees to help promote renewable energy, energy storage technology, and energy efficiency projects. The loan guarantees are aimed at promoting greenhouse gas-reducing technologies where DOE support will be "catalytic" -- that is, support of a particular project will help catalyze widespread adoption of the technology -- and the technology is replicable and market-ready.

Specific categories of projects eligible for loan guarantees include renewable energy projects that incorporate energy storage, smart grid and energy storage projects that promote renewables integration, and microgrid projects if they reduce carbon dioxide emissions. In addition, biofuels, waste-to-energy projects, and a variety of energy efficiency processes and technologies are eligible. Finally, loan guarantees can be used to retrofit existing non-powered dams with hydroelectric generation and to install variable speed pump-turbines into existing dams. As recently noted here, Congress also recently appropriated money to provide production incentives for hydroelectric power produced by new generators installed on existing non-powered dams and conduits.

DOE will being receiving initial applications October 1, 2014, and will begin receiving supplemental applications for those projects passing the initial screen on January 14, 2015. The solicitation provides for four additional rounds of applications.

If you have any questions about the DOE's loan program, energy project construction or finance, or other matters involving energy or environmental law, please contact a member of GTH's Energy, Telecommunications, and Utilities or Environment & Natural Resources practice groups. We're proud that our partner Jim Waldo was recently named 2013 Lawyer of the Year for Energy and Natural Resources Law, and six practice members were recently recognized as Washington Super Lawyers.

Please Join Us for LSI's Columbia River Treaty Conference

July 21, 2014

Please join us for Law Seminar International's Columbia River Treaty Conference, which will be held here in Seattle on September 22 & 23, 2014. The conference is particularly timely because, as we've discussed at length here, September marks a critical turning point for the Treaty, which is one of the cornerstones of our regional economy, and a major factor in issues ranging from salmon restoration to water quality and flood control. We're pleased to announce that GTH partner Jim Waldo will co-chair the conference and GTH partner Eric Christensen will be speaking. We hope to see you there!

Nearly Nine Years Later, Congress Finally Funds Incentives for Power Production on Existing Dams

July 21, 2014

When Congress passed the Energy Policy Act of 2005 nearly nine years ago, it included a provision, Section 242, authorizing incentives to retrofit non-powered dams, canals, and conduits with new hydroelectric generation. Until this year, however, Section 242 gathered dust, with Congress failing to authorize any funding. For the first time, when it finally passed its funding bill for Fiscal Year 2014 (October 1, 2013-September 2014) in January, Congress authorized $3.6 million to fund the Section 242 incentives program, dubbed the Hydropower Production Incentive Program ("HPIP"). The U.S. Department of Energy is now finalizing guidance on operation of the HPIP, and anticipates it will begin taking applications for HPIP funding later this summer.

There are over 80,000 non-powered dams in the United States, and a 2012 Oak Ridge National Laboratory study concluded that these dams have the potential to produce about 12,000 MW of new, renewable generation capacity, including about 225 MW here in the Pacific Northwest. In addition to HPIP funding, last summer Congress enacted two bills that greatly reduce the regulatory barriers to constructing new hydroelectric generation on existing dams, canals, and similar facilities. In combination with this legislation, the HPIP represent a major opportunity to extract value from existing dams, especially in the West, where many irrigation dams and canals were constructed without hydroelectric capacity.

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Iowa Supreme Court Clears Regulatory Path for Rooftop Solar Providers, Concluding They Are Not Regulated "Public Utilities"

July 16, 2014

Last week, in a decision that is likely to have far-reaching consequences both for the solar power industry and for traditional utilities, the Iowa Supreme Court found that a solar rooftop leasing company is not a "public utility" subject to regulation by the Iowa Utilities Board. The Iowa Court is the first to address whether a company leasing solar panels on a customer's rooftop is a regulated "public utility" under state utility laws. If followed in other states, the court's conclusion will greatly reduce the regulatory burdens faced by sellers of solar rooftop systems, especially those using innovative leasing/PPA arrangements, while intensifying pressure on traditional utilities from the growing market for customer-owned solar power. (SZ Enterprises, LLC d/b/a Eagle Point Solar v. Iowa Utilities Board, No. 13-0642 (Iowa Sup. Ct., issued July 11, 2014).

As noted previously, the Washington Utilities and Transportation Commission ("UTC") last year cleared some regulatory roadblocks for third-party owners of distributed generation systems such as rooftop solar generators. However, it reserved the question whether such third-party owners are "public service companies" subject to UTC regulation, and has yet to issue an guidance on that question. The Iowa court's conclusion therefore may hold particular sway in this state.

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U.S. Senate Confirms Norman Bay and Cheryl LeFleur as FERC Commissioners

July 15, 2014

The United States Senate today confirmed President Obama's nominations of Cheryl A. LeFleur and Norman Bay to serve on the Federal Energy Regulatory Commission. Commissioner LeFleur has served on the Commission since 2010 and the confirmation will allow her to serve a full five-year term. Mr. Bay will replace former Chairman Jon Wellinghoff.

Mr. Bay has been the Director of FERC's Office of Enforcement since 2009. In that capacity, he was responsible for a substantial rise in that office's profile. For example, as a result of an Office of Enforcement investigation of market manipulation in the West, FERC last year sought nearly $500 million in penalties against Barclays Bank and certain of its power traders, and $410 million against JP Morgan.

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Decoupling: Washington Muddles Toward a New Utility Model

July 15, 2014

Several trends have converged in recent years to put traditionally-structured utilities under increasing stress. First, the growth rate of electricity consumption in the United States has steadily declined over the last several decades, to the point that the Energy Information Administration ("EIA") recently projected consumption in the future will grow at less than one percent annually. Second, limits on greenhouse gas emissions and other environmental regulations place increasing economic pressure on traditional central-station generation, especially coal-fired plants. Third, economic trends, including steady declines in prices for equipment and state policies favoring renewable generation, make distributed generation and other alternatives to power from traditional utilities increasingly attractive, especially in high-cost states.

Because traditional utility rates are based on the amount of energy sold (e.g., cents per kWh of electricity sold to the end-use consumer), these trends put utilities in a difficult position. Utilities must finance huge infrastructure investments, including the transformation of the nation's generation fleet, especially aging coal-fired plants, to a low-carbon future and major updates and expansions of the nation's electric transmission system. At the same time, demand for their products is likely to be essentially stagnant, and they face increasing competitive pressure from non-utility alternatives. As a result, predictions of a "utility death spiral" abound.

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"September 16: Pivot Point for the Columbia River Treaty and the Future of the Columbia River Basin": Eric Christensen Publishes Article in "The Water Report"

July 10, 2014

We're proud to announce that GTH partner Eric Christensen has published an article in the July 2014 issue of The Water Report, one of the most respected trade journals among water resource professionals. We've inserted the text below:

SEPTEMBER 16: PIVOT POINT FOR THE COLUMBIA RIVER TREATY
AND THE FUTURE OF THE COLUMBIA RIVER BASIN

By Eric Christensen, Partner Gordon Thomas Honeywell

The Columbia River is the flowing heart of the Pacific Northwest's economy and environment. Major industries including hydroelectric power, irrigation, fisheries, recreation and navigation all depend upon the River. The River supports iconic salmon and steelhead runs that are central to native cultures throughout the Columbia River Basin. While the River is the lifeblood of dozens of communities lining its shores, it can be a grave danger to these same communities, as destructive floods in, for example, 1896 and 1948, demonstrate.

Managing the river to support multiple, often-competing uses, while managing floods and protecting water quality, presents mammoth challenges. Adding to these challenges is the fact that the Columbia Basin occupies two countries, flowing for several hundred miles through Canada before entering the United States. For the last fifty years, the Columbia River Treaty ("CRT") has governed water storage, flood control, and power operations on the Columbia, with profound effects on both sides of the border.

A key treaty milestone is fast approaching: September 16, 2014, marks the first time since 1964 that the parties can provide notice of their intent to terminate the CRT. Anticipating this milestone, extensive consultation processes have been carried out on both sides of the border to develop recommendations on whether the CRT should be terminated or continued and, if continued, under what terms. Within the last few months, the consultations have been completed and recommendations submitted to the federal governments on both sides of the border. Comparing these recommendations reveals that a broad consensus that the CRT should be modernized, but little agreement on what modernization means. How and whether these competing views are resolved will have profound effects throughout the Columbia Basin for decades to come.

THE TREATY AND DEVELOPMENT OF THE COLUMBIA BASIN

The CRT is a product of an era when rivers were viewed in utilitarian terms, and primacy was placed on development to maximize their hydroelectric capacity and navigation potential. On the U.S. side of the border, the idea of comprehensive river development dates to 1925, when Congress amended the Rivers and Harbors Act to require the U.S. Army Corps of Engineers ("COE") to conduct "multiple-use studies on the nation's rivers." The COE completed its study of the Columbia in 1932 and, facing the specter of Depression-era poverty, President Franklin Roosevelt seized upon construction of the Grand Coulee and Bonneville Dams as a means to spur economic development by creating abundant, inexpensive electricity and irrigating the vast Columbia Plateau.
With the completion of Grand Coulee in 1942, attention turned to the next logical site for construction of a major dam, at Libby, Montana. But the Libby dam would flood over forty miles of the Kootenay Valley in British Columbia, making construction an international issue. Then, in 1948, a major Columbia River flood destroyed Vanport, then the second-largest city in Oregon, killing fifteen people. Flood control had not been a major consideration in early planning efforts, but the Vanport flood dramatically highlighted the need for flood storage. But potential dam sites on the U.S. side of the border offered relatively limited opportunities for storage, creating another international issue.

On the Canadian side of the border, similar pressures for river development were unfolding, culminating in the election of WAC Bennett as Premier of British Columbia in 1952. Bennett would serve for two decades, easily the longest tenure of any B.C. Premier. Bennett advocated for broad-scale development of British Columbia's natural resources, including its vast water resources. He advanced a "Two Rivers Policy," with major hydroelectric and water storage reservoirs to be constructed on the Columbia and Peace Rivers, and created the British Columbia Hydro and Power Authority ("BC Hydro") to carry out this work. Further, quirks of hydrology and topography mean that 50% of the Basin's flood storage capacity lies in Canada even though only 15% of the Basin's area lies north of the border. It thus became clear to both sides that agreement on a framework for River development between the two countries was necessary.
For much of this period, beginning in 1943, the two countries cooperatively studied Columbia River development through the International Joint Commission. The Commission's plan, finally delivered in 1959, laid the groundwork for comprehensive development of the River and for the CRT, which was finalized in 1961.

THE FUNDAMENTAL BARGAIN OF THE COLUMBIA RIVER TREATY

The CRT addresses a basic fact of Columbia River geography: Storage on the River is concentrated in Canada, while hydropower production is concentrated in the United States. For this reason, flood control in the United States depends heavily on storage operations in Canada. Further, there is a strong interdependence between Canadian and U.S. hydroelectric dams operating on the same river. Hence, the CRT can best be understood as encapsulating two basic principles. First, Canada provides flood control benefits to the United States and the United States pays Canada for these benefits. Second, coordinated operation of Canada's storage reservoirs, carried out by the bi-national Permanent Engineering Board, allows power output from dams in the United States to be optimized, and the countries split the benefits of this additional downstream power. Canada's share of these downstream power benefits is known as the "Canadian Entitlement."

With these principles established, the CRT paved the way for four major dams, three in Canada and one in the United States. The three Canadian dams (Mica, Arrow/Keenleyside, and Duncan) would create 15.5 million acre-feet ("MAF") of storage. The United States was authorized to construct Libby Dam on the Kootenai River in Montana, with nearly 5 MAF of storage.

The CRT did not provide financing for the Canadian dams, which created a stumbling block for treaty ratification in Canada. Recognizing that power from the Canadian dams would not be needed in British Columbia for decades, WAC Bennett suggested that the power could be sold to utilities in the United States. A large group of Pacific Northwest utilities took up this offer, agreeing in the Columbia Power Storage Exchange Agreement ("CPSE") to pay approximately $254 million for the first thirty years of the Canadian Entitlement. The CSPE thus financed construction of the Canadian dams, removing the final barrier to ratification of the CRT. On September 16, 1964, in a ceremony at the Peace Arch International Park attended by a crowd of 10,000, U.S. President Lyndon Johnson and Canadian Prime Minister Lester Pearson signed the CRT, the culmination of a two-decade effort to create a bi-national plan for development of the River.

The parties agreed that the CRT should remain in place for no less than sixty years and, after that, would continue unless terminated, with ten years' notice required for termination. Thus, September 16, 2014, is a critical date for the CRT. This is the first date upon which either side can provide the required ten-year notice of termination upon expiration of the CRT's 60-year minimum term, which runs through September 16, 2024.
In preparation for September 16, the the COE and the Bonneville Power Administration ("BPA")(referred to jointly as the "U.S. Entity" in CRT parlance) have conducted extensive technical studies and, as noted above, broad outreach programs to determine whether to seek termination, modification, or other changes to the CRT. The Government of British Columbia had carried out a similar undertaking north of the border.

UPDATING THE CRT

The CRT is a product of its times, focusing almost exclusively on acre-feet of storage and megawatt-hours of power. To Twenty-First Century readers, the most striking feature of the CRT is its failure to even mention fisheries, wildlife, water quality, and the other environmental issues, whether in the context of national environmental policy or Native American rights. As those involved in Pacific Northwest water and power issues are well aware, since the passage of landmark legislation such as the Endangered Species Act and Clean Water Act in the 1970s, the region has struggled mightily to maintain the enormous economic benefits provided by the Columbia Basin dams while recovering endangered salmon and steelhead runs, improving water quality, and meeting other mandates arising from modern environmental legislation. And, as discussed below, landmark court rulings on both sides of the border have greatly expanded the role Native American tribes play in natural resources and environmental policy.

Hence, it is not surprising that the consultation processes on both sides of the border resulted in recommendations that ecosystem values be recognized and integrated into the CRT. On the U.S. side, the U.S. Entity Regional Recommendation for the Future of the Columbia River Treaty After 2024 ("U.S. Recommendation"), adopted in December 2013, concludes that "ecosystem-based functions" should be a recognized, shared value of the CRT. On the Canadian side, the Columbia River Treaty Review B.C. Decision ("B.C. Recommendation"), adopted in March 2014, also espouses the principle that ecosystem benefits should be recognized, accounted for, and equitably shared between the two countries. But exactly what is included in "ecosystem functions" and how those functions should be treated in the CRT is largely left to the imagination.
On other issues, the Recommendations diverge. Each side claims that the CRT in its current form provides inadequate compensation to that side and that the other side receives excessive benefits. The Recommendations reflect a similar gulf between the two countries on an array critical issues. These include:

Flood Control
Upon ratification of the CRT in 1964, the United States made a one-time payment to Canada of $64.4 million for defined flood control benefits for the sixty-year period ending in 2024 using the 15.5 MAF of storage constructed under the CRT. After 2024, the CRT's flood control regime changes substantially, even if the Treaty is not modified. Rather than providing defined flood control benefits, flood control will be based upon ill-defined treaty provisions requiring Canada to provide flood control when "called upon" by the United States, but only after the United States makes "effective use" of its own storage reservoirs for flood management. If the U.S. calls upon Canada for flood control, the U.S. must pay both the direct costs and opportunity costs, in the form of forgone power production, incurred by Canada for flood control operations. The CRT does not, however, provide specifics as to how any of these terms are defined, and it has become clear that the two sides interpret the terms differently.

An examination of the Recommendations reveals fundamentally different views about how flood management should be handled after 2024. Perhaps the most obvious difference lies in basic flood management objectives. The B.C. Recommendation advocates a 600,000 cubic feet per second ("cfs") flood control target, while the U.S. Recommendation argues the existing flood control target, 450,000 cfs, should be retained. The lower target, 450,000 cfs, is considered the threshold at which flood damage begins to occur on the U.S. portion of the River. By contrast, 600,000 cfs is the threshold at which major flood damage starts to occur. Adoption of the 600,000 cfs target, then, implies that the United States would have to make substantial investments in flood management or bear increased costs from flood damage if the Canadian Recommendations on this issue are adopted.

The flood control regime adopted after 2024 could also substantially limit the use of U.S. reservoir storage capacity to support irrigation and other current river uses. Studies conducted by the U.S. Entity suggest that "effective use" of U.S. storage capacity will require reservoirs to be drawn down more often and to lower levels than they are now, which could impair the ability of those reservoirs to meet irrigation demands, as well as demands for navigation, fisheries, and other in-river uses. The magnitude of these impacts depends heavily upon how "effective use" is defined. In addition, these impacts are substantially greater if the U.S. maintains a 450,000 cfs flood management target for flood management, rather than shifting to a 600,000 cfs target. On the other hand, reducing reliance on Canadian storage reservoirs will require less fluctuation of reservoir levels and fewer drawdowns, reducing associated impacts on navigation, recreation, and dust levels (from exposed reservoir sediments) in the Canadian portion of the Basin.

The Canadian Entitlement and Power Production

While flood control under the CRT may change drastically in 2024, the same is not true of river coordination. Unless the CRT is terminated or renegotiated, coordinated river operations will continue much as they have under the Treaty to date. From the U.S. perspective, this is problematic because the CRT includes at least two outdated assumptions. First, treaty negotiators assumed that regional base-load generation would increasingly be supplied by coal- and nuclear-fired plants, with hydro shifting to meet peak demands, but construction of thermal plants fell far short of those expectations. Second, the CRT does not recognize constraints arising from U.S. environmental laws such as the Endangered Species Act. As a result, the Canadian Entitlement is now out of line with the actual benefits of coordinated river operation, creating substantial costs for the United States. The U.S. Entity estimates that, for the period from August 2010 to July 2011, the "Canadian Entitlement" provided 535.7 megawatts ("MW") of annual average energy to Canada, delivered at rates up to 1,316 MW, valued at between $250 million and $350 million annually.

But, according to a U.S. Entity study, fisheries conservation requirements have reduced the output of the U.S. hydro system by 1520 to 1655 MW on an annual average, and the benefits of coordinated river operation have fallen accordingly. If the Treaty were terminated, with the resulting loss of coordinated river operations, the study concluded that output of the U.S. hydro system would drop by about 90-94 MW on an annual average, when environmental constraints are accounted for. This represents less than one percent of the output of the U.S. system. By contrast, the study estimated the Canadian Entitlement in 2024 would be about 470 average MW using the current CRT calculation. Accordingly, the U.S. Recommendation concludes that "Canada is deriving substantially greater value from coordinated power operations than the United States," and "rebalancing" the Canadian Entitlement is necessary.

The B.C. Recommendation, by contrast, argues that the Canadian Entitlement is the sole form of compensation currently operating under the CRT, and that the level of benefits provided does not reflect the "full range" of "impacts in British Columbia." In particular, British Columbia has argued that the U.S. receives huge flood control benefits, with avoided damages in the billions of dollars. On the other hand, the burdens created by the CRT have fallen disproportionately on Southeast British Columbia, where 231 square miles of valley bottom land were flooded, communities displaced, and economies disrupted by construction of the three Canadian CRT dams. With expiration of the CSPE in the mid-1990s, the Canadian Entitlement began flowing back to Canada and B.C.'s Parliament directed that funds from the Canadian Entitlement be used to fund the Columbia Basin Trust, which funds mitigation of impacts of dam construction and operation in southeast British Columbia.

Reducing the Canadian Entitlement, as the U.S. Entity recommends, would thus reduce funding for mitigation efforts in the most heavily affected regions of British Columbia, creating a potentially serious political conflict. One solution may be to direct U.S. payments for flood control to the Columbia Basin Trust. The U.S. Entity estimates that compensation for lost hydropower production would be in the range of $4 million to $34 million for each time Canada is requested to assist with flood management under the "called upon" regime.

A similar disconnect between costs and beneficiaries also exists on the U.S. side of the border. The costs of the Canadian Entitlement are borne by BPA, and therefore ultimately fall upon BPA's power customers, primarily public power entities such as Public Utility Districts, municipal power agencies, and rural electric cooperatives. But flood control primarily benefits communities along the River, and BPA power customers are, for the most part, located far from areas affected by Columbia River flooding. This divergence between beneficiaries and those who bear the costs could create strong opposition to the CRT among U.S. power interests. The U.S. Recommendation therefore suggests that "U.S. interests should ensure that costs associated with any Treaty operation are aligned with the appropriate party."

Ecosystem Functions

The U.S. Recommendation urges the modernized CRT to provide for "stream-flows from Canada with appropriate timing, quantity, and water quality to promote productive populations of anadromous fish," and also to provide reservoir conditions that support healthy fish and wildlife populations. The U.S. Recommendation also states that stream-flows should be part of the "long-term assurance of eco-system based function" provided by the CRT, rather than being negotiated on a yearly basis as part of annual operating plans developed by the U.S. and Canadian Entities, as currently occurs. The U.S. Recommendation also advocates a joint program to study and possibly implement fish passage at the Chief Joseph and Grand Coulee dams in order to restore anadromous fish runs in the Canadian portion of the Columbia River Basin.
The B.C. Recommendations concerning ecosystem functions are considerably less detailed, suggesting only that the CRT recognize and account for ecosystem functions, and that such functions are "an important consideration" in planning and implementing the CRT. On the issue of Grand Coulee fish passage, the B.C. Recommendation concludes that this is "not a Treaty issue" because salmon migration into Canada was eliminated at Grand Coulee in 1938, well before the CRT was ratified. Fish passage is therefore "the responsibility of each country regarding their respective infrastructure."

Other Resources

Both the U.S. and B.C. Recommendations urge broader recognition of benefits, including navigation, recreation, agricultural, and municipal uses. True to form, the U.S. Recommendation includes greater detail, noting that studies conducted by the U.S. Entity identified the potential for additional fall and winter storage in Canada, which could be used to support downstream irrigation, navigation, industrial, and in-stream uses in spring and summer. The B.C. Recommendation merely sets forth the principle that these are among the downstream uses that should be recognized, accounted for, and "shared equitably" between the two countries.

The difficult for CRT negotiators is, of course, that these different river uses often compete. For example, water retained in the river for navigation or devoted to municipal uses cannot be used by irrigators. Indeed, a great deal of controversy has arisen in recent decades over the use of increased flows to encourage in-stream migration of juvenile salmon because the water devoted to fish flows is generally unavailable to generate power or to support other economic uses of the River.

THE FUTURE OF THE TREATY

In both countries, the respective Recommendations have now been submitted to the each country's federal governments, and primary responsibility now lies with the U.S. Department of State and the Canadian Foreign Ministry to determine next steps. And, despite differences on specific issues, it is unlikely that either country will immediately seek to terminate the CRT. In fact, both countries recognize that the CRT has been, on the whole, a resounding success, and both Recommendations therefore argue that the CRT should be reformed, but should not be terminated. The U.S. Recommendation, however, places an important limit on this principle, suggesting, somewhat ominously, that if agreement on "key aspects of a modernized Treaty" is not attained by 2015, "other options" to modernize the CRT "should be evaluated."

The outcome of the negotiations will be strongly influenced by several factors that were not present when the CRT was originally negotiated in the 1950s and '60s. These include:

Native American Rights

Because they have been accorded improved legal and political status in the last half-century, Native Americans on both sides of the border will have much greater influence on modernization of the CRT than on the original negotiations. In the United States, court decisions such as the landmark "Boldt decision" (United States v. Washington, 384 F. Supp. 312 (W.D. Wash. 1974), aff'd, 526 F.2d 676 (9th Cir. 1975)) read treaty rights broadly, giving tribes in the United States considerable leverage over decisions involving traditional fisheries and other natural resources. In Canada, similar legal developments, culminating in the 1997 Delgamuukw decision (Delgamuukw v. British Columbia, 3 S.C.R. 1010 (1997)), accorded First Nations substantial legal rights related to land and natural resources, requiring Canadian federal and provincial governments to consult with First Nations on a nation-to-nation basis.

Both Canadian First Nations and Native American tribes in the United States view the CRT as an avenue to improve and protect salmon runs and other natural resources, as well as cultural resources on both sides of the border. It is therefore unsurprising that the Recommendations from both sides of the border contain numerous references to the need for improving protection of cultural and natural resources important to First Nations and Native American tribes.

Climate Change and Adaptive Management

Absent when the CRT was first negotiated, climate change is now the subject of ubiquitous study and political controversy. Current climate models suggest that, while overall precipitation levels in the Columbia River Basin area likely to remain relatively constant as the region's climate warms, a substantial shift in river flows will likely occur, with increasing winter flows and a smaller spring freshet as increasing amounts of winter precipitation fall as rain rather than mountain snow, especially in the U.S. portion of the Basin. If stream-flows change as predicted, significant changes in flood control, storage, and hydroelectric operations will be required. Hence, the Recommendations from both sides of the border counsel in favor of flexibility to adapt to climate-induced stream-flow changes.

The history of the CRT also suggests the need for adaptability. Much of the dissatisfaction with the CRT today arises from predictions made in the 1960s about, for example, the value of the Canadian Entitlement, that have turned out to be incorrect by a wide margin. As the Recommendations make clear, if the formulas used to calculate benefits under the CRT diverge from the actual, on-the-ground benefits provided by the CRT, political opposition will arise from interests that perceive they are being over-charged for the benefits they receive. To make the CRT politically viable over the long term, then, negotiators should concentrate on developing benefits formulas that incorporate the changing values of Treaty benefits. For example, downstream power benefits should be calculated using the regional market price indices that have developed in the power industry in the last three decades. These indices were unavailable when the CRT was originally negotiated, but now can be incorporated into the Treaty as a means to ensure that power benefits reflect the changing value of power over time, and therefore keep power-related benefit payments in line with actual value of the power generated or transferred.

Future Duration of the Treaty

Another issue raised by the Recommendations is the duration the CRT after 2024. Neither Recommendation endorses a specific period, but both suggest that the post-2024 CRT should remain in place for a considerable period. The B.C. Recommendation states that the CRT after 2024 "should be fixed for a sufficient duration to provide planning and operational certainty" while including "adaptive mechanisms" to account for changes over time. The U.S. Recommendation similarly urges that the "minimum duration" of the post-2024 CRT "should be long enough to allow each country to rely on the Treaty's planned operations and benefits for purposes of managing their long-range budgets, resource plans, and investments," but should also incorporate "adaptive management" mechanisms to allow necessary course corrections over time.

Because investments in major water and power infrastructure generally involve assets with an extremely long life and long-term amortization, these statements imply that the duration of the post-2024 CRT should be in the range of 30-50 years to provide the assurances for such long-term investments. But neither country is likely to commit to a new multi-decade term unless negotiated-for benefits will remain in line with actual benefits over the long term. This underscores the importance of the benefits formulas and other adaptive management provisions, discussed above, that anticipate long-term changes in relevant parameters and account for those changes in a manner fair and reasonably predictable to both sides.

OPTIONS FOR TREATY MODIFICATION

The CRT could be terminated and a completely new Treaty negotiated, signed by the President, with two-thirds majority approval by the U.S. Senate under the Treaty Clause of the U.S. Constitution, with parallel political processes in Canada. Following this course would present substantial and obvious political perils. Fortunately, there are a number of options available to negotiators other than allow the CRT to continue in its current form indefinitely or terminating it and negotiating an entirely new Treaty.
The menu of options available to negotiators includes, for example, an exchange of notes, reflecting agreement between the two nations on specific issues. Such an exchange of notes occurred when the CRT was ratified in 1964, and was aimed at clarifying some portions of the 1961 text. The CRT also includes Annexes and Protocols that set forth details on flood control, downstream power benefits calculations, and other issues, which could be modified without terminating the CRT itself. Similarly, contracts along the lines of the CSPE or implementation legislation in one or both countries could be used as the vehicle for modernization, or to address specific problems, without requiring Treaty termination.

These options have important differences involving, for example, whether formal legislative approval is required, how the agreement is enforced, and how durable the agreement would be over time. Fortunately, the range of options available will allow negotiators to select one or more options that are appropriate for the particular issues being addressed, the need for permanence, and the desire for formal political approval.

NON-TREATY STORAGE AGREEMENT

When Canada actually constructed the Mica Dam, it included an additional 5 MAF of storage that was not required under the CRT. This is referred to as "Non-Treaty Storage." Use of the Non-Treaty Storage has been governed for several decades under a series of agreements between the U.S. Entity and BC Hydro. The most recent Non-Treaty Storage Agreement ("NTSA"), signed in 2012, governs operation of the Non-Treaty Storage through September 15, 2024, so will end simultaneously with the expiration of the CRT's 60-year minimum term. The 2012 NTSA is remarkable in that it generated almost no controversy, a nearly unheard-of feat for any BPA matter involving significant water and power resources. It also addresses many of the same issues that the Recommendations identify as concerns, and therefore may serve as a model for resolution of those issues in the post-2024 CRT.

The NTSA provides the BPA and BC Hydro each have continuing access to 1.5 MAF of Mica's active storage, and BC Hydro may make available to BPA an additional 1 MAF from the Mica reservoir at its discretion. Except for provisions addressing dry years, all transactions are by mutual agreement and are coordinated on a weekly basis. Canada receives an equitable share of the downstream energy created by coordinated use of Non-Treaty Storage, with value determined by referenced to published energy price indices for the Mid-Columbia energy trading hub. BPA has used the added flexibility provided by the NTSA to benefit, for example, fisheries in the U.S., and to enhance power production at U.S. hydroelectric facilities.

CONCLUSION

September 16 marks a key juncture in the history of the Columbia River and surrounding regions. That date marks the opening of a process that is likely to result in substantial changes to the bi-national framework that has successfully governed the Columbia River for the last half-century. September 16 therefore represents a literally once-in-a-lifetime opportunity to shape the future of the River and the region through modernization of the CRT. The Recommendations developed by the two sides document major differences on a range of important issues. Over the long course of CRT negotiation and implementation, however, both sides have shown a remarkable capacity for identifying creative approaches to resolving differences and creating mutual benefits. There is good reason to believe this spirit of creative problem solving can help bridge the gaps between the two sides. Whether and how these solutions are developed will have profound and long-lasting impacts on the River, its resources, and the millions of people who depend on those resources.

Seventh Circuit Rejects FERC's Cost-Spreading Mechanism for High-Voltage Transmission, Raising Questions for the Pacific Northwest

July 1, 2014

Last week, the U.S. Court of Appeals for the Seventh Circuit once again rejected a cost-spreading mechanism developed by the Federal Energy Regulatory Commission ("FERC") for high-voltage transmission facilities constructed in the PJM Interconnection. While PJM is located on the opposite coast, the Seventh Circuit's decision may nonetheless have important implications for transmission construction here in the Pacific Northwest.

The basic problem FERC has wrestled with is that utilities in the eastern end of PJM's footprint in the heavily-populated mid-Atlantic region will benefit disproportionately from construction of high-voltage transmission. By contrast, utilities in the western portion of PJM will receive only modest benefits from high-voltage transmission construction, which is currently driven largely by the need to improve reliability in the east. FERC has been wrestling with this problem for more than seven years, with final resolution likely several years away. In the Northwest, the problem is a mirror image of PJM -- congestion and reliability problems are largely in population centers along the West Coast, meaning that high-voltage transmission upgrades are likely to disproportionately benefit utilities serving these areas.

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U.S. Supreme Court Denies Review of California Low-Carbon Fuel Standard

June 30, 2014

The U.S. Supreme Court today denied several petitions seeking review of the Ninth Circuit's decision upholding California's Low-Carbon Fuel Standard ("LCFS") against claims that the LCFS violates the Commerce Clause of the U.S. Constitution. While today's decision makes the Ninth Circuit's decision final, the underlying issue -- how far individual states can go to regulate greenhouse gases and promote renewable energy without violating the Commerce Clause -- will remain the subject of intense litigation. For example, recent lower-court decisions from Colorado and Minnesota, reaching apparently opposite conclusions on the constitutionality of state renewable portfolio requirements, suggest that the Supreme Court may ultimately have to step into the fray.

As we've previously reported here and here, California's LCFS requires petroleum distributors in the state to reduce the carbon intensity of motor fuels they sell by blending them with biofuels or other lower-carbon alternatives. The LCFS contains a complex mechanism which uses a life-cycle analysis to assign carbon intensity scores to different biofuels production processes, providing a significant economic advantage to fuels with lower carbon intensity scores. This mechanism was challenged by a coalition of out-of-state alcohol fuels producers and trade groups, who argued that California's mechanism discriminates against them on its face by assigning higher carbon intensity scores to out-of-state producers than in-state producers. California rebutted these claims by asserting that its life-cycle analysis model is location-neutral and reflects the reality that production of alcohol fuels in some areas has a greater carbon footprint than fuels produced within California. Alcohol fuels produced in the Midwest, for example, generally have a higher carbon footprint than fuels produced within California because Midwest biofuels are produced using electricity from a grid that relies more heavily on coal-fired plants and because of the lengthy transportation routes required to deliver Midwest fuels into California add to the out-of-state fuel's carbon intensity.

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Six GTH Energy and Environmental Named Washington "Super Lawyers"

June 23, 2014

We're pleased to announce that nineteen Gordon Thomas Honeywell attorneys have been named 2014 Washington Super Lawyers, including six members of our Energy, Telecommunications & Utilities and Environmental & Natural Resources practice groups.

The "Super Lawyers" practicing in our energy, environmental, and natural resources areas are Margaret Archer, Eric Christensen, Don Cohen, Brad Jones, and Bill Lynn. In addition, practice member Bill West has been named a "Rising Star."

"Super Lawyers" are selected through a process of peer review and independent evaluation, and represent the top five percent of practitioners in the State of Washington.

FERC Approves Energy Imbalance Market Tariffs, Paving Way for October Start-Up

June 20, 2014

At its monthly meeting yesterday, the Federal Energy Regulatory Commission ("FERC") approved tariffs that will allow the western Energy Imbalance Market ("EIM") to open as planned on October 1, 2014. The EIM is designed to allow economic dispatch at five-minute intervals of energy balancing resources in the footprint of participating utilities. The EIM is one of a number of initiatives undertaken by utilities in the West to address the problems created by the rapid expansion of non-dispatchable wind and solar resources. Because these resources produce output that can be both highly variable and unpredictable, they have created increasing demand for balancing resources that can respond rapidly to changes in generation output to maintain the balance between generation supply and electric demand necessary for reliable operation of the electric system.

Yesterday's FERC orders approve the EIM proposed jointly by PacifiCorp and the California Independent System Operator ("Cal-ISO"). The PacifiCorp-ISO EIM will employ the Cal-ISO's existing five-minute market mechanism to dispatch balancing resources in the EIM's footprint. Initially, the EIM will dispatch resources within California, as well as within the two balancing authorities operated by PacifiCorp, which are centered on its service territories in the Pacific Northwest and Utah. Participation in the EIM is voluntary and the system is designed to allow expansion through addition of new utility participants.

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Next Frontiers in Climate Litigation: Adaptation and Ocean Acidification

June 11, 2014

Recent legal developments in climate litigation and regulation suggest that the legal landscape related to climate change is continuing to evolve, with adaptation to climate change and ocean acidification recently taking center stage. Adaptation is the idea that cities, utilities, and the builders and owners of other critical infrastructure should take steps to protect the public from rising sea levels, increasingly intense storms, and other impacts predicted by climate science. Ocean acidification is, in addition to climate disruption, a side-effect of increasing atmospheric carbon concentrations. As carbon from the atmosphere is absorbed into ocean water, the acidity of the ocean rises, with potentially serious consequences for ocean food chains and fisheries. As reported in a lengthy series published by the Seattle Times, the effects of increased ocean acidity are already beginning to appear along Washington's coast.

Climate adaption has come to the fore recently in two high-profile matters. First, the New York Public Service Commission ("NYPSC") recently approved a rate case settlement involving Consolidated Edison that will require Con Ed to undertake state-of-the-art planning and hardening of its assets to protect them from the increasingly severe weather events predicted to result from a changing climate. The hardening measures are predicted to cost approximately $1 billion. Because of its highly-criticized response to Hurricane Sandy, Con Ed may be have been an easy target, but it is likely that the NYPSC's action will serve as a model for other utility commissions concerned about utlity storm response and the resiliency of the electric system in the face of increasingly severe weather events. The NYPSC matter is nicely summarized here by Columbia Law School's Center for Climate Change Law.

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EPA Proposes Limits on Carbon Dioxide From Power Plants: What It Means for the Pacific Northwest

June 6, 2014

The U.S. Environmental Protection Agency this week issued is long-anticipated proposal to limit carbon dioxide from power plants, dubbed the "Clean Power Plan." Predictably, both industry groups and environmental interests attacked the plan, in some cases even before it was released. A careful review of the proposal suggests, however, that the impacts of the rule, if adopted, are likely to be relatively modest in the Pacific Northwest, chiefly by placing additional economic pressure on already beleaguered coal-fired plants in Montana and Wyoming, while adding the pressure of federal law to break the log-jam in Olympia regarding climate-related legislation. The flexibility provided to states to comply with carbon dioxide limitations also lays the groundwork for interstate cooperation to identify least-cost solutions and may create new and lucrative opportunities for companies involved in energy conservation, clean tech, renewable energy and a variety of other industries where carbon dioxide emissions might be reduced at relatively little cost.

The proposed rule has been summarized in greater detail elsewhere. In brief, the proposal at its core would require existing power plants to reduce carbon dioxide emissions by 30 percent over 2005 levels by 2030, with interim limits that would come into force in 2020. The proposal establishes state-specific goals for carbon dioxide emissions, but provides states considerable flexibility to meet these goals using four "building blocks" -- improving power plant heat rates, improving energy conservation, dispatching power from natural gas and other less carbon-intensive resources rather than from coal generation, and encouraging the construction and dispatch of renewable energy resources. The proposal also encourages interstate cooperation and allows for trading of carbon-reduction credits, as already occurs, for example, in the Northeast's RGGI program. The EPA's final rule is due by June 2015, with state implementation plans to be finalized by June 2016. Litigation over the rule is certain to occur, so it is unclear whether these deadlines will be met.

The choice of a 2005 baseline, rather than the 1990 baseline generally used in discussions of greenhouse gas reductions, is important because U.S. GHG emissions peaked in that year and have declined 9% overall since then, while power plant emissions have declined 16%, primarily because the "fracking" boom has created cheap natural gas, which has displaced significant amounts of coal used for electricity generation. Georgetown University's Climate Center has published a useful table, which provides an indication of reductions required from 2012 emissions levels rather than 2005 levels.

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Bonneville Hiring Fiasco: BPA Watch Provides a Useful Chronology

May 28, 2014

Last summer, the Northwest power industry was stunned by the Department of Energy's sudden and unanticipated suspensions of two highly-respected top-tier executives at the Bonneville Power Administration, Administrator Bill Drummond and Chief Operating Officer Anita Decker. This week, Seattle attorney Dan Seligman has released a lengthy and carefully researched chronology of the problems in BPA's compliance with federally-mandated veterans preferences that ultimately caused the suspensions. Seligman's work, based on an extensive review of publicly-available documents, helps makes sense of what appeared at the time to be a bolt from the blue.

If you have any questions about BPA, the energy industry in the Pacific Northwest, or other matters involving the energy or environmental law, please contact a member of GTH's Energy, Telecommunications, and Utilities or Environment & Natural Resources practice groups. We're proud that our partner Jim Waldo was recently named 2013 Lawyer of the Year for Energy and Natural Resources Law, and practice group members Don Cohen, Bill Lynn, and Brad Jones were all named among Seattle's Best Lawyers. Disclaimer: Links to Mr. Seligman's work are provided as a convenience to our readers. GTH takes no responsibility for the content of Mr. Seligman's work or the contents of BPA Watch.