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Join GTH at the Washington Future Energy Conference

September 9, 2014

Please join us at the Washington Future Energy Conference on November 5. Gordon Thomas Honeywell is proud to be a major sponsor of this event. Now in its fifth year, the Future Energy Conference brings together energy innovators, utilities, scientists, investors, and many others to discuss the future of the energy industry in our state.

Speakers include GTH partner Eric Christensen, who will moderate a panel discussing the electrification of Washington's transportation system. The panel will include Steve Marshall of the Center for Advanced Transportation and Energy Solutions, Charles Knutson, Senior Policy Advisor to Washington Governor Jay Inslee, and John McCoy, Legislative Director for the Seattle Electric Vehicle Association.

We look forward to seeing you November 5.

Pot and Power: Power Planning Council Estimates Demand Growth and Conservation Potential

September 9, 2014

As Washington's experiment in legalization of recreational marijuana use moves gradually toward full implementation, the consequences for Washington's utilities are begining to come into focus. Confirming more general studies we've discussed previously, the Northwest Power & Conservation Council ("NPCC") this week will be discussing a staff report that quantifies the range of increases in electric consumption that may arise from marijuana legalization in Washington, as well as other Northwest states that may follow Washington's lead.

Consistent with other studies, the NPCC study recognizes that, although indoor marijuana cultivation offers a number of advantages to the grower, it is extremely energy intensive. This fact is dramatically illustrated by comparing the energy intensity of indoor marijuana production with the energy intensity of aluminum production, perhaps the most energy-intensive of the Northwest's traditional industries. Aluminum production, the study notes, requires roughly 16 kWh of electricity to produce one kilogram of aluminum, while indoor grow operations require a whopping 4,000-6,000 kWh to produce one kilogram of marijuana. All told, the NPCC estimates, marijuana legalization in Washington will produce an increase in electricity consumption in the range of 60 to 160 average MW over the next two decades, while demand will grow approximately 240 aMW in the four-state region by 2035. In addition, the study notes, the demand from grow operations varies significantly over the course of the day, and a proliferation of grow operations may therefore add to utility peak-hour demands.

Continue reading "Pot and Power: Power Planning Council Estimates Demand Growth and Conservation Potential" »

U.S. Appeals Court Concludes FERC Lacks Authority to Fine Federal Entities for Reliability Violations

August 22, 2014

In a ruling that could have far-reaching implications for the electric reliability here in the Pacific Northwest, the U.S. Court of Appeals for the District of Columbia Circuit today found that the Federal Power Act does not authorize the Southwest Power Administration ("SWPA") to pay fines for admitted violations of mandatory electric reliability standards.

The decision turns on the doctrine of sovereign immunity. In its modern form, the doctrine bars federal government liability unless Congress provides a clearly-expressed statutory waiver of sovereign immunity. Today's decision applies this doctrine to Section 215 of the Federal Power Act, the provision Congress added to the Act in 2005 to create a system of mandatory electric reliability standards. Section 215 authorizes the Federal Energy Regulatory Commission ("FERC") to impose fines on "users, owners and operators" of the Bulk Electric System if they violate electric reliability standards developed by the North American Electric Reliability Corporation ("NERC"). Carefully parsing the language of Section 215, today's decision finds no clear expression of Congressional intent to allow federal entities such as SWPA to pay fines for violations of reliability standards.

Continue reading "U.S. Appeals Court Concludes FERC Lacks Authority to Fine Federal Entities for Reliability Violations" »

Regulating Emergency Generators: EPA Denies Rehearing of RICE Rule, Appeals Court is Next Stop

August 20, 2014

On August 15, the U.S. Environmental Protection Agency ("EPA") issued a notice denying petitions for rehearing of its new rules governing air emissions from stationary Reciprocating Internal Combustion Engines ("RICE"). RICE, especially diesel engines, are widely used for emergency backup generation for hospitals, factories, and other facilities requiring an uninterrupted supply of power. They are also an important source of power to stabilize the electric grid in certain types of emergencies. Developments concerning the RICE emissions rule are therefore of great concern to electric utilities and a multitude of end-use electric consumers who rely on diesel back-up generators.

The rehearing petitions stem from EPA's 2010 proposal to extend its regulation of hazardous air pollutants emitted by stationary RICE from the previous 500 horsepower limit down to engines as small as 100 HP. As we reported early last year, in response to concerns related to the mismatch between the proposed RICE rule and NERC reliability standards, EPA modified the proposed rules to allow generators that have not been retrofitted with expensive pollution control equipment to operate for up to 100 hours per year during declared electrical emergencies, and for such generators to operate for up to 50 hours per year to prevent voltage collapse or overloads in local transmission or distribution systems.

Continue reading "Regulating Emergency Generators: EPA Denies Rehearing of RICE Rule, Appeals Court is Next Stop" »

Milestone in Transmission Regulation: U.S. Court of Appeals Upholds Order No. 1000

August 18, 2014

On Friday, the U.S. Court of Appeals for the District of Columbia Circuit rejected a host of challenges to the Federal Energy Regulatory Commission's ("FERC") Order No. 1000, upholding the order in its entirety. As we've previously discussed, Order No. 1000 aims to create a level regulatory playing field for independent transmission developers, thus encouraging new sources of badly-needed investment in the nation's transmission infrastructure. The D.C. Circuit's 97-page opinion upholding the order represents an important milestone in the evolution of regulation in the electric industry.

Order No. 1000 changed the planning and cost allocation regime for interstate transmission projects in three major requirements:

(1) Each FERC-jurisdictional transmission provider must participate in a regional transmission planning process that identifies the most cost-effective regional and inter-regional transmission projects, and provides for a method of cost-allocation for the selected projects meeting six specific principles. Independent transmission developers and other non-incumbents need not participate in this process, but it must be open to their participation.

(2) The planning process must provide for transmission expansion driven by public policy requirements, along with economic and reliability needs. State renewable portfolio standards and other public policies favoring the development of renewable energy are the largest public policy factor driving the need for new transmission.

(3) The federal "right of first refusal" ("ROFR") must be removed from FERC-approved transmission tariffs. The ROFR allows incumbent utilities to construct transmission projects proposed by other entities within the incumbents' service territories. FERC views this as a major barrier to entry for independent transmission developers, whose investment in planning and permitting is essentially wiped out if the incumbent exercises its ROFR. Although not common in the Northwest, the ROFR requirement proved extremely controversial in other parts of the country.

Continue reading "Milestone in Transmission Regulation: U.S. Court of Appeals Upholds Order No. 1000" »

Eric Christensen Quoted in EnergyWire Article on Utility Service to Marijuana Producers

August 11, 2014

GTH Partner Eric Christensen was quoted in Friday's lead EnergyWire article, which addresses the problems utilities face in serving energy-hungry marijuana grow operations under new marijuana legalization regimes in Washington and Colorado. The article can be found here. EnergyWire is the energy-centered daily trade magazine of highly-respected Environment & Energy Publishing.

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!

"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.

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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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.

Who Holds the Almighty and Powerful Ring? 13 Steps for Utility Cyber Security Protection

May 13, 2014

We are happy to announce that Eric Christensen and Maj. Gen. (Ret.) Tim Lowenberg of GTH-Governmental Affairs have published the cover story in the May 2014 Northwest Public Power Association Bulletin. Here is a link to the article on the NWPPA's website. The text of the article follows:

Cover Story
Who Holds the Almighty and Powerful Ring in the Cyber World?
Thirteen Steps for Utility Cybersecurity Protection


By
Eric Christensen, Partner
Gordon Thomas Honeywell

and

Maj. Gen. (Ret.) Tim Lowenberg, Vice President
Gordon Thomas Honeywell Governmental Affairs

While computer and internet technology create enormous benefits for twenty-first century utilities, they also expose utilities to new and sinister cyber threats. For utility managers, entering the cyber world can feel like entering J.R.R. Tolkien's "Middle Earth", a strange land filled with treacherous creatures like orcs, ring-wraiths, and wargs. Like Middle Earth, the cyber world is inhabited by peculiar and threatening forces ranging from amateur hackers to organized criminal enterprises searching for valuable financial information to politically motivated actors and nation-states capable of using malicious computer codes as weapons systems. And like Gollum, the hobbit twisted beyond all recognition by the power of the One Ring, threats in the cyber world often go undetected, arise from nebulous but nefarious motives and can unleash powerful, destructive effects beyond all expectation.

In light of the near-universal consensus among defense analysts, policy makers and computer experts that the electric utility sector is among the most vulnerable of sectors to cyber-attacks, how should utility managers address these threats? We recommend the following thirteen steps that all utilities, regardless of size, should take to mitigate risk in the complex and ever changing world of cyber-security.

Step 1: NIST Cybersecurity Framework
On February 12, 2014, the National Institute of Standards and Technology ("NIST") released the first version of its Framework for Improving Critical Infrastructure Cybersecurity. The Framework, issued in response to President Obama's Executive Order No. 13636, is intended to create common, voluntary industry standards and best practices for addressing cyber-security threats. The Framework provides a standardized approach for identifying cyber-security threats and protecting organizations against those threats through technological fixes and education of management and front-line operators. While the Framework is an ongoing and evolving document, it is a useful starting point for developing a cyber security strategy. The steps we recommend here are consistent with the NIST Framework.

Step 2: NERC CIP Standards
Because they are mandatory and violations can lead to substantial penalties, NERC Reliability Standards are, of course, of primary concern to electric utilities. NERC's Critical Infrastructure Protection ("CIP") standards define utility obligations to address threats in the cyber-security realm and should therefore be a prime focus of every utility. After a long period of flux, the Federal Energy Regulatory Commission ("FERC") in November 2013 adopted Version 5 of the CIP standards, with certain reservations. Utilities with "High and Medium Impact" assets (as defined in NERC's "BES Cyber Asset" definition) must come into compliance with Version 5 by April 2016 and those with "Low Impact" assets must come into compliance by April 2017. Utility managers should therefore pay careful attention to these standards, as well as refinements to the standards now under development in response to FERC's November 2013 order. In addition, NERC is conducting a pilot program with results due in the near future that should provide useful information for utility compliance managers.

Utility managers should also pay close attention to physical security standards. In reaction to damage caused by a sophisticated physical attack on the Metcalf Substation in California's Silicon Valley, FERC on March 7 ordered NERC to develop standards to secure key electrical facilities against physical attack. Compliance with these standards could be extremely expensive. In raising this concern, FERC Commissioner John Norris recently noted that just three utilities reported to him they may have to spend more than $500 million for physical security enhancements in the wake of the Metcalf incident. As is also obvious, under-reaction could prove even more costly for the utility and for our national security.

Step 3: Develop a Cyber-Security Strategy
In compliance with the NIST Framework and CIP standards, utility management should develop a cyber-security strategy that identifies cyber-risks, provides clear guidance and training to utility employees to effectively address those risks, and ensures the strategy is carried out and documented through continuous feedback to utility managers. As discussed below, it is important that the strategy include coordination with affected municipal and state governments, first responders, and Federal Information Sharing and Analysis Centers ("ISACs").

Step 4: CEO Briefings
The Cyber-Security Strategy developed in Step 3 should include a requirement for regular briefings of the utility's chief executive officer and relevant senior management by cyber security personnel, including updates on newly-identified cyber threats, progress in implementing CIP standards and other mitigation measures, and adaptations to the Strategy to address new threats, vulnerabilities and emerging challenges. Such briefings demonstrate the importance of cyber-security to the rest of the organization and ensure senior management is aware of cyber-related issues. Full awareness of cyber threats should, in turn, help assure the organization is devoting adequate resources to addressing those threats, and build the "culture of compliance" NERC looks for in assessing adherence to Reliability Standards.

Step 5: Legal Review of IT Contracts
The utility should conduct a legal review of its IT equipment and services contracts to ensure compliance with CIP standards, the Security Development Lifecyle guidelines discussed below, the utility's internal Cyber-Security Strategy, and other relevant requirements.

Step 6: Review IT Procurement
The utility should also ensure it is procuring computer software and hardware in a "secure" manner in conformity with Security Development Lifecycle ("SDL") processes and other best practices. Such procurement practices guard against incorporation or introduction of unsafe equipment and malicious software into the utility's computer systems.

Step 7: Procurement Staff Training
Consistent with Steps 5 and 6, the utility's procurement and acquisition staff, as well as its IT security staff, should receive training on SDL and other requirements relevant to IT acquisition and should be given resources sufficient to ensure effective cyber security provisions are incorporated into all IT acquisition contracts.

Step 8: Verify Implementation of Cyber-Related Contract Requirements
To ensure the measures discussed in Steps 5 through 7 are properly implemented, the utility should review its contractual relationships with third party IT service providers to verify that security-related requirements of IT contracts are actually being carried out in conformity with contractual and industry standards. Substandard computer installations and non-conforming contract services can give hackers, cyber-criminals, and cyber-attackers access to critical computer-controlled infrastructure.

Step 9: Use Information Sharing and Analysis Centers ("ISACs")
ISACs (mentioned in Step 3 above) are sector-specific organizations developed voluntarily in cooperation with the Department of Homeland Security to facilitate detection and prevention of cyber-intrusions, vulnerability scanning, penetration testing, and training and education services. The Department of Homeland Security coordinates the flow of information to, from and among fifteen national ISACs. Utility managers and security officials should pay particular attention to ES-ISAC, the ISAC for the electricity sector. Information from other ISACs may also enhance awareness of cyber-threats as well as the tactics, techniques and procedures employed by nefarious actors. These collateral sources include the Multi-State ISAC, which provides cyber threat information and cyber response assistance to state and local governments including utility commissions; the Supply Chain ISAC, which focuses on threats identified in the acquisition/procurement process; the Water ISAC, which provides useful information for water utilities; the Nuclear Energy ISAC, which covers nuclear energy cyber issues; and the Financial Services ISAC, which has information helpful to protecting the financial information of utility customers as well as the utility's own financial information.

Step 10: Develop Disaster Recovery Plans
Most utilities have extensive business continuity and recovery plans that describe how the utility will deal with natural disasters such as earthquakes and major storms. Disaster preparedness also requires development of plans to assure the utility's recovery from a major cyber-attack or series of attacks. The threat of such attacks is so real that a cyber mitigation, response and recovery plan should be the subject of a separate, detailed Annex to the utility's continuity plan. NARUC's Cybersecurity for State Regulators 2.0 (February 2014) provides a comprehensive set of criteria and recommended actions (from a wide variety of sources) for utility commissions to use as assessment tools. These sources and others are helpful in developing an effective Cyber Annex to the utility continuity and recovery plan.

Step 11: Build a Relationship With Law Enforcement
Federal, state and local law enforcement agencies and some state military departments have important roles in identifying cyber intrusions, developing coordinated responses to such intrusions, apprehending or assisting in the apprehension of cyber criminals and recovering from major cyber incidents. Utilities should strive to build strong relationships with these agencies. To be effective, the utility must pre-identify the specific law enforcement officials it will contact in case of a suspected terrorist attack or cyber intrusion. The utility should go beyond the minimum requirement of compiling a contact list to create active, ongoing relationships with the law enforcement officials it will need to rely on in the event of a major cyber-attack.

Step 12: Practice Cyber Incident Responses
As with most utility functions, the adage "practice makes perfect" applies to cyber incident preparedness and cyber incident response. Fortunately, the Department of Homeland Security's "Cyber Storm" program offers excellent opportunities for utilities to participate in a realistic simulation of a major cyber-attack. The Cyber Storm exercise series provides an opportunity for more than 1,000 local entities to participate in a coordinated, week-long national cyber exercise, the results of which are used to develop other progressively challenging exercises and enhance the nation's cyber response systems. Washington utilities such as Snohomish County PUD played an active role in the 2013 Cyber Storm exercise. The next Cyber Storm exercise is scheduled for 2015.

Step 13: Support Your Local Emergency Response Plan
Finally, the utility should determine if its state government has developed a cyber response plan. If a plan exists, the utility at a minimum should become thoroughly familiar with it and, even more important, should offer to participate in the development and continuous testing and refinement of the plan.

The State of Washington, for example, leverages its "cyber security centers of excellence" and lessons learned from Cyber Storm exercises to integrate cyber security planning by state agencies ranging from the Washington Military Department (including its civilian State Emergency Operations Center and Air and Army National Guard cyber operations units) to the Office of the State Chief Information Officer, the Washington State Patrol, the Washington State Fusion Center, the Utilities and Transportation Commission, state universities, municipalities such as the City of Seattle, aerial and maritime port authorities and public utilities. These and other stakeholders, participating as members of a Washington State Cyber Integrated Project Team, have contributed to development, testing and refinement of a Washington State Cyber Incident Annex that is based on the National Cyber Incident Response Plan. The Washington Cyber Incident Annex includes provisions for convening a Cyber Unified Coordination Group to oversee cyber incident responses, which representatives from utilities and other critical infrastructure sectors that could be subject to cyber attack.

CONCLUSION
The conflict between good and evil in Middle Earth was finally resolved when Gollum, still madly clutching the One Ring, falls into the fire at the Cracks of Doom. With the malevolent force of the Ring destroyed, the forces of evil were shorn of their power and collapsed, allowing the hobbits and other peaceful residents of Middle Earth to return to normal life. The moment when the forces of evil in the cyber world will be shorn of their power is a long way off. Until that time comes, dealing with malevolent forces in the cyber domain will be an omnipresent and growing challenge. Because electric power is so critical to the functioning of our modern society, utilities are, willingly or not, thrust into the role of front-line players in the battle for control of cyberspace. The thirteen steps described above, if implemented, will help utilities protect their own assets, and help secure the nation against potentially crippling cyber attacks.

Pot, Power & Pollution: The Overlooked Impacts of Marijuana Legalization on Utilities and the Environment

April 17, 2014

Last month, Washington issued its first license for a legal marijuana grow operation under Initiative 502 ("I-502"), the marijuana legalization measure adopted by Washington voters in November 2012. A wave of additional operations will follow, as about 2,800 producers have applied for licenses to grow marijuana. While the implications of I-502 for the criminal justice system, land use, taxation and many other issues have been widely debated, the potentially significant changes in electricity and water use that are likely to follow from I-502's implementation have received almost no scrutiny. Nor have the important implications for environmental protection. Given the stakes, Washington utilities and environmental regulators should pay close attention to I-502 and the ongoing process of implementing the initiative.

At the outset, it is important to understand that the United States already produces huge amounts of cannabis. Official estimates suggest that U.S. production was somewhere in the range of 10,000 to 24,000 metric tons in 2001, making it America's largest cash crop by value. A more recent study suggests that production may actually be far higher - 69,000 metric tons. Given that marijuana production generally remains illegal, these estimates are highly uncertain. But there is little doubt that, as marijuana production comes out of the shadows and into the realm of legitimate business, power and water utilities will need to confront a number of serious and complex issues.

Implications for Electric Utilities
For electric utilities, legalization is a major concern because cannabis production, which generally relies on energy-intensive indoor growing operations, uses huge amounts of electricity. One recent study estimates that marijuana production may account for as much as 1% of the nation's entire electric consumption, accounting for a total bill of approximately $6 billion. In California, the numbers are even higher. Marijuana production in that state is estimated to use 3% of all electricity consumed there, equivalent to 9% of all residential electricity use.


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I-937 Updates: New Legislation and New Administrative Rules May Alter Washington's Renewable Portfolio Standard

April 7, 2014

As a result of both legislative and administrative action, several notable changes to Washington's Initiative 937 ("I-937", also known as the Washington Energy Independence Act) are on the horizon. While rejecting large-scale reform, the legislature made significant course corrections related to treatment of conservation and conduit hydro projects under the initiative. Those changes, and possibly several others, will be addressed in ongoing rulemaking proceedings at the Washington Department of Commerce and Washington Utilities & Transportation Commission ("UTC").

Two changes to I-937 were enacted in the 2014 session of the Washington Legislature. First, HB 1643, popularly known as the "conservation smoothing" legislation, allows utilities that achieve conservation in excess of specified targets to credit the excess toward future compliance periods, within limits. As originally enacted by the voters in 2006, I-937 required all covered utilities to obtain all "achievable cost-effective conservation." This mandate was carried out in a two-year process, which requires utilities first to identify conservation targets, then to adopt a plan to achieve those targets. In carrying out this mandate, many utilities, especially smaller utilities, found that conservation is not achieved in neat blocks, but instead is often achieved in major increments that may exceed specific biennial conservation targets. In these circumstances, I-937 both denied utilities the benefit of conservation achieved above biennial targets and created a perverse incentive to delay these conservation achievements.

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Western PURPA War Update: Retreats, Advances, But Little Clarity

February 4, 2014

As we discussed last summer, the expansion of renewable energy generation, especially wind generation, has produced an escalating conflict between the Federal Energy Regulatory Commission ("FERC") and several Western states over the application of the Public Utility Regulatory Policies Act ("PURPA"). In recent months, at least one major conflict has been resolved, while other conflicts continue to develop. While future developments may depend upon whether newly-nominated FERC Chairman Norman Bay adopts the aggressive enforcement policy of his predecessor, Jon Wellinghoff, recent action provides some hints as to the future legal landscape.

PURPA is a 1978 law that, among other requirements, mandates that utilities purchase power produced by smaller renewable generators. Recent conflicts have arisen over PURPA's basic mandate, which requires utilities to purchase power from PURPA-eligible generators, called "Qualifying Facilities" or "QFs", at avoided-cost rates. Conflicts have also arisen from efforts to square PURPA with recent industry developments, such as ownership of Renewable Energy Credits and integration of variable renewable resources..

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