GTH Energy & Natural Resources Law Blog

In a June 14 decision substantially clarifying and expanding federal open access transmission rights, the Federal Energy Regulatory Commission ("FERC") ruled that open access transmission rights cannot be limited to Points of Delivery ("PODs") established for scheduling purposes, but must allow third-party shippers to deliver power across the entire system of a regulated transmitting utility. The decision also reaffirms the right of PURPA "Qualifying Facilities" ("QFs") to transmit power to remote sellers rather than selling to the utility with which the QF directly interconnects.

The June 14 decision (Kootenai Electric Cooperative, Inc., 143 FERC P 61,232 (2013)) addresses one skirmish in a broader regional conflict pitting regional investor-owned utilities, especially Idaho Power Company, and state utility commissions against regional renewable energy producers seeking to enforce the obligations of utilities to purchase output from QFs under the 1978 Public Utility Regulatory Policies Act ("PURPA"). The June 14 decision arises from the efforts of Kooentai Electric Cooperative ("KEC") to sell output from its 3.2-MW Fighting Creek Landfill Gas Project, which is certified QF. After failing to reach terms to sell Fighting Creek output directly to its neighboring utility, Avista, KEC determined that it could instead sell power indirectly to Idaho Power at relatively favorable PURPA rates established by the OPUC for sales into Idaho Power's Eastern Oregon service territory.

Continue reading "FERC Affirms Open Access Rights for QFs in Complaint Against the Oregon PUC" »

The Washington State Energy Office (which operates within the Department of Commerce) recently issued an Advisory Opinion of considerable importance to utilities required to meet Initiative 937's energy conservation targets. The Advisory Opinion concludes that a utility may count documented and cost-effective energy savings toward I-937 conservation targets even if the utility has no direct involvement in carrying out the conservation measure.

Passed by Washington voters in 2006, I-937 (also known as the Washington Energy Independence Act) is well known for imposing a Renewable Portfolio Standard that requires covered utilities to purchase an increasing amount of qualified renewable resources, ultimately requiring 15% of their portfolios to be supplied by renewables by 2020. Less well know, but equally important, I-937 also requires covered utilities to develop and carry out plans for acquiring "all available conservation that is cost-effective, reliable, and feasible." The Advisory Opinion answers some important questions for utilities carrying out this conservation mandate.

Continue reading "State Energy Office Concludes Non-Utility Conservation Can Be Used for I-937 Compliance" »

The Washington Supreme Court recently handed a significant victory to Washington's Public Utility Districts when it denied a petition for review of Shoulberg v. Public Utility District No. 1 of Jefferson County. Pursuing a long-standing grievance, taxpayers in Port Townsend filed a class-action lawsuit challenging the PUD's taxation of Port Townsend property owners. The Superior Court and the Washington Court of Appeals (169 Wn. App. 173, 280 P.3d 491 (2012)) rejected the challenge. With the Supreme Court's denial of the petition for review, the Court of Appeals decision is now the final word.

The case involves interpretation of RCW 54.04.030, the section of the PUD statute aimed at preventing duplication of services when PUDs are established in counties with municipal utility systems. The taxpayer plaintiffs argued that property taxes imposed on Port Townsend property owners by the PUD violated the statute's prohibition on duplicative taxation, which prohibits taxation of "property situated within" any city to "pay for any utility, or part thereof, of like character to any utility, owned or operated by such [city]."

Continue reading "Jefferson County PUD Prevails In Tax Dispute; GTH Successfully Defends Summary Judgment Dismissal of Class Action Lawsuit" »

We're proud to announce that GTH partner Eric Christensen penned the cover story in the May 2013 issue of the Northwest Public Power Association Bulletin. Here is the text of the article:

The rapid rise of variable renewable resources, especially wind power, has put increasing pressure on the West's electric system to balance the rapidly fluctuating output often produced by these resources. In response, a regional Energy Imbalance Market ("EIM") is now under active consideration. The EIM would allow Balancing Area Authorities ("BAAs") to obtain balancing reserves from across a broad region, in theory allowing more economic and reliable operation of the region's balancing capacity. Public power has greeted EIM with considerable skepticism, observing that Regional Transmission Organizations ("RTOs") and other "organized markets" have often failed to produce expected benefits.

Public power is equally concerned that an EIM could subject public power systems to Federal Energy Regulatory Commission ("FERC") jurisdiction. Centralized control by FERC is, of course, the antithesis of local control, one of public power's keystone values. FERC's recent tendency to pursue its jurisdiction aggressively on behalf of renewable producers heightens this concern. For example, FERC in 2011 for the first time asserted its "FERC-lite" jurisdiction, invalidating the Bonneville Power Administration's approach to managing periods of excess wind generation.
As this article explains, public power is right to be concerned that an EIM could result in both expanded FERC jurisdiction and a broader push toward a West-wide RTO. Both risks, however, can be mitigated by insisting on specific structures and conditions for EIM participation.

Relevant Precedents: FERC Jurisdiction Over Consumer-Owned Utilities Operating in Organized Markets

In the industry's first few decades, federal jurisdiction was of little concern to public power. Public power operated in its own sphere, governed by elected representatives of the citizens it serves, generally free from either state or federal rate regulation. With increasing integration of the industry and regulatory restructuring, these jurisdictional lines have blurred. In some cases, Congress added new statutory authority giving FERC jurisdiction over specific aspects of consumer-owned systems. In other cases, FERC leveraged its existing statutory authority. For example, to enforce its "open access" transmission regime, FERC required consumer-owned transmission systems to adopt "Safe Harbor" open access tariffs so that they could obtain "reciprocal" access to IOU-owned transmission facilities.

An examination of recent precedents from Western RTOs and cooperative transmission ventures demonstrates that there is some basis for concern that participation in an EIM could subject a consumer-owned utility to new FERC jurisdiction. Perhaps most notoriously, after the meltdown of Western power markets in 2000-01, FERC attempted to force public power entities that had participated in the California ISO and PX markets to disgorge refunds. Ultimately, the Ninth Circuit rejected those attempts, concluding that the Federal Power Act plainly prohibits FERC from exercising its refund authority over public power entities. The Court, however, left the door open for California to pursue refunds in court. This opening has proved costly for public power. For example, in April, the U.S. Court of Claims allowed California's contract-based lawsuit against the Bonneville Power Administration ("BPA") to move forward. This is a particularly bitter pill for Northwest public power ratepayers, many of whom suffered greatly from California's missteps during the 2000-01 market meltdown and were generally denied relief by FERC. They now face the prospect of paying again for California's mistakes, this time through inflated BPA rates.

The Courts have also concluded that consumer-owned utilities participating in the California Independent System Operator ("ISO") may be subject to just-and-reasonable rate regulation where the rates charged by the consumer-owned utility affect the FERC-jurisdictional rates charged by the ISO. When the City of Vernon, California's municipal utility joined the ISO, the rates charged by Vernon for ISO-administered access to Vernon's transmission system became an element of the transmission rates charged by the ISO. FERC concluded that, because Vernon's transmission rates were an element of the ISO's transmission rates, Vernon's rates must be subject to FERC oversight to ensure that the resulting transmission rates charged by the ISO are just and reasonable. After extended litigation, the Ninth Circuit ultimately upheld this result.
FERC has asserted a similar form of jurisdiction over public power entities in other regions, as well. For example, where Basin Electric Cooperative entered into a joint-use transmission arrangement with a FERC-jurisdictional IOU, FERC asserted jurisdiction to review Basin's transmission rates because Basin's rates are a component of the rates charged by the joint-use system.

On the other hand, the courts have flatly rejected FERC attempts to force changes in the management structure of the RTOs and ISOs. Following the 2000-01 crisis, FERC concluded that the ISO's management structure was partly to blame for market dysfunctions, and attempted to force a change in the composition of the ISO Board. The U.S. Court of Appeals for the D.C. Circuit rejected FERC's assertion of authority. Of particular interest, the Court of Appeals rejected FERC's claim that its authority to regulate the "practices" of jurisdictional utilities allows FERC to order specific changes in the management of those utilities. FERC's reading of the statute, the Court concluded, ignores the surrounding statutory language, which is aimed at providing FERC with authority to regulate rates, not every aspect of utility operations. Thus, the Court reasoned, FERC can regulate utility "practices" only if they are directly connected with the utility's rates. Because there was no clear connection between the structure of the ISO's board and the rates it charged, the Court concluded, FERC's attempt to dictate the structure of the ISO's governing board exceeded its statutory authority.
In summary, the participation of consumer-owned utilities in "organized markets" such as the California ISO is a mixed bag. FERC has on a number of occasions asserted jurisdiction over consumer-owned utilities participating in ISOs or RTOs. And, while the Courts have rejected some of these assertions, they have upheld others. Consumer-owned utilities contemplating participation in the EIM are therefore well-advised to exercise caution if they wish to avoid becoming subject to increased FERC jurisdiction.

Limiting FERC Jurisdiction in an EIM
While exposure to FERC jurisdiction is a valid concern, expanding FERC jurisdiction need not follow inevitably from a decision to participate in the EIM. For example, a number of consumer-owned utilities participate along with FERC-jurisdictional IOUs in regional transmission bodies such as ColumbiaGrid and WestConnect. FERC precedent regarding these and similar regional ventures demonstrate that, with appropriate safeguards, FERC's assertion of jurisdiction over consumer-owned participants can be limited.

Such safeguards include:

• Defining off-ramps for consumer-owned utilities. Perhaps the best safeguard for consumer-owned utilities is a clear "off-ramp," allowing them to terminate their participation in EIM if FERC attempts to extend its jurisdiction over them. For example, WestConnect proposed a transmission pilot project aimed at reducing the "pancaking" of transmission rates across the systems of its members, which included both jurisdictional IOUs and non-jurisdictional co-ops and consumer-owned utilities. FERC approved an agreement allowing participants to withdraw at any time prior to the start-up of the pilot, at any time after start-up as a result of adverse regulatory action, and after ninety days' notice for any other reason occurring after start-up. Similarly, the Nebraska Public Power District ("NPPD") and Omaha Public Power District ("OPPD") in the Southwest Power Pool are authorized to withdraw from the Southwest Power Pool if FERC does not accept their rates or transmission revenue requirements. The ability to withdraw from the organization administering EIM in response to an unjustified claim of FERC jurisdiction gives consumer-owned participants powerful leverage to prevent FERC from overstepping its bounds.

• De-coupling jurisdictional and non-jurisdictional rates. It may be possible to structure an EIM so that the rates paid to non-jurisdictional utilities remain separate and distinct from the rates paid to FERC-jurisdictional IOUs. For example, before the WestConnect transmission pilot discussed above went into effect, FERC declared that the rates charged by non-jurisdictional utilities were not subject to FERC review because they did not affect rates charged by jurisdictional IOUs and additional safeguards, such as rate caps, were in place to ensure that jurisdictional rates remain just and reasonable. Similarly, FERC has approved participation of NPPD and OPPD in the Southwest Power Pool subject to agreements that explicitly limit FERC's authority to review the NPPD's and OPPD's rates or revenue requirements. As these examples demonstrate, it may be possible to limit FERC jurisdiction by separating EIM rates paid to non-jurisdictional utilities from rates paid to jurisdictional utilities, or by insisting upon specific contractual limits on FERC jurisdiction over public power.

• De-coupling the EIM market from transmission rates. The EIM should be limited to the specific function of allowing regional exchange of regulating reserves and other sub-hourly products. It should not operate a centrally-administered transmission market. Limiting the EIM's functions in this manner will prevent FERC from attempting to leverage its jurisdiction over interstate transmission.

• Recognizing public power authorities. The authority of public power governing bodies to set their own rates and policies is, of course, a cornerstone of the public power movement. Similarly, consumer-owned utilities operate under unique limitations arising from, for example, state law and from federal rules governing municipal bonds. Consumer-owned utilities participating in the EIM should insist on language in governing agreements that will prevent the actions of the EIM from violating state law, putting tax-exempt financing at risk, or displacing the basic functions of publicly-elected governing bodies. Such mechanisms not only assure consumer-owned utilities that they are operating within the boundaries of existing law, but also serve to limit FERC jurisdiction by requiring FERC to abide by the legal limits faced by consumer-owned utilities.

It is important to recognize that, in the Energy Policy Act of 2005, Congress granted FERC new refund authority over consumer-owned utilities. This new authority allows FERC to order refunds from consumer-owned utilities for short-term sales (sales for periods of less than one month) if the sales are "through an organized market in which the rates for sale are established by [FERC]-approved tariff (rather than by contract)" and the sale violates that tariff. FERC has yet to provide any clear guidance as to the meaning of this new authority. Hence, consumer-owned entities contemplating participation in an EIM must recognize the existence of the new authority, devise strategies for limiting the authority, and consider the possibility that their short-term sales on the EIM could be subject to FERC-ordered refunds.

Limiting EIM Expansion
As with FERC jurisdiction, public power is rightly concerned that, even if an EIM is wise, it could pave the way for a full-fledged RTO, with its attendant costs, complications, and market manipulation risks. In the same way that public power participants in an EIM should insist on limits to FERC jurisdiction, they should also insist on limits that prevent EIM from becoming a "slippery slope" to a West-wide RTO.

Two considerations are key. First, there is no reason that the EIM itself should be considered an RTO. On the contrary, if the functions of the EIM are strictly limited to its core mission, it would not be an RTO because it would not operate all the functions of an RTO. Rather, it would be more like ColumbiaGrid or WestConnect, organizations which perform limited transmission functions but are neither registered as an RTO nor considered to be an RTO by FERC.

Second, the governing documents of EIM should either prohibit expansion of the organization or else require a supermajority to move forward with any new functions. For example, ColumbiaGrid's governing documents allow it to take on new functions only with a super-majority vote of its members. Such a supermajority requirement can prevent movement toward in RTO unless a strong regional consensus, which necessarily must include public power, develops in favor of RTOs.
 

Conclusion
Public power has good cause to be concerned that participation in an EIM could result in expanded FERC jurisdiction over consumer-owned utilities and could be a step toward a West-wide RTO. These are not inevitable consequences of an EIM, however, and a number of proven safeguards are available to prevent these outcomes if consumer-owned utilities elect to participate in the EIM.

(Note: While the article is officially the "Cover Story" of the May NWPPA Bulletin, the photo on the cover is in fact a vendor from NWPPA's recent Engineering and Operations Conference. This is because, despite a valiant effort, NWPPA's editors could not find a compelling graphic concerning the EIM or FERC jurisdiction.)

The Washington Supreme Court late last week issued a pair of opinions that provide a road map for public agencies struggling to reconcile disclosure obligations under the Washington Public Records Act ("PRA") with the thicket of state and federal laws protecting information from public disclosure. Read together, the decisions clarify how public agencies should treat information that is protected from disclosure under either federal law or under the multitude of exemptions from public disclosure provided by Washington law. The cases also serve as a powerful reminder that Washington public agencies must have public disclosure policies in place and carefully follow those policies -- with assistance from legal counsel, if required -- when responding to requests for disclosure of public records. Finally, the Court seems to have gone out of its way to provide guidance on its view of how the Public Records Act should be applied. It may therefore be advisable for public agencies with a disclosure policy in place to review the policy in light of the Court's new guidance.

The opinion in Resident Action Council v. Seattle Housing Authority leaves the reader with a sense of the Court's frustration that Washington public agencies seem regularly to misunderstand or misapply the PRA. The Court seems to imply that such errors help make the PRA one of the most litigated statutes before the Court. Despite Chief Justice Madsen's concurrence arguing that the Court goes well beyond what is required to decide the case, the opinion expends a good deal of ink setting forth the analytical framework the Court believes public agencies should follow when responding to PRA requests.

As an over-arching framework, the Court identifies five "indispensable steps" an agency must go through in responding to a PRA request, and even includes a flow chart to illustrate these steps. In essence, the flowchart is simply a way to illustrate the familiar principle that public agencies have an obligation to disclose public records unless the record is subject to an exemption and, if the record is subject to an exemption, to disclose redacted records. If the agency has properly determined that the information is protected, it can be released only "in rare cases" where a judge concludes that continued protection of the information is "clearly unnecessary."

The Court adds a new step to this analytical framework, identifying a system for classifying the PRA's141 exemptions and explaining how the different classes of exemptions should be analyzed. The Court divides the PRA's exemptions into "categorical" exemptions and "conditional" exemptions. Categorical exemptions are those that "exempt without limit a particular type of information or record." For example, RCW 42.56.230(a) categorically exempts debit card numbers from public disclosure. Conditional exemptions are those that exempt a particular type of information from public disclosure, "but only insofar as an identified privacy right or vital governmental interest is demonstrably threatened in a given case." For example, the PRA exempts from disclosure the identity of crime victims but only "if disclosure would endanger any person's life, physical safety, or property." RCW 42.56.240(2). The Court's opinion includes an appendix that categorizes all 141 PRA exemptions as either categorical, conditional, or, in the case of four exemptions, "ambiguous."

Continue reading "Public Records at the Intersection of Personal Privacy, Public Disclosure, and Litigation: Washington Supreme Court Clarifies Public Records Act Obligations" »

The Washington State Court of Appeals today issued an opinion finding that Washington Public Utility Districts ("PUDs") have the statutory authority to condemn state school trust lands in order to construct transmission lines and other utility infrastructure. Today's opinion is the latest chapter in a twisting saga that began in 1996, when Okanogan County PUD began planning a new transmission line between existing substations in Pateros and Twisp in the Methow Valley. The opinion confirms that, unless state lands have been dedicated to a particular public use, PUDs have authority to condemn those lands for utility purposes. By extension, the opinion should allow other Washington municipalities, such as Port Districts, cities, and towns, to condemn state lands for public purposes because they have statutory condemnation authority similar to that of PUDs.

The long and winding road of litigation began with a decade of environmental review, culminating in a Court of Appeals opinion confirming that Okanogan PUD's environmental review met required standards and that the PUD did not act arbitrarily in selecting the route for the transmission line. (Gebbers v. Okanogan County Public Util. Dist. No. 1, 144 Wn.App. 371, 183 P.3d 324, rev. denied, 165 Wn.2d 1004, 198 P.3d 511 (2008)). The PUD then began obtaining easements covering the selected route. After negotiating easements for about 85% of the required land, the PUD then filed a petition for condemnation against the remaining property owners. Among the parcels involved in the condemnation proceeding was a tract of state school trust lands.

Continue reading "Washington Appeals Court Finds PUDs Have Authority to Condemn Public Trust Lands" »

The Washington Supreme Court today rejected tort claims based on exposure to Electromagnetic Fields ("EMF") from a utility substation. The Court's rejection of the EMF claim, which is consistent with similar conclusions reached by, for example, the California Supreme Court, is perhaps the final brick in the wall for EMF claims against electric utilities. The decision is therefore an important milestone in the effort, played out over the last several decades, to protect electric utilities from EMF claims with dubious scientific support. In addition, the Court rejected an inverse condemnation claim against the City of Kirkland, broadly protecting local land use decision-makers against tort liability.

The case, entitled Lakey v. Puget Sound Energy, arises from Puget Sound Energy's ("PSE") routine upgrade of an electric substation in a Kirkland, Washington neighborhood. Because the upgrade required relatively minor variances from the local zoning code, PSE sought variances from the City of Kirkland. Neighboring property owners unsuccessfully fought the variance. They then sued PSE, seeking damages for exposure to EMF from the substation and the City of Kirkland under an inverse condemnation theory. The trial court rejected both claims. After a Frye hearing, the trial court rejected the plaintiffs' expert scientific testimony as unreliable. And it rejected the inverse condemnation claim on legal grounds. The Court of Appeals certified the case for direct appeal to the Washington Supreme Court, which heard argument on October 18, 2012.

Continue reading "Washington Supreme Court Rejects EMF Damages Claim Against PSE and Kirkland, Relieving Major Liability Concern" »

In a decision of great interest to Washington's Public Hospital Districts, Public Utility Districts, Port Districts, and many other state and local government entities, the Supreme Court this week issued an opinion clarifying and narrowing antitrust immunity for state and local governments. As a result of the decision, public agencies will need to exercise great care when taking actions that could restrict competition.

Under the "state-action immunity doctrine," the courts have long recognized that local government entities are immune from federal antitrust liability if they act under state law intended to restrict competition. But, for immunity to apply, a local government entity must act under a "clearly articulated and affirmatively expressed state policy to displace competition." This week's Supreme Court decision, FTC v. Phoebe Putney Health System, Inc., clarifies how this "clearly articulated and affirmatively expressed" test should be applied. The Court concludes that, while state legislatures need not explicitly state that they intend to restrict competition, limitation of competition must be the natural and logical consequence of the policy adopted by the state.

Continue reading "U.S. Supreme Court Narrows Antitrust Exemptions for Local Government Entities" »

Eric Christensen published an article in this month's Northwest Public Power Bulletin entitled "Electric Reliability and the Bulk Electric System Definition: Next Steps for Reducing Regulatory Burdens." The article is a follow-on to the article he published in the November 2012 Bulletin concerning the development of the keystone "Bulk Electric System" definition. We've reprinted the new article here:

ELECTRIC RELIABILITY AND THE "BULK ELECTRIC SYSTEM" DEFINITION:
NEXT STEPS FOR REDUCING REGULATORY BURDENS

By
Eric Christensen, Partner
Gordon Thomas Honeywell

On December 20, the Federal Energy Regulatory Commission ("FERC") issued Order No. 773, adopting a new "Bulk Electric System" ("BES") definition. The BES definition is foundational to FERC's reliability regime because it defines the universe of facilities over which FERC can exercise its reliability authority. Order No. 773 also includes new procedural tools for public power utilities seeking to reduce their reliability compliance burdens. The order represents a major victory for public power, but, to obtain its full benefits, utilities should consider additional steps. This article outlines the major options now available.

As reported in the November 2012 Bulletin, Order No. 773 culminates two years of work by the NERC Standards Drafting Team, with strong participation of Western public power coordinated through NWPPA, to develop a rational and workable BES definition. The new definition, developed with what FERC Commissioner Lafleur describes as "creativity and care," initially defines facilities operating above 100-kV as BES, but then refines this "core definition" with "a thoughtful and nuanced list of specifically included and excluded facilities, and an exception process to add or remove specific facilities." The new BES definition is a huge improvement over the disastrous approach originally proposed by FERC. As Commissioner LeFleur observed, the BES definition "illustrates the success" of FERC's "new paradigm" for reliability standards development, which employs NERC's industry-centered process rather than "unduly prescriptive" FERC mandates, to find the most efficient and effective solutions for meeting reliability goals.

NEW OPTIONS FOR PUBLIC POWER

Under Order No. 773 and existing NERC rules, public power agencies now have several options for reducing reliability compliance burdens. Choosing the best options will depend on each utility's specific circumstances. The available procedures include:

1. Phase II of the BES Definition Standards Development Process.
As it developed the new BES definition, the Standards Drafting Team identified many issues that could not be resolved in the limited time allowed by FERC. These issues were deferred to Phase II of the standards drafting process, which is now underway. Phase II will examine several questions of great importance to public power and refine the BES definition accordingly. These questions include, for example, how the new definition will affect functional registrations, the technical justification for the 100-kV threshold in the "core" definition, the appropriate capacity thresholds for classifying generators as BES, and the points of demarcation between BES and non-BES facilities. Western public power agencies should focus as closely on Phase II as they did on Phase I, and NWPPA should continue its critical coordination function.

2. Petition for Deregistration.
Entities are responsible for complying with reliability standards based on their registration in one or more of fifteen NERC-defined functional categories, ranging from "Distribution Provider" to "Balancing Authority." In the West, the initial registration process generally assumed a very broad definition of the BES, with the result that many purely local distribution utilities were inappropriately registered as Transmission Owners, Transmission Operators, or under other functions that assume ownership of BES facilities. If the new BES definition means that a utility no longer owns or operates BES facilities, the utility can, on the strength of the new BES definition, file a Petition for Deregistration with WECC seeking to deregister from transmission-related functions (e.g., "Transmission Owner" and "Transmission Operator") .

 
3. Exceptions Process.
In addition to approving the BES definition, Order No. 773 approved a new "Exception Process," which allows utilities inappropriately categorized as BES under the definition to file an "Exception Request." If the utility can demonstrate, based on technical studies, that its facilities are "not necessary for the Reliable Operation of the interconnected bulk-power transmission system," NERC will reclassify the facilities as non-BES. If the utility successfully pursues an Exception Request, it may then be able to deregister from transmission-related functions. The Exception Process can also be used to demonstrate that specific utility-owned facilities are non-BES, thereby removing those facilities from the obligation to comply with BES-related reliability standards.

4. Petition for Declaration That A System is "Used for Local Distribution."
In the most surprising aspect of Order No. 773, FERC imposed a new procedure requiring owners of local distribution facilities to petition FERC directly if they believe their facilities are "used in the local distribution of electric energy," and are therefore excluded from the BES under Section 215(a)(1) of the Federal Power Act. In making this determination, FERC will focus on the function of the system, in contrast to the system's material reliability impacts that would be examined in an Exception process. FERC will use, among other factors, the "Seven Factor Test," developed in the 1990s to distinguish local distribution from transmission as traditional industry structures were changing. This procedure gives local distribution utilities a chance to escape BES classification even if they cannot do so under the BES definition or the Exception process. The procedural path is likely to be less time-consuming and expensive than the Exception process because utilities can petition FERC directly rather than having to go first to WECC and NERC, and the issues to be resolved by FERC are likely to be less technical and fact-intensive than in the Exception process.

5. Facility-Specific Notification to WECC.
In addition, Order No. 773 allows a utility to notify WECC if it determines that specific facilities it owns are no longer classified as BES under the new BES definition. The procedure is simple - nothing more than a notification is required. Reclassification in this manner could significantly reduce a utility's compliance burden because removing facilities from the BES will reduce or eliminate the obligation to comply with reliability standards applicable to BES owner/operators.

6. Standard-by-Standard Negotiation.
Following earlier FERC precedent, Order No. 773 FERC invites utilities to bargain with NERC for exemption from reliability standards that do not make sense in a utility's specific circumstances, which could substantially reduce compliance burdens. NWPPA could serve a valuable function in this regard by organizing a group of its members to analyze and develop a list of reliability standards that should not apply to specific types of utilities (i.e, full-requirements customers of Bonneville Power Administration, utilities with no scheduling function) and assist in helping members seek exemptions from unnecessary requirements.

7. Agreed Transfer of Responsibilities.
Finally, individual utilities may be able to transfer compliance obligations to other entities by agreement. NERC rules allow reliability obligations to be transferred to, for example, joint action agencies, G&T cooperatives, or other entities with appropriate functional registrations. A utility transferring compliance responsibilities in this way could deregister from specific functions, or even completely deregister. NWPPA could render assistance in this area by, for example, exploring whether economies of scale can be achieved by transferring compliance responsibilities to a joint entity or negotiating with Bonneville Power Administration to take responsibility for its customers' transmission-related compliance obligations.

CONCLUSION
After Order No. 773, public power managers interested in reducing the cost of reliability compliance can choose from a menu of options. In making this choice, managers will need to carefully evaluate the specific circumstances of their utility. But Order No. 773 substantially increases the chances that meaningful reductions in compliance obligations can be achieved by NWPPA members.

At this time of year here in the Pacific Northwest, months of damp and dreary weather leave even the hardiest natives yearning for the brighter days of spring and summer. In February, Northwest gardeners can often be found digging, planting, composting, and weeding in the hope that this will somehow hasten the coming of more pleasant weather. Of course, spring cannot be rushed, but comes only in its own time. Yesterday, PacifiCorp and the California ISO ("CAISO") announced a Memorandum of Understanding ("MOU") committing the two entities to implementing a real-time Energy Imbalance Market ("EIM") by October of 2014. Like Northwest gardeners attempting to rush the spring, the MOU appears to be an attempt to jumpstart an EIM in the West. Because PacifiCorp and the CAISO are two of the largest transmission operators in the West, the effort must be taken seriously.

The EIM is one proposed solution to the problems of integrating increasing volumes of variable generation from renewable resources such as wind power. The core aim of EIM is to establish a market for regulating and balancing reserves that would allow system operators to draw on a wide range and diversity of resources to maintain electric system balance as renewable generation rises and falls, which theoretically will improve the efficiency of balancing operations. The EIM idea has been under consideration in the Northwest for the last couple of years, and has advanced to the point that detailed studies are being performed.

Continue reading "Rushing the Spring? PacifiCorp, California ISO Announce Energy Imbalance Market" »

Recent statistics from the Energy Information Administration suggest that the electricity industry's era of load growth has ended. That is, slow growth in demand is not just a result of the "Great Recession," but the product of underlying and persistent market fundamentals. These fundamentals, EIA suggests, will continue to produce modest growth in electric loads well into the future. At the same time, the strong growth in renewable generation, especially sources like wind and solar that are characterized by sometimes extreme variations in output, is creating a strong demand for peaking capacity and system flexibility. These persistent changes in electricity demand, combined with rising pressure to, for example, comply with environmental goals such as greenhouse gas reductions, is forcing a re-examination of some of the most fundamental assumptions in the industry. The Pacific Northwest is a harbinger of both industry trends because it has been a pioneer in energy conservation and because of the rapid expansion of wind capacity in the region over the last decade.

Noting a steady decline in the rate of growth of electric consumption, the EIA predicts the rate of demand growth will be less than one percent in the future. The EIA's conclusions are supported by a clear trend-line. Electricity consumption grew at an annual rate of 9.8% in the decade between 1949 and 1959, but it has dropped steadily in each decade since, with growth averaging only 0.7% per year during the first decade of this century. With continuing innovation in energy conservation technologies, one might reasonably conclude that growth in demand will be even slower. For example, highly efficient LED lights are poised for a major leap into the market for electric lighting. The Department of Energy estimates this technology alone could save as much as 348 TWh of electricity by 2027. Similar technological leaps in energy conservation, using, for example, nanotechnology, may be on the horizon.

Continue reading "The New Normal: Has Slow Load Growth and Limited Capacity Become the Norm In The Pacific Northwest?" »

Eric Christensen published an article concerning the new "Bulk Electric System" definition and how it is likely to aid Northwest utilities in complying with the FERC/NERC electric reliability regime in the November 2102 issue of the Northwest Public Power Bulletin. We've reprinted the text (without footnotes) here:

The ancient Byzantine Empire was famous for "bureaucratic overelaboration bordering on lunacy." In modern times, "Byzantine" has come to describe a system with "so many labyrinthine internal interconnections" that it is impossible to simplify or clarify. For power managers struggling to cope with the mind-numbing complexities of mandatory electric reliability standards, "Byzantine" seems a useful description.

For example, although many reliability standards have been mandatory since 2007, basic terms such as "Bulk Electric System" ("BES") and "Local Distribution" have yet to be defined. These terms are critical in determining a utility's compliance obligations because, if a utility owns or operates BES facilities, it will be obligated to comply with a much larger set of standards than otherwise.

Fortunately, interpretative assistance is at last on the way, in the form of the "Bulk Electric System" definition currently under consideration by the Federal Energy Regulatory Commission ("FERC"). NWPPA played a major role in developing the definition, helping leverage the expertise of its members by coordinating public power participation in the development of the BES definition from its inception. Public power's persistence helped produce a definition that will promote reliable operation of the backbone high-voltage transmission system while avoiding unnecessary and expensive regulation of local distribution systems.

After Congress launched the mandatory reliability regime in 2005, regulators muddled along for several years, using an old and ambiguous BES definition from the era of non-mandatory reliability standards. This changed suddenly in March 2010, when FERC proposed its own BES definition, which would have declared any facility rated above 100 kV to be BES, with exceptions granted only by petition to FERC.

If adopted, FERC's proposal would have resulted in systematic over-regulation, especially in the West. Western utilities frequently operate 115-kV distribution facilities, and, under FERC's 100-kV test, these facilities would have been classified as BES. If this occurred, compliance costs for the distribution-only systems often operated by public power would skyrocket, but with no improvement in reliability. To give one example, classifying 115-kV distribution systems as BES transmission would have required public owners of these systems to spend tens or even hundreds of thousands of dollars to obtain training for system operators from the North American Electric Reliability Corporation ("NERC"). But these distribution system operators generally have no access to the bulk system controls NERC would train them to operate. Money spent on training would, therefore, simply be wasted.

Fortunately, after strong industry reaction to the March 2010 proposal, FERC modified its approach. Rather than simply imposing a 100-kV test, FERC directed NERC to develop a new definition, challenging NERC to find an approach that would more effectively meet FERC's objectives. Public power representatives, including many from the West, devoted countless hours to the Standards Development Process that followed. The resulting proposal is vastly superior to FERC's original hard-line proposal and, if adopted, should improve bulk system reliability while avoiding the needless expense and overregulation that would have resulted from FERC's initial approach.

For example, the new definition makes clear that radial systems and local networks are not BES, even if operated above 100-kV. Both configurations are commonly employed by Western public power agencies to provide local distribution service. These exceptions should therefore allow most public power agencies operating local distribution to avoid inappropriate categorization as BES operators. Even if this does not occur, the new proposal includes an "Exceptions Process," whereby public power systems inappropriately classified under the definition as BES may be reclassified based upon technical analysis demonstrating that a system has no meaningful impact on the reliability of the backbone transmission system.

In June, FERC proposed adopting the NERC-developed definition but expressed a number of concerns, suggesting it may require additional changes to the NERC proposal. In order to reassure FERC, and thereby promote FERC adoption of the NERC proposal without modifications, NWPPA helped coordinate extensive comments from public power experts across the West addressing FERC's concerns and demonstrating that the proposed definition satisfies them.

In the next few months, FERC is expected to issue a final order concerning the BES definition. Public power's concerted efforts to develop a reasonable definition, and to support that definition at FERC, substantially increase the likelihood FERC will issue a favorable decision. The NWPPA's efforts should serve as a model for future public power involvement in developing reliability standards and in improving the operation of the reliability system.

Washington State's Court of Appeals recently upheld the Washington Department of Ecology's decision to retain existing water quality standards limiting dissolved gases at hydroelectric dams. The decision carries significance well beyond the specific dispute resolved by the court because it limits one avenue -- increased spill -- that may have relieved some of the pressure on the Bonneville Power Administration ("BPA") to integrate increasing amounts of variable wind generation into the regional grid. As we have previously reported, BPA's decision to require curtailments of wind generation during high-wind/high-water events has produced contentious litigation, pitting the Northwest's wind generators against BPA and its public power customers. Although it does not directly address the issues involved in that litigation, the Court of Appeals decision nonetheless has significant bearing on the BPA litigation because it means that BPA's non-curtailment options will continue to be limited.

The Court of Appeals case, Northwest Sportfishing Industry Association v. Department of Ecology, arose from a petition filed by a group of fisheries and environmental advocates asking the Department of Ecology to raise its Total Dissolved Gas ("TDG") standards to accommodate greater flows over the dams. TDG standards are aimed at preventing damage to fish and other aquatic species from gas-bubble trauma. Gas-bubble trauma occurs when excessive levels of atmospheric gases in the water column are absorbed by aquatic creatures and then released in their tissues as gas bubbles, much like "the bends" in a human diver. Gas-bubble trauma can cause significant physiological damage or even death, and is therefore of concern for the Columbia Basin's salmon and steelhead runs, including several listed under the Endangered Species Act. The fisheries advocates who filed the petition believe that TDG limits can be raised by the Department of Ecology without threatening significantly greater damage to fisheries from gas-bubble trauma, and that higher TDG limits will accommodate greater spill over the Columbia Basin's dams, leading to an improvement in the survival of salmon smolts migrating downstream.

Greater latitude for spill would also give BPA some additional flexibility to manage springtime conditions, in which high run-off in the river system often coincides with high winds and high power production from the region's wind fleet. In such conditions, BPA has sometimes curtailed production from wind generators because generation during periods of high wind combined with production from federal dams in the region exceeded the demand during that period. An additional margin for spill would allow BPA to spill additional water over the Columbia Basin's dams rather than running it through turbines (which produces significantly lower concentrations of dissolved gas but also power when it is not always needed). Because less power would then be produced by hydroelectric turbines, there would be a greater margin for allowing wind generators to produce without curtailments.

Continue reading "Wind War Subplot: Challenge to Washington Gas Limits Fails, Barrier to Increased Spill Remains in Place" »

As reported in our posting of November 2, the U.S. Supreme Court this term is considering two cases of particular significance for dam operators. The first, Arkansas Fish & Game Commission v. United States, was decided last week. The court rejected the proposition that no Fifth Amendment taking can occur from temporary flooding caused by a government-owned dam. This result will give little comfort to dam operators since takings claims will now be decided on a fact-intensive balancing test rather than on the basis of a per se rule that takings can arise only from permanent or predictable periodic flooding.

The case arose from seasonal flooding at the Donaldson Black River Wildlife Management Area ("WMA") in northwest Arkansas caused the U.S. Army Corps of Engineers' Clearwater Dam, located 115 miles upstream in Missouri. In the 1990s, the Corps began to deviate from its accepted operating plan for the Clearwater reservoir in order to reduce damage to crops upstream from the dam. Arkansas sued the Corps, asserting that deviations from operating rules increased flooding in the WMA, damaging hardwoods and reducing the value of the habitat in the WMA. The claim succeeded in the lower court, but the U.S. Court of Appeals for the Federal Circuit, in a split en banc decision, reversed, holding that the flooding was only temporary and therefore could not support a takings claim. This holding was primarily based on Supreme Court takings precedents from 1924 and 1917 involving dams.

Continue reading "Floodgates Open to Takings Claims? Supreme Court Finds That Even Temporary Flooding From Government-Owned Dams May Constitute a "Taking"" »

On October 18, the Federal Energy Regulatory Commission (FERC) issued Order No. 1000-B, denying rehearing of its landmark Order No. 1000. Like other recent FERC actions, such as its Policy Statement on Allocation of Capacity on New Merchant Transmission Projects, issued in July, Order No. 1000 is aimed at reducing barriers to entry in the market for electric transmission, and thereby encouraging investment in transmission by independent transmission developers and other non-incumbents.

In Order 1000, FERC amended its regulatory structure for transmission planning and cost allocation with three major requirements:

(1) Each public utility transmission provider must participate in a regional transmission planning process that produces a transmission plan identifying 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) Most controversially, the federal "right of first refusal" ("ROFR") must be removed from FERC-approved transmission tariffs. The ROFR allows incumbent utilities to construct transmission projects within their own service territories, even if originally planned and permitted by another entity. FERC views this as a major barrier to entry for independent transmission developers.

Continue reading "FERC Stays the Course, Denies Rehearing of Its Landmark Order No. 1000" »