We invite you to join us June 6 in Tacoma for a conference entitled "Re-Using Contaminated Land: Transactions & Technologies." The conference will address the legal and technical aspects of "brownfields" development. Gordon Thomas Honeywell is proud to be a premiere sponsor of the conference. The agenda and other information is available here.
"EIM, RTOs, and FERC Jurisdiction: Does Participation in a Regional Energy Imbalance Market Subject Public Power to FERC Jurisdcition?": Eric Christensen Publishes Article in May NWPPA Bulletin
Does Participation in a Regional Energy Imbalance Market
Subject Public Power to FERC Jurisdiction?
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.
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.)
Public Records at the Intersection of Personal Privacy, Public Disclosure, and Litigation: Washington Supreme Court Clarifies Public Records Act Obligations
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."
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.
The Energy Trust of Oregon recently released an RFP for Renewable Energy Project Assistance Funding. The Energy Trust will provide $40,000 to $150,000 to selected projects to support early-stage development of non-solar renewable energy in Oregon. Funding will support such early-stage development activities as feasibility studies, permitting, interconnection studies, engineering and design, and financing. The response deadline is June 3, 2013.
The Energy Trust is a non-profit organization supported by public-purpose charges imposed on the customers of Portland General Electric, Pacific Power, Northwest Natural Gas, and Cascade Natural Gas.
New Washington Energy Legislation: Legislature Continues to Wrestle With Questions Raised by Renewables
Reflecting new Gov. Jay Inslee's strong interest in renewable energy and climate change, these issues were hot topics during this year's legislative session. With the conclusion of the regular session at the end of April, the fate of most energy-related bills has now been decided. Because Gov. Inslee has called an executive session to address unresolved tax and budget issues, the final story has not yet been written. But a number of bills important to electric utilities, renewable energy developers, and others in the energy industry have now become law.
As has become routine in recent years, Washington's Renewable Portfolio Standard, Initiative 937 ("I-937") continues to be a flashpoint for controversy. Although comprehensive reforms reflecting a "grand bargain" between environmental and industry interests once again eluded the legislature, three important changes to I-937 were enacted. These are:
SB 5400 (signed April 23): This legislation allows a utility subject to I-937 to count wind energy imported from states where the utility has retail customers toward the utility's I-937 compliance obligations. The bill provides a limited waiver from I-937's requirement that renewable power must come from the Pacific Northwest. For reasons we have previously discussed, this provision is, at best, constitutionally suspect. It is also probably counterproductive because California has used similar territorial restrictions to limit access to its renewables marketplace, causing havoc in the Pacific Northwest renewables industry. As a practical matter, the result of the bill is somewhat limited, allowing PacifiCorp to count otherwise-excluded Wyoming wind resources toward its I-937 compliance obligations.
HB 1154 (signed May 1): This bill amends I-937's prohibition against double-counting of the environmental benefits of renewable generators so that biomass and biogas producers can sell carbon offsets attributable to the destruction of methane (a powerful greenhouse gas), while still receiving credit for renewable energy production under I-937. This change will allow dairy digesters, landfill gas generators, and similar renewable generators to participate in emerging carbon-offset markets like those in California. These markets promise a potentially substantial revenue stream for operators of biomass and biogas facilities. This legislation may therefore kick-start construction of such facilities in Washington.
SB5297 (Governor's signature pending): This bill is follow-up legislation to the complex legislative package passed in 2011 to facilitate the transition of the Centralia Steam Plant from coal to natural gas. Part of the 2011 legislation allowed utilities to purchase long-term "coal transition power" contracts from Centralia to provide the financial assurances necessary for the refueling of the plant. This bill helps facilitate contracts for "coal transition power" by permitting utilities to purchase coal transition power without threatening their eligibility for I-937's "safe harbor" for no-growth utilities. The "safe harbor" provision allows utilities with no load growth to comply with I-937 by spending 1% of their retail revenues on eligible renewable resources, even if that spending does not achieve otherwise-applicable portfolio requirements for renewable resources.
PacifiCorp late yesterday issued a Request for Proposals ("RFP") for Oregon solar photovoltaic projects. The RFP is intended to help PacifiCorp comply with Oregon's Renewable Portfolio Standard, which includes a requirement for utilities to acquire solar power.
The RFP seeks bids from solar systems with a capacity of between 500 kW and 5 MW. PacifiCorp aims to acquire a total of up to 6.7 MW of solar capacity. Projects must interconnect directly with PacifiCorp's system or have firm transmission capacity to deliver power to the PacifiCorp system. Responses to the RFP are due on June 11, with final selection of winning bids scheduled for October 4, 2013. The project must achieve commercial operation by December 31, 2014.
If you have any questions about the RFP, PacifiCorp, the Oregon RPS statute, or other matters concerning renewable energy development, please contact a member of GTH's Renewable Energy practice group. We have decades of experience in all aspects of renewable energy development, including siting, permitting, contracting, financing, state and federal tax issues, transmission and interconnection.
FERC Refines "Bulk Electric System" Definition, Adopts New Cybersecurity Standards Proving Value of the Definition
At its April meeting, the Federal Energy Regulatory Commission ("FERC") issued Order No. 773-A, which generally reaffirms its December order (Order No. 773, discussed here) approving the definition of "Bulk Electric System" proposed by the North American Electric Reliability Corporation ("NERC"). The Commission also proposed to adopt Version 5 of NERC's Critical Infrastructure Protection ("CIP") standards. These standards incorporate the BES definition, demonstrating the importance of the BES definition to the regime of mandatory electric reliability standards.
Order No. 773 capped a years-long process to define one of the fundamental terms used in the mandatory electric reliability system adopted by Congress in the Energy Policy Act of 2005. By clarifying the legal landscape, Orders No. 773 and 773-A lay the groundwork for a number of different strategies regulated utilities may employ to reduce the sometimes daunting burdens of reliability compliance.
Similarly, the CIP proposal is an important way-point in a years-long effort to develop and improve cybersecurity standards. In the proposed rule, FERC proposes to skip directly from CIP version 3 to CIP version 5 standards, jumping over the version 4 standards it previously approved. The proposal demonstrates the importance of the BES definition approved in Orders No. 773 and 773-A because the new standards, if adopted, classify facilities based on whether they have "low," "medium," or "high" impact on the BES, and impose compliance obligations depending on this classification.
IRS Provides Tax-Day Gift to Renewable Energy Producers, Providing Guidance on Production Tax Credit Eligibility
While many of us were scrambling to finish our tax returns on April 15, the Internal Revenue Service ("IRS") was also busy, issuing long-anticipated guidance of critical importance for renewable energy developers. The new IRS guidance, Notice No. 2013-29, provides standards for determining whether the "beginning of construction" of a renewable energy facility has occurred by January 1, 2014, the deadline for the facility to be eligible for the Production Tax Credit ("PTC"). Eligible generation owners may opt to take the energy investment tax credit ("ITC") in lieu of the PTC. The new IRS guidance is of great importance to renewable energy developers because the availability of PTCs or ITCs is often critical to project economics.
Congress extended the deadlines for PTC eligibility as part of the 2012's American Taxpayer Relief Act. Before that law was enacted, a facility was required to be "placed in service" before January 1, 2014, to be eligible for the PTC. Wind facilities were required to be "placed in service" by January 1, 2013. The new legislation makes all types of eligible renewable energy facilities eligible for the PTC if they "begin construction" before January 1, 2014. The legislation left open the question of what it means to "begin construction." IRS's new Notice provides some specific parameters to answer than question.
In the latest chapter of decades-long litigation over the treaty rights of Washington's Native American tribes, the U.S. District Court for the Western District of Washington recently ordered three Washington state agencies to remove culverts from state-managed roads that block access to salmon spawning habitat. (U.S. v. Washington, No. CV 70-9213 (issued March 29, 2013)). The order requires culvert replacement to be completed by the fall of 2016 on state recreational lands, and by 2030 on highways administered by the Washington State Department of Transportation ("WSDOT").
The litigation has roots dating all the way back to Washington's earliest days as a U.S. territory. Among other duties, Isaac Stevens, Washington's first territorial governor, entered a series of treaties with Washington's Native American tribes. In return for ceding large amounts of land, the Stevens treaties provided: "The right of taking fish at all usual and accustomed grounds and stations, is further secured to said Indians, in common with all citizens of the Territory." More than a century later, this language became the linchpin of the U.S. District Court's foundational 1974 opinion, United States v. Washington, 384 F. Supp. 312 (W.D. Wash. 1974), which held that the Stevens treaties entitled the tribes to fifty percent of the state's "harvestable" fish. Often called the "Boldt Decision," after its author, the late District Judge George Boldt, the decision was the culmination of a political movement, complete with civil disobediance, celebrity "fish-ins, and sometimes violent clashes. The decision was upheld by the U.S. Court of Appeals for the Ninth Circuit and largely upheld by the U.S. Supreme Court. The practical result of the decision is that Washington's tribes have become "co-managers" of the state's fishery resources.
Market Manipulation, Preemption, and FERC Jurisdiction: Antitrust Claim from 2000-01 Crisis Revived By Ninth Circuit
The U.S. Court of Appeals for the Ninth Circuit today revived a class-action antitrust case against a large assemblage of natural gas sellers and marketers who were allegedly involved in manipulating Western natural gas prices during 2000-01. Manipulation of gas prices was one factor contributing to the meltdown of Western electricity markets during the same period. The court's decision, entitled In re: Western States Wholesale Natural Gas Antitrust Litigation, limits the extent to which the Federal Energy Regulatory Commission's exclusive jurisdiction under the Natural Gas Act ("NGA") preempts private antitrust claims under both state and federal law.
While the immediate effect of the court's decision is to allow plaintiffs harmed by the alleged gas market manipulation to seek potentially substantial antitrust remedies, the decision is likely to have long-term import well beyond the specifics of the particular facts addressed by the court. This is so because the NGA is one of a family of similar New Deal-era statues which also includes statutes like the Federal Power Act and the Federal Communications Act, and the court's decision turns on language that is common to this family of statutes. Further, the court opens the way for antitrust damage claims that allow injured private parties to seek damages, including treble damages, against market manipulators. These private actions will serve to bolster FERC's recently-intensified battle against energy market manipulation, which extends to the power markets as well as the natural gas markets.
Poles Left Standing: Ninth Circuit Rejects Claim That Utility Poles Must Be Regulated Under the Clean Water Act and the Resource Conservation and Recovery Act
In an important victory for users of treated wooden poles, the U.S. Court of Appeals for the Ninth Circuit last week concluded that wooden utility poles are neither a "point source" subject to regulation under the Clean Water Act ("CWA") nor a "solid waste" subject to regulation under the Resource Conservation and Recovery Act ("RCRA"). The decision is an important landmark for electric utilities, telecommunications carriers, and other companies using treated wooden poles. If the court had reached the opposite result, these industries could have been subject to burdensome new regulation under both the CWA and RCRA.
The Ninth Circuit's decision, Ecological Rights Foundation v. Pacific Gas & Electric Co., rejects a lawsuit brought under the citizen suit provisions of the CWA and RCRA by a California environmental organization. The environmental plaintiff claimed that PCP and other wood treating chemicals are washed into the environment by rainwater, resulting in a "discharge" of a pollutant requiring the owner of wood poles to obtain a NPDES permit under the CWA. Relying on the U.S. Supreme Court's recent decision rejecting a similar claim with respect to logging roads, the Ninth Circuit rejected this claim, as well. The court found that wooden poles are not a "point source" subject to CWA regulation. In particular, under EPA's approach to regulation of stormwater discharges, governed by 1987 amendments to the CWA, no NPDES permit is required because wood poles are not "associated with industrial activity," as would be the case at an industrial plant or storage area where rainwater is captured and channeled.
Current conventional wisdom in the energy industry holds that the natural gas "fracking" revolution will lead to an era of sustained supply gluts and low prices. Low natural gas prices, in turn, will allow for rapid expansion of gas-fired electric generation, leading to a period of sustained low prices in the electricity markets. According to the conventional wisdom, then, the fracking boom will create a sustained economic headwind for renewable generators forced to compete with low-priced gas generation. But several recent scientific and economic studies suggest that the conventional wisdom might be wrong.
By now, the tectonic changes in energy markets arising from the massive increase in natural gas production brought about by application of horizontal drilling and hydraulic fracturing techniques -- commonly known as "fracking" -- are well known. As usefully summarized in this recent primer by Harvard environmental policy professors Michael McElroy and Xi Lu, fracking reversed a long-term decline in domestic natural gas production, driving prices down as much as 86% from their 2008 highs. Among the many unanticipated results, coal-fired generation has declined precipitously, reaching a record-low of 34% of generation last year. Because gas-fired generation produces only about one-half the carbon dioxide of coal generation, the nation's carbon dioxide emissions have fallen to 1992 levels despite persistent political paralysis on climate issues.
Today, POWER magazine, one of the most widely-read electronic publications in the energy industry, published an opinion piece authored by Eric Christensen concerning integration of variable renewable generation resources in the Pacific Northwest.
You can link to the article here.
We've also published the text of the article below:
THE PACIFIC NORTHWEST STRUGGLES TO INTEGRATE
ITS RAPIDLY-GROWING WIND FLEET
Eric Christensen, Chairman
Energy, Telecommunications & Utilities Practice Group
Gordon Thomas Honeywell, LLP
Mae West said, "Too much of a good thing can be taxing." The Pacific Northwest has a good thing -- plentiful, carbon-free power from its huge wind and hydroelectric fleets. But wind's huge variability can be taxing. The Northwest's scramble to integrate growing wind generation, and the resulting litigation melee, underscore the importance of quickly solving the variable resource integration puzzle.
Over the last decade, wind generation in the Northwest has exploded. Wind capacity has grown from almost nothing to nearly 5,000 MW in the region's largest balancing area, the Bonneville Power Administration. Already, hourly ramps from wind generation regularly exceed 2,000 MW. These rapid ramps will continue to grow with the size of the wind fleet, which Bonneville expects to reach 6,000-7,500 MW by 2017. With its huge carbon-free capacity and flexibility to rapidly adjust output, the Northwest's hydro system is the ideally suited to balance these ramps. But the hydro system is now often taxed to the breaking point to reliably integrate large volumes of wind generation.
The immediate problem stems from Clean Water Act limits on dissolved gases. These limits are designed to protect aquatic creatures, including endangered Columbia River salmon runs, from "gas bubble trauma" - the equivalent of "the bends" in human divers. To avoid violating dissolved gas limits, Bonneville runs water through hydroelectric turbines (which does not increase dissolved gases), rather than spilling water over dams (which adds dissolved gases). But the resulting hydro generation, when it coincides with high wind generation, has periodically exceeded regional demand. Twisting the knife, the Washington State Court of Appeals recently rejected an attempt to increase dissolved gas limits on the Columbia, denying Bonneville an added measure of flexibility to avoid curtailments.
Bonneville has twice proposed solutions to this problem, relying on curtailments to wind generation. Wind producers complain that Bonneville's curtailment policies impose unique burdens on them, causing, for example, lost Production Tax Credits and Renewable Energy Credits, in addition to lost power production. Responding to complaints filed by wind producers, FERC has twice rejected Bonneville's proposed solutions. FERC's decisions raise fundamental legal questions concerning the extent to which Bonneville policy will be dictated by FERC, as opposed to the regional interests that have traditionally held sway at Bonneville, and litigation can therefore be expected to continue for years.
However, the litigation involves trivial amounts of power. Only about 150,000 MWh of wind production have been curtailed over the last two years in a region that consumes roughly 170 million MWh annually. Worse, the litigation has driven a wedge between wind producers and many of its natural allies. The wind boom has breathed new life into struggling rural economies across the region. But those same rural areas are mostly served by publicly-owned utilities that rely on power from the federal hydro system, and many in the rural Northwest view the wind generators' litigation as an attack on this vital resource.
Most importantly, the litigation ignores the Golden Bear in the room -- California's protectionist policies that have effectively walled off its robust renewable energy market from the rest of the West. California's policies are vulnerable legally because, for example, they violate the U.S. Constitution's "dormant" Commerce Clause. Yet, while Northwest renewable energy interests squabble over trivial amounts of power, California's destructive policies have gone unchallenged. And the curtailment issue is merely a symptom of the ultimate problem - even the Pacific Northwest's vast hydroelectric system lacks the capacity to integrate ever-greater amounts of variable wind generation.
To solve the wind integration problem, the Northwest needs to attack counterproductive policies like California's. It also needs grow the regional capacity pie. The region is already exploring improved coordination between balancing authorities and other short-term measures that will marginally improve its ability to integrate variable resources. Additional physical storage capacity is also critical. Hence, the region needs to explore major investments in proven technologies like pumped storage, as well as cutting-edge storage technologies like advanced batteries. Electrification of the regional transportation system coupled with "smart grid" technology may allow electric car batteries to become a major storage resource. The region also needs to improve transmission links to the major storage reservoirs in British Columbia and to expand the footprint of its wind fleet so that the fleet's output is more diverse and therefore easier to integrate. Finally, the region needs to encourage greater use of non-variable renewables like geothermal.
Following this path, the region can continue developing its diverse renewable energy resources. If it does so, it may find, as Mae West also said, that "too much of a good thing can be wonderful!"
CFTC Issues Two Final Rules Exempting Certain Public Power and RTO Transactions From Most Dodd-Frank Requirements
Yesterday, the Commodities Futures Trading Commission ("CFTC") issued two final rules that clarify the regulatory landscape for public power and other utilities attempting to comply with the Dodd-Frank Act. The first rule exempts energy-related transactions between public power and cooperative utilities from most Dodd-Frank requirements. The second exempts most transactions entered into in centralized RTO or ISO markets governed by FERC-approved tariffs. Together, the orders offer welcome guidance to electric utilities struggling to comply with Dodd-Frank requirements that have often raised more questions than answers.
The first rule concerns transactions between public power entities, including municipal and government-owned utilities and cooperatives. The rule provides that transactions between "Exempt Entities" involving "Exempt Non-Financial Energy Transactions" will be exempt from most requirements of the Dodd-Frank Act. "Exempt Entities" include municipal utilities, government-owned utilities, tribal utilities, and cooperatives that are tax-exempt under Section 501(c)(12) of the Internal Revenue Code. "Exempt Non-Financial Energy Transactions" include transactions involving delivery of electric energy, generation capacity, transmission services, fuel deliveries, and environmental attributes (such as "Renewable Energy Credits") if entered into for purposes of managing supply or price risks associated with the utility's obligation to deliver electric energy to its customers. Hence, if a transaction is between two publicly-owned utilities or cooperatives and involves delivery of commodities or services required to serve end-use customers, the transactions will be exempt from the most burdensome requirements of the Dodd-Frank Act, such as exchange-trading and collateralization obligations. Notably, both parties must be publicly-owned or cooperative utilities for the exempt to apply, and the exemption does not apply to interest rate, credit, or other kinds of non-energy transactions.