FERC rules on Saguaro QF

Monday, August 27, 2018

U.S. energy regulators have denied a petition by a Nevada electric utility that would have rejected a regulatory filing by a local power plant. The ruling preserves the power plant's ability to sell electricity to its host utility.

The case centers on Saguaro Power Company, owner and operator of a 105 megawatt topping-cycle cogeneration facility in Henderson, Nevada. The plant sells electricity to Nevada Power Company under a power purchase agreement. Under that PPA, the energy and capacity rates paid by Nevada Power to Saguaro would be reduced by 20 percent if Saguaro loses its status as a "qualifying facility" or QF under federal law.

Since 1978, qualifying facilities have been entitled to receive certain benefits under the federal law called PURPA, but the process and requirements for becoming a QF have changed over time. Prior to August 8, 2005, in order to be a QF, a cogeneration facility was required to “produce electric energy and forms of useful thermal output (such as heat or steam), used for industrial, commercial, heating, or cooling purposes, through the sequential use of energy” and meet the applicable operating and efficiency standards. Since then, EPAct 2005 and Order No. 671 have provided that any “new” cogeneration facilities, i.e., a cogeneration facility that was either not certified as a QF on or before August 8, 2005 or had not filed a notice of self-certification or Commission application for certification prior to February 2, 2006, must also demonstrate that the “thermal energy output... is used in a productive and beneficial manner.”

In December 2017, Saguaro filed a Form No. 556 recertifying its facility as an existing cogeneration QF. That filing identified new thermal hosts who will receive thermal energy in the form of distilled water from the facility’s low pressure steam output, replacing thermal hosts previously identified in a prior self-recertification filing.

But Nevada Power Company filed a petition for declaratory order with the Federal Energy Regulatory Commission, asserting that Saguaro's self-recertification filing was deficient. Specifically, the utility argued that Saguaro failed to demonstrate its compliance with the operating and efficiency standards -- and also that the facility should be treated as "new" and thus be subject to additional standards under the Energy Policy Act of 2005 and the Commission's Order No. 671, such as whether the facility is being used in a productive and beneficial manner.

The Commission has rejected Nevada Power's petition. In its order denying Nevada Power's petition, the Commission noted that its Order No. 671 establishes a rebuttable presumption that an existing QF does not become a "new cogeneration facility" merely because it files for recertification, and that Saguaro represented having made no changes to its facility. The Commission concluded that filing for recertification to identify new replacement thermal hosts did not make the Saguaro facility "new."

US EPA proposes Affordable Clean Energy rule

Tuesday, August 21, 2018

The U.S. Environmental Protection Agency has proposed a new rule addressing greenhouse gas emissions from existing coal-fired electric utility generating units and power plants. EPA's proposed "Affordable Clean Energy Rule" is designed to replace the Clean Power Plan regulations adopted in 2015.

On August 21, 2018, EPA announced the Affordable Clean Energy or ACE Rule. As described by the agency, the rule encompasses four main actions to reduce greenhouse gas emissions:
  • Defining the “best system of emission reduction” (BSER) for existing power plants as on-site, heat-rate efficiency improvements;
  • Providing states a list of “candidate technologies” that can be used to establish standards of performance and be incorporated into their state plans;
  • Updating the New Source Review (NSR) permitting program to further encourage efficiency improvements at existing power plants; and
  • Aligning regulations under Clean Air Act section 111(d) to give states adequate time and flexibility to develop their state plans. 
According to EPA's regulatory impact analysis, replacing the Clean Power Plan with the ACE Rule would reduce CO2 emissions from their current level, and "could provide $400 million in annual net benefits," largely in the form of reduced compliance burden on covered power plants. While EPA adopted the Clean Power Plan in 2015, in 2016 the Supreme Court granted opponents stay of the regulations, and they never took full effect.

EPA will take comment on the ACE Rule proposal for 60 days after publication in the Federal Register and will hold a public hearing.

Laos dam construction and collapse

Thursday, July 26, 2018

A dam under construction in Laos as part of a hydropower scheme has collapsed, causing flooding and damage.

At issue is the Xe-Pian Xe-Namnoy project, a 410-megawatt hydroelectric power project under development for Xe-Pian Xe-Namnoy Power Company (PNPC). PNPC is a joint venture among the government of Laos and construction and power companies from South Korea and Thailand. The project, whose construction costs are estimated at about $1 billion, involves the construction of three primary dams to form reservoirs. Construction of the system was reportedly 90% complete, with commercial operation projected for 2019, and an agreement in place agreement to export 90% of project power to Thailand. The project has been touted for the degree of international investment involved, although some have criticized the project for insufficient local benefits.

From an engineering perspective, the project's primary dams impound water in a large reservoir. The project also includes three auxiliary "saddle dams" near several heads of the reservoir, essentially to prevent the reservoir from spilling down the impoundment's back side as it fills.
A map of the project, found at http://www.pnpclaos.com/index.php/en/project/maps
Project maps posted online by PNPC show saddle dams on three of the main reservoir's western branches.
Another project map found at http://www.pnpclaos.com/index.php/en/project/maps

One of these smaller saddle dams reportedly failed on July 23, 2018, allegedly due to severe rains. Saddle Dam D -- a facility 8 meters wide, 770 meters long and 16 meters high -- was built to support water diversion around the project's reservoir. But the structure reportedly fractured, causing water to spill downstream to the Xe Pian river outside of the project's intended path of water flow. According to the prime minister of Laos, at least 26 people have died and 131 are missing from the resulting flooding, and several villages .

Response and recovery actions are ongoing. The dam collapse highlights the importance of safety in dam construction and reservoir operations, as did the February 2017 failure of the Oroville Dam's spillway in California.

FERC Order 848, cyber security and reliability

Thursday, July 19, 2018

U.S. energy regulators have issued an order directing the nation's electric reliability organization to strengthen its standards for the mandatory reporting of cyber security incidents.

Federal law authorizes the Federal Energy Regulatory Commission to regulate significant aspects of the bulk electric system's reliability. The Commission's jurisdiction over reliability covers the nation's electric reliability organization, North American Electric Reliability Corporation (NERC), which is charged with developing and submitting mandatory reliability standards for the Commission for approval.

Following increased concern over cybersecurity and hacking affecting utilities, in 2017 the Commission issued a Notice of Proposed Rulemaking proposing to direct that NERC develop enhanced Cyber Security Incident reporting requirements. At that time, then-current reliability standards generally required responsible entities to report Cyber Security Incidents only if they have “compromised or disrupted one or more reliability tasks. But the Commission expressed a concern that this reporting threshold "may understate the true scope of cyber-related threats facing the Bulk-Power System, particularly given the lack of any reportable incidents in 2015 and 2016." As a result, the Commission proposed requiring NERC to develop and submit modifications to its reliability standards, to require the reporting of cyber security incidents that compromise, or attempt to compromise, certain security infrastructure.

On July 19, 2018, the Federal Energy Regulatory Commission issued its Order No. 848. Through that order, the Commission adopted its own proposal to "improve awareness of existing and future cyber security threats and potential vulnerabilities." As described by the Commission, Order No. 848's directive consists of four elements:
  1. responsible entities must report Cyber Security Incidents that compromise, or attempt to compromise, a responsible entity’s Electronic Security Perimeter (ESP) or associated Electronic Access Control or Monitoring Systems (EACMS);
  2. required information in Cyber Security Incident reports should include certain minimum information to improve the quality of reporting and allow for ease of comparison by ensuring that each report includes specified fields of information;
  3. filing deadlines for Cyber Security Incident reports should be established once a compromise or disruption to reliable BES operation, or an attempted compromise or disruption, is identified by a responsible entity; and
  4. Cyber Security Incident reports should continue to be sent to the Electricity Information Sharing and Analysis Center (E-ISAC), rather than the Commission, but the reports should also be sent to the Department of Homeland Security (DHS) Industrial Control Systems Cyber Emergency Response Team (ICS-CERT). Further, NERC must file an annual, public, and anonymized summary of the reports with the Commission.
The Commission directed NERC to submit these modifications to its reliability standards within six months of Order No. 848's effective date.

NC dismisses PURPA complaint

Focusing on form over substance, North Carolina utility regulators have dismissed a hydroelectric generator's claims that it is entitled to sell the Yadkin River projects' hydroelectricity to local utilities at specified prices.

Cube Yadkin Generation, LLC owns hydroelectric facilities located on the Yadkin River in North Carolina. The company acquired the former Alcoa Corp. dams in 2016. Prior to that purchase, Cube had some discussions with local utilities Duke Energy Progress, LLC and Duke Energy Carolinas, LLC, regarding the sale of power from the hydro projects to the utilities under the federal Public Utility Regulatory Policies Act (PURPA).

PURPA allows certain small or renewable independent power producers meeting defined criteria to self-certify as "qualifying facilities" entitled to special rate and regulatory treatment. These benefits can include the right to sell energy and capacity to the generator's local host utility, usually at either at the utility's avoided cost or at a negotiated rate. Federal regulations generally give QFs the option to sell energy "as-available," or under a long-term contract or other legally enforceable obligation for delivery of energy or capacity over a specified term.

After Cube Yadkin acquired the dams, the utility ultimately refused to buy hydropower from three of the dams on Cube's terms. In March 2018, the generator complained to the North Carolina Utilities Commission. In its complaint, the company asked for a declaratory ruling that the utilities are obligated to purchase the projects' output at rates established under PURPA, as well as other relief including a requirement that the utilities enter into power purchase agreements with Cube for a term of not less than 10 years.

In a July 16, 2018 order, the North Carolina Utilities Commission dismissed the company's complaint. In that order, a majority of the Commission found that the generator had not submitted a "Notice of Commitment" form to the utility, which the majority said was required under North Carolina's implementation of PURPA if a generator wished to establish a legally enforceable obligation that the utility purchase its power. Noting that Cube hadn't submitted the Notice of Commitment form, and therefore that Cube hadn't established a legally enforceable obligation, the Commission denied Cube's request for declaratory ruling.

The Commission next considered whether Cube should be granted a waiver of the requirement to use the Notice of Commitment form. After recapping its view of the purpose of establishing a legally enforceable obligation, and how the Commission had developed its requirements for establishing a legally enforceable obligation, the Commission rejected Cube's request for waiver of the required use of the Notice of Commitment form. As a result of these conclusions, the Commission granted the utilities' motion to dismiss.

Two Commissioners dissented from the majority decision, noting that the majority opinion dismissed the case without allowing the full development of the record or a hearing on the merits.

Vermont PUC opens electric vehicle investigation

Tuesday, July 17, 2018

Vermont utility regulators have opened an investigation to identify and eliminate barriers to the widespread adoption of electric vehicles in that state, following a legislative call in the state's general transportation bill for an examination of electric vehicle charging issues.

This spring, Vermont Governor Phil Scott signed into law Act 158 (H.917) of the 2017-2018 Vermont legislative session. Section 25 of Act 158 requires the Vermont Public Utilities Commission to investigate and to prepare a written report concerning the charging of plug-in electric vehicles (EV).

On July 9, 2018, the Commission issued an order opening an investigation into promoting the ownership and use of electric vehicles in Vermont. In a press release accompanying the order, the Commission noted the harmful contributions of Vermont's transportation sector to greenhouse gas emissions and global climate change, and the prospect that electrifying transportation could help the state comply with its climate and greenhouse gas goals. The order notes that commonly cited barriers to widespread EV deployment may include vehicle range limits, limited availability of charging opportunities, cost, and vehicle performance -- and even barriers more unique to Vermont, such as cold winters and a rural, mountainous landscape.

The Commission says its investigation will include multiple cycles of written filings and workshops, addressing topics including barriers to EV adoption, as well as ways EV drivers can contribute financially to road and highway maintenance. The investigation will culminate in a report to be filed with the Vermont Legislature by July 1, 2019, presenting the Commission's analysis of barriers to electric vehicle adoption and recommendations on how to reduce or eliminate those barriers.

The Commission has docketed the case as No. 18-2660-INV, and has invited interested persons and entities to file a proposed scope, structure, and schedule for the case no later than July 30, 2018.

US Atlantic offshore wind leasing plan up for comment

Thursday, May 24, 2018

U.S. ocean energy regulators have extended a deadline for public comment on a proposed path forward for offshore renewable energy leasing on the Atlantic Outer Continental Shelf. The Bureau of Ocean Energy Management's "Proposed Path Forward for Future Offshore Renewable Energy Leasing on the Atlantic Outer Continental Shelf" lists factors the agency proposes to consider in identifying areas for possible future offshore wind leasing.

BOEM is an agency of the Department of the Interior, charged with advancing the responsible development of offshore energy and marine mineral resources covering over 1.7 billion acres of the Outer Continental Shelf. As of May 2018, BOEM has held seven competitive lease sales, yielding over $68 million in high bids for almost 1.4 million acres in federal waters. BOEM now has 13 offshore wind energy leases, capable of supporting 17 gigawatts of generating capacity, covering every state from Massachusetts to North Carolina (Cape Cod to Cape Hatteras).

On April 6, 2018, BOEM published a Request for Feedback in the Federal Register, presenting the agency's "Proposed Path Forward for Future Offshore Renewable Energy Leasing on the Atlantic Outer Continental Shelf." In that notice, the agency said it is conducting a high-level assessment of all waters offshore the United States Atlantic Coast for potential future offshore wind lease locations, and proposes to rely on specific factors to help it assess which geographic areas along the Atlantic are the most likely to have highest potential for successful offshore wind development in the next three to five years.

BOEM said its intent in publishing the Notice was "to start a conversation surrounding its approach to future renewable energy leasing on the Atlantic OCS." Its proposed factors for identifying offshore wind forecast areas include exclusionary factors (which create "no-go" areas for offshore wind) and positive factors (increasing the likelihood that location would fall within a forecast area). Under BOEM's proposal, exclusionary factors would include areas prohibited by the Outer Continental Shelf Lands Act for leasing, Department of Defense conflict areas, and charted marine vessel traffic routes. Positive factors for an areas include that it has not previously been removed, is greater than 10 nautical miles from shore, is shallower than 60 meters in depth, is adjacent to states with offshore wind economic incentives or with an interest in identifying additional lease areas, or where industry has expressed interest.

Comments on BOEM's proposed path forward for offshore renewable energy leasing on the Atlantic were slated to be due on May 21, but on May 18, 2018, the Bureau of Ocean Energy Management announced that it would accept comments through July 5, 2018.

BOEM says this "Atlantic assessment is intended to inform future area identification processes, not replace them" -- so after reviewing comments it receives, BOEM will coordinate with its intergovernmental renewable energy task forces and conduct additional stakeholder outreach.

Kilauea lava approaches geothermal power plant

Tuesday, May 22, 2018

Lava erupting from the Kilauea volcano on Hawaii has caused a nearby geothermal power plant to shut down.

Puna Geothermal Venture is a geothermal energy conversion plant on the island of Hawaii. It brings steam and hot liquid from underground wells to the surface, where the steam is directed to a turbine generator to produce electricity. A second turbine uses the first turbine's exhaust steam to generate additional electricity. Under a contract, up to 38 megawatts of power produced by the project is sold to Hawaii Electric Light Company and distributed to customers, reportedly representing about a quarter of the big island's electricity supply.

But as Kilauea erupts, lava flows are reportedly threatening the Puna plant. The majority upstream owner of project operator Puna Geothermal Venture GP, Ormat Technologies Inc., issued a press release on May 15 describing steps taken to secure the Puna facilities in accordance with its emergency response plan, including taking electricity generation offline, shutting down and protecting the geothermal wells, removing flammable materials, and cooperating with state emergency agencies. The Honolulu Civil Beat reported on May 21 that most of the plant's wells have been capped, and that lava flows have reached the plant property but so far have been held back by a natural berm.

According to Ormat's May 15 press release, its property and business interruption insurance policies include insurance coverage in the event of volcanic eruptions and earthquake in an amount of up to $100 million (combined). But the company noted that any significant physical damage to, or extended shut-down of, the Puna facilities could have an adverse impact on the power plant's electricity generation and availability, which in turn could have a material adverse impact on the company's business and results of operations.

NECPUC 2018 energy symposium

Monday, May 21, 2018

New England utility regulators have gathered in Maine for the 71st annual symposium of the New England Conference of Public Utilities Commissioners.

NECPUC is a non-profit corporation which provides regional regulatory assistance on matters of common concern to public utilities commissions of the six New England states. Its board of directors is composed of public utilities commissioners from the six New England states. NECPUC meets regularly throughout the year and sponsors an annual symposium on regulatory issues.

NECPUC holds its 71st annual symposium in Cape Neddick, Maine, from May 20-23, 2018. The agenda for the 2018 NECPUC event includes programs focused on topics affecting the New England utility landscape. For the energy sector, these include a plenary session on wholesale markets and how consumers are impacted by "reliability-centric market challenges," as well as a panel on advancing electric vehicle infrastructure in New England. Another set of panels focuses on how to analyze, regulate, and manage risks of high-impact, low-frequency events like cybersecurity attacks or extreme weather. Other panels cover water, telecommunications, and natural gas topics.

Speakers scheduled to appear include Maine Governor Paul LePage and Federal Energy Regulatory Commission Commissioner Robert Powelson, as well as commissioners from numerous state public utilities commissions.

ISO-NE 2018 CELT projects future energy usage declines

Tuesday, May 15, 2018

The operator of New England's bulk electric grid projects that both energy usage and peak demand from the utility grid will decline slightly in the region over the 10-year period between 2018 and 2027, primarily due to the deployment of energy efficiency measures and behind-the-meter solar arrays.

ISO New England Inc. is the regional transmission organization responsible for the electric grid and electricity markets across most of New England. On April 30, 2018, ISO-NE published its 2018-2027 Forecast Report of Capacity, Energy, Loads, and Transmission, or CELT Report. The grid operator prepares annual CELT reports which describe the assumptions used in ISO system planning and reliability studies. These assumptions include the total generating capability of in-region resources, as well as a long-term forecast for growth in energy consumption and peak demand.

According to ISO-NE's 2018 CELT Report, overall regional electricity use will grow 0.9% annually over the 10-year period. But when energy efficiency and behind-the-meter generation are taken into account, ISO-NE's forecasts for both regional energy usage and peak demand project slight declines over the 10-year period. The grid operator projects an annual decrease in net energy usage by -0.9% annually, with seasonal peak demands projected to decline by -0.2% to 0.7% annually. ISO cites "continuing robust installation of energy-efficiency measures and behind-the-meter solar arrays throughout the region" as the primary factors driving this decline.