Vineyard Wind construction and operations plan to be reviewed

Friday, March 30, 2018

U.S. ocean energy regulators have announced their intent to study the environmental impacts of approving an offshore wind developer's plans to construct and operate an 800-megawatt wind energy facility offshore Massachusetts.

At issue is a proposal by Vineyard Wind LLC to construct and operate an 800-megawatt (MW) wind energy facility offshore Massachusetts. The project area, a lease for which was awarded to Offshore MW LLC by the U.S. Bureau of Ocean Energy Management in 2015, is located about 14 miles from the islands of Martha’s Vineyard and Nantucket, in water with depths of about 121 to 161 feet.

Vineyard Wind proposed a Construction and Operations Plan for its project in December 2017, potentially to be constructed as two 400 MW phases, up to five years apart. The project would entail the installation of up to 106 wind turbine generators, each with a capacity between 8 and 10 MW, with two or four offshore substations or electrical service platforms. Potential export cable landfalls include the towns of Yarmouth, Barnstable, and Nantucket, and on-shore construction and staging at the New Bedford Marine Commerce Terminal facility.

On March 29, 2018, the U.S. Bureau of Ocean Energy Management (BOEM) announced its publication of a Notice of Intent to prepare an Environmental Impact Statement for Vineyawrd Wind's Construction and Operations Plan. BOEM has opened a 30-day public comment period, during which it will conduct five public scoping meetings and accept comments that will be used to inform preparation of the EIS.

BOEM recently proposed revised its regulatory processes by publishing draft guidelines for the use of “Design Envelopes” in Construction and Operations Plans for offshore wind energy facilities, which it said would allow developers greater flexibility. Vineyard Wind's is said to be the first to use this design envelope approach in its proposed COP.

Report on US electric grid physical security

Wednesday, March 28, 2018

Since a 2013 rifle attack on a critical electric power substation in California, the U.S. electric power sector has generally moved toward greater physical security for critical assets, according to a report published by the Congressional Research Service. But the report says bulk power security "remains a work in progress," and suggests further investment -- and policy reforms -- may follow.

The report published on March 19, 2018 -- NERC Standards for Bulk Power Physical Security: Is the Grid More Secure? -- begins with the premise that securing the electric power grid is among the nation's highest priorities for critical infrastructure protection. It notes that a 2013 rifle attack on an electric transmission substation in California which caused widespread power outages also broadened policy attention from cybersecurity to encompass the physical security of assets critical to the power grid.

In response, Congress enacted legislation to strengthen power grid physical security and to facilitate its recovery from disruption. Section 1104 of the Fixing America’s Surface Transportation (FAST) Act contains provisions to protect or restore the reliability of critical electric infrastructure or defense of critical electric infrastructure during a grid security emergency. The Federal Energy Regulatory Commission (FERC) and the nation's electric reliability organization NERC also took action to develop new reliability standards for the physical security of bulk power critical infrastructure.

But physical security risks may persist. The report references a September 2016 rifle attack on a Garkane Energy Cooperative transformer substation in Utah as illustrating this persistence. The report notes that while it is probably accurate to conclude that the grid is more physically secure than it was in 2013, "it has not necessarily reached the level of physical security needed based on the sector's own assessments of risk.

The report notes Congress's continued concern about the physical security of the electric grid. It identifies possible areas for further policy focus as including "security implementation oversight, cost recovery, hardening vs. resilience, and the quality of threat information."

Meanwhile, cybersecurity has remained a priority. An October 2017 FERC report describing the results of its audits of regulated companies' cybersecurity protection processes and procedures noted that most met the applicable mandatory standards. But earlier this month, NERC fined an anonymous utility $2.7 million for alleged violations of reliability standards in connection with a data security breach, and the U.S. Department of Homeland Security issued warnings about Russian hackers targeting computer systems controlling energy and other critical infrastructure.

Interest in shoring up the security of energy infrastructure and systems -- both from physical attacks as well as cyber threats -- appears poised to drive continued discussions, regulation, and investment.

Can challenges or prize competitions solve water supply problems?

Monday, March 26, 2018

How can challenges or prize competitions help society address barriers that may prevent long-term access to low-cost water supplies?

The U.S. Department of Energy's Office of Energy Efficiency and Renewable Energy (EERE) has published a Request for Information, seeking information from the public to understand the key technical and other barriers that may prevent long-term access to low-cost water supplies that could be best addressed through challenges and prize competitions.

Water is essential for human health, economic growth, and agricultural productivity, and plays significant roles in the U.S. energy sector. The Department of Energy uses the term "energy-water nexus" to describe the interconnected nature of energy and water systems. While the U.S. has generally benefited from access to low-cost water supplies, according to the Energy Department, "new challenges are emerging that, if left unaddressed, could threaten this paradigm" including competing uses and water quality problems.

The Energy Department operates a variety of programs to advance domestic energy policy, including programs focused on research and development and grant funding. But could the Department of Energy be more effective by offering challenges or prize competitions? Unlike traditional R&D funding in which participants are selected up front with funding provided at the beginning in order to pursue a target or goal, challenges and prize competitions typically define a problem and offer a reward to anyone finding a solution.

Challenges and prize competitions have been adopted by the federal government as well as private actors. Since 2010, federal entities have awarded millions of dollars in prize money and other incentives through over 740 challenges and prize competitions, and nonprofits and private companies have launched many more.

In a Request for Information published in the Federal Register on March 19, 2018, the Energy Department identified challenges and prize competitions as "tools and approaches the Federal government and others can use to engage a broad range of stakeholders, including the general public, to develop solutions to difficult problems. Challenges and prize competitions rely on competitive structures to drive innovation among participants and usually offer rewards (financial and/or other) to winners and/or finalists."

Through the request, the Energy Department asks for public feedback on a variety of issues relating to using prizes and challenges to solve problems around the energy-water nexus, including an identification of challenges whose solution would allow for a significant increase in the volume of available water produced from non-traditional sources, significant improvements in industrial and power-sector water efficiency, or reductions in the cost to treat and deliver drinking water and wastewater to consumers without harming water quality.

Responses to the Request for Information are due no later than 5:00 p.m. (ET) on May 14, 2018.

FERC extends resilience comment date

Friday, March 23, 2018

Calling electric grid resilience "a critical issue for the American people and for our economy and national security," U.S. energy regulators have extended to May 9, 2018, a deadline for public comment on the resilience of the nation's bulk power system in organized wholesale markets.

The resilience of energy infrastructure is drawing increased public interest. Last year, U.S. Secretary of Energy proposed a rule for consideration by the Federal Energy Regulatory Commission whose nominal focus was on incentivizing electric generator resilience and reliability. While the Commission terminated that rulemaking on January 8, 2018, without adopting new regulations, at the same time the Commission did initiate a new proceeding to evaluate the resilience of the bulk power system in the regions operated by the Regional Transmission Organizations and the Independent System Operators (RTOs/ISOs).

In that order, the Commission said it hoped the new case would develop a common understanding of what resilience of the bulk power system means and requires, identify how each RTO and ISO assesses resilience, help the Commission evaluate whether it should take additional action regarding resilience. At the time, the Commission directed six regional transmission organizations and independent system operators to respond within 60 days, and solicited public comment within 30 days of the grid operators' due date.

The case has drawn interest. Last week, a coalition of energy industry trade associations filed a motion requesting an extension of time of 30 days for interested entities to respond to the RTO/ISO filings.

In an order issued on March 20, 2018, the Commission described the resilience of the bulk power system as "a priority of this Commission and a critical issue for the American people and for our economy and national security." Noting the importance of basing next steps on the best available information, including "a robust record and as much relevant information and thoughtful input as possible," the Commission extended the time for interested entities to submit comments under the January 8 Order by 30 days – to May 9, 2018.

US warns of Russian Government Cyber Activity Targeting Energy and Other Critical Infrastructure

Thursday, March 22, 2018

The U.S. Department of Homeland Security has warned that for at least two years, Russian government cyber actors have targeted government entities and multiple U.S. critical infrastructure sectors, including the energy, nuclear, commercial facilities, water, aviation, and critical manufacturing sectors.

In a joint Technical Alert issued March 15, 2018 by the Department of Homeland Security's U.S. Computer Emergency Readiness Team (US-CERT) and the Federal Bureau of Investigation, the agencies warned of a "multi-stage intrusion campaign by Russian government cyber actors." The report follows an October 2017 alert by computer security firm Symantec of a re-emergence of a sophisticated cyber espionage group known as "Dragonfly."

According to the government agencies' report, the Russian cyber threat actors seem to have deliberately targeted specific organizations, as opposed to pursuing targets of opportunity. In an initial "staging" phase, the campaign used tools like malware, watering holes, and spear phishing to gain access to small commercial facilities' networks -- typically peripheral organizations like trusted third-party suppliers whose networks may be less secure. For example, the threat actors sent emails with malicious attachments appearing to be personnel resumes or contract documents. Clicking on links in the attachments exposed the victims to malware or data harvesting. In a subsequent phase, the threat actors made further use of the staging targets' networks as "pivot points and malware repositories" for use in targeting their final intended victims.

The report says that these Russian government cyber actors used this hacked access for network reconnaissance and collection of information pertaining to Industrial Control Systems (ICS). It describes multiple instances of threat actors accessing workstations and servers on corporate networks that contained data output from control systems within energy generation facilities.

Cyber security is now a significant concern, both domestically and abroad. A February 2018 report by the U.S. intelligence community described the targeting of national security information and proprietary information from US companies and research institutions involved with defense, energy, finance, dual-use technology, and other areas as "a persistent threat to US interests." Last month, U.S. electric grid reliability regulators imposed a $2.7 million penalty on an unidentified utility for its violations of mandatory reliability standards in connection with a data security breach -- the largest fine to date associated with U.S. utility cybersecurity regulation. In that case, a third-party contractor hired by the utility allegedly copied protected data from the utility's network to the contractor's unsecured network -- where it was accessible online without the need to enter a user ID or password, and where it was in fact accessed by one or more unknown outside entities.

In 2014, reports emerged that Russian hackers had found flaws in solar panel monitoring software that, if left unfixed, could allow malicious actors to damage the electric grid. Foreign state-sponsored cyber attacks in 2016 and 2017 against Ukraine and Saudi Arabia targeted multiple sectors across critical infrastructure, government, and commercial networks, causing disruption to Ukrainian energy distribution networks.

FERC disallows MLP pipelines' recovery of income tax allowance

Wednesday, March 21, 2018

U.S. energy regulators have revised their policies, and will no longer allow master limited partnership (MLP) interstate natural gas and oil pipelines to recover an income tax allowance in their cost-of-service rates. The Federal Energy Regulatory Commission issued its Revised Policy Statement on Treatment of Income Taxes following a 2016 federal court order addressing the topic.

At issue is the Commission's policy on how MLP pipelines may set their cost-based rates. As described by the Commission, an MLP is a partnership form in which units are traded on exchanges much like corporate stock. To be treated as an MLP for Federal income tax purposes, an MLP must receive at least 90 percent of its income from certain qualifying sources, including natural gas and oil transportation.

MLP pipelines are not corporations, but are pass-through entities. This means that MLPs are not taxed at the pipeline level; instead, for tax purposes, the partnership agreement allocates to each partner a share of the partnership’s taxable income, and each partner is personally responsible for paying income taxes on the partnership’s net taxable income.

From 2005 until a 2016 court ruling, the Commission's 2005 Income Tax Policy Statement allowed all partnership entities (including MLPs) to recover an income tax allowance for the partners' tax costs, much like a corporation receives an income tax allowance for its corporate income tax costs. Alongside this income tax policy, the Commission has used a discounted cash flow (DCF) methodology to determine the rate of return regulated entities need to attract capital.

In 2008, a pipeline MLP named SFPP, L.P. filed a cost-of-service rate increase to increase the rates for a line running between California and Arizona. Shippers protested the filed rates, including the interaction between (a) the Commission’s policy permitting an income tax allowance policy for partnership business forms (such as SFPP) and (b) the Commission’s DCF methodology used to determine a cost-of-service rate of return. The Commission eventually issued orders addressing issues in the case including the income tax allowance issue, which were challenged in court.

On appeal, in 2016 the United States Court of Appeals for the District of Columbia Circuit issued a decision known as United Airlines, Inc. v. FERC, 827 F.3d 122 (2016). In that case, the D.C. Circuit held that because both the partnership income tax allowance and the DCF ROE may include investors’ tax costs, permitting both may result in a double recovery, and remanded the case back to the Commission for further action.

This week, the Commission took that further action. It issued an order in the SFPP case denying that MLP an income tax allowance. More holistically, the Commission concurrently issued a Revised Policy Statement on Treatment of Income Taxes. In the revised policy statement, the Commission found that "an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology."

NH revises, reopens C&I solar rebate program

Tuesday, March 20, 2018

New Hampshire utility regulators have reopened a program offering a rebate to commercial and industrial electric customers who undertake qualifying solar energy projects, while reducing the size of the incentive and changing other program terms.

To encourage commercial and industrial (C&I) customers to participate in solar photovoltaic and solar thermal energy projects, the New Hampshire Public Utilities Commission first approved a solar rebate program in 2010. That program disburses funds from the state's Renewable Energy Fund to customers in exchange for customers' development of qualifying solar projects.

Terms and conditions for New Hampshire's C&I solar rebate program have varied since 2010, and the amounts of rebates available under the program have generally decreased over time. In 2015, the Commission created two separate categories of eligible projects with different rebate rates: Category 1, consisting of solar electric and thermal systems rated less than or equal to 100 kilowatts (AC) or thermal equivalent, and Category 2 consisting of solar electric systems greater than 100 kilowatts (AC) but less than or equal to 500 kilowatts (AC).

A 2016 Commission order set program rebate levels at $0.65 per watt (AC) for Category 1 new electric projects, and $0.55 per watt (AC), but not in excess of $175,000, for Category 2 new electric projects, in each case subject to a limit of 25 percent of the total project cost if less than the incentive payment otherwise calculated.

But the program closed to new applications as of July 14, 2017, due to "record demand" and a lack of funds. Even the allocation of additional funds only reopened the program for waitlisted applications, while keeping it closed to new applicants.

On February 13, 2018, Commission staff recommended reopening the program, while modifying it to further reduce the applicable incentive levels and to consolidate Category 1 and 2 projects into a single program that would allow applications for projects with capacities up to and including 500 kW AC.

On March 8, 2018, the Commission issued its Order No. 26,111, modifying the solar rebate program's terms and reopening the program. The changes include reduction in the amount of the rebate to $0.40 per watt up to a maximum of $50,000, or 25 percent of total project cost, whichever is less; and consolidation of Category 1 and 2 photovoltaic projects into a single program that would allow applications for projects with capacities up to and including 500 kilowatts AC. No change was made to the program terms and conditions applicable to solar thermal projects.

Under the order, the modified program terms and conditions became effective on March 19, 2018, and the program was reopened as of that date. The Commission noted that in anticipation of "robust demand for and potential oversubscription of the reopened program," it will conduct a public lottery in April to allocate initial queue positions for applications.

FERC acts on 2017 tax cuts

Monday, March 19, 2018

Federal utility regulators have taken a portfolio of actions in response to recent changes to U.S. tax law which reduced the tax rates applicable to many electric utilities and pipeline companies. Some rates for use of infrastructure will be reduced automatically, while regulators prompted others to explain why they should not be reduced to reflect the tax law changes. At the same time, regulators have opened an inquiry and proposed a rulemaking to address further aspects of the 2017 federal tax law change.

Late last year, Congress enacted the Tax Cuts and Jobs Act of 2017. That law amended U.S. tax law in a variety of ways. Among other things, the 2017 tax law changes reduced the federal corporate income tax rate from a maximum 35 percent to a flat 21 percent rate, effective January 1, 2018.

Many electric utilities and natural gas and oil pipeline companies stand to benefit from this tax reduction in the form of reduced income tax expense going forward, as well as a reduction in accumulated deferred income taxes on the books of rate-regulated companies. Where tax expense decreases, so does the cost of service.

Rates for use of some federally regulated energy infrastructure are set based on cost of service. On March 15, 2018, the Federal Energy Regulatory Commission took a series of actions to address the effect of the tax law changes on its regulated industries including electric transmission companies, interstate natural gas pipelines, and oil pipelines. According to the Commission, its actions “recognize the specific regulatory and operating parameters that must be addressed differently for each of the industries it regulates.”

Transmission rates for most FERC-regulated utilities automatically adjust with changes in the tax rates based on a formula whose inputs are updated annually or on some other regular cycle. For these utilities, a reduction in corporate income tax means a reduction in rates, although the ratemaking process means there can be a lag in time before rate reductions take effect.

But in some cases, utility tariffs provide for rates are either stated as a fixed number, or the formula includes a fixed tax rate. The Commission identified 48 companies whose transmission tariffs specifically reference tax rates of 35 percent. In a pair of show-cause orders issued under the Federal Power Act -- one for utilities with stated rates, and one for utilities with formula rates referencing 35 percent -- the Commission directed these companies to propose revisions to their transmission rates or show why they should not do so. It also issued two waivers allowing certain utilities mid-year rate adjustments to reflect the new tax law.

Interstate natural gas pipelines typically have stated rates for their services. These rates are approved by the Commission in a rate proceeding under Natural Gas Act sections 4 or 5 and remain in effect until changed in a subsequent section 4 or 5 proceeding. To revise its practices with respect to natural gas pipelines, the Commission issued a Notice of Proposed Rulemaking that would allow it determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax reduction and the Commission’s recently revised policies on income tax allowance. Under the rule proposed by the Commission, interstate pipelines would need to file a one-time report called “FERC Form No. 501-G” describing the rate effect of these changes. In addition to filing the one-time report, each pipeline would have four options: a pro rata rate reduction, a rate settlement or case, an explanation why no rate change is needed, or merely filing the FERC report and letting the Commission decide if further action is required.

While cost-of-service ratemaking typically applies to public utilities and interstate natural gas pipelines, most oil pipelines set their rates using indexing. With respect to oil pipelines regulated by the FERC, the Commission said it will address tax changes in the 2020 five-year review of the oil pipeline index level.

Concurrently, the Commission opened an inquiry into the effect of the Tax Cuts and Jobs Act of 2017 on all jurisdictional rates, including whether the Commission should address certain changes relating to accumulated deferred income taxes and bonus depreciation. In a presentation to the Commission, staff described this Notice of Inquiry as "a vehicle to help the Commission build a record to determine whether additional action is needed."

In a separate policy statement and order issued on March 15, the Commission revised its policies to disallow income tax allowance cost recovery in MLP pipeline rates.

ISO-NE files 12th capacity auction results

Monday, March 12, 2018

The organization responsible for New England's wholesale electricity markets has announced the results of its twelfth annual forward capacity auction. According to grid operator ISO New England, Inc., its FCA 12 concluded with sufficient resources to meet electricity demand in 2021-2022, at the lowest price in five years.

As in some (but not all) other organized electricity markets, New England's electricity market design includes a wholesale energy market as well as a forward capacity market. Operated by ISO New England, the Forward Capacity Market or FCM is designed to secure capacity resources sufficient to meet future demand. The capacity market is separate from the energy market, and can provide additional revenues for qualified resources.

The grid operator conducts annual Forward Capacity Auctions or FCAs, held three years in advance of each one-year operating period. Generation and other capacity resources such as load management or energy efficiency can compete in these auctions to obtain monthly market-priced capacity payments during the delivery year, in exchange for the obligation to supply capacity -- and supply energy or curtail demand when dispatched by the ISO in that future period. Capacity revenues can support the development of new resources as well as the retention of existing plants by providing predictable cash flows and incentivizing consistent resource availability.

ISO New England held its twelfth FCA on February 5 and 6, 2018, auctioning off capacity supply obligations for the capacity commitment period of June 1, 2021 through May 31, 2022. On February 28, 2018, ISO New England submitted its forward capacity auction results filing for FCA12 to the Commission. According to the filing, the descending clock auction commenced with a starting price of $12.684/kW-month, with resources in most zones to be paid at a clearing price of $4.631/kW-month based on the system sloped demand curve. About 1,100 megawatts of imports over certain interfaces with Canada will be paid at reduced capacity clearing prices. These prices are all below recent ISO-NE forward capacity auction results.

Through FCA12, ISO-NE procured 30,011 megawatts of generation, including 174 megawatts of new generation. The auction also acquired about 3,600 megawatts of energy efficiency and demand-reduction measures, 514 megawatts of which is new. The grid operator estimated the total cost of the capacity market in 2021-2022 to be approximately $2.07 billion.

ISO noted that it had rejected two "de-list bids", or requests by existing generators to leave the capacity market, for local reliability reasons. It identified those bids as coming from Exelon Generation Company, LLC with respect to its Mystic 7 and 8 units, totaling about 1,278 megawatts. As described in supporting testimony, ISO asserted that "allowing the resources to leave the market would have resulted in a violation of NERC, NPCC, or ISO criteria." According to a related press release, ISO found that "transmission lines in Greater Boston could be overloaded if Mystic 7 and Mystic 8 were not available during 2021-2022."

ISO described the results of the auction as just and reasonable, and asked the Commission to accept the filing.

FERC Order 842 requires primary frequency response by generators

U.S. energy regulators have issued an order amending standard interconnection agreements to require new generators to install, maintain and operate a functioning governor or equivalent controls capable of primary frequency response as a precondition of interconnection. The Federal Energy Regulatory Commission's Order No. 842 also amended the pro forma interconnection agreements to include certain operating requirements including maximum droop and deadband parameters, and sustained response provisions.

As described by the Commission, reliable operation of an alternating current grid requires maintaining system frequency within predetermined boundaries above and below 60 Hertz. Frequency response describes an interconnected grid’s ability to arrest and stabilize deviations from this predetermined range of frequencies after a sudden loss of generation or load.

Historically, the U.S. grid's primary frequency response capability came from baseload synchronous generators such as coal-fired power plants. But many such plants have retired in recent years, with further retirements expected. In 2016, the Commission noted that shifts in the portfolio of U.S. electric generators meant fewer resources could likely provide primary frequency response, especially if new variable energy resources such as wind and solar did not provide this service. In response, it opened an inquiry into what primary frequency response reforms it should make.

On February 15, 2018, the Commission issued its Order No. 842 revising its regulations to require newly interconnecting large and small generating facilities, both synchronous and non-synchronous, to install, maintain, and operate equipment capable of providing primary frequency response as a condition of interconnection. The final rule also amends the Commission's pro forma interconnection agreements to include certain operating requirements including maximum droop and deadband parameters, and sustained response provisions. It provides exemptions for nuclear power plants and some combined heat-and-power plants.

These requirements will apply to most newly interconnecting generation facilities that execute, or request the unexecuted filing of, an LGIA or SGIA on or after the rule’s effective date, as well as to existing large and small generating facilities that take any action that requires the submission of a new interconnection request that results in the filing of an executed or unexecuted interconnection agreement on or after the effective date.

In a press release, the Commission said its action was intended to address "the increasing impact of the evolving generation resource mix." Commissioner LaFleur made a separate statement in which she noted that while decreases in the nation's portfolio percentage of synchronous generation have contributed to declining frequency response performance, "recent technological advancements have enabled new non-synchronous generating facilities, such as wind and solar, to cost-effectively include primary frequency response capabilities in their facilities." Improved inverters and battery storage are among these innovations.

The Commission has also recently noted the potential of electric storage resources to provide frequency response and other services. Its Order No. 841 is designed to remove barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators, including markets for frequency response.

NERC fines utility $2.7 million for cyber breach

Friday, March 9, 2018

The electric reliability organization responsible for the grid spanning much of North America has penalized an unidentified utility $2.7 million for its violations of mandatory reliability standards in connection with a data security breach. The penalty may be the largest fine to date associated with U.S. utility cybersecurity regulation.

NERC, or the North American Electric Reliability Corporation, is charged by U.S. law with ensuring the reliability of the nation's bulk power system. NERC establishes reliability standards for the bulk electric system, which are approved by the Federal Energy Regulatory Commission, and takes action to monitor and enforce compliance with its reliability standards.

On February 28, 2018, NERC filed with the Commission a Notice of Penalty regarding what it described as noncompliance by an "Unidentified Registered Entity (URE)", following a settlement between the anonymous utility and regional reliability group Western Electricity Coordinating Council (WECC).

Some of the details of the underlying fact pattern are protected from public disclosure as Critical Energy Infrastructure Information or CEII. But NERC's public filing says the settlement arose from WECC's determination and findings that the anonymous utility violated two of NERC's Critical Infrastructure Protection or CIP cybersecurity standards. According to NERC's report, the utility received a report that an outside "white hat security researcher" had found data publicly available online which appeared to be protected information associated with the utility.

Following this tipoff, an investigation by the utility and regional reliability group WECC revealed that a third-party contractor hired by the utility had copied data from the utility's network environment to the contractor's network environment, where it was no longer subject to the utility's visibility or control -- in violation of the contractor's authority. While the data was on the contractor's network, a subset of live utility data including over 30,000 records was accessible online without the need to enter a user ID or password for a period of 70 days. These records included some associated with the utility's Critical Cyber Assets, such as servers storing user data, systems controlling physical access within the utility's control centers and substations, and supervisory control and data acquisition or SCADA systems. System logs showed unauthorized access to this data set by both the white hat researcher and unidentified IP addresses.

According to the Settlement Agreement, the anonymous utility neither admitted nor denied the violations, but agreed to pay a $2,700,000 penalty and take other compliance actions. This may represent the largest fine to date for violations of NERC's CIP standards. While federal penalty policy encourages self-reporting of violations and having an internal compliance program in place -- as the anonymous utility did -- the settlement notes that the utility "was not fully transparent and forthcoming with all pertinent information detailing the data exposed in the incident." In particular, the settlement says the utility did not initially provide WECC with all the data fields exposed in the incident. These factors, combined with a finding that the violations posed a serious and substantial risk to the reliability of the bulk power system, led WECC to set the penalty amount at $2.7 million, which NERC subsequently approved.

By federal rule, the penalty will be effective upon expiration of the 30-day period following the penalty notice's filing with the Federal Energy Regulatory Commission or, if FERC decides to review the penalty, upon final determination by FERC.

Vermont Yankee decommissioning settlement

Wednesday, March 7, 2018

The owner of the closed Vermont Yankee Nuclear Power Station and the company proposing to buy and decommission the plant have announced a settlement with the state of Vermont and other interested parties. Under the settlement agreement and a related memorandum of understanding, proposed buyer NorthStar Group Services Inc. would provide increased financial assurances and a "comprehensive reporting protocol" and agreed to detailed standards for restoring the project site in the town of Vernon. If approved by regulators, the deal could also lead to the Vermont Yankee plant's decontamination and dismantlement about 45 years sooner than current owner and licensee Entergy Corp. originally proposed.

The Vermont Yankee Nuclear Power Station began commercial operation in 1972. Entergy bought the plant from the Vermont Yankee Nuclear Power Corp. in 2002, and shut it down permanently on December 29, 2014. In a Post Shutdown Decommissioning Activities Report contemporaneously filed with the Nuclear Regulatory Commission, Entergy said it expected to initiate decontamination and dismantlement of the Vermont Yankee site in 2068, with projected completion of both decommissioning and site restoration by 2075. In November 2016, Entergy proposed selling the site to NorthStar for decommissioning.

On March 7, 2018, Entergy and NorthStar announced what they called "significant milestones in the approval of the proposed transaction": signing a settlement agreement and memorandum of understanding with Vermont state agencies and other interested parties. Agencies signing the agreement, in whole or in part, included the Vermont Department of Public Service, Agency of Natural Resources, Department of Health, and Attorney General's Office.  Other signatories to the settlement include the Town of Vernon Planning and Economic Development Commission, the Windham Regional Commission, the Abenaki Nation of Missisquoi and the Elnu Abenaki Tribe, and the New England Coalition on Nuclear Pollution (NEC).

Under the settlement's revised vision of the proposed transaction, NorthStar has committed to initiate decontamination and dismantlement by 2021 (and potentially as early as 2019) and to complete decommissioning and restoration of most of the Vermont Yankee site by 2030 (and potentially as early as 2026). The Independent Spent Fuel Storage Installation or ISFSI would remain on-site.

The settlement also calls for NorthStar to provide additional financial assurance beyond that originally proposed. Enhanced financial assurance provisions include an increase in the amount of NorthStar's corporate support agreement from $125 million to $140 million; establishment of an escrow account, subcontractor guaranty, and pollution insurance requirements; and a comprehensive reporting protocol. Entergy also committed to contribute to the Site Restoration Trust, and to possibly use future proceeds from litigation against the U.S. Department of Energy over spent fuel storage costs as additional financial assurance.

The settlement remains subject to approval by the Vermont Public Utility Commission. The transaction would also require approval by the U.S. Nuclear Regulatory Commission.

Maine considers water shortage readiness

Tuesday, March 6, 2018

In the midst of a regulatory inquiry into Maine water utilities' ability to prepare for and respond to water supply emergencies, agency staff have issued a preliminary recommendation intended to stimulate further discussion and comment -- which could ultimately lead to changes in how Maine regulates water utilities and water supply.

2016 brought drought to much of Maine. According to a Notice of Inquiry issued by the Maine Public Utilities Commission that year, the drought posed special challenges for some of Maine's water systems with limited sources of supply -- especially those with significant seasonal demands, antiquated infrastructure, or high levels of non-revenue water. In response, the Commission opened an inquiry to gather information that will allow it to identify problems and identify collaborative and proactive solutions. The Commission received responsive comments from about a dozen water utilities, and staff conducted additional research on the topic.

On March 5, 2018, the Commission staff issued its Preliminary Recommendation in regard to the Inquiry. The document describes its recommendations as preliminary and “intended to stimulate further discussion and comment on the issues raised in the document”. It says its intended audience “is broader than the usual participants in Commission proceedings and includes entities that may not be familiar with Commission practices and governing statutes.”

Findings in the 36-page Preliminary Recommendation include:

  • Maine’s 152 water utilities responded well to the 2016 drought.
  • Most of Maine's water utilities should be allowed to make their own decisions regarding water supply emergencies.
    • Most Maine water utilities have the ability to adequately prepare for, and respond to, a water supply emergency.
    • Water supply emergencies are not amenable to a one-size-fits-all approach because of the wide variety of potential circumstances.
    • All Maine water utilities should be required to prepare some sort of Emergency Response Plan, and all that experience a water supply emergency should be required to prepare an after-action report.
  • Water utilities need clearly-defined authority to respond to a water supply emergency -- ideally in the utility's Terms and Conditions.
  • Various entities can provide help to a water utility that needs assistance preparing for, and responding to, a water supply emergency. Support can come from neighboring systems, membership organizations, and state agencies.
  • State agencies should work cooperatively to support water utilities before, during, and after a water supply emergency.
  • Effective communication before and during a water supply emergency is critical.
  • Some Maine water utilities are more vulnerable to a water supply emergency and may need assistance -- especially those with a limited source of supply, aging infrastructure, high levels of non-revenue/unaccounted-for water, seasonal demands, and lack of metered service. Other challenges include a lack of resources, recalcitrant customers, and local socioeconomic factors, or excessively prioritizing low rates over critical system improvements.

Commission staff has requested written comments by March 30. It said it is considering holding between two and five workshops across Maine to solicit oral comments about the Preliminary Recommendation, after which it will draft a Final Recommendation for the Commission’s review.

US considers critical minerals update

Friday, March 2, 2018

The U.S. Department of the Interior has published an updated draft list of minerals considered critical to the nation's economic and national security. The move follows a presidential order calling for revised national strategies for managing critical mineral commodities.

President Donald Trump issued Executive Order 13817 on December 20, 2017.
Predicated on a finding that the United States "is heavily reliant on imports of certain mineral commodities that are vital to the Nation’s security and economic prosperity," the executive order directed the Secretary of the Interior, in coordination with the Secretary of Defense and in consultation with the heads of other relevant executive departments and agencies, to publish a list of critical minerals, to reduce national vulnerability to disruptions in the supply of critical minerals, and to develop a strategy to reduce reliance on critical minerals.

The executive order defines “critical mineral” as including (i) non-fuel minerals or mineral material essential to the economic and national security of the United States, (ii) the supply chain of which is vulnerable to disruption, and (iii) that serve an essential function in the manufacturing of a product, the absence of which would have significant consequences for our economy or our national security.

On February 16, 2018, the U.S. Department of Interior's U.S. Geological Survey released a draft list of 35 critical minerals, requesting public comment before March 19, 2018. Minerals identified in the draft 2018 list include: aluminum (bauxite), antimony, arsenic, barite, beryllium, bismith, cesium, chromium, cobalt, fluorspar, gallium, germanium, graphite (natural), hafnium, helium, indium, lithium, magnesium, manganese, niobium, platinum group metals, potash, rare earth elements group, rhenium, rubidium, scandium, strontium, tantalum, titanium, tungsten, uranium, vanadium, and zirconium.

Previous USGS lists of critical minerals have focused on about 23 mineral commodities: antimony, barite, beryllium, cobalt, fluorite or fluorspar, gallium, germanium, graphite, hafnium, indium, lithium, manganese, niobium, platinum group elements, rare earth elements, rhenium, selenium, tantalum, tellurium, tin, titanium, vanadium, and zirconium.

Once the list of critical minerals is finalized, the executive order calls for the Secretary of Commerce, in coordination with other agencies, to submit a report to the President including a strategy to reduce the Nation’s reliance on critical minerals, an assessment of technologies for recycling and reprocessing critical minerals, a plan to improve mapping to support private sector mineral exploration of critical minerals, and a proposal to streamline regulatory processes.

Report: 50 GW US electric storage potential

Thursday, March 1, 2018

A recently adopted federal regulation aimed at helping electric storage resources participate in wholesale electricity markets could unlock 7,000 megawatts of storage potential -- or up to 50,000 megawatts if all benefits can be captured through state and federal action -- according to a report by consulting firm The Brattle Group.

The study is titled, “Getting to 50 GW? The Role of FERC Order 841, RTOs, States, and Utilities in Unlocking Storage’s Potential.” Released on February 22, 2018, the report concludes that electric storage market potential could grow to 50,000 MW within the next ten years, if storage costs continue to decline and state and federal regulatory policies continue to be supportive.

The Brattle report comes one week after the Federal Energy Regulatory Commission's issuance of Order No. 841, a final rule aimed at removing barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators. The Brattle report describes Order 841 as "an important step in unlocking the value in wholesale energy, ancillary services, and capacity markets," noting the consulting firm's finding that at least half of storage's total possible value can be achieved in wholesale electricity markets.

Crucially, the Brattle study finds that fully realizing the value of electric storage will require state policy reforms similar to those at the federal level. Generally speaking, wholesale electricity sales and interstate transmission are subject to federal jurisdiction, while retail sales and local distribution are subject to state jurisdiction. This split jurisdiction means that some value streams available through battery storage can be only captured at the state level -- for example benefits from deferring or avoiding investments in transmission and distribution infrastructure by using storage as a non-transmission alternative, or customer benefits like increased reliability and engagement with power supply.

Storage can also save customers money -- as noted in the report, avoiding retail rate demand changes is one of the primary business drivers for storage deployment by U.S. commercial and industrial customers. But these values can only be fully captured through state action to remove the barriers that remain.

Some states are acting to incentivize or require energy storage investments. California set a mandate of 1,325 megawatts of storage by 2020, and Oregon and Massachusetts have also set state storage mandates.

The report also covers implications for existing storage resources, most of which are hydropower. It finds that existing storage resources can provide substantial new capabilities, if they can be operated more flexibly than today. As noted in the report, "Increasing flexibility of existing hydro can be very valuable, reducing the need for new investments." The report also suggests that optimizing operating strategies could increase storage revenues by 2 to 5 times.