Page 1453 – RTO Insider

April 27, 2016

SPP Awards First Order 1000 Project — But it May Not be Needed

By Tom Kleckner

SANTA FE, N.M. — SPP awarded its first competitively bid transmission project under FERC Order 1000 on Tuesday, but it may not be built because of declining load forecasts.

The RTO’s Board of Directors and Members Committee both voted to accept an industry expert panel’s (IEP) recommendation to award the 22.6-mile, 115-kV line from Walkemeyer to North Liberal in southwest Kansas to Mid-Kansas Electric.

spp, order 1000 — The proposed Walkemeyer-North Liberal 115-kV line is in Seward County, in the southwest corner of Mid-Kansas Electric’s service territory.

Oklahoma Gas & Electric was selected as the alternative “designated transmission owner” should Mid-Kansas be unable to construct the project. Mid-Kansas and OG&E received the panel’s two highest scores among the 11 competitive proposals submitted to SPP.

Mid-Kansas CEO Stuart Lowry accepted congratulations from fellow members and gathered his employees in a group hug after the vote, before telling RTO Insider the company had proposed the project be re-evaluated. He later told members the Mid-Kansas and Sunflower Electric Power system has seen a 27% reduction in load forecasts within the project’s region.

Mid-Kansas is owned by five electric cooperatives members and a not-for-profit company, and managed and operated by Sunflower, a wholesale generation and transmission provider.

Mid-Kansas said the area has seen a drop in forecasted loads from oil and gas exploration. It also loses the auxiliary load of a nearby gas-powered generating plant when SPP doesn’t dispatch the plant. The load forecast that drove the need for the Walkemeyer project was conducted almost three years ago as part of SPP’s Integrated Transmission Planning 10-year assessment.

“I try to put myself in [the stakeholders’] shoes,” Lowry said. “This project is a reliability project, so it’s totally driven by load forecasts. We’re seeing a reduction in the region, so we made a decision we need to report on this. If the information is correct, we want to do what is best.”

Lowry said Mid-Kansas has contracted with Burns & McDonnell to provide an “independent set of eyes” on the need for the new line.

Mid-Kansas asked SPP last month to re-evaluate notices-to-construct it has already received for the two noncompetitive portions of the project, which include terminal upgrades at the existing North Liberal and Walkemeyer substations. The board granted staff’s request for an expedited review of the need for both NTCs, which were awarded last summer.

SPP CEO Nick Brown also mentioned the load-forecast changes at a Gulf Coast Power Association conference two weeks ago. (See Grid Execs Talk Cybersecurity, Renewables, Order 1000.)

Paul Suskie, SPP’s executive vice president of regulatory policy and general counsel, said SPP members are free under the Tariff to request project re-evaluations at any time.

“The request to restudy this line is a part of our stakeholder process that occurs every year,” he said. “SPP will re-evaluate this line as we have others in the past.”

Mid-Kansas’ winning bid received an 892.85 score on a 1,000-point scale from the IEP, 13% higher than OG&E’s proposal, which scored a 785.67. The other nine bidders were not identified.

Mid-Kansas was one of only two bidders to win 100 incentive points for providing a “detailed project proposal,” but it would have won even without it, the IEP said.

The IEP’s scoring methodology graded each respondent on engineering design, experience in project management, construction and operations, a rate analysis (estimated total cost, including financing, FERC incentives and any cost certainty guarantees by the bidder) and finance (including financial viability and creditworthiness).

The panel said the Mid-Kansas proposal met all of its evaluation criteria, receiving 90% of the possible finance points and contained the second-lowest 40-year net present value.

SPP Board of Directors Meeting, Order 1000 — Steve Strickland, chairman of SPP’s industry expert panel, makes a point during Tuesday’s board meeting as FERC Chairman Norman Bay, center, and others listen. *© RTO Insider*

“Our recommendation was built around what the entire panel felt would a successful project,” said the panel’s chair, Steve Strickland, who spent 35 years with Entergy Arkansas. “We defined that as a project that operated as intended, was on schedule and under budget.”

The Mid-Kansas and OG&E proposals were very close with their engineering and construction cost estimates ($8.33 million versus $8.44 million, respectively) and NPV estimates ($10.57 million versus $10.15 million).

“This represents a lot of hard work by our staff. A lot of the credit goes to them,” said Lowry, naming Mid-Kansas COO Kyle Nelson, CFO Davis Rooney and Al Tamimi, vice president of transmission planning and policy at Sunflower. “There was a lot of uncertainty over the process, how the proposals would be evaluated … everyone learned a great deal.”

Formed in 2005, Mid-Kansas serves a combined 200,000 members in western and central Kansas. Its assets include 843 MW of natural gas, coal and wind generation and about 1,140 miles of transmission. Sunflower adds another 655 MW of generation and 1,205 miles of transmission.

SPP stakeholders developed and FERC approved a transmission owner selection process to comply with Order 1000, which required the removal of federal rights of first refusal for certain transmission projects.

The process began in June 2014, when interested parties had 180 days to respond to the Walkemeyer project’s request for proposals. The IEP was established in November, and shortly thereafter it began its review and evaluation of the 11 responses.

[Editor’s Note: An earlier version of this article incorrectly stated the net present value of the Mid-Kansas and OGE proposals in billions rather than millions. It also incorrectly stated that the noncompetitive portion of the project included a switching station.]

April 25, 2016

MISO Planning Advisory Committees Briefs

MISO is recommending that Michigan Electric Transmission Co. (METC) construct a portion of a proposed transmission line intended to upgrade supply for Coldwater, Mich., while rejecting expedited review for a broader proposal.

The RTO is backing a portion of the proposed $65 million Coldwater load interconnection project that would provide the city an additional 18 MW of supply capability by 2017 via a 138-kV tap from an existing METC line. Parent company ITC Holdings sought expedited review of a larger project that would have included an additional 18 MW of capacity by 2021. (See “MISO Receives 1st Expedited Review Request,” MISO Planning Advisory Committee Briefs.)

MISO said it agreed with stakeholders at the Technical Study Task Force, which reviewed the project in March, that only the improvements necessary to manage Coldwater’s 2017 incremental load required expedited treatment. Less pressing work to meet the 2021 goal would be relegated to the MISO 2016 Transmission Expansion Plan.

Of Coldwater’s total load of 88 MW, 65 MW is currently supplied through a single 4.5-mile 138-kV transmission circuit, Thompson Adu, MISO senior manager of transmission expansion planning, told the Planning Advisory Committee last week. New industrial load is expected to push that total to more than 120 MW by 2026.

METC’s proposed radial supply line would carry 83 MW when completed, Adu said.

MISO Adds Tariff Provisions for Identical Market Participant-Funded Projects

MISO has revised its Tariff to comply with a December FERC order requiring a first-come, first-served selection procedure when more than one market participant proposes to fund the same transmission projects.

The process set out in the Tariff will mirror that already represented in a MISO business practices manual.

The issue was brought to light last year when Boston Energy Trading and Marketing and J. Aron & Co. both proposed to fund Ameren Illinois’ Effingham-Effingham NW 138-kV line in Illinois at an estimated cost of more than $1 million.

Boston Energy filed a complaint saying that MISO tried to force it to partner with J. Aron on the project based on language in a BPM but that it lacked Tariff authority to do so.

FERC sided with Boston Energy, saying MISO’s Tariff was unjust and unreasonable because it lacked provisions for processing market participant-funded transmission projects (EL15-89). The commission required new Tariff language that addresses how the RTO “will handle multiple, similar requests for market participant funding of a transmission upgrade.”

The Tariff revisions will mirror BPM language already vetted by the PAC. Adu said the new language will be filed with the commission by the June 20 compliance deadline.

MISO Order 1000 Compliance

MISO is nearing completion of its Order 1000 interregional compliance obligations, said Eric Thoms, the RTO’s manager of planning coordination and strategy.

FERC accepted MISO’s compliance filings with both SPP and Southeastern Regional Transmission Planning, while seeking clarification on cost allocation, interconnection projects and ownership rights in its joint filing with PJM (ER13-1944-001, et al.).

Meanwhile, MISO continues to pursue interregional efforts with its neighbors. At present, 14 projects near the MISO-SPP seam are being considered in MTEP16.

MISO and PJM have begun searching for “low-cost, quick-implementation upgrades” as part of their 2016 quick hits study process. Thoms said there was “value” in the quick hits studies, but the process needs to be formalized to reflect cost allocation.

“If we’re looking at low-hanging fruit … there’s no need for [multiple regional approval processes],” he said.

MISO and PJM have also completed two targeted studies from 2015 on the Michigan-Indiana and Quad Cities interfaces.

“We’ll continue to monitor this issue,” Thoms said.

— Amanda Durish Cook

April 25, 2016

FERC Rules on MISO Revenue Sufficiency Guarantee

By Amanda Durish Cook

FERC on Thursday cleared a backlog of disputes over MISO’s revenue sufficiency guarantee (RSG), issuing a quartet of orders in dockets dating back to 2009 concerning intermittent resources, headroom, cost allocation and resettlement procedures.

The commission:

Exempted intermittent resources from RSG charges when they respond to MISO curtailment orders (ER11-2275-003) but refused to rehear arguments that such resources should be exempt from RSG charges altogether (ER09-411- 005);
Upheld MISO’s continued use of a real-time headroom definition in its allocation of RSG charges (ER11-2275-002); and
Refused to rehear arguments about MISO’s RSG assessments on MISO customers making both virtual supply offers and electricity withdrawals (EL07-86-012, et al.).

Generation or demand response resources receive RSG payments if they are committed through the reliability assessment commitment (RAC) process after the close of the day-ahead markets and they receive insufficient real-time energy and operating reserve revenues to cover its production costs.

Intermittent Resources

FERC’s order exempting curtailed intermittent resources from RSG charges was made effective July 2, 2011, rather than the May 2011 date sought by renewable generators. E.ON Climate and Renewables North America and NextEra Energy Power Marketing protested the later date, saying it subjected them to extra months of revenue sufficiency guarantee charges for “no just reason.”

FERC ruled the extra 60 days were reasonable because MISO needed extra time to adjust its systems and procedures to incorporate the exemption.

In the second case, the commission reiterated a compliance order rejecting a request to exempt intermittent resources from all RSG charges.

The commission cited an “extensive record” documenting that “increases and decreases in the real-time output of intermittent resources, as well as the reduced forecasts or unavailability of such resources, may cause real-time revenue sufficiency guarantee costs.”

FERC said the rehearing requests from more than 15 companies only repeated arguments it previously rejected and that exempting intermittent resources from RSG charges “would unfairly shift costs to other market participants.”

The companies had claimed MISO’s Independent Market Monitor overstated intermittent resources’ contributions to the make-whole costs and a MISO analysis didn’t take into account several intermittent characteristics, including transmission de-rates, grandfathered transmission agreements, system topology and changes in loop flows.

FERC said that while it recognized changes between thermal and intermittent resources, the differences didn’t warrant an exemption.

Headroom Definition

In a third ruling, FERC upheld MISO’s definition of real-time headroom — the difference between the real-time economic maximum dispatch and real-time dispatch targets for resources — in its allocation of RSG charges.

Under methodology proposed by MISO and accepted by FERC in 2011, the headroom charge was calculated based on the lesser of headroom or the aggregate of the hourly economic maximum dispatch amounts of all resources committed in any RAC process. In the Thursday order, FERC clarified that the headroom definition isn’t limited to intra-day RAC commitments and includes commitments made in MISO’s forward RAC process.

MISO’s Transmission-Dependent Utilities sector had said MISO’s headroom cap should be eliminated or limited to include only headroom contributed by resources committed in the intra-day RAC. The commission said the forward reliability assessment commitment process is part of the real-time commitment process, and therefore should be included.

A group of six financial marketers said FERC headroom costs should be allocated to all market participants based on market load ratio, rather than assessed on virtual offers and deviations. FERC responded that headroom allocations are already based on market load share.

The order also upheld MISO’s allocation of exempted deviations, which were challenged by Westar Energy on the basis that too many costs are allocated to deviations than to load. FERC brushed the complaint aside. “As the commission has stated in previous revenue sufficiency guarantee charge proceedings, there is no such thing as an ideal and static proportion of costs that should be allocated to any activity. Rather, a reasonable allocation is one that reflects cost causation principles,” FERC said.

Virtual Offers

In the final order, FERC refused to rehear arguments about flaws in RSG proceedings first brought up nine years ago. In 2007, Ameren, Northern Indiana Public Service Co. and eight other utilities alleged discrimination in MISO’s RSG rate because it was assessed on only a subgroup of MISO customers making both virtual supply offers and electricity withdrawals. MISO was directed to modify its Tariff so the RSG applied to all cleared virtual supply offers. The RTO then began stakeholder discussions on refunds and resettlement for the period of Nov. 5, 2007, to Nov. 9, 2008.

Several companies requested rehearing on the matter. Tenaska Power Services wanted FERC to order MISO to issue refunds with interest. Seven financial marketers asked for MISO’s RSG to be recalculated by adding exempted deviations back into the formula. The bulk of the requests claimed that MISO didn’t hold any stakeholder meetings on the resettlement.

FERC refused all rehearing requests, saying the issues in the case were “strictly limited to the compliance requirements” and the companies’ requests were beyond the scope of the order. “The resettlement process undertaken by MISO, reflecting its interpretation of the MISO tariff with respect to exempted deviations, has been the subject of proceedings in docket no. ER04-691,” FERC noted.

April 25, 2016

FERC Upholds PJM’s Treatment of Demand Response

By Suzanne Herel

FERC last week denied five requests for changes in PJM’s treatment of demand response, rebuffing filings by the Independent Market Monitor, DR providers, industrial customers and Public Service Enterprise Group.

The commission rejected an allegation by the Monitor that PJM doesn’t treat DR in a way comparable with generation capacity resources. The Monitor said it should be subject to a must-offer requirement in the day-ahead energy market as well as the energy offer cap (EL14-20). (See Monitor Asks FERC for Must-Offer on Demand Response.)

“The commission has … explained that comparability does not require that generation resources and demand response resources be subject to the same operational parameters in every circumstance,” FERC said.

Viridity Energy had filed a complaint that PJM’s compensation provisions are discriminatory to capacity-only resources because an end-use customer that registers with one curtailment service provider (CSP) for capacity and a second CSP for energy does not receive a guaranteed energy payment when called to reduce load in response to an emergency.

FERC cited reliability issues and the avoidance of double payments in denying the complaint (EL12-54).

The commission said the differences in compensation were justified by the need to avoid errors in measurement and verification by customers represented by two different CSPs from inadvertently or intentionally submitting duplicate offers for the same megawatts covering the same time period. “Duplicate offers, as PJM notes, could create reliability problems by erroneously indicating to PJM’s operators that they will be getting twice the demand reduction that is actually available during an emergency condition. As PJM further notes, market participants, in this circumstance, could be required to pay twice for the same reduction.”

EnergyConnect and Comverge were denied rehearing of a May 2014 order accepting rules increasing the operational flexibility of DR. FERC also found that PJM’s compliance filing satisfied the requirements of the May order (ER14-822).

The commission also denied a rehearing request from the PJM Industrial Customer Coalition regarding a January 2014 order that capped PJM’s procurement of certain limited-availability DR products. The order noted that PJM’s limited and extended summer DR products will be eliminated as a result of the new Capacity Performance rules (ER14-504).

Finally, FERC denied a rehearing request from PSEG that challenged a requirement that DR providers submit certain information before the Base Residual Auction proving their ability to perform when needed (ER13-2108). In part, the commission found that the general statement of obligation applies to all capacity resources and is not specific to DR.

Chairman Norman Bay said that the Supreme Court upholding FERC’s jurisdiction over DR has allowed the commission to begin clearing a backlog of DR cases. “There were a number of DR matters that could not be resolved until the Supreme Court issued its decision,” he said.

April 25, 2016

Company Briefs

Consumers Energy decommissioned the last of its Michigan “Classic Seven” coal-fired turbines in response to tighter EPA emissions restrictions. The B.C. Cobb Generating Facility on Muskegon Lake ended its 67-year run in mid-April.

The turbines were retired in staggered order in consultation with MISO. The turbines included two at B.C. Cobb, two at the D.E. Karn/J.C. Weadock Generating Complex in Essexville and three at the J.R. Whiting Generating Complex in Luna Pier.

Consumers is currently outfitting five of its operational coal-fired plants with scrubber systems to meet emissions standards.

More: MLive

LG&E/KU Unveil Kentucky’s Largest Solar Array

Kentucky’s largest solar facility was inaugurated last week by Louisville Gas & Electric and Kentucky Utilities. The E.W. Brown Generation Station in central Kentucky contains about 44,600 solar panels, capable of producing 19,000 MWh of electricity annually.

“We’re embarking on a new era and introducing a new source of energy to our generation portfolio that will work in concert with our coal, natural gas and hydroelectric fleet,” Paul Thompson, chief operating officer for the PPL-owned utilities, said at an unveiling ceremony.

Thompson said the new facility will allow LG&E and KU to study how commercial-scale solar energy is impacted by factors such as cloud cover and “how it integrates with the existing generating units.”

More: The Advocate-Messenger

Exelon, RES Join to Build 10-MW Energy Storage Unit

Exelon Generation and Renewable Energy Systems are joining to build a 10-MW energy storage facility in Clinton County, Ohio, that is expected to be operational by the end of the year.

RES, which operates 48 MW of storage facilities, will oversee construction of the project, which Exelon Generation will operate. The unit will comprise three tractor-trailer-sized modular units near a substation for easy interconnection with PJM.

The facility will provide frequency regulation for the RTO. “Exelon’s deployment of battery storage technology provides customers and grid operators with innovative solutions to meet their technical requirements and enhance system reliability,” said Corey Hessen, vice president of Exelon Generation Development.

More: Exelon Generation

Con Ed Investing in More Natural Gas Pipelines

Consolidated Edison is investing about $975 million in a joint venture to own natural gas pipelines and storage serving the northeast markets.

Stagecoach Gas Services will be managed by Crestwood Equity Partners and own assets in Pennsylvania and New York.

Con Ed announced the creation of Con Edison Transmission, a unit to invest in pipeline and transmission line projects, in January. Like other utilities, Con Ed is investing more in pipelines as electricity demand slows.

More: Bloomberg

Exelon Warns of Possible Clinton Nuke Closure

Although it cleared the 2016/17 MISO capacity auction, the Clinton nuclear station may not stay open after May 31, 2017, without some sort of subsidies, warned Exelon CEO Chris Crane.

“Without urgent action on the policy front, we will have no choice but to prepare for a potential early retirement in the face of continued financial losses at our Clinton nuclear plant,” he said. “The loss of this plant would have significant economic impacts on southern Illinois and erase the environmental benefits equal to 80% of the wind installed in Illinois, making it significantly harder and more expensive for the state to meet its carbon reduction goals.”

Exelon is in the middle of a hard lobbying campaign in Illinois, seeking policy changes that would reward Clinton, and its five other nuclear stations in Illinois, for being carbon-free.

More: Exelon

SunEdison’s Rise in Solar Industry Ends in Bankruptcy

SunEdison, the St. Louis-based company that shot to the top of American solar energy companies, filed for bankruptcy protection last week after multiple acquisitions left the company strapped for cash.

Analysts say the cause of the company’s demise stems from unwise investments, not an inherent problem with the solar industry. Much of the company’s growth occurred through a rapid series of large acquisitions, encumbering itself with substantial debt.

“Our decision to initiate a court-supervised restructuring was a difficult but important step to address our immediate liquidity issues,” CEO Ahmad Chatila said.

More: The Associated Press

GridLiance Adds Seattle CFO To its Leadership Team

bishopgridliancesourcegridliance — Bishop

GridLiance last week announced it had hired Seattle City Light CFO Jeff Bishop as its senior vice president, CFO and treasurer.

Bishop has spent 15 years in the industry, including financial leadership roles at PacifiCorp. He holds two bachelor’s degrees: one in accounting from Washington State University and another in zoology from the University of Washington.

“Municipal and consumer-owned power agencies, which have historically been unable to invest in large-scale, regional transmission projects, will benefit from GridLiance’s forward-thinking approach,” Bishop said.

More: GridLiance

Wind Farm Being Developed Near Colstrip Plant

Clearwater Energy is laying the groundwork for a 300-MW wind farm in eastern Montana, near transmission infrastructure that now serves the coal-fired Colstrip Power Plant near Billings.

The 500-kV power lines and a substation are big enough to accommodate Colstrip and the 300-MW Clearwater project. The Bonneville Power Administration, NorthWestern Energy and other stakeholders in the transmission lines serving Colstrip have discussed upgrading the transmission system to 700 MW. The Clearwater project is being planned to fill that extra capacity if it materializes.

More: Missoulian

Northern Pass Tx Line Contractors Named

Eversource Energy has named the contractors and material suppliers for the $1.6 billion Northern Pass transmission line, which is awaiting final state and federal permits.

Eversource named Quanta Service subsidiary PAR Electrical Contractors as general contractor. Burns and McDonnell Engineering will continue as part of the project team. The ABB Group will design and build the line’s underground section and a converter station in Franklin, N.H.

More: New Hampshire Union Leader

PPL Completes Northeast-Pocono Reliability Project

PPL Electric Utilities last week completed its $350 million Northeast-Pocono Reliability Project — more than a year before its original target date.

The 60-mile 230-kV line, which includes three new substations, should mean fewer and shorter outages for customers in Pennsylvania’s Lackawanna, Monroe, Wayne, Pike
and Luzerne counties, the company said. It’s the second major transmission project completed by PPL in the past year, following the $648 million Susquehanna-Roseland line, which was completed in May 2015.

While construction on Northeast-Pocono is complete, the company said land restoration will continue through the end of the year.

More: PPL

April 25, 2016

FERC Orders Further Changes to NYISO RMR Rules

By William Opalka

FERC told NYISO last week that proposed changes to its rules for reliability-must-run generators are insufficient, ordering another compliance filing in 60 days.

FERC, NYISO, reliability-must-run agreements — Cayuga Plant *Source: Wikipedia*

In February 2015, the commission found NYISO’s Tariff unjust and unreasonable because it lacked rules governing the retention and compensation of generating units needed for reliability. FERC took action after several coal-fired and nuclear generators in western New York announced their closures and the ISO was unable over nearly four years to win stakeholder consensus regarding uniform compensation rules for RMR units. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)

On Thursday, the commission said the ISO’s revised rules complied only in part with its directive (ER16-120, EL 15-37).

The commission approved the ISO’s use of going-forward costs as a compensation mechanism for generators and its use of net present value to compare solutions to reliability concerns. But it rejected the ISO’s proposed role for the New York Public Service Commission, its cost allocation proposal and its plan for bidding RMR generators into capacity auctions.

‘Gap Solution’

NYISO proposed adding its RMR rules to its existing “gap solution” process. The gap solution is currently triggered when the ISO’s biennial reliability planning process determines that neither market-based nor regulated proposals will address a reliability need quickly enough, or if its Board of Directors — after consulting with state regulators — determines there is an imminent reliability threat.

Under the ISO’s proposal, it would solicit gap solution — generation, transmission or demand response — and market-based solution proposals when it identifies a reliability need that would result from a generator deactivation.

If there are no viable market-based solutions, the ISO would provide the PSC with a list of transmission and DR gap proposals. The ISO would enter into an RMR agreement only if there are no viable non-generation solutions or if the PSC does not select such a solution from the list provided by the ISO.

FERC said the ISO’s plan was inconsistent with Order 1000, improperly delegated authority to the PSC and could lead to inefficient transmission development.

The commission also rejected a proposal that generators provide 365 days’ notice before deactivation, more than doubling the 180 days required by the PSC. Generators had protested that the proposed notice period was “unreasonably long.”

FERC did not rule on the merits of the extended time frame but said it would address the timing issue after NYISO proposes Tariff amendments outside of the gap solution process. The commission further said it could not determine whether a generator should be compensated during the notice period and at what level.

Capacity Pricing

FERC also rejected the ISO’s proposed cost allocation for RMR generators and transmission gap solutions as inconsistent with Order 1000 and its plan to bid RMR generators into its capacity auction at prices above $0/kW-month. “It is more efficient for RMR generators to offer their [unforced capacity] at $0.00/kW-month as ‘price-takers,’” FERC said.

It accepted in part the ISO’s provisions to prevent generators from “toggling” between RMR compensation and market-based rates, requiring additional protections.

FERC also denied rehearing of a PSC complaint that FERC’s February 2015 order encroached on its jurisdiction. (See FERC Interfering with Reliability Order, NYPSC Says.)

April 25, 2016

FERC Open Meeting Briefs

WASHINGTON — A May 13 FERC technical conference reviewing generator interconnection procedures will include a discussion on the interconnection of energy storage resources (RM16-12, RM15-12).

FERC-commissioners-listen-to-National-Labs-presentations-content-web — FERC commissioners listen as representatives from the Energy Department’s National Laboratories give a presentation on grid modernization. © *RTO Insider.*

The tech conference was scheduled in response to a 2015 petition by the American Wind Energy Association to revise the commission’s pro forma large generator interconnection agreement. Other topics to be discussed include the current status of interconnection queues and transparency in the interconnection study process.

The conference was brought up by FERC Chairman Norman Bay during a presentation staff gave the commission at its open meeting last week on the data requests it sent six grid operators regarding their rules for energy storage participation in the wholesale markets. The storage issues slated for discussion at the conference are largely the same as those the RTOs will address in their responses to the data requests, which are due May 2. (See FERC to Examine RTO Roles for Energy Storage.)

“Energy storage is one of the big potential game changers in the energy industry,” Commissioner Tony Clark said. “This line of inquiry that we’re opening and the responses we’re going to get back I think are going to be tremendously important.”

National Labs Brief FERC on Grid Modernization

Representatives from the Department of Energy and its national laboratories said that increased communication and cooperation with FERC will be needed in order to help them in their efforts to modernize the grid.

These efforts — including integrating renewable energy resources and energy storage, and increasing protection against cyber threats — were detailed in a series of presentations at the commission’s open meeting last week. The integration of new technologies will result in a paradigm shift in how energy is generated and used, they said.

One of “the key trends and themes that we’re reinforcing is the evolution towards more distributed control,” said Jeff Dagle, chief electrical engineer at Pacific Northwest National Laboratory. “Historically, we’ve forecasted demand and dispatched supply. I think increasingly in the future, we’ll be forecasting supply and dispatching demand.”

Chuck Goldman, of the Lawrence Berkley National Laboratory, urged FERC to consider having its senior staff participate in the advisory committees on some of the labs’ projects. He also said the commission should “think about the kinds of [research and development] that might be appropriate for ISOs that’s in the public interest [and] that can deal with grid modernization issues.”

– Michael Brooks

April 25, 2016

FERC Rejects Rehearing on SPP-WAPA JOA

By Tom Kleckner

FERC last week accepted revisions to SPP’s joint operating agreement with Western Area Power Administration-Upper Great Plains Region (WAPA-UGP), denying rehearing and clarification requests by MISO and 23 of its transmission owners (EL12-60, ER12-1586).

The commission’s April 21 order granted SPP and the Integrated System’s request for clarification that the term “energy exchange” reflects their intent that the JOA does not affect the transmission rights or service of third parties.

MISO and its TOs had protested FERC’s September 2012 order accepting the JOA, which was filed in April 2012 as a precursor to the IS’ membership in SPP. They said part of the JOA would be “incompatible” with market-to-market coordination between MISO and SPP when the latter’s Integrated Marketplace began operating, and that the agreement equated to “assessing compensation for loop flow.”

FERC rejected both arguments. The IS, comprising WAPA-UGP, Basin Electric Power Cooperative and Heartland Consumers Power District, became full transmission-owning members of SPP in October.

The commission clarified that that sections 5.4-5.6 of the JOA are the parties’ method for addressing contract path capacity determinations. The commission affirmed its prior determination that the language does not violate market-to-market principles or constitute unauthorized loop flow compensation.

“As the commission stated elsewhere in the Sept. 18 order, sections 5.4-5.6 of the [WAPA-SPP] JOA do not govern loop flow; rather, loop flow is governed by the congestion management process.”

April 25, 2016

Utility-Solar Partnership Proposes Net Metering Overhaul

By William Opalka

New York utilities and three solar companies on Tuesday proposed a business model that they said would replace net metering and address cost-shifting concerns, a pact that could serve as a model nationally (15-E-0751).

The proposal was made in a proceeding of New York’s Reforming the Energy Vision initiative.

The Solar Progress Partnership includes Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, National Grid, Orange and Rockland Utilities, Rochester Gas and Electric and the solar companies SolarCity, SunEdison and SunPower.

“At its core, the partnership’s proposal provides simplicity for customers, recognizes the locational value of clean [distributed energy resources] and attempts to resolve potential bill impacts, particularly to customers who are not participating in [net metering],” the filing states.

Under net metering, utilities pay for surplus power from rooftop solar systems. Utilities say this means ratepayers without solar systems are paying more than their share of grid costs. (In the Orange and Rockland service territory, customers are reimbursed at the NYISO day-ahead hourly price, which is the wholesale rate. Some other utilities pay at the retail rate.)

The proposal would preserve credits for residential rooftop solar systems. But it proposes a transition from the current net metering model that would begin in 2020 for larger projects. The filing recommends collecting a payment from solar developers for community and remote solar projects connected to the grid.

The proposal marks a potential cease-fire in the battles solar developers have fought with utilities in states across the country. In December, SolarCity announced it was ending operations in Nevada after regulators cut payments to rooftop panel owners.

News of the agreement appeared to cheer investors. SolarCity shares ended last week at $33.34, up 9% from the open Tuesday, while SunPower shares were up less than 1% at $21.66. SunEdison shares were trading at $0.34 Thursday — when the company announced it was seeking Chapter 11 bankruptcy protection — up 6% from Tuesday.

“We’re working together to keep our state’s solar market vibrant while enabling us to maintain the robust power grid that solar energy requires, and in a way that is fair to all customers,” Con Edison CEO John McAvoy said in a joint statement.

SolarCity CEO Lyndon Rive also was conciliatory. “The deep institutional knowledge of these six utilities and the creative approach they are taking to the evolution of electricity is inspiring. Leaders like these will lay the foundation for the grid of the future.”

The partnership said the proposal came out of discussions facilitated by the Advanced Energy Economy Institute.

LMP+D+E

The proposal said it would use elements of a New York Public Service Commission staff white paper to transition to a compensation structure “that more closely aligns with the value the resources bring to the power system, including the wholesale power system (‘LMP’), the electric distribution system (‘D’) and to society at large (‘E’), which is generally the environmental benefit.”

Each community distributed generation (CDG) project would be assigned to a tranche that would establish a compensation rate and developer payments. “Each successive tranche would incorporate higher developer payments, gradually moving the total resource compensation rate to LMP+D+E,” the partnership said.

According to PSC data, the state has more than 3,100 MW net energy metering resources installed or in utilities’ interconnection queues. “These queues have more than doubled in the first three months of 2016,” the proposal said. “Much of this recent development activity has been configured as CDG projects.”

Barriers to Entry?

The plan would require developers to provide letters of credit, a condition that Karl Rábago, head of the Pace Energy and Climate Center, said bars small developers.

“In the early days of the Texas market deregulation, that’s really what shook out the smaller developers,” Rábago, a former Texas Public Utility Commissioner told Capital New York. “I don’t have a line of credit if I’m a small player.”

April 25, 2016

ERCOT Board of Directors Briefs

AUSTIN, Texas — ERCOT’s Independent Market Monitor said last week that negative prices are becoming less frequent and that they have virtually no impact on average energy prices, despite media attention given to them.

Steve Reedy, the IMM’s deputy director, told the Board of Directors during his regular update that while negative prices “are not a problem, they’re certainly something as an economist that interest me.”

Reedy said the Monitor saw “significant amounts” of negative pricing in ERCOT’s West zone — where most of the ISO’s 15,764 MW of wind capacity resides — during the first year of the nodal market, which went live in 2010. The completion of the $6.8 billion, 3,600-mile Competitive Renewable Energy Zone (CREZ) transmission buildout in February 2014 resolved most of the congestion issues.

“For the most part, we’ve seen [those prices] go away,” Reedy said. “We still have negative prices, but rather than being the norm early in the nodal market and in the zonal market, it’s now the exception.”

Reedy expressed mild frustration that a September Slate article detailing prices reaching as low as -$8.52/MWh led to a flurry of additional press coverage. He said the Sept. 13 event was typical of wind energy being offered into the market at off-peak hours.

Testing his hypothesis, Reedy asked Monitor staff to calculate negative prices’ effect on the ERCOT market by replacing every negative price with a zero.

The end result? An energy-weighted price of $26.78/MWh for 2015, virtually identical to the $26.77 average including the negative prices.

“It’s a late-night, early-morning phenomenon. It’s not an example of the CREZ being used up,” Reedy said. “It’s driven a lot of press, but it’s not had a major effect on the price.”

Ken-Anderson, PUCT at the ERCOT Board of Directors Meeting — Anderson © *RTO Insider*

Texas Public Utility Commissioner Ken Anderson asked whether ERCOT would be seeing the same behavior without the federal production tax credit, which is worth $23/MWh. “No, I don’t think that would be the case without the PTC,” Reedy told the commissioner.

“We’ve seen over the last five years that the west export capacity, due to CREZ, has expanded significantly,” he said. “Even with the growth of wind energy, we rarely get that crossover where [we end up with negative prices].”

Asked what was causing the low-priced energy, Reedy could only reply with anecdotal evidence, suggesting that some coal generators might be running overnight to reduce their fuel stockpiles, and that other market participants might be running units overnight to eliminate start-up risks.

Reedy also discussed the operating reserve demand curve (ORDC), a price adder created to reflect the value of reserves during high-load periods. ERCOT staff compiled stakeholder proposals for revising the ORDC in a white paper earlier this year, following Anderson’s call for a PUC review of it and its methodology. (See “State Regulators Seeking Answers to Summer Incident,” ERCOT: No Consensus on Operating Reserve Changes.)

Texas regulators are considering whether to artificially raise wholesale power prices, as ERCOT is seeing prices at 14-year lows. The PUCT met April 14 to consider the issue and will again discuss the topic May 4. Commission staff has issued a memo summarizing comments it has received from market participants.

[Editor’s Note: An earlier version of this article stated incorrectly that the white paper contained ERCOT staff’s recommended changes to the ORDC.]

Board Easily Passes LOC Revision

The board approved the Technical Advisory Committee’s recommended parameters for payments of lost opportunity costs to generators ordered to ramp down for grid reliability, with just two opposing votes and no discussion.

“No questions?” board Chair Craven Crowell asked the members, surveying the room. Addressing TAC Chair Randa Stephenson, he said, “Sounds like you did a good job on it then.”

“We worked hard,” Stephenson responded.

The board had remanded Nodal Protocol Revision Request (NPRR) 649 back to the TAC at its February meeting. Last month, the committee was able to reach agreement on one of three options, amending the language to reflect comments it received from the board. (See ERCOT Stakeholders Agree on Lost Opportunity Costs Rule.)

The Texas Office of Public Utility Counsel’s Tonya Baer (Residential Consumers) and the City of Dallas’ Nick Fehrenbach (Commercial Consumers) cast the two negative votes.

Stephenson, of the Lower Colorado River Authority, said the request’s original impact analysis of $100,000 to $150,000 had been reduced to the $50,000-$75,000 range, assuming high-dispatch limit (HDL) overrides remain at current levels. She said ERCOT has revised its procedures since Odessa-Ector Power Partners claimed its combined cycle plant had lost $300,000 because of three days of HDL overrides in November 2012 and only one HDL since last May.

“We anticipate costs to the load … when this does occur [again], it will be an uplift,” Stephenson said. She said the TAC will continue to monitor and report back on any uplifts.

The board also approved NPRR 745, which changes the emergency response service’s availability from an hourly to 15-minute interval evaluation and makes other minor changes.

ERCOT Net Above Budget, Despite Mild Weather

Bill-Magness,-ERCOT-CEO at the Board of Directors meeting — Magness © RTO Insider

ERCOT CEO Bill Magness told the board that 2016’s net revenues are $1.8 million above expected, despite system administration fees being $1.7 million under budget due to mild weather conditions. Timing differences kept spending $3.1 million under budget, he said in his report.

Pointing to an overhead screen filled with maps of Texas, Magness said, “That’s five different ways up there of saying it’s warm. The basic story is, we did have a pretty warm, pretty dry winter.”

Magness also reported that staff is testing an upgrade to ERCOT’s energy management system, which could go live as early as May 26. He noted the EMS is just one of several software systems scheduled to go live this year.

The CEO also mentioned ERCOT’s creation of the Grid Resilience Working Group, which will assess low-probability but “potentially high-impact” risks to the ISO’s system. Its first meeting is scheduled for April 26.

Bermudez, NPRRs Approved

The board re-elected unaffiliated Director Jorge Bermudez to a third and final term. His second term expires in June.

It also unanimously approved seven NPRRs and one change-request on its consent agenda:

NPRR 741: Clarifications to estimated aggregate liability (EAL) and total potential exposure (TPE) credit exposure calculations.
NPRR744: Reliability unit commitment trigger for the reliability deployment price adder and alignment with RUC settlement.
NPRR 746: Adjustments due to negative load.
NPRR 748: Revisions associated with NERC reliability standard COM-002-4 and other clarifications associated with dispatch instructions.
NPRR 749: Requires ERCOT to publish the cost of options for all outstanding congestion revenue rights within the CRR auction process.
NPRR 750: Clarifies the practice for setting telemetry when providing fast-responding regulation service.
SCR 787: Changes the net-dependable capability and reactive capability (NDCRC) application to provide historical generator information to all associated resource entities.

— Tom Kleckner