MISO: Mass-Based CPP Plan 1/3 Cost of Rate-Based

By Amanda Durish Cook

CARMEL, Ind. — Mass-based compliance with the Clean Power Plan would cost less than one-third as much as a rate-based method by 2030, according to modeling by MISO.

MISO found that the price disparity between rate-based compliance, which limits emissions in tons per megawatt-hour, and mass-based compliance, which caps emissions in tons per year, increases over time due to the mass-based method’s increased flexibility under emissions trading.

By 2030, production-based compliance costs are expected to reach about $17 billion under a rate-based plan, while mass-based compliance is estimated at about $5 billion, according to the near-term analysis presented at Wednesday’s Planning Advisory Committee meeting. This includes the expense of generation, interchange and emissions, excluding additional transmission and pipeline infrastructure, and other capital costs.

MISO has said that individual states won’t shoulder the burden equally.

MISO Will be Compliant in First Years

Jordan Bakke, policy studies lead at MISO, said rate-based compliance is centered around adding zero-emission resources while mass-based compliance requires also removing emission-heavy generation. Early compliance targets are slated to be met through MISO states’ existing renewable portfolio standards and natural gas’s replacement of coal generation, but additional changes will be needed to continue compliance.

clean power plan — MISO believes that early compliance targets are met through renewable portfolio standards and coal to gas re-dispatch, but comprehensive planning needs to start today to meet increasingly stringent compliance targets in the mid-2020s.

“The planning that has already occurred will only get us so far,” Bakke said. Compliance costs would rise significantly in the “mid- to late 2020s,” he said, after MISO’s existing generation mix fails to carry it through increasingly stringent emissions goals.

The threats to MISO’s coal fleet are less severe in a regional mass-based approach. The analysis forecasts six coal units to be idled by 2030 under mass-based plans, versus nine under rate-based compliance.

With either option, the grid operator said it would need new zero-emission resources to temper the price of CO₂, which is expected to rise from about $20/short ton in 2022 to about $40/short ton by 2030 under mass-based compliance and almost $140/short ton under a rate-based regime.

“Coal unit capacity factors decrease greatly over time under the CPP, more dramatically with a rate-based implementation,” MISO wrote. On the other hand, MISO has suggested that mass-based compliance might require less capital investment because system dispatch won’t have to undergo as many changes. The RTO said the low capacity factors, even using a business-as-usual measurement, show coal units won’t be economically viable by 2022 or 2030.

66 Cases Modeled

Bakke said that the near-term modeling ran 66 cases with differing changes in capacity and either mass- or rate-based compliance: three business-as-usual scenarios in the years 2022, 2025 and 2030; 39 instances of business-as-usual resources but with CPP constraints applied; and 24 runs using alternative resource scenarios combined with CPP constraints. The three business-as-usual cases, which rely heavily on coal generation, would not meet emissions targets, while both categories that use CPP constraints would.

The study assumes a liquid carbon emissions market and that all states choose either mass- or rate-based plans. Bakke said further modeling will be needed if states decide to use a mix of rate-based and mass-based trading.

MISO said it assumed a $4.67/MMBtu natural gas price for 2015. In addition to modeling using its existing generation fleet, the RTO also is including units with signed generation interconnection agreements and projects approved under the 2015 Transmission Expansion Plan.

MISO Wants Reliability Provisions in State Plans

Meanwhile, Kari Bennett, MISO’s senior corporate counsel, said MISO’s comments to the EPA on the federal implementation plan (FIP) will focus on reliability.

In its comments, MISO said it would like EPA to authorize the use of a reliability safety valve in FIPs, similar to that in state implementation plans. MISO said EPA should allow a “meaningful, case-specific review of reliability that is comparable to the state plan requirement.” (See related story, FERC Outlines Principles for Clean Power Plan Analyses.)

Bennett said the comments do not get into the mechanics of how a safety valve would be developed or used.

“As we look at the situation, reliability is often case-specific and a sensitive issue,” she said. “We do think it is prudent for the EPA to include a reliability safety plan in the federal plan as well as state plans.”

January 26, 2016

FERC OKs MISO-SPP Transmission Settlement

By Amanda Durish Cook

FERC on Thursday approved MISO and SPP’s uncontested settlement agreement with a trio of orders governing how MISO transfers power between its North and South regions using SPP transmission.

FERC determined the settlement was “fair and reasonable and in the public interest” (ER14-1174, et al). The commission upheld a Jan. 5 settlement judge’s certification that the agreement was uncontested.

The RTOs agreed in October to the terms of the seven-year settlement, which stipulates north-to-south flows be capped at 3,000 MW and south to north be limited to 2,500 MW. (See SPP, MISO Reach Deal to End Transmission Dispute.) MISO and SPP have 45 days to file Tariff changes with FERC.

Two other orders dismissed all rehearing requests relating to issues prior to the settlement and approved the cancellation of SPP’s hurdle rate mechanism.

Clark Urges Caution

Commissioner Tony Clark wrote a concurring statement, saying the order “leaves the door open as to how the commission would analyze the settlement in the event a challenge is brought.”

Clark said the settlement puts new conditions on MISO’s transmission service because of the transfer limits established between MISO Midwest and MISO South.

“Because these terms could impact more than just the settling parties, including future MISO market participants, I do not think it is appropriate to extend the heightened Mobile-Sierra standard to those third parties or the commission acting [without formal prompting from another party]. Consistent with my prior statements, if we are to preserve the integrity of the Mobile-Sierra standard, we should be judicious in its application.”

The Mobile-Sierra doctrine, named after a pair of Supreme Court rulings, holds that negotiated contracts are presumed to be just and reasonable unless it “seriously harms the public interest” or the parties to the contract agree that the standard should not apply.

MISO, SPP Looking Forward

Jennifer Curran, MISO’s vice president of system planning and seams administration, said MISO was pleased with FERC’s approval. “With this issue behind us, we look forward to continued collaboration across our seams for the benefit of all our customers.”

SPP is “pleased to have the issue resolved,” said David Avery, SPP’s director of corporate communications.

As a result of the settlement, FERC moved to eliminate the $9.57/MWh hurdle rate on flows exceeding the 1,000-MW transfer limit per SPP and MISO’s joint operating agreement (ER16-56). MISO’s proposed Tariff revisions to replace the hurdle rate with a mutual compensation system will become effective Feb. 1.

“As explained by MISO, the substitution of the SPP service agreement with a payment structure for SPP’s and joint parties’ available system capacity obviates any need for the hurdle rate,” FERC said.

However, MISO’s proposed revisions to the commission failed to delete a few mentions of the SPP service agreement, as pointed out by MISO stakeholders. FERC directed MISO to remove the phrase and make a compliance filing in 30 days.

FERC also dismissed as moot requests for rehearing from MISO, MISO transmission owners and Entergy over now obsolete matters in the RTOs’ joint operating agreement (ER14-1174-001, et al).

Having made a one-time, $16 million payment to SPP to fund surplus flow charges over the past two years, MISO is continuing cost allocation talks (ER14-1736).

Beginning next month and continuing until February 2017, MISO will pay SPP $1.33 million per month to cover flows over the 1,000-MW contract path that cross MISO’s North-South interface, but MISO hasn’t yet determined a final cost allocation mechanism that would govern how the cost is split among MISO’s generation owners. (See “MISO to Begin SPP Settlement with $16 Million Payment,” MISO Market Subcommittee Briefs.)

January 26, 2016April 22, 2024

State Briefs

PSC Considering Entergy’s $133M Rate Increase

The Public Service Commission is considering a proposed settlement that would increase Entergy Arkansas rates by more than 8%.

The commissioners will vote in February on a settlement that would give Entergy an increase of $133.6 million, 20% less than the $167 million increase the utility originally sought. The settlement was reached between the utility and several entities, including the attorney general’s office and Entergy’s major commercial customers.

Entergy said the increase is needed because of improvements to its electrical infrastructure and its $237 million purchase of an interest in a gas-fired generation plant. The settlement would allow Entergy a 9.75% return on equity.

More: Arkansas Democrat-Gazette

CONNECTICUT

Rooftop Solar Program Praised by Governor

Gov. Dannel Malloy showed up as a booster for a public-private partnership that brings solar panels and lower electricity bills to the state’s residents. The Solar for All initiative links residents with PosiGen Solar and Energy Efficiency, a solar system installation company.

The company offers solar panel installation under a 20-year agreement at an introductory price of $20/month for the first year if more than 50 households sign up. After the first year, the basic charge goes up to $79/month for a 6-kW system. The program is subsidized by a $5 million investment by the state’s Green Bank program as part of a way to lower greenhouse gas emissions in the state.

More: New Haven Register; PosiGen

INDIANA

Wind Turbine Shrinks School District’s Power Bill

The Shenandoah School District reported it had a zero balance on its December electricity bill, thanks to a wind turbine it installed two years ago.

According to school officials, the 900-kW turbine is intended to supply 85% of the power used by the elementary, middle and high schools. District Business Manager Julia Miller said the district pays between $105,000 and $112,000 annually for electricity, about half its bill before the turbine went into service.

Shenandoah School District used government bonds to finance the $2.6 million turbine, which is expected to pay for itself within 10 years.

More: News-Sentinel

KANSAS

Legislators Blast $20M Deal for Capitol Grounds’ Power Plant

Legislators are upset Gov. Sam Brownback’s administration signed a $20 million lease-purchase for construction of a new state power plant in Topeka that they say sidesteps legislative oversight.

Members of the House and Senate expressed frustration with the 15-year contract executed Dec. 29 because the total cost was millions of dollars higher than previously disclosed, the first payment wasn’t included in Brownback’s budget and the arrangement had not been approved by the state’s joint building committee.

In October, the Department of Administration said the heating and cooling plant to be located one block north of the Capitol would cost about $12 million. The previous estimate shared with legislators monitoring state building projects was $9 million.

More: The Topeka Capital-Journal

Bill Killing Tx Authority Criticized by Wind Advocates

A bill that would terminate the funding for the Electric Transmission Authority, which was formed a decade ago because it was thought utilities were not developing sufficient transmission lines, is being seen as a threat to future wind projects in the state.

Sen. Robert Olson, chairman of the Senate Utilities Commission, said transmission planning is now largely done by SPP and the transmission authority is unnecessary. But wind energy advocates say the state-centric transmission authority stimulated the growth of wind energy by developing a robust transmission system in Kansas.

More: Midwest Energy News

MICHIGAN

PSC Launches Investigation into Consumers’ Estimates

The Public Service Commission is investigating the way Consumers Energy estimates bills after about 300 customers last year complained about inaccurate bill estimates. The commission has asked the company to file a report by Feb. 18 detailing its staffing levels and its communications process with customers on billing estimates, along with an accounting of the number of bills that were underestimated or overestimated.

“One of the issues that has come up in our meetings is the algorithm the software uses in calculating and estimating what a bill would be,” said Judy Palnau, a PSC spokesperson. “Is it possible the algorithm needs adjusting?”

A company spokesman said it estimates bills when it is unable to read a customer’s meter.

More: Mlive

MISSOURI

Ameren to Help Noranda Smelter, Asks for Regulation Changes

Ameren Missouri said it is working with lawmakers to change utility regulations to help Noranda Aluminum, a smelter that buys 10% of the utility’s power. The smelter has threatened to shut down if it cannot reduce its energy costs.

The St. Louis utility wants regulations modeled on those in neighboring Illinois, where “near-automatic” annual rate increases are offered in return for more grid investment. The change would reduce the Public Service Commission’s authority in utilities’ rate structure and rate adjustments.

Noranda has said it will lay off almost 500 of the 850 smelter workers by February and will wind down operations by March 12 unless it can “secure a substantially more sustainable power rate for the smelter,” according to the St. Louis Post-Dispatch. The announcement was prompted by a power outage that shut down two of the smelter’s three aluminum production lines.

More: St. Louis Post-Dispatch

MONTANA

CPP Rules Threaten Coal Plant, Economy Officials Say

Shutting down one or more units at Colstrip’s 40-year-old coal-fired power plant complex would devastate the state’s economy through possible job losses and higher power bills, state elected officials and industry backers said Jan. 18 in Billings.

The discussion centered on concerns that EPA’s proposed Clean Power Plan, which calls for the state to reduce its carbon emissions by 47%, will have an adverse impact on Colstrip, where four power units produce 2,094 MW and employ about 350 workers. The plants are the state’s biggest producers of greenhouse gases.

The Colstrip plant has six owners: NorthWestern Energy, Talen Energy, Portland General Electric, Puget Sound Energy, Avista and PacifiCorp. The latter four market power in Washington and Oregon, where legislators are proposing new laws this year to cut cross-state purchases of coal power.

More: Billings Gazette

NEBRASKA

Local Utilities Rejecting NPPD’s 20-Year Wholesale Contracts

A dozen towns and one regional power provider have spurned Nebraska Public Power District’s demands for 20-year wholesale electric contracts.

NPPD’s current 20-year contracts expire at the end of 2021, but the utility asked its customers to commit to new contracts now to protect its bond rating. NPPD has inked new contracts with 62 of its 75 wholesale customers, which include rural public power districts and municipal buyers that made up 92% of the district’s revenue in 2014.

But some wholesale customers have opted to shop around SPP for competitive suppliers. For most of NPPD’s wholesale customers, this is the first contract negotiation in which it has been feasible to look for alternative suppliers in the RTO’s broader market.

More: Lincoln Journal Star

NEW HAMPSHIRE

Jury Slams ENH Power for Stealing Customer Info

A Superior Court jury ordered the parent company of the state’s largest competitive supplier of electricity, ENH Power, to pay more than $500,000 in damages to a smaller competitor for stealing confidential customer lists, sales leads and other proprietary information.

The Rockingham County jury found that ENH officials convinced an employee of Freedom Companies to steal the information and give it to them. An attorney for ENH vowed to appeal.

More: New Hampshire Union Leader

Anti-Pipeline Bills Reviewed by Lawmakers

Two bills introduced to impede efforts to build a natural gas pipeline through the state came under review by lawmakers, but some legislators questioned whether they have the ability to regulate interstate projects, which typically come under federal jurisdiction.

The legislation was introduced in response to Kinder Morgan’s plan to build the $5 billion Northeast Energy Direct pipeline to deliver shale gas from Pennsylvania through Massachusetts and part of New Hampshire. One bill would levy a tax on gas transported through the state, and the second would prohibit passing any of the construction charges to state residents.

Kinder Morgan has vowed to oppose the legislation. “We believe that at a time when New Hampshire residents are paying among the highest energy rates in the country, that it would be inappropriate to potentially increase those costs through a new tax,” said spokeswoman Susan Geiger.

More: New Hampshire Union Leader

NEW JERSEY

Environmental Group Fights Proposed Power Plant

The Sierra Club is protesting a Massachusetts company’s proposal to build a natural gas-fired power plant on 423 acres in Hillsborough.

Jeff Tittel of the Sierra Club said the site is environmentally sensitive because of its proximity to the Delaware and Raritan Canal and it contains wetlands.

Genesis Power’s $1 billion Amwell Energy Center would generate enough electricity to power 700,000 homes.

More: myCentralJersey.com

NEW MEXICO

Town Gets Solar Farm, New Wholesale Power Contract

Guzman Energy has struck a seven-year agreement with the city of Aztec that supplies the city with power at a substantial savings from the current municipal supplier.

Guzman agreed to build a 1-MW solar farm that will generate about 8% of the city’s electricity and supply the remainder of the power from Guzman’s other assets. The new contract sets the price at 5 cents/kWh.

The agreement will replace Aztec’s expiring 10-year deal with Public Service Company of New Mexico that started out at 7.5 cents/kWh and included yearly increases based on natural gas futures, the city said. Those yearly increases mean the city is actually paying PNM closer to 8 cents/kWh.

More: The Daily Times

NEW YORK

NYC Launches Pilot to Switch Food Trucks to Solar

New York City has started a pilot program to convince mobile food vendors to switch to clean energy by subsidizing food carts that are equipped with solar panels and battery storage systems.

MOVE Systems, a New York firm that has developed carts with solar panels on their roofs, hopes the PV carts would reduce vendors’ energy costs by 20%, and could also cut greenhouse gas emissions from the city’s estimated 8,000 food trucks and carts by 60%. The carts would also have backup propane generators.

Most of the vendors now use propane or diesel generators.

More: International Business Times

NORTH DAKOTA

PSC Sets Hearing for Wind Farm, Tx Project

The Public Service Commission scheduled a public hearing for March to consider a proposed wind energy project and transmission line in Stark County.

Brady Wind, a subsidiary of NextEra Energy Resources, proposes to erect as many as 87 wind turbines to generate 150 MW of electricity at an estimated cost of $235 million. The company is also looking to build a 19-mile 230-kV transmission line from the project.

It’s the second attempt for NextEra to build a wind farm in the area. The Stark County Commission in May rejected a conditional use permit for a project of similar size, which was planned for a 61-square-mile area in eastern Stark County between Gladstone and Richardton.

More: The Bismarck Tribune

OKLAHOMA

PSO Enacts Interim Rate Increase While it Awaits Ruling

Public Service Company of Oklahoma said it will put an interim electric rate increase into effect that will generate $75 million while it awaits a final decision from the Corporation Commission on its formal $169 million rate-increase request.

Under state law, utilities are allowed to implement interim rates if they don’t get a final decision from the commission within six months. The interim rates are subject to refund if the commission doesn’t grant PSO’s full request.

The utility said that customers will actually pay less under the new rate structure because the higher rates are more than offset by lower electricity costs attributed to cheap natural gas prices. PSO said a typical residential customer using about 1,100 kW of electricity a month should see bills fall by $2.44.

More: The Oklahoman

PENNSYLVANIA

UGI Utilities Requesting Distribution Rate Increase

UGI Utilities is asking for a distribution rate increase now that a settlement with the Public Utilities Commission barring it from doing so has expired.

After a 2011 gas explosion killed five people in Allentown, the company agreed to expedite its replacement of old natural gas distribution lines, improve leak detection and pay a $500,000 civil penalty. The settlement also prohibited UGI from imposing a distribution system improvement charge for two years.

Filing for a base rate increase is a prerequisite to adding a system-improvement charge. The requested hike would raise an average residential customer’s bill by about 19.7% and a commercial consumer’s bill by about 7.4%.

More: The Morning Call

State Orders Crackdown on Methane Emissions

Gov. Tom Wolf announced a state-directed crackdown on methane emissions from shale gas wells and pipelines last week, in an attempt to address the problem of releases of the gas that had so far been unregulated. The four-part plan will involve a new permitting process for shale gas wells, a new permitting process for pipeline compressor stations and gas processing facilities, leak limits at existing gas and oil facilities, and establishment of best practices to address leaks.

Methane has 84 times the heat-trapping capabilities of carbon dioxide, another greenhouse gas that gets more attention.

“These regulations will improve our air, address the urgent crisis of climate change and help businesses reclaim product that is now wasted,” Wolf said. “The best companies understand the business case for reducing methane leaks. Methane that doesn’t leak into the atmosphere can be used for energy production.”

More: Pittsburgh Post-Gazette

VIRGINIA

Draining of Dominion Coal Ash Ponds Months Away

Dominion Resources says it needs to complete design work before it begins to drain two coal ash ponds into the Potomac and James rivers.

The State Water Control Board granted Dominion permission to “dewater” its coal ash retention ponds at its Possum Point and Bremo Bluff stations. Possum Point is on the Potomac River and Bremo Bluff is on the James River. Several environmental groups, and at least one state agency, say they plan to appeal the board’s decision.

Dominion is also investigating remediating ash impoundments at two other plants.

More: Bay Journal

January 26, 2016

FERC to Investigate Rates of 4 Natural Gas Pipeline Cos.

By Suzanne Herel

FERC on Thursday called for an investigation into four interstate natural gas pipelines that it believes might be charging shippers in PJM, ISO-NE, NYISO and CAISO too much.

The pipelines — Empire Pipeline (RP16-300-000), Iroquois Gas Transmission System (RP16-301-000), Columbia Gulf Transmission (RP16-302-000) and Tuscarora Gas Transmission (RP16-299-000) — have been ordered to file a cost and revenue study within 75 days and appear before an administrative law judge for evidentiary hearings.

The ’ earnings were flagged in a FERC review of annual reports filed by 129 pipeline companies for 2013 and 2014. The analysis found returns on equity for the four pipelines ranged from 15.8% (Empire, 2013) to 24.9% (Tuscarora, 2014). The industry average ROE is a little more than 12%.

“These estimated levels of returns led staff to believe that these four pipelines are over-recovering their costs of service and may be charging rates that are no longer just and reasonable,” James Sarikas, of FERC’s Office of Energy Market Regulation, said in a presentation to the commission. “In addition, none of these pipelines have an existing settlement with its customers that places a currently effective moratorium on existing rates, or requires it to file a new general [Natural Gas Act] Section 4 rate case in the future.”

First Probes Since 2013

The probes are the first in two years to be conducted under Section 5 of the NGA, designed to protect consumers from excessive rates and charges.

FERC in 2009 began a regular, in-depth review of the cost and revenue information filed by large pipelines and in 2011 expanded its focus to include smaller operations.

In that time, the commission initiated 10 proceedings to determine if the pipelines’ transportation and storage rates might not be just and reasonable. Eight of those investigations ended in settlement agreements, and two were terminated.

Dena Wiggins, president of the Natural Gas Supply Association, which represents gas producers and marketers, said her group was pleased that FERC had opened the investigations, adding that they underscore a need for revisions to Section 5.

“Legislation that reforms Section 5, granting FERC the authority to award refunds to shippers in cases where pipelines are determined to have overcharged, would further enhance consumer protections, since currently FERC can only order an overearning pipeline to lower its rates going forward from the date of the commission’s order,” she said in a statement. “Now that FERC has adopted a new modernization surcharge policy that grants interstate pipelines new opportunities to recover costs outside of a general rate case, Section 5 reform is more important than ever.”

Pipelines Span the Country

FERC’s orders outlined their concerns over the companies’ earnings:

Empire, an affiliate of National Fuel Gas, received authorization in 2011 to construct the Tioga County Extension Project, which enables it to transport natural gas south from Canada and product from the Marcellus shale north from Pennsylvania. It had not filed a rate case since 2006. The commission’s review found Empire earned $24.6 million after income taxes in 2013, an ROE of 15.8%, and $28.6 million (20.2%) the following year.
Iroquois, which owns pipelines from the Canadian border through New York and western Connecticut, has not adjusted its rates since 2004. FERC said it had an after-tax return of $54 million (16.2%) in 2013 and $55.6 million (16.3%) in 2014.
Columbia Gulf operates about 3,400 miles of pipeline located primarily in Louisiana, Mississippi, Tennessee and Kentucky. Its current rates are the result of a 2011 settlement agreement, which barred it from seeking to modify rates before April 1, 2014. The company earned $21.9 million (17.3%) for 2013 and $26.4 million (18.2%) for 2014.
Tuscarora, which operates a 229-mile pipeline in Nevada and northwestern California, had not had a rate examination since a 2012 settlement with the Nevada Public Utilities Commission. FERC’s review indicated earnings of $9.7 million (23.6%) for 2013 and $9.6 million (24.9%) for 2014.

January 26, 2016

ATC to Separate Legacy Assets from Development Arm

American Transmission Co. won permission from FERC last week for a corporate reorganization that will split its existing transmission assets from its development partnership with Duke Energy.

ATC said the separation was driven by its owners — utilities, co-operatives and municipalities — who were unwilling or unable to take part in projects outside of the company’s 9,500 miles of “existing core transmission” in Wisconsin, Michigan, Illinois and Minnesota.

FERC approved the creation of a new holding company, ATC Holdco LLC, which will assume most of ATC’s 50% share in Duke-American Transmission Co., which is seeking development opportunities in PJM, MISO and SPP (EC16-47).

ATC’s owners can remain invested in the legacy transmission only or exchange their interests for shares in the development arm.

The companies pledged to not pass on any transaction-related costs to customers for five years, but FERC reminded them that the commission doesn’t allow rate recovery to finance transactions.

“Regardless of the terms of applicants’ hold-harmless commitment, we remind applicants that the commission historically has not permitted rate recovery of acquisition premiums,” FERC wrote in the order, issued Wednesday. “If applicants seek recovery of any acquisition premium associated with the transaction, they must be able to demonstrate in a subsequent proceeding … that its acquisition was ‘prudent and provides measurable, demonstrable benefits to ratepayers.’”

No comments were filed opposing the transaction. Wisconsin Electric Power Co. and Wisconsin Public Service Corp. submitted their written support.

— Amanda Durish Cook

January 26, 2016

FERC: Entergy not Required to Buy from Large QFs

By Tom Kleckner

Entergy’s operating companies don’t have to sign new purchase power agreements with most qualifying facilities above 20 MW, FERC ruled last week (QM14-3-000).

Because of their membership in MISO, the commission said, the Entergy companies had met their “statutory standard” under a 2006 order in which the commission revised its regulations implementing the Public Utility Regulatory Policies Act.

In a separate order, the commission granted Arkansas Electric Cooperative Corp. (AECC) similar relief based on the 2006 order, which said that QFs with net capacity above 20 MW were presumed to have “nondiscriminatory access” to wholesale markets in RTOs such as MISO.

The commission denied Entergy’s request for relief regarding one QF, Dow Chemical’s Plaquemine facility south of Baton Rouge, La., which it said faced transmission constraints.

Excluding the Dow facility, FERC said MISO provides all “over-20 QFs” in Entergy’s territories “nondiscriminatory access to independently administered, auction-based day-ahead and real-time wholesale markets for the sale of electric energy and to wholesale markets for long-term sales of capacity and electric energy.”

Entergy’s request was supported by the Louisiana Public Service Commission but protested by several industrial customers with QFs.

The Louisiana PSC said QFs in Entergy’s service territory have nondiscriminatory access to MISO’s markets and noted the company’s request “was made in part to satisfy the Louisiana commission’s requirements — which included removing the PURPA ‘put’ obligation — in approving MISO membership for Entergy Gulf States Louisiana and Entergy Louisiana.”

Justice Department Investigation

Protests by Occidental Chemical and Formosa Plastics cited an open Department of Justice antitrust investigation into Entergy’s transmission practices. Formosa said FERC should deny Entergy’s application pending a resolution of the investigation, noting that the department sought to have Entergy divest its transmission system. Occidental said that MISO had not approved transmission improvements to relieve the Amite South load pocket.

The commission said that because Amite South is import constrained, Occidental’s Taft QF was not prevented from selling energy outside the load pocket, and noted that LMPs at the plant are higher than average LMPs in MISO.

“Moreover, as Entergy points out, any energy which the Taft QF sells to load-serving entities outside the Amite South load pocket, including through the sub-regional power balance constraint to load-serving entities in MISO Midwest would, therefore, most often relieve congestion caused by the constraint, rather than be barred by it, and would instead receive congestion credits,” FERC said.

In contrast, FERC said, Dow’s 1,491-MW Plaquemine QF is located in a generation pocket, which is export constrained and subject to lower LMPs than the rest of MISO.

Entergy told FERC that transmission upgrades are scheduled to go in service around the Dow facility in December 2018. FERC said Entergy will be able to file for termination of its obligation to the Dow QF once the upgrades are completed.

The commission emphasized that granting Entergy’s application “does not relieve Entergy of its obligation to abide by its existing agreements.”

Entergy told FERC it would honor existing contracts “pending satisfaction of applicable contract termination requirements” and said it would not “seek to terminate any existing agreements effective prior to 120 days” after its request was accepted. FERC’s order was effective Oct. 23, 2015, the date of Entergy’s filing.

AECC Request Approved

In a related order, FERC also granted AECC’s request to terminate its PURPA obligations for “over-20” QFs in MISO (QM15-3-000).

AECC made the request in April on behalf of itself and its 17 members, 14 of which are in MISO, but later amended the application so that it applied solely to the cooperative. The commission agreed with AECC that it relies on Entergy Arkansas’ transmission system to serve its members’ load.

January 26, 2016

FERC Denies Fidelity Affiliate Request

FERC last week denied a request by two energy companies to declare they were not affiliates of the investment management wing of Fidelity Investments (EL15-96).

The companies, Backyard Farms Energy and Devonshire Energy, are indirect subsidiaries of Fidelity parent company FMR.

Devonshire was formed to purchase wholesale power for FMR’s multiple operating companies; Backyard Farms Energy purchases wholesale energy for use by an affiliated greenhouse grower of tomatoes in Maine.

The two energy companies argued that the mutual fund accounts managed by subsidiary Fidelity Management & Research are not owned by the parent company itself but by shareholders and institutions.

Backyard and Devonshire said they made the request for a declaratory order because they were concerned that they would be required to file a change of status if their affiliates acquired more than 10% of another energy company.

FERC said that its regulations classify the companies as affiliates of Fidelity Management because they are under the common control of FMR.

“Regardless of the ownership of the Fidelity accounts themselves, the fact remains that the Fidelity advisers manage and control the investments that the Fidelity accounts make and also exercise voting rights for the Fidelity funds in some circumstances,” the commission said.

— Michael Brooks

January 25, 2016

Supreme Court Upholds FERC Jurisdiction over DR

By Rich Heidorn Jr.

WASHINGTON — The Supreme Court on Monday upheld FERC’s jurisdiction over demand response, reversing the D.C. Circuit Court of Appeals in a 6-2 ruling.

“The [Federal Power Act] provides FERC with the authority to regulate wholesale market operators’ compensation of demand response bids,” wrote Justice Elena Kagan in an opinion joined by Chief Justice John Roberts and Justices Anthony Kennedy, Ruth Bader Ginsburg, Stephen Breyer and Sonia Sotomayor. (FERC v. Electric Power Supply Association, 14-840, 14-841).

The decision upheld FERC Order 745, which required grid operators to pay DR providers LMPs — equal to generation.

“This decision means that consumers will continue to see the significant benefits of demand response, which enhances competition in the markets, reduces wholesale prices and helps makes the grid more reliable,” FERC Chairman Norman Bay said in a statement.

The Electric Power Supply Association, which filed the lawsuit challenging Order 745, did not respond to requests for comment.

Justice Clarence Thomas joined Justice Antonin Scalia’s dissent. Justice Samuel Alito recused himself in the case, reportedly because he owns stock in Johnson Controls, parent company of DR provider EnergyConnect.

In May 2014, the D.C. Circuit vacated Order 745 in a 2-1 ruling, saying DR is a retail product and thus subject to state, not federal, jurisdiction. It also said FERC’s requirement that DR receive LMPs was “arbitrary and capricious.”

The Supreme Court majority disagreed on both counts.

Growing Importance

FERC sought Supreme Court review because of the growing importance of DR. While the D.C. Circuit ruling explicitly addressed only DR participation in wholesale energy markets, FERC said the ruling also threatened its participation in wholesale capacity markets.

That could have created an upheaval in markets such as PJM, where capacity auctions represent about 95% of total DR revenue. After some uncertainty, PJM decided to include DR in the 2018/19 Base Residual Auction last August.

PJM issued a statement saying it was pleased with the ruling. “Certainty and continuity are important in markets. Demand response brings value to competitive wholesale markets and is a vital component of electric system reliability.”

UBS Securities Monday reiterated its prediction that one-quarter of the DR that bid in to the PJM 2018/19 capacity auction as base product will leave the market when it transitions to 100% Capacity Performance for 2020/21, raising the price by about $14/MW-day.

Three-Part Analysis

Kagan broke the court’s analysis into three parts. “First, the practices at issue directly affect wholesale rates. Second, FERC has not regulated retail sales. Taken together, these conclusions establish that [Order 745] complies with the FPA’s plain terms. Third, the contrary view would conflict with the FPA’s core purposes.”

“The FPA has delegated to FERC the authority — and, indeed, the duty — to ensure that rules or practices ‘affecting’ wholesale rates are just and reasonable. To prevent the statute from assuming near-infinite breadth, this court adopts the D. C. Circuit’s common-sense construction limiting FERC’s ‘affecting’ jurisdiction to rules or practices that ‘directly affect the [wholesale] rate.’ That standard is easily met here. Wholesale demand response is all about reducing wholesale rates; so too the rules and practices that determine how those programs operate. That is particularly true here, as the formula for compensating demand response necessarily lowers wholesale electricity prices by displacing higher-priced generation bids.”

Not Retail

Kagan said Order 745 did not regulate retail electricity sales that are under state jurisdiction.

“A FERC regulation does not run afoul of [the FPA’s] proscription just because it affects the quantity or terms of retail sales. Transactions occurring on the wholesale market have natural consequences at the retail level, and so too, of necessity, will FERC’s regulation of those wholesale matters. That is of no legal consequence.

“When FERC regulates what takes place on the wholesale market, as part of carrying out its charge to improve how that market runs, then no matter the effect on retail rates, [the FPA] imposes no bar. Here, every aspect of FERC’s regulatory plan happens exclusively on the wholesale market and governs exclusively that market’s rules.”

The court said EPSA’s position would “subvert the FPA” and leave DR without any agency able to regulate it.

“EPSA’s arguments suggest that the entire practice of wholesale demand response falls outside what FERC can regulate, and EPSA concedes that states also lack that authority. But under the FPA, wholesale demand response programs could not go forward if no entity had jurisdiction to regulate them. That outcome would flout the FPA’s core purposes of protecting ‘against excessive prices’ and ensuring effective transmission of electric power.

“The FPA should not be read, against its clear terms, to halt a practice that so evidently enables FERC to fulfill its statutory duties of holding down prices and enhancing reliability in the wholesale energy market.”

LMP for DR also Upheld

The court also rejected complaints that FERC was overcompensating DR by requiring LMPs. “This court’s important but limited role is to ensure that FERC engaged in reasoned decision making — that it weighed competing views, selected a compensation formula with adequate support in the record and intelligibly explained the reasons for making that decision. Here, FERC provided a detailed explanation of its choice of LMP and responded at length to contrary views. FERC’s serious and careful discussion of the issue satisfies the arbitrary and capricious standard.”

Reaction

The ruling was celebrated by environmental groups, the White House and DR investors.

EnerNOC, the only publicly traded pure-play DR provider, saw its shares jump more than 70% on the news, rising from $4.09/share to close at $7.03/share.

Shares of independent power producers fell sharply, with Dynegy down 11.55%, NRG Energy off 9.5%, Calpine dropping almost 8% and Talen Energy losing 6%. Utilities in PJM also had a poor day, with Exelon (-3%), Public Service Enterprise Group (-2.2%), and American Electric Power (-1.33%) all showing losses, along with FirstEnergy (-1.4%), which had filed a FERC challenge seeking to bar DR from PJM capacity auctions following the D.C. Circuit ruling. The PJM Power Providers (P3) Group, whose members include Dynegy, Calpine and NRG, had no immediate comment.

“We are extremely proud of our involvement in this seminal case that ensures an important role for demand-side resources in our nation’s wholesale electricity markets,” EnerNOC CEO Tim Healy said in a statement. “Today’s decision is a tremendous win for all energy consumers, for the economy and for the environment.”

“This decision allows us to continue realizing billions in annual savings from innovative incentives and business models that ensure we use our electricity system efficiently,” said White House spokesman Frank Benenati, who called the ruling “good news for consumers, clean energy, reliability and the overall economy.”

“It’s going to make consumers an equal participant in the market in a way they never were before,” Jon Wellinghoff, who chaired FERC when it issued Order 745, told Greentech Media. “That was the intention of Order 745, and that has been vindicated.”

Also happy was the Environmental Defense Fund: “Today’s Supreme Court decision is a victory for all Americans who want greater choice and value broader customer access to clean, low-cost energy,” said President Fred Krupp. “Demand response is helping millions of Americans get low-cost, clean and reliable electricity. Today’s court ruling will help expand customer choice, and solidify demand response as a crucial part of our clean energy future.”

Exelon praised the ruling, saying DR is “a valuable tool for our customers to manage their energy costs, and we believe it should play a role in our nation’s energy mix.”

The libertarian Competitive Enterprise Institute was critical. “The Supreme Court sends a clear message by ruling in favor of FERC’s power demand rule: Energy politics are a game that ignores both the rule of law and states’ constitutional authority. The effects of this decision trickle down to each individual consumer,” said Myron Ebell, director of the institute’s Center for Energy and Environment.

NARUC: Coordination is Key

Travis Kavulla, president of the National Association of Regulatory Utility Commissioners, said the ruling’s holding that energy conservation measures can be valued in both a retail and wholesale context “may serve to blur the already fuzzy line between state and federal jurisdiction.”

Kavulla cited a 2010 NARUC resolution on the jurisdictional overlap, which said “the coordination of federal and state initiatives offers the best way to assure the full benefits of demand response are delivered to customers.”

Kagan noted that the “statutory division generates a steady flow of jurisdictional disputes because — in point of fact if not of law — the wholesale and retail markets in electricity are inextricably linked.”

Indeed, the court will deal with another jurisdictional dispute next month. It has scheduled oral arguments for Feb. 24 on two cases pitting New Jersey and Maryland regulators against FERC. The court will consider orders by the 3rd and 4th U.S. Circuit Courts of Appeals that upheld lower court rulings throwing out contracts in which generation developers won state-issued subsidies to build plants in the two states. (See SCOTUS Agrees to Hear Md., NJ-FERC Subsidy Case.)

Wide Margin of Victory

The margin of FERC’s victory was a bit of a surprise. At oral arguments in October, the court’s liberal wing indicated support for FERC’s jurisdiction, but the commission faced harsh questions from Roberts, Kennedy and Scalia. (See FERC Jurisdiction over DR in Peril as Supreme Court Splits.)

In his dissent, Scalia said the majority’s opinion “inverts the proper inquiry.”

“Paying someone not to conclude a [retail purchase of power] that otherwise would without a doubt have been concluded is most assuredly a regulation of that transaction,” he wrote.

“While the majority would find every sale of electric energy to be within FERC’s authority to regulate unless the transaction is demonstrably a retail sale, the statute actually excludes from FERC’s jurisdiction all sales of electric energy except those that are demonstrably sales at wholesale.”

Scalia said the FPA defined the “sale of electric energy at wholesale” as “a sale of electric energy to any person for resale.”

“No matter how many times the majority incants and italicizes the word ‘wholesale’ … nothing can change the fact that the vast majority of (and likely all) demand response participants — ‘[a]ggregators of multiple users of electricity, as well as large-scale individual users like factories or big-box stores’— do not resell electric energy; they consume it themselves. FERC’s own definition of demand response is aimed at energy consumers, not resellers.”

Suzanne Herel contributed to this article.

January 24, 2016

NYPSC OKs $5.3B Clean Energy Fund

By William Opalka

ALBANY, N.Y. — The New York Public Service Commission on Thursday approved a 10-year, $5.3 billion Clean Energy Fund, a centerpiece of Gov. Andrew Cuomo’s Reforming the Energy Vision initiative to shift the state to resources that will fight climate change and provide more resilience.

NYPSC Chair Audrey Zibelman said the commission’s action was a milestone in the nearly two-year effort. “I really feel like we’re turning the chapter to the next stage of REV,” she said.

The commission also advanced the docket for the creation of a Clean Energy Standard that would mandate 50% of New York’s electricity come from “clean” energy sources by 2030. The NYPSC is under a Cuomo mandate to create the regulatory framework for the CES by June. Part of that mandate includes creation of financial incentives to keep New York’s upstate nuclear power plants viable until the renewable resources reach their target in 14 years. (See related story, New York Would Require Nuclear Power Mandate, Subsidy.)

Leaders of the Republican-controlled state Senate asked the commission to delay action on the initiatives, saying that while they support the goals of the fund, it should be considered as part of the 2015-2016 budget.

The Clean Energy Fund will advance solar, wind, energy efficiency and other clean tech industries to spur economic development and reduce carbon emissions, officials said. Cuomo said the $5 billion investment will leverage more than $29 billion in private sector funding.

The fund will be administered by the New York State Energy Research and Development Authority and financed through the systems benefit charge paid by ratepayers. It will receive $585 million this year and will be phased down annually, finally reaching zero after a decade.

Goals

In addition to the $29 billion in private investment, the 10-year goals include: 10.6 million MWh and 13.4 million MMBtu of energy efficiency; 88 million MWh of renewable energy; 133 million tons of CO₂ reduction; and $39 billion in customer bill savings.

The order says the traditional method of ratepayer-funded grants and rebates is too limited to effect the changes needed to meet New York’s climate and energy goals.

“The state’s greenhouse gas reduction goals demand that we achieve significantly more than is practical to achieve through current ratepayer-funded direct payment programs,” the orders states. “The status quo must evolve to a model that recognizes the appropriate use of targeted programs combined with spurring private sector involvement to reach the level of scale needed to realize our objectives. Transitioning from predominately government-directed resource acquisition approaches to market-based initiatives that intrinsically recognize the value of clean resources requires careful planning, along with a long-term commitment to the market.”

The projected $39 billion in customer bill savings will come from “innovative projects and private-public partnerships focused on reducing greenhouse gas emissions, making energy more affordable through energy efficiency and renewable energy, and mobilizing private-sector capital,” according to the governor.

Businesses are expected to see lower costs of $1.5 billion over the next 10 years, including an immediate reduction of $91 million from 2016 electric and gas system benefits charges compared to 2015.

The fund includes:

Market Development ($2.7 billion): NYSERDA initiatives are intended to stimulate consumer demand for clean energy alternatives and energy efficiency while helping to build clean energy supply chains. At least $234.5 million must be invested in low-to-moderate income initiatives during the first three years.
NY-Sun ($961 million): The fund finalizes the state’s commitment announced in 2014 for growing solar electricity by supporting rapid and continued cost reduction.
NY Green Bank ($782 million): The fund will complete the capitalization of the bank, which leverages private capital for clean energy projects. The fund will increase the NY Green Bank’s total investment to $1 billion and is expected to leverage an estimated $8 billion in private investment. (See Project Interest Overwhelms New York’s Green Bank.)
Innovation and Research ($717 million): Research and technology development is intended to drive clean-tech business growth and job creation while providing more energy choices.

Other REV Orders

The commission also approved several orders related to the REV proceeding.

Electric and gas utilities were directed to develop new energy efficiency programs, which included budgets and targets over the next three years (15-M-0252).

An earlier program based on rebates and subsidies expired at the end of 2015, but the REV initiative directed the utilities to develop flexible approaches that aligned with the state’s climate and energy goals.

“The commission directed that with this flexibility, utilities should develop programs that are market-based and include market mechanisms that combine resource acquisition with third-party activities to drive greater value for customers, achieve greater market-wide efficiency savings, target specific system needs and depend less on direct ratepayer support,” the order states.

The NYPSC also established a benefit-cost analysis for evaluating new energy proposals to determine whether they meet REV goals (14-M-0101).

The framework was included in the original REV order last year. Appendix C of Thursday’s order spells out the framework in detail. Utilities were directed to file “Benefit Cost Analysis Handbooks” by June 30.

The commission also expanded the scope of its large-scale renewable energy proceeding to bring it in alignment with the state’s Clean Energy Plan (15-E-0302). The LSR docket is the vehicle in which financial incentives for nuclear plants will be released and public comments gathered.

The Clean Energy Plan was released in December and first laid out the 50% renewable energy goal. The concurrent Clean Energy Standard proceeding formalizes that goal as state policy.

January 22, 2016

Plan Would Pay NY Nuclear Plants for Zero Emissions

By William Opalka

ALBANY, N.Y. — Upstate nuclear power plants would earn extra payments for emissions-free energy under a New York Public Service Commission staff proposal announced Thursday.

The proposal was previewed at the conclusion of the regular commission meeting, ahead of a planned staff white paper on Gov. Andrew Cuomo’s proposed Clean Energy Standard

Cuomo gave the PSC a June deadline to provide the regulatory framework for New York to derive 50% of its electricity from “clean” sources by 2030. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)

Zero Emission Credits

Under a broad outline, nuclear plants would be eligible to earn Zero Emission Credits (ZECs), similar to renewable energy credits (RECs) earned by wind and solar generators.

Like RECs, ZECs will be tradable, but the two would not be interchangeable under the plan.

“The staff proposal is to establish a requirement for all load-serving entities to procure a pro rata share of Zero Emission Credits … to produce an emission-free value for energy produced by nuclear power plants,” said Scott Weiner, director for markets and innovation.

Weiner referred to the plan as a “nuclear power bridge to a renewables future.”

It would also provide a lifeline to western New York’s financially stressed nuclear plants. The R.E. Ginna nuclear plant is seeking ratepayer subsidies after a reliability need was determined. The James A. FitzPatrick plant announced its closure due to low energy prices, and a third plant, Nine Mile Point, is under financial pressure. (See Entergy Rebuffs Cuomo Offer; FitzPatrick Closing Unchanged.)

Cuomo wants to close the state’s fourth nuclear plant, Entergy’s Indian Point facility, because of its proximity to New York City.

Officials declined to discuss specific details of the CES, which would also include revisions to the way New York procures and credits renewable energy.

New York’s most recent renewable portfolio standard expired in 2014. State regulators have been discussing a revised RPS for months in a so-called large renewables proceeding. Nuclear generation has now been added to the proceeding.

‘Drama’

The meeting started with “drama,” as PSC Chair Audrey Zibelman put it, when the Republican-led state Senate hand-delivered a letter to the commission seeking a delay in action on the CES and the creation of a $5.3 billion Clean Energy Fund.

The letter, signed by Majority Leader John Flanagan, his deputy and the head of the energy committee, said action was “premature” on the CEF, another order that’s part of the state’s Reforming the Energy Vision proceeding. (See related story, NYPSC OKs $5.3B Clean Energy Fund.)

“The CEF is a major fiscal initiative and has the potential to be even larger when taking into account the CES,” they wrote. “While we do not believe the commission is taking the fiscal implications of these initiatives lightly, it is the position of the conference that these proceedings would be strengthened by a real cost-benefit analysis and genuine opportunity for public input.”

The commission held a 38-minute executive session to discuss the letter but decided to proceed. Zibelman was particularly pointed in saying the letter failed to demonstrate any reason for the commission to delay action.

“This petition was filed in 2014 and there has been considerable opportunity for public commentary both in terms of the number of public statements, hearings and meetings … as well as the process before us,” she said. “There’s no question that we have in front of us a very robust record.”

For administrative ease, Zibelman said, the CES has been rolled into the existing proceeding for large-scale renewables (15-E-0302) rather than a new docket.