Page 1436 – RTO Insider

May 23, 2016

FERC Rulings in Brief: Week of May 19

Below is a summary of rulings issued by FERC last week.

FERC Finalizes Hold-Harmless Rules

FERC issued a policy statement finalizing rules regarding the use of hold-harmless commitments to protect customers from rate increases resulting from utility mergers (PL15-3).

The commitments — agreements not to seek recovery of transaction-related costs in rates unless they are offset by transaction-related savings — have become a common feature of merger applications under Section 203 of the Federal Power Act, but the commission hadn’t defined the costs with specificity, leading to inconsistencies.

The commission:

Clarified the scope and definition of the costs that should be subject to hold-harmless commitments;
Identified the types of controls and procedures that applicants offering hold-harmless commitments must implement to track the costs involved;
Clarified that an applicant may be able to demonstrate that the transaction will not have an adverse effect on rates without making any hold-harmless commitment; and
Declined to adopt its proposal to no longer accept hold-harmless commitments that are limited in duration. (See FERC to Tighten Policy on Hold Harmless Merger Commitments.)

Reliability Standard Wins Preliminary OK

FERC issued a Notice of Proposed Rulemaking (NOPR) proposing to approve NERC reliability standard BAL-002-2 (Disturbance Control Standard — Contingency Reserve for Recovery from a Balancing Contingency Event). The rule requires applicable entities to balance resources and demand, and return their area control error (ACE) to defined values following a disturbance. The commission required NERC to modify the standard to address concerns over extensions or delay of the periods for ACE recovery and contingency reserve restoration. It also directed NERC to address a reliability gap regarding power losses above the most severe single contingency (RM16-7).

Constellation’s Reactive Payments Cut Due to Retirements

The commission accepted a petition from Constellation Power Source Generation to reduce its revenue requirement for reactive supply and voltage control service by almost $225,000 as a result of the retirements of Riverside Unit CT 6 (June 1, 2014), Perryman Unit CT 2 (Feb. 1, 2016) and Riverside Unit 4 (planned for June 1, 2016). The commission also ordered hearing and settlement judge procedures to determine whether the company’s reactive power rate for its remaining fleet in the Baltimore Gas and Electric zones should be reduced further (ER16-746-001, et al.). (See Impatient FERC Orders Immediate PJM Action on Reactive Power Payments to Retired Plants.)

SoCalEd Can Recover Abandoned Tx Project Costs

FERC ruled that Southern California Edison may recover abandoned plant costs for the canceled Coolwater-Lugo transmission project but set settlement and hearing judge procedures to determine how much of the $37 million claimed by the company was prudently incurred. The project was no longer needed after the retirement of NRG Energy’s 636-MW Coolwater Generating Station and three other generators. The Los Angeles Department of Water and Power and the M-S-R Public Power Agency challenged the $8.51 million in overhead costs that SoCalEd included in its claim, saying the company provided little documentation for how overhead costs were allocated to the project (ER16-1025).

Settlement on SSR Units OK’d

The commission approved an uncontested settlement reached among several Illinois companies and MISO that changes Illinois Power Holdings’ annual revenue requirement for the operation of Edwards Unit 1, a 90-MW coal-fired steam boiler in Peoria, Ill., designated as a MISO system support resource. The new annual revenue requirements will be $7 million for 2013, $11.1 million for 2014 and $6.5 million for 2015 (ER14-2619-004, et al.).

Rehearings Denied

The commission also:

Denied rehearing but granted clarification of its October 2015 ruling in Order 816, which amended its regulations governing market-based rate authorizations (MBRA). (See FERC Refines Market-Based Rate Rules.)

The commission clarified that qualifying facilities in RTOs and ISOs are exempt from reporting requirements on long-term firm energy and capacity purchases. The commission also said that it did not intend to change the definition of long-term firm transmission reservations: those longer than 28 days. It also offered clarifications regarding the definition of a seller’s relevant geographic market and said MBRA applicants and sellers will not have to comply with the corporate organizational chart requirement until the commission issues an order at a later date (RM14-14-001).

Denied rehearing of its October ruling exempting American Transmission Systems Inc. and Duke Energy companies in Ohio and Kentucky from certain MISO multi-value project (MVP) transmission charges. MISO and MISO’s Transmission Owners sought rehearing to assign a usage fee to ATSI and Duke for MVPs approved before the companies moved from MISO to PJM in 2011. In the rehearing denial, FERC pointed out that MISO’s MVP cost allocation on withdrawing members was instituted in 2012 and said charging the companies would violate its rule against retroactive ratemaking. The commission also rejected arguments that MISO’s Tariff at the time of ATSI’s and Duke’s exits could be interpreted to allow for MVP-related financial obligations (ER12-715-004).
Denied El Paso Electric’s request for rehearing of a November 2015 order that required prior approval for utilities to engage in simultaneous exchange transactions involving their marketing affiliate and its affiliated transmission provider’s system (EL10-71-002).
Denied rehearing of a September 2015 order allowing future affiliates of Kanstar Transmission to use the same formula rate and incentives approved for Kanstar (ER15-2237-002).

– Rich Heidorn Jr. and Amanda Durish Cook

May 23, 2016

Aides Give Behind-the-Scenes Look at Senate Energy Bill

By Suzanne Herel and Rich Heidorn Jr.

CAMBRIDGE, Md. — Two aides from the Senate Committee on Energy and Natural Resources gave PJM Annual Meeting attendees a behind-the-scenes look at the making of the Energy Policy Modernization Act of 2016 (S.2102), the Senate’s first major energy bill in nearly 10 years.

Left to right: McCormick, Gray, Glazer © RTO Insider, PJM General Session, Senate Energy Bill — Left to right: McCormick, Gray, Glazer © *RTO Insider*

Patrick McCormick, chief counsel to Chairman Lisa Murkowski (R-Alaska), and Spencer Gray, an aide to ranking member Maria Cantwell (D-Wash.), were the featured guests in the second half of PJM’s general session. Moderator Craig Glazer, PJM vice president for federal government policy, promised the session would be “a cross between a high school civics lesson and ‘House of Cards.’”

Not ‘Revolutionary’

The bill passed the Senate on April 21 with a bipartisan vote of 85-12. To become law, however, it must be reconciled with a House bill that cleared in December with support from only three Democrats. (See U.S. Senate Energy Bill Faces Tight Calendar, Partisan Divide.)

Gray acknowledged the Senate bill didn’t contain the “revolutionary” changes of the 1992 Energy Policy Act, which mandated open transmission access and opened the industry to retail choice, or EPACT 2005, which created mandatory reliability standards.

But he and McCormick said it was nonetheless a victory over partisan gridlock — the product of weekly lunch and breakfast meetings between Murkowski and Cantwell, followed by several committee hearings and six weeks of bipartisan negotiations. It ended with a three-day markup at which some 90 amendments were considered. The final bill cleared the committee 18-4.

“I do think personal relationships matter,” Gray said. “The polarization in Congress … reflects, whether precisely or not, some level of polarization in the country. So it’s more difficult now I think to develop those relationships. And our bosses have worked hard at that.”

RTO Reporting Requirement

Gray at PJM General Session , senate energy bill — Gray © *RTO Insider*

Section 4302 of the bill requires RTOs and ISOs to report to FERC on their reliability, capacity resources, wholesale electricity prices and generation diversity.

McCormick said the provision resulted from Murkowski’s concern over the loss of baseload and intermediate generation, an issue he said was brought to her attention by former FERC Commissioner Philip Moeller.

McCormick and Gray said the reporting requirement was a compromise between members who sought more prescriptive language and those opposed to federal mandates. (Separately, Murkowski and House Energy and Commerce Chairman Fred Upton (R-Mich.) also have asked FERC to study price formation. And the Government Accountability Office has begun a study at Congress’ direction to compare capacity markets in the Northeast to those in the Midwest.)

The aides noted that the 22-member committee — more than one-fifth of the Senate — is shifting from predominantly Western states but still dominated by members in regions without organized electricity markets.

‘Soft Touch’ or Not?

“We’re not well positioned to second guess individual provisions of market design, whether it’s capacity markets or energy markets or other provisions that RTOs and ISOs are considering,” Gray said. “So the approach that the committee’s taken on an issue like this has been a fairly soft touch.

“Members [of Congress] are very wary about having solutions from a particular region pushed, let alone forced on their region,” he added.

In a question-and-answer session, Marji Philips of Direct Energy took issue with the aides’ characterization of the reporting provision.

“It’s pretty widely admitted that that bill is the ‘Save the Nuclear and Coal Plant Bill,’” she said. “The language mirrors very closely PJM’s Capacity Performance requirements. And it’s great that it’s been turned from a mandate to a report, but … the report gets everybody abuzz almost as much as a mandate. So if MISO isn’t doing this or New York isn’t doing this — they all look at this and say, ‘I’m not going to be the one to report to Congress that we’re not meeting this Capacity Performance requirement.’ You actually really are in some ways imposing PJM on other regions through this legislation.”

Philips asked the aides to broaden the language in conference with the House to ensure a role for demand response, “so it doesn’t read that you must have … hard steel [in the ground] that runs baseload.”

May 23, 2016

MISO Planning Advisory Committee Briefs

MISO last week reversed its position on the possibility of developing a limited coordinated system planning study with SPP.

Eric Thoms (copyright RTO Insider) - MISO planning advisory committee — Thoms © *RTO Insider*

The Planning Advisory Committee approved a recommendation that the RTO participate in a study identifying joint transmission needs along MISO’s seam with SPP’s Integrated System in North Dakota, South Dakota and Iowa.

The committee will vote on the motion via email, with results tallied at its June 15 meeting.

MISO staff last month recommended forgoing a coordinated study and focusing instead on improving the study process. SPP’s Seams Steering Committee voted in favor of embarking on a study. (See MISO, SPP Disagree on 2016 Joint Study.)

Eric Thoms, MISO manager of planning coordination and strategy, said the RTO has since adjusted its views, adding that a study focused on one target area would be more helpful than an all-encompassing study.

MISO PAC liaison Jeff Webb said the change resulted from stakeholder requests for some form of study with SPP despite the views of RTO staff.

MISO, Planning Advisory Committee — MISO stakeholders recommended the RTO participate in a study identifying joint transmission needs along its seam with SPP’s Integrated System in North Dakota, South Dakota and Iowa. *Map source: MISO*

“It’s not a matter of us being tired of doing studies,” he said. “That’s what we’re here for.”

MISO is also open to a coordinated Clean Power Plan-related study in 2017 after regional needs are identified in MTEP 17.

Interregional process improvements will continue regardless of the study decision, Thoms said.

The committee rejected another motion submitted by the Transmission Developers sector that recommended that MISO perform a broader coordinated study to evaluate the “impact of higher renewable penetration [and] alternative transfer scenarios on interregional reliability needs and historical high congestion along the MISO North/Central and SPP seam.”

MTEP 17 Futures Finalized

MISO has narrowed its 2017 Transmission Expansion Planning (MTEP 17) to three futures, eliminating a limited carbon emission scenario determined to be too similar to an existing fleet future. (See MISO Proposes 3 New MTEP 17 Futures.)

The final MTEP 17 futures are:

An existing fleet future with limited fleet changes and no modeled carbon cap;
An accelerated alternative technologies future that envisions innovation fostering a 30% carbon emissions reduction; and
A policy regulations future in which federal rules drive a 25% reduction in carbon emissions.

Ellis © RTO Insider; MISO Planning Advisory Committee — Ellis © *RTO Insider*

MISO adjusted the existing fleet scenario after stakeholders pointed out that low natural gas prices increase activity in the industrial corridor of Zone 9 along the Gulf Coast. Additionally, no scenarios will assume the renewable tax credit extends beyond 2022, which stakeholders pointed out was an uncertainty.

The futures went through three rounds of formal review and “reflect a balance of stakeholder feedback [while] bookending uncertainty,” said Matt Ellis, a MISO policy studies engineer.

“Even if the [Clean Power Plan] stay is overturned, these three futures still make sense,” Ellis added.

The PAC will further discuss the MTEP 17 futures during its June and July meetings. Planning wraps up in September with a presentation of a finalized regional resource forecast.

MISO Releases EPA Air Pollution Rule Study and CPP Paper

While MISO states will be compliant with EPA’s updated Cross State Air Pollution Rule (CSAPR) in 2017 even without NO_x emission trading, RTO staff say a regional trading arrangement would be the least expensive path to compliance.

That finding was the result of MISO’s own CSAPR study, according to Jordan Bakke, senior policy studies engineer for the RTO.

MISO studied three scenarios: a business-as-usual case; a no-trading scenario in which states strive for compliance individually; and seasonal NO_x trading among MISO states from May to September.

Bakke noted that 11 of the 23 states affected by the CSAPR rule are in MISO.

MISO states can meet their 2017 seasonal NO_x budget through a redispatch of natural gas for coal, but they would emit right up to their caps.

Under seasonal NO_x allowance trading, MISO production costs increase $31 million compared with a business-as-usual case without rule compliance.

If MISO states fail to adopt trading, overall costs rise, with Arkansas carrying the brunt at nearly $200 million in production, interchange and emission costs to achieve 2017 compliance. With emissions trading, Iowa carries the largest cost, at less than $25 million.

MISO used its 2015 Transmission Expansion Plan and 2017 forecast data to inform modeling, which included 2017 retirements and a projected $2.64/MMBtu Henry Hub price for natural gas. Current emissions-control technology was assumed to remain in place, with CSAPR compliance achieved only through energy and emission trading.

Footprint Diversity Study Timeline Accelerated

Stakeholders say MISO’s proposed footprint diversity study should begin sooner than the RTO first suggested. The study would examine the benefits of expanding flows on the constrained transmission interface linking the RTO’s North/Central and South regions, including exploring the option of building new transmission. (See MISO Proposes Study to Measure Benefits of New North-South Tx.)

MISO Director of Policy Studies J.T. Smith said the RTO will scope out a study process beginning in the fall, with a study targeted to begin in 2017. The Economic Planning Users Group will evaluate scope development.

— Amanda Durish Cook

May 23, 2016

FERC Approves NYISO Behind-the-Meter Rules

By Michael Brooks

FERC last week accepted NYISO’s proposed Tariff revisions allowing large behind-the-meter resources in New York to participate in the ISO’s energy and capacity markets (ER16-1213). The new rules became effective Thursday.

solar-panels-on-top-of-building-(Cubit-Power-Systems)-web - FERC, NYISO, behind-the-meter — *Photo source: Cubit Power Systems*

“We recognize the potential benefits of reducing obstacles to using excess capacity of behind-the-meter resources to support New York’s grid,” the commission said. “NYISO’s proposal advances this goal, as behind-the-meter resources that meet NYISO’s eligibility requirements will be permitted to bid energy and capacity in a comparable way to other suppliers and receive payments if they are dispatched. Their participation should improve the competitiveness, efficiency and reliability of those markets.”

Under the changes, behind-the-meter generators must be at least 2 MW, serve a load of at least 1 MW and be capable of exporting at least 1 MW to the New York grid. The new rules include calculations for determining a resource’s available installed capacity (ICAP). The ISO would also apply all of its current market power mitigation rules to BTM resources.

NYISO also proposed a new eligibility requirement for resources seeking to qualify as an ICAP supplier to guard against the possibility behind-the-meter resources would not be subject to the ISO’s interconnection procedures. For existing resources subject to the new requirement, there will be a 60-day transition period in which they may sell capacity without having to enter a class year study.

Currently, two generators serving load behind the meter are allowed to participate in NYISO’s markets. The ISO would work with these generators so they can qualify as BTM resources under the new rules, it told FERC.

Stakeholders generally supported NYISO’s proposal but several protested specific aspects of the ISO’s proposal.

The New York Public Service Commission told FERC that market power mitigation was unnecessary for distributed generation, arguing that it is too small in scale to pose a threat. FERC dismissed the regulators’ comment, saying the PSC “has not provided any support for its assertion.”

The Independent Power Producers of New York protested the transition period, arguing that NYISO had not identified to which resources the period would apply. IPPNY said that allowing resources to sell capacity without being subject to a class year study could threaten reliability.

FERC dismissed these arguments as well. “We find that the concerns raised by IPPNY regarding reliability are unsupported,” it said. “Reliability concerns will be reasonably mitigated by the limited duration of the transition period and the requirement that any grandfathered projects must have completed all required interconnection studies and have an effective interconnection agreement by May 19, 2016.”

May 23, 2016

Berkshire Denied Rehearing on EIM Market Power

By Robert Mullin

FERC last week denied a request by NV Energy and PacifiCorp to rehear a previous decision that prohibits the two companies’ generating units from offering energy into the Western Energy Imbalance Market (EIM) at prices above default energy bids because of market power concerns.

Both companies are subsidiaries of Warren Buffet’s Berkshire Hathaway Energy — and currently the only major participants in the CAISO-run EIM outside of California.

The commission’s May 19 ruling also provided a key clarification: The companies’ future EIM market power studies must provide analysis of potential power in EIM submarkets stemming from transmission constraints — not just the market as a whole (ER15-2281-001, ER15-2282-002, ER15-2283-001).

That condition will apply to any new EIM participants as well, FERC said.

At issue in last week’s ruling was a November 2015 order that found the companies had provided a “deficient” market analysis that failed to disprove their horizontal market power in the EIM. The order also questioned CAISO’s ability to mitigate such power outside the ISO’s own balancing area.

“This is problematic because all of the EIM-participating generation in the NV Energy and PacifiCorp-East balancing authority areas is owned by the Berkshire EIM sellers,” the commission wrote in that order. “Therefore, when the interconnections between CAISO and the NV Energy balancing authority area are constrained, customers in the NV Energy and PacifiCorp-East balancing authority areas must take service from a Berkshire EIM seller for imbalance energy.”

FERC’s solution: to cap the companies’ imbalance energy offers at default bids and require that they facilitate CAISO’s enforcement of all internal transmission constraints throughout the NV Energy and PacifiCorp balancing areas — effectively bringing the ISO’s local market power mitigation measures into those territories.

While the companies did not oppose the first condition, they contested the second, arguing that the commission had veered from precedent by imposing bidding restrictions rather than relying on CAISO’s mitigation to address market power concerns.

In their rehearing request, the companies pointed out that generator participation in the EIM is voluntary — a fact recognized by FERC. They also argued that market power in imbalance energy did not present the same concerns as concentration in energy or capacity markets.

FERC shot down both arguments in its denial.

“The sufficiency of commission-approved market monitoring and mitigation to address market power concerns has never been invulnerable to challenge,” the commission wrote, noting FERC precedent of allowing intervenors to challenge the efficacy of an RTO’s monitoring regime.

The commission also reiterated its concern that the EIM could be subject to physical withholding precisely because it was developed and approved as a voluntary market.

“That concern is not to be overlooked simply because imbalance energy is a small part of an EIM entity’s reliability and load serving obligations,” the commission said.

The commission was also unconvinced by the companies’ contention that they have little incentive to manipulate a market in which they are among the largest buyers.

“The ability to exercise market power provides adequate justification to impose mitigation,” the commission said.

May 23, 2016

PJM General Session Focuses on Distributed Resources

By Suzanne Herel

CAMBRIDGE, Md. — Three experts examined the challenges of integrating distributed energy resources into electricity markets at the general session of PJM’s Annual Meeting last week.

L to R - Agate,Tabors, Hauser at General Session - PJM distributed energy resources — Left to right: Agate, Tabors, Hauser © *RTO Insider*

Richard Tabors, co-director of the Utility of the Future Study at the Massachusetts Institute of Technology, envisioned a platform market structure akin to the sharing economy of services such as Uber and Airbnb.

Such a construct, enabling multiple participants to buy and sell energy from each other, requires accurately valuing generation and demand response resources — including real energy, reactive power and reserves, he said.

“How far and how deeply can I take that pricing question? I can take the arithmetic all the way to the meter,” he said.

Tabors called the method distributed locational marginal price (DLMP). Tabors called the method distributed locational marginal price (DLMP). “There’s a huge number of hours when there’s a material difference between the nodal transmission prices and the nodal prices occurring on the attached distribution feeder,” he said.

It is a model that Tabors’ consulting firm presented for the New York State Energy Research and Development Authority under the state’s Reforming the Energy Vision initiative. (See related story, NY REV Order Revamps Utility Business Model.)

Gridwise Alliance CEO Steve Hauser focused on the challenge of encouraging technology while furthering the public good in developing the grid of the future.

The industry is moving from being utility-centric to customer-focused, he said, sparking an evolving business model to accommodate two-way power flow. The model must be adaptable and allow customers to provide services back to the grid, he said.

He noted that D.C. and PJM states Illinois, Maryland, Delaware and Pennsylvania ranked in the top 10 in the alliance’s annual Grid Modernization Index.

Like Tabors, Hauser said the industry must properly value, integrate and optimize DER — and provide better information to decision-makers.

Will Agate, senior vice president of energy operations and initiatives at the Philadelphia Navy Yard, outlined how the former military base has become a “Smart Energy Campus” with its own microgrid. Agate said the yard is one of the most successful Base Realignment and Closure (BRAC) projects in the U.S., with industrial and office tenants including the Aker Philadelphia Shipyard, a Tastykake bakery, Urban Outfitters and GlaxoSmithKline.

The Navy Yard invested $33 million in grid modernization to create what Agate called “one of the largest nonmilitary, unregulated electric systems on the East Coast.”

As part of its energy master plan, the Navy Yard is reducing demand while adding supply independence.

In addition to its 10-MW substation with a PECO Energy tie-in, the Navy Yard has on-site generation: a 6-MW natural gas peak shaver and 1 MW of solar generation.

Although the Navy Yard project is somewhat unique, Agate said it can provide “lessons learned” for other communities considering microgrid and smart grid solutions. Agate said it is important to bring stakeholders together to agree on a master plan and to not be afraid of getting something started.

May 23, 2016

Overheard at the NE Restructuring Roundtable

New England restructuring roundtable — Perez-Arriaga © *RTO Insider*

Massachusetts Institute of Technology professor Ignacio Perez-Arriaga, said the university’s Utility of the Future study, scheduled for release in October, will have two major messages: “One is we have to reduce the barriers that impede an efficient and effective participation by distributed energy resources … and all resources, including DERs, should be exposed to correct economic signals, to allow DERs to respond to system conditions.”

Judson © RTO Insider - New England restructuring roundtable — Judson © *RTO Insider*

Massachusetts Department of Energy Resources Commissioner Judith Judson said a comprehensive state study on energy storage will be released in the coming weeks, which will soon be followed by a request for proposals for demonstration projects. “Massachusetts has been lagging behind, currently ranked about 23rd in advanced storage (electrochemical and thermal), and we want to change that.”

New England round table — Sylvester © *RTO Insider*

Maryrose Sylvester, CEO of GE Current, a new General Electric company merging LEDs, energy efficiency services and the “industrial Internet,” discussed how data collection is driving optimal uses of energy efficiency. “Think of all the ways that people can make themselves more productive, when they have so much information. The challenge for a customer is how do you turn all of that data into something that is really usable, that tells them what to do, what to start doing, what to stop doing and to make it very actionable.”

Anthony Eggert, ClimateWorks Foundation - New England round table — Eggert © *RTO Insider*

Anthony Eggert, director of transportation for the ClimateWorks Foundation, said global electric vehicle sales reached about 1% of total sales in the fourth quarter of last year. “If we are going to meet our decarbonization goals, we have to have electric-drive vehicles as the dominant part, especially in the passenger vehicle market.”

Brostrøm © <em>RTO Insider</em> — Brostrøm © *RTO Insider*

DONG Energy’s Thomas Brostrøm said the company, which has had extensive experience developing offshore wind in Europe, sees opportunities in the U.S., where it holds federal leases for potential developments off Massachusetts and New Jersey. “We would have capacity factors in the high 20% to the low 30s [on the European projects], but that is trending upward as we’re seeing capacity factors in the higher 40s or low 50s as the newer turbines are coming online,” said Brostrøm, general manager of the Danish company’s North American operations.

May 23, 2016

Constitution Pipeline Appeals Rejection of Water Permit

By Ted Caddell

Arguing that New York’s denial of a crucial water quality certification was “arbitrary and capricious” and ran counter to FERC approval, Constitution Pipeline last week appealed the state’s decision to the 2nd Circuit Court of Appeals (16-1568).

Separately, the company also asked the U.S. District Court for the Northern District of New York for a declaration that federal law trumps state “permitting jurisdiction over certain other environmental matters” (1:16-cv-00568).

“We believe the court will agree that this permit denial was arbitrary and unjustified and improperly relies on the same failed arguments that the [New York Department of Environmental Conservation] made during the FERC certificate proceeding regarding the pipeline route and stream crossings,” the project’s sponsors said in a statement. “We are ultimately seeking to have the court overturn this veiled attempt by the state to usurp the federal government’s authority and essentially ‘veto’ a FERC-certificated energy infrastructure project.”

New York environmental officials denied the water quality permit for the 124-mile pipeline, which is designed to carry shale gas from Pennsylvania fields to markets in eastern New York and New England. (See New York Environmental Department Rejects Constitution Pipeline.)

It was the last regulatory approval needed for the project, which is backed by Williams Partners, Cabot Oil & Gas, Piedmont Natural Gas and WGL Holdings. It received FERC approval in December 2014.

The state said the application “fails in a meaningful way to address the significant water resource impacts that could occur from this project and has failed to provide sufficient information to demonstrate compliance with New York state water quality standards.”

The project sponsors charge that the state’s denial of the crucial permit will delay the necessary infusion of natural gas supply to the starved Northeast and block the estimated 2,400 direct and indirect jobs the project would bring to the region.

May 23, 2016

Brattle Study Sees ERCOT Continuing to Rely on Nat Gas, Renewables

By Tom Kleckner

A Brattle Group analysis of the potential effect of regulatory and market factors on ERCOT’s generation says the ISO will rely primarily on natural gas, wind and utility-scale solar power over the next 20 years, continuing recent trends.

ERCOT’s current monthly demand and energy report shows natural gas is providing 46.7% of its generation this year, followed by coal (19.6%) and wind (18.3%). Nuclear represents 14.6% of the ISO’s generation, but the Brattle study sees that dropping to 9% by 2035. Brattle said low natural gas prices could result in the retirement of 12 GW of coal-fired generation, 60% of ERCOT’s current fleet, by 2022.

Solar accounts for just 0.2% of ERCOT’s generation, but the ISO expects that to grow from 288 MW to more than 1,000 MW by the time summer begins, with another 6,700 MW of solar capacity under study in the transmission queue.

The Brattle Group study assumes that natural gas prices will remain below $4/MMBtu and that solar photovoltaic prices will continue to decline. That will result in reduced carbon emissions and inflation-adjusted wholesale prices equal to those of 2014, the report said, and make proposed federal regulations “largely irrelevant.”

The analysis was commissioned by the Texas Clean Energy Coalition, which has hired Brattle to conduct three previous studies.

ERCOT, Brattle Group — *Information for 2015 for this month has been updated based on final settlements. **Information for 2016 for this month has been updated based on final settlements.

Brattle built its study on four reference cases: low/high natural gas prices and low/high cost of utility-scale solar PV, based on natural gas futures and ERCOT and National Renewable Energy Laboratory forecasts. Analysts also explored three policy scenarios for each case: improved state energy efficiency programs, and mass- and rate-based emission limits under the Clean Power Plan.

This year, ERCOT said its monthly energy use is down 1.1% from 2015, though April’s peak demand was up 12.6% — the first time it has surpassed monthly demand from last year (50,920 MW versus 45,227 MW for April 2015).

Transmission Concerns

ERCOT spokesperson Robbie Searcy said while the Brattle study used “many of the same basic assumptions” as the ISO’s studies, its own analysis indicates “recent environmental regulations may accelerate the pace of unit retirements, potentially faster than the system can adapt to support reliability.”

Searcy said the ERCOT study focused on localized transmission-system reliability, which would be more susceptible to generation retirements. “It could take several years for the transmission system to catch up with these needs, in turn creating potential reliability challenges in the interim,” she said.

May 23, 2016

NY REV Order Revamps Utility Business Model

By William Opalka

The New York Public Service Commission on Thursday approved an overhaul of the way utilities will earn money as the state switches to more distributed and cleaner energy sources.

The so-called Track 2 order in the state’s Reforming the Energy Vision initiative intends to provide a framework for utilities to remain financially sound while offering customers greater choices to interact with third parties (14-M-0101).

The order was contemplated when New York embarked on the REV process two years ago. A part of that initiative continued last summer with the release of a staff white paper that offered a more detailed look at how a utility of the 21st century could operate. (See NYPSC Outlines Reforming the Energy Vision Changes.)

‘Energy and Financially Inefficient’

The current grid was based on utilities earning returns on investments in large, centralized power systems sized to meet peak electric demand that occurs only a few days each year, “an energy and financially inefficient system,” the commission said in announcing the order.

“Cost-of-service ratemaking has allowed regulated distribution utilities to be insulated from the opportunities and the competitive pressures of the modern information economy. As a result, gains in capital productivity remain low and the efficiencies made possible by information technologies and new business models have been slow to materialize in the utility sector.”

The rules will create a new business model with “earnings opportunities for utilities that are aligned with consumer value and with a more efficient and resilient distributed low-carbon electric system,” the 158-page order states.

The NYPSC said the “historic structural reforms” to ratemaking are “unprecedented in its breadth and scope,” an effort to accommodate the digital economy while also transitioning to New York’s clean energy goals of deriving 50% of its energy from renewable resources by 2030. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)

“What we want is utilities to start thinking about the ability to use third-party programs, not as something that they have to do because we require them to do them, or they do the minimum to make us happy, but because they want to do this because the earnings they can get from using other resources that drive efficiency can give them as much opportunity as traditional cost of service,” PSC Chair Audrey Zibelman said at the meeting.

“The focus of this decision is to create a modern regulatory model that challenges utilities to take actions to achieve these objectives by better aligning utility shareholder financial interest with consumer interest,” the order states.

‘Transactive’ Grid

The order envisions a two-way “transactive” grid instead of the current one-directional flow.

It builds on traditional cost-of-service ratemaking with the addition of market-based platform earnings and outcome-based earnings opportunities.

The order states there are three principles to ratemaking reform:

The unidirectional grid must evolve into a more diversified and resilient distributed model engaging customers and third parties;
Universal, reliable, resilient and secure delivery service must be ensured at just and reasonable prices; and
System efficiency and consumer value and choice must be improved to achieve a more productive mix of utility and third-party investment.

Platform Service Revenues

Platform service revenues (PSRs) are new forms of utility earnings derived from distribution-level markets. The order contemplates early-stage earnings will come from displacing capital intensive infrastructure projects with non-wires alternatives, such as the Brooklyn-Queens Demand Management Program, which has allowed Consolidated Edison to defer building a $1 billion substation in Brooklyn in favor of less-costly distributed energy resources: solar, batteries and energy efficiency. (See NYPSC OKs Con Ed’s Demand Management Program to Relieve NYC Overloads.)

As markets mature, opportunities to earn with PSRs will increase, the order says. “Earning adjustment mechanisms” are for the design of new incentives earned under several categories:

System efficiency: Each utility will propose a peak reduction target and a load factor improvement target.
Energy efficiency: The Clean Energy Advisory Council will develop targets for energy efficiency beyond the existing energy efficiency transition implementation plan and Clean Energy Fund targets.
Interconnection: A positive earning opportunity will be developed based on satisfaction surveys of DER providers regarding utilities’ delivery of timely and cost effective interconnection approvals. Utilities will be required to meet standardized interconnection requirements (SIR) to earn positive adjustments. The commission will also consider on a case-by-case basis negative earning adjustments for failure to meet benchmarks.
Greenhouse Gas reductions: Utilities will have earning opportunities tied to reducing the cost of achieving the Clean Energy Standard’s (CES) target of 50% renewable generation by 2030. Those opportunities will be better defined in the CES proceeding. “Utilities will be required to develop a more efficient and cleaner network through retail markets for distributed energy resources such as solar, geothermal, wind, fuel cells, combined heat and power and battery storage, energy efficiency and other advanced energy services,” according to the order.

Unregulated utility subsidiaries are permitted to offer competitive value-added services, provided they create standards of conduct to prevent conflicts of interest.

Time-of-Use Rates

Customer participation in advanced rate design will be encouraged through opt-in time-of-use rates. The state will review successful programs adopted elsewhere and seek to improve promotion and customer education while creating smart-home pilot projects through collaborations with third parties or the New York State Energy and Research Development Authority.

Rate cases will examine the existing demand charges applicable to commercial and industrial customers to determine if they can be made more time sensitive.

Zibelman said an “overarching concern” is that utilities maintain their financial integrity because of the large capital requirements needed for initiatives such as vehicle electrification.

Each of the utilities will be required to file a system efficiency proposal by Dec. 1 to reduce high-cost energy generation during times of peak energy demand.

Implementation, with beginning steps from the utilities mandated to start later in 2016, will take much longer.

“I estimate there are at least 100 policy decisions in this item,” Commissioner Gregg Sayre said. “This is a process that will certainly take years. And if technology and markets continue to change at the same pace that they are changing now, we will never be done. And that’s OK, in fact, it’s even good.”