Page 1548 – RTO Insider

May 18, 2015

FERC Denies Rehearings on ROE Challenges

By Michael Brooks and William Opalka

The Federal Energy Regulatory Commission said last week that the single-step discounted cash flow (DCF) analyses that it formerly used are adequate to support rate complaints made before it changed the rules.

FERC made the assertion in denying requests by Xcel Energy and the New England Transmission Owners that it reconsider its orders establishing hearing and settlement judge proceedings in return on equity (ROE) disputes.

The rulings involved complaints that sought to reduce the New England TOs’ ROE (EL13-33 & EL14-86-001) and two ROE disputes between Xcel’s Southwestern Public Service Co. (SPS) and Golden Spread Electric Cooperative (EL13-78 & EL12-59).

Opinion 531

Golden Spread has two agreements with SPS: a power purchase agreement with a 10.25% return on equity (ROE) and a transmission agreement with an 11.27% ROE. In April 2012, Golden Spread filed a complaint with FERC, using a single-step DCF analysis to show that SPS’s ROE in both agreements should be reduced to 9.15%. The co-op filed another complaint in July 2013 using more recent data but again asserting the 9.15% ROE.

Xcel and the New England TOs contended that the old, one-step DCF methodology is not valid because of the commission’s June 2014 ruling Opinion 531, which changed its DCF methodology to a two-step process it has long used for natural gas and oil pipelines that incorporates long-term growth rates. The commission issued Opinion 531 on the same day it ordered the hearing proceedings in the Golden Spread complaints. (See FERC Splits over ROE.)

FERC disagreed, saying that both Xcel and the New England TOs misinterpreted the commission’s findings regarding the one-step DCF methodology in Opinion 531. The commission did not find that the one-step DCF methodology was inadequate, FERC said Thursday. “Rather, the commission found that, given the evolution of the electric industry, it had become more appropriate to use the two-step DCF methodology to determine what ROE to set as a public utility’s ROE.”

“That the two-step DCF methodology ‘is preferable to the one-step DCF methodology’ for ultimately setting a public utility’s ROE does not preclude the commission from relying on DCF studies using the one-step DCF methodology” in complaints made prior to Opinion 531, FERC said.

Golden Spread vs. SPS

FERC also disagreed with Xcel’s assertion that Golden Spread’s July 2013 complaint only served to extend the maximum 15-month refund-effective period for its April 2012 complaint. Golden Spread filed the later complaint the day before the first complaint’s refund period expired.

“Golden Spread filed two separate complaints, based on different facts, thereby commencing two separate proceedings,” FERC said. It noted that though both of Golden Spread’s analyses determined a 9.15% figure, this was a median ROE produced from different ranges: 7.51 to 10.59% in 2012 and 6.37 to 11.51% in 2013. Therefore, “we expect the parties in this case to litigate a separate ROE for each refund period,” the commission said.

New England TOs

The New England TOs had cited the use of the single-step DCF as one of their grounds for seeking rehearing of FERC’s orders on two ROE challenges: the commission’s June 2014 order on a December 2012 complaint (EL13-33) and its November 2014 order on a July 2014 complaint filed by a different group of complainants (EL14-86).

Both complaints alleged that the New England TOs’ 11.14% base ROE was unjust and unreasonable.

In addition to dismissing objections to the single-step DCF analysis, the commission also rejected the New England TOs’ argument that the commission erred in EL13-33 because the ROE that the complainants sought to change was already within the commission’s “zone of reasonableness.”

The commission disagreed. “The zone of reasonableness produced by a DCF analysis does not create a zone of immunity for a utility’s ROE. Showing that a utility’s existing ROE is unjust and unreasonable ‘merely requires showing that the commission’s ROE methodology now produces a numerical value below the existing numerical value.’ Therefore, the commission appropriately concluded that [the complainants] made a prima facie showing that New England TOs’ 11.14% base ROE might be unjust and unreasonable.”

May 18, 2015June 15, 2023

Company Briefs

The Federal Energy Regulatory Commission gave NorthWestern Corp. its blessing Thursday to issue up to $950 million in securities over the next two years.

The securities include $250 million in equity, $300 million in secured debt and $400 million in unsecured debt. NorthWestern said that the funds received from the issuance would go toward refinancing $150 million in first mortgage bonds in Montana in addition to paying for normal business activities.

FERC approved the issuance although NorthWestern’s 1.73 interest coverage ratio fell below the commission’s 2.0 benchmark. NorthWestern explained that this was because the analysis included interest expenses from $450 million of debt it issued in November 2014 to finance its purchase of 11 hydroelectric plants from PPL Montana but not a corresponding rate increase approved by the Montana Public Service Commission.

More: ES15-14

Duke Pleads Guilty to Coal Ash Charges, Fined $102 Million

Duke Energy pleaded guilty in federal court last week to nine criminal violations of the Clean Water Act for polluting four major rivers with toxic coal ash. U.S. District Court Judge Malcolm J. Howard accepted the guilty pleas and fined the company $102 million.

The violations stem from coal ash spills or leaches into four rivers from five power plants in North Carolina, including a massive spill into the Dan River last year.

Federal attorneys and company officials reached a plea agreement after negotiations earlier this year, and the pleas and fines signal the end of federal action against the company. Duke still faces charges and fines from North Carolina environmental officials, as well as a shareholder suit filed against it in Chancery Court in Delaware.

More: Los Angeles Times

Suit Alleges Duke Board Members Leaned on NC Regulators on Ash Issue

A shareholder suit against Duke Energy alleges that the company’s board of directors lobbied North Carolina environmental regulators to limit the company’s legal exposure from coal ash spills. The suit has been sealed in an agreement between both the shareholder filing the suit, Judy Mesirov of Philadelphia, and the company. But according to some of the unsealed documents, Mesirov alleges that some Duke executives and board members exposed the company to billions of dollars in liability because of their actions.

Duke has been battling legal claims since a massive coal ash spill polluted the Dan River last year. The company reached a $102 million settlement with federal authorities related to the incident but faces state charges related to groundwater contamination stemming from other ash spills.

More: Charlotte Business Journal

FirstEnergy Looking for Coal Ash Disposal Site

FirstEnergy is closing the largest coal ash dump in the U.S. — Little Blue Run in Beaver County, Pa. — and is now looking for a place to dispose of the 2.5 million tons of coal ash produced by its Bruce Mansfield plant in nearby Shippingport, Pa.

It has two sites selected so far, but both require transportation of the ash by barge on the Ohio River. FirstEnergy is seeking permits from the Pennsylvania Department of Environmental Protection to let it use a now-closed ash dump at the retired Hatfield’s Ferry coal plant as an interim measure.

The company is under a consent order to close the Little Blue Run site by the end of 2016, partly because of toxins leaching out of the site and into ground and surface water.

More: Pittsburgh Post-Gazette

Entergy’s Arkansas Nuclear One Garners Lowest Marks in NRC Review

Entergy’s Arkansas Nuclear One in Russellville was ranked near the bottom in the Nuclear Regulatory Commission’s annual operations safety review, the agency said recently. The ranking was the result of “a significant decline in plant performance,” NRC said.

That included a fatal accident in 2013 and a series of flaws with the plant’s flood-control systems that turned up during an NRC inspection.

The commission has allowed the plant to continue operations because it has seen improvement, an NRC official said. “The NRC does believe that the plant can operate safely and therefore they have not been asked to shut down. They have demonstrated sustained improvement so far with making corrective action to some of these issues that we’ve discussed.”

More: THV11

North Dakota Co-op Gets $12.5 Million for Tx Lines

The U.S. Department of Agriculture awarded Slope Electric Cooperative a $12.5 million loan to expand its electrical transmission system in western North Dakota. The money will go toward building 66 miles of power lines in Adam, Bowman, Hettinger and Slope counties. The co-op also received a $431,600 grant for smart grid projects.

More: Bismarck Tribune

We Energies’ Plan to Invest More in Coal Plant Draws Criticism

We Energies has applied to the Wisconsin Public Service Commission to spend about $100 million to upgrade coal handling and storage at its Oak Creek coal-fired station, saying it could save customers $16 million to $25 million a year. The upgrades would allow the 10-year-old plant to use softer, cheaper Wisconsin-mined coal, leading to fuel savings that would be passed on to customers.

The Citizens Utility Board and Clean Wisconsin objected, saying the softer coal would produce more emissions.

“At a time when the state of Wisconsin must develop a plan for cost-effective carbon dioxide emission reductions, We Energies is proposing to significantly increase CO₂ emissions,” said Katie Nekola of Clean Wisconsin. “In its short-sighted pursuit of fuel cost savings, the utility ignores the long-term costs of increasing CO₂ output, both to ratepayers and the environment.”

More: Milwaukee Journal Sentinel

Consumers Energy Retiring ‘Classic Seven’ Coal Plants

Consumers Energy is retiring 32% of its generation fleet by April 2016 in an effort to reduce emissions and increase sustainability. “These plants, which we call our ‘Classic Seven,’ have provided reliable, affordable energy for Michigan residents for decades, but it doesn’t make economic sense to spend more to keep them running,” said David Mengebier, Consumers Energy’s senior vice president for governmental and public affairs.

The company announced the plant retirements in its Accountability Report, in which it says that since 1998 it has reduced particulate emissions at its plants by 91%, nitrous oxide by 78%, sulfur dioxide by 53%, mercury by 28% and carbon by 13%. The only U.S. utility closing more coal plants is AEP Ohio.

More: Fierce Energy; Consumers Energy

Allete Buying 100-MW Wind Farm in Pennsylvania from AES

Allete Clean Energy is buying a 100-MW wind farm in Troy, Pa., from AES for $108 million, plus an undisclosed amount of existing debt. Armenia Mountain Wind is near the New York-Pennsylvania border and has 67 1.5-MW turbines that were installed in 2009. The facility’s output is sold through power purchase agreements that expire in 2025. Allete, which owns six wind farms, bought three of them from AES. Armenia Mountain is the largest in its portfolio.

More: PennEnergy

DTE Building 1.1-MW Solar Array Outside Ann Arbor

DTE Energy is building Michigan’s largest solar panel array outside of Ann Arbor. The 1.1-MW facility, with 4,000 photovoltaic panels, will produce enough electricity to power 185 homes, according to the company.

DTE has already received approval from Ann Arbor Township to build on the 8-acre site. When completed later this year, it will join nearly 9 MW of solar generation the company has in 22 sites in the state. The company is investing in renewable energy as a result of a state mandate to obtain 10% of its energy from renewable sources by 2015.

More: MLive

May 18, 2015June 15, 2023

PJM Market Monitor Q1 Review: Markets Working but Improvement Needed

By Suzanne Herel

In its first quarterly State of the Market Report for 2015, PJM’s Independent Market Monitor found that market performance was better than in the first three months of 2014, but it identified areas needing attention, including the ability for participants to increase markups in tight market conditions and flaws in the capacity market.

The report, released Monday, coincided with PJM’s response to the Monitor’s 2014 annual State of the Market Report, saying the RTO had either implemented or was in the process of addressing 66% of the Monitor’s concerns. (See Monitor: Winter Prices Boosted PJM Prices, Raise Withholding Concerns.)

Capacity

Both reports addressed the need to implement PJM’s Capacity Performance plan, on which the Federal Energy Regulatory Commission is expected to rule by June 9. (See PJM Responds to FERC Queries on Capacity Performance, Requests Approval.)

PJM’s response detailed how the polar vortex and winter storms of 2014 tested the reliability of the grid, making apparent the need for some improvements.

“The January 2014 events call attention to many of the recommendations the IMM has made in previous State of the Market Reports regarding performance incentives for capacity resources, the need to enforce annual performance for demand resources and for ensuring as much flexibility as possible regarding generator operating parameters,” PJM said.

Similarly, the Monitor’s report noted that the markets have reflected February’s unusually cold weather.

“PJM markets did work during the extreme conditions, but the experience continues to highlight areas of market design that need improvement,” it said.

For one, it is “more critical than ever” to fix capacity market prices, the Monitor said.

“The underlying capacity market issues have not been addressed,” it said. “For example, uplift remained high in large part as a result of inflexible unit parameters, which were based, in many cases, on inflexible gas supply arrangements; outages were high, performance incentives remain weak, prices in the capacity market remain well below replacement costs and there is no resolution of the disconnect between the incentives facing electric generating units and the incentives facing gas pipelines, which is a barrier to the construction of new pipeline capacity.”

Withholding Concerns

The quarterly review concluded that energy prices generally reflected competitive behavior. But, it said, “the behavior of some participants during the high demand periods in 2014 and 2015 raises concerns about economic withholding.”

“In particular,” the Monitor said, “there are issues related to the ability to increase markups substantially in tight market conditions, to the uncertainties about the pricing and availability of natural gas, and to the lack of adequate incentives for unit owners to take all necessary actions to acquire fuel and generate power rather than take an outage.”

The fact that January 2014 was so severe, however, makes a quarter comparison difficult to interpret, Market Monitor Joe Bowring said. “It’s important to remember to put things in longer terms, in historical perspective,” he said.

He pointed to the load-weighted average of real-time LMPs as example. The average fell 45.2%, from $92.98/MWh in the first three months last year to $50.91/MWh this quarter. But that is 36.1% higher compared with the same period in 2013, the Monitor noted, as well as higher than the same quarters in 2009-2012.

“Even though prices went down dramatically, they’re really not that low,” Bowring said, also noting that they were higher than 11 of the 16 first quarters since the markets began in 1999.

The decrease in prices over last year is a result of lower fuel prices and demand, along with better grid operations, according to the report.

“Another key point is that markup remains significant. It was higher in terms of percent,” he said. “Markup is an indicator of non-competitive behavior. To the extent that we see markup cropping up, it’s a concern to competitiveness and an important flag for people.”

Meanwhile, total energy uplift charges for the quarter — still high compared with recent years — dropped by $560.6 million to $186.9 million, a 75% decrease, from last year.

Net revenues, while higher than in the first quarter of 2013, were “uniformly lower” compared with last year, which reflects the very high net revenues in January 2014.

Demand Response

The Monitor also touched on the Supreme Court’s upcoming review of an appellate court ruling voiding the Federal Energy Regulatory Commission’s jurisdiction over pricing of demand response in energy markets (Electric Power Supply Association v. Federal Energy Regulatory Commission). The Monitor said the situation “does create an opportunity to rethink the ways in which demand-side resources can most effectively participate in wholesale power markets based on market principles.

“Demand response should be on the demand side of the capacity market rather than on the supply side.”

It went on to say, “Demand resources should be provided a fair opportunity to compete, but demand resources should no longer be provided special advantages inconsistent with competitive markets. This approach would work regardless of the final decision of the EPSA case.”

PJM Releases Annual Report

PJM on Monday also released its 2014 Annual Report. The theme “Anticipate, Adapt, Advance” will be the subject of discussion at the RTO’s annual meeting in Atlantic City this week.

May 18, 2015June 15, 2023

No ‘Death Spiral’ for Utilities – for Now

At the New England Energy Conference and Exposition last week, industry experts said there is no evidence that distributed generation is leading to a “death spiral” for traditional utilities.

“We know it’s an issue; with time it could unfold very differently. But for now it’s not really affecting utility credit ratings,” said Peter Rigby, global head of Standard & Poor’s risk analytics and research.

Anthony Marone, senior vice president of customer and business services at UIL Holdings, said that despite state incentives, rooftop solar’s penetration remains small and has not impacted UIL’s business model. But continued growth will create “equity” issues, he said.

“If you have many times the penetration today, you start to create potentially isolated problems on certain circuits or feeders or certain neighborhoods,” Marone said. “If in every neighborhood there were two systems, maybe it’s no problem. But if you all of the sudden have three, now you’ve got to upsize the transformer, or [if] you have to do other things, the question becomes who pays for that? Is it the consumer who installed the generation or is it society as a whole?”

May 18, 2015June 15, 2023

Questions and Answers on NERC’s Proposed GMD Rules

In May 2013, the Federal Energy Regulatory Commission issued Order 779 requiring the North American Electric Reliability Corp. to develop a standard to protect the grid against geomagnetic disturbances caused by solar storms. The commission said it was acting to close a “reliability gap.” (See FERC Orders Rules on Geomagnetic Disturbances.)

In June 2014, the commission approved the first stage of its response with a standard (EOP-010-1) requiring development of operating procedures to mitigate effects of GMDs. (See FERC OKs GMD, Training Standards; Proposes Modeling Rule Change.)

For stage two, FERC required NERC to determine the severity of a “benchmark” GMD event — the threshold against which covered entities would evaluate their system’s vulnerability and develop protective strategies.

What is the threat?

GMD events occur when the sun ejects charged particles that can cause changes in Earth’s magnetic fields. A solar particle can reach Earth in 17 to 96 hours.

NERC determines the severity of a GMD based on the “geoelectric field” — the electric potential measured in volts per kilometer on the earth’s surface — a reflection of the rate of change of the magnetic fields.

The geoelectric field acts as a voltage source that can cause geomagnetically induced currents (GICs) to flow on transmission lines. The magnitude of the geoelectric field is impacted by the geomagnetic latitude — the proximity to Earth’s magnetic north and south poles — and the ability of the planet’s crust to conduct electricity hundreds of kilometers down to its mantle. Local earth conductivity impacts the severity of the geoelectric fields that are formed during a GMD event; a lower earth conductivity results in higher geoelectric fields.

What is covered by the standard?

The standard would apply to planning coordinators, transmission planners, transmission owners and generation owners who own or whose planning coordinator or transmission planning area includes a transformer with a high side, wye-grounded winding connected at 200 kV or higher.

How is the benchmark event defined?

NERC proposed defining the benchmark GMD based on a one-in-100-year frequency of occurrence. Its definition is composed of four elements: (1) a reference peak geoelectric field amplitude of 8 V/km; (2) a scaling factor to account for local geomagnetic latitude; (3) a scaling factor to account for local earth conductivity; and (4) a reference geomagnetic field time series or wave shape to allow analysis of the impact on equipment.

The benchmark estimates that a one-in-100 year GMD event would cause an 8 V/km reference peak geoelectric field at Québec’s geomagnetic latitude and earth conductivity.

The 1989 solar storm that caused the collapse of the Hydro- Québec grid illustrates the potential risk. Shortly before 3 a.m. ET on March 13, 1989, a large impulse in the geomagnetic field was detected near the U.S.-Canada border. That started a series of disturbances that brought down the grid serving Montreal and the rest of Québec within about 90 seconds. The storm also caused large disturbances in the U.S., damaging some transformers severely — including one at the Salem nuclear plant in New Jersey — and nearly knocking out PJM and transmission systems from New England to the Midwest.

NERC’s standard drafting team “spatially averaged” four different station groups of data from Northern Europe, each covering a square area about 500 km wide (310 miles). The team noted that the reliability standard is designed to address wide-area effects caused by a severe GMD, such as increased volt-ampere reactive (var) absorption and voltage depressions.

“Without characterizing GMD on regional scales, statistical estimates could be weighted by local effects and suggest unduly pessimistic conditions when considering cascading failure and voltage collapse,” NERC said.

NERC used scaling factors to adjust the 8 V/km value for different geomagnetic latitudes and earth conductivities.

What is required by the proposed standard?

The proposed standard has seven requirements:

Planning coordinators and transmission planners must determine their responsibilities for maintaining models and performing studies needed to complete the GMD vulnerability assessment specified in Requirement 4.
Planning coordinators and transmission planners must maintain system models and GIC system models needed to complete the GMD vulnerability assessment.
Planning coordinators and transmission planners must have criteria for acceptable system steady state voltage limits for their systems during the benchmark GMD event.
Planning coordinators and transmission planners must conduct a GMD vulnerability assessment every 60 months based on the benchmark GMD event.
Planning coordinators and transmission planners must provide GIC flow information for use in the transformer thermal impact assessment (Requirement 6) to each transmission owner and generator owner that owns an affected transformer within the planning area.
Transmission owners and generator owners must conduct thermal impact assessments on affected transformers where the maximum effective GIC value provided in Requirement 5 is 75 amperes per phase (A/phase) or greater.
Planning coordinators and transmission planners must develop corrective action plans if the GMD vulnerability assessment concludes that the system does not meet the performance requirements.

— Rich Heidorn Jr.

May 18, 2015June 15, 2023

FERC Accepts Interregional Cost Allocation Plan for ISO-NE, NYISO, PJM

By William Opalka

The Federal Energy Regulatory Commission on Thursday conditionally accepted the interregional transmission planning and cost allocation proposals by ISO-NE, NYISO and PJM (ER13-1957 et al), completing the commission’s initial review of all of the interregional compliance filings required under Order 1000.

FERC found that the three regions complied with its requirement that neighboring transmission planning regions propose a common interregional cost allocation method by agreeing on the use of an avoided-cost method. As permitted by Order 1000, they proposed to apply their avoided-cost allocation to all selected interregional transmission facilities, rather than having separate interregional cost allocation methods for different types of interregional projects.

FERC said the filing conformed to its requirement that interregional cost allocation methods address regional reliability and economic needs as well as transmission needs driven by public policy requirements.

The commission previously ruled that an avoided-cost method was not permissible as the sole cost allocation method for regional transmission projects because it would “not allocate costs in a manner that is at least roughly commensurate with estimated benefits because it does not adequately assess the potential benefits provided by that transmission facility.”

However, it concluded that an avoided-cost only method is permissible for interregional transmission.

“We find that the interplay between the regional transmission planning and interregional coordination requirements of Order No. 1000 address, at the interregional level, the commission’s concerns regarding use of the avoided-cost only method at the regional level,” it wrote.

The commission rejected avoided-cost-only allocation for regional projects because a regional facility that resulted in a more cost-effective transmission solution than what was included in the roll-up of local transmission plans would not be eligible for regional cost allocation if there was no transmission facility in the local transmission plans that it would displace.

In contrast, the commission said it believed “there will be regional transmission facilities identified in the regional transmission planning process that are needed to meet transmission needs driven by reliability, economic and/or public policy requirements that potential interregional transmission facilities may displace.”

The filing updated the Northeastern Protocol, which the three regions adopted in 2004 to facilitate the exchange of information and establish a committee structure for the coordination of interregional planning. The Joint ISO/RTO Planning Committee, comprised of staff representatives from the regions, will be charged with evaluating interregional transmission solutions with input from the Interregional Planning Stakeholder Advisory Committee, which is open to stakeholders.

The commission required the regions to make only minor ministerial changes in compliance filings due in 60 days.

May 18, 2015June 15, 2023

ISO-NE VP Ethier: Market Rule Changes Will Slow

GROTON, Conn. — Robert Ethier has a dream: A day when ISO-NE no longer needs constant stakeholder meetings to tweak its market rules.

“We’ll know when we’ve hit on the right market design when we don’t need to make changes to accommodate the changes in the fundamentals,” Ethier, vice president of market operations for ISO-NE, said during a panel discussion at the New England Energy Conference and Exposition last week. “A good, stable, robust market design should adapt to pretty much whatever you can throw at it.”

Ethier said that although New England’s market has work to do to improve demand-side response and integrate the dispatch of wind, it has made progress over the last decade.

“The market is being driven much more by the fundamentals and by policy than by market design. … These markets are really being driven by the larger forces that are changing our economy — changes in fuel prices, changes in technology, changes in policy needs and desires. And that’s really what ought to be driving the markets. It shouldn’t be the market design that’s dominating the discussion.

“I hesitate to say this but I almost think we can see the day when the rate of change in the markets really decreases because the markets have the flexibility they need to react to whatever gets thrown at them,” he said.

May 18, 2015June 15, 2023

Electric Retailers Lament Obstacles

By Rich Heidorn Jr.

GROTON, Conn. — Electric retailers have made progress in moving away from the cutthroat price competition that shaved margins, but restrictions on billing and metering and “organizational inertia” continue to be challenges, a panel told the New England Energy Conference and Exposition last week.

Cullen Hay, general manager of Direct Energy’s residential operations in the Northeast and Midwest, said his company used acquisitions to grow in the past, as it joined other electric retailers in seeking price-conscious customers even as their costs went up. Power suppliers have fewer barriers to prevent customer attrition than cable TV suppliers, telecommunication companies or banks, he said.

“We all kind of lived under the same mantra that as one customer came in the front door, one customer would walk out the back door,” he said.

Over the last three years, however, electric retailers have begun to increase their customer engagement by offering additional services such as home warranties and rooftop solar, he said. “These are not gimmicks. These are the value-added things that the telecom industry found successful when they were handed a deregulated market,” he said.

“The new wave of the industry is knowledge …. Our mission statement is getting our consumers the information they need to make really intelligent decisions. And that goes with consumption-reduction tools like [the] Nest [thermostat] and online portals that allows them to see what their consumption looks like, what their community’s consumption patterns look like” to identify inefficient appliances and make informed decisions.

“That’s the retail, residential industry in the next five years. And it’s already happening.”

Progress, Challenges in Pursuit of C&I Customers

High capacity and transmission costs in regions such as PJM and New England are leading more commercial and industrial customers to welcome companies offering to improve efficiency in return for a share of the cost savings, said Dean Musser, CEO of Tangent Energy Solutions.

“The power customers [are] out there pushing and pushing for ways to innovate. And it’s up to us in this industry to capture that innovation,” he said.

Michael Volpe, who heads SunEdison’s distributed generation business in PJM, said electric retailers could be doing better among C&I customers if not for “organizational inertia.”

“In my experience most energy buyers have a lot of technical acumen but are hesitant to pursue things that they may perceive to be risky due to the long-term nature” of the payback, he said.

The choice, he said, is “getting into the offices of the CFO and sharing how the energy opportunity set has broadened [or] giving the power [to lower-ranking employees] to promote it up” the corporate chain.

Smart Grid Unfulfilled

Musser said the industry and its customers are not getting the full benefits of the billions invested in smart meters.

Philadelphia’s PECO Energy has smart meters for every C&I customer, he said. “But the data is not available until a day later. And if you want a pulse to get the data right away, [it costs] $1,800 and it’s going to take six months.

“That little pulse is two wires coming out of the meter that will enable this … customer to have real-time data every 15 minutes so they can see their consumption and take advantage of all the new products. … But if you’re looking at it a day late that doesn’t help at all.

“Some utilities are adopting methods where there’s free pulses now to get customer adoption. But across the U.S. it’s all over the board for what it costs and how long it takes to get a pulse out of a utility meter,” he said.

Itemized Bills

Hay said limits on itemized bills also are hurting efforts to educate customers about the value of options available to them.

“Customers may not read direct mail pieces and they may not read their email. But they will look at their bill,” he said. “We are limited to the number of line items we have and the amount of information a supplier like us [can provide]. A more engaged customer is going to be interested in the whole product catalog. We have to find a way to give them that information.”

Because of those limitations, Hay said, his company would like to be the ones sending the bills instead of the distribution utility.

“We are pushing for supplier-consolidated billing with any utility in the U.S. market that will allow us to do so. We are pushing it as part of the [New York] REV program.

“It’s going to have costs associated with it, but we’re prepared to bear those costs. I believe that the impact to churn and the impact to customer attrition that comes from us not having that direct relationship will far exceed whatever cost structure we have to take on.”

May 15, 2015

UPDATE: Md., Del. PSCs OK Exelon-Pepco Deal

By Michael Brooks and Suzanne Herel

The Delaware Public Service Commission on Tuesday unanimously approved Exelon’s $6.8 billion acquisition of Pepco Holdings Inc.

“There is a whole list of very positive things in this agreement,” Chairman Dallas Winslow told The News Journal.

The commission had delayed making its decision earlier this month when it learned that the Maryland Public Service Commission was going to make its decision soon (see below). Commission staff had argued that Maryland’s decision would be helpful, as their settlement with Exelon and Pepco contains a “most favored nation” clause, assuring that Delaware receives the same benefits as other states in the deal.

The commission has yet to make a formal order that reflects the balancing of benefits and did not say when it would do so. The approval leaves D.C. as the only holdout on a decision. The deal has been approved by the Federal Energy Regulatory Commission as well as regulators in New Jersey and in Virginia.

Maryland Approves with 3-2 Vote

The Maryland Public Service Commission voted 3-2 to approve the deal on May 15, saying Exelon’s reputation for service excellence was a deciding factor.

It conditioned the deal on higher reliability standards, $100 rate credits for residential customers and $43.2 million in energy efficiency programs in Montgomery and Prince George’s counties.

Voting in support were Chairman Kevin Hughes and Commissioners Kelly Speakes-Backman and Lawrence Brenner, who noted that Exelon ranked in the top-quartile of reliability metrics, while PHI has lagged.

“Simply put, the evidence demonstrates that Delmarva and Pepco will be better utilities because of the merger,” they said in the order released Friday, which included 46 conditions. “Exelon has demonstrated that it knows how to run electric and gas distribution companies; indeed it is nationally recognized for its standards of excellence.”

Voting against the deal were Commissioners Harold Williams and Anne Hoskins. “The merger will impose substantial competitive harm to Maryland’s electricity market by eliminating across-the fence competition, silencing PHI’s unique non-generation voice, and chilling innovation in new energy-related technologies and products,” they said in a 51-page dissent. Exelon still needs to win the approval of Delaware and D.C. to close the deal.

The approval revises certain provisions of a settlement Exelon had reached in March with Montgomery and Prince George’s, in which the corporation agreed to pay a one-time $50 rate credit to each residential customer of Pepco’s two utilities in the state, Delmarva Power & Light and Potomac Electric Power Co. (PEPCO). Exelon had also agreed to invest $57.6 million in energy efficiency. (See Exelon, Pepco Ink Deal with Md. Counties, but Critics Stand Firm.)

The commission also required Exelon to:

Develop 15 MW of solar generation by the end of 2018 — 5 MW in Montgomery County, 5 MW in Prince George’s County and 5 MW in the Delmarva service territory.
Establish a $14.4 million Green Sustainability Fund — $8.4 million for Montgomery and $6 million for Prince George’s — for the counties to fund solar, energy storage and other distributed generation projects.
Exceed Pepco’s level of charitable giving of $656,000 annually for at least 10 years.
Remain a part of PJM at least until the end of 2024.
Develop a pilot program for recreational and transportation use by residents of Pepco’s transmission right-of-ways.

Exelon and Pepco have until May 26 to accept the commission’s conditions. In a statement, Exelon CEO Chris Crane said the company was pleased with the decision and that the commission had recognized its reliability marks, but that the conditions in the order would be “challenging.”

“It poses some stringent conditions that will be difficult to fulfill, but all of us at Exelon accept the challenge and commit to proving ourselves in an expanded role in Maryland,” Crane said.

Critics Disappointed

Commissioners Williams and Hoskins dissented, echoing criticism that has been levied at Exelon throughout the proceeding.

“Maryland w Exelon ill lose its wires-only electric utilities, Pepco and Delmarva, which will be purchased by an energy conglomerate concerned with protecting its vast fleet of electric power plants, from which it derives most of its revenue,” they said. “Exelon’s economic interests to shield that fleet from emerging distributed energy technologies and other competitive threats are inherently misaligned with the interests of the customers of Pepco and Delmarva, who are predominantly concerned with efficient, cost-effective and reliable electric service.”

They also noted that the Green Sustainable Fund would not benefit Delmarva Power’s territory on the state’s Eastern Shore.

While Montgomery County Executive Ike Leggett had reached the county’s settlement with Exelon, the County Council unanimously passed a resolution saying the settlement didn’t go far enough to protect ratepayers and encourage renewable energy. Councilmember Roger Berliner, an energy attorney who spearheaded the resolution, said he was “deeply disappointed with the decision.”

“Exelon has a proven track record of favoring its own nuclear generation holdings over renewable technologies like solar and wind,” Berliner said. “This merger poses an unacceptable threat to both ratepayers and our environment.”

Berliner did acknowledge the beneficial conditions of the approval. He said that he has been “knocking on Pepco’s doors” to open up their rights-of-way, but the utility “stiff-armed us for years.”

The order includes a concession Berliner had sought — a Montgomery County “green bank” through which the county will use Exelon contributions to “leverage” investment in clean energy and energy-efficiency technologies.

But Berliner lamented the fact that these breakthroughs were achieved through the acquisition process, and by the level of Exelon’s commitment to renewable energy, which he said, “just didn’t go far enough.”

Environmentalists agreed.

“We are disappointed by today’s decision, which comes as a blow to the future of clean energy in Maryland,” said David Smedick of the Sierra Club. “The meager conditions added by the commission do not come close to mitigating the harms that the merger will cause to Marylanders.”

Maryland Attorney General Brian E. Frosh also blasted the order.

“Today is a bad day for consumers, and a great day for monopolies,” he said in a statement. “This merger — which the PSC approved by the slimmest of margins — would create a company controlling service to 80% of Maryland’s electric consumers, with the incentive and ability to stifle competition and suppress innovation. The harm to customers under this arrangement are obvious and substantial.”

PJM Independent Market Monitor Joe Bowring was disappointed by the ruling.

“They didn’t accept our conditions, so we didn’t think they did enough,” Bowring said. “What we would have liked was for Maryland to accept the conditions we proposed,” which the Monitor has proposed to all of the involved entities.

One to Go

Opposition to the Exelon-Pepco marriage continued to grow last week in D.C., where regulators may make a decision as soon as May 27, when the record closes.

Four D.C. Council members and more than half of the District’s 42 local advisory neighborhood commissioners — some of whom rallied on the steps of the Wilson Building Tuesday — are lobbying Mayor Muriel Bowser to take a stand against the transaction, though she doesn’t have an official role in the decision.

Councilman David Grosso submitted a May 12 letter to the D.C. PSC urging the board to reject the deal. The following day, People’s Counsel Sandra Mattavous-Frye filed a brief advising the PSC against the takeover.

“While this merger provides a wealth of benefits for Exelon and PHI’s shareholders, it exposes District of Columbia ratepayers to a number of unnecessary risks,” she said. “I am primarily concerned that Exelon has failed to commit to meeting established reliability standards, that any financial benefit to consumers will be erased with the first rate case and that the major decisions impacting the city’s electrical infrastructure will be made by executives in Chicago.

“As it regards the city, I am concerned that the success the District has achieved in the area of deploying renewables will be compromised by Exelon’s corporate philosophy that favors generation companies. Moreover, I have no confidence in Exelon’s ability to deliver on the promise of more jobs.”

A Year in the Making

The deal, announced last April as an all-cash transaction, has been more than a year in the making. If the deal is approved, it will create the Mid-Atlantic’s largest electric and gas utility.

Exelon is familiar with mergers. The company is the product of the 2000 pairing of Philadelphia’s PECO Energy and Chicago’s Commonwealth Edison. In 2012, it acquired Baltimore’s Constellation Energy.

It hasn’t always been successful in its deal making, however.

Exelon dropped a proposed merger with Public Service Enterprise Group in 2006, and had its overtures spurned by PPL in 1995 and NRG in 2009.

Exelon has said the deal will boost its customer count to almost 9.8 million from 7.8 million and increase its rate base to almost $26 billion from $19 billion.

Exelon hopes to close the deal by the end of the year.

May 15, 2015

Another Meeting Day, Another Drama at FERC

By Rich Heidorn Jr.

WASHINGTON — Despite changing its meeting date to avoid threats of mass demonstrations next week, the Federal Energy Regulatory Commission couldn’t avoid another protest drama Thursday.

FERC instituted a new policy that forced all non-employees — lawyers, lobbyists, reporters and protesters — through a lengthier and more rigorous-than-normal security screening that included photographs. After receiving a paper ID badge and going through a metal detector, the known protestors were directed left, while the others went right to the escalator to the second-floor Commission Meeting Room.

When the protestors were informed they would be quarantined in a commission hearing room where they could watch video of the meeting, they began chanting “Shut FERC down!” (See video.) While organizers claimed the protesters numbered three dozen, only about 15 appeared in a video the group shot after being ejected.

Suits, not T-shirts

Among them was Ted Glick, national campaign coordinator at the Chesapeake Climate Action Network, who wore a suit rather than the red T-shirt he and other protesters had worn in previous meetings. (See Protests Continue — on Camera — at FERC.)

About 20 minutes into the meeting, as the commission was discussing a ruling on an Order 1000 compliance filing, the protesters apparently exited the hearing room. The protesters’ chants were audible — if not discernible — in the meeting room until they were escorted out of the building.

FERC Chairman Norman Bay joked, “I hope the protesters haven’t moved from pipelines to Order 1000,” prompting laughter.

But at least three protesters slipped the dragnet and were able to make brief statements before being escorted out.

PennEast Pipeline

The first two, Patty Cronheim of Hopewell Township, N.J., and Angela Switzer of Delaware Township, N.J., stood up to protest the proposed PennEast Pipeline. The 36-inch pipeline would deliver about 1 billion cubic feet of gas per day from Luzerne County, Pa., to Transco’s pipeline interconnection in Mercer County, N.J., 108 miles away.

“You’re destroying lives, you’re abusing eminent domain,” Switzer said before being led out of the meeting. “This is corporate greed over public need.”

Switzer said afterward she is concerned the pipeline, which would cross her 60-acre farm, could result in contamination of her water wells. “I live in an arsenic-rich zone and there’s a chance when they drill through the bedrock they’re going to release arsenic into my wells,” she said. “… FERC is not listening to us.”

The backers of the project — AGL Resources; NJR Pipeline Company; PSEG Power; South Jersey Industries; Spectra Energy Partners; and UGI Energy Services — are hoping for FERC approval in 2016.

A third protester, Maggie Henry, of Bessemer in Western Pennsylvania, stood up as the meeting was adjourned, shouting “In the shale plays of Pennsylvania, you are killing people!”

In a press conference afterward, Bay turned serious, reading a statement in which he criticized the repeated meeting interruptions as “disrespectful” and ineffective.

“I respect the First Amendment rights of the protesters and I want to hear their views. But there are ways to do that and there are ways not to do that,” he said. “The way not to do it is to disrupt our proceedings. In my view the disruptions are disrespectful, they violate the law [and] they can pose public security concerns. They often violate the ex parte rule. They prevent us from doing our work and it’s a turnoff. It’s ineffective and unpersuasive as a matter of advocacy.”

Bay also noted that the commission does not regulate the production of natural gas. “If someone is upset with fracking, they should probably talk to the states. If I had any advice for the protesters it would be this: tell them to reconsider what they’re doing and I would urge them to stop disrupting our meetings.”

FERC acknowledged that it had rescheduled the meeting at the recommendation of Federal Protective Services, which wanted to avoid demonstrations planned for the week of May 21-29, including the scheduled May 21 session. Beyond Extreme Energy, the organization that has been coordinating the FERC protests, had said it is hoping to attract more than 500 demonstrators to FERC during the week.

In November, about 100 climate change protesters blockaded FERC headquarters, snarling traffic on First St. N.E. About 25 were arrested.