Page 1459 – RTO Insider

April 4, 2016

SPP Briefs: State of the Market, Study w/ AECI

The SPP Market Monitoring Unit’s State of the Market report for the winter months once again highlighted wind generation’s growing importance within the RTO’s footprint.

According to the report, which covered December 2015 through February 2016, wind generation accounted for 17.7% of SPP’s energy, a 43% increase from last winter. Wind generation accounted for 12.4% of energy production last winter and 10.2% during the winter of 2014.

As if to punctuate the point, SPP set a new wind peak during the evening hours of March 28, shortly after the market report was released. The RTO’s new wind peak of 10,809 MW at 9:22 p.m. CT broke the previous record of 10,783 MW, set March 21. Wind penetration reached 40.34% March 28, short of the 41.1% high set March 7.

Wind generation peaked in February, producing nearly 21% of SPP’s energy, according to the Monitor’s report. SPP has 12,397 MW of installed and available wind capacity in its footprint, with another 33,819 MW in various stages of development.

The increase in wind power came at the expense of coal generation, which saw the percentage of energy it produced fall to 46.3% for the month, down from 57% in February 2015.

The report said the increase in wind generation “comes [with] an increase in congestion.” Most congestion in the SPP footprint can be found in the “wind alley” of the Texas Panhandle, western Oklahoma and western Kansas.

The Monitor measures congestion by a constraint’s shadow price, “which reflects the intensity of congestion on the path represented by the flowgate.” It said the shadow price “indicates the marginal value of an additional megawatt of relief on a constraint in reducing the total production costs.”

Shadow prices reached almost $60/MWh on one flowgate and topped $40/MWh on at least two other flowgates.

The Monitor report also said gas costs continued to drop during the winter, with an average Panhandle Hub cost of $1.98/MMBtu, more than 30% lower than 2015 ($2.90/MMBtu) and nearly two-thirds lower than 2014 ($5.68/MMBtu).

The average real-time balancing market’s winter 2016 LMP was $17.82/MWh, down from $25.20/MWh in 2015. The day-ahead market’s average LMP was $18.33/MWh, down from $25.73/MWh last winter.

SPP, AECI Begin Biennial Joint-Study Process

SPP and Associated Electric Cooperative Inc. (AECI) began their biennial joint-study process with a call for stakeholder feedback and input on a proposed scope last week.

The SPP-AECI Interregional Stakeholder Advisory Committee (IPSAC) has identified several voltage and congestion issues in Missouri and Oklahoma, but the committee said April 1 it is giving stakeholders two to three weeks to comment on the scope. A separate meeting will be scheduled for the study scope’s formal endorsement.

The IPSAC will evaluate the SPP and AECI transmission systems and determine whether “mutually beneficial” joint projects exist. A joint planning committee comprising a representative from each staff will determine cost allocations on a case-by-case basis, with responsibility “assigned equitably” based on the constraint being resolved — and subject to approval of each region.

The two entities have been performing joint studies every other year since 2010, as outlined in their joint operating agreement. The 2014 study identified 463 potential needs along the SPP-AECI seam but resulted in no joint solutions.

Stakeholders asked staff whether this study might solve long-standing constraints in the Lake of the Ozarks region in central Missouri.

“We studied some alternatives in the last joint-study process related to a 345[-kV line] across this lakes area, but we did not see a lot of economic value or immediate reliability concerns a line across that area would solve,” said David Kelley, SPP’s director of interregional relations. “But constraints obviously move around, so we’re always willing to look at an alternative.”

James Vermillion, a senior planning engineer for AECI, said the association’s latest 10-year Long Range Transmission Plan has identified almost $40 million in improvements to maintain grid reliability. Still, that is down from the 2009-19 plan, which identified more than $221 million in projects.

AECI, based in Springfield, Mo., is owned by and provides wholesale power to six regional generation and transmission cooperatives.

SPP.org Wins Best Energy Website Award

SPP’s recently redesigned website has been honored as the Best Energy Website in the 2016 Internet Advertising Competition (IAC) Awards.

SPP.org was redesigned by Little Rock interactive agency Aristotle, which called the new site “a case study in responsive web design that combines great aesthetics and interactive technical features without sacrificing speed.”

The IAC Awards highlight the “best online advertising” in 96 industries and nine online formats, including video, newsletters, email and social media.

– Tom Kleckner

April 4, 2016

Company Briefs

Central Hudson Gas & Electric appointed Michael L. Mosher as CEO, effective April 1. He succeeds James P. Laurito, CEO since 2009, and who has been promoted to executive vice president of parent company Fortis. Laurito will remain on the Central Hudson board.

Central Hudson board Chair Margarita K. Dilley said Mosher has the experience, knowledge and vision to propel the utility to new heights of accomplishment in a rapidly changing industry.

“Mike’s substantial and diverse background in operations and regulatory affairs has prepared him to assume the leadership of Central Hudson at a critical time in its evolution,” Dilley said. “We are confident that he will continue the momentum that our company has achieved during Jim’s outstanding tenure.”

More: Central Hudson Gas & Electric

Wind Farm Developer Facing Bankruptcy

SunEdison, saddled with nearly $10 billion in long-term debt, is at risk of filing for bankruptcy protection, one of its affiliates said.

In a Securities and Exchange Commission filing last Tuesday, TerraForm Global said “liquidity difficulties” mean that “there is a substantial risk that SunEdison will soon seek bankruptcy protection.” The company is also reportedly being investigated by SEC for possibly overstating to investors how much cash it had on hand in November.

More: Portland Press Herald

Peabody, Arch Announce 465 Layoffs at 2 Wyo. Coal Mines

The two largest coal mines in the U.S., both in Wyoming, announced massive layoffs last week. Peabody Energy cut 235 people, or 15% of the workforce, March 31 at North Antelope Rochelle. Arch Coal said the same day it was cutting 15%, or 230 people, at its Black Thunder Mine.

Until now, Wyoming’s coal industry has largely avoided the massive cutbacks seen in Appalachian coal operations. The two mines, which produce about 100 million tons of coal a year, are generally regarded as among the most cost-effective mines in the country.

More: Billings Gazette

PacifiCorp to Close Coal Unit At Wyoming’s Kemmerer Plant

PacifiCorp has abandoned plans to convert a coal unit at its Naughton Plant in southwestern Wyoming to natural gas, saying it will now retire the unit at the end of 2017. The company said the move is a result of declining electricity demand and reflects the costs of installing environmental upgrades to meet federal haze requirements.

PacifiCorp’s initial plan had been to shutter Unit 3 for five months, starting at the end of 2017, and convert it to natural gas. The estimated cost of the conversion was $160 million. Natural gas had been a cheaper option for complying with regional haze requirements than upgrading the unit’s coal burning equipment under the Oregon-based utility’s initial calculations.

More: Casper Star-Tribune

AECC, Ouachita Dedicate 100-Acre Ark. Solar Farm

Aerojet Rocketdyne, Arkansas Electric Cooperative Corp. and Ouachita Electric Cooperative Corp. formally commissioned a 100-acre solar project in southern Arkansas last week. The 12-MW array located in an industrial park will supply power to Aerojet’s nearby facility.

The facility was completed in late 2015 and is capable of generating enough electricity to power the equivalent of 2,400 single-family homes. Excess solar energy will be sold in the wholesale power market.

More: Magnolia Reporter

DTE Proposes 10-Acre Solar Farm in Vacant Detroit Parcel

DTE Energy is proposing the development of a 10-acre solar array on a former playground in Detroit, which the utility said “could be one of the largest urban solar arrays in the U.S.”

The project, in Detroit’s Grandale neighborhood on the former O’Shea Park, would produce 2 MW, enough for 330 residential customers.

More: MLive

Consumers Energy: Cheapest Natural Gas in Almost 2 Decades

Consumers Energy has reported that its natural gas commodity price has fallen to its lowest level in 18 years.

Consumers’ natural gas commodity price for April is $2.54 per 1,000 cubic feet, which represents the most inexpensive rate since March 1998. Consumers estimates that the average residential customer paid $250 less this winter on natural gas bills.

“The price for natural gas that we’ll put into effect in April continues a decade of falling costs,” said Tim Sparks, the utility’s vice president of energy supply operations.

More: Consumers Energy

Solar Capacity Awarded to 4 Companies in Tenn. Project

The Tennessee Valley Authority, together with the Tennessee Valley Public Power Association, has awarded 16.7 MW of solar capacity to four local power companies for projects expected to generate enough electricity to supply more than 1,300 homes.

The projects were chosen from 11 proposals that are part of the Distributed Solar Solutions pilot project. TVA has more than 400 MW of solar power under contract.

More: Solar Industry Magazine

Duke Energy Asks to Upgrade Ohio River Hydro Station

Duke Energy is seeking permission to modernize its Markland Hydro Station on the Ohio River near Florence, Ind. The company wants to replace three hydroelectric turbines, generators and related equipment.

If the proposal is approved by the Indiana Utility Regulatory Commission, work on the hydro station could begin this summer and last until mid-2020.

“The generating units at Markland Hydro have served our customers well with clean, renewable energy since 1967,” said Melody Birmingham-Byrd, president of Duke Energy Indiana. “As we move toward increasingly cleaner energy, these modernized generation units will harness more of the renewable resources of the Ohio River for many years to come.”

More: Duke Energy

SandRidge Energy Flirting With Bankruptcy Decision

SandRidge Energy, an Oklahoma City oil and gas exploration company, has informed the Securities and Exchange Commission that it has talked with advisers about the possibility of filing for bankruptcy. Plunging natural gas prices and depressed energy demand have left a number of energy companies with onerous debt burdens.

The company laid off nearly 200 employees, including three executives, earlier this month. It has outstanding loans of nearly $600 million.

More: KOCO

Berkshire Power Pleads Guilty To Emissions Violations

Berkshire Power, the operator of a Western Massachusetts power plant, has agreed to plead guilty and pay $8.5 million for tampering with air pollution monitoring equipment and reporting false data about emissions levels.

Federal prosecutors say that employees at Berkshire Power in Agawam, Mass., manipulated the emissions monitoring system between January 2009 and March 2011 to conceal excess emissions. The actions were violations of the federal Clean Air Act.

The plant’s managers also violated the Federal Power Act for lying to ISO-NE about the plant’s availability to produce power, the first-ever criminal charges under that statute, according to the Justice Department.

More: The Boston Globe

April 4, 2016

MISO Proposes 3 New MTEP 17 Futures

By Amanda Durish Cook

MISO last week proposed the adoption of three new future scenarios intended to inform the development of the 2017 Transmission Expansion Plan (MTEP 17).

Jenell McKay, a MISO senior analyst, told participants at a March 30 workshop that stakeholders are seeking a “range of modeling futures and some form of carbon reduction modeling” to assist in the planning cycle.

The three retooled “futures” include:

An “existing fleet” narrative in which MISO’s generation fleet is largely unchanged because of low demand and no carbon regulations are modeled. Already-planned coal retirements are factored into the scenario, and remaining coal units retire only after reaching their 65-year age limits. MISO also assumes renewable tax credits will expire in 2022, existing nuclear units will stay online and low natural gas prices and a stagnant economy curb renewable growth. As a result, gross aggregate demand grows at just 0.3 to 0.4%, and the energy growth rate is similarly low at 0.4 to 0.5%.
A “policy regulation” future based on the final Clean Power Plan rule, with a 25% reduction of carbon emissions across MISO, which drives 16 GW of coal retirements and increased reliance on mid-range-priced natural gas. MISO also assumes that nuclear units remain online and non-nuclear, non-coal generators retire according to 55-year age limits. Aggregate demand grows at the current 0.8 to 0.9% rate, while energy growth hovers around 0.7 to 0.9%.
An “accelerated alternative technologies” future in which a “robust” economy propels expanded demand, leading to a 35% carbon reduction and steering MISO to 24 GW worth of coal retirements. This future assumes high natural gas prices, retirement of non-nuclear, non-coal generators at 55-year age limits, license renewals for nuclear units and continuation of renewable tax credits beyond 2022. Aggregate demand and energy consumption growth rates both surpass 1% under the scenario.

To address stakeholder concerns about price volatility, all future scenarios assume a 30% variance between high and low natural gas prices during the study period. McKay said assumptions about storage technologies were not included in any of the narratives but could be inserted during an “R&D phase” over the next few months.

In response to several questions about why MISO is not modeling a business-as-usual case for MTEP 17, McKay responded that industry uncertainties about carbon regulation, coal retirements and renewable penetration made a definite BAU scenario elusive. “We didn’t feel comfortable calling anything business-as-usual,” she said. “For instance, if the CPP is upheld [following court challenges], the policy regulation future will be the business-as-usual case.”

Matt Ellis, MISO manager of policy studies, said stakeholders can still weigh in on the futures. “Do they pass a smell test? Are they reflecting what’s already happening on your factory floors?” he asked.

MISO hopes to continue discussion about the futures at an April 20 Planning Advisory Committee before putting them to a vote at the May PAC meeting.

OMS Asked to Back Modeling Allowance Auction

Meanwhile, the Organization of MISO States could urge MISO to model a carbon emissions allowance auction after being approached by the Coalition of MISO Transmission Customers about the issue last week.

Coalition representative Robert Weishaar told a March 31 OMS meeting that he raised the issue with MISO staff, who he said were “reluctant” to model the net cost of CPP CO₂ allowances that are auctioned rather than allocated.

Weishaar said he was not advocating an auction over an allocation but wanted to see both hypotheticals in MISO’s CPP modeling. “We’ve taken a particularly critical interest in MISO CPP modeling to date,” he said.

Calling the omission a “gap in the MISO modeling approach,” Weishaar asked for OMS’ support in endorsing a future letter on the matter.

Libby Jacobs of the Iowa Utilities Board said she would support such a letter, but other OMS members expressed indifference.

Texas Public Utility Commissioner Ken Anderson said an auction may affect generator dispatches and the fuel mix, but those points were moot. “Because we’re in the ‘just say no’ camp to the CPP, we’re not particularly interested in MISO modeling,” Anderson said.

April 4, 2016

How Utility Conservatism is Hampering Tx Innovation

By Rich Heidorn Jr.

WASHINGTON — Risk-averse engineers and outdated utility ratemaking structures are preventing quicker deployment of innovative technologies that could avoid transmission line rebuilds and save money, speakers told the Infocast Transmission Summit last week.

The discussion came in a session on how technologies such as dynamic line ratings, phasor measurement units and HVDC can increase the capacity of existing rights of way.

McCall © RTO Insider (utility, transmission) — McCall © RTO Insider)

Jack McCall, vice president of sales for Lindsey Manufacturing, likened DLRs and PMUs to technologies that can increase vehicle speeds on a curvy highway: PMUs are like Ferraris, which can take curves at high speeds; DLR, he said, is like straightening the road.

Gregg Rotenberg, president of Smart Wires, quoted former Southern Co. CEO David Ratcliffe, who said there are three types of transmission organizations: ostriches, who choose to ignore change; deer, who are frozen in place by change; and lions, who will seek to capitalize on the change and “are going to eat a bunch of ostrich and deer.”

Ali Amirali, senior vice president of private equity fund Starwood Energy Group Global, offered a fourth type: cats, who are indifferent to change. He cited the Bonneville Power Administration, which he said views its mission as delivering hydropower to preferred customers and does not seek to maximize the capacity of the system because it’s not part of the agency’s “mandate.”

“And they curtail wind all the time,” interjected Hudson Gilmer, vice president of commercial markets for Genscape.

Gilmer © RTO Insider (utility, transmission) — Gilmer *© RTO Insider*

DLRs, which can measure conductor temperature, sag and line capacity, as well as detect icing and “galloping” — high-amplitude, low-frequency oscillation caused by wind — have been available for more than a decade, but early applications required scheduling an outage and deployment of bucket trucks and crews. “And once it was on a line, congestion is almost like whack-a-mole; it moves around on your network,” Gilmer said. “And then it’s very hard to get [operations and maintenance] dollars to move it to a new place.”

“If you look back over the last 10 to 20 years, there have been so many studies done both in North America and elsewhere in the world that show that dynamic line rating truly does expose easily 10% to 25% additional capacity on any transmission line almost on a regular basis,” added McCall. “It’s a very low-hanging fruit.”

Newer DLR technologies, such as those sold by Genscape and Lindsey, are easier to install but still face institutional inertia.

(utility, transmission) — Amirali *© RTO Insider*

“Why do we not have real-time monitoring? … It’s not the technology. It is the policies. It is the standards. It is the personnel and it’s the decision making,” Amirali said.

“The people who are running the grid — me included, [a] former operator — are about the most conservative people on Earth,” he continued. “We are trained to be conservative. Because [if] an engineer takes a risk and he’s successful, nobody really knows about it [because] the system operates the way it was supposed to. We take a risk and we fail: Chernobyl!”

The resistance to change also is a function of utilities’ organizational structures and revenue models, speakers said.

“Risk doesn’t stop us from doing deals,” Rotenberg said. “The bigger challenge is those transmission organizations who choose to look at all the risk in front of them in terms of how fast the world is changing, how fast generation and load are changing and say, ‘No I’m just going to keep building the lines and reconductoring every line possible because I think my ratepayers will keep paying it.”

“What a utility gets rewarded on is deploying capital,” agreed Amirali. “Why build one line when you can build two?”

Rotenberg said his company has proposed a $30 million deployment of its technology for a western utility as an alternative to a $175 million reconductoring.

“Every regulator who’s heard about this project is saying, ‘How can I make sure my utility does it?’

“Eight of 10 [utility] CEOs … do understand [the value of cheaper non-transmission alternatives]. Only six out of 10 vice presidents of transmission understand that,” Rotenberg said. The transmission vice presidents’ view, he said, is that congestion is “not my cost.”

transmission, utility — Jack McCall talks while Jeffrey Hein of Excel and Ali Amirali listen *© RTO Insider*

McCall said FERC should offer DLR compensation based on the difference in LMPs with and without constraints the devices relieve, similar to the way it designed the compensation scheme for demand response in Order 745.

Amirali said the commission also should reconsider its 2010 Western Grid Development ruling (EL10-19), which approved use of storage to defer a transmission upgrade but said such resources could not be used for any other purpose if they are receiving a rate of return. He said the ruling discouraged more widespread use of storage.

“You’re buying a Cadillac for one day a year,” he said. “It’s a wasted use of an extraordinarily dynamic asset.”

Bouchard © RTO Insider — Bouchard *© RTO Insider*

In a separate session, Philippe Bouchard, vice president of business development for Eos Energy Storage, praised Maine regulators for requiring utilities to evaluate untraditional transmission alternatives.

“It’s not a requirement that they go purchase energy storage or demand response or anything else. It’s just integrating that viewpoint into the methodology of looking at all available resources to meet their needs,” he said. “And there’s some really great opportunities, 15 or 20 miles of transmission lines that are stretching into the pockets of Maine that are ripe for [transmission and distribution] deferral.”

Jeffrey-Hein,-Xcel-Energy-web — Hein *© RTO Insider*

Jeffrey Hein, senior manager of regional transmission policy for Xcel Energy, said planning regions across the country have included non-transmission alternatives in their procedures. “This may now begin to introduce some competition, to …. pit technology against technology, old, new, what’s best to place where.”

Rotenberg said “one or two big wins” are all that’s required to change the mindset.

“Once we have one or two projects that everyone was certain were going to be a new line or rebuild and turn it into a non-wires alternative, everyone’s eyes will open up,” he said. “The hurdle [for building new lines or upgrades] is going to become much higher. The certainty … that that upgrade is required for a very long time is just going to keep going up and up.”

April 4, 2016

ERCOT Approaches 50% Wind Penetration Mark

ERCOT, wind — Roscoe Wind Farm at sunrise *Source: Wikipedia*

ERCOT continues to creep closer to the 50% mark for wind penetration, reaching 48.28% of load on March 23. The Texas grid operator said last week it generated 13,154 MW of wind energy at 1:10 a.m., when the overall load was 27,245 MW.

The ISO’s previous high for wind penetration was 45.14%, set on Feb. 18. Its wind peak remains 14,023 MW, also set Feb. 18.

ERCOT has 15,764 MW of installed wind capacity. Wind energy accounted for 18.4% of its system generation in 2015.

— Tom Kleckner

April 4, 2016

Federal Briefs

Technology giants Apple, Amazon, Google and Microsoft filed a joint friend of the court brief in support of EPA’s Clean Power Plan, hoping to strengthen the agency’s position against legal challengers.

The companies said that they believe that the CPP “reflects reasonable and attainable assumptions about the increasing availability of renewable generation in the nation’s power sector.”

The case is expected to be heard in the D.C. Circuit Court of Appeals in June.

More: 9to5Mac

Inspection Finds Broken Bolts At Entergy’s Indian Point Unit 2

More than a quarter of the bolts securing plates directing water around uranium fuel rods at Entergy’s Indian Point 2 nuclear reactor were found to be either broken, deformed or missing, according to a report released on March 29.

The March 7 inspection by Entergy found that 227 of the 832 bolts were either damaged or missing, a failure rate of 27.2%. The company and the Nuclear Regulatory Commission may order a similar inspection of Indian Point 3 to see if there is a similar bolt issue.

The missing fasteners are a concern because similar bolt damage was identified as the cause of a partial meltdown of the Fermi reactor in 1966.

More: The Huffington Post

FERC Delays Approval Of 2 Pa. Pipelines

FERC has delayed the timetable to review two proposed Marcellus Shale natural gas pipelines, pushing the potential approval dates into early 2017.

The Atlantic Sunrise project in Pennsylvania, a Williams Partners project, was seeking authorization from FERC by the end of April. The FERC schedule expects the review to be completed in January 2017. That pipeline is planned to run south from Susquehanna County to link up with an existing Transco pipeline in Lancaster County.

The PennEast Pipeline, a $1.2 billion 114-mile line that is to run from Northeastern Pennsylvania into New Jersey, sought approval from FERC by August of this year. But the FERC schedule shows the review won’t be completed until March 2017. PennEast is a UGI project.

More: Central Penn Business Journal

Bird Conservancy Group Targets 3 Wind Farms

The American Bird Conservancy says that three proposed wind projects near migration routes or important avian rookeries should not be built because they represent threats to endangered birds.

The conservancy said the turbines at two of the proposed wind farms, in North Dakota and in Kansas, are near migratory paths of the federally protected whooping crane. A proposed wind farm in northwest Missouri could threaten some of the migrating birds that use the Squaw Creek National Wildlife Refuge, including snow geese, bald eagles and trumpeter and tundra swans.

“There’s plenty of data to suggest that plenty of birds are being struck by the blades on these turbines,” a conservancy spokesman said. “Hundreds of thousands at a minimum.” The conservancy said wind farms in such areas should probably be prohibited.

More: Midwest Energy News

41 Companies Volunteer To Cut Methane Emissions

EPA and 41 energy companies announced a partnership to voluntarily reduce methane emissions from natural gas operations at the Global Methane Forum in D.C. last week.

Called the Natural Gas STAR Methane Challenge Program, the partnership is aimed at curbing methane emissions at wellheads and at various points along transportation systems.

The partners include Southern California Gas, whose gas storage well in California leaked thousands of tons of methane earlier this year. Other companies include Exelon, Duke Energy, TransCanada and Xcel Energy.

More: The Associated Press

Federal Weather Researchers See Record Ice Retreat in Arctic

NASA and the National Snow and Ice Data Center say the maximum ice buildup in the Arctic is coming in low this year. Ice growth for February was 1.16 million kilometers below average. And March’s reading, at 14.52 million square kilometers, was the lowest maximum extent on record.

This is the second straight winter that showed below-average maximum ice extents.

“Records attract attention, but the critical thing is, what’s the trend,” a member of the National Academy of Sciences’ Polar Research Board. “This is just part of the overall trend of unraveling in the Arctic.”

More: The Washington Post

DOE Wants to Move 7 Tons Of Plutonium Cross Country

The Department of Energy is considering shipping nearly 7 tons of weapons-grade plutonium from the department’s Savannah River Site in South Carolina to the Waste Isolation Pilot Plant in Las Cruces, N.M.

The plan is going forward despite the fact that the New Mexico plant has been closed since February 2014 due to a fire and unrelated radiation release there. The plutonium was to be de-weaponized at the South Carolina site, but now the department plans to dilute it to a level where it can be shipped. The New Mexico facility is more than 2,000 feet below ground.

“The importance of keeping nuclear materials out of the hands of terrorists is clearer today than ever and is essential to protecting our nation and allies,” said the National Nuclear Security Administration.

More: Albuquerque Journal

FERC Staff: Reject Coaltrain ‘Rhetoric’

FERC staff told the commission Friday that a Pennsylvania-based power trading company’s response failed to dent their case that the company made riskless up-to-congestion transactions to collect line-loss payments. Staff asked the commission to uphold its findings and order the company to pay $42 million in penalties and unjust profits.

“Despite the rhetoric deployed throughout their lengthy submissions, the respondents do not credibly rebut the factual and legal conclusions in the staff report,” staff said in its response to Coaltrain Energy’s March 4 filing (IN16-4). The company’s answers to FERC’s Order to Show Cause contended it didn’t manipulate the market, that its trading strategy wasn’t deceptive and that it didn’t engage in wash trades or try to affect market prices.

As part of its response, staff included screenshots of one Coaltrain trader’s computer showing that he entered 137,800 MWh of “Over-Collected Losses” trades just three minutes after starting work on one day — evidence, staff said, that the trades were not based on “any meaningful research” but were intended to profit on the losses alone. Staff said Coaltrain also made misleading statements to PJM’s Independent Market Monitor in July and August 2010 in which it “falsely promised to stop making trades aimed at [collecting line-loss payments] after the IMM warned that trading to do so was illegitimate.”

More: Traders Deny FERC Charges; Seek Independent Review

April 4, 2016

FERC Orders MISO to Charge Uniform Interconnection Fees

By Amanda Durish Cook

MISO must charge equal fees to all generators entering its interconnection queue regardless of whether they are internal, external, new or existing resources, FERC ruled last week (EL15-99).

The commission also directed MISO to revise its Tariff to spell out procedures related to external resources entering the queue, a process currently described only in the RTO’s Business Practice Manuals. FERC agreed with a group of MISO generators who contended that the absence of an explicit Tariff provision created a lack of transparency around the nature of RTO service agreements with external resources.

“The commission requires that matters that significantly affect rates and services, are readily susceptible of specification and are not so generally understood be in the Tariff rather than Business Practice Manuals,” the order stated.

FERC considered the issue significant enough to open a separate Section 206 proceeding (EL16-12) to review MISO’s Tariff and require revisions outlining specific procedures and milestone payments for all interconnection customers.

The ruling stems from a complaint by a group of internal MISO generators who contested the RTO’s practice of exempting external generating resources from paying a significant fee levied on any new internal resources seeking to enter the final stage of the interconnection process.

At the outset of the definitive planning phase (DPP), any new MISO interconnection customers within the footprint must make an M2 milestone payment to fund system impact and interconnection facilities studies, as well as a later network upgrade facilities study, before preparing a construction schedule and cost analysis. Existing internal generators are exempted from the payments. MISO also waives the fee for both new and existing generators outside its footprint under the assumption that those resources have already established interconnection agreements within their own balancing areas.

The complainants contended that the differing payment requirements represent a competitive disadvantage for them because external generators face a “significantly lower entry fee than generation internal to MISO.” The generators further argued that the lack of monetary collateral tied to the DPP phase could lead external resources to submit speculative project requests or nonchalantly withdraw projects, forcing MISO to revise its study assumptions and thereby delay other projects in the queue. They asked FERC to consider two options: Either force MISO to require all new interconnection customers to pay the milestone payments or eliminate the payments altogether in the interest of fairness.

In its answer to the complaint, MISO said the request to treat existing external generation identically to new internal generation was unjust and unreasonable. The RTO pointed to the milestone payment exemption for existing generation, also noting that the payments are refundable upon finalizing a generator interconnection agreement. The RTO said it would resolve the payment dispute by charging “some form” of initial payment to external customers wanting to enter the queue.

In its ruling, FERC went a step beyond the complainants’ original request by requiring all interconnection customers — including existing internal generators — to post milestone payments.

“All interconnection customers, whether they are new or existing, or internal or external, are seeking interconnection service and will be entering the DPP,” the commission said. “The Tariff provisions should ensure that all interconnection customers, internal and external, and new and existing, are treated comparably.”

FERC gave MISO 60 days to update its Tariff with the changes related to the interconnection process. The changes must include a pro forma service agreement and initial payment details for external resources. A final order on the matter is expected by Nov. 30.

April 4, 2016

GridLiance Closes Deal for Tri-County Co-Op’s Tx Assets

By Tom Kleckner

Competitive transmission company GridLiance announced Monday it had closed its acquisition of about 410 miles of 69- and 115-kV transmission lines and related substation infrastructure from Tri-County Electric Cooperative (TCEC) in the Oklahoma Panhandle.

GridLiance CEO Ed Rahill called the transmission acquisition — GridLiance’s first —”an important milestone” for its business model to partner with cooperatives and other public power agencies.

GridLiance, which was formed in 2014, acquired Tri-County’s transmission assets and assumed full operational responsibility through its South Central MCN subsidiary, effective April 1. Under the transaction’s terms, GridLiance will represent the co-op and its members’ interest “in planning and development of new transmission projects within” SPP, the company said.

The company announced the deal in September. (See GridLiance Makes First Acquisitions.)

Rahill said his company would assume operations and maintenance responsibility for Tri-County’s assets, with the latter’s “boots on the ground” employees providing some O&M services.

“Over the long term, we can provide TCEC with a clear path to invest in SPP transmission projects that will reduce network congestion, increase service reliability and lower service costs,” Rahill said.

Tri-County CEO Jack Perkins said the move will allow the co-op to focus on its distribution system, with GridLiance upgrading the transmission assets. “Equally as important, we look forward to jointly investing with them in transmission projects that were previously inaccessible to us,” he said in a statement.

Headquartered in Hooker, Okla., the cooperative serves about 23,000 meters in the Oklahoma Panhandle, southwestern Kansas, the northern border of the Texas Panhandle and parts of Colorado and New Mexico.

GridLiance says its planning and development models are focused on providing more reliable transmission to public power customers, “hedging rising costs for regionally planned projects.” In addition to jointly planning, developing, owning and operating new transmission assets, GridLiance says it will work with entities such as Tri-County to identify “existing transmission infrastructure that can be more efficiently and cost-effectively upgraded and integrated into their RTO.”

GridLiance also announced Monday additions to its operations and compliance teams with the appointments of several regional-industry veterans to leadership positions: Kevin Hopper (late of Associated Electric Cooperative Inc.), president of the SPP Region; Neal Chapman (LS Power), vice president of engineering; and Jim Useldinger (Kansas City Power & Light), vice president of operations.

All three will be based in GridLiance’s Kansas City office and directly oversee the newly acquired TCEC transmission assets’ engineering and operations functions. The company said they will work with COO Noman Williams and Trent Carlson, regulatory and compliance vice president, to “build out its platform into other regions.”

GridLiance has also added several former SPP employees in recent months, including Brett Hooton, the RTO’s senior interregional coordinator, and Jody Holland, its manager of steady-state planning.

GridLiance is backed by Blackstone Energy Partners, an affiliate of New York private equity giant Blackstone Group.

April 4, 2016January 27, 2024

Overheard at the Transmission Summit

WASHINGTON — More than 100 transmission developers, consultants, RTO officials and utility executives attended Infocast’s 19th Annual Transmission Summit. Here’s some of what we heard.

Competitive Transmission

Curt Bjurlin, an environmental services manager for Stantec, asked whether there are too many transmission developers chasing too few competitive opportunities under FERC Order 1000.

“I’m reminded of a story of a guy who comes to town and wants to play in a poker game and someone says ‘Why do you want to play in that game? Don’t you know it’s rigged?’ He says, ‘Yeah, but it’s the only game in town.’”

Bjurlin said he expects developers to employ more rigorous go/no-go decisions on bidding in the future.

Southern Co. is one utility that’s not entering the game. “We’ve looked at that business continually and feel that there’s enough players in that market and not a lot of projects to go after,” said Bruce Edelston, vice president of energy policy. “So we decided to stick to our knitting in our own service area.”

Lack of Interregional Transmission Projects

Edelston said the planning process isn’t the reason for the lack of interregional transmission projects.

“It’s whether there’s somebody who is benefiting from that line who’s willing to pay for it. … There are very few interregional lines that are going to be economic when you look at the alternatives available to the purchasing region — the region that would be receiving the renewable energy. They often have local alternatives or closer alternatives that don’t require transmission fixes, and these long distance interregional lines can be very, very expensive — and as we’re seeing with the Clean Line Energy Partners lines up in Illinois — very, very difficult to build.”

“In our case, with the price of solar having come down so far, it turns out to be much more economic to build utility-scale solar within our service area than it is to build long-distance transmission to access wind in the Midwest. And I think that’s true for a lot of East Coast load centers. You also have the opportunity these days to buy RECs — or renewable energy certificates — to meet any renewable portfolio standards that you have.”

Jared E. Alholinna, regional transmission planning strategist for Great River Energy, recalled MISO’s joint study with PJM, which identified up to 75 different “quick hit” transmission projects along their seam. (See MISO, SPP Considering Second Joint Tx Study.)

“Not one of them showed economic benefits. Many stakeholders thought this was a failure — you know, they’re saying ‘0 for 75.’”

The real reasons for not finding a viable project, he said, included the success of MISO’s multi-value projects in reducing congestion and low natural gas prices that make it cheap to redispatch around congestion.

“There have been projects on the border that are on the cusp of meeting criteria, but when you have two different RTOs, you have two different needs and you have two different approval processes. And trying to get all those stars aligned we’re finding is very, very difficult.”

Xcel Seeking Larger Dispatch Areas in the West

Gerald R. Deaver, manager of regional transmission policy for Xcel Energy, said although his company’s operators have developed expertise in making their systems more flexible, the increasing penetration of renewables is creating operational challenges.

“Xcel has been pushing the development of regional markets in the West because we think geographic diversity is the best way to deal with some of this imbalance between regions or areas with renewables. And it seems to be getting more traction in the West.”

“We’re trying to develop along the Front Range [in central Colorado and southeastern Wyoming], a common dispatch area with a number of entities, both [FERC] jurisdictional and non-jurisdictional, to try and widen that footprint. … I doubt you could go Western Interconnection-wide with, for example, an RTO, but we’re really pushing for bigger geographic areas for dispatch. That’s going to require probably some additional transmission interconnections.”

Xcel has reduced its carbon emissions by 20% since it began adding renewables in 2005, and its Colorado Public Service unit now gets 60% of its energy from wind during some hours of the day, Deaver said. “We’ve been able to line up long-term purchases of wind at steadily decreasing prices.”

Distributed Energy Resources

Eric Ackerman, director of alternative regulation for the Edison Electric Institute, said the planning for distributed energy resources will require granular data regarding both customer energy use and system status that few utilities currently capture, even though some 65 million interval meters have been deployed.

“But even if we have the data, the next issue is … do we want to give the data to the market? Because in California and in New York the preference is to have market-based third-party suppliers deliver the distributed energy. So the market is endlessly hungry for this data. They’d like it in real time. They’d like it constantly updated. And utilities — my members — are pushing back. They think their distribution franchise requires them to plan the system. And if they give too much of the data to the market, guess what? The market’s going to run away with that and they will lose control of their plan.”

Stuart Nachmias, vice president of energy policy and regulatory affairs for Consolidated Edison, said, however, there is a win-win opportunity for utilities and new entrants. “The [cost of] solar technology is coming down. But if you talk to the solar companies, their biggest cost is customer acquisition. And to the extent that utilities together with solar companies or battery providers ultimately can help reduce that acquisition cost and share in those savings there’s tremendous value.”

Nachmias also gave an update on his company’s plan to use distributed generation and demand-side management to address overloads in Brooklyn and Queens and delay the need for a $1 billion substation upgrade for a decade. (See NYPSC OKs Con Ed’s Demand Management Program to Relieve NYC Overloads.) “Stitching together the solution [is] really complex — much more than we thought,” he said. “And getting customer engagement is very difficult.”

Market for Grid-Scale Storage

Philippe Bouchard, vice president of business development for Eos Energy Storage, said that frequency regulation has been good for energy storage — responsible for about 80% of the 200 MW deployed last year.

“However the challenge with that market and application is … it’s a pretty shallow market. If you compare the amount of money that flows through FR in PJM relative to the energy market or the capacity market, it’s tiny. And the more assets that get built to provide that service are essentially cannibalizing the revenue streams that they can monetize.

“To me the real drivers of the market are going to be projects more like [Southern California Edison’s request for four hours of locational capacity] — large-scale longer duration projects that are providing services under long-term contracts with creditworthy off-takers. These are projects that are easily financed, that are providing a reliability service to the grid and which offer flexibility too.”

Alex Ma, senior manager of regulatory affairs for Invenergy, said grid operators will need to change their interconnection process in order to realize the potential storage has for supplementing variable energy resources.

“From an interconnection standpoint, it seems very difficult to get past the fact that you have two different technologies at the same [point of interconnection],” he said, recommending changes to “fast-track some of the resources — not necessarily based on size as they are today with small and large generation — but on technology.”

Brad Jones, CEO of NYISO, said storage is central to New York’s effort to create a more resilient grid following Superstorm Sandy. “The best technology for meeting resiliency at the distributed grid is having storage located there — having storage located at all the major substations to serve that load if they get disconnected.”

But, citing a Brattle Group study, he said only 40% of storage’s value is in resiliency. “The remainder of the value of storage comes from operating in the market. Recognizing that they can store energy at nighttime when it may be zero or negatively priced and can release the energy in the day when it’s positive. I’d like to see a way if we can figure out a way to capture those other benefits as well — perhaps allow the utility companies to auction off the energy value that exists in the wholesale market and then let others take that to market.”

John Jung, CEO of Greensmith Energy Management Systems, said the number of companies seeking a share of the energy storage industry will decline in the future. “There’s going to be a lot of consolidation in this space. It’s very natural. I’ve seen it in a lot of other spaces where there’s a lot of [venture capital] money. There was some $270 million in VC money that poured into this industry.”

Clean Power Plan

Gil Rodgers, senior managing director for natural gas markets at Energyzt, said he thinks the Clean Power Plan will likely survive legal challenges. “So it would be a mistake, it would really be foolish, not to consider the fact that this is something that’s coming down the road.”

Missouri Public Service Commissioner Scott Rupp said RTOs “can use [the CPP] to start making cases to build more transmission. Most of the people that make up them that have a lot of weight are the transmission companies.”

“I think it’s uncontestable” that the Clean Power Plan will be “a big driver for transmission,” agreed Larry Eisenstat of law firm Crowell & Moring.

Michael Ferguson, director at Standard & Poor’s, said states should not wait to respond to the rule. “We all know that when it comes to building a generator profile, building the transmission lines tends to be the long pole in the tent. … So if you’re a state that’s relying really heavily on new transmission build, it’s something that you probably don’t want to put off for too long.”

Kerry Worthington, a program officer for the National Association of Regulatory Utility Commissioners, also had advice. “My message to you today is to not depend on your assumptions and leave your options open,” she said. “It’s very difficult to predict with accuracy what the Clean Power Plan will look like after the stay.”

David Treichler, director of modeling and analytics at Oncor, predicted it would not be long before overnight load in Texas was served entirely by wind energy. “Things are going in this direction. CPP is not going to be the major driver for a clean Texas. Economics will be. … Government is not always the provocateur of our pain.”

Despite the CPP and competition from wind and cheap gas, some coal generation will be around for decades, said Todd Williams, a partner with ScottMadden. He noted that the average lifespan of a coal plant is 55 years and the newest one was built a year ago. “We’re going to have coal in the portfolio through at least 2070, if not beyond. … Coal’s not going away completely. Reminds me of the Monty Python skit ‘Not Dead Yet.’”

Improving Gas Infrastructure

“I would like to see going forward, in the next five years, coordinated planning discussions between the gas industry and the RTOs,” said John Lawhorn, MISO’s senior director of policy and economic studies.

“We have found that if you have a good fuel assurance program, like New England ISO has for several years, you don’t have electric reliability problems,” said Henry Chao, NYISO vice president of system resource planning.

“Ensuring that gas gets to the generators is definitely not currently in the job description of the ISOs or RTOs, as it’s currently written,” said Tanya Bodell, executive director at Energyzt. “Ensuring … reliability is; creating market-based incentives … to maintain that reliability most certainly is available.”

— Rich Heidorn Jr. and Michael Brooks

April 4, 2016

PJM Markets and Reliability and Members Committees Briefs

WILMINGTON, Del. — Mike Kormos, the departing chair of the Markets and Reliability Committee, couldn’t attend his last meeting because of a scheduling conflict, said CEO Andy Ott, who lauded his colleague for his nearly three decades of work at PJM.

Mike Kormos, PJM — Kormos *© RTO Insider*

“As he and I grew through the ranks of PJM, I saw him as a partner, and I think you all saw him as a person you could talk to on any subject and collaborate with,” he said. “I’m going to miss him. PJM is going to miss him. He has been with us for 28 years, and there’s just no replacing that kind of experience.”

Ott has said the position will not be filled.

Kormos, executive vice president and chief operations officer, announced his resignation last month. His last day with PJM is April 15. (See PJM COO Kormos Leaving; Post Won’t be Filled.) He has not indicated his future plans.

CFO Suzanne Daugherty, the new chair, presided over her first committee meeting. Members passed around Kormos’ place card, on which they penned parting sentiments.

Members OK Operating Parameters but Urge Refinements

The MRC unanimously approved changes to Manual 11: Energy and Ancillary Services Market Operations; Manual 15: Cost Development Guidelines; and Manual 28: Operating Agreement Accounting. The revisions define operating parameters. (See “Operating Parameter Definitions Approved,” PJM Market Implementation Committee Briefs.)

The changes to Manual 15, regarding start-up and no-load costs, also were endorsed unanimously by the Members Committee.

An alternate proposal put forward by Bob O’Connell of Main Line Electricity Market Consultants was not taken up for a vote because the initial motion passed. Combined cycle units traditionally have been disadvantaged by these definitions, he said. Minimum run time begins when the first gas turbine is synchronized, he said, leaving open the possibility that PJM could release a unit before the steam turbine is synchronized. O’Connell’s definitions included a calculation that would let PJM know when the steam turbine had been synched.

While the parameters would not invoke a nonperformance charge under the new Capacity Performance construct, they could affect make-whole payments, PJM’s Adam Keech said.

While O’Connell’s definitions were not considered, a number of members and the Independent Market Monitor agreed that the issue he raised should be addressed.

PJM’s Adrien Ford, who chairs the Market Implementation Committee, pointed out that the problem statement leading to the operating parameter definitions had been amended in his committee, allowing for ongoing conversations about them.

Keech said that even if the alternate definitions were approved, PJM programmers wouldn’t be able to implement them by June 1, when the new delivery year begins under CP rules.

“We have a bunch of significant compliance obligations coming down the pike that we are trying to work through as soon as we can,” he said. “While I understand the value of these changes, they don’t fall into compliance changes. I’m not certain what date we could hit with these.”

If the way the parameters are used is changed, especially for combined cycle units, it would require changes to the software and how PJM clears the day-ahead markets, he said.

Ed Tatum of American Municipal Power encouraged PJM to continue studying the issue.

“The stakes are huge,” he said. “AMP is very concerned about how these parameters are going to be implemented. They could have draconian impacts on a supplier. It is important from our standpoint to get it right — and if we can’t get it right, to think about transitioning things so we’re not unduly burdening or penalizing people. This is a grave concern.”

MRC, MC Endorse Interim Ramp Rate for Performance Assessment Hours

MRC members approved a temporary performance assessment hour ramp rate with a 77% sector-weighted vote. The interim solution also was approved by the MC, over 11 objections.

The vote calls for revisions to Tariff and Manual 18: PJM Capacity Market. (See “PAH Ramp Rate for CP Approved,” PJM Operating Committee Briefs.)

Market Monitor Joe Bowring voiced his opposition. “This significantly weakens the incentives of Capacity Performance,” he said. “We regard this as a direct contravention of FERC’s no-excuses policy. It’s not a good idea.”

Assistant General Counsel Jen Tribulski said that PJM’s filing with FERC will explicitly note that the ramp rate is an interim measure to “get us through the coming months.”

“We fully intend to continue the discussion,” which will include the issue of using original equipment manufacturing specifications, she said.

MC Votes to Flex Meeting Start Time Following MRC

Following a lively debate, the Members Committee voted to flex the start time of its meetings going forward. The change will ensure that lunch is preserved, which members said is valuable for networking.

The issue had been raised at the last meeting by John Horstmann of Dayton Power & Light, who asked if there was a way to streamline the work of the MRC and MC, which are held on the same day.

On Thursday, he suggested allowing the MRC — which usually has a meatier agenda than the MC — to run as long as necessary in order not to truncate debate and have the MC start 15 minutes to a half hour after it ends. If necessary, members will break for lunch during the MRC meeting.

Ten members objected.

Scheduling Changes Approved

The MRC unanimously approved revisions to transmission and energy scheduling practices to reflect PJM’s adjustment to its day-ahead energy market timeline. The changes include adding a five-minute “shotgun window” for the spot-in product. (See “Day-ahead Submission Deadline Moved up,” PJM Market Implementation Committee Briefs.)

MRC, MC Approve Updated Definitions, Clarifications to Governing Documents

The MRC approved updated definitions and clarifications to PJM’s governing documents. They involve the terms PJM board, market participant, credit breach, PJM region, regional entity, affiliate, PJM markets, economic minimum and transmission customer.

The MC also endorsed changes to governing documents as well as additional clarifications to previously endorsed revisions.

In addition, that committee approved Tariff and Operating Agreement revisions regarding the definition of the term counterparty. In an Aug. 27 vote, the word was removed from a batch of proposed definitions and returned to the Governing Documents Enhancements and Clarifications Subcommittee for further review at member request. The definition was aligned to use more precise language in the OA that specifies when PJMSettlement will and will not be a counterparty to a transaction or agreement.

Changes to Confidentiality Rule Allow Release of Certain Information

With two objections and one abstention, the MRC approved changes to Manual 33: Administrative Services for PJM Interconnection Agreement that allow PJM to release market data under six circumstances. (See “Market Data Confidentiality Rule Change Gets First Reading,” Market Implementation Committee Briefs.)

They address individual generation outages, the availability of demand response, cleared and offered capacity resources, information regarding uplift payments, results of the three pivotal supplier test and member data that has been made public by that member or a regulatory agency.

MRC Approves Manual Changes

The following manual changes were endorsed at Thursday’s meeting. Three of the votes were unanimous. There was one abstention on the changes to Manual 11 regarding Capacity Performance.

Manual 1: Control Center and Data Exchange Requirements. Adds new section for planning, coordination and notification of system changes and events; includes new content with updated procedures. New Attachment C is the new Inter-Control Center Communication Protocol (ICCP) failover test plans diagram. Revisions remove references to the PJM ICCP network interface control document and PJM ICCP communications workbook.

PJM’s Ryan Nice said that some companies had been found to be taking outages of a few minutes on their emergency management systems and not alerting PJM. “The implications of that are quite serious,” he said.

Manual 6: Financial Transmission Rights. Housekeeping changes resulting from annual review. Clarifications better describe existing rules and processes.
Manual 11: Energy and Ancillary Services. Changes accommodate the implementation of Capacity Performance regarding unit-specific parameters. For non-Capacity Performance resources, the status quo remains until 2018. From that delivery year on, unit-specific parameters for base capacity resources will apply during hot weather alerts, emergency actions during hot weather operations and when being offer-capped to maintain system reliability. For CP resources, beginning in delivery year 2016, unit-specific parameters will apply during hot weather alerts, cold weather alerts, emergency actions and when being offer-capped to maintain system reliability.
Manual 11: Energy and Ancillary Services Market Operations. Revisions reflect day-ahead market timeline changes. Among them: the deadline for submitting day-ahead bids will be 10:30 a.m. The day-ahead clearing window will be reduced to three hours. The deadline for posting day-ahead results will be 1:30 p.m. or as soon as practicable. Results will be posted upon approval but not before noon.

– Suzanne Herel