Page 1452 – RTO Insider

April 11, 2016

PJM Planning Committee and TEAC Briefs

VALLEY FORGE, Pa. — Interconnection customers would be required to provide more documentation earlier to ensure consideration of their projects under proposed changes to the queue submittal process.

The recommendations came out of the Earlier Queue Submittal Task Force, which was convened after current rules — which charge nonrefundable fees that escalate later in the queue window — were found to be ineffective in incenting earlier applications. (See “Still Searching for Ways to Incent Early Project Submissions,” PJM Planning Committee Briefs.)

Early on, the task force decided that it would have little luck trying to change human behavior and instead focused on the objective of being able to start building models for the projects, PJM’s Dave Egan said.

The thinking led to a number of proposed changes.

Currently, queue priority is assigned based on the date the application and deposit are submitted, and supporting documentation is not required. Under the new rules, priority would not be secured until all required elements of a project, including site control, were submitted.

PJM would perform a deficiency review only after all the elements, aside from site control, were in hand.

Applications would have to clear their deficiencies by the close of the queue window or be terminated. PJM would codify in the Tariff that it has five business days to review a deficiency response.

Project deposits would become chargeable immediately upon application, and instead of socializing the cost of applications that fail to clear their deficiencies, PJM would charge the customer.

Instead of having a different fee structure for large generation and small generation, the nonrefundable amount would be 10% of the overall fee for all projects, and the refundable portion would be spent by PJM first.

PJM also proposes to move the opening of queue windows to April from May and to October from November as soon as this fall. That will improve the opportunity of generation to participate in the May Base Residual Auction, Egan said.

The Planning Committee will be asked to vote on the changes in May.

Reference Model for CPP Study Introduced

PJM introduced the reference model it will use to study the economic and reliability implications of the Clean Power Plan.

The initial review will look at the next 20 years and provide potential scenarios driven by policy, regulation and the market. (See PJM to Proceed on CPP Study Despite Supreme Court Ruling.)

The study was requested by the Organization of PJM States.

PJM PC & TEAC — PJM’s energy and capacity prices and its generation mix would be affected by differing Clean Power Plan scenarios.

At Thursday’s Transmission Expansion Advisory Committee meeting (TEAC), PJM also presented results of sensitivities conducted on the reference model that assumed state renewable portfolio standards and gas prices averaging $3.43/MMBtu through 2037. (The reference case assumes an average of $5.14/MMBtu.)

Among the key observations, PJM found that high capacity prices will allow natural gas combined cycles to enter the market despite low energy prices, while coal and nuclear resources will increase their dependence on the capacity market to recover their costs.

Wind and solar will be able to grow in a low-gas-price environment as long as renewable portfolio standards are enforced. PJM also predicts that lower gas prices will result in a reduction of carbon emissions through increased retirements of coal plants and the entry of new gas combined cycle plants.

PJM expects to release a final report by the end of May.

Year’s First Proposal Window Draws 26 Projects

The first competitive transmission proposal window of the year drew 26 projects from seven entities.

The projects address generator deliverability, common mode outage violations and end-of-life facilities.

Three are transmission owner upgrades ranging in cost from $7.7 million to $48.5 million. Twenty-three are greenfield projects with cost estimates of $15.6 million to $111.5 million.

More details will be provided at a future TEAC meeting.

PJM collected about $190,000 to study the projects under its new proposal fee structure. (See “Two-tiered Fee Schedule for Order 1000 Projects OK’d,” PJM Markets and Reliability Committee Briefs.)

Proposal Would Exclude TO Upgrades from Order 1000 Window

PJM is proposing to exclude certain transmission owner upgrades from the Order 1000 competitive window process. They include typical short-circuit violations and fixes to substation terminal equipment such as wave traps, current transformers and capacitors.

“We’re looking at situations where the upgrade is only a modest upgrade to equipment inside a substation,” said Steve Herling, PJM vice president of planning. “Our intention is to not have a window for something we know can be easily fixed.”

Few baseline projects driven by short circuits have resulted in a greenfield project, said PJM’s Mark Sims, who plans to present proposed changes on a first read next month at the Planning and Markets and Reliability committees.

– Suzanne Herel

April 8, 2016

Seventh Circuit Court Upholds FERC Order 1000 ROFR Provisions

By Rich Heidorn Jr.

A federal appeals court Wednesday unanimously upheld FERC Order 1000’s right-of-first-refusal provisions, rejecting challenges from the MISO Transmission Owners and LSP Transmission Holdings.

The 7th Circuit Court of Appeals in Chicago ruled after consolidating a challenge by the transmission owners, who sought to preserve the ROFR in the MISO transmission agreement (14‐2153), with two by LSP that contended FERC did not go far enough in injecting competition into transmission development (14‐2533, 15‐1316).

MISO ROFR

The three-judge panel was especially critical of the TO’s challenge to Order 1000’s requirement that federal ROFRs be removed from FERC jurisdictional tariffs. Invoking the Mobile-Sierra doctrine, the TOs said FERC should presume that their contractual ROFR is reasonable.

Richard_Posner_at_Harvard_University - for web (Wikimedia) — 7th Circuit Court of Appeals Judge Richard A. Posner

“But why?” Judge Richard A. Posner asked in the opinion. “The owners have made no effort to show that the right is in the public interest. Neither in their briefs nor at oral argument were they able to articulate any benefit that such a right would (with limited exceptions …) confer on consumers of electricity or on society as a whole. … Contract rights are not sacred, especially when they curtail competition.”

The TOs contended that their ROFR was not intended to prevent competition but to give MISO power to require TOs to build needed facilities in their service territories. “But that makes no sense,” the court said. “Had there been no intention or expectation of competition, there would have been no need for a right of first refusal.”

Baseline Reliability Projects

In the second case, LSP asked the court to overturn FERC’s decision to allow a TO the right to build any baseline reliability projects whose costs are allocated to that company’s territory alone and not subject to regional cost allocation. FERC justified this exception on the grounds that requiring competition on such projects — which often require quick turnarounds — could lead to delays because of the time required to conduct bidding and the potential for litigation by losing bidders.

LSP said reliability projects covering more than one pricing zone should be considered regional and thus open for competition.

“But a transmission facility is not regional for purposes of cost allocation if all its costs are allocated to the pricing zone in which it is located,” the court said. “A right of first refusal would be problematic, therefore, only if the benefits of a baseline reliability project were largely or entirely realized in pricing zones other than the one in which the project was to be built.”

State ROFRs, Entergy

LSP raised a related complaint in the third suit, challenging FERC’s decision to treat the entire Entergy footprint — Texas, Arkansas, Louisiana and Mississippi — as a “local” area not subject to competition and regional cost allocation.

“The vast region covered by Entergy’s multiple operating companies hardly complies with the usual understanding of ‘local,’” the court acknowledged. “But ‘local’ need not retain its usual understanding when used to designate the service area of a giant electrical transmission entity. It is a relative term; New York City is a huge city yet as a matter of scale is ‘local’ relative to New York state, or to the Northeast. Entergy’s retail distribution service territories can be said to be ‘local’ for a different reason: the separate operating companies actually operate as one and have so operated for more than 50 years.”

LSP also challenged FERC’s approval of MISO rules implementing Order 1000, including its rules for evaluating competitive bids, which consider not only the project’s estimated cost but also its design and the quality of the bidder’s management.

The court rejected LSP’s desire to make cost the primary criteria for selection, saying, “There is no indication that any of MISO’s criteria favor incumbent developers over nonincumbent ones who have demonstrated an equal ability to execute a project effectively.”

The judges also upheld MISO’s acknowledgment of state ROFRs, over which FERC has no jurisdiction. LSP cited a Minnesota law that grants an incumbent TO the right to construct, own and maintain any lines that connect to the TO’s system.

“It would be a waste of time for MISO to conduct a protracted competitive bidding and evaluation process when the incumbent transmission company has a right of first refusal conferred by state law,” the court said.

The 7th Circuit’s ruling is the second to uphold Order 1000’s removal of federal ROFRs, following one by the D.C. Circuit Court of Appeals in August 2014 that consolidated more than a dozen cases. (See FERC Order 1000 Upheld.)

There are at least six pending cases involving compliance by PJM, Columbia Grid, ISO-NE, SPP and WestConnect in the D.C. Circuit and the 5th Circuit, according to FERC.

April 4, 2016

NYISO Management Committee Briefs

New York’s natural gas demand set a single-day record in February, although the winter was much milder than the average over the past 30 years.

The winter operations review presented at the NYISO Management Committee meeting on Wednesday showed that only three relatively brief cold snaps occurred over the winter, with the worst one in mid-February. Cold snaps in December and January, when daylight hours are shorter, have greater potential to stress the electric system, said Wes Yeomans, NYISO’s vice president of operations.

On Feb. 13, during the coldest three-day period of the winter, the ISO set a 6.6 Bcf single-day record for natural gas demand, exceeding the previous mark of 6.4 Bcf set in February 2015. Yeomans said 100% of the natural gas system’s capacity was reached that day, for both heating and electricity generation.

The record was as much a function of the low cost of natural gas as power demand, Yeomans said. “Gas prices remained below oil prices for the day,” he said.

NYISO relies heavily on dual-fuel capable generation, so when natural gas supply becomes constrained — or when it becomes uneconomic relative to the cost of oil-fired generation — fuel-switching becomes more widespread. That did not occur during this stretch.

The peak load in mid-February was 22,951 MW. No demand response resources were called upon this winter.

“Our winter peak was below the 50/50 forecast by quite a bit,” Yeomans said. The peak of 23,317 MW on Jan. 19 was the lowest winter peak since at least 2004. The forecasted peak was 24,515 MW.

Yeomans said the fuel-monitoring platform the ISO created to improve reliability also appeared to be “working well.”

ICAP Demand Curve Reset

The committee voted to set the capacity market demand curve every four years with an annual reset, an increase from the current three-year cycle. The demand curve was introduced more than a decade ago.

“The change is recognizing calls from stakeholders,” said Paul Hibbard, vice president of the Analysis Group, the consultant hired by NYISO.

The changes more accurately reflect the New York wholesale market as generation assets enter and leave, Hibbbard said. The annual reset would consider the gross cost of new entry and forecast energy and ancillary services revenues, as well as adjusting historical revenues to reflect market conditions.

Another factor in extending the cycle is the 18 to 20 months needed for setting the demand curve.

The change needs to be ratified by the NYISO Board of Directors. Further refinements would be performed over the next several months, in advance of a filing with FERC by Nov. 30. NYISO anticipates an operational date of May 1, 2017.

— William Opalka

April 4, 2016

Grid 2.0 Asks DC PSC to Reconsider Merger Approval

By Suzanne Herel

One party to the Exelon-Pepco Holdings Inc. merger case has asked the D.C. Public Service Commission to reconsider its approval, and the People’s Counsel said she’s considering doing the same.

Sandra Mattavous Fry (Twitter) - Exelon-Pepco Merger — Mattavous-Fry *Source: Twitter*

Grid 2.0, which advocates for distributed generation, and did not sign on to any proposed settlement in the case, said in a March 25 filing that the commission failed to give adequate notice of public hearings and did not provide support for its finding that the settlement it crafted itself was in the public interest.

“The commission … failed to make any independent finding that the revised settlement agreement is in the public interest,” it said, calling the PSC’s conclusion “arbitrary and capricious.”

The nine settling parties, who approved an initial agreement that was later amended by the commission, have until April 22 to file an application for reconsideration with the PSC. Four other groups that intervened but did not sign on to the settlement also have the opportunity to appeal the decision.

The joint applicants responded to the filing, saying “every part of Grid 2.0’s argument is wrong.”

“The commission approved the merger after two years of the most exhaustive consideration that the commission has ever given to any issue, and it did so based on one of the most extensive records the commission has ever compiled,” they said.

D.C. People’s Counsel Sandra Mattavous-Frye said last week on the Kojo Nnamdi radio show that she is reviewing the ruling with an eye toward issues that might warrant her office taking action.

“I do have some major concerns about the process throughout the case. You didn’t really know what to expect or how the commission came to its determination,” she said. “It’s not over until it’s over. But I do admit that the lift is going to be heavier at this junction.”

Exelon and Pepco closed the $6.8 billion transaction just hours after the PSC approved the deal on March 23. (See Exelon Closes Pepco Merger Following OK from PSC.)

Mattavous-Frye cited “uncertainty created by the commission’s plan,” specifically how it plans to use $32.8 million of the $72.8 million customer investment fund that commissioners “redirected … for themselves without any clear explanation of how those funds will be used.”

If the commission stands by its decision, parties may turn to the D.C. Court of Appeals.

The acquisition, approved on a 2-1 vote with Chairwoman Betty Ann Kane in opposition, creates the country’s largest utility by customer count.

In an interview last week with the Washington Business Journal, Exelon CEO Chris Crane and new Pepco head David Velazquez said they would work to prove themselves to merger opponents and will be active in district affairs.

April 4, 2016

GridEx III Shows Vulnerability of Power Grid to Cyberattack

By Ted Caddell

GridEx III, a drill to test the emergency response capabilities of the North American high-voltage power grid, highlighted several vulnerabilities in the face of a simulated cyberattack. The lesson: Responding to a wide-scale computer malware attack is completely different from overcoming a monster storm.

“Electricity system recovery and restoration would be delayed or may not begin until the nature of the cyber risks are understood and mitigation strategies are available,” said NERC’s final report on the November drill.

GridEx III drew 4,400 participants from grid operators, federal agencies and local, state and federal law enforcement. The two-day scenario hit the grid with cyber and physical attacks resulting in blackouts in several cities. Organizers sent waves of simulated malware to grid operators by email. Throughout the beginning stages of the drill, operators were also notified about simulated attacks on physical plants such as transmission lines and substations.

“We wanted to challenge the coordinators to be on that ragged edge … [to see what they need to do to] protect the reliability of the system,” Bill Lawrence, NERC associate director of stakeholder engagement, said during a press conference Thursday.

The scenario employed email delivery of simulated malware — a tactic used by hackers who attacked three utilities in Ukraine in December. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)

The after-action reports showed that secure sharing of communication between parties and reporting methods remains a problem.

“Industry needs to coordinate with local law enforcement to identify and assess the physical risks to electricity facilities and workers,” the report said. “Unlike how industry responds to major storms through mutual assistance, industry’s capability to analyze malware is limited and would require expertise likely available from software suppliers, control system vendors or government resources.”

Another observation was that the information-gathering tools may be capturing too much. The NERC-run information portal captured reports in real time, but participants said they and the system quickly became overwhelmed.

NERC, the report said, “should continue to enhance the [information] portal to support real-time, searchable, urgent communication and collaboration.”

Another major observation gleaned from the simulated cyber and physical attack was that recovery would be prolonged and expensive. “Utilities will need unprecedented levels of financial resources in order to restore their facilities and eventually resume normal operations,” the report said.

The massive expense of a widespread restoration effort raised a question: Where is that money going to come from?

“There are certain regulations and laws out there that could be useful for grid restoration,” Lawrence said. “For example, the Stafford Disaster Relief and Emergency Assistance Act is designed to deliver relief and funding to individuals that are impacted by a disaster.”

But the law doesn’t provide relief for private corporations, such as investor-owned utilities. “Obviously if the utility isn’t generating power, they can’t pay their employees, and that would be a severe impact,” Lawrence said.

GridEx III featured the first use of social media for communications purposes. The report also recommended lengthening the planning time for the next exercise.

April 4, 2016

ISO-NE Again Defends Capacity Auctions

By William Opalka

ISO-NE CEO Gordon van Welie last week again defended the RTO’s capacity auction to congressmen who say market practices have led to inflated electricity rates for New England ratepayers.

In an eight-page, single-spaced letter sent Monday, van Welie reminded the New England congressional delegation of his testimony three years ago that highlighted the dramatic shift in the region’s market.

“Since then, 4,200 MW of resources have either announced plans to retire or have actually retired. Importantly, since 2013, the region’s Forward Capacity Market (FCM) has procured over 4,700 MW of new capacity resources — demonstrating that the FCM is procuring new, economically competitive resources to meet the region’s energy needs,” he wrote. (See Prices Down 26% in ISO-NE Capacity Auction.)

Van Welie’s letter was a response to a March 14 letter sent to FERC and the RTO by the delegation members after results of the 10th Forward Capacity Auction were filed.

“While these clearing prices were the result of a ‘competitive auction’ according to ISO-NE, the results are roughly equal to FCA 8, an auction that triggered administrative pricing rules due to lack of competition. They are also triple the capacity payments derived from the auctions prior to FCA 8,” the delegation wrote.

The congressmen acknowledged that prices declined more than 25% from FCA 9, but they noted that the previous year was a record $4 billion.

Ten senators and representatives joined in the letter, which was written by Massachusetts Democrats Rep. Joseph P. Kennedy III and Sen. Edward Markey. The members have repeatedly complained to FERC, without success, about alleged market manipulation. (See Congressional Meeting Fails to Sway LaFleur on Capacity Results.)

Van Welie said that market participants respond to price signals.

“We share your goal of ensuring that prices in the capacity market are just and reasonable. The FCM must and does signal the true value of capacity in New England. Artificial prices (whether too high or too low) do not benefit regional electric reliability or New England residents,” he wrote.

April 4, 2016

ERCOT Stakeholders Agree on Lost Opportunity Costs Rule

By Tom Kleckner

AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week agreed on a method for paying lost opportunity costs to generators ordered to ramp down for grid reliability, a solution that will now go to the ISO’s Board of Directors.

Stakeholders discussed three options brought forth by ERCOT staff to address Nodal Protocol Revision Request 649 (Addressing Issues Surrounding High Dispatch Limit (HDL) Overrides), which was remanded back to TAC during the board’s February meeting. (See LOC Rule Sent Back to ERCOT’s Stakeholder Process.)

Staff’s preferred option was the first of three it presented: rewriting the NPRR’s language to replace compensation for opportunity costs with “justified” losses suffered by qualified scheduling entities (QSEs) holding existing contracts. The QSEs would have to provide an attestation of loss, calculations and supporting documentation to recover a claim.

A second option proposed software changes to override the resource node’s LMP, which would have created difficulties at the 98 nodes with at least two generator connections. The third, and priciest option, at $200,000 to $300,000 plus ongoing support, would pre-position manual constraints associated with each resource node in the system model.

As the discussion wore on, it became apparent stakeholders were coalescing on the first of ERCOT’s options.

“This seems to be a quickly diminishing issue,” said Shell Energy’s Greg Thurnher, representing independent power marketers. “It looks like Option 1 is the remedy.”

Brandon-Whittle,-Megawatt-Analytics-web — Whittle

“We think Option 1 is the way to go for now,” said Megawatt Analytics’ Brandon Whittle, speaking for Odessa-Ector Power Partners and Koch Services. “It puts the onus on the people who might get hurt. No generator wants to be paid back for their losses because of HDL overrides. We’d rather adjust the LMPs.”

The proposal passed by a 23-5 vote, with two abstentions. The NPRR will go before ERCOT’s board April 19. Staff will revise the revision request’s impact analysis and better define energy bilateral contracts.

Odessa-Ector, a subsidiary of Koch Ag & Energy Solutions, initiated discussion of the issue when it claimed its combined cycle plant had lost $300,000 because of three days of dispatch overrides in November 2012. ERCOT submitted the NPRR to satisfy a settlement agreement with Odessa-Ector after the company filed a complaint with the Public Utility Commission of Texas (docket #41790).

Luminant’s Amanda Frazier expressed a preference for an earlier version of the NPRR, which failed to secure sufficient votes. But she said that in subsequent discussions, “ERCOT has eliminated a number of concerns we originally had.

“The damages are limited to those attested to by the resources, and compensating the actual damages rather than the opportunity costs is a good compromise,” she said.

Resmi Surendran, ERCOT senior manager of market analytics and design, highlighted staff’s efforts to reduce HDL overrides, which peaked at more than 348,000 minutes in 2011. The numbers have steadily dropped since then, with only 57 minutes of overrides recorded last year.

Surendran attributed the improved results to increased operator training, their ability to enter manual constraints, the availability of new generic transmission constraints and topology improvements.

Whittle sought reassurance from ERCOT that the NPRR’s cost can be reduced from its current staff estimate of $100,000 to $150,000.

“We try to implement [any changes] at the minimum cost we can,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “We’ll definitely go back and see if we can’t reduce the cost. I just can’t give you a number, right now.”

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.