Page 1333 – RTO Insider

March 21, 2017

Q4 Revenues up 7% for Top 30; Net Income Drops

By Rich Heidorn Jr.

Companies in the RTO Insider Top 30 reported revenues of more than $75 billion in the fourth quarter of 2016, a 7% increase over a year earlier, as all but five companies saw topline growth.

FirstEnergy, Public Service Enterprise Group, NextEra Energy and NRG Energy all reported revenue drops in the fourth quarter while Consolidated Edison was flat.

Similarly, all but five companies were profitable in the quarter. The exceptions were FirstEnergy (a $5.8 billion loss) Entergy ($1.8 billion), NRG ($987 million), Duke Energy ($222 million) and PSEG ($98 million). But the losses were so large they swamped their peers’ earnings, resulting in a cumulative loss of $2.62 billion for the quarter.

FirstEnergy reported a loss of $6.2 billion for the entire year, largely because of asset impairment and plant exit costs related to its decision to leave competitive generation by mid-2018. The company is seeking subsidies for its Davis-Besse and Perry nuclear plants in Ohio to make them attractive to buyers. (See FirstEnergy Seeking ZECs to Aid Sale of Ohio Nukes.)

Despite the fourth-quarter loss, Entergy, which also is exiting merchant nuclear generation, earned $1.27 billion for the year ($7.11/share), beating Zacks’ consensus estimate of $6.83/share. (See Entergy Beats Expectations Despite 80% Drop in Earnings.)

Avangrid’s 29% jump in Q4 revenues and more than doubling of net income reflected the first full year of operations including UIL Holdings, which it acquired in December 2015.

Edison International earned $377 million in the fourth quarter, versus a $50 million loss a year earlier. In February, its Southern California Edison unit joined with other investor-owned utilities in proposing spending $1 billion on transportation electrification. SoCalEd plans to spend $573 million, including pilot projects for electric transit buses and electrification of cargo handling equipment at the Port of Long Beach.

Edison CEO Pedro Pizarro said the company has “scaled back business development” at Edison Transmission because of “limited FERC Order 1000 opportunities in our target markets.” The company will continue its role in the Grid Assurance initiative to pool inventory and develop best practices to support transmission system reliability.

Dominion earned $457 million for the fourth quarter, a 28% jump, thanks to its acquisition of Questar, which added 56 Bcf of gas storage and 3,400 miles of gas transmission to its assets. Due in part to the acquisition, the company announced last month it was rebranding and replacing “Resources” with “Energy” in its name. The company now does business in 18 states. (See Dominion Resources Changing Name to Dominion Energy.)

The company could see a boost to earnings if Connecticut lawmakers approve legislation providing additional revenues for its Millstone nuclear plant. (See related story, Connecticut Moves Closer to Equating Nuclear with Renewables.)

Company	Market Cap ($ billions)	Revenue Q4 2016 ($ billions)	% change vs. 2015	Net income Q4 2016 ($ millions)	% change vs. 2015
NRG Energy	$3.87	$2.53	-16%	($987.00)	NA
NextEra Energy	$55.91	$3.70	-9%	$966.00	91%
Public Service Enterprise Group	$22.15	$2.09	-8%	($98.00)	NA
FirstEnergy	$13.70	$3.38	-5%	($5,796.00)	NA
Consolidated Edison	$21.63	$2.71	0%	$206.00	17%
Berkshire Hathaway Energy	NA	$4.17	1%	$483.00	1%
Pinnacle West Capital	$8.66	$0.74	1%	$53.25	29%
Great Plains Energy	$5.89	$0.58	2%	$98.00	328%
PPL	$23.14	$1.83	3%	$465.00	17%
Ameren	$12.73	$1.36	4%	$32.00	10%
American Electric Power	$30.96	$3.79	5%	$373.40	-20%
Eversource Energy	$18.65	$1.78	5%	$231.10	26%
Entergy	$13.11	$2.65	6%	($1,765.54)	NA
Xcel Energy	$20.64	$2.79	6%	$227.48	9%
WEC Energy Group	$18.51	$1.96	6%	$194.70	8%
Alliant Energy	$8.63	$0.80	8%	$65.20	78%
Sempra Energy	$25.18	$2.91	8%	$379.00	3%
CMS Energy	$11.62	$1.64	9%	$77.00	-27%
Calpine	$4.10	$1.58	10%	$24.00	NA
Westar Energy	$7.99	$0.61	11%	$53.94	37%
PG&E	$33.86	$4.71	13%	$696.00	404%
Duke Energy	$54.33	$4.82	14%	($227.00)	NA
DTE Energy	$17.68	$2.87	16%	$131.00	64%
Centerpoint Energy	$10.61	$2.08	16%	$101.00	NA
Exelon	$32.79	$7.87	18%	$204.00	-34%
Nisource Inc	$7.15	$1.30	18%	$88.80	49%
OGE Energy	$6.68	$0.53	19%	$57.90	97%
Dominion Energy	$48.10	$3.09	21%	$457.00	28%
Edison International	$23.46	$2.88	23%	$377.00	NA
Avangrid	$11.70	$1.49	29%	$207.00	116%
Total		$75.23	7%	$(2,625)	-35%

NOTE: No % change is listed for net income if either the current quarter or previous year was a loss.

March 20, 2017

MISO, PJM Find Value in CPP Study, Despite Rule’s Likely Demise

By Amanda Durish Cook

CARMEL, Ind. — EPA’s Clean Power Plan may be undone by the Trump administration, but MISO and PJM officials say their recently completed study on the rule yielded some valuable insights nonetheless.

“The CPP provides a good stress test to illustrate not only the value of interregional coordination but state coordination, as new policies and/or regulations are considered,” the RTOs opined in the study, which was released last week.

The study examined Michigan, Indiana, Illinois and Kentucky — states on the RTOs’ seam — and focused on transmission congestion, generation mix, production costs and economic trading.

PJM Net Exporter

Coal retirements and new combined cycle gas additions would make PJM a net exporter of power to MISO by 2030 because PJM’s gas additions “are located much closer to shale formations and thus have a lower fuel delivery basis and lower operating cost than the MISO resources,” according to the study. Over the last five years, the net scheduled interchange between the two regions has varied, with each at times being a net seller.

EPA trump clean power plan — Map shows MISO-PJM seams with states in both RTOs framed in brown | *MISO, PJM*

The study also found that transmission congestion costs would rise by between $1.1 billion and $1.8 billion between 2025 and 2030 if the CPP is enforced. The increase is owed to higher fuel prices and load, new generation constructed without transmission reinforcements, outages and policy decisions that shift the locations of the most economic sources of generation.

It projects LMPs would be between $54 and $70/MWh by 2030, with MISO having a slighter higher LMP than PJM under all CPP scenarios.

The report identified three variables — natural gas prices, the geographic scope of emissions trading and how much energy efficiency can count toward compliance — as “key drivers” and used them as sensitivities in the study.

Gas Price Impact

The analysis agreed with previous CPP studies by the RTOs that concluded that the cost of natural gas would be the biggest single determinant in the cost of compliance. “The price of natural gas has by far the biggest impact,” MISO Senior Policy Studies Engineer Jordan Bakke said at a March 15 Planning Advisory Committee meeting. (See PJM: Regional Plan Cuts Costs, but Gas Prices are Wild Card for CPP Compliance.)

The study found that standardizing state energy efficiency measurement and verification rules would allow commoditization of credits across broader markets, helping to offset deployment costs. “Non-similar state policies can drive significant economic distortions along the MISO-PJM seam and exacerbate transmission cost impacts,” the report said. “Conversely, the ability to transact fungible products amongst states results in greater market efficiency.”

Both RTOs used previous analyses for the study, MISO bringing its 2017 Transmission Expansion Plan policy regulations future and PJM supplying its September 2016 CPP study. The earlier studies showed that state emissions credit trading resulted in “lower costs, fewer generation retirements and more efficient generation investment.”

MISO and PJM began the study six months ago, after the CPP was stayed by the Supreme Court but before Trump’s election. “The political landscape was a lot different a year ago,” Bakke acknowledged. “But we still find value in this entire exercise.”

Bakke said the analysis would only be used for informational purposes at this point and would not influence MTEP 18 futures. He also said the study could become a template for future cross-RTO policy analyses.

The study is the first policy-focused study MISO has ever completed with another RTO, according to Bakke. “I think this helped open the lines of communication,” he said.

Both MISO and PJM said the study should not be viewed as a recommendation for complying with the CPP. “However, states, utilities and other entities can consider the observations made from this analysis within the specific context of the CPP or in a broader context as they consider other policy goals that can influence already dynamic economic interactions in electric markets,” they wrote.

March 20, 2017

MISO’s Competitive Tx Evaluation Costs $1.3 Million

CARMEL, Ind. — MISO spent $1.3 million to evaluate construction bids in its first competitive transmission process, including administrative costs for issuing the request for proposals and drafting a post-selection report.

The work was funded entirely by the 11 developers that submitted proposals. Brian Pedersen, senior manager of competitive transmission, said MISO required a $100,000 deposit from each of the 11 developers to fund the cost of Duff-Coleman bid evaluation, but the RTO had to bill each of them another $21,000 to make up for all evaluation costs.

Stakeholders asked how the process could be streamlined to reduce costs.

“There aren’t a whole lot of economies to scale, since we still have to evaluate everything,” Pederson said at the March 15 Planning Advisory Committee meeting.

The RTO and stakeholders would discuss evaluation criteria and process transparency during the April meeting of the new Competitive Transmission Task Team, he said. May’s meeting will focus on possible improvements to MISO’s developer qualification process.

MISO competitive transmission — | *MISO*

Pederson also said MISO will publicly post information from Republic Transmission’s first quarterly report on the Duff-Coleman project sometime during the second quarter. (See LS Power Unit Wins MISO’s First Competitive Project.)

— Amanda Durish Cook

March 20, 2017

Changes to Put CAISO Market Monitor Under Full Board Oversight

By Robert Mullin

CAISO’s Board of Governors last week approved a measure investing the board with complete oversight authority over the grid operator’s internal Market Monitor.

The change comes in response to FERC’s recommendations in a 2016 audit report that found that SPP executives had “inappropriate” involvement in the oversight of that RTO’s internal Market Monitoring Unit. (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)

caiso market monitor board of governors — Collanton | © *RTO Insider*

“This is our response to FERC guidance on oversight of the Department of Market Monitoring,” Roger Collanton, CAISO general counsel, said during a March 15 meeting of the board. “In particular, [we’re] giving the board more direct oversight over the administrative functions of market monitoring in order to enhance the appearance and, in fact, the independence for market monitoring.”

CAISO’s Tariff currently outlines a “dual” reporting structure in which the department is subject to direct board oversight for its “core” monitoring responsibilities, while at the same time reporting to the ISO’s CEO for administrative purposes, which include budgeting and staffing matters.

The new arrangement calls for the establishment of an Oversight Committee to be staffed by governors Ashutosh Bhagwat and Angelina Galiteva. It will be charged with overseeing the department’s administration and operations, including determining staffing levels and compensation, setting departmental goals, approving budgets and ensuring that the ISO is providing adequate corporate support. The committee will operate under a newly created charter.

“The arrangement will still allow for the Department of Market Monitoring staff, as well as the director, to communicate directly with the [full] board as they need,” said Greg Fisher, senior counsel with the ISO. “However, the Oversight Committee will be something that they can reach out to for various issues.”

Fisher said the proposed changes arose out of a review of the recommendations from FERC’s audit of SPP, discussions with FERC staff currently auditing the ISO and consultation with DMM Director Eric Hildebrandt.

“I just want to emphasize that we’re very supportive of this,” Hildebrandt said. “We’re looking forward to working with the Oversight Committee, but as [Fisher] mentioned, this is really just to bring our organization in line with what FERC identified as best practices based on some other ISOs.”

Hildebrandt went on to laud CAISO CEO Steve Berberich for supporting the Monitor’s independence and for “always” having provided the necessary resources and staffing for the department. Hildebrandt called the prospect of direct engagement with the CEO and the Oversight Committee “the best of both worlds.”

“I support these [changes] under one condition, and that’s that I can continue to have that kind of relationship with [Berberich] and interface with him,” Hildebrandt said. “I think that’s very helpful in just our working as an internal Market Monitor.”

“The charter is designed with that type of flexibility in mind, so that the Oversight Committee has full ability to delegate responsibility as it sees fit to management, as well as anticipating that same type of collaboration and interaction with management,” Collanton said.

March 20, 2017

Board Approves CAISO Small TO Generator Interconnection Plan

By Robert Mullin

CAISO’s Board of Governors last week approved a proposal designed to prevent smaller transmission owners from footing the costs for network upgrades needed to interconnect generation serving load outside of their service territories.

generator interconnection plan caiso — Valley Electric Association serves about 18,000 customers in a sparsely populated region along the California-Nevada border. | *VEA*

The plan was the product of seven months of work by CAISO staff and stakeholders to address a situation facing Valley Electric Association — one that could also apply to other small utilities that join the ISO in the future. (See CAISO Issues Final Proposal for Small TO Interconnection Costs.)

Valley Electric, a Nevada-based cooperative serving about 18,000 electric customers in a sparsely populated area along the California-Nevada border, has recently been targeted as a promising site for developing solar projects intended to help California achieve its 50% by 2030 renewable portfolio standard.

Avoiding Rate Shock

“This proposal addresses the rate shock that would happen for a small [TO] and would have de minimis impact on larger [TOs],” Stephen Rutty, CAISO’s director of grid assets, told the board during its March 15 meeting.

Rutty pointed out that only a handful of CAISO stakeholders opposed the proposal, which would require the ISO to determine on a case-by-case basis whether a candidate TO could be allowed to fold low-voltage generator interconnection costs into high-voltage transmission revenue requirements, thereby spreading costs among the ISO’s entire ratepayer base. San Diego Gas and Electric demurred, citing a concern that CAISO’s solution did not meet FERC cost allocation rules.

The proposal requires that an eligible TO be very small relative to others (with a gross load of 2 million MWh or less), located in a renewable resource-rich area gaining “elevated” interest for generator procurements and not in need of the new interconnecting generation to meet an RPS.

CAISO has estimated that a single $10 million network upgrade required by new generation would increase Valley Electric’s combined high- and low-voltage transmission access charge (TAC) by nearly 14%.

“However, if they are allowed, under this proposal, to put it into their high-voltage TAC, their increase would be about 0.04%, and the rest of the [participating TOs] would see a very similar de minimis impact,” Rutty said.

150 MW New Generation vs. 130 MW Load

Valley Electric representative Josh Weber, an attorney with Davison Van Cleve, sought to provide some additional context for the board.

“Valley’s peak load, out there in the desert when the air conditioners are all running and it’s 114 degrees outside, is somewhere around 130 MW,” Weber said, adding that the cooperative is currently negotiating about 150 MW worth of generator interconnection agreements. Those deals alone could incur $6 million to $9 million in upgrade costs for the 138-kV lines that would be subject to the proposed rule.

“So that means that the generation that Valley is working hard to interconnect is much, much more than Valley’s entire peak load,” Weber said. “I think that kind of speaks to the magnitude of the cost shift that we’re talking about here.”

Speaking on behalf of the Large-scale Solar Association, California Wind Energy Association and Independent Energy Producers Association, attorney Joe Karp offered his support for the proposal.

“Several options were considered, and this option is a narrowly tailored option that addresses a unique issue,” Karp said. “We believe the solution here is consistent with general FERC and [CAISO] policy on allocating infrastructure and upgrade costs.”

Catherine Hackney, director of state legislative policy for Southern California Edison, provided an additional endorsement, saying her utility appreciated the ISO’s efforts to narrow the proposal to fit Valley Electric’s circumstances.

Cost Allocation Concerns

SoCalEd’s neighbor to the south, however, took a contrary position.

“San Diego Gas and Electric agrees with just about everybody that something needs to be done, but I think the solution here that’s been identified is, frankly, inconsistent with FERC’s policy on cost allocation,” said Jan Strack, SDG&E’s manager of transmission planning.

FERC has been “pretty clear” that costs for transmission projects should follow benefits, Strack said.

“Instead, what we have in this proposal is a one-off kind of allocation mechanism where the size of the entity suddenly takes on great weight,” he said. “Nowhere in FERC’s cost allocation principles do I see any principle that size matters.”

Strack said the ISO still needs to determine the best way to establish a linkage between benefits and costs of transmission projects.

“I think until that exercise has been gone through, it will be very premature to go forward with this one-off, unprincipled approach to allocating transmission costs just on the basis of the size of the entity,” he said.

Strack contended that all electricity users benefit from the reduced carbon emissions and lower prices fostered by new renewable generation.

“Pretty much everybody realizes benefits from these connections, so to divide this up between low- and high- [voltage] — even in the way the ISO is proposing here — is a mistake, and I don’t think it’s going to survive a test at FERC,” Strack said.

“Size was not the only criteria here,” countered Keith Casey, CAISO vice president for market and infrastructure development. “The other piece of that was that [Valley Electric] did not have an RPS [and] did not benefit from renewables connecting to its system.”

Casey agreed that FERC’s principles require costs to follow benefits, but he said that Valley Electric’s lack of benefits from the new generation would provide a “principled” argument to FERC.

He also contended that FERC must in this case consider the issue of “just and reasonable” rates.

“Imposing that cost on a small number of customers when you’re looking at a 14% increase in just one year — we think there’s an issue there around the just and reasonableness of that,” Casey said.

March 20, 2017

MISO-SPP Coordinated Study Yields 1 Possible Project – For Now

By Amanda Durish Cook

CARMEL, Ind. — Preliminary results of MISO and SPP’s 2016 coordinated system study are in, and the RTOs say one South Dakota project has potential even though it fails MISO’s $5 million interregional cost threshold.

Davey Lopez, MISO advisor of planning coordination and strategy, said the project — the Split Rock-Lawrence 115-kV circuit into Sioux Falls, S.D. — costs $4.56 million but is still a strong contender at a 4.79 benefit-cost ratio. The RTOs would split the benefit of the transmission project at 56% for MISO and 44% for SPP.

“This project still shows high potential to be an interregional project. … Both MISO and SPP are open to removing that hurdle,” Lopez said of MISO’s threshold. MISO won FERC approval to shed its $5 million cost minimum and 345-kV limit with PJM last year in favor of no cost floor and a 100-kV threshold. But the commission said the order did not apply to the MISO-SPP process. (See FERC Signals Bulk of NIPSCO Order Work Complete.)

The RTOs looked at seven needs for the coordinated study: two shared tie-lines, one MISO project and four SPP projects. Three of the seven possible projects are unlikely to move forward, MISO stakeholders learned at a March 15 Planning Advisory Committee meeting.

MISO’s Planning Advisory Committee Meeting | © *RTO Insider*

Three other projects passed joint operating agreement cost and benefit tests, but the RTOs still have reservations:

The $8 million Lyon County 345/115-kV transformer in South Dakota has a 1.14 B/C ratio and could be split 8% to MISO and 92% SPP according to regional benefit. However, MISO and SPP say those preliminary results are “highly dependent” on solar expansion in the area and said more analysis is needed before recommendation.
The $8.3 million Crosstown-Blue Valley 161-kV line in Missouri has a 3.34 B/C ratio and could be portioned 32% to MISO and 68% to SPP. SPP staff is currently evaluating whether its own solution could be more cost-effective, and MISO says that to pursue the project, it would have to revise its cost allocation process because the line is below 345 kV.
The $25 million New Brookline-James River 345-kV line and new 345/161-kV James River transformer in Missouri has a 2.06 B/C ratio and could be divided 19% to MISO and 81% to SPP. But SPP is again examining its own regional solution and MISO is testing its own regional criteria because the project is located wholly outside of MISO and because MISO’s adjusted production cost is not in synch with SPP’s.

PAC Chair Cynthia Crane said the RTOs’ mismatched adjusted production cost calculations seem to be driving a lot of MISO’s cost allocation issues.

Lopez said both RTOs will make efforts in the future to align their adjusted production cost calculation. He also said the study’s sub-345-kV projects must be regionally approved on a case-by-case basis because of the 345-kV prerequisite.

The remaining three projects in the coordinated study either failed the 5% minimum regional cost benefit percentage or the $5 million project floor. In all three cases, either MISO or SPP will continue to evaluate the projects in their own regional processes.

More testing is needed to come up with a final list of projects, Lopez said.

The RTOs will finalize the coordinated study’s findings and publish a report in late April. At that time, the Interregional Planning Stakeholder Advisory Committee will vote on which recommended projects might proceed. The MISO side of the IPSAC vote will be conducted through the PAC.

MISO still maintains that the coordinated study will influence a longer-term joint study between the RTOs in 2017, although it’s unclear when they will work together on future interregional projects. Stakeholders learned earlier this month that a comprehensive MISO-SPP joint study is unlikely to occur in 2017. (See “Long Odds for 2nd MISO-SPP Joint Study,” SPP Briefs.)

The coordinated study was originally meant to focus on needs along SPP’s Integrated System in North Dakota, South Dakota and Iowa, and some stakeholders were doubtful that any projects would materialize. (See MISO-SPP Study Scope Finalized; Stakeholders Doubtful Projects will Result.) Last year, the IPSAC identified an initial list of high priority seams efforts for the study.

March 17, 2017

MISO Changes MTEP Futures Weighting for South

By Amanda Durish Cook

CARMEL, Ind. — The futures assumptions for MISO’s 2017 Transmission Expansion Plan are finalized, with the RTO granting its South region a different future weighting in one study.

MISO will use a 40% weighting for an existing trends future, 40% for policy regulations future and 20% for accelerated alternative technologies when conducting its market congestion planning study, which this year is focused solely on MISO South. The other studies in MTEP 17 will continue to use a 31% weighting for existing trends, 43% for policy regulations and 26% for accelerated alternative technologies.

The RTO revisited the weighting in February in response to a request from stakeholders who noted the Trump administration’s plan to eliminate the EPA Clean Power Plan. (See MISO Stakeholders Seek Review of MTEP Futures Under Trump.)

“We went through a presidential election that changed a lot of things,” MISO Director of Policy Studies J.T. Smith said at a March 15 Planning Advisory Committee meeting. “There were some concerns that, given the political climate, maybe the futures — developed in mid-2016 — didn’t quite reflect what the current situation is.”

MTEP MISO market congestion planning study — J. T. Smith | © *RTO Insider*

Smith said the revisions are meant to reflect regional differences within MISO; he pointed out that MISO South transmission owners and the state regulators of southern states all asked for more emphasis on existing trends.

Both the Louisiana Public Service Commission and Arkansas Public Service Commission asked for existing trends to be given 50% consideration while policy regulations and accelerated alternative technologies receive 30% and 20% weighting, respectively. Entergy went a step further to request a 60% likelihood for existing trends, 25% for policy regulations and 15% accelerated alternative technologies.

All other MISO stakeholders that commented on futures weighting — including MISO’s coordinating, environmental and transmission developer sectors, the Iowa Utilities Board, the Indiana Utility Regulatory Commission, the Minnesota Public Utilities Commission, the Minnesota Department of Commerce, Big Rivers Electric, Midwest Power Transmission Arkansas and WPPI Energy — urged MISO to leave weighting as is.

“When we saw that regional separation, we realized that maybe there needs to be a change this year,” Smith explained, adding that the near-term nature of the market congestion planning study can better absorb a change in weighting and not affect other longer-term planning. The study is designed to identify projects to relieve congestion.

Going forward, Smith said he’d like to focus more on the probability that the generating fleet will change regardless of potential federal policy shifts. Development of MTEP 18 futures will begin at the June Planning Advisory Committee meeting, and Smith said it’s unlikely that MISO will allow divergent weightings in the next MTEP cycle.

“I still think we’re going through fleet change,” said Smith, who also admitted that “it’s uncomfortable when you change assumptions halfway through.”

Smith also said MTEP 17 weights would not change in MISO’s footprint diversity study, which is specifically designed to identify alternatives to using SPP’s transmission interface for flows between MISO South and MISO Midwest.

Some stakeholders said that conducting one MTEP study using separate future weighting is inconsistent. Others asked how MISO arrived at the altered weights. Smith said the RTO only considered comments from southern stakeholders when creating the new percentages and did not use any mathematical calculations.

Xcel Energy engineer Drew Siebenaler pointed out that most stakeholders that submitted comments on the futures supported leaving them as is. Noting that all MISO stakeholders pay for the MTEP process, he said MISO South should fund its own study if it wants to handpick assumptions.

Smith said Siebenaler’s concerns were valid and that MISO would work to improve the futures weighting process in the future.

Meanwhile, Arash Ghodsian, of MISO’s economic studies department, said the footprint diversity study and the market congestion planning study continue on track, with project candidates emerging in June. He said stakeholders submitted 58 project ideas for the market congestion planning study.

March 17, 2017

CAPS Hires EnerNOC Alum as Executive Director

By Rory D. Sweeney

The Consumer Advocates of the PJM States (CAPS) has hired former EnerNOC executive Gregory Poulos to replace retiring Executive Director Dan Griffiths. He will transition in as Griffiths, who is expected to depart by the end of the year, leaves.

Poulos had been at EnerNOC since 2010, rising from a manager to the director of regulatory affairs. EnerNOC provides demand response and energy management services for industrial clients. His role focused on demand response and energy-market development in PJM and MISO as well as in the states within the grid operators’ footprints.

Before EnerNOC, Poulos had stints as an assistant consumer counsel in the Office of the Ohio Consumers’ Counsel, and assistant chief of the charitable law section of the Ohio attorney general’s office.

Griffiths had worked for another DR provider, Comverge, before joining CAPS. Before Comverge, he spent seven years in the Pennsylvania Office of Consumer Advocate and 18 years at the state’s Public Utility Commission.

CAPS is made up of all state utility consumer advocate offices in the PJM region, an area spanning all or parts of 13 states and D.C. In his new role, Poulos’ duties will include being a constant presence at PJM stakeholder meetings. (See CAPS Leader Looking to Pass the Torch.)

In a news release distributed Wednesday, CAPS President Robert Mork, of the Indiana Office of Utility Consumer Counselor, cited Poulos’ “strong mix of experience and a deep understanding of the people and processes at PJM” as a major benefit for the organization.

“Dan Griffiths served our organization well as it began formal operations,” Mork said. “Hiring Greg represents the next major step as CAPS works with its members to ensure consumer interests are taken into account at PJM. Bills paid by the region’s consumers include billions of dollars in PJM charges each year, and effective participation in the PJM stakeholder process has become vital to ensuring reasonable prices and reliable power in each of our states.”

Poulos called the opportunity “a great honor” and noted the cooperative nature of the CAPS membership, despite their distance and often disparate interests.

CAPS got its initial funding from a 2012 FERC market manipulation settlement with Constellation Energy. Last year, FERC approved PJM’s creation of a funding mechanism to support the organization through a charge to residential electric customers. (See FERC Approves PJM Funding of Consumer Advocates.)

March 17, 2017

FERC Staff OKs MISO Mitigation Changes; Refunds Possible

By Amanda Durish Cook

With FERC staff’s hesitant nod, MISO will apply a more stringent physical withholding rule and remove demand response and energy efficiency from market monitoring in next month’s Planning Resource Auction.

The commission released a short delegated order March 15 that accepted and suspended MISO’s proposed changes subject to refund (ER17-806).

FERC Director of Electric Power Regulation Penny Murrell, using authority delegated to her in the absence of a FERC quorum, said the commission’s preliminary review had not concluded the changes were just and reasonable and that the tentative approval was subject to further commission order.

The order will allow MISO to apply a 50-MW minimum for physical withholding rules to affiliated market participants collectively, rather than individually to each affiliated company. MISO’s Independent Market Monitor had recommended the change in its 2015 State of the Market Report, saying that as “capacity margins fall in MISO, the market will become more vulnerable to physical withholding.”

FERC MISO physical withholding — | *MISO*

The order also allows MISO to exempt DR, EE and external resources from PRA mitigation measures. The RTO said DR and EE resources are too small to have market power.

The rules will “provide stakeholders with greater certainty, prevent large suppliers from circumventing MISO’s mitigation provisions and encourage the participation of demand resources, energy efficiency resources and external resources” in the capacity auction, the RTO said. (See MISO Plans Additional Capacity Auction Revamps for 2017.)

A third change will allow planning resources to request facility-specific reference levels for the auction.

Reference levels are used to determine a resource’s marginal costs, including risk and opportunity costs and technical characteristics for physical offer parameters.

In its filing, MISO said its Tariff is vague as to the types of resources that can obtain a facility-specific reference level rather than using defaults. The change will permit facility-specific levels for planning resources not otherwise exempted from market mitigation.

March 16, 2017

Opposition to Va. Tx Line May Trigger Unintended Consequences

By Rory D. Sweeney

PJM is responding to permitting delays for a 500-kV transmission line across the James River by instituting a multilayered strategy that could cost ratepayers in Virginia’s middle peninsula.

The Surry-Skiffes Creek line was proposed to maintain grid reliability on the peninsula after Dominion Energy complies on May 1 with an EPA mandate to shutter its two Yorktown coal-fired units. The project’s opponents are concerned the line would ruin the view at Jamestown and other historic sites nearby. A study conducted on behalf of the National Parks Conservation Association concluded Dominion overestimated projected power growth and called for consideration of other alternatives, including underwater lines and converting the Yorktown units to natural gas.

PJM yorktown transmission line — Proposed Yorktown pricing interface, which will expose ratepayers to high LMPs should the regional system threaten voltage collapse. | *PJM*

Approved by the PJM Board of Managers in 2012, the transmission project remains stalled pending permit approval from the U.S. Army Corps of Engineers. Dominion representatives have estimated construction of the line would take at least one year after all permits are approved.

Remedial Action Scheme

Opponents have dismissed as a scare tactic Dominion’s warning that failing to build the line could result in blackouts, but the company announced last month it has developed a remedial action scheme for the region that calls for dropping service to approximately 150,000 customers to prevent a potential voltage collapse from N-1-1 contingencies. (See Dominion Says Blackouts the Only Solution for Va. Peninsula.)

At a series of committee meetings last week, PJM staff detailed several other changes for the area that will have consequences protesters likely haven’t imagined.

Paul McGlynn, PJM general manager of system planning, announced at the Transmission Expansion Advisory Committee meeting that the RTO has offered Dominion a reliability-must-run contract on the units starting on April 1 and continuing until either the transmission line is constructed or another reliability solution materializes.

PJM calculated that 44% of the costs for retaining the units would be allocated to Dominion’s Virginia Electric Power and Power Co., with nearly 10% each to American Electric Power’s East zone and Commonwealth Edison.

At the Market Implementation Committee meeting the day before the TEAC meeting, PJM staff presented its new Yorktown pricing interface, which will set real-time LMPs if demand response or other load-management resources are deployed. It would be triggered on a sub-zonal basis when thermal or voltage conditions are encountered that create N-2 or N-1-1 contingencies.

At the meeting, PJM’s Independent Market Monitor Joe Bowring took issue with the plan because it allows DR to set regional prices “well above any level that generation can set it” — potentially as high as $1,800 MWh. Prices in the region are usually around $40/MWh. The interface would only be modeled in the day-ahead market if conditions are known prior to market close, and it won’t be modeled for financial transmission rights auctions.

“It’d be one thing if DR were nodal and were dispatched with the same offer caps,” Bowring said. “In a sense, the core issue is that DR can have a price and set price at $1,800 or more.”