Maryland Gov. Larry Hogan said Friday he will support a ban on fracking, potentially making the state among the first to enact a statutory ban on the oil and gas extraction method.
Hogan
In making the announcement, Hogan, a Republican, departed from his previous stance that he would support the practice and that he believed it could be done in an “environmentally sensitive manner.” His new stance is the exact opposite, that it’s impossible for the process to occur without unacceptable environmental risks.
“I’ve decided that we must take the next step and move from virtually banning fracking to actually banning fracking,” he said. “The choice to me is clear: Either you support a ban on fracking, or you are for fracking.”
He made the announcement alongside state Sen. Bobby Zirkin (D-Baltimore), the lead sponsor of SB 740, which would establish the ban. The House of Delegates passed a ban on the practice by a veto-proof margin two weeks ago.
“Larry Hogan just took a big step for Maryland and the nation in moving us toward” solving global climate change, Mike Tidwell, the executive director of the Chesapeake Climate Action Network, said in a news release.
The controversial process of high-volume fracking has never been used in Maryland, but the state’s two-year moratorium is due to expire in October. Parts of western Maryland sit atop the Marcellus shale, a rock layer several thousand feet below ground laden with natural gas that runs from Ohio to New York. New York and Vermont already prohibit fracking.
Geologic Map of Western Maryland | Maryland Department of Natural Resources; click image for original
Hogan said his decision was partially based on the state legislature failing to implement rules proposed last year that he said would have been the most stringent in the nation and made it “virtually impossible for anyone to ever engage in fracking in Maryland.” Because the legislature didn’t enact the regulation, Hogan is now supporting a statutory ban.
Prior to Hogan’s announcement, the ban looked unlikely to be approved this session. Legislators feared a veto from Hogan and instead favored extending the moratorium. Sen. Joan Carter Conway (D-Baltimore) had proposed extending the moratorium for two years and requiring each county and Baltimore City to hold referendums next year on whether to ban the practice locally. As the chair of Senate Education, Health and Environmental Affairs Committee, she will decide if the ban bill receives a vote before the moratorium expires.
CARY, N.C. — Stephen Rourke, vice president of system planning at ISO-NE, worries distributed energy resources will force RTOs to change their focus.
“We’re so used to operating at the wholesale level. We dispatched 350 generators for the last 40 years. Now there’s 108,000 solar installations. So we’re kind of getting dragged, whether we like to or not, from a wholesale view of the power system, to a retail view,” he said during the RTO Insider-SAS ISO Summit at SAS headquarters last week.
“What we won’t have [visibility of] is if everybody who has solar panels in their houses puts a 4-kW battery in their garage — and there are hundreds of thousands of those. So that’s going to be a data challenge.
“If you’re 5 MW or greater, you need a [remote terminal unit], you have to have a leased telephone line. Those are thousands of dollars to buy and hundreds of dollars a month to lease the phone line. Your 500-kW solar panel can’t afford to do that, but we have thousands of them. So how do we get the data and how do we process the data? It is … a challenge for us. So we’re going to need help from others certainly with the technology platform.”
‘Layered Control Structure’
Layered Control Structure for DER | Lorenzo Kristov
Lorenzo Kristov, principal for market and infrastructure policy at CAISO, says it doesn’t have to be the RTO’s headache. He has proposed what he calls a “layered control structure” in which the distribution utilities would aggregate DER data for their RTOs.
“Each tier in this hierarchy only needs to see interchange with the next tier above and below, not the details of what’s going [on] inside because the optimization is happening locally,” he explained. “The ISO then focuses on bulk system integration, while the distribution utility … coordinates the operation of the DERs. The layered control structure reduces complexity, allows scalability and increases resilience and security. And finally the fractal structure mimics nature’s design of complex organisms and ecosystems.”
Kristov urged DER aggregators to bring “use cases” to CAISO to aid it in updating its market rules.
Currently, the ISO uses one of two models for DER: the demand response model and the non-generation resource used for storage. “When you’re charging, you’re using energy at retail; your ability to provide services to the ISO is very limited.
“Several parties have signed up as [DER] aggregators, but they haven’t brought in the resource yet,” he said. “Part of what we’re trying to figure out is what do we need to do to improve those rules. So I would say more active engagement in our stakeholder process [is needed] to bring us specific use cases. How do we want to operate in your markets? What is it we want to do? What are our capabilities? There’s a lot of technical detail that we can’t figure out because it’s the developers who have these things in mind.”
DER also needs standards, said Ralph Masiello, senior vice president of Quanta Technology. He cited the aftermath of Superstorm Sandy in New Jersey in 2012.
“Too many of those [solar] installations did not disconnect when the distribution circuit went dead and so restoration was held up by the need for utility linemen to come verify that the line was dead before the tree crews could start clearing the debris,” he recounted.
“Normally the utility knows from its SCADA that the line is dead. But if you have just one … PV panel that didn’t de-energize, it’s enough to put high voltage on a downed line and make it dangerous. So there’s kind of a big data opportunity there. The utility needs to know where are those panels and what is their status.”
Solar PV could create a role on distribution systems for synchrophasors that previously have been used mainly in transmission, Masiello said, citing a Department of Energy project testing whether PV panels can be used to develop “synthetic inertia.”
“Can you take a smart inverter on PV — it’s already got communications and … time-synch capability — and build the synchrophasor into that smart inverter? And then you can use it as a key to developing local synthetic inertia from the panels.”
Masiello also said his company is beginning to get requests to do forecasting on the distribution systems.
One need, he said, is identifying distribution lines subject to solar “backfeeding” onto the transmission system, as has become common in Germany and begun happening between 10 a.m. and 2 p.m. in Hawaii.
“In other words, there’s not enough load on a segment of line to be able to absorb all of the solar that’s being generated,”
he explained. Utilities “may have to move some customers from one distribution segment to another.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:25)
Members will be asked to endorse the following proposed manual changes:
A. Manual 13: Emergency Operations. Revisions developed in response to new NERC standards.
Members will be asked to endorse the proposed shortage pricing and operating reserve demand curve solution and associated manual revisions. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
Members will be asked to endorse a proposed problem statement and issue charge by Bob O’Connell of Panda Power Funds regarding calculation of opportunity costs for units with less than three years of historical LMPs. The initiative would evaluate whether the opportunity cost calculator included in PJM’s Markets Gateway produces the same results as that used by the Independent Market Monitor, Monitoring Analytics. It also would consider updating the calculators to reflect the nonperformance penalties under Capacity Performance. (See “Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes,” PJM Markets and Reliability and Members Committees Briefs.)
7. Modeling Generation Senior Task Force (MGSTF) (10:50-11:00)
Members will be asked to endorse a draft charter for the MGSTF, an outgrowth of the Combined Cycle Owners User Group, which concluded that a more detailed generator model for combined cycle units might also be applicable to other steam units. The task force will consider expanding the model used by PJM to improve the ability to represent components of all generation types.
8. Incremental Auction Senior Task Force (IASTF) (11:00-11:10)
Members will be asked to endorse a draft charter for the IASTF, which will consider changes to the Incremental Auction process and structure, excess capacity sales, and PJM participation in the auctions.
9. Replacement Capacity (11:10-11:40)
Members will be asked to endorse a revised version of a previously rejected problem statement and issue charge regarding procurement of replacement capacity in Reliability Pricing Model Incremental Auctions. (See “Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes,” PJM Markets and Reliability and Members Committees Briefs.)
CARY, N.C. — PJM CEO Andy Ott said last week the RTO will look for ways to incorporate “resilience” in its markets and system operations, providing hints at a white paper it will release later this month on the issue.
Speaking at the RTO Insider/SAS ISO Summit last week, Ott said the initiative was sparked by fuel security concerns — the risks of sabotage or cyberattacks on grid assets or gas pipelines — and a desire to recognize the reliability value of baseload nuclear and coal plants struggling to compete in the PJM market. Later in the panel discussion, former FERC Commissioner Tony Clark — participating via phone after snow canceled his flight from D.C. — forecast how the commission and the courts may rule on zero-emission credits that provide additional revenues to nuclear plants.
Ott said one possible shift in PJM would be changing contingency plans from replacing the largest single generator to ones that consider the loss of a gas pipeline supplying multiple generators.
PJM CEO Andy Ott wants to find ways to value the fuel security of coal and nuclear plants.
“All the generation connected in a certain section of that pipeline could go off very quickly if it loses pressure because of an explosion or some event. Maybe we should be operating to the loss of that and look at that operational risk inside the market and price that in so the units that didn’t have that kind of fuel security risk would be worth more money,” Ott said. “That would help, of course, the resources that are less dependent on just-in-time fuel” such as nuclear and coal. Ott also said PJM will seek to become more “dynamic” in its management of operations.
Concern over Pipelines, Transmission Corridor
“One obvious [example] is to look at the way we deploy synchronized reserves or operating reserves and expand the contingency set that you’re looking at to include pipeline contingencies. … Or if you have a transmission corridor that you’re very worried about — potentially include that as part of your constraint set. So when you’re dispatching generation or deploying demand response, you’re essentially recognizing that double contingency or triple contingency as part of operations in certain circumstances. Not 8,760 hours [per year] but when you think that vulnerability exists, you can price it in.”
It also could mean system restoration plans becoming less dependent on individual transmission lines or fuel sources, Ott said.
Ott did not offer details on how fuel security would be priced into the markets. The RTO has already taken steps to address reliability concerns with its Capacity Performance rules, which increased penalties for nonperformance and rewards for overproduction during emergencies.
Coal Group Petitions PJM, MISO
On Friday, meanwhile, the American Coalition for Clean Coal Electricity (ACCCE) sent Ott a letter calling on PJM to take steps to prevent further retirements of coal-fired generation and “take into account the likelihood of changes to federal environmental policies.”
“We are confident the new administration will withdraw or rewrite environmental regulations that are causing, or could cause, more coal retirements,” ACCCE CEO Paul Bailey wrote. “These rules include the Clean Power Plan, Coal Combustion Residuals, Effluent Limitations Guidelines, Cross State Air Pollution Rule and Regional Haze.”
Bailey said the Capacity Performance rules were helpful but insufficient. “We do not think these changes go far enough in recognizing the advantages of baseload coal-fired generation. In particular, the changes have not led to higher capacity prices that are necessary to keep coal plants from prematurely retiring,” he wrote.
ACCCE says 121 coal-fired generators totaling 20.1 GW have retired in PJM, most because of environmental regulations, and another 28 plants (8.9 GW) have announced plans to shut down.
Almost 93,000 MW of coal-fired electric generating capacity (558 electric generating units) in 43 states have shut down or plan to shut down over the period 2010 – 2030 | American Coalition for Clean Coal Electricity
The group also sent a letter to MISO CEO John Bear asking the RTO to change rules “to ensure the reliability attributes of coal-fired generation … are properly valued.” MISO has lost 103 coal-fired generators (8 GW), with another 45 retirements (10.5 GW) pending.
Former Commissioner: FERC May Reject ZECs
Nuclear spent fuel pool | Nuclear Energy Institute
Former Commissioner Clark, now a senior adviser at Wilkinson Barker Knauer, said zero-emission credits approved for nuclear plants in New York and Illinois — and under consideration in Connecticut and other states — may be rejected by FERC or the courts because of their impact on wholesale market prices. (See related story, Connecticut Moves Closer to Equating Nuclear with Renewables.)
Clark called ZECs the third iteration of states’ efforts to build or preserve generation within their borders. Last April, the Supreme Court rejected Maryland’s contract-for-differences with the developer of a combined cycle unit, saying that by tying the contract to PJM capacity prices, the state had violated federal jurisdiction.
In May, American Electric Power and FirstEnergy withdrew power purchase agreements that Ohio regulators had approved with their unregulated generation after FERC indicated it would review the deals for violations of affiliate abuse rules. “The merchant generators basically did a very surgical strike in [their] filing at FERC” in requesting the affiliate review, Clark said.
With ZECs, “the states … have really gotten craftier about how they can [preserve at-risk generators],” said Clark, noting that they were designed to be similar to state renewable energy credits (RECs).
“Merchant generators have … said these RECs are an out-of-market subsidy [that] distort prices. And the commission has said, ‘OK, theoretically we understand what you’re saying.’ But there wasn’t enough provable harm for the commission to really do anything about it,” Clark said. The RECs “were either conceptual at the time of the challenge … or it was a small enough part of the market … that it didn’t seem like it was a big enough issue that the commission could act on. So effectively the commission could punt on that issue.
“Now if you’re talking about certain regions of the country where nuclear units are 20%, 30% of the market, or if you’re talking about other out-of-market interventions like in the Northeast — you’ve heard about long-term power contracts … with Canadian hydro — that might be 30% of the state’s energy needs.
“Well that does have a very material impact on the market themselves, so that will be a challenge for the commission to see if this is a zero-sum game, or the commission will have to declare in some ways these things federally jurisdictional and carve the states out. Or is there a way to thread the needle? That’s what each of the ISOs that’s dealing with this is doing.
“Here’s where it will get to be very tricky for the commission,” Clark concluded. “I’m not sure exactly how it will end up dealing with it.”
North America’s independent grid operators released a report Thursday that concludes the “ongoing effectiveness” of renewable technologies will depend directly upon the electric system’s ability to “accommodate them.”
The ISO/RTO Council (IRC)’s report, “Emerging Technologies: How ISOs and RTOs can create a more nimble, robust bulk electricity system,” concludes the future of the North American power grid depends on effectively adding renewables, the accuracy and availability of data from behind-the-meter resources and coordinating these distributed energy resources at the grid-operator level to preserve reliability.
The report captures the results of a study conducted by the IRC’s Emerging Technologies Task Force (ETTF), which was formed in 2015 to review the deployment of new technologies and identify where that deployment intersects with operational and policy considerations.
The report notes more than 80% of North America’s wind and solar capacity lies in regions served by IRC members. These technologies face a serious challenge, the report said — the electric system itself.
SPP CEO Nick Brown, the IRC’s current chair, noted grid operators from different geographic regions “overlap … in their thinking” of the role emerging technologies will play.
Technology Precedes Policy
“Here’s the challenge: Technology always precedes policy,” Brown said during a panel discussion last week at the RTO Insider/SAS ISO Summit. “And as technology presents things, then we have to understand how to manage them [through] appropriate policies.”
The IRC is an affiliation of nine nonprofit grid operators that serve two-thirds of electricity consumers in the U.S. and more than half in Canada.
“Any time the IRC speaks with strong consensus on a matter like it has done here, I hope our industry takes notice,” Brown said in a news release.
“Each of the IRC member organizations is unique,” said ETTF Chair Edward Arlitt, of Ontario’s Independent Electricity System Operator. “One ISO or RTO may have greater solar capacity in their region, another may be farther along in their handling of DERs, and all of us have regulatory and operational constraints unique to the provinces, states and regions in which we serve.”
Western Interconnection renewable capacity with transmission investment to support high renewable penetration (2020-2025).
The task force used a straw poll to determine that handling emerging technologies was the highest-ranked priority among IRC members.
‘Imperatives’
The task force’s research produced what it called imperatives necessary to ensure the grid’s continued reliability and efficiency as the penetration of emerging technologies increases:
Manage the variability of supply and increasing levels of renewable integration enabled by emerging technologies. Is there enough “cohesive innovation” happening to integrate renewable generation, grid-scale energy storage and microgrids’ disparate components into the Bulk Electric System?
The IRC said while it is agnostic to specific technologies that may facilitate renewable integration, it supports policies that “accommodate emerging renewable integration technologies” and pursuing “continentwide consensus” on how much integration will be achieved through regional or interregional trade.
Computer-modeled load profiles for CAISO under various future scenarios of 20%-50% PV penetration.
The report recommends avoiding committing too early to specific technologies and calls for a “suitable policy environment” to ensure new technologies and approaches continue to be developed, tested and applied to renewable integration.
Address the IRC members’ lack of consistent, reliable, DER-related data as the grid becomes more distributed and less predictable.
The report says the lack of consistent and reliable data — such as between SCADA systems and new phasor measurement units (PMU) — should not constrain “situational-awareness arrangements” across transmission/distribution connections. It also says RTOs should have access to basic, static DER data series in their service territories. The task force said location, size and technological capabilities are examples of data needed to manage an increasingly distributed system.
The task force recommended developing an operations data framework flexible enough to handle local differences in DER penetrations.
Noting FERC’s November 2016 Notice of Proposed Rulemaking, which would require wholesale markets to accommodate energy storage and DER, the IRC suggests a formalized framework to help RTOs “harness the capabilities and manage the risks” of intermittent DER growth. (See FERC Rule Would Boost Energy Storage, DER.)
The task force recommends jurisdictions with distribution system operators (DSO) conform to standards that allow safe interaction between DSOs, non-utility entities and the Bulk Electric System. It said it supports policies that ensure if distribution-level variability poses risk to system reliability, RTOs have “appropriate authority” over DERs or mitigate their impact on the grid.
CARY, N.C. — PJM CEO Andy Ott and SPP CEO Nick Brown said last week that FERC Order 1000 is causing their staffs headaches while doing little to encourage transmission development.
“I think the driver behind Order 1000 was to get more people wanting to invest in transmission,” Ott told the RTO Insider/SAS ISO Summit last week, where he appeared on a panel with Brown and former FERC Commissioner Tony Clark, who participated via phone after snow canceled his flight from D.C. “We haven’t had any shortage of [interest]. In fact, everyone wants to invest in transmission because it’s a pretty safe investment. [Order 1000] was almost like a solution in search of a problem. … It’s actually creating more challenges to investment.”
“It created more overhead and more uncertainty at a time when we didn’t need more overheard in order to invest in transmission,” said Brown. “I am thankful that we completed the vast majority of our transmission buildout in a pre-Order 1000 environment.”
Ott said enforcing cost caps on competitive projects and allocating costs for them are tasks that RTOs are ill-equipped to handle. “We’re not a regulator,” he said.
Clark, who joined the commission after the order was issued in 2011, said the intent of the initiative was good, noting that it has pushed regions to conduct joint planning.
“The concern that I always had … is that there is so much process built into Order 1000,” each step of which becomes an opportunity for litigation and delay, Clark said.
“What you end up with is just what Andy and Nick were talking about, which is actually less investment happening than would otherwise happen organically on its own because you’re doing so much to meet the burdens of the process in Order 1000 that you’re sort of losing the forest for the trees.”
Clark said it’s too soon to determine whether the order will be successful in introducing competition into transmission development. “Incumbents have so many natural advantages in terms of building large infrastructure projects within their footprint that I don’t know that that’s something you can regulate away. Nor should we necessarily try to.”
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.)
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.
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.
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.
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
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.)
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.
“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.”
Hildebrandt
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.
The ISO/RTO Council (IRC)’s 
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 
