FORT LAUDERDALE, Fla. — NERC’s Board of Trustees on Thursday voted to dissolve the SPP Regional Entity (RE) by terminating the RTO’s regional delegation agreement, ending a reliability oversight role that concerned both the reliability organization and FERC.
With the termination of the NERC-SPP delegation agreement, most of the RE’s 122 registered entities will be reassigned to the Midwest Reliability Organization (MRO), with the remainder joining SERC Reliability Corp. At the same time, NERC will take over compliance monitoring and enforcement of the RTO for two years following the dissolution’s effective date. SERC has been responsible for compliance monitoring and enforcement since 2010.
SPP CEO Nick Brown said he supported the trustees’ decision but was disappointed in NERC assuming SERC’s monitoring role. The RTO said it preferred having ReliabilityFirst take that responsibility. (See NERC Seeks to Oversee SPP Reliability Compliance.)
“Their decision to provide compliance enforcement services for two years was not what we hoped for, but we’re ready to move forward,” Brown said in a statement. “We look forward to working in the NERC arena to improve processes related to regional assignment and compliance monitoring and enforcement.”
NERC will determine a successor for SPP’s compliance monitoring and enforcement after completing its two years of oversight, said the organization’s interim CEO, Charles Berardesco.
SPP said last July that it would dissolve the RE, which is responsible for auditing and enforcing reliability rules in three balancing authorities: SPP, Southwestern Power Administration and parts of MISO. (See SPP to Dissolve Regional Entity.)
SPP was appointed by NERC as an RE in 2007, but Brown said last year it became clear that agreement was “in jeopardy” as the RE’s footprint did not grow to match the RTO’s current 14-state territory. NERC also expressed concerns about the relationship between SPP, the RE and the RTO’s corporate compliance responsibilities.
That dual role also caused problems with FERC, which criticized SPP in a 2008 audit for failing to ensure the RE’s independence from the RTO (PA08-2, AD09-3). The audit called for improved oversight from the RE Board of Trustees to prevent conflicts of interest.
The termination agreement is expected to be approved by MRO next week. Berardesco said the agency will then move “expeditiously” to file for FERC’s “prompt” approval, easing the RE’s concern that it will continue to hemorrhage its staff.
NERC staff said they plan to make the FERC filing as soon as early March. SPP hopes to complete the transition by the end of July.
“We all recognize as the SPP RE goes away, there is the potential for a gap with people leaving,” Berardesco said.
Ken McIntyre, NERC vice president and director of standards and compliance, reassured the trustees that the agency is working closely with the RE to stem further staff losses, saying, “We are closely aligned on the issues as we move forward.”
He said staff are already working on the filing and are only waiting on final approval from the MRO board. “We have every incentive to move forward as quickly as we can. That’s in the best interest of everyone involved.”
McIntyre also said staff have collaborated with MRO and SERC to “ensure a high level of continuity during and after the transfer occurs.”
“I believe the level of staffing they have requested is correct and necessary to handle the number of entities that are transitioning,” he said. “We are confident … that both REs are capable of handling the oversight of the entities in their regions.”
MRO and SERC are both adding staff — including some from the SPP RE — to handle their additional responsibilities. NERC will also provide the REs with additional support.
“Staff has been working with both entities regarding their new responsibilities,” McIntyre said. “We’ve told both entities we would be enhancing our oversight in the next few months, to help them do the work.”
Registered entities were reassigned without looking at RTO or market boundaries, McIntyre said. (See NERC Assigns SPP RE Registered Entities to MRO, SERC.) He told the trustees that incumbent MRO and SERC entities will see only a small increase in cost, if that.
NRG Energy on Wednesday said it has agreed to sell several of its businesses in transactions that will bring the company $2.8 billion in cash and take $7 billion in debt off its books.
The deals, which NRG expects to close in the second half of the year, involve its renewables businesses, its interest in NRG Yield and its South Central Generating subsidiary.
The sales, which require numerous regulatory approvals, are part of the transformation plan that NRG launched last July in response to pressure from hedge fund Elliott Management and private investment firm Bluescape Energy Partners, which a year ago revealed they owned a 9.4% stake in NRG and said they believed its shares were “deeply undervalued and that there exist numerous opportunities to significantly increase shareholder value, including operational and financial improvements as well as strategic initiatives.”
NRG expects to announce more sales over the course of the year and is revising its total asset sales cash proceeds target under the plan to $3.2 billion.
Global Infrastructure Partners (GIP) agreed to buy NRG’s controlling stake and 46% interest in NRG Yield, as well as its renewable development and operations and maintenance businesses, for $1.375 billion in cash.
GIP is a $40 billion private equity fund that “makes equity investments in high quality infrastructure assets in the energy, transport and water/waste sectors where we possess deep experience and strong relationships,” according to the company’s website.
“We view each of the three acquired businesses — the [NRG Yield] stake, the O&M business and the development business — as highly complementary and well positioned to capitalize on the increasing market demand for low-cost, clean energy,” GIP Chairman Adebayo Ogunlesi said in a statement.
The sale is subject to antitrust review under the Hart-Scott-Rodino act and must be approved by FERC, the U.S. Department of Energy, the California Public Utilities Commission, the Connecticut Public Utilities Regulatory Authority and the Pennsylvania Public Utility Commission.
As part of the deal, NRG also has agreed to sell two assets to NRG Yield for about $407 million: the 527-MW Carlsbad Energy Center, a natural-gas fired power plant in Carlsbad, Calif., scheduled to come online by the end of the year, and the 154-MW Buckthorn Solar farm in Pecos County, Texas.
Additionally, NRG will sell its South Central business to Cleco Corporate Holdings for $1 billion in cash. The South Central unit owns and operates 3,555 MW in generation assets consisting of a 75% stake in the 300-MW Bayou Cove natural gas plant in Jennings, La.; the 430-MW Big Cajun-I natural gas plant in Jarreau, La.; the 1,461-MW Big Cajun-II coal and natural gas plant in New Roads, La.; the 1,263-MW Cottonwood natural gas plant in Deweyville, Texas; and the 176-MW Sterlington natural gas plant in Sterlington, La. NRG will lease back the Cottonwood plant through May 2025.
That sale is also subject to antitrust review and must be approved by FERC, the Committee on Foreign Investment in the United States and the Louisiana Public Service Commission.
Cleco Sees Big Growth from NRG Acquisition
Eric Schouest, vice president of marketing-South for Cleco Power, told the Gulf Coast Power Association’s MISO South regional conference in New Orleans on Thursday that his company’s acquisition includes full service wholesale power supply contracts for nine Louisiana cooperatives, five municipalities in Arkansas, Louisiana and Texas, and one investor-owned utility. “We serve about 23 of the 64 parishes in the state of Louisiana. It adds about 23, 24 new ones,” he said.
Environmental groups have moved to halt an attempted roll-back of Illinois’ emissions standards, which would weaken pollution limits for Dynegy’s coal-fired generation fleet within the state.
The Environmental Defense Fund, Environmental Law and Policy Center (ELPC), Natural Resources Defense Council (NRDC), Sierra Club and Respiratory Health Association last week filed a joint motion to stop the Illinois Pollution Control Board from holding hearings on the proposed emissions rule change until Dynegy completes its merger with Vistra in late April. (See Vistra Energy Swallowing Dynegy in $1.7B Deal.)
Dynegy Plant | Illinois 12th District
The nonprofits argue that Vistra has so far been uninvolved with drafting the Multi-Pollutant Standard rulemaking and won’t be bound to “any of Dynegy’s statements about how it would operate the plants were the rule to be implemented.”
In their motion, the groups say, “It is unknown whether, in a few months’ time, the new owners will wish to pursue the current proposed rule modifications, maintain the current rule, or propose additional or different modifications…In several months…Dynegy will no longer be the decision-makers.”
The groups further contend that while Dynegy’s proposed pollutant rulemaking is predicated on its need for financial relief, the company’s financial picture will be sunnier after the merger.
“The resulting company will have over $4 billion in equity and face an entirely different financial situation, undercutting Dynegy’s main argument for the rule change,” the organizations claim.
Dynegy attorneys worked with the Illinois Environmental Protection Agency last year to revise the state’s 2006 clean air standard for coal plants. The company is seeking to replace the current rate-based emissions limits with an annual cap on sulfur dioxide and nitrogen oxide emissions for the state’s coal fleet as a whole. If approved, the new sulfur dioxide limit would be almost double what Dynegy emitted last year, while the nitrogen oxide cap would be 79% higher. Additionally, the caps would not decline should Dynegy retire or mothball any plants. (See “Illinois EPA Rule Change Still in the Works,” Dynegy Auction Proposal Fails to Gain Ill. Lawmaker Support.)
Dynegy says it will not waver in its pursuit of aggregate annual tonnage caps and contends that the hearings should continue as planned.
“Dynegy’s focus is on business as usual. As a result of anti-trust laws, we have to operate independently of Vistra Energy. We believe the established hearing process that’s being conducted by the Illinois Pollution Control Board should continue,” said Dynegy spokesman David Byford.
More than that, Byford argued, the motion is bad for business in the state.
“The motion by the environmentalists sets a bad precedent and will have a chilling effect on anyone doing business or considering doing business in Illinois. Any prudent owner will undertake a number of internal and external initiatives to help the plants’ viability, and evaluate each plant on a stand-alone basis, just as any business — large or small — would do,” he said in an email to RTO Insider.
Byford also contends that the Illinois EPA estimates that allowable sulfur dioxide emissions under the proposed rule would be 17% lower than under the current rule, while nitrogen oxide emissions would be 24% lower. But environmental groups have said the draft rule will permit overall emissions to exceed those of Dynegy’s fleet in the last two years, and some predict the company will shutter its more expensive coal plants with modern pollution controls, allowing cheaper plants without scrubbers to run.
The groups also argue the rulemaking stands to benefit a company that will soon cease to exist.
“This motion will ensure that Illinois doesn’t rush to change important pollution standards that protect the health and environment of Illinoisans only to help a company that will no longer be in existence by the middle of this year,” said NRDC staff attorney Toba Pearlman.
“The Illinois Environmental Protection Agency has been talking to the wrong company. It’s time to put an end to this poorly conceived, backroom proposal to boost profits at the expense of public health,” said ELPC staff attorney Lindsay Dubin.
The Pollution Control Board held one hearing on the proposed rule change in Peoria last month, and has scheduled another for March 6 in Edwardsville.
Peak Reliability and PJM Connext on Tuesday refined their pitch to attract participants to a new Western energy market, saying they envision “a marketplace built by and for the West.”
“We sense, and we have heard, some people saying it’s coming down to the time for some choice in markets in the West again,” PJM Connext’s Fran Barrett said during a Feb. 6 meeting and conference call hosted by Peak. He added that PJM is “heavily, heavily focused on the bottom line.”
Barrett emphasized PJM’s experience operating a 13-state market in the East, and indicated a focus on reliability, self-governance and providing options for various market structures for potential participants. Officials from the organizations provided more detail on how the new Peak/PJM market would coordinate with other market and non-market areas, including possible congestion management practices.
Peak and PJM Connext this week outlined how their proposed market would coordinate with other market and non-market areas.
Peak and PJM first described their joint market initiative in January. (See Peak, PJM Detail Western Market Proposal.) In a presentation Tuesday, they laid out three possible market options “customized to the needs of participants,” each of which includes a nodal real-time market, day-ahead market, financial transmission rights, integrated settlement and credit management. Settlement would be based on PJM’s structure, modified for the West, with a central counter-party structure and weekly billing.
Interregional Coordination Proposed
Peak and PJM also provided more detail about how their proposed market would coordinate with other areas in the West. Their goal is to implement the market in two phases, the first using an “enhanced curtailment calculator” tool in a process comparable to the transmission loading relief procedure used in the Eastern Interconnection.
A second “market-to-market” phase would be more complex and similar to how PJM conducts coordination with MISO and NYISO. In those cases, the RTOs use combined redispatch as a joint congestion management tool for greater efficiency, and costs are allocated between RTOs based on transmission flows and negotiated historical rights.
Barrett said Peak and PJM did not know exactly what minimum size footprint or configuration would be necessary to make the proposal work, noting they were gathering data to study the issue.
“We haven’t modeled in the Swiss cheese or the string cheese or if we will have people all over the place,” Barrett said, describing the possible variable shapes of the market’s footprint.
RENSSELAER, N.Y. — New York’s Integrating Public Policy Task Force (IPPTF) hit resistance on the first paragraph when it unveiled its final work plan for pricing carbon into the state’s wholesale electricity on Monday.
That section sets out the plan’s intended purpose: to explore incorporating the costs of carbon into the market while “providing the greatest benefits at the least cost to consumers.”
Several stakeholders at the Feb. 5 meeting sought a clearer definition of “benefits,” while others wanted to know why the plan would focus primarily on benefits to consumers. In addition, some expressed concerns about how carbon pricing would translate into actual carbon reductions, given existing constraints within the state.
| DOE
The IPPTF is a joint effort of NYISO and the state’s Department of Public Service (17-01821). The group’s latest plan includes five issue tracks, reduced from six: 1) straw proposal development; 2) wholesale energy market mechanics (including “carbon leakage” and how to measure emissions) and interaction with other wholesale market processes; 3) policy mechanics, such as setting the carbon charge; 4) interaction with other state policies; and 5) customer impacts. (See New York Stakeholders Debate Carbon Policy ‘Issue Tracks’.)
Energy Market Primer
IPPTF co-chair Marco Padula, DPS deputy director for market structure, clarified that the group wasn’t created to review the contents of the state’s Clean Energy Standard but to achieve the objectives set out in the rule — namely, that 50% of New York’s electricity come from renewable energy sources by 2030.
Padula said the task force should work out the details of each track over the course of the year, as it posts reports from each meeting along with stakeholder comments. The task force will meet nearly every Monday to work through the tracks and plans to develop preliminary proposals by early August to deliver a unified proposal by December.
Erin Hogan, of the DPS Utility Intervention Unit, said the task force needs to better understand what goal is being discussed because state policy calls for 50% of the target to be met by energy efficiency measures, meaning “that renewables needed afterwards would be less.”
In the near future, stakeholders “should perhaps have a primer, maybe a little presentation just to level what exactly we’re talking about, so we don’t tie ourselves up in knots in the middle of meetings without having that level of understanding what the goals really are,” Hogan said.
Representing a coalition of large industrial, commercial and institutional energy customers, Couch White attorney Michael Mager reminded the task force of a key goal of the exercise.
“I don’t care whether you get to it now or when we get to the last track,” Mager said. “At the last meeting … there was some agreement in the room that, in addition to price impacts, we should also be measuring exactly what carbon abatement would be taking place. It doesn’t seem to have been reflected in the work plan, [which] still kind of limits the last track to customer impacts. It doesn’t seem to address anywhere actually measuring whether we’d be reducing carbon emissions at all.”
The Transmission-Emissions Nexus
The predicament of New York’s biggest metro area loomed large during the meeting. Ron Minsk, a consultant to New York City, delivered a presentation that emphasized the need for a new transmission to deliver renewable energy to the state’s largest load center. With a peak load of more than 11,500 MW, the city accounts for approximately 30% of the state’s load. The downstate region, including Long Island, represents about 50%. Minsk’s presentation echoed comments the city filed with the task force in January.
Transmission Congestion Corridors in New York State | City of New York
“We don’t want to end up having an approach where we have renewables displacing other renewables,” Minsk said. “So this gets to the transmission issues, which the city has expressed concern about before. It goes to that submission, making sure that the benefits are widely distributed. … Even with new transmission projects that are already on the books, there are transmission constraints that keep upstate power from getting downstate.”
The upstate grid is already pretty clean, with about 85% of generation carbon free, he said.
“In order to meet the state’s goals, you’re going to have to get more renewable power downstate, and, in order to do that, you have to relieve transmission,” Minsk said.
The city’s comments pointed out that NYISO has already drawn a similar conclusion, noting that even if the state adds the desired quantity of new renewables by 2030, it will not realize their full benefits without new transmission or local storage resources — or if renewable development occurs far from load centers.
Mark Younger of Hudson Energy Economics said more renewable generation will provide no consumer benefits whatsoever if it’s built in the wrong location.
Modeled future carbon intensity (tCO2e/MMBtu) of the electric grid with ranges based on changes to NYC electric demand. | City of New York
“Maybe the proper way to look at it is how are you getting the cheapest dollar per ton reduction, considering that to serve New York City and the southern area, [either] you’re … paying directly for generation there or you’re paying for generation somewhere else and the infrastructure that’s necessary to get there,” Younger said.
The transmission infrastructure is part of the price of achieving the desired carbon reduction, he said.
“You can’t ignore that infrastructure because … it looks very cheap to build all your renewable resources far away, but then incur billions of dollars that you don’t recognize as part of that decision to build the resources far away,” Younger said.
The task force next meets Feb. 12 at NYISO headquarters.
MISO on Tuesday opened a bidding window for its second-ever competitive transmission solicitation, a process required under FERC Order 1000.
Developers will be eligible to bid on the $130 million, 500-kV Hartburg-Sabine Junction project in eastern Texas until July 20. The congestion-relieving line and substation are slated to be in service by June 1, 2023.
Hartburg to Sabine Junction project | MISO
MISO’s Board of Directors last week granted late approval for the project under the RTO’s 2017 Transmission Expansion Plan. (See MISO Board Approves Texas Competitive Tx Project.) MISO expects to select a developer by the end of the year and post a full report on its evaluation no later than Jan. 30, 2019.
“When completed, this project will help bring economic benefits to a transmission-constrained area of Texas,” said Kent Fonvielle, executive director for MISO’s South region.
MISO will judge the proposals based on weighted criteria, which include cost and design, project implementation, operations and maintenance, and participation in the planning process. The RTO has revealed that 11 potential developers will already receive the 5% planning participation credit for suggesting the Hartburg-Sabine project in MISO’s annual Market Congestion Planning Study. They include Ameren Transmission Company of Illinois, Duke-American Transmission Co., East Texas Electric Cooperative, Entergy Texas, Grid America, ITC Holdings, Midcontinent MCN, Midwest Power Transmission Arkansas, NextEra Energy Transmission, Transource Energy and Xcel Energy.
Each proposal requires a $100,000 fee before MISO will begin considerations.
Prospective developers are required to communicate about the project using MISO’s TDQS@misoenergy.org email address and are instructed not to contact any RTO personnel directly. As with its first competitive transmission project in 2016, MISO will publicly post all developer questions and any answers it can provide on its competitive administration webpage. MISO will accept questions about the request for proposals until June 25 and will hold three informational meetings by conference call on Feb. 27, April 9 and May 29.
MISO has redacted some critical energy infrastructure information from the public version of its RFP, including interconnection requirements, some of Entergy’s local planning criteria, the coordinates of the new substation and aerial views of existing lines in the area.
CAISO’s operating revenues jumped 4.4% to $214 million last year on the back of increased Energy Imbalance Market (EIM) earnings and an uptick in summer activity.
The ISO reported “true operating income” (operating revenue minus operating expenses) of $47.4 million for the full year, compared with $44.4 million in 2016. True operating income fluctuates throughout the year as a large portion of revenue comes in the summer, when energy demand and prices are higher.
CAISO is a nonprofit corporation that earns the bulk of its revenue from a grid management charge (GMC), composed of market services, system operations and congestion revenue rights charges assessed by the megawatt-hour. The ISO also collects other charges and fees, including those for trades between scheduling coordinators. It additionally operates the EIM.
Including depreciation and amortization, CAISO’s fourth-quarter report showed a $6.9 million net operating income “loss,” but spokesman Steven Greenlee said that is “merely an accounting outcome.”
“The level of net operating income has no effect on our cash flow, budgeting or grid management charges,” Greenlee told RTO Insider.
CAISO collected $47.3 million of its operating revenue from its GMC in the fourth quarter, up from about $45.8 million the previous year. Other operating revenues totaled $4 million during the last quarter. GMC revenue for 2017 grew by 3% to $198.3 million and was higher than what CAISO had budgeted.
August Sees Highest Take
CAISO’s gross market revenues for all services going through the ISO market peaked at $1.2 billion in August, the period of highest summer demand and when the ISO dealt with the impact of the solar eclipse on solar generation. (SeeGrid Operators Manage Solar Eclipse.) Revenues fell to their lowest in February, at slightly more than $500 million.
The gross revenue figure represents the total value of all energy transactions and related services included on ISO invoices. CAISO recoups its costs through the GMC, which is a small component of these overall market revenues, the ISO said.
Q4 Expenses Grow
The ISO’s fourth-quarter operating expenses were $51 million, up about 16% from the same period a year earlier. Expenses include salaries and benefits to employees, building and facility costs, insurance, outside contractors, legal and auditing services, training, travel and professional dues.
CAISO’s expenditures for consulting and contracting services grew by $2.9 million quarter-over-quarter to $7.2 million. Third-party vendor contracts rose from $2.6 million to $3.5 million between the same two periods.
CAISO’s expenses grew by $7 million, or 67%, compared with fourth quarter 2016
While expenses grew, they were $7.1 million less than CAISO had budgeted for the year. The ISO cut salaries and wages by about $1 million quarter-over-quarter and had lower “building, leases and facilities” costs, and lower legal and auditing expenses. The ISO cut three full-time positions in 2017, leaving the headcount at 599.
Revenue Exceeds Budgeted Level
Fourth-quarter operating revenues exceeded the budget by $7.5 million, mostly because of EIM administrative charges and forecasting fees beating projections, the ISO said.
CAISO’s Corporate Management Committee approved $19.5 million in projects last year to increase electric system performance and to meet FERC mandates, the ISO said. These include market improvements, technology, customer service, grid readiness and other funds.
The ISO on Jan. 3 had $1.9 billion in collateral from market participants to support $294 million in aggregate liabilities in the market.
In a potential victory for merchant transmission developers, a FERC administrative law judge has concluded that PJM’s system impact study (SIS) process is unjust and unreasonable because of a lack of transparency (EL15-79).
ALJ Philip C. Baten’s Jan. 19 initial decision ordered PJM to reinstate three interconnection queue positions he said were unfairly eliminated when developer TranSource refused to pay for a facility study, the next stage of its interconnection process after the SIS. He also ordered the refund of TranSource’s SIS application fees.
Baten dismissed several other remedies TranSource — not to be confused with Transource Energy, a joint venture of American Electric Power and Great Plains Energy — sought, including its claim for $63.6 million in “lost business” opportunities. Parties have 30 days to file exceptions to Baten’s decision.
PJM spokesman Ray Dotter said the RTO will challenge the ruling.
“We have concerns about the judge’s proposed remedy to put the project back into the planning queue because it would be disruptive to other interconnection customers with pending projects,” he told RTO Insider. “PJM has looked at and revised its processes. We have made great progress on the identified transparency points. As the next step in the proceeding, we will file with the commission a brief on exceptions to the initial findings.”
Inflated Costs?
TranSource filed a complaint in June 2015 contending that PJM and transmission owners Public Service Electric and Gas, PPL, Jersey Central Power & Light and Delmarva Power & Light inflated the cost of upgrades necessary to approve three requests for incremental auction revenue rights (IARRs). (See Transmission Developer: PJM TOs Inflating Upgrade Costs for ARRs.)
Baten said he could not determine whether the $1.7 billion in upgrades PJM identified were indeed necessary, noting that the case focused on the impact studies, which are supposed to produce only “good faith” cost estimates.
But he sided with FERC trial staff in faulting PJM for failing to provide transparency throughout TranSource’s efforts to secure IARRs for making upgrades that would reduce congestion on the transmission grid.
TranSource’s upgrade proposals used facility ratings from FERC Form 715 filings made by PJM on behalf of the TOs. Baten said that was a “reasonable” assumption based on “statutory and regulatory provisions” and language in PJM’s Tariff.
But the RTO testified its cost estimates were based on the line ratings expected at the time that the project being studied would be in service — including planned upgrades.
PJM’s estimates also incorporate the host TO’s review of limiting elements based on the methodologies they file under NERC reliability standard FAC-008-3. The methodologies are not public and not the same as those used for Form 715, Baten said.
A TranSource witness, electrical engineer Dale Douglass, testified in the case that FirstEnergy’s FAC-008-3 ratings methodology was “clear and logical” but that the other three TOs did not clearly specify the maximum conductor temperature used to determine the line ratings.
“For some years the commission has fostered policies to pry open the transmission grid to greater competition. … The commission does recognize that interconnection customers should be able to reasonably estimate their cost before entering the queue,” Baten wrote. “Nowhere in the PJM [Open Access Transmission Tariff], Operating Agreement, or manuals or any written manifestation, which may be presented to outside parties, does PJM explain or indicate that the FERC Form 715 ratings are not used to process IARR requests. … The evidence is sufficient to show that TranSource was not advised of these parts of the model within a time frame to afford it the opportunity to make sound business judgments.”
Readington-Roseland Line
A primary conflict was over estimates for upgrading PSE&G’s Readington-Roseland 230-kV line in New Jersey.
PJM’s analysis of transmission upgrade requests under Tariff Attachment EE is done in two steps. The SIS provides developers with an estimate of what their plan will cost with +/- 40% accuracy.
Analyses of the condition of the Readington-Roseland line was a source of contention in the TranSource case | PJM
The first component of the SIS is the simultaneous feasibility test, in which PJM tests whether the developer’s IARR request can be accommodated without diminishing the income of the current ARR holders. After that, PJM identifies the facilities that are impacted by the IARRs and the relevant TOs conduct “desk-side” studies — so called because they do not involve site visits — using the confidential methodology to identify upgrades needed to accommodate the IARRs and their estimated cost.
If the developer chooses to proceed based on the SIS results, PJM conducts an in-depth facilities study that requires a refundable deposit of at least $100,000 and is supposed to provide a more accurate itemization of required upgrades.
A facilities study done for Exelon in late 2014 pegged the cost to repair the Readington-Roseland line at about $14.2 million. Although the towers had been in service for 80 years, “based on visual observation only, tower replacements are not anticipated,” the study said.
Branchburg — Pleasant Valley Transmission Tower Damage | PJM
But an SIS done for TranSource six months later increased the estimate more than nine times to nearly $126.5 million. When Richard Crouch, a PSE&G electrical engineer, reviewed the project three months later, he called for a complete wreck and rebuild for more than $142.7 million, a $16 million increase that he couldn’t adequately explain, the decision said. In his testimony, Crouch said he based his replacement decision on his “institutional knowledge” of the conditions of several other lines that are similar in age and terrain, which he used as surrogates in his own “desk-side” study.
By 2016, PSE&G engineers had put the line on its list of facilities violating the company’s Form 715 end-of-life criteria.
“If the line had such a dire status by 2016, it could not have been in a better condition in 2014 when the [TranSource study] began. The FERC Form 715 of that earlier period should have noted the condition,” Baten wrote. PSE&G “did not timely report the end-of-life condition of this line on FERC Form 715.”
“PSE&G follows the FERC-approved PJM process for all planning decisions, including with regard to the facilities discussed by Judge Baten in the TranSource decision,” spokesman Mike Jennings said.
TranSource contested the SIS for Readington-Roseland and its other requested upgrades, saying it lost financing because of what it called PJM’s “badly inflated” estimates. The RTO eliminated TranSource’s queue positions when it refused to pay for the studies.
Unduly Discriminatory
Baten ruled that the lack of transparency in PJM’s SIS process made it “unduly discriminatory” to merchant developers by depriving them of business opportunities. He noted that, because IARRs were implemented in 2007, only two projects out of 100 submissions under two separate Tariff sections have been awarded IARRs.
The judge said that trial staff generally sided with PJM in the case, but that a staff witness, economist C. Shelley Norman, agreed that “PJM’s process for reviewing and evaluating IARR requests was significantly lacking in clarity and transparency.
“Even PJM’s witness David Egan [manager of the Interconnection Projects Department] agreed during his deposition,” Baten added.
“PJM’s lack of clarity and transparency in its IARR study process has likely caused systemic issues and contributed to the low completion rate of successful merchant IARR projects,” wrote Baten, who noted the record included hundreds of pages of email correspondence between TranSource and the RTO between June 2013 and March 2015. PJM’s “dribbling out of piecemeal information over time … is not consistent with the level of transparency that the commission orders have envisioned. … These obvious failures in this case are indicative of a severely flawed SIS process.”
Revised IARR Manual
During the hearing in the case, PJM and its Independent Market Monitor developed a manual detailing the procedures that the RTO followed to determine the TranSource upgrades. Baten said that although the manual was intended to improve transparency, it “does not provide any methodologies that the TOs use or will use to rate their facilities when they get the request from PJM to determine the extent and any necessary upgrades to meet an IARR request.”
Because the manual was not litigated at the hearing, Baten said he could not rule on whether it is sufficiently transparent.
“The commission on its own motion may order that PJM should offer the manual to a stakeholder process for proper vetting. At this point, the manual represents the efforts of PJM and the IMM to clarify the IARR process. On its face it does neglect a discussion of the role of the TOs in the process. More flaws could be undiscerned at this point in its development.”
Two-Stage SIS?
The judge rejected as beyond the scope of the docket TranSource’s request that PJM add another phase of impact studies before the facilities study so that requests by merchant transmission developers are handled in the same manner as requests for generation interconnection studies. Baten said the commission “should consider” TranSource’s request. PJM’s Planning Committee began a discussion on whether an additional study phase is necessary in September. Tariff revisions, which include replacing an initial study for projects with a feasibility study prior to an SIS, were approved by the Markets and Reliability Committee in December and the Members Committee in January. PJM plans to present additional manual revisions at Thursday’s Planning Committee meeting. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
VALLEY FORGE, Pa. — One thing is clear in the PJM turf war over control of the transmission replacement process: Neither side is conceding an inch until a FERC decision forces them to.
Representatives of transmission owners and their customers once again staked their claims at last week’s meeting of the Transmission Replacement Processes Senior Task Force (TRPSTF). TOs argued it’s their sole right and responsibility to manage their infrastructure, while transmission customers called for increased transparency of the processes TOs use to determine when towers and other equipment should be replaced. The projects are part of a class of transmission development that doesn’t require PJM approval, known as “supplementals.”
PJM staff stuck to a strict definition of the RTO’s role over such projects.
“We look at the reasonability of the information [TOs provide] and that they have followed the procedures that have been specified, but validation is a much stronger word,” Vice President of Planning Steve Herling said. “We validate that they follow their procedures. We cannot validate the individual elements of the actual material condition.”
The task force has made little progress since it was chartered in May 2016 to “develop alternatives for providing more transparency and consistency in the communication and review of end-of-life projects in the Regional Transmission Expansion Plan.” (See PJM Demands Agreement on Tx Replacement Definitions.)
FERC issued a show cause order in August 2016 questioning whether PJM TOs’ procedures for planning supplemental projects provided stakeholders opportunity for “early and meaningful input and participation,” as required by Order 890 (EL16-71). TOs included in their response a proposed addition to the Tariff known as Attachment M-3, which they argue would improve transparency.
The show cause order precipitated a 10-month hiatus of the task force, which ended in July. Since then, American Municipal Power and Old Dominion Electric Cooperative — who say they are advocating for their customers — have proposed an alternative to Attachment M-3 that would give PJM more say over when and how TOs can replace aging equipment. Currently, TOs fully control that process through Form 715.
The sides spent much of last week’s meeting walking through AMP and ODEC’s responses to questions TOs had posed about their proposal. The TOs argued that many of the AMP/ODEC provisions violate PJM’s governing documents and the organizational structure TOs agreed to when they joined the RTO. Exelon’s Gary Guy and Gloria Godson led much of the TO criticism.
“I cannot agree to” the AMP/ODEC proposal, Guy said. “We subjected ourselves to PJM, to their operational control … but not to any other third parties, and we’re not going to use the Tariff of PJM to write rules of compliance between us and third parties.”
PJM staff maintained their neutrality, saying that they expect TOs to provide explanations of their decisions but not information necessary to replicate their studies. Staff said the control they have over projects needed to address system reliability issues — known as “baseline” projects — doesn’t extend to supplementals.
“If it’s a baseline project, we get involved in that conversation [on sizing and specifications]. If it’s a supplemental … I don’t believe we have a role,” Herling said.
“I maintain my water heater … but after a while, when the bottom fell out of it, I went ahead and I had to get a new one. But I’m not characterizing my new water heater as maintenance,” AMP’s Ed Tatum said.
“You may choose to replace your water heater when the bottom falls out. Others may choose to replace it when it starts to get rusty on the top,” PJM’s Paul McGlynn responded.
PJM staff then walked through proposed solutions they developed internally. The proposals received substantial feedback from stakeholders, but TOs clarified at the end that their engagement didn’t represent approval.
“We’re not negotiating against our [M-3 proposal] in the FERC docket,” PPL’s Frank “Chip” Richardson said. “PJM’s proposal may go well beyond what transmission owners filed in that docket. We don’t know yet. We have to take it back and look at it.”
The D.C. Circuit Court of Appeals ruled Friday that FERC failed to adequately explain why it approved capacity market rules for ISO-NE in 2014 like those it had rejected in PJM for suppressing prices.
The Feb. 2 ruling granted petitions for review by Exelon and the New England Power Generators Association on rules allowing new suppliers to lock in their first-year clearing prices for six additional years while requiring them to offer at $0 in years 2 through 7 (15-1071).
“On the record before us, we conclude that FERC did not engage in the reasoned decision-making required by the Administrative Procedure Act,” the court said. “FERC failed to respond to the substantial arguments put forward by petitioners and failed to square its decision with its past precedent.”
PJM Ruling
NEPGA and Exelon contended the rules reduce clearing prices paid to both new and existing suppliers.
The petitioners said the commission’s approval of the rules is at odds with its 2009 ruling rejecting a similar construct in PJM (ER05-1410, et al.). In the 2009 ruling, FERC ruled that zero-price bidding would result in unjust and discriminatory pricing. It said a bid-floor was needed to ensure that a price-locked new entrant “will not reduce [the] price to the existing resources by submitting a $0 bid in years 2 and 3, knowing that it is guaranteed to be paid its first-year bid price no matter what it bids.”
NEPGA and Exelon contend the New England rules are likely to result in more severe price suppression than would have occurred in PJM, which has only a three-year lock-in. In addition, the lock-in — available to any new market entrant in New England — was rarely triggered in PJM.
No ‘Reasoned Analysis’
The opinion by a three-judge panel led by Robert L. Wilkins said FERC “brushed aside the seeming contradiction” between its ISO-NE and PJM rulings.
New England Dispatch Zones | ISO-NE
“FERC’s responses to petitioners’ arguments below amounted to conclusory statements that dismissed petitioners’ concerns without providing reasoned analysis. To respond to petitioners’ main contention that the ISO-NE Tariff rules suppressed prices and discriminated against existing suppliers in a way that the commission rejected in PJM, FERC first stated that conditions in the two markets were different, and then pointed to the vertical demand curve in place at the time under the ISO-NE Tariff. The commission issued this explanation despite the fact that it issued an order the very same day adopting an ISO-NE proposal to start using a sloped demand curve.”
The petitioners argued that the commission should have either rejected ISO-NE’s lock-in rules, required it to eliminate the zero-price offer requirement when it accepted a sloped demand curve or found another way to address the price suppression for existing suppliers.
The court noted that FERC cited “numerous cases to stress the broad array of practical difficulties to balance and interests to consider, including higher consumer prices, reliable price signals, producer flexibility, producer confidence, system reliability, and increasing system capacity and efficiency.”
“FERC contends that it truly has changed its view about the lock-in and capacity-carry-forward rules since its PJM decision and even doubled down by suggesting at oral argument that it would be more receptive to the Tariff changes at issue in PJM if they were proposed today,” the court said. “All this may be true. But FERC’s complex mandate doesn’t relieve it of the requirements of reasoned decision-making. … Although FERC may be sincere in its change of heart and, as a substantive matter, correct that its new rationale is just and reasonable, the commission must provide some analysis and explanation in its orders regarding why it changed course.”
The court declined to rule on whether the petitioners had met their burden to demonstrate that the ISO-NE rules resulted in unjust and unreasonable rates. But it said, “FERC must provide a more robust rationale for its seeming inconsistency with past precedent and practice.”
