Page 1328 – RTO Insider

May 1, 2017

Utility Proposal Would Increase Legacy Costs for California CCAs

By Robert Mullin

Californians who receive their electricity service from one of the state’s growing number of community choice aggregators (CCAs) could face higher costs under a plan being proposed by the state’s three investor-owned utilities.

The proposal — filed jointly by Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — calls for the California Public Utilities Commission to adopt a new approach to apportioning the utilities’ costs for energy contracts among the departing and remaining customers.

community choice aggregator california utilities — Wind farm near Palm Springs, Cal. | © *RTO Insider*

Utility customers departing for CCAs and direct access arrangements “are not paying their full share of costs associated with the long-term contracts [for renewables], forcing other customers to pay more,” PG&E said in a statement. California’s direct access program allows nonresidential retail customers to purchase power from independent electricity suppliers.

The new plan would replace the PUC’s current formula for calculating those costs — the power charge indifference adjustment (PCIA) — with a new system the utilities call the portfolio allocation methodology (PAM).

The PCIA acts as an exit fee, requiring customers departing for CCA to pay for their estimated share of the contracts IOUs signed to meet California’s energy policy mandates, such as the renewable portfolio standard and energy storage requirements. The fees are assessed until the termination of the contracts. Departing customers also pay a competition transition charge (CTC) that represents their share of a utility’s costs for older fossil fuel generation.

‘Financially Indifferent’

The fees are designed to keep the IOUs’ remaining bundled service customers “financially indifferent” to the departure of CCA customers, the PUC has said.

The PCIA’s calculation relies on an estimate of “above-market” costs incurred by the IOUs for procuring or building policy-driven resources.

But the utilities see a problem with that approach. The PUC bases its “above-market” cost assessment on administratively defined benchmarks developed during a time when prices for renewable energy credits and resource adequacy were higher than they are today. That makes the IOUs’ portfolios appear cheaper than they actually are, the utilities contend.

“This directly translates into departing load customers paying PCIA and CTC rates that do not fully pay for their share of the actual above-market costs of the portfolios, which is contrary to law,” the utilities said.

Under the utilities’ PAM proposal, departing customers would be charged based on the “actual” costs for the contracts procured on their behalf. On the flip side, those customers would also be allocated the “actual value” of contract portfolios, including RECs, capacity credits and revenues generated from providing ancillary services.

Under the new methodology, rates for the contracts would be regularly trued-up in the same manner as those charged to the IOUs’ remaining bundled customers, although the utilities note that most of the agreements in question are fixed-cost.

The IOUs are proposing to implement PAM on a “vintaged-portfolio” basis that depends on the customer’s departure date, “ensuring that all customers are only assigned the costs and benefits of resources actually procured or built on their behalf.”

“We can achieve the state’s clean energy goals while also supporting customer choice and treating all customers fairly and equally,” said Steve Malnight, PG&E’s senior vice president of strategy and policy.

Consumer Protections Needed

Woody Hastings, renewable energy implementation manager for the Santa Rosa-based Center for Climate Protection, told RTO Insider his support for the proposal would in part depend on whether it contains adequate consumer protections. “We have long held that the PCIA is broken,” he said.

Hastings said that while his organization agrees with the concept of bundled ratepayer indifference, his assessment of the plan would come down to exactly what expenses the utilities would roll into the new methodology.

“We need some kind of assurance that avoidable costs are being avoided,” Hastings said. “A third-party audit should happen [in order] to show that the numbers being presented are valid.”

In their filing, the utilities said they will seek approval to develop a formal process to provide load-serving entities with access to portfolio and contract data as part of the PAM.

“PAM is transparent, objective and fully consistent with California law … and should be expeditiously adopted by the commission,” the utilities wrote.

May 1, 2017

FERC Seeks More Details on MISO Pseudo-Tie Proposal

By Amanda Durish Cook

FERC staff wants more details on MISO’s proposed pro forma pseudo-tie agreement, which the RTO hopes to begin enforcing in June. On Friday, staff issued a deficiency letter posing 10 questions to the RTO — some of which echoed concerns stakeholders raised in December. (See MISO Stakeholders Narrowly Support New Pseudo-Tie Rules.)

The proposal would allow proposed pseudo-ties to be rejected and existing ones revoked if a market-to-market flowgate is not within 2% of MISO and the neighboring market’s calculated generator-to-load distribution factor.

The rules also require market participants to agree to a congestion management plan with both RTOs prior to pseudo-tie implementation and to maintain long-term firm transmission service requests from source to sink for the life of the pseudo-tie. New transmission service requests would have to be submitted a year in advance. The agreement also opens approved pseudo-ties up for restudies when changes to the source or sink occur.

FERC’s questions asked for details in particular about the generator-to-load distribution factor threshold, the transmission service request requirement and MISO’s attempts to coordinate with PJM before filing the proposal in February.

Coordination with PJM

FERC staff asked “the extent to which MISO worked with neighboring balancing authorities” ― in this case, PJM ― in developing the protocol, including the right to terminate pseudo-ties and the requirements for firm transmission. They asked MISO to list which issues were discussed and which were still unresolved at the time of its filing, and to describe any efforts to include the agreement in the RTOs’ joint operating agreement.

PJM filed a protest to the proposed pro forma, complaining that it had not been given input in MISO’s rulemaking process.

“Please explain why the proposal includes only one balancing authority (i.e., MISO) as a signatory to the agreement, when both the native and attaining balancing authorities are impacted entities in a pseudo-tie arrangement,” staff asked. “How does such proposal adequately address the concerns of other entities involved in the pseudo-tie arrangement related to the agreement?”

Stakeholders asked MISO late last year if the RTO would attempt to memorialize a version of its agreement in the JOA, but staff said at the time that there was no need to do so. MISO Senior Director of Regional Operations David Zwergel said in April that the two RTOs were considering adding coordinated pseudo-tie policies to their JOA.

Termination Process

Staff want to know more about MISO’s process for terminating a pseudo-tie. They asked what notification or coordination MISO would use with the involved balancing authority and also asked if terminating the agreement would have the same results as terminating the pseudo-tie, as MISO used both phrases in the agreement.

Distribution Factor

MISO’s explanation of its 2% generator-to-load distribution factor threshold seemed too vague for FERC staff. They asked how the RTO would account for modeling differences between balancing authorities and how it decided the 2% figure was appropriate. In the agreement, MISO proposed comparing its generator-to-load distribution factor to either an interchange distribution calculator or the other balancing authority’s generator-to-load distribution factor, and FERC staff asked how MISO would decide which one to use.

Application to Existing Pseudo-Ties

Staff want clarification on whether the new rules will apply to existing pseudo-ties, pointing out that MISO contradicted itself in the agreement language by saying that existing pseudo-ties could be revoked if the generator-to-load distribution factor doesn’t line up within the 2% while writing, “MISO proposes that the requirements outlined in the agreement will not be retroactively applied to existing pseudo-ties.”

“Does MISO’s proposal intend to apply … to existing pseudo-ties that were implemented prior to the effective date that the pro forma agreement was added to the Tariff?” staff asked.

In previous stakeholder meetings, MISO staff have said that while the RTO doesn’t envision having to revoke any existing pseudo-ties based on the 2% threshold, it wants the right to rescind existing pseudo-ties in case an attaining RTO drastically changes its model and large discrepancies between models occur.

Firm Transmission

The firm transmission requirement is also a source of ambiguity, FERC staff said. They asked if pseudo-ties would be de facto cut off if a transmission service request (TSR) expires, and if pseudo-ties would be suspended in the time it takes to transition an old TSR to a new one. What happens, they asked, to pseudo-ties granted approval before the new pro forma but not yet holding TSRs, or pseudo-ties without TSRs that have cleared the capacity auction?

Restudies

MISO must provide FERC proposed conditions for the restudy of pseudo-ties, with more detail around “circumstances under which changes to the source or sink data could occur that would require a restudy of the TSR,” FERC said.

The RTO also has to establish who will be responsible for the cost of network upgrades if a restudy shows they are needed.

Staff also asked that MISO describe the operational and dispatch data it receives from pseudo-tied generators and how often it gets such data.

The RTO has 45 days to respond to the commission’s questions.

Future of Pseudo-Ties

FERC’s questions come as the future of pseudo-ties themselves is threatened. MISO Market Monitor David Patton filed a Section 206 complaint April 6, claiming that the increasing use of pseudo-ties degrades reliability, hampers efficient dispatch and raises costs. He asked FERC to eliminate PJM’s existing pseudo-tie definition (EL17-62). (See Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal.)

MISO has predicted that about 2,800 MW of its generation will pseudo-tie into PJM in the 2017/18 planning year beginning June 1.

May 1, 2017

NYISO Management Committee Briefs

RENSSELAER, N.Y. — NYISO achieved a wind energy record of 1,574 MW at around noon on March 2, representing 9% of the state’s power generation, COO Rick Gonzales told the Management Committee on Wednesday. The record production came six days before powerful storms lashed Rochester and other parts of western New York. Rochester Gas & Electric reported four wind gusts on March 8 that were in the top 10 ever recorded in Rochester.

NYISO management committee con ed black start — Workers clean up after the wind storm | *Office of Governor Andrew Cuomo*

The high wind storm event led to multiple transmission line outages, prompting NYISO to reduce both West Zone generation and Ontario imports to manage system reliability. More than 30,000 households were left without power for days.

In his operating performance report, Gonzales also said that NYISO had reduced production costs by $5.5 million so far this year through congestion coordination with PJM under the ISO’s Broader Regional Markets initiative.

LBMP up Almost 70% over March 2016

Locational-based marginal prices (LBMP) averaged $34.97/MWh in March, an almost 70% increase over the $20.66/MWh a year earlier and a $4 increase over February.

The year-to-date average through March was $37.81/MWh, a 23% increase from $30.68/MWh a year ago.

The rise in power prices was less dramatic than that in natural gas. Prices at Transco Z6 NY averaged $3.49/MMBtu in March, up 169% over the prior year.

Con Ed Black Start Testing Increased

The Management Committee voted to increase testing for black start generating units in Consolidated Edison’s service territory.

Under Tariff changes approved by the committee, all Con Ed black start units must fully test every year, rather than every other year. The units will be required to energize a transmission bus. Synchronization testing and partial testing of steam units are eliminated under the new procedures. Post-test supplemental resource evaluation running of the steam units is also eliminated, as it would necessitate synchronization.

con ed black start nyiso management committee — ConEd plant on the East River at 15th Street in Manhattan, New York City

The change will bring the Con Ed territory into compliance with NERC reliability standard EOP-005 for black start testing, David Mahlmann, the ISO’s operations manager, said at the meeting on April 26.

Con Ed registered as a NERC transmission operator in July 2016. Previously, the utility had been operating only under the black start rules of the New York State Reliability Council. The council has updated its testing requirements to comply with the NERC rule and directed the ISO to change its rules.

The motion approved by the committee recommends that the NYISO Board of Directors authorize a FERC filing of the Tariff changes reflecting the new testing requirements, which were also incorporated in the ISO’s system restoration manual.

Liam Baker of Eastern Generation expressed concern about incremental costs resulting from the increased testing. “Do I have to file a [Section] 205 at FERC every time I make a capital improvement?” he said. “It might not be millions of dollars but tens of thousands, and it gets ridiculous when you have to hire counsel for a small amount.”

NYISO Assistant General Counsel Carl Patka said that incremental unit cost compensation is outlined in the Tariff, which “says that the generator will submit to the ISO its actual costs incurred, and the ISO together with FERC has 30 days to respond.”

Customer Satisfaction High

Market participants and customers are generally happy with their interactions with NYISO, according to the grid operator’s biannual customer satisfaction survey, conducted by the Siena College Research Institute (SRI).

SRI Director Don Levy told the Management Committee the ISO received a 98.8% “customer inquiry satisfaction” score on the survey, which had a response rate of 31%. The respondents were those who had made inquiries of the ISO on any subject, whether concerning an invoice or a Tariff detail.

The ISO’s rating on market participant satisfaction was lower, at 78% on a response rate of 23%. The 354 participants included end users, generation owners, other suppliers, public power and environmental entities, and transmission owners. There was brief debate at the meeting as to whether the lower score qualified as a B- or a C+.

Levy said the two surveys resulted in a combined score of 88.5%.

The surveys identified several areas in which NYISO could improve, according to Levy:

Tariff, legal and regulatory webpages;
ISO manuals, technical bulletins and user’s guides;
Market mitigation and analysis interactions;
Transparency of operations; and
Increasing the consideration of stakeholder input.

Respondents said the ISO’s strengths included accurate customer settlement invoices; timely responses to credit department inquiries; staff’s professionalism; fair handling of all interactions; and the communications department.

NYISO Switching to NAESB Digital Certificate May 1

Beginning May 1, NYISO will no longer accept its own certificates for Market Information System (MIS) applications, instead requiring a valid North American Energy Standards Board (NAESB) digital certificate, Stakeholder Services Team Lead Diana Ortiz said.

“As we speak, we are updating the wildcard SSL server certificates for all MIS production applications,” Ortiz said. The ISO has been transitioning to the new system since last year to be fully compliant with FERC Order 676-H by May 15. (See FERC Backs NERC, NAESB Standards.)

NYISO stopped issuing its own certificates for MIS applications on March 1, and about 85% of market participants have already completed the transition process. A significant portion of those who have not made the switch no longer need access to MIS applications, Ortiz said. Anyone in doubt as to their status can contact Stakeholder Services for assistance by calling 518-356-6060, sending an email to stakeholder_services@nyiso.com or using the live chat feature on www.nyiso.com.

— Michael Kuser

May 1, 2017

MISO Informational Forum Briefs

CARMEL, Ind. — In spite of higher outages, some instances of severe weather and more expensive natural gas, MISO staff reported smooth market operations overall in March.

Systemwide energy prices averaged $29.51/MWh in March, about 50% higher than March 2016. The increase was owed mostly to an increase in natural gas prices, which jumped 63% from a year earlier, MISO said at an April 25 Informational Forum. Day-ahead prices averaged $29.44/MWh for the month. Natural gas prices at the Henry Hub and Chicago Citygate rose about $1/MMBtu from last March.

Colder temperatures in the MISO footprint drove load to an average 70.8 GW during March, a 2.4-GW year-over-year increase.

miso informational forum natural gas prices — Chatterjee | © *RTO Insider*

MISO Executive Director of System Operations Renuka Chatterjee said markets easily navigated an 88-GW load peak on March 15, even with planned and forced outages hitting a total 43.4 GW, a product of the spring maintenance season. She also said markets were largely unaffected by tornadoes and thunderstorms in MISO’s South and Central regions.

However, 14.6 GW of forced generation outages and high load drove up congestion, leading to real-time LMP spikes at the Texas and Louisiana hubs, hitting $54/MWh and $40/MWh, respectively. As a result, MISO monitored deviations between day-ahead and real-time pricing for the month. Price divergence averaged 24%, compared to last March’s 12%.

MISO also paid extra attention to its scheduling of units for the month after a unit was unnecessarily given a delayed stop time on March 12. Chatterjee said the inefficient scheduling of just one unit caused the metric to be flagged for monitoring.

“That goes to show how tight these metrics have become,” she said.

NERC Official: Shifting Resource Mix Could Mean Standards Revision

Some reliability standards could use an update to reflect the increasing adoption of renewable generation sources, NERC Chief Reliability Officer Mark Lauby said in a report on the organization’s 2017 reliability leadership summit in March.

Lauby said the existing AC system will have to accommodate a changing resource mix in the near term and grid operators will have to make sure enough energy is on hand. Shifting resources may require a revision of some standards, Lauby said, such as NERC’s revised definition for the Bulk Electric System, which includes thresholds of 20 MW for individual facilities and 75 MW for aggregate facilities.

“We’re going to be working with industry to review these standards and see what … standards need updating,” Lauby said. “I just worry about the speed. I don’t want to look in the rearview mirror and wish I would have done something. It’s going to take some good analysis.”

He said NERC also wants to make sure that state regulators fully understand the impacts of any renewable portfolio standards they might pass.

“When it comes to standards for reliability, I think of what Scotty said to Captain Kirk [in “Star Trek”]: ‘I can’t change the laws of physics,’” he joked.

MISO Deputy General Counsel Eric Stephens asked what industry employees can do to mitigate reliability risks. Lauby said those in the energy industry can make risks to reliability known through outreach.

“I think we also need to understand implications themselves. … Some folks said it could be 60% of generation on the distributed side [in the future]. We need to understand what those implications are and how those standards need to be adjusted for more ramping, voltage support and frequency response.”

Lauby also thanked MISO for its vigilance. “I have to say, I really appreciate the continued focus MISO has on reliability.”

The RTO, meanwhile, is weighing whether to submit comments to NERC on cutting back on the amount of revised and new standards it introduces annually.

MISO Consulting Advisor Terry Bilke said NERC rolls out 35 to 40 changes to standards and new standards per year. At the April Reliability Subcommittee meeting, he said the RTO might offer comments to NERC on how to “stabilize” the standards.

Bilke also said MISO believes that NERC should be required to meet criteria before introducing new or revised reliability standards.

MISO Hurricane Prep in May

The RTO will conduct hurricane action plan training with MISO South member operators throughout May in preparation for the Atlantic hurricane season beginning in June. It also will host emergency communication presentations for state and local emergency officials.

“We haven’t had one yet, but I do think it’s inevitable, obviously, and we want to be ready for that,” MISO CEO John Bear said.

The RTO convened a hurricane readiness team last spring to spot inadequacies in contingency plans and train MISO South operators. (See MISO Sees Enough Capacity for Summer.)

— Amanda Durish Cook

May 1, 2017

MISO Advisory Committee Briefs

CARMEL, Ind. — The MISO Advisory Committee is attempting to resuscitate a yearslong discussion on whether the RTO should crack down on generators that fail to follow dispatch instructions.

Although the committee did not ultimately decide whether to ask for a proposal during the April 26 conference call, it planned for more discussion on the topic at its May 4 call.

Multiple stakeholders asked MISO to convene a workshop on the uninstructed deviations issue to discuss the RTO’s analysis and what its proposal will look like.

Chair Audrey Penner said the issue has repeatedly fallen on and off the committee’s work plan. “It seems like no one is working quite together on this issue,” Penner said. She asked stakeholders if they want action from MISO, if they think the issue needs to be dropped or if the issue would solve itself with the introduction of five-minute settlements.

“I think MISO wants to hear more clearly from stakeholders on what they want,” Penner added. She asked sectors to provide suggestions on the issue to the Market Subcommittee, where discussion will take place.

MSC Chair Kent Feliks, who noted that narrowing uninstructed deviations “has been discussed for years in pretty good detail in the Market Subcommittee,” said input from AC sectors would be helpful.

The issue has earned “medium” priority on MISO’s Market Roadmap list of market improvements — with a goal last October for a formula change and tighter bands by the end of 2017 — but the project has been at a standstill for a year.

John Weissenborn, MISO’s director of market services, said the delay can be chalked up to RTO staff working on other, more pressing priorities. He said MISO will run a study using historical data that could provide generators guidance on whether their current ramp rate would pass muster under tighter bandwidths.

“I think there has been a lack of coalescing around the issue,” Weissenborn told stakeholders. “It is an important issue, and there is a reliability issue with these dragging megawatts.” He added that aligning the dispatch signal with five-minute settlements is a “very good step” but wouldn’t eliminate the issue of generators receiving make-whole payments despite not responding to dispatch instructions.

The Independent Market Monitor has repeated concerns over the last five years that slow-ramping resources have too much flexibility to deviate from dispatch instructions, with bandwidths so generous that generators can ignore dispatch signals and still profit using the day-ahead margin assistance payment. (See Monitor Again Criticizes MISO’s Uninstructed Deviation Rules.) “Generators can essentially ignore dispatch signals and not be penalized under MISO’s rules,” the committee summarized.

Currently, MISO flags generators if they deviate more than 8% from dispatch instructions for four consecutive five-minute intervals. Monitor David Patton has recommended MISO move to a system based on ramp rate. The threshold for failure to follow dispatch would be set at 2.5 minutes, or half of the unit’s offered ramp capability, capped at 10% of the dispatch level to limit gaming. Units that do not respond to instructions after 20 minutes would be flagged and potentially disqualified from receiving real-time offer revenue sufficiency guarantee payments or day-ahead margin assistance payments.

Organized Feedback Process Ask Crops up at AC Strategic Retreat

Stakeholders from the AC again called attention to what they called MISO’s inconsistent process for gathering and sharing stakeholder feedback.

The topic was brought up in closed meetings at a committee strategic retreat, held in early April in Montreal.

MISO’s stakeholder relations team, committee liaisons and stakeholders are currently working on a more transparent and formal process on how the RTO accepts and shares stakeholder feedback, Penner reported at the April 26 AC meeting.

Stakeholders have said repeatedly that MISO needs to have a more formal and transparent process on how it collects and when it publicly shares feedback. (See MISO Takes Stakeholders’ Temperature on Redesign.)

Currently, it’s up to MISO discretion on what feedback is shared, although the RTO does allow stakeholders to indicate which feedback should be considered confidential. At times, MISO summarizes comments without attributing companies; in other situations, the RTO shares verbatim excerpts and reveals the source. Requests for stakeholder feedback and the summarized or truncated feedback itself is usually shared on meeting presentations.

Some committee members have suggested staggering meetings so companies have more time to submit feedback and no longer juggle simultaneous feedback deadlines. MISO usually allows about two weeks for stakeholders to draft and organize comments on proposals. While discussing improvements to its feedback process, the committee is also soliciting presentation ideas for the next two Board of Directors meetings.

‘Day in the Life of a Megawatt’

During the annual stakeholder meeting in Branson, Mo., in June, MISO stakeholders will not conduct a usual hot topic discussion, Penner said. Instead, each of MISO’s nine sectors will make a short presentation to the board.

NRG Energy’s Tia Elliott suggested that the MISO sectors share “A Day in the Life of a Megawatt” theme, with each sector explaining their piece of the energy lifecycle. Penner asked for ideas on what sector representatives might want to present.

The usual hot topic discussion format will resume at the September board meeting in St. Paul, Minn., and AC leadership wants discussion ideas. Those wishing to submit a topic for consideration must fill out a request form.

MISO Executive Director of External Affairs Kari Bennett said state regulators have mentioned discussing distributed energy resources. Adam McKinnie, chief utility economist for the Missouri Public Service Commission, affirmed that his commission would be interested in discussing how DERs are used and how it might be tracked.

“I think it would be an interesting topic to handle,” McKinnie said.

WEC Energy Group’s Chris Plante also suggested that each sector could discuss its version of a top-three goals for MISO before the board, possibly using past and present recommendations in the Monitor’s State of the Market Reports for inspiration.

Sector Vote Redo Breaks Nominating Committee Tie

The previous tie among two stakeholders to serve on MISO’s Nominating Committee has been broken, with Entergy’s Matt Brown beating out Madison Gas and Electric’s Megan Wisersky.

The other stakeholder seat will be held by Arkansas Public Service Commission Chairman Ted Thomas. (See “Committee Could Lengthen Board Member’s Tenure,” MISO Board of Directors Briefs.) The vote for the second stakeholder seat originally ended in a tie among MISO’s seven voting sectors. In addition to the two stakeholders appointed by the AC, the committee consists of three board members.

“There will be regular updates from the Nominating Committee throughout 2017,” Bennett said. The terms of Directors Thomas Rainwater, Paul Bonavia and Baljit Dail expire at the end of the year. Rainwater and Bonavia have not reached MISO’s limit of three three-year terms and both will seek re-election. With five first-time directors added since 2015, veteran board member Dail ― who has reached the term limit ― has agreed to seek re-election for an additional three-year term if the Nominating Committee deems that a waiver is appropriate and the rest of the board agrees.

— Amanda Durish Cook

May 1, 2017

Q1 Earnings Briefs

Summoning his inner rocker, American Electric Power CEO Nick Akins said last week he is looking forward to the company’s fully regulated future, one without merchant plants, capacity markets and auctions.

A drummer in his spare time, Akins told financial analysts at an earnings call Thursday that AEP’s outlook reminds him of how he felt at this year’s Rock and Roll Hall of Fame Induction Ceremony in New York.

“The ceremony was outstanding, as usual — much like AEP’s performance in recent years — but there was still an overhang for me, because as a Journey fan [lead singer] Steve Perry spoke but didn’t sing with the band at the ceremony,” said Akins, who sits on the Rock and Roll Hall of Fame and Museum’s board of trustees.

AEP CEO Nick Akins on drums rocking out for the Hall of Fame’s 20th anniversary *AEP/Twitter*

“I can tell you today that we feel at AEP very good about where we stand as a company today, with no real overhanging issues to cloud our view of where this company is going,” he said. “It’s as if Steve Perry, in fact, did sing once again with Journey. Don’t stop believing in AEP.” (See AEP’s Akins Optimistic over Regulated Future.)

Investors haven’t, pushing AEP’s stock price from its $67.44/share open Thursday to close at $67.83/share Friday, despite missing analysts’ expectations for the first quarter.

AEP reported first-quarter earnings of $592 million ($1.20/share), up from $501 million ($1.02/share) in Q1 2016. Operating earnings came in at 96 cents/share, missing Wall Street’s expectations of 97 to 98 cents.

The Columbus, Ohio-based company attributed its drop in sales — to $3.9 billion from $4 billion — to its service territory’s third-warmest temperatures in 40 years.

AEP did realize a $127 million profit through the earlier-than-expected sale of four merchant plants to Lightstone, a joint venture between The Blackstone Group and ArcLight Capital Partners. The plants include three fired by natural gas, with 2,533 MW of capacity, and the giant 2,665-MW Gen. James M. Gavin coal plant.

The company is plowing the transaction’s proceeds back into its regulated business, transmission and AEP Renewables. Akins said AEP’s affiliates are on pace to invest $300 million to $350 million in contracted renewables; the company has an investment goal of $1 billion over the next three years.

“Our progress has been consistent with our message of using a disciplined approach to methodically [reduce the] risk of merchant generation and augmenting … earnings from contracted renewables,” he said.

AEP hopes to complete its strategic review of its merchant fleet this year, Akins said. He said the company has given its consent to Dayton Power and Light to retire its 603-MW share of a 2,317-MW coal plant due to close in 2018 and sell its 330-MW share of the 1,300-MW coal-fired William H. Zimmer Power Station to Dynegy in exchange for the latter’s 312-MW share of Conesville Unit 4.

That will reduce the company’s competitive generation business to its ownership stake in Conesville Power Station’s four units (1,695 MW) and one of the Cardinal Power Station’s three units (595 MW). The plants burn coal and oil.

AEP reaffirmed its earnings guidance range of $3.55 to $3.75/share.

Entergy Reports Another Bad Quarter

Entergy Beats Expectations Despite 80% Drop in Earnings.)

The results included a $230.9 million charge for the costs of winding down Entergy Wholesale Commodities and its five nuclear units.

CFO Drew Marsh told analysts the company expects “pretty strong cash flow” for the next few periods because it won’t be paying for refueling outages at two of the nuclear plants.

“Are we making any progress? I would say, absolutely,” Marsh said. “Internally, we’ve been scrubbing the numbers down hard, so we would hope to show you some specific progress over the balance of the year.”

CEO Leo Denault announced Entergy Louisiana recently signed a contract with a Calpine subsidiary to build a 360-MW gas peaking plant in Bogalusa, La. Entergy will operate the plant, which is expected to be completed in 2021.

Xcel Energy Says 1st Q Earnings ‘In Line’

Despite matching 2016 first-quarter performance, Xcel Energy CEO Ben Fowke said Thursday his company survived warmer temperatures with “first-quarter earnings … generally in line with our internal plan.”

Xcel reported first-quarter earnings of $239 million ($0.47/share), virtually unchanged from the year prior of $241 million ($0.47/share). That fell short of the Zacks consensus estimate of 50 cents/share.

Fowke was unperturbed, saying that by keeping its operating costs flat for the year, the company will be on track to meet its earnings guidance of $2.25 to $2.35/share.

He also noted Xcel was named by the American Wind Energy Association as the No. 1 utility wind provider for the 12th straight year. The company has proposed adding almost 3,400 MW of new wind to its system as part of its “steel-for-fuel” strategy.

NextEra Sees More Fossil, Nuke Retirements

NextEra Energy officials said they continue to see a bright future for renewable energy and darker days for traditional power sources.

Speaking during the company’s April 21 conference call with financial analysts, NextEra CFO John Ketchum said “improved wind and solar economics” and low natural gas prices will “continue to lead to additional retirements of coal, nuclear and less fuel-efficient oil- and gas-fired generation units, creating significant opportunities for renewables growth going forward.”

NextEra Energy Resources, the company’s wholesale electricity supplier, owns and operates about 16,500 MW of wind and solar capacity. Ketchum said the company had signed contracts for 413 MW of new wind generation and 208 MW of solar energy during the first quarter.

“Customer origination activity continues to be largely driven by economics,” he said. “Based upon continued equipment efficiency improvements and cost declines, Energy Resources can offer wind [power purchase agreements] at very competitive prices.”

The company reported first-quarter earnings of $1.58 billion ($3.37/share), compared to $653 million ($1.41/share) a year earlier. Adjusted to exclude the effects of non-qualifying hedges, the net effect of “other than temporary” impairments, operating results from its Spain solar project and merger-related expenses, Q1 earnings were $820 million ($1.75/share) versus $732 million ($1.59/share) in Q1 2016.

– Tom Kleckner

April 28, 2017January 15, 2024

SPP Board Cancels Panhandle Line, Seeks New Congestion Study

By Tom Kleckner

TULSA, Okla. — SPP’s Board of Directors on Tuesday sided with stakeholders’ recommendation to cancel a major 345-kV line but promised a new study to address congestion in the footprint.

The board directed staff to pull Southwestern Public Service’s Potter-Tolk line in the Texas Panhandle from the 2017 Integrated Transmission Planning 10-year assessment’s portfolio. The project was originally identified as reducing congestion and adjusted production costs (APC), avoiding future reliability projects, and improving thermal and voltage stability margins.

However, the board in January asked SPP staff to further evaluate the project after SPS argued against the need for the line, saying it was “the wrong time” for it. The additional analysis and modeling changes revealed a 6.5% decrease in the region’s APC savings, and a third-party review added $29 million to the project’s $144 million projected cost after more detailed routing assumptions lengthened the line from 90 miles to 109. (See “Members OK Removing SPS Line from 2017 ITP10,” SPP Markets and Operations Policy Committee Briefs.)

The board’s move came following a lengthy discussion that raised questions about SPP’s planning processes, the reliability of stakeholder data being provided for studies and the amount of additional wind energy that will eventually be built in the area.

Getting the Red and Yellow Out

“This hurts me to take this out of the portfolio, but that damn yellow and red has been in that area of Texas ever since we can remember,” said Board Chair Jim Eckelberger, alluding to the shades used to denote high prices — often driven by congestion —on SPP’s price contour map. “We’ve got to get rid of it. There’s nothing blue [low-cost] down there. It’s just congested all the time.”

Eckelberger was able to mollify members by also asking SPP to conduct a high-priority study in a “thoughtful way” to “do away with the yellow.” Staff will report back to the board and Members Committee in July with its study assumptions and scope for an analysis to be completed no later than April 2018. That would also allow additional time to see how much additional generation is developed in the Panhandle.

“By the time we see the end result, we’ll see an awful lot of what is actually being built in that area,” Eckelberger said. “I’ll be damned if we’re going to have that yellow in there for the long term.”

The motion passed easily, drawing only opposition from independent transmission provider ITC-Great Plains and an abstention from West Texas’ Golden Spread Electric Cooperative.

Stuart Solomon, president of American Electric Power subsidiary Public Service Company of Oklahoma, asked the board to broaden its view and study congestion in other areas of the SPP footprint. “The Texas Panhandle is not the only place we’re seeing extreme congestion,” he said.

“As long as we’re going through this process, why not?” Eckelberger responded.

The Potter-Tolk line would have run southwest of Amarillo to connect with an SPS power plant being re-evaluated for continued operation. Initial studies showed the line would reduce congestion in a frequently constrained area (FCA), but new load projections showed a reduction of almost 800 MW in the area.

In March, SPS parent Xcel Energy announced wind projects totaling 1,230 MW in New Mexico and Texas north of the FCA. Another 8.8 GW of wind projects, based on SPP’s generation interconnection queue, have been proposed in the northern Panhandle.

“Based on these recent revelations and some of the uncertainty about these revelations, there’s too much uncertainty to proceed with Potter-to-Tolk,” SPP Engineering Vice President Lanny Nickell said. “The projects that have already been approved and come into service will dramatically reduce the congestion in the area. It doesn’t eliminate it but reduces it.”

PTC Impact

Steve Gaw, who represents the Wind Coalition, noted some of the study scenarios did not assume additional wind generation would be built. He said the phase-out of the production tax credit will lead to additional wind energy coming online after the first results of SPP’s new transmission planning process are released and before it can be considered. Projects that begin construction this year will receive 80% of the PTC value, a percentage that will fall to 60% in 2018 and 40% in 2019.

Gaw said it is unrealistic to assume there will be no additional wind growth, considering 4 to 5 GW of wind generation sites have approved interconnection agreements, the queue contains a potential 27 GW of wind energy and the PTC deadlines.

“If the assumption here is to stay exactly as we are today … to me, that’s an unreasonable assumption,” he said. “That does not adequately encompass what wind development is going to do. I’m concerned that if we don’t do something more … we’re going to run into a significant issue without having properly prepared for it.

“Yes, there’s a risk of building a project that’s not needed. There’s also a risk of not building a project that is needed.”

“If you look back at … various studies over the years, you’ll find we’ve been very conservative, probably too conservative, in forecasting the expansion of renewable generation in the footprint,” ITC-Great Plains’ Brett Leopold said. “It results in inefficiencies in planning.”

Kicking the Can?

Golden Spread’s Mike Wise filed a letter with SPP raising concerns about the project’s withdrawal, noting it was the only FERC Order 1000-eligible project in ITP10. The letter was cosigned by Hunt Transmission Services’ Bill Bojorquez and distributed to members an hour after the board meeting began.

Wise and Bojorquez said that the conclusion that the only Order 1000 project was no longer needed “should raise several red flags to the board.” They criticized the increased cost estimate (“We … were not shown sufficient evidence … the original cost estimate was unreasonable.”); the “highly suspect” change in load projections; and a new generation plan for “new wind generation that lacks regulatory approval.”

Wise’s main point of contention was SPP’s inability to relieve a north-south constraint that staff admitted costs the area about $38 million a year in congestion.

“For many years, a lack of transmission in this area has caused the establishment of the FCA and this constrained flowgate,” Wise and Bojorquez wrote. “The result is significantly higher LMPs for all network consumer loads in the south part of the system, and the ITP process of SPP has not identified or offered a solution.”

“We’re really anxious to get not just the flowgate alleviated, but this FCA … eliminated,” Wise told the board and members. “If not today, then when? If this isn’t the line, then what is going to resolve the FCA and this flowgate? We can’t just kick the can down the road another year and look at it again. That’s what we’ve said for 10 years now.”

Bill Grant, director of strategic planning for SPS, defended his company. “We didn’t ask SPP to go out and use new assumptions,” he said, referring to load projections that may not have been in the 2017 models.

“We need to continue to look at this area,” he said. “If the wind does develop, some of that wind will be identified in the GI study. We’re building generation too, so we might be paying for some of these projects as well. If we’re the ones adding wind, that’s the proper thing to do.”

April 28, 2017

MISO Stakeholders Give Go-Ahead on SD Interregional Project

By Amanda Durish Cook

The first MISO-SPP interregional project inched closer to reality Thursday with a vote of confidence from the MISO Planning Advisory Committee.

Four stakeholder sectors in attendance at a special April 27 PAC meeting ― Environmental, Transmission Owners, Coordinating and Power Marketers ― voted unanimously to approve the South Dakota project’s regional review. The $5.2 million project will relieve congestion on the tie line shared between the Western Area Power Administration and MISO’s Xcel Energy territory. (See 1 Project Recommended for MISO-SPP Coordinated Plan.)

The PAC charter does not require a voting sector quorum for project recommendation votes. MISO moved its stakeholder vote from the Interregional Planning Stakeholder Advisory Committee to the PAC late last year amid concerns that a vote in the IPSAC wouldn’t give stakeholders time to process voting issues and would be poorly attended. (See “PAC Could Hold IPSAC Vote Outside of Interregional Meetings,” MISO Planning Advisory Committee Briefs.)

SPP, meanwhile, will hold its stakeholder vote at a Seams Steering Committee teleconference May 3. SPP officials have also recommended its stakeholders approve the project, the only joint recommendation to come out of the RTOs’ coordinated system plan study conducted last year.

Both stakeholder votes are nonbinding. The MISO-SPP Joint RTO Planning Committee — composed of staff with ultimate say over interregional issues — can override the votes.

Before the vote was conducted, MISO officials hinted that they would press for regional review regardless of their stakeholders’ views.

“We’re just trying to memorialize stakeholder opinion,” MISO’s Eric Thoms explained of the vote.

MISO PAC liaison Jeff Webb said the small project has already come a long way because it comes recommended by both MISO and SPP leadership, a first for the RTOs. “This is a procedural motion more than anything,” he said. “We’re merely seeking input … and we anticipate that no stakeholders would oppose the project. We have the right to take your vote under advisement, and we’re very much inclined to check this project out.”

MISO will proceed with a regional review process only if the JRPC also votes in favor of the project. If it is approved, the RTO would most likely process the project as part of its 2017 Transmission Expansion Plan, said Davey Lopez, MISO adviser for planning coordination and strategy.

At an April 25 Informational Forum, MISO CEO John Bear said the possible approval of the first MISO-SPP interregional project would be a “rare” occurrence, given the complex approval process the project must clear.

MISO would designate its portion of the project as miscellaneous, unable to qualify for cost allocation, because it does not meet the 345-kV voltage threshold required of its market efficiency projects. The RTOs have no voltage threshold on interregional projects, but they do have a $5 million cost criteria, a requirement that either RTO must see a 5% or greater share of the project’s benefits and a condition that the estimated in-service date be within 10 years of project approval.

Acting on a complaint by Northern Indiana Public Service Co., FERC last year ordered MISO to eliminate its 345-kV threshold on interregional projects with PJM. (See FERC Signals Bulk of NIPSCO Order Work Complete.)

April 28, 2017

Salt River Project Signs on to Become 9th EIM Participant

By Robert Mullin

Phoenix-based Salt River Project (SRP) on Thursday signed an agreement with CAISO that puts the utility on track to join with the Western Energy Imbalance Market (EIM) in April 2020.

By linking up with the EIM, SRP will follow a course already charted by Arizona’s biggest utility, Arizona Public Service, which began trading in the West’s only real-time electricity market last October. (See Arizona Public Service, Puget Sound Energy Begin Trading in EIM.)

Publicly owned SRP is Arizona’s second largest electricity provider and the biggest supplier of water in the greater Phoenix area. It serves more than 1 million customers within a territory that covers more ground than the state of Delaware.

The utility estimates that it will save up to $4.5 million yearly by participating in the EIM.

“The EIM can help save money for SRP and its customers by providing real-time access to the lowest-cost resources across a significant portion of the Western grid,” John Coggins, SRP’s senior director of power delivery, said in a statement. “It will complement SRP-owned generating resources and energy purchases from the wholesale market.”

Salt River Project Arizona Public Service EIM — Theodore Roosevelt Dam

SRP controls about 9.5 GW of generating capacity, which includes the utility’s ownership of 3,461 MW of natural gas, a 688-MW share in the output from the Palo Verde nuclear plant and 745 MW of renewable generation, more than half of which is hydroelectric. The portfolio also includes 2,225 MW of coal-fired generation.

Perhaps most important for the EIM, which relies on having ample transmission capacity to prevent market separation, SRP offers key transmission assets that will improve transfer capability in the desert Southwest. Among them are 500-kV lines extending from Phoenix to points north and west, including to the Mead and Marketplace wheeling points near the California-Nevada border, the Navajo generating station in northern Arizona and the Palo Verde plant west of the city. Palo Verde, Mead and Marketplace all function as key pricing points for power wheeled into the Southern California market.

Under its agreement with CAISO, SRP will pay the ISO a $910,000 fixed implementation fee to cover preparations for EIM membership. Those include integrating SRP’s full network model into the market’s software, facilitating data exchange and performing market simulations leading up to the go-live date.

SRP will be the ninth balancing authority to join the EIM. Besides APS, current members include PacifiCorp, NV Energy and Puget Sound Energy. Portland General Electric is scheduled to begin trading in the market this October, followed next spring by Idaho Power. Sacramento Municipal Utility District and Seattle City Light are slated to join in April 2019, making them the first publicly owned participants.

CAISO estimates that the EIM has produced $142 million in gross benefits for its members since the market commenced operation in November 2014. The benefits represent either cost savings — for example, the reduced need for reserves and greenhouse gas credits — or increased profits from merchant operations. The market’s ability to reduce renewable curtailments also enables participants to collect renewable energy credits that would not otherwise be issued. (See EIM Benefit up 8% in Q4 with APS, Puget Sound Additions.)

April 28, 2017

MISO’s Next Step on Storage: ‘Common Issues’; Task Team?

By Amanda Durish Cook

CARMEL, Ind. — MISO will schedule a “common issues” meeting in response to a request from a group of stakeholders to better define energy storage, a prelude to the possible formation of a task team dedicated to the issue.

Consumers Energy, DTE Energy, Ameren, Xcel Energy and Indianapolis Power and Light, which all own storage resources, submitted a joint request that MISO create a model for storage’s participation in the market and track its growth using the RTO’s Market Roadmap project list. The companies asked that MISO revise its Tariff, dispatch methodology, capacity constructs and models used to determine interconnection rights to “recognize the physical and operational characteristics of energy storage resources.”

At an April 26 Steering Committee meeting, Chair Tia Elliott said the common issues meeting will be used to gather information before creating an energy storage task team or work group. The meeting date has not been scheduled by MISO’s stakeholder relations team.

The RTO is already under pressure to revise its rules for storage under FERC’s Feb. 1 order in response to a complaint by IPL over compensation for the 20-MW battery at its Harding Street Station. (See MISO Ordered to Change Storage Rules Following IPL Complaint.)

Justin Stewart of MISO’s stakeholder relations unit said the stakeholders’ request was too broad to be covered by a single Market Roadmap assignment, saying it “touches too many market functions.”

Under the stakeholder redesign completed last year, Steering Committee members can assign completed issues submissions forms to other committees, reject considering the issue altogether, assign it as a common issue or send it back for more detailed information.

Aligned with NOPR

DTE’s Nick Griffin, who authored the request, said his proposal aligns with the aims of FERC’s Notice of Proposed Rulemaking on energy storage, issued in November. (See FERC Rule Would Boost Energy Storage, DER.)

“Whether or not FERC mandates this, we feel this will be useful to leverage storage in the MISO market,” Griffin said.

Steering Committee members said the topic could warrant a common issues meeting and then a possible task team. But they said creating storage market definitions was too tall an order for a typical Market Roadmap assignment.

“The topic of energy storage does touch many of the areas under [the main MISO committees]. It may be appropriate for us to consider a task force or a work group … where these issues related to energy storage can be discussed,” Elliott said.

MISO Executive Director of External Affairs Kari Bennett said the RTO was open to creating a stakeholder group to handle energy storage topics as part of a “big picture evaluation.”

MISO energy storage — MISO’s Kim Sperry (L) and Kari Bennett | © *RTO Insider*

“I think there’s a lot of embedded issues in here, and the Market Roadmap typically only handles one issue. … I think that a common issues meeting could be used to tease out all of those individual issues,” Alliant Energy’s Mitchell Myhre said.

MISO Executive Director of Market Design Jeff Bladen said a task team could use its six-month lifespan to come up with a “package of recommendations,” then have the RTO’s committees review their possible responsibilities in creating market definitions for storage. “Because it’s so important, it would be important for stakeholders to get a chance to think through all of those issues in a multifaceted fashion,” Bladen said.

Compliance Filing in IPL Complaint

In March, MISO requested a rehearing of FERC’s order in the IPL complaint, arguing that the storage NOPR is a “near-complete” overlap of the ordered storage revisions (EL17-8). MISO said IPL’s insistence that it participate fully in the market is hollow, as the Harding Street storage only provides primary frequency response.

However, with FERC at a near-standstill from the lack of a quorum, MISO made a compliance filing April 3 in response to the order, proposing the creation of a new resource category, Stored Energy Resource – Type II, that would not be limited to regulating services (ER17-1376). The proposal would require that storage function largely as a demand response resource, except that it would be treated as a regular generation resource for settlements and would not be eligible for revenue sufficiency guarantee payments or day-ahead margin assurance payments.

“We made a compliance filing in the docket, but it doesn’t do justice to the issue,” Bladen said, indicating that a more detailed market model for storage is inevitable.