Page 1284 – RTO Insider

August 7, 2017

PUCT Workshop to Address ERCOT Market Improvements

By Tom Kleckner

AUSTIN, Texas — ERCOT’s energy-only market may not be broken, but stakeholders will discuss some fine-tuning at a Public Utility Commission workshop this week.

Market participants have complained about ERCOT’s use of reliability unit commitments, reliability-must-run contracts and other out-of-market actions. The Independent Market Monitor’s most recent State of the Market report made several recommendations on improving price formation. Texas regulators frequently discuss the need for real-time market co-optimization.

ERCOT PUCT price formation — Hogan | © *RTO Insider*

And now comes an ERCOT market review by a pair of industry experts on competitive market design, William Hogan and Susan Pope. Hogan, professor of global energy policy at Harvard University’s John F. Kennedy School of Government, is credited with pioneering the design of modern energy-only markets. Pope, the managing director of FTI Consulting, is an expert on economics and price formation in electricity markets.

Their report, “Priorities for the Evolution of an Energy-Only Market in ERCOT,” was commissioned by Calpine and NRG Energy “to inform important policy decisions … to ensure the sustainability of the ERCOT competitive market” and filed with the commission in May.

On Thursday, Hogan and Pope will present their recommendations during a workshop hosted by PUC staff. They will be joined by Potomac Economics President David Patton, whose firm provides market monitoring services for ERCOT, ISO-NE, MISO and NYISO. All three will participate in a Q&A session with staff, commissioners and other interested parties, while ERCOT staff and the Monitor will discuss progress on the commission’s market co-optimization and price-formation dockets (41837 and 47199).

“Our energy-only market is doing pretty well,” PUCT Commissioner Ken Anderson said during the commission’s most recent open meeting in July. “There are issues that need to be improved or corrected. There are always tweaks.

“I’d like ERCOT and the IMM to be able to comment on the cost estimate and time implementation,” Anderson said. “[The IMM has] been pushing real-time co-optimization in the time I’ve been here. I’ve been concerned about the price estimate and the time it would take to implement.”

ERCOT’s preliminary estimate is that it will take at least $40 million and up to five years to implement co-optimization. Staff has also reported to the PUC the numerous actions it has already taken or will to address price formation.

Anderson has called Hogan and Pope’s report a “very interesting read” and “largely complimentary” to the ERCOT market.

“It does point out the challenges resulting from natural gas [generation] and the dramatic expansion of intermittent renewable resources,” Anderson said. “At the heart of the report is a recognition that our market is premised foundationally on proper scarcity pricing.”

The report calls ERCOT’s commitment to price formation as the “single most important principle to get right in the energy-only market structure.”

“However,” Hogan and Pope write, “the existence and emergence of numerous factors that distort price formation” threaten the ERCOT competitive market “if left unaddressed.”

Hogan and Pope’s review was primarily meant to assess ERCOT’s operating reserve demand curve (ORDC), a PUC-ordered price adder designed to reflect the value of reserves. They concluded that while the ORDC has operated “within the context of its basic design,” it has not been “severely tested,” and scarcity price formation is being “adversely influenced by factors not contemplated by the ORDC.”

Anderson has pointed to an August 2015 event, when “the ORDC adder did not seem to reflect appropriately” a reduction in physical responsive capacity (PRC) — online generation able to quickly respond to system disturbance. He questioned whether the inputs used to calculate the loss-of-load probability should be re-evaluated. (See ERCOT: No Consensus on Operating Reserve Changes.)

During that event, ERCOT operators deployed non-spinning reserves as PRC dropped to 2,371 MW. However, real-time online reserve capacity was 3,629 MW, and wholesale prices reflected that availability.

Hogan and Pope also say other improvements can be made to ERCOT’s market “to better maintain private market response to energy prices as the driver of resource investment, maintenance expenditure and retirement decisions.”

The energy-only market was supposed to drive investment in generation, but the availability of cheap natural gas and renewable resources has made new coal and nuclear plants uneconomic.

“The stress of these forces has exposed areas where there is a need for adjustments to pricing rules and policies within ERCOT,” Hogan and Pope write.

Their report focuses on three recommendations:

Improving the ORDC calculation to address “the reliability impacts of changes in the generation supply mix and the price impacts of reliability deployments,” and considering the use of the marginal cost of transmission losses in dispatch and pricing.
Changes to mitigated offer prices and pricing of transmission constraints to properly set prices when using RUCs or other reliability actions to relieve transmission constraints. Regionwide and local ORDCs should be included in co‐optimized energy and reserves dispatch.
Considering alternatives to socialized transmission planning, “which, by building new transmission in advance of scarcity developing, fails to provide the opportunity for markets to respond.”

Luminant, the largest generator in the state, opposes the use of marginal losses, saying pricing and dispatch based on marginal losses is inconsistent with transmission-cost policies established by Senate Bill 7, Texas’ 1999 deregulation legislation. Amanda Frazier, the company’s representative to ERCOT’s Technical Advisory Committee, said using the marginal cost of transmission losses could result “in a significant disruption to the market by redistributing revenues from generators in the West and North to generators in Houston.”

Luminant’s opposition is just emblematic of the shareholder discussions taking place within ERCOT.

“Stakeholders have been addressing this, I think, a little too slowly,” Anderson said. “I think we’re probably going to need to pick this up to get the ball moving a little faster.”

August 7, 2017

CAISO Developing New Bidding Rules

By Jason Fordney

FOLSOM, Calif. — CAISO is refining market rule changes to more accurately reflect suppliers’ costs of producing and dispatching electricity while also increasing their bidding flexibility.

Stakeholders attending an Aug. 3 workshop learned more about recent proposed changes to bidding rules in the ISO’s Commitment Cost and Default Energy Bid Enhancements (CCDEBE) initiative. Energy suppliers say that even with improvements over the past decade, they don’t have the bidding flexibility they need to reflect all costs under all conditions.

Commitment Cost and Default Energy Bid Enhancements — The CCDEBE technical working group meets at CAISO headquarters | © *RTO Insider*

Based on feedback from market participants, CAISO has acknowledged that its current bidding rules need more flexibility and do not always reflect certain costs, price volatility and “business needs.” The rule changes are also designed to incentivize flexible resources that help manage renewable generation when fuel supplies are tight and reduce the risk of not recovering costs for gas and non-gas resource operators.

CAISO is the only organized wholesale electricity market in the U.S. that does not currently support market-based commitment cost bids subject to mitigation, said Cathleen Colbert, senior market design and policy developer at the ISO.

“We wanted to put this out, to get the conversation started and to get feedback,” she said at the workshop, where she presented details of the proposal.

Market rules must allow suppliers to submit economic prices based on costs and risk while protecting themselves from structural issues in the market, the ISO said. Mitigated prices must reasonably reflect suppliers’ expectations of their costs.

CAISO mitigates market-based commitment costs using the “three pivotal supplier” test, which checks for market power by measuring the degree to which a given market relies on just three suppliers — rather than drawing on excess generation from other suppliers — to meet demand. Commitment costs refer to the portion of the supply offer that involves start-up, transition and maintaining minimum load requirements. Suppliers can submit either market-based energy offers or cost-based commitment cost offers. Cost-based offers are subject to a cap that provides only limited flexibility, CAISO said, while market-based energy offers have a $1,000/MWh cap and are mitigated when uncompetitive conditions are found.

The CCDEBE program is one of a series of ongoing market updates CAISO is working on to deal with changing conditions on the grid and public policy goals. The ISO plans to end certain temporary measures in a separate proceeding on Aliso Canyon gas-electric coordination when the CCDEBE procedures are implemented. (See CAISO Board Approves Aliso Canyon Rules Package.)

The ISO is additionally working to comply with FERC Order 831, which requires that supplier costs are reflected when energy bids rise above $1,000/MWh. (See New FERC Rule Will Double RTO Offer Caps.) The federal rule was put in place last November after wholesale power prices spiked during the winter storms of 2013-2014 and generators said they could not recover their costs.

The system operator posted its revised CCDEBE proposal on Aug. 2, with comments due Aug. 7. The package is due to go the Western Energy Imbalance Market (EIM) Governing Body for an advisory vote on Oct. 10 and to the CAISO Board of Governors for approval on Nov. 1.

“People are very eager for us to get this in place a quick as we can in 2018,” CAISO Market Design Manager Brad Cooper said. “Our timeline is very tight.”

August 7, 2017

Duke Seeks to add Solar Following Legislative Victory

By Rory D. Sweeney

Duke Energy executives used Thursday’s quarterly earnings call to outline a vision for expanding its solar generation assets through recently enacted legislation in North Carolina.

The nation’s second-largest utility reported earnings of $686 million ($0.98/share) in the second quarter on revenue of almost $5.6 billion, a jump from $509 million ($0.74/share) on revenue of $5.2 billion a year earlier.

Adjusted diluted earnings for the quarter were $1.01/share, compared with $1.07/share a year ago.

Duke spent nearly a year fighting for the “Competitive Energy Solutions for North Carolina” plan, which was signed into law by Gov. Roy Cooper (D) on July 27 (House Bill 589). The law establishes competitive bidding for most utility-scale solar projects in the state and allows for utilities to use the state’s fuel cost rates to recover cost for facilities contracted under the Public Utility Regulatory Policies Act. It also reduces mandatory PURPA contracts from 15 years to 10 and places an 18-month moratorium on wind development in the state.

Pathway for Solar

Duke Chairman and CEO Lynn Good praised the legislation for providing the company a pathway to developing almost 900 MW of solar generation and acquiring more. The law includes a commitment from Duke to seek 2,660 MW of new renewable energy by mid-2021. The company is permitted to compete for 30% of that goal and may buy other approved projects to expand its ownership beyond the 30% cap. Without the legislation, Duke would have little control over the projects’ development but would be required by PURPA to purchase the power.

“The law also allows for the recovery of costs associated with these projects through a new rider to be established by the [North Carolina Utilities] Commission. The competitive bidding process will ensure that new renewables are brought on to the system at market-based rates, delivering nearly $1 billion in savings for our customers over the next decade,” Good said. “In our five-year plan, we have something like $400 million of capital directed towards that type of investment in the Carolinas. So, we do have more investment opportunities than we imagined.”

Additionally, company officials argued that proposed rate increases for coal ash disposal will ultimately benefit customers. The company has been dealing for years with issues regarding leakage from ponds used to store residual ash at its coal-fired generators. It has set aside $500 million for resolving the disposal and contamination issues and has asked for another $195 million from ratepayers in cases filed with the NCUC in June and July.

If approved, the requests would include recovery for a wastewater treatment facility at the Mayo plant in Roxboro, N.C., and an estimate of ongoing costs for closing the ponds.

Pipe at Dan River Ash Basin | *Duke Energy*

“This approach would allow us to recover our estimated costs as incurred, reducing our financing costs and ultimately benefiting our retail customers,” Duke CFO Steve Young said. “If approved, this will build upon the recent third quarter, allowing both [the Duke Energy Carolinas and Duke Energy Progress subsidiaries] to recover costs for coal ash remediation from wholesale customers. We believe this was a prudent approach to managing these expenses and maintaining competitive rates for our customers.”

Good also called the transition to electric vehicles “positive” but wasn’t overly enthusiastic.

“I think it will grow over time. I don’t see it as a step change though in load growth because of all the other factors impacting load, including energy efficiency and other items,” she said.

Misgivings on Wind Ban

Duke Energy Center in Charlotte, NC | *Duke Energy*

In signing HB 589, Cooper criticized the last-minute addition of an 18-month bar on wind development, issuing an executive order to mitigate the effects of the moratorium.

Cooper said he signed the bill because of its importance to the state’s “already booming” solar industry. “I strongly oppose the ugly, last-minute, politically motivated wind moratorium,” he said. “However, this fragile and hard-fought solar deal will be lost if I veto this legislation and that veto is sustained.”

Supporters of the moratorium, which bars approval of new wind farms before the end of 2018, said it was necessary to allow the legislature time to study the impact of wind turbines on the state’s military bases.

Cooper’s executive order directs the state Department of Environmental Quality “to continue recruiting wind energy investments and to move forward with all of the behind-the-scenes work involved with bringing wind energy projects online, including reviewing permits and conducting pre-application review for prospective sites.”

“I want wind energy facilities to come online quickly when this moratorium expires so our economy and our environment can continue to benefit,” Cooper said.

August 7, 2017

MISO Reliability Subcommittee Briefs: Aug. 3, 2017

Recommendations made by NERC and FERC in a June report on restoring power after the loss of normal communications are guidelines and not likely to become binding, a NERC official said last week.

ReliabilityFirst Corp. Chair John Idzior, one of several experts who prepared the joint FERC-NERC study and report, told the MISO Reliability Subcommittee that utilities are too reliant on supervisory control and data acquisition (SCADA) and energy management systems (EMS) when restoring the bulk power system from a total blackout. (See NERC: Despite Solid 2016, Grid Threats Remain.)

The joint report recommends that entities take five measures to restore power absent SCADA and EMS, which include:

Improving backup communication measures;
Planning for extra control room personnel on hand during a restoration without SCADA or EMS;
Reviewing backup power resource provisions beyond normal battery backups;
Using other power system analysis tools; and
Training personnel for situations where SCADA and EMS are unavailable.

Idzior said that the recommendations will not be enforced and will likely not become future NERC reliability requirements.

“It’s currently guidance for entities to use as they see fit. There is no follow-up or tracking as a result of these recommendations,” Idzior told MISO stakeholders at an Aug. 3 Reliability Subcommittee meeting. “This is more an above-and-beyond. I don’t see a push for this being included in reliability standards.”

Hwikwon Ham of the Minnesota Public Utilities Commission asked if any entity could enforce the recommendations. RTOs could incorporate the recommendations into their own restoration planning protocols, Idzior responded.

Idzior said the report’s findings will be presented to NERC’s Operating Committee at future meetings, but the entities that participated in the study will remain confidential.

MISO: Not Enough Solar to Add More Reserves

MISO staff expect the RTO will remain largely unaffected by a possible NERC industry recommendation to procure more operating reserves to cover the widespread loss of solar resources during faults on the power system.

The possible NERC recommendation stems from an August 2016 event, when 1,200 MW of Southern California solar generation was lost after the Blue Cut wildfire erroneously tripped inverters. (See CAISO Boosts Reserves After August Event Report.) RTOs have until Aug. 31 to respond to NERC’s request for solar inverter data and reserve information.

MISO reliability subcommittee NERC — Swan | © *RTO Insider*

Steve Swan, MISO senior real-time operations engineer, said MISO will solicit data from the three solar farms representing about 170 MW capacity in the RTO’s footprint.

“MISO will be answering for the MISO balancing authority. We’re drafting the answer, and it’s basically going to say yes and no,” Swan said, referring to the fact that the RTO does cover the loss of solar through reserves, but only incidentally because of the relatively small amount of solar participating in the market.

“Eventually, we’ll get over 1,700 MW of solar, but that’s a ways down the road,” Swan said.

MISO is more interested in reviewing the responses from markets in the Western U.S., where solar participation is more prevalent, he said. “There will be some good information coming out of this, but right now, it’s not an issue to MISO.”

Dispatch Instruction Pilot Almost Ready

MISO is “very close” to implementing a pilot program that seeks to encourage generating units to more closely follow dispatch instructions, Swan said.

Under the program — which was conceived by MISO’s Independent Market Monitor, the RTO will send real-time alerts to generators that do not follow dispatch, followed by direct contact from MISO operators notifying unit operators of their non-responsiveness. Before rolling out the pilot, MISO staff will work with the Monitor to eliminate the chance for false positives, which could occur when the RTO binds a transmission constraint, Swan said.

Information collected from each notice will be conveyed to the Monitor to either confirm the lagging response or report system conditions that prevented efficient dispatch.

“The idea is we’ll be sending information back to the IMM in every instance,” Swan said.

Reliability Subcommittee Chair Tony Jankowski asked for MISO to provide a presentation on its current dispatch requirements at the next Steering Committee meeting in October. He also asked for an update on the RTO’s effort to tighten its tolerance bands on generators’ uninstructed deviations from dispatch orders. MISO in May said the project was in the software development phase after several months of delay. The Monitor has been recommending the project for more than five years. (See Monitor Again Criticizes MISO’s Uninstructed Deviation Rules.)

Northern Indiana Public Service Co.’s Bill SeDoris said his company is concerned about the move to tighten dispatch tolerance bands. The new standard is set to go live next spring, and generation owners need to know if the move will affect headroom, he added.

Swan said he would return to the RSC with updates.

MISO and PJM File JOA Pseudo-Tie Rules

MISO and PJM on Aug. 1 filed changes to their joint operating agreement (JOA) to better manage the RTOs’ pseudo-tied resources, MISO’s Kim Sperry said.

The filing (ER17-2220) aims to improve the “administration and coordination of pseudo-ties between MISO and PJM by incorporating into the JOA standard definitions, rules and responsibilities between the two RTOs,” MISO said. PJM submitted a simultaneous filing to adopt identical changes in its version of the JOA.

The standard rule set makes clear that pseudo-ties must obtain station service according to native balancing authority rules and follow the modeling rules of both the native and attaining balancing authority areas. The rules dictate that only pseudo-tied units — and not the RTOs — are responsible for compensating an attaining balancing authority for failure to deliver energy. Pseudo-tied resources also cannot be directed to serve load in the native balancing authority when the attaining balancing authority requires the unit’s output — unless they are needed to avoid exceeding NERC operating limits in the native balancing authority. (See MISO, PJM Float Pseudo-Tie Coordination Plan.)

Jankowski asked if the filing marked a first in a series of filings to improve MISO and PJM pseudo-tie coordination.

Sperry said that while the RTOs will continue working together into the fall on a separate filing to address the double-counting of pseudo-tie congestion, MISO does not envision another joint filing to amend the RTOs’ administration of pseudo-ties.

— Amanda Durish Cook

August 7, 2017

PPL: No Load Growth in Sight for US Operations

By Rory D. Sweeney

PPL is maintaining a flat demand outlook for its U.S. service territories through 2020, company executives said during Thursday’s quarterly earnings call.

The utility, which operates in Pennsylvania, Kentucky and the U.K., said it is not forecasting load growth in the U.S. through the end of the decade. Its previous business plan assumed 0.5 to 1% annual load growth.

Chairman and CEO Bill Spence said the company’s Pennsylvania utility may ask regulators for a rate true-up based on volume. He said there was no “near-term concern” for its Kentucky operations.

“I think the best tool for us to deal with demand, which is flat, is our forward rate years,” added Victor Staffieri, CEO of PPL’s LG&E and KU. “So, we take that into account every time we file [a rate case]. You all know we’ve been filing every two years and so I would expect that would be the best way for us to capture any changes in the … demand.”

The company posted a profit of $292 million ($0.43/share) in the second quarter, compared with $483 million ($0.71/share) a year ago. The decline was primarily driven by lower foreign currency exchange rates, company executives said.

Earnings from ongoing operations were $356 million ($0.52/share), compared with $380 million ($0.56/share) a year ago.

PPL load growth earnings — PPL Pole Truck | *PPL*

The company reduced its expected annual earnings from its regulated Kentucky utilities by 2 cents/share, attributing the drop to lower electricity sales because of mild weather. For the year, which included Kentucky’s warmest February on record, the company said weather in the U.S. has negatively impacted its results by about 3 cents/share.

However, the company remains confident in its 2017 earnings forecast of $2.05 to $2.25/share, a 5 to 6% compound annual growth in earnings per share and a 4% growth in dividends through 2020.

The British pound, which fell from about $1.48 to as low as $1.20 following the U.K.’s vote in June 2016 to leave the European Union, has since rebounded to about $1.30. The company said it can reach the low end of its projected EPS even if the pound hits parity with the dollar.

British pound to U.S. dollar exchange rate | XE

“We’re executing very well on our low-risk business plans,” Spence said.

[Editor’s note: Quotes from conference call courtesy of Seeking Alpha.]

August 7, 2017

OGE, CenterPoint Earnings Calls Focus on Enable Midstream

By Tom Kleckner

CenterPoint Energy and OGE Energy both reported positive earnings Thursday, but company officials spent much of their time during conference calls with analysts discussing their gas-gathering and processing joint venture, Enable Midstream.

CenterPoint executives had promised an update during its call on efforts to sell or spin off its 54.1% share of the partnership. Instead, they could only say that a spinoff is no longer being considered because it would result in undesired credit metrics for the company. (See OGE Anticipates Legislative Review of Oklahoma Regulators.)

CenterPoint Energy lineman | *CenterPoint Energy*

“I’m hesitant to give another date in the future when hopefully this will be closed out,” CEO Scott Prochazka told analysts. “We hope to move this to conclusion pretty quickly.”

CenterPoint said multiple parties are conducting due diligence to potentially acquire shares of Enable but would not comment on the status. The Houston-based company last month extended another right of first offer to OGE.

“We would like to reduce our exposure to the oil and gas sector,” Prochazka said. “If we’re not able to affect an outright sale, we would like to lighten our ownership through a public sale.”

The process of “diluting” CenterPoint’s ownership share has been ongoing since last year.

“It’s admittedly taken longer than suspected,” CenterPoint CFO Bill Rogers said. “We took some time to get confidence in the forecasts over multiple years that we could then present to multiple buyers. Any potential purchaser wants to get comfortable with their partner.”

“My view is we’re both aligned around wanting Enable to do well,” OGE CEO Sean Trauschke said during the Oklahoma City-based company’s earnings call, which preceded CenterPoint’s. “We continue to be pleased with its performance. Enable is doing everything it was set up to do, and there is significant untapped value in this business, and we are excited for what the future holds.”

OGE holds a 25.7% limited-partnership interest and a 50% management interest in Enable.

Trauschke said OGE has received about $70 million in distributions from Enable this year and noted the company recently announced a second-quarter distribution of $35 million.

Enable Midsteam’s structure | *Enable Midstream Partners*

Formed in 2013, Enable’s assets include about 12,900 miles of gathering pipelines, 14 major processing plants with 2.5 Bcfd of processing capacity, 7,800 miles of interstate pipelines, 2,200 miles of intrastate pipelines and eight storage facilities with 85 Bcf of storage capacity.

Enable was trading at $15.42/share Friday, up just over 20% in the last year.

Q2 Earnings Beat Investors’ Expectations

Quarterly earnings at both OGE and CenterPoint exceeded investors’ expectations.

OGE said lower operating expenses resulted in net income of $104.8 million ($0.52/share), up from $72 million ($0.35/share) a year ago. Analysts surveyed by Zacks Investment Research had predicted earnings of 47 cents/share.

OGE expects full-year earnings to be between $1.93 and $2.09/share.

Investors reacted to the news Thursday by pushing OGE’s share prices up 66 cents to $36.01 in after-hours trading. The stock is up 15.4% in the last year.

“I’m proud we aren’t talking about surprises: surprises like delays, cost overruns,” Trauschke said. “Quite simply, we’re getting things done in an environment where we don’t necessarily control variables like the weather or actions of others.”

CenterPoint reported net income of $125 million ($0.29/share), up from $73 million ($0.17/share) last year. The company attributed the good news to rate increases and customer growth.

Zacks’ analyst survey had projected earnings of 21 cents/share.

CenterPoint shares gained 83 cents Thursday, finishing at $28.47 after the market closed.

August 7, 2017

NiSource Blames Debt Refinance Fee for Q2 Loss

NiSource lost $44.3 million ($0.14/share) in the second quarter, with company officials pinning the sagging earnings on an expensive debt-related charge.

The Merrillville, Ind.-based parent of Northern Indiana Public Service Co. and Columbia Gas took a $111.5 million charge on early extinguishment of higher-coupon, long-term debt. However, CEO Joseph Hamrock said the charge, incurred for refinancing $990.7 million in debt, will be offset in the long term. The refinance will “result in significant interest expense savings over the next several years,” Hamrock said during an Aug. 2 earnings call.

NiSource reported $167 million in net income from continuing operations for the first six months of this year, compared with $215.6 million in the first half of 2016.

NiSource earnings — NiSource Headquarters | *NiSource*

CFO Donald Brown said the company currently carries $7.9 billion in debt, with a 13-year weighted average maturity for long-term debt and a 5.4% average interest rate.

“It’s worth mentioning that our credit ratings at the three major agencies are investment-grade. Standard & Poor’s rates NiSource at BBB+, Moody’s at Baa2 and Fitch at BBB ― all with stable outlook. Going forward, our financial foundation is solid and poised for continued growth,” Brown said.

Hamrock said the company plans to invest $1.6 billion to $1.8 billion annually in utility infrastructure programs from 2018 through 2020, part of more than $30 billion in long-term investment opportunities the company has identified. (See NiSource Pegs Q1 Success on Infrastructure Investments.)

— Amanda Durish Cook

August 7, 2017

Con Ed Earnings Down; PSC Rules on Subway Outage, Solar Pilot

By Michael Kuser

Consolidated Edison on Thursday reported its second-quarter net income dropped almost one-third from a year ago, mainly reflecting changes in rate plans and regulatory charges and the impact of weather on revenues from the company’s district-energy steam system.

The company posted $175 million in net income for the quarter ($0.57/share) on $2.63 billion in revenue, compared with $232 million ($0.78/share) on $2.79 billion in revenue in 2016.

Adjusted earnings — which exclude the gain on the sale of a solar electric production project, the impairment of a solar electric production investment in 2016 and the mark-to-market impact of the company’s Clean Energy Businesses — were virtually equal to last year at $178 million ($0.58/share) versus $179 million ($0.60/share) in 2016.

The new electric rate plan for Consolidated Edison Company of New York (CECONY) included changes in the timing of recognition of annual revenues between quarters. Operations and maintenance expenses for CECONY for the second quarter and first half reflect lower pension costs and lower regulatory assessments and fees.

CEO John McAvoy said the company has begun installing smart meters and offering customers new products such as smart air conditioners and Wi-Fi-enabled thermostats.

NYPSC Actions

The New York Public Service Commission on Aug. 2 approved a pilot 3-MW solar project by CECONY aimed at saving low-income customers money on their utility bills (16-E-0622). Con Ed will place the solar panels on rooftops and property owned by the utility.

con ed nypsc earnings — Solar panels | *ConEd*

The commission also directed the utility to change the way it tries to collect money from delinquent customers (16-M-0501). Specifically, Con Ed must propose a process for executing deferred payment agreements and make the company’s meter-seizures “much more straightforward,” the order said.

“To prevent backsliding, Con Edison is required to provide quarterly updates to commission staff to ensure the new procedures are being properly executed,” PSC Chair John B. Rhodes said.

The Public Utility Law Project of New York had requested that the commission examine the utility’s methods of seizing customers’ electric or gas meters for unpaid bills, as well as the way it negotiates deferred payment agreements.

The commission also voted to issue an order on Con Ed’s response to a power outage April 21 that cut electricity to the Seventh Avenue subway station and led to a loss of the subway signals (17-E-0428).

Although the order was not immediately available, it is expected to require the company to create a stockpile of emergency generators that could be deployed anywhere in the system within 30 minutes take actions, as laid out in a July 26 letter from Rhodes.

He also said Con Ed would need to replace its aluminum cables with failure-resistant copper cables and install backup electric lines to eliminate single points of failure. It also must analyze power supply and power quality affecting the subway’s signal system.

Gov. Andrew Cuomo said last week that power-related issues caused more than 32,000 subway delays in the last year.

August 7, 2017

Berkshire Hathaway Energy Earnings Up on Solar Rebound

By Rich Heidorn Jr.

Berkshire Hathaway Energy reported a $38 million increase in earnings for the second quarter over a year earlier, largely because of improved performance of BHE Renewables.

The renewable unit saw net income increase $39 million due primarily to higher generation at the Solar Star projects, which were hobbled by transformer-related forced outages in 2016. It also benefited from earnings from tax equity investments reaching commercial operation and additional wind and solar capacity placed in service.

Berkshire Hathaway Energy earnings — Buffett

BHE Transmission’s earnings dropped by $15 million from lower earnings at AltaLink and BHE U.S. Transmission, which saw lower income from Electric Transmission Texas because of new rates that took effect in March.

Oncor Hearing Set

BHE is awaiting an Aug. 21 U.S. bankruptcy court hearing on its proposed $9 billion acquisition of Energy Future Holdings’ Texas utility Oncor. BHE’s bid is being opposed by EFH’s largest creditor, Elliott Management, which won an 11-day delay in the hearing after telling the bankruptcy court on July 26 that 10 other investors are interested in joining it in a competing bid. (See PUCT Staff Welcomes Buffett’s Oncor Bid; Debtor Miffed.)

Elliott’s $9.3 billion offer values Oncor at $18.5 billion including debt, exceeding the $18.1 billion valuation in BHE’s all-cash deal.

BHE said July 26 that it supports Oncor’s rate settlement with Texas regulators and its agreement to swap $400 million of assets with Sharyland Utilities. “The rate settlement contemplates a stronger financial structure for Oncor, with more owner-funded equity to fund proposed projects and investments in the grid,” BHE said.

Pending approval by Texas regulators, Sharyland would take over 258 miles of 345-kV transmission from Oncor in exchange for Sharyland’s distribution network and retail delivery customers. “Oncor will be welcoming thousands of new customers, many of which are located in areas that have seen significant load growth, like the Permian Basin,” said Oncor CEO Bob Shapard.

The proposed swap was submitted to the Public Utility Commission of Texas on Friday (Docket No. 47469).

August 4, 2017

CAISO Flex Capacity Effort Targets Increased Variability

By Jason Fordney

CAISO is developing new tools to deal with the variable output from the increasing amount of renewable and non-dispatchable generation on its grid, an effort that could bring fundamental changes to California’s resource adequacy rules.

The tools are meant to deal with the highly variable output of new wind and solar generation and changes in net load on the CAISO grid. The grid operator must not only properly balance generation and demand, but also avoid reliability violations and accommodate policy objectives such as renewable integration.

CAISO flexible capacity renewables — | *CAISO*

“The system is evolving and the challenges are evolving,” CAISO Principal of Renewable Generation Clyde Loutan said in an stakeholder call Wednesday. He added that “we are encountering operational challenges on the system that we need to understand.”

Through its Flexible Resource Adequacy Criteria and Must Offer Obligations 2 (FRACMOO2) proceeding, the ISO is proposing to introduce new variations of its flexible resource adequacy capacity product, which is intended to increase the ramp rate of the flexible capacity fleet that is becoming more critical to integrating new renewables.

The bulk of the current proposal is designed as short-term modifications to the flexible capacity criteria to emphasize start-up and minimum run times. CAISO is exploring the use of intertie resources but does not yet have a specific proposal. It hopes to have a program in place in time for the 2020 resource adequacy year. A separate initiative will develop a long-term flexible capacity solution and a resource adequacy roadmap in conjunction with the California Public Utilities Commission.

“The proposed short-term solution is unlikely to be sustainable long-term because the forecasted three-hour net load ramps could exceed the available flexible capacity in several years under this proposal without additional enhancements,” CAISO said in its revised straw proposal.

The package is designed to address the changing characteristics of the grid as CAISO requires quicker ramping speeds within shorter time cycles. While the steepest three-hour net load ramp in 2015 was about 10,600 MW, those ramps are projected to reach about 16,800 MW by 2020, with one ISO estimate putting hourly ramps as high as 7,000 MW by that time. New flexible capacity products would be designed to address variability and uncertainty down to five-minute increments.

The proposal is divided into an operational aspect and a capacity procurement workstream, Johannes Pfeifenberger of the Brattle Group said in a presentation during the call. Brattle has been developing a proposal for CAISO’s flexible capacity procurement framework. Addressing the issue requires a better understanding of the physical capability of the system and flexible and non-flexible resources, he said.

There was broad opposition to a previous ISO flexible capacity proposal, according to a CAISO presentation. Critics contended that the plan conflated three separate drivers that should be dealt with more independently: curtailment of renewables, risk of generation retirements and maintaining a reliable grid.

During the Aug. 2 call, CAISO officials were asked if they have considered putting more limits on how quickly variable resources are allowed to ramp up or down, as is done in ERCOT.

“We are trying to look at all solutions right now,” Loutan said. But ERCOT has different operating characteristics, less non-dispatchable generation and different frequency requirements, he said, noting also that Texas is not interconnected with other regions, unlike California.

CAISO said it has been considering limiting the ramp rate of renewables to manage swings in generation output, but oversupply and minimum load requirements put more focus on flexible resources and start times of flexible capacity resources. The ISO proposed to require a flexible capacity resource have a start-up time of less than 4.5 hours and minimum run time of less than 4.5 hours.

CAISO is accepting comments on FRACMOO2 until Aug. 16, with a draft final proposal planned for December. The initiative also requires coordination with the PUC and other agencies with generation resource adequacy jurisdiction.

The ISO hopes to submit a final product to the Board of Governors next summer, followed by implementation in 2020.