CAISO officials said Tuesday they “reluctantly” plan for the ISO to become a reliability coordinator (RC) by spring 2019 and will depart from the ISO’s current RC, Peak Reliability, which recently emerged as a potential market competitor.
The ISO cited as the reasons for the move Peak’s decision to partner with PJM to provide market services and Mountain West Transmission Group’s likely departure from Peak after it joins SPP. (See PJM Unit to Help Develop Western Markets.) CAISO said in a press release it could provide reliability services “at significantly reduced costs.”
| CAISO
“The ISO reluctantly takes these steps and will collaborate with the rest of the funding parties to ensure continuity of reliability services and to avoid any party being adversely affected financially,” CAISO CEO Steve Berberich said. Services would include outage coordination, day-ahead planning, and real-time reliability monitoring.
The ISO said it will hold a call on the proposal Jan. 4 and conduct public meetings later this month in Folsom, Calif.; Phoenix, Ariz.; and Portland, Ore.
CAISO last month proposed to extend its day-ahead market into the territory of its regional Western Energy Imbalance Market (EIM), setting up a possible competition with Peak to provide an organized market to other areas of the West. (See CAISO Bid for Western RTO to Face Competition in 2018.)
RCs monitor compliance with NERC and regional standards, including monitoring risks, taking actions to preserve reliability and leading power restoration efforts.
Vancouver, Wash.-based Peak said it will have a business plan for its market offering in place by the end of March. The organization said last year it held more than 130 meetings, including some with public utility commissioners in Washington, Montana and Nevada; FERC; and the office of California Gov. Jerry Brown.
Peak in 2014 split off from the Western Electricity Coordinating Council, a NERC Regional Entity based in Salt Lake City, Utah. WECC recently began its own realignment toward core reliability functions. (See WECC Finding New Direction in Old Mission.)
Advanced meters have reached a 43% penetration rate but demand resources’ contribution to meeting RTO/ISO peak demand has decreased, FERC reported in its 12th annual report on demand response and advanced metering.
DR in the organized wholesale markets dropped to 5.7% in 2016 from 6.6% in 2015 according to RTO/ISO reports, as demand resource participation fell 10% while peak demand grew by 3%.
The decreased participation was largely because of a 24% (3,030 MW) drop in DR enrollment in PJM, which lost 2,900 MW in its reliability program (limited, extended summer and annual DR) and 900 MW in its economic program. The drops were partially offset by 600 MW of DR entering the market as Capacity Performance resources.
CAISO saw DR participation fall by 8% because of decreased enrollment in price-responsive demand programs administered by California’s three investor-owned utilities. ISO-NE and NYISO saw 4% drops while MISO saw a 1% increase.
Retail DR, by contrast, showed growth. Potential peak demand savings from retail DR programs nationwide increased by 5.4% between 2014 and 2015, according to the Energy Information Administration. Industrial customers were responsible for 52% of potential savings, while residential customers contributed 26% and commercial customers 21%, a breakdown that FERC said has “remained fairly stable over time.”
FERC also cited EIA data showing that 64.7 million advanced meters were deployed nationwide in 2015 out of a total of 150.8 million meters.
The report also took note of states’ grid modernization efforts, including deployment of time-of-use rates. The annual report, released Dec. 28, was mandated by Congress in the Energy Policy Act of 2005.
Con Ed ‘Value Stack’ Approved
Consolidated Edison last week won FERC approval to recover its payments to distributed energy resources customers under the New York Public Service Commission’s Reforming the Energy Vision initiative (ER18-214).
The PSC created a “value stack” describing the services provided by DERs: capacity; environmental value; demand reduction value; and locational system relief. (See NYPSC Limits ESCO Service, Sets New DER Compensation.) Con Ed agreed to New York City’s request that its annual accounting to FERC include an itemization of the four DER cost components.
Other Rulings
In other rulings last week, the commission:
Ordered a Section 206 proceeding to determine reactive service rates for Allegheny Energy Supply’s 80-MW coal bed methane-fueled facility located in Buchanan, Va. (ER17-2575, EL18-46).
Approved transmission rate incentives for Dairyland Power Cooperative’s share of the Cardinal-Hickory Creek 345-kV transmission project (ER18-193). The commission approved a hypothetical capital structure of 45% equity/55% debt and recovery of 100% of prudently incurred costs if the project is canceled for reasons beyond Dairyland’s control. The 125-mile project will run from the Cardinal substation in Middleton, Wis., to the Hickory Creek substation in Dubuque County, Iowa. Dairyland will own 9% of the project with American Transmission Co. and ITC Midwest each owning 45.5%. Pending regulatory approval, the companies expect to begin construction in January 2022 with an in-service date of June 2023.
Ordered hearing and settlement procedures on proposed revisions to the transmission formula rate templates of Public Service Company of Oklahoma, Southwestern Electric Power Co., AEP Oklahoma Transmission and AEP Southwestern Transmission (ER18-194, ER18-195). Oklahoma Municipal Power Authority, East Texas Electric Cooperative and Northeast Texas Electric Cooperative protested that the AEP filings failed to justify the proposed changes, which AEP said were needed to transition from a historic basis to a forward-looking accounting method. The commission said the resolution of the dockets is subject to the outcome of East Texas’ complaint over the AEP companies’ 10.7% base return on equity (EL17-76).
Set hearing and settlement proceedings on Southwestern Public Service’s proposed revisions to the formula rate implementation protocols in its power supply agreements with Central Valley Electric Cooperative, Lea County Electric Cooperative, Farmers Electric Cooperative of New Mexico, Roosevelt County Electric Cooperative, Tri-County Electric Cooperative and West Texas Municipal Power Agency (ER18-228). The revisions update the depreciation rates for the two units at SPS’ Tolk generating station based on a 2032 retirement date and the retirement of its Carlsbad generator at the end of 2017. The commission cited protests by several co-ops that SPS had not presented proof it had made a legally binding decision to retire Tolk or Carlsbad earlier than previously indicated. They said that could allow SPS to change its decision after having benefited from recovering accelerated depreciation. Chairman Kevin McIntyre did not participate in the ruling.
Approved an uncontested settlement on Alliant Energy’s revenue requirement for providing reactive supply and voltage control at its Interstate Power and Light and Wisconsin Power and Light generating facilities (EL17-60, ER17-980-001). The settlement will pay IPL $3.58 million and WPL $3.77 million. Alliant had requested an annual revenue requirement of $4.23 million for IPL, a decrease from the $4.89 million it received in 2015, and $4.45 million for WPL, an increase from $2.41 million in 2015.
FERC last week ordered hearing and settlement proceedings on Southern California Edison’s proposal to revise its transmission formula rate, while approving an incentive for RTO participation over the objections of new Commissioner Richard Glick (ER18-169, EL18-44.)
The commission accepted the company’s filing effective Jan. 1 subject to refund. Although SCE proposed a reduction in its transmission revenue requirement, the commission said “a further decrease may be warranted.”
SCE proposed a base return on equity of 10.3%, saying the range resulting from FERC’s two-step discounted cash flow model — 6.97 to 9.15% — was too low.
The commission approved a 50-basis-point ROE adder for SCE’s participation in CAISO over the objections of the California Public Utilities Commission, which said the incentive is “an unjust and unreasonable windfall to SoCal Edison shareholders because SoCal Edison’s participation in CAISO is required by state law and the state of California determines whether SoCal Edison remains a member of CAISO.”
“The CPUC’s arguments … have been considered and rejected by the commission in earlier orders, and we reject them for the same reasons here,” the commission said. “We also note that companies continue to confront decisions about whether to form and join ISO/RTOs, and we believe the stability of the incentive adder for ISO/RTO participation (albeit capped by the top of the zone of reasonableness) is important to the congressional and commission policy of promoting ISO/RTO membership,” it added.
| Southern California Edison
Glick sided with the CPUC, saying, “I do not believe that this summary approval is the product of reasoned decision-making.”
“SoCal Edison’s membership in CAISO is not voluntary and, therefore, awarding a 50-basis-point RTO participation adder does nothing to harness for consumers the benefits of RTO membership,” Glick wrote in a dissent.
Glick said the ruling belied the commission’s “repeated statements that the RTO participation adder is not a ‘generic’ adder awarded to all public utility members of an RTO.
“Although I do not question the benefits of membership in an RTO — and I support using an RTO participation adder where it incentivizes RTO membership — I believe that the commission’s approach in this proceeding essentially transforms the ‘case-by-case’ evaluation of a request for an RTO participation adder that the commission described in Order No. 679 into exactly the type of generic determination that the commission forswore in Order No. 679 and subsequent orders.”
FERC ordered hearing and settlement procedures in a dispute over reliability-must-run agreements filed by Calpine for its Yuba City, Feather River and Metcalf generators in CAISO.
Yuba City power plant | CalpineMap identifying the need for Yuba City and Feather River plants | CAISO
The commission’s Dec. 29 orders approved the Yuba City and Feather River (ER18-230) and the Metcalf RMRs (ER18-240) effective Jan. 1, 2018, subject to refund.
The ISO and Pacific Gas and Electric filed protests over the RMRs filed by Calpine’s Gilroy Energy Center subsidiary for the Yuba City and Feather River plants. CAISO designated the units as RMR in March, but the ISO told FERC that Gilroy had not supported provisions related to scheduling coordinator charges, greenhouse gas emissions and gas prices. (See PG&E, CAISO Protest Calpine RMR Terms.)
CAISO also protested Metcalf’s proposed changes to its cost-of-service schedules, arguing that they are unsupported or reflect errors in implementation of applicable formulas.
The ISO is increasing its use of out-of-market RMR payments to keep units online, raising concerns that its market is not producing the price signals sufficient to support units needed to provide reliable electric service.
FERC last week approved changes to MISO and PJM’s Joint Operating Agreement to improve their coordination of pseudo-tied generators, rejecting calls for a technical conference (ER17-2218).
The RTOs said the changes were needed to address the market and reliability challenges resulting from the increased number of pseudo-tied resources. Pseudo-tied volumes from MISO into PJM increased from about 155 MW in June 2015 to 2,160 MW in June 2017.
In November, the commission had accepted PJM’s proposed revisions to the requirements for pseudo-tied resources seeking to participate in the RTO’s capacity auctions (ER17-1138).
The RTOs will coordinate modeling and technical details of pseudo-tied resources;
To capture the impacts of pseudo-tied resources on flowgates, neither PJM nor MISO nor the entity seeking to pseudo-tie a resource will tag the scheduled energy flows from pseudo-tied resources. Information about the pseudo-tied resources is included in the market-to-market management procedure;
The RTOs will not recall a pseudo-tied resource that is committed to the attaining balancing authority as a capacity resource to serve load in the native balancing authority;
The native reliability coordinator can commit, decommit or redispatch the pseudo-tied resource under certain circumstances;
Entities seeking to pseudo-tie must pay for transmission losses; and
The RTOs can suspend or terminate a pseudo-tied resource if it no longer satisfies the requirements for a pseudo-tie.
FERC approved the changes over the concerns of intervenors who said it should evaluate them along with issues raised in other pseudo-tie proceedings. MISO’s Independent Market Monitor — which has challenged PJM’s requirement that external capacity resources must be pseudo-tied — said the commission should schedule a technical conference on the issues.
FERC, however, said it agrees with the RTOs that the JOA revisions “are separate and distinct from issues pending in other pseudo-tie related proceedings: These proceedings specifically address administration and coordination of pseudo-tied resources between the RTOs. In contrast, some of the other proceedings pertain more to the agreement that a pseudo-tied resource enters into with the relevant balancing authorities and the requirements for becoming pseudo-tied.”
The commission also rejected as beyond the scope of the proceeding American Municipal Power’s complaint that the JOA revisions won’t help imports from pseudo-tied resources out of MISO into PJM because they don’t resolve the issue of double-charging for congestion. “The parties have made no showing that the provisions filed by the RTOs are unjust and unreasonable because congestion is not addressed,” it said, noting that the RTOs made separate filings on Oct. 23 to address the congestion overlap issue (ER18-136, ER18-137).
FERC dismissed challenges to the RTOs’ proposed non-recallability provision, saying they had “sufficiently delineated the limited circumstances under which a pseudo-tied resource can be committed, decommitted or redispatched by the native reliability coordinator. While we agree that the ability of a pseudo-tied resource to meet its capacity requirement is essential to system reliability, we find that the instant JOA revisions do not inappropriately reduce PJM’s or MISO’s control over a pseudo-tied capacity resource.”
In less than 12 months in office, President Trump has abrogated the Paris Agreement on climate change and sought to disembowel the Obama administration’s Clean Power Plan. His Interior Department ended the Obama-era ban on coal mining on federal lands and is removing 2 million acres of national monuments from federal protection.
Trump and congressional Republicans also have taken steps to expand oil and gas development in the Arctic National Wildlife Refuge and off the Atlantic Coast. FERC, restored to full strength for the first time in two years, is under Republican control and facing a Jan. 10 deadline for responding to Energy Secretary Rick Perry’s demand for price supports for coal and nuclear generators.
Yet there’s also evidence that the energy economy has ballast that can withstand even this political wind storm. The economics of cheap shale gas and subsidized solar and wind continue to win market share. Dozens of cities and states responded to Trump’s Paris snub by pledging to meet the U.S. emissions targets. Despite Trump’s claim last week to have “saved” the coal industry, employment has risen by only 1,200 (2.4%) since January and remains near historic lows; although domestic coal production was up 8% in 2017 over 2016, the Energy Information Administration expects a decline in 2018.
While California’s wildfires and the hurricanes that brought biblical rain and ruinous winds have some fearing it’s already too late to prevent severe damage from global warming, RTO Insider will continue covering the nitty gritty of energy policy in 2018 — Armageddon be damned.
Here’s some of the top national stories we’ll be chronicling in the coming year.
FERC’s New Makeup
FERC limped through half of 2017 without a quorum. For all of July, after the departure of Colette Honorable, Cheryl LaFleur was the only commissioner on the 11th floor of FERC headquarters.
New Chairman Kevin McIntyre, a Republican, joined FERC after 22 years at Jones Day. Although he was coleader of the law firm’s global energy practice, he acknowledged in a FERC podcast that he has kept a low profile during his career. “I think that flying below the radar … has been a function of what my role has been in private practice where, typically, I and my law firm colleagues were retained not to land our client in the headlines, but in most instances just to serve as a forceful advocate.” (His former Jones Day colleague Don McGahn is Trump’s White House counsel.)
In his first open meeting Dec. 21, McIntyre surprised FERC watchers by announcing the commission would review its 1999 policy statement on natural gas pipeline licensing — a seeming olive branch to LaFleur, a Democrat, who later gushed, “I was already looking forward to 2018 with all you fine folks, and I now am even more.” (See FERC to Review Gas Pipeline Approval Process.)
It was an encouraging development for those who believe FERC’s nonpartisanship has been a strength. But there’s no assurance that the review, which will likely take months, will materially impact pipelines’ 99.5% success rate in winning FERC approval.
DOE NOPR
An earlier indication of where FERC is headed will come by Jan. 10, when McIntyre has promised the commission will rule on the Department of Energy’s Notice of Proposed Rulemaking.
McIntyre won a 30-day delay on the original deadline, telling Perry he and fellow newcomer Richard Glick needed more time to review the more than 1,500 comments filed in the docket (RM18-1). (See McIntyre Takes FERC Chair; Wins Delay on NOPR.)
Perry called for compensating coal and nuclear plants in regions with competitive capacity markets that maintain 90 days of fuel on site, saying they were needed for grid resiliency.
Commissioner Neil Chatterjee has lobbied for interim subsidies for coal and nuclear plants to provide them a “lifeline” pending a lengthier FERC review.
Although there has been speculation that LaFleur and Commissioner Robert Powelson want to issue a Notice of Inquiry to RTOs and ISOs, they have not expressed definitive positions publicly.
Changes on PURPA?
The new FERC commissioners also may consider making rule changes to address longstanding complaints about the Public Utility Regulatory Policies Act, the subject of a July 2016 technical conference and numerous congressional hearings. The National Association of Regulatory Utility Commissioners asked FERC on Dec. 18 to change its interpretation of PURPA to “align” the 1978 law “with modern realities.” (See NARUC Calls for PURPA Reforms, Outlines Proposed Changes.)
Chatterjee has said he wants FERC to address gaming of the commission’s “1-mile rule,” while Powelson promised in his confirmation hearing to look at “what’s working with PURPA and what’s not.” But both said major changes could require congressional action. (See Chatterjee Outlines Goals for FERC Tenure and No Fireworks for FERC Nominees at Senate Hearing.)
Other Rulemakings
In his podcast interview, McIntyre declared as priorities the commission’s storage NOPR (RM16-23, AD16-20) and revising its policy for determining just and reasonable returns on equity. He also called for more transparency regarding the timing of FERC’s rulings. “As a practitioner, I know firsthand what it’s like to wonder when on earth the commission is going to make a decision on a given matter,” he said. “And I think we owe it to stakeholders and the public itself to be as transparent as we can possibly be about what to expect.”
The ROE discussion got a new variable with the Republicans’ reduction of the corporate federal income tax from 35% to 21%. Montana regulators voted last week to require its utilities to pass the tax savings through to consumers, and Michigan, South Dakota, Kansas and other states reportedly also have opened dockets on this issue. (See Steve Huntoon’s latest Counterflow column, Brother, Can You Spare 70 Billion Dimes?)
NERC Seeks New CEO, Security Chief
Another issue facing FERC is its oversight of NERC, which the commission in 2006 empowered with responsibility for ensuring the reliability of North America’s electric grid.
NERC CEO Gerry Cauley (center) and General Counsel Charles Berardesco (to Cauley’s left) attend a NERC board meeting in New Orleans Nov. 9, hours before Cauley’s arrest for domestic abuse. Also pictured are Board Chair Roy Thilly (to Cauley’s right), and board members Jan Schori (left) and Frederick W. Gorbet (foreground). | NERC
In November, the Electric Reliability Organization was rocked by the arrest of CEO Gerry Cauley on domestic abuse charges. Cauley, the face of NERC at congressional hearings and FERC technical conferences for nearly eight years, allegedly attacked his estranged wife in an argument over what his wife said was an affair with a female subordinate. (See Cauley Arrest Tied to Relationship with NERC Subordinate.)
General Counsel Charles Berardesco was named interim CEO while NERC searches for a replacement for Cauley, who resigned effective Nov. 20 after reaching a severance agreement, according to sources. (See Cauley Resigns; NERC Launches Search for Replacement.) A week later, NERC also parted ways with its chief security officer in what sources told RTO Insider was a forced resignation. (See NERC Parts Ways with Chief Security Officer.)
While FERC has generally approved NERC’s reliability standards as proposed, the commission has on occasion overruled the ERO or pushed its own initiatives. On Dec. 21, for example, it ordered NERC to lower the threshold for mandatory reporting of cyber incidents. (See FERC Orders Tightened Cyber Reporting Rules.)
Thus far, however, the commission has not shown an interest in addressing what current and former NERC officials say was an authoritarian corporate culture under Cauley, a West Point graduate. Might FERC take a larger role in overseeing NERC management? Given increasing concerns over the grid’s vulnerability to cyberattacks and terrorism, the stakes could scarcely be higher.
EPA Administrator Scott Pruitt has brought dramatic change to the agency, angering and demoralizing many career staffers.
According to The Washington Post, EPA has, or is attempting, to reverse 19 rules, including a request that oil and gas companies report their methane emissions. EPA’s staffing has dropped to its lowest level since the Reagan administration following the departure of more than 700 employees, many through agency buyouts. Pruitt also has remade the agency’s scientific advisory boards, replacing many academics with representatives from states and regulated industries.
In December, as the Supreme Court was considering whether to hear DTE Energy’s appeal of EPA sanctions for modifying Michigan’s largest coal-fired power plant without getting federal permits for a projected rise in emissions, Pruitt reversed the agency’s stance. He said EPA would no longer bring New Source Review cases against generators in disputes over emission projections, a departure from the agency’s prior use of NSR as a preventative. (See Penalty Review Denied, DTE Faces Friendlier EPA.)
In November, almost 60 former EPA attorneys wrote an open letter criticizing Pruitt’s announcement that the agency would stop negotiating settlements in response to lawsuits by environmental groups. Pruitt has long criticized the “sue and settle” practice, which he said lacks transparency and “circumvent[s] the regulatory process set forth by Congress.”
The attorneys said Pruitt misrepresented the impact of such settlements and that his new policy gives regulated parties “a special and powerful seat at the table with no corresponding role for other members of the public.”
Clean Power Plan
It was a foregone conclusion that Pruitt would seek to undo the Clean Power Plan. As Oklahoma’s attorney general, he led states challenging the rule as an overreach of the Clean Air Act. What wasn’t known was how he planned to reverse the rule. On Dec. 18, EPA issued an Advance Notice of Proposed Rulemaking, saying it would solicit public input for 60 days on how to limit greenhouse gas emissions from existing electric generators. Pruitt had told Congress earlier that the agency would issue a replacement rule, rather than seek to overturn its 2009 endangerment finding on greenhouse gases. (See Pruitt Confirms EPA Working on CPP Replacement.)
Pruitt’s “inside the fence line” replacement is certain to prompt new challenges from environmental groups as being an inadequate response.
Solar Import Duties
The solar industry is holding its breath for Trump’s decision on the U.S. International Trade Commission’s October recommendation for import duties as high as 35% on solar cells and modules. The ITC’s recommendation followed its unanimous ruling in September that increased imports of solar cells and components are harming domestic manufacturers.
A flood of cheap imports has helped create a boom in U.S. solar installations, as total installation costs have fallen almost 70%. The Solar Energy Industries Association says increased prices resulting from the case could threaten the 9,000 U.S. solar companies and their 260,000 employees. (See Federal Trade Panel Recommends Solar PV Quotas.)
It won’t be until 2020 when the presidency — and thus FERC — will be up for grabs. But the 2018 midterm elections could also influence electric policy. Democrats need to win a net 24 seats to take control of the House of Representatives. The GOP’s margin in the Senate dropped to 51-49 with Democrat Doug Jones’ upset victory in the Alabama special election. But 25 of the 33 seats up for re-election next year are held by Democrats or independents. (The seat of resigning Sen. Al Franken (D-Minn.) also will be filled in a special election.)
The website FiveThirtyEight reported last month that generic congressional surveys by both it and CNN show “Republicans in worse shape right now than any other majority party at this point in the midterm cycle since at least the 1938 election.” Democrats lead Republicans by 49.6-37.4% according to FiveThirtyEight and 56-38% per CNN. “No other survey taken in November or December in the year before a midterm has found the majority party in the House down by that much since at least the 1938 cycle,” according to FiveThirtyEight.
Trump, meanwhile, has been losing support fastest in the states that gave him the most support in 2016, FiveThirtyEight also reported. In states where Trump won by at least 10 percentage points, his net approval rating is down an average of 18 points.
I’m sorry to disappoint folks by kicking off the new year without another column on the Trump-Perry carbon tax (aka the DOE NOPR).
This column is about another tax matter: that very beautiful tax legislation that became the law of the land on Dec. 22. OK, maybe not very beautiful, or even beautiful, or even not that attractive. But whatever.
The centerpiece of the tax legislation is a reduction in the corporate tax rate from 35% to 21%. The raison d’etre is making the U.S. corporate tax rate more competitive with the rest of the world.
Public utilities are direct beneficiaries of this reduction, even though they are one industry that can’t move outside the U.S. You can’t get your utility service from China (at least not yet). Utility customers ought to be the indirect beneficiaries, but as I discuss here, it ain’t clear how that’s going to happen and when.
I know we all hate death and taxes, but please bear with me.
How Income Taxes Work in Rate Regulation
Traditional rate regulation allows utilities a return on their invested capital (aka rate base[1]) based on a composite of their shareholder equity (stock) and their debt (bonds). The equity portion is determined net of income taxes, so utilities are given an income tax allowance to cover income taxes.
So let’s take an example of a utility with a rate base of $10 billion that is financed 50% by debt and 50% by equity. Let’s say the equity portion of $5 billion is being allowed an annual return of 10%, or $500 million. That 10% is a rough average of allowed returns on equity (ROE).
By the way, this 10% allowed level of ROE is wildly excessive for reasons I’ve explained before,[2] but no one seems particularly concerned about that. The excessive ROE is not only unfair to consumers in and of itself, but it has spurred a spending frenzy by utilities to increase rate base notwithstanding little to no growth in demand.[3] Utilities do not need any more encouragement to “invest” consumers’ money in gold-plating.
Anyway, getting back to the point of this column (and I do have one), to get to a “net of tax” return of 10%, that percentage is “grossed up” for taxes, which can be calculated by dividing by 1 minus the tax rate, or 65%.[4] So for $5 billion of equity, the utility is awarded $769 million that consumers actually pay.
You can confirm this admittedly convoluted approach by multiplying $769 million by 35% (the tax rate) to get an income tax allowance of $269 million and then subtracting that $269 million from $769 million to get the $500 million “net of tax” allowed return.
Cut in Tax Rate Amounts to $7+ Billion Owed to Electric Consumers. Per Year.
So what’s the difference as a result of the tax rate reduction from 35% to 21%? We get the tax “gross up” by dividing by 1 minus the new tax rate, or 79%. So for $5 billion of equity, and $500 million of “net of tax” return, the utility would receive $633 million.
To recap, the overall return on $5 billion at an income tax rate of 35% is $769 million. The overall return on $5 billion at an income tax rate of 21% is $633 million. See the difference? The former is 21.5% more than the latter.
This means that if a utility’s overall equity return was just and reasonable on New Year’s Eve, on New Year’s Day it was 21.5% more than just and reasonable.
What does that amount to? There is roughly $41 billion in relevant electric utility earnings.[5] So on New Year’s Day, electric utility rates became excessive by $7 billion ($41 billion, minus $41 billion divided by 1.215). That’s 70 billion dimes.
And the tax cut creates another benefit for utilities: excess accumulated deferred income taxes. I will spare you an explanation of this. But believe me, it is another huge pile of money that consumers ought to start getting back as of … yesterday.
Who Is Getting Electricity Consumers Their $7+ Billion?
What are our nation’s regulators doing about this?
So far it seems to be a trickle instead of a wave.[6] And it’s not as if the utilities even think they’re entitled to windfalls. The Edison Electric Institute issued a press release headlined: “Passage of Tax Reform Bill a Win for Electricity Consumers.”[7] S&P Global simply assumes that regulators will require pass through to consumers.[8]
We need more action from our nation’s regulators to, as Captain Picard might say, make it so.
Although rate base has a number of complicating factors, in most regulatory jurisdictions, it is basically the booked cost of utility capital investment less the accumulated depreciation for that investment. ↑
I’m ignoring state income taxes for simplicity. There is negligible effect on the point being made. ↑
EEI reports members’ energy operating income of $73 billion for 2016 here, http://www.eei.org/resourcesandmedia/industrydataanalysis/industryfinancialanalysis/QtrlyFinancialUpdates/Documents/QFU_Income_Statement/2016_Y_Income_Statement.xlsx. Subtracting $22 billion of interest expense yields $51 billion of normalized equity return. I reduced that $51 billion by a guesstimate of 20% to reflect merchant generation owned by EEI utilities (principally in PJM), utility formula rates that track prevailing tax rates, and tax adjustment provisions in individual utility tariffs (such as per a rate case settlement). That leaves $41 billion upon which to apply the income tax reduction effect. ↑
One year later, the future of PJM’s markets remains as unsettled as ever.
The RTO entered 2017 preoccupied with its capacity construct and how to address the impact of state-subsidized generation. It ended the year without an agreement on capacity rule changes and facing a new threat to its markets: the Department of Energy’s request that FERC order price supports for nuclear and coal plants.
It was concerns that other states might follow Illinois and New York in subsidizing at-risk nuclear plants that led PJM to create the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) in early 2017. The yearlong effort has not gone the RTO’s way. Stakeholders produced nine other proposals with which PJM’s two-stage repricing concept was forced to compete. As the examination wore on, many stakeholders, including state regulators and consumer advocates, became convinced the current construct remains the best option. They are supporting a proposal by the Independent Market Monitor that they see as changing the current construct the least.
The RTO responded to the DOE Notice of Proposed Rulemaking by calling for a change to its method for developing LMPs. At its final stakeholder meeting of the year, PJM won endorsement for a stakeholder task force to examine the energy market rules and provide recommended fixes. (See “PJM Wins Examination of Price Formation,” PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)
Subsidized generation is one of several major issues PJM will face in 2018. Below are the questions the country’s oldest power pool will likely address in the coming year.
The CCPPSTF endorsed only one proposal: the Monitor’s plan to extend the minimum offer price rule (MOPR) to all units indefinitely, with exemptions for self supply, competitive entry, public power and state renewable portfolio standard programs.
But PJM announced it will not recommend those revisions to its board and instead plans to seek FERC approval for its repricing proposal, which would disconnect the offer price from the probability of clearing the auction.
A vote on the Monitor’s proposal was deferred until the Jan. 21 Markets and Reliability and Members committee meetings, in part to await FERC’s decision on DOE’s request. (See MOPR-Ex Faces Uphill Battle as PJM Declines Recommendation.)
The Monitor has said it will file its proposal with FERC if it receives a “supermajority” of stakeholder support.
In addition to shaking up the capacity discussion, the DOE NOPR also accelerated PJM’s plan for changing its day-ahead and real-time energy markets. The RTO’s current LMP methodology is simplified, effectively prohibiting large, inflexible resources like coal and nuclear generators from setting LMPs in its real-time and day-ahead energy markets. Instead, cheaper, more flexible units that are dispatched ahead of those units set prices, and the inflexible units receive “uplift” payments to cover their operating costs.
PJM argues the inflexible units should be allowed to set LMPs and the more flexible units should be paid extra for their ability to moderate output to help align supply with demand. The RTO will seek to build support for its proposal through the recently approved examination of energy market price formation. (See PJM: Energy Price Formation Addresses DOE NOPR.)
Christie | New Jersey
Some observers see the proposal as PJM’s hasty response to states subsidizing their in-state nuclear resources. New York started the trend with its zero-emission credits in 2016, and Illinois soon followed with its own ZEC program. Similar proposals are on the table in Pennsylvania, Ohio and New Jersey, the last of which could enact legislation before Gov. Chris Christie’s lame-duck tenure ends Jan. 19. (See NJ Nuclear Subsidy Bill Moves Swiftly out of Committee.)
The legislation includes caveats that reduce the state’s subsidies if market rule changes improve the plants’ revenues. The issue charge estimates that it could take most of 2018 to finalize the details of the RTO’s plan. But PJM officials intend to move much more quickly. In its response to the DOE NOPR, the RTO told FERC that it should order it and other RTOs to file price formation rule changes within 180 days. (See NOPR Reply Comments Bring More Criticism of PJM Proposal.)
Is Carbon Trading in PJM’s Future?
RGGI’s Member States | NRDC
The two-stage capacity repricing and the energy market price formation proposals are two pieces of PJM’s three-part plan for responding to state public policy initiatives. The third piece, which proposes a regional carbon-trading structure, might also receive additional discussion in 2018. The PJM proposal suggests establishing regional carbon prices that can be reflected in wholesale market prices.
New Jersey Governor-elect Phil Murphy pledged to rejoin the Regional Greenhouse Gas Initiative — which Christie withdrew from — within 100 days of assuming office. The state would rejoin Delaware and Maryland among the PJM states participating in RGGI. (See EBA Panelists Discuss Carbon Policy, Renewables Integration.)
What Becomes of Summer Demand Response?
Another flash point has been PJM’s efforts to develop ways for seasonal resources such as demand response to comply with Capacity Performance rules requiring year-round availability.
In October 2016, PJM asked FERC to approve a package of rule changes despite stakeholders’ concern that the proposal didn’t go far enough. The RTO’s proposal relaxed prohibitions on seasonal resources aggregating across locational deliverability areas, provided additional winter capacity interconnection rights (CIRs) and modified rules for measuring DR performance in the winter.
PJM stakeholders, however, aren’t waiting around. They won approval to examine the situation through a Summer-Only Demand Response Senior Task Force formed in November. The group will look at the additional summer-season resources that don’t get aggregated and seek uses for them. (See Stakeholders Seek Load Discussion in PJM DR Task Force.)
Transmission customers and merchant developers have been pressing incumbent transmission owners on several fronts. For merchant developers, the focus is on getting PJM to consider cost-containment provisions in project proposals. LS Power’s Sharon Segner has been leading this fight and recently won concessions from TOs on allowing construction cost caps. This isn’t enough for Segner, who is seeking approval of cost caps on return on equity and annual revenue requirements. (See “Cost-containment in Proposals,” PJM PC/TEAC Briefs: Dec. 14, 2017.)
American Municipal Power’s Ed Tatum has pushed for additional transparency on transmission projects proposed by TOs and the criteria used to determine when infrastructure has reached the end of its life. AMP released a study in October that showed more than half of the $24.3 billion in transmission projects in PJM since 2012 were supplemental projects unneeded to comply with RTO or federal reliability requirements and were not subject to rigorous review. AMP continued pressing its case for more transparency during a marathon Transmission Expansion Advisory Committee meeting in December. (See AMP Presses AEP, PSE&G on Transmission Projects.)
State representatives are on AMP’s side. Both the Consumer Advocates of the PJM States and the Organization of PJM States Inc. have indicated their support for the efforts.
Can PJM Ensure Gas Generation Without Control of Pipelines?
While the definition of resiliency remains up for debate, PJM staff have brought several plans for stakeholder endorsement under its banner. In addition to price formation, which is intended to preserve fuel diversity, PJM has expressed concern that the loss of a major gas pipeline could idle multiple generation units.
The RTO is seeking to coordinate the natural gas pipeline system’s procedures with grid operators’ needs, a process it calls “operationalizing.” The effort won agreements from gas-fired generators in December on manual changes specifying that PJM “may need to direct” switching to an alternate pipeline or fuel on a pre-contingency basis and that it “will use best operator efforts” to move interruptible users off before firm service users. (See “Fuel-Switch Clarifications Endorsed,” PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)
As if PJM didn’t have enough on its plate, FERC on Dec. 21 ordered the RTO (along with SPP and NYISO) to change their tariffs to incorporate fast-start resources into energy and ancillary services pricing (EL18-34). (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
FERC said PJM has special pricing rules only for block-loaded units — resources whose economic minimum operating limits equal their economic maximums, meaning they have no dispatchable range. The RTO seeks to let them set price by relaxing the economic minimum operating limit of online block-loaded resources by up to 10%. The commission said PJM’s practices may not be just and reasonable because they don’t allow block-loaded resources’ economic minimum to be relaxed by more than 10% and because they limit the relaxation to only block-loaded resources.
The commission gave the RTOs 45 days to file initial briefs in the Section 206 proceedings.
FERC’s Dec. 21 order requiring SPP to help fast-start resources set LMPs added one more to-do for the RTO in what is shaping up to be a busy 2018.
SPP’s integration of the Mountain West Transmission Group drew much of the RTO’s attention in 2017. But it also has been working to solve underfunding issues in its financial transmission rights market, address stakeholder concerns over transmission cost allocations, identify seams transmission projects that can be built and incorporate the constantly increasing amounts of wind energy. And as they have for the last several years, stakeholders and SPP officials spent countless hours attempting to unravel the Z2 transmission project accounting mess.
Fast-Start Order
FERC gave SPP and stakeholders 45 days to file initial briefs in the Section 206 proceeding it created to drive Tariff changes to benefit fast-start resources. The commission found SPP’s approach “inconsistent with minimizing production costs” and ordered it to allow the commitment costs of fast-start resources (start-up and no-load costs) to be reflected in prices. SPP said it will decide its plan for responding to FERC’s fast-start order in early January. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
Working out the details will likely fall to SPP’s Market Working Group (MWG).
Congestion Hedging
The MWG has been spending the last few months working on improvements to SPP’s congestion-hedging process.
SPP’s Integrated Marketplace rules are intended to allow load-serving entities to translate firm transmission service reservations (TSRs) into a product that allows them to obtain credits to hedge daily congestion costs.
The RTO allocates auction revenue rights based upon firm network or point-to-point transmission reservations. But market participants have complained they are not receiving sufficient hedges.
Keith Collins, executive director of SPP’s Market Monitoring Unit, says the main area of concern is the initial transition from a physical transmission right (the TSR) to a financial right (the ARR).
| SPP
Because ARRs are allocated months in advance of the day-ahead market, congestion patterns can change in the interim because of transmission outages, derates and upgrades and unexpected generation outages.
The MMU also notes that many prevailing-flow ARRs are not nominated, leaving hedges “on the table.” In addition, the availability of prevailing-flow ARRs is limited because most counterflow ARRs are not nominated.
Charles Cates, SPP’s manager of transmission services, told the Board of Directors in December that the RTO’s congestion market is about portfolios, not single-path entitlements and awards.
Staff say total congestion revenues continue to increase, with the revenues shifting from LSEs to financial entities (the non-ARR holders). Candidate ARRs associated with redispatch are contingent on completion of transmission upgrades, they say.
“Building transmission to help [create] more ARRs is an expensive answer to the problem,” Collins said.
| SPP
The MMU has suggested hedging congestion from the physical day-ahead flow, taking the emphasis off day-ahead congestion prices.
Among the options SPP is considering are obligating the LSEs to nominate counterflow, reducing percentages in the annual transmission congestion rights auction, and limiting first-round ARR nominations by source and path.
The MWG will provide an update on its progress during the January board and Markets and Operations Policy Committee meetings. If the MWG can’t find a better mechanism, a task force could be created to take up the issue.
Mountain West Integration
The biggest to-do on SPP’s list is completing the integration of Mountain West, which primarily services Colorado, Wyoming and Nebraska. Mountain West announced its intention to join the RTO in January, but it had been holding discussions with SPP’s management team for almost a year prior. In September, Mountain West said it would begin public negotiations. (See SPP, Mountain West Integration Work Goes Public.)
| SPP
SPP has established a Members Forum and State Commission Forum to assist with its due diligence effort. SPP’s Strategic Planning Committee spent the last quarter of 2017 conducting numerous executive sessions with Mountain West representatives. The discussions are expected to continue well into 2018.
Mountain West said it has had “significant success” resolving issues concerning rate design and cost-shift mitigation. Any changes to governing documents, such as SPP’s Tariff, bylaws and membership agreement, must go through the RTO’s stakeholder process for review before they are considered by the board. The Regional Tariff Working Group (RTWG) has primary responsibility for Tariff changes, while the Corporate Governance Committee will consider changes to the membership agreement and SPP bylaws.
SPP and Mountain West are working on an Oct. 1, 2019, target date for membership but will begin the regulatory approval process this year. FERC filings could come as soon as October, assuming the SPP board approves the integration at its July or October meetings. The RTO expects FERC review to take 60 to 180 days.
The Colorado Public Utilities Commission will play a key role in the process. The commission has jurisdictional authority over Xcel Energy’s Public Service Company of Colorado and Black Hills Energy, two of the eight Mountain West members seeking to join SPP. The PUC held three informational sessions on the merger last year and could hold as many as three more in 2018. (See Colo. Regulators Talk Governance with SPP, Mountain West.)
When it’s all over, SPP will have expanded its current 14-state footprint into the Rocky Mountains, adding Colorado, most of Montana and portions of Arizona and Utah. The new SPP will grow by 165,000 square miles, adding 16,000 miles of transmission lines and 21 GW of generating capacity.
Mountain West will eliminate the pancake transmission rates that led to its search for RTO membership, while SPP members will see 10-year net present value benefits of about $209 million, according to the RTO.
Z2
In October, the board approved a cleanup of Tariff language that it hopes will help it resolve long-standing problems with Attachment Z2 of SPP’s Tariff, which details how financial credits and obligations are assigned for sponsored transmission upgrades. (See “Z2 Fix Allows Short-Term Service Agreements to Expire,” SPP Board of Directors/Members Committee Briefs: Oct. 31, 2017.)
ERCOT enters 2018 facing new questions, as the growth in wind energy has begun threatening not only coal but also less efficient natural gas-fired generation.
In late November, the 155-MW Fluvanna Wind Energy Project in West Texas went online, pushing ERCOT’s wind power capacity past 20 GW. The milestone came a few weeks after the ISO approved the retirement of 2.4 GW of coal-fired generation, dropping its coal capacity to 15.1 GW in early 2018. (See ERCOT OKs Luminant Coal Retirements.)
The retirements, along with those of several gas resources, has halved ERCOT’s planning reserve margin to 9.3% for summer 2018, leading Beth Garza, director of the ISO’s Independent Market Monitor, to proclaim an end to the “fat and happy times.”
“We’ve had really two years of clearly unsustainably low prices with high reserve margins,” Garza told the ERCOT Board of Directors in October. “We’re looking at a much different situation going into the summer of 2018.”
The Monitor says it hasn’t seen a summer with such tight reserve margins since 2007. “Will we see coal generators making profits that justify future investment?” asked IMM Deputy Director Steve Reedy during an October conference, noting the Monitor has seen more capacity on the ERCOT system than might be justified.
“If the load doesn’t rise fast enough to justify the generation, we expect to see retirements. So, we will see [in 2018] if retirements in the market work,” Reedy said.
| Potomac Economics
After bottoming out in 2016 with the lowest real-time prices ($24.62/MWh) since the nodal market began operations in 2010, the ISO has seen prices increase to an average of $28.56/MWh through November. Still, that 16% increase lags the 28% rise in natural gas prices over the same period.
Solar, Wind Dominate Queue
All the while, wind and, increasingly, solar projects continue to flood the market. More than 29 GW of wind and almost 25 GW of solar are currently going through some form of study, accounting for the bulk of ERCOT’s latest generator interconnection status report.
Joshua Rhodes, a research fellow at the University of Texas’ Energy Institute, projects ERCOT’s wind capacity to reach 24.4 GW by the end of 2018. Given current capacity factors and coal retirements, that means wind will surpass coal as a fuel source for electricity by 2019. Coal generation has accounted for 32.2% of the ISO’s production this year, compared to wind’s 17.5%. Natural gas exceeds both, at 39%.
| NextEra Energy Resources
So far, cheaper natural gas and wind have driven inefficient coal and gas plants out of the market.
“We haven’t had a true scarcity event in years, but if we have severe weather, we could have one,” said NRG Texas’ Bill Barnes, speaking on the same conference panel with Reedy. “That’s when we can all sit back and say, ‘Yes, that’s how it’s supposed to work.’ Or will there be temptation to intervene in the market?”
Market Rule Changes?
NRG Texas partnered with Calpine to sponsor a report of the ERCOT market, published in May. The report, coauthored by Harvard University’s William Hogan and FTI Consulting’s Susan Pope, recommends several market improvements, including adjusting the operating reserve demand curve (ORDC), adding local scarcity pricing and potentially implementing real-time co-optimization (RTC), to address intermittent renewables and improve incentives for generators. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
The Public Utility Commission of Texas, which regulates ERCOT, has conducted a pair of workshops to discuss price-formation issues in the Texas grid operator’s energy-only market (project 47199). Stakeholders have suggested a wide range of market improvements, from adjusting reliability unit commitment (RUC) mitigation rules and instituting penalty curves for pricing constraints, to incorporating marginal losses’ costs into dispatch decisions and requiring locational reserve requirements.
The question of whether to defer market design changes until after the summer is yet another issue that must now be resolved.
The Monitor has called RTC the “most vital” market improvement. RTC is “foundational” to efficient pricing, it told the PUC, “especially in an energy-only market like ERCOT where participants rely on energy prices to facilitate short-term decisions to commit generation and long-term decisions to invest and retire.”
“The benefits of RTC would be substantial, as supported by the results seen by other [ISOs] where RTC is implemented,” the Monitor said.
ERCOT staff have been working on a study of the costs and time it would take to implement RTC or marginal losses in the wholesale market. A July report indicated it would take at least $40 million and four to five years to make the changes. A September report lowered those figures to at least $10 million and 18-24 months.
In December, the ISO filed a proposed plan to further assess the benefits of implementing RTC and marginal losses. Staff suggest using IMM software code to run a simulation of RTC in historical security constrained economic dispatch (SCED) cases to estimate the cost savings on an interval-by-interval basis, a process they expect to take six months.
ERCOT said introducing RTC into the market would provide additional flexibility in the real-time market in locating ancillary services, which would require modifying the RUC engine “to ensure a reliable operating plan.”
Staff predicted it would take about six months to complete a benefits assessment of marginal losses. ERCOT and the Monitor have promised another status update by the end of the first quarter.
New Loads, Oncor Deal
In the meantime, the PUC will hold a hearing Jan. 17-18 on Lubbock Power & Light’s proposed migration of 430 MW of load from SPP into ERCOT. The commission is also waiting on the results of a joint study on Rayburn County Electric Cooperative’s proposed transfer of another 150 MW of load from SPP to ERCOT.
In February, the PUC is scheduled to conduct a hearing on California-based Sempra Energy’s proposed $9.45 billion acquisition of Oncor and its bankrupt parent, Energy Future Holdings. Sempra and Oncor on Dec. 14 filed a settlement they had reached with key Texas stakeholder groups. (See Sempra, Oncor Reach Deal with Texas Stakeholders.)
