Page 1207 – RTO Insider

January 2, 2018

Counterflow: Brother, Can You Spare 70 Billion Dimes?

Counterflow

By Steve Huntoon

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.

[Editor’s Note: Since this column’s publication, more states have begun actions to claw back the tax savings for consumers. See Utilities Likely to Pass Tax Bill Gains to Customers.]

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. ↑
http://www.energy-counsel.com/docs/Nice-Work-If-You-Can-Get-It-Fortnightly-August-2016.pdf. ↑
LED lighting is killing electric demand, as I’ve written about, http://www.energy-counsel.com/docs/LED-Kills-the-Edison-Star-2017-01-24%20RTO-Insider-Individual-Column.pdf, as have others more recently, https://energyathaas.wordpress.com/2017/05/08/evidence-of-a-decline-in-electricity-use-by-u-s-households/. ↑
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 exception is Kansas, where on Dec. 14, the Kansas Corporation Commission staff requested rate investigations with interim accounting measures, http://estar.kcc.ks.gov/estar/ViewFile.aspx/S20171214155815.pdf?Id=660e208e-b7b9-4263-9168-688f4dc50759, and a Kansas industrial consumers group filed a complaint against all investor-owned electric and gas utilities, http://estar.kcc.ks.gov/estar/ViewFile.aspx?Id=6d5a5f12-f228-483a-b416-1f7b488f0bbf. And Montana regulators voted last week to require its utilities to immediately defer the tax benefit and to submit proposals for passing it through to consumers. Michigan and South Dakota are among other states reportedly opening dockets on this issue. ↑
http://eei.org/resourcesandmedia/newsroom/Pages/Press%20Releases/EEI%20Passage%20of%20Tax%20Reform%20Bill%20a%20Win%20for%20Electricity%20Customers.aspx. ↑
“On the regulated side of the fence, utilities will almost certainly be required to pass along savings from new tax guidelines through state regulatory proceedings.” https://marketintelligence.spglobal.com/documents/our-thinking/research-reports/Corporate-Tax-Reform-and-Utilities.PDF. ↑

January 2, 2018

PJM Markets Still Unsettled

By Rory D. Sweeney

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.

DOE NOPR capacity market pjm CCPPSTF — CCPPSTF attendees left to right: Dave Scarpignato, Calpine; Tom Hoatson, LS Power; Adrien Ford, ODEC; Susan Bruce, Attorney for the PJM Industrial Customer Coalition; Ruth Anne Price, Division of the Public Advocate of the State of Delaware; Carl Johnson, representing the PJM Public Power Coalition; Sharon Midgley, Exelon; Jason Barker, Exelon; Luis Fondacci, NCEMC and Ken Foladare, Tangibl | © *RTO Insider*

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.

Will PJM Maintain Control of its Energy Markets?

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.)

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?

pjm capacity market CCPPSTF DOE NOPR — 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.

FERC staff approved the plan in March while the commission lacked a quorum, but it could revisit the issue now that four new commissioners have joined. (See FERC Staff OKs PJM Aggregation, DR Rules; Refunds Possible.)

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.)

Who Triumphs in the Transmission Battle?

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.)

NERC also has called for more attention to gas pipeline contingencies in reliability planning. (See NERC: Natural Gas Dependence Alters Reliability Planning.)

How Will PJM Meet Fast-Start Order?

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.

January 2, 2018

Fast-Start Resource Pricing Adds to SPP’s Workload in 2018

By Tom Kleckner

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 FERC fast-start resources LMPs — | *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.

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 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.)

January 2, 2018

Wind Nearing Coal as ERCOT Ponders Thinning Reserves

By Tom Kleckner

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.)

Reserve Margin Reduced

ERCOT reserve margins wind energy — Garza | © *RTO Insider*

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.

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%.

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.)

January 2, 2018

MISO in 2018: Storage, Software, Settlements and Studies

By Amanda Durish Cook

CARMEL, Ind. — MISO’s 2018 to-do list includes continuing efforts to expand energy storage participation, extensive software upgrades, a tardy five-minute settlements rollout and studies on its changing resource mix.

Storage Dialogue

In August, MISO stakeholders determined that creating energy storage market definitions and rules was the single biggest market issue for 2018. (See “Stakeholders Give Energy Storage Top Spot in Roadmap,” FERC Rule Would Boost Energy Storage, DER.)

In January, the task force plans to create a list of how storage currently participates in MISO markets and when it is and isn’t compensated to identify “gaps,” according to American Transmission Co.’s Bob McKee. Fernandes said that he didn’t want to simply roll storage benefits into a fixed transmission charge “on the backs of ratepayers.”

MISO Executive Director of Market Design Jeff Bladen said the RTO will work on storage attribute compensation “to the extent to which we can identify appropriate uncompensated attributes.” He warned that not all stakeholders will agree that certain attributes ought to be compensated.

External Capacity Zones

MISO hopes in 2018 to conclude yearslong efforts to introduce external capacity zones into its Planning Resource Auction. In response to the increase in intermittent generation and an aging baseload fleet that’s more prone to outages, the RTO also is considering setting capacity procurement requirements for load-serving entities. MISO predicts it will require just more than 17% of reserves for the 2018/19 planning year, a requirement that’s been steadily increasing year-over-year.

5-Minute Settlements Deferment

Some of MISO’s 2018 capital spending will be devoted to a delayed execution of FERC-ordered five-minute settlements.

In mid-November, MISO asked FERC to delay the settlements’ go-live date to July 1, instead of March 1 (ER18-314), after stakeholders said the RTO’s behind-schedule replacement of its overall settlements computer system would result in a rushed process for members to make their own software adaptions to accommodate the new process. The extra time will be used for software testing for both MISO and its member companies. (See MISO Members Seek Delay on Five-Minute Settlements.)

Raising the Offer Cap

The RTO also must regroup and plan direction on a revised Order 831 compliance filing after its energy offer cap design was rejected by FERC (ER18-300) in November.

FERC turned down MISO’s $1,000/MWh soft cap and $2,000/MWh hard cap, saying it would prohibit resources from submitting cost-based offers above the hard cap. (See MISO to Seek Waiver After FERC Rejects Offer Cap Plan.)

Queue Discussion Lined Up

MISO’s new interconnection queue design was accepted by FERC at the beginning of 2017, but there may be more changes coming.

Although the new queue design is meant to reduce the amount of time spent on studies, a very full queue project line-up has MISO staff warning stakeholders of delays.

Some stakeholders have already asked FERC to force additional rule changes. (See EDF Asks MISO to Revisit Queue Overhaul.)

“We just went through a rather exhaustive queue reform, but now that we’ve got the process and implemented it, there are a certain number of stakeholders that don’t believe it’s working,” said Wisconsin Public Service’s Chris Plante during the December Advisory Committee meeting.

MISO energy storage software upgrades — December Advisory Committee | © *RTO Insider*

MISO President Clair Moeller said the last time that the queue was this packed was in 2007.

About 60 GW of proposed generation is seeking interconnection, including 30 GW of wind, 15 GW of solar, 12 GW of natural gas and 600 MW of other resources. The queue also holds about 140 MW of prospective battery storage capacity.

“There’s a lot of capacity in the queue, and a lot of it won’t come online, but a lot of it will,” MISO CEO John Bear said during a Sept. 21 Board of Directors meeting.

Market Platform Replacement

MISO’s information technology department and vendor General Electric will begin in 2018 a seven-yearlong replacement of its market platform, the system responsible for operation of the day-ahead and real-time markets.

“These systems were designed in the late 90s and began operation in the early 2000s, and you think about all the technology advancements since then and how the cybersecurity threat landscape has changed,” Kevin Sherd, MISO director of forward operations planning, said at a December Market Subcommittee meeting.

The RTO expects to spend $21.7 million in 2018 on the project, one-sixth of its planned total spending over the next seven years. (See MISO Makes Case for $130M Market Platform Upgrade.)

MISO is looking for a system that “will best position us for the future,” Sherd said. The RTO’s current inflexible system, which has become increasingly challenged by market changes, will be swapped for a modular market platform allowing programs to be changed without impacting others. “Building something that is more adaptable is our core principle,” he said.

New Website

MISO will fully launch its new external website in the coming weeks. Sometime after January, MISO’s current site will shift to the web address old.misoenergy.com. The RTO will maintain its old public website through the first quarter to make certain that it still has a website in the event of a failure of the new website.

A beta version of the new website has been up since October at beta.misoenergy.org, where the RTO recently added log-in capability for meeting registrations.

Competitive Bidding in 2018

MISO will oversee the competitive bidding of the yet-unapproved $130 million Hartburg-Sabine 500-kV line market efficiency project in eastern Texas this year. (See MISO Board Approves $2.6B Transmission Spending Package.)

The Hartburg-Sabine project will be MISO’s second-ever competitively bid transmission project and the first such project to include a substation. The RTO plans to add two new staff members to oversee the competitive process. The line is intended to alleviate constraints in MISO South’s West of the Atchafalaya Basin load pocket area spanning Texas and Louisiana.

Meanwhile, work is underway on the Duff-Coleman 345-kV transmission project in Southern Indiana and Western Kentucky, MISO’s first competitively bid project. For most of 2018, LS Power subsidiary Republic Transmission will work on project design, environmental permitting and securing rights of way. Construction is slated to begin the fourth quarter of 2018. MISO selected Republic’s $49.8 million proposal for the new, 30-mile, 345-kV line last December. (See LS Power Unit Wins MISO’s First Competitive Project.) Republic said it expects to encounter “construction risks and challenges,” most notably acquiring federal permits to cross the Ohio River.

The PJM Relationship

MISO and PJM also hope to implement a two-part fix in early 2018 to remedy their double-charging of congestion fees on pseudo-tied generation. The RTOs are facing five complaints concerning overlapping congestion charges for pseudo-tied generators. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)

The fix has been complicated by the discovery that PJM has been making errors on market-to-market calculations.

For years, PJM has been overstating its own transmission loading relief (TLR) because of a calculation error and its failure to order mandated tests required to define M2M constraints between the two RTOs. (See MISO Board, Monitor Seek Response to PJM M2M Missteps.)

“We’re going to explore with PJM what needs to happen retroactively and maybe what needs to happen going forward,” Bladen said during a Dec. 14 Market Subcommittee meeting.

Sign-of-the-Times Studies

MISO is planning studies in 2018 on how to respond to increasing natural gas and renewable generation. One study will gauge how the natural gas supply affects MISO’s dispatch ability.

Vice President of System Planning Jennifer Curran said the RTO and stakeholders will work throughout 2018 to “recognize the impact large gas pipeline contingencies have on the MISO system.”

Curran said MISO already has a good idea of where pipelines are located, but it wants to analyze the footprint’s gas supply and the potential consequences if some infrastructure were to fail.

MISO’s 2018 Transmission Expansion Plan will seek to identify where wind generation is likely to grow the fastest.

At the Annual Stakeholders’ Meeting in June, Board Chairman Michael Curran said he had confidence MISO could scale future obstacles, including portfolio evolution, renewable penetration and future federal and state regulations.

“It’s a very unsettling time. It’s almost as if the earth is moving from under us. And that may be the case in Oklahoma with fracking ― unproven of course,” he quipped.

January 2, 2018

CAISO Bid for Western RTO to Face Competition in 2018

By Jason Fordney

The Western Energy Imbalance Market (EIM) expanded its footprint and ambitions in 2017 while new suitors lined up to compete with CAISO as the vehicle for a Western RTO.

CAISO EIM Western RTO resource adequacy — Current and pending members of CAISO’s Western EIM | *CAISO*

Idaho, Washington, Arizona, Nevada and Canadian provinces are considering how to access regional markets while protecting the financial health of their resources and keeping costs reasonable for consumers.

The EIM has been recognized as a success story. The increased efficiency of regional dispatch and having more offramps for generation are attractive not only for renewables, but also for coal, hydro and natural gas generation in the market’s balancing authorities.

Five utilities have joined the EIM since its inception in 2014, including Portland General Electric in 2017. Six others have announced plans to join: Idaho Power and Powerex in 2018; Los Angeles Department of Power & Water and the Sacramento Municipal Utilities District in 2019; and the Salt River Project and Seattle City Light slated for 2020. In December, CAISO announced plans to expand its EIM offerings with a day-ahead market. (See CAISO Plan Extends Day-Ahead Market to EIM.)

Mountain West, Peak Reliability

But CAISO faces competition in its bid to expand into a RTO.

Last January, Mountain West Transmission Group said it would begin talks to join SPP. Mountain West, a partnership consisting of seven different transmission-owning entities within the Western Interconnection, covers most of Colorado and Wyoming with smaller areas of Arizona, Montana, New Mexico and Utah. The potential move has been of keen interest to regulators in the affected states. (See Colo. Regulators Talk Governance with SPP, Mountain West.)

In December, reliability coordinator Peak Reliability announced it would work with a unit of PJM to develop new market structures for the West. “We are continuing our review with PJM Connext of potential reliability services and markets in the West and our outreach with western industry leaders and stakeholders,” spokeswoman Rachel Sherrard told RTO Insider last week. (See PJM Unit to Help Develop Western Markets.)

Legislation Stalls

The California State Legislature ended its 2017 session in September after failing to pass bills that would have advanced CAISO’s regionalization efforts.

AB 726 and AB 813, which were returned to the Senate Rules Committee, would have repealed a section of the Clean Energy and Pollution Reduction Act of 2015 governing the transformation of the ISO into an RTO and created a Commission on Regional Grid Transformation. The bills would authorize the transformation if the CAISO Board of Governors and the commission took certain actions by the end of 2018.

Lawmakers say they will reconsider the legislation after they return to Sacramento this month. The debate over regionalization in California involves issues of state control over resources and policy, and highlights concerns over energy costs and the influence of labor groups worried over exporting energy jobs.

The legislature also is under heavy pressure to pass zero-carbon legislation that also fell short in 2017. California’s policies to phase out fossil fuels in favor of renewables and new technologies have raised cost concerns and forced changes to long-standing engineering approaches to accommodate more variable renewable output and the complexities of smaller, distributed resources. (See CAISO Regionalization, 100% Clean Energy Bills Fizzle.)

Gov. Jerry Brown has taken a defiant stance against President Trump’s environmental policies, recently traveling internationally to evangelize for fighting climate change.

Brown attributed the recent wildfire devastation in California to climate change, saying the state’s fire season is now months rather than weeks. Fire investigators are focused on utility infrastructure as a possible cause, setting up complicated and contentious proceedings at the Public Utilities Commission over penalties and cost recovery. (See CPUC Targets Wildfires, Multifamily Solar, RMRs.)

During an interview on “60 Minutes,” Brown discussed Trump and climate change in religious terms. “I don’t think President Trump has the fear of the Lord, the fear of the wrath of God, which leads one to more humility,” he said. “And this is such a reckless disregard for the truth and for the existential consequences that can be unleashed.”

This summer, Brown signed a bill that extended the state’s carbon cap-and-trade program until 2030. (See California Lawmakers Extend Cap-and-Trade.) The program will help the state meet its goal of reducing GHG emissions to 40% below 1990 levels by 2030.

Other CAISO, PUC Initiatives

In addition to its regionalization efforts, CAISO has more than a dozen other initiatives underway, with day-ahead market enhancements and resource adequacy at the top of the list in its 2018 roadmap. The conflict between state resource adequacy programs and CAISO’s reliability management are another priority because of the increasing number of reliability-must-run agreements.

The growth of community choice aggregators led the PUC to propose that they be subject to the same resource adequacy requirements as electric utilities. (See California Proposes Resource Adequacy Obligations for CCAs.)

In December, the board of the Western Electricity Coordinating Council, the NERC-designated Regional Entity for 14 Western U.S. states, Alberta, British Columbia and a small portion of Baja California, Mexico, endorsed a new three-year operating plan. The plan continues the transformation that began in 2014, when Peak Reliability split off from WECC as the Reliability Coordinator for the Western Interconnection, except Alberta. (See WECC Finding New Direction in Old Mission.)

January 2, 2018January 17, 2024

CORRECTED: New England Leads East in Renewables Transition

By Michael Kuser

ISO New England will open the new year by filing with FERC a two-settlement market construct to integrate state-sponsored renewable energy resources into the wholesale electricity market.

The New England Power Pool’s Participants Committee voted Dec. 8 on the two-tier market concept called Competitive Auctions with Sponsored Policy Resources (CASPR), but with 57.75% of the vote, the proposal failed to reach the 60% mark needed to be considered supported by the PC. Nonetheless, the RTO plans to file the proposal with FERC this month, according to spokesperson Matt Kakley. (See New England Strives to Find CASPR Consensus.) [Editor’s Note: An earlier version of this article incorrectly stated that the vote would be taken in January.]

Under CASPR, ISO-NE would conduct the Forward Capacity Auction in two stages, allowing existing resources that have capacity obligations and a desire to retire to trade out their obligations with incoming state-sponsored resources in a manner that doesn’t affect price formation in the primary auction.

In the primary FCA, resources would clear based on current rules, including those designed to mitigate offers below competitive prices such as state-sponsored resources. In the secondary or substitution auction, existing resources that cleared in the FCA would be able to transfer their capacity obligations to new sponsored policy resources that did not clear, with the existing resource agreeing to retire early in exchange for a “severance” payment.

CASPR, which arose from the Integrating Markets and Public Policy (IMAPP) process begun in 2016, is just one of the electricity policy issues facing New England.

State-Sponsored Renewable Energy

In January, Massachusetts will select the winners of last July’s solicitation for 9.45 TWh/year of hydro and Class I renewables (wind, solar or energy storage). Contracts with the winning bidders under the MA 83D request for proposals are due to be completed in late April.

The proposals include an HVDC transmission line from northern Vermont to New Hampshire to deliver 1,200 MW of new wind power from Canada; a 375-mile submarine HVDC transmission line extending from New Brunswick to Plymouth, Mass.; and a submarine cable under Lake Champlain to bring 1,000 MW of hydropower, solar and wind from Canada. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)

Offshore Wind in Mass.

Three developers submitted proposals Dec. 20 in response to Massachusetts’ solicitation for up to 800 MW of offshore wind energy, offering projects that include a transmission “backbone” and storage to enable them to perform like a baseload resource.

The state’s 2016 Act to Promote Energy Diversity mandates that the Department of Energy Resources and the state’s distribution utilities sign long-term contracts for 1,600 MW of offshore wind by June 30, 2027.

The state’s first RFPs (solicitation 83C) called for a minimum of 400 MW but said the state would consider bids of up to 800 MW if it determines that a larger proposal is superior to and more economical than the others.

The three developers — all with ties to the state’s utilities — have purchased renewable energy leases off the coast from the federal Bureau of Ocean Energy Management. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)

The state will announce the winners of the offshore wind solicitation on April 23, and contracts are to be submitted at the end of July.

Storage Coming on Strong

As of December, ISO-NE reported more than 470 MW of energy storage in the interconnection queue, a nearly six-fold increase in one year.

Massachusetts is funding incentives to include energy storage in solar installations, as well as grants for peak demand reduction. Pairing energy storage with solar panels is meant to enhance grid resiliency by reducing the need for traditional generation to ramp up when the sun goes down. Peak reduction grants cover a wide range of projects, from utilities improving the efficiency of substations, to municipalities working to reduce the energy consumption of big-box retail stores, to a thermal energy storage project on Nantucket that will delay the need for a new undersea transmission cable. (See Massachusetts Awards $20M in Energy Storage Grants.)

The state in 2017 launched its Solar Massachusetts Renewable Target (SMART) program to provide incentives for “long-term sustainable … cost-effective solar development.” The program provides incentives based on location, and to projects that provide unique benefits, including community solar and energy storage

Massachusetts’s new Alternative Energy Portfolio Standard is the only one of its kind in the country. The final draft regulations, released Dec. 29, include combined heat and power, flywheel storage, renewable thermal, fuel cells and waste-to-energy thermal technologies. The regulations oblige all retail electric suppliers to acquire a percentage of their power from eligible technologies, starting at 4.25% in 2017 and increasing by 0.25% each year through 2020, and by the same amount each year thereafter, subject to DOER review.

Millstone Debate

Opponents of Dominion Energy’s bid to win state subsidies for its Millstone nuclear plant were cheered in December as consultants hired by Connecticut said the plant is likely to remain profitable through 2035 even under low natural gas prices. The report by Levitan & Associates concluded “there is no ‘missing money’ required to ensure Millstone’s financial viability through the existing term of Millstone’s Unit 2 operating license” in 2035. (See Millstone Likely Profitable Through 2035, Conn. Consultant Says.)

The report projected that in 2022 the plant would earn after-tax net cash flow of $100 million under a low gas price/high operating cost scenario, to more than $200 million under the reference case that assumed “business-as-usual” conditions.

Connecticut Gov. Dannel Malloy ordered state regulators in July to assess the economic viability of the plant and determine whether the state should provide it financial support. Malloy’s executive order also directed the state Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority to assess the role of large-scale hydropower, demand-reduction measures, energy storage and emissions-free renewable energy in helping Connecticut meet its ambitious targets to cut its carbon output. (See CT Gov Orders Financial Analysis of Millstone Plant.)

January 2, 2018March 14, 2024

New York Forges Ahead on Clean Energy

New York’s electricity policymakers were very busy in 2017, setting a U.S.-record offshore wind target, devising an outline for pricing carbon into wholesale markets and facing down legal challenges to efforts to rein in energy service companies and its nuclear subsidies. The state also agreed with Entergy on the staggered closing of its 2,311-MW Indian Point nuclear plant, which will retire the second of its two remaining generators in 2021.

2018 will be eventful as well. Storage targets will be mandated early this year, the technical details of carbon pricing will be ironed out in conferences and public hearings, and a master plan for offshore wind will be released.

Carbon Pricing

Prompted by the state Public Service Commission’s decision to subsidize upstate nuclear plants through zero-emissions credits (ZECs), NYISO commissioned a report by The Brattle Group on pricing carbon into generation offers and reflecting it in energy clearing prices. Released by NYISO and the state Department of Public Service in August, the report found that a $40/ton carbon charge in New York state would have “a relatively small impact” on customer costs, ranging from a −1% to +2% change in total customer electric bills. (See NYISO Study Sees Little Cost Impact from Carbon Charge.)

The ISO and the PSC in October established the Integrating Public Policy Task Force (IPPTF) to explore the carbon pricing issue. In the fall, the task force held public hearings and a technical conference to discuss issues, including the allocation of carbon revenues and border adjustment mechanisms to prevent “carbon leakage” — an increase in emissions in regions neighboring New York. (See New York Hashes out Details of Carbon Policy.)

The IPPTF will next meet Jan. 8 in Albany.

ZECs Win in Court

ZECs are part of the state’s Clean Energy Standard, which mandates reducing greenhouse gas emissions by 40% by 2030, from a 1990 baseline, and by 80% by 2050. It also calls for renewables to meet 50% of the state’s energy needs by 2030.

In July, a federal judge dismissed a challenge to the ZEC program by the Electric Power Supply Association and several of its members.

The plaintiffs argued that the program violates the Federal Power Act and the Constitution’s dormant Commerce Clause by intruding on FERC’s authority to regulate wholesale prices and favoring in-state generators. (See New York ZEC Suit Dismissed.)

In August, the plaintiffs appealed to the 2nd U.S. Circuit Court of Appeals to review the ruling. Oral arguments have been proposed for the week of March 18, but the schedule has not been finalized. (The 7th Circuit will hear a similar challenge to the Illinois ZEC program Jan. 3.)

Indian Point Closure and Reliability

The year began with Gov. Andrew Cuomo reaching an agreement with Entergy on his long-sought goal of closing the Indian Point nuclear plant, which the governor worries is too close to New York City. Under the deal, Units 2 and 3 will be deactivated by April 30, 2021. The agreement would allow the plants to operate for two additional two-year increments — with final closure slated for 2025 — if an emergency affected reliability in the New York City area. Unit 1 was shut down in 1974.

NYISO reported in December that gas-fired and dual-fuel generation coming online in the next few years will be enough to maintain reliability after the Indian Point closure.

The ISO report cited three generation projects totaling 1,818 MW under construction: the 120-MW Bayonne Energy Center II uprate in NYISO Zone J, and the 678-MW CPV Valley and 1,020-MW Cricket Valley plants in Zone G. (See New Builds to Cover Indian Point Closure, NYISO Finds.)

Distributed Energy Resources and ESCOs

New York’s utilities will use 2018 to continue developing the analytical tools to deal with distributed energy resources and transition from a one-way transmission system to a multidirectional grid.

The ISO’s DER Roadmap, issued in February 2017, outlines the grid operator’s plans for integrating DER into its ancillary services, capacity and energy markets over the next five years.

In September, the PSC approved an order implementing a new compensation structure for DER. (See NYPSC Limits ESCO Service, Sets New DER Compensation.)

In July, the commission expanded and extended Consolidated Edison’s Brooklyn-Queens Demand Management project and in August approved a Con Ed solar project dedicated exclusively to low-income customers.

In October, the PSC approved an implementation plan to allow municipalities to engage in community choice aggregation initiatives, and enacted the first consumer protection standards for DER. (See New York PSC Adopts DER Rules, Sanctions ESCOs.)

The PSC also faced legal challenges to its December 2016 order banning energy service companies (ESCOs) from serving low-income customers unless they obtain waivers by guaranteeing reduced bills or other benefits (Case 12-M-0476).

State and federal courts temporarily blocked the ban on several occasions during 2017. In November, the 2nd Circuit denied a motion for a stay pending appeal. On Nov. 22, the PSC issued an order setting dates for implementation of the December 2016 order on a rolling basis as contracts expire. In the meantime, the commission approved waivers on about half of the dozen requests it received from ESCOs.

Coming Storage Revolution

On Nov. 29, Cuomo signed legislation requiring the PSC to establish targets for energy storage by early 2018. (See NYISO Readies Market for Energy Storage, State Targets.)

In December, NYISO released a report detailing its plan for opening its wholesale markets to storage. The ISO report, “State of Storage: Energy Storage Resources in New York’s Wholesale Markets,” lays out three stages to facilitate storage participation — integration, optimization and aggregation with other DER. The ISO will allow storage resources to provide all the grid services that they’re capable of, while also reducing the minimum participation size from 1 MW to 0.1 MW.

Storage developers and utilities have been working with the ISO to establish ways storage can participate in both retail and wholesale markets. The ISO report distinguishes between storage in front of the meter and behind the meter, with the former more likely to participate in wholesale market transactions, although BTM storage could become a wholesale player when aggregated with other distributed resources. (See New York Sees Storage in Retail and Wholesale Markets.)

The ISO plans on having storage market rules ready for commercial use in 2020.

The PSC in May took actions to allow large commercial batteries in New York City, and in December approved a three-year, $7.5 million pilot program for Con Edison to control its New York City customers’ air conditioners to help shave peak demand in summer. Con Edison also is working with various companies on demonstration projects to use storage and software to shave peak demand.

Offshore Wind

New York will be the biggest state player in offshore wind if it meets the target set by Cuomo in January 2017: 2,400 MW by 2030. State policymakers are embracing offshore wind for both its utility-scale generation, its ability to be developed close to the major load centers of New York City and Long Island, and its potential jobs. (See New York Seeks to Lead US in Offshore Wind.)

The first offshore wind lease for New York, a nearly 80,000-acre site off the Rockaways in Queens large enough to generate up to 1 GW, went to Norway-based Statoil in December 2016. Statoil says the project, which it has dubbed Empire Wind, is in early-stage development. It hopes to sign a power purchase agreement with a U.S. utility for the project by the end of 2018.

The first project in the water could be the 90-MW South Fork Project off Montauk, which was approved by the Long Island Power Authority in January. Developer Deepwater Wind says construction could start as early as 2019, with the wind farm operational as early as 2022.

The New York State Energy Research and Development Authority is drafting a master plan that will include an offtake transmission element, the crucial part of getting wind-generated power to shore. The master plan will include a timeline and recommendations on how to speed up the offshore planning and permitting process.

December 24, 2017

Stakeholder Soapbox: Your Audit Report may be Worthless

By Terry Brinker

If you are like me, some sounds drive you crazy. For example, nails raking across a blackboard have always made me cringe. Recently, another sound or comment has given me that same response. When I speak with companies about doing a compliance assessment, an internal controls evaluation or even a mock audit, often I hear, “We are good; we passed our most recent audit.” Someone may as well have just raked his or her nails across a blackboard.

Just ask the entities involved in the 2011 Southwest Blackout how passing an audit helped their case in the subsequent investigation. I will tell you. It did not help. Federal regulators assessed $37 million in fines and penalties as a result of that event. Arizona Public Service was assessed a penalty of $3.25 million despite having passed an audit earlier in the year. The Western Electricity Coordinating Council and Peak Reliability, WECC’s successor as the reliability coordinator for most of the Western Interconnection, was penalized $16 million. Peak had recently passed a NERC certification, which is essentially an audit of an entity’s readiness and capabilities. No one received a get-out-of-jail-free card.

Entities have regarded a good audit report as proof that they have a good compliance program. In fact, your audit report may be worthless. Regional Entities perform audits and send a report to NERC. Often these regional auditors are folks with whom you either worked or see so often you become friends. Many potential violations are often reduced to recommendations or suggestions resulting in a clean audit report. After all, I know “Fred” or “Sue,” and they will clean up these little nits.

What is overlooked or simply not understood is that if there is an event involving your company, an anonymous complaint filed against you or a spot check is performed that results in an investigation, your friends — oops, I meant regional auditors — will not be able to help you. NERC and FERC will step in and kick the regions out faster than a drunk uncle at the family Christmas gathering. NERC and FERC will go through your company with a fine-tooth comb, reviewing compliance documents, listening to voice recordings, conducting interviews and getting staff on the record. They will leave no stone unturned.

Not to mention, NERC and FERC have a higher standard than the regions. I know because I was a senior investigator at NERC and was responsible for conducting the above-mentioned duties, which resulted in millions of dollars in fines and penalties for entities. And remember, you do not have to be the utility that caused the event. Imperial Irrigation District (IID) was penalized $12 million even though they did not initiate the event. This is why I stress to my clients that I am not just preparing them for an audit, but also closing any compliance gaps in case there is a reason for NERC or FERC to come snooping around.

Leadership at utility companies must ask themselves if they are comfortable having a “check the box” compliance program, which meets the letter of the law, or a robust compliance program that meets the spirit of the law and would withstand the rigors of audits and investigations alike. Organizations owe it to their stakeholders to have a robust risk management program that will greatly limit its liability. If internal controls evaluations, mock audits and compliance assessments are not a part of the risk management strategy, I question leadership’s commitment to be the best it can be. There will be another event that will lead to another investigation, and stiff fines and penalties will be handed out. In the words of Bruno Mars, “Don’t believe me just watch.”

“But we passed our audit!” will not help the utilities involved. So, let me ask, has your company conducted an internal controls evaluation, compliance assessment or mock audit lately? And remember, I hate the sound of nails raking across a blackboard.

Terry Brinker, who has 23 years of experience leading, facilitating and implementing improvements in power plant operations, control room operations, compliance and regulatory matters, is the president of Reliable Energy Advisors. Terry previously served in leadership roles during a five-year stint at NERC, where he served as senior manager of standards information and personnel certification, manager of registration services, and senior event investigator.

December 24, 2017

FERC OKs Changes to SPP’s Tx Planning Process

By Tom Kleckner

FERC last week accepted Tariff revisions to streamline SPP’s Integrated Transmission Planning (ITP) process, despite opposition from wind developers.

The commission’s Dec. 21 order accepted the revisions as consistent with the transmission planning requirements under FERC Orders 890 and 1000 (ER17-2027).

SPP’s filing drew protests from the American Wind Energy Association, the Wind Coalition and four renewable energy companies. They contended that SPP’s ITP process did not meet Order 890’s transparency principle because it lacked details of the process currently found in the ITP Manual.

Arkansas transmission lines | *MGN Photo*

AWEA and the Wind Coalition also argued that the Tariff should “specify the transmission elements and voltage levels to which the ITP assessment applies; more clearly provide opportunities for stakeholder input on economic transmission needs; include additional details on the inputs SPP plans to incorporate into its planning studies and how SPP will determine the inputs to use; and explain how SPP will coordinate its aggregate transmission study, generation interconnection and ITP processes.”

The wind developers added that the Tariff, rather than the ITP Manual, “should detail how SPP determines the variable operations and maintenance cost for wind and solar resources; incorporate reasonable, objective standards to identify the amount of wind generation that SPP will use in its planning models; include triggers to address economic market conditions; and specify the criteria for identifying persistent operational issues.

FERC said the concerns “relate to elements of the ITP process that SPP does not propose to change, and thus are beyond the scope.”

“SPP’s proposed Tariff revisions implement this proposal without otherwise modifying the existing ITP process,” the commission said.

The protesters further argued that SPP should hold two planning summits per planning cycle, rather than the proposed annual summit. FERC agreed with the RTO’s argument that reducing the number of required planning summits “will not affect stakeholders’ ability to provide input.”

ITP integrated transmission planning SPP — GridLiance’s Brian Gedrich (l), SPP Director Harry Skilton discuss the new transmission planning process in 2016 | © *RTO Insider*

“Stakeholders may participate at the working group level and throughout the transmission planning process,” the commission noted, saying SPP could always schedule additional planning summits as needed.

Stakeholders approved the process changes, which were developed by a member task force, in July 2016. Under the new process, SPP will combine the ITP’s near-term and 10-year assessments and NERC transmission planning assessments into a single 10-year study. It also modified the 20-year assessment’s timing from at least once every three years to five years.

The changes will result in an annual transmission expansion plan addressing reliability, economic and policy needs. The first study under the new process began in September, and results will be unveiled in October 2019.