CAISO this month launched a sweeping set of updates to its interconnection policies, an annual process made increasingly complex by a rapidly changing resource mix.
The effort “will likely address some substantial concepts but also a myriad of minor concepts that have not been addressed in some time,” the ISO said of its 2018 Interconnection Process Enhancements (IPE) initiative.
“Once we finalize the scope of the initiative, we will be able to determine the issues that will be included in this year’s process and the timing for development,” CAISO said.
The program is divided into six broad categories: deliverability; energy storage; generator interconnection agreements; interconnection cost responsibility and financial security; interconnection requests; and modifications.
A Jan. 17 issue paper defined the proposals that CAISO is considering. The document includes 42 potential topics and will be developed into a draft final proposal, but the ISO has not specified when it would be presented to the Board of Governors for approval.
The deliverability category alone contains nearly a dozen topic areas related to transmission planning, criteria for commercial viability and transparency into the availability of deliverability.
Other major tasks laid out in the IPE paper include:
Ensuring the development of the most viable projects;
Giving projects with power purchase agreements a greater opportunity for deliverability; and
Providing resource developers reasonable timelines for interconnection.
The ISO expects a March ruling from FERC on last year’s more narrowly tailored IPE package, which was expedited to obtain a ruling before the next transmission plan deliverability (TPD) allocation takes place in March.
The ISO published its issue paper on the proposal on January 17
A TPD allocation provides resources the transmission capacity required to deliver power during peak conditions and is a condition of receiving full capacity deliverability status, which is critical for eligibility to be counted as resource adequacy.
CAISO twice a year allocates TPD to generating projects that meet certain criteria. The 2017 IPE package proposes a third TPD allocation, which FERC is likely to approve.
The TPD allocation process works well during periods of high procurement, CAISO said. However, renewable procurements have recently slowed significantly, resulting in few projects meeting the criteria to qualify for a TPD allocation.
There are also uncertainties around renewable procurement that will affect the ability of a resource to obtain power purchase agreements. CAISO noted that the California Public Utilities Commission has proposed establishing a two-year resource procurement cycle to meet the targets of integrated resource plans, with the first procurement proposed for the end of 2018. But modeling used by the commission for the program shows a minimal need for renewable procurement until 2026 because California utilities are on track to meet — or exceed — renewable portfolio standard targets, the ISO said.
“The IRP will have significant impacts on interconnection customer’s ability to obtain PPAs for their projects,” CAISO said.
In a Jan. 24 presentation, CAISO discussed items that stakeholders requested be included in the IPE, including a proposal that would allow interconnection customers to replace their entire project with storage during the interconnection process. But CAISO has only approved up to 10% conversion to battery from an existing project during the process.
“A complete change of technology from existing technology requires a study to determine the new electrical characteristics and the impact to the grid,” CAISO said in explaining that it would not explore that topic in IPE 2018.
The energy storage category of IPE 2018 is focused on distributed energy resources, wholly replacing existing facilities and deliverability assessment for energy storage.
The ISO is taking comment on the IPE package through Feb. 7 and said stakeholders should suggest other items that might be included.
CARMEL, Ind. — MISO is asking stakeholders to put pen to paper by spring to describe how the RTO should measure grid resilience.
Stakeholders will participate in a broad discussion of what constitutes resilience during MISO Board of Directors Week in late March. And the RTO has asked each stakeholder sector to prepare its own whitepaper on the topic.
During a Jan. 23 Informational Forum, MISO CEO John Bear celebrated FERC’s recent decision to reject Energy Secretary Rick Perry’s proposed rulemaking to financially support nuclear and coal-fired generators, instead requiring RTOs to answer questions about how they assess resilience. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.) Bear said MISO is committed to promoting reliability and resilience throughout its footprint, emphasizing that no near-term reliability issues exist, attributable in part to the RTO’s partnership with state regulators.
DOE’s original rulemaking timeline didn’t allow for “reasoned decision-making and thoughtful review,” Bear added.
“A one-size fits-all wasn’t feasible in MISO given our diverse footprint,” he said, promising to work with stakeholders in drafting a response to the order. MISO Director of Planning Jeff Webb last week said the RTO is still holding internal meetings to formulate its response.
MISO Website Officially Migrates
MISO’s officially launched its redesigned website on Jan. 16, and market reports and real-time data feeds are up and running, said Kacey George, the RTO’s digital strategy adviser.
“We had 12 million hits on the first day,” George said.
MISO expects to upload planning and training materials as well as leadership and governance pages by the end of the month, she said. Staff must also address a few bugs, namely involving some member pages related to the interconnection queue.
Lower natural gas prices and relatively light congestion translated into lower year-over-year prices for MISO in December despite slightly higher load.
Shawn McFarlane, MISO executive director of strategy, said average temperatures in the RTO’s footprint last month ranged from 1 to 6 degrees Fahrenheit colder than the 30-year average, driving the increase in load. But prices averaged $27.26/MWh, 11% lower than the same period a year earlier.
“We were about $3/MWh lower than what we saw last year,” McFarlane said.
He credited the lower prices to a 25-cents/MMBtu drop in gas prices and lower congestion compared with the previous December. Average load was up 0.8 GW to 77.7 GW, and load peaked at 98.8 GW on Dec. 27, a 5.8% increase over the average monthly high.
“Multiple rounds of arctic air swept through the footprint” during the month, McFarlane said, making load forecasting challenging and leading to two days with a poor unit commitment score in MISO’s monthly self-assessment.
“Holiday loads … are always kind of tricky to figure out,” he said.
McFarlane also said MISO had to manage high market-to-market congestion with SPP in December because of high wind output and transmission outages in SPP.
MISO Shuffles Leadership
MISO has made several leadership changes in the new year, Bear said.
Todd Ramey will now exclusively head MISO’s market platform replacement effort, leaving his role of vice president of system operations to become vice president of system enhancements, a new position. MISO is poised to spend $130 million by 2024 to replace its aging market platform with a more adaptable modular system.
Former Executive Vice President of Operations and Corporate Services Richard Doying will step away from the operational side of MISO to focus exclusively on designing a market for the future.
“Everything is on the table here,” Bear said of Doying’s new role. “Put some simulations in place and stress it. What concerns me is not so much the next five years, but the five years after that … and the queue shows that. If we don’t get ahead of the curve, we’ll be chasing it.”
Bear said the markets were designed in 2005 and not equipped for today’s realities of more exact forecasting, high wind penetration and copious amounts of data.
“Quite frankly, it’s hard to keep the system safe. It wasn’t designed for the environment we live in today,” Bear said.
Finally, MISO South Vice President Todd Hillman will transition to become head of external affairs.
Additionally, in December, MISO revealed a plan of executive succession that promoted Clair Moeller from vice president to president of MISO, and will have Moeller stepping into the role of CEO should something unforeseen happen to Bear. (See MISO Board Promotes Moeller, OKs 2018 Budget.)
Entergy New Orleans CEO Talks Big Easy Challenges
MISO welcomed Entergy New Orleans CEO Charles Rice during the meeting for a brief conversation of the challenges and considerations of powering the Big Easy.
“It’s a pretty unique place in terms of the population density and the geography. We’re surrounded by water on three sides. For us to import power into the City of New Orleans is very challenging and very difficult,” Rice said.
The city has little right-of-way space for additional transmission lines, Rice added.
The CEO highlighted the need for the planned, $210 million, 128-MW natural gas-fired plant within city limits at the site of Entergy’s retired Michoud plant. He has previously warned that the city has only 1 MW of generation within its borders and needs a more reliable, onsite generation source. The proposed plant currently awaits New Orleans City Council approval; city advisers rejected an earlier proposal from the utility for a larger, more expensive plant.
Hillman asked how Entergy New Orleans plans to prepare for the increased likelihood of another hurricane.
“We never stop preparing. We prepare year-round for hurricanes,” Rice said. “And after … we take a look at what went right, what went wrong.”
Entergy is still in the process of replacing natural gas pipelines damaged by Hurricane Katrina in 2005. “Right now, we’re probably focused on the largest gas infrastructure project in the country,” Rice said.
Rice said New Orleans’ demographics make providing utility service a delicate balance: “37% of my customers live at or below the poverty level, so I’m always thinking of that,” Rice said. “When we make decisions, we have to make sure it’s something our customers can afford.”
He said New Orleans is making strides in its goal of having up to 100 MW of rooftop solar located within the city and will pursue other new technologies, such as building microgrids at hospitals in the coming years.
“There’s going to come a time when customers are going to want to have 100% control of their energy,” Rice said. “If customers want a microgrid, we have to give them a microgrid. If they want rooftop solar, we’re going to have to figure out how to make that work.”
MISO traditionally holds its springtime quarterly board meeting within the city’s French Quarter; this year’s meetings occur March 27-29.
CAISO last week kicked off an effort to implement major changes in the way it procures backstop generation needed to maintain grid reliability, in the face of growing stakeholder dissatisfaction over increased use of the practice.
The ISO is reviewing its reliability-must-run (RMR) and capacity procurement mechanism (CPM) programs and considering combining the two. It considers both backstop procurements to be “last resorts” to guarantee adequate capacity when it identifies generation deficiencies, as well as to prepare for unexpected events on the grid.
CAISO is undertaking the effort “to address concerns identified by the ISO and by other stakeholders” in light of recent RMR and CPM designations, it said in a Jan. 23 straw proposal and issue paper.
“This initiative will review the RMR tariff provisions, pro forma agreement and procurement process, and seek to clarify and align the use of RMR procurement and backstop procurement under the CPM tariff,” CAISO said.
CAISO has recently increased its reliance on RMRs and CPMs for gas-fired power plants, which are unpopular with owners of other resources competing in the market, as well as state regulators who favor non-fossil-based resources. The ISO in recent months has inked contracts with gas plants, citing misalignments with state resource adequacy programs as one reason for doing so.
CAISO has signed RMR contracts with four natural gas-fired power plants | CAISO
The initiative will also look at reworking the ISO’s Condition 1 and Condition 2 classifications for RMR units, which have different payment structures. The former recover only a portion of their revenue requirement, while the latter operate under a full cost-of-service payment methodology.
Following recommendations from the ISO’s Internal Market Monitor, the proposal seeks to remove certain limits on market participation currently imposed on Condition 2 resources and make both types of units subject to must-offer obligations for energy and ancillary services. In a protest of the Metcalf RMR filed at FERC, the Monitor said consumers are currently bearing full costs for Condition 2 facilities that are barred from CAISO markets in many hours.
The grid operator’s Board of Governors in November approved the latest RMRs, with Governor Ashutosh Bhagwat saying: “I am going to hold my nose very, very hard” while voting in favor. (See Board Decisions Highlight CAISO Market Problems.)
But the California Public Utilities Commission responded on Jan. 11 by fast-tracking a nullification of the RMRs. (See CPUC Retires Diablo Canyon, Replaces Calpine RMRs.) Representatives from the CPUC and Pacific Gas and Electric told the ISO board in public meetings that they opposed the contracts.
Grid planners are being pushed into backstop procurements to maintain longer-term reliability as gas generators fail to obtain contracts under California’s resource adequacy program. CAISO has 852 MW of capacity under RMR, including Dynegy’s Oakland units and Calpine’s Feather River, Yuba City and Metcalf Energy Center plants, all of which were signed in September-November 2017.
The involuntary RMRs receive a negotiated rate, and CPMs receive a market-based price subject to a cap. The cost of the contracts eventually falls on retail ratepayers, which must shoulder tens of millions of dollars, often with relatively short notice.
Some power marketers say the rapid growth of community choice aggregators has further scrambled the procurement picture as customers depart from investor-owned utilities, leaving a small rate base to shoulder the costs.
CAISO said it wants to develop the first phase of the new program enhancements in time for May approval by the board. A second phase would be in place this fall to be used in 2019 and would clarify when RMR is used instead of CPM and explore whether the two designations can be merged.
The ISO has already posted a detailed presentation for a Jan. 30 stakeholder meeting to be led by Keith Johnson, manager of infrastructure and regulatory policy.
FERC on Friday accepted an unexecuted large generator interconnection agreement (LGIA) filed by ISO-NE and National Grid for Clear River Energy’s 1,100-MW natural gas-fired plant in Burrillville, R.I. (EL18-349).
The commission’s Jan. 26 order rejected Clear River’s protests over the dates for providing financial security for the cost of required transmission upgrades; its request to self-build certain interconnection facilities; its cost responsibility for transmission upgrades; and its request for additional data backing the cost allocation.
Clear River’s twin one-by-one combined cycle generating units will interconnect with the grid at National Grid’s existing Sherman Road 345-kV switching station through a new 345-kV generator lead line. During LGIA negotiations, Clear River requested to push back the initial commercial operation date two years, to May 31, 2021. National Grid confirmed that it could meet the new deadlines.
Clear River complained that the unexecuted agreement would require it to begin spending up to $88 million prior to the project’s permits being secured.
The commission ruled that the milestones developed by National Grid were based on the schedule proposed by Clear River. “Clear River’s request to adjust the dates by which it must issue its notices to proceed and post security appears to be due to permitting delays. We note that, if Clear River prefers to proceed once it receives the required permits, then it is free to propose later key milestone dates. National Grid has stated that it will re-evaluate the other milestones should Clear River avail itself of this option.”
The commission also rejected Clear River’s request to self-build its interconnection facilities, saying that option is only available if National Grid is unable to meet Clear River’s milestone dates.
FERC also found that ISO-NE had provided all the information it is required to in justifying Clear River’s $44 million in transmission upgrades.
| Clear River Energy
It also rejected Clear River’s request to restudy its cost obligation because of the two-year delay in its proposed commercial operational date. The company said some upgrades in its LGIA will not be necessary because of several transmission projects expected to be online by 2021 in the Southeast Massachusetts/Rhode Island area: the New Grand Army switching station; upgrades to the Somerset Substation; and upgrades to transmission lines X3 and W4.
FERC said Clear River’s decision to delay its commercial operating date was not grounds for triggering a restudy under ISO-NE’s Tariff.
In November, Clear River had filed a separate complaint asking FERC to eliminate provisions in the RTO’s pro forma LGIA that permit the direct assignment to interconnection customers of network upgrade-related operations and maintenance costs (EL18-31). On Jan. 23, however, the company filed to withdraw the complaint.
“Clear River believes it has shown that, given the nature of the relevant upgrades (which consist almost entirely of replacing or relocating existing network facilities), there very likely would be no monetary impact on Rhode Island ratepayers whatsoever. Nevertheless, the relief sought by Clear River has proven contentious in the Rhode Island Energy Facility Siting Board (EFSB) proceeding regarding Clear River’s application for the permits necessary for the project to be constructed,” the company said. “Accordingly, in order to remove this issue from being considered in any way in the EFSB proceeding — and to eliminate even the false perception of negative ratepayer impact — Clear River is submitting this notice of withdrawal.”
FERC’s Jan. 26 order noted that the notice of withdrawal remains pending. “The commission’s determination in this case should not be read as prejudging the resolution of any substantive issue in that proceeding,” it said.
FERC accepted ISO-NE’s informational filing for Forward Capacity Auction 12, rejecting protests from a demand response provider and renewable generators over qualification rules (ER18-264).
The commission’s Jan. 19 order agreed with the RTO’s list of resources that qualified for the Feb. 5 auction for the 2021/22 delivery year. It also approved the three capacity zones to be modeled, which are unchanged from FCA 11.
| ISO-NE
Efficiency Maine Trust — a quasi-state agency that administers energy efficiency programs in Maine and is overseen by the state Public Utilities Commission — protested the RTO’s methodology for calculating existing capacity qualification values. The agency said ISO-NE inappropriately subtracts the amount of expiring measures from a demand resource’s qualified capacity from a prior FCA, rather than from the demand resource’s actual and known performance capacity, as reported in ISO-NE’s energy efficiency measure database.
ISO-NE rules define qualified capacity — the quantity for which a capacity supplier is compensated — as the lower of the resource’s summer or winter qualified capacity. When a capacity supplier’s summer and winter qualified capacity is significantly different, as is the case with the Efficiency Maine programs, the supplier will not receive compensation for the higher seasonal capacity unless it can pair the higher capacity with other resources in a composite offer.
Storage Technology Connected Directly to Power Grid as a Generator | ISO-NE
Efficiency Maine said the RTO’s rules would deny it compensation for $3.7 million in capacity for FCA 12, although it said it has been able to reduce the loss to $1.5 million through composite offers covering its entire qualified summer capacity.
The commission said Efficiency Maine projects performed above their qualified capacity because measures installed after the initial clearing of the resources. “We agree with ISO-NE that Efficiency Maine should have sought to qualify any additional capacity prior to such additional measures being in service. Accordingly, to the extent that the Efficiency Maine projects’ overperformance is the result of Efficiency Maine’s failure to seek to clear new incremental capacity in the FCA, we find it inappropriate to now mitigate the consequences of that action (or inaction) through changes to the demand resource methodology.”
The commission also agreed with the RTO “that it would be inappropriate for the commission to require ISO-NE to use Efficiency Maine’s proposed methodology for the Efficiency Maine projects while still using the current demand response methodology for all other energy efficiency resources with expiring measures.”
Renewable Technology Resource Exemption
The commission also rejected a joint protest by CPower and Tesla, which combined to enter Tesla’s SolarCity rooftop generation into the auction.
The companies asked the commission to require ISO-NE to re-evaluate the renewable technology resource (RTR) designation for five solar projects and one combined solar and fuel cell project.
The projects passed the RTO’s qualification process and were assigned the default offer review trigger price (ORTP) — a price floor based on the cost of new entry — of $12.864/kW-month. CPower said it did not challenge the ORTP because it sought to use the RTR exemption to receive an offer floor price of $0/kW-month. RTO rules permit up to 200 MW of RTR exemptions annually to renewable resources receiving out-of-market revenue through state renewable portfolio programs.
In October, however, ISO-NE rejected CPower’s application as incomplete. CPower contended the additional information the RTO requested meant that new resources must already be accepted into a state RPS program and receiving revenue to qualify for RTR designation, contrary to the RTO’s Tariff.
ISO-NE responded that although CPower’s qualification package was sufficient to determine an appropriate capacity amount to qualify each resource, it lacked details necessary to determine whether each resource met the requirements for an RTR designation.
The commission sided with the RTO.
“Although CPower’s qualification package contains some location-specific information and that CPower’s RTR submittal contains general information on possibly applicable RPS statues and regulations, we agree with ISO-NE that neither sufficiently enable ISO-NE to determine the specific provisions and manner (e.g., on an individual or aggregate basis) in which the renewable projects seek RPS qualification,” the commission said. “We agree that such specificity is necessary for ISO-NE to have sufficient certainty that the renewable projects will still qualify as RTR resources by the time of the relevant capacity commitment period. Thus, we find that CPower failed to comply with the Tariff’s requirements to obtain RTR designation.”
Zones and Resources
As in FCA 11, ISO-NE will model three capacity zones in FCA 12: Southeastern New England (Southeastern Massachusetts, Rhode Island and Northeastern Massachusetts/Boston), which will be modeled as import constrained; Northern New England (Maine, New Hampshire and Vermont), which will be modeled as export constrained; and Rest of Pool (Connecticut and Western/Central Massachusetts).
The installed capacity requirement (ICR) is 34,683 MW. After accounting for 958 MW per month of Hydro-Québec interconnection capability credits, FCA 12 will procure a net ICR of 33,725 MW.
ISO-NE qualified 5,605 MW of new resources and 35,007 MW of existing resources: 30,702 MW from intermittent and non-intermittent generation; 82 MW from imports; and 3,224 MW from demand resources.
The RTO said 2,309 MW of static de-list bids — one-year exemptions from the auction — were submitted for FCA 12.
American Electric Power beat Wall Street’s expectations with a positive yearend earnings report last week, but CEO Nick Akins spent much of a conference call with analysts focused on its Public Service Company of Oklahoma (PSO) subsidiary and its rate case before state regulators.
Akins referred to “disappointing” outcomes in its previous and current rate cases, which have left PSO with a regulated operating return on equity of 6.2% — the second-lowest among AEP’s operating companies and below an authorized ROE of 9.5%. He said AEP may invest its money elsewhere without improved returns, noting the company pulled “several hundred million dollars” of investment out of Oklahoma after PSO’s previous rate case.
PSO’s Tulsa Power Station | Flickr
“We have plenty of places to put our capital, and so Oklahoma would wind up being sort of in the red area,” Akins said during the Jan. 25 call. “That’s something we take very seriously because we want to make investment in Oklahoma.”
An administrative law judge has recommended a 5% ROE in PSO’s current rate case before the Oklahoma Corporation Commission, a “negative trend” Akins is hopeful will be reversed. If the OCC approves the ALJ’s recommendation, “That’s just another really bad message about investment in Oklahoma.”
Moody’s Investors Service recently downgraded PSO’s rating outlook from stable to negative, saying its “limited cushion … for deterioration in financial performance” would be “incrementally impacted” by the recent changes in federal tax law. “We now expect key credit metrics to be lower for longer,” Moody’s said.
Construction at an Invenergy wind farm | Invenergy
“Now that PSO is on negative credit outlook by Moody’s, a positive result is even more important,” Akins said. “[PSO] doesn’t deserve the ROE recommendation and it doesn’t deserve the outcomes that we’re getting in Oklahoma. We’re going to let the commission speak on this. I really believe that the commission will be responsive, so let’s just wait and see what that order looks like.”
AEP’s Wind Catcher site | Invenergy
Also key to AEP’s future success in the Sooner State is its $4.5 billion Wind Catcher project, a 2-GW wind farm in the Panhandle that will deliver energy to PSO and its sister company, Southwestern Electric Power Co. AEP is seeking regulatory approvals in Oklahoma, Arkansas, Louisiana and Texas, while PSO is gathering community input on proposed transmission siting.
“We are in a very critical time in the life of this project,” Akins said. “In my mind, it would be an absolute travesty to let this unique hedge against the market pass, and I remain confident that it will get done.”
The Columbus, Ohio-based company reported fourth-quarter operating earnings of 85 cents/share, beating Zacks Consensus Estimate of 81 cents/share. AEP recorded a profit of $1.9 billion in 2017, triple the $611 million the year before, although sales were $15.4 billion, down from $16.4 billion.
Year-end earnings were $3.68/share, down from $3.94 from the year-ago period. AEP’s share price finished the week at $68.77, down almost 12% from its 52-week high of $78.07.
NextEra Reports $5.38B Profit in ‘Terrific Year’
NextEra Energy on Jan. 26 reported a 2017 profit of $5.38 billion, though that number was adjusted down to $3.17 billion after allowing for the effects of tax legislation and other unusual charges. Still, that was up from $2.88 billion in 2016.
The Florida-based company said its revenue increased to $17.2 billion, up from $16.2 billion in 2016.
“It was a terrific year,” said CEO Jim Robo.
However, the company’s adjusted fourth-quarter earnings came in at $1.25/share, falling short of the Zacks’ estimate of $1.31/share. The company reported fourth-quarter GAAP net income of $2.16 billion.
NextEra said its Florida Power & Light utility will reduce customer bills by using federal tax savings to forgo recovery of $1.3 billion in Hurricane Irma restoration costs. It said NextEra Energy Resources added a record 2.7 GW to its contracted renewables backlog.
NextEra stock gained $2.83 on Friday to close at $157.69/share, up 1.8% on the day. Its share price has gained almost 30% over the last 12 months.
FERC last week denied CPower’s request for a one-time waiver to replace the results of a failed demand response audit with those of a more successful one conducted a week later (ER18-185).
| ISO-NE
In its request, the energy management company said that it had asked ISO-NE on July 17, 2017, to perform an audit of its real-time demand response resources (RTDRs). But when the RTO initiated the audit July 19, a communications problem prevented CPower from receiving the audit dispatch signal, causing most of the company’s resources to fail to perform. CPower pointed out that ISO-NE is the only RTO in the country that does not back up DR dispatch signals with an email, text message or phone call.
| ISO-NE
As a result of the failed audit, CPower concluded the month with a demand reduction value of nearly zero.
ISO-NE’s Tariff requires seasonal testing of RTDRs to establish their capabilities and ensure they are available to respond during an emergency event.
The RTO suggested that CPower request a second audit to “mitigate partially” the negative impacts of the first. A July 26 audit demonstrated 94% of the claimed capacity that CPower had registered in the RTDR program, and the company asked the grid operator to replace the July 19 results with those of July 26.
ISO-NE denied the request, saying its Tariff stipulates that a second audit cannot replace an initial audit conducted during that same month. It further argued that allowing RTDRs “another bite at the apple” to replace a poor performance during an audit could compromise the significance of such audits or impact future performance.
The RTO also said that granting the waiver would harm third parties by requiring the resettlement of capacity payments away from resources that followed dispatch instructions and performed well during their audits.
FERC agreed with ISO-NE, saying that CPower’s request was “not of limited scope because it would require rerunning market settlements” and thereby affect other market participants. The commission also noted that allowing resettlement would result in preferential treatment for CPower compared with other RTDRs that also performed poorly in the audits.
“Further, granting waiver would have broad implications on the effectiveness of auditing rules. It could undermine the integrity of audits — which by their nature test performance during unpredictable conditions — and impact future performance of RTDR,” the commission said.
President Trump’s decision to impose tariffs on imported solar cells and modules may not spur domestic manufacturing, but it will boost costs, slowing the fast-growing sector, analysts said last week.
The tariffs, based on recommendations from the International Trade Commission (ITC), start at 30% for the first year and drop by 5% each year over the following four years, with the first 2.5 GW of imported solar equipment exempt.
| SEIA
Bloomberg New Energy Finance and ClearView Energy Partners separately predicted the decision will boost the cost of utility-scale solar by 10% and home rooftop units by 4%. ClearView, citing data from the National Renewable Energy Laboratory, also predicted a 6% increase in the cost of distributed commercial solar projects.
GTM Research estimated it may cut U.S. installations by 11% over the next five years.
Expansion Plans
U.S. Trade Representative Robert Lighthizer announced Trump’s decision to impose tariffs on imported solar cells and modules and washing machines on Monday. Trump said they will create jobs in the U.S. “Our [manufacturers] have been decimated, and those companies are going to be coming back strong,” he said in a televised signing ceremony Tuesday.
Greentech Media reported that several of the 14 crystalline-silicon cell and module manufacturers in the U.S. have announced expansion plans: Texas-based module manufacturer Mission Solar Energy, which had to lay off workers in early 2017, said last week it is hiring 50 new employees to increase production and move to a 24/7 schedule. Earlier this month, California-based Solaria announced it had raised $23 million in financing to expand its manufacturing capacity. Tesla said last week it is “committed to expanding its domestic manufacturing” at its Gigafactory 2 in Buffalo, N.Y. And SolarWorld Americas of Oregon, one of two petitioners in the ITC case, resumed manufacturing in September after the commission ruled in its favor. The company says it will add 200 workers by the end of the year. (See Trade Panel Rules PV Imports Hurting Domestic Manufacturers.)
Skepticism
But some analysts said Trump’s move — even if it survives a potential challenge before the World Trade Organization — is unlikely to seriously dent the dominance of Chinese manufacturers, whose share of global solar production grew from 7% in 2005 to 61% in 2012, according to U.S. government statistics.
“Anyone expecting a U.S. manufacturing renaissance as a result of these tariffs is set to be disappointed,” said Hugh Bromley, a solar analyst for Bloomberg New Energy Finance. “A tariff lasting only four years and ratcheting down quickly is unlikely to attract any manufacturing investment that was not going to occur anyway.”
The four-year limit “doesn’t give somebody much incentive to build a factory” in the U.S., agreed Varun Sivaram, fellow for science and technology at the Council on Foreign Relations. Sivaram, author of an upcoming book on solar power, said the U.S. and other nations should be leapfrogging China by investing in new solar technologies.
ClearView also was skeptical of a manufacturing boost, citing data from the Clean Energy Manufacturing Analysis Center, which found that the U.S. has capacity to manufacture about 2.8 GW of solar modules per year — less than one-fifth of the 14.7 GW of solar capacity brought online last year. “Absent nations that are exempt from today’s remedies, domestic manufacturers seem unlikely to increase capacity swiftly enough to meet future demand (or even last year’s actuals),” ClearView said.
Section 201 of the Trade Act of 1974 authorizes the president to create tariffs or take other actions in response to an ITC determination that increased imports are a substantial cause of serious injury to domestic producers. The tariff was the first action by Trump to make good on his campaign promises to revise trade rules to rebuild U.S. manufacturing.
Opening the Floodgates?
Trump’s decision drew fire from members of Congress in both parties and from conservative free-market groups, including the Heritage Foundation, the R Street Institute and the American Legislative Exchange Council. “There’s a real chance that this opens the floodgates” to other industries petitioning the ITC, Chad Bown, a trade expert at the Peterson Institute, toldThe Washington Post. Clark Packard, trade policy counsel at R Street, said he feared the increase in prices will lead to calls for more domestic subsidies for solar.
Others worried it could spur a trade war as the Chinese retaliate. ClearView noted that previous trade remedies imposed by the U.S. under Section 201 were successfully challenged before the WTO, most recently forcing President George W. Bush to reverse duties on imported steel in 2001. South Korea and China said last week they are considering filing complaints with the WTO.
Sens. Martin Heinrich (D-N.M.) and Thom Tillis (R-N.C.), who joined with 14 Senate colleagues in a letter opposing tariffs, said last week they are considering legislative responses to Trump’s decision. “There’s no doubt that this is a significant speedbump for our solar industry,” Heinrich said in a statement.
Job Losses
The Solar Energy Industries Association (SEIA) predicted the tariff will slash domestic solar output by 6.7 GW by 2021 and eliminate 23,000 U.S. manufacturing jobs this year. The group said that out of 38,000 solar manufacturing jobs in the U.S., all but about 2,000 make something other than cells and panels, producing products such as “metal racking systems, high-tech inverters, [and] machines that [improve] solar panel output by tracking the sun and other electrical products.”
Solar job growth since 2010 | SEIA, Solar Foundation
SEIA CEO Abigail Ross Hopper said during a media conference call Tuesday that while the group was unhappy with Trump’s decision, it was relieved he didn’t impose tougher sanctions requested by SolarWorld and fellow petitioner Suniva. The ITC had recommended import duties as high as 35%. (See Federal Trade Panel Recommends Solar PV Quotas.)
“I think this administration really grappled with understanding that solar is creating more jobs in this economy than many other industries and many other energy sources,” Hopper said.
| SEIA
Since 2008, grid-connected solar power has increased more than 38-fold to 42.4 GW, according to the Department of Energy, with more than 260,000 people currently employed. Solar’s share of U.S. electrical generation has risen from 0.1% in 2010 to 1.4% today and is forecast to exceed 3% by 2020 and 5% by 2022, according to SEIA and the Solar Foundation.
The cost to install solar has dropped by more than 70% since 2010, the groups said. In 2016, solar was responsible for 39% of all new electric generating capacity, besting all other technologies for the first time.
“There’s no doubt this decision will hurt U.S. manufacturing, not help it,” Bill Vietas, president of RBI Solar in Cincinnati, Ohio, said during the SEIA press conference. “The U.S. solar manufacturing sector has been growing as our industry has surged over the past five years. Government tariffs will increase the cost of solar and depress demand, which will reduce the orders we’re getting and cost manufacturing workers their jobs.”
Jessica Collingsworth, lead Midwest energy analyst at the Union of Concerned Scientists, said the tariff will hamper solar’s growth in Illinois under the Future Energy Jobs Act. The tariff “threatens the development under Solar for All, which is a job training initiative and solar deployment program for low-income and economically disadvantaged communities throughout the state,” she said. “More expensive solar panels will decelerate new solar installation, delaying Illinois’s transition to a clean energy economy.”
ITC Findings
The Trump administration contends that China has used its own incentives and subsidies to flood the U.S. with underpriced solar cells and modules, hurting domestic manufacturers.
The U.S. imposed anti-dumping and other duties in 2012 and 2013, but Chinese producers evaded those tariffs by moving production to other countries.
ITC initiated the latest investigation in May 2017, after Georgia-based Suniva filed a complaint citing domestic solar industry job losses and wage declines. The company, majority-owned by privately held Chinese firm Shunfeng International Clean Energy, declared bankruptcy last April.
The commission found that “artificially low” priced solar cells and modules from China have spurred solar growth in the U.S. and that China has used incentives, subsidies and tariffs of its own to dominate the global solar equipment supply chain.
“The ITC determined that increased solar cell and module imports are a substantial cause of serious injury to the domestic industry,” the White House said. “Although the commissioners could not agree on a single remedy to recommend, most of them favored an increase in duties with a carve-out for a specified quantity of imported cells.”
Falling prices since 2009 | SEIA, Solar Foundation
Prices for solar cells and modules fell by 60% between 2012 and 2016. “By 2017, the U.S. solar industry had almost disappeared, with 25 companies closing since 2012. Only two producers of both solar cells and modules, and eight firms that produced modules using imported cells, remained viable,” Lighthizer said.
Community Solar Growth to Continue
Trump’s “announcement does nothing to slow the momentum or dampen the excitement for community solar,” said Jeff Cramer, executive director of the Coalition for Community Solar Access. “More and more states are turning to community solar due to its proximity to customers, innovation in product designs and strong customer demand. We expect these advantages, combined with strong state-level support for projects, will result in community solar being able to weather these tariffs and remain a bright spot in the U.S. solar market.”
Lubbock Power & Light told Texas regulators last week that it continues to hammer out settlement agreements that will resolve most of the arguments in the utility’s proposed migration of 470 MW of load from SPP to ERCOT.
Chris Brewster, legal counsel for LP&L, told the Public Utility Commission on Jan. 25 that the utility has modified a settlement agreement reached Jan. 17 with PUC staff and several consumer groups. (See Texas Regulators Noncommittal After LP&L Hearings.)
LP&L counsel Chris Brewster (center) updates the PUC on the utility’s settlement agreements | PUCT
He also said the utility has reached a separate agreement in principle on the SPP side that involves an upfront payment from LP&L to SPP and Southwestern Public Service, which serves Lubbock’s load under a pair of long-term contracts. Brewster did not disclose monetary figures or further details in the agreement, which had not been filed with the PUC as of Friday afternoon.
The Texas parties agreed the only outstanding issue in the proceeding (Docket 47576) pertains to who will build the $360 million in infrastructure ERCOT has projected would be needed to connect LP&L’s load with its system.
“The discussions are ongoing,” Brewster told the PUC. “The parties in West Texas have a perspective on that.”
The commissioners discussed whether to carve out the transmission construction issue separately, but they decided to allow Brewster a chance to include it in the settlement agreements. Brewster will update the PUC at its next open meeting on Feb. 15.
PUC Opens Rulemaking on Distributed Battery Storage
The commission voted to dismiss an AEP Texas request to connect battery storage facilities to the ERCOT grid (Docket 46368), instead opening a rulemaking to “develop a framework within which [it] can consider a broader range of technologies and study the potential impacts to the competitive retail market and energy-only wholesale market in ERCOT.”
Chair DeAnn Walker said in a memo that AEP’s proposal included issues that need “additional commission review and information,” and suggested the PUC “take a wider view of the innovative concepts raised in this docket as well as other potential technological solutions.”
An administrative law judge had approved AEP’s proposal to connect a pair of utility-scale lithium-ion battery facilities to the ERCOT system in West Texas, but the company ran into broad industry opposition when the ALJ ordered the facilities to be classified as distribution assets and included in AEP’s cost-of-service rates. (See PUCT Considering Rulemaking over AEP Battery Proposal.)
In her memo, Walker said she “firmly” believed the energy consumed by the batteries should not be treated as unaccounted for — or unmetered — energy, as AEP proposed.
“The rulemaking should address a method by which any energy necessary for the implementation of a solution can be measured and accounted for within the market,” she said.
Walker also suggested amending PUC rules to require a utility to obtain a certificate of convenience and necessity to use “non-traditional technologies to solve distribution problems.”
PUCT Commissioners left to right: Brandy Marquez, DeAnn Walker and Arthur D’Andrea | PUCT
“We’re excited about seeing this technology get into our market,” said Commissioner Brandy Marty Marquez. “Batteries are the commonsensical response to the renewables we’ll see in our market.”
Commissioner Arthur D’Andrea said he had concerns about allowing “regulated utilities to play in this space.”
“The energy does overhang the market,” he said.
Commission Issues Favorable Entergy Orders
In a pair of actions related to Entergy Texas, the PUC signed off on a report analyzing the costs and benefits of MISO membership and approved the company’s request to build a 230-kV transmission line in southeast Texas.
The commission requested the report when it approved the transfer of operational control of Entergy’s assets to MISO in October 2012. The PUC declined Texas Industrial Energy Consumers’ proposal to impose reporting requirements on Entergy, agreeing with staff that it already can request information from the utility as it deems necessary.
MISO last week said it will hold off on a decision to expedite its review of a proposal to interconnect Foxconn’s massive electronics plant planned for southeastern Wisconsin until it gets more feedback from stakeholders.
The RTO’s studies of American Transmission Co.’s plan to interconnect the Foxconn plant concluded the project is suitable for recommendation to the Board of Directors under the normal approval timeline for the 2018 Transmission Expansion Plan. But MISO is stopping short of granting expedited status until it hears stakeholder opinions at a Feb. 14 Planning Advisory Committee meeting.
ATC submitted the request for accelerated approval, contending that the proposed $140 million Mount Pleasant Tech Interconnection Project to hook up the $10 billion electronic manufacturing plant with We Energies’ network cannot wait until the usual approvals at the end of the year as part of MTEP 18. ATC has proposed constructing a 14-mile 345-kV transmission line, a new 345/138-kV substation and new underground 138-kV lines to connect the substation to a smaller Foxconn-owned substation near the plant. The transmission developer said it received We Energies’ request to construct the infrastructure in mid-October and notified MISO of the need for expedited approval in late November.
MISO’s studies have found the project will have no adverse impact on system reliability, with the project meeting NERC and ATC local planning reliability criteria.
Minimal Economic Benefits
But MISO also determined that potential systemwide economic gains from the Foxconn project fall far short of the threshold for qualifying as a market efficiency project eligible for competitive bidding or broader cost allocation.
During a Jan. 25 conference call, MISO economic analyst Nicholas Przybilla said the RTO found the benefit-cost ratio of the project would likely be 0.009:1, well below the 1.25:1 requirement for market efficiency projects. He said the economic assessment was provided for informational purposes only, as the lead time and projected December 2019 in-service date are too short for consideration anyway.
Michigan Public Service Commission staffer Bonnie Janssen asked why the economic benefits were so low.
“There is a decent amount of interconnect in the area already,” Przybilla said.
Earlier this month, three Milwaukee aldermen questioned We Energies and ATC’s plan to pass the costs of the interconnection to ratepayers, given that the project stands to benefit just one large industrial customer. (See Milwaukee Signals Fight Against Foxconn Interconnection Plan.)
In response to a question from Kavita Maini, an economist for Midwest Industrial Customers, MISO said its study relied solely on ATC’s 230-MW load projection for the plant, rather than considering any other forecasts. ATC staff at the meeting said they determined that figure was credible after examining similar manufacturing plants in Asia.
Joseph Dunn, MISO West Region expansion planning engineer, said ATC provided an $130 million alternative proposal that would loop existing 345-kV lines into the new substation, but the RTO found the project would result in inferior reliability and more right-of-way approvals when compared to the original project.
If approved, ATC’s interconnection project will eliminate the need for the $12 million reconstruction of a 345-kV bus in Racine, Wis., that was originally approved in the MTEP 16 cycle. That smaller project also has a December 2019 in-service date, but MISO staff said it will be withdrawn should ATC’s project win approval.
