Page 1582 – RTO Insider

November 21, 2016April 1, 2025

FERC: Renewables Must Provide Frequency Response

By Rich Heidorn Jr.

In a rulemaking reflecting both reliability concerns and the technological advances of renewable generators, FERC on Thursday proposed revising the pro forma Large Generator Interconnection Agreement (LGIA) and Small Generator Interconnection Agreement (SGIA) to require all newly interconnecting facilities to install and enable primary frequency response capability (RM16-6).

The commission said the existing pro forma LGIA may be unduly discriminatory because its primary frequency response requirements apply only to synchronous generating facilities “and do not account for recent technological advancements that have enabled new non-synchronous generating facilities to now have primary frequency response capabilities.”

Wind farm near Palm Springs, Calif. | © RTO Insider

The proposed changes will “ensure fair and consistent treatment for all types of generating facilities, help balancing authorities meet their frequency response obligations pursuant to NERC reliability standard BAL-003-1.1 and help improve reliability during system restoration and islanding situations,” the commission said.

FERC said the rules would not apply to nuclear generators and would not impose “headroom” requirements for new generators. The commission said it would not require that generators be paid for complying with the frequency response requirement.

Declining Frequency Response

Acknowledging concerns over declining frequency response performance, the commission asked for comment on whether the Notice of Proposed Rulemaking is sufficient “to ensure adequate levels of primary frequency response, or whether additional reforms are needed.”

“While the three [contiguous] U.S. interconnections currently exhibit adequate frequency response performance above their interconnection frequency response obligations, there has been a significant decline in the frequency response performance of the Western and Eastern Interconnections,” FERC said.

The commission noted declining frequency response was identified as early as a 1991 study by NERC and the Electric Power Research Institute.

It also cited a 2010 NERC survey of generator owners and operators that found that only 30% of generators in the Eastern Interconnection provided primary frequency response and that only 10% provided sustained primary frequency response. “This suggests that many generators within the interconnection disable or otherwise set their governors or outer-loop controls such that they provide little to no primary frequency response,” the commission said.

“The commission’s pro forma generator interconnection agreements and procedures were developed at a time when traditional synchronous generating facilities with standard governor controls and large rotational inertia were the predominant sources of electricity generation. However, the nation’s resource mix has undergone significant change since” the pro forma rules were issued in 2003 and 2005.

“This transformation has been characterized by the retirement of baseload, synchronous generating facilities and the integration of more distributed generation, demand response and natural gas generating facilities, and the rapid expansion of non-synchronous variable energy resources (VERs) such as wind and solar,” the commission said.

It cited U.S. Energy Information Administration data that the U.S. added 13 GW of wind, 6.2 GW of utility-scale solar photovoltaic and 3.6 GW of distributed solar PV generation in 2014 and 2015. “Conversely, NERC has reported that almost 42 GW of synchronous generating facilities (e.g., coal, nuclear and natural gas) have retired between 2011 and 2014, and the EIA recently reported that nearly 14 GW of coal and 3 GW of natural gas generating facilities retired in 2015.”

The commission said that although wind and solar generators now have the technology to provide primary frequency response, “this functionality has not historically been a standard feature that was included and enabled on non-synchronous generating facilities. Moreover, wind and solar generating facilities typically operate at their maximum operating output, leaving no capacity (or ‘headroom’) to provide primary frequency response during under-frequency conditions.”

RTO Rule Changes

The commission acknowledged it was playing catch up with RTOs that have already begun changing the rules for asynchronous generators:

ISO-NE and NYISO have adopted provisions to their LGIAs that establish more specific requirements for governor operation.
PJM has implemented governor requirements for non-nuclear generators and required new non-synchronous generators to have “enhanced inverters” allowing the provision of primary frequency response. (See Enhanced Inverters Clear MRC.)
MISO requires governor operation as a condition for providing regulating reserves but does not require specific settings.
The commission recently accepted CAISO Tariff rules on governor settings and provisions for sustained primary frequency response.

November 21, 2016

FERC Rule Would Boost Energy Storage, DER

By Rich Heidorn Jr.

In a big boost to the energy storage industry, FERC on Thursday proposed a sweeping order aimed at knocking down market barriers to storage and distributed energy resources.

The Notice of Proposed Rulemaking would require RTOs to allow aggregated distributed energy resources and storage resources of 100 kW and above to participate in capacity, energy and ancillary services markets. It also would allow storage to provide services not procured through markets, such as black start, primary frequency response and reactive power (RM16-23, AD16-20).

ferc energy storage der — Myersdale PA Energy Storage | *NextEra*

“As the costs of electric storage resources continue to decline and their technical potential expands, the ability of these resources to provide operational and economic benefits to the organized wholesale electric markets will increase,” the commission said. “We preliminarily find that it is important to remove barriers to participation now so that the competitive benefits are realized without delay.”

In a separate order, the commission also issued a NOPR proposing to require all newly interconnecting large and small generating facilities to install and enable primary frequency response — a requirement new to renewable generators (RM16-6). (See related story, FERC Proposes Frequency Response Requirements for Renewables.)

FERC’s Heard Enough

In the rhythm of FERC rulemaking, staff-led technical conferences are part of a process that is followed by post-conference comments and months of deliberation before the issuance of a NOPR.

Not so with the commission’s deliberations on RTOs’ rules on energy storage and DERs.

Thursday’s NOPR came only eight days after a daylong technical conference at which representatives of RTOs, utilities and technology companies debated the breadth of storage’s potential uses and ways to avoid overcompensating resources performing multiple functions (AD16-25). (See FERC Panelists Debate Storage Uses, Compensation.)

It also followed an Oct. 21 complaint by AES’ Indianapolis Power and Light seeking to goose rule changes in MISO. (See related story, MISO Asks FERC to Dismiss IPL Storage Complaint.)

It’s now apparent that FERC had already heard enough even before convening the conference. The 139-page NOPR was likely the result of months of internal debate and negotiations.

In April, the commission issued data requests to the six jurisdictional RTOs and ISOs seeking information on their rules on storage and DER participation. The RTOs’ responses were followed by dozens of comments from other stakeholders.

“As numerous commenters state, existing RTO/ISO rules that govern participation of electric storage resources in some organized wholesale electric markets fail to ensure that electric storage resources that are technically capable of providing specific services are permitted to do so,” the commission said Thursday.

FERC said outdated and inflexible market rules have hampered innovation. “For instance, some electric storage resources have chosen to participate as demand response resources simply because, absent other participation models, that is the participation model that more closely resembles the manner in which electric storage resources might participate in the organized wholesale electric markets.”

‘Participatory Model’

The NOPR would require RTOs to revise their rules to create a “participation model” that accommodates “the physical and operational characteristics” of storage to allow them to provide any services they are physically capable of.

“Where compensation for these services exists, electric storage resources should also receive such compensation commensurate with the service provided,” the commission added.

One key change would be the requirement that RTOs’ bidding parameters reflect storage’s unique characteristics, including allowing storage to de-rate its capacity to meet minimum run-time requirements to provide capacity or other services.

In addition, RTO criteria for qualifying storage resources “must not limit participation to any particular type of electric storage resource or other technology,” FERC said.

“For example, resources such as thermal storage that can both increase and decrease their energy consumption could aggregate with other distributed energy resources with common physical or operational characteristics and qualify as a market participant using the participation model proposed here.”

In addition to batteries, the commission said the rules also must accommodate “flywheels, compressed air [and] pumped hydro … whether located on the interstate grid or on a distribution system.”

State-of-Charge

The commission said bidding parameters must take into account storage’s state-of-charge to ensure resources are dispatched in a way that maximizes their operational effectiveness.

“While some existing bidding parameters were developed for older electric storage technologies (such as pumped hydro facilities), newer storage technologies (such as battery storage) have greater flexibility to transition between charging and discharging. Therefore, bidding parameters designed for slower storage technologies or other types of generation resources that are not capable of charging and discharging energy may limit the opportunity for faster electric storage resources to participate in the organized wholesale electric markets.”

For RTOs with capacity markets, the commission proposed that the de-rated capacity value for electric storage “be consistent with the quantity of energy that must be offered into the day-ahead energy market for resources with capacity obligations.”

The commission said storage’s participation also should not be barred by requirements, designed for synchronous generators, that the resource be online and synchronized to the grid to be eligible to provide ancillary services.

“Newer technologies, particularly electric storage resources, tend to be capable of faster start-up times and higher ramp rates than traditional synchronous generators and are therefore able to provide ramping, spinning and regulating reserve services without already being online and running,” the commission said. “Therefore, we preliminarily find that participation in ancillary service markets should be based on a resource’s ability to provide services when it is called upon rather than on the real-time operating status of the resource.”

Energy Schedules

But the commission acknowledged that because RTOs co-optimize energy and ancillary services dispatch and pricing, they may require ancillary services providers to have an energy schedule. “As a result, it is not clear whether eliminating the requirement for a resource to be online and synchronized to the grid would be impactful given the continued need to have an energy schedule,” it said, asking for comment on whether the requirement for energy schedules could be relaxed.

“Specifically, we seek comment on whether dispatch and pricing of energy and ancillary services would continue to be internally consistent if a resource were not required to offer to provide energy in order to offer to provide ancillary services.”

Size

The NOPR says that the RTOs’ minimum size requirement for participation in the markets should be no more than 100 kW, a threshold the commission said “balances the benefits of increased competition with the ability of RTO/ISO market clearing software to effectively model and dispatch smaller resources often located on the distribution system.”

The limit would apply to any minimum capacity requirements, minimum offer requirements and minimum bid requirements.

Pricing

The NOPR proposes that the energy that storage resources purchases from RTO markets and then resells back to those markets must be at the wholesale LMP. It also said storage should be permitted to set LMPs both as buyers and sellers.

“This proposal includes the requirements that the RTOs/ISOs accept wholesale bids from electric storage resources to buy energy so that the economic preferences of the electric storage resources are fully integrated into the market, the electric storage resource can set the price as a load resource where market rules allow and the electric storage resource can be available to the RTO/ISO as a dispatchable demand asset. However, we note that these requirements must not prohibit electric storage resources from participating in organized wholesale electric markets as price takers, consistent with the existing rules for self-scheduled load resources.”

Smaller DER

The NOPR also acknowledged the expected growth of DER in requiring RTOs to “remove any unnecessary limitations on how the distributed energy resources that participate in such aggregations must be operated.”

“It is clear from the comments that the ability to meaningfully participate in the organized wholesale electric markets for these smaller distributed energy resources is through aggregations,” the commission said.

Energy Storage at Grand Ridge, IL | Invenergy — Energy Storage at Grand Ridge, IL | *Invenergy*

“For example, combining the discharge times of multiple electric storage resources and/or combining them with distributed generation resources could allow aggregated resources to meet minimum run-time requirements that individual electric storage resources may not be able to meet.”

Under FERC’s proposal, a DER aggregator could register as a generation asset “if that is the participation model that best reflects its physical characteristics.”

The commission expressed hope that price signals will encourage DER to locate in areas where new capacity is most needed, helping reduce congestion costs during load peaks and to reducing transmission investments for delivering energy into high-priced load pockets.

“Unlike larger fossil fuel generators that often are not able to locate in load pockets due to environmental or other citing concerns, distributed energy resources are more able to co-locate with load and provide associated benefits,” the commission said. “We also believe that the shorter lead time to develop many forms of distributed energy resources compared to traditional generators or transmission lines allows them to rapidly respond to near-term generation or transmission reliability-related requirements, further improving their ability to enhance reliability and reduce system costs.”

Transaction Costs

The commission said the changes should remove the commercial and transactional barriers to DER participation in wholesale markets.

“Owners and operators of individual distributed energy resources may be reluctant to incur the significant costs of participating in the organized wholesale electric markets, such as the costs of the necessary metering, telemetry and communication equipment,” it noted.

“The smaller a resource is, the more likely the transaction costs to sell services into the organized wholesale electric markets outweigh the benefits that the prospective market participant may realize from selling wholesale services. However, some of these costs can be reduced by participating in the organized wholesale electric markets through a distributed energy resource aggregation; for example, the time and resources necessary to learn the market rules and actively submit bids and/or offers into the organized wholesale electric markets.”

FERC said integrating DERs into the markets will help RTOs account for them in calculating installed capacity requirements and day-ahead energy demand, “thereby reducing uncertainty in load forecasts and reducing the risk of over procurement of resources and the associated costs.”

LaFleur Statement

Commissioner Cheryl LaFleur issued a statement saying that DERs “will play a critical role in the future of the grid” but noting that they present “unique issues since they are connected to the grid at the distribution level.”

She called for “close coordination among the RTO/ISOs, the distribution control centers that operate the systems to which they are connected and the distributed energy resource aggregators. … This coordination could include, for example, real-time operating procedures and software-enabled communications among the control centers.”

The commission noted that it was awaiting an informational report from CAISO, which recently began implementing rules for DER aggregations.

CAISO’s Tariff also includes participation models for Generators, Proxy Demand Resources, Reliability Demand Response Resources and Non-Generator Resources.

Comment Period

The commission will accept comments for 60 days after the NOPR is published in the Federal Register. In particular, the commission solicited comment from the RTOs on the rule and software changes that would be required to implement the new requirements as well as the associated costs and how they can be minimized.

November 18, 2016April 1, 2025

NY Regulators Approve FitzPatrick Sale

By William Opalka

ALBANY, N.Y. — The New York Public Service Commission on Thursday approved Entergy’s sale of the James A. FitzPatrick nuclear plant to Exelon, a transaction needed to prevent the plant’s imminent closure (16-E-0472).

A year ago, Entergy announced it would close the money-losing plant in early 2017. Exelon began negotiations in the summer to purchase the plant for $110 million, contingent on the state’s approval of a subsidy to keep the plant operating and regulators’ approval of the transaction by Nov. 18. (See FitzPatrick Sale Filed with New York Regulators.)

New York Public Service Commission chair Zibelman, fitzpatrick

Zibelman | © RTO Insider

“It’s the next step forward on the Clean Energy Standard,” PSC Chair Audrey Zibelman said at a news conference after the meeting. “We understood this transaction would have to happen” to keep the plant running.

Having pledged to acquire 50% of the state’s electricity from renewable sources by 2030, New York officials see nuclear power as an interim carbon-free source until renewables are deployed at scale. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)

The commission found the sale in the public interest, saying there were no adverse environmental consequences, Exelon has the financial wherewithal to maintain safe operations and the acquisition would not give it undue market power.

PSC economist Warren Meyers said the transaction means Entergy and Exelon swap places as the fourth- and fifth-largest owners of generation in the state. Before the transaction, Entergy controlled 7% of New York’s fleet and Exelon had 6%. After the sale, those numbers change to 5% and 8%, respectively. Entergy owns the Indian Point nuclear plant north of New York City.

Critics of the zero-emission credit (ZEC) say the 12-year subsidy could cost ratepayers up to $7.6 billion to keep FitzPatrick and two other upstate nuclear plants open. “This is part of a larger picture and that picture is that the Public Service Commission has moved in favor of a mandatory bailout from ratepayers in the entire state,” Manna Jo Greene, Hudson River Sloop Clearwater’s environmental director, said after the meeting. “Had they not agreed on the bailout, this transaction would not have occurred.”

Zibelman acknowledged the likelihood of the plant’s closure without PSC approval, but she emphasized the environmental benefits. The state can’t afford to step back from its low-emission commitments, she said. When nuclear plants have closed in Germany and New England, carbon emissions have risen as the lost energy was replaced by fossil fuel plants, Zibelman said. (See CO2 Emissions Increase in ISO-NE.)

The ZECs have been opposed by other environmentalists and they also say the companies’ petition for FERC approval of the FitzPatrick sale needed to include information about the subsidy. (See Federal Suit Challenges NY Nuclear Subsidies.)

new york public service commission hearing attendees, fitzpatrick

Crowded room at the New York PSC Hearing | © RTO Insider

Exelon spokesman Marshall Murphy declined to comment on whether the company would seek to cancel the sale if the ZECs are voided by the courts. “The company is not going to speculate on any legal outcome with respect to the Clean Energy Standard,” he said.

Besides FitzPatrick, the ZECs would be paid to Exelon’s neighboring Nine Mile Point 1 and 2 plants, and its R.E. Ginna facility to the west.

“With a number of nuclear energy plants across the country at-risk for premature closure — or having closed already — New York is a bright spot on the map when it comes to recognizing and preserving the many benefits that these plants provide,” the advocacy group Nuclear Matters said in a statement. “While we will need to review the final order in order to fully evaluate the PSC’s decision, the approval of the FitzPatrick transfer preserves a host of benefits for all New Yorkers, allowing the continued operation of a reliable producer of carbon-free energy that is also a key driver of jobs and economic growth in the state.”

The Nuclear Energy Institute also praised the vote. “By its own cost-benefit analysis, the Public Service Commission recognized that the gross benefits of keeping FitzPatrick and the other upstate plants operating in the first two years of the Clean Energy Standard program are approximately $5 billion. This is weighted against a cost of less than $1 billion and thus hugely beneficial,” NEI said in a statement.

The 882-MW plant began operating in 1975 and is licensed through 2034.

The transaction must also be approved by the U.S. Department of Justice, the Nuclear Regulatory Commission and FERC. It is expected to close in the second quarter of 2017.

November 18, 2016

Market Manipulation Cases Dominate FERC Enforcement

By Rich Heidorn Jr.

Market manipulation cases dominated FERC’s enforcement efforts in fiscal year 2016, responsible for more than two-thirds of the probes launched during the year, according to the Office of Enforcement’s 10th annual Report on Enforcement, released Thursday.

The report said the office’s Division of Investigations opened 17 probes in FY 2016, some of which involved multiple subjects: 12 involved potential market manipulation, 11 included potential tariff violations and one each involved potential violations of a commission certificate order, the Standards of Conduct and a commission filing requirement.

Enforcement closed 11 investigations during the year, about half of them because of insufficient evidence and the other half resulting in settlements. One of the companies involved in settlements, Berkshire Power, also pleaded guilty to a criminal violation of the Federal Power Act — the first conviction ever in the 81 years since the law’s enactment, according to FERC.

Among the settlements, about two-thirds involved market manipulation, one-quarter involved tariff violations and the remainder involved reliability standards.

ferc market manipulation — Market Manipulation Cases Dominate FERC Enforcement Efforts | *FERC*

In FY 2015, by contrast, reliability standards settlements and those involving market manipulation were about even at more than 40% each, with the remainder attributed to tariff violations.

The annual report includes several other highlights:

The commission said it spent more time in federal court last year because of two challenges to FERC orders assessing penalties, continuing litigation on four cases from prior years and a commission proceeding on an administrative law judge’s initial decision finding violations of the Natural Gas Act. In all, staff sought to recover $567 million in civil penalties and $45 million in disgorgement through litigation.
Staff received 110 new self-reports from electric utilities, generators and other market participants, including almost 60 from RTO or ISOs. Including those reports submitted in prior years, staff closed 126 self-reports.
The Division of Audits and Accounting conducted 14 audits of oil pipeline, utility and natural gas companies, issuing 214 recommendations and ordering refunds and recoveries of $5.3 million. The report highlighted an audit of SPP that found problems with the independence of the RTO’s Internal Market Monitoring unit (PA15-6). (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.) It also singled out its audit of Duke Energy’s compliance with conditions the commission set in approving the company’s acquisition of Progress Energy (PA14-2). The audit found that Duke and its subsidiaries overstated their wholesale power and transmission customers’ revenue requirements by $17.5 million by improperly including merger transaction expenses without making a Section 205 filing showing that the costs were offset by merger-related savings. Auditors also found the company improperly included $2.4 million of lobbying costs in operating accounts.

White Papers

Enforcement also issued two staff white papers based on its 10 years of experience since Congress gave the agency stronger enforcement powers under the Energy Policy Act of 2005.

One, Anti-Market Manipulation Enforcement Efforts Ten Years After EPAct 2005, includes lessons learned in four areas: factors the commission and courts have found to be indicative of fraudulent conduct under the Anti-Manipulation Rule, adopted under Order 670; types of conduct that the commission has found to constitute market manipulation (including cross-market manipulation schemes, gaming and misrepresentations); mitigating and aggravating factors the commission considers in assessing penalties; and examples of market manipulation investigations that staff closed without action and the reasons why.

Staff said it was impossible to provide an exhaustive list of all types of manipulation, “because determining whether certain conduct constitutes manipulation is a fact-specific inquiry.”

“Market participants are increasingly sophisticated,” the report said, quoting from a ruling by the 8th U.S. Circuit Court of Appeals: The “methods and techniques of manipulation are limited only by the ingenuity of man.”

The second white paper, Effective Energy Trading Compliance Practices, is an effort to respond to market participants’ requests for more guidance on creating effective compliance programs to prevent and detect market manipulation. It includes examples of compliance practices that staff found effective and those that it found lacking.

Among the best practices cited:

Hiring compliance personnel with a variety of professional and educational experience, including legal, operations, risk management and trading.
Integrating compliance personnel into the organization’s business units (for example, locating compliance personnel on the trading floor and regularly rotating business unit employees into compliance functions).
Performing background investigations on energy traders for evidence of criminal activity, civil lawsuits, drug abuse, excessive gambling or financial problems.
Implementing compensation structures that incentivize compliance.
Implementing rules discouraging traders from using price-setting instruments such as physical natural gas or electric products to benefit open financial positions. It also recommended conducting statistical reviews of position concentrations.
Recording and retaining all trader communications for at least five years, including emails, instant messages and phone calls.

In contrast, the report says an overreliance on standardized and long annual training is ineffective. It also cautioned against relying heavily on attorneys for training rather than including operational staff. “Operational staff can help tailor compliance trainings and make them more relatable to the traders receiving the training,” the report said.

It also said companies should have ways to resolve disputes between compliance personnel and traders. “Traders should not be permitted to decide which advice to heed and which to ignore,” it said.

November 16, 2016

Bill to Save Coal, Nuclear Plants Introduced in Illinois

By Rory D. Sweeney

Illinois lawmakers on Tuesday introduced a wide-ranging energy bill that would provide ratepayer-financed support for nuclear, coal, renewables and energy efficiency (SB 2814).

Dubbed the Future Energy Jobs Bill, it has one sponsor in each house of the General Assembly: Sen. Don Harmon and Rep. Robert Rita, both Democrats from the Chicago area. The legislation touches on almost every aspect of the electric industry:

Zero Emission Credits (ZECs) that utilities must buy from qualifying generating units.
A fixed resource adequacy plan (FRAP) that would put the state in charge of procuring capacity for its MISO region in Southern Illinois.
A tariff to recover costs for increasing the implementation of energy efficiency and demand response projects.
Revisions to the state’s renewable portfolio standard to fix an issue that advocates say hampers renewable investment.
Revisions to the retail rate structure, including implementing a “grid impact rate.”
Installation of up to six microgrids, restricted to specific utilities.

A version of the bill has been pushed by Exelon since it threatened in May to shut down its Clinton and Quad Cities nuclear plants if the state didn’t provide subsidies, such as the emissions credits proposed in the new bill. (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)

exelon, clinton, quad cities, illinois, nuclear power, coal power — The Clinton Nuclear Station is one of two nuclear plants in Illinois that Exelon has threatened to shut down if it doesn’t receive requested financial relief from the state. | *Exelon*

The bill had been opposed by Dynegy, which plans to shutter three 40-year-old coal-fired plants in central and southern Illinois, but the Houston-based power provider got on board once the FRAP was added. Dynegy says Dynegy Introduces Bill to Move All of Ill. Into PJM.)

“In the last six months alone, the flawed market design has resulted in Dynegy shutting down more than 15% of generation in Southern Illinois and additional plants could be at risk in the future,” Dynegy’s David Onufer said. “The legislation deals with gaps in the downstate market by providing a competitive process to secure generation for the future. It’s non-discriminatory and open to all fuel resource types that meet the required high standards of performance.”

When neither Exelon nor Dynegy could push their initiatives through the legislature earlier this year, they decided to coalesce around one piece of legislation. (See Ill. Lawmakers Fail to Address Exelon, Dynegy Legislation.)

“The legislation reflects the work of a broad group of stakeholders to achieve comprehensive energy legislation that is urgently needed to strengthen our economy and save and create tens of thousands of jobs,” Exelon’s Paul Adams said. “As with any piece of major legislation, it will continue to evolve as stakeholders weigh in. But at its core, we know the bill will bring significant benefits to consumers and the environment in Illinois. … There is broad agreement regarding the need to urgently address energy challenges in Illinois.”

The ZECs would start at $16.50/MWh, which is based on the U.S. Interagency Working Group on Social Cost of Carbon, and increase by $1/MWh per year, starting in 2023.

The number of credits that eligible facilities would receive is less easy to calculate. The amount is based on a complicated formula that limits the increase in retail customers’ bills to no more than 2.015% of the price per kilowatt-hour that consumers paid in 2009.

The bill is opposed by the BEST Coalition, which includes a wide variety of commercial and industrial ratepayers. Organizer Dave Lundy says that because Illinois is a substantial exporter of energy, saddling in-state customers with additional costs would subsidize out-of-state consumers. He pointed to grid operator studies showing that none of the plants threatened to be closed would impact reliability to the extent that transmission would need to be built or that they would need to receive reliability must run contracts.

He called the emissions credits and FRAP “bailouts” for nuclear and coal interests and said they would cause volatility in retail rates.

Consumers, particularly those on a budget, “can’t absorb wild swings from month to month,” he said. “You may be a winner three or four months out of the year, but if you’re a loser and you’re not in a position to pay that bill, you’re in trouble.”

Lundy said the microgrids could be useful in theory, but he criticized the fact that they were granted to utilities to build and not open to competitive bidding. He feared the utilities will “gold-plate” and overcharge for them.

He also applauded the long-awaited fix to the RPS policy, but he said packaging it with the rest of the bill’s initiatives made it come at too high a cost. “I can’t even call that a positive because [the RPS fix] requires the destruction of the entire market, and you’ll never be able to build anything else,” he said. “It’s a hollow victory.”

Despite the bill’s name, “it is undeniable that a massive rate hike will make Illinois less competitive. … You will kill jobs,” he said.

“Nobody’s advocating [closing] all the baseload units in the state. … You don’t need to shut down the coal plants if they’re economic to run,” he said. “We are not anti-nuclear; we are anti-bailout.”

November 16, 2016

UPDATED: MISO Asks FERC to Dismiss IPL Storage Complaint

By Amanda Durish Cook and Rich Heidorn Jr.

MISO asked FERC to reject Indianapolis Power and Light’s complaint over energy storage rules, calling it disruptive to stakeholder proceedings and the commission’s broad rulemaking.

MISO asked the commission to dismiss IPL’s Oct. 21 complaint and let it continue using its stakeholder proceedings and Market Roadmap process as the venues for storage market design. MISO also said it would honor “deliberate commission policy” (EL17-8).

MISO’s response was one of a flurry of comments filed Nov. 10, before the commission issued its Nov. 15 Notice of Proposed Rulemaking outlining requirements that RTOs and ISOs remove barriers to storage and aggregated distributed energy resources. (See related story, FERC Rule Would Boost Energy Storage, DER.)

The RTO said IPL’s request could “distract and detract” from its efforts to work out storage issues with stakeholders and from FERC’s effort to address the issue industry-wide, “rather than within the narrow confines of a single market participant’s complaint in this limited proceeding.”

IPL told FERC that it had no way to receive compensation for the 20-MW battery at its Harding Street Station although the facility has been providing MISO with primary frequency response since May. (See IPL Asks FERC to Force Update to MISO Storage Rules.)

IPL/AES Harding Street Energy Storage - FERC, MISO — Harding Street Energy Storage | *AES*

MISO responded that IPL’s request “improperly circumvents” FERC’s rulemaking on storage compensation and grid integration, a process that continued with a technical conference Nov. 9. (See FERC Panelists Debate Storage Uses, Compensation.)

The RTO also argues that IPL “neither shows any immediate damage to itself from waiting for the outcome of such commission processes” and claims that there is no pressing need for primary frequency response service in the MISO footprint.

MISO also accused IPL of exaggerating and mischaracterizing alleged Tariff shortcomings and said IPL provided no proof of how MISO’s current storage energy resource dispatch protocols would harm the life of the Harding Street battery.

“A number of issues raised in the IPL complaint are already being addressed as part of MISO’s Market Roadmap process and through separate ongoing public stakeholder discussions,” MISO spokesman Jay Hermacinski said. “Stakeholder discussions and the Market Roadmap process are intended to comprehensively evaluate possible changes to MISO’s Tariff necessary to further accommodate various energy storage technologies.”

Others Weigh In

IPL’s complaint won support from the Energy Storage Association, Advanced Energy Economy and a coalition of environmental organizations, including the Sustainable FERC Project and the Natural Resources Defense Council.

The groups said FERC should order MISO to create a separate market product for primary frequency response and to revise its dispatch protocol to one “appropriate for all energy storage technologies.”

Duke Energy Indiana said the commission should order MISO only to conduct a study of — and initiate a stakeholder process on — frequency response. It said the commission should “be cautious about approving that a new product (along with that product’s value suggested by IPL) be added to the MISO [Tariff] without first requiring a thorough vetting by MISO, the MISO transmission owners and other stakeholders.”

Battery maker Alevo USA also urged caution, saying IPL’s statements about the limitations of lithium ion batteries are “not necessarily correct.” It said it supports IPL’s intent to remove barriers to entry for storage. But it said FERC should order MISO to develop a “technology-neutral” market design rather than “pick[ing] winners and losers based on what IPL proposes.”

Also weighing in on the matter was NextEra Energy Resources, which asked the commission to coordinate its response to IPL with its actions in other proceedings, including the commission’s Notice of Inquiry on primary frequency response, in which the commission also took action last week (RM16-6). (See related story, FERC: Renewables Must Provide Frequency Response.)

“NextEra Resources agrees with IPL that MISO’s current energy and ancillary services products are unduly discriminatory with respect to storage resources attempting to provide service. However, the deficiencies with respect to MISO’s regulating service product are not unique to MISO or its regulation product,” NextEra said, adding that it and others had raised such concerns in AD16-20 regarding “a range of products in a number of RTOs/ISOs.”

NextEra also said it was concerned that IPL’s proposed compensation structure for primary frequency response lacks a capacity payment.

“Even when an RTO/ISO imposes particular dead band and droop settings to ensure that resources automatically provide primary frequency response, the resource must maintain sufficient headroom in order to be able to increase output in response to deviations when frequency is low. Yet holding back this capacity to be available to respond to under-frequency conditions comes at a cost. A capacity payment for primary frequency response would compensate resources for this opportunity cost and thereby ensure the resource will be available to respond, and should be a part of any RTO/ISO compensation mechanism for primary frequency response.”

November 15, 2016

PJM Market Monitor’s Q3 Report Finds Markets Competitive

By Rory D. Sweeney

PJM’s capacity and regulation market results were “generally competitive” in the first nine months of 2016 but remain vulnerable to stress, according to the Independent Market Monitor’s third-quarter State of the Market Report.

The report by Monitoring Analytics added five new or modified recommendations on uplift, the capacity market and demand response.

The load-weighted average real-time LMP was $29.32/MWh in the first nine months of 2016, lower than for any corresponding period since 2000, reflecting both lower fuel prices and lower demand. It was 25% lower than the first nine months last year.

pjm market monitor — | *Monitoring Analytics*

If all things, including fuel and emissions costs, had remained constant in 2016 from 2015, the load-weighted LMP would have been $31.67/MWh, still below the 2015 mark of $38.94/MWh. PJM’s average real-time load in the first nine months of 2016 decreased by 1.4% from the first nine months of 2015, to 90,599 MW.

The structures for all but the aggregate energy, day-ahead schedule reserve and financial transmission rights markets were uncompetitive, the report said. The PJM region and all locational deliverability areas in almost every market have failed the three pivotal supplier market power test for almost every auction since at least 2007.

Market design received a “mixed” evaluation. Although the Reliability Pricing Model design and Capacity Performance modifications have “many positive features,” the report said, several features “still threaten competitive outcomes.” Among them: the definition of DR, which allows “inferior” products to substitute for capacity; the definition of unit offer parameters; and the inclusion of imports as substitutes for internal capacity resources.

The Monitor also raised concerns over replacement capacity, recommending against allowing retroactive replacement capacity transactions.

Market performance and participant behavior during high-demand hours raised several concerns, the report said, including potential economic withholding.

“In particular, there are issues related to aggregate market power, or the ability to increase markups substantially in tight market conditions, to the uncertainties about the pricing and availability of natural gas, and to the lack of adequate incentives for unit owners to take all necessary actions to acquire fuel and generate power rather than take an outage,” it explained.

In addition to its suggestion on replacement capacity, the Monitor added four other new or amended recommendations.

First, it recommended that PJM initiate a stakeholder process if it plans to modify its price-setting logic — a software change the RTO made in 2014 to reduce uplift by selecting as marginal any unit committed by PJM to provide reactive services, black start or transmission constraint relief if that unit would otherwise run with an incremental offer greater than the LMP.

The recommendation was one of several that the Monitor said could have reduced the uplift rate paid by decrement bids in the Eastern Region by 93% — to $0.032/MWh instead of $0.446/MWh — in the first nine months of 2016.

The Monitor also recommended that capacity released by PJM in incremental auctions should be offered at the Base Residual Auction clearing price or not have the offer price revealed at all to avoid suppressing the IA price. (See “Proposal Chosen for Capacity Release,” PJM Markets and Reliability and Members Committees Briefs.)

Energy efficiency resources shouldn’t be included on the supply side of the capacity market, the Monitor concluded. “PJM’s load forecasts now account for future EE, but did not when EE was first added to the capacity market. If EE is not included on the supply side, there is no reason to have an add back mechanism,” the Monitor said. “If EE remains on the supply side, the implementation of the EE add-back mechanism should be modified to ensure that market clearing prices are not affected.”

Finally, the Monitor also recommended not removing any defined subzones and maintaining a public record of all created and removed subzones.

November 15, 2016

Texas PUC Sets Hearing Schedule for NextEra-Oncor Merger

By Tom Kleckner

The Public Utility Commission of Texas last week scheduled hearing dates on NextEra Energy’s proposed acquisition of Oncor.

PUCT Commissioner Ken Anderson | © RTO Insider — PUCT Commissioner Ken Anderson | © *RTO Insider*

The commission set a prehearing conference for Friday at the commission’s offices in Austin. The parties will discuss the docket’s (No. 46238) procedural schedule, pending motions and any other matters “that may assist” in the proceedings.

The order also set Feb. 21-24 as potential hearing dates before the commission. That would keep the merger on course to receive PUC approval by the end of the second quarter.

The commissioners could have assigned the case to the State Office of Administrative Hearings (SOAH), but they chose to keep it within their jurisdiction instead. However, a SOAH administrative law judge will be responsible for conducting discovery in the case.

“I would have preferred SOAH, because I don’t think it’s that complex,” Commissioner Ken Anderson said. “Maybe we just start holding our holidays in Oncor’s headquarters in Dallas.”

NextEra announced in late July it had reached an agreement to acquire an 80% interest in Oncor; on Oct. 31 it announced it would acquire the remaining 20%.

Other Matters

The commission punted most of the other meaty issues on its agenda to its next open meeting on Dec. 1.

The PUC debated jurisdictional issues related to distributed generation interconnection agreements, before agreeing to resume the rulemaking’s discussion in December (No. 45078).

Citing a “gut instinct,” Chair Donna Nelson said she was reluctant to rule against staff’s opinion that interconnection agreements do not give the PUC jurisdiction over customer complaints.

PUCT Chair Donna Nelson (left) and Commissioner Marty Marquez | © RTO Insider — PUCT Chair Donna Nelson (left) and Commissioner Marty Marquez | © *RTO Insider*

“When I read the comments,” Anderson said, “a lot of the [market] participants who staff believe we would not have jurisdiction over have said they don’t mind the jurisdiction.”

“That’s what I struggle with,” Nelson responded. “I met with some companies, including solar companies, who said ‘we think the interconnection agreement, where we’ve agreed to be subject to your jurisdiction, gives you jurisdiction,’ but staff doesn’t agree with that.”

Nelson said she was concerned solar customers would come to the commission seeking redress from potential “bad actors” but that it would be unable to take up the matter.

“To that end, if we did adopt this with staff’s language, we’ve got a bunch of stuff out there that says we don’t have jurisdiction, and we’re asking the Legislature to potentially give us jurisdiction,” Commissioner Brandy Marty Marquez said. “Waiting until the next meeting to make a final decision is a prudent idea, but it kind of sounds like this might be something we need to pull down until we get through the legislative session.” The Texas Legislature’s next session begins Jan. 10.

The commission also decided to take more time to review a report on alternative ratemaking mechanisms that’s due to the Legislature in January (No. 46046), giving the commissioners an opportunity to agree on any recommendations.

“I got a call from a legislator who asked what recommendations were going to be made,” Anderson said. “I said, ‘I’m not sure I have any. We did the report you asked for.’”

“I’d like to see if there’s a recommendation we can make regarding appropriate reforms,” Nelson said.

The PUC also took no action on Lone Star Transmission’s proposal to cut its transmission costs by $6 million, providing the company files its settlement agreement by the end of the year. The settlement will negate the need for a rate case (No. 45636).

The commission approved a rehearing over the City of Garland’s request to amend a certificate of convenience and necessity for a 345-kV line in East Texas, allowing it to “tackle the merits” after the holidays, Anderson said.

November 15, 2016

PJM Markets and Reliability and Members Committees Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

NOTE: The meetings this week will NOT be in Wilmington, Del., as is customary. They will be held at PJM’s Conference and Training Center in Valley Forge, Pa. RTO Insider will be there covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-10:10)

Members will be asked to endorse the following manual changes:

A. Manual 3: Transmission Operations. Revisions, the result of a periodic review, include updating voltage control at nuclear stations, certain special protection scheme references and the BC/PEPCO operating procedure.

B. Manual 14A: Generation & Transmission Interconnection Process. Revisions resulting from special Planning Committee sessions, set new service request cost allocation and study methods. To ensure manual language allows cost allocation to occur for all projects, the word “interconnection” is replaced with “new service” in section B.2 of Attachment B.

C. Manual 14B: PJM Region Transmission Planning Process. Revisions will update the Capacity Import Limit calculation procedure. Starting with the 2020/21 delivery year, the CIL will no longer be applied as part of the Reliability Pricing Model. As part of new long term firm transmission service study procedures approved earlier this year, the CIL will be considered during interconnection studies associated with new transmission service requests.

D. Manual 15: Cost Development Guidelines. Revisions will implement updates the fuel-cost policy procedures, part of PJM’s compliance filing on hourly offers, which is awaiting FERC action (ER16-372-002). Major changes include an annual review of the policies, reasons for updating a policy outside of the annual review and a process for submitting undefined costs. (See “Fuel-Cost Policy Revisions Approved,” PJM Market Implementation Committee Briefs.)

E. Manual 18B: Energy Efficiency Measurement & Verification. Revisions, the result of a periodic review, include updates to incorporate the implementation of Capacity Performance.

F. Manual 21: Rules and Procedures for Determination of Generating Capability. Revisions, the result of a periodic review, include clarifications to testing rules and terms.

G. Manual 28: Operating Agreement Accounting. Revisions made to align with recent Manual 1 revisions clarify metering language and define a “fully metered EDC” as one that “reports hourly net energy flows from all metered tie lines to PJM via Power Meter and revenue meter data for the hourly net energy delivered by all generators within that EDC’s territory via Power Meter, for the purposes of energy market accounting.” The changes were developed in response to a stakeholder request.

3. Day Ahead Scheduling Reserve Requirement (10:10-10:25)

Members will be asked to endorse the 2017 day-ahead schedule reserve requirement. (See “Day-Ahead Scheduling Reserve Eligibility to be Studied,” PJM Market Implementation Committee Briefs.)

4. Manual 35 Retirement (10:25-10:35)

Members will be asked to endorse the retirement of Manual 35 and receive an update on its proposed replacement, the new Glossary section of PJM’s website. (See “PJM to Retire Manual 35,” PJM Planning Committee Briefs.)

5. Underperformance Risk Management Sr. Task Force (URMSTF) (10:35-10:50)

Members will be asked to endorse a package of revisions and updates to address underperformance risks. (See No End in Sight for PJM Capacity Market Changes.)

6. Base Capacity Extension (10:50-11:05)

Members will be asked to endorse a proposed one-year extension of Base Capacity made by Jeff Whitehead of Direct Energy. (See No End in Sight for PJM Capacity Market Changes.)

7. Excess Capacity Release Problem Statement/Issue Charge (11:05-11:20)

Members will be asked to approve a problem statement and issue charge presented by Jeff Whitehead of Direct Energy regarding PJM’s sell back of excess capacity in the incremental auctions. (See No End in Sight for PJM Capacity Market Changes.)

8. Combined Cycle Modeling Problem Statement (11:20-11:35)

Members will be asked to approve a problem statement presented by Bob O’Connell, of PPGI Fund A/B Development, regarding combined cycle unit modeling that was developed in the Combined Cycle User Group.

9. Winter-Season Resource Adequacy and Capacity Requirements Problem Statement/Issue Charge (11:35-11:50)

Members will be asked to approve a problem statement and issue charge presented by James Wilson on behalf of the Maryland Office of the Peoples’ Counsel regarding requirements for resource adequacy and capacity needs in the winter. (See No End in Sight for PJM Capacity Market Changes.)

10. Pumped-Storage Hydropower Tariff/OA Revisions (11:50-12:00)

Members will be asked to endorse Tariff and Operating Agreement revisions recommended by the Governing Document Enhancement & Clarification Subcommittee regarding the day-ahead scheduling of pumped-storage hydropower.

11. Revisions to Manual 18 Regarding Replacement of Capacity Obligations (12:00-12:15)

Members will be asked to endorse revisions presented by Barry Trayers of Citigroup Energy (and an accompanying friendly amendment from PJM) proposed for Manual 18: Capacity Market regarding the immediate replacement of capacity obligations.

Members Committee

Consent Agenda (2:20-2:25)

Members will be asked to endorse:

2016 Installed Reserve Margin study results. (See “IRM Study Approved but Criticized for Lack of Winter Analysis,” PJM Markets and Reliability and Members Committees Briefs.)

Proposed clarifying updates to the credit policy in Tariff Attachment Q. (See “Credit Policy Changes Approved,” PJM Markets and Reliability and Members Committees Briefs.)

1. Elections (2:25-2:40)

Members will be asked to elect new representatives for the Finance Committee, sector whips and the vice chair of the Members Committee for 2016-17.

2. Fuel Cost Policy and Hourly Offers (2:40-3:00)

Members will be asked to endorse revisions to Manual 15: Cost Development Guidelines. See MRC item 2.D. above.

— Rory D. Sweeney

November 15, 2016March 12, 2024

Overheard at the TREIA GridNEXT Conference

GEORGETOWN, Texas — Almost 150 national and regional renewable energy industry representatives gathered here for the Texas Renewable Energy Industries Alliance’s GridNEXT conference. ERCOT CEO Bill Magness and NYISO CEO Brad Jones both delivered presentations, and panel discussions focused on distributed generation, storage technologies, renewable power and the various challenges facing the ERCOT grid.

Future Prices in the Texas Market

Magness opened the conference with a SWOT analysis of ERCOT. In listing the strengths, weaknesses, opportunities and threats facing the ISO, Magness’ focus became apparent: the ability to keep track of distributed energy resources (DERs) and their integration.

He noted ERCOT has about 900 MW of distributed generation connected in its retail-choice areas and “roughly” another 200 MW in the market’s noncompetitive areas.

“That’s not a huge penetration at this point. These resources don’t raise a long-term reliability issue and we’re not waving a red flag, but we expect to see more,” Magness said. “We need to come up with a process to map those DERs. It’s the distribution service provider’s job to model the system, but we want to map those things into things we’re responsible for.”

Magness said ERCOT will soon be issuing a white paper on DERs and asked for stakeholders’ help with improving the resources’ visibility. “We want to work with you on that. We’ve got to get an answer, because it’s holding up the usefulness of the ERCOT system.”

He likened the ISO to an Austin-area moving company. “Their motto is, ‘If we can get it loose, we can move it,’” Magness said. “If we can see it, we can integrate it.”

NYISO CEO Explains 50-by-30

Magness’ counterpart at NYISO, the Texas-native Jones, delivered the conference’s keynote address. Jones detailed the ISO’s plan to meet New York’s “50-by-30” goal: 50% renewable energy use by 2030. To meet that goal, NYISO would have to add either 25,000 MW of solar, 15,000 MW of wind or 4,000 MW of hydro by 2030; it currently has 1,700 MW of wind and 3,000 MW of hydro.

“It’s a significant overall goal, but this is the goal, economy-wide,” Jones said. “It includes transportation, it includes home heating, it includes all those elements. Electric generation would have to decrease production by 60% to account for increases in transportation.”

He said New York’s recent actions to protect the region’s aging nuclear plants will help the transition to a lower-carbon fuel mix. “The state has been very firm: We need to maintain nuclear generation,” Jones said.

The state “had a real concern it would lose these real low-carbon facilities, and that it would make it almost impossible to achieve this 50-by-30 goal. [The nuclear facilities] did it by making a side arrangement with the government. Utilities will charge the customers for it to provide enough financial support to keep them in N.Y. If we’re going to be a low-carbon [grid operator], we have to make sure we’re paying for the attributes we want, whether that’s fast-ramping capacity or baseload gen or low carbon or renewable facilities.”

Renewable Energy Credits: All About the Money?

Addressing the issue of corporate procurement of renewable energy, Jessica Adkins, a partner with the Bracewell law firm, said there are differences among major corporations seeking renewable energy credits (RECs). “If your goal is to say you’re buying green energy, that’s easy for people to do,” she said.

“If all your goal is to claim you’re buying renewables, you can offset usage with RECs. Where Amazon is going is additionality. They want do to more than go green. They want to tell their customers they’re putting renewables on the grid.”

“In our business and outside our business, I’m seeing a further diversification of companies doing these kind of deals,” said Adkins’ fellow panelist, Hans Royal, associate vice president of strategic renewables for Renewable Choice. “They don’t really have an environmental goal, but they see the fixed price of energy. Education is the No. 1 hurdle to why we’re not seeing a faster adoption. It’s coming … industry organizations are actively sharing information and trying to create a community in the purchase-power space. Getting information out to those companies is key.”

Texas Energy Aggregation’s T.J. Ermoian said the issue is the color of money, no matter where customers are. “If they see the government investing in [renewables], they’ll be more comfortable,” he said.

“Being in Texas, we’re energy-rich. I tell people I’m in the middle [of the state] between George Bush’s ranch and Ted Nugent. We’re in the reddest of red states,” Ermoian said. “I start talking about climate change in Texas, and the eyes start to glaze over. Money is the greenest thing people understand. If we can give them a compelling economic vision and quantify what they’ve been paying and say, ‘Here’s what you could be paying.’ … Well, most people are pretty good at math.”

Energy Storage a Positive ‘Disruptive Technology’

Referring to energy storage as a “disruptive technology,” Narrow Gate Energy President Darrell Hayslip was one of several panelists who predicted a brighter future for the technology.

“We’re all trying to figure out where will storage go. Where will it play?” he said. “We’ve done a lot to prove out this technology. The trick now is how are we going to apply it in the system. These are disruptive technologies that require some changes.

“It’s something new we’ve never had before. Cars wouldn’t do any good without highways, cell phones without infrastructure. We’ve got to see infrastructure catch up. The builders don’t make that investment unless they see benefits come out.”

Fractal Business Analytics CEO Judy McElroy said she is finding “compelling reasons” for solar and storage in ERCOT. She predicted one of the largest municipal utilities in Texas — thought to be San Antonio’s CPS Energy, with nine solar farms already generating 230 MW of energy — would be issuing a request for proposals within a week for energy storage solutions.

“We’re seeing in ERCOT the evolution a utility goes through. They’ll do solar first, then storage,” McElroy said. “You have to take into account that from a utility’s perspective, things take a lot of time. It’s sometimes more complex than it needs to be.”

“A lot of people are looking at RFPs in the future,” said Bradley Feuge, head of project management for German solar manufacturer KACO new energy. “Once this big RFP comes out … this municipality kind of sets the pace in the state. They’re seen as a leader nationally, and once they take the leap, you’ll see more people stepping out there as well.”

“Once you add solar to storage, then you essentially have a microgrid that can sustain an hour or so of outages,” said Hugo Mena, Electric Power Engineers’ vice president of business development. “EPE has seen this coming for a couple of years because the integration of storage, whether to a solar plant or a wind farm or storage as a transmission asset, is positive for the grid. The question now is, when it is going to be economically feasible for developers or utilities to implement this technology in their systems. We’ve seen at the municipal level that it’s become economically feasible, but some [investor-owned utilities] are also installing storage for microgrid purposes.”

Transmission Planning: More Complicated than Rocket Science

Bill Bojorquez, Hunt Power’s vice president for transmission planning, said during a panel focused on Texas transmission that continued solar and wind development in the state will not be able to take advantage of initiatives like ERCOT’s Competitive Renewable Energy Zone (CREZ). The $7 billion project facilitated the construction of 3,600 miles of transmission lines, connecting West Texas wind farms with the state’s huge metropolitan load centers.

“We have a lot of solar development coming into West Texas, but this area has a weak transmission grid,” Bojorquez said. “Without CREZ, wind and solar are going to have to follow the same process of any other generation. You’re going to have to commit before we can plan for you.”

“Twenty-five years ago, transmission couldn’t get funding in a company. It was all about generation and keeping things patched together so we didn’t get into trouble at the commission,” said Calvin Crowder, president of GridLiance’s South Central Region. “The returns in Texas are attractive considering what else you’ve seen. There’s been a lot of transmission invest in the investor-owned utilities, the municipal power utilities and the municipal power agencies, as well as the co-ops.”

“Texas knows about energy in every single form. We know how to manage it, we know how to control it, we know how to develop it,” said Ken Donohoo, Oncor’s director of system planning, distribution and transmission. “We as planners have to think about a lot more changes and complexity. Communications and control is key.”

As an example, Donohoo said Oncor has more than 9,300 rooftop solar installations on its system. “We know where every one of those is on our system,” he said.

“Transmission planning isn’t rocket science,” Crowder said. “I talked to a planner once and they said, ‘That’s right. It’s a lot more complicated than putting a rocket in the air.’”

Distributed Generation and Microgrids: Evolving Business Models

Thomas McAndrew, whose Enchanted Rock company provides on-site, natural gas-fueled backup power, said his business provides what is essentially a microgrid control system.

“Our primary job is reliability,” said McAndrew, Enchanted Rock’s managing director. “We’re creating a portfolio of quick-response natural gas assets. We think that’s incredibly important in our current environment, especially in ERCOT. We’re going to have periods of time in the shoulder months where we can displace almost all thermal generation. You may have wind at 90% of the supply stack, but we think it’s important to have quick-start assets. We’re there to buffer when we have sudden changes in either wind or solar generation.”

Brandon Middaugh, a senior program manager with Microsoft, described what she saw as “an interesting trend” in the high-tech industry.

“You have these large, concentrated customer loads,” she said. “When that’s one of your main operating costs, it really drives an organization to build up capacity to interact more directly with the markets, to be more about this collaboration and understand how [electric] markets work today, how they’re evolving and how that affects customers like Microsoft.

“There’s more of a need on our part to interact directly with the whole market,” Middaugh said. “That actually serves the grid operators and the utilities well. Apple, Google and others are registering to self-supply and become wholesale participants. I think you will see more of that, and it can be a boon to grid operators.”

Distributed PV Modules Taking off in San Antonio, Elsewhere

San Antonio’s burgeoning solar market was also a topic of conversation during a panel on distributed PV pricing. Rick Luna, CPS Energy’s senior manager of product development, said under the city’s rebate program, customers are paid to host rooftop solar systems.

CPS Energy’s board recently extended the seven-year-old program, though it is gradually reducing the rebate’s amount. Luna said 500 systems will be eventually installed, noting the $30 million program was expected to sell out next year. However, he said, there are downsides to the explosion of interest.

“That $30 million will be spent by January,” he said. “We’ve seen new market players from other markets coming to San Antonio and aggressively marketing to customers. We welcome them, but it’s not always a fair game. Customers don’t always know what solar should cost … they sign these contracts with $20,000, $30,000 commitments. We’ve updated our rules to try and educate our customers and give them some information to arm them and help them make a more informed decision.”

“There’s been some significant PV module pricing decreases this year,” said Eric Cotney, vice president of sales and marketing for Dallas-based Axium Solar. He attributed the 30% in cost reductions to better technology and lighter modules.

“PV modules are continuing to creep up in the power ratings. What used to be a 25-W power module is now a 275-W power module,” Cotney said. “You add labor efficiencies into that because [technicians] are now able to work with smaller modules. And then racking companies are making their systems more minimalist with fewer bolts, making them lighter and faster to put together. As more of our crews are up on roofs and encountering different installation challenges, we’re getting better at what we do.”

Solar Marketers Debate Texas Market’s Future

Another panel debated whether there’s still room for growth in the Texas market, with ERCOT showing 2,000 MW of solar generation with signed interconnection agreements and the ISO’s long-term studies showing another 20,000 MW in potential additions.

“In states like Texas, where the overall weighted power prices are low, it’s a race to deliver solar at prices that compete with traditional generation,” said Preston Schultz, director of development for Chicago-based Hecate Energy. “Everything is definitely bigger in Texas. You’ve got landowners who control large chunks of land, you’ve got an educated landowner base. In [the Southeast] we’re having to educate landowners most of the time what the technology is. They just haven’t seen it. We come to Texas, they know renewables, they know wind, they know solar on the utility scale. That just makes our job easier.”

David Dixon, of renewable energy company Native, said his company sees the same growth opportunities in the Texas market. He pointed to the Public Utility Commission of Texas’ Power to Choose website, where some retail electric providers are offering to buy customers’ excess renewable energy.

“We expect to see double-digit growth, especially in the residential market. We’re still seeing prices come down,” Dixon said. “What we’re not seeing is solutions for home storage aligning with the homeowner’s expectations. We’re in the early adopter’s stage, but I do think in the future, we’ll be installing storage solutions.”

“The commercial markets have grown due to projects in North Texas, thanks to Oncor rebates,” said Mark Begert, executive vice president and director for Meridian Solar. “Even 1- to 2-MW projects represent a pretty meaningful lift to the overall commercial market in Texas. The lower prevailing electricity rates are a challenge. Rooftop solar return requirements for solar customers are significantly higher than you see in the residential market. Commercial customers want their [internal rates of return] in the mid to high teens. They want payback in five years. The residential customer is more comfortable with eight to 10 years. That’s a significant return threshold solar has to overcome.”