Page 1667 – RTO Insider

March 21, 2016April 7, 2025

FERC: Cheap Gas Drove down Electricity Prices in 2015

By Michael Brooks

WASHINGTON — On-peak day-ahead electricity prices in the U.S. were down 27 to 35% in 2015 compared to 2014 largely because of cheap natural gas, FERC staff said in its State of the Markets presentation Thursday. LMPs in New York hit a 15-year low.

FERC: 2014 a Record-Breaking Year for Natural Gas.)

The increase in supply has led to the addition of 51 Bcf/d in new pipelines in the last five years, with an additional 49 Bcf/d planned or proposed to come online by 2018. Demand for gas, however, grew only 1.3% last year as a result of a mild winter.

As a result of the low prices, gas-fired generation surpassed coal-fired on a monthly basis for the first time in April 2015, and beat coal in six of 11 months through November, according to the Energy Information Administration. Each provided about one-third of all electricity generation.

EIA predicted last week that natural gas will provide 33% of generation in 2016 while coal’s share falls to 32%. Bowring Urges Return to ‘Fundamentals’.)

FERC staff said they expect the trend of lower gas prices to continue into 2016 but that production has likely plateaued and will decline in the long run, as the low prices begin to push higher-cost producers out of the market.

About one-sixth of U.S. natural gas is a byproduct of oil production, which suffered as prices fell 66% between June 2014 and December 2015. According to the U.S. Bureau of Labor Statistics, the oil and gas industry shed about 17,000 jobs last year, while the U.S. oil rig count dropped by 61%.

“Long-term demand growth for U.S. natural gas will likely come from increased gas-fired electric generation, particularly in the Southeast, growing industrial demand, LNG exports and pipeline exports to Mexico,” staff said.

The price of LNG, which was exported for the first time from Cheniere Energy’s Sabine Pass terminal on the Texas-Louisiana border to Mexico last month, is indexed to oil in most long-term contracts.

LMPs down, Capacity Prices up

The fall in electricity prices was in sharp contrast to 2014, when prices rose across the country, in part due to the severe winter in the Northeast and Midwest.

While LMPs fell, capacity prices rose in PJM and ISO-NE, as the lower gas prices drove out coal-fired and nuclear generators and forced other nuclear plants to rely on capacity auctions for revenue. FERC noted that the clearing price for the Rest of RTO zone in PJM has risen 152.6% since 2013 and more than 200% in ISO-NE for the same period.

“These lower LMPs and higher capacity prices in PJM have resulted in the ‘all-in’ costs of energy, capacity, transmission and ancillary services to increase by 5% between 2013 and 2015,” FERC staff said.

“As the markets are calling for new resources, we’re seeing significant increases in the capacity markets, really stress testing the markets, and … I think ancillary services are going to get a lot more important in the future [to] balance all the interruptible resources,” Commissioner Cheryl LaFleur said.

Electricity demand fell by 1.1% in 2015 as a result of low economic growth and increased efficiency in appliances. Electricity use fell in the industrial sector, while residential and commercial customers showed little or no growth.

DER and Renewable Growth Continues

While the net generation of power plants nationwide has increased 1.2% since 2011, the total electricity sold back by net metering customers has increased by nearly 500%, FERC staff said. Demand response revenues, meanwhile, have also increased through the capacity markets in PJM and ISO-NE for the past three years, a trend FERC expects to continue as a result of the Supreme Court’s decision on Order 745, upholding FERC’s jurisdiction over DR.

Wind continues to be the dominant renewable energy resource in the U.S., rising to 4.6% of total generation. While solar rose to only 1% of total generation in the country, it makes up 13% of installed capacity in California, home to half of the country’s utility-scale solar.

March 21, 2016

FERC Declines Rehearing in Decade-Old MISO Pricing Dispute

By Amanda Durish Cook

FERC last week declined MISO’s request to reconsider a 2008 refund order stemming from transmission pricing complaints filed by the city of Holland, Mich., and DTE Energy Trading more than a decade ago (EL05-55-003, EL05-63-005).

Proceedings for the case go back to early 2005, when FERC found that MISO had violated its Tariff by charging the Holland Board of Public Works and DTE a higher hourly non-firm point-to-point transmission rate in instances when the utilities redirected the receipt point for their firm point-to-point service within the same transmission pricing zone — but on a non-firm basis. The commission ordered MISO to issue refunds with interest for the difference between the two hourly service rates. The RTO was also required to file accompanying refund reports for Holland, DTE and “other similarly situated customers,” effectively extending refund eligibility to other market participants incurring similar charges.

In May 2008, after conditionally accepting MISO’s 2005 and 2006 refund reports, FERC further ordered the grid operator to refund overcharges for ancillary services associated with customers’ redirect service.

In its rehearing request, MISO contested the ancillary services refund along with aspects of FERC’s earlier decisions. The RTO argued that FERC’s rulings had violated the Federal Power Act on two counts.

First, by directing MISO to refund the charges related to ancillary services, the commission had corrected its order outside the timeframe permitted under the FPA, namely before an appeal had been filed or in advance of the deadline for petitioning for judicial review. MISO also said FERC sought to exploit ambiguities in its refund order by rewriting the methodology associated with the refunds.

Second, FERC’s order directing MISO to issue refunds dating back to 2002 violated an FPA provision barring refunds for periods preceding a complaint filing, MISO said.

MISO further contended that any refunds should be limited to the original complainants, and that calculating and issuing refunds to all affected customers during the period in question will be “time-consuming and costly.” FERC has stipulated a refund period of February 2002 to January 2009.

In denying the rehearing, FERC reiterated that the commission has “authority to go back to the date that the violation first occurred” and its seven-year refund period was “consistent with the refunds previously provided and accepted in these proceedings.”

FERC also said that ancillary services are needed to maintain reliability for transmission service and should be priced accordingly.

“Because these ancillary services were necessary to accomplish transmission service, they are part of any transmission service, including redirect service, and should be priced consistent with the service being provided,” FERC said. “The commission’s general policy is to order refunds for overcharges and for violations of the filed rate.”

March 21, 2016

FERC: Entergy Can Exclude Above-Market PPAs from Bandwidth Calculation

By Amanda Durish Cook

FERC last week granted Entergy permission to exclude from its system-wide “bandwidth” calculation the above-market portion of the price paid for electricity under two power purchase agreements with generators certified under the Public Utility Regulatory Policies Act and Louisiana’s Renewable Energy Pilot Program (ER14-1640).

FERC, Entergy — Rain CII’s calcining Plant in Sulphur, LA *(Source: Rain CII)*

The March 17 ruling came despite a protest from the Louisiana Public Service Commission, which contended it was excluded from the settlement agreement.

The decision does not alter the actual value of Entergy Gulf States Louisiana’s PPAs with the Rain CII Carbon calcined petroleum coke facility in Sulphur and the Agrilectric rice hull-fueled power plant in Lake Charles. Rather, the commission is allowing Entergy to internally “re-price” the contracts to accommodate the “bandwidth” process the company uses to ensure that none of its subsidiaries have production costs 11% above or below the company average.

Supporters of Entergy’s position said the company’s re-pricing approach prevents the costs of local and state policy initiatives — such as renewable mandates — from being exported to other jurisdictions. However, the Louisiana PSC called the re-pricing practice “unduly discriminatory” to Entergy Gulf States Louisiana and its customers, which will incur increased costs to cover the entire above-market portion of the contract prices.

The PSC also called the settlement procedure an “abuse” because it only included parties that agreed with Entergy’s original 2014 filing.

FERC disagreed.

“We note that the settlement, and the proposed revision it approves, establishes a policy that is applicable to all similar renewable energy PPAs entered into by any of the participating Entergy operating companies,” FERC said. The commission added that Entergy entered into the PPAs “to meet the requirements of the [Renewable Energy Pilot] Program for the benefit of Entergy Gulf States Louisiana’s customers, rather than for the benefit of the Entergy system as a whole.”

March 21, 2016

FERC OKs Wisconsin Utilities’ Asset Transfer

FERC last week gave the go-ahead for American Transmission Co. and Wisconsin Power & Light to swap a combined $830,000 worth of assets (EC16-61).

ATC Substation, WP&L, FERC, MISO — ATC Substation *(Source: ATC)*

Under the agreement, WPL will acquire five ATC substations valued at $458,820 in exchange for $370,863 in transmission-related equipment, which include a power transformer, storage batteries, 138-kV line frames and foundations, poles and historical air brake switches. The Wisconsin-based companies said the move will better “align ownership of the relevant facilities by function,” providing WPL new distribution facilities while handing ATC more transmission assets, which will be turned over to the operational control of MISO.

Both companies will pay current net book value for all facilities in cash without an acquisition adjustment. ATC said the transaction will have “virtually no effect on transmission rates,” noting that the difference in value between the assets being exchanged is only a “tiny fraction” of the company’s total net utility plant of $3.4 billion. WPL receives nearly all of its transmission services from ATC.

— Amanda Durish Cook

March 21, 2016

Louisiana City Allowed RTO Tx Adder

The city of Alexandria, La., is entitled to collect a MISO-related adder of 50 basis points on top of its authorized rate of return on equity without having to make a request to federal regulators, FERC ruled last week (EL15-75).

Alexandria, Louisiana in MISO (FERC) — Alexandria, Louisiana Skyline

The commission said Alexandria’s petition to implement the RTO membership adder was unnecessary because the city was already eligible to do so under MISO’s municipal generic template, a formula municipal transmission owners can use to derive their revenue requirements. FERC last June directed the RTO to include the adder, which became effective immediately (ER15-1067).

The commission also granted Alexandria’s request to defer adder collection until after a decision on an ongoing complaint against MISO transmission owners (EL14-12). In that proceeding, MISO transmission customers argue that the current 12.38% base return on equity earned by owners should be decreased to 9.15%.

— Amanda Durish Cook

March 14, 2016

FERC Upholds MISO Cancellation of GIA

By Amanda Durish Cook

FERC has accepted MISO’s request to terminate a generator interconnection agreement (GIA) with EDF Renewable Energy’s 150-MW Merricourt wind project in North Dakota, eliminating the prospect the facility would be granted additional time in the interconnection queue before completing construction.

FERC said MISO’s interconnection policy is clear in denying such extensions unless a project’s development has been hindered by another project in the queue.

“No such circumstances are presented here, and, even if such circumstances were present, Merricourt could not extend its [commercial operation date more than] three years beyond the original COD,” the commission wrote (ER16-471).

Commissioner Cheryl LaFleur was the sole dissenter in the 3-1 ruling, citing worries that the decision could create barriers for other wind projects.

MISO revoked Merricourt’s GIA after the facility failed to meet a Dec. 1 deadline to begin commercial operations, despite a request to extend the term until Sept. 30, 2017. Merricourt maintained the project was eligible for such treatment because it had completed a significant amount of construction and was close to securing a long-term power purchase agreement. Development hit a snag in 2011 when Xcel Energy withdrew its PPA for the project, but Merricourt said it could bring the wind farm online by the end of this year.

FERC’s ruling pivoted on a narrow reading of the text within MISO’s GIA with Merricourt, particularly a provision permitting the developer to extend the in-service date after demonstrating “significant steps to maintain or restore operational readiness.” The commission ultimately agreed with MISO’s interpretation that the language only applies to a facility that has already begun — and then ceased — operating.

FERC added that keeping the wind project active could be unfair to other projects in the queue.

In her dissent, LaFleur focused instead on Merricourt’s progress with the project, which she said was so advanced that it would not cause harm to other project developers.

“In my view, our precedent provides the commission with clear authority to determine whether a COD extension is appropriate in a given case,” LaFleur wrote. “Here, I believe that Merricourt has both demonstrated meaningful progress towards reaching commercial operation in a reasonable timeframe … and effectively rebutted concerns expressed by MISO that the Merricourt project is speculative and potentially harmful to other customers in the queue.”

MISO has said that Merricourt is free to continue work on the project, which has so far cost about $20 million according to the developer. That will require it to re-enter the queue and obtain a new GIA.

March 14, 2016

Cost Estimate of PSEG Portion of Artificial Island Fix Doubles to $272M

By Suzanne Herel

VALLEY FORGE, Pa. — The estimated cost for Public Service Electric & Gas’ portion of the Artificial Island stability fix has nearly doubled, from $137 million to $272 million, PJM told the Transmission Expansion Advisory Committee on Thursday.

“We certainly were surprised when we first saw the numbers,” Steve Herling, PJM vice president of planning, told RTO Insider. “In retrospect, we wish we’d had more foresight. We’re going to have to take a real hard look at what this tells us about our process going forward. We don’t like making an estimate that’s this far off.”

PJM stands by its selection of the project, which involves building a new 230-kV transmission line from the nuclear complex in New Jersey to Delaware.

“Based on what we have seen so far, we still believe we have the right project,” Herling said. “There are elements of the design that we continue to discuss, and we’re looking for opportunities to further optimize it and mitigate costs, but at this point we still believe we have the right project.”

LS Power was chosen to build the line, with PSE&G and Pepco Holdings Inc. assigned to construct the necessary connection facilities. LS Power won the deal in large part because it committed to limiting construction costs to $146 million. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.)

“LS Power’s cost cap commitment has not changed, and LS Power continues to focus on successful development of its portion of the Artificial Island project,” company Vice President Sharon Segner said.

Paul McGlynn, PJM general manager of system planning, said the cost allocation of the project would remain the same, with the bulk of the price tag being designated to customers on the Delmarva Peninsula.

After Delaware and Maryland regulators and consumer advocates complained about the seemingly disproportionate cost assignment, FERC suspended PJM’s Tariff changes involving the project’s cost allocation pending additional review (EL15-95).

At a Jan. 12 technical conference ordered by the commission, stakeholders debated cost allocation based on the solution-based distribution factor (DFAX) method. (See related story, Commenters: DFAX Cost Allocation Inappropriate for Some Projects.)

So, how did PJM planners miss the mark so widely?

Herling said the Artificial Island project is unique and there was little to compare it to.

“This is the first time we’ve had to deal with so much work inside of a nuclear station,” he said. “We did our best to add substantial adders … but in some areas they weren’t big enough,” he said. “I don’t know how PJM could have done better with that other than doing more extensive detail design work,” which would be expensive and time-consuming, he said. “We will be talking about that, as far as how to do things differently moving forward.”

The Board of Managers, which approved the Artificial Island project, reviews cost increases but does not need to approve them unless the scope of the project is altered, Herling said.

“We review all significant changes with the board. They will ask us questions. They will ask us to get more information. They may suggest alternatives that we should be looking at. At the end of the day, we will do everything they ask us to do, and hopefully they will be satisfied with the information.” But, Herling said, “If the project continues in the [Regional Transmission Expansion Plan], the board does not have to approve revised costs.”

The board could decide to switch to another project, but that’s not likely, Herling said.

PSE&G’s portion of the project consists of three main elements: installing a static VAR compensator (SVC) at the New Freedom substation; putting in optical ground wire (OPGW) for high-speed relaying; and expanding the Salem substation. Herling noted that the SVC and OPGW work were common to all proposals and that any vendor likely would have run into the same cost issues.

The SVC work, which PJM estimated at $38 million, is expected to cost $43 million more, according to PSE&G, in part because of additional site work including wetland mitigation, storm water management and the relocation of a helicopter pad and several buildings. PSE&G also ran into higher vendor cost estimates, McGlynn said.

Additional site work for the OPGW installation increased PJM’s estimate of $25 million by $14 million.

The Salem expansion, estimated at $74 million, will cost an additional $78 million, in part because of the cost differential for security and access requirements needed to work in a nuclear facility.

“We understood that working in Salem would be more challenging than working at a 500-kV substation in the middle of a cornfield someplace,” McGlynn said. “What we’re trying to look at and consider and get a better understanding of is the difference in cost.”

A number of committee members were incredulous.

“Percentage-wise, this is a big miss as far as what we thought we were looking at,” said Dave Mabry, representing the PJM Industrial Customer Coalition, noting that there are no cost commitments involved in the PSE&G work, all of which is considered an upgrade as opposed to a greenfield project.

“We were at $250 million … now we’re up to $350 million,” Mabry said. “The concern here is, is there another shoe that’s going to drop?”

March 14, 2016January 26, 2025

EBA 2016 Midwest Chapter Annual Meeting

INDIANAPOLIS — The Clean Power Plan, Order 1000, FERC enforcement and distributed generation were favorite topics at last week’s annual meeting of the Energy Bar Association’s Midwest chapter. Here’s a sampling of what we heard.

Energy Bar Association, Commissioner Colette Honorable, FERC

Honorable © RTO Insider

“Let’s not talk about how the stay will halt work” on the Clean Power Plan, FERC Commissioner Colette Honorable said. “The industry was moving toward a more renewable future long before the Clean Power Plan came along. Let’s continue our work regardless of the stay. It’s a stay. It’s not a decision on the ultimate merits of the plan.”

Honorable also asked the Energy Bar Association for feedback on whether Order 1000 could be improved. “I know it’s not perfect. … We know that the sticky part is interregional planning. I want Order 1000 to aid in the development of these very important interregional projects and not be a barrier.”

Allen © RTO Insider

Steve Allen, pipeline safety director at the Indiana Utility Regulatory Commission, commented on the trend of electric utilities acquiring gas businesses to feed their gas turbines. “You can have a good safety culture without having a good pipeline safety management system in place, but you can’t have a good pipeline safety management system without a good safety culture.”

Tsoukalis © RTO Insider

John Tsoukalis, an associate with The Brattle Group, said if FERC prohibits virtual trades at nodes with financial transmission rights in order to stop participants from taking losses on virtuals to increase the value of their FTRs, it would also end legitimate trading and harm the market. “FERC is growing aggressive on how they [prove intent],” he said. “But that’s still a question: How heavily does intent versus economic evidence weigh in FERC’s investigation?”

John Parsons, MIT Sloan School of Management

John Parsons, of the MIT Sloan School of Management, discussed the bidding strategy that landed J.P. Morgan in FERC’s crosshairs for market manipulation in California and Michigan in 2013. “From 10 to 11 p.m., their bid price was negative $30/MWh; from 1 to 2 a.m., their bid price was $999/MWh. What they were trying to do was exploit a seam in the algorithm. [The unit] got paid $999/MWh for the two to three hours it took to ramp down,” he said.

Jim Cater, director of economic and financial policy for the American Public Power Association, questioned the appeal of customer-owned distributed energy resources such as rooftop solar. “There’s a notion that somehow there’s a customer groundswell of this, but I don’t know that many people who are involved with this at home,” he said. “I don’t want to be perceived as a naysayer … but this has got momentum behind it that could benefit from a bit of cost-benefit analysis.”

Donna M. Attanasio, senior advisor for energy law programs at George Washington University Law School, talked about the genesis of the e21 Initiative, which the university launched in 2014 along with the Great Plains Institute, Xcel Energy and others to plot a new regulatory model in Minnesota. “Customers want green power; they want more flexibility. If the utilities aren’t going to provide these, customers are going out and getting it themselves. This is where the e21 Initiative started.”

Stacy Stotts, a partner and member of the environmental and natural resources division at Stinson Leonard Street, commented on the Supreme Court’s stay of the Clean Power Plan. “To say the stay is unprecedented is an understatement. The biggest argument [against the CPP] is that utilities are already regulated under the Clean Air Act. If this argument prevails, the rule is gone, it’s going to be vacated … I think that’s a strong argument. Now, what if the rule is vacated? An important thing to remember is the EPA [still] has to regulate emissions — the Supreme Court told them to in Massachusetts v. EPA.”

Stotts also predicted President Obama’s effort to win Senate approval of a replacement for Justice Antonin Scalia “will be a brutal appointment process.”

– Amanda Durish Cook

March 14, 2016

CAISO Tariff Change Would Extend Market to DER

By Robert Mullin

CAISO has asked FERC to approve a new Tariff provision that would enable rooftop solar and other small distributed energy resources (DER) to participate in California’s energy and ancillary services markets (ER16-1085).

The rule changes create an “initial framework” to extend market participation to DER smaller than 0.5 MW — the current minimum for selling into the ISO’s wholesale market — by allowing for aggregation at the distribution system level.

CAISO is anticipating participation by distributed generation, energy storage and electric vehicle charging stations, but the framework leaves open the possibility for market entry by other types of resources located on either side of the customer meter. This “broad definition” of eligibility is intended to avoid excluding emerging technologies from participating in aggregation.

“The framework will accommodate various resource types as well as different business models, provided the aggregation is capable of operating as an integrated resource and meets specific technical requirements,” CAISO wrote. Those models could include microgrids interconnected to distribution systems as well as third-party aggregators and utilities operating DER.

The rules would bar some resources from participating in aggregations, including generation rated at 1 MW or greater, demand-side resources bid into the market by curtailment service providers and demand response intended to react to grid emergencies. Generating units between 0.5 MW and 1 MW would need to terminate their participating generator agreements in order to join an aggregation. Also excluded would be resources already participating in a retail net energy metering program.

New Participant Type

The Tariff revisions would introduce three new terms into CAISO’s official market lexicon:

Distributed energy resources: Any resource in the ISO balancing area with a first point of interconnection to a utility distribution company or a metered subsystem.
Distributed energy resource aggregation: A “market resource” comprising one or more DER organized to participate in the wholesale market. Aggregations can contain multiple resource types, but resources will be restricted to participating in a single aggregation.
Distributed energy resource provider: “A new type of market participant,” according to CAISO, DER providers would be owners or operators of an aggregation. They would engage the market through a registered scheduling coordinator, which would submit schedules and bids based on the aggregation’s generation distribution factors.

The rules would permit a DER aggregation to operate at a single pricing node or across multiple nodes. Regardless of the configuration, the resources are required to provide a net response at the nodal level consistent with dispatch instructions, with missteps subject to imbalance charges.

Compensation will be based on nodal LMPs, but CAISO will not directly poll meters in an aggregation, so DER scheduling coordinators must provide the ISO with settlement quality meter data in order to receive payments.

In its filing with FERC, CAISO urges approval of the changes by pointing out that distributed facilities already participate in ISO wholesale markets as both generating and demand-side resources.

“The Tariff revisions proposed in this filing do not change those arrangements,” CAISO wrote. “Instead, the CAISO is extending the same opportunity to support the reliable operation of the transmission system to aggregations of distribution-connected resources, recognizing the significant transformation in the industry and deployment of emerging technologies.”

March 14, 2016February 12, 2025

CT Power and Energy Society’s Annual Energy, Environment and Development Conference

Connecticut sees itself as an energy technology and policy innovator, but much work remains to help it maintain its leadership position, speakers said at the annual Connecticut Power and Energy Society’s Energy, Environment and Development Conference last week.

Connecticut Gov. Dannel Malloy said he is looking forward to the Clean Power Plan, which he believes will be upheld in the courts. “In Connecticut and New England, what these rules are saying is ‘finally, the rest of the country is going to have to live by the same set of rules that we’ve had to live by,’” he said.

New England has long complained of being at the ‘end of the tailpipe’ from Midwest polluters. Malloy said the CPP will be good for his state’s environment — and its economy. “I think it will level the playing field, at least with respect with our ability to compete with other states [and] with respect to the cost of the eventual product, electric energy.”

David Kooris, director of the City of Bridgeport’s office of planning and economic development, recounted the difficulties the city had winning state and federal regulatory approval for a 1.6-MW anaerobic digester and cogeneration facility built near a wastewater treatment plant. “The regulatory environment isn’t yet ready to accommodate some of the new technologies we’re talking about. That was a tough regulatory process and [state environmental regulators] were working closely with us, knowing it was an objective of theirs. But it was fairly arduous just because of the outdated aspects of the regulations.”

Daniel Sosland, president of the Acadia Center, said technology is creating a historic transition in the electric industry. “The question is how fast will we get there. Will markets drive changes? Will policy keep up?” he asked. “The system that we’ve built and has been reliable is a one-way power flow … but in the system we’re building now, the centerpiece is in your community. It’s in your home, it’s in your place of work.”

Jonathan Milley is director of business development for Vionx Energy, which is developing flow battery technology that proponents say will deliver long-duration energy storage at lower costs than lithium-ion batteries. He talked about storage’s challenges in winning a place in the market. “Storage is trying to find a leg in the three-legged stool in between generation, transmission and distribution, and doesn’t quite know how to fit into the equation.”

Katie Scharf Dykes, the Connecticut Department of Energy and Environmental Protection’s deputy commissioner for energy, spoke of accommodating state public policy goals in deregulated wholesale energy markets. “I hope there’s a peaceful resolution, a productive resolution,” she said. “State public policy goals are not discretionary whims; we have a statutory mandate to cut carbon, and we have an obligation to our ratepayers and our children to address this challenge.”

Paul Hibbard, vice president of The Analysis Group, said resolving cost allocation questions is essential to overcoming the region’s infrastructure challenges. “The real confusing piece is what consumers will pay for which pieces of infrastructure, how much will that cost and what might be the alternatives.”

– William Opalka