Gleanings from the web and the world, condensed for convenience, illustrated for enlightenment, arranged for impact...
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YESTERDAY
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Founding Editor Herman K. Trabish
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WEEKEND VIDEOS, June 17-18
email: herman@NewEnergyNews.net
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Just a few years ago, the great environmentalist Robert F. Kennedy, Jr., was championing natural gas as a key “bridge” fuel to a New Energy future. But the times keep a-changing… From greenmanbucket via YouTube
posted by Herman K. Trabish @ 8:14 AM
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Fracking comes with the mad pursuit of the bridge fuel and this is what comes with fracking. From Jeremy Buckingham via YouTube
posted by Herman K. Trabish @ 8:13 AM
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A new film from the director who made "Gasland" that offers a sort of hope. From JFOX via Vimeo
posted by Herman K. Trabish @ 8:12 AM
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Denmark Mulls Taxing Beef, Other Red Meats To Fight Climate Change
Angela Laguipo, April 29, 2016 (Tech Times)
“…[Denmark is considering a tax on beef and other red meats in its battle against climate change…Danes have an ethical obligation to reduce the impact of climate change and they could do this by lowering their red meat consumption [according to the Danish Council of Ethics, an independent body that advises the government]…The majority of council members (14 of 17) said they support the ‘red meat tax.’ The council recommends an initial tax on beef, but will include other red meats in the future…[Other food products] deemed harmful to the environment could also be taxed…Animal agriculture accounts for about 18 percent of all greenhouse gas emissions, which is more than the overall emissions from all types of transport across the globe…Scientists believe global food production, animal agriculture, and waste disposal are key factors that contribute to climate change]…” click here for more
posted by Herman K. Trabish @ 8:50 AM
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Vision 2030 and solar energy: A timely development
Ahmed S. Nada, 29 April 2016 (Al Arabiya English)
“…[With the launch of Vision 2030, Saudi Arabia’s solar energy potential is now well defined and backed by Prince Mohammad bin Salman bin Abdulaziz Al-Saud, Deputy Crown Prince and Chairman of the Council of Economic and Development Affairs, and] the country’s visionary leaders…[It succinctly summarizes] Saudi Arabia’s emphasis on developing its new renewable energy market…First and foremost, [is] the upcoming launch of the King Salman Renewable Energy Initiative and an ‘initial’ renewable energy target of 9.5 gigawatts (GW)…[It] is the highest level commitment to renewable energy ever seen from the Kingdom…[Second is] the country’s commitment to ‘guarantee the competitiveness of renewable energy through the gradual liberalization of the fuel market’ [which is] clear evidence that the government fully intends to deliver on its renewable energy goals…[The document indicates Saudi Arabia will look to invest in research and development, manufacturing, and other elements] of the value chain…” click here for more
posted by Herman K. Trabish @ 8:50 AM
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Australia Becomes The First Country To Generate Zero-Emission Electricity From Ocean Waves
Rishabh Bannerji, April 21, 2016 (India Times)
“…Australia is leading the way [on energy that is sustainable and reliable] with a plan to generate zero-emission electricity…[from the constant] movement of the ocean…[Carnegie Wave Energy’s CETO 5 wave energy generators] make this happen…[Three CETO 5 units are now being used] to provide energy to a nearby naval base, but there are plans to expand to other locations…The water pumps convert the ocean waves into high-powered water which then creates hydroelectricity to power a reverse-osmosis desalination plant…[No ocean life is being harmed and the ocean is not being polluted, according] to the company…” click here for more
posted by Herman K. Trabish @ 8:49 AM
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Wind energy converter inspired by ancient boats; A bladeless wind energy convertor inspired by the sailing boats of Ancient Carthage is set to breeze past traditional turbines in terms of efficiency, according to its Tunisian developers.
Amy Pollock, April 25, 2016 (Reuters)
“The ancient civilisation of Carthage meets 21st century design in this wind energy convertor. The Saphonian is bladeless and non-rotating and can capture twice as much energy as a traditional wind turbine, say its developers. Tunisian start-up Saphon Energy took its inspiration from Carthage's sailing boats of 2,000 years ago, as well as the movements of birds and fish. The result - an aerodynamic bowl-shaped sail and a wind convertor that follows a figure of eight pattern. Engineers say their design beats traditional wind turbines on performance and cost, making it ideal for off grid energy generation in developing countries…The designers say risks to birds and other wildlife are reduced and the wind energy convertor is far quieter than traditional turbines.” click here for more
posted by Herman K. Trabish @ 8:49 AM
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posted by Herman K. Trabish @ 9:18 AM
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Giant wave-riding platform design puts solar power out to sea
David Szondy, April 25, 2016 (GizMag)
“Sea-based wind farms are becoming a common sight in many parts of the world…[and engineers] at the Vienna University of Technology foresee a future where platforms 100 m (330 ft) long and covered with solar panels float on even heavy seas thanks to a new floatation system called Heliofloat…Relocating panels offshore could make for installations of incredible size and generating potential, but…[they would face] tempests with waves that can pound a floating platform to kindling…[T]he TU Wien team claims that its Heliofloat system can support lightweight platforms the size of football fields that are stable even in heavy seas…[TU Wien is exploring other applications including desalination plants, biomass extraction, and protection of lakes from evaporation ]for the Heliofloat technology as it seeks partners and investors...” click here for more
posted by Herman K. Trabish @ 9:17 AM
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Local Food Truck Runs Entirely On Solar and Wind Energy
Tina Yazdani, April 24, 2016 (Time Warner Cable News)
“They're authentic Italian, wood-fired oven pizzas [that customers say are ‘fantastic’] and all of their ingredients come from local gardens…[But The Pi Truck is making an impression because it] is run entirely by solar and wind energy…[Owner Sam Maggio’s] hope is that this action will inspire other businesses in the community to [do their part for the planet and save themselves money. Maggio is] saving between $500 and $1000 a month…The Pi Truck can be found along the Seneca Wine Trail [in New York’s Finger Lakes region] all summer long.” click here for more
posted by Herman K. Trabish @ 9:17 AM
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This Company May Have Solved the Electric Car Charging Problem; Sometimes design thinking can solve engineering problems
Brady Dale, April 25, 2016 (UK Observer)
“…[The new solution for electric car charging from TankTwo can fully charge a car in minutes rather than hours…[T]he batteries are not especially different in terms of how much juice they can hold per square inch…[because TankTwo] didn’t solve the problem with engineering so much as with design…[Its] “string batteries” look like little eggs, with a bunch of contact surfaces…[They each have “brains” that allow] the batteries to determine how to best route the power in and out…[E]lectric cars could still be powered using a plug-in, which would still take as long as it takes any other car to charge, normally…[but] if a car needs a charge quickly, it can roll up to a station equipped to service TankTwo systems, suck out all the string batteries and then replace them with fully charged ones in under three minutes…[The] batteries don’t need to be wired together. They just need to be touching and their internal processors sort it out…The company promises the batteries will cost less to consumers…[and will] stay usable longer, lowering the replacement cost for [an EV’s] most expensive part…” click here for more
posted by Herman K. Trabish @ 9:16 AM
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New software offerings helps utilities boost community solar programs; Competition is heating up in the software-as-a-service field for shared solar
Herman K. Trabish, July 16, 2015 (Utility Dive)
The nation’s hottest solar market is being invaded by software developers – and they could give utilities the competitive edge they want.
Because communuity shared offers otherwise excluded utility customers the solar opportunity, it is the “biggest trend” for solar at utilities, according to a recent Solar Electric Power Association (SEPA) report on the topic.
It also is, according to the GTM Research, the most significant U.S. solar growth market.
“We spent tens of millions of dollars figuring out how to do this and then about $10 million and six years building the technology,” Clean Energy Collective (CEC) Founder/President Paul Spencer said of his new software offering.
“The concept is to plug the holes the developer needs filled in order to get more community solar into the marketplace.”
Community shared solar’s explosive growth
New data in DOE’s recent report on shared solar shows an estimated 49% of households and 48% of businesses unable to host solar on their own rooftops.
By subscribing to a share of a centrally located array’s output, utility customers who are renters, or have roofs too old or too shaded, or who use too little electricity to justify an individual installation can get solar benefits like a fixed electricity price likely to soon be exceeded by rising utility rates.
“By opening the market to these customers,” DOE reports, “shared solar could represent 32% to 49% of the distributed PV market in 2020, thereby leading to cumulative PV deployment growth in 2015 to 2020 of 5.5 GW to 11.0 GW, and representing $8.2–$16.3 billion of cumulative investment.”
The U.S. community shared solar market will add 115 MW in 2015, a roughly 500% year-on-year increase in growth over the 21 MW added in 2014, and almost twice the 66 MW cumulative installed capacity at the end of last year, according GTM Research’s new report, "Community Solar Outlook 2015-2020."
From 2015 through 2020, the “most significant U.S. solar growth market” will add 1,800 MW, a 59% annual rate, and be installing at the rate of 500 MW per year in 2020, according to GTM.
Some 29 developers are working in community shared solar projects, GTM finds, but sector leaders Clean Energy Collective and SunShare account for 32% the capacity now online. National residential market players like NRG Home, SunEdison, and SolarCity are moving in rapidly.
CEC was the first into the community shared solar space with its 2010 El Jebel, Colorado, array. To date, 24 states have projects in some stage of operation or developent. California, Colorado, Massachusetts, and Minnesota are expected to add over 80% of new capacity through 2017 but, with governing legislation moving in 20 states, geographic diversification is coming.
Software-as-a-service to community shared solar
CEC began developing its RemoteMeter software in 2009 at the same time it was working to make the shared solar concept viable. The software was conceived by Spencer and his team as a way to manage customer information and to integrate with a utility’s billing system.
It was designed to directly apply the credits earned for the subscribed portion of the community-owned solar array to the customer’s bill “as if the panels were on the customer’s house,” Spencer, a former software and engineering entrepreneur, said. “That was the first functionality.”
Designing the new software was a crucial step in the progress of shared solar because “we knew the utilities would say they wouldn’t do it if they have to pay people to key in all the customers’ credits,” Spencer said.
The software has evolved into CEC’s Community Solar Platform (CSP), a software-as-a-service (SaaS) product Spencer believes will move the market forward and give utilities the know-how to open “a great new business line for them.”
A CEC pre-designed format is loaded onto a utility-buyer's website, as examples now being used by Poudre Valley REA and Kit Carson Cooperative demonstrate. This can be done in minutes and the utilities can begin recruiting subscribers almost immediately, Spencer said.
The software platform has three options, he explained. RemoteMeter Foundation embodies the foundational tools, such as bill crediting contracts. RemoteMeter Engagement is the website template and ecommerce and customer engagement tools. RemoteMeter O&M guides the operations and maintenance of solar facilities.
There are three packages of services provided "over the top of those," he went on.
-A “delivery blueprint” is a step-by-step guide to construction, from the selection of equipment to pricing.
-A “finance solutions” deals with solar’s many financial complexities, including tax equity, customer finance, and project finance.
-“Customer services” covers everything CEC has learned about customer interactions.
“Buyers can choose which components they want,” Spencer said.
The Competition
“Utilities are all looking for a way to get involved in the community solar boom and software-as-a-service is a great idea for them,” said SunShare CEO David Amster-Olzewski. “We have been developing the same thing and are starting discussions with utility companies about our plans to roll out a similar solution.”
Like CEC’s CSP, SunShare’s solution is an evolution of the platform it built from its own experience. It plugs into any billing system, from those of large investor-owned companies to those of cooperatives and municipal utilities. It makes bill crediting “a seamless transaction between the utility and the utility customer.”
SunShare’s software also handles construction, management, and operations of utility programs. As the company broadens its footprint nationally to match CEC's, SunShae expects to be able to offer an SaaS product and consultative services “to help utilities choose the best business model to meet their objectives,” Amster-Olzewski said.
“An IOU might want to earn a profit for their shareholders whereas a cooperative or a muni might want a less expensive project to keep their members’ rates down,” he said.
Though SunShare has not branded or widely marketed its software, it is presently available and the developer is rolling it out with individual utilities, Amster-Olzewski said. “We call it the SunShare Experience.”
Both CEC’s CSP and the SunShare Experience are also available to private sector developers and companies interested in offering a branded solar product to employees. Energy Services Management (ESM) provider Tendril recently announced a more limited software solution for community shared solar developers.
“Whereas residential solar used to be an impenetrable market for utilities,Tendril explained, “it is now not only an energy source utilities can tap, but also an engaging service they can market and sell to a customer-base that has been underserved by rooftop solar providers."
The Tendril Community Solar solution is designed with three parts to streamline the customer-facing part of shared solar:
-multiple marketing tools can cut the costs of customer acquisition,
-methods of interaction can grow higher-quality, pre-qualified leads, and continuing customer engagement can keep references and recommendations flowing.
Cannibalizing their own businesses?
Making its “secret sauce” publicly available, even at the substantial set-up and monthly fees CEC will charge, could seem like “cannibalizing our own business,” Spencer said.
He had long seen it that way, but recently he came to a new realization.
“We have been busier than we can handle for five straight years, ever since we announced our first project to the public. Every year, the demand has outpaced our ability to keep up,” he said. “We have 150 employees and we are growing as quickly as we can but we still don’t have enough people.”
Because their customers are asking for it, "community shared solar went from being a nicety to being a necessity,” Spencer said. He finally decided the only thing he could do to foster growth is provide a scalable tool.
“It only takes a short amount of time to set up a utility whereas we might spend a year getting a utility’s project developed and subscribed,” he said. “If utilities have the tools and the know-how, community solar can be a great new business line for them.”
posted by Herman K. Trabish @ 8:33 AM
1 comments
Inside Hawaii's landmark regulatory proceeding to value distributed resources; Phase 1 of the tumultuous docket has brought only 'general disagreement' among stakeholders
Herman K. Trabish, July 21, 2015 (Utility Dive)
With more than 12% of its electric customers generating their own power from solar, Hawaii is the front lines of the struggle to value distributed generation properly for utilities and their customers.
As Utility Dive has reported, how the state's electric suppliers value the output of rooftop solar and other distributed energy resources will impact the financial health of the island's utilities, its transition to renewable resources, and how much customers pay in a state with the nation's highest electric rates.
To that end, Hawaii regulators opened a landmark regulatory proceeding in August of last year. It is aimed at devising a valuation scheme for distributed resources acceptable to utilities, solar installers, and consumer advocates. But if the second phase of the proceeding is anything like the first, those stakeholders are in for a rough ride.
The Phase 1 collaboration of stakeholders reached an impasse when solar advocates and the Hawaiian Electric Companies (HECO), the state’s dominant electricity provider, failed to find common ground on how to revise net energy metering (NEM), the rate at which customers with solar panels are renumerated for the electricity they send to the grid.
As a result, The Alliance for Solar Choice (TASC), the most outspoken of the solar advocates, called for a full adversarial process in which HECO would have to show evidence proving its positions and arguments in the rate case. In reply, HECO asked the commission to disqualify TASC from further participation in the proceedings.
With the battle lines drawn and the second phase about to begin, the commissioners have their work cut out for them.
HECO's solar conundrum
Each stakeholder filed a June 29 Final Statement of Position (FSOP) in the regulatory proceeding, laying out their positions for the next phase of rulemaking. HECO’s document begins with a review of the Hawaii solar industry’s unparalleled achievements and the utility’s efforts to keep pace.
“As of the end of 2014, over 51,000 DG systems have been installed, representing a total 390 MW of capacity and 12% of residential customers,” it reports.
After falling far behind the onslaught of interconnection applications in late 2013 and early 2014, HECO mounted a commission-driven effort and “conditionally approved 4,176 out of roughly 5,700 customers in the post October 2014 queue.”
In total, HECO handled more PV interconnections per customer than any utility in the country, and 20 times the national average. But, it adds, “the unprecedented DG growth has also created economic, technical, and equity issues that must be addressed.”
Solar's winning value proposition, supported by the high price of oil-fired electricity in Hawaii and the falling cost of panels, have turned NEM into a financial strain on all HECO’s customers, the FSOP explains. The result, it argues, is NEM customers not paying a fair share of the fixed grid maintenance costs and those costs are shifted to non-NEM customers.
In addition, the financial burden forces HECO to displace “more cost-effective, diverse, and grid-friendly renewable resources.”
In short, NEM “is no longer sustainable in its current form.” The Commission recognized this, HECO says, in its call for “a new model where the customer value proposition is predicated upon how distributed solar PV benefits both individual customers and the overall electric system.”
The utility’s FSOP proposes several remedies. Per the commission’s instruction, it provides Self-Supply and Grid-Supply options to DER owners.
The Self-Supply Option promises interconnection without a "lengthy" review period as long as the system has “certain modifications to address safety and reliability concerns.”
Its Grid-Supply Option compensates DER owners for electricity their systems sell to the grid at $0.180 per kWh which is a “cost effective rate for all customers, but which nevertheless does not significantly lengthen the payback period.” Over 15 years, the rate would save HECO’s non-DER owning customers “about $206 million,” the utility estimates.
When these options are in place, HECO says, the Commission should “declare the existing NEM program fully subscribed," effectively ending retail rate net metering in Hawaii.
Finally, it promises a DER 2.0 Transition Plan that will “set the framework to achieve a more sustainable distributed energy resource program.”
This plan includes an increase in the minimum monthly bill to $25, advanced smart inverter standards, a residential time-of-use (TOU) rate program, and new PV hosting capacity studies that allow proactive identification of distribution circuit capacity to cut the time needed for interconnection application evaluation.
The solar industry's filing
Solar and environmental advocates submitted a joint June 29 FSOP. The Hawaii Solar Energy Association (HSEA), the Hawaii PV Coalition, the Hawaii Renewable Energy Alliance (HREA), Life of the Land, SunPower, and TASC signed on.
They endorse the commission’s pursuit of "a flexible, efficient, fair, and cost-effective DER market structure" and recalled its efforts to expand and streamline interconnections and its intent with Phase 1 to “jumpstart” the transition to customer-based solutions for Hawaii solar.
They then note that the approximately “27% of the HECO Companies' renewable portfolio mix” in 2014 prevented the use of “millions of barrels of oil, curbed Hawai'i's greenhouse gas emissions, and reduced the over four billion dollars sent out-of-state each year.” They also remind the commission of NEM’s central role in driving that renewable energy growth.
Their recommendations strikingly echo those of HECO in broad terms, except in the case of rate structure. They too propose a minimum bill, TOU rates, a streamlined interconnection process, Self Supply and Grid Supply options, and a new NEM credit “to account for the State's uniquely high penetration levels.”
Finally, however, the Joint Parties vehemently object to the call by HECO and others to take “the drastic step of eliminating NEM immediately and replacing it” with “an arbitrary or severely low compensation rate.”
They insist NEM should be handled, as the commission originally planned, in a Phase 2 process that follows “proper studies of the cost and benefits of NEM” because “8 of 11 recent cost-benefit analyses conducted on NEM have found that the benefits NEM customers provide are worth more than the compensation NEM customers receive.”
Altering NEM without further evidence and analysis would be, they argue, a violation of “due process and administrative law principles.”
Among the questions that require definitive answers are whether HECO’s proposals could impose “significant taxation” on new solar customers, including loss of the federal tax credit, new and potentially discriminatory rate classes and charges, increased technical challenges to the grid, failure to grow DERS, or diminished third-party financing options for DER customers.
The call for evidence
On July 2, TASC filed a motion to initiate formal evidentiary hearings at the PUC on the solar issues. Though the group's spokesperson declined to talk to Utility Dive because of the swirling controversy, the filings make TASC's positions clear.
Evidentiary hearings are needed, it argues, “to establish a sufficient evidentiary record through discovery and the ability to respond on the record to the positions and evidence offered.”
TASC made what it describes as a "good faith effort" but failed to reach agreement with the HECO Companies and other parties in Phase 1 on what it calls "issues vital to the property and financial interests of TASC, its members, and their customers.”
The primary focus of disagreement was, by all available accounts, the net metering reimbursement rate.
Approved proceeding intervenors have “a right to a hearing to cross-examine witnesses, put on evidence, and respond to evidence submitted by other parties in order to assist the Commission in establishing a record upon which it can make a just and reasonable decision,” The TASC filing explains. That record was not established in Phase 1 and formal evidentiary hearings are the best remedy, the group argues.
The Hawaii Division of Consumer Advocacy called for the motion to be denied.
“The Commission was very clear in its intent to conduct an aggressive, expedient and urgent regulatory investigation for Phase 1,” the division, housed in the state's Department of Commerce, argues. TASC has presented no evidence it was denied the “opportunity to participate and establish the evidentiary record."
"An evidentiary hearing will only serve to further delay the Commission's timely resolution of the ‘high priority’ issues," the agency argued in its filing.
“The direction from the commission was that the parties should arrive at a settlement agreement. That didn’t happen. There was general disagreement,” explained Hawaii Consumer Advocate Jeffrey Ono, whose office filed the motion. The commission will now have to decide whether to accept or deny TASC’s motion, but its original orders and directions show it “understands the urgency to move on in the proceedings toward a sustainable solar industry.”
Hawaii’s Department of Business, Economic Development, and Tourism(DBEDT) echoed the consumer advocate. A “sufficient record has been developed,” DBEDT argues, and the motion “would delay the implementation of longer-term distributed energy resources market solutions.”
TASC’s partners in the FSOP – including HSEA, the Hawaii PV Coalition, HREA, technical expert Ron Hooson, Life of the Land, and SunPower – filed a joint “statement of no position” on TASC’s motion for an evidentiary hearing, as did environmental advocate Blue Planet Foundation.
Most of the intervening parties, including all the solar industry parties, said “no position” on the specific request for an evidentiary hearing, acknowledged HSEA Attorney Isaac Moriwake, "but we emphasized in our joint filing that decisions need to be based on data and due process,” he said.
The utility doesn't think TASC's motives are to truly get more information.
“This is clearly a delay tactic,” HECO Senior Vice President Jim Alberts told Utility Dive. “TASC had every opportunity to investigate during the 90 day process laid out by the PUC order … Further hearings would only delay that process.” HECO wants TASC out
On July 10, HECO asked the commission for an order removing TASC from the proceeding, or an order requiring TASC's compliance with commission direction not to “broaden the issues or to unduly delay.”
HECO accuses TASC of “litigating issues in the media versus through the collaborative process established by the Commission.” Its cites an April 14, 2015, article in the Honolulu Star-Advertiser in which, according to the utility, TASC questioned and misrepresented HECO’s handling of its interconnection queue.
Commission staff then directed proceeding stakeholders to "facilitate open, frank, collaborative, and productive discussion” and avoid involving the public. But, HECO argues, TASC demonstrated “bad faith conduct” with the issue of a May press release revealing details of HECO’s proceeding proposal and criticizing it.
The press release also supported the group KULOLO (Keep Our Utilities Locally Owned and Locally Operated), a group that advocates transforming HECO into a publicly-owned utility. HECO's filing argues that this “calls into question whether TASC really had any interest at all in engaging in a collaborative process."
Finally, HECO argues, TASC has consistently misrepresented its proposal to replace NEM as a type of feed-in tariff (FIT) that would subject Hawaii solar owners to “significant taxation” and threaten the loss of the federal tax credit.
The proposed NEM alternative is like the existing NEM credit, not an FIT, and holds no threat of creating tax problem or compromising access to the ITC, HECO says. With a FIT arrangement, all the output of a distributed system is sent to the grid and reimbursed, typically at an above-retail rate. NEM is a typically retail-rate credit provided to DER owners for the electricity their systems send to the grid after onsite consumption is met.
“Our proposal is structured to function in the same way as net energy metering (NEM) as an energy exchange,” Alberts explained. “If our proposal is taxable, then so is NEM.” In its press releases, TASC references tax opinions claiming the HECO tariff puts solar owners at risk of tax liabilities not incurred with NEM. Alberts said HECO rejects TASC’s “cherry-picked” expert tax opinions because they are about an FIT, which the utility's tariff is not.
“TASC'S repeated violations of both the letter and spirit of the commission's directives warrant removal from this proceeding,” the utility’s motion asserts.
TASC's “misinformation campaign” about HECO’s proposal “will undoubtedly confuse customers and may actually discourage potential solar customers from moving forward with solar,” Alberts believes.
“TASC’s conduct violates the standards expected of the parties involved in this critically important work,” HECO’s motion argues. “We needcollaborative, productive discussions among all players.”
The tax question
There are two strands to HECO’s complaints. One is about TASC’s conduct. The other is about TASC's insistence that the utility's proposed alternative to NEM would create tax liabilities for solar owners.
Marco Mangelsdorf, a Hawaii solar industry veteran and founder of both ProVision Solar and the Hawaii PV Coalition, defends HECO.
Of the three tax opinions TASC cited, Mangelsdorf told Utility Dive, “all clearly say that they are rendered on the basis of a feed-in-tariff. The HECO proposal is not a new FIT. It is an energy exchange, just like the current NEM program.”
One of the opinions (originally from the firm Skadden) was rendered on a 2013 Arizona question and “can’t possibly assess the risk of HECO’s proposal,” Mangelsdorf noted.
And, Mangelsdorf said, “there are serious, and more narrow, self-interests at play here.” His own company, other Hawaii solar installers, and companies represented by TASC have prospered as the result of "lucrative incentives” like retail rate NEM, he noted.
According to 2012 Hawaii Department of Taxation data Mangelsdorf was able to obtain, $164 million was claimed through the state’s 24.5% solar tax credit. By his reading of the Department’s figures, about half went to out-of-state investors, including those in companies TASC represents.
“To ignore the pecuniary interests of these parties who are speaking out so loudly, and supposedly with the motivation of doing what’s best for Hawaii residents, does a disservice to the honest and responsible debate we need to have over these subsidies,” he said.
HECO and the other intervenors, of course, have major financial interest in the proceeding as well, and the solar advocates say it's a bit extreme to attempt to get TASC out of the proceeding.
The utility’s call to have TASC dismissed is “a bit over the top,” Moriwake said. “They are trying to police people’s public speech. This is bad form and bad precedent.”
HECO’s complaints, replies TASC in its July 16 response, “relate to events taking place outside of this proceeding that have no remedy before the Commission."
"The Commission is neither the arbiter of First Amendment claims nor the proper authority to resolve specious accusations regarding the conduct of licensed attorneys,” the group wrote.
TASC did not violate “any law or rule or order of the Commission,” it insists. “No basis in the record or the law exists for the Commission to take the extreme remedy of removing a party that has substantial and direct interests in the outcome of this proceeding.”
TASC acknowledges HECO’s concerns about the tax-related questions. But it should not be removed because it disagrees with HECO.
“The tax issues underlying the motion are a critical element of a public debate impacting Hawaii residents,” TASC insists. “TASC shoulders an important responsibility to increase public awareness about the issues.”
There are no grounds for such an “extreme remedy” that would deny TASC “due process” simply because it engaged in its “fundamental right to engage in public advocacy,” the filing concludes.
Moriwake offered more context. HECO’s reaction is “overheated,” he said. The commission was clear it wanted the Phase 1 discussions to take place in a safe, collaborative, and confidential context. But once the FSOPs were filed, the stakeholders were accountable for their positions.
“This is a public matter of great public interest and the utility is misguided if it thinks that it doesn’t have to answer for potentially damaging positions they are taking towards solar customers and the market.” Moriwake said. “After the confidential discussions broke down and the parties went to litigation, there was no expectation or requirement that those publicly litigated matters couldn’t be discussed.”
As to the proposal TASC revealed in its May press release, he added, it “was not materially different than what HECO had already made public in their August 2014 plans as well as their January 2015 motion to end NEM.”
What's next in the proceeding
At the precipice of a new phase of rulemaking, it is not clear what the PUC will do, or when it will do it.
Most participants said it's unlikely the regulators would approve TASC's request for an extended Phase 1 proceeding with an evidentiary hearing because of the urgency in dealing with DERs.
It could embrace either of the final position statements or neither as the basis for an extended Phase 2 proceeding. And that might or might not include TASC.
“The PUC could approve the Joint Parties FSOP, based on actual data and analysis, and reject HECO’s proposals,” Moriwake said.
There are also things the stakeholders can agree on, he added. The hosting capacity circuit analyses may be the next evolutionary step in interconnection. But if HECO’s filing prevails “it will slam the door on solar.”
On the tax liability question, the salient point is that the Joint Parties included expert analysis in its FSOP and “there is at least a substantial risk of tax liability” in HECO’s proposal that the utility has not provided evidence to defend, Moriwake believes.
“If HECO is so certain there is no tax issue, they should indemnify customers from liability,” he suggested.
If the PUC approves an evidentiary hearing, TASC could require HECO to convince the commission there is no tax liability.
The PUC will consider all of the input and issue a decision and the timing of that decision is at the discretion of the commission, Alberts said. “The next step will be to enter into the second phase to work on longer term issues.”
“I have no doubt about the commissioners’ ability to do their job, Moriwake said. “The commission and all the parties, including the utility, did their best in Phase 1 to take a collaborative approach.”
But in filing the motion to dismiss TASC, he said, “it appears HECO feels the gloves are off and there is nobody to collaborate with. Maybe collaboration is off the table. But filing the motion is pouring gas on the fire.”
The commission needs to help the stakeholders “step back and take a deep breath,” he suggested. “We need to agree on the things we can agree on and agree to disagree on the hard things and leave it to the commission to decide those.”
“The PUC will ultimately determine the process and we will respect that decision,” Alberts said. “We believe the collaborative process the PUC envisioned can be a very effective process to get solutions to customers more quickly."
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Regional Transmission Organizations: Recommendations for the West
Introduction
An historic reorganization of the western electricity delivery system is underway. The sources of our electricity are changing rapidly, driven by shifting economics that include plunging natural gas prices, new state and federal policy goals, and the rise of renewable energy resources. Renewable generation sources have been shown capable of reliably powering increasing shares of our economy. And as large amounts of renewable power are added to the western grid, major changes in how it operates will be needed.
There are many benefits to the potential expansion of the California Independent System Operator (CAISO) across much of the western grid (the Western Interconnection, which serves parts of Montana, Nebraska, New Mexico, South Dakota, Texas, Wyoming, and Mexico; all of Arizona, California, Colorado, Idaho, Nevada, Oregon, Utah, Washington; and the Canadian provinces of British Columbia and Alberta). These benefits include cost savings for customers across the region, the avoidance of building redundant transmission lines and expensive power plants, and the reliable and cost-effective integration of renewable energy resources. Based on experience gained in the rest of the country’s organized grid regions, this Issue Brief examines issues related to renewable power integration and conventional power plant retirements as they apply to expanding CAISO’s footprint.
Regional transmission organizations (RTOs) or Independent System Operators (ISOs)—the terms are interchangeable— run large regional portions of the national electrical system across most of the country. They include the Midcontinent Independent System Operator (MISO) and PJM, the grid operator for the nation’s largest electricity market stretching from the mid-Atlantic states to the Midwest. Studies by these groups have shown that large levels of renewable energy can already be safely and reliably integrated into generation supplies without having to resort to large amounts of gas-fired generation to balance out variability due to fluctuations in the wind and sun.1 A large system footprint, combined with closely coordinated and consolidated grid operations, can avoid the need for significant fossil-fueled generation.2
This kind of operational control and coordination is a common trait in the RTOs/ISOs (including CAISO) that run most of the nation’s electrical grid. Drawing renewable power from across large areas allows grid operators to blend the variability of geographically separated wind farms because the wind in one part of the region is often blowing when it is calm in another, allowing generation in the windy area to replace the energy lost where it calm. Similarly for solar energy, when it is cloudy in one area, it is likely to be sunny in another.
As the 2014 PJM Renewable Integration Study concluded:
PJM has long held that ISOs and RTOs are better able to integrate variable energy resources because of their organized markets and regional infrastructure planning processes, but the study found that PJM’s large geographic footprint also provides significant benefit for integrating wind and solar generation because it greatly reduces the magnitude of variability-related challenges.3
Economies of scale, technology improvements, and national policy goals have driven renewable energy penetration to new highs worldwide. More than a billion dollars per day was invested globally in renewable energy sources in 2015 ($367 billion total).4 In the United States, renewable energy growth continues its relentless upward trajectory, with solar additions to the electricity system forecast to more than double in 2016 over the previous year.5 As renewable energy’s star is rising, the coal industry’s market position is deteriorating at an accelerating rate, due in large part to unfavorable market conditions.
Some would resist making the changes needed to facilitate the large additions of renewable power necessary to meet our national climate goals because of the fear that some coal plants will be perpetuated in an energy market. They might point to features such as capacity markets (discussed later) in the Eastern Interconnection as proof that markets allow coal plants to stay alive, even if they are infrequently run—some as little as a few hours a year. However, since 2009, PJM (which covers 13 mid-Atlantic states and the District of Columbia) has retired 21,336 megawatts (MW) of coal unit capacity. In the same period, MISO (which covers 15 states in the Midwest and Great Plains and two Canadian provinces) retired 5,713 MW of coal generation. All of these retirements took place without material, unresolvable reliability issues and relatively few out-of-market payment arrangements to keep units running for reliability purposes. In any case, these features of existing markets needn’t be replicated for an expanded western electricity market.
As western coal plants continue to be retired, the use of the extraordinary renewable resources in the West, along with distributed generation like rooftop solar, energy efficiency, and demand response programs, will ensure the system has adequate supplies to meet virtually every load condition and even enhance system reliability. It is time to look at ways to expedite the renewable energy transition to meet the deep penetrations of clean power we will need to meet an 80 percent reduction in greenhouse gas emissions by 2050, as specified by California’s groundbreaking Global Warming Solutions Act, AB 32. This transition will require a major transformation in how the electricity grid is organized, operated, and planned. In the western United States, this means eliminating as much of the operational fragmentation as possible from the system (see map) and placing coordinated operations and planning into fewer hands.
The key to deep penetration of renewable power into the grid, myriad studies tell us, is operating the system over a large geographic footprint, using both policy and market tools to define the types of power plants used and balancing power and demand over seasons, days, hours, and even minutes.6,7
Expanding the operational and market functions of the current CAISO footprint across more of the West, and establishing a governance framework that allows CAISO to act as a regional system operator, can provide many of the tools we need to transition to renewable energy and reliably and affordably meet the climate challenge. We can take the best of the RTO experience from around the country and avoid features that are not well-suited to our uniquely western needs…
How Regional Energy Markets Work
Existing RTOs operate different types of centralized energy markets within their regions. All of the RTOs and ISOs have day-ahead and real-time wholesale energy markets. As with other commodities, utilities buy this electricity in bulk amounts and then sell it to consumers as a retail product. Some of the RTOs and ISOs also have an additional market tool, called a forward capacity market (discussed later), along with various ancillary service markets from which they obtain energy and operational capabilities from some strategically located power plants. Ancillary services are tools that keep the grid stable and operating smoothly by ensuring that the system is energized properly or operating within the correct specifications. Ancillary services include things like frequency response and operating reserves.
Organized energy markets function similarly across RTO regions. In the day-ahead market, the RTO or ISO first works with the utilities in its region to predict customer demand for each hour of the following day. Utilities and other power plant owners offer bids for power in the dayahead market to satisfy demand on an hourly basis. The RTO then selects the resources to meet that demand the following day. It selects the lowest-cost resource first, then the next lowest, and so on until it has chosen enough generation to meet predicted demand. Because the RTO selects the lowest-cost resources available to meet demand (load), renewable generation—which has no fuel cost—is usually dispatched first. The price paid to all generators providing power within a given hour of the day is the price offered to meet the last megawatt of demand from the highest-cost power plant that clears the market. This price is called the clearing price. The units that clear are obligated to provide energy during the hours for which they cleared the following day.
In reality, customer demand at any given hour will not be exactly what was predicted. As a result, RTOs operate real-time markets during each operating day to account for the differences between predicted and actual demand, in 5- to 15-minute intervals. Resources bid into the realtime markets (or spot markets) are cleared in a lowest-tohighest-cost fashion, just like the day-ahead market, and are dispatched in real time. Because of renewable energy’s free fuel, the more renewable energy that is available, the fewer hours of higher-cost fossil generation will be dispatched to meet a system’s load.
As the electrical system transforms by converting from conventional generation to renewable energy, conventional power plants become increasingly uneconomical and less competitive with cleaner resources. As carbon costs are added (as with AB 32 provisions in California, or as expected with the U.S. Environmental Protection Agency’s Clean Power Plan to limit power plant emissions), this shift occurs even faster. One strategy for reducing carbon dioxide pollution is to add an additional cost to electricity from conventional plants based on how much pollution they release to the atmosphere. This cost, often called a carbon adder, makes power from these generators more expensive and less likely to be chosen in the day-ahead or real-time market…
Conclusions
-A western RTO or Regional System Operator (RSO) would greatly facilitate efforts to transform the electricity sector in the region to a low-carbon energy delivery system.
-An RSO can help all western states more efficiently meet load and more cost effectively help them comply with federal and state pollution and energy procurement mandates and goals by providing access to lower-cost renewable power from throughout the region.
-All RSOs (including CAISO) have been able to reliably integrate increasing amounts of renewable energy into their systems.
-A balkanized, multi-balancing-area authority system results in an inefficient use of the grid and unnecessary investment in transmission and generation infrastructure, and it makes renewable integration more difficult.
-Geographically large electric system footprints aid renewable integration, aggregate renewable energy’s variability, and reduce the need for flexibility reserves, saving money and enhancing reliability.
-RTOs, because they control the dispatch of all generation in their footprint, can better take advantage of existing gas generation—avoiding the need for new fossilfueled power plants—to integrate high penetrations of renewable energy.
-Energy markets have led to a large number of conventional plant retirements in the Eastern Interconnection.
-Capacity markets have been used to guarantee reliability in eastern RTOs with mixed results. Greater participation has been provided for demand response products in capacity markets, but some uneconomical plants have been preserved by capacity payments when they are no longer competitive in the wholesale market. These include uneconomical coal plants, though they may be infrequently used.
-Regional markets intrinsically favor renewable electricity generators that have zero fuel costs and very low marginal costs.
-A capacity market is not necessary in the Western Interconnection, which is already long on natural gas resources and rich in diverse renewables that often operate during different hours.
-The consolidated operation of RTOs has been shown to reduce and better manage renewable energy curtailment.
-RTO consolidated planning can lead to better identification of infrastructure needs, avoided overinvestment in infrastructure, better use of the existing system, and better justification of new infrastructure when it is needed.
Recommendations
-Western state legislators and regulators should approve the consolidation of the various transmission and electricity balancing areas in the western grid into an RTO/RSO to better manage and more efficiently integrate increasing amounts of renewable power.
-Authorities should approve expanding the existing successful ISO platform from CAISO to across the West. This will save resources and time and facilitate a more rapid system transformation. It builds on the already expanded ISO regional real-time market.
-A new RSO should avoid the establishment of a capacity market, which can perpetuate uneconomical generation. It is not needed in the Western Interconnection to meet reliability. Resource adequacy will continue to be assured through competitive utility procurement under the supervision of state regulators and local utility boards even as many older power plants are retired.
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Transforming to Deliver a More Affordable Clean Energy Future for Hawai‘i; HECO’s 2016 Power Supply Improvement Plan (Part 2)
April 2016 (Hawaiian Electric Companies)
Eight Observations and Concerns
The Commission noted eight Observations and Concerns [in a plan submitted earlier this year that was rejected], each of which encompasses a wide swath of areas under analysis in developing our 2016 updated PSIP. None of these eight Observations and Concerns can be considered in isolation. As such, we have integrated them throughout our planning, modeling, analyses, and decision-making.
#1. CUSTOMER RATE AND BILL IMPACTS
Chapter 3 fully describes the overall planning process, plan development, and iterative optimization process from the 1st iteration, which was included in the PSIP Interim Status Report filed February 16, 2016, through the development of the Final Plans and selection of the Preferred Plans. Financial analysis and “all-in” results are presented in Chapter 4. The Net Present Value of cumulative revenue requirements, under both 2015 EIA Annual Energy Outlook Reference and February 2016 EIA Short Term Energy Outlook fuel price forecasts, have been calculated for the best evaluated resource plan for each theme. Residential customer rates and monthly bill impacts, in nominal and real (2016) $/kWh, are provided for both fuel price forecasts. It should be noted that all finalist and Preferred Plans meet or exceed all statutory RPS requirements.
To maximize the accuracy of our analyses, we updated all input assumptions, including resource costs, fuel costs, and resource availability assumptions. We also shared all relevant assumptions with the Parties to solicit feedback. In addition, we engaged NREL to independently assess resource cost assumptions and provide an analysis of wind and PV availability. NREL’s reports can be found in Appendix F.
Theme 2, which uses the LNG fuel price forecasts included in Appendix J, produced significant cost savings and has the largest beneficial impact to customer bills. To address the uncertainty in future fuel prices, sensitivity analyses were completed for both the 2015 EIA Annual Energy Outlook Reference fuel price forecast and February 2016 EIA Short Term Energy Outlook fuel price forecast for each case. While there is no way to accurately predict future fuel prices, results from Ascend Analytics’ stochastic modeling of all-in delivered LNG and oil indicate that oil prices are characterized by “higher levels of volatility and slower rates of mean reversion as compared to natural gas. Higher volatility in oil prices translates to more uncertainty in future oil prices and a wider 90- percent confidence band in comparison to LNG.” Figure 2-1 depicts these results.
To address the capital expenditure constraints, revenue requirement projections which included capital expenditure projections for power supply, smart grid, ERP, and all other utility capital expenditures (referred to as “balance of utility business capital expenditures”) were considered. As described in detail in Appendix I, the balance of utility business capital expenditures have been calculated using a top down approach for the high fuel price scenario. Chapter 4 summarizes the capital expenditures by category for each Theme.
#2. TECHNICAL COSTS AND RESOURCE AVAILABILITY
Utility-scale resources are a key decision variable in the Decision Framework, which assesses the cost-effectiveness of various resource types.
We started by updating all resource costs, including capital costs, interconnection costs, fuel costs, O&M costs, and resource availability assumptions. Virtually all deployable technologies were considered. Though found not to be cost-effective at this time, new concepts such as accelerating alternative fuel vehicle adoptions (electric vehicles and hydrogen vehicles) and flexible electrification where electric vehicles could be used for load balancing were evaluated by E3. We retained NREL to independently assess our new resource cost assumptions and made appropriate adjustments to our assumptions as a result. We also commissioned NREL to develop independent assessments of the utility– scale solar PV and wind levels that could be developed on each island based on topographic, land-use restrictions, proximity to urban areas, and renewable energy production potentials in specific locations. NREL’s reports can be found in Appendix F.
Although adjustments were made to O‘ahu for utility scale PV and onshore wind to be consistent with NREL’s resource potential estimates, cases including high levels of PV were developed and analyzed. We compared case results of varying levels of energy storage and biofuels, and developed an optimized-mix of these dispatchable resources. In addition, we included community-based renewable energy (CBRE), DER and DR resources, utility scale PV, geothermal, onshore and offshore wind, biomass, biofuels, pumped storage hydro, and battery energy storage systems. (After this filing, we will complete our analysis of an inter-island transmission system, including estimated costs and benefits relative to offshore renewable energy serving O‘ahu and benefits of combined grid operations.)
Chapter 3 fully describes the planning process and Appendix K provides all of the cases considered. Both high DG-PV and market DG-PV cases were evaluated. Integration requirements for DG-PV are discussed in detail in Appendix N. Identification and consideration of integration costs for DG-PV was included in all of the analyses. In addition, accelerating renewables (Theme 1) which achieves 100% RE on the neighbor islands (including Lana‘i and Moloka‘i) by 2030 were developed and optimized for cost.
As noted in Chapter 3 and Appendix C, the overarching objective of the planning process was to optimize and find the lowest cost mix of resources and plan to achieve the statutory RPS requirements. The resulting near-term actions to acquire cost-effective RE projects are described in Chapter 8.
#3. DISTRIBUTED ENERGY RESOURCES INTEGRATION
DER is one of three key resource-types that were optimized as part of the Decision Framework, and we evaluated the full spectrum of DER. Energy efficiency attainment and electric vehicle adoption were forecast and incorporated in system net load for all PSIP cases. Demand response, distributed storage, and DG-PV were optimized through iterative cycles to achieve lowest system cost while enabling customers to provide costeffective and reliable grid services. Self-consumption economics were based on retail rates; grid export economics were based on the value the DER provides the system (utility-scale PV LCOE for DG-PV, value of storage to the system for distributed storage, value to the system for DR).
Multiple options were developed to integrate DG-PV on over-hosting capacity circuits and the lowest cost integration option was selected for explicit consideration in the economics for those DG-PV systems forecast to be installed on an over-hosting capacity circuit. The DG-PV integration strategies and costs are more fully described in Appendix N.
We determined high-value system-level use cases for DER in 2016 - 2020 as follows. Robust DG-PV adoption compensated at utility-scale PV LCOE reduces the need to procure utility-scale PV and helps meet near-term RPS targets cost-effectively. Storage was analyzed as a decision variable in the various PSIP cases, and was found to be cost effective for selected use cases in DR programs.
We sought cost effective solutions by weighing the costs and benefits of (full or partial) inverter retrofit against alternative ones when addressing either circuit or system-level interconnection barriers. For instance, we are currently considering the cost and benefits of legacy inverters without ride-through capabilities in our contingency battery analysis. We considered retrofit of inverters to ones that have reactive power capabilities for voltage mitigation in the DG-PV integration analysis (see, Appendix N).
A cornerstone of the DR program portfolio is the aggregation of DR resources. All of the proposed DR services utilize various DER technologies to achieve this aggregation philosophy. Furthermore, the demand response management system that will be used to deliver the DR services through the intelligent management and optimization of groups of DERs has been specified to allow for the attribution, selection and dispatch of these resources across various zones. These zones map to the physical topography of the various islands’ systems and span from the system level at the highest level down to the individual circuit at the lowest level. As such, the current architecture and system design of the DR portfolio implementation allows for targeted deployment of DERs, which is suitable and appropriate as a tool for helping to address distribution or transmission level constraints such as those being considered by non-transmission alternatives in South Maui.
We varied RPS attainment in the analysis cases and, through iterative cycles, optimized DER amounts across islands and across cases to determine the role and contribution of DER in high-RPS attainment scenarios. In addition to the DG-PV adoption forecast optimized for the system, we analyzed a "high DG-PV" forecast to further characterize the role and contribution of DER in aggressive RPS attainment scenarios. DER plays a significant role in the preferred plans. Further work on how to achieve the sustainable DER adoption as envisioned by the preferred plans will be covered in the DER 2.0 proceedings.
#4. FOSSIL-FUEL PLANT DISPATCH AND RETIREMENTS
Chapter 3 outlines the breadth of cases considered in the three iterations completed, around three Themes: Theme 1–Accelerate Renewables, Theme 2–Renewables With LNG, and Theme 3–Renewables Without LNG. Cases considered various mixes and amounts of resources. The multiple cases were specifically designed to iterate towards a low-cost objective, and address risks associated with changes in fuel price by analyzing both LNG and oil, and analyzing various fuel price forecasts. We refined those cases to incorporate results from preceding runs of DER, DR, and utility-scale resources iterations to determine low cost potential with minimized risks, and analyzed grid modernization to characterize the tradeoffs and risks of modernizing our generating fleet versus other resource options. We identified potential dates for displacement of fossil generation, then updated our Fossil Generation Retirement Plans. Additional details for the Fossil Generation Retirement Plan can be found in Chapter 8 and the Component Plans included in Appendix M.
Theme 2 included LNG as a transitional fuel on O‘ahu, Maui, and Hawai‘i Island and modernization of the generation fleet on O‘ahu with efficient, flexible replacement generation selected to support the growing renewable fleet on O‘ahu. Additional details of LNG as a transitional fuel are described below. For all cases, both high and low fuel price forecasts were evaluated to understand the respective cost impact. The analyses suggest that the most significant savings can be achieved with LNG and modernization of the generation fleet with market DG-PV. Details of the Preferred Plan are provided in Chapters, 5, 6, and 7, and the financial results are provided in Chapter 4. It should be noted that all cases comply with statutory RPS requirements.
As part of our analysis, we reviewed and clarified our environmental compliance strategies, and updated our Environmental Compliance Plan and Key Generator Utilization Plan. Finally, we updated our Generation Commitment and Economic Dispatch Review. All of these plans are included in Appendix M, Component Plans. LNG as a Transitional Fuel
We have highlighted the need for modernized and flexible generation resources in order to minimize costs, reduce emissions and facilitate the increased integration of variable renewable resources. Even with these new resources in place, the Companies’ current fuel source for its dispatchable generation during the transition period to a 100% RE will be petroleum-based fuels.
As a result, customers will be exposed to a petroleum-based fuel which is: ■ Forecasted to cost more than LNG. ■ Significantly more volatile in price than LNG. ■ Subject to increasing restrictions under tightening federal environmental standards.
With LNG as a transition fuel, the Companies see an opportunity to lower the cost to customers, reduce pricing volatility, and accelerate the reduction in air emissions. An LNG plan has been designed specifically as a transition solution for Hawai‘i that seeks to limit the amount of investment in permanent island infrastructure. Further, the Companies’ plan contemplates that the LNG seller will have the ability to remarket excess LNG, which will reduce the risk for potential variability in the demand for LNG as the integration of renewable resources increases. Hawaiian Electric does not view LNG as substituting for, or competing with, new renewable resources on the islands. Rather LNG represents a complementary solution which can help achieve the Companies’ goals of keeping costs to the customers as low as possible while mitigating impacts to the environment and flexibility integrating intermittent renewable resources. LNG represents a good value proposition to customers under a wide range of potential renewable penetration scenarios, especially when combined with the flexible, efficient, modernized generation described in the previous section.
Overview of the LNG Delivery System: In initially evaluating an LNG delivery solution for Hawai‘i, the Companies looked at (1) land based LNG import terminals and (2) Floating Storage and Regasification Units (FSRU), both of which entailed installation of permanent infrastructure on and offshore, new gas pipelines, and long permitting processes. Therefore, the Companies opted to issue a request for proposal (RFP) for a containerized LNG solution to land LNG in Hawai‘i and distribute it to its generation fleet across the State. This solution would use International Standards Organization (ISO) containers, metal vessels that can be loaded and transported on a conventional truck, to transport LNG locally and, maximize flexibility and reduce requirements for dedicated land based infrastructure.
A possible LNG supply chain would consist of the following components: ■ Natural gas sourced from some of the most prolific gas reserves located in Northeast British Columbia. The gas would be transported from the gas reserves to Fortis BC’s Tilbury liquefaction plant on the Fraser River by pipeline where it would be liquefied. ■ The LNG would be loaded onboard ships for transport to Hawai‘i. Upon arrival in Hawai‘i, the LNG would be delivered in ISO containers to points of use on O‘ahu, Maui, and Hawai‘i Island. ■ Multiple ships, owned and operated by the seller, would be employed to ensure a steady rate of LNG delivery to the various generating stations.
The containerized supply chain was selected as the option with the greatest congruence with the following evaluation criteria set forth by the Companies.
Flexibility with Minimal Permanent Infrastructure: To be consistent with achieving the RPS goals, the Companies required any fuel supply to have flexibility to accommodate a dynamic energy environment and generation from renewable resources. The fuel supply system should have minimal permanent infrastructure that could limit flexibility and increase the risk of stranded assets.
Neighbor Island Coverage: The Companies required a cost-effective solution that could supply fuel to Maui and Hawai‘i Island just as easily as to O‘ahu without making substantial modifications to the overall supply chain.
Minimal Permitting: To expedite adoption of cheaper natural gas in the fuel portfolio, the Companies required non-permanent infrastructure for the LNG supply system to avoid extensive and time-consuming permitting processes associated with developing an LNG terminal.
Security of Supply: To mitigate geo-political risk and ensure continuity of supply, the Companies sought a fuel supply from a North America as opposed to gas sourced from politically sensitive global locations.
Lower Price Volatility to Customers-Gas vs. Oil Indexed Pricing: Globally, LNG is typically priced off a formula which is indexed to oil prices. To reduce dependence on oil-linked, fuel pricing (current fuel portfolio) and minimize commodity pricing volatility, the Companies required LNG to be indexed off of North American natural gas prices.
Ability to Serve Other Customers in Hawai‘i: The Companies wanted the LNG seller to have the ability to sell excess volumes to third party off-takers and/or for the Companies to take additional spot volumes if available.
Unit Conversions Under a merged scenario between the Hawaiian Electric Companies and NextEra Energy, the Companies intend to enter into an agreement to acquire approximately 800,000 metric tons of LNG annually from the Fortis LNG facility in Vancouver, BC. Deliveries could start in 2021 and coincide with the commencement of commercial operations of modernized combined cycle units at Kahe. In addition to the modernized units, the Companies would convert five of their existing generation units (six including HEP if its purchase by the Companies is approved by the Commission) to allow them to use LNG in addition to petroleum-based fuels. This involves installation of new equipment to receive, store and regasify the LNG, and conversion of the existing generating units to allow for gas utilization (with total estimated cost of the conversions at approximately $340 million). Although not yet negotiated, it is assumed that the two combustion turbines at the Kalaeloa Partners LP Generating Station would also be modified to use LNG. After the completion of the modernization and conversions, the Companies would have approximately 1,100 MW of generation capacity capable of using LNG-based fuel during the transition period to 100% RPS (as outlined in Table 2-1).
#5. SYSTEM SECURITY REQUIREMENTS
Selected resource cases from each of the three Themes for each island grid were screened for system security with a focus on loss of generator and electrical transmission fault disturbances. These selected resource plans formed the basis for performing a limited system security analyses that defined in a technology neutral manner the fast frequency response (FFR) and primary frequency response (PFR) requirements for selected years of a plan. The results of the security analysis are presented in Appendix O.
Since filing our 2014 PSIPs, we have updated and revised our system security requirements and focused this analysis on single contingency loss of generation events to determine acceptable under frequency load shedding (UFLS)14 capacities. Loss of generation contingencies have a greater impact on resource plans because it dictates online reserve requirements which in turn, establish FFR and PFR requirements. A full system security analysis that includes voltage stability, rotor angle stability and fault current protection coordination on for all islands will be performed for the preferred plans.
For O‘ahu, HI-TPL-001 was revised to allow no UFLS for single generator contingency events (previous criteria allowed 12% customer loss) while Maui and Hawai‘i Island allow 15% loss of system load (previous criteria allowed 15% customer loss). The Moloka‘i and Lana‘i systems were removed from HI-TPL-001 since these systems are unique island distribution systems that do not qualify as transmission systems. Further revisions to HI-TPL-001 are required for multiple contingency events, both loss of generation and/or loss of transmission elements.
The more stringent HI-TPL-001 criteria for O‘ahu is designed to minimize the risk of deep load shed events, and potential island-wide blackouts with an appropriately sized FFR resource such as a BESS which become more likely in the future with even more distributed PV. Under high levels of distributed PV penetration, the residential load net of PV is reduced so UFLS schemes are less effective, compromising system security. UFLS is designed to shed low impact loads and avoid critical load like hospitals, emergency responders, military bases, schools, etc. The proliferation of distributed PV is primarily on residential distribution circuits so the daytime UFLS capacities continue to degrade and it is becoming more difficult to find sufficient load to shed during a single contingency event. Additionally, the more stringent criterion support the use of distributed resources to supply fast frequency response. Load shedding of the distribution system, as allowed under the previous criteria, would be counterproductive since it would disconnect demand response resources from the system.
The limited system security analysis for Hawai‘i Island was expanded to simulate the impacts of transmission faults that cause loss of generation contingency events for selected resource plans. Hawai‘i Island's transmission infrastructure covers a very large territory that increases its exposure to electrical faults that can cause large capacities of DG-PV to disconnect from the system. Additional analyses were performed to determine FFR and PFR requirements to ensure system security for Hawai‘i Island and should be indicative findings when these analyses are conducted for the preferred plan.
Fundamentally, distributed generation (primarily PV) poses one of the biggest challenges to system security because it imposes conflicting requirements on the electrical system: 1) the reduction of system load displaces synchronous generators and 2) distributed resources increases regulating and frequency response reserve requirements that are traditionally provided by synchronous generators.
More specifically, transformation of the electrical system must address the following system security issues: ■ DG-PV displaces synchronous generators that provide essential grid services like inertia, regulating reserves, and system fault current. ■ DG-PV reduces the capacity of the system’s under frequency load shed scheme (UFLS). ■ Legacy DG-PV and their less flexible frequency ride through ability increases the magnitude of a loss of generation or fault contingency. ■ DG-PV is currently not controllable by and is invisible to the system operator.
The process of identifying needs and designing solutions follows a several-step process that we believe addresses the Commission’s concerns regarding the prior PSIP filing. (Note that this process was outlined as six steps in the Companies’ February 2016 filing. The revised process is equivalent, but reorganized to complement the rest of the PSIP more clearly.) The five steps are: 1. Establish operational reliability criteria. 2. Define technology-neutral ancillary services for meeting reliability criteria. 3. Determine the amount of ancillary services needed to support the resource plan. 4. Find the lowest reasonable cost solution, considering all types of qualified resources. 5. Identify flexible planning and future analyses to optimize over time.
The amounts of each type of ancillary service needed to meet system security vary by island, resource plan, and time period. That is because Frequency Response needs are driven by the size of the largest contingency event, which is generally the loss of the largest unit online at the time (combined with potential sympathetic loss of legacy DG-PV). Regulation needs are driven by the variability of net load (that is, load minus variable generation output), which depends especially on the amount of PV and wind, and Replacement Reserve needs are driven by the amounts of Frequency Response and Regulation needed after an event.
The Companies defined fast frequency response and primary frequency response requirements in technology-neutral terms so any qualified resource can meet them, whether traditional generation, advanced features of inverter-interfaced generation and storage, or demand response. Our objective is to identify the lowest reasonable cost combination that ensures system security for a given resource plan and in subsequent iterations, let the market and specific resource applications determine available resources.
To do so, we break the analysis into three steps: 1. Construct an initial pre-DR solution that meets system security needs; 2. Substitute DR to the full extent it is cost-effective, producing a revised resource strategy; 3. Consider whether the solution would affect system conditions (especially unit commitment and dispatch, affecting inertia and the amount of Primary Frequency Reserves available) to warrant another iteration of analysis.
There was not sufficient time to complete these three steps for the preferred plans. These steps will be done in conjunction with development of the Demand Response Programs.
#6. ANCILLARY SERVICES
As part of this filing, the Companies’ analyses began with the establishment of operational reliability criteria and the refinement of grid service definitions sufficient to meet these reliability criteria. This refinement of ancillary services was grounded in the definitions of grid services found in the Supplemental Report filed under Docket No. 2007-0341, filed November 30, 2015.
In particular, Fast Frequency Response (FFR) was refined into several sub-categories of FFR, including: Instantaneous Inertia (II), Primary Frequency Reserves (PFR), Fast Frequency Reserves 1 Up (FFR1Up) and 2 Up (FFR2Up), and Fast Frequency Reserves Down (FFRDown). Further, Supplemental Reserves was recast to Replacement Reserves (RR) and Regulating Reserves was refined to Regulation Reserves Up (RegUp) and Regulating Reserves Down (RegDown). The Companies then revised these ancillary services needs for the O‘ahu cases.
These revised ancillary service needs for O‘ahu were coupled with the existing needs defined for the other island systems and a set of resources that are capable of costeffectively meeting the ancillary service needs were identified. Included in this resource pool was utility-scale, centralized energy storage resource options as well as a DR portfolio that included the use of distributed, behind-the-meter storage options. As part of the DR optimization effort, the Companies developed respective optimal and most cost-effective implementation of the combination of these resources. The final optimized potential of distributed storage will be iterated and refined prior to filing the Final DR Program Portfolio application.
Consistent with the previous methodology applied during the development of the Interim DR Program Portfolio application (Docket No. 2015-0412), the Companies assessed the quantities of these service needs over a 30-year horizon and developed the value of these services by virtue of the costs associated with delivering them. With these values defined, the Companies were then positioned to assess substitution opportunities for delivering these services via the most cost-effective means possible.
The DR portfolio, utilizing a growing population of DERs, was considered as a cost effective substitution option for delivering these ancillary services. The Companies refined the DR portfolio based on previous feedback in an attempt to find the lowest reasonable cost solution considering all types of qualified resources for all islands. The Companies then identified flexible planning and future analyses to optimize the DR portfolio over time. This process is not complete, but will continue until the Final DR Program Portfolio application is filed in mid-2016. Finally, the Companies updated our Must-Run Generation Reduction Plans and Generation Flexibility Plans to include these ancillary service refinements.
#7. INTER-ISLAND TRANSMISSION
Our PSIP analyses show that, for O‘ahu to achieve 100% renewable energy in 2045, significantly greater off–island renewable resources will be required (if found to be more cost effective than biofuels). Analysis performed in this updated PSIP has shown that O‘ahu would require more offshore capacity than was included in our 2014 PSIP assumptions. Because of this, we plan to further analyze an array of inter-island transmission options after April 1, 2016. A plan for addressing the interisland transmission analysis is discussed in Chapter 9: Next Steps. In conjunction with the analysis, we also plan to further investigate offshore wind.
#8. IMPLEMENTATION RISKS AND CONTINGENCIES
Our Decision Framework contains nine risks and uncertainties that we used as part of our assessment to develop our 2016 updated PSIP. The risks identified in the Decision Framework were used as parameters in the selection of representative resource plans for each Theme on each island and ultimately to select each island’s Preferred Plan.
Chapter 3 describes the multiple initial cases, which were specifically designed to iterate toward a low-cost objective. The impact of accelerating the implementation of renewable energy resources, LNG and generation modernization, while accounting for risks attributed to changes in fuel prices for both LNG and oil, were evaluated. We refined these cases to incorporate results from preceding runs of DER, DR, and utility-scale resource iterative cycles, iterated to achieve low-cost and minimized risk objectives, and analyzed grid modernization to characterize tradeoffs and risks of capital investments. We ran production simulation using different modeling software (via consultants) for comparative purposes, conducted stochastic analysis to characterize risks associated with fuel price forecasts (through Ascend Analytics as described above), and ran sensitivity analyses using high and low fuel price forecasts.
We calculated present values of revenue requirements, and the relative difference in revenue requirements between cases for initial cases. Capital expenditure constraints were considered as described above. Using the Decision Framework, the Preferred Plans were selected and five-year action plans to implement the Preferred Plans were developed. It should be noted that with the exception of Theme 2 which requires LNG, generation modernization, and unit conversions, the near term actions for all final plans are very similar.
posted by Herman K. Trabish @ 9:11 AM
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