MA second offshore wind procurement solicited

Friday, May 31, 2019

The electric distribution companies of Massachusetts, in coordination with state Department of Energy Resources, have issued a second request for proposals for long-term contracts for offshore wind energy projects as required by state law.

Under Section 83C of Chapter 169 of the Acts of 2008, as amended by chapter 188 of the Acts of 2016, An Act to Promote Energy Diversity, Massachusetts electric distribution companies are required to jointly procure significant amounts of energy from offshore wind projects. A first round of solicitations under Section 83C in 2017 yielded contracts with offshore wind developer Vineyard Wind LLC for 800 megawatts of generation. The law was subsequently amended to require another 800 megawatts of offshore wind by June 30, 2027.

On May 23, 2019, distribution companies Fitchburg Gas & Electric Light Company d/b/a Unitil, Massachusetts Electric Company and Nantucket Electric Company d/b/a National Grid, and NSTAR Electric Company d/b/a Eversource Energy issued their second request for proposals pursuant to Section 83C. The RFP seeks "reasonable proposals" to enter into cost-effective long-term contracts for offshore wind energy generation and associated renewable energy certificates or RECs. It expresses the utilities' intent to procure at least 400 megawatts of offshore wind energy generation, or up to 800 megawatts if the evaluation team determines that a larger-scaled proposal is both superior to other proposals and is likely to produce more economic net benefits to ratepayers.

As approved by the state Department of Public Utilities on May 23, 2019, the timeline for the second offshore wind procurement requires confidential proposals to be submitted by August 9, 2019, with projects selected for negotiation by November 8, contract execution by December 13, and submission of the contracts for DPU approval by January 10, 2020. The timeline also includes a bidders conference scheduled for June 4, and an opportunity for prospective bidders to submit written questions pertaining to the solicitation by June 11.

Beyond this second solicitation under Section 83C, further solicitations are expected: a subsequently enacted law requires the procurement of an additional 1,600 megawatts of offshore wind by December 31, 2035.

US approves more exports of LNG "freedom gas"

Thursday, May 30, 2019

The U.S. Department of Energy has approved additional exports of domestically produced natural gas from a liquefied natural gas terminal in Texas, describing the increased export capacity as "critical to spreading freedom gas throughout the world," and praising "an efficient regulatory system that allows for molecules of U.S. freedom to be exported to the world."

In a May 28, 2019 press release, the Department of Energy announced its approval of increased exports from the Freeport LNG Terminal located on Quintana Island, Texas. Freeport LNG Expansion, L.P. and other Freeport entities had previously received approval to export LNG from the first three liquefaction trains at the Terminal, as well as to site, construct and operate a fourth liquefaction train (Train 4) to be built at the Freeport LNG Terminal.

By its Order No. 4374, the Department gave Freeport LNG Expansion, L.P. and FLNG Liquefaction 4, LLC (together, FLEX4) the authority to export up to 0.72 billion cubic feet per day of natural gas as LNG from Train 4. The order authorizes FLEX4 to export U.S.-sourced liquefied natural gas to any country with which the United States has not entered into a free trade agreement requiring national treatment for trade in natural gas, and with which trade is not prohibited by U.S. law or policy.

The Department's press release quotes U.S. Under Secretary of Energy Mark W. Menezes as saying, "Increasing export capacity from the Freeport LNG project is critical to spreading freedom gas throughout the world by giving America’s allies a diverse and affordable source of clean energy." The press release also quotes Assistant Secretary for Fossil Energy Steven Winberg as expressing his pleasure that "the Department of Energy is doing what it can to promote an efficient regulatory system that allows for molecules of U.S. freedom to be exported to the world."

Freeport's first liquefaction train is expected to start making commercial exports later in 2019. U.S. exports of natural gas are increasing and poised to rise further. The first exports from the Lower 48 came in February 2016, when the first cargo shipped from the Sabine Pass terminal in Louisiana. Since 2017, the U.S. has exported more natural gas than it imports. U.S. LNG export capacity is on track to double from 5 billion cubic feet per day to 10 Bcf/d by the end of 2020, with significantly more export capacity approved or pending. Meanwhile, domestic production of natural gas reached a new peak of 101.3 billion cubic feet per day in 2018.

MA approves second offshore wind procurement process

Thursday, May 23, 2019

Massachusetts utility regulators have approved a proposed timetable and method for soliciting a second round of long-term contracts for offshore wind energy generation.

Section 83C of the Green Communities Act requires Massachusetts electric distribution companies to jointly propose a timetable and method for the solicitation and execution of long-term contracts, subject to review and approval by the Department of Public Utilities. As it has been amended, Section 83C calls for multiple procurement rounds, to result in cost effective long-term contracts for offshore wind energy generation equal to approximately 1,600 megawatts of aggregate nameplate capacity not later than June 30, 2027. A subsequent law requires the procurement of an additional 1,600 megawatts of offshore wind, by December 31, 2035.

In 2017, the state's electric utilities issued their first solicitation under Section 83C, which resulted in contracts with offshore wind developer Vineyard Wind LLC for 800 megawatts of generation. Section 83C requires that any long-term contracts resulting from this second solicitation must include a nominal levelized price per megawatt-hour that is less than the levelized price resulting from the first solicitation (which was $64.97 per megawatt-hour in 2017 real dollars).

In March 2019, the utilities proposed a timetable and process for soliciting a second round of offshore wind contracts. The utilities proposed a second RFP to seek at least 400 megawatts, but with consideration of proposals from 200 megawatts up to approximately 800 megawatts if a larger-scale proposal is both superior to other proposals and is likely to produce more economic net benefits to customers.

By order dated May 17, 2019, the Department of Public Utilities approved the utilities' proposed timetable and method. The Department accepted the utilities' assertion that a nominal levelized price of $84.23 per megawatt is equivalent to the first solicitation's result. The Department also accepted the utilities' timetable, which includes RFP issuance on May 17, 2019, confidential proposals due by August 9, project selection by November 8, contract execution by December 13, 2019, and submission of contracts for regulatory approval by January 10, 2020.

While approving the overall timetable and process proposed by the utilities, the Department did deny a request by National Grid USA for a "regulatory out", or a provision in any future power purchase agreement resulting from the solicitation which would allow the utility to terminate the agreement if the utility cannot pass the contract's costs onto its ratepayers. In denying National Grid's request for such a "regulatory out", the Department noted that such a clause has never been used in long-term renewable energy contract solicitation in Massachusetts, and that its inclusion would place "the full risk of regulatory disallowance on project developers," in turn making financing more difficult and more expensive. For these reasons, the Department directed National Grid not to include a "regulatory out" provision in its form power purchase agreement for this solicitation.

New England electricity carbon emissions decline

Wednesday, May 22, 2019

Carbon dioxide emissions from New England's electric power generators continued to decline in 2017, according to a recent report from the region's grid operator.

According to ISO New England Inc., regional emissions of sulfur dioxide, nitrogen oxides, and carbon dioxide all declined in 2017 compared to the previous year, due largely to a decline in the use of fossil fuels to generate electricity. For carbon dioxide, the report shows that the New England system emitted 34,969 short kilotons in 2017, a 6.7% decrease relative to 2016, with an average emission rate of 682 pounds per megawatt-hour.

The region's electricity-sector carbon emissions peaked in 2005, at 60,580 short kilotons. According to the report, carbon emissions in 2017 were 42% lower than in 2005. The report cites several key factors contributing to the year-over-year declines, including continuing declines in coal- and oil-fired generation, lower levels of demand for electricity, and significant increases in production from non-emitting hydro, solar and wind resources.

FERC Order 841-A affirms electric storage market participation

Monday, May 20, 2019

On May 16, 2019, the Federal Energy Regulatory Commission issued an order generally affirming an earlier order which established reforms to remove barriers to the participation of electric storage resources in certain organized wholesale markets. The Commission's Order No. 841-A denied various requests for rehearing of last year's Order No. 841.

In 2018's Order No. 841, the Commission found that existing rules for electricity markets operated by regional transmission organizations and independent system operators were unjust and unreasonable in light of barriers that they present to the participation of electric storage. Based on this finding, the Commission ordered wholesale market makers to revise their tariffs to "establish a participation model consisting of market rules that, recognizing the physical and operational characteristics of electric storage resources, facilitates their participation in the RTO/ISO markets." Order No. 841 required each regional organization's participation model to (1) ensure that a resource using the participation model for electric storage resources is eligible to provide all capacity, energy, and ancillary services that it is technically capable of providing in the RTO/ISO markets; (2) ensure that a resource using the participation model for electric storage resources can be dispatched and can set the wholesale market clearing price as both a wholesale seller and wholesale buyer consistent with existing market rules that govern when a resource can set the wholesale price; (3) account for the physical and operational characteristics of electric storage resources through bidding parameters or other means; and (4) establish a minimum size requirement for participation in the RTO/ISO markets that does not exceed 100 kW. Order No. 841 also required that the sale of electric energy from the RTO/ISO markets to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price.

In Order No. 841-A, the Commission generally affirmed these findings, while clarifying a handful of relatively limited points. The ruling ends for now some of the uncertainty over the scope and applicability of Order No. 841.

As regional wholesale markets develop tariff revisions to integrate electric storage resources, there could be significant opportunities to develop and benefit from electric storage. Reports have suggested significant potential for electric storage deployment -- with one 2018 study suggesting the U.S. could be home to between 7 and 50 gigawatts of storage, if costs continue to decline and sufficient policy support is available.

FERC changes enforcement process, ends preliminary notices

Thursday, May 16, 2019

Ending a decade-long practice of issuing Notices of Alleged Violations in early stages of enforcement investigations, this week the Federal Energy Regulatory rescinded its 2009 Order Authorizing Secretary to Issue Staff’s Preliminary Notice of Violations.

Historically, the Commission generally did not issue any public notice of its investigations or targets until an investigation was either resolved through settlement or escalated through a Commission order to show cause. In 2009, the Commission adopted a policy of issuing Notices of Alleged Violations at a relatively early stage in its process for investigating possible violations of federal energy law. Under that policy, Commission enforcement staff would issue a public notice after giving an investigative subject an opportunity to respond to staff's preliminary findings, but before staff finalized its conclusions or the Commission issued an order. At the time, the Commission said this policy balanced investigative subjects' confidentiality against the benefits of enhanced transparency, but some commenters criticized the policy for its publication of alleged violations before a full investigation had been completed.

In 2011, the Commission upheld its policy in an order on requests for rehearing and clarification of its 2009 order. At the same time, the Commission committed to monitoring and evaluating the effectiveness of the policy. Shortly thereafter, the Commission issued its first Notices of Alleged Violations. Over the years, Commission staff continued to issue notices of alleged violation.

But in an order issued on May 16, 2019, the Commission rescinded this policy based on a finding that "the balance has shifted." Specifically, the Commission found that "the potential adverse consequences that NAVs pose for investigative subjects are no longer justified in light of the limited transparency NAVs have generated and the more effective, alternative means of adding transparency that the Commission has developed since the NAV Order."

At the same time, the Commission said that the transparency benefits it had hoped the policy would bring have been limited. Meanwhile, the Commission has gained access to other sources of information that support its investigations, and now uses "these data sets and sophisticated algorithmic screens to detect potential manipulation, anticompetitive behavior, and other anomalous activities in the energy markets we oversee."

Weighing the limited benefits against the risk of reputational harm to subjects, the Commission found that the "potential negative impacts on investigative subjects are no longer warranted in light of the limited transparency NAVs have generated and the alternative methods of adding transparency the Commission has developed since adopting the policy."

The Commission therefore rescinded its 2009 policy as "no longer warranted." This decision removes the Commission secretary's authorization to issue staff preliminary notices of violation.

The move bears resemblance to recent Commission practice of not publicly identifying utilities alleged to have violated reliability standards, despite calls for public disclosure and transparency.

FERC grants QF rule waiver for distributed solar developer

Tuesday, May 14, 2019

Last month federal regulators issued an order that could facilitate the development of small-scale distributed solar projects. The Federal Energy Regulatory Commission's April 18, 2019 order granting certain waivers to residential solar developer Sunrun, Inc. could open the door to reduced administrative burdens for developers of clustered residential-scale solar projects.

Under the federal Public Utility Regulatory Policies Act of 1978 (PURPA), certain electrical generators can be certified as "qualifying facilities" or QFs if they meet defined standards. QFs can avail themselves of benefits under federal law, such as the right to sell energy and capacity to utilities, as well as exemptions from certain other federal laws.

The Federal Energy Regulatory Commission's regulations generally require a facility to file a Form No. 556 for self-certification or to apply for Commission certification in order to be a QF. But for generating facilities with net power production capacities of 1 MW or less, the Commission's Order No. 732 created an exemption, such that those facilities are not required to file either a notice of self-certification or an application for Commission certification in order to qualify as a QF.

The Commission's regulations also include what is commonly referred to as the "one-mile rule," under which a small power production facility located within one mile of another small power production facility that uses the same energy resource and has the same owner is considered to be the same facility for purposes of determining if the facility exceeds the 80 MW limit on a small power production QF. In a pair of rulings known as SunE B9 and SunE M5B, the Commission found that the one-mile rule should also be used to determine whether the exemption from the QF certification filing requirement is applicable for QFs that are 1 MW or less.

On September 24, 2018, residential-scale solar developer Sunrun, Inc. filed a petition to the Commission requesting waivers of qualifying facility certification filing requirements, including the rule requiring identification of other generating facilities within one mile with at least 5 percent common ownership. Sunrun's business model allows its client homeowners to buy and own the photovoltaic systems installed by Sunrun, but also offers an option whereby Sunrun will finance, own, and maintain the system. In its petition to the Commission, Sunrun expressed concern that the PV systems Sunrun owns will collectively, as a cluster, be deemed to be owned by the same person for purposes of the Commission’s one-mile rule, under which QFs that are owned by the same entity or an affiliated entity and are located within one mile of each other are considered to be one QF (and therefore are limited to 80 MW in the aggregate).

On April 18, 2019, the Commission issued an order granting Sunrun's petition for declaratory order. The Commission found that granting Sunrun waiver of the QF certification filing requirements for separately-interconnected, individual residential rooftop solar PV systems and related equipment with maximum net power production of 20 kW or less for which Sunrun provides financing, "aligns with the purpose of the 1 MW filing exemption, which was set forth to ease the administrative burden for both the Commission and small scale QFs." The Commission also granted waiver of the requirement to submit a list of affiliated generation within one mile when filing Form No. 556 for Sunrun-owned clusters of residential PV systems of 20 kW or less located within one mile.

On its face, the ruling applies only to Sunrun and is limited in scope to the waivers Sunrun had requested. But the order suggests the Commission could be willing to grant similar waivers for other developers who aggregate significant amounts of small-scale residential or other distributed solar projects, which could help reduce the administrative burden on project developers and thereby could make solar more accessible to homeowners.

FERC approves Dominion penalty for alleged anti-manipulation violation

Wednesday, May 8, 2019

Federal energy regulators have approved a settlement between a Virginia electric utility and regulatory enforcement staff over allegations of market manipulation. The settlement requires Virginia Electric and Power Company (doing business as Dominion Energy Virginia) to pay a civil penalty of $7 million to the U.S. Treasury, and to disgorge an additional $7 million to  regional transmission organization PJM Interconnection, L.L.C.

At issue is an order issued by the Federal Energy Regulatory Commission approving a stipulation and consent agreement between the Commission's Office of Enforcement and utility Dominion Energy Virginia. The allegations relate to how Dominion Energy Virginia submitted bids to supply electricity to the PJM market from the utility's fleet of 20 simple-cycle combustion turbines, with an aggregate generating capacity of 2,414 megawatts. According to the order, enforcement staff alleged that during a 12-month period in 2010 and 2011, the utility violated the Commission's anti-manipulation rule by changing its bid pricing and structure for these units to obtain more day-ahead commitments to generate, to increase lost opportunity credits, and to achieve longer real-time run times when dispatched -- specifically, by inflating the units' claimed startup costs while discounting their incremental energy offers.

As part of the settlement, Dominion Energy Virginia stipulated to certain facts, but neither admitted nor denied the alleged violations. The utility agreed to pay a civil penalty of $7 million, to disgorge another $7 million to PJM, and to be subject to enhanced reporting and compliance requirements.

The Commission approved the stipulation and consent agreement, finding that "the Agreement is a fair and equitable resolution of the matters concerned and is in the public interest, as it reflects the nature and seriousness of the conduct and recognizes the specific considerations stated above and in the Agreement."

According to the Commission's 2018 Report on Enforcement, in fiscal year 2018, "staff negotiated six settlements that resulted in more than $83 million in civil penalties and disgorgement of more than $66 million in unjust profits." Since 2007, the enforcement office says its staff has negotiated settlements allowing for the recovery of approximately $776 million in civil penalties plus disgorgement of approximately $511 million.

Oregon pumped storage project licensed

Monday, May 6, 2019

U.S. hydropower regulators have issued a license for a pumped storage project to be developed in Oregon. As licensed by the Federal Energy Regulatory Commission, the Swan Lake North Pumped Storage Hydroelectric Project would be located near Klamath Falls, and could produce 393.3 megawatts of power for up to 9 hours at a time.

Pumped storage projects cycle water between two reservoirs at different elevations, generally using equipment that can both pump water uphill for storage in the upper reservoir and then generate electricity by letting the water flow back down to the lower reservoir. Pumped storage can be used to store and release surplus energy (such as may be produced by wind or other nondispatchable renewable facilities), to provide reliability benefits, and to moderate electricity prices by pumping when prices are low and releasing when prices are high. While development of battery storage facilities is increasing, pumped storage facilities represent the vast bulk of currently deployed energy storage in the U.S.

In this case, the licensee is Swan Lake North Hydro LLC. The project is a joint development by Rye Development and National Grid. In 2015, the company applied to the Commission for a license to construct, operate, and maintain the project. Facilities described in the license include a new upper and lower reservoirs, connected by a series of penstocks and a powerhouse with generating/pumping facilities. According to the license order, the project will operate using off-peak energy (i.e., energy available during periods of low electrical demand) to pump water from the lower reservoir to the upper reservoir and generate energy by passing the water from the upper to the lower reservoir through generating units during periods of high electrical demand. Project generation will be timed "based on on-peak/off-peak power considerations, the need to augment the production of renewable wind and solar power generation, or to provide ancillary power services."

The license order addresses project economics. As licensed, the project is expected to generate 1,187,000 megawatt-hours per year, at a levelized annual cost of about $114,968,700, or $96.86 per megawatt-hour. Considering an alternative power cost of $108.09/MWh, the order suggests that in the first year of operation, project power will cost $13,329,300, or $11.23/MWh, less than the cost of alternative power.

The Commission granted the project license for a 50-year term, citing the "substantial investment in new facilities."

Maine public power bill proposed

Friday, May 3, 2019

The Maine legislature is considering a bill that would create a public power authority to acquire and operate most of the state's electric transmission and distribution systems. Sponsored by state Representative Seth Berry (who co-chairs the legislature's energy committee), with co-sponsors including Senate President Troy Jackson and Republican Senator David Woodsome, LD 1646 bears the title, "An Act To Restore Local Ownership and Control of Maine's Power Delivery Systems."

The bill would create the Maine Power Delivery Authority "to provide for its customer-owners in this State reliable electric transmission and distribution services at the lowest possible cost." The Authority would be a consumer-owned transmission and distribution utility, with the mandate to "purchase all utility facilities in the State" owned by any investor-owned transmission and distribution utilities, for their net book value. (Currently, these utilities are Emera Maine and Central Maine Power Company; they collectively serve about 92 percent of Maine's retail load.) The bill would require the Authority to contract with a qualified nongovernmental entity to provide operations and administrative services.

Structurally, the Authority would be a body corporate and politic and a public instrumentality of the State and would be governed by a bipartisan board composed of 10 Maine residents, appointed by the Governor and confirmed by the Legislature. As a public municipal corporation, the Authority would be generally exempt from state income and property taxes, but would make payments in lieu of taxes to municipalities, counties, and the state, if revenues are sufficient.

LD 1646 has been referred to the legislative's committee on energy, utilities, and technology, which will schedule and hold a public hearing on the proposal. Nationally, 49 million Americans are served by public power utilities according to the American Public Power Association. While most Maine electricity customers are currently served by investor-owned transmission and distribution utilities, Maine has several consumer-owned utilities (including municipal electric departments and districts).

This is not the first time that Maine has considered public power; proposals in 1956 and 1973 attracted much attention -- including a 1956 speech and publication by a Central Maine Power Company executive titled "Public Power, the First Step Toward Eventual Socialism?" -- but those earlier proposals did not come to fruition. Is 2019 the year for Maine to take this step?

NY supports energy storage

Thursday, May 2, 2019

New York has announced the availability of $280 million in incentive funding to support the state's energy storage goals, as part of a larger $400 million package of support for energy storage.

Energy storage -- in batteries or through other technologies -- can improve the efficiency of the electric grid. Depending on its siting and configuration, storage can avoid the need for wires upgrades, or improve the ability of wind and solar energy sources to meet periods of peak demand.

A number of states are exploring or adopting policies to encourage the development of electric storage resources. In December 2018, New York set goals to add 1,500 megawatts of energy storage by 2025 and 3,000 megawatts by 2030, and gave the New York State Energy Research and Development Authority (NYSERDA) authority to develop and implement incentives to accelerate the transformation of the energy storage market.

On April 25, 2019, NYSERDA released its final implementation plan for energy storage market acceleration. Concurrently, Governor Andrew Cuomo announced that $280 million of support is available for energy storage projects to accelerate growth within the industry and drive down energy storage deployment costs to build a sustainable and affordable market.

Incentives include $150 million in funding for energy storage projects larger than 5 megawatts, offering $110/kWh for projects up to 20 megawatts and at $85/kWh for larger projects. The incentives also include $130 million for the Retail Energy Storage Incentive Program, a megawatt hour block system, supporting customer-sited energy storage projects up to 5 megawatts; under the retail program, incentive levels start at $350/kWh, and decline similar to under the NY-Sun Megawatt Block program. 

These NYSERDA incentives are part of a larger $400 million state plan to support energy storage. The broader state plan includes an additional $70 million to "build a self-sustaining storage market" plus $53 million in Regional Greenhouse Gas Initiative funding for energy storage projects located on Long Island.

Maine Climate Change Council legislation unveiled

Wednesday, May 1, 2019

Maine Governor Janet Mills has introduced proposed legislation to create a Maine Climate Change Council. While the bill had not been formally printed by the legislature's Office of the Revisor of Statutes as of May 1, the Governor's office posted a copy of the bill captioned, LR2478, An Act to Create the Maine Climate Council to Assist Maine to Mitigate, Prepare for and Adapt to Climate Change.

The draft bill includes a variety of provisions designed to advance clean energy goals:
  • It includes language requiring the inclusion of more renewable resources in the state's electricity supply -- 80 percent by 2030, and 100 percent by 2050. (Current law requires 40 percent of electricity sold at retail to come from renewable resources. According to the U.S. Energy Information Administration, in 2017, about three-quarters of Maine's net electricity generation came from renewable energy resources, with 30% from hydroelectricity, 26% from wood and other biomass, and 20% from wind.)
  • It repeals the existing law setting Maine's goals for reduction of greenhouse gases (which currently calls for a reduction to 1990 levels by 2010, to 10 percent below 1990 levels by 2020, and in the long term "reduction sufficient to eliminate any dangerous threat to the climate. According to the most recent report of the Maine Department of Environmental Protection, in 2015 Maine's greenhouse gas emissions were 11.7 percent below 1990 levels.) It replaces this section with a new section, requiring reduction to 45 percent below 1990 levels by 2030, and 80 percent below 1990 levels by 2050. The bill requires the Department of Environmental Protection to adopt rules to ensure compliance with these new levels.
  • It creates the Maine Climate Change Council to advise the Governor and Legislature on ways to mitigate the causes of, prepare for and adapt to the consequences of climate change. The council would be composed of up to about 40 people filling specific roles prescribed in the legislation such as business, youth, and science. The structure would include a scientific and technical subcommittee, plus working groups on transportation, coastal and marine issues, buildings, infrastructure and housing, working lands and ecosystems, and energy topics.
  • It requires the Maine Climate Change Council to update the state climate action plan by December 2020, with further updates to the plan every 4 years thereafter. (The Maine Department of Environmental Protection released the current version of the climate action plan in 2004.) The bill also requires the council to report on progress toward implementing the climate action plan by December 2022, and every 2 years thereafter.
In a statement, Governor Mills said that the bill represents a step in combating the threat of climate change by "expanding our clean energy economy, and investing in our future by creating the Maine Climate Council and marshaling experts across the state to take urgent action." The bill's lead sponsor, Senator David Woodsome, is a Republican co-chair of the legislature's energy committee. Procedurally, next steps include the formal printing of the bill by the Revisor, followed by its reference to legislative committee for a public hearing to be scheduled in the coming weeks.