Month: June 2019

Energy Infrastructure Update for April 2019 Issued by FERC

Energy Infrastructure Update for April 2019 Issued by FERC

On June 7, the Federal Energy Regulatory Commission (FERC) released their Energy Infrastructure Update for April, related to natural gas and hydropower, and covering the highlights for electric generation and transmissions.

In April, six new pipeline projects were certified and another one was proposed. Two Liquefied natural gas (LNG) import/export projects were certified.

In the year thus far, a total of four pipeline projects have been placed into service, compared to three in the same period in 2018; 13 more have been certified, compared to 19 at this time last year. One LNG storage facility has been certified, compared to three last year.

For LNG imports and exports, two exports have been placed in service this year, compared to one in 2018; four import/exports have been certified this year, compared to none at this point in 2018.

For hydropower, one license was filed in April, and that is the only activity in April. Another two facilities have filed capacity amendments in this year so far.

In April there were no new coal facilities, as there have been for all of 2019 to that point; there were four at this time in 2018.

There was one new natural gas unit, making 22 for the year to date; there were 26 at this time in 2018. There has been nothing new for nuclear power this year; there were three at this point last year. One new oil facility was added in April, making it a total of three for the year; compared to 10 from this time last year. There were no hydropower units added, but there have been four this year; compared to six last year. There was one wind power unit added, making it a total of 18 this year; compared to 17 last year. There have been no new biomass units added this year, compared to five last year. There have been no new geothermal steam units added this year either, and only two were added in this period last year. Four new solar powered units were added in April, making a total of 102 this year; compared to 213 at this time last year.

There were many proposed additions and retirements in April, to be done by May 2022. There were two proposed additions for coal, both are considered highly probable, and 50 proposed retirements. There were 226 proposed additions for natural gas, 110 are highly probable, and 109 units were proposed retired. Nuclear power had 11 additions proposed, three are highly probable, and eight proposed retirements. There were 11 additions for oil, 11 are highly probable, and there were 26 retirements. Hydropower had 224 additions, 82 highly probable, and 19 retirements. There were 543 additions for wind, 140 highly probable, and one retirement. There were 64 biomass additions, 29 highly probable, and 30 retirements. There were 18 geothermal steam additions, six highly probable, and no proposed retirements. Solar power had 2,510 additions proposed, 527 highly probable, and one retirement.

For electric transmissions, in the ≤230 range, 71 miles of line was laid in April, making a total of 91 this year; compared to April 2018 with 11 miles of line and a total of 392.3 in all of 2018. There were 1,748 miles of line proposed to be put in service by May 2021, and 532.1 were highly probable. In the 345 voltage, four miles of line were completed, making a total of 169 this year; there were 70 in April 2018, and 819.3 in all of 2018. There were 2,712 miles proposed, 1,067 considered highly probable. In the 500-voltage range, there were none laid in April, of this year or last, and only a total of 7.4 miles in 2019 this year total, and 69.4 in 2018; 1,662 miles were proposed additions, 738 of which are highly probable. A total of 75 miles were laid in April, close to the 81 in 2018; there have been 267.4 miles this year so far, compared to 1,281 in 2018. A total of 6,122 miles have been proposed, and 2,337.1 are considered highly probable.

FERC Has Approved Freeport LNG’s Request

FERC Has Approved Freeport LNG’s Request

The Federal Energy Regulatory Commission (FERC) on May 16, approved the Freeport LNG terminal in Texas’ request for construction of the Train 4 expansion. This is the fourth liquefied natural gas (LNG) export project that FERC has approved this year. Freeport LNG filed an application for the expansion in June 2017.

“I’m proud of the efforts by the Commission and its staff to process today’s and our previous LNG orders,” FERC Chairman Neil Chatterjee said. “Exporting LNG from the United States can help increase the availability of inexpensive, clean-burning fuel to our global allies who are looking for an efficient, affordable and environmentally friendly source of generation.”

This expansion “involves construction of a liquefaction unit similar to Freeport’s other three units at the site, as well as associated pipelines, storage vessels and related facilities.” It should allow 0.74 billion cubic feet of natural gas per day when it’s finished.

Two of FERC’s Commissioners released individual statements about this ruling, Cheryl A. LaFleur and Richard Glick. LaFleur wrote that she concurs with the approval, while Glick dissents. Glick wrote that he dissents for a few reasons, including that in his opinion, “it violates both the Natural Gas Act (NGA) and the National Environmental Policy Act (NEPA).”

To read the entire approval, click here.

Statement of Commissioner McNamee

Statement of Commissioner McNamee

On May 16, the Federal Energy Regulatory Commission (FERC) released an order for rehearing and clarification on Order No. 841, “amending its regulations under the Federal Power Act to remove barriers to the participation of electric storage resources in the capacity, energy, and ancillary service markets operated by Regional Transmission Organizations and Independent System Operators.” FERC Commissioner Bernard L. McNamee released a statement to argue his positions on some of the issues in the rehearing order. McNamee decided to issue a separate statement “because I am concerned that, like Order No. 841, today’s order on rehearing fails to recognize the states’ interests in ESRs located behind a retail meter (behind-the-meter) or connected to distribution facilities.”

In this statement, McNamee says that “I am troubled, however, that the Storage Orders do not fully respect or consider the impact they may have on local distribution systems, the states that regulate those local distributions systems, and local retail customers. To that end, I dissent from today’s order. I would have granted the rehearing requests asking the Commission to reconsider: (i) its finding that it has jurisdiction over whether ESRs located behind-the-meter or on the local distribution system are permitted to participate in the RTO/ISO markets through the ESR participation model and thereby asserting jurisdiction over distribution facilities; and (ii) its failure to provide states the opportunity to opt-out of the participation model created by the Storage Orders.”

“Electric energy storage resources (ESRs) have the potential to transform the electricity industry.” This is because they “will allow the electric transmission system to take full advantage of periods of high generation from intermittent resources, such as wind and solar, and use that energy in times when those resources are not available, but energy is needed.” He explained that there has been a growing amount of ESRs participating in the electricity market, which will allow a “greater shifting between generation and load — thereby enhancing reliability and market signals.” He says the ESRS can make a significant impact on the market and economic efficiency, which has to date been unattainable by the industry and its consumers.

“Order No. 841-A mandates that ESRs be permitted to use distribution facilities so that they may access the wholesale electric market,” McNamee writes. “There is no doubt that the participation of ESRs behind-the-meter or on the distribution lines can ‘affect wholesale rates,’ but in order to ‘affect’ wholesale rates such ESRs must first have access to the wholesale market, and they can only do so by using distribution facilities. In my view, the FPA does not provide the Commission with the authority to require that distribution facilities permit ESRs to use those facilities to access wholesale markets.”

For an ESR that’s “located either behind-the-meter or on the distribution system, the only way it can sell its energy at wholesale is by using distribution facilities to deliver energy to the wholesale market.” FERC concluded in Order 841 “that because ESRs’ sales and purchases can affect wholesale rates, the Commission therefore has the authority to dictate that ESRs have access to the wholesale market through distribution facilities… It is only when an ESR is provided access to the wholesale power markets through the distribution facilities that the Commission can exercise its authority; but the Commission cannot mandate that such access be provided on the local distribution facilities. That decision remains with the local distribution utilities and the states that regulate them.”

“In Order No. 841, the Commission asserted that because ESRs can [affect] wholesale rates, ESRs must be allowed to connect behind-the-meter and to the distribution facilities in order to participate in the wholesale markets… I believe that the requirement in the Storage Orders that states must permit distribution and behind-the-meter ESRs to use distribution facilities to access the wholesale markets creates a regulatory plan that fails to ‘happen exclusively’ on the wholesale market and fails to exclusively govern the wholesale market’s rules.”

At one point, FERC “considered a request for a declaratory ruling that, among other things, found the Commission had exclusive jurisdiction under the FPA to regulate the participation of certain EERs in wholesale electricity markets and that the states lacked the authority to bar or otherwise interfere with the participation of EERs in those markets.”

“The Storage Orders will likely result in day-to-day operational impacts on the distribution system greater than those presented by EERs or DR, but without providing states an opportunity to avoid these impacts by allowing them to opt out… An ESR’s activity quite literally pushes or pulls energy across the distribution facilities and thereby has a very real physical impact on the distribution system. The physical nature of an ESR’s activities may impact the operations of distribution-level facilities as well as their safety and reliability in a manner that DR’s and EERs’ voluntary decision not to consume electricity does not… The real physical and operational impacts ESRs have on the distribution system in my estimation weigh in favor of the Commission exercising its discretion to provide an opt-out to the states in this matter.”

“I am concerned that the Storage Orders potentially will create complications for, and impact the day-to-day operations and management of, the distribution system – as well as its safety and reliability – in a manner that is in fact greater than the impact of demand response resources because ESRs actually inject energy into the system.”

“Order No. 841 holds that ‘state responsibilities include, among other things, retail services and matters related to the distribution system, including design, operations, power quality, reliability, and system costs.’ However, the majority in Order No. 841-A dismisses the issue of increased cost on the distribution system as ‘outside the scope of this proceeding’ and argues that ‘we are not changing the responsibilities of the distribution utilities.’” McNamee says he disagrees with this, because “it is clear that many parties feel strongly that the Storage Orders do in fact increase their responsibilities, and if the majority does not want to address these issues in this proceeding, then they should at least provide an option for states to avoid these costs by opting out.”

“The majority also should not dismiss concerns over equity or cost allocation. When a distribution utility is concerned that it ‘will need to harden the underlying distribution system to support bidirectional power flows and pay for substantial metering upgrades’ to accommodate ESRs, and that the associated costs ‘could be trapped at the distribution level and allocated to end-users rather than wholesale market participants,’ in my view the Commission should not flatly disclaim involvement. The majority is willing to assert jurisdiction over the distribution system through the participation model, but they are unwilling to confront or take responsibility for the practical ramifications of their decisions.”

“In the complex and overlapping jurisdictions of electricity, a retail customer with a complaint or question about his or her bill or service may find it difficult to know whom to contact about that service. When service involves the distribution system, it is natural for a customer to call the local utility or the state public utility commission. The Commission should be cognizant that, by denying states an opt-out provision with respect to the Storage Orders, the majority is not only placing a burden on the distribution utility or the state to address any impacts of ESRs on the distribution system, they are in effect asking the distribution utility or state to take ownership of and accountability for that burden.”

McNamee concluded saying that if ESRs have the “correct regulatory and policy framework,” they could “transform the electricity industry by unlocking significant economic and market efficiency benefits.”

The order for rehearing will become effective 90 days after its publication in the Federal Register.