FERC Releases its Energy Infrastructure Update for July 2019

FERC Releases its Energy Infrastructure Update for July 2019

The Federal Energy Regulatory Commission (FERC) issued its monthly Energy Infrastructure Update for July 2019. This update covers the news and highlights for energy around the country, in gas, hydropower, and electric generation. In July there were five natural gas pipelines were certified and another five were proposed. One natural gas storage facility was certified. For liquified natural gas (LNG) imports and exports, one export was placed in service, and one import/export was certified.For the year to date, five natural gas pipelines have been placed in service, compared to six at this point in 2018; 19 have been certified, compared to 31 in 2018. No storage facilities have been placed in service this year, as was the case last year as well, but three have been certified, compared to four in 2018. Three LNG import and export facilities have been placed in service, compared to one in 2018; five have been certified, whereas none were at this point last year.

For hydropower, two conventional facilities filed for licenses, and there was no further activity in July. For the year to date, three conventional hydropower facilities have filed for licenses, along with one hydrokinetic facility. One license was issued to a pumped storage facility, and another to a hydrokinetic facility. One 10-MW Exception was issued, and a capacity amendment was issued. Nothing has been placed in service this year.

The electric generation highlights detailed the new and expanded units in July, plus the year to date, and a comparison of this period in 2018. Wind power had three new units this month, bringing the total to 25 for the year; compared to 27 last year. There were also three solar power units in July, bringing that total to 207 for the year; compared to 345 last year. There were no new units for coal, natural gas, nuclear power, oil, water, biomass, geothermal steam, or waste heat in July.

There were a number of proposed additions and retirements of generation units in July; this is all planned to occur by July 2022. Coal had two proposed additions, one that is under construction, and 57 retirements. Natural gas had 224 additions, another 100 under construction, and 109 retirements. Nuclear power had nine additions, one under construction, and nine retirements. Oil had 12 additions, two under construction, and 26 retirements. Hydropower had 220 additions, 84 under construction, and 20 retirements. Wind had 550 additions, 172 under construction, and two retirements. Biomass had 59 additions, 28 under construction, and 28 retirements. Geothermal steam had 18 additions, six under construction, and no retirements. Solar power had 2,622 additions, 580 under construction, and one retirement.

For electric transmissions, in the ≤230 voltage range, there were no lines completed in July, but there were 540 miles proposed to be placed in service by August 2021. In the 345-voltage range, 9.5 miles were completed in July, compared to 39 in 2018. This brings to total for 345 this year up to 299.5, compared to 847.2 in 2018. There were also 752.4 miles of proposed additions. The 500-voltage range did not have anything completed in July, but there were 670 miles proposed to be added.

FERC Issues DEIS for the Bucks Creek Hydropower Project

FERC Issues DEIS for the Bucks Creek Hydropower Project

In June, the Federal Energy Regulatory Commission (FERC) released a draft Environmental Impact Statement to relicense the “Pacific Gas and Electric Company and City of Santa Clara, California’s (co-applicants) existing 84.8-megawatt Bucks Creek Hydropower Project No. 619.” The application for the project was filed in December 2016, which is ” located on Bucks, Grizzly,
and Milk Ranch Creeks in Plumas County, California. The project consists of the Bucks Creek and Grizzly Developments and, as proposed, would occupy 1,316 acres of federal lands within the Plumas National Forest.” They also filed a supplemental application in May 2018.

“The project consists of Bucks Creek Powerhouse; Grizzly Powerhouse, and the Grizzly Tap Transmission Line; water storage, diversion, and conveyance facilities associated with the two powerhouses, including Bucks Lake, Lower Bucks Lake, Three Lakes, Grizzly Forebay; and other associated facilities.” They do not plan to “add capacity or make any major modifications to the project or its operations under the new license.” The only modifications they have proposed to make are:

· “Install a Howell-Bunger valve at the end of the existing low-level outlet of Bucks Lake Dam to release the minimum instream flows into Bucks Creek.
· “Enhance existing recreation facilities, including campgrounds, picnic areas, boat launches, day use areas, and trails, and construct a Bucks Lake Shoreline Trail and new facilities at the Bucks Lake Boat-In Campground.”

They also proposed to make changes to the already existing boundary that will: “(1) include existing facilities and roads that are necessary for current and future operation and maintenance (O&M) activities, and recreation development; (2) remove land and roads currently within the
boundary that are not required for project purposes; and (3) reduce the shoreline buffer along project impoundments where project infrastructure and recreation facilities are in proximity to the shoreline.”

FERC found four primary issues with relicensing the Bucks Creek Hydropower Project: “(1) the protection of aquatic habitats including stream flows, water temperature, and recruitment of spawning gravel and woody material; (2) the protection of special-status wildlife species from
human disturbance; (3) the need for additional recreational opportunities and facilities in the project area; and (4) the protection of cultural resources.”

FERC recommended the staff alternative in the draft EIS, “which consists of measures included in the co-applicants’ proposal, as well as most of the mandatory conditions and recommendations made by state and federal agencies and non-governmental organizations, and some additional measures developed by the staff.”

The draft EIS consists of the views of “governmental agencies, non-governmental organizations, affected Indian tribes, the public, the license applicant, and Federal Energy Regulatory Commission (Commission) staff.” It has FERC’s evaluations of the proposal as well as some alternatives.


FERC seeks comments on white paper on CIP Standards Notices Penalties

FERC seeks comments on white paper on CIP Standards Notices Penalties

The Federal Energy Regulatory Commission (FERC) is seeking comments from the public about a white paper FERC and the North American Electric Reliability Corporation (NERC) put together. The “white paper proposes to provide transparency and public access to information on violations of mandatory reliability standards governing cybersecurity of the bulk electric
system while protecting sensitive information that could jeopardize security.”

FERC has “received an unprecedented number of Freedom of Information Act(FOIA) requests for non-public information in the Notices of Penalty (NOPs) for violations of Critical Infrastructure Protection (CIP) reliability standards” since 2018. Since 2010, NERC “has been submitting CIP NOPs to FERC… they typically include information regarding the nature of the violations, potential vulnerabilities to cyber systems as a result of noncompliance, and mitigation activities.” The white paper also “proposes that NERC would submit each notice with a public cover letter that discloses the name of the violator, which reliability standards were violated, and the amount of penalties assessed.” In every notice would be “non-public attachments that detail the nature of the violation, mitigation activity and potential vulnerabilities to cyber systems. These attachments would also contain a request for designation of such information as Critical Energy Infrastructure Information.”

The proposed changes will make it more straightforward to distinguish between public and non-public information, which “should make submission and processing of the notices more efficient while also reducing the risk of inadvertent disclosure of non-public information. While names of violators would be made public, detailed information that could be useful in planning an attack on critical infrastructure, such as details regarding violations, mitigation and vulnerabilities, likely would be considered exempt from FOIA.”

“FERC is seeking comment on many aspects of the white paper, including: the potential security benefits and, if applicable, risks associated with the proposed NOP format; difficulties with implementation or other concerns that should be considered; and the level of transparency provided by this proposed changed.”

The notice of the white paper says that comments need to be filed within 30 days, and FERC “encourages electronic submission of comments in lieu of paper using the ‘eFiling’ link at http://www.ferc.gov .” For those who prefer not to file their comments electronically, they can submit their comments to “Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426.” All filings on this will be accessible online, under the eLibrary link. There is an option to subscribe to the docket to be alerted via email when a new document is added. FERC Commissioner Cheryl A. LaFleur issued a statement regarding the white paper, explaining her opinions on the matter.

LaFleur said she “mentioned at our Reliability Technical Conference in June, the handling and confidentiality of these NOPs has been an issue of growing controversy. As I advocated then, I think it is essential that FERC and NERC conduct public process to consider the appropriate balance between transparency and security in these instances. I am very pleased that such a process is being instituted today.”

She explained that the procedures that are currently in place have been there for over a decade, without changing, and she thinks it is good that they consider revising the processes now. “it is important that we handle NOPs so as to avoid subjecting the bulk electric system to risk of a cyber attack once a vulnerability is identified. At the same time, I believe state
regulators, members of the public, and others have a legitimate interest in such violations, and we should seek to achieve as much transparency as we can consistent with protecting legitimate security interests.”

LaFleur says the proposal is “worthy of consideration for a way to handle these NOPs differently. I hope that we receive a wide range of comments on the White Paper, including any suggestions for alternative processes, which will allow FERC and NERC to move forward on this issue.”

The Notice was issued on August 27, 2019, comments can be submitted until September 27, 2019.

TariffShark Tiger SP1 Now Available

TariffShark Tiger SP1 Now Available

Links Technology Solutions, Inc. is excited to announce the release of TariffShark Tiger SP1. This release is an update to the TariffShark Tiger eTariff software. If you are a user of TariffShark Tiger, you are entitled to this software update for no additional fees.

If you want to learn about the upgrade process and your quickest path to running the new software, please contact TariffShark Support.

If you’re not yet using TariffShark to meet your FERC eTariff obligations, we invite you to contact sales and ask for a demo of TariffShark Tiger today.

What’s New in the Update?

Improvements

  • Performance improvements throughout, most notably
    • Running validations
    • Improved speed and robustness of interactions with Microsoft Word on the desktop
    • Improved speed and robustness of TRV Content Processing
    • TariffShark window closes much faster when leaving the application
    • Tariff Timeline
    • SmartBar rendering
    • Grid/table rendering
  • Validation F063 was changed from FAIL to WARNING
  • Enabled configuration of Publishing Options for Whole Documents at Tariff Record and TRV levels
  • Progress bar (e.g. when publishing) is more informative
  • Results from validation performed in Create XML wizard now include validation codes

Fixes

  • Whole Document TRVs correctly participate in publishing and FERC Attachment content generation
  • Users and Logging In
    • Users may once again log in using their email addresses
    • Usernames may contain spaces (e.g. “Taylor Thomas”)
    • Usernames may begin with numeric digits (e.g. “3ldmt3k”)
  • Record FERC Order form no longer sets non-midnight FERC Effective Date values

Technology

  • Secure connection between TariffShark client and application server seek TLS 1.2 by default
  • Added support for SQL Server 2017
  • TariffShark Tiger desktop client can be installed silently
Statements from FERC in ISO New England Inc. to Comply with the Fair Rates Act of 2018, Part Two: Commissioner Richard Glick’s Statement

Statements from FERC in ISO New England Inc. to Comply with the Fair Rates Act of 2018, Part Two: Commissioner Richard Glick’s Statement

The Chairman and Commissioners of the Federal Energy Regulatory Commission (FERC) released statements regarding ISO New England Inc. filing revisions to the “ISO-NE Transmission, Markets and Services Tariff (Tariff) to implement an inventoried energy program in the Capacity Commitment Periods associated with the 14th and 15th Forward Capacity
Auctions (FCA 14 and FCA 15, respectively) to compensate resources for maintaining inventoried energy during the winter months of 2023-2024 and 2024-2025 (Inventoried Energy Program or program).” In May, FERC issued a letter to ISO-NE to inform them that the filing was deficient, and they needed additional information; they received a response in June.
Since FERC did not take action by August 5, the amended proposal from ISO-NE “became effective by operation of law.”

FERC did not act on the filing due to “a lack of quorum at this time.” As per section 205(g)(1)(B) of the FPA, the FERC Chairman and Commissioners provided written statements explaining their views of the filing.

This is Commissioner Richard Glick’s statement.

Glick said that he found the program to be unjust and unreasonable because “The program will cost New England consumers as much as $300 million without any evidence to suggest that it will actually improve the region’s fuel security or that any improvement is likely to be worth the cost. Indeed, the program goes so far as to hand out substantial payments to nuclear, coal, and hydropower generators with no indication that these payments will change their behavior in the slightest.” He said he found this to be a windfall instead of a reasonable rate.

Glick agreed that there is an issue with fuel security in New England, and that during “especially cold winter days, the region’s natural gas transportation capacity can become constrained, creating a risk that there may not be enough natural gas available to supply the natural gas-fired
power plants that would otherwise help power the grid. On these days, the region tends to substitute oil and natural gas delivered via liquefied natural gas (LNG) terminals for gas that would otherwise be shipped through the constrained pipelines.” However, since oil and LNG are not relied upon much during normal weather conditions, “there is a concern that resources may not always have enough of these fuels on hand to sustain the grid over a long period of time. Although the number of these cold winter days has historically been low—and the region has never actually run out of oil and natural gas—the consequences of not being able to generate enough electricity could be catastrophic, making the region’s fuel security an issue we must take seriously.”

Glick stressed that he believes FERC should be “taking fuel security seriously means that ISO New England, stakeholders, and the Commission itself must ensure that efforts to address this issue actually help the region procure the services needed to operate the grid reliably. It also means that we must not waste consumers’ money on poorly designed solutions that do little, if anything, to improve the region’s fuel security.” He believes that “wasting consumers’ money is exactly what the Inventoried Energy program does.”

He explained that the program “proposes to pay certain types of resources for maintaining ‘inventoried energy’—which is, essentially, onsite fuel that the resource can convert into electricity —during two winters: 2023-2024 and 2024-2025. A resource is eligible to participate in one of two ways: either by entering a forward contract, which requires the resource to have a certain amount of ‘inventoried energy’ onsite whenever the ISO declares a cold weather event, or through the spot market, which allows the resource to be paid for whatever ‘inventoried energy’ it happens to have onsite during a cold weather event.”

He explained the “fatal flaws” that he saw in the proposal. “Most importantly, ISO New England does not point to any evidence that there is a near-term operational problem that cannot be adequately addressed by its existing rules or any evidence that the Inventoried Energy program would address any such problem by making the region more fuel secure. Without such analysis, there is no foundation to evaluate whether the program will achieve its intended purpose or do so in a manner that is just and reasonable.”

“At least a third of the capacity eligible to receive payments through the Inventoried Energy program is from resources that will not change their behavior in response to these payments because they already maintain considerably more than three days’-worth of fuel onsite.” He explained that “at least $40 million dollars a year is likely to be spent on resources, such as coal and nuclear generators, that will not change their behavior in response to those payments. That is an utter waste of ratepayers’ money. Based on the record here, one cannot help but wonder whether burning that money might contribute as much to fuel security as wasting it on entities that we know will not do anything differently.”

Glick said “the record suggests that the Inventoried Energy program’s poor design will dissuade other types of resources from participating. For example, ISO New England explains that its proposed forward rate is based on the fair market value of a fuel contract between a natural gas-only generator and an LNG storage terminal. This suggests that the program is intended to incentivize resources to enter into backup LNG contracts.” However, ISO New England has described the “forward rate as representing the ‘break even’ payment associated with a backup LNG contract, meaning that, at that price, resources will be economically indifferent about whether to enter such a contract.” It is because of this that Glick thinks “there is little reason to think that the program will do anything to change the behavior of natural gas-only units, which, as noted, are the primary concern when it comes to fuel security in New England.”

ISO New England suggested that the program was “just and reasonable because it might forestall the retirement of otherwise uneconomic resources, which might then benefit the region’s fuel security… creating a program to funnel money to uneconomic resources in order to prevent their retirement would seem to undermine a key element of the balancing act that the Commission relied upon when it found the Capacity Auctions with Sponsored Policy Resources (CASPR) program just and reasonable.”

But even if we assume, for the sake of argument, that the Inventoried Energy program will make an incremental contribution to fuel security, ISO New England has not shown that this contribution is likely to be worth the program’s considerable price tag. As noted, the ISO estimates that the Inventoried Energy program will cost New England ratepayers between $200 and $300 million over just two years. But the record is insufficient to determine whether that is just and reasonable. For one thing, there is no evidence of how much incremental ‘inventoried energy’ the ISO might get in response to those payments.” He said that since they “did not perform any analysis of how much ‘inventoried energy’ it needs, we have no way of knowing whether the program will satisfy any need for ‘inventoried energy’ that New England may or may not have. And without that information, we simply cannot assess what benefit, if any, New England customers will receive from the program, and therefore whether it is just and reasonable.”

“The Inventoried Energy program does not possess even the basic principles of an effective market-based solution, which the Commission has repeatedly instructed ISO New England to make the foundation of its approach to fuel security.” Glick said that it it those principles that
“help to ensure that the approach is effective, both in delivering the product in question and in ensuring that customers get what they pay for.”

ISO New England “evaluate[d] neither the specific need for inventoried fuel nor the quantity demanded. As a result, there is no market competition for this product because every resource with the necessary attributes receives the same price. But without competition, the price-setting mechanism is untethered from market fundamentals and may produce an extremely inefficient outcome.” He said this is what will happen now; “SO New England established a fixed price, $82.49 per megawatt-hour, without making any attempt to evaluate how much ‘inventoried energy’ it should buy at the price or how much resources might supply at that price.”

“ISO New England’s decision to pursue such an ill-conceived approach is all-the-more disappointing because the ISO has better options than the Inventoried Energy program to address any short-term need that might exist.” He said there were other options that would allow the region’s need to be addressed at a better rate. ” In general, by taking away the downside
risk of having excess fuel at the end of the winter, the Winter Reliability Program provided a proven method for incentivizing resources to procure fuel while targeting payments at resources that might actually respond to those payments. A modified version of the Winter Reliability Program might have helped to address any short-term need while providing at least some evidentiary basis, in the form of real-world experience, for the Commission to evaluate whether the proposal might be effective and worth the cost—in other words, whether it is just and reasonable.”

FERC Makes Early Action Determination for Public Utility District No. 1 of Chelan County, Washington

FERC Makes Early Action Determination for Public Utility District No. 1 of Chelan County, Washington

In June Public Utility District No. 1 of Chelan County in Washington filed a​ ​request for determination​ that “project investments over the term of the existing license” met the criteria in subsection 36(b)(2) of the Federal Power Act, to ensure “that the investments will be considered when the Commission sets the term for the next license for the project.” This is for the Rock Island Project on the Columbia River, near Wenatchee.

Chelan PUD predicts that by 2029 there will be a “total investment during the current license term of over $710 million. Specifically, Chelan PUD requests that the Commission determine whether the following project investments meet the criteria under FPA section 36(b)(2): (a) rehabilitation of Powerhouses 1 and 2; (b) design and construction of new office, warehouse, and storage facilities; (c) replacement of two spillway gate hoists; and (d) implementation of an Anadromous Fish Agreement and Habitat Conservation Plan (HCP).”

They noted that the Federal Energy Regulatory Commission (FERC) “has not issued any order extending the existing license term,” which was issued in 1989. “Therefore, Chelan PUD maintains that the Commission must consider, at the time it determines the next license term, any investment meeting FPA section 36(b)(2)(A) criteria that was not a requirement of the 1989 license order.”

Chelan PUD has requested that FERC “consider the ‘significant’ investments it has made and is proposing to make to rehabilitate the two Rock Island Project powerhouses. Powerhouse 1 contains 10 turbine-generator units (B1 through B10); Powerhouse 2 contains eight
turbine-generator units (U1 through U8). In 2003 and 2017, Chelan PUD notified the Commission of its intent to rehabilitate 9 of the 10 generating units at Powerhouse 1.” Chelan PUD says that those units ““were reaching the end of their remaining useful lives,” and that
“rehabilitation was necessary to keep the project ‘in an adequate condition of repair.'”

Only three Powerhouse 1 units have been rehabilitated: “Unit B10 completed in 2008, Unit B9 completed in 2012, and Unit B6 completed in 2018.” They plan to have the remaining units rehabilitated by 2022. “By 2029, Chelan PUD plans to rehabilitate eight bulb turbine-generator units at Powerhouse 2. Chelan PUD anticipates that the rehabilitation of Powerhouse 2 will provide an additional 40 years of reliable and efficient power generation capability for the units. Chelan PUD estimates that it will cost approximately $270 million to rehabilitate Powerhouse 1, and approximately $352 million to rehabilitate Powerhouse 2.”

“Chelan PUD’s turbine and generator improvements will enhance the efficiency and reliability of the Rock Island Project. These improvements were not considered by the Commission as contributing to the existing 40-year license term. Therefore, we find that the Powerhouse 1 and Powerhouse 2 rehabilitation projects qualify as ‘rehabilitation or replacement of major equipment,’ meeting the criteria under FPA section 36(b)(2).”

“Chelan PUD intends to implement a long-term Rock Island facilities master plan that will include constructing or updating multiple office, warehouse, and storage facilities at the Rock Island Project, estimated at $40 million.” FERC noted that Chelan PUD’s request for determination had “limited information on this investment, such that it is unclear whether it would qualify as a ‘project-related’ investment under the criteria of section 36(b)(2)(A).” FERC is also uncertain if “Congress intended for us to consider ancillary facilities, such as office buildings, that do not have a demonstrated direct hydropower purpose, may not be necessary for project operation, and may have other uses. Therefore, based on the information before us, we cannot determine whether these investments meet the criteria under section 36(b)(2).” They noted that Chelan PUD was welcome to ” file further information on these matters during the relicensing process.”

Chelan PUD also said it ” plans to replace two spillway bay gate hoists to improve the safety and reliability of the spillway operation. In March 2020, Chelan PUD plans to replace the existing manually-operated hoists with automatic hoists, increasing the spillway gate capacity. Chelan PUD anticipates that these improvements will cost an estimated $4 million.”
“Chelan PUD’s planned replacement of manual spillway gate hoists with auto hoists will allow remote gate operation and increase gate capacity, improving the safety and reliability of the spillway. These improvements were not considered by the Commission as contributing to the existing 40-year license term. Therefore, we find that this planned investment meets the section 36(b)(2) criteria.”

In June 2004, FERC approved “a project-specific HCP for the Rock Island Project,” for which they amended “the license to incorporate the provisions of the plan as special articles. The Rock Island Project HCP is a comprehensive and long-term management plan for salmonid species affected by the project.” In order “To achieve the objective of the HCP – achieving and maintaining a ‘no net impact’ for each plan species – Chelan PUD explains that it has spent more than $44 million on fish passage survival studies, hatchery construction, operation and maintenance, annual funding for tributary protection and restoration projects, fish predator control programs, and ongoing passage facilities operations and maintenance.”

FERC found those measures applicable to FPA section 36(b)(2) criteria, but recommended that “during the licensing process, Chelan PUD may wish to provide additional information to clarify the nature of these measures, such as explanations of the extent to which the measures arise from HCP obligations, as opposed to the requirements of the 1987 settlement agreement regarding the project.”

FERC’s final determinations were:
“(A) that Chelan PUD’s investments made to rehabilitate the two Rock Island powerhouses, improve the project spillway, and implement its HCP appear to meet the criteria set forth in section 36(b)(2) of the Federal Power Act.

“(B) that it is unable to find whether Chelan PUD’s construction investments in new office, warehouse, and storage facilities meet the criteria set forth in section 36(b)(2) of the Federal Power Act.”

FERC is Creating a New LNG Division in Texas

FERC is Creating a New LNG Division in Texas

The Federal Energy Regulatory Commission (FERC)​ ​announced​ that they will be “creating a new division in its Office of Energy Projects to accommodate the growing number and complexity of applications to site, build and operate liquefied natural gas export terminals.” The new division will be the Division of LNG Facility Review & Inspection (DLNG), and it will have “20 existing LNG staff members in Washington, D.C., and eight additional full-time staffers recruited in the Houston area and based in a new Houston Regional Office.”

FERC Chairman Neil Chatterjee said in the announcement that, “As the demand for U.S. LNG and the number and complexity of project applications has grown, the Commission has experienced a similar growth in the need for FERC to expand its oversight in this program area. Much of the work related to these LNG projects, and the expertise it requires, is based in and around Houston, the so-called ‘Energy Capital of the World.’ For that reason, after careful research and evaluation, the Commission has determined we should direct our newest efforts to recruiting staff in the area to build upon the good work already being done on these issues at our D.C. headquarters.’”

FERC has had 13 staff members “dedicated to working on LNG engineering and review issues,” since April 2018. Since then, that number has grown to 20 staff members, “whose efforts are critical to completing engineering reviews, coordinating safety reviews with the Pipeline and Hazardous Materials Safety Administration at the Department of Transportation, and preparing engineering analyses for inclusion in environmental documents.” The DLNG and the Houston expansion are intended to help FERC prepare for additional work when “LNG project applicants make final investment decisions and move toward construction.”

The Office of the Executive Director and the Office of Energy Projects have started coordinating with General Services Administration about the office configuration and space requirements in the Houston office. There will soon be job postings for the additional staff, starting with the Division Director.