Author: TariffShark

FERC has Approved Two New LNG Pipeline Projects

FERC has Approved Two New LNG Pipeline Projects

On April 18, the Federal Energy Regulatory Commission (FERC) approved two new liquefied natural gas (LNG) export pipeline projects, the Port Arthur LNG and Pipeline projects and the Driftwood LNG and Pipeline projects.

“Today’s orders show that FERC is making a lot of headway on processing LNG applications in a more efficient manner, and I’m proud of the work that we are doing,” FERC Chairman Neil Chatterjee said. “LNG exports can help increase the availability of inexpensive, clean-burning fuel to our global allies who are looking for an efficient, affordable, environmentally friendly source of generation. FERC continues to focus on developing a regulatory ecosystem that allows new technologies to flourish.”

The Driftwood LNG project will be located in Calcasieu Parish, La and it has been authorized to construct LNG facilities that “would export an estimated 27.6 million metric tons of liquefied natural gas per year.” Driftwood’s Pipeline project will consist of “6 miles of mainline pipeline, 3.4 miles of lateral pipeline, 15 new meter stations, and three new compressor stations to transport up to 3.9 billion cubic feet (Bcf) of natural gas per day to feed the LNG facilities.”

The Port Arthur LNG project will have a “total production capacity of an estimated 13.5 million metric tons per year,” and it will be located near Port Arthur, Texas. The Port Arthur Pipeline project will “consist of two pipelines – the 130.9-mile Louisiana Connector Project and the 34.2-mile Texas Connector Pipeline, each with a capacity to transport up to 2 Bcf of gas per day to feed the LNG facilities.” There will also be “three compressor stations and other related facilities” in the Pipeline project.

Both the Driftwood project and the Port Arthur project will “export gas to Free Trade Agreement (FTA) countries.” The sponsors for both projects currently “have applications pending before the U.S. Department of Energy seeking authorization to export gas to non-FTA countries.”

FERC currently has 10 LNG export projects pending.

The concurrence for the Driftwood Projects can be read here. The concurrence for the Port Arthur Projects can be read here.

FERC Released Recommendations to Improve Security

FERC Released Recommendations to Improve Security

On March 29, the Federal Energy Regulatory Commission (FERC) issued a report that had recommendations to help the “users, owners and operators of the bulk-power system assess their risks, compliance efforts and overall cyber security posture.” The suggestions in the report are all based upon the lessons FERC learned during the 2018 fiscal year from “non-public audits of several registered entities of the Bulk Electric System and staff reviews of emerging advanced cyber and physical threats to energy infrastructure.” Those lessons will help FERC improve security for “the nation’s electric grid, strengthen cyber security and help facilitate compliance with mandatory reliability standards.”

“FERC’s Office of Electric Reliability, with assistance from its Office of Enforcement, conducted the audits in collaboration with the North American Electric Reliability Corporation (NERC) and its regional entities.” The FERC Office of Energy Infrastructure also assisted with analyzing the data obtained by the audit.

The report’s recommendations are:

  • “Enhance documented processes and procedures for security awareness training to consider NIST SP 800-50, ‘Building an Information Technology Security Awareness and Training Program’ guidance.
  • Consider implementing valid Security Certificates within the boundaries of BES Cyber Systems with encryption sufficiently strong enough to ensure proper authentication of internal connections.
  • Consider implementing encryption for Interactive Remote Access (IRA) that is sufficiently strong enough to protect the data that is sent between the remote access client and the BES Cyber System’s Intermediate System.
  • Consider Internet Control Message Protocol (ICMP) as a logical access port for all the BES Cyber Assets.
  • Enhance documented processes and procedures for incident response to consider the NIST SP 800-61, “Computer Security Incident Handling Guide.”
  • Consider the remote configuration of applicable Cyber Assets via a TCP/IP-toRS232 Bridge during vulnerability assessments.
  • Consider the use of secure administrative hosts to perform administrative tasks when accessing either Electronic Access Control or Monitoring Systems (EACMS) or Physical Access Control Systems (PACS).
  • Consider replacing or upgrading “End-of-Life” system components of an applicable Cyber Asset.
  • Consider incorporating file verification methods, such as hashing, during manual patching processes and procedures, where appropriate.
  • Consider using automated mechanisms that enforce asset inventory updates during configuration management.”

The report also notes some lessons they previously learned:

  • “Conduct a thorough review of CIP Reliability Standards compliance documentation to identify where the documented instructional processes are inconsistent with actual processes employed.
  • For each remote cyber asset conducting IRA, disable all other network access outside of the connection to the applicable Cyber System that is being remotely accessed, unless there is a documented business or operational need.
  • Enhance documented processes and procedures for identifying BES Cyber System Information to consider the NERC Critical Infrastructure Protection Committee guidance document, ‘Security Guideline for the Electricity Sector: Protecting Sensitive Information.’”

“The audits evaluated the registered entities’ compliance with the applicable Critical Infrastructure Protection (CIP) Reliability Standards and identified other possible areas for improvement not specifically addressed by the CIP reliability standards.”

FERC Initiates Pipeline Rate Investigation Terminates 38 Proceedings

FERC Initiates Pipeline Rate Investigation Terminates 38 Proceedings

The Federal Energy Regulatory Commission (FERC) opened an investigation and ordered a hearing on March 20, to determine whether or not the Stagecoach Pipeline & Storage Company has been “substantially over-recovering its cost of service, resulting in unjust and unreasonable rates.” FERC also discovered that “38 gas companies have complied with the filing requirements of Order 849 and terminated their FERC Form 501-G proceedings without any further action.”

In July 2018, FERC directed every interstate natural gas pipeline company to file Form 501-G, which is “a one-time report that provides a rough estimate of the pipeline’s return on equity before and after passage of the Tax Cuts & Jobs Act and changes to the Commission’s income tax allowance policies in response to rulings by the D.C. Circuit.”

The March 20 order for the investigation follows FERC’s review of the 501-G, as well as other filings by Stagecoach. FERC is concerned that the earnings Stagecoach receives “may exceed its actual cost of service, including a reasonable rate of return on equity.” The hearing and investigation will determine if the existing rates are indeed “just and reasonable in accordance with section 5 of the Natural Gas Act.

FERC has not determined “a just and reasonable return on equity for Stagecoach, and therefore set this issue, among others, for hearing before FERC’s administrative law judges.” Stagecoach was directed by FERC to “file a cost and revenue study for the latest available 12-month period within 75 days of the issuance of its order.”

FERC listed “the 38 companies whose FERC Form 501-G proceedings were terminated without further action:”

  • Cheniere Creole Trail Pipeline
  • Cheyenne Plains Gas Pipeline Company
  • Cimarron River Pipeline
  • Colorado Interstate Gas Company, L.L.C.
  • Crossroads Pipeline Company 
  • Dauphin Island Gathering Partners
  • DBM Pipeline, LLC
  • Destin Pipeline Company, L.L.C.
  • Florida Gas Transmission Company, LLC
  • Florida Southeast Connection, LLC
  • Golden Pass Pipeline LLC
  • Gulf Crossing Pipeline Company LLC
  • Kinder Morgan Illinois Pipeline LLC
  • Kinder Morgan Louisiana Pipeline LLC
  • KO Transmission Company 
  • MarkWest Pioneer, L.L.C.
  • Midcontinent Express Pipeline LLC 
  • Mojave Pipeline Company, L.L.C.
  • National Grid LNG, LLC
  • NGO Transmission, Inc.
  • Pine Needle LNG Company, LLC 
  • Rockies Express Pipeline LLC
  • Rover Pipeline LLC
  • Ruby Pipeline, L.L.C. 
  • Sabal Trail Transmission, LLC
  • Sabine Pipe Line LLC
  • Sea Robin Pipeline Company, LLC
  • Sierrita Gas Pipeline LLC
  • Stingray Pipeline Company, L.L.C.
  • TransColorado Gas Transmission Company LLC
  • Trans-Union Interstate Pipeline, L.P.
  • Transwestern Pipeline Company, LLC
  • UGI Mt. Bethel Pipeline, LLC
  • UGI Sunbury, LLC
  • USG Pipeline Company, LLC
  • Venice Gathering System, L.L.C.
  • West Texas Gas, Inc.
  • WTG Hugoton, LP
FERC Staff Issues Energy Infrastructure Update for January 2019

FERC Staff Issues Energy Infrastructure Update for January 2019

On March 12, the Federal Energy Regulatory Commission (FERC) released their Energy Infrastructure Update for January, related to natural gas and hydropower, and covering the highlights for electric generation and transmissions.

In January, two liquefied natural gas (LNG) pipeline projects were certified, and another four were proposed. There were no updates to any storage or import/export LNG projects. In January 2018, seven LNG pipelines were certified, and there are no other differences in totals for that month last year.

For nonfederal hydropower, one capacity amendment was filed, and nothing new was issued or placed in service.

For new generation in-service electric generation, there was one new natural gas unit, compared to three in 2018. There were no nuclear power or oil units, compared to three in January 2018. There were no hydropower or biomass units, the same as in 2018. Wind power had four new units, compared to 12 last year. There were no updates to geothermal steam power, compared to one in January 2018. There were 18 new solar power units added, compared to 44 in 2018. In total, 23 new units were added, one-third of the 69 units added in January 2018.

There were a number of proposed additions and retirements of units by February 2022. For coal there was one proposed addition and 54 retirements; for natural gas there were 265 proposed additions and 94 retirements; there were 12 proposed additions for nuclear power and nine retirements; for oil, there were 18 proposed additions and 25 retirements; hydropower had 238 proposed additions and 18 retirements; wind power had 538 proposed additions and no retirements; biomass had 53 proposed additions and 27 retirements; geothermal steam had 18 proposed additions; and solar power had 2,394 proposed additions and five retirements.

For electric transmission highlights, “American Electric Power announced plans to increase their four year forward transmission capital expenditure plans by $1.7 billion.” FERC also noted there were no transmission projects completed in January, compared to 30 in January 2018.

FERC Issues Final Rules to Revise Regulations to Confirm with the FPA’s Recent Changes

FERC Issues Final Rules to Revise Regulations to Confirm with the FPA’s Recent Changes

On February 21, the Federal Energy Regulatory Commission (FERC) issued two final rules revising regulations in order to conform to recent changes made by Congress to the Federal Power Act (FPA), in relation to FERC’s review of hydropower permits and public utility mergers.

The rule related to mergers “implements statutory changes to FPA section 203 by amending FERC regulations requiring a public utility to seek authorization to merge or consolidate jurisdictional facilities so that such authorization is required only when those facilities are valued at more than $10 million.”

These revisions will also require public utility companies to tell FERC about “mergers or consolidations if the facilities are valued at more than $1 million but less than $10 million.” It will also “reduce the regulatory burden on utilities for lower-value transactions, and the final action comes within the 180-day period set by Congress.”

The rule about hydropower “conforms the Commission’s regulations to the America’s Water Infrastructure Act of 2018, which amended sections of the FPA related to preliminary permits, qualifying conduit hydropower facilities, and start for payment of annual charges. Under the Act and the Commission’s amended rules, FERC can issue preliminary permits for four years and extend a permit once for an additional four years, instead of three-year terms for preliminary permits with a possible two-year extension.”

This rule also now allows FERC to “issue a second four-year extension if warranted by extraordinary circumstances.” FERC also increased the “maximum installed capacity for qualifying conduit exemptions is increased from five megawatts (MW) to 40 MW.”

FERC was authorized by the Act to “to issue extensions of the start of construction deadline for licenses for up to eight years, which affects the start of the payment of annual charges … Annual charges will begin two years after a license is issued or any extension deadline expires.”

The third rule FERC issued was to clarify and update the “requirements related to interlocking officers and directors.” FERC’s position on “late-filed applications and informational reports” was also clarified.

FERC Clarifies Reforms of Generator Interconnection Procedures and Agreements

FERC Clarifies Reforms of Generator Interconnection Procedures and Agreements

The Federal Energy Regulatory Commission (FERC) clarified its position on Order 845 on February 21. “Order No. 845 adopted ten reforms to improve certainty for interconnection customers, promote more informed interconnection decisions, and enhance the interconnection process.”

FERC received 12 requests for a rehearing or clarification on Order 845. “The draft order grants in part and denies in part the requests for rehearing and clarification.” While most of the reforms in 845 will remain unchanged, FERC granted the rehearing for some of the reforms. The rehearing was granted to clarify “two aspects of the reform to remove a limitation on the interconnection customer’s option to build.”

The Order requires “transmission providers [to] explain why they do not consider a specific network upgrade to be a standalone network upgrade, and second, allows transmission providers to recover option to build oversight costs.” It also clarifies two different parts of the “option to build reform by finding, first, that the Order No. 845 option to build provisions apply to all public utility transmission providers, including those that reimburse interconnection customers for network upgrades, and second, that the option to build does not apply to stand alone network upgrades on affected systems.”

The rehearing also covered reforms to “create a surplus interconnection service process,” explaining that FERC has no intentions to “limit the ability of RTOs and ISOs to argue that an independent entity variation is appropriate.”

There were clarifications regarding the “study model and assumption transparency.” It found that:

  • “Transmission providers may use the Commission’s critical energy/electric infrastructure information regulations as a model for evaluating entities that request network model information and assumptions.”
  • “The phrase ‘current system conditions’ does not require transmission providers to maintain network models that reflect current real-time operating conditions of the transmission provider’s system but should reflect the system conditions currently used in interconnection studies.”

They also clarified the reforms to “institute interconnection study deadline reporting requirements.” Another clarification was on “the date for measuring study performance metrics and clarifies that the reporting requirements do not require transmission providers to post 2017 interconnection study metrics. Instead, the first required report will be for the first quarter of 2020.”

As for the reforms on “requesting interconnection service below generating facility capacity,” a partial rehearing was granted “to find that an interconnection customer may propose control technologies at any time at which it is permitted to request interconnection service below generating facility capacity.”

They also addressed “the reform that allows interconnection customers to request interconnection service below generating facility capacity,” clarifying that transmission providers “must provide a detailed explanation if it determines additional studies at the full generating facility capacity are necessary when the interconnection customer has requested service below full generating facility capacity.”

The draft order denied other requests for rehearings or clarification.

The draft order will go into effect 75 days after it is published in the Federal Register. Public utility transmission providers have to “submit a single compliance filing, within 90 days of the issuance of this order, to comply with Order No. 845 and this draft order on rehearing and clarification.”

Federal Energy Regulatory Commission (FERC) Chairman Neil Chatterjee testified before the Senate Energy & Natural Resources Committee

Federal Energy Regulatory Commission (FERC) Chairman Neil Chatterjee testified before the Senate Energy & Natural Resources Committee

On February 14, the  Federal Energy Regulatory Commission (FERC) Chairman Neil Chatterjee testified before the Senate Energy & Natural Resources Committee to discuss cybersecurity in the energy industry. Chatterjee had three specific points to bring up in his testimony: “first, the evolution of mandatory reliability standards; second, the voluntary partnerships FERC has established with industry and other agencies; and third, the interdependency of the electric and natural gas systems.”

For the mandatory reliability standards, Chatterjee discussed the ruling under the Federal Power Act that gave FERC “authority to approve mandatory reliability standards developed by the North American Electric Reliability Corporation (NERC).” After these are approved, they become mandatory and either NERC or FERC enforces them. “NERC’s standards for cybersecurity, known as the Critical Infrastructure Protection (CIP) standards, became mandatory and enforceable in 2009.”

In the last ten years, “the CIP standards have matured considerably and now form an effective framework for protections against cyber threats,” Chatterjee said. As a result of the standards maturing, “the need for constant revisions to address discrete issues and, instead, has allowed both FERC and NERC to focus on tackling emerging threats.”  Chatterjee brought up two recent actions that FERC has taken in regard to this. “First, at our October 2018 Commission Meeting, FERC approved NERC’s proposed reliability standards to address supply chain threats. This action is particularly significant given that these specific threats to the energy sector continue to grow. Second, at our July 2018 Commission Meeting, FERC approved a final rule directing NERC to expand reporting requirements for critical systems.”

Chatterjee said the final ruling “directed NERC to develop a standard that requires registered entities to report successful and attempted intrusions into critical systems to NERC’s Electricity Information Sharing and Analysis Center, as well as to the Department of Homeland Security.” The Chairman said this was “an important step toward enhancing the collection and distribution of information on rapidly evolving threats.”

As for voluntary partnerships, Chatterjee said that even though the CIP standards are an “important baseline for cybersecurity practices,” merely complying “is not enough to achieve cybersecurity excellence.” FERC has developed “two-prong approach to address threats to energy infrastructure: mandatory reliability standards overseen by our Office of Electric Reliability, and voluntary initiatives overseen by our Office of Energy Infrastructure Security (OEIS).” OEIS works with partners in state and federal agencies as well as those in the industry “to develop and promote best practices for critical infrastructure security. These initiatives include … voluntary architecture assessments of interested entities, classified briefings for state and industry officials, and joint security programs with other government agencies and industry.”

Chatterjee wants to continue strengthening those partnerships, and in the spirit of that, FERC is holding a joint technical conference with the Department of Energy on March 28. “The conference will explore current threats against energy infrastructure, best practices for mitigation, current incentives for investing in physical and cybersecurity protections, and cost recovery practices at both the state and federal level.”

As for the interdependency of the electric and natural gas systems, Chatterjee expressed his concerns that “because of our nation’s growing use of natural gas for power generation, a successful cyberattack on the natural gas pipeline system could have a significant impact on the electric grid.”

“I recently met with TSA Administrator David Pekoske to discuss pipeline cybersecurity and was impressed by his focus on this vital issue as well as his pledge to taking further action to improve TSA’s oversight of pipeline security. While I think both industry and government have made significant strides toward addressing this issue, I believe more work still needs to be done, and the Commission stands ready to assist in these efforts.”

A full video of Chatterjee’s testimony can be viewed here.