Tag: FERC

FERC Approves First Compliance Filings on Landmark Storage Rule

FERC Approves First Compliance Filings on Landmark Storage Rule

The Federal Energy Regulatory Commission (FERC) approved two orders to implement Order No. 841, which is a “landmark storage rulemaking aimed at breaking down market barriers to electricity storage.” Order No. 841 was enacted in February 2018, and it “addresses the participation of electric storage resources in the capacity, energy, and ancillary service markets operated by organized wholesale power markets to more effectively integrate electric storage resources, enhance competition and help ensure that those markets produce just and reasonable rates.”

It “requires each organized power market to revise its tariff to establish a participation model consisting of market rules that recognize the physical and operational characteristics of electric storage resources and facilitate their participation in those markets.”

FERC Chairman Neil Chatterjee said “Electricity storage must be able to participate on an even playing field in the wholesale power markets that we regulate. Breaking down these market barriers encourages the innovation and technological advancements that are essential to the future of our grid.”

The orders they ruled in October 2019 address “compliance filings of Southwest Power Pool (SPP) and PJM Interconnection (PJM).” The two operators were found to have generally complied with the rule, but there was a need for further action. FERC “initiated proceedings under section 206 of the Federal Power Act to address the specific issue of minimum run-time requirements.”

“FERC found that both SPP’s and PJM’s proposals generally enable electric storage resources to provide all services they are capable of providing; allow electric storage resources to be compensated for those services in the same manner as other resources; and appropriately recognize the unique physical and operational characteristics of electric storage resources.” They were instructed by FERC to submit compliance filings within 60 days.

The tariffs for both of the operators do “generally satisfy Order No. 841’s directive allowing electric storage resources to de-rate their capacity to meet minimum run-time requirements, FERC also found that neither market includes in its tariff minimum run-time requirements for resource adequacy and capacity.” Since these can impact rates and the terms and conditions of service, FERC “instituted 206 proceedings, and directed SPP and PJM to submit tariff provisions reflecting their rules and practices regarding resource adequacy minimum run-time requirements and capacity minimum run-time requirements, respectively, for all resource types.”

PJM and SPP have to submit the tariff provisions within 45 days of the 206 notice’s publication in the Federal Register.

Related documents in this ruling:

Order E-1

Order E-2

Presentation

Statement from Commissioner Bernard L. McNamee on E-1

Statement from Commissioner Bernard L. McNamee on E-2

FERC Releases Final HDD Guidance Plan

FERC Releases Final HDD Guidance Plan

The Office of Energy Projects finalized the Federal Energy Regulatory Commission’s (FERC) Guidance for Horizontal Directional Drill Monitoring, Inadvertent Return Response, and Contingency Plans (HDD Guidance).

After FERC released its draft of the HDD Guidance, they “received comments from 15 entities including natural gas pipeline companies, engineering consulting firms, trade organizations, environmental interest groups, and state environmental departments.” Those led FERC to make revisions to address those comments. The comments that “either were too location-specific, were already adequately/accurately addressed as written, or regarded topics that were not relevant to the HDD Guidance” were not included in the modifications.

“The HDD Guidance is intended to assist the industry with preparation of their project HDD plans for FERC staff review.” FERC stressed that the “guidance does not substitute for, amend, or supersede the Commission’s regulations under the Natural Gas Act of 1938 or the Commission’s and Council on Environmental Quality’s regulations under the National Environmental Policy Act.” It does not grant additional rights or impose new legal obligations.

“The purpose of this guidance is to describe the technical components of an HDD Plan including drilling fluid composition and management, monitoring procedures, and response procedures for an inadvertent return of drilling fluid to the ground surface (IR).” They also provided an outline for an HDD Plan, which is formatted into “an effective presentation based on our experience, but is not mandatory and may be modified (including the use of footnotes where necessary for clarification) for individual projects.”

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.

FERC Streamlines Processes for Market-Based Sellers

FERC Streamlines Processes for Market-Based Sellers

The Federal Energy Regulatory Commission (FERC) has finalized a set of rules to help “ease the regulatory burden for electric power sellers with market-based rate authority,” while making sure that FERC keeps preventing the “potential exercise of market power.”

The first rule “concerns the horizontal market power analysis required for market-based rate sellers.” They have eliminated the “obligation to submit indicative screens in order to obtain or retain market-based rate authority in certain organized wholesale power markets.” The sellers will not have to “submit the pivotal supplier screen and the wholesale market share screen in any organized wholesale power market that administers energy, ancillary services, and capacity markets subject to Commission-approved monitoring and mitigation.”

In the organized markets that “do not administer capacity markets” with the FERC approved monitoring and mitigation, “that is the Southwest Power Pool and California Independent System Operator, market-based rate sellers will be required to submit analyses if they wish to sell capacity there. All market-based rate sellers still would be required to file a vertical market power analysis as well as an asset appendix, which provides comprehensive information relevant to determine a seller’s market power and ensure just and reasonable rates.”

The second rule FERC finalized will help improve their “monitoring of wholesale power markets by streamlining the way it collects certain data for market-based rate purposes, specifically collecting this information in a database. The approved changes will eliminate duplication, minimize compliance burdens, modernize data collections, and make information collected through its programs more usable and accessible for the Commission, its staff, and the public.” One of the main things this rule does is adopt changes to help “reduce and clarify the scope of ownership information that sellers must provide as part of their market-based rate filings, revises the information required in a seller’s asset appendix as well as the format through which such information must be submitted, and eliminates the requirement that sellers submit corporate organizational charts.”

FERC issued a Notice of Proposed Rulemaking about this in July 2016, proposing to “collect connected entity data from market-based rate sellers and entities that trade virtual products or hold financial transmission rights;” the final rule did not adopt that proposal.

The first rule will go into effect 60 days after it is published in the Federal Register.

The second rule will go into effect on October 1, 2020.

FERC Commissioner Richard Glick issued a statement dissenting the second rule and explaining his choice to do so.

Glick said that while he does support some aspects of the rule “that streamline collection of the data needed to regulate market-based rates by creating a relational database and revising certain information requirements.” He noted that he dissented because FERC “is declining to finalize a critical aspect of the underlying notice of proposed rulemaking that would have required Sellers and entities that trade virtual products or that hold financial transmission rights (Virtual/FTR Participants) to report information regarding their legal and financial connections to various other entities.” He said that this “information is critical to combatting market manipulation and the Commission’s retreat from the NOPR proposal will hinder our efforts to detect and deter such manipulation.”

Glick explained that the context is important in policing market manipulation, and “a transaction that seems benign when viewed in isolation may raise serious concerns when viewed with an understanding of the relationships between the transacting parties and/or other market participants. Unfortunately, information regarding the legal and contractual relationships between market participants is not widely available and may, in some cases, be impossible to ascertain without the cooperation of the participants themselves.  That lack of information can leave the Commission in the dark and unable to fully monitor wholesale market trading activity for potentially manipulative acts.”

The problem is more acute, Glick explained, “when it comes to market participants that transact only in virtual or FTR products.  Virtual/FTR Participants are very active in RTO/ISO markets and surveilling their activity for potentially manipulative acts consumes a significant share of the Office of Enforcement’s time and resources.” He said it may be somewhat surprising that FERC collects “limited information about Virtual/FTR Participants and often cannot paint a complete picture of their relationships with other market participants.” FERC also has “no mechanism for tracking recidivist fraudsters who deal in these products and perpetuate their fraud by moving to different companies or participating in more than one RTO or ISO.  And, perhaps most egregiously, the Commission’s current regulations do not impose a duty of candor on Virtual/FTR Participants, meaning that bad actors can lie with impunity, at least insofar as the Commission is concerned. The abandoned aspects of the NOPR would have addressed all three deficiencies, among others.”

There can be consequences to having those deficiencies, Glick said, citing a recent example of a FERC order of “how an individual involved in one manipulative scheme was able to move, rather seamlessly, to allegedly perpetuate a similar scheme at another entity.” FERC “issued an Order to Show Cause with an accompanying report and recommendation from the Office of Enforcement that detailed how Federico Corteggiano allegedly engaged in a cross-product market manipulation scheme in the California Independent System Operator’s (CAISO). As described in that order, this alleged scheme used techniques that were similar to another manipulative scheme involving Corteggiano while he was employed at Deutsche Bank. Without the Connected Entity reporting requirements contemplated in the NOPR, the Commission lacks any effective means of tracking individuals who perpetrate a manipulative scheme at one entity and then move locations and engage in similar conduct elsewhere, as Corteggiano is alleged to have done. That makes no sense. We should not be leaving the Office of Enforcement to play ‘whack-a-mole,’ addressing recidivist fraudsters only when evidence of their latest fraud comes to light.”

Glick also used the example of “GreenHat Energy, LLC’s (GreenHat) default on its FTRs in PJM Interconnection, L.L.C. (PJM), at least as it is described in an independent report prepared for PJM’s Board.” In the report, there are allegations that “GreenHat told PJM it had bilateral contracts that would provide a future revenue stream, alleviating the need for additional collateral. 10   The report further contends that PJM mistakenly relied on GreenHat’s representations and the contracts in question did not provide the promised revenue stream, significantly exacerbating GreenHat’s collateral shortfall.” He said that under the current regulations, “no duty of candor attached to GreenHat’s allegedly misleading statements.  It is, of course, impossible to know how a duty of candor for Virtual/FTR Participants would affect potential misstatements.  But, if there were a duty of candor for Virtual/FTR Participants, it would give the Commission a basis for investigating potentially misleading statements and, if appropriate, sanctioning that conduct.”

Glick said that while FERC “does not dispute the benefits that the Connected Entities Information would provide, it ‘declines to adopt’ this aspect of the NOPR without any real analysis or explanation and based only on its ‘appreciat[ion]’ of the ‘difficulties of and burdens imposed by this aspect of the NOPR.'” There is nothing to suggest in the record that the associated burdens this reporting obligation may cause would outweigh the benefits. The Notice initially “paired back the scope of Connected Entity Information compared to the previous NOPR addressing this issue.” He believes that FERC “could have further explored ways to limit the impact of this rule if it were truly concerned about that burden by, for example, eliminating the inclusion of contracts for defining connected entities, which received strong pushback from industry.  Alternatively, the Commission could have established a phased-in implementation schedule to provide industry time to adjust to the new reporting requirements.”

Instead, FERC made a “conclusory statement based on an unspecified burden to industry.  It makes no effort to explain why that burden outweighs the benefits that Connected Entities Information would provide to the Commission’s ability to carry out its enforcement responsibilities.  Without such information, the predictable result of today’s order is that market participants are more likely to find themselves subject to a manipulative scheme than if we had proceeded to a final rule on these aspects of the NOPR.”

Glick said that one of FERC’s chief priorities should be “identifying, eliminating, and punishing market manipulation,” which it has been since 2005 when “Congress vested the Commission with that responsibility” when amendments were made to the “FPA in the wake of the Western Energy Crisis. In addition to the financial losses directly attributable to a particular instance of fraud, market manipulation erodes participants’ confidence in wholesale electricity markets—a dynamic that has serious deleterious consequences for the long-term health and viability of those markets.” He said he can “appreciate the importance of avoiding unnecessary regulatory burdens, the record in this proceeding indicates that the Connected Entity Information is necessary and would, in the long-term, benefit all market participants, including those subject to the regulations, by helping to ensure confidence in the integrity of wholesale electricity markets.”

The Importance of Properly Winterizing Electric Generation Facilities

The Importance of Properly Winterizing Electric Generation Facilities

The Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corporation (NERC) released a report to stress “the need for generation owners and operators to adequately prepare for winter weather conditions to ensure bulk electric system reliability.”

Abnormally low temperatures on January 17, 2018, led “regional operators in the Midwest and South Central U.S. (MidContinent Independent System Operator and Southwest Power Pool)” to call for voluntary reductions in electricity use. The system managed to stay stable during this cold front. “However, continued reliable operation would have required shedding firm load if MISO had experienced its largest single generation contingency in MISO South.”

The report found that “despite prior guidance from FERC and NERC, cold-weather events continue to result in unplanned outages that imperil reliable system operations.” The report recommends the creation of “one or more mandatory Reliability Standards requiring generator owner/operators to prepare for the cold weather and provide information about those preparations to their Reliability Coordinators and Balancing Authorities.”

In addition to developing a Reliability Standard, the report suggested that “enhanced outreach and actions by system operators to encourage generator performance can also help to prevent a recurrence of the large-scale unplanned outages like those seen during this event, the 2014 Polar Vortex and the 2011 Southwest cold weather event.”

FERC’s report also found that it was not just a failure to winterize the generation facilities properly, there were issues with the gas supply that contributed to the event.

FERC and NERC had several recommendations and sound practices to help in future cold-weather events, including:

  • “Generator owners and operators should perform winterization activities to prepare for cold weather, and should ensure the accuracy of their units’ ambient temperature design specifications;
  • “Balancing Authorities and Reliability Coordinators should be aware of generating units’ specific limitations, such as ambient temperatures beyond which they cannot be expected to perform or the lack of firm gas transportation;
  • “Planning coordinators and transmission planners should jointly develop and study scenarios to be better prepared for seasonal extreme weather conditions; and
  • “Transmission owners and operators should conduct analyses that delineate different summer and winter ratings for both normal and extreme conditions.”

The full report can be viewed here.

Final EIS Issued for Texas LNG Project

Final EIS Issued for Texas LNG Project

The Federal Energy Regulatory Commission (FERC) has issued a final environmental impact statement (EIS) for the Texas LNG Project that Texas LNG Brownsville, LLC (Texas LNG) proposed.

Texas LNG requested authorization to “site, construct, and operate a liquefied natural gas (LNG) terminal (LNG terminal) to liquefy and export natural gas at a proposed site on the Brownsville Ship Channel in Cameron County, Texas.”

The pipeline project will consist of the following facilities:

  • “gas gate station and interconnect facility;
  • “pretreatment facility to remove water, carbon dioxide, hydrogen sulfide, mercury, and heavier (pentane and above) hydrocarbons;
  • “a liquefaction facility consisting of two liquefaction trains and ancillary support facilities;
  • “two approximately 210,000 cubic meter (m3) aboveground full containment LNG storage tanks with cryogenic pipeline connections to the liquefaction facility and berthing dock;
  • “an LNG carrier berthing dock capable of receiving LNG carriers between approximately 130,000 m3 and 180,000 m3 in capacity;
  • “a permanent material offloading facility to allow waterborne deliveries of equipment and materials during construction and mooring of tug boats while an LNG carrier is at the berth;
  • “thermal oxidizer, warm wet flare, cold dry flare, spare flare, acid gas flare, and marine flare; and
  • “administration, control, maintenance, and warehouse buildings and related parking lots; electrical transmission line and substation, water pipeline, septic system, and stormwater facilities/outfalls.”

The natural gas delivered to the project site will come from a “non-jurisdictional intrastate, 30-inch-diameter natural gas pipeline that would be constructed, owned, and operated by a third party, separate from Texas LNG.”

The FERC staff prepared the EIS “in compliance with the requirements of the National Environmental Policy Act (NEPA), the Council on Environmental Quality regulations for implementing NEPA in Title 40 Code of Federal Regulations, Parts 1500–1508 (40 CFR 1500-1508), and FERC regulations implementing NEPA (18 CFR 380).”

FERC asserted that the recommendations and conclusions in the EIS are those of the FERC staff alone, though they did consider the input in their determinations from: “the U.S. Army Corps of Engineers, U.S. Coast Guard, Department of Energy, U.S. Department of Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration, the DOT’s Federal Aviation Administration, the U.S. Fish and Wildlife Service (FWS), the National Park Service, the U.S. Environmental Protection Agency, and the National Oceanic and Atmospheric Administration – National Marine Fisheries Service (NMFS).” While those agencies did act as cooperating agencies during FERC’s determinations, those agencies may still make their own determinations on the EIS after an independent review.

FERC concluded that the Texas LNG Project’s construction and operation would have adverse effects on the environment, but the impacts could “be reduced to less than significant levels with the implementation of Texas LNG’s proposed impact avoidance, minimization, and mitigation measures and the additional measures recommended by FERC staff, with the exception of visual resources.”

“The Texas LNG Project, combined with other projects in the geographic scope, including the Rio Grande LNG and Annova LNG Projects, would result in significant cumulative impacts from sediment/turbidity and shoreline erosions within the Brownsville Ship Channel during operations from vessel transits; on the federally listed ocelot and jaguarundi from habitat loss and potential for increased vehicular strikes during construction; on the federally listed aplomado falcon from habitat loss; and on visual resources from the presence of above ground structures.”

The conclusions FERC reached were based on “information provided by Texas LNG and through data requests; field investigations; literature research; geospatial analysis; alternatives analysis; public comments and scoping sessions; and coordination with federal, state, and local agencies and Native American tribes.” The factors considered in their conclusions were:

  • “The LNG terminal would be constructed in an area currently zoned for commercial and industrial use, along an existing, man-made ship channel.
  • “Texas LNG would follow its Spill Prevention and Response Plan (construction), Spill Prevention Control and Countermeasures Plan (operation), Stormwater Pollution Prevention Plan, Noxious Weed and Invasive Plant Plan, Facility Lighting Plan, Migratory Bird Plan, Terrestrial Reptile and Amphibian Conservation Plan, Unanticipated Discovery Plan for cultural resources, and Fugitive Dust Control Plan.
  • “The U.S. Coast Guard issued a Letter of Recommendation indicating that the Brownsville Ship Channel would be considered suitable for the LNG marine traffic associated with the Project.
  • “The U.S. Department of Transportation has no objection to Texas LNG’s methodology to comply with the 49 CFR 193 siting requirements for the LNG terminal.
  • “All appropriate consultations with the FWS and NMFS regarding federally listed threatened and endangered species would be completed before construction is allowed to start.
  • “All appropriate National Historic Preservation Act consultations with the Texas State Historic Preservation Office and Advisory Council on Historic Preservation would be completed before construction is allowed to start in any given area.
  • “Texas LNG would implement its Project-specific Environmental Construction Plan, which incorporates our Upland Erosion Control, Revegetation, and Maintenance Plan and Wetland and Waterbody Construction and Mitigation Procedures, to minimize impacts on soils, wetlands, and waterbodies.
  • “The FERC’s environmental and engineering inspection and mitigation monitoring program for this Project would ensure compliance with all mitigation measures and conditions of any FERC authorization.”

FERC also “developed site-specific mitigation measures that Texas LNG should implement to further reduce the environmental impacts that would otherwise result from construction of the Project.”

The EIS can be read in full here:

Volume I of the Environmental Analysis

Volume II of the Appendices