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Commissioner Cheryl A. LaFleur
February 21, 2019
Docket No.
Order Item: C-2 PDF
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Concurrence regarding Northern Natural Gas Company

Today’s order grants Northern Natural Gas Company’s (Northern) request for authorization to construct and operate two projects, the Northern Lights 2019 Expansion Project (2019 Expansion Project) and the Rochester Project.1 After carefully balancing the need for these Projects and the environmental impacts, I find the Projects are in the public interest. For the reasons discussed below, I concur.

Together, the Projects will enable Northern to provide an additional 138,504 Dth/day of firm transportation service in Minnesota. With respect to the 2019 Expansion Project, CenterPoint Energy Minnesota Gas (CenterPoint) and Xcel Energy on behalf of Northern States Power-Minnesota (Xcel Energy), two local distribution companies (LDCs), contracted for 101,411 Dth/day.2 Of that amount, Xcel Energy will deliver 38,000 Dth/day of gas to the Mankato Energy Center.3 The remaining volumes on the 2019 Expansion Project will serve incremental residential, commercial, and industrial end-users within Minnesota, including the Twin Cities.4 The Rochester Project will provide 37,093 Dth/day to the Minnesota Energy Resources Corporation (MERC).

The Environmental Assessment (EA) quantified the direct greenhouse gas (GHG) emissions from the construction and operation of both Projects.5 The EA also quantified the indirect impacts of the downstream emissions from the Mankato Energy Center and the Certificate Order provides the context for the associated downstream GHG emissions by comparing them to the Minnesota GHG inventory and the nationwide GHG inventory.6 While I appreciate that the Commission, as required by the D.C. Circuit in Sierra Club v. FERC,7 quantified and considered the downstream emissions from the Mankato Energy Center, I believe the Commission should not ignore the downstream GHG emissions associated with burning the rest of the natural gas from both the 2019 Expansion Project and the Rochester Project.8

To address my concerns about the Commission’s failure to consider the rest of the downstream emissions impacts in this proceeding,9 I have considered the downstream GHG emissions as part of my public interest determination. Using a methodology developed by the Environmental Protection Agency to estimate the downstream GHG emissions from the 2019 Expansion Project and the Rochester Project, and assuming as an upper-bound estimate that all of the gas to be transported is eventually combusted, 138,504 Dth/d of natural gas service would result in approximately 2.68 million metric tons per year of downstream CO2 emissions. This figure represents a 3.02 percent increase in CO2 emissions in Minnesota,10 and a 0.05 percent increase at the national level.11 I note that Minnesota has announced its intention to replace coal generation with natural gas generation, so the net GHG emissions might be considerably different than the full-burn calculation if we were to offset the emissions from retiring coal-burning units. However, there is a lack of information presented in the record about specific end uses.

I acknowledge that the disclosure of state and national comparison data to provide context to the quantified emissions is only the first step to assist the Commission in ascribing significance to a given rate or volume of GHG emissions. However, to date, the Commission has not identified a framework for reaching a significance determination. As I have previously explained, using the Social Cost of Carbon12 could enable the Commission to assess the significance of GHG emissions.13 While the Commission has argued that monetizing climate damages through the Social Cost of Carbon does not readily lend itself to the Commission’s environmental review of natural gas facilities, I am confident that, given the importance of this issue, the Commission could find a way to adapt and apply a metric such as the Social Cost of Carbon to reach a significance threshold determination. Indeed, the Commission makes challenging determinations on quantitative and qualitative issues in many other areas of our work, but has simply chosen not to attempt a significance determination in this context.14 While making a significance determination on downstream GHG emissions could be difficult, that challenge does not relieve the Commission of its responsibility to address this issue.

Using the approach I originally articulated in Broad Run,15 I find the 2019 Expansion Project and the Rochester Project are in the public interest. For these reasons, I respectfully concur.


    1 Northern Natural Gas Company, 166 FERC ¶ 61,136 (2019) (Certificate Order). While these Projects have independent utility, Northern combined them into one application to avoid environmental segmentation. The Projects overlap in construction time, geography, and hydraulic demands on Northern’s existing system. Application at 3-4.
    2 Certificate Order at PP 7-8.
    3 Application at 8 n. 9. The Mankato Energy Center is a natural gas fired power plant in Blue Earth County, Minnesota.
    5 EA at 121-129 & Tables B.8.3-1, B.8.3-2, B.8.4-1, B.8.4-2, and B.8.4-3.
    6 EA at 163. Certificate Order at P 36.
    7 867 F.3d 1357 (D.C. Cir. 2017); see also Florida Southeast Connection, LLC, 162 FERC ¶ 61,233 (2018) (LaFleur, Comm’r, dissenting in part).
    8 I believe it is reasonably foreseeable, in the vast majority of cases, that the gas being transported by pipelines FERC authorizes will be burned for electric generation or residential, commercial, or industrial end uses and that downstream GHG emissions will result from burning that gas. See Mid States Coalition for Progress v. Surface Transportation Board, 345 F.3d 520, 549 (8th Cir. 2003) (Mid States). In Mid States, the Court concluded that the Surface Transportation Board erred by failing to consider the downstream impacts of the burning of transported coal. Even though the record lacked specificity regarding the extent to which the transported coal would be burned, the Court concluded the nature of the impact was clear.
    9 I have previously expressed my disagreement with the Commission’s policy limiting the disclosure and consideration of downstream and upstream GHG emissions impacts in our project review. See Dominion Transmission Inc., 163 FERC ¶ 61,128 (2018) (LaFleur, Comm’r, dissenting in part).
    11 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2016, (April 2018).
    12 12/documents/social_cost_of_carbon_fact_sheet.pdf
    13 See, e.g., Florida Southeast Connection, 162 FERC ¶ 61,233 (2018) (LaFleur, Comm’r, dissenting in part); Dominion Transmission Inc., 163 FERC ¶ 61,128 (2018) (LaFleur, Comm’r, dissenting in part); and Florida Southeast Connection, LLC, 164 FERC ¶ 61,099 (2018) (LaFleur, Comm’r, dissenting).
    14 Many of the core areas of the Commission’s work have required the development of analytical frameworks, often a combination of quantitative measurements and qualitative assessments, to fulfill the Commission’s responsibilities under its broad authorizing statutes. This work regularly requires that the Commission exercise judgment, based on its expertise, precedent, and the record before it. For example, to help determine just and reasonable returns on equity (ROEs) under the Federal Power Act, Natural Gas Act, and Interstate Commerce Act, the Commission identifies a proxy group of comparably risky companies, applies a method or methods to determine a range of potentially reasonable ROEs (i.e., the zone of reasonableness), and then considers various factors to determine the just and reasonable ROE within that range. See also, e.g., Promoting Transmission Investment through Pricing Reform, Order No. 679, FERC Stats. & Regs. ¶ 31,222, order on reh’g, Order No. 679-A, FERC Stats. & Regs. ¶ 31,236 (2006), order on reh’g, 119 FERC ¶ 61,062 (2007) (establishing Commission regulations and policy for reviewing requests for transmission incentives); Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, FERC Stats. & Regs. ¶ 31,323 (2011), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh’g and clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014) (requiring, among other things, the development of regional cost allocation methods subject to certain general cost allocation principles); BP Pipelines (Alaska) Inc., Opinion No. 544, 153 FERC ¶ 61,233 (2015) (conducting a prudence review of a significant expansion of the Trans Alaska Pipeline System). I also note that the Commission is currently actively considering a broad topic – resilience – whose scope and complexity might similarly require the development of new analytical frameworks for conducting the Commission’s work.
    15 Tennessee Gas Pipeline Company, 163 FERC ¶ 61,190 (2018) (LaFleur, Comm’r, concurring) (Broad Run). See RH enerytrans, LLC, 165 FERC ¶ 61,218 (2018) (LaFleur, Comm’r, concurring) (“I am trying to move beyond my disagreement with the Commission’s approach to its environmental review of proposed pipeline projects, and base my public interest determination on the facts in the record—even ones not discussed in our environmental documents or in the certificate order.”). See also Texas Eastern Transmission, LP, 165 FERC ¶ 61,132 (2018) (LaFleur, Comm’r, concurring); and PennEast Pipeline Company, LLC., 164 FERC ¶ 61,098 (2018) (LaFleur, Comm’r, concurring in part and dissenting in part).
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