HRC or member-contributedFERC conducts economic analysis for projects using the methodology required by the 1995 Mead decision, which prevents forecasting energy prices. While this made sense at the time, climate change and renewable energy sources make this approach outdated. For a deeper dive into how the Mead policy works, check out this assessment of the first couple years of implementation.
By David Marcus on behalf of the Hydropower Reform Coalition.
I. Introduction and summary
A. Introduction
In its Mead decision of July 13, 1995, FERC modified its economic analysis methodology to cease considering the potential effects of inflation on project economics. It also reemphasized that project economics are not a decision criterion for approval/disapproval of a project. At the same time, individual mitigation measures continue to be accepted or rejected based on cost, with FERC citing its balancing obligation under Federal Power Act (FPA) section 10(a) as the basis for rejecting mitigation measures that are “too expensive.”[1] This paper examines the ways in which FERC computes and uses dollar costs and values for the power and non-power aspects of the projects it licenses. It looks both at economic (ie., dollar-denominated) analysis of projects as a whole and economic analysis of individual measures proposed as project conditions.
I have reviewed over 60 FERC documents issued in the last two years, dealing with more than 90 separate FERC projects.[2] The economic analyses in these documents show an enormous range of net economic values for the various projects, and an enormous range of alternative power costs. For individual projects, FERC estimates alternative power costs from 1.7[3] to 12.1[4] cents per kwh. Estimated net values (alternative power cost minus hydro project cost) for proposed projects range from over 5 cents per kwh[5] to under -5 cents per kwh.[6] The only common thread is that in no case has either FERC or its staff denied or proposed to deny a license.
Since the Mead decision cost can be a factor in deciding whether FERC will include a proposed mitigation measure as a license condition, but cost is not a factor in deciding whether or not to award a license. Cost can thus limit how much mitigation is required as a licensing condition, but not whether a project should be licensed at all.
A closer review shows that FERC appears to consider costs only in very limited ways. Overall project economics (often referred to in FERC documents as the “ANB,” or “annual net benefits” of a project) rarely if ever affects a staff proposal or a FERC licensing decision. Only occasionally is an individual mitigation measure rejected because it would be costly compared to net project benefits, and other mitigation measures are routinely accepted even when net project benefits are negative. FERC does not generally use total mitigation costs as a decision criterion for anything, nor does FERC use net project value as a decision criterion. Projects are approved or proposed for approval even when their computed costs are as much as twice the cost of alternative sources of power, resulting in strongly negative ANBs.[7]
The fact that overall net project value doesn’t matter in deciding whether to grant a license doesn’t mean that mitigation measures are not rejected because of their cost. Mitigation measures appear to be singled out for more critical review when their dollar costs are relatively high compared to the total energy value of the proposed project.[8] FERC frequently rejects specific mitigation measures on the basis that the cost of the particular measure is too high compared to the benefits that the particular measure would provide.[9] But when it does so, it does so on an ad hoc basis, with (almost always) no quantification in dollar terms of the benefits of the mitigation measure which it is rejecting as too costly. Conversely, mitigation measures that are required are almost never justified on an economic basis, but are simply asserted to produce nonpower values (e.g., environmental or recreation benefits) greater than their costs. Some mitigation measures are simply included on the basis that an agency required them pursuant to FPA sections 4(e) or 18, with no environmental or economic justification given at all.
B. Summary of findings and recommendations
My review of NEPA documentation and licenses issued in the 18 months since Mead shows that FERC analyzes the economic costs, but rarely the values, of the nonpower aspects of projects.[10] Thus, perhaps not surprisingly, well over 1/3 of all projects are reported to have negative net economic values.[11] For power generation, both cost and value are calculated.[12] However, power value analyses are frequently flawed by inaccurate assumptions about the source, characteristics, and costs of replacement generation in the event of license denial.[13] Decommissioning costs are rarely taken into account.[14] Cost inflation is (intentionally) ignored, yet future costs are discounted at high rates which make no sense in the absence of inflation.[15]
FERC’s economic analysis methods facilitate the inappropriate rejection of mitigation measures with large environmental, recreational, or other nonpower benefits. They also make license denial almost impossible, even when FERC openly admits that dam removal would be environmentally preferable.
I conclude that there are several ways FERC could improve its economic analysis. These include a greater use of market prices to evaluate replacement energy costs and use of a lower discount rate for future costs.[16] Decommissioning costs should be incorporated into both FERC’s economic calculations[17] and its licensing decisions.[18] Perhaps most importantly, FERC should perform far more quantification of the dollar benefits (or costs) of the nonpower aspects of projects. Particularly where mitigation measures with both high dollar costs and large environmental benefits are involved, the current subjective balancing of dollars against environmental quality can be greatly improved.[19] FERC should focus on the forward-looking costs and benefits of projects, not their past costs, if only to avoid exacerbating stranded cost problems during this era of electric power restructuring.[20] Finally, FERC should reopen the possibility of letting overall project value affect licensing decisions, contrary to Mead. FERC should consider whether a project license should ever be denied or further conditioned in response to a strongly negative net project economic value.[21]
[1] Of course FERC also rejects mitigation measures on other grounds, such as a lack of evidence that they will produce any actual environmental benefit. The discussion of mitigation measures in this paper focusses on the role of economics in choosing the acceptable set of mitigation measures.
[2] See Appendix A. 18 of the projects have been licensed, with the rest recommended for license approval by FERC staff.
[3] Dairyland project, FERC #1960, Flambeau R., WI
[4] Bear Swamp Pumped Storage, FERC #2334, MA.
[5] Ripogenus (FERC #2572, ME), Cloquet (FERC #2363, MN), and Bear Swamp PS (FERC #2334, MA) projects.
[6] Condit (FERC #2342, WA) project FEIS, October 1996, pp. 5-17, 5-18.
[7] E.g., the Enloe Dam project in Washington (FERC #10536), licensed 9/13/96, with a forecast project cost of 54 mills/kwh and an alternative cost of power to the licensee of 28 mills per kwh. See also FERC project #s 2283, 11482, and 10854, in each of which FERC staff has proposed licensing with conditions that make the proposed project more than twice as expensive as non-hydro alternatives. Finally, FERC staff has proposed licensing the new Felts Mill project in New York (FERC #4715, 9/96 FEIS) and relicensing the existing Condit project in Washington (FERC #2342, 10/96 FEIS) at costs with mitigation conditions of more than triple the cost of alternative sources of power.
[8] The value of the energy output of the project is computed by converting the project’s megawatt (Mw) and kilowatthour (kwh) output into dollar terms. It is a gross value, before netting out the cost to produce those Mw and kwh.
[9] See Appendix A.
[10] Section II.B.1.
[11] Section II.D.1.a.
[12] Section II.A.2.a.
[13] Section II.A.2.c.(2)(c)
[14] Section II.C.
[15] Section II.A.2.c.1.
[16] Sections II.E.1.c-d.
[17] Section II.E.1.a.
[18] Section II.E.2.a.
[19] Sections II.E.1.b., II.E.2.b., and II.E.2.d.
[20] Section II.E.2.c.
[21] Section II.E.2.e.
