By Mark Sundback, William Rappolt and Andrew Mina
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Law360 (October 16, 2020, 5:49 PM EDT) —
| Mark Sundback |
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| William Rappolt |
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| Andrew Mina |
The Federal Energy Regulatory Commission is tasked with ascertaining and fixing “proper and adequate depreciation and amortization” accounts for various classes of property owned by providers of interstate energy transmission services.[1] FERC is also authorized to investigate and ascertain the actual legitimate cost of property and depreciation thereon, and “other facts which bear on the determination of such cost or depreciation and the fair value of such property.”[2]
Depreciation is defined in FERC’s Uniform System of Accounts as the loss in service value not restored by current maintenance, including from prospective retirements of plants, as well as “obsolescence … [and] changes in demand and requirements of public authorities.”[3] Amortization gradually extinguishes an amount across “a fixed period, over the life of the asset … to which it applies, or over the period during which it is anticipated the benefit [from the asset] will be realized.”[4]
These principles were applied in the U.S. Supreme Court’s decision in Federal Power Commission v. Hope Natural Gas Co.[5] Hope usually is remembered in the context of addressing the adequacy of authorized equity returns, but that case also addressed depreciation.
It found that FERC is not bound to use any single formula or combination of formulae in determining rates,[6] as is suggested by the reference to fair value in the Federal Power Act, or FPA,[7] and the Natural Gas Act, or NGA.[8]
Ratemaking involves balancing ratepayers’ interests against investors’ “legitimate concern with the financial integrity of the company whose rates are being regulated,”[9] such that “the utility is made whole and the integrity of its investment maintained.”[10] The Hope decision asserted at several junctures that “gas is a wasting asset with a diminishing supply,” meaning reserves “are becoming increasingly valuable.”[11]
The Hope court concluded that the pipeline at issue could be extended to attach new supplies “when various present sources of gas supply are exhausted;” hence the property had more than scrap value at the end of its use.[12]
Hope was decided in 1944, when transmission networks in industrial Appalachia faced surging demand for the commodity that appeared increasingly scarce — very different from current circumstances.[13] Instead of facing the growing, relatively untapped market of 80 years ago, hydrocarbon pipelines now confront efforts to eliminate the consumption of those fuels from large parts of the economy — most importantly, electric generation — in time frames that are far shorter (e.g., within 15 years) than service lives utilized for ratemaking purposes.[14]
Various localities have adopted bans on constructing new homes with natural gas connections. Opponents of new transmission facilities have pursued litigation that has delayed construction and increased costs for hydrocarbon-based technologies. Attention has again turned to a carbon tax to address climate change concerns,[15] which, if levied, will disadvantage hydrocarbons, all else equal.
It would be arbitrary and capricious to fail to recognize the impacts on the remaining economic lives of transmission assets of a carbon tax or prohibitions on hydrocarbon-fired electric generation. All the while, FERC continues to insist on applying a 30- or a 35-year depreciable life to transmission facilities, even in the face of changes in “demand and the requirements of public authorities”[16] such as state renewable portfolio mandates and federal proposals for massive decarbonization of electric generation within much shorter periods, such as 15 to 25 years.[17]
In other words, FERC forces transmission facilities to presume continued economic viability long after states eliminate the largest single source of demand for pipelines, according to U.S. Energy Information Administration data. Without prompt recognition of this new reality, regulated transmission owners will not capture adequate levels of depreciation reimbursement, as required by the NGA and the FPA.[18]
Owners would not be made whole, and could not maintain the integrity of their investment, as required by Hope.[19] Resulting rates premised on inadequate depreciation also may no longer be just and reasonable, in accordance with NGA Sections 4 and 5 and FPA Sections 205 and 206.[20]
This means that transmission assets may be stranded long before the end of their physical, or previously estimated economically viable, remaining lives. The Hope-era circumstances of transmission assets able to serve new markets,[21] attracted by the scarcity value of the commodity of energy, is upended now, as end use markets are closed off to hydrocarbons, and commodity prices signal their extraordinary abundance, rather than scarcity.
Thus, the paradigm has shifted. Transmission assets serving natural gas and oil will find their commercial prospects curtailed from entire sectors of the economy. Instead of commodity scarcity, it appears likely that significant hydrocarbon resources previously anticipated as marketable will never be removed from the ground.
Electric transmission assets also may become stranded, especially those serving natural gas-fired generation. Renewable assets, pursuing the windiest or sunniest sites, or distributed energy resources and rooftop solar, will not necessarily be located at the same place as conventional thermal generation facilities, which typically have been located adjacent to sources of large amounts of water used for cooling purposes.
Hence electric transmission systems built around conventional generation usually will not suffice in a market where renewables play the kind of role envisioned by states’ renewable standards. However, electric transmission is not quite in the same position as hydrocarbon transmission, although it will face its own challenges. To the extent electric transmission providers retain substantial demand going forward (albeit serviced by new generation using different locales), they may have a more robust customer base from which to collect stranded costs.
Natural gas-fired electric generation assets also may be stranded. Higher unit costs for conventional resources in the generation stack relative to renewables with no incremental dispatch costs mean the latter will be dispatched in many hours to the exclusion of conventional generation.[22] Both pipeline and high voltage transmission assets serving such generators will be stranded.
Consequently, new, more realistic depreciation schedules are needed for transmission assets that face stranding. FERC has in the past adopted rate alternatives to traditional straight-line amortization to deal with competitive developments facing particular facilities.[23] In one instance, the commission, by implementing levelized rates, effectively caused ratepayers to pay more in the early years of a pipeline’s operation than the amount of accrued book depreciation.[24]
As another example, some oil pipelines have used a unit-of-throughput depreciation methodology. Traditionally, the unit-of-throughput method has been associated with pipeline capacity that has a narrow set of markets, such as a pipeline that can only access production from one field.[25] In the future, throughput constraints may arise not from the supply perspective, but rather from the consumption market, as uses and markets are closed down to oil and natural gas — e.g., due to state renewable portfolios and electrification/decarbonization of transportation.[26]
Depreciation schedules associated with tax rules — e.g., double declining balance — may make more sense for assets exposed to a collapse in demand in the future.[27] Front-loading depreciation may be a technique that has value in a market with falling demand.
Rate derivation is not an academic exercise; it reflects commercial realities facing the transmission operator.[28] Resolving this issue now will avoid or reduce future disputes over whether transmission capacity is used and useful.[29] In light of the significant dislocations and challenges facing energy transmission networks in the U.S., it is high time to reevaluate methodologies for depreciation of those assets.
Failure to do so would thwart both the requirement that the utility is made whole, and the protection of investors’ legitimate concern with the financial integrity of the regulated enterprise, consistent with the statutorily-mandated adequate rate of depreciation.
Mark Sundback and William Rappolt are partners, and Andrew Mina is an associate, at Sheppard Mullin Richter & Hampton LLP.
The opinions expressed are those of the author(s) and do not necessarily reflect the views of the firm, its clients or Portfolio Media Inc., or any of its or their respective affiliates. This article is for general information purposes and is not intended to be and should not be taken as legal advice.
[1] 15 U.S.C. § 717h(a); 16 U.S.C. § 825a(a).
[2] 15 U.S.C. § 717e(a) (2019); 16 U.S.C. § 824g(a)(2019).
[3] 18 C.F.R. § 101 (Definition 12B, “Depreciation”; see also 18 C.F.R. § 201 (which also adds as a relevant factor “the exhaustion of natural resources”).
[4] See 18 C.F.R. Part 201, Definition No. 4 (“Amortization”); 18 C.F.R. Part 101, Definition No. 4.
[5] FPC v. Hope Natural Gas Co., 320 U.S. 591 (1944).
[6] FPC v. Hope Natural Gas Co., 320 U.S. 591, 602 (1944).
[7] 16 U.S.C. § 824g(a).
[8] 15 U.S.C. § 717e(a).
[9] Hope, 320 U.S. at 603.
[10] Hope, 320 U.S. at 606.
[11] Hope, 320 U.S. at 608.
[12] Hope, 320 U.S. at n.6.
[13] According to EIA data, marketed natural gas volumes doubled over the 10 years preceding the Hope decision. See U.S. Natural Gas Marketed Production, Data 1, “U.S. Natural Gas Marketed Production” N90504US2 (2020).
[14] See, e.g., Biden-Sanders Unity Task Force Recommendations (July 8, 2020).
[15] See, e.g., Notice of Technical Conference, Carbon Pricing in Organized Electricity Markets, Docket No. AD20-14-000 (June 17, 2020).
[16] 18 C.F.R. § 101 (Definition 12B, “Depreciation)”; see also 18 C.F.R. § 201.
[17] See e.g., the Virginia Clean Energy Act (S.B. 851/H.B. 1526) of 2020.
[18] 15 U.S.C. § 717h(a); 16 U.S.C. § 825a(a).
[19] Hope, 320 U.S. at n.6.
[20] 15 U.S.C. §§ 717c(a), 717d(a); 16 U.S.C. §§824d(a); 824d(e); 824e(a).
[21] Hope, 320 U.S. at n.6.
[22] FERC has proposed changes in the organized markets’ minimum offer prices of resources in response to concerns about “state subsidies.” See, e.g., Calpine Corp. v. FERC, 169 FERC ¶ 61,239 (2019).
[23] See, e.g., Opin. No. 486, Kern River Gas Transmission Co., 117 FERC ¶ 61,077 at P 22 (2006).
[24] See, e.g., Opin. No. 486; 117 FERC ¶ 61,077 at P 22.
[25] Karapuk Transportation Co., 55 FERC ¶ 61,122 at p. 61,381 (1991); Tennessee Gas Pipeline, 56 F.P.C. at 120, 128 (1976).
[26] See, e.g., Oregon Dept of Environmental Quality Chapter 340, Division 253, 340-253-000 et seq. (latest amendment effective 5/7/20, https://secure.sos.state.or.us/oard/displayDivisionRules.action).
[27] U.S. Dept. of Treasury “A History of Federal Tax Depreciation Policy,” https://ww.treasury.gov/resource-center/tax-policy/tax-analysis/Documents/WP-64.pdf (3/12/20), p. 12.
[28] See, e.g., Order No. 636, FERC Stats. & Regs. ¶ 30,939 at p. 30,393-94, 30,431, 30,433-34 (emphasizing the importance of commercial challenges presented by different types of market participants competing against one another, as well as pipeline-on-pipeline competition).
[29] See, e.g., Jersey Central Power & Light v. FERC, 810 F.2d 1168 (D.C. Cir. 1987).
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