Regions of the country adhering to the Restructured Administrative Market Model (RAMM), particularly in its ‘purest’ forms, are having a tough go of it lately.
Between state interventions with particular energy policy preferences that impact the pricing system, to Federal Energy Regulatory Commission decisions on whether — and how much — to accommodate particular state energy policy goals, to federal appellate challenges from merchant power suppliers to these state interventions, the integrity of the RAMM has been rejected by the political economy of various federal and state regulators and legislators.
It should be enough to make a RAMM supporter take pause when the reaction to “market” outcomes is the individual states responding with a game of Mad Libs: “Yes, but, our policy is to change the outcome[s] with [subsidies], [resource mandates], [price supports], and/or [tax preferences].”
Commentaries on how political economy intrudes into market outcomes for vital resources and products — be they nuclear plants or steel and aluminum tariffs — is second nature for exasperated economists from Adam Smith to Paul Krugman. In the electricity sphere, exasperated “market” defenders are forced to retreat from defending markets per se to the weaker claim that the RAMM is, in any event, better than monopoly regulation.
An alternate prism
We propose an alternate prism for consideration: Which permutation of monopoly is to be preferred? The purer RAMM of NE-ISO, NY ISO, PJM and ERCOT or the joint dispatch, rate-based approach used in SPP and MISO and, generally speaking, traditional state-based vertically integrated monopolies? Each is a particular species of monopoly, with its own strengths and weaknesses. But the fundamental question is one of comparative institutional monopolies and their regulation, not one of “markets” versus “monopolies.”
So what do we mean by each model is a monopoly in its own way?
For starters, the traditional vertical state-regulated monopoly is relatively straightforward: State law permits a single electric provider to supply service in a given territory and then regulates it through administrative, cooperative or municipal ownership institutions, respectively. All electric distribution systems partake of this monopoly character. To be sure, certain market mechanisms are used by states. Competitive bidding for wholesale power supply has been a feature of vertically integrated states for decades now, and bi-lateral power contracting, along with the “build/buy” question for utilities, is regularly confronted, along with attendant distortions inherent in cost-of-service regulation. Nevertheless, the competitive bidding market mechanisms used in some states are quite robust.
The RAMM operators, meanwhile, are worthy monopolists in their own right and must embrace their own monopoly fiats. There is a voluntary step in joining the RAMM, but once joined, RAMM authority controls all transactions within the prescribed territory. To be sure, bilateral transactions are permitted but within a closely superintended construct. Sounds a lot like a single entity driving the scope, terms and nature of a transaction. If it acts like a monopoly, and can drive terms like a monopoly, and does not allow exit from its superintendence, then let’s call it a monopoly.
A perusal of the RAMM operator structures supports this conclusion. Take Section IV.A of the ISO-NE tariff, entitled “Recovery of ISO Administrative Expenses.” It spells out rates and charges provided by the ISO relating to scheduling, system control, dispatch, energy administration service, and reliability administration service. Then it unveils the monopoly fingerprints: “The rates and charges for each Service during a calendar year are based on the allocated portion of that year’s Revenue Requirement. ‘Revenue Requirement’ refers to the budgeted total expense for the year as adjusted by true-ups described herein.” The “revenue requirement” is the centerpiece of any monopoly utility’s rate case. A “true-up” finds it home in any monopoly utility’s rate riders.
A tour out of New England south into PJM reveals a similar construct. PJM — to its credit — makes it clear here. PJM provides it “does not make money,” but that is not synonymous with the notion that “PJM does not recover its costs.” To the contrary, “PJM recovers its administrative costs — the costs of operating the electric transmission system and the wholesale electricity markets — through fixed rates billed to members based on their activity levels.” Sound familiar?
The graph below from PJM provides a “sample budget” that forms the illustrative basis for administrative costs recovered from members, with cost recovery breaking out approximately as follows: 75% from load-serving entities, 20% from other generation owners and 5% from financial marketers and traders.
This graph would be equally at home in the testimony of a monopoly utility’s cost of service witness as it is on the website of the “electricity market” for this region of the country. PJM recovers compensation costs and costs of outside services, including “cost for contractors and consultants.” Recovery of these types of costs is of high controversy in monopoly utility rate cases, yet on the “market” website, they hide in plain sight.
The “Depreciation and Interest” bucket is defined on the site as “the gradual payment of PJM’s capital expenditures and related debt financing over the period during which an asset is expected to be usable for the purpose it was acquired.” This is a good synopsis of the recovery of costs associated with monopoly utility-owned assets. It is PJM’s revenue requirement.
ERCOT: The purest RAMM
Which brings us finally to ERCOT, the purest expression of the RAMM model. ERCOT recovers its costs consistent with a fee schedule, the most significant of which is the ERCOT System Administration Fee (SAF). The SAF is explained on the current fee schedule as follows “$0.555 per MWh to fund ERCOT activities subject to Public Utility Commission of Texas (PUCT) oversight. This fee is charged to all Qualified Scheduling Entities (QSEs) based on Load represented.” The SAF was increased from 46.5 cents/MWh to 55.5 cents/MWh beginning in 2016. How did we get there?
Easy — just like PJM does, but without the helpful illustration.
First, ERCOT had lighter energy demand than forecasted in the early months of 2015, resulting in a projected revenue shortfall of approximately $5 million. ERCOT, identifying a revenue deficiency, reacted as any monopoly utility would, and swiftly moved to correct for that deficiency. ERCOT set budgets of approximately $220 million for 2016 and $223 million for 2017, from which it derived the revised SAF. These budgets and the revised SAF were then approved by the PUCT which must approve the budgets and the SAF. Again, this parallels the trials and travails of the monopoly utility, where state commissions approve the revenue requirement and rate design, sometimes separately and sometimes together.
It is all a cost of service regime.
The superintendence and cost structures described above indicate we have monopoly permutations operating and serving electricity customers in each region of the country. Let us keep this in mind and at the forefront of discussions as we continue down the road of evaluating state “market interventions,” i.e., ‘around market’ solutions, and looking at issues in the resilience docket before FERC.
The trusty fallback of “markets are great” and “markets are working great” just cannot cut it anymore, because these are not markets at all. We have alternate monopoly structures using ersatz, non-emergent pricing schemes to accomplish market ends dictated by regulators, advocates and suppliers. Some institutional arrangements may be better than others based on the political economy of a given state or region. But, let’s be clear that central planning is the core tenet of RAMM, just as it is with traditional monopoly service providers.
Ray Gifford is the managing partner and Matt Larson a partner in the Denver office of Wilkinson Barker Knauer LLP.