Read the RTO Rule. You'll see that it paves the way for transcos.
On Dec. 20, the Federal Energy Regulatory Commission hit the streets (both Wall and Main) with Order 2000, its rule on regional transmission organizations (RTOs). Ever since, utilities, investors and their advisers have been poring through the 727 pages of the document. They want to know, "What does the FERC really want?"
The question is not simply academic. On March 1 in Cincinnati, the FERC will open the first of five collaborative workshops to explore the RTO Rule and help the industry respond. Other workshops will follow: in Philadelphia (March 15-16), Las Vegas (March 23-24), Kansas City (March 29-30) and Atlanta (April 5-6).
Nevertheless, even as we look forward to the collaborative process, some in the industry with an ax to grind have already jumped the gun, offering their own interpretations of the RTO Rule and what the commission wants and intends, with varying degrees of accuracy.
Winston Churchill once wrote that a lie travels halfway around the world before the truth can pull on a boot. Myths move fast, too. Yet we hope to help the industry start walking along the proper path.
In this article, we touch on some of the major points of contention over Order 2000 - myths we have heard about the RTO Rule and the FERC's expectations. To do that, we make a reasoned effort to debunk the top 10 myths about Order 2000 (giving page citations to the original text to buttress our points). We list the myths in descending order of the degree of currency attained by each. Beyond that, we rely only on the power of sunlight - "the best disinfectant," as Justice Brandeis would say.
Myth No. 1: Volunteer ¼ or Else!
Reality: or else the market will pass you by
Most of the initial discussion about Order 2000 pertained to whether the FERC "mandated" that utilities must join RTOs, or whether it "sort of" mandated, or maybe "will mandate."
Indeed, the question of voluntary or mandatory approach lay at the heart of the debate at the FERC over the RTO Rule. Choose "voluntary" and you must line the road to RTOs with incentives and flexibility. Choose "mandatory" and you need only point to the destination. The FERC would then start to think about so-called "second generation" issues.
We understand that people involved in policy or politics like to choose winners and losers. "Spin" is "in." We know the industry likes to spend a lot of energy on the question, "Who won?" In fact, in a political city in an election year, the "losers" likely will refuse to concede.
Nevertheless, the regulated utilities want to do what FERC expects of them. On that score, the FERC has a record of speaking from behind the curtain. Recall the efforts of a majority in the late 1980s through the mid-1990s to enact open access through mergers and market-based rates.
In the context of the actual rule, however, the debate on whether a mandate is present amounts to a sideshow at a carnival. Read the regulatory text. Analyze the Preamble. Listen to the speeches of every commissioner. The FERC listed eight specific innovative pricing proposals (translated: incentives) that it will consider for RTOs. The commission indicated all over the 727 pages of Order 2000 that flexibility will rule the day when it comes to the mechanics of fulfilling the 12 goals the rule outlines for RTOs.
Of course, it is true that the FERC "expects" utilities to join RTOs! However, this "expectation" follows from incentives, not mandates.
Once the FERC chose the path of incentives and flexibility, nothing else mattered. It remains to be seen whether the FERC will take a more direct role in the future, after it has analyzed the initial filings that will come in as late as Jan. 15, 2001. No one can predict what utilities will list as the reasons for not joining.
We think the incentives the FERC has laid out will do the trick, with maybe one or two exceptions. These exceptions reside in the western United States and both will exist for political reasons.
Mandates may come into play in the context of FERC deciding what to do if RTOs fail to form, despite the incentives and for invalid reasons. Those who need to learn Order 2000 to decide what to do before Oct. 15, 2000, should stop thinking about what happens afterward. That question belongs in the realm of the purely hypothetical.
Myth No. 2: "Collaboration" Means
Reality: The Workshops Offer
Where to locate RTOs - and who should decide - marks a second key debate.
The "magic marker" brigade (to borrow former Commissioner Bailey's phrase) urged the FERC to draw the lines. Some suggested political divisions, such as New England, New York and the Mid-Atlantic States. Others wanted engineering boundaries, such as the three interconnections. A third group wanted something in between, aligning boundaries with the 10 North American Electric Reliability Councils. Some wanted these RTOs immediately, while others saw boundary lines as goals.
Now, having failed to achieve their aims in the language of the rule, these advocates seek the same result indirectly in the collaborative workshops that the commission will conduct this spring.
By their reading of the tea leaves, they say the FERC opened the workshops to "jawbone" and "cajole" (though not to "extort") utilities into various configurations. Or perhaps the FERC wants its staff to use the workshops to fill in the empty spaces on the RTO map, even if leaving the exact dimensions to the participants.
Think again. As Gov. Alfred E. Smith of New York used to say, "let's look at the record."
Order 2000 gives the purpose of the meetings as "develop[ing] a consensus agreement ¼ establishing a strategic process and a schedule for further collaboration." (p. 649.) That does not imply that RTOs must emerge. Rather, the FERC staff attends the workshops at the discretion of the parties. (p. 649.) Even if the staff comes, the role they play depends on the wishes of participants.
Finally, lest people read too much into the locations of the meetings, Order 2000 said the FERC would choose the five cities only for convenience and how they fit the budget. The RTO Rule says that more than one gathering may result in more than one RTO (or, we add, none).
Just as with joining an RTO, Order 2000 does not mandate any particular result from the collaborative process. Here, again, the industry reads too much into the phrase "we expect." With the incentives placed on the table, and the opportunity for investors to make profits from transmission, the FERC only "expects" that transmission owners will attend at least one meeting.
Myth No. 3: Passive Owners Face "Tough" Rules
Reality: Entergy Didn't See It that Way
The next five myths turn to the merits of RTOs. Thus, having conceded that RTOs truly are voluntary, some critics interpret Order 2000 as setting impossibly high hurdles for those who might prefer a for-profit transmission company (transco) instead of a not-for-profit independent system operator (ISO).
This and the next myth have a ring of truth to them. Unfortunately, it's the ring of half-truth.
Yes, any buyer of transmission without a lot of money must give the seller (an integrated utility) at least some stake in the enterprise, whether it be a financial interest (passive) or minority voting rights (active). And these ownership interests bear close examination. But most of the information requirements set down for passive RTO owners in Order 2000 come from the list the FERC majority put together last year in a declaratory ruling granted to Entergy. And no one at that time, including the company itself, called that burden difficult. Indeed, the dissenting opinion in that case considered the requirements to be too lax. (See Entergy Services Inc., 88 FERC ¶ 61,149.)
The Preamble to Order 2000 has sections on passive and active ownership and a thorough discussion of each. Order 2000 sets information requirements for passive owners to file as part of an application for approval as an RTO. A transco can show that it raises capital and makes investment independently of owners that have no votes and that it owes no fiduciary duty to the generator-passive owners. Any company with passive ownership, such as bondholders, works that way. Transcos, as corporations, should do so, too.
While the passive owners must show the "extent" of control over a number of functions (ratesetting, board removal, admittance of new members and access to information not publicly available) this requirement is a far cry from a prohibition against "any" control over operations. In Entergy, a majority of the commission accepted provisions for removal of directors for cause (such as malfeasance and creating harm to financial integrity of the company). Thus, Order 2000 expressly allows access to confidential information "necessary to protect the passive owner's capital investment." (footnote 308.)
The RTO Rule adds that the definition of "passive ownership" used by the Securities and Exchange Commission may serve as a model for the FERC. That definition speaks of a financial interest or a long-term lease that establishes payments independent of profits. As the FERC stated, "it would be acceptable for market participants to develop passive ownership arrangements that are purely financial." (p. 213.) Such arrangements allow for passive owners to dissolve the enterprise in cases of default, at least according to SEC opinion letters. Order 2000 also indicates that purely financial arrangements "could" gain exemption from audits of independence, assuming that the FERC will adopt that requirement after reviewing comments on rehearing. (p. 211, and footnote 304.)
Myth No. 4: Active Owners Face "Absolute Limits"
Reality: Except in Certain Cases
Propagators of this myth point to the safe harbors, presumptions and (in one case) the benchmark on forms of voting ownership, as if the FERC intended to set ceilings.
In reality, the FERC set a "safe harbor" of 5 percent on individual market participants, but said it would allow higher percentages in individual cases, as long as the higher amount would still fall below the level that would confer operating control. (pp. 218-21.)
Also, while Order 2000 set a "sunset" date of five years for active ownership in RTOs, it allows an extension if the request meets the independence standards and the public interest. (p. 221.) Order 2000 set a "benchmark" of 15 percent for classes of market participants, but allowed parties to argue for higher or lower ratios in individual cases. (p. 222.)
Myth No. 5: Transcos Can't Function
Reality: Transcos can thrive
This myth comes in two versions. One says that the FERC's own rule makes make it illegal for transcos to form. The other says that even if transcos do form, they will prove too small to make it on their own, and so must morph into ISOs. Here we debunk each myth in turn.
Transcos Illegal? The first and more credible myth sounds like Joseph Heller's "Catch 22." It arises from the definition of "market participant" contained in Section 35.3499(b)(2) of the regulatory text.
The confusion stems from the language in that section that refers to an entity that "provides transmission service" to an RTO as a "market participant." Some say that a transco itself provides transmission services, and so will become a market participant in its own right, subject to the restrictions on active ownership. That would mean that a transco could not form.
This argument may seem airtight, but here we refute it on three levels.
First, consider which party actually deals with customers when transmission services are provided, and which does not. The language in the definition reads, "transmission services to an RTO." (Emphasis added). That would exclude a transco operating as an RTO, since it would sell transmission to customers, not to an RTO. By contrast, however, when an ISO becomes an RTO, the ISO deals with customers. Any integrated utility within that ISO "provides transmission services to an RTO." And, if that weren't enough, the definition adds in the "unless" clause that if the FERC finds no conflict of economic interests, transmission providers will not fall under the category of market participant.
Second, the Preamble states in footnote 295 that if a transco acquires an interest in a neighboring company (to provide transmission services) in order to expand the RTO, the FERC will not consider the owner-transco a market participant. Moreover, in many places (e.g., p. 505) the Preamble mentions that the success of Order 2000 depends on the viability of a stand-alone transmission business, a label that fits transcos (we would say better than ISOs).
Third, the Preamble states that FERC encourages distribution companies in a market, entities that provide the local version of transmission service, to purchase the transmission grid. If some favoritism may result (if some but not all companies become the transmission owners), the commission will disallow the arrangement, but the burden will lie on the agency. A pure transmission company does not raise such issues. (pp. 198-99.) Also, the Preamble excludes minority interests in divested generators from the definition of market participant. (pp. 200-01.) All the more, companies that own no generation can safely become RTOs. Finally, Order 2000 states that true suppliers of last resort (the companies that sell under compulsion of state law and do not compete) can expect an exemption from market participant status. Some of these suppliers of last resort, including incumbent utilities, will surely own transmission. (p. 200.)
Transcos Too Small? The second, less-credible variation holds that transcos will cover "too small" an area and will have to exist within ISOs. Further, to fulfill the RTO characteristic of "operational authority," the ISO supposedly will have to operate the grid. All agree that if Order 2000 forces a transco to surrender operation of the grid to an ISO, then the FERC will have hobbled transcos. Fortunately, these interpretations have no merit.
One should pause before assuming that a transco must start out as "too small," in contrast to an ISO. We remind readers that the Alliance Transmission Co., which the FERC has conditionally approved, subject to further information, encompasses an area of 43,000 square miles in nine states. The Alliance eclipses the National Grid of England by a factor of six. The United States has large holding companies, such as Entergy, that have indicated a willingness to become transcos. We would hardly consider them "too small," especially if they combine with large neighboring systems.
Finally, a transco within an ISO would be the one to operate the grid. Since the transco has no reason to discriminate, it does not necessarily need an ISO. In fact, in most cases, an ISO, with its committees and bureaucracy, would hinder efficiency. A transco could also coordinate with neighboring systems. The profit motive drives shipping lines, for example, to coordinate container cargoes with railroads and trucks. The ISO might collect information and otherwise support the transco, but should not operate the grid belonging to the transco. Contrary to claims we heard, no "tension" exists between the characteristics of regional scope and operational authority.
Myth No. 6: Today's ISOs Have a Free Ticket
Reality: Not Until Proven
The next two myths offer a variation of the last three. Rather than say the FERC has made transcos impossible, this argument sees ISOs as the favored child - that an ISO need only call itself an RTO to become one in fact and law.
In this school of thought, at worst an ISO need only make minimal changes to win certification. Yet once advocates of the ISO digest Order 2000 more closely, they must come to a different conclusion.
The advocates see three reasons to believe that Order 2000 enshrines existing ISOs as RTOs. First, the "scope" section of the Preamble lists two of the considerations in defining RTO boundaries as (a) existing reliability councils and (b) control areas. Surely that must include ISOs, especially since Order 2000 "builds on" Order No. 888 and its ISO principles. Second, the FERC uses the term RTO to encompass ISOs and transcos, meaning ISOs "in their present state." Third, the FERC "would not dare" undo the work that went into forming the ISOs the agency approved.
In fact, a complete review of the Preamble belies the first two claims. The filing requirements for ISOs impose on these institutions the burden to explain how they meet the 12 RTO characteristics and functions and, if not, how they will change to meet that goal. Except for the three-month grace period added to the ISOs filing deadline, Order 2000 imposes the same requirements on all utilities.
The section of the Preamble on scope says that the RTO must encompass a natural trading area and be able to perform the functions Order No. 2000 assigns. The FERC also said that number of customers and size of the load count more than geography in assessing the scope of an RTO. (pp. 259-60.) Can single-state ISOs fulfill these requirements? Can those multi-state ISOs that have cobbled together many trading areas or leave "holes" in their service territories measure up? That remains for FERC to determine in 2001.
And what of all that work in forming ISOs? Would the FERC simply ignore that? As to this argument, we say, "try us and find out."
Myth No. 7: Future ISOs Will Have It Easier
Reality: don't bet on it
Some say that utilities should have an easier time becoming ISOs rather than transcos, because the FERC has adopted rules for transcos on passive and active ownership, but nothing comparable for ISOs. They note that the commission never required divestiture of transmission. It only required operational separation of transmission, and that's what an ISO represents.
In reality, however, Order 2000 implies something different. It declares that the success of the RTO Rule depends on the viability of a stand-alone transmission business. Does an ISO represent a stand-alone transmission business? The existing ones do not, at least in our view.
Moreover, it may turn out that an ISO will have more difficulty with the test of an independent board than a transco might have with rules on passive and active ownership.
The section in the Preamble after the discussion on passive and active ownership deals with governing boards for ISOs. The FERC requires independence from stakeholders. Yet the commission here declined to offer many details on what constitutes independence, unlike the situation for passive and active ownership, where Order 2000 gives guidance. The Preamble states that FERC has inadequate experience to judge whether multi-interest group (stakeholder) boards meet the requirement or whether the commission should require independent (non-stakeholder) boards. The Preamble also states that FERC will require an independent audit of ISO boards two years after any qualifies as an RTO. (p. 229, and footnote 330.)
With an audit looming, which has more difficulty, the transco, with its rules on passive and active ownership, or the ISO, with the uncertainty surrounding its board? We submit the transco. The ISO could not, in practice, "play it safe" by choosing to create a non-stakeholder board. Transmission owners have objected to that type of governance and some think it engenders inefficiency by keeping the experts out. Nevertheless, stakeholder boards allow transmission owners to wield influence in the governance of the RTO, even if indirectly through log rolling.
Utilities may find becoming transcos easier in another respect as well. Order 2000 gives RTOs important responsibilities in running the grid. Section 35.34(k)(7) of the regulatory text defines the responsibilities of RTOs in planning and expansion to include "direct[ing]" construction of facilities to ensure reliability. As of this writing, utilities have applied for rehearing of that requirement. They ask the FERC to add a guarantee that the transmission owners within the ISO/RTO will recover the cost of facilities. However, even if the FERC should grant the petitions, owners still would not recover costs if the not-for-profit ISO/RTO should make a mistake in overestimating threats to reliability. That can happen with the RTOs division of responsibility from accountability. Remember what happened with nuclear plants, even when regulators allowed the costs in rates.
Myth No. 8: FERC Will categorically Deny Some
Reality: ferc will be flexible
The myths about incentives emerged from the debates long before Order 2000, when rhetoric filled the air about "FERC candy" and "signing bonuses." In the end, of course, the commission made incentives the linchpin of Order 2000. It even included some of those "signing bonuses" that the critics decried. At the meeting where the FERC adopted the RTO Rule, I, one of your authors (Commissioner Hébert) noted that everyone had compromised, at least to some degree. Nevertheless, the idea has spread that the final rule somehow narrowed the list of incentives that the FERC would consider from what the commissioner advocated.
Here are the facts. Section (e) of the regulatory text (the provision that governs transmission price innovation) lists eight separate incentives. Only two of those - concerning rate moratoria - have any time limits. The FERC has discussed and now stands ready to approve these eight. RTOs eventually may gain others, as Section (e)(4) states that RTOs may submit "any other" proposal in a filing under Section 205 of the Federal Power Act.
Moreover, consider one particular incentive, an acquisition adjustment (an increase in the rate base to reflect purchase price). RTOs may well qualify, since the Preamble states that the FERC will follow current policy on rate base valuation. The applicable precedent, the 1988 Minnesota Power & Light Co. case, permits the adjustment on a showing of measurable benefit. (See 43 FERC ¶61,104.)
We regard the required showing as something a transco easily should achieve.
Myth No. 9: It Will Approve Only Two Types
Reality: Expect To See More
We have heard claims that Order 2000 rejected incentives in the "signing bonus" category: namely, accelerated depreciation, changes in computation to flat-rate depreciation and incremental pricing. According to that argument, only two types of incentives would remain: (1) performance-based rates, and (2) higher rates of return to reflect risk. They fall under the class of "forward looking" incentives that do not cost consumers any money.
This analysis bears rethinking. In the regulatory text, Section 35.34(e)(2) lists accelerated depreciation, changes to levelized (flat rate) depreciation and incremental prices for new construction. The latter comes under the rubric of a combination of average rate access fee for existing facilities and incremental pricing for new ones.
Myth No. 10: Everyone Can Get
Reality: Only the RTO, Not the Utilities
On the other side of the fence, integrated utilities want incentives for themselves, rather than for the RTO. That's true especially for an ISO/RTO.
Yet in Section 35.34(k)(5), Order 2000 provides that the RTO will decide the rate structure. The owners at most can state only a revenue requirement, subject to negotiation within the RTO. That means the owners set the costs to be recovered. Whether to ask for incentives is a choice that belongs to the RTO, as the regional grid manager. Otherwise, customers will fall into paying multiple, pancaked rates, within a region, as some owners have incentive rates and others do not.
In sum, if you want incentives for yourself, become a transco, qualify as an RTO and make the demonstration that the FERC requires. Prove a need to induce efficiency into the transmission business.
Curt L. Hébert Jr. sits as a commissioner at the Federal Energy Regulatory Commission. First appointed in 1997, his second term expires in June 2004. Joshua Z. Rokach advises the commissioner on electric issues. This article reflects the opinions of the authors only.
Is There a Mandate?
We now lay that issue to rest.
The "free market" crowd and the "regulator faction" disagree on whether Order 2000 forces utilities to join RTOs. If you pay careful attention, you will hear the regulator faction speaking of what the FERC supposedly "could" do, if some utilities eventually choose not to join an RTO.
We acknowledge that Order 2000 does allow the FERC to act in specific cases (in a merger case, for instance), but only if necessary to uphold the Federal Power Act and supported by the record. (Order 2000, p. 142.) But first, we ask that they continue reading. Elsewhere in Order 2000, the FERC states categorically that it will not mandate RTO participation:
We are not adopting as a generic policy in this Final Rule either that RTO participation is required in order to retain or obtain market-based rate authorization for wholesale power sales, or that RTO participation is required for a disposition of jurisdictional facilities to be in the public interest. (pp. 116-17.)
But now let's examine the possibility of future commission action, spelled out in Order 2000 in text immediately following the quote above:
However, in response to those who argue that the Commission has a statutory responsibility to remedy undue discrimination and anticompetitive effects ¼ we recognize that we may have to consider, in individual cases, issues that arise as to whether market power has been mitigated ¼ or whether a merger would be in the public interest, without RTO participation. (p. 145.)
Notice how the commission circumscribes its remedial authority. In the very next sentence, the Order lists only (1) the filing deadlines, (2) the obligations to participate in good faith in the collaborative process, and (3) meeting the 12 functions and characteristics as the mandatory aspects of the rule.
Further, in the section on legal authority, Order No. 2000 says,"[N]or do we propose to use the denial of market-based rate authority as a penalty for not complying with this Rule." (p. 150.)
Regarding mergers, Order 2000 says only that participation in an RTO "might be an appropriate remedy" for market power. (p. 649.)
We rest our case. A large chasm exists between the certainty of "will always" and the mere possibility of "might, if the record supports it."
- C.L.H., J.Z.R.
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