Dominion Resources touts its "impacted" method, but opponents call it a "stalking horse" (em a scheme to avoid full review at FERC.
Is the Federal Energy Regulatory Commission prepared to accept true marginal-cost pricing for electric transmission?
With all the criticism leveled at the traditional "contract path," one would think that the FERC would consider a new approach to transmission pricing.
In fact, last year in its final Order No. 888, the Commission recognized the possible advantages of marginal cost methods, which would set prices based upon actual flows in the transmission grid:
[S]ome versions of flow-based pricing could more accurately reflect and price the actual power flows on transmission systems and thus could produce efficiency gains, better generating siting decisions, and benefits for customers and utilities alike. %n1%n
Nevertheless, the FERC still has proved to be extremely wary of marginal cost pricing for transmission. Its 1994 policy statement on transmission pricing puts the burden of proof squarely on those who would move away from traditional, embedded-cost pricing:
[U]nlike sales of generation, the Commission cannot rely on competitive market forces to discipline prices for firm transmission service. Accordingly, any transmission owner advocating a market-based transmission pricing method must demonstrate how it has alleviated these serious concerns. %n2%n
Lately, however, some have come to question the FERC's true commitment to innovative transmission pricing. %n3%n Perhaps that is why, as of early May, the Commission had yet to act on a petition proposing flow-based pricing filed last July by Dominion Resources Inc., the holding company for Virginia Power. In that petition, %n4%n Dominion Resources outlined a transmission pricing method called the "Impacted Megawatt-Mile Method" (em a method not entirely new to engineers and rate witnesses, but one that would force a significant change on the FERC and the industry in general.
In simple terms (and subject to certain exceptions) %n5%n , the IMM method would set different prices for different power movements over the grid, depending upon how any single transaction would change (impact) loads on various transmission line segments. Two seemingly identical transactions could carry different transmission prices, depending upon the day, time or the sequence in which each was requested and scheduled. In theory, the method would ensure that transmission prices maintain a direct relationship between transmission line usage and the current reproduction cost value of transmission assets deemed to have been "impacted" by the use.
As might be expected, Dominion Resources faces objections from a host of critics. Many companies have intervened, with some filing protests. The protestors include Old Dominion Electric Cooperative Inc., the Transmission Access Policy Study Group, Southeastern Federal Power Customers, %n6%n North Carolina Electric Membership Corp., Alabama Electric Cooperative Inc., Central Virginia Electric Cooperative Inc., Duquesne Light Co., and DuPont Power Marketing Inc.
The intervenors raise concerns that span regulatory, engineering and political concerns. One intervenor, Otter Tail Power Co., for example, has not protested per se, but simply wants to participate in the discussion. As a member of the Mid-Continent Area Power Pool, which has proposed its own flow-based pricing method, Otter Tail apparently wants to get an early read on how the FERC will respond. But of all the reasons for protests, the most obscure objection has risen to claim the highest profile.
In short, some of the protestors accuse Dominion Resources as acting as a "stalking horse" for the electric industry.
Dominion Resources is a holding company. It owns no transmission assets. Technically speaking, the FERC does not even have jurisdiction over Dominion Resources. %n7%n Thus, the petition asks only for a declaratory ruling that the IMM method would pass muster under the FERC's open-access and comparability policies for electric transmission. The petition does not even offer a tariff in the conventional sense. It does not give examples of actual rates, nor does the FERC have authority to force Dominion Resources to give such examples. It only presents a formula. The details would be worked out when transmission-owning utilities filed actual flow-based tariffs using some variation of an IMM method. Several protestors feel that the petition would force the FERC to rule on the IMM method without seeing a true picture of how it would affect transmission rates.
ODEC calls the petition "entirely hypothetical."
It says that Dominion Resources is seeking FERC approval for a mere theory "so that real transmission-owning utilities (em including presumably the Dominion Resources subsidiary Virginia Power (em can apply this pricing approach in real-world circumstances, without ... unwanted interference by FERC."
North Carolina EMC echoes that claim: "Dominion is unwilling to unveil the full details ... of its proposal. ... [It has] used the petition route as a vehicle for filing a rate proposal in an almost complete factual vacuum."
Yet, who can deny the logic of marginal cost pricing? As Dominion Resources explained in its petition:
[P]rices are based on actual system impacts and distance of flow. ... [T]ransmission owners [get] an economic basis for making needed system improvements (em a basis they often lack entirely under the traditional contract path approach.
Overall, the Dominion Resources proposal would appear to follow today's general consensus that marginal-cost pricing sends more accurate pricing signals than embedded-cost methods.
The Method
This small space cannot possibly do justice as a complete explanation of the impacted megawatt-mile pricing method proposed by Dominion Resources. Suffice it to say, however, that the IMM method would operate very much like the way IBM programmed its "Deep Blue" computer to plays chess against world champion Garry Kasparov. Computers would receive a proposed power transaction, weigh all conceivable consequences and then set a transmission rate accordingly.
Under the IMM method, computer software would assign a separate value for every line segment on the transmission grid, based upon voltage capacity and reproduction cost. %n8%n Computers would then analyze line loading on the transmission grid immediately before and after every single transmission transaction, depending on the category of service requested (e.g., firm or nonfirm). %n9%n Every change in line loading would be recorded, on virtually every line segment, weighted by the length (mileage) of each individual segment. The sum of these changes would reflect all total impacts on the grid imposed by the transaction. When multiplied by a dollar figure, the formula would convert these changes into a hypothetical cost representing the value of usage imposed on the line by the transaction. In theory, this cost value would offer some measure of the restraints (if any) imposed by the transaction (em and the extent to which the transaction might preclude other power movements.
Some changes on some line segments could actually reflect a drop in thermal load (em sometimes in the prevailing direction of the transmission movement, or sometimes in the opposite (counterflow) direction. These negative changes in fact might relieve constraints to such an extent as to make other transactions possible (or less costly) that otherwise would be precluded by a lack of transmission capacity. Thus, the IMM method provides for various reciprocal rate credits (including a credit for not using the full amount of a scheduled firm reservation) to reflect these positive effects on line constraints (see sidebar).
All in all, the formula would set a complex rate for firm transmission service that would feature eight separate rate components:
1) capacity reservation charge (fixed charge);
2) reactive power charge (fixed);
3) replacement of line losses (fixed charge for capacity cost of generation);
4) counterflow credit;
5) credit for third-party use of customer's unused capacity reservation;
6) credit for third-party use of facilities or additions paid for by the customer;
7) line-loss charge (variable charge); and
8) an administrative charge.
The formula would also provide a mechanism for mitigating constraints, allowing a potential customer to seek bids from those who might be able to remove a given constraint. Such bids would be capped at the cost of removing the constraints, plus a 10-percent premium.
Another important factor, not to be overlooked, concerns native load. The IMM method proposed by Dominion Resources would apply only to incremental transmission services. It would not cover native wholesale or retail load. As might be expected, that grandfather exemption has raised a firestorm of objections. (Dominion Resources called it "a barrage of complaints.") Even Duquesne Light Co., itself a franchised utility with its own native load, charged that by limiting the incremental pricing formula non-native transmission arrangements, it would distort attempts by the FERC to introduce open access in transmission and competition in the generating sector.
Nevertheless, Dominion Resources believes that its IMM method will prove particularly well-suited to a competitive generation market where participants rely heavily on the transmission grid. It suggests that IMM (incremental) pricing will encourage enhancement or new construction of transmission facilities where warranted by market conditions:
Traditional pricing is likely to leave retail ratepayers or shareholders 'holding the bag' for transmission investments made to meet the requirements of third-party transactions. ...
This problem is exacerbated by the lumpiness of transmission investments. ...
Impacted megawatt-mile pricing addresses [this problem] by basing prices for all new service on incremental costs.
If only it were that simple. As matters stand, the intervenors have identified quite a long list of objections to the Dominion Resources pricing proposal.
Objections
A major objection to the proposed IMM pricing formula lies in the fact that transmission customers would find it difficult to forecast prices.
DuPont Power Marketing Inc. put it this way: "The IMM approach deprives power marketers ... of their ability to effectively compete with utilities such as Dominion Resources. The [formula] is anti-competitive in that it creates a complex transmission pricing formula which cannot be readily or easily determined or forecasted by potential competitors."
Others charge that the IMM formula would end up boosting transmission rates too high. Two
intervenors, Central Virginia Electric Co-op. Inc., and Craig-Botetourt Electric Co-op. Inc., joined their protests:
Small transmission-dependent utilities moving from bundled requirements service to unbundled transmission service ... would find that their new unbundled transmission service is much more costly than the transmission component of their bundled requirements service and the bundled transmission component of the provider's retail service.
Another key objection concerns the proposal by Dominion Resources to grandfather native load and charge incremental, impact- and distance-based pricing only for new unbundled services. According to Duquesne Light Co.:
Charging unbundled customers a distance-sensitive rate, while permitting bundled customers to continue paying postage-stamp rates ... will give customers an artificial incentive to continue purchasing power on a bundled basis from the transmitting utility (or an artificial incentive to switch suppliers).
But for that charge, Dominion Resources had a reply waiting:
Because marginal cost pricing approaches, such as IMM, are forward looking [they] cannot be readily applied to individual uses arrange for in the past ... Indeed, it would be exceedingly difficult (if not impossible) to reconstruct the circumstances that existed at the times at which existing uses were committed.
Beyond the grandfathering of native load, the most serious objections concern the choice of a distance-weighted pricing method, and the idea that prices should reflect line loadings, even though, for the great majority of hours during the year, most sections of the transmission grid are not particularly heavily loaded. Details on those points can be found in the protest filed by the Transmission Access Policy Study Group. %n10%n
TAPS argues, for instance, that distance-based pricing tends to distort rates, increasing transmission rates to customers located at the periphery of a utility's service area. It cited FERC precedent %n11%n indicating that distance-based wholesale transmission pricing is discriminatory when integrated with retail rates that contain bundled, non-distance-based transmission rates (as for native load).
Moreover, TAPS notes that the Texas Public Utility Commission (which it says has wide experience with megawatt-mile pricing for electric transmission) is now moving away from distance-based transmission pricing. %n12%n
To bolster its arguments, TAPS has peppered its arguments with analysis by Riley G. Rhorer, a professional electrical engineer and a partner in the firm of R.W. Beck. According to TAPS, Rhorer has identified a host of theoretical problems with impacted megawatt-mile pricing:
• Large-Firm Bias. Utilities with geographically diverse generation and load will benefit from internal flow cancellations.
• Small Systems Suffer. Megawatt-mile rates, liked pancaked postage-stamp rates, tend to segment markets geographically. Small systems suffer most.
• Gaming Potential. Each transaction is priced against a base of all prior transactions, making ordering significant, and creating a gaming potential for those able to reserve capacity early on.
• Overemphasizes Line
Loading. IMM pricing incorporates "questionable" assumptions that transmission over heavily loaded lines should cost more than transmission over lightly loaded lines. (A lightly loaded line in a non-contingency setting could nevertheless prove critical to the system.) IMM pricing may not afford enough compensation to the line owner.
• Loop Flows. IMM has potential to encourage looping of radial lines (attract flows).
• Ignores Reliability. IMM pricing ignores the fact that new transmission construction is often based on reliability and contingency analysis, not just incremental impacts.
TAPS concludes by questioning whether the electric utility industry as a whole has the guts to implement a complex incremental pricing scheme for electric transmission: "[T]he tariff has no utility sponsor. Nobody is proposing to adopt it."
But on the other hand, as mentioned earlier, the MAPP regional reliability council has proposed a restated pool agreement incorporating a flow-based transmission pricing method. (However, Otter Tail Power Co. notes that the two methods are different and perhaps "irreconcilable." %n13%n)
Dominion Resources also answers many of the objections described above, pointing out, for instance, that because transmission lines are lightly loaded during most hours, the impacts assigned to line segments under its IMM method will be smaller than one might think. Overall, says Dominion Resources, IMM pricing should produce total revenues "that are far lower than total [system] replacement costs."
Outlook
Only time will tell whether the FERC ultimately proves willing to adopt flow-based transmission pricing. In March, however, the FERC took what might be viewed as a cautious first step, when it accepted an experimental participation agreement filed by the General Agreement on Parallel Paths that proposes a method to compensate utilities for unscheduled loop flows. %n14%n
For its part, Dominion Resources sees a concrete advantage with the "hypothetical" nature of its proposal:
Because of the unique features of the [IMM method] public utilities have been reluctant to adopt this novel approach. ... In this way, utilities, power pool, and Regional Transmission Groups will have the benefit of the Commission's views prior to filing a flow-based rate schedule.
The company remains convinced that its method has what it takes to bring transmission pricing into the world of open access and competition in generation. Et
Bruce W. Radford is editor of PUBLIC UTILITIES FORTNIGHTLY.
Too Hypothetical?
"Dominion Resources candidly admits that its petition is intended as a stalking horse."
(em Southeastern Federal Power Customers Inc.
"Dominion Resources owns no transmission facilities ... and is not jurisdictional to FERC. ... [Its] pricing proposal is entirely hypothetical."
(em Old Dominion Elec. Co-op. Inc.
"Paradoxically, all [these] intervenors ... are non-jurisdictional entities and hence, by their reasoning, should be ignored."
(em Dominion Resources Inc.
Too Complicated?
"It requires complex data manipulations ... costs would be difficult to predict, especially for a small utility without personnel and sophisticated computer equipment."
(em Central Va. Elec. Co-op. Inc.,
Craig-Botetourt Elec. Co-op. Inc.
"Dominion's suggestion that IMM pricing 'is no more complex than traditional cost-of-service ratemaking' ... cannot be taken seriously."
(em Alabama Elec. Co-op. Inc.
"These arguments miss the point, and are simply knee-jerk reactions to anything new and different. All ratemaking is complex."
(em Dominion Resources Inc.
A Sample Transaction
A short passage from the Dominion Resources petition will illustrate the complexity of charges and credits, in this case for firm service:
Capacity Reservation Charge: The fixed charge for transmission capacity is derived from a formula which considers flow distribution, distance and magnitude, the duplication cost of the affected facilities, line loadings, and the average utilization of the facilities. ...
For each proposed firm transmission service, the model will calculate the actual change in the power flow, in megawatts, over each line segment at the time of the peak. The change in power flow, multiplied by the length of the line, determines the number of impacted megawatt miles. ... For each affected line, the number of impacted megawatt miles is then adjusted by an impact factor that is a reflection of line loadings. ...
The "monthly line charge" for each voltage class, in dollars, is based on the duplication cost of the line. ...
The number of allocated megawatt miles for each line will be multiplied by the monthly line charge. ... The sum of these charges is the monthly fixed Capacity Reservation Charge.
* * *
Counterflow Credit: For counterflows (identified negative power flow changes), two credits are provided. First, a credit is granted for each line on which the power flow change is negative. ...
Second, where counterflows actually create capacity that is used by a subsequent customer(s) for service in the prevailing flow direction, the counterflow customer is given a second credit. ...
Credit for Unscheduled Firm Transmission Service: Where a firm transmission customer does not use the full amount of its reservation, it will receive, as a credit, any revenues received for nonfirm use of transmission capacity reserved but not use. ...
Customer Facilities Expansion Credit: An additional credit ... is provided to transmission customers who have paid for the construction of new facilities.
Source: Petition for Declaratory Order of Dominion Resources Inc., Regarding Its Impacted Megawatt-Mile
Transmission Service Tariff Proposal,
Docket No. EL96-63-000, filed July 2, 1996.
1Order No. 888, April 24, 1996, Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities, III FERC Stats & Regs ¶31,056.
2Policy Statement, Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided by Public Utilities Under the Federal Power Act, 69 FERC ¶61,086, IV FERC Stats & Regs ¶31,005 (1994).
3See, e.g., "ISO Pricing: Let's Not Socialize Transmission Rates," by Mark J. Volpe, PUBLIC UTILITIES FORTNIGHTLY, Feb. 15, 1997, p. 48.
4Petition for Declaratory Order of Dominion Resources Inc., Regarding Its Impacted Megawatt-Mile Transmission Service Tariff Proposal, FERC Docket No. EL96-63-000, filed July 2, 1996.
5A big exception would apply to grandfathered native load, wholesale and retail, served by franchised electric utilities.
6A nonprofit corporation representing 238 rural electric cooperatives and municipally owned electric systems that buy capacity and energy directly or indirectly from the Southeastern Power Administration of the U.S. Department of Energy.
7But see, Enova Corp. & Pacific Enterprises, FERC Docket No. EL97-15-000, April 30, 1997 (suggesting that the FERC take jurisdiction over holding companies under its merger review authority), reported in this issue, p. 37.
8Reproduction cost, taken from Handy-Whitman indices.
9For "firm" service (minimum term of one year) the fixed reservation charge would reflect changes in line loadings relative to the annual system peak. Prices for "priority nonfirm service" would reflect changes in line loadings relative to the next day's peak demand. Prices for "standard nonfirm service" would be based on actual, real-time line loadings, plus any incremental service already scheduled for the next hour.
10TAPS is chaired by Roy Thilly, g.m. and counsel for Wisconsin Public Power Inc. System, and include other municipal and publicly owned utilities, represented by the Washington, D.C., law firm Spiegel & McDiarmid.
11Tex-La Elec. Co-op. of Texas, Inc., 69 FERC ¶ 62,034 (1994).
12According to TAPS, the Texas PUC in its recent open-access transmission rulemaking adopted a new transmission pricing method establishing regional rates by which 70 percent of transmission costs (apart from losses) would be recovered under a postage-stamp rate, and only 30 percent under a megawatt-mile approach.
13"[The] differences are in some cases significant, and perhaps irreconcilable. For example, Dominion's flow-based pricing scheme would include a "counterflow credit" as transmission line capacity is loaded and unloaded ... The pricing method proposed by MAPP, on the other hand (which Otter Tail has opposed) would not differentiate between positive and negative flows and therefore provides no corresponding credit."
14Allegheny Power Service Corp., et al., Docket No. ER97- 697-000, March 25, 1997, 78 FERC ¶ 61,314.
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