Fortnightly
Unbundling Retail Prices: An Electric Utility Prepares for Life as a Disco
May 15, 1999
By George R. Pleat
How BG&E would revamp prices for distribution service, creating a new series of fixed and variable wires charges, and changing the balance among customer classes.
On April 7, Maryland Gov. Parris Glendening signed state Senate Bill 300, "Electric Utility Industry Restructuring," mandating retail choice for at least one-third of the state's residential electric customers by July 1, 2000 (the balance phased in over the next two years), and choice for all business customers by Jan. 1, 2001.
That news upped the ante for my company, Baltimore Gas & Electric Co., a combined electric and gas utility, since we were already engaged in restructuring activity in two cases pending before the Maryland Public Service Commission.fn1
Last year, at the PSC, we had filed a set of proposed unbundled retail electric prices for each of our customer classes, including ideas for functional separation of certain costs related to generation and transmission, and their reallocation within a new price design for distribution services. We pursued various strategies on functional cost separation and price design, always with several goals in mind:
Match the identified and unbundled disco services with their corresponding costs;
Price disco services accordingly and in a manner intuitive for residential customers;
Accept the notion of bill impacts for certain individual customers (but with limitations), during the competitive transition phase; and
Ensure long-term financial stability for BG&E stockholders.
Now, with legislation enacted and competition a certainty, these proposals become more urgent.
The new restructuring law will not require Maryland utilities to sell off generation. Nevertheless, with generation deregulated and supply open to customer choice, our unbundling plan proposes to isolate certain costs related to generation and reallocate them to wires services. That implies certain impacts on customer bills, with limitations, through the competitive transition phase, since BG&E's rates heretofore have contained some imbalances between customer classes.
Functional Separation:
Moving Costs to the Wires Side
In 1998, in Maryland PSC Cases 8794 and 8804, Baltimore Gas & Electric filed new, unbundled retail electric prices for each customer class [fn2] as a part of a general effort to unbundle prices for distribution functions generally, including distribution wires services, billing and metering services, and outdoor lighting business services.
During that process, we developed six key strategies for functional cost separation:
1. Recovering generation regulatory assets and decommissioning costs through a non-bypassable delivery charge;
2. Moving radial transmission lines to distribution wires;
3. Recovering, through a distribution wires charge, the residual retail transmission network costs not approved by the Federal Energy Regulatory Commission;
4. Sharing uncollectible bad debt expenses between generation and distribution services;
5. Retaining load-management devices in the wires service; and
6. Segmenting pure billing and metering costs.
1. Generation Costs. BG&E proposes to isolate generation costs relating to regulatory assets and decommissioning costs and recover these expenses in a non-bypassable deliverable service charge. The objective is to ensure payment from connected wires customers, regardless of generation choice, of assets imposed on BG&E by traditional regulation (e.g., post-retirement benefit liabilities) and ensure funding for eventual cleanup costs at our Calvert Cliffs nuclear power plant.
The regulatory assets and decommissioning costs are allocated to customers based on BG&E's current cost-of-service approach for embedded generation plant. Subsequently, the expenses are recovered via the kilowatt-hour charge. These costs are not recovered from large customers on a kilowatt basis because system peak kilowatt demand measurements may not be available for every connected customer when generation choice is in place. The disco's attempts to get some kind of regional coincident peak demand data from competitive suppliers may be futile because the data may not be recorded by the supplier. Alternatively, measuring kilowatt-hour throughput for regulatory asset recovery and decommissioning funding will be less complicated and costly for the disco.
Because some generation regulatory asset and decommissioning costs are shaved from the existing kilowatt generation tariff and rolled into a kilowatt-hour charge, there will be some billing impacts in those customer classes with generation kilowatt tariffs. Overall, BG&E customers with high load factors will have slightly larger bills, while those customers with low load factors will have slightly lower bills.
2. Radial Transmission. BG&E defines upstream distribution wires substation and feeders to include traditionally booked 115/230-kV radial transmission assets. This series of one-directional-flow lines has two operational roles. Some lines are system-driven and feed one-direction bulk power to the 34-kV and 13-kV local distribution grids. The other function of the radial is to serve retail customers directly at 115-kV power levels. We are re-booking all transmission assets into appropriate distribution accounts and defining these radial lines as a distribution service.fn3 As discussed below, this strategy of moving assets into the distribution wires service forms the basis of a distribution charge for high-voltage customers.
3. Network Transmission. In addition to transferring the radial transmission costs to the disco wires service, BG&E proposes to recover in its distribution wires charge any retail network transmission revenue requirement not allowed by the FERC in wholesale transmission ratemaking.
For consistency, we define the unbundled retail transmission price for all customers to be based on the FERC-approved network revenue requirement used for BG&E's wholesale transmission price.fn4 Because BG&E is engaged in a retail electric restructuring proceeding, it must recover all retail network revenue requirements - which include some costs not reflected by the FERC in its Form 1 wholesale transmission ratemaking (e.g., common plant for a combined utility). Though the residual revenue requirement amount was somewhat small for BG&E, it warrants recovery for the stockholder.
By including the residual network transmission cost in the distribution wires charge, leak proof earnings on these assets are ensured. We propose to allocate the residual amount to customer classes on a 1 Coincident Peak basis, similar to the FERC-approved wholesale rate development. The costs then will be recovered through the applicable proposed distribution wires-pricing mechanism in that customer class.
4. Uncollectible Bad Debt. Like many other investor-owned utilities with the obligation to serve electric customers, BG&E has accrued significant bad debt expenses on unpaid electric bills. We propose to split the annual expenses between the generation and distribution business lines based on corresponding revenue requirements, since today's unpaid electric retail bills include fully regulated, bundled electric monopoly service.fn5 During the interim, the distribution portion (30 percent) will be recovered by all connected customers through the proposed wires charges.
With the obligation-to-serve requirement intact for the BG&E distribution service, we believe it is critical that we maintain a regulated cost-recovery mechanism for distribution-related bad debt expense. We feel our wires price proposals are well-suited place holders for such cost recovery since this business line is the most likely to be PSC-regulated in the near future. The issue, however, of specifically who is responsible for paying the uncollectible distribution as well as generation bad debt expense has not been resolved and likely will be debated in the Maryland PSC restructuring proceedings.
5. Load Management Devices. BG&E has about $50 million invested in load management devices. The devices give the utility control over air conditioning and hot water heating loads in times of generating supply shortages for the Pennsylvania-New Jersey-Maryland (PJM) power pool. Also, we can execute these devices when PJM energy prices spike up - a useful tool for minimizing fuel costs, assuming no fuel rate mechanism is in place.fn6 As an incentive for retail customers, BG&E pays annual credits for the right to control load.
But how to unbundle these costs and determine what assets may be stranded in the future? We propose that these costs are not part of our generation stranded costs.fn7 By default, the costs are recovered through the distribution wires charges (since the FERC does not recognize these costs for transmission ratemaking.)
Today's costs must be recovered by BG&E since the devices play an active role in PJM generation planning and could provide some fuel savings to BG&E stockholders under the price freeze transition phase. The distribution wires service is more likely to be PSC-regulated in the near future and provides the least risky form of cost recovery of these assets.
Questions that will emerge when open access is fully operational include: Will these load-management assets still be useful for distribution service when retail generation becomes completely competitive? Will these devices have any stranded costs when this milestone is reached?
6. Billing and Metering. As part of the PSC's retail price unbundling requirements, BG&E must separate disco costs between wires and billing/metering services. The wires costs include all assets and related operations and maintenance expenses consisting of 115-/230-kV radial lines, 34-kV substation and feeders, 13-kV substations and feeders, secondary transformers and lines, service drops and call center expenses relating to service restoration. This process involves defining the parameters of billing and metering activities, and reexamining company management of the revenue-cycle process.
We have defined billing activities and associated book costs as including billing operations, revenue processing, credit and collections (labor only and excluding uncollectible bad debt), call center (billing inquiries only) and customer relations (major and special accounts section of the marketing division and investigations).
The metering activities and associated book costs include installation, the meter itself, reading, O&M, field services (e.g., turning meters on and off) and meter-related call center expenses.
All of the billing and metering labor expenses identified will be adjusted for department, corporate and fringe benefit overhead. Some traditional billing services costs shift to the distribution wires service. These costs consist of about 50 percent of the call center expenses, and are related directly to service restoration.
Beyond definitions, retail price unbundling has pushed us to take a more precise look at our various business line cost centers. One area of keen interest to BG&E has been the activities involving revenue cycle management. These activities primarily consist of pure billing and meter reading functions. The BG&E efforts to unbundle and identify the multitude of billing and metering reading cost center activities lay the groundwork for the company to monitor financial performance on revenue cycle management efforts. The financial monitoring will be invaluable to the utility for strategic decision-making.
Price Design:
Toward a New Regime of Wires Charges
How do these strategies for functional cost separation translate to prices for distribution services? In our plan, we propose five salient strategies for price design:
1. A fixed monthly wires charge for the mass residential and "mom and pop" commercial market;
2. Prices for services provided at different distribution voltage levels, based on the kilovolt-ampere demand for customers taking distribution services at 13 kilovolts and above;
3. A wires demand ratchet for the large secondary and primary voltage customers;
4. Shifting outdoor lighting prices closer to marginal cost; and
5. Equalizing rate of return on book investment across all business lines and retail customer classes.
1. Mass Market Customers. One important price objective for BG&E in the unbundling process is the establishment of a monthly fixed wires price for its mass market retail customers.fn8 The fixed-price concept is based on a price-recovery mechanism that captures those infrastructure wires costs that are not variable with usage. These costs consist of underground and overhead secondary service lines, secondary transformers and service drop. According to area system planners, if customers change their consumption behaviors (like switching from gas heat to all electric), these costs are least likely to vary.
The costs that will vary with changes in consumption patterns, according to area system planners, will be the upstream substations and feeders costs. Consequently, we propose to recover these expenses through usage charges.
With the introduction of a fixed monthly wires price, BG&E minimizes the volatility of earnings due to weather fluctuations. With more stable cash flows, future asset and O&M planning for wires service is simplified. The downside to fixed wires pricing is that billing increases are imposed on low-use customers. However, for every losing customer there is a winner: the high-use customer.
2. Primary Voltage Customers. Another goal is to make unbundled prices more intuitive to customers. To that end, we propose to re-classify our primary voltage customers by specific voltage-level wires service requirements. The reasoning behind this concept is that the customer only pays for those distribution wire grid costs that are required. The customers tapping off of 115-kV radial lines would only pay for these costs and not any cost bypassed (34 kV and below). The 34-kV customers would pay for 115-kV radial lines as well as 34-kV substation and feeder lines, but no costs below 34 kV. The 13-kV customer would pay for 115-kV radial, 34-kV substation and feeder costs and 13-kV substation feeder costs, but no costs below 13 kV. Consequently, the 115-kV customer pays the lowest wires charge while the 13-kV customer pays the highest charge.
To encourage primary voltage customers to improve their power factor, BG&E designed a kilovolt-ampere wires demand charge to recover wires costs. BG&E area distribution planners formulate substation and feeder capacity requirements based on local megavolt-ampere demand levels. It makes intuitive sense to recover these same costs from customers on a kilovolt-amp basis. By applying a kilovolt-amp wires charge to all connected primary customers, there are incentives for customers with low power factors (or high kilovolt-amp) to reduce demands through the purchase of more efficient electric motors. Everything else being equal, those customers with high power factors will have reduced bills because of the associated low kilovolt-amp.
BG&E's primary voltage customers have installed meters that have kilovolt-amp reading capabilities, so significant load recording installation costs are avoided if this price design is accepted. Also, by applying a generic power factor charge to all customers regardless of power factor and kilovolt-amp use, it will be unnecessary for BG&E to inform individual customers that they must be switched from kilowatt billing to kilovolt-amp billing.fn9
In addition to getting out of the power factor enforcement business by instituting a generic kilovolt-amp charge, the disco will realize long-term capacitor, line loss and wires capacity savings if customers with poor power factors react to the price signal and reduce their kilovolt-amp consumption.
3. Dealing With Self-Generation. One concern for our company focuses on the potential erosion of disco wires revenue from customer on-site generation. Under BG&E's current tariff, a typical customer can purchase distribution demand services under a monthly kilowatt tariff. In effect, it's pay-as-you-go for wires service. This traditional rate design does not take into account the fact that BG&E must size substations and the feeders based on the customer's peak load regardless of fluctuating loads.
In the future, if the market for on-site generation continues to expand and BG&E wires service is used as a backup for maintenance-plagued mini-generators, a demand ratchet wires-pricing mechanism will ensure the necessary revenues to meet the costs of standby substation and feeder service.
BG&E proposes a 12-month moving demand ratchet (kilovolt-amp demand) to set prices for all large secondary and primary voltage customers. Each month's wires charge will be based on the highest customer peak demand during the preceding 12 months. If, in the future, an on-site generating customer wants to avoid any backup charges, it must not choose backup service from BG&E for 12 month in a row; otherwise, a one-month purchase of wires service will guarantee the disco at least a 12-month stream of distribution revenue. The 12-month moving demand ratchet price is designed to recover those costs that are incurred to meet a customer's peak demand. The price design also insulates the disco's earnings from wild swings due to weather impacts.
4. Outdoor Lighting. BG&E provides a menu of electric outdoor street lighting services with quasi-regulated and competitive characteristics. Most of the services have regulated tariffs; however, the fixture and pole installation and related O&M activities compete directly with private vendors. Because of this unique element, BG&E performed an extensive marginal cost analysis to determine how close current tariffs are to new project costs.
BG&E provides a fully bundled outdoor lighting service called private area lighting, the tariffs of which are regulated by the PSC. A typical service in this category would provide security lighting for an auto dealership. BG&E charges the customer a fully bundled, monthly fixed rate based on lamp wattage designed to recover generation, transmission, distribution wires and the fixture, poles and related O&M.
For private area lighting, BG&E analyzed the marginal cost of this fully bundled service and matched these expenses with current bundled tariffs. The study revealed that the fully bundled price for overhead line fixture projects is deficient in recovering corresponding costs, while underground line fixture projects have bundled tariffs that earn well above marginal cost. One factor behind these outcomes is vintage pricing. The overhead lighting services over many years had not kept up with current costs, while underground services (new in the last 20 years) were designed much closer to current costs. The study's findings prompted our proposal to decrease underground tariffs more significantly than overhead tariffs in the restructuring case.fn10
BG&E also provides unbundled fixtures and pole street lighting services (excluding generation, transmission and wires service) to state, city and county governments. These services include monthly fixture and pole rentals, maintenance of company- and customer-owned equipment, and underground cable rental. All of these services are competitive with private vendors. However, the tariffs charged by BG&E for these services are regulated by the PSC.
BG&E analyzed the marginal cost of each unbundled street lighting service, and matched these expenses with the current unbundled tariff. The study showed that some services are profitable while other services are not. Tariffs that cleared significantly their corresponding marginal cost were underground fixtures and pole installations and maintenance of fixtures and poles.
The street lighting tariffs that are under-recovering marginal costs significantly are the overhead fixtures and pole installations (especially those related to distribution) and underground cable extensions. The poor cost-recovery in overhead fixture and pole installation is related to vintage pricing, as discussed above with regard to private area lighting. For underground cable extensions, the current rental tariff only recovers maintenance of the facility.fn11 The study's conclusions prompted BG&E to propose a significant increase in monthly overhead distribution pole rental tariffs, as well as an increase in overhead fixture and pole tariffs.
5. Equalizing Rates of Return. Probably BG&E's most significant rate design proposal is the equalization of rates of return by business line and, more importantly, by retail customer class.
In the process of separating functional costs, BG&E assumes equalized rates of return across all business lines at the authorized PSC-regulated levels. The strategy is long-term in that unbundled prices for stand-alone business should bring adequate income returns to the stockholder, and prices should be fair and equitable to the customer.
Because BG&E still is fully vertically integrated and won't begin to position itself horizontally until the transition phase of restructuring is over, it is difficult to determine stand-alone returns on capital. By default, BG&E proposes the current PSC-authorized rate. For the short-term, by equalizing rates of return across functions, BG&E removes potential cross-subsidization of costs between any particular business operations.fn12
Previously, for many years under traditional regulation, our embedded cost-of-service studies consistently had shown that residential customers contributed rates of return well below the system average - especially the time-of-use rate schedule. In contrast, the large and small commercial customers contributed rates of return significantly above system average. It always has been a goal of BG&E to bring these returns closer to system average.
Today, as we face competitive retail generation - and quite possibly a competitive billing and metering market as well - it makes good business sense for us to eliminate these rate regulation subsidies to avoid lost business through "cream skimming" or "cherry picking" by alternative generation or distribution service suppliers. For example, large commercial customers likely will have their own energy experts, will purchase energy in a least-cost manner and have the capital to build on-site generation for wires bypass. Maintaining prices that contain subsidized costs can only make BG&E less competitive. We should begin to price our services on full cost and provide our customers with the correct price signals for comparison shopping. Let the customer make the final choice on service and give BG&E, an investor-owned company, a competitive position in emerging deregulated markets.
George R. Pleat is the principal pricing analyst at Baltimore Gas & Electric Co. This article is adapted from a paper presented at the Electric Distribution Business Conference, Jan. 27-28, 1999, Electric Utilities Consultants Inc. The views and opinions expressed by the author are not necessarily those of BG&E.
1 Case 8794 was opened to quantify stranded costs and unbundle retail rates. It is consolidated with Case 8804, a rate decrease proposed for BG&E by the state People's Counsel. According to information posted on the Md. PSC website, hearings in the two cases were set to begin in mid-April.
2 According to the Maryland PSC electric restructuring schedule, unbundled retail prices will go into effect no later than July 2000. In July 2000, 33 percent of retail customer load will be eligible for generation choice, 66 percent in 2001 and 100 percent in 2002.
3 In contrast, BGE network transmission lines and stations have two-directional flows with power sources and both end points thus accepting inter-regional and well as intra-regional bulk power flows. Network transmission costs are about 90 percent of total booked traditional transmission costs.
4 The retail transmission price is based on the FERC-approved wholesale price so that generation choice is not biased by potentially different transmission charges.
5 The transmission function is shielded from these expenses simply because the FERC-approved revenue requirement for wholesale transmission does not include these costs.
6 BGE proposes in its July 1998 restructuring filing to freeze the fuel rate and roll the current fuel price into base tariffs.
7 It must be noted that the retail price unbundling process to some degree will be dictated by the utility's proposed restructuring filing on stranded costs. Price designers in the restructuring phase must learn to live with this reality.
8 The mass market primarily consists of single-phase, secondary service residential and small commercial customers.
9 Under BGE's Rider 11 tariff, customers with power factors of less than 0.90 are supposed to have the demand portion of their bill adjusted for kilovolt-amp impact.
10 The actual 1997 rate of return for the private area lighting service is well above system average. In the restructuring case, BGE proposes equalizing all retail customer class rates of return. Consequently overall revenue must be reduced. The marginal cost study provides a guideline for the reductions.
11 In the future it is probable that an up-front per foot cable installation charge will be necessary to send the correct price signal to the customer on an underground cable extension request. If an up-front cash contribution from the customer is contemplated, the issue of reducing rate base and earnings potential must be weighed with the obvious benefit of better cash flow.
12 Under BGE's net back pricing proposal, the embedded cost-based generation price was required to be estimated by customer class and assumed at the same rate of return as other business lines. With the net back pricing proposal, if the customer chooses an alternative energy supply, a credit will be received on the retail bill based on the avoided generation costs to BGE.
Sidebar by Bruce W. Radford:
The Maryland Model - Key Provisions
State legislation on electric competition allows stranded cost recovery, requiring mitigation, but allows utilities to choose whether to divest their generation assets.
Customer Choice
One-third of residential customers have retail choice by July 1, 2000.
Second-third (residential) has choice by July 1, 2001.
Last third by July 2002.
All commercial and industrial customers have right to choose by Jan. 1, 2001.
Rates and Savings
State PSC must cap total rates paid by consumers for first four years after choice begins.
PSC must guarantee cut (3 percent to 7.5 percent) in residential base rates for first four years (only for customers of investor-owned utilities).
PSC to protect low-income customers via a $34 million universal service fund.
Customers not choosing an alternative supplier take "standard offer service."
Transition Costs
PSC to conduct public hearings to determine transition costs or benefits, and any allocation thereof between stockholders and ratepayers.
Utilities to recover transition costs, if prudently incurred.
Verifiable transition costs subject to full mitigation.
PSC may provide limited exception from transition cost recovery for certain on-site self-generation.
PSC may adjust transition cost recovery to take into account any generation assets sold by a utility or affiliate before June 30, 2005.
Most Notable Feature:
"The Commission may not require an electric company to divest itself of a generation asset or prohibit an electric company from divesting itself voluntarily of a generation asset." Senate Bill, sec. 7-505(B)(9).
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