1

Fixed Cost Recovery, Renewables Adoption, and Rate Fairness By

Robert J. Procter, Ph.D.

I. Introduction and Overview

Recovering a utility’s fixed cost has been an issue for quite a long time. Recently,

this issue has been a focus in several newspapers as well as the regulatory forum. One

aspect of this interest is how a utility’s approach to recovering its fixed cost affects the

economics of renewables, particularly Photovoltaic (PV). Another angle that is once

again receiving added political attention is the argument that the social cost of

environmental bads (pollution), negative externalities to economists, should be included

in utility planning. A third focus was a rate filing that proposed a dramatic change in a

gas utility’s rate design that would have caused a major change in its commodity prices.

In testimony filed by Northwest Natural Gas (NWN) in their rate filing of

December 2011 before the Oregon Public Utility Commission (Commission), they

proposed a radical change in their approach to fixed cost recovery.1 Their proposal was

to rely solely on a demand charge for FC recovery. While NWN has no electric service

responsibilities, testimony contained in their filing is relevant to electric utilities. In

addition, how an electric utility proposes to recover its FC has implications for the

success of net metering to promote adoption of renewables. A recent New York Times

(NYT) article2 on the shifting politics of renewable energy provides a good overview of

this set of issues. Remarking on that article, James Bushnell, an associate professor of

economics at University of California at Davis, notes that the majority of charges on a

customer’s bill are to cover the utility’s fixed costs. Bushnell correctly notes that, “We

2

have been recovering fixed costs with variable rates for so long that people do not realize

what the costs [of utility provided power] really are.”3

A number of other articles have appeared that address the growing battle

between utility commissions, utilities, solar companies, local governments, and a

variety of advocacy groups on all sides of this issue. For example, in one article in The

Denver Post, described the conflict as one between competing business models.4

Arguments pro and con about the correct level of benefits that PV provides to the

power system partly hinge on what costs the utility avoids (referred to as Avoided

Costs). As that article illustrates, some PV advocates critique utility assessment of

benefits for excluding important benefits, such as, environmental improvements, and

propose they be added to existing benefit estimates.

Regarding the utility’s avoided costs and cost recovery through rates, it’s

important to understand that these are two separate issues that do overlap. For

example, according to the Denver Post article, the utility has estimated its avoided cost

at about 4.6 cents/kWh compared to a net metering payment of about 10.5 cents/kWh.

A good deal of the acrimony among competing points of view arises because of this

difference.

Summarizing the remainder of this paper, Section II examines the role of the

Commission as that has been expressed in administrative rule, statute, and legal

decisions. It also contains an overview of selected actions by The Federal Energy

Regulatory Commission (FERC) that help provide a counterpoint to some of the

arguments made by NWN. Section III borrows aspects from regulatory economics and

economics of a business. That section forms an analytical footing for the remainder of

3

the paper. Section IV looks more closely at the relationship between determining both

a rate design and rate setting and how those decisions can affect PV generated

electricity. Section V examines in more depth several issues that arise about rate design

and rate setting using material presented in Section III. Specifically, six explicit or

implicit assumptions in NWN’s testimony supporting its Long-run Incremental Cost

(LRIC) Study are critiqued. Finally, Section VI will present a selected set of summary

observations.

II. Legislative Action and Court Rulings Define The Role of the Commission

We must begin with a short overview of legislative direction and court rulings.

Legislative direction and court rulings help to define how much latitude NWN (or any

utility rate making under Commission jurisdiction) has to define both a proposed rate

design and set of rates and the Commission’s latitude to set rates and rate design.

Referring to Oregon statutes, the “The legislature has authorized the PUC, in

regulating the rates of public utilities within its jurisdiction, to “make use of the

jurisdiction and powers of the office to protect [utility] customers, and the public

generally, from unjust and unreasonable exactions and practices and to obtain for them

adequate service at fair and reasonable rates. [Emphasis added]”5 Therefore, the

legislature delegated to the Commission the right and obligation to determine if a

utility’s actions are unjust and unreasonable and impede adequate service at reasonable

rates. How to determine whether some action is unjust and whether rates are fair and

reasonable was not specified.

Turing to selected court rulings to seek greater clarity regarding the standards

used to determine if a utility’s actions are unjust or rates are unfair and unreasonable

4

sheds little light on these matters. One ruling states “...Rates are fair and reasonable for

the purposes of this subsection if the rates provide adequate revenue both for operating

expenses of the public utility *** and for capital costs of the utility, with a return to the

equity holder that is: (a) Commensurate with the return on investments in other

enterprises having corresponding risks; and (b) sufficient to ensure confidence in the

financial integrity of the utility, allowing the utility to maintain its credit and attract

capital.”6 Anyone with more than passing knowledge of the ratemaking process will

understand that this guidance amounts to building a very wide gate through which the

utility may drive its rate proposal.

The ruling also notes that the Legislature’s direction to the Commission is also

quite broad on this issue and that the Court’s review of rates previously established

through Commission Orders is typically very limited. It goes so far as to argue that

even if an aggrieved party files suit and the Court remands the Commission’s Order, the

Commission is free to review the case using its existing delegated authority, unless the

remand has specifically limited its discretion. As a result, we must conclude that in all

but the most egregious cases, the Court is sending a signal to stakeholders that the

Commission will be the venue for rate case decisions.

How does one distinguish between unfair and unduly discriminatory, on the one

hand, from fair and reasonably discriminatory, on the other? Here again, that

determination lies primarily with the Commission. Oregon courts have acknowledged

that when the Commission is acting within its legal authority to balance the competing

policy objectives embedded within a set of rates, even if one or more aggrieved party

5

believes that those rates are unfair, unjust and unduly discriminatory, the aggrieved

party will likely not prevail if they choose to petition the court for redress.

It’s also noteworthy that this appears to grant a good deal of latitude to the

utility to determine a set of rates, as long as the utility is able to mount a persuasive

defense of their proposed rates. The defense should define why its proposed rates and

rate design are just and reasonable and not unduly discriminatory. As anyone who has

participated in a rate case knows, rate cases are not about capital ‘T’ truth. They are

adversarial processes in which each stakeholder attempts to maximize its benefits and

minimize its cost exposure. Since court rulings have clarified that the Commission is

the authority empowered to make the judgment call on what rates are not unduly

discriminatory, an aggrieved party faces a very high hurdle to persuade a court that the

rates adopted by the Commission are unduly discriminatory. Of course,

Commissioners are either elected or appointed, and as such, are political actors. They

are also fallible human beings.

While The FERC has no authority over retail rate setting, it is important to

review The FERC’s approach to one particular aspect of cost allocation that plays a

crucial role in both NWN’s rate design testimony and how to recover the utility’s FC.

The FERC has adopted various solutions to the policy question of what amount of FC

should be recovered using a fixed charge versus what amount should be recovered

using a variable charge.7 The FERC rightly notes that the issue of what amount of FC is

recovered using a commodity charge has implications for the rate levels assigned to

various customer classes. They also rightly note that the total cost of service of a given

customer will depend on that customer’s load factor.8

6

Clearly, the FERC is aware of these ramifications of rate design and rate setting.

They understand that decisions about how to recover FC has very real impacts on

different customer classes (for example, residential, commercial, industrial) as well as

on different customers within a given class. For example, if you own a 4,000 sq. ft.

house, you would prefer a lower variable charge and a higher fixed charge than if you

owned a 1,000 sq. ft. house, all else equal.

It’s worth noting that the FERC varied how fixed costs should be recovered.

They first assigned all FC to the commodity charge and over the years shifted between

all FC being assigned to the customer charge to having a portion of them included in

the variable charge and a portion assigned to the customer charge. These various policy

approaches to allocating FCs were sometimes supported on the basis of whether peak

use or annual consumption was paramount in planning. At other times a particular

allocation of FC between the variable and the fixed charges was justified on the basis of

how they supported a particular policy goal, such as increasing consumption.

III. Pricing what you sell, Recovering your Costs, and Staying in Business

Business economics argues that efficient resource use mandates that price, P, or rate

in the case of a utility, equal marginal cost (MC), P=MC. It is important to remember

that this rule is the conceptual approach to help find the profit-maximizing level of

production (think sales) for the business. It is the guiding light aimed at helping the

business decide resource use. The minimum requirement for a business to survive over

the long term, say a “mom & pop” (M&P) business, is that it covers its variable and FC

and earns a sufficient accounting profit so that the business owner(s) may cover their

personal expenses.

7

We know that retail electric and gas utilities are regulated monopolies for some

very good reasons. Society isn’t served well by those businesses going in and out of

business or using their monopoly power to set rates that exceed their variable and fixed

costs, including the cost of capital. As a result, economic regulation has historically

been the solution to achieve the dual goals of lowering rates and increasing output

while providing the utility an opportunity to earn a rate of return on invested capital.

Turning to pricing of milk at the M&P, when we go to buy a gallon of milk, we

pay one price for that milk. That one price must be cover the business’s fixed and

variable costs for that milk plus some return (accounting profit) to the M&P owner.

For the regulated service, such as electricity, residential customers have generally faced

a price for their electricity usage, and a separate charge, typically referred to as a

demand charge, to cover the utility’s costs that are independent of the amount of kWh’s

consumed in a given month. I cannot think of any other product or service bought and

sold in a market that has this price structure.

Now, we know that if the commission sets the commodity charge equal to MC

for a kWh of electricity, this will not recover the utility’s FC or any other overhead

costs, unless there is a demand charge. This is conceptually the same as the M&P

setting the price of a gallon of milk equal to its cost for milk, labor, and so forth, with

no revenue from milk sales able to cover its overhead, which includes its FC. The

M&P can stay in business for a short time while the business loses money, but over

time it will shut its doors.

We know that at the margin, the value of a kWh of new generation to the utility

equals the cost that the utility avoids if its purchases this kWh from its next more

8

expensive source. In short run planning, such as meeting loads today, tomorrow, and

anywhere from several months to several years into the future, the avoided cost will

generally reflect the short run costs of acquiring that kWh either from owned surplus

generation or its purchases from the power market. In longer run planning, such as

meeting loads several or more years down the road it often, though not always, reflects

the variable and FC, including financing costs, of constructing and operating a new

power plant. What type of plant will likely be built depends on the region of the

country. Here in the Pacific Northwest, that will typically be a simple (SCCT) or a

combined cycle combustion turbine (CCCT), when a plant is economically justified.

Business economics gets more complicated when statutes mandate the utility

acquire specific amounts of power from specific types of generation. This is

conceptually similar to requiring the M&P business (or the wholesale supplier to the

M&P business) to acquire milk from a specific supplier (specific dairy or specific

cows) because of it has a better environmental profile.

There are a number of approaches to dealing with this problem of different

generation sources having different environmental profiles. One approach that’s been

used to date is to rely on the state’s policing power to establish Renewable Portfolio

Standards (RPS). Environmentalists have also argued that some cost premium should

be included in utility planning to help put PV on a level playing field with fossil

generation. Yet another method to encourage PV adoption is net metering. 9

Transactive Energy (TE) may provide a different approach to electricity pricing

that both mimics how virtually every other retail product is priced while also addressing

the issue of recovering the utility’s FC. At this point, how an industry that produces

9

such a strategic product like electricity shifts from the historical model at the retail level

to one envisioned by TE is less than clear.

IV. Utility Production Costs, Rate Design, Cost Recovery, and Payments for PV-

Generated Electricity

How much should the utility be willing to pay for a kWh of renewable energy?

Both the NYT and the Denver Post article, along with other pieces, such as that by

Bushnell, address the argument that the utility should monetize the environmental

benefits of a kWh of PV generation. What was missing is any discussion of the scope

of commission authority to mandate that the utility pay a premium for the PV generated

electricity. There are states, such as California and Oregon, to name only two that have

mandated that the electric utilities in those states acquire specified amounts of

electricity from renewable generation. These RPS standards are proxies for paying a

premium for kWh’s generated from renewables. Before such a premium is included in

what the utility pays for that kWh from a renewable generator, we must be careful to

avoid double - counting the environmental benefit of renewable generation.

As noted earlier in this paper, environmental advocates support including a cost

adder to thermal resources in the utility’s avoided cost studies. This is a second

approach to leveling the field for PV generated kWh’s. A third approach to promoting

PV adoption is to change the utility’s rate design.

In states with net metering statutes, those statutes typically require the utility to

pay the PV generator the energy rate that would otherwise have been paid by that entity

to the utility. The rate for that kWh at the point of consumption will be the utility’s

commodity rate for delivered energy posted in the appropriate rate schedule. If that

10

energy rate only covers the utility’s variable costs, such as for fuel and some amount

for variable operating and maintenance expenses, then the price the utility will be

willing to pay for a kWh from PV will be below the sum of variable and capital costs to

install it at the home or business. This problem arises in part because the PV generator

faces both the variable and all the capital costs of purchasing and installing the PV.10

By including some amount of the utility’s FC in the energy charge, this essentially

increases the value of each kWh generated and consumed at the point of generation.

As capital costs are included in the energy charge, the payment for a kWh

generated from PV will more closely approximate the utility’s LRIC for an incremental

kWh of electricity. Therefore, one approach to addressing some of the debate raised in

the NYT and Denver Post articles is mandating that the utility use its LRIC as its

avoided cost for purposes of determining the value of a kWh from PV.11 If the utility’s

LRIC is used, then it’s seems only fair that the utility’s obligation to purchase PV

generated kWh’s also be constrained to the amount of kWh’s identified in its least-cost

plan.

As the reader knows, PV-generated kWh’s reduce the utility’s revenues, all else

equal. In part, this is what is being addressed in a report from the staff of the New York

Public Service Commission. It notes that under rate of return (RoR) regulation “…

utilities still have an incentive to maximize their capital expenditures, and little

incentive to optimize system efficiency to reduce capital needs.”12 As lost revenues

reduce the net returns to the utility, at some point it risks not achieving its allowed RoR

even if its overall efficiency is improved. Lost revenues also add another dimension to

existing debates about rate fairness since they lead to a reallocation of costs to

11

remaining loads leading to higher rates for customers meeting all their electricity needs

through purchases form the utility, all else equal.

Finally, the paper from the New York Commission (NYC Paper) on reforming

the energy vision, addressed other rate design issues that have not been discussed here.

Among them is the importance of dynamic price signals (DPR) that”…reflect system

needs and costs over short and long term horizons.”13 The importance of DPR will

vary by region of the country and by utility within a region. Here in the Pacific

Northwest (PNW), it is less important for the PNW as a whole since average energy

rather than capacity tends to be the planning criteria. However, on a utility-specific

level capacity can be an issue under certain conditions. Additionally, the issue of DPR

is receiving significant attention already.

The NYC Paper does raise an important issue going forward – new rate designs

that explicitly focus on the value provided by an increasingly two-way transmission and

distribution (T&D) system. Hopefully, as those discussions move forward they will

distinguish between cost, price, and value from the viewpoints of the buyer and the

seller. These three concepts (cost, price, value) are different. Accurately pricing the

services provided by a two-way T&D system will tax accounting systems that are the

basis of rates development unless market-based approaches are employed. Providing

accurate price information is important for both PV owners as well as the non-PV

owner who faces the risk of higher than needed rates that arise from reduced sales due

to PV adoption.

TE is one approach to pricing of products and services that is receiving more

attention. It is focused on increasing the efficient use of the electricity infra-structure,

12

from generation through consumption taking account of a radically transformed

electricity sector with many more scenarios than are accommodated by rate tariffs. It

envisions a shift away from rates posted in tariffs to a framework where prices are

market driven, think of this as dynamic pricing taken to the limit, where posted rates

being replaced by forward and spot transactions.14

V. Rate Design and Rate Fairness

Arriving at a set of rates is based on more than guidance from regulatory

economics. When the analyst moves from regulatory economics that supports

setting prices based on cost causation principles, and into the practice of developing

a set of rates for the utility, the goals and objectives of the utility, the commission,

and other stakeholders become quite significant. This section critiques implicit and

explicit assumptions made in the NWN filing that can have bearing on the utiltiy’s

commodity price, its FC level, and what it willing to pay for PV generated

electricity. They also bear on the issue of fairness.

A. The MC Study does not reflect actual costs

NWN’s initial filing contained its LRIC study and supporting testimony

(Feingold).15 Feingold argued, “Marginal cost studies do not reflect actually

incurred costs, but rely on estimates of the expected changes in cost associated

with changes in utility service.”16 It’s true that such studies examine changes in

cost as sales are expected to change. It’s also true that a MC study does not

need to rely on actually incurred costs. However, MC, or its substitute

incremental costs, does not require there to be new electricity or gas deliveries

that exceed existing sales. Depending on projections of sales growth and future

13

commodity and capital costs, current costs may provide a reasonable estimate of

its LRIC. That is, an estimate that is within the decision maker’s risk tolerance.

Additionally, if MC (or LRIC) is based on future costs that exceed current

costs, those results may have broader applicability than Feingold suggests.

While he limits its use to the situation where new sales push existing sales

above the system’s design day requirements, the MC (or LRIC) helps to provide

information to customers about the benefit of limiting growth in consumption

before system capacity is reached. As we’ve seen earlier in this paper, while

this is a very important pricing signal to more effectively manage existing utility

assets, the effectiveness of this pricing signal depends on what rate design is

used.

B. The MC Study should exclude equipment repair and replacement costs

Feingold argues that including distribution mains replacement costs in

MC becomes relevant only when “…new customers are added to the

system…[which] may increase design day requirements above…[what] existing

facilities can serve…”17 Arguing that when use by existing customers lies below

peak delivery capability there should be no cost included in the LRIC associated

with transmission & distribution (T&D) buries a policy issue in the analytics of

the LRIC study. When existing customers don’t face costs associated with

sustaining system capabilities, those customers are implicitly encouraged to

increase their consumption. Maybe NWN and the Commission intend that

result; but, policy decisions are better defended by the executives who are

responsible for setting the overall rate strategy.

14

Further, when the cost of replacing existing infrastructure is excluded

from the LRIC, it’s no longer a reasonable approximation of the utility’s LRTC,

unless the utility will not face spending to sustain system capabilities above

what is currently embedded in rates. Rather, it is reasonable to include some

amount of costs in the LRIC study as a contingency to help assure that rates

include costs to sustain system delivery capabilities. In doing so, again

depending on the overall rate design, the commodity charge will include costs

associated with sustaining system capabilities. While this won’t be as strong a

signal to wisely manage use as will a signal that includes some amount of the

utility’s FC, it’s a better signal than ignoring these costs when developing the

utility’s MC.

C. Uses must be in conflict for common (joint) costs to arise

Feingold argues, “Common costs occur when the fixed costs of

providing service to one or more classes, or the cost of providing multiple

products to the same class, use the same facilities and the use by one class

precludes the use by another class” [Emphasis added]. The part of the

definition of common costs highlighted in italics is neither a necessary nor a

sufficient condition for common costs to exist. When a good or service is

bought and sold in a market, like electricity, gas, and water are, common costs

arise only when the use of a particular facility, say a distribution line, by one

class (or one customer within a class) does not preclude its use by another class

(or another customer in that same class).

15

Gas flowing in the distribution system pipe, or electricity flowing down

the distribution line, flows to all customers along that distribution segment.18

As a result, each customer’s use of the commodity occurs because each

customer is also implicitly ‘using’ the services of the distribution system. My

use does not impede my neighbor from also ‘using’ the wires, poles, or pipes,

and compression stations to meet their consumption. Rather, my ‘consumption’

of those facilities and my neighbor’s ‘consumption’ of the same facilities are in

common. This is what gives rise to the need to apportion those costs to various

uses, otherwise known as common, or joint product, cost allocation.

D. The Stand Alone Cost test can be used to find cross-subsidies

Allocating joint product costs is a well-traveled road in both economic

theory and regulatory economics, and as such there is no reason to delve into

pros and cons of one method versus another method any further in this paper.

Suffice it to say, there are any number of approaches that have been used in an

effort to craft a value-neutral approach to this very real problem. Unfortunately,

there is no way to avoid a value-laden approach to joint cost allocation. The

approaches I have seen proposed to determine if a given joint cost allocation

results in subsidy-free prices are far from the rigorous methods summarized in

this section. Maybe one reason for that dichotomy is the sheer complexity

involved in implementing the rigorous methods that follow.

There is an overlap between joint cost allocation and subsidy free

pricing. Where common costs exist, economists argue that efficient pricing

16

requires that joint costs be assigned to the product and/or party that give rise to

them. This is not a value neutral approach.

Feingold proposes that we determine if a particular rate excludes a

subsidy by applying the following rule: a subsidy free price is one where the

price of the service exceeds MC but lies below the stand-alone cost (SAC) of

that service.

To correctly implement the SAC methodology requires developing a

proxy utility in order to have a reference for cost comparisons. Heald argues

that it is virtually impossible to construct such a benchmark.19

It’s the complexity inherent in the SAC methodology that causes him to

conclude that it’s virtual impossible to correctly implement the test. That

complexity arises from the fact that the test requires that the analyst know the

cost functions of the existing and alternative technologies, along with the data

they require. He warns us that it’s the asymmetric information between the

existing business, regulators, and potential entrants that makes accurate SAC

testing virtually impossible. Finally, comparing each output of the existing firm

to the possible cost of each product produced separately by potential entrants

can result in very different conclusions partly depending on how rapidly

technology is changing and the strength of economies of scope and scale

enjoyed by the incumbent firm.20

His conclusions rightly include the observation that cost allocation is

partly technical and partly political. More to the point, he argues that efforts to

find technical solutions to this problem of determining if subsidies exist, where

17

they are, and how large they are will only generate frustration. The crucial issue

for Heald is the challenge of developing comparable cost data. In his words,

“Without comparable cost data, the cross subsidy problem cannot be

satisfactorily addressed.”21

Jamison echoes Heald’s conclusion noting, “…it is infeasible for

regulators to establish subsidy-free prices with any degree of confidence.”22

Explaining why this is an impossible task, Jamison argues that to develop

subsidy-free prices requires the regulator to know “…the utility's cost function,

its competitors' cost functions, their competitors' cost functions, and so on until

all combinations of products which could have economies of joint production

and that could be affected by the utility's prices, have been considered.”23

Ralph supports Heald and also noted that Faulhaber (who authored a

seminal article on the topic of cross-subsidization) demonstrated that the test for

subsidy free prices “…must be applied to all possible groupings of consumers

(or products) as well as to each individual consumer, since each individual may

cover their incremental costs, and yet some group of consumers may not…”24

Falhaber himself felt the need to weight in on the cross-subsidy debate

with a short paper noting a tendency for analysts and researchers to incorrectly

test for cross- subsidization. In particular, he reiterates a crucial conclusion

from his 1975 paper that, “both the SAC and the IC [incremental cost] tests

must be applied not only to each service individually, but to all possible groups

of services.”25 He then hammers home the point that applying these tests to

individual services in isolation, which he notes has tended to be the case in the

18

regulatory arena, is a fatal error and cannot be considered a reasonable

approximation, or ‘good enough’ approach, if you will.

It is little wonder that Jamison, Heald, and Falhaber were less than

sanguine about the ability of a regulatory body to determine whether or not a set

of proposed prices contained any cross-subsidies. As a practical matter, a

regulatory commission can partly circumvent this problem by requiring the

utility to perform this work. That will then require its staff to opine on the

adequacy of the utility’s work. Over time, both the utility and its regulatory

commission could develop this capability only if there is a strong commitment

on the commission’s part, since it will be costly and time consuming. Various

stakeholders will likely argue that such a requirement amounts to adding

analysis as complex as least-cost planning with little or no gain.

E. When no cross-subsidy exists, the rates are just and reasonable

Feingold implicitly argues that rates should be considered just and

reasonable when costs have been assigned to the product and group causing

those costs. Needless to say, even if these tests were implemented consistent

with the requirements laid out above, and even if they demonstrated that no

cross-subsidy exists, some stakeholder(s) will likely judge a set of rates to be

discriminatory or unjust.

One alternative pricing scheme from economic price theory promotes

assigning costs not the customer that gives rise to them is known as the inverse

elasticity rule. This pricing guideline argues that the commodity price of a kWh

should be set higher for customers with fewer options, and lower for the

customers with more options. This rule would then results in a higher

19

commodity price for low-income customers than for higher income customers.

This is a second approach to resolving the problem of determining if there are

any cross subsidies. Oregon Commission staff proposes yet a third method in

their testimony filed in the NWN case. They argue that when cost causation

remains murky, the method to use that retains fairness requires assigning those

costs to the different products and customer classes based on benefits

received.26

Each of these three approaches to concluding no cross subsidy exists and

therefore a set of rates are fair and just do not meet the requirements for

determining if a cross subsidy exists that were summarized in the previous

section. In addition, while each of these rules may appear objective, they are

not. For reasons enunciated in this paper, no such objective rule exists. The

economist has no solid perch from which to opine on the sanctity of one method

versus a competing method of judging fairness.

F. Economic theory requires that fixed costs be recovered using a fixed charge

Section II above addressed this issue without identifying it. We saw

that in competitive markets, P=AC in both short run and long run equilibrium,

and AC covers both fixed and variable costs.27 Since AC includes both fixed

and variable costs, this breaks down Feingold’s argument that economic theory

supports placing all the fixed charges into the customer (fixed) charge and

recouping all variable costs in a commodity charge.28 As a result, he appears to

misread economic analysis while also ignoring the role policy objectives should

play in rate design decisions. If the M&P business is unable to cover its fixed

cost at that market- clearing price using the profit maximizing level of output,

20

then over time, the best course of action is for its owners to go out of business.

This is quite different from arguing that economics supports recovering fixed

cost using a fixed charge.

VI. Summary Observations

Arguments about fairness are endless. They are endless because they are

positional, not factual. However, they raise issues of undue discrimination that

go beyond debates about whether or not a set of rates (prices) are subsidy free.

These debates are often resolved either in a settlement acceptable to most or all

parties to the rate case, or by the regulatory commission in the absence of a

settlement.

As we have seen, there are a number of arguments made in NWN’s

initial testimony that this author calls into question. Even though the ruling on

NWN’s filing was released in later 2012-early 2013 that set aside a significant

portion of their proposed revision to their existing rate design, the issues raised

in this paper are still relevant to subsequent rate filings by NWN, by other

regulated utilities before commissions in other jurisdictions, and also to the

arguments made about fixed cost recovery in debates about payments by the

utility for PV and other renewables. A series of specific observations follows.

o RPS standards should be viewed as proxies for paying a premium for kWh’s

generated from renewables. Before a premium is included in the utility’s

avoided cost analysis or to what the utility is willing to pay for power from a

renewable generator, the company must be careful to avoid double counting

the environmental benefit of renewable generation.

21

o How fixed costs are recovered is a rate design policy issue. Thought should

be given to how the regulatory approach using RPS standards work versus

allocating some or all fixed cost to the commodity charge.

o Utilities face lost revenues when PV generation substitutes for purchases

from the utility. Therefore, the utility has a built in incentive to minimize

the utility’s cost of kWh’s from PV and the number of kWh’s acquired.

Lost revenues from PV are no different than lost revenues from energy

efficiency (EE) investments. As with EE lost revenues, while the utility’s

total revenues are reduced, all else equal, an argument can be made that the

PV payment on a per kWh basis should be set somewhat less that the per

kWh LRIC. This reduction can be based on the argument that PV does

place costs on the utility as a result of the utility’s on-going obligation to

serve the needs of its customers. This also works to mitigate lost revenues.

o While benefit-cost analysis was not addressed in this paper, these lost

revenues should not be counted as a cost of installing PV. Those lost

revenues are an income transfer away from the utility and to other parties.

o As fixed costs are included in the energy charge, the payment for a kWh

generated from PV will more closely approximate the utility’s LRIC for a

kWh of electricity. Commissions should consider mandating that the utility

use its LRIC as its avoided cost for determining the value of a kWh from

PV.

o Transactive Energy may be one approach to addressing many of these

issues. Much work is yet to be done in that area including defining practical

22

ways to test this approach. This work must include identifying an explicit

and concrete approach to the transition from the historical approach to that

envisioned by TE.

o No objective criterion exists to allocate common costs. What this means is

that the impact of differing approaches on real people must be the basis for

selecting one method for common cost allocation over competing methods.

o Economics does not mandate that fixed costs must, or should, be recovered

using a fixed charge. As the regulated commodity’s price approaches

average costs, more of the utility’s fixed costs are recovered. Allocating

more fixed cost to the commodity charge will move the commodity price

towards average cost.

o No objective criteria exist to analytically resolve arguments about which

rate design and cost allocation is fairer. It was argued that the SAC can be

an objective test, but it has significant implementation challenges. Even if it

could be implemented objectively, that will not resolve the policy debate

that revolves around rate design and cost allocation. That must be faced

head on.

23

End Notes

1 Application of NW Natural for a General Rate Revision, Filed December 30, 2011 before the Oregon Public Utility Commission, See: http://edocs.puc.state.or.us/efdocs/UAA/ug221uaa142959.pdf 2 “Fissures in G.O.P. as Some Conservatives Embrace Renewable Energy,” by John Schwartz, New York Times, Jan. 25, 2014, See: http://www.nytimes.com/2014/01/26/us/politics/fissures-in-gop-as-some-conservatives-embrace-renewable-energy.html?ref=us&_r=0 3 James Bushnell, “The Politics of Renewable Energy,” Energy Institute at Haas, U.C. Berkeley, Haas School of Business, January 26, 2014. 4 “Battle over rooftop solar heads to Public Utilities Commission,” by Mark Jaffe, The Denver Post, January 12, 2014, See: http://www.denverpost.com/business/ci_24889841/battle-over-rooftop-solar-heads-public-utilities-commission#ixzz2vrj9bxk4. 5 Ibid, at 85. 6 Ibid. 7 A concise summary of the various approaches and rationales appears in the previously noted FERC Cost-of-Service Manual, pp. 30-33. 8 Ibid, p. 29. 9 Analysis is needed to assess when these various policies overlap and when they are complementary. 10 This analysis may not address when a business enters a leasing contract with the homeowner. 11 While utility investments are “lumpy,” MC is used here for simplicity. 12 Reforming the Energy Vision, NYS Department of Public Service Staff Report and Proposal, Case 14M-0101, April 24, 2014, p.50. 13 Ibid, p. 58. 14 “Transactive Energy: A Sustainable Business and Regulatory Model for Electricity,” Baker Street Publishing, See: On slideshare, transactive-energy-keystone-of-sustainable-electricity-markets. Also, “The Future of Transactive Energy in North America,” by David Katz, Presented at Fourth Annual Smart Grid Modernization Summit, Toronto, Canada, August 21, 2013. See: www.slideshare.net/dkatz2/the-future-of-transactive-energy-in-north-america?qid=4df43d7c-723d-47c1-8bd4-773be7ec4582&v=qf1&b=&from_search=3 15 “Direct Testimony of Russell A. Feingold. LONG-RUN INCREMENTAL COST STUDY / RATE DESIGN EXHIBIT 1100” in Application of NW Natural for a General Rate Revision, Filed December 30, 2011 before the Oregon Public Utility Commission, see: http://edocs.puc.state.or.us/efdocs/UAA/ug221uaa142959.pdf 16 Ibid, pp. 5 - 6. 17 Ibid, pg. 6. 18 An electric distribution line can have voltage degradations that impose real costs on customers closer to the end of that line. This issue is set-aside at this time. 19 David Heald, “Contrasting Approaches to the ‘Problem’ of Cross subsidy,” Management Accounting Research, 1996, pp. 53-72. 20 Ibid, p. 58.

21 Ibid, p. 69. 22 Mark A. Jamison, “Theory and Application of Subsidy-free Prices,” from Industry Structure and Pricing: The New Rivalry in Infrastructure, Kluwer Academic Publishers, 1999, p. 140.

24

23 Ibid. 24 Eric Ralph, “Cross-subsidy: A Novice’s Guide to the Arcane,” Duke University, July 27, 1992, p. 15. 25 Gerald R. Faulhaber, “Cross-Subsidy Analysis with more than Two Services,” The Journal of Competition Law & Economics, August 11, 2002, p. 442. 26 Staff testimony Compton/15-Compton/16. 27 In competitive markets, P=MC and in equilibrium, P=MC=AC can also occur in the short-run. It must obtain in the long run since any other result will either attract new business to the industry or result in business leaving the industry thereby forcing price back to P=MC=AC. 28 From the standpoint of cost recovery risk, cost recovery risk is reduced using the method proposed by Feingold. However, that argument does not appear in his direct testimony.