Fixed costs recovery, renewables adoption, and rate fairness 5 6-14
Fixed Cost Recovery, Renewables Adoption, and Rate Fairness
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
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
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
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
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
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
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
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
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
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
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
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
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
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-
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
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
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
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,
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 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
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
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.
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
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).
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
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
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
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
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
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
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
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
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,
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
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.
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
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
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
Application of NW Natural for a General Rate Revision, Filed December 30, 2011 before the
Oregon Public Utility Commission, See:
“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-
James Bushnell, “The Politics of Renewable Energy,” Energy Institute at Haas, U.C.
Berkeley, Haas School of Business, January 26, 2014.
“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-
Ibid, at 85.
A concise summary of the various approaches and rationales appears in the previously noted
FERC Cost-of-Service Manual, pp. 30-33.
Ibid, p. 29.
Analysis is needed to assess when these various policies overlap and when they are
This analysis may not address when a business enters a leasing contract with the
While utility investments are “lumpy,” MC is used here for simplicity.
Reforming the Energy Vision, NYS Department of Public Service Staff Report and Proposal,
Case 14M-0101, April 24, 2014, p.50.
Ibid, p. 58.
“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-
“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:
Ibid, pp. 5 - 6.
Ibid, pg. 6.
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.
David Heald, “Contrasting Approaches to the ‘Problem’ of Cross subsidy,” Management
Accounting Research, 1996, pp. 53-72.
Ibid, p. 58.
Ibid, p. 69.
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.
Eric Ralph, “Cross-subsidy: A Novice’s Guide to the Arcane,” Duke University, July 27,
1992, p. 15.
Gerald R. Faulhaber, “Cross-Subsidy Analysis with more than Two Services,” The Journal
of Competition Law & Economics, August 11, 2002, p. 442.
Staff testimony Compton/15-Compton/16.
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.
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.