20160812Terzic Direct.pdf

Ronald L. Williams, ISB No. 3034
Williams Bradbury, P.C.
1015 W. Hays St.
Boise, ID 83 702
Telephone: [phone]
Email: [e-mail]
Attorneys for Intermountain Gas Company
BEFORE THE IDAHO PUBLIC UTILITES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
INTERMOUNTAIN GAS COMP ANY FOR )
THE AUTHORITY TO CHANGE ITS RATES ) Case No. INT-G-16-02
AND CHARGES FOR NATURAL GAS )
SERVICE TO NATURAL GAS CUSTOMERS )
IN THE STATE OF IDAHO ) �����������)
DIRECT TESTIMONY OF BRANKO TERZIC
FOR INTERMOUNTAIN GAS COMPANY
August 12, 2016
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Please state your name, title and business address.
My name is Branko Terzic and my business address is 1800 M Street NW,
Second Floor, Washington, D.C. 20036.
By whom are you employed and in what capacity?
I am employed as a Managing Director at the Berkeley Research Group.
On whose behalf are you testifying?
I am testifying on behalf of Intermountain Gas Company ("Intermountain" or the
"Company")
Mr. Terzic, please describe your educational and professional background.
I have a B.S. in Engineering from the University of Wisconsin - Milwaukee. I
have over four decades of regulatory, consulting and management experience in
the natural gas and electric public utility sectors. My regulatory experience
includes service as a commissioner on the Public Service Commission of
Wisconsin (1981-1986) and on the Federal Energy Regulatory Commission
(1990-1993). My management experience in natural gas includes serving as
Chairman, President and Chief Executive Officer of Yankee Energy System Inc.
and its main subsidiary Yankee Gas Services Company, a distribution gas utility
in Connecticut. I have also served as a consultant to both private corporations and
to government agencies ( domestic and international) on a range of regulatory
issues affecting the electric and natural gas utility sectors. I am a member of the
Society of Utility Regulatory Financial Analysts, the U.S. Association for Energy
Economics, the Natural Gas Roundtable, and the Association of Energy
Engineers, among others. I have guest lectured on energy topics at Johns Hopkins
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University, Yale University, Syracuse University, and George Washington
University, and am currently a faculty member at the Washington Campus
( sixteen university MBA members), where I continue to lecture on issues related
to the energy industry. A copy of my curriculum vitae is attached as Exhibit 17.
What is the purpose of your testimony?
My testimony is broken into two parts.
First, I intend to explain why the Idaho Public Utilities Commission (the
Commission) should approve Intermountain's proposal, presented in the
testimony of Lori B. Blattner, 1) to increase the customer charge for residential
and commercial customers. and 2) presented in the testimony of David Swenson,
to introduce a demand related rate for industrial customers.
In the second part of my testimony, I intend to explain why the
Commission should approve the Company's decoupling proposal called a Fixed
Cost Collection Mechanism, as presented in the testimony of Michael P.
McGrath.
I. CUSTOMER CHARGE
What is the ratemaking basis for customer charges and a demand related
charge?
Both of these charges have their basis in the fact that public utilities, such as
electric, natural gas and water utilities, are both capital intensive and have other
fixed costs as a proportion of their annual revenue requirements. This means that
the utility incurs these costs regardless of the level of natural gas volumes flowing
through the distribution system.
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Given that fact, it seems reasonable to charge a fixed monthly fee to
recover some or all of these costs. It seems reasonable to me that residential and
commercial customers would understand the basis for a "customer" charge as
representing a charge to recover some or all of the costs to deliver, or distribute,
natural gas to their home or business and to meter and bill the same. Ms.
Blattner' s testimony presents the disparity between the current customer charges
and the actual level customer costs associated with providing monthly service.
The introduction of demand based charges for the larger industrial gas
customers is, in my opinion well overdue. There is a sound theoretical and
practical basis for demand charges and this has been recognized for over a
century. For example, a demand rate was developed by the British engineer Dr.
James Hopkinson in 1892. In the U.S. the rate engineer Harry Barker, writing in
the book Public Utility Rates (1917) describes Hopkinson's work and notes that at
that time a three part rate was proposed with " ... a charge based on the customer's
maximum demand at any time ( for this is related to the investment for that
customer) .. a second part, proportional to the amount of service shown by
meter ... a third part - a fixed sum to cover the cost per customer of expenses
proportional only to the number of customers."(P.7) Notice that this was written
at the tum of the last century where it was already recognized that customer
demand directly caused the necessary level of investment and that a "customer
charge", the 'third part" in his summary, was warranted.
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A fixed charge per month for large industrial customers has already been
adopted by the natural gas utility serving Northern Idaho and by other gas
distribution companies in the Northwest as well.
What is the origin of fixed costs in a public utility revenue requirement?
The four major components of a public utility's annual revenue requirement, the
basis for rates, include 1) operating and maintenance expense, 2) depreciation
expense, 3) taxes and 4) return of rate base. Even upon casual inspection one can
see that few costs vary in the test year with volume of service.
For example, depreciation and return do not vary with customer volumes
during the test year. The annual depreciation expense ($21,707,112) is based on a
rate base and annual depreciation rate both approved by the regulator. So these are
"fixed" costs. Likewise the annual return is based on the approved rate base and
approved rate of return. The return too is a fixed cost. Property taxes are fixed and
based on rate base. Income taxes are based on the approved return times the tax
rate. Leaving us with the cost category of annual "operating and maintenance"
expenses which consist of labor costs - mostly fixed payroll and benefits with
some overtime. In sum, for a gas distribution system, a significant high level of
costs are fixed during the test year.
Why is there such a high level of fixed costs in a natural gas distribution
utility?
First consider that a natural gas distribution system is designed and built to 1)
connect all customers to the distribution grid, and 2) to meet the maximum peak
demand required by customers. The size needed and commensurate reasonable
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construction costs are approved by the regulator and the approved capital costs
become the main part of the utility's rate base. Utilities are capital intensive
meaning that there is a large capital investment needed for every dollar of
revenue. Gas distribution companies typically need a dollar or more of investment
for each dollar of revenue.
The term demand (also called capacity) of a utility system is the
cumulative peak demand of all customers in terms of usage during the peak day.
A natural gas system is designed and built to meet the "design peak day" which is
the peak load that would occur if the system experienced the occurrence of the
lowest temperatures during the heating system." 1 In the case of a natural gas
distribution system this demand is expressed in term of therms or cubic feet of gas
which can be delivered on the peak day.
What is the basis for the establishment of customer and demand charges in a
utility system?
The questions of both the establishment and level of customer charges and
demand charges are key issues in the subsequent cost of service studies (COS),
also called allocated cost of service studies (ACOSS). These COS studies provide
the basis for 1) allocation of the revenue requirement to different classes of
service and 2) provide information for the design of ultimate utility rates.
Cost of service studies can be performed on the basis of embedded
(accounting) costs or on estimates of Long-run marginal or Short-run marginal
costs. For regulated utilities in the US, mostly it is the embedded costs which are
1 Gas Rate Fundamentals, 4th Edition, American Gas Association Pate Committee 1987 P.229
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the basis for a cost of service study and ensuing apportionment. As more fully
described in the testimony of Ms. Blattner, the COS proceeds by taking the annual
revenue requirement and apportioning it in three steps: functionalization,
classification and allocation. The functions are storage and gas supply,
transmission, distribution, other customer costs and revenue related costs. The
classification apportions the previously functionalized costs to demand related
( capacity), commodity related (gas volumes) and customer related costs. The third
step is to allocate the classified costs to the various customer classes. Demand
costs relate to the peak usage of a utility's customers. The end result is that the
COS develops the revenue required from each class of customer based on the
addition of the customer, demand and commodity costs attributable to that class.
The next step is the design of utility rates for each class guided by the
regulator's direction as to what portion of the customer, demand and commodity
related costs should go into a volumetric charge and how much into fixed monthly
charges.
What underlying principle is the basis for allocating demand costs in a cost
of service study?
According to Professor Alfred Kahn in The Economics of Regulation (1988) the
basis for demand allocation is "the respective causal responsibilities of various
buyers" (P.95/I), or in other words what is known among regulators as the "cost
causer is the cost payer" principle. Kahn elaborates that the "proper measure of
that responsibility is the proportionate share of each customer to total demand
placed on the system at its peak."
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This view is confirmed by Drs. Paul J. Garfield and Wallace P. Lovejoy in
Public Utility Economics (1964) as "The annual peak demand on the system
determines the size of the plant; the latter essentially determines the total demand
or capacity costs." They also point out that "the major difficulty arises in the
allocation of a cost category designated demand or capacity costs" and has "been
the subject of study since the tum of the last century [201h]"
Probably the most quoted authority on public utility rate making is
Professor James Bonbright writing in Principles of Public Utility Rates. In
discussing the various cost apportionment formulas for capacity cost available,
Bonbright writes "of the formulas described the one that would probably come
closest to receiving support from the economists, at least from the standpoint of
cost analysis, is the system peak method." (P. 354)
Most state commissions, some with over a hundred years of experience,
have settled by now on their preferred demand allocation method or methods for
their jurisdictional gas and electric utilities. FERC has done the same and for
natural gas pipelines, switching in 1992 from a "Seaboard" formula of 50%
demand in the fixed rate and 50% in the volumetric, to a 100% of fixed cost in the
fixed rate ( called straight fixed-variable).
What costs are related to the "customer charge" on a gas distribution
system?
According to the Gas Rate Fundamentals handbook "Customer-related costs,
then, are primarily distribution and customer accounting costs. They are allocated
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directly to the customer of a particular class of service. Metering costs are an
example of customer-related costs." (P. 137)
These costs vary with the number of customer and typically include,
beside meter reading costs, the costs of billing a customer and some distribution
costs. The exact make up of costs associated with "customer charges" varies with
the practices of the individual state commissions. That is, some states may include
more distribution system costs than others related to demand.
The reason for this is that for residential gas meters and the utility's billing
systems do not allow for residential and GS customers to be charged for their
maximum demand on the system. Therefore the next best solution is to convert
the expected demand charge into a customer charge, which is equitable as
customers in this class are similar to each other so that the customer charge
collects as a demand charge would.
The testimony of Lori B. Blattner indicates that Intermountain's unit
customer-related costs are estimated at $13.50 per month, while the Company's
monthly customer charge is only $2.50 in the summer and $6.50 in the winter
months. Thus, a customer going on vacation for a summer month and shutting off
gas appliances would pay only $2.50, which would be grossly inadequate to
recover the fixed cost investment in the distribution system standing by to provide
service for that customer during the entire month, let alone the associated meter
reading and billing costs. The implication of that fact is that other customers
would have to cover this shortfall in revenues.
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Would higher residential customer charges negatively impact
disproportionate numbers of low income customers, compared to the
company's general population of residential customers?
Not in this case. The company has prepared an analysis that shows that the usage
of low income customers is similar to the usage of the general population. Thus it
is not correct to assume that all low natural gas usage customers are also "low
income" customers. Low usage can come from the decision by a high income
customer to only use natural gas only for cooking rather than space heating. Low
usage can also occur annually from retirees who move to warmer climates in the
winter leaving their homes vacant for the high heating consumption months.
Conversely, high natural gas usage may be experienced by large but poor families
cooking and space heating with older less-efficient appliances in poorly insulated
homes.
Low income customers will always be affected greater by increases in the
cost of any essential compared to higher income customers. That is purely a
mathematical statement. Increasing the customer charge is economic efficient
pricing. Kahn directly addresses this issue by stating that variations from this
pricing may be made for "expediency and practicality" but that "objections to the
principle itself' are for the most part not susceptible to scientific refutation, since
basically they involve nonscientific value judgments." (P. 100-102/1) Having
attempted to deal with special rates for "low income" customers as a state PSC
commissioner during the high periods of inflation in the 1980's I would
discourage using utility rates to ameliorate problems of poverty.
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Would the shift in customer charge, as proposed by Intermountain,
discourage conservation or encourage unnecessary use of natural gas?
I do not believe so. Correctly done the average customer should see a monthly bill
at the same level before the change as after. While the fixed customer charge will
increase, the volumetric charge will decrease, leading, on average, to a total bill
the same as before. Thus, there would not be any price signal indicating that
delivered gas service was any cheaper than before.
Even if the commodity price of natural is slightly lower in the future, due
to this shift, it is not people who use natural gas but their appliances and devices.
These devices do not see any price. When the weather gets colder the family
furnace or cooking range will not use more gas just because it is less expensive
than it was before. Yes, customers do control the thermostat, but is it likely that
small changes in gas commodity price will cause major changes in life style
choices (increasing thermostat settings in winter or cooking more often) for the
average consumer? Conversely, if the price of gas is lower, it is also highly
unlikely that consumers will go out and install a second furnace and a second
kitchen range.
With respect to which price signals to consumers would cause them to
replace lower efficiency furnaces and appliances for new ones, I believe that
consumers are more likely to change their furnaces and appliances due to
mechanical problems, age and rebates and other promotional programs than
changes in commodity gas costs. I doubt whether gas appliance sales have
skyrocketed during this recent period of commodity gas prices at the recent low
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$2.00 per MCF level coming down from a high a few years ago of $8.00 per
MCF.
Do you support Intermountain's proposal to change their rate structure and
implement a demand charge for large industrial natural gas customers?
Yes, I do. As I indicated earlier in this testimony the capital investment in the
natural gas system is a factor of the size of the system in terms of how much gas
can be delivered in a specific period of time. The more gas required in that time
period, called the "demand" (from the view of the customer and "capacity" from
the view of the utility when making its capital investment), the larger, physically,
the system needs to be and the greater capital cost in incurred. Under the most
basic rate making principles that entities which cause the demand should pay their
proportionate share of costs in meeting that demand. Volumetric use is not the
controlling factor here but the size of the system is since size dictates how much
gas can flow, at safe pressure, in the relevant time period.
For example, most ofus are aware that filling a swimming pool with a
garden hose would take longer than filling it with a fire hose. The final volume of
water would be the same to fill the pool from either hose. However, the capacity
or demand from the fire hose would be much greater than that through the garden
hose. Most people would understand that a large fire hose would be more
expensive than a garden hose and the same is true for the large natural gas pipes
required by large industrial customers. The large industrial customers would have
larger service pipes and they would use a larger portion of the capacity of the
common distribution system in the streets.
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Another cost associated with "demand" incurred by the distribution gas
system is the cost of Federal Energy Regulatory Commission (FERC) regulated
interstate natural gas pipeline system delivering gas to the distribution system's
city gate. In 1992 the FERC adopted a rate making design called "straight fixed-
variable" (SFV) which allocated all of the fixed costs to a monthly fixed charge
for capacity ( demand) leaving only variable costs in the volumetric rate.
Distribution gas utilities as customers of natural gas pipelines pay a fixed
monthly demand rate based on their reservation of maximum capacity needed.
This capacity/demand is a function of the simultaneous maximum demand placed
by the distribution customers on the system. If that demand increases the
distribution gas utility must sign up for more capacity. If demand diminishes the
utility can reduce its demand reservation. Thus the demand of large industrial
customers, along with demand of other customer classes dictates how much
pipeline capacity must be reserved. Thus an industrial demand charge will more
fairly allow this cost to be allocated to the customers causing the demand. Since
changes in rate design are generally designed to collect the same revenue
requirement, as before the change, increases in fixed costs would be accompanied
with a decrease in the volumetric rate.
II. FIXED COST COLLECTION MECHANICISM
Turning now to the second part of your testimony, do you have an opinion on
whether the Commission should adopt he Company's proposal to implement
a Fixed Cost Collection Mechanism ("FCCM")?
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Yes. It is my opinion that the FCCM presented in Mr. McGrath's testimony is a
necessary component of the Demand Side Management (DSM) program
presented in the testimony of Allison A. Spector in this proceeding.
Ms. Spector' s testimony includes a description of the company's proposed
DSM program, the program direct cost and reference to a revenue decoupling
proposal in the form of the FCCM Tariff in Mr. McGrath's testimony. The
purpose of the FCCM is to mitigate revenue losses resulting from this
conservation program and other factors. It is my opinion that the FCCM is a
critical component of the DSM proposal and its acceptance by the commission
would be in keeping with the public interest and good regulatory practice.
What is the nature of the term "fixed costs" in the context of the FCCM
proposal?
As I explained earlier, a natural gas utility incurs certain fixed costs during the
test year period for which the revenue requirement is estimated, and upon which
rates are based. These costs do not vary with the volume of natural gas delivered
through the Company's distribution system or taken by any individual customer.
An allocated cost of service study, as prepared by all natural gas utilities in
support of rate design, has within it a breakdown of fixed and variable costs by
customer class. The problem arises when natural gas distribution rates are
designed to predominately recover costs in the volumetric component and
experienced volumes fall below those expected. The result will be programmatic
deficiency in revenue and failure to collect needed revenues.
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Why would the acceptance of the FCCM be in the public interest and good
regulatory practice?
Because a FCCM is a natural and important component or counter-weight to a
well designed and implemented_demand-side management (DSM) program. It is a
regulatory mechanism for mitigating economic penalties on the utility associated
with the desire to obtain environmental and consumer benefits commensurate
with a well-designed DSM program.
DSM is one technique for reducing natural gas distribution company
demand and usage. It usually responds to a utility regulatory commission's desire
to look at both supply-side and demand-side options, with an accompanying
analysis costs and rate impacts. Typical regulatory DSM objectives are the
promotion of efficiency in the consumption of energy and obtaining
environmental benefits. The Idaho Commission has extensive experience with
such programs, having accepted and reviewed filings by both its electric and
natural gas utilities.
The treatment of DSM programs in the natural gas distribution industry is
detailed in the National Regulatory Research Institute's (NRRI) August 1994
paper "Integrated Resources Planning for Local Gas Distribution Companies: A
Critical Review of Regulatory Policy Issues". That paper refers to the two basic
elements of a DSM program as "a set of administrative procedures and
ratemaking mechanism." In accordance with this report in these Intermountain
Gas Company proceedings Ms. Spector has presented the procedures for DSM
and Mr. McGrath has presented a rate making mechanism.
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Is a request for a decoupling mechanism, such as the FCCM proposal
appropriate when a utility adopts a demand side management program?
Yes, it is. The Commission recognized this with its earlier cases in the electric
industry. For natural gas distribution utilities, the cited NRRI paper clearly states
that ratemaking mechanism elements when adopting DSM "generally attempt to
allow recovery of investments and expenses of various options, recovery of
revenues caused by lost sales due to successful implementation of demand-side
management (DSM) options, or otherwise make supply side and DSM options
equally profitable, offer additional financial incentives for successful DSM
options, and promote overall costs minimization." (Page 3) In this case, Mr.
McGraths testimony on FCCM lays out a specific proposal in keeping with the
DSM program.
Is ratemaking treatment to recover lost revenues an indispensable part of a
DSM proposal?
It is. The NRRI report is direct on this point: "Recognizing the fact that adoption
of cost-effective DSM options may lead to a reduction in sales, and therefore, a
reduction of revenues and profits, mechanisms to compensate the utility for lost
revenues have been proposed and used." Thus, I believe it is indispensable.
Is there a case where a DSM program may not lead to a reduction in
"revenues and profits"?
In most cases DSM would lead to reduction in revenues. However, if the
distribution gas company rate design had all fixed costs in a monthly fixed charge,
or if rates were based on steep declining block rates, then the lost revenues would
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merely reflect lower purchased gas costs. In that case the utility's return (profit)
would be collected in the fixed charge or early rate blocks.
This is not the case in regard to Intermountain Gas Company's tariffs
where both the residential services tariffs RS-1 and RS-2 have fixed monthly
customer charges of $2.50 per bill April to November and $6.50 December
through March with an energy charge based on dollars per therm. In this type of
rate design the bulk of the revenue comes to the utility in the energy charges and
this would include revenues to cover the return component of the revenue
requirement. There is also the exception where the DSM objective of reduction of
negative environmental impacts is to be accomplished by increasing the direct use
of natural gas.
Is a decoupling mechanism, such as the FCCM proposed here, only required
when a distribution gas company applies for a DSM program?
No. A decoupling mechanism is appropriate, in my opinion, whenever a utility
rate design is such that a decrease in sales volumes adversely affects the ability of
the utility to earn a reasonable return on investment. Mr. McGrath's testimony
listed a number of reasons why natural gas sales per customer were declining on
Intermountain's system, and those factors are found all around the United States,
not just here in Idaho. A legal principle in regulation is that the commission
approved rates must give the utility a reasonable opportunity to earn a fair return
on investment. When a commission has direct evidence that a regulatory policy or
rate design results directly in the inability of a utility to have that opportunity,
then the policy or rate design must be corrected or effects mitigated.
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Is the FCCM the only decoupling mechanism available?
No. Regulators have approved a variety of decoupling mechanisms based on local
preferences, practices and circumstances. The FCCM proposal for Intermountain
was made with knowledge of this Commission's first case to investigate financial
disincentives to energy efficiency in the case of an electric utility back in 2004.
The result was a pilot Fixed Cost Adjustment mechanism (FCA) for Idaho Power
Company in 2007. In 2012 that pilot was made permanent. Additionally, in 2015,
the Commission approved a three-year pilot program for an FCA mechanism for
A vista Utilities' electric and natural gas operations.
Have regulators explicitly cited lost revenue as a reason for implementing a
recovery mechanism?
Yes, for example the Ontario Energy Board, the public utility regulatory agency
in the Province of Ontario, has explicitly listed, among its "Guiding principles for
the DSM Framework" as a principle number "4. Gas utilities will be able to
recover costs and lost revenues from DSM programs."2 In this case, we have a
regulator - the Ontario Energy Board- and there are likely others, which has
publicly tied decoupling as a required condition for DSM implementation.
What is the significance of an FCCM, or similar mechanism, to utility
investors?
A regulated utility, such as a natural gas distribution company, is required to have
facilities sufficient to provide safe, reliable and adequate service to its customers.
This means that sufficient physical facilities must be built and available to provide
2 As cited in its recent "Report of the Board Demand Side Management Framework for Natural Gas
Distributers (2015-2020) EB-1024-0134"
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needed service. The funds to pay for the construction of the assets come from
debt and equity provided by investors. Regulators do not include the cost of utility
assets in the revenue requirement until the facilities are actually providing service.
An announcement that the utility has implemented DSM indicates to the investor
that the utility, with regulatory approval, is instituting programs to decrease sales
of natural gas on the system. Without some mechanism to compensate for the
revenue from these programmatic lost sales the investor would assume that the
opportunity earn a reasonable return on their investment has been or is being
diminished especially when the rate design, as in this case, is predominately based
on volumes. This factor, unmitigated, would signal increased risk to the investor.
Thus the establishment of FCCM provides a better opportunity, but again no
guarantee, of reasonable returns in the future.
Does the issue of giving utility investors a reasonable opportunity to earn a
fair return also extend to Intermountain's proposed increase in its customer
charge for residential and commercial customers and the establishment of
demand charges for large industrial customers?
Yes, it does and for similar reasons. The FCCM is proposed in response to the
request to establish a DSM program. The customer charge and demand charges
are also designed to, in addition to addressing issues of equity and cost causation,
reduce the uncertainty of revenue collection but from all of the other factors
which affect volumetric sales negatively as I explained earlier in my testimony.
Does that conclude your testimony?
Yes it does.
Terzic, Di 18
Intermountain Gas Company