OAH 8-2500-19924-2
MPUC Docket
No. G-007, 011/GR-08-835
STATE OF MINNESOTA
OFFICE OF ADMINISTRATIVE HEARINGS
FOR THE PUBLIC UTILITIES COMMISSION
|
In the Matter of the
Application of Minnesota Energy Resources Corporation for Authority to
Increase Rates for Natural Gas Service in Minnesota
|
SUMMARY
OF TESTIMONY
AT
THE PUBLIC HEARINGS,
FINDINGS
OF FACT,
CONCLUSIONS
AND
RECOMMENDATIONS
|
This matter came on for public and evidentiary hearings
before Administrative Law Judge Eric L. Lipman in January and February of 2009.
Public hearings were held in this matter in Rochester, Minnesota and Eagan, Minnesota
on January 8, 2009. Additionally, a
public hearing was held in Cloquet,
Minnesota on January 12, 2009.
On February 3, 2009, an evidentiary hearing was held
in the Large Hearing Room at the offices of the Minnesota Public Utilities
Commission (“Commission”). The
evidentiary hearing continued on a successive day and concluded on February 4,
2009.
Following
the close of the evidentiary hearing, the parties submitted post-hearing
submissions and reply briefs. The
evidentiary hearing record closed on March 18, 2009.
The following persons noted their appearance:
Ann M. Seha,
Michael J. Ahern and Sarah J. Kerbeshian, Dorsey & Whitney LLP, appeared on
behalf of Minnesota Energy Resources Corporation (“MERC”)
Karen Finstad
Hammel and Julia E. Anderson, Assistant Attorneys General, appeared on behalf
of the Minnesota Office of Energy Security (“OES”).
William T. Stamets
and Ronald M. Giteck, Assistant Attorneys General, appeared on behalf of the
Minnesota Office of the Attorney General-Residential Utilities Division (“OAG-RUD”).
Andrew P. Moratzka, Mackall, Crounse
& Moore, appeared on behalf of ArcelorMittal USA, Hibbing Taconite Company,
Northshore Mining Company, United States Steel Corporation and United Taconite,
LLC, (collectively known as the “Large Power Intervenors,” “LPI” or the “Taconites”).
Eric F. Swanson,
Winthrop & Weinstine, appeared on behalf of Cornerstone Energy,
Incorporated d/b/a Constellation New Energy--Gas Division, LLC (“Constellation”)
Robert Harding,
Rates Analyst; Jerry Dasinger, Financial Analyst; and Stuart Mitchell, Rates
Analyst; appeared on behalf of the Staff of the Minnesota Public Utilities
Commission (the “Commission”).
STATEMENT OF ISSUES
MERC has requested
an annual increase in its natural gas revenues of $22,041,889. Of the total annual increase, $18,416,621 is
requested to increase natural gas rates for Peoples Natural Gas (“MERC-PNG”),
and $3,625,268 to increase natural gas rates for Northern Minnesota Utilities
(“MERC-NMU”).
By way of a September
25, 2008 Notice and Order for Hearing, the Commission
directed that an evidentiary record be established on this request. At the close of the evidentiary hearing the following
matters remain in dispute.
(1)
Is the test year revenue increase sought by the
Company reasonable or will it result in unreasonable and excessive earnings by
the Company?
(2)
Is the rate design proposed by the Company,
including proposed revisions to customer charges, reasonable?
(3)
Are the Company's proposed capital structure, cost
of capital, and return on equity reasonable?
(4)
What is the appropriate return on equity (“ROE”)?
(5)
Based upon the appropriate return on equity, what
is the appropriate overall rate of return (“ROR”)?
(6)
How should the revenue requirement be allocated to
the customer classes?
(7)
Should the residential customer charge be
increased, and if so, by how much?
(8)
Should the customer charge be approved as proposed
for Small Volume Interruptible customers?
(9)
How should MERC account for rate case expenses
if, after the close of the three-year amortization period, it has not yet filed
a new rate case with the Commission?
SUMMARY OF TESTIMONY AT THE PUBLIC HEARINGS
Pursuant to Minn. R.
7829.1100, the Administrative Law Judge conducted public hearings on January 8 and January 12, 2009. The public hearings were held to elicit
public comment regarding proposed rate increases.
Public
hearings on MERC’s proposed rate increase were held on January 8, 2009, at
the Olmsted County
Government Center
in Rochester, Minnesota
and at the Dakota County Vo-Tech College in Rosemount,
Minnesota; and on January 12, 2009, at
the Cloquet City Hall.
At the outset of the public
hearings the Administrative Law Judge made introductory remarks, followed by
short remarks from the Commission staff and David Kult, MERC’s General Manager
of Operations and Engineering. At each
hearing, Mr. Kult briefly explained MERC’s rate increase request and how it
would likely affect the average residential customer. Following these presentations, members of the
public and staff of OES and OAG-RUD offered testimony and dialogued with other
participants at the hearing.
A summary of the testimony rendered
at these evening hearings follows below:
Southern Minnesota Public Hearing
– Rochester, Minnesota
At the public
hearing in Rochester, Minnesota each of the five members of the
public in attendance offered testimony for the hearing record.
Howard Wilson, a ratepayer from Rochester, Minnesota,
expressed concern over the high percentage rates of increase associated with
the monthly customer charge.
Larry Smith, the Executive Director of
Finance for Independent
School District 535 – the
Rochester Public Schools, detailed the impact that a rate increase would have
upon the school system and the challenge that ISD 535 faces in providing
cost-effective natural gas service to 32 different buildings.
Paul
Weber, a ratepayer from Claremont,
Minnesota, argued that the
proposed rates of increase were unwarranted because of MERC’s unsatisfactory
methods of customer service.
Raymond
F. Schmitz, a ratepayer from Rochester,
Minnesota, argued that these
rates of increase in customer charges, and the proposed rates of return for the
company, were at odds with the general under-performance of the economy and the
prices that should be charged during a recession. Mr. Schmitz asserted that such rates of
increase would be unduly burdensome to all classes of MERC customers.
Philip
Barton, a ratepayer from Rochester,
Minnesota, argued that MERC
should not be permitted to recover for costs incurred prior to its 2006
purchase of facilities from Aquila, Inc.
Metropolitan Area Public
Hearing – Eagan, Minnesota
At the public hearing in Eagan, Minnesota
two of the five members of the public in attendance offered testimony for the
hearing record.
Richard Dornfeld, a ratepayer from Rosemount, Minnesota,
expressed concern over the higher percentage rates of increase for the
residential class of customers in comparison to other customer classes.
Jim
Fischer, a ratepayer from Lakeville,
Minnesota, expressed concern over
the rate of proposed increase in comparison to the rise in the Consumer Price
Index over the same period.
Northern Minnesota Public
Hearing – Cloquet, Minnesota
At the public hearing in Cloquet, Minnesota
the sole member of the public in attendance offered testimony for the hearing
record.
Jerry
Moe, a ratepayer from Eveleth,
Minnesota, expressed the view
that any request for a rate increase at a time when there is general financial
instability in the broader economy will be viewed with suspicion and anxiety.
SUMMARY
OF THE WRITTEN COMMENTS
In addition to the testimony and exhibits
developed at the public hearing, thirteen ratepayers submitted written comments
to the Administrative Law Judge before the close of the comment period on
January 22, 2009. A summary of
the written comments follows below:
David Bunker, a ratepayer from Bovey, Minnesota, expressed
skepticism over the need for a natural gas rate increase at a time when oil and
gasoline prices are falling and there is a general drop in prices throughout
the economy.
Herbert
Craw, a ratepayer from Chisholm,
Minnesota, noting that his
natural gas bills have doubled between 1997 and the present day, asserted that
natural gas rates are sufficiently high enough.
Gilbert
Eby, a ratepayer from North Branch, Minnesota,
expressed the concern that as pensioners he and his wife are “pressed to the
limits of our financial independence with the constant rise in the cost of
living.”
Arlo
Finney, a ratepayer from Farmington,
Minnesota, argued that any
increase in natural gas rates should be delayed as a sign that the company “is
willing to share the burden of poor economic times.”
Donald
W. Green, a ratepayer from Detroit
Lakes, Minnesota,
opposes the proposed rate increase on the grounds that it is not necessary and
will “only aggrevate the financial problems that exist for many people.”
Henry
and Vivian Hentges, ratepayers from Saint
Charles, Minnesota,
argued that in poor economic times, MERC should cover any increased costs by
reducing corporate salaries.
Deborah
Herrick, a ratepayer from Worthington,
Minnesota, does not believe the
rate increase is justified when many ratepayers are doing their best to reduce
the amount of energy that they consume.
Janet
Lasch, a ratepayer from North Branch, Minnesota, opposed the requested increase in
natural gas rates on the grounds that the applicant’s record of customer
service is “very poor.”
Lois
Paulson, a ratepayer from Park Rapids, Minnesota, expressed concern over the timing
of a natural gas rate increase; noting both that oil and gasoline prices are
falling and that there is a general downturn in the economy.
Bill
Reid, a ratepayer from Chisholm,
Minnesota, expressed skepticism
over the need for the proposed increases, arguing that any increase in costs
could be covered by reductions in corporate salaries and staffing.
Marilyn
Theismann, a ratepayer from Rochester,
Minnesota, expressed the view that
the proposed rate increases “reflects a blatant disregard for consumers.”
Holly
Wilson, the daughter of a ratepayer in Thief River Falls, Minnesota,
expressed concern that an increase in natural gas rates cannot be met by
elderly ratepayers on fixed incomes.
Robert
M. Zeller, a ratepayer from Mantorville,
Minnesota, urged the Commission
to look closely at MERC executive compensation levels before approving the
requested rate increase. Further, if a
rate increase is needed, he urges that rates be raised for commercial classes
of customers; on the grounds that business entities may deduct expenditures
made for natural gas as a business expense.
1.
MERC is a Delaware
corporation and one of six subsidiary corporations of Integrys Energy Group,
Inc. (“Integrys”). MERC is authorized to
do business in Minnesota and its principal
office is located in Rosemount,
Minnesota.
2.
MERC purchased the Minnesota assets of Aquila, Inc. in a sale
approved by the Commission on June 1, 2006.
The sale included two operating units – Aquila Networks-Peoples Natural
Gas (now known as MERC-PNG) and Aquila Networks-Northern Minnesota Utilities (now
known as MERC-NMU).
3.
Currently, MERC serves approximately 207,000
natural gas customers in 51 counties in Minnesota.
4.
MERC provides service to its Minnesota customers under the same rates,
terms, and conditions that were established for Aquila, Inc. in that company’s
last natural gas rate case – a set of rates that was effective on July 29, 2003.
5.
On July 31, 2008, MERC filed an application seeking
an increase to its rate – its first following the June 1, 2006 sale of
Aquila-PNG and Aquila-NMU.
6.
MERC’s application seeks an annual rate increase of
$18,416,621 for MERC-PNG and $3,625,268 for MERC-NMU – for a combined total increase
of $22,041,889. In percentage terms, the
proposed rate increases amount to a rise of 6.92 percent for MERC-PNG
customers; a rise of 4.58 percent for MERC-NMU customers; and an overall
percentage increase of 6.92 percent over current rates.
7.
Additionally, MERC’s application seeks a return on
common equity of 11.25 percent.
8.
The Company’s application included proposed interim
rate schedules that are based upon a 2008 test year and were adjusted for known
and measurable changes. MERC also
submitted a separate miscellaneous rate change filing seeking to restate the
Base Cost of Gas for these interim rates.
9.
On August 1, 2008, the Commission issued a notice
to potentially interested parties requesting comments on whether the Commission
should accept the filing as substantially complete and whether it should refer
the case to the Office of Administrative Hearings (“OAH”) for contested case proceedings.
10.
On August 11, 2008, the Office of Energy Security
of the Minnesota Department of Commerce (“OES”) filed comments, recommending
acceptance of the filing as complete and referring the case for contested case
proceedings.
11.
The Taconites also filed comments on August 11,
2008. The Taconites recommended a
finding of exigent circumstances that would permit MERC to forgo collecting a
portion of the interim rate revenue from large power customers. The Taconites asserted that a large interim
rate increase qualified as an “exigent circumstance” because it would lead
MERC’s industrial customers to bypass MERC’s system.
12.
MERC filed a letter on August 13, 2008, stating
that it concurred with the recommendations of the OES and the Taconites and did
not intend to file reply comments.
13.
On September 11, 2008, the Commission met to
consider all of these matters and whether to request parties to develop any
specific matters in the rate case. On
September 25, 2008 the Commission issued Orders in this case memorializing its
September 11, 2008 determinations. The
Commission found the rate case filing to be substantially complete; suspended
the proposed rates pending a final decision on the merits of the rate case
filing; and set an interim rate schedule.
14.
In its September 25, 2008 Order
Setting Interim Rates, the Commission authorized an annualized interim
rate increase of $19,836,777 ($16,787,734 for MERC-PNG and $3,049,043 for
MERC-NMU), less than the amount requested by MERC ($1,628,887 for MERC-PNG and
$576,225 for MERC-NMU) in order to maintain revenue neutrality of Conservation
Improvement Program (“CIP”) costs.
15.
In a related proceeding, the Commission set a new
base cost of gas for interim rates.
16.
Also on September 25, 2008, the Commission issued a
Notice and Order for Hearing, referring
the matter to the OAH for contested case proceedings. In its order, it directed the Office of
Administrative Hearings to “specifically and thoroughly address” during the
course of contested case proceedings, the following issues:
(1)
Is the test year revenue increase sought by the
Company reasonable or will it result in unreasonable and excessive earnings by
the Company?
(2)
Is the rate design proposed by the Company,
including proposed revisions to customer charges, reasonable?
(3)
Are the Company's proposed capital structure, cost
of capital, and return on equity reasonable?
17.
The undersigned Administrative Law Judge held a
prehearing conference on October 13, 2008.
As provided in the First and
Second Prehearing Orders, parties of right and intervenors includes the
OES, the Residential and Small Business Utilities Division of the Office of the
Attorney General (“OAG-RUD”), Cornerstone Energy, LLC d/b/a Constellation New
Energy - Gas Division (referred to throughout this proceeding as
“Cornerstone”), and the Taconites (ArcelorMittal USA, Hibbing Taconite Company,
Northshore Mining Company, United States Steel Corporation and United Taconite,
LLC).
18.
On October 17, 2008, the undersigned issued a Protective Order to address the handling
of non-public information during the proceedings.
19.
A second prehearing conference was held by
conference call on January 12, 2009, to review the progress of settlement
negotiations.
20.
As noted above, the evidentiary hearing in this
matter was held February 3 and 4, 2009.
21.
Prior to the commencement of hearing, the OES
and MERC reached agreement on many of the issues through the normal course of
resolution through pre-filed testimony.
Other issues were resolved during the course of the evidentiary hearing. Among the accords reached between these
parties were:
a.
Elements of the rate base;
b.
Exclusions from the rate base;
c.
Distribution plant adjustments to the rate base;
d.
Customer deposits adjustments to the rate base;
e.
Construction Work in Progress accounting
practice;
f.
Regulatory Asset and Liability adjustments;
g.
Cash Working Capital requirements;
h.
Rate base disallowances for service and main
extensions;
i.
Service and main extension record-keeping
requirements;
j.
Winter construction charges disallowances;
k.
Winter construction charges reporting;
l.
Cost allocation methods among utility and
non-utility customers;
m.
Integrys business support, medical plan and
dental plan costs;
n.
Depreciation rate and expense adjustments;
o.
Interest synchronization on final adjustments;
p.
Adjustments to bad debt expenses;
q.
Adjustments to conservation improvement program
revenues;
r.
Natural gas sales forecasting methods;
s.
Exclusion of unamortized rate case expenses;
t.
Allocating rate case expenses by a general
allocation factor;
u.
Adjustments to the rate of annual expense;
v.
Adjustments to advertising expenses;
w.
Conservation improvement program tracker account
methods and amortization period;
x.
Conservation cost recovery methods;
y.
Filing and recovery methods for conservation
improvement program costs in the test year;
and,
z.
Tariff changes regarding:
i. Small
volume balancing;
ii. Telemetry
requirements;
iii. Returned
check practice;
iv. Reconnection
practice;
v. Usage
data request practice;
vi. Winter
construction and “abnormal circumstance” practice;
vii. Connections
to non-primary space heating customers;
and,
viii.
Waiver of Contribution in Aid of Construction
practice.
The undersigned finds that these agreed-upon adjustments,
tariff revisions, accounting practices and recordkeeping requirements are all reasonable
and urges their adoption by the Commission.
II. General Principles
22.
A reasonable rate enables a public utility not only
to recover its operating expenses, depreciation, and taxes, but also allows it
to compete for funds in capital markets. The rate
of return should be sufficient to cover operating expenses – including debt
service and dividends on stock – and continued assurance in the utility’s
ability to maintain credit and attract capital.
23.
A just and reasonable return should be similar to
returns on investments in other businesses having corresponding risk.
24.
The determination of reasonableness involves a
balancing of consumer and utility interests. Assuring a fair rate of return must be balanced against
the rate-paying public’s interest in rates that are just and reasonable. Minnesota
law requires that any doubt as to reasonableness of proposed rates must be
resolved in favor of the consumer.
25.
In carrying out its statutory responsibilities, the
Commission has announced the following principles for rate design:
(A)
Rates should be designed to provide the Company a
reasonable opportunity to recover all prudently incurred costs, including costs
of attracting capital. These rates, when matched to test-year customer counts
and sales projections, should allow the Company a reasonable opportunity to
collect its revenue requirement.
(B)
Rates should be designed to promote an efficient
use of resources. As such, they should reflect the costs that classes of customers
impose upon the system.
(C)
Rates and conditions of service should provide a
reasonable continuity with the past. Rate-design changes should be reasonable
and, to the extent possible, gradual to prevent drastic impacts on existing
customers.
(D)
Rates should be understandable and easy to
administer.
26.
Setting the rates at or near the embedded cost to
serve each customer class serves the public interest in assuring that adequate
price signals are sent to customers who receive service.
27.
MERC bears the burden to prove by a fair
preponderance of the evidence. that it
is just and reasonable that it should recover from ratepayers the costs of its
claimed expenses.
28.
In its rate-setting orders, the Commission has
balanced the interests of ratepayers and utilities.
A reasonable rate enables an investor-owned utility to recover its
operating expenses, depreciation, and taxes, as well as compete for funds in
capital markets. Allowing a fair and
reasonable return upon the utility’s investment in property used to provide the
utility service is a factor in setting just and reasonable rates. This return
on investment in property is commonly referred to as return on equity or ROE.”
29.
For publicly-traded companies, the Return on
Equity is determined by the actual performance of that company’s stock in the
marketplace. Because MERC securities are
not publicly traded, however, it is necessary to establish the ROE figure for
MERC by other means. The Commission has
historically relied upon the Discounted Cash Flow (“DCF”) analysis to derive
ROE for rate cases. This is the most
widely accepted model and one that has been used consistently as a starting
point for establishing the cost of equity in public utility cases before the
Commission.
30.
The Discounted Cash Flow model provides an Return
on Equity estimate that meets the Hope
and Bluefield criteria for a fair
return; it produces data
that are commensurate with the returns that are being earned on other investments
with equivalent risks; and it effectively estimates a rate of return that is sufficient
to enable the utility to attract capital, maintain its credit rating and assure
its financial integrity.
31.
MERC is a subsidiary corporation of Integrys, Energy
Group, Inc. (“Integrys”). Integrys
issues debt on behalf of its subsidiaries.
Under this arrangement, MERC had $102,646,935 of debt at the time of its
application. MERC is financed with a combination of
long-term debt, short-term debt and common equity.
32.
In its application, MERC submitted two separate
capital structures –“Permanent Capital” and “Total Capital.”
33.
MERC’s Total Capital incorporated two adjustments
to Permanent Capital. One of these proposed
adjustments is for customer deposits in the amount of $374,371 and is labeled
“Other Interest Bearing Balance Sheet Items.”
The other proposed adjustment includes non-utility expenditures, MERC’s
CIP expenditures and plant disallowances in the amount of $5,871,457, and is
denominated “Capital Structure Adjustments.”
34.
OES complained
that
MERC’s capital adjustments decrease the weighted cost of total capital by
0.2511 percent, thus affecting its rate of return; and that no other regulated Minnesota utility adjusted its rate of return in this way.
35.
MERC witness, Lisa Gast, CPA, responded to this
concern in her Rebuttal Testimony by submitting revised schedules updating
MERC’s capital structure, cost of capital, and required rate of return for the
2008 proposed test year for actual results through November 2008. MERC’s revised Schedule D-1 incorporates the
OES’s recommendations and does not make adjustments to Permanent Capital.
36.
MERC’s rebuttal testimony reflects Dr. Griffing’s
recommendation to use what MERC termed “Permanent Capital” as its proposed
capital structure. The
OES agrees with MERC’s capital structure proposal as modified by Ms. Gast in
her Rebuttal Testimony. Ms. Gast’s updated recommendation for MERC’s
capital structure is:
Component Ratio (%)
Long-Term Debt 43.42%
Short-Term Debt
7.81%
Common Equity 48.77%
Total 100%
37.
No other party commented upon, or proposed an
alternative to, the capital structure agreed upon by the OES and MERC.
38.
MERC’s revised proposed capital structure set forth
above and included in Ms. Gast’s Rebuttal Testimony schedules is reasonable. MERC has demonstrated that its proposed
capital structure reflects the actual financial transactions of its business.
39.
OES and MERC agree on the appropriate capital structure
and the cost of both long-term and short-term debt. However, as detailed below, there is a
significant difference in the recommended Returns on Equity.
40.
As a wholly owned subsidiary of Integrys, MERC has
no publicly traded common stock. Although Integrys common stock is traded
publicly, MERC’s regulated local distribution company (“LDC”) segment only
accounts for approximately 11.4 percent of the parent company’s earnings
available to shareholders. As such, it
was the view of OES analysts that MERC’s operations represented too little of
Integrys’ earnings, for the parent company’s Return on Equity and Rate of
Return to serve as an appropriate proxy in the assignment of an ROR and ROE for
MERC.
41.
MERC and the OES each proposed a rate for Return on
Equity. In developing their proposals,
MERC and OES each began their respective calculations with the Discounted Cash
Flow analysis.
42.
The DCF method uses the current dividend yield and
the expected growth rate of this yield to determine a rate of return that is sufficient
to induce investment. The Discounted
Cash Flow analysis is derived from a formula for determining the net present
value, or price per share, of a share of stock.
43.
The DCF model uses three inputs – dividends, market
equity prices and growth rates. The
first two inputs are market-based and follow from marketplace decisions of both
the companies and their investors with respect to the value of equity
shares. Growth rate data are drawn from independent
experts. Because of the types of data
that are used in the formula, the Discounted Cash Flow minimizes the
opportunities for analyst decision-making and judgment to influence the
computation of the Return on Equity.
44.
Although the OES and MERC each employed the DCF
analysis, there were some differences in the groups of companies selected for
comparison and other variables, between the sets of calculations – variations
that produced different results.
45.
As part of their respective Discounted Cash Flow
analyses, OES and MERC drew data from a set of comparable companies which each
believed represented a similar set of investment risks as MERC. Because MERC common stock is not publicly
traded, reference to the data from these other firms provides a basis to
calibrate an appropriate Return on Equity.
OES refers to its collection of similar firms the “Comparison Group,”
whereas MERC titled its selections the “Gas Group.” From the data drawn from the set of
comparison companies, the Discounted Cash Flow computations follow from a fixed
formula.
46.
OES and MERC agree upon seven of the companies
that should be included in the DCF comparison group – and disagree as to three
others. A side-by-side listing of the
respective proposals appears below.
|
OES Comparison
Group
|
MERC Gas Group
|
|
(a)
AGL Resources, Inc.
(b)
Laclede Group, Inc.
(c)
New Jersey Resources Corp.
(d)
Northwest Natural Gas
(e)
Piedmont Natural Gas Co.
(f)
South Jersey Industries, Inc.
(g)
WGL Holdings, Inc.
(h)
(NOT INCLUDED BY OES)
(i)
(NOT INCLUDED BY OES)
(j)
Southwest Gas
|
(a)
AGL Resources, Inc.
(b)
Laclede Group, Inc.
(c)
New Jersey Resources Corp.
(d)
Northwest Natural Gas
(e)
Piedmont Natural Gas Co.
(f)
South Jersey Industries, Inc.
(g)
WGL Holdings, Inc.
(h)
Atmos Energy Group;
(i)
NICOR, Inc.
(j)
(NOT INCLUDED BY MERC).
|
47.
The OES’s expert, Dr. Marlon F. Griffing, sought to
develop a comparison group of publicly traded companies operating within the Standard
Industrial Classification Code 4924 – signifying “Natural Gas Distribution.” Dr. Griffing sought companies that are: based
in the United States; publicly traded; currently paying dividends; have positive
growth-rate projections from expert analysts; not expected to merge into or be
acquired by another company; have a Standard and Poors bond rating between AA-
and BBB-; and have at least 60 percent of net income (or another earnings
indicator) from regulated local distribution operations.
48.
Dr. Griffing excluded Atmos Energy from his Comparison
Group because it did not have at least 60 percent of its net income from local
distribution operations. Dr. Griffing
excluded NICOR, Inc. from his comparison group because its Standard & Poors
bond rating of “AA” fell outside of the “AA-” to “BBB-” range that he ordinarily
uses.
49.
Mr. Moul sought to develop a comparison group of
companies by beginning first with the gas utilities listed in the basic service
of Value Line and excluding those
firms whose size and business operations make them too dissimilar to MERC. Additionally, Mr. Moul excluded Southwest Gas from
his comparison group “due to its location.”
50.
While many of the companies listed in the
Comparison Group are likewise included in the Gas Group, the eight firms in Dr.
Griffing’s Comparison group more closely approximate the regulatory
environments, operations and investment risk presented by MERC than do the nine
firms in the Gas Group.
51.
To determine an ROE, both Dr. Griffing and Mr. Moul
examined earnings growth rate projections and used inputs from three reporting
services: Value Line Investment Survey (“Value Line”), Yahoo! Finance and Zacks
Investment Research (“Zacks”). Likewise,
the experts both used similar dividend-yield equations and sources for dividend
inputs. While both Mr. Moul and Dr. Griffing used the
Discounted Cash Flow model, as detailed below, they differ in their application
of this technique when developing Return on Equity recommendations.
52.
Relying upon the Commission’s earlier acceptance,
in other proceedings, of the “constant-growth” DCF method, Dr. Griffing used this
DCF method in his analysis. The constant
growth method assumes that dividends (D) are received at the end of each year;
the annual growth rate of dividends (g) is constant to infinity; and the
discount rate for dividends (k) is constant to infinity.
53.
Dr. Griffing used data from a 30-day period between
September 16 and October 15, 2008 to calculate dividend yields. As he explained, this period includes enough trading
days to dampen short-term aberrations in the capital markets and was close in
time to the then most recently published growth estimates preceding the due
date for the filing of direct testimony in this proceeding.
54.
In his Direct Testimony, Dr. Griffing recommended a
Return on Equity range between 8.53 percent and 11.47 percent with a midpoint
of 9.93 percent.
55.
Noting that no clear pattern was evident in
recent share prices of the companies of the “Comparison Group” and the “Gas
Group,” Dr.
Griffing discounted the effect of the recent turmoil in the financial markets on
the assignment of an appropriate Return on Equity. Dr. Griffing asserts that during the period that
Mr. Moul used for his DCF analysis, five of the ten companies that are listed
in the two groups showed share price increases and five showed share price
decreases.
56.
In his Surrebuttal Testimony, and relying upon updated
company report and annualized dividend data gleaned after the due date for the
filing of direct testimony in this proceeding, Dr. Griffing recommended a Return on Equity
range between 8.89 percent and 11.66 percent with a midpoint of 10.21 percent.
57.
The Return on Equity range reflects the differences
among various expert forecasts used in the calculation of a Return on Equity. Forecasters differ as to the impact that
future interest-rate changes, rates of economic growth and regulatory changes
will have upon companies in the Comparison Group.
58.
As a check upon the reasonableness of the Return
on Equity calculations that followed from his Discounted Cash Flow analysis,
Dr. Griffing also undertook a Capital Asset Pricing Model (“CAPM”) analysis. The CAPM computes a cost of equity by determining the systematic
risk of an investment – called “the Beta” – by subtracting a “risk-free rate of
return” from the total return on the market of equities.
59.
Dr. Griffing began his analysis by selecting the
average yield on a 20-Year Treasury bond for September 16 - October 15 to
represent his riskless asset rate. Dr.
Griffing reasoned that these longer-term bonds were less volatile than shorter-term
intermediate Treasury bonds; and therefore were more appropriate for use in a CAPM
analysis. Dr. Griffing used the average
beta of the eight companies in his Comparison Group from the September 12, 2008
Value Line Investment Survey, which
is 0.81. For the risk-premium component
of the analysis, Dr. Griffing used the 6.5 percent value from Ibbotson
Associates’ annual yearbook.
60.
Dr. Griffing’s CAPM analysis yielded a Return on
Equity of 9.59 percent. This rate is within the overall range of his
DCF analysis and is close to the 9.93 percent midpoint of this range.
61.
Dr. Griffing updated his CAPM analysis in his
Surrebuttal Testimony. The outcome of
his updated CAPM analysis is 7.80 percent, which is outside the low end of his
updated Return on Equity range of between 8.89 percent and 11.66 percent. Concluding that this result demonstrated that
the CAPM can produce unreliable results, Dr. Griffing adjusted the inputs to
his CAPM analysis using data provided by Mr. Moul to incorporate a forecast
market risk premium. By adding the
forecast market risk premium for the Standard & Poors Composite 500, to the
historical market risk premium used in his CAPM analysis, Dr. Griffing obtained
a Return on Equity result of 9.35 percent.
9.35 percent is inside the low end of the Return on Equity range of his Discounted
Cash Flow results.
62.
Dr. Griffing also assessed the reasonableness of
his updated DCF result against the Public
Utilities Fortnightly annual Return on Equity survey. The most recent of these surveys was
published in the November 2008 issue and covers the period between September 1,
2007 and August 31, 2008. Dr. Griffing
found 28 cases for natural gas-only Local Distribution Companies within the survey. The mean Return on Equity award for the 28
companies is 10.36 percent. The median
award is 10.20 percent. Seventeen awards
are 10.20 percent or lower. The mean of
Dr. Griffing’s updated DCF analysis is 10.21 percent, one basis point higher
than the median Return on Equity of the companies in the Public Utilities Fortnightly survey and 15 basis points lower than
the mean Return on Equity of all 28 companies.
63.
Calculation of the overall allowable Rate of Return
is derived by multiplying each capital structure component by the cost of that
component and then adding the various results together for a total. Dr. Griffing’s recommended 10.21 percent Return
on Equity results, when combined with rates for other component costs, results
in a Rate of Return of 7.98 percent:
|
OES Cost of Capital Recommendation
Weighted
Component Ratio (%) Cost Rate Average
Cost
Long-Term Debt 43.42% 6.28% 2.73%
Short-Term Debt
7.81% 3.45% 0.27%
Common Equity 48.77% 10.21% 4.98%
Total 100% 7.98%.
|
3. MERC
Return on Equity and Rate of Return Recommendation
64.
In his Direct Testimony, Mr. Moul recommended a
Return on Equity of 11.25 percent.
65.
In his Rebuttal Testimony, Mr. Moul updated this
recommendation to urge a Return on Equity of 11.75 percent. This recommendation blends results from a
Discounted Cash Flow analysis, a “Risk Premium” analysis and a Capital Asset
Pricing Model analysis.
66.
While Mr. Moul’s Discounted Cash Flow analysis
results in a Return on Equity estimate of 10.04 percent, this initial figure is
adjusted; as Mr. Moul argues, to better reflect the actual risk of MERC’s
equities. Noting that the market values
of equity for the companies in the MERC Gas Group exceed the book values of this
equity, he argues that the Return on Equity calculation that is produced
by an unadjusted Discounted Cash Flow analysis understates the actual degree of risk. In his recommendation, therefore, Mr. Moul
urges application of a “leverage adjustment.”
67.
Likewise, Mr. Moul’s Capital Asset Pricing Model analysis
includes a leverage adjustment to his beta value. Argues Mr. Moul: “To develop a CAPM cost rate applicable to a
book value capital structure, the Value
Line (market value) betas have been unleveraged and releveraged for the
book value common equity ratios using the [Robert S.] Hamada formula.”
68.
Mr. Moul also includes a size adjustment of 0.92
percent in his CAPM analysis. Mr. Moul
argues that because of MERC’s relatively smaller size, when compared to like
local distribution companies, both the risk of investment in MERC, and the
rates of return it must offer investors, increases.
69.
Testing his synthesized Return on Equity
recommendation, Mr. Moul employed a Comparable Earnings analysis. He used both historically-realized returns
and forecasted returns for non-utility companies over a ten-year period. The historical median rate of return for
these companies was 13.90 percent and the forecasted return was 12.00 percent,
with a combined average of 12.95 percent.
Like the CAPM and Risk-premium approaches, the results of Comparable
Earnings analyses are influenced by analyst judgment.
70.
Combining MERC’s capital structure with the Return
on Equity derived from Mr. Moul’s analysis, MERC concluded that the overall
cost of capital was 11.75 percent. This
figure follows from Mr. Moul’s analytical methods when his original
calculations, which used data from May of 2008, are updated with data from October
of 2008.
71.
While MERC argues with genuine force that its
comparatively small size makes it more difficult to attract investment capital
than companies in either the “Comparison Group” or the “Gas Group,” its
proposed methods of accounting for these challenges have not been recognized
previously by the Commission and they invite more risk of analyst manipulation
than does the Discounted
Cash Flow method.
72.
Dr. Griffing’s Discounted Cash Flow analysis is firm evidence
that a Return on Equity of 10.21 percent will be sufficient to attract
investment capital. His additional calculations
using this method with MERC’s Gas Group further emphasize the reasonableness of
his Return on Equity recommendation.
73.
Twenty seven of the twenty eight awards reported in
the November 2008 Public Utilities
Fortnightly Return on Equity survey were 11.20 percent or lower.
74.
By using the OES’ proposed capital structure and
Dr. Griffing’s updated Discounted Cash Flow analysis, it is clear that the
allowable Rate of Return is 7.98 percent, which reflects the OES’s recommended
Return on Equity of 10.21 percent.
75.
When setting rates, the Commission will consider
those revenues and expenses shown by the Applicant to be reasonably
representative of ongoing operations and incurred during its projected test
year.
76.
Use of the year ending on December 31, 2008, as the
projected test year for determining MERC’s revenue requirement is reasonable.
77.
The OES’ proposed adjustments to the test year
sales and revenue are reasonable.
78.
At the close of the evidentiary hearing on February
4, 2009, a single expense issue remained unresolved between OES and MERC. The parties agree upon the proper allocation
of rate case expenses to non-regulated activities and an amortization period
for the rate case expenses. The parties do not
fully agree on an appropriate method of accounting for, and later recovery of, rate
case expenses.
79.
MERC proposed a three-year amortization period for
its rate case expenses. It argues that
this is a reasonable time-period based upon its estimate of the timing of its
next application for a rate increase. MERC
states that, overall, companies in the natural gas industry are undertaking
rate cases more frequently than in years past; and that a three-year
amortization period is consistent with the current cycle of rate-case filings.
80.
While OES accepts as reasonable MERC’s proposal to
amortize its rate case expenses over a three-year period, without a substantial
history of rate filing activity by MERC, OES is not confidant of its prediction
that MERC will return to the Commission with another rate application in three
years time. It expresses the concern
that, without other safeguards, MERC will over-collect significant rate-making
expenses after the three-year amortization period. OES proposes that MERC segregate through
deferred accounting rate-case expenses after the three-year amortization period.
81.
MERC's request for current rate case expenses in
this matter is appropriate, the total of which should be amortized over a
three-year period. Further, establishing
a deferred accounting account to track any monthly recovery of rate case
expense after the three-year amortization period expires is reasonable.
82.
The OES recommendation that rate case expenses
after the expiration of the three-year amortization period be credited against
the revenue requirement in MERC’s next rate case does not constitute
single-issue ratemaking.
83.
The OES recommendation that rate case expenses
after the expiration of the three-year amortization period be credited against
the revenue requirement in MERC’s next rate case is reasonable.
84.
The record in this matter shows that under the
current rates MERC will experience a substantial revenue shortfall. MERC is entitled to recover this revenue
shortfall through an adjustment of its natural gas distribution rates.
85.
With the adjustments to rate base and test year
operating expenses and revenues agreed to by OES and MERC (either in prefiled
testimony or during the evidentiary hearing), the one remaining factor
influencing the gross revenue deficiency is the cost of common equity.
86.
Using the OES’s recommended cost of equity of 10.21
percent and the resultant rate of return of 7.98 percent, the undersigned finds
that the gross revenue deficiency for MERC-PNG is approximately $13,646,056 and
the gross revenue deficiency for MERC-NMU is approximately $1,885,474.
87.
These numbers are approximate because it is
anticipated that the parties will submit final gross revenue deficiency calculations
for each MERC subunit as part of the process of the presentment and review of
this Report and the final rate determination by the Commission.
88.
MERC’s natural gas rate structure consists of rates
designed to recover wholesale (commodity and demand) costs; fixed customer
costs; and costs to deliver the wholesale gas to customers. The customer charge and delivery rate
constitute the delivery charge portion of a customer’s bill.
89.
Under Minnesota
law, the wholesale cost to MERC for the natural gas that is sold to customers
is passed through to customers without additional markup. In Minnesota,
the costs of providing natural gas service and the utility’s authorized rate of
return are recovered through the delivery charge.
90.
For Residential customers, the costs of providing
natural gas service and the utility’s authorized rate of return are recovered
through customer charges or through a volumetric distribution charge. To the extent that customer charges do not
recover the full cost of connecting a customer to, and maintaining the customer
on the distribution system (including such costs as ongoing metering, billing,
customer service and maintenance), the costs associated with these services
will be recovered through a volumetric charge.
91.
The customer charge is the amount paid monthly by
any customer that is connected to MERC’s gas distribution system. This charge is paid independently of gas
usage. The basic customer charges were
set most recently in 2003 and vary by customer class.
92.
The delivery rate is calculated by multiplying the
therms in the natural gas that is purchased by an established rate. Customary rate design practice includes
allocating a portion of the projected revenue requirement to the basic charge
and the remainder to the delivery rate.
93.
Among the services provided by MERC to its
customers are sales service and transportation service. Under sales service, customers rely on
MERC-PNG’s or MERC-NMU’s regulated utility to obtain gas and arrange for transportation
of that gas to the customer.
94.
Under transportation service, customers acquire
their own gas supplies through an unregulated gas supplier and arrange for delivery
to a Town Border Station (TBS). From
Town Border Stations, MERC-PNG’s and MERC-NMU’s distribution system is used to
transport the gas to various customers.
Transportation customers typically bear more responsibility for
balancing and nominating gas supplies than do sales customers.
95.
Both sales and transportation customers may elect
to take “firm” or “interruptible” service.
Firm service is typically not subject to curtailment and is priced to
include the costs of providing a reliable source of supply. Service to customers who subscribe to
interruptible tariffs can be order to curtail their use for a time as may be
needed in order to maintain overall system reliability.
96.
Regardless of where customers obtain gas supplies –
from MERC or some other supplier – all customers who use MERC’s distribution
system must pay for the transportation of natural gas. Indeed, a key principle of effective rate
design is that the cost of transportation to a particular customer be uniform
among, and not a basis of competition between, MERC and other potential
suppliers of natural gas.
97.
This transportation component is strictly regulated
under Minnesota
state law because the distribution of natural gas is considered a “natural
monopoly.” Rates for these services
include, at a minimum, the incremental cost of transporting natural gas through
the distribution system, along with providing metering, billing and other
customer services.
98.
MERC proposed
to increase the monthly Transportation Administration Fee from the current
level of $150.00 to $170.00 per metered account for all transportation
customers.
99.
Constellation
objects to MERC’s proposal to increase the Transportation Administration Fee
for small volume transportation customers and proposed that the fee be reduced
to $50.00 per month for small volume transportation customers.
100.
The undersigned concludes that MERC’s proposed
increase to the transportation administration fee is supported by the Class
Cost of Service study
and recommends that the transportation administration charge be increased to
$170.00 per month per metered account for all transportation customers and that
the Commission adopt MERC’s proposal to require all small volume transportation
customers to install telemetry.
101. In
order to establish an estimated cost of service for the various customer
classes and individual components of cost within each customer class, MERC
began, as required by rule, with a Class Cost of Service Study (“CCOSS”).
102. The objective of a
Class Cost of Service Study should be to identify, as accurately as possible,
which customer class is responsible for each cost incurred by the utility that
is providing the service. A Class Cost
of Service Study should reflect cost causality, with no other factors
influencing the study.
103. As
part of its application, MERC submitted a fully distributed embedded cost study
that apportions its historic as well as ongoing costs.
104. MERC
was the only party to submit a Class Cost of Service Study in this proceeding.
105. MERC’s
revenue apportionment proposals was designed to move customer classes towards
their cost of service and to move the rates that are assessed by MERC-PNG and
MERC-MNU closer together. MERC hopes to further
consolidate the rate areas of these formerly separate utilities.
106. In
very general terms, MERC’s rate proposals for MERC-PNG and MERC-NMU share a
number of the same features. MERC proposes
keeping residential rates below the cost of service, although urging a movement
of residential rates closer to the actual cost of service. In addition, within the general service class,
MERC’s proposes to set rates for the larger commercial and industrial general
service customers at higher than the cost of service, while smaller commercial
and industrial customers would be below the cost of service. Likewise, interruptible and transportation
customers generally would continue to pay rates that are set above their cost
of service.
107. To the extent that
MERC-PNG’s and MERC-NMU’s non-general service customers can use alternative
energy sources (such as propane, or No. 2, or No. 6 fuel oil) to replace
natural gas, each utility must be sensitive to the prices of those alternatives
in crafting rates for its customers.
Unlike electric utilities which have assigned exclusive service
territories, there are no assigned service areas for natural gas
utilities. However, some non-general
service customers may be able to bypass a utility’s system altogether.
108. MERC
proposed a small increase to the distribution charge for the Super Large Volume
(SLV) customer class, from $0.0040 to $0.0042 per therm. MERC limited the proposed rate increase for
this class due to concern that any additional increases in this rate class
would make MERC offerings noncompetitive and result in SLV customers bypassing
MERC's system entirely. MERC asserts
that once bypass occurs, it is difficult to regain these customers. So as to avoid losing the support of the
super large volume customers toward common costs on the system, MERC proposes
to shield this class from some of the effects of increased costs of service.
109. Similarly,
out of concerns over potential customer bypass, MERC proposes to hold the
distribution charge for MERC-NMU’s SLV Interruptible Transport rate class flat.
110. The OES reviewed
MERC’s proposed revenue apportionment to SLV customers to determine whether the
proposed rates are covering the incremental cost of serving them. MERC’s response to OES Information Request
No. 310 indicated that incremental costs are being covered, and, thus, the OES
concluded that MERC’s proposed revenue apportionment to the SLV customers is
reasonable.
111. The
OES reviewed MERC's proposed revenue apportionment, and the rationale offered
by MERC for the proposed apportionment, and determined that the apportionment
was reasonable.
112. Further, OES
concluded that the customer classes that are furthest from cost are being moved
slightly closer to cost than other customer classes, without shifting the
burden significantly to those classes of customers which are apportioned
revenue responsibility above their allocated costs.
113. No
other party filed testimony on the revenue apportionment in this case.
114. The undersigned concludes
that MERC supported its use of fully distributed embedded Class Cost of
Services Study and that its study should be used as a basis for revenue
apportionment and rate design.
115. Based upon the
agreed upon resolution between MERC and the OES of certain financial issues, it
is predicted that the gross revenue deficiency will be less than what MERC
originally requested.
116. In
the event of a determination that MERC receives a smaller revenue requirement
than applied for in this case, OES recommended that rates for the Super Large
Volume customers for MERC-PNG and MERC-NMU be held constant, and that the
decreased revenue requirement be apportioned proportionately to the remaining
customer classes. MERC agreed with this
approach.
117. Historically
and in MERC’s current proposal, the rates established for the Super Large
Volume customer classes have reflected concerns over both recovering the cost
of service while attempting to prevent bypass of MERC's natural gas system by
these customers. As a result, it is
reasonable for the Commission to consider the SLV rate class separately when
passing upon potential reductions to a revenue apportionment so to meet a later
lower revenue requirement.
118. The OES’s proposed
revenue apportionment with proportionately reduced amounts for all but the
Super Large Volume customer class is reasonable, and strikes the best balance
between the various rate design principles used by the Commission. The amount apportioned to Super Large Volume
class should be kept as initially requested by MERC.
119. The record
includes a recommended revenue apportionment as to which all parties have had
the opportunity to submit pre-filed Rebuttal Testimony and test through cross-examination. This recommendation is reasonable for all
customer classes and should be accepted.
120. The residential
customer’s bill includes three elements—the commodity charge for natural gas,
the volumetric distribution charge and the customer charge.
121. Currently,
MERC-NMU’s residential customer charge is set at $5.50 per month and MERC-PNG’s
is set at $6.50 per month. MERC proposes
to charge both MERC-NMU and MERC-PNG residential customers a $9.00 per month customer
charge. As with other features of its
rate application, MERC asserts that its proposal is intended to move customer
charges for the residential classes closer to the actual cost of service and to
facilitate a future consolidation of the rate schedules between MERC-PNG and
MERC-NMU.
122. MERC’s incremental analysis shows that the
proposed residential customer charge of $9.00 per month does not recover the
incremental, customer classified costs.
123. The residential customer charge has not been
increased in the eight years since Aquila’s
rate case in Docket No. G007,011/GR-00-951.
124. The Consumer Price Index for Urban Consumers
has increased 24.79% between the 2000 test year and 2008.
125. MERC
asserts that the current and proposed customer charges are below the cost of
service and the recoveries are supported by the Class Cost of Service Study:
|
|
Current
Customer Charge
|
Proposed
Customer
Charge
|
Customer Charge Justified by the CCOSS
|
|
MERC-PNG (GS-1, GS-4, and GS-5)
|
$6.50
|
$9.00
|
$25.47
|
|
MERC-NMU (GS-NMU)
|
$5.50
|
$9.00
|
$29.11
|
Because the customer
charges are below the customer cost, MERC argues that these costs are shifted
to distribution charges, and that as a result, customers with higher than
average usage pay more than their proportionate share of these costs. MERC maintains that this shifting of costs constitutes
an intra-class subsidy that is inconsistent with the provisions of Minn. Stat.
§§ 216B.03 and 216B.07.
126.
As Ms. Peirce of OES elegantly summarized in her
testimony, “[i]mplicit in the argument to keep customer charges low is that it is
appropriate to ask Customer A to pay some of the fixed costs of serving
Customer B.”
127.
The amount of intra-class subsidization from
customers within the residential customer class is not based upon an ability to
pay. For example, Ms. Peirce predicts
that the result of maintaining the fixed customer charge below the actual cost
of services is that some lower-income residential customers, who have high
winter usage, will pay for costs through volumetric charges that they do not
impose on the system.
128.
While acknowledging the appropriateness of moving customer
charges closer to actual costs, OES prefers a set of more modest increases, and
extending the subsidies from other customer classes as an “interim step toward
consolidating the rate structures.” It initially urged a residential customer
charge of $7.50 for MERC-PNG and $7.00 for MERC-NMU – and then later proposed
that a residential customer charge of $7.25 be set for both companies.
129. The OAG-RUD claimed
that MERC’s cost support does not provide a basis for an increase in the
residential customer charge. OAG-RUD
argued that the residential customer charges for MERC-PNG and MERC-NMU should
not increase.
130. The OAG-RUD also took
issue with relying too heavily on the CCOSS as the basis for cost allocation or
as a revenue recovery tool. Its view was
that the Commission can more accurately determine whether a subsidy for a class
exists by comparing marginal costs for providing a specific service with the
rate charged.
131. As detailed more
fully in the Memorandum that follows below, MERC has demonstrated that an
increase in the residential customer charge from $5.50 for MERC-NMU and $6.50
for MERC-PNG to $9.00 per month for each company is reasonable and appropriate. MERC has demonstrated that the proposed increases
in the residential customer charge appropriately assigns costs to that class,
while avoiding ratepayer confusion, disincentives to conservation and significant
rate shock. Additionally,
the proposed customer charges will likely result in a more uniform set of winter
and summer utility bills; send more accurate price signals to customers by
bringing their rates closer to the true cost of service; and provide
incrementally more stable cash flows to the utility.
132. In the view of the
Administrative Law Judge, the claim that an increase in the residential
customer charge of (up to and including) $3.50 per month will have the tendency to “confuse and alienate” customers
is overstated.
133. MERC proposed to
include certain 2007 year-end Conservation Improvement Program (“CIP”) tracker
account balances and certain Demand Side Management (“DSM”) financial
incentives in test year CIP expenses.
MERC proposes to recover these expenses through the Conservation Cost
Recovery Charge (“CCRC”), which is a feature of both MERC-PNG’s and MERC-NMU’s
base rates.
134. MERC’s allocation
of its approved Conservation Improvement Plan expenses and Conservation Cost
Recovery Charge is appropriate.
135.
MERC requested Commission approval of the CIP tracker
account balances and the Demand Side Management incentives parallel filings
submitted in MPUC Dockets Nos. G011/M-08-843 and G007/M-08-844.
136. For MERC-PNG, MERC
proposed a 2007 year end CIP tracker account balance of $2,764,463 and 2006 and
2007 DSM financial incentives of $491,706 and $468,445, respectively.
137. For MERC-NMU, MERC
proposed a 2007 year end CIP tracker account balance of $866,744 and 2006 and
2007 DSM financial incentives of $39,113 and $69,179, respectively.
138. On December 17,
2008, the OES submitted comments in Docket Nos. G011/M-08-843 and
G007/M-08-844. For MERC-PNG, the OES
recommended adjustments to the 2007 CIP tracker account, which resulted in a
year-end 2007 balance of $2,715,561 – rather than the proposed year-end 2007
balance of $2,764,463 – a difference of $48,902.
139. Similarly, for
MERC-NMU, the OES recommended adjustments to the 2006 and 2007 CIP tracker
accounts, which resulted in a year-end 2007 balance of $825,033 – rather than
the proposed year-end 2007 balance of $866,745 – a difference of $41,712.
140. The OES’s
recommended adjustments for MERC-PNG and MERC NMU included a recommended
disallowance of their proposed 2007 DSM financial incentives in Docket Nos.
G011/M-08-843 and G007/M-08-844. MERC
was also not able to reconcile two different CIP expenses for 2006 and 2007 for
MERC-PNG and MERC-NMU that were reported in the CIP tracker accounts in Docket
Nos. G011/M-08-843 and G007/M-08-844 and the CIP status reports in Docket Nos.
G011/CIP-04-816.03 and G007/CIP-04-815.03, respectively. Thus, the OES recommended including in the
CIP tracker accounts the CIP expense amounts that were previously approved by
the Director of the OES in MERC’s status reports dockets. In addition, MERC did not correctly calculate
its year-end 2006 CIP tracker account balances for MERC-PNG and MERC-NMU in
Docket Nos. G011/M-08-843 and G007/M-08-844, respectively.
141. On January 7,
2009, MERC responded in Rebuttal Testimony by proposing a two-track procedural
approach for determining the levels of CIP tracker account balances and DSM
financial incentives to include in test year CIP expenses for MERC-PNG and
MERC-NMU. Each track would be dependant upon
the timing of the Commission’s determinations in MPUC Docket Nos. G011/M-08-843
and G007/M-08-844 in relation to its determinations in this docket.
142. If the Commission
does not make determinations in Docket Nos. G011/M-08-843 and G007/M-08-844
prior to a determination on final rates in the present docket, MERC proposed to
use the CIP tracker account balances and DSM financial incentives for 2006 and
2007 proposed by the OES in Docket Nos. G011/M-08- 843 and G007/M-08-844 to
calculate deferred CIP expenses for the test year. MERC also proposed to include in test year
CIP expenses 2005 DSM financial incentives for MERC-PNG and MERC-NMU of
$380,631 and $116,415, respectively.
These DSM financial incentives were previously approved by the
Commission in Docket Nos. G011/M-06-823 and G007/M-06-822, but were inadvertently
not included for recovery by MERC. In
addition, MERC proposed that it be ordered to recover any difference between
the CIP tracker balances and DSM financial incentives included in test year CIP
expenses in this proceeding and those ultimately approved by the Commission in
Docket Nos. G007/M-08-844 and G011/M-08-843.
This set of arrangements would form “Track One.”
143. If the Commission
makes determinations in Docket Nos. G011/M-08-843 and G007/M-08-844 prior to a
determination on final rates in the present docket, however, MERC proposed that
the approved 2007 year-end CIP tracker account balances and DSM financial
incentives for 2005, 2006, and 2007 be included in test year CIP expenses in
the general rate case. This set of alternative arrangements would form “Track
Two.”
144. On January 22,
2009, the OES agreed in Surrebuttal Testimony with MERC’s two-track procedural
approach.
145. The
undersigned concludes that MERC’s two-track approach for the recovery of
Conservation Improvement Program tracker account balances and Demand Side
Management incentives, is consistent with the Commission’s prior practice and
yet does not prejudge or presume to foretell the decisions that the Commission
will in Docket Nos. G011/M-08-843 and G007/M-08-844.
Based on the foregoing Findings, the
Administrative Law judge makes the following:
CONCLUSIONS
1.
The Minnesota Public Utilities Commission and the
Administrative Law Judge have jurisdiction over the subject matter of this
proceeding pursuant to Minnesota Statutes §§ 14.50, 216B.08 and 216B.16.
2.
In the absence of competition, government
regulation has been used to approximate the results that would be achieved in a
competitive environment. Minnesota
Statutes §§ 216B.03 and 216B.07 require rates to be reasonable and not
unreasonably discriminatory.
3.
Modifying MERC’s natural gas rates in the manner
described in the Findings and Conclusions above results in just and reasonable
rates that are in the public interest as those terms are used Minn. Stat. §
216B.11.
4.
The rate finally ordered by the Commission should
be compared to the interim rate set in the Commission’s September 25, 2008
Order Setting Interim Rates, and a refund be ordered to the extent that the
interim rate exceeds the final rate, subject to any true-up ordered regarding
any particular expense.
5.
Any Finding that is more appropriately designated
as a Conclusion is hereby adopted as a Conclusion.
RECOMMENDATION
Based upon the foregoing Findings and
Conclusions, IT IS RECOMMENDED that the Minnesota Public Utilities Commission determine
that:
1.
MERC is entitled to increase gross annual revenues
in the manner and in an amount consistent with the terms of this Order.
2.
Within 30 days of the service date of this Order, MERC
shall file with the Commission for its review and approval, and serve on all
parties in this proceeding, revised schedules of rates and charges reflecting
the revenue requirement for annual periods beginning with the effective date of
the new rates, and the rate design decisions contained herein. MERC shall include proposed customer notices
explaining the final rates. Parties
shall have 14 days to comment.
3.
If the Commission orders an Interim Rate Refund,
within 30 days of the service date of this Order, MERC shall file with the
Commission for its review and approval, and serve upon all parties in this
proceeding, a proposed plan for refunding to all customers, with interest, the
revenue collected during the Interim Rate period in excess of the amount
authorized herein. Parties shall have 14
days to comment.
4.
The matters set forth in these Findings and
Conclusions should govern the mathematical and computational aspects of the
Findings and Conclusions. Any
computations found to be in conflict with the items expressed should be
adjusted to conform to the body of this Report.
Dated:
April 17, 2009.
_/s/ Eric L. Lipman _
ERIC L. LIPMAN
Administrative Law Judge
Notice is hereby given that pursuant to Minn. Stat. § 14.61, and the
Rules of Practice of the Minnesota Public Utilities Commission (“Commission”)
and the Office of Administrative Hearings, exceptions to this Report, if any,
by any party adversely affected must be filed according to the schedule which
the Commission will announce. Exceptions
must be specific and stated and numbered separately. Proposed Findings of Fact, Conclusions and
Order should be included, and copies there of shall be served upon all
parties. Oral argument before a majority
of the Commission will be permitted to all parties adversely affected by the
Administrative Law Judge’s recommendation who request such argument. Such request must accompany the filed
exceptions or reply (if any), and shall be filed with the e-docket system, or
an original and 15 copies of each document should be filed with the Commission.
The Commission will make the final
determination of the matter after the expiration of the period for filing
exceptions, or after oral argument, if such is requested and had in the
matter.
Further notice is hereby given that the
Commission may, at its own discretion, accept or reject the Administrative Law
Judge’s recommendation and that said recommendation has no legal effect unless
expressly adopted by the Commission as its final order.
MEMORANDUM
While the
record in this case includes a complex array of cost and revenue data, the
disputes between the parties can be quickly summarized: As to one or another feature of MERC’s rate
proposal, each party comes forward requesting special relief from the Commission’s
familiar methods, in the hopes of obtaining benefits for particular companies
or classes of customers.
In this vein, for example, MERC argues that
notwithstanding a long-history of using an unmodified Discounted Cash Flow
analysis, the Commission should employ a set of analyst-developed adjustments
to make MERC’s equities more attractive to investors. While MERC argues with genuine force
that its comparatively small size makes it more difficult to attract investment
capital than companies in either the “Comparison Group” or the “Gas Group,” its
proposed methods of accounting for these challenges have not been recognized
previously by the Commission and they invite more risk of analyst manipulation
than does the Discounted
Cash Flow method. Without clear guidance
that the types of adjustments undertaken by Mr. Moul are acceptable to the
Commission, and are not overly susceptible to analyst manipulation, such
enhancements to the DCF method are disfavored.
For a different set of
beneficiaries, OES and OAG-RUD argue that the Commission should intervene to keep
the monthly charge to residential customers artificially low for the indefinite
future. OES and OAG-RUD urge this result
so as to avoid “rate shock” to residential customers. While it is true that 20 of MERC’s 207,000
customers submitted testimony opposing any residential rate increase, in the
view of the Administrative Law Judge, the claim that an increase in the
residential customer charge of up to and including $3.50 per month will have
the tendency to “confuse and alienate” a large number of customers, is
overstated. This is particularly true
because the monthly charge represents a relatively small portion of the average
residential customer’s annualized natural gas bill and MERC’s proposal includes
a corresponding average per therm rate reduction for residential customers.
Indeed, the more likely possibility
is that the alternatives urged by OES and OAG-RUD would be more shocking to residential
customers. OES and OAG-RUD recommend that
comparatively larger shares of fixed costs be shifted to distribution charges, such
that customers with higher than average usage would continue to pay more than
their proportionate share of these costs.
“Implicit in the argument to keep customer charges low,” Ms. Peirce of
OES reminds us, “is that it is appropriate to ask Customer A to pay some of the
fixed costs of serving Customer B.” Because there is genuine doubt that any of
the twenty commentators who opposed a residential rate increase, would prefer
the system of higher average costs per therm and cross-subsidizing their
neighbor’s utility bills, as argued by OES and OAG-RUD, the predictions of
“rate shock” are of limited guidance.
The alternatives that OES and OAG-RUD recommend for residential
customers are worse.
Moreover, to the extent that any rates
which have the tendency to “shock customers” follow from long lag times between
ratemaking petitions, all of the participants in the ratemaking process (the Applicants,
OES, OAG-RUD, Intervenors, OAH, the Commission, the Minnesota Legislature and
the public) bear some share of responsibility.
As the record in this comparatively simple case bears out, the
ratemaking process (particularly for companies whose stock is not publicly
traded) is a very resource-intensive and costly enterprise. Even in those instances in which the rate
case expenses are fully recoverable at a later date, sensible applicants will
approach with genuine caution the prospect of undertaking a new rate case
because the staff impacts upon employees can be so grueling.
Thus, while
guarding against potential “rate shock” is an important part of the
Commission’s analysis, it should be viewed as one factor in the context of a much
broader regulatory environment. A
countervailing concern to “shocking” residential customers is that even
bringing a narrow set of ratemaking matters to a decision is a costly,
difficult and complex undertaking.
On balance, MERC’s requested
increases in the monthly charges for residential customers are consistent with
the actual costs of service and are reasonable.
The Taconites come forward to argue that to
the extent that there is smaller revenue deficiency for MERC than was earlier
projected, they should share
equally in any later re-apportionment of the revenue requirements. Because the rates for MERC’s SLV customers will increase
at a far smaller rate than other classes, and MERC-PNG’s SLV rates are now set
below the cost of service, these arguments are not well taken. In the view of the Administrative Law Judge,
to the extent that MERC’s revenue requirements are later re-apportioned, the
customer classes that are furthest from cost should be moved closer to cost,
provided that other customer classes are not “apportioned revenue
responsibility above their allocated costs.”
In its application, MERC proposes to raise the Transportation
Administration Fee from $150 to $170. Constellation urges a 66 percent
reduction in the current fee for small volume transportation customers like
it. Because MERC’s requested increase
reflects the reasonable monthly costs of administering MERC’s transportation
tariff for each metered account; these costs are not related to amount of gas
that is consumed by the gas customer; and the Commission set this fee at $150
per month for all classes of MERC customers in 2000; the fee reduction
requested by Constellation is unwarranted.
With one exception, the Administrative
Law Judge has recommended the results that follow from the familiar formulas over
special adjustments for particular interests.
The one exception is with respect to MERC’s request that the rate of
increase for the class of Super Large Volume customers be held far lower than
would otherwise be indicated by the Class Cost of Service Study. Presumably, if given its druthers, MERC would
much prefer to assign the Super Large Volume customers rates which match the true
costs of providing the service to these companies; but it refrains from urging this
result out of concern over customer bypass and the resulting impact that bypass
might have upon revenues for the entire system.
In the view of the Administrative Law Judge, this rationale has special
persuasive force because it is not an example of a party’s preferred result
being urged over an opposing party’s competing interests.
The Commission is best guided by the
methods it has followed in the past – which, in this case, can be found in twin
pillars of OES’s updated Discounted Cash Flow analysis and MERC’s Class Cost of
Service Study. With these tools, the Commission
is well equipped to promote the efficient use of resources, a reasonable rate
of return for regulated companies and the adoption of rates that are fair and
reasonable for all classes of customers.
E. L. L.
