15-2500-17032-2
G008/GR-05-1380
STATE OF
OFFICE OF ADMINISTRATIVE
HEARINGS
FOR THE
|
In
the Matter of the Application of CenterPoint Energy |
FINDINGS OF FACT, CONCLUSIONS, AND RECOMMENDED ORDER |
This matter
came on for evidentiary hearing before Administrative Law Judge Beverly Jones
Heydinger on April 11, 2006 in the Large Hearing Room at the offices of the
Public Utilities Commission (“Commission”) in
After the conclusion of the evidentiary hearing, the Commission determined that additional hearings were appropriate regarding the proposed affordability program and the background on CenterPoint’s billing system. Additional hearings were scheduled for June 8 and June 28, 2006. Following further discovery, the parties agreed that the June 8 hearing was not necessary and it was cancelled. The hearing on the billing program was held on June 28, 2006.
A briefing schedule was established at the conclusion of the evidentiary hearings. Posthearing briefs were filed on July 11, 2006; supplemental briefs were filed on August 4, 2006; and reply briefs were filed on August 14, 2006. The hearing record closed on August 14, 2006.
Eric Swanson and David Aafedt,
Attorneys at Law, Winthrop & Weinstine,
Karen Finstad Hammel and
Valerie Smith, Assistant Attorneys General, 1400
Ron Giteck and Steve Alpert,
Assistant Attorneys General, 900 Bremer Tower,
Chris Duffrin, Assistant
Director, and Pam Marshall, Executive Director of the Energy CENTS Coalition
(Energy CENTS), 823 East 7th Street, Saint Paul, Minnesota 55106,
appeared on behalf of Energy CENTS.
James Strommen, Attorney at
Law, Kennedy & Graven,
Robert Harding, Rates Analyst; Jerry Dasinger,
Financial Analyst; and Stuart Mitchell, Rates Analyst,
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 thereof 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 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 as set forth above, 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.
Under Minn. Stat. § 216B.16, subd. 1a,
if the Commission rejects or modifies the Settlement between the Energy CENTS and the Company, this
matter may be extended by 60 days for conclusion of this proceeding.
CenterPoint
has requested an increase in its natural gas rates of $40.9 million, which is
approximately a 2.4% increase in annual revenues. The Commission
has directed that an evidentiary record be established on that request with
regard to the following issues:
·
Is the revenue increase sought by CenterPoint reasonable or will it
provide CenterPoint with unreasonable or excessive earnings?
·
Is the rate
design proposed by CenterPoint – including the proposed residential customer
charge and “block rates” – reasonable? CenterPoint proposes to increase the
proportion of its revenues that it collects through a fixed monthly charge and
decrease the proportion that it collects for each unit of gas sold. In
addition, CenterPoint no longer proposes to charge a uniform rate per therm of
gas it provides to residential customers; instead, it proposes to charge
varying prices depending on the volume of gas the customer consumes.
·
Are CenterPoint’s proposed capital structure and return on capital
reasonable? Generally a utility can
acquire capital more cheaply by borrowing than by selling equity, but debt
payments restrict a utility’s finances more than equity does, so a balance
needs to be struck in the public interest. The Commission must provide an
opportunity for utilities to earn sufficient revenues to pay an adequate return
on capital, but not an excessive return.
·
Is it reasonable for CenterPoint to model normal weather on the basis of
ten years of data rather than twenty?
The past ten years have been warmer on average than the ten years
prior. All else being equal, a gas
utility will sell less gas in warmer weather, and therefore would need to
recover a larger share of its operating costs for each unit of gas sold.
·
Should the Commission approve CenterPoint’s proposed residential affordability
program? CenterPoint favors creating a
program to subsidize service to low–income customers, but many details remain
unspecified.
·
Should the Commission authorize CenterPoint to recover uncollected gas
costs through the Purchased Gas Adjustment (PGA) pursuant to Minnesota Rules
parts 7825.2390 – 7825.2920? An energy
utility’s bill reflects both a base rate and various automatic adjustments to
that base rate such as the PGA. The base rate reflects a utility’s prudently–incurred
costs, including the cost of revenues lost when a customer cannot pay its bill.
The PGA permits gas utilities to adjust their rates periodically to reflect
fluctuations in the cost of natural gas. CenterPoint now proposes to recover
the fuel–related portion of bad debt costs through the PGA rather than through
base rates. [1]
·
Was CenterPoint prudent regarding its investment in and implementation
of its new billing system and related calling issues. [2]
Based on all the proceedings herein, the Administrative Law Judge makes
the following:
A. Description of the Company
1.
In 1997, the Commission approved a merger between the NorAm Energy
Corporation (NorAm) and Houston Industries, Inc. (HI). CenterPoint Energy was then a division of
NorAm. HI changed its name to Reliant
Energy, Inc. in 1999. After a
restructuring to spin off unregulated businesses in 2002, the regulated
businesses began operating under the name of CenterPoint Energy, Inc.
(CNP). CenterPoint Energy Resources
Corporation (CPRC) is a wholly-owned subsidiary of CNP.[3]
2.
CenterPoint operates the natural gas utility service known as
CenterPoint Energy Minnesota Gas in
3.
CenterPoint distributes natural gas to over 750,000 customers in
B. Jurisdictional-Procedural
Background
4.
On November 2, 2005, CenterPoint filed a Petition with the Commission,
under Minn. Stat. § 216B.16, for an increase in natural gas rates of $40,878,000
(over all, approximately a 2.4 percent increase over the test year (current
rates)). CenterPoint also made a request
for Interim Rates in the amount of $34,719,000 (a 2.07 percent increase).[8]
5.
On December 21, 2005, the Commission issued an Order accepting the
filing as complete as of November 2, 2005, and suspending the proposed rate
increase until the Commission determines the reasonableness of the proposed
rates.[9] Also on that date the Commission issued a
Notice and Order for Hearing, directing that a contested case hearing be
convened to determine the reasonableness of the rate changes proposed by
CenterPoint.[10]
6.
On December 21, 2005, the Commission issued an Order approving the
proposed interim rates. The interim rates
became effective on January 1, 2005.
CenterPoint is collecting interim rates subject to refund if the interim
rates are in excess of the final rates determined by the Commission.[11]
7.
On January 13, 2006, a prehearing conference was held before
Administrative Law Judge Beverly Jones Heydinger in
8.
On May 1, 2006, CenterPoint submitted a Motion For Extension of the
deadline for the Commission to take final action on its rate increase request. The Commission considered the motion on May
11, 2006. At that hearing, CenterPoint offered
to waive its statutory right under Minn. Stat. § 216B.16, subd. 2, to place its
proposed final rates into effect following the expiration of the statutory
deadline for deciding rate increase petitions.
The waiver period proposed was one month. This period was in addition to the month-long
extension relating to a stipulation regarding a proposed Affordability Program.
9.
On May 17, 2006, the Commission issued an Order Referring Prudence
Issues Regarding Billing System Investment and Implementation To Administrative
Law Judge For Discovery and Hearing. The
Commission also extended the deadline for a Commission decision in this matter
to November 2, 2006, and referred this matter back to the ALJ for additional
discovery and hearing on the issues of the prudence of the investment in and
the implementation of the new billing system and related calling issues.[12]
10.
On June 28, 2006,
the evidentiary hearing reconvened to address the remaining issues relating to
the Affordability Program and the billing system. At the hearing, a briefing schedule was
established, with posthearing briefs due on July 11, 2006 and reply briefs due
August 14, 2006. The hearing record
closed in this matter on August 14, 2006.
C. Natural Gas Service Areas
11.
CenterPoint’s natural gas customers are divided between two service
areas, denominated the Northern Service Area and the Viking Service Area. CenterPoint has been moving toward
consolidating the rate structures of these two areas that have previously been
modestly different. The Northern Service
Area includes the City of
D. Summary of Public Comments
12.
Public comments on CenterPoint’s proposed rate increase were received
from attendees at the five public hearings, including one video conference, and
persons who mailed (or emailed) their written comments. All of those comments have been read and this
summary is provided as a representative sampling of those comments.
13.
At the public
hearings, CenterPoint Energy was represented by Rolf Lund, Public Relations
Officer, or Patty Pedersen, Associate Director of Public Relations. They testified in a consistent manner at all
hearings. A rate case “fact sheet” was
distributed to assist the public in understanding CenterPoint’s proposed rate
increase. The proposed rate increase for
natural gas distribution by CenterPoint Energy would increase revenues by $40.9
million annually, which is 2.4 percent of the company’s total annual
revenue. Because this increase only
affects the costs of providing distribution, only 20 percent of a typical
customer’s bill is affected.[14]
14.
The rate increase
is needed, CenterPoint contends, to recover the costs of its growing
distribution system. Increases in the
cost of bad debt and in the cost of storing purchased natural gas, both linked
to rising gas costs, were cited by CenterPoint as adding to the need for a rate
increase. Street and highway projects
have required CenterPoint to move gas lines, thereby increasing capital
costs. The Midwest Gas replacement
project was also identified as increasing costs by $7 million, adding to
CenterPoint’s revenue shortfall.
CenterPoint undertook this project following a gas explosion and
investigation by the Office of Pipeline Safety to replace gas lines that could
contain a defective coupling.
CenterPoint also noted that the per customer use of natural gas was
decreasing, causing a reduction in revenue, without a corresponding reduction
in fixed costs. The revenue impact of declining natural gas
usage was estimated to be about $7 million.[15]
15.
CenterPoint
estimated that the impact of the proposed rate increase on the average
residential customer would be approximately $3 per month, half tied to the
proposed increase in the residential basic customer charge, from the current
level of $6.50 to the proposed $8.00.
CenterPoint suggested that the additional revenue from the increase in
the fixed charge would benefit the company by rendering its revenues less
dependent on seasonal fluctuations and, thus more consistent throughout the
year. The proposal for introducing block
rates was mentioned, and CenterPoint asserted that this approach would
encourage conservation.[16]
16.
At the public
hearings, the Office of the Attorney General (OAG) was represented by Ron
Giteck and Mary McKinley, Assistant Attorneys General in the Residential and
Small Business Utilities Division; Jessica Palmer-Denig, Manager of the
Residential and Small Utilities Division; Colleen Crossley, Consumer Liaison;
Amy Brendmoen, Investigator; and Curtis Nelson, a Financial Analyst. Specifically, the OAG expressed concern that,
under CenterPoint’s proposal, business customer rates would decrease at the
expense of residential customer rates.
Further, the new rate design will likely increase rates paid by
residential customers in a greater proportion than business customers. Including the increase in the residential
basic charge from the prior year’s rate adjustment, the change from $5 to $8
amounts to a 60 percent rate increase for residential customers in that single
charge. The OAG also noted that the
impact of the block rate proposal amounts to an additional residential basic
charge of $1.62, because almost all residential customers will use the first
block of therms every month. The impact
of bad debt on CenterPoint’s rate increase request was raised as a concern. OAG disputed whether CenterPoint’s
explanation of declining use was accurate.
The proposed cost of the Midwest Gas replacement project and the manner
in which customer billing system changes were accomplished were also of concern
to the OAG.[17]
17.
At the public
hearings, the Department of Commerce (Department) was represented by Karen
Finstad Hammel and Valerie Smith, Assistant Attorneys General, and Analysts
Michelle St. Pierre, Sundra Bender, Jason Bonnett, Vince Chavez, Bryan Minder,
and Dr. Marlon Griffing. The testimony
from the Department representatives was consistent throughout the public
hearings. In essence, the Department’s
presentation at the public hearings was that it represents the interests of all
ratepayers in utility proceedings before the Commission. The Department noted that its review of costs
and revenue resulted in a proposed reduction of CenterPoint’s requested rate
increase to $27 million. The Department also noted its agreement with
CenterPoint’s proposal to raise the residential basic charge to $8.00.[18]
18.
The Energy CENTS
Coalition (Energy CENTS) was represented by Chris Duffrin. Energy CENTS is a statewide coalition of
organizations that promote more affordable energy service for low-income and
fixed-income Minnesotans through advocacy efforts, regulatory proceedings, and
policy and program development. The
agreement between CenterPoint and Energy CENTS on a $5 million energy
affordability program and the effect of that agreement on bad debt recovery was
described. Remaining concerns expressed
by Energy CENTS included the impact of the proposed residential basic charge
increase and the modified block rate increase.
Energy CENTS also questioned why customers should be paying for the
Midwest Gas replacement project before litigation concerning responsibility for
the line explosion had been resolved.[19]
19.
Commissioner Reha
was present for the evening videoconference and at the hearing in
20.
Michele H.
Kimball, State Director, and Hubert H. (Skip) Humphrey, III, State President of
the Minnesota chapter of the American Association of Retired Persons (AARP)
noted that CenterPoint’s proposed rate increases in both the basic charge and
the delivery charge would result in average monthly increases of $3 (for
Northern customers) and $5 (for Viking customers). These increases, ranging from 3.3% to 5.7%
for residential customers, were contrasted with the overall revenue increase of
2.4%. AARP urged the adoption of rates
that ensured residential customers paid only their fair share of any revenue
increase.
21.
AARP objected to
the increase in the residential basic charge from $6.50 to $8.00. Although AARP acknowledges that utilities
favor higher basic charges to stabilize their cash flow, AARP maintains that
high basic charges are “bad public policy.”
Lowry Johnson, President of the Sabathani AARP chapter, urged the
commission to keep the interests of residential customers in mind when deciding
on CenterPoint’s proposed rate increase.
Particularly for older Americans, AARP maintained that utility services
overall can account for as much as 23% of a household’s monthly income. The proposed residential basic charge
increase to $8.00 was opposed as merely favoring CenterPoint’s private
interest. [20]
22.
AARP also
objected to the change from a single delivery rate to the modified inverted
block rate approach proposed by CenterPoint.
This change will, AARP asserts, discourage conservation and penalize
low-income and low-usage customers. AARP
also objected to automatic adjustments for bad debt expenses. AARP suggested that CenterPoint offer debt
collection alternatives and increase enrollment in low-income energy assistance
programs to address the bad debt problem.
23.
Regarding the
overall economic burden imposed by energy costs, AARP recommended adoption of a
low-income energy assistance program that would limit the percentage of
household income that must be devoted to energy costs. An arrearage forgiveness component was also
recommended.
24.
Many members of
the public were concerned about the recent steep increases in their utility
bills. Although some of them
acknowledged that much of the increase was tied to the rise in the cost of
natural gas, the overall impact on customers has the effect of making it more
difficult to pay their gas bill. Low
income and fixed income customers, in particular, have trouble finding the
money to pay their utility bill and keep up with other rising costs such as
health care and local taxes. Charles Long of
25.
Elizabeth and
Joseph Bush of
26.
Doctor Christine
Ziebold, a physician specializing in children’s environmental health, expressed
concern that CenterPoint’s proposed rate structure provides disincentives for
switching to renewable energy. She described that rate structure as “globally
unsustainable and irresponsible business.”[22]
27.
Donald Hinrichs
of
28.
James Meiners of
Minneapolis, Minnesota, described the impact of CenterPoint’s proposed rate
structure would have on low-usage consumers of natural gas like him who use
less than 18 therms per month. For these
customers, the percentage increase is far higher than that indicated by
CenterPoint for the Residential customer class.
This was echoed by others, including Mae Singer and Mary Magnuson of
29.
Ms. Harlan, Jan
Steuve of
30.
Several members
of the public objected to CenterPoint’s contention that increased energy
efficiency and conservation had led to declining usage, which in turn would
require an increase in rates to meet CenterPoint’s fixed costs. One commenter questioned why the increase in
customers would not help to offset some of the decreased revenue from lower
customer usage. Others questioned why
additional conservation was not encouraged rather than discouraged through the
requested increase.
31.
Elaine Fleskes of
32.
One commenter,
Jim Million of
33.
Mike Banks, a
Councilmember from
34.
One commenter
disputed CenterPoint’s assertions regarding return on equity. One maintained
that CenterPoint should produce more revenue from its unregulated services.
35.
Some members of
the public simply objected to the increase because CenterPoint had received an
increase so recently, and CenterPoint’s reasons for the increase were
unsupported. One complained that
executive compensation was excessive and contributed to the rate increase.[23] Others complained about the difficulty
understanding either the bills that they received or the options that might be
available for paying the increased bills.
36.
Additional
comments addressed the extra burden that low-income customers bear when rates
are increased. Shada Buyobe-Hammond,
Chair of the Minnesota Association of Community Organizations for Reform Now
(ACORN), strongly objected to CenterPoint’s proposed rate increase. ACORN’s concerns included the effect of
additional increases on customers already on repayment plans, the distribution
of the burden between commercial and residential classes, and a perceived lack
of outreach to low-income communities.[24] Victor Smith, President of Men Against
Destruction, Defending Against Drugs and Social Disorder (MAD DADS), also
objected. MAD DADS maintained that high
gas costs contributed to a host of problems faced by low-income customers. Mr. Smith also suggested that the public
would get better notice of the rate hearings if notice was included in the
local community papers and through radio.[25]
37.
Several persons
objected to CenterPoint receiving a rate increase to cover increased bad
debt. In their view, this further
“punishes” customers who pay their bills, many of whom may sacrifice other
necessary goods and services to do so.[26] John Doll of
E. CenterPoint Capital Structure
38.
CenterPoint lacks a readily defined capital structure, due to its status
as a wholly-owned subsidiary. Under such
circumstances, Commission practice has been to substitute a hypothetical
capital structure that is then used to assess the proposed rates.[28] For the purposes of the 2004 Rate Matter, CenterPoint
proposed and the parties agreed to the following capital structure: [29]
2004 CenterPoint Capital Structure |
|
|
Long-Term
Debt |
46.17% |
|
Short-Term
Debt |
3.56% |
|
Common
Stock Equity |
50.27% |
The Commission
accepted the capital structure as part of the settlement in that matter.
39.
CenterPoint proposed that the following capital structure be used to
determine the revenue requirements in this proceeding: [30]
2006 CenterPoint Proposed Capital Structure |
|
|
Long-Term
Debt |
47.27% |
|
Short-Term
Debt |
2.60% |
|
Common
Stock Equity |
50.13% |
40.
CenterPoint calculated the proposed structure from the projected debt
and equity balances from the 2006 test year.
The result was very similar to the previously-approved 2004 capital
structure.[31]
41.
The Department initially proposed a capital structure differing
significantly from CenterPoint’s proposal for long-term and short-term debt,
and differing slightly in the relationship of debt to equity. These differences arose from the Department’s
methodology, which averaged CenterPoint’s actual financial results from 2003,
2004, and 2005.[32]
42.
With additional information obtained through this contested case
proceeding, the Department reassessed its position on CenterPoint’s capital
structure. The Department objected to
CenterPoint’s proposed capital structure as unsupported. CenterPoint’s updated figures for long-term
debt ($332,793,000) and common equity ($326,222,000) were added, with the total
equating to 87.78% of CenterPoint’s total capital structure. The Department divided the total by the
percentage and arrived at $750,539,000, described as the total value of
CenterPoint’s capital structure.
Subtracting the long-term debt and common equity figures from this total
value results in the average amount of short-term debt ($91,716,000) that CenterPoint
will incur in the test year. [33]
43.
With these calculations, the Department asserts that CenterPoint is
being operated with a capital structure significantly different from the
debt/equity ratio of 50/50 required by a recent Commission Order regarding
CenterPoint’s financial condition.[34] In that proceeding, CenterPoint undertook to:
1) maintain a capitalization structure in
Department Proposed Capital Structure for CenterPoint |
|
|
Long-Term
Debt |
44.31% |
|
Short-Term
Debt |
12.22% |
|
Common
Stock Equity |
43.47% |
44.
At the hearing, testimony tended to support the Department’s assertion
that CenterPoint’s business operations did not reflect a capital structure with
a 50/50 debt/equity ratio.[37] CenterPoint acknowledged that significant
short-term debt had been accumulated and that an infusion of capital was “being
considered.”[38]
45.
CenterPoint provided no contrary analysis to demonstrate that the
Department was incorrect in its calculations or conclusions regarding the
percentages appropriately assigned to equity, long-term debt, and short-term
debt. CenterPoint’s testimony on its
efforts to maintain 50/50 debt/equity ratio were not supported by documentation.[39] CenterPoint’s testimony regarding the levels
of short-term debt tended to support the Department’s position on this issue.[40] While CenterPoint maintained it has taken “a
number of steps [to maintain its debt/equity ratio],” this record lacks the factual
support needed to conclude that CenterPoint’s test year structure will reflect
the percentages proposed in CenterPoint’s rate petition.[41]
46.
The 50/50 debt-to-equity ratio required under the 2003 Reliant Energy Minnegasco
Inquiry Order was cited by CenterPoint as reason to approve its
proposed capital structure. The Department
disputed this contention, maintaining that the capital structure for setting
rates should reflect the realities of how CenterPoint has conducted the
financial aspects of its business.[42]
47.
The 2003 Reliant Energy Minnegasco Inquiry Order does not direct
CenterPoint to use a 50/50 debt-to-equity ratio in rate setting. Rather, that Order directs CenterPoint to
“maintain approximately a 50/50 debt equity ratio. . . . “ The Order is aimed at the actual financial
transactions engaged in by CenterPoint when operating its business, not a
hypothetical situation arising solely in ratemaking.
48.
The Department recognized that actions taken subsequent to the hearing
(or taken but not supported by evidence in the record) could support a
different capital structure and change CenterPoint’s revenue requirement by
approximately $3 million. To accommodate
that possibility, the Department proposed adopting CenterPoint’s proposed
capital structure of 47.27% long-term debt, 2.6% short-term debt, and 50.13%
common stock equity, subject to CenterPoint’s demonstration that its actions conform
to that structure.[43]
49.
CenterPoint agreed that the Department’s proposal provides a reasonable
means for the Commission to confirm that the hypothetical capital structure
approaches the 50/50 requirement of the 2003 Reliant Energy Minnegasco Inquiry Order. CenterPoint committed to providing a report
by March 1, 2007, addressing:
A.
Whether the Company did indeed convert over $100 million of short-term
debt to long-term debt.
B.
Whether this conversion, coupled with the seasonal forces discussed by CenterPoint,
have dramatically reduced the Company’s short-term debt.
C.
Whether CenterPoint discontinued paying dividends to its parent company.
D.
Whether CenterPoint made equity infusions in 2006, and in what amounts.
E.
What is the appropriate debt/equity ratio for CenterPoint in light of
the foregoing actions.[44]
50.
The Department’s proposed capital structure is supported by the record
in this matter. With the further showing
proposed by CenterPoint, CenterPoint’s alternative capital structure may be appropriate
for adoption. CenterPoint bears the
burden of demonstrating the appropriate capital structure to be used for
calculating CenterPoint’s revenue requirement.
Since CenterPoint has not shown on the record in this proceeding that it
has complied with the 50/50 debt/equity requirement of the 2003 Reliant Energy Minnegasco
Inquiry Order, the Administrative Law Judge recommends that the
Commission adopt the Department’s proposed capital structure for rate
setting. In the event the Commission
accepts CenterPoint’s capital structure, the Administrative Law Judge
recommends that the Commission require that CenterPoint file a report by March
1, 2007 report consistent with the Department’s recommendation and include in
the Commission’s order true-up language that expressly commits CenterPoint to
accepting the adjusted revenue requirement demonstrated by that report.
F. Return on Equity – Rate of Return
51.
The Commission’s statutory responsibility is to set rates that are just
and reasonable.[45] The determination of reasonableness involves
a balancing of consumer and utility interests.
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. Allowing a
fair and reasonable return upon the utility’s investment in property to provide
the utility service is a factor in setting just and reasonable rates.[46]
52.
A regulated utility’s return must be reasonably sufficient to assure
financial soundness and provide the utility adequate means to raise capital.[48] The investor requirement for a return
sufficient to cover operating expenses includes debt service, dividends on
stock, and continued assurance in the utility’s ability to maintain credit and
attract capital.[49] A just and reasonable return should be
similar to returns on investments in other businesses having corresponding
risk.[50]
53.
CenterPoint requested a return on equity (ROE) figure of 11.25%,
supported by the analysis of its witness,
Dr. Samuel Hadaway. In calculating the
proposed ROE, Dr. Hadaway utilized a Discounted Cash Flow (“DCF”) analysis. Dr. Hadaway described DCF analysis as being
“predicated on the concept . . . that a stock’s price represents the present
value of all future cash flows expected from the stock.”[51] DCF, simply speaking, estimates dividend
yield plus the stock’s growth rate, by assuming either long-term constant
growth or fluctuating (multi-stage) growth rates. In order to exercise informed judgment about
capital market costs and the expectations for long-range growth rates, Dr.
Hadaway initially used both the constant growth and multistage growth DCF
models in his analysis. The results of
these models were then compared to market-based risk premiums and projected
economic conditions.[52] Dr. Hadaway then rejected the results of the constant
growth DCF model, due to his perception that the resulting return was too low.[53] The multistage DCF analyses resulted in a reasonable
return on equity range of 10.0% to 10.6%.
With the use of long-term forecasted growth in gross domestic product (GDP)
in a constant growth model he arrived at return on equity from 10.4% to 11.0%. Dr. Hadaway blended the two results for a
final DCF range of 10.0% to 11.0%.
Adding a further risk premium assessment, Dr. Hadaway concluded that an
ROE of 11.25% reflects the cost of capital for an investment with the mix of risks
currently faced by CenterPoint.[54]
54.
To arrive at the 11.25% figure, Dr. Hadaway relied on ranges of ROEs
from two comparison groups. One group,
the S&P Gas Utilities group (“S&P Group”), was comprised of fifteen
companies. The S&P Group averaged a
2005 projected growth rate of 6.4% (down from 8.0% in 2001). The other group was a subset of the S&P Group,
comprised of utilities with 66% of revenue from regulated gas operations (66% Group). The 66% Group averaged a 2005 projected
growth rate of 4.6% (down from 7.5% in 2001).[55] To
arrive at the proposed ROE, Dr. Hadaway took the DCF projected results and
added an equity risk premium resulting in a ROE range of 10.75% to 11.25%. He concluded that 11.25% was the reasonable
cost of equity due to risks and uncertainty in the natural gas business.[56]
55.
Combining CenterPoint’s hypothetical capital structure with the ROE
derived from his analysis, Dr. Hadaway concluded that the overall cost of
capital was 8.51% for the test year 2006,
broken out as follows:
CenterPoint’s Cost of Capital Proposal
Component Percent
of Total Cost Rate Weighted ROR
Long-Term Debt 47.27% 5.78% 2.73%
Short-Term Debt 2.60% 5.20% 0.14%
Common Stock Equity 50.13% 11.25% 5.64%
Total Rate of Return (ROR) 8.51%[57]
56.
While agreeing with CenterPoint on the expected cost rate of long-term
and short-term debt, the Department disagreed with the proposed ROE. The Department initially recommended an ROE of
9.98%, (later updated to 9.71%). The
Department relied upon the analysis of
Dr. Marlon Griffing in support of its proposed ROE. Dr.
Griffing also used a DCF analysis in calculating the Department’s proposed ROE. For his DCF analysis, Dr. Griffing used a
single comparison group (“Comparison Group”) comprised of all natural gas local
distribution companies (“LDCs”) meeting certain standards that were listed in a
S&P database.[58] Dr. Griffing used the constant growth version
of the DCF analysis to calculate CenterPoint’s ROE.[59]
57.
Dr. Griffing’s Comparison Group was comprised
of those listed LDCs that were classified under the Standard Industrial
Classification (SIC) code 4924 (natural gas distribution). The LDC must also have publicly traded shares
and currently pay dividends. To be
included in the Comparison Group, the LDC must have a S&P bond rating
between AA- and BBB+. Dr. Griffing
excluded any LDC from the Comparison Group if the company was expected to merge
with another company or be acquired. [60]
58.
The Comparison Group screening criteria were
intended to limit the LDCs used for ROE analysis to those companies that are
similar to CenterPoint and whose equity valuations are not unduly influenced by
unusual market activity. Use of the bond
rating standard was intended to limit the Comparison Group to those LDCs with
similar investment risk to that of CenterPoint. [61]
59.
Eighteen LDCs were listed in SIC code
4924. Dr. Griffing added one LDC,
Keyspan Corp., to the list, since that company is similar to CenterPoint and
that company was included in both Dr. Hadaway’s S&P Group and 66%
Group. Three LDCs were removed since they
were not paying dividends. One LDC
lacked a debt rating. Another LDC,
Nicor, Inc., had a debt rating higher than the selected range. One LDC, Atmos Energy Corp., had a debt
rating below the selected range. To
further focus the Comparison Group on LDCs that are similar to CenterPoint, Dr.
Griffing excluded non-U.S. based companies and those without a minimum of 70%
net income/operating income from regulated LDC operations. These additional criteria excluded four LDCs
(Keyspan among them).[62]
60.
The Comparison Group as finally constituted
had nine LDCs, including Peoples Energy.
After his initial analysis, Dr. Griffing noted that Peoples Energy had agreed
to customer refunds totaling $100 million and to forgo collection of $200
million in bad debt. From this
information, Dr. Griffing concluded that Peoples Energy was not a comparable
utility to CenterPoint and excluded its financial information from the DCF
calculation.[63] Dr. Griffing kept Peoples Energy in the
Comparison Group for illustrative purposes only.[64] All of the Comparison Group LDCs were in the
S&P Group. Five LDCs in the
Comparison Group were in the 66% Group. [65]
61.
The average projected growth rate of the Comparison Group was 5.7%
(compared to 6.4% for the S&P Group and 4.6% for the 66% Group).[66] Using
the growth rate estimates and anticipated dividend yields for the Comparison
Group, Dr. Griffing established a range of ROEs. The range extended from a low of 9.28% to a
high of 10.14%. The numerical midpoint
of the range, 9.71%, was chosen as the ROE appropriate for CenterPoint.[67]
62.
CenterPoint asserted that the Department’s
approach in establishing a comparison group and the methodology used in
arriving at a proposed ROE understated CenterPoint’s business risks. Higher risk generally requires a higher ROE
to attract capital. CenterPoint asserted
that the higher basic charges and the presence of weather normalization in some
utilities’ rate designs are risk-abating factors that are not present in
CenterPoint’s situation. Thus,
CenterPoint maintains, its ROE should be at the high end of the ROE
calculations.[68]
63.
The Department objected to CenterPoint’s positions regarding higher
risk. Dr. Griffing noted that Dr.
Hadaway uses a risk premium DCF model that includes a subjective perception of
forward-looking risk.[69] Since the DCF model already includes investor
risk in the analysis, the Department maintains that adding a risk premium is “employing
double-counting” the effect of risk on ROE.[70] The Department also objected to CenterPoint’s
use of multiple DCF analyses as applying subjective judgment to result in the
highest possible ROE.[71]
64.
Dr. Griffing used the range of recent utility
ROE awards as a reasonableness check on the DCF modeling results. Using fifteen awards identified in Public
Utilities Fortnightly and a survey by Regulatory Research Associates, a range
of 9.5% to 10.5% resulted. Dr. Griffing
noted that both his initially proposed ROE (9.98%) and his updated ROE (9.71%)
fell in the range of awards, although at the lower end of that range. [72] He also noted that Dr. Hadaway’s most recent
information (from the third and fourth quarters of 2005), included six awards
ranging from 9.45% to 10.0%.[73]
65.
CenterPoint objected to the Department’s approach, maintaining that Dr.
Hadaway’s use of multiple tools was a “check on reasonableness,” that his use
of “informed judgment” results in a better forecast, and that his result is
more in keeping with ratemaking precedent.[74] The Department’s approach was criticized as
relying on a single formula, failing to apply checks of reasonableness, and
resulting in “an apparent ‘race to the bottom.’”[75]
66.
The Department identified five specific shortcomings with Dr. Hadaway’s
approach:
1) It uses an input, GDP growth rate, that is not a
reasonable measure of expected growth for natural gas LDCs and inflates his
outcomes. See DOC Ex. 80 at 43-44 (Griffing Direct); DOC Ex. 84 at 18-19
(Griffing Surrebuttal); and Department Initial
2) His risk-premium analysis relies on a number
that includes 120 unsubstantiated basis points. See DOC Ex. 80 at 50 (Griffing
Direct); and Department Initial
3) His rejection of his DCF constant-growth results
is based on his unreasonable risk-premium number. See CenterPoint Initial
4) No consideration is given to the viewpoint that
it is the risk-premium number that is too high rather than the DCF number that
is too low. See CPE Ex. 29 at 34-35 (Hadaway Direct)
5) He uses interest rates and general economic
trends as a reason for pushing his risk-premium result to the top of his
“Judgment of ROE Range,” thus incorporating these factors twice in his
analysis. See DOC Ex. 80 at 51-53 (Griffing Direct); DOC Ex. 84 at 18-20
(Griffing Surrebuttal); and Department Initial
67.
The Commission has recently addressed the issue of risk assessment in
ROE calculation. The Commission stated:
The Department did not ignore the four risks asserted by the Company,
but (as noted above) addressed each one, demonstrating in each instance that
the asserted factor was either nonimpacting or negligibly impacting and would
have been taken into account by Standard & Poor's in setting relevant bond
ratings. The Department and the ALJ also properly noted that in selecting to
emphasize only four of the multiple factors involved in risk assessment, the
Company has sought a one-sided and incomplete consideration of risk that would
effectively double count factors already taken into account.[77]
68.
The use of multiple forecasting tools, the selective rejection of
results, and the additional consideration of risk are all indicative of efforts
to substitute judgment for analysis.
CenterPoint’s finally proposed ROE, 11.25%, exceeds even the range of
results achieved by the weighted DCF analysis relied upon by CenterPoint’s
expert. Comparison of Dr. Griffing’s
results with the range of ROE actually awarded in other jurisdictions is strong
evidence that his results reflect an appropriate range of returns that are
sufficient to attract investment capital.
Applying the midpoint of the range for the actual ROE is a reasonable
means of assuring that the interests of shareholders and ratepayers are
balanced. The Department’s proposed ROE
of 9.71% is reasonable.
69.
Calculation of the allowable rate of return (ROR) is derived by
multiplying each capital structure component by the cost of that component,
then adding the results to arrive at the ROR for that particular utility. [78] The Department
and CenterPoint agreed that the cost of long-term debt was appropriately 5.78%
and the cost of short-term debt was appropriately 5.20%.[79] The Department proposed the following cost of
capital structure for establishing CenterPoint’s rates:
Department’s Cost of Capital Proposal
Component Percent
of Total Cost Rate Weighted ROR
Long-Term Debt 44.134% 5.78% 2.56%
Short-Term Debt 12.22% 5.20% 0.64%
Common Stock Equity 43.47% 9.71% 4.22%
Total Rate of Return (ROR) 7.42%[80]
70.
As discussed in foregoing findings, the capital structures proposed by
the Department and CenterPoint vary widely.
The most important differences are between the levels of common stock
equity and short-term debt in each calculation.
These differences account for most of the wide disparity between the two
parties’ ROR calculation. Applying the
Department’s proposed ROE to the hypothetical common stock equity level ordered
by the Commission (and subtracting the difference from the short-term debt
figure calculated by the Department) results in an ROR of approximately 7.7%. Applying the range of reasonableness check, 7.7%
would fall in the middle range of the actual awards identified by both
CenterPoint and the Department. This
outcome also conforms to the 8.03% ROR in the settlement of the 2004
CenterPoint Rate Matter.[81] Had CenterPoint operated in the manner envisioned
in the 2003 Reliant Energy Minnegasco Inquiry Order, the 7.7% ROR
would be appropriate.
71.
CenterPoint agreed to a compliance filing to demonstrate that it is
operating with a 50% equity/50% debt ratio.[82] If the Commission approves of this procedure,
the appropriate cost of capital calculation pending CenterPoint’s filing is as
follows:[83]
Department’s Alternative Cost of Capital Proposal
Component Percent
of Total Cost Rate Weighted ROR
Long-Term Debt 47.27% 5.78% 2.73%
Short-Term Debt 2.60% 5.20% 0.14%
Common Stock Equity 50.13% 9.71% 4.87%
Total Rate of Return (ROR) 7.74%[84]
72.
The revenue requirement for
CenterPoint in this rate matter should be adjusted to reflect the capital
structure ultimately chosen. The record
supports the cost rates advanced by the Department for calculating
CenterPoint’s ROR.
G. Existing Rate Structure
73.
Prior to approval of CenterPoint’s interim rate, the Company’s natural
gas rate structure consisted of the wholesale cost, basic charges, and a
delivery rate. The basic charge and
delivery rate constitute the delivery charge portion of the customer bill. The wholesale cost to CenterPoint for the
natural gas sold to customers is passed through in customer bills without
markup. Thus, the delivery charge must
account for CenterPoint’s costs of providing natural gas service and
CenterPoint’s return.[85]
74.
The basic charge is the amount paid monthly by any customer connected to
CenterPoint’s gas distribution system.
This charge is paid independent of gas usage. For residential customers in both the Northern
Service Area (Northern customers) and the Viking Service Area (Viking
customers), the charge is $6.50 per month.
This charge was increased from the previous level of $5.00 as the result
of the 2004 CenterPoint Rate Matter.
The $6.50 per month basic charge took effect on August 12, 2005. [86] For commercial classes of customers in both
Northern and Viking areas, the customer basic charge is accompanied by a basic
transportation service charge that varies depending on customer class and
service area.[87]
75.
The remaining portion of the customer bill is the delivery rate. This charge is calculated by multiplying the
therms in the natural gas purchased by an established rate.[88] For Northern customers, the current rate is
$0.11928. For Viking customers, that
rate is $0.09093.[89] Commercial classes pay a rate (with one
exception) ranging from $0.11654 to $0.03731.
The exception is for large general service customers which pay a demand
peak rate of $0.59926 (Northern) or $0.69326 (Viking). [90]
H. Test Year
76.
CenterPoint projected a test year for calculation of the proposed rates
in this matter. The Company began with
the actual financial information for the calendar-year base period ending
December 31, 2004. This information was
adjusted to eliminate out-of-period expenses from the calculation. A normal operating year adjustment was made
to address known changes in operating conditions for the regulated utility
portion of CenterPoint’s business. The
resulting information was corrected for inflation. The year ending on December 31, 2006 was used
as the projected test year. [91]
77.
Almost three-quarters of CenterPoint’s natural gas sales are identified
as “heat sensitive.” These are sales
that fluctuate based on the actual temperature of the local weather. Heat sensitive sales account for approximately
70 percent of total sales in the test year.[92] CenterPoint used a ten-year rolling average
to derive the temperatures to be applied in the test year. The 35-year period from 1970 through 2004
showed a statistically significant mean reduction in heating-degree days
(meaning the temperature was warmer), particularly over the last decade. CenterPoint attributed this statistically
significant reduction in heating-degree days to global climate change, which is
seen as causing a warmer climate in CenterPoint’s service area.[93]
78.
In addition to the reduction in heating-degree days, CenterPoint
maintained that new construction is increasingly multi-unit housing, thereby
increasing efficiency and reducing the heating needs of residential customers
in CenterPoint’s service area. Increases
in the overall cost of natural gas, prompting consumers to conserve energy, and
the widespread improvement in energy-efficient appliances and building
practices were cited as additional factors reducing the anticipated demand for
natural gas in the test year. [94]
79.
CenterPoint separately forecast the anticipated usage by Large Volume
Dual Fuel (LVDF) customers, assessing the particular needs of each customer in
making adjustments from prior usage patterns.
The Department inquired of the method used by CenterPoint to adjust its
forecast. CenterPoint provided
documentation of the reasons for each change.
Based on the information provided, the Department agreed with
CenterPoint’s LVDF forecast.[95]
80.
The use of ten-year rolling averages was criticized by the Department as
unreasonably sensitive to updates in the data.
The Department used twenty-year weather data.[96] OAG disputed CenterPoint’s position on
multi-unit housing construction.[97]
81.
CenterPoint forecasted that the total volume of natural gas delivered to
customers would amount to 157,653,000 Dkt in the test year.[98] This forecast was based on 795,075 customers,
with econometric modeling done for small service classes (residential and small
commercial) and individual customer forecast sales for large volume customers.[99] CenterPoint used eight years of customer data
and the 10-year rolling average for weather.[100]
82.
Using its regression analysis, the Department forecast the total volume
of natural gas sales to be 157,963,000 Dkt in the test year. CenterPoint
accepted the Department’s forecast for the purposes of this rate matter, while
not agreeing with the Department’s methodology.
Use of the Department’s forecast requires an increase in the cost of gas
of $1,469,040 and an increase in operating revenue of $1,717,070. These changes result in a net required
revenue reduction of $248,030. [101]
83.
The Commission questioned whether modeling normal weather on the basis
of ten years of data rather than twenty is reasonable. With the agreement to use the Department’s
twenty-year result, there is an insufficient record to reach a firm conclusion
on that issue. The similarity between
the two results does suggest that the ten-year model is reasonable.
I. Test Year Revenue, Expenses and Operating
Income
84.
CenterPoint calculated its test year expenses to be $1,685,811,000 and
that the forecast test year operating revenue is $1,656,434,000, resulting in
an operating income of $29,377,000. [102]
85.
CenterPoint calculated the commodity price of gas to be $9.588 per Dkt,
based on NYMEX market data, resulting in a test-year commodity cost of
$1,334,005,384.[103] The Department calculated the price to be
$8.515 per Dkt, based on a different forecast.[104] Energy CENTS arrived at a price of $8.98/Dkt,
using the Henry Hub price.[105]
86.
Further analysis
by the Department of the pricing information presented resulted in a proposed
cost of gas of $9.052/Dkt.[106] CenterPoint, the Department, and Energy CENTS
reached consensus that the commodity price of gas should be forecast at
$9.052/Dkt.[107] That cost is reasonable and should be
approved.
J. Revenue Requirements
87.
For the test year (using existing rates) CenterPoint calculated that its
operating income of $29,377,000 would result in an overall rate of return of
4.69%, CenterPoint maintains that 8.51% is the rate of return that is required
for just and reasonable rates. To
achieve that rate of return, CenterPoint calculated that revenue of $53,334,000
would be required, leaving a net shortfall of $23,967,000. CenterPoint calculated the gross revenue
conversion factor to be 1.7056.[108] The net shortfall, multiplied by the gross
revenue conversion factor, results in an overall claimed revenue deficiency of
$40,878,000. [109]
88.
CenterPoint maintains that four discrete factors have prompted this rate
request. Declining residential customer
use, together with reductions from the other small, firm-volume business
classes has led to reduced sales from the forecast levels. CenterPoint has experienced increased bad
debt expenses over its anticipated levels.
The increased capital costs, including replacement expenses for the
defective equipment installed for Midwest Gas, have increased CenterPoint’s
expenses over the forecast levels. The
higher forecast wholesale cost of natural gas in the test year increases the
costs CenterPoint incurs for working capital.
For these reasons, CenterPoint maintains that the revenue established
from the 2004 CenterPoint Rate Matter is now insufficient. [110]
K. Customer Cost of Service Study
89.
In preparation for this rate application, CenterPoint conducted a
customer cost of service study (CCOSS).
The CCOSS analyzed CenterPoint’s administrative and operating costs and
attempted to associate identifiable costs with the particular class of customer
triggering the cost. In this proceeding,
CenterPoint used the same model as in the 2004 CenterPoint Rate Matter. CenterPoint described the model as using cost
causation as the controlling element of the cost classification and cost
allocation process.[111] The CCOSS was updated from the prior rate
matter by changing the allocation mechanism to the rate base to assign
responsibility for income taxes.[112]
90.
This method is appropriate, CenterPoint asserts, because required income
is determined by applying an allowed rate of return to the rate base
number. Since income tax expense for
the test year is positive, CenterPoint maintains that the various classes of
service should also have a positive allocation.
To achieve this result, CenterPoint allocated income tax to the various
customer classes in the same percentage as that class is represented in
CenterPoint’s rate base. CenterPoint
maintains that subsidies for one class of service result in an inappropriate credit
and that this burdens all other classes with an income tax expense obligation.[113] Based on its CCOSS, CenterPoint concluded
that the monthly cost of serving the General Service (Residential and
Commercial) customers was $20.47.[114]
91.
The Department accepted CenterPoint’s CCOSS.[115] Energy CENTS objected to CenterPoint’s tax
allocation for the CCOSS. This
methodology, Energy CENTS maintains, is unsupported and results in a
residential cost of service that is contrary to the actual costs of serving
those customers.[116]
92.
Energy CENTS points out that actual taxes are paid on taxable income. Taxable income is determined by the pre-tax
income received by a company. It is not determined by “required income,” which
is a figure determined in a rate case. If the overall pre-tax income were
negative, it would result in a tax credit for the company. Energy CENTS maintains that the same logic
should apply when allocating tax expense across customer classes. If the taxable income would result in a tax
credit for a certain class, the credit should be reflected in the CCOSS. Energy CENTS continues to urge the Commission
to reject CenterPoint’s proposal to link income tax expense to the rate base.[117]
93.
Income tax is based on revenue, net of costs. CenterPoint does not operate as separate
businesses with regard to its different customer classes. By using its rate base as the measure for tax
allocation in the CCOSS, tax costs are distributed across each customer class
in a equitable fashion. Allocation of
income tax expenses based on the rate base is supported by CenterPoint’s analysis.
L. Initial Rate Proposal
94.
The Company initially proposed an overall rate increase of 2.4% over
test year gross revenues, resulting in an increase of $40,878,000. [118] This proposal includes an increase in rates
for the Residential Class of 3.3% in the Northern Area and 5.7% in the Viking
Area.[119] The residential rate design includes a
proposed increase in the monthly basic charge from $6.50 to $8.00. CenterPoint also proposed to change the
delivery rate from a flat charge of $0.09093 per therm to a modified inverted
block rate system. This approach imposes
a delivery charge of $0.21000 per therm on the first unit of therms (in this
instance, 18 therms), decreasing to $0.12000 per therm on the next unit of
therms (here 82 therms). The delivery
charge then rises to $0.12500 per therm on the third unit of therms (150
therms). Once the residential customer
reaches 250 therms of usage, the delivery rate returns to $0.21000 per therm. [120]
95.
CenterPoint also proposed increases to the rates for business classes of
customers. The largest proposed
increases are in the Viking Area for Commercial/Industrial Firm A (C/I A),
9.1%, and Commercial/Industrial Firm B (C/I B), 6.7%. In the combined assessment for both service
areas, the increases were 3.3% for C/I A, and 1.7% for C/I B. Smaller increases were proposed for the
remaining classes.[121]
M. Revenue Requirements Generally
96.
The methodology for setting rates generally relies
on dividing estimated future costs over estimated future sales. The result determines the actual rates to be
charged. Volumetric sales estimates are very
important in determining the appropriate rates to be set. Overestimating sales can result in a utility
failing to receive an appropriate return on investment. Underestimating sales can result in the recovery
of a higher rate of return than the return authorized by the Commission. Issues regarding sales forecasts by CenterPoint
and the Department for the 2005 test year differed and are discussed in other findings.
97.
In setting rates for a public utility, the Commission must determine the
total level of investment by the utility in its “utility property used and
useful in rendering service to the public.”[122] In utility rate cases, such investments are
referred to as the utility’s rate base.[123] CenterPoint’s initial filing maintained that
the test year rate base for the 12 month period ending December 31, 2006 amounted
to $626,844,000.[124] CenterPoint used the same methodology to
determine the rate base as that utilized in the 2004 Rate Matter. [125]
98.
The Department proposed several adjustments to CenterPoint’s rate
base. First, the Department recommended
that the proposed beginning of test year rate base figure (as projected in CenterPoint’s
November 2, 2005 filing in this matter) be adjusted to “recognize the actual
2005 ending plant balance excluding the $1,991,000 of inspection and clerical
expense …”[126] This adjustment was based on the Department’s
assessment that CenterPoint’s actual 2005 capital expenditures were
substantially less than CenterPoint’s original projection. CenterPoint acknowledged that its actual 2005
total capital expenditures fell $7.3 million short of the projected figure.
99.
CenterPoint maintained that this difference
was more than outweighed by the Company’s investment in its new billing system,
originally projected to have a cost of approximately $11.5 million projected
for 2005, but ultimately placed in service at a total cost of approximately
$14.4 million in January 2006.[127] The Department responded that the half year
convention for the $14.4 million be recognized in CenterPoint’s rate base.[128]
100.
The Department has not suggested that CenterPoint capture each of the
changes in investment that have occurred.
The Department’s approach has been to adjust to what is now known to be the
actual rate base beginning balance. To
this actual figure, the Department proposes to add the higher new billing
system total cost and the Midwest Project additions. The Department is proposing to remove the
cash remittance equipment and the related decrease in test year expenses. The Department maintains that its suggested
adjustments do not constitute an impractical and impossible task. The
Department maintains that ignoring CenterPoint’s overstatement of the test year
rate base would be unreasonable.[129]
101.
Forecasting necessarily carries a degree of uncertainty. Changes between anticipated costs and actual
costs are inevitable. Because the rates
being set are carried forward over a period of years, there is a need to ensure
that the starting point is as accurate as possible. Where known significant changes can be
identified, adjusting the starting point is appropriate. The Department’s suggested alterations more
accurately reflect CenterPoint’s rate base and should be adopted.
102.
On December 28, 2004, a natural gas fitting at
a business in
103.
The improper fittings had been installed in
1980 by a predecessor company, acquired by CenterPoint in 1993. Records of the installations indicated that a
large number of service lines, up to 33,000, could be affected by the improper
fittings.[131] In May 2005, the Minnesota Office of Pipeline
Safety (“MNOPS”) issued a Compliance Order to address the problem identified in
the Ramsey Incident. The MNOPS Order
required that CenterPoint replace or visually inspect all plastic service lines
installed prior to 1984 by North Central Public Service Company. CenterPoint was also obligated to maintain
detailed records of what was found and what remedial measures were taken.[132]
104.
Under the direction of the MNOPS Order,
CenterPoint initiated the Midwest Gas Replacement Project. The Midwest Gas Replacement Project inspected
over 30,000 service lines and replaced those lines where needed.
105.
CenterPoint included $39,536,861 as actual
2005 and projected 2006 tangible capital expenditures in its rate base arising
from the Midwest Gas Replacement Project.[133] SRA maintained that none of this amount was
appropriate for inclusion in the rate base as the acquisition was negligently
made.[134] SRA also maintained that a decision by the
Commission allowing recovery of the costs for the Midwest Gas Replacement
Project could prejudice CenterPoint’s effort to recover alleged overpayments
for the value of the property from the seller.[135]
OAG agreed that third-party recovery had
not yet been exhausted by CenterPoint and that prior Commission decisions had
tracked recoveries for inclusion in subsequent rate cases. [136]
106.
OAG maintained that none of the expenditures
regarding the Midwest Gas Replacement Project should be included in the rate
base at this time. CenterPoint’s
inability to describe the specifics of the Project is cited by OAG as
CenterPoint failing to meet its burden of proof that these costs are appropriate. OAG recommended that the Commission open
another docket to examine the costs of the Midwest Gas Replacement Project and
determine which costs should be borne by ratepayers.[137]
107.
The Department did not oppose inclusion of the
108.
CenterPoint maintained that its expenditures
were required by
Subd. 11. Pipeline safety programs. All
costs of a public utility that are necessary to comply with state pipeline
safety programs under sections 216D.01 to 216D.07, 299F.56 to 299F.64, or
299J.01 to 299J.17 must be recognized and included by the commission in the
determination of just and reasonable rates as if the costs were directly
incurred by the utility in furnishing utility service.[140]
109.
The effect of the statute on ratemaking was
assessed by the Minnesota Supreme Court, which stated:
The language of section 216B.16, subd. 11, is clear
and unambiguous and, therefore, not subject to judicial interpretation. . .
. The statute mandates that all costs
necessary to comply with state pipeline safety programs are to be treated as if
they were “directly incurred by the utility in providing service.”.[141]
110.
To the extent that CenterPoint’s costs are
“necessary” for compliance with the pipeline safety obligations, the costs are
recoverable through rates. CenterPoint
has commenced a third party action against MidAmerican Energy Company, the
successor to Midwest Gas.[142] Therefore, the Department recommended that
the Commission require the Company to report to the Commission all third party
recovery obtained, together with a proposal for returning any such recovery to
ratepayers. CenterPoint agreed with the
Department’s recommendation.[143]
111.
CenterPoint acknowledged the goals behind the Department’s
suggested approach to handling any third party recovery, stating:
Any dollars recovered through litigation or insurance would
be recorded as an offset to capital/rate base.
As proceeds reducing capital/rate base, if any, are collected, the
Company proposes to calculate the associated revenue requirement impact on base
rates annually. Interest on the revenue
requirement at the prime interest rate will also be computed annually. When the proceeds result in a capital
reduction of $10 million or once litigation is complete, whichever occurs
sooner, a refund will be made. At that
time, the Company would calculate the impact on base rates and would file a
timely request with the Commission to reduce its rates. Additionally, the Company would annually file
a report with the Commission on the account balance and the results of any
pending litigation or insurance claims.[144]
112.
The agreed-upon approach to tracking
recoveries is a reasonable method of refunding to customers the amounts
collected in a timely fashion, without unduly burdening CenterPoint, and
without causing confusion to customers by generating multiple adjustments to
their billings. The refund mechanism
ensures that the money recovered (if any) will be returned to customers. This proposal is reasonable, will prevent
“double recovery,” and is appropriate for approval by the Commission.
113.
CenterPoint has demonstrated that the costs of
the Midwest Gas Replacement Project were necessary to comply with a State pipeline safety
program. By statute, the costs must be
recognized and included in the Commission’s determination of just and
reasonable rates.[145]
114.
The Department also recommended adjustment to CenterPoint’s rate base to
deny capital treatment of roughly $2 million related to certain expenses
associated with the Midwest Project. CenterPoint
expensed these items in 2005, but requested permission to capitalize them for
ratemaking purposes, given the nature of the expenses. The Department objected to capitalizing these
expenses. The Department maintained that
such treatment would violate Generally Accepted Accounting Principles (“GAAP”). [146]
115.
CenterPoint maintained that the rate base treatment of those expenses
was appropriate, stating:
These costs were a
necessary part of the replacement program.
In most service line replacement projects we know what service line we
are going to replace and where that service line is. In this case, we had to do a significant
amount of work to define the population of service lines that had the potential
to have improperly installed fittings.
Once the potential population was identified, we then had to physically
examine the service line to determine if it was constructed of plastic or steel
and then whether it was composed of the particular type of plastic that was at
risk. All of these costs were necessary
just to determine which service line was to be replaced. They were critical to the implementation of
the replacement plan and should be capitalized as a cost of the replacement
plan.[147]
116.
The Department responded that these additional expenses cannot be
included in the rate base because they were incurred out of the test year
period.[148] CenterPoint has demonstrated that these are
known costs, incurred in a necessary remediation program. Affording these costs different treatment has
not been shown reasonable.
117.
As part of its transfer of billing operations
to
118.
The Department urged that the ALJ take
judicial notice of Docket No. G-008/AI-06-0560.
CenterPoint’s Petition in the cited docket identified equipment that was
no longer to be included in CenterPoint’s rate base.[150] The Department described the inclusion of
amounts for this equipment in CenterPoint’s rate base as a “discrepancy in the
amount the Company included in rate base for equipment that has been removed
from rate base in the test year.”[151] The
Company retired the equipment in January 2006 and, according to the Petition, transferred
it to its affiliate CenterPoint Energy Service Co. ("Service Company') in
March 2006. In January 2006, Service
Company began providing the cash remittance processing for CenterPoint Energy
and allocating costs based on the service.
119.
CenterPoint maintained that the Commission
already rejected the Department’s requested treatment by not explicitly
including this issue for the reopened hearing on the billing system in this
matter.[152] The Department maintained that including additional
amounts in rate base for CenterPoint’s billing system and the Midwest Project
is unreasonable if a known substantial change that reduces the rate base is not
accounted for. Failing to remove the cash
remittance equipment net plant amount of $274,403 would, in the Department’s
assessment, amount to the double counting of plant. The Department also recommended reducing the
income statement expenses by approximately $66,000 for the reduction in costs
related to the cash remittance being performed in
120.
CenterPoint
argues that cash remittance processing is no different than hundreds of other
issues in the rate case – during the course of the test year, some changes
positively impact the Company’s financial picture, and some changes negatively
impact the Company’s financial picture. Under
this view, it is inappropriate and unreasonable to isolate one issue that may
work to the Company’s financial detriment without considering issues (such as
continually rising interest rates or rising gasoline prices) which, if
considered, would increase the Company’s revenues. CenterPoint maintains that such a pursuit
would lead to continual “updating” and result in the inability to ever close
the record in a ratemaking proceeding.
121.
As discussed in a foregoing finding, where known significant changes can
be identified, adjustments to the underlying figures are appropriate. The Department’s proposed exclusion of the
cash remittance equipment is appropriate, particularly since CenterPoint controlled
the timing of the change.
122.
CenterPoint placed a new billing system (known
as the Customer Care and Service billing system or “CCS”) into service in January
2006. Designed to support many different
areas of the CenterPoint’s operations, CCS is integral to the customer service
function, including: management of meter reading schedules and data;
calculation of billing amounts and printing of invoices; posting of customer
payment files and payment programs; credit activities; customer requested work
orders; direct customer contact; and online (internet) customer service.[155]
123.
As part of the Commission’s May 2006 review of
CenterPoint’s service quality reports, the Commission noted that issues had
arisen regarding the implementation of CCS.
On May 17, 2006, the Commission ordered further record development on CenterPoint’s
investment in and implementation of CCS.[156] Due to the differing nature of the two
issues, prudence in investment is assessed here, and prudence in implementation
is addressed in subsequent Findings.
124.
In the additional proceedings conducted
pursuant to the Commission’s Order, no party challenged CenterPoint’s prudence
in investing in a new billing system.
CenterPoint demonstrated that a functioning billing system is critical
to the efficient provision of utility service.
The legacy system supplanted by CCS had been in use for 23 years, used
an old programming language, and relied on an obsolete file structure. The legacy system was difficult to maintain
and very difficult to change in response to CenterPoint’s needs. CenterPoint also experienced difficulty
obtaining useful management reporting from the legacy system. CenterPoint demonstrated that replacement of
the legacy system was prudent to address demonstrated limitations with that
system and ensure the ongoing reliability customer service and billing
functions.
125.
CenterPoint adjusted its gross plant balance
to reflect that CCS was not placed in service in 2005. The gross plant balance was again adjusted to
add in the full amount of the costs of that system. $14,374,000.[157] The Department agreed with the CenterPoint's
rate base treatment of CCS (as shown in response to DOC IR No. 145), so long as
the cash remittal equipment adjustment is made as well. Inclusion of CSS in the rate base as set out
by the Department is appropriate.
126.
Service line extensions are subject to a tariff that divides the
financial responsibility for installing that infrastructure. CenterPoint pays for the initial portion of
the installation and the customer receiving services is responsible for costs
over the set length identified in the tariff.
In response to an information request by the Department, CenterPoint
performed a quantitative analysis to measure the cost and load justifications
behind the extensions tariff. In a
sampling of CenterPoint’s application of that tariff for residential service,
CenterPoint identified six errors. To assure
that errors in applying the tariff do not impose a burden on other ratepayers,
CenterPoint proposed a downward revision of $89,807 to its rate base.[158] Two additional errors were identified in a
main line commercial project and a residential service line project. No adjustment was proposed for either of
these errors, since they both fall within the acceptable error rate of
CenterPoint’s sampling software.[159]
127.
The Department concluded that the quantitative analysis demonstrated
that CenterPoint’s extensions tariff was justified, both for load and
cost. The Department declined to endorse
CenterPoint’s proposed rates.[160] The Department agreed with CenterPoint’s
approach to sampling for determining errors in applying the extensions
tariff. The Department did not object to
CenterPoint’s position on not adjusting for the two errors that were within the
margin of error for the sampling software.
The Department recommended approval of the downward rate base adjustment
of $89,807.[161]
128.
As part of the settlement in the 2004 Rate Matter, CenterPoint agreed
to include an accounting of winter construction charges in its Annual
Jurisdictional Report to the Commission.
In this proceeding, CenterPoint proposed to discontinue that reporting. The Department opposed discontinuing that
reporting. The Department also proposed
that the Commission require CenterPoint to make a separate tariff filing. In this filing, CenterPoint would provide
specific cost types of main line and service line extensions that occur in
winter. The tariff filing would also
include cost types for customer-requested additional service lines, extension
alterations, and meter relocations.[162]
129.
CenterPoint proposed tariff changes as part of
this proceeding to reflect the rate modifications involved in this matter.[163] The Department agreed with CenterPoint’s
proposed changes, except for those changes needed to reflect rate design
modifications.[164] At the hearing, CenterPoint agreed with the
Department’s proposals regarding tariffs.[165]
130.
The agreed-to tariff changes are reasonable
and should be adopted. CenterPoint has
not demonstrated that discontinuing the winter construction reporting is
needed. The Department’s specific
proposals for additional tariff language and reporting are reasonable.[166]
131.
Part of the rate determination is establishing
an appropriate forecast of CenterPoint’s operating expenses for the test
year. The parties differed on the levels
of certain expenses, mostly based on the differences in methodology used to
calculate those expenses.
132.
CenterPoint identified rate case expenses that it would incur in this
matter, including consultant and outside legal fees, administrative costs, and
billings from the administrative law judge, the Department of Commerce and the
Public Utilities Commission. The
estimate for those expenses is $1,182,275. CenterPoint did not allocate any of these
expenses to its nonregulated business units. CenterPoint proposed that its expenses for
this rate matter be recovered over a two-year period. CenterPoint also seeks to include the
unrecovered costs from the 2004 Rate Matter, estimated at
$554,167, over a two-year period.[167]
133.
The Department asserted prior rate case
expenses are not recoverable. Regarding
the current matter, the Department asserts that the total amount should be reduced
to the previous rate case costs plus inflation, and that the allowable expenses
be amortized over a four-year period.
These adjustments result in a reduction of the test year expenses by $191,710.[168] the Department also maintains that a portion
of the rate case expense should be allocated to CenterPoint’s nonregulated
operations.
134.
CenterPoint withdrew its request for unrecovered costs from the 2004
Rate Matter.[169] While continuing to maintain that no
allocation to nonregulated business operations was required, CenterPoint
maintained that 4% would be an appropriate amount if such allocation were
deemed necessary, based on a weighted average of recent natural gas rate
matters.[170] The Department’s proposed adjustment to the 2004
Rate Matter level of expenses (plus inflation) was opposed as unsupported.
135.
The 2004 Rate Matter
was resolved by settlement. That outcome
reduced overall expenses for that proceeding.
Very few issues were agreed to in this proceeding. The rate case expenses can be reasonably
expected to be higher in this proceeding.
The higher amount is properly included as expenses. Those expenses must be allocated between
regulated and nonregulated operations, however.
Of all the other rate matters surveyed, the most similar is
136.
CenterPoint proposed a two-year amortization
period for the rate case expenses incurred in this proceeding. The two-year period was based on
CenterPoint’s estimate of when it will next be filing for a rate
adjustment. The Department recommended a
four-year amortization period, based on the average period between rate filings,
going back to 1977. The same average is
obtained using CenterPoint’s rate filings from 1993 onward.[173]
137.
Amortizing rate case expenses is appropriate
since they are expenses that will not be incurred in each year on a going-forward
basis. CenterPoint’s proposal for a two-year
amortization period is supported only by the opinion of its witnesses regarding
possible future rate filing. The record
in this matter contains several significant changes in CenterPoint’s financial
situation that prompted this rate matter.
Those significant changes are unlikely to be repeated in the near
term. Under these circumstances, the
Department’s average period between rate filings, four years, is the
appropriate figure for amortizing rate case expenses.
138.
CenterPoint operates Conservation Improvement Program/Demand Side
Management projects (CIP) as part of its efforts to improve customer
conservation. CIP is submitted
biennially to the Department for consideration and approval by the Commissioner
of Commerce. CenterPoint’s CIP for
2005-2006 was approved on November 30, 2004.[174] The Department recommended accepting the
approved CIP.[175]
139.
Costs to the CIP program are recovered by utilities through a
conservation cost recovery charge (“CCRC”).
The costs incurred in CIP projects, less the revenue obtained through the
CCRC, are netted out through the CIP tracker balance. In each rate case, CenterPoint “trues up” its
CIP tracker account balance. CenterPoint also proposed amortizing the
tracker account balance over a two-year period, to be consistent with
CenterPoint’s anticipated filing of its next rate matter.[176]
140.
The Department accepted the tracker balance and proposed test year
expenses, but initially objected to the restatement of the tracker balance,
whereby CenterPoint applied the finally approved adjustment to the CCRC over
the interim rate period. The Department
withdrew its objection after it acknowledged that CenterPoint’s restatement
results in a refund of $388,652 to ratepayers.[177]
141.
The Department continued to object to CenterPoint’s proposed recovery of
expenses by amortizing the tracker balance over two years. The Department maintained that a four-year
amortization period was the correct approach.[178]
142.
The Department also maintained that CIP expenses should be allocated
across customer classes by throughput. The
throughput method was adopted in five recent gas rate cases. The Department also recommended that all
143.
The simplest method for account recovery, offsetting
the CIP tracker account balance against any interim rate refund required in
this matter, is the appropriate means of truing up that balance. Any remaining balance should be amortized
over a four-year period, consistent with the rate case expense amortization
period. The benefits of conservation are
experienced across all rate classes.
Reflecting this benefit, CIP costs should be allocated among rate classes on
a volumetric basis.
144.
CenterPoint used interest synchronization in
its calculation of income taxes. The
Department recommends reflecting the income tax effects of the Department's
adjustments and using the interest synchronization method for income tax
purposes. With the adoption of the
Department's revenue requirement calculation, the tax expense amount is
increased by $344,000.[180]
145.
As discussed in foregoing findings,
CenterPoint calculated a gross revenue deficiency of $40.879 million. The Department calculated two alternative
gross revenue deficiencies: Alternative 1 (based on the 7.42% ROR) was a
deficiency of $21.575 million, and Alternative 2 (based on a 7.74% ROR) was a
deficiency of $24.934 million.[181]
Should the Commission accept the
recommended 7.42% ROR, CenterPoint’s appropriate gross revenue deficiency is
$21.575 million, further adjusted by the other changes to the rate base in this
matter.
146.
CenterPoint operates both regulated and nonregulated businesses. CenterPoint's operating costs must be allocated
between these businesses to ensure that rates are determined only by costs
incurred by regulated business operations.
By prior Commission Order, CenterPoint has incorporated allocation
methods into a Cost Allocation Manual (CAM) that governs the division of
expenses between regulated, nonregulated, and capital accounts.[182]
147.
CenterPoint calculated the test year general allocation factor used to
derive CenterPoint’s regulated business revenue requirement by adjusting the
2004 regulated/non-regulated general allocation ratio. The Department noted that the adjustment reflected
only some of the planned and projected changes in CenterPoint’s
148.
Based on its calculation, the Department recommended an adjustment of
$368,767 to the claimed corporate costs.
This amount is the difference between the generally allocated expenses
included in CenterPoint’s proposed revenue requirement and the amount that
would have been allocated to regulated operations using the factor calculated by
the Department.[184]
149.
In response, CenterPoint recalculated its general allocation factor and
arrived at revised general allocator of 72.52 percent versus the filed
calculation of 72.75 percent. By
CenterPoint’s calculation, using the new allocation factor reduces the test
year expense by $26,602 from the original submission.[185]
150.
CenterPoint and the Department agreed that the
initially proposed general allocation factor of 72.75 percent should be revised
to 72.52 percent.[186]
But the Department questioned additional
adjustments to determine projected 2006 operating expenses for CenterPoint’s consolidated
regulated/nonregulated operations. The
Department surmised that the projected 2006 operating expenses were already
reflected in CenterPoint’s response to Department IR 109(B) and used by the
Department in its calculation.[187]
151.
The Department conducted further analysis on
the additional information provided by CenterPoint to support the proposed
allocation of corporate costs. The
Department concluded that the information was insufficiently detailed to confirm
CenterPoint’s proposed allocation factor.[188] The record supports the test year general
allocation factor determined by the Department, and a resulting test year
adjustment of $368,767 as calculated by the Department.[189]
152.
The Department also demonstrated that
CenterPoint improperly allocated legal expenses between the regulated and
unregulated business operations of CenterPoint.
The Department’s analysis included adjustments to provide proper
allocation between those business operations.
An additional adjustment of $186,132 for improperly allocated legal
expenses has been demonstrated to be appropriate.[190]
153.
CenterPoint receives services from its parent corporation, CNP, which
are included in the expenses that form part of CenterPoint’s rate
calculation. CNP maintains a corporate
“general ledger” where the costs of certain centralized corporate activities
are recorded. These corporate costs are
then billed out to CNP’s various business units, including the Company, through
a detailed methodology that has been reviewed, discussed, and generally agreed
upon with regulators over the past many years.
Under this methodology, the first step is for each department to
directly bill the costs of providing its services to specific users wherever
possible (“direct billing”). When direct
billing is not practical, costs are assigned using cost-causation principles,
following the principles established by the National Association of Regulatory
Utility Commissioners (“NARUC”) “guidelines for cost allocations and affiliate
transactions.”[191] The primary areas to which costs are
allocated by CNP are Executive, Finance, Communications, Legal, and Human
Resources.[192]
154.
CNP’s methodology was reviewed and assessed by
a consulting firm. One part of the
corporate allocation work performed by CNP utilizes the Composite Ratio
Formula, developed at the specific request of staff of the Securities Exchange
Commission (“SEC”). SEC staff audited
CNP’s allocations in 2005 and proposed no changes to this formula. CenterPoint indicated that CNP’s corporate
allocations applicable to CenterPoint’s
155.
The Department objected to the increased level
of corporate cost assigned to CenterPoint by CNP. The Department analyzed the CNP cost
categories and the amounts allocated to each.
Increases in the amounts for certain categories and the addition of
items within categories were noted by the Department as needing justification.[195] These costs, the Department maintains, are
not supported as to amount or reasonableness.[196].
156.
CenterPoint objected to the Department’s
approach, stating:
There are several reasons
why this method is not appropriate.
First, this method does not take into account two years of
inflation. Second, this method does not
take into account expenses incurred in one cost center in 2004 and planned in
another cost center in 2006. For
example, Ms. Bender points out that ‘Pres and CEO’ allocable costs increased
dramatically from 2004 to 2006. However,
a significant portion of the increase is due to costs that were incurred in the
‘process improvement’ and ‘gas group president’ centers in 2004 but are
budgeted in the president and CEO cost center in 2006. The process improvement and gas group
president cost centers show a reduction of almost $1 million between 2004 and
2006. Another example is work that was
done at Minnesota Gas in 2004 and is planned at corporate in 2006. The internal audit function at Minnesota Gas
was transferred to corporate at the end of 2004. Some human resources activities were also
transferred to corporate. Those
transfers are reflected in a reduction to Minnesota Gas operating expenses in
the Complement adjustment.[197]
157.
As an
alternative, CenterPoint proposed that these costs be calculated by
establishing a baseline of demonstrated corporate costs from 2004, factoring in
inflation, and adding known and measurable changes to that figure. The resulting amount would be applied to
CenterPoint using the 2006 allocation factors.[198] The total allocation under this alternative
approach is $9.51 million.[199] The Department noted that this alternative
approach would not recognize reductions in costs that should have occurred when
the Texas Genco business unit was sold.[200]
158.
CenterPoint provided additional information
about the CNP allocations from 2004 and 2006.
But this information was not broken out into the same categories. The 2006 totals come from the five areas identified
above (Executive,
Finance, Communications, Legal, and Human Resources), while the 2004 totals are
broken out into those five and two additional areas (IT and Shared Services). There is no
information regarding how those costs are treated in the calculation.
159.
CenterPoint adopted a new accounting system on
January 1, 2004. The financial
information CenterPoint relies on in this rate matter was presented in the
format of the prior accounting system.
The Department noted that this transition has made classification of
particular costs difficult.[201] In addition, particular costs appear to be
unsupported in the workpapers developed by CenterPoint in making its cost
allocations. Upon analyzing the
spreadsheets used to support the allocations, the Department noted that the
costs were not identified in sufficient detail to verify the allocation. The Department also noted another significant
irregularity reflected in the transactions on the spreadsheets. [202] The Department proposed that the Commission
order CenterPoint to provide a base year reconciliation with the proposed
adjustments and test year information in CenterPoint’s next rate case. [203]
160.
CenterPoint described certain increases as
“known and measurable changes,” which include the transfer of various functions
and initiation of new corporate functions.
The total of these changes is an increase in costs of approximately
$740,000.[204]
161.
CenterPoint asserted that the Department’s
approach was merely a “pick and choose” approach to test year corporate
costs. CenterPoint maintained that
criticism of these expenses requires an examination of the 2006 proposed
corporate expenses to determine whether or not those expenses are reasonable, CenterPoint maintained that the Department was
merely comparing 2004 corporate expenses with 2006 corporate expenses in those
same categories, and selecting the lower number, regardless of year.[205]
162.
The Department responded that its approach was
to determine what costs, if any, could be established and shown to be
reasonable. The Department’s analysis of
CenterPoint’s information concluded that a cost was justified if any support
was provided for that cost. The 2004
costs were only used when the alternative was for the Department to recommend no
recovery of that cost.[206] The Department demonstrated that its
comparison of 2004 to 2006 was comprehensive.
The Department’s approach results in supported and reasonable costs
being included in the rate determination.
163.
The Department’s analysis supports a reduction
of $2,080,683 for corporate expenses.
164.
CenterPoint requested a test year pension
expense of $1.6 million before allocation between regulated and non-regulated
operations. The base year pension
expense was $6.1 million. This reduction
in test year pension expense primarily arose from a large contribution made to
the pension fund by CenterPoint at the end of 2004. Other factors in the expense reduction were
increased by expected earnings on pension fund assets and reduced amortization
of previously unrecognized losses.
CenterPoint relied upon an actuarial analysis using CenterPoint’s
participant demographics and actuarial assumptions used by CNP (which actually
administers CenterPoint’s pension fund), in arriving at its pension expense
figure.[207]
165.
The Department recommended that the pension benefit
expense be adjusted by levelizing the expense to the four-year average of
funding levels (over the period from 2001 to 2004). The Department maintained that CenterPoint’s
past levels of pension funding have not matched the level of expense built into
rates since 1994.[208]
166.
CenterPoint maintains that the Department is
engaged in impermissible single issue and retroactive ratemaking. Using the same levelizing approach with other
post employment benefits results in higher rates of recovery.[209] CenterPoint also claimed that the pension
period used for averaging deliberately excluded the 2005 pension expense, which
would increase the recoverable expense.
167.
The Department responded that the other
pension items were not sufficiently large to warrant attention. The averaging period used was the period for
which CenterPoint made information available.
The 2005 information was not provided in time for the Department to
analyze the data. CenterPoint itself
changed the pension benefit analysis by making a large voluntary contribution
to the pension fund at the end of 2004. The result was a large reduction in
test year pension expense compared to the 2004 base year amount. The actuarial
assumptions used for the test year may differ materially from actual results
due to CenterPoint’s contributions.[210]
168.
In a recent rate matter, the Commission
levelized the pension expense over five years and stated:
Levelizing is standard ratemaking treatment of
anomalies in test year expenses, and the possibility that the timing of the
Company’s next rate case may work to its disadvantage in regard to this one
test year expense does not justify abandoning normal test year procedures for
dollar-for-dollar recovery.[211]
169.
In this matter, the Department has shown that CenterPoint’s
recent pension expenses are anomalous and that an actuarial forecast is not
consistent with the past experience in pension funding. Under these circumstances, the levelizing
approach from the 2004 IPL Order is appropriate to determine the pension rate
expense. The Department’s approach
reduces CenterPoint’s test-year general and administrative expense by $220,797.[212]
170.
CenterPoint proposed calculating a test-year bad debt expense by taking
the actual 12-month period (ending June 30, 2005) bad debt expense as a
percentage of firm revenue for that period.
The resulting percentage, calculated to be 1.37%, was identified as the
bad debt factor to be applied to the test year firm revenue to derive the
appropriate bad debt expense figure.[213] CenterPoint noted that the actual bad debt
factor for the 12-month period ending December 31, 2005 had risen to 1.42%.[214]
171.
The Department recommended linking the bad debt expense to the rate case
revenue requirement, thereby decreasing the Customer Service and Information
expense by $1,027,822.[215] The Department concluded that a bad debt
factor of 1.37% was reasonable and actual bad debt expenses in the test year would
not be overstated using that figure.[216]
172.
CenterPoint and Energy CENTS entered into a
Stipulation addressing three issues: (1) an affordability program (discussed
with rate design issues below); (2) bad debt recovery; and (3) PGA recovery of
the gas cost portion of its bad debts (discussed in Findings below). As part of this Stipulation, CenterPoint
adjusted its bad debt factor to 1.27% and withdrew the PGA cost recovery
proposal.[217]
173.
The lower bad debt factor was derived from averaging the actual bad debt
percentages over the past two calendar years (2004 and 2005). The OAG expressed concern that the resulting
percentage did not adequately account for the ameliorative effect of the
Affordability Program and federal and state assistance programs. CenterPoint responded that the Affordability
Program expressly includes:
[A] financial evaluation
including, the total net savings including cost reductions on utility functions
such as the impact of the Program on write-offs, service disconnections and
reconnections and collection activities. . . .
[A]ny net benefit after the initial four-year term of the Program will
be added to the Tracker for refund to residential ratepayers.[218]
174.
The terms of the Affordability Program, including the financial
evaluation and tracker adjustment, address the concerns of the OAG regarding
potential over-recovery of bad debt costs.
The agreement to use a bad debt factor of 1.27% is supported by the record and is unlikely to result in the excessive
retention of funds in the bad debt reserve that a higher percentage could
generate. The terms of the Affordability
Program preclude any harm to residential ratepayers. Use of the 1.27% bad debt factor has
been shown to be appropriate.
175.
CenterPoint’s initial filing included a “fleet
adjustment” reflecting an increase in the per gallon cost of gasoline between
the base year and the test year. The
adjustment also reflects an increase in miles driven. No party challenged the increase in miles
driven.
176.
CenterPoint noted in its initial filing that
the average price per gallon of gasoline for the base year 2004 was $1.74 per gallon.[219] The increase in gasoline prices in 2005, to
over $3.00 per gallon at some locations, was also noted. CenterPoint projected gasoline to cost $2.56
per gallon over the test year, based on the average
177.
The Department objected to CenterPoint’s
use of the price of gasoline on one single day to determine the reasonable cost
of gasoline for the test year. The
Department noted that the January and February gasoline prices averaged 89
percent lower than the average for the entire year for 2002 through 2005 due to
seasonality of gasoline demand.[221] The Department maintained that seasonal
fluctuations and the historic January/February prices from 2002 through 2005
averaging 89 percent of the average price for the year required use of a lower
figure for the cost of gasoline. Based
on the EIA’s projected average of $2.42 per gallon for 2006, the Department
increased its recommended cost of gasoline from $2.21 to $2.46 per gallon.[222] Energy CENTS recommended using the 2005
weekly average price as the test year price.
178.
CenterPoint has demonstrated that the price
of gasoline for the test year is likely to exceed the forecasted levels when
using the Department’s methodology. Put
another way, the usual forecasting methodology results in an anomalous result. Under such limited circumstances, the use of a
benchmark high price within the forecast period is sufficient support for
determining the price in the test year.
Fleet expenses should be calculated using the $2.56
per gallon projected gasoline cost over the test year,
179.
CenterPoint has been self-insured for more
than 15 years for automobile and general insurance claims. This self-insurance covers up to $1 million on
general liability claims for 2004, 2005 and 2006.[223]
Other insurance is maintained by
CenterPoint for claims above that amount.[224] As part of its filing, CenterPoint included
expenses related to general liability and auto claims. CenterPoint used a three-year average of
actual claims activity attributable to regulated operations from January of
2002 through December of 2004 to determine this expense. The test-year
claims expense totals $728,347 ($79,589 for auto, $499,875 for litigation, and
$148,883 for general claims) before adding inflation of $9,147.[225] The three-year average was
used to “smooth out” the results, since the size of claims can vary
significantly from year to year.
180.
The Department recommended that the claims
expense be normalized or levelized over a four-year period, consistent with
other Department amortizations recommended in other rate case adjustments. A four-year period, the Department maintains, will
more fairly normalize these expenses for purposes of rates. Using the historical
claims expense for CenterPoint from 2001 through 2004 totals $2,345,279. [226] Dividing that amount by four years results in
an average of $586,320. Subtracting this average from the Company's proposed
$728,347 results in a decrease of $142,027. Accordingly, inflation would also be reduced
by $6,065 for a total adjustment of $148,092. [227]
The Department's recommendation
decreases general and administrative expenses by $148,092. [228]
181.
CenterPoint responded to the Department’s
suggestion by adding the actual expense numbers for 2005. The Department objected to using 2005 data for
the four-year analysis, maintaining that using that year would be inconsistent
with the Department’s approach on pension expenses, where data from 2001-2004
was used to calculate the Department’s position. [229]
182.
The
Department has not demonstrated any linkage between pension expenses and claims
expenses. The averaging is used to
ensure that the test year’s costs are not unduly influenced by peaks or valleys
in recent expenses. Absent the sort of
unusual situation posed by the pension situation, including the most recent
available data is appropriate for determining the average. The Department advocated for updating the
rate base to actual 2005 numbers and the reasoning for doing so applies equally
to the claims expense. CenterPoint’s
four-year average should be adopted for determining the test-year claims
expense.
183.
CenterPoint identified expenses of $1,047,794 for general and
informational advertisements.[230] The Department disputed whether the content
of four specific advertising promotions met the statutorily-established
categories authorizing inclusion in the rate base.[231] The identified programs were, in the
Department’s view, directed at promoting additional gas consumption, promoting
goodwill, and enhancing CenterPoint’s image.
These are not allowable advertising expenses under Minn. Stat. §
216B.16, subd. 8(a)(4), and the Department proposed reducing the claimed
expenses by $7,568 to reflect those disallowed expenses.[232] At the evidentiary hearing, CenterPoint
agreed to that adjustment.[233] The effect of the change is to decrease the
allowable advertising expense by $7,568 to $1,040,236.[234]
184.
As part of the 2004 CenterPoint Rate Matter, CenterPoint and the Department
agreed that $250,000 in research and development expenses for the Gas
Technology Institute (GTI) would be allowed.
GTI is a not-for-profit corporation located in
185.
CenterPoint has proposed $250,000 in GTI
research and development expenses in the test year for this proceeding.[238] The Department noted that there have been no
funded GTI projects since the Commission approval of the rates in the 2004 CenterPoint Rate Matter.[239] With the lack of projects actually funded,
the Department suggested that additional monitoring of the projects and their
associated costs would be appropriate. [240]
186.
In response, CenterPoint agreed that GTI
projects would be open for inspection and that accounting would be provided for
each funded GTI project. CenterPoint
also proposed to establish a separate liability account to which the expense
dollars would be applied.[241]
The Department agreed with the liability
account approach and recommended that its starting balance equal all revenues
collected from ratepayers for GTI project funding from the implementation of
interim rates in this ratemaking. The
Department also recommended annual compliance filings on the account, detailing
revenues and GTI expenses over the prior period.[242]
187.
The compliance filings would be used to
show what money had been applied each month at the level approved by the
Commission and show actual expenditures debited to the account at the time
payments are made.[243]
CenterPoint also agreed that the account
would be subject to true up at the time of its next rate case. Any unexpended balance would be returned to
customers. The Department recommended
that the Commission clarify the true-up provision to limit the changes to
refunding to customers, not increasing the account balance in the event
CenterPoint expends more than the $250,000 annual expense approved for GTI
research. The Department also requested
clarification that the cap of $250,000 applies separately to each year, and
that such expenditures are not netted across years in the true-up process.[244]
188.
The proposed $250,000 in GTI research and
development expenses in the test year are reasonable costs. Establishing a separate liability account for
these expenses is appropriate. The
account starting balance should equal all revenues collected from ratepayers
for GTI project funding from the implementation of interim rates in this
ratemaking. CenterPoint should submit
annual compliance filings on the account, detailing revenues and GTI expenses
over the prior period. The annual
expenses for research and development should not to be carried over from
year-to-year.
189.
The existing mechanism for bad debt recovery is to build into rates an
expense for uncollectible accounts.
CenterPoint identified the increased impact of bad debt costs as a
substantial financial cause of this rate proceeding. To address the problem, CenterPoint initially
proposed to recover the gas cost portion of its bad debt through the purchased
gas adjustment (PGA). This would
transfer responsibility for the portion of the bad debt expense that is
comprised of the cost of natural gas directly to customers. As an alternative, CenterPoint proposed
creation of a tracking account to determine the amounts that constitute the gas
portion of the bad debt expense and allow for future recovery of amounts not
covered by rates. [245]
190.
The Department objected to the proposed changes in bad debt cost
recovery. Specifically, the Department
cites Minn. Stat. § 216B.16, subd. 7, which states:
Notwithstanding any other provision of this
chapter, the commission may permit a public utility to file rate schedules
containing provisions for the automatic adjustment of charges for public
utility service in direct relation to changes in: (1) federally regulated
wholesale rates for energy delivered through interstate facilities; (2) direct
costs for natural gas delivered; or (3) costs for fuel used in generation of
electricity or the manufacture of gas.
191.
The charge proposed by CenterPoint for inclusion in the PGA is not the
“direct cost of gas” within the meaning of the statute. Rather, those charges are indirect, having
come from the customer’s failure to pay.
The appropriate mechanism for recovering bad debt expenses remains through
the rates charged to customers, determined through the test year methodology. This issue was addressed by CenterPoint in
its Stipulation with Energy CENTS, where the proposal to recover costs through
the PGA was withdrawn.[246] Regardless of the stipulation, inclusion of
the costs in the PGA would be inappropriate.
192.
In its initial rate proposal, CenterPoint proposed establishing an
affordability program to assist low income customers in meeting the
increasingly high cost of natural gas.[247] In the course of the contested case
proceeding, Energy Cents and CenterPoint arrived at an agreement regarding how the affordability program (“the
program”) would be established, funded, and administered. Because the details of that program were not
well established, additional testimony was prefiled and a further day of
hearing was held on June 28, 2006 to establish a record regarding the program.
193.
The program would have an annual budget of $5 million
and the costs would be charged solely to the residential class of
ratepayers. Eligibility for the program
is determined by actual receipt of benefits from the Low Income Home Energy
Assistance Project (LIHEAP). The program
included an affordability component and an arrearage forgiveness
component. The affordability component
consists of a credit on the customer’s bill that is one-twelfth the difference
between the customer’s estimated annual gas bill and 6% of the customer’s
household income.[248]
194.
The arrearage forgiveness component consists
of a credit to be applied each month after a customer’s payment is
received. The credit consists of an
amount added to the customer’s payment as a “co–pay” of a portion of the
outstanding arrearages. The customer’s
overall arrearage amount would be apportioned for repayment over a period not
to exceed 24 months. [249]
195.
Participating customers who miss two
consecutive payments may be terminated from the program. Customers who are terminated from the program
may be disconnected from gas service, unless the cold weather rule applies. Customers who maintain their payments will
not be disconnected, no matter how large their arrearages. Information concerning participation in the
program will be mailed to customers who are 90 days or more in arrears. [250]
196.
Under the stipulation, the total program cost
shall not exceed $5 million per year.
That figure includes administrative costs, and CenterPoint pledged to
make its best effort to contain those costs to less than 5% of the total
program costs. Those costs are to be recovered through the volumetric charge
applied solely to the residential class.
The parties agreed that a tracking mechanism would be established at the
initiation of the program to provide for the recovery of actual program costs. The program will have an initial four-year
term, and CenterPoint will report annually to the Commission on the status of
the program. [251]
197.
Included in the Stipulation were changes to CenterPoint’s proposed bad
debt recovery. As discussed in foregoing
Findings, CenterPoint’s bad debt expense for this rate matter would be
calculated by application of a 1.27% bad debt factor. As part of the Stipulation, CenterPoint also agreed
to withdraw its proposal to recover the cost of unrecoverable gas through the
purchased gas adjustment (PGA). [252]
198.
OAG expressed concern that the development and administration costs
could consume an excessive portion of the program’s budget. The potential for one-time development costs
of $300,000 and administration costs of $250,000 per year were cited as reasons
to disapprove the stipulation regarding the program. [253]
199.
The OAG objected to the use of tracking as the cost recovery mechanism
as being outside the statutory authority of the Commission. OAG also objected to limiting the cost
recovery to the Residential class of customers.[254] Deferred accounting was proposed as the means
to determine how the program’s costs should be allocated across customer
classes.[255]
200.
The program limits eligibility to customers who are recipients of LIHEAP
assistance. OAG objected to this
limitation as discriminatory towards customers who are LIHEAP-eligible, but do
not receive that assistance due to budget limitations.[256] Energy CENTS cited the Xcel Energy electric
affordability program as demonstrating that the limitation to existing LIHEAP
recipients is an approved, nondiscriminatory method of administering the
program. The statute setting out
standards for such a program expressly limits benefits to “low-income
customers” and states, “For the purposes of this subdivision,
"low-income" describes a customer who is receiving assistance from
the federal low-income home energy assistance program.”[257]
201.
OAG proposed that the Commission open a separate docket to establish a
state-wide affordability program, rather than approaching the subject in a
“piecemeal” manner.[258] The legislation authorizing the Xcel program
indicates that there is no compelling reason to delay instituting the
affordability program over CenterPoint’s large customer base in favor of a
comprehensive program at some future date.
N. Rate Design
Generally
202.
Setting reasonable rates requires attention to
their design. Once a utility’s revenue
requirement is determined by the Commission, how that requirement will be met
by increasing charges paid by customers must be established. Rate design is the application of revenue
requirements to customer classes.
203.
The issues to be addressed in rate design were
recently summarized in the
The Commission’s design of rates is a largely
quasi-legislative function. The application
of proportional distribution of the revenue requirement among customer classes
involves policy decisions that are guided by fundamental principles of rate
structure. The preference to eliminate cross-subsidization, for example, may be
balanced against drastic changes in the cost of natural gas to particular rate
classes. The Commission has used the following principles in its rate design
decisions:
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.
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.
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.
Rates should be
understandable and easy to administer.[259]
Residential Basic Charge
204.
As in the 2004 Rate Matter, CenterPoint has proposed an increase in the residential
basic charge. CenterPoint’s proposal would
increase that charge from $6.50 to $8.00 per month. CenterPoint relies on its customer cost of
service study (CCOSS) to support the increase.
The CCOSS was performed with three different approaches. One was an overall study of embedded
costs. The other two were specific to
each of CenterPoint’s two rate areas (Northern and Viking).[260]
205.
The overall cost of service to residential ratepayers was determined to
be $20.47 by the CCOSS.[261] CenterPoint maintained that with an $8.00 per
month customer charge, it would recover roughly the same percentage of fixed
costs from its residential customers as Xcel Energy currently recovers in its $8
per month customer charge for residential electricity service.[262] The proposed change, CenterPoint maintains, is
a continued slow movement toward the cost of service, which reduces intra-class
subsidies, while imposing only a gradual increase in the overall costs paid by
customers.
206.
The Department noted that the three studies submitted by CenterPoint
mostly followed the same approach as the CCOSS submitted in the 2004
Rate Matter, which was part of the settlement approved by the
Commission. The two differences noted
were the separate accounting for transportation customers and moving the
allocation of income tax to the rate base.
The Department did not dispute any part of CenterPoint’s CCOSS.[263] Energy CENTS disputed the tax allocation and
that issue was addressed in a prior finding.
207.
The Department’s assessment of proper rate
design is to gradually move the residential basic charge closer to actual costs
incurred to serve that class of customer over time.[264] The Department asserts that CenterPoint’s
proposed increase of the monthly basic charge from $6.50 to $8.00 reduces
interclass subsidies, reduces bill volatility between heating and nonheating
seasons, and conforms the percentage of fixed costs to that awarded in a recent
Xcel rate matter.[265]
208.
OAG and Energy CENTS noted that the Commission
explicitly refused to raise the residential basic charge to $8.00 just one year
ago.[266] Energy CENTS urged retention of the $6.50
customer charge. OAG included the impact
of the modified inverted block rate and asserted that CenterPoint’s proposal
amounted to a basic charge of $9.63.
This increase was opposed by OAG as excessive.[267]
209.
The Commission ruled on the issue of increasing CenterPoint’s
residential basic charge just over one year ago. At that time, CenterPoint was seeking an
increase from $5.00 to an agreed-to level of $8.00. That Commission analyzed the issue as
follows:
In short, the commission finds that the
advantages the $8.00 customer charge might offer in terms of economic
efficiency and revenue stability are more than offset by its adverse impact on
low-income households, its tendency to neutralize conservation incentives in
the minds of residential customers, and its potential to undermine customers’
confidence in the reasonableness of the rate structure.
*
* *
The last
time the company’s customer charge was adjusted was in its 1992 rate case;
since that time, the Consumer Price Index (CPI) has gone up by roughly 25%.
While the 60% increase proposed in the settlement significantly exceeds
inflation as measured by the CPI, the 30% increase represented by a $6.50
customer charge does not.
Since permitting inflation adjustments to
customer charges carries fewer risks than overhauling rate structures to rely
on them more heavily, since customer charges do perform the helpful function of
stabilizing utility revenue, and since the amount of money it issue – $1.50 per
month – is relatively small by almost any standard, the commission will permit
the company to institute a new residential customer charge of $6.50.[268]
210.
The effect of CenterPoint’s proposal is to
phase-in an $8.00 residential basic charge over two years (the first year being
the $6.50 basic charge approved by the Commission in 2005). Had the Commission thought such an approach
to be appropriate, such a phase-in could have been adopted in that proceeding.
211.
The Commission’s rationale for approving the
$1.50 increase in 2005 clearly ties the appropriate increase to overall
customer price increases. Since the
increase was approved in June 2005, customer prices (as measured by the CPI)
have increased by 4.3%.[269] Applying the Commission’s customer price
approach, an increase of $0.28 to the basic residential charge would be
appropriate. Anticipating the consistent
rise in consumer prices and applying a reasonable forecast of the period before
CenterPoint files for a new rate adjustment, an increase of $0.50 to the basic
residential charge is justified. Such an
increase moves the rate incrementally closer to the cost of providing the
service, conforms to the rate of increase in general consumer costs, and
constitutes an objectively small increase in the basic charge.
212.
Ensuring that the rate structure does not discourage conservation is
another consideration in the approval of a particular rate design. An argument made throughout this proceeding
is that increasing the residential basic charge acts as a disincentive to
conservation. OAG and Energy Cents
maintain that the proposed increase in the residential basic charge will discourage
conservation. Both parties cite the statutory
mandate that “to the maximum reasonable extent, the commission shall set rates
to encourage energy conservation.”[270]
213.
CenterPoint responded that the interpretation of the statute urged by
OAG and Energy CENTS would have prohibited all past Commission increases in
customer charges, including its recent decision in the Xcel rate case, and
taken to its extreme would require elimination of customer charges.[271] CenterPoint also noted that the entire
delivery charge is significantly smaller than the wholesale charge portion of
an average customer’s bill. [272] CenterPoint maintains that proper pricing signals
are the most important factor in customer decisions, including conservation,
and that increasing the residential basic customer charge is important to
accurate pricing.[273]
214.
Adjustments to rate design must consider the
impact on conservation. The Commission
has held that sufficiently large increases can affect customer conservation.[274] Increasing the residential basic charge by $0.50
will not have any impact on customer conservation efforts.
Basic Charge for Other Classes
215.
CenterPoint did not propose any changes to the
basic charge for any of the Commercial, Industrial, or Small Volume Dual Fuel
classes from amounts set by the Commission in the 2004 Rate Matter. The
Department agreed with CenterPoint’s position on these charges.[275]
216.
The basic charge for Large Volume Dual Fuel
customers was set at $330 per month in the 2004 Rate Matter.
CenterPoint proposes to raise that basic charge to $400 per month.[276] The Department expressed no objection to the
proposed increase.[277] The basic charge increase to the LVDF customer
class is reasonable.
Revenue Apportionment Between Classes
217.
A critical component of rate design is the
division between rate classes of the increase in revenue needed to address the
utility’s demonstrated revenue deficiency.
With an overall rate increase of approximately 2.4%, CenterPoint has
proposed the following increases, apportioned by rate class:[278]
|
Class |
Total Revenue
(including gas costs) |
Not Including Gas Costs |
|
Residential |
3.31% |
21.45% |
|
Comm.
& Ind. A |
3.32% |
17.05% |
|
Comm.
& Ind. B |
1.67% |
11.62% |
|
Comm.
& Ind. C |
1.65% |
14.13% |
|
Small
Vol. Dual Fuel A |
1.65% |
18.36% |
|
Small
Vol. Dual Fuel B |
1.65% |
21.16% |
|
Large
Vol. Dual Fuel |
0.10% |
2.38% |
|
Transportation |
0.67% |
0.67% |
218.
The Department maintained that this degree of
movement in rates, while essentially eliminating any interclass subsidies,
would result in rate shock for residential and some small business customers.[279]
Using CenterPoint’s CCOSS, the
Department determined that all the Commercial and Industrial classes should
experience the same rate increase to avoid rate shock for any individual class.[280] While this approach differs from the
Department’s position in the 2004 Rate
Matter, the change is based on the recent, unequal rate increases
experienced by the Commercial and Industrial classes in 2005. The Department does not recommend the same
approach for the Large Volume Dual Fuel class, since there is actual price
competition for customers in this class.[281] The Department’s proposed apportionment
results in increases for the various customer classes as follows:[282]
|
Class |
Total Revenue
(including gas costs) |
Not Including Gas Costs |
|
Residential |
2.69% |
17.39% |
|
Comm.
& Ind. A |
2.69% |
13.76% |
|
Comm.
& Ind. B |
2.69% |
18.63% |
|
Comm.
& Ind. C |
2.69% |
22.95% |
|
Small
Vol. Dual Fuel A |
2.69% |
29.87% |
|
Small
Vol. Dual Fuel B |
2.69% |
34.44% |
|
Large
Vol. Dual Fuel |
0.10% |
2.38% |
|
Transportation |
0.67% |
0.67% |
219.
The Department’s approach means that revenue
from the Residential and C/I A classes would cover 99.39% and 99.38% of those
classes’ cost of service, respectively.
By contrast, the other classes (excepting LVDF and Transportation) would
recover 100.99% to 101.02% of their classes’ costs.[283] The Department maintains that its approach
will have a less significant effect on customer rates, thereby reducing rate
shock, and better adhere to the Commission’s principles of rate design.
220.
Some variation between classes is
justified. The Commission could consider
the rate shock that would occur if all cross-subsidization were eliminated at
once. As noted by commentators,
residential customers cannot pass on price increases. That class of customers is already
experiencing the impact of increasing wholesale gas prices. The Department’s proposed revenue apportionment
is the best option, considering the Commission’s rate design principles. The only modification needed to the
Department’s proposal is to allocate the approved cost of the Affordability
Program solely to the residential class.
Since this cost will increase the impact of the rate increase on the
residential customer class, it is further support for the Department’s overall
approach to revenue allocation.
Service Area Consolidation
221.
In the 2004 Rate Matter settlement, CenterPoint and the Department
agreed that the proposed merger of the Viking and Northern service areas would
be limited to synchronizing the two areas’ basic service charges and
consolidating purchase gas adjustments (PGAs).[284] In this proceeding, CenterPoint has proposed
to merge the two service areas into one, applying the same rates to all
customers in their respective classes.[285]
222.
The Department agreed in principle to the merger, but noted that the
change in nongas rates results in an overall increase of 41% to Viking area
customers. The average Viking area
residential customer would experience a total annual bill increase of $25.00
from the merger.[286] The Department maintained that such increases
would necessarily result in rate shock to customers. The Department initially proposed phasing in
the merger through three adjustments conducted over a period of three
years. The first adjustment would be a
movement by one-third toward full consolidation. That adjustment would occur twelve months
after the Commission’s order in this matter.
The second and third adjustments would be in the same degree and on the
same time table, resulting in full consolidation in three years. The Department maintained that consolidation
on its timetable reduces rate shock and allows for planning to meet the
increase in costs. The Department
compared its approach to that taken by the Commission in a recent gas rate
matter.[287]
223.
CenterPoint responded by revising its proposal to a 50% adjustment to
Viking area customers to take effect with the rate change in this proceeding
and the remaining 50% adjustment to occur 12 months after the rate change takes
effect.[288] The Department adjusted its proposal to have
the merger adjustment occur in one step, 18 months after the rate increase
takes effect (or April 2008, whichever is later). The Department reasoned that the Viking area
merger increase should be timed to avoid the costs of the peak heating season.[289]
224.
CenterPoint’s proposal accomplishes the merger
in a reasonable period of time, but Viking-area residential customers would see
a big jump in rates over twelve months.
The Department’s proposal recognizes the significant price increase
arising from this matter and the likely additional increase that would occur if
CenterPoint were to file for a rate increase again in two years. Positioning the price adjustment to the
Viking area customers in between the two rate increases results in a lesser
degree of rate shock, due to phasing in the increase between the two rate
increases. The Department’s proposal to
implement the rate merger in one step after 18 months also provides a degree of
certainty regarding these increases to Viking area customers. It is a reasonable approach.
Block Rate Design
225.
As part of its proposed rate design, CenterPoint proposed a change to the
delivery rate from its current flat charge of $0.09093 per therm. The new rate follows a modified inverted
block rate approach. As proposed by
CenterPoint, the delivery charge would be $0.21000 per therm on the first unit
of therms, up to 18 therms. The next 82
therms would be provided at the lower charge of $0.12000 per therm. The next 150 therms would be provided at $0.12500
per therm. All usage over 250 therms
would be provided at a delivery rate of $0.21000 per therm.[290]
226.
CenterPoint maintained that the first block of
therms would cover “primarily non-heating usage or the minimum base use each
month during the year for this class.”[291] CenterPoint’s reasons for setting this level
of pricing for this block were “better assuring that low usage customers cover
the cost of service [and] . . . provid[ing] more certain recovery of a minimum level
of costs incurred by the Company.”[292]
227.
The Department opposed CenterPoint’s use of
the initial block rate as an inappropriate method of recovering fixed
costs. CenterPoint described its
approach as resulting in “stable monthly revenue of nearly $12 a month from
each customer . . . a meaningful increase in the recovery of ongoing, fixed
type costs through the rate design was obtained.”[293] The Department also noted that the declining
block rate discouraged conservation by providing lower rates until the 250
therm threshold was reached.[294]
228.
The Department advocated retaining the flat
rate approach per therm. In the
alternative, the Department proposed an inverted block rate design which
increases the price of gas as each threshold is reached to promote conservation. The first block would have the lowest price
per therm, covering the first 100 therms.
The price would increase for the second block of 150 therms. The third block would consist of all gas
purchased over 250 therms and this block would have the highest price per
therm. Assuming no changes to CenterPoint’s
requested revenue, the Department estimated that the block rates would be: $0.13428 (first block), $0.15604
(second block), and $0.21000 (third block).[295]
229.
The Department analyzed the percentage increase
of costs to an average residential customer over a typical twelve-month cycle
using CenterPoint’s proposed block rates.
In those months with low usage, staying in CenterPoint’s first block (18
therms), the customer experiences an increase of 6.3% over the present
rate. In the highest usage months, the
average user experiences an increase between 2.5 to 2.7%.[296] The comparison is also useful for estimating
the impact on low-volume consumers (using 18 therms or less in a month). The Department’s comparison of costs
indicates that such users will experience an increase of approximately 6.3%
under CenterPoint’s proposed block rate design.
230.
CenterPoint’s modified inverted block rate
proposal is explicitly designed to increase the minimum monthly cost paid by
residential customers. The Commission
has expressed its opinion on such costs, and their impact on customers. There is no reason to impose a more
complicated volumetric charge as a means of disguising what is, in effect, a
higher monthly basic charge. The
Department and OAG have shown that retaining the flat rate approach is more
consistent with principles of rate design, particularly with regard to reducing
customer confusion and minimizing rate shock.
Following those principles, the Administrative Law Judge recommends
retention of the flat rate volumetric charge for CenterPoint’s rate design.
231.
Should the Commission determine that an
inverted block rate would create greater incentives for conservation and that
those incentives outweigh other rate design considerations, the Department’s
inverted block system would better protect low volume customers from rate
shock.
LGS Rate Design
232.
As part of its proposed rate design, CenterPoint requested a change in the
Demand and Commodity rates for the LGS customer class.[297] The change was described as revenue neutral.[298] CenterPoint maintains that the current
commodity component for rates in this class unduly limits the flexibility needed
for negotiation to obtain customers for this class. There are currently no customers receiving
service under this rate.
233.
The Department questioned whether the LGS changes would create an
incentive for a current customer (particularly at the LVDF rate) to change to
the LGS rate at a lower cost, resulting in less revenue to CenterPoint. This situation could result in a subsidy to
the LGS class.[299] CenterPoint adjusted its proposed change to have
the LGS commodity rate mirror the LVDF class delivery charge. The result was to minimize the difference in
price between the LGS and LVDF classes.[300] The Department agreed that CenterPoint’s
modified approach addressed the potential for a revenue deficiency and
recommended that the LGS rate design be approved as finally proposed.[301]
O. Customer Billing System Implementation
234.
Beginning in Summer 2005, CenterPoint began
notifying customers through its bill inserts and website that a new billing
system was planned.[302] The CCS system was originally scheduled for
launch in September 2005, but was delayed to January 2006. [303]
235.
CenterPoint’s 2005 performance goals for call
center contact included answering 75% of telephone calls within 30 seconds,
answering calls at an average speed ranging from 22 to 28 seconds, and having
an abandoned call percentage that does not exceed the range of 5 to 8%. In 2005, CenterPoint answered 78% of the
calls within 30 seconds, at an average speed of 23 seconds, and with 7.9% of
the calls abandoned. [304]
236.
CenterPoint expected an initial decline in
customer service performance following implementation, due to increased call
volume and longer call handling time. For those reasons, CenterPoint asserted that
preparations for the new system conversion included staffing CenterPoint’s call
center with customer service representatives (“CSRs”) at a higher than normal
level entering Fall 2005.[305]
237.
CenterPoint introduced its CCS in January 2006. At that time, the address for customer
payments changed from
238.
The OAG disputed CenterPoint’s claims
regarding adequate staffing, noting that CenterPoint’s available CSRs declined
by 16 from the period the system was expected to enter service compared to when
the CCS was actually initiated.[307] Further, the OAG notes that CenterPoint
planned for insufficient trunk line capacity, resulting in customers receiving busy
signals. Many of those calls were
abandoned by customers before a CSR was available to respond to the customer
inquiry.
239.
Complaints were received and the Commission’s
Consumer Affairs staff discussed the situation with CenterPoint on February 16,
2006. [308] CenterPoint began providing weekly status
reporting to the Commission on call center volumes and CSR response time. The volume of calls was significantly above
the normal level of customer inquiry.
The average answering speed was just under four minutes for the week of
January 23, 2006. Abandoned calls
accounted for 20.6% of calls received.
Only 17% of the calls were answered within 30 seconds.[309]
240.
Over the following weeks, call center volume
declined, additional telephone trunk lines were added (increasing capacity by
15%), and CSR familiarity with the new system increased. CenterPoint noted that the primary areas for
customer questions were billing inquiries (about the format, no previous
balance, did not receive bill), budget billing questions, payment issues (not
showing payment that was made, issues with automatic withdrawal), and high gas
bill questions.[310]
241.
As CenterPoint completed its addition of
trained staff and additional telephone capacity, call center volume increased
to over 3,000 calls per day, with the average answering time falling from 117
seconds in the week ending March 3 to 80 seconds in the following week. Abandoned calls fell to 14.5%. CenterPoint noted that many of the customer
inquiries were being handled through the website customer service application
or through interactive voice response (IVR, another automated system using
structured questions and simple answers to access information). [311]
242.
The March 2006 call volume, average speed of
answer, and abandoned call percentage remained constant. The most significant improvement came with
the week ending March 10, which had 37% of calls answered within seconds, but
that figure fell to 27% the following week, partly caused by inclement weather.[312] The April call volume declined to
consistently below 3,000 calls per day, but the average answering speed
remained at just under one minute. At no
point did CenterPoint answer half of the calls within 30 seconds (compared with
the 2005 goal of 75%).[313]
243.
CenterPoint responded to the staffing issue,
indicating that each CSR requires, on average, 400 hours of training. This training includes 276 functionality sets
and 1,296 scenarios, covering all types of customer service inquiries.[314] CenterPoint maintains that this investment in
time, and the burden on available training resources, prevented any additional
CSRs from being available to handle the volume of calls.
244.
CenterPoint considered a multi-tiered system,
where customer calls are triaged for appropriate handling. CenterPoint described the intake layer as
“untrained employees.”[315] This approach was considered to be “not a
viable strategy because it creates a cycle of repeat customer call backs and
excessive backlog.” [316] CenterPoint has not indicated how an unanswered
call is superior to a system that actually answers customer calls, but may
require a referral or a returned call.
245.
CenterPoint was fully aware that an unusual
event directly affecting customers would occur and when that event would occur. CenterPoint was also aware that more
customers would be calling for assistance and that staff was needed to
respond. CenterPoint was also aware that
customers would have specific questions regarding the new billing system that
could be answered by staff who were not fully-trained CSRs.
246.
Adhering to full training schedules for CSRs
to address a short-term information problem does not constitute reasonably
prudent implementation of CenterPoint’s billing system. Failing to emphasize that the change in the
billing address would add additional days to delivery was not reasonably prudent
implementation of the new billing system.
247.
CenterPoint responded to the customer billing
problems arising from the billing changes by reversing late fees for those
customers who payment was received up to five days after the due date. These reversed charges amounted to $224,231, between
February 2006 to May 2006. This amount
is in addition to the late fees that were reversed when customers got through
to CSRs and complained about the late fee.
CenterPoint’s calculation of the total late fees reversed arising from
customer service problems and the implementation of the billing system is
$300,378.[317] CenterPoint does not have any means of
identifying customers who attempted to contact a CSR and were sufficiently
frustrated to abandon further efforts.[318]
248.
The Department maintained that CenterPoint’s
reversal of late fees was insufficient and proposed that all late fees from
February through June, 2006 be reversed.[319]
249.
With the combined impact of a changed billing
address and insufficient customer service response capacity, reversing late
fees is an appropriate response.
CenterPoint’s reversal of late fees for customers who were able to
contact a CSR is appropriate, but the five-day grace period is insufficient to
address the problem created by CenterPoint’s implementation problems. Customers have a reasonable expectation of
being able to contact a utility before paying a bill that the customer does not
understand. Since CenterPoint cannot
identify individual customers who became discouraged, reversing late fees for
payments received up to 30 days late over the period of February 2006 through June
2006 would more effectively address the problem. The continued high volume of customer calls
strongly suggests that customers are still raising questions about their bills. The 30-day period is more likely to reach the
customers who had questions about CenterPoint’s billing that were not answered
promptly.
O. Concepts to Govern
250.
The parties to this proceeding have taken
significantly different approaches to how the revenues and expenses of CenterPoint
should be calculated to arrive at just and reasonable rates. In a number of areas, the underlying cost
numbers are not readily apparent from the record, resulting in an inability to
set out detailed calculation of the precise numbers recommended by the Administrative
Law Judge. The concepts 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 concepts expressed should be adjusted to conform to the concepts expressed
in the body of this Report
Based on the foregoing Findings, the
Administrative Law judge makes the following:
1.
The Minnesota Public Utilities Commission and the Administrative Law
Judge have jurisdiction over the subject matter of this proceeding pursuant to
Minn. Stat. Ch. 216B and section 14.50.
2.
Any of the foregoing Findings which contain material which should be
treated as a Conclusion is hereby adopted as a Conclusion.
3.
CenterPoint has not demonstrated that its proposed capital structure
reflects the actual financial transactions of the business. The Department’s
proposed capital structure of 44.31% long-term debt, 12.22% short-term debt,
and 43.47% common stock equity. Should
the Commission conclude that CenterPoint should be given the opportunity to
provide further evidence regarding its capital structure, CenterPoint should be
required to file a report by March 1, 2007 report consistent with the
Department’s recommendation and be ordered to true-up its adjusted revenue
requirement as demonstrated by that report.
4.
CenterPoint has not demonstrated that its proposed return on equity
(ROE) strikes an appropriate balance between the interests of shareholders and
ratepayers. The Department has
demonstrated that its proposed ROE, 9.71%, does strike that balance and should
be adopted in this matter.
5.
With adoption of the Department’s proposed capital structure, the
allowable rate of return (ROR) is 7.42%.
Should the Commission adopt CenterPoint’s proposed capital structure,
the ROR is 7.7%.
6.
Use of the year ending on December 31, 2006 as the projected test year
for determining CenterPoint’s revenue requirement is reasonable. The Department forecast of the total volume
of CenterPoint’s natural gas sales, using a twenty-year methodology, as
157,963,000 Dkt in the test year is reasonable.
There is insufficient evidence in the record to address whether the
10-year average forecast methodology is superior to the 20-year average methodology. Use of the Department’s forecast requires an
increase in the cost of gas of $1,469,040 and an increase in operating revenue
of $1,717,070. These changes result in a
net required revenue reduction of $248,030.
7.
CenterPoint has demonstrated that it incurred the expenses for the
Midwest Gas Replacement Project pursuant to a natural gas safety program within
the meaning of Minn. Stat. § 216B.16, subd. 11.
Under that statute, CenterPoint is entitled to recover the costs of the
Project.
8.
CenterPoint proposed that its projected test year rate base for the 12
month period ending December 31, 2006 be set at $626,844,000. CenterPoint's forecast is appropriately
adjusted for the actual 2005 ending plant balance. CenterPoint properly included $39,536,861 as
actual 2005 and projected 2006 tangible capital expenditures for the Midwest
Gas Replacement Project and $1,991,000 for capitalized inspection and clerical
expenses arising from that Project. CenterPoint’s
test year net plant is appropriately reduced for the retirement of cash
remittal equipment by $274,403 (and the
income statement expenses should be reduced by approximately $66,000 for the
change in processing from
9.
The tariff changes agreed to by the parties
are reasonable and should be adopted.
CenterPoint should be required to continue reporting its winter
construction and follow the Department’s specific proposals for additional
tariff language and reporting.
10.
CenterPoint withdrew its request for unrecovered costs for rate case
expenses from the 2004 Rate Matter, estimated at $554,167. CenterPoint’s request for $1,182,275 for rate
case expenses in this matter is appropriate, reduced by CenterPoint’s general
allocator for nonregulated business operations, and the resulting total
amortized over a four-year period.
11.
CenterPoint’s CIP tracker proposal should be
approved, offsetting the CIP tracker account balance against any interim rate
refund required in this matter. Any
remaining balance should be amortized over a four-year period. CIP costs should be allocated among rate classes on
a volumetric basis.
12.
The Department’s recommendation to use the
interest synchronization method for income tax purposes is appropriate and
thereby increases CenterPoint’s tax expense by $344,000.
13.
CenterPoint’s proposed corporate expenses should be reduced by the test year general allocation factor determined
by the Department, resulting in an adjustment of $368,767 to those expenses. An additional adjustment of $186,132 for
improperly allocated legal expenses is appropriate. CenterPoint did not meet its burden to
demonstrate the reasonableness of its claimed expenses allocated from its
parent corporation, CNP. The claimed
amount should be reduced by $2,080,683 in accordance with the Department’s
analysis of those corporate expenses.
14.
CenterPoint’s test-year general and
administrative expense should be reduced by $220,797 to adjust the pension
expense using the levelizing methodology proposed by the Department.
15.
CenterPoint and Energy CENTS have demonstrated that calculation of the
test-year bad debt expense as 1.27% of the test year firm revenue is
reasonable. The proposal (now withdrawn)
to recover the gas cost portion of the bad debt expense through the PGA is
contrary to law and could not have been approved.
16.
CenterPoint’s “fleet adjustment” to reflect an
increase in miles driven and the increase in the per-gallon cost of gasoline
between the base year and the test year is appropriate and should be included
in the test year expenses.
17.
The Department’s proposal to use a four-year
average of actual claims activity attributable to regulated operations to
determine the allowable claims expense is appropriate. CenterPoint’s proposal to use the actual
claims activity through December 2005 is reasonable and the claims expense
average should be calculated using that data.
18.
CenterPoint’s claimed expenses of $1,047,794 for general and
informational advertisements were disputed by the Department as not meeting the
statutory requirements for allowable expenses.
The parties agreed that the claimed expenses should be reduced by $7,568
to account for the disputed expenses. At
the evidentiary hearing, CenterPoint agreed to that adjustment.[320] The effect of the change is to decrease the
allowable advertising expense by $7,568 to $1,040,236.
19.
CenterPoint’s proposed $250,000 expenses for
GTI research and development, agreed to by the parties are reasonable costs for
inclusion in the test year. The
Commission should direct CenterPoint to establish a separate liability account
for these expenses, with a starting balance equal to all revenues collected
from ratepayers for GTI project funding from the implementation of interim
rates in this ratemaking. Annual
expenses for research and development should not to be carried over from
year-to-year. The Commission should
require CenterPoint to submit annual compliance filings on this account,
detailing revenues and GTI expenses over the prior period.
20.
The Affordability Program, as agreed to between CenterPoint and Energy
CENTS, with an annual budget of $5 million charged solely to the residential
class of ratepayers is reasonable. There
is no impropriety in determining eligibility for the program by requiring
actual receipt of LIHEAP benefits. The
division of the assistance into an affordability component and an arrearage
forgiveness component is reasonable.
21.
CenterPoint and the Department have not demonstrated that an increase in
the residential basic charge to $8.00 per month is an appropriate adjustment to
balance the need to recoup the costs of serving the residential class of
customers with the need to encourage conservation, avoid rate shock, and
account for other factors between rate classes.
22.
There is sufficient evidence in the record to support an increase in the
residential basic customer charge from $6.50 per month to $7.00 per month,
while avoiding rate shock and meeting the Commission’s obligation to encourage
energy conservation.
23.
CenterPoint has not demonstrated that a modified inverted block rate is
appropriate for the residential customer class.
The Department has not demonstrated that implementing an inverted block
rate is needed to encourage conservation in the residential customer class.
24.
CenterPoint has not demonstrated that its
proposed allocation of the rate increase across customer classes is
sufficiently sensitive to the principle of rate shock. With the recent rate impact of the 2004 CenterPoint Rate Matter,
CenterPoint’s proposed allocation overemphasizes the need to eliminate cross-subsidization
between customer classes. Since the
residential class of customers cannot pass on price increases and that class of
customers is already experiencing the impact of increasing wholesales gas
prices, apportioning a higher percentage of the rate increase in this matter to
the residential class is unreasonable. The
Department’s proposed revenue apportionment, 2.69% across all customer classes
that are not experiencing competition, strikes the best balance between the
various rate design principles of the Commission. The Department’s proposal must be modified to
allocate the approved cost of the Affordability Program solely to the
residential class.
25.
The merger adjustment between the Northern area and Viking area should
occur in one step, 18 months after the rate increase in this matter takes
effect (or April 2008, whichever is later).
26.
CenterPoint has demonstrated that its
investment in a new billing system was prudent.
CenterPoint has not demonstrated that its implementation of the new
billing system and related calling issues was prudent. The Commission should order that CenterPoint reverse its late fees for customer payments
received up to 30 days late over the period of February 2006 through June 2006
to address the shortcomings in the implementation of those systems.
27.
Modifying CenterPoint’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 within the meaning of Minn. Stat. § 216B.11.
28.
The rate finally ordered by the Commission should be compared to the
interim rate set in the Commission’s December 21, 2005 Order, 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.
Based on the foregoing Findings and Conclusions above, IT IS
RECOMMENDED that the Public Utilities Commission issue the following:
1.
CenterPoint 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, the CenterPoint 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. CenterPoint 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, CenterPoint 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.
Dated this 8th day of September,
2006.
__/s/ Beverly Jones
Heydinger______
BEVERLY JONES HEYDINGER
Administrative Law Judge
Reported: Shaddix and Associates
Transcripts Prepared
[1] In the Matter of the Application of CenterPoint Energy Minnesota Gas, a Division of CenterPoint Energy Resources Corp. for Authority to Increase Natural Gas Rates in Minnesota, PUC Docket No. G-008/GR-05-1380, at 4-5 (Notice and Order for Hearing issued December 21, 2005) (generally “2005 CenterPoint Rate Matter “).
[2] 2005 CenterPoint Rate Matter, (Order Referring Prudence Issues Regarding Billing System Investment and Implementation to Administrative Law Judge for Discovery and Hearing issued May 17, 2006).
[3]
Ex. 12,
[4]
Ex. 12,
[5] Ex. 1, Binder 1, Tab G. The total number of customers is essentially unchanged from that in CenterPoint’s last rate proceeding. ITMO the Petition of CenterPoint Energy Minnegasco, a Division of CenterPoint Resources Corp., for Authority to Increase Its Natural Gas Rates in Minnesota, Finding 6, OAH Docket No. 7-2500-16151-2, PUC Docket No. G-008/GR-04-901 (ALJ Findings of Fact, Conclusion, and Recommendation issued March 25, 2005)(2004 CenterPoint Rate Matter).
.
[6] Ex. 1, Binder 1, Tab G.
[7] 2004 CenterPoint
Rate Matter,
(Commission Order Accepting and Modifying Settlement and Requiring Compliance
Filing issued June 8, 2005)(“2005 Commission Order”). Prior to the 2005 Commission Order, the most
recent rate increase for CenterPoint, occurred in 1996. ITMO the Application of Minnegasco, a Division
of NorAm Energy Corp., for Authority to Increase Its Natural Gas Rates in
[8] Ex. 1, Binder 1, Notice of Change in Rates.
[9] 2005 CenterPoint Rate Matter, (Order Accepting Filing and Suspending Rates issued December 21, 2005).
[10]
[11]
[12] 2005 CenterPoint Rate Matter, (Order Referring Prudence Issues Regarding Billing System Investment and Implementation to Administrative Law Judge for Discovery and Hearing issued May 17, 2006).
[13]
Ex. 12,
[14]
[15]
[16]
[17]
[18]
[19]
[20]
[21]
[22]
[23]
[24]
[25]
[26] See e.g., Coon Rapids Public Hearing Tr. (March 30, 2006), at 27-34.
[27]
[28] ITMO
the Application of Minnegasco, a Division of Arkla, Inc., for Authority to
Increase Its Rates for Natural Gas Service in
[29] 2004 CenterPoint Rate Matter, Findings 9 and 10, (ALJ Findings of Fact, Conclusions of Law, and Recommended Order issued March 25, 2005)(“2005 ALJ Recommendation”).
[30] Ex. 1, Binder 1, Tab D.
[31] Ex. 29, Hadaway Direct, at 5.
[32] Ex. 80, Griffing Direct, at 34.
[33] Ex. 84, Griffing Surrebuttal, at 12.
[34] ITMO an Inquiry into Possible Effects of the Financial Difficulties at Reliant Energy, Inc. on Reliant Energy Minnegasco and its Customers, PUC Docket No. G-008/CI-02-1368 (Order Requiring Filings to Protect Minnesota Ratepayers issued April 8, 2003)("2003 Reliant Energy Minnegasco Inquiry Order").
[35] 2003 Reliant Energy Minnegasco Inquiry Order, at 10, 12.
[36] Ex. 84, Griffing Surrebuttal, at 12.
[37] See Ex. 90 (showing 13-month averages for CenterPoint’s capital structure of 44.83% equity, 38.06% long-term debt, and 17.11% short-term debt). The percentages are taken from the replacement Ex. 90 that was submitted on May 5, 2006, correcting a mathematical error in the initial document.
[38] Hearing Tr. Vol 2, at 52-53.
[39] Hearing Tr. Vol 2, at 37-38 and 52-53.
[40] Hearing Tr. Vol. 2, at 133-139.
[41] CenterPoint Brief, at 14.
[42] Hearing Tr. Vol. 3, at 198-199.
[43] Department Brief, at 21-22.
[44] CenterPoint Reply Brief, at 4.
[45]
[46] Minn. Stat. § 216B.16, subd. 6 (2005).
[47]
[48] Bluefield
Waterworks & Improvement Co. v. Public Service Commission of
[49] Federal
Power Commission v. Hope Natural Gas Co., 320
[50]
[51] Ex. 29, Hadaway Direct, at 19.
[52] Ex. 29, Hadaway Direct, at 24.
[53] Ex. 29, Hadaway Direct, at 34-35.
[54] Ex. 29, Hadaway Direct, at 38-39.
[55] Ex. 29, Hadaway Direct, Schedule SCH-3.
[56] Ex. 29, Hadaway Direct, at.38-39.
[57] CenterPoint Brief, at 41.
[58] Ex. 80, Griffing Direct, at 9-10.
[59] Hearing Tr. Vol. 3, at 201-202.
[60] Ex. 80, Griffing Direct, at 10.
[61] Ex. 80, Griffing Direct, at 10.
[62] Keyspan later announced plans to be acquired by another company, which is a further ground for excluding that company from the Comparison Group. Ex. 84, Griffing Surrebuttal, at 5.
[63] Ex. 84, Griffing Surrebuttal, at 6.
[64] Ex. 84, Griffing Surrebuttal, MFG-S-5.
[65] Ex. 80, Griffing Direct, at 11-15; Ex. 29, Hadaway Direct, Schedule SCH-3.
[66] Ex. 84, Griffing Surrebuttal, at 6.
[67] Ex. 84, Griffing Surrebuttal, at 6.
[68] CenterPoint Brief, at 30.
[69] Ex. 84, Griffing Surrebuttal, at 14.
[70] Department Reply Brief, at 17.
[71] Department Reply Brief, at 15.
[72] Ex. 84, Griffing Surrebuttal, at 14.
[73] Ex. 30, Hadaway Rebuttal, Ex. 84, Griffing Surrebuttal, at 15.
[74] CenterPoint Brief, at 24.
[75] CenterPoint Brief, at 25.
[76] Department Reply Brief, at 19.
[77] In the Matter of a Petition by Great Plains
Natural Gas Company, a Division of MDU Resources Group, Inc., for Authority to
Increase Natural Gas Rates in
[78] Ex. 84, Griffing Surrebuttal, at 12.
[79] Ex. 84, Griffing Surrebuttal, at 12
[80] Ex. 84, Griffing Surrebuttal, at 12; Department Brief, at 13.
[81] Ex. 13, Hadaway Rebuttal, SCH-R, Schedule 1, at 2.
[82] CenterPoint Reply Brief, at 4.
[83] Department Brief, at 21-22.
[84] Ex. 84, Griffing Surrebuttal, at 12; Department Brief, at 13.
[85] Ex. 12, Hammond Direct, at 19-20; Hearing Tr., Vol. 1, at 36-39.
[86] Ex. 1, Binder 1, Proposed Tariffs.
[87] Ex. 1, Binder 1, Proposed Tariffs.
[88]
One therm is equal to 100,000 BTU’s.
CenterPoint calculates the therm value of gas provided by sampling
delivered gas for its BTU content per cubic foot and multiplying that value by
the cubic feet actually delivered to a customer.
[89] Ex. 1, Binder 1, Proposed Tariffs.
[90] Ex. 1, Binder 1, Proposed Tariffs; Ex. 12, Hammond Direct, at 20.
[91]
Ex. 12,
[92]
Ex. 12,
[93] Ex. 18, Yang Direct, at 12-16, Schedule 2.
[94] Ex. 18, Yang Direct, at 4-11.
[95] Ex. 75, Chavez Direct, at 24-26.
[96] Ex. 75, Chavez Direct, at 17, 20.
[97] OAG Brief, at 23-25.
[98] Ex. 18, Yang Direct, at 29. “Dkt” stands for dekatherm, with a conversion factor of 1 Dkt equaling 10 therms.
[99] Ex. 18, Yang Direct, Schedules 6 and 7.
[100] Ex. 18, Yang Direct, at 16, Schedule 3.
[101] Ex. 75, Chavez Direct, at 28-29.
[102]
Ex. 12,
[103] Ex. 28, Fransdal Rebuttal, at 7
[104] Department Brief, at 69; Ex. 75, Chavez Direct, at 36.
[105] Ex. 48, Duffrin Direct, at 3.
[106] Ex. 79, Chavez Surrebuttal, at 9.
[107] Hearing Tr. Vol. 1, at 225 (Fransdal) and Hearing Tr. Vol. 2, at 189-190 (Duffrin).
[108] Ex. 1, Binder 1, Tab F.
[109]
Ex. 12,
[110]
Ex. 12,
[111]
Ex. 12,
[112]
Ex. 13
[113]
Ex. 13
[114]
Ex. 12,
[115] Ex. 74, Bonnett Surrebuttal , at 2.
[116] Energy CENTS Reply Brief, at 10-12.
[117] Ex. 48, Dufferin Direct, at 18-19; Energy CENTS Brief, at 32.
[118] Ex. 1, Binder 1, Notice of Change in Rates.
[119] Ex. 1, Binder 1, Tab E.
[120] Ex. 1, Binder 1, Proposed Tariffs.
[121] Ex. 1, Binder 1, Proposed Tariffs.
[122]
[123] Hearing Tr. Vol. 3, at. 212.
[124] Ex. 31, Nesvig Direct, at 77 and Schedules 46, 47, 52-60, 62 and 64.
[125] Ex. 31, Nesvig Direct, at 77.
[126]
Ex. 62,
[127] CenterPoint Brief, at 43.
[128] Hearing Tr. Vol. 3, at. 120-123..
[129] Department Reply Brief, at 6.
[130] Ex. 22, MNOPS Pipeline Incident Report at 13.
[131] Ex. 22, MNOPS Pipeline Incident Report at 13.
[132] Ex. 24, MNOPS Compliance Order .
[133] Ex. 34 (note that actual amounts were listed, not truncated as indicated in the document header).
[134] SRA Reply Brief, at 1.
[135] SRA Reply Brief, at 2.
[136] OAG Reply Brief, at 8-9.
[137] OAG Reply Brief, at 4-7.
[138] Department Reply Brief, at 7.
[139]
Ex. 62,
[140]
[141]
Minnegasco
v.
[142] Lyla Burkman, as Trustee for the Heirs and Next-of-Kin of Lorraine Melton, deceased v. CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy, a Delaware corporation doing business in Minnesota v. MidAmerican Energy Company, an Iowa corporation a/k/a MidAmerican Energy and a/k/a Midwest Gas, a division of Midwest Power Systems, Inc., U. S. District Court File 06-CV-00325 (in which CenterPoint is seeking $40 million in remediation costs).
[143] Hearing Tr., Vol. 1, at 79.
[144]
Ex. 13,
[145]
[146]
Ex. 62,
[147] Ex. 31, Nesvig Direct, at 81.
[148] Department Reply Brief, at 6-8.
[149] CenterPoint Reply Brief, at 10.
[150] Petition for Approval of Affiliated Interest Agreement Between CenterPoint Energy and CenterPoint Energy Service Company to Transfer Cash Remittance Equipment, No. G-008/AI-06-0560 (Cash Remittance Petition).
[151] Department Brief, at 36.
[152] CenterPoint Reply Brief, at 10.
[153] Department Brief, at 36 (citing Cash Remittance Petition, Department Comment filed July 11, 2006).
[154] Department Brief, at 36.
[155] Ex. 97, Pyles Supplemental, at 2-3 .
[156] 2005 CenterPoint Rate Matter, (Order Referring Prudence Issues Regarding Billing System Investment and Implementation to Administrative Law Judge for Discovery and Hearing issued May 17, 2006).
[157]
Ex. 62,
[158] CenterPoint Brief, at 70.
[159] Ex. 67-D, Minder Direct, at 41-42; Department Brief, at 84.
[160] Ex. 67-D, Minder Direct, at 42; Department Brief, at 84.
[161] Ex. 67-D, Minder Direct, at 41; Department Brief, at 84.
[162] Ex. 69, Minder Surrebuttal, at 15; Department Brief, at 85.
[163] Ex. 67-A, Minder Direct, at 43, Ex. 67-C, Minder Direct, BJM-23.
[164] Department Brief, at 85-86.
[165] Hearing Tr. Vol. 2, at 152.
[166] Ex. 69, Minder Surrebuttal, at 15; Department Brief, at 85.
[167] Ex. 31, Nesvig Direct, at 68-69, Schedule 22.
[168]
Ex. 62,
[169]
Had the request not been withdrawn, the ALJ would have recommended that the
request be denied, consistent with the Commission’s recent decision in
[170] Ex. 32A, Nesvig Rebuttal, at 8, Schedule 2.
[171]
[172]
Ex. 61,
[173] Department Brief, at 44-45.
[174] In the Matter of the Implementation of the CenterPoint Energy Minnegasco 2005-2006 Biennial Natural Gas Conservation Improvement Program, Commerce Docket No. G-008/CIP-04-821 (Deputy Commissioner Decision issued November 30, 2004).
[175] Ex. 67A, Minder Direct, at 3; Department Brief, at 77-78.
[176] CenterPoint Brief, at 98.
[177] Ex. 69, Minder Surrebuttal, at 6; Department Brief, at 79-80.
[178] Department Brief, at 81.
[179] Ex. 67A Minder Direct, at 12-14; Department Brief, at 81-82.
[180]
Ex. 61,
[181] Department Brief, at 86, and Attachment 2.
[182] See e.g. Ex. 31, Nesvig Direct, Schedule 24.
[183] Ex. 66, Bender Surrebuttal, at 11.
[184] Ex. 64, Bender Direct, at 15, SB-4.
[185] Ex. 32A, Nesvig Rebuttal, at 24.
[186] CenterPoint Brief, at 93.
[187] See Ex. 64. Bender Direct. SB-4.
[188] Ex. 66, Bender Surrebuttal, at 7-9.
[189] Ex. 64, Bender Direct, at 15-16, SB-4, and SB-5. The allocation factor was designated trade secret and for that reason, the factor is not identified here.
[190] Ex. 64, Bender Direct, at 13-14. The allocation methods and corrections were designated trade secret and for that reason, that information is not identified here.
[191] See Ex. 31, Nesvig Direct , at 49-52.
[192] Ex. 31, Nesvig Direct, at 52
[193] See Ex. 31, Nesvig Direct , at 49-52. The Sarbanes-Oxley Act of 2002 is Pub. L. No. 107-204, 116 Stat. 745 (July 30, 2002),
[194] Ex. 32A, Nesvig Rebuttal, at 19-20.
[195] Ex. 64, Bender Direct, at 4.
[196] Ex. 66, Bender Surrebuttal, at 6; Department Brief, at 48.
[197] Ex. 32, Nesvig Rebuttal, at 18-19.
[198] Ex. 32A, Nesvig Rebuttal, 20-21
[199] Ex. 32A, Nesvig Rebuttal, Schedule 8, at 1.
[200] Department Brief, at 50.
[201] Ex. 66, Bender Surrebuttal, at 9-10.
[202] Ex. 66, Bender Surrebuttal, at 8.
[203] Ex. 66, Bender Surrebuttal, at 8.
[204] Ex. 32A, Nesvig Rebuttal, Schedule 8, at 1.
[205] CenterPoint Brief, at 89.
[206] Department Reply Brief, at 40-41
[207] Ex. 32A, Nesvig Rebuttal, at 2-3.
[208]
Ex. 62,
[209]
See Hearing Tr. Vol. 3, at 129-130 (
[210] Hearing Tr., Vol. 3 at 131-32.
[211]
ITMO
a Petition by Interstate Power and Light Company for Authority to Increase
Electric Rates in
[212]
Ex. 61,
[213] Ex. 4, Nesvig Workpapers, Vol 1, Schedule 6, Workpaper 4; Department Brief, at 61-62.
[214] Ex. 32, Nesvig Rebuttal, at 13, Schedule 5.
[215] Department Brief, at 61-62.
[216]
Ex. 61,
[217] Ex. 17.
[218] Ex. 171, Draft Gas Affordability Service Program Tariff, Section 5.3.
[219] Ex. 31, Nesvig Direct , at 25.
[220] Ex. 31, Nesvig Direct , at 25.
[221] See Ex. 32A, Nesvig Rebuttal at 11.
[222]
Ex. 62,
[223]
Ex. 61,
[224]
Ex. 61,
[225]
Ex. 61,
[226]
Ex. 61,
[227]
Ex. 61,
[228]
Ex. 61,
[229]
Ex. 62,
[230] Ex. 31 Nesvig Direct, at 44; Ex. 67-A Minder Direct, at 31.
[231] Department Brief, at 73-74 (citing Minn. Stat. § 216B.16, subd. 8).
[232]
[233] Hearing Tr. Vol. 2, at 152.
[234] Ex. 44, Vol. 1, at 27.
[235] Ex. 67-A, Minder Direct, at 38.
[236] Department Brief at 75.
[237] Hearing Tr. Vol. 2, at 155.
[238] Ex. 31 Nesvig Direct, at 29-30.
[239] Hearing Tr. Vol. 2, at 155.
[240] Ex. 67-A, Minder Direct, at 42.
[241] Ex. 32 Nesvig Rebuttal, at 25-26.
[242] Department Brief, at 76-77.
[243] See CenterPoint Brief, at 102-03.
[244] Department Reply Brief, at 29-30.
[245]
Ex. 12,
[246] Ex. 17.
[247]
Ex. 12,
[248] Ex. 17.
[249] Ex. 17.
[250] Ex. 17.
[251] Ex. 17.
[252] Ex. 17.
[253] OAG Brief, at 73.
[254] Ex. 118, at 8.
[255] OAG Brief, at 75.
[256] OAG Brief, at 75.
[257]
[258] OAG Brief, at 75.
[259]
[260]
Ex. 12,
[261]
Ex. 12,
[262] CenterPoint Brief, at 121.
[263] Ex. 70, Bonnett Direct, at 22; Department Brief, at 89.
[264] Ex. 70, Bonnett Direct, at 23; Department Brief, at 89.
[265]
In the Matter of an Application
by Northern States Power Company d/b/a Xcel Energy for Authority to Increase
Rates for Natural Gas Service in the State of
[266] OAG Brief, at 12; Energy CENTS Brief, at 35-36.
[267] OAG Brief, at 14, 21.
[268] 2004 CenterPoint Rate Matter, PUC Order, at 9 (Order Accepting and Modifying Settlement and Requiring Compliance Filing issued June 08, 2005).
[269] U.S. Department of Labor, Bureau of Labor Statistics, News (issued July 19, 2006) (http://www.bls.gov/news.release/pdf/cpi.pdf)
[270]
[271] CenterPoint Brief, at 122.
[272] CenterPoint Brief, at 123.
[273]
Ex. 13,
[274] 2004 CenterPoint Rate Matter, PUC Order, at 8 (Order Accepting and Modifying Settlement and Requiring Compliance Filing issued June 08, 2005).
[275] Ex. 70, Bonnett Direct, at 25; Department Brief, at 91.
[276] Ex. 12, Hammond Direct, at 25 (also increasing the basic charge for the Large General Service rate, which currently has no customers).
[277] Department Brief, at 91.
[278] Ex. 70, Bonnett Direct, at 14.
[279] Ex. 70, Bonnett Direct, at 15.
[280] Ex. 70, Bonnett Direct, at 16.
[281] Ex. 70, Bonnett Direct, at 17.
[282] Ex. 70, Bonnett Direct, at 20.
[283] Ex. 70, Bonnett Direct, at 20.
[284] Ex. 70, Bonnett Direct, at 27.
[285]
Ex. 12,
[286]
Ex. 13,
[287]
Ex. 70, Bonnett Direct, at 28-30 (citing In the Matter of a Petition by
Great Plains Natural Gas Company, a Division of MDU Resources Group, Inc., for
Authority to Increase Natural Gas Rates in
[288]
Ex. 13,
[289] Ex. 74 Bonnett Surrebuttal, at 12; Department Brief, at 98.
[290] Ex. 1, Binder 1, Proposed Tariffs.
[291] CenterPoint Brief, at 124.
[292] CenterPoint Brief, at 124.
[293] Ex. 71, Bonnett Direct, JB-7, at 2.
[294] Department Brief, at 99-100.
[295] Ex. 71, Bonnett Direct, at 34.
[296] Ex. 71, Bonnett Direct, JB-8.
[297] As noted in a foregoing finding, CenterPoint is also proposing to increase the basic charge for this class by $70.00.
[298]
Ex. 12,
[299] Ex. 71, Bonnett Direct, at 36.
[300]
Ex. 13,
[301] Department Brief, at 103.
[302] Ex. 110.
[303] Ex. 97, Pyles Supplemental, at 7-8; Ex. 98, Newman Supplemental, at 4-5, Ex. 108, Ex. 146; and Hearing Tr. Vol. 4, at 24-25 (Newman).
[304] Ex. 98, Newman Supplemental, at 3
[305] Ex. 98, Newman Supplemental, at 4-5, Ex. 108, and Hearing Tr. Vol. 4, at 24-25 (Newman).
[306] Hearing Tr., Vol. IV, at 55.
[307] OAG Brief, at 69-70.
[308] Ex. 98, Newman Supplemental, at 5.
[309] Ex. 98, Newman Supplemental, at 5, Status Reports to MPUC.
[310] Ex. 98, Newman Supplemental, Status Reports to MPUC, Weeks of 2/20 and 1/23.
[311] Ex. 98, Newman Supplemental, Status Reports to MPUC, Weeks beginning March 6.
[312] Ex. 98, Newman Supplemental, Status Reports to MPUC, Weeks beginning March 13.
[313] Ex. 98, Newman Supplemental, Status Reports to MPUC, Weeks beginning March 27, April 10, and April 17.
[314] Ex. 98, Newman Supplemental, at 7; Ex. 97, Pyles Supplemental, at 15-16.
[315] Ex. 98, Newman Supplemental, at 5.
[316] Ex. 98, Newman Supplemental, at 5.
[317] Ex. 164.
[318] Hearing Tr., Vol. IV, at 47-48.
[319] Department Reply Brief, at 34.
[320] Hearing Tr. Vol. 2, at 152.