OAH 12-2500-20147-2
MPUC G-008/GR-08-1075
STATE OF
OFFICE OF ADMINISTRATIVE HEARINGS
FOR THE PUBLIC UTILITIES COMMISSION
|
In the Matter of
an Application by CenterPoint Energy for Authority to Increase Natural Gas
Rates in |
FINDINGS
OF FACT, CONCLUSIONS OF LAW, |
TABLE OF CONTENTS
JURISDICTIONAL AND PROCEDURAL BACKGROUND
Cost of Gas and Gas Storage Inventory
Sales Forecasts, With The Exception Of The Appropriate
Time Period To Use For “Normal Weather”
Pension and Employee Taxes and Benefits
Depreciation Allocated From Service Company
Rate Base – Plant In Service, With Exception of
Service and Main Extensions Adjustment
Travel, Meals, Lodging, Entertainment, Customer
Appreciation, Board of Directors Expenses
Applying Carrying Charges to CIP Tracker Account/CIP
Recovery
Interest Synchronization Methodology
Service Quality Implementation
Statutory and Regulatory Overview
Proposed Decoupling Stipulation in this Docket
The Company’s Compliance with the Commission’s
Criteria and Standards
Adherence to the guiding statute
Form of the decoupling mechanism
Conservation Program Development
Midwest Gas Replacement Pipeline Costs
Bad Debt Expense Recovery (BDER) Mechanism
Service and Main Line Extensions
Rate Case Expense Amortization
Court Ordered Access Expenses.
Cost Allocations, Escalation Factor
10-Year vs. 20-Year Weather Normalization for Sales
Forecast
Amortization Period for CIP Tracker
Cost of Capital and Overall Rate of Return
CLASS COST OF SERVICE STUDY (CCOSS)
Conservation Program Development
Bad Debt Expense Recovery (BDER) Mechanism
Service and Main Line Extensions
Rate Case Expense Amortization
Cost Allocations, Escalation Factor
10-Year vs. 20 Year Weather Normalization for Sales
Forecast
CLASS COST OF SERVICE STUDY (CCOSS)
OAH 12-2500-20147-2
MPUC G-008/GR-08-1075
STATE OF
OFFICE OF ADMINISTRATIVE HEARINGS
FOR THE PUBLIC UTILITIES COMMISSION
|
In the Matter of
an Application by CenterPoint Energy for Authority to Increase Natural Gas
Rates in |
FINDINGS
OF FACT, CONCLUSIONS OF LAW, |
An
evidentiary hearing was held before Administrative Law Judge Steve M.
Mihalchick beginning on August 6, 2009 at 9:00 a.m. in the Large Hearing Room
at the offices of the Public Utilities Commission (“Commission”) in
Eric F. Swanson and
David M. Aafedt, Attorneys at Law, Winthrop & Weinstine, P.A.,
Karen Finstad Hammel
and Julia Anderson, Assistant Attorneys General, 1400
Ronald M. Giteck and
William T. Stamets, Assistant Attorneys General, 900 Bremer Tower,
Pam Marshall,
Executive Director, Energy CENTS Coalition,
James Strommen,
Attorney at Law, Kennedy & Graven, 470
Elizabeth I. Goodpaster,
Commission Staff Janet
Gonzalez, Jerry Dasinger, Robert Harding, Stuart Mitchell, and Rachel Welch were
present.
Public
hearings were held in
A briefing schedule was established at the conclusion of the evidentiary hearings. Posthearing briefs were filed on September 16, 2009 by all of the parties except the Isaac Walton League of America and Minnesota Center of Environmental Advocacy (ICWA/MCEA) which requested and received permission to submit its initial brief on September 23, 2009. Reply briefs and Proposed Findings were filed on September 30, 2009. An amended CenterPoint exhibit 140 was filed on October 20, 2009 at the request of the Administrative Law Judge. The hearing record closed on that date.
Notice is
hereby given that, pursuant to Minn. Stat. § 14.61,
and the Rules of Practice of the Minnesota Public Utilities Commission
(Commission or MPUC) 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 Energy CENTS, the
ICWA/MCEA and the Company, this matter may
be extended by 60 days for conclusion of this proceeding.
On
November 3, 2008, CenterPoint requested an increase in its natural gas rates of
$60 million, which is approximately a 3.9% increase in overall annual
revenues. The Company also proposed a rate
design, including a pilot decoupling plan, to cover the costs of the plan in
light of the legislature’s goals to reduce natural gas sales.[1] The Commission has directed that an evidentiary
record be established on that request with regard to the following issues:[2]
1.
Is the test year revenue increase sought by the
Company reasonable or will it result in unreasonable and excessive earnings by
the Company?
2.
Is the rate design proposed by the Company,
including proposed revisions to customer charges, reasonable?
3.
Are the Company's proposed capital structure,
cost of capital, and return on equity reasonable?
4.
Is the amount of bad debt expense claimed
reasonable? How was the amount
calculated, how can it be replicated and verified, and is it subject to
manipulation?
5.
Are the inflation factors claimed, including the
general inflation factor of 9.2%, appropriate, given current conditions?
6.
Are the dues included in test year expense
appropriate in amount and appropriate for rate recovery?
7.
How do Commercial/Industrial Class C customers
meet the eligibility criteria for the Company's market-rate service rider? How many market-rate customers does the
Company have?
8.
How does the "guaranteed savings
discount" bill credit work? What is
the source of the money for the discount? Why is the bill credit applied to all volumes
of gas sold rather than just the market-rate volumes?
9.
How does the market-rate premium paid by
customers work and where does the money go?
10.
How are the guaranteed savings discount and the
market-rate premiums and/or discounts incorporated into the calculations of the
Company's revenue deficiency for final rates, revenue deficiency for interim
rates, and any potential interim rate refund?
1. CenterPoint Energy Minnesota Gas (CenterPoint, the Company, or CPE) is a Minnesota Local Distribution Company (LDC). It is a division of CenterPoint Energy Resources Corporation, which is a wholly-owned subsidiary of CenterPoint Energy, Inc.[3]
2.
CenterPoint Energy, Inc., is located in
3.
CenterPoint distributes natural gas to more than
260 communities and 750,000 customers in
4. On November 3, 2008, CenterPoint filed a general rate case petition seeking an annual rate increase of some $59,800,000, or approximately 3.9 percent. On November 4, 2008, the Commission issued a notice to potentially interested parties requesting comments on whether the Commission should accept the filing as substantially complete and whether it should refer the case to the Office of Administrative Hearings for contested case proceedings.
5. The only party to file comments was the OES, which recommended accepting the filing as complete and referring the case for contested case proceedings.
6. On December 11, 2008, the Commission accepted the application as substantially complete, referred the case for contested case proceedings, and authorized an interim rate increase of $51,229,000.
7. On December 17, 2008, CenterPoint filed with the Commission a waiver of its statutory right to a final decision on this matter within the ten-month time frame set forth in Minn. Stat. § 216B.16, provided that the final order is issued no later than January 11, 2010.
8. The Commission issued a Notice and Order for Hearing on December 22, 2008, reflecting its decision to refer the case to the Office of Administrative Hearings for contested case proceedings. On the same day, the Commission issued an Order finding the rate case filing to be substantially complete and suspending the proposed rates and another Order setting an interim rate schedule for use during the suspension period.[6]
9.
A prehearing conference was held on January 12,
2009, at the Commission’s offices in
10. The First Prehearing Order was issued February 2, 2009, establishing a procedural schedule. Initial parties to the proceeding were CenterPoint and the OES. Intervention petitions filed by SRA, ECC, and OAG-RUD were granted in the First Prehearing Order.
11. A Protective Order was issued on February 25, 2009, to address the handling of nonpublic data.
12. In a separate order dated March 9, 2009, the Administrative Law Judge granted intervention to the Minnesota Mechanical Contractors’ Association (MMCA), but limited MMCA’s participation to issues regarding CenterPoint’s allocation of costs and resources between its regulated and nonregulated businesses.
13. On April 1, 2009, CenterPoint filed supplemental direct testimony addressing the market rate issue identified by the Commission in the Notice and Order for Hearing.
14. On April 7, 2009, the petition to intervene filed by IWLA/MCEA was granted. The Energy CENTS Coalition (ECC) filed a petition to intervene on May 4, 2009. This petition was granted in an Order dated May 18, 2009.
15. On June 23, 2009, the Administrative Law Judge issued an order compelling responses to certain information requests which had been requested by the OAG-RUD.
16.
Public hearings were held in
17. The Administrative Law Judge received 33 written public comments.[7]
18. The evidentiary hearing was held on August 6 and 7, 2009, and on August 11, 2009, in the Commission’s Large Hearing Room.
19.
There were five public hearings scheduled. Two of the hearings were scheduled on July
14, 2009 at 1:30 p.m. and 6:00 p.m. in
20.
Jeff Daugherty, Director of Regulatory and
Legislative Activities for CenterPoint Energy’s
21. At each hearing, Mr. Daugherty explained that the Company is requesting new distribution rates in this case totaling $59.8 million, or about 3.9 percent. He stated that the case is “only about the cost of providing you with utility distribution service, which makes up about 20 percent of your bill. This rate case is not about wholesale gas costs, which make up about 80 percent of the bill and are passed through without markup.”[8]
22. Mr. Daugherty also stated that the “proposed rates in this rate case would affect customers differently depending on how much gas they use, changes in the wholesale cost of gas, and their customer group, while on average the proposed new rates would add about $5 per month to the average residential customer’s bill.”[9]
23. Also present at the July 14, 2009, hearing were Marlon Griffing, public utilities financial analyst, appearing on behalf of the OES, and Elizabeth Goodpaster, the attorney representing the IWLA/MCEA.
24. Mr. Griffing and other representatives of OES at the other public hearings, made statements explaining that OES represents the interests of all ratepayers in utility proceedings before the PUC. The OES representatives all stated that OES’ investigation, “to date has concluded that $13 million per year of the $59.8 million” of the Company’s stated required revenue increases should be rejected.[10]
25. Four members of the public spoke at the July 14, 2009 hearing. Mr. Dennis Murphy asked about the conversion of cubic feet of gas as indicated on his gas meter to therms, which is the volumetric basis for billing. Mr. Murphy wondered why the Company had to have a rate case when it looked to him as though the Company could make more profit simply by adjusting the formula for converting cubic feet into therms.[11]
26. Mr. Klenken responded, explaining the reasons for the conversion from cubic feet into therms. Mr. Klenken reviewed some of the history of the adoption of the therm as a measure and the way in which the conversion is calculated. Mr. Klenken also explained that the variation in the cost of gas to Mr. Murphy was a reflection of changing market prices for gas, not the result of a rate case.[12]
27. Mr. Murphy also asked for clarification about what the delivery charge is and what part of the bill will be subject to the rate increase, and Mr. Klenken responded to those questions. Finally, Mr. Murphy asked about what the gas affordability program is, and Mr. Daugherty responded to him with a very brief history and explanation about that program.[13]
28. Mr. Gene Cichowicz then stated his opposition to the decoupling process. He noted that some states have tried decoupling and later stopped it and that decoupling appears to penalize people who conserve. He was especially concerned that decoupling would be put in place on top of a rate increase. Mr. Daugherty explained that the purpose of decoupling is to allow the Company to cover its costs, even as usage decreases. Mr. Cichowicz wondered why that could not be built into the Company’s rate request, and Mr. Daugherty responded that the rates have to be based on the test year, ending in December 2009, and that it is not permissible to project further into the future than that. Mr. Griffing assured Mr. Cichowicz that the OES would be providing extensive testimony about decoupling on behalf of all consumers.[14]
29. Ms. Goodpaster offered information about the role the IWLA and MCEA are playing in this matter and their interest in encouraging utility companies to focus on conservation. Ms. Goodpaster explained that the goal of the decoupling mechanism is to make the utility company “indifferent” to its customers’ declining use of natural gas.[15] She also pointed out that the decoupling program is a three-year pilot program and that an added component of CPE’s program is “a component to the rider that would, as you go up in usage your rate increases, and so the lower usage gets a better rate” as a price signal to customers to conserve on their own usage.[16]
30. Mr. Daugherty elaborated on Ms. Goodpaster’s comments, explaining that “customers who use less gas will have a discount on their rate, and the rate design is such that as consumers use more there’s a surcharge on their gas cost rate.” Mr. Daugherty confirmed that this is known as the “inverted block rate” proposal.[17]
31. Mr. Roger Kloster then spoke against the rate increase, noting that, as a Social Security recipient, his income is frozen. Mr. Kloster stated that the gas company should “learn to live on what you’re receiving because that’s all you’re going to get.”[18] Mr. Kloster also objected to being penalized for conserving energy. Mr. Kloster asked whether the Company has any kind of discount for senior citizens. Mr. Daugherty replied that CenterPoint does not have such a program, and Mr. Kloster suggested that they should have one.[19]
32. Finally, Mr. Omar Nelson asked whether the Company is “efficiently and vigorously” trying to collect payment on past due bills. Mr. Daugherty assured Mr. Nelson that this issue would be explored fully in the rate case. Mr. Nelson also expressed concern about whether the customer charge for natural gas itself accurately reflects the changes in market prices.[20]
33.
In addition to the CenterPoint representatives
and Ms. Goodpaster, Ronald Giteck, attorney from the OAG/RUD, Samir Ouanes,
rates analyst from OES, and Ms. Dercks from the Consumer Affairs Office of the
PUC all spoke at the July 15 hearing in
34. Mr. Giteck introduced himself, describing his office as “directed to represent the interests of the residential and small business ratepayers.” Mr. Giteck added that “[t]here are certain aspects of the rate case that we think are not good for residential and small business ratepayers.”[21]
35. Ms. Dercks explained briefly what the Consumer Affairs Office does and offered to take public comments in a variety of forms in this case.[22] Ms. Goodpaster and Mr. Daugherty made essentially the same statements they made at the July 14, 2009 public hearing.[23]
36. Mr. Tom Ryan asked why, given the decrease in the cost of natural gas, CenterPoint was raising rates rather than passing along the savings in gas costs.[24] Mr. Daugherty and Mr. Klenken explained that the changes in natural gas prices have been passed through to consumers and that the proposed rate increase is not on the gas prices but on the distribution system costs.[25]
37. Mr. Klenken then introduced a chart showing average residential billing rates by month for the last several years.[26] He demonstrated with the chart that, in July 2008, the residential billing rate for natural gas was $1.41 per therm and in July 2009, it had fallen to about 56 cents per therm. He clarified that the 3.9 percent rate increase sought by the Company is 3.9% of the total bill. Mr. Giteck added that he believes the increase on the distribution portion of the bill is about 23 percent for residential customers and 26 percent for small businesses.[27]
38. Mr. Klenken observed that when the cost of natural gas falls as much as it has within the last year, the fraction of a customer’s bill that is just natural gas cost becomes less than the 80 percent the Company has characterized as not subject to this rate increase.[28]
39. Following these discussions, Mr. Ryan reiterated that the customer price reduction in natural gas charges did not appear to be consistent with the drop in wholesale natural gas prices.[29]
40.
There was no mention of the inverted block gas
cost rate during the July 15, 2009 public hearing in
41.
Representatives of CenterPoint, OES, OAG, and
the PUC all attended the July 22, 2009, hearing in
42.
Mr. Kelly McCabe, representing a metal finishing
company in
43. Mr. McCabe expressed concerns about being penalized for conservation and wondered whether decoupling would permit those who conserve to be rewarded while those who do not would pay increases.[34] Mr. Daugherty explained the decoupling mechanism and then explained that, as an “interruptible customer,” Mr. McCabe’s company would not be included in the decoupling proposal.[35]
44. Mr. Daugherty briefly explained the inverted block gas cost rate proposal.[36] Mr. McCabe stated that he is opposed to the rate increase.[37]
45.
Representatives of CenterPoint, OES, and the PUC
all attended the July 23, 2009, hearing in
46. Mr. Eugene Krueger first stated his disagreement with having to support the gas affordability program to support people who are delinquent on their bills. Mr. Daugherty explained both the decoupling program and the gas affordability program.[39]
47. Mr. Krueger also raised the question of how and why the Company converts the cubic centimeters measured by the gas meter into therms for billing purposes.[40] Mr. Klenken, who has been involved in discussions with Mr. Krueger over a number of years about the question of conversion into therms, responded to many of Mr. Krueger’s concerns.[41]
48.
There was no mention of the inverted block gas
cost rate during the July 23, 2009, public hearing in
49. The Administrative Law Judge received 33 public comments outside of the public hearings. Most of the comments opposed CenterPoint’s petition for a rate increase, at least for residential customers.
50. Four commenters expressed concerns that executives at CenterPoint Energy should not be raising rates when their own salaries and corporate budgets are so high and the company is not efficiently run.[42]
51. One commenter disagreed with any salary increases for CenterPoint employees at a time when so many customers are facing decreases and layoffs. The same commenter attached a CenterPoint shareholder report describing an increase in the Company’s net income and dividends in 2007.[43]
52. One commenter noted that a $5.00 per month increase for gas customers would be a huge increase for the Company overall and asked that people on fixed incomes be considered in this case.[44]
53. Twenty commenters objected based on the difficulty that people on low or fixed incomes or who are struggling with job losses have in paying increasing utility bills, and the monopolistic nature of utility service, which limits customer choice regarding the source of energy needed to heat their homes.[45]
54. Six commenters pointed out that increased conservation by consumers should not result in higher bills for those consumers and that the company needs to figure out how to make conservation profitable for itself.[46]
55. One commenter objected to having customers bear the cost of the Company’s Conservation Improvement Program, stating that these costs should come from the Company’s profits.[47]
56. Three commenters pointed out that the cost of natural gas has declined 70-90% in the past year, attaching data from the Star Tribune and the Wall Street Journal.[48]
57. One commenter noted that supplies seem to be available to an extent that does not seem consistent with continued rising costs.[49]
58. One commenter stated that ratepayers had a rate increase less than two years ago.[50]
59. One commenter noted that CPE “already has the ability to increase its cash flow at least on a temporary basis by adjusting the monthly rate it charges under the budget plan” in which he participates. The writer pointed out that for the past several years he has been overcharged on his budget plan for the cost of gas and has had a credit to adjust over the summer months. This results in CPE’s use of the customer’s money (and the many others on budget plans) for months at a time, creating a sort of ongoing interest-free loan. Given that, and the company’s monopoly of service in many areas, the writer states that the company has enough of an economic advantage so that it should not be rewarded with a rate increase.[51]
60. One commenter argued that, given that the rate increase is not related to the cost of the gas itself, it “is purely a fee for profit” and that improved technology and automation should be leading to lower rather than higher prices.[52]
61. The Crow Wing County Board of Commissioners submitted a letter opposing the rate increase, pointing out declining employment of individuals and declining revenues for all kinds of government services. In Crow Wing county, the letter points out, the Board is faced with the challenge of cutting millions of dollars from its operating budget just when its citizens are in most need of its help and least able to absorb tax increases. Referring to the idea of increasing taxes to cover costs, the letter states:
We are committed to avoiding that and CenterPoint Energy should be exposed to the same realities of changed economic circumstances that both government and the private sector are currently facing. Raising consumer rates is easy; finding creative ways to cut costs is not.[53]
62. Two commenters stated that the notice they received regarding the rate increase gave them insufficient clear information to understand the reasons for the rate increase.[54]
63. Two commenters were opposed to the gas affordability charge, stating that customers should not be forced to support people who cannot, or will not, pay their own gas bills. One of those commenters pointed out that, since the people who do not pay their bills are billed anyway, “CenterPoint is collecting double amounts.” The other commenter mentioned that this was made worse because ratepayers are being asked to pay for collection agency and customer service costs.[55]
64. One commenter also expressed concern about the conversion in measurement of gas used from cubic foot meters to therms. The commenter felt that CPE was overcharging as a result of this conversion.[56]
65. One commenter objected to the Conservation Enabling Rider (Decoupling Program) as a form of deregulation which will allow the Company to automatically annually adjust rates with no customer protections. The same commenter wondered how a cap and trade policy will affect rates in the future. [57]
66.
The Chief House and Senate authors of the 2007
Next Generation Energy Act expressed support for the decoupling proposal
contained in the stipulation agreement filed by CenterPoint Energy, the Izaak
Walton League, the
67. Through the normal course of the proceeding, certain issues have been resolved among the parties, thus reducing the number of disputed issues to be decided in this case.[59] The following issues have been resolved for purposes of setting rates in this case:
a. off-system sales;
b. cost of gas and storage inventory;
c. sales forecasts, with the exception of the appropriate time period to use for “normal weather;”
d. inflation factors
e. fleet fuel expense;
f. easement clearing;
g. odorant;
h. pension and employee taxes and benefits;
i. late payment factor;
j. depreciation rates;
k. depreciation allocated from service company;
l. rate base – plant in service, with exception of service and main extensions adjustment;
m. travel, meals, lodging, entertainment, customer appreciation, board of directors expenses;
n. application of carrying charges to CIP tracker account/CIP recovery;
o. advertising;
p. marketing;
q. Gas Technology Institute;
r. organizational dues;
s. interest synchronization methodology;
t. cash working capital;
u. reconnect charges;
v. distribution system expenses;
w. collection costs;
x. billing-related costs;
y. service quality implementation;
z. complement;
aa. claims; and
bb. GAP (gas affordability program) administrative costs.
68. CenterPoint Energy engages in certain transactions referred to as “off-system sales” or “other gas revenues.” These transactions consist of storage exchanges, point exchanges and swing sales.[60] The Company’s filing included revenues of $5,912,279 for these transactions, after comparing historical levels of these revenues to expectations of similar revenue going forward and considering market conditions.[61]
69. The OES analyzed the Company’s off-system sales and noted that the volatility associated with these revenues makes forecasting difficult and “can result in a situation where either the shareholders or the ratepayers are harmed.”[62]
70. Due to this volatility, and in order to treat off-system sales consistently with capacity release revenues, the OES recommended that the net margins on off-system sales flow through the purchased gas adjustment (“PGA”). At the same time, OES noted that with PGA treatment “the utility may not have the same incentive to pursue the level of margins that would have been set in base rates” potentially lessening the benefit to ratepayers.[63] Therefore, to provide the Company an incentive to pursue these transactions, the OES recommended that the Company be provided an incentive equal to the Company’s overall rate of return multiplied by the net off-system sales revenues.[64] Capacity release revenues would continue to flow to ratepayers with no incentive to the Company.
71. The Company provided Rebuttal Testimony stating that the incentive recommended by the OES is extremely conservative. According to the Company, a more typical split of off-system sales revenues would be for the utility to retain 10% to 15% of the revenues, including capacity release revenues, in the calculation of the incentive.[65]
72. While the Company may view the OES recommendation as conservative, the Company agreed to it, with the following clarifications, agreed to by both the OES and the Company:[66]
a. The changed treatment of off-system sales would begin with the date of interim rates. This means that off-system sales would be removed from the test year and that the crediting of off-system sales to ratepayers and the Company incentive would begin with the date of interim rates.
b. The actual amount of off-system sales generated between the date of interim rates and the date of final rates, net of the incentive for the same period, would flow back to ratepayers through the interim rate refund. There would be no allocation of this refund amount between the demand and commodity portion of gas costs as will occur on a going-forward basis in the monthly PGA.
c. On a going-forward basis, the monthly PGA would include an estimate of the amount of off-system sales expected in the upcoming month. The off-system sales will be split between commodity and demand cost-of-gas as outlined in Ms. St. Pierre’s testimony (i.e., storage exchange and swing sales would be a demand cost credit and other point exchanges would be a commodity cost credit).
d. The annual AAA filing would include a separately identified calculation of the over/under recovery of the off-system sales credits to ratepayers and of the incentive.
e. The “net margin” of off-system sales means the transaction revenue less any incremental transportation or fuel charges.
f. The incentive that CenterPoint Energy would earn and flow to shareholders would be equivalent to the overall rate of return approved in this case.
73. No party other than the Company and OES provided testimony on this issue.
74. The record supports the reasonableness of the OES proposal with respect to off-system sales, with the clarifications agreed to by both the Company and the OES.
75. CenterPoint Energy’s Initial Filing incorporated a commodity cost of gas of approximately $9.00 per dekatherm.[67] The Company based this recommendation on a three-step process and utilizing Energy Information Administration (“EIA”) projections on natural gas prices to develop its forecast.[68]
76. In its Direct Testimony, the OES conducted its own analysis and developed a range of gas costs of $7.00 to $8.00 per dekatherm, before recommending a commodity cost of $7.50 per dekatherm.[69]
77. In Rebuttal Testimony, the Company also conducted further analysis and developed a range of commodity costs of $6.532 to $8.00 per dekatherm.[70] Based on that analysis, the Company agreed to OES’s recommended $7.50 per dekatherm commodity cost of gas as reasonable for this rate case.
78. In Surrebuttal Testimony, the OES examined additional data and recommended a commodity cost of gas of $6.819 per dekatherm as a reasonable cost for this rate case since it “reflects both current market expectation but also represents the overall historical trend in natural gas prices.”[71]
79. The Company agreed with the OES’s final recommendation, both with respect to the cost of gas and with respect to the resulting gas storage inventory adjustment.[72]
80. No other party provided testimony or analysis on this issue.
81. The record supports the OES’s recommended price of $6.819 per dekatherm as a reasonable estimate of the cost of gas for the period until CenterPoint files its next rate case.[73]
82. The Company presented detailed test year sales forecasts for each of its customer classes.[74]
83. The OES developed its own sales forecast for each class, reflecting certain methodological differences when compared to the approach used by the Company.[75] However, with the exception of the appropriate period to use in order to “weather normalize” test year sales (applicable for all but the large volume classes), these methodological differences do not lead to significantly different results. Therefore, for purposes of setting rates in this proceeding, the Company did not object to the use of the OES’s methodology for all but the large volume classes.[76]
84. The Company agreed to the OES’s sales forecast for the large volume customer classes.[77]
85. No other party presented testimony on the sales forecast.
86. The record establishes a test year sales forecast for CenterPoint Energy of either 156,841,496 dekatherms (the Company’s forecast) or 159,303,157 dekatherms (the OES forecast), depending on the Commission’s resolution of the proper time period to use for “weather normalization” purposes, discussed by the ALJ in separate Findings.[78]
87. In its Initial Filing, the Company provided testimony supporting the various inflation factors it applied to the base year, in developing its test year expenses.[79] The Company proposed two payroll inflation rates and a general inflation factor rate to adjust those expenses affected by inflation.[80]
88. In Direct Testimony, the OES proposed alternative test year inflation rates.[81] Specifically, the OES proposed a payroll inflation factor of 6.43%, a secondary payroll inflation factor of 5.03%, a general inflation factor of 4.6%, and a Service Company inflation factor of 6.01%.[82]
89. In Rebuttal Testimony, Company witness Mr. Nesvig confirmed that the OES inflation factors, as proposed by Mr. Heinen, are reasonable.[83] Both Mr. Heinen and Mr. Nesvig acknowledged that economic conditions had changed dramatically between the time of filing and the time of intervenors’ prefiled testimony, and that the OES’s proposed inflation factors are appropriate for purposes of setting rates.[84]
90. No other party provided testimony on this issue.
91. The revised inflation factors result in a test year adjustment of $1,716,226 in reduced inflation costs.[85]
92. The revised inflation factors result in an adjustment to corporate allocations of $208,023.[86] The Company agreed to that adjustment.
93. Finally, OES recommended of an adjustment of $349,501 to remove certain inflation that had inadvertently been counted twice.[87] Again, the Company agreed with that adjustment.
94. In its Initial Filing, the Company included a projected test year fleet fuel expense based on a cost of $3.89 per gallon of fuel, based on Energy Information Agency forecasts, and on a 1% annual increase in miles driven, due to system growth.[88]
95. Although the OES agreed to a 1% increase in gallons based upon a projected increase in miles driven, the OES disagreed with the projected increase in average fuel price projected for the test year.[89] In lieu of the Company’s projected fuel cost, the OES recommended a per gallon cost of fuel of $2.69 for the test year, resulting in a reduction of $672,171 in expenses.[90]
96. The Company agreed that the OES’s fleet fuel expense recommendation is reasonable for purposes of setting rates and is an appropriate resolution of this issue.[91]
97. No other party provided testimony on this issue.
98. Based on the parties’ agreement, test year expenses for fleet fuel are reduced by $672,171.
99. On behalf of the Company, Mr. Nesvig proposed an increase in easement clearing costs in 2009 of $454,900, to clear approximately 19 miles of easements from brush and overgrowth so that routine maintenance can be performed.[92]
100. In lieu of the projected test year expense for 2009, the OES proposed that the Company be allowed to recover for 2009 its average annual easement clearing costs over the period of 2005 to 2008, resulting in a reduction in test year expenses of $402,760.[93]
101. The Company agreed to Mr. Johnson’s proposed adjustment for this item, and no other party provided testimony on the issue.[94]
102. Company witness Mr. Nesvig projected a test year expense of $524,488 for odorant, based upon the 2008 usage as adjusted for additional requirements relating to customer growth.[95] This figure was calculated based upon an estimated usage for the test year multiplied by the estimated 2009 price per pound.[96]
103. In his Direct Testimony, OES witness Mr. Johnson sought an updated amount of odorant used by the Company for 2008, which was provided by the Company in Mr. Nesvig’s Rebuttal Testimony.[97]
104. Based upon the Company’s actual usage for 2008 of 109,360 pounds, multiplied by the price of $2.32 per pound, Mr. Johnson proposed a reduction of $189,109 for odorant.[98]
105. The Company agreed that Mr. Johnson’s proposal is a reasonable forecast for test year odorant costs, and no other party provided testimony on this issue.[99]
106. The record supports the reasonableness of reducing test year expenses by $189,109.
107. The Company’s filing included test year pension expense of $2.2 million before allocation between the Company’s regulated and non-regulated operations.[100]
108. Due to the significant change in market conditions between the time of the Company’s filing of the case and the filing of the parties’ testimony in this matter, the Company filed a revised pension expense calculation in Mr. Nesvig’s Rebuttal Testimony.[101] In his Rebuttal Testimony, Mr. Nesvig proposed a $7.4 million increase (from the Company’s Initial Filing), of which $3.6 million is allocated to the regulated business.[102] As Mr. Nesvig testified, the revised pension expense was an actuarial calculation using updated assumptions for the long-term rate of return, the discount rate, and the value of the pension assets.[103]
109. In response to the Company’s revised pension expense, Mr. Johnson of the OES indicated that he did not dispute the Company’s actuarial calculation.[104] Mr. Johnson further agreed with Mr. Nesvig that a number of rate case expense items including inflation, costs of gas, and fleet fuel expenses should reflect more recent information.[105] Based upon these considerations, Mr. Johnson recommended allowing the Company to reflect its higher pension expense; however, he recommended that the Commission use an average of the Company’s actuarial estimates from July and December 2008, which balances the effects of the highs and lows in the market.[106] Accordingly, Mr. Johnson recommended an increase of test year pension expense of $1,804,049 from the Company’s original filing.[107]
110. The Company agreed to this OES recommendation for purposes of setting rates in this proceeding, and no other party provided testimony on this issue.[108]
111. The record supports the reasonableness of increasing test year pension expenses by $1,804,049.
112. The Company’s filing also included various additional adjustments relating to employee taxes and benefit program adjustments.[109] As Mr. Nesvig explained, the Company’s employee benefit programs are similar to those of other large companies, including, but not limited to, medical and dental insurance, vision plan, a 401(k) savings plan, as well as post-employment benefits for retired employees.[110] Mr. Nesvig provided a detailed description of test year adjustments for each of these items in his Direct Testimony and supporting work papers.
113. No other party to the proceeding presented any testimony on these issues, and these issues are therefore resolved.
114. In its Initial Filing, the Company proposed a revenue-related adjustment reflecting an increase in revenues related to the late payment charges to customers that the Company expects in the test year.[111] The Company developed its revenue number by taking actual late payment charges as a percentage of firm revenue for the twelve-month period ending December 31, 2007, and applying that percentage (0.63%) to test year firm revenue.[112]
115. The OES agreed with the Company’s methodology for calculating the late payment factor, which had been approved by the Commission in the Company’s previous rate cases.[113] However, the OES recommended using the more current 2008 ratio of late payment fees as a percent of firm revenue and applying that figure (0.53%) to test year firm revenue.[114] Based upon this revised late payment factor, Ms. St. Pierre recommended that the Company’s test year revenues be decreased by $2,771,771 for the late payment fees adjustment.
116. The Company agreed with the OES recommendation.[115]
117. The OAG initially challenged the Company’s calculation of its late payment fees, proposing a defined dollar amount rather than a percentage of firm revenue.[116] However, in Rebuttal Testimony, the OAG agreed with the OES rationale and testimony.[117] Accordingly, all parties are in agreement with respect to the handling of late payment fees, and the issue is resolved.
118. The record supports the use of a late payment fee factor of 0.53%, to be applied to the final test year firm revenue.
119. In conjunction with its test year expenses affected by additional plant investments, the Company proposed an increase in depreciation expense resulting from the additional new plant investment.[118] For purposes of determining depreciation, the Company used the depreciation rates approved by the Commission in its 2004 Depreciation Study for Depreciable Plant Serving Minnesota, Docket No. G-008/D-04- 1069.[119]
120.
In response, Ms. St. Pierre of the OES noted
that the Company files its depreciation study every five years, the most recent
one of which was filed by the Company on July 14, 2009.[120] Generally,
121. To the extent that the Commission approves the new depreciation rates for the Company in a final order, before the final rates are approved in this case, then Ms. St. Pierre recommended that the test year revenue requirement include the approved depreciation rates.[123] The applicable depreciation rates impact the Company’s test year depreciation expense, accumulated depreciation, and deferred tax.[124]
122. The Company agreed with Ms. St. Pierre’s recommendation, and no other party provided testimony on this matter, thereby resolving the issue.[125]
123. To the extent that the Commission approves the new depreciation rates for the Company in a final order, before the final rates are approved in this case, the final test year revenue requirement for the Company should reflect the newly approved depreciation rates.
124. The Company’s Initial Filing addressed the depreciation expense allocated from CenterPoint Energy Service Company to the Company.[126] Based on a recent analysis performed by the Company, Mr. Nesvig testified that the service lives of the Company’s assets have changed.[127] More specifically, Mr. Nesvig testified that the depreciation rates being used prior to 2008 were too low and the actual life of the assets were much shorter than the lives anticipated when the old depreciation rates were set.[128] As he explained, the adjustment downward with respect to the useful life of the assets at issue, primarily computer equipment and IT software, reflected the changes in the types of computer equipment now in use and the rapid obsolescence of the equipment.[129]
125. Based upon a study performed by an outside consultant, as well as an internal study performed by the Company’s Property Accounting Group, the Company proposed a reduction in the useful life of the assets from 11 to 4.35 years.[130]
126. In response to the Company’s proposed handling of depreciation, Ms. St. Pierre instead proposed a 7-year life for the Service Company’s IT assets.[131] Based on this proposal, the OES recommended a reduction of $312,380 of depreciation expense and the same amount in distributed accumulated depreciation.[132]
127. In Rebuttal Testimony, Mr. Nesvig agreed to the OES proposals, in principle, but noted that some of the reduction in depreciation expense should be assigned to non-regulated operations, and the depreciation expense reduction should be reflected as a reduction in corporate charges, not a reduction in depreciation expense.[133] Of the IT depreciation reduction, Mr. Nesvig identified $211,306 as being attributable to the regulated operation.[134]
128. In response, Ms. St. Pierre agreed with Mr. Nesvig’s conclusion that the OES’s initially proposed adjustment should be reduced, as well as his conclusions that the adjustment should not impact the rate base depreciation reserve and that administrative and general expense, rather than depreciation expense, should be reduced because it is a corporate allocation of costs.[135] Accordingly, Ms. St. Pierre recommended to exclude $211,306 of Administrative and General Expense in the income statement for the Service Company, and withdrew her recommendation to exclude $312,380 of Distribution Accumulated Depreciation in the rate base for the Service Company Depreciation Adjustment.[136]
129. The Company agreed to the OES recommendation, and no other party filed testimony on this issue. Accordingly, the issue is resolved.
130. In the Company’s Initial Filing, it explained that gross plant amounts were calculated by starting with 2007 gross plant data and adjusting it to reflect capital additions and retirements expected to occur through the end of the test year.[137] The Company also made adjustment to remove any capital items that should not be recovered in rates (i.e., non-utility related plant).[138] Specifically, the Company forecasted an average gross plant balance of $1,278,838,000, which was an increase of approximately $111,220,000 over the base year 2007 gross plant balance, and included forecasted amounts for 2008 additions and retirements.[139]
131. In response to an OES information request and other informal requests subsequent to the filing of the case, the Company provided the OES with the Company’s actual 2008 additions, retirements, and depreciation expense for 2008.[140]
132. Based on the availability of 2008 actual amounts for gross plant and accumulated depreciation and amortization rather than forecasted amounts, Ms. St. Pierre testified that test year net plant appeared to be overstated by approximately $4,137,000.[141] As a result, Ms. St. Pierre recommended that gross plant and accumulated depreciation be reduced by $6,204,000 and $2,067,000, respectively, as well as that the Company’s deferred income tax balance be increased by $251,000.[142]
133. The Company agreed to the OES recommendation, and no other party filed testimony on this issue.[143] Accordingly, the issue is resolved.
134. In its testimony filed over the course of the case, the OAG challenged certain travel, meals, lodging, entertainment, customer appreciation, employee recognition and board of director expenses incurred by the Company.[144]
135. In response to the OAG’s concerns, the Company agreed to remove approximately $133,000 in Service Company club membership costs, Service Company charitable contributions and corporate sponsorships, and charges from the Edison Electric Institute that had been allocated to the Company.[145]
136. Furthermore, based upon continued dialogue between the Company and the OAG, the Company agreed to remove from the test year $167,000 for expenses related to travel, meals, lodging, entertainment, customer appreciation, employee recognition and board of director expenses in order to resolve the issue.[146]
137. The Company and the OAG also agreed to a General Expense Reporting Plan, as detailed in Schedule 1 to Mr. Nesvig’s Surrebuttal Testimony, and Schedule JJL-2, as revised, to Mr. Lindell’s Surrebuttal Testimony.
138. No other party filed testimony on this issue.
139. The record supports the reasonableness of the OAG and Company agreements on this issue, resulting in a reduction in test year expenses of $300,000.
140. In the Company’s Initial Filing, it included an adjustment to reflect Conservation Improvement Program (“CIP”) expenses that had been under-recovered in prior years, as well as test year CIP expenses.[147] Consistent with past Commission handling, as well as various statutory directives encouraging conservation, the Company proposed truing up its actual CIP tracker account balance, as of December 31, 2008, against the interim rate refund.[148]
141. In response, Mr. Minder of the OES confirmed that the Company’s proposal was a reasonable way to allow the Company to recover its actual costs.[149]
142. The Company also proposed including the CIP tracker balance as part of rate base.[150] The Company’s rationale was that the projected CIP tracker balance should be included in base rates because it was a working capital item and represented the average projected tracker balance during the test year.[151]
143. In response, the OES recommended excluding the tracker balance from the rate base, instead proposing that the Company be allowed to implement carrying charges to its CIP tracker account balance, effective January 1, 2009, based on the rate of return approved in this proceeding.[152]
144. The Company agreed that Mr. Minder’s proposal was an acceptable alternative, and no other party provided testimony on this matter, thereby resolving the issue.[153]
145. The Company’s Initial Filing included proposed test year advertising expenses.[154]
146. The OES reviewed the reasonableness of the Company’s test year advertising expenses, and proposed that the Commission disallow $3,717 associated with the JD Power and Associates promotion.[155]
147. The Company did not oppose the OES’s recommendation, and no other party testified on this issue.
148. The record supports the reasonableness of reducing test-year advertising expense by $3,717.[156]
149. The Company’s Initial Filing included certain marketing program expenses.[157] These marketing programs focus on providing information about conservation and more efficient gas equipment, which promotes cost-effective, environmentally responsible energy consumption.[158] The Company’s proposed marketing programs and their associated dollar amounts in the test year are the Residential Water Heater program ($294,796), the Foodservice Program ($65,536), and the Commercial and Industrial Market Rebate ($66,890).[159]
150. The OES’s review of the Company’s marketing expenses was guided by the principle that a Company’s marketing program and the recoverability of the costs associated therewith must demonstrate that the marketing program benefits ratepayers (i.e., the marketing program must generate sufficient new revenues to justify the program’s costs).[160] Mr. Minder concluded that the Company’s cost/benefit analysis for its marketing programs is consistent with the OES’s approach, and that its programs provide benefits to ratepayers.[161] Mr. Minder ultimately recommended that the Commission allow the Company to recover its proposed test year marketing expenses for its three Marketing Programs.[162]
151. Notwithstanding this general approval of the Company’s marketing programs and the inclusion of their costs in test year expenses, Mr. Minder added a caveat to his recommendation with respect to the Company’s Residential Water Heater Program.[163] Specifically, Mr. Minder recommended that any natural gas water heater funded under this program must have an energy factor that meets or exceeds the energy factor of water heaters that are eligible for rebate under the Company’s approved CIP.[164]
152. In response to Mr. Minder’s proposal, the Company proposed certain clarifications.[165] First, the Company confirmed that it was willing to add a requirement to the Company’s agreements with builders that required CIP-qualifying water heaters be installed.[166] Second, the Company proposed to grandfather in existing agreements with builders where there was a defined end-term and exclude these agreements from this requirement, but apply the new requirement only to contracts entered into after January 1, 2010.[167] Lastly, the Company proposed to exclude certain water heaters larger than 50 gallons, as there did not appear to be any CIP qualifying water heaters of that size.[168]
153. In Surrebuttal Testimony, Mr. Minder agreed with the Company’s first clarification, as well as the Company’s proposal that this new requirement apply to all new builders’ agreements entered into after January 1, 2010.[169] He also requested that the Company include in a final compliance filing a sample residential water heater program agreement effectuating the minimum energy factor requirement.[170] However, Mr. Minder recommended denial of the Company’s proposal to “grandfather” certain existing agreements with builders, as well as the Company’s proposal to exclude certain water heaters larger than 50 gallons.[171]
154. At the evidentiary hearing, Company witness Mr. Nesvig addressed the items that had not been finally resolved by the parties via their exchange of written testimony.[172] First, the Company confirmed that it was willing to waive its request that certain of its builders’ contracts be grandfathered and exempt from the high-efficiency water heaters.[173] Second, the Company agreed that it was willing to withdraw its request that water heaters greater than 50 gallons be exempt from the minimum efficiency requirement, while maintaining that an exception to the high efficiency water heater requirement for water heaters over 75 gallons was needed if no qualifying models are available on the market.[174]
155. On behalf of the OES, Mr. Minder confirmed his agreement with Mr. Nesvig’s proposed resolution of these issues, thereby resolving the matter. No other party provided testimony on this issue.
156. The Company is a member of the Gas Technology Institute (GTI), an organization that focuses on developing technology to provide improvements in service quality, reduce costs, enhance safety, and provide environmental benefits to the gas industry.[175]
157. In the Company’s last rate case, the Commission approved GTI expenses of $250,000, with various conditions, including that the Company would only support projects that would have a long-term benefit to the Company and ratepayers, and return to ratepayers any portion of the annual expense that was not contributed to GTI.[176]
158. In 2007, the Company contributed $100,000 to GTI and proposed this level to be included in base rates in the future, which reflected a reduction of $150,000 from the base year.[177]
159. Based upon the OES’s review of the reasonableness of the proposed inclusion of $100,000 in rates, and the Company’s compliance with the Commission’s prior docket, Mr. Minder recommended that these expenses be approved, including the Company’s proposed inclusion in the interim rate refund of the beginning test year liability account balance of $530,000.[178] In addition, Mr. Minder recommended various conditions associated with his recommended approval of the GTI expenses, including, among other things, ongoing compliance with various parts of the Commission’s Order relating to GTI expenses from the Company’s last rate case.[179]
160. The Company agreed to the OES’s proposed conditions and no other party provided testimony on this matter, thereby resolving the issue.
161. In the Company’s filing, it proposed the recovery of various organizational dues.[180] The Company testified that memberships in organizations allow CenterPoint Energy employees to obtain information and make contacts with others, enabling them to be better informed with respect to industry issues and learn new and improved ways of dealing with those issues and better meet the needs of ratepayers.[181]
162. In his Direct Testimony, OES witness Mr. Johnson did not dispute the Company’s organizational dues, with the exception of $15,360 for the Company’s membership in Minnesota Utility Investors (MUI).[182] Mr. Johnson recommended a reduction in test year expenses of $15,360 to remove the MUI dues from the test year.
163. The Company agreed to the OES’s recommendation to disallow this expense for purposes of resolving the issue in this case, and no other party provided testimony on this issue.[183]
164. The record supports the reasonableness of excluding $15,360 in MUI dues from the test year.
165. Although the issue was not specifically addressed in the Company’s Direct Testimony, the Company presented in Volume I, Schedule C-3(a) of its filing various calculations relating to the deduction of interest and other charges in calculating its net income before income tax.[184]
166. As OES witness Mr. Johnson explained in his testimony, when an adjustment is made to the Company’s weighted cost of debt, test year rate base, or operating income statement, it necessarily requires that an interest synchronization adjustment be made.[185] Based upon the Company’s use of interest synchronization in the calculation of its income taxes, and the OES’s proposed adjustments to the test year, the OES ultimately recommended an adjustment decreasing the Company’s test year expense.[186]
167. Mr. Nesvig confirmed during the evidentiary hearing that Mr. Johnson’s proposed interest synchronization methodology was acceptable to the Company, and no other party provided testimony on this issue.[187]
168. A final adjustment for interest synchronization should be calculated, as proposed by the OES, after all of the other adjustments are finalized in the case.
169. In its Initial Filing and in Mr. Nesvig’s Direct Testimony, the Company described that it had included cash working capital in its test year rate base and explained the methodology used to calculate it.[188] Mr. Nesvig testified that the Company prepared a new lead-lag study for this rate case using 2007 calendar year data, which followed the same methodology that was approved in CenterPoint Energy’s previous rate cases.[189]
170. The OES reviewed the Company’s lead-lag study and had no concerns.[190] The OES also reviewed the Company’s calculation of cash available from tax collection. Due to other adjustments being proposed by the OES, Mr. Johnson recommended that the test year cash working capital also be adjusted for the lead-lag study, noting that cash working capital will ultimately have to be adjusted to reflect the Company’s approved expense levels.[191]
171. The Company agreed with the OES recommendation, and no other party filed testimony on this issue, thereby resolving the issue for this case.
172. In accordance with its tariff, the Company is allowed to charge customers a fee to recommence gas service after the meter has been locked for non-payment.[192] As approved by the Commission in its prior rate case, CenterPoint credited the bad debt expense account on the income statement with the reconnect charges.[193]
173. In the OES’s Rebuttal Testimony, Ms. St. Pierre proposed that the Commission require that the reconnect charges be included in Other Revenue as it is a tariff-governed rate that she believed should be considered revenue for ratemaking purposes.[194]
174. In response, Mr. Nesvig agreed that including reconnect charges in Other Revenue, rather than as a credit to net write-off expense, was reasonable.[195] Mr. Nesvig pointed out, however, that there should be no impact on the test year revenue requirements by making this change.[196] Accordingly, he proposed that, if test year Other Revenue is increased to reflect the transfer of reconnect charges to that account, test year bad debt expense should be increased by that same amount.[197]
175. Ms. St. Pierre disagreed with the Company’s position, questioning the Company’s position that there was a direct dollar-for-dollar link between the test year level of bad debt expense and reconnect revenue and stating that there was no way to determine how much the test year bad debt expense should be increased when considering the reconnect charges.[198] In conjunction with her testimony, Ms. St. Pierre recommended that the Company include $582,000 in Other Revenue in the test year revenue requirement without an offsetting increase to bad debt.[199]
176. Ms. St. Pierre also recommended a proposed increase in revenue of $194,000 if the Company’s proposal to increase the reconnect charge from $22.50 to $30.00 was approved.[200]
177. During the contested case hearing, Mr. Nesvig stated that for purposes of this rate case, the Company accepts the OES position to include $582,000 in Other Revenue in the test year revenue requirement without an offsetting increase to bad debt expense.[201]
178. Mr. Nesvig also agreed with Ms. St. Pierre’s calculation of an increase in revenue of $194,000 if the Company’s proposed $30.00 reconnect charge was approved.[202] However, the OES opposed any increase in the reconnect charge in this case. The Company accepts the OES position on this matter. Thus, no adjustment is required.
179. The Company’s filing reflected various test year adjustments attributable to distribution system operating and maintenance expense increases, including atmospheric corrosion inspections, easement clearings, pipeline integrity inspections, pipe coating, and the painting of regulator stations, as well as copper riser replacements and carbon monoxide (CO) checks.[203]
180. In accordance with federal regulations, the Company is required to inspect meters for atmospheric corrosion every three years.[204] Based upon an average of 50,000 meter inspections each year, the Company’s filing included an increase of $203,216 necessary to cover the incremental increase in inspections.[205]
181. The Company also projected an increase of $676,700 in costs, for a total of $815,000, associated with pipeline integrity work.[206] The increase in costs is attributable to an increase in the number of inspections and a significant increase in cost per mile of pipeline assessed.[207] The increase is also due to assessing the integrity of transmission pipeline inside casings in High Consequence Areas in accordance with federal regulations, which involves stripping off the casing from around the pipe, performing a visual inspection of the external surface of the pipe, making necessary repairs, and recoating and reburying the pipe.[208] This was not required during previous years of the pipeline integrity program.[209]
182. The Company also plans on spending an additional $100,000 in the test year on corrosion protection relating to coating of pipe under bridges and the painting of regulator stations.[210] In accordance with federal law, gas mains on bridges are inspected every three years and maintenance or repairs are performed where necessary.[211] The coating of pipe under bridges curtails corrosion and reduces the need for more costly maintenance.[212] The increase will allow the Company to paint 10 of its 88 system bridges, which is based on the annual average activity in 2005 and 2006.[213] With respect to the painting of regulator stations, based upon an average cost of $2,000 per station, the Company projects that it will be able to paint 25 sites in 2009.[214]
183.
Lastly, the Company projected a test year
increase in carbon monoxide (CO) checks resulting in an increase in costs of
$329,231.[215] By way
of background, the Minnesota Legislature passed legislation requiring all homes
to have a CO alarm in their sleeping area.[216] Based
upon an estimate of a major manufacturer, only 30% of
184. No party other than the Company presented any evidence on these distribution system expenses. The record supports the Company’s position, and it should be adopted.
185. In the Company’s Initial Filing, Mr. Nesvig sponsored testimony detailing CenterPoint’s customer receivable collection costs.[220] As Mr. Nesvig explained, the Company’s test year collection costs reflected an expected $1.1 million decrease in collection costs for 2009 as compared with the base year.[221] The reduction in collection costs were largely attributable to lower field visit and call center costs, which were partially offset by an increase in costs to gain access to meters that the Company had been unable to access through normal procedures.[222]
186. No party other than the Company presented any evidence on these distribution system expenses. The record supports the Company’s position, and it should be adopted.
187. Due to an increase in the number of customers from the base year to the test year, the Company’s filing included an adjustment reflecting an increase in billing costs.[223] The Company’s increased costs relate to the increased number of bills and envelopes, postage, bank fees, and meter readings.[224] The costs were based on actual 2007 costs per customer applied to the number of new customers forecast between the base year and test year.[225] No party presented any conflicting evidence on this issue. The record supports the Company’s position, and it should be adopted.
188. Due to ongoing Commission concerns regarding utility phone service levels and complaint resolution times, as well as ongoing discussions with the OES, the Company proposed a test year adjustment reflecting the incremental costs necessary to achieve an 80/20 service level (i.e., 80% of the calls answered within 20 seconds in 2009 in contrast to the Company achieving a 70/30 service level, 70% of calls answered within 30 seconds, in 2007).[226] The proposed adjustment also reflects labor and outside contractor costs necessary to improve phone answer time during peak periods and provide additional complaint tracking and reporting.[227]
189. To the extent that the Commission determines that a 70/30 service level remains appropriate, rather than the 80/20 service quality level, the Company also detailed its increased costs of $160,000 necessary to maintain this level of service, which is attributable to increase call volumes.[228] No other party to the proceeding presented testimony on this issue.
190.
Based upon the addition of certain new
positions, as well as the elimination of others, the Company’s complement
changed for the test year.[229] The
complement adjustment was calculated by examining, on a
department-by-department basis, changes in complement from base year to test
year and the payroll changes associated with each.[230] The
impact to the Company’s operating expenses was a reduction of approximately
$216,000 in the test year.[231]
191.
No other party presented any evidence on this
issue. The record supports the Company’s position, and it should
be adopted.
192.
The Company proposed an adjustment in expenses
attributable to an increase in
general liability and auto claims.[232] Based
upon the outcome of the Company’s
2005 rate case, and due to the fact that the size of claims can vary significantly, the Company calculated
the increase using a four year average of actual claims activity attributable to regulated operations for the time
period of January 2004 through
December 2007.[233] The four
year average claims cost was compared to that of the base year to calculate the test year adjustment.[234]
193.
No other party presented any evidence on this
issue. The record supports the Company’s position, and it should
be adopted.
194.
On July 8, 2009, the Commission ordered the
parties to this case to review Gas
Affordability Program (“GAP”) administrative costs to determine whether any additional costs above those
permitted by the Company’s tariff were included in the test year and, if so, whether the
inclusion of such costs were appropriate.[235] As Mr.
Nesvig explained, other than
those administrative costs included in the GAP tracker, there were no administrative costs included in
the test year.[236] This was
because the test year calculations
only included 2007 base year adjusted for known and measurable changes.[237] As there
were no GAP administrative expenses in the base year, the Company did not include any GAP expenses in the test
year.[238]
195.
Mr. Nesvig also testified that even if an
alternative sales forecast is adopted by
the Commission, there is no impact on GAP administrative expenses since the
level of expenses is capped at
$5 million per year.[239] Instead
of changing the level of administrative
expenses, the GAP recovery rate would need to change, so that the total dollar amount recovered (and
recognized as an expense) would continue to equal the $5 million allowed under the GAP tariff.[240]
196.
No other party presented any evidence on this
issue. The record supports the Company’s position, and it should
be adopted.
197.
With the Next Generation Energy Act (“NGEA”),
the 2007
198. The NGEA also provides that
It is the energy policy of the state of Minnesota to achieve annual energy savings equal to 1.5 percent of annual retail energy sales of electricity and natural gas directly through energy conservation improvement programs and rate design, and indirectly through energy codes and appliance standards, programs designed to transform the market or change consumer behavior, energy savings resulting from efficiency improvements to the utility infrastructure and system, and other efforts to promote energy efficiency and energy conservation.[242]
199.
Recognizing the inherent conflict between an
energy company’s legitimate need to earn profits for its shareholders and its
obligations to encourage consumers to use less energy, the legislature enacted
Minn. Stat. § 216B.2412, which requires the PUC to establish criteria and
standards and to approve pilot programs for
“decoupling” energy sales from revenues.
The statute defines “decoupling” as
a regulatory tool
designed to separate a utility’s revenue from changes in energy sales. The purpose of decoupling is to reduce a
utility’s disincentive to promote energy efficiency.[243]
200.
Decoupling
is a significant departure from a traditional rate structure. A traditional rate structure provides
for the recovery of most of a utility’s fixed costs on a volumetric basis.[244] This
structure motivates the utility to maximize its revenues by increasing its sales above
that established in its most recent rate case.[245] As
CenterPoint Energy witness Feingold explained: “Every utility that has its
rates structured with volumetric rate components has a throughput incentive to
maximize its sales volumes because that action maximizes its sales revenues.”[246] Under such
a structure, a utility is not financially motivated to pursue conservation. Rather, a traditional structure creates an
automatic disincentive for utilities to promote conservation or energy
efficiency initiatives, since such actions will only reduce the utility’s revenues
and resulting earnings.[247] The legislature also directed the PUC to
establish criteria and standards for decoupling “to mitigate the impact on
public utilities of the energy-savings goals
. . . without adversely affecting utility ratepayers.”[248]
201.
The
legislature granted the PUC substantial discretion in its design of the
criteria and standards for review and approval of decoupling programs requiring
that:
The commission shall, by order, establish criteria and standards for decoupling. The commission shall design the criteria and standards to mitigate the impact on public utilities of the energy savings goals under section 216B.241 without adversely affecting utility ratepayers. In designing the criteria, the commission shall consider energy efficiency, weather, and cost of capital, among other factors.[249]
202. In its Order Establishing Criteria and Standards to be Utilized in Pilot Proposals for Revenue Decoupling, the Commission determined that it was not
ready at this juncture to set final criteria and standards regarding decoupling, believing that the most promising approach is to examine the pilot proposals that will be submitted based on the criteria and standards established by this Order. After implementation and review of these pilot projects, utilities will be in the position to tackle the details of implementing an effective decoupling program.[250]
203. Nonetheless, the Commission did adopt standards in the Order, and specifically required the Company to file additional information describing how its decoupling proposal meets those standards as part of this rate case.[251]
204. The Commission’s criteria and standards require that a utility proposing a decoupling program
shall state the form of decoupling proposed and the purpose behind such choice. This should provide a detailed definition of what types of sales changes are included in the mechanism, i.e. weather-related sales changes, declining use per customer, etc. and the reason for such inclusion.[252]
205. The Commission’s Order requires that all utility decoupling proposals provide information addressing:
a. how the decoupling structure “adheres to the guiding statute;”
b. what form it will take;
c. how the cost of capital will or will not be impacted;
d. which classes will be included;
e. how the decoupling mechanism will operate; and
f. how service quality will be maintained.[253]
206. The Order also requires yearly review of pilot programs, with detailed information to be provided by the utility; and includes some specific requirements for implementation of the pilot programs.[254]
207. In its Initial Filing, CenterPoint proposed a pilot decoupling program and accompanying Conservation Enabling Rider to fully decouple the Company’s sales from its revenues in order to remove the financial harm to the utility from aggressively pursuing energy efficiency and energy conservation.[255]
208. Subsequently, the Company, the IWLA/MCEA, and ECC (Stipulating Parties) entered into a Stipulation which:
a. modified the originally proposed Decoupling program and accompanying Rider by: (a) excluding adjustments based on variations in weather; (b) instituting a “cap” of the amount of any upward or downward rate adjustments based on the stipulation; and (c) providing an inverted black rate structure for gas costs for certain rate classes;
b. specified that no adjustment to the Company’s authorized cost of capital is appropriate due to Commission approval of the Decoupling Program;
c. provided that the Stipulating Parties support the Company’s proposed Residential and Commercial/Industrial rate design as set forth in the Company’s initial filing, including a residential monthly basic charge of $8.00;
d. required the Parties to work cooperatively to identify and implement new conservation programs, modifications to existing programs and new delivery mechanisms, including programs identified in the recent conservation and efficiency “potential study” performed by Navigant consulting (the “Navigant Report”) and programs targeting high consumption LIHEAP households and low-income renters.
209. The Commission requires a utility proposing a decoupling program to state how its
proposed decoupling mechanism adheres to the guiding statute. Each utility shall explain the purpose of their mechanism in the context of the New Generation Energy Act of 2007’s savings goals and how their mechanism will further the state policy of increased conservation investment.[256]
210. The Decoupling Program separates the Company’s revenue from changes in energy sales, with the exception of the impact of weather by comparing the “allowed revenues” (defined as the Commission-approved revenue per customer as established by this rate case multiplied by the number of customers) to the “weather normalized revenues” and providing for recovery (or refund) of the difference.[257]
211. The recovery or refund will result in an annual adjustment of the delivery charge per therm for each included rate class.[258] This adjustment is subject to a 4% plus or minus cap. This means that the actual volumetric charge will neither increase nor decrease by more than 4% from one twelve-month period to the next.[259]
212. The decoupling mechanism provides the Company with a mechanism to recover financial losses due to reduced sales (except for reduced sales due to abnormally warm weather) without filing a general rate case. This automatic adjustment is intended to remove the Company’s disincentive to pursue efficiency and conservation efforts that will reduce gas sales.[260]
213. Representative Kalin and Senator Dibble, the chief House and Senate authors of the NGEA provisions addressing energy efficiency and conservation, including the Decoupling Statute, agreed that the Decoupling Program is consistent with the statute and will further the policy of increased conservation investment.[261] The legislators both expressed their support for the Decoupling Program, stating that “the goal of decoupling is to remove utility disincentives to focus greater investments in cost effective energy efficiency and conservation.”[262] The chief authors indicated that they believe the Decoupling Program “will accomplish this objective.”[263]
214. The record demonstrates that the Decoupling Program will not adversely affect utility ratepayers because the per therm delivery charge to which the adjustment will apply is part of the much smaller portion of a ratepayer’s bill. Approximately 80% of a ratepayer’s bill is attributable to the cost of the gas itself. The per therm delivery charge is part of the other 20% of the bill, which also includes the basic monthly fee. That will only increase if the ratepayer’s gas usage, and thus the charge for gas, decreases. Consequently, with decreased gas usage, the overall bill will decrease and the ratepayer will not be adversely affected.[264]
215. Other conservation and industry organizations, including the Natural Resources Defense Council and the American Gas Association, support decoupling programs similar in concept to the Decoupling Program in this case. These organizations cite added benefits such as customers saving money by using less natural gas; reduced stress on the market resulting from reduced overall use helping to push down short-term prices; enhancing state policies to encourage economic development by increasing energy efficiency and lowering business costs; and support of state policy objectives and the public’s desire to use energy efficiently and wisely.[265]
216. The Commission’s second criterion and standard for decoupling programs requires the utility to
state the form of decoupling proposed and the purpose behind such choice. This should provide a detailed definition of what types of sales changes are included in the mechanism, i.e. weather-related sales changes, declining use per customer, etc., and the reason for such inclusion.[266]
217. The Commission defined “full” decoupling as a structure which “insulates a utility’s revenue collection [from] any deviation of actual sales from expected sales.” It distinguished “full” decoupling from “partial decoupling,” which, it said, “operates much like full decoupling, except a deviation from actual sales is only partially trued up. Limited decoupling limits adjustments for sales losses derived only from specific causes, such as weather or conservation efforts.”[267]
218. The Stipulating Parties agreed to a partial decoupling mechanism that will adjust rates for changes in use per customer not including weather-related changes.[268]
219. The partial decoupling mechanism agreed to by the Stipulating Parties does not exclude such other causes of changes in use per customer as declining use due to economic conditions, high gas costs, building codes or appliance standards.[269]
220. The Commission’s third criterion and standard requires the Company to “detail how [its] proposed mechanism will/will not impact the company’s cost of capital.”[270]
221. To determine the representative cost of capital, the embedded costs of each of the three elements in the capital structure are weighted by the long-term debt ratio, short-term debt ratio, and equity ratio, respectively. The sum of these weighted costs is the overall rate of return on capital.
222. The Company projected costs for 2009 of 5.79 percent for long-term debt and 3.53 percent for short-term debt.[271] Dr. Griffing accepted these costs and used them in his ROE analysis, along with his recommended rate of return on equity of 10.24 percent, as shown in the table below which shows the overall ROR of 8.09 percent on the Company’s total capital.
CenterPoint’s Overall Rate of Return
Percent Weighted
Component of
Total % Cost Average Cost
Long-Term Debt 45.76% 5.79% 2.65%
Short-Term Debt 1.70% 3.53% 0.06%
Common
Stock Equity 52.55% 10.24% 5.38%
Total 8.09%
223. The Company provided substantial information and analysis to the record regarding any impact of the Decoupling Program on the Company’s cost of capital.[272] Company witness Mr. Hevert testified that the CE Rider originally proposed by the Company did not warrant any adjustment to the Company’s cost of capital.[273] He reached this conclusion after fully examining the proxy group used to estimate CenterPoint Energy’s cost of equity. That analysis demonstrated that seven of the nine proxy group companies have in place some form of rate structure that eliminates or lessens the throughput incentive by addressing the disparity between sales volumes used to develop rates and sales volumes actually realized, with five of the nine proxy group companies having greater than 50% of their operations covered by such a mechanism.[274] In addition, when other rate design mechanisms are incorporated into the analysis, “all of the proxy companies employ tariff structures across the majority of their operations that mitigate declining use per customer.”[275]
224. Mr. Hevert also analyzed the potential impact of the CE Rider on the credit rating of CenterPoint Energy. As he noted, “it appears that rating agencies will not necessarily upgrade the credit of a utility for the approval of a decoupling mechanism; however, a company without full revenue decoupling stands a greater risk of potential downgrade.”[276] This results from the increasing prevalence of decoupling mechanisms and weather normalization adjustments, such that:
rating agencies increasingly view decoupling mechanisms in the context of a set of revenue stabilization mechanisms, and the implementation of such structures as the status quo for natural gas utilities. The implication is that some form of revenue stabilization is expected, and companies without such protection may be susceptible to negative actions from the rating agencies.[277]
225. OES cost of capital witness Dr. Griffing agreed that adoption of the Decoupling Program should not lead to a downward adjustment to the Company’s cost of capital.[278] In Dr. Griffing’s view, “a company’s debt rating captures all factors that affect risk and to single out a [decoupling mechanism] as a reason for adjustment is to count it twice.”[279]
226. This testimony, like Mr. Hevert’s testimony, focused on the Company’s originally proposed CE Rider. By agreeing to the decoupling program, the Company has removed variations in weather from the decoupling mechanism. Of Mr. Hevert’s proxy group companies, all but one has a rate structure in place that mitigates the effect of weather on usage. Thus, the decoupling program would represent “a significant difference from the proxy group companies that would indicate a more, not less risky position for CenterPoint,” further supporting a determination that no cost of capital adjustment is appropriate if the Commission approves the Program. [280]
227. The OAG offered no testimony as to the appropriate rate of return for CenterPoint Energy. The OAG suggested that a downward adjustment be made to the Company’s return on equity if decoupling is approved, but offered no testimony specifying what size adjustment, if any, should be made to the Company’s rate of return if the Program is adopted. [281]
228. In its Initial Brief, the OAG for the first time, presented a proposed minimum adjustment of “no less than 27 basis points” to the Company’s return on equity. The OAG made this recommendation without regard for what return on equity is approved for the Company and without consideration of the comparable group analyses of Mr. Hevert or Dr. Griffing.
229. The OAG calculated its 27 basis point adjustment based on a table of regulatory decisions from other jurisdictions. However, the OAG table ties any reduction in ROE for the Companies listed to the existence of a decoupling program, even when the regulatory Commissions involved made no reference to such a program, as opposed to changes in underlying economic conditions or other factors that might influence a utility’s ROE. [282]
230. The OAG proposal is not adequately supported. The Company and OES expert witnesses demonstrated that approval of the decoupling program does not necessitate an adjustment to the Company’s cost of capital.
231. On the other hand, if the Commission does not approve the decoupling program, the Company seeks an increase in its cost of capital. It argues that then CenterPoint Energy would be comparatively more risky than the proxy group and that the heightened risk, when compared to the proxy group, would require a higher return for CenterPoint Energy than an unadjusted proxy group analysis would indicate.[283]
232. Company ROE witness Mr. Hevert proposed a 20 basis point upward adjustment. He testified that “it has become apparent that revenue decoupling mechanisms simply lend the implementing companies the ability to ‘maintain their credit ratings or stabilize their credit outlooks.’” He further testified that while the implementation of revenue decoupling mechanisms has not increased any utility’s debt rating, the rejection of a decoupling structure has resulted in a rating downgrade in at least one instance. After the Arizona Commission denied a decoupling proposal by Southwest Gas, its debt rating was downgraded one rating notch; and Mr. Hevert’s analysis of the average yield on two debt issuances, one before and one after the downgrade, showed an impact of 55 basis points.[284]
233. Mr. Hevert acknowledged that the lack of data makes it difficult to estimate the effect on the Company’s cost of capital if the pilot decoupling program is denied.[285]
234. The OES opposed any upward adjustment to the Company’s ROE in the event of denial of the decoupling program. OES witness Griffing testified that no single element of a Company’s risk profile should be the basis for an adjustment to ROE, either upward or downward.[286] Rather, Dr. Griffing opined that his comparable group already reflected companies sufficiently similar to CenterPoint Energy that no adjustment was required.[287]
236. In its fourth criterion and standard, the Commission states that “[a]ll utilities must identify the rate classes involved in the pilot, as well as provide rationale for the inclusion of participating classes and the exclusion, if any, of other classes.”[288]
237. The Commission also specifically required that all decoupling pilot programs be implemented in more than one customer class.[289]
238. The Decoupling Program includes the Residential class and the Commercial/Industrial A, B and C classes. The Program is extended to these four classes because the Company believes the customers in these classes are most likely to be impacted by future conservation efforts and have shown significant decreased usage per customer.[290] While in the past the Company may have realized the majority of its conservation savings in its largest industrial classes, that no longer holds true.[291]
239. The Navigant Report identified the incremental energy savings over the next three years coming primarily from the residential market.[292] Over the next ten years, residential gas usage is predicted to be relatively flat, while commercial and industrial usage are each expected to rise.[293]
240. The Program does not include any of the dual fuel classes, because these classes are more likely to be industrial customers and use natural gas for processing. Therefore, their usage is tied more to general economic conditions, rather than energy efficiency or other factors that are causing the declining use per customer seen in the small volume firm classes.[294] In addition, these classes can include market rate customers that should not be subject to decoupling rate adjustments because these market rate customers have rates governed by contract that would not allow the Company to implement the CE Rider for those customers.[295]
241. The fifth criterion and standard adopted by the Commission requires:
All utilities must provide precise detail on how the decoupling mechanism will operate, with the understanding that any decoupling pilot program be transparent and easy to follow from a customer perspective. Details to be provided are as follows:
a. how rate adjustments will be calculated;
b. when rate adjustments will be made;
c. whether a rate cap or collar is provided to mitigate the risk of rate shock and justification for not so providing if a proposal lacks such safeguards;
d. what portion of the customer’s bill will be impacted by the true-up (volumetric vs. customer charge);
e. how will the rate adjustment be displayed on the customer’s bill;
f. length of pilot (with the understanding that no pilot may extend longer than 36 months except through implementation in a rate case);
g. how the decoupling mechanism will work in concert with any automatic recovery mechanism or financial incentive; this evaluation requires that all utilities provide a list of all automatic recovery mechanisms and incentives as well as justification for any such mechanism/incentive that the utility plans to continue throughout the course of the pilot including an explanation as to how the decoupling pilot mechanism, coupled with any other automatic adjustments and incentives, will not result in double recovery.[296]
242. The Stipulating Parties set forth the general mechanics of the Program in the revised proposed CE Rider.[297]
243. The most notable differences in the mechanics of the Program, as compared to the Company’s original proposal, are the exclusion of weather variations and the incorporation of an inverted block gas cost (IBGC) rate structure, described in Findings 273 through 278 below.[298]
244. The draft CE Rider tariff describes the calculation of the rate adjustments under the Program.[299] The calculation will be done annually on a class-by-class basis and applied on a per-therm basis. Each year, the Company will file detail with the Commission showing its “authorized revenues,” equaling the authorized revenue per customer as determined in this rate case multiplied by the number of customers in the class.[300]
245. The Company will also provide detail showing the “weather normalized revenues,” equaling the actual non-gas revenues for the period, adjusted for non-normal weather, unbilled non-gas revenues, and other rider revenues.[301]
246. The Decoupling Program requires the Company to show its calculation of the “CE Rider Adjustment,” which will take the allowed revenues, subtract the weather normalized revenues and divide that figure by the class forecast volumes for the twelve month period beginning March 1 of the year the report detailing these calculations is filed.[302]
247. For purposes of this “forecast,” the Company proposes to use the sales per customer results of this rate case, updated for the projected number of customers. Given that the Company continues to experience customer count growth on its system, this methodology will result in a higher forecast of sales compared to simply keeping the class sales volumes static from the test year levels established in this rate case.[303] As such, this methodology will lead to a lower overall adjustment than would occur if the adjustment were simply calculated on the basis of test year sales.
248. The rate adjustment will be filed as part of an annual Evaluation Report by March 1 of each year; and effective with bills rendered on or after March 1 of the year in which the Rider Evaluation Report is filed.[304]
249. The Decoupling Program limits the size of any adjustment to no more than 4% upward or downward on a per unit basis. The +/- 4% “cap” applies to the total volumetric charge for each of the rate classes included in the Decoupling Program. This “cap” is intended to ensure that the Decoupling Program will not adversely affect utility ratepayers or the Company, while still pursuing the other statutory goals and purposes.[305]
250. To the extent that the Program actually triggers the “cap” limiting the size of an upward adjustment in rates, the trigger will necessarily mean that natural gas usage, and consequently the larger portion of the affected customers’ bills, has declined significantly, consistent with the goal of the NGEA.
251. The draft CE Rider provides that the adjustment will be applied to the delivery charge on a volumetric basis.[306]
252. The Stipulating Parties proposed including the adjustment in the delivery charge, rather than displaying it as a separate line item on the customer’s bill.[307] The Company asserted that creating a separate line item on the bill would result in higher administrative costs for the Company that would ultimately be borne by customers.[308]
253. The Company did not provide any evidence regarding the administrative cost involved in adding a line item on customer bills to display billing adjustments in delivery charges made as a result of the Decoupling Program.
254. OES and OAG/RUD object to including the adjustment in the delivery charge rather than displaying it as a separate line item. OES asserts that this creates a lack of transparency which is “a major flaw” in the Decoupling Program.[309] Unlike traditional regulation where the delivery charge is set and remains the same between rate cases, customers affected by the Decoupling Program would see the delivery charge change with no explanation of the reason for the change.[310] This lack of transparency will make it difficult for customers provide feedback to the PUC needed to analyze the effectiveness of the Decoupling Program.[311]
255. The Decoupling Program has an initial three year term.[312]
256. The Decoupling Program excludes gas revenues and revenues associated with the Conservation Improvement Program Adjustment Rider, the Gas Affordability Service Program, the Franchise Fee Rider, the Conservation Improvement Program revenues collected through base rates, the proposed Bad Debt Expense Recovery Mechanism and other non-rate class specific revenues from the calculations of any CE Rider adjustment.[313]
257. The Company’s current Demand Side Management Financial Incentive is dependent on several factors, including energy savings achieved, the amount of spending on conservation and the degree of cost-effectiveness of its CIP program, and is not linked to the Company’s earnings.[314] The Company is not awarded “lost margin” recovery in its incentive plan. The Decoupling Program removes the financial disincentive to the Company from pursuing conservation or energy efficiencies due to the negative impact of such usage reductions on CenterPoint Energy’s non-gas revenues.[315]
258. The Demand Side Management Financial Incentives granted to CenterPoint have decreased from a high of $2,129,167 for 2005 to $530,405 for 2007. The Company’s request $483,993 for 2008 is pending.[316]
259. The Decoupling Program and the Demand Side Management Financial Incentive are separate but complementary approaches to achieving greater conservation and energy efficiency goals. Unlike the Decoupling Program, the Demand Side Management Financial Incentive does not address the disincentive the Company faces when it is asked to encourage conservation by its customers.
260.
The Decoupling Program and any incentive
mechanism serve complementary purposes, with both aimed at increasing the
likelihood of achieving
261. As its sixth criterion and standard the Commission requires that:
All utilities must provide detail on how the utility plans to measure and maintain service quality under the pilot program, consistent with any service quality standards or reporting requirements established in other dockets. Phone answer time, gas emergency response time, missed appointments for service installations, time to reconnect service, and number of customers disconnected for non-payment should all be addressed in a pilot service quality evaluation.[317]
262. The Stipulating Parties agreed that CenterPoint Energy will continue to provide quarterly service quality reports, which currently measure and report:
a. Gas System Reliability – specifically Gas Service Interruptions (both the number of customers and the average duration of unplanned service interruption), Gas System Damages (as reported to the Minnesota Office of Pipeline Safety) and Emergency Response Times (as reported to the Minnesota Office of Pipeline Safety);
b. Mislocate Rate – as reported to the Minnesota Office of Pipeline Safety;
c. Phone answer time – including the average speed of answer, the total number of calls and the number of calls received through dedicated lines;
d. Customer Complaints – specifically, the number of complaints received from state agencies (and the Better Business Bureau) and in the company’s call center; and
e. Customer Service Expenses – CenterPoint Energy currently reports the total amount of customer service related operating expenses.[318]
263. The Stipulating Parties noted that Company currently reports the number of customers disconnected for non-payment and will incorporate that information into its annual Evaluation Report (described in Finding 268 below). The Stipulating Parties also agreed that CenterPoint Energy will measure and report information regarding missed appointments for service installations and time to reconnect service as established by the Commission in its investigation into Gas Utility Service Quality Standards (Docket No. G-999/CI-09-409).[319]
264. In addition, the Stipulating Parties agreed that, as part of its initial Evaluation Report Filing, CenterPoint Energy will provide recent historical information on the above metrics which it has available, in order to assist the Commission in determining a “baseline” service quality level prior to implementation of the Program.[320]
265. CenterPoint Energy will fully comply with any other service quality reporting obligations established in other dockets.[321]
266. No party suggested further or different service quality measures, and the record supports approval of the Decoupling Program with respect to service quality issues.
267. The Commission’s final criterion and standards require that:
All utility pilot proposals shall be reviewed yearly. If the Commission determines that the pilot is harming ratepayers and/or failing to meet objectives, the Commission may suspend the pilot at any time or recommend modifications. As part of their annual review, all utilities shall provide information that shall be specified in an evaluation plan established as part of the pilot plan that shall include, but not be limited to the following information:
a. total adjustments by class
b. total adjustment charges collected (or refunded)
c. number of customer complaints
d. has the pilot stabilized revenues for the class(es) and how has such stabilization impacted the utility’s overall risk profile
e. comparison of how revenues under traditional regulation would have differed from those collected under the decoupling pilot
f. is the utility meeting energy efficiency savings goals? Has the decoupling pilot influenced the achievement or likelihood of achievement of those goals?
g. problems encountered and improvements/suggestions for the future.[322]
268. The Stipulating Parties agreed that CenterPoint Energy will provide all such information as part of its annual Evaluation Report Filing.[323] In addition, the Stipulating Parties agreed that as a part of each annual filing, the Company will provide:
a. a summary of the nature of any complaints received regarding the Program;
b. specific discussion of how the decoupling pilot has influenced the Company’s progress toward meeting the State’s energy efficiency goals;
c. a report of the Company’s expenditures related to conservation, together with a comparison of those levels to historic levels;
d. To the extent that “weather normalized revenues” fell short of (or exceeded) “allowed revenues,” a discussion and quantification, where possible, of the factors leading to that shortfall (or excess).[324]
269. The OES supports a significantly more detailed evaluation protocol than the one required by the Commission’s Decoupling Order.[325] The evaluation protocol recommended by Mr. Chavez is one required by the Washington Utilities and Transportation Commission for Avista Utilities.[326] That protocol focuses more heavily on the effectiveness of the Company’s conservation programs than on the Decoupling Program itself.[327]
270. The Company points out that, to the extent that CenterPoint Energy reaches the energy savings milestones of the NGEA, that achievement will have resulted from a wide range of utility, customer and energy industry related factors, including the Decoupling Program.[328] Because of this, the kind of detailed information sought by OES is not feasible.[329]
271. The fundamental evaluation “metrics” the Commission has set forth in its Decoupling Order will be consistent with the approach taken by other states – observing the Company’s overall approach to efficiency and conservation, the resulting achievements of the Company’s energy conservation programs, and the increased efficiency with which energy is used on the Company’s system.[330]
272. The record reflects that the Program set forth in the Stipulation meets the terms of the Decoupling Statute and utilizes the criteria and standards established by the Commission in its Decoupling Order. As such, the Program should be approved.
273. The IBGC would extend to the Residential and Commercial/Industrial A and B classes.[331] Commercial/Industrial C customers were not included since this class is less homogeneous than the smaller classes and has a lower but no upper limit on usage, making it difficult to set blocks.[332]
274. For those classes included, the IBGC structure is designed to lessen the financial burden on low use customers and increase the conservation signal to high use customers. The blocks were established to be revenue neutral overall, as compared to gas cost recovery without the inverted block rates.[333] The first block covers the average winter usage, the second block covers 80% of the average winter usage, the third block takes in 120% of average winter usage, the fourth block 150% of average winter usage, and the last block encourages reduction in peak usage, with increasing opportunities for energy savings available to customers as the blocks increase.[334]
275. The Company opposed the IBGC structure in the absence of the Decoupling Program. Because this structure should lead customers using natural gas in the higher blocks to increase their conservation efforts and reduce usage, the Decoupling Program must be implemented in concert with the IBGC structure to alleviate the financial harm that the reduced usage would otherwise impose on the Company.[335]
276. ECC strongly supports the IBGC because, in general, natural gas and other energy use tends to increase with household income. Therefore, low-income customers who are also often low-use customers will pay less under the IBGC design than they would otherwise pay for gas, which makes up a significant majority of most customers’ bills.[336]
277. The IWLA and MCEA support the IBGC because it will encourage conservation by sending a positive price signal to customers who conserve.[337]
279. In addition to the terms of the Decoupling Program, the Stipulating Parties agreed to:
work cooperatively, on a going forward basis, to identify and implement new conservation programs, modifications to existing programs, and new delivery program mechanisms provided that they are cost effective. New programs and program modifications may include, but are not limited to, those indicated in the company’s recent DSM potential study by Navigant Consulting and programs targeting high consumption LIHEAP households and low-income renters.[338]
280. The Company has found developing conservation programs for low-income renters and other low-income customers especially challenging in the past, so specific attention to this market may provide new opportunities for conservation.[339]
281. The Suburban Rate Authority and the OAG object to the Decoupling Program because it does not include specific conservation programs.
282. OES objects to the conservation portion of the Stipulation, citing 2009 Minn. Laws ch. 110, § 32, which permits the Commissioner of Commerce to approve a natural gas retail company’s energy conservation improvement plan submitted in calendar year 2009 if the request includes a study that specifies how the utility may:
(i) average savings of at least 0.75 percent over the three years following submission of the plan . . . .
283. OES views Minn. Stat. § 216B.2412, which provides for pilot decoupling programs, as a means of inducing gas companies to exceed the conservation savings specified in their plans submitted pursuant to Minn. Stat. § 216B.41 and 2009 Minn. Laws ch. 110, § 32.[340]
284. Based on its understanding of the decoupling pilot statute and the absence of a commitment by the Company in the Decoupling Program to specific additional energy saving, OES opposes the Decoupling Program.[341]
285. The Department of Commerce, not the Commission, has authority to administer and approve energy conservation programs. Any specific conservation program must go through the Department’s review and approval process.[342] The Stipulating Parties plan to work with one another to introduce additional conservation programs to the OES for approval.[343]
286.
On December 28, 2004, a natural gas fitting on a
service line in
287. 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 required to maintain detailed records of what was found and what remedial measures were taken. Based on that order, CenterPoint initiated the Midwest Gas Replacement Project, during which it inspected over 30,000 service lines and replaced those lines where needed.[345]
288. In CenterPoint’s last rate case, the Commission ordered that ten percent (about $4 million) of the nearly $40 million costs from the Midwest Line Replacement project (“Project”) which the Company proposed to include in its rate base in that matter be deferred.[346]
289. The Commission’s purpose in deferring recovery of ten percent of the cost of the Project was to motivate the Company to ensure that it exhausted its legal remedies for potential third-party recovery.[347]
290. In the Company’s 2005 rate case, both the ALJ and the Commission considered – and disposed of – the same arguments that are being raised by the OAG and the SRA in the instant case regarding the Midwest Gas replacement costs. The ALJ’s Findings of Fact, Conclusions, and Recommended Order quoted Minnesota Statutes section 216B.16, subdivision 11, which provides that “[a]ll costs of a public utility that are necessary to comply with state pipeline safety programs…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.”[348]
291. The ALJ also specifically addressed the Minnesota Supreme Court’s interpretation of the effect of Minnesota Statutes section 216B.16, subdivision 11, on ratemaking. In Minnegasco v. MPUC, the Supreme Court determined that “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 furnishing utility service.’”[349]
292. The ALJ concluded that “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.”[350]
293. The Commission adopted the ALJ’s recommendation essentially in its entirely, with only a slight modification, the explanation of which was as follows:
The Commission finds that the action proposed by the RUD-OAG and the SRA in their exceptions (denial of recovery or substantial delay in recovery) is not consistent with the requirements of Minn. Stat. § 216B.16, subd. 11.
First, the Commission rejects the RUD-OAG’s assertion that the record is inadequate to support recovery of the costs in question. In the context of the statute’s specific mandate, the record established by CenterPoint is indeed adequate to invoke the statute’s specific mandate and justify recovery in this case. In addition, there are sound public policy reasons for interpreting the statute’s mandate to allow recovery of the specific category of expenses identified (state pipeline safety program-related expenses). The record supports that these costs were incurred in direct response to a directive from the Office of Pipeline Safety. Pipeline safety is a paramount concern (even more so after the tragic explosion on December 28, 2004) and a narrow interpretation of what is required for recovery may discourage or impede utilities from making expenditures to meet directives of the Office of Pipeline Safety. In addition, as a practical consideration, the RUDOAG did not identify any particular expenditure which it challenged as inappropriate for recovery.
Second, in light of the statute, placing all recovery of these expenses on hold pending the outcome of litigation between CenterPoint and the third parties as advocated by the RUDOAG and the SRA is not warranted.
At the same time, the RUD-OAG and the SRA have a good point that if the Company is allowed to recover all these expenditures from ratepayers at once, the Company may well lose motivation to litigate sound claims they have against third-parties to recover those expenditures. No party disputes that in this case, any moneys recovered from these sources against third parties should be returned to the rate payers to avoid the Company double-collecting these expenses, once from the rate payers and again from third-party defendants. Indeed, the Company has proposed to turn over any such recovery not to the Company’s shareholders but to the rate payers and the ALJ specifically accepted this.
The Company insisted that having filed the lawsuits against MEC and others to recoup the expenditures in question, no additional motivation to thoroughly pursue these claims is necessary. Its attorneys, the Company stated, are bound by professional obligation to pursue those suits through vigorously to the end. The Commission acknowledges the Company’s representation that the suits will be pursued vigorously to the end and factors that representation into its ultimate decision on this matter. Having done so, however, the Commission still finds it prudent to defer some meaningful level of recovery as additional motivation to promote the Company’s full exploration of the Company’s rights to recover against the third parties.
Applying the rule of reasonableness to the broad terms of the statute, therefore, the Commission finds that in these circumstances it is consistent with the requirements of Minn. Stat. § 216B.16, subd. 11, to modify the ALJ’s recommendation by deferring recovery of 10 percent of the capitalized costs in question pending the Company’s exhaustion of its legal remedies against the third parties.[351]
294. The Commission determined definitively in the last rate case that the Midwest Replacement Project costs were recoverable by the Company in accordance with not only the plain language of the statute, but also sound public policy.[352]
295. The sole issue left open by the Commission for consideration and review in future rate cases was the deferral of recovery of ten percent of the capitalized costs pending the Company’s exhaustion of its legal remedies against third parties.[353]
296. In a follow-up Order, on its own motion, the Commission clarified “the rate for carrying charges on deferred costs associated with the Midwest Gas service line replacement project that was omitted from the Commission’s November 2, 2006 FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDER.”[354]
297. The Commission went on to order that the “authorized carrying charge rate is 5.78%” and that the “clarification is consistent with the Commission’s November 2, 2006 Order and the Company’s understanding of and intent to implement that Order.”[355]
298. In accordance with the Commission’s November 2, 2006 Order in the Company’s last rate case, the Company vigorously pursued and exhausted its available legal remedies.[356]
299. No party to this proceeding has argued that the Company failed to vigorously pursue its legal remedies until it exhausted those remedies.[357]
300. The result of the Company’s legal action was a settlement agreement with MidAmerican Energy Company, the amount of which was credited to gross plant, reducing rate base.[358]
301. As Mr. Nesvig explained in his direct testimony and in accordance with the Commission’s Orders from the prior rate case, the carrying charges of approximately $500,000 related to the deferred costs were added to gross plant.[359]
302. The OAG raised two separate arguments against the Company’s recovery of the remaining ten percent of the Midwest Gas replacement costs and carrying charges. First, the OAG argues that the remaining ten percent of costs should be denied because the costs are not costs which are automatically borne by ratepayers by statute.[360] In the last case, as noted above, the Commission rejected this same argument by the OAG when it concluded that, “[i]n the context of the statute’s specific mandate, the record established by CenterPoint is indeed adequate to invoke the statute’s specific mandate and justify recovery in this case.”[361] The OAG has not introduced any new evidence to demonstrate that the Commission erred or that the underlying facts were misstated or have changed.
303. Second, the OAG argued that the Company should not be allowed to recover carrying charges on the $4 million amount deferred from the last rate case because that would be contrary to the Commission’s intent.[362] However, the Commission expressly noted in its January 22, 2007, Order that carrying charges on the deferred costs associated with the Midwest Gas service line replacement project were allowed and recoverable.[363]
304. The SRA also argued against the Company’s recovery of the deferred ten percent amount of Midwest Gas replacement project costs, as well as the carrying charges. In essence, the SRA questioned both the Company’s acquisition of the properties and the Company’s settlement with MidAmerican Energy.[364] The SRA also recommended that the Commission reopen an almost twenty-year old docket based upon language in the Commission’s Order that it retained jurisdiction to review “any exchange-related cost increases….”[365]
305. The Commission specifically reviewed and approved the transaction whereby the Company acquired the MidAmerican Energy properties.[366] The Commission’s review included the legal documentation that the SRA appears to criticize.[367]
306. No party presented evidence that would support denying the Company recovery of the remaining ten percent of its costs from the Midwest Gas Replacement Project.
307. Consistent
with the Company’s calculation of its late payment charges and its handling in
past rate cases, the Company calculated its bad debt as a percentage of firm
revenue. For the period ending December
31, 2007, the most recent year available at the time of the Company’s rate case
filing, bad debt expense as a percentage of firm revenue was 2.09%. The Company then applied that percentage to
the test year firm revenues to arrive at its test year bad debt expense of $26,521,258.[368] OES witness
12/31/07 Bad Debt Expense $23,535,537
Divided by Firm Revenue in 2007 $1,123,519,640
Equals Bad debt % 2.09%
Multiplied by Total Test-Year Firm Revenue $1,266,049,465
Test Period Bad Debt Expense $26,521,258
308. At the time of the Company’s rate case filing, 2008 figures were not available.[370] As they became available, OES recommended that the more current 2008 figures be used for bad debt expense, which resulted in a rate of 2.05 percent. This percentage is a decrease of 0.04 percent from the 2007 percentage of 2.09 percent. This OES’s proposal resulted in a decrease in bad debt expense of $4,717,703.[371] The 2008 percentage reflects the conclusion by the Company’s external auditor’s most recent estimate that bad debt expense is declining.[372] The OES also recommends that the Commission require that the bad debt expense be adjusted to reflect the final approved revenue requirement. The OAG-RUD supports the OES’s adjustments for bad debt expense.[373]
309. The ECC recommends a bad-debt factor of 1.70 percent, based on the average historical bad debt expense. ECC averaged the bad debt expense from 2000-2006, and then averaged that figure with the 2007 and 2008 actual expense amounts to arrive at its recommendation.[374] In her Surrebuttal Testimony, ECC witness Ms. Pam Marshall argued that the Company’s bad debt expense factor should be rejected, stating that a more reasonable approach would be to average the years 2005-2008 and allow a bad debt factor of 1.835 percent. ECC asserts that increases in LIHEAP funding can lower the amount of uncollectible revenue.[375] Although ECC argued that the bad debt factor should be lower than 2.09 percent proposed by CenterPoint, ECC did not argue that the OES’s recommended bad debt factor of 2.05 percent is unreasonable.
310. In response to Ms. St. Pierre’s testimony, Company witness Mr. Nesvig testified that still more recent figures available for the twelve month period ending May 2009 reflected that bad debt as a percentage of firm revenue was 2.50%, as opposed to the 2.05% recommended by Ms. St. Pierre.[376] Nevertheless, for purposes of narrowing the disputed issues in this case, the Company agreed to the OES’s recommended bad debt factor of 2.05% for setting rates.[377]
311. In response to the ECC’s proposals, Mr. Nesvig testified that the ECC did not accurately describe the interrelations between past due bills, write-off, bad debt expense, and the bad debt factor.[378] In his view, “[w]hile a decrease in the past due balance may reduce the amount that could be written off in the future, it does not follow that the bad debt expense as a percentage of firm revenue (the bad debt factor) will decrease.”[379]
312. The ECC’s proposed bad debt factor was not well supported and is confusing. By using data from 2000-2006, it departed from Commission precedent. The data from that period do not reflect conditions in the base year or test year of this case or recent economic conditions.[380]
313. The ECC’s proposed bad debt factor should not be adopted. Rather, the 2.05% bad debt factor, and corresponding bad debt adjustment of $4,717,703, agreed to by the Company, OES, and OAG should be adopted. It is appropriate for setting test year bad debt expense and consistent with Commission precedent.
314. The Company proposed the establishment of a BDER Mechanism that would compare, on an annual basis, the amount of actual bad debt expense (net of late payment fees) recorded on its accounting books and the amount of revenue billed to customers for this item, to determine if the Company over-recovered or under-recovered.[381] Any difference would be deferred to a special account. The Company would provide annual filings to the Commission detailing these entries and the account would be “trued-up,” either at the time of the Company’s next rate case or in a miscellaneous filing if necessary.[382]
315. The Company acknowledged that the Commission has historically included bad debt expenses in base rates in the non-gas, distribution margin portion of the utility’s rates.[383] The Company testified that in times of relative gas-price stability, this process was satisfactory. However, during times of significant volatility in gas prices, simply setting a level in base rates exposes both the Company and the customer to the possibility of either over-collection or under-collection of these costs. The Company proposed the BDER to ensure against such results. Over the past few years these expenses have grown significantly and, in the Company’s view, the BDER provides a mechanism to allow recovery of these expenses, subject to full Commission oversight. At the same time, in the event that these expenses drop significantly, the BDER also assures that ratepayers will not “overpay” for these costs.[384]
316. The Company did not comment on the impact of the poor economy on the ability of many customers to pay their bills as also causing an increase in uncollectible accounts.
317. The proposed BDER excludes recovery from transportation customers in the tracked amounts.[385]
318. The Company and OES concur that no special statutory authorization is required for this type of tracking mechanism, but the proposal must be assessed in light of the Commission’s policies regarding deferred accounting treatment.[386]
319. The Commission establishes a utility’s rates as part of a general rate case that considers a comprehensive assessment of the costs as well as revenues during a 12-month test year. Any deferral of out-of-test-year costs or revenues to a later test year may be allowed under certain limited circumstances. At a minimum, the Commission requires amounts for which deferral is sought to be: (1) related to utility operations for which ratepayers have incurred costs or received benefits; (2) large enough to have a significant impact on the utility’s financial condition; (3) unusual or extraordinary items; and (4) subject to future review for reasonableness and prudence. Depending on the facts as presented in prior deferral requests, the Commission has also considered other criteria for deferral of costs such as the nexus to present ratepayer’s use; the nature of the costs (purpose, frequency and cause); whether the costs are unforeseeable; whether the utility is pursuing insurance and third party recovery; whether the utility is collecting the costs either in base rates or the fuel clause; whether the Commission has ordered a program to meet public policy mandates; the rate impact on the utility; and whether there are benefits and costs to ratepayers. Additionally, to maintain control over the items deferred, the Commission has consistently prohibited deferral of costs prior to a utility’s request for deferral.[387]
320. Under these standards regarding deferred accounting, the Company’s bad debt expense does not qualify for deferred accounting treatment. Although bad debt expense is a large expense related to utility operations, it is not unusual, extraordinary, or unforeseeable. Bad debt expense is a routine cost of doing business.[388]
321. The OES also expressed other concerns. First, the OES testified that there is no incentive for CenterPoint to enhance its collection efforts or even continue its existing collection efforts if the BDER is approved. Second, the tracker would true up only to an estimated amount, never to the actual bad debt expense. Third, there is no link between the BDER and outreach efforts for LIHEAP or the Gas Affordability Plan (“GAP”), which help reduce overall bad debt.[389] Fourth, because purchased gas costs have decreased significantly, the amount of bad debt expense in the test year should be reduced, in turn reducing any perceived need for the BDER.[390]
322. The OAG joins OES’s criticisms of the BDER. It also joins the ECC in its criticisms of the BDER in light of what it calls the Company’s inadequate LIHEAP outreach efforts. The ECC believes that the Company’s disconnection policies and onerous payment arrangement terms make it difficult for customers to reconnect their gas service, which results in higher uncollectibles.[391] As the OES suggested above, there should be some linkage between BDER and LIHEAP.
323. It has not been shown that there would be benefit to ratepayers if the BDER mechanism is adopted. As OES suggests, if the actual amount of bad debt expense goes up, ratepayers can be harmed. If it goes down, shareholders receive a windfall at the expense of ratepayers. Fluctuating gas price was given as the cause of bad debt and the justification for the proposal. But it is likely that there are other significant reasons for people not paying their bills. The state of the economy is likely one of those. It creates upward pressure on bad debt expense, even if the price of gas continues its recent decline. LIHEAP outreach is another influence on bad debt expense. Given the uncertainty of the evidence, the proposal should not be adopted.
324. In its March 31, 1995, Order Terminating Investigation and Closing Docket No. G-999/CI-90-563, (the 90-563 Order) the Commission ordered the parties in each subsequent rate case filing by a natural gas company to “address the following kinds of questions:”
· Should the “free” footage or service extension allowance include the majority of all new extensions with only the extremely long extensions requiring a customer contribution-in-aid-of-construction (CIAC)?
· How should the LDC [Local Distribution Company] determine the economic feasibility of service extension projects and whether the excess footage charges are collected?
· Should the LDC's service extension policy be tariffed in number of feet without consideration to varying construction costs amongst projects or should the allowance be tariffed as a total dollar amount per customer?
· Is the LDC's extension charge refund policy appropriate?
· Should customers be allowed to run their own service line from the street to the house (or use an independent contractor) if it would be less expensive than having the utility construct the line?
· Should the LDC be required to offer its customers financing for service extension charges? This could be offered as an alternative to paying extension charges in advance of construction.
325. The 90-563 Order also stated that the Commission had three concerns about the impact of extensions upon a company’s rate base and requested that the Department, in future rate cases, investigate extensions to make sure that (1) LDCs are applying their tariffs correctly and consistently, (2) that they are appropriately cost and load justified, and (3) that wasteful additions to plant and facilities are not allowed into rate base.
326. The 90-653 Order went on to state:
In future rate cases
initiated by
327. The Commission’s December 22, 2008, NOTICE AND ORDER FOR HEARING in this matter listed ten issues to be addressed. None of them dealt with extension policies or tariffs.
328. In Mr. Nesvig’s testimony, the Company responded to each of the six questions posed by the 90-653 Order. As part of the OES’s review in this case, Mr. Minder examined the Company’s responses. Mr. Minder testified that the Company appropriately responded to the “six questions” posed in the 90-653 Order. [392]
329. Regarding the “three concerns” posed in the 90-653 Order, the Company performed an analysis with the methodology it used in its last rate case. To determine if it was applying its tariffs correctly and consistently, it reviewed its service line extension for residential projects for 2005 through 2007 by taking a separate randomly selected sample for each. The results of the service line sampling revealed errors in three, two, and two extensions for the years 2005, 2006, and 2007, respectively. The Company’s analysis of the commercial service line extension noted no errors in the application of its tariff. As a result, the Company concluded that there were no systemic problems in the application of its tariff, noting that the only errors detected were the result of human error and within the allowable number of errors given the sample criteria.[393]
330. With respect to the errors noted in the Company’s application of its tariff, Mr. Nesvig testified that the Company will provides specific training on the extension tariff to each employee, including written procedures that are to be followed. Managers also review and approve all new main and commercial service line extension requests prior to processing to ensure compliance. The Company conducts annual review training for all employees in this Department, as well as random audits to ensure compliance. [394]
331. Regarding the second concern of appropriate cost and load justification, Mr. Nesvig noted that historically, most “tariffs specify a footage allowance and a [dollar] per foot charge for extensions that go beyond the footage allowance. The footage allowance amount is determined by what the LDC can recover from the new customer through earnings in a relatively short period of time. The amount of time is usually 3 to 5 years rather than the expected life of the pipe.” The Company’s filing indicates that it will be able to recover extension costs from its customers, through earnings, well within five years.[395] Thus, the Company has demonstrated that its extensions are, in fact, appropriately cost and load justified.
332. Regarding the possibility of wasteful additions to plant and facilities would not be included in rate base, Mr. Nesvig testified that he adjusted rate base to exclude those options that did not meet the used and useful test, such as the peak-shaving plants that were a part of the Company’s Midwest Gas Minnesota purchase in 1993.[396] The OES’s Mr. Minder agreed that the Company’s extension tariff ensures that wasteful additions to plant and facility are not allowed into rate base.[397]
333. The OES reviewed the Company’s extension policies and tariffs against additional general principles of its own and found that:
a. The Company’s extension procedures on footage allowances are reasonable and consistent with the OES’s principles for service extensions.
b. The Company’s general approach to economic feasibility and the collection of excess footage charges is reasonable.[398]
c. The Company’s policy for the residential class of a “free” footage allowance based upon typical construction length is consistent with the OES’s position on footage allowances.
d. The Company’s long-time refund practice is appropriate.[399]
e. The Company’s tariff requirements and policy regarding customer installation of service lines are reasonable.[400]
f. The Company’s current tariff with respect to financing for natural gas service extension charges is reasonable.[401]
334. Because the Commission accepted the sampling method used by the Company in its 2005 rate case to determine compliance with its extension tariff, the OES did not oppose the Company’s use of the same sampling method in this docket. However, the OES asserts that the Company was required to, and failed to present an analysis showing compliance with its extension tariff using a method used to evaluate compliance with extension tariffs two recent rate cases: the 2006 natural gas rate case of Northern States Power Company (Xcel Energy), Docket No. G002/GR-06-1429, and the 2008 natural gas rate case of the Minnesota Energy Resources Corporation (MERC), Docket No. G007,011/GR-08-835. That method used the amount of uncollected CIAC as a percentage of the CIAC that should have been collected to determine compliance with those utilities’ extension tariffs.[402]
335. OES witness Mr. Minder performed such a CIAC analysis for this case. Based upon that analysis, the OES recommends disallowance of $175,421 in main and service line extension-related costs in the test-year, and additional associated adjustments.[403]
336. The Company did not refute the OES’s CIAC analysis. Rather, it argues that it should not be held to this new standard that arose in an order that had not been issued at the time this docket was filed and in an order in a case to which the Company was not a party. Moreover, the Company argues, the Commission has never notified the Company that its compliance with the 90-563 Docket would be gauged by this new standard. The Company states that it is more than willing to follow this “new standard” in future cases so that it has adequate time and notice to implement the required changes, but that it is neither fair nor appropriate to change the standards in the midst of a case.[404]
337. The OES notes that Minnesota law requires that utilities bear the burden of proving that the costs they propose to impose on ratepayers are just and reasonable,[405] and that consumers be provided the benefit of any doubt as to reasonableness.[406] It argues that if the Commission wishes to evaluate the records in this rate case in a manner different from the prior CenterPoint rate case, it may do so. It highlights the importance of proof of extension-related costs as stated in the 90-563 Order. It restates Mr. Minder’s testimony that the Company most likely was well aware of the use of the CIAC method in the 06-1429 Docket.[407]
338. Whether the Company was aware that a CIAC analysis had been used in two recent cases is irrelevant. So is the fact that service extension costs are just another cost that must be justified by applicant in a rate case. The 90-563 Order did show the significance of these particular costs, and it was explicit as to what types of information were to be provided and what the Department was to investigate. There has been no claim that the orders in the 06-1429 Docket or the MERC docket contained any direction from the Commission that the CIAC method of analyzing the costs should be considered in other existing or even future gas rate dockets. The 90-563 Order was also explicit that any issues to be addressed regarding extensions would be set out in the Orders for Hearing. That was not done here.
339. The Company has met its burden of establishing compliance with prior Commission orders and its tariff as it relates to the Company’s proposed rate base adjustments for service and main line extensions. The OES’s proposed adjustment should not be adopted.
340. The Commission directed the establishment of an environmental tracker account for the Company in its 1995 rate case, stating
The Commission agrees with the parties and the ALJ that the use of a tracker account will provide a reasonable mechanism to account for the costs and recoveries of environmental costs. Due to the uncertainty of the level of costs which will ultimately be incurred for environmental costs, the Commission is concerned that mechanisms be put in place which will assure that prudent environmental costs be recovered, no more nor less. The Commission will direct the establishment of the tracker account effective October 10, 1995.[408]
341. In directing the establishment of this tracker, the Commission noted the high costs that can be involved in environmental cleanups, the substantial legal costs and insurance recoveries that may occur, and the volatility of these costs and recoveries.[409] In order to meet its goals of allowing recovery of cleanup costs, no more and no less, and “to assure that neither the Company nor ratepayers are unduly financing the tracker balance,” the Commission also directed that the Company record a carrying charge on the monthly tracker balance equal to its pre-tax, Commission approved rate of return.[410] The Commission also required an annual reporting of all expenses and entries and assumptions related to the account, so that it could closely monitor the tracker.[411]
342. The environmental tracker has continued in place unchallenged through the Company’s two recent rate cases.
343. The environmental tracker currently contains a balance of approximately $8.3 million, including carrying charges.[412]
344. Insurance recoveries and their associated carrying charges reside in a separate account that is amortized to the tracker account as work is completed.[413] This recognizes the fact that significant work remains and the Company faces significant future expenditures for which it has recovered insurance proceeds. Amortization of those recoveries as work is completed properly matches the recovery to the expenditures.[414] Moreover, as the insurance recoveries are amortized, the Company must appropriately allocate these recoveries to the “regulated” and “non-regulated” operations.[415]
345. Carrying charges are calculated on the net tracker balance and the insurance recovery balance to ensure that ratepayers are not harmed by the credit balance of the tracker.[416]
346. The Company stopped receiving money from ratepayers to cover the costs of environmental cleanup after requesting permission to reduce the environmental recovery rate to zero in 1998.[417]
347. As directed by the Commission, since the inception of the environmental tracker account CenterPoint Energy has provided annual filings to the Commission. Those filings provide a detailed summary of all entries and assumptions regarding the balance in the account, including all costs incurred by the Company.[418]
348. The Company has significant environmental liabilities that exist, yet the amount and the timing of the cleanup costs is uncertain.[419]
349. The environmental work faced by the Company is required by State and federal environmental laws.[420]
350. Under these laws, the Company may be a “responsible person” with financial responsibility for clean-up of certain sites.[421] However, there may also be other responsible parties and, in fact, at one site the Company has entered into a “tolling agreement” with the University of Minnesota whereby both parties have preserved certain claims and defenses against each other.[422] This leads to uncertainty on both the timing and the precise amount of the costs that will be incurred by the Company.[423]
351.
The Company provided the testimony of Alan Van
Norman, a professional environmental engineer with over 30 years of experience
who has worked with the Company on environmental remediation matters for the
past 24 years.[424] Mr. Van
Norman reviewed the Company’s projection of environmental clean-up costs of $4 million
to $35 million related to the
352. The OAG recommends that the Commission close the environmental tracker, and order a refund to customers of the tracker balance as well as a refund of all insurance recoveries, recommending a three year amortization period for this refund.[426]
353.
The OAG
stated that the tracker account has outlived its purpose, since “future environmental
clean-up costs are not expected to be significant for the
354. Given the recommendation to close the environmental tracker account, the OAG recommended that the Company “be allowed to include a normalized level of environmental cleanup costs in rates. A normalized level based on expenditures for the years 2005 to 2007 would be an appropriate amount to establish in rates.”[428]
355. The years 2005-2007 are the three years of lowest expenditures by the Company for environmental costs during the period from 1991-2008.[429] The amount spent by the Company for environmental costs in 2008 was nearly twice what it spent in 2007.[430] The ALJ recommends that the environmental tracker account be retained.
356. The Company included a rate case expense adjustment as part of its filing in this case, which reflects the amortization of the Company’s expenses incurred by the Company to prepare the rate case.[431] These expenses include consultant and legal fees, as well as administrative costs and billings from the Office of Administrative Hearings, the Office of Energy Security and the Commission.[432] Based upon the amount of time between this rate case and the time before the Company anticipates filing its next case, the Company amortized these expenses over a two-year time period.[433]
357. OES witness Mr. Johnson reviewed the Company’s rate case expenses.[434] Mr. Johnson and the Company were in agreement on the Company’s estimate of rate case costs and the allocation of the rate case expenses to non-regulated operations. The only issue that Mr. Johnson challenged was the Company’s proposal to amortize these costs over a two-year period.[435]
358. Mr. Johnson proposed a four year average which, he asserted, reflected the average intervals between the Company’s most recent nine rate cases.[436]
359. Company witness Mr. Nesvig explained that the OES’s proposed use of “averages” can be misleading, noting that 4 of the 8 intervals used reflected a time period of 2 years or less, and 6 of the 8 intervals were 3 years or less.[437]
360. The pilot Decoupling Program, which is the center of the rate design in this case, is limited to three years.[438] If the Commission determines that the pilot is harming ratepayers or failing to meet objectives, the Commission may suspend the pilot at any time, or recommend modifications.[439] CPE will almost certainly file a rate case within three years, if the decoupling program is approved. The ALJ accordingly recommends that these expenses be amortized over three years.
361.
CenterPoint proposes to include two types of
incentive compensation expense in the test year—the Company’s Long-Term
Incentive Compensation Plan and Short-Term Incentive Compensation Plan. The Company’s treatment of its employee
compensation and benefits program has not changed since its last rate case,
where it was not challenged by any other party. [440]
362.
The proposed
test year LTIP expense to the Company reflects an increase of $190,230 from the
base year to the test year. In total,
STI and LTIP expenses reflect a reduction of more than $400,000 from the base
year to the test year.[441]
363.
OES recommends that, based upon an Order entered
by the Commission on May 4, 2009, in the Minnesota Power rate case, the
Company’s entire LTIP expense of $229,683 should be disallowed.[442] The OES also recommended, again based upon
the Commission’s May 4, 2009, Order, that the Company’s STI expenses be reduced
by $8,825, the amount by which any short term compensation award exceeded 25%
of total compensation.[443] Lastly, again relying on the Commission’s May
4, 2009, Order, the OES recommended that any incentive compensation award that
is not made to employees, but that were included in base rates, be refunded to
ratepayers.[444]
364. LTIP expense reflects the FAS (Financial Accounting Standards) 123R amounts related to CenterPoint Energy performance shares and stock awards granted to employees at the fair market value of the equity award on the grant date. Expenses include the pro rata portion related to 2009 of actual grants from 2007 and 2008 and expected grants in 2009. The stock awards generally vest over a three year period and are tied to specific dividend declaration goals. Performance shares also vest over a three-year period, but the amount of stock issued can vary based on whether or not CenterPoint Energy, Inc., meets or exceeds certain performance goals. The test-year expense is projected on meeting those performance goals at the targeted level.[445] CenterPoint proposes to include $229,683 of LTIP expense in the test-year.[446] This amount is equal to the performance shares and stock awards that will vest in 2009.[447]
365. The OES asked CenterPoint to explain why ratepayers should pay for awards that are tied to specific dividend declaration goals.[448] In its reply, the Company stated that CenterPoint Energy, Inc., added a dividend trigger to the stock award portion of its long term incentive compensation in 2005. The Company limits these awards to management level employees or senior individual contributors. The employee must remain employed for three years and the Company must maintain or increase its common stock dividend during the vesting period.[449]
366. The OES identified eight rate cases in which the Commission either did not approve or denied recovery of long-term incentive compensation.[450] In Minnesota Power’s recent general rate case, the Commission stated:
Further, as the Commission previously recognized, offering key decision makers large financial rewards for producing short term shareholder benefits does not promote regulatory efficiency or the long term fortunes of the Company. The Company concedes that with respect to the LTIP program, there is emphasis on earnings as a goal. Such a goal benefits shareholders more so than ratepayers. The Commission finds that these considerations justify the decision to eliminate the Long Term Incentive Plan in its entirety, as recommended by the ALJ. This will necessitate a reduction in test year expenses by $1,227,858.[451]
367. CenterPoint’s LTIP, like that of Minnesota Power, consists of performance shares and stock awards based on specific dividend declaration goals.[452] Based on the Minnesota Power Order and the Commission’s policies, the OES recommends that the Commission disallow CenterPoint’s entire LTIP expense of $229,683 from the test-year Employee Pensions and Benefits expense.
368. CenterPoint proposed to include $1,737,475 of short-term incentive compensation in the test-year. This amount is based on the total 2007 eligible earnings of all officers, non-union employees, and eligible union employees at a 100 percent target payout level multiplied by the test-year payroll inflation percentages.[453]
369. The OES noted that CenterPoint’s test year includes STI that exceeds 25 percent of base pay for one individual who has a target STI percentage of 30 percent. Market data is used to ensure STI target levels are competitive with the external market for similar positions. The amount that exceeds 25 % in the test year is $8,300. [454]
370. The OES also pointed out that the Commission has limited the incentive compensation to 25 percent of base pay in seven recent rate cases, and to 15 percent of base pay in one case.[455] The Commission’s Order in the Minnesota Power rate case addressed that Company’s range of incentive compensation available as follows:
The Commission also
finds it appropriate to reduce the range of incentive compensation available
pursuant to the [Annual Incentive Compensation] plan to the 25 percent total
compensation advanced by the OES and recommended by the ALJ (including the 5
percent of base compensation available under the results sharing awards). This will necessitate a reduction in test year
expenses by $167,143. The Commission
finds that reducing the level of total incentive compensation available to
eligible employees will both benefit ratepayers and result in rates that are
just and reasonable. Further, these
measures place the Company’s incentive compensation plan squarely in line with
other
371. The OES recommends that the Commission require that the test-year STI expense be reduced by $8,300, which is the amount that exceeds 25 percent. However, since this figure does not appear to include the inflation adjustment, the OES also recommends an inflation rate of 6.32 percent for non-union payroll inflation.[457] Thus, the OES recommends that inflation of $525 (6.32 percent times $8,300) must be added to calculate the appropriate amount to remove from the test year expenses. The test-year STI in Administrative and General expense should be reduced by a total of $8,825.[458]
372.
The
Company responded that its total compensation program is market-based, with
total compensation, including STI and LTIP, being targeted at the 50th
percentile of similar jobs at similar companies. It states that the OES’s adjustments for STI
and LTIP, if adopted, would simply encourage the Company to restructure its
compensation structure so that all of the compensation is guaranteed as up
front “base pay,” rather than putting a portion of the pay at risk. Moreover, according to the Company, since its
total compensation package targets the 50th percentile, the OES’s
proposed disallowance of STI or LTIP would reduce the recoverable portion of
affected employees’ compensation to a level below market level – a level at
which it will be difficult to attract and retain qualified employees. The OES’s proposed LTIP adjustment also
undercuts one of the key benefits of a LTIP program from the Company’s (and
ratepayers’) perspective – providing an incentive for key employees to stay
with the Company because LTIP benefits vest over time.[459]
373. The OES’s recommendations regarding the LTIP and STI adjustments are reasonable, follow Commission precedent, and should be adopted.
374. The incentive compensation plans provided by the Company allow the payment of awards by the Compensation Committee of the Board of CenterPoint Energy, Inc. The payments are discretionary and the plans may be amended, modified, suspended, or terminated.[460]
375. The Commission has previously required in at least five rate cases that a utility refund to customers all incentive compensation approved by the Commission and included in base rates but not paid to employees. In the recent Minnesota Power rate case, the Commission’s final order provided the following with regard to the refund mechanism:
The Commission requires utilities to refund unpaid incentive compensation amounts for two main reasons: (1) to reduce the risk that corporate self-interest will influence how the discretion inherent in these programs is exercised; and (2) to avoid rewarding the shareholders and upper management for poor performance by their work force. Further, there is no principled reason to permit a fund earmarked for employee compensation to be converted into earnings in the event of an earnings shortfall. [461]
376. The OES recommends that the Commission require CenterPoint to refund to customers all incentive compensation approved by the Commission and included in base rates, but not paid to employees. This recommendation is necessary since CenterPoint’s employee compensation plans are discretionary and the plans may be amended, modified, suspended, or terminated between general rate cases. Including the costs of these programs in rates without the refund requirement could mean that ratepayers would pay for a program which later could cease to exist or not be used in a given year.[462]
377. The OES also recommends that the Commission require an annual report on incentive compensation similar to the annual report required from Northern States Power in Docket Nos. E002/GR-92-1185 and G002/GR-92-1186. That is, the compliance report should include the following: (1) a description of the incentive compensation plan; (2) the accounting of amounts of unpaid incentive compensation built into rates to be returned to customers; (3) an evaluation of the incentive compensation plan’s success in meeting its stated goals including the payout ratio; and (4) a proposal for refund, if applicable. Further, the OES recommends that a date for the annual report be set at 30 days after incentive compensation is normally scheduled for payout.[463]
378.
The
Company acknowledged that the Commission has approved of similar treatment in
other cases, but argued that STI expense should not be singled out for special
treatment, but treated as other normalized expenses without a true up or refund
mechanism.[464]
379.
Again,
the OES recommendation is reasonable and consistent with the Commission current
approach to unpaid incentive compensation and reporting of refunds. It should be adopted.
380. In its filing, the Company proposed a decrease of $1.1 million in collection-related costs, partially offset by a requested increase of $235,200 in the test year expenses associated with an increase in costs necessary to gain access to inside meters through court order where the Company cannot gain access through other normal procedures.[465]
381. The Company seeks access to its customers’ inside meters for any number of reasons, including meter reading, inspections and repair, or disconnection.[466] There also are numerous cases where a customer abandons a property, where no property owner exists, or where no one responds to provide access to Company representatives. The Company also encounters circumstances where a customer, who has the means to pay the bill, is content to leave the bill unpaid and simply prevents disconnection of service by denying the Company access to its equipment.
382. In cases where a customer refuses to grant access, the Company is required to follow the Commission’s procedures entitled “Uniform Access To Customers’ Premises.”[467] In accordance with those procedures, in those circumstances where the customer does not provide consent, the Company must obtain a court order to gain access to the property.[468]
383. The court-ordered access process is entirely separate from, and in addition to, other attempts to obtain customer cooperation (including disconnection notices) that the Company utilizes to attempt to gain physical access to premises prior to seeking a court order.[469]
384.
Chapter 7820 of the
A utility shall not enter a customer’s premises if the customer has not consented; or the utility has not obtained a court order authorizing entry; or an emergency situation involving imminent danger to life or property does not reasonably appear to exist.[471]
385. Court orders serve the limited function of authorizing access to the property to perform any task the Company is authorized or required to undertake at the property.[472]
386. When a customer is disconnected pursuant to the court order process, the customer has received both the full series of disconnection notices, in accordance with Minnesota Rule 7820.2400, and also has separately received at least two notices requesting access to the premises.[473]
387. Customers disconnected pursuant to a court order actually receive more process and notice than those customers to whose meters the Company can gain access without an order, such as those with outdoor meters.[474]
388. The OAG objected to the $235,200 increased collections expense for the court-ordered access but did not provide a basis for that objection other than its general objection to the Company using court-ordered access for the purpose of disconnection.[475]
389. In order to avoid continued need for court-ordered access to indoor meters, the OAG recommended that “CPE should be directed to upgrade its system by eliminating inside meters, which would obviate the need for CPE personnel to access private dwellings and businesses.”[476]
390. The cost to move all of the Company’s indoor meters outdoors would be about $90-$120 million, which would contribute to an increase in rates for all customers.[477]
391. The alternative to court-ordered access when the Company has to disconnect an indoor meter to which it is denied access, is to disconnect service by digging up the service line. “[T]he cost to disconnect and reconnect service would be about ten times greater and would be billed to the customer disconnected for nonpayment. The court-ordered access process significantly reduces the cost of collection and does not add to the payment burden of customers already behind in their bill.”[478]
392. In this proceeding, the OAG raised concerns that “if court ordered access for the purpose of disconnection is lawful, the Company must provide notice in these letters that CPE is requesting access to the customers’ premises to disconnect utility service for nonpayment.”[479]
393. Although the OAG did not provide any legal authority for that statement, the Company has sought to ensure that it has addressed the OAG’s concerns by revising its correspondence to include a statement that access is requested for the purpose of disconnection, when access is sought for that reason.[480]
394. The OAG also suggests that the Company’s letters to customers should include an offer to enter into a payment agreement in accordance with Minn. Stat. § 216B.098.[481]
395. Again, to ensure that the Company has addressed the OAG’s concerns on this issue, the Company has amended its correspondence to customers to include an offer to make payment arrangements.[482] The Commission should accept the $235,200 expense as proposed by the Company.
396.
The Company’s test year included lobbying
expenses expected to be incurred by the Company associated with issues at the
397. The OAG
disputes that ratepayers should pay for the Company’s involvement in the legislative process. It points out that the Commission’s Orders in
the Company’s 2004 and 2005 rate cases were void of any discussion related
to the Company’s lobbying expenses and that in its 1992 rate case, the Commission
acknowledged and accepted the Company’s
agreement to exclude lobbying expenses after the OAG objected to rate recovery
of the expenses. The OAG cites several
Commission decisions that have excluded lobbying expenses from rate recovery.[484] It
asks that they be excluded here.
398. It is not clear what positions the Company took on the issues it lobbied, but it is safe to assume that the Company would lobby primarily on matters that affect its own finances. The linkage of that lobbying to ratepayer benefit is not clear, but may well exist. Reducing costs for the Company, or avoiding higher costs, generally should be reflected in lower rates for ratepayers at some point. On the other hand, there are likely some lobbying efforts by the Company directed to support of policies that do not benefit the ratepayers. In the proper case, it could be reasonable to include some amount of lobbying expense. But here, there has been no reliable demonstration and quantification of ratepayer benefit. The Company’s lobbying expenses should be denied.
399.
The
Company fully allocates its costs between regulated and non-regulated business
operations in accordance with the FCC’s Cost Apportionment Principles, which
were formally adopted by the Commission in Docket No. G-008/C-91-942.[485]
400.
In
accordance with the Commission Orders, the Company’s cost allocation process
involves several steps. First, each
department directly bills the costs of providing services to specific business
units. Second, when direct billing is
not practical, costs are assigned utilizing cost causation principles that are
closely related to the service provided.
This approach follows the cost allocation principles of the National
Association of Regulatory Utility Commissioners (“NARUC”) “Guidelines for Cost
Allocations and Affiliate Transactions.”
Lastly, when neither direct nor indirect cost causation factors is used,
the Company allocates costs based on the Company’s composite ratio, which is a
three-part formula consisting of gross margin, assets, and number of employees.[486]
401.
Although
the Commission’s generic cost allocation docket, Docket No. G,E-999/CI-90-1008,
prescribes a general allocator when neither direct nor indirect measures of
cost causation can be found, the Commission has approved the use of the
Company’s composite ratio in lieu of the general allocator because it is
reasonable, consistent across business units, and can be easily administered
and audited.[487]
402.
The
Company and the OES agree that the use of the composite ratio in lieu of the
general allocator results in fewer costs being assigned to the Company than
would occur using the general allocator and is in the public interest.[488]
403.
OAG
witness Mr. Lindell recommended use of the general allocator for corporate
costs, in lieu of the composite ratio.[489] The OAG calculated the general allocator
percentage for
404.
The
OAG’s calculation is inconsistent with the Commission’s Order in Docket No.
90-1008. In that docket, the general
allocator is described as a ratio of all expenses assigned or attributed to
regulated and non-regulated activities excluding the costs of gas, purchased
power and costs of goods sold. In this
case, however, OAG witness Mr. Lindell used only Service Company direct and
support expenses assigned to the various operating units in his
calculation. This calculation should
have included all other expenses assigned or attributed to regulated and
non-regulated activities, including costs incurred at the business unit. Based upon this miscalculation, the OAG
excluded over 90% of all assigned or attributed expenses that should have been
included in the calculation.[491]
405.
The
composite ratio proposed by the Company and the OES results in lower costs
being allocated to Minnesota ratepayers than does a general allocator properly
calculated in accordance with Commission docket number 90-1008. The use of the composite ratio is fully
supported by the record, consistent with Commission precedent, and in the
public interest.[492] It should be accepted by the Commission.
406. CenterPoint Energy applied a compound escalation factor of 7.29 percent to its adjusted 2007 base-year corporate costs to determine the test-year inflation amount of $1,666,791.[493] The OES disagreed with the Company’s proposed escalation factor of 7.29 percent, and proposed a revised escalation factor of 6.01 percent over the two-year period from 2007 to the 2009 test-year.[494] The OES’s proposed escalation factor reduces CenterPoint Energy’s corporate costs by $208,028.
407. CenterPoint accepted the OES’s proposed escalation factor of 6.01 percent.[495] CenterPoint also accepts the OES’s proposed adjustment for corporate costs of $208,028, based on the 6.01 percent escalation factor.[496] The effect of the adjustment is a reduction in CenterPoint’s test-year corporate costs of $208,028.[497] The escalation factor agreed to by OES and CenterPoint is reasonable and should be accepted by the Commission.
408. CPE agreed to use the results of OES’s alternative sales forecast for purposes of this rate case.[498] The only dispute between the parties is whether CPE has shown the reasonableness of using a 10-year period, rather than a 20-year period, to determine normal test-year weather for use in calculating the test-year sales forecast.
409.
Test-year sales volumes are important in
calculating a utility’s revenue requirement.
In developing a sales forecast, the effort is to predict sales as
accurately as possible and not to bias the forecast either for the utility or
against the utility.[499] If sales
are underestimated, the utility’s revenue deficiency is spread over too few
units, meaning the utility collects more revenues per therm than is warranted
by costs and leading to customers paying “too high” a rate.[500] Conversely,
if sales are overestimated, the utility’s revenue deficiency is spread over too
many units, meaning the utility collects fewer revenues per therm than is
warranted by costs and leading to customers paying “too low” a rate.[501]
410.
Test-year sales are different from actual
historical sales, although both types of test-years require “normal”
assumptions. It is essential to remove
the effects of abnormal weather from the test-year sales forecast, since the
purpose of the test year is to represent expected sales under normal
conditions. Sales forecasts accordingly
must account for weather and determine the level of sales that will occur in a
“normal” weather year by utilizing “normal” heating degree days (“HDDs”) in the
development of the forecast.[502] Weather is typically the most
significant factor affecting sales to natural gas customers in
411.
The Company maintains that the rolling 10-year
average of HDDs better predicts actual heating degree days one year and two
years into the future, using variance analysis, than using either 15-year or
20-year rolling average weather.[504] The
Company asserts that measurable climate change has taken place since the
1970’s, particularly in the wintertime and particularly in
412. The OES noted that the Commission has used 20-year and 30-year normal weather to set rates for many years. OES contends that use of a shorter period would allow an abnormal weather year to have a larger influence on the determination of “normal” weather. OES compared the use of ten-year and 20-year data to actual weather data over the period from 1950 to 2007. During that period, Minneapolis-St. Paul experienced average calendar year HDDs of 7,824 with a standard deviation of 579 HDDs. The Company’s ten-year data stream had an average HDD value of 7,108, as compared to the 20-year data stream with an average HDD value of 7,500. OES asserts that shorter time periods clearly increase the volatility of the weather model.[507]
413.
OES also points out that, although the trend
since 1970 may be that weather has become warmer, the trend using a more recent
period—1998 to 2008—shows that weather has been colder, and the number of HDDs
in the Twin Cities has increased.[508] The
record establishes that 2008 was the coldest year in a decade for the
414.
The
OES recommended that the Commission use 20-year weather data to develop the
sales forecast in this case, but open a new docket to explore the implications
of this issue for all
415.
Because
of the difficulty in determining what “normal” weather is over an appropriate
period of time, and because this issue affects all utilities, the ALJ
recommends that the Commission adopt the OES proposal to use 20-year weather
data to develop the sales forecast in this case, but open a new docket to
investigate the propriety of changing this policy in future cases.
416. The Company and OES are in agreement with the Company’s proposed handling of CIP cost recovery on a prospective basis and the application of carrying charges to the CIP tracker account. The Company’s estimated CIP tracker account balance as of December 31, 2008, is $8,085,253.[512] The updated actual CIP tracker account balance as of December 31, 2008, is $8,178,943.[513]
417. In the Company’s 2005 rate case, the actual CIP tracker account balance was zeroed out against the interim rate refund, instead of being included as a test-year CIP expense. The Company proposes the same treatment here.
418. The OES agrees with the Company’s proposal to true up the CIP tracker account balance and does not oppose implementing the true-up through an offset against an interim rate refund. The only issue in dispute with respect to the CIP tracker account balance is the amortization time period that would be used, should the Commission decide to include the balance as a test-year expense instead of netting the actual, unamortized balance against any interim rate refund required in the case.[514]
419.
The parties’ positions on the appropriate
amortization period are the same as with regard to rate case expenses. The Company proposed a two year amortization
period, asserting that a two-year period is appropriate because it anticipates
filing its next rate case within two years, and considering the average
interval between the Company’s most recent rate case filings.[515] OES
proposes amortization over a four-year period.
420. For the reasons stated above with regard to rate case expenses, the ALJ recommends that the Commission use a three-year amortization period. In the event the Commission decides to use a different period for rate case expenses, the ALJ recommends that the same amortization period be used for this expense.
421. CenterPoint proposed to increase from $22.50 to $30.00 the reconnection fee to reinstate gas service when the gas meter has been locked for non-payment. The Company’s cost study supporting this increase shows the average cost to be $59.36.[516] The costs to lock and unlock a meter have remained approximately the same since the last rate case.[517]
422. The Commission has indicated a preference for retaining some level of intra-class subsidy for this service. Specifically, the Commission indicated that there are public policy reasons for setting the rate below costs to enhance low-income customers’ ability to maintain affordable, reliable, and continuous service, to stretch the limited public and private funds available to assist low-income households facing energy crises, and to ease administration of the assistance.[518]
423. For these reasons, the OES recommended that there be no increase in the reconnection fee.[519] CenterPoint did not state an opposition to this recommendation.[520] The ALJ recommends that the reconnection fee not be increased.
424. In conjunction with this case, the Commission asked the parties to address the effectiveness of the Company’s LIHEAP outreach efforts.[521] The Company’s LIHEAP outreach efforts are detailed in the Company’s response to OES Information Request No. 176.[522] These LIHEAP activities include a variety of media, messages, and audiences, designed to make customers aware of LIHEAP, to make applying for LIHEAP easier, and to reinforce the Company’s relationships with local providers.
425. In addition to the Company’s direct outreach activities, the Company conducts significant mass marketing activities and indirect outreach activities in a variety of media and messages to communicate with its low-income customers about the availability of heating assistance and other programs.[523] Mass marketing and indirect outreach activities are an appropriate method of communicating with all CPE customers about the availability of LIHEAP, in light of the fact that the Company does not know which of its 700,000 customers may be eligible for LIHEAP.[524]
426.
The Company spent $190,000 on LIHEAP outreach
activities in the 2008-2009 program year.[525] The
average LIHEAP outreach cost was $5 per LIHEAP recipient, and the average
number of message exposures was about 3.2 per LIHEAP recipient.[526] The
Company’s customer participation rate (5.2%) in LIHEAP is almost identical to
the participation rates of Xcel’s (5.3%) natural gas customers.[527]
427.
The OAG does not specifically criticize the
Company’s LIHEAP outreach efforts. Instead, it argues that the Company should
spend less on court-ordered access, and more on LIHEAP. As discussed more fully in other findings, the
ALJ has concluded that the expenses associated with the court-ordered access program
are appropriate.
428.
The ECC is critical of many aspects of the
Company’s LIHEAP outreach efforts. It
suggested that the Company should focus on mailing to customers who are behind
on their bills to inform them of the availability of LIHEAP;[528] it recommended that the Company inform
customers about the availability of LIHEAP assistance each time the customer
calls in to request a payment arrangement;[529] and it
proposed that LIHEAP information be mailed with disconnection notices
issued during the winter, as well as increased use of outbound calling.[530] In
response, the Company provided evidence that it already takes each of
these proposed actions.[531]
429. The ALJ finds that the level and cost of the Company’s LIHEAP outreach program are reasonable and that the Company’s outreach efforts need not be changed in response to suggestions by the ECC and OAG.
430. The cost of capital and rate of return is addressed in the discussion of the decoupling proposal at Findings 220 to 235.
431.
The Commission’s rules require utilities to file
a Class Cost of Service Study (CCOSS) with every general rate case filing.[532]
432. The purpose of a CCOSS is to identify, as accurately as possible, the responsibility of each customer class for each cost incurred by the utility in providing service. A CCOSS should reflect cost causality, which means that each customer class that imposes a cost on the system should be assigned that cost. The CCOSS can then be used as one important factor in determining how costs should be recovered from customer classes through rate design.[533]
433. There are three steps in performing a CCOSS. First, costs are functionalized, or grouped according to their purpose. Second, costs are classified based on how they are incurred. Third, costs are allocated to the various customer classes.[534]
434. The Company provided the only CCOSS in this proceeding. The Company’s CCOSS used the same Cost Allocation and Rate Design (CARD) model in this proceeding that it used in its recent rate cases.[535] In the Company’s last rate case, the Commission accepted the CCOSS, but with modifications “to allocate income tax expenses in proportion to pre-tax income – for informational purposes.” [536]
435. CenterPoint used a two-step approach to comply with the Commission’s Order in the Company’s 2005 rate case[537] First, the Company calculated the amount of income tax expenses under current rates ($1,663,314) and the amount of income tax expenses on the deficiency (difference between the revenue deficiency and the operating income deficiency, or $24,730,000). The sum of these two amounts ($26,393,314) is the total amount of income tax expenses under the Company’s proposed rates. Then the Company allocated the first amount on the basis of Operating Income Pre Tax Less Interest and the second amount on the basis of Rate Base.[538]
436. Company CCOSS witness Mr. Troxle stated testified that the “rate base” approach is reasonable and appropriate, since required income is determined by applying an allowed rate of return to the rate base number. He further testified that a rate base approach would avoid the negative income tax liability to the residential and small business classes that results form the use of an income tax allocator. According to Mr. Troxle, a “negative” result simply perpetuates an under-recovery by class that resulted, not from true cost causation principles but from rate design policy decisions made in the past.[539]
437. The OES largely agreed with the Company’s CCOSS. However, OES CCOSS witness Dr. Ouanes recommended a different methodology for allocating income taxes. He revised the Company’s method to allocate the amount of income tax expenses on the basis of Operating Income Pre Tax Less Interest under proposed rates to be more consistent with the Commission’s Order in the 2005 rate case regarding the allocation of income taxes and results in a different allocation of income taxes to classes from the Company’s two-step approach.[540]
438. Because rates are not set entirely based on costs, neither the Company nor the OES proposed methods for the current proceeding use current rates or propose rates that fully reflect the CCOSS. However, the OES offers its proposed method as a first step towards addressing this issue.[541] The Company agreed that the OES approach is another acceptable method by which to comply with the Commission’s 2005 rate case Order. However, the OES approach results in a negative allocation of income taxes to the Commercial and Industrial A customer class. For that reason, the Company prefers its approach on this issue.[542]
439. It appears that CenterPoint’s current CCOSS model cannot easily be changed to incorporate the OES’s revisions. The OES recommends that the Commission require CenterPoint to allocate income tax expenses in future CCOSSs based on pre-tax income that fully reflects the CCOSSs.[543]
440. Dr. Ouanes found that some of the Company’s allocation choices were not fully supported, which the Company explained as the result of an effort “to minimize controversy and reduce the analytical burden upon Staff, other parties, the ALJs, and ultimately the Commissioners.”[544] The OES stated that this approach appears to be acceptable for this rate case, but CenterPoint’s CCOSS should be further reviewed in future rate cases.
441. Because CenterPoint’s CCOSS reflects the CCOSS which was accepted in CenterPoint’s last rate case, and CenterPoint has attempted to comply with the Commission’s Order regarding the allocation of income taxes, the OES recommends that the Commission accept the Company’s proposed CCOSS--modified to allocate income tax expenses in proportion to pre-tax income under proposed rates less interest--for use as providing some guidance in designing rates in this case only.[545] The OES also recommends that the Commission require CenterPoint to allocate in future CCOSSs income tax expenses based on pre-tax income that fully reflects the CCOSSs. The OES further recommends that the Commission require the Company to file in future rate cases an explanatory filing identifying and describing each classification and allocation method used in the CCOSS, and justifying why each method is appropriate and superior to other methods considered by the Company. The justification could rely in part on the NARUC Gas Manual, but should also be based on the Company’s specific system requirements (engineering and operating characteristics) and experience.[546] The Company did not object to the OES recommendation.
442. The OAG objected to CenterPoint’s CCOSS, noting that any CCOSS is “arbitrary,”[547] but provided no alternative CCOSS and identified no specific changes it believes should be made to the Company’s study.
443. The OAG also suggested that different levels of return and different interest costs should be assigned to the various rate classes.[548] This approach would depart from accepted practice.[549] In addition, the OAG provided no study, no recommendation, and no example of how such an exercise would be undertaken.[550] The OAG’s recommendation should not be adopted.
444. The Company is correct that in developing its CCOSS in this proceeding, it followed standard industry and regulatory practice and that no other party presented a CCOSS for use in this proceeding. But it did not follow the Commission’s prior Order regarding allocation of income taxes. The OES recommendation recalculating income taxes results in a negative allocation of income taxes to the small Commercial and Industrial Class, but is nonetheless reasonable and should be adopted by the Commission.
445. Using the results of the CCOSS as a guide, CenterPoint proposed an inter-class revenue apportionment that moves rates closer to cost, yet still retains substantial inter-class subsidies.[551]
446. CenterPoint provides several types of service: sales and transportation, firm and interruptible, market rate and standard service. Under sales service, customers rely on CenterPoint to procure and deliver gas service, including gas demand and commodity. CenterPoint does so by arranging for natural gas to be delivered to a Town Border Station and then the Company delivers that gas through its distribution system to the individual customer. Under transportation service, customers acquire their own natural gas supplies through an unregulated gas supplier to be delivered to a Town Border Station and then CenterPoint transports this gas through its distribution system. Larger customers can choose between sales service and transportation service. Transportation-only service is not available to residential and small business customers; instead these customers also take sales service.[552]
447. Customers on sales and transportation services may choose between firm or interruptible service. In addition, customers who are deemed to be subject to effective competition under Minnesota Statute § 216B.163 may take service under a flexible tariff.[553]
448. CenterPoint’s basic service classes include firm and interruptible classes. The three firm sales classes offered are (1) Residential, (2) Commercial and Industrial (“C/I”), and (3) Large General Service (“LGS”), available to commercial and industrial customers whose peak day requirements are greater than 2,000 therms. The Company offers two interruptible (non-firm) sales classes: (1) Small Volume Dual Fuel (“SVDF”), available to commercial and industrial customers with requirements of 25 therms an hour and peak day requirements of up to 2,000 therms; and (2) Large Volume Dual Fuel (“LVDF”) available to commercial and industrial customers with a peak day requirement that exceeds 1,999 therms and CenterPoint’s transportation-only service (i.e., without the sale of natural gas) with separate rates for small and large volume customers.[554]
449. The OES reviewed the rate design recommendations proposed by the Company applying the Company’s proposed CCOSS. Consistent with the Commission’s past practices, the OES recommended that rates be based on the following four goals: (1) rates should be designed to provide the Company a reasonable opportunity to recover all prudently incurred costs, including the cost of capital; (2) rates should be designed to promote an efficient use of resources; (3) rate changes should be gradual in order to limit rate shock to consumers; and (4) rates should be understandable and easy to administer.[555]
450. The OES evaluated the Company’s proposed revenue allocation by comparing the current and proposed revenues with the results of CPE’s proposed CCOSS to determine which customer classes are substantially below their respective cost of service, and which classes are contributing revenues in excess of their cost of service, thus resulting in an inter-class subsidy. The OES also reviewed the revenue contributions from customer classes with bypass or alternative fuel options to ensure that the rates and revenue contributions remain competitive with the given alternatives.[556] CenterPoint proposes to apportion revenue increases as shown in the following table.[557]
Summary of Center Point Energy's Proposed Revenue Apportionment
|
Customer Class |
Current Apportion-ment |
Proposed Apportion-ment |
Cost Based Apportion-ment |
Percent Increase in Revenue w/out gas costs * |
Percent Increase in Revenue w/ gas costs |
|
Residential |
61.99% |
65.98% |
72.74% |
32.59% |
5.95% |
|
C&I – A |
2.42% |
2.47% |
3.24% |
27.45% |
5.96% |
|
C&I – B |
4.23% |
3.99% |
3.80% |
17.59% |
2.95% |
|
C&I – C |
16.54% |
14.65% |
11.22% |
10.34% |
1.45% |
|
|
|
|
|
|
|
|
Small Volume Dual Fuel – A |
4.34% |
3.98% |
2.20% |
14.30% |
1.55% |
|
Small Volume Dual Fuel – B |
3.38% |
3.13% |
1.48% |
15.17% |
1.50% |
|
|
|
|
|
|
|
|
Large Volume Sales &
Transportation |
7.10% |
5.80% |
5.32% |
5.32% |
1.68% |
|
Total |
100.00% |
100.00% |
100.00% |
24.57% |
3.95% |
* Note: the percentages in this column do not equal the percentage difference between “Current Apportionment” and CenterPoint’s “Proposed Apportionment.”[558]
451. Based on its review and analysis, the OES supported the Company’s proposed revenue apportionment, concluding:
[T]he Company’s proposal moves each class closer to cost . . . without placing an unreasonable burden on any class. . . [U]nder the Company’s proposal the Residential and C&I-A classes continue to be allocated costs that are less than the cost of service resulting from the CCOSS. Specifically, the residential class would be allocated 90.70% of the cost of service and the C&I-A class would be allocated 76.41% of the cost of service. I conclude that this proposal appropriately balances the goals of moving rates closer to cost while recognizing concerns regarding rate shock.[559]
452. The OES originally proposed that, if the Commission ultimately approves a lower revenue requirement than the $59 million requested by the Company, the proposed revenue increases to the Dual Fuel classes should remain unchanged, with the benefit of the lower revenue requirement instead being spread over the Residential and Commercial/Industrial classes.[560]
453. In response, the Company indicated that, in order to maintain the appropriate relationship of delivery charges among the classes, the Small Volume Dual Fuel A and B customer classes should also receive a pro rated share of any reduced revenue requirement.[561] Otherwise, the Company and its other customers risk having these Small Volume Dual Fuel customers switch to firm service, losing the system benefits of having interruptible customers.[562] The OES agreed. Thus, both the Company and OES recommended that any reduction in revenue requirement be prorated among the Residential and all Commercial/Industrial and Small Volume Dual Fuel customer classes.
454. There are two types of commodity rates for qualifying classes: standard rates and flexible rates. Once standard rates are approved, CenterPoint may not change them without an Order from the Commission except to reflect changes in the cost of gas. Under flexible rates, however, CenterPoint can vary the non-gas portion of the commodity rate for eligible customers within a specified range. This flexibility allows the Company to remain competitive with alternative fuels when prices of those alternatives fall below standard gas prices.[563]
455. CenterPoint sets its flexible rates so that the rate can be increased above the standard rate by the same amount that it can be discounted. The Commission has accepted this methodology for setting flexible rates in previous CenterPoint rate cases. The OES testified that the Company’s current proposal is reasonable since it appropriately retains the same level of flexibility to flex upward or downward.[564]
456. CenterPoint proposes relatively little increase in the revenue apportionment for the LVDF class. It does propose that the LVDF sales and transportation classes, taken as a whole and considering the need to keep the sales and transportation margin equal, pay close to but slightly more than the embedded cost of serving the two classes. The OES concluded that CenterPoint’s proposed revenue apportionment for LVDF customers is reasonable.[565]
457. The OES also applied its criteria in determining the revenue responsibility for the SVDF sub-class using the competitive value-of-service approach. The OES first reviewed the price of natural gas compared to the prices of alternative fuels used by SVDF customers (i.e., No. 2 fuel oil). The OES’s review of the curtailment history of these customers showed that SVDF customers have been curtailed with more regularity since the Company's last general rate case than had been the case prior to that time.[566]
458. During an on-site review of the Company's records, the OES determined that the Company’s records indicate that past practices of those customers show that SVDF customers value natural gas service more than any other alternative fuel. By not switching to an alternative fuel or bypassing the system altogether the SVDF customers have shown that the current level of natural gas service is appropriate and has "value" for them. Therefore, the OES reasonably concluded that the service currently received from CenterPoint has an appropriate amount of value for these customers. Under CenterPoint’s proposed apportionment, SVDF customers continue to be apportioned more revenue responsibility than under a cost-based apportionment. However, the rates charged to these customers would modestly increase under the Company’s proposal. Therefore, the OES concluded that CenterPoint’s proposed revenue apportionment for SVDF customers is reasonable.[567]
459. Under the Company’s proposal, the residential and C&I-A classes will experience an increase in cost including the cost of gas of 5.95% compared to an overall increase of 3.95%. This proposal moves these classes closer to cost. The Residential and C&I-A classes continue to be allocated costs that are less that the cost of service as determined from the CCOSS. Specifically, the residential class would be allocated 90.70% of the cost of service and the C&I-A class would be allocated 76.41% of the cost of service. The OES concluded that the Company’s proposal should be adopted because it moves each customer class closer to cost, while maintaining the relationship between sales and transportation margins, without placing an unreasonable burden on any class.[568]
460. The OAG disagrees with the Company and OES proposed revenue apportionment, recommending an across-the-board increase to all customer classes.[569]
461. The OAG recommendation ignores cost issues in their entirety and is not a reasonable result. The OES correctly noted that Company’s CCOSS is the “best and only indication of costs to serve each class of customers that is available in the record.”[570] Moreover, “there is no indication in the record that the costs to serve the classes would warrant applying an equal increase to each class.”[571]
462. The Company and the OES gave significant weight to appropriate non-cost factors in their proposed revenue allocations, recommending only incremental movement toward the cost of service as indicated by the CCOSS. That recommendation is reasonable and the Company’s revenues should be apportioned as set forth in the Company and OES testimonies.
463. The Company proposed modest increases in the customer (or “basic”) charge in each of its customer classes, in order to move those charges closer to cost, while still recognizing concerns for gradualism and guarding against “rate shock.”[572]
464.
For the Residential Class, the Company’s CCOSS
showed a fixed cost per customer of more than $20.00 per month; however, the
Company proposed to increase the charge from $6.50 to $8.00 – the same basic
charge currently approved by the Commission for Xcel Energy and Greater
Minnesota Gas.[573]
465.
The OES agreed with the Company’s customer
charge proposal for all but the largest customer classes.[574] For the
smaller customers, including the Residential class, OES agreed that the
Company’s proposal reasonably moved the basic charges closer to cost, without
causing “rate shock” or other concerns. For the largest customer classes, OES
recommended somewhat larger increases to bring the charges more in line with
costs.[575] Finally,
the OES indicated that its customer charge proposal should be adopted, whether
or not the Company gains approval of its decoupling pilot program.[576]
466. The Company’s position is that moving the large customer classes fully to cost would be a dramatic change that it could not support, since it would lead to customer charge increases of 150% to 10,000%.[577] In the event the Commission approves of the pilot decoupling program, the Company agreed to the OES’s recommendation to increase the basic charge for these large customer classes somewhat more than it initially proposed. Thus, if the Commission approves the pilot decoupling program for CenterPoint Energy, all parties but the OAG agreed to the following customer charges by class:
Class Current Basic New Basic Charge/Month Charge/Month
Residential
$6.50 $8.00
Commercial/Industrial
– A $9.50 $12.00
Commercial/Industrial
– B $15.00 $18.00
Commercial/Industrial
– C $35.00 $43.00
Small
Volume Dual Fuel – A $50.00 $60.00
Small
Volume Dual Fuel – B $75.00 $90.00
Large
Volume Dual Fuel -
Sales $400.00 $600.00
Large
Volume Dual Fuel –
Transportation $500.00 $700.00
Large
Volume Firm –
Transportation $500.00 $700.00
467.
The OAG objected to any increase in the basic
charge for the Residential or Commercial/Industrial A classes, whether or not
the Commission approves a decoupling pilot program for the Company.[578]
468.
The OAG’s recommendation would leave the basic
charges for these classes far below cost and out of line with the charges
approved for other
469. The record supports the reasonableness of these customer charges, as agreed to by the Company, OES, MCEA, IWLA and ECC. In the event that the Commission does not approve the proposed decoupling program, the Company proposes to increase the basic charge for the Residential class to $14.00. The ALJ does not recommend that the basic charge for residential customers be increased so significantly in one step. The ALJ recommends that the Commission approve the basic charges listed above, even if the decoupling program is not approved.
470. In the Company’s 2005 rate case, the Commission approved a gas affordability program (GAP) under Minn. Stat. §216B.16, subd. 15. The program is designed to:
· decrease the percentage of income that low-income households devote to energy bills;
· increase payments by participating customers over time by increasing the frequency of payments;
· decrease or eliminate arrears for participating customers;
· decrease a utility’s costs associated with customer collection activities; and
· coordinate the program with other low-income bill payment assistance and conservation resources.
Customers who receive financial assistance under LIHEAP are eligible to participate in the GAP.[579]
471. CenterPoint’s GAP was initially approved by the Commission as a pilot program, with an implementation date of May 1, 2007, and a termination date of December 31, 2010. Costs of the program are paid by CenterPoint’s firm ratepayers, except for firm customers who take natural gas service only under market (flexible) rates.[580] The Commission approved a program cap of $5 million, and a rate of $0.0054/therm to be applied to these appropriate firm ratepayers’ bills, with the GAP revenues and expenses being tracked in a tracker account.[581]
472. Financial assistance under the GAP consists of two components: the affordability component and the arrearage forgiveness component.[582] The affordability component consists of a bill credit determined as one-twelfth of the difference between CenterPoint’s estimate of the Qualified Customer’s annual gas bill and 6% of the Qualified Customer’s household income as provided by the Qualified Customer to CenterPoint. This bill credit is a Program cost included in the Tracker. Any energy assistance sums not applied to arrears are to be applied to a Qualified Customer’s current bill. The Arrearage Forgiveness component consists of a monthly credit applied each month after receipt of the Qualified Customer’s payment. The credit is designed to retire pre-program arrears over a period of up to 24 months, with the Company matching the Qualifying Customer’s contribution to retiring pre-program arrears. This arrearage forgiveness credit is a Program cost included in the Tracker.
473.
CenterPoint’s GAP, consistently with the
later-approved GAPs of six other
474. The Company proposed no changes to the GAP program in this docket. To the extent that any modifications are necessary, the Company believes those changes should be made after review of the program at the end of the pilot period.
475. ECC proposes several specific changes to the Company’s GAP in this proceeding. First, ECC seeks to extend the end date of the GAP pilot to May 31, 2011, such that the program would operate for a full four years, although on a non-calendar year basis. In addition, ECC recommends changes to the Affordability Credit by:
· decreasing the percentage that participating customers are required to pay from six percent to four percent of household income; and/ or
· excluding LIHEAP grants from a participant’s GAP credit calculation.[587]
476. ECC
does not propose increasing CenterPoint’s $5 million cap for the program.[588] ECC
states that its proposal would “re-direct” GAP money to fewer customers than
those who currently participate in the program.
ECC proposes that the number of participating GAP customers would
decrease to the “originally estimated level.”[589] Thus,
based on the current GAP participation level of approximately 15,000 LIHEAP
customers, it appears that ECC expects the impact of its proposed GAP changes
to result in elimination or disqualification of at least 5,000 current
participants in order to meet the originally estimated level of between 7,500
to 10,000 participants.
477. The OES opposes the changes recommended by the ECC. The OES recommends continuing CenterPoint’s GAP as it is currently approved (on a calendar year basis), rather than extending the end date by five months.[590] Although LIHEAP operates on a fiscal year basis, the benefit of administering the Company’s GAP on a calendar year basis is that it will allow ready comparison with the results of the other utilities’ GAPs, which operate on a calendar year basis. If, however, the Commission wishes to consider extending the pilot period, the OES suggests extending the end date by one year, to December 31, 2011, in order to retain the calendar year basis of CenterPoint’s GAP.[591]
478. The OES also opposes the proposal to change the calculation of the Affordability Credit at this time, on the basis that the proposed changes would increase the program cost per participant and could be implemented only by drastically decreasing the number of current GAP participants.[592]
479. CenterPoint expects to reach the Commission-approved GAP cap of $5 million by the end of 2009.[593] Thus, without raising the cap, ECC’s proposals will require elimination of some of the current low income customers from the GAP.[594] In addition, ECC’s proposal to decrease the percent of household income (increase the GAP payment) per participant from six percent to four percent, would appear to increase significantly the per participant program cost of the Affordability Credit.
480. ECC did not provide an estimate of the expected magnitude of impact on current GAP customers that may occur as a result of ECC’s proposed change in calculating the Affordability Credit.[595] The OES evaluated the financial impact of ECC’s proposals using two different assumptions: one assumption was that the current level in GAP participation through May 2009 was extended to an entire year; the other was that current participation levels remained about the same.[596] Under a no-growth assumption, together with ECC’s example that its proposed changes would increase the amount of the GAP credit per participant, from $6.66 to $40, a significant decrease in existing GAP participants would be inevitable in order to stay within the $5 million cap. Even if the existing number of participants were to remain about the same, or about 15,000 for ease of calculation, ECC’s proposal would add approximately $5.4 million to the GAP in additional expenses.[597]
481. The ALJ recommends that the Commission deny ECC’s proposed changes to the GAP program. Extending the program as proposed would make it more difficult to compare the results from one utility to another, and changing the calculation of the affordability credit would likely lead to a drastic decrease in current participation. Any changes of this magnitude should be made only after completion of the pilot term.
482. The Company’s initial filing proposed various tariff changes. Other than certain specifically noted exceptions, the OES recommended that the Company’s proposed tariff changes be approved.[598] No other party provided testimony on these issues.
483. The OES raised concerns regarding the Company’s tariff for customer-requested construction activities during the winter, which the Company had inadvertently neglected to file. OES recommended that the Company be ordered to file a miscellaneous tariff on this matter, and the Company agreed to file such a tariff.[599]
484. The OES further recommended that the Company continue reporting winter construction information in the Company’s Annual Jurisdictional Report, at least until the Commission approves the tariff provisions regarding winter construction, customer-requested additional service line, extension alterations, and meter relocations. In addition, the OES recommended that the Company be required to continue tracking this winter construction data for possible use in future proceedings. The Company has no objection to such reporting.
485. The Commission’s December 22, 2008 Notice and Order for Hearing identifies the following issues for hearing:
(7) How do Commercial/Industrial Class C customers meet the eligibility criteria for the Company's market-rate service rider? How many market-rate customers does the Company have?
(8) How does the "guaranteed savings discount" bill credit work? What is the source of the money for the discount? Why is the bill credit applied to all volumes of gas sold rather than just the market-rate volumes?
(9) How does the market-rate premium paid by customers work and where does the money go?
(10) How are the guaranteed savings discount and the market-rate premiums and/or discounts incorporated into the calculations of the Company's revenue deficiency for final rates, revenue deficiency for interim rates, and any potential interim rate refund?
486. In response to these questions, the Company filed Supplemental Direct Testimony of Douglas W. Peterson. Mr. Peterson described the eligibility criteria as provided in the Market Rate Service Rider and the number of customers on market rates. He then explained that the “guaranteed savings discount” credit referenced by the Commission was provided by a Marketer, CenterPoint Energy Services (“CES”), for unregulated energy services. Mr. Peterson stated that he does not work for CES or any other unregulated Marketer and therefore cannot answer the questions found in items 8 and 9. In response to item 10, Mr. Peterson further stated that as the guaranteed savings discount and market-rate premiums/discounts are found in a CES billing statement issued to a customer, these billing components do not relate to any CenterPoint charges and would, therefore, not be incorporated into CenterPoint’s ratemaking process.[600]
487. The Company also provided a copy of the customer bill that is the source of the Commission’s concerns.[601] That bill is from CES, a non-regulated marketer. As a non-regulated marketer, CES is not under the Commission’s jurisdiction. The Commission, therefore, does not approve, reject or modify the rates charged by CES, nor are the rates charged by CES incorporated into CenterPoint Energy’s ratemaking process.
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 that should be treated as Conclusions are hereby adopted as Conclusions.
3. CenterPoint and the Stipulating Parties have demonstrated that, with the exception discussed in Conclusion 12 below, the Decoupling Program as agreed to and outlined in the Stipulation and accompanying CE Rider meets the requirements for a Pilot Decoupling Program pursuant to Minn. Stat. § 216B.2412 and the Commission’s June 19, 2009 Decoupling Order.
4. The CE Rider, the Stipulation, and Exhibit A attached to the Stipulation demonstrate that the Decoupling Program will adhere to the guiding statute and is designed to encourage CenterPoint to pursue energy efficiency free from the competing goals of profitability and support of the State’s energy goals. Because the Decoupling Program will adjust rates annually on the gas delivery charge, which is typically only 20-30% of a customer’s bill, the adjustment will not “adversely affect . . . ratepayers.”
5. The form of the Decoupling Program is a partial decoupling mechanism because it will exclude weather-related changes in gas use in the adjustment calculation. The Decoupling Program will not exclude other causes of changes in use such as economic conditions, rising gas prices, building codes or appliance standards. This partial decoupling mechanism should be approved because it meets the requirements of both Minn. Stat. § 216B.2412 and the Decoupling Order, neither of which require a proposed decoupling mechanism to be a limited decoupling mechanism.
6. CenterPoint has demonstrated that implementation of the Decoupling Program would not warrant any adjustment to the Company’s cost of capital because, while the Decoupling Program would lower the amount of risk to the Company and provide further stability for it, its debt rating will take into account all of the factors that affect risk to the Company.
7. CenterPoint failed to demonstrate that its cost of capital should be increased if the Decoupling Program is not approved because it failed to show that disapproval of the decoupling program would put it at any greater risk than it is at the current time.
8. The OAG/RUD failed to demonstrate that the Commission should order a downward adjustment of “no less than 27 basis points” to the Company’s return on equity if the Decoupling Program is approved because it presented no underlying evidence specific to CenterPoint to support the reasonableness of such an adjustment.
9. CenterPoint has identified the rate classes involved in the Decoupling Program and demonstrated reasons for the inclusion of certain classes and exclusion of others. The evidence supports CenterPoint’s position that Residential and Commercial/Industrial A, B and C classes are most likely to be impacted by future conservation efforts and have shown significant decreased sales per customer. Furthermore, dual fuel customers are reasonably excluded because they are more likely to use natural gas for processing and therefore most likely to be affected by general economic conditions rather than energy efficiency. In addition, these classes include market rate customers whose rates are governed by contract which cannot be overridden by the Decoupling Program.
10. Except for its failure to provide for transparency by listing the Decoupling adjustment on a separate line on ratepayers’ bills, CenterPoint provided sufficient detail on how the Decoupling Program will operate to meet the requirements of transparency and ease of understanding.
11. As described in Findings 244 through 251 of this Report, the adjustment will be calculated and applied annually to the delivery charge on a volumetric basis.
13. The proposal for an initial three-year pilot term for the Decoupling Program is consistent with both the decoupling statute and the Decoupling Order.
14. The cap on adjustments will protect customers from rate shock, especially given that upward adjustments will, by definition, be accompanied by a downward trend in gas consumption.
15. The methodology used in calculating the Decoupling Program’s rate adjustments is simple, straightforward, and transparent. As such, the Parties have proposed a mechanism that should have minimal controversy surrounding its calculation and which should be easy to administer.
16. With the exception of the proposal to include the Decoupling Program adjustment in the delivery charge, rather than displaying it as a separate line item on the customer’s bill, the mechanics of the Decoupling Program are straightforward and transparent. As such they are reasonable for this pilot Decoupling Program.
17. By excluding gas revenues and revenues associated with the CIP Adjustment Rider, the GAP program, the Franchise Fee Rider, the CIP revenues collected through base rates, any Bad Debt Expense Recovery Mechanism revenues approved in this docket and other non-rate class specific revenues from the calculations of the CE Rider adjustment, the Company insures that no “double recovery” occurs for these items. Therefore, continuation of these other rate mechanisms throughout the pilot program period is appropriate.
18. Because the Company’s Demand Side Management Financial Incentive does not award “lost margin” recovery, the Decoupling Program is complementary to rather than duplicative of the Demand Side Management Financial Incentive.
19. The Decoupling Program includes detailed plans on how CenterPoint plans to measure and maintain service quality under the program consistent with the standards set forth in the Decoupling Order.
20. The information the Company agrees to provide in its annual evaluation report exceeds the requirements of the Commission’s Decoupling Order.
21. CenterPoint and the Stipulating Parties have demonstrated that the Inverted Block Gas Cost (IBGC) structure proposed in the Stipulation and accompanying CE Rider is reasonable and appropriate, if implemented in conjunction with the Decoupling Program. The proposed IBGC structure will encourage conservation by sending a strong price signal to high-volume customers, and will lessen the impact of the Decoupling Program on smaller-volume customers, including low-income small-volume customers.
22. The OAG, has failed to demonstrate that implementation of the IBGC structure in the absence of a Decoupling Program would serve the goals of the NGEA and related statutes. Because the IBGC encourages conservation, implementation of the IBGC structure without the Decoupling Program would make the Company even more vulnerable to decreased sales than it is under the current rate structure. Such a result would be directly contrary to the purpose of the decoupling statute.
23. Minn. Stat. § 216B.241 and 2009 Minn. Laws ch. 110, § 32, do not establish conditions precedent which must be met before a Decoupling Plan can be approved pursuant to Minn. Stat. § 216B.2412.
24. Nothing in the language of 2009 Minn. Laws, Ch. 110, § 32; Minn. Stat. § 216B.2412; or the Commission’s Decoupling Order requires the Company to exceed the conservation goals it sets under its Interim Energy Savings Plan or to include specific conservation plans as part of the proposed Decoupling Program. Under its Decoupling Order, the Commission will review the Decoupling Program based on whether the Decoupling Program has influenced the achievement or likelihood of achievement of the Company’s energy efficiency savings goals.
25. Because the Decoupling Program includes an evaluation plan that exceeds the Decoupling Order’s requirements, it meets the requirements in Minn. Stat. § 216B.2412 that it “assess the merits of a rate-decoupling strategy to promote energy efficiency and conservation” and that it “be designed to determine whether a rate-decoupling strategy achieves energy savings.”
26. The Midwest Gas replacement costs were safety-related pipeline program costs for which the Legislature expressly authorized recovery and were not “exchange-related cost increases….” Therefore, there is no basis to re-open the PUC Docket number 93-92 to reconsider the costs allowed in that case in which the Commission reviewed and approved the transaction whereby CenterPoint acquired the MidAmerican Energy properties.
27. The Commission decided in Docket number 05-1380, the 2005 CenterPoint rate case, that CenterPoint’s expenses in the Midwest Gas Replacement Project were completely allowed pursuant to Minn. Stat. § 216B.16, subd. 11, withholding only 10 percent of those expenses to insure that the Company exhausted its legal remedies against third parties. Nothing in the Commission’s Order in the 2005 docket permits re-evaluation of that decision.
28. Because it has met the condition the Commission specified in the 2005 rate case of exhausting its legal remedies against third parties, the Company is entitled to receive the remaining ten-percent of its costs in the Midwest Gas Replacement Project.
29. The Company is entitled to collect a carrying charge based on a rate of 5.78% on the ten-percent of its recovery withheld in the 05-1380 Docket.
30. The ECC’s proposed bad debt factor should not be adopted. Rather, the 2.05% bad debt factor, and corresponding bad debt adjustment of $4,717,703, agreed to by the Company, OES, and OAG should be adopted.
31. There is not a preponderance of the evidence to support of the BDER mechanism. Given the uncertainty of the evidence, the proposal should not be adopted.
32. There was no direction by the Commission in the 06-1429 Docket or the MERC docket that the CIAC method of analyzing extension costs should used in this case. The Notice of and Order for Hearing in this case specified no such requirement even though the 90-563 Order was explicit that any issues to be addressed regarding extensions would be set out in the Orders for Hearing. The OES can normally require a company to perform reasonable analyses of its claimed cost. But in this case there is an express provision in the 90-653 Order that was not followed. It would be unfair to impose the additional requirement on the Company well after it had filed its application.
33. The Company has met its burden of establishing compliance with prior Commission orders and its tariff as it relates to the Company’s proposed rate base adjustments for service and main line extensions. The OES’s proposed adjustment should not be adopted.
34. The record demonstrates that the environmental tracker account continues to serve the purpose for which the Commission established it. Retaining the account accomplishes the Commission’s objectives when it directed establishment of the account in 1995.
35. The application of carrying charges insures that neither ratepayers nor shareholders benefit from the tracker balance, thus, no harm to ratepayers results from keeping the tracker mechanism in place. Continuing the tracker account insures that ratepayers will pay the cost of prudent remediation, no more and no less, an important fact in the face of significant uncertainties regarding the cost and timing of required cleanups. Finally, the ongoing annual reporting assures that the Commission will continue to have oversight of this account.
36. If the environmental tracker is closed and the money in the account is refunded to ratepayers, any short-term “benefit” to ratepayers associated with a one-time “refund” would shift the burden by concurrently increasing rates to include an ongoing environmental clean-up cost in rates, and additionally could require a substantial increase to cover specific higher remediation costs at the time they occur.
37. If the tracker account is closed and “a normalized level of environmental clean-up costs” is included in the base rate in this case, that level should be based on an average of the years 2001-2008 which, with the exception of 2001, have remained within a significantly lower dollar range than the years between 1991 and 2000.[602]
38. Based upon the average of the intervals between the Company’s most recent rate case filings, and based upon its anticipated timing for the filing of its next rate case, and in view of the three-year time limit on the pilot Decoupling Program, a three-year amortization period for rate case expenses is supported by a preponderance of the evidence.
39. The Commission has limited the incentive compensation to 25 percent of base pay in seven recent rate cases, and to 15 percent of base pay in one case. The OES’s recommendations regarding the LTIP and STI adjustments follow that precedent, are reasonable, and should be adopted.
40. The OES recommendation that the Commission require CenterPoint to refund to customers all incentive compensation approved by the Commission and included in base rates, but not paid to employees is also reasonable and should be adopted.
41. The OES recommendation that the Commission require an annual report on incentive compensation similar to the annual report required from Northern States Power in Docket Nos. E002/GR-92-1185 and G002/GR-92-1186 is also reasonable and consistent with Commission practice. It should be adopted.
42.
The Company has demonstrated that its court
ordered access process is consistent with
43. The Company further demonstrated that the OAG’s proposal to discontinue the court ordered access process and, instead, dig the line outside of the premises, as well as the OAG’s proposal to move all of the Company’s inside meters to the outside of each premise, is not in the interests of the Company’s ratepayers.
44. Minnesota Rule 7820.3100 requires the Company to seek a court order to obtain access where consent is otherwise not provided. Minnesota Rule 7820.2400 addresses disconnection procedures. The Company has demonstrated that it is meeting the requirements of both of these rules with its customer notification procedures for impending disconnection and court-ordered access.
45. In this case, the OAG argued that, although the Company may gain access to inside meters for meter readings and inspections, it may not use a court order to gain access to a customer’s premises for disconnection. The OAG’s arguments are not supported by the record. When the Company disconnects service, it follows each and every step of the disconnection process required by the applicable statutes and rules.
46.
The ALJ finds that the record evidence supports
the Company’s continued use of court ordered access to disconnect delinquent,
non-responsive customers, as the process is in accordance with
47. The Company’s lobbying expenses should be denied. There has been no reliable demonstration and quantification that the expenditures were in the best interest of ratepayers.
48. The composite ratio proposed by the Company and the OES results in lower costs being allocated to Minnesota ratepayers than does a general allocator properly calculated in accordance with Commission docket number 90-1008. The use of the composite ratio is fully supported by the record, consistent with Commission precedent, and in the public interest. It should be accepted by the Commission.
49. The OES’s proposed escalation factor of 6.01 percent, which CenterPoint has accepted, is reasonable and should be accepted by the Commission.
50. CPE failed to demonstrate that it is reasonable to substitute a 10-year period, rather than a 20-year period, to determine normal test-year weather for use in calculating the test-year forecast. Pending further inquiry into the question of the best time period to use to determine test-year weather in utility rate cases, it is reasonable for the Commission to continue to use the 20-year period it has used in the past.
51. Should the Commission decide to include the CIP Tracker account balance as a test-year expense instead of netting the actual, unamortized balance against any interim rate refund in this docket, it is reasonable to apply the same three-year amortization period to the CIP tracker account balance as is applied to the rate case expense.
52. The costs to lock and unlock a meter have remained approximately the same since the last rate case and the Commission has indicated a preference for retaining some level of intra-class subsidy for this service. Therefore, the reconnection fee should not be increased.
53. The Company demonstrated that the level and cost of its LIHEAP outreach program is reasonable and need not be changed. ECC and the OAG failed to demonstrate that it is reasonable to require increased outreach in the LIHEAP program.
54. The Company is correct that in developing its CCOSS in this proceeding, it followed standard industry and regulatory practice and that no other party presented a CCOSS for use in this proceeding. But it did not follow the Commission’s prior Order regarding allocation of income taxes. The OES recommendation recalculating income taxes results in a negative allocation of income taxes to the small Commercial and Industrial Class, but is nonetheless reasonable and should be adopted by the Commission.
55. The Commission should accept the Company’s proposed CCOSS, modified to allocate income tax expenses in proportion to pre-tax income under proposed rates less interest. The Commission should also require CenterPoint to allocate in future CCOSSs income tax expenses based on pre-tax income that fully reflects the CCOSSs.
56. Based on its review and analysis, the OES supported the Company’s proposed revenue apportionment because it moves each class closer to cost without placing an unreasonable burden on any class. The Company’s revenue apportionment should be adopted.
57. The OES originally proposed that, if the Commission ultimately approves a lower revenue requirement than the $59 million requested by the Company, the proposed revenue increases to the Dual Fuel classes should remain unchanged, with the benefit of the lower revenue requirement instead being spread over the Residential and Commercial/Industrial classes. Both the Company and OES now recommended that any reduction in revenue requirement be prorated among the Residential and all Commercial/Industrial and Small Volume Dual Fuel customer classes. That recommendation should be adopted as well.
58. The Company demonstrated that the customer charges that CenterPoint, OES, MCEA/IWLA and ECC agreed to are reasonable and would move the charges closer to cost without causing “rate shock.”
59. The Company failed to demonstrate that an increased residential basic charge to $14.00 per month is reasonable in the event that the Decoupling Program is not approved.
60. ECC failed to demonstrate that its recommended changes to the GAP program are either reasonable or necessary. The changes urged by ECC would significantly alter the nature of the program, which is a pilot program, and would interfere with evaluation of the program. In addition, the changes would have a significant negative impact on many of the programs current participants.
61. The Company demonstrated that its proposed tariff changes are reasonable, and that it will supplement the proposed tariff with an additional filing for customer-requested construction activities during the winter.
62. The Commission’s concerns about the Market Rate Service Rider arose out of a customer bill from CES, a non-regulated marketer. The Commission lacks jurisdiction to review the rates charged by CES, or to incorporate them into CenterPoint’s ratemaking docket. Therefore, it is reasonable for the Commission to decline to address the questions relating to the Market Rate Service Rider.
Based on the foregoing Findings and Conclusions, IT IS RECOMMENDED that the Minnesota Public Utilities Commission order that:
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, 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.
4. 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.
Dated: November 2, 2009
/s/ Steve M. Mihalchick
__________________________
STEVE M. MIHALCHICK
Administrative Law Judge
[1]
[2] In
the Matter of the Application of CenterPoint Energy for Authority to Increase
Natural Gas Rates in
[3] Exh. 652 at 9 (Griffing Direct).
[4]
[5] See
Exh. 110 at 2 (Baker Direct); and Ex. 121 at 556-56 (Nesvig Direct).
[6] 2008 CenterPoint Rate Matter, Order
Accepting Filing, Suspending Rates, and Requiring Filing of Waiver (Dec. 22,
2008) and Order Setting Interim Rates (Dec. 22, 2008).
[7] See
Exhs. 1 through 33.
[8]
[9]
[10] See, e.g., Coon Rapids Public Hearing (July 14, 2009) Tr. at 12.
[11]
[12]
[13]
[14]
[15]
[16]
[17]
[18]
[19]
[20]
[21]
[22]
[23]
[24]
[25]
[26]
[27]
[28]
[29]
[30]
[31]
[32]
[33]
[34]
[35]
[36]
[37]
[38]
[39]
[40]
[41]
[42] See Public Comments 1, 2, 7 and 15.
[43] See Public Comment 32.
[44] See Public Comment 33.
[45] See Public Comments 2,4,6,8,9,10-16, 19-21, 24-25, 28-29.
[46] See Public Comments 1,3, 4, 26 and 31-32.
[47] See Public Comment 32.
[48] See Public Comments 3,6 and 13.
[49] See Public Comment 31.
[50] See Public Comment 32.
[51] See Public Comment 22.
[52] See Public Comment 23.
[53] See Public Comment 5.
[54] See Public Comments 24 and 26.
[55] See Public Comments 28 and 32.
[56] See Public Comment 28.
[57] See Public Comment 32.
[58] See Public Comments 27 and 30.
[59] CPE and OES list “Cost of Capital” as a
resolved financial issue. But the issue
is only resolved between those two parties if the decoupling program is approved. On the other hand, OAG/RUD disagrees with the
CPE/OES resolution if the decoupling program is approved. Thus, there is no consensus among the
parties; therefore, the ALJ will address this issue separately.
[60] OES Exh. 643 at 3-6 and Attachment MAS-2 (
[61] CPE Exh. 121 at 33-34 and CPE Exh. 104 at
Schedule 15,Workpaper 14 (Nesvig).
[62] OES Exh. 643 at 12 (
[63]
[64]
[65] CPE Exh. 120 at 9 (Pennington).
[66] CPE Exh. 111 at 4-6 (Baker); OES Exh. 646 at 3-4 (
[67] CPE Exh. 121 at 118-121 and Schedule 32
(Nesvig).
[68]
[69] OES Exh. 600 at 77-83 (Heinen).
[70] CPE Exh. 120 at 11-13 and Schedules 4 and 5
(Pennington).
[71] OES Exh.
615 at 3-7 and Schedules S-1 to S-3 (Heinen).
[72] Tr. Vol. 1 at 143 (Pennington) and at 154
(Nesvig).
[73] OES Exh. 615 at 7 (Heinen).
[74] CPE Exh. 127 and associated workpapers in
CPE Exh. 103 (Drews).
[75] See
OES Exh. 600 at 42-63 (Heinen).
[76] CPE Exh. 128 at 2 (Drews).
[77]
[78]
[79] CPE Exh. 121 at 72 (Nesvig).
[80]
[81] OES Exh. 607 at 69-77 (Heinen).
[82]
[83]
[84]
[85] OES Exh. 650 at 14 (Johnson).
[86] OES Exh. 647 at 12 and 650 at 14 (Johnson).
[87]
[88] CPE Exh. 121 at 31 (Nesvig).
[89] OES Exh.
647 at 23-24 (Johnson).
[90]
[91] CPE Exh. 122 at 9 (Nesvig); OES Exh. 650 at
5 (Johnson).
[92] CPE Exh. 121 at 17-18 (Nesvig).
[93] OES Exh. 647 at 29 (Johnson).
[94] CPE Exh. 122 at 25-26 (Nesvig); OES Exh.
650 at 15 (Johnson).
[95] CPE Exh. 121 at 32 (Nesvig).
[96]
[97] OES Exh. 650 at 8-9 (Johnson).
[98]
[99]
[100] CPE Exh. 121 at 80-81 (Nesvig).
[101] CPE Exh. 122 at 10-11 (Nesvig).
[102]
[103]
[104] OES Exh. 651 at 13 (Johnson).
[105]
[106]
[107]
[108] Tr.. Vol. 1 at 156 (Nesvig).
[109] CPE Exh. 121 at 78-84 (Nesvig).
[110]
[111]
[112]
[113] OES Exh. 643 at 27-28 (
[114]
[115] OES Exh. 650 at 18 (Johnson); CPE Exh. 122
at 2-3 (Nesvig).
[116] OAG Exh. 507 at 16-18 (Lindell).
[117] OAG Exh. 508 at 17-18 (Lindell).
[118] CPE Exh. 121 at 84-85 (Nesvig).
[119]
[120] OES Exh. 643 at 37 (
[121]
[122]
[123]
[124] OES Exh. 646 at 18 (
[125] Tr. Vol. 1 at 156-157 (Nesvig).
[126] CPE Exh. 121 at 69-70 (Nesvig).
[127]
[128]
[129]
[130]
[131] OES Exh. 643 at 41 (
[132]
[133] CPE Exh. 122 at 12-13 (Nesvig).
[134]
[135] OES Exh. 646 at 19 (
[136]
[137] CPE Exh. 1121 at 98 (Nesvig).
[138]
[139] OES Exh. 643 at 42 (
[140]
[141]
[142]
[143] CPE Exh. 122 at 16-17 (Nesvig).
[144] OAG Exhibs. 507 at 54-78 and 508 at 2-11
(Lindell).
[145] CPE Exh. 122 at 29 (Nesvig).
[146] CPE Exh. 123 at 9 (Nesvig).
[147] CPE Exh. 121 at 15 and Schedule 9 (Nesvig).
[148]
[149] OES Exh. 633 at 4 (Minder). To the extent
that the Commission decides not to net the balance against any interim rate
refund, the Company proposed a two-year amortization period to recover the test
year CIP expenses. The Company’s discussion of the appropriate amortization
period for purposes of this issue and recovery of rate case expenses is
addressed in further detail, below.
[150] CPE Exh. 121 at 15 (Nesvig); OES Exh. 633
at 11 (Minder); CPE Ex. 122 at 18-19 (Nesvig).
[151] CPW Exh. 121 at 15 (Nesvig); OES Exh. 633
at 12 (Minder).
[152] OES Exh. 633 at 13 (Minder).
[153] CPE Exh. 122 at 19 (Nesvig).
[154] CPE Exh. 121 at 52 (Nesvig).
[155] OES Exh. 633 at 39 (Minder).
[156] CPE Exh. 122 at 22 (Nesvig).
[157] CPE Exh. 121 at 37-38 (Nesvig).
[158]
[159]
[160] OES Exh. 633 at 26 (Minder).
[161]
[162]
[163]
[164]
[165] CPE Exh. 122 at 20 (Nesvig).
[166]
[167]
[168]
[169] OES Exh. 642 at 11 (Minder).
[170]
[171]
[172] Tr. Vol. 1 at 160-161 (Nesvig).
[173]
[174]
[175] CPE Exh. 121 at 35 (Nesvig).
[176]
[177]
[178] OES Exh. 633 at 40-47 (Minder).
[179] OES Exh. 642 at 22-23 (Minder).
[180] CPE
Exh. 121 at 24-26 (Nesvig).
[181]
[182] OES Ex. 647 at 35-36 (Johnson).
[183] CPE Exh. 121 at 22 (Nesvig); OES Exh. 650
at 9 (Johnson).
[184] OES Exh. 647 at 37 (Johnson).
[185]
[186]
[187] Tr. Vol. 1 at 155-156 (Nesvig).
[188] CPE Exhibs. 121 at 97 and 109, Schedule 50,
Workpaper 2 (Nesvig).
[189] CPE Exh. 121 at 97 (Nesvig).
[190] OES Exh. 647 at 38 (Johnson).
[191]
[192] OES Exh. 643 at 25 (
[193] CPE Exh. 122 at 17 (Nesvig); OES Exh. 643
at 26 (
[194] OES Exh. 643 at 26 (
[195] CPE Exh. 122 at 17 (Nesvig).
[196]
[197]
[198] OES Exh. 646 at 10 (
[199]
[200]
[201] Tr. Vol. 1 at 159-160 (Nesvig).
[202]
[203] CPE
Exh. 121 at 15-20 and Schedule 10 (Nesvig). The issue of easement clearings is addressed
separately above.
[204]
[205]
[206]
[207]
[208]
[209]
[210]
[211]
[212]
[213]
[214]
[215]
[216]
[217]
[218]
[219]
[220]
[221]
[222]
[223] CPE Exh. 121 at 14-15 and Schedule 8
(Nesvig).
[224]
[225]
[226] CPE Exh. 121 at 21 (Nesvig).
[227]
[228]
[229]
[230] CPE Exh. 121 at 21 (Nesvig).
[231]
[232]
[233]
[234]
[235] CPE Exh. 122 at 31 and Schedule 5 (Nesvig).
[236]
[237]
[238]
[239]
[240]
[241] Minn. Stat. § 216C.05, subd. 2 (2009).
[242]
[243] Minn. Stat. § 216B.2412, subds. 1 and 3
(2009).
[244] CPE Exh. 112 at 19 (Feingold Direct) and
Tr. Vol. 1, at 30-31 (Feingold).
[245]
[246] Tr. Vol. 1 at 31.
[247] CPE Exh. 112 at 19-20 (Feingold).
[248] Minn. Stat. § 216B.2412, subd. 2 (2009).
[249]
[250] See
Order Establishing Criteria and Standards (“Decoupling Order”) at 7, PUC Docket
No. E,G-999/CI-08-132 (June 19, 2009).
[251]
[252]
[253]
[254]
[255] See
CPE Exhibs. 110 a t 18-21 (Baker) and 136 at 13-17 and Schedule 4 (Gastineau).
[256] Decoupling Order at 7.
[257] CPE Exh. 137 at Schedule 3 (Gastineau).
[258] CPE Exh. 137 at 4 and Schedule 3
(Gastineau).
[259]
[260]
[261] Public Comments 27 (Representative Jeremy
Kalin) and 30 (Senator Scott Dibble).
[262]
[263]
[264] CPE Exh. 113 at 19 (Feingold); see IWLA/MCEA Initial Brief,
Attachments.
[265] CPE Exh. 112 at Schedule 6 (Feingold).
[266] Decoupling Order at 7.
[267] Decoupling Order at 3, f.n. 4.
[268] CPE Exh. 140 at 2.
[269] CPE Exh. 140.
[270] Decoupling Order at 8.
[271] Exh. 653, Att. (MFG-5), Sch. 4.
[272] CPE Exh. 131 at 43-63 and Schedule 6; CPE
Exh. 132 at 26-36; CPE Exh. 133 at 1-15
(Hevert); CPE
Response to OES Information Request 1011, included as OES Exh. 619 at
VCC-9; CPE
Responses to OES Information Requests 1018 and 1021, OAG Information
Request 142
and IWLA Information Requests 2 and 3 (attached to CPE Exh. 140, and
supplemented
by CPE Exh. 142).
[273] CPE Exh. 131 at 45 (Hevert).
[274]
[275]
[276]
[277]
[278] OES Exh. 652 at 39, 43 and OES Exh. 654 at
13 (Griffing).
[279] OES Exh. 652 at 40 (Griffing).
[280] CPE Exh. 133 at 7-8.
[281] Tr. Vol. 3 at 88-89 (Lindell).
[282] OAG Initial Brief at 19-24.
[283] CPE Ex. 131 at 60-61 (Hevert).
[284] CPE Ex. 131 at 61-63 and Schedule 8 (Hevert).
[285] CPE Ex. 131 at 62 (Hevert).
[286] OES Ex. 652 at 42 (Griffing).
[287] OES Ex. 652 at 42 (Griffing).
[288] Decoupling Order at 8.
[289]
[290] CPE Exh. 140 at 3-4.
[291] Tr. Vol. 1 at 97-98 (Feingold); CPE Exh.
141 at 14.
[292] CPE Exh. 141 at 169.
[293]
[294] CPE Exh. 140 at 4.
[295]
[296] Decoupling Order at 9.
[297] CPE Exh. 137 at Schedule 3 (Gastineau).
[298] CPE Exh. 140 at 4.
[299] CPE Exh. 136 at Schedule 3 (Gastineau).
[300]
[301]
[302]
[303] Tr. Vol. 2 at 125-132 (Gastineau).
[304] CPE Exh. 140 at 4.
[305]
[306] CPE Exh. 137 at Schedule 3 (Gastineau).
[307] CPE Exh. 140 at 5.
[308] CPE Exh. 137 at 11 (Gastineau).
[309] OES Init.
[310]
[311]
[312] CPE Exh. 140, Ex. 1, CE Rider at 1.
[313] CPE Exh. 140 at 5; CPE Exh. 137 at Schedule
3, p. 2 of 3.
[314] CPE Response to OAG Information Request 139
attached to CPE Exh. 140.
[315] CPE Exh. 140 at 6.
[316] CPE Response to OAG Information Request 139
attached to CPE Exh. 140
[317] Decoupling Order at 8.
[318] CPE Exh. 140 at 7.
[319]
[320]
[321]
[322] Decoupling Order at 8-9.
[323] CPE Exh. 140 at 8.
[324]
[325] OES Exh. 617 at 63.
[326]
[327] OES Exh. 619 (Chavez Exh. VCC-19).
[328] CPE Exh. 113 at 16-17 (Feingold).
[329]
[330]
[331] CPE Exh. 139 at Schedule 1, p. 4
(Gastineau).
[332]
[333] CPE
Exh. 138 at Schedule 1, p. 3 (CPE Response to OES Information Request
1059).
[334]
[335] Tr. Vol. 2 at 79 (Gastineau),
[336]
ECC Initial Brief at 10-11. See Order
Accepting and Modifying Settlement and Requiring Compliance Filing, In the
Matter of an Application by CenterPoint Energy for Authority to Increase
Natural Gas Rates in
[337] IWLA/MCEA Reply Brief at 2.
[338] CPE Exh. 137, Sched. 1, pg. 2 (Gastineau).
[339] Tr. Vol. 3 at 14-15 (
[340] Tr. Vol. 3 at 116-118 (Chavez).
[341]
[342] Minn. Stat. § 216B.241 and 2009 Minn. Laws
ch. 110, § 32; see Tr. Vol. 3 at
119-120 (Chavez).
[343] Tr. Vol. 3 at 61-62 (Grant).
[344] In
the Matter of An Application by CenterPoint Energy Minnesota Gas, a Division of
CenterPoint Energy Resources Corp., for Authority to Increase Natural Gas Rates
in Minnesota, PUC Docket No, G008/GR-05-1380, Findings of Fact, Conclusions
of Law and Order (Nov. 2, 2006) (“2006 CPE Order”) at 6-7.
[345]
[346] CPE Exh. 121 at 99 (Nesvig); 2006 CPE Order
at 9-10.
[347]
[348] In
the Matter of An Application by CenterPoint Energy Minnesota Gas, a Division of
CenterPoint Energy Resources Corp., for Authority to Increase Natural Gas Rates
in Minnesota, OAH Docket No. 15-2500-17032-2, PUC Docket No,
G008/GR-05-1380, Findings of Fact, Conclusions and Recommended Order, Finding
no. 108 (Sept. 8. 2006).
[349]
[350]
[351] 2006 CPE Order at 9-10.
[352]
[353]
[354] Commission Order Denying Reconsideration,
Docket No. G-008/GR-05-1380 at 2 (January 22, 2007)
[355]
[356] CPE Exh. 121 at 99 (Nesvig).
[357] See
Initial Brief of Suburban Rate Authority (SRA) at 12-13 (Sept. 16, 2009).
[358] CPE Exh. 121 at 99.
[359]
[360] OAG Initial Brief at 59-66.
[361] 2006 CPE Order at 9-10.
[362] OAG Initial Brief at 65.
[363] Commission Order Denying Reconsideration,
Docket No. G-008/GR-05-1380 at 1-2 (January 22, 2007).
[364] SRA Initial Brief at 1-18.
[365]
[366] Commission Order, Docket No. 93-92.
[367]
[368] CPE Ex. 121 at 12 (Nesvig) and at Schedule 6, Workpaper 4.
[369]
Ex. 643 at 21 (
[370]
OES Ex. 643 at 24 (
[371]
[372]
[373] Exh. 509 at 17 (Lindell Rebuttal).
[374]
Exh. 200 at 18 (
[375] Exh. 201 at 6 (Marshall Surrebuttal).
[376] CPE Ex. 122 at 2 (Nesvig).
[377]
[378] CPE Ex. 122 at 6 (Nesvig).
[379]
[380] CPE Ex. 122 at 8 (Nesvig).
[381] CPE Ex. 121 at 124 (Nesvig).
[382]
[383] CPE Ex. 110 at 10 (Baker).
[384]
[385]
Exh. 643 at 14 (
[386]
Exh. 121 at 124 (Nesvig Direct); Exh. 643 at 16 (
[387]
Exh. 643 at 16 (
[388]
[389]
[390]
Exh. 643 at 19 (
[391]
ECC Ex. 200 (
[392] CPE Ex. 121 at 103-104; OES Ex. 633 at 54-68 (Minder).
[393] CPE Ex. 122 at 6 (Nesvig) at 109-113 and Schedule 57.
[394] CPE Ex. 122 at 27, 113 (Nesvig).
[395] CPE Ex. 122 at 113-14 (Nesvig).
[396] CPE Ex. 122 at 114-15 (Nesvig) and Schedule 41, page 2.
[397] OES Ex. 633 at 83 (Minder).
[398] Exh. 638 at 63 (Minder Direct).
[399] Exh. 638 at 65 (Minder Direct).
[400] Exh. 638 at 66 (Minder Direct).
[401] Exh. 638 at 67 (Minder Direct).
[402] Exh. 638 at 70-71 (Minder Direct).
[403]
OES Init.
[404] See, e.g., CPE Reply Brief at 40-42.
[405] Minn. Stat. § 216B.16, subd. 4 (2008).
[406]
[407] See, e.g., OES Reply Brief at 20-22.
[408] PUC Docket No. G-008/GR-95-700, Findings of
Fact, Conclusions of Law and Order (1995 Order) at 23 (June 10, 1996).
[409]
[410]
[411]
[412] Tr. Vol. 1 at 163 (Nesvig).
[413]
[414]
[415]
[416]
[417] CPE Exh. 122 at 23 (Nesvig).
[418]
[419] CPE Exh. 122 at 25 (Nesvig).
[420] CPE Exh. 118 at 3 (Van Norman).
[421]
[422] CPE Exh. 122 at 24 (Nesvig).
[423]
[424] CPE Exh. 118 at 1 and Schedule 1 (Van
Norman).
[425] CPE Exh. 118 at 5 and Schedule 1 (Van
Norman); Tr. Vol. 1 at 139-140 (Van Norman).
[426] OAH Exh. 510 at 13 (Lindell).
[427]
[428]
[429] OAG Trade Secret Exh. 505 at 10.
[430]
[431] CPE Exh. 121 at 88 (Nesvig).
[432]
[433]
[434] OES Exh. 648 at 25-27 (Johnson).
[435]
[436]
[437] CPE Exh. 122 at 12 (Nesvig).
[438] CPE Exh. 140 at 5.
[439] Decoupling Order at 8.
[440] Exh. 121 at 75-78 (Nesvig Direct); and Exh. 105
(KRN-WP), Vol. 2, Sch. 21; and Exh. 109
(KRN-WP), Vol. 4, Sch. 63, at 1-8, workpaper 1.
[441] Exh. 121 at 77-78 (Nesvig Direct).
[442]
OES Ex. 643 at 32 (
[443]
[444]
OES Ex. 643 at 36 (
[445] Exh. 121 at 77 (Nesvig Direct).
[446] Exh. 105 at (KRN-WP), Vol. 2, Sch. 21, Workpaper 6.
[447]
Exh. 643 at 30 (
[448] Exh. 644, Att. (MAS-13)
[449]
Exh. 643 at 31 (
[450]
[451] In the Matter of
the Application of Minnesota Power for Authority to Increase Electric Service
rates in Minnesota, Findings of
Fact, Conclusions of Law and Order at 44, Docket No. E015/GR-08-415 (May 4,
2009) (“
[452]
Exh. 646 at 14 (
[453]
Exh. 643 at 33 (
[454]
Exh. 643 at 33; and Exh. 644, Att. (MAS-14) (
[455]
Exh. 643 at 33 (
[456]
[457] Exh. 600 at 64-76 (Heinen Direct).
[458]
Exh. 643 at 34-35 (
[459] CPE Ex. 122 at 14 (Nesvig).
[460]
See Exh. 643 at 35; and Exh. 644,
Att. (MAS-13) (
[461]
[462]
Exh. 643 at 36 (
[463]
Exh. 643 at 36-37 (
[464] CPE Ex. 122 at 15-16 (Nesvig).
[465] CPE Exhibs. 121 at 14 (Nesvig) and 115 at 8 (Ferrary).
[466] CPE Exh. 117 at 3 (Ferrary).
[467] Minn. R. 7820.3100, subp. 1 (2009).
[468]
[469] Tr. Vol. 1 at 106-107 (Ferrary).
[470]
[471]
[472]
[473] Tr. Vol. 1 at 106-107 (Ferrary); see Minn. R. 7820.2400 and 7820.3100, subp. 1.
[474]
[475] OAG Initial Brief at 51-58.
[476] OAG Initial Brief at 58.
[477] CPE Exh. 117 at 5 (Ferrary).
[478]
[479] OAG Initial Brief at 57.
[480] CPE Initial Brief at 80 and Exh. A.
[481] OAG Initial Brief at 57.
[482] CPE Initial Brief at 80 and Exh. A.
[483] CPE Ex. 111 at 8 (Baker).
[484]
See
OAG Ex. 510 (Lindell Surrebuttal) at 4-5, n. 4 (citing numerous
previous Commission decisions prohibiting the rate recovery of lobbying
expenses.) See also Ex.
OAG’s Initial Brief at 8 (citing Re Northern States Power Company,
Docket No. E-002/GR-85-558, 75 P.U.R.4th 538, 582, Re
[485] CPE Ex. 121 at 93-94 (Nesvig); OES Ex. 647 at 7-8 (Johnson).
[486] CPE Ex. 121 at 64-65 (Nesvig); OES Ex. 647 at 10 (Johnson).
[487] CPE Ex. 121 at 67 (Nesvig); OES Ex. 647 at 11 (Johnson).
[488] CPE Ex. 121 at 67 (Nesvig); OES Ex. 647 at 11 (Johnson).
[489] OAG Ex. 509 at 28-33 (Lindell).
[490] CPE Ex. 123 at 2 (Nesvig).
[491] CPE Ex. 123 at 3 (Nesvig).
[492] CPE Ex. 123 at 2 (Nesvig).
[493] Exh. 105 (KRN-WP), Vol. 2, Sch. 18, at 1 of 1, Workpaper 6.
[494] Exh. 600 at 76-77 (Heinen Direct).
[495] Exh. 122 at 8 (Nesvig Rebuttal).
[496]
[497] Exh. 649, Att. (MAJ-10) (Johnson Direct Attachments).
[498] CPE Exh. 616 at 10 (Heinen).
[499] Tr. Vol. 3 at 94 (Heinen).
[500]
[501] Tr. Vol. 3 at 95-96 (Heinen).
[502]
[503] Tr. Vol. 3 at 96 (Heinen).
[504] CPE Ex. 127 at 16-17; CPE Exh. 128 at 5 (Drews).
[505] CPE Exh. 129 at 12-13 (Livezey).
[506]
[507] OES Exh. 600 at 27-28 (Heinen).
[508] OES Exh. 601, Att. (AJH-12) (Heinen).
[509] CPE Exh. 129 at 23, 26 and 31; EPE Exh. 113 at 24-25 (Feingold).
[510] OES Exh. 616, Att. AJH-S-4.
[511] OES Exh. 615 at 22-23 (Heinen).
[512] See CPE Exh. 109, Vol. 4, Sch. 54, Workpaper 1 (Nesvig).
[513] OES Exh. 633 at BJM-2 (Minder).
[514] OES Exh. 633 at 7-8 (Minder); CPE Exh. 122 at 18 (Nesvig).
[515] CPE Exh. 122 at 18 (Nesvig).
[516] Mr. Gastineau’s Workpaper #6
[517] Exh. 628 at 32 (Shaw Public Direct)
[518]In the Matter of the Application of
CenterPoint Energy Minnegasco, a Division of CenterPoint Energy Resources
Corp., for Authority to Increase Natural Gas Rates in
[519] Exh. 628 at 33 (Shaw Public Direct).
[520] Tr. Vol. 3 at 131 (Shaw).
[521] CPE Exh. 116 at 12 n. 19 (Ferrary) (citing Commission Order).
[522]
[523] CPE Ex. 116 at 6 (Ferrary).
[524] CPE Ex. 116 at 6 (Ferrary).
[525]
[526]
[527]
[528]
ECC Exh. 200 at 22 (
[529]
[530]
ECC Exh. 200 at 23 (
[531] CPE Exh. 116 at 10, 11 (as part of the Commission-approved Cold Weather Rule script), & (Ferrary).
[532]
[533] Exh. 623 at 2-3 (Ouanes Direct).
[534]
Exh. 643 at 42 (
[535]
[536] CenterPoint 05-1380 Order at 38.
[537] Exh. 623, Att. (SO-3) (Ouanes Direct).
[538] Exh. 623 at 6, Att. (SO-3) (Ouanes Direct).
[539] CPE Ex. 134 at 7-8 (Troxle).
[540] Exh. 623 at 6, Att. (SO-4) (Ouanes Direct).
[541] Exh. 624 at 3-4 (Ouanes Surrebuttal).
[542] CPE Ex. 135 at 3 (Troxle).
[543] Exh. 624 at 3-4, 9 (Ouanes Surrebuttal).
[544] Exh. 623 at 8 (Ouanes Direct) (citing CenterPoint).
[545] Exh. 135 (MAT-R), Sch. 1, (Troxle Rebuttal).
[546] Exh. 624 at 8-9 (Ouanes Surrebuttal).
[547] OAG Ex. 507 at 39 (Lindell).
[548]
[549] CPE Ex. 135 at 11-12 (Troxle).
[550]
[551] See CPE Ex. 136 at 4-5 (Gastineau); CPE Ex. 135 at 12 (Troxle).
[552] Exh. 628 at 6 (Shaw Direct).
[553] Exh. 628 at 7 (Shaw Direct).
[554] See Exh. 101 (Proposed Tariffs, Vol. 2).
[555] Exh. 628 at 2-3 (Shaw Direct).
[556]
[557] See Exh. 625, Att. (CJS-2).
[558] Exh. 625, Att. (CJS-2).
[559]
[560]
[561] CPE Ex. 137 at 28 (Gastineau).
[562] OES Ex. 632 at 6-7 (Shaw).
[563] Exh. 628 at 12 (Shaw Direct).
[564] Exh. 628 at 13 (Shaw Direct).
[565] Exh. 628 at 20 (Shaw Direct).
[566]
[567]
[568]
[569] See OAG Ex. 507 at 45-46 (Lindell).
[570] OES Ex. 631 at 2 (Shaw).
[571]
[572] CPE Exs. 136 at 6-10 and 137 at 25-26 (Gastineau).
[573] CPE Ex. 136 at 8 (Gastineau).
[574] OES Exh. 625 at 24-25 (Shaw).
[575]
[576]
[577] CPE Exh. 137 at 23 (Gastineau).
[578] OAG Exh. 507 at 54 (Lindell).
[579] OES Exh. 641 at 10 (Minder).
[580] See the
Commission’s November 19, 2007, Order
Approving Tariff Revisions in Docket No.
G008/M-07-686.
[581] OES Exh. 641 at 10-11 (Minder).
[582]
[583]
[584] Tr. Vol. 3 at 167 (Minder).
[585]
ECC Exh. 201 at 27 (
[586]
[587]
[588]
[589] ECC Exh. 201 at 30.
[590] OES Exh. 641 at 12 (Minder).
[591]
[592] Tr. Vol. 3 at 172 (Minder).
[593]
[594]
[595] Tr. Vol. 3 at 170-72 (Minder).
[596]
[597]
[598] OES Exh. 638 at 47 (Minder).
[599] Tr. Vol. 1 at 158-59 (Nesvig).
[600] CPE Exh. 124 at 9-11 (Peterson).
[601]
[602] See
OAH Trade Secret Exh. 505 at 10.