STATE OF MISSOURI
PUBLIC SERVICE COMMISSION
At a session of the Public Service Commission held at its office in Jefferson City on the 24th day of June, 2015.
BEFORE
THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the Matter of The Empire )
District
Electric Company for Authority ) File
No. ER-2014-0351
to File Tariffs Increasing Rates for ) Tracking No. YE-2015-0074
Electric Service Provided to Customers )
in the Company’s Missouri Service Area )
|
REPORT AND ORDER |
Issue Date:
June 24, 2015
Effective Date: July 24, 2015
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the Matter of The Empire )
District
Electric Company for Authority ) File
No. ER-2014-0351
to File Tariffs Increasing Rates for ) Tracking No. YE-2015-0074
Electric Service Provided to Customers )
in the Company’s Missouri Service Area )
REPORT
AND ORDER
Table of Contents
Appearances....................................................................................................... 3
Procedural
History................................................................................................ 4
General Findings
of Fact...................................................................................... 6
Conclusions of
Law Regarding Jurisdiction............................................................. 7
This Issues.......................................................................................................... 8
I. Revised Agreement.................................................................................... .......................................................................................................... 8
II. Class Cost of Service................................................................................. ........................................................................................................ 14
III. Large Power Rate Design........................................................................... ........................................................................................................ 21
IV. Fuel Adjustment Clause.............................................................................. ........................................................................................................ 23
Ordered paragraphs............................................................................................. 30
APPEARANCES
For The Empire
District Electric Company:
Diana Carter, Attorney at Law,
and Dean Cooper, Attorney at Law
Brydon, Swearengen
& England, P.C.,
312 East Capitol
Jefferson City,
MO 65102
For Midwest Energy
Consumers Group:
David
Woodsmall, Attorney at
Law
Woodsmall Law Office,
308
East High St., Suite 204
Jefferson City, MO 65101
For Midwest Energy Users’ Association:
Stuart
Conrad, Attorney at Law
Finnegan, Conrad & Peterson
3100 Broadway
1209 Penntower
Office Center
Kansas City, MO 64111
For City of Joplin:
Marc
Ellinger, Attorney at Law
Blitz, Bardgett & Deutsch
308 East High Street, Suite 301
Jefferson City, MO 65101
For the Missouri Department of Economic
Development, Missouri Division of Energy
Ollie
Green, Senior Legal
Counsel, and Alex Antal,
Legal Counsel
Department of Economic Development
301 West High Street
Jefferson City, MO 65102
For the Staff of the Missouri Public Service
Commission:
Robert Berlin, Senior Counsel,
and Jeff Keevil, Senior Counsel
200 Madison Street,
Jefferson City, Missouri 65102
For the Office of
the Public Counsel and the Public
Dustin J. Allison, Public Counsel, and Christina Baker, Assistant Public Counsel
Office of the Public Counsel
P.O. Box 2230
200 Madison Street, Suite 650
Jefferson City, MO 65102
REGULATORY
LAW JUDGE: Kim
S. Burton
The Missouri Public Service Commission, having considered all the competent and substantial evidence upon the whole record, makes the following findings of fact and conclusions of law. The positions and arguments of all of the parties have been considered by the Commission in making this decision. Failure to specifically address a piece of evidence, position, or argument of any party does not indicate the Commission has failed to consider relevant evidence, but indicates rather that the omitted material was not dispositive of this decision.
Procedural History
On August 29, 2014, the
Empire District Electric Company (“Empire”) filed a tariff to increase the
general rate for electric service. The submitted tariff would have increased
Empire’s annual electric revenues by approximately $24.3 million dollars
(approximately 5.5%). The tariff (Tracking No. YE-2015-0074) had a September
28, 2014 effective date. The Commission issued an order on September 4, 2014,
suspending the tariff until July 26, 2015.[1]
The Commission also directed notice be provided to interested parties and set a
deadline for applications to intervene. The following parties filed
applications to intervene that were granted by the Commission: the Missouri
Department of Economic Development—Division of
Energy (“DED”); the
City of Joplin, Missouri (“Joplin”); Midwest Energy Users’ Association
(“MEUA”);[2]
and Midwest Energy Consumers Group (“MECG”).[3]
On October 28, 2014, the Commission issued a procedural schedule and set the Test Year to run from May 2013 through April 2014, with an updated test year of August 31, 2014, and a true-up date of December 31, 2014. The Commission conducted three local public hearings; two in Joplin and one in Reeds Spring, Missouri. Consistent with the procedural schedule, the parties filed direct, rebuttal and surrebuttal testimony.
An evidentiary hearing was held on April 14 and April 17, 2015, for the purpose of hearing testimony on the disputed issues. The Commission admitted into the record all pre-filed witness testimony, including exhibits and other attachments.[4] In total, the Commission admitted 98 exhibits into evidence. The Commission cancelled the scheduled true-up hearing upon the request of the parties. The parties filed initial post hearing briefs on May 15, 2015 and reply briefs on May 29, 2015.
General Findings of Fact
1.
Empire
is a Kansas Corporation with its principal place of business in Joplin,
Missouri. Empire is engaged in the business of the manufacture, transmission
and distribution of electricity. Empire provides electrical utility services in
Missouri, Kansas, Arkansas, and Oklahoma. Empire’s service area includes
approximately 10,000 square miles in southwest Missouri and the adjacent
corners of the three surrounding states. Empire is regulated by the utility regulatory
commissions in all four states and by the Federal Energy Regulatory Commission
(“FERC”). [5]
2.
Empire
mainly serves smaller communities, with the largest city in its service
territory—Joplin, Missouri—having a population of approximately 50,000. The company’s
service territory includes small to medium manufacturing operations, medical,
agricultural, entertainment, tourism, and retail interests. In Missouri, Empire
serves approximately 125,750 residential customers, 21,463 commercial
customers, 276 industrial customers, 1,845 public authority and street and
highway customers, and 3 wholesale customers.[6]
3.
Empire
solely owns and operates four power plants: the Asbury Power Plant, the
Riverton Power Plant, the Energy Center Power Plant, and the Ozark Beach Dam
and Hydroelectric Plant. Empire also operates and jointly owns the State Line
Power Plant.[7]
4.
Empire
owns 12% of the Iatan Power Station and 7.52% of the Plum Point facility.[8]
5.
Empire
filed tariffs with the Commission (Tracking No. YE-2015-0074) requesting an
overall increase of $24.3 million in Missouri jurisdictional revenue, exclusive
of applicable fees or taxes—an increase of 5.5%. Environmental improvement
costs at its Asbury generating unit as well as increased Regional Transmission
Organization (“RTO”) charges, and a new maintenance contract for the Riverton
12 generating unit were factors in Empire’s request for a rate increase.[9]
6.
As part
of Empire’s plan to comply with EPA standards, Empire installed a scrubber,
fabric filter, and power activated carbon injection system at its Asbury plant
(“AQCS”). The AQCS improvements at the Asbury plant were completed in December
2014, after the test year. The budgeted costs from the project ranged from $112
million to $130 million.[10]
7.
Empire
is completing the construction and conversion of Riverton Unit 12 to a combined
cycle unit, which should be completed in mid-2016.[11]
Empire is expected to file another general rate case within a year to recover
what are primarily environmental compliance costs associated with the Riverton
Unit 12 improvements.[12]
Conclusions of Law Regarding
Jurisdiction
Empire is an electric corporation and public utility, as defined in § 386.020, and is subject to Commission regulations pursuant to Chapters 386 and 393, RSMo.[13] Section 393.140(11) authorizes the Commission to regulate the rates Empire charges its customers. When seeking to increase the rates it charges its customers, Empire has the burden of proof to show by a preponderance of the evidence that increased rates are just and reasonable.[14]
When evaluating if rates are just and reasonable, the Commission will balance the interests of Empire’s investors in making a reasonable return with the interest of the consumers.[15] The Commission is not bound to the use of any single formula when determining just and reasonable rates.[16] It is the results reached, not the method employed which are controlling.[17]
THE ISSUES
I.
Revised Agreement
Prior to the evidentiary hearing, Empire, Staff, OPC, Joplin, DED, and MEUA (jointly referred to as, the “Signatories”) submitted a joint agreement, Revised Stipulation and Agreement and List of Issues, (hereinafter, “Revised Agreement”).[18] On that same day, April 8, the Signatories also filed a Non-Unanimous Stipulation and Agreement on Certain Issues. MECG filed notice of its non-objection to the Revised Agreement and a separate objection to the Non-Unanimous Stipulation and Agreement on Certain Issues (“Position Statement”).
The Revised Agreement resolves all but three disputed issues in the following manner:
1. Empire will be authorized to file tariffs designed to increase the company’s revenues by $17,125,000 (3.9%), exclusive of any applicable license, occupation, franchise, gross receipts taxes, or similar fees or taxes. It is also agreed that Staff’s billing determinants and current revenues, shown in Exhibit B, should be used in the setting of rates in this case.
2. Depreciation of Riverton Unit 7 and Asbury Unit 2 will be discontinued, with Empire directed to use the depreciation rates shown in Exhibit C of the Revised Agreement.
3. Empire will discontinue its Vegetation Management Tracker, with the balance to be trued up in Empire’s next general rate case.
4. Empire will discontinue the Iatan 2/Iatan Common/Plum Point O&M Trackers, with the accumulated balances to be trued up in Empire’s next general rate case.
5. A Riverton 12 Long-Term Maintenance Tracker shall be established, with the base set at $2.7 million, Missouri jurisdictional. Fluctuations in actual charges above or below this annual level of expense will be recorded in a regulatory asset/liability account. The balance recorded in the regulatory asset/liability account should be amortized over three years, with the revenue requirement associated with this tracker considered during Empire’s next Missouri general rate case.
6. Empire will continue its current Energy Efficiency Programs—excepting the low-income weatherization program—at current funding levels and with the current recovery mechanism, until Empire has an approved Pre-Missouri Energy Efficiency Investment Act (“MEEIA”) compliance plan or until the effective date of rates in Empire’s next general rate case.
7. Empire will continue its Low-Income Weatherization program, with an annual budget of $225,000. If the budget amount is not spent in any given Empire budget year, the balance will roll over to be spent in a future Empire budget year. Going forward, the low-income weatherization program is not a “demand side measure” or program for purposes of § 393.1075.7.[19] Costs for this program are built into and will be recovered through the agreed-upon revenue requirement.
8. Empire will be authorized to continue its Fuel Adjustment Clause (“FAC”) with modifications. Southwest Power Pool (“SPP”) Schedule 1A and 12 charges will be excluded from the FAC. Empire’s FAC will also exclude Empire’s labor, administrative, and convention costs from Acct. 501. For the FAC tariff, the Missouri jurisdictional energy allocation factor will be used in the allocation of off-system sales revenues (accounts 447133 and 447830), and Renewable Energy Credits (“REC”) revenues (account 456073). Empire agrees to work with stakeholders to develop descriptions of the costs and revenues flowing through the FAC, to be filed with the Commission in the next general rate case.
9. No changes will be made to the Economic Development Rider.
10. Empire will include the following language regarding Standby Service into its tariffs: “Any ‘qualifying facility’ as defined in 4 CSR 240-20.060(1)(G) shall be provided, upon request, stand-by power at the otherwise applicable standard rates which would apply if the Company provided energy at the customer’s full service requirements.”
11. Empire also agrees to work towards submitting a Standby Tariff in its next general rate case that will incorporate concepts agreed to by the parties.[20] Empire also agrees to conduct a standby service cost study before its next general rate case filing, unless the Signatories agree additional time is necessary.
12. The Residential Customer Charge will not be increased in this rate case.
13. Empire will continue the use of a tracker mechanism for pension and OPEB expenses, with the annual level of ongoing Missouri jurisdictional pension and OPEBs expenses at $6,909,482 and $883,144, respectively. The Accounting Standards 715-30 and 715-6- (FAS 87/106) tracker language shall continue in effect. The impact of the expiration of the “substantive plan agreement” amortization on OPEB expenses will continue to be reflected in Empire’s ongoing tracker balance calculations.
14. Empire will provide monthly quality of service reporting and will continue submitting monthly revenue and usage reports to Staff. Empire will also continue providing information in its monthly reports, as agreed to in the Non-Unanimous Stipulation and Agreement filed May 12, 2010, in File No. ER-2010-0130).[21]
15. The extension policy proposed by Empire will be implemented.
16. The Commission will adopt Staff’s recommended in-service criteria and find the Asbury AQCS to be fully operational and used for service. Any party to Empire’s next general rate case may argue the book value of Asbury AQCS. No party is precluded in Empire’s next rate case from seeking any disallowance.
17. Empire will make the following total company depreciation reserve adjustments to reflect the unitization of Iatan 2 plant:
|
Account # |
Account Description |
Depreciation Reserve Adjusment |
|
311I2 |
Structures and Improvements |
$101,450.83 |
|
312I2 |
Boiler Plant Equipment |
$1,494,664.97 |
|
314I2 |
Turbogenerator Units |
$963,628.98 |
|
315I2 |
Accessory Electrical Equip |
($281,415.67) |
|
316I2 |
Misc Power Plant Equip |
($2,278,329.11) |
18. Empire will make the following adjustments to the additional amortization balances recorded in separate subaccounts in reserves to reflect the unitization of Iatan 2 plant balances:
|
Account # |
Account Description |
Depreciation Reserve Adjustment |
|
311.05 |
Structures and Improvements |
($361,914.88) |
|
312.05 |
Boiler Plant Equipment |
$5,814,553.61 |
|
314.05 |
Turbogenerator Units |
$5,401,677.38 |
|
315.05 |
Accessory Electrical Equip |
($809,308.39) |
|
316.05 |
Misc Power Plant Equip |
($10,045,007.72) |
19. Empire will continue amortization of the DSM regulatory asset for costs incurred during the Regulatory Plan for a total term of 10 years.
20. Empire will continue amortization for the DSM program costs incurred after the end of the Regulatory Plan and prior to any program implementation under MEEIA for a total term of six years.
21. Empire will continue to flow the Southwest Power Administration (“SWPA”) payment associated with the capacity restrictions to be implemented for Ozark Beach hydro facility, net of tax, back to the customers over a 10 year period, which began on the effective date of rates in File No. ER-2011-0004, pursuant to a tracker mechanism; for an annual reduction of expense of approximately $1.365 million on a Missouri jurisdictional basis.
22. Empire will refund through rates, beginning with the effective date of rates in this case, the ITC over-collection balance as of December 31, 2014, of $205,593. The refund will be through an amortization over 24 months. Additional over-recovery of the ITC from January 2015 through the effective dates of rates for this case will be reviewed during Empire’s next general rate case.
Decision:
Since MECG did not object to the Revised Agreement, pursuant to 4 CSR 240-2.115(2)(C), the Commission may treat it as a unanimous agreement. The Commission is not required to separately state its findings of fact or conclusions of law for those issues disposed of by stipulation and agreement.[22] The evidence admitted into the record is substantial and competent. Based upon the Commission’s independent review of the record and the Revised Agreement, the Commission finds that the Revised Agreement is consistent with the public interest and provides Empire with a sufficient cash flow to provide safe and adequate service. The $17,125,000 (3.9%), increase in Empire’s revenues is just and reasonable.
The Commission will authorize Empire to file tariffs in compliance with the Revised Agreement. The Commission will also incorporate the terms of the Revised Agreement into this Report and Order and direct all parties to comply with the terms of the Revised Agreement.
II.
Class Cost of Service
a. How do Empire’s residential and industrial rates compare with national
averages?
b. What, if any, revenue neutral interclass shifts are supported by Class
Cost of Service Studies?
c. What, if any, revenue neutral interclass shifts should be made in
designing the rates resulting from this case?
d. What, if any, changes to the Commercial and Industrial customer charges
are supported by CCOSS?
e. What, if any, changes to the Commercial and Industrial customer charges
should be made in designing the rates resulting from this case?
f. What, if any, changes to the LP tail block rate are supported by CCOSS?
g. What, if any changes to the LP tail block rate should be made in
designing the rates from this case?
Findings of Fact:
8. Under the
terms of the Revised Agreement, the parties agreed to an increase in Empire’s
revenue requirement of approximately 3.9% and no increase in the residential
customer charge from its current amount of $12.52.[23]
The average bill for an Empire residential customer is $131 per month.[24]
9. A cost of
service analysis provides the revenue requirement necessary for a utility to
recover prudently incurred costs of providing service, including a return of
and on the capital needed to provide services.[25]
If it correctly calculates class cost causation, a cost of service (“CCOS”)
study can be useful to allocate costs among customer classes and to determine
rates that allow a utility a reasonable opportunity to earn the allowed return.[26] A
CCOS study approach to rates aims to allocate costs to the causing class.[27]
10. Staff submitted a CCOS study using the Base and Intermediate Peak of analysis method (“BIP”). Staff’s CCOS study is based on a test year of May 1, 2013, through April 30, 2014, updated through August 31, 2014.[28] Of the four CCOS studies submitted by the parties, Staff’s most reasonably recognizes the relationship between the cost of the plant required to serve various levels of demand and energy requirements and the cost of producing energy.[29]
11. Staff’s
CCOS recommendation shows that residential rates are 8.06% below costs, while
large power (“LP”) rates are 8.35% above costs[30]
and general power (“GP”) rates are 7.9% above costs.[31]
All four CCOS studies filed by the parties show that the residential class is
contributing below its share of the rate of return.[32]
12. Based
on Staff’s CCOS results, Signatories to the Position Statement recommend an
increase/decrease to the current base retail revenue on a revenue neutral basis
to the various classes of customers.[33]
13. “Revenue neutral” means that the revenue shifts among classes do not change the utility’s total system revenues. This term is used to compare revenue deficiencies between customer classes and makes it easier to determine the shifts needed between the classes of customers, when appropriate.[34]
14. Shifting customer costs from variable volumetric rates—that a customer can reduce through energy efficiency—to fixed customer charge will reduce incentive efforts to conserve energy.[35] While Staff’s CCOS study supports an increase to residential and all other customer charges by the average increase for each applicable class, the Signatories agreed in the Revised Agreement to not increase the residential customer charge.[36]
15. Staff’s CCOS study, supported by the Signatories to the Position Statement, recommends the residential service (“RG”) class receive a positive 0.75% adjustment and the total electric billing (“TEB”), GP, and LP classes receive a negative adjustment of approximately 0.85%.[37]
16. After making the revenue neutral interclass adjustments, Staff’s CCOS report supports assigning to applicable customer classes the portion of the revenue increase/decrease attributable to the energy efficiency programs from MEEIA program costs. Staff’s CCOS results support no retail increase for the feed mill (“PFM”) and combined lighting classes as existing revenues received from these classes are providing more revenue to Empire than Empire’s cost to serve. After applying these steps, Staff’s CCOS Report supports each rate component of each class being increased across-the-board for each class on an equal percentage to recover the $17,125,000 increase in revenue agreed to in the Revised Agreement. [38]
17. The Signatories to the Position Statement recommend a revenue neutral shift that includes a 0.75 %increase for the residential class and a 0.85 %decrease for the LP, TEB, and GP classes.[39] Even though the residential class rates are approximately 8.1% below the class cost of service, the Signatories only recommend a 0.75% increase in the residential rates.[40]
18. Retail rates are pricing signals that drive customer behavior. Empire’s average industrial rates are 16% above the national average, while its residential rates are 3.5% below the national average.[41] Based on Staff’s CCOS study, the residential class needs an 8.1% revenue neutral adjustment in order to cover the costs incurred to serve the class. An adjustment of a 0.75% increase for the residential class, it would take numerous rate cases with similar adjustments over several years for the residential rates to reach cost of service while other classes pay a disproportionate share.[42]
19. Competitive industrial rates are important for the retention and expansion of industries within Empire’s service area.[43] If businesses leave Empire’s service area, Empire’s remaining customers bear the burden of covering the utility’s fixed costs with a smaller amount of billing determinants. This may result in increased rates for all of Empire’s remaining customers.[44]
20. Attempting to completely eradicate the 8.1% residential rate class discrepancy in this rate case would be too punitive to the customers in that class.[45] A revenue neutral adjustment of 25% of the 8.1% needed adjustment would increase the residential rates by approximately 2%. This 2% increase, in additional to the 3.9% revenue requirement increase, agreed to by the parties in the Revised Agreement, would raise the average residential customer’s monthly bill by approximately 5.9%. Since the average monthly bill for an Empire residential customer is $131, this would increase the monthly bill by approximately $7.73 ($131 * 5.9% = $7.73). In comparison, with the .75% revenue neutral increase for the residential class supported by the Signatories in the Joint Position, the average monthly bill for an Empire residential customer would increase by approximately $6.09 ($131 * [3.9% + .75%] = $6.09.
21. A 2% revenue neutral adjustment for the residential class is not punitive to the residential class and helps to eliminate any residential subsidy in a shorter timeframe.[46]
22. The current tail block rate for the LP class is 0.0363 per kWh in the summer (3.63 cents a kWh) and 3.5 cents a kWh in the summer.[47] Despite MECG’s argument to the contrary, the cost of energy for the LP tail block is not below the current tail block rate.[48]
23. Staff’s CCOS study supports the Signatories’ position that each rate component of each class be increased across the board for each class on an equal percentage basis, including the tail block rates for the LP class.[49]
Conclusions of Law:
Since MECG objected to the Position Statement, it is a nonunanimous stipulation and agreement of those issues it resolves. Pursuant to Commission Rule 4 CSR 240-2.115(2)(D) the Commission will only consider such a stipulation as the position of the Signatories, except that no party is bound by it, and the Commission must still make a determination after hearing of all remaining issues. “Not only can the Commission select its methodology in determining rates and make pragmatic adjustments called for by particular circumstances, but it also may adopt or reject any or all of any witnesses’ testimony.”[50]
Decision:
Staff’s CCOS study supports the position of the Signatories that each rate component for each class be increased across the board for each class on an equal percentage basis.[51] The Signatories also recommend a neutral adjustment recommended by the Signatories (a 0.75% increase for the residential class) to address the recognized 8.1% residential rate class discrepancy. MECG recommends an increase to residential rates by 25% of the needed 8.1% revenue neutral adjustment in order to send a more accurate pricing signal to all of Empire’s customers and take a significant step towards moving the residential class closer to its cost of service. The difference between the two is not of such a significant amount as to cause “rate shock.” The Commission finds that the increase to residential rates by 25% of the needed 8.1% revenue neutral adjustment is just and reasonable.
Additionally, MECG recommends removing all fixed costs from the second energy block for the LP rate class by adjusting that tail block rate down to coincide with the base costs of fuel. The Signatories oppose this option and instead recommend that each rate component of each class be increased across the board for each class on an equal percentage basis. The evidence presented by MECG does not support a change in the LP tail block rate.
The Commission finds Staff’s CCOS study supports the position of the Signatories to increase each rate component across the board on an equal percentage basis to be just and reasonable.
III.
Large Power Rate Design
Should Empire be required to submit a Large Power rate schedule in its
next rate case that recognizes a time differentiated facilities demand charge?
Findings of
Fact:
24. Empire
currently has 38 customers in its LP rate class.[52]
Those Customers have demand meters.[53]
25. Empire offers a time differentiated billing demand charge for its special transmission rate classes (SC-P and SC-T), but not for its LP rate class.[54] Time differentiation of the billing demand sends pricing signals that encourage industrial customers to shift their operation away from peak to off-peak periods. By offering a time differentiated billing demand charge for the LP rate schedule, Empire will send the proper capacity price signals regarding transmission and generation infrastructure costs. If members of the LP rate class shift their operations based on capacity price signals, Empire may be able to postpone or cancel future capacity additions.[55]
26. Empire may
need to manually enter the billing determinants for those customers in the LP
class if they are billed on a time-differentiated demand charge, but the amount
of this added expense is unknown. Signatories to the Position Statement opposed
MECG’s request for the submission of a LP rate design in Empire’s next general
rate case that recognizes a time differentiated demand charge; however, no
substantive testimony was offered opposing it.[56]
Conclusions of
Law:
The
Commission makes no additional conclusions of law.
Decision:
The
Commission recognizes the importance of minimizing the collection of fixed
costs through the energy charge. Empire opposes the possibility of a large power
rate design due to what it asserts are manual tabulation charges to calculate.
Empire provided no evidence to demonstrate the unfeasibility of these
additional costs, especially if the LP class is to be the class assigned the
expense for covering those costs. From a policy perspective, the ability to
incentivize members of the LP class to adjust the timing of their use, when
possible, will benefit all ratepayers if it postpones or avoids the not
insignificant costs of increasing capacity. The Commission will direct Empire
to work with Staff and other parties prior to the filing of their next general
rate case to determine the feasibility of an LP rate schedule that will
recognize a time differentiated facilities demand charge, including its costs
and benefits.
IV.
Fuel
Adjustment Clause
Should SPP Transmission Costs and Revenues be included? If so, what
transmission costs and revenues should be included?
Findings of Fact:
27.
An FAC is a mechanism established in a general rate proceeding
that allows periodic adjustments, outside a general rate case, to reflect
increases and decreases in prudently incurred fuel and purchased power costs.[57]
An FAC moves the risk of changes in fuel and transportation costs from the
electric utility to that utility’s ratepayers. An FAC is a deviation from the
usual prohibition against single issue ratemaking.[58]
28. In 2008, the Commission first authorized the
use of an FAC by Empire (File No. ER-2008-0093). Since then, the Commission has
authorized the continuation, with modifications, of Empire’s FAC in three
subsequent rate cases.[59]
29. As part of this general rate case, Empire
requests that its FAC continue with the current 95 percent/5 percent
recovery/return sharing mechanism.[60]
Under this FAC sharing level, Empire absorbs (if the energy costs are above the
base) or returns (for energy costs below the base) 5% of the over/under
balance.[61]
30. Empire currently recovers RTO related
transmission costs in base rates that are determined in a rate case test year
and annualized for any known and expected changes.[62]
Empire is a member of the Southwest Power Pool (“SPP”), an RTO. Empire wants to
include in its FAC the net transmission costs and charges from SPP’s Integrated
Marketplace (“IM”).[63]
31. In March 2014, SPP began operating its IM. The
SPP IM is an energy market with a day-ahead market, real-time balancing market,
and transmission congestion market.[64]
Empire is registered in the SPP IM as both a generating and load-serving
entity.[65]
Empire offers all of its generation into the SPP IM and bids its entire load
from the SPP IM. [66]
32. The SPP IM replaced the Energy Imbalance Market (“EIM”). In the SPP IM, Empire’s entire native load is supplied from the SPP IM at locational marginal prices. Empire bids in its resources, and if requested by SPP, sells its generation into the SPP IM and receives the revenue. [67]
33. This change in procedure has not made Empire’s
fuel and purchased power costs more or less subject to Empire’s control or
predictable.[68]
34. Staff’s CCOS study includes purchased power costs and revenues in FERC accounts 555, 565, and 456, which includes purchased power costs as well as costs and revenues from SPP’s energy and transmission service markets.[69]
35. No change in Empire’s FAC is required due to the SPP IM. Fuel costs are still accounted for; off-system sales and purchased power can be determined. Transmission costs for off-system sales and true purchased power can be determined.[70]
36. SPP’s Schedule 1A transmission rate is designed to recover costs associated with administration of SPP’s Open Access Transmission Tariff and is used by SPP for tariff administration. Schedule 12 transmission costs are those costs allocated by SPP on behalf of FERC to recover FERC administration costs for transmission services.[71] SPP Schedule 1-A (Tariff Administration Service) and SPP Schedule 12 (FERC Assessment Charge) are not fluctuating fuel and purchased power costs, but rather, administrative costs.[72]
37. The projected five year SPP related transmission expansion costs are expected to increase, but do not demonstrate volatility.[73]
38. Empire’s Missouri jurisdictional RTO
transmission costs are reasonably projected and thus not volatile.[74]
Conclusions
of Law:
Section 386.266 authorizes the use by an electrical corporation of an interim energy charge or periodic rate adjustment outside of a general rate proceeding to reflect increases and decreases in prudently incurred fuel and purchased-power costs, including transportation. The statute authorizes the Commission to include features in an FAC designed to provide an electrical corporation with incentives to improve the efficiency and cost-effectiveness of its fuel and purchased-power procurement activities. This FAC is not a statutory right granted to electric utilities; it is granted based on the Commission’s discretion after examination of the expenses.
Under Commission Rule 4 CSR 240-20.090(2), the Commission may approve the establishment, continuation or modification of an FAC and associated rate schedules. In determining what cost components to include in the FAC, the Commission will consider the magnitude of the costs, the ability of the utility to manage the costs, the volatility of the cost components and the incentive provided to the utility as the result of an inclusion or exclusion of a cost component. The Commission is not limited to only those considerations when evaluating a requested FAC. It is within the Commission’s discretion to determine what portions of prudently incurred fuel and purchased power costs may be recovered in the FAC and what portion shall be recovered in base rates.
However, Section 386.266.1
provides as follows:
Subject
to the requirements of this section, any electrical corporation may make an
application to the commission to approve rate schedules authorizing an interim
energy charge or periodic rate adjustments outside of general rate proceedings to reflect increases and decreases in its
prudently incurred fuel and purchased-power costs, including transportation.
The commission may, in accordance with
existing law, include in such rate schedules features designed to provide the
electrical corporation with incentives to improve the efficiency and
cost-effectiveness of its fuel and purchased-power procurement activities.
(emphasis added)
The emphasized clause limits the costs that can be flowed through the FAC for recovery between rate cases. It allows for recovery of transportation costs, which has been determined to include transmission costs, but such transmission costs are limited to those connected to purchased power costs.
Decision:
Through approval of the Revised Agreement, the Commission approves the continuing use of an FAC by Empire.
Empire’s position is that net fuel and purchased power (“FPP”) cost would be the cost to serve native load from the SPP IM, plus the cost of Empire’s FPP cost to generate energy for the market, minus revenue received from the SPP IM market sales. Empire’s interpretation of “purchased power” under the SPP IM includes the power that Empire generates and then offers through the SPP IM, even if it is used for its native load.
The Commission recently issued a Report and Order in an Ameren Missouri rate case, File No. ER-2014-0258, where it determined it is unlikely the drafters of the FAC envisioned a situation where a utility would consider all its generation either purchased power or off-system sales. In fact, the policy underlying the FAC statute is clear on its face: § 386.266, “…is meant to insulate the utility from unexpected and uncontrollable fluctuations in transportation costs of purchased power.”[75] Nowhere in the record do the facts support a finding that all SPP IM related transmission costs are unexpected and uncontrollable. Furthermore, as has been the case since the FAC statute was created, the costs of transporting energy in addition to the energy generated by the utility or energy in excess of what the utility needs to serve its load are the costs that are unexpected and out of the utility’s control to such an extent that a deviation from traditional rate making is justified. Therefore, the costs Empire incurs related to transmission that are appropriate for the FAC, from a policy perspective and by statute, are:
1) Costs to transmit electric power it did not generate to its own load (“true purchased power”); or
2) Costs to transmit excess electric power it is selling to third parties to locations outside of its RTO (“Off-system sales”).
Empire argues that the Commission cannot make the same determination that it made in the Ameren Missouri rate case (File No. ER-2014-0258) since the parties did not present factual evidence related to such an argument. Empire is incorrect. The determination the Commission made in Ameren Missouri’s rate case was based on its legal analysis of the FAC statutes, and the analysis in that case applies equally to the question of what transmission costs should be included in Empire’s FAC. The legal analysis does not change with the facts submitted. .
Empire also argues that, “no party raised the legal issue of whether transmission costs for purchased power should or should not include transmission costs related to self-generated power”[76] and presents this argument as another reason why the Commission cannot make the same determination in this case that it made in the Ameren Missouri rate case. While the exclusion of RTO transmission costs for native load may not have been specifically addressed in the pre-filed testimony in this case, counsel for MECG argued for this position at the evidentiary hearing and in post-hearing briefs. At the time of the evidentiary hearing in this case, the Commission was beginning to deliberate on the Ameren Missouri rate case. During opening statements at the April 14 evidentiary hearing, MECG’s counsel stated, “…we want you, whatever decision you make in the Ameren case, we want it applied to Empire as well. There’s an issue in Ameren to disallow transmission costs within the fuel adjustment clause, and we agree with that.”[77]
A general rate case is a long process wherein issues are expected to arise that are not always anticipated by the parties at the early stages. Empire’s use of an FAC and the costs eligible for recovery through the FAC are issues presented for consideration in this case, and the parties’ choice to submit certain legal arguments and not others cannot preclude the Commission from interpreting the law as it determines is most appropriate.
Based on the Commission interpretation of § 386.266, its discretion under the Commission’s rules to determine what rates will be recovered in an FAC, and the facts presented, the Commission finds it appropriate to exclude those transmission expenses that do not fall within the two categories described above.
Empire’s transmission costs to be included in the FAC are:
1) costs to transmit electric power it did not generate to its own load (true purchased power); and,
2) costs to transmit excess electric power it is selling to third parties to locations outside of SPP (off-system sales).
Costs in the FAC will continue to be collected on a per kWh basis. Empire’s current FAC 95%/5% recovery/return sharing mechanism will continue.
THE COMMISSION ORDERS
THAT:
1. The tariff sheets filed by The Empire District Electric Company on August 29, 2014, and assigned Tracking No. YE-2015-0074, are rejected.
2. The Revised Stipulation and Agreement and List of Issues, filed on April 8, 2015, is approved and incorporated into this order as if fully set forth herein. The parties shall comply with the terms of the Revised Agreement. A copy of the Revised Agreement is attached to this order as Attachment 1.
3. The Empire District Electric Company is authorized to file a tariff sufficient to recover revenues as determined by the Commission in this order no later than July 7, 2015.
4. Before its next general rate proceeding, The Empire District Electric Company shall work with Staff and other interested parties to determine whether implementing a Large Power rate schedule that recognizes a time differentiated facilities demand charge is feasible, and if so, what would be the costs and benefits of doing so for the Commission’s consideration.
5. The Empire District Electric Company shall file the information required by § 393.275.1, and Commission Rule 4 CSR 240-10-060 no later than August 14, 2015.
6. This report and order shall become effective on July 24, 2015.
BY THE COMMISSION
Morris L. Woodruff
Secretary
R. Kenny, Chm., Stoll, C., concur;
Hall, and Rupp, CC., concur with separate concurring opinions to follow;
and certify compliance with the
provisions of Section 436.080,RSMo.
Dated at Jefferson City, Missouri,
on this 24th day of June, 2015
Burton, Regulatory Law Judge.