Decision 2014-051
Direct Energy Regulated Services,
ENMAX Energy Corporation and
EPCOR Energy Alberta Inc.
Regulated Rate Tariff and Energy Price Setting Plans –
Generic Proceeding:
Part A – Transition Period
March 3, 2014
The Alberta Utilities Commission
Decision 2014-051: Direct Energy Regulated Services, ENMAX Energy Corporation and
EPCOR Energy Alberta Inc.
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Part A – Transition Period
Application No. 1610120
Proceeding ID No. 2941
March 3, 2014
Published by
The Alberta Utilities Commission
Fifth Avenue Place, Fourth Floor, 425 First Street S.W.
Calgary, Alberta
T2P 3L8
Telephone: 403-592-8845
Fax: 403-592-4406
Website: www.auc.ab.ca
Contents
1
Introduction ........................................................................................................................... 1
2
Interim approval under the Regulated Rate Option Regulation ...................................... 2
3
The current EPSPs ................................................................................................................ 4
3.1
DERS ........................................................................................................................... 4
3.2
EEAI ............................................................................................................................ 4
3.3
EEC .............................................................................................................................. 5
4
Options for the EPSP transition period .............................................................................. 6
4.1
DERS ........................................................................................................................... 6
4.2
EEAI ............................................................................................................................ 6
4.3
EEC .............................................................................................................................. 8
4.4
The CCA ...................................................................................................................... 9
4.5
TCE .............................................................................................................................. 9
4.6
The UCA ...................................................................................................................... 9
5
Order .................................................................................................................................... 14
Appendix 1 – Proceeding participants ...................................................................................... 15
AUC Decision 2014-051 (March 3, 2014) • i
The Alberta Utilities Commission
Calgary, Alberta
Direct Energy Regulated Services,
ENMAX Energy Corporation and
EPCOR Energy Alberta Inc.
Regulated Rate Tariff and Energy Price Setting Plans –
Generic Proceeding: Part A – Transition Period
1
Decision 2014-051
Application No. 1610120
Proceeding ID No. 2941
Introduction
1.
Direct Energy Regulated Services (DERS), ENMAX Energy Corporation (EEC) and
EPCOR Energy Alberta Inc. (EEAI) are regulated rate option (RRO) providers regulated by the
Alberta Utilities Commission (the AUC or the Commission). Each of these three RRO providers
is required to file monthly energy rates with the Commission. These monthly energy rates are
determined under the Electric Utilities Act, SA 2003 c. E-5.1, in accordance with the Regulated
Rate Option Regulation, AR 262/2005, and the energy price setting plans (EPSPs) of the three
RRO providers. These EPSPs establish and govern the procurement and pricing of electricity for
regulated rate option customers in the respective distribution service areas of the three RRO
providers. DERS is the RRO provider in the ATCO Electric Ltd. service area, EEC is the RRO
provider in the ENMAX Power Corporation (The City of Calgary) service area, and EEAI is the
RRO provider for the EPCOR Distribution & Transmission Inc. (City of Edmonton) and the
FortisAlberta Inc. service areas.
2.
Each of the three current EPSPs was the result of negotiations that led to negotiated
settlement agreements, and each one expires on June 30, 2014. The three RRO providers filed
their new EPSPs with the Commission on January 27, 2014.
3.
The current EPSP for DERS was approved in Decision 2011-199.1 The current EPSP for
EEC was approved in Decision 2011-486.2 The Commission issued Decision 2011-1233 on
March 31, 2011, initially approving EEAI’s EPSP, which was to be effective from July 1, 2011
to June 30, 2014. EEAI filed three amendment applications to its 2011-2014 EPSP, which were
approved in Decision 2011-259,4 Decision 2011-314,5 and Decision 2013-021.6 In Decision
1
2
3
4
5
6
Decision 2011-199: Direct Energy Regulated Services, Application for Approval of a Settlement Agreement in
respect of the 2011-2014 Energy Price Setting Plan, Application No. 1607016, Proceeding ID No. 1077, May 5,
2011.
Decision 2011-486: ENMAX Energy Corporation, Application for approval of a Settlement Agreement in
respect of the 2011-2014 Energy Price Setting Plan: Part B – Settlement Agreement, Application No. 1607214,
Proceeding ID No. 1174, December 13, 2011.
Decision 2011-123: EPCOR Energy Alberta Inc. Application for Approval of a Settlement Agreement in
respect of the 2011-2014 Energy Price Setting Plan, Application No. 1606913, Proceeding ID No. 1032,
March 31, 2011.
Decision 2011-259: EPCOR Energy Alberta Inc., Amendment to 2011-2014 Energy Price Setting Plan,
Application No. 1607373, Proceeding ID No. 1266, June 15, 2011.
Decision 2011-314: EPCOR Energy Alberta Inc., Amendment to 2011-2014 Energy Price Setting Plan,
Application No. 1607479, Proceeding ID No. 1335, July 22, 2011.
Decision 2013-021: EPCOR Energy Alberta Inc., Application to Amend the 2011-2014 Energy Price Setting
Plan, Application No. 1608970, Proceeding ID No. 2216, January 25, 2013.
AUC Decision 2014-051 (March 3, 2014) • 1
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
2013-292,7 the Commission approved an EPSP amending agreement and amended EPSP for
EEAI, which is effective August 7, 2013.
4.
In a letter dated November 22, 2013, the Commission advised parties that it would be
beneficial to examine, in one generic proceeding, all of the elements of the upcoming new EPSPs
for all three RRO providers, including the reasonable return component. The generic proceeding
is currently underway, and will consist of a full process, including an oral hearing.
5.
Because a full process will be conducted, the decision on the generic proceeding will not
be issued before the expiry of the current EPSPs on June 30, 2014. The Commission, therefore,
must approve some mechanism for the monthly energy charges and reasonable return to be
determined during the transition period between the expiry of the current EPSPs and the
implementation of the new EPSPs. Interested parties were directed to submit comments on this
matter by December 16, 2013. Parties also were provided an opportunity to submit reply
comments by January 20, 2014.
6.
2
The following parties submitted either comments, reply comments, or both:

DERS

EEAI

EEC

The Consumers’ Coalition of Alberta (CCA)

TransCanada Energy Ltd. (TCE)

The Office of the Utilities Consumer Advocate (UCA)
Interim approval under the Regulated Rate Option Regulation
7.
The Commission is mindful that interim approval of any procurement or pricing
mechanism relating to electricity charges for RRO customers is quite different than a typical
interim approval the Commission grants, where rates may be adjusted or refunded in future
periods following final rate approvals. The requirements relating to regulated rate tariffs are set
out in sections 103 and 104 of the Electric Utilities Act and the Regulated Rate Option
Regulation.
8.
Section 103(1) states, “each owner of an electric distribution system must prepare a
regulated rate tariff for the purpose of recovering the prudent costs of providing electricity
services to eligible customers.” Under Section 103(2) the owner must apply for approval of its
regulated rate tariff to the Commission unless Section 103(3) or Section 103(4) applies.
Sections 103(8) and 103(9) state:
7
Decision 2013-292: EPCOR Energy Alberta Inc., Amendments to the 2011-2014 Energy Price Setting Plan,
Application No. 1609493, Proceeding ID No. 2565, August 7, 2013.
2 • AUC Decision 2014-051 (March 3, 2014)
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
103(8) The owner may recover in its regulated rate tariff its prudent billing costs of
(a)
distribution tariff billing for the regulated rate, and
(b)
billing to eligible customers for the regulated rate tariff, including taxes and municipal
charges.
103(9) If an eligible customer who is in the service area of the owner’s electric distribution
system is not enrolled with a retailer, the owner is the customer’s regulated rate provider and the
customer is deemed to have elected to purchase electricity services under that owner’s regulated
rate tariff.
9.
DERS, EEAI and EEC perform the duties or functions of the owners in each of the
owners’ respective service areas through arrangements with the electric distribution owners, in
accordance with Section 104.
10.
The Regulated Rate Option Regulation was amended effective January 29, 2013.8 The
amendments included a change from the price setting period for procurement of energy from 45
to 120 days (Section 11), and various amendments to remove the transitional rate provisions
related to the July 1, 2006 to June 30, 2010 period. Sections 3(2) and 6(2) of the Regulated Rate
Option Regulation that relate to the generic proceeding remain unchanged.
11.
Section 3(2) provides:
3(2) A proposed regulated rate tariff must not use, provide for or contemplate any
deferral accounts, true-ups, rate riders or other similar accounts or devices for energy
related costs.
12.
Section 6(2) provides:
6(2) A regulatory authority must not approve a regulated rate tariff that uses, provides for
or contemplates any deferral accounts, true-ups, rate riders or other similar accounts or
devices for energy related costs.
13.
EEC,9 EEAI10 and the CCA11 submitted that the Commission would be unable to approve
interim refundable rates in this case given the regulatory restrictions. The UCA12 stated that
certain aspects of the proposed interim margins are potentially non-refundable.
14.
The Commission has concluded that the provisions of the Regulated Rate Option
Regulation prevent the Commission from approving electricity charges for regulated rate option
customers on an “interim refundable” or “interim adjustable” basis. Sections 3(2) and 6(2) of the
Regulated Rate Option Regulation prohibit a “true-up” for any differences relating to electricity
charges approved after June 30, 2014, and before a decision on the generic proceeding is issued.
Therefore, DERS’, EEC’s, and EEAI’s rates during this transition period will be final rates.
8
9
10
11
12
AR 11/2013.
Exhibit 28.01, paragraph 10.
Exhibit 29.01, paragraph 4.
Exhibit 20.02, paragraph 3.
Exhibit 27.01, paragraph 9.
AUC Decision 2014-051 (March 3, 2014) • 3
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
15.
The Commission’s findings on DERS’, EEC’s, and EEAI’s proposals for the transition
period between June 30, 2014, and the issuance of the decision on the generic proceeding are
discussed below. The electricity charges approved during the transition period will be approved
on a final basis.
3
The current EPSPs
3.1
DERS
16.
DERS’ current EPSP was negotiated with consumer representatives and included as part
of a negotiated settlement agreement13 that was approved in Decision 2011-199.
17.
DERS’ EPSP is based on block procurement that occurs under the direction and with the
input of the consultation parties14 and the independent advisor. DERS prepares a forecast of the
month ahead metered load and total load approximately 50 days before the beginning of each
month. During the period beginning 45 days before the month and ending before DERS files its
proposed energy charges for a given month, DERS acquires block hedges of sufficient volume to
hedge the forecast total load. The cost of the procured hedges forms a portion of the basis for
determining the monthly energy rate.
18.
Section 1(g) of the negotiated settlement agreement states that the risk compensation
amount to be charged by DERS is $2.97 per megawatt hour (MWh) plus 1.5 per cent of power
procurement costs as defined in Schedule A of the EPSP. DERS and the consultation parties
agreed15 to set the after-tax return for the obligation of DERS to provide electricity services in
accordance with Section 2 of the Regulated Rate Option Regulation at $1.75/MWh. DERS
applies the forecast tax rate for the upcoming year to establish the before-tax return amount to be
included in the monthly energy rate calculation.
3.2
EEAI
19.
The current EPSP of EEAI was negotiated with consumer representatives and included as
part of an EPSP amended agreement16 that was approved in Decision 2013-292.
20.
EEAI and the consultation parties17 agreed that the procurement period in the amended
EPSP would be increased from 45 days to 120 days to be consistent with the amendments to the
Regulated Rate Option Regulation. EEAI’s procurement will continue to be completed through a
series of auctions. The number of Natural Gas Exchange (NGX) auction session buying rounds,
as defined in the agreement, has increased from three with one contingency auction to eight
rounds with one contingency auction. Additionally, the block sizes in the amended EPSP have
been reduced from 25 megawatts (MW) for flat and 10 MW for peak to 10 MW for flat and
five MW for peak.18
13
14
15
16
17
18
A copy of the negotiated settlement agreement is included as Appendix 2 to Decision 2011-199.
The consultation parties are the UCA and the CCA.
See Section 1(k) of the negotiated settlement agreement.
A copy of the negotiated settlement agreement is included as Appendix 2 to Decision 2013-292.
The consultation parties are the UCA and the CCA.
Decision 2013-292, paragraph 46.
4 • AUC Decision 2014-051 (March 3, 2014)
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
21.
EEAI and the consultation parties agreed to a mechanism that adjusts the commodity risk
margin on a quarterly basis. The revised commodity risk compensation consists of four
components:




The continuation of the fixed risk margin ($2.11/MWh) agreed to in the 2011-2014
settlement and approved in Decision 2011-123.
A weighted systematic loss component calculated by applying a one-third weighting to
the average systematic loss for the most recent 12 months and two-thirds weighting to the
average systematic loss for the period from January 2002 through to the month prior to
the most recent 12 months.
A weighting adjustment factor, which adjusts the one-third and two-thirds weighting
relative to the commodity risk levels occurring in the most recent 12-month period.
An extreme risk margin adder, which provides for additional commodity risk
compensation to EEAI when commodity risk levels reach extreme levels.19
Section 1(f) of the EPSP amended agreement states that EEAI also will receive an administrative
risk margin of $0.41/MWh, and an after-tax return of $1.38/MWh. The after-tax return amount is
grossed up for income taxes.
3.3
EEC
22.
EEC’s current EPSP was negotiated with consumer representatives and included as part
of a negotiated settlement agreement20 that was approved in Decision 2011-486.
23.
EEC’s EPSP is based on block procurement that occurs under the direction and with the
input of the consultation parties21 and the independent advisor. EEC prepares a forecast of the
month ahead net metered load at least 60 days before the beginning of each month. During the
period beginning 45 days before the month and ending when the backstop mechanism begins,
EEC acquires block hedges of sufficient volume to hedge the forecast net metered load. The
weighted average contracted price of all blocks, including the price of any offers that EEC is
determined to have accepted under the procurement process, forms the base price component of
EEC’s portfolio price. Included in the portfolio price are any incentive compensation and any
backstop incentive compensation that EEC receives, along with any other verifiable over the
counter transaction costs. The calculation of the incentive compensation and the backstop
incentive compensation is described in Section 11 of Appendix 1 of the EPSP.
24.
Section 10 of the EPSP describes the risk compensation that EEC is entitled to receive,
including procurement risk compensation of $3.50/MWh plus 2.25 per cent of the portfolio price,
and an amount of $0.61/MWh for administrative risk compensation. Sections 10 and 11 of the
EPSP describe the reasonable return that EEC is entitled to receive. The return consists of
$0.50/MWh after-tax for load obligation return, and a going concern return to a maximum of
$1.00/MWh after-tax. The load obligation return is intended to compensate EEC for the
obligation to provide regulated rate service to eligible customers. Section 13 of the EPSP permits
EEC to recover the amounts payable under the Payment in Lieu of Tax Regulation, AR 112/2003
with respect to the load obligation return and the going concern return.
19
20
21
Decision 2013-292, paragraph 59.
A copy of the negotiated settlement agreement is included as Appendix 3 to Decision 2011-486.
The consultation parties are the UCA and the CCA.
AUC Decision 2014-051 (March 3, 2014) • 5
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
4
25.
4.1
Options for the EPSP transition period
The following recommendations were made for the transition period.
DERS
26.
Considering that DERS did not have an application before the Commission at the time of
filing its comments, DERS proposed that it continue to operate under its current EPSP but that
the after-tax return amount be updated from $1.75 to $2.95/MWh. DERS relied on
Section 6(1)(b)(i) of the Regulated Rate Option Regulation, which indicates that a regulated rate
tariff must allow for a reasonable return for the obligation to provide electricity services. DERS
indicated that the 1.43 per cent mark-up on total revenues used to determine its current after-tax
return amount of $1.75/MWh was based on its revenues from over six years ago, and should be
updated to reflect its recent total revenues.
27.
Applying the 1.43 per cent mark-up to its 2012 actual revenues, DERS calculated a total
after-tax return amount of $4.182 million to be collected through the energy charge. Dividing the
$4.182 million by the actual 2012 load figure of 1,417,376 MWh results in the proposed updated
after-tax return charge of $2.95/MWh.22
4.2
EEAI
28.
EEAI referred to sections 5 and 6 of the Regulated Rate Option Regulation. It submitted
that the risk margin must be just and reasonable, and must provide EEAI with just and
reasonable financial compensation for the risks to which EEAI is directly exposed. EEAI
submitted that the regulated rate tariff must allow for a reasonable return for the obligation on the
owner to provide electricity services, and the risk margin must not be considered as a part of that
reasonable return. EEAI further submitted that a regulated rate tariff must not impede the
development of an efficient market for electricity based on fair and open competition in which
neither the market nor the structure of the Alberta electric industry is distorted by unfair
advantages of any participant.23
29.
EEAI submitted that its current commodity risk margin mechanism and the return margin
are inadequate. It referred to its most recent application for approval of the amended EPSP,24 and
indicated that, in that application, EEAI specifically noted the commodity risk margin being
applied for did not reflect the increased risk to which EEAI had become exposed.25
30.
Noting that there are a number of differences between the current circumstances and
those addressed by the Commission in a typical utility tariff application, EEAI submitted that the
Commission’s general approach of approving approximately 50 per cent of the difference
between current rates and the rates applied for by the utility on a final basis, provides a basis for
addressing the issues at hand. EEAI indicated that, given the Regulated Rate Option Regulation
precludes the Commission from approving an increase on an interim refundable basis, approving
50 per cent of the requested increase, for what it believes would be a relatively short period of
time, would strike an appropriate balance between ensuring that EEAI is more appropriately
22
23
24
25
Exhibit 3, DERS’ comments, December 16, 2013, page 2.
This is addressed in Section 6(1)(d) or the Regulated Rate Option Regulation.
Application No. 1609493, which was addressed in Decision 2013-292.
Exhibit 6, paragraph 6.
6 • AUC Decision 2014-051 (March 3, 2014)
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
compensated for the commodity risks it faces and recognizing that customers should bear an
appropriate level of cost associated with those risks.
31.
EEAI indicated that, although the commodity risk compensation mechanism currently in
place as approved in Decision 2013-292 is more adaptive than the historical locked-in structure,
it is far from being fully adaptive because it is calculated by applying an approximately one-third
weighting to the commodity risk level (average systematic loss or risk incurred) for the most
recent 12 months and an approximately two-thirds weighting to the commodity risk level for the
period from January 2002 through to the month prior to the most recent 12 months.
32.
EEAI provided an analysis that showed that its currently approved commodity risk
compensation mechanism would have resulted in a 6.54 per cent average commodity risk margin
over the period of July 2006 to June 2013; and a 6.86 per cent average commodity risk margin
over the period of January 2011 to June 2013. EEAI indicated that using the applied-for
commodity risk margin mechanism set out in its initial 2014-2018 EPSP application,26 the
relevant percentages would have been 8.48 per cent for the period of July 2006 to June 2013 and
10.82 per cent for the period of January 2011 to June 2013.
33.
EEAI stated that the 2002 to 2011 time period is not reflective of the current dynamic
commodity risk environment experienced since the beginning of 2011, and as such, does not
provide a reasonable basis upon which to forecast the commodity risk compensation that is
required to provide an RRO provider with adequate protection against default (i.e. revenues
insufficient to cover expenses). Further, the mechanism approved in Decision 2013-292 applies a
fixed $/MWh as the default compensation component of the risk compensation mechanism.
EEAI added that fixed $/MWh risk compensation mechanisms are unable to adapt to changes in
forward pricing and result in under compensation when forward prices rise above the forward
price level assumed when converting the percentage default compensation to a fixed $/MWh
amount. In the current dynamic commodity risk environment, where the volatility of forward
prices can be substantial, this inflexibility frequently under-compensates an RRO provider.
34.
EEAI submitted that in comparison, the 12-month moving average commodity risk
compensation structure, which it applied for in its initial 2014-2018 EPSP application, results in
commodity risk compensation percentages that more reasonably reflect the level of commodity
risk to which EEAI is directly exposed.
35.
Given the above arguments with respect to commodity risk compensation structure, EEAI
proposed that the increase in commodity risk compensation be calculated as the mid-point
between the commodity risk margin determined by using the currently approved mechanism, and
the commodity risk margin determined by using the mechanism set out in its initial 2014-2018
EPSP application. EEAI provided an illustrative example of how the value of the proposed
commodity risk margin increase would be calculated, assuming that the increase was being
calculated for implementation in its January 2014 rates. This example showed the total risk
compensation for January 2014, under the current EPSP of $5.38/MWh, and total risk
compensation for January 2014 of $7.11/MWh, using the commodity risk margin mechanism
included in EEAI’s initial 2014-2018 EPSP. The mid-point of these two figures is $6.24/MWh.
26
EEAI submitted an initial 2014-2018 EPSP application, which was assigned Proceeding ID No. 2845. The
Commission subsequently closed this proceeding after it decided to hold the generic proceeding.
AUC Decision 2014-051 (March 3, 2014) • 7
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
36.
EEAI’s after-tax return included in its current EPSP is $1.38/MWh. In its proposed EPSP
for 2014-2018, EEAI requested a pre-tax return amount of $8.21/MWh.27 Using the current
income tax rate of 25 per cent that EEAI included in its January 2014 monthly energy charge
filing with the Commission,28 this equates to an after-tax amount of $6.16.29 The mid-point of the
two after-tax amounts of $1.38/MWh and $6.16/MWh is $3.77/MWh, which is the resulting
after-tax return for which EEAI is requesting approval in the transition period.
37.
EEAI stated that it did not create the current timing issue, having sought to file its
2014-2018 EPSP application in sufficient time to allow a decision to be issued by the
Commission in time for implementation on July 1, 2014.30 EEAI submitted that it would be
wholly unfair to require EEAI to continue to operate under the current inadequate commodity
risk margin mechanism and return margin past the current June 30, 2014 expiry date.
38.
EEAI indicated that it is proposing a reduction in the number of NGX auction sessions in
its energy procurement process to reflect a reduction in the number of customers it serves. This
reduction in the number of customers has reduced, and will continue to reduce, the hedging
volumes required to serve its customer base. As a result of the anticipated reduction in the
hedging volumes over the upcoming months, the average number of blocks procured using eight
auctions would drop to five. EEAI stated that if the average number of blocks drops below a
reasonable level, it will reduce the efficiency and effectiveness of the auction process and may
lead suppliers to become disinterested in participating. It added that by reducing the number of
NGX auction sessions to six, EEAI will be able to maintain roughly the same average number of
blocks procured in each auction as it has historically procured. Reducing the number of auction
sessions will also require amendments to the confidential NGX auction session evaluation
criteria schedule to the current EPSP. In order to implement the reduction in the number of
auction sessions for procurement for July, 2014, EEAI submitted that it will require Commission
approval by February 28, 2014.31
4.3
EEC
39.
EEC submitted that it continue to operate under its current EPSP, but that a fixed
procurement risk compensation amount of $6.24/MWh be included to replace the current
procurement risk compensation amount of $3.50/MWh plus 2.25 per cent of the portfolio price.
40.
EEC noted the requirements of the Regulated Rate Option Regulation, sections 5(3) and
5(4), which deal with risks included in the risk margin. EEC Wholesale Trading has been
engaged to manage the RRO energy procurement and related activities during the term of the
current EPSP, and EEC Wholesale Trading has experienced significant losses in managing the
risks associated with the EPSP. EEC provided a listing of the monthly gains and losses over the
period from July, 2011 to October, 2013, with the average loss being $6.44/MWh.
41.
Based on its current procurement risk compensation and assuming a portfolio price of
$70/MWh, procurement risk compensation is estimated at $5.08/MWh, which EEC stated is
27
28
29
30
31
Exhibit 32.01, page 12 of 277 (pdf), paragraph 11.
Application No. 1610197, EEAI’s Electric Energy Charges, January 2014, Attachment 3 – EEAI January 2014
RRT Energy Charge Calculation, Excel worksheet entitled “3-Inputs,” cell E68.
$8.21*(1-.25) = $6.16.
Exhibit 6.01, page 3, paragraph 11 and Exhibit 29.01, page 2, paragraph 5.
Exhibit 29.01, EEAI letter dated January 20, 2014, page 3.
8 • AUC Decision 2014-051 (March 3, 2014)
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
significantly below the average loss amount of $6.44/MWh, and demonstrates that the current
risk compensation is not just and reasonable. EEC stated that approving an EPSP for the
transition period that does not take these losses into account would violate Section 5 of the
Regulated Rate Option Regulation, which requires the Commission to ensure that the risk margin
is just and reasonable.
42.
EEC submitted that in the spirit of adopting a standardized and consistent approach
among RRO providers, to simplify approaches among the three RRO providers, and to be
mindful of the timing constraints surrounding the generic proceeding, it is requesting that the
procurement risk compensation of $6.24/MWh proposed by EEAI also be applied to EEC during
the transition period, on a non-refundable basis. This $6.24/MWh would replace the $3.50/MWh
plus 2.25 per cent of the portfolio price that EEC is currently receiving.
4.4
The CCA
43.
The CCA stated that the Regulated Rate Option Regulation, as currently worded, will not
permit any deferral or true-up or similar account to deal with how the monthly energy charges
and return should be determined during the transition period between the expiry of the current
EPSPs and the implementation of the new EPSPs. The CCA submitted that an amendment to the
Regulated Rate Option Regulation may be appropriate to allow for the approval of an interim
refundable rate commencing July 1, 2014, and to remain effective until final EPSPs are
approved.
4.5
TCE
44.
TCE submitted that during the transition period, the monthly energy charges and return
should be calculated in accordance with the current EPSPs notwithstanding their expiry. TCE
stated that the purchasing mechanisms in the current EPSPs have already been approved by the
Commission and industry is familiar with them. It added that use of the current mechanisms will
ensure consistency and continuity until new purchasing mechanisms are tested and approved in
the generic proceeding.
4.6
The UCA
45.
The UCA recommended continuing with the current EPSP until the matters in the generic
proceeding are determined. The UCA indicated that it will be providing expert evidence in the
generic proceeding with respect to the risk margins and reasonable return for the three RRO
providers. It submitted that the justness and reasonableness of the risk margins and reasonable
return must be tested in evidence before the Commission. Due to the potentially non-refundable
nature of certain aspects of the proposed margins for the transition period, it is neither just nor
reasonable to award increases in the margins merely because the RRO providers request them.
The procedurally fair option is to maintain the current EPSPs, which were tested before the
Commission and were previously deemed to be just and reasonable.
46.
In light of the increased costs and lack of reciprocal benefits to customers associated with
the 120-day procurement under the current EPSP for EEAI, the UCA proposed that one option
for the Commission to consider would be to revert to the pre-amendment EPSP, which provided
for a 3.35 per cent and $2.11/MWh risk margin. The UCA added, however, that this may be
unfair without hearing and testing all of the evidence in the generic proceeding.
AUC Decision 2014-051 (March 3, 2014) • 9
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
Commission findings
DERS
47.
DERS’ request to increase its after-tax return margin from $1.75 to $2.95/MWh is based
on its actual revenues from 2012. The $1.75/MWh amount DERS presently receives was part of
a negotiated settlement agreement that the Commission approved in Decision 2011-199. The
details of this negotiation, as well as information concerning the method of calculation applied,
were not submitted to or reviewed by the Commission. DERS and consultation parties agreed to
set the after-tax return for the provision of electricity services at $1.75/MWh, which was
previously approved by the Commission in Decision 2006-107,32 effective on July 1, 2006.
48.
The Commission has before it DERS’ complete 2014-2018 EPSP submission. Because
the generic proceeding has just commenced, the 2014-2018 EPSP remains to be tested in this
generic proceeding and other parties have not yet been afforded an opportunity to file evidence
in response to DERS’ 2014-2018 EPSP submission. Until DERS’ 2014-2018 EPSP has been
fully tested, the Commission is unable to determine whether the use of 2012 actual revenues is a
more accurate measure for calculating the after-tax return charge on which the proposed increase
to $2.95/MWh is based.
49.
Given that the current after-tax return margin was the result of a negotiated settlement,
which was approved in its entirety, the Commission has no information on what other elements
of the settlement, if any, may have been agreed to by parties as part of the agreement to adopt the
after-tax return margin. The Commission has given significant weight to the fact that DERS’
EPSP was arrived at through negotiations between DERS and customer representatives. In
approving DERS’ EPSP in Decision 2011-199, the Commission was satisfied that the interests of
all the parties involved, including DERS’, were served.33
50.
The Commission considers that continuing with the existing EPSP balances the
reasonable opportunity for DERS to recover its prudent costs and expenses, while recognizing
the principles of certainty and reasonable rates in customer’s monthly bills through energy
charges that are not subject to deferral accounts, true-ups, or rate riders under sections 3(2) and
6(2) of the Regulated Rate Option Regulation.
51.
Consequently, the Commission denies DERS’ request to increase its after-tax return
margin in its EPSP during the transition period. Accordingly, the Commission finds that keeping
the energy charges during the transition period at the levels set in the current EPSP, which was
negotiated, is fair and reasonable.
52.
DERS shall adhere to the EPSP approved in Decision 2011-199, until the Commission
otherwise directs.
EEAI
53.
EEAI’s recommendation that its commodity risk margin and reasonable return amount be
increased is based on the calculation methodology put forward in EEAI’s proposed 2014-2018
EPSP. The Commission has before it EEAI’s complete 2014-2018 EPSP submission. Because
32
33
Decision 2006-107: Direct Energy Regulated Services, Reasonable Return Margin Effective July 1, 2006,
Application No. 1455025, November 1, 2006.
For DERS, please refer to paragraph 16 of Decision 2011-199.
10 • AUC Decision 2014-051 (March 3, 2014)
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
the generic proceeding has just commenced, the 2014-2018 EPSP remains to be tested in this
generic proceeding and other parties have not yet been afforded an opportunity to file evidence
in response to EEAI’s 2014-2018 EPSP submission. Until EEAI’s 2014-2018 EPSP has been
fully tested, the Commission is unable to determine without testing the proposal whether an
increase to the commodity risk margin and an increase to the return are required. In the absence
of any tested evidence that changes are required to the current EPSP, the Commission finds that
the most reasonable way to set energy charges during the transition period is in accordance with
the current EPSP.
54.
The Commission also considers that EEAI’s amending agreement approved in Decision
2013-292 was reached recently through negotiations with consultation parties. In that decision,
the Commission approved the amending agreement and amended EPSP which included an
increase in the commodity risk margin and changed the procurement period to120 days,
consistent with the increase in the number of days permitted in the price setting period for the
month in the amended Regulated Rate Option Regulation. In approving EEAI’s amended EPSP,
the Commission was satisfied that the amending agreement and amended EPSP served the
interests of all the parties involved, including EEAI’s.34 Consequently, the Commission denies
EEAI’s request to increase its commodity risk margin and return amount for inclusion in its
EPSP during the transition period.
55.
The Commission acknowledges EEAI’s submission that it did not create the current
timing issue as it had previously filed a 2014-2018 EPSP application before the generic
proceeding was created. However, even without the establishment of the generic proceeding, the
timing of EEAI’s submission of its original 2014-2018 EPSP would not have allowed for
implementation of the 120-day price setting period for the month of July 2014. EEAI’s original
2014-2018 EPSP application was filed on September 23, 2013, and was assigned Proceeding ID
No. 2845. In its original 2014-2018 EPSP application, EEAI requested approval timelines as
follows:
160. It is necessary for EEAI to initiate the energy procurement processes contemplated
in the 2014-2018 EPSP by March 3, 2014. Therefore, EEAI respectfully requests that the
Commission make all reasonable efforts to issue a final approval for the 2014-2018 EPSP
on or before February 14, 2014.35
56.
As outlined in Commission Bulletin 2010-16,36 the issuance of a decision for a full
written process proceeding is expected to be from 214 to 262 calendar days from the date the
application was filed, assuming a complete filing was received, and there are no procedural
delays. If an oral hearing is required, this would extend the issuance date for the Commission’s
decision. April 25, 2014, is 214 calendar days after September 23, 2013, and June 12, 2014, is
262 calendar days after September 23, 2013. April 25, 2014, and June 12, 2014, are after the
latest decision issuance date of March 3, 2014, that EEAI would have required, and much later
than the February 14, 2014, issuance date that EEAI requested. Consequently, EEAI still would
have required a transition period EPSP to be in place, and the establishment of the generic
proceeding simply means that the transition period will be longer.
34
35
36
Please refer to paragraph 28 of Decision 2013-292.
Proceeding ID No. 2845, Exhibit 1, application, paragraph 160.
Bulletin 2010-16, Performance Standards for Processing Rate-Related Applications, April 26, 2010.
AUC Decision 2014-051 (March 3, 2014) • 11
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
57.
Decision 2013-292 regarding EEAI’s 2011-2014 amended EPSP was rendered in August
2013, and was recently reviewed and approved by the Commission. In its November 22, 2013
letter commencing the generic proceeding, the Commission found that consideration of the three
EPSP provider plans in one proceeding allows for a more thorough understanding of any
similarities and differences among the EPSP plans and would reduce duplication.37 The generic
proceeding, therefore, should afford a more efficient regulatory process by testing the EPSPs
through one proceeding.
58.
For these reasons, the Commission considers that continuing with the existing EPSP
balances the reasonable opportunity for EEAI to recover its prudent costs and expenses, while
recognizing the principles of certainty and reasonable rates in customer’s monthly bills through
energy charges that are not subject to deferral accounts, true-ups, or rate riders under sections
3(2) and 6(2) of the Regulated Rate Option Regulation.
59.
Similarly, the Commission does not agree with EEAI’s request to reduce the number of
NGX auction sessions from eight to six. On August 7, 2013, just seven months ago, the
Commission approved amendments to EEAI’s 2011-2014 EPSP, in which the number of NGX
auction sessions was increased from three to eight.38 The Commission considers that any
anticipated reduction in the number of customers and hedging volumes would have been taken
into account by EEAI at the time of its EPSP amendment application. EEAI did not provide any
evidence to support its assumptions that anticipated reductions in the number of customers and
hedging volumes, which were made less than a year ago, are no longer valid. Although there
might be a concern about future changes to the eligibility criteria for RRO service, the
Commission is not prepared to approve revisions to the auction sessions without testing the
underlying rationale and assumptions that may have changed since Decision 2013-292, which
was approved effective August 7, 2013.
60.
The Commission finds that keeping the energy charges during the transition period at the
level set in the current EPSP, which was negotiated, is fair and reasonable. EEAI shall adhere to
the EPSP approved in Decision 2013-292, until the Commission otherwise directs.
EEC
61.
EEC’s request to change its procurement risk compensation from $3.50/MWh plus
2.25 per cent of the portfolio price to a fixed amount of $6.24/MWh is based on the sample
calculation included in EEAI’s comments.39 The Commission acknowledges EEC’s submission
that, in the spirit of adopting a standardized and consistent approach among RRO providers, the
procurement risk compensation of $6.24/MWh proposed by EEAI should also be applied to EEC
during the transition period.
62.
The Commission has before it EEC’s complete 2014-2018 EPSP submission. Because the
generic proceeding has just commenced, the 2014-2018 EPSP remains to be tested in this generic
37
38
39
Exhibit 1, page 1.
Decision 2013-292.
Exhibit 6.01, EEAI’s submission. The $6.24/MWh is calculated in Table 1 of EEAI’s submission. Table 1 of
EEAI’s submission is entitled “Illustrative Example Proposed Interim Increase to Commodity Risk Margin”. In
paragraph 14 of its submission, EEAI states: “Table 1 provides an illustrative example of how EEAI proposes to
calculate the value of the proposed Commodity Risk Margin increase, assuming that increase were being
calculated for implementation in EEAI’s January 2014 rates.”
12 • AUC Decision 2014-051 (March 3, 2014)
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
proceeding and other parties have not yet been afforded an opportunity to file evidence in
response to EEC’s 2014-2018 EPSP submission. Until EEC’s 2014-2018 EPSP has been fully
tested, the Commission is unable to determine whether a revision to EEC’s procurement risk
compensation amount is required. The Commission considers that it is not reasonable to approve
an increase based on a sample calculation that has not been tested, especially given that energy
rates during the transition period are not subject to true-up.
63.
Given that the current procurement risk compensation was the result of a negotiated
settlement, which was approved in its entirety, the Commission has no information on what other
elements of the settlement, if any, may have been agreed to by parties as part of the agreement to
adopt the procurement risk compensation. The Commission has given significant weight to the
fact that EEC’s EPSP was arrived at through negotiations between EEC and customer
representatives. In approving EEC’s negotiated EPSP, the Commission was satisfied that the
interests of all the parties involved, including EEC’s, were served.40 The Commission considers
that continuing with the existing EPSP balances the reasonable opportunity for EEC to recover
its prudent costs and expenses, while recognizing the principles of certainty and reasonable rates
in customers’ monthly bills through energy charges that are not subject to deferral accounts, trueups, or rate riders under sections 3(2) and 6(2) of the Regulated Rate Option Regulation.
64.
Accordingly, the Commission finds that keeping the energy charges during the transition
period at the level set in the current EPSP, which was negotiated, is fair and reasonable.
Consequently, the Commission denies EEC’s request to increase its procurement risk
compensation in its EPSP during the transition period. EEC shall adhere to the EPSP approved in
Decision 2011-486, until the Commission otherwise directs.
40
For EEC, please refer to paragraph 65 of Decision 2011-486.
AUC Decision 2014-051 (March 3, 2014) • 13
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
5
65.
Order
It is hereby ordered that:
(1)
Direct Energy Regulated Services shall adhere to the energy price setting plan
approved by the Commission in Decision 2011-199, until the Commission
otherwise directs.
(2)
EPCOR Energy Alberta Inc. shall adhere to the energy price setting plan
approved by the Commission in Decision 2013-292, until the Commission
otherwise directs.
(3)
ENMAX Energy Corporation shall adhere to the energy price setting plan
approved by the Commission in Decision 2011-486, until the Commission
otherwise directs.
Dated on March 3, 2014.
The Alberta Utilities Commission
(original signed by)
Mark Kolesar
Vice-Chair
(original signed by)
Kay Holgate
Commission Member
(original signed by)
Henry van Egteren
Commission Member
14 • AUC Decision 2014-051 (March 3, 2014)
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
Appendix 1 – Proceeding participants
Name of organization (abbreviation)
counsel or representative
Direct Energy Regulated Services (DERS)
L. Manning
N. Black
K. Hillas
C. Severson
ENMAX Energy Corporation (EEC)
D. Wood
K. Leonard
L. Janzen
J. Schlauch
T. Carle
EPCOR Energy Alberta Inc. (EEAI)
J. Baraniecki
N. Lamers
The City of Calgary
D. Evanchuk
M. Rowe
Consumers’ Coalition of Alberta (CCA)
J. A. Wachowich
A. P. Merani
R. Retnanandan
Forte Business Solutions Ltd.
S. Fulton
FortisAlberta Inc.
T. Dalgleish
I. Lorimer
M. Stroh
J. Sullivan
J. Walsh
J. Croteau
TransCanada Energy Ltd. (TCE)
S. Kley
V. Kostesky
C. Best
TransAlta Corporation
C. Codd
Office of the Utilities Consumer Advocate (UCA)
C. R. McCreary
K. Arrowsmith
AUC Decision 2014-051 (March 3, 2014) • 15
Regulated Rate Tariff and Energy Price Setting Plans – Generic Proceeding:
Direct Energy Regulated Services,
Part A – Transition Period
ENMAX Energy Corporation and EPCOR Energy Alberta Inc.
Name of organization (abbreviation)
counsel or representative
Market Surveillance Administrator
E. White
The Alberta Utilities Commission
Commission Panel
M. Kolesar, Vice-Chair
K. Holgate, Commission Member
H. van Egteren, Commission Member
Commission Staff
A. Sabo (Commission counsel)
L. Desaulniers (Commission counsel)
D. Mitchell
C. Burt
B. Clarke
A. Davison
C. Pham
L. Maruejols
C. Arnot
16 • AUC Decision 2014-051 (March 3, 2014)