ORDER NO. 890 (Excerpts)
FINAL RULE
TABLE OF CONTENTS
I. INTRODUCTION .......................................................................................................................... 1.
II. BACKGROUND ........................................................................................................................... 9.
A. Historical Antecedent ............................................................................................................. 9.
B. Order No. 888 and Subsequent Reforms.................................................................................14.
C. EPAct 2005 and Recent Developments ..................................................................................22.
III. NEED FOR REFORM OF ORDER NO. 888 .............................................................................26.
A. Opportunities for Undue Discrimination Continue to Exist.....................................................26.
B. Lack of Transparency Undermines Confidence in Open Access and Impedes
Enforcement of Open Access Requirements ...............................................................................44.
C. Congestion and Inadequate Infrastructure Development Impede Customers’ Use of the
Grid ...........................................................................................................................................52.
D. A Consistent Method of Measuring ATC Is Needed ...............................................................62.
E. Discriminatory Pricing of Imbalances.....................................................................................70.
F. Redispatch/Conditional Firm .................................................................................................73.
G. EPAct 2005 Emphasized Certain Policies and Priorities for the Commission .........................79.
IV. SUMMARY, SCOPE AND APPLICABILITY OF THE FINAL RULE ..................................82.
A. Summary of Reforms.............................................................................................................83.
B. Core Elements of Order No. 888 That Are Retained ...............................................................91.
1. Federal/State Jurisdiction ..................................................................................................92.
2. Native Load Protection .....................................................................................................95.
3. The Types of Transmission Services Offered .................................................................. 110.
4. Functional Unbundling .................................................................................................... 117.
C. Applicability of the Final Rule ............................................................................................ 124.
1. Non-ISO/RTO Public Utility Transmission Providers ...................................................... 124.
2. ISO and RTO Public Utility Transmission Providers and Transmission Owner
Members of ISOs and RTOs ................................................................................................ 143.
3. Non-Public Utility Transmission Providers/Reciprocity .................................................. 162.
V. REFORMS OF THE OATT ....................................................................................................... 193.
A. Consistency and Transparency of ATC Calculations ........................................................... 193.
B. Coordinated, Open and Transparent Planning ...................................................................... 418.
C. Transmission Pricing .......................................................................................................... 603.
1. General ........................................................................................................................... 603.
2. Energy and Generation Imbalances .................................................................................. 627.
a. Tiered Approach to Imbalance Penalties in the OATT
b. Intentional Deviations
c. Calculation of Incremental Cost
d. Inadvertent Energy Treatment
e. Netting/Crediting of Energy and Generator Imbalances
f. Intra-Hour Netting
g. Distribution of Penalty Revenues Above Incremental Cost
3. Credits for Network Customers ....................................................................................... 729.
4. Capacity Reassignment ................................................................................................... 778.
5. “Operational” Penalties ................................................................................................... 826.
a. Unreserved Use Penalties ........................................................................................... 826.
b. Distribution of Operational Penalties .......................................................................... 850.
c. Applicability of Operational Penalties Proposal to RTOs and Other Independent
or Non-Profit Entities ...................................................................................................... 866.
6. “Higher of” Pricing Policy ............................................................................................... 870.
7. Other Ancillary Services.................................................................................................. 886.
D. Non-Rate Terms and Conditions .......................................................................................... 901.
1. Modifications to Long-Term Firm Point-to-Point Service ............................................... 901.
a. Planning Redispatch and Conditional Firm Options .................................................... 901.
b. Proposals for Transparent Redispatch ....................................................................... 1095.
c. Other Requested Service Modifications ................................................................... 1165.
2. Hourly Firm Service ..................................................................................................... 1177.
3. Rollover Rights ............................................................................................................ 1214.
4. Modification of Receipt or Delivery Points .................................................................... 1268.
5. Acquisition of Transmission Service ............................................................................. 1296.
a. Processing of Service Requests ................................................................................ 1296.
b. Reservation Priority.................................................................................................. 1394.
6. Designation of Network Resources ................................................................................ 1432.
a. Qualification as a Network Resource ........................................................................ 1432.
b. Documentation for Network Resources ..................................................................... 1507.
c. Undesignation of Network Resources ....................................................................... 1534.
7. Clarifications Related to Network Service ..................................................................... 1592.
a. Secondary Network Service ...................................................................................... 1592.
b. Behind the Meter Generation ................................................................................... 1614.
8. Transmission Curtailments ........................................................................................... 1620.
9. Standardization of Rules and Practices........................................................................... 1633.
a. Business Practices .................................................................................................... 1633.
b. Liability and Indemnification ................................................................................... 1662.
10. OATT Definitions ...................................................................................................... 1678.
E. Enforcement ..................................................................................................................... 1714.
1. General Policy ............................................................................................................... 1715.
2. Civil Penalties ............................................................................................................... 1724.
VI. INFORMATION COLLECTION STATEMENT .................................................................. 1752.
VII. ENVIRONMENTAL ANALYSIS.......................................................................................... 1758.
VIII. REGULATORY FLEXIBILITY ACT ANALYSIS ............................................................ 1759.
IX. DOCUMENT AVAILABILITY .............................................................................................. 1760.
X. EFFECTIVE DATE AND CONGRESSIONAL NOTIFICATION......................................... 1763.
APPENDIX A: Summary of Compliance Requirements
APPENDIX B: Commenting Party Acronyms
APPENDIX C:
Pro Forma Open Access Transmission Tariff
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III. NEED FOR REFORM OF ORDER NO. 888
E. DISCRIMINATORY PRICING OF IMBALANCES
70. Order No. 888 focused primarily on the adoption of non-rate terms and
conditions of service, rather than instituting broad reform of the Commission’s
transmission pricing policies. Consistent with this focus, the Commission did
not propose broad transmission pricing reform in the NOPR, but rather
focused on instances where current pricing practices under the pro forma
OATT may no longer be sufficient to remedy undue discrimination or ensure
just and reasonable rates. One significant reform proposed in the NOPR related
to charges for imbalance energy. The Commission preliminarily found that
the existing policies provide wide discretion in the development of these
charges and hence the potential for undue discrimination. The Commission
therefore proposed certain principles to remedy that potential and sought comment
on whether a specific imbalance pricing method would be appropriate.
Comments
71. In general, transmission customers complain about the level and scope of
energy and generator imbalance charges that are levied under the pro forma OATT
and under individual interconnection agreements. Customers complain that
energy imbalance charges are excessive and not related to the actual costs
incurred by transmission providers. They also argue that the inconsistency
between these charges in different control areas is unnecessary, and that other
means of compensating the transmission provider, such as return-in-kind, should
be considered. Generators likewise complain that generator imbalance
charges are excessive, that transmission providers refuse to credit generators
with the revenues resulting from imbalance penalties that are collected, and
that transmission providers prevent unaffiliated generators from purchasing
or self-supplying generator imbalance services. In addition, owners of
intermittent resources complain that generator imbalance charges, which are
imposed to provide an incentive for generators to schedule accurately, are
inappropriate given their lack of control and ability to cure deviations.
Commission Determination
72. The Commission agrees that imbalance charges should provide
appropriate incentives to keep schedules accurate without being excessive.
We also find that consistency in imbalance charges, both between and among
energy and generator imbalances, is preferable to the wide variety of
imbalance provisions in place today. All imbalances have the same net effect on
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the transmission system in that they require other generation to be ramped up or
down to compensate for the imbalance. As such, the Commission adopts two pro
forma OATT provisions (Schedule 4 for energy imbalances and Schedule 9 for
generator imbalances) based on a tiered structure similar to the imbalance
provision used by Bonneville, as described further below. Such an approach
recognizes the link between escalating deviations and potential reliability
impacts on the system while keeping imbalance charges closely related to
incremental costs. The Commission finds, however, that intermittent resources
should be exempt from the highest-tier deviation band. We also require
transmission providers to credit to all non-offending transmission customers
the revenues they collect in excess of incremental costs.
V. REFORMS OF THE OATT
C. Transmission Pricing
2. Energy and Generation Imbalances
a. Tiered Approach to Imbalance Penalties in the OATT
663. In order to increase consistency among transmission providers in the
application of imbalance charges, and to ensure that the level of the charges
provides appropriate incentives to keep schedules accurate without being
excessive, the Commission adopts in the pro forma OATT imbalance provisions
similar to those implemented by Bonneville. We agree with commenters that a
graduated bandwidth approach recognizes the link between escalating deviations
and potential reliability impacts on the system. Furthermore, we conclude that
these provisions adhere to the three principles discussed in the NOPR, which we
also adopt here: (1) the charges must be based on incremental cost or some
multiple thereof; (2) the charges must provide an incentive for accurate
scheduling, such as by increasing the percentage of the adder above (and below)
incremental cost as the deviations become larger; and (3) the provisions must
account for the special circumstances presented by intermittent generators and
their limited ability to precisely forecast or control generation levels, such as
waiving the more punitive adders associated with higher deviations.
664. Specifically, imbalances of less than or equal to 1.5 percent of the scheduled
energy (or two megawatts, whichever is larger) will be netted on a monthly basis
and settled financially at 100 percent of incremental or decremental cost at
the end of each month. Imbalances between 1.5 and 7.5 percent of the scheduled
amounts (or two to ten megawatts, whichever is larger) will be settled financially
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at 90 percent of the transmission provider’s system decremental cost for
overscheduling imbalances that require the transmission provider to decrease
generation or 110 percent of the incremental cost for underscheduling imbalances
that require increased generation in the control area. Imbalances greater than 7.5
percent of the scheduled amounts (or 10 megawatts, whichever is larger) will be
settled at 75 percent of the system decremental cost for overscheduling imbalances
or 125 percent of the incremental cost for underscheduling imbalances.
665. The Commission adopts Bonneville’s tariff provisions that provide that
intermittent resources are exempt from the third-tier deviation band and would pay
the second-tier deviation band charges for all deviations greater than the larger of
1.5 percent or two megawatts. We believe this is consistent with the fact that
intermittent generators cannot always accurately follow their schedules and that
high penalties will not lessen the incentive to deviate from their schedules.
b. Intentional Deviations
676. The Commission recognizes the need to provide transmission customers
with the appropriate incentives not to intentionally dump power on the
system or lean on other generation. We do not believe, however, that separate
penalties for intentional deviations need to be generically imposed in the pro
forma OATT. The tiered imbalance penalties adopted in this Final Rule
generally provide a sufficient incentive not to engage in such behavior.
Proposals to assess additional penalties for intentional deviations will
continue to be considered on a case-by-case basis, subject to a showing that
they are necessary under the circumstances. We note that any such tariff
provisions must include clearly defined processes for identifying intentional
deviations and the associated penalties.
c. Calculation of Incremental Cost
NOPR Proposal
677. With respect to the pricing of energy and generation imbalances, the
Commission stated in the NOPR its belief that charges based on incremental costs
or multiples of incremental costs would provide the proper incentive to keep
schedules accurate without being excessive. The Commission proposed that
incremental cost be defined to include both energy and commitment1 costs, to the
1
The Commission noted that "capacity commitment" is generally defined
as the generating capacity committed by a utility to provide capability for another
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extent additional commitments are needed.2 The Commission sought comment on
how such charges should be calculated, as well as how they would be applied to
transmission customers. The Commission sought further comment as to how
additional demand and energy costs, if incurred in responding to imbalances, such
as redispatch, commitment, or additional regulation reserves, should be
appropriately reflected in the calculation of imbalance charges and which
customers should be charged for such costs.
Commission Determination
687. The Commission concludes that it is appropriate to define incremental cost,
for purposes of the tiered imbalance provisions adopted above, as the transmission
provider’s actual average hourly cost of the last 10 MW dispatched to supply the
transmission provider’s native load, based on the replacement cost of fuel, unit
heat rates, start-up costs, incremental operation and maintenance costs, and
purchased and interchange power costs and taxes, as applicable.
688. In deriving such charges, we note that the Commission proposed in paragraph
244 of the NOPR that incremental cost be defined to include both additional
energy and commitment costs. The Commission also sought comment on how
additional demand and energy costs, such as redispatch, commitment, or
additional regulation reserves, would be appropriately recovered if incurred in
responding to imbalances.
689. The Commission finds that it is appropriate, through the definition of
incremental cost, to allow for recovery of both commitment and redispatch
costs while excluding the cost recovery of additional regulation reserve costs.
Commitment and redispatch costs shall be accommodated as a part of the hourly
cost of the last 10 MW dispatch and in the start up cost portion of the definition.
The Commission concludes that excluding additional regulation costs as a general
matter is appropriate since much of those costs would be demand costs. We
believe including charges for unit commitment costs (e.g., start-up and minimum
utility to attain its reserve level. See, e.g., Central & South West Services, Inc., 48
FERC ¶ 61,197 at 61,731 n.9 (1989).
2
The Commission proposed defining incremental cost, based on its
decision in Consumers, as the transmission provider’s actual average hourly cost
of the last 10 MW dispatched to supply the transmission provider’s native load,
based on the replacement cost of fuel, unit heat rates, start-up costs, incremental
operation and maintenance costs, and purchased and interchange power costs and
taxes.
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load costs) and O&M costs is necessary to ensure that both energy and generation
imbalance charges reflect the full incremental costs incurred by the transmission
provider. We emphasize, however, that such costs should only be the
additional costs incurred by the transmission provider due to the imbalance.
If applicable, start-up costs should be allocated pro rata to the offending
transmission customers based on cost causation principles.
692. We do not believe it appropriate to require transmission providers to use
market proxy pricing to calculate incremental costs in the pro forma OATT. The
feasibility of using market proxies must be considered on a case-by-case basis,
given the characteristics of each market. If proposed, the proxy price must
represent a valid alternative to the incremental cost calculation, reflecting
competitive, transparent and liquid conditions similar to those that would
exist in the seller’s market.
g. Distribution of Penalty Revenues above Incremental cost
727. In this Final Rule, the Commission has reformed existing imbalance
provisions to reduce the variety of different methodologies used for determining
imbalance charges and ensure that the level of the charges provide appropriate
incentives to keep schedules accurate without being excessive. We also believe
that transmission providers should have a consistent method of treating revenues
received through imbalance penalties or charges that are in excess of incremental
cost. The Commission has previously required transmission providers with
significant imbalance penalties to develop a mechanism to credit penalty revenues
to non-offending transmission customers. This was intended to remove the
incentive of the transmission provider to hinder the development of other
imbalance services that do not rely on penalties. We believe it is appropriate to
maintain the requirement that transmission providers credit revenues in
excess of incremental costs. Therefore, as part of their compliance filings in this
proceeding, transmission providers are required to develop a mechanism for
crediting such revenues to all non-offending transmission customers
(including affiliated transmission customers) and the transmission provider
on behalf of its own customers. Such a distribution of penalty revenues
recognizes that transmission providers bear the responsibility to correct
imbalances and often use their own facilities to do so.
728. We acknowledge that in the CP&L decision, the Commission declined to
allow the transmission provider to allocate a share of imbalance penalty revenues
to itself as a user of the transmission system on behalf retail customers. Given the
reforms to the pro forma OATT imbalance provisions adopted in this Final Rule,
we believe the circumstances presented in that case are no longer applicable.
There, the Commission based its holding on its understanding that the high
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imbalance penalties imposed by the transmission provider were an interim
measure that were intended to be in place only until an imbalance market was
developed. In this Final Rule, we are adopting imbalance charges that are
closely related to incremental cost and therefore minimize any incentive on
the part of the transmission provider to rely on penalty revenues rather than
seeking other methods of encouraging accurate scheduling. Under these
circumstances, there remains no reason to exclude the transmission provider
from receiving an appropriate share of penalty revenues.
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