Market-Based Rates For Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 30924-30935 [E9-14784]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 74, Number 123 (Monday, June 29, 2009)]
[Rules and Regulations]
[Pages 30924-30935]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E9-14784]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM04-7-006; Order No. 697-C]


Market-Based Rates For Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities

Issued June 18, 2009.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Order on rehearing and clarification.

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SUMMARY: The Federal Energy Regulatory Commission is granting in part 
and denying in part the requests for rehearing and clarification of its 
determinations in Order No. 697-B, which granted rehearing and 
clarification of certain revisions to Commission regulations and to the 
standards for obtaining and retaining market-based rate authority for 
sales of energy, capacity and ancillary services to ensure that such 
sales are just and reasonable.

DATES: Effective Date: This order on rehearing will become effective 
July 29, 2009.

FOR FURTHER INFORMATION CONTACT: 

Michelle Barnaby (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426, (202) 502-8407.
Paige Bullard (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-6462.

SUPPLEMENTARY INFORMATION: 

Table of Contents

 
                                                          Paragraph No.
 
I. Introduction........................................                1
II. Background.........................................                2
III. Discussion........................................                8
    A. Vertical Market Power...........................                8
        Other Barriers to Entry........................                8
    B. Mitigation......................................               23

[[Page 30925]]

 
  Protecting Mitigated Markets.........................               23
    C. Implementation Process..........................               47
        Clarifications on Implementation Process.......               47
IV. Information Collection Statement...................               49
V. Document Availability...............................               50
VI. Effective Date.....................................               53
Regulatory Text
Appendix C to Order No. 697-C: Revised Tariff Language
Appendix D-2 to Order No. 697-C: Revised Regional
 Review Schedule
 

    Before Commissioners: Jon Wellinghoff, Chairman; Suedeen G. 
Kelly, Marc Spitzer, and Philip D. Moeller.

Order on Rehearing and Clarification

 I. Introduction

    1. In this order, the Commission addresses requests for rehearing 
and clarification of Order No. 697-B. Specifically, the Commission 
clarifies the requirement that sellers file a notification of change in 
status when they acquire sites for new generation capacity 
development.\1\ The Commission denies the requests for rehearing of the 
tariff provision governing mitigated sales at the metered boundary and 
affirms its determination in Order No. 697-B to revise the mitigated 
sales tariff provision in order to ensure that a mitigated seller 
making market-based rate sales at the metered boundary does not sell 
power into the mitigated market either directly or through its 
affiliates.\2\
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    \1\ 18 CFR 35.42 (2008).
    \2\ Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities, Order No. 697-
B, 73 FR 79,610 (Dec. 30, 2008), FERC Stats. & Regs. ] 31,285 
(2008).
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II. Background

    2. On June 21, 2007, the Federal Energy Regulatory Commission 
(Commission) issued Order No. 697,\3\ codifying and, in certain 
respects, revising its standards for obtaining and retaining market-
based rates for public utilities. In order to accomplish this, as well 
as streamline the administration of the market-based rate program, the 
Commission modified its regulations at 18 CFR part 35, subpart H, 
governing market-based rate authorization. The Commission explained 
that there are three major aspects of its market-based regulatory 
regime: (1) Market power analyses of sellers and associated conditions 
and filing requirements; (2) market rules imposed on sellers that 
participate in Regional Transmission Organization (RTO) and Independent 
System Operator (ISO) organized markets; and (3) ongoing oversight and 
enforcement activities. Order No. 697 focused on the first of the three 
features to ensure that market-based rates charged by public utilities 
are just and reasonable. Order No. 697 became effective on September 
18, 2007.
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    \3\ Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities, Order No. 697, 
FERC Stats. & Regs. ] 31,252 (Order No. 697 or Final Rule), 
clarified, 121 FERC ] 61,260 (2007), order on reh'g, Order No. 697-
A, 73 FR 25,832 (May 7, 2008), FERC Stats. & Regs. ] 31,268 (2008); 
clarified, 124 FERC ] 61,055 (2008) (July 17 Clarification Order), 
order on reh'g, Order No. 697-B, 73 FR 79,610 (Dec. 30, 2008), FERC 
Stats. & Regs. ] 31,285 (2008).
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    3. The Commission issued an order clarifying four aspects of Order 
No. 697 on December 14, 2007.\4\ Specifically, that order addressed: 
(1) The effective date for compliance with the requirements of Order 
No. 697; (2) which entities are required to file updated market power 
analyses for the Commission's regional review; (3) the data required 
for horizontal market power analyses; and (4) what constitute ``seller-
specific terms and conditions'' that sellers may list in their market-
based rate tariffs in addition to the standard provisions listed in 
Appendix C to Order No. 697. The Commission also extended the deadline 
for sellers to file the first set of regional triennial studies that 
were directed in Order No. 697 from December 2007 to 30 days after the 
date of issuance of the December 14 Clarification Order.
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    \4\ Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities, 121 FERC ] 
61,260 (2007) (December 14 Clarification Order).
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    4. On April 21, 2008, the Commission issued Order No. 697-A,\5\ in 
which it responded to a number of requests for rehearing and 
clarification of Order No. 697. In most respects, the Commission 
affirmed the determinations made in Order No. 697 and denied rehearing 
of the issues raised. However, with respect to several issues, the 
Commission granted rehearing or provided clarification.
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    \5\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 (2008).
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    5. On July 17, 2008, the Commission issued an order clarifying 
certain aspects of Order No. 697-A related to the allocation of 
simultaneous transmission import capability for purposes of performing 
the indicative screens.\6\ Specifically, that order granted the 
requests for rehearing with regard to footnote 208 of Order No. 697-A 
and clarified that in performing the indicative screen analysis, 
market-based rate sellers may allocate the simultaneous import limit 
capability on a pro rata basis (after accounting for the seller's firm 
transmission rights) based on the relative shares of the seller's (and 
its affiliates') and competing suppliers' uncommitted generation 
capacity in first-tier markets.\7\
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    \6\ July 17 Clarification Order, 124 FERC ] 61,055.
    \7\ Id. P 5.
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    6. On December 19, 2008, the Commission issued Order No. 697-B \8\ 
in which it clarified and affirmed the determinations made in Order No. 
697-A. Specifically, the Commission provided clarification regarding 
the allocation of seasonal and longer transmission reservations. The 
Commission also clarified that it will require a seller making an 
affirmative statement as to whether a contractual arrangement transfers 
control to seek a ``letter of concurrence'' from other affected parties 
identifying the degree to which each party controls a facility, and to 
submit these letters with its filing. The Commission denied the request 
that it clarify that only sites for which necessary permitting for a 
generation plant has been completed and/or sites on which construction 
for a generation plant has begun apply under the definition of ``inputs 
to electric power production'' in Sec.  35.36(a)(4) of the Commission's 
regulations. The Commission also revised the definition of 
``affiliate'' in section 35.36(a)(9) of its regulations to delete the 
separate definition for exempt wholesale generators. In addition, the 
Commission provided a number of other clarifications with regard to, 
among others, the pricing of sales of non-power goods and services and 
the tariff provision governing sales at the metered boundary.
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    \8\ Order No. 697-B, FERC Stats. & Regs. ] 31,285.
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    7. On January 28, 2009, in response to Tampa Electric Company's 
(Tampa Electric) request for extension of time to comply with the 
tariff provision on

[[Page 30926]]

mitigated sales at the metered boundary as revised in Order No. 697-B, 
the Commission issued an order granting the extension requested by 
Tampa Electric until such time as the Commission issues an order on 
rehearing of Order No. 697-B.\9\ That order clarified that affected 
entities must continue to comply with the mitigated sales tariff 
provision adopted in Order No. 697-A \10\ (which became effective on 
June 6, 2008), until such time as the Commission acts on the requests 
for rehearing of Order No. 697-B.
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    \9\ Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities, 126 FERC ] 
61,072 (2009) (Order Granting Extension of Time to Comply).
    \10\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at Appendix 
C.
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III. Discussion

A. Vertical Market Power

Other Barriers to Entry
Background
    8. Order No. 697 adopted the NOPR proposal to consider a seller's 
ability to erect other barriers to entry as part of the vertical market 
power analysis, but modified the requirements when addressing other 
barriers to entry.\11\ It also provided clarification regarding the 
information that a seller must provide with respect to other barriers 
to entry (including which inputs to electric power production the 
Commission will consider as other barriers to entry) and modified the 
proposed regulatory text in that regard.\12\
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    \11\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 440.
    \12\ Id.
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    9. On rehearing, the Commission clarified that it was not its 
intent for the term ``inputs to electric power production'' to 
encompass every instance of a seller entering into a coal supply 
contract with a coal vendor in the ordinary course of business. The 
Commission clarified that Order No. 697 encompasses physical coal 
sources and ownership of or control over who may access transportation 
of coal via barges and railcar trains.\13\ Thus, the Commission revised 
its definition of ``inputs to electric power production'' in Sec.  
35.36(a)(4) as follows: ``intrastate natural gas transportation, 
intrastate natural gas storage or distribution facilities; sites for 
new generation capacity development; physical coal supply sources and 
ownership of or control over who may access transportation of coal 
supplies.'' \14\
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    \13\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 176 
(emphasis in original).
    \14\ Id.
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    10. In Order No. 697-B, the Commission rejected the Electric Power 
Supply Association's (EPSA) proposal that the term ``sites for new 
generation capacity development'' mean only sites with respect to which 
permits for new generation have been obtained or where construction of 
new generation is underway, and not encompass land that could 
potentially be used for generation. The Commission explained that 
``sites for new generation capacity development'' should be construed 
to include ownership of land that could potentially be used for 
generation, not just sites for which permits for new generation have 
been obtained or where construction of new generation is underway. The 
Commission also clarified that ``sites for new generation capacity 
development'' does not include land that cannot be used for generation 
capacity development.\15\
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    \15\ Order No. 697-B, FERC Stats. & Regs. ] 31,285 at P 38.
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Requests for Rehearing
    11. American Wind Energy Association (American Wind) requests 
rehearing of Order No. 697-B's clarification that sites for new 
generation capacity development should be construed to include 
ownership of land that could potentially be used for generation, 
arguing that the scope and intent behind this requirement was not fully 
illuminated until the Commission's clarification of this requirement in 
Order No. 697-B.\16\ American Wind contends that the Commission should 
grant rehearing of the term ``sites for new generation capacity 
development'' so as to only require reporting for sites for new 
generation development that are located in load pockets where a 
``potential'' for vertical market power may exist, and should clarify 
that it will rely on the existing rebuttable presumption that all other 
sites do not create a barrier to entry.\17\
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    \16\ American Wind January 21, 2009 Rehearing Request at 5.
    \17\ Id. at 5-6.
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    12. American Wind argues that the Commission's interpretation of 
the reporting burden to include sites that could potentially be used 
for generation substantially increases the regulatory compliance burden 
on market-based rate sellers, and that the increased burden can be 
illustrated with respect to the impact on wind energy developers. It 
explains that in developing new wind power generation sites, wind 
energy developers seek to initially lease approximately 150 acres for 
each turbine. American Wind states that in developing a 100 megawatt 
project using 1.5 megawatt wind turbines, a developer may seek to 
initially have 10,000 acres of land under control. It further explains 
that control over such land may result from leases that would likely be 
made with multiple landowners over a period of several months, and that 
in regions with significant wind development, it would not be 
surprising to find a vast number of acres for potential new generation 
sites under some form of control, via leases or some other form of 
agreement, by wind energy developers.\18\
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    \18\ Id. at 6-7.
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    13. According to American Wind, the requirement to file 
notifications of change in status every time a market-based rate seller 
or its affiliates acquire sites that potentially could be used for 
generation would create a substantial burden and a competitive risk, 
while not providing any associated benefit to the Commission. American 
Wind asserts that wind developers in particular would be subjected to 
increased risk of the disclosure of their proprietary and competitive 
information because wind developers regularly compete for new land that 
can be used for wind development projects.\19\ It states that in the 
development process, wind energy developers spend significant time and 
effort searching for new land that may be appropriate for wind 
development sites, and that information as to where a wind energy 
developer is considering the development of new generation projects is 
highly proprietary and confidential. American Wind contends that even 
assuming a filing submitted at the Commission includes information ``on 
a summarized, balancing authority area basis, given the small size of 
some balancing authorities, the public release of such proprietary and 
confidential information could lead to competitive harm.'' \20\ 
American Wind also argues that if a seller's control of potential new 
generation sites were alleged to create a new barrier to entry, the 
Commission, either pursuant to a complaint filed by a third party or a 
Commission-initiated investigation, would have ample authority to take 
action and challenge the rebuttable presumption that ownership or 
control over sites for new generation development does not create a 
barrier to entry.\21\
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    \19\ Id. at 7.
    \20\ Id.
    \21\ Id. at 8.
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    14. American Wind therefore requests that the Commission grant 
rehearing of the term ``sites for new generation capacity development'' 
so as to only require reporting for sites for new

[[Page 30927]]

generation capacity development that are located in load pockets where 
a ``potential'' for vertical market power may exist. American Wind 
argues that for the purposes of this reporting requirement, the 
Commission could define load pockets as submarkets where the Commission 
has determined that internal transmission constraints make the market 
smaller than the balancing authority area, RTO/ISO footprint or RTO/ISO 
submarket.\22\
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    \22\ Id. at 9.
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    15. If the Commission declines to grant its request to only require 
reporting for sites for new generation development that are located in 
load pockets where a ``potential'' for vertical market power may exist, 
American Wind requests clarification that the Commission will only 
require reporting for sites for new generation capacity development 
when ``site control'' is first required to be demonstrated in the 
interconnection process.\23\ American Wind claims that sites that have 
not yet been required to demonstrate site control in the 
interconnection process would not likely be used to enhance a seller's 
vertical market power, and accordingly, there is no need for the 
Commission to be notified of such sites prior to when ``site control'' 
is required to be demonstrated. American Wind argues that using this 
milestone as the triggering point for when a seller must notify the 
Commission of sites for new generation capacity development ``would 
better align the reporting requirement with the underlying vertical 
market power concerns that are at the heart of the requirement'' and 
``would strike a better balance between the Commission's regulatory 
concerns and the compliance burden on and competitive risks to market-
based rate sellers.'' \24\
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    \23\ Id. at 11.
    \24\ Id.
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Commission Determination
    16. We will deny American Wind's request for rehearing of the 
definition of ``inputs to electric power production'' so that it 
requires only reporting for sites for new generation capacity 
development that are located in load pockets where a ``potential'' for 
vertical market power may exist. Such a revision to the requirement is 
too narrowly focused and therefore would not allow the Commission to 
timely monitor for potential barriers to entry or affiliate abuse 
involving generation sites. Since load pockets typically exist in areas 
(e.g., population centers) that are not well-suited for the development 
of renewable generation sources (e.g., large wind farms requiring 
thousands of acres of land),\25\ limiting the reporting of sites for 
new generation development to just load pockets would mean that the 
Commission would not be informed of most instances where land was being 
acquired for the development of new renewable generation capacity.
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    \25\ See id. at 6 (stating that ``in developing a 100 MW project 
using 1.5 MW wind turbines (approximately 65 turbines), a developer 
may seek to initially have under control 10,000 acres of land.'').
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    17. With respect to American Wind's alternative request that the 
Commission only require reporting for sites for new generation capacity 
development when site control is first required to be demonstrated in 
the interconnection process, we believe this approach has merit, as 
modified below. Modifications are necessary because it is not clear 
that American Wind's request would address both its concerns about the 
disclosure of commercially sensitive information and the Commission's 
regulatory concerns regarding a seller's ability to erect barriers to 
entry through its acquisition of sites for new generation capacity 
development. First, the information provided in an interconnection 
request, including the demonstration of site control, is not required 
to be public.\26\ Second, transmission providers post the location of 
interconnection requests on OASIS by county and State, but do not post 
the identity of the interconnection customer when the interconnection 
request is made ``because disclosing the identity at that early stage 
may put the Interconnection Customer at a competitive disadvantage and 
its project at risk.'' \27\ Thus, the American Wind alternative 
approach would require the seller to report information that in the 
interconnection process may be considered non-public and proprietary. 
While American Wind's concerns about the disclosure of commercially 
sensitive information could be addressed by allowing sellers to file 
site information with the Commission confidentially, we do not believe 
that it is appropriate to routinely permit change in status reports to 
be filed at the Commission as non-public documents. One of the purposes 
of the change of status reporting requirement is to provide interested 
parties the opportunity to intervene and comment if they believe the 
seller's acquisition of sites for new generation capacity development 
creates a barrier to entry, which could be undermined if such reports 
were routinely filed with confidential information redacted.\28\
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    \26\ Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, at P 270 
(2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 
31,160, order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 
31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. 
] 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. 
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007).
    \27\ Id. P 114.
    \28\ See Order No. 697, FERC Stats. & Regs. ] 31,252 at P 446; 
1018 (explaining that the Commission will allow intervenors to rebut 
the presumption that a seller's ownership of, control of or 
affiliation with entities that own or control inputs to electric 
power production do not allow a seller to raise entry barriers).
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    18. Accordingly, in order to address our regulatory concerns and 
the concerns of American Wind, we grant rehearing and revise section 
35.42 of our regulations to require, for all entities with market-based 
rate authorization, quarterly reporting of a seller's acquisition of a 
site or sites for new generation capacity development for which site 
control has been demonstrated in the interconnection process and for 
which the potential number of megawatts that are reasonably 
commercially feasible on the site or sites for new generation capacity 
development is equal to 100 megawatts or more. For the purposes of this 
reporting requirement, we will use the definition of ``site control'' 
that is provided in section 1 of the Standard Large Generator 
Interconnection Procedures (LGIP).\29\ To the extent that a seller 
elects to make a monetary deposit so that it may demonstrate site 
control at a later time in the interconnection process,\30\ such 
deposit will trigger this quarterly reporting requirement instead of 
the demonstration of site control if the

[[Page 30928]]

potential number of megawatts that are reasonably commercially feasible 
on the site or sites for new generation capacity development is equal 
to 100 megawatts or more.\31\ All market-based rate sellers will be 
required to report the acquisition of control of sites for new 
generation capacity development on a quarterly basis instead of within 
30 days of the acquisition.\32\ Such quarterly filings must be 
submitted within 30 days after the end of each quarter, e.g., by April 
30 for the first quarter. Thus, the time period in which sellers are 
required to report the acquisition of control of sites for new 
generation capacity development is being extended, which will ease some 
of the administrative burden about which American Wind has raised 
concerns. For all changes in status other than the acquisition of 
control of sites for new generation capacity development, all sellers 
will still be required to file a change in status report no later than 
30 days after the change in status occurs.\33\
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    \29\ Section 1 of the LGIP adopted in Order No. 2003 defines 
``site control'' as ``documentation reasonably demonstrating: (1) 
Ownership of, a leasehold interest in, or a right to develop a site 
for the purpose of constructing the Generating Facility; (2) an 
option to purchase or acquire a leasehold site for such purpose; or 
(3) an exclusivity or other business relationship between 
Interconnection Customer and the entity having the right to sell, 
lease or grant Interconnection Customer the right to possess or 
occupy a site for such purpose.'' Order No. 2003, FERC Stats. & 
Regs. ] 31,146, LGIP Sec.  1. The same requirements apply to small 
generators and wind generating facilities. See Order No. 2006, FERC 
Stats. & Regs. ] 31,180, Small Generator Interconnection Procedures 
Sec.  1.5; Interconnection for Wind Energy, Order No. 661, FERC 
Stats. & Regs. ] 31,186, order on reh'g, Order No. 661-A, FERC 
Stats. & Regs. ] 31,198 (2005).
    \30\ See LGIP Sec.  3.3.1 (stating that ``[t]o initiate an 
Interconnection Request, Interconnection Customer must submit all of 
the following: (i) a $10,000 deposit, (ii) a completed application 
in the form of Appendix 1, and (iii) demonstration of Site Control 
or a posting of an additional deposit of $10,000. Such deposits 
shall be applied toward any Interconnection Studies pursuant to the 
Interconnection Request. If Interconnection Customer demonstrates 
Site Control within the cure period specified in Section 3.3.3 after 
submitting its Interconnection Request, the additional deposit shall 
be refundable; otherwise, all such deposit(s), additional and 
initial, become non-refundable.'').
    \31\ We note that if a term other than ``site control'' is used 
to describe the specific means by which site control is demonstrated 
in the interconnection process, then the reporting requirement will 
be triggered when a demonstration of site control is made under that 
term. For example, ``site exclusivity'' is considered as the 
specific means by which site control is determined in the California 
Independent System Operator's (CAISO's) Generator Interconnection 
Process Reform tariff amendment. See California Independent System 
Operator Corp., 124 FERC ] 61,292, at P 40-41, 63 (2008). Therefore, 
the demonstration of ``site exclusivity'' in the interconnection 
process set forth in the CAISO's Generator Interconnection Process 
Reform tariff amendment will trigger the quarterly requirement to 
report a seller's acquisition of control of a site or sites for new 
generation capacity development.
    \32\ In this context, ``control'' refers to ``site control'' as 
it is defined in the LGIP, or as explained in footnote 31.
    \33\ A change in status includes, but is not limited to, the 
following: Ownership or control of generation capacity that results 
in net increases of 100 MW or more, or of inputs to electric power 
production, or ownership, operation or control of transmission 
facilities, or affiliation with any entity not disclosed in the 
application for market-based rate authority that owns or controls 
generation facilities or inputs to electric power production or that 
owns, operates or controls transmission facilities, or affiliation 
with any entity that has a franchised service area. See 18 CFR 
35.42.
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    19. The quarterly reports that entities will be submitting to 
report the acquisition of control of a site or sites for new generation 
capacity development must include: (a) The number of sites acquired; 
(b) the relevant geographic market in which the sites are located; \34\ 
and (c) the maximum potential number of megawatts that are reasonably 
commercially feasible on the sites reported, which must be 
justified.\35\ The information regarding the maximum potential number 
of megawatts for the sites may be reported on an aggregate basis for 
each relevant geographic market(s) in which the site(s) are located, 
i.e., without providing the specific location of particular sites. 
Sellers must provide a justification for the number of megawatts that 
they estimate could be developed on the site or sites. Such 
justification must be based on the maximum potential number of 
megawatts that could be produced on the site with the technology for 
which the site was acquired. Sellers must be forthright in estimating 
and reporting the maximum potential number of megawatts that are 
reasonably commercially feasible on the site or sites for new 
generation capacity development. The Commission will use all of this 
reported information to identify sellers that may be erecting barriers 
to entry. We will revise section 35.42 of our regulations to reflect 
this site acquisition change to the change in status reporting 
requirement.
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    \34\ The relevant geographic markets include those defined in 
Order No. 697 and those defined in subsequent Commission orders. 
Order No. 697, FERC Stats. & Regs. ] 31,252 at P 231-32, 237.
    \35\ We note that if a site is later expanded to allow for 
additional generation capacity development and such expansion 
results in an increase of 100 megawatts or more, a seller will be 
required to file a notification of change in status to notify the 
Commission of such a change within 30 days after the end of that 
quarter.
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    20. Separate and apart from the above reporting requirement, and in 
order to address our concern that Sellers may acquire land that is not 
used for the development of new generation capacity, and that is 
instead acquired for the purpose of preventing new generation capacity 
from being developed on that land, a Seller must also report any land 
it has acquired, taken a leasehold interest in, obtained an option to 
purchase or lease, or entered into an exclusivity or other arrangement 
to acquire for the purpose of developing a generation site and for 
which site control has not yet been demonstrated (as discussed above) 
during the prior three years (triggering event), and for which the 
potential number of megawatts that are reasonably commercially feasible 
on the land for new generation capacity development is equal to 100 
megawatts or more. A Seller must report each such triggering event in a 
single report by January 1 of the year following the calendar year in 
which the triggering event occurred. Thus, for example, if a Seller 
acquires land for new generation capacity development in January 2009, 
and additional land in March 2009 and it has not demonstrated site 
control for generation projects on that land (as described above) as of 
January and March 2012, respectively, then such Seller must file a 
change in status report notifying the Commission of both acquisitions 
by January 1, 2013. The information that must be provided and the 
aggregation of the maximum potential number of megawatts by relevant 
geographic market is the same as required in the quarterly reports, as 
described above. We will revise section 35.42 of our regulations to 
reflect this additional change to the change in status reporting 
requirement.
    21. Finally, for acquired, leased or optioned land lacking site 
control that have already been held for three years or more prior to 
the effective date of this order, a Seller must report the required 
information by January 1, 2010, unless this information has been 
previously provided to the Commission.
    22. We believe that our revision to this requirement strikes a 
balance by addressing American Wind's concern regarding the burden of 
the existing requirement and its concern that commercially sensitive 
information about sites for wind generation development will be made 
public, and by also providing the Commission with the information 
necessary to evaluate a seller's ability to erect barriers to entry. In 
particular, permitting the information on sites for new generation 
capacity development to be provided on an aggregate basis for each 
relevant geographic market reduces any potential competitive harm that 
could result from reporting the location of the sites (since reporting 
will be on an aggregate basis), and also enables the Commission, which 
evaluates vertical market power by examining the relevant geographic 
market in which a seller is located, to obtain the information it needs 
to evaluate a seller's ability to exercise market power in a particular 
relevant geographic market. Requiring quarterly (and yearly, as 
necessary) reporting of sites acquired for new generation capacity 
development also reduces the administrative burden on sellers, which 
previously were required to report the acquisition of sites within 30 
days of the acquisition. In addition, requiring reporting on a 
quarterly basis (and yearly, as necessary) will likely reduce any 
potential competitive harm that could result from the disclosure of the 
nominal information regarding the location of the site or sites for new 
generation capacity development. Further, in their applications for 
market-based rate authority and their updated market power analyses, 
sellers are obligated to make an affirmative statement that they have 
not erected barriers to entry into the relevant market and will not 
erect barriers to entry into

[[Page 30929]]

the relevant market. This continuing obligation provides assurance to 
the Commission that a seller is not erecting barriers to entry.\36\
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    \36\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 447.
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B. Mitigation

Protecting Mitigated Markets
Sales at the Metered Boundary
Background
    23. In Order No. 697, the Commission stated that it would continue 
to apply mitigation to all sales in the balancing authority area in 
which a seller is found, or presumed, to have market power. However, 
the Commission said it would allow mitigated sellers to make market-
based rate sales at the metered boundary between a balancing authority 
area in which a seller is found, or presumed, to have market power and 
a balancing authority area in which the seller has market-based rate 
authority, under certain circumstances.\37\ The Commission also adopted 
a requirement that mitigated sellers wishing to make market-based rate 
sales at the metered boundary between a balancing authority area in 
which the seller was found, or presumed, to have market power and a 
balancing authority area in which the seller has market-based rate 
authority maintain sufficient documentation and use a specific tariff 
provision for such sales.\38\
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    \37\ Id. P 817 (citing North American Electric Reliability 
Corporation, Glossary of Terms Used in Reliability Standards at 2 
(2007), available at ftp://www.nerc.com/pub/sys/all_updl/standards/rs/Glossary_02May07.pdf)).
    \38\ Id. P 830.
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    24. On rehearing in Order No. 697-A, the Commission revised the 
tariff language governing market-based rate sales at the metered 
boundary to conform with the discussion in the December 14 
Clarification Order regarding use of the term ``mitigated market.'' The 
Commission stated that, as explained in the December 14 Clarification 
Order, ``balancing authority area in which a seller is found, or 
presumed, to have market power'' is a more accurate way to describe the 
area in which a seller is mitigated.\39\
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    \39\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 333.
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    25. In addition, after considering comments regarding the 
difficulty of determining and documenting intent, the Commission 
decided in Order No. 697-A to eliminate the intent element of the 
tariff provision, which stated that ``any power sold hereunder is not 
intended to serve load in the seller's mitigated market.'' Because the 
Commission eliminated the seller's intent requirement, it modified the 
tariff provision to require that ``the mitigated seller and its 
affiliates do not sell the same power back into the balancing authority 
area where the seller is mitigated.'' \40\ In this regard, the 
Commission noted that ``[t]o provide additional regulatory certainty 
for mitigated sellers, the Commission clarified that once the power has 
been sold at the metered boundary at market-based rates, the mitigated 
seller and its affiliates may not sell that same power back into the 
mitigated balancing authority area, whether at cost-based or market-
based rates.'' \41\ The Commission also stated that because it was 
eliminating the intent requirement, it need not address issues raised 
regarding documentation necessary to demonstrate the mitigated seller's 
intent.
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    \40\ Id. P 334.
    \41\ Id. n.464.
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    26. Further, in response to a request for clarification submitted 
by the Pinnacle West Companies (Pinnacle), the Commission also 
clarified in Order No. 697-A that mitigated sellers and their 
affiliates are prohibited from selling power at market-based rates in 
the balancing authority area in which a seller is found, or presumed, 
to have market power.\42\ Accordingly, the Commission clarified that an 
affiliate of a mitigated seller is prohibited from selling power that 
was purchased at a market-based rate at the metered boundary back into 
the balancing authority area in which the seller has been found, or 
presumed, to have market power. The Commission stated that to the 
extent that the mitigated seller or its affiliates believe that it is 
not practical to track such power, they can either choose to make no 
market-based rate sales at the metered boundary or limit such sales to 
sales to end users of the power, thereby eliminating the danger that 
they will violate their tariff by re-selling the power back into a 
balancing authority in which they are mitigated.\43\
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    \42\ Id. P 335.
    \43\ Id. P 336.
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    27. In Order No. 697-B, in response to the rehearing request of 
E.ON U.S. LLC (E.ON), the Commission explained that it appreciated 
concerns regarding the difficulty of defining the term ``same power.'' 
For this reason, the Commission revised the tariff provision for 
market-based rate sales at the metered boundary, which included 
revising the provision stating that the ``Seller and its affiliates do 
not sell the same power back into the balancing authority area where 
the seller is mitigated,'' to state that ``if the Seller wants to sell 
at the metered boundary of a mitigated balancing authority area at 
market-based rates, then neither it nor its affiliates can sell into 
that mitigated balancing authority area from the outside.'' The 
Commission noted that this revised tariff language will prevent a 
mitigated seller making market-based rate sales at the metered boundary 
from selling power into the mitigated market through its affiliates. It 
also explained that sellers may choose to make no market-based rate 
sales at the metered boundary, or to limit such sales to end users of 
the power, thereby eliminating the danger they will violate their 
tariff by re-selling power back into a balancing authority in which 
they are mitigated.\44\
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    \44\ Order No. 697-B, FERC Stats. & Regs. ] 31,285 at P 77 
(citing Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 336).
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Requests for Rehearing
    28. On rehearing of Order No. 697-B, E.ON again takes issue with 
the mitigated sales tariff provision, arguing that the Commission erred 
in revising the mitigated sales tariff provision in Order No. 697-B. 
E.ON contends that the revised tariff provision is overbroad and 
prohibits legitimate transactions. It argues that the tariff provision 
should be revised to state that ``(ii) if the Seller sells at the 
metered boundary of a mitigated balancing authority area at market-
based rates, then neither it nor its affiliates can sell into that 
mitigated balancing authority area from the outside at the same border 
for delivery at the same time except pursuant to long-term (one-year or 
longer) agreements or as a result of changed circumstances.'' \45\ E.ON 
argues that, as revised in Order No. 697-B, the tariff provision 
governing mitigated sales does not expressly state that a border sale 
need actually occur. E.ON suggests that the Commission should change 
the words ``wants to sell'' to ``sells'' to eliminate any risk of 
misinterpretation. In support of its proposal, E.ON argues that the 
mitigated sales tariff provision should contain a ``temporal 
limitation'' so that it cannot be read to prohibit a mitigated seller 
or its affiliates from ever selling from the outside into the mitigated 
balancing authority area. E.ON believes that the Commission intended 
only to stop the ``looping'' of power in a manner that circumvents the 
mitigation imposed on an entity.\46\
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    \45\ E.ON January 21, 2009 Rehearing Request at 3, 5.
    \46\ Id. at 8.
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    29. E.ON also argues that the mitigated sales tariff provision 
should contain an exemption for retail or

[[Page 30930]]

wholesale cost-based requirements contracts into the mitigated 
balancing authority area from the outside so that long-term purchases 
from outside a mitigated market used to serve retail or cost-based 
wholesale requirements customers do not restrict the ability of a 
mitigated seller from making a spot ``outbound'' border sale. According 
to E.ON, failure to modify the condition in this manner would severely 
restrict the ability of its public utility subsidiaries Louisville Gas 
and Electric Company and Kentucky Utilities Company to make truly 
``outbound'' off-system sales at the border of their control area, 
leading to higher prices.\47\ E.ON also proposes adding language to the 
condition so as to carve out long-term agreements of one-year or more 
in duration that provide for the sale of power into the mitigated 
market from the outside. E.ON contends that as revised in Order No. 
697-B, the mitigated sales tariff provision could prohibit transactions 
necessitated by reserve sharing agreements or changed operational 
circumstances, and could have a chilling effect on forward contracting 
by forcing mitigated sellers to only transact in real time because of 
their concerns that they may guess wrong and need to buy power at the 
last minute if they are short, or sell power at the last minute if 
called upon under a reserve sharing agreement.\48\ In addition, E.ON 
asserts that the revised mitigated sales tariff provision could 
prohibit opportunity purchases by utilities that seek to reduce the 
costs of serving load.\49\
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    \47\ Id. at 10.
    \48\ Id. at 12.
    \49\ Id. at 13.
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    30. Pinnacle, too, seeks further revision to the mitigated sales 
tariff provision and argues that the Commission erred in linking all 
market-based rate sales made at the metered boundary to all incoming 
sales into a mitigated balancing authority area. Pinnacle requests that 
the Commission clarify that making a border sale does not prohibit all 
future sales of a mitigated seller or its affiliates from entering the 
mitigated balancing authority area. It states that, at a minimum, the 
Commission should clarify that it does not intend for the revised 
provision to capture cost-based sales into or out of a mitigated 
balancing authority area.\50\ Pinnacle states that if the revised 
provision is interpreted to prohibit any subsequent sales of a 
mitigated seller or its affiliates from entering the mitigated 
balancing authority area, this would completely preclude the mitigated 
seller from selling into the mitigated balancing authority area. Such a 
result, Pinnacle contends, could endanger the stability of the Phoenix 
Valley Load Pocket in the event of an emergency,\51\ and could result 
in Pinnacle violating its must-offer requirements. Specifically, 
Pinnacle states that if it is not permitted to make sales into the 
mitigated balancing authority area, or is effectively prohibited from 
making sales at border points, its posting of available capacity will 
be less effective for the Southwest in that Pinnacle would have to 
withhold available generation due to its inability to make sales in 
certain areas.\52\
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    \50\ Pinnacle January 21, 2009 Rehearing Request at 5.
    \51\ Id. at 3-4.
    \52\ Id. at 4.
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    31. MidAmerican Energy Company (MidAmerican) and American Electric 
Power Service Corporation (AEP) also seek rehearing of the mitigated 
sales tariff provision as revised in Order No. 697-B. These petitioners 
argue that the Commission erred in adopting an overly broad mitigation 
provision that could restrict legitimate transactions. They contend 
that under the tariff provision adopted in Order No. 697-B, mitigated 
utilities are presented with three alternatives, each of which 
``unnecessarily and unfairly'' disadvantages their customers: (i) 
Decline to make market-based rate sales and thereby forego revenues 
used to reduce system costs; (ii) decline to import power from ``the 
outside'' and thereby forego least-cost resources that could be used to 
reliably serve load and make sales within the mitigated market; or 
(iii) make sales to customers within the mitigated market at prices 
that may not recover incremental costs, thereby unfairly subsidizing 
those transactions.\53\ MidAmerican and AEP therefore assert that the 
Commission should rescind Order No. 697-B's revision and revert to the 
mitigated sales tariff provision adopted in Order No. 697. According to 
these petitioners, the tariff provision adopted in Order No. 697 
captures transactions purposefully structured to evade mitigation while 
permitting utilities to continue to engage in legitimate transactions 
from the ``outside,'' even when energy scheduled under those 
transactions subsequently is reflected in the price for opportunity 
sales made within the balancing authority area.\54\
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    \53\ MidAmerican January 21, 2009 Rehearing Request at 6.
    \54\ Id. at 7-8.
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    32. MidAmerican and AEP argue that if the Commission declines to 
grant rehearing, it should clarify that the mitigated sales tariff 
provision applies only to short-term purchases made from the 
``outside'' by the mitigated seller and not to deliveries scheduled 
from the mitigated seller's own generation originating ``outside'' the 
mitigated balancing authority area or from long-term capacity contracts 
entered into to meet load requirements. These petitioners contend that 
these arrangements ``do not involve the Commission's ricochet concern 
and should not be swept within the Order No. 697-B mitigation 
provision.'' \55\
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    \55\ Id. at 8.
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    33. Xcel Energy Services Inc. (Xcel) requests clarification that 
the prohibition on sales into the mitigated balancing authority area 
does not prevent a mitigated seller from engaging in a purchase of 
economy power from outside the mitigated balancing authority area in 
order to lower costs for serving native load. It argues that mitigated 
sellers that make sales of power at border locations may have 
opportunities to enter into legitimate economy purchases outside the 
balancing authority area that would serve to lower overall generation 
costs to their native load customers. Xcel contends that one mitigation 
option is to ``track the power from a border sale with the possibility 
of retroactive re-pricing.'' \56\
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    \56\ Xcel January 21, 2009 Request for Clarification at 7.
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    34. Xcel requests clarification that mitigated sellers are only 
prohibited from making sales into a mitigated balancing authority area 
if the seller is simultaneously engaged in a sale at the metered 
boundary.\57\ In support of this request, Xcel argues that during 
periods when the seller is not making sales at the border of its 
mitigated balancing authority area, there would be no way for the 
seller or its affiliates to benefit from their market power in the 
mitigated balancing authority area through a sale that originates 
outside of that mitigated balancing authority area.\58\ Xcel therefore 
asks for clarification that it is permitted to enter into a sale at a 
delivery point located outside of the mitigated balancing authority 
area to a counterparty within the balancing authority area.
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    \57\ Id. at 5.
    \58\ Id. at 8.
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    35. The Edison Electric Institute (EEI) likewise seeks rehearing of 
the mitigated sales tariff provision as set forth in Order No. 697-
B.\59\ EEI contends that

[[Page 30931]]

the revised provision will unnecessarily constrain sales by mitigated 
sellers and their affiliates to the detriment of customers in all 
markets. EEI argues that as revised in Order No. 697-B, the mitigated 
sales tariff provision could be interpreted to prohibit all sales by 
mitigated sellers and their affiliates into a mitigated market from the 
outside if the sellers opt to engage in one or more metered boundary 
sales. EEI asserts that this interpretation would completely exclude 
all sales into the mitigated balancing authority area by a mitigated 
seller and its affiliates, removing these sellers from the marketplace 
and exacerbating any potential imbalance of market power in the 
mitigated balancing authority area.\60\ EEI contends that the revised 
tariff language could be interpreted to violate certain must-offer and 
load-following requirements.
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    \59\ We note that EEI's request for rehearing of the mitigated 
sales tariff provision is out-of-time insofar as EEI did not raise 
issues concerning mitigated sales at the metered boundary on 
rehearing of Order Nos. 697 and 697-A and appears to be an attempt 
to re-litigate the determinations made by the Commission in those 
orders.
    \60\ EEI January 22, 2009 Corrected Rehearing Request at 5-6.
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    36. EEI argues that the Commission should return to the intent-
based concept adopted in Order No. 697, while also identifying five 
types of transactions that would be permitted without first needing to 
demonstrate intent even if a mitigated seller does engage in market-
based rate sales at the metered boundary.\61\ EEI asserts that the 
following five types of transactions should be permitted without first 
needing to demonstrate intent, even if a mitigated seller does engage 
in market-based rate border sales: (1) Sales at ``liquid trading hubs'' 
or into ISO and RTO markets outside of the seller's mitigated market; 
(2) cost-based sales in which title transfers within the mitigated 
market (whether they are sourced and sunk in the mitigated market, are 
sourced ``into'' the mitigated market from the outside by the seller or 
its affiliates, or are wheeled ``out of'' the mitigated market by a 
purchaser); (3) sales to load-serving entities such as investor-owned 
utilities, municipalities, and cooperatives that serve retail load 
outside the mitigated market, even if those entities may at times need 
to sell power back into the mitigated market if their supply is too 
great (since the timing and occurrence of such excess-power sales back 
into the mitigated market will be beyond the control of the mitigated 
seller); (4) other types of transactions that are independent of the 
border sales, such as sales of blocks of power to be delivered at dates 
and times other than the border sale block of power, power made 
available under must-offer requirements, and load-following power; and 
(5) to bolster reliability, the Commission should clarify that the 
border sale constraints do not require a mitigated seller or its 
affiliates, which otherwise would be precluded from selling power into 
the mitigated area from the outside, to withhold making those sales 
during times at which the seller or affiliates are called on to act to 
maintain system reliability. EEI argues that at a minimum, the 
Commission should clarify that the border sales constraints will not 
prevent emergency sales, sales that are required to maintain reserve 
levels or to comply with system redispatch obligations, or sales that 
are otherwise authorized by the Commission either generically or case-
by-case.\62\
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    \61\ Id. at 3.
    \62\ Id. at 8-9.
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    37. EEI also includes an expedited motion for partial stay in its 
rehearing request in which it asks that the Commission stay the 
effectiveness of the border sales constraints set forth in Order Nos. 
697, 697-A and 697-B until at least 30 days after the Commission has 
acted on the merits of EEI's request for rehearing.\63\
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    \63\ Id. at 9.
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    38. Separately, Tampa Electric submitted a motion for an extension 
of time to comply with the revised mitigated sales tariff provision set 
forth in Order No. 697-B. Tampa Electric requests that the Commission 
defer the effective date of the modified language governing mitigated 
sales at the metered boundary pending Commission action on requests for 
rehearing of Order No. 697-B on this issue.\64\ Tampa Electric also 
states that it supports EEI's request for rehearing.
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    \64\ In its request for an extension of time to comply with the 
revised mitigated sales tariff provision, Tampa Electric states that 
it supports EEI's request for rehearing. On January 28, 2009, the 
Commission issued an order granting Tampa Electric's request for an 
extension of time to comply with the tariff provision on mitigated 
sales at the metered boundary as revised in Order No. 697-B until 
such time as the Commission issues an order on rehearing of Order 
No. 697-B. Order Granting Extension of Time to Comply, 126 FERC ] 
61,072; see supra P 6.
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    39. On January 27, 2009, the National Rural Electric Cooperative 
Association (NRECA) and the American Public Power Association (APPA) 
filed an answer in response to EEI's motion for partial stay. NRECA and 
APPA argue that EEI's motion for partial stay should be denied because 
EEI does not demonstrate that a stay is appropriate. They argue that 
EEI does not specify any irreparable injury that EEI or its member 
companies will suffer absent a stay, does not address whether the 
requested stay would substantially harm other parties, and does not 
show that the stay is in the public interest. They point out that EEI's 
request for rehearing is the third time in this proceeding that sellers 
have requested the Commission to modify the restrictions on market-
based sale at the metered boundaries of mitigated balancing authority 
areas.\65\ NRECA and APPA also argue that ending all restrictions on 
market based rate sales at the metered boundary of balancing authority 
areas in which a seller is mitigated, even temporarily, would harm 
wholesale markets and customers.\66\
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    \65\ NRECA and APPA January 27, 2009 Answer at 1-2.
    \66\ Id. at 3-4.
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Commission Determination
Procedural Issues
    40. We find that EEI does not provide the required justification 
for a stay of the mitigated sales tariff provision. Under section 705 
of the Administrative Procedure Act (APA), the Commission may stay its 
action when it finds that ``justice so requires.'' \67\ In addressing 
motions for stay, the Commission considers: (1) Whether the moving 
party will suffer irreparable injury without a stay; (2) whether 
issuing a stay will substantially harm other parties; and (3) whether a 
stay is in the public interest.\68\ The Commission's general policy is 
to refrain from granting a stay of its orders, to assure definiteness 
and finality in Commission proceedings.\69\ The key element in the 
inquiry is irreparable injury to the moving party.\70\ If a party is 
unable to demonstrate that it will suffer irreparable harm absent a 
stay, we need not examine the other factors.\71\ However, the 
Commission may examine the other factors where appropriate.\72\
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    \67\ 5 U.S.C. 705 (2006).
    \68\ Pinnacle West Capital Corp., 115 FERC ] 61,064, at P 8 
(2006) (citing CMS Midland, Inc., Midland Cogeneration Venture 
Limited Partnership, 56 FERC ] 61,177, at 61,361 (1991), aff'd sub 
nom. Michigan Municipal Cooperative Group v. FERC, 990 F.2d 1377 
(D.C. Cir. 1993), cert. denied, 510 U.S. 990 (1993)).
    \69\ Id.
    \70\ Id.
    \71\ CMS Midland, Inc., Midland Cogeneration Venture Limited 
Partnership, Midland Cogeneration Venture Limited Partnership, 56 
FERC ] 61,177, at 61,631 (1991) (footnote omitted).
    \72\ Pinnacle West Capital Corp., 115 FERC ] 61,064, at P 8 
(2006) (citing The Montana Power Company, Confederated Salish and 
Kootenai Tribes of the Flathead Reservation, 85 FERC ] 61,400, at 
62,535 (1998)).
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    41. EEI's request for stay does not address whether it will suffer 
irreparable injury without a stay of the mitigated sales tariff 
provision, and also does not address whether issuing a stay

[[Page 30932]]

will substantially harm other parties or whether a stay is in the 
public interest. Rather, EEI's request for stay consists only of the 
following statement: ``[g]iven the serious, negative potential effects 
of the border sales related constraints set out in Orders No. 697, 697-
A, and 697-B on market participants and customers in mitigated and non-
mitigated markets, EEI requests that the Commission stay the 
effectiveness of those constraints until at least 30 days after the 
Commission has acted on the merits of EEI's request for rehearing.'' 
\73\ This claim is too broad and speculative to justify the granting of 
injunctive relief.\74\ We also note that EEI did not raise issues 
concerning mitigated sales at the metered boundary on rehearing of 
Order Nos. 697 and 697-A. Because EEI fails to provide the required 
justification for a stay of the mitigated sales tariff provision, EEI's 
motion for a partial stay is denied.\75\
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    \73\ EEI January 21, 2009 Rehearing Request at 9.
    \74\ In Wisconsin Gas v. FERC, 758 F.2d 669, 674 (D.C. Cir. 
1985) the court stated that, to meet the irreparable injury test for 
granting a stay:
    ``First, the injury must be both certain and great; it must be 
actual and not theoretical. Injunctive relief ``will not be granted 
against something merely feared as liable to occur at some 
indefinite time,'' Connecticut v. Massachusetts, 282 U.S. 660, 674, 
75 L. Ed. 602, 51 S. Ct. 286 (1931); the party seeking injunctive 
relief must show that ``the injury complained of [is] of such 
imminence that there is a `clear and present' need for equitable 
relief to prevent irreparable harm.'' Ashland Oil, Inc. v. FTC, 409 
F. Supp. 297, 307 (D.D.C.), aff'd, 179 U.S. App. D.C. 22, 548 F.2d 
977 (D.C. Cir. 1976) (citations and internal quotations omitted).''
    \75\ In granting Tampa Electric's request for extension of time 
to comply with the tariff provision on mitigated sales at the 
metered boundary as revised in Order No. 697-B, the Commission 
clarified that affected entities must continue to comply with the 
mitigated sales tariff provision adopted in Order No. 697-A until 
such time as the Commission acts on the requests for rehearing of 
Order No. 697-B. Order Granting Extension of Time to Comply, 126 
FE