UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Uplift Allocation and Transparency in Markets
Operated by Regional Transmission
Organizations and Independent System Operators
)
)
)
Docket No. RM17-2-000
PJM INTERCONNECTION, L.L.C.
COMMENTS TO NOTICE OF PROPOSED RULEMAKING
Pursuant to the Federal Energy Regulatory Commission’s (“Commission”) Notice of
Proposed Rulemaking issued in the above-referenced proceeding on January 19, 2017
(“NOPR”), PJM Interconnection, L.L.C. (“PJM”) hereby submits the following comments.
I.
INTRODUCTION
The NOPR is the fifth of the Commission’s notices of proposed rulemakings arising out
of its proceeding in Docket No. AD14-14-000 addressing price formation in markets operated by
Regional Transmission Organizations and Independent System Operators (collectively,
“RTOs/ISOs”).1 To date, PJM has generally supported the Commission’s initiatives in the Price
Formation Proceeding, and indeed believes that many of the steps taken by the Commission will
improve price transparency across all RTOs/ISOs.
Moreover, PJM generally supports the
NOPR’s goal of increasing transparency in the reporting of uplift in RTOs/ISOs.2 However,
PJM believes the proposed rules regarding uplift allocation attempt to distribute uplift in a more
surgical manner than a “cost causality” methodology is capable of accomplishing. In PJM’s
view, the Commission’s proposed rules do not actually achieve the goal of allocating uplift based
on cost causation because such a goal is unachievable at the level of granularity proposed by the
Commission. In this sense, and as explained below, the premise of the NOPR that uplift can be
1
Hereinafter, the “Price Formation Proceeding.”
2
See e.g. NOPR at P 3.
allocated to deviations that cause uplift and that “helpful” versus “harmful” actions3 can be easily
identified and incentivized through cost allocation does not recognize the intertwined and
complex nature of uplift, which makes the identification of the specific cause of costs elusive and
ultimately impossible.
For these reasons and the reasons outlined in more detail below, PJM believes the
Commission’s proposed uplift allocation methodology will add significant complexity and
arbitrariness while moving no closer to the Commission’s intended goal of allocating uplift
based on cost causation principles.4
Rather than mandating this new uplift allocation
methodology, the Commission should continue to focus its efforts on minimizing the total
amount of uplift, as this goal provides a far more substantial benefit to all market participants.
The Commission has attempted to do this through the reforms it proposed in its recent “FastStart Pricing NOPR,”5 for which PJM was largely supportive.6 Accordingly, PJM urges the
Commission to alter its approach to this NOPR to largely move forward with its transparencyrelated provisions while declining to mandate its proposed cost allocation methodology.
II.
UPLIFT ALLOCATION
A.
The NOPR Incorrectly Assumes Allocation of Uplift Can Be Used to Influence
Specific Market Behavior
The NOPR states that “[a]t the highest level, the allocation of uplift costs should, to the
extent possible, encourage behavior that will reduce the need for uplift-creating actions and
avoid discouraging market participant behavior that lowers total production costs (i.e., enhances
3
See e.g. id. at P 14.
4
See e.g. id. at P 4.
5
See Fast-Start Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators,
Notice of Proposed Rulemaking, 157 FERC ¶ 61, 213 (2016).
6
See generally PJM Interconnection, L.L.C., Comments to Notice of Proposed Rulemaking, Docket No. RM17-3-000 (Feb.
28, 2017).
2
efficiency).”7 While PJM agrees with this general statement in principle, it does not believe this
goal can be achieved.
From an RTO/ISO perspective, there is no way to determine with certainty which specific
deviations generate uplift before or after the market has cleared.8
Because this cannot be
determined with any degree of certainty, constructing an allocation methodology that
discourages such transactions is impossible. In order to achieve the Commission’s goals, a
market participant would need to know which types of transactions will cause uplift at the time
they transact in the market. However, from a market participant’s perspective, uplift is random.
Neither they, nor the RTO/ISO, can determine the amount of uplift they will be allocated until
after the market has cleared and the profits and losses of all market transactions are calculated.
Nor can the market participant or RTO/ISO determine whether a specific transaction contributed
to the creation of uplift given the complexity of the market. Accordingly, by the time a market
participant is allocated uplift, it is too late for it to take action that would have reduced uplift.
Further, the same transaction on two different days can result in different uplift allocations
because system conditions and other market participants’ behavior can change from day-to-day,
resulting in different amounts of uplift for relatively similar Operating Days.9
For these reasons, it is difficult for PJM to envision how the Commission’s proposed
uplift allocation, or any allocation methodology, can achieve the Commission’s intended goals of
apportioning uplift based on cost-causation principles or induce market participants to behave in
a manner that would result in a lower uplift allocation to them.
7
NOPR at P 2.
8
See e.g. PJM Interconnection, L.L.C., Report on Price Formation Issues, Docket No. AD14-14-000, at 28-29 (Feb. 17,
2016) (“PJM Price Formation Report”).
9
Capitalized terms used and not otherwise defined herein have the meaning set forth in the PJM Open Access Transmission
Tariff (“Tariff”) and Amended and Restated Operating Agreement of PJM Interconnection, L.L.C. (“Operating Agreement”).
3
B.
The Commission Should Not Require Uplift Allocation Based on Specific
Categories
In the NOPR, the Commission proposed to split uplift costs into at least two categories:
(1) a system-wide capacity category and (2) a congestion management category. 10 The NOPR
states that the Commission’s intention is to allocate the costs to the market participant that
caused the uplift. However, in order to achieve Commission’s intended goal, it would be
necessary to clearly define why a specific transaction is collecting uplift (i.e. capacity or
transmission) and then determine which transaction caused that uplift.
It is PJM’s opinion separation of uplift into these two categories would be an arbitrary
determination because all market transactions ultimately impact how PJM maintains power
balance and controls transmission constraints. For example, when PJM solves its Day-ahead
Energy Market or dispatches the system in real-time, the power balance constraint and
transmission constraints are solved simultaneously. This is because the transactions that resolve
transmission constraints and those that are used to balance supply and demand are the same.
Every injection or withdrawal on the power system imposes some flow on a transmission facility
that is ultimately lost through transmission system losses, consumed by load, or used to meet the
needs of interchange transactions. Segregating transactions into specific categories can only be
done subjectively, which is inconsistent with the principles of cost causation. For these reasons,
splitting uplift into the proposed categories should not be required.
C.
Ambiguities in NOPR Proposal Could Lead to Unintended Consequences.
The Commission’s proposed exemption of deviations from a day-ahead schedule caused
by a transaction following dispatch is appropriate.11 This is part of PJM’s practices today and
helps reinforce the incentive for resources to follow dispatch.
10
See NOPR at P 40.
11
See e.g. id. at P 53.
4
Importantly, the manner in which PJM determines deviations for resources that are
following dispatch instructions differs slightly from what the Commission has proposed. Today,
generation and demand response resources following PJM dispatch are assessed deviations based
on the difference between where PJM dispatched the resource and its actual output (or
consumption).
PJM employs this methodology as opposed to what the Commission has
proposed, which is the difference between actual output and the day-ahead scheduled megawatt
amount.12 Notably, under one possible reading of the Commission’s proposal, a resource could
elect to follow its day-ahead schedule in real-time and not be assessed a deviation even though
PJM dispatched the unit differently in real-time. If a resource does not follow dispatch in realtime, it requires the RTO/ISO to take counteractions to control the system that may result in
uplift being created. For this reason, PJM instituted changes in 2008 to measure deviations of
resources based on how well the resources follow real-time dispatch instructions. Requiring
PJM to remove this enhancement to how it determines deviations would dilute the incentive to
follow dispatch and increase uplift payments.
While PJM believes that no universal definition of “deviations” is required across all
RTOs/ISOs because each RTO/ISO’s system is different and subtle nuances may influence how
deviations are calculated, should the Commission proceed with a universal definition of
“deviations” in a Final Rule, PJM recommends that the Commission clarify therein that
deviations must be based in part on how well resources follow RTO/ISO dispatch instructions in
real-time, and not merely whether they operate to their day-ahead schedule.
12
See e.g. id. at P 38.
5
D.
Changing the Determination of Uplift Allocation from Daily to Hourly Will
Increase Volatility, But Will Not Provide Actionable Incentives.
PJM opposes the Commission’s proposal to require that “real-time uplift costs allocated
to deviations must be settled using hourly uplift rate calculations.”13 Currently, the rate at which
PJM charges deviations to its market participants is calculated on a daily basis, rather than an
hourly basis. PJM uses this methodology in large part because the accrual of uplift payments in
the PJM markets is based on the profits and losses for a specific transaction over a set of hours,
rather than over a single hour. For example, if PJM commits a generator to run for its Minimum
Run Time of four hours, the resource’s Market Seller will receive an uplift payment if its total
costs exceed its market revenues across the entire four hours, regardless of the profits or losses in
any one hour.
Importantly, PJM’s Members currently pay a per MWh rate for deviations over the
course of an entire Operating Day, and deviation rates are calculated separately for the eastern
and western portions of the PJM Region. Moving to twenty-four different hourly rates, as
opposed to a single daily rate, will have the inherent effect of increasing rate volatility. In a
market in which uplift payments are credited hourly, this change would align deviations with the
hourly cost of uplift. However, it will also increase the risk each Market Seller undertakes
because the volatility of the rate it pays will increase.
As noted, market participants are unable to respond directly to uplift costs until after they
are already exposed to them, and it is impossible for market participants and RTOs/ISOs to know
in advance which hours will have relatively high or low uplift costs. Therefore, in PJM’s view
the proposed increase in granularity of the rate calculation cannot be used to drive a specific
beneficial behavior, and will likely only serve as a deterrent to market participants engaging in
transactions generally given higher rate volatility.
13
See id. at P 35.
6
E.
The Commission’s Netting Proposal Will Result in a More Volatile Uplift
Allocation Which May Have Adverse Effects
PJM’s interpretation of the NOPR is that the Commission’s proposed ideal uplift
allocation would directly allocate uplift to the causal parties based on their resources’ net impact
on the market.
To achieve this goal, the Commission proposes that RTO/ISOs identify
deviations that either help or hurt “efforts to address system needs” and do so for each market
participant on a “net” basis.14 Under this proposal, each market participant’s portfolio would be
netted across each uplift category to determine their portfolio’s impact. In a second step, those
impacts would be determined to be helpful or harmful. Only those market participants with net
harmful deviations would be allocated uplift.
Generally, the more granular the allocation of uplift, the more volatile and sizeable the
allocations will become. By reducing the number of parties over which uplift is allocated, either
by attempting to implement a more causal allocation process or by allowing widespread netting
of deviations, each remaining party that receives an allocation of uplift will receive a relatively
larger share of total system uplift. This reality, combined with the fact that a market participant
cannot tell if a transaction will cause uplift at the time it is submitted, along with higher rate
volatility, will likely mean that the Commission’s proposed allocation methodology will generate
enough uncertainty in the market that it will deter even beneficial activity, and accordingly
should not be adopted.
Moreover, the Commission’s reference to “efforts to address system needs” is extremely
broad, and it is unclear to PJM as to the intended goal of identifying “helping” and “harming”
deviations.
If the “system need” is price convergence, a way to identify “helping” and
“harming” deviations could be whether the transactions associated with the deviations are
profitable. Those transactions that are profitable would aide in converging prices, while those
14
See NOPR at P 45.
7
that are unprofitable would not. Of course, here too this is not necessarily known to market
participants at the time they execute their transactions. On the other hand, if the “system need”
is minimizing uplift, it is unclear what the defining criteria would be for the reasons previously
stated.
With regard to the Commission’s request for comments on advanced notification
requirements in determining helpful deviations,15 PJM agrees with the general premise that
advance knowledge of the impact of market activity on the transmission system will always help
the RTO/ISO make better-informed, more optimal decisions concerning resource dispatch.
However, whether or not those decisions, absent that information, would have resulted in more
or less uplift is an entirely different matter that requires much more rigor than a simple
notification time threshold. Accordingly, the Commission’s proposed notification requirement is
not advisable.
F.
PJM Has Made Substantial Progress On Reducing Uplift
The Commission should be commended for its efforts to ensure better price formation
across RTOs/ISOs.
However, it should be noted that PJM has already made substantial
improvements to its market rules and operational practices to minimize the amount of uplift in its
markets. Figure 1 below shows the percentage of all of PJM Market Participants’ bills that have
been attributable to uplift, and hence unhedgeable, since 2001.
15
See id. at P 50.
8
Figure 1
As shown, in 2001 uplift accounted for 8.5% of market participant’s bills, but has
steadily decreased over time. Even in 2014, the year of the Polar Vortex in the PJM Region, and
in many ways the catalyst for the Price Formation Proceeding, uplift was less than 2% of total
customers’ bills. Importantly, in response to the cold weather events of 2014, PJM instituted
several changes to its operational practices and market design to minimize uplift, including but
not limited to:
1. real-time scheduling of long lead combustion turbine units with Day-ahead Energy Market
commitments;
2. use of closed loop pricing interfaces and thermal surrogates to set price for voltage and
stability issues;
3. increased use of analytical tools to identify uplift trends;
4. increased operator training and awareness;
5. real-time monitoring and identification of units incurring uplift; and,
9
6. changes to the way in which combustion turbine units are compensated for lost opportunity
credits.16
These steps helped enable uplift decrease to historically low amounts in 2016, in which
uplift constituted a mere 0.35% of total bills. In other words, in 2016 approximately 99.65% of
PJM total billed amounts were attributable to costs other than uplift, and thus were hedgeable.
Accordingly, PJM’s current rules have helped greatly reduce uplift compared to prior
years, and PJM’s current rules fairly and equitably allocate uplift.17
While PJM believes
improvements can still be made to its uplift allocation methodology, notably by treating Up-toCongestion transactions comparably to other Virtual Transactions,18 these are more
circumscribed changes.
In contrast, the Commission’s proposal will require a tremendous
amount of resources to implement, will cause increased rate volatility, and in PJM’s view, is no
closer to allocating uplift based on cost causation principles than PJM’s current methodology.
III.
TRANSPARENCY PROPOSAL
PJM is generally supportive of the Commission’s proposed reforms to increase
transparency surrounding the creation and allocation of uplift, and offers the following
comments on specific aspects of the Commission’s proposal.
A.
Reporting Requirement
The Commission proposes that:
“within 20 days of the end of each month, each RTO/ISO post on its website two
reports, at minimum, regarding uplift payments. First, the RTO/ISO should report
the total uplift payments in dollars paid daily to the resources in each transmission
zone, subject to certain exceptions described below. Each RTO/ISO must post the
total amount of uplift in dollars in each category (e.g., day-ahead, real-time,
voltage and local reliability) paid to resources in each transmission zone for each
day within the calendar month. We propose to require that each RTO/ISO post
16
See e.g. PJM Interconnection, L.L.C., 152 FERC ¶ 61,165 (2015).
17
See PJM Price Formation Report at 28. For a more detailed description of PJM’s current uplift allocation methodology,
see id. at 28-32
18
See id. at 33.
10
uplift payment amounts based on its specific uplift categories to allow market
participants to distinguish between different types of uplift. Second, each
RTO/ISO must post the resource name and the total amount of uplift paid in
dollars aggregated across the month to each resource that received uplift
payments within the calendar month.”19
PJM is supportive of the Commission’s proposed reporting requirement, so long as it acts
as a minimum standard for RTO/ISO reporting requirements, and allows RTOs/ISOs to have
more stringent reporting requirements. For example, with regard to the total amount of uplift
paid daily to market participants for market activity in each Transmission Zone, PJM already
reports this information within seven Business Days after the end of each month, not twenty days
after as proposed by the Commission. Additionally, PJM does not object to reporting uplift by
category as the Commission proposes.
B.
Reporting Uplift By Resource
PJM does not oppose the Commission’s proposal to report uplift by resource.20
However, PJM does not currently do so because of stakeholder concerns related to revealing
market-sensitive information - particularly bidding strategies. PJM urges the Commission to
consider these factors when deciding whether to require all RTOs/ISOs to report uplift by
resource as proposed.
C.
Transmission Zone Definition and Reporting.
With regard to the Commission’s proposal to define a Transmission Zone as “a
geographic area that is used for the local allocation of charges,”21 PJM supports this definition as
long as PJM may continue to utilize its current Transmission Zones, described in Tariff,
Attachment J, to allocate uplift. PJM allocates uplift by these Transmission Zones today, and
19
NOPR at P 83.
20
See e.g. id. at P 82.
21
See id. at P 85.
11
does not believe it would be prudent to change this longstanding practice in response to the
NOPR.
Moreover, PJM opposes the Commission’s proposal that “transmission zones with fewer
than four resources need not be reported individually; rather, transmission zones with fewer than
four resources may be aggregated with a neighboring transmission zone and reported
collectively.”22 Because PJM reports uplift on a daily basis, this could mean that on one day,
four or more resources in a Transmission Zone may receive an uplift allocation, meaning the
Transmission Zone would not be aggregated with another Transmission Zone on that day for
reporting purposes; while the next day fewer than four resources in a Transmission Zone may
receive uplift allocations, meaning the Transmission Zone would be aggregated with another
Transmission Zone for reporting purposes. Given this fact, the Commission’s proposal adds
unneeded complexity and decreases transparency because whether a Transmission Zone’s daily
uplift allocation is based on a standalone or aggregated basis will likely vary over time. Instead,
PJM believes its current practice of reporting uplift by Transmission Zone, even if only one
resource in that zone receives uplift on a given day, provides sufficient transparency to the
market while also protecting market sensitive information.
D.
Charge Code
PJM seeks clarification on the Commission’s proposed requirement “for a daily
breakdown of uplift categories by charge code.”23 PJM is unsure what the Commission means
by “charge code” in this statement. If the Commission is referring to billing line items on market
participants’ bills, PJM already shows market participants’ uplift charges by billing line item
today, and does not object to continuing this practice going forward.
22
See id. at P 89.
23
See id. at P 86.
12
E.
Additional Details in Uplift Report
PJM notes that its current uplift reports provide more details than those proposed by the
Commission,24 and takes no position on whether these additional details should be mandated to
be reported across all RTOs/ISOs.25 However, PJM requests that it may continue to publish
these additional details if they are not mandated by any Final Rule because they provide greater
transparency to all market participants.
F.
Posting Operator Initiated Commitments
The Commission seeks comment on the types of unit commitments that should be
reported as operator-initiated commitments.26 To clarify, in PJM there are no “automated”
commitments either real-time or day-ahead.
Instead, several applications, including PJM’s
intermediate-term security constrained economic dispatch (IT SCED) software, provide
commitment suggestions to PJM operators while considering maintaining power balance and
controlling transmission constraints. PJM operators perform additional analyses once these
suggestions are received, including running transmission studies to ensure committing the
resource will not result in overloads prior to finally committing a unit. Both these analyses and
the operators’ decisions all occur after the clearing of the Day-ahead Energy Market, which
occurs by 1:30 PM on the day prior to the Operating Day. Therefore, PJM does not have an
“automated” way to post the types of unit commitments after the close of its Day-ahead Energy
Market.
24
Notably, PJM’s reports on uplift provide uplift totals by Transmission Zone describing, among other data: 1) Day-ahead
Energy Market Operating Reserve credits; 2) balancing Operating Reserve credits; 3) reactive credits; 4) Blackstart credits;
and 5) Lost Opportunity credits. See PJM.com, Uplift Data (available at http://www.pjm.com/markets-andoperations/energy/uplift-data.aspx).
25
See NOPR at P 83.
26
See id. at P 93.
13
Accordingly, PJM interprets the Commission’s proposal to require PJM to post all
commitments made by PJM operators that occur after the close of the Day-ahead Energy Market.
PJM is able to accomplish this goal, but requests clarification that this was the Commission’s
intended outcome. Further with regard to the proposed reporting timeframe of four hours,27 PJM
believes it will be able to comply with this deadline the vast majority of instances, subject to
unforeseeable technical issues. PJM therefore requests that in any Final Rule, the Commission
provide flexibility in the reporting timeframe to account for such technical problems so that if
they are to occur, PJM is not exposed to a compliance violation.
G.
Common Set of Categories
The Commission next seeks comment on whether it should define a common set of
categories used as the reason resources are committed across all RTOs/ISOs.28
PJM is
supportive of the Commission defining a minimum set of categories but requests the
Commission permit each RTO/ISO to develop its own additional categories as desired.
RTO/ISOs have different market designs and operational practices, and therefore each RTO/ISO
should separately define how they commit resources and for what reasons.
Additionally, it is unclear what level of detail the Commission is contemplating for such
categories. Notably, PJM believes that the identification of specific resources committed to
control specific transmission constraints is CEII and therefore should not be published. A Final
Rule should clarify the level of detail envisioned for this proposal.
27
See id. at P 94.
28
See id. at P 95.
14
H.
Transmission Outages
With regard to whether additional reporting of transmission outages should be required,29
PJM does not believe this is necessary. PJM currently provides substantial information on
transmission outages on its website,30 and believes the level of detail it currently posts on its
website is sufficient and that posting more information, namely transmission outages that
disconnect generating units or stations from the transmission system, may risk releasing
confidential market participant information because the status of a unit or station would be
identified via this posting. Accordingly, PJM requests that the Commission not require further
disclosures related to transmission outages compared to what PJM already makes public today.
Further, PJM is supportive of the Commission’s proposal to “include certain provisions
related to transmission constraint penalty factors in their tariffs because transmission constraint
penalty factors can significantly impact market clearing prices.”31
I.
Posting Model Data
The Commission seeks comment on “whether certain classes of market participants are
prohibited from obtaining the network model in certain RTOs/ISOs.”32 PJM acknowledges that
certain entities are prohibited from accessing market models, however there are good and
important reasons why that is the case.
PJM posts substantial data related to its models and systems,33 taking into account the
need to also preserve market participants’ market sensitive information, but most importantly the
29
See id. at P 100.
30
See PJM.com, Outage Information (available at http://www.pjm.com/markets-and-operations/etools/oasis/systeminformation/outage-info.aspx).
31
See NOPR at PP 96.
32
See id. at P 101.
33
Specifically, PJM posts its FTR model on its website. See PJM.com, Financial Transmission Rights (available at
http://pjm.com/markets-and-operations/ftr.aspx). Further, PJM posts supplemental information, such as transmission outage
15
security and reliability of the bulk transmission system.
PJM’s internal models contain
significant amounts of sensitive and CEII data that if it made publically available, would
compromise the security of the bulk electric system. It is true that in some limited instances,
PJM shares some of these models with certain entities that it does not with others (for example,
EMS model data with Transmission Owners). But in these limited instances, these models are
shared not for the sake of market transparency, but because Transmission Owners use this
information to coordinate the reliability of the transmission system with PJM. When this
information is shared, it is done so pursuant to non-disclosure agreements and in a highly secure
manner. Notably, the Transmission Owners do not in any way financially benefit from this
information, but instead need this information to perform their essential transmission function.
PJM believes that its current procedures and rules for sharing model data strike the correct
balance between market transparency, complying with NERC requirements, protecting the
security of the bulk electric system and believes that these procedures should not be changed as a
result of the NOPR.
IV.
IMPLEMENTATION TIMELINE
With regard to the Commission’s proposed implementation timeline, PJM agrees with the
Commission that 90 days from any Final Order’s effective date is sufficient time to submit a
compliance filing with conforming tariff revisions.34 However, should the Commission decide to
proceed with the cost allocation provisions of the NOPR despite the reservations stated herein,
PJM notes that many factors will contribute to when PJM can implement any Final Order.
Importantly, if a Final Order is issued requesting an implementation date before the Fall of 2018,
it will be extremely difficult for PJM to implement revisions by then because PJM’s human,
data, on OASIS. See PJM.com, Outage Information (available at http://www.pjm.com/markets-andoperations/etools/oasis/system-information/outage-info.aspx).
34
See NOPR at P 102.
16
financial and technical resources are already allocated to implementing Coordinated Transaction
Scheduling with MISO by October 2017, hourly offers by November 2017, and 5-minute
settlements by February 2018. Further, if a Final Rule requires extensive changes to PJM’s
current processes for allocating uplift, additional time will be required for implementation.
While PJM could institute the transparency changes on a shorter timeframe (preferably 9
months after the issuance of a Final Rule in this proceeding), PJM cannot begin to make any
system changes needed for uplift allocation until after it implements 5-minute settlements in
early 2018.35 Accordingly, PJM requests that any Final Order issued in this proceeding not
require PJM to implement any reforms related to uplift allocation before April 2019 if such
reforms are indeed required by any Final Rule.
V.
CONCLUSION
For the foregoing reasons, PJM respectfully requests that the Commission consider its
comments herein.
Respectfully submitted,
Craig Glazer
Vice President – Federal Government Policy
PJM Interconnection, L.L.C.
1200 G Street, N.W.
Suite 600
Washington, D.C. 20005
(202) 423-4743
[email protected]
35
Steven Shparber
Counsel
PJM Interconnection, L.L.C.
2750 Monroe Blvd
Audubon, PA 19403
(610) 666-8933
[email protected]
See e.g. PJM Interconnection, L.L.C., Order No. 825 Compliance Filing, Docket No. ER17-775-000 (Jan. 11, 2017).
17
CERTIFICATE OF SERVICE
I hereby certify that I have this day served the foregoing document upon each person
designated on the official service list compiled by the Secretary in this proceeding.
Dated at Audubon, PA this 10th day of April, 2017.
Steven Shparber