Issue 2
2015 March/April
Inside this Issue
Page
A Note from the President
1
PRC -005-2
2
Dancing with Systems
3
Regulatory Affairs
4-5
The Seam
6-7
The Lighthouse
8-10
Standards Update
11-12
Watt’s Up at RF
13-14
Reliability Committee
15
Calendar
16
RF Member Roster
17
ReliabilityFirst Corporation
3 Summit Park Drive
Suite 600
Cleveland, OH 44131
Main Phone: 216-503-0600
Web: www.rfirst.org
Follow us on
A Note from the President
Tim Gallagher, President and CEO
Dear Stakeholders:
Spring is in the air bringing with it renewed life and new
beginnings! Here at RF, we are experiencing new
beginnings as well.
We wrapped up our first quarter with our Board of
Directors Meeting, which took place from March 25-26.
I am happy to announce that at that meeting our Board
approved RF’s first Annual Report for 2014. This Report
is the culmination of the collaborative effort between RF,
its members, and stakeholders with the goal of
continuing to strive to operate a transparent
organization. Basically, we want you to know what we
have been up to and why. The 2014 Annual Report
focuses on several company-wide initiatives as well as
significant departmental activities. This newsletter
provides an overview of the Annual Report but you can
read the entire report, which I encourage you to do, on
our website next week.
Also in this issue, you will learn about the new ground
broken by FERC when it issued two recent Orders
approving NERC’s Risk-Based Registration Initiative
and Reliability Assurance Initiative on an ERO-wide
basis. Both of these programs strive to improve
reliability by focusing on risk. The overall goal of RiskBased Registration is to ensure entities are registered
and made subject to the Reliability Standards based on
the risk they pose to reliability, while the Reliability
Assurance program aims to provide reasonable
assurance of reliability through risk-based compliance
monitoring and enforcement. We at RF appreciate the
value that both of these programs bring and will
continue to work closely with NERC and the other
Regions to uniformly implement these programs across
North America.
Carl Dister continues his discussion on a systems
approach to reliability by focusing on the need for all of
us to renew our interest in our given areas of expertise
and to keep up with new and changing issues. Not to be
outdone, Lew Folkerth also provides a thoughtful
column aimed to continue guiding you in your transition
to version 5 of the Critical Infrastructure Protection
Reliability Standards.
Finally, as we move forward into 2015, RF will hold its
Spring Workshop from April 14-17, 2015, providing its
members and interested stakeholders the opportunity to
learn about the upcoming changes related to version 5 of
the Critical Infrastructure Protection Reliability
Standards, risk-based monitoring and enforcement, and
several other important topics and issues. I will again be
observing the sessions and look forward to learning from
your insightful questions and unique perspectives. I
hope to see you there!
Forward Together
ReliabilityFirst
Important Changes Coming With
PRC-005-2
n
Ÿ
Those for transformers connecting aggregated generation that is part of the BES; and
Ÿ
Those for station service or excitation transformers connected to the generator bus of generators
which are part of the BES, that act to trip the generator.
Under the previous version of PRC-005, an entity had the ability to determine its own Protection
System maintenance and testing program, including maintenance and testing intervals, their basis, and
a summary of procedures. However, under the new PRC-005-2, an entity must identify whether it will
follow the time-based method provided in the standard, the performance-based method (described in
PRC-005 Attachment A), or a combination of the two.
With the April 1, 2015 implementation date for PRC-005-2 fast
approaching, this article aims to highlight the important
changes effected by the new Standard.
PRC-005-2 applies to Transmission Owners, Generator Owners,
and Distribution Providers. It combines four existing Standards
addressing various aspects of maintenance and testing of
Protection and Control Systems, including:
(1) Transmission and Generation Protection Systems
Maintenance and Testing (previously PRC-005-1.1b);
(2) Underfrequency Load Shedding Equipment
Maintenance Programs (previously PRC-008-0);
(3) Undervoltage Load Shedding (UVLS) System
Maintenance and Testing (previously PRC-011-0); and,
(4) Special Protection System Maintenance and Testing
(previously PRC-017-0).
In addition, PRC-005-2 includes a new Requirement, R5, that
requires entities to demonstrate efforts to correct identified
Unresolved Maintenance Issues, which are defined as
“deficienc[ies] identified during a maintenance activity that
cause[] the component to not meet the intended performance,
cannot be corrected, and require[] follow-up corrective action.”
For generator Facilities that are part of the BES, PRC-005-2
applies to the following types of Protection Systems:
Ÿ
Those that act to trip the generator directly or through
lockout or auxiliary tripping relays;
Ÿ
Those for step-up transformers for generators that are
part of the BES;
Page 2
The time-based method utilizes predefined maintenance intervals for each component type as shown in
the tables at the end of the standard. An entity may modify these intervals by using the performancebased method for components that meet the performance-based criteria defined in Attachment A.
Entities are required to fully comply with R1, R2 and R5 by April 1, 2015. However, NERC’s proposed
implementation plan provides a longer implementation period with respect to R3 and R4, as shown in
the table below, including a phased implementation process for maintenance intervals 3 years or
greater:
Maximum Maintenance Interval
% Compliant
Date
Less than 1 year
1-2 calendar years
3 calendar years
3 calendar years
3 calendar years
6 calendar years
6 calendar years
6 calendar years
12 calendar years
12 calendar years
12 calendar years
100%
100%
30%
60%
100%
30%
60%
100%
30%
60%
100%
10/1/2015
4/1/2017
4/1/20161
4/1/2017
4/1/2018
4/1/20172
4/1/2019
4/1/2021
4/1/2019
4/1/2023
4/1/2027
1 Or, for generating plants with scheduled outage intervals exceeding two years, at the conclusion of the first
succeeding maintenance outage.
2 Or, for generating plants with scheduled outage intervals exceeding three years, at the conclusion of the first
succeeding maintenance outage.
For those interested in reading more about PRC-005-2, NERC’s Implementation Plan can be found
here as well as NERC’s FAQ document here.
n
Dancing with Systems
dancing
w ith
By: Carl Dister, Principal Reliability Consultant
Keeping up with the Weavers
systems
A few weeks ago, a
colleague sent me
a classic technical
paper from a 1948
issue of American
Scientist. The era
in which it is was
published brought
to my mind visions of the TV Show Leave it to Beaver,
Polka Dancing with Frankie Yankovic, and expressions
like “Keeping up with the Joneses.” The author of the
article was Warren Weaver and the article was simply
titled “Science and Complexity.”
Around the same time I received this classic article, my
son invited me to the movie Imitation Game, which took
place during a similar era. The movie looked back to the
advent of the Turing Machine and how it helped crack
German message encryption. Both the article and the
movie reminded me how far behind I had been in my
career in “Keeping Up” with applied Complexity Science,
a key component of Systems Thinking.
For 30 years, I was successful in my career applying the
basic engineering equations learned in college
coursework, and I had a prejudice that Complexity
Science was some type of political campaign from the
scientific community to support political issues (e.g.,
Creationism vs Evolution, Global Climate Change,
Capitalism, etc.). I wasn't interested in a political debate
as a traditional Engineer. However, I have come to
realize that Complexity Science is to Systems Thinking as
Classical Science is to Basic Engineering. And in the area
of Risk Management, understanding the foundations of
Complexity Science is critical, not a political party
propaganda tool.
Here is a summary of some of the takeaways from the
1948 Weaver paper. (How well do you think these
radical ideas apply to Risk Management in your
organizations almost 70 years later?):
“The essence of science is not to be found in its outward
appearance, in its physical manifestations,… the
Page 3
scientific method requires of its practitioners high
standards of personal honesty, open-mindedness,
focused vision, and love of the truth” (Are we focused on
the “truth” of Reliability, or the relativism of
Compliance?)
“We must stop thinking of science in terms of gadgetry.
Above all, science must not be thought of as a modern
improved black magic capable of accomplishing
anything and everything.” (Do we believe improving
reliability simply means spending more money on
equipment?)
“As never before, the quantitative experimental methods
and the mathematical analytical methods of the physical
sciences are being applied to the biological, the medical,
and even the social sciences”; “Knowledge of individual
and group behavior must be improved” (How are we
doing with applying the Social Sciences to Resiliency?)
“Communication must be improved between peoples of
different languages and cultures, as well as between all
the varied interests.” (Do we understand the importance
of diversity in the workforce to face unknown threats?)
“Some scientists will seek and develop for themselves
new kinds of collaborative arrangements; that these
groups will have members drawn from essentially all
fields of science; and that these new ways of working,
effectively instrumented by huge computers, will
contribute greatly to the advance which the next half
century will surely achieve in handling the complex, but
essentially organic, problems of the biological and social
sciences” (Do we have cross functional risk teams (not
separate OPS and CIP focused teams) that include Social
Scientists and Financial folks?)
How clear an understanding of Complexity Science do we
have compared to the Classical Science most of us
learned in school?
As I have been trying to keep up with Complexity
Science, especially how to apply it to real world problems
like improving grid reliability and resiliency, here are a
few foundational references I have personally found
helpful to “Keep up with the Weavers”:
Mitchell, M., Complexity : A Guided Tour. 2011, New
York; Oxford: Oxford University Press. xvi, 349 p.
Melanie Mitchell's book is very readable! She
purposefully wrote the book to help people without
detailed math and science backgrounds to understand
the basics of Complexity.
Rosa, E.A., O. Renn, and A.M. McCright, The Risk
Society Revisited : Social Theory and Governance. 2014,
Philadelphia: Temple University Press. xxx, 233 pages.
The Risk Society dives into the underpinnings of Risk
Management, and how we should be considering risks
in governance. Although not highly mathematical, this
book explores the philosophy behind the concept of
risk. I found it very helpful in understanding the way
different people from different levels of society
understand risk.
Flake, G.W., The Computational Beauty of Nature :
Computer Explorations of Fractals, Chaos, Complex
Systems, and Adaptation. 1998, Cambridge, Mass: MIT
Press. xviii, 493 p.
Gary Flake’s book is a real blast for those of you who
have a background in computer science. Even without
that background, he shows how computation is at work
in the natural world around you. Fascinating.
Strogatz, S.H., Nonlinear Dynamics and Chaos : with
Applications to Physics, Biology, Chemistry, and
Engineering. Studies in Nonlinearity. 1994 (Revised in
2014) Reading, Mass.: Addison-Wesley Pub. xi, 498 p.
This book is a classic in the field of Complexity Science.
As the title implies, the mathematics underpinning
complexity science is highly non-linear. For those of us
who were trained in engineering using
classical calculus, this book continues on
where we left off. The visualizations and
examples are superb.
Live Long and Prosper!
n
Regulatory Affairs
Senate Committee on Homeland Security and
Governmental Affairs Holds Cybersecurity Hearing
On January 28, 2015, The U.S. Senate Committee on Homeland Security and Governmental Affairs held
a meeting entitled “Protecting America from Cyber Attacks: The Importance of Information Sharing.”
Committee Chairman Ron Johnson (R-WI) explained that the purpose of the hearing was to better
understand cybersecurity threats in order to craft legislation that would appropriately respond to those
threats.
Representatives from American Express, Microsoft, Marsh & McLennan Companies, FireEye, and the
Center for Democracy & Technology all testified at the hearing. Their testimony stressed the evolving
nature of cyber security threats, the tremendous increase in the number
of threats over the last few years, and the need for information sharing
legislation with strong liability protections. Information sharing is most
effective when it is “real time” sharing and when private companies and
government consistently share information with each other. The
witnesses also stressed that however Congress responds to these
increased cybersecurity threats will influence international policy on
cybersecurity.
U.S. Department of Energy Considers Stockpiling
Large Transformers to Prevent Grid Threats
The United States Department of Energy’s Office of Electric Delivery and
Energy Reliability has been studying the potential need to stockpile
transformers in case damage to the power grid causes widespread
blackouts. Such damage could come from physical terrorist attacks on
substations, cyberattacks that cause physical harm, or large solar storms
that add too much current to the grid. One of the challenges related to
recovering from a blackout caused by, or resulting in, damage to a
transformer is that the U.S. grid has a limited number of spare, large
transformers, which are increasingly supplied by overseas manufacturers.
On March 9, 2015, the DOE Office of Electric Delivery and Energy Reliability also announced up to $27
million in funding for academic collaborations that will develop and transition advanced cybersecurity
technologies to the energy sector. This funding will help the energy sector adjust to the ever changing
cybersecurity landscape and further reduce the risk of a power disruption resulting from a cyber incident.
Page 4
FERC Issues Order on NERC's
Risk-Based Registration Initiative
On March 19, 2015, FERC issued an Order
approving the overwhelming majority of
NERC's proposed revisions to the NERC Rules
of Procedure designed to implement NERC's
Risk-Based Registration (RBR) initiative, which
NERC states is intended to ensure that entities are subject
to an appropriate set of applicable Reliability Standards by
using a consistent approach to risk assessment and
registration. The major reforms proposed by NERC
include:
(1) the elimination of the Purchase-Selling Entity,
Interchange Authority, and Load-Serving Entity
functional registration categories;
(2) modifications to the thresholds for registering
entities as Distribution Providers; and,
(3) procedural improvements to the registration
process.
In the Order, FERC concluded that NERC's overall goal of
ensuring entities are registered and made subject to the
Reliability Standards based on the risk they pose to
reliability was reasonable and determined that many of the
proposed revisions clearly promote this goal and were
adequately justified. However, FERC concluded that NERC
failed to adequately justify the proposed elimination of the
Load-Serving Entity function from the registry process and
directed NERC to submit a compliance filing within 60 days
to address FERC's concerns on this issue.
Additionally, while FERC approved NERC’s proposed
revisions related to the registration of Distribution
Providers, FERC directed NERC to include Reliability
Standard PRC-005 as applicable to underfrequency load
shedding-only Distribution Providers. Finally, FERC also
directed NERC to make one further modification to the
proposed revisions to the Rules of Procedure, and directed
NERC to submit a one-year compliance filing discussing the
implementation of the RBR program. The full FERC Order
can be found here.
n
Regulatory Affairs
FERC Issues Order on the Reliability Assurance Initiative
On November 3, 2014, NERC submitted to the FERC a
filing describing the Reliability Assurance Initiative
(RAI), which aims to provide reasonable assurance of
reliability through risk-based compliance monitoring
and enforcement.
On February 19, 2015, FERC issued an Order (Order)
approving the implementation of the RAI, subject to the
following:
1) A compliance filing;
2) Certain conditions; and
3) An annual reporting requirement.
See 150 FERC ¶ 61,108.
Compliance Filing
FERC directed NERC to submit a compliance filing, due
May 9, 2015, addressing the following three items.
First, NERC must propose revisions to the NERC Rules
of Procedure to include RAI concepts and programs.
According to FERC, the NERC Rules of Procedure
should, at a minimum, recognize the existence of the
RAI processes, articulate basic RAI concepts and define
fundamental RAI elements, and require Commission
approval for significant changes in the RAI program as
NERC further develops and implements its risk-based
approach. Second, NERC must address its oversight
plan for the RAI. Third, NERC must address a
methodology for: (a) assessing an entity's internal
controls as a prerequisite to self-logging; and (b)
standardizing the Regions' review of noncompliances
recorded on the self-logs.
Conditions
FERC imposed certain conditions on the
implementation and continued development of the RAI
program relating to:
1) Transparency (requiring public posting) of
compliance exceptions;
2) Treatment of compliance exceptions in
compliance history;
3) Finality of compliance exceptions; and
4) Qualifications for self-logging.
Regarding self-logging, FERC’s Order provides that
NERC must require some level of formal review of an
entity's internal controls before granting the flexibility
to self-log instances of noncompliance. Regarding the
transparency of compliance exceptions, although RF
Commissioner Bay to Succeed
Chairman LaFleur as FERC Chairman in April
FERC Commissioner Norman Bay, who previously
served as Director of FERC’s Office of Enforcement,
will assume the position of FERC Chairman when
Cheryl LaFleur steps down in April. She was
appointed to this position after Chairman Jon
Wellinghoff’s departure in November 2013.
supported NERC’s position against the public posting of
compliance exceptions, RF nevertheless recognizes the
value that the practice of public posting will provide to
the industry.
Annual Reporting Requirements
FERC directed NERC to submit an annual filing, by
February 19, 2016, addressing the following:
1) Progress of the RAI program and any necessary
enhancements or expansions;
2) Interplay between the RAI program and other
NERC program areas;
3) Whether a baseline audit is necessary to
properly evaluate a Registered Entity's internal
controls;
4) NERC's oversight of the RAI program; and
5) Inherent Risk Assessments and other CMEP
tools.
The Regions are working closely with NERC as NERC
prepares its Compliance Filing. We will keep you
updated on progress. The full Order is available here:
RAI Order.
FERC HoldsTechnical
Conference on EPA's Clean Power Act
On March 11, 2015, RF attended FERC’s Eastern Regional technical
conference on the EPA’s Clean Power Act in Washington, D.C., to
discuss implications of compliance approaches to the Clean Power
Plan proposed rule, issued by the EPA on June 2, 2014.
During her 17 month tenure leading the commission,
LaFleur effectively dealt with concerns about climate
change, the EPA's draft Clean Power Plan, natural gas
infrastructure, and grid reliability.
This conference was the second in a series of four technical
conferences on the EPA’s Clean Power Act, focusing on issues related
to electric reliability, wholesale electric markets and operations, and energy infrastructure.
The discussion during this conference regularly returned to
considering the need for a “reliability safety value” in the EPA’s
proposed rule making and what that might look like.
Chairwoman LaFleur will continue to serve as FERC
Commissioner after Commissioner Bay takes over the
gavel as Chairman in April.
The Central Regional technical conference took place on March 31,
2015, in St. Louis, Missouri. The final technical conference will be
scheduled soon.
Page 5
Sn
The Seam
MISO & PJM Submit Fuel Assurance Reports to FERC
In late 2014, FERC issued an Order in which it asked
each RTO and ISO to report on the status of its efforts
to address market and system performance associated
with fuel assurance issues. This issue of The Seam will
provide an overview of MISO and PJM's fuel
assurance reports to FERC in response to this Order.
MISO Fuel Assurance Report
MISO explained that in its footprint, Load Serving
Entities (LSEs), with oversight by the States as
applicable, are primarily responsible for resource
adequacy planning and fuel assurance issues. In turn,
MISO’s role is to support and facilitate the role of the
LSEs and the States with market designs that
incentivize fuel assurance, supply availability, and the
efficient dispatching of available resources across
MISO’s broad, multi-State footprint to reliably meet
demand.
... MISO’s role is to support
and facilitate the role of the
LSEs and the States with
market designs that
incentivize fuel assurance,
supply availability, and the
efficient dispatching of
available resources across
MISO’s broad, multi-State
footprint to reliably meet
demand.
MISO stated
that fuel
assurance
issues have
become more
prominent as a
result of
emerging
environmental
regulations,
evolving fuel
economics, and
associated
lower MISO
reserve
margins. MISO
is continually
reviewing
opportunities
for increased transparency, reduced operational
volatility, enhanced situational awareness, and
improved market alignment to address fuel assurance
concerns and needs as the challenges become more
prominent.
MISO noted that fuel assurance in its footprint is
primarily a concern during severe winter weather
when:
i)
natural gas and coal procurement /
transportation logistic constraints and
disruptions may be exacerbated; and
ii) competition is highest for natural gas in other
sectors (e.g., as a heating fuel). MISO’s system
reliability during the extreme weather
conditions of the 2014 polar vortex
demonstrated MISO's ability to effectively
manage adverse conditions. MISO is
leveraging its experiences from this event to
implement several new operating procedures,
improve fuel issue transparency, and evaluate
potential market enhancements with
stakeholders.
MISO also previously determined that increased
situational awareness associated with the gas industry
was necessary. Historically, MISO had limited
visibility and awareness of how the pipeline industry
interfaced with generation. Consequently, operational
flow orders or other less common system activities in
the pipeline industry did not always raise effective
situational awareness for generation capacity.
In response, MISO conducted an Electric/Gas
Coordination Field Trial with two prominent gas
pipeline companies in late 2013, and continues to
work through its stakeholder processes to improve
electric and natural gas communication going forward
with all of the 70-plus gas pipeline operators serving
gas-fired power plants in MISO's 15-State footprint.
MISO has developed tools to improve visibility into
gas pipeline events and associated notifications. These
methods include a new control room display of the
pipeline infrastructure and a consolidated gas pipeline
critical notice webpage. MISO also initiated a
generator survey in late 2014, to obtain better
information about generator fuel assurance practices
such as the use of backup fuels or some form of firm
pipeline capacity.
On the pricing front, MISO is working to improve the
price signals in its energy and operating reserves
markets that appropriately align the market incentives
to the reliability needs of the MISO system. Two
examples are the adoption of Extended Locational
Marginal Pricing (ELMP) and Evaluation of Value of
Lost Load (VOLL) Pricing. ELMP allows prices to
better reflect total operational costs when MISO
commits a fast-start resource to meet requirements,
while VOLL establishes the locational marginal
pricing price cap in MISO markets (if established too
low, generators may be unwilling to follow dispatch or
make themselves available during emergency
situations, and may be less likely to build generation).
PJM Fuel Assurance Report
PJM noted that fuel assurance issues were highlighted
during the Polar Vortex as fuel supply inadequacies
and generator outages in the PJM region led to tight
system conditions. Fuel-related contractual
constraints on generator availability, inflexible
pipeline tariff provisions, and gas marketer demands
for multi-day gas commitments severely constrained
generators and drove up prices even during weekend
Continued on page 7
Page 6
Sn
The Seam
Continued from page 6
PJM’s most significant
initiative to improve fuel is its
and non-peak hours during the Polar
Vortex. These issues are becoming more
urgent given the trend toward greater
reliance on gas-fired generation.
PJM highlighted various strategies,
Capacity Performance
programs, and mechanisms aimed at
improving fuel assurance in its region.
Proposal, where owners and
PJM’s most significant initiative to improve
operators of generation
fuel is its Capacity Performance Proposal,
where owners and operators of
capacity resources would
generation capacity resources
would have strong economic
have strong economic
incentives to invest in fuel
assurance and improved
incentives to invest in fuel
operation and maintenance,
including firm fuel transportation
assurance and improved
arrangements, dual-fuel capability, on-site
operation and maintenance ...
storage, and weatherization. Additionally,
the proposal would make capacity market
offer caps more flexible to allow fuel
assurance costs to be included in sell offers, and would impose more severe economic
consequences for resource non-performance.
PJM has also proposed energy market reforms that would require offers from
capacity resources to be based strictly on the specific physical operational
characteristics of those resources, and not on economic or budgetary considerations,
including considerations related to natural gas supply. This means sellers would have
greater incentive to invest in fuel assurance including dual-fuel capability and on-site
storage.
PJM highlighted its Gas Unit Commitment Coordination process, which introduced
changes in real-time operations for this winter, including improved clarity in
dispatcher communications and notifications, improved generator data accuracy,
more transparency and standardization in the commitment of units with long lead
times due to fuel restrictions, and better sharing of updated unit parameters
(including dual-fuel capability and availability, fuel inventories, and operational
restrictions).
PJM has undertaken a number of other initiatives, both short and long term, to
improve fuel assurance, including:
(1) A winter study and sensitivity analysis which included a gas shortage
Page7
scenario based on pipeline restrictions;
(2) A survey of generator fuel inventories and operational capabilities;
(3) The development of a cold-weather resource capability test and preparation
checklist for generators;
(4) The rollout of new dispatch training that also reviews emergency procedures
to relevant PJM and PJM member company staff;
(5) The development of a gas-fired generator database that
included information on dual-fuel capabilities and the
generator's natural gas service provider;
(6) A geographic information system mapping of gas-fired
generators and gas pipelines;
(7) The establishment of protocols for the sharing of nonpublic, operational
information with interstate pipeline operators within the PJM region;
(8) The establishment of a PJM gas analysis team that supports PJM dispatchers
in understanding the impact of natural gas availability on PJM's ability to
reliably operate the grid; and
(9) The establishment of a mechanism by which a Market Seller can make
intraday changes on an hourly basis to a generator's cost-based schedule in
the real-time energy market. This ability is expected to improve the
availability of generation and the efficiency of the markets by allowing sellers
to include in their cost-based schedules a more accurate reflection of true
fuel costs, which otherwise might result in out-of-market payments or taking
a generator off-line
rather than
operating at a loss.
n
The Lighthouse
By: Lew Folkerth, Principal Reliability Consultant
Compliance Approach for CIP-005-5 R1
We continue the series of compliance approaches that began in the previous issue
with a discussion of CIP-002-5.1 R1. While I call what follows a “Compliance
Approach,” you will find my recommendations may go beyond compliance. Blindly
following the recommendations here will NOT ensure compliance or a desirable audit
outcome. You, as the Registered Entity, must apply these approaches to your specific
circumstances. No one can tell you how to be compliant. You must chart your own
course, perhaps referring to that point of light on the shore to help you find your way.
Cyber Systems, unless low impact BES Cyber
Systems are explicitly mentioned. I will discuss
low impact BES Cyber Systems in a future
article, probably after FERC acts on CIP
Version 6.
CIP-005-5 R1 - Discussion of the Language
There has been considerable confusion over the
identification and classification of the Cyber
Assets to be protected by the Version 5 (and 6)
CIP Standards. Cyber Assets for which the CIP
Standards are applicable may fit one or more of
these classifications:
Ÿ A component of a BES Cyber System;
Ÿ An Electronic Access Control or Monitoring
System (EACMS);
Ÿ A Protected Cyber Asset (PCA);
Ÿ A Physical Access Control System (PACS).
I won't repeat the language of CIP-005-5 R1 here. The base Requirement and its five
Parts are comprised of one sentence each. Each sentence is straightforward with, in
my opinion, little or no ambiguity. The ambiguity and ongoing discussion and
clarification efforts involve some of the terms defined in the NERC Glossary that are
used in this Requirement. These terms, and some of the points under discussion, are:
Ÿ
BES Cyber System
-
An entity is granted great flexibility in defining its BES Cyber Systems. Where
and when is this flexibility useful? What are the pitfalls to consider when
exercising this flexibility?
Ÿ
Cyber Assets
- What does “programmable electronic device” really mean?
Ÿ
External Routable Connectivity
-
Ÿ
When is a routable connection “bi-directional” and, more importantly, when
is it not?
Under what circumstances can a serially connected device be considered to
be accessible via bi-directional routable protocol connection?
Electronic Access Point
- What are the implications of the access point being defined as an “interface?”
Control Center
- Does the ability to remotely start a generator from the control room of a
different generator make that control room a Control Center?
I don't answer those questions in this article. I list them here to inform you that there
are ongoing discussions regarding these issues. Please follow the development of the
Frequently Asked Questions (FAQs) and Lessons Learned on the NERC web site. If
you would like me to address any of these issues in a future article, please see the
“Feedback” section below.
This article will deal with Cyber Assets associated with high and medium impact BES
Considerations for Processes and
Procedures
Little Sable Point, MI
(Photo: L. Folkerth)
Let's first cover these components and determine when and how to identify them.
Step 1: Identify BES Cyber Systems and BES Cyber Assets (per CIP-0025.1 R1)
The first step in identifying the Cyber Assets to be protected is to identify your BES
Cyber Systems as required by CIP-002-5.1 R1. After completing CIP-002-5.1 R1 you
will have a list of your BES Cyber Systems and the BES Cyber Assets (and, optionally,
Cyber Assets) that comprise the BES Cyber Systems. Also, you will have assigned an
impact rating to each BES Cyber System.
Step 2: Identify the Cyber Assets that are required to reside within an
Electronic Security Perimeter (ESP)
Those Cyber Assets of high and medium impact BES Cyber Systems that are
connected to a network with a routable protocol are required to reside within an ESP.
This is separate from the concept of External Routable Connectivity.
Step 3: Identify Electronic Security Perimeter(s) around each of the
Cyber Assets identified in Step 2
In this step you will define the “logical border” enclosing each of the Cyber Assets you
identified in the previous step. You can have as many ESPs as you choose. Make sure
that every Cyber Asset of every high and medium impact BES Cyber System that is
Continued on page 9
Page 8
n
The Lighthouse
Continued from page 8
connected to a network with a routable protocol is
protected by an ESP.
Step 4: Identify any Protected Cyber Assets
(PCA)
Once the ESP is defined, identify any additional Cyber
Assets connected to the ESP network that are not part
of a BES Cyber System. These Cyber Assets must either
be relocated outside of the ESP, or they must be
identified as PCA.
In addition, any Cyber Asset of a BES Cyber System
that is not part of the highest rated BES Cyber System
within the ESP must be designated as a PCA associated
with the highest rated BES Cyber System. For example,
if an ESP contains both medium and low impact BES
Cyber Systems, then the Cyber Assets of the low impact
BES Cyber Systems must be identified as PCA
associated with a medium impact BES Cyber System.
Step 5: Identify the Electronic Access Point(s)
(EAP) for each ESP
If any Cyber Asset within an ESP can be accessed from
outside the ESP via a bi-directional routable protocol
connection, then you must identify one or more EAPs
for this traffic. Note that the EAP is an “interface” of a
Cyber Asset. This is a significant change from CIP-0053. Any Cyber Asset that has an interface designated as
an EAP must be identified as an EACMS for use in Step
7.
Step 6: Identify the methods and systems used
for Interactive Remote Access
If you are going to permit Interactive Remote Access
into your ESPs, you need to identify the Cyber Assets
that will be used for this purpose. Any Cyber Asset used
as part of an Intermediate System must be identified as
an EACMS for use in Step 7.
Step 7: Identify the Electronic Access Control or
Monitoring Systems (EACMS) associated with
each ESP
Any Cyber Asset that is used for electronic access
control or for electronic access monitoring must be
identified as an EACMS. This will include firewalls or
other network devices that host an EAP, components of
Intermediate Systems, authentication systems,
intrusion detection systems, or any other system that
meets the definition.
Step 8: Identify the Physical Security Perimeter
(PSP) surrounding each ESP (per CIP-006-6
R1)
Identifying, at least at a general level, the PSPs lets us
identify the Physical Access Control Systems in Step 9.
The details of identifying the PSPs must be left for a
discussion of CIP-006-6.
Step 9: Identify the Physical Access Control
Systems (PACS) for each PSP
Any Cyber Asset that controls, alerts, or logs access to a
PSP must be identified as part of a PACS.
Step 10: Identify the BES Cyber Systems with
special attributes
Some Requirements only apply to BES Cyber Systems
or associated Cyber Assets with special attributes. The
BES Cyber Systems with these attributes must be
identified so that the appropriate Requirements are
applied.
Suggested
Evidence
Your
compliance evidence should include the process used to
identify your Cyber Assets within the scope of CIP
compliance, and any applicable attributes (such as
External Routable Connectivity), per the steps above.
Note that Steps 1 and 8 could reside in the processes
for CIP-002-5.1 R1 and CIP-006-6 R1, respectively.
You should be prepared to show that you followed this
process to create your list of in-scope Cyber Assets.
You should also be able to show the outcome of your
process. I suggest keeping the outcome in a
spreadsheet or database table with one row for each inscope Cyber Asset. I suggest maintaining the following
information, at a minimum, for each row in the table:
Ÿ
Cyber Asset identifier (this identifier should also be
clearly marked on the Cyber Asset to facilitate audit
review)
Ÿ
Type of Cyber Asset (server, workstation, switch,
firewall, etc.)
Ÿ
If part of a BES Cyber System:
- BES Cyber System identifier
- Impact rating of BES Cyber System
- Is the Cyber Asset connected to a network via a
routable protocol?
Asset type (Control Center, Transmission
substation, etc.)
If within an ESP, the ESP identifier
If within a PSP, the PSP identifier
Classification of Cyber Asset (BES Cyber Asset,
Cyber Asset of a BES Cyber System, EACMS, PACS,
PCA)
Vendor (Dell, Cisco, etc.)
Model
Operating System (Windows Server 2008, IOS 15.4,
etc.)
External Routable Connectivity
These are the Cyber Assets that communicate
outside of an ESP with a bi-directional routable
protocol. This is not a simple determination, and a
Lessons Learned document is being prepared to
provide additional clarification.
Dial-Up Connectivity
If a BES Cyber System is accessible via a dial-up
connection (modem and phone line, or equivalent)
this constitutes dial-up connectivity.
Step 11: Identify any medium impact BES Cyber
Systems (and associated EAP) at Control
Centers
If a medium impact BES Cyber System or an associated
PCA is at a Control Center, then it must be identified,
as additional Requirements apply.
Ÿ
Ÿ
Ÿ
Ÿ
Ÿ
Ÿ
Ÿ
Ÿ
If this is a guest on a virtual system:
Continued on page 10
Page 9
n
The Lighthouse
Continued from page 9
-
The type of virtualization (VMware ESX, etc.)
Physical host identifier
Ÿ
Deployment date, if deployed within the audit
period
Ÿ
Indicators (yes/no) for:
- Dial-up Connectivity
- External Routable Connectivity
Ÿ
If information is for multiple registered entities,
indicate the entity responsible for compliance
For each ESP, identify all Electronic Access Points.
For each Electronic Access Point, provide:
Ÿ The list of inbound access permissions
Ÿ The list of outbound access permissions
Ÿ The reason for granting access for each of the
inbound and outbound permissions
Ÿ Evidence that all other access is denied by default
For each in-scope Cyber Asset with Dial-up
Connectivity, provide:
equivalent will be requested by the audit teams during
the review of CIP-005-5 R1. Also, this list will make
your job of identifying and protecting your in-scope
assets much easier. If you keep this list and periodically
review it, you will be ahead of the curve when you are
audited.
Ensure all Electronic Access points have been
identified. Ensure that you can provide the inbound
and outbound permissions (rule sets), and the reason
for each permission. Ensure that you can demonstrate
deny by default.
If you permit Dial-up Connectivity, your process must
show how it is controlled and authenticated. If your
dial-up equipment does not support authentication, be
sure you have a TFE in place.
If you do not permit or do not use Dial-up Connectivity,
be able to document this.
For BES Cyber Systems at Control Centers, ensure you
can provide evidence demonstrating your ability to
detect malicious communications in both directions.
Best Practices
Ÿ
Evidence that authentication is performed when
establishing a connection, or
Here are some practices not explicitly required by CIP005-5 R1, but that are highly advisable:
Ÿ
A reference to an approved Technical Feasibility
Exception (TFE) covering this Part and this Cyber
Asset
1.
Keep the Cyber Asset spreadsheet or database
(from Suggested Evidence, above) under version
control. In other words, keep a record of all
changes, including details of the change and the
date of the change.
2.
Periodically review the evidence for this
requirement to ensure it is correct and current.
Document this review, including who performed
the review and the date.
For each Electronic Access Point for a high impact BES
Cyber System or a medium impact BES Cyber System
at a Control Center, provide evidence of one or more
methods of detecting malicious communications.
Compliance Approach
For all high and medium impact BES Cyber Systems,
be able to show that all BES Cyber Assets, and all Cyber
Assets that are part of a BES Cyber System, that are
connected to a network via a routable protocol, are
identified and are protected by an ESP.
The CIP Standards do not explicitly require a list of inscope Cyber Assets. However, creating and maintaining
such a list is an implicit requirement; this list or an
Page 10
3.
Periodically perform a discovery process to identify
any previously unidentified devices within your
ESPs. Document this process, document each time
it is performed, and the results of each discovery.
4.
Ensure your change management procedures
require updating the evidence for this requirement
as part of any applicable change.
5.
If Part 1.5 is applicable to you, have a method of
alerting appropriate personnel on detected
malicious communications.
Managing Compliance with CIP-002-5.1 R1
As CIP Senior Manager, you should understand the
approach your subject matter experts (SMEs) have
taken to identify and document the Electronic Security
Perimeters. Here are some questions you might ask
your SMEs:
Ÿ
Is there a comprehensive list of Cyber Assets that
are subject to CIP compliance? If not, how are these
Cyber Assets being managed?
Ÿ
Have all Cyber Assets that are subject to CIP
compliance been identified? How do we know this?
Ÿ
Are there processes we follow to keep the Electronic
Security Perimeter documentation up to date? Are
these processes and the resulting evidence approved
by the appropriate manager?
Ÿ
Each inbound and outbound access permission
requires a reason for the permission. Have these
reasons been reviewed to ensure that they are
actually the reasons the permission is required, as
opposed to a statement of the nature of the
permission? For example, if an inbound permission
permits email to pass to a protected system, does
the reason say what the permission is (“email to
system xyz”), or does it provide an actual reason
(“email to system xyz is required to permit
coordination of failover status between primary and
backup systems”)?
References
CIP-005-5
NERC Glossary
'NERCs “Implementation Study, Lessons Learned,
and FAQs” Web Page
Feedback
Please let me hear any feedback you may have on these
articles. Suggestions for topics are always appreciated.
I may be reached at lew.folkerth@rfirst.org.
n
Standards Update
CIP Version 5 News
NERC will continue its Small Group Advisory Sessions (SGAS) from April 21 to
April 23 in Atlanta. These sessions are closed one-on-one discussions lasting 60
to 90 minutes between a Registered Entity's subject matter experts and ERO
staff about issues pertinent to that entity's implementation of the CIP V5
Standards. The SGAS will be held along with a CIP Version 5 Workshop on
April 24 that covers topics such as bright line criteria, CIP V5 core
requirements, lessons learned from the implementation study, CIP Standards
modification status, and compliance. Information about this and more CIP V5
workshop resources can be found on the CIP V5 Transition Page.
On January 21, 2015, NERC filed a petition for approval of TPL-007-1, which is the
second phase of standards to address geomagnetic disturbances.
NERC has created a 2015 Curriculum document, which is a repository of
numerous training resources from both NERC and the Regional Entities in
three categories: 100 – Standard-Specific Training, 200 – Compliance and
Enforcement Considerations, and 300 – Lessons Learned, Guidance, and
FAQs. Upcoming workshops and training can be found on the 2015 Events page
or the CIP Workshops and Curriculum Calendar.
On January 22, 2015, FERC issued a final rule approving PRC-005-3, which
includes revisions to require applicable entities to test and maintain certain
autoreclosing relays as part of a protection system maintenance program. The
Commission directed NERC to develop a modification to the Standard to include
maintenance and testing of supervisory relays. This Standard becomes enforceable
on April 1, 2016.
Three new draft lessons learned documents were posted for comment in
January and February addressing programmable electronic devices, interactive
remote access, and EACMS mixed trust authentication. Feedback on those
lessons learned is now posted. In addition, two additional lessons learned have
been posted for comment relating to the grouping of BES Cyber Systems and
identification of BES Cyber Systems at control centers based on functional
registration. Two lessons learned documents have been finalized relating to
generation segmentation and far-end relays. Lessons learned documents are
supporting reference documents designed to convey lessons learned from the
NERC CIP Version 5 transition program, and do not establish new
requirements under the Standards, modify the requirements, or provide a
formal interpretation of the Standards.
On February 13, 2015, NERC filed a petition for approval of the following proposed
Standards: CIP-003-6, CIP-004-6, CIP-006-6, CIP-007-6, CIP-009-6, CIP-010-2,
and CIP-011-2. This package of updated CIP Standards addresses modifications
directed by FERC in its Order No. 791, which approved the CIP Version 5 Standards.
These changes include the removal of “identify, assess, and correct” throughout the
Version 5 cybersecurity standards, the addition of security controls for Low Impact
BES Cyber Security Systems, and requirements for the protection of transient
devices and communication networks.
ReliabilityFirst will host a CIP Version 5 workshop on April 16 and April 17.
This workshop will include presentations on various transition and
implementation topics and will be held after the Spring Reliability workshop on
April 14 and April 15. For more details, including a link for registration, see the
2015 Spring Reliability Workshop announcement.
NERC Filings and FERC Orders
On February 19, 2015, FERC issued an order approving MOD-031-1, which provides
authority for planners and operators to collect demand, energy, and related data to
support reliability studies and assessments.
On March 4, 2015, FERC issued an order approving PRC-006-2, which establishes
design and documentation requirements for automatic underfrequency load
shedding programs to arrest declining frequency, assist recovery of frequency
following underfrequency events, and provide last resort system preservation
measures. This revised Standard becomes enforceable on October 1, 2015.
NERC filed a supplemental petition to FERC on March 13, 2015 for approval of of
PRC-001-1.1, PRC-019-2 and PRC-024-2 to clarify their applicability to dispersed
generation resources.
Page 11
n
Standards Update
This recurring column provides our Registered Entities with relevant and recent updates to the Reliability
Standards and Requirements. As we have noted before, this column does not cover all updates on
Reliability Standards, but we will focus on updates that might be of more significant interest to the industry.
Please take note of the following changes to Standards and progress on new and revised Standards.
Reliability Standard Audit Worksheets
NERC has provided one new RSAW, BAL-003-1, available on its RSAW web
page. A Reliability Standard Audit Worksheet (RSAW) is a guide provided by
NERC that describes types of evidence Registered Entities may use to
demonstrate compliance with a Reliability Standard. RSAWs also include
information regarding how Regional Entities and NERC may assess that
evidence.
Recent and Upcoming Standards
Enforcement Dates
Ÿ
TPL-001-4 became enforceable on January 1, 2015.
Ÿ
BAL-003-1, the new GMD Standard EOP-010-1, and PRC-005-2 become
enforceable on April 1, 2015.
Ÿ
MOD-032-1 will be enforceable on July 1, 2015.
Ÿ
The recently-approved CIP-014-1 and the revised PRC-006-2 will be
enforceable October 1, 2015.
Page 12
New Standards Projects
Several new Standards projects and new project phases are underway. Projects
are described on the NERC Standards website, along with links to all drafts,
voting results, and similar materials. Recent additions include the following
projects:
Ÿ
Project 2007-06.2 System Protection Coordination
Ÿ
Project 2008-02.2 Phase 2 Undervoltage Load Shedding: Misoperations
Ÿ
Project 2015-02 Emergency Operations Periodic Review
Ÿ
Project 2015-03 Periodic Review of System Operating Limit Standards
Ÿ
Project 2015-04 Alignment of NERC Glossary of Terms and Definitions
Used in the Rules of Procedure
Standards Resources
NERC has updated its list of FAQs related to the new BES definition. The
complete list of FAQs
n
Watt’s Up at RF
ReliabilityFirst has Career Opportunities
RF Spring Workshop
RF’s core mission is to preserve and enhance the bulk power system reliability and security within
the RF footprint. In doing so, RF is committed to supporting the efforts and serving as an
extension of the North American Electric Reliability Corporation (NERC) in its mission as the
Electric Reliability Organization (ERO) to ensure the reliability of the bulk power system in North
America.
RF’s upcoming spring workshop scheduled for April 14-17, 2015,
will include two major sessions:
RF currently has employment opportunities within its Compliance Monitoring, Entity
Development, and Risk Analysis and Mitigation areas. These positons offer
opportunities to collaborate, coach, and monitor Registered Entities that
function as users, owners and/or operators of the Bulk Electric System. If you
are interested in joining our team or would like more information, click here:
The general session will take place from April 14-15. This
session will include an overview of:
1. General Session; and
2. CIP v5 Workshop
Ÿ
Ÿ
Ÿ
Ÿ
Ÿ
ReliabilityFirst Board Approves
Public Release of
First Annual Report
During the
March 2015
meeting, the RF
Board of
Directors
accepted RF’s
first Annual
Report for FY 2014 and approved it for public
release.
Assurance Initiative (RAI) in the most
effective manner possible.
The FY2014 Annual Report focuses on several
company-wide initiatives as well as significant
departmental activities.
Additionally, RF also embarked on several
other company-wide initiatives including
developing an Enterprise Risk Management
Program to identify and address key risks
facing the corporation, creating a Threats and
Vulnerabilities Team to identify and address
emerging BES threats and vulnerabilities, and
completing the first Regional Risk Assessment
to identify high-priority risks within the RF
footprint.
One of the key company-wide initiatives for
2014 was RF’s corporate restructuring, which
was implemented to more clearly focus RF’s
operational activities around risk and to
support and implement the Reliability
The Fy2014 Annual Report describes these, as
well as several department-specific activities,
in more detail. Keep an eye out for the public
release of the full Annual Report in the
coming weeks.
Page 13
Ÿ
Ÿ
Internal Controls Evaluation (ICE);
Inherent Risk Assessment (IRA);
RF’s Risk-Based Enforcement Process;
CIP Lessons Learned;
Energy Management System (EMS) Outages Analysis;
Lessons Learned, preparing effective self-reports and
mitigation plans; and
ICS Cyber Security & Risk.
The CIP v5 workshop will take place from April 16-17 and will
include topics such as Impact Rating Criteria, CIP v5 Core
Requirements, Risk-Based Compliance approach to CIP v5, as
well as an open Q&A panel discussion. We will post the agenda
for the entire spring workshop on our website in the coming
weeks.
SPRING
2015
Follow
on
n
Watt’s Up at RF
RF Celebrates
History
As many of you know, the conference rooms in our
new office space are named after some of the thirteen
states located within our footprint, such as the
Delaware, Illinois, Indiana and the Michigan
conference rooms.
When we moved to this new office space, several
members donated images for us to display in these
conference rooms that capture the important role that
the energy sector has played in the history of their
respective states, as well as the nation given the
critical location, both geographically and electrically,
of the ReliabilityFirst footprint.
Donated by The Dayton Power and Light
Company and displayed in the Ohio
Conference Room
Donated by PSEG and displayed in
the New Jersey Conference Room
We would like to thank our members for contributing
these compelling images, and would like to share
some of them with you. The next time you visit
ReliabilityFirst's offices in Cleveland, Ohio, please
take the time to enjoy these and other images that are
proudly displayed throughout our conference rooms.
Forward Together, ReliabilityFirst.
Donated by FirstEnergy and displayed in
the Pennsylvania Conference Room
Donated by We Energies and displayed in the
Wisconsin Conference Room
Page 14
Donated by Southern Maryland
Electric Cooperative and
displayed in the Maryland
Conference Room
Donated by Baltimore Gas & Electric and
displayed in the Maryland Conference
Room
n
Reliability Committees
RELIABILITY
COMMITTEE (RC)
The Committee will be
holding its first of two
face-to-face meetings
on Wednesday, May 13,
2015, at
ReliabilityFirst's offices, located at 3 Summit Park Drive, Cleveland, OH 44131.
The meeting agenda will include items to endorse the summer reliability
assessment reports and a presentation on an aspect of human performance. If
there is an item you would like to see on the agenda, please contact Kevin Sherd
or Jeff Mitchell. The second 2015 face-to-face meeting of the Committee will be
November 18, 2015 at the ReliabilityFirst offices.
You can contact Joyce Lemmon at for any questions regarding the meeting
details.
For information on past RC meetings, the minutes are posted on the
ReliabilityFirst website here.
Coming up either in late summer or the fall, ReliabilityFirst is planning to host a
one-day training session targeted for substation supervisors, mechanics, and
relay technicians. The training will encompass power line carrier equipment
(which was conducted last year with our Protection Subcommittee, a substation
tool kit to aid in labeling during maintenance activities (developed by Dominion
Virginia Power), and other human performance aspects of substation work and
lessons learned.)
Stay tuned for more information. Continuing education hours may be earned for
this training. We hope there will be much interest in this, and it is meant to get
information to the personnel who may benefit from the information the most.
OPERATIONS SUBCOMMITTEE (OS)
Please mark your calendar for our spring face-to-face meeting on Tuesday, May
12 from 1:00-5:00 p.m. ET at the ReliabilityFirst offices. The semi-annual
“Neighbor's meeting” is held to cover operational topics for the upcoming
summer period. It is also a great opportunity to network with your industry
colleagues in the RF region and to share best practices and “war stories” (plus
there is free food!). For more information on the Operations Subcommittee,
please contact John Idzior.
Page 15
PROTECTION SUBCOMMITTEE (PS)
The next Protection Subcommittee conference call will be held on April 22, 2015
beginning at 2:00 p.m. ET. To become a new member of the PS or to submit an
agenda item, please contact Bill Crossland. Also, the ReliabilityFirst staff is
considering a misoperation peer review and is exploring the processes that other
Regions such as NPCC and SERC use for their misoperation peer reviews. More
information will be coming via future PS meetings and conference calls.
Coming up later this year, ReliabilityFirst is planning to host a one-day training
session via the Subcommittee on settings for microprocessor relays. Stay tuned
for more information. Continuing education hours may be earned for this
training and there will be no fee to attend!
RESOURCE ASSESSMENT SUBCOMMITTEE (RAS)
The WebEx conference call to review the 2015 Summer Resource Assessment is
scheduled for April 28 from 9:00 a.m.-12 p.m. ET. The agenda for the meeting
and the draft assessment will be sent out by April 24, 2015.
Once the RAS has completed its review, the draft assessment will be presented to
the Reliability Committee for endorsement before seeking Board of Director
approval and public posting on the internet.
TRANSMISSION PERFORMANCE SUBCOMMITTEE (TPS)
The next TPS meeting will be held on May 5, 2015 at the ReliabilityFirst offices in
Cleveland. This will be the first time that the TPS has met face-to-face in over
four years. During this meeting, the TPS will be reviewing the 2015 and 2016
portions of the summer seasonal transmission assessment that will be presented
at the May 13, 2015 Reliability Committee meeting.
The staff facilitator for the TPS is Ray Mason. For more information, contact Ray
Mason.
SPECIAL PROTECTION SYSTEM (SPS) REVIEW STATUS
The SPS Review Team has eight SPS installations due for a periodic 5-year review
in 2015. Data requests for these reviews will be sent to the respective SPS owners
shortly. Please contact Bill Crossland with questions regarding SPS reviews.
RF 2015 Calendar of Events
Complete calendar located at RF website
Date
Time (ET)
Meeting Details
Location
Apr 14-17 See Agenda
ReliabilityFirst Spring Workshops
Cleveland, OH
Apr 22
2:00 pm to 4:00 pm
Reliability - Protection Subcommittee
Apr 28
9:00 am to 12:00 pm
Reliability - Resource Assessment Subcommittee
WebEx
May 05
8:00 am to 4:00 pm
Reliability - Transmission Performance Committee
Cleveland, OH
May 12
1:00 pm to 5:00 pm
Reliability - Operations Subcommittee
Cleveland, OH
May 13
8:00 am to 5:00 pm
Reliability Committee
Cleveland, OH
Jun 03
1:00 pm to 5:30 pm
Board of Directors Committee Meetings
Cleveland, OH
Jun 04
8:30 am to 3:00 pm
Annual Meeting of the Members
Board of Directors Meeting
Cleveland, OH
Conference Call
Share your feedback
Please email any ideas or
suggestions for the
newsletter to
prcommrequest@rfirst.org
Newsletter Update
Starting in 2015, the RF Newsletter
will move to a bimonthly publication!
Page 16
Forward Together
ReliabilityFirst
ReliabilityFirst Members
ReliabilityFirst
Page 17
Forward Together
AEP ENERGY PARTNERS
AES NORTH AMERICA GENERATION
ALLEGHENY ELECTRIC COOPERATIVE, INC
AMERICAN ELECTRIC POWER SERVICE CORP
AMERICAN TRANSMISSION CO, LLC
APPALACHIAN POWER COMPANY
ATLANTIC CITY ELECTRIC
BALTIMORE GAS & ELECTRIC COMPANY
BOSTON ENERGY TRADING & MARKETING & TRADING, INC
BUCKEYE POWER INC
CALPINE ENERGY SERVICES, LP
CASTLETON COMMODITIES MERCHANT TRADING LP
CITY OF VINELAND, NJ
CMS ENERGY RESOURCE MANAGEMENT CO
CMS ENTERPRISES COMPANY
CLOVERLAND ELECTRIC COOPERATIVE
CONSUMERS ENERGY COMPANY
DARBY ENERGY, LLLP
THE DAYTON POWER & LIGHT CO
DC OFFICE OF THE PEOPLE'S COUNSEL
DELMARVA POWER
DOMINION ENERGY, INC
DTE ELECTRIC
DUKE ENERGY SHARED SERVICES INC
DUQUESNE LIGHT COMPANY
DYNEGY, INC
EXELON CORPORATION
FIRSTENERGY SERVICES COMPANY
HAZELTON GENERATION LLC
HOOSIER ENERGY RURAL ELECTRIC COOPERATIVE, INC
ILLINOIS CITIZENS UTILITY BOARD
ILLINOIS MUNICIPAL ELECTRIC AGENCY
INDIANA MICHIGAN POWER COMPANY
INDIANAPOLIS POWER & LIGHT COMPANY
INTERNATIONAL TRANSMISSION COMPANY
LANSING BOARD OF WATER AND LIGHT
LINDEN VFT, LLC
MICHIGAN ELECTRIC TRANSMISSION CO, LLC
MICHIGAN PUBLIC POWER AGENCY
MIDCONTINENT INDEPENDENT SYSTEM OPERATOR, INC
MORGAN STANLEY CAPITAL GROUP, INC
NEPTUNE REGIONAL TRANSMISSION SYSTEM, LLC
NEXTERA ENERGY RESOURCES, LLC
NORTHERN INDIANA PUBLIC SERVICE COMPANY
OHIO POWER COMPANY
OHIO VALLEY ELECTRIC CORPORATION
OLD DOMINION ELECTRIC COOPERATIVE
ROCKLAND ELECTRIC COMPANY
PENNSYLVANIA OFFICE OF CONSUMER ADVOCATE
PEPCO ENERGY SERVICES, INC
PJM INTERCONNECTION, LLC
POTOMAC ELECTRIC POWER COMPANY
PPL BRUNNER ISLAND, LLC
PPL ELECTRIC UTILITIES CORPORATION
PPL ENERGYPLUS, LLC
PPL HOLTWOOD, LLC
PPL LOWER MOUNT BETHEL ENERGY, LLC
PPL MARTINS CREEK, LLC
PPL MONTOUR, LLC
PPL SUSQUEHANNA, LLC
PUBLIC SERVICE ENTERPRISE GROUP, INC
SOUTHERN MARYLAND ELECTRIC COOPERATIVE, INC
TENASKA, INC
TENNESSEE VALLEY AUTHORITY
UTILITY SERVICES, INC
VECTREN ENERGY DELIVERY OF INDIANA, INC
WABASH VALLEY POWER ASSOCIATION, INC
WISCONSIN ELECTRIC POWER COMPANY
WOLVERINE POWER SUPPLY COOPERATIVE, INC