RMEL Electric Energy Issue 1 2012 by Alive Publishing Group

electric spotlight on critical energy issues

Sunzia Southwest Transmission Project Details Large-Scale Renewable Grid Impacts

ISSUE 1 / 2012

www.RMEL.org

Vegetation Management Analysis for the Future Ratemaking Strategies NERC CIP – From the Auditor’s Perspective 2012 NESC Changes

Fossil Air Quality Control Nuclear Geothermal Biomass

Shaping the Future of Power Generation

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contents

Features 12 SunZia Southwest Transmission Project: Bringing Resources to Load by Tom Wray, Project Manager, SunZia Southwest Transmission Project

18 Integrating Large-Scale Renewables into the Electricity Grid by David Mooney, Center Director, Electricity, Resources & Buildings System Integration, National Renewable Energy Laboratory

24 Finding the Sweet Spot with BPAâ&#x20AC;&#x2122;s Vegetation Management Program by Steve Narolski, Program Manager-Veg. Mgmt. & Access Maintenance

32 The Art of Residential Ratemaking by Jim Marshall, Manager, Jackson Thornton Utilities Consultants and Terry Mitchell, CPA, Principal, Jackson Thornton Utilities Consultants

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36 Easing the Pain of a NERC CIP Audit by Michael W Tibbs, CPP, CSPM, CHS-III, Senior Vice President & COO, Corporate Risk Solutions, Inc.

42 2012 National Electric Safety Code: The Changes by Mark Swan, P.E., Consulting Engineer, MDS Engineering Consulting, LLC

Departments 06 Board of Directors 08 2012 Spring Electric Energy Conference 50 RMEL Membership Listings 54 2012 Calendar of Events 56 Index to Advertisers

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rmel information

RMEL Board of Directors Officers President Kelly Harrison Westar Energy VP, Transmission President Elect Andy Ramirez El Paso Electric Company VP, Power Generation Past President Larry Covillo Yampa Valley Electric Association, Inc. President Vice President, Membership Dan Schmidt Black & Veatch Corp. VP, Energy

Directors Vice President, Education Tony Montoya Western Area Power Administration COO Vice President, Finance Stuart Wevik Black Hills Corporation VP, Utility Operations Secretary Vice President, Vital Issues Richard PeĂąa CPS Energy Sr. VP, Energy Development Vice President, Member Services Mike McInnes Tri-State Generation and Transmission Assn. Sr. VP, Production

Doug Bennion PacifiCorp VP, Engineering Services & Capital Investment

Mike Hummel SRP Associate General Manager

Tim Brossart Xcel Energy VP, Construction Operations & Maintenance Mike DeConcini UniSource Sr. VP, COO

Mike Morris Zachry Holdings, Inc VP, Business Development, Engineering Pat Themig PNM Resources VP, Generation

Scott Fry Mycoff, Fry & Prouse LLC Managing Director Jon Hansen Omaha Public Power District VP, Energy Production & Marketing

Rest Easy.

Tom Kent Nebraska Public Power District VP & COO

Rick Putnicki RMEL Executive Director

www.RMEL.org Published Spring 2012 Published For: RMEL 6855 S. Havana St, Ste 430, Centennial, CO 80112 T: (303) 865-5544 F: (303) 865-5548 www.RMEL.org Electric Energy is the official magazine of RMEL. Published three times a year, the publication discusses critical issues in the electric energy industry. Subscribe to Electric Energy by contacting RMEL. Editorial content and feedback can also be directed to RMEL. Advertising in the magazine supports RMEL education programs and activities. For advertising opportunities, please contact Deborah Juris from HungryEye Media, LLC at (303) 883-4159. Pu b l ish ed by:

Westwoodâ&#x20AC;&#x2122;s solutions support the siting, design, and construction of electric transmission and energy projects. With offices and professional registrations across the U.S., we are able to service projects almost anywhere. Put your project in our hands. At the end of the day, you will rest easy.

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2012 spring conference

Maximize Your Training Budget at RMEL’s Spring Conference Join 300 members of RMEL’s trusted community to learn, network and discover solutions at RMEL’s Spring Management, Engineering and Operations Conference, May 20-22, 2012 in Omaha, NE.

f you are managing people or projects, engineering, planning or operating systems in the electric utility industry, this conference is for you. The Spring Management, Engineering and Operations Conference has been a tradition since RMEL’s early beginnings. Known for providing outstanding continuing education and networking opportunities, this conference is a must attend event for engineering, operations and management personnel in the electric energy industry. With 30 presentations, this conference covers issues in generation, transmission, distribution, safety, customer service, human resources and other management topics. The timely topics and breakout structure of the conference allows attendees to customize their education experience to focus on presentations and resources that address their needs. Ample time is also provided to network with industry peers and visit with exhibitors. The educational program will begin on Monday with a general session presented by Kimball Rasmussen, CEO, Deseret Power. Kimball will discuss ways to communicate a rational look at climate change, green jobs and renewables. Utilities face many regulatory impacts in meeting targets and requirements to install renewable energy. But many questions remain unresolved. Will replacing fossil fuels with wind and solar make an appreciable reduction in carbon emissions? Can we expect millions of green jobs? Is wind a real contender to reduce CO2? This fact-based presentation will attempt to answer these questions with a rational look at the issues. The next general session, on Tuesday morning, will focus on issues and challenges from the FCC’s Pole Attachment Order. Thomas B. Magee, Partner, Keller and Heckman LLP, will analyze the numerous issues and challenges being faced by electric utility pole owners after the Federal Communications Commission’s decision last year to dramatically revise pole attachment regulations to the detriment of electric utilities. The FCC’s Pole Attachment Order establishes make-ready deadlines, lowers pole attachment rates, imposes FCC jurisdiction over the “joint use” relationship between electric utility and telephone company pole owners, and imposes other operating constraints, all in a misguided effort to promote broadband services. Along with these general session presentations, the event features educational breakout sessions in three tracks: generation; transmission and distribution; and management. The slate of generation track presentations will guide

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attendees through topics like environmental regulations, nuclear energy, modern concepts in makeup water production, coal-fired to combined cycle repowering and pipeline repair technologies. One of the presenters, Gary Ruhl, Manager Technical Services, Omaha Public Power District, will discuss how the utility dealt with unprecedented flooding at its facilities on the Missouri River. With its Fort Calhoun Nuclear Station already in outage and fighting to stay dry, the 1400MW from OPPD’s Nebraska City Station became critical to avoid rolling blackouts in southeast Nebraska including the Omaha area. Look forward to details on distributed generation, layered intelligence for the distribution grid, taking the guesswork out

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of aged underground decisions, large-scale medium voltage power protection and power availability in the transmission and distribution track. A presentation from Steven C. Cobb, Director, Transmission Planning, SRP, will discuss FERC Order 1000’s impacts to transmission planning and cost allocation. The Order specifically requires FERC jurisdictional Transmission Providers to amend their Open Access Transmission Tariffs (OATT) to participate in a regional transmission planning process. This presentation will provide an overview of the Order and describe the approach Transmission Providers in the Western Interconnection are taking to comply with it. The third track of presentations, focused on management, covers the gamut of high-level challenges faced by managers throughout the utility industry, including ways to communicate with the customer of the, data capture and security, aging workforce, transformation of the coal fleet, managing safety through leading indicators and renewable integration. John Lescenski, Manager, Generation Engineering & Technical Services, Generation Strategy, NV Energy, will discuss NV Energy’s strategy for determining realistic retirement dates for generating plants. In the 2006, the Public Utilities Commission of Nevada (PUCN) directed Nevada Power Company (now NV Energy) to develop a process to establish life span estimates for its production equipment. The Life Span Analysis Process (LSAP) was established using information from numerous sources including other utilities, state public utility commissions, large industry research organizations, a major industry consulting firm, and existing internal procedures. This presentation will provide an introduction to the LSAP and provide several case studies where the LSAP was used to determine generation lifespans. This event offers something for every person in the utility industry, whether you need to make the right contacts or find

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the right answers. Utilities of all types of ownership participate including IOU, G&T, municipal, cooperative and others. Vendors of all types are valued participants in the conference and community dialogue to improve operations and enhance customer service.

Golf Outing to Benefit RMEL Foundation Scholarships Enjoy a golf outing at Quarry Oaks Golf Club on May 20th. The format will be a four-person scramble and proceeds will benefit the RMEL Foundation scholarship program.

Guests and Spouses are Welcome Bring your guest to the 2012 Spring Management, Engineering and Operations Conference. If your guest registers for the full conference, they are registered for all meals and the Champions Receptions on Sunday and Monday. If they register for an individual day, they will be registered for meals and the Champions Reception for that day only. Guest registration prices simply cover the cost of meals. All attendees will receive a continuing education certificate. The certificate provides professional development hours based on participation. For more information and to register for the Spring Management, Engineering and Operations Conference, go to www.RMEL.org or call (303) 865-5544.

OMAHA, NE May 20-22, 2012

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FOCUSED ON OUR CUSTOMERS, POSITIONED FOR THE FUTURE. After a major storm knocked out power in their service area, Vermont Electric Cooperative pushed to build a state-of-the-art “smart grid” system. VEC needed a strong financial partner for this project – and found one in CoBank and Farm Credit Leasing. The new system dramatically reduced the length of power outages and made it much easier to manage overall power supply. In 2011, VEC was the winner of Power magazine’s first-ever Smart Grid Award. CoBank’s commitment to serving rural America has never been stronger than it is today. We remain dedicated to the rural energy industry and are proud of the strength and spirit of our customers.

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COCONINO

YAVAPAI

NAVAJO

SunZia Southwest Transmission Project

SOCORRO

LEGEND Sources: Land Ownership U.S. Fish and Wildlife Service

AZ BLM 2009 Bureau of Land Management AZ State Land Department and ALRIS 2008 U.S. Dept. of Defense ESRI StreetMap 2008, Mimbres RMP 1989 NM BLM 2009, SocorroRange PRMP 2009 McGregor Withdrawal Tri-County RMP 2009 National Park Service POWERmap, powermap.platts.com U.S.D.A. Forest ©2009 Platts, a Division of theService McGraw-Hill Companies USGS, EPG, Inc. 2010 U.S.D.A Other

U.S. Bureau of Reclamation Indian Reservation A PA C H E StateTrust Land Local or State Parks

Arizona New Mexico

Land Ownership and Jurisdiction

Private/Other

Project Location

G I L ANew Mexico

Arizona

M A R I C O PA

Flagstaff

Base Features

Albuquerque

Project0 Features 5 10

Phoenix

ce Features

ty ver/Stream

State Highway

ke/Reservoir

Interstate

ban Area

Railroad

County Boundary

! !

#0 #0

Study Area - April 2010 Substation Siting Area

Alternative Routes - Midpoint to SunZia East

Jurisdictional Boundary Wilderness Area

2B 2C 2D

May 12, 2010

Wilderness Study Area (WSA)

Reference Features

Proposed Substation Existing Substation !

Pipeline (Diameter 6”+)

City River/Stream

State Highway

345kV Transmission Line 230kV Transmission Line

Lake/Reservoir

Interstate

138kV/161kV Transmission Line 115kV Transmission Line

Urban Area

Railroad

500kV Transmission Line

U.S. Highway

C AT R O N

Utilities

Contour Interval 200 feet

State Boundary !

SunZia Proposed Miles Route - Sept. 8, 2008 Alternative Route Segments

Las Cruces

Tucson

U.S. Highway

GRAHAM

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SIERRA GREENLEE

PINAL Proposed Route (2008)

GRANT

Proposed Route (2008)

Lordsburg

LUNA

COCHISE

PIMA

HIDALGO

New Mexico Mexico

S A N TA C R U Z

SunZia Southwest Transmission Project:

SunZia Southwest Transmission Project

LEGEND

Land Ownership

Flagstaff

Phoenix Tucson

U.S. Bureau of Reclamation

McGregor Range Withdrawal National Park Service U.S.D.A. Forest Service U.S.D.A Other

Indian Reservation StateTrust Land

Bringing Resources

Project Location Arizona

U.S. Fish and Wildlife Service

Bureau of Land Management U.S. Dept. of Defense

Land Ownership and Jurisdiction

Local or State Parks Private/Other

LEGEND LEGEND SunZia Southwest SunZia Southwest Transmission Transmission Project Project Land Ownership Land Ownership

New Mexico

Base Features

Albuquerque

Bureau of Land Management Bureau of Land Management

Las Cruces

#0 #0

Alternative Route Segments

Alternative Routes - Midpoint to SunZia East 1 1A

west roject

LEGEND

Land Ownership

Project Location Project Location

Arizona Flagstaff

2B 2C 2D

NewArizona Mexico Flagstaff Albuquerque

2E Phoenix

Albuquerque

McGregor Range Withdrawal National Park Service

Las Cruces

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U.S.D.A. Forest Service U.S.D.A Other

1 1A

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2 2A

Mexico

Urban Area

State Hig

U.S. High

Interstate Railroad

Sources: Utilities

#0 #0

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Utilities

#0 #0

1 2B 2C 1A 2D 2 2E 2A

3 2B 4 2C 5 2D 2E

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\\172.16.5.48\epg\epg\geospatial\projects\sunzia\sunziasw\mxd\phx_gis_02\study_area_mar_2010\ownership_20100511_2008alts.mxd \\172.16.5.48\epg\epg\geospatial\projects\sunzia\sunziasw\mxd\phx_gis_02\study_area_mar_2010\ownership_20100511_2008alts.mxd (201005120848) (201005120848)

Base Features

Study Area - April 2010

! !

Proposed Substation Existing Substation !

Pipeline (Diameter 6”+)

City River/Stream

State Highway

345kV Transmission Line 230kV Transmission Line

Lake/Reservoir

Interstate

138kV/161kV Transmission Line 115kV Transmission Line

Urban Area

Railroad

500kV Transmission Line

County Boundary State Boundary

U.S. Highway !

Alternative Routes - Midpoint to SunZia East

#0 #0

SunZia Proposed Route - Sept. 8, 2008

e l e c tAlternative r i c Route e n eSegments r g y | s p r i n gSubstation 2 0 1 2Siting Area

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buquerque

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Alternative Routes Alternative - Midpoint Routes to SunZia - Midpoint East to SunZia East

Base Features Base Features Project Features Project Features

Phoenix

Reference Features

Lake/Reservoir

New Mexico

345kV Transmission Line Substation U.S.D.A.Siting ForestArea Service U.S.D.A. Forest Service Local or State Parks Local or State Parks 230kV Transmission Line U.S.D.A Other U.S.D.A Other Private/Other Private/Other Existing Substation 138kV/161kV Transmission Line Pipeline (Diameter 6”+) 115kV Transmission Line !

U.S. Fish and Wildlife Service Bureau of Land Management Las epg\geospatial\projects\sunzia\sunziasw\mxd\phx_gis_02\study_area_mar_2010\ownership_20100511_2008alts.mxd (201005120848) Cruces Tucson Tucson U.S. Bureau of Reclamation U.S. Dept. of Defense

ip and on

U.S. Fish and Wildlife U.S. Fish Service and Wildlife Service

Dept. of Defense U.S. Dept. ofUtilities Defense U.S. Bureau of Reclamation U.S. Bureau of Reclamation Land Ownership Land Ownership and and U.S. McGregor Range McGregor WithdrawalRange Withdrawal Indian Reservation Indian Reservation 500kV Transmission Line SunZia Proposed RouteJurisdiction - Sept. 8, 2008 Jurisdiction Study Area - Park AprilService 2010 National National Service StateTrust Land StateTrust Land By: TomParkWray, Project Substation Manager, SunZia Southwest Transmission Project Proposed

Project Features

Jurisdictional Boundary Wilderness Area Wilderness Study Area (WSA)

TO R R A N C E

Project Definition

SunZia is a 500 kV transmission project consisting of approximately 500 miles of two separate 500 kV alternating current (AC) transmission lines in mainly parallel corridors, including up to five substations. These EHV facilities will be constructed between south-central New Mexico and south-central Arizona (see SunZia Project Study Area Map). In addition to originating and terminating substations, three intermediate subs are planned to interconnect SunZia to the existing 345 kV transmission grid in both states, and to allow installation of series compensation. The project also includes the option to construct and operate one of the 500 kV circuits as a bipolar direct current (DC) facility, depending on the demand for transmission capacity over SunZia’s path. SunZia’s AC configuration will create 3,000 MW of transfer capacity, or 4,500 MW under the hybrid AC/DC option. The project is owned by MMR Group and its wholly-owned subsidiary, Southwestern Power Group, Salt River Project, Tri-State Generation & Transmission Assn., Tucson Electric Power and ShellWind Energy, Inc. Southwestern Power Group of Phoenix is responsible for project management of SunZia’s development activities, including siting, permitting, licensing, preliminary engineering and design and environmental studies. The owners will also be directly involved with right-ofway acquisition, final engineering and design, procurement, construction and operation of the project.

2B 2C

LINCOLN

5 Proposed Route (2008)

OTERO

New Mexico Texas

DOŇA ANA

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to Load O

County Boundary

State Boundary

hway !

Jurisdictional Boundary Wilderness Area

Regional Planning Origins

Sources:

Reference Features City River/Stream

State Highway

Lake/Reservoir

Interstate Railroad

Urban Area

County Boundary

U.S. Highway

State Boundary !

SunZia was conceived to provide a cost-effective transmission alternative for stranded renewable energy resources, particularly wind and solar generation in New Mexico and Arizona, for delivery to markets in California, Arizona and Nevada. The high-quality 10 20 30 40 wind energy resource in central New Miles Mexico has been estimated at over Contour Interval 200 feet 10,000 MW. MayThe 12, original 2010 concept for the project emerged in 2006 from the transmission planning efforts of the Southwest

AZ BLM 2009 AZ State Land Department and ALRIS 2008 10 20 30ESRI StreetMap 40 2008, Mimbres RMP 1989 NM BLM 2009, Socorro PRMP 2009 Tri-County RMP 2009 Miles POWERmap, powermap.platts.com ©2009 Platts, a Division of the McGraw-Hill Companies Contour Interval 200 feet USGS, EPG, Inc. 2010

May 12, 2010

Wilderness Study Area (WSA)

n Line

ghway

Sources:

Jurisdictional Boundary Wilderness Area Wilderness Study Area (WSA)

Area Subregional Transmission Planning Group (SWAT). SWAT’s assigned subcommittees conducted power flow studies to find ways to increase total transfer capacity and mitigate transmission congestion between southern New Mexico and southern Arizona. With primary EHV interconnections between the two states being associated with large base load generation in the Four Corners area (e.g. WECC Paths 22, 23 and 48), along with increasing load growth in the southern areas of both states, the need to improve power flow capability over WECC Path 49 became increasingly important to regional reliability. The Department of Energy’s National Electric Congestions Study (2009) confirmed this to be an area needing additional transmission capacity.

Searching for Partners In an effort to attract investors and development partners, Southwestern Power Group initiated the equivalent of an “open season” in December 2006 seeking participants interested in jointly developing the SunZia Project. Solicitations of interest went out to over 100 parties involved in transmission planning, project development and operations. By January 2007, 34 formal responses had been received, with 16 indicating strong interest to participate in the project’s development as owners. Following a series of organizational meetings beginning in February of that year, a smaller group of 12 parties continued to discuss investing in the project. By the end of April 2008 the project sponsor group had formed and consisted of five owners that included load-serving utilities, an equity investment group, a major wind energy company and Southwestern Power Group. Since that time, the owner group has changed but continues to reflect a very similar blending of interests and participation. The development of SunZia has proceeded in an orderly manner under a board of directors and a project management company, Southwestern Power Group, which oversees all of the project’s preconstruction development activities, work scope, schedules and budgets. w w w. r mel .o rg

Obtaining the Permits SunZia’s interstate nature and the fact that its proposed and alternative alignments traverses lands managed by the federal government ensured that it would be the subject of an examination under the National Environmental Policy Act (NEPA). SunZia filed an SF-299 ROW application with the Bureau of Land Management (BLM) in September 2008. In late May 2009, the BLM published a Notice of Intent in the Federal Register to announce that an environmental impact statement would be initiated. Since then, preparation of the EIS has included over a year of scoping, public meetings, evaluation of comments from the public and the commitment from 13 Cooperating Agencies (at state and federal levels) to review the EIS. Environmental resource impact studies, field inventories, review of general plans and land use plans, resource management plans and consultation activities, particularly with Native American Tribes as required under Section 106 of the National Historic Preservation Act of 1966 (16 USC 470 et. seq.), as amended, have all been underway. The BLM estimates that the Draft EIS will be available for public review and comment by mid-April. This review period is expected to last at least 90 days and will be followed

by analysis of comments submitted to the BLM, leading up to compilation and issuance of a Final EIS, hopefully, sometime this summer. A Record of Decision will then follow the publication of the availability of the Final EIS. State siting permits are also required for the project in both New Mexico and Arizona. Although those separate processes will not likely begin until the Final EIS is completed, SunZia should have all of its siting permits obtained by the end of the first quarter of 2013. Construction activity will begin when: • Rights-of-way and land leases are completed; • Design and engineering of the lines, towers and substations are completed; • SunZia’s Construction, Operations and Maintenance Plan is completed, approved and filed with applicable state and federal agencies; • The ECP contract has been awarded and procurement activities are completed; • Construction and term financing facilities are fully syndicated and undertakings finalized; and • N otice(s) to Proceed are issued by the BLM and state trust land agencies in both states.

Rapid Rapid Response Response Team Pilot Projects TransmissionLines Lines Transmission Name Project Name Boardman-Hemingway Boardman-Hemingway CAPX 2020 Hampton-Lacrosse CAPX 2020 Hampton-Lacrosse Cascade Crossing Cascade Crossing

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Casc

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Susquehanna-Roseland

TransWest Express TransWest Express

ay st We

ss pre

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175

350 Miles

Last updated 9/20/2011

SunZia

Ü Source: BLS Current Population Survey, 2008.

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SunZia estimates a construction period of about thirty months per 500 kV circuit and related terminating and interconnecting substations. Earliest in-service date for the initial 500 kV transmission facility is estimated at summer 2016.

FERC Order and Finding Customers SunZia obtained a Declaratory Order from the Federal Energy Regulatory Commission in May 2011. The Order provides the commercial basis for regulated activity regarding the merchant-owned transmission capacity in the project. Capacity ownership attributable to the utilities in SunZia’s ownership group will be made available through these

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utilities’ existing open access transmission tariff. Fifty percent of the merchant transmission capacity will be allocated through an anchor tenant process and bilateral negotiations. The remaining 50% of merchant transmission capacity will be made available through capacity auctions held in open season solicitations. SunZia’s merchant owners are negotiating anchor tenant agreements at this time and anticipate that this activity will extend into the summer of this year.

Speeding Up the Process In an ongoing effort to help bring interstate transmission projects on line more quickly, while reducing the time requirement and uncertainty associated with the effort, the Obama Administration initiated the Rapid Response Team for Transmission (RRTT) last October. In recognition of the need to modernize an aging high voltage power grid, SunZia and six other projects, most of them in the West, were identified as pilot projects worthy of increased effort to hasten the permitting and licensing processes at the federal level (see RRTT Pilot Projects Map). “These projects will serve as pilot demonstrations of streamlined federal permitting and increased cooperation at the federal, state and tribal levels”, and that these projects represent the “… kinds of job-creating projects that the President wants to see across the country...”, were among statements in the press releases that characterized the emphasis the Administration placed on this new policy imitative. Recent focus by the RRTT has been on finding ways to improve communication and coordination between federal and state facility siting authorities and processes to avoid duplica-

tion of the fact-finding effort and the possibility of project-killing federal and state siting authorizations that are inconsistent. SunZia has seen the efforts of the RRTT pay off in the form of more efficient handling of interdepartmental communications and expedited treatment of necessary consultations among federal agencies during the course of the NEPA process currently underway.

action by industry peers in the form of technical studies and rigorous examination by power industry participants. Regional planning organizations in the Western Electricity Coordinating Council are the best forums for this necessary pre-filing activity and should be every transmission projectâ&#x20AC;&#x2122;s first stop on its long and challenging road for bringing resources to load. Tom Wray is the Project Manager for the SunZia Southwest Transmission Project. Wray has worked in the electric power industry in the western United States for 40 years and is a founding partner in the energy project development firm of SouthWestern Power located in Phoenix. Tom can be reached at twray@southwesternpower.com.

Projects in the West Take More Time Given the abundance of lands in Indian Country and federally-managed real estate in the western US, linear projects such as high voltage transmission facilities will almost always trigger the need to comply with NEPA. Project development must manage the nexus between this complex effort of federal review and state siting requirements, with both patience and care. A complete NEPA Record, whether assembled by the lead federal agency to support an environmental assessment or a full-blown environmental impact statement, will prove invaluable during the state siting process. State public utility commissions or other state siting authorities will likely find the availability of a detailed examination of environmental impacts and project purpose and need, which is also characterized by a complete scoping and public involvement effort, a welcome record for issuing complementary state-level decisions for the project. The existence of a thorough analysis of reasonable and feasible alternatives to the applicantâ&#x20AC;&#x2122;s proposed action will similarly be regarded by state siting authorities as evidence of a thorough vetting of the projectâ&#x20AC;&#x2122;s application. Aside from the complexities of facility siting in federal and state jurisdictions, there is no substitute for a complete review of the proposed w w w. r mel .o rg

Integrating Largeinto the

Electrici

Integrating large scale renewable generation into the electricity grid has the potential to replace a significant share of coal-generated electricity with cleaner sources of energy. And, as the pace and scale of new energy technology development increases and consumer demand rises, utilities are seeking to understand the impacts of large scale renewable integration on the grid. 18

elec tric energy | spring 2012

-Scale Renewables

ity Grid

By David Mooney, Center Director, Electricity, Resources & Buildings Systems Integration, National Renewable Energy Laboratory

any of these clean energy technologies have unique operating characteristics that will necessitate a transformation of how existing electricity systems are configured and operated. Operational and infrastructure concerns rank high as renewable electricity standards and incentives have jump-started deployment of new energy technologies and the market for grid enabled vehicles is ramping up. The new Energy Systems Integration Facility (ESIF) at U.S. Department of Energy’s (DOE) National Renewable Energy Laboratory (NREL) is aimed at tackling the challenge of keeping the power grid running reliably while at the same time introducing a host of new technologies into an already complex

system. As the nation’s only laboratory solely dedicated to advancing renewable energy and energy efficiency, NREL also is looking for partnerships with utilities, industry, academia, and government research institutions to help examine pathways for integrating large scale renewable generation. According to the Energy Information Agency Energy Outlook 2011, electricity generation from renewable sources is expected to grow in response to renewable fuel standards, statelevel renewable electricity standards and federal tax credits. Triggered by growing concerns about climate change, widespread adoption of state-level renewable portfolio standards (RPSs) and incentives has occurred over the past few years. An w w w. r mel .o rg

RPS is a regulation enacted as a state policy that requires utility generation portfolios to provide a certain percentage of their electricity generation from renewable energy sources. As of May 2011, 29 states and the District of Columbia had set target percentages and dates for the integration of renewable sources of energy. Renewable resource availability varies widely across the regional climates and geographies of the United States; some states are better endowed with certain renewable resources than others; thus renewable energy deployment growth spans different technologies. Most state RPS laws and regulations include solar, wind, geothermal, and biomass in their renewable portfolio standard legislation. Targets usually are set low and gradually increase annually. States and utilities both stand to benefit in many ways long-term as the percentage of renewable sources grows, but not without overcoming some of the most complex and challenging issues of our time.

Utility Challenges

Determining how to manage the increased variability and uncertainty from variable generation is the principal challenge in large scale integration.

Unlike conventional electricity generation from fossil fuel plants, generation from variable renewable sources such as wind and solar are not easy to control and require significant changes in the way a power system is planned and operated. To add to the challenge of variable resource planning and operations, delivery at both the transmission and distribution level is impacted by the often remote nature of the best renewable resources.

Variable Renewable Generation Variable renewable generation (VGR) outputs from solar, wind, and other new technologies cannot always be controlled and scheduled to respond to the variable consumer demand for electricity. The crux of the renewables integration challenge can be captured in the recognition that the introduction of large amounts of these technologies introduces variability and uncertainty in generation beyond the existing variability and uncertainty that is inherent in the load. Just as we know the load will vary with time throughout the day, but weâ&#x20AC;&#x2122;re uncertain just exactly how much, wind and solar generators will also vary throughout the day, but there is uncertainty in just how much the change will be over the timeframes . Determining how to manage the increased variability and uncertainty from variable generation is the principal challenge in large scale integration. Variability on both sides of the supply/demand equation creates a new paradigm for utility operators. The way in which operators handle these new challenges can dramatically impact the

elec tric energy | spring 2012

reliability and efficiency of operating a power system with large amounts of variable generation. As is well known, traditional electric power systems use a combination of generator technologies to meet the systemâ&#x20AC;&#x2122;s total electricity demand. In the United States, a large fraction of total demand is met by baseload plants. These plants are typically in excess of 500 MW each and generate electricity using steam created by coal or nuclear fuels. The daily variations in demand are met largely by cycling plants, typically smaller coal plants, steam or gas turbine plants fueled by natural gas, and hydroelectric plants. Operating constraints from conventional generators may make it difficult to respond quickly enough to the additional variability that VRGs contribute to system operating requirements. Because VRGs influence the amount and type of generation that needs to be available to serve the remaining load, and because of the physical start-up, shut-down, and ramp constraints of some conventional generation technologies, one very important tool to incorporate in the control room is an accurate forecast of the VRG availability over a one to three day operating horizon. Advanced forecasting techniques need to continue to be developed and variable resource forecast that are converted to power plant output need to be incorporated into day-to-day operational planning and realtime operations. Over time, the composition of the non-VRG generation fleet may change so that it becomes more flexible. In addition, additional demand-response, to the extent that it is available, can help efficiently integrate VRG sources.

Grid-level Energy Storage Because of the variability and uncertainty of renewable energy sources and electricity demand, there has been an increased call for the deployment of energy storage as an essential component of future energy systems that use large amounts of variable renewable resources. Excess generating capacity available during periods of low demand can be used to energize an energy storage device. The stored energy then can be used to provide electricity during periods of high demand or high variability, helping to reduce power system loads during these times. In addition to meeting the predictable daily, weekly, and seasonal variation in demand, utilities plan for unforeseen increases in demand, losses of conventional plants, transmission lines, and other contingencies. But rapid deployment of storage devices is held back by concerns over technology risk, costs, and financial complexity. Recent studies show that considerable VRG penetrations in excess

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of 20 percent on an annualized basis can be accommodated without the need for new storage on the system. Storage will likely be a key part of the solution in the long term, however, and research is currently underway to determine how to best value and integrate storage into the system.

Transmission Renewable energy resources such as wind and solar often are far from load centers and from existing transmission lines. This creates challenges because transmission lines are difficult to site and build, often taking seven to 10 years between the time the line permitting process begins and the time it is energized. Large-scale renewable generating plants often can be sited and built in less than a yearâ&#x20AC;&#x2122;s time. This creates a sequencing problem because it is difficult to obtain financing for a generation project unless a demonstrated transmission path exists to deliver the energy to load, and building transmission to as-yet undeveloped generation sites is difficult because cost recovery of investments to deliver an uncertain energy supply is hard to obtain. While building plants with lower-capacityfactor resources closer to load can mitigate transmission siting challenges, studies have shown that it can be more cost effective to build out higher capacity resources with transmission simply because capacity is more expensive than transmission.

Distribution Currently, VRG technologies have realized only low levels of penetration in the distribution system and have been viewed as more demand reduction technologies than generation technologies. At low penetrations, distributed renewable energy systems are serving only local loads, and are not treated as resources to the larger systems. However, in high penetration scenarios, distributed generation systems will begin to create two-way power flow and impact power flow at the transmission level, which will in turn impact how the transmission system is operated as well as dispatch planning and operations for central generation plants. This new model of distribution grid functionality will require multiple changes in the way the system operates, and the way distributed VRGs interact with the grid. VRG sources are currently considered passive players from the grid perspective. To realize their full potential, advanced planning and control technologies, along with new codes and standards, will need to be developed to allow these sources of generation to safely and effectively interact and interoperate with other grid technologies and resources, such as load balancing and storage.

Integration Studies When considering solutions to VRG integration challenges, it is helpful to review the significant work that already has been

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elec tric energy | spring 2012

WORK T A H T IONS T U L O RIC S ELECT

undertaken in this area. Recent years have seen a substantial foundation of work begun in efforts both to identify integration issues and to begin to develop solutions. To date, wind energy technology has been deployed and integrated into the power system in greater quantities than other VRG resources. There is, therefore, more knowledge and experience integrating wind than any other technology. As previously explained, the primary challenges associated with integrating wind result from its variability and uncertainty. Careful simulation and analysis help bring to light the challenges that will need to be addressed to maintain electricity system reliability under highly variable sources such as wind and solar. Once such study 他 one of the largest regional wind and solar integration studies to date 他 is the Western Wind and Solar Integration Study (WWSIS). The WWSIS investigates the operational impacts and economics of integrating large-scale wind, photovoltaics, and concentrating solar power into the power system in the western United States. Sponsored by DOE and run by NREL, WWSIS was conducted by a team of researchers in wind power, solar power, and utility operations, with oversight from technical experts in these fields. A technical review committee, composed of members of WestConnect utilities, western utility organizations, and industry and technical experts, reviewed technical

results and progress and a broader stakeholder group met to ensure study direction and results were relevant to western grid issues. The report can be found at www.nrel.gov/docs/ fy10osti/47434.pdf. Key findings in this study indicate that it is feasible to integrate 30 percent wind and 5 percent solar into the WestConnect footprint and reliably operate that system (with no additional storage) if a number of operations and market reforms are assumed. Follow-on work to that study is looking at the emissions and O&M impacts on the conventional generation fleet of that level of penetration. NREL, along with multiple partners, continues to aggressively research and analyze issues related to energy systems integration while developing methodologies to cost-effectively incorporate greater penetrations of renewable and demand technologies. David Mooney, Director of the Electricity, Resources, and Building Systems Integration Center National Renewable Energy Laboratory, is currently leading efforts to identify and address technical issues associated with the large-scale deployment and integration of renewable and efficiency technologies into the existing energy infrastructure. In this capacity, he leads 200 researchers conducting $120M in R&D annually. David can be reached at david.mooney@nrel.gov.

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Finding the

‘Sweet By Steve Narolski, Program Manager-Veg. Mgmt. & Access Maintenance

Spot’

with BPA’s Vegetation Management Program

Utilities small and large face similar issues with their power lines - waking up in a cold sweat when the wind blows with gale force, wondering if their system will hold or whether wind-blown trees are about to cause an outage. The massive Blackout that crippled the United States’ eastern grid into Canada in 2003 was caused, in part, by trees growing into power lines. Resulting regulations enhanced clearance distances between conductors and nearby vegetation through the North American Electric Reliability Corporation’s FAC-003-1, essentially describing what a given utility’s transmission vegetation management program should afford or look like.

elec tric energy | spring 2012

History Bonneville Power Administration (BPA) is a federal entity within the US Department of Energy. The agency provides bulk energy throughout the Pacific Northwest to public utilities, private companies, and individual consumers. Its mission as is to create and deliver the best value for customers, stakeholders and constituents as it acts in concert with others to assure the Pacific Northwest: • An adequate, efficient, economical and reliable power supply; • A transmission system that effectively integrates and transmits power from federal and non-federal generat-

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ing units, provides service to BPA’s customers, supports interregional interconnections, and maintains electrical reliability and stability; and • Mitigation of the Federal Columbia River Power System’s impacts on fish and wildlife BPA manages over 15,000 miles of high-voltage transmission lines using approximately 19,000 miles of access roads to deliver power in eight states of the Northwest. Most recently, BPA incurred two vegetation-related sustained outages in 2007 and 2008 respectively. These events triggered an intense internal audit and external review by the Western Electricity Coordinating Council (WECC). One outcome was the need for BPA to enhance how it manages and maintains its rights-of-way system wide. Prior to these outages, vegetation maintenance funding resembled a sine wave, with marked peaks and valleys. Identifying an optimal funding level, or ‘sweet spot’ which strikes a balance between cost and return on investment, escaped forecasters.

Current State & Review During the late 1990s though early 2000s, BPA partnered with Oregon State University on research projects assessing how to manage power line corridors towards establishing early succession or low-growing plant communities. The agency decided to resurrect this research and start applying the findings through maintenance in a more thoughtful manner. Forty-four months have passed since its last vegetationrelated sustained outage, the longest stretch in the BPA’s history. During the interim, BPA has invested significant effort to identify and remove incompatible vegetation within its power line easements. Part of this success came from experimenting with existing and new technology to identify the state of vegetation-to-conductor clearance along rights-of-way. A formal review of the different vegetation inspection

elec tric energy | spring 2012

techniques BPA utilized in the months following the 2008 outage was conducted to determine which were the most accurate and most cost-effective. The inspection techniques BPA used to assess clearance between conductors and vegetation included: • Transmission Line Maintenance (TLM) ground patrols • Aerial patrols with helicopters • Third-party contractors ground patrols • Light Detection and Ranging (LiDAR)

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LiDAR led the list as the most accurate technique, and also the most costly, for the initial classification. One of the factors driving the cost of capturing accurate data is the number of circuits within a corridor. Sampling single circuit rights-of-ways is almost twice as expensive as multi-circuit corridors. Future data capturing, especially when using the same vendor, was projected to realize a saving of 40-50 percent in subsequent cycles. Aerial patrols with helicopters using trained, professional observers were the least costly but the most inaccurate for most vegetative clearance issue reporting. Presently, LiDAR data is collected on approximately 20 percent of BPA’s system annually. The agency samples the highest growth sites, west of the Cascade Mountains every three years, and the slower growing sites east of the Cascades once every five-eight years. The results of the LiDAR sampling have supplemented observations noted from ground patrols and aerial helicopter patrol reconnaissance. This system of overlapping

patrols, along with assessments BPA’s natural resource specialist perform on-site while setting up or conducting their normal work, provides quality control audits while double-checking for transmission corridor health and clearance issues.

Analysis and Finding the ‘Sweet Spot’ BPA’s Vice-President of Transmission, Robin Furrer, coined the term, ‘sweet spot’, to pinpoint the right funding level to protect the integrity and reliability of BPA’s transmission system with an acceptable amount of risk. In defining BPA’s ‘sweet spot’, agency leaders determined there could be no future vegetation-caused sustained grow-into outages, and those resulting from off-ROW damage caused by major storms would be kept to an acceptable, nominal level. Such an intersection of costs and gains would measure where the funding level for maintenance activities provides the greatest return, and when adding more funding yields would result in diminishing returns. BPA’s vegetation management and access road maintenance programs have evolved from reactive to proac-

Inspection Comparison Accuracy Percent Accuracy 100% 80% 60% 40% 20% 0% Aerial Reg

Aerial Veg

elec tric energy | spring 2012

TLM

Private Contractor

Lidar

tive, while striving to find that ‘sweet spot’. This evolution required both transparency and better accountability from all of BPA’s interactive divisions. The agency had to develop new tools to track and analyze all aspects of this program, identifying opportunities for improvement, and implementing best management practices. Today, BPA tracks project costs against projections for current year’s work. We also report and measure out-year projects being developed and packaged for bidding in order to give contractors advance notice. This allows the agency’s business partners to forecast their potential workloads and plan for work that would fill their upcoming year. To find the ‘sweet spot’, BPA had to first analyze vegetation inspection practices, before the program could move forward. An internal analysis of the types of vegetation inspection techniques used during the 2009 fiscal year showed that although aerial patrols were the most cost-effective, they yielded the lowest level of accuracy. LiDAR was proven to be the most accurate method, but also the most expensive. Project planning and bid awarding helped populate projected expense work-ups and demonstrated the program was adhering to its budget forecasts. While somewhat basic, this exercise

would indicate the trending towards the elusive ‘sweet spot’. Once BPA’s projects are awarded, the projects are managed using the cost performance index (CPI), the scheduled performance index (SPI), and the critical ratio (CR). The CPI ratio aims to determine how the project is progressing by measuring the total amount spent against the allocated budget. It is expressed as a ratio of the budgeted cost of work performed (BCWP) to the actual cost of work performed (ACWP). If the BCWP is equal to the ACWP, the ratio is one, indicating that the project is following its budget effectively. A CPI ratio lower than one means the budgeted costs are lower than the actual costs. This indicates that the project is overspending. In a case where the CPI ratio is higher than one, it means that the project is actually saving money. The SPI is similar to the CPI only it measures the ratio of scheduled work as it compares to actual work performed. A SPI of less than 1.0 represents a project behind schedule. If the ratio is greater than 1.0, it is ahead of schedule. The CPI and SPI ratios are used in conjunction to determine the critical ratio of the project. The critical ratio is an important indicator of project health because it considers

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both the SPI and the CPI. In other words, CR considers both the budget as well as the schedule of the project, and is therefore an indicator of the overall status of the project. A critical ratio of greater than 1 is good and indicates that the project is proceeding well on track.

Future State BPA’s vision for the future state of its vegetation management and access maintenance operations is for these program to be right-funded. The agency will have found that ‘sweet spot’, allowing us to maintain most corridors in a sustainable

800.438.0790

cycle, with ROW conditions that ensure reliability and safety. Cycle- or mid-cycle applications of herbicides will help promote and maintain low-lying plant communities while reducing the presence of invasive, noxious, or undesirable plants. Future circuit patrols will be scheduled for maximum efficiency. One scenario could leverage increased annual LiDAR coverage to supplement ground patrols and reduce the amount of overlap between these inspection techniques. In the future, all data bases and related software programs would ‘talk’ to each other through a master software package. Paper tracking will be a thing of the past. All records, scope of work packages, and contractor invoicing will be electronic, with back-up data instantly available. This will be synchronized with the agency’s inclusive GIS. The total package may have a similar look and feed to proprietary software BPA developed in the past. This “one software to bind” will facilitate one-click report generation that can be accessed by any manager to produce needed reports at a moment’s notice. Ultimately, and most important, our future state will reinforce BPA’s ability to deliver on its mission to customers: safe and reliable service with no vegetation-related outages. Steve Narolski is program manager for Bonneville Power Administration’s vegetation management and access maintenance program. His professional licenses and certificates include a California-registered professional forester, a certified forester of the Society of American Foresters, an International Society of Arboriculture certified arborist with utility option, and a Tree Farms of America inspector. Steve can be reached at swnarolski@bpa.gov.

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The Art of

Residential Ratemaking By Jim Marshall, Manager, Jackson Thornton Utilities Consultants and Terry Mitchell, CPA, Principal, Jackson Thornton Utilities Consultants

elec tric energy | spring 2012

most reading this article know, public utilities providing electricity to retail customers are finding significant challenges in designing and setting retail rates. In fact, utilities haven’t had to face these types of challenges for the past two decades. From 1983 until 2000, electric cooperatives were able to maintain stable rates priced in the average range of approximately 6.3 cents per kilowatt hour (kWh) delivered to the customer. Evidence that changes are occurring is that retail rates have increased more than 39 percent for electric cooperatives since 2000. And as you also know, the challenges causing these price increases are many. Included among the most significant are: Wholesale price increases in electricity, driven by the costs of new generation and the dependency on other sources of energy with more volatility in price than that of coal. The need for infrastructure upgrades that are increasingly expensive. Little or no growth in retail loads and kWh sales. The social issue of creating more conservative and efficient uses of electricity by residential and retail customers. The desire of publicly elected boards (that have the responsibility of setting the rates) to assist their customers who have been challenged by these tough economic times. These challenges demand that the management teams and the boards of public utilities become proactive in the ratemaking process. It is imperative that rate setting policies be established and reviewed by the management teams along with the boards on an annual basis.

A Little History

To set the stage for the rest of this article, we want to give some history as it relates to the process of setting utility rates. The foundational process and the principles for such are found in the book, Principles of Public Utility Rates, by James C. Bonbright. In summary, the basic principles are: Revenue stability – rates should meet the total annual revenue requirements of the utility. Rates should be stable – changes in rates from year-toyear should not cause “rate shock.” Rates should be equitable – each rate class and the different users within the same rate class should pay their share (there should be no subsidies between or within classes). Rates should be fair – each class and customers within each class should pay based upon the costs incurred by the electric utility to serve each class (cost of service principles). Rates should be straightforward (simple) – rates should be designed so that the customer, given all the measures, could calculate their own bill just the same as the utility. Rates should be defensible – each rate should be free from controversies as to the proper interpretation and, ultimately, supported by the cost of service study.

Rates should be efficient – rates to each class and the

rate blocks for each class should be designed to discourage wasteful use of service while promoting the usage and demand for energy. Bonbright’s work lends strong support to the philosophy that prices must match cost to serve, both in terms of revenue requirements and to the rate design. In addition, Bonbright acknowledges a host of factors that influence the rate design process. The other factors are often referred to as a part of the philosophy of ratemaking and/or the social aspects of the ratemaking process. Thus, the ratemaking process demands considerable judgment and a balancing of various factors and interests. This is where the “art” of ratemaking comes into play. How do we take the black and white results of a cost of service study and meet the intangible goals of a utility’s decision makers? The effort becomes, in practice, closely tied to the goals and desires of the community.

Phases of the Ratemaking Process

Determine the annual revenue requirements of the utility Allocate the cost to serve each class based on how each class

uses the system – Demand – Energy – Customer Within each class determine “Fixed” vs. “Variable” expenses Rate Design The true cornerstone of the process is making sure the rates are fair and equitable. But the reality is that utilities must also be mindful of social and political concerns vs. cost of service alone. If you couple that with looming capacity restraints and related issues, you have the potential for a very tangled — and potentially political — mess.

But Here’s the Good News

One of the biggest challenges (and opportunities) utilities have is the availability of information to members. Residential customers are becoming more and more informed because of the availability of information. Smart meters have been game changers when it comes to information. That’s true transparency. What that means to utilities is that there is no longer an “average” residential customer. Now, rates can be designed accordingly per type of user. Bottom line, the more information utilities have, the more innovative they can be with rate redesign. Your consumers have a desire for options and alternatives when it comes to their rates and billing. Based on our experience, here are six residential options to consider: Prepaid Rate. Also known as “pay as you go.” Customers choose how much and how often they want to pay before they use the electricity. It’s great for the consumer but how w w w. r mel .o rg

Customer: “Just tell me what I need to do to buy energy about the utility? Picture this: an elderly customer goes into the cooperative office and tells them she has $300 for her elec- efficiently and save money?” This rate has a direct focus on changing consumers’ behavior. If a customer can focus the tric bill this month. She prepays the $300. About a week later, vast majority of their usage in off-peak hours, their savings it’s a very cold day—she looks at the meter connected to her thermostat and realizes she’s used $30 worth of electricity that could be substantial. If enough consumers follow the proper pattern, the utility’s peak demand could be lowered signifiday. Concerned, she calls customer service. The helpful reprecantly and result in savings for the utility. sentative tells her to add a sweater and put the thermostat on Budget Billing Rate. This program allows a customer 72 vs. 78. Now, she’s an educated and energy-conscious custo pay a specified amount each month instead of paying tomer. And she won’t come back to use that energy at another time—she’s simply stopped using as much energy. Therefore, it their actual billed amount. This eliminates the typically high seasonal bills that to ocis imperative that we recover all of cur during the summer or winter our fixed costs with fixed revenue. months. In most cases, the utilDemand Ratchet Rate. This ity will have a slight premium type of rate has commonly been embedded in this pricing so as to used with commercial/industrial cusprotect itself from higher than tomers and is a newer option for the expected customer consumption. residential class. The main reason The advantage for the consumer is for this is that we haven’t had the that it allows them to have stable infrastructure in place; with smart electric expenses all year. This type meters we now have the technology. of rate typically has an annual or Basically, a ratchet is when a utility bi-annual adjustment. charges you demand based off of Traditional Rate. The status the peak you hit during the past 11 quo—the customer is billed based months. For example, my family’s on consumption. Keep in mind maximum demand during the year that not all customers will want to was 10 kW and my utility had an change from this traditional model. 80 percent ratchet. We would never As wholesale pricing mechanisms pay on less than 8 kW—even if we continue to evolve, we need to be exonly hit 3 kW during the month. tremely careful with how we design With the metering infrastructure our “standard” retail residential rates in place, ratchet clauses are becomgoing forward. ing more popular than ever before. Net Metering Rate. This option Because, as electric providers, we build is for consumers who own (generour facilities to be able to meet peak ally small) renewable energy facilities demand, we need to recoup the invest(such as wind and solar power). In ment from the user that is causing us this context, “net” means “what to incur that cost. This demand rate remains after deductions” or the allows the residential user to pay for deduction of any energy outflows that investment over the course of the from metered energy inflows. Under year as opposed to having unnecessarinet metering, a system owner receives ly high bills during high usage months. retail credit for at least a portion of The demand rate will also allow the — F inance & Administration Manager. the electricity they generate. end user to have a certain level of Southeastern electric cooperative While, in theory, this helps the control over their bill. If the customer utility shave its peak, that isn’t often was able to peak shave, they not only the case. On a very hot and humid receive immediate savings that month, day in the Southeast, it isn’t unusual but they also have lowered the “trigger for consumers to have to pull from level” for the ratchet. the grid. They are still contributing to the peak demand for Time of Use Rate. As we all know, the pricing of electricity the system. Unfortunately, during the milder days of the year, is based on the estimated cost of electricity during a particular their own generation may meet their entire need. Therefore, time block. Time-of-use rates are usually divided into three or the utility has less consumption to recoup their cost. Because four time blocks per 24-hour period (on-peak, mid-peak, offthe actual kWh purchased from the utility can vary wildly, peak and sometimes super off-peak) and by seasons of the year it is important to recoup all fixed expenses in the form of a (summer and winter). Time-of-use rate differs from Real-time customer charge. pricing in that it is based on forecasted (as opposed to actual).

“I have never and I repeat— never—been able to so closely forecast how close a year as I was in 2011. Our cost of service study and the resulting rates were dead on. Talk about a happy board.”

elec tric energy | spring 2012

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So What Now?

We advise our utility clients that now is not the time for you or your boards to stick your proverbial heads in the sand. If you have not already begun the process of adjusting fees to match cost of service, do so now. A good cost of service study is invaluable in helping to develop long-term financial projections. Review rate structures to move your clients closer to cost of service and implement demand charges to recover distribution costs. Use some of the examples above to develop alternative rates that allow your customers to reduce charges and your organization to reduce costs. Just remember that the process of ratemaking is part science, part art. The most accurate numbers we can obtain are vital and serve as our guide. But at the end of the day, we find the “people factor”—the social and political aspects of the community—trumps the numbers every time. Jim Marshall specializes in cost of service studies, rate design, financial forecasting and consulting for utilities throughout the United States. He is a Manager with Jackson Thornton Utilities Consultants and is a member of the Association of Energy Engineers, the American Water Works Association and the Tennessee Association of Utility Districts. Jim can be reached at Jim.Marshall@jacksonthornton.com. Terry Mitchell, CPA, specializes in rate design, financial forecasting and consulting to utilities throughout the United States. He is a Principal with Jackson Thornton Utilities Consultants and has been involved with the electrical distribution industry for more than 37 years. Terry currently serves as General Editor for the Utility Cooperative Forum in The Cooperative Accountant, a quarterly publication of the National Society of Accountants for Cooperatives. He also serves as a National Director on the Electric Cooperative division of the National Society of Cooperative Accountants. Terry can be reached at Terry.Mitchell@jacksonthornton.com.

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Easing the Pain of a NERC CIP Audit By Michael W. Tibbs, CPP, CSPM, CHS-III, Senior Vice President & COO, Corporate Risk Solutions, Inc.

t’s no surprise that undergoing a North American Electric Reliability Corporation (NERC) Critical Infrastructure Protection (CIP) audit can be an arduous task, yet many entities get through it quickly with manageable stress levels. What’s their secret? Great preparation. It takes 18 to 24 months of diligent effort to be ready to effectively handle the audit. What follows is a synopsis of the major milestones for a smooth audit. There are numerous additional elements of a successful compliance program that are too lengthy to include here. Assuming you have a compliance program in place and most of your documentation is in order, you should begin preparing for the audit by scheduling a detailed gap analysis 12 to 18 months out. This should provide feedback on the effectiveness of your compliance efforts. It is at this stage that many compliance teams come to the unsettling realization that the policies and procedures that they worked so hard to write are not producing adequate evidence, or in some cases, not even being followed. The gap analysis should produce a very detailed report showing the entity’s compliance status with every nuance of each requirement and sub-requirement. It should include

elec tric energy | spring 2012

specific recommendations for remediation of any deficiencies. The findings should be evaluated, prioritized, and put on an action items list to allow you to track progress in correcting any deficiencies. At this point the magnitude of a weak compliance program becomes glaringly obvious and senior management should be made aware if not everything is perfect and you are considering filing Self-Reports. Now that you have management’s full attention, it’s a good time to ask for additional resources to help you correct the deficiencies and get fully in compliance. Many entities find that they now need to update policies, procedures, plans and workflow charts. If any evidence is lacking, get the processes fixed right now so you can accumulate proper evidence to submit at audit time. A vital preparation step is the mock audit. This should be done five to six months out from the audit. The mock audit should be conducted in the same format as the real audit will be. It should be a formal process that gives the subject matter experts (SMEs) a full dress rehearsal for the real thing. It should include preliminary testimony training and evidence presentation techniques. Practice delivering convincing testimony to explain the evidence goes a long

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way towards building confidence and helping the SMEs relax while under the scrutiny of the audit team. An additional SME testimony training program should be conducted approximately 30 days in advance of the audit. This allows the SMEs to practice their responses to auditor questions in a timeframe close enough to the actual audit to remember the lessons and feel confident about the testimony they are about to provide. Develop your Reliability Standards Audit Worksheets (RSAWs) and use them during the mock audit. This is not the time for extensive written testimony. If the narrative varies from your documentation, it won’t be considered as acceptable evidence. Frankly, many entities spend too much time trying to write something creative for the RSAW. Auditors use these forms to guide them through the evidence and to write their notes. While they don’t need extensive detail, RSAWs should effectively introduce the specific sections of policies, plans and procedures your entity uses to prove compliance. Add in samples of supporting evidence such as logs and event documentation to further

support your compliance posture. Be sure to carefully check the evidence artifacts in advance for errors or blank spaces. If it is not a perfect example, replace it with a better one. During the mock audit you will learn if you have any difficulty in organizing evidence for submission. Many entities have some glitches in their evidence retrieval process, so now is the time to work out any issues so you can readily produce evidence as needed during the audit and avoid those 20 hour days responding to Data Requests (DRs) you hear horror stories about. Approximately 90 days out from the first on-site week you will receive a DR from your Regional Entity. Most regions are using a workbook for logging evidence. Be sure to follow the instructions, being very careful to use the naming convention required for the evidence files. The audit proceeds at the pace of the audit team scribe, so using the proper naming convention will make it easy on the scribe and speed up the audit. Again, carefully review your evidence before it is submitted to ensure that it represents your best work.

NERC Audit Timeline

Quarterly

BiAnnually

18-12 Months: Gap Analysis

16-9 Months

12-7 Months

12-6 Months

8-6 Months

6 Months: mock audit

5-3 Months

4-3 Months

3-2 Months

90 Days

Annually

3-30 Months Post

3-6 Months Post

60-90 Days Post

0-15 Days Post

0 Day: AUDIT

On-Site NERC Audit Support

elec tric energy | spring 2012

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30-0 Days

60 Days

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Upon receipt of your DR response, the audit team will convene to review the documents at their office. If the documentation is clear and concise, they can check it off at this point and not need to cover it again during the on-site visit. During the review the auditors will prepare questions on issues they don’t understand from your documentation. They may also submit an additional DR if they feel more evidence is needed to prove compliance. If that happens, respond as soon as possible with your best evidence examples. Everything checked off at this point saves you time later. Logistics should be reviewed two weeks prior to the audit. You will be required to provide two audit rooms. The audit rooms should be equipped with data projectors and computers dedicated to presenting evidence. Using two screens works very well. One screen can show the procedure document or process flow chart while the second screen simultaneously shows the evidence output from the process. The computer used for the presentation should not have email or Instant Messaging turned on. Having a message pop up from a colleague saying that they can’t find the evidence you need is not a good idea! Set up a “bull pen” area located away from the audit rooms as a gathering place for your SMEs and compliance support staff. This is the area where evidence samples can be vetted and final preparation for testimony can be rehearsed. Remind the SMEs not to discuss the audit or their testimony in public spaces where they might be overheard by an auditor. Remember that while on site during your audit, everything heard or seen by the auditors is potentially evidence. The on-site phase generally involves two weeks, commonly separated by an off-site week. The audit schedule should be confirmed during the in-briefing. The in-brief and out-brief are the appropriate times to break out the big guns - meaning senior executives in the audience to show management’s commitment to the compliance program. Introduce the executives including their titles. It gives a great first impression to the audit team if they see executive management is involved. On the other hand, if no senior executives show up it raises a question about their commitment. The first audit week is usually a review of policies, procedures and plans with the second week being the more intensive review of detailed evidence. The in-between week can be used by the entity to gather whatever evidence is necessary in response to DRs that weren’t already fulfilled. The audit team Lead will inform you when the responses must be submitted. If for some reason you cannot meet that deadline, let them know in advance and ask for an extension. The audit team realizes the work load you are under and will try to oblige any reasonable request. There will be a firm final deadline after which no further evidence can be considered because the auditors need a certain amount of time to evaluated the evidence and prepare their findings for the out-brief.

elec tric energy | spring 2012

The audit team will be divided into a technical team, usually with SCADA and IT network security expertise, and a non-technical team with experience in physical security and operations. There may also be observers from NERC or the Federal Energy Regulatory Commission (FERC) monitoring the audit team. You’ll need to provide an audit room for both audit teams and be prepared with SMEs to introduce evidence and respond to auditors questions in both rooms concurrently. If you are an entity with a small number of SMEs who can’t support testimony in two rooms at once, explain that to the audit team lead up front and he or she will try to schedule around your limitations. Before testifying, the SMEs should briefly introduce themselves, including their title, related work experience, special training programs they have attended, certifications, participation in regional working groups or standards drafting teams, and any other CIP-related area of expertise they have. When the auditors hear that the person has 20+ years in the industry, attends all the regional workshops, heads up an industry leadership team, participates in Idaho National Laboratory’s energy segment programs, and has certifications from multiple internationally recognized professional organizations, that witness has immediate credibility and the urge to debate with you is minimized. Even if you are well-prepared you should plan on long days during the audit. If you can schedule resources to staggered shifts for DR responses it will reduce the fatigue factor tremendously. During the audit be sure to have a qualified resource dedicated to reviewing evidence that is planned to be submitted in response to DRs. Your SMEs will be tired and under stress, and they may not select the best evidence examples. Don’t allow them to submit any evidence that has not been vetted. Have SMEs rehearse their presentation of the supplemental evidence with someone qualified to evaluate their answers before they go one-onone with the auditors. Post audit you will receive the audit report. Hopefully it brings with it only good news. If there are any Open Enforcement Actions, you need to plan resource availability for mitigation planning and implementation. Audits frequently point out documentation shortcomings, so plan on a team dedicated to drafting updated documents. The chart on the follow pages portrays the detailed audit timeline. It’s a lot of work, but properly prepared, you can survive a NERC CIP audit with a minimum of pain. Mike Tibbs has been involved with electric utilities from a security perspective since 1973 and has completed hundreds of security consulting and NERC CIP projects for utility clients. Mike has also conducted hundreds of TFE reviews, mitigation plan reviews, and RBAM evaluations. To reach Mike, email mtibbs@corprisk.net.

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2012 National Electrical Safety Code: The Changes By Mark Swan, P.E., Consulting Engineer, MDS Engineering Consulting, LLC

It has happened every five years since 1997. The National Electrical Safety Code (NESC) has been revised. The 2012 edition of the NESC was published on August 1, 2011 and became effective on February 1, 2012 or as administrative or regulatory agencies adopt the most current version. The following discussion is a summary of some of the revisions to the NESC. There is not space to review all of the changes. Because policies, design practices, and operations vary from one utility to another, a minor change for one utility may be considered a major change to another. Therefore, it is incumbent on each utility to carefully review the 2012 NESC in order to make their own determinations regarding their approach to compliance with the 2012 NESC rules. The formal three year revision process that resulted in the 2012 NESC started on July 17, 2008 and proceeded through six steps before publication date. This revision process resulted in approximately 500 proposed changes that filled 719 pages. As might be expected, not all of these proposed revisions were approved. While there are several significant changes contained in the 2012 NESC, many of the approved revisions were minor in nature, such as format alterations, terminology changes, etc. Looking into the future, the formal process to revise the 2012 NESC begins on July 15, 2013, the final date to submit proposed changes. A preprint of the proposed changes will be available on September 1, 2014. This is the first opportunity for the public to see the proposals that could be incorporated into the 2017 NESC.

elec tric energy | spring 2012

Now, back to the present, there are a few changes in the 2012 NESC that impact several rules throughout the Code.

î Signs

The American National Standards Institute (ANSI) made revisions to their sign standards in 2006 and 2007. So any reference to signage in the NESC was changed to comply with the current ANSI A535 standards. This change does not require that utilities change out every installed sign on their systems. The â&#x20AC;&#x153;grandfatherâ&#x20AC;? clause in the Code (Rule 013.B.) allows installations that complied with prior Code editions to remain without modification. However, it may create an issue for those signs in stock in a warehouse that have not yet been installed.

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 guys

 grounding All references to “ungrounded guys” (Rule 215.C.) were removed from the Code. Guys (anchor or span) must be either grounded or insulated. Connection of a guy wire to an anchor rod/anchor does not constitute a ground. A grounded guy must be intentionally connected to an effectively grounded neutral or grounding conductor.

 antennas

The proliferation of communication antennas installed on electric power structures has prompted changes in several sections of the Code. Most of the revisions are relatively minor, but utility personnel should review the changes for any new radio/antenna installations. The following paragraphs describe changes made to specific parts or sections of the NESC.

 purpose and scope

This edition of the Code devotes significant effort in attempting to clarify which electric power facilities must comply with the NESC and which must comply with the National Electric Code (NEC). The utility must define a “service point”. All facilities on the source side of the service point must comply with the NESC. Those facilities on the load side of the service point must comply with the NEC, regardless of ownership. In areas where utilities cannot obtain an easement (military bases, Indian reservations, etc.), the utility must have an agreement with the owning entity to install power facilities. A careful review of these Code sections is necessary, as the changes may be significant depending on a utility’s operating policies and practices.

 definitions

The 2012 NESC contains 17 new definitions. Several of the newly defined terms apply to the Purpose and Scope changes. Fifteen existing definitions were revised. A review of the new and revised definitions is essential in understanding some of the changes in the NESC.

elec tric energy | spring 2012

Very few changes were made to Section 9 of the Code. The most significant change removed the diameter and thickness requirements for use of direct embed steel poles as grounding electrodes. Previous editions of the Code required a minimum diameter of 5 inches and a minimum thickness of ¼ inch of metal. The provision requiring 5 feet of bare metal contact with earth was maintained.

 electric supply stations

Several revisions were made to Part 1. Most of the changes were minor but two of the changes will be discussed here. The first involves the safety clearance zone – the space required from the station fence to the closest energized part. Vertical clearance above the nearest supporting surface to a part of indeterminate voltage or energized parts (Rule 124) may be determined by using the “taut-string” provision (Rule 124.D) as shown below. The vertical clearance requirement of Table 124 may consist of the vertical and diagonal components as long as the vertical component is at least 5 feet. A reduced safety zone clearance is allowed if an impenetrable wall is constructed. The reduced clearance is determined by using the following formula: H + R1 > R + 5.0 ft Where H is the wall height, R is the value from Table 1101 that varies with voltage. R1 is the clearance allowed with an impenetrable wall. Vertical clearance above the nearest supporting surface to a part of indeterminate voltage or energized parts (Rule 124) may be determined by using the “taut-string” provision (Rule 124.D) as shown below. The vertical clearance requirement of Table 124 may consist of the vertical and diagonal components as long as the vertical component is at least 5 feet.

 overhead lines

Not surprisingly, more than half of the proposed changes to the Code involved Part 2. Most of the final revisions were minor in nature. One of the minor revisions involved Rule 214.A.4, Inspections. Past editions had required that “defects” be recorded until corrected. The new edition also requires “conditions” be included. “Conditions” refers to such items as clearance issues, attachment problems, etc. Another minor change involves attachments. It is now

For example, the Heavy Loading District temperature is 0º required that any attachment have the approval of the F. This change requires that utilities review their sag-tension structure owner. While this requirement is part of many atcharts. The sag-tension chart shown below for the popular tachment agreements, this revision codifies the requirement, 336.4 KCM Merlin ACSR conductor highlights the concern. which will be helpful. Note that at the 2012 Code temperature requirement for Another change requires that all non-utility attachments the Heavy Loading District of 0º F, no wind or ice load, the (such as flags & banners) have the approval of the occupants of final tension is right at the 25 percent limit set by the NESC. the space on the structure in addition to the structure owner. Additionally, attachments may not cause the structure to be out of compliance with the NESC. Also, attachments must not obstruct climbing space. Because of the significant variation in weather conditions The revisions to Part 3 of the Code were primarily clarifications experienced due to elevation change in Hawaii and other of existing rules. The same change regarding inspections and reU.S. island territories, a new ice and wind loading zone was cord keeping made in Part 2, was made in Part 3. Utilities must created. The warm islands Zone 4 covers those islands in inspect for and maintain records for defects and conditions. latitudes between 25º N and 25º S of the equator. A careful Separation between flammable material lines (natural gas, review of Section 23 Clearances and Section 250 Loadings is petroleum, etc) and electric lines is now required to be “not less recommended for those doing work in the islands. than 12 inches” in Rule 320.B.5. In the past no minimum separaMinor revisions were made through out Section 23 Cleartion was specified, as long as the separation was sufficient to ances. A careful review of this section is advised. prevent damage during installation and maintenance activities. A very helpful clarification was made regarding horizontal clearance from an overhead line to Sag Tension Chart a building. Table 234-1 requires a certain clearance with the conductor at rest (no wind load) and Rule Conductor: Merlin, 336.4 KCM, 18/1 ACSR 234.C.1.b specifies a clearance with the conducArea: 0.2789 in2 | Stress-strain data from Chart No. 1-844 NESC Heavy Loading District | Creep is a factor | Ruling Span = 250 ft. tor displaced by a 6 lb/ft2 wind at 60ºF. Many line designers have interpreted these provisions to mean that one or the other must be met. This is not a corFinal Conditions Initial Conditions rect interpretation. This change in the Code clearly Tension % of Tension % of Wind Temp Sag ft. Sag ft. Ice in. lbs. RBS lbs. RBS PSF F specifies that both of these conditions must be met. -20.0 0 0 1.04 2747 31.65 0.95 3016 34.75 Attempts were made to reduce confusion regarding clearances over swimming pools. -10.0 0 0 1.16 2453 28.26 1.02 2808 32.35 Rule 234.E.1 was modified to further define 0 0 0 1.31 2170 25.00 1.10 2595 29.90 clearances over spas (hot-tubs, jacuzzis, etc.). 0 0.5 4 3.51 3420 39.40 3.47 3464 39.91 Changes made in Section 242. Grades of 10.0 0 0 1.50 1904 21.94 1.20 2378 27.40 Construction simplified the application of the 20.0 0 0 1.72 1660 19.13 1.32 2160 24.89 requirements of this section. The elements of Table 30.0 0 0 1.98 1445 16.65 1.47 1944 22.39 242-1 and 242-2 were combined allowing the 32.0 0 0 2.03 1406 16.19 1.50 1901 21.90 elimination of Table 242-2. 32.0 0.5 0 3.56 2416 27.84 3.25 2651 30.55 Several rules and tables in Section 250, Loadings, were revised. Special wind regions, as shown 40.0 0 0 2.26 1261 14.53 1.65 1734 19.97 on maps in Figure 250-2, are highlighted in new 50.0 0 0 2.57 1110 12.79 1.86 1536 17.69 notes to the Code. While notes are not considered 60.0 0 0 2.89 988 11.38 2.11 1356 15.62 requirements, it may be prudent for designers to 60.0 0 6.0 3.21 1218 14.04 2.52 1551 17.86 account for these high wind areas in their structure 60.0 0 9.0 3.47 1420 16.36 2.85 1726 19.89 design considerations. 70.0 0 0 3.21 890 10.25 2.38 1198 13.80 Another seemingly minor change in Rule 261.H.1 80.0 0 0 3.52 811 9.34 2.58 1065 12.27 could have major impacts to some utilities. This 90.0 0 0 3.83 747 8.60 2.99 955 11.00 section sets limits on initial unloaded tension and final unloaded tension of conductors at a specified temper100.0 0 0 4.12 697 7.99 3.30 865 9.97 ature, in order to minimize the potential for Aeolian 110.0 0 0 4.40 649 7.48 3.61 792 9.12 vibration. The 2007 edition set the temperature at 60º 120.0 0 0 4.67 612 7.05 3.91 731 8.43 F. The 2012 Code specifies the temperature shown in 167.0 0 0 5.82 492 5.66 5.18 553 6.37 Table 251-1 for the appropriate loading district.

 underground lines

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A change in Section 35 of the 2012 Code requires that “cable in duct not part of a conduit system” be treated the same as direct buried cable. The definition of a conduit system is given as: any combination of duct, conduits, or vaults joined together to form an integrated whole. So given this definition, is a single 4 inch PVC duct running from one pad mounted cabinet to another a “duct not part of a conduit system”? Section 355 was added to the Code. This section contains rules for ducts not part of a conduit system. However, this addition does not provide an answer to the previous question. A change to Rule 352.D. Burial Depth, formalizes a concept that many of us have utilized over the years regarding supplemental protection and reduced burial depths. The addition states that if cable is installed in duct, additional protection is not necessary if the duct will protect the cable from damage due to surface activity. However, if this single duct is considered “a duct not part of a conduit system” can the new provisions of Rule 352.D. be used? The answer is apparently left to the interpretation of each utility.

 work rules

One of the changes to Part 4 of the Code has been widely anticipated. New provisions have been added specifying arcrated clothing systems for voltages of 50V to 1000V. These requirements are set out in Table 410-1. A significant set of footnotes accompanies this table. These footnotes primarily describe the justification and sources used for the development of the table. Careful reading and evaluation of these footnotes is recommended to be certain the electrical characteristics of your utility system fit within conditions described. The contents of the 2007 version of Table 410-1 (clothing systems for voltages for 1.1KV to 46KV), remain unchanged. The table was renumbered to 410-2. Likewise, the previous Table 410-2 was relabeled Table 410-3. All of the clearing times were modified in the new Table 410-3 based on new calculation methodology. The 2012 Code (Rule 410.A.3.a) does provide the utility with the option to perform a detailed fault current arc analysis to determine the appropriate clothing system or use Tables 410-1, 2, 3. A new paragraph was added to Rule 421.A, General Operating Routines, Duties of the First Level Supervisor. This new paragraph requires that a “job briefing” be performed before starting each job. The Code recommends the briefing include at least the following topics: ■ Work procedures ■ Personal protective equipment (PPE) requirements ■ Energy source controls ■ Hazards of the job ■ Special precautions This addition to the Code should not create much concern

elec tric energy | spring 2012

for most utilities, since the Occupational Safety and Health Administration (OSHA) regulations have required these types of “tail gate” sessions for some time. Due to several fatal accidents over the recent past, a modification to Rule 442.A.2, Setting/moving/removing poles near energized lines, was made. In previous editions, personal protective equipment was required for ground personnel only if contact was made with “ungrounded” vehicles involved in the operation. The 2012 Code requires PPE for employees if contact is made with any vehicle involved in the operation, grounded or not. Several revisions to Rule 441, work rules for work near energized conductors or parts, simplified and clarified the requirements. The provisions of Tables 441-2 & 3, minimum approach distances for alternating current (AC) live work, were combined into Table 441-1. Tables 441-2 & 3 were eliminated. A new Table 441-2 was included that covers minimum approach distances for live work on direct current (DC) systems. The new version of the Code removed some very specific requirements for the placement of personal protective grounds contained in Rule 444.D. The new provision simply specifies that temporary personal protective grounds be installed in such a manner that employees are protected from hazardous potential differences. The specific protective grounding method used to achieve this requirement is left to the utility, contractor, etc. Notes were added that highlight the dangers associated with step, touch and induced voltages.

 appendices

The five appendices at the end of the NESC provide information about various aspects of the Code. No changes or only minor changes were made to four of the appendices. Significant revisions were made to Appendix C.

 conclusions

One of main benefits to the regular five-year Code revision cycle is that we do not seem to experience the major overhauls of the NESC that occurred in the 1970s and 1980s. The 2012 NESC has several changes, some of which are highlighted in this discussion, that utilities must review and incorporate in their design and operation procedures. But in general, the revisions in this Code edition should not present major issues or problems for most utilities. Mark Swan has spent 39 years in the electrical power industry. He has been responsible for the design, installation, operation and maintenance of electrical substations, transmission, distribution lines, transmission and distribution operations control centers, and other related facilities. Mark can be reached at mswan1295@comcast.net.

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RMEL Member Companies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56

ABB, Inc. ABCO Industrial Sales, Inc. ADA-ES, Inc. Alexander Publications Alstom Power Altec Industries, Inc. AMEC American Coal Council AREVA Solar Inc. Arizona Electric Power Cooperative, Inc. Arizona Public Service Arkansas River Power Authority Asplundh Tree Expert Co. Associated Electric Cooperative, Inc. ATCO Noise Management Austin Energy Ayres Associates Babcock & Wilcox Company Babcock Power, Inc. Basin Electric Power Cooperative Bechtel Power Corporation Black & Veatch Corp. Black Hills Corporation Black Hills Electric Cooperative Boilermakers Local #101 Boone Electric Cooperative Border States Electric Brand Energy & Infrastructure Services Brooks Manufacturing Company Burns & McDonnell Butler Public Power District C.I.Agent Solutions Carbon Power & Light, Inc. Casey Industrial, Inc. CBS Arc Safe Center Electric Light & Power System Central New Mexico Electric Cooperative, Inc. CH2M Hill Chimney Rock Public Power District City of Alliance Electric Department City of Aztec Electric Department City of Boulder City of Cody City of Farmington City of Fountain City of Gillette City of Imperial City of Yuma Co-Mo Electric Cooperative CoBank Colorado Energy Management, LLC Colorado Powerline, Inc. Colorado Public Utilities Commission Colorado Rural Electric Association Colorado Springs Utilities Colorado State University

elec tric energy | spring 2012

57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110

Commonwealth Associates, Inc. Consert Inc. Continental Divide Electric Cooperative Corporate Risk Solutions, Inc. County of Los Alamos Dept. of Public Utilities CPS Energy Davies Consulting Deloitte Delta Montrose Electric Assn. DIS-TRAN Packaged Substations, LLC Dowdy Recruiting LLC E & T Equipment, LLC E3 Consulting El Paso Electric Company El Paso Natural Gas Company Electrical Consultants, Inc. Emerson Process Management The Empire District Electric Company Empire Electric Association, Inc. Energy & Resource Consulting Group, LLC Energy Reps Engineering, Procurement & Construction, LLC ENOSERV, LLC Equal Electric, Inc. ESCâ&#x20AC; engineering Estes Park Light & Power Dept. Exponential Engineering Company Faith Enterprises Inc Finley Engineering Company, Inc. Foothills Energy Services Inc. Fort Collins Utilities Foster Wheeler Fuel Tech, Inc. Garden City Municipal Utilities GE Energy Genscape, Inc. Glenwood Springs Electric System Golder Associates, Inc. Grand Island Utilities Grand Valley Rural Power Lines, Inc. Great Southwestern Construction, Inc. Gunnison County Electric Association, Inc. Hamilton Associates, Inc. Hamon Research - Cottrell Harris Group, Inc. Hartigan Power Equipment Company Hawkeye Helicopter LLC HDR, Inc. Heartland Consumers Power District Heartland Solutions, Inc. High Energy, Inc. (HEI) High Plains Power, Inc. Highline Electric Assn. Hitachi Power Systems America, Ltd

111 112 113 114 115 116 117 118 119 120 121 122 123 124 125 126 127 128 129 130 131 132 133 134 135 136 137 138 139 140 141 142 143 144 145 146 147 148 149 150 151 152 153 154 155 156 157 158 159 160 161 162 163 164 165

Holy Cross Energy Homer Electric Association, Inc. Honeywell Process Solutions Howard Electric Cooperative Hughes Brothers, Inc. IBEW, Local Union 111 IMCORP Independence Power & Light Intercounty Electric Coop Association Intermountain Rural Electric Assn. ION Consulting Irby Irwin Industries, Inc. J.L. Hermon & Associates, Inc. Jemez Mountains Electric Cooperative, Inc. Kansas City Board of Public Utilities KD Johnson, Inc. Kiewit Kit Carson Electric Cooperative Kleinfelder Klondyke Construction LLC KVA Supply Co. La Junta Municipal Utilities La Plata Electric Association, Inc. Lake Region Electric Coop Inc. Lamar Utilities Board Laminated Wood Systems, Inc. Lane-Scott Electric Cooperative, Inc. Lauren Engineers & Constructors LEADERSHIP A Business Imperative, Inc. Lewis Associates, Inc. Lincoln Electric System Longmont Power and Communications Loup River Public Power District Loveland Water & Power Luminate, LLC Marsulex Environmental Technologies Merrick & Company Missouri River Energy Services Morgan County Rural Electric Assn. Mountain Parks Electric, Inc. Mountain States Utility Sales Mountain View Electric Assn. Mycoff, Fry & Prouse LLC NAES Corp. Navigant Navopache Electric Cooperative, Inc. Nebraska Public Power District NEI Electric Power Engineering, Inc. NMPP Energy Nooter/Eriksen, Inc. Norris Public Power District North Platte Light & Power Northeast Community College Northeast Missouri Electric Power Cooperative

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member listings cont’d

166 Northeast Oklahoma Electric Coop Inc. 167 Northwest Rural Public Power District 168 Novinda Corporation 169 NV Energy 170 Occupational Safety Councils of America 171 OIC Outage 172 Omaha Public Power District 173 Omnicon Technical Sales 174 On-Ramp Wireless 175 Osmose Utilities Services, Inc. 176 Otero County Electric Cooperative 177 PacifiCorp 178 Panhandle Rural Electric Membership Assn. 179 PAR Electrical Contractors, Inc. 180 PCS Mobile 181 Peak Power Engineering, Inc. 182 Peterson Co. 183 Pike Electric, LLC 184 Pioneer Electric Cooperative, Inc. 185 Pipefitters Local Union #208 186 Platte River Power Authority 187 PNM Resources 188 Poudre Valley Rural Electric Assn. 189 Power & Industrial Services Corp 190 POWER Engineers, Inc. 191 Power Equipment Specialists, Inc. 192 Power Pole Inspections 193 Power Product Services 194 PowerQuip 195 Provo City Power 196 Quanta Services 197 Raton Public Service 198 REC Associates 199 Reliability Management Group (RMG) 200 Reliable Power Consultants, Inc. 201 Rkneal, Inc. 202 Rocky Mountain Generation Cooperative, Inc. 203 S&C Electric Company 204 Sabre Tubular Structures 205 Safety One Inc. 206 SAIC 207 San Isabel Electric Assn. 208 San Luis Valley Rural Electric Cooperative 209 San Miguel Power Assn. 210 Sangre De Cristo Electric Assn. 211 Sargent & Lundy 212 Scientech 213 Sega Inc. 214 SENER Engineering and Systems, Inc. 215 The Shaw Group 216 Siemens Energy Inc. 217 Sierra Electric Cooperative, Inc. 218 Sierra Southwest Cooperative Services, Inc. 219 SNC-Lavalin Constructors Inc. 220 The Socorro Electric Cooperative, Inc. 221 Solomon Associates 222 South Central PPD

elec tric energy | spring 2012

223 Southeast Colorado Power Assn. 224 Southeast Community College 225 Southern Pioneer Electric Company 226 Southwest Generation 227 Southwest Transmission Cooperative, Inc. 228 Southwestern Power Group II 229 Southwire Company 230 SPIDAWeb LLC 231 Springfield Municipal Light & Power 232 SPX Cooling Technologies 233 SRP 234 Stanley Consultants, Inc. 235 STEAG Energy Services LLC 236 STRUCTURAL 237 Sturgeon Electric Co., Inc. 238 Sulphur Springs Valley Electric Cooperative 239 Sundt Construction 240 Sunflower Electric Power Corporation 241 T & R Electric Supply Co., Inc. 242 Technically Speaking, Inc. 243 Thomas & Betts Steel Structures Division 244 TIC - The Industrial Company 245 Total-Western, Inc. 246 Towill, Inc. 247 Trachte, Inc. “Buildings & Shelters” 248 Trans American Power Products, Inc. 249 Transformer Technologies 250 Trees Inc 251 Tri-State Generation and Transmission Assn. 252 Trimble 253 Trinidad Municipal Light & Power 254 UC Synergetic 255 Ulteig Engineers, Inc. 256 UniSource

257 United Power, Inc. 258 Universal Field Services Inc. 259 University of Colorado 260 University of Idaho Utility Executive Course College of Business and Economics 261 URS Energy & Construction Inc. 262 Utility Telecom Consulting Group, Inc. 263 Valmont Newmark, Valmont Industries, Inc. 264 Victaulic 265 Wärtsilä North America, Inc. 266 Waukesha Electric Systems, An SPX Company 267 Wazee Companies LLC 268 West Plains Engineering, Inc. 269 Westar Energy 270 Western Area Power Administration 271 Western Cultural Resource Management, Inc. (WCRM, Inc.) 272 Western Line Constructors Chapter, Inc. NECA 273 Western Nebraska Community College 274 Western United Electric Supply 275 Westwood Professional Services 276 Wheat Belt Public Power District 277 Wheatland Electric Cooperative 278 Wheatland Rural Electric Assn. 279 White River Electric Assn., Inc. 280 White River Valley Electric Cooperative 281 William W. Rutherford & Associates 282 WorleyParsons Group, Inc. 283 Wyoming Rural Electric Association 284 Wyrulec Company 285 Xcel Energy 286 Y-W Electric Association, Inc. 287 Yampa Valley Electric Association, Inc. 288 Zachry Holdings, Inc.

There’s more at Merrick Merrick’s client-focused project delivery teams have served the energy industry since the firm’s founding in 1955. At the core of our services is an understanding of your business, operations, industry, and marketplace conditions. That understanding is combined with the expertise of the firm’s talented professionals to deliver vital solutions that work. When you’re looking for more, call Merrick. Contact: Chris Biondolilo, PE - Project Manager 2450 South Peoria Street Aurora, CO 80014-5475 303-353-3876

www.merrick.com

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Employee Owned

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w w w. zhi . co m ENGINEERING | CONSTRUC TION | INDUSTRIAL SERVICES | NUCLEAR

rmel 2012 calendar

2012 Calendar of Events January 19, 2012

April 11-13, 2012

August 24, 2012

Introduction to the Electric Utility Workshop Denver, CO

Distribution Overhead and Underground Design and Staking Workshop Denver, CO

Safety Roundtable Fort Collins, CO

April 24-25, 2012

Fall Executive Leadership and Management Convention Summerlin, NV

February 7-8, 2012 New Distribution Engineers Workshop Denver, CO

February 24, 2012 Safety Roundtable Denver, CO

March 1-2, 2012 Power Supply Planning and Projects Conference Denver, CO

March 2, 2012 Generation Vital Issues Roundtable Denver, CO

March 6-7, 2012 Transmission Planning and Operations Conference Denver, CO

Health, Safety and Security Conference Denver, CO

September 9-11, 2012 September 27, 2012

Safety Roundtable Denver, CO

2013 Spring Management, Engineering and Operations Conference Planning Session Denver, CO

May 20-22, 2012

October 9, 2012

Spring Management, Engineering and Operations Conference Omaha, NE

OSHA Update Workshop Denver, CO

June 14-15, 2012

Renewable Planning and Operations Conference Denver, CO

April 25, 2012

Plant Management Conference Location: Las Vegas, NV

June 15, 2012 Plant Management Roundtable Location: Las Vegas, NV

March 7, 2012

June 21-22, 2012

Transmission Vital Issues Roundtable Denver, CO

NERC Planning, Operations and Compliance Conference Denver, CO

March 8-9, 2012

July 10, 2012

Distribution Overhead and Underground Operations and Maintenance Conference Denver, CO

RMEL Golf Tournament Westminster, CO

October 16, 2012 November 2, 2012 Underground Distribution Design and Protection Workshop Denver, CO

November 16, 2012 Safety Roundtable Westminster, CO

March 9, 2012 Distribution Vital Issues Roundtable Denver, CO

March 20, 2012 Electric Utility Workforce Management Roundtable Denver, CO

elec tric energy | spring 2012

continuing education certificates Continuing education certificates awarding Professional Development Hours are provided to attendees at all RMEL education events. Check the event brochure for details on the number of hours offered at each event.

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advertiser index

AMEC Black & Veatch Corp.

www.amec.com

(770) 810-9698

www.bv.com

(913) 458-2000

Border States Electric

www.borderstateselectric.com

(701) 293-5834

California Turbo, Inc.

www.californiaturbo.com

(800) 448-1446

CoBank

www.cobank.com

(800) 542-8072

www.ch2m.com

(303) 771-0900

CH2M Hill

Inside Back Cover

Colorado Powerline, Inc.

(303) 660-3784

DIS-TRAN Packaged Substations, LLC

www.distran.com

(318) 448-0274

Emerson

www.emersonprocesspowerwater.com

(708) 263-6114

ERG Consulting

www.ERGconsulting.com

(203) 843-0600

Fuel Tech

www.ftek.com

(630) 845-4500

Great Southwestern Construction, Inc.

www.gswc.us

(303) 688-5816

HDR, Inc.

www.hdrinc.com

(402) 399-1000

Harris Group, Inc.

www.harrisgroup.com

(303) 291-0355

Hitachi Power Systems America, Ltd.

www.hitachipowersystems.us

(908) 605-2800

Hughes Brothers

www.hughesbros.com

(402) 643-2991

www.kiewit.com

(913) 928-7000

www.KVAsupply.com

(303) 217-7500

Kiewit KVA/WESCO

Inside Front Cover, 47

Back Cover 21

Laminated Wood Systems, Inc.

www.lwsinc.com

(402) 643-4708

Merrick & Company

www.merrick.com

(303) 751-0741

National Electric Coil

www.national-electric-coil.com

(614) 488-1151

Nebraska Public Power District

www.nppd.com

(402) 564-8561

Pioneer Electric Cooperative, Inc.

www.pioneerelectric.coop

(620) 356-4111

POWER Engineers

www.powereng.com

(208) 788-3456

Power Product Services

www.powerproductservices.com

(720) 859-4625

Quanta Services

www.quantaservices.com

(713) 629-7600

RK Neal

www.rkneal.com

(270) 442-9880

Rocky Mountain Power

www.rockymountainpower.net

(866) 870-3419

Sabre Tubular Structures

www.SabreTubularStructures.com

(817) 852-1700

Siemens

www.siemens.com

(303) 696-8446

Sega, Inc.

www.segainc.com

(913) 681-2881

Stanley Consultants, Inc.

www.stanleygroup.com

(303) 799-6806

Sturgeon Electric Co. Inc.

www.myrgroup.com

(303) 286-8000

T & R Electric Supply Co., Inc.

www.tr.com

(800) 843-7994

TIC â&#x20AC;&#x201C; The Industrial Company

www.ticinc.com

(970) 879-2561

Trees Inc.

www.treesinc.com

(866) 865-9617

Ulteig Engineers, Inc.

www.ulteig.com

(701) 237-3211

University of Idaho Summit

www.uiueg.org

(208) 885-6265

Wazee Crane

www.wazeeco.com

(720) 281-2847

Wazee Electric

www.wazeeco.com

(720) 279-8449

Westwood/ETG

www.westwoodps.com

(952) 937-5150

Young & Franklin

www.yf.com

(315) 457-3110

Zachry Holdings, Inc.

www.zhi.com

(210) 588-5000

Xcel

www.xcelenergy.com

(800) 481-4700

elec tric energy | spring 2012

Meeting the Power Industry Needs in a Sustainable Manner

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