–

SAFER, SMARTER, GREENER

© 2015 DNV GL All rights reserved. This publication or parts thereof may not be reproduced or

transmitted in any form or by any means, including photocopying or recording, without the prior written

consent of DNV GL.

TABLE OF CONTENTS

1. Executive Summary ........................................................................................ 1

2. Introduction ................................................................................................... 2

3. EPA’s 111(d)– What is it all about? .................................................................... 4

3-1 State Compliance Plans ................................................................................ 7

3-2 States, Multi-States, and the Role of Utilities .................................................. 8

3-3 Compliance Timeline .................................................................................. 10

3-4 Estimated Impact by the EPA ...................................................................... 11

4. Utility Perspective on EPA’s 111(d) .................................................................. 11

4-1 Utility Perspective on EPA’s Authority Under 111(d) ....................................... 11

4-2 Utility Perspective on the Four Building Blocks of 111(d) ................................ 14

4-3 Utility Perspective on Timeline of 111(d) ...................................................... 16

5. State Perspective on EPA’s 111(d) ................................................................... 17

6. DNV GL’s Perspective on EPA’s 111(d) ............................................................. 18

6-1 Is the Clean Power Plan Achievable by 2030? ................................................ 18

6-2 Implementation Likely to be Delayed ........................................................... 21

6-3 The Clean Power Plan Creates Winners and Losers ......................................... 21

6-4 A Broader Range of Compliance Options is Needed ........................................ 24

7. Developing Strategy and Compliance Under Uncertainty .................................... 26

7-1 Designing Actionable State Implementation Plans .......................................... 26

7-2 DNV GL Services to Work Towards Compliance.............................................. 28

Acknowledgements ........................................................................................... 30

About the contributing authors.............................................................................. 31

DNV KEMA is now DNV GL .................................................................................... 33

About DNV GL .................................................................................................. 33

In the Energy industry ...................................................................................... 33

1

1. EXECUTIVE SUMMARY

EPA’s proposed regulations of carbon dioxide emissions under the “The Clean Power Plan” calls for

emission reductions from existing fossil fuel-fired electric generating units of 30 percent by 2030,

compared to 2005 levels. EPA proposes to achieve these reductions through four building blocks: heat

rate improvements; increased dispatch of natural gas combined cycle units; increased reliance on

renewable and nuclear generation; and increased end-use energy efficiency.

The proposed regulation has triggered 1.6 million responses filed during the June-December 2014

public comment period. Judging from these responses, the review from both regulators and the

industry is mixed, and it is clear that much remains to be done before workable regulations are in

place across the United States. In addition to a myriad technical concerns, many stakeholders

question EPA’s regulatory authority to mandate the proposed actions. This is likely to trigger

extensive political, regulatory and legal debates, leading to delayed implementation.

The Clean Power Plan introduces the most significant environmental reform to the power industry

since the Clean Air Act of 1970. Power plant owners will need to devise a strategy for controlling

compliance costs and identifying growth opportunities. Based on this, they need to determine the best

regulatory strategy at the state and federal level.

At the same time, the sweeping reforms call for states to do much of the work in designing a workable

policy that achieves the EPA goals. State regulators need to decide how to best implement the plan

and need to find the most cost effective collaborative approach for reducing emissions without

hurting key industries and rate payers within their jurisdictions.

DNV GL finds that there are several issues that need to be considered carefully and that are likely to

lead to significant delays in implementing the Clean Power Plan:

Broader set of compliance options needed. Even though states have a large number of

compliance options, significant cost savings could be unlocked by considering inclusion of

other industrial CO2 emission sectors as well as offsets.

Regulations take time. Not only do states need to decide how to collaborate on the Clean

Power Plan before the 2016 filing deadline, but they will also need to agree on a staggering

amount of

detail – how to report, monitor, and verify emissions and emission reductions, how to store

and transfer data, how to resolve disputes, etc. DNV GL expects that this will delay

implementation by at least a couple of years compared to the targeted 2020 start of the plan’s

implementation phase.

Winners and losers. DNV GL estimates that the Clean Power Plan will cost 80-120 Billion

dollars to implement. In addition, the impact on owners and operators of power plants will

2

vary significantly depending on the asset base and the states in which electricity providers are

active. Ultimately, this will impact both rate payers and investors. Unless state or federal

regulators can address issues around potentially unequal impact among rate payers and

investors, legal challenges and delays are likely.

Security and Reliability. New state regulations need to balance long term security of the energy

supply against greenhouse gas reductions – maintaining diversity in the supply chain will

likely be important for controlling costs and reliability. In phasing out coal-fired generation,

regulators will also need to consider implications for reliability as baseload generation is

replaced by less-reliable renewable sources.

This white paper provides an overview of the key pieces of the U.S. Environmental Protection

Agency’s proposed carbon regulations under section 111(d) of the Clean Air Act, and identifies

stakeholder inputs, risks, opportunities, and potential compliance options for state regulators and for

power industry stakeholders.

2. INTRODUCTION

On June 2, 2014, the U.S. Environmental Protection Agency issued proposed emission guidelines for

states to follow in developing plans to address carbon dioxide (CO2) emissions from existing fossil

fuel-fired electric utility generating units (EGUs). The proposal, issued under Section 111(d) of the

Clean Air Act (CAA), is formally known as Carbon Pollution Emission Guidelines for Existing

Stationary Sources: Electric Utility Generating Units, and is also referred to as 111(d) or the Clean

Power Plan (CPP).

The proposed guidelines of 111(d) are designed to achieve a 30 percent cut from 2005 emissions by

2030, with an interim target of 25 percent on average between 2020 and 2029. Each state has an

individual target to meet, with those targets expressed in a lb/MWh rate-based or mass-based CO2

emission performance levels. The EPA came up with these reduction targets using the “best system of

emission reduction” (BSER) determination, looking at technical feasibility, system costs, and

technology diffusion within each state. The BSER form four “building blocks”, which the EPA used to

determine the states’ emission goals.

3

Figure ‎2-1. BSER Building Blocks for 111(d)

These four blocks relate to 1) heat rate improvement at coal plants, 2) higher dispatch of natural gas

generators, 3) increased renewable electricity and nuclear generation, and 4) demand side

management programs. These blocks also act as tools for the states to design and implement their

plans to meet their respective emissions performance level.

States must develop plans to describe how they intend to use these tools to meet these goals. EPA has

laid out several criteria and requirements that states need to develop in their plans in order to be

considered compliant, with a deadline to submit by June 30, 2016. States are required to begin making

emissions reductions by 2020, and be in full compliance with their emission performance level no

later than 2030.

While there are differing opinions about the goals of 111(d)—some utilities support the goals, while

many others oppose them—nearly all companies with affected sources believe that the regulations

proposed under 111(d) need to be changed. Many believe the EPA has overstepped its legal authority,

or the goals set forth are either unachievable or damaging to grid reliability. Similarly, several states

are concerned that 111(d) puts their state at an economic disadvantage compared to neighboring

states, or that the goals do not take into account previous CO2 reduction efforts. Most of the concerns

from the states mirror those from the utilities, and several are bringing lawsuits against the EPA at

this time.

The final version of 111(d) will not be issued until the summer of 2015 at the earliest, and there is a

high probability that legal challenges from multiple parties could hold up rule implementation.

However, from national and global perspectives, carbon regulation has become an increasingly

important part of the business conversation. From international agreements that the US has recently

engaged in, to multi-billion dollar companies factoring carbon pricing into their long-term business

4

planning, it is imperative for every company and business to take stock of their current carbon

impacts, and understand what can be done to mitigate those emissions.

DNV GL has the technical and business expertise to help companies navigate those waters, regardless

of the final requirements of proposed rules like 111(d). These range the from Supply-Side services

such as renewable energy and retrofit support, Demand-Side services like Market Assessment and

Energy Efficiency Potential, and finally program development and implementation, such as Energy

Master Planning and Smart Green Cities Action Plans. DNV GL has been offering these services for

years, and has a proven track record of delivering value to clients in these areas.

3. EPA’S 111(D)– WHAT IS IT ALL ABOUT?

On June 2, 2014, the U.S. Environmental Protection Agency issued proposed emission guidelines for

states to follow in developing plans to address carbon dioxide (CO2) emissions from existing fossil

fuel-fired electric utility generating units (EGUs). The proposal, issued under Section 111(d) of the

Clean Air Act (CAA), is formally known as Carbon Pollution Emission Guidelines for Existing

Stationary Sources: Electric Utility Generating Units, and is also referred to as 111(d) or the Clean

Power Plan (CPP).1

111(d) is one of three rules addressing CO2 emissions from utility sources. The first, called Standards

of Performance for Greenhouse Gas Emissions From New Stationary Sources: Electric Utility

Generating Units, initially released in March 2012 and then re-proposed in September 2013,

addresses new electric generating unit emissions.2 Concurrent with the 111(d) proposed rules for

existing utility sources released in June, 2014, EPA released proposed standards of performance to

limit emissions from modified and reconstructed

fossil-fired electric utility steam generating units and natural gas-fired stationary combustion

turbines.3

The proposed guidelines of 111(d) are designed to achieve a 30 percent cut from 2005 emissions by

2030, with an interim target of 25 percent on average between 2020 and 2029. Each state has an

individual target to meet, with those targets expressed in a lb/MWh rate-based or mass-based CO2

emission performance levels. Figure ‎3-1 below illustrates the percent reduction targets of emission

rates set by EPA for the 2030 goal. The vast majority of states have a target between -20% and -40%.

1 Federal Register,” Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,” accessed on

12/18/2014 from https://www.federalregister.gov/articles/2014/06/18/2014-13726/carbon-pollution-emission-guidelines-for-existing-

stationary-sources-electric-utility-generating 2 Federal Register, 79 FR 1429, “Standards of Performance for Greenhouse Gas Emissions From New Stationary Sources: Electric Utility

Generating Units,” pg. 1429 -1519 (91 pages) accessed on 12/18/2014 from https://www.federalregister.gov/articles/2014/01/08/2013-

28668/standards-of-performance-for-greenhouse-gas-emissions-from-new-stationary-sources-electric-utility 3 Federal Register, 79 FR 34959, “Carbon Pollution Standards for Modified and Reconstructed Stationary Sources: Electric Utility Generating

Units,” pg. 34959 -34994 accessed on 12/18/2014 from https://www.federalregister.gov/articles/2014/06/18/2014-13725/carbon-pollution-standards-for-modified-and-reconstructed-stationary-sources-electric-utility

5

Figure ‎3-1. Emissions Reduction Targets by state (lbs/MWh CO2 emission reduction in 2030

compared to 2012 baseline)

The 2005 state-level emission rates used to establish these goals were determined by dividing state-

wide EGU CO2 emissions in 2005 by the amount of electricity generated at the affected fossil fuel-fired

EGUs in the same year. EPA then estimated an emission rate goal that reflects the potential for

emission reductions in each state.

Emission reduction requirements vary widely in terms of percentage reductions among states, Figure

3-2 shows emission reduction targets by state (from highest to lowest reduction):

6

Figure 3-2. Carbon Emission Reduction Targets by State until 2030 (Continental U.S.)

The EPA came up with these reduction targets using the “best system of emission reduction” (BSER)

determination, looking at technical feasibility, system costs, and technology diffusion within each

state.

Figure 3-3 shows the building blocks of 111(d). The BSER form four “building blocks”, which the EPA

used to determine the states’ emission goals. These four blocks relate to 1) heat rate improvement at

coal plants, 2) higher dispatch of natural gas generators, 3) increased renewable electricity and

nuclear generation, and 4) demand side management programs. These blocks also act as tools for the

states to design and implement their plans to meet their respective emissions performance level.4

Figure 3-3. EPA’s Best System of Emission Reductions (BSER) proposed in the existing Source Rule under 111(d)

4 Federal Register, 79 FR 34878”, Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,”

accessed on 12/18/2014 from https://www.federalregister.gov/articles/2014/06/18/2014-13726/carbon-pollution-emission-guidelines-for-existing-stationary-sources-electric-utility-generating

0%

10%

20%

30%

40%

50%

60%

70%

80%

WA

SC

NH

GA NJ

LA

TX

TN

VA

MD

OK

NV

WI

IL PA

CT

UT

NE

KS

MT

WV

KY

ME

ND

The four building blocks

of 111(d)

Improve exisiting coal-fired steam EGU heat rates.

Increase use of existing and under construction NGCC

units.

Add renewable capacity, and

discourage early retirement of

nuclear plants.

Implement demand-side

energy efficiency programs

7

A unique feature of 111(d) is that it does not target individual units. Instead, it allows states flexibility

in designing their state implementation plans to meet their CO2 reduction goals. The next section

explores the criteria for those plans set out by the EPA, and potential impacts of those plans.

3-1 State Compliance Plans

For many years, Section 110 of the CAA has required states to meet National Ambient Air Quality

Standards by developing state implementation plans (SIPs). These plans are focused around meeting

air quality standards in a geographical area for criteria air pollutant (such as lead, sulfur dioxide,

nitrous oxide, etc.) from specific sources.

The proposed rule under 111(d) differentiates itself by pursuing a system-wide approach rather than

a source-based approach. The source-based approach used in section 110 limits emissions almost

exclusively at the source of air pollution, usually power plants. The system-wide approach looks

beyond the source and allows the examination of all options that could be used to reduce emissions.5

The system approach also incorporates consideration of cost, technical feasibility and other factors.

For this system approach, EPA has laid out several criteria and requirements that states need to

accomplish in their plans in order to be considered compliant. These are the initial steps in planning

and monitoring that states need to provide to the EPA by June 30, 2016. Figure ‎3-4 shows how EPA is

proposing to evaluate and approve state plans based on four general criteria. Below these four

general criteria are twelve (12) tangible action items associated with compliance. These twelve steps

are the elements included in the Federal Register required for state compliance.6

5 Federal Register, “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,” accessed on

December 3, 2014 from https://www.federalregister.gov/articles/2014/06/18/2014-13726/carbon-pollution-emission-guidelines-for-existing-

stationary-sources-electric-utility-generating#h-9 6 Ibid. pg. 34838

8

Figure ‎3-4. Criteria for State Plans to be in Compliance with 111(d)

3-2 States, Multi-States, and the Role of Utilities

One important aspect of 111(d) is who will be held responsible for meeting targets set by the EPA.

The proposed 111(d) rule has options for the state plans to hold the EGUs fully responsible for the

emission targets (either rate or mass-based), or to have plans that rely on a portfolio approach, where

the building blocks being implemented can impact both affected EGUs as well as entities other than

the identified EGUs impacted in the state.

The proposed rule identifies two main types of portfolio approaches: utility-driven and state-driven.

The utility-driven portfolio approach takes a resource planning approach to emission reductions

whereby the state plan is envisioned to set performance standards, emission targets or similar goals

to which the utility needs to conform.

Under the state-driven portfolio approach, the measures in a state plan could include emission

standards for affected EGUs, but also requirements that apply to entities other than affected EGUs, for

example, renewable portfolio standards (RPS) or end-use energy efficiency resource standards

(EERS), both of which can apply to sectors outside of the power sector.7 The state plans could also

include a common mass-cap for the electricity sector in the state under which a cap and trade system

7 Federal Register, 79 FR pg. 34901, “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units ,”

accessed on 12/12/2004 from https://www.federalregister.gov/articles/2014/06/18/2014-13726/carbon-pollution-emission-guidelines-for-existing-stationary-sources-electric-utility-generating

Criteria for State Plans compliance

Enforceable measures that reduce EGU CO2

emissions

Identification of affected entities

Identification of state emission performance

level

Plan and geographic scope

Projected emissions goal and

timeline to achieve

Identification of emission standards

Quantifiable and enforceable standard

Plan to achieve emission

performance level

Quantifiable and verifiable emission

reductions

Identification of milestones

Description of state reporting

Monitoring and reporting plan

Reporting on plan implementation and

progress toward CO2 goal

Identification of backstop measures

Certification of hearing on state plan

Supporting material

9

could be established, similar to what is currently in place in California or the Regional Greenhouse Gas

Initiative in the Northeast. Table ‎3-1 below lays out the different approaches for 111(d), and the

target of reductions for each of those approaches.

Table ‎3-1. Four approaches for how 111(d) can be implemented

Approach Measurement Target of reductions

Rate-based CO2

Emissions Limits for

Affected EGUs

Rate-based emission

reduction targets

Affected EGUs

Mass-based CO2

Emissions Limits for

Affected EGUs

Mass-based emission

reduction targets

Affected EGUs

Utility-Driven Portfolio

Approach

Rate-based or

mass-based emission

reduction targets

Measures that directly apply to affected

EGUs (e.g., repowering or retirement of

one or more EGUs) as well as RE and

demand-side EE measures that avoid

affected EGU CO2 emissions

State-Driven Portfolio

Approach

Rate-based or

mass-based emission

reduction targets

Measures that directly apply to affected

EGUs, as well as requirements that apply

to entities other than affected EGUs, for

example, renewable portfolio standards

or end-use energy efficiency resource

standards

Multi-state action. As part of the rulemaking process, the EPA was aware that several states are

currently engaged in multi-state carbon exchanges, and wanted to have a flexible mechanism for

those systems to be accounted for in the state plans. A multi-state approach incorporating either a

rate- or mass-based goal would also be approvable based upon a demonstration that the state's plan

would achieve the equivalent in stringency, including compliance timing, to the state-specific rate-

based goal set by the EPA.8 As such, the EPA is seeking comment on whether states participating in

multi-state plans need to have a single submittal from all participating states, or if each state still

needs to submit an individual plan.

Both the common multi-state submittal and each individual participating state submittal would be

required to address all twelve plan components described in Figure ‎3-4. This is another component of

111(d) that is still under discussion, but the main emphasis from the EPA is that if states want to join

a multi-state plan that is already in existence, or create a new one, there will be mechanisms in place

for those multi-state plans to be documented.

8 Ibid. pg.34837

10

3-3 Compliance Timeline

EPA’s proposal calls for finalizing the Clean Power Plan rulemaking by June 1, 2015. Under the current

timeline, states are required to submit their plans by June 30, 2016. If a state is unable to complete its

entire plan in that time, it must submit an initial plan meeting certain minimum requirements, and

then the full plan by June 30 of either 2017 or 2018, depending on whether inter-state emissions

trading is part of the plan. States are required to begin making emissions reductions by 2020, and to

be in full compliance with their emission performance level no later than 2030. This timeline may

shift due to legal challenges and other hurdles, further discussed in Section 6-2.

Figure ‎3-5. Timeline of 111(d) implementation and compliance

Carbon market design; program design; litigation support;

investment/retirement analysis; power market studies

Carbon offset registration, monitoring and verification (certification);

operation of utility and state programs

11

3-4 Estimated Impact by the EPA

The EPA anticipates the following impacts related to implementing 111(d):

Average nationwide retail electricity prices will increase by roughly 6 to 7 percent in 2020

relative to the base case (i.e. conditions without the proposed guidelines), and by roughly 3

percent in 2030 for the contiguous United States relative to the base case. 9

Average monthly electricity bills are anticipated to increase by roughly 3 percent in 2020, but

decline by approximately 9 percent by 2030.10

Increasing penetration of demand-side programs will offset increased prices to end users by

their expected savings from reduced electricity use.

Domestic coal demand and coal prices to decline as a result of implementing the plan with

prices falling 16 to 17 percent in 2020 and roughly 18 percent in 2030, relative to business-as-

usual.

Delivered natural gas prices to increase by 9 to 12 percent in 2020 and power sector gas

consumption to increase by 1.2 trillion cubic feet (TCF) in 2020 relative to the base case, and

then begin to decline over time.

CO2 emission reductions up to 555 million tons per year by 2030 with annual compliance

costs of about $8 billion in 2030 (in 2011 dollars), equivalent to $13–$16 per ton of CO2

reduction. These costs include the amortized cost of capital investment, needed new capacity,

shifts between or amongst various fuels, deployment of energy efficiency programs, and other

actions associated with compliance.11

4. UTILITY PERSPECTIVE ON EPA’S 111(D)

While there are differing opinions about the goals of 111(d)—some utilities support the goals, while

many others oppose them—nearly all companies with affected sources believe that the regulations

proposed under 111(d) need to be changed in several ways.

4-1 Utility Perspective on EPA’s Authority Under 111(d)

The National Rural Electric Cooperative Association (NRECA) submitted comments on the proposed

rules that aggressively challenge EPA’s legal authority to promulgate rules under Section 111(d),

especially in the form being proposed. Their concerns include procedural issues regarding whether

Section 111(d) can be used to regulate electric power plant carbon dioxide emissions, as well as

doubts about the workability of the entire rule proposed by EPA. NRECA, which represents

cooperatives with a significant portion of the generating mix invested in coal, says in its comments

9 Ibid. pg. 34934

10 Ibid. pg.34934

11 Federal Register, 79 FR pg. 34934, “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units ,”

accessed on 12/12/2004 from https://www.federalregister.gov/articles/2014/06/18/2014-13726/carbon-pollution-emission-guidelines-for-existing-stationary-sources-electric-utility-generating

12

that “Because the proposed rule is unlawful and unworkable as drafted, EPA should decline to finalize

it in its present form.”12

Several Investor Owned Utilities (IOUs), mostly from the southern and mid-western regions of the US,

believe that the EPA has exceeded their authority in their decision to regulate CO2 under 111(d) of the

CAA. Figure 4-1 provides a geographical look at what these utilities are saying around the country.

12

National Rural Electric Cooperative Association,” Comments on Proposed Carbon Pollution Emission Guidelines for Existing Stationary Sources:

Electric Utility Generating Units and Notice of Data Availability,” accessed on 12/18/2014 from http://www.eenews.net/assets/2014/12/15/document_ew_01.pdf

13

Figure 4-1. Utility perspective on 111(d) and corresponding generation fuel mix of that utility in certain service territories

13

13

Regulations.gov, “Standards of Performance for Greenhouse Gas Emissions from Existing Sources: Electric Utility Generating Units,” accessed on 12/24/2014 from

http://www.regulations.gov/#!docketBrowser;rpp=25;po=0;D=EPA-HQ-OAR-2013-0602

Coal Natural Gas/Oil Nuclear Renewables Hydro Other

Utility generation fuel mix

14

4-2 Utility Perspective on the Four Building Blocks of 111(d)

The majority of the comments filed from utilities to the EPA focused around the four building blocks of

the 111(d) proposed rule, and concerns, as well as suggestions related to these options. For most of the

comments submitted, there were many similarities in concerns across the utilities.

The first building block of improving existing coal-fired steam EGU heat rates was met with much

skepticism. AEP stated that “given the inherent variability in heat rate due to duty cycles and other

uncontrollable factors, and the lack of an effective real-time heat rate measurement technique, it is

infeasible to establish traditional emission limitations or standards based on improved heat rates.” 14

Dominion also had similar perspective. They stated that industry consultants have reviewed the EPA’s

heat rate improvement methods, and believe that the short-term and long-term benefits are exaggerated.

Dominion states that many of these improvements depend on the specifics of the plants, while the EPA

cites the improvements on an industry-wide aggregate basis. Dominion believes that it is inappropriate

to apply measures determined in aggregate to individual units. They also feel that EPA hasn’t taken into

consideration that several plants may have already incorporated these efficiency increases, and therefore

the need to adjust the expected gains that could be made in different regions. 15

The second building block (increased use of existing and under construction natural gas units) was

received with concern from both heavy users of natural gas, as well as utilities that have very little

deployment of this resource. Florida Electric Power Coordinating Group notes that Natural Gas Combined

Cycle (NGCC) goal of 70% capacity factor in unachievable in the timeframe allotted. They believe the

quantity of natural gas, as well as infrastructure for distribution, is inadequate to meet this rate in

Florida.16 On the other side, utilities like Xcel were concerned that the rule doesn’t consider the impact of

renewable energy on the dispatch of natural gas combined cycle plants, related to the 70% capacity factor

target in 111(d).17 Xcel believes that EPA should consider the impact of high levels of wind penetration on

reducing NG capacity factors, and recalculate the baseline NGCC capacity factors for each state. These

wind/NGCC “displacement factors” demonstrate that NGCCs in states with high wind penetration have a

lower capacity factor due directly to the operation of wind generation in those states and their utility

systems, and the 70% capacity factor goal actually punishes states that have higher deployment of wind.

14

American Electric Power, “Comment submitted by John M. McManus, Vice President, Environmental Services, American Electric Power (AEP),”

accessed on 12/18/2014 from http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-24030 15

Dominion Resources Services, Inc., “Comment submitted by Pamela F. Faggert, Chief Environmental Officer and Vice President, Corporate

Compliance, Dominion Resources Services, Inc.,” pg. 39 accessed on 12/18/2014 from http://www.regulations.gov/#!documentDetail;D=EPA-HQ-

OAR-2013-0602-22566 16

Florida Electric Power Coordinating Group, Inc,” Comment submitted by Hopping Green & Sams, P.A., on behalf of Florida Electric Power

Coordinating Group, Inc.,” pg.6, accessed on 12/18/2014 from http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-22811 17

Xcel Energy, “Comment submitted by Frank P. Prager, Vice President, Policy and Strategy, Xcel Energy Inc,” accessed on 12/18/2014 from

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-22976

15

The third building block focuses on adding renewable capacity, and discouraging early retirement of

nuclear plants. Among many utilities, TVA’s public comments present cross-cutting concerns regarding

the ability to reach the stated goals relating to renewable energy. One major concern they express is that

EPA does not give any credit for early actions on C02 reductions before 2012, but continues to measure

reductions from 2005 levels. TVA reduced its CO2 emissions over 20% between 2005 and 2012, and they

feel those savings should count towards their goal. 18 In regards to future renewable generation, TVA also

expresses concerns about how the EPA predicted future growth of renewables, and the resource

availability to utilities. TVA states that prior growth of renewable resources is not necessarily an

indication of future growth, as technical potential is not synonymous with achievable renewable

generation because it does not consider a variety of critical factors that affect actual deployment of

renewable energy. For the nuclear energy component of this building block, TVA states that EPA’s plan

does not consider whether these nuclear units are “at risk” when setting the state goals. These are

nuclear plants that are not economically viable in capacity markets due to low natural gas prices and

units that are not planning to seek re-licensure through the Nuclear Regulatory Commission.

National Grid comments on the treatment of hydroelectric power under this third building block, and the

fact that RGGI and other states agree that it should be counted toward compliance, and not considered

part of the base. National Grid would like to see EPA include hydroelectric resources in the goal

computation procedure, and permit all existing and future hydroelectric resources to qualify for

compliance purposes.19

Finally, the fourth building block relates to energy efficiency. AEP writes that in regards to energy

efficiency, “there is no single ‘best practice’ that can be established for all states. Each state should be

allowed to incorporate its energy planning strategy into a plan under section 111(d) to the extent it

determines is appropriate.”20 Finally, Dominion states that “EPA’s yet to be determined evaluation,

measurement and verification protocols must be issued…to ensure that states are investing in those

programs that are acceptable to the EPA.”21 Dominion also points out that EPA’s approach towards

energy efficiency targets doesn’t recognize different regulatory models and rate structures from state to

state. To achieve the state’s target for energy efficiency, it may require a state commission to approve

18

Tennessee Valley Authority, “TVA Comments to EPA on the Proposed Carbon Pollution Emission Guidelines for

Existing Stationary Sources: Electric Generating Units ,” pg. 2 accessed on 12/18/2014 from

http://www.seealliance.org/wp-content/uploads/TVA-2.pdf 19

National Grid, “Comment submitted by Edward White, Vice President Environmental, National Grid,” pg.1 accessed on 12/18/2014 from

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-24299 20

American Electric Power, “Comment submitted by John M. McManus, Vice President, Environmental Services, American Electric Power (AEP),” pg. 2

accessed on 12/18/2014 from http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2013-0602-24030 21

Dominion Resources Services, Inc., “Comment submitted by Pamela F. Faggert, Chief Environmental Officer and Vice President, Corporate

Compliance, Dominion Resources Services, Inc.,” pg. 7 accessed on 12/18/2014 from http://www.regulations.gov/#!documentDetail;D=EPA-HQ-

OAR-2013-0602-22566

16

programs that are not cost-effective, thus “usurping the state commission’s authority to protect

ratepayers.”22

4-3 Utility Perspective on Timeline of 111(d)

In a press release issued in conjunction with the filing of its comments on the Clean Power Plan, Edison

Electric Institute president Tom Kuhn said, “The transition to a cleaner generating fleet requires a great

deal of time, infrastructure development and planning that EPA has not allowed for in the proposed

guidelines’ compliance schedule.”23 The issue surrounding timeframe and interim goals is shared by many

utilities as well.

The interim compliance period of 2020-2029 is especially problematic to the electric power sector, as it is

seen as something that would lead to suboptimal deployment of capital, e.g. installing large amounts of

gas-fired generation in order to meet the near-term requirements, while blocking the way for more cost-

effective compliance methods that take longer to implement. Furthermore, there is uncertainty about the

availability and accessibility of an adequate supply of natural gas to support an expanded reliance on gas-

fired power plants.

These concerns are echoed by system operators as well. John Bear, chief executive for the Midcontinent

Independent System Operator, said in a letter to EPA that the interim emissions reduction targets present

"an unrealistic time frame for action" and pose a risk to reliability beginning in 2020. MISO estimates that

14,000 MW—a fourth of the coal-fueled generation expected to exist in the midcontinent region in

2020—may be forced offline under 111(d).24

22

Ibid. pg.35 23

Edison Electric Institute, “EEI Submits Comments to EPA on the Proposed Guidelines for Greenhouse Gas Emissions From Existing Generation

Units,” accessed on 12/18/2014 from

http://www.eei.org/resourcesandmedia/newsroom/Pages/Press%20Releases/EEI%20Submits%20Comments%20to%20EPA%20on%20the%20Pro

posed%20Guidelines%20for%20Greenhouse%20Gas%20Emissions%20From%20Existing%20Generation%20Units.aspx 24

Midcontinent Independent System Operator, Inc , “MISO Comments to EPA on Proposed CPP,” accessed on 12/18/2014 from

https://www.misoenergy.org/Library/Repository/Communication%20Material/EPA%20Regulations/MISO%20Comments%20to%20EPA%20on%20P

roposed%20CPP%2011-25-14.pdf

17

5. STATE PERSPECTIVE ON EPA’S 111(D)

Several states are concerned that the EPA ruling on 111(d) does not provide fair or clear approach to

reaching the stated CO2 reduction goals.25 26 27 Many states submitted comments to EPA regarding their

concerns, and these comments were publicly available in a similar fashion to the comments from utilities.

Most of the concerns from the states mirrored those from the utilities, and could be categorized as

follows:

States that have already reduced a large amount of CO2, or already integrated natural gas into a

large chunk of their fuel mix, feel they are getting penalized by having CO2 targets that may not

incorporate that effort.

Concern that different CO2 targets across all of the states provides an uneven playing field. Some

states believe that they will be placed at an economic disadvantage to neighboring states after

comparing the CO2 reduction targets.

Concern that there will be a large decline in employment opportunity for states that rely heavily

on CO2 heavy fuel sources.

Concern that EPA does not have the authority to regulate entities under 111(d) that are already

being regulated under section 112 of the CAA.28

Other states wrote a letter in support of the law and EPA, with comments meant to help guide the EPA for

smoother implementation29:

Establish the performance level of the standard based on a “best system of emission reduction”

that reflects the full range of approaches that states have successfully demonstrated can cost-

effectively reduce carbon pollution from the electricity system as a whole;

Establish the form of the emission guideline in a way that equitably recognizes the different

starting points and circumstances of different states, including the pollution reductions achieved

by states through climate and clean energy programs; and

Allow for a variety of rigorous state compliance options, including options for compliance through

participation in regional emission budget trading programs and state portfolio programs.

25

Alabama Department of Environmental Management, “Comments to EPA on 111(d),” accessed on 12/18/2014 from

http://www.seealliance.org/wp-content/uploads/ADEM.pdf 26

Virginia Department of Environmental Quality, “Comments to EPA on 111(d),” accessed on 12/18/2014 from

http://www.seealliance.org/wp-content/uploads/Virginia-DEQ.pdf 27

Louisiana Department of Environmental Quality, “Comments to EPA on 111(d),” accessed on 12/18.2014 from

http://www.seealliance.org/wp-content/uploads/Louisiana-DEQ.pdf 28

Attorneys General of the States of Oklahoma, West Virginia, Nebraska, Alabama, Florida, Georgia, Indiana, Kansas, Louisiana, Michigan, Montana,

North Dakota, Ohio, South Carolina, South Dakota, Utah and Wyoming,” Comment from the Attorneys General … on Proposed EPA Carbon Pollution

Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,” accessed on 12/12/2014 from

http://www.ok.gov/oag/documents/EPA%20Comment%20Letter%20111d%2011-24-2014.pdf 29

State Environmental Agency leaders from CA, CO, DE, IL, ME, MD, MA, MN, NH, NY, OR, RI, VT, WA, Open Letter to the EPA Administrator Gina

McCarthy on Emission Standards Under Clean Air Act Section 111(d), December 16, 2013.,”States’ §111(d) Implementation Group Input to EPA on

Carbon Pollution Standards for Existing Power Plants,” accessed on 12/23/2014 from http://www.regulations.gov/#!documentDetail;D=EPA-HQ-

OAR-2013-0602-0198

18

6. DNV GL’S PERSPECTIVE ON EPA’S 111(D)

Will EPA’s Clean Power Plan be implemented in line with its current schedule? What is the impact on the

industry? What options should be considered besides what is already in the Clean Power Plan?

The Clean Power Plan leaves many questions unanswered and electricity providers have valid reasons to

be concerned about long term implications. A great deal is at stake and depending on when and how the

state plans are implemented, the costs to the industry and to rate payers will vary considerably. This

section provides DNV GL perspective on whether the goals of 111(d) can be achieved in allotted time,

discussing the potential winners and losers, and addressing the various compliance options that could be

implemented at the utility or state level.

6-1 Is the Clean Power Plan Achievable by 2030?

In 2012, the total emissions of CO2 from US power plants were about 2.2 billion tons and the total average

emissions per MWh amounted to about 1,300 pounds.30 If the 2030 emissions goals set up by the EPA

under the Clean Power Plan (Figure ‎3-1) were aggregated across all states and weighted by actual 2012

emissions, this would correspond to a national emissions goal of about 1,012 lb per MWh. Thus, by 2030,

the power sector would need to be about 30 percent cleaner than today. Even if we were to account for

potential load growth and only allowing natural gas fired power plants to be built in the future, an

additional 500 million tons of CO2 needs to be removed from the power sector.

Where will these emission reductions come from? There are several resource alternatives that could

potentially replace coal fired generation. First, in 2013-2014, between 5,000-8,000 MW of coal fired

generation has retired. This takes care of about 200 million tons, but leaves nearly 300 million tons per

year to be removed (see Figure ‎6-1), corresponding to another 40,000 MW of coal fired capacity yet to be

retired. Most of these additional retirements have already been announced by utilities but it is not yet

clear exactly what new capacity will take its place.

30

EIA,“ Table 9.1. Emissions from Energy Consumption at Conventional Power Plants and Combined-Heat-and-Power Plants ,” accessed on

12/24/2014 from http://www.eia.gov/electricity/annual/html/epa_09_01.html

19

Figure ‎6-1. 2030 Emission Reduction Goals and Incremental Reduction Needs

There are several options for replacing retiring coal fired generation—nuclear, combined cycle gas

capacity, wind, solar, energy efficiency are all potentially part of the mix. Figure ‎6-2 shows a simplified

example of how much of each resource would be needed if only one resource-type were to replace coal.

While clearly simplified, Figure ‎6-2 suggests that meeting the 2030 emissions goals would require a

substantial scale-up of investments in the 2015-2030 period. For example, if only wind were to replace

coal fired generation, it would require nearly 120,000 MW of new capacity, about twice the current total

installed base across the continent. If instead coal were to be replaced by natural gas, a much higher

number of coal plants would need to be retired – while clean, natural gas plants still emits about half as

much as coal fired plants.

20

Figure ‎6-2. Coal Replacement Example

Figure ‎6-2 only addresses supply side alternatives. If we instead assume that we could scale up energy

efficiency to remove 300 million tons of CO2 emissions compared to business as usual by 2030, this would

virtually eliminate load growth over the next 15 years. The United States is still among the more energy

intensive economies in the world—on par with Australia and consuming nearly twice as much electricity

per capita as Germany.31 However, progress has been relatively slow, and removing load growth

completely is clearly not a realistic near term expectation but a process that evolves over time.

So how much will compliance cost? The Clean Power Plan means that about 50 percent more capacity

would need to be built in the next 15 years than would otherwise be needed to meet load growth on a

business-as-usual basis.32 Assuming wind and new gas fired capacity cost approximately $1,000 per kW

overnight construction cost, compliance with the clean power plan could trigger $80-120 billion of

additional investments until 2030. Unless the burden of this additional investment is spread evenly

among rate payers, the rate impact could be significant for some parts of the country

31

The World Bank, “Electric power consumption (kWh per capita),” accessed on 12/24/2014 from

http://data.worldbank.org/indicator/EG.USE.ELEC.KH.PC 32

Based on an assumed capacity factor for coal, nuclear and natural gas plants of 85 percent, wind capacity factor of 35 percent and an annual load

growth of 1 percent per year.

21

6-2 Implementation Likely to be Delayed

EPA expects to finalize the Clean Power Plan rulemaking by June 1, 2015. States will be required to

submit their plans by June 30, 2016. If a state is unable to complete its entire plan in that time, they must

submit an initial plan meeting certain minimum requirements, and then the full plan by June 30 of either

2017 or 2018, depending on whether inter-state emissions trading is part of the plan. States are required

to begin making emissions reductions by 2020, and to be in full compliance with their emission

performance level no later than 2030.

There are already some signals that suggest that the Clean Power Plan may get significantly delayed. A

number of states (Oklahoma, West Virginia, Nebraska, Alabama, Florida, Georgia, Indiana, Kansas,

Louisiana, Michigan, Montana, North Dakota, Ohio, South Carolina, South Dakota, Utah, and Wyoming)

have decided to sue the EPA, claiming that the regulations are not only unprecedented but also illegal.33

The initial 90 day public commenting period was extended until December 2014 and over 3 million

comments were filed as highlighted above.34 Given the broad nature of the Plan and its uneven impact on

states as well as the significance of the both emission reductions and the level of state effort required to

design programs, it is a virtual certainty that implementation will be delayed. Further contributing to

likely delays is the fact that between today and the plan’s implementation date lie many federal and state

elections that may alter the course and ambition of the Clean Power Plan, including two presidential

elections.

6-3 The Clean Power Plan Creates Winners and Losers

Many utilities have a multi-state footprint and will thus be subject to a multitude of state-specific

emissions targets under the Clean Power Plan. The carbon footprint for utilities also varies widely—while

some rely heavily on coal, others are more dependent on nuclear and gas fired generation for their

electricity supply. But it is not sufficient to merely look at which utility has the highest number of coal-

fired power plants to find utilities at risk. The state goals and total exposure to carbon reduction targets

must also be taken into account. For example, a power company with mostly nuclear assets that operates

mainly in states with only modest carbon reduction targets may not be significantly impacted by the

Clean Power Plan, whereas a utility with high emissions on a per megawatt-hour basis and operates in

states with stringent emissions reductions requirements has much at stake, and potentially a lot to lose

unless flexible compliance mechanisms can be devised.

33

Attorneys General of the States of Oklahoma, West Virginia, Nebraska, Alabama, Florida, Georgia, Indiana, Kansas, Louisiana, Michigan, Montana,

North Dakota, Ohio, South Carolina, South Dakota, Utah and Wyoming,” Comment from the Attorneys General … on Proposed EPA Carbon Pollution

Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units,” accessed on 12/12/2014 from

http://www.ok.gov/oag/documents/EPA%20Comment%20Letter%20111d%2011-24-2014.pdf 34

Regulations.gov, “Standards of Performance for Greenhouse Gas Emissions from Existing Sources: Electric Utility Generating Units,” accessed on

12/23/2014 from http://www.regulations.gov/#!docketDetail;D=EPA-HQ-OAR-2013-0602

22

To determine who is most at risk, DNV GL developed a new metric that translates state emission

restrictions into corresponding carbon emission constraints for power producers depending on each

company’s unique combination of states in which it is active in and the emissions profile of its generation

fleet. We call this the Implied Emissions Goal for each company. Using this metric, a company that has

lower emissions than its peers (or the national average) and that operates in states with less ambitious

carbon reduction should have a lower hurdle of emissions reductions than power companies active in

states with more stringent emission reduction requirements and higher-emitting power plants. Figure

6-3 identifies how the top 50 largest power companies in the United States (generation by holding

company) compare with respect to emissions and the stringency of emission reductions that each

respective company will face with its current generator portfolio. Figure 6-3 suggests that there is a wide

spread in how exposed the companies are to the Clean Power Plan.

23

Figure 6-3. Risk analysis for largest US utilities with respect to current emissions and the stringency of emission reductions

1. PG&E Corp

2. Public Service Enterprise Group Inc

3. Exelon Corp 4. Pinnacle West Capital Corp

5. NextEra Energy Inc

6. Entergy Corp

7. Dominion Resources Inc 8. Calpine Corp

9. LS Power Group

10. Entegra Power Group LLC

11. Tenaska Inc 12. SCANA Corp

13. Carlyle Group (The)

14. GDF SUEZ SA

15. Energy Capital Partners

16. Southern Co 17. Duke Energy Corp

18. Tennessee Valley Authority

19. General Electric Co

20. Energy Future Holdings Corp 21. JEA

22. Salt River Project

23. Xcel Energy Inc

24. TECO Energy Inc

25. CPS Energy

26. NRG Energy Inc 27. OGE Energy Corp

28. Cleco Corp

29. Energy Investors Funds Group

30. Santee Cooper 31. FirstEnergy Corp

32. Lower Colorado River Authority

33. Los Angeles Dept of Water & Power

34. CMS Energy Corp 35. Dynegy Inc

36. Nebraska Public Power District

37. Berkshire Hathaway Inc

38. American Electric Power Co Inc

39. Ameren Corp 40. Westar Energy Inc

41. DTE Energy Co

42. PPL Corp

43. Tri State Generation & Transmission Association Inc 44. Wisconsin Energy Corp

45. Associated Electric Coop Inc

46. AES Corp (The)

24

With the Clean Power Plan in its current form, Figure 6-3 suggests that that many companies will face

hard choices on what resources to invest in and need to carefully consider the risks with each. Figure 6-3

also suggests that the impact will be very uneven – while some companies may escape virtually

unscathed, others may be forced to make significant investments resulting in steep rate increases.

Resource choices are many and each comes with its own set of risks: Wind is relatively affordable and

offers zero emissions but is intermittent. Nuclear energy offers emissions-free baseload energy but the

upfront costs are high, fuel disposal is controversial and the public opinion on the used nuclear energy is

mixed. The currently favored choice is natural gas—a combination of low gas prices, lower emissions and

lower capital costs means that combined cycle natural gas plants compete head-to-head with coal for

serving baseload needs. But fuel price risks remain a potential concern as gas prices tend to vary widely.

In addition to cost and emissions, reliability, fuel security and risk must also be factored in. Even though

each company’s situation and asset base is unique, a few general observations emerge if the Clean Power

Plan is implemented in its current form:

The industry is facing a huge challenge in re-juvenating its assets portfolio with gas-fired

generation, wind and solar, and possibly nuclear generation

Investor-owned companies will see a significant impact on their valuation

The rate increases for some utilities will be dramatic

State implementation plan designs will be a major factor in how high the compliance costs will go

and what the impact on rate payers will be

6-4 A Broader Range of Compliance Options is Needed

The options open to states for devising their respective state implementation plans are outlined in

Section 3, above. Figure 6-4, below, outlines the options open to states, ranging from direct regulation of

individual generating units (EGUs) to setting a mass-cap for emissions which could include only the

power sector or possibly multiple sectors and could also include a single state or multiple states.

25

Figure 6-4. Example of state implementation plan options

Despite this flexibility in state implementation plans, there could be additional options that could

contribute to reducing compliance costs, in particular offsets from other emission sources and/or sectors.

For example, in 2012 and 2013, the international offset programs Clean Development Mechanisms and

Joint Implementation used for compliance under the Kyoto Protocol issued 300-400 million tons of

carbon offsets per year.35 This suggests that there is no shortage of international carbon offsets, and these

could serve as a safety valve to hedge against high compliance costs while at the same time achieving the

equivalent emission reductions, just not in the immediate state concerned.

Another design issue is whether to regulate emissions at the point of generation or at the point of

consumption (via the load serving entity). If the targeted emission reductions were to be implemented at

the consumption point, it could allow load serving entities and generators to also factor in losses in the

transmission and distribution systems. This approach would also more accurately capture the impact of

energy efficiency, demand response, and distributed generation by taking transmission and distribution

losses associated with large central station generation into account.

For example, two of DNV GL’s large utility clients are investigating Conservation Voltage Reduction,

which reduces voltage to a feeder within allowable limits and get energy efficiency gains on both sides of

35

UNFCCC, “CDM Insights: Project Activities,” accessed on 12/24/2014 from http://cdm.unfccc.int/Statistics/Public/CDMinsights/index.html

26

the meter. DNV GL is currently providing the impact analysis for these types of programs, as utilities

want to be able to gain as much efficiency from their existing infrastructure before having to undertake

capital intensive retrofits or even new, renewable generation construction.

A broader set of options will contribute to lower compliance costs and ultimately help reduce the impact

for rate payers. But the myriad of choices creates a complex set of options to consider when designing,

monitoring and evaluating a plan to demonstrate compliance with the 111(d). The next section outlines

the service offerings that DNV GL provides to help clients understand these choices, and help develop a

plan that fits their needs.

7. DEVELOPING STRATEGY AND COMPLIANCE UNDER UNCERTAINTY

There is tremendous uncertainty on how the Clean Power Plan will play out and when it will be

implemented. The complexity is also increased by the “usual suspects” economic growth, electric

demand growth, technological change, fuel prices and capital costs for new resources. Despite this

complexity, states must devise implementation plans that will impact the power industry for decades and

investors must make long-term choices on generation supply and transmission infrastructure. DNV GL

has supported numerous power companies with decisions and investment strategy that factors in

uncertainty and have supported states and utilities with developing long term policy for renewable

generation. Tools and techniques we utilize include scenario based strategic planning, policy road-

mapping, technology road-mapping, and detailed operational research to find performance

improvements.

7-1 Designing Actionable State Implementation Plans

State implementation plans are due on June 30, 2016 with an additional grace period until June 30, 2017.

The deadline for multi-state implementation plans has currently been defined as June 30, 2018. It is likely

that these deadlines will slide since the EPA has already introduced delays in their own planning dates.

Implementation is targeted to start in 2020, and be in full compliance with EPA’s mandated emission

performance levels no later than 2030.

DNV GL’s approach for designing actionable policy draws on our experience in supporting a number of

states on important sustainability policy to improve energy efficiency, renewable energy policy, and

market design. EPA’s Clean Power Plan calls for a comprehensive examination of policy options uniquely

defined by opportunities and constraints in each state. Figure 7-1 outlines the roadmap process for

getting from today’s confusing array of compliance options to a state implementation plan.

27

Figure 7-1. State Implementation Plan Design Roadmap

DNV GL’s proposed roadmap process is driven by EPA’s Best System of Emission Reductions (4-Block

tool kit to be used by the states to design and implement plans to meet their respective emissions

performance levels).

Each state with its utilities and related stakeholders is unique when it comes to energy mix and impact

by fossil fuel-fired electric utility generating units (EGUs). While some states are mainly driven by hydro,

renewables, natural gas others are faced with more challenging choices in dealing with a power supply

fuelled by coal.

Given the wide variety of compliance options, DNV GL recommends using a comprehensive roadmapping

approach for identifying options, analysing their implications and gaining stakeholder buy-in. The

roadmapping approach allows states, utilities, rate payers industry and other key stakeholders (e.g.

renewables developers) to take full advantage of its own unique construct, needs and opportunities.

Developing a roadmap will sharpen executive vision, spur executive sponsorship and implementation to

work towards 111(d) compliance.

28

7-2 DNV GL Services to Work Towards Compliance

Internationally, DNV GL’s legacy companies DNV and GL have been active for more than 15 years in

helping companies identify carbon offsets and perform monitoring, validation and verification of carbon

emissions.

DNV GL offers services across the energy supply chain which can provide support to customers who are

trying to navigate the potential compliance options under EPA’s 111(d). We have extensive experience in

power system planning and understand the unique concerns clients have when considering upgrading

conventional generation and increasing their reliance on renewable generation. Furthermore, we

understand the importance demand-side management will play in meeting the goals of 111(d), and offer

program planning, implementation, and evaluation services to support clients in this area as well. DNV

GL’s rate & cost of service support, and load research & forecasting services, can help clients understand

the potential impact of 111(d) on their markets.

Table 7-1 provides an overview of the service offerings the DNV GL offers to clients that will aid them in

being in compliance with 111(d) carbon reduction goals. All of these services are professional resources

that DNV GL has been offering for years, and we have a proven track record of delivering value to clients

in these areas.

29

Table 7-1 DNV GL Service Offerings that support the four building blocks of 111(d)

Supply-Side Services Demand-Side Services EGU Retrofit Support:

Improve power plant operations to reduce emissions

Inspections/Certification of retrofit projects

Identify most cost-effective retrofit options for improving heat rates at existing facilities

Run utility PMO for large and complex retrofit projects

Market Assessment and Energy Efficiency Potential:

Saturation Studies

Potential Studies

Market Segmentation

Strategic Planning

Program Design

Program Implementation

Cost Effectiveness Screening

Evaluation, Measurement, and Verification:

Portfolio Evaluation

Impact Evaluation

Process Evaluation

Renewable Energy Support:

Grid integration of renewables and analysis of inertia and flexibility

Near term forecasting of renewable generation and weather

Distributed Energy Resources (DERs), storage integration, distribution systems

DSM Program Planning and Implementation:

Program Design

Program Implementation including administrative support and delivery

Carbon Emission Impact Modelling:

Estimating Carbon Impacts from Program Evaluation

Estimating Carbon Reduction Potential of DSM Measures

Conservation Voltage Reduction

Implementation

Evaluation and Measurement

Microgrid Analysis and Optimization TRM Development/ Deemed Savings Calculations

Load Research and Forecasting

Rate and Cost of Service Support

Energy Master Planning

Establish current energy consumption, greenhouse gas emissions, and energy cost baselines

Identify and prioritize energy efficiency, clean energy, and green power procurement options to be implemented over a long-term horizon

Establish milestones and verification processes

Smart Green Cities Action Plans

Develop a shared understanding of municipal and utility resources, needs, and energy goals

Develop an implantation plan that can include benchmarking, climate action planning, energy manager services, tools for analyzing infrastructure savings

30

ACKNOWLEDGEMENTS

The authors would like to thank Dr. Miriam Goldberg, Tim Pettit, Tamara Kuiken Whitiken, Jane Howell

and Bethany Genier for their invaluable support to develop this white paper. We would also like to

express our sincere appreciation for the insightful comments given by Robert Wilhite.

31

ABOUT THE CONTRIBUTING AUTHORS

Olof Bystrom Head of Section DNV GL Energy

Olof Bystrom leads DNV GL’s wholesale energy market practice. His

consulting engagements focus on utility strategy, renewables integration

and energy economics. The wholesale team covers analytical needs from

real-time operational issues that help clients understand market design and

reliability, to long term forecasts that support strategic decisions.

Dr. Bystrom has 15 years of experience in energy, climate change and

environmental markets.

Contact Info:

Olof.bystrom@dnvgl.com

510 407 3576

Bert Taube Consultant

DNV GL Energy

Bert Taube is a Principal Consultant in DNV GL’s Policy Advisory and

Research practice. He is focused on project developments related to

energy efficiency programs, utility load and financial solutions as well as

data technology. Bert has spent more than 20 years creating and leading

projects for high-voltage power transmission and electric transportation

networks as well as Big Data analytics and automation software to serve

mission-critical industries.

Contact Info:

Bert.taube@dnvgl.com

408 307 4424

Jason Symonds Consultant

DNV GL Energy

Jason Symonds is a consultant in DNV GL’s Policy Advisory and Research

practice, with experience helping utility clients perform M&V evaluations

on both residential and non-residential energy efficiency programs. This

includes developing energy efficiency potential models, as well as

performing program attribution methodology, and incorporating

Net-to-Gross Ratios into impact analysis. He has developed and

implemented surveys for Transportation and Renewable Energy program

evaluations, collecting primary data from program participants and

vendors.

Contact Info:

Jason.symonds@dnvgl.com

571 286 8174

32

Kristina Kelly Consultant

DNV GL Energy

Kristina Kelly, a Senior Consultant in DNV GL’s Policy, Advisory, and

Research team, has been working at DNV GL since June 2008 and has

ten years of energy research and analysis experience. In her current

position, Ms. Kelly has managed a number of electric and gas efficiency

potential studies and evaluations of the energy and carbon savings

attributable to the ENERGY STAR program and clean energy policy

support programs funded by the State Energy Program. Ms. Kelly also

oversaw the recent analysis of carbon and labor impacts associated with

ARRA-funded energy programs.

Contact Info:

Kristina.kelly@dnvgl.com

339 234 3330

Dick Bratcher Senior Principal

Consultant

DNV GL Energy

Dick Bratcher has spent 35 years working on environmental issues

associated with the electric power industry. His practice at DNV GL is

focused on development and delivery of consulting services that help

clients assess risks, develop strategies, and implement mitigation and

adaptation measures to minimize physical, regulatory, reputational, and

financial risk associated with greenhouse gases and other emissions.

Contact Info:

Dick.bratcher@dnvgl.com

510 338 8062

Curt Puckett Head of Department

DNV GL Energy

Curt Puckett is Head of the Client Care Department of DNV GL’s Policy

Advisory and Research Business. Curt has been in the interval load data

analysis area of the utility sector since 1979. He spent the early part of

his career with Consumers Energy (Jackson Michigan) in the areas of load

research and energy efficiency/ demand response evaluation. In 1990,

Curt Puckett and Roger Wright created a start-up called RLW Analytics

addressing the growing need to evaluate the performance of energy

efficiency and demand response programs. He was named President and

CEO of RLW in 2005. The company was acquired by KEMA in 2009.

Subsequent mergers with DNV and GL made it become part of DNV GL

Energy. Curt has held a variety of leadership positions within KEMA, DNV

KEMA and DNV ever since RLW’s acquisition.

Contact Info:

Curt.puckett@dnvgl.com

517 898 7078

33

DNV KEMA IS NOW DNV GL

About DNV GL

Driven by its purpose of safeguarding life, property and the environment, DNV GL enables organizations

to advance the safety and sustainability of their business. DNV GL provides classification and technical

assurance along with software and independent expert advisory services to the maritime, oil & gas and

energy industries. It also provides certification services to customers across a wide range of industries.

DNV GL, whose origins go back to 1864, operates globally in more than 100 countries with its 16,000

professionals dedicated to helping their customers make the world safer, smarter and greener.

In the Energy industry

In DNV GL we unite the strengths of DNV, KEMA, Garrad Hassan, and GL Renewables Certification.

DNV GL’s 2,500 energy experts support customers around the globe in delivering a safe, reliable, efficient,

and sustainable energy supply. We deliver world-renowned testing, certification and advisory services to

the energy value chain including renewables and energy efficiency. Our expertise spans onshore and

offshore wind power, solar, conventional generation, transmission and distribution, smart grids, and

sustainable energy use, as well as energy markets and regulations. Our testing, certification and advisory

services are delivered independent from each other.

Learn more at www.dnvgl.com/energy.

DNV GL can help you identify the challenges and opportunities meeting the goals of 111(d) will bring.

Contact Olof Bystrom at olof.bystrom@dnvgl.com or Bert Taube at bert.taube@dnvgl.com to find out

how we can help you develop a roadmap to successfully navigate these changes.