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Demand Side Management
Demand-Side Management and Demand Response
Demand-Side Management (DSM) is a key component of our environmental
commitment to the communities we serve. Our Conservation Improvement Program
(CIP) allows us to offer energy efficiency (EE) and demand response (DR) products
to both residential and business customers. These environmentally-focused products,
along with our renewable energy products, provide our customers with choices in
how they use energy and impact the environment. Energy savings achieved through
these products reduce our resource needs and impact how we plan to meet the longterm energy and demand needs of our customers.
A.
Energy Efficiency
In this resource plan, we continue our dedication to achieving high levels of savings
while keeping in mind the changing landscape of DSM and the customer impact such
levels may have on our resources as well as future rates. The environment in
Minnesota and nationally for energy efficiency has changed since the Commission last
examined the Company’s goals in the 2010 Resource Plann. Customer energy savings
are increasing due to energy efficiency standards and building codes, rather than as a
result of the Company’s DSM initiatives. The increasing standards greatly reduce the
future energy savings potential for the Company’s CIP since this savings occurs
outside of utility-sponsored programs.
Future energy savings potential is also declining due to organic conservation, which
the Company defines as naturally-occurring implementation of high-efficiency
equipment outside of DSM programs, or codes and standards. Lastly, there has been a
leveling of electricity sales due to the sluggish economic recovery and the Company
has experienced declines in its avoided energy and capacity costs. All of these factors
reduce the impact that utility-sponsored DSM programs can have on energy usage and
demand and make it more difficult for the Company to meet aggressive DSM goals.
Upward rate pressure also continues to be a concern as the cost of pursuing
aggressive energy savings goals increases.
In light of these factors, Xcel Energy proposes to implement an aggressive, yet costeffective, energy savings goal of roughly 1.5 percent of retail sales for the resource
planning period. We anticipate continuing to work with stakeholders to overcome
challenges facing our CIP in the coming years.
In this section, we will recap the recent historical performance of the Company’s CIP,
explain the growing concern of rate impact from these programs, discuss the many
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factors impacting the future potential of energy savings and present the modeled
scenarios leading to our recommendation.
1.
Historical Performance
Xcel Energy has one of the longest-running and most successful DSM programs in
the country. Between 1990 and 2013, Xcel Energy spent over $1 billion (nominal) on
its Minnesota DSM efforts and saved nearly 7,000 GWh of energy and 3,000 MW of
demand.
Since the last Resource Plan, the Company has continued to grow its DSM portfolio
and has been successful in expanding to new customer markets, such as multi-family;
new technologies/industries, for example data centers; and continued exploration of
new program concepts, including behavioral and midstream incentives. All the
Company’s efforts to grow and evolve the DSM portfolio proved worthwhile when in
2011, the Company achieved the state’s 1.5 percent energy savings target. A trend of
achieving above the 1.5 percent target continued for the next two years.1
Figure 1: Historical DSM Achievements 2007-2013
Below we discuss the Company’s strategies that helped achieve such high energy
savings in recent years.
The percent of sales is calculated using a three-year average of weather-normalized sales determined and
approved with each Triennial Plan (2010-2012 and 2013-2015). Due to a decrease in sales, the same amount
of savings would represent a different percent of sales when comparing 2012 and 2013. To most accurately
compare years, one should compare total MWh savings achieved.
1
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a.
Expansion of Existing Programs
Expanding our existing programs has been a major growth strategy. Programs are
reviewed on an ongoing basis to identify growth potential through the recognition
and resolution of participation barriers, the addition of new energy saving
technologies, and the expansion into new customer segments. For example, in this
triennial we adjusted the Data Center program requirements to align with industry
practices; transitioned the Energy Feedback pilot into a full program now available to
all customers through the Company’s My Account online account management
feature; and launched a new midstream program designed to make it easier for
customers to receive the benefits of our Lighting Efficiency program.
b.
Development of New Programs
Given the market saturation that has occurred with our robust portfolio of programs,
the development of new programs is vital to maintaining energy savings at the same
energy savings level of recent years. As such, we have developed a number of new
pilot programs in the past few years, such as the Energy Feedback Pilot for business
customers and the Multi-family Energy Savings Program for income-qualifying
customers. Additional details on these new programs can be found in our 2013-2015
CIP Triennial Plan docket. 2
c.
Influence of Lighting Savings
A significant portion of energy savings in both the residential and business markets
has historically come from lighting technologies, specifically the adoption of Compact
Fluorescent Lamps (CFLs). Lighting technologies are included as an aspect of a
number of other programs, including Business New Construction, Energy Star
Homes, and Home Energy Squad. In total over half of our electric direct-impact
programs claim energy savings related to lighting upgrades. Because of this, any
change to lighting standards and/or technologies has a significant impact on our
energy savings achievement at a portfolio level.
We have developed and implemented several strategies designed to provide expanded
and more convenient ways for all customers to participate in our programs, and to
motivate customers to invest in a variety of energy conservation measures. We believe
that these efforts demonstrate our ongoing commitment to innovate and improve our
DSM portfolio. Our challenge going forward is to continue to find ways to evolve our
Docket No. E,G002/CIP-12-44,In the Matter of the Implementation of Northern States Power Company,
a Minnesota Corporation’s 2013/2014/2015 Triennial Natural Gas and Electric Conservation Improvement
Program.
2
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portfolio to fit the ever-changing landscape, while keeping the portfolio well-balanced
and cost-effective.
2.
Changing DSM Landscape
Historically, DSM has reduced rates for all customers and resulted in positive benefits
for the utility, but the benefits of such investments are declining both for the utility
and its customers. Figure 2 below is a table showing the slow decline of benefits in the
form of average cost-effectiveness test results for each triennial period. We show here
the triennial averages for the societal test (which compares total societal benefits to
total costs), rate impact test (which compares system benefits to utility costs and lost
revenues), and utility test (which compares system benefits to utility costs alone).
Figure 2: Declining Cost-Benefits of DSM
The Company assesses its CIP product offerings based on several criteria in addition
to the usual cost-effectiveness tests, some of which are closely related:
Ensure value to all stakeholders: Offer products that provide benefits to
participants and the community at large. Provide options to all customer
segments. Develop a broad portfolio of offerings so all customers have an
equal opportunity to participate.
• Control costs and customer rate impacts: Act prudently on behalf of customers
by ensuring that energy efficiency costs are appropriate and managed in order
to maximize customer value.
• Balance energy and demand savings: Offer a blend of products that collectively
deliver solid energy savings and demand savings so all customers benefit
•
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regardless of whether it is through direct energy bill reductions or through
lower revenue requirements due to the electric system benefits attributable to
these products.
• Develop products that provide long-term value: Continue to develop products
that provide long-term energy and demand savings in order to affect the
Company’s resource plan to meet future customer needs.
The environment for offering these products in Minnesota and nationally is changing.
There have been several significant changes regarding technologies, economics, and
customer demand, summarized below.
a.
Declining Avoided Energy and Capacity Costs for utilities
Costs to procure or build new generation and the price of fuel to power the
generation have both declined. Natural gas, which is commonly on the margin, has
dropped in recent years. The benefits of DSM are therefore declining because the cost
of what DSM is avoiding is lower.
b.
Growing Rate Impacts for Customers
Declining avoided costs paired with greater sales losses due to energy efficiency is
causing the amount that our customers pay for our DSM portfolio to increase even as
the Company’s electric revenue requirement continues to fall. Participating customers
can counteract the increased rate impact by lowering their overall energy use resulting
in lower bills, but it is more difficult to achieve overall cost reductions from DSM that
benefit non-participants as well.
c.
Value of Peak vs. Off-Peak Savings
In addition, the DSM portfolio has changed over time to include an increasing
amount of off-peak energy saving measures. Since customers get billed a straightforward volumetric rate, customers participating in DSM receive the same bill
reductions (lost sales on the utility side) no matter when the savings occur (on peak or
off peak). The utility on the other hand, receives the most benefit if the savings occur
during the system’s peak since a kWh during the system peak is more expensive to
produce. To this end, a DSM portfolio that accumulates significant off-peak energy
savings reduce bills at a greater rate than it provides benefit and therefore can have an
impact on all customer rates.
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We will continue to support the expansion of these product offerings while ensuring
all stakeholders are benefiting from our ongoing investment. When stakeholders are
either financially neutral or benefit from our continued investment in
environmentally-focused programs, we consider it a positive investment.
3.
Future DSM Potential
As mentioned above, the future potential for the Company’s CIP is impacted by many
external factors. Our customers are influenced to reduce their usage in various ways
beyond utility programs impacting the level of potential CIP-eligible savings available.
The Company believes these other sources of energy savings – increased codes and
standards and organic conservation, which includes lifestyle changes (desktop
computers to iPads) and industry competition and marketing (ENERGY STAR®
labels) – contribute to the State’s target of 1.5 percent energy savings and should, in
some way, be reflected in the total state savings calculation. In this section, we discuss
these other sources and provide context for their impact by looking at the example of
lighting technologies.
a.
Increases in Energy Efficiency Standards and Building Codes
The federal government continues to increase energy efficiency standards for new
technologies and equipment available for sale in the United States. Two recent and
ongoing increases will lead to significant energy savings for customers, but are also
severely reducing energy savings potential from utility-sponsored DSM products.
Business lighting standards increased the baseline for energy efficient lighting in 2012
(2009 Department of Energy rulemaking) and new Residential lighting standards have
taken effect from 2012-14 to increase minimum efficiency of incandescent bulbs of
45-100W by 30 percent (2007 Energy Independence & Security Act).
The result is a large portion of the DSM lighting products we have provided in recent
years will no longer provide any incremental energy savings above the baseline
standard. In addition, the incremental energy savings will be reduced for products that
continue to provide savings in excess of the baseline. The result is that energy savings
are increasing naturally through higher standards, but DSM potential has been sharply
declining since 2013.
We further explain this situation using our lighting portfolio as an example. Figure 3
shows the total energy savings achieved due to business and residential lighting
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efficiency in the recent past, and the fraction of total portfolio energy savings they
represent.
Figure 3: Total Energy Savings Achieved in Lighting
This figure shows that the DSM potential from other measures is not anticipated to
change after the significant ramp-up to meet Next Generation Energy Act (NGEA)
targets. The variability in DSM achievements in the past few years and through the
next half-decade is largely a result of changes in savings attributable to lighting
measures.
For example, in 2013 our Business Portfolio had a goal of approximately 320 GWh
and exceeded that goal by 5 GWh. In the same year, the Lighting Efficiency
Program’s goal was nearly 55 GWh, and the actual achievements exceeded the goal by
11 GWh. In other words, the Lighting Efficiency Program was expected to generate
approximately 17 percent of the portfolio's savings and instead made up about 20
percent helping make up for programs that were underachieving. As the lighting
savings are eroded by codes, standards, and organic efficiency, our ability to meet or
exceed overall segment goals will become increasingly challenging.
While the case of Business and Residential Lighting is not typical of all technologies,
as not all technologies are subject to a recently enacted standard change, it does
illustrate a few conditions that will likely reduce the potential for other technologies.
Almost universally the subsequent improvements in efficiency for each technology are
progressively smaller in magnitude. As codes and standards increase the baseline
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efficiency, the loss in energy savings attributable to DSM programs is larger than the
increased energy savings from efficiency gains from new technologies.
b.
Organic Conservation
An additional market-based driver of the changing landscape for energy efficiency is
organic conservation, which the Company defines as energy savings achieved through
naturally-occurring implementation of high-efficiency equipment outside of DSM
programs. The energy savings resulting from this organic DSM includes customers
who take action without participating in energy efficiency programs. The drivers for
organic conservation include customers preference towards green products, new
product technologies, and competition among manufacturers to differentiate product
offerings. These factors lead to more naturally occurring energy efficiency in the
market outside of utility products and programs.
To better understand the impacts of this organic conservation, the Company funded a
research study, 2013 Assessment of Organic Conservation3 conducted by The Brattle
Group (Organic Study). This study should not be viewed as incremental to the
potential included in the DSM Market Assessment, since some customers choose to
save energy by taking actions eligible for rebates under the Company’s current
offerings but without participating in our programs. The purpose of this study is to
demonstrate that the Company’s ability to capture all of the potential within the
territory is limited by the influence of other parties that may also motivate customers
to find ways to use energy more efficiently.
While the Organic Study shows that the utility share of savings from future energy
efficiency appears to be declining, customers will continue to achieve growing
amounts of energy efficiency outside of utility programs. For instance, the study
suggests that 77 percent of energy efficiency gains in the commercial lighting market
between 2012 and 2015 is attained through organic conservation.4 This is driven by
increasingly proactive manufacturers, improvements in building practices, and energy
industry allies that have built upon our history of helping customers conserve energy.
The level of energy efficiency occurring in total depends on what is counted towards
State savings targets, as the achievements claimed by the utilities represent only a
portion of the savings realized. For example, the Department of Energy and the
Environmental Protection Agency have had success in recent years through their
ENERGY STAR efforts working with electronics manufacturers and retailers to
3
Please see Appendix P for a copy of the study.
Study, April 2014, page 12
4Organic
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produce and stock more efficient models. Energy efficiency is increasingly being
driven by multiple influencers in the market, some of them benefiting from utility
programs and others driven by the market.
4.
Future Energy Efficiency Scenarios and Recommended Goal
To identify future potential, the Company commissions several energy savings
potential studies. In 2014, DNV GL (formally known as KEMA, Inc.) performed the
2014 Update to the Minnesota DSM Market Potential Assessment (DSM Market
Assessment). The DSM Market Assessment focuses on adoption of technologies
through traditional utility-sponsored channels. However, the dynamics of the energy
efficiency marketplace are changing, thanks in part to past commitments to DSM by
the State of Minnesota and the Company.
Similar to past Resource Plans, the Company developed its energy savings scenarios
largely on the DSM Market Assessment. The scenarios modeled for this plan are
supported by the DSM Market Assessment and the subsequent versions. 5
a.
DSM Assessment
Our goal-setting analysis in this plan incorporated data from the Company’s DSM
Market Assessment as noted above. The study identified the areas and measures
where the largest DSM potential exists in our service territory.
Specifically, the Study includes:
• An estimate of current saturations of electric energy efficiency measures
included in the Minnesota Deemed Savings Database (DSD), collected
primarily through onsite survey methods,
• An estimate of the remaining DSM potential segregated into technical,
economic and market (achievable) potential,
• Energy and demand savings, costs, and lifetimes of energy efficiency measures
from the Minnesota DSD,
• Best practice results of residential and commercial programs across the
Midwest and North America, and
• Three different market potential scenarios based on the fraction of participant
costs covered by participant rebates (50 percent, 75 percent and 100 percent).
5
See Appendix Q for the current version.
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For background, DSM potential is most easily described in terms of three tiers:
Technical, Economic, and Achievable potential.
Technical potential represents the amount of DSM available, assuming that all
technically-feasible electricity energy efficiency measures are immediately installed in
year one. Economic potential is a snapshot in time that assumes all measures that pass
the Total Resource Cost (TRC) test are instantly implemented.
Economic potential represents the subset of technical potential that is cost-effective to
install when compared to supply-side alternatives.
Achievable, or market, potential represents the amount of savings that would occur in
response to program incentives and in consideration of the myriad market barriers to
adoption. Achievable potential is usually considerably lower than economic potential
because of market barriers and other challenges to implementing energy efficiency.
To estimate achievable potential for the DSM Market Assessment, KEMA used a
computer model to estimate conversion rates from inefficient products to more
efficient products for retrofit and replacement measures, and installation rates in new
buildings for new construction markets. These conversion, replacement, and new
construction penetration rates were based on utilities’ actual experiences with these
types of programs, and the observed penetration rates at various rebate levels. This
relationship between penetration rates and the various rebate levels (50 percent, 75
percent and 100 percent) were applied by measure. The resulting estimated impacts
and costs of these achievable potential scenarios are used as the basis for developing
the DSM scenarios discussed below.
b.
Developing Energy Savings Scenarios
We developed three different levels of DSM in this Resource Plan, based on the
achievable potential scenarios described above. Table 1 shows the utility costs,
expected GWh achievements, and percent of sales metric6 of each of the scenarios,
averaged over the potential study time period (2016-2021).
Estimated as the forecast of weather-normalized sales of the three-year period prior to each triennial plan
period, adjusted for exempt customers.
6
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Table 1: 2016-2021 Average Percent of Sales by Scenario
Rebate
Level
50%
75%
100%
GWh
393
444
516
Cost
(millions)
93
137
217
% of
Sales
1.36%
1.53%
1.78%
Given the percent of Sales averages, the three scenarios are referred to as the 1.3
percent, 1.5 percent and 1.7 percent DSM scenarios. The 1.7 percent scenario
represents the achievable potential at 100 percent rebate levels. The Company believes
this is the maximum reasonable achievable scenario, so it is not feasible to model 2
percent of sales.
Beyond 2021, the Company does not have an estimation of the potential costs or
achievements of DSM, although the Company does believe that the future energy
savings potential will continue to decline. For this reason, the savings associated with
the 50 percent Rebate Level of 393 GWh is used for each of the scenarios beyond
2021. Table 2 shows the DSM scenarios through the 2030 program years considered
in the DSM modeling:
Table 2: GWh Goals by Scenario
Scenario
1.3%
1.5%
1.7%
Rebate Level
50%
75%
100%
2016-2021
GWh
393
444
516
2022-2030
GWh
393
393
393
Ordering Point 2e from the Commission’s February 27, 2014 Order in Docket No. E002/RP-13-368 requires the Company to evaluate the energy efficiency potential
among all customers, including those that are CIP exempt. The Company complied
with this requirement with the completion of the DSM Market Assessment, which
evaluated potential among all customers. The Company also evaluated the future
energy savings potential specifically with our CIP exempt customers. Knowing that
these customers must continue to implement energy efficiency improvements in order
to remain CIP exempt, the Company believes it is reasonable to assume the same level
of energy savings to occur in the future as it has historically with these customers.
Since historical energy savings from these customers are reflected in actual sales data
(reduced sales) it was determined that future energy savings (reduced sales) are
embedded into the sales forecast at the rate at which they occurred in the past. Based
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on this, and the fact that CIP exempt customers cannot participate in DSM, the
Company has not included any additional potential for these customers in the DSM
scenarios.
c.
Modeling Results
Our DSM portfolio has traditionally been modeled to include a reduction in load
rather than an additional resource to be chosen. The Commission has raised concern
around the justification for this practice.7 Modeling DSM as a reduction in load
assumes that that DSM is the most cost-effective resource available and thus chosen
over and before any further chosen resource. If DSM was instead used as resource
that could be picked from various sources, it would compete with resources such as
wind and solar and varying levels of DSM. The Utility Test net benefits presented in
Table 3 demonstrate that the DSM scenarios are more cost-effective than supply-side
resources; however, the preferred 1.5 percent DSM scenario provides the greatest net
benefits.
To determine the cost-effectiveness of each of the three DSM scenarios, the expected
impacts of each of the scenarios are modeled in the Strategist model runs given
various scenarios. The DSM impacts and costs were limited to pursuit of the three
levels of DSM over the 2016-2030 DSM program years, which include lifetime
impacts extending from 2015-2048 given the 20-yr life of some measures installed
over the 2016-2030 program years.
Table 3 below shows the present value (2015) net benefits of each of the three DSM
scenarios using the Utility Test and Total Resource Cost Test, which are routinely
applied to DSM programs to determine cost-effectiveness. The Utility Test includes
the system benefits and utility costs resulting from DSM and is similar to the
minimization of revenue requirements criteria generally applied to supply-side assets.
The Total Resource Cost test additionally includes any net costs paid by DSM
program participants.
August 5, 2013 Notice from the Commission to all utilities (Docket No.E002/RP-10-825) referencing the
Commission’s May 10, 2013 ORDER in Minnesota Power’s Resource Plan (Docket No. E015/RP-13-53.
7
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Table 3: Scenario Benefits – Net Benefits
($ millions)
2016-2030 Program Years
1.3%
Utility Cost Test
$2,273
Total Resource Cost Test
$1,825
1.5%
$2,118
$1,870
1.7%
$1,851
$1,851
These results show that the most beneficial DSM scenario in terms of minimizing
revenue requirements (Utility Cost Test) is the 1.3 percent scenario. This scenario
provides nearly $2.3 billion in avoided revenue requirements over the 15 program
years. As the level of DSM pursued increases to 1.5 percent and 1.7 percent, revenue
requirements are still avoided at significant levels, but the total in avoided revenue
requirements declines. This occurs because the increase in utility costs resulting from
higher rebates applied to the entire population of participants exceeds the system
benefits attained from the incremental participation resulting from the higher rebates.
These results also show that the Total Resource Cost rises slightly to peak at 1.5
percent of sales, but then declines. The 1.7 percent scenario is estimated to be attained
with rebates equal to 100 percent of the participant costs, removing participant costs.
This scenario produces marginally less net benefits. This suggests that the marginal
DSM measures that are adopted with the significant reduction or removal of costs to
participants tend to be marginally cost-effective or even non-cost-effective.
Based on the modeling results, the Company recommends use of the 1.5 percent
DSM scenario as the preferred scenario, for the following reasons:
• The 1.5 percent scenario offers the greatest TRC net benefits.
• 1.5 percent of sales is comparable to the recent historical achievements of the
Company and is equal to the current statewide goals.
• The spend required to achieve the 1.5 percent of sales goal ($137 million per
year) at a level somewhat higher than recent historical spend, shows a
continued strengthened commitment to DSM by the Company.
• Pursuit of goals beyond this level require spend levels double the current spend
($218 million per year for 1.7 percent of sales) and results in no additional net
benefits.
Consistent with previous approved resource plan goals, we ask the Commission to
approve our proposed goals, provided in Table 4 below, for the terms of the planning
period, and not on an annual basis. The Company will file CIP plans every three years
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with more detailed annual goals and budgets, which may be approved or modified by
the Department of Commerce, Division of Energy Resources.
Table 4: Recommended DSM Goals
Scenario
1.5%
B.
Rebate Level
75%
2016-2021
GWh
444
2022-2030
GWh
393
Demand Response
Demand Response is commonly referred to as load management, which means an
activity, service or technology to change the timing or the efficiency of a customer’s
use of energy that allows a utility or customer to respond to wholesale market
fluctuations or to reduce peak demand for energy or capacity.8
This resource plan finds our demand response portfolio in a period of uncertainty.
While we continue our commitment to providing customer options and growing our
demand response resources, we must be vigilant in adjusting the portfolio as the
landscape for such resources becomes more defined through federal regulation and
additional requirements by the Midcontinent Independent System Operator (MISO).
Additionally, new technologies are being developed to provided customer additional
choices as to how and when they reduce their usage moving demand response from a
utility controlled resource to one controlled directly by customers. How these
technologies are used and to what extent they can be verified are being tested. The
type of demand response resources we could use within our portfolio and specifically
within this Resource Plan have become more complex as the landscape for such
offerings adjusts.
Load projections for our demand response resources have dropped since examining
targets for the portfolio in our 2010 Resource Plan. This change is in part due to EPA
rules and requirements and adjusting claimed savings for certain technologies. Finally,
as the Company experiences declines in avoided energy and capacity costs the value
proposition for offering additional demand response resources alters. We present
demand response scenarios within this resource plan based on these observed changes
in the marketplace, contracted third-party analysis and detailed modeling.
8
Minn. Stat. § 216B.241
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Despite the uncertainty in today’s environment, the Company is challenged to
increase demand response without knowing the future rules for which we will be held
accountable to and the associated impacts it may have on our customers. Therefore
while we recognize an opportunity to grow our existing demand response portfolio,
the Company presents moderate growth in this Resource Plan through 2030. The
projected growth includes 76 MW for a total of 1,009 MW of demand reduction by
2030. We anticipate significant change in the portfolio over the next several years as
the new marketplace becomes settled and look forward to working with stakeholders
as we adjust our portfolio to align our programs.
The remainder of the demand response section within the DSM Appendix will
outline the challenges the Company will face as we adapt to the changing landscape of
demand response. We’ll review the results of the Company’s third-party potential
study and note the opportunities that exist today before presenting our future demand
response scenario.
1.
Landscape for Demand Response
The Company has a long history of continued success with demand response.
Beginning in the 1980’s, the Company was one of the first utilities in Minnesota to
bring various load management programs for all customer classes to market. We’ve
since grown our offerings so it now exceeds 930 MW or approximately 10 percent of
our system peak.
The demand response industry is in the midst of significant change due to evolving
federal regulations and impending rules adjustments for Independent System
Operators (ISO’s) that will alter the use and value of demand response to utilities and
customers. Additionally, changes in technologies and how demand response is utilized
will impact future potential. The following summarizes some of the ongoing changes
and developments that are not yet finalized that will impact NSPM and NSPW DR
well into the future.
a.
Market Rules
The Company originally launched DR programs to ensure reliable energy to all
customers at times when the local system was constrained, typically due to high use or
unexpected plant outages. The landscape remained mostly unchanged, and hence our
DR portfolio is used only as an emergency resource. In the past few years, attention
on the national level has increased related to the use of DR. The view was that DR as
a resource should be on par with other generation resources within energy markets;
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for NSPM and NSPW, that market is defined by MISO. The key change was defining
DR relative to other generation resources based on economics. This change was
spurred by Section 529 of the Energy Independence and Securities Act of 2007,
followed by new FERC rules.
FERC 745 in 2011 set rules for compensation levels in the day-ahead and real-time
energy markets. MISO has recently adjusted their rules on compensation in response
to FERC 745. With this compensation adjustment, there are additional requirements
and review of utility DR portfolios. In 2014, the U.S. District Court vacated FERC
745; putting the future of demand response in question. As of the filing of this plan,
this order is still unsettled and is being contested. For now, the associated MISO rules
still stand but they may change before the issue is settled, creating uncertainty for how
we intend to use and adjust our DR portfolio within the MISO market. The Company
continues to actively monitor these changes.
The Company is aware that change is occurring, but with an uncertain future is
cautious about making substantial changes to the programs impacting our customers
until there is more certainty.
b.
Technology
New DR technologies are developing rapidly due to the anticipated future market
opportunities. We expect these advancements will lead to increased choices for
customers to participate in DR and have more control over how they use and save
energy. Based on our interpretation of the developments, we anticipate there will be
two different types of customer demand response categories in the future: NonDispatchable and Dispatchable.
Dispatchable Resources involve direct or physical control of electric demand reductions
from retail customers that often are utilized during specified time frames. DR
programs over the past few decades have mostly been Dispatachable DR. Customer
offerings in this category include:
• Direct Load Control (DLC). The utility directly controls a customer’s load during
periods of high demand. The Company’s Saver’s Switch program is a DLC
product. A switch is installed on a central air conditioner which is remotely
cycled during periods of peak demand in the summer months.
• Interruptible Tariffs. Customers agree with the utility to reduce consumption to a
pre-specified level in return for an incentive, credit or discount. The Company’s
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Peak Control and Energy Control offering are the Company’s Interruptible
Tariffs.
• Other Demand Response Offerings. Examples include capacity bidding, demand
bidding and aggregator offerings. These resources can either be controllable as
customer obligation or as a voluntary load reduction indicated by a trigger in
demand price. The Company does not currently have these types of resources
within their portfolio.
Non-Dispatchable DR is indirect or non-physical control of electric demand reductions
from retail customers often taking place during reoccurring intervals and often
referred to as dynamic pricing strategies. The Company’s Time-of-Use rate is a pricing
strategy, but is not currently used as a DR resource.
Many new technologies focus on Non-Dispatchable Resources, which could include
pricing scenarios and smart thermostats. While this type of DR expands the
opportunity for customer engagement, it also changes how the utility depends upon
and utilizes these resources. It should be noted that due to the uncertainty that exists
today, it is uncertain whether these resources could be used to meet MISO resource
requirements since many of them are currently not eligible for resource compliance.
2.
2013/2014 Demand Response Potential Study
In our last Resource Plan, we provided the Commission a demand response
benchmarking study to provide context to how the Company compared to other
portfolio’s across the nation. While the data provided a significant addition of
potential savings, it didn’t include appropriate cost-effectiveness review or qualitative
data to lend to its effective use within the resource plan. As such, in accordance with
the Commission’s March 5, 2013, Order in Docket Order No. E002/RP-10-825, we
completed a potential study on demand response for the entire NSP System, which
encompasses customers served by the Northern States Power-Minnesota (NSPM) and
Northern States Power-Wisconsin (NSPW) operating companies. The following
outlines the Commission Order:
Demand Response: Xcel shall evaluate the potential capacity savings that Xcel could achieve
via demand response programs, and the extent to which Xcel may rely on demand response in
forecasting future years
The Company hired The Brattle Group to quantify the market potential for DR
programs to reduce peak demand within the NSP System. The study titled, The
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Appendix G
Demand Side Management
Demand Response Market Potential in Xcel Energy’s Northern States Power Service Territory
(DR Potential Study) 9, includes (1) an overview of what demand response opportunity
exists in the market regardless of cost effectiveness, and (2) supply curve information
that includes specified price points. The Company used the supply curve data to
inform our resource planning process.
The raw analysis from the potential study identified nearly 400 MW of additional DR
market potential through 2028, excluding dynamic pricing. This analysis also excluded
the cost effectiveness of this new potential. This megawatt potential is defined by one
portfolio identified within the study. The study does provide further portfolios. It
should be noted that these portfolios were developed to remove the natural overlap
resulting from similar products within the marketplace. Potential developed per
product type can’t be added to products in isolation.
The Brattle Group determined market potential using empirically-based assumptions
about the eligible customer base, participation and per-customer impacts. The
Company provided market characteristics and observed per-participant impacts where
available to assist in the evaluation. In the case of price-based options, the Company
utilized estimates from The Brattle Group’s extensive library of recent pilots across
the country, as well as results of pilots in the Company’s other jurisdictions.
Additionally, the DR Potential Study shows the incremental potential for dynamic
pricing strategies, including pricing rates such as time-of-use and critical peak pricing.
While there was market potential identified, the Company chose not to review the
cost-effectiveness of these programs, because we currently do not have the metering
infrastructure in place to support the two-way communications necessary for
advanced pricing strategies.
The second part of the DR Potential Study created supply curves the Company could
use within the Strategist Model. The supply curves account for a range of customer
incentive levels that could be offered for each demand response option.10 The midlevel price point translates loosely into our current incentive levels 11 while the others
are lower or higher to help determine potential price points for resource planning
analysis.
See Appendix O for the study.
Demand Response Market Potential in Xcel Energy’s Northern States Power Service Territory, The Brattle Group, April
2014, page 11.
11 The Electric Rate Savings program offer different options – for ease of review we combined all of these
into one price point.
9
10
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Appendix G
Demand Side Management
The Company offers a cautionary remark regarding the DR Potential Study. The study
was intended to provide long-term view of market potential that may exist within our
service territory. The potential data from the Brattle Group analysis and report is
based on a snapshot at a particular point in time. The actual implementation of
programs and new opportunities must be reviewed individually by the Company as
conditions in the future evolve.
The final part of DR Potential Study was to provide an analysis of what type of
savings would be needed to perform in the top 25 percent of participation for such
programs nationwide. This request was made per Commission Order in Docket No.
E-002/RP-10-825.
Consider the goal of achieving participation rates for demand response programs in the top 25
percent of such programs nationwide, as addressed in Xcel’s 2012 Demand-Side
Management Market Potential Assessment, to help meet projected demand in the 20172019 timeframe.
Figure 5, shows the results of this analysis. It is important to note that these measures
do not include cost-effectiveness and assume that measures are offered in isolation.
Figure 4: Comparison of Scenario Results 12
Demand Response Market Potential in Xcel Energy’s Northern States Power Service Territory, The Brattle Group, April
2014, page 77.
12
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Appendix G
Demand Side Management
The analysis shows the Company’s demand response potential based on primary
market research is similar, but slightly higher, than estimates based on the national 75th
percentile of participation rates. Impacts of our current demand response portfolio
are below this national average.
The Company has two additional concerns regarding this Order Point and how it was
answered by The Brattle Group. First, the data used to review the “top 25 percent”
was originally identified within FERC’s 2011 survey entitled 2012 Assessment of Demand
Response and Advanced Metering as consistent with our original potential study. This data
does not address cost-effectiveness; nor does it note where in the country these
programs exist. Second, there is a significant difference between how different utilities
use demand response dependent upon the market construct in which they operate.
For instance, in the PJM Interconnection market demand response resources are paid
a higher price than other alternatives. PJM prices DR higher than in MISO, which
impacts the amount of demand response that is available and used by customers
across the nation.
The Company drew several conclusions from the 2013/14 market potential study.
• Incremental demand response potential exists within our territory. As indicated by the
Study and subsequent cost-effective screening, there is approximately 130 MW
of additional load potential in NSP based on lower price points.13
• Growth will be dependent on market conditions. Additional growth in DR programs
will be dependent upon market conditions. The Study presents discussion
around MISO and provides potential for demand bidding products –
dependent upon the outcome of market pricing and rules. Uncertain conditions
today make it difficult to predict how DR will be used in future planning.
• Continue to assess dynamic pricing. There are several considerations around
dynamic pricing options. To-date, these types of resources are not used for
demand response (as noted above) and are therefore not included in setting
future targets. As an ongoing rate option for customers, these strategies
continue to be analyzed.
13
“DR Cost-Effectiveness Screening Memo” June 30, 2014, can be found in Appendix N.
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3.
Appendix G
Demand Side Management
Future DR Scenarios
The Company is currently below targets established in its 2010 resource plan, and
therefore has less DR resources available than originally projected in the 2013
potential study. It is not uncommon for a demand response portfolio to change as our
participating customers’ needs change and adjustments to load selection frequently
occur. Part of maintaining a DR portfolio is projecting normal load loss. Two specific
things occurred between 2010 and 2014 that lowered our original projections: a drop
in per switch estimates for Saver’s Switch and a significant (~20 MW) drop in Electric
Rate Savings participation due to extended EPA rules for back-up generation14.
Table 4 shows the 2010 DR levels compared to those we are forecasting within our
current Resource Plan.
Table 5: Cumulative DR MW –
2010 Resource Plan Compared to 2015 Resource Plan
Cumulative MW of DR by Year
IRP
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2010
1,103
1,111
1,115
1,111
1,107
1,103
1,099
1,095
1,091
1,087
1,083
1,079
1,076
1,072
1,068
1,065
2015
933
942
953
964
975
986
996
1,007
1,017
1,028
1,030
1,025
1,021
1,017
1,013
1,009
The proposed levels of demand response include both incremental load, as identified
within the market potential study, as well as replacement load lost as a result of
customer choice.
The Company has taken the DR Potential Study and reviewed potential costeffectiveness of incremental growth. We’ve also had to account for load loss within
the current portfolio in 2015 (~159 MW) compared to the 2010 Forecast. Overall, the
portfolio will grow by nearly 76 MW (more than half of the identified cost-effective
load found in the Study).
Although we are currently maintaining our portfolio rather than significantly adjusting
for growth, the Company is aware of ongoing change and opportunity within this area
of business. We are actively reviewing potential adjustments to existing programs, new
program opportunities and new ways of incenting customers to participate. The
Reciprocating Internal Combustion Engines (RICE) National Emissions Standards for Hazardous Air
Pollutants (NESHAP) rules published January 2013
14
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Xcel Energy
Appendix G
Demand Side Management
Company commits to continuing this analysis and informing the Commission as
changes and additional programs are being developed. We believe that it best to not
make significant changes to our demand response targets and programs until such
time as there is more certainty in the market and further planning can occur utilizing
the results of our analysis.
The future opportunities to grow demand response remain uncertain. The Company
views demand response as a valuable means of ensuring the reliability of its service at
a reasonable cost. We will continue to watch the evolution of demand response in the
marketplace – reviewing opportunities, and changing our portfolio and programs
based on prospects that continue to provide cost-effective options for customers.
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