BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO
PROCEEDING NO. 19R-0096E
IN THE MATTER OF THE PROPOSED AMENDMENTS TO RULES REGULATING
ELECTRIC UTILITIES, 4 CODE OF COLORADO REGULATIONS 723-3,
RELATING TO ELECTRIC RESOURCE PLANNING, THE RENEWABLE ENERGY
STANDARD, NET METERING, COMMUNITY SOLAR GARDENS, QUALIFYING
FACILITIES, AND INTERCONNECTION PROCEDURES AND STANDARDS

COMMENTS OF

Colorado PUC E-Filings System

THE COLORADO ENERGY OFFICE

May 1, 2019

 TABLE OF CONTENTS
INTRODUCTION ..................................................................................................................... 1
COMMENTS............................................................................................................................. 3
I.

Definitions (3001)........................................................................................................... 3

II. Electric Resource Planning Rules (3600-3617) ............................................................. 3
A.

Rule 3600: Applicability ............................................................................................. 4

B.

Rule 3601: Overview and Purpose ............................................................................. 7

C.

Rule 3602: Definitions ................................................................................................ 8

D. Rule 3603: ERP Filing Requirements ........................................................................ 8
E.

Rule 3604: Contents of the ERP................................................................................. 9

F. Rule 3605: Cooperative Electric Generation and Transmission Association
Reporting Requirements ..................................................................................................11
G. Rule 3606: Electric Energy and Demand Forecasts .................................................11
H. Rule 3607: Assessment of Existing Resources ..........................................................12
I.

Rule 3608: Transmission Resources .........................................................................13

J.

Rule 3609: Planning Reserve Margins and Contingency Plans ...............................14

K. Rule 3610: Assessment of Need for Resources..........................................................14
L.
III.

Rule 3617: Amendment of an Approved ERP ...........................................................14
Renewable Energy Standard Rules (3650-3668) ......................................................15

A.

Rule 3654: Renewable Energy Standard ..................................................................17

B.

Rule 3656: RES Compliance Plan .............................................................................19

C.

Rule 3657: Standard Rebate Offer, REC Purchases, and Contracts ........................24

D. Rule 3658: Renewable Energy Credits .....................................................................26
E.

Rule 3659 and 3661: Cost Recovery and Retail Rate Impact ...................................26

F.

Rule 3662: RES Compliance Reporting ....................................................................27

IV.

Net Metering Rules (3675-3699) ...............................................................................28

A.

Rule 3678: Eligible Retail Renewable Distributed Generation ................................29

B.

Rule 3679: Net Metering Credits ..............................................................................30

C.

Rule 3680: Metering Requirements ..........................................................................31

D. Rule 3681: Rates for Net Metering ...........................................................................33
V. Community Solar Gardens Rules (3875-3883) .............................................................33
A.

Rule 3881: Billing Credits and Unsubscribed Renewable Energy ...........................34

B.

Rule 3882: Purchases from CSGs .............................................................................36

ii

 VI.

Qualifying Facilities Rules (3900-3953)....................................................................38

VII.

Generation Interconnection Procedures (3668-3675) ...............................................40

A.

Rule 3853: General Interconnection Procedures ......................................................41

B.

Rule 3854: Level 1 Process ........................................................................................42

CONCLUSION ........................................................................................................................43

iii

 The Colorado Energy Office (“CEO”), by and through its undersigned counsel, hereby
submits comments related to the above-captioned matter, pursuant to Public Utilities
Commission (“Commission”) Decision No. C19-0197. CEO appreciates the opportunity to
provide comments for the Commission’s consideration in response to its Notice of Proposed
Rulemaking (“NOPR”) to amend the Commission’s Rules Regulating Electric Utilities, 4
Code of Colorado Regulations (“CCR”) 723-3.
INTRODUCTION
CEO is a state agency, statutorily charged with sustaining Colorado’s energy
economy and promoting all Colorado energy, as well as promoting energy efficiency,
increasing energy security, lowering long-term consumer costs and protecting the
environment. See § 24-38.5-101 C.R.S. CEO’s statutory duty includes “[w]ork[ing] with
communities, utilities, private and public organizations, and individuals to promote…
[c]lean and renewable energy, such as wind, hydroelectricity, solar, and geothermal,” and
“[e]nergy efficiency technologies and practices.” See § 24-38.5-102, C.R.S. CEO’s mission is
to deliver cost-effective energy services and advance innovative energy solutions for the
benefit of all Coloradans.
Previously, CEO provided two rounds of comments and proposed redline rules in the
“Stakeholder Outreach Proceeding” (Proceeding No. 17M-0694E), addressing the
Commission’s rules implementing the state’s renewable energy standard (“RES”); rules
related to interconnection; rules providing guidance on qualifying facilities (“QFs”); new
rules related to distribution system planning (“DSP”); and rules governing the electric
resource planning (“ERP”) process. In preparing these previous comments, CEO worked
with a number of other interested participants to develop the collaborative redline rules
that were provided as attachments in that proceeding.

1

 CEO appreciates the opportunity to provide comments to the Commission in support
of CEO’s mission. CEO is not proposing new rule language at this time, but we intend to
provide redline proposals at a later date.
CEO welcomes the Commission’s retention of competitive bidding in electric
resource planning and the overall effort to streamline and clarify the resource planning
process. CEO also welcomes the discussion about the best way to integrate RES and other
planning processes with the ERP process and supports a pre-ERP process among
stakeholders. We support the Commission's proposed changes that provide opportunities for
Colorado’s low-income and underserved groups to participate in and benefit from the
development of clean energy that can help reduce their energy burden. CEO’s comments
reflect not only our statutory duties; we also propose changes that further Governor Polis’
climate and energy goals including: decarbonizing the grid, electrifying transportation,
advancing other beneficial electrification, and ensuring that all Coloradans have a
reasonable opportunity to benefit from clean energy. These initial comments explain CEO’s
continued support for many of the modifications it proposed in the Stakeholder Outreach
Proceeding and, in places, expand on those proposed modifications. CEO’s comments
address all the topics in the NOPR.
CEO recognizes that the Commission undertook significant efforts to hear from
different stakeholders on a range of issues as part of its Stakeholder Outreach Proceeding.
CEO notes that the Commission appears not to have adopted many of the consensus
proposals that we recommended. Further, as discussed in our comments, CEO views
several of the Commission’s draft proposal as departures from current practice.

2

 COMMENTS
I.

Definitions (3001)
CEO recommends that the Commission add a definition of Distributed Energy

Resource (“DER”) to the definition section.
The rules currently define and reference “demand-side resources,” which include
energy efficiency, energy conservation, load management, and demand response or any
combination of these measures. CEO believes that this definition leaves out other
important technologies that should be considered in planning such as distributed renewable
generation, energy storage, electric vehicles, and microgrids. CEO recommends that the
Commission adopt a definition of DERs includes both the demand-side resources already
defined in the Commission’s rules but represents a larger category of resources including
just listed.
II.

Electric Resource Planning Rules (3600-3617)
The ERP rules establish a process to develop portfolios of electric generation

resources that cost-effectively meet the energy needs of Colorado’s public utilities. As stated
in Rule 3601, it is a policy of the state of Colorado that a primary goal of electric resource
planning is to minimize the net present value of revenue requirements (“NPVRR”). In
addition to minimizing NPVRR, the Commission must give the fullest possible
consideration to the cost-effective implementation of new clean energy and energy-efficient
technologies. The general intent of CEO’s proposed modifications to the ERP Rules are to
(1) ensure utilities are, to the extent possible, integrating other planning process with
resource planning; (2) increase the transparency and inclusiveness of the ERP process and
allow for more robust stakeholder engagement; (3) ensure the rules encourage the adoption
of eligible energy resources, and particularly, distributed energy resources (“DER”); and (4)
reduce the carbon intensity of Colorado’s electricity generation. These comments discuss
3

 CEO’s recommended modifications rule by rule and address a number of the Commission’s
questions related to the ERP Rules.
A.

Rule 3600: Applicability

CEO recommends that the Commission subject Tri-State Generation and
Transmission Association’s (Tri-State) resource planning process to the same level of
scrutiny as plans submitted by other public utilities. CEO submits that reducing carbon
emission in Colorado requires reducing emissions from all the state’s public utilities and
that stronger Commission oversight of Tri-State is a key to meeting carbon reduction goals.
Currently, the Commission does not require Tri-State to participate in the same
resource planning process as the other public utilities that are not exempt from
Commission oversight. CEO recommends the Commission require Tri-State to seek review
of its resource need and its acquisition of new generation and transmission resources
through the full ERP process, and that the Commission apply the same standards of review
regarding minimizing NPVRR and meeting other state policy goals to Tri-State that it
applies to other utilities. As discussed below, CEO supports the Commission’s view that it
possesses the legal authority to require Tri-State to file a resource plan for approval by the
Commission, and CEO believes that doing so would further state policies and better ensure
that more Coloradans see the benefits of a transition to renewable energy resources
including lower energy costs, cleaner air, and reduced greenhouse gas emissions.
The Commission has long held that it has authority to require Tri-State to file an
ERP and to apply for a Certificate of Public Convenience and Necessity (“CPCN”) for new
resources.1 To date, the Commission has declined to assert its authority and has instead

1

See Decision Nos. C09-0092, ¶¶ 4-8, and C10-0101, ¶ 15, in Proceeding No. 09I-041E.

4

 merely required Tri-State, through Rule 3605, to file a report showing its load forecasts, an
assessment of existing resources, its planning reserves, and a needs assessment.
The Commission’s authority over Tri-State stems from its Constitutional authority
over public utilities. The Commission’s authority under article XXV of the Colorado
Constitution is not narrowly confined, rather it extends to incidental powers that are
necessary to enable it to regulate public utilities.2 The Public Utilities Law provides
additional authority and restrictions on the Commission’s jurisdiction over public utilities
in Colorado. By statutory definition, Tri-State is a public utility because it is an “electrical
corporation” in Colorado that “operat[es] for the purposes of supplying the public.”3 TriState is not considered a “cooperative electric association,”4 therefore, it cannot exempt
itself from Commission jurisdiction.5 In fact, the Commission recently reaffirmed its
authority to regulate the rates, charges, and tariffs of Tri-State.6
Further support for the Commission’s authority over a public utility’s generation
and transmission resource planning process comes from the requirement of a public utility
to first obtain a CPCN from the Commission before constructing “a new facility, plan, or
system or extension if its facility, plant, or system.”7 Because Tri-State is a public utility
and it is not exempt from the statutory CPCN requirement, Tri-State is not exempt from
participating in the Commission’s ERP process. As stated above, the Commission has
chosen not to require Tri-State to file ERPs in the past, but it has always had the authority
to do so.

Colo. Const. art. XXV.
§ 40-1-103, C.R.S. (public utility defined).
4 § 40-9.5-102, C.R.S.
5 See § 40-9.5.103, C.R.S. (allowing cooperative electric associations to vote to exempt themselves
from Commission jurisdiction.).
6 Decision No. C19-0297-I, ¶¶ 16-27, in Proceeding No. 18F-0866E.
7 § 40-5-101, C.R.S.
2
3

5

 CEO suggests that the time is ripe for the Commission to require Tri-State to
participate in a more robust ERP process that assesses the utility’s proposed resource need
and reviews and approves the resources proposed to meet that need in order to ensure that
Tri-State’s resource plan minimizes the NPVRR and meets other state policy goals.
Tri-State serves 18 electrical cooperatives in Colorado. Under the Commission’s
current approach, Tri-State files its report informing the Commission of its resource need.
The Commission may choose to hold a hearing and solicit public comment on the report and
it may issue a decision “express[ing] its opinion” about Tri-State’s plan, but the Commission
does not approve, modify, or deny Tri-State’s plan for meeting its future resource need.8
Recently, the Commission has not held a hearing or issued any opinion about a Tri-State
resource report. Unlike the more rigorous approach taken with the other public utilities,
there is no opportunity for a third-party to review the assumptions that Tri-State makes to
support its proposed resource need. Nor is there a neutral setting, such as a Commission
hearing, for stakeholder input or feedback on the plan’s cost-effectiveness, whether the plan
gives fullest possible consideration to the cost-effective implementation of new clean energy
technologies, or whether the plan reduces carbon emissions. Finally, because the
Commission does not evaluate the Tri-State resource plan, Tri-State is not subject to the
requirements of minimizing NPVRR or using renewable energy to the maximum
practicable extent that other public utilities are subject to. In short, while Tri-State may
choose to comply with state public utility planning goals on a voluntary basis, because there
is no review or oversight there is no way to ensure that they are meeting those goals.
Requiring Tri-State to undergo a regular ERP filing could also advance the state
goal of addressing climate change by reducing greenhouse gas emissions from electricity

8

Decision No. C10-0101, ¶ 9.

6

 generation throughout Colorado. The Commission’s proposed changes to the ERP rules
include adding language to Rule 3604(k) requiring an “assessment of potential cost-effective
early retirements of utility-owned resources with retirement dates during the planning
period.” Tri-State currently meets roughly 49% of its customer’s needs with coal-fired
generation. Requiring Tri-State to submit an ERP for Commission review and approval
would provide an opportunity for Tri-State members and the Commission to evaluate
whether Tri-State’s coal units continue to be economic for its members or whether there are
lower-cost and cleaner alternatives to meet that energy need.
B.

Rule 3601: Overview and Purpose

In its proposed Rule 3601(c), CEO recommends adding language related to how
electric resource planning should be an integrated process that takes into account other
types of utility planning and activities that effect a utility’s load or need for new generation
such as demand-side management (“DSM”) planning, transmission planning, RES
planning, vehicle or beneficial electrification planning, and the use of non-wire alternatives
as part of distribution system planning. Integrating information from these other planning
processes, such as reduced load, shifting load to off peak periods or periods of maximum
renewable production, adding new load that allows better integration of renewables, or
increased generation, will ensure a more holistic perspective of the utility’s need, increase
the use of DERs, and expand customer choice.
CEO recommends adding the following language to Rule 3601(c): “It is the policy of
the State of Colorado to utilize renewable energy resources to the maximum practicable
extent to save consumers and businesses money, attract new businesses and jobs, promote
the development of rural economies, and minimize water use for electricity generation.”
CEO also recommends that the Commission adopt language stating that it is a goal of
electric resource planning to minimize carbon dioxide and other greenhouse gas emissions
7

 from electricity generation in order to protect and preserve the state’s natural resources
and environment.
C.

Rule 3602: Definitions

CEO proposes retaining the definition of “Section 123 resources.” CEO further
recommends modifying the definition to clarify the kind of resources that can be considered
Section 123 resources and adding the phrase “environmentally beneficial” to describe the
allowable energy technologies or demonstration projects. While CEO agrees with the
Commission’s statement that it no longer makes sense to presume that wind and solar are
more expensive than the other resources that compete in Phase II resource solicitations,
CEO suggests that removing the definition of a Section 123 resource is premature. Neither
CEO nor the Commission can foresee what clean technologies may yet emerge over the
coming years that could fit into the definition of a Section 123 resource and would benefit
from the different standard of review that applies to those resources in Phase II of an ERP.
CEO suggests that the definition of a Section 123 is an essential tool that the Commission
can use to consider not yet price competitive technologies that will help create new
renewable and clean energy technology markets and reduce carbon and other emissions
within the ERP process.
D.

Rule 3603: ERP Filing Requirements

In the NOPR, the Commission asks for input on proposed Rule 3603 and whether
the Commission should adopt different ERP requirements and procedures for Public
Service as compared to Black Hills due to its much smaller size.
CEO recommends the Commission apply the same ERP requirements and
procedures equally to all public utilities including Black Hills, Public Service, and TriState. If there are specific ERP requirements that a utility believes pose a particular
administrative burden, such as the filing of specific reports, the utility can request a waiver
8

 of that requirement. If the Commission finds that a utility is consistently unable to meet
certain requirements, then it might consider addressing by rule whether those specific
provisions should continue to apply.
E.

Rule 3604: Contents of the ERP

In proposed Rule 3604, CEO recommends several additions to a Phase I ERP filing
that add to the transparency of the resource planning process, including: projected
emissions of existing resources; fuel price forecasts; the methodology for evaluating of bid
contracts for renewable energy credits (“RECs”) without associated energy; the assessment
of the costs of existing and proposed resources, including fuel costs, operating costs,
regulatory carbon dioxide costs and externalities, or social costs of carbon dioxide
emissions; and a description of the modelling assumptions, inputs, and software the utility
proposes to use to evaluate bids and existing resources in Phase II. CEO also addresses the
Commission question about additional procedures and processes related to the ERP.
Consistent with our recommendation that the Commission retain the definition of a
Section 123 resource and adopt rules for distribution system planning, CEO recommends
that the Commission does not remove the requirement for a utility to file alternate plans
under Rule 3604. CEO supports the Commission’s inclusion in Rule 3604 of a requirement
for a utility to address the potential early retirement of utility-owned resources during the
planning period as one possible alternative.
The Commission also seeks input on the use of scenarios in resource planning, the
integration of resource planning with other planning processes, and whether the
Commission should open a proceeding prior to the ERP for the purpose of receiving certain
studies. CEO supports all three approaches and, as discussed below, recommends that they
could be combined to achieve a better integrated and more efficient ERP process.

9

 CEO suggests that Commission adopt a rule establishing a non-litigated, pre-ERP
filing process, and further recommends that this proceeding require a utility to participate
in stakeholder workshops related to the filings made in the proceeding. CEO believes that
this proceeding and stakeholder process could reduce some of the administrative burden in
the ERP proceeding and provide additional administrative efficiencies. Through this
proposed process, CEO and other stakeholders could engage with the utility outside of the
formal requirements of a litigated proceeding to review the utility’s proposed scenarios and
provide feedback or make recommendations for changes to those scenarios that a utility
could incorporate in its initial filing. The stakeholders could also informally review and
comment on the other reports and information that a utility is required to file in an ERP
proceeding. The stakeholder process could also be a venue for clarifying the specific
software model and inputs that the utility will be using in the ERP. Finally, a non-litigated
pre-ERP process could provide an opportunity for the Commissioners to engage with one
another at public meetings, and through this dialogue, to inform the utility and other
stakeholders about what they would like to see included or addressed in the ERP filing.
The Commission also asked whether it should endeavor to develop different sets of
assumptions about the future for exploring possible risks that may arise from those
assumptions in an ERP context, and whether such assumptions should be part of the Phase
I proceeding or precede the utility’s development of its initial ERP filing. In response to this
question, CEO suggests that instead of the Commission developing different sets of
assumptions about the future, it require the utilities to develop and present the scenarios it
believes to be the most relevant in the pre-ERP stakeholder proceeding. This would allow
interested stakeholders to engage with the utility on changes to the scenarios or to propose
alternative scenarios. The Commission could also engage with the utility to provide
feedback on whether it would like to see changes to the scenarios or see additional
10

 scenarios. The utility could include this feedback into the development of the scenarios that
it files with the ERP. In the alternative, the Commission could require that scenarios be
included as part of the utility’s Phase I filing so that the Commission and interveners could
review and provide feedback on these scenarios. The scenarios could also be a topic of
discussion in the stakeholder workshop CEO is recommending that would precede the filing
of the ERP.
Finally, CEO recommends that the Commission consider directing a utility use the
social cost of carbon (“SCC”), as defined by the Interagency Working Group, in the
development of its base case optimization. This would allow the Commission and other
interveners the opportunity to understand the impact of carbon emissions in the first model
run and to assess any alternatives developed against this base case.
F.

Rule 3605: Cooperative Electric Generation and Transmission
Association Reporting Requirements

CEO recommends eliminating this rule if the Commission adopts CEO’s
recommended modifications to proposed Rule 3600 related to the applicability of the ERP
rules to Tri-State. In this case, reporting requirements for Tri-State would be located in
other sections of the rules.
G.

Rule 3606: Electric Energy and Demand Forecasts

CEO recommends adding language to proposed Rule 3606(e) that requires utilities
to explain the relevant forecast inputs and assumptions derived from the utility’s demand
side management reports and plans and any future distribution system planning reports
and plans in the description and justification section related to energy and demand
forecasts. This change is in line with the goal of creating a more integrated resource
planning process, as discussed above.

11

 H.

Rule 3607: Assessment of Existing Resources

In the NOPR, the Commission requested legal arguments regarding whether it has
authority to assess existing resources in the Phase I of an ERP proceeding. Sierra Club
provides an extensive legal analysis in its initial comments and concludes that:
Commission evaluation of existing resources is necessary to accomplish the
legislative functions delegated to the Commission, namely, the Commission’s
mandate to ensure that all charges made, demanded, or received by any public
utility for any rate, fare, product, or commodity furnished or to be furnished or
any service rendered or to be rendered shall be just and reasonable.9
Sierra Club also concludes that “there is no Constitutional or statutory provision that bars
the Commission from assessing the economics of, and need for, a utility’s existing
resources.”10 Finally, Sierra Club notes that Commission evaluation of existing resources in
the context of a Phase I ERP would not require the Commission to second-guess its prior
prudency determinations.11 CEO agrees with Sierra Club’s legal analysis and we do not
believe that further legal argument is necessary.
CEO appreciates the Commission’s addition of a benchmarking provision within rule
3607 that requires a utility to compare the costs and performance of existing resources to
the costs and performance of the generic resources. While CEO generally supports this
concept, it also recommends some additional language that will go further to ensure that
utilities are acquiring and utilizing the most competitively priced resources possible and
passing those savings on to ratepayers. CEO’s proposed rule language also provides the
Commission with the information it needs to give the fullest possible consideration to the
cost-effective implementation of new clean energy.

Initial Comments of Sierra Club, filed on March 29, 2019, at 2 (internal citations omitted).
Id. at 4.
11 Id.
9

10

12

 In the utility’s assessment of existing resources, in proposed Rule 3607(a)(V), CEO
recommends the Commission require utilities to provide additional information on the
existing resources by facility, including estimated incremental decommissioning costs not
included in the depreciation expense, remaining depreciation expense and identification of
potential new capital or maintenance expenses for their estimated remaining useful lives,
and actual expenses of utility-owned generation facilities since the filing of the most recent
ERP.
In proposed Rule 3607, CEO recommends providing additional guidelines for
utilities related to the evaluation of the early retirement of existing resources, including
that utilities shall evaluate early retirement during the resource acquisition period for each
existing utility-owned generation facility that has a terminal date within 15 years of the
end of the resource acquisition period. In addition, for each of these, the utilities shall
provide the cost of early retirement, the estimated operational and capital savings from
early retirement, and accelerated depreciation costs, as well as describing the replacement
resource need, possible system reliability impacts and corrective actions for such impacts,
and how the retirement can be represented in modeling for fair comparison of costs and
benefits against alternative resources.
CEO also recommends requiring the utilities to assess existing “distributed energy
resources” in addition to “demand side resources,” which would include resources acquired
through net metering, CSGs, RES Compliance Plans, Demand Side Management Plans,
and any future Distribution System Plans. This will support the intent of creating a more
integrating ERP process.
I.

Rule 3608: Transmission Resources

CEO recommends adding language to proposed Rule 3608(d) that clarifies that in
the utility’s consideration of transmission costs and benefits in its comparison of possible
13

 resource alternatives, transmission benefits shall include the ability to connect greater
amounts of renewable energy. This provision would encourage utilities to consider the
longer-term benefits of future renewable development, which is important for continuing to
move toward the state’s renewable energy goals.
J.

Rule 3609: Planning Reserve Margins and Contingency Plans

CEO recommends adding a provision to proposed Rule 3609 that requires the utility
to utilize distributed energy resources, including demand side resources, as its priority and
first source of contingency resources. CEO also recommends the Commission direct a utility
to consider the geographic and resource diversity of its existing renewable resources as it
calculates the needs for a planning reserve margin. CEO proposes that the Commission
direct staff to lead a workshop among interested stakeholders on developing an appropriate
mechanism for calculating the planning reserve margin.
K.

Rule 3610: Assessment of Need for Resources

CEO proposes reorganizing and modifying proposed Rule 3610 in order to clarify
that, in addition to considering the energy and demand forecasts and planning reserve
margins, the utility should consider early retirement of existing resources, demand side
resources, DERs and energy from QFs, pursuant to Rule 3607. CEO also suggests the
Commission require the utility to present future costs of energy efficiency and demand
response resources and include these as alternatives to new and existing resources in its
portfolio modeling. This will ensure the utility is implementing cost-effective demand-side
resources to reduce the need for additional resources that would otherwise be met through
a competitive acquisition process.
L.

Rule 3617: Amendment of an Approved ERP

CEO recommends the Commissions add language to proposed Rule 3617 that
requires any application for approval of amendments to an approved ERP to include any
14

 proposed changes to solicitation documents, request for proposal documents or standard
contracts. This will ensure that the Commission and intervenors have the opportunity to
review and provide feedback on the new documents.
III.

Renewable Energy Standard Rules (3650-3668)
The renewable energy standard rules are integral to advancing clean and renewable

energy in Colorado, establishing a process to implement the Renewable Energy Standard
(“RES”) for utilities in Colorado, pursuant to §§ 40-2-124 and 40-2-127, C.R.S. CEO
references the overview and purpose of the Renewable Energy Standard Rules (current and
proposed Rule 3651), and maintains that this continues to be the appropriate framework for
the RES rules and any proposed revisions:
Therefore, in order to save consumers and businesses money, attract new
businesses and jobs, promote development of rural economies, minimize water
use for electricity generation, diversify Colorado's energy resources, reduce the
impact of volatile fuel prices, and improve the natural environment of the
state, it is in the best interests of the citizens of Colorado to develop
and utilize renewable energy resources to the maximum practicable
extent. (Emphasis added.)
As such, CEO recognizes two important components contained in RES Rules: compliance
with the RES and small eligible energy resource planning. In its comments, CEO provides
its perspective on both of these components but places a greater emphasis on the
acquisition of small eligible energy resources. As discussed in greater detail below, CEO is
still reviewing several of the Commission’s proposals, and intends to submit rule revisions
at a later date.
Several modifications contemplated in the proposed RES Rules represent significant
departures from current practices. For example, the proposal that net metering is a means
by which investor-owned utilities cause eligible energy to be generated and the implication
that the energy could therefore be counted for the demonstration of compliance with the
RES is new and could have unforeseen consequences. CEO recognizes that the conversation
15

 about RECs and RES compliance occurs at a time when a growing number of Public Service
customers are pursuing retail renewable distributed generation outside of utility incentive
programs. However, the shift to counting such energy for compliance or to using a net
metering credit to show a utility “caused” generation raises several issues. As discussed
below, CEO requests that the Commission engage with stakeholders after the initial
hearing so that we may better understand the Commission’s intent for this rule change.
In addition to CEO’s concern about the apparent shift away from RECs, we are
concerned about the impacts of the Commission’s proposal to reduce the standard rebate
offer to $0 from the $2.00 that is currently in rules. As CEO stated in our comments and
proposed rule modifications in the Stakeholder Outreach Proceeding, and again in these
comments, we maintain that certain incentives—including upfront or production-based
incentives—are still needed to support access to renewable energy for underserved
customer groups and low-income customers. CEO recommends that the Commission
require utilities to retain the Standard Rebate Offer at $2.00 in rules as a possible
incentive. CEO recognizes that, although RESA funding has successfully fostered certain
markets, a more directed approach to incentives still may be necessary to support hard-toreach market segments. Utilities and stakeholders have practices for identifying and
including this population segment in RES planning.
Consistent with CEO’s mission and with our comments in the Stakeholder Outreach
Proceeding, CEO again asks the Commission to add a definition for underserved customers
in the RES rules. CEO maintains that there are customers or customer groups—beyond
those currently recognized through traditional definition of low-income—who would benefit
from additional incentives in order to be able to participate in retain distributed generation
programs. These groups are considered underserved because they are part of a hard-toreach market segment. These customers face challenges that currently prevent them from
16

 participating in those programs, and CEO believes that incentives may help these groups
overcome these barriers. For example, customer groups including “renters” and
“agricultural customers” are specifically identified in § 40-2-127, C.R.S., as groups that
should be able to participate in CSGs, but CEO understands that those groups may be
participating at lower levels than other groups. Not all renters or agricultural customers
necessarily qualify for low-income programs. Nor is either group associated with a special
rate class or meter.
In addition, CEO suggests that a tailored approach to incentives may allow for
certain new uses of a utility’s RESA funds while still reserving a portion of those funds to
support the programs that traditionally have received them. CEO suggests that a key role
for the Commission under the new Electric Rules should be to decarbonize utility electric
systems while appropriately balancing acquisition of grid-scale resources with the
opportunity for customers to participate through distributed renewable resources. We
suggest that the Commission should be especially mindful of ensuring reasonable
opportunities for both low-income and underserved customers to participate.
A.

Rule 3654: Renewable Energy Standard

Throughout the NOPR, and in this section, the Commission appears to propose a
substantial change in how a utility demonstrates compliance with its obligation under the
RES. Under current practice, a utility typically demonstrates that it has caused retail
distributed generation to be generated through the provision of a payment to the customer
for the purchase of the REC, which represents the positive environmental benefits from the
use of the eligible energy resource. The language in the NOPR appears to suggest that a
utility can claim that a net metering credit is sufficient to show the utility “causes” eligible
energy to be generated, thus giving the utility the right to count the energy generated for

17

 compliance with its RES obligations, even if the utility is not purchasing the RECs from the
customer.
CEO believes this proposal could have unintended consequences, and suggests that
the Commission take additional time to inform stakeholders about the reasoning behind
this change so we can better understand and evaluate the consequences of using something
other than RECs for compliance with the RES. CEO is concerned that separating RECs
from RES compliance and using a net metering credit to show that a utility has caused
eligible energy to be generated could have significant implications for RES compliance, as
well as the broader distributed generation market. For example, if the RECs are no longer
needed for compliance, what impact will that have on the price of RECs?
CEO believes that the ability for customers to retain RECs—and therefore claim the
environmental benefits of using renewable distributed generation—is an important
component of using retail distributed generation for those customers and for retail
distributed generation policy in general. Customers that participate in a utility standard
offer program receive two different payments, a net metering credit and a production based
incentive payment that gives the utility a right to claim the REC, or the environmental
benefits, of the generation. The changes proposed in the NOPR could erode the ability of
customers that do not participate in a utility rebate offer program to retain the RECs, or
environmental benefits, of their retail distributed generation, by allowing a utility to claim
those benefits simply because the customer earns a net metering credit. In short, as CEO
understands the Commission’s proposal, the utility would no longer need to offer a payment
for the REC. Previous CEO comments and redlines in the Stakeholder Outreach Proceeding
have highlighted the distinction between RECs and incentives, including advocating for the
importance of untangling these two features. CEO encourages additional broad stakeholder
discussions after the initial hearings on this proposed change.
18

 It is also unclear from the Commission’s proposed change whether retail distributed
generation would still generate RECs. If so, it might lead to double counting of
environmental benefits. For example, if a customer-owned distributed generation system
does generate a REC, it appears that the customer would retain the REC and the utility
would count the kWh of electricity generated to show compliance with the RES. This,
however, appears to let both the customer and the utility claim environmental benefits
from the same distributed generation system. At minimum, CEO proposes that any
approach adopted by the Commission on the “cause” of renewable generation should contain
clear procedures that avoid any double-counting of RECs. In addition to gaining a greater
understanding of the implications of and reasoning behind this policy, CEO requests
additional time to evaluate how this policy would affect utility compliance with the RES.
CEO believes that such a significant departure from current practice merits more
time and discussion among stakeholders and the Commission to better understand the
motivation behind this proposed change as well as the implications and consequences of
this proposal.
B.

Rule 3656: RES Compliance Plan

CEO supports the Commission’s efforts to streamline RES compliance planning and
to better integrate RES planning with the ERP process. CEO asks the Commission to
consider whether the timing of the RES and ERP filings proposed in the NOPR represents
the most efficient or advantageous approach to integrating the various planning processes
that come before the Commission. CEO notes that there are additional planning processes
that may inform either the ERP or the RES that are not included in the current approach to
integration. For example, it appears that the Commission does not attempt to integrate
transmission planning in the resource planning process, which may be necessary to
facilitate the acquisition of utility scale eligible energy resources from Colorado’s energy
19

 resource zones. Further, the Commission does not include distribution system planning
within the scope of this NOPR or within its current efforts to integrate resource planning
processes. CEO recommends that the Commission require each investor-owned utility to
file a Distribution System Plan, and we suggest that those plans be included in the
Commission’s efforts to integrate resource planning processes.
While CEO supports aspects of the NOPR, we note that several significant changes
in the RES rules are proposed without specific comments or discussion as to why the
changes are being made. For example, a new framework is introduced in the RES rules
regarding “cost-effective retail renewable distributed generation.” Proposed Rule 3656
begins with “It is the Commission’s policy that utilities should meet the RES in the most
cost-effective manner. . . .” CEO asserts that the Commission has historically interpreted
this to apply to a RES Plan on a portfolio-level through retail rate impact rules. CEO is
uncertain if the phrase “cost-effective retail renewable distributed generation” added in
several places throughout the proposed RES rules creates a new paradigm where individual
programs will be evaluated for cost-effectiveness. Should this be the Commission’s intent,
CEO requests additional time and information from the Commission before opining on the
proposal. For example, the NOPR does not indicate: how the Commission proposes to
determine cost-effectiveness; whether there will be cost-benefit test that would be applied;
or at what level (e.g., program or portfolio) such a test would apply. CEO requests that the
Commission, before adopting such an approach, provide clear answers to the above
questions.
CEO is also concerned about how a cost-effectiveness or cost-benefit test would be
applied to renewable energy programs directed toward low-income customers. Currently,
utility demand side management programs must have a Modified Total Resource Cost Test

20

 (mTRC) score above 1.0 to be found cost-effective. However, programs directed toward lowincome customers are not required to achieve an mTRC of 1.0 or above.
CEO also requests clarification from the Commission on what types of renewable
generation programs are subject to the RES planning process. The NOPR appears to
suggest that the RES planning process will focus on the acquisition of distributed retail
generation and certain other small (i.e., below 20 MW) resources. CEO asks the
Commission to clarify whether it intends that WindSource, RenewableConnect, or CSGs
will be acquired through a RES planning process or if the Commission intends for a utility
to include these in its ERP filings. CEO also seeks clarification about whether QFs under
20 MW in size for which the utility has established tariffs under proposed Rules 3903 and
3904 would participate in the ERP process or whether the Commission intends to
implement a process in the RES plan for QFs under 20 MW in size to seek a legally
enforceable obligation from the utility.
Energy storage is declining in price and becoming an option for utility acquisition as
well as for customers that participate in retail distributed generation programs. Therefore,
CEO recommends that the RES Compliance Plan rules require a utility to include energy
storage as part of its acquisitions in its RES Compliance Plan.
CEO also recommends that the Commission require that any incentives or programs
that serve low-income or underserved customer groups addressed in the RES rules have
corresponding language requiring that a utility include those programs or incentives in its
RES Compliance Plan. For example, as discussed later, CEO supports the Commission’s
efforts to expand CSG capacity for customer groups identified in statute, including
populations of “renters, low-income utility customers, and agricultural producers” and
recommends requiring that a utility be required to include in its RES Compliance Plan a
program or other method of acquisition to ensure that this goal is achieved. CEO also
21

 supports the Commission’s proposal to allow customers to contribute excess bill credits to a
third party and recommends additional rule language requiring a utility to include details
on any program related to the contribution of excess billing credits from CSGs to third
parties in their RES Compliance Plans.
The Commission has proposed striking several requirements that a utility currently
must include in its RES Compliance Plan filing. CEO’s comments here directly address two
of those proposed changes.
First, the NOPR proposes eliminating the requirement that a utility include an
estimate of the RESA funds available during the period covered by the RES Compliance
Plan. CEO suggests that RESA funds are still needed for smaller eligible and renewable
energy systems and to support low-income programs. Therefore, it is essential that the
Commission and other interveners be presented a clear picture of the RESA funds that are
available to support such programs.
Second, consistent with other language in the rules that appears to move away from
RECs as a mechanism to demonstrate compliance with the RES, the NOPR proposes to
eliminate current Rule 3657(b)(XV) and remove the requirement that a utility explain how
RECs are tracked and how RES compliance is calculated. CEO reiterates its earlier concern
that moving from RECs as the RES compliance mechanism represents a significant
departure from current practice that is not well justified and that the approach raises the
risk of a double counting of the environmental benefits of renewable or eligible energy
resources. Therefore, we recommend that the Commission not strike this requirement.
The Commission proposed several questions in its NOPR related to proposed Rule
3656 to which CEO responds below.
What is the appropriate and discrete role for the Commission in setting
acquisition targets or capacity size limits to support the growth of retail
renewable distributed generation and the growth of CSGs?
22

 CEO considers the question of the appropriate role of the Commission in
determining a minimum and maximum market size to be an essential one. CEO’s response
about the Commission’s role in ensuring market access underpins many of our comments.
While the development of retail renewable distributed generation and CSGs will change
annually and across regulated utilities, CEO considers the Commission’s appropriate and
discrete role to ensure that all customers have reasonable access to retail renewable
distributed generation or CSGs and that those programs comply with the statutory retail
rate impact cap.
The implementation of minimum acquisition targets supports this goal of providing
access by ensuring that the market is not unduly constrained. CEO recommends that as the
Commission considers its role in placing an upper limit on CSG or retail distributed
generation programs that it consider the impacts that a cap or maximum size will have on
thriving markets, which CEO believes should be permitted to progress without undue
regulation by the Commission. To that end, CEO suggests that in adopting any maximum
program size that the Commission do so based on statutory criteria of ensuring that a RES
Compliance Plan complies with the retail rate impact cap for RES compliance or to address
reasonable concerns about system reliability. Finally, CEO suggests that the Commission
still has a role in ensuring equitable market access for low-income residential customers
and other underserved customer groups and that the Commission can set expectations,
specific targets, or incentives for retail distributed generation, CSG, or other utility
programs that are part of a utility’s four-year RES planning cycle.
Consistent with the Commission’s question about its role in CSG markets, CEO also
recommends that just as the Commission contemplates a stakeholder framework for
assessing ERP modeling software and assumptions to be revisited in four-year ERP
planning cycles, the Commission develop a framework for reviewing market access and
23

 participation in retail renewable distributed generation and CSG programs. Based on the
outcome of this process, the Commission may then set expectations or specific targets for
utility programs, which the utility will then respond to by developing programs supported
by the stakeholder process. This same framework would be utilized in the next four-year
RES cycle to determine if market access remains a concern for certain demographics or if
new, underserved, identifiable markets have emerged.
What improvements should the Commission make to its Electric Rules and its
regulatory processes with respect to market size, the pace of market growth, and
interrelationships between the retail renewable distributed generation and CSG
markets?
As noted above, CEO supports the Commission’s effort to integrate ERP and RES
planning. We recommend the Commission also add Distribution System Planning to this
integration. We also believe that a non-litigated, pre-ERP process could facilitate better
understanding of what will or should be included in an ERP and may reduce some of the
time for the Phase I modeling process.
CEO understands that one of the purposes of the Electric Rules is to establish
uniform requirements for applicable utilities. However, rather than establishing rigid
requirements for utilities to address markets in these rules, CEO proposes the Commission
require utilities to evaluate these markets, their health, and their needs as it relates
specifically to each utility in each four year resource planning cycle.
Should it be necessary for the utility to specify in each RES Compliance Plan
its plan to acquire specifically: retail renewable distributed generation from
residential retail customers; retail renewable distributed generation from
nonresidential retail customers; wholesale renewable distributed generation;
and eligible energy resources to be acquired pursuant to the ERP Rules?
CEO supports this, as it increases transparency and market certainty.
C.

Rule 3657: Standard Rebate Offer, REC Purchases, and Contracts

24

 In proposed Rule 3657, the Commission reduces the Standard Rebate Offer (“SRO”)
from $2.00 per Watt to $0.00 per Watt. The Commission also asks the following question:
Given that § 40-2-124(1)(e)(I.5), C.R.S., states that the Commission may set the
SRO at a lower amount than $2.00 per watt “if the Commission determines,
based upon a qualifying utility’s renewable resource plan or application, that
market changes support the change,” should the Commission adopt this
proposed rule given the applications and RES Compliance Plans filed by Public
Service in Proceeding Nos. 11A-135E, 11A-418E, 13A-0836E, 14A-0414E, and
16A-0139E and by Black Hills in Proceeding Nos. 12A-1207E, 13A-0445E, 14A0535E, and 16A-0436E?
CEO recognizes that the current SRO for both utilities is $0.00 per Watt, as
established and maintained in the proceedings referenced above, and that the Commission’s
proposed change is an effort to align the language in the Commission’s Rules with what is
happening in practice. CEO notes that the Commission’s proposed rule would both lower
the SRO to $0.00 per Watt permanently and remove any flexibility for the Commission to
adjust the SRO later. Under current Rule 3658, with the SRO set at $2.00 per Watt, the
Commission has the flexibility to reduce the SRO to $0.00 based on finding that then
current market conditions warrant a lower amount. CEO agrees with the Commission that
some customers appear to be unaffected by an SRO of $0.00. However, CEO asserts that the
current SRO of $2.00 per Watt served as the basis for the incentives in CEO’s Low-Income
Solar Rooftop program. This is just one example of where having a non-zero SRO afforded
the utility, stakeholders, and the Commission flexibility to offer an incentive to certain
customer groups, including low-income customers, that need an incentive in order to
participate in a utility retail distributed generation program.
CEO recognizes that there may be other avenues to offer incentives to support
access to renewable energy for low-income and hard-to-reach or underserved customers.
CEO supports the flexibility included in the current rule language recommends the

25

 Commission retain the current rule language setting the SRO to $2.00 in proposed Rule
3657(a).
D.

Rule 3658: Renewable Energy Credits

CEO supports the Commission’s efforts to allow a utility to acquire RECs through
purchase. As discussed above, CEO asserts that a REC represents the environmental
attributes (non-energy benefits) of renewable generation and that without a corresponding
retirement of RECs the generation from renewable energy has no claim to these
environmental benefits.
If the Commission adopts proposed Rule 3658, then CEO recommends the
Commission add to the end a statement that a utility cannot claim the non-energy
attributes—including any and all credits, benefits, emissions reductions, offsets or
allowances—of renewable energy if the RECs associated with that generation have been
retained by the customer or are not otherwise possessed by the utility. This prohibition
against claiming environmental benefits should apply to any utility marketing materials as
well.
E.

Rule 3659 and 3661: Cost Recovery and Retail Rate Impact

The Commission proposes several changes to the use of the RESA account and to
utility reporting requirements for the RESA account that CEO believes merit further
discussion. First, the Commission proposes removing RESA account reporting from utility
RES Compliance Plans. Second, the Commission proposes to no longer consider the RESA
surcharge as the principal measure of the retail rate impact, and consistent with that,
proposes striking Rule 3660(c).
Proposed Rule 3661 provides the greatest detail on the Commission’s proposal to
sever the RESA surcharge from the measurement of the retail rate impact. However,
despite the language of proposed Rule 3661(e), CEO is unclear exactly how the Commission
26

 expects a utility to calculate the incremental cost of renewable energy or to demonstrate
compliance with the retail rate impact as required by § 40-2-124(1)(g)(I), C.R.S. As
discussed in CEO’s comments in the Stakeholder Outreach Proceeding, CEO believes that
the RESA is still necessary and important for compliance with the retail rate impact as well
as the rest of the RES statute.
CEO requests that the Commission explain to stakeholders why the Commission is
seeking these changes to the RESA and what outcome the Commission expects in moving to
a new method for calculating the incremental cost. After CEO better understands the
Commission’s intent in these rule changes, we hope to offer additional comments.
The Commission asks the following question related to how the retail rate impact is
currently calculated:
Is it necessary to retain the two-scenario process for calculating the retail rate
impact using the same methods the utility uses for its ERP? Are other, less
complicated methods now suitable?
CEO may be open to considering an alternative to the RES/No RES calculation that
has been the basis for determining the retail rate impact in a utility ERP. However, while
the Commission seeks input on this issue, it has not identified any concerns or deficiencies
with the current approach. Therefore, CEO has not developed an alternative proposal or
recommendation. CEO recommends that the Commission host stakeholder discussions or at
least allow time for stakeholder discussions outside the Commission on this topic before the
Commission makes a final decision on this question. As the Commission considers
responses to this question, CEO opines that the RES/No RES calculation has been a
transparent approach for determining the incremental cost of renewable and eligible energy
resources and whether a utility’s acquisition of those resources satisfies the 2% retail rate
impact cap.
F.

Rule 3662: RES Compliance Reporting
27

 In alignment with CEO’s recommendations for proposed Rule 3656, CEO proposes
that any incentives or programs for low-income customers or underserved customer groups
that are adopted in the RES rules have corresponding reporting requirements added to the
section. CEO also proposes that utilities include language in their RES Compliance Plans
about how they will develop or maintain programs that encourage CSG subscriptions from
customer groups identified in statute, including populations of “renters, low-income utility
customers, and agricultural producers.” Alternatively, utilities may provide a narrative
describing why there is insufficient demand for retail distributed generation from these
customer groups.
CEO does not support removing RESA reporting from RES Compliance Plans. CEO
believes that providing an account of the current and projected RESA funds and the
calculation of the 2% retail rate impact via the RESA has been an important tool for the
Commission in considering the appropriate size of certain renewable generation programs
and incentive levels, and it has ensured that a utility RES Compliance Plan satisfies the 2%
retail rate impact cap.
CEO also recommends that the Commission add a provision to proposed Rule 3662
requiring utilities to report on the outcomes of any program related to the contribution of
excess billing credits from CSGs to third parties in their RES Compliance Reports, as is
further discussed in the CSG Rules section of these comments.
IV.

Net Metering Rules (3675-3699)
The Commission’s Net Metering Rules (current Rule 3664 and proposed Rules 3675-

3699) implement the provision in § 40-2-124(1)(e)(I)(B), C.R.S., that requires investor
owned utilities to allow customers’ retail electricity consumption to be offset by retail
renewable distributed generation. CEO supports the Commission’s decision to move the Net
Metering Rules to a separate section from the Renewable Energy Standard Rules.
28

 A.

Rule 3678: Eligible Retail Renewable Distributed Generation

CEO suggests that the Commission modify proposed Rule 3678(a) to clarify how
utilities should calculate the appropriate system size for retail renewable distributed
generation systems. Both the Commission’s existing and proposed rule explains that a
system shall be sized to supply no more than 120 percent of the customer’s average annual
electricity consumption, in compliance with § 40-2-124(1)(c)(II)(B), C.R.S. However, it is not
clear based on this language how size should be calculated—whether it should be based
simply on nameplate capacity—or the actual expected electrical output, which could be
affected by shading, roof orientation and other site conditions. CEO’s proposed
modifications to proposed Rule 3678(a) make explicit that actual expected electrical output
is the pertinent data point and that additional factors affecting output should be taken into
account when making this projection. This will ensure that systems are sized optimally in
accordance with both the 120 percent requirement and specific site conditions, and that
customers are not needlessly installing undersized systems in certain conditions due to this
rule being misinterpreted as a calculation based on nameplate capacity. Software capable of
these calculations, such as the National Renewable Energy Laboratory’s “PVWatts,” is
readily available to provide these site-specific calculations and is referenced elsewhere in
PUC Rules.
CEO also suggests the Commission reconsider its approach to the calculation of the
120 percent limit under Rule 3678(a) and the annual utility bill data required. CEO
believes that the intent of the 120 percent provision was to allow customers to meet their
own energy needs but to prevent a customer from becoming an energy exporter. CEO
supports the broader implementation of electric vehicles and other approaches to beneficial
electrification that will help reduce greenhouse gas emissions. We suggest that the current
approach of calculating the 120 percent limit of a retail distributed generation facility by
29

 using historical consumption data may disadvantage customers who undertake beneficial
electrification to near in time to when they install an on-site solar generating resource and
may prevent those customers from meeting their own energy needs.
For example, if a customer chose to increase their electric load significantly less than
a year before installing an on-site solar generating resource, the calculation of the
preceding year’s average annual consumption would not fully reflect a new addition of load.
To illustrate this example further, a customer who acquires an electric vehicle and
necessary charging equipment only six months before installing an on-site solar generating
resource might not be able to offset all or most of their electricity usage with an
appropriately sized system, because the new permanent load from the electric vehicle
charging would only be present on six of the twelve months of annual utility data.
Consequently, if a customer is aware of this process and desires an appropriately sized
system, they might need to wait a year with the new load—while paying for the increased
load for a year—in order to “count” the new load for purposes of the 120 percent statutory
limit.
B.

Rule 3679: Net Metering Credits

Current and proposed Rule 3679(a) states, “excess kWh shall be carried forward
from month to month and credited at a ratio of 1:1 against the customer’s retail kWh
consumption in subsequent months.” CEO suggests that, as the investor-owned utilities
move toward time-of-use rates, and as customers install more energy storage systems, the
approach of using a 1:1 kWh credit may make it difficult for customers to capture the full
value of the production from their on-site solar generating resources. The problem arises
because under a time-of-use framework energy produced and consumed at different times
has different values with peak energy production being worth more than off-peak energy
production.
30

 CEO supports what it believes to be the Commission’s response to this issue in
proposed Rule 3679(d). The Commission proposes monetizing net metering credit by
requiring a utility to multiply the amount of energy generated by the rate for the time
period in which that energy is generated. This monetary credit is then carried forward each
month on the customer’s bill and can be applied to consumption in any time period or as a
credit against the customers aggregated consumption. CEO believes that monetizing the
net metering credit permits a retail renewable distribution generation customer greater
ability to offset their generation while maintaining the intent of time-of-use rates to reflect
the changing value of energy and reduced peak demand.
CEO recommends that the Commission consider revising proposed Rule 3679(a) to
clarify that the 1:1 credit either is or can be monetized and carried forward. CEO prefers
the former approach and recommends the following revision:
If a customer with retail renewable distributed generation generates
renewable energy pursuant to rule 3678 in excess of the customer’s
consumption, the excess kWh shall be credited at a ratio of 1:1 by monetizing
the kWh as a dollar value credit based on the utility prevailing rate when the
kWh was generated, carried forward from month to month, and credited
against the customer’s retail kWh consumption on a dollar value basis in
subsequent months.
Under this approach, a customer could apply a credit generated during peak hours
to another portion of her bill. However, a credit generated at an off-peak time could only be
applied to the portion of the bill attributable to off-peak consumption. CEO believes that
the approach of monetizing a credit is simpler for a customer to understand and track, and
fairly and accurately captures the value of a net metering credit under a TOU rate.
C.

Rule 3680: Metering Requirements

Proposed Rule 3680 revises requirements related to production meters and the
Commission has solicited input from parties on additional changes contemplated regarding
the use or requirement of production meters. CEO supports the reasonable use of estimates
31

 of electricity production in lieu of a production meter. A production meter is necessary for
measuring the RECs that the utility acquires from retail renewable distributed generation
for compliance with the RES. However, measuring RECs is not necessary in cases where a
utility is not acquiring RECs, and “net metering only” customers who are not participating
in a utility incentive program and who retain their RECs should not be required to install a
production meter.
If a customer is participating in a utility incentive program, CEO proposes that a
proxy value or estimate be utilized for small retail renewable distributed generation
systems in place of requiring those systems to have a production meter. This may be a
tiered approach similar to the proxy volume included in proposed Rule 3681(d)(II) or it may
be a system-specific estimate pursuant to proposed Rule 3678(a). CEO also proposes that
the Commission consider requiring voluntary written consent from a larger retail
renewable distributed generation customer if a utility deems a production meter to be
necessary. The production meter cost is not a cost caused by the individual customer, but
rather a cost that results from the need of the utility to track and record RECs for RES
compliance.
The Commission asks:
If net metering is deemed to “cause” eligible energy to be generated, could
estimates of the electricity produced by certain systems suffice for RES
compliance purposes such that no production meter is necessary? For example,
would estimates be sufficient for retail renewable distributed generation not
over ten 10 kW? If estimates are suitable, should the Commission adopt the
same or similar provisions for estimating the production of retail renewable
distributed generation as in Existing Rule 3658(f)(X) which was applied for the
upfront standard offers to purchase RECs?
As stated above, CEO supports the estimation of production in lieu of a production
meter, especially for small systems. Non-hardware, “soft” costs represent a significant

32

 percentage of total retail renewable distributed generation system costs. CEO supports
efforts to reduce these soft costs for retail renewable distributed generation customers.
D.

Rule 3681: Rates for Net Metering

The Commission requested comments from stakeholders on a series of questions
relating to proposed Rule 3681 and whether Commission rules should allow or establish a
separate rate class for net metering customers. CEO understands that the Commission has
the authority to establish different rates classes when it finds that there is sufficient
commonality among a group of customers and that that group is sufficiently distinct from
other groups of customers. While the Commission can implement different rate classes, it
must find that new rates are just, reasonable, and non-discriminatory. CEO notes that the
Commission has not looked in depth at the issue the cost and benefits of net metering,
which CEO believes would be necessary for the Commission to assess whether a separate
net metering rate could be just and reasonable. CEO suggests that before the Commission
adopts a separate net metering rate that it conduct a study, such as a value of solar study,
which would provide a foundation to evaluate the cost and benefits of net metering and may
address whether those warrant a separate rate class.
V.

Community Solar Gardens Rules (3875-3883)
The CSG Rules implement § 40-2-127, C.R.S., setting forth requirements for CSGs

located in investor owned utility service territories. The intent of the Colorado General
Assembly in passing the Community Solar Garden Act was to promote broader
participation in renewable energy by encouraging the development and deployment of
CSGs.12 The statute also directs the Commission to formulate and implement policies that
simultaneously encourage: (1) the ownership by customers of subscriptions in CSGs and

12

§ 40-2-127(1)(b), C.R.S.

33

 other forms of distributed generation, (2) ownership in CSGs by residential retail customers
and agricultural producers, including low-income customers, (3) the development of CSGs
with attributes that the commission finds result in lower overall total costs for the utility's
customers, (4) successful financing and operation of CSGs owned by subscriber
organizations, and (5) the achievement of the goals and objectives of the RES.13
A.

Rule 3881: Billing Credits and Unsubscribed Renewable Energy

In its final set of comments filed in the Stakeholder Engagement Proceeding on
September 7, 2018, CEO supported the proposal by Energy Outreach Colorado (EOC) to
allow utilities to contribute unsubscribed renewable energy and RECs to a third party
administrator qualified and approved by the utility for the purpose of providing low-income
energy assistance and bills reductions within the utility’s service territory. CEO also
suggested that the Commission add additional provisions in the rule to ensure a fair and
transparent system, including (1) defining the term “qualified and approved third party
administrators,” and (2) specifying the criteria third parties must satisfy to become
qualified and approved. CEO proposed new rule language that included provisions
requiring a utility to present the details of its plan to allow contributions of billing credits
and/or unsubscribed renewable energy and RECs to a third party administrator in its RES
Compliance Plan. CEO envisioned this type of program being open to a number of entities,
as long as the utility specified the criteria it was using to qualify the entities, along with
other details, in its description of the proposed program in the RES Compliance Plan.
Proposed Rule 3881(a)-(c) include a version of EOC’s proposal, which allows a CSG
subscriber to contribute excess billing credits to the “nonprofit corporation established for
low-income energy assistance pursuant to § 40-8.5-104, C.R.S.” EOC is currently the only

13

§ 40-2-127(5)(a)(IV), C.R.S.

34

 entity that has been so designated under the statute. Unlike CEO’s recommendation in the
Stakeholder Outreach Proceeding, the proposed provisions allow only EOC to participate in
such a program, excluding any other entities that may be equally suited to participate. CEO
continues to recommend that such a program be open to multiple third party providers.
CEO also recommends the Commission clarify the rate that will be applied to the
calculation of the donated credit.
CEO further recommends changes to proposed Rule 3881(d) that require utilities to
propose any new program for donating bill credits in their RES Compliance Plans and
report on the outcome of this program in their RES Compliance Reports. The details in a
RES Compliance Plan should include (1) the utility’s proposed process for qualification and
approval of third parties, to ensure third parties are treated in an equitable manner; (2) the
criteria a third party must meet to become qualified and approved, to ensure the
transparency of the evaluation system and allow third parties to be fully informed; (3) the
method by which a utility will determine an equitable allocation of billing credits to
multiple third party administrators; (4) the way in which the program will be marketed to
customers as a renewable program, to ensure that low-income customers know that they
are receiving benefits derived from renewable energy that are distinct from traditional bill
assistance; and (5) a reporting methodology to be included in each Annual RES Compliance
Report. The details in a RES Compliance Report should include the total number of CSG
excess billing credits that could have been, and that actually were, contributed to a
qualified third party administrator for low-income energy assistance.
Because a bill credit donation program is new and there are still many details to be
determined, presenting this information in RES Compliance Plans and RES Compliance
Reports filed at the Commission is important for allowing the Commission and stakeholders
an opportunity to provide feedback on the program. CEO appreciates Commissioner
35

 Koncilja’s attention to this issue and believes our recommended approach will alleviate any
concern over which entities may participate in such a program, as well as ensuring there is
an avenue through which the program can be examined further by the Commission and
stakeholders.
B.

Rule 3882: Purchases from CSGs

In proposed Rule 3882(a), the Commission has proposed striking the language
explaining that an investor owned utility’s plan for the acquisition of renewable energy and
RECs from CSGs shall be part of the RES Compliance Plan. CEO requests that the
Commission provide additional information about the intent and purpose of this change.
CEO cannot tell from the proposed rule language whether the Commission suggests that
utilities file a separate plan for the acquisitions of CSGs or whether the proposed rule
simply leaves open the question of the most appropriate avenue for acquiring CSG power.
The Commission posed a related question about whether it should continue to establish the
acquisition targets for CSGs as part of the utility’s RES Compliance Plan proceeding or in
other proceedings. CEO believes the RES Compliance Plan is still the most appropriate
proceeding for the Commission to establish CSG acquisition targets related to RES
compliance.
The Commission’s proposed Rule 3882(a) also requires that a utility dedicate 50
percent of CSG purchases to residential, agricultural, and small commercial customers, and
allows the utility to propose a standard offer price for the purchase of RECs from such
customers. While CEO appreciates the Commission’s acknowledgment that these customer
classes require special provisions to ensure that CSGs are meeting the statutory mandate
to expand access to solar, we suggest the Commission consider a slightly different approach
that may better ensure the financeability of CSGs that serve these kinds of customers so
that the CSG market in Colorado continues to thrive. CEO supports the recommendation of
36

 the Colorado Solar and Storage Association (COSSA) and the Solar Energy Industries
Association (SEIA) in their initial comments in this proceeding, which proposes requiring
utilities to put forward a standard offer credit adder which will help offset the additional
cost of serving these customers classes, in addition to a standard offer REC price for lowincome customers in particular. This approach will help address the economic barriers to
serving these customers, which is essential for the financing and development of CSGs with
a high percentage of residential, agricultural and small commercial subscribers. Grid
Alternatives also supported this type of approach in its initial comments in this proceeding,
noting that “standard offer incentives or adders are common and nationally proven
mechanisms for spurring low-income customer adoption and participation by other
underserved market segments…”14 CEO believes this approach, instead of or in addition to
a 50 percent carve-out, will result in a more robust and sustainable market for CSGs in
Colorado. The health of this market will have clear economic development benefits for the
state, while also benefiting consumers by allowing them to save money on their energy bills,
reduce their carbon footprint, and invest in locally produced clean energy in their
community.
In the Stakeholder Outreach Proceeding, CEO, along with other parties,
recommended adding a provision to rules permitting acquisitions of CSGs outside of a
utility’s RES Compliance Plan and that subscribers to these CSGs would not be required to
sell or transfer their RECs to the utility. CEO continues to recommend this provision be
adopted, as it would serve the goals of providing more equitable access to CSGs for
underserved customer types and classes, and ensuring that CSGs are available to
customers that wish to subscribe. The current CSG market in Colorado is artificially

14

Initial Comments of GRID Alternatives, Inc., filed in Proceeding 19R-0096E, at 26.

37

 constrained by the maximum CSG capacity approved by the Commission through utilities’
RES Compliance Plans. CSG developers are bound by this maximum capacity and cannot
sell CSG power to as many customers as are demanding it. This provision will allow the
market to function in an unconstrained manner and meet the customer demand for CSG
power, thereby encouraging broader participation in CSGs. This will ensure that customers
that are interested in subscribing to a CSG—including those that have been historically
underserved—are able to do so, even when utilities’ RES requirements have already been
met. This is similar in concept to the way in which net metering customers have the ability
to interconnect distributed generation outside of a utility’s RES Compliance Plan and
incentive program.
VI.

Qualifying Facilities Rules (3900-3953)
CEO supports the Commission’s proposal to use the competitive bidding process of a

quadrennial ERP to comply with PURPA. CEO agrees with the Commission that QFs 20
MW or greater should compete with all other resources in the utility’s all source
solicitation. However, because the FERC has established a rebuttable presumption that
QFs that are 20 MW or smaller are not competitive with larger facilities, CEO further
recommends that the Commission establish a separate bid analysis and selection process
for QFs between 5 and 20 MW.
The Commission states that it seeks comments on two options for tariff-based
determination of avoided costs for projects greater than 100 kW and less than the minimum
project size eligible to bid into the ERP. Option A entails the use of computer-based
modeling to establish avoided costs, which could be applied as the differential revenue
requirement approach. Option B entails a “market-based mechanism” preferably tied to a
Phase II ERP solicitation.

38

 While not offering a legal analysis, CEO notes that requiring QFs 20 MW and
smaller to compete with larger resources as part of a utility’s all source solicitation may not
comply with PURPA. FERC rule 18 C.F.R. 292.309(a) makes an exception from PURPA’s
“must buy” provision in circumstances where the QF has access to wholesale markets or a
regional transmission organization. However, 18 C.F.R. 292.309(d)(1) provides a rebuttable
presumption that 20 MW and smaller QFs are discriminated in the market. The inability
for QFs 20 MW and smaller to compete with other larger resources is evidenced by the fact
that no QF of that size has ever won a bid in Public Service’s or Black Hills’s ERP Phase II
bidding process. Therefore, CEO recommends that the Commission does not implement a
rule that requires the Commission to determine whether competitive bidding as part of the
utility’s all-source solicitation is reasonably accessible for QFs 20 MW and smaller. Instead,
the Commission should allow these smaller QFs to bid into the all-source solicitation, but
the Commission and the utility should conduct a separate bid analysis leading to separate
resource acquisition process for these smaller QFs. A separate bid selection process through
competitive bidding for resources 20 MW and under complies with PURPA because it does
not force these smaller QFs to compete with larger resources. This process is also consistent
with the Commission’s historic approach of using competitive bidding to acquire new
resources in an ERP and to set a price for avoided cost.
CEO does not have specific rule language to propose at this point, but proposes that
competitive bidding would be open all resources 5 MW an up. A utility’s Phase II 120-day
report would identify the average price of all bids from QFs that are 5-20 MW in size. That
average price would then become a clearing price. The utility would then award a contract
to all bids for QFs between 5-20 MW in size that provided a bid price lower than the
average bid price. The capacity available from those QF contracts would reduce the overall

39

 new capacity that the utility could acquire from resources larger than 20 MW acquired
through the competitive bidding process.
CEO suggests that the Commission extend its new tariff-based approach to setting
the avoided cost for QFs between 100 kW and 5 MW.
VII.

Generation Interconnection Procedures (3668-3675)
CEO supports the Commission’s efforts to modernize and update the interconnection

rules. However, CEO is concerned that, as stated in the NOPR, the Commission relied on
utility comments from the Stakeholder Outreach Proceeding as the foundation for the
proposed rules.
In the Stakeholder Outreach Proceeding, CEO submitted proposed revisions to the
Commission’s interconnection rules that were intended to improve the clarity and
organization of the rules, and to modernize, standardize, and streamline the
interconnection process. CEO’s proposed changes would allow utilities to process
interconnection requests efficiency while ensuring the rules are inclusive of new
technologies.
CEO also supported the joint petition of Energy Freedom Coalition of America, the
Colorado Solar Energy Industries Association, Sunrun, Inc., and Vote Solar to open a
rulemaking to modify the interconnection rules and address the Small Generation
Interconnection Procedures (SGIP), for the primary purpose of adding energy storage
guidelines to the scope of current Rule 3667.15 In CEO’s notice of intervention in that
proceeding, CEO suggested that the Commission broaden the scope of the proposed
rulemaking to update the SGIP in a more holistic way to align our state interconnection
policies more closely with federal Standard Interconnection Agreements and Procedures for

15

Proceeding No. 17M-0131E, Petition to Open a Rulemaking Proceeding, at ¶¶ 3-4.

40

 Small Generators.16 CEO continues to maintain that the updated Commission rules should
align with FERC Order 792.
CEO also continues to support its prior position in the Stakeholder Outreach
Proceeding that the Commission should modify the rules addressing storage systems. As we
stated in comments, integrating energy storage technologies across the electric grid can
result in many benefits for utilities, their customers, and society as a whole. These benefits
include more efficient utilization of grid resources, the deferral or avoidance of costly
upgrades, increased grid reliability, the provision of capacity reserves and voltage support,
reduction of peak demand, avoidance or mitigation of system disruptions, support of higher
penetrations of renewable energy on the grid, and increased consumer control over energy
use and costs.
A.

Rule 3853: General Interconnection Procedures

In the NOPR, the Commission notes CEO’s 2018 request for a partial variance in
Proceeding No. 18V-0594E from current Rules 3667(e)(XI) and 3667(j)(VII) for a Level 1
system. The Commission requests comments on whether the insurance amounts set forth in
this rule continue to be appropriate. CEO asserts that the current insurance requirement
for Level 1 systems is not appropriate. We propose that the Commission eliminate the
current requirement in proposed Rule 3854(c)(VII) for $300,000 in liability insurance
coverage for Level 1 systems (currently designated as 10 kW or less). Should the
Commission find that a requirement for liability insurance for Level 1 systems is still
necessary, CEO proposes that the Commission require a reduced amount—such as
$100,000.

16

Proceeding No. 17M-0694, Notice of Intervention of the Colorado Energy Office.

41

 While any requirement for liability insurance for Level 1 systems should properly
account for customer, developer, and utility needs and circumstances, a review of state
liability insurance policies for Level 1 systems indicates Colorado’s current policy is more
stringent than most other states. Through its research, CEO found that nine states do not
have statewide interconnection policies or do not address liability insurance in state
interconnection policies. Of the remaining 41 states, 29 states and the District of Columbia
do not require additional liability insurance for Level 1 systems. Five states determine that
utilities can require liability insurance for Level 1 systems if the amount is “reasonable” or
by using other indeterminate criteria. Of the remaining seven states with insurance
requirements, two require $100,000 in liability insurance coverage and five states require
$300,000 in liability insurance coverage for Level 1 systems. Furthermore, more than half
of states consider Level 1 systems to have a maximum capacity of Colorado’s current 10 kW
cap, meaning these reduced liability insurance requirements are deemed appropriate for
systems that are considered Level 1 or Level 2 system in Colorado.
CEO asserts that a reduced amount of liability insurance coverage is appropriate for
Level 1 systems based on its experience administering its Low-Income Rooftop Solar
program for Weatherization Assistance Program (“WAP”) clients. The purpose of this
program is to reduce income-qualified clients’ utility bills and provide distributed
generation access to a traditionally underserved demographic. The average solar
photovoltaic installation in the Low-Income Rooftop Solar program is 3.0 kW. In certain
instances, the $300,000 liability insurance requirement clients creates a barrier to
expanding distributed generation access to this group.
B.

Rule 3854: Level 1 Process

CEO believes that the Commission’s proposed approach to the Level 1
interconnection process may present a barrier that disadvantages smaller retail distributed
42

 generation systems in Colorado. CEO supports the Commission’s efforts to modernize and
simplify the interconnection processes; however, we recommend that the Commission does
not rely so heavily on utilities to develop its proposed interconnection policy. Instead, the
Commission should direct the utilities to work with CEO and other stakeholders in a series
of workshops after the initial hearings to develop a joint proposal to update and modernize
the Level 1 interconnection process without forfeiting any reliability of the electric grid.
CONCLUSION
For the reasons enumerated herein, CEO respectfully requests that the Commission
consider these comments in this rulemaking proceeding.

Respectfully submitted this 1st day of May, 2019.

PHILIP J. WEISER
Attorney General
/s/ Jessica L. Lowrey
JESSICA L. LOWREY, 45158
Natural Resources and Environment Section
1300 Broadway, 7th Floor
Denver, CO 80203
Telephone: 720.508.6167
Email: jessica.lowrey@coag.gov

43