C08-0248 Decision No. C08-0248
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO
07R-371G DOCKET NO. 07R-371G
In the matter of the proposed rules regarding Natural Gas demand-side management, pursuant to House Bill 07-1037, enacted as §40-3.2-103.
DECISION ADOPTING FINAL RULES
Mailed Date:	March 7, 2008
Adopted Date:	March 5, 2008

TABLE OF CONTENTS
I.	BY THE COMMISSION	1
A.	Background	1
B.	Deliberations on the Final Rule	3
II.	ORDER	20

I.	BY THE COMMISSION
A.	Background
1.	On June 27, 2007, we issued Decision No. C07-0562 opening Docket No. 07I‑251G, to investigate issues associated with the natural gas Demand Side Management (DSM) requirements contained in § 40-3.2-103, C.R.S.  In that Decision, we established dates for: (1) an informal workshop; (2) stakeholder comments and proposed rules; and (3) stakeholder reply comments.  
2.	Commission Staff held an informal workshop on July 18, 2007.  Initial comments were filed by Ratepayers United of Colorado (RUC), Energy Outreach Colorado (EOC), Colorado Natural Gas, Inc.(CNG), Atmos Energy Corporation (Atmos), Southwest Energy Efficiency Project (SWEEP), the Colorado Office of Consumer Counsel (OCC), SourceGas Distribution, LLC, (SourceGas), Public Service Company of Colorado (Public Service), Aquila Networks-PNG (Aquila), and the Energy Science Center.  RUC, OCC, Public Service, and SourceGas filed reply comments.  We issued a Notice of Proposed Rulemaking (NOPR) by Decision No. C07-0830.
3.	The basis and purpose of the proposed rules is to implement the recent legislation codified at §40-3.2-103, C.R.S., which directs the Commission to implement rules to establish specific natural gas DSM requirements for jurisdictional natural gas utilities.
4.	Section 40-3.2-103, C.R.S., provides that, on or before September 30, 2007, the Commission is required to commence a rule-making proceeding to develop expenditure and natural gas savings targets, funding and cost-recovery mechanisms, and a financial bonus structure for DSM programs implemented by investor-owned gas distribution utilities.
5.	We requested that interested persons file comments no later than November 1, 2007, and reply comments no later than November 20, 2007.  We took additional general comments at a hearing on December 3, 2007.  Additionally, we sought comments in written or oral form based on questions attached to Decision No. C07-1009, and comments to those questions were also addressed at the December 3, 2007 hearing.  Ten parties provided written and oral comments, including Colorado Energy Efficiency Business Coalition (CEEBC); SWEEP; EOC; the OCC; RUC; Public Service; Aquila; SourceGas; Atmos and CNG.
6.	At the December 3, 2007 hearing, we concluded that an additional comment hearing on February 13, 2008 was necessary to gather further comments on the current issues and concerns regarding this rulemaking.
7.	On January 16, 2008, we issued Decision No. C08-0066 which was a Supplement to the Notice of Proposed Rulemaking (Supplemental NOPR).  In that Decision we released a revised version of the proposed rules, requested written comments be submitted by February 8, 2008, and set forth the details concerning a hearing to take oral comments on the revised proposed rule.
8.	Five parties submitted written comments in response to the Supplemental NOPR, including Public Service; the OCC; Aquila; SWEEP; and the Energy Efficiency Business Coalition of Colorado (EEBC).  At the February 13, 2008 comment hearing these five parties offered additional comments, or made themselves available for questions, along with representatives of SourceGas and Atmos Energy.
B.	Deliberations on the Final Rule
9.	On February 27, 2008, we convened a Deliberation Meeting to review the proposed rule and the comments received.  The Deliberation Meeting was continued on March 5, 2008.
10.	Comments were received from all of the participating utilities concerning the issues they perceived regarding the proposed rules.  General comments made specific reference to various rules (4755, 4756, 4758 and 4759).  Public Service proposed deletion of those rules in their entirety and this opinion was supported by other utilities.  We have reviewed the proposed rules from the perspective of their alleged inflexibility and the burden they place upon utilities.  As noted in the Decision accompanying the Supplement NOPR (Decision No. C08-0066), we are attempting to strike a balance between competing needs and demands.  As it pertains to burden and flexibility, our objective is to create a framework and a process sufficient to carry out the legislative intent while not interfering where utilities should be provided discretion.
11.	Concerning Rule 4406, various utilities commented in response to the first NOPR that the suggested language should be deleted.  The language in Rule 4406(b)(II)(D) was retained so that customers would be informed of the additional DSM costs being incurred.  Oral comments received from Public Service in response to the Supplemental NOPR clarified its position, in terms of objecting to a “per-unit” cost being itemized on customer bills.  We concur that this level of detail is not necessary.  Consequently, it has been eliminated.
12.	Concerning Rule 4750, Aquila and Public Service both commented that the language in this rule exceeded the parameters of the statute and suggested deletion of specific words and phrases.  While we view the statute as providing a fair amount of latitude to the Commission, we modified the language in this rule (as indicated in rules attached to the Supplemental NOPR) to better reflect the legislative intent and Commission’s objectives.  The edits also included changes to this rule concerning the schedule for utility filings, reflecting proposed changes in other rules.  No additional comments concerning Rule 4750 were received in response to our rule changes as indicated in the Supplemental NOPR.  Therefore, we adopt the language of Rule 4750 as provided in the Supplemental NOPR, with minor grammatical changes.
13.	Concerning Rule 4751, Public Service suggested several changes to the definitions of terms, including the deletion of some definitions, in response to the NOPR.  Most of these suggestions were incorporated into the subsequent rule changes.  Also, the definitions of “Cost effective” and “DSM Education” were modified to reflect the statutory definition contained in §40-1-102, C.R.S.  Several comments were received from various parties concerning the definitions of benefits and costs within the cost-effectiveness test.  The definition of “Modified Total Resource Cost test” was revised in response to these comments.  The OCC proposed deleting references to “residential or commercial” from the definition of “sales customer” or “full service customer” so as to not preclude the possibility of a sales customer from another class.  We find that the definition as proposed in the Supplemental NOPR adequately covers all likely gas customers.  
14.	Aquila offered amended language for the definition of “DSM program” to include information and services.  We agree with this proposed change.  SWEEP requested that net economic benefits should be calculated at the program level as well as the portfolio level.  Since net economic benefits are calculated as a component of the bonus calculation, and since the bonus applies to the portfolio not individual programs, we do not see a need to revise the definition as proposed by SWEEP.  Furthermore, program level performance data (expenditures and cost effectiveness) will be included in the annual reports, which provide the basis from which a program-specific net economic benefit can be determined.  Also, EEBC commented that the definitions should incorporate all possible benefits of DSM.  The topic of including all possible benefits is addressed in Rule 4753(l)(I).
15.	Concerning Rule 4752, the various utilities and SWEEP expressed opposition to the proposed filing schedule.  SWEEP recommended that DSM plans be filed every three years, as is the practice in Nevada.  Aquila also commented that, based upon their experience administering gas DSM programs in other states, multiple year programs filings are significantly better and more workable than annual filings.  The rule as amended in the Supplemental NOPR reflected these comments.  Public Service, on behalf of all Colorado Local Distribution Companies (LDCs), opposed the proposed March 1 filing deadline for annual reports and bonus applications.  Public Service expressed a concern that some of the data needed for these filings may not be available by March 1, and instead suggested April 1 as a deadline.  We agree with this proposed change.  Also, the Supplemental NOPR set forth a staggered filing schedule (April and July) for subsequent DSM plans from four of the gas utilities and was silent on when the others were to file.  For clarity and simplicity, we modify the schedule so that all DSM plans are filed by May 1 of the final year of the current DSM plan.
16.	Concerning Rule 4753, several comments were received concerning the required contents of a DSM plan filing.  Various parties expressed concerns that the proposed rule was overly burdensome, requiring excessive content and was inflexible.  In response to these comments we revised Rule 4753 to reduce the content requirements, while achieving the objective of receiving DSM plan filings that clearly describe the utility’s DSM planning process and substantiate the proposed DSM programs, without being overly burdensome.  In response to the proposed rule amendments, SWEEP commented that the expenditure projections within a DSM plan should be provided for each program, not just the overall portfolio.  Pursuant to §40-3.2-103 (6)(a) the utilities are required to submit annual reports to the Commission which include program expenditures.  In order to fulfill this requirement, utilities will need to develop program level budgets and track expenditures by program.  As a result, we find that requiring DSM plans to include program level budgets is a reasonable additional requirement which should not be a significant burden.
17.	Based upon comments received, Rule 4753(e) was amended to reduce the content required in a DSM plan.  The objective of these changes was to focus the plan contents on just the DSM programs being proposed.  Public Service commented on the “market assessment” requirement, expressing concern about the burden of regularly conducting such an assessment.  Public Service proposed greater flexibility.  Oral comments received during the February 13, 2008, hearing served to further clarify this concern.  Our objective is to receive within DSM plan filings, the data and information sufficient to identify the distinct market segments within a gas utility’s total customer base.  It was not meant to require an assessment of the market potential for DSM as a prerequisite to each DSM plan filing.  Consequently, we revised the wording of Rule 4753, substituting the language “descriptions of identifiable market segments, with respect to gas usage and unique characteristics” in place of the term “market assessment.”  We conclude that all utilities should be able to provide such data and information within their DSM plans without having to conduct a formal market assessment.
18.	Various parties commented on the process by which the DSM plan targets will be established.  The essence of the concern expressed pertains to whether the utility sets the targets or proposes the targets, especially since the targets are the basis for awarding a bonus.  We clarified that the utility proposes targets in their DSM plan filing, which is filed as an application that can be set for hearing in which parties can intervene.  Through the adjudicatory process the targets will be decided by the Commission.
19.	Concerning Rule 4753(e), review of the initial comments led us to conclude that the information and data being required in a DSM plan is necessary.  Specifically, we revised the language in sub-paragraph (II) to narrow the focus to only the DSM measures that the utility is proposing (as opposed to potential DSM measures).  We agree that the language is unclear concerning how the utility is to rank possible DSM programs.  Further, we conclude that the language in this sub-paragraph needs to be refocused to apply only to the DSM programs that the utility is proposing, as opposed to “possible DSM programs” as stated in the Supplemental NOPR.  We also revise the ranking process required in Rule 4753 (e)(IV) to clarify how proposed DSM programs are to be compared.   This ranking of proposed DSM programs is keyed to the value and potential of each program,  based upon the analysis conducted of each program pursuant to Rule 4753(e)(III).
20.	Also regarding Rule 4753(e), we find that there is an inadvertent omission regarding the expectation that each proposed DSM program have a projected modified TRC test value of at least 1.0.  Consequently, we incorporate this concept into Rule 4753(e)(IV).
21.	EOC provided comments as to how the gas DSM rules should address access to DSM programs by low-income customers, whether to require utilities to include low-income DSM programs in their portfolios and whether to exempt low-income customers from DSM cost adjustments.  Other parties offered comments in response to EOC’s recommendations.  We find that there are not grounds for excluding low-income customers from the DSM cost adjustment.  However, we do expect gas utilities to include the low-income customer segment in their gas DSM program planning.  Section 40-3.2-103 (3)(a) provides options for how gas utilities can target low-income customers and we strongly encourage utilities to develop gas DSM plans that include a low-income component.
22.	Several comments were received concerning the minimum expenditure requirement set forth in the proposed rules.  One particular concern was the definition of revenue, particularly since the expenditure minimum is defined as a percentage of the utility’s gas revenues.  Several parties suggested that revenue be defined as the non-commodity, or base-rate portion, of a gas utility’s revenues.  We agree with the rationale that removing commodity from the definition will reduce the volatility in calculating a minimum DSM expenditure level, and that this can improve multi-year DSM planning.  On the other hand, §40-3.2-103(2)(a), clearly sets the minimum expenditure as “at least one-half of one percent of a natural gas utility’s revenues” without any reference to exempting commodity sales from revenues.  Based upon a review of Colorado gas utility revenues, it is evident that, on average, the commodity portion is about seventy-five percent of total revenue.  Using this average, we calculate that two percent of base rate revenue is equivalent to one-half of one percent of total revenue.  We substituted two percent of base revenue as the expenditure minimum in the draft rule.  Nevertheless, we are concerned that, given the variation among Colorado utilities regarding the portion of revenues derived from commodity sales, using two percent of base revenue as the minimum may result in some utilities being out of compliance with the statutory minimum.  Therefore, we amend Rule 4753(g)(I) to include language setting the minimum expenditure target at the higher of two percent of base rate revenue or one-half of one percent of total revenue.  We are aware that for at least one utility (Colorado Natural Gas), this calculation of the expenditure minimum may greatly increase its required expenditure level due to its relatively high ratio of commodity to base rate revenues.  If the expenditure minimum is unattainable, the utility should consider requesting a waiver of this rule as part of its initial DSM plan application.  
23.	Our objective with the expenditure minimum rule is to promote substantial DSM implementation, which may require expenditures well beyond the statutory minimum.  We are aware that the Colorado gas utilities are diverse in terms of their size, experience with DSM and market characteristics and that some will require a phase-in period in order even to achieve the minimum expenditure level.  As a result, while we do not increase the expenditure minimum beyond the statutory level at this time, we nonetheless anticipate reviewing this rule to reconsider the minimum expenditure level, if necessary, after initial DSM plans have been approved and implemented.  
24.	Rule 4753(g)(IV) pertains to DSM activities such as education and program planning, which must be independently verified as cost-effective.  A limit on how much a utility can expend on these activities was deleted in the Supplemental NOPR in response to comments received.  Also, the terms “impact and process evaluations” were included in this section to more completely reflect the statutory language of §40-3.2-103(5).  In response to the Supplemental NOPR, SWEEP commented that the term “market transformation programs” should also be included in this sub-paragraph.  We agree, particularly since it is our intent to encourage utilities to not only consider DSM programs with short term impacts but also DSM programs that would yield the longer term impact of transforming how a specific market, such as the new housing market, approaches gas consumption or leads to adoption of transformation technologies, such as solar, hot water heaters.  SWEEP also suggested that an expenditure limit of twenty percent be placed upon this overall category of DSM expenses.  While we agree that a DSM plan with a disproportionately large quantity of these types of expenditures may not be sound, we believe that the overall Total Resource Cost (TRC) test and bonus incentives will serve to limit a utility’s expenditure on these activities.  We also find that the term “market transformation” must be defined so that its inclusion in this rule is clear.  As a result, we include it in the definition section under Rule 4751.  
25.	With regard to expenditures beyond the expenditure target, the rules proposed limiting such expenditures by their impact upon the rate increase approved in the utility’s DSM plan.  Based upon comments received, we amended the rule to allow for a five percent overage, after which the utility’s energy target would have to increase proportionately.  SWEEP and Public Service commented that this did not provide adequate flexibility to utilities in achieving their energy targets and that the utilities should have the discretion to exceed their expenditure targets.  We agree that the five percent is overly restrictive.  Rather, we find that the 25 percent variance proposed by Public Service is reasonable.  
26.	The comments were mixed concerning whether an over-expenditure should also trigger an increased energy target.  We find that an adjustment in the energy target is not necessary.  The TRC and the net economic benefits calculations will serve to restrain over-expenditures, since additional expenditures without some amount of additional energy saved will adversely affect a DSM portfolio’s overall cost-effectiveness and bonus.
27.	Rule 4753(j) proposed that the utility would quantify and justify any proposed non-energy benefits.  In response to comments from various parties, we amended the rule to list which specific non-energy benefits the utility was expected to include and quantify, and deferred to “current market values” when including these benefits into the TRC calculation.  Comments received from SWEEP urged the Commission to determine specific values for avoided emissions, since they are specifically referenced in §40-1-102(5)(b)(II) in regards to calculating the DSM benefit-cost ratio.  EEBC also urged that the Commission include all benefits possible within the evaluation of DSM programs.  Several parties referenced examples from other states regarding the defining and quantifying of non-energy benefits within DSM benefit-cost calculations.  A review of these sources yielded a wide range of approaches.  For example, Utah excludes non-energy benefits, while Iowa establishes a factor representing the general value of these benefits, to be applied to the avoided energy and capacity cost values.  Minnesota created specific ranges of values for various emissions, while New York values other societal benefits resulting from DSM, such as employment and wage increases, improved housing resale values and health/comfort factors.  
28.	We find that, because the statute calls for the “valuation of avoided emissions” and for the inclusion of “nonenergy benefits as determined by the Commission” (See §40-1-102(5)(b)(II) and (III)), we must provide guidance regarding valuing and inclusion of these benefits.  Further, we find that, while there is a myriad of non-energy benefits that potentially could be identified, it is not feasible to provide specific values or ranges for many of these to a degree that will meaningfully assist in calculating the TRC.  Consequently, we conclude that the Iowa approach, with modifications, is the most effective way to acknowledge the value of non-energy benefits.  However, rather than providing a non-energy adjustment factor that is applied to avoided cost values which fluctuate with the price of energy, we find it to be more effective to provide an adjustment value to be applied to the overall TRC benefit value.  We conclude that a TRC should be scaled by a factor of 1.05 to represent avoided emissions and societal benefits.  Further, we find that a utility should retain the option to propose a different value for these benefits, so long as they provide documentation to substantiate the value proposed.
29.	The language originally proposed in Rule 4754 was substantially revised in response to comments from the parties concerning the bonus calculation.  The new language, starting with paragraph (g), serves to explain and delineate the process through which a bonus amount is calculated, the connection between the bonus and the targets, and what the bonus should reward.
30.	The OCC commented that the bonus should be “two-tiered” with one part tied to performance and the other tied to the utility’s specific lost revenue value.  We disagree with the need to create utility-specific bonus structures.  The bonus structure proposed in the Supplemental NOPR adequately addresses concerns regarding lost revenue resulting from DSM.  Furthermore, the utilities did not express objections with this aspect of the proposed bonus structure.
31.	The OCC, Public Service and SWEEP commented on the proposal to allow a bonus to be earned starting when a utility achieves 80 percent of its energy target.  Some comments supported this approach while others suggested that the bonus not be earned until 100 percent of the energy target is achieved.  We are not convinced that the 80 percent approach as proposed needs to be revised.  We find that it is a reasonable balance between the competing objectives, of motivating utility DSM performance across various utilities, acknowledging the occurrence of some lost revenues due to DSM and encouraging utilities to meet, if not exceed, their energy targets.
32.	Public Service commented that the “savings factor” component creates unnecessary complexity and that the costs associated with this factor are not totally under the control of the utility.  While we acknowledge that this factor does add to the complexity of the bonus calculation, we believe that this complexity is worthwhile since it yields a bonus calculation that motivates the two desired outcomes of gas DSM - maximum amounts of energy saved and cost-effective expenditure of funds in the pursuit of energy savings.  Also, while there may be some costs outside of the control of the utility, we find that the utility should be able to make the management decisions necessary to respond to such changes in costs, and that this factor will serve to encourage sound management.  
33.	We clarified Rule 4754(g)(II), to indicate that a utility must first achieve the minimum expenditure threshold in order to earn a bonus.   Public Service commented that the bonus should not be tied to spending, but rather only to energy savings and net economic benefits.  We agree that our objective is not to reward spending, but to reward performance relative to saving energy cost effectively.  However, we find that §40-3.2-103 (2)(a) clearly sets forth a minimum expenditure expectation and this rule serves to reinforce that statutory expectation.
34.	SWEEP recommended revising the terms “Energy Factor” and “Savings Factor” as set forth in Rule 4754(g)(III).  We are not convinced that the terms as proposed require revision.  Further, those terms, as currently defined, serve to reinforce the primary emphasis on saving energy (through an energy factor), and is consistent with the concept that savings (as a target or factor) pertains to the ratio of energy saved per dollar expended.
35.	In response to comments received, we included Rule 4754(h).  The intent of the rule is to mitigate any conflicting directives in the rules, specifically concerning motivating utilities to seek out cost-effective DSM programs and simultaneously incorporating a low-income DSM component which may not be as cost-effective as other options.  
36.	In response to this language SWEEP commented that if the cost and benefits of low-income programs can be excluded from the bonus calculation, then they should also be excluded from the targets.  We find that there is a need to ensure that low-income programs are not adversely affecting a utility’s bonus calculation.  We also find that any low-income DSM program with a TRC greater than 1.0 will have a positive affect upon net economic benefits and, consequently, a positive impact on the utility’s potential bonus.  However,, we are also aware that a low-income program could adversely affect a utility’s Savings Factor, since such programs tend to operate relatively close to a TRC break-even.  As a result, we revise the language of Rule 4754(h) to ensure that low-income programs do not adversely affect the Savings Factor.
37.	Rule 4755(b) was revised to balance the impact, especially upon smaller DSM programs, of the costs of an independent third party with the benefits of using an independent third party.  Public Service commented that the use of an independent third party is unnecessary and is not the most effective use of DSM funds.  Through oral comments received on February 13, 2008, it was indicated that other states such as Minnesota, Iowa and Utah, do not require an independent third party evaluation.  While we are sensitive to maintaining impartiality in the evaluation of DSM programs, we find that requiring an independent third party evaluation is unnecessary.  Further, we find that, through the transparency of the evaluation data provided to the Commission through annual reports and DSM plan filings, we can ascertain the accuracy of evaluation results.  If it subsequently appears that there is reason for concern, those concerns can be addressed through a subsequent rulemaking.
38.	Public Service and Aquila also commented on the frequency of evaluations and how evaluations are to be scheduled relative to the utilities' preparation and filing of subsequent DSM plans as contemplated in Rule 4755(b).  We agree with Public Service and Aquila in part and find that these comments present sound reasoning for modifying this portion of the rule.  However, we do not agree with the recommendation that an evaluation occur only once every five years.  Rather, we agree with the language proposed by Aquila that proposes a schedule of one evaluation per DSM plan period.  We also agree to the proposed language that includes the evaluation of findings within subsequent DSM plan filings.
39.	Rule 4755(c) sets forth what shall be included in the measurement and evaluation of a DSM plan.  The Supplemental NOPR expanded upon the original proposed rule language and more explicitly delineated tasks to be accomplished through measurement and evaluation, as well as focusing the evaluation on DSM programs versus measures.  In response to this proposal, SWEEP commented that an evaluation should specifically address free ridership, spillover and the net-to-gross ratio.  We find that these are all aspects of conventional DSM measurements and evaluations and therefore they will be specifically included in the rule.
40.	EEBC urged the Commission to require the independent evaluator to establish upper and lower values for all DSM benefits.  Based upon our determination that an independent evaluator will not be required, this suggestion is moot.  Further, our findings on the definition and valuation of non-energy benefits (see paragraph 27) addresses this concern.  Therefore, we find that Rule 4755(c)(IV) should be deleted.
41.	SWEEP commented that the phrase “education and/or” should be inserted into Rule 4755(c)(VI).  This serves to expand the focus of measurement and evaluation, as it pertains to indirect impact programs beyond market transformation to also include assessing the impact of educational activities.  We agree with this recommendation and modify Rule 4755(c)(VI) to include the phrase as suggested.
42.	Comments were received from various parties in response to Rule 4756 as presented in the original NOPR.  Changes reflecting these comments were incorporated into the Supplemental NOPR.  Portions of the content originally in Rule 4756 were moved into other rules to improve clarity and consistency.  Also, other paragraphs, such as the original paragraph (a) which addressed the cost/benefit test, were deleted since that topic was addressed elsewhere in the rules.  Also, proposed changes to the “Amortization Periods” paragraph were incorporated into the rule, as well as suggested language acknowledging the positive interplay between gas and electric DSM programs.
43.	In response to those changes, Public Service suggested that the amortization period as proposed in Rule 4756(a) should be more flexible and not tied to the lifetime of the DSM measure or program.  We agree with Public Service and find that this proposed rule should be amended to allow the utility to propose an amortization period within its DSM plan filing.
44.	Public Service offered comment concerning the requirement that Gas Purchase Plans be adjusted to reflect reduced energy needs resulting from DSM programs.  It commented that the DSM impacts will not be of a magnitude to impact overall gas purchases and that the DSM impacts are already factored into forecast sales.  We agree and find that Rule 4756(b) should be deleted.
45.	Public Service commented that the definition of the term “full” in Rule 4756(d) is unclear, as it pertains to giving “full consideration.”  We find that the intent of the rule will still be achieved without the use of the word “full” and, therefore, we delete that word.
46.	Comments were received from various parties in response to Rule 4757.   Paragraph (c) was amended in response to comments that a TRC value of 1.0 or greater is a basis for determining prudence concerning DSM expenses.  Several parties objected to the proposed language objecting to the denial of cost recovery based upon the TRC value.  We find that the language as proposed may be excessive in it presumption of imprudence.  We conclude that the language should be amended to convey that costs yielding a TRC below 1.0 will be “subject to review” and that  “the presumption of prudence is lost.”
47.	The Supplemental NOPR also proposed revised language concerning existing low-income DSM programs, in response to comments received from EOC.  The intent of this revised language is to implement the option set forth in the statute concerning existing programs as contained in §40-3.2-103(7), particularly concerning continuation of existing cost recovery practices.  There is a fifteen-year practice of recovering the costs of the Energy $aving Partners (E$P) Program from all Public Service customers.  We find that this is a reasonable approach to cost recovery for E$P and that it should continue.  To do otherwise would increase the burden upon some customers.  We are sensitive to the fact that this requires Public Service to continue an existing DSMCA practice for E$P while implementing a new one for all other DSM expenditures.  However, the E$P cost recovery is already in place, and the new DSMCA will be necessary for all other DSM expenditures regardless.  Therefore, we find the resulting obligation nominal and appropriate.
48.	Public Service and Aquila both commented on the terminology used concerning DSMCA filings in Rule 4757(i) Rule 4757(g).  The parties object to the term “application” within the context of filing a cost adjustment.  The parties suggest that the reference to Rule 4110 in paragraph (h) was vague and ambiguous.  While we find that the intent of this language and reference, in its current form, was not meant to change how utilities file cost adjustments, we agree that the language proposed by Public Service and Aquila clarifies the intent and it should therefore be substituted into the rule.  We further agree to delete the reference to Rule 4110 in paragraph (h).
49.	The language in Rule 4757 (paragraph (n) in the original NOPR, and (l) in the Supplemental NOPR) addresses interest on over- or under-recovery.  Comments were received in response to this language expressing a concern that the asymmetry undermines the purpose of the interest payment and would provide a perverse incentive of encouraging the utility to never under-collect.  We are sensitive to the possible disincentive resulting from this approach to accruing interest, and we find that, since it may encourage maximum investments in cost-effective DSM, the interest on over- or under-recovery should be symmetrical.
50.	Comments were also received expressing concerns with the amount of content and detail required when filing a Gas DSM Cost Adjustment as proposed in Rule 4758.  In response to these concerns the rule was substantially rewritten, reducing the content requirements and specificity concerning these filings.  Further, for consistency, the revised rule referenced the “detail and scope of information supplied in support” of Gas Cost Adjustment filings.  Public Service commented that this language was vague and ambiguous and suggested that 4758(b) was sufficient to provide the information needed.  Public Service also commented that 4758(a)(III) violates the procedure set forth in rule 1303(b).  While we are concerned that a lack of detail and scope in cost adjustment filings impedes effective regulatory oversight, we support deleting sub-4758(a)(II) and (III).  We expect utilities to provide details in their filings sufficient to support thorough and expedient processing of these filings.
51.	Public Service also commented that Rule 4758(a)(IV) gives excessive power to Commission Staff to determine whether a filing is sufficient, and conflicts with Rule 1303(b).  We do not agree with Public Service’s comments regarding the role of the Staff.  The role of Staff here is to make a recommendation to the Commission, and the proposed language does not alter that role.  However, we do find that the language of proposed Rule 4758(a)(IV), while more directly conveying the desire of the Commission to receive complete filings, is somewhat duplicative of existing rule 1303(b).  Therefore, Rule 4758(a)(IV) is deleted.
52.	No changes were proposed to Rule 4759.  Rule 4760 was changed in response to comments received concerning the process for awarding a bonus.  The bonus calculation language was deleted from this section.  Instead, all of the bonus calculation language was incorporated into Rule 4754 for clarity.  No comments were received in response to the proposed changes to Rules 4759 and 4760.  Therefore, we find that these rules should be adopted as presented in the Supplemental NOPR.
II.	ORDER
A.	The Commission Orders That:
1.	The Commission adopts the Rules regarding Natural Gas Demand-side Management, pursuant to House Bill 07-1037, enacted as §40-3.2-103 attached to this Order as Attachment A.
2.	The rules shall be effective 20 days after publication by the Secretary of State.
3.	The opinion of the Attorney General of the State of Colorado shall be obtained regarding the constitutionality and legality of the rules.
4.	A copy of the rules adopted by the Order shall be filed with the Office of the Secretary of State for publication in The Colorado Register.  The rules shall be submitted to the appropriate committee of the Colorado General Assembly if the General Assembly is in session at the time this Order becomes effective, or to the committee on legal services, if the General Assembly is not in session, for an opinion as to whether the adopted rules conform with § 24-4-103, C.R.S.
5.	The 20-day time period provided by § 40-6-114(1), C.R.S. to file an application for rehearing, reargument or reconsideration shall begin on the first day after the effective date of this Order.
6.	This Order is effective upon its Mailed Date.
B.	ADOPTED IN COMMISSIONERS’ WEEKLY MEETING
March 5, 2008

		THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO

________________________________

________________________________

________________________________
	Commissioners
	
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C08-0248-EDecision No. C08-0248-E 
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO
07R-371GDOCKET NO. 07R-371G
In the matter of the proposed rules regarding Natural Gas demand-side management, pursuant to House Bill 07-1037, enacted as §40-3.2-103.
ERRATA NOTICE

DECISION ADOPTING FINAL RULES
Errata mailed March 13, 2008
original Decision No. C08-0248 mailed March 7, 2008

	1.	In mailing Decision No. C08-0248, we omitted attaching a clean version of the adopted rules.  The clean version of the adopted rules is attached to this errata notice to correct this omission.  
	2.	The attached, clean version of the adopted rules contains certain non-substantive formatting and textual corrections from the redlined version.  Until redline and strikeout was accepted, certain formatting and textual errors in the rules were not noticeable; so we make these corrections to the clean version attached.  

		THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO

_______________________________________________
	Doug Dean,  Director
	Dated at Denver, Colorado this
13th day of March, 2008. 	
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C08-0425 Decision No. C08-0425
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO
07R-371G DOCKET NO. 07R-371G
In the matter of the proposed rules regarding Natural Gas demand-side management, pursuant to House Bill 07-1037, enacted as §40-3.2-103.
ORDER DENYING APPLICATION FOR REHEARING, REARGUMENT, OR RECONSIDERATION
Mailed Date:	April 22, 2008
Adopted Date:	April 16, 2008
I.	by the commission
A.	Background
	1.	In Decision No. C08-0248, we adopted final rules regarding natural gas Demand Side Management (DSM).  That Decision set forth the 20-day period for the filing of applications for rehearing, reargument, or reconsideration, which expired on March 27, 2008.
	2.	On March 27, 2008, Public Service Company of Colorado (Public Service) filed an application for rehearing, reargument, or reconsideration of Decision No. C08-0248 (RRR).
	3.	Public Service’s RRR application requests that the Commission reconsider portions of Rule 4 Code of Colorado Regulations 723-4-4752.  Public Service requests that subpart (a) be amended to allow Public Service more time to file its DSM plan than the 120 days set forth in the rule.  Public Service also requests that subpart (c) be modified to allow it to file a biennial plan rather than a triennial plan.
B.	Discussion
	4.	Public Service expresses a desire to file a combined gas and electric DSM plan and is concerned that current proceedings affecting electric DSM will delay its filing of this DSM combined plan beyond the 120-day deadline set forth in the rule.  Public Service proposes a tentative filing date for its initial DSM plan of September 1, 2008.
	5.	Public Service has proposed, in Docket No. 07A-420E, to file a biennial electric DSM plan for 2009 through 2010.  Since it proposes to file a combined electric and gas DSM plan, it further proposes that its initial gas DSM plan cover two years (2009 through 2010), instead of the requirement found in Rule 4752 that its gas DSM plan be a three-year plan.  Public Service further states in its application that it “is not opposed to filing a triennial Plan in the future.”
	6.	We are supportive of Public Service filing a combined electric and gas DSM plan and do not want the gas DSM rules to be an impediment to such a filing.
	7.	It appears from the application that Public Service is defining the effective date of the final rules as being March 7, 2008, the date of the Commission’s Order (Decision No. C08-0248).  This is not the effective date of the final rules.  As noted in paragraph 2 of Decision No. C08-0248, “(t)he rules shall be effective 20 days after publication by the Secretary of State.”  The rules have not yet been published by the Secretary of State.  We thus find that the earliest date at which the final rules will take effect is June 1, 2008.  We further find that the date of September 1, 2008, proposed by Public Service for filing a DSM plan, will nonetheless comply with the final rules.
	8.	We find that the request to file a biennial plan rather than a triennial plan has merit, since it will improve the coordination of gas and electric DSM planning by Public Service.  Since Public Service does not object to future DSM plans covering three years, as set forth in the final rule, we find no reason to reconsider the rule.  Rather, we find that this request can be addressed as a request to waive the rule.
II.	ORDER
A.	The Commission Orders That:
	1.	The application for rehearing, reargument, or reconsideration filed by Public Service Company of Colorado is denied consistent with the discussion above.
	2.	Public Service shall proceed with filing a two-year demand side management (DSM) plan combining gas and electric DSM, and to include within this filing a request to waive Rule 4 Code of Colorado Regulations 723-4-4752(c) concerning the filing of a three-year plan.
	3.	This Order is effective upon its Mailed Date.
B.	ADOPTED IN COMMISSIONERS’ WEEKLY MEETING
April 16, 2008.

		THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO

________________________________

________________________________

________________________________
	Commissioners

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