COLORADO DEPARTMENT OF REGULATORY AGENCIES
Public Utilities Commission
4 Code of Colorado Regulations (CCR) 723-4
PART 4
RULES REGULATING GAS UTILITIES AND PIPELINE OPERATORS

Table of Contents (of Affected Sections)
BASIS, PURPOSE, AND STATUTORY AUTHORITY.
GENERAL PROVISIONS
4005.	Records.
4006.	Reports.
BILLING AND SERVICE
4406.	Itemized Billing Components.
4708. – 4749.	[Reserved].
DEMAND SIDE MANAGEMENT
4750.	Overview and Purpose.
4751.	Definitions.
4752.	Filing Schedule.
4753.	Annual DSM Plan Filing and Application for Cost Recovery.
4754.	Annual DSM Report and Application for Bonus.
4755.	Measurement and Verification.
4756.	General Provisions.
4757.	Funding and Cost Recovery Mechanism.
4758.	Contents of Gas DSM Cost Adjustment Applications.
4759.	Bill Itemization.
4760.	Gas DSM Bonus (G-DSM Bonus) Applications.
BASIS, PURPOSE, AND STATUTORY AUTHORITY.
The basis and purpose of these rules is to set forth rules describing the service to be provided by jurisdictional gas utilities and master meter operators to their customers and describing the manner of regulation over jurisdictional gas utilities, master meter operators, and the services they provide.  These rules address a wide variety of subject areas including, but not limited to, service interruption, meter testing and accuracy, safety, customer information, customer deposits, rate schedules and tariffs, discontinuance of service, master meter operations, transportation service, flexible regulation, procedures for administering the Low-Income Energy Assistance Act, cost allocation between regulated and unregulated operations, recovery of gas costs, demand side management, and appeals regarding local government land use decisions.  The statutory authority for these rules can be found at §§ 29-20-108, 40-1-103.5, 40-2-108, 40-2-115, 40-3-102, 40-3-103, 40-3-104.3, 40-3-111, 40-3-114, 40-3-101, 40-4-106, 40-4-108, 40-4-109, 40-5-103, 40-7-117, and 40-8.7-105(5), C.R.S.
GENERAL PROVISIONS
*	*	*
[signifies omission of unaffected rules]
4005.	Records.
(a)	Except as a specific rule may require, every utility shall maintain, for a period of not less than three years, and shall make available for inspection at its principal place of business during regular business hours, the following:
*	*	*
(XV)	Records concerning demand side management, pursuant to Rule 4758.
(XVI)	As applicable, the records and documents required to be created pursuant to rules 4910 to 4920.
*	*	*
4006.	Reports.
*	*	*
(h)	A utility shall file demand side management reports pursuant to rule 4754.
(i)	A utility shall file reports required by rules 4910 through 4917.
(j)	A utility shall file with the Commission any report required by a rule in this 4000 series of rules.
(k)	A utility shall file with the Commission such special reports as the Commission may require.
*	*	*
BILLING AND SERVICE
*	*	*
4406.	Itemized Billing Components.
(a)	A utility shall provide itemized gas cost information to all customers commencing with the first complete billing cycle in which the new rates are in effect.  The information may be provided in the form of a bill insert or a separate mailing.
(b)	The information provided pursuant to this rule shall include the following:
(I)	For transportation customers:
(A)	The per-unit and monthly local distribution company costs billed to the customer.
(B)	If applicable, the per-unit and monthly gas cost adjustment transportation costs.
(II)	For all other customers:
(A)	The per-unit and monthly local distribution company costs billed to the customer.
(B)	The per-unit and monthly gas commodity costs for that customer.
(C)	The per-unit and monthly costs of upstream services for that customer.
(D)	The per-unit and monthly gas demand side management costs for that customer.
*	*	*
4708. – 4749.	[Reserved].
DEMAND SIDE MANAGEMENT
4750.	Overview and Purpose.
These rules implement §§ 40-1-102, 40-3.2-101, 40-3.2-103, and 40-3.2-105,C.R.S. for gas utilities required by statute to be rate-regulated.  Consistent with statutory requirements, the purpose of these Demand Side Management (DSM) rules is to reduce end-use natural gas consumption in a cost effective manner, by implementing programs that will enable each class of sales customer to participate in one or more DSM measures.  The utility shall design DSM programs to give priority to achievable energy savings, customer benefits, cost effectiveness ratios, adoption potential, market transformation capability and ability to replicate in the utility service territory; while considering the overall rate impacts of such programs.  
(a)	Each utility files an annual DSM plan and application for cost recovery to establish an expenditure target, savings target, funding mechanism, cost-recovery mechanism, benefit/cost targets, and bonus structure.
(b)	Each utility also files an annual DSM report and application for bonus as an expedited three-month proceeding. 
(c)	Biannually, each utility files a measurement and verification report which evaluates the actual implementation and performance associated with its DSM program.
4751.	Definitions.
The following definitions apply to rules 4750 through 4760, unless a specific statute or rule provides otherwise.  In the event of a conflict between these definitions and a statutory definition, the statutory definition shall apply.
(a)	“Amortization” means the gradual cost recovery of expenditures for DSM programs, in regular payments over a specified period of time. Such payments may include both principal and carrying cost.  
(b)	“Arrearages” means the amount of an obligation from past transactions.
(c)	“Audit” means a facility or home energy audit to assess how much energy the facility or home consumes and to evaluate measures to make the facility or home more energy efficient.
(d)	“Benefit/cost ratio” means the ratio of the present value of benefits to the present value of costs.  
(e)	“Cost effectiveness test” means a benefit/cost ratio of greater than one.  Cost effectiveness of DSM programs can be established through the use of Participant Test, Ratepayer Impact Test, Total Resource Cost (TRC) Test, or Modified TRC Test.
(f)	“Demand side management” (DSM) means the implementation of programs or measures which serve to control or influence the demand of natural gas usage.
(g)	“DSM education” means any expenditure made in order to increase general awareness of DSM, such as the available/developing energy efficient programs, incentives, equipment available to customers, conducted in a community setting and not individual customer sites.  Education programs shall not be subject to independent cost-effectiveness requirements. 
(h)	“DSM period” means the effective period of the DSM plan, July 1 through June 30.
(i)	“DSM program” means energy efficiency, conservation, load management, and demand response programs or any combination of these programs that are aimed at influencing and reducing natural gas usage. 
(j)	“Energy efficiency program” see DSM program.
(k)	“Measure” means an individual component or technology in a DSM program. 
(l)	“Modified TRC test” means an economic test used to compare the present value of the benefits to the present value of the costs over the useful life of a DSM measure or program, including the economic value of non-energy benefits.
(m)	“Sales customer” or “full service customer” means a residential or commercial customer that purchases a bundled natural gas supply and delivery service from a utility.
4752.	Filing Schedule.
(a)	August 1st of each year – Each utility shall file its annual DSM plan and application for cost recovery.  The annual DSM plan will be effective from July 1st through June 30th to coincide with the gas purchase year for the Commission’s Gas Cost Adjustment rules 4600 - 4609.  
(I)	This 210-day proceeding will conclude on approximately March 1st.  
(II)	July 1st – The utility shall implement its annual DSM plan, and cost recovery begins as established in the annual DSM plan.
(b)	October 1st – Each utility shall submit its annual DSM report and application for bonus.  Biannually, on the same date, the utility shall file its measurement and verification report.
(c)	December 30th (approximate) – Within three months of the filing of the annual DSM report and application for bonus, the Commission shall issue a decision on the DSM bonus, and will direct the utility to file appropriate compliance tariffs to implement cost recovery of the bonus.
4753.	Annual DSM Plan Filing and Application for Cost Recovery.
On an annual basis, on or before August 1st, the utility shall file a natural gas DSM plan for approval.  The plan shall detail the utility’s estimated annual natural gas energy savings for the plan year, the measures proposed in the plan and programs that will produce DSM benefits.  As a part of the annual DSM plan filing, each utility shall also file proposed rates, to be effective beginning on July 1st of the following year.  The Commission will use information in the DSM plan filing for its annual report to the Colorado general assembly.
(a)	The utility shall include in its annual DSM plan filing the design, implementation, oversight and cost effectiveness of natural gas DSM programs, including information on total usage analysis, technical potential and program savings (in therms).
(b)	The utility shall justify its proposed DSM programs based on the criteria set forth in the Overview and Purpose, rule 4750.  At a minimum the utility shall provide the following information detailing how it developed its proposed DSM program:
(I)	A market assessment for determining gas usage and characteristics across customer groups. 
(II)	A comprehensive list of potential DSM measures for saving energy in the targeted markets, including a detailed description of each measure based on generally accepted best practices, such as the American Council for Efficient Economy (ACEEE) summary report on best natural gas energy efficiency programs.
(III)	A detailed analysis of selected measures for a utility’s service territory in terms of markets, customer classes, cost effectiveness and accessibility to products.
(IV)	A ranking of all feasible DSM measures.
(V)	The projected number of customers within the customer class for each program.
(VI)	Projected energy savings, based on the analysis in paragraphs (I) through (V) of this subsection.
(VII)	Program strategies to promote the technologies based on industry best practices.
(VIII)	Proposed cost effectiveness of the designed program, including costs to the utility and to participating customers.
(IX)	An analysis of the impact of the proposed DSM program expenditures on utility rates, assuming a 12-month cost recovery period.
(X)	A final set of recommended DSM programs.
(c)	The utility may propose one or more DSM programs that are targeted to low-income customers.
(d)	As a part of its annual DSM plan filing each utility shall propose its expenditure target, pursuant to § 40-3.2-103 (2)(a), C.R.S.
(I)	The natural gas utility’s annual minimum expenditure targets for natural gas DSM programs shall be one-half of one percent (0.5%) of a natural gas utility’s revenues, from its sales customers in the 12-month calendar period prior to setting the targets. 
(II)	Each utility shall establish its expenditure target based on DSM measures that will gain customer participation and energy savings in the most cost effective manner.
(III)	Expenditure targets in excess of one half percent of revenues may be considered by the Commission if higher targets can be justified in terms of achieving greater cost effective energy savings.
(IV)	Moneys spent for education programs and program planning related to natural gas DSM programs can be recovered without having to show that such expenditures, on an independent basis, are cost-effective, but shall be included in the overall benefit/cost ratio analysis. The amount spent for these activities shall be less than 10 percent of the expenditure target.
(e)	The utility shall propose a budget plan.  The budget for the plan and for each program for each year of implementation shall be itemized by proposed costs.  The plan and program budgets shall be categorized into: 
(I)	Planning and design costs; 
(II)	Administrative costs; 
(III)	Advertising and promotional costs; 
(IV)	Customer incentive costs; 
(V)	Equipment costs; 
(VI)	Installation costs; 
(VII)	Measurement and verification costs; and 
(VIII)	Miscellaneous costs. 
(f)	The budget plan shall include explanations of anticipated increases/decreases in financial and human resources. 
(g)	A utility may spend more than the annual expenditure target established by the Commission only if it does not exceed maximum rate increase approved by the Commission as a part of plan approval. 
(h)	Savings target  As a part of its annual DSM plan each utility shall propose its savings target based on the level of expenditures within a utility’s annual DSM plan.  Savings targets shall be established that are commensurate with program expenditures and expressed in terms of an amount of gas saved per unit of program expenditures. 
(i)	Benefit/Cost targets  As a part of its annual DSM plan each utility shall propose benefit/cost targets based on planned expenditures and expected savings.  The entire portfolio of DSM programs must satisfy a benefit/cost ratio of unity (1) or greater.  
(j)	Justification of non-energy benefits and quantification  Each utility shall fully justify and quantify any proposed non-energy benefits.
(I)	Where possible, the utility shall quantify non-energy benefits based on dekatherms saved.
(II)	Otherwise, the utility shall quantify non-energy benefits based on other measurable savings, such as reduced emissions of CO2, NOX, methane, or gallons of water saved, for example.
(III)	To the extent that a utility currently recovers arrearages and late payments in rates, the utility shall not include these costs as non-energy benefits. 
(k)	Distribution of DSM program expenses.
(I)	At a minimum, the utility shall spend 90 percent of annual DSM plan costs on activities and programs that result in actual reduction in natural gas usage. Customer education and broad-based program costs not directly related to a specific DSM program or offering shall be limited to no more than 10 percent of the total annual DSM plan costs.
(II)	The utility shall include in its benefit/cost analysis all DSM education, research and evaluation costs, including those costs that do not apply to individual programs. Impact and process evaluation, program planning, and customer education efforts that do not directly address energy efficiency and conservation shall not apply to the benefit/cost analysis.
(III)	Utilities’ existing customer education tools such as on-line energy assessment tools or other similar internet based tools shall not be included for cost recovery in the natural gas DSM program. 
(l)	Measurement and verification plan.  The natural gas utility shall describe in complete detail how it proposes to monitor and evaluate the implementation of its proposed programs and shall show how it will accumulate and validate the information needed to measure the plan’s performance against the standards, pursuant to rule 4755.  The utility shall propose a format for monitoring reports and describe how annual results will be reported to the commission on a detailed, accurate and timely basis.
(m)	Application for cost recovery  The utility shall file an application for cost recovery pursuant to rules 4757 and 4758.
4754.	Annual DSM Report and Application for Bonus. 
On an annual basis, on or before October 1st, each utility shall provide the Commission a detailed natural gas DSM report and application for bonus. 
(a)	In the annual DSM report the utility shall describe its actual DSM programs.  For each measure the utility shall document actual program expenditures, energy savings and the techniques used to estimate these impacts, the estimated cost-effectiveness of program expenditures, and any other information necessary to compare the actual results with the utility’s approved DSM plan.
(b)	Annual program expenditures shall be distributed into cost categories as provided in the approved DSM plan.
(c)	For each DSM measure the utility shall provide an analysis of qualitative and quantitative success of programs in terms of customer acceptance and participation, gas saved per unit of program expenditure, assessment of success of the measure, and any ideas for improvement and greater involvement.
(d)	Benefit/cost actual results  The utility shall provide actual benefit/cost results for the annual plan overall and individual programs that the utility implemented during the plan year.  The utility shall report quantifiable non-energy benefits achieved overall and in individual programs.
(e)	The utility may file an application for bonus, pursuant to rule 4760.  The application for bonus shall include the utility’s calculation of estimated bonus earned using both 25 percent of annual DSM expenditures and 20 percent of net economic benefits.  The net economic benefits shall be calculated as the net present value of the savings implemented, at a discount rate set at the utility’s authorized return, summed over the amortized life of the measure.
(f)	The Commission shall determine the level of bonus, if any, that the gas utility is eligible to collect on the basis of the information included in the report, pursuant to conditions established in the approved DSM plan. Any awarded bonus shall be authorized as a supplement to a utility and not count against their authorized rate of return or be considered in rate proceedings.  The awarded bonus shall be applied over a twelve-month period after approval of the bonus.
4755.	Measurement and Verification.
(a)	Each utility shall implement a measurement and verification (M & V) program to evaluate the actual performance of its DSM program.  The utility shall present its M & V plan as a part of its annual DSM filing, pursuant to rule 4753, and shall include the resulting M & V evaluation report with its annual DSM report and application for bonus, pursuant to rule 4754.  
(b)	As a part of its M & V program, the utility shall hire an independent third party to evaluate the effectiveness of the actual DSM measures and programs implemented by the utility.  This evaluation shall assess the number of measures implemented as well as the actual energy saved, using sampling techniques or other means to measure the actual benefits in an economically feasible manner.  The M & V evaluation shall be implemented at least biannually.  
(c)	The M & V evaluation shall, at a minimum, include the following:
(I)	An assessment of the quantity of individual measures implemented, and a comparison to the corresponding utility projections in its annual DSM filing, pursuant to rule 4753;
(II)	An assessment of the actual energy savings for each measure, and a comparison to the corresponding utility projections in its annual DSM filing, pursuant to rule 4753;
(III)	An assessment of the period of time that each DSM measure actually remains in service, and a comparison to the corresponding utility projections in its annual DSM filing, pursuant to rule 4753;
(IV)	A summary of the actual cost to benefit ratio for each measure or group of measures; and
(V)	Recommendations as to how the utility can improve the market penetration and cost effectiveness of individual DSM programs. 
(d)	Along with the M & V evaluation, the utility shall include a calculation of a revised Gas DSM Cost Adjustment (G-DSMCA) rider if actual benefit/cost test results impact the allowable recovery of DSM costs, or result in any changes to the utility’s currently approved bonus.
4756.	General Provisions.
(a)	Cost/benefit test  Utilities shall use the modified TRC test to evaluate the economic feasibility of current and potential DSM programs.  As a part if its annual DSM filing required in rule 4753, the utility shall establish the specific costs and benefits that will apply under the modified TRC test.
(I)	Costs include the following utility and participant expenditures:
(A)	Program design, administration, evaluation, advertising, and promotion; 
(B)	Customer education; 
(C)	Incentives and discounts;
(D)	Capital costs; 
(E)	Operation and maintenance expenses; and 
(F)	Projected bonus costs.
(II)	Benefits include the following:
(A)	Avoided, transmission, distribution, capacity, and energy costs;
(B)	Avoided emissions costs; and
(C)	Non-energy benefits, to the extent such benefits can be reasonably quantified and valued. 
(b)	Amortization periods. 
(I)	For the base rate method, the utility shall establish the amortization period to match the expected lifetime of the DSM measures, but shall be no less than five years.  The utility shall specify the amortization period for each measure as a part of its annual DSM filing, pursuant to rule 4753.
(II)	For the expense method, the utility shall recover the annual expenditures projected for that year over a one-year period.
(c)	GPP adjustment  The utility shall make a corresponding reduction in its gas supply needs in its Gas Purchase Plan required in rule 4605, to account for the reduced energy needs projected in its annual DSM filing, pursuant to rule 4753.
(d)	Fuel switching  Fuel switching from natural gas to other fossil fuel derived energy sources shall not be included in the gas utility’s DSM program.  Programs to save natural gas through switching to renewables such a solar heating and ground source heat pumps are allowed.  
4757.	Funding and Cost Recovery Mechanism.
Rules 4757 through 4760 are used to revise gas rates on an expedited basis. The purpose of the G-DSMCA is to enable utilities, on an expedited basis, to reflect changes in their base rates for gas sales services and the increases or decreases in costs associated with the funding of DSM Programs.  All such costs shall be recovered through a cost adjustment mechanism that is set on an annual basis, or more frequently if deemed appropriate.  The G-DSMCA allows for prospective recovery of prudently incurred costs of DSM programs within the DSM program expenditure target approved by the Commission in order to provide for funding of the utility’s DSM programs, as well as recovery of deferred G-DSMCA costs, without having to file a rate case.
(a)	A utility may spend a disproportionate share of total expenditures on one or more classes of customers, provided, however, that cost recovery for programs directed at residential customers are to be collected from residential customers only and that cost recovery for programs directed at nonresidential customers are to be collected from nonresidential customers only.
(b)	The utility may recover its  DSM program expenditures either through expensing or by adding DSM program expenditures to base rates as a part of, or outside of, a rate case, with an amortization period as determined by the Commission.  The amortization period shall not be less than five years and shall be consistent with the expected life of the DSM program.  
(c)	There shall be no financial penalty assessed on a utility for failing to reach its approved DSM program expenditure target, nor shall there be a bonus simply for meeting DSM program expenditure target.  All prudently incurred expenditures for the utility’s DSM program should be recoverable, provided, however, that any incremental expenditure on DSM programs that reduces the benefit to cost ratio below the threshold approved in the utility’s DSM plan shall be excluded.  
(d)	Amounts not spent under the DSM program expenditure target shall not roll-over to the next DSM period.  
(e)	A utility has the discretion and the responsibility of managing the portfolio of DSM programs to meet the benefit to cost ratio and the gas savings target.  In implementing DSM programs, a utility shall use reasonable efforts to maximize gas savings consistent with the annual gas efficiency budget.  
(f)	The program expenditures per unit of gas saved shall be consistent with current or forecasted commodity gas cost.
(g)	The length of time used to estimate or calculate the amount of gas saved per unit of program expenditures shall be based on the same amortization period for recovery of the program expenditures.
(h)	A utility may continue DSM programs that were in existence on or before the effective date of § 40-1-102, C.R.S. concerning measures to promote energy efficiency, and shall not be required to obtain approval from the Commission for recovery of costs associated with such programs.  Any new expenditures for such programs must be included in the annual DSM plan filing and G-DSMCA application.
(i)	A utility shall file an application to adjust its G-DSMCA factor. The G-DSMCA application shall be filed pursuant to the schedule provided in rule 4752. 
(j)	A G-DSMCA application shall include, in the following order and specifically identified, the following information, either in the application or in appropriately identified attached exhibits:
(I)	The information required by paragraphs 4758(a) and 4757(m).
(II)	The information required by exhibits 2, 3, and 5 listed in rule 4758 shall be provided in written form and shall be provided electronically, in executable format with all cell formulas intact, using spreadsheet software that is compatible with software used by the Staff.
(k)	If the projected DSM program costs have changed from those used to calculate the currently effective G-DSMCA cost or if a utility’s deferred G-DSMCA cost balance increases or decreases sufficiently, the utility may file an application to revise its currently effective G-DSMCA factor to reflect such changes, provided that the resulting change to the G-DSMCA factor equates to a base rate change of at least one cent ($0.01) per Mcf or Dth.  A utility has the burden of proof to justify any interim G-DSMCA filings and the Commission has the discretion to consolidate the interim G-DSMCA filing with the next regularly scheduled annual G-DSMCA filing.
(l)	Applicability of the G-DSMCA factor. The G-DSMCA factor shall be separately calculated and applied to the utility sales gas base rate schedules of residential and non-residential customers.  
(m)	Return on amortized DSM program expenditure.  For utilities that choose to amortize the DSM program expenditure, the balance of a utility’s investments in cost-effective DSM programs shall earn a return equal to the utility’s current authorized rate of return on rate base.  If a utility will over-earn as a result of such return, said return shall be reduced to a level so that over-earning will not result from it.  The reduction of return on amortized DSM program expenditure shall not be less than zero.
(n)	Interest on under- or over-recovery. The amount of net interest accrued on the average monthly balance in sub-accounts of Account No. 186 (whether positive or negative), is determined by multiplying the monthly balance by an interest rate equal to the Commission-authorized customer deposit rate for gas utilities. If net interest is positive, it will be excluded from the calculation of the deferred G-DSMCA cost.
(o)	Calculation of the G-DSMCA factor. The G-DSMCA factor shall be calculated separately for residential and non-residential customers to at least the accuracy of two significant places pursuant to the following formula:
G-DSMCA factor = (current G-DSMCA cost + deferred G-DSMCA cost) / (forecasted sales customer x monthly service charge + forecasted sales gas quantity x base rate).
4758.	Contents of Gas DSM Cost Adjustment Applications.
(a)	A gas DSM cost adjustment (G-DSMCA) application shall meet the following requirements:
(I)	Every application shall contain exhibits 1 through 7. Exhibits 8 through 11 shall be filed with a G-DSMCA application with an amortization period of longer than one year.  The exhibits shall meet the requirements set out in this rule.
(II)	The exhibits shall be organized in a manner that specifically references, and responds to, the requirements contained in each subparagraph of this rule.
(III)	Cross-referenced and footnoted work-papers fully explaining the amounts shown in each exhibit shall be submitted.
(IV)	When preparing exhibits 9 through 11, the rate base, net operating earnings, capital structure, and cost of capital shall be calculated in conformance with the regulatory principles authorized by the Commission in the utility’s most recent general rate case, including all required pro forma adjustments.
(V)	An explanation of all pro forma adjustments shall be provided.
(b)	G-DSMCA Exhibit No. 1 – G-DSMCA summary. This exhibit shall illustrate all of the following:
(I)	The impact the utility’s currently effective G-DSMCA factor has on each sales gas residential customer class and non-residential customer class on a total dollar and per Mcf or Dth basis in mil ($0.001).
(II)	The amount of gas saved as a result of the utility’s currently effective G-DSMCA factor and the dollar per Mcf or Dth for gas saved by gas residential customer class and non-residential customer class.
(III)	The impact the utility’s proposed G-DSMCA factor has on each sales gas residential customer class and non-residential customer class on a total dollar and per Mcf or Dth basis to the accuracy of one mil ($0.001).
(IV)	The amount of gas saved as a result of the utility’s proposed G-DSMCA and the dollar per Mcf or Dth for gas saved by gas residential customer class and non-residential customer class.
(V)	The percent change in total bill from the proposed G-DSMCA factor for a customer of average usage for each sales gas customer class. This percent change in total bill calculation shall include an itemization of the monthly service and facility charge, base rates and GCA commodity components, and all other tariff charges on the customer bill.
(VI)	The total amount energy saved, and cost, calculated at current gas prices.
(c)	G-DSMCA Exhibit No. 2 - Current G-DSMCA cost calculation. This exhibit shall contain the calculation of the current DSM cost and shall provide month-by-month information for each month of the G-DSMCA effective period with respect to the forecasted cost for each DSM programs, and forecasted sales gas quantity.
(I)	The utility shall calculate current G-DSMCA factor separately for residential and non-residential customers at least to the accuracy of two significant places according to the following formula:
Current G-DSMCA factor = (current G-DSMCA cost + deferred G-DSMCA cost) / (forecasted sales customer x monthly service charge + forecasted sales gas quantity x base rate).
(II)	The utility shall present all cost information by programs separately for residential and non-residential customers in a format comparable with, and corresponding to, the information in the utility’s submittal for each month of the G-DSMCA effective period in its report.
(d)	G-DSMCA Exhibit No. 3 - Deferred G-DSMCA cost calculation. This exhibit shall contain the details of the utility’s actual DSM costs and the calculation of deferred gas DSM cost. In addition, this exhibit shall provide month-by-month information detailing the activity in a deferred gas DSM cost account, Account No. 186, interest on under- or over-recovery, and all other included gas DSM costs. The utility shall calculate deferred gas DSM cost as the aggregate total of the under- or over-recovered gas DSM costs reflected in its Account No. 186, or other approved gas DSM costs, recorded at the close of business for each month of the period at issue (such as the previous gas DSM program year), plus interest, if the net amount represents over recovery.  Each cost a utility desires to have included in the deferred gas DSM cost calculation shall be itemized and clearly identified and itemized for applicability to the period at issue. In its annual G-DSMCA applications the utility shall reflect actual deferred DSM costs for the most recent period ending June 30.
(e)	G-DSMCA Exhibit No. 4 - Current tariff. This exhibit shall contain the tariff page(s) which illustrate the G-DSMCA factor of the utility’s currently-effective rates for sales gas residential and non-residential customers.
(f)	G-DSMCA Exhibit No. 5 - Current gas DSM cost allocations. This exhibit shall fully explain and justify the method(s) used to do each of the following:
(I)	Allocate the costs associated with the gas DSM programs to each specific sales gas customer class.
(II)	Derive the amount of the G-DSMCA factor applied to each specific sales gas customer class.
(g)	G-DSMCA Exhibit No. 6 - Customer notice. This exhibit shall provide the form of notice to customers and the public concerning the utility’s proposed G-DSMCA change. In its customer notice for each sales gas customer class, the utility shall include the following:
(I)	Current and proposed G-DSMCA factor and changes in rates and the associated percentage change.
(II)	Comparison of last year’s average annual bill under prior rates and the projected average annual bill under the proposed G-DSMCA factor in terms of rates and percentage change in the total bill amount using an average usage amount for each sales customer class.  The projected average annual bill shall reflect the impact from the estimated amount of gas saved.
(h)	G-DSMCA Exhibit No. 7 - Components of delivered gas cost. This exhibit shall detail the itemized rate components of delivered gas cost to the customer (rate), pursuant to rule 4759.
(i)	G-DSMCA Exhibit No. 8 - Proposed tariff. This exhibit shall contain the tariff sheets proposed by the utility to reflect the proposed G-DSMCA change.
(j)	G-DSMCA Exhibit No. 9 - Rate base. If a utility chooses the option to recover the cost of the DSM programs through base rates by including an earning on the balance of the amortized amounts of DSM program costs, this exhibit shall calculate the used and useful rate base assets employed by the utility for Commission-regulated gas operations for the most recently completed 12-month period ending June 30.  The depreciation period for said DSM rate base shall be consistent with the period used in the calculation of projected benefit used in the modified TRC test.
(k)	G-DSMCA Exhibit No. 10 - Net operating earnings. If a utility chooses the option to recover the cost of the DSM programs through base rates by including an earning on the balance of the amortized amounts of DSM program costs, this exhibit shall calculate the utility’s net operating earnings for jurisdictional gas operations during the most recently completed 12-month period ending June 30. The utility may exclude any bonus awarded under the DSM programs from net operating earnings.
(l)	G-DSMCA Exhibit No. 11 - Capital structure and cost of capital. If a utility chooses the option to recover the cost of the DSM programs through base rates by including an earning on the balance of the amortized amounts of DSM program costs, this exhibit shall calculate the following information for the most recently completed 12-month period ending June 30:
(I)	The utility’s capital structure for jurisdictional gas operations;
(II)	The utility’s cost of long-term debt and preferred equity;
(III)	The utility’s cost of common equity; and
(IV)	The utility’s weighted average cost of capital.
4759.	Bill Itemization.
Consistent with rule 4406, a utility shall provide itemized gas cost information with gas DSM costs to all customers commencing with the first complete billing cycle in which the new rates are in effect.
4760.	Gas DSM Bonus (G-DSM Bonus) Applications.
The Commission shall review each report submitted and shall determine the level of bonus, if any, that the gas utility is eligible to collect at the request of the utility and on the basis of the information included in the report. The Commission's determination shall be made within three months after receiving the report. Any such bonus shall be authorized as a supplement to the DSMCA cost adjustment mechanism shall be applied over a twelve-month period after approval of the bonus.  A bonus awarded for programs directed at residential customers is to be collected from residential customers only and a bonus awarded for programs directed at nonresidential customers is to be collected from nonresidential customers only.  A utility that implements a new DSM program in phases shall be eligible to receive a bonus under the bonus structure adopted pursuant to paragraph (d) of this subsection during its phase-in period.   
(a)	G-DSM bonus filing requirements.  The utility shall file its annual report to the Commission on or before October 1 of each year.  The utility may request a bonus not to exceed the lower of 25 percent of the expenditures or 20 percent of the net economic benefits of the DSM programs.  The bonus, as modified and authorized by the Commission, shall not count against a gas utility’s authorized rate of return or be considered as net operating earnings in rate proceedings.  
(b)	Contents of G-DSM bonus filing. In the G-DSM bonus filing, the utility shall submit to the Commission the following, at a minimum:
(I)	Documented expenditures on DSM programs for the current G-DSMCA period.
(II)	Gas savings and the techniques used to estimate these gas savings for the current G-DSMCA period.  
(III)	Estimated cost-effectiveness of program expenditures for the current G-DSMCA period in terms of the amount of gas saved per unit of program expenditures.
(IV)	Actual gas savings and the techniques used to calculate these gas savings for the prior G-DSMCA period.  The utility shall explain whether the actual gas savings are validated through the measurement and verification process, pursuant to rule 4755.
(V)	Actual cost-effectiveness of program expenditures for the prior G-DSMCA period in terms of the amount of gas saved per unit of program expenditures.  The utility shall explain whether the actual cost effectiveness of program expenditures is validated through the measurement and verification process, pursuant to rule 4755.
(VI)	Proposed tariffs containing rates to collect the bonus over 12 months.
(c)	Commission procedures for processing filings.  Upon receipt of a G-DSM bonus application, the Commission shall assign a docket number and shall review the submittal for completeness as well as for substance, if a request for bonus is made by a utility. The Commission shall entertain interventions by interested parties, require the oral testimony and the filing of exhibits, and permit expedited discovery, and hold a hearing, as necessary. The Commission shall render a decision approving or disapproving the request for bonus within three months after receiving the G-DSM bonus filing.
(d)	Determination of G-DSM bonus.  A utility may receive a bonus for its performance on meeting or exceeding its goal to promote energy efficiency.  Except during a phase-in period, a utility shall not be eligible for a bonus unless it spends the lower of at least 90 percent of its DSM program expenditure target or one-half of one percent of a utility's base rate revenues from its sales service customers in the year prior to setting such targets.  A utility can request and the Commission may award an amount of bonus for meeting or exceeding the utility’s DSM Savings Target under the tier structure as follows:

Percent of Program Savings Target	Bonus as Percent of DSM Program Expenditure	Bonus as Percent of DSM Net Economic Benefit	
< 100	Not Eligible	Not Eligible	
100 – 120	5	5	
121 – 140	10	10	
141 – 160	15	15	
161 – 200	20	20	
> 200	25	N/A	
(e)	A bonus shall not exceed the lower of 25 percent of DSM program expenditure or 20 percent of net economic benefit.
(f)	Accounting for G-DSM bonus.  Accounting for G-DSM bonus shall follow what has been prescribed for G-DSMCA costs, specifically in regard to interest on over- and under- recovery.  A separate sub-account in Account No. 186 shall be created for any deferred G-DSM bonus amount. 
(g)	Prudence review and adjustment of G-DSM bonus.  If the Commission finds that the actual performance as measured by percent of DSM program savings target pursuant to measurement and verification in rule 4755 differs from the estimated performance, an adjustment shall be made to the amount of G-DSM bonus award.  Any true-up in G-DSM bonus will be implemented on a prospective basis. 
*	*	*
[signifies omission of unaffected rules]