The Colorado legislature enacted H.B. 1037 in 2007, requiring electricity and natural gas investor-owned utilities (IOUs) to engage in demand response and adopt demand-side management (DSM) programs that provide financial incentives for customers to purchase more efficient equipment and use more efficient processes. The law requires these utilities to meet minimum energy and demand savings goals but authorized the Colorado Public Utilities Commission (COPUC) to revise the goals and establish interim savings goals as it deems appropriate.
Electricity Savings Targets (in Gigawatt-Hours (GWh))
COPUC adopted electricity savings goals of 5% of the utility's 2006 peak demand and electricity sales by 2018 for Colorado’s investor-owned electric utilities, Public Service Company of Colorado (d/b/a Xcel Energy) and Colorado Electric Utility Company (d/b/a Black Hills Energy). COPUC set an efficiency target to account for half of the expected increase in demand every year, which meets the goals established by the Colorado legislature. While the statutory goals end in 2018, COPUC extended electricity sales reduction goals through 2020.
The goals established for Xcel Energy in March 2011 were higher than the original goals, beginning with a 1.14% annual reduction in 2012 and increasing each year to a 1.68% annual reduction in 2020. In 2014, the energy saving goals for 2015-2020 were decreased from 2,914 gigawatt-hours (GWh) to 2,400 GWh over the 6-year period, or 400 GWh per year. COPUC reviews programs annually through filings made by each utility as required by the law. The goals established for Black Hills Energy for 2012-2015 in 2012 were similarly larger than the original goals and surpass the statutory goal of a 5% reduction of 2006 electricity sales by 2018. Although Black Hills Energy had already met that statutory goal by 2015, a settlement agreement approved by COPUC established new goals for 2016-2018 that achieve approximately 10% in energy savings over the plan period.
|Savings Target by Utility (GWh)||2012||2013||2014||2015||2016||2017||2018||2019||2020|
|Black Hills Energy||30.9||30.9||22.3||25.0||18.0||19.8||20.6||TBD||TBD|
Demand Reduction Targets (in Megawatts (MW))
COPUC also established demand response goals for Xcel Energy and Black Hills Energy for the following amounts, inclusive of a 65 MW annual reduction from energy efficiency, which are shown in the “Demand Reduction Goals” section below.
|Savings Target by Utility (MW)||2012||2013||2014||2015||2016||2017||2018||2019||2020|
|Black Hills Energy||8.2||8.2||6.3||7.0||5.2||5.6||5.8||TBD||TBD|
H.B. 1037 required the PUC to undertake a rule-making proceeding that would develop expenditure and savings goals, determine cost recovery, and create a financial bonus structure. The law also established that gas utilities must spend at least 0.5% of their previous year’s revenue on DSM programs each year. The law prevents the PUC from assigning financial penalties to gas utilities that fail to meet their energy savings goals but requires utilities to submit annual reports to the PUC. The reports must highlight their program spending, energy savings, and the cost effectiveness of their programs from the previous year. Thus, Colorado does not have required targets for natural gas savings through their programs.
Program Administrator Type
Colorado's investor-owned utilities directly administer the energy efficiency and demand-side management programs intended to meet the standard.
Cost Effectiveness and Program Evaluation
To evaluate the cost effectiveness of its efficiency and demand reduction activities, Colorado utilizes a modified version of the Total Resource Cost test (MTRC) as its primary test for measuring the cost-effectiveness of energy efficiency programs.
While the TRC, one of the five "California tests" from the California Standard Practice Manual, traditionally only values the “monetized” non-energy benefits (i.e. benefits that can be valued directly based on a transparent, agreed-upon price), Colorado’s MTRC includes a 5% “non-energy benefits adder” for gas programs, and 10% for electric programs. In this way, including non-energy benefits in the MTRC is similar to the Societal Cost Test (SCT), which values all costs and benefits associated with DSM programs from the perspective of society as a whole. To judge cost-effectiveness of its natural gas programs, COPUC uses the SCT, and uses a 25% non-energy benefits adder.
Colorado does not specify any other tests on a secondary basis in evaluating electric energy efficiency and DSM programs.
Utility Cost Recovery Provisions (for Investor-Owned Utilities)
While Colorado’s electric IOUs do not have full revenue decoupling, COPUC has allowed them to collect a fixed “disincentive offset” payment plus a performance incentive relative to achieving certain percentages of its annual targets to manage the lost revenue utilities incur associated with these types of programs. Thus, Colorado’s IOUs receive energy efficiency and DSM performance incentives for both its electric and gas programs.
Xcel Energy (Electric)
Xcel Energy receives (on a pre-tax basis) a fixed $5 million “disincentive offset” for achieving 100% of its goals. The table below shows the levels of incentives Xcel can earn.
Xcel also can receive a performance incentive, which provides it with a portion of the net dollar savings achieved by its programs, and tiered relative to its achievement of the annual goals set by COPUC. The performance incentive starts at 5% of the total dollar savings associated with achieving 100% of the utility’s goal each year. The total incentive Xcel may earn, the combined disincentive offset and performance incentive, is capped at $30 million per year.
|Annual Efficiency and DSM Achievement Level||
Performance Incentive (% of Net Economic Benefit)
|100%||$5M||Lesser of 5% or $25M|
|105%||$5M||Lesser of 6% or $25M|
|110%||$5M||Lesser of 7% or $25M|
|115%||$5M||Lesser of 8% or $25M|
|120%||$5M||Lesser of 9% or $25M|
|125% and Above||$5M||Lesser of 10% (and Above) or $25M|
For example, according to its plans, Xcel plans to spend $66 million on its programs in 2015. Hypothetically, if it were to achieve 100% its savings targets at a cost-effectiveness score of 3.0 (thus producing $132 million in net benefits), it would earn: $5 million + $6.6 million (5% of $132 million) = $11.6 million (an 18% pre-tax return).
Black Hills Energy (Electric)
Black Hills Energy also has a similar disincentive offset and performance incentive approach. Black Hills can collect an annual disincentive offset of $150,000 if it achieves 80% of its annual targets, as well as a performance incentive of two-tenths of one percent (2/10th of 1%) for each percentage point by which it exceeds 80% of its annual targets. The total incentive is capped at 20% of Black Hills’ total annual expenditures on efficiency and DSM programs.
|Annual Efficiency and DSM Achievement Level||Amount Exceeding 80% Performance||
"Disincentive Offset" (Pre-Tax)
|85%||5%||$150,000||1% of Net Economic Benefit (Capped at 20% of DSM Budget)|
|90%||10%||$150,000||2% of Net Economic Benefit (Capped at 20% of DSM Budget)|
|95%||15%||$150,000||3% of Net Economic Benefit (Capped at 20% of DSM Budget)|
|100%+||20%||$150,000||4%+ of Net Economic Benefit (Capped at 20% of DSM Budget)|
For example, if Black Hills’ achieved 100% of its 2015 goals at a budget of $5 million and a cost-effectiveness score of 3.0 (producing net avoided cost/”economic” benefits of $10 million), it would earn: $150,000 + $200,000 (4% of $5 million) = $350,000 (approximately a 7% pre-tax return).
The cost of these performance incentives (like all other utility costs) are recovered by both utilities through a Demand Side Management Cost Adjustment (DSMCA) rider on customer bills.
Natural Gas DSM Performance "Bonus"
While there are no out-year natural gas EERS targets in Colorado, Colorado's investor-owned gas utilities can earn a performance bonus comprised of a share of the net avoided costs ("economic benefits") by encouraging cost-effective savings. This bonus has two parts: 1) an "energy factor" and 2) the “savings factor”. The energy factor is the difference between the percentage of the achieved savings and 80%, then multiplied by 50%, while the savings factor is the actual savings (in dekatherms (Dth)) divided by the savings target (also in Dth). The bonus is limited to twenty-five percent of expenditures or twenty percent of the net economic benefits of the DSM programs, whichever amount is lower. Below is an example calculation using both factors, for a hypothetical utility with a gas savings goal of 100,000 Dth, and program performance of 110,000 Dth.
|A||Savings Target (Dth)||100,000|
|B||Actual Savings (Dth)||110,000|
|C||Percentage of Savings Achieved||110%|
|D||Energy Factor (Row C-80%)/2)||15|
|E||Savings Factor (Row B/Row A)||1.1|
|F||Performance Bonus (% of Net Economic Benefits)||16.5|
Special Provisions (Self-Direct Options for Large Customers)
Xcel Energy and Black Hills Energy both offer self-direct options, in which certain customers can use the funds they would pay through the DSMCA to projects of their choosing.
A commercial and industrial customer program is available to Xcel customers who are otherwise barred from participating in other Xcel energy efficiency and DSM programs. Eligible customers must have an aggregated peak load of at least 2 MW in any particular month and aggregate annual energy consumption of at least 10 GWh (10,000,000 kWh). Commercial and industrial customers of Black Hills Energy can participate in its self-direct program if their load is 1 MW in any particular month and they have aggregate annual energy usage of 5,000 MWh (5,000,000 kWh). Customers in both programs receive targeted incentives to spend down their self-directed allocation.
*Examples of non-energy benefits can include, for example, the health or economic development benefits associated with reduced greenhouse gas emissions, or with increased economic development associated with utility bill savings to customers. For a more detailed discussion of non-energy benefits and how they interface with the traditional “California tests” for cost effectiveness, click here.
^Xcel Energy also agreed to 285 MW in demand reduction from programs in which third parties can aggregate demand response impacts.
|Incentive Type:||Energy Efficiency Resource Standard|
|Eligible Renewable/Other Technologies:||Custom/Others pending approval|
|Electric Sales Reduction:||
Statutory Requirement: 5% of 2006 electricity sales by 2018
|Electric Peak Demand Reduction:||
Statutory Requirement: 5% of 2006 peak demand by 2018
|Natural Gas Sales Reduction:||Varies|
|Name:||COPUC Decision No. C11-0442 (Xcel Energy's Requirements)|
|Name:||CRS 40-3.2-101, et seq.|
|Name:||COPUC Decision No. R12-0900 (Black Hills Energy's Goals for 2012-2015)|
|Name:||4 CCR 723-4 (Natural Gas Rules)|
|Name:||COPUC Decision No. C14-0731 (Xcel Energy's Requirements and Shareholder Incentives, 2015-2020)|
|Name:||COPUC Decision No. R15-1292 (Black Hill Energy's Goals for 2016-2018)|
1560 Broadway, Suite 250
Denver CO 80202
This information is sourced from DSIRE; the most comprehensive source of information on incentives and policies that support renewables and energy efficiency in the United States. Established in 1995, DSIRE is operated by the N.C. Clean Energy Technology Center at N.C. State University.
Copyright © 2023 EnergyBot • All rights reserved.
1601 Bryan St Suite 900, Dallas, TX 75201