Report to the Legislative Assembly

Electric and Natural Gas Company Rate Impacts to Meet 2020 Greenhouse Gas Emission Reduction Goals Report to the Legislative Assembly Presented to: Senate Environment and Natural Resources Committee Prepared by: Public Utility Commission of Oregon November 1, 2012

Executive Summary In 2007, the Oregon Legislature passed HB 3543 which establishes greenhouse gas emission reduction goals for the state including greenhouse gas levels that are 10 percent less than 1990 levels by the year 2020. In 2009, the Legislature passed SB 101 which requires the Public Utility Commission of Oregon to report to the Legislature before November 1 of each evennumbered year on the estimated rate impacts for Oregon s regulated electric and natural gas companies from meeting greenhouse gas emission reduction goals in 2020. The emission reduction goals are: Reduce greenhouse gas emissions 10 percent below 1990 levels by 2020 Reduce greenhouse gas emissions 15 percent below 2005 levels by 2020 Electric Company Reductions and Rate Impacts Greenhouse gases are emitted from the burning of fossil fuels (coal and natural gas) to generate electricity to supply the Oregon customers of Idaho Power Company (Idaho Power), PacifiCorp and Portland General Electric Company (PGE). Idaho Power, PacifiCorp and PGE, for the purposes of this report, each identified actions they could take to achieve the greenhouse gas emissions reduction goals. To meet the goal to reduce greenhouse gas emissions 10 percent below 1990 levels by 2020: Idaho Power would have to reduce its greenhouse gas emissions in 2020 by two percent from the level projected in its current integrated resource plan (IRP). Idaho Power assumes that it would meet that emissions goal by curtailing coal fired generation. Idaho Power s estimated electricity rates in 2020 would be about 0.1 percent higher than current rates. PacifiCorp would have to reduce its greenhouse gas emissions in 2020 by 23 percent from the level projected in its most recent IRP. PacifiCorp assumes that it would have to reduce generation from its coal fired plants and add significant amounts of renewable resources, natural gas fired resources, energy conservation, and demand response resources. PacifiCorp s estimated electricity rates in 2020 would be eight percent higher than current rates. PGE would have to reduce its greenhouse gas emissions in 2020 by 54 percent from the level projected in its current IRP. To reduce emissions, in addition to the planned shutdown of its Boardman coal fired plant, PGE assumes that it would have to shut down its Colstrip coal fired power plant and replace the associated generation with renewable resources, among other actions. Following this course of action, PGE s estimated electricity rates in 2020 would be 34 percent higher than current rates. Executive Summary November 1, 2012 Page i

To meet the goal to reduce greenhouse gas emissions 15 percent below 2005 levels by 2020: PacifiCorp would have to reduce its greenhouse gas emissions in 2020 by 11percent from its projected IRP level. PacifiCorp assumes that it would reduce generation from its coal fired plants and add natural gas fired resources, energy conservation, and some renewable resources. PacifiCorp s electricity rates in 2020 would be four percent higher than current rates. PGE would have to reduce its greenhouse gas emissions in 2020 by 20 percent from the projected IRP level. PGE assumes it would achieve this goal by, in addition to the planned shutdown of its Boardman coal fired plant, shutting down its Colstrip coal fired power plant and replacing the associated generation with a mix of natural gas and renewable resources, among other actions. PGE s electricity rates would be an estimated eight to 14 percent higher than current rates. Natural Gas Company Reductions and Rate Impacts The greenhouse gas emissions attributable to Oregon s natural gas companies Avista Utilities (Avista), Cascade Natural Gas Corporation (Cascade), and Northwest Natural Gas Company (NW Natural) stem largely from distribution system and gas equipment methane leaks, but also include company facility energy usage and operation of company fleet vehicles. These emissions do not include the emissions from burning natural gas directly in homes and businesses, and are small in comparison to the emissions from direct burning of natural gas. Avista, Cascade, and NW Natural, for the purposes of this report, each identified actions they could take to achieve the greenhouse gas emissions reduction goals. The three Natural Gas Company estimate each would have to reduce its 2020 emissions by 10 percent to reach the 10 percent less than 1990 goal and 15 percent to reach the 15 percent less than 2005 goal. To meet the greenhouse gas emissions reduction goals the estimated rate increase is significantly less than one percent for each of the three natural Gas Companies. Executive Summary November 1, 2012 Page ii

Electric and Natural Gas Company Rate Impacts to Meet 2020 Greenhouse Gas Emission Reduction Goals In 2007, the Oregon Legislature passed HB 3543 which establishes greenhouse gas emission reduction goals for the state including greenhouse gas levels that are 10 percent less than 1990 levels by the year 2020. In 2009, the Legislature passed SB 101 which requires the Public Utility Commission of Oregon to report to the Legislature before November 1 of each evennumbered year on the estimated rate impacts for Oregon s regulated electric and natural gas companies from meeting greenhouse gas emission reduction goals in 2020. The emission reduction goals are: Reduce greenhouse gas emissions 10 percent below 1990 levels by 2020. Reduce greenhouse gas emissions 15 percent below 2005 levels by 2020. 1. Introduction. a. Basics The term greenhouse gas is defined in ORS 468A.210 as meaning any gas that contributes to anthropogenic (human caused) global warming including, but not limited to, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride. As a result, carbon dioxide is one of a number of greenhouse gases. Direct comparison of gaseous emissions other than carbon dioxide is provided by translating those emissions into carbon dioxide equivalents using global warming potentials. Global warming potentials are published by the Intergovernmental Panel on Climate Change. For the purposes of this report the terms carbon, greenhouse gas, carbon dioxide, and carbon dioxide equivalent are used synonymously. b. Assumptions The greenhouse gas (GHG) emission reduction goals are assumed in this rate impact estimate to be uniformly applied as a percent across the electric companies and natural gas companies. Because the cost per ton of GHG emission reduction may not be uniform between the companies this assumption may not be the most economical for the ratepayers as a whole. This assumption may be revised for future reports. Related to natural gas companies, the GHG emissions reduction goals are interpreted as applying to GHG emissions from their operations and facilities. This interpretation may be revised for future reports. The PUC prepared this report based on modeling and analysis performed by the electric and natural gas companies regulated by the PUC. The PUC reviewed the information provided by the companies to evaluate the reasonableness of the modeling and analysis. Specifically, Idaho Power Company (Idaho Power), PacifiCorp, Portland General Electric Company (PGE), Avista Utilities (Avista), Cascade Natural Gas Corporation (Cascade), and Northwest Natural Gas Company (NW Natural), provided the following information to support preparation of this report: November 1, 2012 Page 1

Description of the actions the company could take to achieve the GHG emissions reduction goals. Estimated GHG emissions for 1990, 2005 and for the 2020 base case. Cumulative and year-by-year rate impacts to customers associated with reaching the 2020 emissions reduction goals. Further the companies were requested to utilize the following assumptions in their work: Integrated Resource Plan base case and compliance case resource portfolios comprised of generating technologies that are commercially and financially viable. Base the analysis on attaining the GHG emission reduction goals by January 1, 2020. For rate impact estimation compare the portfolio which meets the GHG emission reduction goal (compliance portfolio) to the integrated resource plan (IRP) preferred portfolio. Calculate the rate impacts as a percent change in a manner similar to: (Compliance NPVRR-Preferred NPVRR)/Current NPVRR. NPVRR is net present value of revenue requirements, including all generation, distribution, transmission, customer service, sales, and administrative and general costs. For electricity supplied through net market purchases, standard offer sales, and electricity service suppliers, utilize 900 pounds carbon dioxide per megawatt-hour (loosely based on USEPA AP-42 for natural gas combustion), unless a different source and environmental impact can be demonstrated. Use the price per ton of CO2 emissions assumed in preparation of the most recent IRP. Use current resource costs, including the various incentives. The information received from the electric and natural gas companies was reviewed by the PUC for consistency and reasonableness. The information was then summarized and incorporated into this report. The information received from the companies is included in Appendix A. Lastly, the electric and natural gas companies were provided an opportunity to verify data inputs in the draft version of this report. Public comment on the draft final report was received at a PUC public hearing on October 23, 2012. 2. Idaho Power Company (Idaho Power) Idaho Power s Preferred Portfolio identified in its 2011 IRP is expected to produce GHG emissions approximately eight percent below 1990 emissions levels and also approximately 13 percent below 2005 emissions levels, without any modifications to the planned resource November 1, 2012 Page 2

portfolio. In order to reach the Oregon emissions reduction goal for 2020, the Company would need to curtail some of its coal-fueled generation during times that additional surplus sales would otherwise be made. This curtailment would occur during the month of April, when loads would historically be low and excess coal-fueled generation would exist. By meeting the 1990-based goal, Idaho Power then also would meet the 2005-based goal. Idaho Power s approach to reach the GHG emission reduction goal through curtailments of coal-fueled generation would not avoid the need for additional resources in the long-run. As loads continue to grow beyond 2020, Idaho Power s preferred portfolio for the year s 2021-2030 adds the following renewable resources in the form of geothermal, a solar power tower and small hydro as well as several gas fueled resources. Therefore, customer rates would likely receive upward pressure beyond 2020 as Idaho Power makes additional investments to maintain the emissions reduction goals. The resulting increase in rates beyond 2020 have not been quantified in this report. a. Analysis Methodology To estimate the rate impact for meeting the greenhouse gas reduction goals, Idaho Power s 2011 IRP Preferred Portfolio was used as the starting point. This is a reasonable starting point because the Company s Preferred Portfolio nearly meets the GHG emissions reduction goals without additional action. The Company then determined that GHG emissions from coal-fueled generation for surplus energy sales in April is estimated to be larger than the additional emissions reduction to meet the goal. As a result, coalfueled energy generation for surplus sales could be reduced to meet the GHG emissions reduction goal. The Company then calculated the total expected cost to customers as the difference between the value of the surplus sales reduction and the savings from coal-fueled generation curtailment. To quantify the value of the surplus sales reduction the Company calculated the additional amount of greenhouse gas emission reduction needed to meet the 1990-based and 2005-based reduction goals, and the associated generation reduction. The reduced generation quantity was then multiplied by the heavy load hour market electricity price in April to arrive at the value of the surplus sales reduction. The heavy load hour market electricity price was quantified using historical forward prices curves for 2020. To quantify the savings from coal generation curtailment, the generation quantity reduction necessary to reach the emission reduction goals was multiplied by the cost to operate the Jim Bridger Units 2 and 3. Selection of the Jim Bridger Units 2 and 3 for this calculation was arbitrary while still being reflective of the cost savings for coalfueled generation curtailment. b. Greenhouse Gas Emissions Idaho Power estimates its Oregon allocated GHG emissions for 1990 and 2005 were 0.32 million tonnes carbon (319,176 tonnes) and 0.34 million tonnes carbon (338,866 tonnes), respectively. Idaho Power estimates its Oregon allocated GHG emissions in 2020 would be 0.29 million tonnes carbon (293,580 tonnes) for its 2011 IRP Preferred Portfolio. These estimates are based on system-wide 1990 CO2 emissions of approximately 6.89 million tonnes carbon (7,598,952 tons), 2005 CO2 emissions of approximately 7.32 million tonnes carbon (8,067,721 tons), and 4.63 percent allocation to Oregon (allocation calculated using energy sales data in the 2011 Oregon Utility Statistics published by the November 1, 2012 Page 3

PUC). Idaho Power estimates its GHG emissions in 2020 would be approximately 6.34 million tonnes carbon (6,989,568 tons) for its Preferred Portfolio. Applying the GHG emissions reduction goals for 2020 results in allowable Oregon allocated GHG emissions for Idaho Power of 0.29 million tonnes carbon (287,258 tonnes) to meet the 10 percent below 1990 goal and 0.29 million tonnes carbon (288,036 tonnes) to meet the 15 percent below 2005 goal. Reaching the 1990 less 10 percent goal requires a two percent reduction in emissions from the Preferred Portfolio while achieving the 2005 less 15 percent goal also requires a two percent reduction. c. Estimated Rate Impacts 3. PacifiCorp To develop an estimate of the rate impact for meeting the GHG reduction goals Idaho Power prepared an analysis that calculated the difference between the value of a surplus sales reduction and the savings from coal-fueled generation curtailment. This difference was identified as the total expected cost to customers. The generation resource build out is as identified in the Company s 2011 IRP preferred portfolio. The total loss in surplus sales is quantified at $8.776 million. Because coal-fueled generation was curtailed, the savings related to not running the coal-fueled plants equated to $7.125 million. The total expected cost to customers is the difference between the surplus sales and the savings attributed to coal curtailment, which was quantified at $1.652 million. This analysis was also performed for the 2005-based emission reduction goal, which was quantified at $1.444 million. The resulting estimated Oregon customer rate increase is 0.11 percent and 0.09 percent for the 1990-based and 2005-based GHG emission reduction goals respectively. To reach the goal of reducing 2020 GHG emissions to 10 percent less than they were in 1990 or 15 percent less than the 2005 emissions, PacifiCorp assumes reducing generation from coal fired plants on a system-wide basis and adding demand-side management programs to meet load requirements and capacity planning needs. As loads continue to grow beyond 2020, PacifiCorp would have to add renewable resources to maintain its coal fired generation strategy, and to comply with the 2050 GHG emissions reduction goal. As a result, customer rates would likely receive upward pressure beyond 2020. The resulting increase in rates beyond 2020 have not been quantified in this report. a. Analysis Methodology PacifiCorp s overall approach for the estimation of rate impacts was to use its IRP models to develop resource portfolios that result in the targeted reductions in GHG emissions. In addition to specifying the resource portfolios, its System Optimizer model determined portfolio costs that were fed into a full revenue requirements model for calculation of the rate impacts. For the base portfolio to which the GHG emission reduction goal portfolios are compared, PacifiCorp used a modified version of its Preferred Portfolio from the Company s 2011 Integrated Resource Plan. PacifiCorp modified both the base portfolio and C02 emission reduction portfolios to reflect coal plant investment assumptions incorporated in recent state regulatory filings, including November 1, 2012 Page 4

retiring Carbon Units 1 and 2 in Utah in 2015, and converting Naughton Unit 3 in Wyoming in 2015 to burn natural gas. The emission reduction assumptions do not anticipate other coal plant retirements during the 10-year period covered by this study or the acquisition of resources that are not currently commercially or financially available. To account for market price and load forecasts used for the study, the System Optimizer model was allowed to optimize selections of demand side management (DSM) and firm market purchases for each of the three portfolios. To meet the 10 percent below1990 GHG emissions reduction goal an incremental 252 MW of DSM resources are assumed to be added. To meet the 15 percent below 2005 GHG emissions reduction goal an incremental 99 MW of DSM resources are added to company s resource mix. Approximately 1,600 MW of incremental natural gas fired resources and 450 MW of wind resources are assumed in all three portfolios. Critical assumptions for this rate impact study are as follows: GHG emission goals and resource portfolio costs are modeled on a PacifiCorp system-wide basis with costs allocated to Oregon based on the current Multi-state Protocol; Energy and demand growth is offset by new natural gas fired generation as well as energy efficiency and load control programs; Oregon or some other state will allow incremental natural gas generation to be built even though such incremental generation may increase GHG emissions in that state; The option to reduce GHG emissions during the study period by purchasing zero or low-emissions energy in the wholesale market is not available because any such energy will be needed by the owner/contracting party to reduce their own emissions; PacifiCorp will not be able to make wholesale sales from thermal generation since potential buyers must also reduce emissions, and PacifiCorp s natural gas fired generation would be used to offset reduced coal fired generation; and PacifiCorp must continue to meet its current 13 percent capacity planning reserve margin target. b. Greenhouse Gas Emissions As mentioned above, PacifiCorp assumes reducing generation from coal fired plants on a system-wide basis and adding demand-side management resources. This strategy is anticipated to meet both the 1990 less 10 percent and the 2005 less 15 percent GHG emission reduction goals in 2020. PacifiCorp estimates its Oregon allocated GHG emissions for 1990 and 2005 were 10.96 million tonnes carbon and 13.40 million tonnes carbon, respectively. These estimates are based on system-wide 1990 CO2 emissions of approximately 45.25 million tonnes carbon (49,900,000 tons), 2005 CO2 emissions of approximately 55.28 million tonnes carbon (60,940,000 tons), and 24.23 percent allocation to Oregon (allocation calculated using November 1, 2012 Page 5

energy sales data in the 2011 Oregon Utility Statistics published by the PUC). PacifiCorp estimates its Oregon allocated GHG emissions in 2020 would be approximately 12.84 million tonnes carbon (58,399,000 tons system-wide) for its Preferred Portfolio. Applying the GHG emissions reduction goals for 2020 results in allowable Oregon allocated GHG emissions for PacifiCorp of 9.87 million tonnes carbon to meet the 10 percent off 1990 goal and 11.39 million tonnes carbon to meet the 15 percent off 2005 goal. Reaching the 1990 less 10 percent goal requires a 23 percent reduction in emissions from the Preferred Portfolio while achieving the 2005 less 15 percent goal requires an 11 percent reduction. c. Estimated Rate Impacts The estimated rate impacts for the two GHG emissions reduction scenarios: Scenario 1 (10 percent less than 1990 goal); and Scenario 2 (15 percent less than 2005 goal) utilize the full revenue requirements in the baseline forecast prepared for the 2012 Business Plan. The estimated rate impacts also include the Oregon system generation factors from the 2012 Business Plan. The estimated rate impact on PacifiCorp s Oregon rate payers for achieving the GHG emissions reduction goals is an eight percent increase to achieve the 1990 less 10 percent goal, and a four percent increase to attain the 2005 less 15 percent goal. 4. Portland General Electric (PGE) PGE states that any forecast of rate impacts eight years from now to reach a given policy goal by 2020 is contingent on many assumptions, as well as uncertainties about future power supply options and costs later in this decade. Accordingly, PGE states that it is important to recognize that the potential range of variability associated with such forecasts can be significant. Below are additional PGE observations, important practical limitations, and qualifications regarding the rate impact estimate. The portfolios modeled for purposes of this report are constructed with one objective in mind - meeting the greenhouse gas reduction targets described in OAR 860-085-0050 - and do not fully take into account other important factors that must be considered, such as resource diversity, system reliability, and customer affordability. The total price impact to customers should also consider the cost of existing and expected complementary efforts which are already embedded in PGE's 2020 costs, such as RPS compliance and expected federal cap and trade compliance. All contemplated portfolios to reach either the 1990 or 2005 baseline require discontinuation of Boardman coal-fired operations by the end of 2019, one year sooner than specified by the BART IIII Boardman 2020 plan approved by the Oregon Environmental Quality Commission, Oregon Public Utility Commission, and EPA. The higher rate impact for this accelerated Boardman coal curtailment is included in this assessment; however, PGE notes that the cessation of coal-fired operations sooner than 2020 would likely require additional regulatory approvals. To reach both the 10 percent below 1990 and 15 percent below 2005 goals, it is necessary to curtail receipt of power from PGE's 20 percent ownership share in Colstrip units 3 and 4. For November 1, 2012 Page 6

purposes of this assessment, PGE assumed an accelerated recovery of our remaining investment in Colstrip. However, PGE notes that, as a 20 percent owner, it might have little ability to actually curtail production of coal-fired generation at Colstrip. In addition, it is important to recognize that accomplishment of the GHG emissions reduction goals will require a significant change to the electric system. Large changes to the electric system may cause significant unforeseen operational issues requiring significant additional capital expenditures thereby significantly increasing the impact to customer rates. In its preferred portfolio PGE anticipates the shutdown of its Boardman coal fired plant by December 31, 2020. To meet the GHG emissions reduction goals, PGE assumes all its coal fired plants (Boardman and Colstrip) are shut down on December 31, 2019. For modeling purposes, any residual fixed revenue requirement is discounted back and recovered in 2019. Generating resources to replace Boardman and Colstrip are added on January 1, 2020. PGE modeled three alternate replacement portfolios: For the 1990 less 10 Percent Goal: Oregon CO2 Goal Portfolio 1: All coal is replaced with 2,159 MW of Pacific Northwest wind and 568 MW of additional simple cycle combustion turbines (SCCT)*. * It should be noted that current modeling capabilities model capacity demands as averages across the delivery hour. However, actual operations require additional dynamic capacity to provide for intra-hour operating requirements such as contingency reserves, load following and regulation. For the 2005 less 15 Percent Goal: Oregon CO2 Goal Portfolio 2: All coal is replaced with 716 MW of CCCT. Oregon CO2 Goal Portfolio 3: All coal is replaced with 441 MW of CCCT, 566 MW of wind, and 207 MW of SCCT. These replacement portfolios rely on existing technology. However, technical and financial implementation of these resource strategies could prove challenging because of the magnitude and type of the investments involved. In the analysis performed to support this report, maintaining compliance with the GHG emissions reduction goals beyond 2020 presents a significant challenge. For example, assuming a portfolio meets the 2020 goal, then after 2020 all new load growth (net of energy efficiency) will have to be met with non-emitting renewable resources. Thus, while it will be challenging to meet the 2020 goals, maintaining the goals will also be difficult. a. Analysis Methodology PGE s approach for the estimation of rate impacts was to develop IRP resource portfolios that result in the required reductions in GHG emissions. Once developed, these portfolios were run through PGE's IRP dispatch model to calculate total emissions, as well as portfolio costs for the calculation of rate impact measures. For the base portfolio to which November 1, 2012 Page 7

the emission target portfolios are compared, PGE used their 2009 IRP Preferred Portfolio No. 18, BART III (2009 IRP Reply Comments, page 10, portfolio 18, PGE 2020 (BART III) ). Specific modeling assumptions include: The PGE 2009 IRP preferred portfolio assumes that the Boardman plant runs through December 31, 2020. It also assumes that the Colstrip plant is fully depreciated by 2024, but continues to operate. All predictable costs/impacts related to the assumed replacement portfolio (including accruals for eventual decommissioning costs) are included. Cost assumptions are based on Chapter 7.7 of the 2009 IRP and as updated in Chapter 2 of the 2009 IRP Update. CO2 emissions prices are assumed to be $27/ton real levelized in 2012 dollars starting in 2017. See 2009 IRP, Chapter 6, and 2009 IRP Update, page 32, for more detail. The rate impact calculation for a given year, to be consistent with presenting yearly rate impacts, is as follows: (Goal Portfolio Revenue Requirement in that year - Preferred Portfolio Revenue Requirement in that year) / Current Revenue Requirement with Load Growth to that year. There are numerous other assumptions and factors considered by PGE in its analysis. These are discussed in its June 29, 2012 letter included in the Appendix. b. Greenhouse Gas Emissions PGE estimates its GHG emissions for 1990 and 2005 were 4.20 million tonnes carbon and 7.72 million tonnes carbon, respectively. PGE estimates its GHG emissions in 2020 would be 8.16 million tonnes carbon for its Preferred Portfolio (BART III). Applying the GHG emissions reduction goals for 2020 results in allowable GHG emissions for PGE of 3.78 million tonnes carbon to meet the 10 percent below 1990 goal and 6.56 million tonnes carbon to meet the 15 percent below 2005 goal. Reaching the 1990 less 10 percent goal requires a 54 percent reduction in emissions from the Preferred Portfolio (BART III) while achieving the 2005 less 15 percent goal requires a 20 percent reduction. The modeled replacement portfolios all meet the 2005 less 15 percent emission reduction goals in 2020, while only the all-wind portfolio meets the 1990 less 10 percent goal. The 1990 less 10 percent all-wind portfolio is estimated to provide emissions of 3.78 million tonnes carbon, a 10 percent reduction in GHG emissions. The 2005 less 15 percent gas portfolio is estimated to result in emissions of 5.89 million tonnes carbon, a 24 percent reduction of GHG emissions. Lastly, the 2005 less 15 percent gas and wind portfolio is estimated to produce emissions of 5.33 million tonnes carbon, for a 31 percent reduction. November 1, 2012 Page 8

c. Estimated Rate Impacts In PGE's case, the 2005 less 15 percent goal is clearly more actionable than a 1990 less 10 percent goal. When looking at the estimated rate impacts, note that these are incremental increases due solely to actions taken to reach the 2020 C02 policy goal that are above and beyond complementary actions underway or planned, the costs for which could properly be attributed to reaching the GHG reduction goal. The incremental rate impacts are computed relative to a base revenue requirement per PGE s Final 2012 AUT, filed 11/15/11, with assumed load growth thereafter. Further, rate impacts are relative to PGE s 2020 (BART III) proposal. Note that the incremental resource actions occur over the 2019-2020 period. As a result, there are very minimal or no incremental rate impacts prior to 2019. In addition, the total rate impact to customers is not fully reflected in the analysis. The cost impacts presented are for replacement of current coal generation with new gas and/or wind generation. They do not consider additional costs that may be necessary for flexible generation requirements, associated fuel storage, or new transmission due to additional variable generation. The estimated rate impact on PGE s customers of achieving the 1990 less 10 percent GHG emissions reduction goal is a 34 percent increase. The estimated rate impact of attaining the 2005 less 15 percent goal assuming the gas replacement portfolio is an eight percent rate increase. The estimated rate impact of attaining this goal assuming the gas and wind replacement portfolio is a 14 percent increase. 5. Natural Gas Companies As discussed above, the GHG emissions reduction goals are interpreted as applying to GHG emissions from the natural gas company operations and facilities. The GHG emissions attributable to Oregon s natural gas companies stem largely from distribution system and gas equipment methane leaks, but also include company facility energy usage and operation of company fleet vehicles. These emissions do not include the emissions from burning natural gas directly in homes and businesses, and are small in comparison to the emissions from that direct burning of natural gas. The IRP process for natural gas companies does not directly or specifically evaluate operations and facilities as they relate to GHG emissions. As a result, the rate impact analysis in this report for natural gas companies does not utilize IRP modeling but rather analysis prepared specifically for this report. Maintaining compliance with the 2020 GHG emissions reduction goals and attaining the 2050 GHG emissions goals would require the natural gas companies to annually purchase GHG emission offsets (permits) to cover the increment of emissions that could not be reduced through improvements, and to cover any new emissions reductions associated with either customer or company growth. The estimated rate impact associated with this on-going purchase of offsets is estimated to be small. November 1, 2012 Page 9

Common to All Natural Gas Companies a. Analysis Methodology GHG emissions from company operations and facilities includes those resulting from natural gas usage for space and water heating, natural gas usage for operations including compressors, fugitive methane emissions from operations, and the operation of fleet vehicles to service customers. Reductions in GHG emissions are available through improving the efficiency of facility energy use and converting fleet vehicles to run on compressed natural gas (CNG). Fugitive methane emissions associated with line losses can be reduced by replacing and improving distribution pipelines. The natural gas companies preliminarily evaluated these sources of GHG emissions to identify potential operations and facility improvements that could result in emissions reductions. The improvements were then evaluated for feasibility and estimated emissions reductions before progressing to the rate impact estimation process. b. Greenhouse Gas Emissions GHG emissions from natural gas company operations and facilities includes those resulting from distribution system chronic leaks, meters, regulators, and mishaps; natural gas combustion for space conditioning, water heating, and company equipment/appliances; and natural gas usage for back-up electricity generation. However, natural gas companies have few opportunities for reducing their company operation and facility emissions because distribution systems are efficient with few line losses, leaving only reductions through fleet and facility changes. Because of this, compliance with the 2020 goals is expected to require a combination of operations and facility improvements, and the purchase of GHG emission offsets. c. Estimated Rate Impacts Avista Utilities To develop an estimate of the rate impact for meeting the GHG emissions reduction goals the natural gas companies prepared conceptual level cost estimates for the feasible operation and facility improvements identified. The natural gas companies provided these estimated costs with the understanding that the analyses on which these estimates are based incorporate numerous assumptions about uncertain future events, any of which may prove inaccurate. Avista does not have historical energy usage information or fuel consumption information for its fleet vehicles available in order to calculate its 1990 and 2005 GHG emissions. Therefore, for the purposes of this report, the Company used the average emissions from 2009 through 2011 as a proxy for both its 1990 and 2005 emissions levels. The Company finds this to be a reasonable and conservative assumption for the following reasons: November 1, 2012 Page 10

The Company has the same number of overall office and operational facilities, however several of the facilities have had energy efficiency upgrades since 1990 and 2005, and have had reduced staffing, particularly as it relates to Contact/Call Center operations and meter readers due to a reduction in meter reading with the deployment of Automated Meter Reading (AMR) in 2004. The Company is operating fewer vehicles due to, among other things, a reduction in metering reading with the deployment of AMR as mentioned above. By using an average emissions proxy of 2009-2011, the baseline is likely lower than it was both in 1990 and 2005. As it relates to Avista s estimates of CO2 emissions between 2012 and 2020, the total emissions in the State of Oregon are very low to begin with. While the Company will continue to seek out energy efficiency measures at its office facilities, and seek out less CO2 intensive fleet vehicles (i.e., CNG, Hybrid, etc.), it believes overall emissions between 2012 and 2020 will remain somewhat flat, as any reduced emissions may be offset by increased emissions caused by the Company serving more customers. Avista recently filed its 2012 Natural Gas Integrated Resource Plan, which includes scenarios involving a forecasted cost of CO2 emissions. The Company is planning to use a forecasted cost of CO2 emissions of $14 per tonne beginning in 2022. For calculations of the potential rate impact included below, the Company used a $14 per tonne value for the cost of CO2 emissions. a. Analysis Methodology See description above under Common to All Natural Gas Companies. b. Greenhouse Gas Emissions Avista developed estimates of its GHG emissions from operations and facilities in Oregon. As discussed above, Avista does not have historical energy usage information or fuel consumption information for its fleet vehicles available in order to calculate its 1990 and 2005 GHG emissions. Therefore, for the purposes of this report, the Company used the average emissions in Oregon from 2009 through 2011 as a proxy for its 1990, 2005, and 2020 emissions levels. As a result of the above, Oregon GHG emissions for 1990, 2005, and 2020 for Avista are estimated to be 658 tonnes carbon. Based on the GHG emissions reduction goals, and the discussion above, the allowable Oregon allocated GHG emissions in 2020 for Avista is 592 tonnes carbon for the 1990 less 10 percent goal and 559 tonnes carbon for the 2005 less 15 percent goal. Achieving the 1990 less 10 percent goal requires a 10 percent reduction in emissions from the business as usual operating scenario while achieving the 2005 less 15 percent goal requires a 15 percent reduction. c. Estimated Rate Impacts As discussed above, Avista prepared conceptual level cost estimates for the feasible operation and facility improvements identified. The Oregon customer rate increase to November 1, 2012 Page 11

meet the 10 percent off 1990 goal is estimated to be 0.0007 percent and to meet the 15 percent off 2005 goal is 0.0010 percent. Cascade Natural Gas Corporation Cascade does not have historical energy consumption available for determining its 1990 or 2005 GHG emissions. Therefore, 2011 results are used for determining the 2020 GHG emission reduction goals. Cascade believes emissions related to its fleet and office facilities will remain steady through 2020. The Company does not foresee significant long-term changes in these areas and the Company is mindful to ensure that it makes energy efficient equipment purchases, building retrofits, and new fleet choices. Presumable gained efficiencies could offset the impact of increased operations if, and when, that occurs. Cascade s GHG emission estimates do not include unaccounted for gas which is a measurement reported in a utility s Federal Energy Regulatory Commission (FERC) Form 2. Since this is a commonly filed metric, it is worth noting that it is an accounting tool that is more indicative of metering discrepancies than of fugitive emissions. Fugitive emissions are also not included in this analysis as no methodology for measuring these has been established. The Company is willing to refine future reports to include fugitive emissions if measurement is possible. Cascade does not believe line losses will significantly impact the company s carbon footprint. a. Analysis Methodology See description above under Common to All Natural Gas Companies. b. Greenhouse Gas Emissions Cascade developed estimates of its GHG emissions from system-wide operations and facilities. As discussed above, Cascade does not have historical energy consumption available for determining its 1990 or 2005 GHG emissions. Therefore, 2011 results are used for determining the 2020 GHG emission reduction goals. As a result of the above, Oregon GHG emissions for 1990, 2005, and 2020 for Cascade are estimated to be 172 tonnes carbon. The Oregon GHG emissions are based on an estimate of 703 tonnes carbon system-wide and a 24.47 percent allocation to Oregon (allocation calculated using load estimates from Table 3-5 in the Cascade 2011 IRP). Based on the GHG emissions reduction goals, and the discussion above, the allowable Oregon GHG emissions in 2020 for Cascade is 155 tonnes carbon for the 1990 less 10 percent goal and 146 tonnes carbon for the 2005 less 15 percent goal. Achieving the 1990 less 10 percent goal requires a 10 percent reduction in emissions from the business as usual operating scenario while achieving the 2005 less 15 percent goal requires a 15 percent reduction. c. Estimated Rate Impacts As discussed above, Cascade prepared conceptual level cost estimates for the feasible operation and facility improvements identified. The Oregon customer rate increase to meet the 10 percent off 1990 goal is estimated to be 0.0015 percent and to meet the 15 November 1, 2012 Page 12

percent off 2005 goal is 0.0023 percent. This rate impact estimate was calculated by PUC staff based on the estimated increase in Company revenue requirement derived from the 2011 Statement of Operations, Oregon. Northwest Natural Gas Company NW Natural does not have historical energy consumption data necessary for determining its 1990 or 2005 GHG emissions. For the purposes of this study, NW Natural used the average emissions for 2008 and 2009 as the proxy for both 1990 and 2005. The Company believes this is a reasonable assumption because, although the Company serves more customers than it did in 1990, it has fewer employees. Also, equipment and fleet replacements made since 1990 have resulted in improved energy efficiency. The Company further assumes that its emissions related to its fleet and office facilities will remain steady through 2020. The Company does not foresee significant long term changes in these areas, and is mindful to ensure that it makes energy efficient equipment purchases, building retrofits, and new fleet choices. Presumably gained efficiencies could offset the impact of increased operations, were that to occur. But, as noted previously, the Company s operations have reduced in size in spite of serving more customers. NW Natural s estimated GHG emissions do not include unaccounted for gas which is a measurement reported in a utility s FERC Form 2. Since this is a commonly filed metric, it is worth noting that it is an accounting tool that is more indicative of metering discrepancies than of fugitive emissions. Fugitive emissions are also not included in this analysis as no methodology for measuring these has been established. The Company is willing to refine future reports to include fugitive emissions if measurement is possible. NW Natural does not believe line losses will significantly impact the company s carbon footprint, as NW Natural has replaced most of its steel pipe which is a key contributor to fugitive emissions. This rate impact estimation exercise revealed to the Company that its operational emissions are impacted most by its use of compressors to move gas in and out of storage. When gas prices are volatile, storage gas is used more as a least cost supply side resource. When gas storage usage is up, the Company has more GHG emissions. Recently, due to the influx of shale gas into the market, gas prices have been lower and less volatile. As a result, the Company has used less gas from storage to meet its peak day demand and, therefore, has experienced lower GHG emissions. The Company s 2011 GHG emissions are 55 percent lower than its 1990 and 2005 levels based on the Company s assumptions for historic emissions levels. If the Company s 2011 GHG emissions remain unchanged through 2020, no GHG reductions will be necessary to meet the reduction goals and no cost will be incurred. However, if in 2020, the Company uses more gas storage than it did in its proxy year for 1990 and 2005, then GHG reductions will be necessary in 2020. NW Natural does not intend to include a cost for CO2 emissions in its next IRP since no viable CO2 legislation is currently under consideration. The Company understands that this assumption is consistent with the assumptions in other gas utilities current IRPs. However, in the Company s last acknowledged IRP, the cost of CO2 emissions was forecast to begin in 2014 at a cost of $15 per ton and to escalate at a compound annual November 1, 2012 Page 13

growth rate of 7.8 percent. Under this scenario, the cost of CO2 would be $24 per ton in 2020. If in 2020 gas storage is being used more than it was in 2011, resulting in the Company having higher GHG emissions, NW Natural expects it would have to purchase offsets to meet the standard because the Company has no other appreciable steps it can take to reduce its operational GHG emissions. a. Analysis Methodology See description above under Common to All Natural Gas Companies. Unlike the GHG emission reduction rate impact report submitted in 2010, the Company has not included emissions for electricity use as these are commonly referred to as Scope 2 emissions by the Environmental Protection Agency (EPA) and would likely not be the gas utilities responsibility. In addition, as mentioned above, fugitive methane emissions associated with line losses can be reduced by replacing and improving distribution pipelines. Since NW Natural has replaced most of its steel pipe and is among the nation s leaders in reducing unaccounted for gas, limited opportunity remains to reduce its emissions associated with pipeline losses. b. Greenhouse Gas Emissions NW Natural developed estimates of its GHG emissions from system-wide operations and facilities. As discussed above, NW Natural does not have historical energy consumption data necessary for determining its 1990 or 2005 GHG emissions. For the purposes of this report, NW Natural used the average emissions for 2008 and 2009 as the proxy for both 1990 and 2005. As a result of the above, Oregon GHG emissions for 1990 and 2005 for NW Natural are estimated to be 29,653 tonnes carbon. The estimated Oregon emissions in 2020 is 18,256 tonnes carbon if gas storage use remains as it was in 2011 (business as usual) and 29,781 tonnes carbon if gas storage use returns to what it was pre-2010. All the estimated system-wide GHG emissions are assumed for this report to be in Oregon since nearly 90 percent of NW Natural customers are in Oregon (based on Figures 2.5 and 2.6 in the NW Natural 2011 IRP). Based on the GHG emissions reduction goals, and the discussion above, the allowable GHG emissions in 2020 for NW Natural is 26,688 tonnes carbon for the 1990 less 10 percent goal and 25,333 tonnes carbon for the 2005 less 15 percent goal. The 2020 business as usual GHG emissions estimate is already 46 percent below the 1990-based goal and 39 percent below the 2005-based goal. For the higher 2020 GHG emissions estimate, the Company would need to reduce its emissions by 3,093 tonnes (10 percent) to meet the goal of 10 percent below 1990 levels and it would need to reduce emissions by 4,448 tonnes (15 percent) to meet the goal of 15 percent below 2005. November 1, 2012 Page 14

c. Estimated Rate Impacts As discussed above, NW Natural prepared conceptual level cost estimates for the feasible operation and facility improvements identified. The Oregon customer rate impacts derived using NW Natural s current Oregon revenue requirement of $320 million, and an 89.55 percent Oregon allocation (based on Figures 2.5 and 2.6 in the NW Natural 2011 IRP) are an increase of approximately 0.02 percent for the 1990-based goal and 0.03 percent for the 2005-based goal. November 1, 2012 Page 15

Appendix RE 92 Idaho Power Company June 29, 2012 Draft Report and Power Supply Comparison, and attachment RE 84 PacifiCorp July 13, 2012 Biennial Greenhouse Gas Emissions Rate Impact Report RE 80 Portland General Electric Company June 29, 2012 Cover Letter and enclosures RG 47 Avista Utilities July 18, 2012 Avista 2012 Greenhouse Gas Emissions Report RG 49 Cascade Natural Gas Corporation August 13, 2012 Greenhouse Gas (GHG) Compliance Report RG 46 Northwest Natural Gas Company June 29, 2012 Greenhouse Gas (GHG) Compliance Report Northwest Natural Gas Company August 29, 2012 NWN Revenue Requirement email Appendix November 1, 2012 Page A1