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2 A LOW OR WESTERN COOPERATI VES 2 - COST ENERGY FUTURE F GMENTS D LE W AUTHORS & ACKNO ACKNOWLEDGMENTS AND AUTHORS Engel Mark Dyson and Alex DISCLOSURE *Authors listed alphabetically. All authors are from The authors gratefully acknowledge the insights and y Rock Mountain Institute unless otherwise noted. perspectives offered by many colleagues representing electric cooperative utilities, financial institutions, CONTACTS developers, regulatory experts, and renewable energy consumer advocates for this report. [email protected] Mark Dyson, [email protected] Alex Engel, RMI has supported and is continuing to support electric cooperative utilities across several states ED CITATION SUGGEST (Texas, Colorado, and New Mexico), including some and Alex Engel Dyson, . A Low Cost Energy - Mark that are members of Tri State Gen eration & - Future for Western Cooperatives: Emerging Transmission Association , by facilitating competitive Opportunities for Cooperative Electric Utilities to scale solar procurement processes for community - Pursue Clean Energy at a Cost Savings to Their projects. While this support has helped RMI Members . Rocky Mountain Institute, 2018. contextualize the landscape of opportunities available - - future - cost - energy competitive procurement to cooperative utilities with cooperatives - western processes, no proprietary information made available to RMI was used in any way in preparing the analysis presented in this report. ABOUT ROCKY MOUNTAIN INSTITUTE forms global energy use trans an independent nonprofit founded in 1982 — Rocky Mountain Institute (RMI) — to create a clean, prosperous, and secure low - carbon future. It engages businesses, communities, based solutions that cost - institutions, and entrepreneurs to accelerate the adoption of market effectively - shift from fossil fuels to e fficiency and renewables. RMI has offices in Basalt and Boulder, Colorado; New York City; Washington, D.C.; and Beijing. O U M N Y T K A C I N O R CARBON FUTURE CREATING A CLEAN, PROSPEROUS, AND SECURE LOW - I N E S T T U I T


4 A LOW 4 -COST ENERGY FUTURE FOR WESTERN COOPERATI VES 1. EXECUTIVE SUMMARY - cost renewable energy pricing in the United States has created unprecedented The emergence of very low - opportunities for utilities currently reliant on high cost, legacy generating assets, particularly in the Mountain West. The drop in renewables pricing i s also casting into doubt the competitiveness and viability of operators that are slow to transition. In this report, as an indicative case study of this broader trend, we examine the cost savings opportunities - renewables price declines have made possibl e for Tri - State Generation & Transmission Association and its - - member co - ops. Specifically, we consider their opportunity to engage in large scale procurement of cost analyze two illustrative effective renewable energy projects, while maintaining system reliability requirements. We power supply portfolios based on publicly available data, and find that procurement of new wind and solar , State’s members through 2030 - savings potential for Tri - $600 million of cost projects represents approximately - fired generation. Scaled adoption of renewable energy by Tri - ued reliance on legacy coal versus contin State could also mitigate risks of revenue loss and cost increases associated with reliance on existing assets for electricity supply, reducing the rate increases unde r a range of risk scenarios by 30% to 60%. The analysis presented in this case study illustrates that immediate collective action between wholesale energy age providers and member co - ops can mitigate risks, identify regionally appropriate solutions, and lever aggregate buying power, enabling an efficient and equitable transition toward a more cost - effective energy supply mix. 2. INTRODUCTION: A R APIDLY CHANGING ENER GY LANDSCAPE Renewable energy resource prices are falling at an unprecedented pace, much m ore quickly than forecasted even a decade ago, and to a level completely unimagined at the time when utilities built much of the legacy generating capacity in the United States. Less than a decade ago, solar and wind projects were expected to remain relati vely high cost resources with only a minor role to play in the grid. However, forecasters and utility - planners were unable to predict the dramatic and sustained price declines alternative technologies, particularly scale solar photovoltaics (PV), h ave experienced (see Figure 1). A common view in official forecasts was utility - that other presently competitive resources, including wind energy and natural gas fired generation, were also - small role likely to continue playing a in the future supply mix, given expectations of future costs that proved to be too high in both cases. O U M N Y T K A C I N O R CREATING A CLEAN, PROSPEROUS, AND SECURE LOW - CARBON FUTURE I N E S T T U I T

5 A LOW OR WESTERN COOPERATI VES 5 - COST ENERGY FUTURE F - scale solar PV costs vs. historic forecast costs Figure 1 : Historic utility $400 $300 $200 2017$/MWh $100 $0 2010 2009 2016 2015 2017 2013 2012 2011 2014 Historic: Lazard 2010: EPIA Upper 2010: EPIA Lower 2011: SunShot Goal 2016: NREL 2015: NREL 2012: Black & Veatch 2017: NREL Given forecasts of high costs for alternatives, many utilities thus continued their historical investment trajectory in coal - fired generation. For example, in 2010 and 2011, when utilities were expanding coal mining operations 2020 solar PV costs of and planning to build new coal - fired gener ating capacity , forecasts suggested 2015 – $100 — significantly higher than the anticipated costs of new coal assets at the time. 240/MWh – ice in the early But in fact, long - term fixed prices available today for new wind and solar projects entering serv 2020s can outcompete just the operating costs of many existing coal assets , let alone the costs to build and run - . This rapid transition has caught many utilities by surprise, and or gas fired generating capacity new coal - thrown into question the future economic viability of legacy generating assets that are no longer necessar ily the cost option for the customers they serve. - least OMICS OF ENERGY SUPP 3. THE SHIFTING ECON LY IN THE MOUNTAIN WEST This paper presents a case study of the changing economic situation for electricity supply, in an area of the limited in their uptake are cost - country where lower alternatives to legacy assets are currently available, but to . In particular, we focus on the opportunities available to cooperative utilities in the Mountain West currently date Association, a nonprofit, member served by Tri owned cooperative which - - State Generation & Transmission op members and, ultimately, over 1 million consumers in provides wholesale power to 43 distribution co - State has historically relied on a mix of owned coal - fired - Colorado, Nebraska, New Mexico, and Wyoming. Tri power plants and contracted renewable and fossil resources to serve member loads and offer nonmember sales. Tri - State’s current energy mix is 30% renewable via purchases . I n June 2018 it announced a procurement - process for new renewable resourc es, but the majority of its capacity and energy come from a fleet of five coal fired power plants built between 1959 and 2006. - average rate increases - than passed along to its lower State’s owned assets have contributed to - Historically, Tri - - use consumers, relative to other utilities in the states served by Tri - end forward State. However, the go operations and maintenance costs of Tri - State’s legacy generator fleet, estimated from public data, a re now O U M N Y T K A C I N O R CARBON FUTURE - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW I N E S T T U I T

6 A LOW OR WESTERN COOPERATI VES 6 COST ENERGY FUTURE F - higher than prevailing prices for new renewables resources. Contracted prices available for new renewable resources, publicized in 2018 as part of competitive procurement processes from regional utilities including Xcel St wind and NV Energy , undercut the production costs of Tri - ate’s coal fleet (see Figure 2). The Energy and solar or better than in peer utilities’ footprints, State’s service territory are generally as good - resources across Tri designed competitive procurement - State in a well - suggesting that similar pricing could also be available to Tri process. State’s coal fleet costs versus regional renewable energy benchmarks Figure 2 : Tri - $100 $90 Fixed Operations & Maintenance Variable Operations & Maintenance $80 Fuel $70 Xcel Wind Xcel Solar $60 $50 $/MWh $40 $30 $20 $10 Escalante Laramie River Station Nucla Springerville Craig (Yampa) $0 1,200 600 500 400 900 200 100 0 1,000 1,100 700 1,300 1,400 1,500 800 1,600 1,700 1,800 300 MW OSTS ARE ASSUMED TO BE CONSTANT IN REAL TERMS. COMPARATOR LI NES FOR XCEL BIDS AR E FOR E XISTING GENERATION C PRICE CONTRACTS WITH NCLUDE ESTIMATED TRA 2023 IN - SERVICE DATES, AND I - NSMISSION AND OTHER INTEGRATION FIXED COSTS. 2 show both estimates of “integration costs” as well as incremental The prices for renewables in Figure State transmission transmission costs to enable connection of wind and solar energy projects into the Tri - - 2015 meta on integration costs found that utilities seldom impose adders of more than $5 per system. A study MWh of wind or solar production when assessing incremental costs of integration, with a median of approximately $3/MWh; recent inte Rocky Mountain Power in grated resource plans by Western utilities (e.g., 2017 ) have cut that estimate to less than $1/MWh, even including costs for incremental coal asset cycling Western and Colorado - specific regions). We estimated transmission costs based (typically less than $1/MWh for Report associated with its Colorado on the incremental transmission included in Xcel Energy’s 2018 120 Day Energy Plan proposal. - for - one replacements for However low their costs, variable renewable resources like solar and wind are not one the reliability services that existing coal assets provide. Rather, wind and solar r esources can most easily act as cost assets and thus a “fuel saver” when they are available, allowing utilities to reduce operating levels of high - marginal cost renewable energy production - avoiding these assets’ marginal production costs by utilizing low i nstead. The marginal production costs of Tri - State’s assets shown in Figure 2 are generally higher than wind O U M N Y T K A C I N O R - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW CARBON FUTURE I N E S T T U I T

7 - A LOW VES 7 OR WESTERN COOPERATI COST ENERGY FUTURE F 27) received by Xcel Energy and NV Energy in 2018, even – 18/MWh) and in line with solar bids ($23 – bids ($11 for transmission expansion and <$1/MWh adder for other when including an estimated $3/MWh adder - State’s coal assets integration costs associated with these variable renewable resources. Thus, by keeping Tri operational but choosing to run them less when wind and solar resources are available, th ere are significant cost savings available. - 4. MEETING RELIABILI RENEWABLES SYSTEM TY IN A HIGHER In any supply mix transition, a utility needs to maintain system reliability in addition to pursuing least - cost resources. In particular, due to the variabil ity of supply from renewable resources, a portfolio approach is necessary to provide the same set of reliability services as existing, dispatchable generating assets. As part of such a portfolio, wind and solar resources can be supplemented with firm, disp atchable capacity, either from existing assets or new - build resources, to maintain system reliability while reaping the benefits of lower production costs. As an illustration of how new assets could provide the same level of resource adequacy services as a n existing power plant, we illustrate below a case study for a typical Tri State coal - fired power plant, - and compare the economics and reliability implications of its business - as - usual operation with scenarios of lower utilization and/or retirement. Figure 3 compares three scenarios to illustrate the economics and technical aspects of a transition to renewable energy on an asset - by - asset level: - fired power plant continues current operation, providing energy and : The coal Business as usual (BAU) • rce adequacy to Tri State’s system. The power plant’s 247 MW of capacity is assumed to run at resou - 51% capacity factor, based on 2017 data. The go - forward costs are dominated by fuel, with a significant contribution from fixed operations and maintenance costs a s well as annualized costs of required environmental compliance upgrades in the future. We do not include any sunk costs (e.g., depreciation) forward operating costs alone in this case are $40/MWh. - in this analysis; the go n of 100 MW of wind and 100 MW of solar PV, procured at median bid Fuel saver : We model the additio • prices released by Xcel plus a $0.60/MWh adder for integration costs from Rocky Mountain Power’s 120 Day 2017 integrated resource plan and a $3/MWh adder for transmission costs (derived from Xcel’s Report), while keeping the coal plant operating and available to provide firm capacity. The wind and - cost operations of solar complement the coal plant by producing lower cost energy, reducing the higher - onal capacity to the system. The go - forward operating costs of the coal plant, while also providing additi the portfolio of resources are $35/MWh. : In this scenario, we assume the plant retires, avoiding all fixed costs as well as operating • Retirement costs. Additional renewable energy (342 MW total) is installed to replace plant energy production, and capacity purchases (167 MW, assumed to be available at pricing levels equivalent to median Xcel prices) es. The provide for any resource adequacy needs that are not met by wind and solar projects themselv forward operating costs at the portfolio level are $32/MWh. go - We have used fixed assumptions for both renewable energy pricing (i.e., no further cost declines) and the legacy generating asset (i.e., no unanticipated cost increases), and we note t hat lower - cost capacity purchases may be available, especially given the rapidly - falling price of battery energy storage. - effectively reducing Peer utilities in the Mountain West in 2018 have announced similar strategies of cost operating hours and/or ret iring legacy coal while meeting resource adequacy and reliability needs with renewables and other resources: announced pl has NV Energy • ans to develop 1 GW of solar and 100 MW of battery energy storage over - the next 25 years. The availability of low cost solar energy contributes to NV Energy’s ability to O U M N Y T K A C I N O R CARBON FUTURE - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW I N E S T T U I T

8 A LOW OR WESTERN COOPERATI VES 8 - COST ENERGY FUTURE F uled retirement economically retire the 127 MW North Valmy coal plant by 2021, ahead of its 2025 sched date. would shut down two legacy coal units Xcel Energy’s 10 years ahead of Colorado Energy Plan proposal • schedule, replacing them with wind, solar, and battery projects, saving Xcel customers $215 million. Under the proposed investment plan, Xcel would source over half of its energy from wind and solar by 2026. Figure 3 nued coal operation versus renewable procurement : Case study of conti Resource adequacy Energy production Cost of delivered energy 350 1,200 $45 $40 300 1,000 Wind Coal Fixed $35 O&M Solar Wind 250 Wind $30 800 Coal Var. Wind Purchases O&M 200 $25 Solar 600 MW Solar Purchases Coal GWh/y $/MWh $20 150 Coal Fixed O&M Coal Coal Wind $15 400 100 Coal Var. Coal Fuel O&M $10 Wind Coal 200 Solar 50 $5 Solar Coal Fuel Solar 0 0 $0 BAU Retirement Fuel saver BAU Fuel saver BAU Retirement Fuel saver Retirement Y COSTS IN 5. AN OPPORTUNITY FO R LOWER ENERGY SUPPL THE MOUNTAIN WEST To assess the total cost savings opportunity available to Tri State members while maintaining reliability, we - f two illustrative portfolios of resources that could be used to meet Tri analyzed the economics o State’s supply - obligations to its members through 2030. We used public data on Tri - State’s owned assets combined with benchmarks from other regional utilities and meta - studies to inf orm portfolio creation and cost estimates. - as - usual scenario , where Tri - State’s owned generating assets continue to run much as We analyzed a business Unit 1 at they did in 2017. We include the currently announced retirement s of the Nucla generating facility and o f expectations the Craig generating facility, and assume that renewables procurement and load growth follow the - State’s 2015 Electricity Resource Plan. We assume that Tri - State is able to purchase firm capacity laid out in Tri and wholesale energ y at prices consistent with its 2017 10 - K filing and regional benchmarks; these make up a small portion of this portfolio. We also analyzed an energy transition scenario where Tri - State moves to procure energy from new wind and solar projects, at prices consistent with the results of recent competitive procurements. We assume a gradual - legacy asset retirement schedule , where c oal fired assets are phased out by 2026, and Tri - State’s existing gas - - State fired assets are used to provide balancing energy to integrate new renewables projects. We assume Tri usual sc - as - procures firm capacity at a much higher level than in the business enario to cover the capacity gap left by coal retirement. Figure 4 illustrates the results of this analysis, in terms of energy served, firm capacity available, and total supply costs. O U M N Y T K A C I N O R CARBON FUTURE CREATING A CLEAN, PROSPEROUS, AND SECURE LOW - I N E S T T U I T

9 A LOW OR WESTERN COOPERATI VES 9 COST ENERGY FUTURE F - s versus new projects Generating asset portfolio mix and costs with legacy asset Figure 4: Energy transition Business as usual 25.0 25.0 Purchases Purchases Solar 20.0 20.0 Solar Wind 15.0 15.0 Wind Coal 10.0 10.0 Coal Energy (TWh) Gas Gas 5.0 5.0 Basin & Basin & WAPA WAPA 0.0 0.0 2020 2018 2020 2018 2024 2030 2028 2026 2024 2022 2030 2028 2026 2022 4.5 4.5 Purchases 4.0 4.0 Solar Wind 3.5 3.5 Peak Peak 3.0 3.0 Purchases 2.5 2.5 Coal Solar Wind 2.0 2.0 Coal 1.5 1.5 Gas Gas Capacity (GW) 1.0 1.0 Basin & Basin & 0.5 0.5 WAPA WAPA 0.0 0.0 2018 2024 2026 2020 2026 2024 2022 2020 2028 2030 2030 2018 2022 2028 $2,00 0 $2,00 0 $1,75 0 $1,75 0 Other Other $1,50 0 $1,50 0 Trans. Purchases Trans. $1,25 0 $1,25 0 RE Purch. Purchases $1,00 0 $1,00 0 RE Purch. Coal $750 $750 Coal $500 $500 Gas Cost ($mm nominal) Gas $250 $250 Basin & Basin & WAPA WAPA $0 $0 2024 2026 2028 2022 2026 2028 2030 2030 2020 2018 2018 2022 2020 2024 POWER COOPERATIVE AN D THE WESTERN AREA P OWER “BASIN & WAPA” INDIC ATES THE POWER PROVI DERS BASIN ELECTRIC . ADMINISTRATION Under the energy transition scenario, Tri State’s members, and the approximately 1 million end - use consumers - value terms between 2018 2030. Through avoiding - they serve, would save approximately $600 million in present – forward fixed costs of running and maintaining legacy assets, and instead - both the operating costs and the go State could lower supply - acity in competitive procurement processes, Tri cost renewables and cap - sourcing low costs by ~12% in 2030 and pass along those savings to its member - owners. reduction Importantly, this opportunity is ripe for action today. The staged of federal tax incentives for renewable energy through 2022 means that, although further cost declines for renewable and other emerging technologies e in the future, near - term procurement of wind and solar can best take advantage of likely (e.g., batteries) ar utilities like current low pricing, low interest rates, and tax incentives. This situation applies even to cooperative pass State that cannot directly take advantage of the tax credits; developers or tax equity investors can - Tri op utility offtakers that sign a power - to co - through those project cost savings purchase agreement (PPA). - ops are already demonstrating the cost - Several regional utilities and other generation and transmission co ategies, in addition to the Xcel and NV Energy examples discussed above. Moreover, effectiveness of similar str O U M N Y T K A C I N O R - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW CARBON FUTURE I N E S T T U I T

10 A LOW VES 10 - COST ENERGY FUTURE F OR WESTERN COOPERATI proposed investment in Pueblo, CO, as part of its Colorado Energy Plan) projects across the region (e.g., Xcel’s are demonstrating that regional investment in renewable energy can create jobs and drive economic growth. - in 2018 • announced serving the Midwest, op Great River Energy (GRE), a generation & transmission co a goal to achieve 50% renewable energy by 2030, after reaching their 25% renewable energy target in - cost source of electricity to 2017, eight years ahe ad of schedule. GRE has identified wind as the least meet its members’ needs, and plans to invest in 500 MW of wind and purchase 200 MW of hydropower from Manitoba Hydro to meet its 2030 goal while keeping rate increases below inflation. A 2017 zero carbon - (PRPA) could achieve a net Platte River Power Authority demonstrated study • and by 2030, using new energy portfolio across Estes Park, Fort Collins, Longmont, and Lovel investment in renewables coupled with coal retirement. This analysis found a price premium of 8% but used pricing inputs sourced prior to the Xcel bidding process in late 2017; PRPA’s assumed prices in – 26% higher 10 2030 were than Xcel’s median bids for early 2020s delivery, and up to double the levels of the lowest bids that Xcel is pursuing. Rocky Mountain Power • 50 MW of wind capacity in Wyoming as part plans to purchase energy from 1,1 of its . The utility expects these projects, along with a supporting 150 - mile Energy Vision 2020 transmission project, to create between 1,100 an d 1,600 construction jobs and support more than 200 full - time positions in Wyoming communities. ION OPPORTUNITIES 6. RISKS AND MITIGAT State’s system, - The cost savings opportunities illustrated by the case study are clear, and though specific to Tri cost, legacy generating assets as - broadly indicative of the opportunities available to owners of high are alternatives fall in price. In addition to these cost savings opportunities, there are also opportunities to mitigate risks to business solvency by transi tioning away from legacy assets. Two categories of risks present themselves to owners of such assets: revenue loss caused by load defection, and cost increases due to asset - or portfolio - level costs. Both are present under current policy conditions, but co uld be exacerbated by potential policy changes. Revenue loss Current risks of revenue loss are driven by the falling costs of alternatives and the potential for member exit from full - service contracts: • Falling costs of alternatives. Owners of high - cost assets face the risk of load defection, i.e., customers (or, in the case of cooperative utilities, members) choosing to self - supply a growing share of their own - and medium - energy. In particular, prices for small re increasingly competitive with scale solar projects a retail and wholesale rates, respectively, in the Mountain West. Medium - scale solar prices fell 6 0% (i.e., <$45/MWh) is between 2010 and 2016, and community - scale (i.e., 1 – 5 MW) solar at recent prices g cost parity with wholesale energy - only prices in the Mountain West. Commercial - scale (i.e., approachin – 100 scale (e.g., 5 500 kW) solar pricing declined 50% 10 from 2010 to 2016, while residential ro oftop - – kW) solar PV systems have declined in price by 56% . Limiting the potential of solar adoption in the case of Tri State is its Policy 115, which limit s members to 5% self - generation to mitigate a perceived cost - 50% forecast to continue declining another 40 – shift between members. However, PV project costs are urrent policy. by 2030, potentially accelerating adoption even under c • Member exit : As emerging alternative resources fall in price, retail utilities (including co - ops) may seek to exit from all - requirements contracts with wholesale providers that continue to rely on high - cost assets, cost wholesale service available from other providers or market in order to take advantag - e of lower - purchases. For Tri State’s - State, this risk is not hypothetical; one member, accounting for 1.5% of Tri O U M N Y T K A C I N O R CARBON FUTURE - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW I N E S T T U I T

11 A LOW COST ENERGY FUTURE F VES 11 OR WESTERN COOPERATI - are currently in neg already exited - State’s system, and load, has otiation to exit or are Tri several others otherwise considering their options. With new or upheld changes to existing policy, revenue loss could be accelerated through additional load defection and loss of competitiveness due to increased customer access to competitive mar kets: • : PURPA interpretation upheld Current policies limit the potential of community - scale and other State’s Policy 115 discussed above. - distributed generation for utilities across the country, including Tri ruled on (FERC) in 2016 However, the Federal Energy Regulatory Commissi that the 5% limit imposed by Policy 115 did not apply to projects that qualified under the Public Utility Regulatory Policy Act as - State members to procure local resources whose “Qualifying Facilities.” This ruling effectively allows Tri - State’s wholesale rate. This ruling is being prices fall below their avoided cost of energy, i.e., Tri - op load being challenged but, if ultimately upheld and acted upon, could result in significant co - allow, and even obligate, retail economically met by medium scale solar projects. This ruling could also - net metered solar from their own members at avoided energy rates, leading to utilities to purchase non additional adoption from consumers and/or businesses. • Wholesale market expansion: The potential expansion of wholesale markets in the Western United - States would introduce competition for owners of high cost generating assets. A proposal for an expanded Southwest Power Pool market has stalled out due to Xcel Energy leaving the Mountain West Transmission Group , but other proposals are still in play, including expansion of the Energ y Imbalance . While monopoly providers, , and a potential West - wide regional transmission organization (RTO) Market State, have a relatively captive c ustomer base, the increased pricing transparency and including Tri - lower transaction costs available in an organized market could put pressure on high cost assets to exit - the market. Cost increases Risks of cost increases under current policy for owners of legacy gener ating portfolios are driven by the economics of aging assets as well as by a growing market understanding of the risks facing such portfolios: fired generators suffer forced outages (i.e., are unexpectedly unavailable - Nationwide, coal Outage costs: • - to gen 9% of operating hours. Western utilities, including Tri erate power) approximately State and others , operate aging coal - fired power plants that have, in recent years, undergone weeks long - or months - on a few large legacy assets puts outages related to failures or complications with upgrades. Reliance operating utilities at risk of high market price exposure, as well as unexpected compliance costs that need to be borne before the asset can be operational. • cost capital to expand and maintain Cost of capital: Utilities rely on the ability to raise and in vest low - risk and will be infrastructure. This lending is based on creditors’ belief that utilities’ revenues are low - sufficient to cover debt service. In recent years, this belief has been challenged, notably when Barcl ay’s downgraded the entire US electricity sector in response to perceived threats to traditional utility business models relying on captive cu stomer revenues as alternatives fall in price. Tri - State noted in its 2017 Form 10 - K filing that it is considering investing $1.1 billion between 2018 and 2 022; higher costs of capital would likely lead to higher member rates associated with this incremental investment. Under potential policy changes, other risks could confront utilities reliant on legacy fossil assets: • Renewable portfolio standards : Twenty - nine states , including Colorado and New Mexico but not ilities must provide a Wyoming or Nebraska, have renewable portfolio standards (RPS) specifying that ut - portion of their electricity from renewable resources. While Tri State is compliant with existing Colorado and New Mexico law with its 30% share from renewables, laws have been passed in four other states (Oregon, New Jersey, New Yor k, and California) specifying targets of 50%, and several states have O U M N Y T K A C I N O R CARBON FUTURE - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW I N E S T T U I T

12 A LOW OR WESTERN COOPERATI VES 12 - COST ENERGY FUTURE F passed or are actively considering higher targets. No national • Greenhouse gas pricing : - level pricing scheme exists today for carbon dioxide emissions, but emissions pricing . two recent proposals have emer ” or other forms of carbon dividends ged to support “ - ties reliant on high Utili carbon intensity assets would face increased operating costs and competition from lower - emissions resources. As an indicative example of the impact that these risks might have on Tri - State and its members, we analyzed - illustrative sc State would enarios of three of the above eight risk factors and their effect on average rates that Tri have to charge in 2030 to recover its costs in the business as usual and energy transition supply mix scenarios. e of these risk factors, we divided total revenue requirement (shown in To estimate average rates in the absenc Figure 4) by total sales. To calculate the impact of the three risk factors, we looked at a range of illustrative scenarios for member co PA, and greenhouse gas pricing (Figure 5). op exits, qualifying facility uptake under PUR - Figure 5 : Impact of three risk factors on estimated average rates in 2030 $140 $121 $120 $97 $100 $91 $91 $86 $84 $78 $77 $80 $60 $/MWh nominal Base Rate $40 Base Rate $20 $0 QF Carbon Pricing Co-op exits QF Co-op exits Carbon Pricing Current policy Policy changes Current policy Policy changes Business as usual Energy transition $40/ton $10/ton 20% of sales 10% of sales 5% of sales $20/ton 20% of sales 10% of sales 5% of sales Risk mitigation opportunities A transition to a lower - cost supply mix can also help mitigate the risks outlined above by lowering costs and proactively aligning supply mix more closely with potential policy forcing devices. The energy transition case in - each scenario reduces rate increases by between 30% and 60% by minimizing stranded cost risks with load defection, since more costs - usual case, as are variable (e.g., market purchases) versus fixed in the business - as well as by minimizing exposure to environmental compliance costs. Lowering supply costs and passing those o either adopt local generation or fully exit savings along to members can minimize the incentive for members t from the generation and transmission. Lowering supply costs also mitigates the risks of becoming uncompetitive ply mix by as utilities and regulators consider expanded Western electricity markets. Achieving a low - cost sup proactively prioritizing renewable resources, in particular, also minimizes exposure to greenhouse gas pricing or expanded RPS requirements. O U M N Y T K A C I N O R CARBON FUTURE - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW I N E S T T U I T

13 A LOW COST ENERGY FUTURE F VES 13 OR WESTERN COOPERATI - LIMITATIONS OF THIS ANALYSIS 7. CONSERVATISMS AND driven by a lack of detailed data available to study the specifics This analysis includes several limitations, largely - State. To mitigate the lack of available data at the root of many of the limitations of of the system operated by Tri this study, the analysis has also included several conservatisms, noted here. A full technical appendix, with sources for all data used and approaches for all analyses described in this paper, is included at the end of this document. Public data . Our analysis relies exclusively on publicly available data, including financial and other 1. State, its members, and research organizations. Thus our analysis cannot include - reported data from Tri - some specific datasets available only in a proprietary fashion to Tri State and/or its members or contractors, including detailed plant level data and financial accounts information. Our assessment of - - average rates in future years, in particular, relies on an average revenue requirement based analysis, and members. thus is indicative of, but cannot precisely reflect, specific rate structures offered to K to bound the operating Averaged generating fleet costs. We use definitive data from Tri 2. State’s 10 - - costs of its owned generating assets, but we only have access to derived data from industry analysts to split those costs up by plant. To minimiz e any bias introduced by these derived values for plant - level cost - State’s owned fleet by fuel type; thus, our analysis of a low - costs, we average the costs of Tri generation future for Tri - State conservatively does not represent the cost savings potential of retiring the most - expensive plants first. - 3. Resource adequacy focused reliability analysis. Our analysis includes an assessment of the resource adequacy requirements necessary to meet Tri State member loads in each future year assessed, and - the costs of doing so. Lacking detailed operating information for Tri - State’s system, we are not able to use other means for reliability analysis (e.g., power flow models) to assess other specific requirements. However, as Tri - State participates in an increasingly int egrated Western grid, definitive interconnect - , as well as the detailed resource plans of other regional utilities (e.g., Xcel), suggest no level studies issues in maintaining system reliability with g rowing levels of renewable energy adoption. 8. OPTIONS FOR MOVIN G FORWARD The opportunities available to Tri - State and its members are indicative of a broader trend across the country, tage of attractive economics for alternative where utilities currently operating legacy assets can now take advan State’s distribution co - ops is particularly dramatic, as they are balancing the - resources. The opportunity for Tri le for costly competing priorities of lowering their own members’ costs while also being financially responsib legacy investments initially made on their behalf by Tri - State itself. The combination of rapidly evolving economics and competing priorities ensures that the transition to a lower - cost energy future for co - ops will be llenging. complex, and likely cha ops and their providers can pursue a strategy of collective - on, distribution co - To meet these challenges head action, built on transparency and open dialogue, that can bring focused innovation, regionally appropriate State, both the opportunities and power to the situation at hand. In the case of Tri - solutions, and scaled buying risks hinge on the collective action of multiple stakeholders, including Tri - State itself, its co - op members, and use customer members; acting alone, any one gr their end - oup may find it advantageous to take actions (e.g., regressive rate structures, load defection) that make unilateral economic sense but could limit the opportunity for cooperative action among parties. In a 2018 white paper , t he National Rural Electric Cooperative Association advanced the ideal of a “consumer - centric utility” that “innovates for the benefit of all its consumers” and “uses its scale, scope, an d ability to integrate and optimize a portfolio of resources to bring innovation to consumers at lower cost and with fewer risks.” This view of the role of a cooperative utility is consistent with the pressing need for action between wholesale electricity - term opportunities, providers and their members to capitalize on the near cost, clean energy future in the Mountain West. - and mitigate the risks, of a rapidly accelerating, low O U M N Y T K A C I N O R CARBON FUTURE - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW I N E S T T U I T

14 A LOW OR WESTERN COOPERATI VES 14 - COST ENERGY FUTURE F 9. TECHNICAL APPENDI X tional model and a financial model of Tri The case study presented in this paper combines an opera - State’s utility – business, which together provide an estimate of the revenue requirement in each year analyzed (2018 2030). The operational model combines current operating data and projections of future energy sale s and peak load, with different scenarios for resource additions and retirements, as well as for changes to how resources operate, to determine a resource mix that provides the required amount of energy and capacity for each year from 2018 to 2030. The fin ancial model calculates the revenue requirement that represents the cost of the resource mix in a particular scenario. We then divide these scenario revenue requirements by forecasts of sales volume in each of those years to determine the average rate need ed in each year under each scenario to recover costs of service. Case study data sources • The Tri - State 2017 Form 10 - K is our source for Tri - State’s income statement and balance sheet as well as volume and total cost of purchases from Basin Electric Power Cooperative (Basin), the Western Area Power Administration (WAPA), and under wind and solar PPAs. It is also our source for member and nonmember energy sale s volume, total purchased electricity, the capacity of owned plants, and the quantity of firm capacity purchased from Basin and WAPA. The • is our source for plant in service, accumulated depreciation, capital 12 - ate 2017 RUS St - Tri expenditures, and annual depreciation for transmission and generation assets as well as revenue for nonmember transmission. The • State OATT Tri - is our source for Tri - State’s nonmember transmission rate. is our source for load growth projections and planned renewable development. State 2015 ERP • The Tri - - State’s coal - We also use the ERP as our source for the greenhouse gas intensity of Tri fired - and gas power plants. The Bloomberg New Energy Finance 1H 2018 U • S Renewable Energy Market Outlook is our source for forecasts in the future trends of wind and solar PV PPA prices. • The Public Servi ce Company of Colorado 120 day Report is our source for price ranges for wind and solar PV power purchase agreements for the region in 2023, as well as for inferred transmission costs for - incremental renewable additions on a per - megawatt basis. We also tak e the median bid for new gas fired generation capacity as the price for capacity purchases. • The Rocky Mountain Power 2017 IRP (5/1/18 Update) is our source for the cost of integrating energy from wind and solar PV. • The EIA AEO 2015 Electricity Market Module is ou r source for the ongoing annual CapEx for coal - and fired power plants. - gas • The Coal Asset Valuation Tool v6 is our source for the CapEx, incremental fixed operations and intenance (O&M), and year of installation of coal combustion residual and effluent control ma technologies for coal - fired power plants. or the greenhouse gas (GHG) intensity of electricity in CO, NE, WY, and NM. We is our source f • eGRID weighted average of the GHG intensity of those states as a proxy for the GHG - State sales - use a Tri intensity of electricity purchased from Basin and electricity purchased on the wholesale market in the region. • is our source for a levelized transmission adder for new wind and solar PV, as a Reinventing Fire supplement to derived data from Xcel’s 120 Day Report. • up estimates - l Market Intelligence Platform (formerly known as SNL) is our source for bottom S&P Globa - of Tri State production cost in the form of the variable O&M and fixed O&M of Tri - State coal - and gas - fired power plants. We use S&P to download fuel cost and the capacity factor data for Tri - State’s coal - and gas ). We also use S&P - fired power plants (S&P sources the majority of this data from EIA Form 923 - St ate’s member distribution co - ops (S&P sources this data to download sales and peak load data for Tri from ). EIA Form 861 • FERC Form 714 is our source for Tri - Stat e’s load profile. O U M N Y T K A C I N O R CARBON FUTURE - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW I N E S T T U I T

15 A LOW COST ENERGY FUTURE F VES 15 OR WESTERN COOPERATI - Case study scenarios We examined two supply mix scenarios as part of this case study: ERP sales forecast. Coal plants are retired as currently planned. 500 MW of wind is • – Business as usual scenario. constructed as planned in the chosen 2015 ERP Energy transition • ERP sales forecast. All coal plants are retired by 2026, but coal’s share of energy falls – faster. Wind totaling 1.05 GW and solar totaling 1.63 GW is constructed by 2030. Existing gas capacity factor increases to provide bala ncing energy for new wind and solar projects. Risk factors Within each of the two analysis scenarios, we ran sensitivity cases to examine the impact of carbon pricing, t and thus average rates. - generation, and distribution co - op self - distribution co op exits on revenue requiremen The generation portfolios of the sensitivity cases of each scenario maintain consistent shares of generation from each resource in order to isolate the impact on revenue requirement by these sensitivities, rather than from the cha nge in the generation mix. • Greenhouse gas pricing : We calculated impact on revenue requirement associated with illustrative GHG - , $20 - , and $40/ton. pricing of $10 : We calculated impact on revenue - op self - generation and member exits Distribution co requirement • associated with lowered load through self - generation and exits, using illustrative values of 5%, 10%, and 20% in each case. We assumed exiting members would pay a fee and continue to purchase generation - transmission services, while member self would not generate exit fees or transmission revenue. Analysis methodology • All sales projections begin with 2017 total sales to members and nonmembers as Sales projections – K. To project future years we take the total system sales projections from the - reported in the 2017 10 - on - year (YoY) sales gro wth. We then apply those ERP and, for each year, calculate the percent year annual percentage sales growth values to 2017 sales to project total sales through 2030. • Revenue requirement o level cost estimates from S&P analysis imply a lower total production - The plant – Generation K. To resolve this cost (variable and fixed O&M - State’s Form 10 - ) than indicated by data from Tri inconsistency between bottom - up production cost from S&P and top - down production cost - from Form 10 - up numbers to estimate the share of production cost that is K, we use the bottom xed O&M, coal variable O&M, gas fixed O&M, and gas variable O&M, then we apply those coal fi K to get the total cost in each of those shares to the reported production cost in Tri - State’s 10 - four components. For fuel cost, we use the value from S&P for the total c oal fuel cost and subtract that value from the total fuel cost reported on the 10 - K to estimate gas fuel cost. We apply the derived fixed O&M cost for each plant type in § y] - Fixed O&M [$/MW – dollars and divide by current operating capacity of that plant ty pe to get total fixed cost - y. This value for the remaining coal plants increases in 2024 to account for the in $/MW increase in fixed O&M from assumed installation of effluent and coal combustion residuals emission - control equipment. We delay the installat ion of the control technologies by two years from those provided in CAVT. Variable costs [$/MWh] – We apply the derived variable O&M for each plant type in § dollars, add total fuel cost for the plant type in dollars, and divide by 2017 energy production of that plant type to get total variable cost in $/MWh. – These calculations use generation plant balance, § Plant CapEx and Depreciation accumulated depreciation, and annual depreciation from Tri State’s RUS 12. We - determine an annual depreciation rate using n et plant balance and 2017 generation depreciation. We assume that in 2017 and into the future, on average, generation CapEx y of CapEx - and depreciation are equal. Using that assumption we determine the $/MW O U M N Y T K A C I N O R CARBON FUTURE - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW I N E S T T U I T

16 - A LOW 16 COST ENERGY FUTURE F VES OR WESTERN COOPERATI ir capacities and the ratio between associated with the coal and gas plants using the ongoing coal and gas CapEx from EIA. We use these values to determine the annual CapEx for the plants in operation. We assume that all CapEx is funded by debt and all own debt. revenue associated with depreciation is used to pay d o Purchases Basin, WAPA, other hydro, and current wind and solar We assume constant – § 2016/2017 volumes at 2017 prices. For the four small hydro facilities from which Tri - State buys electricity, we derive price from S&P. – We a § New wind and solar ssume 26% capacity factor (CF) for solar and 48% CF for wind. Prices are for 0% escalator PPA contracts. 2023 PPA prices from PSCO’s 120 Day Report are inserted into BNEF’s cost projections and normalized to their 2023 values, to determine prices for each PPA vintage from 2019 to 2030. – § Capacity In scenarios where the sum of owned capacity, firm purchases, and capacity credit adjusted renewable capacity for a given year falls below 115% of peak, we - e. We assume a price of assume capacity must be purchased to make up the differenc - y, which is the median bid for new gas - fired generation capacity in the PSCO $68/kW 120 Day Report. We calculate renewable capacity credit using the average of the - State’s 2015 ERP, and the 15 th percentile of numbers provided in Tri hourly capacity factor of regional wind and solar profiles during Tri State’s top 100 load hours in 2016. - Transmission o – Total transmission cost includes transmission O&M from Form 10 - K and transmission depreciation from RUS s are constant in real terms 12. We assume that these value - from 2018 to 2030. Total Interest is calculated by using current debt outstanding and the interest – Interest o payment for 2017 from the 10 - K to determine an interest rate. That rate is then applied to the total outstanding debt that comes out of the analysis of plant CapEx and depreciation and amortization, as well as debt reduction by distribution co - op exit (in the sensitivity cases where op exits) and debt repayments represented by - we examine the impact of distribution co non op exit - generation depreciation and amortization. We capture the impacts of distribution co fees by reducing Tri State’s outstanding debt by the same proportion as the exiting distribution - co - op’s proportion of sales. o Other – This is a residual cost catego ry that contains all utility and nonutility costs reported in Form 10 - K but not captured elsewhere in the case study model, including coal mining; Other depreciation, amortization and depletion; SG&A; and others. Net Income from Form 10 – - Margin o K. It is r educed by co - op exits proportional to the percentage of sales an exit represents. – Current nonmember transmission revenue and other nonutility revenue. In the o Other Revenue op exits, we assume this revenue - increases sensitivity case where we assess the impact of co by the NM - A - 40 transmission rate multiplied by the corresponding share of capacity volume. Figure details • This figure shows the history of scale solar PV costs vs. historic forecast costs - Figure 1: Historic utility – utility - scale solar PV cost s from 2009 to 2017, using Lazard’s history of annual benchmark estimates - scale solar PV costs from published in 2017. It then layers on top of that history the forecasts of utility 017 dollars in each case: several sources made during the intervening years, converted to constant 2 o 2010, EPIA Upper and Lower: We extrapolate between the 2010, 2015, and 2020 values forecast by the European Photovoltaic Industry Association, for both the Advance and Reference cases reported by . IRENA o 2011, SunShot Goal: We extrapolate from 2011 benchmark pricing to the 202 0 SunShot goal of $60/MWh . - tilt systems of >100 MW, o reported forecasts for fixed 2012, Black & Veatch: We interpolate the - 0 assuming a 6% cost of capital, 30% capacity factor, and 2 year book life. O U M N Y T K A C I N O R CARBON FUTURE - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW I N E S T T U I T

17 A LOW OR WESTERN COOPERATI VES 17 - COST ENERGY FUTURE F 2015, 2016, and 2017, NREL: We report forecasts from the Annual Technology Baseline for 28% o capacity factor projects under the Mid scenario. This figure shows • – costs versus regional renewable energy benchmarks State’s coal fleet - Figure 2: Tri - in $/MWh cost of operating each plant in Tri the all State’s coal fleet. The x - axis shows the capacity of - each plant in MW. The values for variable O&M and fixed O&M for each plant refle ct the adjustment described in the Generation section above between the bottom - up data from S&P Global and Tri - State’s wide costs reported in Form 10 - fleet K. We use each plant’s 2017 capacity factor to calculate the fixed - O&M in $/MWh terms. For compariso n, renewable costs are layered on top; all renewable prices include estimated integration and transmission adders, and represent 2023 delivery. • Figure 3: Case study of continued coal operation versus renewable procurement – This figure compares three scena - fired power rios to illustrate the economics and technical aspects of a transition from a coal plant to renewable energy on an asset State’s Escalante coal plant. by - asset level; in this case, for Tri - - as - The business - ation based on cost data and the capacity usual (BAU) case continues current oper factor for 2017. For Escalante, costs include its fuel cost provided by S&P and its derived fixed O&M and variable O&M as described earlier. The fuel saver case adds 100 MW of wind and 100 MW of solar PV, with PPA prices from PSCO plus adders for integration and transmission. The coal plant provides the energy of the BAU case less the energy produced by the new wind and solar. The retirement case assumes the coal plant is shuttered and all required energy is generat ed by 342 MW of new renewables, split between wind and solar PV. Capacity purchases provide for any resource adequacy needs that are not met by the wind and solar projects themselves, with their capacity contribution calculated using the methodology as des cribed in the Capacity section. – Figure 4: Generating asset portfolio mix and costs with legacy assets versus new projects • This figure State’s utility portfolio under the - shows the energy, capacity, and cost of the various components of Tri rios. The energy and capacity requirements in both cases are identical, the only two core scena difference is in how those needs are met. The differences in the portfolio’s compositions are described components of cost are in the Scenarios section. The methodologies for calculating the various described in the Revenue Requirement section. In the cost figures, the Coal and Gas areas include fuel, fixed O&M, variable O&M, depreciation and amortization, and interest. Figure 5: Impact of three risk factors on estimated averag • e rates in 2030 – This figure shows the - generation (i.e., sensitivities of average rates in the two core scenarios to carbon pricing, increased self - op exits. The figure shows the qualifying facilities on distribution co op systems), and distribution co - erage rate for each core scenario in 2030, then shows the incremental increase in rates that would av result from the loss of 5%, 10%, or 20% of sales as a result of member exits; the loss of 5%, 10%, or - , $20 - plication of a carbon price of $10 - 20% of sales as a result of self generation; and the ap , or $40/ton. O U M N Y T K A C I N O R CARBON FUTURE - CREATING A CLEAN, PROSPEROUS, AND SECURE LOW I N E S T T U I T

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