Introduction

In the past five years, it has become clear that an inexorable change in the way Americans consume energy is underway, as more individuals and businesses reach for the opportunity to produce their own energy, or procure it from providers that can offer energy in greener, more inexpensive, or more socially desirable ways. However, even as consumers seek out new ways to power their homes and businesses, critics have argued that energy consumers who move to exit the grid, either in whole or in part, should pay exorbitant fees in order to protect the ratepayers who remain from future rate increases. However, this paper argues that high exit fees are not necessary, especially in light of our findings that in those places where exits have occurred in the past, rates have not gone up as a result of the departures.

Specifically, this white paper undertakes an analysis of seven examples of large energy users who exited the grid, either through a statutory regime that permitted the exit or through municipalization of the utility, and found that in none of these incidences did the departure of the large energy user cause a rate increase. In some cases, rates did rise, but in none of the instances examined were the rate increases caused by the exiting customer. In at least two of the cases, it can be argued that the departure of the large energy users could very well result in rate decreases or rate stabilization over time, as utilities are freed up from having to purchase new generation or fuel to serve the departed customers and where the utility has the opportunity to sell the excess energy created by the departure into the market.

Additionally, in this white paper we: document the growing number of entities that are seeking to produce their own energy and are being facilitated in that effort by states and local governments; detail the handful of state-led efforts that are designed to address the coming transition to decentralized energy; and argue that states like Nevada can be a part of this facilitated transition through the fair implementation of efforts to depart the grid.

We also explore the likelihood that utilities in the Southwest including and especially Nevada Energy will continue to post strong financial returns over the next five to ten years, as they increasingly access newly emerging energy markets and policies like the California Independent System Operators (CAISO) Energy Imbalance Market and the Federal Energy Regulatory Commissions Order 1000. There are few regions in the nation more financially capable of addressing the growing desire of customers to provide their own power than the Southwest, due to the development of these markets, and the continued persistence of load growth due to in-migration.

Finally, this white paper offers a series of recommendations to policymakers who are being asked to address the desire of large energy consumers to self produce or procure energy from sources other than the incumbent utility.A growing number of large users are demanding the right to exit the grid/self-produce

The applications by four large energy users in Nevada to exit the grid are emblematic of a larger movement that is beginning to emerge across the nation. A growing chorus of energy consumers, both small and large, is voicing a desire to self-produce, for a variety of motivations, ranging from reducing costs, to energy independence, to the ability to reduce their carbon footprint. Some energy consumers, like Wynn Las Vegas, Sands and MGM in Nevada and the City of Boulder, Colorado are pressing forward with plans to largely exit the service of the incumbent utility, and others, like the United States military, are adopting technology that would allow themselves to island certain facilities on demand.

In this section we discuss the efforts of large energy users and groups of users who are pushing forward with plans to provide an increasing amount of their own energy, including three instances Boulder, Colorado, Minneapolis, Minnesota and Maui, Kauai and Parker Ranch, Hawaii, where energy users made or considered proposals similar to the ones made under 704B in Nevada, to procure or produce all of their energy from a source other than the incumbent utility.

Boulder, Colorado

The City of Boulder is one of the most recent entities to seek to form a new municipal utility and exit the service of its incumbent utility, Public Service of Colorado (PSCo, d/b/a Xcel Energy). As stated in recent testimony to the Colorado Public Utilities Commission, the citys objectives in forming this municipal utility are: greater local control and self-determination over its electric delivery system and supply. This includes the Citys goals of democratization, decentralization and de-carbonization of its power supply.[footnoteRef:1] [1: https://documents.bouldercolorado.gov/WebLink8/0/doc/129277/Electronic.aspx ]

The city has spent significant effort to achieve these goals, including the citys approval of $214 million in bond funding to cover 1) the purchase of PSCos transmission and distribution assets and 2) payment for stranded costs that would otherwise be shifted to remaining customers. [footnoteRef:2] Boulders efforts to municipalize have captivated the attention of many in Colorado and across the country, as both sides continue to debate the right of a large energy user like a City to leave the local utility, under what conditions, and at what cost to the municipality.[footnoteRef:3] [2: https://documents.bouldercolorado.gov/WebLink8/0/doc/129277/Electronic.aspx ] [3: Boulder has filed an application before the Colorado Public Utility Commission for the transfer of Xcels assets in the City. It has also made a purchase offer to Xcel, which the utility has declined. See https://documents.bouldercolorado.gov/WebLink8/0/fol/129263/Row1.aspx. See also http://www.utilitydive.com/news/a-utility-in-the-making-the-municipalization-of-boulder-colorado/300268/.]

Minneapolis, Minnesota

In 2014, in an effort to achieve its own ambitious clean energy goals, the City of Minneapolis, Minnesota considered the possibility of municipalizing, creating a city utility by purchasing the assets of two utilities Xcel Energy and CenterPoint Energy. While it ultimately opted not to go the route of outright municipalization,[footnoteRef:4] Minneapolis did use the threat of municipalization to achieve a number of its objectives, as well as expiring franchise agreements that allowed the city to negotiate with the utilities for cleaner energy sources and other energy-related objectives. [4: See Energy Pathways Study, http://www.ci.minneapolis.mn.us/www/groups/public/@citycoordinator/documents/webcontent/wcms1p-121587.pdf, at 57.]

An analysis conducted on behalf of the City of this option determined that significant legal and financial risk stood in the way of municipalization, but ultimately recommended that the City use its franchise agreements with the utilities to require changes in the way distribution infrastructure was implemented, and that the City waive its right to municipalize in return for a Clean Energy Agreement that would help the City achieve its carbon reduction goals.[footnoteRef:5] [5: Id at 62.]

Hawaiian entities

With utility rates that outstrip those of any other U.S. state, Hawaii has become fertile ground for efforts to exit the grid. Record numbers of individual homeowners have gone solar in Hawaii, aided by rates that encourage the adoption of solar, while several large energy users, including a County and a major landowner, have initiated efforts to leave the grid altogether. In the County of Maui, local leaders have begun discussing the possibility of leaving the incumbent, in part in reaction to the recent announcement by NextEra that the Florida based company was pursuing an acquisition of HECO.[footnoteRef:6] In Waimea, on the Big Island of Hawaii, the owners of what is known as Parker Ranch, have similarly been making plans for energy self-determination, at one time discussing with the surrounding community members the possibility of providing power to the area in an effort to boost renewable energy usage while at the same time cutting energy costs.[footnoteRef:7] And in 1999, in Kauai, business leaders decided to exit the electric utility by forming an electric cooperative, the Kauai Island Utility Cooperative (KIUC), and purchasing the assets of the former utility for $215 million.[footnoteRef:8] Interest in determining the nature and disposition of energy provision in Hawaii is intense and growing, and should continue to unfold over the next several years. [6: See Trabish, Herman. "Inside Hawaii Activists' Push to Ditch HECO and Transform the Utility Business Model." Utility Dive. Industry Dive, 28 May 2015.http://www.utilitydive.com/news/inside-hawaii-activists-push-to-ditch-heco-and-transform-the-utility-busin/399492/. ] [7: See "Parker Ranch Community Electric Supply Options." Paniolo Power. Parker Ranch, 2014. http://paniolopower.com/wp-content/uploads/Parker-Case-Study-Community-Solution-White-Paper-20140403-Final.pdf. ] [8: Kauai Island Utility Cooperative. About Us. Kauai Island Utility Cooperative. 2013. http://website.kiuc.coop/content/about-us-0.]

The United States Military

In the past five years, the United States military has become of the nations leading developers of renewable energy, as it seeks to meet an ambitious internal renewable energy goals of reducing its dependence on petroleum, and making its energy infrastructure impervious to outside attack.[footnoteRef:9] Several military branches have also launched major investments in transforming their bases and installation into microgrids, including the United States Navy, which recently announced it would create a centrally controlled grouping of microgrids that would be both interconnected and cyber-secure.[footnoteRef:10] Additionally, the Marine Corp recently began developing a microgrid project at its Twentynine Palms facility in California, that would allow the Marines to island the facility on command.[footnoteRef:11] The militarys focus on diversifying its energy sources and finding new ways to become autonomous from the grid represent another significant reason for developing policies that would facilitate such departures. [9: See http://www.defense.gov/home/features/2010/1010_energy/. See also Daly, John. "U.S. Armys $7 Billion Interest in Renewable Energy." Oil Price. CNBC, 24 Feb. 2014. http://oilprice.com/Energy/Energy-General/U.S.-Armys-7-Billion-Interest-in-Renewable-Energy.html, and see Erwin, Sandra. "Renewable Energy Boom Underway at U.S. Military Bases." 2014. National Defense Industrial Association. http://www.nationaldefensemagazine.org/blog/Lists/Posts/Post.aspx?ID=1380.] [10: The microgrids will be created at Navy installations in San Diego, California. See http://www.greentechmedia.com/articles/read/connecting-the-military-microgrid-dots.] [11: See https://www.greentechmedia.com/green-light/post/dod-turns-to-ge-for-marine-corps-base-microgrid-project.]

Nevadas 704B Applicants

Beginning in 2014, four corporations in Nevada Wynn Las Vegas, Sands, MGM and Switch filed applications before the Nevada Public Utilities Commission (PUCN) seeking to exit the service of the incumbent utility pursuant to a state statute known as 704B.[footnoteRef:12] The statute allows large energy users to purchase energy on the wholesale market from competitive entities other than Nevadas incumbent utilities, provided that they meet a number of specific criteria, and after a hearing and approval by the NPUC.[footnoteRef:13] Most recently, the Commission launched an investigatory docket designed to examine whether Nevada should examine non-by-passable or ongoing charges as a means to address the desire of large power users to exit the grid .[footnoteRef:14] Among the issues that docket is addressing are whether exiting customers should be required to pay a tariff or exit fee that includes legacy contracts of the utility, costs associated with closing and abating a coal plant, and whether departing customers should be able to share in the benefits of emerging energy markets like the Energy Imbalance Market (see discussion below on the EIM).[footnoteRef:15] The 704B process in Nevada is another indicator of the interest among major energy users in producing or procuring their own energy, and is a sign as well of the need to craft tariffs and exit policies that are fair to all. [12: See Docket No. 14-11007. Switch was the first to have its 704B application processed by the NPUC, and in June 2015, its application was denied. As of the writing of this report, Switch had withdrawn its application, and Wynn Las Vegas, MGM and Sands were proceeding ahead with their 704B proposals.] [13: See NAC704B.310, at https://www.leg.state.nv.us/NAC/NAC-704B.html#NAC704BSec310.] [14: See Docket No. 15-06015.] [15: Id.]

Arizonas AG-1

Arizona began experimenting with allowing customers to exit the grid in 2012, when the Arizona Corporation Commission approved a limited pilot program dubbed AG-1, a new tariff that allows commercial and industrial customers to choose their own energy providers.[footnoteRef:16] The new program has proven to be a run-away success, with eight customers and 700 accounts taking service under the tariff since its inception.[footnoteRef:17] Under the new rate rider, large commercial and industrial customers capable of aggregating at least 10 MWs of load can utilize competitive generators for their energy demand, while also utilizing APS as the scheduler of the energy.[footnoteRef:18] No more than 200 MWs could be subscribed under the program, which was slated to run for four years, until the utilitys next rate case. Major subscribers to the tariff include Walmart, Safeway, and Freeport-MacMoran.[footnoteRef:19] Service providers of the competitive energy include Noble Solutions, Constellation NewEnergy, Shell and Direct Energy Business, LLC.[footnoteRef:20] Participants in the AG-1 program are now seeking its extension, an effort that likely will play out in 2016 when the utility files its next rate case.[footnoteRef:21] The success of the AG-1 program is particularly compelling demonstration of the desire for energy self-determination, given how quickly it was subscribed and the push by the current subscribers to expand the tariff. [16: See In the Matter of Arizona Public Service Companys Application for a Hearing to Determine the Fair Value of the Utility Property of the Company for Ratemaking Purposes, to Fix a Just and Reasonable Rate of Return Thereon, and to Approve Rate Schedules Designed to Develop Such Return, Decision No. 73183, Docket Number E-01345A-11-0224.] [17: See Joint Motion to Extend Experimental Rate Rider, Docket Number E-0134A-11-0224. ] [18: The AG-1 tariff was designed such that APS took title to the energy from the competitive provider, thus avoiding the question of whether retail competition would exist in Arizona. The tariff covers energy supplies only, not distribution or ancillary services. See Decision No. 73183, id.] [19: See Joint Motion to Extend Experimental Rate Rider, Docket Number E-0134A-11-0224, id.] [20: Id.] [21: See Joint Motion to Extend Experimental Rate Rider, Id.]

Fortune 500 Corporations

Like the enterprises described above, a number of U.S. Corporations have in recent years begun pressing for greater levels of energy autonomy, in particular focusing on renewables and efficiency as a means toward that end. While this list is long and growing, none is more emblematic than Walmart,[footnoteRef:22] which has been actively striving toward energy independence.[footnoteRef:23] The companys three objectives for reaching a sustainable future consist of developing new renewable energy projects at scale, driving down the cost of renewable energy, and securing cost-effective, stable renewable energy pricing[footnoteRef:24]. In 2005, Walmart began working toward its goal of being supplied by 100 percent renewable energy with the implementation of its first on-site solar project in the United States. Shortly after, in 2006, Walmart launched its first large-scale wind power agreement with Mexico[footnoteRef:25]. Today, Walmart is the largest on-site renewable user and is considered a global renewable energy leader, with more than 335 renewable energy projects worldwide[footnoteRef:26]. The projects provide Walmart facilities over 2.2 billion kilowatt hours of renewable electricity annually or 24.2 percent of the Companys electricity needs globally. In addition, the Company has already achieved 32 percent of its goal to procure 7 billion kilowatt hours of renewable energy by 2020. Fulfillment of the Companys objective would avoid approximately 9 million metric tons of GHG emissions per year[footnoteRef:27] and Walmart asserts that its new energy policy will result in $1 billion in annual savings on energy bills. It is also worth noting that the Company strenuously argues that its targets could be more easily met through changes in public policy that would allow it to contract directly with the providers of renewable energy, without having to route their PPAs through utilities.[footnoteRef:28] [22: Other companies with ambitious internal renewable energy goals include Google, Apple, Ebay, Coca-Cola, BMW, Volkswagon and Yahoo.] [23: See e.g. http://cleantechnica.com/2013/04/23/walmart-targets-ambitious-renewable-energy-energy-efficiency-standards-by-2020/] [24: "Walmart's Approach to Renewable Energy." Walmart. Walmart Stores. http://cdn.corporate.walmart.com/eb/80/4c32210b44ccbae634ddedd18a27/walmarts-approach-to-renewable-energy.pdf. ] [25: Renewable Energy." Walmart. Walmart Stores, 2015. http://corporate.walmart.com/global-responsibility/environment-sustainability/energy. ] [26: "Walmart's Approach to Renewable Energy." Walmart. Walmart Stores. http://cdn.corporate.walmart.com/eb/80/4c32210b44ccbae634ddedd18a27/walmarts-approach-to-renewable-energy.pdf. ] [27: Id. ] [28: Id.]

III. Large customers who have exited the grid have not driven rate increases

Despite the predictions of the opponents of the right to exit the grid, in most locations analyzed for this report, the decision to allow an entity to exit the grid was not followed by significant rate increases. In fact, in those places where a departure from the grid by a large energy user was allowed, rates remained relatively stable, and remaining customers did not experience any substantive differences in either the cost or quality of the electric service provided by the incumbent utility. Most notably, there is no evidence that the grid departures caused rate increases, and in several instances it seems likely that the departures could facilitate downward pressure on rates for remaining customers.

This section of the report looks at seven specific examples of large energy users who exited the grid, pursuant to state laws that allowed them to do so or through municipalization: Direct Access in Oregon; municipalization in Page, Arizona; Community Choice Aggregation in California; municipalization in Winter Park, Florida; municipalization in Jefferson County, Washington State; the proposed municipalization of Boulder, Colorado; and the municipalization of Hermiston, Oregon. We chose these examples because they are all located in states that, like Nevada, continue to have traditional regulatory regimes with vertically integrated utilities, but where, also like Nevada, the state has adopted a statute that permits users to exit the grid under certain conditions.[footnoteRef:29] [29: We did not choose to analyze grid departures in full retail choice states, believing that the more apt comparisons are in states whose regulatory regimes and industry structures are most like that of Nevada: rate of return regulation with vertically integrated utilities.]

Indeed, in many respects, NRS 704B is similar to policies in other states that permit customers to select alternative providers for electric services. The following examples illustrate how customers in other states have successfully exited service from their incumbent electric provider without harming other ratepayers.

A.Community Choice Aggregation, California

Californias Community Choice Aggregation (CCA) policy provides one example of how a state can allow customers to select alternative providers of electric services without leading to a significant detrimental impact on remaining utility customers. CCA enables local governments to aggregate electricity demand within their jurisdictions and procure alternative energy supplies for that demand. Meanwhile, the incumbent utility is still compensated for providing distribution services. In 2002, California passed legislation that enabled CCA by requiring that All electrical corporations shall cooperate fully with any community choice aggregators that investigate, pursue, or implement community choice aggregation programs.[footnoteRef:30] [30: AB 117, http://www.leginfo.ca.gov/pub/01-02/bill/asm/ab_0101-0150/ab_117_bill_20020924_chaptered.pdf ]

In implementing the CCA policy, the CPUC outlined steps to prevent costs from being shifted from CCA customers to remaining bundled customers.[footnoteRef:31] This is accomplished primarily through a Cost Responsibility Surcharge (CRS) which accounts for costs incurred on behalf of CCA customers prior to their transferring to the CCA. These include costs associated with long-term power contracts, bonds, utility owned generation, or other commitments in approved resource plans. The CRS analyzes the liabilities that would otherwise be assumed by bundled utility ratepayers when the CCA begins serving local customers. Those liabilities would then be incorporated in the CRS so that bundled utility ratepayers are not penalized by the utilities' loss of energy customers, thus maintaining ratepayer indifference. [31: http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/42389.htm ]

Since enabling CCA in California, several communities in Pacific Gas and Electrics (PG&E) service territory have offered CCA programs, including the City and County of San Francisco (2010), Marin County (2010), San Joaquin Valley (2007), and Sonoma County (2014). Moreover, the CPUC has proactively sought to empower the formation of CCAs in accordance with California law. For example, in 2010, the CPUC found that Pacific Gas and Electric Company (PG&E) had not been cooperative enough in allowing communities to develop CCA programs and ordered the company to cease its efforts to thwart them.[footnoteRef:32] [32: http://docs.cpuc.ca.gov/PUBLISHED/NEWS_RELEASE/117229.htm ]

Meanwhile, there is little evidence that CCA places any significant burden on remaining PG&E ratepayers. This is demonstrated in PG&Es most recent General Rate Case. As of this writing, the rate design portion of this case is still pending before the CPUC, however parties to the case have reached a settlement agreement on how PG&Es revenue requirement should be allocated. The proposed rate design suggests that PG&Es bundled customers would have a cost responsibility that is a lower share than what would have occurred under the previous rate structure.[footnoteRef:33] This is true despite a significant increase in CCA customers since PG&Es previous rate case. While rates for bundled customers might increase due to an overall increase in PG&Es revenue requirements, there is no evidence that this is directly attributable to CCA. In fact, additional CCA may reduce the load obligation for remaining bundled customers and help to limit future rate increases by limiting the need to procure new generation. [33: http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M152/K869/152869229.PDF ]

Figure 1. Source: PGE 2014 GRC Phase II Settlement

One noteworthy aspect of the discussion on CCA in California is the fact that CCA customers who are paying to cover the costs of long-term power contracts are also entitled to receive this power physically.[footnoteRef:34] Indeed, the CPUC stated: As a general matter, we believe a CCA should have the opportunity to take delivery of any portion of a DWR or utility contract for which it pays through the CRS.[footnoteRef:35] Any attempt to develop an exit charge for departing customers in other states should similarly consider whether customers should be credited for power they are already paying for through the exit charge. [34: The CPUC has not yet weighed in on the method for accomplishing this.] [35: http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/42389-03.htm#P197_55927 ]

B.Municipalization in Winter Park, Florida

In 2005, citizens of Winter Park, Florida[footnoteRef:36] elected to depart from the service of their incumbent electric provider (Progress Energy Florida -- now Duke Energy via merger) and start their own municipal electric provider. [36: Winter Park, FL is a suburban city located in Orange County with a population of approximately 28,000 people. The city is roughly 9 square miles and consists mostly of residential areas.]

The idea of municipalization was raised initially in 2001 when the citys 30-year franchise agreement with Progress Energy expired. Progress Energy, head-quartered in North Carolina, achieved revenues nearing $30 million a year from Winter Park citizens and, in the view of the community, offered little in the way of improved reliability or local accountability to the residents[footnoteRef:37]. Consequently, Winter Park leaders chose not to renew the franchise, in favor of municipalization. Shortly after, both Winter Park and Progress Energy conducted feasibility studies for future municipalization.[footnoteRef:38] [37: "City of Winter Park: Our Municipalization Story." City of Winter Park. http://static1.squarespace.com/static/5504a1ffe4b08eb858c42afd/t/555ddd77e4b0ca1ccdae7c54/1432214903577/The+Winter+Park+Muni+Story.pdf. ] [38: The City of Winter Park determined that the municipalization would cost nearly $28.5 million while Progress Energy concluded it would cost nearly $106 million. In 2003, arbitration was held and the price was set at $42.3 million. See id.]

At the time, Progress Energy Florida mounted a significant publicity campaign to oppose Winter Parks municipalization that raised questions about the impact on rates. However, there is little evidence that Winter Parks actions have negatively affected Progress Energy ratepayers. The chart below illustrates changes to remaining Progress Energy Florida customer electric bills following the municipalization. The most significant changes are primarily due to fuel adjustments[footnoteRef:39] and a surcharge to cover hurricane damage costs[footnoteRef:40] that were unrelated to Winter Parks actions. [39: https://www.progress-energy.com/company/media-room/news-archive/press-release.page?title=Progress+Energy+Florida+rate+settlement+approved+by+PSC&pubdate=09-07-2005 ] [40: https://www.progress-energy.com/company/media-room/news-archive/press-release.page?title=PSC+rules+on+Progress+Energy+Florida+hurricane+cost+recovery+filing+&pubdate=06-21-2005 ]

Figure 2. Data Source: FL Municipal Electric Association, http://publicpower.com/electric-rate-archive/

At the time that Winter Park municipalized, Progress had a base rate increase request pending. In subsequent months, this matter reached a settlement in which base rates were frozen for four years.[footnoteRef:41] Progress filed its next request for a base rate increase nearly four years later in March 2009.[footnoteRef:42] This request was subsequently rejected by the Florida Public Service Commission (PSC).[footnoteRef:43] Notably, Winter Park was not among the reasons cited for requesting this rate increase, which were as follows: [41: http://www.psc.state.fl.us/library/FILINGS/05/09207-05/09207-05.PDF ] [42: Progress Energys 2009 Rate Application: http://www.floridapsc.com/library/FILINGS/09/02412-09/02412-09.pdf ] [43: PSC Order: http://www.floridapsc.com/library/FILINGS/10/01530-10/01530-10.pdf]

Inflationary increases in labor, material and equipment costs Increased costs of health care, property insurance, and liability insurance $4.5 billion in capital costs to add 3,000 MW of generation, additional transmission, and substation, and distribution facilities. State and federal regulatory requirements.

The fact that Progress Energy did not predicate any portion of its rate increase request on the Winter park municipalization is compelling evidence that rates did not increase as a result of it.

C.Oregons Direct Access

Since 2002, Oregon has permitted qualifying non-residential customers to participate in Direct Access, whereby they are able to directly purchase power from a wholesale supplier rather than the incumbent utility.[footnoteRef:44] [44: http://www.oregon.gov/energy/cons/pages/sb1149/business/restruct.aspx ]

To participate, customers are required to pay a transition adjustment over a certain period of time to ensure that they are paying their fair share of energy production costs that the utility already incurred to serve them. After this period the customer can opt-out of the utilitys cost-of-service energy prices and is no longer required to pay for energy supply or the transition adjustment.[footnoteRef:45] Direct Access customers are still responsible for paying the public benefits charge that goes to fund energy efficiency, renewable energy, and low-income programs.Additionally, the customer can opt back in to bundled cost-of-service pricing at a later date.[footnoteRef:46] [45: Oregon Administrative Rules (OAR 860-038), http://arcweb.sos.state.or.us/pages/rules/oars_800/oar_860/860_038.html ] [46: See Oregon PUC Fact Sheet: http://www.puc.state.or.us/consumer/Electric%20Industry%20Restructuring%20Nonresidential%20Customers.pdf ]

Of Oregons large investor-owned utilities, PGE stands out with approximately enrollment of 20 percent eligible customers in the Direct Access program.[footnoteRef:47] For customers who elect Direct Access, PGE offers multiple options for opting out of its cost-of-service (COS) rate. One of these options is a short-term opt-out that permits customers to elect an alternative provider for a single year. Another option is a long-term opt-out that includes both 3-year and 5-year transition periods after which no additional transition adjustment is required.[footnoteRef:48] [47: See http://www.sanger-law.com/new-pacificorp-direct-access-tariff/.] [48: See Portland General alternative pricing plan information: https://portlandgeneral.com/business/medium_large/energy_pricing/pricing_plans/open_enrollment_faq.aspx ]

Notably, Oregon does not presume that the effect of opting out of COS pricing will always shift costs to remaining bundled customers. By reducing the load the utility has to serve, direct access can actually provide a benefit to remaining customers by increasing the utilitys ability to sell excess capacity into the wholesale market. Indeed, in some years, such as 2006 and 2007, the transition adjustment for PGE was actually negative and provided a credit to participants. This occurred due to the fact that the market value of energy was higher than the cost to produce it under the utilitys cost-of-service. The chart below illustrates how the transition adjustment can vary depending on market conditions. Indeed, Direct Access and similar programs should not always be construed as a cost shift to remaining bundled customers.

Figure 3. This chart highlights two examples of the 5-year transition cost adjustment payments required for Direct Access customers. For customers enrolling in 2008, a credit was provided in each year over the 5-year period. For customers enrolling in 2011, a payment was required each year. In both cases, the transition adjustment falls to zero after five years.

Moreover, a review of the 2006 rate case of Portland General Electric (PGE) that occurred in the wake of the adoption of Direct Access in Oregon reveals that PGE did not seek to claim that its requested 1.7 percent rate increase was related to the departure of customers from its system under Direct Access, but rather that the relatively small increase sought was associated with the addition of a new gas power plant, costs associated with the re-licensing of hydro-electric facilities, advanced metering infrastructure implementation, and the rising cost of natural gas at the time, which put upward pressure on rates overall.[footnoteRef:49] Despite the implementation of a new tariff that allowed large customers to choose competitive energy providers, while paying a time-limited exit fee, the utility did not attempt to persuade its regulators that lasting damage was being done to the utility or its customers.[footnoteRef:50] [49: See http://apps.puc.state.or.us/edockets/edocs.asp?FileType=HTB&FileName=ue180htb12256.pdf&DocketID=13199&numSequence=7, Testimony of Piro-Lesh at 8. ] [50: The utility did discuss the existence of Direct Access, along with other factors, and its potential to impact cost of capital, but seemed to conclude that the direct access charge as structured was neutral in its impact on the utility and its remaining customers . See Id, at 21.]

D.City of Boulder

As described above, the City of Boulder is in the throes of an effort to exit the incumbent utility, and importantly, has demonstrated convincingly that it will be able to do so without harming remaining ratepayers. Specifically, the City has developed a gradual transition approach, which prevents additional cost shift to other PSCo customers and could potentially even yield some benefit to remaining PSCo customers. As the City stated in its recent testimony: By gradually departing from the PSCo system, Boulder absorbs the excess capacity that could result from its complete, immediate departure. This approach protects against added costs for other ratepayers and ensures that PSCos capacity remains used, useful and of value to its ratepayers. Boulder developed this transitional power supply plan to avoid unfairly shifting Boulders share of the carrying costs for existing PSCo generation to its other non-Boulder customers. [footnoteRef:51] [51: https://documents.bouldercolorado.gov/WebLink8/0/doc/129270/Electronic.aspx. ]

The chart below illustrates this point further. Over time, Boulder will gradually absorb load obligation from PSCo. This will effectively mitigate PSCos need to procure additional energy resources and should lead to reduced costs for PSCos remaining ratepayers since fewer generation resources are needed.

Figure 4. Source: Chart excerpted from testimony of City of Boulder, https://documents.bouldercolorado.gov/WebLink8/0/doc/129270/Electronic.aspx

0. Jefferson County, Washington State

In 2010, Jefferson County, Washington purchased the distribution system of Puget Sound Energy after a hard fought battle over the Countys plans to municipalize.[footnoteRef:52] Following a threat of condemnation, PSE agreed to sell its assets for $100 million.[footnoteRef:53] [52: See http://www.cobar.org/repository/Inside_Bar/Enviro/Recent%20Municipalization%20Efforts.pdf, at C-2.] [53: Id.]

An analysis of the two rate cases that occurred in the aftermath of Jefferson Countys departure from PSE indicates that the utility did not assert that the Countys exit led to either requested rate increase. More specifically, in 2011, PSE requested a rate increase of 8.1 percent, largely associated with $1.1 billion in utility capital investments in 2009 and 2010.[footnoteRef:54] Among the main drivers of the utilitys rate request: [54: See Pre-filed Direct Testimony of Kimberly J. Harris on Behalf of Puget Sound Energy, Inc. Docket No. UE-111048, at 2.]

The Companys Lower Snake River Wind Project $320 million in new gas and electric transmission projects Compliance tied to reliability and safety needs.[footnoteRef:55] [55: Id at 5.]

In 2013, PSE submitted an application for a .02 percent increase in rates, which was also unrelated to the exit of Jefferson County. In that filing, the utility sought to recover costs associated with three of its generating units. The Company later agreed to a rate decrease in a Settlement Agreement approved by the Washington Utilities and Transportation Commission.[footnoteRef:56] [56: See Puget Sound to Reduce Electric Rates, October 23, 2013, at http://www.utc.wa.gov/aboutUs/Lists/News/DispForm.aspx?ID=222.]

Hermiston, Oregon

In 2001, the City of Hermiston, Oregon voted to separate its energy service from its incumbent utility, Pacific Power and Light (now PacifiCorp), and form its own utility through municipalization. The condemnation effort drew the opposition of the utility, but following a court decision upholding the condemnation, Hermiston purchased the service territory and its assets for $8 million.[footnoteRef:57] [57: According to the American Public Power Association (APPA), this was twice the appraised value of the assets. See http://blog.publicpower.org/sme/?p=171.]

The question of Hermiston, Oregons departure from the PacifiCorp system did arise at the Oregon Public Service Commission in the form of an Order by the PSC to require that the gains made by PacifiCorp on the sale of the assets to Hermiston be placed in a balancing account for later amortization in a rate case, and presumably, for the benefit of the utilitys remaining customers.[footnoteRef:58] Additionally, the Commission ordered PacifiCorp to reduce its rate base by the amount of the departed assets, leading to a cut in the Companys revenue requirement of $675,575, also a benefit to remaining customers.[footnoteRef:59] [58: See Order No. 02-343 at 4, Docket UE 134.] [59: Id.]

It does not appear that PacifiCorp ever attempted to make a significant claim to the PUC that the departure of Hermiston represented a harm to its ratepayers. The issue was not raised in either of the utilitys subsequent rate cases, and was not cited by either the utility or the Commission as a primary driver behind the need for the rate increases. More specifically, in 2004, PacifiCorp sought a 12.5 percent rate increase in November 2004, primarily related to increased fuel costs, capital expenditures, the newly created Transition Adjustment Mechanism (TAM) to implement Direct Access in Oregon (see description above of Direct Access); and an Oregon-specific tax issue impacting the Companys revenue requirement. The Commission granted a 3.17 percent increase at the time.[footnoteRef:60] Two years later, Pacificorp was back before the Commission with a 13.2 rate increase request. That filing dealt with: [60: See In the Matter of PACIFIC POWER & LIGHT COMPANY, dba PacifiCorp, Request for a General Rate Increase in the Companys Oregon Annual Revenues, Docket UE-170. See also Rebuttal Testimony of D. Douglas Larson, id.]

Capital expenditures related to de-carbonizing and making more efficient its generation fleet Increasing operations and maintenance costs The so-called 408 tax issue specific to Oregon An ROE that the Company asserted hobbled it in its efforts to make capital expenditures Resolution of cost allocation related to a class of irrigation customers.[footnoteRef:61] [61: See Trial Brief, Pacificorp, In the Matter of Pacificorp Filing of Revised Tariff Schedules, Docket UE-179.]

Page, Arizona

In 1985, the City of Page, Arizona voted to municipalize a utility by condemning the service territory of Arizona Public Service Company (APS) in and around Page.[footnoteRef:62] The vote of Page residents to municipalize occurred in the wake of a feasibility study conducted on behalf of the town demonstrating significant savings would occur, and following a general sense by the community that the incumbent utilitys prices were rising and that service could be improved under a city-run regime.[footnoteRef:63] Both former and current officials interviewed for this whitepaper described the municipalization process as a contentious one, with the incumbent utility fighting hard to prevent the departure of Page from its system.[footnoteRef:64] As predicted by the feasibility study, the Page municipalization resulted in significant savings to the City, and Page has retained stable rates and strong reserves in the decades following the municipalization vote.[footnoteRef:65] Though the condemnation purchase was hotly disputed, according to one key participant, in the end the sale of the APS assets did not include costs beyond those related to the physical assets being transferred.[footnoteRef:66] [62: Page, Arizona is located in far northern, Arizona, bounded by Lake Powell, the Grand Canyon, and Monument Valley. It is home to approximately 7,500 residents, but swells to a much larger number during tourism season. In 1985, at the time of municipalization, the Citys peak load requirement was approximately 11 MWs.] [63: Telephonic interview with former City Attorney Charles Stoddard, July 22, 2015. Stoddard served as Page City Attorney from 1975 to 2002, and helped to preside over the municipalization process in 1985. Stoddard currently is in private practice in Page, Arizona.] [64: Stoddard interview, id. Following the vote of the citizens of Page to approve the condemnation of the APS facilities in and around Page, APS sued the city. The utility ultimately settled the lawsuit, and Page purchased the system from APS.] [65: Current and former city officials attribute the success of the Page municipalization in part to the structure of the utility, which is to some degree separate from the city, via governance by a separate Board. The utility structure, which was accomplished through an ordinance passed prior to the municipalization, also requires that the general manager of the electric utility report directly to the utilitys board. ] [66: Stoddard interview, id.]

Importantly, a review of the rate cases during and following the municipalization of Page revealed that despite its efforts to fight the departure of Page, APS did not attempt to claim that the departure of the customer caused the need for a rate increase. More specifically, in its 1991 rate case, APS sought a 5.2 percent rate increase, tied primarily to the recovery of costs associated with the construction of the Palo Verde Nuclear Generating Station (PVNGS).[footnoteRef:67] Additionally, a review of the record in the Companys 1986 rate case revealed that all of the issues addressed by the Arizona Corporation Commission at that time pertained to cost recovery of the PVNGS, and not to any claimed costs related to the Page municipalization.[footnoteRef:68] [67: See Decision No. 57649, in Docket No. U-1345-89-162, December 6, 1991. See also Direct Testimony of Jaron B. Norberg, Docket No. U-1345-90-007.] [68: See Decision No. U-1345-85-156, in Docket No. U-1345-85-156, December 5, 1986. See also the 1988 Annual Report of Arizona Public Service Company, in which the Company details its financial and operational status for shareholders, and filed at the Arizona Corporation Commission in Docket No. U-1345-90-007. The 1988 Annual Report does not mention the Page condemnation.]

Indeed, a review of the record demonstrates that APS did not make any filings before the Arizona Corporation Commission related to the Page municipalization and condemnation proceeding, except to withdraw the tariff it once utilized to serve the City.[footnoteRef:69] [69: See Decision No. 55140, in Docket No. U-1345-86-168, August 6, 1986.]

1. NV Energy profits are strong now and the Company will likely benefit from upcoming transmission and energy markets and future load growth in the Southwest

Several emerging policy developments in the West argue strongly in favor of allowing large energy users to exit the grid, and against the position that doing so will cause rate increases in the incumbent utilities service territory. More specifically, in the Southwest, Nevada Energy is well positioned to be the beneficiary of the Energy Imbalance Market under development now by the California Independent System Operator (CAISO) and other off-system sales, as well as Order 1000, to the degree that Nevada Power decides to build transmission between California and other states under the new federal rule. Additionally, like other utilities in the desert Southwest, Nevada Power is likely to benefit from future load growth. Unlike other regions in the nation, Nevada and Arizona continue to see strong population growth.[footnoteRef:70] [70: Between 2010 and 2014, Nevadas population grew 5.1 percent, compared with the U.S. growth rate of 3.3 percent. Private, non-farm employment increased 3.3 percent compared with the national average of 2 percent from 2012-2013.]

A. Off-system sales, including those enabled by the Energy Imbalance Market.

As experience has demonstrated in other states (notably Oregon) the departure of some customers from an incumbent utility can benefit remaining customers by freeing up generation resources for off-system sales. These sales opportunities are poised to increase since wholesale markets in the Western U.S. are rapidly evolving. The recent establishment of an Energy Imbalance Market (EIM) is indicative of this evolution.

In November, 2013, Nevada Energy announced that it would enter the EIM, citing the results of a 2012 study that determined the utility would receive benefits in 2017 of between $6 million and $9.5 million, escalating by the year 2022 to between $7.7 million and $12.2 million. The entry of NV Energy into the EIM was approved by the Nevada PUC in 2013, and as of this writing, NV Energy was poised to begin operation in the EIM in October 2015. The EIM has gained steam and traction steadily since its inception, most recently attracting the membership of Arizona Public Service Company, which estimates its own benefits from joining the market could top $18 million annually.[footnoteRef:71] It is important to note that the benefits of the EIM to its participants grow as the market itself grows and become more liquid, such that it is almost certain that the benefits of the EIM will outstrip the initial estimates of the utilities.[footnoteRef:72] [71: APS estimates it will see annual benefits from the EIM totaling between $7 million and $18 million. See https://www.aps.com/en/ourcompany/news/latestnews/Pages/arizona-public-service-to-participate-in-energy-imbalance-market-.aspx.] [72: An example of this is found in the estimates of Arizona Public Service Companys EIM benefits calculation. APS announced that its entry into the EIM would throw off annual benefits of between $3 and $6.5 million for the existing EIM participants. See id.]

Indeed, the presence of the EIM represents the outer edges of what will likely be a larger energy market presenting untapped opportunities for revenue growth to the member utilities,[footnoteRef:73] and the opportunity for rate mitigation for the ratepayers of these entities. In most states, regulators have the opportunity to require that some portion of the revenues associated with EIM participation and off-system sales be shared with ratepayers, and it is safe to assume that regulators charged with the responsibility of deploying just and reasonable rates will see to it that ratepayers are at least the partial beneficiaries of the EIM windfall. [73: In recent months, Berkshire Hathaway officials have touted and promoted the expansion of the EIM and the ability of NV Energy and PacifiCorp to assist in its build-out. See e.g. http://www.utilitydive.com/news/why-warren-buffett-is-backing-a-western-grid-balancing-market/254333/.]

1. Order 1000

In 2011, the Federal Energy Regulatory Commission issued Order 1000, a landmark policy designed to speed the pace of development of extra high voltage transmission lines in the U.S through the reform of FERCs rules governing planning and cost allocation for transmission lines.[footnoteRef:74] This failure to build needed new electrical infrastructure was believed to be a threat to the reliability of the grid, and one reason why renewable energy was not being built out in far-flung, but resource rich areas of the country.[footnoteRef:75] The view of many at the time was that transmission projects had become bogged down, as it was difficult in many instances to determine who should pay for a given transmission line spanning multiple states, and as in some cases, individual utilities and states fought to prevent transmission lines from being built through their service territories. FERC Order 1000 established a process by which utilities and states are required to come together on a regional basis to form a cost allocation mechanism that can then be used to assign to utilities the costs of building new transmission.[footnoteRef:76] [74: See http://www.ferc.gov/media/news-releases/2011/2011-3/07-21-11-E-6-factsheet.pdf.] [75: Id.] [76: See http://www.ferc.gov/industries/electric/indus-act/trans-plan.asp.]

Order 1000, which is currently being implemented by the states through regional organizations[footnoteRef:77], is likely to be a source of additional revenues for those utilities that actively participate in the build-out of transmission, including NV Energy, which is part of Berkshire Hathaway Energy, a holding Company with significant interest in transmission build-out.[footnoteRef:78] In fact, it is worth noting that with the acquisition of NV Energy, and most recently AltaLink, the Canadian transmission company, Berkshire Hathaway has transformed itself into a holding company with transmission assets throughout most of the Western United States, as well as western Canada.[footnoteRef:79] [77: The regional organization implementing Order 1000 in the Southwest is Westconnect. See http://www.westconnect.com/planning_order_1000_stakeholder_process.php.] [78: See e.g. http://www.elp.com/articles/2014/04/more-than-164-billion-in-transmission-planned-being-built.html. ] [79: See https://www.berkshirehathawayenergyco.com/. Berkshire Hathaway Energy now owns NV Energy, BHE U.S. Transmission, and PacifiCorp, all companies with transmission assets in the West. Most recently, Berkshire Hathaway Energy announced the acquisition of AltaLink, the Canadian transmission company with assets in Western Canada. See http://www.utilitydive.com/news/buffetts-berkshire-hathaway-energy-agrees-to-buy-altalink-for-29b/258784/.]

Indeed, some of the very utilities that are seeing some load loss due to efforts to exit the grid, will see a concomitant increase in revenues from transmission build-out, suggesting that some portion of revenue loss associated with grid departures will be mitigated. Earnings sharing mechanisms established by regulators for these activities would allow the Commission to require Berkshire Hathaway to share profits made by NV Energy or other Berkshire Hathaway Energy subsidiaries doing business in Nevada, to be shared with ratepayers, and if large customers continue to leave the system, more of the profits from activities like FERC Order 1000 transmission projects will go to the remaining customers.An increasing number of states are addressing the right to produce power and exit the grid and are designing the Utility of the Future

The efforts of entities like Wynn Las Vegas, Sands, and MGM to exit the grid, along with attempts at municipalization in Boulder, and the near attempts in Minneapolis and Hawaii described in this whitepaper, are representative of a grassroots push across the county to self produce energy, a desire on the part of many residential and commercial customers to exit the grid that is leading regulators in those states to consider wholesale reforms to the utilitys regulatory regime and business models. Minnesota, New York, Hawaii, Arizona, Massachusetts, California and in a sense Nevada through the 704B process, are coming to grips with the growing desire for decentralization and distributed generation through public dockets and workshop processes that could lead to new ways to regulate utilities and new methods for utilities to operate, and that would facilitate the departure of customers from the grid, while at the same time protecting ratepayers.

Perhaps the most aggressive and advanced of these state-led efforts at reform is New Yorks Reforming the Energy Vision (REV) process. Under REV, the New York Public Service Commission is designing a new utility regulatory system in which decentralized energy will play a much more significant role in providing the states energy needs, and in which the incumbent utilities will become the platforms that enable energy consumers to freely access energy services.[footnoteRef:80] Importantly, the REV effort in New York has drawn hundreds of stakeholders, and has resulted in multiple Orders being issued to date by the NYPSC,[footnoteRef:81] leading many to believe that the process will likely result in significant changes to the utility system in New York that will drive innovation and allow large energy consumers to determine nearly every aspect of their energy service, most importantly who provides it.[footnoteRef:82] [80: See New York Public Service Commission CASE 14-M-0101 Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision, at pg. 12. The reformed electric system will be driven by consumers and non-utility providers, and it will be enabled by utilities acting as Distributed System Platform (DSP) providers. Utilities are responsible for reliability, and the functions needed to enable distributed markets are integrally bound to the functions needed to ensure reliability. Technology innovators and third party aggregators (energy service companies, retail suppliers and demand-management companies) will develop products and services that enable full customer engagement. The utilities acting in concert will constitute a statewide platform that will provide uniform market access to customers and DER providers.] [81: See http://www3.dps.ny.gov/W/PSCWeb.nsf/All/C12C0A18F55877E785257E6F005D533E?OpenDocument#RULINGS for a complete listing of the Commissions REV Orders.] [82: See http://www.greentechmedia.com/articles/read/5-key-proposals-for-new-yorks-grid-transformation; see also http://switchboard.nrdc.org/blogs/jmorris/rev-ing_it_up_in_new_york_a_lo.html.]

Other states are gearing up for a very different utility and energy services future, as well. In Minnesota, a variety of stakeholders have launched what is known as e21, a collaborative effort aimed at developing utility reforms to address decentralization. The e21 effort, which includes the states utilities, environmental groups and observers from the states Public Utilities Commission, is predicated on the idea that utility business models and regulation are no longer effective, and that customer demands for new energy choices are driving the need for change.[footnoteRef:83] [83: See http://www.betterenergy.org/sites/www.betterenergy.org/files/e21_Initiative_Phase_I_Report_2014.pdf. In short, new customer expectations, public policy goals, and the changing utility marketplace are driving the need for a modern electric system that can support new ways for electricity to be generated, delivered, and used.]

In Massachusetts, state utility regulators have issued an order requiring regulated utilities to engage in 10 year distributed planning and to submit grid modernization plans that provide the platform for the increased use of distributed generation, energy efficiency, and smart metering.[footnoteRef:84] [84: See http://www.mass.gov/eea/docs/dpu/electric/12-76-a-order.pdf.]

In Hawaii, where extremely high penetration rates for distributed solar and keen interest in exiting the grid by several large energy users has emerged, regulators have directly ordered the states large utilities to devise new business models that would assist the state in accommodating distributed energy while protecting ratepayers. In particularly dramatic fashion, the Hawaii PUC rejected an Integrated Resource Plan submitted by Hawaii Electric Company (HECO) and laid out a number of steps it would like to see the utility take, including allowing independent power producers to provide energy services to consumers, and the unbundling of services, such that energy consumers could benefit from lower cost energy choices.[footnoteRef:85] [85: See http://puc.hawaii.gov/wp-content/uploads/2014/04/Commissions-Inclinations.pdf.]

And in California, the Staff of the states Public Utilities Commission recently issued a whitepaper examining new utility business models to address the rapid advance of distributed generation in that state.[footnoteRef:86] The whitepaper acknowledges the reality of the disruptive challenges to the existing utility business model, and outlines for California regulators three new utility business models being proposed across the country.[footnoteRef:87] [86: See http://www.cpuc.ca.gov/NR/rdonlyres/929E2B29-F72F-4BBD-9CD1-2C06DF249785/0/PPDElectricUtilityBusinessModels.pdf. A picture of what the electric grid of the future looks like has begun to form: smarter, more flexible, more integrated, more market-based, and more democratic. Lines are beginning to be blurred in terms of who is providing services and who is consuming them, especially when consumers start morphing into pro-sumers customers who consume as well as produce energy. Whereas the old grid was a oneway communication system and the roles were clear and the lines between them were in bold ink, the new grid is far less rigid and far more integrated. This new integrated grid and its new communication functionalities challenge the industry to revisit the business and regulatory model of the electric utility that has existed for over 100 years.] [87: Id.]

FIGURE: 'Utility of the Future' Projects; Source: Greentech Media

Like the other states described in this report, Nevada has an opportunity to become a leader in the effort to transition the nations 100-year old utility system to one more responsive to customers and capable of providing safe, reliable and cost effective service. In fact, as several other states have noted, getting ahead of the curve when it comes to regulatory and utility business models makes it more likely that a state and its ratepayers will win out: innovators are more likely to flock to Nevada, large energy users are less likely to want to leave Nevada for another state offering more energy choices, and the introduction and integration of new energy technologies is likely to take place in a more orderly and cost effective way.

Indeed, and perhaps most importantly, from Nevadas standpoint it makes more sense for state policymakers to allow for an orderly transition that allows companies to stay in Nevada, while also producing their own power than to resist allowing them to choose their own energy providers, and risk their decision to expand elsewhere, or to locate elsewhere in the first instance.

The fact that nearly a half a dozen states are now looking at sweeping regulation or new business models that would accommodate requests like the ones being made by Wynn Las Vegas, MGM and Sands in Nevada, leads to the inescapable conclusion that soon, large energy users will have choices about where they are best able to manage and direct their own energy services and those choices will be located in states that have launched and completed utility regulatory reform efforts and are actively allowing energy users to engage in the energy marketplace. Energy users will increasingly be beckoned to and drawn by the states that have designed a regulatory model that provides for self-determination by all energy users.If companies do not feel they are receiving value from their utility they should be permitted to go elsewhere, and increasingly they can: the case of eBay in Arizona

There are several factors that must be weighed when considering the cost responsibility of a departing load customer. While there may be a desire from regulators to maximize cost recovery from these customers (e.g. through large exit fees) to prevent a cost shift to other customers, this must be weighed against the alternative whereby the customer simply relocates without paying any exit fee or surcharge, thus transferring 100 percent of their cost responsibility to other customers. This is especially relevant to facilities like data centers whose services are easily relocated. These considerations may warrant some relief granted to the customer to prevent shifting even greater costs to other customers.

A recent case in Arizona illustrates this point. In this case eBay, which operates data centers in the state, sought a discounted rate from its electric supplier, Arizona Public Service (presumably at a level lower than its true cost responsibility). Although eBay was not seeking an alternative supplier, the example illustrates the real possibility that a customer could voluntarily leave a utilitys service territory at their own discretion. APS proposed, and the Arizona Corporation Commission approved, a lower rate to prevent even greater cost shifting if the customer left altogether.[footnoteRef:88] As APS said in requesting this discounted rate: [88: ACC Order: http://images.edocket.azcc.gov/docketpdf/0000162456.pdf ]

APS believes this ESA is appropriate and necessary to both retain eBays present load and to encourage eBay to continue to grow in APSs service territory. eBay has data centers in other jurisdictions and can choose to site their business at any location that has the appropriate infrastructure, chiefly power and fiber. If eBay were to move its operations to a location outside of APSs service territory, a substantial amount of revenue requirement responsibility would be shifted to other APS customers.[footnoteRef:89] [89: http://images.edocket.azcc.gov/docketpdf/0000160605.pdf ]

Finally, it should be noted that corporate earnings including those of utilities are generally seen as being tethered to the level of value being provided by the company in the marketplace. If the utility is not able to provide this value, as indicated by the desire of energy consumers to look elsewhere for their power services, regulators and other policymakers should begin to seriously consider whether the earnings they are receiving are justified. Moreover, policymakers should factor this lack of confidence in the incumbent into decisions about when and how energy consumers should be allowed to choose alternative energy providers.Recommendations

As we have demonstrated, there is no evidence that the departure of large energy consumers from the grid causes rate increases. As a result, policymakers who are increasingly being called upon to mediate the question of how and when these departures should be allowed to go forward must exercise caution when being asked to assess exit fees to the departing customers. Fairness and equity are important objectives in the rate making process, and must be the guiding principle when addressing all affected interests in such cases.

We offer the following recommendations to regulators, legislators and the executive branch, in dealing with grid departures:

1. Exit fees should be time limited: Fairness and business certainty require that exit fees and departure tariffs be implemented for a finite period. Policymakers should consider departure tariffs or exit fees be limited to no more than three to five years, a period that is long enough to capture any possible negative impact to remaining customers.2. Exit fees and departure tariffs should be constrained to a finite number of impacts: Fees and tariffs that include items such as stranded costs associated with large scale power plants are unfair and should not be considered by regulators. 3. Mitigation for a utilitys profitability should be included in fees: Utilities that are experiencing extreme profitability are not in need of exit fees and departure tariffs and should be asked by regulators to utilize a percentage of dividends that otherwise would have been provided to investors to mitigate any alleged costs associated with departed customers. Where regulators believe that an exit fee or departure tariff is still necessary, a utilitys ability to withstand lost revenues should be considered by regulators in the design of the fees and tariffs.4. Credit for a utilitys participation in EIM and off-system sales should be available: Clearly, fairness and equity demand that exit fees and departure tariffs should include an offset for a utilitys participation in the EIM and off-system sales. Departing customers were a part of building the utility into an entity capable of participating in the EIM, and therefore should be able to benefit from the fruits of the EIM process.5. Any departure tariff or exit fee should be functionally capable of going negative: If the market value of energy is higher than the cost to produce it under the utilitys cost-of-service, departed customers should receive a credit under any exit fee or departure tariff.6. Exiting customers should be allowed to physically take the energy of the projects the contracts of which are included in their exit fees: As seen in California CCA program, policymakers should be sure to allow exiting customers to take the physical power of any renewable energy project whose contract the departing customer is being asked to pay for through an exit fee or departure tariff. When a former ratepayer is asked to continue to pay for a contract, that ratepayer should be permitted to continue to directly benefit from the power being created as a result.7. In those states where departures are not currently permitted, policymakers should enact legislation that allows for exiting the grid and set out the procedure, following the principles outlines above, by which this would occur.

VIII. Conclusion

As more and more consumers become pro-sumers of energy, demanding the opportunity to choose the manner, quality, and source of their power, regulators and lawmakers will increasingly be called upon to be the facilitators of this choice, and the judges of whether there will be costs associated with these departures. However, as this paper has demonstrated, those policymakers should reject the hyperbolic claims of the opponents of the right to exit the grid that allowing such departures will result in higher rates for remaining consumers. History tells us something very different. In those instances where large energy users have departed the grid, rates have either remained stable over time, or have edged up slightly, and in none of the cases examined for this paper did the utility attempt to claim that the high rates sought over time were associated with the decision of their customers to exit the utility system. Indeed, in two cases analyzed for this paper, we determined that it is actually possible that remaining customers could, over time, experience lower rates following the departure of the large energy consumers, as the utility no longer is required to rate base expensive energy projects needed to serve the departed customer, and as it is able to sell the resulting excess power created in the wake of the exit, thereby minimizing the need for large future rate increases.

Moreover, a number of states in the West and Southwest are likely to be home to utilities that flourish financially, even in the face of the growing departure of large and small customers. The West is experiencing a renaissance of opportunity for energy providers, particularly those capable of accessing extra high voltage transmission systems and selling excess energy and services into the Energy Imbalance Market. Moreover, utilities like Nevada Power And Arizona Public Service Company have opportunities to participate in the development of high voltage transmission projects that will be eligible for cost allocation under FERC Order 1000. The benefits of the revenues from these activities will more than offset any short-term negative effects of departing customers, and will redound to the betterment of both the utilities shareholders and its remaining customers.

1