Nevada’s Mohave Plant Shuts Down

On December 31, 2005, the 1,580 megawatt (MW), coal-fired Mohave Generation Station, located in Laughlin, Nevada, ceased commercial operations. The decision to close the plant represented the culmination of years of environmental and coal supply issues. Concern for the environmental impact of the plant on water supplies and air culminated in a 1999 consent decree that provided for the installation of an estimated $1.2 billion of pollution control facilities. The agreement specified that the facilities were to be in place by the end of 2005 in order for the plant to continue operating after December 31, 2005. Following a lengthy controversy over the adverse effects the plant emissions had on visibility in the Grand Canyon, the Mohave plant’s joint-owners chose to shut down the facility rather than undertake the expenses needed to install pollution abatement equipment mandated by the U.S. Environmental Protection Agency (EPA). This article presents a profile of Nevada’s electric power market along with an analysis of the impact that the lost coal-fired generation has had on electricity supply and prices in Nevada and the surrounding States impacted by the Mohave shutdown.

Figure 1. Additions to Nevada Summer Electric Net Power Capacity, 1936-2007

Source: Energy Information Administration, Form EIA-860, “Annual Electric Generator Report.” Figure Data

Mohave Generation Station—a Major Regional Energy Facility

The Mohave Generation Station was placed in service in 1971 and is located in Laughlin, Nevada, about 90 miles southeast of Las Vegas. At 1,580 MW of capacity, the plant represented the single largest addition to Nevada’s electricity capacity since the State was electrified (Figure 1).

The majority share of the Mohave Generation Station’s capacity was owned by Southern California Edison (56 percent), which was also the operator of the plant (Table 1). Other shareholders include: the Salt River Project² (20 percent), Nevada Power Company (14 percent), and the Los Angeles Department of Water and Power (10 percent). In 2005, the Mohave Generation Station provided Southern California Edison with 7 percent of its power and the Nevada Power Company with 17 percent of its power. With the closure of the Mohave plant, Nevada became a net interstate importer of electricity, and coal’s share of Nevada’s electricity generation fell from 46 percent in 2005 to 23 percent in 2006. The closure of the Mohave plant also resulted in the discontinuance of operations at Arizona’s Black Mesa mine, which was the sole supplier to the plant.

Mohave Generation Station Faces Environmental Opposition

At the time the Mohave Generation Station was completed in 1971, it was Nevada’s largest power plant, a status it retained until its shutdown in 2005. Serious opposition to the continued operation of the Mohave plant began in 1991 when the U.S. Congress directed the EPA to conduct a study of emissions released by the Mohave plant and their impact on visibility in the Grand Canyon. Environmental advocates had long argued that the plant was one of the largest point sources of sulfur dioxide (SO2) in the western United States resulting in visibility impairment at Grand Canyon National Park.³ Beyond the problems with its emissions, the Mohave Generation Station had long-standing contract disputes with the Hopi and Navajo Nations over water and coal use. The Mohave plant was the sole customer of Arizona’s Black Mesa mine, owned by the Hopi and Navajo Nations, the sole supplier of coal to the facility. Further, the boilers at the plant were configured to burn Black Mesa coal, which limited Mohave’s options to pursue other sources of coal supply.

Responding to concerns over the negative environmental effects caused by the Mohave Generation Station, the EPA embarked on an analysis of the impact the Mohave plant had on regional air quality. In its Project MOHAVE (Measurement of Haze and Visibility Effects), the EPA conducted experiments in 1992 to assess the extent to which visibility impairment at the Grand Canyon could be attributed to the Mohave Generation Station.⁴ In 1999, the EPA released its final Project MOHAVE report. The report concluded that SO2 emissions released by the Mohave Generation Station were transported to the Grand Canyon and that emissions from the Mohave Generation Station contributed to visibility impairment at the Grand Canyon. The study also concluded that the Mohave Generation Station was not the major cause of visibility impairment at the Canyon although no other single source accounted for a greater impact upon Grand Canyon visibility than the Mohave plant.

The Clean Air Act Amendments of 1977 requires that when determining that visibility impairment in a Class I area,⁵ such as the Grand Canyon, can be reasonably attributed to a specific facility, the EPA must determine an appropriate pollution control requirement, known as “Best Achievable Retrofit Technology” (BART), for the facility.⁶ The consequent 1999 consent decree required the Mohave Generation Station to install pollution control equipment that would significantly reduce its nitrogen oxide (NOx), SO2, and particulate matter emissions by the end of 2005 or to shut the plant down by the end of 2005. The consent decree also required the station to renegotiate its water and coal contracts. Under the terms of the consent decree, the Mohave Generation Station was to install scrubbers to reduce SO2 emissions from each of the two boilers by 85 percent. Each boiler was also required to meet an SO2 emission limit of 0.150 lbs per million British thermal units (Btu). The installation of baghouses was also required to reduce particulate matter emissions and to meet an air opacity (a measure of plume density) limit of 20 percent. In order to reduce NOx emissions, new burners were to be installed. The estimated cost of this equipment to all of the owners of the Mohave Generation Station was $1.2 billion. Although for several years the owners of the Mohave Generation Station indicated that they intended to continue its operations, the plant went out of service on December 31, 2005, resulting in a 59-percent reduction in Nevada’s coal-based electricity generation.⁷

In addition to its airborne emissions, the Mohave Generation Station had considerable land and water environmental issues. Annually, the Mohave plant used almost 5 million tons of coal and over 4,000 acre-feet of water to transport coal to the plant via slurry pipeline. An additional 19,000 acre-feet of Colorado River water was used for steam and cooling. The Mohave plant had a unique coal supply system, using a 275-mile slurry pipeline (the only pipeline coal delivery system in the world) to transport bituminous coal from the Black Mesa mine, located on Navajo and Hopi lands in northeast Arizona. The slurry pipeline, most of which is buried, is the largest in the country. The Navajo Aquifer provided water to the slurry. The aquifer is also located beneath land owned by the Navajo and Hopi Nations. There have been contract disputes concerning coal royalties and use of the aquifer between the two Indian Nations and Peabody Energy, the firm that leases the mine, and Black Mesa Pipeline Company.

Figure 2. Nevada Electricity Production Fuel Shares, 1990, 2000, 2006

Source: Energy Information Administration, Form EIA-923 "Power Plant Operations Report" and predecessor forms.   Figure Data

Nevada’s Dash to Natural Gas

Most of the electricity production lost due to the closure of the Mohave Generation Station has been replaced by new natural-gas-fired generation, particularly in Nevada.⁸ Even prior to the cessation of operations at the Mohave Generation Station, Nevada had markedly increased its dependence on natural gas as a fuel for electricity supply. During the early part of the current decade Nevada, like many other areas in the United States, experienced a boom in new natural-gas-fired electricity generation capacity. Between 2000 and 2006, natural-gas-fired electricity capacity more than doubled.⁹ In 1990, natural gas accounted for only 10 percent of Nevada’s electricity generation while coal maintained a 75-percent share (Figure 2). In 2005, natural gas had supplanted coal as the State’s largest source of electricity generation. The closure of the Mohave Generation Station, which accounted for 26 percent of total Nevada electricity generation in 2005, led to a sharp increase in natural gas, which provided two-thirds of electricity generation in the State in 2006, while coal’s share fell to 23 percent of the total.

California Imports Largely Unaffected by Mohave Closure

Although two-thirds of the Mohave Generation Station was owned by California power producers, the plant provided a relatively small share of California’s electricity. California’s overall electricity imports are another matter. Typically, California relies on electricity imports for one-fourth to one-third of its electricity supply.¹⁰ Of the electricity imports in 2008, coal-based imports represented 40,348 MWh, or 44 percent of the total. Closure of the Mohave plant contributed to a slight reduction in overall California electricity imports. Prior to closure of the Mohave Generation Station, California electricity suppliers owned 4,353 MW of out-of-State coal electricity capacity.¹¹ This capacity, located in the States of Arizona, Nevada, New Mexico, and Utah, was built largely to serve California markets.¹²

Recent California legislation places future limits on the amount of CO2 California can “import” from other States via electricity purchases.¹³ In June 2008, the Los Angeles Department of Water and Power announced that it would not be drawing on power from its Navajo coal-fired plant in Arizona after 2018.¹⁴ After building little in-State capacity during the 1990s, California has added about 11 gigawatts of natural gas capacity since 2000, increasing the total installed summer capacity by about 21 percent.

Electricity Price Trends Reflect Loss of Cheap Generation

While electricity supply has managed to accommodate Nevada’s rapid economic growth despite the Mohave closure, Nevada’s electricity consumers are experiencing price increases greater than the national average. Electricity prices in Nevada prices ranked 12th lowest among the 50 states in 1990; by 2006, Nevada’s prices were 35th lowest.¹⁵ In 2006, retail prices averaged 9.6 cents per kilowatthour versus 8.9 cents per kilowatthour for the Nation as a whole. The move towards greater reliance on natural gas as a source of electricity supply and less reliance on coal has contributed to this increase in electricity prices for Nevada consumers.

Higher fuel costs lie behind the run up in rates. In 1990, Nevada paid $1.49 per million Btu for coal used in electricity generation.¹⁶ By 2006, this value had risen modestly, to $1.73 per million Btu (MMBtu).¹⁷ By way of comparison, natural gas used in electricity generation, which cost Nevada $1.96 per million Btu in 1990, had risen to $6.53 per million Btu in 2006. With the closure of the Mohave at the end of 2005, the Nevada Power Company reported that its average fuel costs rose 100 percent between 2005 and 2006.¹⁸ Reflecting the recent loss of low-cost coal generation, residential electricity prices jumped 9 percent between 2005 and 2006. In 2005, the year prior to the Mohave closure, coal accounted for 62 percent of Nevada Power’s total fuel requirement (Table 2) at an average cost of $1.59 per MMBtu. In 2006, at a cost of $7.40 per MMBtu, natural gas accounted for 59 percent of Nevada Power’s electricity fuel bill, and even with lower natural gas prices in 2007, the share of natural gas continued to rise, reaching 64 percent.

In addition to having to replace the relatively cheap coal-based power with relatively higher-cost natural-gas-fired generation, regulators in Nevada and California and the Board of Directors of the Salt River Project allowed deferred recovery of the undepreciated value of the plant and associated termination costs through higher electricity rates by creating regulatory assets. For instance, in the case of the Salt River Project, under Statement of Financial Accounting Standard (SFAS) No. 71- Standards for Rate Regulated Enterprise, the Board of Directors, as Salt River Project’s regulator under SFAS No. 71, created a regulatory asset to be recovered over a 10-year period, starting in 2006.¹⁹ The loss of the Mohave plant should have had a significant impact on the owner utility’s fixed cost as construction of the power plant was completed 35 years ago and largely depreciated, while much of the capacity providing replacement power was completed relatively recently.

Although the closure of the Mohave Generation Station amounted to a significant reduction in electric generating capacity for Nevada Power Company, several newly-built and acquired power plants have done much to replace this lost capacity on top of meeting Nevada’s additional load growth. Currently, both Nevada Power Company and Pacific Resources are adding substantial electricity production capacity, by building new units, by expanding existing units, and through purchasing existing power plants. According to Sierra Pacific Resources’ 2007 annual report, between 2003 and 2007 Sierra Pacific Power Company and Nevada Power have either purchased or completed construction of generating facilities or peaking units with a combined summer capacity of 1,574 MW.²⁰ In January 2006, Nevada Power Company completed the 580-MW natural-gas-fired Chuck Lenzie Generating Station. Also during January 2006, Nevada Power Company purchased a 75-percent ownership interest in the Silverhawk Generating Station. Silverhawk is a 514-MW natural-gas-fired combined-cycle plant. In 2007, construction began on two peaking units at Nevada Power’s Clark Station, which will add an additional 626 MWs. These units commenced commercial operation in July 2008. Also in 2007, construction began on an additional unit adding 500 MW of capacity to Nevada Power’s Harry Allen Station.²¹ In April 2008, Nevada Power announced that it had reached an agreement with Reliant Energy, Inc. to purchase Reliant’s 570-MW Bighorn Generation Station.²² The newly-purchased plant began operations in 2004. In July 2008, Sierra Pacific Power Company completed construction of the 733-MW Tracy Combined Cycle Plant, located east of Reno. Rapid growth in additional power supply is expected to continue. Between 2008 and 2013, Nevada is expected to add 4,255 MW of new generation capacity (Table 3).

On February 9, 2009, Nevada Power issued a press release announcing the postponement of the 2-unit, 1,500-MW Ely Energy Center. Environmental and economic uncertainties and the lack of commercially available carbon capture and sequestration (CCS) technology were cited as main reasons for the decision.²³ Nevada Power indicated that permitting delays associated with the Ely Energy Center contributed to the decisions to construct the Harry Allen Plant and to acquire the Bighorn Generating Station (renamed the Walter Higgins Generating Station following the acquisition) from Reliant Energy to meet electricity demand in southern Nevada.

Electricity Trade Reversal

Even with the additional capacity cited above, after closing the Mohave Station, Nevada became a net importer of electricity in contrast to earlier years when the State was a substantial exporter of electricity. In 2006, Nevada imported a net 5,625 million kilowatthours versus net exports of 5,818 million kilowatthours in the prior year (Table 4). In 2005, Nevada exported 17 percent of its electricity production as reflected by the 1.17 net trade index. In 2006, it imported 15 percent of its load requirements, which is represented by the 0.85 net trade index. However, recent data on interstate power flows among Nevada’s neighbor States show little evidence of any major realignment in their electricity trade balances. One possible explanation for this is that the California market is so large relative to that of Nevada that any reversal in power flows between the two States would have a negligible effect on California’s electricity trade balance. However, Nevada’s changed status as a net electricity importer is reflected in the purchased power costs of Nevada Power Company. These costs rose from $223 million in 2005 to $345 million in 2006, a gain of 55 percent.²⁴

With the anticipated addition of new capacity in 2008 and beyond in Nevada, it is likely that imports, as reflected by the net trade index will decline. California has been a consistent importer as compared to New Mexico, Arizona, Utah, and Nevada before the shutdown of the Mohave Station. This is because of California utilities’ ownership of undivided interests in baseload power plants located in these States. These plants include the Palo Verde Nuclear Plant in Arizona, the Intermountain Power Project in Utah, and the Four Corners Power Plant in New Mexico.

Emissions Impacts

The closure of the Mohave Generating Station has led to a significant decline in Nevada’s electricity-related emissions. In 2005, the Mohave plant accounted for 42,000 tons of SO2, 21,000 tons of NOx, and 11,000,000 tons of CO2, which amounted to 79 percent of the State’s SO2 emissions, 48 percent of the State’s NOx emissions, and 39 percent of the State’s CO2 emissions created by the electricity sector. From 2005 to 2006, State electricity-related SO2 emissions dropped 36 percent. NOx and CO2 emissions fell 83 and 20 percent, respectively. Still, the Las Vegas valley is currently designated by the EPA as a non-attainment region for particulate matter and carbon monoxide, although, in part, these emissions are caused by economic sectors besides electricity.

Conclusion

Nevada has seen rapid economic and electricity demand growth over several decades. Due to relatively low natural gas prices, the State expanded its natural-gas-fired electricity supply markedly over the past decade. Meanwhile, Nevada’s reliance on coal, both due to increased natural gas usage and the closure of the Mohave Generation Station, has waned. Nevada’s largest electricity supplier, the Nevada Power Company, relied on the Mohave Generation Station for 17 percent of its electricity supply. This loss, however, was made up for by additional natural-gas-fired generation, reduced power exports, and increased imports. Reflecting the loss of relatively low-cost coal generation, electricity prices rose substantially. The shutdown of the Mohave plant, however, had a positive impact upon the State’s electricity emissions.

Ultimately, it was a business decision that led to the closure of the Mohave Generation Station. From the perspective of the plant owners, the significant expenses related to the installation of pollution abatement equipment along with issues related to fuel supply outweighed the incremental costs of finding alternative sources of power. The Mohave Generation Station was closed due to concerns about the high levels of SO2, NOx, and particulate matter resulting from plant operations, a situation common to many of the Nation’s older coal-fired plants.

State and regional programs to limit or reduce emissions of CO2 and other greenhouse gases and the possible future implementation of a Federal “cap and trade” program for greenhouse gases that is now being considered by Congress could also increase the cost of operating coal-fired plants. The experiences following the closure of the Mohave Station provides some insights into the type of impacts that may occur in regional electricity markets if and when these initiatives result in the closure or reduced utilization of other existing coal-fired generation plants. Even so, the economics of coal-fired generation suggest that closing coal plants will not be achieved without difficult tradeoffs.

¹ Although the Mohave plant has been shut down, it has not been decommissioned.
² The Salt River Project is one of Arizona’s largest electric utilities.
³ In 1998, the Grand Canyon Trust, Sierra Club, and National Parks and Conservation Association filed a lawsuit alleging that the plant routinely violated its air opacity limits and that the owners of the plant claimed exception to these limits during startups and shutdowns which were not included in the plant’s operating permit. The plaintiffs reached a consent decree with the owners of the Mohave Generation Station, with the owners pledging to either install pollution controls or to shutter the plant.
⁴ The study was principally funded by the Environmental Protection Agency, the National Park Service, and Southern California Edison.
⁵ In Section 169A of the 1977 Clean Air Act Amendments, the U. S. Congress set as a national goal, “the prevention of any future and the remedying of any existing impairment of visibility in mandatory Class I Federal areas which results from manmade air pollution.” Section 169A required that the EPA to implement regulations to ensure that reasonable progress toward meeting the Class I air quality goals were achieved. The EPA identified 156 Class I areas, of which the Grand Canyon National Park was included. In 1980, EPA promulgated visibility regulations requiring States to develop and implement plans for addressing visibility impairment in national parks and wilderness areas.
⁶ Environmental Protection Agency, Final Mohave Report Fact Sheet, http://www.epa.gov/region09/air///mohave/mofact.html.
⁷ Energy Information Administration, Form EIA-860, “Annual Electric Generator Report.”
⁸ In part, this also reflected a strategy by Nevada Power to rely more heavily on company-owned plants as a source of electricity.
⁹ Energy Information Administration, State Electricity Profiles, DOE/EIA-0348(01)/2 (Washington, DC, November 2007), p. 142, Table 4.
¹⁰ State Electricity Profiles, 2006, DOE/EIA-0348(01)/2 (Washington, DC, November 2007), p. 145, Table 10.
¹¹ California Energy Commission, http://www.energy.ca.gov/electricity/coal_plants_ownership.html. Accessed 6/30/2008.
¹² California Energy Commission, http://www.energy.ca.gov/electricity/coal_plants_owwnership.html.
¹³ See California Assembly Bill 32.
¹⁴ Los Angeles Department of Water and Power holds a 21-percent interest in the Navajo plant.
¹⁵ Prices reflect average retail price for all sectors. Source: Energy Information Administration, http://www.eia.doe.gov/cneaf/electricity/page/sales_revenue.xls.
¹⁶ State Electricity Profiles, DOE/EIA-0340(01)/2 (Washington, DC, November 2006), p. 143, Table 6.
¹⁷ These values are presented in nominal dollars. In inflation-adjusted dollars, price levels were 43 percent higher in 2006 relative to 1990, which means Nevada actually experienced a decrease in electricity prices in real terms.
¹⁸ Sierra Pacific Resources, 2007 Annual Report, p. 66.
¹⁹ Salt River Project, 2008 Annual Report, Note 9 to Financial Statements, pp. 42-43. The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 71, “Accounting for Certain Types of Regulation,” in 1982. SFAS No. 71 permits regulators to defer and permit recovery of expenses in subsequent time periods, including depreciation expense, which would have been the method by which Salt River Project would have recovered its remaining investment in the Mohave Generating Station. Regulators may allow a utility to earn a return on the unamortized balance of a regulatory asset. SFAS No. 71 provides that the board of directors is the applicable regulatory authority if an entity is not subject to regulation.
²⁰ Sierra Pacific Resources, 2007 Annual Report, p. 44.
²¹ Sierra Pacific Resources, 2007 Annual Report, p. 5.
²² “Update 1-Nevada Power to Buy Reliant’s Bighorn Plant.” Reuters, http://www.reuters.com/article/companyNews/idUSN2235473120080422. http://www.reuters.com/article/bondsNews/idUSN2235473120080422. No capacity is expected to come into service during the years 2009 and 2012.
²³ “NV Energy Postpones Construction of Coal Power Facility in Nevada; Plans to Expedite North-South Transmission Line”, http://investors.nvenergy.com/phoenix.zhtml?c=117698&p=irol-newsArticle_Print&ID=1254617&highlight, February 9, 2009.
²⁴ Federal Energy Regulatory Commission, FERC Form No. 1: Annual Report of Major Electric Utilities, Licensees and Others, 2005, 2006 and 2007.