Aggressive effort puts NVE among nation’s renewables leaders

NV Energy and its predecessor companies have embraced renewable resources since their founding. Long before it was fashionable to be “green”—1899 to be exact—Sierra Pacific Power Co built the first generating station on the east side of the Sierra Nevada range, a hydro plant on the Truckee River. More than 90% of the electricity the company generated over the next six decades came from hydro resources.

Sierra Pacific’s interest in renew­able resources never waned. Twenty-five years ago, it purchased electric­ity from Nevada’s first geothermal powerplant at Wabuska, in Lyon County. The facility, which used a binary cycle to recover geothermal heat, was rated at 600 kW.

How times have changed. Today NV Energy is required by law to pro­duce or buy from renewable sources a specified percentage of the kilowatt-hours it sells customers. Nevada’s Renewable Portfolio Standard (RPS) was one of the first such laws in the nation when it passed in 2001; today more than two-dozen states have an RPS and federal legislation may not be far off.

NV Energy exceeded the 2008 RPS goal assigned to it by the state—9% of retail energy sales generated from renewable resources or saved through the utility’s demand-side manage­ment program (DSM).

Current law requires NV Energy to increase the renewables compo­nent of its generation mix through 2015. That year 20% of kilowatt-hour sales must come from renewable resources; DSM savings can account for up to one-quarter of the com­pany’s portfolio credits. Definition: One portfolio credit (PC) is awarded for each kilowatt-hour of renewable energy generated or each kilowatt-hour of energy saved through the DSM program. Another requirement of the RPS is that 5% of the PCs must come from solar resources.

NEWS FLASH: As the COMBINED CYCLE Journal went to press, the Nevada legislature signed into law the following new RPS goal for inves­tor-owned utilities: 25% of kilowatt-hour sales from renewable resources in 2025. Plus, by 2016, 6% of the RPS must come from solar resources.

Stop. Do you find yourself ask­ing, “Why am I reading about renew­ables in a magazine dedicated to gas-turbine-based powerplants?” If so, that’s understandable. The explanation: The two renewables getting the most attention these days, solar and wind, are intermit­tent resources. This means that if clouds happen by or the wind stops blowing the lights theoretically could go out if you don’t have another type of generat­ing unit available.

NV Energy has studied the impact of renewables on energy supply and grid operations extensively over the last several years as it compiled a portfolio of solar assets that today rank the company second among utilities nationwide in solar electric capacity per customer and third in total solar capacity.

One of the steps NV Energy has taken to respond quickly to discon­tinuities in renewables generation, and also to meet peak customer demand, was to install 600 MW of fast-start gas-turbine (GT) assets at the Edward W Clark Generating Station, located within Las Vegas’ city limits. Read about that project, which was com­pleted early this year, in the follow­ing article.

When configured for low emis­sions (the Clark aeroderivative GTs are permitted for 5 ppm NOx and 2 ppm CO) and located near the load center, compact aeros are a leading choice to back up renewables gen­eration. There certainly are many other options—for example, operate a combined cycle in the unfired mode and use duct burners to quickly ramp up generation when renewables are handcuffed by Mother Nature—but GTs generally will be the lowest-emissions alternative.

Another reason for introducing GT professionals to renewables concerns career development. When new tech­nologies are introduced, leadership is provided by inventors, scientists, developers, marketers. But when promising technologies mature to the point of commercial viability, the leadership baton gener­ally is passed to those respon­sible for the business units where the technology will be applied.

Example 1: The executive responsible for renewable energy at NV Energy is Vice President Thomas R Fair, a 35-yr veteran of the electric power industry with a solid background in utility oper­ations. He reports directly to President/CEO Michael W Yackira, illustrating the importance of renewables in the company’s energy supply strategy.

Example 2: The director of project development and production applications for renewables is Jim Doubek, who managed the largest combined-cycle in the utility’s fleet—the 1100-MW Chuck Lenzie Generating Sta­tion (see Section 7)—before receiving this promotion.

One reason for Doubek’s appoint­ment is that the future of solar (thermal) power from an economic perspective may be strongly influ­enced by the ability to integrate the solar field with an existing or new combined-cycle plant. For the record, such integration could be accomplished with other types of generating facilities, but the pow­erplants most likely to found/built where solar insolation is highest are GT-based because they require the least amount of water.

Renewables portfolio

NV Energy’s renewables portfolio is summarized in Fig 3-1, which was filed as part of the company’s “Portfo­lio Standard Annual Report” for com­pliance year 2008. All projects are in service except for Nos. 7, 12, 21, and 34, which are under construction, and Nos. 3, 4, 5, and 35, which are in active development. Most facilities are owned by others and under long-term contract to NV Energy. The company has a direct investment in one geothermal project as well as in the waste-heat recovery and wind projects.

Geothermal projects dominate for good reason: Nevada ranks second nationally, behind California, in geo­thermal resources. Note that geother­mal and wind resources dominate in the North; world-class solar in the South. Biomass/methane and hydro resources are limited in this state. Fig 3-2 illustrates the opportunity for solar power in the Las Vegas area. It offers greatest potential when power is needed most—in the afternoon of a summer day.

The map also shows the 500-kV transmission tie under development to link the company’s northern and southern generation assets. The line, planned for commercial service by the end of 2012, will greatly increase the operational flexibility of the com­pany’s generation assets and enable renewables development in locations not currently practicable.

As Fair pointed out to the editors, a big difference between conventional generation and renewables is that for the former you bring fuel to the plant; for the latter, you build transmission to where the resources are.

NV Energy continuously evaluates proposals from renewables develop­ers, relying on Black & Veatch to weigh their viability using a score­card that includes price, project read­iness, qualifications and experience of the developer, transmission access, etc. Fig 3-3 compares the levelized cost of electricity production from alternative renewable resources.

Project evaluation is a dynamic activity for several reasons, including the following:

  • Volatility in renewables devel­opment activities. The dramatic increase in construction costs over the last couple of years and the dif­ficulty in borrowing capital caused some developers to withdraw their proposals and others to increase their bids.
  • Delays. Projects in development and under construction are sub­ject to delays, so the company needs more projects in the pipe­line than might seem necessary at first glance.
  • Sales growth. Any increase in energy sales—caused, perhaps, by an especially hot summer not forecast—requires more kilowatt-hours from renewables (the RPS offers no “wiggle room”).
  • Hidden variables. Geothermal projects, in particular, are sub­ject to the vagaries of exploration, which is far from an exact science. In brief, what you think you have might not be entirely accurate. Furthermore, geothermal assets have a finite lifetime at their ini­tial output. Decay in production capability is a reality and peri­odic well enhancements often are needed to maintain output. One note in the utility’s 2008 compli­ance report mentions “significant underproduction from a number of geothermal plants under contract to NVE.”
  • Changing weather patterns may mean a periods of less or more sunshine, less or more wind. Utili­ties in states with RPSs must pro­tect against downside risk.


That Southern Nevada has world-class solar resources is evident in Fig 3-4. The impact of clouds on renew­ables production on a typical July day is presented in Fig 3-5. Fair said that clouds have greater immediate impact on photovoltaic (PV) solar plants, where sunlight is converted directly to electric power, than they do on solar thermal projects.

The cornerstones of NV Ener­gy’s solar resources are the 64-MW Nevada Solar One project and the 12-MW photovoltaic installation at Nellis Air Force Base, a few miles from the Las Vegas Strip. Both plants began commercial operation in 2007.

Nevada Solar One, which cov­ers 400 acres in Boulder City, relies on concentrating solar power (CSP) technology and is the third largest such plant in the world. It was built by Acciona North America and uses 760 parabolic troughs (Fig 3-6) with more than 182,000 mirrors to con­centrate the sun’s rays onto 18,240 receiver tubes. The thermal fluid flowing through the tubes reaches 735F before giving up its heat to make steam that drives a conven­tional turbine.

The PV installation at Nellis con­sists of 70,000 panels covering 140 acres (Fig 3-7) and meets one-quarter of the AFB’s electricity needs. It was built by SunPower Corp, San Jose, Calif, which is now constructing a 25-MW facility of the same type in Florida. The 25-MW plant reportedly will be the largest in the US when complete.

Looking ahead, NV Energy and Solar Millennium LLC, Berkeley, Calif, have entered into a memoran­dum of understanding for the poten­tial development of one or more solar power facilities in Southern Nevada. The first project under consideration is a 250-MW plant using solar trough technology at a Nye County site.

It would include thermal storage, enabling operation beyond daylight hours during the summer months. Goal is to have the project operat­ing by 2013—subject to permitting, financing, and timely approvals by government agencies.

Solar/CC integration. Perhaps of greatest interest to readers of this paper is the work NV Energy is doing to evaluate the potential for integrat­ing solar thermal energy into exist­ing powerplants. Where feasible, addition of solar energy would reduce the consumption of conventional fuel while eliminating the need for the renewable-energy facility to install equipment to convert heat energy to electrical energy. Easier permitting is another perceived benefit.

One integration idea is shown in Fig 3-8. Another is to make steam from solar heat in a separate unfired boiler and inject it directly into the steam turbine downstream of the main admission point. Doubek said NV Energy was not currently inves­tigating the latter option. Consensus view is that making solar steam and combining it with steam made by the HRSG just ahead of the superheater is the option to pursue.

To what degree a given combined cycle can accept solar steam requires careful evaluation of heat-transfer surface, HRSG design, etc. Doubek said the concept was doable from a technical perspective but that it was not as simple as just replacing steam produced by duct burners with that from the solar boiler—a combination of both appears most likely.

“It all boils down to how optimized your HRSGs are,” he continued. Do they have any “reserve” capacity? Work at Lenzie suggests that for that plant, a practical maximum for solar steam is about 40 MW per power block.

The utility is approaching its eval­uation from two directions:

1. It has retained Zachry Engi­neering to model the steam cycles at the existing Lenzie Station and the Allen combined cycle under construc­tion. The engineering review based on the models developed will focus on the capabilities and limitations of the existing equipment and the constraints associated with accepting solar energy. Manufacturers of the heat-recovery steam generators for both plants also will participate to assure compliance with their respec­tive design criteria and to verify materials integrity.

2. Participation in an industry project coordinated by the Electric Power Research Institute (EPRI), Palo Alto, Calif, to identify and evalu­ate the technical and economic viabil­ity of solar-augmentation options for steam-cycle designs. The effort includes the preparation of develop­ment guidelines for at least two case studies. Lenzie is one host.

Possible sites for solar collectors adjacent to both Lenzie and Allen are under evaluation. A preliminary plan of development for solar augmenta­tion at both plants has been submit­ted to the federal Bureau of Land Management.


A wind-resource map for the US will tell you that most development will occur on the coasts and in the Mid­west. There are opportunities else­where, to be sure, but they generally are limited.

Wind gets high visibility in virtu­ally every green speech, media report, etc, which might lead you to believe it is a panacea. Not. Consider the data in the “World Wind Energy Report 2009” recently published by the World Wind Energy Assn, Bonn, Germany—no unbiased source.

Total global installed wind capac­ity at the end of 2008 was a nominal 120,000 MW. The group’s very opti­mistic prediction is that this number would double by the end of 2020—worldwide. Perspective: In only five years (2000-2004) 200,000 MW of gas-turbine-based capacity alone was installed just in the US.

The chart in Fig 3-9 shows just how dramatically wind generation can vary over a short period of time and why several industry presenta­tions by representatives of the lead­ing US wind-turbine manufacturer have urged wind-farm developers to buy one or more of the company’s GTs with their WTs (Fig 3-10). These data were collected at a site being evaluated by NV Energy.

NV Energy has a two-part strat­egy regarding wind project develop­ment:

  • Identify commercially viable sites under development by others for consideration as joint ventures.
  • Evaluate its own candidate wind-development sites, acquire prop­erty rights where prudent, install diagnostic instrumentation to quantify the wind resource, and conduct engineering and economic feasibility studies.

The company’s most advanced wind project is at China Mountain on the Nevada/Idaho border, planned for commercial operation in 2012. NV Energy entered into a joint develop­ment agreement with RES Americas Inc, Broomfield, Colo, and recently closed on the acquisition of 50% of the project development assets.

The 200-MW project is on a 30,000-acre site considered topographically unique—essentially a 14-mi bluff running north/south. The abrupt elevation change as the wind moves west to east off the bluff accelerates the wind, making this site unusually energetic, relative to many others in the region.

Engineers foresee a nominal six turbines per linear mile along the bluff. Final layout depends on the particular turbine model selected. A gravel road network will be built to enable access during construction and operation. The turbines will be electrically connected using 34.5-kV underground cable. Send out will be at 138 or 345 kV.


Geothermal energy consistently has been among the lowest-cost renew­able resources available in Nevada. It also is firm base-load energy, giving it an advantage over the intermit­tent solar and wind resources. But, as mentioned earlier, these resources typically degrade over time, some significantly.

Geothermal resources comprise about three-quarters of NV Energy’s renewables portfolio because Nevada is a “hot” state (Fig 3-11). The com­pany actively pursues project owners with substantial land control and a resource capable of supporting more than 20 MW of generation.

NV Energy received fewer geo­thermal bids in response to its 2008 renewables RFP than it had the previous two years. However, BLM (Bureau of Land Management) leas­ing activity was strong last year and the company expects more geother­mal bids going forward as projects develop and owners are comfortable making formal bids. By contrast, there was a substantial increase in both the number of wind projects bid in 2008 and in project size.

In the geothermal sector, NV Energy works closely with Ormat Technologies Inc, Reno, which owns more than 100 MW of geothermal resources in Nevada and double that in neighboring California. The util­ity buys a significant portion of its “green” electricity from Ormat and is partnering with the renewables developer on a couple of projects.

NV Energy works with other geo­thermal developers as well. To illus­trate: Two major projects (Nos. 12 and 21 in Fig 3-1) nearing completion that will provide the utility 70 MW under a long-term agreement are being built by ENEL North America, a subsidiary of the respected Italian utility and one of the world’s leading electric companies.

Ormat is a multi-faceted company that designs, manufactures, owns, and/or operates geothermal facili­ties worldwide in both high-enthalpy steam fields and low-enthalpy water-dominated resources. The latter are prevalent in Nevada.

To extract energy from water-dominated resources, Ormat relies on the organic Rankine cycle (ORC, sidebar). The company uses the same technology to recover heat from GT exhaust streams, which it calls recov­ered energy generation. REG quali­fies as renewable energy in seven states at present, including Nevada.

One of Ormat’s businesses is the design and manufacture of process heat-transfer equipment (to the ASME Boiler & Pressure Vessel Code) and 1800-rpm multistage turbines for ORC applications pursued both by its project development group and oth­ers. The company buys generators, pipe, valves, and other conventional equipment required to complete the energy-conversion system.

Goodsprings REG. A quick look back at Fig 3-1 reveals the Good­springs Heat Recovery Project, listed as No. 34. This REG facility, under joint development by Ormat and NV Energy, will be 100% owned by the utility. NV Energy will assume responsibility for operations three years after commissioning.

Site location is a GT-based com­pression station on the Kern River natural-gas pipeline just outside the town of Goodsprings, Nev (about a dozen miles northwest of Primm and the Walter M Higgins Generating Station). Goodsprings is equipped with three 14,000-hp Mars® GTs manufactured by Solar Turbines Inc, San Diego. The 5.8-MW output from the REG will be delivered to the utili­ty’s transmission system via an exist­ing 24.9-kV tap to the station.

Ormat’s Roni Omessi, senior director of recovered energy, and Colin Duncan, manager of recovered energy, told the editors that REG is commercially viable over about 4 MW. Tax incentives and renewable energy credits facilitate financing. Goodsprings is expected in service by the end of 2010.

Omessi and Duncan said it typical­ly takes 15-18 months from a notice to proceed to commercial operation of an REG project. The Goodsprings REG will be constructed alongside the compressor station and after operational verification will be tied into the GT exhaust system. Installa­tion of equipment takes about two to three months and an outage of only a couple of days is all that’s required to connect the GTs to the ORC.

Goodsprings will be unmanned as other REG projects are; however, operating data will be monitored continually by Ormat’s M&D Center at company headquarters. Hands-on O&M personnel involvement is esti­mated at less than one person-day per week. ccj

ORC and how it converts heat into ‘green’ electricity

Most powerplant engineers are familiar with the Rankine cycle. Simply put, steam produced in a fossil-fired or nuclear steam generator is expanded in a turbine which drives a generator to convert the work into electricity. Disadvantages of using water as the working fluid are the possibility of it freezing and the need for a vacuum to make the cycle run efficiently.

By contrast, environment-friendly organic compounds—such as pentane—can perform the same function as water/steam but more effectively at lower heat-source tem­peratures. Thus an organic Rankine cycle (ORC) is better suited for recovering low-grade heat and con­verting it into electricity. This should not come as news: Several ORC plants ranging in capability from a few hundred kilowatts to a few megawatts have been installed over the last two decades and are gen­erating electricity using heat recov­ered from geothermal resources, industrial processes, diesel-engine jacket water, etc.

Cycle efficiency typically ranges from 10% to 20% depending on the temperature of the heat source. An economically viable, megawatt-size ORC system probably would require a heat source with a minimum tem­perature in the 280F-290F range. It would have to be located near the heat source and a cooling medium available to condense the vapor, and have access to a transmission line.

Ormat Technologies Inc, Reno, Nev, claims global leadership in ORC technology and relies on it to recover heat from geothermal resources and from gas-turbine exhaust streams. The company refers to the latter as recovered energy generation (REG). Ormat owns about 500 MW of geothermal capacity and has installed REG facilities as large as 20 MW. Its REG portfolio is expected to top 50 MW by year-end. Another 50 MW has been supplied to third parties.

An REG system works this way: Gas-turbine exhaust heat is trans­ferred to a thermal fluid circulating through the recovery unit shown at the left in Fig A. The hot thermal oil boils organic fluid (pentane, for example) in the vaporizer and then gives up some of its remaining heat to pentane in the preheater before returning to the recovery unit.

Vaporized pentane expands through the turbine and flows to the recuperator where it warms the organic working fluid returning from the air-cooled (as in the diagram) or water-cooled condenser. A storage/expansion tank accommodates any losses and maintains a constant head on the system. A typical project is shown in Fig B.

Advantages of the ORC over a conventional Rankine cycle include the following:

  • The expense of installing, operat­ing, and maintaining a water treat­ment system is eliminated.
  • The organic working fluid’s ther­modynamic properties allow much higher condensing pressures than are possible for steam. This per­mits use of shorter turbine blades and minimizes ingress of air into the system. Latter mitigates the need for vacuum maintenance.
  • The saturation curve for hydrocar­bons is such that the working fluid remains dry under all operating conditions—thereby eliminating the need for superheaters and the possibility of erosion damage to turbine buckets and nozzles often found in steam systems.

Geothermal ORC. The ORC used to recover heat from water-dominated geothermal resources is simpler than the one required for REG systems. For the former, hot geothermal fluid is pumped directly into the vaporizer (refer again to Fig A) and cascades through the preheater before it is rein­jected into the geothermal field. The recuperator used in REG systems is not necessary, even for very-low heat-source temperatures; organic liquid is piped directly from the condenser to the preheater.