Renewables already impacting NV Energy’s grid operations

NV Energy, which worked with CTOTF in developing the Integrating Renewables Workshop, brought its “A” team to the meeting to explain the challenges it faces and how it expects to satisfy the requirements of the state’s demanding RPS (Sidebar 6).

Senior VP of Energy Supply Jeff Ceccarelli welcomed attendees to Reno and gave a quick review of the utility’s history. NV Energy and its predecessor companies have been a catalyst for Nevada’s economic development since before the 20^th century.

The first electricity the utility produced was in the Reno area, host city for the workshop. It was used for lighting the mining town of Virginia City and for pumping water from the deep shafts of the area’s world famous silver mines. Thomas Alva Edison personally designed Virginia City’s first electric distribution system.

VP Generation Kevin Geraghty set a positive tone for the workshop and explained the integration challenge the company has in its northern territory. Note that NV Energy operates two independent grids today. Sierra Pacific Power Co built the northern grid and Nevada Power Co the southern grid before the companies merged in 1999. A north-south transmission line linking the two systems, named the One Nevada Transmission Line (or the shortened ON Line), is under construction and expected to be in commercial service at the end of 2012.

Geraghty began with his thoughts on change. “There has never been a time in this industry when there wasn’t change,” he said. The challenge, the executive continued, is to embrace change and accomplish the specified goals with minimum cost impact while maintaining service quality and making electricity production and delivery cleaner and safer.

Tall order for sure. But Geraghty reminded the group of how the industry had successfully adapted to wrenching change in the past. The Clean Air Act was one example. It dramatically changed coal-fired plant design and operation, first requiring unheard of (at the time) levels of particulate removal, then SO2 removal, then NOx destruction, then mercury removal, and so on.

The Clean Water Act again proved the industry’s capability to adapt to change. Plants built before the 1970s typically discharged water—except perhaps for oily drains—through a big pipe directly into a natural watercourse. Today many generating facilities discharge no liquids whatsoever beyond the plant boundaries.

Accommodating intermittent renewables, Geraghty said, was simply the generation industry’s next challenge.

Customer attitudes have changed over time as well. The VP recalled for the group “the early days,” when the customer requirement simply was “hook me up.” Next, customers wanted lower rates, more reliable service, faster hook-ups. Today many customers view the utility as a “safety net” for solar PV and other distributed generation tied to home and business operations.

Geraghty called for the industry “to rise and meet a new level of customer requirements.” Customers don’t want to hear about “intermittency,” power-quality issues, or any of the industry’s other challenges, he said. The electricity supply business was relatively easy in the “old days” Geraghty continued. Utilities had to grow the market, attract new customers, increase electric consumption. Today, “we’re selling efficiency, to help the customer reduce the cost of energy.”

Setting the stage for the next three NV Energy speakers, Geraghty reviewed challenges facing the company on its northern grid regarding integration of “must take” intermittent renewables at a time when demand is decreasing. The whole idea of “must take” can be viewed as a contradiction because a utility sometimes is obligated to take wind energy when no customer needs or wants it.

Richard Salgo, the company’s director of electric-system control operations, offered his perspective as a “grid operator.” He began with an overview of reserves, regulation, and balancing, some of which had been covered earlier by Clyde Loutan of the CalISO.

The basic function of a balancing authority (BA) is to continuously balance loads and resources within a metered boundary, he said. It must ensure that grid frequency is controlled and that all interchange is properly transacted. Also, that the BA does not become a burden to interconnected neighbors by over- or under-generating.

Salgo next put up the area-control-error equation (too detailed for this presentation; access www.integrating-renewables.org), calling it the “barometer of balancing performance.” You want the ACE to be zero, he said; if it’s negative (positive) number you must increase (decrease) generation.

Area load demand, satisfied by BA generation and interchange, traditionally has been considered out of the grid operator’s control. But that may not be true going forward, Salgo said, because the smart grid may enable load control at the customer—at least in some instances. Integration of intermittent renewable resources certainly will make BA generation far less predictable than it is today and complicate the management of interchange.

Spinning reserves, which provide both a portion of the BA contingency reserve requirement and the regulation room for preserving balance as load fluctuates, will have to meet more demanding requirements to accommodate the variability and/or intermittency of renewables. Ramp rates generally will have to be faster and operating ranges extended compared to spinning reserves serving conventional generation.

Operation of NV Energy’s northern grid is already constrained and renewable generation is only a fraction of what it will be in 2025. Example: Nighttime minimum demand can be as low as 700 MW to 750 MW and total production from required thermal assets operating at minimum load and “must-take” renewables already is at that level.

With demand flat, at best, given the economic slowdown, and the need to keep adding more renewables capacity to satisfy the RPS, the challenge is clear. Salgo said the only apparent solution today is to curtail wind production as needed during low-demand periods. Smart grid can’t help much, if any, because there’s little load that can be curtailed.

What the grid-operator expects of the generation fleet is more cycling capability, faster ramps, lower minimum loads, and the ability to make more frequent load adjustments. Demand-side expectations include improved load forecasting (a smart-grid deliverable), demand reductions to compensate for sudden dips in output from solar and wind resources (robust DSM capability), and load-shaping to approximate the expected renewable-portfolio supply curve.

Gary Smith, the company’s director of smart technologies just smiled at Salgo’s demand-side expectations as he walked to the podium. Smart-grid development is moving forward quickly under Smith’s direction as evidenced by the recent rollout of the utility’s Advanced Service Delivery (ASD) program. Foundation of this $301-million program, approved by the Nevada PUC last July 30: advanced metering and a 900-MHz communications network supported by 144 towers statewide.

NV Energy is a DOE grant recipient, so the federal government is chipping in $138 million for the purchase and installation of 1.3 million electric meters and 150,000 gas modules statewide. Meter installation is expected to take up to three years.

The ASD system—reliable, scalable, and secure—will enable customers to take ownership of their energy consumption eventually by scheduling energy purchases and taking advantage of off-peak discounts, etc. Smith showed the cutaway of a home a few years from now with solar PV on the roof, electric vehicles, home area network, demand-response capability, advanced metering, automated gas modules, etc. You can see it at www.integrating-renewables.org.

Operational benefits of ASD are estimated at about $35 million annually. Big savings are expected from eliminating about 17 million manual meter reads annually and from improved energy-theft detection. DSM programs also are expected to reduce generation requirements by 245 MW by the end of 2012, including commercial and industrial. Load control in residences and small commercial operations, peak-time rebates, programmable thermostats, and home-area networks are reducing demand by nearly 150 MW today. Goal is to double that number within a few years.

Dariusz Rekowski, director of fleet O&M and the last of NV Energy’s presenters, opened by acknowledging the grid operator’s expectations of generation and noting that providing dispatch flexibility to support grid stability and demand is conducive to lower operating efficiency, faster ramps, and more stop/start cycles.

They, in turn, contribute to lower capacity factor, increased wear and tear on parts, and a higher number of maintenance cycles. The result: higher O&M costs and outage timing adjustments. Rekowski said it was clear that the company had to spend its O&M dollars more wisely by adopting condition-based, rather than time-based, maintenance and to make better use of its workforce by moving people among plants for planned maintenance.

The former plant director of the company’s Clark, Sunrise, and Higgins generating plants said the challenges of running conventional assets to support renewables included the following:

• Higher emissions per megawatt-hour produced.
• Part-load operational issues.
• Transient-mode operation.
• Higher fuel consumption (higher heat rate).

Rekowski cautioned that more frequent cycling of conventional assets might introduce issues not seen in base-load service. Specifically, he was concerned about water chemistry/treatment effects, turbine water induction, safety, high-energy piping issues, etc.