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Power Purchase Agreements

The City of Santa Maria, a disadvantaged community in Northern Santa Barbara County, undertook a Power Purchase Agreement (PPA) with US Energy to utilize digester gas for energy generation. Initially relying on unreliable microturbines, the city transitioned to a 300 kW engine system that underwent rehabilitation in 2012. Despite improvements, challenges such as unexpected charges and emissions issues remain. This case study illustrates the importance of performance standards, realistic expectations, and the need for expert reviews for successful energy agreements.

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Power Purchase Agreements

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  1. Power Purchase Agreements The City of Santa Maria’s Experience October 23, 2012

  2. City of Santa Maria Statistics • Northern Santa Barbara County. • Disadvantaged community of 100,000. • Largely agricultural. • Secondary trickling filter treatment with anaerobic digesters, percolation ponds, sludge drying beds. • Design 13.5 MGD Currently 8.5 MGD. • Creative solutions to maintain affordability.

  3. History • 2004 - US Energy signed agreement with City for use of digester gas. • 2006 – Installation and start-up of four Ingersoll Rand microturbines completed. • 2007-2008 – System unreliable. Microturbines did not start up to handle varying demand. • 2008 – Microturbines replaced with 300 kW engine. US Energy cost ~$170,000

  4. History (continued) • 2008-2010 – Engine success variable. • 2011 – CHP Clean Energy takes over system. • 2012 – CHP rehabilitates engine and makes other improvements. Estimated cost ~$250,000. Starts back up July 2012.

  5. 2012 Improvements • Rebuilt engine. • Upsized exhaust manifold. • Replaced chiller. • Replaced control system. • Upsized hot water delivery system. • New air-fuel ratio sensors. • New blower, cooler pumps and intercooler.

  6. Elements of PPA Agreement • We provide them gas. • We buy their power at 8.7 cents per kWh. • They pay Departing Load Nonbypassable charges. • They need to run cogen in “efficient and effective manner.” • Term of contract is 10 years, with buyout provisions.

  7. How’s it working out? • Engine still experiences regular outages during partial peak and peak times. • Departing load charges “unanticipated” by CHP. Currently working on waiver. • Very low APCD emissions limits means high potential for lean fuel misfires.

  8. Is it paying off? • Since July 2012, Cogen facility has cost more than if on PG&E alone. • 100% PG&E: $24,100 • 100% Cogen: $16,100 • Currently: • PG&E: $8,300 demand, $7,900 use. • Cogen: $8,000 • Total: $24,200

  9. What would we do differently? • Performance standards! • Uptime criteria. • Demand charge responsibility. • Third party expert review of the design. • Cost evaluation prior to agreement. • Realistic expectations.

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