Hospital energy use in focus

Hospitals provide essential services to society - but many hospitals consume large amounts of energy in fulfilling their mission.  Newly released data shows that large hospitals tend to consume more energy per square foot than do other commercial buildings.

The data released by the U.S. Energy Information Administration last week comes from the 2007 Commercial Buildings Energy Consumption Survey (CBECS).  While 2007-vintage data may seem a bit stale in 2012, the 2007 survey results are the most recently-released from the CBECS program, providing an update to the 2003 survey.  The survey considered the consumption of electricity, natural gas, fuel oil, and district heat (steam or hot water from an outside source used for heating) by a variety of types of commercial buildings.

According to EIA, the roughly 3,040 large hospitals operating in 2007 - defined as those over 200,000 square feet - consumed 458 trillion British thermal units (Btu) of energy in that year.  Of this total energy budget, most came in the form of natural gas and electricity: 208 trillion Btu of natural gas, 194 trillion Btu of electricity, 6 trillion Btu of fuel oil, and 49 trillion Btu of district heat.

Altogether, large hospitals consumed about 5.5% of the commercial sector's total energy consumption in 2007.  On a Btu per square foot basis, the EIA data suggests that large hospitals' energy intensity exceeds that of other commercial building types, with large hospitals accounting for only 2% of commercial floorspace in 2003.

This energy intensity may not be surprising: hospitals are typically open around the clock, have high demands for heating, ventilation, and air conditioning, and are home to a variety of energy-intensive activities ranging from laundry and food service to sterilization and computer servers.  Hospitals' need for a high degree of electric service reliability have led 95% of large hospitals to use energy for generating their own electricity, mostly in the form of fuel oil-fired emergency back-up generation.

At the same time, most hospitals' consciousness about their energy footprint has led them to pursue energy efficiency.  The EIA data shows that most large hospitals have energy management and conservation plans, and use energy-saving products like compact fluorescent lights or sophisticated services to reduce their consumption of electricity.

Still, the EIA data suggests that large hospitals still have room for improvement.  What more can hospitals do to reduce their energy footprint and its associated costs, while continuing to provide the services society demands?

FERC issues wave energy license

Federal energy regulators have issued a license to a wave energy project off the Oregon coast.  If built as proposed, the project could be the first grid-tied commercial-scale wave energy project in U.S. waters.

A sailboat cruises past the Bear Island Lighthouse near Northeast Harbor, Maine.

Last week the Federal Energy Regulatory Commission issued a license (76-page PDF) to Reedsport OPT Wave Park, LLC for the ocean energy project.  In its license application filed in January 2010, the Ocean Power Technologies, Inc. subsidiary proposed a buoy-based wave energy conversion project to be located about 2.5 nautical miles off the coast of Reedsport, in Douglas County, Oregon.  Water depths in the project area range from about 204 to 225 feet.

According to the FERC order issuing the project's license, the project will generate electricity from using ten PowerBuoy wave energy converters anchored to the seafloor.  Each buoy will have a 150 kilowatt nameplate capacity; physically, each buoy has a maximum diameter of 36 feet, extends 29.5 feet above water, and has a draft of 115 feet.
 
The marine renewable energy project will be built in two phases.  In the first phase, a single PowerBuoy will be installed; this will enable the developer to test the mooring system and buoy operation, as well as to study the electromagnetic fields and acoustic emissions produced by the project.  This single buoy will not be connected to the grid.  After at least one season of monitoring this single buoy, the developer will add up to nine additional PowerBuoys and connect the array to the mainland grid. The ten buoy units will be deployed in an array of three rows about 330 feet apart, with a footprint of about 30 acres.

The developer reportedly expects to install the first buoy by the end of 2012, with the remaining generators to be installed by 2015.  FERC's license for the project has a term of 35 years.

MA net metering expands under new law

Massachusetts legislation signed into law earlier this month provides a variety of incentives for renewable generation in the northeastern US and adjacent Canadian provinces. Senate Bill 2395, An Act relative to competitively priced electricity in the Commonwealth, expands opportunities for net metering, a practice whereby electricity consumers can spin their meters backwards and offset the cost of electricity they buy by producing renewable power themselves.

Under existing Massachusetts law, qualified retail electricity customers who own distributed power generation equipment like solar photovoltaic panels have the right to sell excess power to their local utility at the same retail rates the customers pay to buy power from the utility.  In essence, this allows customers to offset their utility bills for purchasing power by producing more power than the customer needs.  This can be a powerful incentive for customers to develop distributed generation projects, because the retail rates utilities must pay for net metered power are typically higher than the wholesale rates otherwise available to distributed generators.

To limit the size of this incentive, previous law capped net metering to 3% of each utility's historic peak energy load.  Privately-owned equipment like solar panels on businesses or homes was capped at 1% of historic peak load, while publicly-owned facilities (schools, governmental buildings, etc.) were capped at 2%.

The new law doubles the amount of consumer-owned generation eligible for net metering, raising the private and public caps to 3% each.  This amounts to a tripling of the amount of privately-owned distributed generation eligible for net metering.

The law also allows anaerobic digestion to qualify for net metering.  This expansion of eligible technologies is likely to spur the expansion of projects that convert food, farm, and other organic waste to biogas for combustion in engines or turbines connected to electric generators.

An anaerobic digester located on a farm in New England.  The digester breaks organic waste down into biogas that can be used to produce renewable electricity.

As I noted yesterday, the new law also more than doubles the amount of renewable electricity that utilities must purchase from independent generators through long-term power purchase agreements.

Massachusetts increases renewable energy incentives

Energy legislation signed by Massachusetts Governor Deval Patrick earlier this month creates new opportunities for renewable energy projects in New England.

Finally enacted as Senate Bill 2395, the bill titled "An Act relative to competitively priced electricity in the Commonwealth" (37-page PDF) represents a combination of legislative proposals offered during the 2012 session.  The Act expands opportunities for renewable energy and energy efficiency, while seeking to manage increases in the cost of energy to consumers.

A number of the Act's provisions improve opportunities for renewable electricity production in Massachusetts and other New England states.  Building on the Green Communities Act of 2008, the new law increases the amount of electricity that electric distribution companies may purchase from renewable generating facilities under long-term contracts.  Previous law had required utilities to procure up to 3% of their electricity through long-term power purchase agreements with independent renewable energy developers.

The 2012 act amends the Green Communities Act by requiring distribution companies to solicit 10 to 20-year power purchase agreements from renewable developers for up to an additional 4% of the utilities' annual load.  By the end of 2016, the Commonwealth's distribution companies will conduct two rounds of joint solicitations for the new contracts.  Unlike previous renewable PPA negotiations such as led utility National Grid to select offshore wind developer Cape Wind as a renewable energy supplier, the new contracts must be negotiated through a competitive bid process.

The new law also provides a boon for distributed generation, requiring 10% of the newly-mandated supply to come from newly developed, small, emerging or diverse renewable energy distributed generation facilities located in its service territory.  Standards for these distributed generation projects require a maximum project capacity no greater than 6 megawatts.  Eligible distributed generation projcts cannot be net metering facilities, and must rely on a technology with no more than 30 megawatts of installed capacity in Massachusetts as of April 2012.

Under the Massachusetts renewable portfolio standard, projects eligible for this incentive may be built in any New England state, New York, or eastern Canada.

BOEM moves on Statoil's Maine offshore wind project

U.S. ocean energy managers announced today that they will start their review of the environmental impacts of a proposed deepwater floating offshore wind project off the Maine coast.

The federal Bureau of Ocean Energy Management, or BOEM, announced today it is moving forward with an assessment of a project proposed by Statoil North America to build a full-scale demonstration project of floating wind turbine technology offshore Maine.  Located about 12 nautical miles offshore of Maine's midcoast region, BOEM describes the project as entailing 4 turbines with a net capacity of 12 megawatts. 

The E. Frank Thompson ferry steaming away from the Maine island of Vinalhaven, home to the Fox Island Wind project.  Statoil's proposed offshore wind project would be near Boothbay Harbor, about 45 miles southeast of Vinalhaven.

BOEM's announcement represents the next step in a process that began in October 2011 when Statoil filed an unsolicited commercial lease application.  That application requested a lease for about 22 square miles of ocean space for the project.  Statoil also responded to a request for proposals by the Maine Public Utilities Commission seeking deepwater offshore wind and tidal projects; if selected by the Maine PUC, Statoil could receive a long-term contract to sell the project's output at subsidized rates.

Following today's announcement, BOEM will publish a Request for Competitive Interest Notice in the Federal Register.  Through this document, BOEM will inquire whether other developers are interested in constructing wind facilities in the same area off the coast of Maine.  Whether other qualified developers respond will determine whether BOEM proceed with leasing on a competitive or non-competitive basis.  Once the request for interest is published, developers and other members of the public will have 60 days to submit indications of competitive interest or comments about potential environmental consequences and other uses of the proposed lease area.

BOEM will also publish a Notice of Intent to Prepare an Environmental Impact Statement (EIS) in the Federal Register.  Under federal law, the EIS will consider the reasonably foreseeable environmental consequences associated with the Statoil project.  Once the notice is published, the public will have 90 days to submit comments on important environmental issues and reasonable alternatives related to the proposed leasing, site characterization and assessment activities, and construction and operation activities.  BOEM will use these comments to shape its environmental analysis and EIS.

California utility time of use rates

California regulators have upheld a decision to change the way many business and agricultural customers are charged for electricity.  Under the new structure, known as "time of use" pricing, customers will pay different rates for the energy consume depending on the real-time balance of supply and demand.

Historically, electricity consumers paid rates set by state public utilities commissions that, in the aggregate, allow utilities to recover their costs and make a reasonable rate of return on their investment.  Typically, these rates for energy have been fixed in advance, changing only when a utility files a new tariff or secures its regulators' approval to raise the rates.  Absent such a change, customers' retail rates remained fixed throughout the day and the year.

In recent years, real-time wholesale markets have developed across much of the United States.  The true cost of producing and delivering power varies in real time, depending on the balance of supply and demand.  If consumers demand more electricity, more and more expensive generating units are required to serve their load, resulting in an increase in the true cost of power.  Conversely, at night or during mild weather, decreased demand typically leads to a reduction in the real-time cost of power.  Real-time wholesale markets are designed to allow utilities and other wholesale buyers to respond to price variations, buying more electricity when it is less expensive or conserving power when prices rise.  Most retail customers like homeowners and businesses are not directly exposed to these real-time variations, instead paying the utility's fixed tariff rates.

This paradigm is starting to change in parts of the country.   In 2010, the California Public Utilities Commission ordered utility Pacific Gas and Electric Co. to implement a variable pricing structure for many of its business and agricultural customers by next March. The utility asked the regulators to allow customers to opt out of the time of use rates and back in to their previous fixed rates, pointing to its experience with customer complaints over a lack of an opt-out mechanism for smart meters.

Last week, the commission upheld its earlier decision, noting that evidence suggested that few customers would see increased bills as a result of the shift to time-of-use rates. Will more regulators and utilities shift customers to time-of-use rates?

EIA data on electricity generator costs

What does it cost to build a new power plant?  The answer depends on the technology used and other factors - but the U.S. Energy Information Administration publishes a useful reference presenting its analysis of the so-called "overnight cost" of building new centralized electricity generation stations using a variety of technologies.

Each year, the EIA publishes an Annual Energy Outlook containing projections for the upcoming year.  This outlook considers a variety of potential future outcomes based on factors like changes in the demand for electricity or variations in fuel pricing.

Underlying the outlook is a series of assumptions about factors including the demand for electricity.  A document released last week by EIA looks at a variety of new central station electricity generating technologies, and provides cost and performance characteristics for each.

One section of the data focuses on the total overnight cost of new projects initiated in 2011, defined as the overnight capital cost including contingency factors, excluding regional multipliers, learning effects, and interest.  According to EIA, advanced combustion turbines have the lowest overnight cost: $666 per kilowatt (in 2010 dollars).  By contrast, municipal solid waste - landfill gas facilities have the highest overnight cost: $8,233 per kW.  Other technologies fall between these two extremes.

Capital cost is only one piece of the puzzle; variable and fixed operations and maintenance costs also play a major role in the economics of electric generation.  According to EIA, variable O&M costs range from zero per megawatt-hour (for onshore and offshore wind, and solar thermal and photovoltaic) to $14.70 per MWh for a conventional combustion turbine.  Fixed O&M costs range from as low as $6.70 per kilowatt for advanced combustion turbines to as high as $378.76 per kW for MSW - landfill gas facilities.

Not every technology is appropriate for any given site, and economic considerations must be matched with environmental, siting, and other factors in choosing power plant technologies needed to meet consumer demand.  EIA's data is also aggregated and analytically-derived, meaning individual projects will likely have capital or O&M costs that deviate from these averages.  Nevertheless the EIA data illustrates some of the dynamics underlying our future energy mix - will we build facilities with low capital costs but higher O&M costs, more expensive facilities with lower O&M costs -- or can we find technologies that perform well in all categories?