By Kate Zerrenner

The American Council for an Energy Efficient Economy (ACEEE) recently released its inaugural City Energy Efficiency Scorecard, which ranks cities on their energy efficiency efforts, specifically on initiatives for buildings, transportation, energy and water utility efforts, local government operations and communitywide projects.

Austin placed in the top ten at #6, followed by Houston (#13), Dallas (#14) and San Antonio (#16) in the top 20 and El Paso (#23) and Fort Worth #26 falling just below that mark. Austin and San Antonio probably don’t surprise too many people, especially in light of my previous posts, but Houston, the nation’s oil and gas capital, and Dallas, a high-powered business center, probably don’t spring to mind for most people. However, these two cities have recently turned the tide and are gearing up for a big Texas clean energy showdown.

I think it’s worthwhile to mention that these two cities are impacted by the drought, although Houston feels the strain less due to its location in the Gulf Coast flood plain. But this locational drought-buffer carries its own problems, namely the threat of rising sea-levels, which are predicted to significantly affect Houston.

On top of that, both cities are in non-attainment with ozone standards, meaning their air quality is worse than the minimum threshold set by the U.S. Environmental Protection Agency (EPA). Therefore, there is a great need to improve the cities’ air quality in order to protect local citizens from health hazards. This gives them a further incentive to undertake clean energy initiatives.

These environmental factors bring to light an important connection relating to energy use.  If Texas utilizes more wind and solar photovoltaic (PV) energy, which consume little to no water and generate negligible carbon emissions, we can supply more water to the state’s agriculture sector and thirsty cities and cut down on air pollution.  Also, energy efficiency, by reducing our need for energy, automatically reduces the need for water and diminishes carbon pollution.  The more we invest in energy efficiency, the more we lower our overall energy use—saving enormous amounts of water and reducing harmful power plant emissions.  After all, the cleanest source of energy is the energy we don’t use.

Dallas

Source: Texarkana Gazette

The City of Dallas established an initiative called Green Dallas to inform residents on ways to make Dallas more sustainable. One of the programs under this initiative, funded by the U.S. Department of Energy, allowed the city to upgrade 248 of its buildings with energy efficiency technologies, which led to an annual energy savings of $1 million. Potentially, the city could use those savings to invest in other ‘green’ projects, such as paying for energy audits of fire stations, libraries and parks to discover where to get the biggest bang for the city’s buck on future projects.

Additionally, the Dallas-Fort Worth International Airport (DFW) became the first airport to partner with the EPA’s WaterSense program and remodel four of its five terminals with efficiency and conservation in mind. Water upgrades in the airport are projected to save 5.5 million gallons per month. Furthermore, DFW is one of the country’s largest renewable energy purchasers with twenty percent of its electricity needs coming from clean energy resources, like wind and solar PV.

Dallas’ efforts don’t just stop there. The ACEEE scorecard ranks Dallas #8 in the country for transportation-related energy efficiency initiatives. The city’s rail system is a great way to lower the number of commuters driving back and forth on the highway each day, and the city is purchasing energy-efficiency vehicles and building out EV-charging stations throughout the city.

Houston

This summer, Houston announced its plan to purchase over 140 megawatts of renewable power over the next two years, making it the largest municipal purchaser of renewable power in the nation, and in the top ten overall. This clean energy will supply half of the city’s annual electricity needs, enough to power about 55,000 homes each year. Furthermore, the city has reduced greenhouse gas emissions by 26% compared to its 2007 inventory levels.

Houston invested $60 million towards upgrading 5.2 million square feet of its city facilities with energy water efficient technologies. A total of 297 city facilities are projected to achieve roughly 30% in energy use reductions. Houston is also a community partner in the Department of Energy’s Better Buildings Challenge. Through this challenge, Houston committed 30 million square feet to achieve a 20% energy reduction goal by 2020.

Most recently, the city’s Parks and Recreation Department underwent energy efficiency upgrades and Houston now has its eyes set on upgrading the city’s libraries.

Under the leadership of Mayor Annise Parker, Houston has initiated the Houston Green Office Challenge, which challenges commercial building owners and managers to improve their sustainability credentials through cleaner transportation choices, energy conservation, property management/tenant engagement, water efficiency and waste reduction.  The challenge is in its third year with over 400 participants.

Texas

The initiatives listed above are just a few of the efforts the cities of Houston and Dallas have undertaken to merit ACEEE’s high national ranking, as well as the attention in regional and national press. There is still a lot to be done in these cities and across the state. It will require a statewide approach to really make the strides necessary to improve our energy and water use and protect Texans from the impending impacts of climate change. Texas’ statewide leadership should look to these cities as examples of energy efficiency and clean energy ingenuity and make Texas’ power grid and water systems as efficient and clean as possible for the betterment of the state.

By Dan Mueller

Texas is home to half the oil and gas exploration and production in the United States. Looking out west is the Permian Basin. To the north is the Barnett. Out east is the Haynesville and due south is the Eagle Ford. Oil and gas is a vibrant industry in Texas. Historically it’s been the lifeblood of the state’s economy.  But, as with any industrial development, it comes with its own set of serious risks to the environment. Impacts on our land, air, water and climate that if not managed correctly can have lasting consequences.

As an engineer working on water quality issues and related environmental issues for over 30 years, I’ve seen firsthand the effects of unregulated industrial activity. In 1980, the federal government passed the Comprehensive Environmental Response, Compensation, and Liability Act, better known as Superfund. Superfund legislation gave the Environmental Protection Agency broad authority to compel the cleanup of abandoned hazardous waste sites in our country, suing those responsible, and even establishing a trust fund to address toxic sites with no known responsible party. In Texas, these sites were the result of decades of industrial development caused by, for example, old lead production plants dating back to the early 1900s, World War II era defense manufacturing and the rise of the petrochemical industry.

The Highlands Acid Pit site just outside of Houston was the first Superfund site I encountered. Located near the bank of the San Jacinto River, the site had been used in the early 1950’s as a dump for industrial sludge believed to be from the oil and gas refining process. As my introduction to environmental engineering work, I was brought here to conduct soil and water sampling to determine the scale of the environmental impacts and cleanup options. I vividly remember walking into an area with absolutely no vegetation or wildlife – a stark contrast to the native trees and brush in the surrounding area. I’ve since visited a number of Superfund sites, each a lasting reminder of the importance of strong regulation and potential ramifications when this does not exist.

Since those early days, I’ve worked on a myriad of challenging environmental projects, and have had the opportunity to interface with policy experts in a variety of capacities on state, federal and local levels.  Through this first-hand experience I have gained a deep appreciation for protecting our land and water resources and properly managing environmental risks associated with industrial activities.

I now serve as Director of Natural Gas Exploration and Production at EDF – a title that maybe does not best describe my role, but I’m the natural gas team’s resident expert on water quality and waste management issues.  My years of onsite experience with the environmental risks of oil and gas drilling operations now play a valuable role in helping EDF craft smart policy solutions to minimize the water and soil impacts of natural gas operations and respond comprehensively and effectively when impacts do occur.

The Highland Acid Pit took ten years to clean up. The process was slow and costly and included extensive excavation of surface soils, backfilling the excavated area and covering it with grass.  To this day – six decades after first being used as a toxic waste dump – the site is fenced off from the public and still subject to frequent monitoring. This picture of a world without regulation is a reminder that when it comes to our natural gas work here at EDF, there is no substitute for getting the rules right and no excuse for not learning from past mistakes. Water is a precious resource, vital to the ecosystems it supports and with competing demands from nature, domestic needs, food production, and industrial activities. We can’t afford a do-over.

This is one of a group of posts about why industry experts work at EDF.

By EDF Blogs

By: Matt Golden, Senior Energy Finance Consultant, Environmental Defense Fund

The Investor Confidence Project (ICP) is pleased to announce the release of our newest Energy Performance Protocol for Standard Commercial projects – defined as multiple-measure energy efficiency projects typically costing less than $1MM.

This protocol strikes a balance between engineering and measurement and verification best practices and the need for a streamlined, cost-effective approach to developing a standardized investment quality energy efficiency project.  This latest addition complements our existing Large Commercial Protocol in an effort to develop a family of protocols addressing the range of projects types common in the growing energy efficiency retrofit marketplace.

The goal of the Energy Performance Protocols, as a whole, is to reduce transaction costs associated with investing in energy efficiency projects by standardizing how projects are baselined, engineered, installed, operated and measured.  This allows investors and building owners to gain confidence in the long-term return on their energy efficiency investments.  The goal is to bring together project originators, building owners and investors in a more transparent, and thus more robust, marketplace.

Currently, every energy efficiency retrofit is a custom project.  Even though many firms are following similar sets of technical standards, it is extremely difficult for an investor to evaluate the differences, resulting in costly engineering review processes that often take months to conduct.  By following an ICP Energy Performance Protocol with a documentation package stamped by a responsible Professional Engineer, the time and effort required to assess performance risk on projects will be substantially reduced, allowing for a more competitive and open energy efficiency investment market.

The ICP is working on a family of protocols to fit the range of projects currently in the market.  We are currently working on a Targeted Commercial Protocol for single measure projects and a Multifamily Protocol, as well as piloting a Quality Assurance Protocol that will standardize how projects are validated and enable a streamlined third-party validation system.

Without further ado, the ICP team is proud to present the first version of the ICP Energy Performance Protocol for Standard Commercial.

By Mark Brownstein

This commentary originally appeared on EDF's Voices blog.

Source: Penn State Outreach/flickr

Earlier this week, a prestigious scientific journal, the Proceedings of the National Academy of Sciences (PNAS) published “Measurements of methane emissions at natural gas production sites in the United States.”  This study is the first in a comprehensive research initiative that Environmental Defense Fund is helping to produce with more than 90 partner universities, scientists, research facilities and natural gas industry companies. This effort, the largest scientific undertaking in EDF’s history, is an unprecedented attempt to measure where and how much methane is being released across the entire natural gas supply chain.

By the time the work is finished, around the end of 2014, scientists working with EDF will have completed sixteen studies characterizing methane emissions in five key areas of the natural gas system: production, gathering and processing,transmission and storage, local distribution and use in operating and fueling heavy and medium weight trucks.

The study that published Monday was led by Dr. David Allen of the University of Texas at Austin (UT) and is based on some of the first-ever direct measurements of methane emissions from shale gas wells that use hydraulic fracturing, or “fracking.”

Getting the Facts

You’ve probably heard or seen advertisements sponsored by the natural gas industry talking about how natural gas is a low-carbon alternative to coal and oil, and this is true, but it’s not the whole story.  Natural gas has roughly half the carbon content of coal and one-third the carbon content of oil.  This means that natural gas creates less carbon dioxide than coal or oil when burned.

But the fact the natural gas industry likes to ignore is that natural gas is methane, and when methane is vented or escapes into the atmosphere its short-term impact on global warming is 72 times more powerful than the carbon dioxide created when it is burned.  Even a small amount of methane emitted to the atmosphere, as little as 1% or less of all the natural gas produced, can work to undo some or all of the benefits we think we are getting when we substitute natural gas for coal or oil.

The problem is that while folks in the natural gas industry know that some amount of the methane they produce and distribute is lost along the way, they don’t know exactly how much is lost, or where exactly those loses are the greatest.  All anyone has had until now are estimates based on research that the U.S. Environmental Protection Agency did nearly 20 years ago.

It is much more difficult to solve a problem when you don’t know its size or source.  And that’s why EDF believes it is critically important to go out into the field and get real data on methane emission pollution from gas production, and then put that information to work in formulating regulations and practices that reduce or eliminate this pollution.

Shedding light on total leakage rates

Dr. Allen found that overall emission rates at the wells studied are in line with current EPA estimates for the production segment. The study also contains three other notable findings:

First, methane emissions  during  ‘well completion’ – the process of getting the well ready to produce gas after it is drilled and fractured – are lower than current EPA estimates.  This is because the majority of wells tested were using “green completion” technology or flares which were shown to be highly effective in reducing methane emissions at this point in the production process.

The use of these technologies is a direct consequence of federal New Source Performance Standards (NSPS) for natural gas producers, enacted in the summer of 2012.  By January of 2015, this requirement in EPA’s rule tightens and all natural gas producers will have to green complete to control wellhead emissions. Clearly, the study shows that some have adopted green completions already and that it works really well.  What we don’t know is how common this technology is across the industry in advance of the mandatory compliance date.

Second, the UT study showed that emissions from pneumatic valves, which control routine operations at the well pad, are higher than EPA estimates.  These valves are designed to vent a certain amount of methane during normal operation, and the fact that these emissions are higher than EPA estimates indicates that there is an opportunity to further reduce emissions through the use of available low- and no-emissions valves.

Third, the study found “fugitive emissions” – leaks from equipment at the production site – are also much higher than EPA estimates.  This too suggests an opportunity for lowering production sector emissions through leak detection and repair requirements.  This means an emphasis on better field performance and maintenance.

Are these results representative?

There are over 2000 natural gas producers in the United States, and so it is fair to wonder whether the nine who participated in this study are representative of the industry as a whole.  No one can say for sure, but what we do know is that the nine companies participating in this study account for roughly 12% of all onshore gas wells in the U.S., and 16% of gross gas production and almost half of all new well completions in 2012.

As to whether participating companies provided only their “best” sites, the answer is no.  The University of Texas study team decided where and when they wanted to test based on their study criteria.  Companies then made available all of the sites that satisfied UT’s request.  Companies did not cherry pick the sites.

Finally, skeptics may wonder whether these companies made cosmetic improvements to their sites before testers came to take measurements.  The answer is no.

First, companies usually only had limited advance notice of when UT was coming to region to test.

Second, the air emission control equipment that was tested is typically designed into a drilling project from the start and cannot simply be rolled out at a moment’s notice.  And further, once the capital is spent to develop the site using emission-controlling technologies and techniques – such as “green completions,” which reduce emissions at the end of the hydraulic fracturing process, when frack fluids and sands are drawn back up the well to make way for gas production – companies have every incentive to run it.  Otherwise, they would not reap a return on their investment.

Third, and finally, there is the simple fact that if companies were modifying their behavior in anticipation of the UT researchers’ arrival, it is doubtful fugitive emissions – leaks due to inattentive maintenance and operations – would have been so high.  If companies were trying to game the results, they certainly did not succeed.

One headline from the study is that green completions are an effective way to control emissions at the end of the hydraulic fracturing process, and that’s good news, because the Environmental Protection Agency is requiring unconventional natural gas wells to use green completions beginning in January 2015. (Today, operators can either use green completion or flare off the methane). No one knows how many operators today are using green completions. For that reason, this study does not claim to offer a snapshot of current industry wide production practices. However, the data suggests that once this practice is required broadly in Jan. 2015, emissions from this phase of the production process will decline.

Where do we go from here?

While EDF will continue to sponsor and participate in research to better understand methane emissions across the natural gas supply chain, this first study provides enough information to suggest where regulatory reforms are required.

First, green completion technology, which this study demonstrates is so effective, should be required for all unconventional oil and gas development, and not just gas development, as is currently the case.  The rule needs to be extended to shale oil and hybrid oil-and-has wells, which are not covered by the EPA regulation.

Second, clearly there is a need to reduce emissions from pneumatic valves, and there is technology that can do this, and it should be required.

Third, there is no excuse for us to allow natural gas to be lost through leaks.  This is bad for the environment and a waste of a natural resource.  A requirement that natural gas producers engage in regular and effective leak detection and repair program is in order.  Both the states and the federal government have the authority and the obligation to act and EDF will be campaigning hard to make sure that they do.

By Lauren Navarro

This commentary originally appeared on EDF's California Dream 2.0 blog.

As the 8th largest economy in the world, California remains a global leader in clean tech investment, innovation and adoption of landmark climate and energy policies. What defines our success?  Our ability to try things first, set the bar high, and get policies right.

California’s Renewable Portfolio Standard (RPS) is a perfect example of that bold, pioneering spirit. Passed in 2011, the RPS required that 33% of electricity come from renewables by 2020 – a lofty benchmark, even by California’s standards. Along with self-generation and solar rooftop programs, California is successfully adding solar, wind, and other distributed generation to its resource portfolio.

In fact, renewables are successfully becoming a large part of daytime energy use, the California Independent Systems Operator (CAISO) – the organization in charge of balancing the statewide grid – is concerned over how to make up for that energy when the sun goes down while evening energy demand spikes.  The question is: How can the CAISO reliably integrate renewables?

The CAISO is currently figuring out how to address this need for “flexible” power and will have a draft final decision out on Sept 18th.  Just like people prefer to take routes they know well when they drive, the CAISO is most comfortable with what they know: familiar fossil fuels. Using clean resources and demand response instead is new territory for them that will require careful orienteering.

Yet CAISO must get comfortable with the new, cleaner terrain to ensure a less polluting, less expensive, more resilient energy future.  California passed the RPS to reduce fossil fuel consumption — and the pollution that comes with it.  If fossil fuels become the main method by which renewables are integrated, they could eliminate the emissions benefits of renewables entirely, while consumers pay more than necessary to integrate renewable energy.

There are clean options that have been proven to work in grid operations, such as demand response – the voluntary reduction of electricity use by customers who are paid to do so when called upon.  By reducing demand at key times, demand response lowers the need for electricity production and saves money in the process. (This is an area where California can learn from East Coast states that are robustly using demand response in their electricity markets.)

EDF has actively engaged CAISO on the need for “flexible” power, and knows they are working hard to figure out how to use demand response and other clean options to integrate renewables. We have also asked CAISO to utilize existing, clean resources and to revisit this framework every few years to make sure it is as clean as it can be – all to make sure that California has time to get it right.

Leading the way isn’t always easy, but if successful, California and CAISO will show they can utilize proven resources like demand response to keep California’s energy policies clean and cost-effective, while readying the grid for high levels of renewable resources.

By Brad Copithorne

This commentary originally appeared on EDF's California Dream 2.0 blog.

Yesterday, the California Public Utilities Commission (“CPUC”) updated their June 25 proposed decision that included implementation rules for an On-Bill Repayment (“OBR”) program for public and commercial properties.  An OBR program allows property owners to finance energy efficiency upgrades on their buildings and repay the obligations through their utility bills.  Banks and other private investors provide the funding and borrowers get low interest rates because the obligations are an integral part of the utility bill and, under the EDF proposal, are fully transferable upon change in ownership or occupancy.

The CPUC’s revised decision contains many of the elements necessary for a successful program including making the OBR obligation an integral part of the utility bill through a tariff.  Ed Wojtowicz, VP of Finance at Honeywell recently told me, “By integrating the financing charge into the utility bill, we expect that OBR will help many towns, cities and school districts approve money saving energy efficiency projects.”  We have heard similar sentiments from other market participants and are optimistic that this OBR program will accelerate money-saving clean energy investments in municipal and school properties.

Unfortunately, our California utilities — PG&E, SoCal Edison and Sempra —  have been fighting OBR tooth and nail for the past two years, as they fear that a successful OBR program would increase investment in distributed solar, potentially reduce utility control of energy efficiency programs and allow other companies to have access to the utility bill and customer relationships. Over the past three weeks, the utilities have had ten separate private meetings with CPUC commissioners or staff in an attempt to halt the OBR program.

Californians deserve better.

A well-structured OBR platform attaches to the meter as a tariff-based charge and thus survives changes in ownership. According to an EDF study, such a platform could save California businesses over $37 billion over 12 years in avoided energy costs, would improve the quality of California’s air and environment by keeping 76 million metric tons of CO2 equivalent out of our skies, and provide property owners with the opportunity to choose clean energy solutions that are cheaper than traditional energy.

The California utilities are working hard to keep these good things from happening.  As of now, the revised decision does not provide for full transferability of the OBR obligation in the event of a sale or foreclosure.

Why is this important?

While this does not particularly matter for municipal buildings (schools tend not to transfer ownership), we have heard from numerous financial institutions that they will not invest in commercial property OBR projects without full transferability of the OBR obligation.  Without transferability, the investment will likely be wiped out in a foreclosure.

Most commercial properties have mortgages and are owned by special purpose real estate companies.  Without an OBR program with full transferability, most of these buildings are unable to obtain the credit necessary to invest in renewable generation or energy efficiency projects.

While we are pleased that OBR will increase investment in retrofits of state and locally owner properties, this is only a small part of the potential market.  According to a 2010 report by McKinsey & Company, government buildings are projected to make up only 9.6% of nonresidential energy use by the year 2020. The remaining 90.4% of nonresidential energy use will come from private commercial and industrial buildings, for which the proposed OBR program is, unfortunately, ill-suited.

This represents a missed opportunity for California to increase investment in clean energy projects, create jobs, save money for tenants and property owners and continue California’s leadership in the clean energy industry.

The CPUC will be voting on September 19.  We hope that they will reconsider and create an OBR program that will create investment in both commercial and public buildings. For energy efficiency financing in California, it would be two steps in the right direction.

 

What others are saying about the need for a robust OBR program:

Citi, Director, Steve Vierengel:

At the Citi and EDF “Innovations in Energy Efficiency and Distributed Generation Finance II” conference on February 28, 2013, Steve Vierengel, Director at Citi, stated that “automatic transferability without subordination will be critical to the success of an OBR program.”

SolarCity Comments to CPUC filed August 5th, 2013:

“[We] are concerned about a key feature of the PD’s OBR pilot that may frustrate or completely nullify the benefits of OBR or limit the applicability of any lessons learned from the pilot. Specifically, the requirement that subsequent property owners, landlords and tenants (to the maximum extent feasible) will have to provide written consent to the OBR obligation is problematic, particularly following a foreclosure.”

Metrus Energy, CEO/President Bob Hinkle:

“A properly structured OBR program will likely allow Metrus (and other energy services companies) to finance projects that do not qualify today. Survivability of the OBR obligation through a foreclosure, is what separates OBR from a second lien, unsecured loan or other traditional financing products.”

-Letter to Brad Copithorne dated July 2nd, 2013

SCIenergy, CEO Steve Gossett Jr:

“If implemented with survivability through foreclosure that is not contingent upon future occupants’ consent, and is not-subordinated to energy charges, OBR may catalyze significant growth in the energy efficiency market.”

-Letter to Brad Copithorne dated July 15th 2013

Renewable Funding Comments to CPUC filed August 5th, 2013:

“Without a tariff-based obligation that applies to the property until the OBR obligation is satisfied, this pilot will not create a new lending opportunity from the perspective of financial institutions.”

Carbon Lighthouse, CEO Brenden Millstein:

“Carbon Lighthouse has dozens of projects lined up and ready to be executed through the OBR program, but these projects may have difficulty moving forward if the OBR attachment mechanism is not done well.”

-Letter to Brad Copithorne dated June 25th, 2013

Matadors Community Credit Union (MCCU), Chief Lending Officer Mark Tsimanis:

“MCCU believes that an OBR program that survives foreclosure, is not contingent upon consent of future owners or occupants, provides adequate disclosure, and is treated equal to the energy charge on the utility bill may significantly grow the energy efficiency market.”

-Letter to Brad Copithorne on July 12th, 2013

PineBridge Investments, Vice President Gunter Seeger:

“If the obligation is considered subordinate to the energy charge or does not run-with-the meter through changes in occupancy, then OBR offers no credit enhancement relative to existing opportunities and PineBridge would be unlikely to participate in OBR.”

-Letter to Commissioner Ferron dated August 2nd, 2013

Alternative Power Capital Comments to CPUC filed August 5th, 2013:

“Attachment of the OBR obligation to the meter via a tariffed charge that applies to subsequent customers on a property transfer, with service termination right for default, has the potential to open up a new market opportunity.”

 

By Dan Grossman

Methane, the primary component of natural gas, is a powerful greenhouse gas – 72 times more potent than carbon dioxide over a 20-year time frame. The largest single source of U.S. methane emissions is the vast network of infrastructure and activity involved in the production, processing and delivery of natural gas. These emissions, if not controlled, pose a significant risk to the climate. In the near term, the opportunity to maximize the climate benefit of natural gas compared to other fossil fuels rests on whether methane emissions can be minimized.

A groundbreaking study released today demonstrates that some operators have been successful in deploying technologies and strategies to minimize methane emissions from production, creating optimism that we can make the natural gas climate bet payoff.  However, we also know that such technologies and strategies are not universally deployed in the industry and, not surprisingly, other studies demonstrate much higher methane leakage rates.

We simply need to be vigilant to ensure that such production is done right.

The University of Texas study, published in the Proceedings of the National Academy of Sciences, involved taking direct measurements of actual methane emissions – as opposed to estimating emissions through indirect methods such as engineering formulas, as has often been the case in earlier studies.  Measurements were taken at well sites in multiple geographic regions – including the Rocky Mountain West. It is the first of 16 studies EDF is participating in to assess the scope of methane leakage throughout the natural gas supply chain (from production on through to local distribution and key end users).

Nine companies volunteered to have emissions at their well sites measured for the study.  We don’t know whether the data collected from the well sites operated by these nine companies are representative of industry at large (the 478 wells visited by the UT team constitute about 0.1% of all onshore natural gas wells in the U.S.), but we do know enough to say there are plenty of opportunities to reduce methane emissions:

• According to data in the UT study, operators in the Rockies may be releasing up to 2.6 billion cubic feet of natural gas annually into the atmosphere through fugitive emissions – i.e., leaky equipment – instead of getting it into a sales line.  From a greenhouse gas perspective, that is the equivalent of pollution from almost 560,000 passenger vehicles.  And at $3.00 per MCF, it represents an economic waste of more than $75 million per year.
• Operators that utilize reduced emission completions (RECs or “green completions”) are able to dramatically reduce methane emissions, as compared to EPA estimates of emissions from wells that don’t use green completions.
• While other studies using different methods of measuring total leakage (e.g., flyover measurements of entire basins) paint a bleaker picture of the methane footprint of natural gas operations, this study demonstrates that robust control technologies and strategies can be very effective in reducing such methane emissions.
• The federal government and the states should build on the regulatory frameworks they already have in place and develop new, cost-effective rules to enhance the efficiency and reduce the emissions profile of natural gas operations.  Key regulatory improvements include expanding the EPA’s green completions requirement, mandating robust leak detection and repair (LDAR) programs to control fugitive emissions, and applying emission control requirements to existing sources – not just new ones.

In Colorado, the Air Quality Control Commission is crafting rules to address many of these very issues.  It is absolutely critical that the state help us realize the climate promise of natural gas by adopting, for example, rigorous LDAR requirements for well sites and capture requirements for storage tanks.

It is reassuring to know that America’s natural gas bounty holds the promise to help slow the pace of global climate change.  But now it is up to us to insist that such promise not be allowed to go up in fumes.

 

By Kate Zerrenner

A glossary of energy and water terms

In recent posts I’ve discussed the need for energy and water planners to co-manage resources more comprehensively. But another significant barrier exists: language. Water and energy planners use different terminology and a lack of understanding for these distinctions hampers true coordination. Also, it prevents customers from understanding how to make sense of their own usage patterns and maximize energy and water efficiency.

Electricity measurements

Getting into the nuts and bolts — or watts and volts — of the issue can get very dry very quickly, so let’s go over some basic units of measurement to set the stage.

Electricity is measured in watts, usually represented as kilowatts (kW), megawatts (MW), but often discussed as megawatt-hours (MWh). One MW is roughly equivalent to ten running cars engines. A MWh is the total amount of electricity produced by a power plant in one hour, roughly the amount of energy used by 330 homes in one hour. According to the U.S. Energy Information Administration (EIA), in May 2013, Texas generated 12,261 gigawatt-hours (GWh) of electricity from coal-fired power plants (1 GWh = 1,000 MWh) and only 4,116 GWh from renewable energy sources, such as wind and solar.

Water measurements

While electricity’s units of measurements are fairly streamlined, water is measured differently depending on volume. Specifically, acre-feet are used for large amounts (e.g. reservoirs, aqueducts and canals), while smaller amounts are measured in gallons. An acre-foot is the amount of water it would take to cover an acre of land with a depth of one foot, roughly 326,000 gallons. As an example, an Olympic-size swimming pool amounts to two acre-feet, and the average family of four uses roughly 400 gallons of water a day. Estimates of water use in the U.S. vary and are more difficult to estimate than electric use due to the inherent challenges of measurement and leaks, among other factors. The U.S. Geological Survey (USGS) estimates that in 2005, 410 billion gallons of water were withdrawn per day.

Withdrawal versus consumption

The term “withdrawn” brings us to another confusing set of terms: withdrawal versus consumption. As I mentioned in an earlier blog post, when talking about water for energy use, there is a distinction between these respective measurements, and this has a huge impact on both sectors.

Withdrawal is the amount of the water taken from the water source, whereas consumption is the portion of that water used and not returned to the original source for reuse. It should be noted that water returned to its original source exists in a different condition than when it was first withdrawn, which can contribute to stress on the water supply. The electric sector withdraws more water than any other sector in the U.S., amounting to more than 40%.

Source: The Artemis Project

Efficiency versus conservation

Although the terms “energy conservation” and “energy efficiency” are often used interchangeably, they do in fact mean two different things.

Energy conservation refers to reducing energy waste. Examples include turning up your air-conditioning when you leave for the day or turning off the lights once you leave a room. Conservation is often associated with sacrifice, and many people still equate both conservation and efficiency with that sentiment.

Energy Efficiency refers to people using technology not only to reduce energy waste, but also to use less energy. For example, a new, efficient air conditioning unit will cool a house the same way an older unit can, but requires less energy to achieve the same effect. However, if a person runs the new unit all day at low temperatures while no one is home, they are wasting energy.  .

Basically, efficiency involves technology and conservation involves behavior. But the biggest bang for the buck naturally comes with a combination of efficiency and conservation.

Water and energy use terminology may be technical, but understanding the similarities and differences will make all the difference when it comes to efficiently using our scarce resources and empowering people to engage in this very important conversation.

By Kate Zerrenner

This commentary originally appeared on EDF's Texas Clean Air Matters blog.

With Labor Day behind us, Texans can look forward to a welcome respite from the hundred-degree days of August. The pending arrival of fall may signal milder temperatures for now, but the latest report from John Nielson-Gammon, Texas’ state climatologist, tells a different story about Texas’ long-term climate trend. The study released last month indicates that peak summer temperatures may increase by up to five degrees by 2060. What we once thought of as a unique heat wave (think back to 2011) are likely to become the new normal, and will eventually – according to Nielson-Gammon – be replaced by even hotter temperatures.

At the same time, increasing temperatures would place further severe stress on the state’s energy and water systems. Texas’ recent extreme summers have already plunged much of the state into drought. The latest data released by the U.S. Drought Monitor predict water emergencies could occur in at least nine U.S. cities—five of which are in Texas. And experts expect the drought will persist for years to come as climate change intensifies.

Texas lawmakers must take these grim projections into account as they plan the state’s energy and water futures. Some Texas decision makers are already calling for more fossil-fuel power plants to cover the need for more power (to run all those air conditioners) in light of 2011’s historic summer highs, which will emit more carbon pollution into the air and add to the warming. These same Texas lawmakers insist we should keep our heads in the sand, ignore the mounting evidence pointing to a new climate normal and do nothing to alleviate or adapt to the problem.

To meet the state’s energy and water needs in these changing times, we should prioritize energy resources that don’t contribute to a worsening climate and have little or no water or carbon footprint. Clean energy sources such as wind energy and solar photovoltaics have the potential to produce all the energy we need while consuming little water and releasing negligible carbon emissions. Other customer-facing resources like energy efficiency and demand response help reduce the need for power altogether. On top of that, these technologies actually save customers money on their energy bill and pay Texans for conserving energy.

The U.S. Department of Energy predicts that the amount of water required by fossil fuel power plants will increase as global warming progresses. To avoid a compounding problem, Texas should turn away from water-intensive sources of electricity, like fossil fuel power plants. Anything we can do to reduce the impact of climate change while freeing up water for agriculture, thirsty cities and drought-stricken waterways should become a priority for the state.

If we don’t act now, we might find ourselves with an energy and water system irreconcilably crippled by the effects of climate change.

By Caroline Paulsen

Earlier this year, the Alliance Commission on National Energy Efficiency Policy unveiled a plan to double nationwide energy productivity by 2030.  It’s an ambitious move to greatly increase our nation’s use of energy efficiency, which represents a huge – and largely untapped – opportunity.  Reducing wasted energy through efficiency cuts harmful pollution and saves people money on their energy bills.  After all, the cheapest, cleanest, most reliable electricity is the electricity we don’t have to use.

Source: Church Times

Similarly, the State Energy Race to the Top Initiative (Initiative) is an incentive for states to make voluntary progress to increase their energy productivity. The U.S. Senate is moving forward to make this idea a reality.  Originally introduced as a bill in June, the Initiative has now been filed as a potential amendment, sponsored by Senators Mark Warner (D-VA), Joe Manchin (D-WV), and Jon Tester (D-MT), to the Shaheen-Portman energy efficiency bill.  If passed, the Initiative will stimulate energy innovation in both the public and private sectors, and allow states to tailor energy saving policies to their particular needs.

Administered by the Department of Energy (DOE), the Initiative will be broken into two phases.  In the first phase, following the submission of state proposals through their energy office, DOE selects 25 states to receive funding (a combined $60 million) to move their energy productivity concepts forward.  Although states have complete independence in developing and implementing their own clean energy strategies, the DOE will provide technical assistance upon request.  Eighteen months later, in the second phase, the 25 states will be asked to submit progress reports to DOE.  Based on their projects’ success, DOE will then select up to six states to receive a share of $122 million to continue their energy saving efforts.

The $200 million initiative challenges states to work with diverse stakeholders, including electric utilities, regulators, clean tech entrepreneurs and environmental organizations.  Proposals should benefit all stakeholders, and can include a number of clean energy policy and program ideas.  This could involve the expansion of industrial efficiency, building retrofits, demand response policies, smart grid investments and combined heat and power.

In order for innovative clean energy technologies to take off as the “norm” across the country, some key states need to lead the charge – and this is where a State Energy Race to the Top Initiative could help drive progress.  Many of the decisions regarding clean energy investment and deployment, including grid modernization, are governed by state policies in coordination with state legislatures, state energy offices, utilities and other stakeholders.

State regulators in some states, such as California, Texas, Illinois, North Carolina and New York, are already working to put smart power policies in place.  California, one of the first to act, ordered its main investor-owned utilities to address three areas: reducing harmful pollution, fostering competition to increase energy innovation and allowing new clean energy sources the same access as traditional fossil fuel power generation.  Texas, for example, boasts one of the most modern power grids in the country due to advanced, smart metering and greater customer engagement, allowing Texans to participate as “prosumers’ – or consumers and producers of energy. Under this Initiative, any state that takes steps to push clean energy policies such as these would be eligible to apply for funds through the competitive grant program.

If you’re wondering how states that are newer to clean energy policy will compete with those that are already clean energy leaders, the Initiative is designed to prevent this advantage.  The productivity increase of any state is relative to that state’s initial baseline, as opposed to other states.  DOE will also be taking geographic diversity into account when allocating the funding, and will put aside $8 million for Indian Tribe participation.

The Initiative builds on existing public and private networks, like the State Energy Program, but is a separate statute in itself.  It has also seen strong support from groups such as the National Association of State Energy Officials, the American Gas Association and Edison Electric Institute.

The initiative has potential to make a great difference in our country’s energy productivity – providing a cost-effective tool for reducing our nation’s energy consumption, while saving consumers money and reducing harmful air pollution.  A recent ACEEE study estimates that the State Energy Race to the Top Initiative would result in cumulative energy savings of roughly 380 billion kilowatts per hour (kWh) and a cumulative savings of carbon dioxide of 71.25 million metric tons (MMT) by 2030.  This reduction in CO2 emissions is equivalent to the annual greenhouse gas emissions from nearly 15 million passenger vehicles, or 20 coal-fired power plants.  According to a recent study, the Initiative would also significantly leverage additional capital.  In fact, ACEEE’s study shows that every $1 invested in this program returns $8.40 in energy savings.  A great investment for the American taxpayer!

The bottom line is that this Initiative a simple, effective, affordable idea that could yield real results for our health, economy and environment.  It will allow states to develop energy saving policies and programs that work best for them, without mandates.  It will also drive states to become clean energy leaders by giving them a reason to innovate and a means to do it.

Click here to take action by urging your Senator to cosponsor the State Energy Race to the Top Initiative.

 

By Jim Marston

I’ve seen many energy issues expand and contract in the years I’ve been with EDF since 1988.  Our organization has celebrated and participated in many victories regarding climate change, including landmark legislation that put limits for the first time on California’s greenhouse gas emissions, the elimination of eight out of 11 new coal plants in Texas as part of the utility TXU’s buyout and federal standards for controlling air pollution from unconventional gas activities.  At the same time, we’ve seen clean energy sources both praised and attacked.

No issue, however, has been as thorny as natural gas.  We used to think if we just switched from coal or oil to natural gas, we could be certain that the climate change scenario would improve dramatically.  But with lingering uncertainty around just how much methane, a very potent greenhouse, is being emitted and is leaking out across the natural gas system, we are still weighing the amount of climate benefit of its use.

When you don’t know something that you want to know, you turn to experts who either have the knowledge or can acquire the knowledge by asking the right questions.  So, as head of EDF’s US Climate and Energy Program, I’ve assembled a team whose judgment I trust to find answers to the question that defines our gas work: How can we minimize the risks associated with operations and maximize the inherent climate benefit of natural gas?

Over the years, I’ve worked with many commendable professionals on energy issues.  Tapping the best and brightest for our natural gas team means finding those professionals who have worked in all aspects of the energy arena.  That encompasses those within industry, at the state or federal regulatory levels, or whoever understands the issues, the people and the detailed processes.

Like any other team at EDF, our natural gas team is made up of seasoned environmental lawyers, former regulators and policy leaders, technically astute scientists and engineers.  Dealing with unconventional shale plays has meant making some unconventional hires at EDF, including several people who have years of experience working for the oil and gas industry.  But what better way to distill the most salient points of an issue than go to those who know exactly how to drill down (pun intended) into them by way of experience.

EDF’s hallmark is finding market-based solutions to challenging environmental problems using the facts.  For our natural gas work, this has meant looking at the effects of rapid development squarely – not for where we want it to be, but for where it is – and focusing our efforts to have the most impact on those dealing with the repercussions of poor industry practices.

These dedicated professionals likely could make a higher salary at other venues, but choose to leave industry to work for EDF because it’s where they know they can make a significant, positive difference.  I’m inspired by their dedication and knowledge daily, and I’m confident in the ability of this team to ensure that the time spent on this important issue is not lost while we continue to push for greater adoption of and reliance on “smart power” sources like energy efficiency and renewables.

This is one of a group of posts about why industry experts work at EDF.

By Marita Mirzatuny

In an effort to gauge where America’s power grid stands, Washington D.C.-based group GridWise Alliance evaluated grid modernization in 41 states and the District of Columbia.  Texas and California tied for first place—standing far above the next runner up.

So what makes Texas’ grid so special?

Texas restructured its electricity market in 1999, introducing competition into the retail electric market.  The new competitive retail market gave most Texans a choice of electricity providers from dozens of companies, so these energy providers compete to offer the most advanced services.  For example, Texans can opt for 100% renewable electricity from Green Mountain Energy.

Additionally, in an effort to update Texas’ electric grid, the Public Utility Commission, Texas’ governing body for electricity, passed a resolution prompting “wires companies”(the firms that deliver energy from power plants to homes and businesses) to invest in millions of smart meters.  Smart meters can help eliminate huge waste in the energy system, reduce peak energy demand (rush hour on the electrical wires) and spur the adoption of clean, low-carbon energy resources, such as wind and solar power, by managing energy demand and generation more efficiently.

Now Texas boasts more installed smart meters than any other state.  Already, smart meters have led to quicker outage detection and reporting.  They also empower customers with the ability to reduce their electricity use and reward customers accordingly, when combined with customer-facing home energy management technologies.

Combined, advanced, smart metering and greater customer engagement could produce a more resilient power grid of the future, where customers participate as “prosumers’ – or consumers and producers of energy.  Some pockets of Texas are already leading by example.

As we have highlighted, Austin’s neighborhood smart grid test-bed is making great strides towards smarter power.  Pecan Street Inc.’s demonstration project collects massive amounts of voluntary energy data to provide customers with real-time feedback from a neighborhood powered almost entirely by its own rooftop solar panels  A modernized energy system, like the one being designed and tested at Pecan Street, puts energy generation in the hands of customers—fundamentally strengthening the power grid.

Source: El Paso Times

Energy is always more reliable when it’s produced locally.  That’s why military leaders at Texas’ Fort Bliss are using over 20 megawatts (MW) of solar power and water recycling to help meet the Army's energy conservation and security goal.  These energy- and water-saving strategies not only keep the base secure, but they also go a long way toward reducing regional air pollution and water use.  The base commendably aspires to achieve a net-zero energy, water and waste footprint by 2020.

While Texas is moving in the right direction with its expansive wind industry and smart grid development, many of those who are deeply invested in aging fossil fuel technology are either blocking the way to the finish line or stalling the transition to a new, diverse energy portfolio.

If Texas is going to weather the impacts of climate change, we need to further invest in a modern power grid that encourages customer engagement and has the intelligence to minimize costly power outages and utilize customer-facing, demand-side resources, such as rooftop solar panels and energy efficiency.  The progress we’ve made so far is admirable, but we’re far from achieving a truly modernized, smart grid.  That’s why EDF is working with policymakers, investors and entrepreneurs to see that Texas seizes opportunities and drives innovation in the new clean energy economy.

By Andrew Williams

Source: Julia Schmalz/Bloomberg

After being caught off guard by the early winds of the shale gale, Pennsylvania officials have been in a near-constant state of regulatory and legislative activity for the last few years, working to put rules in place to reduce the risks posed by the increase in natural gas development.  We’ve given PA high marks on some of those efforts, and we’ve disagreed strenuously with others.  But we believe in giving credit where credit is due – and the Keystone State certainly deserves credit for the long hours that officials and stakeholders have devoted to improving regulations.

In some critical areas, such as reducing air pollution from leaky equipment located at natural gas processing plants and compressor stations, the Bureau of Air Quality at the Pennsylvania Department of Environmental Protection (DEP) has demonstrated real leadership.

Now, DEP has revised its technical guidance document known as Exemption 38, narrowing the eligibility criteria for the air quality permit exemption.  Astonishingly, under the previous version almost all oil and gas production facilities were exempted from the state’s air quality requirements. Past guidance for Exemption 38 considered well sites and all the equipment associated with them to be “minor sources” – even though they can individually contribute to poor air quality conditions, particularly in densely populated areas.   In Pennsylvania 90 percent of wells are concentrated in ten counties, with just three counties accounting for 50 percent of all wells.  Without proper pollution controls and monitoring, this intensive development can easily lead to unhealthy local air quality.

In response to some of these concerns, the Pennsylvania DEP revised Exemption 38 to do a couple of things.

First, it tightens the scope of the current exemption – limiting the availability of the exemption to only those facilities whose emissions fall below a certain threshold – and it provides a process by which industry must document within the initial 180 days of production that any well site claiming the exemption in fact qualifies for it.  While we think it would be wise to require such documentation earlier in the process, we also recognize that this is a marked improvement over the status quo – whereby the permit exemption was wide open to just about any well site operator, with no emissions limits and no documentation required.

Second, the DEP now requires operators to implement pollution control strategies that go ‘above and beyond’ legal minimums in return for getting a permit exemption.  We commend DEP for thinking outside the box and requiring exemption seekers to implement controls that are better than what federal and state law otherwise requires.

One example of this is DEP’s proposal to require operators check for and repair leaks (known as “leak detection and repair” or LDAR programs) at well sites annually.  We believe leak detection should be performed far more frequently than once a year.  Wyoming and California, for example, require certain operators to check for and repair leaks at well sites on a quarterly basis.  And the PA DEP requires quarterly LDAR for compressor stations and processing facilities.  We think the standard for well sites should be at least as strong.  That said, we also recognize that the new LDAR requirement represents an important new step in the right direction – one that most oil and gas producing states have yet to take.

Another of the ‘above and beyond’ measures requires operators to use enclosed flares on tanks and other equipment.  Requiring enclosed rather than open flares, which are more prone to going out, is a no-brainer.  And there are additional commonsense measures we’d like to see DEP implement in the near future.  For example, flares should be required to have continuous ignition devices to ensure they stay lit, and they should be required to operate at the highest efficiency levels.  Doing so guarantees a cleaner burn that will reduce emissions of the most harmful pollutants.

While these and other aspects of the proposed Exemption 38 will improve operations at well sites, the fact remains that permit exemptions are inherently problematic.  When operators get permit exemptions, regulatory agencies lose some of their ability to perform oversight responsibilities in a meaningful way.

The permitting process is one of the first and most important opportunities state air quality engineers have to make sure operators are aware of and able to meet federal and state requirements.  You’d be surprised to hear how often companies don’t know what they’re supposed to do to comply with the law.  When you exempt operators from permitting, you lose a critical opportunity to correct these misunderstandings early on.

Permitting also allows the state to consider what impacts new well sites might have on the region when combined with other local pollution sources.  An accurate picture of the cumulative effect of multiple sources, especially in areas of concentrated gas development, allows the state to adjust controls to respond to actual air quality conditions.

Finally, Exemption 38 offers very little in the way of enforceability.  To its credit, the final version of the permit exemption is much improved by the inclusion of detailed guidance to operators outlining the type of information they need to provide in order to document their eligibility for an exemption.  However, we believe it is critical that any exemption program be coupled with detailed monitoring and reporting requirements; otherwise, regulators and the public have no assurance that oil and gas operations are staying in compliance on an ongoing basis.  As of now, such monitoring and reporting requirements are absent from Exemption 38.

Ultimately, permit exemptions should be granted only sparingly, and they should be granted only in return for using the most cutting-edge pollution control strategies.  We commend the DEP for making important progress on these fronts.  But any exemptions should also come with robust monitoring and reporting requirements that will guarantee that agencies such as the DEP –the cops on the beat – will know what’s really happening in the field.  This is an area where more work needs to be done.  The silver lining here is the DEP has shown in recent years that it’s willing to keep plugging away at regulatory improvements, so we’re hopeful we’ll have an opportunity to work with the state to make these changes.  Certainly, we must – the health of local communities is what’s at stake.

By Tim O'Connor

This commentary originally appeared on EDF's California Dream 2.0 blog.

By: Tim O'Connor and Shira Silver

Californians struggling with high gas prices should feel optimistic about the future.  A new memo by economists from EDF and Chuck Mason, a prominent economist at the University of Wyoming, demonstrates that policies established to reduce emissions and help the state reach its climate change goals also help to arm consumers at the pump.

The Low Carbon Fuel Standard, cap and trade, and other complementary policies such as Governor Brown’s Zero Emission Vehicle program and national Renewable Portfolio Standards seek to integrate lower or zero-carbon fuels into the energy market in an effort to reduce greenhouse gas pollution.

As our memo explains, in California these efforts also help to increase the market share for alternative, lower-carbon fuels. Between now and 2020, alternatives may grow to occupy between 15 and 24 percent of the market, creating new jobs and addressing the large market share that oil companies have in California.

Currently six oil companies control 94 percent of the fuels market in California. Through a set of mergers and other factors they have developed a strong lock on fuel in the state, and more specifically on consumers’ pocketbooks at the pump.

When alternative fuels enter the market, however, and establish themselves collectively as a ‘competitive fringe’ sector in the market, they could reach almost a quarter of the fuel market for cars and trucks. They have the potential to displace up to 3.7 billion gallons of gasoline a year.

Figure 1. Alternative fuels 2020 projections and market share

Alternative Fuel Type

Year 2020 Projected Volume

Volume of displaced gallons of gasoline in California in 2020 (per year)

% of fuel market share of cars and trucks in CA in 2020 (gasoline and diesel)

Natural Gas-cars

95 MM therms sold

76 million

.5%

Natural Gas-trucks

15-35% new heavy duty trucks

199 million -221 million

1.3-1.5%

Biofuel-ethanol

1.6 billion-2.4 billion gallons

1.6 billion-2.4 billion

10.9-16.4%

Biofuel- biodiesel

5% belend-15% blend into diesel

200 million-600 million

1.3-4%

Electricity and hydrogen passenger vehicles

500,000-1,000,000 vehicles on the road

160.5 million-321 million

1-2%

 

Total displaced gallons of gasoline:

2.3 billion-3.7 billion per year

Market share of alternative fuels:

15-24%

With increased consumer choice from options such as natural gas vehicles, biodiesel and electric cars – overall consumer choice goes up and prices go down.  This healthier market would result in fewer price spikes at the pump, and a more sustainable transportation system.

For the sake of our pocketbooks, we must continue to foster policies that help the environment, create jobs, spur new industries and reduce gas prices. Because in the end we could all use a little more green.

 

By Kate Zerrenner

Over the past several weeks, I've written a lot about the intimate and inextricable connection between energy and water. The energy-water nexus involves a number of technologies, environmental factors and stakeholders. Thus, it’s no surprise that water and energy’s fundamental connection has eluded policymakers for so long. With this post, I review the lessons discussed so far, so that policymakers can understand the key issues surrounding the energy-water nexus and what’s at stake if we fail to act now.

The Bottom Line

Conventional electricity sources, like coal, natural gas and nuclear power plants, require an abundance of water — about 190 billion gallons per day. Because the majority of our electricity comes from these sources, high energy use strains the water system and contributes to Texas’ prolonged drought. Coincidentally, extreme drought could force power plants to shut down.

Climate change is having a profound effect on our weather patterns, making extreme heat and drought more common in Texas and throughout the Southwest. If we don’t set the energy-water system on a sustainable course, we risk a compounded problem.

Finding a solution will require unconventional cooperation and swift action.

To reduce the water footprint of our energy sources, the water consumption of electricity sources should be an integral part of long-term electricity planning, and be reflected in competitive electricity markets.

Today, the lower water impact of wind and solar facilities versus a coal plant is not accounted for in the energy market or by most electricity planners. Renewable energy sources, such as wind and solar photovoltaics, use essentially no water, giving them a vast advantage over fossil-fuel electricity sources. Integrating water use with electricity planning and the wholesale electricity market would help reveal synergies that show just how competitive renewables are with fossil fuels, and speed our transition to a clean energy economy.

Energy efficiency upgrades and reductions in energy use through demand response are some of the most cost-effective energy resources we have. These innovative technologies reduce Texas’ reliance on fossil-fuel electricity and actually bolster our water supply and cut harmful carbon emissions at the same time. Accounting for water use would go a long way towards integrating these unconventional “negawatt” energy resources (technologies that save energy through efficiency) into the power market.

The more we include water and other environmental considerations in the energy market—the faster we can transition to a cleaner, more sustainable energy system.

Of course, it’s a two-way street. The energy and greenhouse gas (GHG) emissions impact of the water system should be a major part of water planning. When water planners consider energy use, they discover unique opportunities to cut energy costs and reduce emissions.

Source: ncsl.org

Mirroring the case for energy, water conservation is the best way to preserve our water supply and reduce the energy required for water operations. Simple strategies, such as using reclaimed wastewater for irrigation, can vastly reduce a city’s water needs. State and municipal planners should always weigh the benefits of water conservation initiatives versus building a new energy-intensive water treatment plant or pipeline.

It’s all connected. Conserving energy saves water and conserving water saves energy.

If we break down the longstanding division between energy and water planning, we reveal the most beneficial steps to improve the efficiency of the energy-water system.

San Antonio: A Model for Energy-Water Co-Management

The city of San Antonio offers a good example of effective energy-water co-management. San Antonio Water System (SAWS) prioritizes energy management and has won numerous awards for its energy savings. The water utility’s most innovative project to date is Dos Rios, a combined sewage treatment and biogas plant that reduces harmful air pollution and generates revenue from the sale of biogas. CPS Energy, the city’s municipally-owned electric utility, even installed a 20 megawatt solar farm at the facility to further cut down GHG emissions and water-use.

San Antonio is a unique case: it has the jurisdictional advantage of local control over both its electricity and water. The city maintains control of its electric utility due to an exception for municipal utilities in Texas’ 1999 electricity deregulation bill, and water utilities remain under municipal control throughout the state. CPS Energy and SAWS recognize each other as among their largest customers, and coordinate their planning cycles accordingly.

The city also benefits from a uniquely water-smart population. Until recently, San Antonio received all its water from one source, the Edwards Aquifer. Because the aquifer is a vital water source for a large portion of South-Central Texas, San Antonio residents were raised with water conservation in mind to preserve the aquifer.

The unique factors contributing to San Antonio’s leadership in energy-water co-management can’t be seamlessly transplanted into other cities and counties. The regulatory division between electric and water utilities is complex and varies from state to state. Nevertheless, San Antonio embodies the best practices that could be adopted and applied to many cities’ unique energy-water challenges.

Facing the energy-water nexus head on will take a monumental effort from the highest levels of government. We’re just now realizing the profound connection between energy and water use —but the energy-water nexus will be with us for some time. Climate change is accelerating, and we can expect drought to become more common in the future.

We have to emphasize energy and water co-management as the nation’s energy system slowly evolves and prioritize low-water and low-carbon options like wind and solar. Leaders at the local, state, national and international levels should bridge the divide between energy and water as they develop solutions to transform the global energy system and cope with a changing climate.

By Marita Mirzatuny

Source: Nest

If you have been following our Texas Energy Crunch campaign over the last year, you know that demand response (DR) can play a pivotal role in meeting Texas’ energy needs without relying on dirty, inefficient fossil fuels that pollute our air and consume much-needed water.  Simply put, demand response rewards those who reduce electricity use during peak (high energy demand) times, resulting in more money in peoples’ pockets, a more stable and reliable electric grid and less harmful pollution from fossil fuel-fired power plants.

That said, fully harnessing DR in Texas homes has been a bit of a challenge, despite the high electricity prices that result from the scorching summer temperatures.  To understand the issue, it’s important to look at the obstacles emerging technologies often face.  I highlight some of these obstacles in a recent EDF Voices blog and will be diving deeper in future posts.  Namely, the infrastructure to fully enable residential DR adoption isn’t in place, yet.

More smart meters have been deployed in Texas than any other state, but the other half of the equation – the customer-facing devices – has not been adopted with as much zest.  As it stands, utilities mainly benefit from smart meters, while customers wait for home energy management (HEM) devices.  These devices will empower customers by enabling them to control their use energy and reduce electricity costs.  HEM devices will also account for customer’s energy conservation efforts and reward them accordingly.  There are still many unanswered questions about how HEM systems can really take off, but some Texas electric utilities are leading the charge with pilot projects.

Earlier this year, Austin Energy (AE) launched Power Partners, using Nest learning thermostats and other brands, such as Ecobee, Filtrete, etc.  These smart thermostats allow AE to cycle off air conditioning units, with the owner’s permission, when the power grid is particularly strained during peak times.  AE hopes the project will “help the community lower summer power demands, prevent power outages and delay the need to build new power plants.”  To top it all off, customers received an $85 rebate per thermostat for participating.

Nest refers to its AE partnership as “Rush Hour Rewards,” which introduces an interesting analogy to help explain demand response: “Rush Hours will occur sometime between 2-7 pm, usually from 4-6 pm, and only on weekdays.  You'll only get one rush hour a day, and rush hours won't happen more than three days in a row.”  Of course, the home owner always has the chance to override the Rush Hour request. Furthermore, the Nest community forum and blog allows customers to ask questions, share stories and offer advice, allowing for Nest to listen and improve its product.

So far the program has been a success.  On June 27th temperatures in Austin soared to a blazing 103°F, pushing the power grid to its limits.  Nest thermostats lowered AC runtime during the hottest part of the day by 56%, on average.  Before the Rush Hour event, Nest pre-cooled many of the homes and let temperatures rise slowly by less than 1.6°F on average.  This not only prevented the onset of a potential blackout, but prevented a lot of dirty coal from being burned to meet the rising energy demand.

Was AE successful?

Yes!  Only one out of every ten participants adjusted the thermostat highlighting the ultimate control that the consumer maintains at all times.  The following day, when temperatures reached 106°F, AE signaled another event.   Rush Hour Rewards lowered AC use by 49%, on average, and only 12% of participants adjusted their thermostats settings.  These results show that when customers have the right tools at hand and are given the option to capture energy savings, they are all for it.  As HEM systems become more readily available, utilities will see an empowered customer base eager to earn money through energy conservation.

According to Fred Yebra, Austin Energy Director of Energy Efficiency Services, “as the rapid pace of new technology continues to advance using smart phones and other smart devices, Austin Energy will provide new programs and incentives to increase convenience, comfort and savings for our customers.”

As the smart grid, or the “energy internet” advances, it will become increasingly important for electric utilities to keep pace with innovation.  We applaud Austin Energy, Nest, and the other companies for sparking the momentum in Texas.  Their leadership helps raise the bar for other electric utilities seeking to modernize their outdated, analog energy systems.

Innovative approaches, such as AE and Nest’s ‘Rush Hour Rewards, allow consumers and utilities to become partners – producing and reducing power together.  This will help advance the technological investments needed to promote energy conservation and accelerate the transition to a clean energy economy.

By John Finnigan

A new documentary about smart meters opens on September 5th called Take Back Your Power.  The film suggests that smart meters cause illness.  According to an August 12 USA Today story, the film’s director was inspired by a friend who became seriously ill after a smart meter was installed at his home.  Naturally, this type of personal experience might shape one’s view on smart meters, but correlation is not causation.

Electric utilities have installed over 38 million smart meters across the country and there “has never been a documented injury or health problem associated with such meters.”  According to the Federal Communication Commission (FCC), “no scientific evidence establishes a causal link between wireless device use and cancer or other illnesses.”

Smart meters send information to utilities by using radio frequencies (RFs) such as those currently used by televisions, radios, baby monitors, cell phones and wifi routers.  RF signals have permeated our atmosphere for as long as we’ve had televisions and radios.

We use these devices every day, and many of them create much higher levels of RF exposure than smart meters.  The exposure level depends on the strength of the RF signal emitted by the device, the duration of the RF signal and—importantly— the distance from the source.  Cell phones emit up to several thousand times more RF signals than smart meters.  Smart meters also transmit intermittently and briefly during the day, while we talk on cell phones for long periods.  Finally, smart meters are located outside the home, while cell phones are often used close to one’s head.

These factors result in a dramatic difference in RF exposure from smart meters compared to cell phones.  So, whether or not future studies find that RFs cause health impacts (because current studies do not; see these reports by: Lawrence Berkley National Laboratory and Electric Power Research Industry), smart meters make up a very small part of a person’s daily exposure.

Smart meters are an integral part of a smarter utility system that makes better use of distributed, clean energy, manages energy demand more intelligently and gives customers – for the first time ever – an active role in using, choosing and controlling the energy they need to power their homes and businesses.  Smart meters are an important ingredient in designing a clean, less polluting, low-carbon energy system.

EDF has a long history of working at the intersection where the environment meets human health, and our internal experts have taken a very hard look  at the available research on RFs.  However, we support utilities taking a proactive consumer-oriented approach to smart grid installations, including allowing individuals who oppose the installation of smart meters in their homes to be able to opt out.  The opt out option not only allows people to control whether or not they receive a smart meter, but it also allows everyone else – customers and utilities included – to reap the vast array of economic, environmental and health benefits from modernizing our antiquated, wasteful and polluting energy infrastructure.

Given the significant environmental and health-related benefits that could result from a more efficient, resilient grid by way of more locally-generated clean energy and fewer fossil-fuel power plants, EDF believes that case for smart meters is much stronger than the case against them.  The following states investigated the issue in connection with their smart grid deployments and reached the same conclusion: Arizona, California, Connecticut, Hawaii, Maine, Michigan, Wyoming and most recently Texas.

For more information on this topic, please see the Smart Grid Consumer Collaborative’s video Separating the facts from the Fiction about Smart Meters.

By Brad Copithorne

This commentary originally appeared on EDF's California Dream 2.0 blog.

For over two years, EDF has been working to establish an On-Bill Repayment program in California that would allow property owners to finance energy efficiency or renewable generation projects and repay the obligation through their utility bill.  Since utility bills tend to get paid and the obligation could ‘run with the meter’, defaults are expected to be low, which will improve the availability and reduce the cost of financing.  In May 2012, the California Public Utilities Commission (“CPUC”) agreed with our position and ordered the large utilities in California to develop a program for commercial properties.  EDF estimates that this program could generate $5B of investment over 12 years, which is expected to support 36,000 jobs.

Unfortunately, we are still waiting for the nonresidential OBR pilot in California to be implemented and if the utilities get their way, we may be waiting for close to another full year.  The California utilities appear to be fearful of change, distributed generation, and the impact of reduced demand.  They have employed aggressive tactics with teams of lawyers arguing and re-arguing every potential issue, even after the issues have presumably been settled by the CPUC.

This stands in sharp contrast to what is happening in Hawaii.  On March 25, the Hawaii Public Utilities Commission (“HPUC”) ordered the primary Hawaii utility, Hawaiian Electric Company, (“HECO”) to establish an OBR program for residential and commercial customers.  I just returned from 3 days in Honolulu and it appears that they are working cooperatively to get the program running in the first quarter of 2014.  This timetable of 12 months from HPUC order to implementation is less than half of what we seem to need in California, despite the fact that the Hawaii program covers a much broader range of property types and relies on public as well as private sources of financing.

The difference in timelines seems to be driven by the attitudes of the utilities.  While HECO is working to solve problems, the California utilities are looking to create roadblocks.  I saw this in action last week in Hawaii.

One of the key design elements of an OBR program is a method to allocate the money when a customer pays only part of the bill.  As you would imagine, the utilities generally want to be paid first.  Unfortunately, we have heard from both prospective lenders and rating agencies that this would make an OBR program largely unattractive.  Their concern is that a utility that is getting paid in full might lack incentive to aggressively collect any money still owed to the bank.  EDF has advocated that partial payments be allocated proportionally to the amount owed to each party.  That seems fair to us and last May the CPUC agreed and ordered the program be established that way.  Unfortunately, that has not been the end of the story.  The utilities have complained that this was expensive to do (evidently their billing systems are run with an abacus), that this would somehow increase their credit losses (OBR actually has the banks sharing utility credit losses that the utilities would otherwise incur) and, most improbably, that proportional allocation is somehow illegal.

Last week, I braced myself when a HECO representative started talking about how expensive it would be to implement proportional payments.  Besides, since it does not happen very often, why do the banks care so much?  I replied with an explanation of why it mattered and finished with a challenge.  “If partial payments don’t happen very often, why not let the banks get paid first?”

Much to my delight, his reply was, “We have been discussing that option and may very well go that direction.”

HECO is clearly a utility that wants to help their customers reduce utility bills and looks to solve problems.  I only wish our California utilities could develop that kind of can-do attitude to get an OBR program running by early next year.

 

By Jon Goldstein

The Latin phrase “Scientia potentia est” may not ring a bell, but its translation should: knowledge is power.

The oil and gas industry spends millions every year to expand  its knowledge of underground energy reserves. That is because better geologic knowledge is powerful stuff, it can mean the difference between a very profitable well or a very expensive dry hole.

Doesn’t it make sense then for the industry to also invest in better knowledge of local water resources? Investing a small amount in understanding local groundwater quality before you drill, and following up to monitor whether that water is potentially impacted once energy production commences is also incredibly powerful for local residents, state regulators and the industry alike.

Wyoming oil and gas regulators have proposed a testing program that aims to do exactly this – establish a groundwater quality baseline in areas where oil and gas development is planned, and then follow up with two sets of tests to monitor for potential impacts from this specific activity.

Now open for public comment until October 7, the Wyoming draft rule would, on the whole, create a strong, scientifically valid groundwater testing program. This program would provide transparency and a first line of defense for local residents to help detect any groundwater contamination that may result from oil and natural gas development. It will help the state meet its obligations to protect groundwater resources and public health. And it will offer cheap insurance for industry if groundwater contamination that exists before drilling begins is mistakenly attributed to operators.

Wyoming’s groundwater testing proposal has several strong suits. It contains no arbitrary cap on the number of water wells tested and ensures testing happens within a scientifically appropriate distance from development. It relies on state oversight including technical experts at the Wyoming Oil and Gas Conservation Commission (WOGCC) and the Wyoming Department of Environmental Quality. And it includes a strong, universally applied Sampling and Analysis Plan (SAP) that ensures an “apples to apples” comparison of results. To our knowledge Wyoming’s proposed SAP is the most detailed guidance provided by any state regarding how private water wells should be sampled.

Meanwhile, Wyoming’s proposed program would do all this without costing producers any more than they have to spend to comply with other states’ less rigorous programs.

Governor Mead, his staff, and the WOGCC deserve a lot of credit for leading this initiative.

While the framework is strong, there are still a few issues that deserve attention. Based on feedback it received during an earlier, informal public comment period, the WOGCC made several changes to the draft version of rule. At least two changes that have been requested by industry representatives could be problematic.

Dissolved Gasses: The WOGCC’s original draft rule included two levels of dissolved methane with differing requirements: a level of 1 milligram per liter (mg/l) to trigger further scientific analysis of groundwater and a 10 mg/l level to trigger immediate notification of landowners and regulators. At the request of industry, both have been changed to 10 mg/l. This is a major flaw that can and should be fixed. Weakening the scientific analysis trigger by a factor of 10 provides inadequate protection. It would fail to ensure that potential water contamination that is caused by drilling is caught quickly. Both the Colorado Oil and Gas Conservation Commission’s rule and the Colorado Oil and Gas Association’s voluntary program include a 1 mg/l level to trigger further scientific analysis. A weak 10 mg/l initial trigger has the potential of subverting the purpose of the groundwater testing program – to better understand potential drilling impacts as quickly as possible so that they may be addressed.

Master Plans: The rule has been amended to allow developers to seek approval for “master plans” that would cover multiple wells over potentially large geographic areas. If these plans are simply a way to better coordinate the required testing protocols with a company’s drilling program, to improve data management or to seek efficiencies in submittals to the WOGCC, this could be positive. However, these master plans should in no way undermine the strong, well-by-well approach taken in the larger rule. Mandating that at a minimum these plans are open for public review could help address some of these issues.

EDF will continue to advocate for these needed improvements as this rule moves toward a hearing scheduled for October 15. In the meantime, we encourage you to exercise your power and comment as well.

By Brad Copithorne

This commentary originally appeared on EDF's Voices blog.

Source: jurvetson/Flickr

The European Union, the United Kingdom, Australia and the State of California have all set ambitious targets to reduce greenhouse gas emissions 80% by 2050. Given that a large share of global greenhouse gas emissions comes from transportation (including 29% of U.S. emissions), it will be very tough to meet this goal without “decarbonizing” our cars and trucks.

The most obvious solution is electric vehicles (EVs) charged by clean energy sources like solar or wind. While several startup EV companies – including Fisker, Coda and Better Place – have struggled, the Tesla car company seems to be succeeding. At least that’s the current view of the markets: Tesla shares have more than tripled since March and in May the company raised almost $1 billion in new capital.

Test driving the Tesla

In June, I decided to see what the all the fuss was about and went for a test drive. The Tesla Model S is the kind of revolutionary idea that can only happen when a product is designed with a clean sheet of paper. Most EV designs start with a conventional car and have the batteries stuffed in the trunk or under the seats. A Tesla battery is part of the undercarriage of the car. This lowers the center of gravity and creates a car that handles like a supercar. Tesla also replaced all the buttons on the center console with a 17” touchscreen that doubles as the most beautiful and functional navigation system that I have ever seen. The Tesla received the highest score ever from Consumer Reports for a car and won car of the year from Motor Trend and Automobile Magazine.

Another Tesla innovation is their sales process. Tesla owns their own showrooms. Cars are generally built to order and salespeople are not paid on commission. This allows the company to save a great deal of money by reducing inventory, costs and the profit margin of the middleman (the dealer). Unfortunately, the conventional auto industry is fighting back and they are using dirty tactics by invoking franchise laws.

Push back from dealers

Other than Tesla, most all cars are sold through networks of dealers. The dealers take risks by owning inventory and building local relationships. Franchise laws exist in most states to protect dealers from the risk that suppliers could try to wipe out the value of their investment by cutting them out of the sales cycle. The laws were created to protect a Chevy dealer from GM, not to protect the dealer from someone introducing a better product.

As outlined in a recent article in the Wall Street Journal, gasoline car dealers are attempting to use these laws to prevent Tesla from directly selling cars in Texas, North Carolina, Minnesota and Virginia. I would rather the incumbent car companies spend the effort on designing an EV that can compete with Tesla. If you agree, a petition has been started that asks states to allow Tesla to compete directly.

Sticker shock

One criticism of Tesla is that their products are only practical for wealthy consumers. With a current minimum price north of $60K, it seems hard today to argue with that position. On the other hand, most electronic consumer products tend to be extremely expensive in their early incarnations. How many people had cell phones 25 years ago?

I had the privilege of hearing Stephen Chu, the former Secretary of Energy, speak about the topic recently. He said that at current rates of improvement in battery technology, EVs would be clearly superior to gasoline powered cars by 2020. Chu showed a graph of declining battery prices over time. In 2007, it cost about $1000 to buy a battery that would store 1 kilowatt-hour (kwh) of energy. This is enough to power an EV three to four. In 2012 the market price was down to $500 per kwh and he expected that to be near $200 by 2020. Additionally, he believed that Tesla may be ahead of the game and be currently producing these batteries at around $300 per kwh. The future is coming.

So, how was my test drive? In a word, it was outstanding. The car is fun, fast and stylish. I put my deposit down in June and took delivery in late July. With solar panels on the roof of our house, I am now driving the zero-carbon vehicle of the future.