Decarbonization Roadmap for the Midcontinent

Written by: Doug Scott, Vice President, Strategic Initiatives, Great Plains Institute and former Chair & Commissioner, Illinois Commerce Commission

Chairman Scott

Doug Scott

By 2050, the midcontinent region of the United States could achieve substantial decarbonization of the electric generation sector through a number of pathways, utilizing existing technologies. That is just one of the key findings of “A Roadmap to Decarbonization in the Midcontinent”, which was released July 24 by the Midcontinent Power Sector Collaborative (Collaborative).

The Collaborative is a diverse group of stakeholders located in the 15 states that comprise the footprint of the Midcontinent Independent System Operator (MISO). The group includes investor-owned utilities (IOU), merchant power producers, power cooperatives, public power, environmental organizations and observing state officials, and is staffed by the Great Plains Institute. The region includes all or part of the following states: Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas and Wisconsin.

Participants in the Collaborative, which has been meeting since 2012, believe that the electricity sector will substantially decarbonize by mid-century, due to a number of factors. Consider all of the changes that are occurring in the sector that are leading to a more decarbonized system: lower natural gas and renewable costs; consumer demand for energy efficiency and renewables; investor demand for lower carbon risk; an aging infrastructure which allows for replacement of generation; flat or declining energy demand; and technology that is driving many of the changes. Collaborative members also believe that it is likely that future government policy will require decarbonization.

Against this backdrop, Collaborative participants utilized modeling to demonstrate various pathways to 80 percent and 95 percent decarbonization of the electricity sector by 2050. The goal is to help inform public policy, as stakeholders and policy makers are working to establish their energy futures.

In addition to identifying various pathways to decarbonization by 2050, the roadmap had a number of other key findings. Some of those findings are:

  • Because electrification is likely to play a huge role for transportation and buildings, decarbonization of the electric sector is essential.
  • The region will need to utilize a variety of very low or zero-carbon resources to achieve decarbonization, including natural gas with carbon capture, renewable energy and energy efficiency.
  • It will be necessary to explore in future phases of the roadmap the role that energy efficiency can play in decarbonization, as well as the role that can be played by flexible demand and other distributed energy resources.
  • The region must step up its deployment of renewables to be on a path to decarbonization, but it is not universally agreed upon how much wind and solar resources can be added and remain cost-effective.
  • Investment in research, development and deployment of new zero or low-emission technologies (such as energy storage, new nuclear plants and carbon capture) will be necessary.
  • Waiting to take carbon risk into account may have consequences, including larger costs in later years.
  • There are unique characteristics to the midcontinent region, including the existing large amounts of wind on the system, its current complimentary nature with other generation sources.
  • Transmission plays an important role to lower the overall cost of decarbonization.

While Collaborative participants did not reach agreement on all aspects of the research, the report does contain a number of consensus principles for policy makers and regulators, that the group hopes may be utilized by stakeholders and public officials as they make decision on the future of electricity generation in the midcontinent. Among those consensus principles are the following:

  1. Invest in all cost-effective energy efficiency.
  2. Invest in cost-effective renewable energy.
  3. Very low and zero-carbon resources that are dispatchable and flexible to follow load will be essential on the system.
  4. Preserve existing nuclear power to the extent it makes technical, economic and environmental sense.
  5. Investments in carbon-emitting resources should be evaluated against the genuine risk that substantial decarbonization of the sector will be required by mid-century.
  6. Step changes are not foreseeable, and energy and carbon policies must be flexible enough to accommodate those changes.
  7. Flexible, market-based approaches to reducing carbon emissions have advantages because they do not pick winners among different technology types and allow the market to find the lowest cost solutions. But because there are drawbacks to the flexibility of a market=based policy, policies that support the development of a broader mix of technologies is prudent.
  8. Targeted incentives to spur research, development and deployment of key low-or-zero-carbon technologies will be important just as tax incentives for renewables have been effective at lowering the cost of those technologies.
  9. Wholesale electricity market structures should evolve to value attributes that contribute to a lower-carbon grid.

The Collaborative will continue its work, next addressing the potential impact of electrification of the transportation and building sectors. The group is hopeful that the Roadmap and its future additions will provide a useful resource as policy makers continue to address the rapidly-changing world of power generation, and make the best decisions they can for their residents.

The full roadmap may be found at roadmap.betterenergy.org.

 

FUTURE Act Passage Will Spur Carbon Capture Activity

Written by: Doug Scott, Vice President, Strategic Initiatives, Great Plains Institute and former Chair & Commissioner, Illinois Commerce Commission

Chairman Scott

Doug Scott

Recent passage of federal legislation may significantly change the economic prospects for coal plants and other industrial facilities that incorporate carbon capture technology. The wide-ranging budget bill passed by Congress and signed by the President in February includes the FUTURE Act, bi-partisan legislation introduced last year in the U.S. Senate to reform the federal tax credit for capturing and storing carbon dioxide (CO2) from power plants and industrial facilities.

The lead Senate sponsors of the FUTURE Act were Heidi Heitkamp (D-ND), Shelley Moore Capito (R-WV), Sheldon Whitehouse (D-RI), and John Barrasso (R-WY). They were joined by over 20 additional Senate co-sponsors. Congressman Mike Conaway (R-TX) led a similar bi-partisan effort in the U.S. House.

Specifically, the bill does the following:

Enhanced Tax Credit

The legislation increases the amount of the credit to $35 per ton for CO2 stored geologically through enhanced oil recovery (EOR), and $50 per ton for CO2 storage in other geologic formations, and not used for EOR or other purposes. The prior credit of $10 and $20 respectively, simply did not sufficiently close the gap that makes capture projects economic. The difference in the credit amounts for beneficial use and storage are to recognize that captured CO2 has a value that can be realized in certain marketplaces, such as for EOR.

Lifting the Credit Cap

Prior to the passage of this legislation, the tax credit was capped at 75 million tons of captured CO2, available on a first-come, first-serve basis. This caused uncertainty for projects, as developers didn’t know if the credits would be available to them. This was not discernable until after a project was financed, which meant the credit couldn’t be used to attract private finance. The new legislation removed the cap on credits.

Lowering the Capture Threshold

The new legislation will allow more projects to be eligible for the credits, by lowering the threshold of metric tons of CO2 needed to be captured in order to qualify. The previous level was 500, 000 tons, which remains for electric generating units in the new act. But it has been lowered to 100,000 metric tons for all other industrial facilities. This will allow more facilities to participate, and should result in additional captured CO2. This expansion will be very important for facilities such as ethanol production.

Greater Flexibility in Who Claims Credit

Before passage of the new act, the tax credit could only be claimed by the company that both captured and stored (physically or contractually) the CO2. In the new construct, the owner of the carbon capture equipment is the recipient of the credit. The recipient can allow another entity involved in storing or beneficially utilizing the CO2 to claim the credit. Because these projects are very often complicated, involving multiple players, allowing this flexibility may allow for better credit utilization and likely easier financing in many instances.

The FUTURE Act had wide, bi-partisan support. As mentioned earlier, it was co-sponsored by one-quarter of the Senate, with great geographic and philosophic diversity. And efforts to enhance the carbon capture tax credit received support from a number of Governors, and organizations including the Western Governors Association (WGA), the Southern States Energy Board (SSEB) and the National Association of Regulatory Electric Commissioners (NARUC).

Significant support also came from the Carbon Capture Coalition (formerly the National Enhanced Oil Recovery Initiative), a wide-ranging stakeholder group that energy, industrial and technology companies, energy and environmental policy organizations and labor unions.

Reforming the 45Q tax credit was also the cornerstone of policy recommendations put forth by a bi-partisan State CO2-EOR Work Group consisting of 14 states from around the country. The bi-partisan support for this legislation is rarely found today, especially on issues involving energy.

It is anticipated that passage of this legislation, for the reasons listed above, will result in a number of new carbon capture projects moving forward. This should thus provide a role for carbon capture at coal and natural gas plants going forward, and add them to the mix of potential sources of energy as we plan our energy future.

IoT and LoRaWAN: Transforming AMI utility networking systems

 

Sponsored by: Cheryl Norton, President, Missouri American Water. ~ Written by: David Stewart Jones, Writer, Researcher, & Journalist

David Stewart Jones updated 185 X 270

David Stewart Jones

Proprietary Advanced Metering Infrastructure (AMI) systems have been a driving force in the water industry for the past decade. However, new infrastructure management systems based “Internet of Things” (IoT) connectivity harnessing “LoRaWAN” (Low-Power/Wide-Area) long-range wireless telecommunications now have the potential to become the new industry standard. With open standards and open architecture, these new IoT-based systems are poised to rapidly replace older single-purpose systems — and revolutionize water utility infrastructure management.

IoT and LoRaWAN networking

“Today — in 2017 — do utilities really want to keep adopting proprietary systems that will never be capable of doing anything beyond reading meters for the next 15 to 20 years?” asks Thomas Butler, marketing VP with AMI systems provider Mueller Systems.

Advanced Metering Infrastructure (AMI) systems over the past decade have largely replaced older “drive-by” automatic meter reading (AMR) systems used by water utilities in North America. Delivering continuously available two-way data-gathering and communications between the network and metering devices, AMI systems accurately measure and collect detailed usage and billing information and enable a broad array of operational and customer-service benefits. Although capable and proven, most existing AMI systems are proprietary designs that are typically limited to meter-reading and data-gathering capabilities — “one-trick ponies” with limited functionality that cannot be easily expanded or adapted to meet the future needs of water utilities.

However, many utilities are now seizing opportunities to take their AMI system to the next level. Emerging next-generation AMI systems are incorporating the latest “Internet of Things” (IoT) technologies providing two-way communications and data transfer with specialized cloud-connected remote sensors and devices that is ushering in a new era of automated infrastructure management. Revolutionary advances include LoRaWAN™ wireless RF technology that enables connecting low-cost battery-operated sensors over long distances in harsh environments, ideal for water utilities operating across vast areas where wired connectivity would be extremely challenging or cost-prohibitive.

LoRaWAN wireless wide-area networking provides secure communications between remote sensors, devices, and enterprise-grade public and private networks for IoT, industrial, and “smart city” applications. Embraced by industry leaders like Comcast, IBM, Cisco, and others, LoRaWAN and its communications protocols have become an open global standard supported by more than 500 industry leaders. In use by a number of public network operators and included in many trial and deployments, LoRaWAN is rapidly emerging as a new industry standard for water utilities.

“Many water utilities simply cannot imagine some of the unforeseen challenges and specialized needs they will be facing in two years, much less five years, or ten years down the road. So why would they lock themselves into an infrastructure management system that can’t keep up with their needs?” says Mueller Systems’ Butler. “An AMI system based on LoRaWAN technology will read your meters today, monitor pipeline leaks tomorrow, and perform real-time water quality analysis next year if you need it. These new IoT-based AMI systems create ‘smart utilities’, yet support everything from monitoring parking meters to tracking pets. The potential uses are endless.”

“Open standards” AMI systems

Wirelessly connected AMI water distribution components are providing unexpected solutions to long-standing problems. Shortly after Pennsylvania American Water acquired a Scranton/Wilkes-Barre-area utility two decades ago, the utility discovered a number of service problems and billing disputes involving several neighborhoods with water service lines originally installed in an unusual “shared service” arrangement.

 Instead of the typical installation with each property connected by a separate service line and dedicated shutoff valve, multiple properties in these neighborhoods were sharing a single service line controlled by a single curbside shutoff valve. The utility could not shut off water service to one resident without interrupting service to adjacent neighbors — and some customers who believed they were safe from service disconnection actually stopped paying their water bills.

“The only remedy a few years ago for these kinds of infrastructure mistakes was to retrofit new service lines and shutoff valves throughout entire neighborhoods, an undertaking that was far too costly just to avoid problems with service disconnections and non-paying customers,” says David Hughes, infrastructure engineer with water and wastewater public utility American Water. “However, our new AMI network enabled us to completely sidestep the need to retrofit new service lines and shutoff valves in those Scranton/Wilkes-Barre neighborhoods, and the remote-disconnect AMI water meters gave us full inside-the-meter control over water service in areas where we previously had virtually no control at all.”

In contrast to older AMI systems based on proprietary technologies using undisclosed software coding methods, emerging next-generation AMI systems are designed to “open standards,” developed using freely available “open source” software code and algorithms. Shared and maintained by multiple industry vendors using “open architecture” design, standards-based development encourages open collaboration between utilities, industry vendors, and service providers, and simplifies adding, upgrading and integrating system components to a standards-based AMI system.

“A standards-based AMI system enables utilities to focus on their core water distribution business, get out of the communications networking business, and quickly deploy or integrate the right tool when needed,” says John Marciszewski of Echologics, provider of EchoShore® pipeline leak detection and monitoring technology to American Water.

A pipeline leak monitoring and detection platform for water distribution systems, EchoShore technology uses battery-powered monitoring “nodes” incorporating ultra-sensitive acoustic sensors to detect and pinpoint water leaks long before they become detectable by conventional detection methods. Echologics is developing a toolkit that enables LoRaWAN users to make EchoShore technology interoperable over an AMI/LoRaWAN network, enabling utilities to quickly integrate and deploy the leak-monitoring platform — or interchangeably deploy a different solution.

“Utilities implementing a standards-based AMI network are no longer locked into customized and proprietary solutions from a single provider, and open standards enables utilities to choose freely among third-party manufacturers and vendors offering AMI products and technologies,” says Marciszewski. “Older AMI systems have limited capabilities, but having an open communications protocol enables compatibility with thousands of different products and applications. Could you imagine having your smartphone limited to running only five different applications?”

“Smart Cities” vision

Standards-based AMI networks with LoRaWAN connectivity have the potential to fulfill the “Smart Cities” vision for transforming tomorrow’s urban landscape. Using IoT technologies to link, monitor, and control all aspects of municipal services, including electrical grid and natural gas consumption, smart roads and traffic control, environmental monitoring and safety, structural health, water leakage detection, water quality monitoring, automated waste management, and more.

“The water industry is just getting started with Internet of Things technologies,” says Cheryl Norton, president of Missouri American Water. “We are behind some other industries and we have a lot of work to do, but is very exciting to be on the technology forefront, and discovering new ways for our industry to operate more efficiently and conserve and protect our precious water resources are the key elements of our industry future.”

Norton notes that the new standards-based AMI systems also have the potential to provide utilities with a robust cyber-security program. “Utilities that don’t have a cyber-security program absolutely need take a step back right now and come up with a plan, because ignoring cyber-security could cause a complete downfall of our industry.”

Standards-based AMI networks also have the potential to be a unifying technology capable of simultaneously serving multiple types of utilities with a single infrastructure communications network, providing the seamless interoperability needed for tomorrow’s “water-energy nexus.”

“Ultimately, all utilities — water, power, and gas — are serving the same ratepayer. So why are we requiring ratepayers to support three or four different systems in the same area?” asks NJ Board of Public Utilities Commissioner Mary-Anna Holden, who is also National Association of Regulatory Utility Commissioners’ (NARUC) Water Committee Chair.

“If it can be done all in a single platform, and some areas are already initiating projects for sharing a single AMI network among local water, power and gas services,” Commissioner Holden continued, “Don’t limit your vision. Include future ‘Smart City’ capabilities into your utility, municipality, or regional planning instead of limited-capability infrastructure management systems.”

David Stewart Jones is a freelance writer and researcher based in Toronto, Canada. Correspondence can be addressed to fri@missouri.edu, or emailed to davidstewartjones@outlook.com.

The Importance of Rate Case “Fundamentals”

Sponsored by: Pauline Ahern, Executive Director, ScottMadden, Inc. ~ Written by: Eric Hanson, Managing Associate & Preston Fowler, Director, ScottMadden, Inc.

Pauline Ahern

Pauline Ahern

After a few years of declining rate case filings, the number of electric and gas utilities filing rate cases in 2016 increased significantly. This trend continued into 2017 as 63 rate cases (41 electric and 22 gas) were filed in the first quarter alone. In addition to these cases, another 21 electric and gas utilities have indicated they plan to file a rate case before the end of the calendar year. 2017 cases filed-to-date represent an aggregate requested increase of approximately $3.9 billion. Recovering the costs associated with constructing and/or replacing assets remains the primary reason for these requested increases.

However, many of the cases filed include efforts by utilities to seek policy changes to address emerging issues that are impacting the industry. Though the specific changes being pursued vary based on numerous factors, including the type of utility, geographic location, regulatory environment, existing asset base, etc., they typically include:

Eric Hanson

Eric Hanson

Modifications to traditional rate design to address stagnant/declining load growth and associated revenues, increased penetration of distributed energy resources (particularly solar), and other technologies that are impacting demand, rapidly transforming the grid (primarily on the distribution side), and slowly changing the utility business model.

Adaptation of traditional rate-making constructs toward performance-based ratemaking, multi-year rate cases, future test years, etc., to encourage utility investments in grid modernization, reduce regulatory lag, and promote customer-centric outcomes.

Transitioning the generation fleet from traditional centralized baseload plants (particularly older coal, oil, and in some instances nuclear) toward natural gas, renewables, and other more distributed and flexible generation assets that produce lower direct carbon emissions.

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Preston Fowler

Pursuit of pilot or experimental programs like battery storage, system-wide AMI deployment, and other technology deployments to improve operations and oversight at the distribution level.

Special riders targeting infrastructure replacement, particularly true for gas utilities to replace existing cast iron pipes and steel mains.

It is important to note that this list does not include any of the modifications to energy regulations that the Trump Administration has implemented either through Executive Order or proposed through legislative solutions. These modifications include repealing many of the regulations enacted under previous administrations, eliminating the production and/or investment tax credit for wind and solar resources, pre-empting state laws relating to renewable portfolio standards, and other policies that promote renewable resources, could have a significant impact on utilities. Given these potential impacts, it is a safe assumption that state regulatory commissions will continue to desire some degree of oversight, either through rate cases or other regulatory mechanisms, over how utilities will respond to potential changes in federal laws/regulations.

As a result, based on our experience, many utilities have or will soon be hitting the perfect storm when it comes to preparing and filing rate cases. Utilities will likely be filing rate cases more frequently, and the rate cases will be more complex. In many instances, the people preparing the rate cases may not have the necessary resources or skills. To overcome these obstacles, utilities will need to focus on the “fundamentals” to help ensure a favorable outcome

Focusing on the Fundamentals

Many of you probably remember your high school coach, whatever sport in which you participated, telling you to “focus on the fundamentals.” Improving the basic kicking, throwing, or catching skills applicable to your chosen sport was a precursor to winning games. Often in business, the American Football analogy of “blocking and tackling” is used to describe basic, simple, or mundane tasks associated with a larger effort. This characterization is unfortunate because anybody with knowledge of football understands that a team will not be successful (i.e., score a touchdown/field goal or stop an opponent from scoring) if it cannot block and tackle effectively. The need to focus on fundamentals is also true when filing a rate case. These fundamentals include:

  • Developing a comprehensive work plan and providing the necessary support to ensure adherence to the plan. The work plan typically involves thinking through all of the activities required to complete the rate case, and the dates by which they should be completed, including an appropriate timeline that provides adequate flexibility to allow for unexpected issues, supporting analysis, and legal and management review and approval;
  • Ensuring that strategic themes are formalized and agreed upon early in the case and approved by senior management. These themes could be pursued in the case or simply introduced in the case to lay the groundwork for discussion in a separate forum;
  • Determining which functional areas will be engaged in developing the rate case and ensuring that everyone understands their role/responsibilities and what is expected from them for the rate case;
  • Identifying the witnesses who will be responsible for writing direct testimony and ensuring that their testimony is tailored to address the strategic themes of the case. For newer witnesses, this often requires educating the individual(s) on the rate case process and providing assistance outlining and drafting testimony;
  • Establishing a process with which to manage the substantial amount of data and documents that are included in the rate case filing to ensure version control is maintained throughout the drafting, review, and approval process. While often overlooked, this should also include establishing an issues/actions/decisions log that tracks all outstanding issues as well as decisions that have been made to date; and
  • Setting a meeting cadence that ensures the multitude of individuals involved in developing the case are on the same page in terms of strategic themes, timelines/due dates, etc., and having a forum to discuss and resolve outstanding issues. This also includes establishing a process to ensure members of senior management are aware of the specific case components so they are able to think strategically about how the case could impact other parts of the business.

Why Is This Important?

Given all that utility personnel have on their plate during the rate case process, often times these “fundamentals” are overlooked. Unfortunately, failure to develop and adhere to a proper work plan, establish strategic priorities, clearly outline roles and responsibilities, keep everyone informed of progress through regular meetings, etc., can lead to significant difficulties later in the process. Having a team and process in place that will support the filing of the rate case in a timely manner is of significant importance to a utility. Given that the purpose of most rate case filings is to increase the revenue requirement, the faster and more complete a rate case can be filed, the faster it may move through the process, and, if approved, the faster the rate increase will be implemented. Filing a rate case that lacks sufficient detail(s) or contains analytical or logical errors, cannot be well argued, etc., creates the risk of a less favorable rate case outcome

Are Missouri’s Renewable Energy Standards Outdated?

Written by: Commissioner Scott Rupp, Missouri Public Service Commission

Commissioner Scott Rupp

Commissioner Scott Rupp

In 2007, the iPhone was introduced to the world, the Dow Jones Industrial Average was 12,000, and the hit TV show of the year was The Soprano’s.

Here we are, ten years later, and we are on the 10th generation of the iPhone, the Dow Jones Industrial Average is 20,409, and Tony Soprano is dead.

A lot has changed in ten years. However, one thing that has not changed is Missouri’s Renewable Energy Standard (RES).  In 2007 the language that would eventually end up on the ballot as Proposition C in 2008 was drafted.  Proposition C, which created Missouri’s Renewable Energy Standard, was passed by the voters of Missouri in 2008, garnering 66% of the vote.  It received a higher percentage of support than any other RES in US history, and it outlined specific percentage goals for Missouri to reach in renewable energy production from 2011 to 2021.

Fast forward a decade:

  • The cost of photo voltaic panels has dropped around 90% since Missouri’s RES was adopted by the voters.
  • The cost of wind energy (price per kilowatt-hour) has fallen over 50% since Missouri’s RES was approved by the electorate.
  • Missouri’s Renewable Energy Standard has not changed in a decade.

Ask yourself this question:  If you worked at the same company for ten years, and you trimmed costs for that company by 90%, but you never received a raise since 2008, how would you feel?

If the costs of renewable energy have dropped so significantly over the past decade, why have the renewable energy production targets for Missouri not been increased?

One-half of Missouri’s investor owned regulated utilities have already surpassed the renewable energy standards for 2021, but others are not even close to hitting those minimum requirements.  Why aren’t all utilities blowing these dated requirements/standards out of the water when the cost to produce that energy has dropped 50-90%?  One answer is because of cost mitigation measures in the RES.

“Utilities may be excused from their [RES] obligation for events beyond their control or if the cost of compliance with the standard increases retail electricity rates by more than 1% in any year.”

Missouri ranks as having the 2nd most restrictive investment cost cap measures in the US, falling 4 ½ times below the national average.  If the investment cost cap included in the RES language were due to the higher cost of renewable energy in 2007/2008,  and those costs have dramatically dropped, isn’t it time we adjust the investment cost cap to reflect those massive cost reductions?

Here is another important question: Are Missouri’s RES standards thwarting job growth in our state?

According to a January 2017 article in Fortune Magazine the solar and wind industries are each creating jobs at a rate 12 times faster than the rest of the U.S. economy. Additionally solar and wind jobs have grown at rates of about 20% annually in recent years.  If Missouri has the 2nd most restrictive investment cost cap on renewable energy, are we sending all that job growth to other states?

I believe it is time for Missouri (and all US States) to take a long hard look at their renewable energy standards.  It is my hope that they would be updated to reflect the changes in the cost structure and the market for renewables, to ensure that our noble goals are not so outdated that they become an obstacle to creating jobs and growing our economy.

Comm. Scott Rupp has been on the Missouri Public Service Commission since 2014.  He runs an informational and entertaining website www.SimplifyingEnergy.com where you can find his weekly blogs and podcasts related to the energy industry.  You can follow him on Twitter @Scott_Rupp.

Growth Opportunities for Carbon Capture and Enhanced Oil Recovery.

Written by: Doug Scott, Vice President, Strategic Initiatives, Great Plains Institute.

 

Chairman Scott

Doug Scott

A work group of state officials convened in 2015 by Wyoming Governor Matt Mead and Montana Governor Steve Bullock, and joined by colleagues and officials in 12 other states,  released a new report outlining growing opportunities for capturing carbon dioxide from industrial facilities and power plants for use in enhanced oil recovery (CO2-EOR) with geologic storage.

The  report, “Putting The Puzzle Together: State & Federal Policy Drivers for Growing America’s Carbon Capture and CO2-EOR Industry”, includes detailed analyses and federal and state recommendations of the State CO2-EOR Deployment Work Group. The Work Group includes leading private sector stakeholders and CO2-EOR experts, in addition to the state officials.

The report notes that market forces and federal and state policy are driving the energy industry to reduce carbon emissions and that carbon capture with CO2-EOR compares cost-effectively with other carbon emissions reduction options.

The Work Group recommends a targeted package of federal incentives for CO2-EOR, including:

  • Improving and expanding the existing tax credit for storage of captured CO2, by both raising the amount of the existing credit, and improving the conditions for its use;
  • Deploying a revenue-neutral mechanism to stabilize the price paid for CO2—and carbon capture revenue—by removing volatility and investment risk associated with CO2 prices linked to oil prices (thus providing a more predictable revenue stream for project developers and investors); and
  • Offering tax-exempt private activity bonds and master limited partnership tax status for CO2-EOR projects to provide project financing on better terms (these mechanisms are already common and have proven effective for other types of energy project development).

States can also assist by optimizing existing taxes commonly levied by states to complement federal incentives in helping carbon capture projects achieve commercial viability. Analysis undertaken for the work group shows that an optimized approach to state taxes can add the equivalent of roughly $8 per barrel of oil to the economics of a carbon capture project.

The work group endorsed a targeted package of federal and state incentives for CO2-EOR that will help ensure that CO2-EOR becomes an integral part of our future energy system. While the technology for CO2-EOR has been in use for almost half a century, the costs of deploying carbon capture at power plants remain high.  The economics have been further hampered by both low natural gas prices that makes new conventional natural gas plants cheaper and low oil prices that reduce revenues from the sale of captured CO2. These incentives can make projects viable by closing the economic gap between the cost of installing carbon capture at power plants versus building new conventional natural gas units.

Based on modeling results and qualitative criteria, the work group identified the extension, reform and expansion of the Section 45Q tax credit as its top priority for stimulating commercial deployment of carbon capture at power plants and industrial facilities.

The work group report is timely, as Congress has recently been considering Section 45Q tax credit reforms. The Carbon Capture, Utilization and Storage Act (S. 3179) introduced by Senator Heidi Heitkamp (D-ND) was co-sponsored on a bi-partisan basis by one-fifth of the U.S. Senate. Bipartisan companion legislation in the U.S. House, the Carbon Capture Act (H.R. 4622) introduced by Representative Mike Conaway (R-TX), has attracted 49 co-sponsors. Governor Mead and Governor Bullock have endorsed these bills in letters to Congress, as has the Western Governors Association and Southern States Energy Board.

While the legislation did not ultimately pass in the 2016 session of Congress, the large number of bipartisan sponsors suggests that similar legislation is expected to be introduced this year.

The Work Group report emphasizes that complementary federal and state incentives will spur commercial deployment of carbon capture by enticing private investment into projects. This will, in turn, bring down costs over time, just as incentives have similarly accomplished for other energy technologies such as wind and solar, thus prompting a number of states to add carbon capture with CO2-EOR to the mix of energy choices they consider. The Work Group has also released a report on C02 pipeline infrastructure, and is working on a report concerning dispatch of power from CO2-EOR facilities onto the power grids.

Tackling the Replacement of the Nation’s Lead Service Lines.

Sponsored by: John Marciszewski, Director, Business Development, Echologics

Written by: Michael Deane, Executive Director, National Association of Water Companies.

May POV- Image Michael Deane resized

Michael Deane

The challenges facing the nation’s water infrastructure has been a subject receiving increased attention in recent years. One specific area of heightened awareness pertains to the presence of lead in drinking water systems.

Lead can enter drinking water when pipes and plumbing fixtures that contain lead corrode, especially where the water has high acidity or low mineral content. Leaded solder, used to connect copper pipe and fittings, and leaded alloy, used in faucets and other plumbing components, can cause excessive lead levels. A third, and major, source of contamination is lead service lines – the pipes that connect the water utilities’ underground system of water mains to a home, business or public-use facility.

Even though using lead pipes for new service lines was banned in the 1980s, they still connect an estimated 6.1 million older homes and businesses to water systems across the country. Removing lead service lines significantly reduces the risk of exposure to lead in drinking water. Lead has many widely-known negative health implications, such as impairing normal brain development in infants and children, as well as contributing to learning and behavioral problems.

The members of the National Association of Water Companies (NAWC) provide quality water service to more than 73 million customers and share a commitment to empowering Americans with information about ways they can help ensure the quality of their drinking water. Water management professionals across the nation realize the importance of educating their customers, clarifying who is responsible for replacing outdated lead service lines and providing as much assistance as possible.

NAWC is a founding member of a new national initiative called the Lead Service Line Replacement Collaborative (LSLR) recently launched to help address this problem. The LSLR Collaborative is a joint effort of 24 diverse organizations representing the public health, water utility and environmental sectors working with state and local governments. The LSLR Collaborative aims to assist communities in recognizing the need to remove lead lines, as well as provide tools to support local action to do so.

Certainly, funding to replace lead service lines is one of the most challenging hurdles in this effort. The US Environmental Protection Agency (EPA) estimates the cost for replacement nationwide ranges from 16 to 80 billion dollars. Fortunately, one of the tools the LSLR Collaborative provides is guidance on various funding models to help communities finance service line replacement projects.

Successful full lead service line replacement is most efficiently accomplished when all parties – property owners, residents, plumbers, water utilities and regulators – have a common understanding of the task at hand, how this new task is being integrated into existing practice, and where regulatory agencies, local government, and local public health experts support the community’s approach. The LSLR Collaborative website shares success stories where cities passed local legislation to support a replacement program, or tapped into state and federal resources – like state infrastructure replacement programs, community assistance initiatives and federal grants – to help offset costs.

For example, in 2000 Madison, Wisconsin became the first city in the country to pass a local ordinance requiring property owners to replace lead service lines. The utility had already begun replacing lead pipes in its system, but the real threat to contamination was the more than 8,000 service lines connecting to private property. To help offset the cost to property owners, the local utility offered to cover up to $1,000 using funds it generated by leasing part of its property to a telecommunications company for cellular antennas. By 2012, all of the city’s lead service lines had been replaced. It was a creative solution to a serious public health issue, and one that is now used as a model for other cities.

Another success story can be found about 200 miles northwest of Madison, in the small city of  Eau Claire, Wisconsin. Here the town turned to a state Environmental Improvement Fund grant that provided $500,000 to reimburse property owners for replacing lead service lines. The Wisconsin Department of Natural Resources had allocated $11.8 million for lead service replacement projects statewide. Property owners in Eau Claire can now apply to receive up to $1,000 to put toward replacing their lead lines, which are estimated to cost between $850 and $2,200.

The Collaborative is careful to emphasize that there is no one-size-fits-all solution. Every community is different, and the best funding mechanism will depend on a combination of factors unique to each. Deciding on a financing approach will require understanding the scope of the problem. This will take input from the local water utility in order to help define the problems and possible solutions. Determining variables like how many lead service lines a community has, the approximate population exposed, the historical baseline lead data at the tap and the estimated cost of service line replacement helps inform the best funding approach. Once these and other core factors are determined, a custom replacement plan can be developed.

Replacing lead service lines is just one of the many challenges facing our nation’s water infrastructure, and just like addressing the issue as a whole, there is no simple solution. We all must play a role – national, state and local community leaders, water utilities, and customers. The LSLR Collaborative is an excellent example of the way diverse individuals and organizations – spanning industries and sectors – are working together toward a common goal. Collectively, we can reduce risks associated with exposure to lead in drinking water, and accelerate voluntary lead service line replacement in communities across the country.

Please visit www.lslr-collaborative.org to learn more about the Lead Service Line Replacement Collaborative.