Thursday, January 26, 2017

Overall annual cost to London from traffic delays on busy roads is £5.5 billion ($6.8 Billion)

The overall annual cost to London from traffic delays on busy roads is £5.5 billion. This figure represents a huge 30 per cent increase in just two years (£4.2 billion in 2012/13).  The cost of delays for an average vehicle is £20.83 per hour.

The London Assembly Transport Committee report ‘London Stalling’ released today calls on the Mayor to reform the Congestion Charge and ultimately replace with it road pricing. The Committee suggests a way of charging people for road usage that is targeted at areas of congestion, at the times congestion occurs.  

It’s a popular idea, with over half of road users responding to a Committee survey saying they support road pricing - only a fifth were opposed.

In the short-term, the Congestion Charge should be reformed to better reflect the impact of vehicles on congestion. The daily flat rate should be replaced with a charging structure that ensures vehicles in the zone at peak times, and spending longer in the zone, face the highest charges.

The report also recommends:
  • reducing restrictions on night-time deliveries
  • piloting a ban on personal deliveries for staff
  • reconsidering ‘click and collect’ at Tube and rail stations
  • devolving Vehicle Excise Duty to the Mayor
  • piloting a local Workplace Parking Levy
Traffic congestion
The full report is available at:
The survey is available at 
City of London
Press Release dated 19 January 2017

Wednesday, January 25, 2017

1st Comprehensive Cost/Benefit Study of Climate Policies in San Joaquin Valley Finds Over $13 Billion in Economic Benefits, Mostly in Renewable Energy

Amid concerns about the economic and employment impacts of California’s ambitious climate policies, the first comprehensive, academic study of their effects in the San Joaquin Valley has found a total economic benefit of $13.4 billion. The study, The Economic Impacts of California’s Major Climate Programs on the San Joaquin Valley, addresses compliance and investment costs as well as the benefits across the region, and finds a net boost to the Valley’s economy from the state’s major climate programs, including the creation of tens of thousands of jobs.  The Valley is especially vulnerable to air quality problems that climate policies tend to alleviate. But it also faces more socioeconomic challenges than other parts of the state and is less equipped to take chances with its economy.
“This report shows that even in one of the poorest and most disadvantaged regions of the state and nation, California’s existing climate policies can provide net economic benefits,” said Ethan Elkind, who coordinated the report for the Center for Law, Energy and the Environment (CLEE) at the UC Berkeley School of Law. Researchers looked at three key California climate and clean energy policies: 1) cap-and-trade, which established a market designed to reduce carbon emissions from major polluters; 2) the Renewables Portfolio Standard (RPS), which calls for California to get 33 percent of its energy from renewable sources by 2020, growing to 50 percent by 2030; and 3) energy efficiency programs run by investor-owned utilities and overseen by the Public Utilities Commission....
After accounting for compliance and other costs, the UC researchers estimate the cap-and-trade program had a direct economic benefit of $119 million to the San Joaquin Valley, and boosted the economy by $200 million when you include indirect and induced economic benefits. If you include spending that has been allocated but not yet disbursed, those numbers rise to $1 billion in direct economic benefits and $1.5 billion when including indirect economic benefits.
orange groves and other agriculture
Proceeds from carbon auctions disbursed in the region so far have largely gone towards initial work on the state’s high-speed rail project, affordable housing, irrigation modernization and electric vehicle incentives. The study found that industries benefiting from the investment of cap-and-trade revenue, such as construction, generate more economic activity in the region than those industries bearing the costs of cap-and-trade compliance.
Researchers calculated a potential negative impact on 400 jobs due to compliance, but found that on a net basis, more than 700 jobs were created directly, and more than 1,600 supporting service and industry jobs were created indirectly, from 2013 through 2015. In the same period, state and local tax revenues received a $4.7 million boost.
Renewables Portfolio Standard
A lot of attention is paid to the state’s carbon cap-and-trade program, but in terms of the San Joaquin Valley’s economy, the state’s Renewables Portfolio Standard (RPS) has had a bigger impact so far. Construction on renewable energy projects has resulted in $11.6 billion in total economic activity in the Valley.
The San Joaquin Valley is home to 24 percent of the state’s solar generation and 54 percent of the state’s wind generation, providing significant employment opportunities in the region.
“Building and operating renewable energy facilities means jobs,” Jones said. From 2002 to 2015, renewable programs created about 31,000 direct jobs in the San Joaquin Valley – for people building and operating renewable energy facilities, for example – and created another 57,000 indirect and induced jobs for suppliers, supporting businesses and the like, for a total of 88,000 jobs. “Most of these direct jobs are the well-paid, local, career-track jobs the Valley really needs,” concluded Jones.
Energy Efficiency Programs
The report found energy efficiency programs overseen by the California Public Utilities Commission (CPUC) are cost-efficient vehicles for families, businesses and institutions to save energy and money year after year. By cutting demand, efficiency efforts also reduce the need for costly new power-generating infrastructure.
Energy efficiency programs in the San Joaquin Valley are the most cost-effective in the state, according to the report authors’ analysis of data reported by the CPUC. The report’s researchers found these programs in the Valley have provided net economic benefits of $248 million since 2010.
“Energy efficiency programs are job creators,” Jones said. “From 2006 to 2015, utility energy efficiency programs created 6,700 direct jobs, two-thirds of them in the construction industry and 10,700 indirect and induced jobs in the Valley, for a total of 17,400 jobs.“

Sunday, January 22, 2017

Natural Gas and Wind are the Lowest-Cost Generation Technologies for Much of the U.S., New UT Austin Research Shows

Natural gas and wind are the lowest-cost technology options for new electricity generation across much of the U.S. when cost, public health impacts and environmental effects are considered, according to new research released today by The University of Texas at Austin.

University researchers assessed multiple generation technologies including coal, natural gas, solar, wind and nuclear. Their findings, as depicted in a series of maps illustrating the cost of each generation technology on a county-by-county basis throughout the U.S., are featured in a new white paper titled “New U.S. Power Costs: by County, with Environmental Externalities.”

The paper is part of a comprehensive study coordinated by UT Austin’s Energy Institute titled the “Full Cost of Electricity (FCe-),” an interdisciplinary project that synthesizes expert analyses from faculty members and other researchers across the university — from engineering, economics, law and public policy.

The research team adopted a holistic approach to probe the key factors affecting the total direct and indirect costs of generating and delivering electricity. Their work resulted in the production of a series of authoritative white papers that provide an in-depth assessment and examination of various electric power system options.

Researchers categorized the electricity system into three principal components: consumers; generation technologies; and the wires, poles, storage and other hardware required to connect end users and generators. Taken as a whole, the white papers assess the interaction among these three components, as well as costs often considered external to the electricity system, such as environmental effects and public health impacts.
Energy Institute
“These are complex, interrelated issues that cannot be adequately addressed from one perspective,” said Dr. Tom Edgar, director of the Energy Institute. “We assembled a cross-disciplinary team to provide a fuller understanding of these costs and their policy implications.”

For the white paper on power generation costs, researchers used data from existing studies to enhance a formula known as the Levelized Cost of Electricity (LCOE). In addition to including public health impacts and environmental effects — which the LCOE typically does not — the research team used data to calculate county-specific costs for each technology.

The team also developed online calculators to facilitate a discussion among policymakers and others about the cost implications of policy actions associated with new electricity generation.

Dr. Joshua Rhodes, postdoctoral research fellow at the Energy Institute and lead author of the paper, said the cost estimates are based on a series of assumptions that researchers debated at length. “We think our methodology is sound and hope it enhances constructive dialogue,” Rhodes said. “But we also know that cost factors change over time, and people disagree about whether to include some of them.  “We wanted to provide an opportunity for people to change these inputs, and the tools we’ve created allow for that,” he added.

Researchers analyzed data for the most competitive sources of new electricity generation. Wind proved to be the lowest-cost option for a broad swath of the country, from the High Plains and Midwest and into Texas. Natural gas prevailed for much of the remainder of the U.S.; nuclear was found to be the lowest-cost option in 400 out of 3,110 counties nationwide.

The FCe- study examined numerous factors affecting the cost of electricity generation, including:
  • Power Plant Costs (both operating and capital costs)
  • Environmental and Health Costs (air quality, greenhouse gases)
  • Infrastructure Costs (transmission & distribution lines, rail, pipelines)
  • Fuel Cost (variability, full fuel cycle)
  • Integration of renewable and distributed energy resources
  • Energy Efficiency
  • Government financial support for electricity generation (subsidies)

The calculator at looks like this:
Depending upon the existing capacity of the grid and incremental quantity of generation added, transmission interconnection costs for new generation can be negligible to significant (e.g., 0-600 $/kW in ERCOT).  
No power plant (ultimately) has zero interconnection costs. All grid-connected power plants depend upon transmission and distribution to deliver electricity to consumers. The costs of building and operating the grid are non-trivial at 700-800 $/yr per customer, or approximately 3 cents/kWh.
The current long-term forecast ... indicates that the market expects natural gas prices to remain relatively low (under $4.35 per Million Btu) through 2025.
The number of customers in a utility’s territory is the single best predictor for annual TD&A costs. Between 1994 and 2014, the average TD&A cost per customer was $119/ Customer-Year, $291/ Customer-Year, and $333/CustomerYear, respectively, for a total of $700- $800 per year for each customer 
In general, renewable energy sources such as utility-scale solar and wind energy require more bulk transmission system expansion because the best wind and solar resources tend to be located further away from electric load. As an example, the bulk long-distance renewable transmissions lines used to connect the Electric Reliability Council of Texas’s (ERCOT) Competitive Renewable Energy Zones (CREZ) in north and west Texas costed approximately $6.9 billion in total, or $600/kW, which is more than conventional greenfeld and brownfeld generation projects.
Distribution system costs have been roughly constant since the late 1970s, with typical costs near $290/Customer-Year since 1994...

Thursday, January 19, 2017

The Local Economic and Welfare Consequences of Hydraulic Fracturing

Exploiting geological variation within shale deposits and timing in the initiation of hydraulic fracturing, this paper finds that allowing fracking leads to sharp increases in oil and gas recovery and improvements in a wide set of economic indicators. At the same time, estimated willingness-to-pay (WTP) for the decrease in local amenities (e.g., crime and noise) is roughly equal to -$1,000 to -$1,600 per household annually (-1.9% to -3.1% of mean household in-come). Overall, we estimate that WTP for allowing fracking equals about $1,300 to $1,900 per household annually (2.5% to 3.7%), although there is substantial heterogeneity across shale regions.
Using a new identification strategy based on geological variation in shale deposits within shale plays, we estimate the effects of fracking on local communities. There are four primary findings. First, counties with high fracking potential produce roughly an additional $400 million of oil and natural gas annually three years after the discovery of successful fracking techniques, relative to other counties in the same shale play. Second, these counties experience marked increases in economic activity with gains in total income (4.4 - 6.9 percent), employment (3.6 - 5.4 percent), and salaries (7.6 - 13.0 percent). Further, local governments see substantial increases in revenues (15.5 percent) that are larger than the average increases in expenditures (12.9 percent) though the increased expenditures seem largely aimed at supporting the new economic activity, with little effect, for example, on per pupil expenditures in public schools. Third, there is evidence of deterioration in the quality of life or total amenities, perhaps most notably marginally significant estimates of higher violent crime rates, despite a 20 percent increase in public safety expenditures....
Image result for Hydrofracking epa
by Alexander W. Bartik, Janet Currie, Michael Greenstone and Christoper R. Knittel
The University of Chicago Becker Friedman Institute for Research in Economics
Working Paper 2016-29; December 21, 2016
Keywords: Public Policy, Environment, fracking, economic impact, economic growth

Rooftop Solar Arrays on Five Fire Stations Expected to Reduce Electric Costs 30% for Less Than $1,500

The Dubuque City Council recently approved agreements with Eagle Point Solar of Dubuque for the installation of rooftop solar arrays on five of the City’s six fire stations. The project is expected to reduce electricity costs at the stations by more than 30 percent.

The contract award follows a request for proposal process which generated responses from five firms. The City Council unanimously approved a power purchase agreement and a collateral assignment agreement with Eagle Point Solar for the installation of rooftop solar arrays....

Once installed, the arrays are expected to permanently reduce the City’s cost of each kilowatt hour (kWh) of electricity utilized in the five fire stations by more than 30 percent. Specifically, the terms of the contract include a $0.085/kWh initial rate with a three percent inflation rate. This compares with the current aggregate Alliant Energy rate for the fire facilities of $0.116/kWh. The only upfront funding required for this project from the City is for equipment upgrades to allow internet connectivity for the solar arrays, not to exceed $1,500.The percentage of electricity use offset and carbon dioxide offset at each station varies, due to available roof space and usage at that site:

  • Headquarters 66.15 kW Electric Offset 37% CO2 Offset 1,651 tons
  • Station 2 35.28 kW Electric Offset 96% CO2 Offset 887 tons
  • Station 3 27.72 kW Electric Offset 55% CO2 Offset 697 tons
  • Station 4 15.75 kW Electric Offset 26% CO2 Offset 377 tons
  • Station 5 5.04 kW Electric Offset 28% CO2 Offset 128 tons
  • Total System Size 150.8 kW Carbon Offset 3,740 tons
According to Eagle Point Solar, the combination of the five solar arrays, over their lifetime, will offset the equivalent of: planting 87,141 trees, the reduction of 7.48 million automobile miles driven (or 381,480 gallons of gasoline), recycling 11,818 tons of waste rather than landfilling it, displacing carbon dioxide emissions from the annual electricity use of 425 homes, or 1,822 tons of coal burned.

Wednesday, January 18, 2017

Defensive Investments and the Demand for Air Quality: Evidence from the NOx Budget Program

The demand for air quality depends on health impacts and defensive investments that improve health, but little research assesses the empirical importance of defenses. We study the NOx Budget Program (NBP), an important cap-and-trade market for nitrogen oxides (NOx) emissions, a key ingredient in ozone air pollution. A rich quasi-experiment suggests that the NBP decreased NOx emissions, ambient ozone concentrations, pharmaceutical expenditures, and mortality rates. Reductions in pharmaceutical purchases and mortality are valued at about $800 million and $1.5 billion annually, respectively, in a region covering 19 Eastern and Midwestern United States; these findings suggest that defensive investments account for more than one-third of the willingness-to-pay for reductions in NOx emissions. Further, the NBP’s estimated benefits easily exceed its costs and instrumental variable estimates indicate that the estimated benefits of NOx reductions are substantial.
nitrogen oxide cycle
by Olivier Deschenes 1, Michael Greenstone 2 and Joseph S. Shapiro 
1. University of California, Santa Barbara - College of Letters & Science - Department of Economics;
1. National Bureau of Economic Research (NBER); IZA Institute of Labor Economics
2. University of Chicago - Department of Economics; National Bureau of Economic Research (NBER)
3. Yale University, Department of Economics; National Bureau of Economic Research (NBER); Yale University - Cowles Foundation
Social Science Research Network (SSRN) www,
June 1, 2016, Number of Pages in PDF File: 74
Keywords: willingness to pay for air quality, cap and trade, ozone, pharmaceuticals, mortality, compensatory behavior, human health

Got A Favorite 2017 Energy Forecast? Technology Will Make It Obsolete

... The U.S. Energy Information Administration (EIA) ... just released its latest Annual Energy Outlook. The Outlook offers predictions about the future of energy prices, production and consumption in the United States.... EIA has found that its own predictions of crude oil and natural gas prices differ from realized prices by 30 to 35%. Their forecast errors for renewables are sometimes even larger.

The EIA is not alone in making bad predictions. Professional oil price forecasters and futures market participants make bets about future oil and gas prices that routinely turn out to be completely wrong.   But contrary to what you might think, these forecasting errors should not be viewed as evidence that the EIA or any of these forecasters are doing a bad job, or even as mistakes at all.  Instead, they point to the key role that changing technology—and specifically supply-side technology—has played in the energy landscape in recent years. The history of forecasting errors in the U.S. natural gas market is a perfect example of this phenomenon.
Consider EIA's 2000 forecast of natural gas markets in 2015: 25 trillion cubic feet (TCF) of production at an average price of about $5 per thousand cubic feet (MCF).  Actual production in 2015 was about 27 TCF at an average price of $3.37 per MCF—we got more gas at a lower price than expected....

77% of EIA's forecasting errors are best interpreted as forecasting errors about the supply curve for natural gas, as opposed to the demand curve.  This is true for forecasts made before the shale gas boom (80%) as well as for more recent forecasts (72%). The figure also shows that EIA's forecasts made before the start of the shale gas boom tended to overestimate supply (66% of the time), while forecasts made after tended to underestimate supply (63% of the time).

Why has supply been harder to predict than demand? Over the last 20 years, there have been two large shocks to the “technology” of natural gas production: an unexpected decrease in natural gas discoveries in the Gulf of Mexico starting in the early 2000s, followed by the unexpected boom in shale gas development more recently.

Until the mid-2000s, the EIA forecasted about 5 TCF of offshore gas production per year.  In reality, offshore gas production decreased in nearly every year since 1997, and now stands at just 1.3 TCF.  An important cause of this decline in production has been a 70% drop in the rate of new offshore gas field discoveries since 2000. Because discoveries had been stable at about 2 TCF per year for the 15 years leading up to 2000, it is fair to say that this absence of technological progress, and therefore negative shock to supply, was rather unexpected.
Credit: Wikimedia Commons
Wikimedia Commons
The opposite is true for onshore gas fields, where rapid and unexpected improvements in hydraulic fracturing technology helped gas production far outpace forecasts in places like Texas, Louisiana, Pennsylvania and West Virginia. Although EIA correctly anticipated as early as 2000 that shale gas resources would grow in importance, they underestimated the speed and magnitude of this change.   As recently as 2005, EIA still forecasted less than 10 TCF of shale gas production per year for the then foreseeable future. In reality, U.S. shale gas production is now more than 15 TCF per year.
Recently, this uncertainty has been driven by the emergence of new ways of getting more gas inexpensively. However, it is important to remember that this uncertainty can also be caused by technological “misses,” like declining exploration success in the Gulf of Mexico.... Forecasts of future supply can be too optimistic just as often as they are too pessimistic.

by Thomas Covert, Contributor
Energy Policy Institute at the University of Chicago
January 5, 2017

Study Shows Electricity Markets Are More Cost-Effective Than Cost of Service Regulation - Natural experiment using the U.S. electricity system shows regions using a market approach save about $3 billion a year.

Are markets more cost-effective than cost of service regulation and other approaches? Despite markets’ imperfections, a new natural experiment using the U.S. electricity system points to yes. The study finds that regions using a market approach to buy and trade electricity save about $3 billion a year because of the increased efficiencies and coordination the markets bring.

“While many have compared major differences in economic systems across countries—where there are many moving parts and it’s difficult to convincingly identify the true source of those differences—this study focuses on a single industry that has undergone a profound reorganization,” says Steve Cicala, the author of the study and an assistant professor at the University of Chicago Harris School of Public Policy. “The study is an additional piece of evidence that, while not perfect, markets perform well relative to the alternative.”

Cicala used a unique policy shift within the U.S. electricity system to compare a market versus command-and-control regulatory structure. Periodically since the late 1990’s, some regions of the country changed overnight from using vertically-integrated local monopolies to make power decisions to a decentralized market-based auction system. Cicala constructed a virtually complete hourly characterization of U.S. electric grid supply and demand from 1999 to 2012 and compared the data in wholesale electricity markets versus regulated command-and-control areas before and after the market was introduced. In doing so, Cicala looked at two key measures: “out of merit” costs and trade across utility service territories.

The “out of merit” costs occur when power plant operators don’t use the lowest-cost available plants because those plants are forced to go off-line for maintenance or some other reason. The additional cost of output from the more expensive plants relative to the lowest-cost units is the out of merit cost. The study finds that power plant generators operating within markets are more likely to ensure their power plants are available to run when it is most economical for them to run. This means the lowest-cost plants are used 10 percent more often in market regions—reducing out of merit costs by nearly 20 percent.
Trade between utilities is also a factor. When importing electricity from another area, one could save having to fire up a more expensive unit. When exporting, one could gain any additional revenue beyond that required to generate the power. The study finds that generators operating within markets are able to better identify low-cost generators across areas and better coordinate the dispatch of power, increasing trade by 10 percent. The savings from these transactions increases by 20 percent a year.

“Some policymakers are right now deciding whether their state should join a market system, while others are deciding whether they should return to the regulated approach,” says Cicala. “While these markets are certainly vulnerable to market power, this study shows that previously unmeasured cost reductions far outweigh those losses."

January 9, 2017

This paper measures changes in electricity generation costs caused by the introduction of market mechanisms to determine output decisions in service areas that were previously using command-and-control-type operations. I use the staggered transition to markets from 1999- 2012 to evaluate the causal impact of liberalization using a nationwide panel of hourly data on electricity demand and unit-level costs, capacities, and output. To address the potentially confounding effects of unrelated fuel price changes, I use machine learning methods to predict the allocation of output to generating units in the absence of markets for counterfactual production patterns. I find that markets reduce production costs by $3B per year by reallocating output among existing power plants: Gains from trade across service areas increase by 20% based on a 10% increase in traded electricity, and costs from using uneconomical units fall 20% from a 10% reduction in their operation.

Tuesday, January 17, 2017

Utilisation of rice residues for decentralised electricity generation in Ghana: An economic analysis

• Economic viability of decentralised electricity from rice residue in Ghana is studied.
• Electricity produced from straw combustion ranged between 11.6 and 13 US cents/kWh.
• Residue cost contribute 49–54% of electricity production cost from straw combustion.
• Husk gasification mini-grids are cheaper than other rural electrification options.
• Husk gasifiers should be promoted in remote rural communities of Northern Ghana.

Developing countries, especially in Sub-Saharan Africa, face large challenges to achieve universal electrification. Using the case of Ghana, this study explores the role that rice residues can play to help developing countries meet their electrification needs. In Ghana, Levelised Electricity Costs (LEC) of a grid-connected 5 MWe straw combustion plant ranged between 11.6 and 13.0 US cents/kWh, based on region of implementation. Rice straw combustion is a viable grid-connected option in all regions, as the bioenergy Feed-in-Tariff is 29.5 US cents/kWh in Ghana. Residue supply cost contributes significantly (49–54%) to LEC of rice straw combustion.

LEC of husk gasification mini-grids ranged between 5 and 53 US cents/kWh for rural populations between 3000 and 250 people. Husk gasification mini-grids can be a suitable electrification solution for these un-electrified populations, as its LEC is lower than the average LEC of grid extension diesel mini-grids and off-grid solar systems for remote communities in Ghana. Electricity produced from husk gasification has the potential to cater to 7% of the needs of un-electrified communities in Ghana. The methodology and analysis of this study can support policymakers of similar countries decide the economic feasibility of decentralised bioenergy solutions while forming national electrification plans.
by Pooja Vijay Ramamurthi 1, , , Maria Cristina Fernandes 1, Per Sieverts Nielsen 2, Clemente Pedro Nunes 1
a CERENA/DEQ, Instituto Superior Técnico, Universidade de Lisboa, Av. Rovisco Pais, 1049-001 Lisboa, Portugal
b DTU Climate Centre, Systems Analysis, Department of Management Engineering, Technical University of Denmark, Denmark
Volume 111, 15; September, 2016; Pages 620–629
Keywords: Rice residues; Electricity access; Economic feasibility; Rural electrification; Levelized Electricity Cost; Ghana

Sunday, January 15, 2017

Governance and implementation challenges for mangrove forest Payments for Ecosystem Services (PES): Empirical evidence from the Philippines

• Economic, social, and governance challenges for mangrove PES are investigated.
• The research uses primary data from two coastal sites in the Philippines.
• Mangrove carbon PES could contribute an additional 2.3–5.8% to current village income.
• Payments could finance ventures that counteract the environmental benefits of schemes.
• PES may require multi-level and multi-actor governance with local participation.

Mangrove forests have been considered as potentially suitable for PES, though few mangrove PES schemes exist worldwide, suggesting they - and the broader social-ecological and governance systems in which they sit - may not be as conducive to PES as first thought. This study assesses economic, social, and governance challenges to implementing PES in mangroves. It draws on empirical evidence from two prospective community-level mangrove carbon PES schemes in the Philippines, where fishing and aquaculture are major livelihoods. We conducted (1) policy reviews and interviews with local communities, government, and NGOs to investigate governability; (2) village income accounting to determine the extra income that participants could receive through PES; and (3) a choice ranking exercise to elicit preferences on how payments could best be spent to enhance participant wellbeing. The latter approach identifies key gender differences, and enables potential PES-induced social-ecological trade-offs to be pre-empted. Blue carbon PES can contribute an additional 2.3–5.8% of current village incomes, while villagers would prefer to spend the monies on more effective fishing equipment, which could perversely jeopardize fishery sustainability. To be most successful, coastal PES schemes in the Philippines need to be managed through a multi-level governance regime involving co-management and local participation.
Mangrove forest at low tide, Philippines
by Benjamin S. Thompson 1, , , Jurgenne H. Primaver 1 and 2, Daniel A. Friess 1
1. Department of Geography, National University of Singapore, 1 Arts Link, Singapore 117570, Singapore
2. Community-Based Mangrove Rehabilitation Project, Zoological Society of London, 132 Quezon St., Iloilo City, Philippines
Ecosystem Services via Elsevier Science Direct
Volume 23, February 2017, Available online 28 December 2016; Pages 146–155

Keywords: Benefit sharing; Blue carbon; Conservation; Gender; Perverse incentives; Fishers

Saturday, January 14, 2017

Risky Business Project - From Risk to Return: Investing in a Clean Energy Economy - Clean energy a major private sector investment opportunity say Bloomberg, Paulson, and Steyer

Reducing the risk posed by climate change is both economically and technically achievable, according to a new report by the Risky Business Project, and would create significant new opportunities for American business. To do so would require building a clean energy economy in America – meaning widespread electrification, including of cars and homes, electricity generation from zero or low-carbon sources, and energy efficiency upgrades. A clear and consistent policy framework can unlock the investments needed for this transition.

“Companies and governments across the globe need to reduce their vulnerability to climate change and work to curb carbon emissions,” said Risky Business Project Co-Chair Henry M. Paulson. “Transforming the U.S. economy to rely on low-carbon, clean energy would be a massive undertaking, but this report shows we can achieve this vision with existing technologies.”

The new report, From Risk to Return: Investing in a Clean Energy Economy, finds that an average of $320 billion a year in private sector investment is needed through 2050 to build a clean energy economy and achieve the emissions reductions necessary to avoid the worst economic impacts of climate change. These necessary investments would be similar in scale to other major recent investments made by American business, including in computers and software at $350 billion per year over the past decade. Investments in clean energy could yield on average up to $366 billion in savings per year from reductions in spending on fossil fuels.

The country would gain over 1 million new jobs by 2030, with utilities, construction, and manufacturing seeing the largest gains. But 270,000 jobs would be lost in coal mining, oil, and gas related jobs, primarily in Southern and Mountain states.

“Coal is dying because cheaper and cleaner forms of energy are replacing it. This transition is both saving lives and saving us money, and the faster we can accelerate it, the better off our country will be,” said Michael R. Bloomberg, Co-Chair of the Risky Business Project.

The report calls on business leaders to put in place actionable plans for incorporating climate risk into their decision-making, including using an internal price on carbon in their calculations, and conducting detailed analyses of company exposure to climate risk.

“The stakes for our planet are higher than they have ever been and the cost of inaction is one our economy simply cannot afford,” said Risky Business Project Co-Chair Thomas F. Steyer. “Moving to clean energy will help mitigate the worst negative impacts of climate change and create enormous opportunity for American businesses. Now, more than ever, business must lead this transition for the sake of our climate, our country, and our economic security.”

The report outlines a series of policy principles necessary to achieve a transition to a clean energy economy. These include government removing subsidies for activities that increase climate risk, and providing incentives for innovation and for the deployment of clean energy. One way of accelerating the transition would be to put a price on carbon that accounts for the true costs of carbon pollution. The report also suggests that with global momentum moving towards reducing carbon emissions, U.S. competitiveness is at risk if American businesses do not invest in low-carbon technologies.

The full report is available free of charge at,
Under the Mixed Resources pathway, the researchers found that the total additional capital investment necessary to cut carbon emissions 80 percent economy-wide by 2050 would be:
  • $220 billion per year from 2020 to 2030
  • $410 billion per year between 2030 and 2040
  • $360 billion per year between 2040 and 2050

These capital investments would significantly reduce fuel costs, with the savings growing every decade. The savings would be:
  • $70 billion per year from 2020 to 2030
  • $370 billion per year from 2030 to 2040
  • $700 billion per year from 2040 to 2050

Average Annual Additional Capital Investments and Fuel Expenditures by Decade
The largest additional investments would be in power generation ($55 billion per year); advanced biofuels ($45 billion per year); purchases of advanced light duty vehicles ($75 billion per year); and energy efficiency measures ($16 billion per year). Businesses that become leaders in these sectors could see large increases in revenue in the years ahead, while those that lag behind risk being left with stranded assets.

Friday, January 13, 2017

Physical and monetary ecosystem service accounts for Europe: A case study for in-stream nitrogen retention

• We present a case study of ecosystem accounting based on the SEEA-EEA framework.
• Accounts for water purification are developed in physical and monetary terms.
• Flow accounts include both actual and sustainable flows.
• Capacity is assessed as Net Present Value of the sustainable flow.
• Replacement cost is the exchange value technique used for the monetary valuation.

In this paper we present a case study of integrated ecosystem and economic accounting based on the System of Environmental Economic Accounting — Experimental Ecosystem Accounts (SEEA-EEA). We develop accounts, in physical and monetary terms, for the water purification ecosystem service in Europe over a 20-year time period (1985–2005). The estimation of nitrogen retention is based on the GREEN biophysical model, within which we impose a sustainability threshold to obtain the physical indicators of capacity – the ability of an ecosystem to sustainably supply ecosystem services. Key messages of our paper pertain the notion of capacity, operationalized in accounting terms with reference to individual ecosystem services rather than to the ecosystem as a whole, and intended as the stock that provides the sustainable flow of the service. The study clarifies the difference between sustainable flow and actual flow of the service, which should be calculated jointly so as to enable an assessment of the sustainability of current use of ecosystem services. Finally, by distinguishing the notion of ‘process’ (referred to the ecosystem) from that of ‘capacity’ (pertaining specific services) and proposing a methodology to calculate capacity and flow, we suggest an implementable way to operationalize the SEEA-EEA accounts.

We calculate that replacing this ecosystem service capacity would require approximately one million ha of constructed wetland, representing a net present value of between 310 billion € in 1990 and 459 billion € for the year 2005.
Monetary flows by country follow:
A river flowing into a lake surrounded by green rushes
by Alessandra La Notte 1, Joachim Maes 1, Silvana Dalmazzone 2, Neville D. Crossman 3, Bruna Grizzetti 1, Giovanni Bidoglio 1
1. European Commission - Joint Research Centre, Directorate D – Sustainable Resources, Via Enrico Fermi 2749, 21027 Ispra, VA, Italy
2. Department of Economics and Statistics, University of Torino, Campus Luigi Einaudi, Lungo dora Siena 100, 10153 Torino, Italy
3. CSIRO Land and Water Flagship, Waite Campus, 5064 Adelaide, South Australia, Australia
Ecosystem Services via Elsevier Science Direct
Volume 23, February 2017, Pages 18–29
Keywords: Ecosystem accounting; Ecosystem services; Water purification; Capacity; Sustainable flow; Actual flow

Thursday, January 12, 2017

2016: A historic year for billion-dollar weather and climate disasters in U.S.

NOAA’s National Centers for Environmental Information (NCEI) tracks U.S. weather and climate events that have great economic and societal impacts ( Since 1980, the U.S. has sustained 203 weather and climate disasters where the overall damage costs reached or exceeded $1 billion (including adjustments based on the Consumer Price Index, as of January 2017). The cumulative costs for these 203 events exceed $1.1 trillion.

The year 2016 was an unusual year, as there were 15 weather and climate events with losses exceeding $1 billion each across the United States. These events included drought, wildfire, 4 inland flood events, 8 severe storm events, and a tropical cyclone event (see map below). Cumulatively, these 15 events led to 138 fatalities and caused $46.0 billion in total, direct costs. The 2016 total was the 2nd highest annual number of U.S. billion-dollar disasters, behind the 16 events that occurred in 2011.
Map of the US with icons showing location and type of 2016's billion-dollar disasters, including inland floods, hurricanes, fires, droughts, and tornadoes
The location and type of the 15 weather and climate disasters in 2016 with losses exceeding $1 billion dollars. The majority of events occurred in the middle of the country form the Central Plains to Texas and Louisiana. Map by NOAA NCEI, adapted by
Perhaps most surprising were the 4 separate billion-dollar inland flood (i.e., non-tropical) events during 2016, doubling the previous record, as no more than 2 billion-dollar inland flood events have occurred in a year since 1980. Three of these flood events were clustered in Louisiana and Texas between March and August, collectively causing damage approaching $15.0 billion. This is a notable record, further highlighted by the numerous other record flooding events that impacted the U.S. in 2016.

The changing frequency of billion-dollar disaster events
The U.S. has experienced a rising number of events that cause significant amounts of damage. From 1980–2016, the annual average number of billion-dollar events is 5.5 (CPI-adjusted). For the most recent 5 years (2012–2016), the annual average is 10.6 events (CPI-adjusted). The year 2005 was the most costly since 1980 due to the combined impacts of Katrina, Rita, Wilma, and Dennis, as shown in the following time-series. The year 2012 was the second most costly due to the extreme U.S. drought ($30 billion) and Sandy ($65 billion) driving the losses.
animated gif showing each year's billion dollar disasters (1981-2016) with color-coded bars made of different event types
animated gif showing each year's billion dollar disasters (1981-2016) with color-coded bars made of different event types
Animation showing the number (bar height) and type (bar color) of billion-dollar weather and climate disasters in the United States since 1980. The purple line shows total annual costs. The red line shows the running 5-year average. NOAA animation adapted from NCEI originals by Adam Smith.

Measuring Renewable Energy Externalities: Evidence from Subjective Well-being Data

Electricity from renewable sources avoids disadvantages of conventional power generation but often meets with local resistance. We use 324,763 observations on the subjective well-being of 46,678 individuals in Germany, 1994–2012, for identifying and valuing the local externalities from solar, wind, and biomass plants in respondents’ postcode district and adjacent postcode districts. We find significant well-being externalities of all three technologies that differ with regard to their temporal and spatial characteristics. The monetary equivalent of 1 MW capacity expansion of wind power and biomass installations is estimated to be 0.35% and 1.25% of monthly per capita income, respectively. 
Photo Gallery: Germany's Energiewende Hits Headwinds
by Charlotte von Möllendorff, and Heinz Welsch
Land Economics via University of Wisconsin Press
Volume 93, Number 1;  February 1, 2017; Pages 109-126

Evaluating services and damage costs of degradation of a major lake ecosystem

• Ecosystem services of lakes are commonly ignored and likely underestimated.
• We develop a systematic approach to assess the value of lake ecosystem services.
• We also assess potential damage costs associated with eutrophication.
• Our study shows lakes as an important economic asset, justifying restoration and conservation.

Values of ecosystems and potential losses associated with their degradation are complex and often ignored in economic assessments. The concept of ecosystem services may describe these values, as it is widely used to communicate the benefits that humans derive from ecosystems. The aim of this study was to conduct a valuation of a lake ecosystem and potential damage costs arising from its degradation. The approach was applied to Lake Rotorua (central North Island, New Zealand). The range of values derived from ecosystem services provided by Lake Rotorua was calculated using selected indicators and direct market pricing, indirect pricing (hedonic pricing, replacement cost) and existence value pricing. Social damage costs were calculated from loss of income from impaired recreation and reduced property values, as well as ecological damage costs caused by algal blooms and decline in habitat quality for aquatic fauna. The values of ecosystem services provided by Lake Rotorua in 2012 were calculated to be NZD 94-138 million p.a., with potential damage costs of eutrophication calculated at $14-48 million p.a. These estimates indicate that lakes are an important economic asset, and continuous ecosystem degradation has an external cost that is commonly ignored in management decisions.
Lake Rotorua.jpg
by Hannah Mueller 1, David P. Hamilton 1 and Graeme J. Doole 2
1. Environmental Research Institute, University of Waikato, Private Bag 3105, Hamilton 3240, New Zealand
2. Waikato Management School, University of Waikato, Private Bag 3105, Hamilton 3240, New Zealand
Ecosystem Services via Elsevier Science Direct
Volume 22, Part B, December 2016, Pages 370–380
Special Issue: Integrated valuation of ecosystem services: challenges and solutions
Keywords: Ecosystem services; Valuation; Ecological damage costs; Eutrophication; Lake restoration; Conservation benefits

National Academies of Sciences, Engineering and Medicine Report Recommends New Framework for Estimating the Social Cost of Carbon

To estimate the social cost of carbon dioxide for use in regulatory impact analyses, the federal government should use a new framework that would strengthen the scientific basis, provide greater transparency, and improve characterization of the uncertainties of the estimates, says a new report by the National Academies of Sciences, Engineering, and Medicine. The report also identifies a number of near- and longer-term improvements that should be made for calculating the social cost of carbon.

The social cost of carbon (SC-CO2) is an estimate, in dollars, of the net damages incurred by society from a 1 metric ton increase in carbon dioxide emissions in a given year.  The SC-CO2 is intended to be a comprehensive estimate of the net damages from carbon emissions —that is, the net costs and benefits associated with climate change impacts such as changes in net agricultural productivity, risks to human health, and damage from such events as floods.  As required by executive orders and a court ruling, government agencies use the SC-CO2 when analyzing the impacts of various regulations, including standards for vehicle emissions and fuel economy, regulation of emissions from power plants, and energy efficiency standards for appliances. 

The federal Interagency Working Group on the Social Cost of Greenhouse Gases (IWG) developed in 2010 a methodology to estimate the SC-CO2. The National Academies committee that authored the report was charged with examining potential approaches for a comprehensive update to this methodology to ensure that SC-CO2 estimates reflect the best available science. The committee was not asked to estimate a value for the social cost of carbon.

The IWG’s methodology uses three distinct models to estimate the economic consequences of CO2 emissions. First, a baseline of CO2 emissions is defined along with projections of underlying socioeconomic factors -- global economic growth and population -- decades into the future. Then, a small increase in CO2 emissions is added to the baseline for each of the three models, which is translated into an increase in atmospheric CO2 and a resulting increase in global mean temperature. These results are used to estimate potential net damages in dollars, using discounting to convert future damages into present dollars. The final IWG analysis averages the results from the three models.  

The report recommends that the IWG “unbundle” this process and instead use a framework in which each step of the SC-CO2 calculation is developed as one of four separate but integrated “modules”: the socioeconomic module, which generates projections of greenhouse gas emissions based on its estimates of population and world economic output; the climate module, which translates changes in emissions into changes in temperature; the damages module, which estimates the net impact of temperature changes in dollar terms; and the discounting module. Data generated by the socioeconomic module would feed into each of the other three modules, and the temperature changes generated by the climate module would inform the damages module. Each module would be developed based on expertise in the relevant scientific disciplines to reflect the most up-to-date research. The report offers detailed recommendations about how the IWG should develop each of the modules and how the proposed framework could include feedbacks between and interactions within the modules.

The current SC-CO2 methodology uses constant discount rates of 2.5 percent, 3.0 percent, and 5.0 percent. The report notes that differences in the discount rates have large impacts on the estimates; the SC-CO2 estimates per metric ton emitted in 2020 is $62 using a 2.5 percent rate, $42 using a 3.0 percent rate, and $12 using the 5.0 percent rate (in 2007 dollars).
climate change

Alaskan Village, Citing Climate Change, Seeks Disaster Relief In Order To Relocate

The tiny village of Newtok near Alaska's western coast has been sliding into the Ninglick River for years. As temperatures increase — faster there than in the rest of the U.S. — the frozen permafrost underneath Newtok is thawing. About 70 feet of land a year erode away, putting the village's colorful buildings, some on stilts, ever closer to the water's edge.

Now, in an unprecedented test case, Newtok wants the federal government to declare these mounting impacts of climate change an official disaster. Villagers say it's their last shot at unlocking the tens of millions of dollars needed to relocate the entire community.

"We just need to get out of there," says Romy Cadiente, the village relocation coordinator. "For the safety of the 450 people there."
A new village has been chosen 9 miles away, and several houses are already built.

Cadiente says the problem is money: The Army Corps of Engineers has estimated it will cost $80 million to $130 million to relocate key infrastructure.
Many of Alaska's villages are dealing with erosion and thawing permafrost. But Newtok's needs may be the most immediate. It has already lost its barge landing, sewage lagoon and landfill. As river water seeps in and land sinks, it expects to lose its source of drinking water this year, and its school and airport by 2020.
Usually, the president, with input from the Federal Emergency Management Agency, declares a disaster after a specific catastrophic event. But Newtok is asking for the declaration based on mounting damage from erosion and thawing permafrost over the past decade....
Rachel Waldholz, Alaska Public Media
National Public Radio
January 10, 2017

Wednesday, January 11, 2017

Statoil wins offshore wind lease in New York

Statoil has been declared the provisional winner of the U.S. government’s wind lease sale of 79,350 acres offshore New York.  Statoil will now have the opportunity to explore the potential development of an offshore wind farm to provide New York City and Long Island with a significant, long-term source of renewable electricity.  Statoil submitted a winning bid of $42,469,725 during the online offshore wind auction concluded December 15, 2016 by the U.S. Department of the Interior's Bureau of Ocean Energy Management (BOEM).
The lease comprises an area that could potentially accommodate more than 1 GW of offshore wind, with a phased development expected to start with 400-600 MW. The New York Wind Energy Area is located 14-30 miles (30-60 km) offshore, spans 79,350 acres (321 km2), and covers water depths between 65 and 131 feet (20-40 meters).

Statoil will next conduct studies to better understand the seabed conditions, the grid connection options and wind resources involved in the lease site.

The State of New York projects that offshore wind will be a significant part of the renewable energy generation needed to meet its Clean Energy Standard in 2030.
Nysted Wind Facility, 8-12 miles offshore Denmark, the North Sea. Wind turbines are arranged to
take advantage of the prevailing wind conditions at the project site, and turbine spacing
is carefully designed to maximize cost efficiency and power production. 
In Europe, Statoil is developing an offshore wind portfolio with the capacity of providing over 1 million homes with renewable energy. Statoil currently holds a 40% share in the Sheringham Shoal wind farm in the UK, which has been in production since 2012. The Dudgeon offshore wind farm, also located offshore Norfolk in the UK – and the world’s first floating offshore wind farm, Hywind Scotland – will come in production in 2017. Earlier this year, Statoil acquired 50% of the Arkona offshore wind farm in Germany, which will come in production in 2019.

KIUC and AES Distributed Energy Announce Plan to Construct Innovative Renewable Peaker Plant on Kauaʻi Utilizing a Hybrid Solar and Battery Storage System

Kauaʻi Island Utility Cooperative (KIUC) and AES Distributed Energy, Inc. (AES DE), a subsidiary of The AES Corporation (AES), today announced the execution of a power purchase agreement (PPA) for an innovative plant that will provide solar energy together with the benefits of battery-based energy storage for optimal balancing of generation with peak demand. The project consists of 28 megawatt (MW) solar photovoltaic and a 20 MW five-hour duration energy storage system.

The system will be located on former sugar land between Lāwaʻi and Kōloa on Kauaʻi’s south shore. It will be the largest solar-plus-utility-scale-battery system in the state of Hawaiʻi and one of the biggest battery systems in the world.

“Energy from the project will be priced at 11 cents per kWh and will provide 11 percent of Kauaʻi’s electric generation, increasing KIUC’s renewable sourced generation to well over 50 percent,” said KIUC’s President and Chief Executive Officer, David Bissell. “The project delivers power to the island’s electrical grid at significantly less than the current cost of oil-fired power and should help stabilize and even reduce electric rates to KIUC’s members. It is remarkable that we are able to obtain fixed pricing for dispatchable solar based renewable energy, backed by a significant battery system, at about half the cost of what a basic direct to grid solar project cost a few years ago.” Bissell estimates that the project will reduce KIUC’s fossil fuel usage by more than 3.7 million gallons yearly.
AES DE will be the long-term owner and operator of the project. The company is committed to providing innovative renewable energy solutions to its utility, corporate governmental customers. AES now operates one of the largest fleets of battery-based energy storage in the world.
According to Utility Dive:

The project is the second flexible solar facility for the small co-op. In 2015, KIUC signed a deal with SolarCity to pair a 13 MW solar array with a 52 MWh battery that will deliver power for $0.145/kWh.

The project is expected to provide 11% of Kauai's energy needs, "increasing KIUC's renewable sourced generation to well over 50%," Bissell said. The island has been known to reach renewable energy penetrations of above 90% during peak wind and solar generating hours.

Not only are the costs of both solar-plus-storage facilities below the cost of fossil fuel to power the island, they often beat the cost of the fuel alone. According to co-op documents, KIUC has paid between $0.122/kWh and $0.18/kWh in just fuel and commodity costs since Dec. 2014, with Nov. 2016 costs coming in above $0.15/kWh.

In 2015, the most recent year reported, KIUC's average residential electric rates were $0.323/kWh — lower than past years due to dipping oil prices. Rates for other customer classes were higher.

Press Release dated January 10, 2017
Kauaʻi Island Utility Cooperative (KIUC)
and Gavin Bade @GavinBade "Hawaii co-op signs deal for solar+storage project at 11¢/kWh"

Tuesday, January 10, 2017

Lazard Releases Annual Levelized Cost of Energy and Levelized Cost of Storage Analyses

Lazard Ltd (NYSE:LAZ) has released its annual in-depth studies comparing the costs of energy from various generation technologies and of energy storage technologies for different applications.

Lazard's latest annual Levelized Cost of Energy Analysis (LCOE 10.0) shows a continued decline in the cost of generating electricity from solar technology, with lesser cost declines in other forms of renewable energy. Lazard's latest annual Levelized Cost of Storage Analysis (LCOS 2.0) shows cost declines in most battery storage technologies, but with wide variations depending on the type of application and battery technology.

In addition, LCOS 2.0, conducted with support from Enovation Partners, builds on the inaugural LCOS study conducted in 2015 with a refined methodology and the addition of new analysis that illustrates and compares the economics of "real-world" energy storage applications.

The full report is available free of charge at

[On an unsubsidized basis, Lazard estimated the LCOE of land-based wind to be between $32/MWh and $62/MWh, lower than that of a combined cycle natural gas plant, which came in at between $48/MWh and $78/MWh. 

Utility-scale solar costs had a smaller range, coming in between $46/MWh and $56/MWh for thin film installations. Rooftop and community solar costs were higher, due largely to scale.

The report shows solar costs falling faster than other forms of generation, with utility-scale PV costs ... falling 11 percent to between $46 and $61 per megawatt-hour (MWh), with thin-film costs a fraction lower than crystalline silicon costs.

This is roughly in line with cost estimates made by GTM Research, which finds that new power purchase agreements for large-scale solar are being signed at $35-60/MWh. However, these projects will typically be completed in 2017 or later, so costs are lower.

It also puts PV at less than half the cost of nuclear generation....

This makes utility-scale PV slightly more expensive than onshore wind, which came in at $32-$62/MWh. ...

The analysis also puts rooftop commercial and industrial (C&I) solar at $88-$193/MWh, and shows rooftop residential solar costs falling 26 percent to $138-$222/MWh.

This is by far the steepest cost decline of any technology.
For replacement of peaker plants, Lazard put the LCOS of lithium-ion batteries at $285-$581 per MWh, but the cost was much lower at $190-$277 for frequency regulation. Lazard also notes that while lithium-ion batteries are more expensive than peaker plants for some applications, some uses of energy storage are attractive relative to conventional alternatives.]

Synergies between biodiversity conservation and ecosystem service provision: Lessons on integrated ecosystem service valuation from a Himalayan protected area, Nepal

• TESSA was used for integrated ecosystem services valuation of Shivapuri-Nagarjun National Park, Nepal.
• Net monetary ecosystem service value of protecting the Park was estimated at $11 million y-1.
• Protection avoided a reduction in carbon stock of 60% and a net annual monetary loss of 19%.
• Conservation and ecosystem service provision objectives were congruent at site-level.
• A buffer zone around the park may improve benefit sharing.

We utilised a practical approach to integrated ecosystem service valuation to inform decision-making at Shivapuri-Nagarjun National Park in Nepal. The Toolkit for Ecosystem Service Site-based Assessment (TESSA) was used to compare ecosystem services between two alternative states of the site (protection or lack of protection with consequent changed land use) to estimate the net consequences of protection. We estimated that lack of protection would have substantially reduced the annual ecosystem service flow, including a 74% reduction in the value of greenhouse gas sequestration, 60% reduction in carbon storage, 94% reduction in nature-based recreation, and 88% reduction in water quality. The net monetary benefit of the park was estimated at $11 million year-1. We conclude that: (1) simplified cost-benefit analysis between alternative states can be usefully employed to determine the ecosystem service consequences of land-use change, but monetary benefits should be subject to additional sensitivity analysis; (2) both biophysical indicators and monetary values can be standardised using rose plots, to illustrate the magnitude of synergies and trade-offs among the services; and (3) continued biodiversity protection measures can preserve carbon stock, although the benefit of doing so remains virtual unless an effective governance option is established to realise the monetary values.

Examining the ecosystem service of nutrient removal in a coastal watershed

• The Piscataqua-Salmon Falls watershed community needs to address wastewater treatment plants.
• Conservation could reduce 3–28 t/yr of Nitrogen, worth 10–50 million dollars over ten years.
• Even under high conservation removal estimates of 28.1 ton/yr, point source reductions are needed.

Globally, managers are trying to prevent or halt the eutrophication of valuable estuaries and bays by reducing nutrient inputs, but justifying the cost of conservation or processing facility upgrades often proves challenging. We focus on a coastal watershed in Maine and New Hampshire struggling with the financial burdens of nitrogen pollution mandates due to the eutrophication of the Great Bay estuary. After creating two future watershed land cover scenarios comparing plausible extremes, we ran them through two models, the Natural Capital Project’s InVEST (Integrated Valuation of Ecosystem Services and Tradeoffs) and a detailed hydrologic and biogeochemical river network model FrAMES (Framework for Aquatic Modeling of the Earth System). Through this work, we both evaluated and valued the ecosystem service of nitrogen retention. We find that both models provide numerical arguments for conservation efforts, and decision makers would benefit from using either an ecosystem services model or a biogeochemical model when dealing with complex issues like nutrient overenrichment. According to both our modeling results, modest watershed conservation efforts as defined by our expert stakeholders, ie: protecting wetlands and forests, could reduce the amount of total nitrogen entering the Great Bay estuary in the range of 3–28 metric tons per year.
aerial shot of Little Bay and Great Bay
by Chelsea E. Berg 1, Madeleine M. Mineau 2 and Shannon H. Rogers 1 
1. Center for the Environment, Plymouth State University, United States MSC 63 17 High Street, Plymouth, NH 03264, United States.
2. Earth Systems Research Center, University of New Hampshire, Durham, NH, USA
Ecosystem Services via Elsevier Science Direct
Volume 22, Part B, December 2016, Available online 24 December 2016; Pages 309–317
Special Issue: Integrated valuation of ecosystem services: challenges and solutions
Keywords: Ecosystem service valuation; Nutrient retention; InVEST; Great Bay; Avoided cost analysis; FrAMES

Estimating the value of ecosystem services in a mixed-use watershed: A choice experiment approach

• Location and costs are significant explanatory variables of MWTP.
• Annual household income was associated with ecosystem services preferences.
• The average MWTP for ecosystem services was extremely low (<$2/household/year)
• A dissociation between local needs and global issues explains the overall low valuations.
The protection of water, land, and air resources has profound implications for the sustainability of ecosystem services provided to societies that are embedded within economies, global systems, and socio-cultural and political contexts. This study assessed preferences for provisioning, regulating, and supporting ecosystem services, specifically, climate regulation (carbon sequestration), nutrient control (water quality), and agricultural and forest productivity, and the willingness to pay for protection of these ecosystem services by residents in the Suwannee River Basin of Florida, as assessed through a household mail survey and choice experiment. A conditional logit model was used to evaluate preferences and marginal willingness to pay (MWTP) under different scenarios. Survey respondents identified nutrient control (water quality) as the most important service, while agricultural and forestry production was somewhat important, and climate regulation/carbon sequestration was the least important. Respondents expressed the highest level of trust in local government agencies to implement ecosystem service protection programs, and welcomed the implementation of such programs anywhere in the basin, but not close to their home. The average MWTP was extremely low (<$2/household/year) when compared to other studies, and suggests that respondents have many competing interests for their discretionary spending in relation to environmental amenities.
Suwannee River.jpg
Pasicha Chaikaew 1 and 3, Alan W. Hodges 2 and Sabine Grunwald 3 
1. Department of Environmental Science, Chulalongkorn University, Bangkok 10330, Thailand
2. Department of Food and Resource Economics, University of Florida, Gainesville, FL 32611, USA
3. Department of Soil and Water Science, University of Florida, Gainesville, FL 32611, USA
Ecosystem Services via Elsevier Science Direct
Volume 23; February, 2017; Pages 228–237
Keywords: Ecosystem services; Choice experiments; Willingness to pay; Preferences