Going Underground: A Focus on Natural Gas Storage

Author: Doug Allen, Account Manager, U.S. Energy Services

U.S. Energy Information Administration (EIA) is an agency within the U.S. Department of Energy that collects and analyzes energy-related data and statistics.  The EIA was created in the 1970’s to provide lawmakers, industry and the public with unbiased and independent energy related information for the purpose of promoting sound policy, ensuring efficient markets, and helping the public understand energy and its relationship to the economy and the environment.

Each week the EIA releases data on the levels of natural gas in storage in the United States.  This closely watched indicator can have a significant impact on the natural gas prices, often moving the market sharply within moments of the release.   Since the U.S. must rely on natural gas from storage to meet winter demand, reports that show levels that are lower than anticipated or that might portend insufficient storage levels in the future tend to push prices higher.   If the expectations are that storage levels may become too high, and thus create a natural gas glut, the market may have a more bearish price reaction.

Natural gas is primarily stored underground in depleted oil and gas fields, natural aquifers converted to storage facilities and salt caverns.  There are about 400 underground facilities currently in use with a cumulative working gas capacity of 4.659 tcf (trillion cubic feet).   The total U.S. consumption of natural gas was about 27.47 tcf in 2015.


While 126 operating entities own these facilities, the actual storage capacity is contracted to many customers.  Data from the EIA website shows us that the 20% of all storage operators manage nearly 70% of the storage in the lower 48 states.  Most of these are interstate pipelines and utility companies.  A deeper dive into the index of the pipeline customers shows that they contract out most of their storage to natural gas and electric utility companies.  Ultimately, utilities control the bulk of U.S. natural gas storage.


To collect the data for the Weekly Natural Gas Storage Report, storage companies that are “statistically selected by the EIA from a listing of all underground natural gas storage operators in the United States” must complete and submit a form detailing their natural gas storage levels.  The EIA estimates the total natural gas storage level based on this sample.

The EIA’s Weekly Natural Gas Storage Report is released each Thursday at 10:30 a.m. Eastern and can be found at this website: http://ir.eia.gov/ngs/ngs.html.  The website also includes historical data, reporting methodologies and any changes to the report release schedule for holidays.   The Weekly Natural Gas Storage Report is a key component of the EIA’s Natural Gas Weekly Update.

Sources: http://www.eia.gov/

Atlantic Coast Pipeline

Author: Kelly Zabel, Account Manager, U.S. Energy Services

Despite abundant natural gas supplies in the Marcellus shale play, lack of pipeline capacity and infrastructure to get this natural gas supply to the growing demand of Virginia and North Carolina has contributed to residents and companies not being able to reap the benefits of the bountiful harvest that has been occurring there for a few years now.  To remedy this situation, four companies – Dominion, Duke Energy, Piedmont Natural Gas, and AGL Resources – have teamed up in a joint venture to build and own the Atlantic Coast Pipeline (ACP).  Some of the benefits of this new pipeline include increased electric generation from a cleaner fuel source (vs. coal), improved service reliability, and room for further customer growth and economic development.  The need for this new pipeline is so heavily felt and widespread that 96% of the capacity is already spoken for under various purchase agreements.

The proposed route is approximately 550 miles long, originating in Harrison County, West Virginia, stretching southeast to Greensville County, Virginia, and then continuing to southern North Carolina.  This includes an almost 70 mile long eastern lateral to Hampton Roads.


Currently, the ACP Team is in the middle of surveying along the proposed route and about 90% of landowners have granted permission for their land to be surveyed.  However, this pipeline is facing strong opposition from rural landowners, especially in Virginia.  Governors of Virginia, West Virginia, and North Carolina are behind the project, stating that this will boost their economies, help their communities, and bring more manufacturing business to their areas.  Yet dozens of landowners are refusing to allow the ACP Team to survey on their land, resulting in numerous lawsuits with more to come.  Opposition groups state a decrease in tourism and damage to the environment and economy as some of the reasons for their reluctance to cooperate.

The ACP Team has also been busy with FERC, submitting the necessary filings to keep this major project moving.  Below is the estimated timeline of the Atlantic Coast Pipeline Project.


Underwater Pipelines

Author: Sandy Zoulek, Account Manager, U.S. Energy Services

Did you know there is an oil pipeline crossing under the water at the five-mile stretch between the Upper and Lower Peninsula of Michigan, where Lake Michigan and Lake Huron meet? The area between the two Great Lakes is called the Straits of Mackinac.  The pipeline, called “Line 5” by its owners, Enbridge Energy, is part of an extensive system which transports oil and liquefied natural gas throughout the Midwest and Canada.

Mackinac Bridge, spanning 5 miles, and connecting the Lower and Upper Peninsula

Mackinac Bridge, spanning 5 miles, and connecting the Lower and Upper Peninsula

Built in 1953, Line 5 is a 30” diameter pipeline that runs 645 miles, originating in Wisconsin, running under the Straits of Mackinac, and ending in Sarnia, Canada.  When underwater, the pipeline consists of two side by side 20” diameter pipes which span the distance shore to shore of approximately 5 miles.  The pipes range in depth, up to 270 feet underwater and 20 million gallons of light crude oil and natural gas fluids pass through them each day.


Did you also know that “The Great Lakes and their connecting channels contain more than 90% of the freshwater of the United States and 20% of the world’s supply of fresh surface water?” National Wildlife Federation 2012

With this fact, and since the pipeline is 63 years old (some consider 50 years the ‘life expectancy’), many activist groups (Patagonia commissioned a Documentary:  Great Lakes, Bad Lines) and Michigan Counties are calling for its retirement.  Reasons range from the obvious risk of a spill, to failure to comply with easement rules, poor safety record by the pipeline’s owner, and the example of the spill on the Kalamazoo River (MI) in 2010 from Line 6B of the Enbridge portfolio. (The Kalamazoo River spill is the largest inland oil spill in US history, releasing one million gallons of heavy crude oil.)

Due to the impending risk of a spill, some Michigan legislators have filed suit to have the pipeline be re-categorized as an off shore pipeline.  Under the Oil Pollution Act, the liability for cleanup costs for owners or operators of onshore facilities is capped at $634 million, whereas companies operating pipelines classified as offshore facilities are required to demonstrate they have sufficient resources to pay for all cleanup costs.

In March of 2016, David Schwab, PH.D., of the University of Michigan Water Center, conducted a study of what he determined was the “worst possible place for an oil spill”. (Statistical Analysis of Straits of Mackinac Line 5: Worst Case Spill Scenarios)  The study, complete with animation to determine to potential flow of the spill, shows that 700 miles of shoreline would be affected by a spill in the Straits.  The Straits are subject to wide and varying factors including constantly changing currents, wind, and ice that would contribute to the complexity of a spill.

Enbridge is fighting back stating that the U of M Water Center modeling study was based on unrealistic assumptions.  Additionally, they have  “introduced new measures to help ensure the line continues to safely transport light crude oil and natural gas liquids……” further stating that “It does not and will not, carry heavy oil.” (heavy oil includes bitumen which was a key factor in the spill cleanup issues at Kalamazoo) Enbridge also states that the line is being operated at less than 25% of its maximum pressure capacity for enhanced safety.

Since the Kalamazoo spill, Enbridge has changed the way it operates, implementing numerous enhancements to operating and safety procedures.  They have established a Pipeline Control System and Leak Detection (PCSLD) department to better focus on maintenance needs. The response time for a spill is listed as 3 minutes in their many online brochures about Line 5.

Enbridge carries out hundreds of safety drills each year, but also embarked in a mock oil spill drill in 2015 specifically in the Straits of Mackinac to show their commitment to the safety of the Straits, Lake Michigan, Lake Huron, and the lakeshore.

This pipeline, as are all 2 million+ miles of pipeline, is governed by the Pipeline Hazardous Material Safety Administration (PHMSA) who is carefully monitoring the safety practices of Enbridge and Line 5. PHMSA’s focus is on public and environmental safety, holding Enbridge and all other pipeline owners and operators accountable for proper maintenance and safe operations.

Emails from Enbridge spokesperson, Ryan Duffy, state that “Line 5, while not perfect, is in very good condition and meets or exceeds today’s standards for new pipelines.”

Everyone, including Enbridge, agrees that an oil spill in the pristine waters of the Straits of Mackinac would be catastrophic.


Capacity Cost in the American Midcontinent

Author: Carl Doten, Account Manager, U.S. Energy Services

The 4th Midcontinent Independent System Operator (MISO) capacity auction was held earlier this month and the results of the auction have now been published (MISO Resource Adequacy Auction Results). The recently published prices offer insight into both expected energy costs for the coming delivery year of June 1, 2016 through May 31, 2017, and trends within the capacity supply/demand balance of each respective zone.

miso-territoryA map of MISO’s territory by zone is shown to the right. Electric consumers located in any of these zones, are likely to be impacted by the auction results either through potential cost changes in base rates in fully regulated service territories or cost changes in the capacity line item component in deregulated service territories.

The extent to which a consumer is impacted by the auction depends on a number of factors including:

  1. Which zone a consumer is located in (unit cost)
  2. Assigned capacity requirement (kW units)
  3. Energy contract structure (exposure)

The auction results (shown in $/Megawatt Day) by zone are shown in the table below along with the results of prior years.


A review of the results with an understanding of the wider context prompts a few observations:

  1. All regions will be adequately supplied with capacity for the coming delivery year.
  2. Six of ten zones within the MISO will see higher capacity prices, while Zone 4 will find welcome relief from the prices of the last delivery year.
  3. The results indicate a shrinking in the available pool of capacity offerings. Most notable was the approximate 2,000 MW of capacity at the price taker point (bid in around $0/MW-day), and 3,000 MW of capacity this last year at the $160/MW-day price point. These losses represent approximately 5% of the bid capacity within the region.
  4. Regional capacity varied only slightly from what was expected, with much of the differential attributed to Reciprocating Internal Combustion Engine (RICE) regulations causing early retirements.

Finally, it should be acknowledged that within the MISO territory, the price set by the auction is only one approach to setting the cost to end users for the capacity component of pricing, and therefore should be looked at more as a price trend indicator than a specific unit cost.

From a higher level, the variability of pricing year over year, and from zone to zone provides a reasonable defense for the efforts that are underway to revise the capacity auction framework in MISO zones that rely on competitive markets to satisfy capacity needs (currently limited to Zone 4 as proposed).  The proposed shift to an annual auction covering the coming 3 delivery years (similar to PJM) would allow end users to better forecast costs, and would allow generators to finance and plan their generation resources based on a longer term view.

For Risk Averse Fuel Consumers, Now May Be A Good Time To Forward Purchase Your Diesel And Gasoline Supplies.

Author: Craig Petter, Account Manager, U.S. Energy Services

Diesel fuel retail price falls below $2.00 per gallon for first time since 2005


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Source: U.S. Energy Information Administration

In mid-February the weekly diesel price survey showed an average retail price for on-highway diesel fuel at $1.98 per gallon. This is the first time the price for diesel has fallen below $2.00 per gallon since February 2005. These lower prices are a reflection of lower per-barrel crude prices and significant storage inventories.


Fundamentals Driving Low Prices

Increases in production               


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Source: U.S. Energy Information Administration


Increases in national storage inventories


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  • EIA data showed a 9.4 million barrel increase in domestic stockpiles.
    • Inventory levels have risen by over 50 million barrels since the start of the year and sit at the highest level since 1930.
  • Global crude market remains bearish amid oversupply and tepid demand.
  • Crude market traded at significant bottom in February, but fundamental reasons surrounding the price collapse are still very much in place.
  • With a shrinking wholesale market, consumers are benefiting from lower supplier markup.


Bullish signals

Exploratory rig counts dropping


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Source: U.S. Energy Information Administration


Petroleum exports continue to rise


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Source: U.S. Energy Information Administration

  • Rigs searching for new production sources are at historic lows.
  • The cost to produce supplies is greater than the current market for many suppliers.
  • Suppliers are capping off already drilled wells in anticipation of higher per barrel pricing in the future.
  • Smaller suppliers being pushed out due to bankruptcy or acquisition.


Consumer Options

With the significant decline in diesel and gasoline pricing over the past few years, many end users are taking advantage of these low prices and developing a Price Risk Management Program (aka Hedging). This is a program where the consumer can forward purchase fuel supplies at a known price.  Locking in all or a percentage of your future fuel costs (hedging) is a powerful tool to mitigate the volatility of an unpredictable market.

Some of the benefits of a disciplined Price Risk Management Plan are:

  • Allows you to “fix” your future diesel and gasoline costs today
  • Reduces market price volatility
  • Increases price certainty
  • Allows you to budget diesel and gasoline costs more accurately
  • Current market conditions are approximately $.45/gallon less than last year

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Congress Extends Tax Credits for Solar & Wind

The week before Christmas Congress passed a pair of budget bills that contained multi-year extensions of tax credits to encourage solar and wind energy development. The extensions were part of a package deal that included extensions for other renewable energy sources such as geothermal, landfill gas, and hydro in exchange for lifting the 1970s ban on the export of crude oil.

The solar energy Investment Tax Credit (ITC) was set to decline from 30% to 10% at the end of 2016. The legislation extends the tax credit at the 30% level through the end of 2019, after which it will decline annually until it hits 10% in 2022. The extension will help the solar industry avoid the boom and bust cycles that have plagued the wind industry due to chronic uncertainty around the production tax credit.

The wind Production Tax Credit (PTC) was extended at the $0.023/kWh level through 2016. The PTC will then decline 20% per year from 2017 through 2020.

The extension of the ITC will help solar to continue its rapid growth trajectory. GTM research attributes a 30% increase in solar investment through 2020, more than $40 billion, to the extension of the ITC. Overall, GTM is predicting that nearly 100 gigawatts of installations, representing $130 billion in investments by 2020. Though a net positive, Bloomberg New Energy Finance (BNEF) is predicting that the extension of the ITC will reduce the amount of solar installed in 2016 as developers no longer have to rush to meet the ITC expiration deadline at the end of 2016. Overall, BNEF predicts the total solar installations in 2016 will be down about 2.8 gigawatts, but the 2017 increase will more than make up for this reduction.

Energy Management Increasingly Seen as a Source of Competitive Advantage

Deloitte’s 2015 Resource Study found that business increasingly views an active energy management program as a way to create and maintain competitive advantage. The study, first conducted in 2011 and update annually thereafter, is based on a survey of over 600 corporate energy management decision-makers. Fully 44% (up 10% from 2014) of respondents identified energy management as integrated into corporate strategy, while 37% said energy management is integrated at the business unit or site level. Reducing electricity costs was identified as a key goal:

  • 79% identified reducing electric costs as important to financial competitiveness
  • 77% identified reducing electric costs as important to image/brand competitiveness

The latter suggests that companies are motivated by more than just cost-cutting; they are also taking into account external stakeholder views.

Businesses are spending capital to achieve their energy management goals. Goals have been set around electricity (88%), natural gas (64%), transportation fuels (59%), carbon (57%), and water (70%), with approximately one-quarter of goals across all five areas being targeted reduction goals.  Ninety-three percent of businesses indicate they invested capital over the last five years to achieve energy goals, totaling around 17% of overall capital spending.

The most popular technologies and strategies for achieving energy management goals in 2015 were:

  • 55% timers/sensors to control when equipment is powered on
  • 53% motion sensors
  • 47% building energy management systems
  • 41% demand response programs
  • 39% onsite generation technology such as solar panels
  • 34% energy recovery systems
  • 26% batteries for load shifting and peak shaving

New technologies will continue to drive increased corporate energy efficiency. A 2015 study by McKinsey & Company finds that operational improvements can improve energy efficiency 10-20%, but investment in new technologies can increase the savings to as high as 50%. Overall, the study finds that adoption of innovative technologies could save industry over $600 billion per year globally. The report outlines new technologies for the following nine sectors.

  • Advanced Industries (e.g. semiconductors, electronics)
  • Cement
  • Chemical
  • Oil Refining
  • Consumer Goods
  • Mining
  • Power
  • Pulp and Paper
  • Steel

The full report can be found here — Greening the future: New technologies that could transform how industry uses energy.

REAP: Rural Renewable Energy & Efficiency

The Rural Energy for America Program (REAP) was created by Congress in the 2008 Farm Bill. Administered by the U.S. Department of Agriculture (USDA) the REAP program provides grants and guaranteed loans to agricultural producers and rural small businesses for renewable energy projects or energy efficiency improvements. In August, the USDA announced $63 million in loans and grants for 264 renewable energy and energy efficiency projects so far in 2015. Several of U.S. Energy’s ethanol clients have made applications to the REAP program to support their energy efficiency improvement efforts.

Applicant Eligibility

Agricultural producers may be in rural or non-rural areas as long as they derive at least 50% of gross income from agricultural operations

Small businesses must be in an area other than a city or town with a population of 50,000 or more. Small businesses can check if they are in an eligible rural area here.

Project Eligibility

Renewable Energy Systems – funds may be used for purchase, installation, and construction of systems. Examples of eligible renewable energy systems include:

  • Biomass
  • Geothermal
  • Hydropower
  • Wind
  • Solar

Energy Efficiency Improvements – funds may be used for purchase, installation, and construction of improvements. Examples of eligible efficiency improvements include:

  • Lighting
  • Insulation, doors & windows
  • High efficiency HVAC
  • High efficiency motors and pumps

Funding Types

Grants and loan guarantees are available through the REAP program and individual projects may apply for one or both. Combined grant and loan guarantee funding cannot be more than 75% of the total project cost.


  • Grants up to 25% of total project cost
  • Renewable energy system grants range between $2,500 – $500,000
  • Energy efficiency grants range between $1,500 – $250,000

Loan Guarantees

  • Loan guarantees up to 75% of total project cost
  • Minimum loan amount of $5,000
  • Maximum loan amount of $25 million

Energy Audits and Assessments

When applying for energy efficiency improvement (EEI) funding an energy audit or assessment is also required as part of the application package. For EEI projects with a total cost greater than $200,000 an Energy Audit must be conducted. For EEI projects with a total cost of less than $200,000 an Energy Assessment or Energy Audit may be done. In general, the Energy Audit requires more in-depth analysis of the proposed EEI, such as detailed specifications, measurement plan, and calculation of direct and indirect costs.

REAP Resource Links

EPA Releases Final Clean Power Plan

On August 3, President Obama announced the U.S. Environmental Protection Agency’s (EPA) final Clean Power Plan (CPP).  First proposed in June, 2014 the goal of the CPP is to reduce carbon dioxide (CO2) emissions from existing power plants 32% from 2005 levels by 2030.  This is an increase from the originally proposed goal of a 30% reduction; and not the only change from proposed rule.  Before reviewing other key changes between the proposed and final rule let’s recap what sources are covered by the CPP.

CPP - PowerSectorCO2Emissions

Source: U.S. EPA

The CPP covers larger electric generating units (EGUs) that sell power to a utility distribution system.  Covered EGUs include any boiler, integrated gasification combined cycle, or combustion turbines (simple or combined cycle) that:

  1. is capable of combusting 250 million BTUs per hour or more
  2. combusts fossil fuel for 10% or more of its total annual heat input
  3. sells the greater of 219,000 MWh per year and one third of its potential electrical output
  4. was in operation or had commenced construction as of January 8, 2014

Given the electrical production numbers above, and assuming a capacity factor of 100%, the smallest possible generating unit that would be covered is 25 MW.  More realistically, covered EGUs will be at least twice this size.

Key Changes in the Final CPP

Mass-Based State Goals: One of the key changes from the proposed to the final rule is the addition of mass-based goal in addition to rate-based goals for each state.  The proposed rule only included rate-based goals. Mass-based goals were added to expand options for states when developing their plans, in particular it facilitates states’ use of mass-based trading programs.

Trading-Ready Mechanisms:  states have the option of developing trading-ready programs, which means EGUs can trade creditable reductions between states without the need for an interstate agreement to be in place beforehand.  EPA is committed to facilitate trading by helping states track emissions and credits.

Compliance Glide Path: one of the biggest criticisms of the proposed rule was the compliance cliff in 2029.  The final rule phases in EGU performance rates over three time periods: 2022-2024, 2025-2027, and 2028-2029; with final compliance in 2030.

BSER made up of Supply Side Building Blocks: EPA sets the level of reductions for EGUs by looking at the Best System of Emission Reductions (BSER) demonstrated for a pollutant.  In the proposed rule the BSER was made of four building blocks, including energy efficiency, a demand-side block.  The final rule only includes the supply-side building blocks shown below:

  • Improved Efficiency at Power Plants
  • Shift Generation from Higher Emitting Coal to Lower Emitting Natural Gas
  • Shift Generation to Zero-Emitting Renewables

Revised Building Block Assumptions: in addition to removing the demand-side building block EPA also revised the assumptions for the remaining supply-side building blocks based on feedback received on the proposed rule.

Building Block Proposed Rule Final Rule
Improved Efficiency at Power Plants Assumes a 6% improvement is possible for coal units 2.1% – 4.3% depending on region of the U.S.
Shift Generation from Higher Emitting Coal to Lower Emitting Natural Gas Increase the capacity factor to 70% for natural gas combined cycle EGUs 75% of net summer capacity
Shift Generation to Zero-Emitting Renewables increase use of renewable resources Assumes more renewables due to falling costs – excludes existing nuclear and renewables

For a complete overview of all the key changes see the EPA fact sheet Clean Power Plan: Key Changes and Improvements; a full list of EPA fact sheets on the CPP is at the bottom of the article.

Implementation and Compliance Timeline

In addition to increasing state flexibility and encouraging trading as a compliance tool the EPA also pushed back the first compliance milestone from 2020 to 2022.  The timeline for submitting plans has been pushed back two months, with at least an initial plan due by September 6, 2016.

CPP - Timeline2

Source: U.S. EPA

The extended timeline may give states greater flexibility in that it will give more time for economic fuel switching from coal to natural gas to continue to play out in the electric generation sector.  Just last week the Energy Information Administration (EIA) announced that power sector CO2 emissions hit a 27 year low in April.  The EIA notes that April is typically the month with the lowest CO2 emissions, and that April 2015 was the lowest of any month since April, 1988.  Comparing these two months 27 years apart the EIA notes that:

  • Natural gas consumption in the sector has tripled
  • Renewable energy consumption doubled
  • Nuclear energy consumption increased 47%
  • Coal consumption decreased 17%

All of these trends have naturally led to a less carbon intense power sector with generation up 44% over the period, but energy use increasing only 33% and CO2 emissions up just 4%.  The graph below shows that the monthly power sector carbon emissions have been trending down since 2005. The full EIA piece is here: Monthly power sector carbon dioxide emissions reach 27-year low in April.



EPA Clean Power Plan Fact Sheets:

Bladeless Wind Power

Vortex Bladeless Field

Image courtesy of Vortex Bladeless

Renewable energy sources make up 13% of the U.S. electric generation portfolio; the U.S. Energy Information Administration (EIA) projects that U.S. renewable electricity generation will grow to 18% by 2040; with wind overtaking hydro as the largest renewable source by then.   Though solar has been growing faster year-over-year, the EIA Short-Term Energy Outlook projects that wind will add more absolute capacity between 2014 and 2016; 18 GW for wind compared with 9 GW of utility-scale solar.

The report Enabling Wind Power Nationwide was released by the Department of Energy in May and focuses on new technologies to expand wind energy in the U.S.  The primary focus is on taller turbines and larger rotors to capture the more consistent and stronger winds at greater heights.  Though there are technical and logistical challenges when raising hub heights from the standard 80 meters (262 feet) to 110 meters (360 feet) or more; this is an extension of existing technology rather than a fundamental technological innovation with how wind energy is collected and converted to electricity.

For this latest Future Friday post we’re going to look at a startup company that is trying to create a fundamental shift in how wind energy is generated.  Vortex Bladeless is rethinking wind energy by doing away with the turbine altogether and harnessing the cyclical pattern of vortices that are formed by wind flowing around a tower.  Vortex says their bladeless system can generate electricity for 40% less than standard turbine technology.  According to the EIA land-based wind turbines already have one of the lowest Levelized Costs of Energy (LCOE), conventional or renewable, except for advanced combined cycle natural gas generation and geothermal (EIA 2015 Annual Energy Outlook).  A further 40% reduction in LCOE would make the Vortex Bladeless technology the lowest cost electric generation technology overall.

Vortex Bladeless Single

Image courtesy of Vortex Bladeless

The Vortex system achieves the cost efficiencies with an innovative, but simple design for harnessing wind energy.  The main mast oscillates in the wind due to the vorticity effect; this oscillation force is transmitted through an elastic rod to drive a generator at the base of the system.  According to Vortex Bladeless this design achieves cost efficiencies in a number of ways:

  •  53% lower manufacturing costs – the blades and nacelle of a traditional wind turbine are eliminated.  Further savings are achieved because the generator is at the base, obviating the need for an expensive mast that can hold the generator 300 – 400 feet in the air safely under high wind loads.
  •  80% lower maintenance costs – the mast and elastic rod are magnetically coupled to the generation system, so there are no mechanical elements that can wear out, require lubrication, etc.
  •  Lower installation costs – the Vortex system is estimated to weigh 80% less than a conventional wind turbine, resulting in easier transportation and installation of the system.  This also results in a foundation that is 50% smaller than a conventional turbine, which generates additional savings.

Traditional wind turbines have one advantage over the Vortex system, they are more efficient.  The Vortex system is estimated to be 30% less efficient that a traditional turbine, but lower costs and the ability to put them closer together than traditional turbines compensates for this disadvantage.

Vortex began field testing a 6 meter scale prototype in 2014 and completed a successful round of crowd funding in June.  The plans are to build a 13 meter system with an output of 4 kW in the next 12 months, and an industrial prototype that is 150 meters with a 1 MW output in the next 36 months.