Retirement of Coal Power Plants Accelerates

According to a new Government Accounting Office (GAO) report released in September, actual and planned retirements of coal-fired power plants has accelerated due to new U.S. EPA rules and regulations and other market forces. 

Back in 2012, GAO performed an analysis of projected closure of coal plants due to four new EPA rules:

  • Cross-State Air Pollution Rule (CSAPR)
  • Mercury and Air Toxics Standard (MATS)
  • Cooling Water Intake Structures Regulation (316(b))
  • Disposal of Coal Combustion Residuals from Electric Utilities (CCR)

Noticeably absent from this list are the new climate change regulations announced by the Obama Administration in June of 2014.  The new regulations seek overall reductions in CO2 emissions of 30% by 2030.

Other factors have contributed greatly to the large number of coal plant retirements.  Those include cheap natural gas resulting from the Utica and Marcellus discoveries in the Midwest.  As well as lower demand in electricity overall. 

Based upon the combination of regulations and market changes, in 2012, GAO forecasted that between 2 to 12 percent of coal-fueled generating capacity could retire.  GAO's new report indicates that the rate of retirements have actually exceeded the top end of the range predicted just two years ago. 

GAO now predicts that 13 percent of coal-fueled generating capacity - 42,192 megawatts (MW)- has either been retired since 2012 or is planned for retirement by 2025.  See, chart below  

NOTE:  Three-quarters of the plant closures will occur by the end of 2015 which corresponds to the initial MATS compliance deadline









Ohio Impacts

The majority of plant closures will occur in the Midwest with Ohio having the largest percentage of retired generating capacity- 14%

It is difficult to predict what this significant disruption in the electricity generation portfolio will have in terms of capacity and prices.  It will be critical to see new natural gas generating capacity come on line before the end of 2015 to replace a large portion of the lost capacity.  

Such impacts were inevitable due to the fact that Ohio relied almost exclusively on coal power prior to the natural gas revolution.  


Ohio EPA Guidance On TENORM Oil & Gas Related Wastes

This past summer the Ohio General Assembly passed House Bill 59 which changed various aspects of the regulatory approach toward oil & gas waste material management.  One aspect dealt with under H.B. 59 was the regulation of oil & gas related waste that may be considered technologically enhanced naturally occurring radioactive material (TENORM).  H.B. 59 provided Ohio EPA the authority to adopt rules regarding the regulation of TENORM.

What is TENORM?

To understand TENORM, one must understand what constitutes NORM- naturally occurring radioactive materials.  NORM is radioactive materials naturally present in the environment (i.e. soils, air and water).  NORM emits low levels of naturally occurring radiation and is common to the environment.   

TENORM is naturally occurring radioactive material with radionuclide concentrations that are increased by or as a result of pat or present human activities.  TENORM is regulated by the Ohio Department of Health.   Oil & gas drilling can generate TENORM.

Which oil field wastes are NORM and which are TENORM?

Certain oil & gas related waste is classified as NORM and exempt from regulation.  As set forth in the Ohio EPA Fact Sheet on TENORM (see below), drill cuttings are considered NORM and not TENORM.  Drill cuttings are the mixture of rock, soil and other subterranean matter brought to the surface during drilling of oil & gas production wells.

Oil & gas drilling related waste classified as TENORM include tank bottoms, spent drilling muds and pipe scale.  Here is a description of each of those waste streams:

  • Tank Bottoms- material accumulated in storage tanks associated with the oil & gas drilling
  • Pipe Scale- the build-up of minerals, rocks, oil and other substances that accumulate on the inside of metal casing and tubing used for the production of oil and natural gas.
  • Drilling Mud-  fluid used to cool and lubricate the drill bit, helps stabilize the well bore during drilling and keeps fluids in the formation from entering the borehole

What do the new guidance documents from Ohio EPA require?

As of September 29, 2013, any landfill or solid waste transfer facility must receive sample results of any TENORM regulation waste to ensure that the material doesn't exceed the regulatory limit of 5 pCI/g above natural background.  The facilities receiving this material must maintain daily logs that identify the waste streams from oil & gas drilling and retain copies of the sampling.

A solid waste transfer facility or landfill that wants to accept TENORM with concentrations above 5 picocuries per gram must receive proper authorizations from ODH and Ohio EPA.  Facilities may receive the material if authorized for purposes of dilution.  However, material above 5 picocuries per gram cannot be disposed of in the landfill. 

Are rules likely to be adopted by Ohio EPA regarding TENORM?

Yes.  Ohio EPA has released a fact sheet soliciting early stakeholder outreach regarding the development of rules regarding TENORM at solid waste landfills and transfer facilities.  The rules would potentially govern:

  • Monitoring leachate and groundwater for radioactive material;
  • Establishing regulations to ensure that TENORM greater than 5 picocuries per gram above natural background is not accepted at the facility.  This include development of detection and prevention plans at landfills or solid waste transfer facilities.

What available guidance documents and fact sheets are available  from Ohio EPA on this issue?

  1. Fact Sheet: Drill Cuttings from Oil and Gas Exploration in the Marcellus and Utica Shale Regions of Ohio (October 2013)
  2. Fact Sheet:  House Bill 59- TENORM Acceptance at Solid Waste Landfills and Transfer Facilities;
  3. Guidance Document:  Impact of HB 59 on Solid Waste Landfills and Transfer Facilities
  4. Municipal Solid Waste Landfill- Daily Log of Operations (Draft)
  5. Solid Waste Transfer Facility- Daily Log of Operations (Draft)


Huge Increase in Disposal of Frac Water in Ohio Deep Wells

An article in the Akron Beacon Journal discusses a study by Kent State University regarding the disposal of flow back water from natural gas fracking in deep wells in Ohio.  Flow back water is the water that comes back up from fracking a natural gas well.  The flow back water is considered wastewater.

A prior post discussed the issues Pennsylvania was facing in handling disposal of flow back water.  As a result of increased regulations in Pennsylvania, the main method of disposal of flow back water had become shipment to Ohio for disposal in deep wells.  Ohio has 179 permitted deep wells.  Pennsylvania has five permitted deep wells. 

Here are some of the key statistics from the study as discussed in the ABJ article:

The volume of Marcellus wastewater has grown 570 percent from 2004 to 2011 due to increased shale gas production in Pennsylvania, Lutz said.

Pennsylvania has about 6,400 Marcellus shale wells that have been drilled and another 3,500 that have been permitted. In comparison, Ohio has about 500 wells permitted in the Utica shale, of which 200 have been drilled.

Lutz said Pennsylvania generated about 20 million barrels (each holding 42 gallons) of wastewater in 2011. About 7 million barrels were shipped to Ohio injection wells.

Ohio is projecting that its injection wells handled nearly 14 million barrels in 2012, up from 12.8 million barrels in 2011. (Final figures have not been compiled). More than half of that volume came from Pennsylvania and West Virginia.

While the increases are huge, what happens when Ohio has more wells?  Will there be a reliable method for disposal of the flow back water from the Pennsylvania and Ohio wells.

As mentioned in the article, Ohio has no means of banning the shipments from out of state.  Ohio tried to regulate shipments of out-of-state solid waste from the east coast.  A similar issue arose when eastern states stopped permitting new landfills and Ohio was the closest state with available capacity.  Ohio starting receiving shipments of solid waste by rail. 

Laws meant to regulate the shipments of out-of-state solid waste were struck down as unconstitutional.  Solid waste was determined by the courts to constitute "interstate commerce."  Under the U.S. Constitution, one state cannot treat unfairly interstate commerce.

Now a similar dynamic is playing out with flow back water from fracking.  The issue will only get worse when Ohio has more wells drilled and needs to find a home for more flowback water generated in-state.


U.S. EPA Releases New Air Emission Standards for Fracking

On April 17th, EPA issued new rules designed to reduce air emissions from oil & gas operations, including wells drilling using hydraulic fracturing ("fracking").  The new federal standards (New Source Performance Standards -NSPS) are seen as the first significant new federal regulation governing fracking. 

Some may wonder how gas wells generate air emissions.  When a horizontal gas well is drilled and fracking is used, large amounts of water and some chemicals are pumped down the well to break up rock in the shale formations in order to release the gas for recovery.  Prior to putting the well into production, the water and chemicals are removed.  This is referred to as "flowback water."

When flow back water is recovered it is accompanied by gases, including volatile organic compounds (VOCs) and methane, which in most cases, is simply vented to the atmosphere. 

Methane emissions from fracking has received significant attention recently due to the fact it is a potent greenhouse gas- 20 times more damaging than CO2 emissions.

EPA says that the oil & gas industry is the largest source of methane emissions in the U.S. making up approximately 40% of all methane emissions.  Controlling VOC and methane emissions is what prompted EPA to issue the new federal standards.

EPA Delay's More Expensive Controls to 2015

EPA seeks to reduce air emissions from fracking by requiring, initially destruction of the gas and then recovery through "green completion."  In a green completion, special equipment separates gas and liquid hydrocarbons from the flowback that comes from the well as it is being prepared for production. The gas and hydrocarbons can then be treated and used or sold.

EPA's draft rule would have mandated "green completion" as the best control technology.  However, industry voiced strong concern that the equipment wasn't widely available and requiring this technology too quickly could impact production.  In the final rule, EPA decided to delay the mandate for "green completion" until January 1, 2015.

Until 2015, producers must control emissions by using flares to burn off the VOCs and methane emissions. The flare must be able to eliminate 95% for the VOC emissions.

For more information:


President Issues Executive Order Creating Interagency Work Group on Fracking

On April 13th, President Obama issued an Executive Order creating a federal inter-agency task to coordinate efforts on oversight of horizontal well drilling and hydraulic fracturing for natural gas.  Method such as hydraulic fracturing (i.e. "fracking") have allowed access to massive new deposits of natural gas bring the price down for natural gas to historic lows.  While fracking has resulted in a huge increase in production, the drilling method continue to generate environmental concerns.

Thus far, the States have really taken the lead in development of new regulations and requirements for fracking.  In my last post I discussed Ohio's recent legislative proposal. Now, the federal government will attempt to coordinate its efforts regarding oversight and planning associated with unconventional natural gas drilling techniques such as fracking.  The Executive Order creates the inter-agency work group for the following purposes:

  1. Coordinate agency policy activities, ensuring their efficient and effective operation and facilitating cooperation among agencies, as appropriate;
  2. coordinate among agencies the sharing of scientific, environmental, and related technical and economic information;
  3. engage in long-term planning and ensure coordination among the appropriate Federal entities with respect to such issues as research, natural resource assessment, and the development of infrastructure; 
  4. promote interagency communication with stakeholders; and
  5. consult with other agencies and offices as appropriate.

The Work Group is made up of 13 federal agencies and departments, including: U.S. EPA, U.S. Dept. of Transportation, Dept. of Interior, Dept. of Energy, and others. 

It appears that industry supports the working group as a potential mechanism to avoid applicative regulation.  This from the Washington Post:

“We have called on the White House to rein in these uncoordinated activities to avoid unnecessary and overlapping federal regulatory efforts and are pleased to see forward progress,” said Jack Gerard, president and CEO of the American Petroleum Institute, the largest lobbying group for the oil and gas industry.

Gerard and other industry leaders met with White House officials Friday.

Dave McCurdy, president and CEO of the American Gas Association, said the new working group will help promote consistency among administration policies.

In it is interesting that the Washington Post and other news outlets reported the purpose of the working group as to "coordinate new regulation."  However, reading through the five stated purposes of the working group none of them even mention regulation. Rather, it appears as if the purpose of the group is to share information, not coordinate regulatory efforts.

In my experience working with such federal inter-agency workgroups associated with the Great Lakes, federal agencies were reluctant to give up their own turf.  Unless the Administration takes an active role in working group it seems very unlikely the agencies, on their own, will coordinate their regulatory efforts.. 



Governor Releases Bill to Regulate Shale Gas Drilling and Wastewater Disposal

Right now there is no other topic in Ohio that generates more news coverage than horizontal gas drilling (or "fracking").   It seems a day doesn't go by without a new news story regarding fracking or related developments.

Ohio has seen oil & gas wells installed for well over a hundred years.  However, until recently huge deposits of natural gas in shale formations deep beneath the ground were not accessible.  Now, using new technology (i.e. fracking) those deposits can be tapped.  The implications for Ohio are certainly significant.

Along with the tremendous opportunity that access to the Utica Shale deposits present, come concerns regarding protecting the environment, including ground water resources. Many have said that Ohio's out dated oil & gas laws need to catch up with today's technology.

Senate Bill 315

In order to address these concerns, on March 22nd Governor Kasich released Ohio Senate Bill 315 (S.B. 315).  While the bill is dubbed an energy bill and does touch on other subjects, its principal focus is new regulation of horizontal gas well drilling.

The bill also attempts to increase regulations on deep well injection as a means of disposal of massive amounts of fracking wastewater and/or brine.  In the aftermath of the controversy as to whether disposal of fracking wastewater led to earthquake(s) in Northeast Ohio, the bill adds to the growing list of new regulations governing this method of disposal.

Major New Requirements in S.B. 315 Governing Horizontal Wells or "Fracking"

  • Creates a new oil & gas permit to be issued by the Ohio Department of Natural Resources (ODNR) for "horizontal wells:"
  • The new horizontal well permit application will require new information that the old oil & gas permit applications never addressed, including:
    • A $15,000 permit fee;
    • Road Use Maintenance Agreements-  will require the applicant to provide a copy of an agreement with local government(s) concerning maintenance of roads, streets, and highways;
    • Source Water Identification- must identify the ground water or surface water source for the production of the well.  This is requirement applies to horizontal well permits because they use millions of gallons of water;
    • Residential Well Sampling-  must show the sample results of all water wells within 1,500 feet of the proposed well prior to commencement of drilling;
    • Insurance Coverage-  must obtain $5 million in coverage for injury to persons or property.  Also, must include a "reasonable level" of coverage for any pollution or contamination that may occur as a result of the drilling, operation, or plugging of the owner's wells. (See discussion below regarding insurance)
    • Disclosure of fluids used in wells- one area of controversy associated with fracking is the use of chemicals along with the water during the drilling and fracking process.  Under the bill, the owner of the well will have to disclose all chemicals used and the amount used during service, operation, and plugging of the well.  These compounds will be posted on ODNR's web page.
    • Fresh Water Impoundments-  ONDR is given rule making authority to regulate location and construction of fresh water impoundments used in fracking.

Major New Requirements Governing Deep Well Injection

  • S.B. 315 increases disposal fees and includes new regulations governing oil & gas injections wells, including:
    • Doubles the fee for each barrel of substance generated locally that is disposed through deep well injection;
    • Raises the fee by five times the amount (20 cents to $1 dollar) for out of state substances shipped in for disposal in Ohio deep wells.  This is likely to address the concern Pennsylvania is shipping its wastewater associated with fracking to Ohio for disposal;
    • Increases the information that must be submitted by a brine/wastewater transporter to be properly certified by the State; and
    • Owner of deep well must obtain list from transporter of brine or wastewater generated through fracking a list of all chemical compounds.

Key Issue under S.B. 315:  How Much Environmental Insurance will be Required?

The philosophy of the bill seems to be requiring data collection prior to commencing the fracking process.  What data is being collected?  The current levels of contamination, if any, in existing residential wells within 1,500 feet prior to horizontal drilling.  Followed by disclosure of all the chemicals compounds used in the fracking process.  

The hope is that the information  (i.e. baseline record) could be used to determine if fracking contaminated groundwater or drinking water supplies.  Simply compare the old well samples to new sample, post fracking, and see if any of the disclosed chemical compounds are detected.

Assume it is demonstrated that contamination did occur as a result of fracking.  The bill requires a "reasonable level" of insurance coverage be provided for environmental contamination.  The determination of "reasonable" will be key issue.

It is likely (and would make good business sense) if you were an oil & gas driller to use the corporate form to try and limit liability if something goes wrong.  This means it is quite possible the only funds that may be available to address contamination will be insurance proceeds.    Therefore, how much insurance coverage is required will be a key issue. 

Cheap Gas Fosters EPA Carbon Cap on Future Coal Plants

On March 28th, U.S. EPA released its highly controversial rulemaking which establishes a carbon dioxide (CO2) emission limit on new coal-fired power plants.  All future coal-fired power plants will have to utilize an unproven technology, carbon capture and sequestration (CCS), to meet the emission limits.  CCS involves capturing CO2 and injecting it deep beneath the earth's surface for permanent storage.

EPA's proposed rule would exempt from the CO2 emission limit new coal plants that begin construction in the next twelve (12) months.  Some analysts have commented that the fifteen coal-fired power plants currently slated for construction may be the last coal plants constructed in the United States.  This from Businessweek:

“This is the tail end of coal generation build-out,” said Teri Viswanath, the director of commodity markets strategy at BNP Paribas SA (BNP) in New York. “The ones we are getting today -- that is going to be the last hurrah for coal-fired generation.”

Certainly that statement would appear to be true unless some of the current plants slated to utilize CCS can demonstrate its a workable technology.  However, with the risk associated with CCS and the costs of new coal power plants, cheap natural gas does seem to be the fuel of choice for new electricity generation in the United States.

Basics of the EPA Rule

EPA's proposed Carbon Pollution Standard for New Power Plants would apply to all fossil-fuel-fired electric utility generating units (EGUs) that are larger than 25 megawatts.  These new EGUs would have to meet an output-based standard of 1,000 pounds of CO2 per megawatt-hour (lb CO2/MWh gross). 

Studies show that 95% of all newly constructed natural gas combined cycle power plant units meet the proposed standard without any add-on controls.  New coal plants without CCS currently generate around 1,800 lbs CO2/MWh gross.  Based on existing technology, the only way new coal plants could meet the 1,000 lbs standard would be through CCS.

Other key points:

  • Existing plants that begin construction in the next 12 months would be grandfathered (won't have to meet the standard);
  • Coal plants could be built without CCS if they add it later and the average CO2 emissions over a 30 year period equal the standard.; and
  • The rule does not cover existing coal-fired power plants

Cheap Natural Gas Behind EPA's Proposed Rule

In releasing the proposed rule, EPA provided a Regulatory Impact Analysis which projected that the rule would be very little negative effect on the cost of electricity or jobs due to low natural gas prices. The chart below shows EPA's analysis of future natural as prices even accounting for the increased use for electric generation.


EPA states in its analysis that market forces have already shifted toward construction of natural gas electricity generating units, in part, due to recent technology used to access deposits of natural gas in the Marcellus and Utica shale formations. 

Under current and foreseeable future market conditions affecting new capacity
additions, gas-fired generating technologies can produce electricity at a lower levelized cost than coal-fired generating technologies, and therefore utilities are expected to rely heavily on combustion turbines and combined cycle plants using natural gas when they do need to expand capacity during the time horizon considered for this analysis. Current and projected natural gas prices are considerably lower than the prices observed over the past decade, largely due to advances in hydraulic fracturing and horizontal drilling techniques that have opened up new shale gas resources and substantially increased the supply of economically recoverable natural gas.

Because the large shale deposits have kept natural gas prices low, EPA finds no real impact from its proposed rule mandating CCS on new coal plants.

One has to ask the question of what happens if the dynamics on natural gas turn out differently.  What if demand increases dramatically or anticipated capacity is much lower?  Will EPA reconsider its carbon standard on new coal plants? 

The rule presents somewhat of a risky proposition by relying on an unproven technology- CCS.  So long as cheap natural gas remains, utilities will have very little incentive to really invest in CCS.

Ohio EPA Issues "Faster Air Permit" for Shale Gas Sites

In anticipation of an influx of shale gas drilling operations coming to the State, Ohio EPA decided to try and get ahead of the curve by developing an expedited permit to cover air emissions from such operations.

On February 1st, Ohio EPA issued a final air pollution general permit to cover production operations at shale gas well sites. By issuing the general permit, Ohio EPA is providing a path for shale gas operators to received expedited regulatory approval necessary to cover air emissions.  Without the general permit, operators must obtain an individual air permit which can take longer and may be less certain as to terms and conditions for operations.

Applicants that meet the criteria, terms and conditions of the permit can expect to receive approval within weeks of applying.  An individual air permit can take six months to issue.  The process is expedited because all the terms and conditions of the permit are established up-front instead of after the application is filled.

The only issue with general permits is that they are one-size fits all templates.  Meaning, you must be sure that your specific operation can meet the terms and conditions cause they can't be changed or modified to meet your specific circumstances.  Company's that cannot live with the general permit terms & conditions can still apply for an individual air permit.

The Agency received many comments from both industry and environmental groups/concerned citizens on the draft permit released in October.  The Agency announced that it had modified the permit to address the following concerns:

  • restricts normal flare operation, increases total flare capacity and allows for emergency flaring to safely burn gas;
  • requires installation of newer spark ignition internal combustion engines if total horsepower is to exceed 1300;
  • removes a limit on the number of storage tanks and replaces it with a limit on the total volume of material stored in tanks;
  • increases allowable dehydrators from one to two; removes unpaved roadways as an emissions unit (it is covered under another existing general permit); and
  • removes the natural gas micro turbine emissions unit (it was determined to be exempt).

Ohio Could be at the Center of a Major Energy Transformation from Coal to Natural Gas

U.S. EPA finally issued its long awaited air pollution regulation aimed at reducing mercury emissions from coal-fired power plants- Mercury and Air Toxics Standards (MATS).  MATS sets specific numeric emission standards for mercury and other air toxics from coal-fire power plants  25 megawatts in size or larger.

MATS will apply to some 1,400 generating units across the country.  The rules carry with them a $9.6 billion dollar price tag.  Power produces have until 2015 to 2016 to comply with the new regulations.

The new regulation, along with a series of earlier federal regulations, have made coal power generation more expensive. Meanwhile, the rich deposits of natural gas in the Marcellus and Utica Shale have kept natural gas prices down. 

Ohio could be at the center of a major shift in power generation.   Right now Ohio's baseload power generation tilts heavily in favor of coal with 86% of its generation from coal and only 2% from natural gas.  However, the scales may be starting to go  in favor of natural gas.  MIT's recent study on natural gas showed its role will increase significantly the coming years in the energy sector. 

On June 8, 2011, AEP released its compliance plan which calls for retirement of coal plants and new natural gas capacity.  According to SourceWatch:

 AEP’s compliance plan would retire nearly 6,000 megawatts (MW) of coal-fueled power generation; upgrade or install new advanced emissions reduction equipment on another 10,100 MW; refuel 1,070 MW of coal generation as 932 MW of natural gas capacity; and build 1,220 MW of natural gas-fueled generation. The cost of AEP’s compliance plan could range from $6 billion to $8 billion in capital investment through the end of the decade

In 2011, many power producers announced they were closing Ohio coal-fire generating facilities.  These include:

  • AEP's Picway
  • AEP's Conesville
  • AEP's Muskingham River
  • Duke Beckjord
  • DP&L Hutchings

According to an Associated Press survey of 55 power producers, more than 32 mostly coal-fired power plants in a dozen states would close. The survey indicated no threat to the reliability of the nation’s power system.

Pennsylvania is about decade ahead of Ohio in its shift toward natural gas due to the fact the Marcellus shale formation is proven and the Utica shale is not.  Pennsylvania offers a glimpse into Ohio's future.

Chart shows Pennsylvania's ten fold increase in natural gas power generation.  In a decade, natural gas has gone from 2% of Pennsylvania's power generation to 17%. 

Meanwhile, coal power generation in Pennsylvania has seen a corresponding drop from 56% to 47% of overall generation in the State.   (Chart- Investment U "Pennsylvania leading the shift to natural gas)


Study Reveals Environmental Issues in Oil & Gas Leases

There was an excellent article in the New York Times discussing the issues homeowners and landowners are facing when signing oil & gas leases- Learning Too Late of the Perils in Oil & Gas Leases

The Times reviewed 111,000 oil & gas leases from Ohio, Pennsylvania, New York Texas and West Virginia.  It found many of the leases contained very unfavorable terms for landowners and homeowners who sign up with drilling companies.  Many of the issues pertain to the potential environmental problems that may happen once drilling commences or even after work is finished at the property.

Concerns identified included:

  • less than half the leases compensate for water contamination;
  • many lack language to protect against livestock and crop damage;
  • grant driller broad rights to build road, store chemicals and even leave waste in place once drilling has ceased.

Not discussed in the article are other issues that need to be considered by landowners when negotiating leases. 

First, even if the lease contains language which entitles the landowner to compensation if environmental contamination or other property damage occurs, does the company really have the resources to pay?  Its possible the corporate structure is established to prevent liability from flowing to the parent corporation.  

Second, what happens if you neighbors sue you claiming environmental contamination, nuisance or property damage?  Does the lease provide any guarantee that your attorney costs will be paid? 

Landowners are constantly hearing about the opportunities associated with the Marcellus and Utica shale deposits.  However, are they protecting themselves properly in the event something goes wrong?