Nearly six months after passage of the much touted Illinois Hydraulic Fracturing Regulation Act (225 ILCS 732/1-1 et seq.) (the Act), the Illinois Department of Natural Resources (IDNR) issued proposed regulations implementing the Act (the HFRA Regulations) and scheduled two public hearings to receive public input (one in Chicago on November 26, 2013 and the second in Ina (downstate Illinois) on December 3, 2013).  In addition, the IDNR will accept written comments to the HFRA Regulations until January 3, 2014 (the IDNR has created an online public comment forum).

The HFR Regulations are subject to the Illinois Administrative Procedure Act’s (IAPA’s) two-step process.  The first step is to obtain public comment no less than 45 days after issuance of notice of the proposed rule in the Illinois Register, and the second step is to finalize the regulations upon a maximum of 45 days’ written notice to the Illinois Joint Committee on Administrative Rules (JCAR).  Critics of the Act have complained that the two  public hearings (with none in central Illinois) and the January 3, 2014 deadline for comments are inadequate.  Under the IAPA, the IDNR has until November 15, 2014 to issue final HFRA Regulations.

Substantively, critics, including environmental groups who originally supported the Act, have questioned several aspects of the HFRA Regulations including: (1) the process that a health professional must take, even in an emergency, to obtain information about hydraulic fracturing chemicals furnished to the IDNR under a claim of trade secret (Section 245.730); (2) what they perceive as a relaxation of the time in which hydraulic fracturing treatment flowback may be temporarily stored in open pits (Section 245.850); and (3) what they perceive as inadequate potential monetary penalties for administrative violations (starting at $50) and operating violations (starting at $100) (Section 245.1120).

The environmental groups are not the only critics of the HFRA Regulations.  The Illinois Oil and Gas Association, which has cast the state as hostile to the oil and gas exploration and production industry, has blamed the Act’s “onerous” nature on driving more than one E&P firm to abandon Illinois in favor of Indiana, which shares the New Albany Shale formation with Illinois and Kentucky.

The IDNR also issued proposed seismicity regulations for Class II Underground Injection Control (UIC) disposal wells that are intended to receive flowback from a high volume horizontal hydraulic fracturing well.  In order to receive a permit under the Act, the operator must identify an existing Class II UIC disposal well that will receive the flowback from the production well.  The proposed regulations implement the Act’s “traffic-light” seismicity reporting and enforcement authority, and add new injection recordkeeping requirements for permittees.

Before applying for a permit under the Act, an applicant must first be registered with the IDNR for at least 30 days.  So far, no firm has registered.  IDNR officials recently predicted that it will be at least a year until hydraulic fracturing begins in Illinois.

by Nicole Castle

On July 24, 2013, Baker Hughes, Inc., the owner of the third-largest pressure pumping fleet in the United States, disclosed as part of its filing with the Securities and Exchange Commission that it had received a civil investigative demand (CID) from the Department of Justice (DOJ) on May 30, 2013.  The CID requests information and documents relating to U.S. pressure pumping services for the period from May 29, 2011, through May 30, 2013.  

Baker Hughes stated in its filing that it was “not able to predict what action, if any, might be taken in the future by the DOJ or other governmental authorities as a result of the investigation.”

Pressure pumping services generally refers to the process of pumping water and other materials into a well to break apart rock formations and increase the well’s oil or gas production.   Pressure pumping is the main step in the hydraulic fracturing process, and has in recent years become more heavily used for extracting oil and natural gas from rock formations.

The following day, on July 25, 2013, Halliburton Co., the largest provider of pressure pumping services in the United States., confirmed that it had also received a CID from the DOJ regarding pressure pumping services.  

by Daryl Kuo

As the world’s largest producer of natural gas, the United States has the potential to also become the world’s leading exporter of liquefied natural gas (LNG).  The Department of Energy (DOE), however, continues to proceed extremely cautiously with respect to authorizing LNG exports, particularly to countries that have not signed free trade agreements (FTA) with the United States.

To approve a project, the DOE must determine that it is not contrary to the public. While exports are presumed to be in the public interest, this presumption can be rebutted in comments filed by opponents to the proposed exports. The public interest test balances various factors, including (i) the impact of the liquefaction project on domestic natural gas demand, supplies, prices and resource base, (ii) the benefits of international trade, and (iii) the benefits to the domestic economy, national energy security and the global environment. The approval process is further impeded by the fact that the applications are processed in the order in which they are received, pursuant to an Order of Precedence issued by the DOE in December 2012. The DOE will not change this order absent a change in policy.

To date, the DOE has only approved two projects to export LNG to non-FTA-signatory countries.  In August 2012, the DOE authorized the Sabine Pass Liquefaction project, and in May 2013, the DOE conditionally approved the Freeport LNG Expansion project, which permits the export of 511 billion cubic feet of gas per year for a twenty year period.  The delay between both approvals stemmed from the DOE’s commissioning of two studies to assess the potential impact of LNG exports on domestic gas prices and the national economy.  Both studies yielded positive findings that encouraged LNG exports.

Although over twenty LNG export applications to non-FTA-signatory countries remain pending before the DOE, the Freeport approval may be indicative of the DOE’s shifting position regarding LNG exports to non-FTA countries.  The DOE’s review of the Freeport application focused on comparing Freeport’s arguments with the objections made by an opponent to the project, taking stock of concurrences by commentators and acknowledging the favorable study findings.  The DOE applied the rebuttable presumption standard strictly and held that the protestor’s evidence was insufficient to rebut the statutory presumption that LNG exports are consistent with public interest.  The DOE did not debate the validity of the arguments made by Freeport or the pro-export commentators; it did not question the significance and accuracy of the studies (in fact, it dedicated over 50 pages to justifying the studies’ methodologies and findings); and, most importantly, it did not lend much weight to the protestor’s objections.

Despite the pro-export tone of the Freeport approval, the DOE indicated that it would proceed cautiously in reviewing pending applications by assessing the cumulative impact of each application.   Energy Secretary Moniz has not commented on the timeline for reviewing pending applications, and some companies are threatening to go to court to speed up the approval process and strike down the Order of Precedence, which was issued after many companies had already applied.  While the Freeport approval is a victory for proponents of LNG exports, the path forward remains rife with uncertainty.

Jennifer Arnel, a summer associate in McDermott’s Houston office, contributed to this article.

by Thomas Hefty

On June 17, 2013, Illinois P.A. 98-0022 (the Act), consisting of the Hydraulic Fracturing Regulatory Act (HFRA) and the Illinois Hydraulic Fracturing Tax Act (HF Tax Act), became law. The Act, which was the result of months of negotiations among industry and some environmental groups, had been stalled since March 2013 after a last-minute amendment added a licensing regime that would have favored water-well drilling contractors. That impasse was resolved when the objectionable well-licensing regime was replaced by a local workforce credit against HF Tax Act liability. The Act is a defeat for those environmental and community groups that favored a moratorium on horizontal hydraulic fracturing in Illinois until the U.S. Environmental Protection Agency completed its ongoing study of horizontal hydraulic fracturing’s potential to affect groundwater resources. HFRA’s supporters tout it as the United States’ most comprehensive and rigorous horizontal hydraulic fracturing regulation, and claim it sets the “best practices standard” for environmental, health and safety regulation.

To read the full article, click here.

 by Charlotte Doerr

The United Kingdom has seen significant steps forward on the shale gas exploitation front.  In light of recent discoveries of substantial reserves in the north-west of England, the ongoing debate on hydraulic fracturing (fracking) has once again come to the fore.  With recent studies from the British Geological Survey estimating that the capacity of the yet-untapped reserves of shale gas could climb to 170 trillion cubic feet (tcf), this is a significant discovery for the United Kingdom and could have important ramifications for the country’s energy supply and policy for many years to come.  The sheer size of these reserves is put sharply into context when viewed alongside the remaining gas reserves in the UK North Sea, judged to be as little as 7 tcf.

The UK’s decision to lift a temporary moratorium on fracking in May 2013, which had been in place since the previous year after shale gas exploration resulted in two minor earthquakes, now paves the way for a flurry of preliminary activity.  Some commentators predict that full-scale exploration will get underway in 2015.

Comments from the UK Chancellor of the Exchequer, George Osborne, that the government would “make the tax and planning changes which will put Britain at the forefront of exploiting shale gas,” suggest that fracking in this sector could become more widespread, as the government relaxes restrictions over the practice.  Supporters have pointed to increased job creation, substantial tax revenues, and reduced reliance on imported energy.  However, critics have been quick to highlight the environmental concerns linked to fracking, such as water contamination and seismic risk.

Everything must be read in light of a governmental Energy and Climate Change Committee inquiry that concluded in April 2013 that any firm determination on the end-result for consumer energy prices based on these gas discoveries is still premature.  Therefore, much work remains to be done and substantial political wrangling will likely follow, before a clear path appears for the UK’s future direction on revitalizing its domestic gas industry.

by Thomas L. Hefty

The Illinois General Assembly could be on the verge of enacting legislation, the Hydraulic Fracturing Regulatory Act (H.B 2615), that some environmental groups are touting as an environmental best practices for regulating the shale oil and gas recovery method known as horizontal hydraulic fracturing (fracing). H.B. 2615, the result of months of negotiations between environmental groups and the oil and gas exploration and production (E&P) industry, was set to be voted on in the Illinois General Assembly in late March, but a last second amendment (favoring in-state licensed drilling companies) has stalled the bill’s progress. 

While HB 2615 is laudable for setting robust regulations on horizontal fracing operations, what should make it the betting favorite is that it is also a revenue bill – the second half of H.B. 2615 contains the Illinois Hydraulic Fracturing Tax Act. Under H.B. 2615, Illinois would finally join the majority of drilling states that tax severed oil and gas. Each Illinois well using horizontal hydraulic fracturing could produce several million dollars in severance taxes during the span of the well’s productive life.

Illinois is one of the few drilling states not to impose any severance or gross production taxes on its substantial oil and gas production. Illinois currently has about 32,000 wells producing between 10 and 11 million bbls of oil (15th nationally) and 2,120 million cubic feet of natural gas, ranking it 26th. That production would increase significantly if large-scale horizontal hydraulic fracturing were introduced in Illinois to the New Albany Shale formation. Technically recoverable shale gas in the New Albany Shale is estimated at up to 11 trillion cubic feet (for comparison, the Marcellus Shale in the East has 84 TCF). A majority of the drilling states, including Indiana and Kentucky, tax oil and gas production. Several others, most prominently Pennsylvania, are currently considering adopting oil and gas severance taxes.

Competing with H.B. 2615 are three other bills: two bills favored by those environmental groups not supporting H.B. 2615 that would put a two-year moratorium on any hydraulic fracturing and an E&P industry-sponsored bill that environmental and community groups strenuously oppose. One would think that with the support of the E&P industry and some environmental groups (including the Natural Resources Defense Council), plus the revenue enhancement features of the severance tax, H.B. 2615 should be a done deal. But given the current state of Illinois politics, taxes might not be the certainty that Ben Franklin once thought they were. 

The shale gas sector in the United Kingdom is still in its infancy, but the UK Government has announced recently new measures and incentives to encourage its growth.  On 13 December 2012, the Government lifted a temporary suspension of drilling at the only drilling site in the United Kingdom, introduced tighter regulations to manage risk associated with hydraulic fracturing (fracing), set out new tax incentives to help accelerate the growth of the industry, and announced that it would establish a new Government office dedicated to the shale gas sector.
Fracing involves the pumping of water, sand and chemicals into shale rock at high pressure, for the purpose of extracting reserves of natural gas.  Many European countries have been wary of fracing and the practice is currently banned in several countries, including France.  The French Government banned fracing in May 2011 in response to pressure from environmental groups.  Reports have suggested that exploration permits were revoked from three companies that had announced they were intending to undertake fracing activities, and seven applications for permits were rejected.  It should be noted that by the French Government has not banned the exploration of shale gas, just the practice of fracing. 
Apart from the United Kingdom, the only other European country that has allowed energy companies to undertake exploratory drilling is Poland.  Poland is said to have the largest reserves of shale gas in the European Union.  As of June 2012, it had granted over 100 licences to foreign companies wishing to undertake exploratory drilling activities in the country.  
The exploitation of onshore gas reserves has already revolutionised the energy sector in the United States, and the UK Government now hopes that Britain will be able to service some of its future gas demand through the use shale gas obtained by fracing.  Europe, as the world’s second-largest gas market, has become increasingly dependent on imported gas, which not only is expensive, but also carries with it all the risks generally associated with an imported product, including the potential for a sudden termination of supply. 
Reports on Shale Gas
The UK Government has commissioned several reports on shale gas in order to assess the potential risks of fracing.  These include, inter alia
In addition to these reports, the British Geological Survey (the BGS) conducts ongoing research into shale gas.  The BGS estimated in 2010 that if shale in the United Kingdom was as productive as shale in the United States, an estimated 150 billion cubic metres of gas could be produced.  The BGS also notes, however, that as little as 10 to 20 per cent of the full UK reserve of shale gas may in fact be recoverable.  Little exploratory drilling has so far taken place in the United Kingdom and there has been no commercial production of shale gas.
The sites with the best prospects of producing large quantities of shale gas are likely to be close to the formations that yield conventional oil and gas reserves.  In the United Kingdom these include the Upper Bowland Shale, which is currently being explored by Australian shale gas company Cuadrilla Resources, and areas near North Sea exploration sites and the English Channel Fields. Cuadrilla has estimated that there could be 5.6 trillion cubic metres of shale reserves beneath the surface of the United Kingdom, although the BGS estimates that this figure is nearer to 4.2 trillion cubic metres.  
Fracing Suspension Lifted
On 13 December 2012, Ed Davey, the UK Secretary of State for Energy and Climate Change, gave his approval to Cuadrilla to resume fracing in Lancashire in the north of England.  Exploratory drilling at the site in Lancashire started in August 2010 but was halted in May 2011 when evidence emerged that fracing may have been triggering seismic activities. 
The Government subsequently commissioned the April and June reports, which served as the basis for Mr Davey’s decision to allow fracing to resume.  Cuadrilla’s operations are currently the only fracing activities that are currently being undertaken in the United Kingdom.  The DECC, the Government department responsible for applications in relation to shale gas operations, did, however, start accepting new applications for exploratory drilling on 13 December 2012. 
Mr Davey’s support for the resumption of fracing was met with a mixed response.  Although many in the energy sector see fracing as the way forward, and an opportunity to tap into an, as yet, underexplored resource, environmentalists have suggested that increased fracing may create a “dash for gas” that will prevent the United Kingdom from meeting its climate change targets, owing to the increased carbon dioxide emissions.  A study has, consequently, been commissioned by Mr Davey to ascertain the possible impact of shale gas developments on greenhouse gas emissions and climate change. 
Proposed Regulatory Regime
Shale gas drilling is covered by the UK regime for all oil and gas exploration and development activities.  In his statement, Mr Davey announced that all new fracing operations will also be subject to new controls to mitigate risks associated with fracing.  These include, inter alia, a more thorough assessment for seismic risk and the installation of a “traffic light system,” under which operations will be stopped automatically under certain conditions.  The threshold for tremors in fracing activities is lower than for industries such as coal mining or construction. 
The controls are, at this stage, yet to be defined, but will be reviewed, as experience develops, to ensure they are proportionate to the risks. 
Measures to Encourage Fracing
The UK Government intends for shale gas to become a major part of the United Kingdom’s gas supply in the long term.  In order to encourage the development of shale gas reserves, the DECC will set up an Office for Unconventional Gas and Oil (the OUGO) and the UK Government will consult on appropriate tax regimes for fracing activities.
The OUGO, together with other UK Government departments, will provide a single point of contact for investors and will ensure a simplified and streamlined regulatory process.  It will be led by the DECC and is intended to help encourage investment in the shale gas sector.
The UK Chancellor of the Exchequer, George Osborne, announced on 5 December 2012, in the Government’s Gas Strategy, that the Coalition Government will launch a consultation on tax incentives for the emerging shale gas industry.  The Chancellor said that the industry would be excluded from the existing North Sea fiscal regime, where tax rates are between 62 and 81 per cent.
European Regulation
The European Parliament rejected a ban on shale gas on 21 November 2012, but asked the European Commission to consider new laws to regulate the sector. 
The Parliament’s decision to regulate the shale gas sector is based on three new studies on shale gas, published by the Commission on 7 September 2012.  The studies look at the potential effects of shale gas on energy markets, the potential climate impact of shale gas production and the potential risks shale gas developments may present to the environment.  There have already been calls, however, to avoid having a single regulatory regime covering the whole of the European Union, given each country’s particular sensibilities to the practice.
The Commission launched a consultation on shale gas and other unconventional fossil fuels on 20 December 2012, inviting comments on the risks and benefits associated with fracing.  The consultation will help the Commission determine whether the existing regulatory framework can manage associated risks effectively, or whether additional regulatory safeguards should be put in place.  The consultation will close on 23 March 2013.
Differences for Operators Between The United States and The United Kingdom
The shale gas industry might not become as profitable in the United Kingdom as it is in the United States.  One of the factors causing concern is excessive use of water in fracing, given that water resources in many parts of the United Kingdom are already under pressure. 
In addition, shale gas reserves are more diffuse than conventional gas sites and productivity at each well falls relatively quickly.  The United Kingdom is populated far more densely than the United States,  which means it will be harder to continually find new drilling sites.
Furthermore, in the United States landowners own the mineral rights beneath their homes, whereas in the United Kingdom the mineral rights are owned by the Crown.  This means there is not the same economic driver to encourage exploratory activities. 
The UK Government expects new estimates for Britain’s shale reserves, which are to be published by the BGS within weeks, to be revised upwards.  If exploratory drilling proves positive, shale gas production might commence in earnest in 2015.  It is clear that the Government is taking the steps required to encourage the expansion of fracing activities, and introducing measures to make it more financially viable. 


by Bethany K. Hatef

The U.S. Department of Energy (DOE) engaged the controversy over exporting liquefied natural gas (LNG) with its December 5 publication of Macroeconomic Impacts of LNG Exports from the United States. Prepared for DOE by NERA Economic Consulting, the report concludes the domestic economy will benefit from LNG exports and thereby paves the way for approval of LNG export applications pending DOE approval. But, given the lead times for building export terminals and that only four of the 15 pending applications are expected to be approved in 2013, significant exports are unlikely in the near term. To be considered, initial public comments on the report must be submitted to the Department by January 24, 2013, reply comments by February 25, 2013.

The report evaluated economic impacts “under a wide range of different assumptions about levels of exports, global market conditions, and the cost of producing natural gas in the U.S.” NERA modeled impacts using its Global Natural Gas Model and its general equilibrium model of the domestic economy. NERA considered the 16 economic scenarios addressed in DOE’s first study, issued in January 2012, as well as 47 global scenarios NERA developed.

The report concludes that in all 63 scenarios evaluated, increased LNG exports produced net domestic economic benefits. Even scenarios of unlimited export of LNG consistently produced higher net economic benefits than scenarios involving limited LNG exports. The report projects some negative effects of increased LNG exports on the U.S. economy, noting that large amounts of exports would slightly raise natural gas prices (e.g., with significant increases in LNG exports, prices could jump by more than $1 per thousand cubic feet over five years, an increase of more than 25 percent) and negatively affect utilities and “energy-intensive” manufacturers (i.e., manufacturers with energy expenditures exceeding 5 percent of output and significant exposure to foreign competition).

Rising domestic natural gas prices would have a ceiling, the report observes, since “importers will not purchase U.S. exports if U.S. wellhead price rises above the cost of competing supplies.” Energy-intensive industries are not projected to lose employment or output exceeding one percent per year. Additionally, the report projects that LNG exports will positively affect some segments of the domestic economy and improve consumer welfare, outcomes that, the report concludes, outweigh the losses associated with increased natural gas prices. The report estimates that LNG exports could produce between $10 and $30 billion in annual export revenues.

The report is certain to fuel already hot contention over whether DOE should authorize LNG exports. Dow Chemical has already decried the report’s conclusions, warning that increased domestic natural gas prices would impede energy-intensive manufacturers’ ability to keep up with their foreign counterparts. As mentioned in last month’s update, Senator Ron Wyden (D-OR) and Congressman Edward Markey (D-MA) are also critics of increased LNG exports, noting that a rise in LNG exports would essentially constitute a transfer of wealth from consumers to oil and gas companies. Environmental groups, who oppose the practice of hydraulic fracturing, which has contributed to the current abundance of natural gas in the U.S., oppose LNG exports as well. On the other side, Senator Lisa Murkowski (R-AK) and Representative Cory Gardner (R-CO) have expressed support for increased LNG exports. Unsurprisingly, natural gas producers, oil companies and Asian LNG importers are also supportive of NERA’s report, noting the opportunities increased LNG exports present for domestic economic growth and reduced natural gas costs.

by James A. Pardo and Brandon H. Barnes

Shale natural gas production emits significantly less fugitive methane than previously thought, concluded researchers at the Massachusetts Institute of Technology (MIT) in a November 26, 2012, study published in Environmental Research Letters.  According to the researchers, "it is incorrect to suggest that shale gas-related hydraulic fracturing has substantially altered the overall [greenhouse gas] intensity of natural gas production." 

 Methane has been singled out as one of the most powerful greenhouse gases (GHG) because of its "global warming potential" – or the relative heat trapped in the atmosphere by a gas – which is 20 times greater than that of carbon dioxide.  Fugitive methane emissions are losses of methane gas that may occur during flowback (the return of fluids), during drill-out following fracturing, and during well-venting to alleviate well-head pressure.  Fugitive emissions can also occur as a result of equipment leaks, transportation or storage losses, and processing losses, but in much smaller quantities. 

An earlier study by Cornell University professor Robert Howarth, which garnered much media attention, reported that shale gas production had a lifetime carbon footprint greater than coal production, mainly as a result of fugitive methane emissions that Howarth had estimated to be as great as 4,638 Mg per well.  In contrast, the MIT study determined that actual fugitive methane emissions average approximately 50 Mg per well after taking into account flaring and green completions technology, both of which are widely used by industry and required under most state regulatory regimes (as well as under new Environmental Protection Agency rules).  The MIT researchers evaluated actual production data from approximately 4,000 horizontal shale natural gas wells, and found a potential for about 228 Mg of fugitive methane emissions per well.  The researchers cautioned that estimates about fugitive methane emissions had been "inappropriately used in analyses of the GHG impact of shale gas" insofar as actual emissions are reduced — by an average of 178 Mg per well — by flaring and green completion technology.        

Hydraulic fracturing stakeholders need to understand the body of publicly available science, as a growing body of research will inform how EPA and other state and federal regulatory agencies will regulate the industry.

by James A. Pardo and Brandon H. Barnes

Speaking about upcoming Bureau of Land Management/Department of Interior (DOI) rules for hydraulic fracturing (fracing) on federal land, DOI Secretary Salazar recently opined that state regulation of fracing was insufficient and suggested that more stringent federal regulations may be required.  This is a sea change for Salazar, who previously made clear his endorsement of state fracing regulation.  While it is possible that Salazar’s comments were meant only to defend the Obama Administration’s issuance of rules for fracing on federal land, that is not the way the comments have been interpreted.  Salazar’s criticism of state fracing efforts as being "not good enough for" him was unambiguous.  The DOI Secretary’s comments came on the same day that DOI extended the period for public comment on the DOI rules by 60 days to September 10, 2012.

The issue of state versus federal fracing regulation has been debated since the process first began garnering significant media attention in the late-2000s.  With some exceptions, the U.S. Environmental Protection Agency (EPA) and other federal agencies cannot regulate the fracing process themselves unless and until Congress reverses its 2005 exemption of fracing from the Underground Injection Control rules of the Safe Drinking Water Act.  Predictably, Salazar’s comments have been seized on by many national non-governmental organizations (NGOs) that have long advocated for federal control over what has always been a state regulated process.  His comments reinvigorate a debate that state regulation advocates appeared to have largely won last year, when Salazar and several members of President Obama’s Department of Energy Task Force on Fracturing openly and clearly expressed their support for state regulatory efforts.  Fracing stakeholders need to be keeping a close eye on the federal-versus-state regulatory debate, as it is certain to gain increased media coverage and political attention in this election year.