For the past three decades, the National Labor Relations Board has enforced a certain definition of “joint employer” when it came to determining obligations under the National Labor Relations Act (the Act). This definition resulted in finding an employment relationship between an entity and workers whom it does not directly employ if the entity shared or co-determined matters governing the workers’ essential terms and conditions of employment and if the entity exercised direct and immediate control over those terms and conditions. In other words, even if the entity had the power to make such decisions, it would not be considered a joint employer unless it actually exercised that power. A recent NLRB case has done away with the requirement that an entity actually exercise its power over the workers before a joint employer status can be found. In Browning-Ferris Industries of California, 362 NLRB No. 186 (Aug. 27, 2015), Browning-Ferris Industries (BFI), the “user company,” operated a recycling facility and contracted with Leadpoint Business Services, the “supplier company,” to staff that facility. The company’s contract provided that Leadpoint was the sole employer of its personnel and also specifically provided that there was no employment relationship between BFI and Leadpoint’s personnel. After the performance of the contract ensued, a union requested to represent some of Leadpoint’s employees, and in its petition, the union claimed that BFI was a joint employer. A union election was held, and initially, a NLRB regional director found that BFI was not a joint employer. The NLRB, in August 2015, reversed the regional director’s finding. In Browning-Ferris, the NLRB claimed that its finding was necessary given the “diversity of workplace arrangements in today’s economy,” and quoted the United States Supreme Court from another context, stating that the NLRB has a “responsibility to adapt the Act to the changing patterns of industrial life.” To the NRLB, that meant drastically changing the joint employer definition. While the previous standard found no joint employment relationship where the user company exerted no direct control over supplier company’s terms and conditions of employment, the NLRB now finds such a relationship when the user company “reserves a contractual right to set a specific term or condition of employment for a supplier employer’s works,” because that company “retains the ultimate authority to ensure that the term in question is administered in accordance with its preferences.” Even if a user company contracts with a staffing agency and reserves the right to terminate the agency’s employees, yet never actually exercises that right or acts in any way to affect the agency’s employees’ terms and conditions of employment, the user company can still be a joint employer when it comes to collective bargaining and unfair labor practices. So, what does Browning-Ferris mean for employers? While Browning-Ferris deals with a staffing agency situation, this decision will affect other types of businesses as well. Depending upon a user company’s or franchise owner’s relationship with related entities, this decision creates a big change in who is considered an employer during collective bargaining and unfair labor practice charges. Even if a user company has little to no oversight or involvement in the supplier company, it could still be on the hook for any charges brought against the supplier. In March, the NLRB indicated its intention to consider franchise owners a joint employer, if possible, after it decided McDonald’s is a joint employer with its franchisees while adjudicating multiple unfair labor practice charges. Browning-Ferris reinforces that March decision. In its decision, the NLRB stated that a primary purposes of the Act is to “promote the peaceful settlement of industrial disputes,” however many critics of Browning-Ferris argue the decision will do exactly the opposite. Now, in addition to the often lengthy processes of collective bargaining and litigating unfair labor practice charges, the parties will have to fight about who exactly is considered an “employer” before a dispute can be resolved. And as this decision is still new, conflicts may arise when determining the necessary parties to the negotiation and approval of a collective bargaining agreement. This can take the form of costly and lengthy litigation to find every possible “employer.” Browning-Ferris will likely also lead to increased liability for companies that have little to no practical control over how a subcontractor or franchisee is conducting itself in terms of labor practices and breaches of collective bargaining agreements. The dissenting NLRB members argue that Browning-Ferris will have the exact opposite of its stated intent of peaceful settlement of disputes; it will likely lead to more conflict, more uncertainty, and more litigation. They warned that the decision “will subject countless entities to unprecedented new joint-bargaining obligations that most do not even know they have … and to economic protest activity, including what have heretofore been unlawful secondary strikes, boycotts, and picketing.” Browning-Ferris makes the staffing agency model much more risky, and it could lead to companies cutting ties with staffing agencies or subcontractors in favor of hiring employees directly. By doing so, an employer has much more control over its potential liability, but places the viability of staffing agencies, subcontractors, and franchise arrangements at risk. There are questions about just how far this new definition of joint employment will go. For example, will federal courts adopt this new definition and extend liability for unpaid wages and violations of Title VII, the ADA, etc., to every possible employer under the NLRB’s standard? If so, employers with franchisees or subcontractors will face a future full of litigation for events over which they had no realistic control. There is the chance that Browning-Ferris will be appealed, but as of yet, no appeal has been filed. Until then, employers will have to be prepared for the possibility that they are on the hook for their subcontractor’s actions. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

As we reported in the August column (The Daily Record, Aug. 3, 2015), the U.S. Environmental Protection Agency issued a rule that sets the first limits on carbon emissions from power plants in the country. Although issued with celebration by the Obama Administration and certain environmental groups, the Clean Power Plan rule issued pursuant to the Clean Air Act has caused significant opposition from the states, power industry and business. However, with the Paris Climate Summit just completed, EPA and the Administration are intent on moving forward with regulations and executive action. As an overview, the rule seeks to achieve a 32 percent reduction in emissions from 2005 levels by 2030. The goal is to reduce carbon dioxide in the power industry which would be accomplished by reducing coal’s share of the electric production pie. Currently it provides 39 percent of the country’s power. However, EPA predicts that it will supply 27 percent based on the rule and market forces, including competition from natural gas. The rule sets up state-specific emission limits based on the greenhouse-gas emission levels in the state’s electricity portfolio. The rule provides that each state will have interim targets that must be met beginning in 2020. States will have one year to develop and submit their individual compliance plans, a regional plan in conjunction with other states, or to seek extensions. Following the submissions, EPA will have one year to approve or reject the plan. EPA is also developing a federal model that states may use or which EPA may impose if a state fails to comply. EPA has referenced cap and trade schemes as a way for states to comply. EPA has set the renewable share at 28 percent of the electric generation. EPA has reduced the share of coal production to 27 percent by 2030. Nuclear power plants do not produce greenhouse gases and account for about 20 percent of the current power portfolio. However, nuclear energy will not count towards the state’s goals unless the plants expand. Several nuclear reactors are set to close, which will require the affected states to keep these sources in place or overcome the loss of clean energy with other sources. The rule is already subject to serious legal challenge from parties across the spectrum — the coal industry, power providers, business groups and states. There are significant questions whether EPA has the constitutional authority and statutory basis under the Clean Air Act to issue the rule. Initially, EPA has gone from regulating single emission sources (i.e., plants and smokestacks) to a sweeping re-design of the US energy system. The plan also appears to trample on principles of federalism under existing Clean Air Act programs because generally EPA sets emission limits and allows states to meet them, but the rule instead commands states to meet a national model. Another concern is whether EPA has double-regulated existing power plants, which is prohibited under the Clean Air Act. West Virginia and 25 states filed suit challenging the Clean Power Plan. In other cases the US Chamber of Commerce and more than a dozen industry groups are the plaintiffs. Several of the states and industry groups have requested the D.C. Circuit to stay the implementation of the rule pending the litigation being resolved due to the significant and immediate costs that are imposed on states and utility companies. In sharp contrast, 18 states, including New York and California, have sought to intervene in the cases in support of the EPA’s rule. In other climate related litigation under the Clean Air Act, 24 states have brought suit against the EPA’s new source performance standards for carbon dioxide emission from new power plants. Conversely, 16 states have filed to intervene in this set of cases on behalf of EPA. While the EPA’s new regulations have pitted the states against each other, it has also sparked different approaches within individual states, with some governors and attorneys general being at odds over legal positions. At the Congressional level, the House and Senate have taken steps to challenge the Clean Power Plan. On December 1, the House adopted a Senate resolution against the Clean Power Plan by a 242- 188 vote. Similarly, on the same date the House passed a resolution against the EPA’s power plant rule. Clearly Congress is upset with the Obama Administration’s attempt to circumvent the legislative process and act unilaterally on climate change issues after failing to succeed on a cap and trade bill in the early years of the Administration. Congress is also planning to hold hearings on climate change matters in 2016. Despite significant opposition from Congress, the Obama Administration participated in and trumpeted the Paris Climate Conference. The Administration is touting a non-binding agreement from the countries in attendance to hold the global temperature rise well below 2 degrees Celsius (3.6 degrees Fahrenheit) and aim for 1.5 degree Celsius. Despite the lack of binding provisions or penalties for non-compliance, the agreement is said to be productive because it will provide pressure on countries to comply. Although the agreement specifically avoided binding provisions and will not be submitted to Congress for approval as a treaty, nor would it have obtained two-thirds Senate approval, the Obama Administration is intent on pressing forward with executive action and regulations. The Clean Power Plan and the Obama Administration’s climate agenda will dramatically affect energy, industry and the public in a variety of ways if fully implemented. Adoption of sweeping regulation by EPA rather than by elected members of Congress, accountable at election-time to the votes, is cause for concern. The outcome of legal challenges and budgetary limits will be critical in addressing executive and regulatory actions in this area. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

The New York State Environmental Quality Review Act (SEQR) was adopted in 1976 and requires that state and local agencies evaluate potential environmental impacts of projects prior to granting approval. Since enactment, it has served as the principal environmental planning tool for New York agencies and municipalities prior to decisions to fund, undertake or approve projects across the state. This article addresses some fundamental changes that have been made to the short and long Environmental Assessment Forms (EAF). The Department of Environmental Conservation (DEC) issued proposed regulatory changes consisting of revised draft forms for public comment in 2011. The full EAF (or long form) used for large projects has not been significantly revised since 1978. The short EAF used for smaller projects was last subject to substantial revisions in 1987. In January 2012, DEC adopted revised model EAF forms to be published as part of the SEQR regulations at 6 NYCRR Part 617.20, Appendices A and B. The revised forms will include consideration of emerging environmental issues such as climate change, energy conservation, environmental justice, smart growth and pollution prevention. The DEC’s changes also seek to incorporate refinements in the process gained from experience over the years. Although the effective date of the new EAF forms was initially slated to be Oct. 1, 2012, it has now been re-scheduled for Oct. 7, 2013. The DEC is working on developing detailed workbooks to correspond with the new forms in an effort to aid project applicants and agencies in preparing and reviewing the SEQR documents. As an overview, when a project applicant submits a land-use application for a new project it is generally accompanied by an EAF to provide information to the agency regarding the proposed action, site location and environmental resources. The agency must first determine whether the proposed action is subject to SEQR, using basic regulatory criteria: is the project included in the list of Type 1 actions (SEQR review required), unlisted, or listed as a Type 2 action (SEQR exempt); is there a potential for significant impact on the environment; and will the planning and design of the project benefit from SEQR review. In determining the significance of potential environmental impacts from a project, the SEQR regulations require agencies to identify and assess relevant areas of environmental concern in order to address impacts that are reasonably foreseeable. The reasonableness standard is key, since potential impacts which are not reasonably foreseeable and are speculative do not have to be addressed. The EAF forms are central to this process. The short form EAF is used for unlisted actions. The long form EAF is used for Type 1 actions, or larger projects that may require preparation of an environmental impact statement. The EAFs consist of the following: Part 1 — prepared by the project sponsor regarding background information on the proposed action; Part 2 — completed by the lead agency, serves to identify potentially significant adverse environmental impacts; and Part 3 — completed by the lead agency to support the agency’s determination of significance. In the event that the agency determines that there will be no significant impacts on the environment (negative declaration), the agency completes the record for reaching that determination and environmental review of the action is concluded. In the event that a positive declaration is issued by the agency, an environmental impact statement must be prepared to further evaluate potential environmental impacts of a project. The current version of the short form EAF consists of two pages and has three parts: Part 1 — Project and Sponsor Information; Part 2 — Impact Assessment; and Part 3 — Determination of Significance. The DEC’s revised form is four pages with expanded details in each section. Aside from format changes, there are a number of substantive changes which make the short form EAF significantly more detailed. A few of the key changes to Part 1 include additional questions regarding: public transportation and pedestrian accommodations near the site; whether the action maximizes use of energy efficient design or on-site renewable energy technology; whether the proposed action will connect to existing public water and sewer utilities; whether the proposal will create new point source storm water discharges; whether the proposed action includes construction of on-site impoundments such as retention ponds, waste lagoons, etc.; and whether solid or hazardous waste has ever been stored on-site or on adjacent property. DEC has added similar questions to the Part 2 Impact Assessment that is prepared by the lead agency for the project. Finally, Part 3 of the new short form EAF will require the lead agency to discuss why each potential impact checked as a “yes” in Part 2 will not result in a significant adverse environmental impact. The new form will require the agency to discuss in detail the impacts, mitigation measures included by the applicant, and an explanation of how the lead agency determined that the impact will not be significant. The revised Part 3 appears to place a much greater burden on the lead agency to discuss and explain each element of Part 2, which forms the basis for its decision. The DEC’s revisions to the long form EAF are substantially more detailed than the changes to the short form. The current version is 21 pages; the DEC’s revised EAF is 35 pages and is significantly more detailed than the current version. The DEC has added similar questions to Part 1 regarding climate change, renewable energy and impacts on existing infrastructure. In addition, DEC has added much more detailed sub-parts on each page regarding existing questions on potential environmental impacts. As an example, the revised form requests information about whether the project will create a new demand for water, anticipated daily use, capacity of the public system, and need for expansion of the system or district. The revised Part 2, which is prepared by the lead agency, is now exceptionally detailed with new questions and sub-parts to existing questions to conform with the expanded Part 1. The updates to SEQR forms are certainly appropriate given the length of time since the last revisions. However, in reviewing the revised EAF forms there are a variety of questions and concerns that are raised. Although the SEQR process has been around for decades, many smaller municipalities and project sponsors still struggle with it under the existing framework. The revised forms require so much detail that it appears to shift the preparation process away from the project sponsor and agency to an engineering function. While the DEC intends to issue the workbooks to correspond with the new form, it remains uncertain whether these will substantially aid applicants or reviewing agencies. The amount of detail which will be required at the initial stage of project review will be significant, and hence the EAF will be much more expensive and time-consuming to prepare. In addition, new questions regarding climate change, energy conservation and similar issues, while part of public discussion, are rather amorphous and difficult for applicants and municipalities to quantify. Unfortunately, the nature of many of the new questions may subject the SEQR process to further litigation brought by applicants and project opponents to a proposed action. Finally, the revised EAF forms appear to raise regulatory hurdles in a state that already faces problems attracting and retaining new business investment. Once the revised SEQR EAF forms because effective on Oct. 7, they will inevitably require substantially more time, review and expense for project sponsors and agencies. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

The development of the natural gas resources in the Marcellus Shale formation across the southern tier of New York and Pennsylvania has taken off within the last few years. While leasing and exploration in New York has continued, well permitting and development has been on hold subject to an executive moratorium while New York state’s Department of Environmental Conservation (DEC) conducted a Supplemental Generic Environmental Statement (SGEIS) under the State Environmental Quality Review Act. The DEC finally issued the draft SGEIS on July 1. The Marcellus Shale formation is a black shale formation deep underground in the southern tier and extending down through Pennsylvania, Ohio and West Virginia. The Marcellus is estimated to hold between 168 and 516 trillion cubic feet of natural gas. By comparison, New York residents use about 1.1 trillion cubic feet per year. However, due to the depth and nature of the formation, horizontal drilling and hydraulic-fracturing techniques are required to access the gas trapped in the shale. Basically, hydraulic fracturing or “fracking” involves the placement of a well within the gas-bearing zone, pumping a pressurized fluid of water and chemicals into the rock, causing a fracture and fission, withdrawing the fluid and allowing the proppant (sand or beads) to remain to prop open the shale fractures so that the natural gas can be extracted. Some estimates suggest that the impact could be as many as 30,000 new jobs and $1.4 billion in annual economic impact. A recent Penn State study of shale gas development in that state has identified the “Marcellus multiplier,” in that for every $1 that gas producers spend, there is $1.90 in total economic impact. Although fracking is far from a new technique, the explosive growth of Marcellus Shale gas development has caused federal and state agencies to take a cautious approach. Critics of gas development have cited potential environmental issues such as air pollution, land-use development, water pollution and traffic matters. In Pennsylvania, residents have raised concern about the potential presence of industrial chemicals in groundwater, along with migration of methane gas around well casings. Overall, there have been relatively few incidents in Pennsylvania, however the high profile nature of the issue has caused the DEC and other environmental agencies to closely scrutinize the practice. Aside from the DEC’s review, the U.S. Environmental Protection Agency is currently conducting an extensive study on hydraulic fracturing. The DEC’s revised SGEIS report is the result of substantial re-analysis of a draft SGEIS issued in December 2009. The latest draft is in excess of 900 pages and represents the DEC’s consideration of 13,000 public comments, industry and consultant input and the DEC’s visits to Pennsylvania sites where incidents have occurred. The new report is significant in a variety of ways. First, the SGEIS reverses key elements of the 2009 report that would have allowed hydraulic fracturing within: the New York City and Syracuse watersheds; primary acquifers; and public forests, wildlife areas and parklands. The new report prohibits these activities. The DEC’s website now contains a map of prohibited drilling areas reflecting these locations. The DEC has indicated that if adopted, the recommendations would protect sensitive areas across the state, while still allowing access to 85 percent of the Marcellus Shale in New York. Second, permits will be allowed on private land subject to stringent regulation and permitting by the DEC. The new restrictions now include the following key provisions: well-water protection — no permits will be issued for sites within 500 feet of a private water well or spring and no permits will be allowed within 2,000 feet of a public drinking water supply well or reservoir subject to review of historical data; well casings — the DEC will generally require a third cemented well casing around each well to prevent the migration of gas; spill control — flowback water will need to be maintained in tanks with secondary containment; stormwater control — new permit processes will regulate storm control measures to prevent runoff; and water withdrawals — a special permit will now be required for large volume withdrawals to protect water bodies. The DEC is also creating a High-Volume Hydraulic Fracturing Advisory Panel to provide further recommendations and oversight of the practice. In addition, the DEC will require approved plans for disposing of flowback water and brine, including a tracking process to monitor disposal of the fluid. The agency will also require water treatment facilities to undergo review and approval prior to accepting waste fluid for treatment. Further, the DEC’s SGEIS has identified 322 chemicals proposed for use in the state along with health hazard information for each. As part of each drilling permit, DEC will require drilling companies to fully disclose and publicly identify products and additives used in the hydraulic fracturing process. The SGEIS also provides that the DEC will notify local governments of each permit application that it receives. The permit applicant must also certify that the proposed activity is consistent with local zoning and land use laws and, if not, the DEC will require an additional level of review prior to issuance of a permit. In another departure from the 2009 SGEIS, the DEC has indicated that the prior report did not adequately consider the socioeconomic and community impacts from hydraulic fracturing. These include both positive and negative impacts from the activity, impacts to local roads and traffic, and visual and noise impacts. As a result, the DEC has engaged independent consultants that are analyzing these potential impacts for consideration in the final report. The SGEIS will be subject to a 60-day comment period starting this month. The DEC will not issue any drilling permits until the public comments are reviewed and the final SGEIS has been issued. The DEC has assessed the Pennsylvania experience, problems and issues and attempted to create a comprehensive permitting process that allows hydraulic fracturing. However, it remains to be determined whether the proper balance has been struck to permit natural gas development while protecting the state’s environment. Initially, the oil and gas industry is concerned about the SGEIS report due to the extent of the areas where drilling is prohibited and the scope of the permitting requirements. Conversely, a variety of environmental groups have argued that there should be a blanket ban on drilling and that the proposed restrictions do not go far enough. Moreover, the DEC’s delay in issuing well permits to prepare another SGEIS has likely tempered the positive economic impact to New York as drilling companies have shifted resources to other states. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

The New York Brownfield Cleanup Program (BCP) was enacted in 2003 and has provided significant legal and financial incentives for private parties to remediate and re-develop brownfield parcels across New York. Based on the duration of sites in the BCP, time is running out for developers to complete brownfield projects prior to the expiration of the tax credits at the end of 2015. As part of Governor Cuomo’s budget, the administration has submitted a series of sweeping legislative changes to extend and modify the BCP tax credits. Overview of the BCP Changes Definition of “Brownfield” revised to a site with documented contamination at levels above soil cleanup standards for the proposed future site use – will require a Phase II site investigation Makes certain Class 2 New York Superfund eligible for the BCP Creates a BCP-EZ program similar to the old VCP program for expedited remediation of sites without tax credits Only participants, and not volunteers, in the BCP would have to pay State costs Site Preparation and Remediation Credits Site preparation tax credits remain: ranging from 22% to 50% of costs depending on cleanup level For sites admitted into the BCP after July 1, 2014, any Certificate of Completion needs to identify the entities eligible for tax credits and percentage of credits available Site preparation costs specifically include remediation of asbestos, lead and PCB Only site preparation costs identified in DEC approved remedial work plan would qualify – exclusion of site investigation, Phase I, and IRM costs Key New Deadlines and Criteria to Obtain Tangible Property Tax Credits Sites admitted into the BCP after July 1, 2014 would be restricted from obtaining tangible property tax credits for the value of on-site construction Sites where a Brownfield Cleanup Agreement is entered after July 1, 2014 need to seek and obtain approval of the tangible property tax credit at the time of the application by documenting that the site meets one of the following: Vacancy : the site property and buildings have been vacant for 15 years or more, or have been both vacant and tax delinquent for 10 years or more; or Financially underwater : the estimated cost of the investigation or remediation for the proposed future use of the site exceeds the appraised value of the property without construction; or Priority economic development project : the project has been determined a PED by the Department of Economic Development, which include locating specific types of businesses at the parcel and the creation of significant jobs of 50, 100, or 300 net new jobs based on the type of business. The proposal would remove sites from the BCP if they were accepted in prior to June 23, 2008 and no COC is issued by December 31, 2015 Sites admitted after July 23, 2008 but prior to July 1, 2014 would be removed if no COC is issued by December 31, 2017 Sites accepted into the program after July 1, 2014 must obtain a COC by December 31, 2025 to apply for tax credits No sites accepted into the BCP after December 31, 2022 would be eligible for tax credits No tangible property tax credits for sites where contamination is from off-site source or DEC determines that prior remediation permits site development for proposed use If a site qualifies for the tangible property tax credit, it will be capped at 24% and the individual components have been adjusted based on the type and location of site Other New York Brownfield Programs The municipal Environmental Restoration Program (ERP) is slated to receive $10 million under the budget Despite new funding source, the ERP sites currently in the program account for all of the new funding – significant additional funding is necessary to allow municipalities to put new sites into the ERP program Funding is removed for the Brownfield Opportunity Area (BOA) Program administered by the Department of State Without BOA funding, municipalities will not be able to progress area-wide BOA planning in the multi-step program or identify sites that might fit into the BCP for re-development If you have questions about the BCP program or the application to specific development sites, please contact us. Based on the proposed deadlines, we strongly encourage you to evaluate potential sites for BCP applications prior to any legislative changes to the program. Download this Legal Alert As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

It has been almost two years since we reported on Marcellus Shale development in New York state. A once projected economic boom from natural gas development has been put on indefinite hold here in the Empire State. Unfortunately, the news is not good and the prognosis for Marcellus exploration in New York remains grim. This despite the irony that Terry and Kim Pegula, who amassed their fortune through natural gas exploration in neighboring states, just acquired the Buffalo Bills franchise for an NFL record $1.4 billion. Realistically, one has to wonder about the state of professional sports teams in Western New York if hydraulic fracturing was not permitted in other states. The Department of Environmental Conservation’s Economic Assessment Report projected that the economic impact from Marcellus Shale development in New York would be significant. Projections suggest that indirect and direct employment could increase from 13,491 to 53,969 full time jobs. This equates to anywhere from $621 million to $2.5 billion in employee earnings, depending on the scope of development. Moreover, the state could receive between $31 million and $125 million in personal income tax receipts. The economic impact would also be great at a local level, where local governments would see a substantial jump in sales tax receipts based on Marcellus Shale development, with a typical 30-year well life spinning off $1.45 million in tax receipts. Here in New York, the picture for natural gas development through hydrofracking is uncertain. On the regulatory front, DEC still needs to finalize regulations before it will issue permits to hydraulically fracture and extract natural gas from the Marcellus Shale formation. The governor has passed off the issue, apparently indefinitely, to the Department of Health to conduct a health study on the process prior to DEC finalizing the SEQR review of proposed regulations. In recent comments to The Buffalo News, the governor indicated that he has not been in contact with DOH, does not plan to be, and said in regards to the study, “When it’s ready, it’s ready.” Perhaps that was simply pre-election talk to avoid the issue, but past history does not give much hope that the regulatory process will be finalized in the near term so that the moratorium on Marcellus hydrofracking permits can be lifted. On the litigation front, the news is actually quite worse. On June 24, the Court of Appeals issued a decision in the consolidated appeal of Norse Energy Corp. v. Town of Dryden; Cooperstown Holstein Corp. v. Town of Middlefield, which upheld the ability of towns to ban hydrofracking through local zoning laws. Since the permit moratorium, many communities across the Marcellus region of the state have acted to ban the practice. The actions have taken the form of temporary moratorium on Marcellus Shale development through use of high volume hydraulic fracturing, as well as local zoning regulation of industrial development to ban the practice. Based on the huge investment in development and leases, industry and landowners challenged the bans, while public interest groups supported the local laws. The state regulates oil and gas development pursuant to the Oil, Gas and Solution Mining Law of the Environmental Conservation Law. Section 23-0303(2) provides that the state’s oil, gas and solution mining regulatory program “supersede[s] all local laws or ordinances relating to the regulation of the oil, gas and solution mining industries; but shall not supersede local government jurisdiction over local roads or the rights of local governments under the real property tax law.” (Emphasis added). In June, the Court of Appeals affirmed the Third Department decisions in both cases, holding that the OGSML does not preempt home rule authority that municipalities have to regulate land use. The court went through a lengthy analysis of pre-emption to determine whether the OGSML preempted local zoning regulations in Dryden and Middlefield that prohibited hydraulic fracturing. The court conducted a three-part inquiry of the OGSML suppression clause by analyzing the plain language of the clause, the statutory scheme, and the legislative history of the provision. Initially, the court determined that the text of the OGSML provision did not preempt local zoning regulations. Rather, the provision was intended only to preempt “local laws that purport to regulate the actual operations of oil and gas activities, not zoning ordinances that restrict or prohibit certain land uses within town boundaries.” The court next assessed the pre-emption clause within the overall statutory scheme. The court found that the suppression clause was part of an overall OGSML statute that provided for DEC regulatory oversight of the industry, and there was nothing in the statute to indicate a broader reach other than to prevent “conflicting local laws directed at the technical operations of the industry.” Finally, in terms of legislative history, the clause was found to be consistent with allowing “local zoning laws regulating the permissible and prohibited uses of municipal land.” The court wrote that the “pertinent passages make no mention of zoning at all, much less evince an intent to take away local land use powers.” The court held that the towns were within their home rule authority to adopt the zoning laws that banned hydraulic fracturing in their respective jurisdictions. Rather, in the court’s judgment, there was “no legislative intent, much less a requisite ‘clear expression,’ requiring the preemption of local land use regulation.” The existing uncertainty regarding the timing and scope of DEC’s proposed hydraulic fracturing regulations has now been compounded by a patchwork of local zoning barring the practice in some areas of the state. Based on the Court of Appeals decision, if DEC finalizes the permit regulations and the moratorium is lifted, the state Legislature will need to address the role of local governments in regulating Marcellus Shale development. At this point, it’s hard to forecast whether it will be allowed in New York or, if so, what the reduced impact will be in the wake of prohibitive local regulation. Many of the oil and gas companies may just continue operations outside the state rather than risk heightened cost and diminished returns on their leases and development investments. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

In an apparent attempt to reduce health risks, the U.S. Environmental Protection Agency issued a new rule requiring the use of lead-safe work practices during renovation activities at residential homes, schools and daycare centers. The Lead-Based Paint Renovation, Repair and Painting Rule, 40 CFR Part 745, was issued under the Residential Lead-Based Paint Hazard Reduction Act of 1992 and applies to any contractor, including renovators, electricians, HVAC contractors, plumbers, painters and maintenance staff who disrupt more than six square feet of lead paint in pre-1978 homes, schools and daycare centers, as well as other areas where children gather. The new rule — which became effective April 22 — is aimed at eliminating instances of childhood lead poisoning. In practice, at least to date, the rule is catching many contractors by surprise and creating a great deal of concern about traditional renovation and remodeling projects. Some contractors even have decided to avoid working on structures covered by the rule due to the regulatory headache and enforcement risk. As an overview, the RRP rule requires contractors performing renovation activities in subject structures to first submit an application and pay a fee to the EPA for certification. Contractors also are required to attend a one-day class to have renovators certified. Both the certification application and training are valid for five years. In Western New York, the training course costs about $150 per attendee. As part of the required training, the RRP rule specifies lead-safe work practices aimed at minimizing dust and debris. The contractor must have at least one certified renovator in charge of each project where lead paint is disturbed. EPA’s RRP rule does not apply to homeowners performing their own renovations, repairs or painting work. There also are certain limited regulatory exceptions to the application of the rule, the first of which is that a written determination has been made by a certified inspector and provided to the contractor stating the structural components to be renovated are free of lead paint or fall below regulatory standards. Certified contractors may use an EPA-approved test kit to test the structural components and determine whether they fall below regulatory standards. Another exemption permits property owners to provide contractors with written certification that no children younger than six and no pregnant women reside in the owner’s residence, that the house is not a child-occupied facility and that the owner acknowledges the renovation firm will not be required to use RRP work practices. Prior to beginning renovation work, contractors are required to provide owners, tenants and child-care facilities with the pamphlet “Renovate Right: Important Lead Hazard Information for Families, Child Care Providers and Schools,” and document compliance with the notice. Lead-safe work practices generally consist of: containment of the work area, including taping and sealing off the area with plastic sheeting, covering floors and furniture that cannot be moved, and sealing off doors and HVAC systems; avoiding renovation activities that generate excessive dust, such as burning and torching, as well as using power equipment with HEPA vacuum attachments; and thoroughly cleaning the work area after the renovation with HEPA vacuum equipment, followed by wet wiping and wet mopping with adequate quantities of rinse water. The work area must be cleaned daily. Contractors also must also perform a final clean-up verification. The work area must be re-cleaned if necessary to meet clearance standards. Contractors also are required to retain all documents for three years after a covered project is completed. In an effort to simplify contractors’ compliance with the RRP rule, the EPA released a handbook “Small Entity Compliance Guide to Renovate Right.” As with most EPA rules, failure to follow the RRP rule can subject contractors to significant fines and penalties ranging from $10,000 per violation. Although the EPA supposedly has done outreach to advise the public and contractors about the new RRP rule, it is still catching many by surprise. Many firms that applied for certification prior to the April 22 effective date are still awaiting approval. According to an EPA enforcement memo, if a firm applied prior to the effective date, the EPA will not disrupt ongoing renovations over certification, but it will demand compliance with the training and lead-safe work practices. Although the apparent regulatory purpose may be laudable, it remains to be seen whether the new rule actually will produce a reduction in childhood lead poisoning. Given the magnitude of the regulation, it seems the EPA’s action will have a significant impact on the residential remodeling industry for older homes. It appears the EPA did not account for the impact of the new regulation, certification and cost impacts on residential remodeling projects. Many homeowners undoubtedly will be surprised by the increased costs for once-routine painting, renovation and repair activities as contractors attempt to comply with the new rule, which has mandated new and unprecedented regulatory and paperwork requirements on the remodeling industry. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

In recent months, development of the natural gas resources in the Marcellus Shale formation across New York’s Southern Tier and Pennsylvania has exploded. The U.S. Environmental Protection Agency held a series of hearings in Binghamton in September regarding the scope of a new hydraulic-fracturing study. The Marcellus Shale formation is a black Shale formation deep underground in the Southern Tier, extending down through Pennsylvania, Ohio and West Virginia. The formation is estimated to hold between 168 and 516 trillion cubic feet of natural gas. By comparison, New York state residents use about 1.1 trillion cubic feet per year. Due to the depth and nature of the formation, however, horizontal drilling and hydraulic-fracturing techniques are required to access the gas trapped within the Shale. In simple terms, hydraulic-fracturing — or “fracking” — involves the placement of a well within the gasbearing zone, pumping a pressurized fluid (water and chemicals) into the rock, causing a fracture and fission, withdrawing the fluid and allowing the proppant (sand or beads) to remain in the fractures to prop open the Shale fractures so that the natural gas can be extracted. Although fracking is far from a new technique, the pace and magnitude of the Marcellus Shale gas development has caused the EPA and state agencies to take a cautious approach. In particular, in October 2009, Congress requested the EPA conduct a new fracking study to assess the environmental impacts of the process. A 2004 EPA study had determined no credible scientific evidence of any environmental risks from fracking. Although challenged at the time by environmental groups, fracking was exempted from federal regulation under the Safe Drinking Water Act’s underground injection control provisions, therefore the 2005 energy reform bill did not address the process. With the tremendous increase in Marcellus Shale gas development, the issue of fracking has landed in the political arena. Critics of gas development point to potential environmental issues such as air pollution, land-use development, water pollution and traffic matters. In New York, there are about 14,000 producing natural gas wells. To the south, large-scale well exploration and development has occurred in Central Pennsylvania. In Dimock, Pa., groundwater sampling has revealed the presence of certain industrial solvents used in the fracking process. Last year, residents in that area sued a mining company, claiming the operations caused the contamination of the groundwater. The migration of methane gas into groundwater supplies also is viewed as a concern. The pace of Marcellus Shale gas development in New York also has caused increased public focus on the fracking issue. New York’s Department of Environmental Conservation recently closed the public comment period on a Supplemental Environmental Impact Statement for horizontal drilling and hydraulic-fracking. The DEC administers New York’s well drilling permit program and requires detailed information on the operator, proposed well location and issues, groundwater protection and environmental compliance prior to issuance of permits. Although no cases of groundwater contamination associated with fracking have been documented in New York, the DEC effectively put the issuance of new gas well permits on hold as additional studies are conducted. Similarly, the state Senate adopted a moratorium on new permits, which if approved by the Assembly will halt the issuance of drilling permits until May 15, 2011. The scope of the EPA’s proposed fracking study includes: identification of potential transport pathways for contaminants into groundwater that may merit further assessment; infiltration from natural fractures or fractures created during the process; leakage from higher in the well, during or after operations due to improper construction, damage or abandonment; and surface leakage from storage pits and spills. At the outset, the gas industry disputes the risk of deep groundwater impacts since most fracking fluids are withdrawn after the injection and dealt with according to state and federal waste regulations, and the remainder left underground is separated from groundwater sources by impermeable strata. Naturally, environmental groups dispute those positions and want the EPA to issue stringent regulations. In September, the EPA held a series of four public hearings in the Binghamton area to solicit comments on the proposed study. The hearings brought out hundreds on both sides of the issues, including some unusual alliances. On the side of more intensive study and regulations were environmentalists, residents and groups such as the Natural Resources Defense Counsel and U.S. Rep. Maurice Hinchey, who co-authored the “FRAC Act,” which would subject fracking to EPA regulation. Conversely, the natural gas industry and trade groups such as the American Petroleum Institute and Independent Oil & Gas Association of New York are opposed to further efforts to delay or stop natural gas development efforts. The industry’s position is that the natural gas wells already are subject to intense state regulation, so there is no need for duplicative regulation by the EPA. The trade groups pointed to the financial impact of development in New York, anticipated to produce millions in drilling permit revenues, tax revenues and new jobs. Some estimates suggest the impact could be as many as 30,000 new jobs and $1.4 billion in annual economic impact. In what is termed the “Marcellus multiplier,” Penn State University study of the gas development now in progress in that state indicates that for every $1 gas producers spend, there is a $1.90 total economic impact. As a result of the potential economic boom for New York, labor unions, the New York-New Jersey African American Chamber of Commerce and other groups provided comments in favor of natural gas development. The EPA study likely will take a few years and may not be concluded until 2013. Given the billons at stake and the potential economic development potential, it remains uncertain whether the EPA will objectively analyze the scientific information and come up with a report that balances environmental protection with sound energy development. If BP’s Deepwater Horizon disaster, the extensive off-shore drilling moratorium and the EPA’s desire to impose regulatory restrictions on coal and energy are any indication, the EPA seems content to favor environmental protectionism over sound energy exploration and development irrespective of the economic problems caused by its regulatory decisions. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

On Aug. 3, the United States Environmental Protection Agency issued a rule that sets the first limits on carbon emissions from power plants in the country. While met with fanfare from the Obama Administration and certain environmental groups, the Clean Power Plan rule issued pursuant to the Clean Air Act has already stirred significant opposition from the states, power industry and business. On Aug. 11, 17 states sued the EPA to rescind the rule as exceeding Clean Air Act authority. However, with a United Nations climate summit slated for December 2015, the chances of EPA and the administration slowing down are virtually nonexistent. Strikingly, the proposed rule from June 2014 was actually strengthened and the final rule is much more onerous. The rule aims at achieving a 32 percent reduction in emissions from 2005 levels by 2030 (up from a 30 percent reduction in the draft rule). The goal is to reduce carbon dioxide in the power industry, which would be accomplished by reducing coal’s share of the electric production pie. Currently it provides 39 percent of the country’s power. However, EPA predicts that it will supply 27 percent based on the rule and market forces, including competition from natural gas. The rule sets up state-specific emission limits based on the greenhouse-gas emissions amount in the state’s electricity portfolio. The rule provides that each state will have interim targets that must be met beginning in 2020. States will have one year to develop and submit their individual compliance plans, a regional plan in conjunction with other states, or to seek extensions. Following the submissions, the EPA will have one year to approve or reject the plan. Significantly, the EPA is also developing a federal model for states which they may use or which the EPA may impose if the states fail to comply. The EPA has pointed to cap and trade schemes as a way for states to comply. In a key departure from the draft rule, the EPA hiked the projected renewable share from 22 percent to 28 percent of the electric generation, suggesting that the cost of renewable energy is decreasing and more projects are being built. Hence, the administration has picked solar and wind power industry segments as “winners” under the Clean Power Plan. The administration has clearly targeted fossil fuels. Coal tops that list. EPA has reduced the share of coal production to 27 percent by 2030. Aside from administration suggestions that coal’s market share is declining because of competition from natural gas and increased costs, the regulations imposed by EPA clearly make it much more expensive. Similarly, although once a key part of the Clean Power Plan, natural gas has been reduced as a central component. Hence, the administration has indicated that its share of the electricity production in 2030 is now projected to be no more than would otherwise be produced under its normal business. Natural gas producers have argued that since it produces half as much carbon as coal, it should have been a central component in the rule aimed at addressing climate change concerns. Instead, the EPA has attempted to force renewable energy over fossil fuels. Nuclear power plants do not produce greenhouse gases and account for about 20 percent of the current power portfolio. However, nuclear energy will not count towards the states’ goals unless the plants expand. This is noteworthy as several nuclear reactors are set to close, thus requiring the affected states to keep these sources in place or overcome the loss of clean energy with other sources. The Clean Power Plan is going to force significant changes to the U.S. power system as fossil fuels are targeted for reduction. Projections suggest that the cost of electricity may increase significantly. For example, a 2014 projection from NERA Economic Consulting indicates that if the states administer their own plan, electric prices may rise an average of 12 percent between 2017 and 2031. However, if the EPA plans are implemented, prices may rise an average of 17 percent during that period. Regardless of the perspective one has on climate change issues, science and potential actions, it is useful to know if the proposed rules being forced on the U.S. power industry and consumers will have a significant impact. Sadly, that is not the case, particularly considering the global emissions from other developed and developing nations. According to the “Model for the Assessment of Greenhouse Gas Induced Climate Change,” which the EPA assisted in developing, it has been estimated that the climate regulations will reduce a mere 0.018 degree Celsius of warming by 2100. More striking is that the U.S. could cut its entire carbon dioxide emission completely and it would not make a difference in global warming. Based on the UN’s Intergovernmental Panel on Climate Change modeling, the world would be a mere .137 degrees Celsius cooler by 2100. Aside from serious questions about the cost and benefit associated with the Clean Power Plan, electricity providers are concerned about the reliability of the power grid. Simply put, taking large quantities of current electric supplies off the system are likely to create significant strains on the U.S. power grid. Significantly, it has been projected that the rule will cause twice as many coal-fired power plants to retire than would occur without the rule. Power operators across the country have expressed concern about reliability under the rule. New York Independent System Operator wrote to the EPA that “the Clean Power Plan presents potentially serious reliability implications for New York.” Finally, the rule will be subject to serious legal challenge from parties across the spectrum, within the coal industry, power providers and states. There are questions whether the EPA has the constitutional authority and statutory basis under the Clean Air Act to issue the rule. Initially, the EPA has gone from regulating single emission sources (i.e., plants and smokestacks) to a sweeping re-design of the U.S. energy system. The plan also appears to trample on federalism principles under existing Clean Air Act programs, whereby the EPA sets emission limits and allows states to meet them, by instead commanding states to meet a national model. Another legal concern is whether EPA has double-regulated existing power plants, which is prohibited under the Clean Air Act. Regardless of one’s perspective on the climate change, the Clean Power Plan is a massive rule that will dramatically affect energy, industry and the public in a variety of ways if it goes into effect. The issuance of such sweeping regulation, by the EPA, rather than elected members of Congress, is another cause for concern due to accountability issues. As a result, the Clean Power Plan will be subject to serious challenge on the legislative, judicial and budgetary fronts in coming months. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

Following Election Day and the shift in Senate control, it may be worth a look ahead at environmental issues that are likely to be confronted in 2015. While the administration of President Obama has already been very active in the regulatory arena, the next two years are likely to continue that trend in key policy areas. With the upcoming 2015 Congress under Republican control, the scrutiny and opposition to the environmental policies of this administration are likely to be heightened. Based on the incredible impact and cost of proposed environmental regulation, additional scrutiny and principled opposition seems warranted. The administration has issued or is in the process of proposing far reaching environmental regulations that will affect all aspects of American life, including greenhouse gas emission standards, methane gas emission standards, rules for handling and storage of coal ash, and hydraulic fracturing on federal lands. The most recent and far-reaching proposals also include considerable expansion of the definition of “waters of the United States” and significantly tightened ozone emission standards. The administration has proposed sweeping new regulations of “navigable waters” under the Clean Water Act. The proposed rule is supposed to address recent U.S. Supreme Court decisions that have left uncertainty about the reach of the federal authority. In April, the United States Environmental Protection Agency proposed a rule known as “waters of the United States” that would substantially increase the federal authority over water, use of water and adjoining land. The reach of the proposed rule is striking and its potential impact on property rights, farming, business and federalism is ominous. The public comment period expired Nov. 28. The volume of comments on the regulation was extensive. For example, the U.S. Chamber of Commerce joined with almost 400 other business groups that requested EPA withdraw the rule which redefines agency jurisdiction over ponds and streams. Significantly, opponents argue that the proposed rule would expand EPA’s authority over creeks, ponds and wetlands broadly and would put millions of rivers and streams under federal control, as well as ditches, puddles and dry creek beds. The expanded jurisdiction could create the need for additional permits for a variety of routine activities near these water sources, such as excavating ditches and building fences. In striking comments, the American Farm Bureau Federation said that the rule “provides none of the clarity and certainty it promises” but “[i]nstead, it creates confusion and risk by providing the agencies with almost unlimited authority to regulate, at their discretion, any low spot where rainwater collects, including common farm ditches, ephemeral drainages, agricultural ponds, and isolated wetlands found in and near farms and ranches across the nation.” Despite the EPA’s suggestion that CWA jurisdiction would only marginally increase, the regulatory community is not accepting that statement. Thus far, the draft rule that received over 500,000 comments and galvanized industry, business, farms and municipalities in opposition has not garnered much public support aside from environmental interest groups. In September, the House of Representatives voted to block the rule and Senate bills have been sponsored as well. However, as with other policy matters, it is unlikely that opposition will dissuade either the administration or regulatory agencies. Consequently, new congressional fights and budgetary restrictions seem to be ahead in 2015. The likely chairman of the Senate Environment and Public Works Committee, James Inhofe, R-Okla., is no fan of the EPA. Inhofe may support his colleagues, Sen. David Vitter, R-La., and Rep. Bill Shuster, R-Pa., who commented that the rule “presents a grave threat to Americans’ property rights, and its finalization will force landowners throughout the country to live with the unending prospect that their homes, farms, or communities could be subject to ruinous Clean Water Act jurisdictional determinations and litigation.” The EPA is slated to issue a final rule in spring 2015 after reviewing comments. Similarly, on Nov. 25, the EPA proposed tightened ozone regulations under the Clean Air Act that would reduce the permissible level to between 65 and 70 parts per billion (ppb). Ozone is the primary component of smog and is addressed under the CAA. In 2008, EPA issued an ozone standard of 75 ppb, but has been trying to make the standards more restrictive ever since. These efforts have caused significant concern among the business, regulated community and elected officials outside the current administration. The regulations need to be finalized by October 2015. If the new standards are promulgated, it will force many U.S. metropolitan areas out of compliance with the CAA. The consequences are significant. The states where these areas are located will be forced to develop State Implementation Plans that specify steps that each non-attainment area will undertake to meet the new standard. Additionally, businesses in the non-attainment areas generally have to purchase new air pollution equipment and obtain new permits. Hence, the non-attainment zones may be red-flagged by site selectors for new business opportunities and force businesses to look elsewhere. Incredibly, the EPA considered a 60 ppb standard despite the agency’s predictions that it would cost the U.S. up to $90 billion per year. In 2011, EPA settled on a proposal for 70 ppb, but in the midst of a presidential election season and concerns about business imports, the president directed the agency to shelve the regulatory proposal. Free from election concerns, the president and EPA are now moving ahead irrespective of the costs to American business and citizens. The Republican Senate and House are likely to take legislative and budgetary steps to try to halt the ozone rule. The National Association of Manufacturers has predicted that the ozone rule would be the costliest regulation in U.S. history. A study performed by NERA Economic Consulting for NAM estimated that a 60 ppb standard would have the following effects: reduce gross domestic product by $270 billion on average per year from 2017 through 2040; cause an average annual loss of 2.9 million jobs through 2040; and impose $2.2 trillion in costs from 2017 through 2040. The EPA’s information suggests that if the standard is lowered to 60 ppb, 93 percent of the counties in the U.S. with ozone monitors would fail to meet them. Republicans in Congress have been very critical of the ozone proposals. This summer, Sen. Vitter and Rep. Lamar Smith, RTexas, wrote to the EPA requesting the agency to comply with the CAA statutory requirement to have the Clean Air Scientific Advisory Committee evaluate the adverse effects, including economic impacts, of attaining and meeting a tighter ozone standard. It does not appear that EPA has complied with this requirement in moving forward with the proposed regulations. Shortly after the proposed regulations were issued, House Speaker John Boehner, R-Ohio, issued stinging comments calling the ozone regulations a job killer and “the most expensive rule ever proposed by the EPA.” Aside from the economics, the potential environmental benefits and science of the regulation are in serious doubt. The proposed standards are below naturally occurring ozone levels near Yellowstone Park in Wyoming. Regardless of one’s perspective on environmental regulation, elected members of Congress should exercise their legislative role to evaluate and act on these and other pending environmental regulations that could gravely impact the U.S., as a whole, and each and every citizen. The cumulative impact of EPA’s aggressive proliferation of regulations to the U.S. needs to be carefully considered. The EPA, like other federal agencies, needs to be accountable to the country and not overstep its regulatory bounds by re-making federal environmental laws without accountability or reasonable limits. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

The American Society for Testing and Materials (ASTM) developed the initial Phase I Environmental Site Assessment (ESA) standard in 1993 to address the scope of environmental due diligence required prior to acquisition of real estate in light of environmental liability concerns under federal and state Superfund statutes. The Phase I is part of the purchaser’s and lender’s due diligence in assessing whether to acquire or lend on a parcel of property. The Phase I report is a document prepared by an environmental consultant that summarizes available site reports, witness information and environmental regulatory database information to determine whether or not there are recognized environmental conditions (REC) on a subject property. If so, based on the status of the transaction, the parcel may require further investigation through soil, groundwater and possibly soil vapor testing. The ASTM Phase I standard was updated in 1997 and 2000. Statutory changes to the federal Superfund statute in 2002 added new defenses and led to the issuance of US EPA regulations on All Appropriate Inquiry (AAI) standards. In coordination with EPA’s final AAI regulations, the ASTM issued its last substantial update to the Phase I standard, captioned ASTM E 1527-05, in 2005. The Phase I standard was heightened by additional investigation requirements in exchange for potential liability protection under the federal Superfund statute. By performing a Phase I meeting the E 1527-05 standard, a property purchaser may be able to avail itself of one of the three Superfund defenses, namely the innocent purchaser, bona fide prospective purchaser or contiguous property owner defense. Environmental consultants, banks, property owners, developers and attorneys have worked with the current Phase I standard since 2005. However, ASTM updates its standards every eight years, and ASTM voted on a series of proposed changes in January 2013. The revisions are currently subject to EPA review, public comment and approval, which is slated to take approximately five months. It is expected that the new Phase I standard, captioned E 1527-13, will be finalized in the next several months. The proposed changes to the Phase I standard include both major and minor revisions. In the major revision area are the following items: simplification of the definition of “Recognized Environmental Conditions,” vapor migration and establishing when regulatory file review is appropriate. The minor revisions to the Phase I standard include user responsibilities and industrial/manufacturing properties. Initially, the REC definition addresses instances in which hazardous substances or petroleum products exist on the property in a manner to indicate a past, present or potential release. The new ASTM Phase I definition has been streamlined as “the presence or likely presence of any hazardous substances or petroleum products in, or at a property: (1) due to any release to the environment; (2) under conditions indicative of a release to the environment; or (3) under conditions that pose a material threat of a future release to the environment.” The new definition is simplified and tracks the definitions of release and environment under CERCLA. In addition, the new Phase I standard includes a revised definition of historic REC and a new definition of controlled REC, known as CREC. The definition of CREC encompasses a REC from “a past release of hazardous substances or petroleum products that has been addressed to the satisfaction of the applicable regulatory authority …” such as through a no further action letter or a brownfield site with institutional and engineering controls to address remaining hazardous substances. Another significant change to the Phase I standard is the inclusion of vapor migration as part of the Phase I. Vapor migration is the potential for contamination in soil and groundwater to cause vapor to infiltrate adjoining buildings. Vapor intrusion is being addressed at numerous sites under the oversight of DEC and the NYS Department of Health. With the addition of vapor intrusion as a Phase I consideration, this media will now need to be considered on the same basis as contaminated soil or groundwater. The new Phase I standard also incorporates E2600-10, which is a national method for assessing vapor intrusion. In addition, a definition of migration has been added to the Phase I standard and the definition of activity and use limitation (AUL) has been revised to include soil vapor. Finally, a few minor revisions have been made to the Phase I standard. The standard now sets out circumstances in which regulatory file review and records review is necessary. The user responsibility section has also been revised. Environmental liens and AULs are generally found in recorded land title records, but in some jurisdictions these are recorded or filed in judicial records. If environmental liens and AULs are only recorded in judicial records, the Phase I standard requires the records to be searched. Under the current Phase I standard, the client or user is required to provide the environmental professional with known environmental lien and AUL information, unless the consultant is engaged to perform that work. However, under the new standard the environmental professional may conduct a search of institutional and engineering control registries in conjunction with the government records search. The standard requires the user to provide commonly known and reasonably ascertainable information within the community, which could be material to the REC determination, to the environmental professional. Further, if the user does not provide the required information under this Phase I section, the environmental professional needs to consider the information shortfall as they would similar to any other data gap. Although it is impossible to predict with certainty when the final Phase I standard will be issued by ASTM, it is expected to occur over the next several months. To the extent that the E1527-13 Phase I standard is finalized it will require additional time, money and effort on the part of the prospective property purchasers, banks and environmental professionals. The exact cost and time impact will depend on geographic and market-particular property factors. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.

As the New York State Department of Environmental Conservation accepts public comments on proposed regulations to address Marcellus shale development, many local communities are beginning to weigh in on the issue. The DEC needs to finalize state regulations before it will issue permits to drill and extract natural gas from the Marcellus shale formation. Nonetheless, communities across the affected region of the state are beginning to act. The actions to date have taken the form of a temporary moratorium on Marcellus shale development through use of high volume hydraulic fracturing, as well as local zoning regulation of industrial development to ban the practice. Based on the substantial investment in leases, exploration and development costs, landowners and natural gas exploration companies are mounting legal challenges. There are significant legal questions regarding whether existing state law pre-empts local regulation of Marcellus shale development. Initially, the state regulates oil and gas development pursuant to the Oil, Gas and Solution Mining Law (OGSML) found at Article 23 of the Environmental Conservation Law (ECL). Section 23-0303(2) provides that the state’s oil, gas and solution mining regulatory program “supersede[s] all local laws or ordinances relating to the regulation of the oil, gas and solution mining industries; but shall not supersede local government jurisdiction over local roads or the rights of local governments under the real property tax law.” (emphasis added). Thus, the question of how much home rule authority municipalities will have in this area will depend upon the courts’ interpretation of this suppression provision of the ECL. In at least one instance a court has addressed the scope of the pre-emption provision in ECL Section 23-0303(2). In Matter of Envirogas, Inc. v. Town of Kiantone, 112 Misc.2d 432 (N.Y. S.Ct., Erie Co. 1982), aff’d 89 A.D.2d 1056 (4th Dept. 1982), lv. den., 58 N.Y.2d 602 (1982), the court invalidated a town zoning ordinance that required payment of a $2,500 compliance bond and a $25 permit fee for oil and gas wells as a result of the preemption provision of Section 23-0303(2). The court held that “where a state law expressly states that its purpose is to supersede all local ordinances then the local government is precluded from legislating on the same subject matter unless it has received ‘clear and explicit’ authority to the contrary,” Id. at 433. Consequently, the court found that Section 23- 0303(2) expressly “pre-empts not only inconsistent local regulation, but also any municipal law which purports to regulate gas and oil well drilling operations, unless the law relates to the local roads or real property taxes which are specifically excluded by the amendment.” The court rejected the town’s assertion that the bond and permit fees were aimed at addressing local roads since the ordinance did not apply to operators of other forms of heavy equipment such as farmers and contractors. Although the suppression provision of the OGSML has not been tested yet relative to Marcellus shale regulation, municipalities interested in enacting local ordinances are relying upon caselaw regarding the ECL’s treatment of surface mining regulation. However, there are key distinctions between the oil and gas statute and the statute covering surface mining. The state’s Mined Land Reclamation Law (MLRL) is set forth in Article 23, Title 27 of the ECL. The MLRL preemption provision differs significantly from that of the OGSML in that it provides that “this title shall supersede all other state and local laws relating to the extractive mining industry; provided, however that nothing in this title shall be construed to prevent any local government from: a) enacting or enforcing local laws or ordinances of general applicability ... or b) ... local zoning ordinances or laws which determine permissible uses in zoning districts,” ECL §23- 2703(2)(a) and (b). (emphasis added). As such, the statutory language differs materially in that the OGSML precludes local regulation, except relating to roads and taxes, while the MLRL permits local zoning regulation. In addition, the statutory purposes are distinct. The OGSML suppression provision was enacted in 1981 to address state-wide problems caused by attempts at local regulation which created a patchwork of regulations and enforcement problems affecting the oil and gas industry. Thus, DEC worked with the Legislature to enact a uniform regulatory regime exclusively administered by the DEC and removed local control. In contrast, the MLRL was aimed at creating a state and local partnership arrangement that recognized the importance of extraction of mineral resources, provided a DEC regulatory program, but acknowledged the importance of local regulation and zoning regarding the siting of surface mines as well as reclamation of mines. In the context of MLRL cases the New York Court of Appeals has held that a municipal zoning ordinance that precluded sand and gravel mines as a permitted use within the town’s zoning district did not relate to the mining industry, but rather “regulating the location, construction and use of buildings, structures, and the use of land in the [t]own,” See Frew Run Gravel Products, Inc. v. Town of Carroll, 71 N.Y.2d 126 (1987). After that decision the state Legislature amended the MLRL section to ensure that local zoning laws which determine permissible uses in zoning districts are outside the scope of pre-emption. In the subsequent case of Gernatt Asphalt Products v. Town of Sardina, 87 N.Y.2d 668 (1996), the Court of Appeals rejected the notion that the state’s MLRL preempted a town’s ability to determine that mining be eliminated as a permitted use within the community. Aside from a complete ban, some municipalities are enacting temporary moratoriums on hydraulic fracturing while they consider zoning changes. In general a local moratorium is warranted when: it is adopted in strict compliance with the procedures for enactment and amendment of zoning regulations; the moratorium does not exceed a reasonable time period; and the municipality makes legitimate efforts to update its comprehensive plan and consider amendments to zoning regulations. Several communities, including the Towns of Marcellus, Skaneateles and DeWitt have enacted moratoriums on hydraulic fracturing while further study and analysis is performed. Many other communities have revised their zoning codes to ban hydraulic fracturing. Given the substantial economic investment by gas exploration companies, zoning amendments that ban the practice are being met with legal challenges. In August 2011 Dryden, New York passed a ban. In September, Anschutz Exploration Company, which holds leases on approximately 22,500 acres in the town and has invested more than $5 million in leases and research, filed suit challenging the town’s action. The lawsuit asserts that the zoning ordinance is invalid and unenforceable because it prohibits the development of oil and gas which State law explicitly authorizes under Article 23 of the ECL. Essentially the gas company position is that OGSML supersedes local ordinances relating to natural gas drilling except two limited areas of jurisdiction relating to local roads and property taxes. The town has argued that the exercise of local zoning authority is a permissible action within the town’s home rule authority. However, the gas company has asserted that the exceptions carved out for zoning regulation by the courts related to surface mining do not apply in this instance and that the action is preempted by the OGSML. Regardless of the initial decision in Dryden and other challenges, the cases are likely to be appealed to the state’s highest court. Depending on the outcome of legal challenges, the State Legislature may need to address the role of local governments in regulating Marcellus shale development. Download the Reprint from The Daily Record As always, if you have any questions, please feel free to contact us here or call us at 585.258.2800.