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Louisiana Law Blog | Employment Matter Lawyers | Kean Miller LLP





By Steven Boutwell on April 30, 2015 Posted in Intellectual Property

For many inventors, the grant of a patent application is quite exciting. However, once the inventor seeks to market their invention, they can find the process costly and overwhelming. Often when small companies or solo inventors develop new ideas that are later patented, they discover that manufacture or use of the patented invention is unmanageable for an entity of their size. Rather than sit on this technology and let the patent protection expire, these persons will seek to sell their patented idea to another person or company who can use them. Scattered among firms and investors who are attempting to acquire valuable patents for use in their own businesses are non-practicing entities, who have more litigious purposes in mind. Non-practicing entities, which are known colloquially as “patent trolls,” are entities that purchase patents solely for the purpose of enforcement of the patent rights. Patent trolls do not make, use, sell, or offer to sell the technology that is disclosed in the patent; rather, they acquire patents and then send out cease and desist letters or demands for licensing fees to persons (typically individuals and smaller companies who do not have the means to pay for expensive patent infringement litigation) that they perceive to be infringing its patents. At times, these claims of infringement are based on tenuous grounds, and the person receiving the threats feels that they have no choice but to pay the patent troll what they are demanding.

Patent trolls have contributed to the push to reform the patent system by a variety of people—from the legislature to late night television show pundits. However, a recent new player has presented an idea for changing the patent landscape by taking would-be sales of patents away from the trolls. Google, who has previously openly criticized the patent system and questioned the need for patents as a whole, announced on April 27, 2015 that it will be testing a new program for two weeks called the “Patent Purchase Promotion.” This promotion invites owners of non-expired United States patents to sell their patents to Google. From May 8, 2015 to May 22, 2015, Google will open a streamlined portal for patent owner to offer to sell their patents to Google at a price that the patent owner sets.[1]  Google will review all of the offers for sale and then let patent owners know Google’s decision by June 26, 2015. Google has not set any kind of standard for the type of non-expired United States patent that will be considered other than that the patent cannot be a design patent. Google anticipates that all of the patent sellers would be paid by the end of August. Through this, Google claims that it is seeking to protect those patent owners who wish to sell their patents without the risk of the patent falling into a patent troll’s hands.

Google has yet to announce how many patents it will be purchasing or how much money it has invested into this new promotion. Google has also not announced what kind of critiques or methodology that Google will be using to evaluate the patent purchase offers that it receives. However, since Google would likely want to obtain some value from the patents it purchases, considerations that are typical of intellectual property acquisitions will likely be involved including, but not limited to:

  • The remaining life of the patent rights (Patent protection is granted for 20 years from the date of filing the patent application. 35 U.S.C. 154.);
  • Strength of the patent (i.e. is the patent strong, or is there a high potential for a patent to be declared invalid?);
  • Breadth of patent rights (i.e. are the patent claims relatively broad, or are the claims limited to the narrow, specific, singular embodiment described in the application?);
  • Ease of use of the patent (i.e. is the cost of purchasing the patent outweighed by the cost of making or selling the disclosed technology?); and
  • Marketplace concerns (e.g. number of competitors, available alternatives in the marketplace, etc.)

One interesting aspect of Google’s promotion is that the sale between the patent owner and Google will not completely remove all rights that a patent owner has in the patent. After the sale, Google promises to grant a non-exclusive, non-transferrable, non-assignable, non-sublicenseable license to the patent owner to develop, make, use, sell, offer to sell, import, export and otherwise transfer or dispose of the patented technology.[2]  So, while a patent owner cannot license his or her invention to another person after Google has purchased the patent, the patent owner still has rights to make some use of the ideas he or she developed and patented.

Google has stated that this initial two-week program is experimental, and that it may reinstitute the program or open the program to foreign patent owners if enough interest is generated in the promotion. The full details of Google’s program are still being released, but the new Patent Purchase Promotion presents an interesting strategy to combat patent trolls’ attempts to purchase patented technology for litigious uses. Rather than sell to the patent trolls, Google hopes that patent owners will instead sell to it.

Selling a patent to Google may be a tempting opportunity to many inventors and patent owners. In its detailing of the program, Google strongly encourages potential patent sellers to consult with an attorney before making a pitch to Google. Among other services, an attorney can assist patent owners with review of the terms of making the pitch to Google and the terms of sale. An attorney can also assist patent owners in understanding what rights they will have to the patented technology once the sale is complete. Consultation with an attorney who is experienced in transactions that involve intellectual property would be extremely beneficial to a hopeful seller to Google.

_______________________________________________

googlepublicpolicy.blogspot.com/2015/04/announcing-patent-purchase-promotion.html ).

services.google.com/fh/files/misc/patent-purchase-agreement.pdf ).

Last year, the EPA announced its intention to add or modify a number of AP-42 emission factors, primarily for petroleum refineries, pursuant to a consent decree entered into with Air Alliance Houston, Community In-Power and Development Association, Inc. Louisiana Bucket Brigade and Texas Environmental Justice Advocacy Services (“Plaintiffs”).  The EPA informally solicited comments on its proposal with a final comment period extended to December 22, . After considering the comments, on April 20, 2015, the EPA made a decision to issue or revise eight emission factors.

Probably the most noteworthy part of the decision is that the EPA decided not to modify the nitrogen oxide (“NOx”) emission factor for industrial flares.  In , the EPA initially proposed to increase this factor forty-fold based on information gleaned from various flare stack test intended to determine the combustion efficiency of flares under various operating conditions (i.e. varying steam and air to fuel ratios).  However, in its final decision, EPA determined not to revise the factor for NOx at this time. According to the EPA:

Based on our review of NOx emissions data for flares and additional information received after proposal, we have determined that the data was not adequate to support revising the NOx emissions factor for flares. Based on comments received, EPA determined that the NOx data used for the proposal contained certain flaws that rendered the data quality suspect.[1]

The EPA also decided not to revise emission factors for tanks and wastewater systems.  Emissions from storage tanks containing organic liquids are estimated based on a series of correlation equations developed by the American Petroleum Institute (“API”) and incorporated into Section 7.1 of AP-42.  As part of this review, the EPA determined that actual measured data from several studies agreed well with emission estimates based on these correlations.[2]  Unlike storage tanks, “there have been no studies to specifically investigate wastewater treatment systems.”[3]  As such, the EPA concluded that the existing AP-42 factors for wastewater treatment provided reasonably accurate estimate of VOC emissions and it was not necessary to make revisions.[4]

“AP-42, Compilations of Air Pollutant Emission Factors has been published since 1972 as the primary compilation of EPA s emission factor information.”[5]  Whereas other more accurate and specific emission levels may (at times) be obtained through other means, AP-42 factors provide an industry average benchmark or default value. Often, as in the case of storage tank emission calculations, no other reasonable method is available to industry or government to determine emission levels on a day-to-day basis.  Industry and regulators have long relied on the emission factors contained in AP-42 to estimate annual emission inventories and to develop the basis for and show compliance with air emission permitted levels.  These changes are designated as final and are effective immediately.

Otherwise the EPA has indicated that it has determined to add several new and modified factors as shown below:

Note 1:  Many sulfur plants have incinerators fired on refinery or natural gas that combust the sulfur recovery unit tail gas.  Many refiners have used natural gas combustion factors as presented in §1.4 of AP-42 or a manufacturers burner rating to estimate NOx emissions from a SRU.

Note 2:  Refiners would have previously used AP-42 factor for natural gas combustion or manufacturers burner ratings to estimate emissions.  As hydrogen production heaters fire much hotter than many typical furnaces, it is apparent that the EPA believed that hydrogen production furnaces required a specific factor.

_________________________________________________________

www.epa.gov/ttn/chief/consentdecree/index_consent_decree.html (last visited April 21, 2015).

www.epa.gov/ttn/chief/consentdecree/final_report_review.pdf (last visited April 22, 2015).

[3]Id. at Chapter 6, p. 38.

[4] Id. at 41.

www.epa.gov/ttn/chief/ap42/index.html (last visited Apr. 22, 2015)

The United States has long had policies prohibiting government employees and government contractors from engaging in trafficking of persons, and the recent Executive Order, titled “Strengthening Protections Against Trafficking in Persons in Federal Contracts”, and Title XVII of the National Defense Authorization Act for Fiscal Year have served to heighten the requirements on federal contractors to comply with federal rules against human trafficking. Prior to the implementation of these new rules, federal law prohibited government employees and contractors from participating in trafficking activities including “severe forms of trafficking in persons.” Severe forms of trafficking in persons is defined by section 103 of the Trafficking Victims Protection Act of 2000 to include the recruitment, harboring, transportation, provision, or obtaining of a person for labor or services, through the use of force, fraud, or coercion for the purpose of subjection to involuntary servitude. The new rules amending the Federal Acquisition Regulation (“FAR”) seek to strengthen the protections against trafficking and provide a stronger framework to eliminate trafficking in persons from government contracts. Since a significant number of federal government contracts are for construction projects, it is imperative that contractors who bid on and win federal contracts be aware of these new regulations.

Under the new regulations, contractors and subcontractors are expressly prohibited from engaging in the following trafficking-related activities:

  • Destroying, concealing, removing, confiscating, or otherwise denying access to an employee’s identity or immigration documents;
  • Failing to provide return transportation for an employee from a foreign country to the country from which the employee was recruited, unless the contractor is exempted or the employee is a victim of trafficking that is seeking redress in his country of employment or is a witness to human trafficking;
  • Solicitation of a person for employment, or offering employment, through materially false or fraudulent pretenses, falsehoods, or promises about that employment. This includes misrepresentations concerning key aspects of employment such as wage payments, fringe benefits, location, and conditions of employment;
  • Use of recruiters who do not comply with local labor laws and charging “recruitment fees” to employees;
  • Providing or arranging housing that fails to meet applicable housing and safety standards; and
  • If required by law or contract, failing to provide an employment contract, recruitment contract, or other required paperwork in writing, in the employee’s native language, prior to departure from the employee’s country of origin.

The regulations impose several additional obligations on federal contractors fro government contracts. For example, these new regulations mandate that contractors inform their employees and agents of the federal government’s anti-trafficking policies and the penalties for non-compliance, which include removal from contract, reduction in benefits, and termination of employment. Contractors and subcontractors are now required to fully cooperate with the federal agencies that are responsible for audits, investigations, or corrective actions related to human trafficking.

For any contractors that are doing work outside of the United States where the contract is valued over $500,000, the contractor must also create and implement a plan to prevent any prohibited trafficking in persons and implement procedures to prevent any such activities. This plan must be appropriately designed with regard to the size and complexity of the project, and a copy of this plan must be submitted upon award of the contract and annually thereafter. The contractor must also certify that, after performing the appropriate due diligence, to the best of the contractor’s knowledge and belief: (1) none of the contractor’s agents, subcontractors, or their agents are engaged in trafficking activities; and (2) if abuses have been found, the contractor has taken the appropriate remedial and referral actions. Contractors will be required to publish their compliance plans at their workplace and on their websites by the start of the contract performance. Should a violation occur, the contracting officer will consider the compliance plan as a mitigating factor when determining the penalties for the violation.

These new requirements apply to all new bids, contracts, and solicitations for contract dated March 2, 2015 onward. Given the heightened new requirements for federal contracts, contractors considering such projects may want to review their current policies and procedures to ensure compliance with the new requirements. Contractors may also consider revising their employee handbooks in light of the new requirements. Consulting a labor and employment or construction attorney may be beneficial in assessing changes to contract labor policies and compliance plans.

By Steven Boutwell on April 15, 2015 Posted in Process Safety Management

The Occupational Safety and Health Administration (“OSHA”) published a Request for Information (“RFI”)  on December 9, concerning possible changes to the Process Safety Management (“PSM”) program codified at 29 C.F.R. 1910.119.  See 78 Fed. Reg. 73756 (Dec. 9, ).  Likewise, the Environmental Protection Agency (“EPA”) published an RFI on July 31, relating to possible changes to the similar Risk Management Program (“RMP”) rules codified at 40 C.F.R. Part 68.  See 79 Fed. Reg. 44604 (July 31, ).  At the time of this writing, the respective comment periods have closed and we are waiting to see new proposed regulations. This is the sixth article in a series of articles concerning these potential rulemaking actions.

OSHA and the EPA requested comments concerning revising the mechanical integrity requirements in the PSM and RMP rules to expand the scope to include unspecified safety-critical equipment.  Comments received by OSHA and the EPA requests were similar in nature.  Although many comments addressed safety-critical equipment, this article will compare comments from three organizations:  the American Fuel Petrochemical Manufactures (“AFPM”), the Mary Kay O’Conner Process Safety Center (“MKOPSC”) at the Texas A M Engineering Experimental Station, and the U.S. Chemical Safety Board (“CSB”).

Both PSM and RMP rules require that an employer or operator maintain a mechanical integrity program that includes written procedures for inspection and testing pressure vessels, storage tanks, piping systems, relief and vent systems and devices, emergency shutdown systems, controls, and pumps.  See 29 C.F.R. 1910.119(j)(1)-(2) and 40 C.F.R 68.73(a)-(b).  The written procedures and the inspection frequency must be consistent with recognized and generally acceptable good engineering practices “RAGAGEP.” See 29 C.F.R. 1910.119(j)(4) and 40 C.F.R. 68.73(d).

When promulgating the PSM rule in 1992, OSHA recognized that it was untenable to classify individual pieces of equipment as critical (or not) with regulatory certainty.  “Equipment considered critical to a process by one employer may not necessarily be considered critical to a different process by another employer.  As a result, there could be confusion with respect to which equipment is subject to the [mechanical integrity] requirements.” 57 Fed. Reg. 6356, 6389 (Feb. 24, 1992).  As a practical matter, OSHA concluded that “there is certain equipment, critical to process safety that is common to all processes.”  Id. However, OSHA then added “if an employer deems additional equipment to be critical to a particular process, that employer should consider that equipment to be covered by this paragraph and treat it accordingly.”  Id .  That said, it should be noted that the preamble language is permissive (should) and the requirement to inspect and test other safety-critical equipment was not included within the rule.  In publishing the RFI, the agencies are requesting comments as to whether the mechanical integrity section should be revised “to explicitly apply the mechanical-integrity requirements of the PSM standard to all equipment that the employer identifies as critical to process safety.”  78 Fed. Reg. at .

Both agencies requested comment as to how employers or operators identified other equipment that was safety-critical.  78 Fed. Reg. at 73766 and 79 Fed. Reg. at 44617.   Whereas OSHA did not provide any suggestion as to what equipment could be affected, the EPA identified “additional types of equipment and systems that could reasonably be judged to be critical to process safety.”  79 Fed. Reg. at 44617.  Examples provided by the EPA “include computer software systems that interact with process components, electrical power systems, and other utility systems[1] that interact with pumps, valves, or control systems.” Id .

In response to the RFI, the CSB stated that PSM and RMP “should require companies to identify their safety-critical equipment/elements (“SCE”) and demonstrate to the regulator that each SCE has a performance standard that addresses functionality, availability, reliability, survivability, and other interactions with other systems as well as a verification scheme.”   CSB Comment to OSHA, p. 19 (Mar. 31, ) and CSB Comments to EPA, p 24 (Oct. 29, ).  Unfortunately the CSB does not provide any insight as to how a company should identify safety-critical equipment but instead effectively anticipates regulatory uncertainty by adding “the regulator could provide a list of common suggested SCE and/or criteria for what constitutes a SCE to assist the company in ensuring all SCE are identified and managed.”  Id .  Further, notwithstanding the open-ended scope, the CSB fails to describe how the “performance standard” suggestion differs from following RAGAGEP.[2]

While embracing the use of a list to identify the majority of safety-critical equipment, the MKOPSC believes that any list will likely be incomplete and miss some equipment that is critical to a specific process.  Whereas the MKOPSC believes that the list should be maintained, it asserts that safety-critical equipment should be defined to include “all equipment which [has] been identified through the [Process Hazard Analysis] as potential causes for catastrophic release of [a] hazardous chemical.”  MKOPSC Comments to OSHA at 35 (Mar. 31, ).

The AFPM expressed concern about having an open-ended mechanical integrity scope as “there is no general consensus among our members as to what safety-critical equipment consists of.”  AFPM Comments to EPA, Section IV (Oct. 29, ). Perhaps of most concern, without a functional definition of safety-critical that is neither vague nor ambiguous, “the phrase ‘safety-critical’ will be misused in the enforcement process to justify post-incident notice of violation.”  Id .  As a result, the AFPM commented that “if the EPA is aware of an existing hazard with certain pieces of equipment the Agency has deemed safety-critical, it should specify the equipment of concern and seek public comment on adding specific equipment to Sec. 68.73.” Id .

Interesting, the EPA separately notes that the mechanical integrity requirements apply specifically to emergency shutdown systems, “however, the regulation does not explicitly require that all covered sources install emergency shutdown systems.”  79 Fed. Reg. at 44617.  As a result the EPA requested comments as to whether the mechanical integrity section should be supplemented or clarified, presumably to require emergency shutdown systems.[3]  In response, the AFPM commented that “our members are very concerned that EPA is moving away from performance-based toward prescriptive regulations.”  AFPM at VI.  The CSB responded by encouraging the “EPA to specify situations where covered sources should be required to install emergency shutdown systems (and maintain them per the existing requirements in §68.73).”  CSB Comments to EPA at 24.  According to the CSB, in 2002, a release of 48,000 pounds of chlorine occurred due to a ruptured transfer hose that could have been minimized had the unloading facility been equipped with an emergency shutdown system. Id. at 24-25.  That said, in a 2007 “Safety Bulletin,” the CSB noted that the Chlorine Institute requires that its members install “remotely operated or automatically actuated emergency shutoff valves systems in place which can safety isolate both ends of the transfer hose/flexible piping.”[4]  The CSB also notes that “the Chlorine Institute members produce 98 percent of chlorine manufactured in the United States and Canada.”  Id .  No information was provided with the CSB comments as to the magnitude of any residual risk.[5]

In conclusion, both OSHA and the EPA requested comments regarding the scope of equipment that should be covered under the mechanical integrity regulations.  Although both agencies suggested an open-ended approach by seeking to cover all safety critical equipment, OSHA, the EPA, and the CSB (in their comments) did not provide any definitions or guidance to assist in identifying safety-critical equipment.  The EPA identified a few examples of equipment that could be safety-critical.  The AFPM commented that any additions to the list should be proposed and go through public comment.  Finally, the MKOPC suggested using the Process Hazard Analysis process to identify additional safety-critical equipment (beyond the enumerated list).

___________________________________________________

[1] Although silent within the RFI, OSHA has separately provided guidance concerning the applicability of PSM to utility systems:

It is OSHA s position that if an employer determines that a utility system or any aspect or part of a process which does not contain an HHC [highly hazardous chemical] but can affect or cause a release of HHC or interfere in the mitigation of the consequences of a release, then, relevant elements of PSM could apply to these aspects. OSHA s position is that any engineering control, including utility systems, which meets the above criteria must be, at a minimum, evaluated, designed, installed, operated (training and procedures), changed, and inspected/tested/maintained per OSHA PSM requirements. 

OSHA Guidance letter, Richard Fairfax, Director, to Howard Feldman (Jan. 31, ), found at https://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=INTERPRETATIONS p_id=27070 (last visited Apr. 9, 2015).

[2] The CSB suggests that safety-critical equipment should be tested and inspected in accordance with a performance standard.  This suggested performance standard addresses the functionality, availability, reliability, and survivability of the equipment.  Under the current rules, employers and operators test and inspect in accordance with procedures that follow RAGAGEP.  Typically, the RAGAGEP is based on an industry code and standard.  Presumably, these codes and standards are developed considering the same sort of considerations: functionality, reliability, etc.  Other codes and standards, such as construction RAGAGEP, may address design issues like survivability (i.e. specifying the amount and type of insulation required to survive a pool fire).  As such, the CSB’s comment may actually address another request in the RFI, i.e. requiring use of updated codes and standards in the design of existing equipment.

[3] It is curious that the EPA would use mechanical integrity requirements to require a process be constructed to a code or standard.  Such would be more consistent with process safety information requirements that equipment comply with RAGAGEP.  See 40 C.F.R. 68.65(d)(vi)and (viii) and (d)(2).  As such, the question posed by the EPA appears to be a back-door attempt to define RAGAGEP, a subject separately included in the RFI.  79 Fed. Reg. at 44617

www.csb.gov/assets/1/19/csbchlorineshutdownbulletin.pdf (last visited Apr. 10, 2015).

[5] The CSB specifically references The Chlorine Institute Pamphlets 85 as describing practices that are mandatory to its members as well as their customers.  As such, these should be considered a RAGAGEP.  Residual risk would either result from the failure of Chlorine Institute members (and their customers) to follow the cited industry practice or from non-members that fail to take the same precautions.

By Edward H. Warner and Daniela Suarez de los Santos

On Thursday, March 26, 2015, Petroleos Mexicanos (Mexico’s national oil company better known as Pemex), BlackRock Inc.. and First Reserve Corp announced a major investment project that will bring U.S. natural gas to central Mexico.  This $900 million USD transaction represents the first large scale infrastructure investment in Mexico since its energy sector was opened to foreign investors in .  The energy reform in Mexico means a new era of partnerships, foreign direct investment, and future success stories in the country.  Thus, the announcement last month is only the beginning.  The questions to consider are: what are the opportunities, what are the challenges, and how can U.S. companies make this groundbreaking change work for them?

Mexico’s energy reform: what’s changed, in layman’s terms?

Mexico’s robust oil and gas production industry is now open to foreign businesses through production contracts, service contracts, production-sharing, profit-sharing, and licenses. For nearly 75 years, Pemex controlled all petroleum production in the country due to the 1938 ban on private sector participation in the Mexican energy industry.  On December 21, , in one fell swoop, that all changed.  The Mexican congress approved and published the energy reform bill officially making the bill a law and drastically changing the Mexican energy sector.  Mexico’s congress further altered the legal framework of the energy industry by passing the Hydrocarbons Act and reforming the Foreign Investment Act.  While other laws and reforms were also passed, the Hydrocarbons Act and the Foreign Investment Act are the most prominent measures pertinent to U.S. oil and gas companies.  The energy reform allows foreign businesses to compete for projects and use their skills and capital for oil development within Mexico’s boarder.  Foreign businesses are required to bid on projects and Pemex is given the right of first refusal on projects aimed at developing Mexican resources.

Foreign investment: what’s in it for U.S. businesses?

U.S. companies can now partner with Pemex for energy projects if they have the experience and capital required for exploration in Mexico.  The Mexican National Hydrocarbons Commission (Comision Nacional de Hidrocarburos or CNH) and the Secretary of Energy set forth minimum requirements for private companies looking to invest in Mexico’s infrastructure.  Private companies can now look to CNH for information and published requirements on the system of “Rounds” that is being implemented.  The bidding process and prequalification criteria for Round One were published on December 11, .  The first round of public bidding for shallow-water fields is expected to conclude by mid-2015.  These lucrative contracts are expected to be awarded between May and September of 2015.

Local assessment: what are the challenges?

Foreign companies may have difficulty managing the different legal environment and the potential risks of partnering in a developing nation. These potential risks could include local dissent to the new energy reform and a still improving bureaucratic environment.  It is too early to determine the extent of effective contract enforcement for these state-private partnerships in the country.  Mexican government officials have commented that they will draw from the experience of countries such as Norway, Brazil and Columbia.  These countries have already implemented state-private partnership agreements.  Nevertheless, Mexico has shown tremendous improvement in its bureaucratic procedures for businesses operating in Mexico.  Mexico introduced a broad range of e-services to improve the efficiency of tax payments, online business registrations, and the securing of construction permits.  The new “e-government ” push aims to improve the submission of electronic documents and to strengthen the transparency of government operations in Mexico as a whole.  The e-government push could improve business operations, and potentially improve all infrastructure operations within the country.

Additional local partnerships: how can U.S companies use reputable local companies to help ease the process of integration?

Foreign companies must be in compliance with the new, government-mandated requirements in order to secure contract bids and ultimately fulfill those contracts.  Businesses may consider partnering with local companies for CNH compliance or bureaucratic procedures involving permits, tax payments, and business registrations.  For example, in the safety sector, companies like Cacer, S.A. de C.V. can help support foreign companies that are chosen to work with Pemex.  Cacer offers oil industry safety training and qualification services to companies conducting oil drilling in Mexico.  The offshore safety training company specifically works with foreign businesses to obtain the necessary certifications outlined by the new energy legislation bidding process, including the guidelines to work with Pemex.

In sum, both opportunities and challenges abound with these groundbreaking energy reforms in Mexico.  With the right planning and partnerships, hopefully the collaboration between Pemex, BlackRock Inc. and First Reserve Corp. will be the first of many opportunities where foreign businesses and Mexican companies work together in this new era.

______________________________________________________

If you wish to view an English translation of the Mexican energy reform decree, you may do so at the link here .

For more information or translation of the Spanish language links contained in this article, please contact Edward H. Warner .

About the authors: Edward Warner is an associate in the Baton Rouge office of Kean Miller. He has legal experience in both Central and South America and is fluent in Spanish. Edward joined the firm in and practices in the business, corporate and real estate groups. He represents clients in a variety of corporate, finance, and commercial real estate transactions.  Daniela Suarez de los Santos is a Mexican attorney at law.  She graduated with honors from the Universidad Cristobal Colon in Veracruz, Mexico in .

By Steven Boutwell on April 7, 2015 Posted in Process Safety Management

The Occupational Safety and Health Administration (“OSHA”) published a Request for Information (“RFI”)  on December 9, concerning possible changes to the Process Safety Management (“PSM”) program codified at 29 C.F.R. 1910.119.  See 78 Fed. Reg. 73756 (Dec. 9, ).  Likewise, the Environmental Protection Agency (“EPA”) published an RFI on July 31, relating to possible changes to the similar Risk Management Program (“RMP”) rules codified at 40 C.F.R. Part 68.  See 79 Fed. Reg. 44604 (July 31, ).  At the time of this writing, the respective comment periods have closed and we are waiting to see new proposed regulations. This is the fifth article in a series of articles concerning these potential rulemaking actions.

OSHA and the EPA requested comments concerning revising the audit requirements in PSM and RMP to require third-party audits.  Comments received by OSHA and the EPA requests were similar in nature.  Although many comments addressed third-party audits, this article will compare comments from four organizations:  The American Fuel Petrochemical Manufactures (AFPM), the American Petroleum Institute (“API”), the Mary Kay O’Conner Process Safety Center (“MKOPSC”) at the Texas A M Engineering Experimental Station, and the U.S. Chemical Safety Board (“CSB”).

Compliance audits are required for Program 2 and 3 RMP facilities.  See 40 CFR 68.58 and 68.79.  Likewise, compliance audits are required under PSM.  See 29 CFR 1910.119(o).  Both programs provide a single minimal requirement for the audit team: “at least one person knowledgeable in the process.”  29 CFR 1910.119(o)(2) and 40 CFR 68.58 (b) and 68.79(b). In requesting comments related to adding a third-party audit requirement, both OSHA and the EPA provide the same information: highest degree of objectivity, Bureau of Safety and Environmental Enforcement (“BSEE”) rules,[1] and CSB’s findings[2] in the BP Texas City incident.  See 78 Fed. Reg. at 73762 and 79 Fed. Reg. at 44618.

Whereas the CSB generally supported requiring third-party audits, several concerns were expressed.  The CSB remarked that such should not reduce any on-going inspection and auditing.[3]  The CSB also remarked that third parties may not in reality be completely objective.  As a result of this later concern, the CSB expresses concern that the addition of a third party auditing requirement may diminish OSHA oversight by “contracting out what it should be doing as a regulator.”  See CSB Comments to OSHA, pp. 22-23 (Mar. 31, ) and CSB Comments to EPA, pp. 26-27 (Oct. 29, ).

The MKOPSC seemed to be more concerned that the audit be led by an accredited auditor.  Consistent with such, an “auditor should have worked in PSM-related activities or have considerable years of experience in PSM-related work” and an “auditor should have undergone formal and recognized training on PSM audit procedures.”  MKOPSC comments to OSHA, p. 46 (Mar. 31, ).  Without making a specific recommendation, the MKOPSC provided a list of advantages and disadvantages related to requiring an audit by a third-party.  The advantages included:

1.  Third party auditors introduce an external view.  It is expected that third party audits are even more objective and less biased than any internal First or Second Party Audits.

2. The potential for greater subject matter expertise exists with a third party auditor compared to internal audits; thus resulting in quality output.

3.  The facility is bound to respond quickly and effectively to the audit recommendations due to the higher profile that is created with the incorporation of third party audits.

Id. at 48.

The disadvantages include:

1.  Third party audits can be expensive and not all facilities can afford this.

2.  By their very nature, third party audits do not allow for development and maturity of a company’s own audit program, steeped in first-hand and in-depth knowledge of internal processes (including technical and chemical process), and operational and managerial systems.

3.  Contentious discussion over specific findings and recommendations can consume valuable time and test the relationship between auditors and those being audited.

4.  Third party auditors may not be familiar with the facility’s culture, technology, or corporate standards and site procedures.

5.  Third party auditors can lose their objectivity over time and fail to identify lapses.  This was seen in the financial community where auditors become financially dependent upon those they audit.[4]

Id. at 48-49

In opposing the requirement to require third-party audits, the API and AFPM stated that OSHA had failed to provide any documentation showing a causal relationship between the failure to use third party auditors and PSM auditing failures.  API Comments to OSHA, p.12. (Mar. 31, ) and AFPM Comments to EPA, third page (Sec. VI) (Oct. 29, ). Without showing a causal relationship, there is no way to say that a requirement to use third-party auditors would improve safety.  The API suggested “that it is more important for OSHA to focus on the audit program/requirements and the quality and competency of the auditors.”[5]  API at 13.  Collectively, comments from the API and AFPM state that internal personnel are better suited to auditing for a number of reasons:  the company’s auditor’s intimate knowledge of the organization and how it functions and the process-related experience of those familiar with the varied processes. Finally, according to the AFPM, “the problem is not with the auditors but, rather the failure to implement many audit findings.”  AFPM at second page (Sec VI).  The AFPM also believes that the BP Incident is an outlier and should not be used to reflect the industry’s approach as a whole.  AFPM at third page (Sec. VI).

Whereas an audit by a third-party has its advantages, according to the comments made to the proposition, it has its disadvantages.  Comments point out that the use of third-party auditors, by itself, did not prevent problems within financial audits as there is a difference between being a third party and being completely independent.  Many parties believe that the emphasis should be on assuring that auditors are properly trained and accredited.  That said, both the API and AFPM expressed concern about the current supply of qualified and accredited third-party auditors.  Conversely, the CSB believes that the best approach is to have more direct auditing performed by the regulators.  At some point OSHA and the EPA will propose rules that reflect their balance of the pros and cons.

____________________________________________________

[1] Oil and gas and sulfur operations which occur in the outer continental shelf comply with a similar but different process safety type program:  Safety and Environmental Management Systems (“SEMS”).  The lead person of a SEMS audit must be “an employee, representative, or agent of the ASP, and must not have any affiliation with the operator.” 30 C.F.R. 250.1920.  Unlike PSM and RMP, an operator must submit a Corrective Action Plan (“CAP”) to BSEE following each audit.  See 30 C.F.R. 250.1920(d).

www.csb.gov/assets/1/19/csbfinalreportbp.pdf (last visited Apr. 7, 2015).

[3] It should be noted that PSM and RMP have inspection requirements that are independent of the auditing requirements.  That said, the audit should ascertain whether the employer or operator is properly inspecting equipment.  Neither PSM or RMP have any requirement to audit facilities directly on a consistent basis.

[4] This comment is consistent with concerns expressed by the CSB that auditors may not be completely objective.

[5] By comparison to BSEE rules, an Audit Service Provider (“ASP”) must be accredited by a BSEE-approved Accreditation Body (“AB”).  See 30 C.F.R. 250.1921(b). 

The Occupational Safety and Health Administration (“OSHA”) published a Request for Information (“RFI”)  on December 9, concerning possible changes to the Process Safety Management (“PSM”) program codified at 29 C.F.R. 1910.119.  See 78 Fed. Reg. 73756 (Dec. 9, ).  Likewise, the Environmental Protection Agency (“EPA”) published an RFI on July 31, relating to possible changes to the similar Risk Management Program (“RMP”) rules codified at 40 C.F.R. Part 68.  See 79 Fed. Reg. 44604 (July 31, ).  At the time of this writing, the respective comment periods have closed and we are waiting to see new proposed regulations. This is the fourth article in a series of articles concerning these potential rulemaking actions.

OSHA and the EPA requested comments concerning applying PSM and RMP regulation to the Oil and Gas Sector.  Comments received by OSHA and the EPA requests were similar in nature. Separate questions were asked in reference to Oil and Gas Well Drilling and Servicing (hereafter “Drilling/Servicing”) and Oil and Gas Production Facilities (hereafter “Production Facilities”).  Although many comments addressed regulations of these two oil and gas sectors, this article will compare comments from four organizations:  the Domestic Energy Producers Alliance (“DEPA”), the American Petroleum Institute (“API”), the Mary Kay O’Conner Process Safety Center (“MKOPSC”) at the Texas A M Engineering Experimental Station, and the U.S. Chemical Safety Board (“CSB”).

Although the EPA and OSHA arrived at approximately the same point concerning the current regulation of the Oil and Gas Industry, they each arrived there in a different manner.  As such, EPA’s basis for excluding much of the oil and gas sector is somewhat different from OSHA’s basis.  Generally speaking, these two agencies initiate jurisdiction at a gas plant not otherwise regulated by pipeline safety agencies.[1] RMP begins at a gas plant as that is where the naturally occurring hydrocarbon exemption ends. See 40 C.F.R 68.115(b)(2)(iii).  Although not explicit in the rule, subsequent determinations indicate that “OSHA believes that gas plants are appropriately covered by the process safety management standard.”[2]  Gas plants are facilities that remove natural gas liquids (ethane, propane, butanes, and pentanes)[3] from natural gas (methane):

Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both, classified as North American Industrial Classification System (NAICS) code 211112 (previously Standard Industrial Classification (SIC) code 1321).

40 C.F.R 68.3

RMP regulation is limited to “stationary sources” and thereby excludes transportation facilities, including storage incident to transportation.  See 40 C.F.R. 68.3.  Additionally, naturally occurring hydrocarbons upstream of a natural gas processing plant or petroleum refinery are not considered when determining if a facility contains a threshold inventory.  “Naturally occurring hydrocarbon mixtures include any combination of the following: condensate, crude oil, field gas, and produced water.”  40 C.F.R. 68.115(b)(2)(iii).  Flammable materials that are heavier than pentane (hexane and heavier) are not covered by the rule. As a result, RMP does not currently apply to much of the oil gas sector.

OSHA likewise exempts facilities that fall under Department of Transportation jurisdiction.  See, 57 Fed. Reg. 6356, 6372 (Feb. 24, 1992).  Other OSHA exemptions interrelate with the subject exclusions:  the atmospheric storage tank exemption and the remote facility exemption.  See 29 C.F.R. 1910.119(a)(1)(ii)(B) and (2)(iii).  Often the greatest quantity of flammable materials (condensates or crude oil) at oil and gas facilities is stored in atmospheric tanks.  Similarly, many oil and gas facilities are remote and normally unoccupied.

PSM specifically exempts oil or gas well drilling or servicing operations.  See 29 C.F.R.119(a)(2)(ii).  OSHA exempted this sector because OSHA “believe[d] that oil and gas well drilling and servicing operations should be covered in a standard designed to address the uniqueness of that industry.”  57 Fed. Reg. at 6369.  At the time of promulgating the 1992 rule, OSHA stated it planned to follow through with a proposed Well Drilling and Servicing rule: this never occurred.[4]   The 1983 proposal focused on unique drilling/servicing concerns (rig siting, emergency escape, safe handling of drilling fluids, respiratory protection for hydrogen sulfide, confined space as in cellars or pits, etc.) and did not contain PSM type elements.

According to RFI, OSHA always intended PSM to cover oil and gas processing facilities.  78 Fed. Reg. at 73758-59. Specifically, in 1999, OSHA informed Regional Administrator of the intent to enforce PSM at oil and gas production facilities. According to the December 1999 memo, OSHA believes that a covered process starts at the top of the well (i.e. upstream of the Christmas tree).[5]  Subsequent to a challenge from the API, OSHA withdrew its determination until such time that they conducted an economic analysis to support rule making.[6] To wit, as part of the RFI, “the Agency requests public comment on completing an economic analysis and possibly resuming enforcement for PSM-covered oil and gas production facilities.”  78 Fed. Reg. at 73759.  Although the distinction is fine, subsequent determinations indicate that “OSHA believes that gas plants are appropriately covered by the process safety management standard.”[7]

The CSB combined comments for the Production Facilities and Drilling/Servicing sectors into a single response.  In providing its comments, the CSB provided four examples of incidents that it investigated.  A summary of an incident that occurred over sixteen years ago (Sonat Exploration Company) was repeated in the RFI.  According to the CSB, the incident occurred while purging air out of a pipeline between the well and the newly constructed separation facility.  See CSB Investigation Report, Catastrophic Vessel Overpressurization, Report No. 1998-002-I-LA. p. 2 (Sept. 21, 2000). Ultimately, the incident occurred due to the failure to maintain an open path to the atmosphere (valves intended to be open were instead closed) resulting in overpressuring equipment.  Id. at 21.  The CSB concluded that the incident could have been prevented by conducting pre-construction hazard analysis, inclusion of overpressure protection, and better operating procedures. Id. at 33-34.

The other three incidents cited were related to “hot work” errors.  Hot work practices include welding, cutting, and brazing and are regulated by OSHA at 29 CFR 1910.252.  Interestingly, the only substantive comment made by the CSB concerning the Drilling/Servicing sector involved hot work.

One ubiquitous hazard that the CSB has encountered in the Oil and Gas Well Drilling and Servicing facilities is hot work type activities where explosions and fires occur from the ignition of flammable vapors in a confined area, such as a tank, typically during maintenance.[8]

CSB Comments to OSHA, p. 5.

In addition the CSB reviewed media reports over a five year period.  Based on this review, the CSB concluded that approximately 8% of “high consequence” incidents occurred in the oil and gas sector. The CSB’s comments fail to define the nature of the data set (8% of what), nor any indicator to rationalize the observation (number of workers, hours worked, portion of the economy, etc), nor any indication that the incidents were related to process safety issues.  Although the CSB appears to conclude that 8% was significant, the CSB did not provide any information that indicated that 8% was statistically significant compared to other similar sectors of the economy.  It should also be noted that the CSB did not review the incidents beyond the information provided in the media reports.  Finally, at least one of the oil and gas sectors included, natural gas liquid extraction, may be already regulated under PSM and RMP and some of the pipeline incidents counted may be regulated under pipeline safety rules.  As such, the numerator of the faction may include regulated and unregulated facilities.

According to the DEPA, exploration and production (“E P”) activities are not the type of activity intended to be regulated by PSM or RMP.  The DEPA points to the legislative history of the Clean Air Act Amendments of 1990 noting that “oil and gas wells, and associated equipment and gas processing, have generally very low levels of air toxics” and that “it is very unlikely that oil and gas sources would present a significant risk to human health.”  DEPA Comments to OSHA, p. 2 (Mar. 31, ).  The DEPA also cites OSHA’s prior determination that Drilling/Servicing activities are unique and concludes that if anything “E P drilling and servicing operations are even more unique today” and that OSHA should preserve the exemption.

The DEPA then extrapolates the uniqueness argument to Production Facilities noting that there are over a million oil and gas wells across the country that are “inherently variable (to address the unique factors associated with each different well)”  compared to a relatively limited number of chemical plants.  See DEPA comment to OSHA, p. 3.  The DEPA further cites that in contrast to chemical plants, that “E P operations pose only a negligible risk of catastrophic release.”  Id.  Finally, “the already negligible risk of a catastrophic release is further dismissed by the fact that personnel engaged in production operations are very rarely permanently stationed at a particular oil and/or gas well in the same way that personnel who work in other industrial sectors.” Id.

The API submitted separated comments relative to the Drilling/Servicing and Production Facilities sectors.  Comments from the API concerning Drilling/Servicing fall into two main areas:  lack of sufficient data and the sector does not involve a process.  Specifically according to the API:

Since oil and gas well drilling or servicing operations are transient (temporary), are inherently variable (to address unique factors associated with each well) and are not “processes” that typically handle covered substances, they are not the type of operation intended to be regulated under the PSM standard.

API comments to OSHA, p. 6 (Mar. 31, ).

The API also believes that:

OSHA has not provided sufficient data or evidence that onshore exploration facilities and related servicing activities have experienced a significant number of catastrophic releases of the type that the PSM standard is meant to address.  There is little performance data showing there is a safety problem at these facilities.  The risk is not high and the safety incidents are not process safety problems but are more occupational safety and thus covered by other regulatio

As discussed previously, OSHA does not currently enforce PSM regulations in Production Facilities (excepting gas plants).  OSHA reversed its intention to enforce PSM at Production Facilities in response to a 2000 letter from the API that it still feels is relevant.  “API’s position on oil and gas production coverage was well-defined in our 2000 letter to OSHA.”  API comments to OSHA, p. 7.  Further, the API believes that process safety risk in Production Facilities is low and that regulatory cost would exceed the benefit.  Finally, the API recommends that OSHA concentrate on using its “existing regulation, enforcement actions, safety alerts, operator education, etc. to support enhanced oil and gas production facility sector-specific safety performance.”  Id. 

The MKOPSC provided data that indicated that oil and gas worker fatalities were significantly higher (per hour worked) than the Chemical Manufacturing[9] sector, however the data also indicated that oil and gas related fatalities were far more likely to be caused by non-PSM/RMP type incidents.  As indicated below, four-out-of-five oil and gas related fatalities were caused by incidents not related to flammable or toxic materials.  Presumably many of these non-PSM issues were addressed by the rule proposed back in 1983.



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