The current business climate is strong, with a positive outlook for the foreseeable future. Existing shale plays are being optimized, new shale plays are being discovered and developed, mergers and acquisition activity is heating up, and new infrastructure is being planned and put on the ground—not to mention record processing margins. However, midstream companies still face significant legal and regulatory issues that can have an unexpected impact on the bottom line.

Each midstream company has its own unique set of risks ranging from new or expanded regulatory requirements to multimillion-dollar lawsuits. Energy consulting firms can provide some practical insight as to what some of these issues are and, more importantly, can identify steps that companies should take to minimize the impact and costs associated with these issues.

Pipeline safety

Increased scrutiny from public and governmental agencies regarding pipeline safety is expected as a result of such incidents as Pacific Gas and Electric Corp.'s (PG&E) gas pipeline explosion in San Bruno, California, the BP Plc oil spill in the Gulf of Mexico and the oil pipeline leak in Michigan.

While the number of pipeline incidents reported by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) has remained relatively steady, yearly property damage costs have reached close to a billion dollars in recent years (see Figure 1).

Yearly property damage costs have reached close to a billion dollars in recent years.

The multimillion-dollar fine faced by PG&E from California state regulators over issues related to lack of proper pipeline records has captured the attention of pipeline owners across the country, and is raising some important issues that could impact all pipeline owners. One of the triggering events was the discovery that the records maintained by the operator showed the pipe to be seamless, when in fact the pipe involved in the rupture was longitudinal-welded pipe with varying segment lengths and weld types.

PG&E was required to conduct a thorough review of its records to ensure that all segments of its pipeline system have "traceable, verifiable, and complete records" to determine the valid, maximum-allowable operating pressure (MAOP). PG&E's response to this directive was not satisfactory to the regulators, which subsequently fined the company.

To establish a pipeline's MAOP, the Department of Transportation (DOT) regulations (Title 49 CFR Part 192 and 195) require one of three methods: 1) a hydrotest, 2) calculate MAOP based on design, construction, inspection, testing and other records, or 3) for older pipelines, historical operating pressures can be used as a basis for establishing MAOP (grandfathering).

PG&E relied on its construction records to calculate the MAOP for the pipeline in the area of the San Bruno explosion. The company's records were discovered to be inaccurate and were not complete for a significant portion of its pipeline system.

Federal regulators, including the National Transportation Safety Board (NTSB) and PHMSA, are urging all pipeline owners to diligently scrutinize the effectiveness of their pipeline integrity management (IM) programs, including a thorough review of their pipeline records for accuracy and completeness.

Increasingly, pipeline owners are no longer relying on calculations from unreliable records or historical operating pressures of a pipeline as a basis for establishing MAOPs. Also, pipeline companies could be required to conduct hydrotests on high-risk segments of their pipeline systems that do not have complete, traceable and verifiable records for establishing MAOP.

In its recent advisories, the NTSB indicated that regulators are observing oversights, discrepancies and inconsistencies in pipeline owners' IM programs. Pipeline owners should be continually reviewing their IM programs to ensure they not only meet the minimum requirements, but that they are taking extra measures in high-risk areas.

Pipeline owners should be actively engaged with regulating agencies to ensure they are complying with existing requirements and are aware of pending changes to pipeline safety requirements. Owners also need to keep abreast of industry best practices related to pipeline IM and consider hiring third parties to conduct independent assessments.

The federal DOT regulations referenced above primarily apply to hazardous liquid and natural gas pipelines involved in interstate transmission and those located in high-consequence areas. Legislation has been introduced that would expand current federal regulations to include low-risk, rural pipelines, including well-gathering systems, which could impose significant costs for midstream companies and a huge administrative burden on PHMSA.

Engine emissions

Elsewhere, two federal regulatory rules related to air emissions that are having a significant impact on midstream companies include the Greenhouse Gas (GHG) Mandatory Reporting rule and recently promulgated emissions standards for reciprocating internal combustion engines (RICE).

As a result, owners of gas-processing and compression facilities will face additional data collection, testing, monitoring and reporting requirements, as well as higher operating and equipment costs.

The Environmental Protection Agency (EPA) issued a Final Rule on August 20, 2010, setting forth National Emissions Standards for Hazardous Air Pollutants (NESHAP) for RICE. The rule establishes numerical emission limits and other requirements for existing stationary spark-ignited reciprocating engines less than 500 horsepower (HP) if located at major sources, and all reciprocating engines at area sources, defined as any area that is not a major source.

Through its rule-making process, the EPA determined that limiting carbon-monoxide and formaldehyde emissions from reciprocating engines would be effective in regulating the discharge of hazardous air pollutants as required by the Clean Air Act.

While companies that operate reciprocating engines need to review the specifics of the NESHAP RICE Final Rule for applicability, the rules generally apply to existing spark-ignited reciprocating engines, two- and four-stroke engines, lean- and rich-burn engines, engines rated

Although the specific requirements vary, depending on engine size, location and use, owners might be required to conduct an initial emissions-performance test to demonstrate they are meeting the specific numerical emission standards. For larger four-stroke engines (>500 HP), performance tests will be required every 8,760 hours of operation, or every three years, in addition to the initial test. These performance tests are in addition to the monitoring, record-keeping and reporting requirements.

Given the number of reciprocating engines used in the midstream industry at field compression sites, gas-processing and treating plants, pipeline-compressor and pump stations along with the applicability of the rule to relatively small engines, the amount of emission testing, monitoring, data collection, and reporting will require significant effort on the part of all operators.

For engines that do not meet the emission requirements, additional costs could be incurred to install additional instrumentation and control technologies, such as oxidation catalysts, or to replace the engine.

In recent years, EBITDA multiples for midstream transactions have been on the rise.

Midstream companies that own and operate reciprocating engines will need to take steps to ensure compliance with the new RICE NESHAP rules. Such compliance measures could include conducting company-wide inventory of reciprocating engine units, determining applicability of RICE NESHAP requirements to existing engines, developing action plans for each site, system or region and assigning responsibilities for implementation of actions, identifying engine monitoring and emission-testing requirements, and discussing emission testing and retrofit options with equipment manufacturers and environmental specialists.

In addition to these implementation steps, midstream companies should closely monitor activities at the federal level regarding RICE NESHAP regulations. The Gas Processors Association (GPA) and other industry groups recently filed suit against the EPA, challenging certain aspects of the rules, including continuous-monitoring requirements and applicability to existing engines at smaller and remote locations.

Industry and the EPA are continuing to have positive discussions that could lead to modifications and/or clarifications to the RICE NESHAP rules. Companies should stay informed through their environmental, safety and health representatives and through industry groups such as the GPA.

Construction disputes

The midstream industry is in the midst of a boom in building new infrastructure and expanding existing facilities to handle gas and liquids production from new shale plays and existing fields.

In a quest to provide needed services to upstream producers, midstream companies are increasingly facing pressure to offer a complete range of services and build infrastructure to secure those customer commitments. The pressure is on those companies to get projects from the concept stage to the field as fast as possible. Subsequently, more pressure is put on engineering firms, construction companies and equipment suppliers.

The pressure to get pipelines and processing facilities built can often result in work scope, cost estimates and schedules that are not adequately developed prior to sanctioning, leading to cost and schedule overruns, quality issues and systems that don't work as intended.

Disputes can result between owners or operators and their contractors, and can often lead to costly arbitrations or lawsuits. Some practical steps can be followed to avoid getting involved in construction disputes.

First, it is important to ensure that sufficient planning and scoping of a project is completed prior to entering into a construction contract. Although this seems obvious, it is often the case that plans are not completely vetted or changes must be made to meet business needs. Smaller companies or those with limited engineering resources should hire third-party engineering firms to prepare a complete set of drawings, specifications, schedules and estimates before any significant construction begins.

The contract for facility construction should be compatible with the degree of planning and scope definition. Using a fixed-price engineering-procurement-construction contract for a project that is not sufficiently scoped will lead to numerous and costly change orders and schedule delays. A reimbursable contract might be better suited for a fast-track project; however, additional company resources will be required to monitor and control the contractor's work.

Another critical but often overlooked aspect is to ensure that project managers not only read the contract but also follow all of its provisions, particularly those related to notices, communications and approvals.

Also, clearly defined dispute-resolution clauses should be included in contracts, in the event of a construction dispute. A typical clause might entail senior-management consultation, third-party mediation, independent experts and technical auditors, binding arbitration or civil litigation.

Property-tax valuations

Not only is the midstream business building new infrastructure, but merger and acquisition activity is also heating up (see Midstream Business, March 2011). The cost for building new facilities and acquiring existing facilities continues to increase. Figure 2 shows the trend in EBITDA multiples for midstream transactions for the past five years.

With the "great recession" of 2008 still having impacts on state and local budgets, taxing authorities are facing increasing pressure to at least maintain, if not increase, their tax revenues. A major source of tax revenues for counties, municipalities and school districts is ad valorem taxes such as property tax. Newly installed facilities or recently purchased assets will be subject to increasing property-tax valuations.

Appraisers are required to consider three methods when appraising the market value of properties, including tangible assets such as land, buildings, machinery and equipment.

The three methods include a cost approach (depreciated replacement cost of the property), an income approach (present value of future economic benefits) and a market approach (sales of comparable properties). Appraisers use their experience and judgment when considering each approach and in the relative weighting when determining a market value for the property.

Installed costs for newly constructed facilities and purchase costs for recently acquired assets, in most cases, will be a significant part of an appraisal. Companies facing annual appraised-value updates or appraisals of new facilities should work closely with their local taxing authorities to ensure the appraisers have a complete understanding of the assets being valued, including all factors that might influence the market value of a property.

If an appraiser determines a value that is higher than expected, it is completely reasonable for the appraiser to be asked to fully explain the methodology and basis used. If a company does not agree with the appraised value, an appeal process or review board should be formed for reconsideration. To appeal an appraisal, a company should prepare and present their own market value assessment, taking into account all applicable methods. If owners and taxing authorities remain far apart on valuation, companies might have to consider the high costs and inherent risks of litigation.

Well-defined terms

Exposure to construction disputes and property valuations can ebb and flow with economic conditions, and regulatory risks often change in response to high-profile safety or environmental incidents.

Other risks facing midstream companies that are not directly linked to the business cycle or new regulatory initiatives are disputes involving gas-processing contracts. These disputes can be between a processor and producer or involve a processor indirectly via a lawsuit by royalty owners against a producer.

Processing contract disputes often arise from the use of generalized, and sometimes confusing, definitions and terms that are contained in both legacy and more recent contracts.

When drafting and negotiating a natural gas purchase or processing contract, it's necessary to think beyond an apparently simple definition, and consider the physical and commercial characteristics of the hydrocarbon or equipment being described.

In the broadest sense, processing is any physical or chemical handling of natural gas, including compression, dehydration, sweetening and liquids extraction. In a narrower definition, processing can be strictly the extraction of liquefiable components from the natural gas stream. The definition of processing has serious implications should later disputes arise over sharing of multiple products and processing costs that might be deducted from revenues.

Condensate has multiple definitions. It can be retrograde condensate produced at the wellhead. Also, it can be pipeline condensate, drip condensate, compression liquids or a gas plant product. The wide-ranging definitions of condensate illustrate the contractual need for understanding the specific characteristics of each natural gas and natural gas liquid (NGL) stream. A more precise definition can avoid later confusion over contractual liquids due the producer.

Perhaps not surprisingly, a plant can mean something entirely different to an accountant, an engineer and a lawyer. Defining a plant as simply all improvements existing on a surveyed plot of land might not be adequate. Processing contracts often have different sharing arrangements for NGLs recovered as plant product versus liquids recovered in field compression facilities or inlet separators.

One potential solution is to define the plant as only selected chemical and thermodynamic processes or very specific equipment. Often, a processing area can be defined by identifying specific pipe flanges at a facility, thus determining exactly where the plant, and thus the processing, begins and ends.

Well-defined products and revenue streams in a processing contract provide a clearer basis for valuation of products and monthly settlement of processing revenues. Well-defined terms, as simple as those identified above, will help avoid disputes between processors and their customers over allocation or sharing of products from gathering and processing contracts.

Deregulation

Another issue related to processing contracts that can affect midstream companies is disputes between producers and royalty owners. Deregulation in the gas industry has moved transactions away from the wellhead, and the evolution of market-trading centers has led to greater transparency in market-price information.

In fact, some royalty owners, seeing higher prices downstream at market-trading centers than those at the wellhead in the field, have sued, seeking royalties on downstream prices rather than on the wellhead value.

While the deduction of associated gathering and processing costs is logical, the producer's ability to deduct these costs from royalty can depend on applicable state law.

Also, while contractual disputes among producers, processors and royalty owners are not likely to go away, better definitions of common industry terms and contracts tailored to system-specific characteristics should help minimize processing contract disputes.