With the well-known advances in hydraulic fracturing that have occurred, natural gas production volumes in the U.S. experienced a noticeable increase since 2006. In spite of a steady decrease in volumes over the past decade, natural gas production on public lands still con- stitutes a significant portion of total production in the U.S.

Data from the U.S. Energy Information Administration show that of the 30 trillion cubic feet (Tcf) of natural gas produced in the U.S. in 2013, about 4.08 Tcf, 13.6%, were produced on federal and Indian lands.

For the right to extract natural gas, E&P companies pay royalties to the owners of public lands: the federal government, state governments and tribal governments.

Royalty payments are a major source of revenue for these landowners. After income taxes, royalties on resource development are the largest source of revenue to the federal government. For many state and tribal governments, royalty payments are an important source of revenue for supporting government services and maintaining infrastructure.

Reporting of production volumes, sales and royalty payments is carefully scrutinized by both the leasee and leasor to ensure that the correct figures are being reported and proper royalty payments are being made. Not surprisingly, disagreements and conflicts arise, often resulting in legal action. One area that has garnered significant attention for a number of years involves the deduction from royalty payments of transportation and processing costs incurred by the producer. When determining which costs can be deducted for federal royalty purposes, producers must consider the marketable condition requirements (MCR) and associated unbundling of midstream costs.

Administration, regulation of royalties

Created in 1982, the U.S. Minerals Management Service (MMS) was established to facilitate mineral revenue collection and manage the Outer Continental Shelf offshore lands. In order to resolve conflicts arising from its conflicting missions of promoting resource development, enforcing safety regulations, and maximizing revenues, the MMS was eventually reorganized into three federal agencies in 2010: the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement and the Office of Natural Resources Revenue (ONRR).

The ONRR is now responsible for managing revenue from energy and mineral leases. It is entrusted with a fiduciary role, managing an average of $11 billion in annual revenues from energy and mineral leases and other monies owed for the use of public natural resources on the Outer Continental Shelf and onshore Federal and American Indian lands. Revenue sources include royalties, rents and bonuses generated throughout the life of the lease.

The ONRR provides guidance for valuation based on regulations specified at Title 30 Code of Federal Regulations (CFR), Chapter XII—Office of Natural Resources Revenue, Department of the Interior, Subchapter A—Natural Resource Revenue. The most relevant in- formation can be found in:
• Part 1202—Royalties;
• Part 1203—Relief or Reduction in Royalty Rates; and
• Part 1206—Production Valuation.

The ONRR also publishes the Oil and Gas Payor Handbook, Volume III—Product Valuation, which contains detailed royalty valuation procedures for federal and Indian oil and natural gas production, including information on allowances that can be deducted from royalty payments. Examples are included for calculating valuations, deter- mining allowances and completing the relevant forms.

Royalty rates and allowances

The royalty rates for natural gas production can vary depending on the owner of the land. Onshore federal production has a royalty rate of 12.5% (1/8 interest). Offshore federal production royalty rates vary by depth and location, but new leases typically have a royalty rate of 16.67% (1/6 interest) to 18.75% (3/16 interest). Royalty rates for production on state lands typically range from 16.67% to 18.75%.

The actual royalty paid as a percentage of sales will not always equate to the royalty rate for a particular source. For instance, data available from the ONRR website show that approximately $2.1 billion in royalties were collected by the ONRR in 2013 for production of natural gas and NGL on federal lands. Based on total reported sales $18.9 billion, the effective royalty rate is 11.1%, which is less than both the onshore (12.5%) and offshore (18.75%) royalty rates.

The reduced royalty payment is at least partially attributable to transportation and processing cost deductions referred to as allowances as stipulated in the regulations. 30 C.F.R. 1206.152(a)(2)—unprocessed
gas—and 30 C.F.R. 1206.153(b)—processed gas—state the following, respectively:

“The value of production, for royalty purposes, of gas subject to this subpart shall be the value of gas determined under this section less applicable allowances….” and “The value of produc- tion, for royalty purposes, of gas subject to this section shall be the combined value of the residue gas and all gas plant products … plus the value of any con- densate recovered downstream of the point of royalty settlement … less applicable transportation allowances and processing allowances …, respectively, for unprocessed and processed gas.”

In accordance with federal regulations, producers must place the gas in marketable condition prior to taking any allowances. Regulations 30 C.F.R. 1206.152(i) and 30 C.F.R. 1206.153(i) state the following, respectively: “The lessee must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government,” and “The lessee must place residue gas and gas plant prod- ucts in marketable condition and market the residue gas and gas plant products for the mutual benefit of the lessee and the lessor at no cost to the Federal Government.”

This requirement is referred to as the Marketable Condition Rule. Marketable condition is defined in 30 C.F.R. 1206.151 as: “Marketable condition means lease products which are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area.”

A subjective debate

What constitutes placing gas in mar- ketable condition and a sales contract typical for a field or area can be subjec- tive and has been and continues to be debated between producers and the ONRR.

Using several historical court cases for support, the ONRR has deemed that the marketable condition requirements are typically the operating conditions and specifications of the mainline pipeline(s) downstream of the transportation and processing systems. Thus, natural gas must meet the mainline pipeline requirements for pressure and product quality, such as carbon dioxide, hydrogen sulfide and water before it is considered marketable.

Meeting the various mainline pipeline specifications requires multiple functions, such as dehydration (water content), amine treating (carbon dioxide and hydrogen sulfide content), and compression (pressure). However, the marketable condition need only be met once. Thus if, for instance, the pressure of a natural gas stream is increased to the downstream mainline pipeline, it has met marketable condition, and all subsequent compression to regain pressure lost to pipeline pressure drop is an allowable deduction, even if the pressure of the natural gas stream drops below the mainline pressure.

As with many rules, there are exceptions. Residue gas “boosting” is not an allowable deduction per the regulations (30 C.F.R. 1202.151(b)). The residue gas recompressor typically found in an NGL extraction plant that utilizes turboexpander technology has been labeled by the ONRR as “boosting.” Subsequently, even if the inlet gas to the gas processing facility has already achieved marketable condition for pressure, the residue recompressor is not considered an allowable deduction.

Midstream’s role

For many producers, these post-production functions are performed by midstream companies. The various regulations and ONRR guidelines govern what transportation and processing deductions are allowable, thus requiring the producer to understand the various services being provided and their associated costs.

Unfortunately for the producer, several if not all of these functions are often assessed as a single fee, such as a percent-of-proceeds or a fixed fee. Thus the producer is forced to either not take any transportation and processing allowances or calcu- late an unbundled cost allocation (UCA) by unbundling the fee into various functions.

The ONRR has already unbundled several New Mexico transportation and processing systems and has published the UCAs on its website. The agency worked with several midstream companies directly over the past several years to obtain data in order to calcu- late these UCAs. Producers can elect to use the UCAs published by the ONRR or do their own unbundling.

The ONRR is continuing to calculate UCAs for other midstream systems that transport and process natural gas produced on federal and Indian lands. A tentative list of systems it is working on for 2015 was provided during the Federal & Indian Royalty Compliance Workshop in Tulsa, Okla. The ONRR is in the process of validating and imple- menting an engineering solution using sophisticated computer modeling tools commonly used in the industry in order to reduce the time it takes to develop UCAs.

Because no systems outside of New Mexico have been unbundled, many producers are in the position of having to calculate UCAs themselves. Doing so requires the producer to de- termine what functions are performed by the midstream service provider,
evaluate marketable condition requirement and then estimate the cost for each function.

This can be a difficult process without operating and costs data from the midstream service provider. To assist in the process, the ONRR has published a set of guidelines for calculating UCAs for transportation and process- ing costs.

Unbundling scenario

Figures 1 and 2 (page 72) show a hypothetical situation in which a producer’s natural gas production is delivered to a midstream company at a central deliv- ery point (CDP). As shown in Figure 1, the producer’s gas is delivered at a pressure of 100 pounds per square inch gauged (psig). The gas is com- pressed to a pressure of 850 psig via two compressor systems: compressor station No. 1 in the field and compres- sor station No. 2 at the inlet of the gas processing facility.

On the discharge of the compressor at station No. 1, the gas is dehydrated from a water content 100 lbs/million standard cubic feet (MMscf) to 6 lbs/MMscf. Figure 2 shows the functions performed at the gas processing plant. The natural gas is first routed through an amine treater where its carbon dioxide content is reduced from 3.0 mole% to 1.5 mole%.

Downstream of the amine treater, the natural gas is routed to a molecular sieve dehydration system to reduce the water absorbed in the amine treating process down to essentially zero (“bone dry”). The natural gas is then routed through a turboexpander-type NGL extraction section. The residue gas leaving the NGL extraction section is recompressed, then delivered to a mainline pipeline, while the extracted NGL are delivered to a Y-grade (mixed gas liquids) pipeline.

The table, Allowable Percentages For Midstream Functions, was developed using information in the ONRR unbundling guidelines and indicates corresponding allowable percentage for each function.

Pipeline specifications

Where MCR is noted, the allowable percentage must be calculated based on mainline pipeline specifications and the degree to which the function meets or exceeds the specification. The ONRR guidelines provide a linear approach as follows. (The linear relationship presented here differs from that in the ONRR guidelines due to inconsistencies in the approaches. The discrepancy has been noted with the ONRR):

Allowable= (Marketable Condition – Outlet Measurement) Percentage (Inlet Measurement – Outlet Measurement)

The marketable condition requirements for pressure, water and carbon dioxide for the mainline pipeline are shown in Figure 2—Natural Gas Processing Plant.

Thus, for each of the functions that require consideration of the MCR, the allowable percentages were calculated as follows:

Compression
(Compressor Station No. 2 only):
Allowable = (800 psig – 850 psig) = 14.3%
Percentage (500 psig – 850 psig)

Dehydration
(field dehydration):
Allowable = (7 lbs/mmscf – 6 lbs/mmscf) = 1.1%
Percentage (100 lbs/mmscf – 6 lbs/mmscf)

Amine Treating:
Allowable = (2.0 mole% – 1.5 mole%) = 33.3%
Percentage (3.0 mole% – 1.5 mole%)

The next step is to apply the allowable percentages for each of these functions to their corresponding costs to determine UCAs for transportation and processing as well as an overall UCA. The table, Unbundling Cost Allocations Cal- culations, shows these calculations based on a set of hypothetical costs.

Figuring costs

Costs are based on capital investment and operating and maintenance (O&M) costs. Capital costs are generally those costs for depreciable fixed assets that are an integral part of the transportation and processing assets. Annual capital costs are calculated based on annual depreciation cost plus a return on undepreciated capital investment or a cost equal to the initial depreciable investment multiplied by a rate of return. O&M costs include expenses such as personnel, consumables, spare parts and overhead.

For a non-arm’s length arrangement between production and midstream affiliates of a single company, capital and O&M costs will be based on lessee’s reasonable actual costs. Being affiliates, generally these costs are readily available.

Not unexpectedly for an arm’s length arrangement, that is, an agreement between independent entities that are not affiliates and that have opposing economic interests regarding that agreement, cost data is typically not shared. A midstream company is naturally hesitant to reveal technical and commercial data that could provide an advantage to the producer during negotiations and the normal course of business.

Nonetheless, the production company is still responsible for unbundling. In the meantime, several producers are developing UCAs based on relative costs for each of the functions through the use of internal resources, outside consultants or both.

How midstream helps

Producers will often unbundle the midstream services they receive in response to orders issued by the ONRR following compliance audits. Improper deductions can result in penalties and fines. Some companies have chosen to be proactive and unbundle prior to in- quiries or data requests from the ONRR. There are various ways a midstream company can help a producer with the unbundling process.

The first and easiest way to help a producer is for the midstream company to provide basic information about its system. Knowing what functions and technologies are utilized and at what point in the system can help a producer estimate relative costs.

Is the natural gas dehydrated in the field, at the plant, or both?

How much horsepower does the midstream company operate in the field and at the plant in both inlet and residue service?

How many miles of transportation piping have been installed?

Basic operating conditions such as gas plant inlet pressure, mainline pres- sures and carbon dioxide concentration in the residue gas would help the producer as well.

If a midstream company wishes to avoid providing system information to the producer, it may want to consider calculating the UCAs internally and providing the figures to the producer.

Understanding the motivation for unbundling by the producers can better equip midstream companies to assist their customers with their unbundling efforts. By working with producer customers, midstream companies can improve customer relationships while not compromising proprietary and competitive information.

Mark R. Lambert is a senior consultant with Pearson Watson Millican & Co., a Dallas-based energy consulting firm that provides technical and commercial solutions to the midstream and downstream energy sectors.

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