Under most oil and gas leases, the lessee owns the natural gas and is obligated to pay the lessor some fraction of the value or of proceeds received from production. Likewise, under the most frequently used AAPL Form 610 Model Form Operating Agreement (the "JOA"), nonoperating working interest owners have the right to either take their share of oil and gas production in kind or have the operator market all of the production.

But lenders and investors behind nonoperating working interest owners often base their price projections and financial covenants on published prices, ignoring the realities of sales under the operator's gas-sales contract and the practical problems of taking production in kind. So, as a nonoperating working interest or royalty owner, how can you ensure the highest or right price for your share of the gas being marketed by the operator? What should you look for to make sure you are paid correctly?

Here are the most common reasons why lessors and nonoperating working interest owners are underpaid for their gas:

Failure to measure, or inaccurate measurement, of natural gas and associated substances. Under most leases, the lessor is entitled to a specific share of the proceeds or value of oil and gas produced and saved from the lease. A nonoperating working interest owner is entitled to a specified share of all production from the lease. Sometimes the production is not adequately measured for purposes of calculating royalty payments to lessors and net revenue payments to nonoperators.

Inaccurate measurement may involve drip, or condensate (liquid hydrocarbons recovered at the surface, resulting from condensation caused by reduced pressure or temperature of hydrocarbons initially in a gaseous phase in the reservoir). This sometimes accumulates in low spots in the pipeline transporting the gas. It is removed from the pipeline and placed into drain lines connected to condensate tanks ("drip pots"). Sometimes drip is overlooked or ignored in calculating payments. Likewise, casinghead gas produced in an oil stream may be overlooked.

Another factor in inaccurate measurement: some meters measure only oil or only gas. This can be a problem if hydrocarbons are commingled at the surface. In such cases, the operator may fail to account accurately for one type of hydrocarbon or the other. A related issue is faulty field-measurement equipment, which results in crediting less than the total production stream. However, it is difficult for an operator to avoid these omissions because, to sell such production, the operator must report it to the regulatory authorities.

Additionally, operators may fail to account to lessors and nonoperators for sales of nonhydrocarbon products such as helium, carbon dioxide and sulfur. If these substances are covered by the lease, lessors and nonoperators are entitled to their respective shares of sale proceeds.

Using an artificially low gross sales price to calculate the lessor's royalty and nonoperator's net revenue payment.

This problem can manifest in several ways. One of the most common is through sale of the gas to an affiliate of the selling party. Under Texas law, such sales are "inherently suspect." In a market-value lease, the sale to an affiliate may be claimed to be the "market." In a proceeds lease, the sale to the affiliate is claimed to be the "proceeds received."

Published indices often do not reflect the full value that a particular lessee received (or could have received) for hydrocarbon products.

But the sale may be at less than the fair market price. The affiliate resells the gas at a higher price and keeps the difference. This is the classic "transfer price" issue. Many leases now base the royalty calculation on the proceeds received in the first arm's-length nonaffiliate sale; however, this provision is frequently ignored.

Operators may sometimes account to lessors and nonoperators for gas production based on volume (i.e. thousand cubic feet, or Mcf), while their sales contract may be based on heating capacity (i.e. Btu). If the lease specifies royalty on a volume basis, that is a correct calculation. However, mixing measurement methods may shortchange lessors and nonoperators whose so-called rich gas has an above-average heating capacity.

On the other hand, if lessors' and nonoperators' respective shares of gas sales are based entirely on wellhead Btu, or if the gas is sold at the well, lessors and nonoperators may be denied their share of the potential margin that sometimes results from processing of the wet-gas stream.

When determining what market price to apply to the royalty share of natural gas and other hydrocarbon products, the lessee has a duty to obtain the highest price reasonably obtainable. Lessees sometimes utilize a price based upon a published index (e.g., Inside FERC, Gas Daily, etc.) and point to that as being fair and reasonable or "market value."

But published indices often do not reflect the full value that a particular lessee received (or could have received) for hydrocarbon products. They typically reflect a wholesale price at a trading location in the vicinity of the producing area, such as Henry Hub, Katy, etc. By entering into agreements downstream with utilities, industrials and various end-use markets, the operator is often able to realize a higher value than the published index price—higher value that is not fully shared with the royalty owner or nonoperator.

On the other hand, a lessor's lease often provides for determination of proceeds or value at the wellhead, in which case the use of published indices, minus transportation cost, can be the best measure of value.

Excessive deduction of "post-production" costs. The traditional gas-royalty clause provides that, on gas sold or used off the premises, the royalty shall be the market value at the well of a stated fraction of the gas so sold or used, and, on gas sold at the well, the royalty shall be the stated fraction of the amount realized from such sale.

Under this type of royalty clause, the operator is entitled to deduct reasonable post-production expenses from the gross sales price before calculating royalty. Which costs are considered post-production costs (and therefore deductible) may differ depending on the language of the lease and the law of the state in which the production occurs.

Costs that are not actually post-production costs under the applicable lease and law are sometimes deducted. For example, the operator might deduct gathering, treating and processing costs in a state in which "production" is not considered to have ended until the operator has produced a "marketable" product. In many states, lessees have a duty to their lessors to place natural gas and other produced products in marketable condition, which can include carrying it to a commercial market.

Pipelines that transport natural gas to market have stringent quality specifications that frequently cannot be met unless the gas is first processed and/or treated. In these circumstances, the lessor, absent lease language to the contrary, should not have to bear any of the costs associated with processing and treating the gas in those states in which the lessee must make the gas marketable.

Nonetheless, the lessor is often charged these costs because the lessee calculates the lessor's royalty based on only a share of the proceeds associated with the sale of liquids and other products that are removed, in essence deducting the liquids paid as a processing fee.

Where state law or specific lease terms allow for deduction of processing costs, such costs should be based solely on the actual costs to remove natural gas liquids and any associated impurities in the gas. In any event, the lessor should receive the highest value reasonably attainable for the full share of any products that are removed and can be marketed.

Even if the cost is a deductible post-production cost, the operator may deduct an amount greater than the actual cost incurred by the operator. For example, the operator may deduct transportation and similar expenses based on published tariffs or trade journal quotes, which may be higher than the actual cost incurred by the operator. Where a lease allows transportation costs to be deducted from the royalty share, such deductions should be based upon actual costs and be in accord with reasonably prudent operator standards. Lessees often impute a cost for transportation that does not reflect actual costs, but is instead based upon a full pipeline tariff or some other measure that does not take into account the actual physical flows and costs.

An exchange or swap is sometimes used where the lessee delivers (or sells) gas to another affiliated or unaffiliated party at one location and receives (or repurchases) a similar quantity in return at another location, thereby eliminating or reducing the transportation expense. The royalty accounting, however, may be based upon another regimen under a theoretical point-to-point transportation arrangement. The result is artificially inflated transportation costs and a diminished settlement to the royalty owner or nonoperator.

Lessors may find it difficult to ferret out possible overcharges on post-production costs because royalty-check stubs often fail to properly identify and categorize, in an understandable manner, the deductions and charges being made. For instance, the operator may lump numerous types of costs into the category of "marketing fees." This arrangement raises the specter of "double dipping" by the operator; the operator may be attempting to deduct the same cost twice—once under the "transportation charges" category and once as a component of the "marketing fee."

Avoiding Underpayment

These steps can help lessors and nonoperators protect themselves from being underpaid for their gas:

Demand strong audit rights. Lessors should insist that their lease include a broad right to periodically audit their lessee's books and records as well as the leasehold production meters. This will enable them to discover possible errors by the lessee in calculating royalty payments.

Nonoperators have audit rights under the Council of Petroleum Accountants Societies (COPAS) accounting procedure attached to most operating agreements. However, the normal Exhibit "C" covers only items charged to the joint account, and the deduction from revenue may not be considered such a charge. In that case, the nonoperator must rely on Section V.D.5 of the JOA. Consider negotiating for stronger audit rights than are provided under the standard language in the operating agreement—for example, the right to examine downstream exchanges or swaps and transportation arrangements.

Require the price on which royalty or net revenue payment is calculated to be the total value obtained by the operator in the first arm's-length sale. The lessor's royalty and the nonoperator's net revenue payment should be based on the total value received by the operator for the sale of the gas under an arm's-length contract competitively negotiated by the operator. It should include all consideration received by the operator for the gas, including non-monetary consideration such as additional pipeline capacity or volume price premiums or transportation discounts.

Specify which post-production costs may be deducted by the lessee and the basis upon which such deductions may be made. The lease should specify what types of post-production costs may be deducted by the lessee before calculating the lessor's royalty; the lease could even define "production" and should, if it is a proceeds lease, specify the calculation to be based on the first sale to a nonaffiliate.

Recently, one of the authors of this article, Rick Harper, found consultants selling concepts to producers solely for the purpose of reducing royalty payments, much like tax shelters. Operator-friendly processing and other post-production cost centers seem to be the new focus. Harper has even heard arguments that the number of producers/lessees using these tactics has made it industry custom and practice.

Lessors and nonoperators should seek out knowledgeable, industry-experienced consultants, lawyers, and auditors to ensure they are protected. These experts tend to pay for themselves. Once the contracts are signed, it's often too late.

W.R. (Rick) Harper Jr. has been in the natural gas business since 1972. He was previously president of Arco Gas; CEO and president of Canor Energy Ltd., Calgary; and senior vice president of Northwest Natural Gas Co. He currently manages an international consulting practice with offices in Houston and Portland. H. Martin Gibson and Stephen Molina are of counsel with Patton Boggs LLP's Dallas office. Previously Molina was general attorney for Arco Oil & Gas Co., chief counsel for Arco Latin America, and general counsel for Vastar Resources Inc., Benton Oil and Gas Co. and the Oman Oil Co. He is a Texas Member of the Interstate Oil & Gas Compact Commission. Gibson is board certified in oil, gas and natural resources law by the Texas Board of Legal Specialization and serves on the Texas Title Standards Joint Editorial Board. Jonathan Harshman is an associate in Patton Boggs' Oil & Gas Practice Group in Dallas.