Oil and Gas Lawyer Blog

Published on: March 23, 2009

Use of Bank Drafts for Bonus Payment in Oil and Gas Leasing

Exploration companies have traditionally used bank drafts to pay bonuses for oil and gas leases. Since drafts look a lot like a check, they can be misleading to mineral owners. Some mineral owners’ recent experiences with dishonored drafts have highlighted the problems with use of these financial instruments.

A draft is like a check, but different. It is an order issued to a bank to pay a party, conditioned on the happening of a specified event. As used by exploration companies, it is an order issued by a company or its landman to the company’s bank to pay the bonus to the mineral owner. Typically, the draft provides that the company has a period of time – 30 to 90 days – from the date its bank receives the draft to “honor” the draft – that is, to tell the bank to pay the bonus to the mineral owner. The draft typically has language like the following:

On approval of lease or mineral deed described herein, and on approval of title to same by drawee not later than 30 days after arrival of this draft at collecting bank.

In other words, the company has 30 days to approve the oil and gas lease being paid for and to approve the mineral owner’s title to the minerals being leased. If the company does not approve the lease, or if it determines that the mineral owner does not have good title to the minerals being leased, it can refuse to pay the draft.

Use of drafts to pay for leases would seem to be a good way, in theory, to facilitate the lease transaction. And in fact, drafts are used every day in hundreds of lease transactions, without incident. But there are problems with its use, and those problems can put landowners at risk. My advice to landowners is to avoid using drafts if possible.

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Published on: March 18, 2009

Oil and Gas Lease Termination Clauses

By John McFarland

Last week I discussed Wagner & Brown v. Sheppard, a recent Texas Supreme Court case that involved a lease termination clause. Sheppard’s lease in that case provided that, if royalties were not paid to her within 120 days after first production, the lease would automatically terminate. That is exactly what happened.

Landowners are usually surpriesed to learn that, under a “standard form” oil and gas lease, the lessee’s failure to pay royalties does not give the lessor the right to terminate the lease. The lease remains in effect, and the lessor’s only remedy is to sue for the unpaid royalties. Landowners often seek to negotiate a clause like Sheppard’s that gives the lessor the right to terminate the lease for failure to pay royalties. Exploration companies of course do not like such a provision. It puts them at risk that, if royalties are not timely paid for some inadvertent reason, they can lose the lease even though they are willing and able to pay the royalties.

First, I think it is not a good idea to include a provision that a lease terminates automatically if royalties are not paid within a specified time. Depending on the circumstances, it may not be in the lessor’s best interest to terminate the lease, even though royalties have been delayed. A better provision is that, if royalties are not paid by a specified date, the lessor has the option to terminate the lease.

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Published on: March 13, 2009

What happens to a pooled lease when the lease terminates?

By John McFarland

A recent decision of the Texas Supreme Court, Wagner & Brown, Ltd. v. Sheppard, has caused quite a stir in oil and gas legal circles. The court was faced with a question never before answered by a Texas appellate court, what is known as a “case of first impression.” Such cases are always interesting to oil and gas lawyers, so I thought I would weigh in on the arguments.

The facts in the case are these: Jane Sheppard owns a 1/8th mineral interest in 62.72 acres in Upshur County. She leased her 1/8th interest, and her lease – along with leases of the other 7/8ths interest in the 62.72 acres and leases of other lands- was pooled to form the W.M. Landers Gas Unit, containing 122.16 acres. Two wells were drilled on Sheppard’s tract, both producing gas.

Sheppard’s lease contains a provision requiring payment of royalties within 120 days of first sales of gas, failing which the lease would terminate. She was not paid on time, and her lease terminated.

Texas law is clear that, if there had been no pooled unit, upon termination of her lease Sheppard would become what is known as a “non-consenting co-tenant” in the two wells on her tract. She would be entitled to receive her 1/8th share of proceeds of sale of gas from the wells, less 1/8th of the costs of production and marketing. But Wagner & Brown contended that Sheppard’s tract was still bound by the pooled unit, even though her lease had expired. Under the pooling clause in Sheppard’s lease, her royalty would be calculated based on the number of acres of her tract compared to the total number of acres in the unit – in this case, 62.72/122.16, or 51.34% of the wells’ production. Wagner & Brown contended that Sheppard should receive 1/8th of 51.34% of production from the wells, less that same fraction of the cost of production and marketing. The Supreme Court agreed with Wagner & Brown, holding that “the termination of Sheppard’s lease did not terminate her participation in the unit.”

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Published on: March 2, 2009

Surface Damages for Oil and Gas Activities in Texas

By John McFarland

Landowners in Texas are often surprised to learn that oil companies have no obligation to compensate them for use of their lands, or to restore the lands after their use, absent a contractual requirement to do so in their oil and gas lease. The typical oil-company form lease provides only that the lessee will pay for damages “caused by its operations to growing crops and timber on the land.” Under such a lease, the company does not have to compensate the surface owner for use of or damage to the surface caused by its operations.

Most exploration companies do compensate the surface owner for surface use. The usual practice is for the company to agree with the surface owner on a single lump-sum payment for each well location, with its attendant roads and flow line easements. The company pays this compensation for two reasons: first, to maintain good relations with the surface owner, and second, to obtain from the surface owner a release, which is presented to the surface owner at the time of the payment. The release typically contains language absolving the company from any and all damages caused by the company’s operations on the property for the well. In other words, part of the consideration for the payment is the landowner’s release of the company from further liability.

Absent a contractual obligation in the lease, the oil company has no obligation to compensate the landowner unless it negligently or intentionally causes damages in excess of the reasonable and necessary damages resulting from its operations. The mineral estate is the “dominant estate,” which means that the mineral owner and his/her lessee have the right to use so much of the surface estate as is reasonably necessary to explore for and produce oil and gas. Texas courts have historically been very careful to protect the rights of the mineral lessee. After all, the oil and gas industry was the principal source of wealth and revenue in Texas for decades, and courts obligingly crafted legal principles designed to facilitate oil and gas exploration and production.

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Published on: February 27, 2009

Ruminations on Unconventional Resource Plays

By John McFarland

The last few years have seen a boom in the oil and gas exploration business in the U.S., driven by new technologies that have allowed exploitation of “unconventional” resources for gas and oil. These resources are often called “resource” plays, because the oil and gas is being produced from shale beds. Shale is known by geologists to be the source or “resource” of pockets of oil and gas accumulated over hundreds of years in more conventional oil and gas sands, trapped by faults and other geological anomalies.

The resource plays in the news over the last couple of years are the Barnett Shale in Texas, in and around Fort Worth, the Fayetteville Shale in Arkansas, the Bakken Shale in North Dakota, and more recently the Marcellus Shale in Pennsylvania and New York, the Haynesville Shale in Louisiana and East Texas, and the recently discovered Eagle Ford Shale in South Texas. Exploitation of these resources has resulted from two factors: improved technology, especially horizontal drilling, and high oil and gas prices. The discovery and exploitation of these shale plays has dramatically increased the U.S. reserves of natural gas. The top producing well in the Haynesville Shale produced 713 million cubic feet of gas in December, an average of 23 mmcf per day.

The table below shows the increase in production from the Barnett Shale since 1982:

Barnet Shale Prod 5.JPG

These shale plays have had dramatic effects in the U.S. economy and in U.S., state and local politics. For example:

— Lease bonuses in the Barnett and Haynesville Shale plays reached heights unheard of last year — $25,000 to $30,000 per acre. By September 2008, Chesapeake had acquired leases covering 550,000 acres, EnCana and Shell had bought 325,000 acres, Petrohawk Energy 275,000 acres, Devon energy 130,000 acres. Haynesville lease bonuses averaged more than $13,400/acre. The Haynesville play was like the California gold rush.

— The Haynesville Shale is 200-300 feet thick. Recoverable gas reserves are estimated at 24-60 Bcf (billion cubic fee, or a million mcf) per square mile. Estimated ultimate recoveries from Haynesville wells have been estimated at 4.5 to 8.5 Bcf per well.

— In and around Fort Worth, and in areas of Pennsylvania, landowners began to organize themselves to bargain with exploration companies as a group, to increase their leverage to obtain better lease terms.

— Ray Perryman, a Texas economist, estimated that the economic impact of the Barnett Shale on the Barnett Shale Region in 2008 was almost $30 Billion.

— Horizontal drilling technology has allowed the drilling of wells in urban areas, including under the DFW Airport and under the campus of Texas Christian University in Fort Worth.

— Urban drilling has also lead to increased regulation by municipalities of drilling activities in urban areas. Fort Worth and surrounding cities have adopted increasingly sophisticated and complex drilling ordinances, regulating aspects of drilling and producing wells that have not heretofore been the subject of regulation, including sound abatement, air pollution, pipeline safety, and street maintenance.

— Members of the Texas Legislature, now in session, have introduced numerous bills – principally in response to complaints by constituents – to allow municipalities, counties and groundwater districts some authority to regulate condemnation for and location of pipelines, underground disposal of produced water and frac water, and “the quality of the environment.” Industry lobbyists are being kept busy opposing those bills.

— The Pennsylvania Legislature is considering bills to impose a property tax on producing minerals and a severance tax on production in that state.

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Published on: February 23, 2009

Post-Production Costs in Texas-Part III: Yturria v. Kerr-McGee

By John McFarland

Last week, in Post-Production Costs in Texas-Part II, I discussed the Texas Supreme Court’s decision in Heritage Resources v. NationsBank regarding the deductibility of post-production costs from lessor’s royalties under an oil and gas lease. Justice Priscilla Owen (now a judge on the U.S. Court of Appeals for the Fifth Circuit) filed a concurring opinion in Heritage in which she said that “it is important to note that we are construing specific language in specific oil and gas leases. Parties to a lease may allocate costs, including post-production or marketing costs, as they choose.” Justice Owen’s conclusion was put to the test in Yturria v. Kerr-McGee Oil & Gas Onshore, LLC, decided by the U.S. 5th Circuit Court of Appeals on September 8, 2008.

My firm represented the royalty owners in Yturria v. Kerr McGee, and I was the author of two of the oil and gas leases construed in that case. As the court points out, these were not “standard” oil and gas leases. They contained detailed provisions as to how royalties were to be calculated and paid. The language was crafted as part of the settlement of earlier litigation with Kerr McGee over royalty payments, and at the time the language was agreed to there were existing wells on the leases that produced substantial quantities of gas. The Kerr-McGee gas was processed before sale under a processing agreement between Kerr-McGee and the processor, Enterprise.; The processing agreement required that Enterprise pay Kerr McGee for 80% of the natural gas liquids extracted from the gas, based on posted prices, less a “T & F Fee” for the costs of transportation and fractionation of the liquids. The issue in the case was whether the royalty owners should bear their royalty share of the T & F Fees charged by Enterprise. The trial court and the court of appeals both ruled in favor of the royalty owners, holding that, under the particular language of the leases, the T & Fees could not be deducted from the lessors’ royalty.

The leases provided that Kerr-McGee would pay a royalty on natural gas liquids (called “plant products” in the leases) equal to “1/4th of 75% of all plant products, or revenue derived therefrom, attributable to gas produced by Lessee from the leased premises (whether or not Lessee’s processing agreement entitles it to a greater or lesser percentage).” The leases also provided that “Lessor’s royalty shall never bear, either directly or indirectly, any part of the costs or expenses of production, gathering, dehydration, compression, transportation (except transportation by truck), manufacture, processing, treatment or marketing of the oil or gas from the leased premises.” The court of appeals agreed with the royalty owners that the “revenue derived” from plant products was the gross revenue based on the price set forth in the Enterprise-Kerr-McGee processing agreement, before deduction of the T & F Fees.

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Published on: February 16, 2009

Post-Production Costs in Texas – Part II

By John McFarland

Last week I introduced the term “post-production costs” and attempted to explain what those costs are and how oil companies account for such costs in calculating royalties. I said that Texas courts have construed the standard gas royalty clause to allow oil companies to deduct post-production costs from royalties. The Texas Supreme Court had occasion in 1996, in Heritage Resources, Inc. v. NationsBank, to address the deductibility of post-production costs. NationsBank (now Bank of America) was named trustee of trusts created under the will of David Tramell. NationsBank signed oil and gas leases covering lands owned by those trusts, and Heritage Resources drilled gas wells on the leases. Heritage deducted transportation costs from the royalties it paid to the trusts, and NationsBank sued to recover those deductions, based on the following language in its leases:

The royalties to be paid Lessor are …

;on gas, .. the market value at the well of 1/5 of the gas so sold or used, … provided, however, that there shall be no deductions from the value of the Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation or other matter to market such gas.

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Published on: February 9, 2009

Deductibility of Post-Production Costs in Texas Oil and Gas Leases

By John McFarland

Mineral owners in Texas have learned that their leases should provide for a “cost-free” royalty. By this, they generally understand that the lease should prohibit the lessee from deducting any costs from their royalty. Herein, then, are some ruminations about what lawyers and oil companies refer to as “post-production costs.”

The problem of post-production costs generally arises only in relation to gas production. The typical oil and gas lease provides that the royalty on gas shall be a specified fraction of “the market value at the well”, or of the “amount realized at the well,” or the “net proceeds at the mouth of the well.” The phrase “at the well,” as interpreted by Texas courts, has a highly specialized meaning. It means that the lessee, in calculating the royalty, can deduct any costs incurred to make the gas marketable and to get the gas to the point of sale. (I’ll bet most mineral owners don’t realize that when they sign a lease.) Such costs are referred to as “post-production costs” because they are incurred after the gas is produced but before it is sold, and they can be quite significant.

Suppose the following facts: ABC Oil Company drills the Jones #1 gas well on the Jones farm. ABC has a lease from Jones that provides for payment of a 1/4th royalty on the “amount realized at the mouth of the well.” The Jones #1 gas as it comes from the ground contains quantities of water, hydrogen sulfide and other impurities that have to be removed before the gas can be sold to a pipeline. Also, the gas itself is actually a mixture of several different hydrocarbon gases – methane, ethane, butane and propane. Although most natural gas is methane — the same gas you burn in your stove — some natural gas contains significant quantities of “heavier” gases such as ethane, butane and propane. If there are enough of those other gases, they must be separated from the methane before the methane can be sold to a pipeline, because the heavier gases tend to condense into a liquid in the pipeline and cause problems with the pipeline’s transmission system. The heavier gases can be sold as separate products. They generally have a higher value per unit volume than methane because they have a higher heating value. That is, they produce more heat per unit volume when they are burned as fuel.

So ABC Oil Company installs separators and treaters on the Jones lease to remove the water and hydrogen sulfide from the gas. The cost of such treatment is $.10 per mcf. ABC also contracts with XYZ Processing Company to “process” the gas to remove the heavier hydrocarbons. Its agreement with XYZ Processing Company provides that XYZ gets to keep 25% of the heavier gases as its fee for processing the gas from the Jones #1 well. ABC also enters into a contract with Big Inch Pipeline Company to transport the methane to Commercial Plastics Company for $.05 per mcf, and ABC enters into a contract to sell the gas to Commercial Plastics Company for $5.00 per mcf. Finally, ABC agrees to sell its 75% of the heavier gases to NGL Purchasing Company for $7.00 per mcf.

In its first month of production, the Jones #1 produces 100,000 mcf of gas. 1,000 mcf of that gas is used as fuel to run the treaters to remove the water and hydrogen sulfide. After the remaining gas is treated and processed, it becomes 90,000 mcf of methane and 9,000 mcf of heavier gases. ABC gets back the 90,000 mcf of methane, which it sells to Commercial Plastics for $450,000, and it gets back 75% of the 9,000 mcf of heavier gases, which it sells to NGL Purchasing Company for $47,250. ABC Oil Company thus receives $450,000 for the methane and $47,250 for the heavier gases, for a total of $497,250.

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