February 2009 Archives

February 27, 2009

Ruminations on Unconventional Resource Plays


 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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February 23, 2009

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


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.

This case illustrates that accounting for gas royalties can be a complex matter. The royalty owners discovered the T & F Fee deduction only after an audit of Kerr-McGee's records and had to engage in four years of litigation to enforce the provisions in their leases.

February 16, 2009

Post-Production Costs in Texas - Part II

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.

The court, with two justices dissenting, held that Heritage had properly deducted transportation costs in calculating the royalties.  The court's reasoning went something like this: (1) The royalties are to be calculated based on the "market value at the well." (2) The proper method of calculating royalties "at the well" is to deduct transportation costs from the gross proceeds of sale of the gas at the point of sale. (3) The "value of Lessor's royalty" is therefore the gross proceeds of sale less transportation costs.  (4) Heritage is not deducting transportation costs from the "value of Lessor's royalty," and so is not violating the lease. If this sounds a little bit circular to you, you aren't alone. The court concluded:

We recognize that our construction of the royalty clauses in ... the ... leases arguably renders the post-productions clause [the no-deductions clause] unnecessary where gas sales occur off the lease. However, the commonly accepted meaning of the "royalty" and "market value at the well" terms renders the post-production clause in each surplusage as a matter of law.

"Surplusage" is a fancy term for "meaningless." I agree with the dissenting opinion, which said of the no-deductions clause in the leases:

What could be more clear? This provision expresses the parties' intent in plain English, and I am puzzled by the Court's decision to ignore the unequivocal intent of sophisticated parties who negotiated contractual terms at arm's length.

On rehearing, four justices voted to rehear the case.  One justice recused himself, so the court was deadlocked 4 to 4 on whether the case was correctly decided. As a result, the motion for rehearing was denied. Although it may be argued that the case has little precedential value, it is in the books, and it is cited regularly by oil companies on this issue. 

What is the lesson in this case for royalty owners? Be careful how you draft a lease clause prohibiting deduction of post-production clauses. Some lawyers go so far as to say in their no-deduction clause that "it is the intent of this provision to prohibit deductions from Lessor's royalty despite the holding in Heritage Resources v. NationsBank." A better practice is to avoid the term "market value at the well" altogether. Change it to "market value at the point of sale." And expressly prohibit any deduction of post-production costs from that value.

February 9, 2009

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

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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