In a previous post I discussed a recent Texas Supreme Court case, Exxon v. Emerald, reversing a multimillion-dollar judgment against Exxon for intentionally sabatoging wells so that they could not be re-entered. This nudged me to look at other royalty-owner related cases handed down by the Texas Supreme Court over the last ten years. The court's record is not a good one for royalty owners. Highlights of the Court's work:
HECI v. Neel (1998). HECI sued an adjacent operator for illegal production on an adjoining lease that damaged the common reservoir underlying both leases, and recovered a judgment for more than $3.7 million. HECI did not inform its royalty owners of the suit and did not share any of the judgment proceeds with the royalty owners. When HECI's royalty owners found out about the suit, they sued HECI to recover their share of the judgment. The Supreme Court held that the royalty owners had waited too long to bring their suit, even though they did not find out about the suit until five years after the trial. The Court held that the royalty owners should have known that the adjacent operator was damaging the common reservoir by its operations.
Yzaguirre v. KCS Resources (2001). Plaintiffs were royalty owners who received royalties under a lease operated by KCS. KCS sold its gas under a 20-year contract with Tennessee Gas Pipeline, and the price under the Tennessee contract greatly exceeded the spot market price of the gas. But KCS paid royalties based on the "market value" of the gas, using comparable spot sale prices, well below the price it received from Tennessee. The Court held that KCS did not owe royalties based on the Tennessee price -- and, it held that the Tennessee contract was not even competent evidence of the market value of the gas.
Wagner & Brown v. Horwood (2001). Plaintiffs sued Wagner & Brown for deducting excess compression fees from their royalties that were charged by a Wagner & Brown affiliate. The Supreme Court ruled that all claims for royalties paid more than four years prior to the suit were barred by the four-year statute of limitations. Plaintiffs argued that Wagner & Brown had falsely told them, when they inquired about the fees, that the fees were only 12 cents per mcf, rather than 25 to 30 cents, so Wagner & Brown should not be allowed to rely on the statute of limitations. The Court rejected this argument, holding that the Plaintiffs' claims were not "inherently undiscoverable," even if Wagner & Brown lied to them about the charges.
Natural Gas Pipeline Company of America v. Pool (2002). Plaintiffs sued NGPL claiming that two leases had terminated due to a lack of production. The trial court entered a judgment for lessors on a jury verdict, which the Court of Appeals affirmed. The Supreme Court reversed. It held that, if the leases had terminated for lack of production, the lessee had subsequently re-acquired title to the leases by adverse possession. This is the first case in the country to hold that adverse possession statutes apply to recover title to an expired oil and gas lease.
In re Bass (2003). Plaintiffs owned a royalty interest under a ranch owned by the Bass family. The Basses refused to lease their land for oil and gas exploration, and the royalty owners sued them for breach of an implied duty to develop the land. The Supreme Court held that the Basses had no implied duty to lease or develop the minerals under their property.
Union Pacific Resources Group v. Hankins (2003). Royalty owners in Crockett County brought suit against Union Pacific, alleging that UPRG was selling gas to an affiliated company at a low price and then reselling it at a higher price, but paying royalties on the lower price. The plaintiffs sought to make the case a class action brought on behalf of all royalty owners in UPRG wells in Crockett County.The Supreme Court held that the case could not be brought as a class action because the royalty language in the leases could be different.
Kerr-McGee Corp. v. Helton (2004). Kerr-McGee drilled a well, the Holmes 17-1, in Wheeler County which produced more than 8.7 billion cubic feet of gas. The well was located 660 feet from the Heltons' lease. Kerr-McGee did not drill an offsetting well on the Helton lease, and the Heltons sued Kerr-McGee for failing to protect their lease against drainage from the Holmes 17-1. The trial court awarded $860,000 in damages, and the Court of Appeals affirmed. But the Supreme Court reversed, ruling that the plaintiffs should have no recovery. The Court held that the plaintiffs' expert witness had not adequately explained how he had measured the amount of gas that would have been produced from a well on the Helton lease if Kerr-McGee had drilled it; the Court said that there was "simply too great an analytical gap between the data [relied on by the expert] and the opinion proffered." The Court refused the plaintiffs' request to remand the case for a new trial.
Forest Oil Corp. v. McAllen (2008). In 1999, Forest Oil settled a lawsuit with McAllen and others who own the McAllen Ranch in Hidalgo County, over claims for royalties and leasehold development. In 2004, McAllen filed a separate suit against Forest to recover for damages caused by burying mercury-contaminated and radioactive material on the ranch. Forest claimed that McAllen was obligated by the 1999 settlement to arbitrate any disputes over its operation of the lease. McAllen claimed that he was fraudulently induced to sign the settlement and was not bound to arbitrate his claims. The Supreme Court held that McAllen was contractually bound to arbitrate. It held that language in the settlement agreement, providing that McAllen was not relying on any statement or representation of Forest in executing the agreement, prevented McAllen from arguing that he was fraudulently induced by Forest to sign the settlement agreement. In so holding, the Court overruled a prior case it had decided in 1997, in which it held that a settlement agreement must "clearly express .. the parties' intent to waive fraudulent inducement claims" in order to preclue a fraudulent inducement claim.
I was unable to find any Supreme Court case in the last ten years that ruled in favor of royalty owners.
Renewable energy is a hot topic in the new Obama Administration. Wind Energy is being touted, especially in Texas, as a solution to global warming and U.S. dependence on foreign oil. Wind farms have sprouted all across Texas. Texas is now the leading wind energy producing state. Texas utilities are about to spend billions of dollars extending high-voltage transmission lines into West Texas and the Panhandle, opening up those areas to additional wind energy projects. The Texas Panhandle will see the next boom in wind energy development. Having grown up in the Panhandle, I can verify that the wind blows there.
Three points are good to keep in mind when reading stories about renewable energy in general, and wind energy in particular. First, it is important to distinguish between two different goals being pursued by the Obama Administration: freedom from dependence on foreign oil, and reduction of carbon emissions. Wind energy is "clean," because it does not produce CO2. To the extent that wind energy can replace conventional coal- and natural gas-burning power plants, it therefore reduces CO2 emissions, thus fighting global warming. But wind energy has little or no effect on imports of oil, which is mostly used for fueling cars and trucks. If and when the auto industry solves the battery problem and is able to produce electric cars, wind energy could contribute to reduction in oil imports.
Second, it is important to understand that, although wind farms are increasing exponentially, they contribute only a tiny portion of the nation's total energy consumption. According to the Energy Information Administration, as illustrated below, in 2007 wind energy contributed only 5% of 7% of the nation's energy -- .35%!
Renewable energy contributes a larger share of the nation's total electricity production, as shown below:
But wind energy again makes up only a small percentage of total renewable energy sources used for electricty production. By far the largest contributor is hydroelectric power, a source that is already largely developed.
Third, wind is not an efficient or reliable source of electric power. Electricity is generated only when the wind blows, and that may not be when consumers need the electricity. Utilities must therefore still have available coal and natural gas power plants to provide electricity when the demand arises, even if the wind is not blowing. Again, until we can solve the battery storage problem so that wind energy can be stored as electricity until it is needed, wind will be only a small contributor to the nation's energy problems.
On March 27, the Texas Supreme Court issued its opinions in two related cases, both styled Exxon Corporation v. Emerald Oil & Gas Company. The cases were argued before the court more than two years ago, and the decisions were awaited with much anticipation. The Court reversed a judgment against Exxon for $8.6 million in actual damages and $10 million in punitive damages.
The facts in the case are remarkable. In the 1950's Exxon's predecessor Humble Oil & Refining Company obtained oil and gas leases covering several thousand acres in Refugio County owned by the O'Connor family. The leases were quite unusual; among other things, they provided for a 50% landowners' royalty. Exxon drilled 121 wells and produced more than 15 million barrels of oil and 65 billion cubic feet of gas from the O'Connor lands. In the 1980's Exxon asked the O'Connors to reduced their royalty, claiming that the leases were becoming uneconomical. Those negotiations failed, and in 1989 Exxon notified the O'Connors that it intended to start plugging wells and abandoning the leases. Negotiations for the O'Connors to take over operation of the wells were not successful, and Exxon began plugging wells and abandoning the leases.
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.
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.
Second, I think that the lessee has a good point as well. The lessor should not be able to terminate a lease because of inadvertence, or an innocent mistake, in paying royalties. A well-drafted termination clause should provide that, if royalties are late, the lessor must give written notice to the lessee and an opportunity to cure the problem. Only if the late payment is not rectified should the lessor have the right to terminate the lease.
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."
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.
Even where the oil company has negligently or intentionally caused excess damages, it is very difficult to recover for those damages absent express contractual authority. A good example of the difficulty faced by landowners suffering surface damages is Primrose Operating Company v. Senn. In that case, the Senns bought a large ranch in West Texas that had extensive oil and gas activity at the time of their purchase, with 500-600 producing wells. After their purchase, the Senns had particular problems with one of the operators, Primrose, which had more than 86 spills of oil and salt water. Testimony at trial showed that it would cost more than $2 million to clean up the spills. The Senns obtained a judgment, after a jury verdict, for $2,110,000 in actual damages and $880,000 in punitive damages. But the court of appeals reversed and held that the Senns were entitled to no compensation. It ruled that, because it was not "economically feasible" to remediate the spills, the damages were limited to the reduction in market value of the ranch caused by the spills, and that, since the value of the ranch had increased since the time of the spills, there was no evidence that the Senns had been damaged.
Any lease by a mineral owner who owns the surface of the leased premises should therefore address the rights of the lessee to use the surface estate and the lessee's obligation to pay compensation for use of or damage to the surface of the lands.
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:
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.
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.
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.
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.