We asked our Zintro experts about the pros and cons of the proposed TransCanada Keystone XL Pipeline. What are the risk factors for the environment? What kind of benefits does the pipeline offer? Here are their responses.
Foboni, an expert in risk and crisis management and risk-based decision making, says that he is participating in the review and risk assessment of a large, long-term project in Northern Canada (Arctic). “Long-term projects around the world, and in particular in the Arctic region, are exposed to a large number of hazards deriving from extreme conditions, and in particular climate change. Warming and the resulting loss of permafrost (the permanently frozen layer of soil and rock) are causing trouble and will bring havoc in the future to the natural environment, and of course, to any permanent structure,” says Foboni. “If proper risk-based decision making has not been performed from inception, with well balanced and sustainable mitigative programs, the hazards will have unpleasant consequences.”
Nigel, an environmental consultant with a blue chip oil and gas background, says the challenges of the Keystone XL Pipeline have been largely met in many locations, including the Alaskan/Canada corridor and many parts of Russia and other cold temperate and arctic zones. “The primary concern should be for the Tundra, in that a buried pipe may not only threaten the delicate balance of temperature, but interfere with fauna associated with these zones,” he says. “Vibration and the potential heat associated with the passing crude may have an impact. Pipeline integrity from the point of view of corrosion monitoring and regular pigging would be an essential provision. Pipeline integrity from the point of view of damage from collision or sabotage is equally important.”
Nigel points out that pumping stations are required throughout the route, with consequential infrastructure associated with the servicing of these stations and way leave examination. Provision for migration routes is needed and a route avoiding areas of special sensitivity should be considered. “Depending upon population density, some economic value may be available for isolated communities in supporting the pipeline construction and consequential supervision,” says Nigel. “However, the case is more likely to be made around the cost-benefit case of accessing the tar sands and generating refined product. The energy costs and environmental impacts, such as energy consumption (fossil or non-fossil), carbon dioxide emissions, and hazardous waste, from production have a cost”.
Dr. Kilpatrick, an economic policy consultant, says that liquid petroleum products made from refined crude oil are primarily used in transportation and manufacturing with a small amount used for home heating, mainly in the Northeast. They cannot be entirely replaced by more environmentally friendly fuels, such as solar and wind, unless and until vehicles are powered by electricity. “At this point, who knows what the law of unintended consequences of that path might be? Meanwhile, the demand for this oil exists, and it will be supplied from somewhere,” says Kilpatrick. “Gas and oil pipelines are built all over the US, usually with little opposition. While human error and corrosion do cause some amount of environmental damage, pipelines are the safest, most environmentally friendly means of transporting hydrocarbons. The root of the opposition to the Keystone XL Pipeline seems to be the production of oil from tar sands in Alberta, CA.”
Kilpatrick says that it is hard to get a handle on how many jobs the pipeline will create. “Most of the numbers are produced by sources with a stake in the outcome, and thus not reliable. I would argue that it will primarily create temporary construction jobs and provide a short term boost to motels, restaurants, and shops in towns along the pipeline route. But, the number of people needed to actually operate the pipeline, including inspection and maintenance, will not be large.”
Alan Herbst, an energy consultant, says that after years of planning, regulatory and environmental review, on August 26, 2011, the US State Department released the Final Environmental Impact Statement for TransCanada’s Keystone XL pipeline project. This review stated there were no environmental obstacles present to prohibit the pipeline’s development and is expected to result in US State Department approval of the project, the last significant hurdle necessary for its permitting and construction.
“The XL project is an expansion of the existing 600k b/d Keystone pipeline that runs from Alberta, Canada to refineries in Illinois and storage facilities in Cushing, Oklahoma. The XL expansion will provide an additional 700k b/d of pipeline capacity and enable crude oil from Canada and North Dakota’s Bakken field to reach refineries in Houston and Port Arthur, Texas,” explains Herbst.
“Proponents of Keystone XL cite the economic benefits (direct and indirect job creation, greater tax revenue and potentially lower oil prices) resulting from the multi-billion dollar project. Opponents have expressed concerns over potential pipeline leaks that could pollute surface water and area aquifers,” says Herbst. “Some pipeline opponents are looking to hinder the further development of Alberta oil sands sector by attempting to limit further construction of regional pipeline takeaway and export capacity.”
While safety and the environment are legitimate concerns, the XL expansion project will meet or exceed all US pipeline safety regulations, will be constructed from high strength steel, and have a fusion bonded epoxy coating along with active cathodic protection to prevent corrosion. “The pipeline will be remotely monitored 24-hours a day and buried at depths from 4 to 25+ feet depending on location. These features permit the safe construction and operation of the Keystone XL pipeline,” says Herbst.
Herbst says that the pipeline, which is expected to enter service in 2013, will provide an outlet for the increasing amounts of crude oil entering Cushing, which has created a supply glut (currently 31 million barrels are in storage) and depressed prices at the NYMEX delivery point. “This abundance of supply has inverted and widened the Brent/WTI spread, which at times has Brent trading at a $25 premium to WTI. Brent, a slightly lower quality crude, was traditionally valued at a $1.25-$1.75 discount to WTI,” he says. “Once the Keystone XL pipeline and one or two other pipelines are built to increase crude oil transport capacity to the US Gulf, the Brent/WTI spread will begin to narrow and possibly revert back to its traditional pricing relationship. This pipeline development will also provide US Gulf refiners with access to growing amounts of high quality Canadian and US crude, lessening their reliance on oil imports from Europe, Africa, Mexico and South America.”
Trans-Continental Pipeline – The current maritime shipping method of transporting liquid fuels between Canada and the United States is protected by a series of U.S. Coast Guard provisions and requirements covering operating procedures and safeguards of the loading ports of origin; shipboard design, construction and operation; (of vessels involved); operating procedures and safeguards at ports of delivery, plus comprehensive liability insurance coverage peculiar to this trade. With over one hundred years of experience in maritime transportation of petroleum products (off the East, West and South coasts of the United States), the overall risks and accrued safety record are well-known factors serving to support the predictability of safe assurance and continuity of this form of trade.
Whereas a proposed trans-continental pipeline may be susceptible to a variety of Federal, State, and Regional jurisdictions and their inherent limitations, requirements and/or provisions, including seismic and environmental limitations. The associated potential risk factors including human life exposure, property damage and subsequent environmental impact, while difficult to estimate within reasonable accuracy, may be seen to outweigh whatever favorable considerations as may be presented by proponents of such an option. Louis J. Lemos
Dear Louis,
Thanks for your comment. If you haven’t already joined Zintro, you would be a great addition. The easiest way to proceed (so that you can market your services to our clients) is for you to go to http://www.zintro.com/choose?aff=wp&mod=Experts and sign up as an expert. That way, relevant client inquiries will automatically be forwarded to you.
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TABLE OF CONTENTS
Chapter 1. Report for mineral Owners.
Page 2. Initial research prior to talking to the landman.
Page 9. Negotiating the up-front money.
Page 17. Royalty information starts here. “The real money”
Page 23 Shut-in Provisions
Page 26. Surface damage from wells and for pipelines too.
Page 30. Pugh Clause
Page 32. Pooling
Page 32. Assignments
Page 36. Horizontal drilling
Page 38 Checking to see if you own your minerals.
Page 45. Sample lease.
Chapter 2. Easements and choices and pipeline corridors.
Page 71. Easement negotiations.
Page 77. Finding the property value.
Page 82. Stopping the easement.
A bit about landmen and the energy companies.
Page 89. In conclusion. A quick summation of dealing with the oil and gas companies and why pipelines are where they are.
This Report is for Mineral Owners
And surface owners
This is not legal advice.
If you own all or part of the minerals under your land, an energy company seeking a lease to explore for oil or natural gas on your land should be a welcome sight. After all, wells producing oil or natural gas on your property could mean very substantial income, even wealth. But before exploration activities can begin, the mineral owner and the energy company have to reach agreement on certain terms regarding the rights, privileges and obligations of the mineral owner and the company during the various stages of exploration and production operations. A contract setting out these rights, privileges and obligations is called an Oil and Gas Lease. As a mineral owner, you may never have seen an Oil and Gas Lease before, and so you will probably be at a disadvantage in negotiating terms that will be favorable to you.
When an energy company (hereafter, the energy company that is seeking rights on your property will be referred to simply as the “Company”) wants to drill a well on your property, the Company first has to obtain an Oil and Gas Lease from you. (Hereafter, the Oil and Gas Lease that you are negotiating will be referred to simply as the “Lease.”)
The Company will send a “Petroleum Landman” aka “Landman” to contact you and negotiate the terms of the agreement that will allow the Company to explore on your land. Never forget that THE LANDMAN REPRESENTS THE COMPANY, not you, even when the Landman tells you that he is not working for the Company directly but only as a contractor from a different business. The Landman’s job is to determine who owns the minerals under tracts of land like yours and then to negotiate a Lease on behalf of the Company so that exploration can proceed.
He will be trying to obtain the best possible deal he can for the Company. He does not represent you and he will not be trying to protect your interests. You will have to do that for yourself.
There is no standard or universal lease form in use by the oil and gas industry as a whole. Instead, each company has a predrafted agreement, usually a version of a Producers 88 Lease Form. The agreement is, naturally, in the best interests of the energy company. You should remember that ALL PROVISIONS OF A LEASE ARE NEGOTIABLE. The Landman negotiating with you may not be authorized to make any changes to the proposed Lease personally, or he may be authorized to make only certain changes that the Company expects that you will demand in exchange for your agreement, but any provision of the Lease is subject to negotiation, so if you demand a change in the provisions of the Lease that the Landman is not authorized to make, he is required to take your counter-offer back to the Company. If the Company wants a Lease from you badly enough, you may get what you ask for.
1. Your ability to negotiate favorable terms will depend on your situation.
First, how much mineral acreage do you own? (You can determine your “mineral acres” by multiplying the amount of land you own by your percentage of ownership of the minerals. For example, if you own all of the minerals under a 160-acre farm, you would be said to own 160 mineral acres. If you own half the minerals under a 240-acre tract, you would be said to own 120 mineral acres.
If you own 5% of the minerals under a 2-acre tract, you would be said to own 0.10 mineral acres.) The more mineral acreage you have under your control, the better your negotiating position because energy companies tend to approach the largest mineral owners in an area first and try to get them to reach an agreement before they go after smaller tracts of land.
Second, how close is your mineral acreage to currently existing producing wells? (One way to find out is to call the state agency in your state that regulates oil and gas development and ask if there are currently any producing wells in your County or Parish. If there are, ask if there are wells in your immediate area. Another way to find out is by contacting the Bureau of Land Management to check if any Federal Mineral Lease Auctions have taken place in your area.
If the federal government owns land near you, and chances are reasonably good that it does, and if there is oil or gas in your area, the Federal Mineral Lease Auction will tell you how much some energy companies have already been willing to pay for Leases in your area. Similarly, you can contact your state government to find out if there have been any State Mineral Lease Auctions in your area. Typically, these auctions take place two or three times a year. Such Auctions will tip you off as to what areas are particularly sought after by energy companies; the higher their bids on certain property, the more anxious the energy companies are likely to be to acquire additional lease acreage in that area from you.)
The closer you are to existing development, the more valuable your mineral acreage is because it suggests to energy companies that your land may also be sitting atop the same oil and gas reservoir.
Finally, the more energy companies looking for a Lease in your area, the better your negotiating position becomes. This should be obvious from everyday experience with making purchases; if you are buying a car and you approach three dealerships instead of one, telling each one what the others are offering you, you are more likely to be offered a better deal than if you accept whatever is offered to you at the first dealership you walk into. When you are approached by a Landman, try to find out what company he represents and try to find out if there other companies he is competing against in the area. Alternatively, try talking to your neighbors to see if any of them have already been approached by the Company that approached you or by other companies. If you get the names of other companies, contact them directly even if they haven’t contacted you, so as to play them off against each other. Bidding in bonus payments, royalties, and other incentives is fairly common, especially in areas that have attracted a lot of interest.
If you decide to make some counteroffers (see examples of such counter-offers later in this manual) the Landman probably won’t be able to accept them or reject them on the spot.
He will have to take your counter-offers to the Company and get back to you when the Company decides how it wants to respond to your offer.
This will delay negotiations somewhat, with the result that you won’t receive your initial “bonus payment” as quickly as if you had accepted whatever the Landman placed before you at first, but you shouldn’t worry about this delay. Because oil and gas wells are often linked to wealth, your views of the negotiating process may be distorted by your hopes and dreams for what may happen in connection with energy exploration on your land, and you may be tempted to sign the first Lease offered to you as quickly as possible. But A HASTILY EXECUTED LEASE MAY TURN YOUR DREAMS INTO A NIGHTMARE.
There are four ways to incorporate negotiated terms into your Lease. First, if the Lease only needs minor changes, strike (that is, draw a line through ) the part of the provision that you are changing, write in the change or changes that have to be made, and then have both parties (the Landman and you) initial and date the margin of any page that you have changed.
This is the procedure to follow if, for example, all you are changing is the Lease Royalty (from 1/8 to 1/6 or some higher interest).
Second, if you have negotiated more extensive changes to the Lease, an Addendum or Exhibit may have to be added or attached to the Lease listing all of the changes and declaring that the provisions contained in the Addendum or Exhibit supersede any provisions contained in the body of the Lease itself. The Addendum or Exhibit will also have to be referenced on the Lease itself, typically in the area where the Legal Description is given on the first page of the Lease.
Third, if the terms you have negotiated with the Landman are such that the Company wants them to remain private rather than a matter of public record, as they would be if a Lease containing those provisions was filed in the County Courthouse, a Memorandum of Agreement or Memorandum of Lease may be executed along with the Lease and the Addendum or Exhibit. The Memorandum usually contains the minimum amount of information necessary to give “constructive notice” of the Company’s Lease, including the name and address of both the mineral owner (Lessor) and the Company (Lessee), the Lease date, the length of the primary term, and the legal description of the property under Lease. Alternately, a Letter of Agreement may be used in place of a Memorandum of Agreement. Letters of Agreement are also used to deal with minor issues that don’t relate to the Lease itself.
Lastly, if the changes are extensive, you may want to simply rewrite the Lease Agreement altogether, although the Company will probably resist this option, since it might lead to the elimination of the standard clauses in their pre-drafted Lease that are helpful to them.
Before considering specific aspects of the Lease Agreement, you will want to consider the Company and person you are dealing with. Not all companies are financially equal and not all companies treat mineral owners with the same degree of respect. It should be remembered that when you agree to allow oil or gas exploration on your property you are effectively getting into business with the Company you lease your minerals to. Would you get into business with just anyone? In many cases, less favorable Lease terms from a stronger or more reputable company would be preferable to better Lease terms from a weaker company.
Who will be signing the Lease on behalf of the Lessor? If it is the Company itself, you can determine whether the Company is legally authorized to do business in your state by calling the Secretary of State (in most states, the Corporations Division) and asking for the name and address of the registered agent of the corporation. If the Secretary’s office can provide such a name and address, the Company is duly authorized. You can then google the name of the Company on the Internet to find information about the financial solvency and solidity of the Company, and perhaps even to see how this Company has dealt with other landowners in the past. You may also want to ask the Landman if the Company you are dealing with is likely to be the producer of oil or gas on your property or whether the Company will be assigning any interest it obtains through the Lease to another company which will actually be producing the oil or gas. If you can discover the identity of the producer, you can follow up by checking with your state government’s oil and gas regulators to see how many wells the assignee company has already drilled, how much oil or gas has been produced from those wells, and whether royalty and surface owners of the land under production have been paid in a timely manner.
You will also want to find out if there are any lawsuits pending against the producing company in your area (check at the Clerk’s Office in your local courthouse) and, if so, what the alleged offenses were. If a producing company hasn’t been paying its royalties in a timely way, you’re better off knowing that right off the bat rather than when money you are counting on doesn’t arrive.
If an individual is going to be signing the Lease, it is all the more necessary to determine who the producing company will actually be.
If the individual who is taking the Lease cannot or will not tell you which company will actually be doing the exploration, then it is more likely that your “bonus payment” may be the only money you ever receive in connection with the Lease. The person taking your Lease may be gambling that the money he is paying you for the Lease will come back to him when he can find a producing company that wants to drill in the area.
Sometimes that works out great for him and for you, and an excellent producing company is found, but there are no guarantees in the Lease that the Lease will ever be assigned at all or that any exploration activities will ever take place. If possible, try to determine what companies the prospective Lessee has dealt with in the past, on the assumption that he will try to approach the same companies with your Lease.
SHOW ME THE MONEY
The most important terms of any agreement that leads to the execution of an Oil and Gas Lease are the ones that relate to how much money you are supposed to receive and how certain you are to receive it. Let’s start by considering the kinds of payments that you as a Mineral Owner can expect to receive in connection with the Lease.
1. Rental or “Bonus Payments” During Primary and Secondary Terms. If you were going to lease a house to someone, you would expect the person to pay you rent for the period of time during which he planned to occupy your house. A “bonus payment” is the Company’s rental payment for the minerals you are leasing to it. Sometimes the rent is paid on a yearly basis, leaving “Delay Rentals” for the second and succeeding years, and sometimes rent is paid for the entire period of the Lease in advance. At the time of signature of the Lease, you should receive at least one year’s worth of Rental payments for your mineral acreage, and preferably payment for the entire term. These payments should come directly from the Company.
2. Production Royalties. Even though the Company is leasing your minerals from you, it doesn’t own those minerals. When oil or natural gas begins to flow from the ground, the Company has to pay you for that oil and gas. The “production royalty” is the payment the Company tenders you for “your” oil or gas.
3. Extension of Primary and Secondary Terms, Shut-In Royalties, Etc. If the Company could be extracting oil and gas from the ground but is not choosing to do so for economic reasons, the well may be said to be “Shut-in.” A decision to declare a well shut-in has a negative impact on you; you would be getting Production Royalties if the Company was producing oil and gas, but they’re not. To make up for declaring a well “shut-in,” the Company agrees in the Lease to give you some compensation. These are the “Shut-in Royalties.” Since you are always better off with Production Royalties than with Shut-in Royalties, with any luck you won’t actually ever receive such payments.
4. Surface Damages. If you are the surface owner of the land on which the well is placed, you may be entitled to payments if a well is plugged or abandoned, or if the exploration only produces a dry hole. If you get a surface damage payment, you have reached the end of the production cycle and won’t be receiving any more money.
1. Rental Payments. The first type of payment you will receive is the Rental Payment. This will come from the Company in the form of a “sight draft,” not in the form of a check. A “sight draft” is a collection item: when you sign the back of it and deposit it in your account, your bank forwards it to the Company’s bank. After a specified number of banking days (not calendar days), typically 30 or 45, the Company has to honor the sight draft and pay it.
Or, it has to deny payment. If the Company doesn’t pay the sight draft, you have no deal (and never actually had a deal) and you have no recourse. You can strike a deal with a different company, or you can reopen negotiations with the Company that refused payment on its sight draft, but you may well be starting from scratch in either case. What is the point of giving someone a sight draft instead of a regular check? First, the Company may not entirely trust its Landmen, and may not like the idea of giving them a checkbook and the right to sign checks that would bind the Company to tens of thousands of dollars in payments without oversight.
Second, they give the Company time to check the title work done by the Landman to make sure that the people he thinks should be paid for the Lease are the people who actually own the minerals. Third, they give the Company time to determine that the Lease is the same one negotiated between the parties. Once all of the Company’s internal paperwork is complete, the draft is approved for payment. Although a Company could decide not to honor a sight draft for any reason at any time prior to approving payment, in practice, once the title to the mineral acreage is confirmed and the Lease is checked, the sight draft invariably turns into money in your account. (But in one recent case, a court ruled a landowner was free to make a deal with a different company up to the moment when the sight draft is honored. It’s not a deal until you get paid.)
Chances are you will at least ask to be paid by check rather than sight draft, and chances are equally good that you will be told that the Company won’t do business that way. In that case, you can at least negotiate the number of days specified on the sight draft. It says “45 days” on the draft? You should be able to get them to bring this down to 30 days at most (as it happens, 30 banking days is just about 45 calendar days anyway), and maybe even to a period as short as 10 or 15 days.
The amount of the Rental Payment is based directly on the Term of the Lease. The actual term draws from several portions of the Lease Agreement, including the paragraphs that define the Primary and any Secondary Terms of the Lease, and the Extension of those Primary and Secondary Terms. The first part of a Lease Term is the Primary Term, a set number of years (or months) negotiated between the parties during which time drilling operations are expected to begin. There are two ways a Lease can address financial obligations during the Primary Term.
A Lease may be said to be “Paid Up,” in which case the “Bonus Payment” (actually, the Lease Rental Payment) offered is intended to cover the entire Primary Term of the Lease with no additional payments required during that period. Alternatively, the Lease may require “Rental Payments” on a yearly basis, in which event the initial Bonus Payment will only cover the first year of the Lease. A “Paid Up” Lease is generally considered preferable to a Lease with Rental Payments since you get all of the money associated with the Primary Term of the Lease in advance instead of having to wait for years to pass before you receive the entire rental amount.
If no drilling operations commence within the entire Primary Term, the Lease terminates at the end of the Primary Term.
If the Lease was “Paid Up,” no further payments by the energy company to the mineral owner are required. If Rental Payments were required, however, a yearly payment has to be made in order to keep the Lease active. This type of delayed rental payment is referred to as a “Delay Payment.”
Such payments usually must be made to the owner in a timely manner, on the anniversary of the Primary Term, or the Lease is deemed to automatically terminate. (If a Delay Payment is called for in your Lease, make sure the Lease also says that the Lease terminates UNLESS a Delay Payment is made in a timely manner. It is possible to write this term so that the energy company can put off making the payment for months.) Make sure that if a Delay Rental is called for in your Lease, it says that the Lease terminates “unless” a payment is made on time.
Since most Leases are “Paid Up” these days, the company seeking the Lease should be willing to agree to accept your proposed language on a Delay Rental if you will accept such a payment.
When you are negotiating a Lease Term, the mineral owner should try to keep the length of the term as short as possible. Some energy companies will ask for a ten- or even twenty-year term, but they will never insist on a term that long if you resist. A three-year to five-year term is much more likely, but even when a three-year term is offered, the mineral owner should try to shorten the term if he can. Many Primary Leases are as short as six-months, especially if the energy company is sure that there is oil or natural gas in your area.
Some companies may try to get you to agree to an option to extend the Primary Term for an additional period of time upon the payment of an additional sum of money at the end of the Primary Term. Do not agree to an extension that doesn’t involve payment of additional money at the end of the first term at a price to be negotiated at that time. Don’t set the price for the second lease term when you set the price for the first term. Things can change in a few years.
Let’s say during the first lease term they do not explore on your land but they do find oil and/or natural gas on one of your neighbor’s land. The value of your mineral lease would increase quite a bit.
If you cannot negotiate a shorter primary term try to negotiate a higher Bonus Payment or Delay Rental payments. Keep in mind that Bonus Payment is based on the length of the Primary Term, so if the Company is ready to pay you, for example, $3,000 per mineral acre for a three-year term, they should be willing to pay you $5,000 per mineral acre for a five-year term on the same land.
In the case of Delay Rental payments, acceptance of a late payment could be construed as a modification of your Lease.
It is best, therefore, to make sure that the Lease says that Delay Rental payments must be received on or before the due date, and not simply postmarked on the due date. It should also say that non-payment of the Delay Rental will automatically terminate the Lease; you should insist on the deletion of any Lease provision requiring that prior notice be given to the Company in order for non-payment of a Delay Rental to terminate the Lease. Make sure the Lessee Company identifies the Lease they are making a Delay Rental payment on. This will help you keep track of payments on Leases and will help with your record-keeping, especially when all or a part of your Lease has been sold to another oil or gas company.
After the Primary and Secondary Terms of the Lease have expired, a third potential part of the Lease Term is made up of Extensions of the Primary and Secondary Terms.
The most common reason to extend your Lease will be if oil or gas production begins. The Lease Term is extended for so long as oil and gas production continues. Such an Extension is in your best interest, since oil and gas are being produced from your land, you are entitled to quarterly payments of Royalties (see “Royalties” below).
As to all portions of your land that are part of the Production Unit (the land which is deemed to be above the reservoir of oil or gas that is being drilled). Sometimes the Production Unit (also known as the Spacing Unit or Pool) is set by the Bureau of Land Management, or by the agency of a state government that regulates oil and gas production, like the Railroad Commission in Texas, but you should be getting paid for all of your land that is deemed to be a part of the Unit the well is drawing product from.
It is possible that not all of the property that you leased will be deemed part of the Production Unit. Even so, all of the land you leased will be deemed “held by production” if even the smallest sliver of your land is part of any Production Unit UNLESS you have a “Pugh Clause” in your Lease. (See “Pugh Clause” below for information on this important aspect of negotiating with an Energy Company.)
Key points to remember when negotiating the Lease Terms and the payments associated with it are:
(a) Try to keep the Lease Term as short as possible, to force earlier exploration;
(b) Try to negotiate as high a Bonus or delay rental as possible;
(c) Use the word “unless” instead of “or” whenever you can;
(d) Be careful about establishing a date for payment of Delay Rentals or other payments;
(e) Be careful about accepting late payments, since such acceptance can serve as a ratification of the failure to make timely payments;
(f) make the Company identify the Lease for which any Delay Rental is being paid so that you can keep track of your Leases more easily; and
(g) Require the Company to make payments so that they are received by the deadline rather than postmarked by the deadline.
2. All Leases contain a paragraph that allocates to the mineral owner a certain portion of the oil, gas, or minerals being produced. This is called “THE ROYALTY CLAUSE”
The Royalty Clause is potentially the most important part of a Lease to a mineral owner, since it is the part that could make you big money. The allocation of Royalties can be stated in terms of market price, market value, or proceeds in kind, but it will invariably give a fraction or a percentage of Royalty, never lower than 1/8th (or 12-1/2%) and rarely higher than 1/4 (25%). Negotiating a good Royalty Clause is one of the most important considerations facing a mineral owner.
In negotiating a Royalty provision, remember that “the higher the percentage of Royalty, the better off you are.” Try to find out from neighbors what they have been offered.
A Royalty will almost always be between 1/8th and 1/4, but it might be almost anywhere in between depending upon how certain the Company is that oil or gas will be found in your area.
Never take the first Royalty percentage offered, as it can almost always be improved upon. If you have been offered 1/8th, you should be able to get at least 1/7th and perhaps as much as 1/6th; if you have been offered as much as 1/6th, you should be able to get 3/16ths; and so on.
If no one in your neighborhood has been approached by a petroleum landman, you may be able to get a solid clue as to what the Company is offering other mineral owners by going to your local courthouse and checking to see if the Company has already filed other Leases from other property owners in your area. Since the first Leases the Company will seek will be from professionals in the oil and gas industry or from property owners with large amounts of land, the Leases at the courthouse will provide a good estimate of what the Company might offer you. If there are a number of Leases already on file, the percentage of Royalty offered to professionals in the business will tell you how high you have a chance of going in your own negotiations for a Royalty percentage.
Unless you have purchased a working interest in the well, which is unlikely if you have been approached to give an energy company an Oil and Gas Lease on your property, all expenses encountered in the production stages will be borne solely by the Company if the Lease says that the value of the substances are fixed at the wellhead. In the course of negotiations, you should make sure this language (fixing value at the wellhead) is included in your Lease. The alternatives are a Royalty “in the pipeline,” “at the point of sale” or at other delivery points.
If you accept any of these alternatives, you are likely to get less money than if your Lease specifies valuation of the oil or gas “at the wellhead,” because your Royalty may take into account compression expenses or refining expenses necessary to make the final product, delivery into the purchaser’s pipeline, transportation costs, expenses necessary to make the product salable, and expenses used in measuring production.
You also want to consider how the Royalty payment is valued. The Lease will include one of several methods for value determination.
The Royalty may be based on the Market Price of the product; often this is defined as the highest posted field price.
If there is no field price, the Royalty value may be determined by “Comparable Sales” in time, quality, quantity and availability. The Royalty may also be evaluated by “Proceeds”; that is, the actual revenue derived from sale of the final product. Finally, the valuation might be made “in kind,” giving you the amount of the product you are entitled to and allowing you to market it as you see fit. If a Market Price valuation is based exclusively on a posted field price, it is not as strong a provision for the mineral owner. For example, the posted price in an area may be set artificially rather than by competitive pressures and may therefore be substantially lower than the prices being paid for comparable minerals at other fields. Even Leases that read “at the highest price or percentage of a posted field within 100 miles by any major oil company for like grade and gravity on the day the oil is removed” may put an energy company in a position to choose a Royalty valuation that isn’t as advantageous to you as one that refers only to Market Price. Evaluating the Royalty based on Proceeds is even worse than based on posted field prices, because since the Royalty value is based upon the actual revenue derived from the sale of the product, it will almost certainly factor in a range of energy company costs that you shouldn’t be liable for.
Royalty payments based on proceeds have proven popular for marketing gas because of the large rises and drops in prices; the Company argues that both parties should commit to a long-term gas price contract, which would allow the Company to assure the mineral owner a constant, dependable Royalty income over time. However, the problem is that proceeds seldom rise as quickly as market prices rise.
Evaluating Royalties based on taking them “in kind” is often a good one for the mineral owner because if the market price rises above any long term commitment price, the mineral owner can take his share in kind and seek a market outlet.
Alternately, if the market price falls below any long term commitment, the mineral owner can take the Lessor’s share of proceeds. If you can’t get the Company to agree to Royalty valuation based on actual Market Price, then “in-kind” may be the best remaining option.
You will also want to make sure in the course of your negotiations that cash flows are adequately protected. The payment provisions should all be conditions of the Lease rather than just Lease covenants. What is the difference between a “condition” and a “covenant”? If something is a condition of the Lease, breaching it automatically terminates the Lease, while if something is a covenant of the Lease, you may have no way to enforce it except to bring an action against the Company in court. If your only recourse when you are not being paid what is supposed to be coming to you is to sue for damages, you are much less likely to take action (the legal fees alone might put you off if the Company tells you that you will be paid “shortly”). By comparison, if the Company could see its Lease terminated if it fails to make payments to you, it is much less likely to take such a risk.
Also, it is useful to insist that the Lease contains full details as to the time, place, and frequency with which Royalty payments are to be paid. Outline the consequences for missing a royalty payment, and demand more by way of a penalty for a delinquent penalty than “interest only.” It is critical that you maintain the option to terminate the Lease if required payments are late by more than 90 to 180 days.
If your Lease terminates because of nonpayment, ask for a provision that will forfeit the equipment, pipe, casings, and other machinery used in production to you so that you can use them to withdraw any remaining gas or oil. Also, consider whether or not the Lessee Company has the right to disburse royalty payments. Some oil and gas purchasers will pay 100% of the proceeds to the Lessee and require the Lessee to pay the mineral owner’s royalty. The company may try to hold back a portion of the royalty if they think someone else may own a share of it if they have full control of the purse strings. Protect your rights to your share. If you may be responsible for any portion of production costs, consider asking for an extra royalty or an “overriding royalty” to recover part or all of those production costs. Try to negotiate a provision that in the event any division order is not in conformity with applicable statutes, the mineral owner has the right to alter the division order to comply with the Lease. If making changes to the division order costs you out of pocket money ask that the Lessee agree to pay for it in advance. Finally, try to get a Minimum Royalty provision in your Lease. This will prevent a small amount of production from keeping the Lease open on a large number of acres. Such a provision states that unless a certain amount of revenue is received annually from royalties or other sources, such as shut-in royalties, the Lease terminates.
Keep in mind, the well head has a shut-off valve. The production can be controlled at the valve. If your well starts out producing, let’s say, 1400 barrels per day, then drops to 200 barrels per day. Find out why. Check on the “other wells” in the area. See what they are producing. Two things can cause this to happen. 1. They are paying you ¼ royalty and the other wells 1/8th royalty. They get more money from the other wells.
2. Some small wildcatters may take in investors to help pay for the initial well. If it pans out, the wildcatter will then drill four or five wells around the primary well using his own money and collecting 100% from them. The well with the investors may get turned down to ¼ capacity while his personal wells run full blast.
The mineral reservoir is only so big. Any mineral coming out of the other wells is money coming out of the wildcatters’ pocket. He wants it all. By keeping your well dribbling production, he can consider it as a storage area for product at a bargain price.
A summary of important issues to consider when negotiating about Royalty payments include
(a) Time, place, and frequency of royalty payments;
(b) Penalty provisions for delinquent payments;
(c) Insist that the Lease address whether the Lessee has the right to disburse royalty payments (operators have been known to keep such Royalty funds and then disappear);
(d) Consider asking for an Overriding Royalty based on recovering all or a certain percentage of production costs;
(e) Ask for free natural gas (sometimes granted for domestic or agricultural purposes);
(f) Determine whether the Company should have free use of water, oil, or gas produced on the premises;
(g) Provide that costs subsequent to production may be deducted from the Royalty, but only if they are reimbursed on a quarterly basis;
(h) State that any division order tendered after production begins cannot be deemed to alter the Lease (give yourself the right to alter a non-conforming division order); and
(i) Make sure that there’s a minimum royalty provision in the Lease.
3. Most Leases contain what are called “shut-in” provisions, “dry hole” provisions, and “cessation of production” provisions and any of those sorts of provisions can result in an extension of the Lease Term beyond the Primary and Secondary Terms. These terms can result in additional income being paid to you as the mineral owner.
A “shut-in” well is one whose production is not being sold or otherwise used by the Company. Provisions relating to a “shut-in” well in a Lease allow the Lease to remain in effect for a period of time with respect to a “producing well,” even if no oil is actually being produced or sold by the Company.
However, the Company has to pay a mineral owner a Royalty for shutting-in a well. Such a Royalty, like a Delay Rental, must be paid on a yearly basis. When negotiating a shut-in well provision, it is important to put a maximum limit on the time that a well can be shut-in. Three years is ordinarily accepted by an energy company as a reasonable period of time to limit shut-ins, but it may be possible for you to get the Company to agree to a two- or even one-year period during which an otherwise productive well can sit idle.
Dry-hole provisions don’t require payment from the Company to you, but they extend both the Primary and Secondary Terms of the Lease, and so negotiating them properly can make a financial difference to you as the mineral owner.
A dry hole refers to a well that has not actually found any oil or natural gas. Dry-hole provisions provide that if a dry hole is drilled, the Lease can continue if the Company begins “drilling or reworking operations” (i.e., tries drilling again to see if it can find what it’s looking for in a slightly different location), typically within 90 days after the dry hole is drilled.
Even if the Company was actually drilling the dry hole at the time the Lease would have expired, the Lease won’t automatically expire when work on the dry hole is completed, since the Company will typically have 90 days to try again.
Cessation of production provisions are like the dry-hole provisions except that they come into play after oil or natural gas has been discovered. Typically, if the Company makes another effort to find a well on your property, your Lease remains in effect.
It is technically possible for a Lease term to be extended indefinitely by the dry-hole and cessation-of-production provisions, but in reality that does not happen because of the high costs involved.
Newer Leases combine the dry-hole and cessation-of-production provisions under the heading known as “Operations.” Most mineral owners find that dry-hole and cessation of production provisions are in their interests because gas and oil are still being diligently sought. What a mineral owner would have a hard time accepting is the shut-in provision, especially when there is no apparent reason for non-production. With the high costs of bringing a well on-line, shut-in provisions are rarely used except when a buyer can’t be found or there is a lack of pipeline to get the product to the market or the price of product doesn’t exceed the cost of production.
When you are negotiating terms relating to these provisions of the Lease, keep the following matters in mind:
(a) require a maximum period for a shut-in well, and try to keep that maximum period as short as possible;
(b) in addition to any maximum term of shut-in, try to get the Company to agree to escalate the shut-in royalty payments for each year of any shut-in;
(c) try to get the shut-ins limited as to acreage if not as to a stated period (i.e., only the closest 160 acres to the well);
(d) try to get confusion as to the payment of shut-in royalties in the same year as production royalties addressed in the Lease (monthly prepayment by Company of shut-in rentals is best for the mineral owner, but a requirement of accounting may work as well, with a failure to account leading to a forfeiture with respect to any remaining months);
(e) specify circumstances under which the shut-in clause may be invoked (lack of market, lack of an available pipeline, government restrictions, and perhaps a determination by the Company that it is economically inadvisable to produce);
(f) ask that only gas wells be permitted to be shut-in;
(g) automatically terminate a shut-in if an adjacent well within the same producing reservoir begins producing and selling oil or gas in commercially viable quantities for a set amount of recent time.
4. Surface Damages can also result in a mineral owner being paid by a Company or an operator. When you grant an Oil and Gas Lease, you give the Company the implied right to use as much of the surface as it reasonably needs to use to drill for oil or gas. It is only if the Company goes beyond what is reasonably necessary, damages the surface intentionally, recklessly or negligently, or fails or refuses to accommodate other ownership interests in the property that the Company is required to pay surface damages.
The Company is usually under no legal obligation to restore the surface to the condition it was found in after completing the extraction of oil or gas, so a mineral owner is well-advised to insist on inserting provisions in the Lease relating to surface damages.
Most companies have two agreements. One agreement for the mineral lease and another agreement for surface damage. The surface agreement is negotiated with the surface owner. That may not always be the mineral owner.
If you can get the Company to agree to pay for all surface damages (like injuries to crops and pastures, erosion or stagnation of the soil, damage to timber, livestock, fences, ditches, canals, buildings, or other structures, or pollution of any waters) that would be best, but there are other approaches as well.
But remember that just including a provision that the Lessee Company is liable for surface damages may not be sufficient to protect you. For example, if the Company’s financial position is such that suing them for damages results in a judgment that can’t actually be enforced (as when the Company has gone bankrupt), then the provision in the Lease requiring Lessee Company to pay surface damages won’t be worth anything. Do a little investigation of the Company and/or the Operator in advance and you can spare yourself a lot of heartache later. Maybe have them put up a bond or money in escrow to cover damages.
In the opening paragraph of your Lease, the Company will tell you what substances they want to explore for. If only oil and gas are sought, you will have less of a problem negotiating conditions than if the Company is seeking, say, uranium or other hazardous materials.
If the Lease doesn’t restrict the Company to oil and gas, make sure it does; if the Company insists on searching for other minerals as well, make them spell out what they are looking for in the Lease, since exploration for minerals other than oil and gas may create additional problems. For example, minerals that lie near the surface can damage the surface when produced and render tillable land useless. Make sure that you are paid the fair market value of all lost or damaged agricultural land. Make sure that your Lease spells out what minerals are covered by the Lease and which are not, and also make sure that the Lease addresses what will happen if additional valuable minerals are found in the course of exploring for oil and gas. If only oil and gas are being sought, limit the Company’s exploration and production to the “BORE HOLE” method only. Any other methods (such as strip mining for coal) will cause a range of additional damages, and the Company should be required to pay additional money.
To avoid unnecessary surface damage to your land, here are some suggestions.
Don’t grant an unrestricted right for underground disposal of water in any wells on your property without prior written consent.
Keep the Company’s routes into and exiting from your property to a minimum. When possible, insist that they use existing roadways through your property, taking the shortest routes possible. Don’t let them build roads anywhere they want. You should have the last word for the location of the wells and the roads. Charge extra for storage areas and parking areas for their equipment. If a new roadway is built, you should decide if you want the Lessee to remove the roadway or leave it for you to use when the Lease has expired. Do not give the Company the right to use your property in any fashion after the lease has expired.
If you have livestock, specify where you want cattle-guards placed, when they must be used, and who will be responsible for closing and locking gates. You may want to discuss soil erosion if you think that is going to become an issue.
Leases usually do not permit a well within 200 feet of your house or out-buildings, but you may want more distance than that. Make sure that all power-lines, pipelines, and other devices buried in the ground are well below plow depth.
Valve stations or shut off valves need to in a protected fenced area away from dwellings and out-buildings. They require additional space. Valve stations are an eyesore, and you will want additional compensation for having one on your land.
If you are going to be cultivating or grazing the area right above a pipeline, you should insist that the Company use the double ditch method for laying any pipe. This requires the excavator to put the topsoil back on top when he’s done backfilling the hole. Have the lessee replant ground cover of your choice or you do the landscaping and you are paid contractors pay.
Have the excess dirt placed where you want it or hauled away.
In Texas, a Lessee has an implied right to use caliche (like gravel) found on leased land free of charge for the construction of roads and drill sites. You may wish to alter that contractually in the Lease. If they use your caliche or gravel, you should be compensated for it. In other states the material used for building roads could be different.
You will want to specify that the Energy Company be required to remove all structures, casings, and equipment within a reasonable number of days after the Lease expires or those things will be forfeited to the land owner/mineral owner. You will probably want the company to remove materials within 90 to 180 days. This helps prevent problems concerning ownership and clean-up operations.
You may also want to have a clause requiring prior consent before any seismic testing gets done because of the potential for surface damage. There are several methods used. Ask the landman about them.
If you cannot get a Company to agree to pay compensation for all surface damages, try to get it to agree to restore the land to the condition it was in prior to the commencement of operations within a fixed period of time after operations cease. You should take before and after pictures. Describe in the Lease how the extent of damages will be determined and how any disagreement will be resolved (a mutually agreeable appraiser would be a useful way to resolve differences about the extent of damages after the fact). If compensation will be in a single lump sum rather than annually, be very careful that all work has been completed and all damages assessed before accepting any compensation, since you may not get a second kick at the can. Resolve how surface damages will be distributed among the owners of the surface.
Make sure the Lease contains a provision setting forth when damage estimates must be produced and how soon thereafter the Company will pay those damages. Requiring a performance bond or an escrow account as security for the Company paying the Surface Damages may make sense, if the Company acknowledges that it will cause substantial damage. Finally, if the Lease is assigned (see “Assignment” below), make both the Company and the Assignee jointly and severally liable for surface damages. If the Company refuses to do that, require surface damages to be paid before assignment can become effective.
5. There are a range of other provisions that will come up in your Lease negotiations that may make an important difference in how much money you make in connection with exploration for oil or gas on your land.
A critical provision is called a “Pugh Clause,” and it is designed to make sure that you are getting paid for all of your land and not just part of it. A Pugh Clause typically takes one of two forms.
A Spacing Unit or Production Unit Pugh Clause states that any land that is not part of a Spacing or Production Unit at the termination of the Primary Term of the Lease is released from the Lease (unless it is held for a different reason unconnected with the Spacing Unit). What that means is that if, after oil or gas production commences on your land, you are only receiving royalties on five acres of the original leased land but the original Lease covered 40 acres of land, the 35 acres of land for which you are not getting paid gets released from the Lease at the end of the Primary Term of the Lease. It is extremely important to insist upon a Spacing or Production Unit Pugh Clause if you are leasing more than a few acres of land, or land in more than one location. If you ask for such a Pugh Clause, almost any Company will agree to give it to you, but if you fail to ask for one, almost no landman or Company will tell you about such a Clause or its effects.
A second kind of Pugh Clause is the Depth Pugh Clause. A Depth Pugh Clause is based on the idea that oil or gas is usually being extracted from a particular identifiable geological substrata of land.
For example, a Company may have found natural gas in the Winnipegosis stratum between 6,000 and 8,000 feet below your property, but there may also be natural gas located in a deeper stratum, say between 12,000 and 14,000 feet below your property. A Depth Pugh clause says that at the end of the Primary Term, all strata that are not being exploited are released from the Lease. Thus, in the example, provided, a Depth Pugh Clause would mean that at the end of the Primary Term, the stratum from 6,000 to 8,000 feet would be held by the Lease for so long as production continued, but you could make an additional Lease with another Company covering the stratum from 12,000 to 14,000 feet. While these clauses are common in areas where a great deal of oil and gas exploration is being conducted and a lot of production is taking place, in some areas it will be difficult to get a Company to agree to one.
If you cannot negotiate a Pugh Clause for any reason, NEVER PLACE TRACTS THAT ARE NOT ADJACENT IN THE SAME LEASE. Otherwise production from one tract or from the pooling of one tract will hold all of the rest of your acreage even if the various tracts comprising your acreage are miles apart.
1. Pooling. Most Leases will have a provision giving Lessee the right to consolidate your leased acres with adjoining tracts. The area thus formed is called a pool or pooled unit. Pools are established to unite under one operator all the mineral owners having an interest in a common underground reservoir.
Pooling, much like spacing, helps the Company to avoid unnecessary drilling and can protect the mineral owner’s rights in a common reservoir of oil or gas.
Pooling also permits the Company to drill the best sites. Pooling
arrangements are sometimes necessary to meet the minimum acreage requirements for a drilling permit.
In Texas, for example, there are two types of pooling arrangements. A voluntary arrangement requires the consent of the mineral owner and provisions relevant to voluntary pooling arrangements are most often found in the Lease forms. A statutory pooling arrangement is one that is mandatory under the law. When entering either type of pooling arrangement, your share of the production is determined by dividing the number of acres you own by the total number of acres in the pooled unit, and then multiplying that fraction by the total Lease Royalty that must be paid for the entire pool.
There is little the mineral owner can do to avoid statutory pooling. But in Texas, if a mineral owner does not consent to voluntary pooling, the Lease cannot be pooled.
You may wish to withhold consent to any voluntary pooling arrangement until the impact of the pooling arrangement is fully explained to you. As a mineral owner, you may want to consent to a voluntary pooling but limit the amount of acres that can be pooled. You would then want to stipulate how many acres can be pooled to no more than that specified in the statutory pooling provisions, which can vary from state to state. Negotiate such provisions before you sign the Lease in the first place.
If the well head is on your property, you may want to have it located so you get as large a share as possible of the pool. That’s more money in your pocket.
Assignment Leases usually contain provisions permitting both you and the Company to assign (sell) any right or interest you or it has under the Lease. These provisions are included for the Company’s benefit, so that it can negotiate with other oil and gas companies. It is a common practice for an individual or independent oil company to lease a large tract and assign (sell) all or part of it to another oil company. So you end up with the developer-producer not necessarily being the original Lessee Company.
In order to retain some control over assignments, you should make sure the Lease contains a provision that the original Lessee is not released from liability for default or non-payment of surface damages on assignment of its interest. Make sure that you must be notified upon any assignment. In Texas, an appellate case upheld the validity of a clause providing for $1,000 damages if the lessee fails to notify the lessor of an assignment. Give yourself to right to disapprove of any assignment; there are times when a marginal Lease changes hands because another operator thinks it has figured out how to make the well produce more, but then the attempt fails and the new Lessor leaves without paying royalties or surface damages.
Warranty Clauses. Leases can contain provisions requiring the mineral owner to defend his interest in, or title to, the leased premises should an ownership dispute arise.
(An ownership dispute could be between the mineral owner and the surface owner if the two are not the same, or any other party claiming an interest in your leased mineral interest.) This provision is known as a Warranty Clause. If the mineral owner breaches the warranty clause by not taking action to protect his or her interest, the Lessee Company may sue the mineral owner, or the Lessee Company could reduce any payments due to the mineral owner. Another example is if the mineral owner claims to own all the mineral rights but in reality only owns half, the Company might thereafter pay the mineral owner only half the bonus, half the delay rentals and half the royalties. This alternative in a lease provision is known as a Proportionate Reduction Clause.
To avoid litigation problems, you should strike any language in the Lease that says or implies that you will warrant or defend the chain of title to the land.
Oil and gas companies spend a lot of money to research titles and you can assume that they know what they think you own. Hold them to the correctness of their own research. If they come up with some rationale for requiring you to offer some form of warranty that you think reasonable, you may want to insert or use a limited or special warranty; negotiating a special warranty should not be a problem.
Free Water, Oil or Gas. As a mineral owner, you will want to pay close attention to Lease provisions allowing free water, oil or gas to the producer for operations. In some states, the Company has the right to use fresh water found above ground or below the surface. The only time this rule is affected is in areas where water is scarce, and then other terms can be negotiated. To keep control of your water supply, if you decide that free water, oil or gas privileges should be granted, stipulate whether the substances may be used for operations conducted both on and off the leased acreage.
You will certainly want to be compensated for water used off the leased premises. Don’t allow Lessee to take free water from your wells, tanks, stock ponds, or reservoirs. Stipulate that any water used by the lessee cannot restrict your supply of fresh water for domestic or agricultural purposes. If secondary recovery operations are undertaken by the Company, state that such water must come from non-fresh sources and deny the use of potable water. If water is to be purchased by the Lessee, state how the price will be determined. It is also possible to require the Lessee to drill a water well for drilling and production operations. State that the water well with all pipes, casings, and pump, reverts back to the mineral owner or surface owner when the Lease terminates. Finally, if the land contains an oil-gas separator, prorate the use of oil or gas that you intend to be provided without charge from the amount needed to run the separator itself.
Force Majeure. The Force Majeure Clause is a provision in the Lease that protects the Company from liability and loss of the Lease whenever things reasonably beyond their control stops operations. A force majeure clause may also act to relieve an operator from having to pay delay rentals. Force majeure is defined as an event reasonably beyond the control of the operator, flooding, fires or other acts of God.
A state oil and gas regulatory body enjoining a well’s operations also is considered force majeure. Force majeure temporarily suspends the lease term, and extends the lease unit until the force majeure is removed. If an operator is forced to suspend drilling operations during the primary term because of a force majeure, no delay rentals would be due on the anniversary date occurring during the force majeure.
To deal with the effects of this clause, require timely written notice of any sustained work stoppage.
Make sure the notice specifies whether the stoppage was pursuant to the force majeure clause or the shut-in clause. A stoppage under the force majeure clause requires no payment while a sustained shut-in does. Negotiate for a term that states that if an unavoidable stoppage should occur during the primary term require delay rentals to be paid anyway. Specify how soon operations must resume once the cause of the stoppage is removed. Some leases allow for 15 months, but 90 days is better for you. Also, consider what should constitute “force majeure.” Human error or stupidity should not be one of them, but financial difficulties, lack of water, lack of materials, lack of transportation facilities, and similar problems can be defined as force majeure or not, depending on your negotiations.
11. Horizontal Drilling
In 1989, a new drilling technique called horizontal drilling was implemented and introduced to the oil and gas industry.
Drillers could make a vertical hole turn 90 degrees at a depth greater than 1,200 feet. In 1990, rules were put into place governing horizontal wells, and assigning additional surface and subsurface acres to a horizontal well.
The amount of additional acreage permitted for a unit depends on the vertical field rules.
If field rules for vertical wells permit units of 40 acres or less, an additional 20 acres may be assigned to the proration unit if the horizontal drain hole is between 100 and 585 feet. For each additional 585 feet (or any part thereof ) drilled horizontally, another 20 acres may be added. If field rules for vertical wells permit units of 40 acres, an additional 40 acres may be added if the horizontal drain hole is between 150 and 827 feet. For each additional 827 feet ( or any part thereof ) drilled horizontally another 40 acres may be added. No acreage assigned to a horizontal well may be assigned to another well in the field.
Information about horizontal drilling, and the statutes that regulate it, is typically available from the state regulatory agency with power over oil and gas drilling. If the landman you are negotiating with tells you that Horizontal Drilling is going to be used, it would be a good idea for you to become more familiar with the technique and its implications in your area before negotiating a Lease that will lock you into this format.
Additional Terms.
(a) You will want the Company to provide you with free access to books, records, and drilling area data accumulated pursuant to its exploration operations.
Try to get copies of all logs for your own files. Also negotiate a provision to get copies of all title opinions and abstracts of title. These sorts of documents will strengthen your negotiating position in future Lease negotiations.
(b) Make sure the Lease defines exactly when drilling operations can commence.
The best criteria may be when the well is spudded with appropriate equipment on site to drill the well to the depth on the drilling permit. Also define when the well is completed. A good possibility for such a definition is when the drilling rig has been released from the well site.
(c) Negotiate provisions allowing you to assume control of the casing when drilling operations have been abandoned. The casing can be used to withdraw any remaining gas or fresh water for domestic or agricultural purposes.
(d) Demand that the Company indemnify you for any demands or causes of action taken against you on account of the Company or its activities on your land, whether those causes are the result of the Company’s actions or the actions of its assignees, employees, agents, contractors, or subcontractors. Make sure the indemnification covers you for violation of environmental laws or any requirements of such laws for restoration of the land after such violation. If you can get the Company to post a bond and/or carry liability insurance for such things, so much the better.
(e) If the legal description of your property says things like “going from the southeast corner of Abner’s farm, north to a clump of trees…,” ask the energy company seeking the Lease to provide you with a survey for a proper legal description, and then amend your Deed with a proper legal description. This may enable you to avoid a lot of problems later on.
DON’T SELL YOUR MINERAL RIGHTS…
It is possible that once it has been determined by an Energy Company that you own mineral rights under a certain piece of property, you will approached by a landman not for a Lease but to buy the minerals you own outright.
Unless you are fully advised as to how much the mineral rights in your area have been selling for, and what they are likely to be worth, and unless you are familiar with the company or person that is seeking to buy your rights, DO NOT SELL YOUR MINERAL RIGHTS.
Remember, when you sell your mineral rights, you are giving someone else the right to come on your land and explore for and extract those minerals, and they will only be liable to you for surface damages. There is never a good reason to rush into signing a sale of mineral rights, or to rush into signing an oil and gas lease, for that matter.
DO YOU OWN MINERALS?
If you have been approached by a Landman to enter into a Lease Agreement or in an attempt to buy your mineral rights, you almost certainly have mineral rights of some kind. Landmen get paid a lot of money for their expertise in determining who owns minerals and who doesn’t, and they are unlikely to have made any major mistakes in their assessments. But if you haven’t been approached by a Landman, finding out whether or not you own minerals can be challenging.
The first clues you will get as to whether or not you own mineral rights under your property will come from checking your Deed. In the area under the legal description of the property, there will be a section devoted to what sorts of rights are NOT being transferred along with the surface of the property.
This section will almost always refer to easements across the property, but it will not always tell you directly how much of the mineral rights under the property you own. However, if this section includes a reference to a previous landowner who kept some or all of the mineral rights under the property when he sold the land (typically including a reference to the Book and Page number so that you can find the deed in which a mineral interest was retained at your local courthouse), then you will at least know that you don’t own all of the minerals under your land.
If the section of your Deed that would tell you what rights are excluded from the sale to you says nothing about mineral rights, chances are pretty good that you actually own the minerals under your property. The only way to know for sure, however, is to “run the title” (look at every single deed from the time of the Patent until the property reaches you) and see if anyone in your chain of title retained any of the minerals. If you are capable of reconstructing the chain of title and find nothing, that may mean you own all of the minerals, or it may mean that you missed the exclusions of minerals in one or more of the deeds in your chain of title. The only way to be certain (well, 95% certain anyway) how much of the minerals you own is to have a professional run the title for you.
That can cost anywhere from a few hundred dollars to a few thousand dollars, depending on how complicated your chain of title is. Title companies will generally not run mineral title for you, even if you request them to do so, so the easiest way to find a landman willing to do the work for you is to either contact a company that hires landmen to appro
QUESTION: No longer just a Halloween phenomenon, pop up stores are evolving into engines of economic development in downtowns and areas that have languished with vacant store fronts. What are your thoughts on popup stores? Do you own one? What’s their potential long-term impact for communities?
The economic downturn has opened up new opportunities that for years were limited to small carts in shopping malls and flea markets. The downturn has resulted in many business failures, which in turn have left many storefronts unoccupied. These vacant storefronts have become challenges for downtown organizations and management companies.
The introduction of pop up store fronts for limited items like Halloween costumes, Christmas decorations, sports memorabilia, special event merchandise, kitchen items and others appear to be filling a void left by the failing stores before them. Where a business could not enter into a long term lease agreement because their long term sales are doubtful, the landlords have agreed to accept a slice of pie (limited term leases) instead to help generate some short term cash flow rather than let the vacant building sit and drag down the image of the area. This will most likely continue till our vacant commercial space availability reduces with a more vibrant economy.
Dear John M. Connors,
Thanks for your comment. I have forwarded your comment to Maureen.
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You ask for tax tips for the small businessman.
You cannot get any smaller business than a Consultant working by himself. Also you cannot beat the fact that anyone with 48 years of experience in the plastics industry has met a few people in the process. I have many resources in my industry and keeping up with them is the key to having respect from all of your business contacts and having referrals consistantly coming in.
The cost of the “keeping up” with associates in the industry is duductable as are all the costs of maintaining the office and travel necessary to keep the consulting business going at a steady pace or level you want. Keep every reciept.you generate and a good calendar with appointments and travel detailed. Keep a separate bank account for the business and a credit card, each that you can access on line from anywhere and that gives you a year end accounting of business expense separated into catagories like gas, hotels, food. Get easy pass for tolls so you do not miss significant deductable dollars as you travel. Keep a log record of the business miles on your car with record of odometer readings.
Deduct it all and do the same thing each year so all the IRS sees is consistancy in expenses reported and the level of expense. A large or unusual expense needs an explaination so you are not targeted for audit. Audits will cost you!!!
Hi Louis,
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There are rumors going around saying the pipeline is also bringing a higher crime rate with it. is this accusation true or meerly rumors traveling around?