O&G has been a blessing in this cycle of uncertainty with the United States economy, but also has created a Black Hills gold rush assault on Indian lands not seen for a while. Although this article is somewhat lengthy, it is important and urgent that you understand what your rights are before it’s too late. Too many folks have told me the “BIA didn’t tell me that.” Of course, who gives away all of their secrets? Negotiating power is in what you know and the other party doesn’t.
The Bureau of Indian Affairs (BIA) revised their Fluids and Mineral Handbook on August 14, 2012. The handbook provides guidance for the BIA in the oil and gas leasing process. The handbook includes applicable federal statutes and regulations and sample forms used in every facet of managing a lease including leasing, assignments, change of name, etc. The forms are sample forms except for the Lease form on page 99 of the handbook, but it can include additional stipulations. One of the greatest misconceptions is that a mineral owner cannot deviate from the O&G lease form provided by the Bureau of Indian Affairs (BIA).
Another misconception is that mineral owners must accept the terms and conditions BIA negotiates on their behalf and determines is in your best interest. If that were true, the BIA needs to remove 25 CFR § 212.20 from their regulations. This regulation provides that Indian mineral owners may (emphasis added) request the Secretary to prepare, advertise and negotiate (emphasis added) mineral leases on their behalf.
Nolo’s Law Dictionary defines may as “An expression of possibility, a permissive choice to act or not, as distinguished from "shall," which is an imperative or often mandatory course of action.” This would clearly indicate that the BIA assists in negotiating leases when requested by the mineral owner(s). There are certain minimum required terms and conditions which aren’t negotiable. However, additional terms and better terms may be negotiated either by inserting them into the standard lease form, or by referencing additional stipulations in accordance with a referenced addendum to the lease.
Additional terms to consider are 1) bonus payment per acre; 2) length of term; 3) lease on top of lease; 4) annual rent payment; 5) royalty rate if the mineral owner desires a rate greater than the minimum rate required by the BIA; 6) lessor consent required for assignment by lessee(s); 7) payment/ damages for seismic activity ; 8) well pad fees if a permit to drill is approved; 9) rights-of-way compensation and activity; and 10) early termination fee. Now, I would like to address each of these separately to provide some guidance as to what can be negotiated.
Normally, the Bureau of Land Management (BLM) provides a pre-sale and post-sale analysis of each Allotment (tract) offered at bid sale. The BLM analysis is used by the BIA to assist in their determination that the bonus payment and rent offer is comparable with the market for the formation intended and location.
The length of contract term usually is five years but three years is more favorable. The shorter term shows the lessee’s intent to act quicker to either drill or dispose of the lease. Longer terms may diminish the value of the lease overall because of market fluctuation.
Mineral owners can require that consent is limited to a specified formation structure. If there are known multiple formations with potential oil or gas development, you can find out which formation the applicant is primarily interested in and limit the development to that formation. This allows a mineral owner to negotiate another lease, or lease on top of a lease, with the same company, or any other company. These aren’t as complicated at they sound, but does require some negotiating skills and knowledge of the industry.
Annual rental payments generally are $5.00 per acre per annum or year. Normally higher annual rent diminishes the overall bonus payment value so don’t be disappointed if the lease applicant holds tight to the current market rate. But, as always, negotiation is just that, asking and seeing where you end up.
One of the most abused practices is lease assignment. Larger investors and companies usually intend to develop the mineral estate while unknowns are looking to acquire leases and sell their interest to companies with more funding resources for development. The common term is called “flipping” of leases. It’s a practice as old as the hills. Generally some lessees hope to acquire the lease for little bonus payment and then sell their interest at a great gain. I have drafted an article addressing this issue and can be read at this link. But in a nutshell, you should add to an addendum any lease assignment requires the consent of the mineral owner(s). No one tells you this, but 25 CFR § 212.53 regarding assignments, overriding royalties, and operating agreements refers to the provisions found 25 CFR §211.53 as applicable to leases under this part. Subsection provides that “(a) …The Indian mineral owner must also consent if approval of the Indian mineral owner is required in the lease.” Allotted lands can use this same provision based on the CFR. Common sense would indicate that when a lessee comes to you for consent, you could reasonably negotiate an additional payment based upon their net profit or gain in the transaction otherwise the assignment cannot be approved by the BIA.
Seismic activity is a necessity unless previously performed and the lessee has acquired the data. Surface damages are paid to the surface user (agricultural lessee, residential lessee, etc.) Some form of compensation to the mineral owner could be negotiated but must be agreed to in the lease terms.
For well pad damages and compensation, $5,000 per pad site was the rate for twenty plus years. Of course, the market has risen and oil prices have increased dramatically since the previous rate was established. It is believed that the BIA has internally raised pad site fees to a minimum of $10,000 per pad site. You should be compensated at least $10,000 for each pad site on each lease.
Consent of Rights-of-Way (ROW) grants are included within the leased area, but, the surface user is entitled to damages and or loss of use of leased acreages taken by the ROW. If the mineral owner also owns the surface, you should negotiate a payment to recover loss of leased acreage taken by the ROW. For example, if you lease 160 acres in a farm lease to a farmer, his leased acreage and rent would have to be adjusted because 5 acres removed from farmable acreage at $30 per acre is a loss of $150 per year to the surface owner. Over the course of a successful well and continued use of the ROW over 20 years, your total loss of annual income would be $3,000. Folks will tell you that the appraisal covers the loss or taking, but does it factor in the life expectancy of a well if a well is developed? Besides, how many times are ROW appraisals provided by BIA even though it is required. A Superintendent should never waive an appraisal or use some other method for determining value for a ROW. If the well is developed, you may want to negotiate a payment every 10 years or so during the life of the ROW so you are still generating income.
All in all, as bad as you need oil and gas income, the oil and gas industry, and the country, needs your oil and gas more. You only live once and you only have a limited opportunity to create income and a lifestyle you deserve. If anybody tells you that you can’t require some of these negotiable terms and conditions I have outlined, tell them let’s discuss this around the table. They don’t negotiate with you when they raise the price of oil or gas at the pumps. But someone will negotiate with you around the table, or the next company in line may.
Jay Daniels has 30 years of experience working in Indian country, managing trust lands and is a member of the Cherokee Nation of Oklahoma. You can find resources and information at RoundhouseTalk.com.