Royalty Litigation: Here We Go Again

Oklahoma Oil and Gas Interest Owners:

Berlin believes it is about time to start chipping away at the giant iceberg of issues surrounding post-production deducts and the litigation that follows. This will be one of multiple posts that address the lessor / lessee relationship, the implied duty of the lessee to market the lessor’s share of production, and the responsibilities of each party to pay for their shares of post-production expenses. As you are well aware, Berlin is merely a mineral schlepping landman and her opinion should not replace the counsel of a well schooled (and likely well paid) oil and gas attorney.

The most important issue that complicates this discussion is that Oklahoma law does not define marketability and in what state produced gas is marketable. Unless the oil and gas lease addresses the lessee’s duty to market or negates the implied duty to market, Oklahoma oil and gas lessees are subject to an implied covenant to market produced hydrocarbons. In Mittelstaedt v. Sante Fe Minerals, Inc., the Oklahoma Supreme Court stated that the lessee has a duty to provide a marketable product available to market at the wellhead or leased premises. But, they did not go so far as to define marketability.

The next question is then, under what circumstances can a lessor be charged costs against their royalties if the production is sold off-lease? The Court writes:

We conclude that the lessor must bear a proportionate share of such costs (transportation, compression, dehydration, blending) if the lessee can show

(1) that the costs enhanced the value of an already marketable product

(2) that such costs are reasonable, and

(3) the actual royalty revenues increased in proportion with the costs assessed against the non-working interest.

Recently, an Oklahoma court took one step towards defining marketability in its decision in Pummill v. Hancock Exploration, LLC when it wrote that:

…gas does not become marketable until it is capable of being sold in the commercial interstate market.

This would imply that if costs were incurred to gather, compress, dehydrate, and process the gas in order for it to be in a condition to be sold in the commercial interstate market, that none of those charges could be proportionally borne by the lessor unless the oil and gas lease stated that the lessor would be responsible for its share of costs. However, any costs incurred after the gas is marketable could be charged to the lessor if they complied with the Mittelstaedt decision and were not expressly forbidden in the oil and gas lease.

As you can see, once an ambiguously worded royalty clause and an attorney drafted post-production clause are thrown into the mix, the outcomes can become exponentially more complex.

Some important questions regarding deductions include:

Whitesnake loves Oklahoma royalty disputes and the fees they generate for plaintiffs’ attorneys…

1. Does the oil and gas lease royalty clause expressly allow or prohibit the deduction of costs?

2. Is there an provision in the exhibit that conflicts with the royalty clause in the lease?

3. Does the implied covenant to market apply?

4. At what point did the gas become marketable?

5. If costs were incurred after the gas became marketable, do they comply with the conditions of the Mittelstaedt decision?

6. Is an affiliate of the operator marketing the gas or is it an arm’s length transaction?

7. Where is the gas actually being sold and who is buying the gas?

Berlin is working on a flow chart / process to assist lessees and Oklahoma lessors in determining appropriate deduction actions. If this would be of interest to you / your company or if you would like a consultation regarding a royalty issue, please contact Berlin. Thanks for reading.

More to follow,

Berlin

Separate but Equal is not Equal

Are all mineral buyers the same?

With the announcement of Longpoint Minerals II securing $802 million to purchase Oklahoma (and Texas) mineral rights and royalties, the froth will return to the marketplace after a few months of reprieve. It is not uncommon for a tract of minerals to be bought and sold three times in a short period of time within the SCOOP or STACK before ending up with the end buyer. The supply of mineral acreage is finite. The billions to deploy in a relatively small geological fairway encourages many participants to enter the mineral trading ecosystem. This article will address some characteristics of each of the participants.

Opportunists
There are more opportunists in the game than anyone else. Due to the variability within any large sample, Opportunists come in all colors. The category, in general, can be defined as individuals or companies whose desired endstate is to locate and negotiate a smaller mineral purchase transaction while simultaneously negotiating the sale of the same tract to another buyer and preferably for more money. Business models vary slightly, some opportunists just broker transactions for a commission, some will assign their purchase and sale agreement for a fee to the end buyer who will fund and close the trade, and other opportunists will fund their own closing and obtain title before marketing and flipping the acreage.

Most opportunists are no better than the snake oil tonic salesmen of the frontier. Beware of their inflated offers to purchase your Oklahoma mineral rights

The companies who discredit the category as a whole are those who contract for the sale of minerals and then fail to close. Either because they don’t have their own funds or they were unable to obtain an agreement to flip the acreage. Many Opportunists mail letters to mineral owners at highly inflated prices with no intention to close. Once the mineral owners engage with the Opportunists, the prospective buyer will drastically lower the offer. These kinds of actions understandably frustrate the original sellers. This conduct also muddies the waters for potential future buyers as they have to contend with the residue of past negotiations and unrealistic price points set by the original Opportunist who didn’t have the funds to close anyways. If sellers insist the buyer have some skin in the game, these kinds of activities are less likely to occur. For seller’s, purchase price should be just one of the factors to consider when selling minerals. The opportunity cost can be very high to have one’s minerals tied up for a few months just to have the Opportunist back out at the last moment. Timelines for closing, contingencies, and most importantly, the buyer’s willingness and ability to close are also important to contemplate when selling a mineral property.

Private Mineral Companies
The next step in the mineral trading food chain are private mineral and royalty acquisition companies (disclaimer: this is how Berlin would classify her business). These are usually smaller operations that consist of sole proprietors or at most a few partners or family members that conduct the day to day affairs. Most do not raise outside money and thus are usually not active buyers in the core of the SCOOP and STACK. These companies are content to buy producing minerals for a reasonable multiple of current cash flow and non-producing property on the fringes or in front of a developing play. Deal flow is sourced by word-of-mouth and select Opportunists. Most pay the bills from a combination of producing royalties and lease bonuses.

Aggregators
Aggregators generate most of current high dollar deal flow in the SCOOP and STACK. Like the Opportunists, they are rarely buying to hold for their own account, but unlike Opportunists, they close the trades with their own funds. Most have relationships with the private-equity or institutionally backed mineral company that provides them with exclusive rights to generate deals in certain geographical areas with an established price point in which to sell their minerals to the larger company. They are paid either on a commission basis or they may be allowed to keep the spread between what they paid for the mineral property and the price set by the end buyer. Aggregators are aggressive in generating deal flow and fill their funnels with leads from call centers, direct mailings, full-page newspaper ads in the county seat’s paper and of course personal relationships with others in the ecosystem.

Private Equity and Institutionally Backed Mineral Companies
The current end buyers of high-value mineral properties in Oklahoma are private equity and institutionally backed mineral companies. Longpoint, mentioned above, is dominant in the space, but other companies like Fortis Minerals, Luxe Minerals, and Haymaker Minerals and Royalties also compete by spending large amounts of other people’s money. These companies can pay a premium for interests in the core areas of the plays due to their lower cost of capital and the longer times horizons for their funds. From a layman’s view of prices, these companies must be modeling the substantial development of multiple geological targets in order to see a return on their investment. From a prospective seller’s point of view, it can be argued that currently, no company will pay more for your interest than one of these firms.

Publicly Traded Mineral Companies
There are a few publicly traded mineral companies. Most seem to be above the fray of the day to day transactions taking place in across the state. Instead, companies like Black Stone Minerals will buy large deals from other large companies, both public and private, that are either divesting their minerals entirely or of assets located in a specific basin. They seem to make a splash on the newswire once or twice a year with an acquisition of $100m+.

Operators
While most exploration and production companies focus their acquisition dollars and efforts on leasing, some firms are finding it advantageous to purchase minerals in sections where they are likely to drill wells. One of the quickest ways to boost the economic returns of the well is to have fewer expenses. There are few items on the well ledger that are as expensive as the royalty burden of a lease. Look to see more companies attempting to acquire mineral acreage in operated units especially if the company is planning to density the section in the near future.

Please comment below or contact Berlin with any more questions about the types of mineral buyers or if you would like to sell your Oklahoma mineral rights.

More to follow,

Berlin

(This post was first published on Oklahoma Minerals on 5 July 2018)

A Well Proposal In Oklahoma - A Boon to the Mailman

Oklahoma Oil and Gas Mineral Owners,

Berlin's friend Bruce called her up on Friday, and after he finished ranting about planting his tomatoes before the last frost date, he got down to asking about well proposals and why he is receiving them in the mail for his Pittsburg County, Oklahoma mineral rights.

Unless one is party to a Joint Operating Agreement, a well proposal in Oklahoma is a non-binding piece of correspondence. It is supposed to be the last of a series of efforts for all owners with the right to drill a well in a certain drilling and spacing unit to agree to drill (or not to drill) that well before a forced pooling proceeding is undertaken at the Oklahoma Corporation Commission. 

A well proposal will usually contain the following pieces of information;

1. The proposing party (and potential operator)
2. The location of the well (usually described to a quarter section level)
3. The target formation
4. The type of well (horizontal or vertical)
5. The depth of the well
6. The cost of the well (an AFE should be included)
7. The proposed farmout/lease terms in lieu of participation in the well

Ever since our friends at Chesapeake popularized not sending out a JOA even between parties who have agreed to the development of a unit, a well proposal should be viewed as a warning order that a forced pooling application will arrive in a few weeks.

Dr. Evil prefers that one forgets that elections under a pre-pooling well proposal are non-binding so he can deem Austin out of the well.

There is little room for negotiation in the terms of the well proposal. If an owner desires not to participate and would prefer to lease/farmout and doesn't like the terms presented in the proposal, the proposing party will say something like, "well, you had your chance hot shot, but now you'll just have to see what we testify to at the pooling hearing." The power of the forced pooling provisions gives her the ability to (1) call anyone she wants "hot shot," and (2) not care about responding to counter-proposals from other owners in the unit. Berlin has been told that is not the case in other states (property rights, who needs property rights?).

If an owner does want to participate in the well, he will still have to elect to do some when the forced pooling order issues. Despite the fact this is usually written into the well proposal, many parties still fail to elect under the order and the operator is more than happy to overlook their previously designated intent and deem them out of the well.

After Berlin explained these facts to Bruce, he asked the only questions that a reasonable person would ask after hearing about how worthless a pre-pooling Oklahoma well proposal is, "what's the point and who benefits?" Berlin isn't sure what the point of the well proposal is, they are often ambiguous and as stated above, non-binding. The beneficiaries are certainly the USPS who really enjoy when letters are sent certified at $7.00/piece and the potential operator's competition who get a 2-3 week notice that applications are about to be filed.  

Please comment below or contact Berlin with any more questions about well proposals or if you would like to sell your Oklahoma mineral rights.

More to follow,

Berlin

Splitting the Baby and the Pooling Bonus

Oklahoma Oil and Gas Mineral Owners:

The Oklahoma Corporation Commission has been regulating on the fly as to rule changes on multi-unit horizontal wells. One of the recent changes is that applicants now must offer a formation election if the applicant desires to force pool more than one common source of supply. Berlin thinks that this effects the unleased Oklahoma mineral owner more than the commissioners had originally intended.

Your call Sol...splitting the pooling bonus for the Oklahoma oil and gas mineral owners.

Old World for the Mineral Owner:

The Commission effectively put a stop to applicants pooling from the surface to granite, instead allowing the the applicant to only pool her target formation and the formation directly uphole and directly downhole. For example, if the applicant proposed a Woodford well, she would have been allowed to pool the Mississippian, Woodford, and Hunton. For simplicity's sake, if my man Bruce was an unleased Oklahoma mineral owner and did not want to participate in the Woodford well with his 10 net mineral acres, he would elect out of the initial well and thus have given up his ability to participate in any Mississippian, Woodford, or Hunton wells while the forced pooling order was in effect. If the only option in lieu of participation was $1,200 per net mineral acre and a 3/16 royalty, Bruce would receive $12,000 from the applicant. 

New World for the Mineral Owner:

The situation has now changed with formation elections. The applicant now has to testify to the perspective value of a well in each formation she expects to pool in order to proportionally allocate the bonus amount. If she testifies that the Mississippian, Woodford, and Hunton are equally perspective, they would receive 1/3 of the allocated bonus each. Now if Bruce elects not to participate in the drilling of the initial Woodford well, he will only receive $4,000 from the applicant ($1,200/nma * (1/3) * 10). If the applicant does not propose a Mississippian or Hunton well during the primary term of the forced pooling order, Bruce will never have an opportunity to make an election and thus will never be compensated for his Mississippian and Hunton formations being pooled for a year.

Now many of you will shout "Berlin, you're a goon, Bruce's Mississippian and Hunton will be open after the primary term of the order." And that is true. Bruce will most likely be open in a year where he could lease or even propose his own well. But Berlin would argue that after a horizontal operator has drilled a Woodford well in the unit, the chances of another operator paying Bruce a premium for his Mississippian and Hunton rights would be unlikely unless better wells are eventually made in the the Mississippian or Hunton.

As there are pros and cons to formation elections for the Oklahoma mineral owner, there are also pros and cons for the applicant/operator. Pro: Her pooling bonus will be lower in the short term, in the case above 1/3 of what it would have been under the old regime. This will be even more advantageous for the operator who is pooling (as opposed to leasing) a greater amount of acreage. Con: Many companies are now valued on their net acres in multiple formations. So now if the operator pools more acreage and initially only drills Woodford wells, her Mississippian acreage count will not see a benefit from the pooling proceedings. This should be somewhat intuitive, she didn't pay for it, she doesn't own it (unless she can convince a bigger fish with someone else's money to pay her for the Mississippian acreage if it is during the primary term of the pooling order).

Conclusion:

Berlin predicts that these rules will change at some point in the future and that an Oklahoma mineral owner will again be permitted to elect out of all formations held by the pooling order in order to receive 100% of the pooling bonus from the outset (TVM, even if they don't call it that...).  

If you have any more questions on split bonus payments under Oklahoma Corporation Commission forced pooling orders or you would like to sell your Oklahoma mineral rights and royalties, please contact Berlin.

More to follow,

Berlin

Extending an Oil and Gas Lease

Oklahoma Oil and Gas Mineral Owners,

It can happen to the best of us, it was three years ago and nobody was drilling deep gas in Custer. You signed an oil and gas lease with an option to extend the primary term. Now, things are different, the "macro-headwinds" have shifted. There are folks with deep pockets paying 3x what you will be paid for your option. Even though $500/acre for a 160 acre lease on the home place would make most smile, you have a yellow equipment problem and were hoping that the original lessee will overlook the option and you will be able to sign a new lease at $1500/acre and buy that excavator you have always dreamed of. So what can you do? 

Some oklahoma oil and gas mineral owners trade their right to drill a well for a royalty and yellow equipment

Some Oklahoma oil and gas mineral owners will attempt to claim that they never received the option bonus. While most lessees who desire to exercise their option will call the lessor to confirm their address before mailing a check, the call is not required. To perfect the option, a lessee is required to send the bonus payment to the lessor's address via certified mail and file an affidavit of lease extension with the county clerk. A lessor is playing with fire if they do not accept the certified mail in order to claim that their bonus was never paid.

What should another company do that would like to buy a lease from a lessor who has a option to extend in their old oil and gas lease that they claim was not exercised? Berlin argues they should do the following to protect themselves:

1. Ask the lessor if they have been contacted by the lessee or its assigns or moved since they signed the lease.
2. Check the records to see if the lessee filed affidavits of extension in the section or the surrounding sections. It would be odd that the lessee would extend some leases, but not others.
3. Request the lessor warrant title to the lease.
4. Require the lessor file an affidavit of non-payment and file the affidavit in front of the new oil and gas lease.

People do weird things when money is involved (and isn't is usually?). As was said in the gun club, "U Signed the M*****f****** Contract." There is no reason to complain (or commit fraud) if the option that you agreed to is exercised. And the company who desires to buy a fresh lease should protect themselves from bad behavior. 

Berlin wrote this post because a loyal reader asked to learn more about the situation. If you have any more Oklahoma oil and gas leasing or mineral rights questions, or would like to sell your Oklahoma royalties or mineral rights, please comment below or drop Berlin a line.

More to follow,

Berlin

Spudding Before Forced Pooling

Oklahoma Oil and Gas Interest Owners:

Bruce was a bit pissed when he called up Berlin today. Apparently, his fence line weaning efforts cost him about 6 hours of sleep after he found the fence knocked down and the calves back with their mommas.  After he calmed down a bit, he asked why so many operators are spudding their wells before a forced pooling order has issued and what his options are as an unleased Oklahoma oil and gas mineral owner named as a respondent in the pooling proceedings.

There are a few reasons why an Oklahoma operator might spud a well before an Oklahoma Corporation Commission ("OCC") forced pooling order is issued.

1. As Berlin discussed yesterday, the OCC is short staffed and the review and issuance of orders is taking a substantial amount of time and in some cases up to 5 months after the pooling was recommended at the hearing. In order to feed the rig monster, operators must keep drilling their wells. After all, a pooling order is not needed to obtain a permit to drill.
2. If a forced pooled unit is not formed and there is no Joint Operating Agreement or any other voluntary pooling of leasehold interest between the working interest owners in the unit, there is no mechanism to govern the development of the unit. One of the consequences of this action is that there are no mechanisms to handle costs. And if a fellow working interest owner can't pay his costs, the operator will not provide well info. In short, operators will spud a well without a forced pooling order so they will not have to share well information in the short term with their competitors.
3. Forced poolings can be a time suck. Dealing with asinine requests on pre-pooling letter agreements, setting protest dates, and finally the protests themselves are often an exercise in busy work. If an operator has a high working interest in the spacing unit, she might just spud the well and file a pooling application in time to have the order issue before the division order title opinion needs to be rendered. 

The rig monster never sleeps, but enjoys purchasing Oklahoma oil and gas mineral rights before a horizontal well is drilled. It increases his NRI and keeps his LPs happy.

The operator incurs a risk when he drills before a pooling order has issued. Hopefully, he has used the time to evaluate the well and if he's made a good well, to lease the offsetting acreage. However, if he had issues drilling or made a marginal well, he is in danger of owning 100% of the working interest as the other working interest parties will have scouted the well and will elect out of the unit when the pooling order issues at a later date. So what are Bruce's options as an Oklahoma oil and gas mineral owner? Once the order issues, he should read the order as it will contain the usual options, however, he should be more strategic as he will have more information available to him.

1. If the operator has made a good well, Bruce's interest will now be substantially more valuable. Bruce could participate in the well if he has completed his diligence on the property and scouted the location. However, Berlin's recommendation is that only professional mineral owners should participate in wells. Still, his mineral interest should command a premium with non-op companies who have other people's money to spend. Bruce should be able to negotiate an oil and gas lease with better terms than those found in the forced pooling order.
2. If the operated drilled a dud, it is unlikely that any non-op will seek Bruce out for his interest unless the non-op just wants to participate with a small amount of acreage in order to obtain well information. In this case, Bruce should just elect the option in lieu of participation under the pooling order that works best for he and his family's situation (ie does he need cash now to buy replacement heifers or maybe more royalty later if an operator decides to density the section). 

Berlin hopes she answered Bruce's question. If you have any more questions about forced pooling, or you would like an offer to sell your Oklahoma oil and gas mineral rights. Please drop Berlin a line or comment below.

More to follow,

Berlin

How Can One Prove That They Exist?

Oklahoma Oil and Gas Royalty Owners:

Berlin received a call today from Sage, a good friend who also happens to be a company landman, Sage reported that an Oklahoma mineral owner (Red) just called to chew on his leg as the mineral owner had never heard of Sage's company (despite the fact they've drilled about 70 wells in the past 2 years). He wanted Sage to prove that his company was legitimate and their lease offer was valid.

Sage could have handled Red and his Oklahoma mineral rights in a more professional manner. Never ask about another man's jeans.

Sage was a bit perplexed as there he was speaking with another human who received a letter that Sage signed and mailed and was questioning Sage's existence. Sage asked if there was a Straussian reading of the question, but the mineral owner told Sage that it was none of his f***ing business, but that he was proud to wear Wranglers.

But with crooks on the loose, it is a valid concern. How can a Oklahoma oil and gas mineral owner verify that the company that she has been approached by is legitimate? Here are a few suggestions:

-Verify the company is registered with the Oklahoma Secretary of State. 

-Verify the company is bonded with the Oklahoma Corporation Commission (if they claim to operate).

-Inquire with your neighbors if they have been contacted by the same outfit.

-Examine the index at the county clerk's office or search for recently recorded instruments on Oklahoma County Records.

-Contact Berlin for more options.

If Sage had suggested any one of the above, he probably could have boated a lease from that call. Instead, Sage lost his cool at the owner's insistence that Sage was a fly-by-night shyster so he slammed the phone on big Red from Anadarko.

More to follow,

Berlin

Is $10 Actually the Bonus Per Acre?

Oklahoma Mineral Rights Owners,

Berlin received another call from Bruce today. He was angry and slightly confused. Bruce was sure that some fly-by-night lease flipper was fixin' to cheat him out of his lease bonus. The Duncan, Oklahoma based outfit had offered him $1,100 per net mineral acre for a 3 + 2, oil and gas lease at a 3/16 royalty for some of his granddaddy's minerals in Beckham County, Oklahoma, which Bruce accepted.

No Oklahoma oil and gas mineral owner is getting jammed on ole girl's watch.

However, upon review of the lease, Bruce read the following statement "Witnesseth that the said Lessor, for and in consideration of Ten and more Dollars, cash in hand paid, the receipt of which is hereby acknowledged...do grant, demise, lease..." Bruce asked the buyer to replace the ten dollars with the actual bonus due and the buyer balked. Bruce asked Berlin if this was proper or if he was getting jammed.

Berlin told Bruce that this is the industry standard and that lessees of Oklahoma oil and gas leases do not place the actual bonus paid of record by writing it into the oil and gas lease. As long as Bruce was satisfied with the terms of payment, the "and more" of the consideration and granting clause that he was presented is legitimate. 

Berlin has written about the terms of the basics of the oil and gas lease before, but if you have any more questions about an oil and gas lease or you are interested in leasing or selling your mineral rights please comment below or drop us a line.

More to follow,

Berlin