The Top 5 Chesapeake Royalty Litigation Trends to Watch
By Keith Mauck
Over the last few years litigation arising from Chesapeake Energy’s royalty practices, has reached a tipping point with a number of new suits being filed in the last year and stretching into new legal theories of liability. The origins of this litigation boom against Chesapeake stems from changes in the company’s royalty calculation, which saw them reinterpreting thousands of royalty agreements beginning in 2012. Among industry observers, this strategy was an attempt partially to mitigate a massive debt burden and cash shortfalls arising out of the 2012 drop in gas prices. Although some experts indicate that, the foundation for this move was rooted in the financial collapse of 2008.
As reported previously, the initial wave of litigation saw the company fighting or settling royalty underpayment lawsuits in Texas, Oklahoma, Louisiana, Arkansas, Kentucky, New York, Virginia and Pennsylvania, areas where Chesapeake leased vast swaths of acreage in the early days of the shale boom. The first wave of lawsuits saw mixed results, with some litigants failing to advance their claims against the company while others were largely successful.
One case that illustrates the potential shift toward decisions favoring royalty owners. In the Demchak litigation (Demchak Partners Limited Partnership, et al. v. Chesapeake Appalachia, L.L.C.), Chesapeake has agreed in principle, although still pending Court approval, to pay $7.5 million as part of a settlement with over 1,000 Pennsylvania landowners claiming an underpayment due to the company deducting post-production costs from royalty checks.[1] The case involved a class action suit involving several thousand leaseholders and prompted the Pennsylvania legislature to pass an amendment to the “Guaranteed Minimum Royalty Act” signed by the Governor requiring royalty check transparency. According to the law listed as Senate Bill 259, royalty check statements must provide a more thorough accounting of payments and deductions.
The second wave of litigation appears to have been spurred on by the success of the Demchak case. In the last year, class action litigation against Chesapeake appeared to be gaining traction. In addition to small leaseholders filing as a plaintiff class, a number of large leaseholders have also advanced litigation with some of the large leaseholders’ cases filed during the first wave of litigation being resolved. It has also seen litigants expanding their theories of liability to include new claims against the company arising from improper deductions from royalty payments. Lastly, Chesapeake has also drawn the attention of Federal Authorities with criminal enforcement measures being launched in Michigan by the Department of Justice. This second wave of royalty litigation marks a new phase in which there will likely be more leaseholder litigants advancing claims and most likely case law in a number of state and federal jurisdictions will likely be shaped by this uptick in litigation.
For royalty owners observing litigation trends against Chesapeake Energy, the following cases could be influential on future royalty dealings with Chesapeake and may shape legal doctrine concerning leaseholder rights. Further, as Demchak illustrated this wave of litigation may act as a potential driver behind new legislation at the state level aimed at how royalties are calculated and disclosed to leaseholders.
The following list represents five recent trends in royalty litigation against Chesapeake to watch in the next year.
5. More Small Leaseholders in Filing Single Cases: The Demchak settlement may act as a trigger point for small leaseholders to advance their claims. However, some firms have elected to employ the strategy of filing individual royalty claims rather than navigate the procedural requirements of establishing a class action suit. For example, the Texas-based McDonald law firm has reportedly been retained by around 4,000 with the hope of 10,000 signing up by Christmas. These suits against Chesapeake in Texas will likely result in a flood of litigation against Chesapeake, which could prove logistically difficult to defend.
4. New Theories of Recovery: In June 2014 a group of Pennsylvania royalty owners have filed suit seeking $5 Million in damages in Federal Court alleging Chesapeake and Access Midstream Partners LP violated the federal Racketeering Influenced and Corrupt Organizations (RICO) Act. This argument takes the traditional royalty claim beyond a matter of contract interpretation to include the allegation that the companies have engaged in a scheme to raise capital by reducing payouts to royalty owners.
3. Potential Criminal Cases: On September 10, 2014 a Michigan State Court judge has ordered that sufficient probable cause existed for the company to stand trial on a racketeering charge and 20 counts of false pretenses charges brought by the Michigan Attorney General. The allegations of the case state that the company allegedly defrauded Michigan property owners by cancelling nearly all of its lease agreements when competition dried up.
2. Developments in Federal Case Law: Two recent federal court decisions this summer coming from the Fifth U.S. Circuit Court of Appeals in New Orleans ruled that Chesapeake could charge royalty owners for post-production costs despite lease provisions, which appeared to state otherwise. This Federal Circuit's jurisdiction includes Louisiana, Texas and Mississippi, potentially affecting Federal and State royalty litigation in these areas.
1. Large Leaseholders Suits: Large leaseholders have brought improper royalty deduction claims against Chesapeake recently with a number of these suits being settled for significant sums of money. For example, the cities of Fort Worth and Arlington sued Chesapeake in 2013 settling their claims this August for over $1 Million. The Hyder family, the leaseholder, owns approximately 1,000 acres, brought a claim against Chesapeake in a San Antonio Court winning an award of $1 Million. Billionaire Ed Bass, Trinity Valley School and Texas Health Harris Methodist Hospital Southwest Fort Worth among others have sued Chesapeake over leases covering 3,290 acres in the Northern District of Texas Federal Court. The case is still pending at this time.
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Replies to This Discussion
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Permalink Reply by Steve P on
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My leases have a Pugh clause, a clause that releases all productive horizons that are more shallow that the producing horizon after the primary term, a royalty provision that excludes the charging of compression, transportation, etc charges, a surface damages clause, and other provisions.
Having said all that, I recently had to put EnCana "on 30 day demand" because they have been charging me transportation charges on a lease that they are operating. Actually, they aren't even operating the unit - SWEPI is the operator, but EnCana owns 50% of the well. SWEPI is deducting those charges, but EnCana is. The 30 days hasn't run yet. We'll see if and how they respond. The good and bad news is that the amount they owe me can fit within the local jurisdiction of "small claims" court.
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Permalink Reply by 30 yr-landman on -
Steve P..........These lease provisions sound useful and fair, except for the release of "all productive horizons (?) that are more shallow than the producing horizon after the primary term". these type release provisiona can sometimes work to the disadvantage of the Lessor. Image X# of years down the road when production from the current zone has become depleted and your operator decides its time to plug and abandon the producing interval in the well/zone. Many times its not worth it for the Lessee to come back to you to try to re-lease prospective shallower zones seen in the well log. So the result is Lessee plugs the well and walks away. NOT GOOD! Other oil companies see the well log information (one published) and can't justify drilling a new well and/or don't understand why the former Lessee didn't attempt a completion in the shallower (released) depths. Result is no one comes back to attempt a completion in the prospective shallower depths. I've seem this happen more than once in the past 34 years. A good solution is to permit your Lessee designate and retain zones in your well(s) "that appear to be productive of oil and or gas in paying or commercial quantities." As for their charging "transportation charges" against your royalty payments, don't disagree but would caution you that sometimes these type charges are charged not by the operator/Lessee but more often by the pipeline, purchaser or gatherer. These type charges are unavoidable and would have to be paid by you or anyone who wanted to sell oil or gas to such pipeline. Let's say you decided to take your royalty share of gas or oil "in kind" and separately market your share of production.....the pipeline/purchaser would charge you and anyone else these type charges. I'd focus more on a getting a reasonable "market value" lease royalty paragraph, especially one that provides for your being paid directly for your royalty share of processed liquids. Many of the big companies will pay your royalties based on MMBTU (heating) value of the product "at the wellhead", then run your gas through an offsite processing plant and keep 100% of the processed liquids. These processed liquids (condensate/oil) are pretty darn valuable these days. Remember, your royalty share is based upon say a 1/5th share of the oil and.or gas but can be further reduced based upon price paid for those sold products. Many times the big companies sell to produced hydrocarbons to a sister "midstream" company or subsidiary. Would you rather have 1/4 share of the gas sold at a "reduced" price or a 1/5th share of the same gas sold at a much higher price? Just a few items to think about next time around.
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Permalink Reply by Henry on
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With regard to the vertical Pugh clause.... I am conflicted. I am currently in negotiations to lease a tract of land. The company has agreed to a Pugh clause whereby they will hold only those formations to which they drill, and they will release everything above and below after the primary term. However, I think I have a pretty good lease here -- 25% cost-free royalty. I am considering NOT taking the Pugh clause. Yes, I will be giving up any possibility of a bonus in the future on my shallow (or deeper) depths. But on the other hand, I would have a 25% cost-free royalty locked in on all depths forever. Decisions, decisions.....Any thoughts out there?
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Permalink Reply by tc on
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One question does your operator have the capital, expertise, willingness, etc.,to drill at these other depths? The reason WildHorse Resources has all that Cotton Valley acreage is because operators like Chesapeake didn't want to be bothered with that formation and also I won't be surprised if that acreage didn't have operator friendly leases. So would this "pretty good lease" be economical for the operator at other depths? If the answer is no, then the chance of you seeing development at these other depths is very slim. 20% of something is more than 25% of zero.
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Permalink Reply by Jesse Joyner on
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Think about it, Henry. Here's an example of what has happened and what can happen in the future. Back in the spring of 2008, a certain landowner was under lease with a vertical Pugh. Then the Haynesville came along. The top-player operator (that the landowner was leased to) contacted the guy and convinced him to allow them to drill deeper without invoking the Pugh by simply offering a pittance per acre, not mentioning the HA and not offering the high-dollar bonus money that was just beginning to fuel the HA leasing. And yes, it was a sweet spot.
Also, at that time many such landowners were still in the dark and didn't know the game had changed, not knowing how high the bonus money per acre was shooting up.
The bottom line. The landowner lost about a million dollars just on the bonus money since he had a valid Pugh. In other words, he was lied to by the landman who was fronting for the operator.
In general, from what I know, getting a vert. Pugh and even a horizontal Pugh isn't a tough negotiation for most savvy mineral owners. And you know that once you sign whatever lease, you'll be stuck in HBP for many years with no way to ever ink a do-over. You'll be stuck. Also, if the operator cuts and runs with a shut-in per an underperforming formation, why are you selling yourself short? If you nailed a good lease on the free royalty and the 25%, why do you think you won't be able to pull off such a hat trick yet again in the future?
If it was me, I'd keep the vert. Pugh and would also ask for a horz. Pugh and would keep the other good stuff the same, yet maybe add some of the other favorable clauses such a shut-in, damages, etc.
Finally, the Kool-Aid drinkers think the big bonus money will never come back. Of course, no sane person ever thought the bonus money would ever make it above $10,000 an acre, either. That was totally impossible. But it actually did happen. And many people to date have made more income off their bonus than they'd garnered so far via their royalty. So the future is an unknown that certain insiders may speculate and gossip about but that few can truly predict. Being under HBP is not always the wisest way to manage a mineral estate.
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Permalink Reply by Steve P on
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my guess is that nearly all of the NW La mineral owners who had unleased minerals in 2007 - 09 have made more off of lease bonuses than royalties. And for one simple reason - the declining price of natural gas means that NONE of our leases were worth $10,000/acre. Don't get me wrong. I'm pleased to have gotten what I got in the way of lease bonuses. But, what operator that paid those bonses has now made a profit on those investments? Lease bonus, cost of drilling a horizontal well, building a gathering line that can handle the pressure, and the capital cost of money from payment of lease bonus to selling production - real money. Lease bonuses were a "sunk cost" for the operators, but if they had known then what they know now, the bonus prices would have never gotten as high as they did. I'm no expert on these matters, but I invested in and lost money on stocks of companies tied to natural gas exploration. Seems that Wall Street concluded that those companies paid too much for the leases.
In many areas of Desoto and Sabine Parishes there are shallow oil, liquid-rich gas or just gas formations. The big operators will never drill those, and I'm not sure how interested they are in "farm-outs" of the shallow rights. Since they royalty for most of the leases in the 2007 - 09 time frame were 25%, there not much margin for farm-outs anyway.
I'd be willing to grant a low-bonus lease to a reputable small operator who would be willing to drill those shallow formations. A vertical Pugh Clause lets me do that. Without the vertical Pugh clause, those shallow formations will likely never be drilled in my life time. And Chesapeake, EnCana, Shell, Exco, Comstock or the others are highly unlikely to recomplete a HS well into a Hosston or Paluxy well. Those days are gone.
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Permalink Reply by 30 yr-landman on
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Remember natural gas prices were upwards of $13 p/MMBTU in 2008 and the industry examples such as EXCO, Chesapeake and other publicly traded companies used "voodoo dolls, smoke and mirrors" to sell "high volume and long life reserves" to the stock market analysts to raise the market caps on their companies (raise capital) when in fact they were destroying shareholder value in their companies. Best example...Chesapeake! While many mineral owners have reaped the rewards of increased activity, I would caution all to remember the crash of 1985-86 when colleges and universities shut down their petroleum industry related schools because there were no jobs available in the Petro industry. This day will come again. Suggest reading of two books to get a better perspective of the history of the Petro. industry....."Titan: The Life of John D. Rockefeller, Sr." by Ron Chernow and "The Prize" by Daniel Yergin. Excellent books that example the ups and downs of the oil industry back to 1865. Above are all excellent comments and observations.
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Permalink Reply by Larry G Smith P.E. on
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Thanks 30 yr -landman, you called it like it was and is. Selling long life reserves to investors that did not know the business. The big volumes of the first producers were the Frac pressures being pulled off the formation and after a short time the real production of these wells are producing what the real reserves are about. Reminds me of when a certain person pulled about the same stunt to sell out his business many years ago. They even bought that business and assumed all the debts, all based on slight of hand.
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