Deed Reformed to Retain Oil & Gas Rights

Learn from an interesting, recent case in the Seventh Appellate District where the fight was about ownership of the oil and gas under a 13-acre tract. Robenolt v. Zyznar, 13 MA 129, CA7, June 13, 2014,

On March 24, 2010, the parties entered into a real estate sales contract for the sale of 13 acres out of the Robenolts’ 48-acre tract. The contract specifically provided that the Robenolts would retain the mineral rights to the property. At the original closing, Zyznar recognized that there was a problem with the legal description of the property being conveyed, particularly as it related to the size of the parcel and the inclusion, or not, of a tree line. He also realized that the deed did not contain any reservation of mineral rights, but during negotiations about the tree line he did not bring this omission to anyone’s attention.

After the closing, the Robenolts realized that their contractual right to the mineral rights had not been included in the deed, but Zyznar refused to agree to a corrective deed. The Robenolts then sued Zyznar, seeking rescission and reformation of the deed based upon mutual mistake.

The trial court found that there was a mutual mistake concerning the Robenolts’ retention of the mineral rights and ordered reformation of the deed. Zyznar appealed.

The appellate court summarized the law of merger and mistake:

“Generally, under the merger doctrine, when a deed is delivered and accepted without qualification, the underlying purchase contract becomes merged into the deed and a cause of action no longer exists upon the contract. Instead, the purchaser is limited to the express covenants in the deed. However, one exception to the merger doctrine that has evolved is mistake. When there is a mutual mistake by the parties to an instrument resulting in an instrument that does not evince the actual intention of those parties, equity allows for reformation of the instrument to reflect the real intention of the parties.” (citations omitted)

The appellate court found that there was competent, credible evidence to support the trial court’s finding of mutual mistake. As the trial court noted, the real estate sales contract was the best evidence of the parties’ true intent. And it clearly stated that the Robenolts were retaining their mineral rights to the property. In bold and underlined typeface, it stated, “the owner shall retain any and all oil and mineral rights on the property.” This constitutes clear and convincing evidence that the execution and recording of the deed without that reservation was a mutual mistake.

Additionally, there was other evidence that supported the trial court’s finding of mutual mistake – Zyznar’s testimony at trial about both the tree line and mineral issues that arose during negotiations with Robenolt. It was clear that the Robenolts had not changed their position about the mineral issue while giving on the tree line issue.

The court summarized,

“All parties were fully aware that, upon transfer of the real estate in question to Zyznar, the Robenolts were to retain all of the mineral rights. This was evidenced by the real estate sales contract and Zyznar’s own testimony at trial. The omission of the mineral rights retention from the deed was, therefore, a mutual mistake and the Robenolts are entitled to equitable reformation of the deed.”

When oil and gas are at stake, litigation — even appellate litigation — are more likely. It has always been thus.

“Paragraph 19” Lease Provision Upheld

In 2007, the Easthams entered into a lease with a lessee who later assigned the lease to Chesapeake. The lease term was five years. Paragraph 19 of the lease stated,

“In consideration of the acceptance of this lease by the Lessee, the Lessor agrees for himself and his heirs, successors and assigns, that no other lease for the minerals covered by this lease shall be granted by the Lessor during the term of this lease or any extension or renewal thereof granted to the Lessee here in. Upon the expiration of this lease and within sixty (60) days thereafter, Lessor grants to Lessee an option to extend or renew under similar terms a like lease.”

On March 14, 2012, Chesapeake filed a notice of extension of the oil and gas lease with the Jefferson County Recorder. Upon filing the notice of extension, Chesapeake sent the Easthams a letter stating that it had extended the lease on the same terms for an additional five years. The letter enclosed a delay rental payment for $490.66.

The Easthams filed a class action suit alleging that Paragraph 19 does not give Chesapeake the option to unilaterally extend the lease, but rather requires that the parties renegotiate the lease at the end of the initial five-year term.

The federal district court agreed with Chesapeake, granting summary judgment in its favor and denying summary judgment to the Easthams, concluding that under the plain language of the lease, Paragraph 19 gave Chesapeake two options: either to extend the lease under its existing terms or renegotiate under new terms.

The Easthams appealed that decision to the Sixth Circuit Court of Appeals and it published its opinion of June 6, 2014. Eastham v. Cheasapeake Appalachia, No. 13-4233, 6th Cir. (June 6, 2014).

The appellate court did not agree with Easthams’ argument that options to “extend” ware synonymous with options to “renew” under Ohio law. Easthams relied on a recent Ohio trial court case, Flannery, et al., v. Enervest Operating, LLC, et al., C.P. No. 12 CVH 27524 (Carroll Cnty. Common Pleas, April 14, 2014). In that case, the state trial court interpreted contract language identical to Paragraph 19 and concluded that there is “no meaningful distinction between an option to extend and an option to renew” a lease. But, as the appellate court said, the Flannery decision is not binding on it. Instead, the appellate court relied on an Ohio Supreme Court case that recognized the distinction.

Then, addressing the argument that the provision was ambiguous, the court said, “The plain language of the lease agreement indicates that Paragraph 19 is unambiguous. Again, the viability of the Easthams’ construction of Paragraph 19 requires the assumption that the terms “extend” and “renew” mean the same thing.” … “Contrary to the Easthams’ argument, however, these words have different meanings.”

Finally, the court said, “Although a party always has the option to attempt to renegotiate new contract terms, through the phrase “renew under similar terms a like lease” Chesapeake here reserved the right to unilaterally bind the Easthams to a new agreement “under similar terms” to the preceding agreement for a new length of time. Indeed, the ability of one party to bind the other unilaterally is an essential feature of option contracts generally.”

Responding to the Easthams’ argument that they had been swindled and the contract should be unenforceable as against public policy, the court said,

“The presumption under Ohio law is the freedom to contract.” *** “And, we were unable to locate either an act of the Ohio General Assembly or an Ohio court case that supports the Easthams’ assertion with regard to Ohio’s public policy about construing oil and gas leases. In short, the Easthams have not actually offered any public policy that the lease could have violated.”

1989 Version of Ohio Dormant Mineral Act Prevails

The Jefferson County trial court decision in Shannon v. Householder finding that the severed mineral interest were automatically reunited with the surface pursuant to DMA ’89 was affirmed on appeal. 7th Dist. No. 13 JE 24, (June 2, 2014)

To reach this result, the appellate court (1) determined that DMA ’06 did not retroactively negate the automatic abandonment effect of DMA ’89, and (2) dismissed the idea espoused in Dahlgren v Brown Farm Properties, Carroll C.P., 13CVH27445, (Nov. 5, 2013). There the court said that DMA’89 requires DMA’06 to establish the Constitutionally-required notice. Also, even if DMA’89 applies to extinguish a dormant interest for nonuse during the 20-year look back period, “[A]t most the absence of those conditions created an inchoate right; it could not and did not transfer ownership without judicial confirmation or at least an opportunity for the disowned party to contest their absence or the effect of their absence.”

In the Shannon court’s view,

“We concluded that the 1989 DMA can still be used after the 2006 DMA amendments because the prior statute was self-executing and the lapsed right automatically vested in the surface owner. See Walker v. Shondrick-Nau, Executrix of Estate of Noon, 7th Dist. No. 13NO402, 2014-Ohio-1499 (fka Walker v. Noon). We maintain that holding and reiterate the rationale here.”

Condensate – Part 2


Sources of Condensate – Where does it come from?

(Part 2 in our condensate series)


In the first part of this series we attempted to define what condensate is. We will pick that up again here focusing on the sources of condensate and condensate-like products.

So what makes a condensate a condensate? According to Mr. Braziel, this is the heart of the problem because the term condensate can refer to a number of products made up of somewhat similar hydrocarbon compounds. See,“Fifty Shades of Condensates – Which One Did You Mean?”, published by Rusty Braziel, 10/22/2012.–which-one-did-you-mean. Much of this section is an excerpt of Mr. Braziel’s blog, to which the reader is commended.

Lease Condensate

When most people talk about condensates they are referring to “lease condensates”, so defined because they are produced as a liquid at the lease level from oil or gas wells and unprocessed except for basic stabilization at or near the wellhead. Lease condensates have wide ranges of API gravities from 45 to 75 degrees. Braziel, supra.

Marty Shumway explains it this way. “The term ‘condensate’ generally refers to the volatilized oil content of produced fluids from an oil and gas well. The volatilized oil content of a gas represents its condensable liquid portion. Condensable refers to the portion that condenses or ‘drops out’ during pressure reduction that often takes place on the lease in separators and other equipment. The intermediate hydrocarbon components (C2 through C7) are the major components of this fraction, which is commonly referred to as lease condensate or distillate.”[1]

Natural Gas Plant Liquids

Similar products are produced at natural gas processing plants. EIA describes “natural gas plant liquids” as the liquids separated from natural gas at natural gas processing plants, fractionating and cycling plants, and [to add to the confusion] in some instances, field facilities. “Lease condensate” is excluded. Products obtained include liquefied petroleum gases (ethane, propane, and butanes), pentanes plus, and isopentane. EIA, supra.

Rusty Braziel also distinguishes “lease condensate” from “plant condensate,” the latter a product of NGL processing plants essentially equivalent to natural gasoline. Since it comes from a processing plant, plant condensate is considered a processed product. Plant condensate production is increasing with the surge in NGLs from growing natural gas production. Braziel, supra.

Light Naphtha

There is a third hydrocarbon product that is also somewhat interchangeable with natural gasoline and middle-of-the-road lease condensates, and that is naphtha, specifically light naphtha. Light naphthas are made up mostly of C5s, C6s and portions of the heavier hydrocarbons. Most of it is produced at petroleum refineries by distillation or the process of condensate splitting and light naphtha is considered a refined product. Braziel, supra. This will be important when we discuss the ban on the exportation of crude oil, which does not extend to refined products.

These hydrocarbon products — lease condensate, plant condensate and naphthas — have been used for years as feed stocks for refinery upgrading processes, for gasoline blending and as feed stocks for petrochemical processes, among other uses.

According to Braziel, the challenge today is to identify how the market will handle increasing volumes of lease and plant condensate. The answer to that challenge is partly wrapped up in the issue of which condensates may be exported and which markets they can go to. Braziel, supra.

We will examine the markets for condensate in Part 3 of this series.

The Utica Shale as a Source for Condensate

It seems clear, if based upon nothing else but industry investment, that Ohio is going to be a source of condensate. Between the dry gas regions in the eastern portion of the Utica and the immature western portion, there will likely be produced a mixture of oil and natural gas, with a band of condensates and wet gas (including ethane, propane, butane, etc.) occurring somewhere in east-central Ohio. These accessory condensates and wet gas compounds are extremely valuable in the chemical and plastics industries.[2]

In fact, much of the profitability of the Utica is based on the “wetness” of its production. This has led to increased interest in the area between the “dry” area to the east and the “immature” area to the west – the so-called “fairway.” As this area is being defined, many wells in the proved area are waiting for the infrastructure — pipelines, processing and fractionation plants — to be constructed. As my friend Gary Heminger, President and CEO of Marathon Petroleum is fond of saying, “Transportation wins.” It’s all about connecting the product to its market.

For example, Marathon recently described its strategy to supply Utica condensate to its refineries at Canton and Catlettsburg.[3] The initial pipeline will link natural gas processing and fractionation facilities to Marathon’s Canton refinery. “The pipeline route would link two gas-processing facilities owned by MarkWest Energy Partners LP at Cadiz (185 MMcf/d cryogenic plant today – expanding to 385 MMcf/d in 3Q 2014) and M3 Midstream LLC (Momentum) at Leesville (200 MMcf/d cryogenic plant) and a fractionator at Scio also owned by M3 (90 Mb/d output). The two cryogenic plants process wet natural gas to separate NGLs from pipeline quality gas including “raw” condensate. [See the flow diagram on my web site, here. Be patient, it eventually opens.] The combined stream of NGLs, known as y-grade,[4] are then further processed in a fractionator to produce purity liquids including natural gasoline or C5. The proposed 8-inch diameter Cornerstone pipeline (about 40 Mb/d capacity) will be batch operated to ship separate parcels of crude, condensate or natural gasoline.[5] Marathon expects to ship raw condensate stabilized to meet pipeline specification from Cadiz and Leesville as well as natural gasoline from Scio.

Other projects have been announced, too. Dallas-based Crosstex Energy companies Crosstex Energy LP and Crosstex Energy Inc. have announced that Crosstex Energy Inc. will invest about $25 million in a third natural gas compression and condensate stabilization plant in the Ohio River Valley.

E2 will build, own, manage, and operate all three compressor stations and condensate stabilization plants in Noble and Monroe counties in the southern portion of the Utica in Ohio. The counties are immediately east of assets in the Ohio River Valley.

The new plant will have compression capacity of 100 MMcfd and condensate stabilization capacity of 5,000 b/d, which brings total expected capacity for the three facilities to 300 MMcfd of compression and 12,000 b/d of condensate stabilization.[6]

In addition to pipelines, transportation by rail is being used to connect Ohio condensate to its markets. Ohio Oil Gathering, a subsidiary of Crosstex Energy, L.P., recently celebrated the reactivation of the company’s Black Run rail terminal on July 17, 2013 at its regional office in Frazeysburg, OH. The Black Run rail terminal is the first facility to move light oil condensate out of the region to refinery and petrochemical markets.[7]

While there are plans to export Utica products to the Gulf Coast by pipeline, there already is plenty of new lease condensate showing up at the Gulf Coast from production in the Eagle Ford and other shale basins. And refineries there are designed to refine heavier crudes, not condensate.

Will the markets for Ohio condensate be there? We will look at that in the next part of this series.


[1] Notes provided by Marty Shumway, MacKenzie Land & Exploration, Ltd., Worthington, Ohio


[3] See

[4] “Y grade is a common term in the industry for the ‘easily’ condensables.” See,

[5] Natural gasoline is a form of natural gas that becomes a liquid under regular atmospheric pressure and moderate temperatures. It can form naturally from condensates or may be obtained by the fractional distillation of wet natural gas. When natural gasoline forms from condensates, it is often referred to as drip gas. See,

[6] “Crosstex to invest in Utica shale compression, condensate stabilization,” Oil & Gas Journal, 05/09/2013.–condensate-stabil.html



View this interactive graphic at Again, be patient. It is a big file but it eventually opens.

natural gas infrastructure graphic

Utica Shale Condensate — What Is This Stuff Anyway?

Shortly after ODNR delivered the Utica shale production numbers for 2012, there were conflicting assessments as to whether it was good news or bad news. See the discussion here. Generally, if one had been looking for high crude oil numbers, perhaps there was disappointment. But as more careful analyses were published, it became clearer that an accurate assessment is not so simple. See, here.[1] While there is a unit of production that would seem to allow “apples to apples” comparisons of the production of crude and gas – barrels of oil per day equivalent, BOE/D – it turns out it is not that simple either. There are NGLs and condensate in the mix, too, and ODNR did not call out those numbers separately. Furthermore, there are different infrastructure requirements and markets for NGLs and condensate. And it gets more complicated than that, say, for example, when the market is foreign. Hydrocarbons, although similar chemically, are distinguished by their provenance. So, for this author, that meant homework. While it will be readily apparent that I am not a petroleum engineer, hopefully this series of articles will enlighten you.

First, some of the terms need to be fleshed out.

Condensate & Condensation

 Condensation is the change of the physical state of matter from gaseous phase into liquid phase, and is the reverse of vaporization.[2]

 Condensate is a liquid – a liquid phase produced by the condensation of a gas. For example, it is the liquid water created (condensed) from the water vapor (a gas) you exhale along with other gases onto cold glass. When the temperature of the vapor is reduced below its saturation temperature – i.e., its dew point corresponding to the pressure in the vapor – a liquid is formed.

Natural Gas Condensate

As in many other cases, “condensate” has a special meaning in the world of oil & gas. “Gas condensate,” or “condensate,” is a hydrocarbon liquid dissolved in saturated natural gas that comes out of solution when the pressure drops below the dew point.[3]

API Gravity

These liquids are described in terms of their API gravities. “API Gravity” is the American Petroleum Institute standard for measuring the relative viscosity or density of oil. The scale is inverted. That is, the lower the API gravity, the more viscous or dense it is. The relationship with water is helpful. If the liquid’s API gravity is greater than 10, it is lighter than and floats on water; if less than 10, it is heavier and sinks. Although an inverted scale/unit inevitably results in confusion (to this writer anyway), it makes sense at least as applied to the value of crude oil – the higher the number, the lighter the crude, and the higher its value.

Oil with API greater than 30º is termed light; between 22º and 30º, medium; below 22º, heavy; and below 10º, extra heavy. Asphalt on average has an API gravity of 8°, Brent Crude 35.5°, and gasoline 50°.[4]

Confusion: Crude oil, NGL or Condensate?

The problem of labeling these hydrocarbons is exacerbated by common usage as condensate is a liquid hydrocarbon that lies halfway between gas and oil. “Over the years condensate has gone by many names: casignhead gas, casinghead gasoline, white gas, and drip gas.”[5]

Hess’ Material Safety Data Sheet for “natural gas condensate sour” lists as synonyms: Drips; Condensate; Field Condensate; Gas Well Condensate; High Pressure Inlet Liquids; Lease Condensate; Natural Gas Liquids (NGL or NGLs); Pipeline Liquids.

In an on-line discussion regarding the nature of crude oil, gasses and associated liquids, an unknown author says,

“If the hydrocarbons in the reservoir were in the liquid phase, we tend to use the label ‘oil’ for both that reservoir liquid and the liquid that remains after ‘dissolved gas’ is liberated when pressure is reduced by production and separation. If the reservoir hydrocarbons were vapor, we tend to use the label ‘condensate’ for liquids condensed when temperature and/or pressure are reduced (especially the latter).”[6] Both oil and condensate are the liquid hydrocarbon phases resulting from “flashing” reservoir hydrocarbon fluids to surface pressure and temperature.

Defining NGL’s, James Speight says, “Natural gas liquids (lease condensate, natural gasoline, NGL) are components of natural gas that are liquid at surface in gas or oil field facilities or a gas processing plant.” Then he goes on to say, “Similarities exist between the composition of natural gas liquids and gas condensate – to the point that the two names are often sometimes erroneously used interchangeably.” Handbook of Industrial Hydrocarbon Processes, James Speight, Elsevier Inc., (2011).

“Lease condensates are similar to natural gasoline, one of the five NGLs.  In fact, natural gasoline is sometimes called a ‘plant’ condensate.” Braziel, infra.

Responding to Gulfport’s reporting of condensate production from one of its wells, Tim Carr, the Marshall Miller Professor of Energy at West Virginia University, finds Gulfport’s different categorization for condensate and NGL somewhat unique. “That is the hydrocarbon liquids in a very saturated natural gas that come out of solution when the pressure drops,” he said of the condensate. “I think when they are distinguishing condensate from NGLs, they are referring to pentane or what is referred to as natural gasoline.”[7]

Speight distinguishes condensate and NGLs this way, “On a strictly comparative basis, the constituents of gas condensate represent the higher boiling constituents of natural gas liquids.” Speight, supra.

Alberta Oil & Gas Trading says, “There is no clear definition of the condensate. Generally crude is considered to be condensate if its API gravity is between 50º API and 120º API.”[8] Rusty Braziel says, “A lease condensate has an API gravity ranging between 45 to 75 degrees.” Braziel, infra. Others say that condensate can have an API gravity of 44-53 degrees.[9] Color is also an indicator.

The EIA Weighs In

The source of the condensate seems to yield a more consistent categorization. The U.S. Energy Information Administration (“EIA”) provides separate estimates of lease condensate and natural gas plant liquids proved reserves. For their purposes, “Lease condensate is a mixture consisting primarily of hydrocarbons heavier than pentanes that is recovered as a liquid from natural gas in lease separation facilities. This category excludes natural gas plant liquids, such as butane and propane, which are recovered at downstream natural gas processing plants or facilities. Lease condensate is often blended directly into other crude oil to enhance quality.[10]

On the other hand, the EIA says, “NGLs are liquid or liquefied hydrocarbons recovered from natural gas in separation facilities or gas processing plants. Natural gas liquids include ethane, propane, butane (normal and iso-), (iso) pentane and pentanes plus (sometimes referred to as natural gasoline or plant condensate).[11] “Pentanes Plus, or C5+, is a mixture of hydrocarbons that is a liquid at ambient temperature and pressure, and consists mostly of pentanes (five carbon chain) and higher carbon number hydrocarbons. Pentanes plus includes, but is not limited to, normal pentane, isopentane, hexanes-plus (natural gasoline), and plant condensate.”[12]

The distinction is important as EIA provides separate estimates of lease condensate and natural gas plant liquids proved reserves. Operators of natural gas fields report their lease condensate reserves and production estimates to EIA on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves.” EIA calculates its estimate of natural gas plant liquids reserves using wet natural gas reserves estimates and a recovery factor determined for each area of origin. Data from Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” are the basis of EIA’s recovery factors.[13]

Ohio engineer, Marty Shumway, says, simply, “Typically, condensate (volatilized oil) is reported by producers as part of crude oil reserves and production and is distinctly different from NGLs. NGLs are generally derived from off-lease gas processing plants.”[14] That’s the way to distinguish NGLs and condensate, I think, but the market is not that simple.

In the next part of this series, we will look at the sources of and markets for condensate.

[1] Where it is said, “It seems likely that the wet gas area of the Utica will produce large volumes of natural gas liquids and condensate. While these liquids may not be quite as valuable as oil they do provide considerable uplift over and above the price of natural gas.”

[2] IUPAC, Compendium of Chemical Terminology, 2nd ed. (the “Gold Book”) (1997).


[4] See,



[7] “Some Utica Shale Gas Wells May Produce $100,000 Daily,” by Duane Nichols, 1/29/13.



[10] “U.S. Crude Oil and Natural Gas Proved Reserves, 2011”, U.S. Energy Information Administration, August 2013.



[13] “U.S. Crude Oil and Natural Gas Proved Reserves, 2011, U.S. Energy Information Administration, August 2013.

[14] Notes provided by Marty Shumway, MacKenzie Land & Exploration, Ltd., Worthington, Ohio

The Ohio Dormant Minerals Act: Part 5

I’ll finish up this series here at my office in Findlay. In the previous parts of this series (Read part 1, part 2, part 3 and part 4) are at Porter Wright’s web site. The earlier blogs discussed the history of DMA and summarized how it provides for the abandonment of severed mineral interests. Now we will look at court opinions that have interpreted the law.

Constitutionality of DMA’89

In Tribett v. Shepherd, Belmont C.P. No. 12-CV-180 (July 22, 2013) stated:

“The Ohio Dormant Mineral Act was enacted in its original form on March 22, 1989. The act has been characterized as a “use it or lose it” statute. The Ohio Legislature attempted to balance the interests of property owners and the compelling public interest in drilling, producing and marketing the mineral interests of this state. Dormant and abandoned mineral interests were viewed as of no benefit to the state, while making use of the state’s mineral resources was for the public good.”

“In order to negate the retroactive effect of the Act, [the three-year grace period was included].”

“The oil and gas owners thereby were given three years to meet one of the “Savings Events” provisions. A similar statute was enacted in Indiana and provided for a two-year grace period. This act was upheld by the United States Supreme Court in Texaco Inc. v. Short. 454 US 516 (1982). In Texaco, it was held that, “There was no constitutional right for a mineral interest owner to receive individual notice that his right will expire.”

“Based upon Texaco, this court finds the 1989 Ohio Dormant Mineral Act to be constitutional.”

The same result in Taylor v Crosby, Belmont C.P. No. 11-CV-422 (Sept. 16, 2013) and Tribett v Shepherd, Belmont C.P. No. 12-CV-180 (July 22, 2013). With its notice provision, DMA’06 would seem to be constitutional as well.

DMA’89 is — and, after DMA’06, remains — self-executing

If the facts are such that the requirements of DMA’89 are met, i.e., no savings event between 1989 and 1969, the surface owner can go to court on that basis as the statute is self-executing. This is what the surface owner did in Wiseman v Potts, Morgan C.P., No. 08 CV 0145 (June 29, 2010), where a 1/3 mineral interest severed in 1947 was found to have been abandoned under DMA’89.

Similarly, in Wendt v. Dickerson, Tuscarawas C.P. No. 2012 CV 020135 (Feb. 21, 2013), the court found that because there had been no title transaction determinative, the mineral interest, severed in 1952, became vested in the surface owners on March 22, 1992 — the effective date of DMA’89 plus the three-year grace period.

A court reach the same result in Marty v Dennis (Winkler), Monroe C.P., 2012-203 (April 11, 2013) and Shannon v. Householder, Jefferson C.P. No. 12CV266 (July 17, 2013)

Moreover, DMA’06 is not retroactive such that it would change the applicability or effectiveness of DMA’89. Shannon v. Householder, supra, (“DMA of 2006 is not retroactive but applies only prospectively in accordance with ORC§1.48 as the same was not ‘expressly made retroactive’ as is required under said statute.”). The same result a week later in Tribett v. Shepherd, Belmont C.P. No. 12-CV-180 (July 22, 2013), citing Revised Code 1.58 (A)(1) and (2).

In Walker v Noon, 7th Dist. No. 13 NO 402 (April 3, 2014), the court said, “There is no language in the 2006 version of R.C. 5301.56 to suggest that it is to be applied retroactively.” So, the court found a severed interest with no savings event automatically abandoned on March 22, 1992. Furthermore, with DMA’06 was enacted, the interest had already been abandoned and thus vested with the surface owner.

Contra — it is not self-executing

But court opinions have not been consistent. In Dahlgren v Brown Farm Properties, Carroll C.P., 13CVH27445, (Nov. 5, 2013), the court said it is implied that DMA’89 requires DMA’06 to establish the constitutionally-required notice. Also, even if DMA’89 applies to extinguish a dormant interest for nonuse during the 20-year look-back period, “[A]t most, the absence of those conditions created an inchoate right; it could not and did not transfer ownership without judicial confirmation or at least an opportunity for the disowned party to contest their absence or the effect of their absence.”

In M&H Partnership v Walter Vance Hines, et al., Harrison C.P. No. CVH-2012-0059 (Jan. 14, 2014), the court ruled that DMA’89 does not provide for “automatic” vesting. In its view, that attribute would be contrary to the purpose of the Marketable Title Act (MTA), which allows persons to rely on a record chain of title.

The DMA’89 look-back period

In M&H Partnership v Walter Vance Hines, et al., Harrison C.P. No. CVH-2012-0059 (Jan. 14, 2014), the court held that a lease granted by the mineral interest owners on July 15, 1969, was a savings event under both DMA’89 and DMA’06 because it had occurred during the fixed 20-year period preceding the DMA ’89 effective date of March 22, 1989. Citing Riddell v. Layman: “Riddell v. Layman, 5th Dist. No. 94 CA 114 (July 10, 1995) is the only appellate decision which touches upon the appropriate 20-year look-back period for DMA’89. The Riddell court decided that ‘the title transaction must have occurred within the proceeding 20 years from the enactment of the statue, which occurred on March 22,1989.’ ”

Also citing Riddel, the court in Wiseman v. Potts, Morgan C.P. 08-CV 0145 (Dec. 10, 2009) said: “Under R.C. 5301.56, the time period for examination was 20 years before the effective date of the statute, in other words from March 1969 through March 1989.” Accord, Wendt v. Dickerson, Tuscarawas C.P. No. 2012 CV 020135 (Feb. 21, 2013).

More recently, in Taylor v Crosby, Belmont C.P. No. 11-CV-422 (Sept. 16, 2013), the court quoted R.C. 5301.56 (D)(1), which provides for “successive filings of claims to preserve,” and concluded, “A static 20 year look back period would have no need for a provision providing for indefinite preservation of mineral interests through successive filing of preservation claims. Based upon the same, the Court finds the [DMA’89] to provided for a ‘rolling look back period.'”

 DMA’89 vis a vis DMA’06

In M&H Partnership v Walter Vance Hines, et al., supra, the court ruled that for DMA’89 to apply, the plaintiff would have needed to bring its action before the effective date of DMA’06.

In Gentile v. Ackerman, Monroe C.P. No. 2012-110 (Jan. 13, 2014), the trial court followed Dodd v. Croskey, 2013-Ohio-4257, (Seventh Dist., Sept. 23, 2013), which we discuss further below, applying DMA’06 to a post-2006 claim.

DMA is part of MTA but DMA is controlling

In Tribett v. Shepherd, Belmont C.P. No. 12-CV-180 (July 22, 2013), plaintiff surface owners claimed ownership of the oil and gas. The defendants claimed ownership based on a 1962 reservation.

The defendants argued that DMA, because it is part of the MTA, would include a restriction specified in the MTA that says marketable title is subject to “all interest and defects which are inherent in the muniments of which such chain of record title is formed.” R.C. 5301.49(A). The defendants further noted that two coal deeds specifically identified the severed oil and gas interest. The court responded:

The Ohio Dormant Mineral Act is a part of the Ohio Marketable Title Act. The specific language required by the Dormant Mineral Act controls over the general language of the Marketable Title Act. The Dormant Mineral Act requires a higher test for a “Savings Event” than does the language of the Marketable Title Act. This court does not find the mere filing, of the [coal deeds] within the muniments of title, to be controlling.

In Dahlgren v Brown Farm Properties, Carroll C.P., 13CVH27445, (Nov. 5, 2013), the court analyzed the relationship between the MTA and DMA saying: “In their context, it is clear that the legislature has always intended that the [MTA] and [DMA] are integrated title laws which should be read together whenever they were in effect.” They also said: “Nothing in either [DMA’89] or [DMA’06] denies that the [MTA] remains applicable to mineral rights, at least to the extent that the [DMA] does not expressly provide differently.”

Yet the Dahlgren court concluded that DMA’89 “impliedly required implementation [by DMA’06] before it finally settled the parties’ rights, at least by a recorded abandonment claim that permitted the adverse party to challenge its validity…” even though it has been held that:

  1. DMA’06 is not retroactive; and
  2. The MTA, like a statute of limitation, automatically terminates old interests.


In Gentile v. Ackerman, Monroe C.P. No. 2012-110 (Jan. 13, 2014), the plaintiff argued that the MTA operated to extinguish a 1/2 severed interest. The facts of the case did not allow the MTA to extinguish the severed interest, but, given the court’s analysis of the MTA, the MTA might have been effective had the facts been different.

Subject to a title transaction

Cases interpreting the DMA often turn on whether the mineral interest has been “the subject of a title transaction,” which is a savings event. For example, in Riddell v. Layman, 5th Dist. No. 94 CA 114 (July 10, 1995), the court held that minerals were “the subject of a title transaction” in the deed that created the severance, which had occurred within the preceding 20 years. The defendant mineral owner prevailed.

Other cases have determined that a deed that references or notes a prior mineral reservation did not make the minerals the subject of a title transaction so the surface owner prevailed on that issue. See Walker v. Noon, Noble C.P., No. 212-0098 (March 20, 2013) (the transaction would need to affect the mineral interest); Wendt v. Dickerson, Tuscarawas C.P. No. 2012 CV 020135 (Feb. 21, 2013); Wiseman v. Potts, Morgan C.P., No. 08 CV 0145 (June 29, 2010); Eisenbarth v. Reusser, Monroe C.P. No. 2012-292 (June 6, 2013) (summarizing the previous cases, “a recitation of the original oil and gas reservation in subsequent transfers of the surface do not affect the severed mineral interest and, therefore, do not constitute ‘title transactions’ under [the DMA]”); and Dodd v. Croskey, 2013-Ohio-4257, 2013 Ohio App. LEXIS 4475 (Seventh Dist., Sept. 23, 2013) (“In order for the mineral interest to be the ‘subject of’ the title transaction the grantor must be conveying that interest or retaining that interest.”); Tribett v. Shepherd, Belmont C.P. No. 12-CV-180 (July 22, 2013).

A lease as a “title transaction”

 Bender v. Morgan, Columbiana C.P., 2012-CV-378 (March 20, 2013) considered the following facts. Harry Dorr reserved the oil and gas interest in 1947. The surface owner filed suit, claiming that she owned the minerals under the DMA. The Dorr heirs argued that an oil and gas lease within the 20-year period predating March 22, 1989, was a “title transaction” and, thus, a “savings event.” The court agreed.

A title transaction does not have to be a conveyance. It must merely “affect” the interest. The court said:

Clearly, an oil and gas lease is an instrument which affects an interest in such minerals.” It conveys a determinable fee interest in the oil and gas. “If one focuses attention on the 1988 oil and gas lease alone …, there can be no determination of abandonment under [DMA’89].

There is a similar result in Eisenbarth v. Reusser, Monroe C.P. No. 2012-292 (June 6, 2013), where a number of leases made the minerals the subject of a title transaction. So, too, in Dahlgren v Brown Farm Properties, Carroll C.P., 13CVH27445, (Nov. 5, 2013), “Those recorded leases are ‘title transactions’ that preclude any deemed abandonment for the plaintiffs’ mineral interests pursuant to [DMA’06].”

More recently, the U.S. District Court for the Northern District of Ohio, Eastern Division, held that an oil and gas lease, specifically a partial release of the lease, was a title transaction that precluded abandonment. McLaughlin v CNX Gas Company, Case No. 5:13CV1502, Dec. 13, 2013.

In McLaughlin, the plaintiff filed an action to quiet title, alleging that the mineral rights merged with the surface rights no later than Jan. 3, 2005 because following the 1985 severance, 20 years passed without a title transaction. In the plaintiff’s view, an oil and gas lease was “nothing more than a license and therefore cannot act in any manner preserve rights under the DMA.” The court did not agree. After reciting the MTA’s definition of “title transaction,” it said:

As the above definition makes clear, title transaction means any transaction affecting title to any interest in land. It is difficult for the Court to conceive of a broader definition than the one chosen by Ohio law. By its plain language, the statute does not require a conveyance or transfer of real property in order to constitute a title transaction. Rather, the statute simply requires a transaction that affects title to any interest in the land.

The nature of the interest conveyed under Ohio law in an oil and gas lease notwithstanding, “[T]hose interests quite clearly still affect title to the mineral rights in the property. As the lease itself was a title transaction, there can be no dispute that the release of rights under that lease qualifies as a title transaction as well. Accordingly, Plaintiff’s claims must fail as a matter of law.”

Contra for an inactive lease

However, in Shannon v. Householder, Jefferson C.P. No. 12CV266 (July 17, 2013), the court said that a mineral lease was not an activity “which under the statute prevents the abandonment of said minerals.” The court pointed out: “No activities were ever commenced under said oil and gas lease.”

Apparently, because the inchoate fee simple determinable never vested in the lessee, the lease was not a title transaction. The rights to look for the minerals and to drill on the property granted in the lease were not enough to make the minerals the subject of a title transaction. However, in Marty v. Dennis (Winkler), discussed below, the court said that the right to receive a royalty payment should production be achieved is an interest in real estate subject to DMA abandonment.

The DMA’06 procedure

In Dodd v Croskey Harrison C.P. No CVH-2011-0019 (Oct. 29, 2012), the point of contention was a 1/3 mineral interest that had been excepted from a 1947 deed. The surface owners attempted to have it deemed abandoned using DMA’06. The lower court found that there had been a title transaction within the DMA’06 look back period so the interest remained with the holders. The court also said that not all of the holders had been provided the requisite notice.

The appellate court affirmed the lower court result but not for all the same reasons. It found that Croskey, an heir of the grantor in the 1947 deed, had filed an affidavit to preserve within 60 days of the owners’ published notice. Dodd v. Croskey, 2013-Ohio-4257, (Seventh Dist., Sept. 23, 2013). Croskey had filed a document titled “Affidavit Preserving Minerals.” It did not identify a savings event so it could not be a “Savings Event Affidavit” under (H)(1)(b), which was added by the 2006 amendment. But was it a “Claim” under (H)(1)(a) and, like other savings events listed in DMA’89, did it have to occur during the 20-year look back period that ends on the notice date?

Does the notice preclude a later claim?

In short, was the Croskey claim a “savings event” under (B)(3)(e) and division (C)?

The surface owner argued that the claim filed by Croskey could not be a savings event because it was not filed within the 20-year look back period preceding the notice. This assertion is based on (H)(1)(a)’s statement that the claim to preserve the mineral interest is to be in accordance with division (C), which mandates the 20-year period.

Despite the statute’s intertwined references, the court did not agree. As the court opined: “The clear language of … (H)(1)(a) does not require the claim to preserve the mineral interest to have been filed within the 20 years immediately preceding the notice. Rather, it requires the claim to be filed within 60 days after the notice.”

Though its MTA progeny would lend credence to the 20-year requirement for a claim, the 2006 amendments, in light of Texaco v Short, clearly intended to ameliorate the harshness of the MTA by providing notice and a chance to respond.

Finally, citing the common law maxim — the law abhors a forfeiture — the court found the filing, albeit outside the 20-year period, a savings event.

In Marty v Dennis (Winkler), discussed below, the court summarized the DMA’06 procedure consistent with the Dodd v. Croskey decision.

Notice requirement

In Tribett v. Shepherd, Belmont C.P. No. 12-CV-180 (July 22, 2013), the surface owner’s failure to attempt service precluded its reliance on DMA’06 for its abandonment claim.

Deadlines are deadlines

Bender v. Morgan, Columbiana C.P., 2012-CV-378 (March 20, 2013) provides a lesson, too. As the court recounts, DMA’06 requires the surface owner to provide notice to the holder under division (E)(1). Next, for the mineral right to vest with the surface owner, (E)(2) requires that an affidavit of abandonment must be filed at least 30 days, but no later than 60 days, after notice. Here, the affidavit was filed 61 days after notice so the court found it “late and ineffective as a matter of law.” Moreover, the holders filed a Claim (this time there was no argument as to its being filed after the notice as in the Dodd v Croskey case) and a separate tax parcel for the mineral interest has been created, both of which the court found effective as savings events.

Royalty interest subject to abandonment

In 1949 John Winkler conveyed property with a reservation:

Also excepting and reserving unto the grantors herein, their heirs and assigns, the one-half (1/2) of the oil and gas royalty, same being one- sixteenth (1/16) of all the oil and one-half (1/2) of all monies received from the sale of gas from the east half of the south east quarter of Section 24, Township 3 of Range 4, containing sixty-eight (68) acres.

Marty, the surface owner, recorded an affidavit under DMA’89 declaring that the severed interest was abandoned. Six days later, notice was published in the paper declaring the interest was abandoned and vested in them. A month later, Marty filed another Affidavit of Abandonment, this time pursuant to DMA’06. Three weeks after that, the Winkler heirs filed their Notice to Preserve Mineral Interests.

In the ensuing litigation, Marty v Dennis (Winkler), Monroe C.P., 2012-203 (April 11, 2013), Winkler’s defense was that their interest is only the right to receive a royalty payment and is not a mineral interest that can be forfeited under DMA, and even it is subject to forfeiture, it had been preserved by the Notice to Preserve Mineral Interests.

The court recounted the self-executing nature of DMA’89. Then it pointed out that in a previous case, Cyril T. Burkhart v. George A. Burkhart, Monroe C.P. CVH 92-278, it had held a royalty interest to be subject to DMA’89. The Winkler heirs tried to distinguish the earlier decision saying that a right to receive a royalty payment is different from an actual mineral interest in the property. Marty responded by arguing there is a difference, but a royalty interest is still an interest in realty until the minerals are produced.

The court agreed with Marty, holding that the interest was subject to abandonment under DMA’89 and DMA’06. Furthermore, because there were no savings events within the DMA’89 look back period, the interest was deemed abandoned as of March 13, 1992, allowing for the DMA ’89’s three-year grace period.

As for the DMA’06 procedure, the court said:

“[T]his Court finds the if a severed interest holder files a notice under paragraph [division (H)], the landowner’s statutory remedy to abandon a Severed Mineral Interest has been exhausted, requiring the filing of a lawsuit. At that point, the severed interest holder must be required to show why the severed interest has not been abandoned. A preservation notice itself cannot be the basis for establishing that the mineral interest has not been abandoned. The holder must show the existence of one of the savings conditions under ORC §5301.56(B).”

Here, the court ruled, there was no savings event and the severed interest was deemed abandoned.


Any time the legislature tries to declare, generically, the winner and loser of competing claims to property rights — especially where the claims are typically fact intensive and the property is increasingly valuable — controversy is inevitable. We will keep you posted as the law develops.