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Eminent Domain

Posted on: February 3rd, 2022
by David Ganje

SIOUX FALLS, S.D. (KELO) — Landowners continue to gather and plan meetings as Summit Carbon Solutions has applied for a carbon dioxide (CO2) pipeline permit in Iowa.

“In the coming weeks we will be filing our permits in South Dakota and North Dakota,” said Jim Pirolli, the chief commercial officer for Summit. The developer has already applied in Iowa, Pirolli said.

Once the permit is submitted South Dakota that kicks off a process that is roughly a year long, he said.

Projects would harvest CO2 for transport in pipelines across five states

Summit and Navigator have proposed two CO2 pipelines whose routes include South Dakota, parts of Iowa and Minnesota. Pipelines would capture CO2 from ethanol plants, which would reduce the plants’ overall carbon footprint and allow those plants to sell ethanol at a higher price in markets such as California, which has strict carbon guidelines. The project would also allow participants to use tax credits provided in the 45Q, which provides a tax credit for each metric ton of sequestered CO2. The captured CO2 would be buried at site in North Dakota by Summit and in Illinois by Navigator.

As Summit seeks to secure easements from landowners in South Dakota, Iowa and other states, the possible use of eminent domain comes up.

Ed Fischbach, a landowner in Spink County, said eminent domain is a concern because as of now, there is at least some opposition to agreeing to easements for the Summit pipeline in his region and in other states.

Eminent domain is “a right of a government to take private property for public use by virtue of the superior dominion of the sovereign power over all lands within its jurisdiction,” according to Merriam-Webster.

“I can only speak to my neighbors but there has been a lot of opposition,” Fischbach said.

Several counties in Iowa have passed resolutions, or written letters to the state’s public utilities board, in opposition to the use of eminent domain for CO2 pipelines.

Pirolli said Summit is somewhat surprised by the letters and resolutions in opposition to eminent domain because it wants to use easements and the project will benefit farmers, participating ethanol plants and the overall rural economy.

“Iowa is really organized and ahead of us,” Fischbach said of organized opposition to CO2 pipelines and eminent domain.

McPherson County has passed a moratorium on pipelines that would include CO2 pipelines, Fischbach and Bruce Mack, a landowner near Aberdeen, said.

Opponents of the proposed C02 pipelines cite safety concerns, permanent damage to the land on which the pipeline is buried, and the use of eminent domain on a private project in which a private developer will make millions.

Landowners should have questions about eminent domain and even the easements, said Dave Ganje, a lawyer based in Rapid city. Ganje works in natural resources law and commercial law and litigation.

Eminent domain for private developers

“The use of eminent domain for pipelines and private developers has been established by the U.S. Supreme Court,” Ganje said.

Ganje cited a 2005 U.S. Supreme Court case called Kelo vs. City of New London (Connecticut) in which the court ruled that the city could use eminent domain to transfer land from one private owner to another private owner. The use did not violate the 5th Amendment’s taking clause, according to the court. The court cited public use and economic development.

Rep. Charlie Hoffman, a Republican from Eureka, said the South Dakota courts may need to decide if eminent domain would be an appropriate use for CO2 pipelines.

Part of the original pipeline plan would have gone through Hoffman’s property. The route has since been switched but Hoffman said that is why he supports the pipeline. The pipeline will be a benefit to farmers and ethanol plants, Hoffman said.

Although he supports the proposed Summit CO2 project he understands farmers’ fears of eminent domain. In general, farmers don’t want private development on their property, he said.

Using eminent domain for the purpose of a pipeline is not unusual, Ganje said. The U.S. has thousands of miles of pipelines for various materials, he said.

The use of eminent domain can be allowed through statute, regulatory body such as a state agency or county government, Ganje said.

Chris Nelson, the South Dakota Public Utilities Commissioner, said the PUC does not get involved in eminent domain. That is between the landowner and developer and decided in circuit court, he said.

Pirolli said it’s too early to talk of eminent domain because Summit wants to work with landowners to obtain easements.

“We have just begun right of way acquisition in the state of South Dakota,” Pirolli said. “So far, we’ve had a great reception.”

“It’s preliminary to say we would have to go down that path…,” Pirolli said of eminent domain. “…acquiring right of way takes a long time.”

If Summit believed it would have to use eminent domain to get much of the property for the pipeline, it would not have pursued the project, Pirolli said.

Eminent domain and easements as a share of the profit?

If eminent domain is used then what is the obligation of the private developer to the property owners? Ganje asked.

How is the value of that property determined and should the property owner be entitled to more than a “one-off” payment, Ganje said are questions that must be asked. Should property owners share in the profit from the private development? Ganje asked.

Ganje said the same questions need to be asked with an easement.

Fischbach said landowners also need to understand if an easement obligates them completely, even if the project is not developed.

“They may never get that easement back,” Fischbach said.

Ganje said some easements are written to allow for uses other than the intended use if the original project does not happen.

Pirolli said if Summit’s pipeline is not developed, nothing else can happen on that easement.

Summit has a structure it uses to determine a fair easement payment to the landowner, Pirolli said.

The structure is based on the value of the land, crop production and other factors, he said.

Summit will also pay 100% of the crop or pasture damage in the first year which is the year of construction, Pirolli said.

It will pay 80% of the crop or pasture damage in the second year and 60% in the third year, Pirolli said. Many farmers report little or no crop damage loss in the second and third year, he said.

Meetings

When Summit applies for a permit in the state of South Dakota the process includes information meetings, hearings and other requirements.

Summit already had several meetings in 2021 to inform the public about the proposed CO2 pipeline project in South Dakota, Pirolli said.

Fischbach said at least two meetings were held in October during harvest which was inconvenient for farmers. Also, he received a letter about the proposed CO2 project toward the end of July and surveyors arrived shortly after to ask about surveying property, Fischbach said.

“No one had heard anything prior to then (July letter),” Fischbach said.

Pirolli said Summit hasn’t been invited to meetings such as the one planned for 5:30 p.m. Wednesday, Feb. 2, at the 4-H building in the fairgrounds in Redfield.

Mack said they hope to have ethanol and county representatives at the meeting.

He described some meetings as organized by “activists who are not focused on the benefits of the project…” They are instead focused on opposing it, Pirolli said.

Summit is focused on educating the public about how pipelines can safely transport CO2 and how capturing it can improve the rural economy.

Meanwhile, Fischbach said landowners like him will continue to educate the public about the possible dangers of CO2 pipeline transport and discuss how to oppose a private development using federal tax credits to make money and possibly, take their land.

South Dakota – the land of socialized oil and gas production

Posted on: January 29th, 2020
by David Ganje

The truest evidence a state will leave for history is the rule of law under which its people lived at the time. Today some governments have not credibly accepted the need for environmental stewardship as a part of governance. Such a government opposes sober consideration of environmental stewardship and instead promotes economic progress as if the two governing issues must be universally incompatible. The absence of a balanced environmental stewardship by the state is the evidence I submit in this opinion piece. The actual policies and positions of the state on natural resource management is the material evidence upon which the future will judge South Dakota. I will here discuss current experiences as well as ‘new’ proposed bills before the 2020 legislature. These things will look weak and ill-considered by those reviewing the state’s history in 50 or 100 years.

In 2015, 2016, 2017 and 2018 I wrote several different analysis, in editorials and opinion pieces, advocating for financial assurance from permit applicants in order to satisfy the need for clean-up and plugging of closed projects. The point of my diverse written recommendations applied to mining operations, wind farms, oil and gas exploratory and operating permits as well as other natural resource operations requiring government authorization. My arguments were presented in numerous opinion pieces over those years. The pieces were published in various papers and websites throughout South Dakota, and importantly were not found in so-called advocacy or biased publications. The purpose of the pieces was to warn as well as advise government agencies and the legislature of the significance of proper planning and vigilant oversite for licensed and permitted projects. Some call this planning and oversight stewardship. I wrote about abandoned projects, abandoned wells, orphaned wells, projects in bankruptcy and projects underfunded and at risk. In a 2017 piece I discussed examples of businesses shutting down and not cleaning up after themselves. South Dakota like most states requires financial assurance terms for oil well permits, for mining operations, for sand and gravel permits, for wind farms. In my pieces I also reviewed specific regional examples of permits which imposed inadequate financial requirements for the decommissioning or closing of permitted projects. To restate my principle argument – decommissioning of a government-permitted project is the most significant long-term aspect to a government’s permitting authority. Little, really nothing, has changed since the publication of the articles. Now, I am not personally offended by those who ignore my advice; this is not unusual in my line of work. But no man is pleased to have his good advice so handsomely neglected as has been the subject and recommendation of my articles. How has the advice been neglected? Let us look at current practices of the state as well as proposed legislation before the South Dakota legislature.

The first example. Spyglass, an out-of-state energy company, abandoned 40 natural-gas wells in Harding County over the last several years. The state belatedly sued the company because of its failure to clean up the abandoned wells. The company denied liability. These abandoned gas wells, some of them leaking, have been around for a long time. I personally viewed one of them in 2014. Why has not the operator cleaned up the mess? The state DENR says that, “The problem all along has been that the company didn’t have the money to do so.” The state apparently did not properly oversee the financial assurance submitted by the company and, according to the Rapid City Journal, the state of South Dakota will be left holding the bag on the costs of closing up the wells. The paper reported, “Someone associated with [Spyglass] later cashed out $20,000 from the bonds without state government’s knowledge, leaving the state with only $10,000 to apply toward the estimated cost of nearly $900,000 to plug the 40 orphaned wells.” The original amount of bond money placed on the wells was inadequate in the first place – and if the monies were mismanaged as suggested – this compounds the state’s problem. A settlement consent agreement was entered into between the state and Spyglass but the agreement did not seem to remedy the situation. In the current session of the legislature a bill is pending to specially fund the DENR with earmarked state monies so that it might, itself, clean up orphaned wells. I have in the past been successful in my dealings and communications with the South Dakota DENR. The DENR has been accessible and willing to discuss public matters as well as my client’s issues in good faith. Yet on the proposed new legislation I recently contacted DENR twice by email indicating I would like to discuss the legislation. They did not favor me with a conversation. Instead the DENR emailed me that ‘the legislation speaks for itself.’ This is not open government.

Here are the takeaways for my first example: 1. inadequate financial assurance amounts were required at the outset, 2. there was an apparent failure to vigilantly oversee the operator’s deposited monies, and 3. we have a financial bailout by the state to plug wells at taxpayer’s expense because of a private company’s botched enterprise.

The second example. I have devised a new law of physics. It applies to government activity only and is otherwise an anomaly within the laws of physics: Every action taken by government is always a reaction- never an initiated action. In the current session the legislature proposes to increase the bond amount to $50,000 per well. This is a discretionary amount, not a mandatory amount. The proposed amount is a figure that the Board of Minerals may impose. Or the Board may impose a higher amount by its own authority. This would be an increase over current law. The proposal is nevertheless discretionary. The new legislation also allows the board to require a supplemental plugging and performance bond in the amount of $20,000 or such a mount as will guarantee the cost of reclamation. Again this is a discretionary bond. The Board “may require, or may delegate.” The solution to orphaned wells is not difficult to understand. When companies get a permit to drill they should pay a mandatory minimum bond that covers the cost of plugging and reclaiming the well. If the company plugs and reclaims the well itself they get their bond money back. If the company does not plug and reclaim the well for whatever reason, as we have seen there are several reasons, the state will have adequate money on hand to do the work. Between 1997 and 2014 it cost the State of Wyoming $11 million in total to plug orphaned wells, and only $3 million was covered by bonds. The number of abandoned wells in North Dakota grew by 10% in 2018 and 2019 over prior years. How did the South Dakota legislature come up with its new bond amounts? Has the state and its experts looked at the state’s experience with the Wasta SD well and the 40 orphaned Spyglass wells? I have seen no public state analysis on these matters. While of course no two projects and no two wells are the same, does good stewardship suggest that the lesser protection for the state is the better? North Dakota State Mineral Resources Director Lynn Helms very recently estimated that an abandoned well costs $150,000 to plug and reclaim.

Here are the takeaways from my second example: 1. an increase in bond amount is good. But the proposed legislation is not a mandatory increased amount. It is discretionary. That’s a cop out. If you want to address the problem you address the problem, 2. the state has still not addressed the proper financial amount for financial assurances by a developer. The Wasta abandoned well case is a South Dakota financial tragedy. I respectfully refer the reader to media articles on the abandoned Wasta well. The official stated remedial costs to the state could be $2 million if the Wasta project were ever to be plugged. That is way more than the bond filed with DENR. Further, the Spyglass problem of 40 orphaned Wells is a recent development. The state proposes to address Spyglass by budgeting about three-quarters of a million dollars’ worth of state funds. State funds are to pay for something a private business should be responsible for from the get-go. Thoughtful rules of the road at the initial stages of any project will help address future problems of possible project abandonment, closure and decommissioning. This would be good stewardship.

David Ganje of Ganje Law Offices practices in the area of natural resources, environmental and commercial law.

Leaky Laws – Oil Spill Liability in New York

Posted on: May 26th, 2016
by David Ganje

Pipelines, even privately owned, are a publically regulated transportation and operating system. The question is not whether pipelines are “essential to our society.”  Pipelines are already integral to the country: the US had over 1,700,000 miles of oil and gas pipelines in 2014. Operating systems will malfunction. The process for legally authorizing operating systems should not. To paraphrase Norman Vincent Peale, the problem with most publically regulated systems is that they would rather be ruined by praise than saved by criticism.

On September 2, 1978 the U.S. Coast Guard discovered evidence of an oil spill entering Newton Creek in Brooklyn. After launching an investigation, the government found over 17 million gallons of petroleum products that had leaked over a period of decades beneath the Greenpoint area, contaminating more than 50 acres of land. Today, new studies put the spill volume up to 30 million gallons. Cleanup began in 1979, but by 2006 only 9 million gallons had been cleaned up – less than a third of the known spill size. Cleanup continues today, with the aid of the federal government. The spill was designated a Superfund site. No one knows how long the leak existed before it was discovered
The relevant question should be how regulated pipeline leaks will be cleaned up, and who will pay for them. Under both Federal and state laws, the party responsible for a leak is the one responsible for cleanup. Usually the operator responsible prefers to take care of the cleanup themselves. Not only does this help soothe public relations problems resulting from a leak, but it helps the operator control the costs. However, a pipeline operator causing a spill may not always be willing or able to clean up a spill. The liable operator could be bankrupt, dissolved, or simply not have the money. The operator responsible for the Greenpoint spill was still in business and capable of footing the bill for their mistakes. This will not always be the case. Not all spills are flashy and obvious. Cleanup should not wait for years of court cases or bureaucratic lethargy. The money for a cleanup must be there, ready to be used.

New York has the NY Environmental Protection and Spill Compensation Fund (“Spill Fund”), established in 1977 to protect the state against petroleum spills. The fund is financed with a tax on petroleum products moving through the state, and any disbursements from the fund to pay for spill remediation is ideally recovered through penalties assigned to the responsible party. Third parties who are damaged by the spill can also file a claim with the Spill Fund and get their damages paid through the Fund, allowing the Fund to add those damages to the remediation it seeks from the responsible party.

This kind of fund is a good start. However, the fund is simply not large enough to handle the kind of oil spills that are possible in this era of pipelines and oil trains. For the 2014-2015 fiscal year, the Spill Fund spent over five million dollars more than it collected, bringing the fund’s total down to twenty-two million dollars. The fund spent thirty-two million that year. The 2015 state budget raised the cap on the Spill Fund from $25 million to $40 million. But even $40 million is not enough to handle the large spills when a company is not around to pay – in fact, $40 million is not even what the fund would be at if the cap had kept pace with inflation.

This is not to say that New York would be alone in a crisis. Both the Coast Guard and the EPA have trust funds in place to help states and the federal government. The Coast Guard’s fund only applies to spills into navigable waters, and cannot apply to cleaning up spills on land. But it would be there to help if the real disaster happened: a lengthy, voluminous spill into one of the many bodies of water in New York State, like the 2013 Enbridge spill in Michigan that cost more than a billion dollars to clean up. EPA maintains their Leaking Underground Storage Tank Fund for spills on land, but that fund is financed with a tax on motor fuel – a tax paid by private citizens, not the companies causing the damages in the first place.

Petroleum spills are not going away. The New York State Spill Hotline receives approximately 16,000 reports of spills each year, and the NY Dept. of Environmental Conservation estimates that approximately 90% of those reports involve petroleum products. Financial assurances for spills must be required before the damage happens, in amounts sufficient to cover the thousands of spills that happen every year. The legislature needs to create a modern statute addressing financial assurances by the operators for pipeline leaks.

Does ‘All’s Well That Ends Well’ Apply To An Oil And Gas Lease?

Posted on: February 19th, 2016
by David Ganje

In oil and gas leases, a shut-in royalty provision is essential to protect the interests of lessors and Operators alike. An Operator is the business responsible for the drilling, completion, and production operations of a well and the physical maintenance of the leased property. Oil and gas lessors like shut-in provisions because they provide that some money continues without the act of suing the Operator to start producing again or get out. Operators like shut-in provisions because they provide a path to maintaining the lease when “the market” makes production ill-advised.

As important as these provisions are for the parties, there are difficulties drafting these terms into an oil and gas lease. For an unprepared lessor, an inadequate shut-in provision allows a non-producing well to sit on his land, shut-in, for years while providing little or nothing to the lessor. For an unprepared Operator, an inadequate shut-in provision forces a lose/lose decision between bad money paid out during new production or losing both the lease and the well that took big bucks to negotiate and complete. For example, what is a fair shut-in period? 3 years? 1 year? Even leases with adequate shut-in provisions have problems in legal interpretation, and in such cases the state code should stand ready with answers. States have woefully inadequate road maps to cover these situations.

New York law requires that production continue with some consistency beyond the primary leasing term. Still, there are some important unknowns that the legislature and the courts have yet to make clear. New York courts have held that “If…there is no production and it is reasonable from the facts to determine that production has finally ceased, then the lessor may recover possession of his lands free of the lease.” But, “temporary cessation of production does not terminate the lease.” What exactly is a final ceasing of production? How long can production cease before it is no longer ‘temporarily’ so? Mechanical issues with wells can last for years, especially if not properly managed – and economic issues can make production untenable for even longer. Complicating this issue, New York courts have implied that these rules only apply when the Operators are not prevented from production by forces outside of their control (which can include market conditions). So how long can lessors be stuck with a non-producing well on their land that the Operators claim has only ‘temporarily’ ceased production because of outside forces? Answer: it is presently unclear.

Where there is no good statutory roadmap, it is vital for all parties to protect their interests with proper shut-in provisions when agreeing to an oil and gas lease. New York must fix their sparse guidance on oil and gas leases that extend past the primary leasing term. Vague statutes that force disagreeing parties into court in order to fill in the legislature’s gaps are not the answer. Astute lessors and Operators can protect their interests by writing a thorough shut-in provision. These matters are too important to be left to hand-me-down, boilerplate lease language.

David Ganje. David Ganje of Ganje Law Offices practices in the area of natural resources, environmental and commercial law in New York. The website is Lexenergy.net

Minneapolis Star Tribune – N.D. oil sinks to $20 per barrel

Posted on: January 16th, 2016
by David Ganje

N.D. oil sinks to $20 per barrel with more bankruptcies expected as drilling activity declines - Photo by JIM GEHRZ

N.D. oil sinks to $20 per barrel with more bankruptcies expected as drilling activity declines

More bankruptcies are expected as drilling declines due to low prices.
By David Shaffer Star Tribune

Oil industry experts have been making dire predictions of $20 per barrel oil. In North Dakota, they’re now reality, prompting warnings of more bankruptcies and less drilling in 2016.

Although the U.S. domestic crude oil benchmark is higher — $29.64 per barrel — Bakken producers must sell at a discount because of the region’s limited oil pipelines and the higher cost of alternate shipping methods.

On Friday, North Dakota light sweet crude dropped to $20 per barrel at the wellhead, the lowest price since 2002, the state Department of Mineral Resources said. That’s one-fifth of what North Dakota producers got in early 2012, when the Bakken oil boom was at its peak.

Now, just 49 drilling rigs are operating in the state, less than a quarter of the number at the peak.

The department’s director, Lynn Helms, said the state’s oil industry is “running on empty” and quoted a verse from Jackson Browne’s song of that name during his monthly “Director’s Cut” conference call.

“We are down in the bottom of the bottom of the tank in terms of cash flow and capital,” Helms said of the state’s oil producers, two of which are in bankruptcy.
Helms said he expects another company to file bankruptcy shortly, and four or five more failures could be down the road. He didn’t name the companies.

“We have looked at … production, wells and situations and tentatively think there are four or five more [companies] at these oil prices that are going to run to the end of their financial rope by the end of 2016,” said Helms.

Seven of the 10 largest North Dakota oil producers reported losses in the third quarter, including the top three, Whiting Petroleum, Continental Resources and Hess Corp.

Two smaller producers, Samson Resources of Tulsa, Okla., and American Eagle Energy, filed for bankruptcy reorganization last year.

Despite the grim outlook, North Dakota reported a 0.4 percent increase in oil production for November, to nearly 1.18 million barrels per day. Natural gas production also rose slightly. The state’s peak oil production was more than 1.2 million barrels per day in December 2014.

But Helms said that at current crude oil prices, the number of drilling rigs could drop to 30 in 2016.

At that rate, North Dakota would barely stay above 1 million barrels per day at the end of 2016, and eventually would fall below that level, he added.

Oil prices also are affecting how much crude is shipped on oil trains, many of which pass through Minnesota on their way to East Coast refineries. About 41 percent of the state’s oil moved on trains in November, down from 47 percent in October, said Justin Kringstad, director of the North Dakota Pipeline Authority, which tracks crude oil shipping.

Most of North Dakota oil now is being shipped to market via pipelines, a reversal of earlier trends that favored rail. The economics of oil trains hinge partly on the price of oil on U.S. coasts being several dollars higher than the midcontinent price. Thanks to that price difference, refiners have been willing to pay the extra cost of shipping Bakken oil by rail.

But Kringstad said the differential “has essentially been eliminated,” a change driven partly by the revival of U.S. oil exports. “We expect that differential to be negligible for the near term,” he said, making the economics of crude-by-rail more challenging.

Helms said one of the state’s largest producers believes oil prices will recover later in 2016, a reference to recent comments by Harold Hamm, chief executive of Continental Resources. Hamm told the Wall Street Journal this week that he expects crude oil to double in price by the end of the year because supplies won’t keep up with demand.

If the gloomier outlook holds true, and more North Dakota producers file for bankruptcy, it could affect royalty recipients and vendors beyond the state’s borders, said David Ganje, a Rapid City, S.D., attorney who practices natural resources law in North Dakota and South Dakota.

“It is a very diverse industry and 48 percent of the royalty owners live out of state,” added Ganje, who said he has represented royalty recipients in Minnesota, Wisconsin and other states.

Although royalty holders have legal protections, he said, bankruptcy cases can slow down payments on oil and gas leases. Often, the oil producer in bankruptcy tries to retain the leases, reorganize and keep operating, he added. Sometimes the leases are sold, which can benefit royalty recipients if the new owner is better capitalized, he said.