Full Case Write-ups

The rule for intangible drilling costs, IDC for short, says you deduct them in the year you pay or incur them. A 1973 drilling partnership tested how far “pay” goes.

The deal

Stephen Keller put $50,000 into a limited drilling partnership that year, through Amarex, Inc.¹. In 1973 the partnership prepaid drilling costs and deducted them as that year’s intangible drilling costs². Keller reported a $50,000 share of the partnership’s 1973 loss, as much as he’d put in^1,3.

Some of the money went out under turnkey contracts, which set a fixed price for the drilling^2,4. The rest went out under other deals, including contracts that pay the driller by the foot or by the day².

Here’s the decision point. The partnership had paid in advance. Did paying early make it a 1973 deduction?

What happened

The Commissioner of Internal Revenue cut Keller’s share of the loss from $50,000 to $21,595 and sent him a deficiency notice, a bill for more tax, of $14,202³.

The Tax Court split the case. The turnkey prepayments couldn’t be refunded and served a real business purpose, so they were deductible in 1973². They locked in a price, so the partnership “effectively got its bargained for benefit in the year of payment,” as the Tax Court found². The other prepayments were not deductible in 1973².

Outcome, as of February 1, 1984: the Eighth Circuit, a federal court of appeals, affirmed the Tax Court’s split ruling in full⁵.

The rule as of 2026

The timing question now has its own rule in the tax code. For a tax shelter, a drilling payment is treated as performed in the year it’s paid if drilling starts within 90 days after year-end⁶. A tax shelter here includes a partnership that had to register the offering of its interests with a federal or state securities regulator⁷. Without that rule, the cost is deducted as the driller does the work⁸. The Caltex Oil Venture case on this page follows a December 1999 prepayment of $5,172,666, most of it on a note, that missed the 90-day window⁹.

This is the first of the two Supreme Court cases the book’s Chapter 4 uses to show who gets depletion. Kirby Petroleum, also on this page, is the second.

A check and no oil

In 1926, a ranching partnership near Amarillo, Texas, collected a bonus of $683,793.75 for oil and gas leases on its land¹. No oil well stood within 3.5 miles¹. The partners had a check and no oil.

Could they take depletion, a deduction for oil used up, before anyone found any? They each claimed a share of a $188,043.28 depletion allowance, 27.5 percent of the bonus¹.

Three losses, then the Supreme Court

The Commissioner disallowed it. The Board of Tax Appeals, the Tax Court of its day, sided with him, and the federal court of appeals affirmed¹. Three rulings, three losses.

The taxpayers took the case to the Supreme Court as Herring v. Commissioner². The government’s position was that no well meant no depletion³. The Court disagreed. It called a bonus “payment in advance for oil and gas to be extracted,” which made it income from the property, eligible for depletion³.

Outcome, as of December 3, 1934: the Supreme Court reversed the rulings against the taxpayers².

Twelve years after Herring, the Supreme Court took the next step. In Kirby Petroleum Co. v. Commissioner, the lessors collected bonuses, royalties and net profits payments, a cut of the profits from the lease¹. The Commissioner agreed that the bonuses and royalties earned depletion, at 27.5 percent then, but fought the net profits payments¹.

The Court’s answer

The Court said the label doesn’t decide it. “Only a taxpayer with an economic interest in the asset, here the oil, is entitled to the depletion,” it wrote¹. The net profits payments came from that same economic interest, so they earned depletion too¹.

Outcome, as of January 28, 1946: the Court extended percentage depletion to the net profits payments¹.

Where the test comes from

The economic-interest test traces to Palmer v. Bender, decided January 9, 1933². Depletion goes to whoever “acquired, by investment, any interest in the oil in place” and looks to its extraction to get that money back². A bare contract right to be paid, with no investment in the minerals, gets none³.

The at-risk rules, Gate 2 in the book’s Chapter 5, name oil and gas outright¹. You’re at risk for the cash and property you put in, plus borrowed money you’re personally on the hook to repay². Money protected by a nonrecourse note, a guarantee or a stop-loss deal doesn’t count³.

The pattern the IRS describes

The IRS’s oil and gas audit guide, the manual its examiners work from, has a name for a deal paid for mostly with notes instead of cash: a “leveraged oil and gas drilling partnership”^4,5. As of its February 2023 revision, the guide calls one abusive when it’s formed with promissory notes to inflate the partners’ interests and produce deductions bigger than their real economic loss⁴. It treats these deals as open to penalties for negligence and for misstating values, and it tells examiners to check whether new investors’ money was paying earlier ones⁶.

The case the government brought

On November 29, 2007, the Justice Department filed for a permanent injunction in federal court in Ohio against Daniel Weddington and James Earl^7,8. The two each owned half of Mid-Con Petroleum, the company drilling the wells⁸. Since at least 2001, the complaint said, they had sold joint-venture interests marketed as fully deductible drilling costs⁹.

The complaint said investors paid for most of the price with demand notes they weren’t personally liable on¹⁰. It called the notes shams, there only to inflate the deduction¹⁰. For one venture, it said, the actual drilling cost was $152,447.85, while the investment in drilling cost the investors claimed was $1,108,000, more than seven times as much¹¹.

The amended complaint, filed April 24, 2008, went further. It alleged the notes were “paid off” with made-up earnings from wells that didn’t exist¹². It alleged that Mid-Con took in about $70,000 a month from its actual wells while sending statements showing more than $500,000 a month used to pay off the notes¹².

How it came out

Outcome, as of November 7, 2008: the court entered a permanent injunction against a third defendant, one he agreed to, barring him from organizing, promoting or selling the Mid-Con drilling programs or any program substantially like them¹³. The order states that agreeing to it isn’t an admission of the government’s allegations, and by its own terms it was to end ten years after entry¹³.

The court records cited on this page don’t show how the claims against Weddington and Earl ended. The rest of this account is what the government alleged. Sham notes like the ones alleged are the gap the at-risk rules are built for: dollars you can’t actually lose don’t count as at risk³.

This story comes from the Tax Court’s opinion and from a case summary by the Center for Agricultural Law and Taxation at Iowa State University.

The December payment

A partnership called Caltex Oil Venture paid $5,172,666, in cash and a note, in December 1999 under a turnkey contract to drill two wells¹. The cash was checks totaling $428,185.50, and most of the price was on the note². Caltex claimed the full $5,172,666 as intangible drilling costs on its 1999 return¹.

Stop at the decision point. The money went out in December. The Tax Court’s opinion says a full 1999 deduction required drilling to start within 90 days after the close of 1999, by March 30, 2000³. That window is the tax code’s special 90-day rule^2,4. The opinion also describes a second, separate rule, measured 3.5 months from the date of payment, which would have allowed only part of the deduction³.

No bit in the ground

The parties agreed that no drill went into the ground during 1999 or 2000². In November 2007 the IRS disallowed the full $5,172,666¹. The Tax Court decided the case on January 12, 2012^2,5. It sided with the IRS, holding that drilling starts only when the bit actually goes into the ground¹. It also held that the 3.5-month rule doesn’t count drilling not yet done as performed in the year of payment¹.

Outcome, as of January 12, 2012: on partial summary judgment, the partnership lost its bid to deduct the $5,172,666 in 1999 under either timing rule^1,2. The ruling left open whether a small amount, at most $7,072.80 by the IRS’s figure, could still come off under the general rule¹.

The lesson is about the calendar. Ask when the bit goes in, not when the wire goes out.

The contract matters too

In another case, Keller, the Tax Court let a drilling partnership deduct prepaid turnkey drilling costs in the year it paid⁶. Those payments were non-refundable and served a real business purpose⁶. Other kinds of prepayment lost, and a federal appeals court affirmed the split in 1984^6,7. The full Keller story is on this page.

The rule

Self-employment tax falls on income from a business you carry on, including your share of a partnership’s business income¹. A limited partner’s share is left out, except guaranteed payments, meaning pay for services the partner actually does for the partnership^2,3.

The statute’s exclusion names limited partners, not LLC members². That leaves the LLC member in a gray area. The statute doesn’t define “limited partner”⁴.

A rule Treasury never finished

In January 1997 Treasury proposed treating LLC members and limited partners alike. An owner would count as a limited partner unless the person had personal liability for the entity’s debts, authority to contract for the entity or more than 500 hours in the business during the year⁵. In August 1997 Congress barred any temporary or final rule defining a limited partner before July 1, 1998⁶. In 2023 the Tax Court noted that Treasury still hadn’t issued one⁴.

As of October 2026 the statute and its regulations are unchanged, and the Treasury and IRS guidance plan for 2026 to 2027, released September 29, 2026, has no project to define “limited partner” for this exclusion⁷.

What the courts have said

The Tax Court has denied the exclusion to professional LLC members, in a 2017 case called Castigliola⁸.

On January 16, 2026, in Sirius Solutions, the Fifth Circuit defined a limited partner as a partner in a limited partnership with limited liability⁹. It said it wasn’t deciding whether LLC members qualify¹⁰. That opinion no longer stands. On August 12, 2026 the Fifth Circuit withdrew it and put a new opinion in its place, K Alain, L.L.L.P. v. Commissioner, which holds that a limited partner, for this exclusion, is a partner who plays no significant role in managing or running the business¹¹.

On September 17, 2026 the Second Circuit, in Soroban Capital Partners, held that a limited partner is one who has limited liability and does not run, manage or otherwise exert control over the partnership¹². It affirmed the Tax Court and said it does not disagree with K Alain¹².

Neither appeals court decided whether LLC members qualify^11,12. So as of October 2026, for an LLC member who works in the business, the exclusion is an open question. If you’d hold through an LLC and work in the business, ask your CPA whether the exclusion reaches you before you sign.

Where it stands, as of October 2026

• The statute names limited partners rather than LLC members and doesn’t define “limited partner”^2,4.
• Treasury proposed a rule in 1997 and hasn’t issued one; its 2026 to 2027 guidance plan has no project on it^4,5,7.
• The Tax Court has denied the exclusion to professional LLC members⁸.
• Two federal appeals courts tied the exclusion in 2026 to whether the partner runs or manages the business, and neither decided whether LLC members qualify^11,12.
• Takeaway: for an LLC member who works in the business, the exclusion is an open question.

Kate J. Crichton was the taxpayer in a case decided in 1940 by the Board of Tax Appeals, which heard taxpayers’ disputes with the IRS in those years¹. She traded oil, gas and mineral rights for an undivided half interest in improved real estate, meaning land with improvements on it¹. As of 2026, the tax code lets you trade real property for real property of like kind without being taxed on the gain at the time².

The question

Here was the question. On one side sat rights to whatever lay underground. On the other sat improved real estate. Were those the same kind of property, or too different to swap tax-free¹?

Stop there. It’s the question behind any oil and gas interest you might someday trade. Which way would you have bet?

The ruling

The Board of Tax Appeals held that the swap was like kind, and on August 9, 1941, the Fifth Circuit, a federal appeals court, affirmed^1,3. The like-kind test sorts property into broad classes, real and personal, the court held³. It doesn’t split parcels of real estate by location or use³.

Outcome, as of 1968: the swap stood, and the IRS wrote the rule into Revenue Ruling 68-331^1,4. That ruling held that a lessee’s interest in a producing oil lease, running until the deposit is used up, traded for a fee interest in an improved ranch, meaning outright ownership of the land, qualified too, to the extent of the ranch land and its permanent improvements⁴. It also said the IRS treats a lessee’s interest in a producing oil lease as real property⁵.

Where the line falls

The same ruling drew a line on the other side. A production payment is a cost-free share of production that ends once a stated dollar amount is paid out⁶. It doesn’t swap like kind for a perpetual overriding royalty on the same lease, a royalty carved out of the lease rather than the minerals^7,8. The payment was a limited interest; the royalty would run as long as oil or gas came out⁷. The ruling took that line from a 1939 Board of Tax Appeals case, Midfield Oil Co.⁷.

The lasting interest won. The time-limited one lost.

Why it matters for state tax

The book’s Chapter 6 opens its state-tax half with this case. Real property gets taxed where it sits, and Texas and Oklahoma both tax oil and gas that way^9,10.

In 2005 a used-car lot in Harrisonville, Missouri, paid its general manager $9,754¹. The general manager was Terry Ellis, and his own self-directed IRA owned 98 percent of the company that ran the lot¹. That paycheck put the entire account on the line.

The rule

Section 4975 of the tax code bars certain deals between an IRA and a “disqualified person.” The barred deals include selling, swapping or leasing property and lending money or extending credit. Furnishing goods or services is barred too². Disqualified persons include fiduciaries and people who provide services to the account, along with members of their families³. Family here means a spouse, ancestors, lineal descendants and their spouses, not brothers and sisters⁴.

If the owner does one of those deals, the whole account stops being an IRA as of January 1 of that year, not just the dollars involved⁵. The tax code does have a penalty tax for prohibited transactions: 15 percent of the amount involved, rising to 100 percent if the deal isn’t fixed⁶. That penalty doesn’t apply to the account’s owner, because losing the IRA applies instead⁷.

The used-car lot

On May 25, 2005, an attorney for Terry Ellis formed CST Investments, LLC to run a used-car business¹. Ellis’s self-directed IRA put in $319,500 for 98 percent of the company. An unrelated employee paid $20 for the other 2 percent¹.

So far, so legal. The IRA’s purchase of the brand-new company wasn’t itself a prohibited transaction, because the company had no members yet⁸.

Now stop at the decision point. The IRA owns the lot. The lot needs a general manager. The man who owns the IRA is standing right there.

Ellis took the job, and CST paid him $9,754 in 2005 and $29,263 in 2006¹. The IRS treated the salary as a prohibited transaction that ended the account’s tax-exempt status¹. It counted the account’s full value at the end of 2005, $321,253, as the amount at stake¹. Its notice, dated March 28, 2011, claimed $135,936 of additional 2005 tax, plus a $27,187 penalty¹.

Ellis went to court, and the Tax Court found he had used his retirement savings as the startup capital for a business he ran¹.

Outcome, as of June 2015: the Eighth Circuit affirmed the Tax Court on the salary, in a decision filed June 5, 2015¹.

Lawrence Peek and Darrell Fleck had self-directed IRAs. In September 2001 their IRAs each paid $309,000 for half of a new company, FP Company¹. FP Company then bought most of the assets of Abbott Fire & Safety for $1,100,000¹. Part of the price was a $200,000 note to the sellers, backed by the two men’s personal guaranties¹. Mortgages on their homes were tied to the deal as well^2,3.

The rule is the one behind the Ellis case, also on this page. Section 4975 of the tax code bars certain deals between an IRA and a disqualified person⁴. If the owner does one, the whole account stops being an IRA as of January 1 of that year⁵.

In December 2010 the IRS mailed the two men notices of deficiency for 2006 and 2007. It said the guaranties and mortgages were prohibited transactions that left capital gains unreported². In 2013 the Tax Court held that the transactions were prohibited, and that accuracy-related penalties applied³.

The men appealed. On December 18, 2014, the Tenth Circuit dismissed the appeal for lack of jurisdiction. They had challenged only some of the Tax Court’s factual findings, not its decisions on the tax owed².

Outcome, as of December 2014: the Tenth Circuit dismissed their appeal, and the Tax Court’s rulings stood².

The book’s Chapter 10 covers royalties and the deductions that can come out of them. Two fights over deductions show what owners can get back, and what it takes.

Naylor Farms and Chaparral

On June 7, 2011, Naylor Farms, Inc., joined by Harrel’s, L.L.C., sued Chaparral Energy in federal court in Oklahoma¹. They alleged it improperly deducted post-production costs from royalties on Oklahoma wells it operated¹. Chaparral operated about 2,500 wells in the state, and the two owners held royalty interests in some of them¹.

Chaparral then went into Chapter 11 bankruptcy, the kind that lets a company reorganize². In August 2016 the owners’ proof of claim, their formal bill to the estate, put damages above $150 million, amended in 2017 to above $90 million².

In January 2017 the district court certified a narrower class than the owners first sought, covering less than 60 percent of the leases they had asked to include³. On May 3, 2019, the Tenth Circuit affirmed the district court’s order letting the owners sue as one class⁴. That ruling was about who could sue together, not about the deductions themselves⁴.

Then the case ran into the balance sheet. By August 2020 Chaparral was in Chapter 11 bankruptcy a second time⁵. On August 15, 2020, the two sides signed a settlement covering the whole nine-year case². It gave the class $2,500,000 in cash plus a $45,000,000 allowed claim in the earlier bankruptcy, to be paid with 1,432,300 shares of Chaparral stock². Chaparral also agreed to pay $850,000 to the class’s lawyers and $150,000 to the class representative². All of it was subject to court approval².

Outcome, as of August 2020: settled, pending court approval². I found no filing that shows the court’s approval or what the class was paid.

Pennsylvania and Chesapeake

A disclosure before the second fight: Chesapeake is a former employer of mine. What follows comes only from the public record.

On December 9, 2015, Pennsylvania’s Attorney General sued Chesapeake in the Bradford County Court of Common Pleas⁶. The suit alleged deceptive royalty underpayment through improper post-production deductions and affiliate arrangements, and it also challenged how Chesapeake acquired leases⁶.

Private class cases ran alongside. Chesapeake reached tentative settlements of them on December 20, 2017 and August 9, 2018, for about $36 million in all, its annual report said⁷. On June 28, 2020, Chesapeake filed for Chapter 11 bankruptcy⁸. Its plan, confirmed in January 2021, rejected those pending class settlements, so they never took effect^7,9. Chesapeake came out of bankruptcy on February 9, 2021⁹.

In March 2021, the Pennsylvania Attorney General’s office announced that Chesapeake would pay $5.3 million for the office to distribute to landowners who leased to it¹⁰. The office put that at about $700 or $367 a landowner, depending on the lease¹⁰. Under the same deal, Chesapeake would pay $350,000 toward the office’s costs¹⁰. The office said Chesapeake also agreed to stop using “market enhancement” and “ready for sale or use” clauses in new Pennsylvania leases¹¹. Those clauses, the office said, let it deduct a share of costs incurred after the gas was marketable¹¹.

A month after it came out of bankruptcy, Chesapeake agreed to new class settlements of $5 million and $1.25 million¹². The Fifth Circuit said those two and the Attorney General’s deal together purportedly resolved the claims of about 23,000 Pennsylvania landowners¹². On June 8, 2023, it vacated the judgments approving the two class settlements, for lack of jurisdiction¹³.

Outcome, as of June 2023: the Attorney General’s office had announced its settlement, and the private class deals had been undone in bankruptcy and on appeal^9,10,13.

A disclosure: Chesapeake is a former employer of mine. What follows comes only from the public record.

XOG Operating held four oil and gas leases covering about 1,625.80 acres in three sections of Wheeler County, Texas¹. It farmed them out to Chesapeake by a term assignment, a handover of the leases for a set term¹. In a farmout, a lease holder lets another company earn part of the lease by paying to drill². The Texas Supreme Court later called a term assignment a “very common form of agreement”¹.

The deal ran on a 2-year primary term, its fixed opening period¹. After that, its retained-acreage clause let Chesapeake keep the proration unit of each well it drilled, and the rest was to go back to XOG¹. A proration unit is the acreage the state’s field rules tie to a well. Where no field rules applied, the clause said each unit “shall be deemed to be 320 acres of land”¹.

That clause was XOG’s decision point, and it came at signing. XOG signed expecting most of the acreage back¹. Chesapeake drilled 6 wells and kept all of it¹.

XOG sued, arguing that Chesapeake’s own state filings covered only about 800 acres, so about 822 should come back¹. Chesapeake counted 320 acres for each of its 6 wells, 1,920 acres in all, more than the whole assignment¹. Five of those wells were in the Allison-Britt Field, under its field rules. The sixth was in the Stiles Ranch Field, where Chesapeake counted the clause’s 320 deemed acres¹. The trial court ruled that XOG take nothing, and in 2015 a divided court of appeals agreed¹.

On April 13, 2018, the Texas Supreme Court affirmed¹. It read “proration unit” as the size the field rules set: 320 acres for each of the 5 wells under field rules, and 320 deemed acres for the sixth, where none applied¹.

Outcome, as of April 2018: 0 acres went back to XOG¹.

My read: careful farmors work out at signing how many acres each well will keep under the field rules, not after the wells are drilled¹.

The book’s Chapter 15 is about owning a non-operated share of wells: someone else runs the wells, and your money shares in what they make. This case is the other side. Same pitch, very different paper.

The Heartland Group Ventures and its affiliates raised about $122 million from more than 700 investors through five unregistered securities offerings, the SEC says¹. The money was purportedly to work over existing Texas wells and drill new ones¹. The pitch was the non-op promise in its plainest form.

Put yourself at the table with that pitch. You’d have the sellers’ word on what the wells produced. Would you hold it up against anything else?

What the SEC alleged

According to the SEC, the word was the problem. It alleges that one group of defendants, Manjit “Roger” Sahota and two companies tied to him, ArcoOil and Barron Petroleum, made material misrepresentations about the wells’ existing and potential production¹. It says only about 1 of every 2 dollars raised went into oil and gas projects, and those projects brought in less than $500,000¹. Beginning in at least 2019, the SEC says, more than $26 million went out as Ponzi-style payments to debt fund investors¹. It says more than $54 million of Heartland investors’ money went to Sahota, ArcoOil, Barron Petroleum and Dallas Resources Inc.¹.

The SEC filed its civil fraud complaint under seal in federal court in the Northern District of Texas on December 1, 2021, and it was unsealed a week later². On December 2 the court issued a temporary restraining order, froze assets and appointed a receiver, a court-appointed manager for what was left¹.

How the case ended

The SEC’s claims were allegations in a civil case, and they ended in agreed judgments, not trials. Between September 24, 2024 and July 25, 2025, the court entered final judgments against all 15 defendants the SEC named, ten entities and five individuals^3,4. Each was entered by consent, without the defendant admitting or denying the allegations^{5,6,7,8,9,10,11,12}.

The judgment against Sahota, entered July 25, 2025, made him jointly liable with his entities for $46,884,439 in disgorgement and interest, less the $13,633,662 the receiver had already collected, plus a separate $236,451 penalty^5,12. Disgorgement means gains paid back. The judgment ordered $33,487,228 paid to the receiver⁵.

What came back

As of the receiver’s July 2024 report, 734 investor claims had been allowed, totaling $98,790,420¹³. Distributions began in September 2024. By December 2024, the investor class the receiver calls Class 4a had been paid $8.2 million in three rounds¹⁴.

In the July 2026 report, the receiver doesn’t expect the ultimate recovery to return investors’ full principal and pay all other creditors in full¹⁵. As of that report, the only payment on the final judgments was $5,000 from one defendant, against a $25,000 penalty^10,16.

Outcome, as of the receiver’s July 2026 report: the receiver doesn’t expect to return investors’ full principal¹⁵, and $5,000 had been paid on the final judgments¹⁶.

The book’s Chapter 18 comes back to this case as a workover pitch.

A DrillCo is a deal where a money partner pays most of the cost of a batch of wells. In return it gets a big working interest that shrinks automatically once it earns an agreed return. EP Energy’s DrillCo shows what can happen to that stake when the operator goes through bankruptcy.

The deal

On January 26, 2017, EP Energy announced a deal to drill up to 150 wells, in two tranches of 75, on its Wolfcamp acreage in the Permian with outside money^1,2. The money came from Wolfcamp Drillco Operating L.P., an investment vehicle managed by affiliates of Apollo Global Management^1,3. It agreed to fund about $450 million, 60 percent of the cost to drill, complete and equip each well, for a 50 percent working interest^1,2,3. Once it earned a 12 percent return on its money in each tranche, its share would drop to 15 percent³. EP Energy said it would keep operational control⁴.

Both sides of the table

The funder was managed and owned by affiliates of Apollo Global Management^3,5. In 2017, those affiliates also owned about 45 percent of EP Energy’s stock and had seats on its board^3,5. EP Energy said the deal was approved by its disinterested directors⁵. EP Energy’s report for 2019 showed two Apollo-appointed directors on its board also sitting on the DrillCo entity’s board⁶. The filings I cite don’t accuse anyone of anything. They do show both sides of the table reporting to the same place.

The bankruptcy

The funder had finished paying before the bankruptcy⁷. EP Energy had drilled and completed all wells under the amended agreement by the second quarter of 2019⁷. EP recovered about $138 million of capital costs from the funder in 2018 and $91 million in 2019⁷. Then EP Energy filed for Chapter 11 bankruptcy on October 3, 2019⁸.

The case took EP’s proved undeveloped reserves to zero at year-end 2019⁹. Those are reserves counted as proved that still need new wells, or major work on old ones, to produce¹⁰. The company booked a revision of 72.9 million barrels of oil equivalent, a unit that counts gas and oil together, and tied it to the bankruptcy, not to geology or price⁹.

What the plan would have done with the DrillCo stake

In November 2019, EP Energy filed its disclosure statement, the court filing that explains a bankruptcy plan to creditors¹¹. It gave the company an option on the DrillCo itself¹¹. The company could have funds managed by affiliates of Apollo and of Access Industries, another holder named in the filing, hand their DrillCo equity to the reorganized company for new shares^11,12. Holders of unsecured claims, owed money with nothing pledged behind it, were slated to share 1.0 percent of the new stock pro rata¹³. That group included unsecured noteholders and general unsecured creditors¹³.

The court confirmed that plan on March 12, 2020¹⁴. Six days later, EP Energy and the noteholders backing it, investors who held its bonds, chose not to carry it out¹⁴. They mutually ended their agreements to support the plan and backstop its funding, and Apollo and Access were among them¹⁴. On April 24, 2020, still in Chapter 11 bankruptcy, EP Energy filed to deregister its stock and stop its SEC reports¹⁵. So the public record I used ends before the answer. I couldn’t confirm what Apollo and Access finally got for their DrillCo stake.

Outcome, as of April 2020: the confirmed plan had been dropped and EP Energy had stopped its SEC reports, so its filings don’t show what the DrillCo stake became^14,15.

As of Evolution Petroleum’s report for the year ended June 30, 2025, Denbury operated the Delhi Field CO2 flood as a subsidiary of ExxonMobil¹. Evolution Petroleum, a public company, owns a piece of Delhi that it doesn’t run¹.

The book’s Chapter 19 tells Denbury’s story right after Legacy Reserves’, another company that ran floods. Legacy filed for Chapter 11 bankruptcy on June 18, 2019, and its plan, effective December 11, 2019, wiped out its old shareholders with no recovery².

A year later, the same door opened for Denbury. On July 30, 2020, in the year of the oil-price collapse, it filed a prepackaged Chapter 11 bankruptcy in federal court in Texas, one its main creditors had agreed to before the filing³. Denbury came out on September 18, 2020, about seven weeks later³.

The plan turned about $2.1 billion of bonds into equity and warrants, rights to buy shares later³. Holders of the second-lien notes, debt with the second claim on the company’s assets, took 95 percent of the new stock⁴. The old shareholders got none. They shared 45.45 percent of a batch of three-year warrants to buy shares at $35.41, adding up to at most 2.5 percent of the new company⁴.

In July 2023, ExxonMobil agreed to buy the reorganized company for $4.9 billion in stock, tying the purchase to its carbon-capture business and Denbury’s CO2 pipelines^5,6. Of the 2.9 million warrants in that batch, held by old shareholders and former subordinated noteholders together, 2.7 million were exercised before the rest expired on September 18, 2023⁷. The deal closed on November 2, 2023⁸.

Outcome, as of November 2023: in 2020, the old shareholders were cut to warrants on at most 2.5 percent of the new company⁴. In 2023, that company sold to ExxonMobil for $4.9 billion in stock^5,8. What that came to for the old shareholders in dollars isn’t in any filing I found.

The flood kept going. As of Evolution Petroleum’s report for the year ended June 30, 2025, Delhi was still producing^1,9.

These are lenders who won every dollar their paper promised. Ultra Petroleum filed for Chapter 11 bankruptcy in Texas on April 29, 2016, after natural gas prices collapsed¹. Chapter 11 is the kind of bankruptcy that lets a company reorganize and keep operating². The filing made Ultra’s notes come due at once, triggering a make-whole of about $201 million, an extra payment owed for paying them off early¹.

Then prices turned, and Ultra became what the Fifth Circuit, the federal appeals court over Texas, later called “massively solvent”¹. It offered the noteholders, the investors holding those notes, principal and pre-filing interest in cash¹. For the time after the filing, it offered interest only at the federal judgment rate of about half of 1 percent and no make-whole at all¹.

Put yourself in their seat. Your principal is on the table. Do you take it, or fight for the rest of what the paper says?

More than 40 insurance companies, hedge funds and other institutions fought¹. On October 14, 2022, the Fifth Circuit held that the Bankruptcy Code normally disallows a make-whole, but an old exception for solvent debtors still applied¹. Ultra had to pay the make-whole and post-filing interest at the contract’s default rate¹.

Outcome, as of October 2022

The court required Ultra to pay what the contract promised, about six and a half years after the filing¹.

By then Ultra had been through a second Chapter 11, filed on May 14, 2020³. It came out on September 14, 2020, with about $2.0 billion of debt eliminated⁴.

My read: the noteholders won because their borrower came out of the bust solvent and their contract spelled out what they were owed. You can’t plan on the first part. You can read the second before you lend.

From 2016 to 2019, Resolute Capital Partners and Homebound Resources sold more than $250 million of unregistered securities tied to oil and gas working interests to retail investors¹. About $192.6 million came through debt funds that lent to an affiliate, PetroRock, at fixed annual returns of 8 to 12 percent². What follows comes from the SEC’s settled order of September 24, 2021, whose findings the two principals neither admitted nor denied^2,3.

Now make it early 2018, and you’re a lender. A note fund called Legacy Energy is offering 8 to 9 percent, lent to PetroRock². The sponsor’s offering papers carry production projections². What would you check them against?

One earlier fund’s wells were projected at 510 barrels of oil a day². After nearly two years they averaged about 40². Later funds kept the 510 projection, and three of them came in at 5, 3 and 5 barrels a day².

Legacy raised about $39.7 million, and nearly half went to pay out two earlier funds through related-party deals that weren’t disclosed². The offering papers for four lender funds pledged 20 percent of what they raised as cash reserves, roughly $15 million². At the end of 2019, PetroRock had less than $100,000 in cash, and only $12,600 of it was set aside for those four funds².

The order imposed $600,000 of penalties on the two firms and the two principals, paid into a Fair Fund, a pool for paying back investors³. It ordered no disgorgement, the return of money gained³. The principals were barred from associating with any broker, dealer or investment adviser and from penny-stock offerings, with a right to apply for reentry after two years².

Outcome, as of September 2021

A $600,000 fund for investors against more than $250 million raised^1,3.

Status of the Fair Fund, as of October 1, 2026

The SEC’s page on the Fair Fund shows the $600,000 held at the Treasury and reports no amount paid to investors⁴. An administrator to oversee payments was appointed on February 11, 2025⁴.

Secured debt is supposed to be the safe seat.

In 2017, Seadrill owed $5.7 billion of secured bank debt, backed by a claim on its assets, plus $2.3 billion of unsecured bonds and other claims¹. That September it announced a restructuring through prearranged Chapter 11 bankruptcy cases, with the main terms agreed before the filing¹. Chapter 11 is the kind of bankruptcy that lets a company reorganize and keep operating².

Picture yourself as one of the lenders. Do you push for your money now, or give the company time? The banks chose time. More than 97 percent of them backed pushing their due dates out roughly five years, with no principal payments until 2020¹. The plan gave unsecured creditors about 15 percent of the reorganized company and left old shareholders about 2 percent¹.

The second time

Four years later the lenders were back. On July 24, 2021, Seadrill signed a plan support agreement, a deal in which creditors commit to back a restructuring plan³. Holders of about 57.8 percent of the senior secured loans agreed to swap $5.6 billion of debt for 83 percent of the new equity and $750 million of new debt³. Old shareholders would get a quarter of 1 percent, and only if every voting class accepted the plan³. General unsecured creditors would split $250,000 in cash³.

Outcome, as of February 2022

The court confirmed the plan on October 26, 2021, and Seadrill came out of Chapter 11 bankruptcy on February 22, 2022^4,5. Before the plan it owed its secured lenders $5,662 million⁶. Part of that stayed as a $683 million loan, not the $750 million in the July deal^3,6. Part was settled in cash with one lender group⁶. The rest became shares, with the lenders getting 83 percent of the new equity before dilution^3,6,7.

Add it up: 83 percent of $1,499 million is about $1.24 billion, and with the $683 million loan that’s about a third of the $5,662 million, not counting the cash^6,7,8. The $1,499 million is Seadrill’s own accounting value for all of the new equity at emergence, not a sale price⁸.

Being secured kept those lenders ahead of the unsecured creditors and the shareholders both times^1,3. The second time, it didn’t keep their loans as loans.

Not every restructuring takes two tries, the way Seadrill’s did. Key Energy Services owed money on 6.75 percent senior notes due 2021, a kind of bond¹. It also owed money on a term loan, a loan with a fixed payoff date¹. On August 24, 2016, holders of more than 87 percent of the term loan and more than 89 percent of the notes backed a plan support agreement, a deal in which creditors commit to back a restructuring plan^1,2.

On October 24, 2016, Key filed a prepackaged Chapter 11 bankruptcy, with the plan written and backed before the filing². Chapter 11 lets a company reorganize and keep operating³. The court confirmed Key’s plan on December 6, and Key came out on December 15 with about $725 million less debt^2,4.

Outcome, as of December 2016

Key was out of Chapter 11 bankruptcy in less than two months⁴. Before the vote, Key’s own disclosure statement projected 100 cents on the dollar for the term lenders and about 15 cents for the noteholders⁵. That leaves out any shares they bought in the rights offering⁵. In the end the noteholders traded $675 million of notes for 7.5 million shares of new stock⁶. The filings cited here give the share count, not what those shares turned out to be worth to the noteholders.

In June 2008 the SEC charged ten defendants in SEC v. McNaul over 22 oil-and-gas equipment “joint ventures”^1,2. From March 2004 to December 2007, the SEC said, they raised about $156 million from more than 1,300 investors in the United States, Canada and Puerto Rico².

Put yourself at that table. The pitch is oilfield equipment, leased out and operated, paying up to 40 percent a year³. Then, the pitch goes, comes a roll-up into a public stock offering paying as much as three to eight times your money^2,3. What would you ask to see?

The SEC says the promises were false and the ventures were structured to evade the securities laws^1,3. It says investors got back only about $7 million over four years, and $1 million of that was newer investors’ money paid to earlier ones, Ponzi-style².

Outcome, as of March 2012

Court records show only what the judge ordered, which isn’t the same as what was collected. In June 2011 the federal court in Kansas ordered Leonard to pay back $6.4 million plus interest and a $130,000 penalty⁴. On October 13, 2011, it ordered McNaul to pay back $5.3 million of what he gained, Lucas $3.2 million, Nunns $1.1 million and Krause $0.8 million^5,6,7,8. In December 2011 Kilgariff agreed to $363,846 plus interest, payable to the court-appointed receiver, a manager for what was left⁹. On March 30, 2012, the court refused to add interest or penalties for McNaul, Lucas, Nunns and Krause¹⁰.

On June 11, 2019, the New York Stock Exchange told Pioneer Energy Services that its stock’s average closing price had been below $1.00, the continued-listing minimum, over 30 straight trading days¹.

Imagine you held shares that June. Your stock is under the line. Do you sell, or wait for a turn?

The price stayed down. On August 14, 2019, the exchange suspended trading in Pioneer’s stock for abnormally low price levels and started delisting it². On March 1, 2020, Pioneer and its affiliates filed for Chapter 11 bankruptcy in federal court in the Southern District of Texas³. That kind of bankruptcy lets a company reorganize and keep operating⁴. This one was prepackaged, meaning the deal with the main creditors was lined up before the filing³.

Under that deal, the old senior unsecured notes, bonds with no collateral behind them, were canceled³. Their holders got 94.25 percent of the reorganized company’s new stock³. Pioneer’s old shareholders weren’t left with nothing. They got the remaining 5.75 percent, before dilution from an equity incentive plan and new convertible notes, debt that can turn into stock⁵. The court confirmed the plan on May 11, 2020, and it took effect on May 29⁶.

Outcome for Pioneer, as of May 2020

The old shareholders got 5.75 percent of the new Pioneer before dilution, and the old noteholders got the rest^3,5,6.

The second driller

Nearly five years later, a second driller went the same way. On December 2, 2024, Independence Contract Drilling, or ICD, filed for Chapter 11 bankruptcy in the same district, with Sidewinder Drilling LLC, under one prepackaged plan⁷.

This time the shareholders didn’t get a vote. Under the plan, all existing ICD common stock was canceled, with no distribution to its holders⁸. Their class was deemed to have rejected the plan and wasn’t entitled to vote on it⁸. The court confirmed the plan on January 9, 2025, and it took effect on January 17, 2025^9,10.

Outcome for ICD, as of January 2025

ICD’s existing shareholders got zero cents on the dollar^8,10.

Sabine Oil & Gas Corporation was a producer in Chapter 11 bankruptcy, the kind that lets a company reorganize and keep operating^1,2,3. Its case ran in federal bankruptcy court in the Southern District of New York¹.

Sabine had gathering agreements with two midstream companies, Nordheim Eagle Ford Gathering, LLC and HPIP Gonzales Holdings, LLC¹. A dedication is the producer’s promise that what it produces from certain acreage goes through one gatherer’s system. Under the HPIP agreements, Sabine had dedicated certain leases and certain oil, gas and water production². Under the Nordheim agreement, it had dedicated gas and condensate, and it had separately promised to pay Nordheim a gathering fee⁴.

In Chapter 11 bankruptcy, a company can ask the court to let it reject contracts, meaning walk away from them⁵. Sabine asked¹.

Look at it from the gatherer’s side. Your fee rests on the producer’s signature, and so does any floor you negotiated, a minimum the producer has to ship or pay for. Now the producer wants out. What do you have besides the signature?

The gatherers’ answer: property law

Their position was that the dedications were covenants running with the land^1,6. That’s a promise tied to the property itself, so it binds whoever owns the lease next, not just the company that signed. If the dedications ran with the land, rejecting the contract wouldn’t erase them^6,7.

The court took it in two steps. It found rejection a reasonable exercise of Sabine’s business judgment, which didn’t require settling the property question⁵. Then, on May 3, 2016, it ruled on that too. Under Texas law, the covenants didn’t run with the land, as real covenants or as equitable servitudes, a close cousin in property law^1,6.

Judge Shelley C. Chapman, the bankruptcy judge presiding over the case, signed the order authorizing the rejection on May 11, 2016¹. On June 15, 2016, she denied the gatherers’ motions to put her rulings on hold pending appeal¹.

The appeal

Nordheim appealed⁸. The district court upheld the ruling, and the Second Circuit Court of Appeals did too, on May 25, 2018⁸. The appeals court went narrower. It didn’t decide whether the covenants touched and concerned the land, one of the tests for a promise that runs with it^8,9. It held that Texas law still requires horizontal privity for a real covenant, a property link between the two parties who first made the promise. Nordheim’s agreement lacked it⁸. The court also found no equitable servitude, because the agreements benefited Nordheim as a company, not land it owned⁸.

Outcome, as of May 2018

Sabine’s rejection of the gathering agreements stood, and the dedications didn’t survive it^1,6,8. The filings cited here show the gatherers’ claims, not what Nordheim or HPIP finally recovered. Sabine’s last quarterly report, in May 2016, listed an unpaid Nordheim shortfall payment of about $3.0 million among the debts to be settled in the bankruptcy, owed because Sabine hadn’t shipped the minimum volumes the contract required¹⁰. It also said it couldn’t yet estimate what either gatherer’s claim would be allowed at¹¹. The order confirming Sabine’s plan, entered on July 27, 2016, left both gatherers’ appeal rights, and any claims that would follow a win, in place¹².

How that one case sits against the rest of the record

• Sabine’s clock: the covenant ruling on May 3, 2016, the rejection order on May 11, the stay denied on June 15 and the appeal affirmed on May 25, 2018. That’s about two years from first ruling to last word^1,8.
• A later bankruptcy went the other way on different paper. On December 20, 2019, a Texas bankruptcy court held that Alta Mesa’s gas dedications to the gatherer Kingfisher ran with the land under Oklahoma law. They survived⁷.
• In a July 2024 ruling in that same Alta Mesa bankruptcy, 27 separate gas-purchase agreements were held not to run with the land. None stated that intent, and none were recorded¹³.
• Before you buy in, have counsel read your agreement against the test the courts apply under the governing state’s law^9,14.
• Takeaway: a dedication is worth what the paper and the state’s law make it, not what the pitch calls it.

Pipe needs a path across somebody’s land. In Texas, a pipeline that carries crude oil “to or for the public for hire” is a common carrier under Chapter 111 of the Natural Resources Code¹. That label is tied to eminent domain, the power to take a right of way over a landowner’s objection, and the courts police who qualifies^2,3.

The 2012 ruling

The modern test came out of a fight between a landowner, Texas Rice Land Partners, and a pipeline company, Denbury Green². The line at issue was a carbon dioxide pipeline known as the Green Line⁴.

In 2012, the Texas Supreme Court held that a pipeline can’t just declare itself a common carrier. It has to serve the public, not only its builder². When the line is built, it has to be more likely than not that it will serve customers outside its own corporate family⁵.

Once a landowner challenges the label, the pipeline has to prove it³. A common-carrier permit, a filed tariff and an offer to carry for anyone willing to pay that tariff aren’t enough on their own³.

The 2017 win

Denbury Green went back to the same court and won on January 6, 2017⁴. The evidence was transportation contracts with two unaffiliated companies, Airgas Carbonic, Inc. and Air Products and Chemicals, Inc., plus an arrangement covering other unaffiliated working-interest owners⁶.

Outcome, as of January 2017: the Texas Supreme Court held that Denbury Green was a common carrier as a matter of law, reversed the court of appeals and reinstated the trial court’s judgment⁴.

My read

That’s about five years from the first ruling to the win. If a line’s plan leans on eminent domain, the right of way is a risk you’re buying. Careful buyers ask how many miles of the route already have signed easements, meaning landowners’ written permission for the pipe. They also ask whether any outside shippers have signed contracts.

The book’s Chapter 26 covers oilfield real estate, from equipment yards to man camps, the housing built for oil workers. Most of its man-camp risks belong to camps that are up and running: empty beds, one customer on one contract and a camp in the wrong place. This case is the exception. The risk was in where the money went.

In May 2015, the SEC froze the assets of North Dakota Developments, LLC and its two owners¹. The SEC accused them of raising over $62 million from hundreds of investors in the U.S. and abroad for man camps housing oil workers in the Bakken, North Dakota’s oil play¹.

The promise

According to the SEC, investors were offered returns of up to 42 percent a year, or a “guaranteed” return of up to 25 percent paid no matter how much rent the camps collected¹.

Where the SEC said the money went

The SEC alleged that more than $25 million went elsewhere¹. It named four uses: undisclosed commissions to sales agents, payments to the two owners, Ponzi-style payments to earlier investors and investments in unrelated Bakken projects for the owners’ own benefit¹.

How it ended

Outcome, as of June 2023: on April 24, 2018, the federal court in North Dakota entered default judgments, judgments entered without a defense, against the two owners, Robert Gavin and Daniel Hogan^1,2,3. Gavin was ordered to pay $350,000 in disgorgement, meaning giving back the gains, plus $24,613 in interest, for a total of $374,613². Hogan was ordered to pay $1,250,000 plus $87,906 in interest, for a total of $1,337,906³. Each was also ordered to pay a $500,000 civil penalty^2,3.

On June 1, 2023, the company and seven relief defendants, parties named to recover money they held, consented to a judgment of $25,357,989.89 in disgorgement and interest⁴. It was treated as satisfied by the assets the court-appointed receiver had collected⁴. A receiver is the person a court puts in charge of gathering and holding the money. On June 16, 2023, the court approved the receivership’s final distribution plan, and the case closed on June 21, 2023⁵.

Treated as satisfied means the judgment was closed out with what the receiver held. It isn’t a figure for what each investor got back.

A case like this is why the checks in the book’s Chapter 26 happen before the wire, not after, starting with proof of what’s been built.

This isn’t a fraud story. It’s a paperwork story.

Rupe Investment Corporation was a closely held family company, one owned by a few people with no public market for its shares¹. A family trust held a minority stake, meaning less than half². Three insiders together held about 79 percent of the voting stock and three of the four board seats².

The trust sued the directors¹. Before trial, the directors offered to buy the trust’s shares themselves, for $1.7 million³.

Put yourself in the trustee’s seat. Take the $1.7 million from the people who control the company, or go to trial and argue the shares are worth more?

The verdict

The trust went to trial on a claim of shareholder oppression, meaning the people in control had treated the minority owner unfairly. A jury agreed. It found the directors’ conduct oppressive and valued the trust’s shares at $7.3 million². The trial court ordered the company to buy them back at that price².

The appeals

On June 20, 2014, the Supreme Court of Texas rejected the claim the $7.3 million award rested on¹. Its majority declined to recognize any common-law claim for shareholder oppression, reasoning that the remedies already in Texas statutes were enough¹.

The trust’s fallback claim, breach of fiduciary duty, went back to the court of appeals. On January 12, 2016, that court found no evidence to support it⁴. It entered a take-nothing judgment, meaning the trust recovered nothing, and ordered it to pay the other side’s costs of appeal⁴.

A jury had found against the directors. No finding against them stood at the end^1,4.

Outcome, as of January 2016: no buyout and no damages for the minority owner, plus the other side’s appeal costs⁴.

United States Oil Fund, LP, ticker USO, was organized in Delaware on May 12, 2005, as a limited partnership and a commodity pool, a fund that pools investors’ money to hold futures¹. Its shares trade on NYSE Arca, a stock exchange, and it holds oil futures contracts^1,2. Its sponsor is United States Commodity Funds, or USCF³. The book’s Chapter 29 explains that machinery. Here’s what happened the week it was tested.

The week

In mid-April 2020, money poured into USO, with record-breaking daily inflows on April 16, 17 and 20⁴.

On April 20, the front-month contract for West Texas Intermediate, or WTI, the U.S. benchmark crude, settled at negative $37.63 a barrel⁵. The front month is the contract closest to delivery. It had never before settled below zero⁵.

The next day, USO ran out of the shares it had registered to sell and suspended creations, the new shares an ETF issues when new money comes in⁶.

Put yourself at your screen that week. Oil is below zero. The fund with “Oil” in its name is the one everybody is buying. What do you think you own?

On April 23, USO’s only futures commission merchant, the broker that cleared its futures trades, sent it formal notice⁷. It would not clear new futures trades funded by new share creations⁷.

What the regulators found

The SEC later found that USO’s filings from April 24 through May 21, 2020, did not fully disclose that limit⁸. That made them misleading, in violation of Section 17(a)(3) of the Securities Act⁸. Meanwhile, on April 28, with its NAV, or net asset value, down to $2.04 a share, USO did a 1-for-8 reverse split, turning every eight shares into one⁹.

On November 8, 2021, USCF and USO settled the SEC’s charges, and USCF settled those of the Commodity Futures Trading Commission, or CFTC, the federal futures regulator. The penalties came to a combined $2.5 million, paid without admitting or denying the findings¹⁰.

The class action

A private class action over the same events names USCF, USO and certain officers¹¹. It was pending in federal court in New York as of USO’s 2021 annual report, and its claims are allegations¹¹. On September 29, 2025, the court dismissed the complaint without prejudice, meaning the claims weren’t barred for good, and let the plaintiff ask to amend it¹². The plaintiff filed that request on November 26, 2025, and the defendants opposed it¹³.

Status, as of June 30, 2026: USO’s quarterly report for that period still showed the plaintiff’s request pending¹³.

What it cost

Outcome, as of December 31, 2020: USO’s NAV stood at $33.07 a share, down from $102.27 a year earlier, split-adjusted¹⁴. The fund reported a net loss of about $1.9 billion for 2020¹⁵.

Nothing in that story happened in the ground. What broke was a contract near delivery and the plumbing between a fund and its broker.

The book’s Chapter 32, “Decoding a Pitch Deck,” reads an offering’s paperwork page by page. This case is the cost page gone wrong.

From 2011 to 2016, the Justice Department says, Christopher Faulkner raised more than $71 million from working-interest investors¹. The SEC called him the self-proclaimed “Frack Master”². He sold turnkey working interests, one price for your piece of a well³.

Put yourself at the table. The offering materials show an estimated cost for the well and your share of it. The number looks precise. What would you hold it up against?

What the plea papers said

According to plea papers the Justice Department described, Faulkner inflated the estimated drilling costs by as much as 800 percent⁴. His three companies, Breitling Energy Corp., Crude Energy, LLC and Patriot Energy, Inc., kept the difference between his projections and what the wells actually cost⁴.

The civil case and the criminal case

In October 2018 he settled the SEC’s civil case and was ordered to pay more than $25 million, mostly disgorgement, meaning giving back the gains, plus interest². On December 1, 2020, he pleaded guilty to two counts of securities fraud and one of tax evasion⁵.

Outcome, as of January 2023: in September 2021 he was sentenced to 15 years in federal prison and ordered to pay $92.4 million in restitution, money a criminal court orders paid back to victims⁶. That $92.4 million is what the court ordered, not what investors have received⁶. Separately, a court-appointed receiver, the manager a court puts in charge of a company’s assets, ran a claims process for the Breitling companies⁷. In a January 2023 filing, the receiver reported that a $100,000 claim had received an interim payment of $8,400, about 8 cents on the dollar⁷.

A precise number isn’t an accurate one. The test for a cost estimate is line items someone independent can read.

The broader count

In a 2013 investor alert, the SEC counted its fraud cases tied to private oil and gas offerings⁸. They were few in 2005 and 2006 and averaged more than 20 a year after that⁸.

Takeaway: a prison sentence punishes the fraud. It doesn’t refund the check, so do the reading before the money moves.

The book’s Chapter 32, “Decoding a Pitch Deck,” reads an offering’s paperwork page by page. This case is the money page gone wrong: how many of the dollars raised reach the ground.

From 2007 to 2011, Arcturus Corp. and Aschere Energy sold interests in drilling joint ventures through a nationwide cold-calling campaign¹. They raised nearly $22 million from at least 380 investors². The investors had votes: on completing wells, on extra assessments and on removing the managers, with a 60 percent vote¹.

Put yourself in that seat. You have a vote and some of the well data. Is what you bought a security, with the protections that come with one, or a partnership share you police yourself?

What the SEC said

The SEC, which filed in December 2013, said only $7.9 million, 36 percent of the money raised, went to drilling wells². It also said the defendants misled investors about material litigation and, without telling them, used offering money to pay the costs of defending and settling it².

The fight over the votes

In March 2016 the district court held the interests were securities³. A final judgment followed in March 2017, ordering Leon Ali Parvizian and the two companies to pay $15.5 million in disgorgement and penalties^3,4.

On June 27, 2019, the Fifth Circuit, the federal appeals court that covers Texas, reversed and sent the case back for trial¹. The votes, the power to remove the managers and the fact that investors sometimes got the same raw well data as the managers raised real questions about whether investors relied only on the promoter¹. That question goes to whether the interests were securities at all. The court didn’t hold that they weren’t¹.

In October 2021, Parvizian and the two companies consented to liability⁴.

Outcome, as of January 2025: on January 28, 2025, the court entered a final judgment of $9,844,127 in disgorgement, $938,770.65 in interest and a $500,000 penalty⁵. That’s about $11.3 million, just over 11 years after the SEC filed^2,6. The judgment is payable to the SEC, which holds the money and proposes a distribution plan for the court to approve⁶.

Dollars in the ground, per 100 raised

• Arcturus: about 36 of every 100 dollars raised went to drilling, by the SEC’s account. The other 64 didn’t².
• Petroleum Unlimited, a 2011 SEC case the book’s Chapter 35 tells: about 18, by what the SEC alleged, since only $534,000 of the $2.9 million raised was used for drilling^7,8.
• For comparison, PDC’s 2004-2006 drilling program: its 2005 prospectus capped the organization and offering costs investors bear at 10.5 percent, set a one-time management fee of 1.5 percent and required at least 90 percent of what was left to go into drilling and completing wells. That’s a floor of at least 79⁹.

Vote or no vote, the check is the same: how much of the money reaches the ground?

The book’s Chapter 32, “Decoding a Pitch Deck,” reads an offering’s paperwork page by page. This case is the prospect page gone wrong.

From 2012 through mid-2015, Brian Alfaro, through Primera Energy LLC, sold working-interest units in named prospects in Gonzales County, Texas: the Screaming Eagle 4H, the Screaming Eagle 6H and the Black Hawk Horizontal Buda #1¹. According to the Texas State Securities Board’s summary of the federal indictment, investors were told their money would pay for leases, testing and drilling, plus a management fee².

Picture the pitch. It names real prospects and spells out the fee. Does a name you can look up mean your money goes there?

Where the money went

The Justice Department says Alfaro spent diverted investor money on a Rolex, about $100,000 of San Antonio Spurs season tickets and luxury cars including a Lamborghini, a Mercedes-Benz and a Porsche³.

The trial and the appeal

On February 13, 2020, after an eight-day trial, a jury convicted him on seven counts of mail fraud⁴. That November he was sentenced to 121 months in prison and ordered to pay $9,922,428.63 in restitution, money a court orders paid back to victims⁴.

On April 7, 2022, about 17 months after sentencing, the Fifth Circuit affirmed the conviction but vacated the sentence and restitution order, because the loss figure was wrong⁴. The district court hadn’t accepted the government’s own concession that the total loss was $9,429,599.73⁴.

Outcome, as of May 2023: conviction affirmed⁴. On remand, the court resentenced Alfaro on June 30, 2022, to 97 months and set restitution at $9,018,527.71⁵. An amended judgment on May 11, 2023, raised it to $9,026,358.92⁵.

A named prospect is checkable, and you should check it. But a real well name tells you where money could go, not where it went.

On March 5, 2015, FINRA suspended Raymond Leslie Boykin’s securities registration¹. He then formed U.S. Energy Assets, LLC, which offered Texans unregistered investments in oil and gas drilling programs¹. The Texas State Securities Board later said FINRA had suspended him for two years for misappropriating confidential client data².

The offer

A protected unit in the #1 H Duchess well, in Harrison County, Texas, cost $220,000, plus $77,000 paid to Timeless Protect LLC for its Cash Back Program¹. Timeless Protect marketed that program as an “absolute guarantee” that took away the risk of drilling¹.

Now picture this offer. A second company promises your money back even if the well fails. Does that make the well safer, or the deal harder to read?

What the 2019 order found

A Texas emergency order on November 22, 2019, read the paper¹. The Cash Back payments were promised regardless of how the well performed, but Timeless Protect kept the right to change the program’s terms on its own¹. The insurance on the trust account had a $3 million aggregate limit that investors weren’t told about¹.

One sales agent, Robert J. Mangiafico Jr., had been convicted in September 2013 of theft and money laundering for stealing $655,000 from elderly widows and sentenced to 40 years in state prison¹. As of the 2019 order, he had recently been released on parole¹.

The order concluded that the respondents were “engaging in fraud” in offering securities¹. It told them to stop offering securities in Texas at once¹.

Outcome, as of October 2022: the emergency order halted sales in November 2019¹. A Texas agreed order in October 2022 found securities fraud and registration violations, including that Boykin’s earlier FINRA suspension wasn’t disclosed to investors². The Board said Boykin and U.S. Energy Assets misled investors about the company’s profitability and regulatory oversight². The agreed order covered U.S. Energy Assets, Texas Victory Joint Venture and Boykin³. It told them to stop offering unregistered securities and to stop acting as unregistered dealers or agents, and it set aside the 2019 emergency order as to them³. It ordered no refund, no restitution and no fine³.

A guarantee is one more promise to check. So is the salesperson’s name, in BrokerCheck⁴. As of 2026, FINRA’s BrokerCheck is free, and a person’s report shows 10 years of employment history plus a disclosure section that covers customer disputes and disciplinary events⁴.

Registration can sound like a technicality. Two Texas orders from 2019 show it can be the whole problem.

SourceRock Energy

SourceRock Energy and its CEO set out to raise $4.4 million for the Phoenix Prospect, an oil-and-gas project in Sumner County, Kansas¹. Of that, $1 million was earmarked as a management fee to an affiliate the CEO owned¹. The securities, the company and its CEO were all unregistered in Texas¹.

In September 2019 SourceRock and its CEO agreed to an order to stop offering securities in Texas¹. The CEO also made investors in the prospect, Texans included, a full rescission offer, an offer to unwind the sale and hand the money back¹.

Travco Oil and Gas

Travco Oil and Gas drew a Texas emergency cease-and-desist order on November 22, 2019². Its principal and a sales agent had offered interests in the Moody 3 Well Development, a project in Wagoner County, Oklahoma, without being registered in Texas as dealers or agents². The order describes the project as three wells and says it actually involves four². In June 2020 Travco settled. The agreed order required it to adopt an internal compliance program, and Travco paid a $1,000 fine³.

Outcome, as of June 2020: an agreed order and a full rescission offer for SourceRock, and an agreed order with a compliance program and a $1,000 fine for Travco^1,3. The public record I found shows no fraud finding against either^1,3. A rescission offer is an offer, and the record doesn’t say how many investors took the refund.

Woodland Resources LLC was soliciting Texans to invest in two oil wells in Seminole County, Oklahoma^1,2. Its director of operations promised annualized returns of up to 70 percent¹. Woodland said one of the wells was making 38 to 40 barrels of oil a day as of October 2018¹.

What the pitch left out

According to the Texas State Securities Board, the pitch left out the director’s past. His prior company had filed for bankruptcy in 2007 listing more than $10 million in debt, and the Board says he hid it^1,3. In 2011 creditors forced another company tied to him into bankruptcy, and when that case was discharged, its creditors were owed more than $44 million in claims¹. In 2010, a federal court in Dallas had ordered that company and him to pay nearly $13 million in damages to investors who sued them for fraud and breach of contract¹.

Sit in an investor’s chair. You had a return figure and a production number. My read is that a search on his name was the cheapest check in the deal.

What the Board found

The Board ran the checks. Official state production records showed the well averaged 19.7 barrels a day for the year ended April 2019, about half the claim^1,4. A July 10, 2019 emergency order from the Texas Securities Commissioner found that he committed fraud, and by February 2020 that finding was final⁵.

Outcome, as of February 2020: a February 20, 2020 order required Woodland to pay a $20,000 fine and offer 27 investors refunds totaling $1,497,519, about $55,000 each on average². That’s an offer of refunds, not a record of refunds paid.

The AFE, the authority for expenditure, is the estimate of what the well will cost¹. The model JOA defines it as an estimate¹. It’s not a price, and it’s not a cap. Even its contingency, the line meant to cover what goes wrong, is part of the estimate.

Here’s how far an estimate can drift, from a court record.

One AFE, four numbers

A Louisiana gas-plant upgrade, the Belle Isle project, started on an AFE of about $16.9 million, signed in September 2012². The operator, Apache, overspent it. A supplemental AFE followed for $37.7 million, then another for $78.5 million, and the project finished at $102 million, about six times the first estimate².

• First AFE, September 2012: about $16.9 million².
• First supplemental AFE: $37.7 million².
• Second supplemental AFE: $78.5 million².
• Final cost: $102 million².

Castex, a non-operator, paid 25 percent of the costs, and Apache paid the other 75 percent³. A Castex vice president learned of the overspending no later than August 2013, from the operator’s monthly joint interest billing statement⁴. That statement showed more than $19.6 million of spending, and the court said the true total was much higher⁴.

The rule, and the exception

The operating agreement, a model form, made the operator answer for losses only in cases of gross negligence or willful misconduct³. Castex sued, and a jury found Apache’s breach was willful misconduct⁵. It set Castex’s damages at $5,566,577, the difference between what Castex agreed to pay and what it actually paid⁵. In May 2021 a Texas appeals court in Houston found the evidence legally sufficient and upheld that award⁵. That was the exception.

The well with five sidetracks

The same suit covered a gas well that took five sidetracks, new paths drilled around trouble in the hole⁶. There the jury found Castex’s damages for the drilling cost overruns were more than $8.9 million⁶. The appeals court deleted Castex’s recovery on that well, interest included⁷.

Outcome, as of April 2023: the $5,566,577 award on the gas plant stood, and the recovery on the sidetracked well was deleted^5,7. The Texas Supreme Court denied review on January 27, 2023, and denied rehearing on April 21, 2023⁸.

This one is a plant, not a single well, and the owners were companies, not individual investors^2,3.

The record

• The appeals opinion: Apache Corp. v. Castex Offshore, Inc., No. 14-19-00605-CV, Texas Fourteenth Court of Appeals in Houston, May 11, 2021².
• The Texas Supreme Court docket: Castex Energy Partners, LLC v. Apache Corporation, No. 21-0533⁸.

So ask the operator for its own record: on its last few wells, the AFE and the final cost, side by side.

A lien is a legal claim against property that secures an unpaid bill. In Texas, a contractor or subcontractor who isn’t paid for work or materials on a well gets a lien¹. It covers the land, the leasehold, the well, pipelines, buildings and equipment¹. It can reach other wells and equipment the owner uses on the property too². The claimant files it with the county clerk within six months after the debt accrues³.

My read: the lien risk that should worry an investor is simple. You pay your cash call. The operator doesn’t pay the mud company, the vendor that supplies the drilling fluid. The mud company’s lien attaches to the well you own part of.

The cover: an owner that paid in full

Texas law does give a paid owner some cover, and the second case below shows it has gaps. An owner served with a subcontractor’s notice may hold back payment, and isn’t liable for more than it owes its contractor when the notice arrives⁴.

In 1986 a Texas appeals court in Amarillo showed that cover at work⁵. An unpaid supplier had won a trial judgment of $7,973.37, plus $2,657.79 in attorney’s fees, with foreclosure of its lien⁵. The appeals court reversed. It held that an owner who paid its mud contractor in full before any notice of the supplier’s claim wasn’t liable, and its lease wasn’t subject to the lien⁵. The supplier took nothing⁵.

The gap: owners who came in after the work

Here’s how it played out in another Texas court. A driller drilled two wells in Taylor County in October and November 1985 for an operator that was then the only record owner of the lease⁶. On January 10, 1986, the operator assigned working interests to four owners and recorded the assignment that day⁶. On March 18, 1986, the driller filed a lien on the operator’s interest in the whole section, naming none of the new owners and sending them no notice⁶.

The owners won summary judgment in the trial court. In February 1992 a Texas appeals court in Eastland reversed and sent the case back⁶. It held that a driller who contracted with the operator owed those owners no notice before filing, and that its lien dated back to when the work was done⁶. The work came before the owners did, and the lien reached back to it anyway⁶.

Outcome, as of February 1992: the 1986 owner that paid in full owed nothing⁵. The 1992 ruling sent the case back for more proceedings and states no dollar outcome⁶. Both rulings are decades old, so ask a lawyer how they stand today.

The record

• Energy-Agri Products, Inc. v. Eisenman Chemical Co., 717 S.W.2d 651, Texas Court of Appeals in Amarillo, June 25, 1986⁵.
• Bandera Drilling Co. v. Lavino, 824 S.W.2d 782, Texas Court of Appeals in Eastland, February 6, 1992⁶.

The check

Liens get filed at the county clerk’s office, so a search there before you sign shows what’s on record so far^3,7. Then ask the operator in writing whether its vendors are paid current. The book’s Chapter 36 covers the check.

The book’s Chapter 35 calls this pattern the checks that never miss: steady payouts from day one. Here’s a Texas case.

What the SEC said

In December 2013 the SEC halted a Texas royalty scheme, Vendetta Royalty Partners¹. The SEC said its promoters raised nearly $18 million from at least 80 investors in more than a dozen states¹. Their offering documents told investors that more than 99 of every 100 dollars would buy oil and gas royalty interests¹. The SEC said only about 10 did, and about $5.9 million went out as “partnership income distributions” paid with new investors’ money¹.

That’s a Ponzi scheme, paying earlier investors with later investors’ money. From the outside, the check looks just like a royalty check. A real royalty check traces back to oil or gas sold from named wells. In the Vendetta scheme, the SEC said, the distributions came from new investors’ money¹.

How it ended

This one ended in criminal court. The promoters were an Austin attorney and his business partner². By 2017, Texas regulators put the total at about $30 million from more than 100 investors in two royalty funds and related ventures². The funds were Vendetta Royalty Partners and Iron Rock Royalty Partners². Texas regulators say those ventures were run as a Ponzi scheme².

The two promoters had each been sentenced to 78 months in federal prison, and on October 2, 2017 a federal judge ordered them to pay $29 million in restitution to investors². Texas regulators said the two spent at least $9 million on themselves, including houses, weddings, travel and luxury cars². They listed some of it:

• $600,000 to buy and remodel houses².
• $400,000 for weddings².
• $500,000 for personal travel².
• $300,000 on one promoter’s collection of Mercedes-Benz and BMW vehicles².

Outcome, as of October 2017: two federal prison sentences of 78 months each and a $29 million restitution order². An order to pay is not a record of money paid back.

The check

Ask where the last distribution came from, and ask for the statement that ties it to oil or gas sold from named wells. Ask for audited financial statements. NASAA’s policy for registered programs calls for an annual report with audited financials within 120 days of year-end³. If the payouts are bigger than what the wells sold, ask what paid the difference. If the answer is new money, walk.

The first walk on the book’s due diligence checklist is a salesperson who isn’t registered. Here’s a case for it.

In a settled order dated December 9, 2024, the SEC said David C. Underwood raised about $4,315,000 from 20 individual investors for two Heartland oil and gas funds between February 2020 and December 2021¹. That’s about $216,000 each on average¹. Heartland paid him 5 to 8 percent of each investment as transaction-based compensation, pay tied to the money he brought in². The SEC said he had never been registered with it, or associated with a firm registered with it, in any capacity³. It also said Heartland told investors some wells were making hundreds of barrels a day when they hadn’t produced a barrel⁴.

My read: a BrokerCheck search on his name before the wire would have turned up no registration, and that’s where I walk.

Outcome, as of December 2024: Underwood settled without admitting or denying the findings⁵. He was ordered to pay $145,972 in disgorgement, money gained that a regulator orders paid back, plus $25,716 in prejudgment interest and a $50,000 civil penalty⁵. The SEC says the disgorgement and interest go to harmed investors to the extent feasible⁵.