Start here

First — what's an "estate"?

In property law, an estate is just a set of ownership rights. The key thing about land is that it can hold more than one estate at once — and they can belong to different people. The two that matter here are the surface estate (the ground itself: soil, buildings, crops, roads, most water) and the mineral estate (the oil, gas, and other minerals below, plus the right to use the surface to reach them).

When those two are owned together, nobody thinks about it. But the moment the minerals are sold off or reserved apart from the surface — a severance — you have two separate properties stacked on the same spot, each free to be owned, leased, taxed, and sold on its own.

Below is a single 160-acre tract. Bob owns the surface; beneath him, the minerals belong to Carl and Susan. Switch between the estates — and pull them apart — to see how they stack, and how the minerals divide into two tracts while the surface stays whole.

Start here

First — what's a "tract"?

A tract is a parcel of land defined by ownership, not by fences. If the same people own an area in the same shares, it's one tract. The instant the ownership differs from one part to the next, you have separate tracts — even if the ground looks identical and there's not a fence in sight.

So tracts aren't fixed forever. Every time land is sold, gifted, or inherited, the ownership pattern can change — and a single tract can divide into two, three, or a dozen separate ones. Following that history is how you prove who owns what today.

Let's watch it happen. Step through the years and see one mineral tract divide into two — arriving exactly at the picture from Concept 01.

Start here

First — what's an "undivided" interest?

An undivided interest means your fraction applies to the whole tract, everywhere, all at once. Own an undivided 1/4 of 80 acres and you don't own any particular 20 acres — you own 1/4 of every single acre, side by side with your co-owners. There is no line on the ground separating "yours" from "theirs."

To talk about how much that is, the industry converts it to net mineral acres: your fraction × the tract's acres. An undivided 1/4 of 80 acres = 20 net mineral acres — a measure of quantity, not a location.

Watch it splinter

Three generations, one 80-acre tract

Fractions rarely stay simple. Every inheritance and every sale splits them further. Watch one owner's 100% become eighths in two generations — this is called fractionalization, and it's why some tracts today have hundreds of owners holding slivers like 1/256.

Every bar is the same 80 acres. The fractions always add back up to 1 — there's never more or less land, just more names on it. By generation three, a 1/6 owner holds 13.33 net mineral acres they could never point to on a map.

Start here

First — what does "leasing" your minerals mean?

Owning minerals doesn't produce a single barrel — someone has to drill, and drilling costs millions. So the mineral owner signs a lease: a company (the lessee) gets the exclusive right to explore and produce, and the owner (the lessor) gets paid two ways — a bonus up front just for signing, and a royalty: a fraction of production, free of drilling costs, for as long as the lease lasts.

How long is that? Every lease has two clocks. The primary term is a fixed window (often 3 years) for the company to drill. If it drills and finds production, the lease rolls into the secondary term — which has no end date at all. It simply lasts as long as the well keeps producing. That's called being held by production.

The easiest way to understand a lease is to follow one through its life:

Start here

First — what's a unit?

Minerals under a field are almost never owned by one person. They're a patchwork of separate tracts, each with its own owners and fractions. On its own, most any single tract is the wrong size or shape to drill — and an operator can't just drill wherever they like. The Railroad Commission assigns every well a proration unit: a set amount of acreage that "belongs" to that well for spacing and production (roughly 160 acres for oil, 640 for gas).

Pooling is simply the act of combining those separate tracts into one unit so a single well can be drilled — and everyone in the unit shares that well's production, normally in proportion to the acreage they brought in. Unitization is the same idea at a larger scale: combining a whole field or reservoir, usually to run enhanced recovery across it.

So far, so good — pooling gets a well drilled that might never happen otherwise. But notice that one word: proportion. Your share is your acreage ÷ the whole unit. That means the size of your tract decides whether pooling is the best thing that ever happened to you, or a haircut you'd rather avoid. Drag the slider below to see both at once.

So — for it, or against it?

It's a decision, not a rule

Start here

First — what's a division order?

Before a well pays anyone, the operator maps out exactly who gets what share of production. Each owner's share is written as a decimal — the decimal interest, also called the division of interest (DOI) — and sent to them on a document called a division order (DO): a statement that says "we show you owning 0.0…X of this well; confirm and we'll start paying."

The decimal isn't invented — it's built by multiplying a few simple fractions together. Each fraction answers one question. Let's build yours from scratch, starting simple and adding one real-world layer at a time.

The whole story in one picture

Same ownership, same royalty — each layer of sharing shrinks the decimal

Each stage multiplied in one more honest fraction. A small decimal usually doesn't mean anyone shorted you — it means the pie you're sharing got bigger. But because a division order is only the operator's math, checking those fractions against your own deed, lease, and the unit's plat is exactly how owners catch real errors.

Start here

First — what are you actually being paid for?

Your well produced oil this month; the operator sold it. Your gross royalty is your decimal share of that sale money — before anything is taken out. From there, two kinds of subtractions can appear on the stub: severance tax, which the state charges on minerals when they're produced and sold (more on this in Concept 08), and post-production costs — the well's share of getting the product treated, moved, and to market, which many (not all) leases let the operator deduct (Concept 10 takes these apart in full).

What's left is your net — the number that actually lands in your account.

Here's a whole month on one stub — a clean $1,000 gross so the math is easy to follow:

Real stubs split this across products (oil, gas, liquids) and months, and often correct earlier months — but every line on them is one of these three things: gross, a subtraction, or net. Concept 13 follows the same dollar the other way — from the purchaser’s payment, into the operator’s bank account, and out to you.

Start here

First — the candy store

Imagine your minerals are a candy store, and every barrel of oil is a candy bar. Two different tax collectors visit — at different times, measuring different things.

Side by side

Start here

First — why would a well not be pooled?

Spacing rules are the reason multi-tract wells need special treatment at all. The Railroad Commission's Statewide Rule 37 keeps wells a minimum distance from any lease line — and a wellbore obviously can't stay 467 feet away from a line it drills straight through. Pooling solves that by erasing the lines: once tracts are pooled, the Commission treats the whole unit as a single lease, so there are no interior lines to violate.

But pooling only happens if each lease grants the authority — and many don't grant enough. Older pooling clauses often cap units at 40 or 80 acres for oil, sizes written for the vertical-well era; a 10,000-foot lateral can't live inside that. Other leases prohibit pooling entirely. So since around 2008, the Commission has issued permits for two other kinds of multi-tract horizontal well: the PSA well and the allocation well. In both, the lease lines survive — only the sharing formula changes.

Below is one well: a 10,000-foot productive lateral crossing three tracts. Switch between the three ways Texas lets an operator permit it — and watch what happens to the lease lines, and to each tract's share of the same oil.

Start here

First — two kinds of cost, and why only one is yours

Every barrel has costs attached to it. Texas law splits them at the wellhead. Everything spent getting oil and gas out of the ground is a production cost, and a royalty owner never pays a dime of it — that's the whole point of a royalty. Everything spent after it reaches the surface, getting it cleaned up and hauled to a buyer, is a post-production cost — and the default rule in Texas is that royalty owners do share those, in proportion to their interest.

The default can be changed. But changing it takes the right words in the lease, and which words work is the whole fight.

Why these costs exist at all

The buyer used to be parked at your well

In the early oil fields there was no gap to pay for. A wagon, and later a truck or a small pipeline, pulled up to the tank battery beside the derrick. The buyer weighed the oil, wrote a price, and hauled it away. Value at the well and value at the sale were the same number, because they happened in the same place.

Modern production doesn't work that way — especially gas. Raw gas coming out of a Permian well is wet, sour, at the wrong pressure, and worth very little where it stands. It has to be gathered, compressed, dried, sweetened, processed to strip out the liquids, and shipped to a hub hundreds of miles away before anyone will pay a headline price for it. The price you read in the news is the price at the far end of that chain. Getting there costs real money, and post-production costs are simply the bill for that trip.

So the money is real and the work is real. The only question — the entire question — is which end of that pipeline your lease uses to measure what your royalty is worth.

The one idea that explains everything

Move the measuring point, move the money

Picture the gas leaving your well and gaining value at every step, because each step makes it worth more to a buyer. Your lease plants a flag somewhere along that line. Your royalty is figured on the value at the flag — and every cost spent downstream of the flag is a cost you share.

Drag the flag and watch your royalty change. Nothing else moves: same well, same gas, same 1/5 royalty fraction.

Don't confuse the two subtractions

Post-production costs are not a tax

These two lines sit right next to each other on a check stub and get mixed up constantly. They come from different places, are set by different people, and only one of them is negotiable.

The words that decide it

Four terms you'll meet in a royalty clause

A royalty clause is really answering three questions: what fraction, measured by what standard, and measured where. Courts call the standard the yardstick and the place the valuation point — and it's the place, far more than any promise about costs, that decides who pays.

How Texas courts have answered it

Thirty years, one lesson

Texas has been sorting this out case by case since the 1990s, and the arc is remarkably consistent: the court finds the valuation point first, and general promises that a royalty is "cost-free" rarely survive contact with a lease that measures value at the well. Precise, mechanical language wins; reassuring language doesn't.

Two further 2026 signals point the same way: the Texas Supreme Court declined to review City of Crowley v. TotalEnergies, where an add-to clause failed against a wellhead point of sale, and a court of appeals wiped out a large royalty-owner verdict in Devon Energy v. Oliver on the same reasoning. The direction of travel is clear — the lease text, not the label on the royalty, is what pays.

What to do about it

Writing them out — before you sign

All the leverage a mineral owner has on this issue exists in the minutes before signature. Once a lease is signed and a well is producing, the clause is what it is, possibly for forty years. Here's what actually moves the needle, and it's worth having a Texas oil and gas attorney draft the language for your specific tract.

General patterns, not a prediction about any particular lease. Every one of these cases turned on the exact words of a specific instrument read as a whole.

Start here

First — what is a savings clause "saving" you from?

The sentence that sets a lease's length is called the habendum clause, and it reads roughly: "for a term of three years and as long thereafter as oil or gas is produced." Those last five words are doing enormous work. Read literally, they mean the lease lives only while oil or gas is actually coming out of the ground and being sold. Stop for a month and the lease would end.

That would be unworkable. Wells get worked over. Pipelines get built late. Compressors fail in February. So every lease form carries a short list of clauses that say, in effect, "and this counts as production too." Those are the savings clauses. Each one bridges a particular kind of gap, and each one has a price and a time limit — or doesn't, which is where the trouble starts.

Here's the shape of the problem. One lease, ten years, with a gap in the middle.

The four bridges

Which clause catches which gap

Four clauses do almost all of this work, and each answers a different question. Read in order, they cover the whole life of a lease — from the first dry hole to the last tired well.

A fifth clause, force majeure, sits behind all of these and pauses the operator's obligations during events genuinely outside their control. It earns its place — but read the list of what counts. If it stretches to cover "lack of a favorable market," "economic conditions," or low prices, it stops being a storm clause and becomes an indefinite hold. The red flag section of the clause dictionary covers that one.

The one to negotiate

Why an uncapped shut-in royalty is the quiet problem

The shut-in royalty exists for an honest reason: a well can be finished months or years before a pipeline reaches it, and nobody benefits from the lease dying in the meantime. Nobody argues with the concept.

The argument is about the number and the clock. Most printed lease forms set the shut-in royalty at something like $1.00 per net mineral acre per year, or a flat $50 to $100 per well — figures written into these forms decades ago and never adjusted for anything. And most set no limit at all on how long, or how many times, that payment can substitute for actual production. Put those two facts together and you get a lease that can be held on your minerals almost indefinitely for the price of a tank of gas.

The fix is not exotic. You cap it, and you price it. Drag the slider and watch what those two changes are worth on a 160-acre tract.

What to ask for

Five edits to the shut-in clause · worth having a Texas oil and gas attorney draft for your tract

That last row is the one people underestimate. If the shut-in payment is written as a covenant, missing it means you'd have to sue for damages and the lease survives. If it's written as a condition, the lease simply ends when the payment doesn't arrive on time — no lawsuit, no notice. Same money, completely different consequence.

Each of these clauses is written out in full in the Term, continuation & Pugh section of the Lease Clause Dictionary, along with why the operator wants it and whether it's already in the standard printed form.

Start here

First — why a lease can end without anyone doing anything

This is the piece that surprises people, and it's the engine behind everything else on this page. A Texas oil and gas lease is not a contract that has to be cancelled. It is a conveyance of the minerals subject to a built-in expiry date — lawyers call it a fee simple determinable with a special limitation. The habendum clause from Concept 11 is that limitation: the lease lasts "as long as oil or gas is produced," and when that stops being true, the estate ends on its own.

No notice. No forfeiture suit. No cure period unless the lease wrote one in. The minerals simply revert to you the instant the condition fails — a moment that may pass, entirely unremarked, while everyone involved carries on assuming the lease is fine.

The catch is that "the condition failed" is easy to say and hard to prove, and there are more ways for a lease to survive than most owners expect. So the job isn't to declare leases dead. It's to build a file.

Read the record

Ten years of one well, month by month

Below is the production history of a single oil well on a 160-acre lease, as it would appear if you pulled the operator's monthly production reports from the Railroad Commission and plotted them. Everything a mineral owner needs to spot a dying lease is visible in this one picture. Step through it.

Plotted on a logarithmic scale — the standard for decline curves, because a well that starts at 4,000 barrels a month and ends at 30 can't be shown honestly any other way. Each gridline is ten times the one below it. Months with no production at all can't sit on a log axis, so they're drawn as red marks in their own band beneath it.

Notice where the actual event is. The well was plugged in 2024 and the operator changed hands in 2023, but neither of those is the moment the lease ended. If this lease terminated, it terminated somewhere in 2022 — when production in paying quantities stopped for good and no savings clause bridged the gap. The 2023 and 2024 filings are just the evidence that nobody was ever coming back.

Before you say the word "terminated"

Four questions that decide it

A string of zeros is a reason to open a file, not a conclusion. Four things routinely save a lease that looks dead on the production report, and all four are checkable.

Which way does the evidence point?

The same file usually contains some of both

The monitoring file

What to pull, and what each record actually tells you

Everything in the left-hand column is a free public filing with the Railroad Commission, searchable by lease, operator, or API number. The one document that isn't is the lease itself, which lives in the county clerk's records — and it's the most important of the lot, because it's the only thing that tells you how long the operator actually gets.

The Railroad Commission's public queries and where each of these filings lives are laid out on the Texas page in "Where to look it up". If your minerals are outside Texas, the same section covers the RRC's equivalent in the ten biggest producing states — the filings have different names, but the monitoring job is identical.

What it's worth

Why anyone bothers

Monitoring is tedious, so it's worth being concrete about the payoff. A lease signed in 1994 on 160 net mineral acres, still alive today on its original terms, against the same acreage re-leased at what the market pays now:

That is the whole argument for keeping a file. The bonus is a one-time number and it's large. The royalty difference is a permanent one and it's larger. Both of them are sitting behind a lease that may already have ended without anyone saying so.

What to do about it

Four steps, in order — and one you shouldn't take alone

Start here

First — three words you already met

This page sits at the end of the getting-paid chain, so it borrows from earlier concepts. You don't need to go back and re-read them; here they are in one line each.

And six that are new here

Every one of these is a piece of plumbing rather than a piece of law. That's the point: the plumbing is where the money actually goes wrong.

Step one — the sale

Why gas takes longer than oil

The well produces and the operator sells the production to a first purchaser. What happens next depends entirely on which product came out of the ground, and it explains a statutory rule that otherwise looks arbitrary.

Oil is simple. A truck or a line takes it, the purchaser writes a run ticket, and a monthly settlement statement follows. One product, one volume, one price.

Gas is not. Raw gas usually travels through a gathering system to a processing plant, where the valuable liquids — ethane, propane, butane, natural gasoline — are stripped out and sold separately from the leftover residue gas. Now there are four products instead of one, and the plant has to work out how much of each finished product came from your particular well, mixed as it was with everyone else's. That's an allocation, and it takes weeks.

This is the whole reason Texas gives a company 90 days to pay gas royalties and only 60 to pay oil. It isn't a favour to the operator. The gas arithmetic genuinely is harder.

Step two — where it lands

One payment, one ordinary bank account

Here is the part that surprises almost everyone. The first purchaser does not send the operator a stack of envelopes with owners' names on them. It sends one payment for the whole month's production from the property. That payment goes into the operator's regular company bank account, mixed in with every other dollar the company has.

There is no separate royalty account. There is no escrow. There is no trust fund. Texas law doesn't require one. From the moment that money arrives, the relationship between the company and you is the same as the relationship between a borrower and a lender: the company owes you an amount. It is not holding your specific dollars in a specific place.

Hold on to that picture. Two of the hardest things on this page — what suspense really is, and what happens to your money if the operator goes bankrupt — follow directly from it.

Step three — the split

The deck: one lump sum, exploded

Inside the operator's revenue accounting department is the division of interest — the deck. It lists every person and entity with a claim on that well and each one's decimal. Once a month the lump sum is exploded across it: volume × price × your decimal = your gross share. Simple arithmetic, run across sometimes thousands of owners.

Here is one month on a well with a 1/5 lease royalty, using the decimal built in Concept 06:

Your decimal sits inside the royalty line, not beside it. That's why a royalty owner's number looks so small next to the well's: you own a slice of a slice.

Three things go wrong at this step, and all three are ordinary rather than sinister:

Your decimal is wrong. Someone misread a deed, dropped a fraction, or missed an old reservation. The stub will still look perfectly tidy.

You aren't in the deck at all. Your interest was never picked up in the title work, so no line exists to pay.

You're in the deck but flagged unpayable. That's suspense, and it has its own section below.

Step four — off the top

What comes out before anyone gets paid

Texas taxes production at the wellhead. The operator remits the tax and charges every interest owner, including you, a proportionate share. This part is not controversial — practically every Texas lease has the royalty owner bearing a share of production taxes, and even strongly owner-favourable clauses carve taxes out as an allowed charge. Concept 08 takes the two taxes apart in full.

Two smaller mechanics worth knowing, because both look like nonpayment and neither is:

Small balances get held. Texas lets a company accrue payments under $100 until they reach $100 or twelve months' worth has piled up, whichever comes first, and hold balances under $10 until production ends. If you'd rather be paid more often, you can ask in writing — an owner owed more than $25 but less than $100 can request monthly payment, and an owner owed less than $10 can request an annual one.

Backup withholding is not lost money. If the payor doesn't have a valid tax ID for you, federal law requires it to withhold 24% and send it to the IRS. You reclaim it on your return. It is also entirely avoidable, and the fix is a single form.

If you own minerals in more than one state, expect identical gross royalties to produce different net checks. Texas has no state income tax and withholds nothing. Oklahoma and New Mexico both withhold state income tax from non-resident royalty owners. That difference is normal, not an error — Where to look it up covers the ten biggest producing states.

The one that nobody shows you

Two stubs, same well, same month, same money

Post-production costs can be accounted for two completely different ways, and only one of them is visible to you.

The itemized method. The company books a gross price and shows separate deduction columns on your stub. Gathering, so many cents. Compression, so many cents. Transportation, so many cents. You can see every one of them, add them up, and argue about them.

The netback method. The company sells the gas under a contract where the midstream company keeps a percentage of the proceeds, or takes its fee out before remitting. The operator records only what it actually received. There is no deduction column — because as far as the accounting system is concerned, no deduction ever happened. The cost is baked into the price.

Below are two owners on the same well, in the same month, with the same decimal. One is paid under an itemized contract and one under a netback contract. Read the stubs as printed. Then reveal what happened upstream of them.

Severance tax is left off both stubs so the single real difference stays visible. In life it comes off both, and both owners also carry it. The $34.18 is one fifth of the $0.70 per Mcf spread, shared out at this owner's decimal — the same arithmetic either way.

Netting is not fraud and it is not unusual — a large share of gas is contracted exactly this way, and the operator has done nothing hidden. But it means the most common way owners audit a royalty, scanning the deduction columns for something to object to, can miss the entire issue. The question worth asking is never "what was deducted." It's "what was the gross price received from the first purchaser, before any deduction, adjustment, or netting?"

The other half of the exposure

Some leaks are volume, not price

Many leases let an operator use gas from the well, free, to run its own equipment. If that equipment sits on your lease, that's ordinary and usually fine. If your gas is being burned to power compressors and plants somewhere else entirely, that's gas you were never paid for — and it will never appear as a price adjustment, because it never entered the price calculation at all.

You find a volume problem a different way: compare the volumes the operator reported to the Railroad Commission against the volumes you were actually paid on. Both numbers are yours to get — the reported ones are public and free, and the paid ones are on your stubs. Where to look it up · Texas shows where the production reports live.

Step five — the statement

What the check stub has to tell you

Texas doesn't leave the contents of a check stub to the company's discretion. There's a statutory minimum, and it exists precisely so a dollar can be traced.

If something you need is missing, you have a statutory right to ask for it. The request must be in writing and sent by certified mail, and the payor has 60 days to answer — by certified mail — on itemized deductions and adjustments, the heating value of the gas, and the Railroad Commission identification number for the lease or well. This is an obligation, not a courtesy: if it isn't met, either side can ask for mediation, and an owner who has to sue to enforce it can recover costs and fees if they prevail.

You are also supposed to be reminded of this right at least once every twelve months. That paragraph of small print arriving with a check each year is the statute talking.

Step six — the clock

When the money is actually due

Texas sets deadlines, and they matter because missing one costs the company money automatically. All of these run from the end of the month the production was sold — not from the day the well produced, and not from the day the operator got round to it.

A lease can change these periods, and many do. When a deadline is missed without a legal excuse, interest accrues automatically — you don't have to ask for it or sue for it to start running — at two percentage points above the rate the New York Federal Reserve Bank charges on loans to depository institutions, unless your lease sets a different rate. A higher rate applies in a few specific situations.

The main legal excuse is worth knowing, because it's the one you'll actually meet: a company may withhold without interest where there's a genuine title dispute, a reasonable doubt about whether you hold clear title to the interest, or an unsatisfied title requirement that puts your identity or whereabouts in question. That is the doorway into the next section.

Step seven — suspense

The account that isn't an account

When a company can't confidently pay you, it puts your money "in suspense." The phrase is one of the most misleading in the industry, and it's worth being blunt about what it means.

Step eight — where it ends up

Three years, then the state

If suspended money stays unclaimed for longer than three years after it became payable, Texas presumes it abandoned and the company must report and remit it to the Texas Comptroller's unclaimed property fund. You can then claim it from the state with proof of ownership.

This is the only point in the entire process where royalty money reliably lands in a genuinely segregated account outside the company's control. It should not take three years and a state agency to get there — but it does mean there is a public, searchable database with real mineral money sitting in it.

Search it under every name your family has used. Maiden names. Misspellings. Married names. Deceased relatives whose interests you inherited. Trust and estate names. It's free, it takes minutes, and it is the single highest-yield thing a passive mineral owner can do in an afternoon.

The one true escrow

Interpleader

Occasionally two or more people claim the same royalty and the company genuinely doesn't know who's right. It doesn't want the money and it doesn't want to be sued twice for the same dollar. So it files an interpleader: it sues all the competing claimants, deposits the disputed money into the registry of the court, and steps out. The claimants fight it out with each other while the money sits under the court's control.

That is the only routine circumstance in which your royalty money actually sits somewhere the operator cannot touch. Being interpleaded feels alarming — you've been named in a lawsuit — but mechanically it is the safest place your money can be while a dispute is pending.

Step nine — the wall

Every month you wait, one month expires

Texas gives you four years to sue for underpaid royalties. The Texas Supreme Court has held that royalty underpayment is not the kind of injury that's inherently impossible to discover — which means the clock generally runs from the underpayment itself, not from the day you worked it out. There's no reset for having been reasonable about it.

So the recoverable window rolls forward. It doesn't wait for you.

That combines badly with everything in the two-stub section above. A netted deduction is exactly the kind of problem an owner suspects for years without ever confirming. By the time it's confirmed, years of it are gone permanently.

Checking is not paranoia and it is not hostility toward your operator. It's the only thing that preserves the claim.

The routine

Eight things, most of them clerical

None of this is a research project. Two of these items are one-time paperwork, four are annual, and the last two take an afternoon once.

Why it's free

Made for mineral owners, by a mineral owner

Oil and gas ownership is one of the most counterintuitive corners of property law, and most of what's written about it is aimed at operators, landmen, or attorneys — not at the person who actually owns the minerals. This project exists to close that gap: to give owners and newcomers the intuition before the jargon, one clear visual at a time. That mission comes first, and it doesn't depend on anyone paying a cent.

That said, keeping a site online isn't free — there's a domain to renew, hosting to maintain, and real time behind every new concept. If Oil, Visualized has helped you understand what you own and you'd like to help keep it running and growing, a donation of any amount is genuinely appreciated. It's entirely optional, and everything here stays free either way.

On a computer? Scan the code with your phone. On your phone? Tap "Open my Venmo," or search @George-Tharp in the Venmo app. Any amount is a real help — thank you for reading.